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SAUDI ARAMCO WORKOVER MANUAL Drilling & Workover Engineering Department May 1999 CHAPTER 1 GENERAL INFORMATION SECTION A INTRODUCTION ___________________________________________________________________________________________________________________________ INTRODUCTION TO THE WORKOVER MANUAL 1.0 OBJECTIVES 2.0 CONTENTS 2.1 Source of Information 2.2 Ownership 2.3 Confidentiality 2.4 Contributors 3.0 REVISIONS 4.0 MEDIA
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Page 1: Saudi Aramco - WorkOver Manual

SAUDI ARAMCO WORKOVER MANUAL

Drilling & Workover Engineering Department May 1999

CHAPTER 1 GENERAL INFORMATION

SECTION A INTRODUCTION ___________________________________________________________________________________________________________________________

INTRODUCTION TO THE WORKOVER MANUAL 1.0 OBJECTIVES 2.0 CONTENTS

2.1 Source of Information 2.2 Ownership 2.3 Confidentiality 2.4 Contributors

3.0 REVISIONS 4.0 MEDIA

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CHAPTER 1 GENERAL INFORMATION

SECTION A INTRODUCTION ___________________________________________________________________________________________________________________________

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INTRODUCTION TO THE WORKOVER MANUAL 1.0 OBJECTIVES

This comprehensive manual has been compiled for the main purpose of serving as a guide to Workover Operations personnel and a reference to new Workover/Drilling Engineers. Most common Saudi Aramco drilling rig operations have been presented in this manual to familiarize the reader with the actual step-by-step procedures required to execute the job. This manual is written in such a way that it is clear, easy to follow, uses acceptable oilfield terminology, and the information is current and very specific to Saudi Aramco’s operations.

2.0 CONTENTS

2.1 Source of Information

The information contained in this manual has been collected from many different sources. These include: Saudi Aramco drilling guideline and instruction letters, Service Company manuals and catalogues, field experience, Saudi Aramco’s Completion & Workover training manual, oil industry recognized standards (e.g. API), and other sources.

2.2 Ownership

Saudi Aramco is the sole owner of the information in this manual. Any alterations or future updates of this manual shall be done only by the Workover Engineering and Technical Service Division personnel.

2.3 Confidentiality

The information in this manual has been prepared for Saudi Aramco. Even though the information is not highly confidential, yet discretion should be exercised when copying pages for non-Saudi Aramco personnel.

2.4 Contributors

Drilling and Workover staff, along with Laboratory Research and Development Center personnel have been instrumental in compiling the information in this manual.

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3.0 REVISIONS

As in every manual, information has to be periodically updated to reflect changing field conditions and the application of new technology. Suggested changes should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for review and inclusion in the next update of the manual. Chapter 1, Section B provides detailed procedures for revising this manual.

4.0 MEDIA

The Workover Manual will be available on different media to meet user requirements. These are: A) Hard copy. B) Electronically, on Drilling & Workover servers. C) CD-ROM disc with key word search capability.

Initially, the manual will be available in hard copy format and electronically, on the servers. Eventually, a CD-ROM version will be distributed to those who require it.

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CHAPTER 1 GENERAL INFORMATION

SECTION B WORKOVER MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES ___________________________________________________________________________________________________________________________

WORKOVER MANUAL ORIGINAL ISSUE & REVISION GUIDELINES

1.0 ORIGINAL DOCUMENT ISSUE

1.1 Document Format 1.2 Media 1.3 Distribution

1.3.1 List 1.3.2 Manual Numbering 1.3.3 Responsibility

2.0 REVISIONS

2.1 Frequency 2.2 Revision Format 2.3 Responsibilities

2.3.1 Manual Modification 2.3.2 Manual Distribution

2.4 Distribution Instructions

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WORKOVER MANUAL ORIGINAL ISSUE & REVISION

GUIDELINES 1.0 ORIGINAL DOCUMENT ISSUE

1.1 Document Format

1.1.1 A common format has been developed to maintain structure uniformity since the manual has been authored by a number of individuals. Future revisions should utilize the same structure in order for the Workover Manual to maintain its organization and appearance.

1.1.2 The Workover Manual has been prepared using Microsoft Word.

Each chapter will consist of an index page, followed by text. Headings, text fonts, bullets and indentations will vary throughout the chapter but will conform to the following guidelines:

A) Page Set-up:

i) Margins Top : 0.5” Bottom : 0.88” Left : 1.25” Right : 1.25” Header : 0.5” Footer : 0.19”

ii) Paper Size Paper Size : Letter Width : 8.5” Height : 11” Orientation : Portrait (checked)

iii) Paper Source First Page : Default Tray Other Pages : Default Tray

iv) Layout Section Start : New Page Header & Footer : Different Odd & Even (checked) Different First Page (checked) Vertical Alignment : Top

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B) Index:

i) Header : ‘As shown above’ ii) Section Heading: Title, Arial 14, Bold, Italic, Centered, Red iii) First Subheading: Title, Arial 11, Bold, First text indent at

0”, Hanging text indent at 3/8”, Teal iv) Second Subheading: Title, Arial 11, Bold, First text indent

at 6/8”, Hanging text indent at 1-1/8”, Black v) Third Subheading: Title, Arial 11, Bold, First text Indent at

1-1/8”, Hanging text indented at 1-5/8”, Black vi) The subheadings numbering sequence should be as

follows: 1.0 First subheading

1.1 Second subheading 1.1.1 Third subheading

vii) Page Numbering: None

C) Text

i) Section Heading : Title, Arial 14, Bold, Italic, Centered, Red

ii) First Subheading : Heading 1, Arial 11, Bold, First text indent at 0”, Hanging text indent at 3/8”, Teal

iii) Second Subheading : Heading 2, Arial 11, Bold, First text indent at 3/8”, Hanging text indent at 6/8’, Dark Red

iv) Third Subheading : Heading 3, Arial 11, First text indent at 6/8”, Hanging text indent at 1-2/8”, Only number or title Blue and bolded

v) Forth Subheading : Body text, Arial 11, First text indent at 1-2/8”, Hanging text indent at 1-5/8”, Black

vi) Fifth Subheading : Body text, Arial 11, First text indent at 1-5/8”, Hanging text indent at 2”

vii) The subheading numbering sequence should be as follows:

1.0 First Subheading 1.1 Second Subheading

1.1.1 Third Subheading A) Fourth Subheading

i) Fifth Subheading The First Subheading numbering sequence cannot be changed. However, subsequent Subheadings can be altered to Bullets or Lettering, depending on context and flow of text.

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viii) Main Text : Body Text, Arial 11, Text alignment Justify. ix) Page Numbering: 1 of xx, 2 of xx, etc, the page number

location will alternate between the lower right and left hand corners.

1.2 Media

The Workover Manual will be available on three different media to meet user requirements. These are:

A) Hard copy (3-ring binder). B) Electronically, on Drilling & Workover servers. C) CD-ROM disc with key word search capability.

1.3 Distribution

1.3.1 List

Hard copies of the Workover Manual (and the Drilling Manual) will be distributed based on need and accessibility to the LAN servers. A copy of the Workover Manual will be stored in electronic form on the LAN server for easy access; consequently, hard copy distribution will be minimized. The hard copy distribution of the Manual will as follows:

A) General Manager, D&W B) Managers, D&W C) Rig Superintendents, D&W D) General Supervisors, DWOED E) Supervisors, DWOED F) Rig Foremen, D&W G) Loss Prevention Representative

Additional copies of the Workover Manual requested by individuals other than those listed above will be considered on a case-by-case basis and will be decided by the custodian of the Manual, General Supervisor of Workover Engineering and Technical Services Division.

1.3.2 Manual Numbering

Each hard copy of the Workover Manual will be numbered to insure the document is traceable. It will be properly marked, both on the

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outside of the binder and on the fist page of the document. A record will be kept of the Manual numbered and the recipient name.

1.3.3 Responsibility

A) A designated person will be responsible for distributing all hard

copies of the Workover Manual to the recipients. B) The responsible person will ask each recipient, prior to delivery,

his preference of the Workover Manual media; hard copy, CD-ROM (when available) or none.

C) Copies of the Workover Manual will be hand-delivered to each recipient and their initials obtained to verify receipt of the manual.

2.0 REVISIONS

2.1 Frequency

The Workover Manual will be updated no later than once every two years. The duration of the revision should not exceed two months since majority of the changes will be minor.

2.2 Format

The same format as the original Workover Manual will be followed. All changes and addendums will be highlighted on a separate page and inserted in the inside cover of the manual for quick reference. The updated sections or paragraphs within the Manual will have a line on the side of the page, as shown to the right of this paragraph. It is also important to change the date of the updated section in the upper right hand corner of the document.

2.3 Responsibilities

2.3.1 Manual Modification

The General Supervisor of Workover Engineering and Technical Services will assign a person to undertake the task of modifying the Workover Manual. The assigned person will collect all pertinent information related to updating the Manual, evaluate the proposed changes/additions, prepare them in a draft form, and circulate to Management for approval. Once approved, he will modify the Manual and highlight the changes as described in Section 2.2 above.

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2.3.2 Manual Distribution

The person designated to modify the Manual will also be responsible for distribution of copies of the Manual. He may seek the help of a technician to deliver the Manual to the rig sites if necessary.

2.4 Distribution Instructions

Using the original Workover Manual distribution list, either inserts, page replacements or complete Manual replacements will be hand delivered to the Manual recipients. Old Manuals that have been replaced will new ones will be destroyed to avoid inadvertent use. When all Manuals have been delivered, the issue list will be updated to reflect the up-to-date Manual recipients.

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SECTION C ORGANIZATION AND RESPONSIBILITES ___________________________________________________________________________________________________________________________

ORGANIZATION AND RESPONSIBILITES 1.0 ORGANIZATION CHART 2.0 RESPONSIBILITIES

2.1 Workover/Drilling Foreman 2.1.1 Well and Comp Location 2.1.2 Rig Move 2.1.3 Program Execution 2.1.4 Communication 2.1.5 Rig Operations 2.1.6 Record Keeping 2.1.7 Miscellaneous

2.2 Workover/Drilling Engineer

2.2.1 Workover Programs 2.2.2 Communication 2.2.3 Rig Surveillance 2.2.4 Completion Report 2.2.5 Training, Seminars, Forums and Courses

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ORGANIZATION CHART AND RESPONSIBILITIES 1.0 ORGANIZATION CHART

1.1 Figure 1-C-1 is the most current organization chart of Drilling & Workover. Due to periodic reorganization and restructuring of Drilling & Workover, this chart maybe replaced the next time the manual is due for an update.

DRILLING & WORKOVER

PLANNING & ACCOUNTINGSERVICES UNIT

SUPERVISOR

Material Acquisition& Forecasting Unit

Supervisor

Drilling RigSupport DivisionSuperintendent

Dril. Equip. & Water Well Maint. Div.Superintendent

Wellsites DivisionSuperintendent

Special ProjectsSuperintendent

DRILLING & WORKOVERSERVICES DEPT.

MANAGER

Drilling Engrg.Division 1

General Supervisor

Drilling Engrg.Division 2

General Supervisor

Workover Engrg.& Tech. Srvcs. Div.General Supervisor

DRILLING & WORKOVERENGINEERING DEPT.

MANAGER

Drilling Division 1Superintendent

Drilling Division 2Superintendent

Drilling Division 3Superintendent

Drilling Division 4Superintendent

Drilling Division 5Workover/DrillingSuperintendent

DEVELOPMENT DRILLING& OFFSHORE WORKOVER

DEPT. MANAGER

Drilling Division 1Superintendent

Drilling Division 2Superintendent

Drilling Division 3Superintendent

Drilling Divison 4Workover/DrillingSuperintendent

DEEP DRILLING& ONSHORE WORKOVER

DEPT. MANAGER

DRILLING & WORKOVERGENERAL MANAGER

Figure 1-C-1

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2.0 RESPONSIBILITIES

2.1 Workover/Drilling Foreman

The Workover/Drilling Foreman has a diverse set of responsibilities, which are very critical in achieving safe workover operations. On Contractor operated workover rigs, the Foreman is the primary liaison between Saudi Aramco and the Contractor. On Company owned rigs, he is the primary site leader, directing all rig operations. Since his responsibilities are numerous and diverse, the following sections, 2.1.1 through 2.1.7 will only cover his main duties: 2.1.1 Well and Camp Location:

A) Inspect new well location to ensure well site, roads, power line crossings, water well location and campsite are within acceptable limits. i) Well site and road dimensions must conform to SAES-B-

062 (See Appendix) ii) Rig equipment that is being transported to the new well site

should clear the power lines as specified in section 2.1.2 (B).

B) Check and report wellhead pressures. Check type and size of

wellhead flanges. Check permanent surface equipment constraints on the well site.

C) Call Cathodic Protection 24 hours prior to rigging up and rigging

down, to disconnect/reconnect cathodic protection cable (if required).

D) Insure the flare pit (usually located south of the well site) is

positioned down-wind of the derrick on all wells except Khuff and Pre-Khuff wells.

E) Two flare pits will be available for Khuff/Pre-Khuff wells. The advantage of having a second flare pit is that in the event of an uncontrolled flow and should the flare go out, then the gas can be safely diverted to the second flare pit. This minimizes the chances of the flow being ignited by the generators, and eliminates the necessity or relocating the rig equipment. Depending on the rig layout, the second pit could be on the

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easterly or westerly side of the location; the first pit is usually located south of the spud point. See Appendix for details.

F) Camp location for all wells (except Khuff/Pre-Khuff wells) are

selected based on a central site that is in proximity of a number of upcoming workovers. This practice eliminates unnecessary and costly camp moves. It is important to note that the camp should never be located within walking distance from the rig.

G) The rig camp should be in a northerly direction and should be no less than 3 to 4 Kms from the well site for all Khuff/Pre-Khuff wells. This distance would allow the rig personnel to concentrate on controlling the well at the rig site, rather than having to worry about evacuating the camp in case of an emergency.

2.1.2 Rig Move:

A) Witness the rig move. Insure safety guidelines are being followed at all times while moving the rig and related equipment to the new well location.

B) When transporting rig equipment under power lines, clearance distance becomes important to prevent line severing and electrocution. The following guidelines are used in determining safe clearance distance. i) 8 feet for 69 kV or greater transmission lines. ii) 5 feet for less than 69 kV transmission lines. When the above clearances are not possible to attain, then every effort should be made to find a different rout to transport the rig equipment. If re-routing is not possible or does not provide the necessary clearance, then de-energizing the power line is considered as the last resort.

C) Witness setting of the main camp.

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2.1.3 Program Execution:

A) Adhere to the workover program and required supplements. Review contents of the program to ensure all steps are fully understood. If unclear, contact the Workover/Drilling Superintendent or Workover Engineering for clarification and consultation.

B) Discuss the program with the Assistant Foreman, contract rig Supervisor and Driller to ensure all the steps are clearly understood.

C) Any changes from the program will need to be discussed with the Superintendent to ensure that all the related facts have been considered.

2.1.4 Communication:

A) Prepare the daily workover report and afternoon report. Transmit to the Superintendent.

B) Communicate with Superintendent regarding possible changes to workover programs based on operational requirements.

C) Obtain advice from Workover Engineering to improve workover techniques and as well conditions dictate.

D) Talk to Service Company representatives regarding operation of their equipment. The operation of each tool should be fully understood prior to running in the well.

E) Discuss with the Superintendent new ideas and suggestions to

improve operating performance and safety procedures. The Foreman is in the best position to observe and experience first-hand rig activities.

2.1.5 Rig Operations

A) Directly supervise important rig operations such as nippling up/ down BOPE, running casing/liner, running tubing, logging/perforating operations, etc.

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B) Witness all non-routine and critical work, e.g. killing, testing of BOPs, fishing, milling, cementing, completion operations, livening, etc.

C) Supervise re-entry sidetrack operations. Monitor performance of motors, bottom-hole assemblies, and bits to optimize sidetrack performance.

D) Order materials and equipment from the Toolhouse in

anticipation of upcoming need. See that all equipment necessary for drilling and completing the well, as well as maintaining the rig, is at the rig site.

E) Schedule Service Company to perform work on the well as needed. Provide sufficient lead-time when contacting the Service Company.

F) Ensure all work performed on the rig is being performed in a

safe and efficient manner.

G) Conduct daily inspection and provide proper daily maintenance of the nearby water supply well.

2.1.6 Record Keeping

A) Casing, tubing and drill pipe tally.

B) Tour sheets.

C) Casing cementing details.

D) Wellhead and tree work (pack-off energizing and testing, bonnet

testing, etc).

E) Inspect and record condition of bottom hole assemblies on all trips. Replace equipment as necessary.

F) Maintain current pre-recorded information kill sheet.

G) Prepare other Saudi Aramco forms and paperwork as needed.

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2.1.7 Miscellaneous

A) Training of the Assistant Foreman

B) Conduct periodic well control and disaster drills

C) Participate in scheduled rig inspections

D) Prepare accident reports as necessary 2.2 Workover/Drilling Engineer

The Workover/Drilling Engineer is primarily responsible for providing technical support to the rig operations to which he is assigned. He uses his knowledge and expertise to advise and recommend solutions to problems and find cost effective ways of performing the rig work. He works closely with the Workover/Drilling Foreman and various organizations within Saudi Aramco to ensure all requirements are met while drilling the well. The following sections, 2.2.1 through 2.2.6, outline his responsibilities in more detail:

2.2.1 Workover Programs

A) The Workover Engineer is responsible for preparing and

publishing the approved workover program at least one week in advance of moving on the well.

B) Prior to preparing the program, the Workover Engineer should

thoroughly research the practices/problems encountered in similar operations in the area. He is also expected to contact the Production and Reservoir Engineers in charge of the field or area where the well is located to obtain important reservoir information, such as pressures, fluctuation of injection trends, facility shut-downs, depth of horizons, etc. He should then design the workover procedure accordingly.

C) The Workover Engineer will check the surplus material list and

include in the program usable materials in order to reduce inventory. Surplus material can be used as long as they continue to meet specifications and are acceptable alternatives without compromising performance and safety.

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D) As well conditions dictate, the Workover Engineer will prepare supplements to the original program in order to revise operating procedures or provide additional direction to the Foreman. The supplements should state the purpose it is being issued for and what problem or change in condition has necessitated the preparation of the supplement. A supplemental program should be issued ahead of work start-up. Sometimes, temporary hand-written directions are faxed to the Workover/Drilling Foreman due to time constraints while the supplement is being prepared.

E) Occasionally, a workover program will be approved but delayed

because of schedule changes. In such a case, the Workover Engineer is responsible for checking all the contents of the previously prepared program to insure current data is being used; if necessary, he will issue a supplement to the program.

F) The Workover Engineer will design the cement program

depending on the mixing/displacement time calculations and bottom hole temperatures. If cement additives are to be used, he will coordinate lab testing on field samples (cement and mix water) by the Service Company and the Saudi Aramco Laboratory ahead of time in order to eliminate all uncertainties.

G) The Workover Engineer will estimate the target time to complete

the programmed well work.

H) A preliminary cost estimate will be prepared prior to each workover for cost justification and budgetary planning.

I) The Workover Engineer is responsible for insuring the

availability of all required completion equipment. If the desired equipment is not available, compatible substitute equipment is an option provided the proponent is in agreement. The Workover Engineer will include in the completion all drift sizes of tubing, nipples, crossovers, etc., and the type of packer and completion fluid. As a final step, he will investigate the possibility of performing a stimulation to remove formation damage and improve well productivity.

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J) The Workover Engineering Supervisor is responsible for reviewing the workover program with the engineer. The Supervisor is to pay special attention to kill procedures and ensure the workover program provides safe direction and is both practical and cost effective.

The following represent additional responsibilities of the Workover Engineer with respect to planning and preparing a workover program for a re-entry sidetrack

K) The Workover Engineer will calculate the mud weight to provide

the required overbalance for proper well control. Supervisor should be consulted if diverting from the established guidelines, as follows: i) Known water bearing zones 100 psi ii) Known oil & gas bearing zones *300 psi * When drilling oil wells with good offset control, calculate the overbalance by taking the reservoir pressure and lost circulation information into consideration. In these cases, the overbalance could be reduced to the range of 200 to 300 psi.

L) The Workover Engineer will coordinate with the Geologist, Production and Reservoir Engineers to obtain target entry location, target size, bottom hole location, and logging requirements. Additional reservoir information, such as pressures, fluctuation of injection trends, facility shut-downs, depth of horizons, adjacent wellbores, potential loss circulation zones, dip angle, and etc. He should then design the sidetrack program accordingly, using this information to avoid potential sidetracking problems.

M) The Workover Engineer will coordinate with the assigned

directional company on an optimum directional plan for the sidetrack. He will also verify that the required directional equipment (with back-up equipment) and experienced directional men are available for the project.

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N) The Workover Engineer will calculate/design an optimum hydraulics program to maximize hole cleaning and rate of penetration based on the available rig equipment (pumps, DCs, etc.). He will study the offset wells and recommend a suitable and cost-effective bit program depending on the lithology and downhole motors associated with the directional plan.

2.2.2 Communication

The Workover Engineer must be a good listener and communicator. He should establish dialog and close contact with the Forman, his Supervisor, Superintendent, other Drilling Engineers, Mud and Cement Lab Experts, Toolhouse and Contractor personnel, Geologist, Reservoir and Production Engineers to exchange information when necessary. Periodic field visits to the rig help enhance his working relationship with the Foreman and rig contract personnel.

2.2.3 Rig Surveillance

A) The Workover Engineer will keep abreast of work progress on

his rig(s). On all wells, the engineer will plot the well drill time progress on a daily basis and ensure that the well work is proceeding as planned. If progress is slower than expected, he will investigate the reasons and make recommendations to remedy the situation. The Workover Engineer is expected to anticipate the technical needs of the rig and keep the Foreman duly advised. If trouble is experienced on a particular job, the Workover Engineer and the Foreman will determine the cause and submit an action plan.

B) The Workover Engineer will obtain results of the open hole

caliper log (re-entry sidetrack) and will calculate the cement volumes based on the bore hole geometry. The cement volume excess should be as follows:

Full Casing Strings 200 – 250 cubic feet of excess, more

than the caliper volume.

Liners 500 – 700 feet of rise around the DP (with the hanger setting tool in place).

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C) The Workover Engineer will witness all perforating jobs. He will discuss with the Service Company the alternatives to best achieve the objective, i.e. deep penetration, underbalanced perforating, large entry holes, gun length, etc.

D) The Workover Engineer is responsible for providing technical

information on tubulars ( i.e. collapse, burst, hardness, etc.) to the Forman as the need arises and provide recommendations on corrosion inhibitors.

E) When running unusual or new equipment, or trial testing a new

procedure, the Workover Engineer should be fully informed of the details and should witness the trial test on the rig.

2.2.4 Completion Report

The Workover Engineer will prepare completion reports for his well(s) and submit to the Supervisor within one (1) week of rig release. The completion report will consist of a summary of the actual well work performed and details regarding changes in plug back depth, casing/liner program, open/closed perforations, production rates/pressures, completion equipment, wellhead equipment. Each completion report will also include a revised completion sketch, wellhead sketch, and wellbore cross-section. It is highly recommended for the Engineer to compile the workover reports on a daily basis in order to meet the completion submission deadline.

2.2.5 Training, Seminars, Forums and Courses

A) It is the Workover Engineer’s responsibility to stay abreast with

new technology. He should attend courses, seminars and forums, time permitting, in order to enhance his knowledge of workover/drilling engineering aspects.

B) The Workover Engineer will devote significant time and effort to

mentor/train young engineers. He will expose the young engineer to all his responsibilities regarding office and fieldwork. Following a specified elapsed time, the young engineer should be on his own and be able to perform the normal duties of a Workover Engineer.

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SECTION D EMERGENCY RESPONSE PLAN ___________________________________________________________________________________________________________________________

EMERGENCY RESPONSE PLAN 1.0 ONSHORE

1.1 The Document 1.2 Purpose 1.3 Content 1.4 Update

2.0 OFFSHORE

2.1 The Document 2.2 Purpose 2.3 Content 2.4 Update

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EMERGENCY RESPONSE PLAN 1.0 ONSHORE

1.1 The Document: An Emergency Response Plan has been available since the early 1980s in the form of a General Instruction, GI-1850.001. The GI is entitled “Onshore Contingency Plan”. It is periodically updated to reflect changes in responsibility and policy. The most current revision is dated 08/01/1996. A copy of GI 1850.001 can be found in Chapter XI, Appendix A.

1.2 Purpose: GI 1850.001 contains the Contingency Plan for a disaster

occurring at any onshore wellsite during drilling or workover operation, or when a Producing organization has turned over responsibility for well control to the Drilling and Workover organization.

1.3 Content: The GI contains clear instructions and guidelines on who reports

the emergency, how it should be reported, which organizations are responsible for taking action, and what are some immediate steps to take to gain expedient control of the well. The document also provides guidance on intentional well ignition, cost accounting, periodic disaster drills, documenting and after-the-fact critiquing of the Contingency Plan implementation.

1.4 Update: GI-1850.001 will be updated every 3 years to assure the document

stays current with the ever-changing requirements. Proposed modifications by individuals should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for evaluation and eventual inclusion into the next update of the GI.

2.0 OFFSHORE

2.1 The Document: An Offshore Emergency Response Plan had been available for sometime as part of the Department Instruction Manual, DIM-1700.001. It was converted to a General Instruction, GI-1851.001 during the last quarter of 1998 for ease of document storage, access and updating. The GI is entitled “Drilling and Workover Operations Offshore Contingency Plan”, and it was last updated as DIM-1700.001 in December 1996. A copy of this new GI 1851.001 can be found in Chapter XI, Appendix A.

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2.2 Purpose: GI 1851.001 contains the Contingency Plan for a disaster occurring at any offshore wellsite during drilling or workover operation, or when Producing has turned over responsibility for well control to the Drilling and Workover organization.

2.3 Content: The GI contains clear instructions and guidelines on who reports

the emergency, how it should be reported, and what are some immediate steps to take to gain expedient control of the well. The document clearly spells out the responsibilities of each organization that is required to provide support, including the Marine Department which provides crucial oil spill and platform fire containment equipment and services. In addition, the GI also outlines the criteria used in deciding on intentional well ignition, procedures for cost accounting, periodic disaster drills, documenting and after-the-fact critiquing of the Contingency Plan implementation.

2.4 Update: GI-1851.001 will be updated every 3 years to assure the document

stays current with the ever-changing requirements. Proposed modifications by individuals should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for evaluation and eventual inclusion into the next update of the GI.

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SECTION E COMMUNICATION SYSTEMS ___________________________________________________________________________________________________________________________

COMMUNCIATION SYSTEMS 1.0 GENERAL 2.0 SYSTEMS

2.1 ESU (Extended Subscriber Unit) 2.2 IMTS (Improved Mobile Telephone System) 2.3 SSB (Single Side Band Radio) 2.4 Satellite Communication 2.5 Drilling Circuit Radio

3.0 REPAIRS

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COMMUNCIATION SYSTEMS 1 0 GENERAL

1.1 Communication between the rigs and camp to the Drilling and Workover Office is of paramount importance during daily workover operations and emergencies. The Workover/Drilling Foreman must have the capability to consult the Workover Superintendent and Engineering on a daily basis as the workover activity progresses. He also needs to be able to call the Toolhouse to order required materials and equipment, and contact Service Companies to schedule upcoming rig work. During critical operations or emergencies, the Foreman needs to keep the Superintendent fully informed of the transpiring events, and be able to discuss action alternatives as well conditions dictate. The importance of an effective communication system cannot be stressed enough.

2.0 SYSTEMS

Every workover rig is equipped with more than one communication system to ensure uninterrupted service. Each system has limitations, however, a combination of these systems complement each other.

2.1 ESU

This is the primary communication service for all rigs. The ESU, Extended Subscriber Unit, radio equipment operates in UHF at a range of up to 60 kms from the rig site. This microwave radio system was originally designed for narrow band voice transmission only, however, it is also being used for sending and receiving fax and low speed data transmission via a modem. Communication on the ESU system is sometimes not possible due to topographic blind spots, such as sand dune valleys.

2.2 IMTS

This is the backup to the ESU system, designed for use in case of emergency. IMTS (Improved Mobile Telephone System) is a 25+ year-old system and carries 4 channels; it is used for voice communication only. Since spare parts are no longer manufactured, the IMTS equipment will eventually be phased out in favor of newer state of the art equipment. There are geographical “dead spots” where communication is not possible due to limitations in antenna distribution and signal strength.

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2.3 SSB

Single Side Band Radios (SSBs) are mounted on every rig Foreman’s vehicle and on all offshore rigs. SSB uses high frequency signal and is monitored by HYZ-3, more commonly known as Y-3. It is possible to make a telephone patch through HYZ-3 on the SSB radio. First call HYZ-3 and tell the operator that you wish to make a telephone patch; give him the number you want to call. If calling the rig from the Drilling and Workover Office, call Y-3 and tell the operator the rig number you would like to contact. The Y-3 telephone number is 876-4088. SSB communication can be completely lost for hours since the signal is sensitive to weather conditions.

2.4 Satellite Communication Saudi Aramco has units available which have the capability to communicate with remote sites through Mini-m satellite. The units are compact, battery charged, portable and easy to operate. The major factor of these equipment is the high operating unit rate of satellite airtime.

2.5 Drilling Circuit Radio Every rig is equipped with a drilling circuit radio. Two channels are available: A or F-1 (when located in Northern area) and B or F-2 (when located in Southern area).

3.0 REPAIRS

All communication problems should be reported to “Communication Repair” by calling 904. A trouble ticket is issued and the faulty communication equipment is repaired or replaced thereafter.

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SECTION F RIG SPECIFICATIONS ___________________________________________________________________________________________________________________________

RIG SPECIFICATIONS 1.0 GENERAL 2.0 ONSHORE RIG SPECIFICATIONS DATA SHEETS

2.1 ADC-3 2.2 ADC-4 2.3 ADC-12 2.4 ADC-15 2.5 ADC-21 2.6 DPS-43 2.7 DPS-44 2.8 DPS-45 2.9 NAD-60 2.10 NAD-70 2.11 NAD-88 2.12 NAD-117 2.13 NAD-128 2.14 NAD-212 2.15 PA-194 (Workover Rig) 2.16 PA-201 2.17 PA-202 2.18 PA-203 2.19 PA-214 2.20 PA-236 2.21 PA-303 (Workover Rig) 2.22 PA-304 2.23 SAR-103 (Workover Rig) 2.24 SAR-151 2.25 SAR-153 2.26 SF-173 2.27 SF-174

3.0 OFFSHORE RIG SPECIFICATIONS DATA SHEETS 3.1 ADC-17 3.2 PA-145 (Workover Rig) 3.3 SAR-201 3.4 SF-32

Rigs contracted rigs after May,1999

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RIG SPECIFICATIONS 1.0 GENERAL

1.1 During drilling operations, it becomes necessary at times to perform rig work, such as fishing or running casing, that requires rig equipment to be operated near the designed limit. If this limit is exceeded, then the equipment is likely to fail thus causing financial loss and delays in the drilling operations. It is common practice to review the rig equipment specifications in order to operate within its capabilities and limitations.

1.2 Each and every rig is supplied with different equipment. The main components of a rig can be categorized as follows: A) Rig equipment B) Rig power C) Mud system & pump D) BOP equipment E) Safety Equipment F) Drill pipe & drill collars

1.3 Important information about a rig is the depth limitation or capacity. Every piece of equipment has a maximum operating limit before failure occurs. In the case of the rig depth limitation, it is based on the load the derrick structure can sustain during operations. The limit is calculated based on the drill pipe size (and weight) to be run, additional equipment on the drill pipe, and the amount of overpull which might be needed in case of getting stuck. There are also safety factors included in the limitation to account for normal wear and tear.

2.0 SPECIFICATION DATA SHEETS Since rig contractors are periodically changed, new rig specification sheets are required. Also, existing rig equipment is sometimes modified or replaced. For these reasons, it is important to update the Specification Data Sheets in section 2.0 of this chapter every time the Drilling Manual is revised. As of May, 1999, there were 23 onshore and 2 offshore drilling rigs in operation.

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2.1 ADC-3 (ONSHORE RIG)

A) Years in Service : 19

B) Rig Equipment 1. Drawworks : Gardner Denver 1100E (1500 hp) 2. Derrick : Pyramid 149’ x 29’ 3. Hook Load : 769,000 lbs 4. Top Drive : Varco-TDS 11S 5. Rotary Table : National C -375 (37-1/2”) 6. Blocks : National 350 ton (Hook/Block Combination) 7. Swivel : National P400 ton 8. Sub-Structure : 18’ from ground to rotary beam 9. Geolograph : Totco, 7 pen

C) Rig Power

1. Engine Power : 4 x Caterpillar D398, 825 hp 2. Drawworks : Gardner Denver 1100E 2 x GE 752 motor – 800 hp 3. Mud Pumps : 4 x GE 752 – 800 hp 4. Rotary : Independent drive, one GE 752 motor – 800 hp 5. Top Drive : 2 x AC Motor, 800 hp each

D) Mud System & Pump

1. Mud Pumps : 1 Gardner Denver PZ-11 (1600 hp) & 1 PZ-10 (1300 hp) 2. Mud Pits & Storage : 1500 bbl. capacity, 120 bbl trip tank 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Swaco 212 – 1000 GPM 5. Centrifuge : None 6. Degasser : Swaco 1000 GPM

E) BOP Equipment (per Saudi Aramco Class ‘A’ Standard)

1. Accumulator : 3000 psi, Koomey 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : Cameron UU 13-5/8” double ram, 5000 psi, H 2S trim Cameron U 13-5/8” single ram, 5000 psi, H2S trim Hydril GK 13-5/8” x 5000 psi, H2S trim Hydril MSP 20” and 20-1/4”, 2000 psi, H2S trim

F) Safety Equipment : 51 Fire extinguishers, 1 fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H 2S monitors, 3 eye wash stations, 1 shower at mud pits, 4 wind socks, 1 Drager H 2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade G, 19.5 lbs/ft, 12,000’ : 3-1/2” Grade G, 13.3 lbs/ft, 16,000’ 2. HWDP : 60 of 5”, 60 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”, 20 of 3-3/8”

H) Depth Capacity : 16,000’ I) DF – GL Elevation : 22.1 feet

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2.2 ADC-4 (ONSHORE RIG)

A) Years in Service : 27

B) Rig Equipment 1. Drawworks : Gardner Denver 1100E (1500 hp) 2. Derrick : LCM 145’ x 25’ 3. Hook Load : 769,000 lbs 4. Top Drive : Varco TDS 9S. 5. Rotary Table : National, 37-1/2” 6. Blocks : Pyramid 350 ton 7. Swivel : National P-400, 400 ton 8. Sub-Structure : 21.86’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D398, 925 hp 2. Drawworks : Gardner Denver 1100E 2 X GE 752 motor – 800 hp 3. Mud Pumps : 4 x GE 752 – 800 hp 4. Rotary : 1 x GE 752, 800 hp, Independent drive 5. Top Drive : 700 hp

D) Mud System & Pump

1. Mud Pumps : 2 x National 10-P130 (1300 hp) 2. Mud Pits & Storage : 1300 bbl capacity, 60 bbl trip tank, 1100 bbl reserve 3. Shale Shakers : 2 x Derrick Flo-line Cleaners 4. Desander/Desilter : Swaco 212/Swaco PO4C16 800 GPM 5. Centrifuge : None 6. Degasser : Swaco 800 GPM

E) BOP Equipment

1. Accumulator : 3000 psi, Koomey 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : Hydril MSP 21-1/4” annular, 2000 psi. Hydril GK 13-3/8” x 5000 psi, H2S trim Cameron U 13-5/8” double ram, 5000 psi, H2S trim

F) Safety Equipment : 74 Fire extinguishers, 1 fire pump, 2 gas detectors, 1 H2S detector System, 1 cascade system, 38 SCBAs, 3 eye wash stations, 1 shower on mud pit, 3 wind socks, 1 Bauer breathing air compressor, 1 foam unit

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade X, 19.5 lbs/ft, 10,000’ : 3-1/2” Grade G, 13.3 lbs/ft, 10,000’ 2-3/8”Grade E, 6.65 lbs./ft, 2000’

2. HWDP : 1830’ of 5”, 3000’ of 3-1/2” 3. Drill Collars : 9 of 9-1/2”, 24 of 8-1/2”, 24 of 6-1/4”, 24 of 4-3/4”, 24 of 3-3/8”

H) Depth Capacity : 16,000’ I) DF – GL Elevation : 25.50 feet

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2.3 ADC-12 (ONSHORE RIG)

A) Years in Service : 13

B) Rig Equipment 1. Drawworks : National 110 UE (1500 hp) 2. Derrick : LCM 149’ x 25’ 3. Hook Load : 710,000 lbs 4. Top Drive : National PS 350/500 5. Rotary Table : National C375, 37-1/2” 6. Blocks : Continental Emsco, 350 ton 7. Swivel : National P-400 ton 8. Sub-Structure : 18’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 1 Caterpillar D399, 1000 hp 4 x Caterpillar D398, 825 hp each 2. Drawworks : 2 x GE 752motor, 1000 hp each 3. Mud Pumps : 4 x Reliance motor, 1000 hp each 4. Rotary : 1 GE 752 motor, 700 hp 5. Top Drive : 1000 hp

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-10 (1300 hp) 2. Mud Pits & Storage : 1500 bbl. capacity, 120 bbl. trip tank. 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Swaco 212, 800 GPM 5. Centrifuge : None 6. Degasser : Swaco, 800 GPM

E) BOP Equipment

1. Accumulator : NL Shaffer/Koomey – Type 20, 3000 psi. 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : Cameron UU 13-5/8” double ram, 5000 psi, H 2S trim Hydril GK 13-5/8” x 5000 psi., H2S trim Hydril MSP 20 and 21-1/4” annular, 2000 psi

F) Safety Equipment : 33 Fire extinguishers, 1 fire pump, 1 gas detector, 1 H2S detector, 1 cascade system, 16 Scott SCBAs, 2 portable gas monitors, 3 eye wash stations, 3 wind socks, 1 shower at mud pit, 1 Bauer breathing air compressor, 1 foam unit

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade E, 19.5 bls/ft., 10,000’ : 3-1/2” Grade G, 15.5lbs/ft., 10,000’

2. HWDP : 70 of 5”, 99 of 3-1/2” 3. Drill Collars : 7 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/2”, 24 of 4-3/4”, 21 of 3-3/8”

H) Depth Capacity : 16,000’ I) DF – GL Elevation : 22.3 feet

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2.4 ADC-15 (ONSHORE RIG)

A) Years in Service : 5

B) Rig Equipment 1. Drawworks : Midcontinent U -1220 EB (2000 hp) 2. Derrick : Dreco slingshot, 146’ x 25’ x 20’ 3. Hook Load : 1,300,000 lbs 4. Top Drive : National Oilwell, PS 350/500 5. Rotary Table : Oilwell, 37-1/2” 6. Blocks : Ideco – 650 ton 7. Swivel : National – 650 ton 8. Sub-Structure : 27’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 6 x Caterpillar D398TA engines, 1000 hp each 2. Drawworks : 2 x EMD D79, 1000 hp each 3. Mud Pumps : 2 x EMD D79 motor , 800 hp each 4. Rotary : 1 GE 752 DC motor, 1000 hp 5. Top Drive : 1 GE 752 motor

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-11 (1600 hp) 2. Mud Pits & Storage : 4000 bbls mud & 1000 bbls drill water, 60 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-line Cleaners 4. Mud Cleaner : 2 x Harrisburg MC-800, 800 gpm each 5. Centrifuge : Swaco - SC4 6. Degasser : Swaco – 1000 GPM

E) BOP Equipment

1. Accumulator : Stewart & Stevensen Koomey Unit 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 2 x Cameron U 13-5/8”, 10,000 psi, double 3 x Stewart & Stevensen 20-3/4”, 5000 psi 1 x SS Q 26-3/4”, 3000 psi, double Hydril GK, 13-5/8”, 5000 psi Hydril MSP, 21-1/4”, 2000 psi Shaffer, 30”, 1000 psi

F) Safety Equipment : 80 Fire extinguishers, 1 fire pump, 1 gas detector, 1 H2S detector, 1 cascade system, Scott SCBAs, 3 portable gas monitors, eye wash stations, 2 shower at mud pits, 3 wind socks, 2 foam units, 1 breathable air compressor G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2’ Grade E, 24.7 lbs/ft., 10,000’ 5” Grade G, 19.5 lbs/ft, 15,000’ 3-1/2” Grade G, 15.5 lbs/ft, 15,000’ 2. HWDP : 25 of 5-1/2”, 30 or 5”, 30 of 3-1/2” 3. Drill Collars : 17 of 9-1/2’, 24 of 8-1/4”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 25,000’ I) DF – GL Elevation : 31 feet

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2.5 ADC-21 (ONSHORE RIG) A) Years in Service : 18 B) Rig Equipment

1. Drawworks : Gardner Denver 3000 E (3000 hp) 2. Derrick : LC Moore, 147’ x 30’ x 26’ 3. Hook Load : 1,550,000 lbs 4. Top Drive : Hydraulic HPS 500 5. Rotary Table : Continental Emsco, 37-1/2’ 6. Blocks : LC Moore, 650 ton 7. Swivel : Continental Emsco 650 ton 8. Sub-Structure : 27 ‘ from ground to rotary beam 9. Geolograph : MD/Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D399 engines 2. Drawworks : 3 x EMD D79 DC motors 3. Mud Pumps : 4 x EMD D79 DC motors 4. Rotary : EMD D79 DC motor 5. Top Drive : GE 752 DC motor

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-11 (1600 hp) 2. Mud Pits & Storage : 4000 bbl mud and 1000 bbl drill water, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 3-cone Desander & 20-cone Desilter/ Mud Cleaner 5. Centrifuge : SC4 6. Degasser : Swaco 1000 GPM

E) BOP Equipment

1. Accumulator : Koomey, 3000 psi WP 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 Cameron 13-5/8” double ram, 10,000 psi

2 x Cameron 13-5/8” single ram, 10,000 psi 1 Cameron U 20-3/4” double ram, 3000 psi 1 Cameron U 20-3/4” single ram, 3000 psi 2 x Cameron U 26-3/4” single ram, 3000 psi Hydril GL 13-5/8”, 5000 psi; Hydril MSP, 21-1/4”, 2000 psi Shaffer, 30”, 1000 psi F) Safety Equipment : Fire extinguishers, 1 fire pump, fixed gas detector system, 1 cascade system, Scott SCBAs, portable gas detectors , eye wash stations and showers, 3 wind socks, 1 foam unit, 1 breathable air compressor G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2” Grade G, 21.9 lbs/ft, 10,000’ 5” Grade G, 19.5 lbs/ft, 15,000’ 3-12” Grade G, 13.3 lbs/ft, 15,000’ 2. HWDP (Joints) : 30 of 5-1/2”, 30 of 5”, 30 of 3-1/2” 3. Drill Collars (Joints) : 12 of 9-1/2”, 30 of 8-1/2’, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 25,000’ I) DF – GL Elevation : 34 feet

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2.6 DPS-43 (ONSHORE RIG)

A) Years in Service : Since May 1997

B) Rig Equipment 1. Drawworks : Oilwell E 2000 (2000 hp) 2. Derrick : Pyramid 152’ 3. Hook Load : 1,300,000 lbs 4. Top Drive : National 350/500 power swivel 5. Rotary Table : Oilwell D-375 6. Blocks : Oilwell B-500 7. Swivel : Oilwell 350/500 power swivel 8. Sub-Structure : 28’ from ground to rotary beam 9. Geolograph : Martin Decker 6-pen recorder

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399, 2000 hp 2. Drawworks : 2 x GE 752 motor 3. Mud Pumps : 2 x GE 752 motor 4. Rotary : Oilwell D 375 5. Top Drive : 1 x GE 752 motor

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell 1700 PT (1700 hp) 2. Mud Pits & Storage : 4000 bbls capacity, 60 bbl trip tank 3. Shale Shakers : 3 x Brandt LCM-2D, 2 x 800 GPM Mud Cleaners 4. Desander/Desilter : 1600 GPM Desander/1600 GPM Desilter 5. Centrifuge : Brandt SC4 6. Degasser : 1x 1200 GPM Degasser

E) BOP Equipment

1. Accumulator : Shaffer 2130420-3SX 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x Shaffer 30” annular, 1000 psi 1 x Shaffer 21-1/4” annular, 2000 psi 2 x Shaffer 13-5/8” double ram, 10,000 psi 1 x Shaffer 13-5/8” annular, 5000 psi 2 x Stewart & Stevenson 26-3/4’ singles, 3000 psi 1 x Shaffer 20-3/4” double, 3000 psi 1 x Shaffer 20-3/4” single, 3000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars 1. Drill Pipe : 5-1/2” Grade E, 21.9 lbs/ft, 10,000’

: 5” Grade G, 19.5 lbs/ft, 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft, 15,000’

2. HWDP : 30 of 5-1/2”, 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 20,000’ I) DF – GL Elevation : 35 feet

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2.7 DPS-44 (ONSHORE RIG)

A) Years in Service : Since April 1998 B) Rig Equipment

1. Drawworks : Oilwell E 2000 (2000 hp) 2. Derrick : Pyramid 152’ 3. Hook Load : 1,000,000 lbs 4. Top Drive : National 350/500 power swivel 5. Rotary Table : Oilwell D-375 6. Blocks : Oilwell B-500 7. Swivel : Oilwell PC 650 8. Sub-Structure : 28’ from ground to rotary beam 9. Geolograph : Martin Decker Drill Watch

C) Rig Power

1. Engine Power : 5 x Caterpillar D -3512 2. Drawworks : 2 x GE 752 motor 3. Mud Pumps : 2 x GE 752 motor 4. Rotary : Oilwell D 375 5. Top Drive : 1 x GE 752 motor

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell 1700 PT (1700 hp) 2. Mud Pits & Storage : 4000 bbls capacity, 60 bbls trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners, 2 x 800 GPM Mud Cleaners 4. Desander/Desilter : 1600 GPM Desander/1600 GPM Desilter 5. Centrifuge : None 6. Degasser : 1x 1200 GPM Degasser

E) BOP Equipment

1. Accumulator : Koomey 2T30420-3SX 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x Shaffer 30” annular, 1000 psi 2 x Shaffer 13-5/8” double ram, 10,000 psi 1 x Shaffer 13-5/8” annular, 5000 psi 1 x Stewart & Stevenson 26-3/4’ single ram, 3000 psi 1 x Stewart & Stevenson 26-3/4’ double ram, 3000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars 1. Drill Pipe : 5-1/2” Grade E, 21.9 lbs/ft, 10,000’

: 5” Grade G, 19.5 lbs/ft, 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft, 15,000’

2. HWDP : 30 of 5-1/2”, 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 20,000’ I) DF – GL Elevation : 35 feet

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2.8 DPS-45 (ONSHORE RIG)

A) Years in Service : Since June 1997

B) Rig Equipment 1. Drawworks : Oilwell E 2000 (2000 hp) 2. Derrick : Pyramid 152’ 3. Hook Load : 1,275,000 lbs 4. Top Drive : National 350/500 power swivel 5. Rotary Table : Oilwell D-375 6. Blocks : Oilwell B-500 7. Swivel : Oilwell 350/500 power swivel 8. Sub-Structure : 28’ from ground to rotary beam 9. Geolograph : Martin Decker 6-Pen recorder

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 2. Drawworks : 2 x GE 752 motor 3. Mud Pumps : 2 x GE 752 motor 4. Rotary : Oilwell D 375 5. Top Drive : 1 x GE 752 motor

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell 1700 PT (1700 hp) 2. Mud Pits & Storage : 4000 bbls capacity, 60 bbls trip tank 3. Shale Shakers : 3 x Brandt shakers, 2 x 800 GPM Mud Cleaners 4. Desander/Desilter : 1600 GPM Desander/1600 GPM Desilter 5. Centrifuge : Brandt/EPI 6. Degasser : 1x 1200 GPM Degasser

E) BOP Equipment

1. Accumulator : Shaffer 2T30420-38X 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x Shaffer 30” annular, 1000 psi 1 x Shaffer 21-1/4” annular, 2000 psi 2 x Shaffer 13-5/8” double, 10,000 psi 1 x Shaffer 13-5/8” annular, 5000 psi 2 x Stewart & Stevenson 26-3/4’ singles, 3000 psi 1 x Shaffer 20-3/4” double, 3000 psi 1 x Shaffer 20-3/4” single, 3000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2” Grade E, 21.9 lbs/ft, 10,000’ : 5” Grade G, 19.5 lbs/ft, 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft., 15,000’

2. HWDP : 30 of 5-1/2”, 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 20,000’ I) DF – GL Elevation : 35 feet

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2.9 NAD-60 (ONSHORE RIG)

A) Years in Service : 9

B) Rig Equipment 1. Drawworks : Midcontinent U -712-EA (1200 hp) 2. Derrick : 142’ x 21’ 3. Hook Load : 500,000 lbs 4. Top Drive : None 5. Rotary Table : Ideco 37-1/2” 6. Blocks : 350 ton 7. Swivel : 350 ton 8. Sub-Structure : 16’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 4 x Caterpillar D -398 TA 2. Drawworks : 2 x GE 752, 1000 hp each 3. Mud Pumps : 2 x GE 752, 1000 hp each 4. Rotary : 1000 hp 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-9 (1000 hp) 2. Mud Pits & Storage : 1500 bbls, 50 bbl trip tank 3. Shale Shakers : 2 x Derrick Flow-Line Cleaners 4. Desander/Desilter : 800 GPM each 5. Centrifuge : None 6. Degasser : Swaco

E) BOP Equipment

1. Accumulator : 7 station Koomey 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : 1 x 21-1/4” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi 1 x 13-5/8” double rams, 5000 psi

F) Safety Equipment : Gas and H2S detectors, Scott air packs, sunbelt cascade unit G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade E, 19.5 lbs/ft, 10,000’ : 3-1/2” Grade E, 13.3 lbs/ft, 10,000’

2. HWDP : 60 of 5”, 60 of 3-1/2” 3. Drill Collars : 9 of 9-1/2”, 30 of 8-1/4”, 30 of 6-1/4”, 30 of 4-3/4

H) Depth Capacity : 12,000’ I) DF – GL Elevation : 19 feet

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2.10 NAD-70 (ONSHORE RIG)

A) Years in Service : Re-contracted in 1999 B) Rig Equipment

1. Drawworks : Midcontinent 1220 (2000 hp) 2. Derrick : Lee C. Moore 147’ x 30’ 3. Hook Load : 1,000,000 lbs 4. Top Drive : None 5. Rotary Table : Emsco 37-1/2” 6. Blocks : 650 ton 7. Swivel : 650 ton 8. Sub-Structure : Lee C. Moore 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 2. Drawworks : 2 x GE 752, 1000 hp each, 2000 hp total 3. Mud Pumps : 4 x GE752, 1600 hp total 4. Rotary : 1 x GE 752 motor 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Emsco FB-1600 (1600 hp), 1 x PZ-7 (550 hp) 2. Mud Pits & Storage : 4000 bbls, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 1 x 4-cone Desander & 2 x 12-cone Desilter 5. Centrifuge : None 6. Degasser : Swaco

E) BOP Equipment

1. Accumulator : 12 station Koomey 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x 30” Shaffer annular, 1000 psi 1 x 21-1/4” Hydril annular, 1000 psi 2 x 26-3/4” Cameron single ram, 3000 psi 1 x 20-3/4” Cameron single ram, 3000 psi 1 x 20-3/4” Cameron double ram, 3000 psi 1 x 13-5/8” Hydril annular, 5000 psi 2 x 13-5/8” Cameron double ram, 10,000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2”, Grade S, 21.9 lbs/ft, 10,000’ : 5”, Grade G, 19.5 lbs/ft, 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft, 9,000’ : 2-3/8” Grade E, 6.7lbs/ft, 5000’

2. HWDP : 30 of 5-1/2”, 30 of 5”, 30 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 20,000’ I) DF – GL Elevation : 34 feet

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2.11 NAD-88 (ONSHORE RIG)

A) Years in Service : 9

B) Rig Equipment 1. Drawworks : Midcontinent U712-EA (1200 hp) 2. Derrick : Lee C Moore, 133’ x 18’ 3. Hook Load : 500,000 lbs 4. Top Drive : None 5. Rotary Table : National, 37-1/2” 6. Blocks : 350 ton 7. Swivel : 350 ton 8. Sub-Structure : 15’ from ground to rotary beam 9. Geolograph : Totco

C) Rig Power

1. Engine Power : 4 x Caterpillar D 398TA, 800 hp each 2. Drawworks : 2 x GE 752, 1000 hp each 3. Mud Pumps : 2 x GE 752, 1000 hp each 4. Rotary : 1000 hp 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-9 (1000 hp) 2. Mud Pits & Storage : 1300 bbls, 48 bbl trip tank 3. Shale Shakers : 2 x Derrick Flow-Line Cleaners 4. Desander/Desilter : 800 GPM each 5. Centrifuge : None 6. Degasser : Sweco

E) BOP Equipment

1. Accumulator : 7 station Koomey 2. Choke Manifold : 2-1/16” 3000 psi WP, sour service 3. BOPs : 1 x 21-1/4” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi 1 x 13-3/5” double ram, 5000 psi

F) Safety Equipment : Gas and H2S detectors, Scott air packs, sunbelt cascade unit

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade E, 19.5 lbs/ft,10,000’ : 3-1/2” Grade E, 13.3 lbs/ft, 10,000’

2. HWDP : 40 of 5”, 40 of 3-1/2” 3. Drill Collars : 9 of 9-1/2”, 30 of 8-1/4”, 30 of 6-1/4”, 30 of 4-1/2”

H) Depth Capacity : 12,000’ I) DF – GL Elevation : 20 feet

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2.12 NAD-117 (ONSHORE RIG)

A) Years in Service : 4

B) Rig Equipment 1. Drawworks : Midcontinent 1220 EB (2000 hp) 2. Derrick : Lee C. Moore 142’ x 32’ 3. Hook Load : 1,300,000 lbs 4. Top Drive : None 5. Rotary Table : Gardner Denver 37-1/2” 6. Blocks : 650 ton 7. Swivel : 650 ton 8. Sub-Structure : 28’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 TA 2. Drawworks : 2 x GE 752, 1000 hp each, 2000 hp total 3. Mud Pumps : 4 x GE752, 1600 hp total 4. Rotary : 1 x GE 752 motor 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Emsco FB, 1600 (1600 hp) 2. Mud Pits & Storage : 4000 bbls, 2 x 50 bbl trip tanks 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : HI-G dryer w/2-cone Desander, 20-cone Desilter 5. Centrifuge : Derrick 6. Degasser : Swaco

E) BOP Equipment

1. Accumulator : 12 station Koomey 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x 30” annular, 1000 psi 1 x 21-1/4” annular, 1000 psi 2 x 26-3/4” single ram, 3000 psi 1 x 20-3/4” double ram, 3000 psi 1 x 13-5/8” Hydril annular, 5000 psi 2 x 13-5/8” double ram, 10,000 psi

F) Safety Equipment : Gas and H2S detectors, Scott air packs, Cascade unit.

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2” Grade E, 21.9 lbs/ft, 10,000‘ : 5” Grade G, 19.5 lbs/ft, 15,000 ‘ : 3-1/2”, Grade G, 13.3 lbs/ft, 15,000’

2. HWDP : 30 of 5-1/2”, 30 of 5”, 30 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 25,000’ I) DF – GL Elevation : 34 feet

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2.13 NAD-128 (ONSHORE RIG)

A) Years in Service : Contracted in 1999 B) Rig Equipment

1. Drawworks : Midcontinent 1220 (2000 hp) 2. Derrick : Lee C. Moore 147’ x 30’ 3. Hook Load : 1,000,000 lbs 4. Top Drive : None 5. Rotary Table : Emsco 37-1/2” 6. Blocks : McKisssick 650 ton 7. Swivel : Emsco 650 ton 8. Sub-Structure : Lee C. Moore 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 2. Drawworks : 2 x GE 752, 1000 hp each, 2000 hp total 3. Mud pumps : 4 x GE752, 1600 hp total 4. Rotary : 1 x GE 752 motor 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Emsco FB-1600 (1600hp), 1 x PZ-7 (550 hp) 2. Mud pits & storage : 4000 bbls, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 1 x 4-cone Desander & 2 x 12-cone Desilter 5. Centrifuge : None 6. Degasser : Swaco

E) BOP Equipment

1. Accumulator : 12 station Koomey 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x 30” Shaffer annular, 1000 psi 1 x 21-1/4” Hydril annular, 1000 psi 2 x 26-3/4” Cameron single ram, 3000 psi 1 x 20-3/4” Cameron single ram, 3000 psi 1 x 20-3/4” Cameron double ram, 3000 psi 1 x 13-5/8” Hydril annular, 5000 psi 2 x 13-5/8” Cameron double ram, 10,000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2”, Grade E, 24.7 lbs/ft, 10,000’ : 5”, Grade G, 19.5 lbs/ft, 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft, 9,000’ : 2-3/8” Grade E, 6.7lbs/ft., 5,000’

2. HWDP : 30 of 5-1/2”, 30 of 5”, 30 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H) Depth Capacity : 20,000’ I) DF – GL Elevation : 34 feet

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2.14 NAD-212 (ONSHORE RIG)

A) Years in Service : 4

B) Rig Equipment 1. Drawworks : National UE 110 (1500 hp) 2. Derrick : Pyramid 156’ x 29 3. Hook Load : 800,000 lbs 4. Top Drive : CanRig 1050E, 500 ton 5. Rotary Table : National 37-1/2” 6. Blocks : 500 ton 7. Swivel : 400 ton 8. Sub-Structure : 21.5’ from ground to rotary beam 9. Geolograph : Swaco, 6 pen

C) Rig Power

1. Engine Power : 4 x Caterpillar D399, 1200 hp each 2. Drawworks : 2 x EDM D79, 1500 hp 3. Mud Pumps : D79, 1300 hp 4. Rotary : EMD D79, 1000 hp 5. Top Drive : GE 752, 1000 hp

D) Mud System & Pump

1. Mud Pumps : 2 x Emsco FB-1300 (1300 hp) 2. Mud Pits & Storage : 2500 bbls, 1 x 60 bbl trip tanks 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 800 GPM each 5. Centrifuge : None 6. Degasser : Welco 5200

E) BOP Equipment 1. Accumulator : Shaffer 9 station 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 29-1/2’ annular, 500 psi 21-1/4” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi 1 x 13-5/8” single ram, 5000 psi 1 x 13-5/8”, double ram 5000 psi

F) Safety Equipment : Gas and H2S detectors, Scott air packs, sunbelt cascade unit

G) Drill Pipe & Drill Collars 1. Drill Pipe : 5” Grade G, 19.5 lbs/ft, 10,000’

: 3-1/2” Grade G, 13.3 lbs/ft, 12,000’ : 2-3/8” Grade E, 6.7 lbs/ft, 5000’

2. HWDP : 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/4”, 30 of 6-1/4”, 30 of 4-3/4”,

30 of 3-3/8”

H) Depth Capacity : 18,000’ I) DF – GL Elevation : 25 feet

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2.15 PA-194 (ONSHORE WORKOVER RIG)

A) Years in Service : Manufactured in 1982

B) Rig Equipment 1. Drawworks : Cabot 2042 (750 hp) 2. Derrick : FourLeg 117’ 3. Hook Load : 300,000 lbs 4. Top Drive : None 5. Rotary Table : G. D. 27 ½” 6. Blocks : 250 ton 7. Swivel : 250 ton 8. Sub-Structure : 300,000 lbs rotary with 250,000 lbs setback 9. Geolograph : Totco – 4 pen

C) Rig Power

1. Engine Power : 2 x Cat. 3406, 360 hp each 2. Drawworks : 700 hp 3. Mud Pumps : 1 x Gardner Denver PZ-8 with 1 x Cat 398 4. Rotary : Torque Tube – 30,000 lb torque 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 1 x Gardner Denver PZ-8 (750 hp) 2. Mud Pits & Storage : 1500 bbls, 50 bbl trip tank 3. Shale Shakers : 1 x Derrick Flo-Line Cleaner 4. Desander/Desilter : None 5. Centrifuge : None 6. Degasser : None

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 2-1/16” 5000 psi. 3. BOPs : 13 5/8” 5000 psi Double Ram

F) Safety Equipment : As per contract requirements G) Drill Pipe & Drill Collars

1. Drill Pipe : 3 ½” Grade E, 13.3 lbs/ft, 10,000’ : :

2. HWDP : 20 of 3 ½” 3. Drill Collars : 20 of. 6 ¼”, 30 of. 4 ¾”

H) Depth Capacity : 7,500’ (drilling) / 15,000’ (workover) I) DF – GL Elevation : 20 feet

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2.16 PA-201 (ONSHORE RIG)

A) Years in Service : Manufactured in 1978

B) Rig Equipment 1. Drawworks : Oilwell 760 (1000 hp) 2. Derrick : 142’ x 21’ 3. Hook Load : 771,000 lbs 4. Top Drive : None 5. Rotary Table : 27-1/2” 6. Blocks : 350 ton 7. Swivel : 300 ton 8. Sub-Structure : 15’ from ground to rotary beam 9. Geolograph : Totco, 6-pen

C) Rig Power

1. Engine Power : 4 x Caterpillar 398, 900 hp each 2. Drawworks : 1 x DC motor, 1000 hp 3. Mud Pumps : 2 x GE 753, 1000 hp each 4. Rotary : 700 hp 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell 1100 PT (1100 hp) 2. Mud Pits & Storage : 1300 bbls, 120 bbl trip tank 3. Shale Shakers : 2 x 1600 GPM 4. Desander/Desilter : 800 GPM each 5. Centrifuge : None 6. Degasser : Drilco

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 2-1/16” 3000 psi WP, sour service 3. BOPs : 21-1/4” annular, 2000 psi 13-5/8” annular, 5000 psi 13-5/8” ram, 5000 psi

F) Safety Equipment : Saudi Aramco Standard

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade E, 19.5 lbs/ft., 10,000’ : 3-1/2” Grade E, 13.3 lbs/ft., 10,000’ : 3-1/2” Grade G, 13.3 lbs/ft., 5000’

2. HWDP : 60 of 3-1/2” 3. Drill Collars : 60 of 3-1/2”, 12 of 9-1/2”, 30 of 8-1/4”, 30 of 6-1/4

30 of 4-3/4”

H) Depth Capacity : 10,000’ I) DF – GL Elevation : 20.8 feet

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2.17 PA-202 (ONSHORE RIG)

A) Years in Service : Manufactured in 1978

B) Rig Equipment 1. Drawworks : Ideco E-1700 (1700 hp) 2. Derrick : 142’ x 25’ 3. Hook Load : 771,000 lbs 4. Top Drive : None 5. Rotary Table : Oilwell A-37-1/2” 6. Blocks : 400 ton 7. Swivel : 400 ton 8. Sub-Structure : Pyramid, 21feet from ground to rotary beam 9. Geolograph : Totco 6-pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -398TA, 900 hp each 2. Drawworks : 2 x GE 752, 1000 hp each 3. Mud Pumps : 2 x GE 752 4. Rotary : 1 GE 752 , 800 hp 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell A-1700 PT (1700 hp) 2. Mud Pits & Storage : 3000 bbls, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Demco 3 -cone Desander and 16-cone Desilter 5. Centrifuge : None 6. Degasser : Brandt, 1200 GPM

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : Hydril 11” Class ‘A’ 10,000 psi, H2S trim Hydril 13-5/8” Class ‘A’ 5000 psi, H2S trim 2 x Hydril 26-3/4” single ram, 3000 psi, H2S trim 2 x Hydril 20-3/4” single ram, 3000 psi, H2S trim Shaffer 30” annular, 1000 psi. Shaffer 21-1/4” annular, 2000 psi Hydril GK 13-5/8” annular, 5000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars :

1. Drill Pipe : 5” Grade G, 19.5 lbs/ft , 15,000’ : 3-1/2” Grade G, 13.3 lbs/ft, 10,000’ : 2-3/8” Grade E, 6.7lbs/ft., 5,000’

2. HWDP : 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”, 18 of 3-3/8”

H) Depth Capacity : 17,000’ I) DF – GL Elevation : 26.8 feet

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2.18 PA-203 (ONSHORE RIG)

A) Years in Service : Manufactured in 1978

B) Rig Equipment 1. Drawworks : Ideco E-1700 (1700 hp) 2. Derrick : 142’ x 25’ 3. Hook Load : 750,000 lbs 4. Top Drive : None 5. Rotary Table : Ideco 37-1/2” 6. Blocks : 400 ton 7. Swivel : 400 ton 8. Sub-Structure : Pyramid, 20.45 feet from ground to rotary beam 9. Geolograph : Totco 6-pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -398TA, 900 hp each 2. Drawworks : 2 x GE 752, 1000 hp each 3. Mud Pumps : 2 x GE 752 4. Rotary : 1 GE 752 , 800 hp 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell 1400 PT (1400 hp) 2. Mud Pits & Storage : 3000 bbls, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Demco 3 -cone Desander and 16-cone Desilter 5. Centrifuge : None 6. Degasser : Swaco

E) BOP Equipment

1. Accumulator : Koomey 16 station 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : Hydril 11” Class ‘A’ 10,000 psi, H2S trim Hydril 13-5/8” Class ‘A’ 5000 psi, H2S trim 2 x Hydril 26-3/4” single ram, 3000 psi, H2S trim 2 x Hydril 20-3/4” single ram, 3000 psi, H2S trim Shaffer 30” annular, 1000 psi. Shaffer 21-1/4” annular, 2000 psi Hydril GK 13-5/8” annular, 5000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars :

1. Drill Pipe : 5-1/2”, Grade E, 24.7 lbs/ft, 10,000’ : 5”, Grade G, 19.5 lbs/ft., 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft., 9,000’ : 2-3/8” Grade E, 6.7lbs/ft., 5000 ft

2. HWDP : 30 of 5-1/2”, 30 of 5”, 50 of 3-1/2” 3. Drill Collars : 18 of 10”, 30 of 8-1/2”, 30 of 6-1/2”, 30 of 4-3/4”

H) Depth Capacity : 17,000’ I) DF – GL Elevation : 26.0 feet

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2.19 PA-214 (ONSHORE RIG)

A) Years in Service : Since 1978

B) Rig Equipment 1. Drawworks : Ideco E900 (900 hp) 2. Derrick : 136’ 3. Hook Load : 525,000 lbs 4. Top Drive : None 5. Rotary Table : 37 ½” 6. Blocks : 350 ton 7. Swivel : 300 ton 8. Sub-Structure : 18.6 feet from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 3 x Cat 399 2. Drawworks : 1 x GE 752 3. Mud Pumps : 2 x GE 752 4. Rotary : 1 x GE 752 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x. Gardner Denver PZ-9 (1000 hp) 2. Mud Pits & Storage : 1450 bbl, 90 bbl trip tank 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 2-cone Desander / 20-cone Desilter 5. Centrifuge : None 6. Degasser : Sweco

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : 1 x 20” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi

1 x 13-5/8” double ram, 5000 psi F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade G, 19.5 lbs/ft., 10,000’ 3 ½” Grade G, 13.3 lbs/ft., 10,000’ 2. HWDP : 60 of 5”, 60 of 3 ½” 3. Drill Collars : 9 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H) Depth Capacity : 10,000’ I) DF – GL Elevation : 22 feet

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2.20 PA-236 (ONSHORE RIG)

A) Years in Service : Manufactured in 1983

B) Rig Equipment 1. Drawworks : Cabot E 2550 (1500 hp) 2. Derrick : 127’ 3. Hook Load : 735,000 lbs 4. Top Drive : None 5. Rotary Table : 37 ½” 6. Blocks : 350 ton 7. Swivel : 350 ton 8. Sub-Structure : 17.8 feet from ground to rotary beam 9. Geolograph : Totco, 6 pin

C) Rig Power

1. Engine Power : 4 x Caterpillar 399 2. Drawworks : 2 x GE 752 3. Mud Pumps : 4 x GE 752 4. Rotary : 1 x GE 752 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner Denver PZ-10 (1300 hp) 2. Mud Pits & Storage : 1500 bbl, 120 bbl trip tank 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 3-cone Desilter/ 16-cone Desilter 5. Centrifuge : None 6. Degasser : Brandt

E) BOP Equipment

1. Accumulator : Shaffer 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : 1 x 21-1/4” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi 1 x 13-5/8 single” ram, 5000 psi

1 x 13-5/8” double ram, 5000 psi F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade G, 19.5 lbs/ft., 10,000’ 3 ½” Grade G, 13.3 lbs/ft, 7,000’ 2. HWDP : 30 of 5”, 30 of 3 ½” 3. Drill Collars : 9 of 9 ½”, 30” of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H) Depth Capacity : 15,000’ I) DF – GL Elevation : 22 feet

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2.21 PA-303 (ONSHORE WORKOVER RIG)

A) Years in Service : Manufactured in 1982

B) Rig Equipment 1. Drawworks : Cabot 2042 (700 hp) 2. Derrick : 117’ Four Leg 3. Hook Load : 350,000 lbs 4. Top Drive : None 5. Rotary Table : Gardner Denver 27 ½” 6. Blocks : 250 ton 7. Swivel : 250 ton 8. Sub-Structure : 300,000 lbs rotary w/ 250,000 lbs setback 9. Geolograph : Totco – 4pen

C) Rig Power

1. Engine Power : 2 x Cat. 3406 – 360 hp each 2. Drawworks : 700 hp 3. Mud Pumps : 1 x Gardner Denver PZ-8 with 1 x Cat 398 4. Rotary : Torque Tube – 30,000 lb torque 5. Top Drive : None

D) Mud System & Pump : National P-80 1 ea.

1. Mud Pumps : 1 x Gardner Denver PZ-8 (750 hp) 2. Mud Pits & Storage : 1500 bbl, 50 bbl trip tank 3. Shale Shakers : 1 x Derrick Flo-Line cleaner 4. Desander/Desilter : None 5. Centrifuge : None 6. Degasser : None

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 2-1/16” 5000 psi 3. BOPs : 13 5/8” double ram, 5000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 3 ½” Grade E, 13.3 lbs/ft., 10,000’ : :

2. HWDP : 20 of. 3 ½” 3. Drill Collars : 20 of. 6 ¼”, 30 of 4 ¾”

H) Depth Capacity : 7,500’ (drilling) / 15,000’ (workover) I) DF – GL Elevation : 20 feet

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2.22 PA-304 (ONSHORE RIG)

A) Years in Service : Manufactured in 1981

B) Rig Equipment 1. Drawworks : EMSCO C-3 (3000 hp) 2. Derrick : DRECO 147’ 3. Hook Load : 1,555,000 4. Top Drive : National PS -500 5. Rotary Table : National 37 ½” 6. Blocks : 650 ton 7. Swivel : 650 ton 8. Sub-Structure : Dreco sling shot, 32 feet from ground to rotary beam 9. Geolograph : Totco 6-pen

C) Rig Power

1. Engine Power : 5 x Caterpillar 399 2. Drawworks : 2 x GE 752 3. Mud Pumps : 4 x GE 752 4. Rotary : 1 x GE 752 5. Top Drive : 1 x GE 752

D) Mud System & Pump

1. Mud Pumps : 2 x EMSCO 1600 (1600 hp each) 2. Mud Pits & Storage : 4000 bbl, 120 bbl trip tank 3. Shale Shakers : 3 x Derrick Flow Line Cleaner 4. Desander/Desilter : 2 x. Derrick High G Dryers 5. Centrifuge : None 6. Degasser : Delimann 1200 GPM

E) BOP Equipment

1. Accumulator : 2 x Koomey 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : 1 x 30” annular, 1000 psi 1 x 20” annular, 2000 psi 1 x 13-5/8” annular, 5000 psi

1 x 26 ¾” double ram, 3000 psi 3 x 20 ¾” single ram, 3000 psi 2 x 13-5/8” double ram, 10,000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5 ½” Grade G, 24.7 lbs/ft, 10,000’ 5” Grade G, 19.5 lbs/ft, 15,000’ 3 ½” Grade G, 13.3 lbs/ft, 15,000’ 2. HWDP : 30 of 5 ½”, 100 of 5”, 100 of 3 ½” 3. Drill Collars : 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H) Depth Capacity : 25,000’ I) DF – GL Elevation : 37.8 feet

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2.23 SAR-103 (ONSHORE WORKOVER RIG)

A) Years in Service : Manufactured in 1993

B) Rig Equipment 1. Drawworks : Skytop (950 hp) 2. Derrick : Skytop 115 ft 3. Hook Load : 410,000 lbs 4. Top Drive : None 5. Rotary Table : Skytop. 37 ½” 6. Blocks : Web Wilson 250 ton 7. Swivel : Oilwell 225 ton 8. Sub-Structure : Skytop, 290,000 # setback 9. Geolograph : Totco – 6-pen

C) Rig Power

1. Engine Power : 2 x Cat.D-379, 600 hp each. 2. Drawworks : 2 x Cat. 3408, 450 hp each 3. Mud pumps : 2 x Cat 398, 1100 HP, PZ8 Triplex 4. Rotary : 350 rpm, 410,000 Lb 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Gardner-Denver PZ-8 (750 hp) 2. Mud pits & storage : 820 bbls, 35 bbl Trip Tank. 3. Shale Shakers : 1 x Derrick Flo-Line Cleaner, tandem unit 4. Desander/Desilter : None 5. Centrifuge : 6” x 8” Mission Magnum with 75 hp GE motor 6. Degasser : None

E) BOP Equipment

1. Accumulator : Cameron, 7 station 2. Choke Manifold : 2-1/16” x 5000 psi 2” Chokes, Class B 3. BOPs : 1 x Shaffer 11” Double, Class II

F) Safety Equipment : H2S LEL 5-channel fixed detection (combustible gas monitor), fire extinguishers and fire hose

G) Drill Pipe & Drill Collars

1. Drill Pipe : 3-1/2” Grade G, 13.3 lbs/ft, 300 joints : 2-3/8” Grade E, 6.65 lbs/ft, 20 joints

2. HWDP : 2 jts of 3 ½” 3. Drill Collars : 15 of 4-3/4” spiral, 20 of. 3-3/8”

H) Depth Capacity : 10,000’ (drilling) / 15,000’ (workover) I) DF – GL Elevation : 18 feet

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2.24 SAR-151 (ONSHORE RIG)

A) Years in Service : 33

B) Rig Equipment 1. Drawworks : Midcontinent U712-EA (1200 hp) 2. Derrick : Lee C Moore, 3. Hook Load : 550,000 lbs 4. Top Drive : None 5. Rotary Table : National 37-1/2” 6. Blocks : 350 ton 7. Swivel : 400 ton 8. Sub-Structure : 12.85’ from ground to rotary beam 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : Rose Hill SCR 2. Drawworks : 2 x GE 752, 1000 hp each 3. Mud Pumps : 2 x GE 752, 1000 hp each 4. Rotary : 1 x GE 752 5. Top Drive : None

D) Mud System & Pump

1. Mud Pumps : 2 x Oilwell Triplex A-1700 PT (1700 hp) 2. Mud Pits & Storage : 1335 bbls, 70 bbl trip tank 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Mud Cleaner/ Desilter 5. Centrifuge : None 6. Degasser : None

E) BOP Equipment

1. Accumulator : Cameron 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : 13-5/8”annular, 3000 psi

13-5/8” double ram, 3000 psi

F) Safety Equipment : 40 regular and 3 (150#) on wheels fire extinguishers, 2 fire hose stations, Combustible gas monitors and alarm, 25 of 30 minute and 11 of 5 minute breathing apparatus, H2S monitor and alarm system (Light & Siren)

G) Drill Pipe & Drill Collars 1. Drill Pipe : 5” Grade G, 19.5 lbs/ft

: 3-1/2” Grade E, 13.3 lbs/ft 2. HWDP : 5”

: 3-1/2” 3. Drill Collars : 8-1/2”, 6-1/4”, 4-3/4”

H) Depth Capacity : 12,000’ I) DF – GL Elevation : 16.3 feet

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2.25 SAR-153 (ONSHORE RIG)

A) Years in Service : Commissioned in 1998

B) Rig Equipment 1. Drawworks : National 110 UE (1500 hp) 2. Derrick : Pyramid 147’ 3. Hook Load : 750,000 lbs 4. Top Drive : National PS 350/500 5. Rotary Table : 37-1/2” 6. Blocks : 350 ton 7. Swivel : 400 ton 8. Sub-Structure : Pyramid, 24.6 feet from ground to rotary beam 9. Geolograph : Totco, 6-pen

C) Rig Power

1. Engine Power : 4 x Caterpillar D 3512, 1321 hp each 2. Drawworks : 1500 hp 3. Mud Pumps : 1300 hp each 4. Rotary : 1365 hp 5. Top Drive : 1365 hp

D) Mud System & Pump

1. Mud Pumps : 2 x National 10P-130 (1300 hp each) 2. Mud Pits & Storage : 1500 bbls, 60 bbl trip tank 3. Shale Shakers : 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : 1 x Derrick Desander 50 gpm : 1 x Derrick Desilter 50 gpm 5. Centrifuge : None 6. Degasser : 1 x Derrick , Model Vacu-Flow 1000 : 1 X Poor Boy Degasser.

E) BOP Equipment

1. Accumulator : Stewart & Stevenson 2. Choke Manifold : Cameron, Class A, 5000 psi WP(from SAR-152), sour service 3. BOPs : Cameron Class B, 3000 psi Hydril GK annular, 13-5/8”, 3000 psi

F) Safety Equipment : Saudi Aramco standard

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade E, 19,5 lbs/ft, : 3-1/2” Grade E, 13.3 lbs /ft

2. HWDP : 5” 3. Drill Collars : 8-1/2”, 6-1/4” 4-3/4”

H) Depth Capacity : 16,000’ I) DF – GL Elevation : 30 feet

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2.26 SF-173 (ONSHORE RIG)

A) Years in Service : 3

B) Rig Equipment 1. Drawworks : Gardner Denver 3000 E (3000 hp) 2. Derrick : Dreco 147’ x 30’ 3. Hook Load : 1,300,000 lbs 4. Top Drive : Varco IDS-1 5. Rotary Table : Gardner Denver 37-1/2” 6. Blocks : 750 ton 7. Swivel : 650 ton 8. Sub-Structure : Dreco , 29.85 feet from ground to rotary beam 8. Geolograph : Totco, 8 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 2. Drawworks : 3 x GE 752, 1000 hp each 3. Mud Pumps : 4 x GE 752, 800 hp each (3200 hp total) 4. Rotary : 1 x GE 752 electric motor, 1000 hp 5. Top Drive : 1 x GE 752 electric motor, 1000 hp

D) Mud System & Pump

1. Mud Pumps : Gardner Denver PZ-11 Triplex (1600 hp) 2. Mud Pits & Storage : 2000 bbls active, 4000 bbls total, 2 x 66 bbl trip tanks 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Harrisburg 4-10” cones/Harrisburg 20-4” cones 5. Centrifuge : Brandt 3400 High volume (200 GPM Minimum) 6. Degasser : Swaco 1600 GPM

E) BOP Equipment

1. Accumulator : 12 station Dual Power, 3000 psi, air & electric 2. Choke Manifold : 4-1/16” 10,000 psi, sour service, 2 x Swaco Super Choke 3. BOPs : 1 x Stewart & Stevens 26-3/4”, Type-Q single, 3000 psi, H 2S trim 1 x Stewart & Stevens 26-3/4”, Type-U Superior double, 3000 psi, H2S trim 2 x Cameron 13-5/8” Type-U, 10,000 psi, H2S trim

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2”, Grade E, 24.7 lbs/ft, 10,000’ : 5”, Grade G, 19.5 lbs/ft., 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft., 15,000’

2. HWDP : 30 of 6-5/8”, 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 10”, 30 of 8-1/2”, 30 of 6-1/2”, 30 of 4-3/4”

H) Depth Capacity : 18,000’ I) DF – GL Elevation : 38 feet

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2.27 SF-174 (ONSHORE RIG)

A) Years in Service : 3

B) Rig Equipment 1. Drawworks : Continental Emsco C3 (3000 hp) 2. Derrick : Pyramid 152’ x 35’ 3. Hook Load : 1,500,000 lbs 4. Top Drive : Varco IDS-1 5. Rotary Table : Continental Emsco 37-1/2” 6. Blocks : 750 Tons 7. Swivel : 650 Tons 8. Sub-Structure : Pyramid, 28.5 feet from ground to rotary beam. 9. Geolograph : Totco, 6 pen

C) Rig Power

1. Engine Power : 5 x Caterpillar D -399 2. Drawworks : 3 x GE 752, 1000 hp each 3. Mud Pumps : 4 x GE 752, 800 hp each (3200 hp total) 4. Rotary : 1 x GE 752, 1000 hp 5. Top Drive : 1 x GE 752, 1000 hp

D) Mud System & Pump

1. Mud Pumps : Emsco FB 1600 Triplex (1600 hp) 2. Mud Pits & Storage : 2000 bbls active, 4000 bbls total, 2 x 60 bbl trip tanks 3. Shale Shakers : 3 x High speed Derrick Flo-Line Cleaners 4. Desander/Desilter : Harrisburg 4-10” cones/Harrisburg 20-4” cones 5. Centrifuge : Brandt 3400 High volume (200 GPM Minimum) 6. Degasser : Swaco 1600 GPM

E) BOP Equipment

1. Accumulator : 12 station Dual Power, 3000 psi, air & electric 2. Choke Manifold : 4-1/16” 10,000 psi, sour service, 2 x Swaco Super Choke 3. BOPs : 1 x Stewart & Stevens 26-3/4”, Type-U single, 3000 psi, H2S trim 1 x Stewart & Stevens 26-3/4”, Type-U double, 3000 psi, H2S trim 2 x Cameron 13-5/8” Type-U, 10,000 psi, H2S trim

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2”, Grade E, 24.7 lbs/ft, 10,000’ : 5”, Grade G, 19.5 lbs/ft., 15,000’ : 3-1/2”, Grade G, 13.3 lbs/ft., 15,000’

2. HWDP : 30 of 6-5/8”, 100 of 5”, 100 of 3-1/2” 3. Drill Collars : 12 of 10”, 30 of 8-1/2”, 30 of 6-1/2”, 30 of 4-3/4”

H) Depth Capacity : 18,000’ I) DF – GL Elevation : 35 feet

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3.1 ADC-17 (OFFSHORE RIG)

A) Years in Service : 18

B) Rig Equipment 1. Drawworks : National 1320 UE (2000 hp) 2. Derrick : DSI 160’ 3. Hook Load : 1,000,000 lbs 4. Top Drive : Varco TDS 3 5. Rotary Table : National C 375, 37-1/2” 6. Blocks : 550 ton 7. Swivel : 650 ton 8. Geolograph : Totco, 7 pen

C) Rig Power 1. Engine Power : 4 x Caterpillar D399, 1215 hp each 2. Drawworks : 2 x GE 752 motor 3. Mud Pumps : 2 x GE 752 motor 4. Rotary : 1 x GE 752 motor 5. Top Drive : Varco TDS 3

D) Mud System & Pump 1. Mud Pumps : 2 x National 12P-160 (1600 hp) 2. Mud Pits & Storage : 1300 bbls capacity, 25 bbl trip tank 3. Shale Shakers : Cascade shakers, Brandt dual tandem 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Derrick Hi-G Dryer 5. Centrifuge : None 6. Degasser : Derrick Vacu Flow

E) BOP Equipment 1. Accumulator : Ross Hill C -180 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : Hydril GL 13-5/8” annular, 5000 psi Hydril MSP 21-1/4” annular, 2000 psi Cameron U 13-5/8” double ram, 5000 psi Cameron U 13-5/8” single ram, 5000 psi

F) Safety Equipment : 80 Fire extinguishers, 1 fire pump, 3 gas detector, 10 H2S detector, 1 cascade system, 97 Scott SCBAs, 4 portable gas monitors, 7 eye wash stations, 1 shower at mud pits, 3 wind s ocks, 1 foam units, 2 breathable air compressor

G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2” Grade G, 24.7 lbs/ft, 5000’; 5” Grade G, 19.5 lbs/ft., 12,000’; 3-1/2” Grade G, 13.3 lbs/ft, 16,000’ 2. HWDP : 30 of 5-1/2”, 60 or 5”, 60 of 3-1/2” 3. Drill Collars (Spiral) : 12 of 9-1/2’, 24 of 8-1/2”, 18 of 6-1/2”, 24 of 4-3/4”

H) Design Criteria 1. Depth Capacity : 20,000’ 2. Max. Water Depth : 250 feet 3. Cantilever : 40’ Max. forward/backward movement : 10’ Transverse on each side from centerline of hole 4. Sub-Structure : Upper – 29’ (Derrick Floor to Base of Cantilever) Lower – 49’ (Derrick Floor to Base of the Hull) – 47’ (Base of Hull to Top of Jack Housing)

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3.2 PA-145 (OFFSHORE WORKOVER RIG) A) Years in Service : Manufactured in 1982

B) Rig Equipment

1. Drawworks : IDECO 1200 (1200 hp) 2. Derrick : 142’ x 21’ 3. Hook Load : 771,000 lbs 4. Top Drive : None 5. Rotary Table : 37 ½” 6. Blocks : 350 ton 7. Swivel : 300 ton 8. Sub-Structure : Cantilever 9. Geolograph : Totco 6 pin

C) Rig Power

1. Engine Power : 4 x Caterpillar 3991200 hp each 2. Drawworks : 1 DC motor, 1000 hp 3. Mud Pumps : 2 x GE 752, 1000 hp each 4. Rotary : 1000 hp 5. Top Drive : None

D) Mud System & Pump 1. Mud Pumps : 2 x Gardner Denver PZ-9 (1000 hp) 2. Mud Pits & Storage : 1300 bbls, 45 bbl trip tank 3. Shale Shakers : 2 x 1600 GPM 4. Desander/Desilter : 800 GPM each 5. Centrifuge : None 6. Degasser : SWACO

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 3-1/8” x 3000 psi 3. BOPs : 21-1/4” annular, 2000 psi 13-5/8” annular, 5000 psi 13-5/8” double ram, 5000 psi 13-5/8” single ram, 5000 psi

F) Safety Equipment : As per contract requirements

G) Drill Pipe & Drill Collars 1. Drill Pipe : 5” Grade E, 19.5 lbs/ft., 10,000’

: 3-1/2” Grade E, 13.3 lbs/ft., 10,000’ : 3-1/2” Grade G, 13.3 lbs/ft., 5000’

2. HWDP : 60 of 3-1/2” 3. Drill Collars : 60 of 3-1/2”, 12 of 9-1/2”, 30 of 8-1/4”, 30 of 6-1/4

30 of 4-3/4”

H) Design Criteria 1. Depth Capacity : 15,000’ 2. Max. Water Depth : 150 feet 3. Cantilever : 40’ Max. forward/backward movement : 8’ Transverse on each side from centerline of hole 4. Sub-Structure : Upper – 26.6’ (Derrick Floor to Base of Cantilever) Lower – 43.0’ (Derrick Floor to Base of the Hull) – 39.3’ (Base of Hull to Top of Jack Housing)

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3.3 SAR-201 (OFFSHORE RIG)

A) Years in Service : 1982

B) Rig Equipment 1. Drawworks : Emsco C2 (2000 hp) 2. Derrick : Pyramid 160’ 3. Hook Load : 1,300,000 lbs 4. Top Drive : Vargo TDS 3 5. Rotary Table : Emsco T3750, 37-1/2” 6. Blocks : 500 ton 7. Swivel : 500 ton 8. Geolograph : Martin Decker/Totco, 8-pen

C) Rig Power

1. Engine Power : 4 x Caterpillar D399 2. Drawworks : 2 x EMD M79, 750 hp each 3. Mud Pumps : 2 x EMD M79, 750 hp each 4. Rotary : 1 x EMD M79, 750 hp 5. Top Drive : 1 x GE 752 , 1000 hp

D) Mud System & Pump

1. Mud Pumps : 2 x Emsco FB 1600 (1600 hp) 2. Mud Pits & Storage : 1900 bbls 3. Shale Shakers : 3 x Derrick Flo-Line Cleaners 4. Desander : 1 x Brandt 5. Centrifuge : Mission Fluid, 11-1/2” impeller 6. Degasser : Brandt

E) BOP Equipment

1. Accumulator : Koomey 2. Choke Manifold : 3-1/8” 5000 psi WP, sour service 3. BOPs : Shaffer 30” annular 13-5/8” annular Cameron Type-U 13-5/8” single ram, 5000 psi Cameron Type-U 13-5/8” double ram, 5000 psi.

F) Safety Equipment : Saudi Aramco standard G) Drill Pipe & Drill Collars

1. Drill Pipe : 5” Grade G, 19.5 lbs/ft, 258 joints : 3-1/2” Grade G, 13.3 lbs/ft, 341 joints

2. HWDP : 112 of 5”, 90 of 3-1/2” 3. Drill Collars : 15 of 8-1/2”, 20 of 6-1/4”, 20 of 4-3/4”

H) Design Criteria 1. Depth Capacity : 20,000’ 2. Max. Water Depth : 230 feet 3. Cantilever : 60’ Max. forward/backward movement : 10’ Transverse on each side from centerline of hole 4. Sub-Structure : Upper – 32’ (Derrick Floor to Base of Cantilever) Lower – 18’ (Derrick Floor to Base of the Hull)

– 42’ (Base of Hull to Top of Jack Housing)

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3.4 SF-32 (OFFSHORE RIG)

A) Years in Service : Manufactured in 1983

B) Rig Equipment 1. Drawworks : National 1625 DE (2000 hp) 2. Derrick : Pyramid 160’ 3. Hook Load : 1,044,000 lbs 4. Top Drive : Varco TDS 4 5. Rotary Table : National C 375, 37-1/2” 6. Blocks : 650 ton 7. Swivel : 650 ton 8. Geolograph : Totco, 7 pen

C) Rig Power 1. Engine Power : 3 x EMD 16-645-E8, 2200 hp each 2. Drawworks : 2 x GE 752 motor 3. Mud Pumps : 2 x GE 752 motor 4. Rotary : 1 x GE 752 motor 5. Top Drive : 1 x GE 752 motor

D) Mud System & Pump 1. Mud Pumps : 2 x National 12P-160 (1600 hp) 2. Mud Pits & Storage : 1850 bbls capacity, 60 bbl trip tank 3. Shale Shakers : 2 x Cascade shakers, Brandt dual tandem 2 x Derrick Flo-Line Cleaners 4. Desander/Desilter : Demco 3 -cone Desander/Demco 16-cone Desilter 5. Centrifuge : None 6. Degasser : Swaco, 1200 gpm unit 7. Mud Cleaner : Brandt

E) BOP Equipment 1. Accumulator : Koomey Model 80 with 28 bottles 2. Choke Manifold : 4-1/16” 10,000 psi WP, sour service 3. BOPs : Shaffer Spherical 30”, 1000 psi Shaffer Spherical 21-1/4”, 2000 psi Cameron U 13-5/8” double ram, 10,000 psi Cameron U 13-5/8” single ram, 10,000 psi

F) Safety Equipment : Fire extinguishers, 2 fire pumps, fixed gas detector system, 1 cascade system, EISF, SCBAs, portable gas detectors, eye wash stations and showers, 3 wind socks, 2 breathing air compressor G) Drill Pipe & Drill Collars

1. Drill Pipe : 5-1/2” Grade G, 24.7 lbs/ft, 5000’.; 5” Grade G, 19.5 lbs/ft., 12,000’; 3-1/2” Grade G, 13.3 lbs/ft, 16,000’ 2. HWDP : 30 of 5-1/2”, 60 or 5”, 60 of 3-1/2” (all spiral) 3. Drill Collars (Spiral) : 12 of 10”, 24 of 8-1/4”, 18 of 6-1/2”, 24 of 4-3/4”

H) Design Criteria 1. Depth Capacity : 20,000’ 2. Max. Water Depth : 300 feet 3. Cantilever : 45’ Max. forward/backward movement : 12’ Transverse on each side from centerline of hole 4. Sub-Structure : Upper – 29’ (Derrick Floor to Base of Cantilever) Lower – 54’ (Derrick Floor to Base of the Hull) – 50’ (Base of Hull to Top of Jack Housing)

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RIG CONTRACTS 1.0 GENERAL INFORMATION

1.1 The Document 1.2 Conditions 1.3 Amendments

2.0 CONTENTS OF A RIG CONTRACT

2.1 Schedule “A” 2.2 Schedule “B” 2.3 Schedule “C” 2.4 Schedule “D” 2.5 Schedule “E” 2.6 Schedule “F” 2.7 Schedule “G” 2.8 Schedule “H”

3.0 ABIDING BY THE RIG CONTRACT

3.1 Responsibilities

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RIG CONTRACTS 1.0 GENERAL INFORMATION

1.1 The Document The contract is an agreement between Saudi Aramco (the Company) and the Contractor, which clearly defines the equipment and services that are to be provided by the Contractor to the Company. It also documents the Company’s obligations towards the Contractor. The contract consists primarily of a signed document with attached schedules, drawings, standard specifications, and any other pertinent references/documents.

1.2 Conditions The following are some key conditions of the existing rig contracts: A) The contract has a specified time limit, which means that the conditions

of the contract have to be met by both the Contractor and the Company for as long as the contract is in effect. At the end of the specified contract period, there usually is a provision to extend the contract at the discretion of the Company. At the end of the contract term, the Company has the option of not renewing the contract or renegotiating the contract for another term.

B) When the Company decides to terminate a contract at its own convenience, prior to the term expiration date, the contract provides for compensation payment to the Contractor at a pre-determined rate.

C) When there are disputes or different interpretation of the contract conditions by both parties, the contract provides for problem resolution through arbitration.

D) The contract is very specific in identifying the minimum equipment and services that are to be provided by the Contractor for drilling and working over wells with a rig. At the same time, the Company has certain responsibilities and obligations that are also spelled out in the contract. Section 2.0 below summarizes the key items of the contract.

1.3 Amendments

When an addition or change to the signed and approved contract is necessary, and waiting for end-of-term contract renewal is not an option, then an Amendment is issued. The Amendment can replace any clause or statement in the original contract and is valid until the contract is terminated

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or expires. It is important to note that an Amendment cannot take effect unless both the Company and the Contractor agree to the contents by signing the document.

2.0 CONTENTS OF A RIG CONTRACT

2.1 Schedule “A”, General Terms and Conditions

This section of the contract addresses the following:

A) Definition of terms used in the contract B) Qualification and requirements of Contractor’s personnel C) Access to well location by contractor D) Housing and medical responsibilities of Contractor for its personnel E) Inspection and testing of Contractor equipment F) Contractor’s warranty of defect-free equipment, materials and

workmanship G) Contractor’s and Saudi Aramco’s liabilities in cases of loss, damage,

and injury. H) Required Insurance coverage of the contractor. I) Contractor’s responsibility to prevent pollution and liability in case it

does occur. J) Both Contractor and Saudi Aramco will use tools, equipment or material

that have valid patents, trademarks and are not trade secrets of another company.

K) Claims settlement. L) Contractor’s and Saudi Aramco’s positions when work cannot be

performed due to uncontrollable situations such as storm, strikes, etc. This is known as ‘Force Majeure’.

M) Saudi Aramco’s recourse when the Contractor does not meet performance expectations.

N) Termination of contract for cause. O) Termination of contract at Saudi Aramco’s convenience. P) Contractor’s obligation to keep Saudi Aramco information confidential. Q) Limits of what the contractor can offer to Saudi Aramco employees so

as not to influence the awarding of any contract. R) Conditions under which work can be subcontracted out to a third party. S) Contractor’s obligation to obtain approval prior to releasing any

information from this contract for publicity reasons. T) Where possible, the contract should be translated into Arabic except for

sections C & G which are highly technical in nature.

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U) Contractor is responsible for conducting all Government relations activities within Saudi Aramco. If requested, Saudi Aramco may provide general guidance.

V) General provisions.

2.2 Schedule “B”, Scope of Work and Technical Provisions

A) Introduction. B) Contractor’s responsibility to drill, core, test complete, workover,

abandon and perform other rig operations. C) Well Programs: Saudi Aramco will provide the Well Programs, 18,000’

is the maximum drill depth unless agreed by both parties, some wells might be horizontal, Company shall notify Contractor at least 24 hours before rig release, and downhole tools and tubulars are subject to 0-8% H2S exposure. Casing: The Well Program will dictate the hole size, depth and size of casing to be run. The casing will be run and cemented per Program. Surveys: Sets the guidelines for single shot surveys in vertical and directional wells. Drilling Fluids: The Company will determine the type of drilling fluid to be used and the Contractor will maintain the fluid characteristics. Measurements: Contractor will measure drill string length with steel tape whenever requested by the Company.

D) Contractor shall be ready to commence operations on the date specified in this section.

E) Contractor shall perform the work on a 24 hour, 7-day a week basis. F) Contractor shall provide its own office and workshop facilities in a local

community. G) Contractor shall provide all services, equipment, machinery, tools,

instruments, materials, supplies, support personnel and labor when performing rig work.

H) Contractor is obligated to make all reports to and receive from the Company Representative on rig activities.

I) Contractor shall drill wells according to acceptable industry practices. Contractor will also clean location within 5 days of rig release or well abandonment.

J) If a hole is damaged or lost due to Contractor’s negligence, then reimbursement payment will be made to the Company.

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2.3 Schedule “C”, Contract Price and Payment Provisions

In this section of the contract, the following are covered: A) Contract pricing conditions B) Payable rates for mobilization, demobilization, daywork, special

daywork rate, downtime, rig and camp move rates, meals, force majeure, equipment and services

C) Termination for cause or at Saudi Aramco’s convenience D) Handling of Invoices and currency of payment E) Saudi Aramco’s rights to audit the contractor’s books and records F) Adjustment of rates and deductions/reimbursements of equipment and

services G) Setoff. This is Saudi Aramco’s right to deduct amounts that are due and

payable to the contractor The appendix at the end of this section contains the actual rig rates for labor related items and services performed.

2.4 Schedule “D”, Safe ty, Health and Environmental Requirements

The main topics covered in this section include:

A) General Provisions

?? Compliance with safety, health and environmental requirements ?? Deviations from Safety Requirements ?? Failure to comply ?? Saudi Aramco Assistance

B) Safety and Health Requirements

?? Loss prevention program ?? Work permits ?? Well control ?? Personnel safety ?? Welding and cutting equipment ?? Personal protective equipment ?? Tools and portable power tools ?? Cartridge operated tools ?? Electrical installations and equipment ?? Cranes and rigging equipment ?? Mechanical equipment ?? Saudi Aramco plant operations ?? Transportation

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?? Injury and damage reporting ?? Work over/or adjacent to water (Gulf) ?? Fire Prevention ?? Ionizing Radiation ?? First Aid Facilities ?? Explosives ?? Contractor Camps

C) Environmental Requirements

?? Introduction ?? Applicable Saudi Aramco and/or other engineering requirements ?? Waste management program ?? Water supply protection ?? Wastewater management ?? Spill control ?? Solid waste management

i) Waste disposal program ii) Containers and storage iii) Hazardous waste storage and handling iv) Method of collection v) Requirements for establishing a landfill disposal site vi) Classification of landfill disposal site vii) Solid waste disposal, site design and operations viii) Offshore disposal

?? Air pollution mitigation ?? Noise control

2.5 Schedule “E”, Settlement of Disputes, Arbitration and Choice of Law

This section of the contract defines the procedures for the Contractor to file a claim against the company. It also addresses the steps involved towards settling a claim through arbitration.

2.6 Schedule “F”, Taxes, Duties and Obligations

In this section, Contractor’s tax liabilities to the Kingdom are discussed, along with recourse when tax payments are delinquent. Also, custom clearance and duties, plus reimbursement to Saudi Aramco are presented.

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2.7 Schedule “G”, Saudi Aramco & Contractor Supplied Materials, Tools, Equipment and Services.

In this section, the following main points are addressed:

A) Contractor’s and the Company’s obligation statement to supply items

and services. B) The Company’s discretion of providing items for rent which the

Contractor is responsible for. C) Contractor’s obligation to rent items at the Company’s request. D) Inspection and reporting of defective items when the Contractor rents

items from the Company. E) Condition and maintenance of Contractor’s ancillary equipment. F) Care of materials, tools and equipment rented from the Company. G) Maintenance of Company supplied tools and equipment. H) Contractor’s right to obtain a refund on custom duties when re-exporting

tools and equipment OOK.

Attachment 1 is a detailed listing of the Contractor supplied minimum equipment and services. This includes A) Rig and Ancillary Equipment

Drawworks, power units, mud pumps, mast and substructure; BOP equipment, crown block, traveling block, hook, swivel; drill pipe elevators and slips; drill collar elevator and slips; kellys and kelly spinner; rotary table and top drive systems; spinning wrench; mud mixing unit, mud tanks, mud mixers, trip tank, flowline cleaners, desander, desilter, mud cleaners, rotary hoses, air hoist, etc.

B) Other Supplies and Equipment Drilling water, fuel and lubricants, potable water, safety equipment, internal communication, and mud material storage boxes.

C) Services Transportation for rig move and other equipment/materials, field camp facilities and requirements, and electrical repairs/maintenance of Company owned equipment at rig site.

D) Deep remote desert additional requirements One 30-ton minimum grove rough terrain crane (or equivalent) with 24-hour operator.

Attachment 2 itemizes the equipment and services that the company shall provide. These are A) Wash pipe, wash over shoes, handling tools, etc. B) Fishing tools C) Roads and locations D) Drilling water

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E) Radio equipment for communication F) Transportation G) Equipment not supplied by Contractor, as specified in the contract.

Drill pipe elevators and slips, back pressure valves and kelly cocks, drill pipe safety valves, drill pipe, drill collars and subs, and heavy weight drill pipe.

2.8 Schedule “H”, Special Terms and Conditions

This section covers the following:

A) Contractor workforce Saudization. B) The land which the Company has to provide to the Contractor for its use

as a yard, storage area and office structure. C) Right of the Company to extend term of the contract by one year. D) Payment conditions to the Contractor in case of early termination of

contract. E) Reaffirming Contractor’s handling and disposal of hazardous material in

accordance with acceptable industry practices. F) Contractor approval requirements prior to camp move. G) Financial penalties in case Contractor cannot commence on specified

date. H) The right for the Contractor to rent required tools/equipment from a third

party. I) The Company’s option to elect not to utilize the Topdrive unit.

3.0 ABIDING BY THE RIG CONTRACT

3.1 Responsibilities

The Workover/Drilling Foreman has the responsibility of ensuring the Contractor meets the contract obligations while drilling or working over a well. He should be very familiar with terms of the contract and ask his Superintendent for advice when unsure. He should know which piece of equipment or service is to be supplied by the Contractor, and which by the Company. Whenever he observes contract violations, it is his duty to notify the Contractor for immediate correction. If the violation is not corrected within a reasonable time, then the Workover/Drilling Foreman should highlight the problem to his Workover/Drilling Superintendent for further action.

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CHAPTER 2 WORKOVER PRACTICES SECTION A WELL LOCATIONS __________________________________________________________________________________________________________________________

WELL LOCATIONS 1.0 INTRODUCTION

2.0 CONSTRUCTION REQUIREMENTS

2.1 Preliminary Survey of Wellsite 2.2 General Specifications

2.2.1 Oil Well Locations 2.2.2 Gas Well Locations

2.3 Location Specifications for Different Rigs 2.4 Rig Campsite 2.5 Clean Up Operations

3.0 WELLSITE SAFETY REQUIREMENTS

3.1 General Spacing Requirements 3.2 Producing Wells in Populated Areas

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WELL LOCATIONS

1.0 INTRODUCTION

The well location must be modified for all onshore workovers requiring rig operations. This location modification involves constructing the wellsite to (a) accommodate rig dimensions/operations, and (b) comply with well safety requirements. This chapter will discuss the construction and wellsite safety requirements for Saudi Aramco onshore workover locations.

2.0 CONSTRUCTION REQUIREMENTS 2.1 Preliminary Survey

A preliminary survey of the wellsite location will be made by a Wellsites Representative and Workover Foreman. The following will be provided during the onsite survey: A) Location and dimensions of all relevant pits, changes in elevations, etc.

The Workover Foreman will determine the need and position of any or all pits.

B) Full sketch of wellhead, as viewed from the North, including the

following:

?? Ground level elevation ?? Top of bottom flange elevation ?? Flowline elevation at strip out point ?? Height of production tree

C) Condition of existing marl on location.

D) Condition of access road. E) Sketch of general layout of well location with respect to flowlines,

permanent structures, security fences, blacktop/skid roads, power cables, and pipelines.

F) Inspection of buried pipelines, power cables, and other obstacles.

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G) Determination of the camp location. If the camp will be moved with the

rig, then the Workover Foreman will approve the new campsite location. H) All scheduled Khuff/Pre-Khuff gas workovers will require a planning

meeting with S. A. Gas Engineering Division, Wellsites Engineering, Drilling & Workover Services, Engineering and Operations. Well Services The objective of the meeting is to define responsibilities regarding the surface facility, pipe lines, permanent security fences, access gates and general preparation of the location for the workover.

2.2 General Specifications for Workovers

2.2.1 Oil Well Locations

General specifications for wellsite construction on oil wells are as follows:

A) The finished location elevation should be the same as the

original location elevation. If the Workover Foreman requires a different elevation, the Workover Superintendent must approve the exception. If approved, the location should be constructed to the top of the required base level. Producing will re-manifold to this elevation (lowering the location after the workover will not be necessary.

B) The preferred orientation of the well location North/South, with

office pit to the North and drainage pit to the South.

C) The required well location sizes for the Saudi Aramco onshore workover rigs are as follows: SAR-103: 90m x 90m PA-194: 90m x 90m PA-303: 90m x 90m

D) Power water injection wells may require additional drainage area

and possible vacuum tanker access to the drainage area. The Workover Foreman during the preliminary survey should provide this requirement.

E) The necessity/position of any or all pits and additional drainage

to be designated by the Workover Foreman.

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F) Flare line and flare pit construction is in accordance with Saudi

Aramco Engineering Standard; SAES-B-062 dated January 23, 1995 for Onshore Wellsite Safety.

I) No loop road required for workover locations.

J) The finished location may require to be capped with 0.3m dry marl.

2.2.2 Khuff/Pre -Khuff Gas Well Locations

General specifications for wellsite construction on Khuff/Pre-Khuff gas wells are as follows: A) The required orientation of the well location is East/West with

drainage to South.

B) Khuff/Pre-Khuff gas well locations should be constructed within the 130m x 130m security fence.

C) All Khuff/Pre-Khuff gas well locations shall have a reserve pit

and two flare pits

D) Workover rigs with a box-on-box substructure (as PA-202, PA-203) are more suitable for rigging up over a Khuff production tree.

E) The existing water well(s) should be utilized.

F) The campsite should be 3-4kms, preferably North of drillsite

location. G) The gas buster dike will be constructed on the South side of the

location (305m long). H) The finished location should be capped with 0.3m dry marl and

0.15m wet compacted marl, if required. The campsite should be capped with0.3m dry marl.

I) Flare line and flare pit construction is in accordance with Saudi

Aramco Engineering Standard; SAES-B-062 dated January 23, 1995 for Onshore Wellsite Safety.

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2.3 Location Specifications for Different Rigs

The following diagrams illustrate the location layout and dimensions required for the active workover rigs currently operating in Saudi Aramco (also included are stacked rigs, which may be activated in the future).

Note: The location drawings of the Khuff/Pre-Khuff rigs indicate the drilling location size, but the rig is restricted to the 130m x 130m security fence (and other permanent structures) to perform workover operations. In addition, drawings with the second flare pit will be added in future manual updates.

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SAR-103 LOCATION: 90m x 90m

45m 45m

FLARE PIT

15m X 15m X 1.5m

60m Min. Distance

OFFICE PIT

45m x 4.5m x 0.5m

DRAINAGE PIT

15m x 15m x

1.5m

GARBAGE PIT

15m x 15m x

1.5m

37m 9m 9m

37m

15m

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PA-194 LOCATION: 90m x 90m

45m 45m

FLARE PIT

15m X 15m X 1.5m

60m Min. Distance

OFFICE PIT

45m x 4.5m x 0.5m

DRAINAGE PIT

15m x 15m x

1.5m

GARBAGE PIT

15m x 15m x

1.5m

37m 9m 9m

37m

15m

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PA-303 LOCATION: 90m x 90m

45m 45m

FLARE PIT

15m X 15m X 1.5m

60m Min. Distance

OFFICE PIT

45m x 4.5m x 0.5m

DRAINAGE

PIT

15m x 15m x 1.5m

GARBAGE PIT

15m x 15m x

1.5m

37m 9m 9m

37m

15m

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ADC-15 and 21 LOCATION: 152m x 136m

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DPS-43, 44, & 45

LOCATION: 152m x 136m

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PA-202

LOCATION: 152m x 136m

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PA-203

LOCATION: 150m x 130m

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PA-304

LOCATION: 152m x 136m

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NAD-70 LOCATION: 150m x 130m

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NAD-117 LOCATION: 152m x 136m

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SF-173 and 174 LOCATION: 161m x 133m

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2.4 Campsites

General specifications for campsite construction are as follows: A) The standard campsite for all rigs consists of 90m x 60m with a 0.30m

marl cap. B) The campsite should be within a distance of 5kms from the location. On

Khuff gas wells, the campsite shall be no less than 3-4kms and preferably North of the location.

C) Wellsites will determine if an existing campsite will fit the above

specifications or if a new campsite is to be constructed. D) A garbage pit and sump pit will be constructed at the campsite.

2.5 Clean Up Operations

Wellsite clean up operations will begin the day the rig moves to the next workover location. The goal of Wellsites Division is to complete the clean up no later than 7 days after the rig move. General specifications for clean up operations are as follows: A) Location and campsite will be graded if deeply rutted or badly marked. B) Any washouts or excavations on location will be filled with marl. C) All pits will be back filled with material from surrounding dikes (or sand if

dike material is not adequate) for both location and campsite. D) All refuse, garbage, and debris will be collected within 90m of the well

location and campsite. E) All cellars on Arab-D wells should be filled with sweet sand prior to rig

release. All cellars on Khuff wells should not be filled. F) Any re-usable drilling material remaining on the wellsite/campsite will be

noted and reported to the Wellsites Supervisor.

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3.0 WELLSITE SAFETY REQUIREMENTS

3.1 General Spacing Specifications

The following spacing requirements regarding wellsite safety are taken from Engineering Standard SAES-B-062 (as shown in Appendix 2A). These specifications apply to onshore oil/gas wells with shut-in wellhead pressure < 3600 psi. All oil/gas wells with shut-in wellhead pressure > 3600 psi and all gas injection wells are to be determined by a case by case basis, with concurrence with the Chief Fire Prevention Engineer. A) The minimum distance from an adjacent well to outer edge of wellsite

location shall be 105m. B) The minimum distances from flare pit to control point are as follows:

Flare pit to overhead power lines (150m) Flare pit to cathodic protection (105m) Flare pit to highway/camel fence/paved road/railroad (105m) Flare pit to above ground pipelines (60m) Flare pit to under ground pipeline (15m)

C) A minimum distance of 450m from wellsite to any of the following:

process areas; major shipping pump, blending/booster pump, or fire pump areas; tetraethyl lead (TEL) facilities; LPG loading racks; atmospheric or pressured vessels; boilers and power generation facilities; major electric distribution centers; buildings, property lines, and residential areas.

D) The minimum distance from oil/gas wells to overhead power lines is

200m. E) The minimum distance from oil/gas wells to cathodic protection or other

noncritical power lines is 105m. F) A minimum distance of 105m from oil/gas wells to any of the following:

right-of way, camel fence, Saudi Aramco or Government highway, paved roads, or railroads.

G) The minimum distance from oil/gas wells to pipelines is 105m. H) Water gravity injectors, power injectors, or supply wells must have a

105m spacing requirement from all other facilities.

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3.2 Producing Wells in Populated Areas

The following requirements apply to producing wells in populated areas. In addition, these requirements may also apply to wells that are located near areas of potential concern, such as roads, parking areas, or campsites. The Proponent Operating/Engineering Department shall determine whether these additional precautionary measures are taken. A) On oil wells, the upper wellhead master valve shall be a spring assisted

fail-safe Surface Safety Valve (SSV), triggered when an abnormally low pressure is sensed. Triggering by abnormally high pressure is required only when necessary to protect the downstream flowline. A fusible device with a melting point 30 degrees Celsius above the higher of the flowing wellhead temperature or maximum design ambient temperature shall be installed on the wellhead to trigger the SSV.

B) A Sub-Surface Safety Valve (SSSV) per API RP 14B specification shall be installed more than 60m below ground level in oil/gas wells. The SSSV shall be controlled by the low pressure pilot. Closure triggered by an abnormal condition in the high pressure piping downstream of the choke shall be provided when required by the Proponent Operating Department. A fusible device with a melting point 30 degrees Celsius above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to separately trigger the SSSV.

C) Wellsites in populated areas shall be enclosed by a fence meeting the

specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant. Two gates shall be 18m wide rig-access gates. The location of these rig-access gates will permit access to all wells on the wellsite.

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CHAPTER 2 WORKOVER PRACTICES SECTION B CASING

CASING 1.0 CASING DESIGN FACTORS 2.0 CASING INSPECTION

2.1 Khuff, Deep & Exploration Wells 2.2 Development Wells

3.0 SAUDI ARAMCO CASING DATA 4.0 KHUFF CASING & TUBING DATA

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CASING

1.0 CASING DESIGN FACTORS

Exact values of loading are difficult to predict throughout the life of the well. For example, if mud of 75 pcf is on the outside of the casing during the running of the casing, this value cannot be expected to remain constant for the entire life of the well. The mud will become deteriorated with time and will reduce this value to perhaps a saltwater value of 64 pcf. Therefore, calculations of burst values assuming a column of mud at 75 pcf are not realistic throughout the life of the well. If the initial casing design is marginal, then over a period of time a tubing leak may result in casing burst. Since casing design is not an exact technique and because of the uncertainties in determining the actual loading as well as the deterioration of the casing itself due to corrosion and wear, a safety factor is used to allow for such uncertainties in the casing design and to ensure that the rated performance of the casing is always greater than any expected loading. In other words the casing strength is always down rated by a chosen design factor value. The minimum casing design factors for Saudi Aramco are as follows:

The design factor is the ratio of the rated casing strength/resistance to the magnitude of the applied force/pressure. Note:

?? The biaxial effect to tension on casing collapse should be calculated in addition to using these design factors.

?? The biaxial effect of tension on casing burst is not required as this is an additional safety factor.

?? The minimum design factor for tension assumes bouyancy and applies to the weakest point (pipe body or joint strength).

?? Other assumptions (such as the extent of casing evacuation, H2S service and maximum SICP) will vary with the well type and casing string.

Collapse: 1.125 Tension: 1.6 Burst: 1.33

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2.0 CASING INSPECTION

2.1 Khuff, Deep & Exploration Wells The 36”, 30” and 24” casing will be externally coated with FBE (fusion bonded epoxy). The 18-5/8” casing will be externally coated FBE from the shoe to the DV. The 13-3/8” casing will be externally coated FBE from 8500’ to the upper DV. The rig crew should inspect all casing and tubing after shipment as follows:

?? Clean and visually inspect all threads. Use casing dope for thread compound.

?? Run API full length drift. ?? Visually inspect for overall damage.

The contracted inspection company (PWS, Vetco or other) should inspect all casing and tubing (13-3/8” and smaller) before shipment to the rig as follows:

?? Clean and inspect all threads. ?? Visually inspect for overall damage. ?? Electromagnetic inspection (4 functions); Longitudinal, Traverse,

Wall Thickness, Grade Verification

2.2 Development Wells

Prior to running the 13-3/8” casing and subsequent strings, insure that the following has been conducted.

?? Run full-length API drift. ?? Clean and visually inspect threads. ?? Visually inspect tubes for damage. ?? Use casing dope for thread compound.

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3.0 SAUDI ARAMCO CASING DATA SIZE WEIGHT GRADE CONNECTION I.D. DRIFT CONN. O.D. BURST COLLAPSE JT/ YLD

STRENGTH

in. ppf in. in. in. psi psi 1,000's lbs.

24 97.00 B SJ 23.25 - - - - - 24 176.00 X-42 VETCO-LS 22.624 22.250 25.500 2170 1080 2,116

18-5/8 87.50 J-55 BTC 17.755 17.567 19.625 2250 630 1,329 18-5/8 87.50 K-55 BTC 17.755 17.567 19.625 2250 630 1,367

13-3/8 61.00 J-55 STC 12.515 12.359 14.375 3090 1540 595 13-3/8 61.00 K-55 STC 12.515 12.359 14.375 3090 1540 633 13-3/8 68.00 J-55 STC 12.415 12.259 14.375 3450 1950 675 13-3/8 68.00 K-55 STC 12.415 12.259 14.375 3450 1950 718 13-3/8 68.00 J-55 BTC 12.415 12.259 14.375 3450 1950 1,069 13-3/8 68.00 K-55 BTC 12.415 12.259 14.375 3450 1950 1,069 13-3/8 72.00 L-80 STC 12.347 12.191 14.375 4550 2670 1,040 13-3/8 72.00 S-95 BTC 12.347 12.250 14.375 4930 * 3470 1,935

9-5/8 36.00 J-55 LTC 8.921 8.765 10.625 3520 2020 453 9-5/8 36.00 K-55 LTC 8.921 8.765 10.625 3520 2020 489 9-5/8 40.00 J-55 LTC 8.835 8.679 10.625 3950 2570 520 9-5/8 40.00 K-55 LTC 8.835 8.679 10.625 3950 2570 561 9-5/8 40.00 L-80 LTC 8.835 8.679 10.625 5750 3090 727 9-5/8 40.00 13CR L-80 LTC 8.835 8.679 10.625 5750 3090 727 9-5/8 43.50 L-80 LTC 8.755 8.599 10.625 6330 3810 813 9-5/8 47.00 L-80 LTC 8.681 8.525 10.625 6870 4760 893 9-5/8 53.50 S-95 BTC 8.535 8.500 10.625 9160 * 8850 1,477

7 23.00 J-55 STC 6.366 6.241 7.656 4360 3270 284 7 26.00 J-55 LTC 6.276 6.151 7.656 4980 4320 367 7 26.00 K-55 LTC 6.276 6.151 7.656 4980 4320 401 7 26.00 J-55 VAM 6.276 6.151 7.681 4980 4320 415 7 26.00 K-55 VAM 6.276 6.151 7.681 4980 4320 415 7 26.00 J-55 NVAM 6.276 6.151 7.681 4980 4320 415 7 26.00 K-55 NVAM 6.276 6.151 7.681 4980 4320 415 7 26.00 13CR L-80 LTC 6.276 6.151 7.656 7240 5410 511 7 35.00 L-80 LTC 6.004 5.879 7.656 9240 10180 734 7 35.00 L-80 VAM 6.004 5.879 7.681 9960 10180 725

5 15.00 K-55 Spec. Cl. BTC 4.408 4.283 5.375 5130 5560 241 5 15.00 13CR L-80 Spec. Cl. BTC 4.408 4.283 5.375 7460 7250 350

4-1/2 11.60 J-55 STC 4.000 3.875 5.000 5350 4960 154 4-1/2 11.60 J-55 LTC 4.000 3.875 5.000 5350 4960 162 4-1/2 11.60 13CR L-80 LTC 4.000 3.875 5.000 7780 6350 212 4-1/2 12.60 J-55 VAM 3.958 3.833 4.892 5790 5720 198 4-1/2 13.50 L-80 VAM 3.920 3.795 4.862 8540 9020 211

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NOTE: TABLE 3.0 SAUDI ARAMCO CASING DATA

[1] Internal yield values (*) listed on page 51 reflect the lower value for buttress

couplings. [2] Value provided is the minimum value, either pipe body strength or joint strength.

NOTE: TABLE 4.0 KHUFF CASING & TUBING DATA

[1] Internal yield values (*) listed on page 52 reflect the lower value for buttress

couplings. [2] Value provided is the minimum value, either pipe body strength or joint strength. [3] The RL-4S connector ID is less than that of the LS connector.

(RL-4S = 22.250” ID, LS = 22.624” ID)

[4] The Hydril PH-6 connector ID is less than that of the pipe body. (Conn. = 2.687” ID, Body = 2.750” ID)

? Tubulars that are being phased out. ? Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]

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4.0 KHUFF CASING & TUBING DATA SIZE WEIGHT GRADE CONN LENGTH wt. I.D. DRIFT CONN. O.D. BURST COLLAPSE JT/ YLD

STRENGTH

in. ppf range in. in. in. in. psi psi 1,000's lbs.

48 253 B BE 40’ 0.500 47.000 - 48.000 - - - 36 236 X-60 BE 40' 0.625 34.750 - 36.000 1822 254 - 30 234 X-42 SJ 55-60' 0.750 28.500 - - 1890 768 - 24 176 X-42 LS R-3 0.688 22.624 22.250 25.500 2170 1080 2,116 24 176 X-42 RL-4S R-3 0.688 22.25 (con) 22.125 25.250 2170 1080 2,116

18-5/8 115 K-55 BTC R-3 0.594 17.437 17.249 20.000 3070 1511 1,850

13-3/8 72 S-95 BTC R-3 0.514 12.347 12.250 14.375 4930 * 3470 1,935 13-3/8 72 NT-95HS NS-CC R-3 " " " 14.375 6390 3680 1,935 13-3/8 72 C-95VT N-VAM R-3 " " " 14.398 6390 3900 1,935 13-3/8 72 SM-95T N-VAM R-3 " " " 14.398 6390 3680 1,935 13-3/8 72 NKHC-95 NK-3SB R-3 " " " 14.375 6390 3890 1,973

13-3/8 86 NT-95HS NS-CC R-3 0.625 12.125 12.000 14.375 7770 6260 2,333 13-3/8 86 C-95VT N-VAM R-3 " " " 14.398 7770 6560 2,333 13-3/8 86 SM-95T N-VAM R-3 " " " 14.398 7770 6240 2,333 13-3/8 86 NKHC-95 NK-3SB R-3 " " " 14.375 7760 6500 2,333

9-5/8 53.5 S-95 BTC R-3 0.545 8.535 8.500 10.625 9160 * 8850 1,477 9-5/8 53.5 NT-90HSS NS-CC R-3 " " " 10.625 8920 9330 1,386 9-5/8 53.5 C-95VTS N-VAM R-3 " " " 10.650 9410 8960 1,477 9-5/8 53.5 SM-95TS N-VAM R-3 " " " 10.650 9410 9350 1,477 9-5/8 53.5 NKAC-95T NK-3SB R-3 " " " 10.625 9410 8940 1,477

9-5/8 58.4 NT-

105HSS NS-CC R-3 0.595 8.435 8.375 10.625 11900 12050 1,739

9-5/8 58.4 NT-110HS NS-CC R-3 " " " 10.625 11960 12870 1,857 9-5/8 58.4 P-110VT N-VAM R-3 " " " 10.650 11900 11880 1,857 9-5/8 58.4 SM-110T N-VAM R-3 " " " 10.650 11900 12800 1,857 9-5/8 58.4 NKHC-110 NK-3SB R-3 " " " 10.625 11900 12860 1,857

7 32 NT-95HSS NS-CC R-3 0.453 6.094 6.000 7.656 10760 11380 885 7 32 C-95VTS NVAM-MS R-3 " " " 7.732 10760 11160 885 7 32 SM-95TS NVAM-MS R-3 " " " 7.732 10760 11190 885 7 32 NKAC-95T NK-3SB R-3 " " " 7.772 10760 11150 885

? 7 35 L-80 NS-CC R-3 0.498 6.004 5.879 7.656 9960 10180 814

? 7 35 L-80 NVAM-MS R-3 " " " 7.805 9960 10180 814

? 7 35 L-80 NK-3SB R-3 " " " 7.772 9960 10180 814

? 5-1/2 23 L-80 N-VAM Tbg. Hngr 0.415 4.670 4.545 6.075 10560 11160 478

5-1/2 20 NT-95HSS NS-CC R-3 0.361 4.778 4.653 6.050 10910 11580 554 5-1/2 20 C-95VTS N-VAM R-3 " " " 6.075 10910 11410 554 5-1/2 20 SM-95TS N-VAM R-3 " " " 6.075 10910 11450 554 5-1/2 20 NKAC-95T NK-3SB R-3 " " " 6.050 10910 11400 554

? 4-1/2 15.1 L-80 N-VAM Tbg. Hngr 0.337 3.826 3.701 5.010 10480 11080 353

4-1/2 13.5 NT-95HSS NS-CC R-3 0.290 3.920 3.795 5.000 10710 11330 364 4-1/2 13.5 C-95VTS N-VAM R-3 " " " 4.961 10710 11090 364 4-1/2 13.5 SM-95TS N-VAM R-3 " " " 4.961 10710 11120 364 4-1/2 13.5 NKAC-95T NK-3SB R-3 " " " 5.000 10710 11080 364 4-1/2 13.5 L-80 N-VAM R-3 0.290 3.920 3.795 4.961 9020 8540 307 4-1/2 13.5 D-95HC HYDRIL TS R-3 " " " 4.719 10720 12070 300

? 4-1/2 13.5 KO-105T HYDRIL TS R-3 " 3.840(con) " " 10710 11280 295

3-1/2 12.95 L-80 HYDRIL PH-6 R-2 0.375 2.687(con) 2.625 4.313 15000 15310 295

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CHAPTER 2 WORKOVER PRACTICES

SECTION C RUNNING CASING AND LINERS ___________________________________________________________________________________________________________________________

RUNNING CASING AND LINERS 1.0 CASING RUNNING GUIDELINES

1.1 Hook Load Requirement 1.1.1 Hoisting System 1.1.2 Determining Maximum Pull

1.2 Equipment Inspection 1.3 Casing Inspection

1.3.1 Electromagnetic Inspection 1.3.2 Grade Verification 1.3.3 Thread Inspection 1.3.4 Drifting

1.4 Casing Tally 1.5 Float Equipment 1.6 Centralizers 1.7 Elevators 1.8 Casing Setting Depth

1.8.1 Wiper Trip 1.8.2 Strapping Out 1.8.3 Conditioning Trip 1.8.4 Pulling Wear Bushing 1.8.5 Drifting Inner String

1.9 Changing and Testing BOP Rams 1.10 Threadlock vs. Welding 1.11 Casing Make -up

1.11.1 Thread Lubricants 1.11.2 Make-up Torque

1.12 Fill Requirements 1.13 Running Speed 1.14 Breaking Circulation 1.15 Landing Casing

1.15.1 Setting Slips 1.15.2 Landing Load

2.0 ADDITIONAL GUIDELINES FOR RUNNING LINERS 2.1 General Instructions 2.2 Float Equipment and Landing Collar 2.3 Wiper Plugs 2.4 Liner Hanger 2.5 Cement Manifold 2.6 Fill Requirements 2.7 Running Speed

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2.8 Breaking Circulation 2.9 Setting Liner Hanger

3.0 FLOAT EQUIPMENT

3.1 Inner String Cementing 3.2 Float Shoe 3.3 Float Collar 3.4 Plug Set

4.0 MULTI-STAGE PACKER COLLAR

4.1 Tool Illustrations/Technical Data 4.2 Free Fall Plug Set 4.3 Displacement Type Plug Set

5.0 CENTRALIZERS

5.1 Collapsible 5.2 Rigid 5.3 SpiraGlider

6.0 LINER HANGERS

6.1 Mechanical-Set Liner Hanger 6.2 Hydraulic-Set Liner Hanger 6.3 Associated Equipment

6.3.1 Setting Collar/Tieback Sleeve 6.3.2 Liner Top Packer 6.3.3 Polished Bore Receptacle 6.3.4 Cementing Manifold

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RUNNING CASING AND LINERS

The purpose of this chapter is to present (1) casing running guidelines, (2) additional liner running requirements, and (3) down-hole equipment associated with these operations. 1.0 CASING RUNNING GUIDELINES

Casing has become one of the most expensive parts of a drilling program. Post well evaluations have shown that the average cost of tubulars is approximately 20% of the completed well cost. More importantly, if these tubulars are not run properly, the success of the entire well could be jeopardized. Thus, an important responsibility of the Workover/Drilling Engineer and Workover/Drilling Foreman is to develop and execute a casing running procedure that will result in minimal risk and ensure the success of the operation. The following casing running guidelines are provided to aid the Workover/Drilling Engineer and Workover/Drilling Foreman in developing a sound work plan for running casing. It must be noted that these guidelines are subject to specific well conditions. 1.1 Hook Load Requirement

The hoisting system capacity (mast, hook, traveling block, as well as the number and condition of lines) should be checked and compared to the calculated hook load for the next casing string. If additional lines are required, the string-up shall be done at least one trip prior to running casing.

1.1.1 Hoisting System

A hoisting system is a way of lifting heavy loads with a lighter lead line pulling force. As with a simple pulley system, the line strung through the blocks creates a mechanical advantage. This mechanical advantage is equal to the number of lines strung between the crown and traveling block. Thus for a 12-line system, without friction, a given weight can be lifted with a pulling force of 1/12 of the weight as shown in Figure 2C-1.

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Figure 2C-1

1.1.2 Determining Maximum Pull The fast line during hoisting has a somewhat greater load than the weight divided by the number of lines. This results from the friction of the sheave bearings and the bending of the line around the sheave. Since the fast line experiences the accumulation of frictional forces from all of the rotating sheaves, its load is the greatest and should be used when calculating design factors.

Fast Line

Dead Line

12 LINE HOISTING SYSTEM

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The fast line load can be calculated as follows,

L = W x Ks (K-1) Kn -1

where, L = Load on Fast Line (lbs) W = Total String Weight with *Overpull (lbs) K = 1.04 (coefficient of friction of roller bearing sheaves) n = Number of Lines s = Number of Sheaves Note:

s = n (for most rigs; since the deadline does not rotate) * Overpull = 50,000 -100,00lbs (margin for working stuck pipe)

Thus, the design factor can be calculated as follows,

DF = B L where, DF = Design Factor for Drilling Line

B = Nominal Catalog Breaking Strength (lbs) L = Load on Fast Line (lbs)

Note: Minimum Design Factor = 2.0 (when setting casing) When a drilling line is operated near its minimum design factor, care should be taken that the line and related equipment is in good operating condition. The Drilling Manager‘s approval is required for casing loads resulting in a design factor < 2.0 with maximum line capacity. Floating the casing to bottom may be a consideration.

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DESIGN FACTORS FOR VARIOUS NUMBER OF LINES AND HOOKLOADS (ALL CALCULATIONS BASED UPON NEW 6 x 19 IWC WIRE ROPE)

Design Factor

HOOK LINES FAST LINE 1” 1-1/8” 1-1/4” 1-3/8” 1-1/2” 1-5/8” 1-3/4” LOAD LOAD I.P. EIPS I.P. EIPS I.P. EIPS I.P. EIPS I.P. EIPS I.P. EIPS I.P. EIPS

200 M

6 8 10

(LBS) 38,200 29,600 24,600

2.3 3.0 3.6

2.7 3.5 4.2

3. 3.8 4.6

3.4 4.4 5.3

3.6 4.7 5.6

4.2 5.3 6.5

4.4 5.6 6.8

5. 6.5 7.8

5.2 6.7 8

6. 7.7 9.2

250M 6 8 10 12

47,750 37,000 30,750 26,500

1.9 2.4 2.9 3.4

2.1 2.8 3.4 3.9

2.4 3. 3.7 4.2

2.8 3.5 4.2 4.9

2.9 3.7 4.5 5.2

3.3 4.3 5.2 6.

3.5 4.5 5.3 6.3

4. 5.2 6.2 7.2

4.2 5.3 6.4 7.5

4.8 6.1 7.4 8.6

300 M 6 8 10 12

57,300 44,400 36,900 31,800

2. 2.4 2.8

2.3 2.8 3.2

2. 2.5 3. 3.5

2.3 2.9 3.5 4.1

2.4 3.1 3.7 4.4

2.8 3.6 4.3 5.

2.9 3.7 4.5 5.2

3.3 4.3 5.2 6.

4. 4.5 5.3 6.2

5.1 6.2 7.1

350 M 6 8 10 12

66,850 51,800 43,050 37,100

1.7 2.1 2.4

2. 2.4 2.8

2.2 2.6 3.

2.5 3. 3.5

2.1 2.7 3.2 3.7

2.4 3.1 3.7 4.3

2.5 3.2 3.9 4.5

2.9 3.7 4.5 5.2

2.9 3.8 4.6 5.3

3.4 4.4 5.3 6.1

4.4 5.3 6.2

5.1 6.0 7.1

5.1 6.2 7.1

5.9 7.1 8.2

400 M 8 10 12

59,200 49,200 42,400

1.8 2.1

2.1 2.4

1.9 2.4 2.7

2.2 2.6 3.

2.3 2.8 3.3

2.7 3.2 3.8

2.8 3.4 3.9

3.2 3.9 4.5

3.3 4. 4.6

3.8 4.6 5.3

3.9 4.6 5.3

4.5 5.3 6.2

4.5 5.4 6.3

5.2 6.2 7.2

450 M 8 10 12

66,600 55,350 47,700

2.0 2.3

2.3 2.7

2.0 2.5 2.9

2.4 2.8 3.3

2.5 3.0 3.5

2.8 3.4 4.0

2.9 3.6 4.1

3.4 4.1 4.8

3.4 4.2 4.8

4.0 4.8 5.5

4.0 4.8 5.5

4.7 5.5 6.4

500 M 8 10 12 14

74,000 61,500 53,000 47,500

1.8 2.1 2.3

2.1 2.4 2.7

1.9 2.2 2.6 2.9

2.1 2.6 3. 3.3

2.2 2.7 3.1 3.5

2.6 3.1 3.6 4.0

2.7 3.2 3.7 4.1

3.1 3.7 4.3 4.8

3.1 3.7 4.2 4.8

3.6 4.3 5.0 5.5

3.6 4.3 5.0 5.6

4.1 5.0 5.7 6.4

600 M 8 10 12 14

88,800 73,800 63,600 57,000

1.8 2.0

2. 2.2

1.9 2.2 2.4

2.1 2.5 2.8

1.9 2.2 2.6 2.9

2.1 2.6 3. 3.3

2.2 2.7 3.1 3.4

2.5 3.1 3.6 4.0

2.6 3.1 3.6 4.0

3.0 3.6 4.1 4.6

3.0 3.6 4.2 4.6

3.4 4.1 4.8 5.3

700 M 8 10 12 14

103,600 86,100 74,200 66,500

1.8 2.0

2.1 2.4

1.9 2.2 2.5

2.2 2.6 2.8

1.9 2.3 2.7 2.9

2.2 2.6 3.1 3.4

2.2 2.7 3.1 3.4

2.5 3.0 3.5 3.9

2.5 3.1 3.6 4.0

3.0 3.5 4.1 4.6

800 M 8 10 12 14

118,400 98,400 84,800 76,000

1.7 1.97 2.2

1.95 2.28 2.53

2.0 2.3 2.6

2.3 2.7 3.0

1.9 2.3 2.7 3.0

2.2 2.6 3.1 3.4

2.2 2.7 3.1 3.5

2.6 3.1 3.6 4.0

900 M 8 10 12 14

133,200 110,700 95,400 85,400

1.75 1.96

1.74 2.01 2.25

1.79 2.08 2.32

1.70 2.05 2.39 2.67

1.87 2.41 2.7

1.9 2.3 2.7 3.1

2.0 2.3 2.8 3.1

2.3 2.7 3.2 3.58

1000 M 10 12 14 16

123,000 106,000 95,000 86,000

1.81 2.02

1.86 2.08 2.3

1.85 2.15 2.4 2.6

1.89 2.17 2.42 2.6

2.14 2.5 2.78 2.8

2.16 2.51 2.80 2.8

2.49 2.89 3.22 3.5

Note: 1. This table is based upon Extra Improved Plow and Improved Plow drilling line (with independent wire rope cores). 2. If a well is highly deviated (with high drag forces), an overpull (50,000 to 100,000 lbs) may be desired. In this case,

the overpull margin must be added to the calculated casing weight to determine the maximum hook load.

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1.2 Equipment Inspection

A complete field inspection by magnetic particle method of elevators, bails, spiders, slips, and hook shall be performed on each rig at least annually. This inspection should be carried out prior to the job on extremely heavy casing loads where minimum design factors are approached.

1.3 Casing Inspection

1.3.1 Required Electromagnetic Inspection

Be aware of the required casing inspection and that it is detailed in the drilling program. If electromagnetic inspection is required, this must be specified by the Workover/Drilling Foreman when the casing is ordered from the Dispatcher and performed by the inspection company prior to delivery to the rigsite. 1.3.2 Visual Casing Grade Verification

The API color codes listed below are used for all sizes/weights of casing and tubing to identify the grade. This color code identification is located on the casing coupling. Casing Grade Verification:

P110 - One White Band C95 - One Yellow Band

N80 - One Red Band C75 - One Blue Band K55 - One Green Band H40 - No Marking

Weight and grade identification may also be stenciled on the pipe body.

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1.3.3 Visual Thread Inspection When the casing is delivered and racked by grade, remove protectors and thoroughly clean casing threads. Visually inspect threads for damage or manufacturing defects. Re-install thread protectors if pipe is to be moved.

1.3.4 Drifting Drift casing with API full-length drift. Defective joints are to be clearly marked and removed to a separate area.

1.4 Casing Tally The casing is tallied by layer and numbered appropriately, in order in which the joints are to be run. The casing tally should be independently checked by both the Toolpusher and Workover/Drilling Foreman. Thread protectors shall be replaced to avoid damage during handling. A running list is essential and should include the following:

? ? Joints to be excluded. ? ? Amount of stick-up above rotary table. ? ? Position of casing collar in BOP stack. ? ? Location of centralizers. ? ? Change points for casing grade. ? ? Location of DV’s (if required). ? ? Location of marker joints (if required). ? ? Location of Float Equipment.

1.5 Float Equipment

The float equipment should be made-up and threadlocked (along with the entire shoe track) in the rotary table with power tongs to ensure the proper torque is applied. This procedure involves only threadlocking the field-end of the casing coupling (as the mill-end of the coupling is not threadlocked). Historically, this procedure has proven effective. If casing back-off is a concern, casing couplings on the shoe track should be removed, threadlocked, and retorqued at float equipment vendor’s facility. As an alternative, multi-stage packer collars (DV’s) could also be made-up with (2) short joints at vendor’s facility to reduce rig time while handling and making up.

All float equipment, multi-stage packer collar(s), opening bombs, and associated plugs shall be visually checked once on location.

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1.6 Centralizers

Install centralizers on the rack in the middle of the appropriate joints as per running list.

1.7 Elevators

All casing lifting/setting equipment shall be visually inspected prior to the job. If ‘side door’ elevators are to be used, check for uneven wear and verify that the casing load will be uniformly distributed over the face of the casing coupling. When ‘side-door’ elevators are in use, avoid impact loading which can open this type of elevator. Care must be taken when running centralizers through the BOP stack and wellhead. If ‘side door ‘ elevators are used to start a heavy casing string, always switch to ‘slip type’ elevators before entering the open hole. The ‘slip type’ elevator is recommended for long heavy casing strings. If ‘slip type’ elevators are to be used, the spider and elevator slips should be examined and verified for even distribution. The spider must be level for proper operation and load distribution. If the slips contact unevenly, there is a possibility of denting or slip-cutting the pipe. Also, the spider and elevator slips should be clean and sharp.

1.8 Casing Setting Depth

Casing setting depth (in reference to re-entry sidetracks or deepenings) is generally referenced to a formation top. Occasionally the drill bit will quit or experience extremely low ROP just prior to reaching the projected depth. In these situations, the Workover/Drilling Engineer should consult with Geology or Reservoir Engineering regarding the following options:

? ? Obtaining approval for a revised casing point. ? ? Logging at this depth and drilling additional rat hole, if required. ? ? Continuing drilling to original casing point. 1.8.1 Wiper Trip The mud shall be conditioned to the desired properties. Controlled fluid loss and Torq-Trim additions are required on deviated/horizontal wells where differential sticking is a concern. A flow check should performed prior to pulling out of the hole. The wiper trip shall be made to the previous casing shoe and the trip tank monitored to ensure the hole is stable. After running back to bottom, circulate bottoms-up and pull out of the hole. A flow check should also be conducted at the casing shoe and again at the drill collars.

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1.8.2 Strapping Out

The casing setting depth must be checked by strapping-out of the hole at least once prior to logging or running casing. If this measurement does not agree with hole depth, the pipe should be re-strapped.

1.8.3 Conditioning Trip

A conditioning trip should be planned prior to running casing if hole problems were encountered during logging or if the logging program required additional time (>10 hours). This decision is made on location by the Drilling Foreman.

1.8.4 Pulling Wear Bushing The wear bushing must be retrieved after the last trip out of hole with the drill string prior to running casing.

1.8.5 Drifting Inner String

On inner string cementing operations, all drill pipe being used as the inner string should be drifted with the correct size ‘rabbit’ to ensure adequate clearance for the drill pipe latch down plug.

1.9 Changing and Testing BOP Rams

Casing rams shall be installed on all Class ‘A’ BOP stacks prior to running casing. The pressure test will consist of testing the casing rams with a joint of casing connected to the test plug with appropriate crossover.

The annular will be used as casing rams on all Class ‘B’ BOP stacks, since the blind rams are on top of the master pipe rams.

1.10 Threadlock vs. Welding

All heat treated casing (C75 and above) shall not be welded, as mechanical properties can be altered through welding operations. The shoe track should be welded (for H40, X42, J55, K55, material) and threadlocked (for C75, L80, N80, C95, S95, etc.). Apply ‘threadlock’ to the pin-end only and wipe off excess to prevent threadlock from falling inside the float equipment. Threadlock has a greater friction factor than thread compound; consequently, a higher make-up torque is required (see Section 1.11.1 of this chapter).

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1.11 Casing Make -Up The actual casing make-up is a function of the applied make-up torque and the thread lubricant used. This assumes the torque gauge is properly calibrated.

1.11.1 Thread Lubricants

An API Modified thread compound with a friction coefficient of 1 shall always be used. All published make-up torque values assume a friction factor of 1. Thread protectors should be removed on the rig floor and thread lubricant applied to pin-end only prior to stabbing each joint. The table below shows the associated friction factors for thread compounds and threadlock used by Saudi Aramco.

Thread Compound Friction Factor Wfd Lube Seal 1.0 Bestolife 270 1.0 Wfd Tube Lok 1.5

Note: Actual Torque = Torque Reading x Friction Factor

1.11.2 Make-Up Torque Use only the recommended make-up torque and ensure that each joint of casing is correctly made up. The optimum make-up torque value is recommended at all times. Although if several threads are exposed when the optimum torque is reached, apply additional torque to the maximum torque value. In addition, if the make-up is such that the thread vanish point is buried two thread turns and the minimum torque value is not reached, the joint should be treated as a bad joint and moved to a separate area. Make-up for Buttress Thread Connections (BTC) should be determined by carefully noting the torque required to make-up several connections to the base of the triangle. Having established this torque value, the remainder of that weight and grade of pipe in the string can be made up accordingly. The make-up tolerance is + 3/8” measured from the base of the triangle, providing that the make-up torque is reached.

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The following table below shows the recommended make-up for the casing and tubing commonly used by Saudi Aramco.

RECOMMENDED MAKE-UP TABLE SAUDI ARAMCO NON-PREMIUM CASING/TUBING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

CONDUCTOR CASING 48” 0.500" wt. 253.65# GR-B, R-3, BE - WELD - 36” 0.625" wt. 236.15# GR-B, R-3, BE - WELD -

30” 0.500" wt. 157.50# X-42, 55/60', SJ - WELD - 30” 0.750" wt. 234.30# X-42, 55/50', SJ - WELD - 30” 0.750" wt. 239.00# X-42, 55/60', JV-LW 26,000 29,000 32,000 24” 97.00# GR-B, R-3, SJ - WELD - ? 24” 0.688” wt. 176.00# X-42, R-3, V-LS 24,000 26,000 28,000 24” 0.688” wt. 176.00# X-42, R-3, V-RL4S 24,000 26,000 28,000 CASING and TUBING 18-5/8” 87.50# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 18-5/8” 115.00# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

13-3/8” 61.00# J-55, R-3, STC 4,460 5,950 7,440 13-3/8” 61.00# K-55, R-3, STC 4,750 6,330 7,910 13-3/8” 68.00# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 13-3/8” 72.00# L-80, R-3, STC 7,720 10,290 12,860 13-3/8” 72.00# S-95, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

9-5/8” 36.00# J-55, R-3, LTC 3,400 4,530 5,660 9-5/8” 36.00# K-55, R-3, LTC 3,670 4,890 6,110 9-5/8” 40.00# J-55, R-3, LTC 3,900 5,200 6,500 9-5/8” 40.00# K-55, R-3, LTC 4,210 5,610 7,010 9-5/8” 40.00# L-80, R-3, LTC 5,450 7,270 9,090 9-5/8” 43.50# L-80, R-3, LTC 6,100 8,130 10,160 9-5/8” 47.00# L-80, R-3, LTC 6,700 8,930 11,160 9-5/8” 53.50# S-95, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

7” 23.00# J-55, R-3, LTC 2,350 3,130 3,910 7” 26.00# J-55, R-3, LTC 2,750 3,670 4,590 7” 26.00# K-55, R-3, LTC 3,010 4,010 5,010 7” 26.00# K-55, R-3, NVAM 6,510 7,230 7,950 ? 7” 26.00# K-55, R-3, OLD VAM 8,000 8,700 10,100

5” 15.00# K-55/L-80, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 4-1/2” 11.60# J-55, R-3, STC 1,160 1,540 1,930

4-1/2” 11.60# L-80, R-3, LTC 1,670 2,230 2,790 4-1/2” 11.60# J-55, R-3, OLD VAM 4,300 4,700 5,100 ? 4-1/2” 12.60# J-55, R-2, NVAM 3,190 3,540 3,890 ? 4-1/2” 12.60# J-55, R-3, OLD VAM 4,300 4,700 5,100 4-1/2” 12.60# L-80-13CR, R-3, FOX - 4,120 -

3-1/2” 9.30# J-55, R-2, EUE 1,710 2,280 2,850 2-7/8” 6.50# J-55, R-2, EUE 1,240 1,650 2,060 2-3/8” 4.70# J-55, R-2, EUE 970 1,290 1,610

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SAUDI ARAMCO PREMIUM CASING and TUBING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

? 13-3/8” 72.00# C -95VT/ SM-95T, R-3, NVAM 14,400 15,900 17,400 13-3/8” 72.00# NKHC-95, R-3, NK-3SB 16,000 20,000 24,000 13-3/8” 72.00# NT-95HS, R-3, NS-CC 13,100 14,800 16,600 ? 13-3/8” 86.00# C -95VT/ SM-95T, R-3, NVAM 14,400 15,900 17,400 13-3/8” 86.00# NKHC-95, R-3, NK-3SB 16,000 20,000 24,000 13-3/8” 86.00# NT-95HS, R-3, NS-CC 13,100 14,800 16,600 ? 9-5/8” 53.50# C-95VTS/SM-95TS, R-3, NVAM 14,400 15,900 17,400 9-5/8” 53.50# NKAC-95T, R-3, NK-3SB 13,200 16,500 19,800 9-5/8” 53.50# NT-90HSS, R-3, NS-CC 9,500 10,800 12,300 ? 9-5/8” 58.40# P-110VT/ SM-110T, R -3, NVAM 14,400 15,900 17,400 9-5/8” 58.40# NKHC-110, R-3, NK-3SB 13,600 17,000 20,400 9-5/8” 58.40# NT-105HS/-110HS, R-3, NS-CC 10,200 11,700 13,300 ? 7” 26.00# K-55, R-2, NVAM 6,510 7,230 7,950

? 7” 32.00# C-95VTS/ SM-95TS, R-3, NVAM 9,850 10,850 11,850 7” 32.00# NKAC-95T, R-3, NK-3SB 8,800 11,000 13,200 7” 32.00# NT-95HSS, R-3, NS-CC 6,600 7,600 8,600 ? 7” 35.00# L-80, R-3, NS-CC 6,900 8,000 9,000 ? 7” 35.00# L-80, R-3, NK-3SB 9,600 12,000 14,400 ? 7” 35.00# L-80, R-3, NVAM MS 9,500 10,500 11,500 ? 7” 35.00# L-80, R-3, HYDRIL SUPER-EU 8,500 9,560 10,625 ? 7” 35.00# L-80, R-3, AB IJ-4S - 10,000 - ? 5-1/2” 20.00# C-95VTS/SM-95TS, R -3, NVAM 6,120 6,800 7,480 5-1/2” 20.00# NKAC-95T, R-3, NK-3SB 5,760 7,200 8,640 5-1/2” 20.00# NT-95HSS, R-3, NS-CC 5,100 5,900 6,800 ? ? 5-1/2” 23.00# L-80, R-3, NVAM 7,170 7,960 8,750

? 4-1/2” 12.60# J-55, R-2, NVAM 3,190 3,540 3,890 ? 4-1/2” 13.50# L-80, R-3, NVAM 4,430 4,920 5,410 ? 4-1/2” 13.50# C-95VTS/ SM-95TS, R-3, NVAM 5,080 5,640 6,200 4-1/2” 13.50# NKAC-95T, R-3, NK-3SB 3,520 4,400 5,280 4-1/2” 13.50# NT-95HSS, R-3, NSCT 2,900 3,600 4,300 ? 4-1/2” 13.50# KO-105T, R-3, HTS 4,200 4,725 5,250 ? ? 4-1/2”15.10# L-80, R-3, NVAM 5,210 5,790 6,370 3-1/2” 12.95# L-80, R-2, HYDRIL PH-6 5,500 6,185 6,875

2-7/8” 6.40# J-55, R-2, NSCT-SC 1,160 1,340 1,520 2-7/8” 8.70# L-80, R-2, HYDRIL PH-6 3,000 3,375 3,750

? 2-3/8” 4.70# L-80, R-2, AB FL-4S - 500 - 2-3/8” 4.70# L-80, R-2, HYDRIL CS 1,500 1,685 1,875 2-3/8” 5.80# L-80, R-2, NVAM 1,500 1,660 1,820 2-3/8” 5.90# L-80, R-2, HYDRIL PH-6 2,200 2,475 2,750 Note: ? Tubulars that are being phased out.

? Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]. The use of a make-up monitoring system (Jam, Torque/Turn, etc.) should be used on all production

tubing strings with specialty connections to ensure a more accurate make-up.

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1.12 Fill Requirements The casing string should be filled every joint while running and topped off every 10 joints, or otherwise dictated by casing collapse calculations (based on evacuated casing and a full column of mud in the annulus). In no case shall the hydrostatic pressure inside the casing be less than reservoir pressure due to infrequent filling (this could result in a kick if the float equipment fails while running the casing).

Note: The Khuff/Pre-Khuff rigs with top drives have installed a short joint on

the top drive to fill the casing faster and reduce mud spillage on the rig floor.

1.13 Running Speed

Casing should be run smoothly. Avoid high acceleration and deceleration, which can cause high surge/swab pressures. The casing running speed should be regulated to approximately 30 seconds per joint or otherwise dictated by surge pressure calculations.

The Driller should be aware of tight spots on the previous trip out of the hole and any problem zones, which could result in stuck pipe or loss circulation while running casing. If tight hole is encountered while running with the casing, a circulating sub should be installed to wash the casing down. ?? If the casing can not be run deeper due to hole conditions, the Drilling

Foreman should inform the Drilling Superintendent and Drilling Engineer. Drilling Engineering and the Superintendent will determine if (1) the casing can be set at this depth or (2) the casing should be laid down and a clean out trip made.

?? If the casing is stuck, the grease pills should be spotted in an attempt to

free the pipe. If unsuccessful, the casing must be cemented in place at the stuck point. Cementing the pipe high is not desirable, as it increases the risk of successfully drilling the next hole section with more zones exposed. This has led to abandoning the well and skidding the rig on some situations where the entire RUS and UER had to be drilled together. Sticking problems have occurred in the following formations:

RUS (Arab-D and Khuff/Pre-Khuff wells) Wasia Shale (Arab-D and Khuff/Pre-Khuff wells) Wara Shale (Shaybah wells) Khafji Stringer (Offshore Horizontal wells)

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1.14 Breaking Circulation

Circulation should be established while running casing as follows,

? ? After running in with the shoe track. ? ? Upon reaching casing shoe depth. ? ? Upon encountering tight hole (if any). ? ? Upon reaching 1-2 joints before TD (for circulating down).

Note: Break circulation slowly. Once total depth is tagged, the casing should be picked up 1-2 feet and free hanging weight recorded. Circulate hole at least one full circulation while recording circulating pressures and rates. Reciprocate casing as specified in the drilling program.

1.15 Landing Casing

Once the casing has been cemented, the BOP stack will be nippled down and raised to set the casing slips. On multi-stage cement jobs, the slips will be set prior to cementing the last stage. 1.15.1 Setting Slips

Do not drop casing slips through the BOP stack. The following problems can occur with this practice,

? ? Slips hanging up in the BOP stack. ? ? Slips stopping on a casing collar (if collar is positioned in stack). ? ? Slips misaligned preventing improper setting.

On single stage cementing, set casing slips as follows, A) Displace cement and bump plug. B) Check for flow-back and verify well is stable. C) Pick-up BOP stack. D) Set casing slips.

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On multi-stage cementing, set casing slips as follows,

A) Displace 1st stage (and 2nd, if 3 stage job) cement with mud. B) Open upper most DV. C) Circulate hole clean with mud. D) WOC. Verify well is static. E) Pick-up BOP stack. F) Set casing slips prior to cementing final stage.

1.15.2 Landing Load

A proper casing landing load is required to avoid excessive or unsafe tensile stresses during the life of the well. The casing should be landed in the casing spool in approximately the same “as cemented” position (no pick-up or slack-off) unless otherwise dictated by landing calculations. A casing string pick-up of less than 6” to set the casing slips is recommended. This pick-up will allow setting the casing slips in the “as cemented” position and will not damage or release the multi-stage packer collar. Cementing the production casing to surface and setting the casing slips in the “as cemented” position will avoid buckling problems (associated with excessive slack-off and changes in well temperature during production). Khuff and Pre-Khuff wells utilize a reinforced support unit which is attached to the casing head to distribute excessive casing loads directly to the cellar floor.

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2.0 ADDITIONAL GUIDELINES FOR RUNNING LINERS

Liners are casing strings that do not extend to the surface but are suspended from the bottom of the previous casing string. A drilling liner is similar to intermediate casing in that it serves to isolate troublesome zones (abnormally pressured zones, weak formations, borehole instability, etc.) during the drilling operation. A production liner is set through the productive interval of the well. Production liners may be tied back to the surface, if required. Advantages of liners as compared to casing are as follows, ? ? Lowers tangible cost. ? ? Reduces tensile running load (may overcome rig limitation). ? ? Eliminates a casing spool requirement on the wellhead. ? ? Allows use of larger production tubing above liner top (if no tie-back).

The following discusses the additional guidelines associated with running drilling or production liners. These guidelines are subject to well conditions and the specific liner hanger equipment utilized.

2.1 General Instructions

A) When running short liners, be aware of the buoyant conditions. If floating is anticipated, consider using hold-down slips on the liner hanger or loading the liner with weighted mud to offset the buoyant force.

B) Drift all drill pipe, crossovers, liner hanger, and setting tools required in

running the liner with the correct size drift to ensure the passage of the drill pipe wiper plug. Rabbit the drill pipe on the conditioning trip prior to running the liner. If the rabbit hangs up in any joint, leave that joint out of the string. Ensure the exact quantity of drill pipe in the derrick is known.

C) The Workover/Drilling Foreman, Toolpusher, and Liner Company

serviceman should compare all pipe figures and displacement calculations.

D) Check the length of the liner versus the drill pipe and collars to be left

out of the hole. As soon as the liner is landed, the number of remaining joints of drill pipe in the derrick should be counted to verify that the liner is on bottom.

E) Install a drill pipe wiper rubber on the drill pipe string while running in

the hole to prevent foreign objects from falling into the wellbore.

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F) The liner cement shall be batch-mixed and displaced using the cement company pump truck. Further details on cementing operations are covered in Chapter 2D of this manual.

2.2 Float Equipment and Landing Collar

Visually inspect all liner float equipment and ensure that they are compatible with the liner hanger equipment and running procedures. The liner company service representative on location should verify the proper ‘shear pressure’ of the ballseat in the landing collar and that the ball is compatible with the seat.

2.3 Wiper Plugs Visually inspect wiper plugs and ensure the drill pipe wiper plug is compatible with the liner wiper plug.

2.4 Liner Hanger

The liner hanger will be inspected, measured, and pre-assembled on the setting tool (complete with liner wiper plug) at the liner shop prior to shipping to the rig. Once the complete liner assembly is on location, a visual inspection should be made and no damage has occurred during transportation. The liner company service representative on location should ensure the proper ‘liner setting’ shear pins are installed. In addition, be aware of the liner hanger operation, method of make-up, running procedure, and procedures to follow in the event of an equipment failure, as directed by the Liner Company serviceman on location.

2.5 Cement manifold Visually inspect the cement manifold along with the liner assembly when it arrives on location. Load the drill pipe wiper plug in the manifold after performing the torque/drag test at the casing shoe (before going into open hole with the liner). Pick up the cement manifold approximately + 30’ from TD. Install the manifold and circulate down to TD. Ensure that lines are hooked-up and ready for immediate reversing (once the cement job is complete).

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2.6 Fill Requirements The liner should be filled every 10 joints or otherwise dictated by liner collapse calculations (based on evacuated casing and a full column of mud in the annulus). Fill the drill pipe at least every 5 stands and check to ensure that the correct amount of fluid required is pumped. In no case shall the hydrostatic pressure inside the liner be less than reservoir pressure due to infrequent filling (this could result in a kick if the float equipment fails while running the liner).

2.7 Running Speed

Control the running speed to reduce high surge pressure created by the small annular clearances associated with liners. The running speed should be regulated to approximately 30 seconds per joint for the liner and 60 seconds per stand for the drill pipe, or otherwise dictated by surge pressure calculations.

The Driller should be aware of tight spots on the previous trip out of the hole and any potential loss circulation zones that could be affected by high running speed.

2.8 Breaking Circulation

Circulation should be established while running the liner as follows,

? ? After running in with the shoe track. ? ? After installing the liner hanger, pick up one stand of drill pipe and slack

off until the liner hanger assembly is below the BOP stack. Circulate one complete liner capacity plus 25%. Ensure that the circulating pressure does not exceed 75% of the pressure required to set the liner hanger.

Record the weight on the liner on the weight indicator.

? ? Upon reaching casing shoe depth, break circulation and ensure that the circulating pressure does not exceed 75% of the pressure required to set the hanger.

Perform torque/drag test and record data. Load the drill pipe wiper plug.

? ? Upon encountering tight hole (if any). ? ? Upon reaching approx. 30’ from TD (for circulating down).

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Note: Break circulation slowly as high pump rates can break down weak formations due to small annular clearances.

Once total depth is tagged, the liner should be picked up 1 to 2 feet. Record the free hanging weight of liner and drill pipe. Circulate hole at least two full circulation volumes while ensuring that the pump pressure does not exceed 75% of the pressure required to set the hanger. Pump at reduced rate until bottoms-up is past the liner top. Rotate and/or reciprocate liner as specified in the drilling program.

2.9 Setting Liner Hanger The liner hanger should always be set higher than the deepest depth

achieved while circulating or reciprocating. This will ensure the liner is hung and not merely standing on bottom.

The specific liner hanger setting procedure will vary with the type of well, cementing program, and type of hanger used. These setting instructions will be provided by the liner hanger serviceman on location or will be detailed in the drilling program. Mechanical-set and hydraulic-set liner hangers are utilized within Saudi Aramco’s drilling operation. The following summarizes four different well types and liner hanger applications,

? ? Arab-D Vertical Well

7” Mechanical-Set Liner Hanger with Pack-Off (Lindsey, BOT) Hanger Set Prior to Cementing Set after Cement Job

? ? Offshore/Shaybah Horizontal Well (BOT, and TIW)

4-1/2” Hydraulic-Set Liner Hanger Set After Cementing

? ? Khuff Vertical Well (BOT and 1st Generation TIW)

7” and 4-1/2” Hydraulic-Set Liner Hangers Set Prior to Cementing

? ? Khuff Horizontal Well (2nd Generation TIW)

7” and 4-1/2” Hydraulic-Set Liner Hanger Hanger Set After Cementing

Further information regarding details on mechanical-set, hydraulic-set, and associated liner hanger equipment is listed in Section 6 of this chapter.

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3.0 FLOAT EQUIPMENT

3.1 Inner String Cementing

Inner string cementing (ISC) is utilized to reduce rig time and cementing cost. The method provides for the cementing of large diameter casing through an inner drill pipe string, virtually eliminating cement contamination and the drill out of large quantities of cement. This system is primarily used on Khuff wells where the 30” casing is cemented at approximately 600’ (with ISC and stab-in float shoe) and 24” casing is cemented at approximately 2200’ (with ISC and stab-in float collar). Casing collapse must be considered on the deep casing strings cemented with ISC. *The maximum surface pressure should be calculated to avoid casing collapse in the event of the hole bridging-off near the casing shoe. On critical depth strings, the surface pump pressure plus the cement hydrostatic pressure (ISC) can exceed the casing collapse rating, even though the casing is supported by mud hydrostatic pressure inside. The following alternatives can prevent casing collapse while ISC at a critical cementing depth: ? ? Increasing mud weight inside the

casing prior to cementing. ? ? Utilizing a pack-off cementing

head (which enables holding additional pressure on the casing). * Max. Surf. Press. = Collapse Rating – [Cmt Hydrostatic Inside ISC – Mud Hydrostatic Inside Csg] 1.125

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3.2 Float Shoes The float shoe reinforces the lower end of the casing string and guides the string away from ledges to cementing depth. It includes a spring-loaded backpressure valve that prevents reverse flow of cement back into the casing following the cementing operation. The outside body of the float shoe is made of steel of the same strength as the casing. The backpressure valve is made of plastic and is enclosed in concrete for easy drill-out.

3.3 Float Collars The float collar serves as a back up to the float shoe in the event the backpressure valve in the float shoe fails to provide a seal. The float collar is normally located 2 to 3 joints above the float shoe. The construction of float collar is similar to the float shoe and also enables easy drill-out.

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3.4 Plug Set The standard plug set consists of a bottom wiper (rupture) plug and top wiper (solid) plug. The primary purpose of bottom wiper plug is to wipe the mud from the casing wall ahead of the cement to minimize contamination. The purpose of the top wiper plug is to isolate the cement slurry from the displacement fluid.

In most cases, the bottom wiper plug is not used to avoid confusion or a potential problem with the bottom plug not rupturing. If the top wiper plug is dropped first, the plug will bump with the cement still inside the casing. A similar result would be experienced if the bottom plug did not rupture. This procedure of ‘not using the bottom wiper plug’ is a Drilling & Workover policy. The only exception would be a possible situation where the top wiper plug might wipe enough mud from a long, small diameter casing string and exceed the capacity of the shoe track (resulting in a wet shoe).

TOP WIPER PLUG

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4.0 MULTI-STAGE PACKER COLLAR

The multi-stage packer collars are hydraulically operated and provide for 2-stage and 3-stage cementing operations. Applications for multi-stage packer collars include the following: ? ? Cementing a high-pressure gas zone and loss circulation zone.

(Example: Isolating abnormal Lower Jilh pressure from the Hanifa and Arab-D reservoirs.)

? ? Cementing above a loss circulation zone. (Example: Cementing to surface above UER.)

? ? Cementing a deep casing string back to surface. (Example: Cementing to surface from the Jilh Dolomite casing point.)

The multi-stage packer collar (DV) is typically located inside the previous casing string to ensure a good packer seat for the 2nd stage cementing. On a 3-stage cement job, the lower DV is run in the open hole section where the hole size is close to gauge. The actual packer depth can be picked from the caliper log, when available, or by rate of penetration.

A 3-stage cement job requires two multi-stage packer collars and two different size plug sets. A conversion kit is installed in the lower DV to accommodate the smaller plug set. The actual DV tool is the same for both 2-stage and 3-stage applications except for the conversion kit installation. 4.1 Tool Illustrations/Technical Data

The following provides tool illustrations and technical data for the multi-stage

packer collars commonly used within Saudi Aramco drilling operation. The actual tool application will be specified in the drilling program based upon casing size, connection, rated service, and other factors.

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18-5/8” Type PES InflatablePacker Collar

w/Metal BladderPacker(ESIPC)

18-5/8” Type PES InflatablePacker Collar

w/Metal BladderPacker(ESIPC)

ClosingSeat

OpeningSeat

PackerElement

External Portsw/Rupture Disk

Internal Ports

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-664-789-00 SA Set No. 813.30226 Size (in) 18.625 Tool Type ESIPC-P HES Set No. 813.30226 Description CEMENTER SET - SAMS #45-664-789-00 - 18-5/8" BUTTRESS

115# - ESIPC W/METAL BLADDER PKR W/2-STG, W/RD FREE FALL PLUG SET

Pkr (HES P/N) 813.78965 Pkr Description COLLAR - TYPE P ES INFL PKR - 18-5/8 BUTTRESS 115# -

METAL BLADDER PKR Plug Set (HES P/N) 813.16870 Plug Set Description PLUG SET - FREE FALL - 18-5/8 8RD & BUTTRESS

87.5-115# 2-STAGE CMTR - W/9.81 ID BAFFLE Open Press (psi) 320 Open Force (lbs) 76000 Inflation (psi) 1450 Closing Press (psi) 475 Closing Force (lbs) 114000 Pkr Differential (psi) 3000 2000 Hole Size (in) 22.750 23.200 Pkr OD (in) 20.800 Pkr Length (in) 75.750 Min ID after Drillout (in) 17.467 Opening Seat ID (in) 14.250 Closing Seat ID (in) 16.000 No. of Circl. Ports 4 Size of Ports (in) 1.125 Recom. Max Hole Size (in) 23.800 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 24.250

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ClosingSeat

OpeningSeat

PackerElement

ExternalPorts

InternalPorts

Multiple StageInflatable

Packer Collar(MSIPC)

Multiple StageInflatable

Packer Collar(MSIPC)

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-734-380-00 SA Set No. N/A Size (in) 13.375 Tool Type MSIPC HES Set No. N/A Description SEE BELOW Pkr (HES P/N) 813.31060 Pkr Description COLLAR - MULT STAGE INFL PKR - 13-3/8 NEW-VAM

61-72# -16.75 OD SUITABLE F/ USE W/ C-95 Plug Set (HES P/N) SEE NOTES AT BOTTOM Plug Set Description SEE NOTES AT BOTTOM Open Press (psi) 675 Open Force (lbs) 81000 Inflation (psi) 1450 Closing Press (psi) 675 Closing Force (lbs) 81000 Pkr Differential (psi) 3500 Hole Size (in) 17.500 Pkr OD (in) 16.750 Pkr Length (in) 56.800 Min ID after Drillout (in) 12.359 Opening Seat ID (in) 10.400 Closing Seat ID (in) 11.250 No. of Circl. Ports 4 Size of Ports (in) 1.250 Recom. Max Hole Size (in) 18.500 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 19.540

Description PLUG SET - FREE FALL - 13-3/8 NEW VAM, 54.5-72#, 2-STAGE CMTR - W/7.40 ID INSERT BAFFLE ADAPTER SUITABLE F/USE

W/C-95 PLUG SET - FREE FALL - 13-3/8 NEW VAM 54.5-72# 3-STAGE CMTR - W/7.40 ID SHUTOFF BAFFLE - F/813 & 854 SERIES TOOLS-SUITABLE F/USE W/C-95 PLUG SET - DISPLACEMENT TYPE - 13-3/8 PREMIUM THD 48-85#

3-STAGE CMTR W/3.25 ID BYPASS BAFFLE -

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-734-777-00 SA Set No. 813.30215 Size (in) 13.375 Tool Type MSIPC HES Set No. 813.30215 Description CEMENTER SET - SAMS #45-664-777-00 - 13-3/8

BUTTRESS61-72# SUITABLE F/USE W/L-80 - MSIPC & 2-STAGE FREE FALL PLUG SET W/7.4 ID SHUTOFF BAFFLE

Pkr (HES P/N) 813.31058 Pkr Description COLLAR - MULT STAGE INFL PKR - 13-3/8 BUTRESS

61-72# -16.75 OD - SUITABLE F/USE W/L-80 Plug Set (HES P/N) 813.16821 Plug Set Description PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-

85# 2-STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID BAFFLE

Open Press (psi) 675 Open Force (lbs) 81000 Inflation (psi) 1450 Closing Press (psi) 675 Closing Force (lbs) 81000 Pkr Differential (psi) 3500 Hole Size (in) 17.500 Pkr OD (in) 16.750 Pkr Length (in) 56.800 Min ID after Drillout (in) 12.359 Opening Seat ID (in) 10.400 Closing Seat ID (in) 11.250 No. of Circl. Ports 4 Size of Ports (in) 1.125 Recom. Max Hole Size (in) 18.500 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 19.540

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ClosingSeat

OpeningSeat

PackerElement

ExternalPorts

w/RuptureDisk

InternalPorts

Multiple StageInflatable

Packer Collarw/Rupture Disk

(MSIPC)

Multiple StageInflatable

Packer Collarw/Rupture Disk

(MSIPC)

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-733-942 SA Set No. N/A Size (in) 9.625 Tool Type MSIPC HES Set No. N/A Description SEE BELOW Pkr (HES P/N) 813.30937 Pkr Description COLLAR - MULT STAGE INFL PKR - 9-5/8, NEW-VAM

43.5-53.5# - 11.75 OD - W/ RD - SUITABLE F/USE W/C-95

Plug Set (HES P/N) SEE NOTES AT BOTTOM Plug Set Description SEE NOTES AT BOTTOM Open Press (psi) 925 Open Force (lbs) 54000 Inflation (psi) 1800 Closing Press (psi) 650 Closing Force (lbs) 38000 Pkr Differential (psi) 4000 Hole Size (in) 12.250 Pkr OD (in) 11.750 Pkr Length (in) 64.100 Min ID after Drillout (in) 8.619 Opening Seat ID (in) 6.926 Closing Seat ID (in) 7.750 No. of Circl. Ports 2 Size of Ports (in) 1.125 Recom. Max Hole Size (in) 14.000 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 15.000

Description PLUG SET - FREE FALL - 9-5/8 NEW VAM 45.5-53.5# 2-STAGE CMTR - W/5.00 ID INSERT BAFFLE ADAPTER - SUITABLE F/USE W/C-95 PLUG SET - DISPLACEMENT TYPE - 2-STAGE - 9-5/8 PREMIUM THD 40-53.5# MULT STAGE CMTR PLUG SET - FREE FALL - 9-5/8 PREMIUM THREAD 43.5-53.5# MULTI STAGE CMTR PLUG SET - DISPLACEMENT TYPE - 9-5/8 PREMIUM THD 36-53.5# & 9-7/8 62.8# 3-STAGE CMTR - W/3.25 ID BYPASS BAFFLE

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-733-932-00 SA Set No. 813.30290 Size (in) 9.625 Tool Type MSIPC HES Set No. 813.30290 Description CEMENTER SET - SAMS #45-733-932-00 - 9-

5/8, 8RD, 29.3-40# SUITABLE F/USE W/P-110 W/ RD - MSIPC W/ 2-STG FREE FALL PLUG SET

Pkr (HES P/N) 813.30854 Pkr Description COLLAR - MULT STAGE INFL PKR - 9-5/8,

8RD29.3-40# - 11.75 OD - W/RUPTURE DISK, SUITABLE F/USE W/P-110

Plug Set (HES P/N) 813.16710 Plug Set Description PLUG SET - FREE FALL - 9-5/8, 8RD, 32.3-

53.5#2-STAGE TYPE P CMTR - W/5.90 ID BAFFLE - REF: 813.16720

Open Press (psi) 860 Open Force (lbs) 54000 Inflation (psi) 1800 Closing Press (psi) 610 Closing Force (lbs) 38000 Pkr Differential (psi) 4000 Hole Size (in) 12.250 Pkr OD (in) 11.750 Pkr Length (in) 64.150 Min ID after Drillout (in) 8.927 Opening Seat ID (in) 6.926 Closing Seat ID (in) 7.750 No. of Circl. Ports 2 Size of Ports (in) 1.125 Recom. Max Hole Size (in) 14.000 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 15.000

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Multiple StagePacker Cementing

Collar(MSPCC)

Multiple StagePacker Cementing

Collar(MSPCC)

ClosingSeat

OpeningSeat

PackerElement

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-664-786-00 SA Set No. 813.30214 Size (in) 13.375 Tool Type MSPCC HES Set No. 813.30214 Description CEMENTER SET - SAMS #45-664-786-00 - 13-3/8, 8RD

48-72# SUITABLE F/USE W/P-110 - MSPCC & 2-STG FREE FALL PLUG SET W/7.40 ID SHUTOFF BAFFLE

Pkr (HES P/N) 854.08441 Pkr Description COLLAR - MULT STAGE PKR CMTG - 13-3/8, 8RD, 48-

72#, 16-3/4 OD PKR - 11.25 ID CLSG SEAT - SUITABLE F/USE

W/P-110 Plug Set (HES P/N) 813.16821

Plug Set Description PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-85#, 2-STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID

BAFFLE Open Press (psi) 560 Open Force (lbs) 81000 Inflation (psi) N/A Closing Press (psi) 560 Closing Force (lbs) 81000 Pkr Differential (psi) 1000 Hole Size (in) 17.500 Pkr OD (in) 16.750 Pkr Length (in) 49.400 Min ID after Drillout (in) 12.579 Opening Seat ID (in) 10.400 Closing Seat ID (in) 11.250 No. of Circl. Ports 6 Size of Ports (in) 1.310 Recom. Max Hole Size (in) 17.750 Recom. Min Hole Size (in) 17.500 Actual Max. Expansion (in) 21.560

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-664-776-00 SA Set No. 813.30272 Size (in) 7.000 Tool Type MSPCC HES Set No. 813.30272 Description CEMENTER SET - SAMS #45-664-776-00 - 7-INCH 8RD

17-23# SUITABLE F/USE W/P-110 - MSPCC W/2-STAGE FREE FALL PLUG SET

Pkr (HES P/N) 854.0519 Pkr Description COLLAR - MULT STAGE PKR CMTG - 7 IN., 8RD, 17-

23# 8-1/2 OD PKR SUITABLE F/USE W/P-110- Plug Set (HES P/N) 813.16571 Plug Set Description PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS

20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE Open Press (psi) 930 Open Force (lbs) 35400 Inflation (psi) N/A Closing Press (psi) 620 Closing Force (lbs) 25600 Pkr Differential (psi) 1000 Hole Size (in) 8.750 Pkr OD (in) 8.500 Pkr Length (in) 45.830 Min ID after Drillout (in) 6.433 Opening Seat ID (in) 4.370 Closing Seat ID (in) 5.120 No. of Circl. Ports 3 Size of Ports (in) 1.310 Recom. Max Hole Size (in) 9.000 Recom. Min Hole Size (in) 8.750 Actual Max. Expansion (in) 10.120

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Type HES InflatablePacker Collar

(ESIPC)

Type HES InflatablePacker Collar

(ESIPC)

ClosingSeat

OpeningSeat

PackerElement

External Portsw/Rupture Disk

Internal Ports

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HALLIBURTON DV PACKER COLLARS

SAMS No. N/A SA Set No. Trial Test Size (in) 7.000 Tool Type ESIPC-H HES Set No. N/A Description SEE BELOW Pkr (HES P/N) 813.78101 Pkr Description COLLAR - TYPE H ES INFL PKR - 7 IN., LG, 8RD,

26# -3 FT PKR - SUITABLE F/USE W/K-55 Plug Set (HES P/N) 813.16571 Plug Set Description PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS

20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE Open Press (psi) 1650 Open Force (lbs) 12300 Inflation (psi) 2200 Closing Press (psi) 1280 Closing Force (lbs) 38400 Pkr Differential (psi) 4000 Hole Size (in) 9.000 Pkr OD (in) 8.250 Pkr Length (in) 192.000 Min ID after Drillout (in) 6.079 Opening Seat ID (in) 4.375 Closing Seat ID (in) 5.120 No. of Circl. Ports 2 Size of Ports (in) 1.125 Recom. Max Hole Size (in) 11.900 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 12.875

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HALLIBURTON DV PACKER COLLARS

SAMS No. 45-733-930-00 SA Set No. N/A Size (in) 4.500 Tool Type ESIPC-H HES Set No. N/A Description SEE BELOW Pkr (HES P/N) 813.78010 Pkr Description COLLAR - TYPE H ES INFL PKR - 4-1/2, 8RD, 9.5-11.6#

10 FT PKR - 5.62 OD - SUITABLE F/USE W/K-55 Plug Set (HES P/N) 809.50100 & 809.52100 Plug Set Description PLUG SET - SR TYPE H - 4-1/2 9.5-13.5# CSG W/3-1/2

(2.00 TO 2.75 ID) DP RELEASING DARTS - W/2-7/8 EUE 8RD SUITABLE F/USE W/K-55TBG BOX THD - F/2.00 MIN ID HANGER SYSTEM

ADAPTER - BAFFLE - 4-1/2 8RD 9.5-11.6# - 2.375 ID LATCH- DOWN INSERT - 2-STAGE CMTR

- Open Press (psi) 1650 Open Force (lbs) 6000 Inflation (psi) 2200 Closing Press (psi) 1080 Closing Force (lbs) 13500 Pkr Differential (psi) 4000 1000 Hole Size (in) 5.875 9.000 Pkr OD (in) 5.750 Pkr Length (in) 276.000 Min ID after Drillout (in) 3.985 Opening Seat ID (in) 2.750 Closing Seat ID (in) 3.370 No. of Circl. Ports 2 Size of Ports (in) 0.685 Recom. Max Hole Size (in) 9.000 Recom. Min Hole Size (in) N/A Actual Max. Expansion (in) 10.000

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4.2 Free Fall Plug Set

A free-fall plug set is used on most of multi-stage cement jobs. This plug set consists of the following: ? ? Closing Plug (closes the DV ports) ? ? Free Fall Opening (opens the DV ports) ? ? Shut-Off Plug (acts as top wiper plug on 1st stage cement) ? ? Shut-Off Baffle (provides seat for Shut-Off Plug)

Two-StageFree Fa l l P lug Se t

with Baff le Adapter

Shut-Off Baffle

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4.3 Displacement Type Plug Set

A displacement type plug set is used in situations where high mud weight limits the use of free-fall plugs (where fall time may exceed the remaining thickening time of the cement). This plug set consists of the following: ? ? Closing Plug (closes the DV ports) ? ? Opening Plug (opens the DV ports) ? ? By-Pass Plug (acts as top wiper plug on 1st stage cement) ? ? By-Pass Baffle (provides seat for By-Pass Plug and allows for continued

circulation until the Opening Plug bumps)

Displacement TypePlug Set

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5.0 CENTRALIZERS

The following centralizers are utilized in Saudi Aramco’s drilling operation. These centralizer designs exceed the requirements of API specification 10D for starting and restoring force. Centralizer placement for deviated and horizontal well applications should be calculated using a software program.

5.1 Collapsible

The collapsible centralizer is a non-welded, hinge type, bow centralizer. This centralizer is used in all vertical well applications. The centralizer should be positioned around a stop collar in the middle of the desired joint (as opposed to locating the centralizer around the casing coupling).

5.2 Rigid

The rigid centralizer is a non-welded, hinge type, rigid bow centralizer. This centralizer is run primarily in the liner lap interval. This centralizer design can provide approximately 100 percent standoff when run inside a cased hole, as in the liner lap application. A stop collar is also recommended for centralizer placement.

5.3 SpiraGlider

The spiraglider centralizer is a steel spiral-bladed centralizer. This centralizer is required on highly deviated or horizontal wells to improve cement flow and provide maximum standoff from the borehole. The spiraglider system consists of a steel centralizer and two beveled stop collars designed to minimize the running resistance.

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6.0 LINER HANGERS

6.1 Mechanical-Set Liner Hanger

The mechanical-set liner hanger is mainly used in vertical or low-angle wellbores. This liner hanger is designed for heavy-duty service and is capable of suspending short as well as long, heavy liners. The tandem cone version (as shown) with staggered slips, provides maximum bypass and heavy load hanging capacity. The increased bypass lessens pressure build-up during the running and cementing operations, which reduces the chance of loss circulation in pressure sensitive formations. The mechanical hanger is set by picking up on the liner and rotating to disengage the J-slot. As the liner is lowered, the springs hold the cage stationary. This allows the barrel to move downward engaging the cones against the slips, which move outward against the casing wall. This liner hanger does not have hold-down slips; consequently, buoyancy must be calculated for short liner applications to avoid the possibility of floating.

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6.2 Hydraulic-Set Liner Hanger The hydraulic-set liner hanger is primarily used in deep, highly deviated, and horizontal well applications. The setting mechanism of the hydro-hanger (as shown) is pressure activated, after a ball is seated in the landing collar. The pressure shears the pins in the setting piston, which pushes the slips up and around the cones. Additional pressure shears the ball-seat in the landing collar, releasing the ball and restoring circulation. The typical shear pin and ball-seat strengths are listed below: Arab-D Deviated Shear Pressure Shear Pin 1200 psi Ball-Seat 2500 psi Khuff/Pre-Khuff Shear Pressure Shear Pin 2250 psi Ball-Seat 3500 psi This liner hanger also does not have hold-down slips; consequently, buoyancy must be calculated for short liner applications to avoid the possibility of floating.

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6.3 Associated Equipment

6.3.1 Setting Collar/Tieback Sleeve The setting collar/tieback sleeve is a basic releasing collar used to carry the liner into the well. It also provides a receptacle which permits the liner to be extended to a point farther up-hole or to surface. The setting collar (as shown) is made up on top of the liner hanger. A right-hand releasing thread ensures easy release of the liner setting tool from the setting collar. The tieback sleeve (as shown) is attached to the setting collar. The receptacle’s polished bore facilitates the entry and seating of the seal nipple, when a tieback is required. The tieback sleeve is provided in optional lengths depending on the well type. The standard lengths for development wells and Khuff/Pre-Khuff wells are 6 feet and 12 feet respectively.

Tie-Back Sleeve

Setting Collar

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6.3.2 Liner Top Packer The liner top packer combines the basic features of the setting collar with the addition of a pack-off at the top of the liner. The packer provides a secondary mechanical seal against gas migration and prevents well fluids from entering the wellbore in uncemented or poorly cemented liners; thus, creating an effective liner lap seal. The liner top packer is optional in most liner applications but is recommended on liners cemented across an abnormally pressured formation, as the Lower Jilh. The liner top packer (as shown) is mechanically set by applying weight to the top of the packer after releasing the liner setting tool and opening the packer setting dogs. The liner top packer also includes a sleeve (as shown) for future tiebacks.

Tie-Back Sleeve

Packer Element

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6.3.3 Polished Bore Receptacle The polished bore receptacle (PBR) is a seal bore with a honed and coated ID to receive production seals for a packer-less completion. The PBR is made up on top of the liner hanger and below the setting collar/tieback sleeve. The polished bore receptacle (as shown) provides for free tubing movement during production. The use of Teflon coating prevents the cement from sticking to the ID during cementing operations and minimizes seizing of the seals during production.

The PBR is primarily used on Khuff/Pre-Khuff wells and is a standard length of 24’.

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6.3.4 Cementing Manifold

The cementing manifold provides a means of circulating and cementing the liner. The manifold consists of a swivel and plug-dropping head with elevator handling sub. The plug-dropping head facilitates the dropping the drill pipe wiper plug and liner hanger setting ball (if a hydraulic-set liner hanger is utilized). The cementing manifold is provided by the liner hanger company as part of the liner hanger equipment

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SECTION D CEMENTING __________________________________________________________________________________________________________________________

CEMENTING 1.0 CEMENT TYPES, SPECIFICATIONS & ADDITIVES

1.1 Cement Types 1.2 Specifications 1.3 Performance of Cement Slurry 1.4 Additive Functions 1.5 Cement Additives

2.0 SLURRY DESIGN

2.1 Factors That Influence Cement Slurry Design 2.2 Limitations of Thickening Time 2.3 Fluid Loss Test

2.3.1 HT/HP Fluid Loss Tests (BHCT<190 0F) 2.3.2 Stirred HT/HP Fluid Loss Tests (BHCT>190 0F)

2.4 WOC (Waiting on Cement) Time 2.4.1 Ultrasonic Cement Analyzer (UCA Test) 2.4.2 Static Gel Strength Analyzer (SGSA Test)

2.5 Pressurized Mud Balance & Densitometers 2.6 Free Fluid Test 2.7 Rheology Test 2.8 Mud-Spacer-Cement Compatibility Test 2.9 Gas Migration Additives 2.10 Cementing: Pre-Job Considerations for Slurry Design 2.11 Pre-Job Meeting 2.12 Cementing Information Form

3.0 LAB TESTING OF CEMENT

3.1 Types of Tests 3.2 When To Send Samples For Testing 3.3 Initial Pilot Testing 3.4 Pilot Testing prior To Mixing 3.5 Field Sample Confirmation Testing

4.0 MIXING CEMENT

4.1 Mix Water Quality 4.2 Type Of Chemicals And Quantity To Be Blended 4.3 Mix Water Blending And Storage System 4.4 Cement Job Quality 4.5 Pre-Mixing Additives 4.6 Sampling and Sample Sizes

4.6.1 Sample Containers

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4.6.2 Dry Cement Sampling 4.6.3 Sampling of Mix Fluid 4.6.4 Sample Size for Lab Testing 4.6.5 Sample Labeling

5.0 BALANCED PLUGS

5.1 Loss Circulation Plugs 5.2 Kick-Off / Sidetrack Plugs

5.2.1 Kick-Off Plugs 5.2.2 Sidetracking

5.3 Isolation/Abandonme nt Plugs 6.0 DISPLACEMENT PROCEDURES

6.1 Casing 6.2 Liners 6.3 Turbulent Flow

7.0 REMEDIAL CEMENTING

7.1 Bradenhead Squeeze 7.2 Packer Squeeze

8.0 CEMENTING EQUIPMENT (PICTURES)

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CEMENTING The Saudi Aramco Oilwell Cement Lab monitors quality of Class G cement sold to the Company. Cement consignments that fall out of specification are not approved for purchase to Saudi Aramco. The Company cement lab technicians sample and test all cement consignments prior to approving the purchase of any consignment of oilwell cement. It is not the intention of this manual to provide cementing recipes. Cement deteriorates with age. As dry cement ages, moisture collects on the particles and partially hydrates the outside covering of the particle. The physical properties of the cement slurry change when this occurs. Generally the thickening time increases, the free fluid increases and the final compressive strength decreases. Any concerns about Cement or Cement formulations contact Drilling Engineering or the Saudi Aramco Oilwell Cement Lab. 1.0 CEMENT TYPES, SPECIFICATIONS & ADDITIVES

1.1 Cement Types

Class G (HSR)* cement is used exclusively in Saudi Aramco operations as the basic oilwell cement. This cement can be blended with many additives to cover a wide range of well conditions. The five normal slurry compositions are as follows: *High Sulfate Resistant

CEMENT SLURRY

WEIGHT (PCF)

SLURRY YIELD

(FT3/SK)

WATER REQUIREMENT

GAL/SK Class G Neat 118 1.15 5.03 Class G +35% Silica Flour 118 1.52 6.28 Class G + 1.5% Bentonite (Prehydrated), 6.6 Lbs. Gel/bbl Of Mix Water

101 1.69 8.96

Class G +35% Silica Sand 125 1.35 5.01 Class G +35% Silica Sand + 5% Expanding Additive

125 1.40 5.25

A) All the above figures refer to a 94 lb sack. B) Slurry weights listed above are absolute weights. Weight of cement

measured from the cement tub in a non-pressurized mud balance may be as much as 15 pcf lighter due to entrapped air.

C) Modifications of the basic slurries will be specified by Drilling Engineering.

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1.2 Specifications

API Specification 10A “Specification for Cement and Materials for Well Cementing” is used for the approval of the purchasing of class G (HSR) cement. API Recommended Practice 10B is used for the basic test procedures for the physical testing of cement slurries. Many instruments in the cement lab are not listed in API RP 10B. Procedures for testing cements are located in the labs procedures manual.

1.3 Performance of Cement Slurry

Data given for the effectiveness of any additives is only valid for the cement, water and additives used for the test. Different cement brands, and even different production runs of the same brand of cement, react differently to the various additives. When there is any doubt, have the actual job cement, water and cement additives tested. Most cement additives from the various service companies are completely compatible with each other. Testing is always recommended if additives from different service companies are being used. Almost all of Schlumberger/Dowell's products are completely compatible with Halliburton’s and BJ’s products and vice versa. Before making any substitutions, consult with the Cement Lab, Drilling Engineering or the Service Company. Many additives have more than one function. For example, a dispersant (friction reducer) can be added to a slurry design to help make the mixing easier for a class G cement slurry that is mixed at a density greater than 118 pcf. The physical effects of adding the dispersant will be reduced the rheology, and lengthen the thickening times. Lists of the more common cement functions and additives used by Saudi Aramco are included in the following pages:

1.4 Additive Functions:

1.4.1 Retarders

The function of retarders is to increase the thickening time (pumping time) of the cement slurry being pumped. Lignosulfonates and their derivatives make up the majority of the cement retarders for use in low and medium temperatures. (80 0F – 220 0F) Higher temperature retarders are composed of Polyhydroxy Organic Acids and sugar derivatives. It has been observed that combinations of low and high temperature retarders are effective in extending thickening times for high temperature applications. High temperature retarders should

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never be used in cements with BHCT lower than 180 0F, unless confirmed by lab tests.

1.4.2 Fluid Loss Additives

The function of fluid loss additives is to reduce the water loss from the cement slurry. This class of cement chemicals and gas migration additives are generally the most expensive part of the cementing invoice. If high fluid loss occurs the following can happen: ?? Premature dehydration of slurry, which can cause

annulus plugging and incomplete placement of slurry. ?? Changes in slurry flow properties (rheology) and

increased slurry density. ?? Damage to production zones by cement filtrate Most fluid loss additives also retard the thickening time. On the 4 ½” and 7” liner jobs for vertical Arab D wells, no retarder is used. Adequate retardation is produced from the synergetic effects combining the fluid loss additive with the dispersants.

1.4.3 Dispersants (Friction Reducers)

The functions of dispersants are: A) to thin the slurry in order to reduce the turbulent flow rate or enable easy mixing of slurry B) to densify cement slurry (increase the solid-to-liquid ratio). C) to aid in fluid loss control. Over dispersing the cement slurry can cause high free fluid and density settling in the cement column. This must be avoided at all times and especially when cementing deviated or horizontal section of the well. Pumping slurry that is not up to the designed weight (density) can easily settle after placement. Pressurized mud balances must be used to confirm correct cement density. Pumping cements that are heavier than the planned density doesn’t cause settling problems. However, the thickening times are generally shorter.

1.4.4 Accelerators

The function of accelerators is to reduce the thickening time and decrease the (WOC) time. Calcium Chloride is the most common accelerator used. Calcium Chloride does not increase the final strength of cement and may perhaps lower the final compressive strength a little. Most fluid loss additives do not work well with Calcium

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Chloride in the cement slurry. Sodium Silicate is recommended if low fluid loss is required with fluid loss control in most cases. Special mixing is required for sodium silicate slurries 1) if accelerator is used then the accelerator must be added first. 2) if a retarder is to be used then the Sodium Silicate should be added first and the retarder must be added last.

1.4.5 Non-Foamers

The function of non-foamer (defoamers) in cement slurry is to release trapped air in the slurry as it is being mixed. Entrapped air cause viscosity increases, which make the cement slurry more difficult to mix. Entrapped air also makes the density of the slurry more difficult to measure. Special non-foamer are used for Latex cement slurries. The addition of excess non-foamer may stabilize foam. Bentonite cement slurries usually require twice as much non-foamer than conventional cements. Latex cements may require as much as five times more non-foamer than conventional cement slurries.

1.4.6 Strength Retrogression Preventers

The function of silica flour and silica sand in cement is to prevent strength retrogression of the set cement. Exposure temperatures of 250 0F to 300 0F require 25% silica flour or silica sand by weight of cement. When cement is exposed to temperatures from 300 0F to 450 0F, 35% silica flour or silica sand is required. At temperatures above 450 0F only silica flour should used. Service companies recommend 35% silica at temperatures over 235 0F. This recommendation is conservative with built in safety factors for improper blending ratios of cement-silica flour and inaccurate temperature data.

1.4.7 Heavy Weight Additives

The function of Heavy weight additives is to increase the slurry density above the level that can be achieved with dispersants. The maximum density achievable with Saudi Class G cement + dispersant is 130-135 pcf. Hematite (a form of Iron Oxide) is normally used to densify cement. The highest density cement pumped in Saudi Aramco is 170 pcf using 185% Hematite. MicroMax, (Manganese tetraoxide), a relatively new product, is available for increasing the density of cement slurries. This product has a lower specific gravity than Hematite but is spherical and small in size. It has two primary advantages 1) it is ground small (less than 1 micron) which allows it to

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be blended in the mix water, and 2) it is spherical which makes the gel strengths much lower, thus reducing the viscosity.

1.4.8 Gas Migration Additives

The function of Gas migration additives is to help prevent fluids (gasses & Liquids) from migrating to the surface during the loss of hydrostatic pressure that occurs prior to the setting of cement. The most popular additive is Liquid Latex. Latex provides low fluid loss to the slurry and lower initial permeability to the set cement. Expanding additives are often included in the slurry design to reverse any shrinkage that occurs during the setting of cement. Special mixing instruction for latex systems: add the stabilizer to the water after the bactericide but prior to any other cement additives.

1.4.9 Extenders

The function of the extenders is 1) to decrease the slurry density or 2) to increase the slurry yield decreasing the total cost. Pre-hydrated Bentonite is the best example of cost saving of a neat cement slurry. However, if low fluid loss is required, the cement can become more expensive as the increased water in the system requires more chemicals to prevent it from escaping from the slurry. Sodium Silicates have also been used to lower the density of cement but are more expensive than pre-hydrated Bentonite. Foam cement and Micro spheres have been utilized with limited success.

1.4.10 Expanding Additives

The function of expanding additives is to increase the bonding strength of the set cement. After cement goes through hydration reaction, the cement shrinks. Expanding additives primarily MgO and CaO or combinations of the two are dry blended in cement to take the set cement out of shrinkage and provide up to 2.5% expansion. This expansion may take up to two weeks to reach completion. Salt (NaCl) is not recommended as an expansion additive in cement due to the higher permeability that high concentrations of salt in cement produce. On the other hand MgO and CaO are not as water soluble as NaCl and provide a lower permeability once the cement has set.

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1.4.11 Bactericide

The function of the Bactericide (biocide) is to kill significant quantities of bacteria in the cement mixing fluid to prevent chemical degradation of cement additives. Bacteria reproduce exponentially and if not controlled will reduce the cement additives to an ineffective level.

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1.5 Cement Additives:

HALLIBURTON CEMENT ADDITIVES RETARDERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

HR-4 172 0F, BHCT

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Can be added to cement containing high temp. retarder to extend thickening time.

HR-5 220 0F, BHCT

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Can be added to cement containing high temp. retarder to extend thickening time

HR-12 320 0F, BHCT

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. sack

HR-15 380 0F, BHCT

Up to 2.5%, BWOC

Added to mix water or dry blended

50 lb. sack

TB-41 250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Added with high temp. retarders to extend thickening time.

Component R

250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

Halad-22A 125 0F - 360 0F

Up to 1.5%, BWOC

Added to mix water or dry blended

50 lb. sack

Halad-322 Up to 180 0F

Up to 1.5%, BWOC

Added to mix water or dry blended

50 lb. sack

Halad-344 Up to 330 0F

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Halad-413 80 0F - 400 0F

Up to 3.0%, BWOC

Added to mix water or dry blended

50 lb. sack

DISPERSANTS (Friction Reducers)

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

CFR-3 Up to 350 0F

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Can be used to help increase the density of cement.

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HALLIBURTON CEMENT ADDITIVES (continued)

ACCELERATORS Name Temp.

range Normal concentration

Mixing procedure

Packing Comments

CaCl2 Up to 120 0F

Up to 2.0%, BWOC

Added to mix water or dry blended

100 lb. sack

CAL-SEAL Up to 170 0F

Up to 90.0%, BWOC

dry blended 100 lb. sack

LIQUID ECONOLITE

Up to 200 0F

Up to 1.0 GPS Added to mix water

52 gallon drum

NaCl Up to 360 0F

Up to 5.0%, BWOC

Added to mix water or dry blended

80 lb. sack

Sodium Chloride

NON-FOAMERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

NF-1 Up to 500 0F

1 PT/10 BBLS Added to mix water

5 gallon can

2 PT/10 BBLS IN BENTONITE SLURRIES

D-AIR-3 Up to 500 0F

0.02 GPS - 0.20 GPS

Added to mix water

54 gallon drum

5 PT/10 BBLS IN LATEX SLURRIES

STRENGTH RETROGRESSION PREVENTERS

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

SSA-1 250 0F – 700 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Flour

SSA-2 250 0F – 700 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Sand

HEAVY WEIGHT ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

Hi-Dense No.4

Up to 500 0F

Depends on required slurry density

dry blended 100 lb. sack

Hematite

Micro-Max Up to 500 0F

Depends on required slurry density

Added to mix water or dry blended

1,500 lb. Big Bag

Soluble in HCl

Hi-Dense No.3

Up to 500 0F

Depends on required slurry density

dry blended 100 lb. sack

Hematite

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HALLIBURTON CEMENT ADDITIVES (continued)

GAS MIGRATION ADDITIVES Name Temp.

range Normal concentration

Mixing procedure

Packing Comments

Latex 2000 Up to 400 0F

0.5 – 3.0 GPS Added to mix water

54 gal drum

Order of mixing critical

Stabilizer 434B Up to 320 0F

0.05 – 0.5 GPS Added to mix water

5 gal can Order of m ixing critical, Does not tolerate Salt

Versa-SET Up to 140 0F

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. bags

EXTENDERS (LIGHT WEIGHT ADDITIVES)

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

Bentonite (PH) Up to 400 0F

Up to 6.0%, BWOC, when prehydrated

Added to mix water

1.5 ton super sacks

Wyoming Bentonite, Non-benificiated

Liquid Econolite

Up to 200 0F

Up to 1.0 GPS Added to mix water

52 gallon drum

Order of mixing critical

EXPANDING ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

MICROBOND-HT

Up to 350 0F

Up to 10.0%, BWOC

dry blended 50 lb. sack

Normal concentration 5.0%

BACTERIACIDES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

BE-3 Up to 120 0F

0.5 gal/1000 gals Added to mix water

5 gal can Add to tank prior to filling with water

BE-6 Up to 120 0F

1 lb/500 bbls Added to mix water

1 lb bag

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES

RETARDERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

D-81 Up to 180 0F, BHCT

Up to 0.25GPS Added to mix water

5 gal. can Liquid version of D-13. Can be added to cement containing high temp. retarder to extend thickening time.

D-800 250 0F, BHCT

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. sack

D-801 250 0F, BHCT

Up to 0.5 gps Added to mix water

5 gal. can Liquid version of D-800. Can be added to cement containing high temp. retarder to extend thickening time.

D-109 175 - 300 0F, BHCT

Up to 0.5 gps Added to mix water

5 gal. can

D-28 200 - 400 0F, BHCT

Up to 2.5%, BWOC

Added to mix water or dry blended

50 lb. sack

D-93 250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

D-60 Up to 200 0F, BHCT

Up to 1.5%, BWOC

Added to mix water or dry blended

50 lb. sack

For use in fresh water

D-112 Up to 200 0F, BHCT

Up to 1.5%, BWOC

Added to mix water or dry blended

50 lb. sack

For low density slurries, good in sat. Salt & f. H2O

D-604 AM 120 0F – 250 0F

Up to 1.0 gps Added to mix water

8 gal. cans

strong dispersant

D-900 Up to 400 0F, BHCT

Up to 0.8%, BWOC

Added to mix water or dry blended

50 lb. sack

H.T. Fluid Loss Additive

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued) DISPERSANTS (Friction Reducers)

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

D-80 Up to 350 0F Up to 0.4 gps Added to mix water

8 gal. cans

Liquid D-65

D-606 Up to 400 0F Up to 1.0%, BWOC

Added to mix water

50 lb. sack

Sodium Sulfate

D-135 Up to 375 0F Up to 0.3 gps Added to mix water

5 gal. cans

Stabilizer for D-600

ACCELERATORS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

CaCl2 Up to 100 0F Up to 2.0%, BWOC

Added to mix water or dry blended

100 lb. sack

Calcium Chloride

D-53 Up to 100 0F Up to 10.0%, BWOC

dry blended 50 KG sack

D-75 Up to 200 0F Up to 1.0 GPS Added to mix water

52 gallon drum

Order of mixing is critical

NaCl Up to 360 0F Up to 5.0%, BWOC

Added to mix water or dry blended

50 Kg. sack

Sodium Chloride

NON-FOAMERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

D-47 Up to 500 0F

1 PT/10 BBLS Added to mix water

5 gallon can

2 PT/10 BBLS IN BENTONITE SLURRIES

D-144 Up to 500 0F

2 PT/10 BBLS Added to mix water

5 gallon can

5 PT/10 BBLS IN LATEX SLURRIES

STRENGTH RETROGRESSION PREVENTERS

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

D-66 250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Flour

D-30 250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Sand

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued) HEAVY WEIGHT ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

D-76 Up to 500 0F

Depends on required slurry density

dry blended 100 lb. sack

Hematite (Fe 3O4)

Micro-Max Up to 500 0F

Depends on required slurry density

Added to mix water or dry blended

100 lb. sack

Soluble in HCl

D-76.1 Up to 500 0F

Depends on required slurry density

dry blended 100 lb. sack

Ferrosilicon

GAS MIGRATION ADDITIVES

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

D-600 Up to 400 0F 0.9 – 2.5 GPS Added to mix water

55 gal drum Gas Block, Order of mixing critical

D-135 Up to 400 0F 0.1 – 0.25 GPS Added to mix water

5 gal can Gas Block Stabilizer Order of mixing critical

D-500 Up to 200 0F 0.9 – 2.5 GPS Added to mix water

55 gal drum Low Temp. Gas Block (Cem-Seal)

EXTENDERS (LIGHT WEIGHT ADDITIVES)

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

D-20 Up to 400 0F Up to 6.0%, BWOC, when prehydrated

Added to mix water

1.5 ton super sacks

Bentonite (PH)

D-75 Up to 200 0F Up to 1.0 GPS Added to mix water

52 gallon drum Order of mixing critical

EXPANDING ADDITIVES Name Temp.

range Normal concentration

Mixing procedure

Packing Comments

B-82 Up to 350 0F

Up to 10.0%, BWOC

dry blended 50 lb. sack Normal concentration 5.0%

BACTERIACIDES Name Temp.

range Normal concentration

Mixing procedure

Packing Comments

M-290 Up to 120 0F

0.5 gal/1000 gals Added to mix water

5 gal can Add to tank prior to filling with water

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BJ SERVICES CEMENT ADDITIVES

RETARDERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

R-3 Up to 210 0F, BHCT

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Can be added to cement containing high temp. retarder to extend thickening time.

R-8 200 - 400 0F, BHCT

Up to 2.5%, BWOC

Added to mix water or dry blended

50 lb. sack

R-9 250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

FL-25 Up to 200 0F, BHCT

Up to 1.5%, BWOC

Added to mix water or dry blended

50 lb. sack

For use in fresh water

BA-10 Up to 240 0F, BHCT

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. sack

For low density slurries, good in sat. Salt & f. H2O

DISPERSANTS (Friction Reducers)

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

CD-32 Up to 350 0F

Up to 2.0%, BWOC

Added to mix water

8 gal. cans

Liquid D-65

ACCELERATORS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

A-7 Up to 100 0F

Up to 2.0%, BWOC

Added to mix water or dry blended

100 lb. sack

Calcium Chloride

A-10 Up to 100 0F

Up to 10.0%, BWOC

dry blended 50 KG sack

Gypsum cement

A-3L Up to 200 0F

Up to 1.0 GPS Added to mix water

52 gallon drum

Order of mixing is critical

A-5 Up to 360 0F

Up to 5.0%, BWOC

Added to mix water or dry blended

50 Kg. sack

Sodium Chloride

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BJ SERVICES CEMENT ADDITIVES (continued) NON-FOAMERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

FP-6L Up to 500 0F

1 PT/10 BBLS Added to mix water

55 gal. drum

2 PT/10 BBLS IN BENTONITE SLURRIES

FP-9L Up to 500 0F

2 PT/10 BBLS Added to mix water

55 gal. drum

5 PT/10 BBLS IN LATEX SLURRIES

FP-12L Up to 500 0F

2 PT/10 BBLS Added to mix water

55 gal. drum

5 PT/10 BBLS IN LATEX SLURRIES

STRENGTH RETROGRESSION PREVENTERS

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

S-8 250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Flour

S-8C 250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Sand

HEAVY WEIGHT ADDITIVES

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

W-5 Up to 500 0F Depends on required slurry density

dry blended 100 lb. sack

Hematite (Fe 3O4)

Micro-Max Up to 500 0F Depends on required slurry density

Added to mix water or dry blended

1,500 lb. Big Bag

Soluble in HCl

GAS MIGRATION ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

BA-86L Up to 400 0F 1.0 – 3.0 GPS Added to mix water

55 gal drum

order of mixing critical

LS-1 Up to 400 0F 0.1 – 0.35 GPS Added to mix water

5 gal can B-86L stabilizer, order of mixing critical

EXTENDERS (LIGHT WEIGHT ADDITIVES)

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

Bentonite (PH) Up to 400 0F Up to 6.0%, BWOC, when pre-hydrated

Added to mix water

1.5 ton super sacks

Sodium Silicate

Up to 200 0F Up to 1.0 GPS Added to mix water

55 gallon drum

Order of mixing critical

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BJ SERVICES CEMENT ADDITIVES (continued)

EXPANDING ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

EC-2 Up to 350 0F

Up to 10.0%, BWOC

dry blended 50 lb. sack Normal concentration 5.0%

BACTERIACIDES Name Temp.

range Normal concentration

Mixing procedure Packing Comments

X-CID Up to 120 0F

1 lb/100 bbls Added to mix water 6 lb can

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NOWMCO CEMENT ADDITIVES

RETARDERS Name Temp.

range Normal concentration

Mixing procedure

Packing Comments

NR-1 Up to 200 0F, BHCT

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

NR-5 200 - 350 0F, BHCT

Up to 2.5%, BWOC

Added to mix water or dry blended

50 lb. sack

FLUID LOSS ADDITIVES

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

NFC-3 Up to 220 0F, BHCT

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. sack

NFC-4 Up to 220 0F, BHCT

Up to 2.0%, BWOC

Added to mix water or dry blended

50 lb. sack

DISPERSANTS (Friction Reducers)

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

DFR-1 Up to 350 0F

Up to 2.0%, BWOC

Added to mix water

50 lb. sack

ACCELERATORS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

CaCl2 Up to 100 0F

Up to 2.0%, BWOC

Added to mix water or dry blended

100 lb. sack

Calcium Chloride

DAL-1 Up to 100 0F

Up to 10.0%, BWOC

dry blended 50 KG sack

Gypsum cement

SODIUM SILICATE

Up to 200 0F

Up to 1.0 GPS Added to mix water

52 gallon drum

Order of mixing is critical

SALT Up to 360 0F

Up to 5.0%, BWOC

Added to mix water or dry blended

50 Kg. sack

Sodium Chloride

NON-FOAMERS

Name Temp. range

Normal concentration

Mixing procedure

Packing Comments

DAF-1 Up to 500 0F

1 PT/10 BBLS Added to mix water

5 gal can 2 PT/10 BBLS IN BENTONITE SLURRIES

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NOWMCO CEMENT ADDITIVES (continued) STRENGTH RETROGRESSION PREVENTERS

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

SFA-200

250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Flour

SFA-100

250 0F – 500 0F 25%-100%, BWOC

dry blended 100 lb. sack

Silica Sand

HEAVY WEIGHT ADDITIVES

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

Hematite Up to 500 0F Depends on required slurry density

dry blended 100 lb. sack

Hematite (Fe 3O4)

EXTENDERS (LIGHT WEIGHT ADDITIVES)

Name Temp. range Normal concentration

Mixing procedure

Packing Comments

Bentonite (PH) Up to 400 0F Up to 6.0%, BWOC, when prehydrated

Added to mix water

1.5 ton super sack

Sodium Silicate

Up to 200 0F Up to 1.0 GPS Added to mix water

55 gallon drum

NOWCHECK, Order of mixing is critical

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2.0 SLURRY DESIGN

2.1 Factors That Influence Cement Slurry Design

Lab tests are run prior to pumping cement in a well. Collecting accurate data prior to designing the cement ensures a good cement design. The following factors will effect the cement slurry design: ?? Well depth ?? Well temperature ?? Mud column pressure ?? Viscosity and water content of cement slurry ?? Strength of cement require to support the pipe ?? Quality of available mixing water ?? Type of mud & density ?? Slurry density ?? Cement shrinkage ?? Permeability of set cement ?? Fluid loss requirements ?? Resistance to corrosive fluids

2.2 Limitations of Thickening Time Test Data

The thickening time test is a dynamic test. While the cement slurry is being tested, measurements are being made of the consistency (viscosity) under downhole circulating conditions. The thickening time test does not give information on how the cement slurry performs under down hole static conditions. The thickening time test does not give useful information on the following: ?? The setting profile of the cement after the plug is bumped. ?? The compressive strength of the cement. ?? How the fluid loss to the formation affects the cement slurry. ?? How long the cement will be pumpable during a shutdown. This is

different for each cement slurry and the particular well conditions. To determine theses parameters, tests that simulate the slurry’s environment under static/dynamic conditions must be performed.

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Shown above is a typical thickening time curve for Class G cement + 1% CaCl2 @ 118 pcf, a BHCT of 100 0F. When the consistency reaches 100 Bc the thickening time is terminated.

The Aramco Oilwell Cement lab has five HT/HP Consistometers for the determination of thickening time.

Typical Thickening Time

0

20

40

60

80

100

120

Time (HRS:MINS)

Temp deg F

Pres. psi

Cons. Bc

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2.3 Fluid Loss Tests

Cement is like drilling mud in some aspects, as it is a suspension of solids. Chemical reactions occur on the surface of the solid particles of cement after water has been added. The rate that a cement slurry loses water through a high permeability zone under pressure is called fluid loss or filtration rate. The water that is lost from the slurry does not give the cementing properties that were originally designed.

When water is lost from the cement slurry, the slurry property’s change: ?? Viscosity increases which increases friction or pump pressures. – High

loss of water will result in a highly viscous cement slurry which is unpumpable.

?? Thickening time decreases ?? Higher solids to liquid ratio – cement bridges may form in areas of

narrow clearances The water that is lost from the cement slurry will have higher compressive strengths. High fluid loss cement slurries can be used when squeezing high injection rate leaks or perforations. Two types of tests are preformed for cement slurries. 1) HT/HP Fluid loss test and 2) Stirred fluid loss test. The permeable medium for both tests is a 325 mesh screen. 2.3.1 HT/HP Fluid Loss Tests (BHCT<190 0F)

The cement slurry is condition at bottom-hole circulating temperature (maximum 190 0F) under atmospheric pressures. The cement is then transferred to the fluid loss cell and tested at the bottom-hole circulating temperature and 1000 psi. The filtrate collected is used to calculate the fluid loss.

2.3.2 Stirred HT/HP Fluid Loss Tests (BHCT>190 0F)

The cement slurry is condition in the test apparatus at bottom-hole circulating temperature and 1100 psi. The cell is then rotated 180 degrees and the test cement slurry falls on to the 325 mesh screen. Back pressure (100 psi) is maintained through out the testing period. The filtrate collected is used to calculate the fluid loss. Cements tested with the Stirred fluid loss cell generally give higher fluid loss values as compared to the same cements tested on the HT/HP fluid loss cell.

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The stirred fluid loss cell gives more accurate fluid loss values than the conventional fluid loss test.

2.4 WOC Time

The industry accepts a compressive strength of 500 psi for drilling out the casing shoe. This is also true for testing and drilling out the top of the liner. On Arab-D wells, where the top of the liner is shallow and the cement density is low the 500 psi compressive strength may take up to 10 hours to develop. On deep gas wells with long liners, up to 30 hours may be required for the cement to develop 500 psi compressive strength. 2.4.1 Ultrasonic Cement Analyzer (UCA Test)

The UCA is a non-destructive test that gives sonic (compressive) strength data as a function of time. This test is usually run for 24 hours. The test is run for longer periods of time depending on the setting profile of the cement. The most important use of the data from the UCA is WOC (waiting on cement) time. It should be noted that this test uses uncontaminated cement slurry unless otherwise specified. Mud contamination in cement slurries can either shorten or lengthen the initial set of the cement. Mud contamination also reduces the final compressive strength.

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Shown above is the compressive strength of a 7” liner jobs for a Khuff gas well

2.4.2 Static Gel Strength Analyzer (SGSA Test)

The SGSA/UCA is a non-destructive test that gives static gel strength & sonic (compressive) strength data as a function of time. The most important use of the data from the SGSA are 1) the time that the cement slurry begins to gel (zero gel) and the time that the slurry reaches a gel strength of 1200 lb/100 ft2 (maximum gel) and 2) sonic strength which WOC (waiting on cement) time is determined. Hydrostatic pressure from the cement slurry is being lost at the Zero Gel point. At the maximum gel point the cement is so thick that fluids (including gases) can not pass through the cement column. For gas and fluid migration control, the shorter the time between zero gel and maximum gel the better the chance for preventing migration of downhole fluids through annulus to surface. Some literature states that gel strength of 500 lb/100 ft2 is the point that gas leakage can be contained. It should also be noted that this test uses uncontaminated cement slurry unless otherwise specified.

ULTRASONIC CEMENT ANALYZER

0

1000

2000

3000

0 50 100 150

TIME (HOURS)

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This Static gel strength data is for a 150 pcf cement used to cement across abnormal pressure Jilh formation

The Saudi Aramco Oilwell Cement lab has three SGSA/UCA units for the determination of static gel strength.

2.5 Pressurized Mud Balance & Densitometers

A pressurized fluid density balance is used to monitor the density of cement slurry that is mixed in the field. Non-pressurized fluid

SGSA/UCA Data

0

700

1400

2100

2800

3500

0:00

1:46

3:32

5:18

7:04

8:50

10:3

6

12:2

2

14:0

8

15:5

4Time

Temperature (°F)

Static Gel Strength(lb/100ft2)

CompressiveStrength (psi)

ZERO GEL

MAX GEL

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density balances (mud balance) should be avoided as errors of up to 15 pcf can occur due to entrapped air in the cement slurry. The pressurized density balance greatly reduces the volume of trapped in the slurry. High density cement slurries that are mixed with latex additives tend to trap more air than conventional cements. A pressurized fluid density balance should be used to calibrate any densitometers on the cementing units. Calibration should be made at two densities. It is recommended to calibrate the densitometer at the cement density and either the spacer or mud density. Once the calibration is complete, it should not be re-adjusted before or during the cement job unless confirmed by the pressurized density balance. The densitometers should be placed on the pressure side of pumps to guaranty accurate density measurements.

Pressurized Mud Balance

2.6 Free Fluid Test (free water)

If excess water is added to the cement beyond the requirement for fluidity or chemical reaction the solid particles separate from the slurry leaving the lighter excess water on top. This excess fluid is called free fluid. Neat class G cement mixed at 118 pcf should have a maximum free fluid of 1.4% according to API Spec 10A, Specification for Cements and Materials for Well Cementing, 22nd Edition, January 1995.

2.7 Rheology Test

Measuring the rheological properties of a cement slurry provide information of the cement slurry’s flow properties and settling tendency. The Fann model 35 rotational viscometer is the most widely used instrument used for determination of rheological properties for well cements. The rheological model is first determined from the Fann readings. Two models are considered for cement slurries (Power Law and Bingham Plastic). Turbulent flow is more easily achieved if n’ (power law) approaches 1 and YP (Bingham Plastic) approaches 0 or negative. Density settling is possible if n’ >1.0 or if YP<1.

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2.8 Mud-Spacer-Cement Compatibility Test Rheology data of cement, spacer and mud are used as guidelines to determine if the fluids are compatible. Rheology of the mixtures of various concentrations of cement-spacer, spacer-mud and cement-spacer-mud are taken to evaluate the effect of mixing of the three fluids. Sever gelling is noted when the rheology readings of the mixtures is much higher than the three initial readings of the cement, spacer and mud. Highly compatible fluids are determined when the Fann readings of the mixtures of the fluids fall in between the readings of the base fluids. Example of mud compatibility test is shown below.

API Compatibility of Heated Fluid Mixtures Well no./Job Type

Date: DD/MM/YYYY

Lab. Project No. xx-xxxxx

Data Taken @ xxxoF _______________________________________________________________________________

Viscosity Dial Reading Sample Type

600 300 200 100 6 3

100% Mud (xxx pcf) Oil / Water based

100% Spacer (xxx pcf)

100% Cement (xxx pcf)

75% Mud / 25% Spacer

25% Mud / 75% Spacer

75% Spacer / 25% Base Cement Slurry

25% Spacer / 75% Base Cement Slurry

25% Mud / 50% Spacer / 25% Base Cement Slurry

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2.9 Gas Migration Additives

Every service company has cement additives that helps reduce or eliminate gas migration during the setting of cement. Service companies also have cement additives that expand after the cement has set. Most additives that are supposed to prevent gas migration as the slurry sets produce cement slurry that has low fluid loss. Common additives to prevent gas migration during the setting of cement are D-600 (Dowell), Latex 2000 (Halliburton) and B-86L (BJ). All of these latex additives require the addition of stabilizer D-135, Stabilizer 434B and LS-1 respectively. Studies show that these polymers and latex additives fill the porosity of the cement matrix giving the cement very low permeability during the transition from slurry to solid. Expanding additives (Microbond-HT, B-82 and EC-2) all expand after the cement has set. This expansion is dependent on the exposure temperature of the cement. The maximum linear expansion with 5% (by weight of cement) of these additives is around 2.5%. It is possible for gas leaking up the annulus, after the cement job, to stop some time later (up to one month) due to late expansion of set cement, which contains these additives. Cements without expanding additives normally shrink after the hydration reaction is complete. Expanding additives and latex additives have been successfully used in cementing the abnormally pressured Jilh formation. More recently expanding additives have been used to cement the Arab-D open hole sections of deep gas wells. These wells have abnormal pressure due to their location, which is usually near to water injectors.

2.10 Cementing: Pre-Job Considerations for Slurry Design

The following will aid in planning a successful cement job.

?? What is the depth? MD, TVD? ?? What is the BHST? ?? What is the BHCT? ?? Has correction been made for Horizontal section of the well with respect

to BHCT? ?? What is the required density? (LOC or Abnormal Pressure Zones) ?? What is the estimated job time? ?? What is the chemical composition of the mix water? Ca+2,Mg+2,Cl-

values? ?? What is the chemical composition of the drilling fluid’s filtrate?

Ca+2,Mg+2,Cl- values? ?? Has bactericide been added to the mix water?

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?? Is there a potential for annular flow of gas or liquid as the cement sets? ?? Are there any special or unusual well conditions that must be

considered?

2.11 Pre-Job Meeting

Before every cement job, the Workover/Drilling Foreman will hold a pre-cement meeting to assure that the objectives are understood, assignments made and possible problems and solutions are discussed. Those involved in the meeting will be the Workover/Drilling Foreman, Workover/Drilling Engineer, Contract Toolpusher, Cementer(s) and the Driller. The liner hanger representative will be on location for liner jobs. The Engineer is available for cement slurry design, volume calculations and recommended pressures for bumping the plugs. He will also discuss the mixing, displacing, and thickening times. All three parties, Engineer, Foreman, and Cementer will individually calculate and compare the slurry and displacement volumes.

Assignments will be made as to who will: ?? Monitor the cement slurry weight. ?? Pump water and mud to the pump trucks or cementing unit. ?? Insert plugs. (Foreman & Cementer) ?? Check displacement volumes. ?? Catch samples. It doesn't do much good to catch a dry sample of

cement unless a container of mixing water is caught at the same time. All signals for communications will be reviewed. The pressure recorder on the cementing unit, the 5 or 6 pen drilling recorder and the radioactive Densiometer (if used) should all be inspected prior to the job to insure that they are working properly. The Foreman must not have any duties that will tie him down to any one operation. He must be free to supervise the overall operation and be able to go to any trouble that may occur. To avoid any potential problems in communications onshore, the pump truck should be located so that visibility is good between the driller's console and the pump truck. The best way to accomplish this is by placing the pump truck at the end of the catwalk.

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2.12 Cementing Information Form

Casing: Cement pumps: Cement:

_____________in OD _________in. Liner _______________sks _____________Gr. _________in. stk _______________bbl _____________in ID _________bbl/stk _______________PCF _____________in DD Mud Weight: _______________PPG _____________bbl/ft Cap. _________PCF Mud Buoy.

Factor:______ _____________ bbl/ft Disp. _________PPG _____________psi IYP Hole: _____________psi Col. ________in. size _____________lb M load ________ft MD _____________ lb MS load ________ft TVD _____________ft MD ________bbl/ft Cap _____________ft TVD ________ bbl/ft Cap + excess _____________ft DV lower _____________ft DVupper

Cement Pump: _______________stk/min = _____________bbl/min Mud Pump: _______________stk/min = _____________bbl/min

Casing Vol. 1)_______ft X ______bbl/ft = ________bbl ________stk 2)_______ft X ______bbl/ft = ________bbl ________stk 3)_______ft X ______bbl/ft = ________bbl ________stk Total casing inside volume = ________bbl ________stk

Annulus Vol. 1)_______ft X ______bbl/ft = ________bbl ________stk 2)_______ft X ______bbl/ft = ________bbl ________stk 3)_______ft X ______bbl/ft = ________bbl ________stk 4)_______ft X ______bbl/ft = ________bbl ________stk Total annulus volume = ________bbl ________stk Cem Head to Shoe: _________bbl = _________stk = ________min Head to Plug Bump : _________bbl = _________stk = ________min Bottom Plug Ruptures at: ___________psi* Proper DV plug Loaded?______________ Mixing Cement Time: ____________hours/minutes Displacing Cement Time: ______ Time Start_______ Time End_______ Total DVlower free fall plug time: ________min DVupper free fall plug time: ________min Top of Cement: 1)___________bbl / _________bbl/ft = ___________ft 2)___________bbl / _________bbl/ft = ___________ft 3)___________bbl / _________bbl/ft = ___________ft Total 1), 2) & 3) = ___________ft WOC Time = __________________ hours *Usually not run in Saudi Aramco Operations

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3.0 LAB TESTING OF CEMENT

3.1 Types of Tests

The cement lab routinely performs the following test on all field cement jobs. ?? Thickening Time (pumping time) ?? Fluid Loss (only if the slurry contains fluid loss additives) ?? Free fluid (free water, vertical or 45 degrees) ?? Rheology (determine turbulent flow rate) ?? Sonic Strength (compressive strength) ?? Slurry Density (pressurized density balance)

The cement lab can perform the following special test at the request of Drilling Operations or Drilling Engineering:

?? Static Gel Strength ?? Settling (density settling) ?? Expansion (both linear & radial) ?? Cement-Spacer-Mud compatibility ?? Gas Migration Potential ?? Cement ROP (Kick-off/Sidetrack Plugs)

3.2 When To Send Samples For Testing

Cement Samples should be sent in for testing for the following reasons: ?? Forman or Engineer suspects a problem with cement, cement additives

or mix water. ?? Service company lab not functioning ?? BHST > 2200F ?? Khuff wells: K2 wells, 13 3/8” casing and deeper, ?? K1 wells, 9 5/8” casings and deeper ?? All CTU Cement Jobs ?? Abnormal well conditions that may adversely affect the cement job. ?? Remote locations * *For remote locations, cement and rig water should be sent to Saudi Aramco and Service Company labs at least three days before the cement job.

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3.3 Initial Pilot Testing

This test is performed on lab cement, raw water (rig water if in stock) and lab additives. The most recent batch of cement from the factory is used to perform these tests. The standard tests are carried out. The most important function of performing this test is to save lab and rig time. Lab tests are performed to determine the retarder and fluid loss additive concentrations to meet the thickening time and fluid loss requirements. Pilot tests are not always performed prior to the writing of the program. Database searches are usually a good starting point in the design of the cement slurry.

3.4 Pilot Testing prior To Mixing

Samples of rig cement blend and rig water are collected and tested for the critical physical properties. This test is used to compare test results from the Aramco oilwell cement lab with the Service company’s lab. When comparing the thickening time results of both labs the following rule should apply: The thickening time results that have the highest concentration of retarder for the shortest acceptable thickening time is the cement formulation that should be mixed in the field. This applies only if all other tests like fluid loss, compressive strength development, etc. are within the requirements set by Workover/Drilling Engineering. These requirements are usually listed on the drilling program.

3.5 Field Sample Confirmation Testing

Samples of cement blend and mixing fluid (water plus cement additives) are sent in by the Service Company to both Saudi Aramco and service company oilwell cement labs. The results are usually faxed to the rig as soon as the thickening time is finished. The compressive strength data is usually sent the next day. For sample sizes see section 4.6.

4.0 MIXING CEMENT

The most important cement slurry property that can be measure in the field is slurry density. All lab tests are performed at the designed slurry density. Variation in slurry density in the field will produce cement slurry that may be unpredictable with respect to thickening time, fluid loss, rheology, free fluid, settling, static gel strength and compressive strength. The pressurized density balance is the best device readily available to field personnel to measure cement density. Batch mixing is the most effective way to ensure accurate slurry density.

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4.1 Mix Water Quality

The water used as pre-blended cement mix water should be reasonably fresh. If the water is too hard (high Calcium & Magnesium concentration) then alternative sources of water should be located. If the proposed water is high in Chloride then alternative sources of water should be located. If no acceptable water can be found send a sample of the proposed water to the cement lab and a softening treatment can be recommended in most cases. Softening treatments usually include adding Soda Ash and or Caustic causing a heavy white precipitate to settle to the bottom of the tank. The clear water should be skimmed off the top after the precipitate has settled to the bottom of the tank. Sometimes there are exceptions to this rule and they should be clearly defined in the drilling program. Biocide should be added to all mix waters that contain retarders, friction reducers or fluid loss additives. If any mix water is questionable then verify that such water is acceptable with the Workover/Drilling Superintendent, Workover/Drilling Engineer, Oilwell cement lab prior to blending chemicals.

4.2 Type of Chemicals and Quantity to Be Blended

The type of chemicals and quantity to be blended in the mix water will be specified in the drilling program or separate cementing procedure (supplement to the program) based on lab data. Mix those chemicals in the water on location. This allows an "on site" check of the water quality and type and quantity of chemicals blended. The Workover/Drilling Foreman is personally responsible for confirming that the proper types and amounts of chemicals and water are utilized in preparing the "mix water” blend.

4.3 Mix Water Blending and Storage System

Mix water must at all times be completely isolated from any source of contamination. The fluid handling system used to blend and pump the cement mix water should be completely isolated from all other fluid systems. A common manifold for the pre-flush, mix water, wash water and mud systems is not acceptable. It is acceptable to utilize a manifold for other fluids than cement mix water; i.e., pre-flush, wash water and mud. An individual fluid handling system of tanks and lines to the cementing unit is necessary for the mix water system. This will usually involve rigging up special lines and tanks. Rig up as necessary to achieve the above.

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4.4 Cement Job Quality

The preparation work prior to performing a complicated cement job is crucial to the success of the cement job. Batch Mix cement when possible. This gives you a positive check of the total batch of cement slurry before it goes downhole. On large jobs (where you can't batch mix), mix and pump a small amount to the desert before pumping cement downhole. This short 'pump test' will exercise the pump system and prove that the system can blend cement slurry with the fluid properties and weight desired. On large critical jobs, where one particular service company does not have the sufficient batch mixing capacity, employ the use of other service company batch mixers. It is recommended that only one Service Company pump the cement job. The Workover/Drilling Foreman should completely satisfy any question he might have regarding the mechanical reliability of the equipment, cementing technique to be used, mix water blend and mix water system reliability, well conditions, etc. before mixing cement. Don't hesitate to discuss any question with the Workover/Drilling Superintendent and eliminate as many problem areas as possible.

4.5 Pre-mixing additives

The tanks that the mixing fluid will be stored should be clean. Lines filling the tank should be flushed if used for purposes other than transporting water. Liquid Bactericide (biocide) should be poured on the bottom of the tank prior to filling the tank. Most resident bacteria colonies will be on the tank bottom. Bacteria thrive on cement chemicals like retarders, fluid loss additives and dispersants. Fill the tank with water. Mixing water should be cool. If Wasia water is used, it must be allowed to cool in open tanks for at least 24 hours. Past experience has indicated that many 'flash sets' were the direct result of using a Hot, saline water. The calcium & chloride content of the mixing water should be checked prior to mixing. Temperature, calcium and chloride content of the mix water should be recorded. Biocides generally have short half-lives. Additional biocide should be added every eight hour during the hotter months (April through October). During the cooler months (November through March) add biocide every 12 hours. Check with the Service Company or the Aramco cement lab for proper order of addition of cement chemicals prior to pre-mixing additives to the water.

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4.6 Sampling and Sample sizes

4.6.1 Sample Containers

All sample containers should be clean and free of moisture. The sample containers for dry cement should be air tight. The sample containers for water and the mixing fluid should be leak proof. Saudi Aramco Material Stock number (25-008-865) One-gallon wide mouth plastic bottles are good for both dry cement and mix fluid.

4.6.2 Dry Cement Sampling

For sampling dry cement either of two methods are acceptable. 1) First Aerate the cement for five to ten minutes, then open the hatch on the bulk storage unit and sample the cement blend approximately one foot (12”) below the top level. 2) Pressurize the bulk storage unit, then blow out a volume of cement that would represent the volume left in the line, then catch the required sample of dry cement.

4.6.3 Sampling of Mix Fluid

After all the cement additives have been mixed in the water, continue to circulate the fluid for thirty minutes. At this point sample the fluid from the top of the tank. Do not sample from a valve. If any fisheyes (dry additive that have gelled due to improper hydration) are floating on the top, do not include them in the sample.

4.6.4 Sample Size of Lab Testing

For pilot testing purposes, each lab should receive a minimum of two gallons of water from the same source that will be used for cementing. The minimum dry cement sample size for lab testing is one gallon for each laboratory and each stage. For a three stage cement job, where all three stages are requested to be tested, the samples should be distributed as follows: Three dry cement samples would go to the Saudi Aramco Cement lab and the other three would go to the Service Company lab. The minimum mix water sample size is one gallon. This is approximately twice the amount required to mix with one gallon of cement. Additional water is required because adjustments may be needed to lengthen the thickening time of the field mixed sample. Usually, the labs will have some leftover cement blend from the pilot

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tests performed prior to mixing. The lab will only resort to using that sample as a last resort.

4.6.5 Sample Labeling

All samples should be labeled as follows: ?? Well Name & No. ?? Rig Name & No. ?? Date ?? Job Description & Stage ?? Description of Sample ?? Include all the additives that are mixed in the water or blended in

the cement. ?? Name of Lab (Saudi Aramco or Service Co.)

5.0 BALANCED PLUGS

Many operations require that a cement plug be set in the open-hole or casing to plug back a well to a shallower depth for a number of reasons. The most important and common applications include the following:

A) Balanced Plug Method

The ideal cement plug is placed so there is no tendency for the cement slurry to continue to flow in any direction at the time pumping is stopped. This involves balancing the hydrostatic pressures inside and outside the drill pipe or tubing so that the height of cement and displacing fluid inside the drill pipe or tubing equals the height of fluids in the annulus. The pipe or tubing is then pulled slowly from the slurry, leaving the plug in place. To allow the pulling of a "dry" string of tubing, common field practice is to cut the displacement volume short by 1/2 to 1 barrel. The characteristics of the mud are very important when balancing a cement plug in a well, particularly the ability to circulate freely during displacement. Whenever possible, the mud should be conditioned thoroughly to uniform densities and rheological properties and the same mud used as the displacement fluid. Movement of well fluids while the cement plug is setting may affect the quality of the plug, therefore, it is imperative that care be taken in accurately spotting the slurry and moving the pipe slowly out of the slurry to avoid backflow, slugging, or swabbing action. The amount of pre-flush or spacer, cement

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slurry, and volume of displacement fluid must be carefully calculated to ensure equal volumes of fluid ahead of and behind the cement plug as it is being placed in the hole. The quantities that must be calculated are as follows:

A) Determine the drill pipe or tubing capacity, the annular capacity, and

hole or casing capacity. B) The length of the cement plug or the number of sacks of cement for a

given length of plug. C) The volumes of spacer needed before and after the cement to balance

the plug properly. D) The height of the plug before the pipe is withdrawn. E) The volume of the displacement fluid.

Balanced Plug Technique

M

M M

W

M

M

M MM

W

M

W W

W

M MM

M

W W

M MM

W

(a) Displacing cement.

(b) Cement, water and mud balanced.

(c) Pulling stringabove top of cement.

(d) Reversing out.

M = MudW = Water

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Balanced Plug Formulas

Cement requirements: N = L * C h where: N = sacks of cement Y L = plug length, ft. Ch = hole or casing capacity, cu ft/ft Y = slurry yield, cu ft/sack Spacer Volume behind the slurry to balance plug: Vb = C p* V a where: Va = spacer volume ahead, bbl Ca Vb = spacer volume behind, bbl Ca = annulus capacity, cu ft/ft Cp = pipe capacity, cu ft/ft Length of balanced plug before pulling pipe from slurry: Lw = N * Y where: Lw = Plug length before pulling the (Ca+Cp) pipe from the slurry, ft Mud Volume for pipe displacement: Vd = [(Lp - Lw) * Cp] - Vb where: Vd = displacement volume, bbl Lp = total pipe length, ft *Cp = pipe capacity, bbl/ft Vb = spacer volume behind, bbl * Note pipe capacity, Cp, is expressed in different units.

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5.1 Loss Circulation Plugs

When mud circulation is lost during drilling, it is sometimes possible to restore lost returns by spotting a cement plug across the thief zone and then drilling back through the plug. Thixotropic cements or low thickening time cements are usually recommended for this application. See Chapter 2, Section F for more details.

5.2 Kick-Off/Sidetrack Plugs

5.2.1 Kicking Off:

For Deviated and Horizontal wells, cement Kick-off plugs can be used. Generally these plugs are not as effective as using a whip stock. Kick-off cement plugs are set in open hole. Additives are mixed in the cement to both densify and lower the ROP in the cement plug. Removing the water (higher density cements) reduces the porosity which lowers the ROP in the set cement. Frac proppants or frac sand can be added to the cement slurry to aid in reducing the ROP in the cement plug to obtain a more successful Kick-off. Ample curing (WOC) time should be given to the cement plug so that the plug obtains at least 90 % of its final strength. It is very difficult to get a cement plug that is harder than the formation unless the kick-off point is in a weak unconsolidated sand or very high porosity zone.

5.2.2 Sidetracking:

In sidetracking a hole around unrecoverable junk, such as a stuck drillstring, it is necessary to place a cement plug above the junk at a required depth that will allow sufficient distance to kick off the cement plug and drill around, bypassing, the original hole and junk. High-density cement plugs are usually recommended for this application.

5.3 Isolation/Abandonment Plugs

For more details on Abandonment guidelines and cement plugs, see Chapter 2, section G.

Zone Isolation: One common reason for plugging back is to isolate a specific zone. The purpose may be to recomplete a zone at a shallower depth, to shut-off water, or to prevent fluid migration into a low-pressure depleted zone.

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Abandonment: To seal off selected intervals of a dry hole or abandon an older, depleted well, a cement plug is placed at the required depth to prevent zonal communication and migration of fluids in the wellbore.

ProducingZone

CementPlug

DepletedZone

PLUG BACK DEPLETED ZONE

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6.0 DISPLACEMENT PROCEDURES

6.1 Casing

Rig pumps will normally be used to displace the cement in full string cement jobs. When using the rig pumps, pre-calibrate the number of strokes per barrel using a trip tank. This will insure that the pump rate can be reduced prior to the plug bumping. Pump displacement fluid until the plug has bumped but DO NOT OVER DISPLACE MORE THAN ½ THE SHOE TRACK CAPACITY. Record whether circulation was maintained. Record the plug bumping pressure. After the plug bumps, hold pressure for a few minutes and then slowly release pressure to make sure the float equipment is holding. On Multistage Cementing jobs where displacement type plugs are used the same displacement rule applies. Usually the bypass plug is displaced 10 barrels short of the bypass baffle. In this case the over displacement would equal 10 barrels plus half the shoe track volume. If the plug has not bumped (landed or seated in the DV) by this time then hold pressure until the cement has set. The Saudi Aramco cement lab has many compressive strength records on the setting behavior (WOC time) of class G cement at many different conditions. They can provide the rig with a WOC time.

6.2 Liners

On all liner jobs, the pumps on the cement truck will be used for displacement, unless under emergency conditions (volumetric displacement is more accurate than a stroke counter). Additional mud de-foamer is usually required to remove entrapped air from the mud and get more accurate volume on the displacement. If you can see the pressure build up (usually about 800 psi) as the 'dart' shears the brass pins before releasing the 'wiper 'plug'; make a note of this volume. This volume added to the liner volume can be used to more accurately determine when the 'wiper plug' will seat in the baffle. If you miss the shear pressure and the 'wiper plug' does not bump after the calculated displacement, DO NOT OVER DISPLACE. It is far easier to drill out cement than it is to squeeze the shoe! Generally, it is recommended to pull three to five stands before reversing out excess cement. Special instructions will be included in the drilling program should alternative procedures be required after the cement is pumped on liner liner jobs. Do not displace cement with oilmud, or water based mud or brine that has high Calcium content.

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6.3 Turbulent Flow

Turbulent flow is always the best flow regime for cleaning mud off casing and formation face. Unfortunately, turbulent flow can not be achieved easily due to formation frac gradient, balance pressure or horsepower required to achieve turbulent flow. Lab reports show the rate required to achieve turbulent flow. Turbulent flow is easier achieved in smaller cross sectional areas. The same cement slurry would reach turbulent flow faster in a 4 ½” liner in 6 inch hole than a 13 3/8” casing in a 17.5” hole.

7.0 REMEDIAL CEMENTING

7.1 Bradenhead Squeeze

The original method of squeezing was the Bradenhead method, which is accomplished through tubing or drillpipe without the use of a packer. BOP rams are closed around the tubing or drill pipe and the injection test carried out to determine the formation breakdown pressure. The cement slurry is then spotted as a balanced plug, and the work string is pulled up and out of the slurry. The annulus is then shut off by closing the annular preventers or pipe rams around the cementing string. Displacing fluid is pumped down the tubing forcing the cement slurry into the zone until the desired squeeze pressure is reached or until a specific amount of the fluid has been pumped. This method is used extensively in squeezing shallow wells and sometimes when squeezing off zones of partial lost circulation during drilling operations.

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SpotCement

Rev erseCirculat ion

ApplySqueez ePressure

Br adenhead Squeeze

When shallow wells are squeezed by this method, fluids in the tubing are displaced into the formation ahead of the cement. In deeper wells, the cement may be spotted halfway down the tubing before the annulus is shut in at the surface. The applicability of Bradenhead squeezing is restricted because the casing must be pressure tight above the point of squeezing and because maximum pressures are limited by the burst strength of the casing and the pressure rating of the wellhead and BOP equipment at the surface. Also, it is sometimes difficult to spot the cement accurately across the interval without using a packer.

7.2 Packer Squeeze

Packer Squeeze

The main objective of this method is the isolation of the casing and wellhead while high pressure is applied downhole. The selective testing and cementing of multiple zones is an operation where isolation packers are commonly used.

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The packer squeeze method uses either an expendable, drillable, packer such as a cement retainer or a retrievable packer tool run on a work string and positioned near the top of the zone to be squeezed. This method is generally considered superior to the Bradenhead method since it confines pressures to a specific point in the hole. Before the cement is placed, an injection test is conducted to determine the formation breakdown pressure. When the desired slurry volume has been pumped or squeeze pressure is obtained, the remaining cement slurry is reversed out. Squeezing objectives and zonal conditions will govern whether high pressures or low pressures are used.

BrineWater

Fresh WaterPre-Flush

CementSlurry

DisplacementBrine

Brine

CementRetainer

Fresh WaterSpacer

Perfs

BrinePumped

CementSlurry atPerfs

FreshWaterSpacer

PACKER SQUEEZE JOB

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There are two common methods for placing the cement at the zone of interest- Bullheading In this method, a packer is set and pressure is applied to the annulus. An injection rate is established into the zone; then the cement is mixed and pumped down the work string. The mud, or brine, as well as the cement is then forced into the zone under pressure until the desired squeeze pressure is obtained. The packer is not released until the job is completed. Sometimes it is necessary to bullhead cement between casing strings into the annulus in order to bring cement back to surface and to seal off the annulus. If this is required, precautions must be taken not to exceed the collapse rating of the inner casing string when squeezing the cement slurry down the casing annulus.

Spotting In this method, after establishing an injection rate into the zone, the packer is released or the by-pass opened. The cement slurry is circulated down the work string to just above the packer. The packer is then re-set or the by-pass closed, and the cement slurry is squeezed away into the zone until the desired squeeze pressure and volumes are reached. With this method, the amount of mud or brine that will be forced into the perforations ahead of the cement is kept to a minimum.

App liedCasi ngPressu re

Cem ent

Mud

Pu mp C e m en t w it h Pa c ke r se tD i sp la c e M u d i n t o F o r ma t i o nHo l d A n n u l u s Pr e ss u r e

AppliedCasi ngPressure

Di splacementFlui d

A p p ly Sq u e e z ePr e ss u r e

Mud

Cem ent

BU L LH EA D I NG

Cement

Mud

Sp o t Ce m en t

Ap plie dCasi ngPressure

Mud

Cem ent

St a b in to Pac k e rA p p l y C as i n g Pr es s ur eD i sp la c e C e me n tA p p l y Sq u e e z e P r e s su r e

Di splacementFlui d

SPOT T I NG

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Packer Squeeze Tools The use of squeeze packers makes it possible to apply higher pressures to specific downhole points than can be applied with the Bradenhead method. The two commonly

used packers are the drillable and the retrievable. Drillable Squeeze Packers Drillable packers, which are expendable, are left in the well and can be drilled out after the squeeze operation. The drillable packer contains a poppet-type backpressure valve to prevent backflow at the completion of displacement and a sliding valve for when it is desirable to hold pressure in either or both directions. The sliding valve makes it possible to support the weight of the hydrostatic fluid column and relieve the cement of this weight while it is setting. Excess cement can be reversed out of the drillpipe without applying the circulating pressure to the squeezed area below the packer. The tubing or drillpipe can also be withdrawn from the well without endangering the squeeze job. Another advantage is that they can be set close to the perforations or between sets of perforations and are easily drilled if required. Cement retainers set on drillpipe or wireline are used instead of packers to prevent backflow when no cement dehydration is expected or when high negative differential pressures may disturb the cement cake. In certain situations, potential communication with upper perforations could make use of a retrievable packer a risky operation. When cementing multiple zones, the cement retainer will isolate the lower perforations, and subsequent zone squeezing can be carried out without waiting for the cement to set. Cement retainers are drillable packers provided with a two-way valve that prevents flow in either or both directions. The valve is operated by a stinger run at the end of the work string. Drillable bridge plugs are normally used to isolate the casing below the zone to be treated. They are of similar in design to the cement retainer, and they can be set on wireline or on drillpipe. Bridge plugs do not allow flow through the tool. Drillable

Squeeze Packer

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Retrievable Squeeze Packers Retrievable packers are usually rented on a job basis and, after the squeeze job, is removed from the well. Unlike drillable packers, the retrievable packer can be set and released as many times as necessary. Retrievable packers with different design features are available on the market. Most are of a non-drillable material and are available in most API sizes. The ones used in squeeze cementing, compression or tension set packers, have a bypass valve to allow the circulation of fluids when running in and once the packer is set. This packer feature permits the spotting of pre-wash fluids and cement down to the zone, cleaning of tools after the job, reversing of excess cement without excessive pressures, and prevents a piston or swabbing effect when tripping the packer in or out of the hole. Retrievable bridge plugs are easily run and operated tools with the same function as the drillable bridge plugs. They are generally run in one trip with the retrievable packer and retrieved later after the cement has been drilled out. Most operators will spot frac sand or acid soluble calcium carbonate on top of the retrievable bridge plug before doing the squeeze job to prevent cement from settling over the top of the retrievable bridge plug.

RetrievableSqueeze Packer

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8.0 CEMENTING EQUIPMENT

Schlumberger/Dowell Cementing Equipment

Left: 200 barrel Batch Mixer, Right: Batch Mixer inside view

Left: Cement Pump Truck Right: Field Bulk Cement Storage Unit

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Halliburton Cementing Equipment

Left: 100 barrel Batch Mixer Right Cement Pump Truck

Left: Bulk Cement Storage Unit Right: 18 5/8” Cementing Head

(2000 cubic feet) BJ Services Batch Mixer

Above: 120 barrel Cement Batch Mixer

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WELLHEADS

1.0 INTRODUCTION

1.1 Wellhead Function 1.2 Tree Function 1.3 Ring Joint Flanges

1.3.1 Ring Gaskets 1.4 Typical Wellhead

1.4.1 Casing Head 1.4.2 Casing Spool 1.4.3 Tubing Spool 1.4.4 Tubing Bonnet (Tubing Head Adapters) 1.4.5 Tree Assemblies

2.0 STANDARD SAUDI ARAMCO WELLHEAD COMPONENTS

2.1 Casing Heads (Landing Base) 2.2 Casing Spools 2.3 Tubing Spools 2.4 Tubing Hangers (Extended Neck) for Oil Service 2.5 Tubing Hangers (Extended Neck) for Gas Service 2.6 Tubing Bonnets for Oil Service 2.7 Tubing Bonnets for Gas Service (With Master Valve) 2.8 Tubing Bonnets for Special Service (Electric Penetrators) 2.9 DSDPO Flange, Double Studded Double Pack-Off Flange 2.10 Trees 2.11 Loose Valves 2.12 Valve Bores and End-To-End Dimensions

3.0 INSTALLATION AND TESTING PROCEDURES

3.1 Primary and Secondary Seals 3.2 Casing Head 3.3 Slip Type Casing Hangers 3.4 Casing and Tubing Spool 3.5 Tubing Hangers 3.6 Tubing Bonnet and Trees 3.7 Trees

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4.0 BACK PRESSURE VALVE INSTALLATION PROCEDURES

4.1 Back Pressure Valves for Oil Well Service 4.2 Back Pressure Valves for Khuff Gas Service 4.3 Type ‘H’ Back Pressure and Two Way Check Valve 4.4 Running Procedures for Type ‘H’ plugs.

4.1.1 Method 1: Installation Using the Retrieving/Running Tool 4.1.2 Method 2: Installation Using the Running Tool

5.0 RE-STUBBING CASING

5.1 Typical Procedure for Arab-D Producer 5.2 Typical Procedure for Arab-D PWI Well

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WELLHEADS 1.0 INTRODUCTION

1.1 Wellhead Function

The wellhead performs three important functions: A) Provides connection and support for blow out preventers and other well

control equipment. B) Provides a sealed connection and support for each tubular string. C) Provides a connection and support for the tree.

1.2 Tree Function

The tree also performs three functions: A) Controls the flow of fluids from the well bore. B) Provides a means of shutting on the well. C) Provides a means of entering the well for servicing and workover.

1.3 Ring Joint Flanges

Flanges are the most commonly used end connections in the oil industry apart from welds and threads (Figure 2E-1). API has standardized flanges that are covered in API Spec 6A. ASME/ANSI has standardized flanges that are covered by ASME/ANSI Spec 16.5. Because Saudi Aramco uses both API and ANSI flanges, knowledge of the similarities and differences is required. Some ANSI ring joint flanges will mate with API flanges but the pressure ratings are different.

24.0000

13.66

14.53

15.47 3.44

21.000

1.500" X 20 BOLT HOLES

RING GROOVE

Figure 2E-1: API 13-5/8" 3,000 psi Flange

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ANSI Class 600 flanges will mate to API 2,000 psi, ANSI Class 900 flanges will mate to API 3,000 psi and ANSI Class 1500 flanges will mate to API 5,000 psi. If an ANSI flange is connected to an API flange, the connection is DERATED to the pressure rating of the ANSI flange because it will not hold as much pressure as the API flange. A comparison of some common flange sizes is given in Table 2E-1 and working pressures of ANSI flanges by temperature is given in Table 2E-2.

Table 2E-1 Comparison of Common API and ANSI Flanges

Size/WP Ring OD Bolt No. of Bolts Bolt Circle

API 12"/3M R-57 24 1 3/8 20 21

ANSI 12"/900 *** 24 1 3/8 20 21

API 11"/5M R-54 23 1 7/8 12 19

ANSI 10"/1500 *** 23 1 7/8 12 19

API 11"/3M R-53 21 1/2 1 3/8 16 18 1/2

ANSI 10"/900 *** 21 1/2 1 3/8 16 18 1/2

API 7"/5M R-46 15 1/2 1 3/8 12 12 1/2

ANSI 6"/1500 *** 15 1/2 1 3/8 12 12 1/2

API 7"/3M R-45 15 1 1/8 12 12 1/2

ANSI 6"/900 *** 15 1 1/8 12 12 1/2

API 4"/3M R-37 11 1/2 1 1/8 8 9 1/4

ANSI 4"/900 *** 11 1/2 1 1/8 8 9 1/4

API 3"/3M R-31 9 1/2 7/8 8 7 1/2

ANSI 3"/900 *** 9 1/2 7/8 8 7 1/2

API 2"/5M R-24 8 1/2 7/8 8 6 1/2

ANSI 2"/1500 *** 8 1/2 7/8 8 6 1/2

*** The ring groove size must be checked for each flange.

Note:

?? Only API flanges are used on producing wellheads, trees and drill through equipment such as blowout preventers.

?? ANSI flanges, fittings and valves are used on water wells, pipelines,

gas plants and some surface production units.

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Table 2E-2 Ratings for Group 1.1 Materials

Working Pressure by ANSI Class, psig

Temperature °F150 300 400 600 900 1500 2500 4500 -20 to 100 285 740 990 1,480 2,220 3,705 6,170 11,110

200 260 675 900 1,350 2,025 3,375 5,625 10,120 300 230 655 875 1,315 1,970 3,280 5,470 9,845 400 200 635 845 1,270 1,900 3,170 5,280 9,505 500 170 600 800 1,200 1,795 2,995 4,990 8,980

Only API flanges are used on producing wellheads, trees and drill through equipment such as blowout preventers. ANSI flanges, fittings and valves are typically used on water wells, pipelines, gas plants and on some surface production units. 1.3.1 Standard Ring Gaskets:

At Saudi Aramco our standard is the type R ring gasket for low pressure connections and the BX for high pressure applications. The oval ring and octagonal ring are both API type R ring gaskets as shown in Figure 2E-2. These gaskets are designed to be used in 2,000, 3,000 and 5,000 psi flanges only. Stud bolts used with type R gaskets must perform the double duty of holding pressure while keeping the gasket compressed. When making up the flanges, the curved surface of the relatively soft oval ring is mated with the flat surfaces of the harder flange ring groove. A small flat is pressed on the curved section of the oval ring. The size of this flat depends on the bolt make-up torque. This is the main reason that ring gaskets can only be used one time and must be replaced with a new gasket each time a flange is made up.

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R OVAL

RX

R OCTAGONAL

BX

Figure 2E-2: API Ring Gaskets

As normal tightening proceeds, forces accumulate and deform the ring to produce a seal. By the time all bolts around the flange have been tightened, the first bolt is loose again. In most API flanged connections with type R gaskets, it is necessary to tighten bolts around the flange several times to reach a stable condition. The octagonal R does not have to deform as much as the oval R to create a seal. When internal pressure forces become great enough to cause flexing in an API connection that uses either of the type R gaskets, the bolting contact force on the seal ring begins to decrease. If flange separation forces exceed the limited resilience of the seal, leakage will occur. External shock loads, such as drilling vibration, add to the compressive loading of the stud bolts. This further deforms the gaskets and can cause leaks making repeated tightening necessary.

The API type BX ring gasket has been developed primarily for use in 10,000 psi and greater working pressure equipment. There are certain exceptions to this where the BX type gasket is used in 5,000 psi flanges. This pressure energized ring joint gasket is for use with type BX flanges only and is not interchangeable with type R or RX gaskets. The BX flanges are designed to make up face to face at the raised face portion of the flanges. Figure 2E-2 illustrates the BX flanges at initial contact.

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1.4 Typical Wellhead:

The typical wellhead for a three string well will consist of: (Figure 2E-3): A) The casing head (sometimes referred to as the Landing Base or

Bradenhead). B) The Intermediate casing head (or Casing Spool); C) The Tubing Head (or Tubing Spool); D) The Tubing Bonnet (or Tubing Head Adapter); E) The Tree.

TREE

TUBING SPOOL

INTERMEDIATECASING HEAD

CASING HEAD

TUBING BONNET

Figure 2E-3: A Three String Wellhead

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1.4.1 Casing Head: The casing head is attached to the top of the surface casing (Figure 2E-4). Since the other tubular strings are tied to the casing head, the surface casing must support the weight of all the subsequent casing and tubing strings, along with the entire wellhead system.

CONDUCTOR PIPE

SURFACE CASING

BASEPLATE

INTERMEDIATE CASING

CASING STUB

CASING HANGER

HEADCASING

CEMENT

CASING - HOLEANNULUS

Figure 2E-4: The Casing Head

The casing head is welded onto the surface casing. The base plate (support unit) is installed under the casing head and is not welded to the conductor or casing head. The casing head accepts the next string of casing, either a protective string or the production string depending on the well design. The next string of pipe is hung by means of a casing hanger in the casing head. The intermediate string is hung in the casing head with a casing hanger and cemented in place. The casing hanger holds the

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intermediate casing and seals the casing to casing annulus. Hangers are discussed in more detail later in this chapter.

1.4.2 Casing Spool: The casing spool is bolted onto the casing head (Figure 2E-5). It can be used to suspend either the production casing string, as shown, or an additional string of protective casing. For each additional protective string, an additional casing spool is required.

PRODUCTION

CASING

CASING SPOOL

CASING HEAD

INTERMEDIATE CASING

SURFACE CASING

CASING STUB

Figure 2E-5: The Casing Spool

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The casing spool consists of a lower flange for connection to the casing head and an upper flange for connection to the subsequent wellhead section. A cylindrical bore with shoulders is machined into the upper half to receive the casing hanger. The casing spool contains a primary seal (the casing hanger) inside the top flange and a secondary seal (the packoff) located inside the lower flange (Figure 2E-6). The names primary seal and secondary seal were derived from a pressure change situation. If the casing spool has a 3,000 psi bottom flange and a 5,000 psi top flange, the casing hanger seal is the first seal to prevent the 5,000 psi fluid from getting to the 3,000 psi flange face. The packoff bushing is the second preventive seal. The secondary seal performs essentially the same function as the primary seal of the casing head. Aramco has two wellhead manufacturers supplying wellhead material. Each system has its own secondary seals. Cooper (makes Cameron & McEvoy) supplies an X-bushing and Vetco Gray supplies an AK bushing. The AK bushing is redesigned from the original CWC bushing so that regardless of which spool is installed, the casing stub (Figure 2E-10) is cut to the same height for the Vetco Gray spool as for the Cameron or McEvoy spool.

RING GASKETGROOVE

CASING HANGER

SECONDARY SEAL

TEST PORT

INJECTION PORT

RING GASKET

RING GASKETGROOVE

Figure 2E-6: The Casing Spool with Secondary Seal

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A ring gasket, made of a special metal alloy, is placed between all flanged connections. The ring gasket fits into specially machined grooves in the upper flange of the casing head and the lower flange of the intermediate casing head. The gasket serves to contain pressures in the wellhead in the event that either or both the primary and secondary seals should fail. Each ring gasket is designed to withstand a maximum pressure that the tubulars will be exposed to during the life of the well. A further explanation of ring gaskets and pressure ratings is discussed later. The side outlets on the casing spool are used to check and relieve pressure inside the casing - casing annulus.

1.4.3 Tubing Spool The tubing head suspends the production tubing and seals off the tubing casing annulus (Figure 2E-7). Like the casing spool, the tubing head includes a secondary seal and side outlets. The top flange of the tubing head is used to connect blowout preventers during conventional workover operations; that is, workovers that require pulling the tubing. The lower flange connects to the top flange of the section below it. A ring gasket is also used between the flanged connections.

PRODUCTIONCASING

TIE DOWN PIN

TUBING

TUBING

HANGER

POLISHED NIPPLE

TUBING HEAD

Figure 2E-7: The Tubing Head

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The tubing hanger assembly performs essentially the same function as the casing hanger; i.e., it suspends the tubing and seals off the tubing - casing annulus. The full weight of the tubing string is virtually supported by the tubing hanger. The tubing hanger is usually equipped with a polish nipple to seal inside the tubing bonnet (Figure 2E-8). However, sometimes the tubing hanger is equipped with an extended neck that is an integral part of the hanger. The polish nipple is a separate item threaded into the tubing hanger. The side outlets of the tubing head can be accessed to; (1) inject a fluid into the tubing casing annulus, as in a gas lift operation; (2) monitor annulus pressure; (3) test annulus for leaks; (4) relieve pressure in the tubing - casing annulus; and (5) supply an exit for the sub-surface safety valve control line. The tie-down pins serve to secure the tubing hanger in the spool. If the tubing is attached to a downhole packer, there is a possibility that the tubing will expand under flowing conditions causing a force large enough to break the seal between the hanger and the spool. For a more detailed view of a tubing hanger refer to Figure 2E-12.

1.4.4 Tubing Bonnet (Tubing Head Adapters): The tubing bonnet (Figure 2E-8) is the equipment that allows the tree to be attached to the wellhead. It has a sealing mechanism, extended neck or polish nipple, which keeps wellbore fluid from coming in contact with the tubing head or the tubing hanger. The tubing bonnet configuration is usually equipped with studs on top and a flange on the bottom although it can be supplied flange by flange or stud by stud. Ring gaskets are installed on top and on the bottom.

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PRODUCTIONCASING

TUBING HEAD

TUBING

TUBING

HANGER

TUBING BONNET

WITH POLISH NIPPLE

Figure 2E-8: Tubing Bonnet and Polish Nipple

1.4.5 Tree Assemblies: The tree is a system of gate valves that regulates the flow of fluids from the well, opens or shuts production from the well, and provides entry into the well for servicing. The tree is connected to the uppermost flange of the wellhead that, typically, is the upper tubing head flange. A typical tree includes several gate valves, a flow tee and a tubing bonnet. This system routes well production into the flow line. The flow line then conducts the fluids from the tree to surface treating facilities. The gate valves are technically the same but are referred to by different names. They include the master valve, the wing valve and the crown valve. Each valve can have a backup and the valves can operate manually or hydraulically. Each valve has only two operating positions; fully open or fully closed. They are used to open or shut the flow from the well.

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2.0 SAUDI ARAMCO STANDARD WELLHEAD COMPONENTS

Saudi Aramco currently purchases wellhead components from four manufacturers. These are Cameron, FMC, Gray and WGI. These components are interchangeable as wellhead sections, that is you may use a Cameron Casing Head, then install a FMC Casing Spool, then a Gray Tubing Spool with a WGI Tubing Bonnet. You cannot, however interchange casing or tubing hangers. A Cameron head must have a Cameron hanger, a FMC head must have a FMC hanger etc. Saudi Aramco stocks all of the major components to drill, complete and workover our wells. The following sections are a listing of the major components by size, pressure rating and service type. Refer to the Drilling and Workover Materials list for current Stock Numbers.

2.1 Casing Heads (Landing Bases):

Top Flange Bottom Casing Hanger 13” 3M 13-5/8” Socket Weld 9-5/8” Automatic 13” 5M 13-5/8” Socket Weld 9-5/8” Automatic 20” 3M 18-5/8” Socket Weld 13-5/8” Automatic 26” 3M 24” Socket Weld 18-5/8” Automatic 26” 3M 26” Socket Weld 18-5/8” Automatic

2.2 Casing Spools:

Top Flange Bottom Flange Packoff Casing Hanger 11” 3M 13” 3M 9-5/8” 7” Automatic 11” 5M 13” 3M 9-5/8” 7” Automatic 11” 5M 13” 5M 9-5/8” 7” Automatic

11” 10M 13” 5M 9-5/8” 7” Automatic 13” 3M 13” 3M 9-5/8” 7” Automatic 13” 3M 20” 3M 13-3/8” 9-5/8” Automatic 13” 5M 13” 5M 9-5/8” 7” Automatic

13” 10M 16” 5M 13-3/8” 9-5/8” Automatic 20” 3M 26” 3M 18-5/8” 13-3/8” Automatic

2.3 Tubing Spools:

Top Flange Bottom Flange Packoff Outlet Size 11” 3M 11” 3M 7” 2” X 2” 11” 3M 11” 3M 7” 6” X 2” 11” 3M 13” 3M 9-5/8” 2” X 2” 11” 3M 13” 3M 9-5/8” 6” X 2” 11” 5M 13” 5M 9-5/8” 2” X 2”

11” 10M 13” 10M 9-5/8” Metal Seal 3” X 3”

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2.4 Tubing Hangers (Extended Neck) for Oil Service:

Bowl Size Tubing Size Thread BPV Prep 11” 2-3/8” EUE 2” Type ‘H’ 11” 2-7/8” EUE 2-1/2” Type ‘H’ 11” 3-1/2” EUE 3” Type ‘H’ 11” 4-1/2” New Vam 4” Type ‘H’ 11” 7” New Vam 7” Type ‘J’

2.5 Tubing Hangers (Extended Neck) for Gas Service:

Bowl Size Tubing Size Thread BPV Prep 11” 3-1/2” PH-6 3” Type ‘H’ 11” 4-1/2” New Vam 4” Type ‘H’ 11” 5-1/2” New Vam 5” Type ‘H’ 11” 7” New Vam 7” Type ‘K’

2.6 Tubing Bonnets for Oil Service:

Studded Top Flange

Bottom Flange Seal Neck Diameter (inches)

2” 3M 11” 3M 5-1/2 3” 3M 11” 3M 5-1/2 4” 3M 11” 3M 5-1/2 7” 3M 11” 3M 7-5/8 7” 5M 11” 5M 7-5/8

2.7 Tubing Bonnets for Gas Service (with Master Valve):

Valve Bore Studded Top Flange Bottom Flange 4-1/2” 7” 10M 11” 10M 5-1/2” 7” 10M 11” 10M

7”nom. (6-3/8” act.) 7” 10M 11” 10M

2.8 Tubing Bonnets for Special Service (Electric Penetrators): Studded Top Flange Bottom Flange Penetrator

7” 3M 20” 3M Genco Model 1 3” 3M 11” 3M Genco Model 1 4” 3M 11” 3M Genco Model 1

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2.9 DSDPO Flanges: Casing Size Studded Bottom

Flange Studded Top

Flange 4-1/2” 11” 3M 11” 3M 4-1/2” 13” 3M 13” 3M

5” 11” 3M 11” 3M 5” 13” 3M 13” 3M 7” 11” 3M 11” 3M 7” 11” 5M 11” 5M 7” 11” 5M 11” 10M 7” 11” 10M 11” 10M 7” 13” 3M 13” 3M

9-5/8” 13” 3M 13” 3M 9-5/8” 13” 3M 13” 5M 9-5/8” 13” 5M 13” 5M 9-5/8” 13” 5M 13” 10M 9-5/8” 13” 10M 13” 10M 13-3/8” 13” 3M 20” 3M 13-3/8” 13”5M 20” 3M 13-3/8” 16” 5M 20” 3M 18-5/8” 26” 3M 26” 3M

2.10 Trees:

Size Working Pressure Service 2” 3M Onshore 3” 3M Onshore 4” 3M Onshore 7” 3M Onshore 4” 3M Offshore 7” 3M Offshore 7” 5M Offshore 3” 10M Khuff 4” 10M Block Khuff

Size Working Pressure Service 5” 10M Block Khuff 7” 10M Block Khuff

10” 3M Power Water Injection

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2.11 Loose Valves: Size Working Pressure Type

2” 3M Manual 3” 3M Manual 4” 3M Manual 7” 3M Manual 2” 5M Manual 3” 5M Manual 4” 5M Manual 3” 10M Manual 4” 10M Manual 7” 10M Manual 2” 3M Hydraulic Actuator 3” 3M Hydraulic Actuator 4” 3M Hydraulic Actuator 7” 3M Hydraulic Actuator 2” 10M Hydraulic Actuator

2.12 Valve Bores and End-To-End Dimensions

Nominal Size (inches) Valve Bore (inches) End-to-End (inches) 3,000 psi Working Pressure

2-1/16 2.06 14.62 2-9/16 2.56 16.62 3-1/8 3.12 17.12

4-1/16 4.12 20.12 5-1/8 5.12 24.12

7-1/16 6.38 24.12 5,000 psi Working Pressure

2-1/16 2.06 14.62 2-9/16 2.56 16.62 3-1/8 3.12 18.62

4-1/16 4.12 21.62 5-1/8 5.12 28.62

7-1/16 6.38 29.00 10,000 psi Working Pressure

2-1/16 2.06 20.50 2-9/16 2.56 22.25 3-1/8 3.12 24.38

4-1/16 4.06 26.38 5-1/8 5.12 29.00

7-1/16 6.38 35.00

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3.0 INSTALLATION AND TESTING PROCEDURES:

3.1 Primary and Secondary Seals: We mentioned in section 1 that one of the purposes of wellhead is to support the tubular strings. Another purpose of wellhead is to seal and isolate the tubular strings from one another. This is done by installing a minimum of two seals on each string of pipe. These are the Primary Seal and the Secondary Seal. The Primary Seal is on the casing or tubing hanger. The secondary seal is in the bottom of either the next spool section, the tubing bonnet or the DSDPO, if one is used. We use three types of secondary seals at Saudi Aramco. First the injectable seal. This is a seal that is activated by injecting plastic packing behind it as we do in X and AK bushings. The second type is the interference fit seal. This type is activated by simply bolting up the flange, the seal energizes automatically. The third type is the metal-to-metal seal. The pack-offs that use this seal have sized metal rings that must be installed by a Service Hand. The metal-to-metal seal is also used as the tubing hanger primary and secondary seal on 10,000 psi (Khuff) tubing hangers. The table below lists all three types and where they are used:

Interference Seals Bottom of casing and tubing spools to

seal on 9-5/8” and smaller pipe. All 3,000 psi and 5,000 psi tubing bonnets.

Injectable Seals Bottom of spools to seal on 13-3/8” and larger pipe. All Double Studded Double Pack-off flanges (DSDPO)

Sized Metal to Metal Bottom of 10,000 psi (Khuff) tubing spools Metal-to Metal Tubing hanger primary and secondary

seals for 10,000 psi (Khuff) equipment

3.2 Casing Heads: The casing head is installed on the conductor casing by slipping the socket in the bottom of the head over the casing and welding inside and outside. The assembly is then pressure tested through a ½” NPT test port between the welds, the O.D. of the casing and the I.D. of the socket. This area is marked in red in Figure 2E-9. A detailed installation procedure, WRS-602, issued by DMD is contained in the Appendix, section D of this manual. Test pressure is determined by taking 80% of the rated collapse of the casing or the working pressure of the top flange, whichever is less. Maximum test pressures are tabulated below.

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Figure 2E-9: Installed Casing Head

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Maximum pressures for testing Casing Heads Casing Size Casing Grade Casing

Weight Rated Collapse Maximum Test

Pressure 13-3/8 J-55 61# 1,540 1,200 13-3/8 J-55 68# 1,950 1,550 13-3/8 L-80 72# 2,670 2,100 13-3/8 NT-95-HS 72# 2,820 2,250 13-3/8 S-95 72# 2,820 2,250 13-3/8 NT-95-HS 86# 6,240 5,000 18-5/8 K-55 87.5# 630 500 18-5/8 K-55 115# 1,140 900

24 GR-B 97# 24 X-42 176# 1,080 850 26 X-42 105# 26 X-42 136#

3.3 Slip Type Casing Hangers

At Saudi Aramco we commonly use the slip type casing hanger. There are two styles of these hangers the Automatic and the Manual. Automatic and Manual refer to the way that the seal on the hanger is activated. The Automatic seal is energized by setting casing weight on the hanger, it usually requires around 50,000 lbs to effect a seal. The Manual hanger will not seal until cap screws in the top of the hanger have been tightened. All of the casing hangers we use may be installed from the drill floor through a BOP stack or the stack may be picked up, secured, and the hanger installed from underneath. There are some considerations when installing a hanger through the BOP stack: ?? The casing must be well centered in the stack. ?? There can be no casing couplings in the stack. The hangers will not go

over them. ?? The hanger should be lowered through the stack with soft line. ?? It is usually not recommended that any hanger larger than 13-5/8” X 7”

be set through the stack. This is because of the weight of the hanger. We currently use four manufacturer’s casing hangers these are Cameron, FMC, Gray and WGI. You may not mix hangers and spools. If you have a Cameron head or spool you must use a Cameron hanger, a Gray spool must use a Gray hanger etc. This is because the profile on the outside of the hanger must match the profile of the head. These profiles are propriety to the manufacturer and are never interchangeable.

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All of our casing hangers basically operate the same way. First lay boards or metal straps across the opening; either the rotary table or the top flange of the casing spool as appropriate. The hanger splits open to allow you to wrap it around the casing. Be careful when doing this so as not to tear the seal element. Set the hanger on the boards or straps so that it is level. Remove the shipping retaining pins or screws that hold the slip segments in place. Coat the casing and the outside of the hanger with light oil. Ensure that the side outlet valve on the casing head or spool is open and that all fluids have drained to the level of the outlet. Remove the boards and lower, do not drop, the hanger into the bowl. Only after the hanger is in the proper position, top of the hanger 1 to 2 inches below the top flange, can casing weight be set on the slips. Pick up the BOP stack and make the rough cut six to eight inches above where the final cutoff will be. Nipple down the BOP. Installing the next wellhead section is discussed in Chapter 2E, section 3.4 Casing and Tubing Spools below. Figure 2E-10 shows a Casing Head with the hanger installed.

3.4 Casing and Tubing Spools

The tubing spool is identical to the casing spool except at Saudi Aramco we have lock screws installed in the top flange of the tubing spool. These lock screws serve two main purposes. First they help energize the primary seal especially when there is a very light tubing string. Second they act as a retention device for the tubing hanger. The retention device would be necessary if, for example, the tubing string parted. Since the tubing hanger is locked in place you could still set a back-pressure valve and retain control of the well.

Figure 2E-10: Casing Head with Hanger Installed

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Before installing the spool, lay it on its side and wash the inside of the spool thoroughly, removing all grease and dirt. Visually check the secondary seals in the bottom of the spool for damage or cuts, replace the seal if any are found. Next, measure from the face of the bottom flange to the shoulder just above the secondary seal. This is the final cut-off height for the casing stub. Saudi Aramco’s standard cut-off is 4-1/2 inches, but this should always be verified before making the final cut. After the final cut is made bevel both the inside and outside of the casing stub. Beveling helps the spool slide on more easily and ensures that there are no burrs or lips on the I.D. that would cause a tool to hang up. Rig pick-up lines to the top flange of the spool so that it hangs level, suspend it over the casing stub. Clean ring grooves and install a new ring gasket. Coat the casing stub and the secondary seal with light oil. Install two studs under each valve orient the spool as required and lower the spool slowly over the casing stub. Fill the bowl above the casing hanger with hydraulic oil. Take care that the stub does not hang-up and cut the secondary seal. Install the rest of the studs and nuts and tighten the flange using normal oilfield practice.

Figure 2E-11: Casing Spool Nippled up on Casing Head

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After the flange is tightened, activate the secondary seals (see section 3.1 above). Now hook up the test pump to the test port and apply test pressure using hydraulic oil. Test pressure is generally 80% of the rated collapse pressure of the casing or the working pressure of the flange, whichever is less. Hold the test pressure for 15 minutes then bleed all pressure to zero. Install the blind plug in the test port. Figure 2E-11 is a depiction of a casing spool installed on a casing head the area in red indicates the void being pressure tested.

3.5 Tubing Hangers

All of the tubing hangers used by Saudi Aramco (Figure 2E-12) are mandrel type hangers with extended necks. They are shipped to the field with a pup joint installed to ease make-up onto the tubing string. After the tubing string has been spaced-out pick up the tubing hanger in install on the top joint of the string. Take care not to damage the O.D. of either the hanger or the extended neck as deep scratches or gouges in this area can prevent the hanger from sealing. Check that all of the lock screws in the top flange of the tubing spool are fully retracted and do not extend into the head. Install a landing joint in the top of the hanger then slack-off on the tubing string and land the hanger in the bowl. Tighten the lock screws, remove the handling joint and install the Back Pressure Valve. Now you may nipple down the BOP stack and you are ready to install the tubing bonnet and tree.

Figure 2E-12: Tubing Spool with Tubing Hanger Installed

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3.6 Tubing Bonnet Before installing the tubing bonnet turn it on its side and wash thoroughly, removing all grease and dirt. Visually inspect the bore of the bonnet and the seals for damage. Rig slings to the bonnet so that it picks up level, suspend it over the extended neck of the tubing hanger. Clean all ring grooves and install new ring gasket. Coat the extended neck of the hanger and the seals in the bonnet with light oil. Fill the bowl on top of the hanger with hydraulic oil. Install four studs 90o from each other to help line up the bonnet. Turn the bonnet to the required orientation and lower over extended neck. Install all studs and nuts and tighten using good oil field practice. Test the connection using hydraulic oil for 3,000 psi and 5,000 psi equipment and nitrogen for 10,000 psi completions. NOTE: Gray has a portable nitrogen test unit that should be used for these tests. Hold test pressure for 15 minutes then bleed all pressure to zero. Figure 2E-13 shows the test area of a bonnet and tubing hanger.

Figure 2E-13: Tubing Spool with Bonnet Installed

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3.7 Trees Rig slings to the tree (Figure 2E-14) so that it will pick up level. Clean the ring grooves and install a new ring gasket. Orient the tree as required and land. Tighten studs using good oil field practice before removing the slings. Rig down the slings. Retrieve the Back Pressure Valve and install a two way check valve, or test plug. Rig up pump to the wing valve and with all valves open test to the working pressure of the tree. Bleed pressure to zero, close master valve and pressure up to working pressure. With master valve closed test each valve in turn. After tree has been tested pull the two way check valve, or test plug and install back pressure valve, if required by the Drilling Program. Close all valves to secure well.

Figure 2E-14: Tree, Bonnet and BPV Installed

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4.0 BACK-PRESSURE VALVES AND TUBING TEST PLUGS:

Saudi Aramco uses three types of Back-Pressure valves on new wells. These are the type ‘H’ the type ‘K’ and the type ‘J’.

4.1 Back Pressure Valves for Oil Well Service:

Size Profile

2-3/8” Type ‘H’ 2-7/8” Type ‘H’ 3-1/2” Type ‘H’ 4-1/2” Type ‘H’

7” Type ‘J’

Note : Please be reminded that the old style hangers had the Gray Type ‘K’ profile or the type ‘H’ profile depending on which company manufactured the hanger. The well file must be checked to determine which BPV should be installed during workover operations. All drilling rig Foremen should check 2-3/8” through 4-1/2” hangers prior to installation, only those with Type ‘H’ profiles should be used.

4.2 Back Pressure Valves for Khuff Gas Service:

All new hangers for Khuff service have the following profiles:

Size Profile

3-1/2” Gray Type ‘K’ 4-1/2” Type ‘H’ 5-1/2” Type ‘H’

7” Gray Type ‘K’

Note : Please be reminded that the older hangers had the Gray Type ‘K’ profile. The well file must be checked to determine which BPV should be installed during workover operations. All rig Foremen should check 3-1/2” and 4-1/2” hangers prior to installation, only those with Type ‘H’ profiles should be installed.

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4.3 Type ‘H’ Back-Pressure and Two Way Check Valves The threaded style Back-Pressure Valve (BPV) and Two-Way Check Valves (TWCV) combine internal running threads, external setting threads and an internal stinger. The type ‘H’ BPV is designed to hold pressure from the wellbore, or below, only. Cameron rates these BPV’s at 20,000 psi. They have an internal, female, right hand running thread that mates with the running, or retrieving tool, and an external, male, left-hand ACME setting thread that mates with the tubing hanger. Please refer to Figure 2E-15, below. The internal plunger consists of a valve and spring assembly that will seal and hold pressure from below. When offset this plunger, see Figure 2E-16, allows pressure to by-pass and equalize above and below the BPV. This plunger also allows fluid to be pumped through the BPV in the event that it is necessary to pump kill fluid into the well with the plug installed. The external seal is a lip type seal on the O.D. of the BPV. This seal is energized when the plug is rotated into the mating profile in the tubing hanger. The type ‘H’ BPV should not be over-tightened. Over-tightening this type of plug will not help it seal, but can make it hard to remove.

Figure 2E-15: BPV, Plunger Closed Figure 2E-16: BPV, Plunger Open

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The type ‘H’ TWCV is designed to plug the tubing in order to test the tree or the BOPE. It will also seal pressure from below. Refer to Figures 2E-17 and 2E-18 below. The plug uses a two-way plunger that will hold tubing pressure from below or moves down and seals test pressure from above. The tubing pressure can be bled down by inserting the retrieving/running tool, which will offset the plunger and allow pressure to by-pass. This plug is not to be used for nipple-up or nipple-down operations! When performing these operations the BPV shall be installed. When nipple down, nipple up, operations are complete the BPV shall be removed and the TWCV installed and the equipment can be tested.

Figure 2E-17: TWCV; Pressure from Below Figure 2E-18: TWCV; Pressure from above

There are two tools available to install and remove these plugs. Figure 2E-19 shows a running/retrieving tool and Figure 2E-20 shows a running tool. The running/retrieving tool can be used to install and remove the plugs. The running tool can only be used to install the plugs and should never be used to remove any plug.

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Figure 2E-19: Retrieving/Running Tool Figure 2E-20: Running Tool

4.4 Running Procedures for Type ‘H’ Plugs

Before Starting: ?? Thoroughly clean the plug with solvent. ?? Inspect the lip seal, replace if damaged or cut. ?? Inspect the running threads and setting threads for damage. ?? Inspect the plunger and spring to ensure that they are not damaged. ?? If possible set the plug in the hanger (before the hanger is installed).

4.4.1 Method 1: Installation using the Retrieving/Running Tool (Figure

2E-19)

A) Measure from the lock-screws on the top flange of the tubing spool to the top of the tree connection (if installing through a tree), or to the drill floor (if installing through BOPE). To this dimension add 18 to 36 inches. This is the length of polished rod required.

B) Assemble the polish rod and attach the Retrieving/Running tool to the bottom piece.

C) Thread the plug onto the Retrieving/Running tool (8 to 8-1/2 rounds) and tighten with two 18” pipe wrenches. The connection should be tight enough that when threading the plug into the hanger it will not break out before it is seated.

D) Coat the plug threads and lip seal with an even application of never-seize.

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E) Lower the assembly through the tree, or BOP, and stab plug into the hanger.

F) Turn to the right one turn to align the threads. G) Turn to the left 4 to 6 rounds until the rod becomes hard to turn.

This is the break-over point and indicates that the plug has seated.

H) With an 18” pipe wrench, continue to rotate the rod to the left until they become easy to turn. This indicates that the Running/Retrieving tool is now backing out of the plug

I) Continue to turn 8 to 10 rounds to completely disengage the Running/Retrieving tool.

J) Remove the rod assembly from the tree, or BOP.

4.4.2 Method 2: Installation using the Running Tool (Figure 2E-20)

A) Measure from the lock-screws on the top flange of the tubing spool to the top of the tree connection (if installing through a tree), or to the drill floor (if installing through BOPE). To this dimension add 18 to 36 inches. This is the length of polished rod required.

B) Assemble the polish rod and attach the Running tool to the bottom piece.

C) Thread the plug onto the Running tool and make it up until it bottoms out, no torque is required.

D) Coat the plug threads and lip seal with an even application of never-seize.

E) Lower the assembly through the tree, or BOP, and stab plug into the hanger.

F) Turn to the right one turn to align the threads. Watch for the rod to drop about ½ inch; this indicates that the torque pin has engaged the slot on the top of the plug.

G) Turn to the left 4 to 6 rounds until the rod becomes hard to turn. This is the break-over point and indicates that the plug has seated.

H) With an 18” pipe wrench, continue to rotate the rods to the left until a maximum of 50 ft lbs. has been applied. Under no circumstances should the plug be over-tightened.

I) Pick up the rod about ½ inch and continue to turn to the left to thread the running tool out of the plug.

J) Continue to turn 8 to 10 rounds to completely disengage the Running tool.

K) Remove the rod assembly from the tree, or BOP.

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5.0 RE-STUBBING CASING:

Many of the older Arab-D producers and Power Water Injection (PWI) wells require ‘re-stubbing’ because of internal/external corrosion of the exposed and uncemented casing near surface. This re-stubbing operation includes:

?? Digging out around the wellhead until good 13-3/8” is located. ?? Cutting off the 13-3/8” and 9-5/8” casing (if required) ?? Welding new 13-3/8” and 9-5/8” casing sections back to surface. ?? Installing a new/reconditioned landing base on the 13-3/8” casing. ?? Landing the 9-5/8” casing with slips in the landing base. ?? Installing new/reconditioned spool(s) and tree.

5.1 Typical Re-Stubbing Procedure for Arab-D Producers

Required Isolation Barriers: (2) Mechanical (1) Non-Mechanical

Tubing removal procedure can vary with specific well completion.

A) Move in and rig up workover rig. Check/report all wellhead pressures. Bleed off annuli pressures. Dig out around the wellhead and check landing base for corrosion and proper support. Mark/report wellhead and valve operators orientation. Flare gas off tubing and TCA, if any. PT TCA to 1000 psi. Kill well by bullheading kill weight NaCl brine down the tubing.

B) RU SAWL. NU/PT lubricator to 2000 psi. Set 3½" PX plug in X nipple

(ID 2.75") and PT to 1000 psi. Open 3½" SSD or punch 3½" tubing. RD SAWL. Circulate tubing and TCA with kill weight brine. Set BPV in tubing hanger. Observe and assure that the well is dead and hole is full. ND tree, NU BOPE and PT to 200/2000 psi. Retrieve BPV.

C) Unsting from packer and circulate hole with kill weight brine. If seals are

stuck, cut tubing above packer. POH and LD tubing. Inspect and report condition of tubing, seal assembly and all nipples.

D) RIH with 9-5/8", 36# casing scraper to +1500’ and POH. RIH with 9-5/8”

RBP. Set RBP at +1400’ and PT to 1000 psi. ND BOPE and Tubing Spool.

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Re-stubbing procedure is listed below.

A) Cut off 13? " casing right below landing base.

B) Dig around 13? " casing until good casing is found. Cut off the landing base and corroded section of 13? " casing. Clean 9? " casing from cement and inspect for corrosion.

C) Re-stub cut-off casing(s) and fill the annulus with Class G neat cement

slurry.

D) Weld new 13? " × 13? " × 2" × 2", 3M Landing Base on 13? " casing. Stab 9-5/8” Casing Spear and engage casing. Land 9? " casing with mechanical slips inside landing base.

Re-completion procedure can vary with specific well requirements.

A) Dress 9-5/8” casing stub. NU new/reconditioned 13? " x 13? " Casing Spool with new bushing. PO and PT 9-5/8” bushing to 1000 psi.

B) NU new/reconditioned 13? " × 11" × 2" × 2", 3M Tubing Spool. NU

BOPE . C) PT 9? " × 13?" annulus to 500 psi with inhibited water with 1% B-1400.

If injection is established, fill the annulus with Class G + 2% CaCl2. RIH with cup tester. PT BOPE and wellhead to 200 and 2000 psi with water. Flush annulus valves with fresh water after cementing.

D) RIH and retrieve the 9-5/8” RBP.

E) Rerun/replace downhole completion equipment as required.

F) ND BOPE.

G) NU new/reconditioned 11” x 4-½” Tubing Bonnet and 4-½” Tree.

H) Report the serial number all new/reconditioned wellhead equipment

installed.

I) Report the length of casing stub(s), sizes and types of flanges and spools.

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5.2 Typical Re-Stubbing Procedure for PWI Wells

Required Isolation Barriers: (2) Mechanical (1) Non-Mechanical

Note: 2nd Mechanical Barrier is required if oil and gas is present on flow back.

Preparation procedure can vary with specific casing program.

A) Move in and rig up workover rig. Check/report all wellhead pressures.

Bleed off annuli pressures. Dig out around the wellhead and check landing base for corrosion and proper support. Mark/report wellhead and valve operators orientation. Flow well to pit and check for oil and gas. Close 10” Ball Valve and ensure valve is holding well pressure. Re-open Ball Valve

B) Kill well by bullheading kill weight CaCl2 brine down the 9-5/8” casing.

Observe well is dead. Close 10” Ball Valve and ND Injection Tree. NU BOPE on top of Ball Valve , pumping brine down the wellbore while nippling up. PT to 300/3000 psi.

C) RIH with 7", 23# casing scraper to + 6500’ and POH. RIH with 7” EZSV

BP. Set EZSV at + 6400’ and PT to 3000 psi. If PT fails, establish injection rate and locate leaks with RTTS.

D) RIH with 9-5/8", 36# casing scraper to +1500’ and POH. RIH with 9-5/8”

RBP. Set RBP at +1400’ and PT to 1000 psi. ND BOPE and 10” Ball Valve.

Re-stubbing procedure is listed below.

A) Cut off 13? " casing right below landing base. B) Dig around 13? " casing until good casing is found. Cut off the landing

base and corroded part of 13? " casing. Clean 9? " casing from cement and inspect for corrosion.

C) Re-stub cut-off casing(s) and fill the annulus with Class G ‘Neat’ cement

slurry. D) Weld new 13? " × 13? " × 2" × 2", 3M Landing Base on 13? " casing.

Stab 9-5/8” Casing Spear and engage casing. Land 9? " casing with mechanical slips inside landing base.

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Re-completion procedure can vary with specific well requirements.

A) Dress 9-5/8” casing stub. NU new/reconditioned 13? " x 13? " Casing Spool with new bushing. PO and PT 9-5/8” bushing to 1000 psi.

B) NU BOPE. C) PT 9? " × 13?" annulus to 500 psi with inhibited water with 1% B-1400.

If injection is established, fill the annulus with Class G + 2% CaCl2. RIH with cup tester. PT BOPE and wellhead to 300 and 3000 psi with water. Flush annulus valves with fresh water after cementing.

D) RIH and retrieve the 9-5/8” RBP. E) RIH with mill. Mill out 7” EZSV BP at + 6400’. POH and LD DP.

F) Close Ball Valve. ND BOPE. G) NU new/reconditioned Injection Tree.

H) Bullhead casing with + 60 bbls fresh water. Flow back for clean up. Run

sinker bar and report fill. I) Report the serial number all new/reconditioned wellhead equipment

installed. J) Report the length of casing stub(s), sizes and types of flanges and

spools.

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LOST CIRCULATION 1.0 INTRODUCTION 2.0 CONVENTIONAL LOSS CIRCULATION MATERIAL

2.1 Characteristics 2.2 Procedures

3.0 ACID SOLUBLE GROUND MARBLE

3.1 Characteristics 3.1.1 Selection of CaCO3 Particle Size Basis 3.1.2 Typical CaCO3 Pill Formulation 3.1.3 Average Properties of CaCO3 Carrier Fluid

3.2 Recommended Procedures 4.0 GUNK PLUG

4.1 Characteristics 4.2 Procedures

5.0 POLYMER PLUG

5.1 Types of Polymer Plugs 5.2 Flo-Chek 5.3 Temblok-100 5.4 High Temperature Blocking Gel 5.5 Protectozone

6.0 BARITE PLUG 6.1 Characteristics 6.2 Slurry Volume Calculations 6.3 Pilot Testing 6.4 Pumping, Displacement Rates and Equipment 6.5 Procedures

7.0 THIXOTROPIC CEMENT

7.1 Characteristics 7.2 Procedures

8.0 CEMENT PLUG

8.1 Characteristics and Precautions 8.2 Procedures

9.0 FOAM CEMENT

9.1 Characteristics 9.2 Procedures

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LOST CIRCULATION

1.0 INTRODUCTION

1.1 Loss of circulation occurs when the formation drilled is extremely permeable and a pressure differential is applied toward the formation. The mud loss rate dramatically increases by the excessive overbalance pressures created by the hydrostatic head of the column of mud in the hole. In some cases, decreasing the differential pressure by reducing the fluid density and pumping rate or pressure will stop fluid losses and regain circulation. However, the most effective method for combating lost circulation is to reduce the permeability of the borehole wall by introducing properly sized bridging material, commonly known as loss circulation material (LCM) into the rock pores with a high viscosity pills. Bridging particles contained in the mud will not seal the zone if they are smaller than the formation pores.

Potential loss of circulation zones usually encountered in Saudi Aramco’s fields include

Pre-Neogene Unconformity (PNU) Umm Er Redhuma (UER) Major losses Wasia Formation Shuaiba Major losses Arab-D Reservoir Major losses Hanifa Reservoir Lower Fadhili Resrevoir Haurania Zone Major losses Below the base of the Jilh dolomite

1.2 Loss circulation material (LCM) is normally added to the circulating drilling

mud, or in a high viscosity pill to be spotted across the lost circulation zone.

The LCM includes, but is not limited to

A) Conventional bridging agents;

Fibrous Material ........................................... Cedar Fiber Flake Material .............................................. Mica coarse and fine Cellophane Granular Material ......................................... Walnut shells Cotton seed hulls

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B) Acid soluble sized Calcium Carbonate (CaCO3);

Ground marble fine ...................................... (10 microns) Ground marble medium ............................... (150 microns) Ground marble coarse ................................. (600 microns) Marble chips ................................................ (2000 microns) Note: Acid soluble CaCO3 is also a granular material

C) Reinforcing plugs, cement and others;

Gunk Plug Barite Plug Polymer Plug Cement Plug Foam Cement Thixotropic Cement

D) The size of the bridging agents are very important, providing consideration is given to the type of loss zone and the severity. The following list provides a general guide for LCM applications:

Approximate Size of

Opening Sealed (Inches) Severity of Loss Materials and Size

ranges 0.125 – 0.250 Seepage to Complete ?? Medium to Coarse Granular

?? Fibrous Material. ?? Fine to Coarse Flakes

Severe Complete Losses

?? Marble Chips ?? Barite Plug

0.250 – 12.00 Complete (cavernous) ?? Cement Plug 12.00 up Complete (cavernous) ?? Gunk or Polymer Plug

?? Drill “Blind”

1.3 Drilling may continue without full returns through PNU and UER, using water and gel sweep to ensure hole cleaning. If circulation is lost while drilling through the Wasia Aquifer with mud, circulation must be regained (do not switch over to water and drill ahead) by using one or a combination of the following techniques:

A) Conventional LCM pill. B) Cement Plug. With open-ended drill pipe +50’ above the LC zone, spot

118 pcf Class-G neat cement; plug length not to exceed 500’. C) Gunk Plug. D) Thixotropic Cement. E) Foam Cement. Only to be used when all above techniques have failed

to regain circulation.

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1.4 If loss of circulation is anticipated while drilling a potential hydrocarbon-bearing zone, run large jet nozzles and BHA without mud motor.

1.4.1 If case loss of circulation is encountered, attempt to regain with at

least two consecutive LCM pills:

A) Sized CaCO3 LCM pills. Do not use any other damaging non-acid soluble materials in this pill.

B) Polymer plugs such as Flo-Chek, Zone-lock, FlexPlug and others. Detailed mixing and pumping procedures for this type of plug should be provided by the Service Company in order to tailor the pill to the specific well conditions.

C) Cement or gunk plugs should not be considered unless severe loss of circulation is encountered just below the shoe and could not be regained utilizing Sized CaCO3. In this case, cement plugs or gunk plugs will have to be utilized to regain circulation to enable drilling to continue.

1.4.2 If unable to regain circulation, continue drilling with mud cap to the next casing point.

A) The only exception to this policy applies when experiencing

complete loss of circulation in the Arab-D reservoir while drilling Khuff/Pre-Khuff well. In these wells, circulation must be regained before proceeding to the casing point (base of Jilh Dolomite).

2.0 CONVENTIONAL LOSS CIRCULATION MATERIAL

2.1 Characteristics

2.1.1 Materials used generally include Mica Course, Mica Fine, Cotton

Seed Hulls, Basco Cedar and Walnut Shells.

2.1.2 Prepare LCM pill by isolating the desired volume from the active mud system and mixing 30 to 150 lbs./bbl of LCM. Any combination of the above LCM can be included in this mixture.

2.2 Procedures

A) Establish the approximate point of the loss, type of formation, mud level

in the hole and rate of loss.

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B) Run in hole with open-ended drill pipe 25 to 50’ above the lost circulation zone.

C) Pump LCM pill down drill pipe until it clears the bottom. D) Pick up drill pipe 2 to 4 stands and wait for LCM to settle. E) Establish circulation to determine extent of healing and if a second LCM

pill is needed.

3.0 ACID SOLUBLE GROUND MARBLE

3.1 Characteristics

3.1.1 Various sizes of ground marble are used to stop lost circulation during the drilling operations. Selection of the proper particle size distribution is dependent on the nature of the formation and the severity of the lost circulation. To seal off a rock with large diameter pores, particles larger than the pore size will be more effective than smaller ones. Any particle smaller than one third the pore size will pass through the pore pattern and will not effective in stopping the losses. Note: The sealing characteristic of the lost circulation pill is governed not by the concentration of particles but by the shape and size distribution of the particles carried in the pill. Properly sized bridging material must be selected to block the formation pores effectively at the wellbore face. The particles should have a broad size range, and 20 - 50 percent of the particles should be at least one-third the average formation pore size to establish the desired bridging mechanism. The reservoir engineer or geologist should be consulted for the proper particle size selection required for a non-penetrating fluid. The lost circulation pills must be spotted at the pay-zone by pumping the pill down hole at a rate that will jam the particles quickly at the entrance of the formation flow channels. Slow pumping may allow the bridging particles to seep into the Arab-D vugular and/or fractured rocks.

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3.1.2 A typical example of a sized CaCO3 pill formulation for Arab-D

payzone is as follows: Order of addition for one barrel

?? Fresh water ?? Defoamer 0.01 - 0.02 gal ?? Suspending polymer (XC-Polymer) 0.50 - 1.00 lb ?? Primary viscosifier (HEC) 1.00 - 2.00 lb ?? Filtrate control polymer (starch) 2.00 - 4.00 lb ?? Lime or MgO 0.50 - 1.00 lb ?? Ground marble medium (150 microns) 30 - 80 lb ?? Ground marble coarse (600 microns) 100 - 120 lb

Note:

1. Add polymers slowly through the hopper to avoid the formation of lumps or fish eyes and achieve high viscosity and gel strength.

2. The concentration and the size distribution of the ground marble can be tailored or varied according to the severity of losses. Medium and Coarse can be pumped through the bit nozzles.

3. When attempting to stop severe lost circulation with large size (2000 micron) Marble Chips, use open-ended drill pipe. Due to the large size of the Marble Chips, the bit nozzles will be plugged.

3.1.3 Average properties of the carrier fluid prior to adding the CaCO3

should be in the following ranges:

? ? Funnel Viscosity 150 - 200 sec/qt ? ? PV 30 - 40 cp ? ? YP 40 - 50 lb/100 ft2 ? ? Gels 12 - 18 lb/100 ft2 ? ? pH 10 - 11

3.2 Recommended Procedures

A) Establish the approximate depth of the thief zone, type of formation (porosity and permeability - is it “Super k”?), height mud stands in the hole and rate of losses.

B) Run in hole with large size jet nozzles or open ended drill pipe to the top

or near the top of the lost circulation zone.

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C) Pump the Marble chip or sized CaCO3 pill through the drill pipe at

normal rate and speed the pump as the pill clears the drill pipe.

D) Pick up drill pipe 3 stands and wait on bridging particles or chips to settle and a cake to build up.

E) Circulate to determine if the lost circulation zone has been sealed. If full circulation can be established, run in hole slowly to bottom and resume normal drilling operation. If partial losses still exist, continue drilling for a while to generate some drilled cuttings which in many cases have helped as a sealing mechanism.

F) Repeat the above procedure and modify the bridging particles size

distribution if required. Perhaps larger particles are needed or the carrier fluid viscosity should be increased.

4.0 GUNK PLUG

4.1 Characteristics

4.1.1 Gunk Plug is bentonite-in-diesel slurry. When dry bentonite is mixed into diesel oil, the bentonite will not yield and the slurry remains a relatively thin fluid. This allows the slurry to be pumped to the bit with relatively low pressure. When the slurry leaves the bit and becomes exposed to water in the annulus, the bentonite will rapidly hydrate, causing the slurry to become extremely viscous or gunk like. This extremely viscous gunk will have high resistance to flow through the rock pores or channels and in many situations it will provide a complete seal.

4.1.2 Gunk Plugs will lose strength with time under downhole conditions

and should be followed by a cement plug to provide a permanent seal.

4.1.3 The slurry is jet mixed with a cement unit to 82 lbs./cu.ft. This normally requires 300 pounds of bentonite per barrel of diesel. Additions of Mica at (about 15 lbs/bbl) will increase the strength of the plug, but is optional. The slurry volume to be pumped normally ranges from 20 to 150 barrels, and is based on the rate of loss circulation and amount of open hole.

4.1.4 Gunk Plugs may become commingled with water inside the drill string.

If this occurs, pump pressure will become excessive, resulting in a plugged drill string. For this reason, sufficient diesel spacers are required ahead and behind the slurry.

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4.2 Procedures

A) Run with closed end drill pipe and mixing sub to 20 feet above loss

circulation zone. Rig up both the cementing unit and the rig pumps so that either can be used to displace the slurry. A third pump should be connected to the annulus.

B) Pump 10 to 20 barrels of diesel into the drill pipe for the spearhead spacer. This step is critical to separate the slurry from the water-based mud.

C) Jet-mix the slurry to 82 pcf. The slurry can be batch mixed or pumped on the run.

D) Tail in with a 10 to 20 barrels diesel spacer.

E) Displace the slurry at a rate of 3 to 5 barrels per minute with mud.

F) Begin pumping water-based mud down the annulus at a rate of 1.0 bbl per minute as soon as the slurry reaches end of the drill pipe.

5.0 POLYMER PLUG

Polymer plugs are commonly used for temporarily or permanently healing of loss circulation. The following are polymers that are available through the in-Kingdom Service Companies. It is important to emphasize the need to (a) tailor the plug design for the well conditions, (b) laboratory test the plug to fine-tune the polymer additive concentrations, and (c) ensure satisfactory polymer plug performance.

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5.1 Types of Polymer Plugs

Service Company Product Name Remarks Limitation B.J. Services High Temperature

Blocking Agent It is pumped as a low viscosity liquid which turns to a rigid polymer plug when subjected to heat, after a controlled time delay. Can be broken down with 15% HCl or water containing oxidizers. Can be jetted out using coiled tubing or drill pipe.

-Highly sensitive to diesel and low pH contamination

Dowell-Schlumberger Permablok It is a solids-free solution with a very low initial viscosity that can easily penetrate formation matrix. It is then activated by temperature to produce a strong, coherent gel. Note: the Maximum temperature that the hardened gel can withstand is 356oF.

-On-site mixing should only be performed with fresh water.

-Max. temp. for D140 hardener is 225oF.

Zonelock S and Zonelock SC

Zonelock S, a solution of liquid extender D75 and water, forms a rigid semi-permeable gel when in contact with a heavy calcium or sodium brine. Zonelock SC utilizes Zonelock S followed by a spacer and then cement slurry. When the slurry contacts the gel resulting from the D75/calcium chloride solution, the cement will set very rapidly (less than 2 minutes). The Zonelock SC forms a permanent seal that can only be drilled out.

- A spacer of fresh water or Trisodium Phosphate M8 must always be used between the D75 solution and cement

LCM D111 Extends the use of RFC (Regulated Fill-Up Cement) to offshore platforms or areas where solid additives is impractical. It imparts thixotropic properties, characteristic of RFC slurries. D111 slurries do not expand upon setting. D111 can be used with any Portland cement and either fresh or seawater.

-Can only be used with limited number of additives.

-Dispersants & fluid -loss control additives destroy the thixotropic properties

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Service Company Product Name Remarks Limitation InstanSeal An unstable inverted emulsion that flips

spontaneously to hard solid gel when exposed to a pressure drop of 650 psi or above across the bit nozzles.

180oF maximum allowable BHST.

Protectozone A rigid aqueous gel with controlled setting and breakdown times. Note: Oilfield brine should not be used; only use fresh water or prepared NaCl brine..

325oF Max. allowable BHST.

Halliburton Flo-Chek A two-fluid system; lead slurry consists of Flo-Chek Chemical A (Injectrol A) to which may be added sand and TUF Additive No. 2. The Flo-Chek Chemical A is followed by a fresh water spacer and a predetermined amount of cement slurry. The latter is used to obtain the final and permanent squeeze.

Injectrol is highly alkaline. 200oF max allowable BHST.

Flex-Plug-W Non-particulate material that reacts with the drilling mud, resulting in a non-brittle bridge at the opening of the loss zone. Note: Must not contact aqueous fluids in the mixing equipment.

Cannot use as additive in a cement slurry.

Temblok-100 Long-life viscous gel which is affected by temperature and pH. 225oF max BHST; above 225oF use Temblok-90.

Easily removed with acid. Cannot be used in CaCl2 brine.

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5.2 Flo-Chek: Typical Mixing and Pumping Procedures

A) Run In Hole with open ended drill pipe to just above the loss circulation

zone. Pump rate should be maintained between 3 to 5 bpm. B) Pump 1000 gals (24 bbls) of 15% CaCl2 water. Add 62 lbs. of Calcium

Chloride to one barrel of water. Need 1488 lbs of CaCl2 to make 1000 gallons of 15% CaCl2 water.

C) Pump 5 bbls of fresh water.

D) Pump 500 gals (12 bbls) of Flo-Chek polymer.

E) Pump 5 bbls of fresh water. F) Pump 50 sacks (10.2 bbls) of cement, mixed at 118 pcf, 5 gals/sack,

and 1.15 cu. ft./sack. G) Pump 5 bbls of fresh water. H) Pump 500 gals (12 bbls) of Flo-Chek polymer. I) Pump 5 bbls of fresh water. J) Pump 150 sacks (30.7 bbls) of cement mixed at 188 pcf, 5 gals/sack,

and 1.15 cu. ft./sack. K) Displace cement with drill water to the end of drill pipe. L) Pull out of hole with drill pipe.

Note: The Flo-Chek and cement must be suitably separated from each

another by fresh water. It is advisable to pump CaCl2 with rig pumps while the fresh water spacer, Flo-Chek and cement is mixed and pumped by Halliburton. The Halliburton pumps must be isolated to prevent intermixing of cement and Flo-Chek.

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5.3 Temblok–100: Typical Mixing and Pumping Procedures

A) Run In Hole with open-ended drill pipe to circulate and condition the

hole.

B) Ensure all equipment that will be used during the job is completely free of acid or other contaminants that may affect the pH of the fluid. The tanks, blenders and pumping equipment must be neutralized by circulating a K-35 solution, which is made up of 100 pounds of K-35 per 1000 gallons of fresh water.

C) Prepare all fluids into neutralized equipment as follows:

1. K-35 spacer (per1000 gallons), made up of

1000 gals of Fresh Water 100 lbs of K-35

2. Temblok-100 (per 1000 gallons) made up of

1000 gallons of Fresh Water 6 lbs TB-41 40 lbs K-35 425 lbs WG-11 35 lbs WG-17

D) The Temblok-100 system should be prepared as follows:

1. Mix the saturated salt water as outlined above. 2. Add the proper amount of TB-41 to the saturated salt water and

mix for 10 minutes.

3. Load into neutralized mixing tank the proper amount of fresh water.

4. Add the appropriate amount of K-35 based on lab tests, to the mix

water and circulate until dissolved. Check the pH to ensure it is 10.5 to 11. If it is less, add small amounts of K-35 until the correct pH is achieved.

5. Add the proper amount of WG-11 and circulate to mix all the gel,

try to avoid any air entrapment.

6. Add the proper amount of WG-17 SLOWLY. The slurry will become more viscous at this point. Slowly circulate the slurry until ready to pump.

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Note: The slurry should not be mixed for more than 1-1/2 hours prior to

pumping as the fluid may become too viscous to pump.

E) Pump the Temblok-100 system, spot and balance as follows:

1. Pump K-35 spacer (usually 500 linear feet of drill pipe). 2. Pump Temblok plug (Volume to be determined by plug length

desired).

3. Pump K-35 spacer (usually 500 linear feet of drill pipe).

4. Pump the required amount of displacement fluid as fast as practical to minimize the residence time in the pipe.

F) Balance the plug as best as possible to reduce any U-tubing or stringing

of the fluid.

G) Shut down and SLOWLY pull the drill pipe from out of the plug so as not to cause any swabbing.

H) Pull the drill pipe up above the plug and reverse circulate until bottom

up are seen to ensure there is no Temblok remaining in the pipe.

Note: Pull far enough above the plug in order not to disturb the Temblok plug.

I) Shut down to allow the Temblok to hydrate for at least 2 hours. J) Run in hole with drill pipe and make an attempt to tag the plug in order

to confirm its position. This will allow the placement of a second pill should the first pill be unsatisfactory or not in the correct place.

K) Pull out of hole with drill pipe if the plug is found to be satisfactory.

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5.4 High Temperature Blocking Gel

The following is a general recipe for the BJ Services High Temperature Blocking Gel. The recipe should be modified depending on the severity of the Loss Circulation.

Ingredients for 1000 gallons (500 pptg System)

GW-38 Suspending Gel) 20 – 50 pounds5 BF-7 (Delay Buffer) 12 pounds1

Boric Acid (Crosslinker) 5 pounds GW-38 (Main Polymer) 480 – 450 pounds2

Breaker Note 3

Note:

1. The BF-7 will vary according to the temperature and delay time required. Delay times can be set from as low as 20 minutes to as high as 4 hours. At 200oF, the above loading will provide 75 minutes pumping time and 120 minutes setting time.

2. The GW-38 loading will vary as required. The suspension gel may be raised (see note 5) to minimize polymer settling at the higher loading and control leak-off.

3. An external breaker of either 15% HCl or water containing oxidizers can be used. The system can be jetted out using coiled tubing or drill pipe.

4. The system is highly sensitive to diesel and low pH contamination. 5. Use the higher loadings to achieve a more viscous base gel. This

will reduce fluid leak-off to the formation.

5.5 Protectozone

5.5.1 Protectozone WL300 Plug U803 and WL500 Plug U804 are gel systems that work at bottom hole static temperatures between 50 and 200oF. The gels are formed by adding varying amounts of Low-Temperature Plugging Agent J170 to the appropriate volumes of fresh water or prepared sodium chloride brine. A water-soluble catalyst Sodium Dichromate M6 is added for control of setting times. Specific breakdown times are obtained by using either Breaker J134 or PROTECTOZONE M24 additive as an internal chemical breaker. Breaker down times of one day to three weeks can be obtained.

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5.5.2 Ingredients for 500 gallons of gel mix:

Amounts of Materials

Order of Addition WL300 WL500 1. Add fresh water to a clean, acid-

free tank. Prepare NaCl brine, if needed.

488 gal 480 gal

2. Add J170 within 5 min. to reduce lumping.

J170 150 lbm

J170 250 lbm

3. Add chemical breakers and continue agitation.

Add J134 Add J134 orM24

4. Prior to pumping, add M6 catalyst and mix for 2 to 3 minutes

Add M6 Add M6

5.5.3 Protectozone WH500 Plug U805 and WH750 Plug U806 are gel systems that work at bottom hole static temperatures between 200 and 325oF. The gels are formed by adding varying amounts of High-Temperature Plugging Agent J171 to the appropriate volumes of fresh water or prepared sodium chloride brine. PROTECTOZONE M24 additive is used when well temperature is between 200 and 255oF. When well temperatures are between 240 and 325oF, FIXAFRAC J59 Diverting agent is used. Diverting agent FIXAFRAC J66 or J66S rock salt is recommended to prevent excessive loss to the formation. Gel life of up to 20 days is possible at temperatures above 200oF.

5.5.4 General Guidelines on Ingredients and Mixing

A) When using J66 and J66S rock salt, the base fluid for

PROTECTOZONE WH must be prepared 9.5 lbm/gal NaCl brine. The salt will slightly increase the thickening time of the WH500/wh750 system.

B) Do not run J66/J66S in the first 10% of the slurry. This should

allow the slurry to penetrate deeper in the larger fractures and vugs.

C) Do not add diverting agent in the last 10% of the slurry (but not

more than the capacity of 500 feet of tubing). This is a safety measure to avoid solids in that portion of the slurry that may remain in the tubing during hesitation-squeeze operations. This length will very for drill pipe depending on the size in use.

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D) Add J66/J66S to the middle 80% of the slurry, do not exceed 0.5 lbm/gal. In large-volume treatments, the diverting agent can be added in stages during the treatment.

E) M24 breaker is used for temperatures up to 260oFand J59 for

temperatures from 240 to 325oF.

F) Add 25 lbm of Synthetic polymer J166 per 1000 gallons for

temperatures to 215oF and 50 lbm for temperatures greater than 215oF.

G) Add 3.5 lbm of Soda Ash M3 for each 25 lbm of J166 used. H) Use 500 lbm of High-Temperature Plugging Agent J171 per

1000 gallons at temperatures above 250oF and 750 lbm of J171 per 1000 gallons at temperatures between 240 and 325oF.

Note: Do not use oilfield brines because such waters contain excessive

amounts of calcium and magnesium salts, which can unpredictably accelerate the setting time.

6.0 BARITE PLUG

A barite plug is very effective in stopping underground blowouts and severe loss circulation. The important fact is that an underground blowout cannot be controlled by conventional methods because the wellbore will not stand full of kill-weight mud. Usually, the first step to shutting off the underground flow is the spotting of a high density barite pill between the flowing and lost returns zones. The barite pill slurry is usually mixed with cementing equipment and is spotted on bottom where the high density of the plug (18 – 22 ppg or 119 – 164 pcf) holds additional pressure on the formation, eventually stopping underground crossflow. After the crossflow is stopped, barite settles out and forms a pressure competent bridge. Sometimes sloughing of the shale also occurs as a result of the fresh filtrate that is created as a result of the barite settling out. This shale sloughing helps in bridging the hole, thus creating zonal isolation. A barite pill can also be used to control high pressure, low permeability formation so that another string of casing can be set. This type of formation will cause severely gas-cut returns, but will not usually cause appreciable well flow; however, the casing seat usually will not hold the mud weight required to contain the formation.

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6.1 Composition and Density

6.1.1 The Barite plug consists of barite, water, a thinner and pH controller.

The thinner is needed to deflocculate the barite slurry, which results in improved pumpability and allows the barite to settle from the slurry at a predictable rate. Common deflocculating agents include

A) SAPP (Sodium Acid Pyrophosphate) which is stable up to 180o

F temperature. Usually SAPP has high fluid loss (?25cc). It is ineffective with some barites and cannot tolerate excessive salt or calcium in the mix water. Pilot testing of the barite plug in the lab is highly recommended prior to field use.

B) Lignosulfonate is stable up to 350o F temperature. It has a low

fluid loss characteristic of ?5cc. 6.1.2 Caustic Soda is used as a pH controller. It provides the alkaline

environment (pH 10-11) necessary for the lignosulfonate to be effective.

6.1.3 The recipe for one barrel of 157 pcf barite slurry includes:

A) 0.54 bbl water B) 691 lbs barite C) 8 lbs lignosulfonate D) 1 lb caustic soda

6.1.4 The lignosulfonate recipe above will work for all barites and in brines

up to sea-water salinity and hardness, provided the pH is kept up close to 11. For mix waters with hardness above 250 ppm, the hardness should be reduced by raising the pH to 11 and then adding soda ash as necessary. With any high salinity brine, pilot testing is recommended to insure the final slurry meets the requirements.

6.1.5 Since SAPP will deflocculate some, but not all, barite slurries, it may

occasionally be substituted for the lignosulfonate in the recipe. Proper concentrations would be 1/2 ppb SAPP and 1/4 ppb caustic soda.

6.1.6 A 157 pcf slurry density usually provides a good balance between maximizing slurry density and adequate pumpability. In some cases pilot testing may indicate a more appropriate density and the recipe may be modified accordingly.

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6.2 Slurry Volume Calculations

6.2.1 Slurry volumes depend on the amount of open hole and the severity

of the kick. These volumes normally range from 300 sacks (40 bbls) to 3000 sacks (400 bbls).

6.2.2 If the kick pressure is know or can be estimated, then the height of the

barite slurry needed to kill the kick can be calculated as follows

H = KD/B

Where H = Barite pill height (feet) K = Excess kick pressure equivalent above mud weight (in pcf). For example, a “ten pcf kick” is K = 10

D = Depth of kick (feet) B = Excess barite slurry density above mud density (pcf)

The slurry volume should be 125 to 150% of the annular capacity necessary to give the height of the plug desired, but should not be less than 40 barrels (300 sacks). If a second barite plug is required, then the slurry volume should be greater than the first.

6.3 Pilot Testing

Because of variations and possible contamination of ingredients, it is always advisable to pilot test a barite slurry in the field prior to pumping in the well. Prepare a sample of the slurry using the above recipe and ingredients (section 7.1.3) at the wellsite. After stirring well, the sample should have the expected density and be pumpable. If the brine needs to settle in the wellbore, the pilot test should reflect so. Reasonable settling is 2 inches in a mud cup after 15 minutes. The settled cake should be hard and somewhat sticky, not soft and slippery. The settling test is not a guarantee that the barite pill will form an effective plug under downhole conditions, but will certainly give an indication of the settling characteristics.

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6.4 Pumping, Displacement Rates and Equipment

6.4.1 Pumping and Displacement Rates

A barite pill should be pumped and displaced at a rate somewhat higher than the kick rate. If the kick rate is unknown, a reasonable rate (5 – 10 barrels per minute) should be used for the first attempt, although prolific blowouts can ultimately require kill fluid placement greater than 100 barrels per minute.

6.4.2 Equipment

The equipment needed on location to prepare and pump a barite plug is as follows: (a) A cementing unit equipped with a high pressure jet in the mixing

hopper (b) A means of delivering the dry barite to the cementing unit (c) Sufficient clean tankage for the mix water so that the

lignosulfonate and caustic soda can be mixed in advance The barite slurry may be pumped into the drill pipe either through a cementing head or through the standpipe and Kelly. In either case, the pump tie-in to the drill pipe should contain provisions for hooking up both the cementing unit pump and the rig pump so that either can be used to displace the slurry. If this is not done and the cementing unit breaks down, the barite may settle in the drill pipe before the mud pump tie-in can be made or the cementing unit repaired. Blockage of the drill string by barite settling will complicate the well control problem.

6.5 Procedures

6.5.1 If Pipe is Free

If pipe is free at the end of the pumping operation, it may be possible to pull out of the plug. The risk of pulling out of a plug that is set to contain an underground blowout is high, especially if a second barite plug becomes necessary. The risk considerations are as follows: A) The pipe may become stuck at the shallower depth. This limits

the effectiveness of subsequent barite plugs if required. B) A stripping operation may be necessary to pull the pipe or to

return to bottom.

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6.5.2 Leave Pipe in Place (Underground Blowout)

A) Mix and pump the slurry at the appropriate rate. Monitor the

slurry density with a densometer in the discharge line or a pressurized mud balance. Displace the slurry immediately at the same rate.

B) Overdisplace the slurry by 5 barrels to clear the drill string.

Continue to pump 1/4 barrel at 15 minute intervals to keep the drill string clear unless pressure remains on the drill pipe.

C) To verify whether the underground flow has been stopped, a

noise log can be used. Temperature surveys can be used in addition for confirmation or if the noise log is not available, however the noise log is more definitive than temperature logs. If temperature surveys are to be used, wait 6 to 10 hours for the temperature to stabilize. The survey will show a hotter than normal temperature in the shallower zone of lost returns. After 4 hours. a second temperature survey will show a decrease in temperature (cooling) across the zone of lost returns.

D) After confirming that underground crossflow has been stopped,

bullhead a cement slurry through the bit to provide a permanent seal. Observe the annulus during pumping. If the casing pressure begins to change a lot or a sudden change in pumping pressure is observed, the barite plug may have been disturbed. In this case, over-displace the cement to clear the drill string. Additional cementing might be desirable to obtain a squeeze pressure.

E) Plug the inside of the drill string. This can be accomplished by

either under-displacing the cement plug in step (D) above, or preferably setting a wireline bridge plug near the top of the collars. Cement should be dump bailed on top of the wireline bridge plug for additional safety.

F) Pressure test the plug, inside the drill pipe. G) Perforate the drill string near the top of the barite plug and

attempt to circulate.

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? ? It may be difficult to tell whether the well is circulating or

flowing from the charged formation. Pressure communication between the drill pipe and annulus is one clue. Another is that a pressure increase should have appeared on the drill pipe from the annulus pressure or on the casing from hydrostatic pressure in the drill pipe when the perforation was made.

? ? Consideration should be given to circulating with lighter mud

because of the known zone of lost returns.

1. Well will circulate

i) Use drill pipe pressure method to circulate annulus clear of formation fluid.

ii) Run a free-point log.

iii) Begin fishing operations.

2. Well will not circulate

i) Squeeze cement slurry through perforation(s). Cut displacement short on final stage to provide an interior plug or set wireline bridge plug. WOC and pressure test plug.

ii) Run free-point log.

iii) Perforate the pipe near the indicated free point.

iv) Circulate using drill pipe pressure method until annulus is clear. If well will not circulate, squeeze perforation(s) with cement or set a wireline bridge plug above perforation(s), and reperforate up the hole.

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6.5.3 Pull Out of Plug (High Pressure, Low Permeability Formation)

A) Mix and pump the slurry. Monitor the slurry weight with a

densometer in the discharge line or a pressurized mud balance. If mixing is interrupted for any reason, immediately begin displacement of the slurry using either the cement unit pumps or the rig pumps. Work the pipe while pumping and displacing.

B) Displace the slurry with mud at the same rate. Cut the

displacement short by 2 or 3 barrels to prevent backflow from the annulus. If a drill pipe float is in the drill string, overdisplace the slurry.

C) Immediately begin pulling the pipe. It may be necessary to strip

the pipe through the annular preventer. Pull at least one stand above the calculated top of the barite slurry.

E) 1. If no pressure is recorded on the annulus, continue working

the pipe while observing the annulus mud level.

i) Annulus full: Begin circulating at a low rate keeping constant watch on the pit levels.

ii) Annulus not full: Fill annulus with water and observe. If annulus stands full, begin circulating at a slow rate. Consider cutting the mud weight if feasible.

2. If pressure is recorded on the annulus, circulate the annulus clear using normal well control techniques. Continue working the pipe.

i) If returns become gas free, the barite pill was successful

and the well is dead. ii) If returns do not become essentially gas free after

circulating two or three annular volumes, the barite pill was not effective. A second plug will be necessary.

E) After determining that the well is dead, go back in the hole to

near the top of the barite slurry. Set a balanced cement plug and pull out a few stands. This step is sometimes eliminated.

F) After waiting for the cement to set up, run back in hole and tag

the top of the cement plug.

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7.0 THIXOTROPIC CEMENT

7.1 Characteristics Thixotropic slurries have the shear-thinning characteristic. This means that the slurry under shear will stay in fluid phase but develops a gel structure when the shearing force stops.

7.2 Procedures

Typical Thixotropic cement job. A) Run in hole open-ended to 25 feet above loss circulation zone. B) Pump desired volume of a selected polymer plug. C) Follow with Thixset cement slurry.

i) Slurry mix: Class-G Cement + 1.0% Comp A + 0.25% Comp B + fresh water + defoamer.

ii) The above mix is a Halliburton recipe. Equivalent chemicals and mixes can be used from the other In-Kingdom pumping service companies.

D) Continue pumping cement until the agreed upon volume has been

pumped or until squeeze pressure is noted. A pressure increase of 250 psi is sufficient for squeeze applications of this nature.

E) Displace the cement with fresh water. Shut down, pull at least four

stands and clear drill pipe. F) Once the drill pipe and annulus are clean, pull out of hole. G) Wait on cement 6 to 8 hours to give the cement time to set. H) Run in hole with drill pipe and tag top of cement. Attempt to fill annulus.

If returns are noticed, resume drilling, otherwise, consider repeating process or attempting different process.

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8.0 CEMENT PLUG

When mud circulation is lost while drilling, it is sometimes possible to restore returns by spotting a cement plug across the thief zone, and then drill back through the plug. The balanced cement plug is usually preferred and it is the most common method.

8.1 Characteristics

When placing a cement plug across a thief zone to combat lost circulation, it is important to take every precaution to ensure that the cement sets properly. The following are general preventive measures: A) Use neat cement with 0.25 lbs/sack of Cellophane Flakes (optional).

Thickening time should be checked against the estimated cement placement time.

B) In shallow thief zones, avoid circulating cement extensively. Extensive

circulation will retard the development of cement strength. It is desirable to achieve early strength and allow the cement to set without agitation.

C) Use sufficient spacer that is compatible with the mud ahead of the

cement (water spacer is usually used). D) When calculating cement volume, include 50 to 100 feet of cement

height above the thief zone depending on the severity of the losses. E) Place the plug with care and move the pipe slowly out of the cement to

minimize swabbing action and mud contamination. F) Allow ample time for the cement to set prior to drilling out. Note: Cement placement failures commonly occur due to fluid backflow,

slugging or improper displacement volumetric calculations.

8.2 Procedures A) Determine the severity of circulation loss to decide on the cement plug

length above the thief zone. Maximum plug length is 500 feet. B) Run in hole with open-ended drill pipe to 10 feet below the bottom of the

loss zone. Spot a 100 bbl LCM pill (50 #/bbl) across loss zone.

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C) Pick-up 30-50’ above the circulation loss zone. Pump down the drill pipe

the calculated spacer, cement, spacer and kill fluid. This involves balancing the hydrostatic pressure inside and outside the drill pipe so that the height of the cement and displacing fluid inside the drill pipe equals the height of fluids in the annulus (see sketch below).

Note : Do not use a water spacer if loss circulation is in the Wasia.

D) Pick up drill pipe to +400 feet above the top of the calculated spacer. While pulling out of the cement, pull slowly to avoid swabbing and mud contamination.

E) Pump mud down the casing-drill pipe annulus and reverse circulate (if

possible) to insure pipe is clean of cement. F) POH to casing shoe. WOC. Attempt to fill hole. If unsuccessful, RIH with

open-ended drill pipe and tag top of cement. Set a second cement plug on top of Plug #1. Repeat process as described above.

G) If the hole can be successfully filled, pull out of hole with open ended

drill pipe. Run in hole with bit and drill out cement plug while keeping a close watch on the mud level in hole. If hole starts taking fluid, note depth and consider spotting of another cement plug or other type of plugs.

Balanced Plug Technique

M

M M

W

M

M

M MM

W

M

W W

W

M MM

M

W W

M MM

W

(a) Displacing cement.

(b) Cement, water and mud balanced.

(c) Pulling stringabove top of cement.

(d) Reversing out.

M = MudW = Water

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9.0 FOAM CEMENT

9.1 Characteristics

Foam Cement is a mixture of cement slurry, foaming agents, and a gas (usually nitrogen). When properly mixed, the process forms an extremely stable, lightweight, low permeability slurry that looks like gray shaving cream. Foam cement slurries can be prepared in the range of 30 to 112 pcf, which develop relatively high compressive strength in a minimum period of time. Although Foam Cement is mainly used in primary cementing, it may be used as a plug to regain lost circulation in zones where all other loss circulation methods have failed.

9.2 Procedures: (Foam Cement with Flo-Chek or Flo-Chek 1:1)

A) The fluid level should be determined as close as possible with an estimate of the fluid density in the well bore.

B) All personnel should be prepared for N2 gas cut returns and a method

of choking the well flow should be installed. It is not advisable to take Foam Cement returns through the rig’s choke manifold. A disposable adjustable choke should be installed if possible. Due to the viscous nature of Foam Cement, it is likely that a cement sheath will be left in the drill pipe. To help reduce this effect, a drill pipe wiper plug and catcher attachment should be installed so that the drill pipe may be cleaned during displacement.

C) RIH with open ended drill pipe, with a plug catcher if available, to a

depth that is at least 50’ above the loss circulation zone.

Note: It is advisable to lead in with a slug of mud containing LC material.

D) Flush and fill lines with fresh water. Pressure test lines to 3000 psi. E) OPTIONAL: Pump the following sequence with the annulus open at

+3BPM:

1. 24 bbls CaCl2 Brine Water as an activator solution 2. 5 bbls Fresh Water as a spacer 3. 12 bbls Flo-Chek or Flo-Chek 1:1 4. 5 bbls Fresh Water as a spacer 5. 24 bbls CaCl2 Brine Water as an activator solution 6. 5 bbls Fresh Water as a spacer 7. 12 bbls Flo-Chek or Flo-Chek 1:1 8. 5 bbls Fresh Water as a spacer

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F) Follow the Flo-Chek system with Foam Cement consisting of Class G

mixed at 118 pcf. Add N2 on the fly to bring the combined slurry weight to 63.5 – 67 pcf. The cement pump rate should be held to +3BPM. The foaming solution, consisting of 1.5% BWOMW HOWCO SUDS and 0.75%BWOMW HC-2, will be injected at a combined rate of 0.6 gal/bbl of slurry. Foamer FDP-C552 may be substituted for the HOWCO SUDS & HC-2 at the same loading.

Note: At any time during the pumping process, with the annulus open,

be sure to close it once returns are noticed. Monitor the pressure closely after the annulus has been closed and be prepared to shutdown quickly.

G) Continue pumping Foam Cement until the agreed upon volume has

been pumped or until squeeze pressure is noted. A pressure increase of 250 psi is sufficient for squeeze applications of this nature.

H) Drop the drill pipe wiper plug, if available, and displace the Foam

Cement with fresh water. I) Shut down, pull at least four stands, shear plug catcher and allow the rig

to reverse out any remaining cement that may be in the drill pipe. Be prepared to reverse out under pressure. If Foam Cement is reversed out, it will exit at an extremely high velocity. Control and regulate the return rate using surface valves or choke manifold.

J) Once the drill pipe and annulus are clean, POOH. K) Wait on cement 12-14 hours to allow the cement time to set. L) RIH with drill pipe and tag top of cement. Attempt to fill annulus. If

returns are noticed, resume drilling. Traces of N2 will be seen at surface while drilling through the Foam Cement column.

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ABANDONMENT GUIDELINES 1. CEMENT PLUGS

1.1 Introduction 1.2 Open Hole

1.2.1 Hydrocarbon Bearing Formations 1.2.2 Porous Aquifers 1.2.3 Last Casing Shoe 1.2.4 Extended Open Hole

1.3 Cased Hole 1.3.1 Casing-to-Formation Annulus 1.3.2 Hydrocarbon Zones 1.3.3 Water Source Zones 1.3.4 Injection Zones 1.3.5 Extended Cased Hole 1.3.6 Casing-To-Casing Annuli 1.3.7 Other Protective Plugs

2. MARKERS

2.1 Onshore 2.2 Offshore

3. RADIOACTIVE TOOLS (Lost in Hole)

3.1 General Information 3.2 Procedures

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ABANDONMENT GUIDELINES 1.0 CEMENT PLUGS

1.1 Introduction Proper abandonment is a combination of sound judgment and applicable oilfield practices tailored to a particular well. Factors affecting abandonment programming include:

A) Mechanical condition B) Hole problems while drilling C) Location D) Casing configuration and cementation integrity E) Productive nature and interrelation of porous aquifers and/or

hydrocarbon bearing zones F) Corrosion considerations G) Local development plans H) Governmental directives I) Economic considerations The guidelines presented herein are intended to establish uniform abandonment objectives while recognizing practical limits often imposed by well conditions.

1.2 Open Hole 1.2.1 Hydrocarbon Bearing Formations

Cement plugs are placed across all hydrocarbon bearing formations and extend at least 100’ below and 100’ above each formation. The presence of the plug across the hydrocarbon formation nearest the last casing shoe is to be confirmed by setting down the string weight on the plug after waiting on cement (WOC). Presence of all plugs isolating gas reservoirs should be checked in the same manner.

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1.2.2 Porous Aquifers Porous aquifers are to be isolated by cement plug placed across and/or between zones resulting in at least 100' of plug height separation between zones where possible. Check integrity (drill string weight) of the plugs as follows: A) Separating aquifers from uphole hydrocarbon zones B) Separating aquifers, which are potable or suitable for irrigation

purposes. The workover engineer should check with the Hydrology Dept. for this information

C) Separating all abnormally pressured water bearing zones

1.2.3 Last Casing Shoe A 300' cement plug should be placed across the last casing shoe and will extend at least 150' above the shoe. The plug should be tagged with the drill string and pressure tested to at least the maximum equivalent mud weight used in the open hole plus 25%. The tag up and pressure test should be witnessed by the Aramco representative on the rig and noted in the tour report.

1.2.4 Extended Open Hole In long sections of open hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 2000' intervals. The plug placement should be tagged with the drill string. Long open hole sections are common on deep exploratory wells.

1.3 Cased Hole

1.3.1 Casing to Formation Annulus

A) Where cement is not returned to surface during a cement job, the top of cement can be estimated from volumes of cement pumped, fluid returned and the hole diameter. Cement bond logs and/or temperature surveys can be run to determine the cement top and should normally be adequate confirmation of annular shut off integrity in critical situations. Under certain circumstances, however, perforating, cement squeezing and a dry test may be warranted.

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B) If the bond is questionable, the annulus should be cement squeezed between hydrocarbon reservoirs, between hydrocarbon and separate porous aquifers, and between separate porous aquifers. The UER is usually isolated from the Khobar by cement squeezing the RUS whereas the Wasia is isolated from the upper aquifers by cement squeezing the LAS.

1.3.2 Hydrocarbon Zones

All hydrocarbon zones tested or commercially produced then abandoned should be squeeze cemented after ensuring annular shut off and pressure tested to at least 50% above the balance mud weight equivalent (not to exceed the derated casing burst pressure). Gas zones are to be squeezed through a cement retainer, capped with at least 50' of cement, tagged and pressure tested as above. Depending upon the condition of the casing, a retrievable isolation test packer may be run for this pressure test if required.

1.3.3 Water Source Zones

Annular shut-off (formation to casing) should be ensured prior to squeeze cementing water source zones. If squeezing is unfeasible, an interior cement plug extending at least 100' below and 100' above will be placed, tagged, and pressure tested to the safe casing limit.

1.3.4 Injection Zones

Abandoned injection zones (water injection, disposal, product injection) should be cement-squeezed after confirming annular shut off above and below the zone. Squeeze integrity should be pressure tested to BH injection pressure + 25% equivalent.

1.3.5 Extended Cased Hole

In long sections of cased hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 3000' intervals. The plug placement should be tagged with the work string.

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1.3.6 Casing to Casing Annuli In some cases, an attempt should be made to cement sections of previously uncemented casing to casing annuli particularly when such section lie opposite hydrocarbon zones or corrosive aquifers having no cement rise on the outside string.

1.3.7 Other Protective Plugs

Abandonment cement plugs should be spotted across other susceptible points in the well as follows: A) 300' cement plug centered on any exposed liner top(s) B) 300' cement plugs centered across exposed stage cementing

equipment C) Cement plug having adequate height to extend 100' below and

above any problem points (casing parts, splits, patches, prior remedial perforations, etc.) in the innermost string

D) From surface to 300' depth (onland) and to 300' below mudline (offshore)

2.0 MARKERS

Once a well has been plugged with cement to the surface, an abandonment marker is installed for future identification.

2.1 Onshore

Onshore abandoned wells should have the landing base removed and salvaged. A steel plate will be welded on the casing cut-off and a 4-1/2" OD steel post is to be welded on top of the steel plate; a sign marker will be installed on top of the post. The post should be at least 4' long and extend at least 4' above ground level. The well name and abandonment date should be clearly embossed on both the post and sign marker, with weld material.

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Abandonment Marker

Well Number and Abandonment Date

Ground Level

Cellar

Sweet Sand

Conductor

Surface Casing

Intermediate Casing Cement Plug #1

Cement Plug #2

Cement Plug #3

4-1/2” Steel Post(with Well Name and Abandonment Date)

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2.2 Offshore

Offshore markers are similar to onshore markers except there is no post or abandonment marker. The blind flange is labeled with the well name and abandonment date.

3.0 RADIOACTIVE TOOLS

3.1 General Information When a radioactive source becomes stuck in a well during workover operations (as in re-entry sidetracks or deepenings), every reasonable attempt should be made to recover the source. If the attempt fails, the source should be abandoned properly per the following procedure in section 3.2. This procedure does not call for the well to be entirely abandoned, only the radioactive source. The decision whether or not to salvage the upper portion of the well should be made on a case-by-case basis.

3.2 Procedures

The following procedure conforms to the rules and regulations set forth by the United States Nuclear Regulatory Commission, specifically Title 10, Chapter 1, Part 39 (Licenses and Radiation Safety Requirements for Well Logging). 3.2.1 The Manager of Drilling and Workover Engineering Department will

submit a statement to the logging company. A copy of this statement will be forwarded to Government Affairs representative. The statement is to include the following: A) Source description; radio-isotope, quantity & activity B) The depth at which the source is stuck C) A summary of the attempts to retrieve the source D) A plan for the abandonment of the source in the well

3.2.2 Spot a +120 pcf cement plug directly above the fish. The plug is to be dyed red (use AMS No. 09-612-747) and dressed to a minimum of 50’ above the radioactive source.

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3.2.3 Place a steel object of adequate size, such as a used bit or whipstock, on top of the plug to prevent the inadvertent reentry of the abandoned hole interval. The bit or whipstock may be placed using a shear sub. See wellbore schematic below.

3.2.4 Install a permanent plaque on the wellhead. It must include:

A) The word “Caution” B) The radiation symbol C) The words “Saudi Aramco”

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D) The field name and well number E) Total depth of the well F) Date that the source was abandoned G) Depth of the source H) Depth of the plug I) Radio-Isotope, quantity & activity of the source

The plaque is to be corrosion resistant. It is usually made of engraved stainless steel, provided by the logging company and is to be installed by Saudi Aramco. See schematic below.

3.2.6 The Workover/Drilling Engineer is to include at least 3 references to

the lost radioactive source in the well’s Completion Report. A) Lost tools section on the Cover Page (page 1) B) Plugs/junk section in the Summary of Operations (page 2) C) Discussion section in the Summary of Operations

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CASING PATCHES

1.0 DESCRIPTION 2.0 APPLICATIONS AND RECOMMENDATIONS

2.1 Collar Leaks 2.2 Perforations 2.3 Split Casing 2.4 Corrosion 2.5 Milled Windows or Wear in Doglegs

3.0 SPECIFICATIONS 4.0 HOLE PREPARATION BEFORE RUNNING THE PATCH

4.1 Locating and Identifying the Leak 4.2 Casing Scraper Run 4.3 API Drift and/or Gauge Run 4.4 Gauge Run in a Deviated Hole 4.5 Circulating with Clean Fluid 4.6 Sand Production from Patch Area

5.0 RUNNING AND SETTING THE PATCH 6.0 OPERATING INSTRUCTIONS

6.1 Well Preparation 6.2 Tool Assembly at the Well Site 6.3 Forming the Liner Against the Casing Wall

7.0 STUCK IN THE HOLE 8.0 REMOVING A SET PATCH 9.0 REDUCED I.D.

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CASING PATCHES 1.0 DESCRIPTION

A casing patch is a thin walled steel liner, which tightly conforms against the inside of the casing, with the intent of permanently sealing off any type of leak. The standard patch restricts the I.D. of the casing by 0.300 inches. A heavier patch is also available in casing sizes 7” and larger with a 0.480 I.D. restriction. The standard patch arrives on location in a corrugated form (the cross section is star shaped) with fiberglass cloth on the outside. The fiberglass cloth, along with the epoxy, acts as a gasket when set. Once in position, pulling a specially designed expander tool through it expands the patch. Once expanded, or formed against the casing I.D., it is permanently held in place by radial compression.

2.0 APPLICATIONS AND RECOMMENDATIONS

The following are examples of where a casing patch could be used to remedy a given problem.

2.1 Collar Leaks

A casing patch can seal off a collar leak. No other special preparation is required other than a scraper and drift run prior to the running of the patch.

2.2 Perforations

Undesired perforations can be sealed off using an internal steel casing patch. The size of the perforations will determine the pressure rating of the patch. Corrosion and erosion of the perfs will increase their size and reduce the internal and external pressure rating of the patch. Patches can be milled out or perforated to re-open a zone.

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2.3 Split Casing

When patching split casing it is recommended that the patch be of sufficient length to cover the split plus 6-8 feet over lap on each end. This is because the split will have the tendency to spread or grow over time or while setting the patch. If the split was caused by excessive pressure, it is important to consider future pressure requirements of the patch.

2.4 Corrosion

Both ends of the patch must be set in good non-corroded pipe when patching corroded casing. Therefore when dealing with long corroded zones (in excess of 60 ft.), an extended length patch might be required. The extended length patch will come in two or more pieces that will require welding on the rig floor while running. Patches as long as 200 ft. have been run utilizing this method. When welding the patch sections together at the rig floor, the well is open to the atmosphere. If there is any chance of well control problems, extended length patches are not recommended.

If corrosion of the patch is of concern, then a corrosion resistant patch material, Incoloy 825, can be used. Typically these patches require more force or hydraulic pressure to be set.

2.5 Milled Windows or Wear in Doglegs

Milled windows or wear holes in doglegs are often quite large and their size and shape are difficult to determine. A milled window might have a rolled-in edge at the bottom. If this edge is large enough it could interfere with the setting of the patch, possible resulting in it becoming stuck in the hole, with the patch being partially set. Therefore it is extremely important to make an API drift run prior to running the patch. If the drift won’t pass, a tapered mill or string mill should be run to remove the restriction. Afterwards re-run the drift to insure the restriction is gone. Doglegs pose similar problems, severe doglegs may not allow the passing of the rigid unset patch to pass. It is strongly recommended that a trip be made with flush joint wash pipe or drill collars longer than the patch assembly and with an O.D. larger than the unset patch to assure the patch and setting equipment will pass through the dogleg. A casing scraper run is normally recommended before setting a patch to clean the area, however if the window or dogleg wear is very large there may be some concern about sticking the scraper. Not making a scraper run has its own risks as well. Foreign material on the casing wall could prevent setting

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the full length of patch resulting in a fishing job. Therefore it is a good idea to run the drift or mill as described above.

3.0 SPECIFICATIONS

Currently Saudi Aramco is using patches for 4-1/2 in., 7 in., and the 9-5/8 in. tubing and casing sizes. The following specs pertain to these tubular sizes.

TUBING OR CASING SIZE TOOL

SPRING COLLET

MINIMUM HOLE SIZE

LINER

WALL

OD (IN)

WT (LBS)

ID (IN)

PATCHED ID (IN)

OD (IN)

STAND. (IN)

COLLAPSED (IN)

OD MAX (IN)

ID MIN (IN)

THICKNESS (IN)

4-1/2 11.6 4.000 3.700 3-1/2 3.828 3.656 3.437 2.375 .120 4-1/2 13.5 3.920 3.620 3-1/2 3.750 3.625 3.437 2.375 .120

7 23 6.366 6.066 5-1/2 6.250 6.031 5.750 4.187 .120 7 26 6.276 5.976 5-1/2 6.172 5.938 5.750 4.187 .120 7 32 6.094 5.790 5-1/2 5.953 5.766 5.500 4.187 .120 7 35 6.004 5.704 5-1/2 5.953 5.766 5.500 4.187 .120

9-5/8 40 8.835 8.535 5-1/2 8.656 8.469 8.125 6.125 .120 9-5/8 43.5 8.755 8.455 5-1/2 8.578 8.391 7.875 5.875 .120 9-5/8 47 8.681 8.381 5-1/2 8.500 8.312 7.875 5.875 .120

Pressure Capacity Chart

CASING OD

(INCHES)

LINER WALL

(INCHES)

LEAK SIZE

(INCHES)

INTERNAL PSI

EXTERNAL PSI

1 OR LESS 9,850 2,500 4-1/2 1/8 2 4,925 1,700

3 3,283 800 1 OR LESS 9,850 1,100 7 1/8 2 4,925 825 3 3,283 650 1 OR LESS 9,850 800

9-5/8 1/8 2 4,925 650 3 3,283 500

The internal pressure capacity is: D psi 9,850P ?? for a 1/8” thick liner. Or, Dpsi 15,431P ?? for a 3/16” thick liner. Where: P = Internal pressure rating (psi) with a 20% safety factor D = Diameter of the leak (in)

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4.0 HOLE PREPARATIONS BEFORE RUNNING THE PATCH

4.1 Locating and Identifying the Leak

A wide variety of methods and equipment can be used to locate leaks, such as bridge plug and packer, RTTS tool, and wireline logs. Correlating or positioning the patch is very critical. If the position of the patch is off by several feet, a slow leak may result. To assure proper placement, a gamma ray log in conjunction with a radioactive sub or a pup joint in the string may be used for exact measurement determination.

4.2 Casing Scraper Run

A casing scraper run is normally recommended before setting a patch to ensure the area is clean. Pipe scale or other debris on the casing wall could prevent setting the full length of patch resulting in a fishing job.

4.3 API Drift and/or Gauge Run

As previously mentioned, it is extremely important to make an API drift or gauge run prior to running the patch into the well. If the pipe won’t drift, a tapered mill or string mill should be run to remove the restriction.

4.4 In a Deviated Hole, a Gauge Run with Flush Pipe Larger in Diameter than the Patch Setting Equipment and 25 ft. Longer than the Patch This will assure the patch and setting equipment will pass through any of the doglegs without getting hung up and becoming stuck.

4.5 Circulate the Well with Clean Fluid to Clean the Well

Circulating clean completion fluid through the well until all the returns come back clean, ensures that all the debris that the gauge ring, casing scraper or tapered mill might have dislodged is removed prior to running the patch.

4.6 If the Well is Making Sand in or Above the Patch Area, it Must be

Stopped

Sand can get in behind the patch preventing a good seal.

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5.0 RUNNING AND SETTING THE PATCH

The following is a brief summary of running and setting the patch. Different well conditions could necessitate the modifying of this procedure. For a more detailed procedure, see Operating Instructions 6.0 of this Chapter.

5.1 The setting tool is assembled and the patch is sized to the casing. The

expander assembly, extensions and casing patch are placed on the lower piston rod. After the steel liner is coated with epoxy resin, the tool is run in the hole on the work string. The liner is positioned across the leak.

5.2 The tubing is picked up to close the circulating valve. 5.3 If a hydraulic hold down is run, hydraulic pressure is applied to force out the

buttons. This anchors the cylinder firmly and isolates the work string from all tensile loads caused by the setting operations.

5.4 Pressure on the under side of the piston pulls the expander assembly back

up through the bottom of the corrugated patch. As pressure increases, the expander assembly is forced further into the patch, expanding it against the inside of the casing. Five feet of patch can be expanded in one stroke. The circulating valve is opened by lowering the work string, thereby telescoping the slide valve. The work string is raised again to pull up the cylinders in relation to the pistons held down by the expander assembly. The expanded section of the patch is held in place on the casing wall by friction caused by compressive hoop stresses. Hydraulic pressure is again applied to the work string after closing the circulating valve, once again expanding the hydraulic hold down buttons.

5.5 The expander assembly is again forced through the corrugated patch,

expanding it against the inside of the casing. This procedure is continued until the entire patch is set. The epoxy resin is extruded into any leaks or cavities in the casing wall and acts as a gasket and additional setting agent. Setting time normally requires less than 30 minutes for a 20-ft. patch. The tool is then removed from the well.

5.6 It is recommended to allow the patch to be set for 24 hrs. prior to pressure

testing the patch. The test pressure should not exceed the approximate internal pressure ratings given in the Specifications tables on the previous pages.

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6.0 OPERATING INSTRUCTIONS

The following is a detailed procedure on well preparation, tool assembly, and tool setting instructions. Once the exact depth that the repair to be made is determined, proceed with the following steps:

6.1 Step 1: Well Preparation

A) The area of the leak should be cleaned with a casing scraper about 15

ft. above and below the patch area. This removes cement cake, perforation burrs, and other solids from the casing wall.

B) A gauge ring with an O.D. not less than casing I.D. minus 1/8 “ should be run above the scraper to assure free passage of the repair tool.

6.2 Step 2: Tool Assembly at the Well Site

The tool will arrive at the location fully assembled in its major parts.

Slide valve, bumper jar, hold down and cylinder assembly will each be ready to couple together.

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Prepare the tool as shown in a place convenient to the rig elevator. Assemble the tool from the “top sub” to the “polish rod coupling”. Cover the well bore to prevent dropping objects downhole.

A) Raise the tool with the

elevators and lift into the derrick, then be sure that the lower polish rod is fully extended.

B) Add extensions to the

polish rod coupling to accommodate the length of patch to be used. In computing the

requirement, remember that the safety joint will add about 12” to 18” to this length. The safety joint is also added at this time. The overall length of the available space for the patch must be about 4” to 14” longer than the patch.

C) Raise the tool. Several

crewmen now hold the patch under the tool. Slowly lower the tool inside the liner.

D) When the tool is through

the liner, slide the Solid Cone and Spring Collet with sleeve over

the safety joint. Now secure the bull plug on the bottom most part of the safety joint. To do this, use a wrench on the bottom most part of the safety joint and one wrench on the bull plug. This will prevent a disengagement of the safety joint’s left hand threads.

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E) The epoxy mix is now prepared. Pour the catalyst from the quart can into the resin in the gallon can. Stir thoroughly for about three minutes. One can of each is sufficient for about 10-15 ft. of liner. Remove the cover from the well bore. Apply the epoxy mixture to the fiberglass of the liner by using rubber gloves as the tool is being lowered. Rub it into the fibers as completely as possible. Lower the tool down hole to the depth required at standard rates ? 2500 feet per hour. The driller should stop slowly at the end of each stand. If the string is stopped suddenly, the downward momentum of the patch may cause the patch to prematurely begin setting. Run slowly and carefully when passing through any known or suspected restrictions in the well. Forcing the patch through restrictions and/or doglegs could also cause the patch to begin setting prematurely. Use as little force as necessary if the patch is dragging while running in the hole.

6.3 Step 3: Forming the Liner Against the Casing Wall

6.3.1 In computing the tubing length necessary to reach patch depth,

measure down to the liner stop (the top of the patch). Once is at the desired depth, mark the pipe. Actuate the slide (drain) valve by lowering the work string 5-10 ft. Then slowly raise the tool to the depth required. The slide valve is now closed. Connect a high-pressure line to the work string. When pressuring first begins, drain all the air out of the line. Now operate the pump at constant speed. This will cause as upward motion of the expander assembly into the patch liner. The pressure gauge will show a gradual increase until the stroke begins. Then the pressure will level off or perhaps drop a small amount. When the end of the stroke is reach, the gauge will show a gradual increase in pressure. Hold the pressure at 3500-4000 psi for about two minutes. Now release the pressure by opening the by-pass valve on the pump. Raise the tool with the elevators approximately 3-1/2 to 5 ft. or until an increase of weight is noted on the weight indicator. The amount that is pulled up represents the end of the stroke. Note: At this point, difficulties have been experienced when attempting to pull up on the string after a pull has been made. The difficulty has been that the hydraulic

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hold down buttons would not release. This has been the case where drilling mud was used instead of water or when the annulus fluid level was low due to the fact that the well would not remain full of fluid. If the hold down buttons do not release, either pressure up on the annulus or work the hold down by continual attempts to pull up in short strokes. When the fluid level is low, either have the driller fill the annulus before each movement or operate the slide (drain) valve and thereby equalize the fluid level inside the tubing with the fluid level in the annulus. When the tool has been pulled up to the end of the stroke, repeat the pressure procedure until the patch is set.

6.3.2 When the patch is set, remove all pressure hoses. Retrieve the tool

from the hole. In order to retrieve the tool with a dry string, raise each stand about 5-8 feet higher than necessary. Then lower the connection to the coupling and break out the stand. This opens the slide (drain) valve.

6.3.3 The patch is now complete. Due to the curing time of the epoxy

mixture, it is preferred that the patch not be tested for at least 24 hrs. This allows the epoxy mixture to reach approximately 90% of its sealing strength.

7.0 STUCK IN THE HOLE

If the patch becomes stuck or the hydraulic setting equipment does not function, the patch can still be set mechanically or released from the safety sub. If after the first hydraulic stroke of the setting tool, it can no longer hold pressure, the patch can be completed with a straight pull by the rig. Therefore a good work string is required on which the patch is to be run. If the patch cannot be set with a straight pull by the rig, the tool can be released by applying upward strain and 8 to 10 rounds of right-hand torque, which releases a safety joint just above the expander assembly, allowing the retrieval of the tool.

8.0 REMOVING A SET PATCH

If it becomes necessary to remove a patch, it can be milled out with mills or rotary shoes. The O.D. of the mill or shoe should be between the drift diameter and 1/16-in. over drift if the patch is set or the drift diameter if stuck.

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9.0 REDUCED I.D.

As mentioned before, the standard patch restricts the I.D. of the casing by 0.300 inches. A heavier patch is also available in casing sizes 7” and larger with a 0.480 I.D. restriction. Therefore, prior to running anything through a patch, ensure that the O.D. of the tool to be run is small enough to pass through the inner diameter of the patch.

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KILL AND LIVENING PROCEDURES FOR WORKOVERS 1.0 INTRODUCTION

2.0 KILL PROCEDURES

2.1 Bullheading 2.2 Circulating 2.3 Coiled Tubing 2.4 Lubricate and Bleed

3.0 LIVENING PROCEDURES

3.1 Bullheading 3.2 Circulating 3.3 Coiled Tubing

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KILL AND LIVENING PROCEDURES FOR WORKOVERS 1.0 INTRODUCTION

Wells with exposed perforations or open hole must be killed before running/ removing the tubing (without the use of a snubbing unit). A well is killed by loading the tubing and/or casing with a fluid of sufficient density so that the hydrostatic head of the fluid exceeds the formation pressure. This chapter will discuss the following procedures for killing a well prior to workover operations: (a) bullheading, (b) circulating, (c) coiled tubing, and (d) lubricate and bleed.

After completing the workover, the well must be livened to put the well back on production. Livening consists of loading the tubing with a fluid of lesser density so that formation pressure exceeds the hydrostatic head of the fluid. This chapter will also describe the following livening procedures: (a) bullheading, (b) circulating, and (c) coiled tubing.

2.0 KILL PROCEDURES

2.1 Bullheading

The bullheading method is utilized when the wellbore is free of obstructions and injectivity can be established into the formation. A kill weight fluid is pumped (bullheaded) down the tubing and/or casing without any returns to surface. Gas wells (such as Khuff/Pre-Khuff wells) are routinely killed by bullheading. Bullheading a kill fluid down the tubing on a gas well is made possible by (1) gas being compressible and (2) gas injectivity being easier than liquid injectivity. Oil wells (such as Arab-D wells) are also routinely killed in this same manner. Bullheading is possible on Arab-D oil wells because of the (1) associated gas, and (2) high permeability of the Arab-D reservoir. The main advantage of bullheading is low cost. Since a rig is not required, the tubing can often be killed before the rig moves on location. This kill method is requires a tubing string of good condition. If not, total placement of the kill fluid may be compromised. A second limitation is the risk of formation damage. If there is any scale or debris inside the tubing, it may be pumped into the perforations, resulting in skin damage.

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The illustration below shows the tubing being killed by the bullhead method.

Note: The kill fluid should be mud, as brine can seep into the formation and result in an under-balanced condition. A dead well will have with zero surface pressure, zero flow rate, and a static fluid level at surface.

SHUT-INTUBINGPRESSURE

0

0

ANNULUSPRESSURE

BULLHEAD KILL PROCEDURE

(A)START OF KILL

SHUT-INTUBINGPRESSURE

0

0

ANNULUSPRESSURE

START PUMPINGKILL FLUIDDOWN TUBING

KILL FLUIDREACHES THEPERFORATIONS(WELL IS DEAD)

(B)KILL COMPLETE

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2.2 Circulating

Most Saudi Aramco wells are completed with inhibited diesel as a packer fluid. In these wells, the tubing-casing annulus will be under-balanced, even after the tubing is killed. Regardless of whether or not the tubing has been killed, the under-balanced packer fluid must be circulated out before the completion equipment can be pulled. This is accomplished using the circulating method. The circulation kill method requires making holes in the tubing just above the packer, using either a mechanical type tubing punch run on slick line or a soft perforating shot run on electric line. Mechanical punches and soft shots are discussed further in the Chapter 5D of this manual. After establishing circulation through the hole in the tubing, the kill fluid is pumped down the tubing and circulated back to surface through the tubing head side outlet. The well should be verified as dead and hole full before attempting to pull the tubing. The circulating method is the least damaging way of killing a well.

The illustration below shows the well being killed by the circulating method.

CIRCULATING KILL PROCEDURE

PUMP KILLFLUID DOWNTHE TUBING

TAKE RETURNSTHROUGH THETUBING HEADSIDE OUTLET

Figure 2

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2.3 Coiled Tubing

This kill method is only used if the bullhead or circulation methods are not feasible. A coiled tubing kill is be required in wells where the (1) wellbore or perforations are be plugged, (2) formation will not accept kill fluid, or (3) bullhead pressure results in excessive wellhead pressure. A coiled tubing unit of adequate coil length, outside diameter clearance, required pressure rating, and BOP stack configuration (as per Saudi Aramco Well Control Manual) is rigged up on the tree. The coil is run inside the production tubing to the perforations (or as deep as possible). Kill fluid is circulated inside the tubing with the coil, thus killing the tubing. If the packer fluid were under-balanced, the circulation method would still be needed before pulling the production tubing.

2.4 Lubricate and Bleed

The lubricate and bleed method is not a commonly used procedure in Saudi Aramco. This method is recommended in wells where the other methods are not possible. For example, a lubricate and bleed procedure was utilized on the UTMN-1811 blowout to control surface pressure during the well kill operation. Other kill methods (bullheading, circulating, and coiled tubing) were not feasible at that point in time. The technique consists of pumping a small volume of very dense fluid down the string until the maximum allowable surface pressure is reached. Operations are stopped for a period of time to permit the dense fluid to fall. The well is then opened and the production fluids and/or gas are bled off until some of the dense fluid is recovered. The process is repeated until the entire tubing volume is displaced with the dense fluid and the well is dead.

3.0 LIVENING PROCEDURES

3.1 Bullheading

A well can be livened by bullheading the kill fluid inside the tubing with a lesser density fluid, in order to achieve an under-balanced condition. This method assumes that kill fluid can be injected into the formation and potential formation damage is not a concern.

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Power Water Injection (PWI) wells, which are tubingless completions, are livened by this method. Following the completion (or workover), the PWI well is displaced to CaCl2 brine, and a 10” ball valve is closed at surface. The BOP stack is nippled down and a 2” injection tree is installed. The CaCl2 brine inside the casing is bullheaded into the formation with fresh water, creating an under-balanced condition. The well is opened and flown for clean up.

3.2 Circulating

Circulating a lesser density fluid (under-balanced) down the production tubing with returns up the tubing-casing annulus is another method of livening a well. The circulating method requires down-hole isolation to control formation pressure while circulating the less dense fluid. The following are examples of circulating to liven the well. Arab-D open hole producers are completed with a 7” production packer and tubing tail (w/ 3-1/2” ‘X’ nipple and ‘XPO’ plug in place). After setting the packer and running the 4-1/2” tubing, the tubing-casing annulus is displaced to inhibited diesel and tubing to diesel. The ‘XPO’ plug is sheared with surface tubing pressure and equalized. A wireline unit is required to retrieve the ‘XPO’ plug mandrel. The well is opened and flown for clean up. Khuff gas producers with a PBR completion also utilize the circulating method for spotting the packer fluid and cushion in the tubing. In this case, the unperforated casing isolates formation pressure. After running the production tubing and spacing out, the tubing-casing annulus is displaced to inhibited diesel and tubing to diesel. The seal assembly is stung into the PBR and the tubing is landed. The well is perforated under-balanced with a diesel cushion and flown for clean up.

3.3 Coiled Tubing

Coiled tubing livening is used when either the bullhead or circulating methods was not feasible or successful. Coiled tubing is be required on wells that do not flow after being under-balanced with water or diesel. A coiled tubing unit of adequate coil length, outside diameter clearance, required pressure rating, and BOP stack configuration (as per Saudi Aramco Well Control Manual) is rigged up on the tree. The coil is run inside the production tubing while circulating nitrogen and unloading the tubing. The well should be continuously monitored for flow while running in the hole and unloading the tubing. Once flow is established, the coil tubing should be pulled out of the hole. The well is opened and flown for clean up.

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SURFACE AND DOWNHOLE PLUGS 1.0 TYPES OF PLUGS

1.1 Back Pressure Valves 1.2 Polymer Plugs 1.3 Cement Plugs 1.4 BOP Test Plugs 1.5 Mechanical Downhole Plugs

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SURFACE AND DOWNHOLE PLUGS 1.0 TYPES OF PLUGS Several types of plugs are used for many purposes in the Oil Industry. Saudi Aramco Drilling and Workover commonly uses Back Pressure Valves and Two-way Check Valves, Chemical Plugs, Balanced Cement Plugs, BOP Test Plugs and Mechanical Downhole Plugs. These different plugs are used as safety barriers while installing, or removing, well control and production equipment and as test plugs when pressure testing equipment. When removing surface control equipment it must be replaced with downhole isolation barriers. Plugs are the most commonly used isolation barrier. Please refer to GI 1853.001, Isolation Barriers For Wells During Drilling and Workover Operations (With and Without Rig) for the required number and type of plug to be used.

1.1 Back Pressure Valves Back Pressure Valves are set in a special profile in the tubing hanger. They are normally used while installing or removing production trees and BOP equipment. Two way check valves can be installed in the same profile and are used to test the equipment. A two way check valve shall only be used to test equipment after it is installed, not during installation or removal operations. This is because it is possible to pump kill weight fluids through a back pressure valve but not through the two way check valve. More details on these plugs and installation and removal procedures may be found in Chapter 2-E, WELLHEAD, Section 4.0.

1.2 Polymer Plugs

Polymer plugs may be spaced across perforations and used as an additional safety device when performing unusual well servicing. They are more commonly used for temporarily or permanently healing lost circulation. More details on these plugs may be found in Chapter 2-F, LOST CIRCULATION, Section 5.0, Polymer Plugs. Whenever using polymer plugs it is important to emphasize the need to (a) tailor the plug design for the well conditions, (b) laboratory test the plug to fine-tune the polymer additive concentrations, and (c) ensure satisfactory polymer plug performance.

1.3 Cement Plugs

Cement plugs may be spotted in casing or, in some cases tubing, and used as an additional barrier during unusual well servicing operations. More details on these plugs may be found in Chapter 2-F, LOST CIRCULATION, Section 5.0, Cement Plugs.

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1.4 BOP Test Plugs

BOP Test plugs are designed to be installed in a casing head, casing spool or tubing spool to provide a bottom seal while testing BOPE. They are designed and built to fit one size head or spool made by one Manufacturer. For example, if you have a Cameron 13-5/8” 3M casing head you must use a Cameron 13-5/8” BOP test plug. If you have a Gray 13-5/8” 3M casing head you must use a Gray 13-5/8” BOP test plug. These plugs may not be interchanged. The preferred running procedure is to make up at least one stand of drill pipe below the plug, preferably hevi-weight. The elastomer seal on the O.D. of the plug should be visually inspected and a coat of grease or pipe dope applied prior to running.

1.5 Mechanical Downhole Plugs

Downhole or “wireline” plugs are used on a daily basis in Saudi Aramco operations. These types of plugs, along with the back pressure valve, are used as isolation barriers after the completion string has been run. The most commonly used wireline plugs are the X locking mandrel and the R locking mandrel. In order to use these plugs there must be a mating X or R landing nipple installed in the completion string. Typically the X nipple is installed in normal weight tubing strings and the R nipple in heavy weight tubing strings. Figure 2J-1 shows the R and X models of landing nipples and lock mandrels. The nipples are selective nipples as they will allow a plug to pass through them and it can be set in a nipple below, or in the selective nipple. Figure 2J-2 shows XN and RN no-go landing nipples and lock mandrels. These nipples are termed no-go because they have an internal profile that will not allow the plug to pass below the nipple, and thus it can only be set in that specific nipple. Figure 2J-1: Selective Nipples and Lock Mandrels

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Saudi Aramco uses the PX and PXN plugs almost exclusively. These plugs come equipped with a pressure equalization valve and matching prong. They are set in X, selective, and XN, no-go, nipples. These plugs are installed in two trips. On the first trip the plug is ruin without the prong. The prong is then inserted on the second trip, sealing the equalization ports and preventing sand or fill from falling into the interior of the plug. The plugs are retrieved in two trips, the prong on the first. This provides an equalization path and prevents the plug from being blown uphole. IF it is desirable to make only one trip XX or XXN plugs may be run. These plugs are run or retrieved and the equalizing ports opened or closed in one trip. All of these plugs may be run and retrieved on coiled tubing. This method would be desirable in a horizontal or highly deviated well. Figures 2J-3 and 2J-4 are tables listing the common sizes of landing nipples and lock mandrels available. Remember to always double check the size before attempting to run a plug.

Figure 2J-2: No-Go Nipples and Mandrels

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Figure 2J-3: X and XN Nipple and Mandrel Dimensions

Packing Borein. mm Ib/ft kg/m in. mm in. mm in. mm in. mm in. mm in. mm

1.050 26.67 1.20 1.79 0.824 20.93 0.730 18.541.315 33.40 1.80 2.68 1.049 26.64 0.955 24.26

2.30 3.432.40 3.572.40 3.57 1.660 42.162.76 4.11 1.500 38.10 1.500 38.10 1.448 36.782.90 4.32

2.063 52.40 3.25 4.84 1.751 44.48 1.657 42.09 1.625 41.28 1.625 41.28 1.536 39.014.60 6.854.70 7.006.40 9.536.50 9.689.30 13.85 2.992 76.00 2.867 72.82 2.813 71.45 2.813 71.45 2.666 67.7210.20 15.34 2.922 74.22 2.797 71.04 2.750 69.85 2.750 69.85 2.635 66.93

4.000 101.60 11.00 16.38 3.476 88.29 3.351 85.10 3.313 84.15 3.313 84.15 3.135 79.63 2.120 53.854.500 114.30 12.75 18.99 3.958 100.53 3.833 97.36 3.813 96.85 3.813 96.85 3.725 94.625.000 127.00 13.00 19.36 4.494 114.14 4.369 110.97 4.313 109.55 4.313 109.55 3.987 101.275.500 139.70 17.00 25.32 4.892 124.26 4.767 121.08 4.562 115.87 4.562 115.87 4.455 113.16 3.120 79.25

X® and XN Landing Nipples and Lock Mandrels Specifications

X® ProfileSize Weight ID Drift

For Standard Tubing WeightsXN Profile

Packing Bore Lock Mandrel ID

No-Go ID

1.900 48.26 1.610 40.89 1.516 38.51

15.7531.75 1.250 31.75 1.135 28.83 0.620

0.750 19.05

1.250

2.313

1.875 47.63 1.875 47.63 1.791 45.49

35.0558.75 2.313 58.75 2.205 56.01 1.380

2.620 66.55

1.750 44.45

1.000 25.40

Available on Request

Tubing

1.66 42.16 1.38 35.05 1.29 32.66

2.375 60.33 1.995 50.67

3.500 88.90

1.901 48.29

2.875 73.03 2.441 6,200 2.347 59.61

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Size Weight ID Drift Packing Bore Bore IDin. Ib/ft in. in. in. in. in. in.

1.660 3.02 1.278 1.184 1.125 1.125 1.012 on Req.1.900 3.64 1.500 1.406 1.375 1.375 1.250 0.620

5.30 1.939 1.845 1.781 1.781 1.640 0.8805.95 1.867 1.7736.20 1.853 1.7597.70 1.703 1.609 1.500 1.500 1.345 0.6207.90 2.323 2.229 2.188 2.188 2.010 1.1208.70 2.259 2.1658.90 2.243 2.1499.50 2.195 2.101

10.40 2.151 2.05711.00 2.065 1.97111.65 1.995 1.90112.95 2.750 2.625 2.562 2.562 2.329 1.38015.80 2.548 2.42316.70 2.480 2.35517.05 2.440 2.315 2.188 2.188 2.010 1.12011.60 3.250 3.303 3.250 3.250 3.088 1.94013.40 3.340 3.215 3.125 3.125 2.907 1.94012.75 3.958 3.833 3.813 3.813 3.725 2.12013.50 3.920 3.79515.50 3.826 3.70116.90 3.754 3.62919.20 3.640 3.51515.00 4.408 4.283 4.125 4.125 3.912 2.75018.00 4.276 4.151 4.000 4.000 3.748 2.38017.00 4.892 4.76720.00 4.778 4.65323.00 4.670 4.545 4.313 4.313 3.987 2.62015.00 5.524 5.39918.00 5.424 5.29924.00 5.921 5.79528.00 5.791 5.66617.00 6.538 6.43120.00 6.456 6.33123.00 6.366 6.24126.00 6.276 6.15129.00 6.184 6.05932.00 6.094 5.96935.00 6.004 5.879 5.875 5.875 5.750 3.750

7.050 7.050 6.925 5.2507.250 7.250 7.125 5.2507.450 7.450 7.325 5.250

5.250

5.625

5.963

8.625 36.00 7.825 7.700

2.313

3.688

3.437

4.562

For Heavy Tubing WeightsR® Profile RN® Profile

1.560

1.937

Tubing

1.710

2.125

2.000

7.000

1.875

2.313

3.688

3.437

4.562

5.250

5.625

5.963

6.000

6.625

1.881

1.716

2.131

3.456

3.260

4.445

5.018

5.500

5.000

5.500

5.770

0.750

0.880

0.880

0.880

1.120

2.380

1.940

4.000

4.500

2.850

3.500

2.375

2.875

3.500

3.750

3.500

1.710

2.125

2.000

1.875

Lock Mandrel ID

Landing Nipples And Lock Mandrels Selective By Running ToolR® And RN® Landing Nipples And Lock Mandrels Specifications

Figure 2J-4: R and RN Nipple and Mandrel Dimensions

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WORKOVER FLUIDS 1.0 INTRODUCTION

1.1 Definitions 1.2 Selection of Fluids 1.3 Fluid Functions

2.0 TYPES OF FLUIDS

2.1 Oil Fluids 2.2 Clear Water Fluids 2.3 Oil & Water Emulsions

3.0 CHARACTERISTICS OF FLUID ADDITIVES

3.1 Acid Soluble (CaCO3) Weighting Material 3.2 Characteristics of Polymers 3.3 Viscosity and Suspension

4.0 SELECTING A COMPLETION FLUID

4.1 Solids-Free High Density Fluids 4.2 Sodium Chloride Brines 4.3 Potassium Chloride Brines 4.4 Calcium Chloride Brines 4.5 Sodium Chloride/Calcium Chloride brines 4.6 Field Operations Utilizing Brines (Compatibility)

5.0 SPECIALLY DESIGNED BRINE/POLYMER SYSTEMS

5.1 Calcium Carbonate Fluids 5.2 Acid Soluble Bridging Material 5.3 Low Density (Oil-In-Water or Brine) Emulsions 5.4 Oil-Based Fluids or Invert Emulsions 5.5 Air/Mist/Foam

6.0 PACKER FLUIDS

6.1 Functions 6.2 Required Characteristics of Packer Fluid 6.3 Necessary Fluid Properties 6.4 Drilling Mud Packer Fluid 6.5 Solids-Free Oil Packer Fluid 6.6 Solids-Free Packer Fluid 6.7 NaCl Brines 6.8 CaCl2 Brines 6.9 Important Points to Remember 6.10 Corrosion Inhibitors

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7.0 HANDLING COMPLETION FLUIDS

7.1 Transportation 7.2 Rig Preparation 7.3 Clear Brines 7.4 Fluid Maintenance 7.5 Displacement Techniques 7.6 Conditioning Mud 7.7 Displacing Mud 7.8 Displacement of Pads/Spacers 7.9 Chemical Washes 7.10 Special Techniques 7.11 Staging Spacer Densities 7.12 General Displacement Procedures 7.13 Displacement of Water-Based Mud using Seawater Flush 7.14 Displacement of Oil-Based Mud using Seawater Flush 7.15 Balanced Displacement of Water-Based Muds 7.16 Balanced Displacement of Oil-Based Mud 7.17 Spacers 7.18 Pills 7.19 Clear Brine Completion Fluid Displacement

8.0 SAFETY

8.1 Safety Apparel 8.2 Rig Safety Equipment

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WORKOVER FLUIDS 1.0 INTRODUCTION

Completion or workover fluids are those that are placed against the producing formation while well killing, cleaning out, stimulating, or perforating. A workover fluid is used during remedial work on a well which has been producing for some time. Any contact of a well servicing fluid with an oil or gas reservoir rock will be a prime source of wellbore damage. Poor performance of water source wells, injection wells, or oil and gas production wells can almost always be traced to undesirable characteristics of drill-in and completion fluids used. We should think of completion fluids as tools that aid in performing a downhole operation after the well has been drilled. As tools, these fluids are introduced in the wellbore for a particular function and should be removed after the job. Therefore, we must try to prevent the loss of damaging fluids into the producing zones. Completion and workover fluids technology evolved in an effort to minimize this damage through the use of specialized fluids. These fluids differ from drilling muds in that they are clean, solids-free or degradable and tailored to be non-damaging to the producing formation.

Two primary objectives must be accomplished regardless of the well servicing operation undertaken:

? Control the well with required density and minimal leak-off ? Protect the producing formation from damage

Note: Drilling mud should be considered as the kill fluid in situations where brine

leak-off is anticipated.

1.1 Definitions

1.1.1 Completion fluids are used for downhole applications such as ? Perforating ? Wellbore cleanout ? Displacement of treating chemicals (surfactants, acids, and

solvents) ? Underreaming, gravel packing, and fracturing ? Cement and sand consolidation ? Packer fluids

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1.1.2 Workover fluids are the general-purpose fluids such as ? Kill fluids to control the well while it is open ? Milling and fishing downhole equipment or sidetracking ? Displacement of cement for zone isolation or plugging old

perforations ? Suspending wells

1.2 Selection of Fluids

Many factors must be considered before a decision is made on the type of well servicing fluid to be used. Selection of fluid should be a logical solution based on operational necessities and formation characteristics. The workover engineer should communicate between the different departments (geological, petrophysical, reservoir, drilling and workover operations and the laboratories) to gather information, conduct the necessary studies and laboratory tests. The proper fluid system can be selected based on the data obtained. In most cases, this selection process requires compromises be made. Usually, formation damage cannot be totally prevented, but certainly it can be minimized by optimizing the favorable aspects of the fluids to be used. Applying the technology available today, we can remove most of the "guess work" in designing the best fluid.

1.2.1 Procedure

? Define the operational objectives. ? Identify the environment under which the fluid must perform

(bottomhole pressure and temperature, location, rig equipment, water supply and surface temperature).

? Evaluate performance of fluids used before and problems encountered in the field.

? Study the reservoir rock and reservoir fluid chemical characteristics.

? Examine possible reactions between candidate fluids, rock minerals & fluid.

? Analyze field results and assess the fluid performance after the job.

? Recommend changes or modifications for future work.

Understanding of the physical and chemical reservoir characteristics by all personnel involved will ensure good planning, help in identifying problems and improve field practices. A reservoir rock sensitivity study may be required along with measurements of the residual damage caused by different fluids. Such a study will determine the

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degree of damage caused and the effectiveness of the remedial measures.

SENSITIVITY STUDY

RESERVOIR FLUID RESERVOIR ROCK

Water analysis & fluid compatibility Mineral analysis & clay fraction

Scaling tendencies Grain & pore size distribution Emulsion tendencies Porosity & permeability

1.3 Fluids Functions

1.3.1 Well control is a primary function. The fluid must be heavy enough to

create the required hydrostatic pressure to stop the well from flowing. The fluid density determines the hydrostatic head and it should be no higher than necessary to minimize the fluid invasion into the subsurface formation. Fluid density is the mass per unit volume and may be measured as pounds mass per cubic foot or pounds mass per gallon. Density may also be expressed in terms of specific gravity or pressure gradient. Specific gravity is the mass of fluid at a given temperature relative to the mass of an equal volume of water at the same temperature. The pressure gradient is the hydrostatic pressure created by the fluid per unit of vertical depth.

Fluid densities decrease with increasing temperature. The amount of decrease depends on the fluid composition. By way of example, 86.77 pcf (11.6 lb/gal ) CaCl2 brine at 70 °F decreases to 83 pcf (11.1 lb/gal) at 230°F. Entrapped gases will affect the measurement of fluid density. If gas entrapment is a problem, one can use a pressurized mud balance or deaerator to measure the fluid density. Two instruments are in general use in the field: Mud balance and Hydrometer ( API 13J ). Three different types of materials are commonly used in the oil field to increase the fluid density. These are

?? Water soluble salts ?? Acid soluble minerals ?? Insoluble minerals

Saudi Aramco's recommended practice is not to use insoluble minerals in well servicing fluid formulations.

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1.3.2 Wellbore cleanout is another major function. Drilled cuttings, produced sand, drilling mud residue, rust, scale, paint chips, iron shavings and debris must be removed from the well. Solids left in the wellbore can enter the perforation restricting the flow capacity of the well. After the well is completed, these solids can fall on the downhole dynamic seal assembly causing leaks and the potential need for an expensive workover. The effectiveness of any fluid used in the well cleanout operations depends on its carrying capacity, which is largely a function of fluid viscosity. Rotating the workstring ( 3-10 rpm ) will improve the removal of solids from the well while circulating. Chemical washes ( water wetting surfactant, mutual solvent in acidic water ) will remove organic and inorganic residue when circulated downhole followed by high viscosity sweeping pill. Examination of tubing recovered from wells shows that corrosion in the annulus could be avoided had solids been effectively removed through proper displacement.

1.3.3 Corrosion protection is an important function of all well servicing

fluids which will remain in the well for an extended period of time. Corrosion inhibitors are added to reduce the fluid corrosion rate to acceptable level. Oxygen scavengers, film forming amines, high temperature inorganic inhibitors and pH buffers are effective chemicals at low concentrations. The simplest and most common method of corrosion control is to use a highly alkaline fluid. Static testing in the lab for thirty days at the desired temperature and pressure, is sufficient to determine the long term corrosivity of the fluid

1.3.4 Formation protection is a function of any fluid that may become in contact with a producing formation. The fluid allowed to leak off to the formation should not contain damaging solids, such as clays, silt, barite, paraffin, asphalt, rust, pipe dope etc.,. The fluid or fluid filtrate should be chemically compatible with the formation fluids and should not allow the clay minerals to hydrate, swell or move. Surfactants, such as the oil wetting corrosion inhibitors, oil-based mud emulsifiers, and lubricants will cause emulsion blockage when introduced into a producing formation. If excessive fluid losses are expected, water-wetting surfactant should be included in the fluid formulation to prevent or remove water blocking.

1.3.5 Treating chemical displacement is a very important function of the

well servicing fluids. To pump acid, mutual solvent, clay stabilizer, injection water, etc into the reservoir rock a workover fluid is usually employed. It must be clean and compatible with the treating

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chemicals and the formation fluids. The wellbore must be also cleaned with properly designed spacers and chemical washes. Electrical logging is greatly affected by the wellbore fluid. Materials and chemicals which adversely affect the quality of the logs should be avoided. Reservoir Engineering should be involved in the selection of the type of workover fluid to be used. Some logs require low chlorides content and others will produce erroneous data in the presence of small amount of barite. Saudi Aramco's recommended practice is to maintain the chlorides below 50,000 mg/l and not to use any barite in the fluids while drilling and completing the payzone section.

2.0 TYPES OF FLUIDS

Completion fluids are used in well operations during the process of establishing final contact between the productive formation and the wellbore. They may be water-based mud, nitrogen, an invert emulsion, solids-free brine, or an acid soluble system. The most significant requirement is that the fluid is not damaging to the producing formation. Packer fluids are used in the annulus between the production tubing and casing. They must provide the required pressure, must be non-toxic and non-corrosive, must not develop high gel strength or allow solids to settle out of suspension over long periods of time, and must cause minimal formation damage. Various types of fluids may be utilized for completion and workover operations. Current literature relating to completion and workover fluids reveals different approaches to classifying such fluids.

Allen and Roberts used the following categories in their discussion of completion and workover fluids.

1. Oil Fluids: 2. Clear Water Fluids: ? Crude oil ? Formation salt water ? Diesel oil ? Seawater or bay water ? Prepared salt water 3. Solid Laden Fluids 4. Conventional Water-Base Muds 5. Oil-based or Invert Emulsion Muds

According to Gray, completion and workover fluids may be categorized as follows:

1. Water-Base Fluids:

? Fluids with water-soluble solids

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? Fluids containing oil-soluble organic particles ? Fluids with acid degradable polymers and solids

2. Oil-in-Water Emulsions (O/W density) 3. Oil-Based or Invert Emulsion (water-in-oil emulsions)

Following Allen's classification, a description of the different types of completion and workover fluids follows:

2.1 Oil Fluids. As the name indicates, oils of different origin are sometimes used

to complete the well. Depending on availability, crude or diesel oil may be used as the completion fluid.

2.1.1 Crude oil is a logical choice where its density is sufficient to control

formation pressure. The fluid has very low viscosity, limited carrying capacity and no gel strength. The loss of fluid to the formation is not harmful from the point of view of clay hydration and migration. Since it has no fluid loss control, fine solids may enter the formation. Crude oil always has to be checked for presence of asphaltenes and paraffins that can damage the formation. The possibility of emulsion forming with the formation water should be checked before it is used. The technique described in the API RP 24 is suitable for field use. If forming of emulsion is possible, a surfactant should be added to prevent it.

2.1.2 Diesel oil is used when a clean and low-density fluid is necessary for

a completion and workover operation. Always check the diesel for a possible solid contamination in order to avoid formation damage. Emulsion and wettability problems will be avoided if the diesel is obtained form the refinery before fuel additives are added. Diesel oil will offer a non-corrosive environment, which makes it attractive as packer fluid.

2.2 Clear Water Fluids. This group includes waters of diverse origin with

different salts in solution. These waters may contain solids, although the concentration is usually very low. Based on the origin of the water, the clear water fluids may be divided as follows:

2.2.1 Formation water is the produced reservoir water. It is a common

workover fluid, since its cost is low. Clean formation water is ideal from the point of view of compatibility with the reservoir fluids and minerals. Before using produced formation water as a completion and workover fluid, a compatibility study with the reservoir rock exposed in

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the wellbore should be run. Also, the calcium content and the scaling tendencies should be determined. Although formation water is taken into consideration as a clean, ready to use fluid, it many times will contains fine solids, treating chemicals, paraffins, asphalt or scale.

All these compounds, if not controlled, may cause serious formation damage. The water should be cleaned or filtered before use and a field check should be run using API RP 42 procedures to avoid emulsion problems.

2.2.2 Abqaiq pit brine is a natural brine available in Abqaiq field with

density of about 77.5 pcf. This brine has high concentrations of sulfate and bicarbonate ions. It can be used as a kill fluid to plug and abandon a well and must not be used for preparing any other salt solutions such as KCl or CaCl2 . Any additions of calcium chloride will precipitate sodium chloride, calcium sulfate, and carbonates which will cause plugging downhole.

Note: ABQAIQ PIT BRINE SHOULD NOT BE USED FOR WELL COMPLETION OR ACID STIMULATION OPERATIONS . IT IS NOT CHEMICALLY COMPATIBLE WITH OTHER FLUIDS. IF USED, CALCIUM SULFATE SCALE WILL PRECIPITATE, THE PRODUCING ZONES AROUND THE WELLBORE WILL BE PERMANENTLY DAMAGED AND THE WELL MAY THEN HAVE TO BE PLUGGED AND ABANDONED.

Abqaiq pit brine analysis ( + 77.5 pcf )

Na 69,409 mg/l Cl 154,425 mg/l Ca 480 mg/l SO4 62,790 mg/l Mg 32,000 mg/l HCO3 683 mg/l Sp.gr 1.242 gm / cc pH 7.2

2.2.3 Seawater is frequently used in coastal areas due to its availability. Depending on salinity, it may be necessary to add NaCl or KCl to avoid formation clays or shale swelling. Calcium chloride brines should not be prepared with seawater. Calcium sulfate and carbonate will precipitate downhole and cause plugging.

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Such so-called clear and clean fluids can be most damaging if proper steps are not taken because:

A) They do not contain sized, well-balanced bridging particles, or fluid-loss

additives that will bridge and seal the formation to assure minimal fluid losses.

Properly sized bridging particles minimizes fluid invasion

into permeable formation.

B) They usually contain both dissolved and undissolved solids which can be carried deep within the formation and can damage it beyond economical repair.

C) Sea and bay water contains living microorganisms like bacteria and

plankton, which also acts as plugging material.

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SEM photo for material ( diatoms ) filtered out of seawater.

D) Seawater usually has a high sulfate concentration (2,600 ppm) which can, in the presence of calcium or barium, plug the well with solid calcium and / or barium sulfate for which there is no economically feasible treatment.

E). Many crude oils, when produced, drop out heavy hydrocarbons like

asphaltenes and waxes in myriad of small particles which are easily injected into the formation and cause severe plugging.

F) Freshwater is quite damaging to many formations containing

appreciable clay content such as the Unayzah reservoir.

2.3 Oil and Water Emulsions

Oil and water are incompatible fluids but can be mechanically mixed under high shear to form emulsions where one phase exists as small droplets (dispersed phase) in the other phase (continuous phase). Invert emulsions consist of water droplets in a continuous oil phase (water-in-oil) and normally contain higher volumes of oil. Direct emulsions or true emulsions consist of oil droplets in a continuous water phase (oil-in-water) and normally contain higher volumes of water. The stability of the emulsion can be drastically improved by the addition of chemicals called surfactants (emulsifiers). They have the special ability to concentrate between the oil and water phases and so stabilize the emulsion.

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Surfactant molecule

Water loving group

Oil loving group

Oil-in-water emulsion

Whether an oil-in-water or water-in-oil emulsion is formed depends on the relative solubility of the emulsifier in the two phases. A preferentially water soluble surfactant, such as sodium oleate, will form an oil-in-water emulsion because it lowers the surface tension on the water side of the oil-water interface, and the interface curves towards the side with the greater surface tension, thereby forming an oil droplet enclosed by water. On the other hand, calcium and magnesium oleate are soluble in oil, but not in water, and thus form water-in-oil emulsion.

Stabilization of invert emulsion with surfactant emulsifier

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3.0 CHARACTERISTICS OF FLUIDS ADDITIVES

3.1 Acid Soluble (CaCO3) Weighting Material

Conventional Water base muds (composed of bentonite, barite, caustic soda, soda ash and lignosulfonates..etc.) should never be used except in zones to be abandoned. These muds contain high concentrations of dispersed fine solids and clays that can cause irreversible formation damage. Also, the filtrate of these muds can cause dispersion, movement and swelling of the formation clay minerals. It may also precipitate fine solids in the formation causing further damage. Fluid densities up to 105 pcf can be achieved with finely ground marble (5 - 10 microns).

Typical Physical and chemical constants for sized marble Hardness (Moh's Scale) 3.0 Specific Gravity 2.7 Bulk density, lb/ft3 168.3 Total carbonates (Ca, Mg) 98.0% (Min.) Total impurities (Al2O3, Fe2O3, SiO2, Mn) 2.0 % (Max.)

Also, it is possible to prepare fluids with a maximum density of 120 pcf using iron carbonate. To minimize the high viscosities associated with large solids content, the calcium carbonate should be ground in such a way that 93% will go through a 325 mesh screen. Both calcium carbonate and iron carbonate are soluble in hydrochloric acid ( HCl 15 % ). Calcium carbonate used has a specific gravity of 2.7 g/cc and should be at least 97 % acid soluble ( iron carbonate is only 87 % ). One gallon of HCl 15% dissolves 1.84 lb of calcium carbonate. Iron carbonate will leave residue of 13% solids in the formation after acidizing. These solids may be left to plug the formation or may be flushed out depending on the size and distribution of the formation pore channels. A combination of hydrochloric acid and hydrofluoric acids ( HF or mud acid ) should not be used with calcium or iron carbonate. The hydrofluoric acid reacts with the calcium and iron to precipitate insoluble salts. Calcium Carbonate ( ground marble )is locally produced and commonly used in drilling fluid. Ground Limestone is not suitable for this application, it breaks and become paste like which causes settling, etc.

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3.2 Characteristics of Polymers

The most suitable viscosifiers for non-damaging completion and workover fluids are the XC-polymer (xanthan gum) and the HEC (hydroxy ethyl cellulose). These polymers are effective in salt brines and the thickening action can be stabilized at temperatures as high as 275°F. Other viscosifiers such as bentonite, polyacrylamide and guar gum are not degradable and should not be used. When choosing a viscosifier, one must be careful to determine the product generic name or chemical composition and whether it is degradable or not. Some polymers should not come in contact with reservoir rocks. In most applications of these systems, it is necessary to add polymers to control filtration and to provide carrying capacity and suspension. After examining the characteristics of all available polymers, the industry chosen polymers to be used are HEC, XC-Polymer and Modified Starch. In applications where a high carrying capacity is required, suspending properties (gel strength) can be only achieved with XC-Polymer xanthan gum). Also, it should be kept in mind that for stabilizing the suspension and minimize settling at high temperature, MgO (magnesium oxide) should be used. It will also provide the proper pH up to 10.

Polymer Type * Viscosity Development

Filtration Control

Suspension Properties

Acid Solubility Brine Tolerance

HEC HEMC CMC XC-Polymer Drispac Starch Guar gum Polyacrylate

NI NI A A A NI NI A

Excellent Excellent

Good Fair Poor Poor

Excellent Poor

Poor Poor Good Poor Good Good Poor Good

Poor Poor Fair

Excellent Poor Poor Poor poor

Excellent

Good Poor Good Poor Poor Fair

Insoluble

Excellent Excellent

Poor Fair Poor Good Good Poor

NI Non lonic A Anionic

Characteristics of water soluble polymers used for viscosity, suspension and filtration control

3.3 Viscosity and Suspension

It is necessary to assure that solids are suspended in the fluid. Suspended solids should not rapidly separate from the fluid when circulation is stopped. Or, we may desire that suspended solids remain suspended in surface tankage for some period of time. Calcium carbonate "fine" should have particles in the range of 0.1 - 10 microns which is fine enough to remain in suspension by imparting gel strength to the well fluid. In drilling fluids, gel

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strength is derived from the interaction of clay particles. In workover fluids gel strength is usually provided by XC-polymer (NOT HEC). A gel strength of only 2 to 4 lb/100 ft² is sufficient to suspend the barite used in drilling muds. More gel strength is required to suspend larger particles or denser particles. If the suspending fluid has no gel strength and suspended particles are above colloid dimensions, then the particles will settle out with time. Particle settling can be drastically slowed, but not eliminated by providing the fluid with increased viscosity. This is usually accomplished in well fluids by adding XC-polymer to the fluid. When gel strength is used to give particle suspending properties to a fluid, one must be concerned not only with the ability of the resulting gel to suspend solids, but also with the pressures required to reinitiate fluid flow. Depending on the location of gelled fluid within the tubulars, undesirable pressure may develop at the surface or bottomhole before the gel breaks and flow is reinitiated. The gel strength determines the pressure required to break circulation.

For example, consider the removal of a gelled packer fluid from an annulus. A concern in this case might be whether or not exposed formation will be fractured before circulation is broken and packer fluid removal begun. In this case, if a 0.57 psi/ft packer fluid with a gel strength of 50 lb/100ft² were to be circulated from a 31/2" x 7" annulus with a 0.54 psi/ft workover fluid in a 10,000 ft well, the pressure required to break circulation would be 840 psi. The 840 psi increase in the surface pressure will be reflected by a similar increase in the overbalance at the perforations. Such an increase may not be tolerable. Circulating fluids are those working fluids used to move things around within a well. These fluids may be required to transport solids into or, more typically, out of the well. They may be required to suspend solids for various lengths of time when circulation ceases. They may also be required to displace treating fluids to the formation and in some cases to over displace the treatment fluids out into the formation. Excessive loss of the circulating fluid to the formation often can not be tolerated. In a workover involving solids transport or washing operations, the workover fluid should be able to carry solids to the surface. In this application, viscosity is the most important fluid property. As the viscosity of the fluid increases, the carrying capacity increases. Brines with viscosifiers added, muds, foam, and gas are the most common fluids used for these clean-up operations. Foam or gas may be used to provide lifting capability for workover or completion fluids, sand, and small cuttings.

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There are three main factors which determine the magnitude of effective viscosity required for solids transport in washing operations. These factors are ?? Well temperature ?? Size and weight of solids to be transported ?? Shear conditions (flow rates and tubular dimensions) in the tubing or

annulus in which the solids are to be transported.

3.3.1 The viscosity decreases more-or-less exponentially as temperature increases. To be conservative it is appropriate to design using the maximum expected circulating temperature thereby providing more than sufficient viscosity for transport at all other temperatures. The fluid temperature profile in a well depends upon wellbore geometry, flow rate. flow direction, elapsed time and geothermal gradient. Accurate estimation of the flowing temperature profile requires a computer simulator. On the basis of such simulations we can generalize as follows:

During circulation the maximum temperature occurs somewhere between 213°F and 250°F. The maximum temperature is lower at high flow rates and higher at low flow rates approaching the geothermal profile as flow ceases. The maximum temperature is always less than the static bottomhole temperature and always greater than the return fluid temperature.

3.3.2 The second factor affecting the desired viscosity of a fluid is the nature of the solids to be transported. As a rule, a higher viscosity is required to transport larger and heavier particles. For example, removing cuttings from milling out a packer will require a viscosity greater than that required to wash sand from the well.

3.3.3 The third factor effecting the desired viscosity is the shear conditions to which the fluid is exposed. The shear rate is determined by the fluid flow rate and wellbore geometry at the point of interest. Shear conditions have an effect similar to the effect of temperature on the fluid viscosity. Most polymer viscosifiers, which are added to brines to increase viscosity, are shear thinning (i.e., their viscosity drops as shear increases). The shear rate through the tubing is significantly greater than shear rate through the tubing casing annulus. Depending on the type of operation, method of fluid circulation, and other well conditions, the shear rate may be lesser or greater.

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Typical shear rate ranges include:

Tanks, Pits 0 - 5 sec–1

Annulus 10 - 500 sec–1 Tubing, Workstring 100 - 3000 sec–1

The relationship between these three factors will determine the range of viscosities that may be achieved with a particular fluid, and the desired concentration of polymer required to achieve a particular viscosity. The effect of particle size on required viscosity is illustrated in the following table:

Particle size

Circul. rate

( BPM)

Fluid density ( pcf )

Tubing

( inch )

Casing

( inch )

Required viscosity (cp)

40 mesh 5 67.3 3.5 Tubing 0.25 40 mesh 5 67.3 3.5 7" annul. 0.7 20 mesh 5 67.3 3.5 Tubing 1.0 20 mesh 5 67.3 3.5 7" annul 2.8 10 mesh 5 67.3 3.5 Tubing 5.8 10 mesh 5 67.3 3.5 7" annul 16

1 cm 5 67.3 3.5 Tubing 150 1 cm 5 67.3 3.5 7" annul 400

Forty mesh sand may be circulated or reverse circulated using a fluid with a viscosity of 0.7 cp or 0.2 cp respectively. This viscosity is less than or equal to the viscosity of water at well temperatures. On the other hand, viscosity somewhat greater than the viscosity of water at well temperatures is required to wash twenty mesh sand. Typically, in this case the viscosity would be raised to 10 cp as a safety margin to compensate for temperature effects and possible shut-downs. Ten mesh sand requires still greater viscosity and large cuttings require a substantial increase in viscosity. The effect of flow rate on the required viscosity is illustrated in the following table:

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Particle size

Circul. rate

( BPM)

Fluid density ( pcf )

Tubing

( inch )

Casing

( inch )

Required viscosity

( cp )

10 mesh ( 2 mm )

1 67.3 3.5 Tubing 29

10 mesh ( 2 mm )

1 67.3 3.5 7" annul. 80

1 cm 1 67.3 3.5 Tubing 750 1 cm 1 67.3 3.5 7" annul 2000 1 cm 5 67.3 3.5 Tubing 150 1 cm 5 67.3 3.5 7" annul 400 1 cm 10 67.3 3.5 Tubing 75 1 cm 10 67.3 3.5 7" annul 200

Larger sand particles (10 mesh = 2 mm) may be reverse circulated from the well at 1 BPM with a 20 cp fluid and circulated from the well with an 80 cp fluid. At the same flow rate particles of 5 times the diameter require 750 cp and 2000 cp viscosity fluids to be removed by reverse and direct circulation respectively. Increasing the circulation rate decreases the required viscosity proportionately.

4.0 SELECTING A COMPLETION FLUID

Some conditions must be satisfied when making a completion fluid selection from all available systems. The fluid must have the necessary density required to control the subsurface pressure. This may narrow the choice considerably. If a non-solids or solids-free fluid is to be used, density limitations before precipitation of the solute will dictate limitation of a particular fluid. For example, if sodium chloride is the solids-free system of choice, then 75 pcf would be the density limit. If a higher density is needed, then calcium chloride can be used to a limit of 86 pcf. After inspecting what fluid would fit the hydrostatic head requirement, a cost comparison should be made. Overall cost, however, should be included at this point, not just the cost per bbl.

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4.1 Solids -Free High Density Fluids

Solids-free brines can have densities ranging from 62.4 to 143.6 pcf .

Saturated Brine Density pcf

NaCl 75 KCl 72 NaBr 95 NaCl / NaBr2 95 NaCl / CaCl2 83 CaCl2 87 CaBr2 106 CaCl2 / CaBr2 113 CaCl2 / CaBr2 / ZnBr2 144 CaBr2 / ZnBr2 151

Comparative Densities of Solids-Free Completion & Workover brines in Pounds Per ft³

Brines used in completion and workover applications may be a single-salt brine, two-salt brine, or a brine blend containing three different salt compounds.

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4.1.1 Single Salt Brines are those made with clean fresh water and one water soluble salt such as potassium chloride, sodium chloride and calcium chloride. They are the simplest brines used in completion and workover fluids. Because they contain only one salt, their initial composition is easily understood. Their density is adjusted by adding either salt or water.

4.1.2 Two salt brines are made with combination of two salts in fresh

water. They required accurate measurement of the starting volume of water and the quantities of salts required for the specific density. Excess salt will precipitate the less soluble salt.

4.1.3 Three salt blends are made with a combination of three salts in fresh

water. They require a specialist to blend in the field due to the complex nature of the blends and several tests required during the preparation of these blends. CaCl2 / CaBr2 / ZnBr2 are example of these blends . These blends are not used in Saudi Aramco wells and will not be discussed in this presentation.

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4.2 Sodium Chloride Brines The most commonly used brine in the oil field is sodium chloride (NaCl). The maximum density of a sodium chloride brine is 74.5 pcf at 60°F. The preparation of brines up to 73 pcf is fairly easy. From 73 pcf to 74.5 pcf , additional sodium chloride dissolves very slowly. Corrosion rates are fairly low for the saturated brine ( 74.5 pcf ) and high for the lower density brines. Corrosion inhibitor is required for NaCl saturated packer fluids. Material requirements for NaCl brines are provided in the formulation charts.

Brine Density To Make 1 bbl ( 42 gal ) at 70 ºF Water 100% NaCl

pcf bbl lb 62.8 0.998 4

63.6 0.993 9 64.3 0.986 16

65.1 0.981 22

65.8 0.976 28

66.6 0.969 35

67.3 0.962 41

68.1 0.955 47

68.8 0.948 54 69.6 0.94 61

70.3 0.933 68

71.1 0.926 74

71.8 0.919 81

72.6 0.91 88

73.3 0.902 98.7

74 0.895 102

74.8 0.888 109

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The effects of temperature change on NaCl density

lb / ft2 = 7.48 X lb / gal

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4.3 Potassium Chloride Brines

Potassium chloride (KCl) brines are excellent completion fluids for water-sensitive formations where densities over 72.5 pcf are not required. Corrosion rates are reasonably low and can be reduced even more by keeping the pH of the system between 8 and 10 using KOH. Material requirements for preparing KCl brines are given in the formulation charts.

Brine Density To Make 1 bbl ( 42 gal ) at 70 ºF Water 100% KCl

pcf bbl lb 62.8 0.995 4

63.6 0.986 11.6

64.3 0.976 18.9

65.1 0.969 26.1 65.8 0.96 33.4

66.6 0.95 40.7

67.3 0.943 47.9

68.1 0.933 55.2

68.8 0.924 62.4

69.6 0.917 69.7

70.3 0.907 76.9 71.1 0.898 84.2

71.8 0.89 91.5

72.6 0.881

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4.4 Calcium Chloride Brines

Calcium chloride (CaCl2) brines are easily mixed at densities up to 86 pcf. Generally, dry CaCl2 is available in two grades 94-97% and 77-80% pure. A considerable amount of heat is generated when dry CaCl2 is mixed with water. Corrosion rates for CaCl2 brines are approximately the same as for KCl and NaCl brines; i.e., reasonably low in the pH range between 7 and 10. Material requirements for preparing CaCl2 brines are given in the formulation charts.

To Make 1 bbl ( 42 gal )

% by Wt. pcf 95% CaCl2 lb Water bbl Chloride mg/l 0 62.4 0 1 0 1 63 3.72 0.998 6454 2 63.5 7.5 0.995 13,018 3 64 11.35 0.933 19,690 4 64.5 15.26 0.99 26,470 5 65 19.23 0.988 33,360 6 65.5 23.27 0.985 40,358 7 66 27.36 0.981 47,466 8 66.6 31.52 0.978 54,682 9 67.2 35.74 0.975 62,006

10 67.7 40.03 0.97 69,440 11 68.3 44.4 0.967 77,018 12 68.8 48.83 0.964 84,710 13 69.4 53.36 0.96 92,560 14 70 57.95 0.957 100,531 15 70.6 62.62 0.953 108,624 16 71.2 67.35 0.949 116,838 17 71.8 72.16 0.945 125,174 18 72.4 77.03 0.94 133,632 19 73 82.01 0.936 142,272 20 73.7 87.07 0.932 151,040 21 74.3 92.2 0.927 159,936 22 74.9 97.4 0.922 168,960 23 75.5 102.7 0.917 178,112 24 76.1 108 0.912 187,392 25 76.8 113.5 0.907 196,880 26 77.5 119 0.901 206,502

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To Make 1 bbl ( 42 gal )

% by Wt. pcf 95% CaCl2 lb Water bbl Chloride mg/l 27 78.1 124.7 0.896 216,259 28 78.8 130.4 0.89 226,150 29 79.4 136.2 0.884 236,269 30 80 142.1 0.879 246,528 31 80.9 148.1 0.872 256,928 32 81.5 154.2 0.866 267,469 33 82.2 160.3 0.86 278,150 34 82.9 166.6 0.853 288,973 35 83.6 173 0.846 300,048 36 84.3 179.4 0.839 311,270 37 85 186.1 0.832 322,758 38 85.8 192.8 0.825 334,400 39 86.5 199.5 0.817 346,070 40 87.3 206.3 0.809 357,888

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The effects of temperature change on CaCl2 density

lb / ft³ = 7.48 X lb / gal

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4.5 Sodium Chloride/Calcium Chloride Brines

For densities between 75.5 and 83 pcf, a combination of sodium chloride and calcium chloride brine is often satisfactory. The advantage of a combination of the two salts is a lower cost compared to that of a calcium chloride brine of the same weight. The disadvantage is that at each density, the fluid is saturated, and in order to increase the density, the fluid must be diluted with fresh water before additional calcium chloride is added. Any excess salt ( NaCl ) will precipitate and plug the perforations , the pipe etc....

Brine Density To Make 1 bbl ( 42 gal )

at 70 ºF Water 100% NaCl 95% CaCl2 pcf bbl lb lb

75.5 0.887 88 29

76.3 0.875 70 52

77 0.875 54 72

77.8 0.876 41 89

78.5 0.871 32 104

79.3 0.868 25 116

80 0.866 20 126

80.8 0.864 16 135

81.5 0.862 13 144

82.3 0.859 10 151

83 0.854 8 159

Note:

A) It is crucial to accurately measure the starting volume of water needed

and the quantities of salt required for each specific density to avoid precipitating NaCl.

B) Pilot testing with the make up water at the rig site is necessary to adjust

the above concentration or change fluid densities.

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4.6 Field Operations Utilizing Brine

Spot-checks of field operations have revealed that most of the so-called clean fluids used in well killing, completion are dirty enough to cause severe, and often irreparable, formation damage. All fluids used in well servicing operations must be analyzed. Preserved samples should be tested in the laboratory for clarity and compatibility with produced formation fluid samples. A clarity test for purity and compatibility should be carried out and repeated at the wellhead. Such a field test consists of observing the fluids in a clear glass. If the sampled fluid is not crystal clear and solid-free, it should be either filtered or discarded. It is advisable to spot-check the visual test with a Millipore-filtration test for presence of micron-sized particles. The Malvern particle size analyzer is available in the Laboratory Research and Development Center for determining the particle size distribution up to 600 microns. Solids particles capable of plugging the formation are picked up from most types of equipment used in the field. Vacuum trucks, dirty tanks, pump tanks, check valves, swivel joints, and tubular goods are the main sources of contamination. Major contamination comes from iron, mud, cement, pipe dope, oxidized crude, sludge, bacteria, chemical additives, and other materials pumped or produced previously through the system. Tanks used for drilling and cementing will have dried mud, sand, silt, crude oil, and partially set cement deposited in suction lines and mixing boxes, on walls,.. etc. Such sediments and rust do not adversely affect the drilling mud, but when clean fluids are placed in the tanks and agitated, these sediments are entrained. Injected dissolved iron is converted in most formations with oxygen into iron hydroxide, a voluminous floc which helps consolidate the bridged solids (clay and silts) within the pores.

Often less than a teaspoon of such " dirt " can plug a perforation

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5.0 SPECIALLY DESIGNED BRINE/POLYMER SYSTEMS

Another category of water-based fluids is specially designed brine / polymer systems. These systems use polymers as a replacement for bentonite for viscosity, solids suspension, and fluid loss control. These systems are formulated in brine for inhibition using sized particles as bridging material to help control loss of filtrate to the formation.

Brine / polymer system can be divided into three major types:

? Acid soluble systems ? Water soluble systems ? Oil soluble systems.

The basic formulation and technology associated with each of these systems is identical. The major difference between these systems lies in nature of the material used as the bridging agents and/or weighting agents. As the name implies, the bridging material is either acid soluble, water soluble, or oil soluble. The systems are composed primarily of various types of polymers, some type of brine water, and special type solids for bridging and weighting material. The most common brine water used is KCl, NaCl, or CaCl2. Should higher densities be required, special type solids are added to increase the density. This is somewhat of an opposite approach from the use of clear brines, but it should be kept in mind that not all solids are damaging. Good useable solids are either acid soluble, water soluble, or oil soluble, and incompressible.

Special fluids can be designed with solids of known particle size distribution and solubility. Special brine / polymer systems can be separated into two types: non-thixotropic and thixotropic. This categorization is governed by the type of polymer used. Non-thixotropic polymer systems are viscous, but have no gel-building ability. The use of these systems is limited to operations where viscous carrier fluid is needed while circulating. They will not suspend solids when circulation is stopped ( lost circulation pills ) . Thixotropic polymer systems have both viscosity and gel-building ability, offering the advantage of suspending solids when circulation is stopped. Weighted brine / polymer systems must be thixotropic. There are a multitude of polymers available and currently being used in the drilling industry. However, for well servicing fluids, the preferred non-damaging polymers used for viscosity and/or suspension are confined to two types: Hydroxy Ethyl Cellulose (HEC) and Xanthan gums (XC-Polymer).

HEC polymers are nonionic derivatives of the cellulose polymer modified to impart water solubility to the cellulose molecule. The nonionic substitution in HEC polymers makes them very tolerant to high salt environments, including divalent calcium and magnesium. Because of this, HEC is ideal for viscosifying most

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completion brines. HEC polymers do not develop gel strengths to suspend solids. Systems made up with HEC polymers alone are considered nonthixotropic. XC polymer is a slightly anionic, high molecular weight polymer produced by bacterial action on carbohydrates. XC-polymer is an excellent viscosifier and suspending agent for KCl and NaCl brines. It functions quite well in CaCl2 brines as long as the polymer is properly sheared in the initial mix. CaCl2 brine / polymer system should be vigorously agitated in the tanks all the time to prevent the polymer chain from coiling. Solids settling will occur if the CaCl2 brine / polymer slurry remains static for a period of time. XC-polymer is one of a very few polymers which will build gel structure. This, therefore, makes XC- polymer the key ingredient when solids suspension is required. Systems containing XC- polymer are considered thixotropic. HEC and XC-polymer are soluble in 15% hydrochloric acid and normally, the two polymers are used together for optimum performance. The temperature stability of both polymers is limited to the 250-275ºF range. Special additives are available to extend the temperature range to 300ºF.

5.1 Calcium Carbonate Fluids

5.1.1 Fluid Formulations (Example)

Formulation & order of addition Average fluid properties (one barrel) Fresh, clean water, bbl : 0.92 Density, lb/ft³ : 71 Defoamer, gal : 0.01 Plastic viscosity, cp : 12 XC-Polymer, lb : 1.00 Yield point, lb/100 ft² : 15 Modified starch, lb : 3.00 Gels, lb/100 ft² : 2/6 MgO, lb : 0.50 Filtrate, ml/30 min : 8 CaCO3 (fine), lb : 10.00 pH, : 9 Salt ( NaCl ), lb : 75.00 Cl¯, mg/ 130,000

5.1.2 If Low Chlorides is Preferred (Example)

Formulation & order of addition Average fluid properties ( one barrel ) Fresh, clean water, bbl : 0.93 Density, lb/ft³ : 71 Defoamer, gal : 0.01 Plastic viscosity, cp : 25 XC-Polymer lb : 1.00 Yield point, lb/100 ft² : 15 Modified starch, lb : 3.00 Gels, lb/100 ft² : 2/6 MgO, lb : 0.50 Filtrate, ml/30 min : 6 CaCO3 (fine), lb : 75.00 pH, : 9 Cl¯, mg/l < 10000

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5.2 Acid Soluble Bridging Material

Fluid loss control for these special brine / polymer systems is achieved by solids and polymers. The key to sealing off a production zone is a proper mixture of bridging solids, colloidal solids, and subcolloidal particles. This combination creates an impermeable bridge across the face of the production zone ( or as close as possible to the wellbore ) for minimizing the fluid or fluid filtrate invasion into the formation. Coarser particles bridge on the pore spaces around the wellbore. This reduces the porosity and permeability at the wellbore surface. This bridge is then sealed by smaller particles, which plug the fine inter-particle spaces of the bridging solids. The bridge or wall cake allows only a very small amount of liquid to filter into the formation. The colloidal and subcolloidal particles are normally a combination of polymers, modified starches, and calcium carbonate. The formation of tight, impermeable bridges requires some knowledge of the particle size distribution of the bridging solid and the average size of the formation pore opening. Particles which are one-third of the average pore size of the formation will get trapped in the pore and initiate a bridge. Smaller particles will pass through the formation, while larger ones will pack on the surface and not seal properly. The average pore size can be calculated by taking the square root of the permeability (in millidarcies) of the formation. This number is the average pore size in microns. For example, if the formation has a permeability of 100 millidarcies, the average pore size is 10 microns. To seal this formation, the bridging material must then contain a percentage of particles in the 3.5 micron range. Designing a bridging material is a delicate process. Care must be taken to see that this material contains enough different size particles to seal production zones. Should a production zone have an extremely high or extremely low permeability, the bridging material may have to be altered to compensate for the abnormal pore sizes. Do not use just any available material for bridging and expect to get a tight seal on the formation. The most commonly used bridging materials is calcium carbonate ( ground marble ). It is the primary bridging agent in the acid soluble brine / polymer systems. This material is totally soluble in 15% hydrochloric acid. Calcium carbonate is used as a weighting agent in the drilling fluids for all the carbonate reservoirs development wells (Arab"D", Hanifa, Hadriyah etc.). In most cases, the fine grind (average particle size is 10 microns) which is used as weight material will not work as a bridging agent in zones with more than 100 md permeability.

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5.2.1 SAMS/Stock (3300 lbs super bags and 50 lbs bags)

A) Ground marble ( fine - 10 microns ) B) Ground marble ( medium - 150 microns ) C) Ground marble ( coarse - 600 microns ) D) Ground marble ( chips - 2000 microns )

5.2.2 Typical Lost Circulation Pill Formulations

Formulation & order of addition Average fluid properties ( one barrel ) Fresh, clean water, bbl : 0.90 Density, lb/ft³ : 71 Defoamer, gal : 0.01 Plastic viscosity, cp : 25 HEC, lb : 1.5 Yield point, lb/100ft² : 20 XC-Polymer, lb : 0.5 Gels, lb/100 ft² :5/15 Modified starch, lb : 1.00 Filtrate, ml/30 min : 10 Lime, lb : 1.00 pH, : 11 Ground marble M , lb : 80.0 Ground marble C , lb : 40.0

5.2.3 Water Soluble Bridging Material

In brine / polymer systems, it is possible to use sized sodium chloride (NaCl) as bridging particles. However, this can only work in a fluid which is near or already saturated with respect to sodium chloride. Therefore, the minimum mud weight is above 75 pcf. Sizing sodium chloride to the small sizes needed is fairly difficult and should be done in a zero humidity environment. The NaCl bridge will dissolve in undersaturated solutions (or fresh water). usually associated with production. This system is relatively expensive and can be justified for dry gas wells.

5.2.4 Oil Soluble Bridging Material

Oil soluble resins are usually paraffin or waxlike particles used as bridging agents in the brine / polymer systems. Since these resins are oil soluble, they are removed when the well is brought back on oil production. Care should be taken when choosing these resins. It is necessary for the melting point of the resin to be approximately the same as the bottom hole temperature. If the melting point is too low, the resin will dissolve before the bridge is set. If the melting point is too high, the resin will not dissolve in the produced oil and the bridge may not be removed. Strong water wetting surfactant should be

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included in the formulation to disperse the resin and prevent it from floating. The carrier fluid should be a high viscosity water or brine. Any trace of oil or oil contamination of the pill will create a big lump of wax and plug the pipe.

5.2.5 Weighting Agents

The HEC and especially the XC-polymer perform best in lower density brines e.g., saturated NaCl (75 pcf) or CaCl2 (85 pcf). Higher densities for these brine / polymer systems can only be accomplished with the addition of solid weighting agents. This weighting agent must be either water or acid soluble. This eliminates the use of barite, since it is neither. The weighting agent should be ground to specifications which allows easy dispersion and suspension. This grind, however, is not nearly as critical as for bridging agents. Extremely finely ground weighting agents cannot be used because of the high surface area, causing viscosity problems. Sodium chloride is water soluble and calcium carbonate is soluble in 15% hydrochloric acid, if the acid can reach the calcium carbonate dowhole. Systems weighted with sodium chloride or calcium carbonate are workable up to 103 pcf, while systems containing the iron compounds can go as high as 142 pcf .

5.2.6 To Summarize:

Lab and field results strongly suggest that the use of specially designed brine/polymer systems, with properly sized bridging particles, are among the best well servicing fluids. These systems form external bridges on the surface of the borehole and seal off production zones with minimum invasion of fluid. The bridge can be removed by mechanical action or it can be solubilized. These systems are inhibitive, and offer a wide range of densities, lifting capacity, and suspension qualities. Compared to clear brines, polymer systems are economical at higher densities. The formation of a good, tight, external bridge is the key to the success of these fluids. This bridge is especially effective in depleted zones which cannot hold the pressure gradient of water or oil. Specially designed brine/polymer systems can effectively control fluid loss at overbalance pressure. Removal of the external bridge is usually accomplished by flushing or bringing the well back on production. If further clean up is necessary, an acid soluble bridge can be removed with a 15% hydrochloric acid

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wash, a sodium chloride bridge can be removed with a low salinity water wash, and an oil soluble resin bridge with a diesel, crude oil or Xylene wash.

5.2.7 When Mixing Brine/Polymer Fluids Remember:

A) High shear mixing is very important to allow the polymers to

perform and to eliminate fisheyes and polymer lumps which may reach the perforations downhole and cause plugging problems.

B) Foaming is almost always a problem while mixing brine-based

fluids. Defoamers should be available on location. Follow the recommended order of addition in the initial mix, and mix defoamer with any salt or water required for system maintenance. Avoid injecting air into the slurry with mixing hopper, guns and pumps.

C) Corrosion could be excessive, but maintaining the pH with lime

or magnesium oxide, using oxygen scavengers (sodium sulfite) and corrosion inhibitors can control this. Be sure the corrosion inhibitor used is not going to be injected into the payzone. All corrosion inhibitors are damaging to the reservoir.

5.3 Low Density (Oil-In-Water or Brine) Emulsions

For low pressure reservoirs requiring drill-in, completion and workover fluids lighter than water ( 62.4 pcf ), two alternatives are available: ?? Direct emulsions, oil-in-water (using Atlasol-S as the emulsifier) ?? Invert emulsions, water-in-oil (using Invermul and / or Ezmul as the

emulsifiers)

5.3.1 Direct emulsions

Low density direct emulsions are made with water as the continuous phase and dispersed oil ( as fine drops ) which is the internal phase. This emulsion is recommended when formation wettability change to oil-wet is undesirable. The emulsifier used is a water wetting surfactant for maintaining the drilled cuttings and solids water wet allowing easy hole cleaning. Viscosity and suspension are developed with small concentrations of water soluble polymers such as XC-polymer and HEC. It is much cheaper than the invert emulsion and has electrical properties similar to water-based fluids. The water

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phase can contain KCl for inhibiting sensitive clays in the reservoir rock. This emulsion is not chemically stable and require mechanical shear ( good agitation ) to prevent oil separation. Under static conditions and downhole temperature, the emulsion will break after sometime. With a high viscosity external phase ( water ) the emulsion can stay stable for longer periods in the hole. Fine solids such as CaCO3 ( 10 microns ) will stabilize the emulsion and makes a suitable drill-in fluid. Emulsions should never be injected into the reservoir even if they are solids-free. Forcing a thick emulsion into the reservoir will create blockage which will require treatment with mutual solvents, surfactants and / or acids to remove.

Formulation and order of addition Average fluid properties (one barrel ) Make-up water, bbl : 0.50 Density, lb/ft3 : 57 XC-Polymer, lb : 1.00 Plastic viscosity, cp : 18 Dextrid, lb : 6.00 Yield point, lb/100 ft2 : 25 MgO, lb : 1.00 10 sec.gel, lb/100 ft2 : 4 Oil, bbl : 0.50 10 min.gel, lb/100 ft2 : 6 Atlosol-S, gal : 0.10 Filtrate, cc/30 min : 4 CaCO3 fine, lb : 5.00 pH, : 9

Note: Fine mesh shaker screens ( 150 - 200 mesh ) will help to maintain the fluid clean No other chemicals should be used . The pH should be maintained with magnesium oxide or lime and the viscosity with XC-polymer. Dextrid along with the fine CaCO3 will control the filtrate and filter cake. The oil must be added to water through the mixing hopper to form the oil-in-water emulsion followed by Atlosol-S. Additions of more oil will cause thickening and additions of more water will cause thinning.

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5.4 Oil-Based Fluids and Invert Emulsions

Oil-based well servicing fluids are generally a form of invert emulsion, with some type of oil as the external or continuous phase. Crude oils are used occasionally, but their application usually is limited to depleted formations. The use of oil-based fluids offers several advantages. These include:

A) High temperature stability for deep high pressure wells. B) Wide density range up to 157 pcf. C) Maximum inhibition for clays. D) Non-corrosive to the tubular and downhole equipment. E) Stable in most subsurface environments.

Formulation & order of addition Average fluid properties ( one barrel ) Oil, bbl : 0.5 Density, lb/ft3 : . 85 Invermul, lb : 6.0 Viscosity sec/qt : 45 Lime, lb : 4.0 Plastic viscosity, cp : . 25 Duratone, lb : 6.0 Yield point, lb/100ft2 : . 20 Water, bbl : 0.2 Gels, lb/100ft2 : 4/8 GeltoneII, lb : 2.0 Filtrate(200 ºF/500psi) ml 2 all oil EZ-Mul, lb : 2.0 Electrical stability, volts : 800 CaCl2(78%), lb : 61.0 Oil/Water ratio : 70/30 CaCO3 fine, lb : 113.0

Invert emulsions originally were developed as drilling fluids, specifically for use in deep, hot holes. The oil-based fluids can be designed for working temperatures in excess of 500°F and densities from 56 to 157 pcf. Since oil is the external phase, the fluid invading the formation will be all oil which should have no effect on the clays in the formation. This minimizes the concern for clay migration or clay swelling. These fluids are non-corrosive and resistant to most contaminants which affect water-base fluids. Formation damage studies with various oil-base fluids consistently show minimal damaging characteristics. Oil-base fluids approach being the ideal well servicing fluid. They do, however, have some disadvantages including that they may:

? be restricted in environmentally sensitive areas. ? contain high solids and damage dry gas sand payzones. ? will change the formation wettability and cause emulsion blocks.

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Stricter environmental regulations are making it difficult to use oil-base fluids without the use of expensive handling equipment and high disposal costs. This is especially true offshore. Higher density oil muds contain a high percentage of solids. The majority of these solids are incompressible, but the fluid could contain a certain percentage of compressible solids, such as organophilic clays or drilled solids. Oil-base fluids contain oil wetting surfactants designed to make the solids dispersed in them preferentially oil wet. These wetting agents could cause the formation to become preferentially oil wet, lowering the relative permeability to oil. Should this occur, the condition is usually temporary. The emulsifiers in the oil-base fluids could form emulsions in the formation, causing emulsion blocks. Mutual solvents and water wetting surfactants will remove the damage and restore productivity. ( Zuluf, Marjan and Safaniyah horizontal wells is a good example ). Exposure of a formation containing only gas and water to an oil-base fluid can result in a reduction of the relative permeability to gas by the introduction of a third immiscible fluid. Oil filtrate invasion will occur. When gas production begins, some of the oil filtrate will back flow and clean up, but some of the filtrate will remain as irreducible or immobile, hence lowering the gas productivity of the well.

5.5 Air / Mist / Foam

The use of dry air, mist, stiff foam, or aerated mud as the circulating fluid is rarely used. Dry air or dust drilling is used when the formation is completely dry or when there is only a slight water influx. Air is ideal to reduce formation damage. Since there is no liquid phase, there is no fluid loss and no invasion of particles. The use of foam as a well servicing fluid should be considered with low bottom hole pressure wells.

6.0 PACKER FLUIDS

6.1 Functions:

The primary function of a packer is to seal off the tubing-casing annulus, and allow production from below the packer, through the tubing. Packer fluids are placed in the casing-tubing annulus to provide a hydrostatic head necessary to control the well in case of packer failure or leaks. Also, to reduce the pressure differential between the inside of tubing and the annulus, the outside of the casing and the annulus, and the perforated interval below the packer and the annulus. The packer fluid performs these functions mainly by protecting the steel in the tubing-casing annulus from corrosion. Since the packer may remain in the annulus for an extended period of time, it is

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necessary to properly inhibit the fluid to prevent or minimize annular corrosion and enhance retrievability of tubing and packers. A worldwide review of workover operations indicated extremely high costs associated with recovery of tubing stuck in settled mud solids. High density water-base or oil-base muds are not stable suspensions when left static in a well for a long time. High temperatures and/or contamination of these muds with the produced gas and oil destroys the initial suspension properties and allow mud solids and weighting materials to settle on top of the packer and around the tubing. Expensive washover and fishing operations are then performed. During the washover, more costly complications such as twist off, stuck washover pipes, casing leaks, blowouts and formation damage could develop. When such complications occur many wells have to be plugged and abandoned. Most of these problems could be eliminated by utilizing solids-free packer fluids.

6.2 Characteristics of Packer Fluid:

? Must be chemically and mechanically stable under downhole conditions,

i.e. no settling of suspended solids and no chemical precipitates if mixed with produced fluids or gases.

? Must not degrade by time or temperature. ? Must not deteriorate packer elastomers. ? Must remain pumpable during the life of the well, i.e. no high gelation or

solidification to be developed by time. ? Must not cause corrosion (inside casing, outside tubing). ? Must not damage the producing formation because they may contact

these producing zones during completion or workover operations.

6.3 Fluid Properties:

? The usual practice is to use a packer fluid with kill density. The packer fluid must contribute to well control during the seating and unseating of the packer.

? A packer fluid should ideally be solids-free. If a packer fluid must be

weighted with solid materials, they should not settle out over the period of fluid use. Solids-weighted packer fluids must have gel strength to prevent the solids from settling.

? The gel strength should not be so great as to prevent initiation of

circulation or tubing movement should a workover become necessary. If solids do segregate out and fall to the bottom, a retrievable packer or the tubing may get stuck, resulting in a long and expensive fishing job.

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6.4 Drilling Mud (Not A Desirable) Packer Fluid

Water base drilling mud organic additives degrade upon prolonged exposure to high temperatures and sometimes generate corrosive gases such as CO2 and H2S. Bacterial activity could also breakdown organic materials and/or produce corrosive elements. Lignosulfonate solutions can react electrochemically at metal surfaces to form sulfides even at moderate temperatures. Properly formulated oil-base muds are non-conductive and should not cause corrosion. However, in case of packer failure or leaks, produced oil or gas dissolves in the oil mud, destroys their suspension properties, allowing the weighting material (barite) to settle on top of the packer, and results in stuck packers and tubing.

6.5 Solids - Free Oil As A Packer Fluid

Clean oil with proper corrosion inhibitor ( oil soluble film forming amine ) is an ideal packer fluid. Clean oil is non-conductive, stable and in case of casing leaks and water influx, the inhibitor will provide protection for some time.

6.6 Solids - Free Packer Fluids

The obvious advantages of utilizing solids-free heavy brines for packer fluid applications triggered extensive investigation into combating their corrositivity via the addition of suitable inhibitors. Increasing the pH, removing the oxygen and selecting the compatible brine or brine blends along with the effective inhibitor for the anticipated environment are very important steps in formulating the proper brine packer fluid.

6.7 NaCl Brines

In the presence of entrained oxygen, sodium chloride can be major contributor to corrosion. The activity of the electrolyte is accelerated by the dissolved salt. When the salt concentration exceeds 12%, the corrosion rate decreases below that of water.

6.8 CaCl2 Brines

In laboratory tests, it was demonstrated that the corrosion rate increases dramatically with an increase in temperature. CaCl2 at 250ºF has a rate of 5 mpy but at 400ºF increases to 55 mpy. However, these high rates will decrease with longer exposure time. This phenomenon indicates the consumption of the active corroding elements in the brine.

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6.9 Important Points To Remember

6.9.1 Based on the laboratory observations, the thirty days static test is a sufficient test period to determine the long term corrosivity of the inhibited brines.

6.9.2 Commonly used film forming amine corrosion inhibitors degrade

between 250ºF and 300ºF and therefore are ineffective for high temperature wells. Also many film forming amines are insoluble in heavy brines.

6.9.3 Calcium brines should not be treated with oxygen scavengers

containing sulfites. These types of chemicals could precipitate calcium scale and have caused stuck packers on several occasions.

6.9.4 In the field, drilling mud should be properly displaced from the

wellbore with the clean brine. Residual mud materials in the annulus must be cleaned out mechanically and chemically (scraper, surfactants...etc.). Mud residue adhering to the metal surfaces can be sites for under deposit corrosion. The brine should be filtered, solids content less than 100 mg/l achieved in the field.

6.9.5 If CO2 ingress into the annulus is expected, low calcium or a calcium

free brine should be considered to minimize chances of precipitating calcium scale. As a rule in CO2 environment, use KCl, NaCl, and NaBr for brine densities up to 92 pcf.

6.9.6 Fluids of low inherent corrosivity are generally hydrocarbon based.

The low electrical conductivity of these fluids suppresses corrosion currents. In low pressure wells the hydrocarbon may be diesel or lease crude. Oil-base or invert-emulsion mud may be used in higher pressure wells. The clay dispersants and emulsifiers in oil muds keep water emulsified and metal surfaces oil wetted, thus, further minimizing conductivity and corrosivity. Both oil soluble and brine dispersible corrosion inhibitors are sometimes added to hydrocarbons to insure corrosion protection when inefficient displacement of water-base mud or brine is anticipated.

6.9.7 Corrosion inhibitors may be added to electrically conductive fluids to

reduce the corrosion rate. Typically, corrosion inhibiting agents function by scavenging oxygen, electrostatically passivating the metal surface, or, more commonly by forming a hydrophobic film on the metal surface that prevents the entrance of corrosion currents into the surface. Corrosion inhibitors function well in brines. Film forming

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corrosion inhibitors do not provide much protection in water-base muds since they tend to adsorb strongly on the mud solids. Bactericides act as corrosion inhibitors by killing bacteria that generate corrosive by-products.

6.9.8 Control of pH is the primary method of reducing corrosion in water-

base muds. When a brine can tolerate a high pH, elevated pH can also control corrosion in brines. High pH controls sweet and sour corrosion by preventing the oxidation of iron by hydrogen ions and by preventing the growth of sulfate reducing bacteria. A pH greater than 9.5 significantly reduces corrosion of iron. Water-base mud pH should be adjusted to a stable value between 10.5 and 11.5 prior to installation of the mud as a packer fluid. The pH of the mud should remain unchanged following circulation for 48 hours before it is considered stabilized. This is necessary because mud components tend to reduce the mud pH with time.

6.10 Corrosion Inhibitors

A water soluble corrosion inhibitor, such as Coat B1400 (or equivalent film forming amin) for solids - free brines provides excellent protection under subsurface conditions. A concentration of 1 % by volume is generally recommended when saltwater is used as a packer fluid or will be left in the wellbore for extended periods of time. Corrosion inhibitor is not usually necessary for salt waters that will be circulated out of the well after completion or workover operations are finished. Most corrosion failures attributable to packer fluids are observed to occur below circulating valves and between packers in multiple completions and in other areas from which mud and fluids are not removed by normal circulating methods. When such possibilities exist, only inhibited fluids should be used. For clean oil packer fluid, Coat 415, an oil-soluble film forming amine is recommended to provide corrosion protection in Arab"D' wells. In case of casing leaks across the Wasia, the inhibitor should give some protection. Lab tests are currently being conducted to determine the optimum concentration required. The use of 3% by volume should continue until the lab study is completed. Contamination of the clear packer fluid to be used or left in a well can be lessened by displacing the drilling fluid with clear untreated fluid, discarding the returned interface between the fluids, and then circulating the clear fluid again after the addition of required corrosion inhibitor and biocide additives. Wastage of corrosion inhibiting chemicals is avoided by delaying their addition until after the first purge of the well with clear fluid.

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Packer fluids which contain water can support the growth of bacteria. Bacterial life processes often generate corrosive by-products and bacterial bodies can plug and damage formation rock. A bactericide should be added to packer fluids to prevent the growth of bacteria. Increasing the fluid salinity to saturation and the pH to 10.5 - 11 will prevent growth of bacteria. The common bactericides used for packer fluid systems contain paraformaldehyde. Bacteria can cause sulfide corrosion in the absence of oxygen (anaerobic conditions). Anaerobic bacteria are able to use hydrogen formed by electrochemical corrosion to reduce sulfate ions, forming hydrogen sulfide. This anaerobic process accelerates the electrochemical corrosion, and the resulting hydrogen sulfide also attacks the steel, forming black iron sulfide scale and pitting corrosion. lron sulfide scale has caused plugging in injection wells. The hydrogen sulfide formed can cause tubular goods to fail through sulfide-stress-cracking/hydrogen-embrittlement under certain conditions. If untreated packer fluids come in contact with the formation, the bacteria may damage the formation (Biofouling). This can occur following a period of bacterial colony growth if the packer fluid is subsequently used as a workover fluid, or if the packer fails and the fluid leaks into the producing tone.

7.0 HANDLING COMPLETION FLUIDS

The proper handling of well servicing fluids is important to the overall success of the operation and the safety of the rig personnel. The objective is to safely handle all fluids while maintaining the volume, density, and clarity or cleanliness of the fluid to control formation damage

7.1 Transportation (Trucks And Boat Hold Tanks)

The key to all successful completion fluid applications is that the fluids are maintained clean and contain no particulate matter considered damaging to the formation. If handling and mixing equipment are not clean, then the expense and effort used to secure clean, uncontaminated fluid or brine are wasted. Visually inspect each tank before any fluid is mixed. Tanks that are not clean or have any water or other liquid in the bottom must be cleaned and dried. lnspect the hoses on the water truck to make sure that they are clean. Boat hold tanks must be visually inspected before any fluid or brine is pumped on board. If the tanks are dirty, they must be scrubbed clean and dried. If this cannot be done, they must be rejected. Tank hatches must be resealed and

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the hatch-to-tank gasket area should be caulked to help prevent fluid contamination should the deck become awash. Be sure that the boat crew knows not to pump into or out of the fluid tanks when the boat is underway. Other tanks must be used to even the keel.

7.2 Rig Preparation

One of the most important, but least acknowledged, aspects of using clean completion fluids or brines is the preparation of the rig before taking or mixing the fluid into the pits. Most muds are not compatible with brines. Every piece of equipment that will come into contact with the clean completion fluid must be meticulously cleaned of muds and other additives. Pits, lines, and valves that have leaks must be repaired to eliminate loss of expensive brines. Small pinhole leaks that are plugged by a drilling mud will not be plugged with the brine. The following recommendations are guidelines for preparing a rig to use clean fluids:

? Isolate all tanks, pumps, and equipment that will be used to carry or

transport the clean fluid or the solids-free brine. ? Scrub all tanks, circulate detergents and/or surfactants through the

entire system to remove contaminants. Rinse the system with water and dump the water until it is clean. While the water is circulating, check for leaks.- remove any additives or other materials in the mixing areas and store them at some other location.

? Cover all the open pits if rain is expected and keep sack materials dry. ? Store brine in closed tanks to help prevent moisture from being drawn

into the brine and lowering the density.

7.3 Clear Brines

The high cost of brines makes it imperative that inspections be accomplished in order to ensure the fluid being mixed is the correct volume, density and clarity. The initial inspection should be performed at the mixing tanks. Subsequent inspections should be performed whenever brines are transferred from tanks or vessels.

?? Check the Volume, this can be done by a flow meter when transferring

or by simply checking the tank. Although this may seem simple, costly errors may be made.

?? Check the Density, the density must be checked with hydrometer .

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?? Check the Clarity, the clarity of the brine should always be checked when the brine is transferred or mixed to ensure that it did not pick up any contaminants.

Samples can be sent to the lab for atomic absorption test to determine the quantity of cations. Anion chromatography will determine the quantity of anions. Total suspended solids and particle size distribution can be also measured. Testing on site can be arranged specially if fluid filtration is required for water injection tests or gravel packing etc...

7.4 Fluid Maintenance

7.4.1 A solids-free system appears to result in less formation damage and

higher productivity. The continued care and maintenance of the fluid in the system is critical during well servicing operations. The following steps should be followed:

A) Mixing and storage tanks should be thoroughly cleaned and

visually inspected before each use. All lines and pumps should be cleaned and inspected.

B) The drilling mud in the casing should always be displaced with a clean, preferably filtered well servicing fluid.

C) The wellbore should be cleaned to remove as much of the drill solids from casing walls and fluid system as possible. Over-displacement with water is the recommended practice. A spacer of at least 500 feet weighted to the necessary density should be used when displacing mud.

D) All tanks should have bottom baffles in order to contain settlings. E) Tank agitators should never be used if clear ,solids free fluid is

being used.. Tanks should be checked often for settlings and should be cleaned when needed.

F) A mud cleaner with a 325 mesh screen can be used to remove solids larger than 44 microns. The brine can then be filtered through 2 micron filters.

G) Tubular goods should be free of rust, scale, and pipe dope. H) An oxygen scavenger or corrosion inhibitor should be added if

necessary to help prevent the formation of iron oxide particles.

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7.5 Displacement Techniques

The proper displacement technique has a dramatic impact on the operation. However, the basic displacement format remains the same, regardless of all other conditions. It is a simple two-step formula: A) Condition the mud before displacing it. B) Displace the mud.

7.6 Conditioning Mud

The actual conditioning of the mud must be done before the mud is removed from the well. This phase is the key factor that determines how clean the well will be after displacement. The purpose of mud conditioning is to disperse and evenly distribute all of the solids from the casing inner walls, the wellbore, tanks, pipes, etc., into the mud. The rheology of the mud is then adjusted to make it flow more easily during displacement. The mud is conditioned using both mechanical and chemical methods. The first step to distribute the solids in the well is, obviously, to circulate the mud in the hole. If the mud has remained in fairly good condition, it will circulate easily and evenly distribute the solids. If the solids have packed at the bottom of the well or annulus, they will have to be washed over or drilled to be dispersed into the mud. The second step is to remove the wall cake. Once the mud can be circulated and the bottom of the hole or the required depth is reached, the mud cake must be removed from the walls. Mechanical scrapers have proven to be the most effective tools to remove these solids from the casing wall. A scraper run should be made for each casing diameter. Circulate the mud through all available solids removal equipment to remove as many solids contaminants as possible. Rotating the workstring will improve the removal of solids from the wellbore while circulating the mud. Most wells are not true vertical holes and some corkscrewing of the hole is assured as the well is drilled. The workstring will lie against the low side of the casing / liner wall at various points. Fluid flow is restricted or virtually nonexistent at these points and solids will collect unless the workstring is rotated. Rotation of the workstring distributes the fluid flow path across the entire hole section. Once the solids are evenly dispersed throughout the mud system, the mud rheology can be adjusted. Thin the mud as much as possible while it still retains its ability to hold the solids in suspension. Usually, adding water to a water-base mud or oil to an oil-base mud is all that is required. Do not use packaged thinners or build density unless well conditions require this.

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7.7 Displacing Mud

After the mud is conditioned a displacement pad to separate the mud from the brine can be as simple as single viscous spacer or as complex as several different pills, each designed to perform one specific function. Let's briefly look at the intended functions of these pills.

7.8 Displacement of Pads/Spacers.

Spacers may be solids free or solids-laden. Their sole function is to separate two incompatible fluids. To do this, the spacer must be more viscous than either of the fluids it separates. The greater viscosity helps to retain the integrity of the spacer by enabling the spacer to stay in plug or laminar flow at higher pump rates than the other fluids. However, some intermingling with the other fluids is probable. Therefore, the spacer must also provide enough distance between the two other incompatible fluids to keep them from contact each other. Each spacer should cover at least 500 feet of the annulus at its largest diameter.

7.9 Chemical Washes

Chemical washes provide a polishing action to remove those solids that remain in the well. These washes usually have a combination of surfactants that remove organic contaminants as well as inorganic contaminants. Coarse materials such as 60/80 frac sand or coarse CaCO3 can be added as scouring agents.

7.10 Special Techniques

A) Water Flushes: When well conditions permit, the mud can be displaced

and the well cleaned by circulating water downhole. This technique has certain restrictions. You must be able to answer "yes" to all of the following questions to successfully use a water flush. ?? Is water readily available and inexpensive ? ?? Is the wellbore isolated from the casing? ?? Will the casing, tubing, and cement bonds withstand the difference

in pressure between the formation pressure and the hydrostatic head of the water?

?? Can the water and some of the mud be easily, inexpensively, and safely disposed of ?

If the answer to all of these questions is yes, the well can be flushed with water. A water flush cleans the well better than any other method.

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Rig time is the greatest cost factor. The chemical cost is essentially nothing. A viscous pill such as 50 barrels of HEC-seawater with a viscosity of 150-200 sec/qt should separate the water and the mud if the mud is to be saved. Another viscous pill should separate the water and the brine when the water is displaced.

B) Reverse Circulation: The density of the brine and the density of the fluid that it is displacing will determine the flow path of the fluid during displacement. The fluid should be pumped down the annulus and up the tubing or wash pipe when the brine is lighter than the fluid that is being displaced. The reason for this flow direction follows. Under static conditions, heavier fluids will sink through lighter fluids due to the force of gravity. Even though a spacer may separate the two fluids, commingling of the fluids can occur. When the fluids are pumped down the annulus, the heavier fluid must be below the lighter weight fluid to help prevent commingling. Commingling may occur in the tubing, but this poses little problem to keeping the annulus clean. Conversely, the flow direction should be down the tubing and up the annulus when the brine is heavier than the fluid it is replacing. Pressure drop values should be calculated and compared to tubing burst strengths before a final decision is made.

7.11 Staging Spacer Densities:

The densities of each spacer should be gradually adjusted. If more than one spacer is used in line between two fluids of dissimilar weight, use the spacer with the recommended highest density for the spacer that is next to the heaviest fluid, and adjust to the lowest density for the spacer that is next to the lightest fluid. For example, when three spacers are used in line to displace a 100 pcf mud with an 80 pcf brine, each spacer should be adjusted to a different density. The spacer next to the 100 pcf mud should weight slightly less than 100 pcf. The middle spacer should be in the neighborhood of 90 pcf and the spacer next to the 80 pcf brine should be between 80 and 90 pcf. The reasoning is the same as that used on determining the best flow direction. A lighter weight fluid should be above the heavier fluid in the annulus to help prevent or retard commingling.

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7.11 General Displacement Procedures

A general procedure to displace the drilling mud with a well servicing fluid is usually performed when a bit and scrapper, properly sized for the casing, is run in the hole on a workstring to PBTD. Four displacement procedures are listed below as a general guideline for a displacement system. The specific displacement procedure must be adjusted to fit individual well requirements.

7.13 Displacement of Water-Based Mud Using Seawater Flush

This following general procedures for the displacement of a water base mud using a seawater flush is intended to highlight relevant points and state some recommended practices.

A) Circulate and condition the mud to obtain the minimum acceptable yield

point before the displacement. B) Displace the water base mud with a viscous HEC/seawater spacer

between the mud and the seawater. This spacer should have a funnel viscosity of 150-200 sec/qt. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. Circulate the seawater until contaminants are less than 50 Nephelometer, Turbidity Units (NTU)

C) Add a chemical wash and circulate two workstring volumes. D) .Add another viscous HEC/seawater spacer between the seawater and

the brine. The funnel viscosity should be 150-200 sec/qt and the spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter.

E) Follow with clean filtered brine. F) Filter the brine to a turbidity of 50 NTU.

7.14 Displacement of Oil - Based Mud Using Seawater Flush

This general procedure for the displacement of an oil base mud using a seawater flush is intended to highlight relevant points and state some recommended practices. Notice that oil-base systems using highly aromatic oils will leave an oil sheen on the seawater.

A) Condition the mud before the displacement. B) Displace the oil-base mud with an oil pad. The volume should be +500

feet of the annulus at its widest diameter. C) Follow the pad with a viscous HEC/seawater spacer between the oil

pad and the seawater. The spacer should have a funnel viscosity of 200-250 sec/qt. The spacer volume is usually equal to about 500 feet of workstring annulus at its widest diameter.

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D) Circulate the seawater until the seawater has less than 50 NTU of solids. Circulate continuously or once through, depending upon pollution control requirements.

E) Add a chemical wash for oil mud and circulate two full workstring volumes.

F) Add a viscous HEC/brine spacer between the seawater and the brine. The funnel

G) viscosity should be 150-200 sec/qt and the spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter.

H) Displace with a clean filtered brine. I) Filter the brine to a turbidity of 50 NTU.

7.15 Balanced Displacement of Water-Based Muds

This following general procedure for the balanced displacement of a water base mud without using a water flush is intended to highlight relevant points and state some recommended practices.

A) Condition the mud before displacement. B) Displace the water base mud with a single pass down hole of the

following spacers:

Spacer 1 This spacer must be compatible with the drilling mud and must have a yield point greater than that of the drilling mud. The spacer should be pumped at a high enough rate so it remains in turbulent flow. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. This spacer should be displaced with weighted brine at least equal to the volume of the spacer. Note the brine following the spacer will be very dirty and a significant portion will probably be lost. Spacer 2 This spacer is a cleaning spacer. This fluid should contain caustic, surfactant or a cleaning compound that will remove the drilling fluid from the casing. This spacer should be weighted if necessary to help prevent an influx of formation fluid, or the returns should be choked. Sand can be placed in this spacer as an abrasive to clean the casing walls. More than one cleaning spacer can be pumped, if desirable. This spacer should be displaced with weighted brine. Spacer 3 This last spacer is intended to separate the clean filtered well servicing fluid from the cleaning spacer. It is usually a viscosified pill of the well servicing brine similar to Spacer 1.

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C) Circulate the clean filtered brine into the well to displace the spacers. D) Circulate the clean filtered brine into the well to displace the spacers. E) Circulate and filter until the brine's turbidity is less than 50 NTU.

7.16 Balance displacement of an oil-based mud.

This general procedure for the displacement of an oil-base mud without using a water flush is intended to highlight relevant points and state some recommended practices. A) Condition the mud before displacement. B) Displace the oil-base mud with a single pass downhole with the well on

choke to control pressure of the following spacers:

Spacer 1: This spacer must be compatible with the drilling mud and must have a yield point greater than that of the drilling mud. The spacer should be pumped at a high enough rate so it remains in turbulent flow. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. This spacer should be displaced with weighted brine at least equal to the volume of the spacer. Note the brine following the spacer will be very dirty and a significant portion will probably be lost. Spacer 2: This spacer is a cleaning spacer. This fluid should contain caustic, surfactant or a cleaning compound that will remove the drilling fluid from the casing. This spacer should be weighted if necessary to help prevent an influx of formation fluid, or the returns should be choked. Sand can be placed in this spacer as an abrasive to clean the casing walls. More than one cleaning spacer can be pumped, if desirable. This spacer should be displaced with weighted brine.

C) Circulate the clean filtered brine into the well to displace the spacers. D) Circulate and filter until the brine's turbidity is less than 50 NTU.

7.17 Spacers

A spacer is a neutral fluid designed to separate two other fluids without contaminating either. Spacers are used when changing from one fluid system to another and are usually used in a cased hole situation. The selection of a spacer depends upon the fluid in the hole and the fluid that will be used for displacement. The selected spacer(s) must be compatible with adjacent fluids. To select a spacer first, determine what type of fluid will be placed in the hole. Next, decide how the fluid in the hole will be conditioned. Then select a spacer that will not contaminate the fluid in the hole. The second

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spacer should not contaminate the first spacer. The second, or third spacer should not contaminate the fluid used for displacement. When a spacer is used to help scour the casing, it should not contaminate either of the adjacent spacers. Some of the most commonly used spacers are viscous spacers, water, weighted spacers, diesel spacers, and frac-sand spacers. General information about each of these spacers is provided on the following pages. This chapter is intended to provide guidelines for the use of spacers, but does not include all available alternatives. Flexibility and judgment will be necessary when using this information.

7.17.1 Viscous Spacers

The spacer is formulated with HEC and the brine to be used. The general guidelines to formulate and use the spacer are: A) Use 1 - 3 ppb HEC, depending upon the type of salt in the fluid. B) The viscosity will range form 35 to 500+ sec/qt depending on

concentrations and type of make-up fluid. The viscosity is determined by the types of fluids separated by the spacer. The spacer should have greater viscosity than the preceding fluid.

C) The volume is determined by rig and hole conditions, and the method of pumping, i.e., long way or short way. (The long way is through the tubing or drill pipe and up the casing. The short way is down the casing or annular space and up the tubing or drill pipe.)

The purposes of the spacer are: ?? To separate two fluids, thereby preventing contamination. ?? To completely displace the fluid in the hole. ?? To clean the casing and not allow debris to collect on the walls. ?? To serve as a marker fluid to distinguish between two fluids. The spacer is pumped following one fluid and preceding another, and then dumped at the surface. Viscous spacers are compatible with other fluids in use, are less expensive than other spacers, and perform effectively. They also contain a minimum of solids.

7.17.2 Water Spacers

As the name indicates, water spacers are composed of water in an amount sufficient to separate the two fluids. The main purposes of the spacer are:

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A) To separate two fluids. B) To move fluid out of the wells. C) To serve as a marker fluid. The spacer is pumped following one fluid and preceding another, and then dumped at the surface. The rationale for its selection and use is: ?? Cheap and quick. ?? Usually used with lightweight completion fluids. ?? Convenient, since seawater may already be in the hole. ?? Water spacers are used as a buffer in conjunction with more

elaborate spacers.

7.17.3 Weighted Spacers

Based on the type of mud that will be displaced, there are two types of weighted spacers A) A filtered, fresh water, weighted spacer may be used when there

is fresh water mud in the hole. Its contents are as follows:

?? Fresh filtered water. ?? Lime to adjust pH. 0.2-0.5 ppb. ?? Xanthan gum to provide suspension, 0.5 - 1.5 ppb. ?? Calcium carbonate, to a maximum density of 105 pcf. If

greater densities are required, use iron carbonate. For additional density, use barite.

B) A seawater weighted spacer contains the following ingredients.

?? Seawater treated with soda ash to remove calcium. ?? Sodium chloride, 10.0 ppb. ?? Xanthan gum, 0.5 -1.5 ppb. ?? Calcium carbonate, to a maximum density of 105 pcf.

Greater densities (up to 127 pcf) require iron carbonate. For additional density, use barite.

The main purposes of the spacer are:

?? To maintain the hydrostatic pressure, thereby keeping the casing from collapsing.

?? To separate two fluids. ?? To serve as a marker fluid.

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The spacer is pumped following one fluid and preceding another. Weighted spacers are used when formation pressure requires that a high hydrostatic head is maintained and/or when water cannot be used to flush out the casing because of differential pressure.

7.17.4 Diesel Spacers

Diesel spacers are emulsified oil spacers. The purposes of these spacers are: A) To wash or clean the pipe. B) To separate water from an oil fluid. Usually diesel spacers are used in conjunction with other weighted spacers The spacer is pumped following one fluid and preceding another. Then, it is placed in a holding tank to avoid pollution. Diesel spacers are used when changing from water-base to an oil-base systems or the reverse. The diesel spacer has a tendency to channel when used alone.

7.17.5 Emulsified Spacers

Contents and Concentrations A) Emulsified oil. B) Water, to control viscosity. (The more water, the higher the

viscosity.) C) Calcium carbonate and/or iron carbonate, to reach desired

density. D) Diesel. The purposes of these spacers are: ?? To separate oil muds from brines during displacement. ?? To serve as a marker fluid. The spacer is pumped following one fluid and preceding another. Spacer is held in a special tank upon return to avoid pollution. The emulsified oil spacer prevents oil mud from becoming thick. Once pumping is started, make sure to continue pumping until all spacers are out of the well.

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7.17.6 Frac-Sand Spacers

Frac-sand spacers are always used in conjunction with other spacers. The basic formulation of the spacer should include the following: A) Fresh water, approximately 5 barrels. B) HEC, to viscosity of 200 sec/qt. C) Frac-sand, 40-50 ppb. The main purposes of the spacers are: ?? To scour the casing and pipe before displacement. ?? To reduce filtering time by achieving a cleaner displacement,

and therefore, preventing the brine from being contaminated by drilling fluid solids.

?? To separate two fluids. For a more effective application: i) Follow with water. ii) Then follow with approximately 2 barrels of viscous brine fluid. iii) Finally, follow with brine. The frac-sand spacer is selected for its ability to scour the hole. It is usually used in a hole that has contained fluid over a long period, or a hole where excessive filter cake has formed.

7.18 Pills

A pill is a mixture, that is different from the fluid that is in the hole. Pills are used to provide viscosity, to carry debris out of the hole, to prevent lost circulation, or during perforation. They are usually used in an open-hole situation. Some of the most commonly used pills are viscous pills and carbonate pills. While this presentation material provides some guidance in the use of pills, it does not represent all available alternatives. Therefore, flexibility and judgment will be necessary when using these recommendations.

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7.18.1 Viscous Pills

A) Formulation: The viscosity of the pill can range form 35 to 400+ sec/qt depending upon the concentration of HEC (0.5 to 5.0- ppb). The viscosity required depends upon the type and severity of the problem. (Most pumps will not pump fluids with funnel viscosities greater than 500 seconds.). When a pill is used to carry sand and cuttings out of the hole, a small amount of xanthan gum (0.1 to 1.0 ppb) may be added to the HEC for additional carrying capacity. Xanthan gum can be used in fresh water and sodium chloride fluids. The purposes of these pills are: ?? To prevent seepage loss to the formation. ?? To carry sand and cuttings out of the well. B) Applications When used to prevent seepage loss, the viscous pill is spotted and sometimes squeezed into the formation. When used to carry sand and cuttings out of the well, the viscous pill is circulated and dumped at the surface. C) Rationale for Selection and Use HEC is less damaging to the formation than carbonate pills. The viscous pill can be produced out of the well instead of having to be acidized.

7.18.2 Carbonate Pill

Contents: Calcium carbonate ( medium and coarse ), make-up fluid,

HEC and, possibly Xanthan gum. Concentration:

A) For seepage, use 5-10 ppb CaC03 plus 0.5 - 1.0 ppb HEC. B) For medium loss, use 20-30 ppb CaC03 plus 0.5-1.5 ppb

HEC. C) For severe loss, use 50-150 ppb CaC03 plus 1.0-2.0 ppb

HEC. D) Xanthan gum can be used for suspension in brine. It

requires high shear and good mixing to allow the polymer to

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yield and suspend the sized CaC03. If you plan to use 50-150 ppb of bridging agent in the fluid and spot across perforations for two hours or more, or if the fluid is to be left in the well over an extended period of time, Xanthan gum is required to prevent the settling of CaC03 particles.

7.19 Clear Brine Completion Fluid Displacement

The most important step in preparation for brine displacement is cleaning the wellbore. Proper procedures should be applied to remove solids and "dirt" from the well and rig equipment. The casing must be cleaned with a bit and scraper or hydraulic jets to free mud solids, scale deposits...etc. Tubing must be scraped and cleaned, inside and out, before being run into the well. If the wellbore is in communication with producing zones, care must be taken to avoid losing into the formation the solids and "dirt" freed during well cleanup. This means a minimum overbalance and the use of sweeping pills. Thick spacers should be used to separate the clean brine from dirty fluid while pumping i.e., avoid contaminating the clean brine with drilling mud or packer fluid already in the hole. In some cases, the hole could be displaced with clean water, mechanically scraped and circulated until all solids are removed from the wellbore. The following spacers are recommended: A) Scrubber Pill (Volume 10-30 bbl) for displacing water base mud.

?? Fresh water ?? Caustic soda, 1-1.5 lb/bbl ?? 20-40 mesh fracturing sand, 20-30 lb/bbl

B) Scrubber Pill (Volume 10-30 bbl) for displacing oil base mud. ?? Fresh water ?? Metaphosphoric acid, 2-4 lb/bbl ?? Non-ionic surfactant, 25% by volume ?? Degreaser, 2-3% by volume ?? 20-40 mesh fracturing sand, 20-30 lb/bbl

The frac-sand will serve as scouring agent to remove mud cake and scale from the casing and tubing. In the case of displacing oil base mud, it is advisable to pump an emulsified oil pill first (10-30 bbls) having a density of 0.2 pcf higher than the displaced oil mud density. This pill will be followed by diesel oil (10-30 bbls) with frac-sand (20-30 lb/bbl) then the scrubber water base pill described above.

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C) High viscosity brine pill volume (10-30 bbls) composed of: ?? The clean completion brine ?? HEC, 1 - 2 lb/bbl

This pill is to be followed by the clean, filtered brine to complete the displacement. Once displacement is completed, continue circulating the brine and start filtering if required. Lost circulation pill (viscous brine pill with the suitable degradable bridging material) should be prepared and kept on hand before displacement starts. This pill should be spotted at the perforated interval to minimize fluid losses into the zone. Proper displacement procedures should always be followed by the removal of solids and "dirt" from the wellbore and rig equipment. Avoid contaminating the clean filtered brines with drilling or packer fluids previously in the hole by using proper spacers. The following are the common contaminants to be separated from completion brines: i) Iron (iron oxide, iron carbonate, iron hydroxide and iron shavings) Iron is

the most serious contaminant for heavy brines. Some iron can give a dark green gelatinous precipitate and can cause filtering problems. The Fe++ sometimes changes to Fe+++ (dark reddish brown precipitate) which is easier to filter because of its loose crystal nature. Some filtration service companies use HCl to keep the iron in solution and avoid plugging the filter media. This way they filter the brine easier and faster. Using HCl will increase the brine acidity and aggravate the situation. In many cases, leaving the filtered brine in storage tanks a few days will allow the iron to precipitate out. Adding HCl or any other acid to the brine or to the filter media should not be allowed.

ii) Pipe Dope: Analysis of downhole plugging materials indicated that iron

compounds and pipe dope were the major constituents.

iii) Mud Additives: Bentonite, barite, illmenite, iron carbonate, iron-oxide, polymers (CMC, starch, lignosulfonate, etc.) calcium carbonate, asphalt, waxes, etc.

iv) Mica, cane fiber, cotton seed hulls, walnut v) Other Lost Circulation Materials (LCM): shells, cellophane, shredded

rubber, etc.

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vi) Drilled Solids: Sand, shale, clay, limestone, dolomite, anhydrite, gypsum, salt, lignite, plant remains, iron oxide, iron carbonate, mica, pyrite, etc.

vii) Crude Oil: Asphaltenes and waxes. viii) Plankton and Bacteria: From seawater or bay water. ix) Downhole Tools: From seawater or bay water. There are two different displacement procedures used today. They are indirect displacement and direct displacement. The choice of procedure depends on casing-tubing strengths and cement bond log results. If the bond logs and casing strength data indicate that the casing will withstand a calculated pressure differential. the indirect displacement procedure should be used. (Pressure differential = bottom hole pressure - hydrostatic head due to salt water.) This procedure uses large volumes of seawater to flush the well, resulting in a clean, solids-free displacement, reduced spacer costs and lower filtration costs. When applying the indirect method (reverse circulation) we have to be sure that the pumping pressure will not exceed the collapse or burst strength of the casing. If the bond logs indicate that the casing will not withstand the differential pressure, the direct displacement procedure should be used. This method does not obtain a clean displacement and expensive filtering will be necessary. However, undesirable pressure situations are eliminated because this procedure maintains a constant hydrostatic head. Both direct and indirect displacement procedures make use of pills and spacers for effective hole cleaning and spacers for effective hole cleaning and separation of fluids. The primary purpose of a spacer is to provide a complete separation of two incompatible fluids. The spacer must be compatible with both the displaced fluid (fluid coming out) and the displacing fluid (fluid going in). Cleaning pills are used to sweep debris out of the hole. Two types of cleaning pills may be used. A basic cleaning pill is composed of brine viscosified with HEC. A scouring pill, used to remove mud cake from the inside of the casing, consists of water, and coarse sand. The scouring pill must be preceded and followed by a viscous spacer to prevent mixing with other fluids.

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7.19.1 Indirect Displacement Procedure

A) Run bit and scraper. B) Condition and thin the mud as much as possible while

maintaining correct rheological properties. Circulate the mud and reciprocate the tubing during this process.

C) Pump seawater down the annulus and up the tubing no faster

than 2 bbl/min. Spot the displaced mud into the desired reserve tank. The reverse circulation reduces intermingling of the mud and seawater. Pumping fluid faster than 2 bbl/min creates turbulent flow and increases intermingling of the mud and seawater.

D) Prepare a 50 barrel pill of fresh water and caustic soda with a

pH of 12 to 13. Circulate this pill slowly through the entire system for two circulations, rotate and reciprocate the pipe while circulating. The high pH helps dissolve the wall cake from the casing.

E) Chase the pill with clean saltwater and flush until the seawater is

clear. F) Prepare a 20 barrel spacer of filtered seawater and HEC with a

funnel viscosity of 150 to 200 sec/qt. Reverse circulate the spacer, pumping at 1 to 2 bbl/min. Follow with the completion fluid.

G) Pump until the density pumped in equals the density in the flow

line. Dump the spacer. H) Place the filtration unit on line.

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Direct displacement ( Heavy brine in / light oil mud out )

Light oil mud

Spacer - 1 500 ft

High viscosity oil mud with additional Geltone

Spacer - 2 500 ft

XC- Polymer / mutual solvent detergent / barite

Spacer - 3 500 ft

Brine / water wetting surfactant caustic / frac sand

Spacer - 4 500 ft

High viscosity clear brine

Heavy brine

( 68 pcf )

( 69 pcf )

( 69 pcf )

( 70 pcf )

( 70 pcf )

( 68 pcf )

BRINE

MUDMUD

BRINE BRINEBRINE

Indirect displacement ( or reverse circulation )

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( Light brine in / heavy water-based mud out )

Heavy mud

Spacer - 4 500 ft

High viscosity mud

Spacer - 3 500 ft

XC- Polymer / detergent / barite Spacer - 2 500 ft

Brine / caustic / frac sand

Spacer - 1 500 ft

High viscosity clear brine

Clear brine ( 70 pcf )

( 70 pcf )

( 70 pcf )

( 74 pcf )

( 75 pcf )

( 73 pcf )

MUD

MUD MUD

BRINE BRINE

MUD

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Indirect displacement ( or reverse circulation ) ( Light brine in / heavy oil-based mud out )

Heavy oil mud

Spacer - 4 500 ft

High viscosity oil mud with additional Geltone

Spacer - 3 500 ft

XC- Polymer / mutual solvent detergent / barite

Spacer - 2 500 ft

Brine / water wetting surfactant caustic / frac sand

Spacer - 1 500 ft

High viscosity clear brine

Clear brine ( 70 pcf )

( 70 pcf )

( 70 pcf )

( 74 pcf )

( 75 pcf )

( 73 pcf )

MUDMUD

BRINEBRINE

MUD

MUD

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Direct displacement ( Heavy brine in / light water-based mud out )

Light mud

Spacer - 1 500 ft

High viscosity mud

Spacer - 2 500 ft

XC- Polymer / detergent / barite

Spacer - 3 500 ft

Brine / caustic / frac sand

Spacer - 4 500 ft

High viscosity clear brine

Heavy brine

( 68 pcf )

( 69 pcf )

( 69 pcf )

( 70 pcf )

( 70 pcf )

( 68 pcf )

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7.19.2 Direct Displacement

Direct displacement is a somewhat tedious procedure which involves using five spacers in line. Each spacer has a specific use. Spacer No. 1 is 20 bbl viscosified mud used as a plug to displace the mud. Spacer No. 2 and 4 separate the spacer with degreaser from organic additives in the mud and from the brine. Spacer No. 3 is a combination scouring-dissolving spacer. The frac-sand is used to scrape mud off casing walls while the degreaser caustic dissolves the mud. Spacer No. 5 is used to separate the solids laden fluids from the solids free. A) Pump 20 bbl of mud into slugging pit and increase funnel

viscosity to 80 sec/qt, B) Run a bit and scraper on the drill string assembly. Circulate the

mud and reciprocate the pipe. C) Condition and thin mud as much as possible while maintaining

the proper rheological properties. D) Pump the 20 bbl pill into the annulus. (Spacer No. 1) E) Follow with a 20 bbl pill of fresh water, xanthan gum(l/2 lb/bbl)

and barite to desired density. (Spacer No. 2) F) Follow with a 10 bbl pill of fresh water, 1 drum of degreaser 500

lb coarse frac sand and caustic soda to a pH of 12.5. (Spacer No. 5)

G) Follow with 10 bbl pill of fresh water, xantham gum (12 lb/bbl) and barite to desired density. (Spacer No. 4)

H) Follow with a 10 bbl pill of the completion fluid viscosified to 150- 200 sec/qt. (Spacer No. 5)

I) Follow with clean brine.

Note: Reverse circulate during steps D through I.

J) Discard all pills. Filter for at least one full circulation after displacement.

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8.0 SAFETY

High density brines have unique chemical properties. Consequently, they should be handled in a different manner than conventional muds, especially for safety reasons. Personnel safety when handling these brine systems involves two aspects:

1) Education of all personnel 2) Proper safety apparel.

A brine is simply a salt (or a blend of salts) plus water. Low concentrations of these salts cause little or no problem. Commercially available salts currently used in Saudi Aramco's fields are: A) Sodium chloride (NaCl) B) Potassium chloride (KCl) C) Calcium chloride (CaCl2)

8.1 Safety Apparel

This is a list of the minimum safety apparel which should be worn when working with or in the vicinity of brines: A) Hard hats B) Chemical splash goggles C) Rubber gloves D) Rubber boots E) Aprons/slicker suits F) Disposable dust/mist respirators

8.2 Rig Safety Equipment

Following is a list of the minimum safety equipment that should be available when working on a rig with brines:

A) Eye wash fountains and drench showers B) Pipe wipers C) Floor mats

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PACKER AND PBR COMPLETIONS 1.0 PACKER COMPLETIONS

1.1 Types of Packers 1.1.1 Permanent vs. Retrievable 1.1.2 Permanent Packers 1.1.3 Retrievable Packers 1.1.4 Single vs. Dual

1.2 Seal Assembly 1.3 Tail Pipe Assembly

2.0 PBR COMPLETION

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PACKER AND PBR COMPLETIONS 1.0 PACKER COMPLETIONS

The central component of any tubing-packer completion is the production packer, whose primary function is to provide a hydraulic seal between the tubing and casing. The hydraulic seal isolates the casing above the packer from high production and stimulation pressures and corrosive fluids. Major production packer functions can be summarized as follows: A) Protect casing from bursting under conditions of high production or injection

pressures. B) Protect casing from corrosive fluids. C) Isolate casing leaks, squeezed perforations or multiple producing intervals. D) Eliminate inefficient “heading” or surging of production fluids. E) Provide better well control by keeping kill or treating fluids in casing annulus. F) Prevent fluid movement between productive zones. G) Keep gas lift pressure off the formation for more efficient gas lift production

operations. 1.1 Types of Packers

Production packers are generally classified as either retrievable or permanent. They can also be categorized according to the manner in which force is applied to activate the sealing element, as compression packers, tension packers or combination tension and compression packers. Packers can further be classified by their setting mechanism, as Hydraulic, Mechanical, Electric Wireline or Slickline set. Evaluation of packer objectives is required to select the proper packer for a given application. Future well operations, such as initial completion, production, stimulation, artificial lift and probable workover procedures should be considered. The packer that offers the lowest overall cost over the projected life of the well, should be selected. Basic Packer Components A permanent Halliburton WB packer is shown in Fig. 4A-1, and in Fig. 4A-2, a retrievable Halliburton Versa Trieve packer. They have the following components in common: ?? Sealing element ?? Slips ?? Cone

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?? Setting and releasing mechanism ?? Flow mandrel

Figure 4A-1 Permanent Packer Figure 4A-2 Retrievable Packer

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A) Sealing Elements: Sealing elements are normally constructed of nitrile-rubber, except in such special applications as thermal-injection or sour-service operations. Nitrile-rubber seals have proved superior for use in moderate temperatures under normal service conditions. The compound characteristics required for a particular job can be achieved through control of the constituents in the compound and the degree of vulcanization. The ability of a seal to hold differential pressure is a function of the elastomer pressure or stress developed in the seal, i.e., the stress must exceed the differential pressure across the packer.

B) Slips:

Slips are serrated or “tooth-like” parts of the packer. Once forced outward by the setting action, the slips “bite” into the casing wall preventing the packer from moving when pressure differentials exist across the packer. Some packers have two sets of opposing mechanical slips. The top set of slips prevents the packer from moving uphole while the bottom slips prevent downward motion. Some packers incorporate bi-directional slips, that is, one set of slips which prevent motion in either direction. There are a few packer designs with a set of lower slips and a set of hydraulically activated hold-down button slips.

C) Cone:

The cone is simply that part of the packer, which forces the slips to move outward and bite into the casing during the setting of the packer. The cone is known by several other names such as the wedge, expander, or expander cone.

D) Mandrel:

The flow mandrel (sometimes called the packer mandrel) is the "tube" part of the packer which allows production to enter the tubing and, in turn, flow on to the surface. It can be generally stated that a packer consists of external components built around the flow mandrel. In many instances, the pressure differential rating of a packer is dependent on the strength of the flow mandrel. Down hole conditions will dictate the type of alloy used to make the flow mandrel.

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E) Setting and Releasing Elements: The setting mechanism on retrievable packers generally consists of a J-latch, a shear pin, or some other clutch arrangement to allow the packer to be engaged. The various mechanisms employed are actuated by a number of different methods, including upward or downward movement, placing weight on the packer, pulling tension in the tubing, or rotating to the right or left. Hydraulically actuated retrievable packers are set with pressure inside the tubing using pump-out plugs, wireline plugs, or flow-out balls. The releasing mechanisms on a retrievable packer involve another wide range of actuation methods - straight pickup, rotating to the right or left, slacking off and then picking up, or picking up to shear pins. Releasing a packer by rotation is difficult to achieve in highly deviated wells. Tubing movement due to changes of pressure and temperature should be evaluated when selecting setting and releasing mechanisms of a retrievable packer. To select a particular type of setting or releasing mechanism, it is necessary to know the conditions existing in the particular wellbore when the packer is set and the operations anticipated during its stay in the hole.

1.1.1 Permanent Vs. Retrievable

When selecting the optimal packer type for a given application, retrievability is often a key factor. Permanent packers are readily milled out in a few hours milling time using a flat bottom mill or in several hours using a rock bit. By comparison removal of a stuck retrievable packer may require two or three days of rig time and considerable expense. Packer milling and retrieving tools, “packer pickers” are also available to recover the permanent packers by cutting the upper slips and catching the remainder of the packer.

Most production packers currently used in Saudi Aramco Operations are the single string, permanent, hydraulic set type. However, a pilot project to evaluate the feasibility of dually completed producers, is ongoing in the Berri Field offshore. Two wells have already been successfully worked over and converted to dual Hanifa/Hadriyah producers utilizing 9-5/8” Baker GT dual string-selective set-retrievable hydraulic packers in conjunction with 7” Baker FB-1 permanent packers. Five Dual Arab-D Horizontal/Vertical Completions have recently been run onshore in the Uthmaniyah and Hawiyah fields utilizing Dresser Oil Tool's Lateral Re-entry System.

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1.1.2 Permanent Packers

Figure 4A-1 shows a Halliburton WB permanent packer which is frequently used by Saudi Aramco. The packer can be run and set on wireline or drill pipe. Selection of the setting mechanism depends on cost (rig cost and service company charges) and wellbore conditions. When the packer is run on drill pipe a hydraulic setting tool is attached to the top of the packer. Once the packer is on depth, a ball is dropped into the setting tool. Pump pressure activates the setting tool which forces the upper slips, upper cone and lower cone to move downward thus compressing the seal element between the cones against the casing. As the slips slide over the cones they are forced to move outward and "bite" into the casing preventing movement of the packer. When the packer is run on wireline, setting is accomplished by firing an explosive charge to create the necessary pressure required to set the packer. Permanent packers cannot be retrieved from the well. A flat bottom mill is used to mill the top slips and part of the sealing element. The packer is then pushed to the bottom and retrieved by using a taper tap or a spear. The packer may also be retrieved by using a milling-retrieving tool. The tool consists of a burn shoe and a collet or a spear. The collet or spear engages the inside of the packer while the top slips are milled by the burn shoe. Once the top slips are milled the packer is pulled to the surface.

A) Characteristics of Permanent Packers: General characteristics common to permanent packers are: i) Permanently set. Once set, no tubing weight or tension is

required to keep it in set position. ii) Economical. Permanent packers have, by design, very few

components. As a result, these packers are less costly than other packers of comparable size.

iii) Highest pressure rating. Permanent packers due to their simple design can be built sturdier than other types of packers. Pressure differential ratings as high as 15,000 psi are possible.

iv) High-temperature rating. Element packages are available to withstand temperatures in excess of 500?F.

v) Popularity. Worldwide, permanent packers are the most frequently used of all packer types.

vi) Floating seal assembly can be used to accommodate tubing movement.

B) Disadvantages:

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The main objection to the permanent packer is the necessity for milling and destroying the packer for removal. A permanent packer can be milled and retrieved in 12 hours using a milling-retrieving tool or in 24 hours using a flat bottom mill. Permanent packers can be sub-divided according to the method required to set the packer. Electric wireline, hydraulic and tubing rotation are the three setting methods available. The electric wireline and hydraulic are by far the most common methods used to set permanent packers. Tubing rotation is rarely used.

C) Electric Wireline Set Packer

The electric wireline set packer is the most commonly used of any type of packer. It can be run and set quickly and accurately at a pre-determined depth. After the packer is set, a production seal assembly and production tubing is then run into the well. Once the seal assembly seals into the packer, tubing length is adjusted at the surface (spaced out) and the well is then completed.

D) Hydraulic Set Packer

There are instances when it is desirable to run a wireline set packer, however, hole conditions may prevent using electric line. To accommodate the running of an electric wireline set packer, a hydraulic setting tool may be used. The hydraulic setting tool takes the place of the electric line setting tool when conditions so dictate. The packer is attached to the hydraulic setting tool and run in the well on pipe. Once on depth, a ball is dropped through the pipe into the setting tool. Hydraulic pump pressure activates the setting tool causing the packer to set. The hydraulic setting tool and workstring are then pulled out of the well and production seals and tubing are run to complete the well.

Some conditions which may require using a hydraulic setting tool are:

i) Assembly weight. If the packer and attached equipment

weighs more than the electric wireline can support, the assembly may be run and set on pipe using the hydraulic setting tool.

ii) Seal assembly on bottom of the packer assembly. If a

previously set lower packer is in place, the seals for the

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lower packer may have to be pushed into that packer using the workstring weight.

iii) High angle of deviation. As the angle of deviation becomes greater, a point is reached, generally 55-60?, where the packer will no longer "slide" down the well. This condition requires running the packer on pipe.

iv) Heavy mud in the well. A thick, viscous mud may prevent the packer assembly from falling on its own. Again, pipe weight may be required to push the packer assembly down hole.

1.1.3 Retrievable Packers

A Halliburton Versa-Trieve retrievable packer is shown in Fig 4A-2. The packer is designed to be set on wireline or tubing. It has bi-directional slips located below the packer elements to prevent debris from settling on them. During the setting sequence, the packer's guide tube is forced downward while the packer's mandrel is pulled upward. This motion drives the top and bottom wedges under the slips to force them out into the casing wall. Additional setting stroke compresses the packer's elements to form a seal against the casing wall.

The packer is maintained in the set position until a shear piston located in the lower end of the packer is moved up to release the packer's mandrel from the packer's shear sleeve. A VRT retrieving tool is used for this operation. Once the packer's mandrel is free to move, a set of shear pins in the VRT tool is sheared, allowing the pulling forces to be transmitted to the packer's mandrel. As the packer's mandrel is moved upward, a snap ring catches the lower end of the element mandrel to release the compression in the packer's elements. Additional upward movement pulls the top wedge from under the slips allowing the slips to move in and release their bite in the casing wall.

The main advantage of retrievable packers is that they can be retrieved without destroying the packer. This saves rig time and the cost of replacing the packer. If the old packer is in satisfactory mechanical condition and is not corroded it can be redressed and rerun in the well. Retrievable packers, however, cost more than permanent packers. Sometimes retrievable packers get stuck and cannot be retrieved by conventional retrieving tools. In this case they have to be milled and retrieved by taper tap. Retrievable packers generally take longer time to mill than permanent packers because their slips are made of harder metal.

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1.1.4 Single vs. Dual

Most production packers currently used in Saudi Aramco operations are the single string, permanent, hydraulic set type. The single permanent packer has historically proven to be the most economical choice for Saudi Aramco in terms of handling high production rates and accommodating periodic workover and stimulation operations. However, with the success of the Berri Field dual completions, additional duals are planned.

The general procedure for the Berri field dual completions is to first run in the hole with the single FB-1 packer and tailpipe assembly on drillpipe and set it + 250’ above the lower zone (the Hadriyah perforations). The setting tool is released and then pulled out of the hole. The top dual Baker GT retrievable packer is run made up on the long tubing string with the lower seal assembly and tail pipe assembly attached to the bottom. The long string seal assembly is stung into the bottom (FB-1) packer. The dual packer is then hydraulically set and pressure tested. The long tubing string is permanently attached to the top packer. Expansion joints are run in both tubing strings to allow for tubing movement. The tubing strings are hung on a special dual tubing hanger. A dual production tree is installed on top of the tubing spool which facilitates producing the two zones separately. Both the short and long strings of the offshore Berri Field Dual Completions contain blast joints, expansion joints, sliding sleeves and wireline retrievable subsurface safety valves (SCSBV), which are not usually run in onshore single string completions.

A) Sliding Sleeves:

The sliding sleeves, sometimes referred to as sliding side doors, are used to displace the tubing and annulus to diesel and inhibited diesel respectively after the dual packer is set. A sliding sleeve is simply a port that can be opened or closed by wireline. It can also be used to kill and circulate out a well without removing the Christmas tree. However in wells with sand laden or highly corrosive fluids, sliding sleeves may fail or become stuck in the open or closed position. In certain applications sliding sleeves are utilized to selectively produce or stimulate targeted zones.

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B) Expansion Joints: Expansion joints are used to compensate for tubing contraction and elongation due to temperature and pressure changes caused by producing and stimulation operations. Most have maximum stroke lengths from 10 to 20 ft. The Berri Dual completions utilize full bore Baker Model–M expansion joints in the short and long strings.

C) Blast Joints:

Blast joints are used in multiple completion wells to protect the area of tubing that remains opposite the upper perforations and exposed to abrasive, corrosive and sand laden fluids. The blast joint is externally coated with rubber, tungsten carbide, ceramics or is itself a special alloy. These coatings serve to reduce abrasion caused by the flow of produced fluid.

D) Subsurface Safety Valve:

A subsurface safety valve is a device installed in the tubing of a well below the wellhead that can be actuated to prevent uncontrolled well flow. This device can be installed and retrieved by wireline (wireline retrievable) or it can be an integral part of the tubing string (tubing retrievable). They can be subsurface or surface controlled.

Figure 4A-3 - Blast Joint, Subsurface Safety Valve and Sliding Sleeve

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Figure 4A-4 - Dual Hanifa/Hadriya Completion on Berri-98

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Four dual - Arab-D Short Radius Horizontal Producer/Vertical Open hole observation wells and one dual short radius Arab-D Horizontal Producer/Arab-D Vertical Producer have recently been drilled and completed by Saudi Aramco in the Utmaniyah, Haradh and Hawiyah Fields using Dresser Oil Tool's Lateral Re-entry System (LRS). Seven more are planned for the near future. Haradh-159 was recently recompleted in this manner utilizing an upper 7" DOT G-10 permanent packer, a 7 x 2.50" DOT LRS-SL Window, a lower DOT 7" Slim-GT Packer and 4-1/2" production tubing as shown below.

Figure 4A-5 - Dual Arab-D Horizontal Producer/Arab-D Vertical Observation Well

Haradh Well No. 159 (P)Cross Section after WO-1

9-5/8” Casing @ 3717’

7” Liner Hanger @ 1712’

TD @ 8736’ MD, 6582’ TVD (30’below topof Zone-2A) 88.7° Inclination, 320° AZM.

4-1/2” Tubing

KOP @ 6406’ TVDLanding Point @ 6736’ MD, 6537’ TVD (top Zone-2A)

LRS Window @ 6394’ - 6400’

‘G-10’ Packer @6299’

‘Slim GT’ Packer @ 6429’with end of 2-3/8” Tailpipe@ 6472’

320320° AZMAZMNorthNorth

Zone-2A

7” Liner @6532’

Vertical PBTD @ 6820’

4 1/2” Liner ( 6452’ - 6832’)

7” Casing Window 6388’ - 6401’

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1.2 Seal Assembly

Since permanent packers cannot be pulled out of the well, the tubing cannot be attached directly to a permanent packer. Occasionally, the tubing may have to be retrieved and repaired or replaced. A pressure tight seal must exist between the tubing and the packer bore forcing the production into the tubing. This is accomplished by using a seal assembly, which attaches to the tubing and seals in the packer. The seal assembly is designed such that it can move in the packer to accommodate tubing elongation or contraction which can result from changes in temperatures and pressures in the tubing and tubing-casing annulus. The basic seal assembly used in Saudi Aramco wells consists of a locator, a spacer bar, a seal unit and a mule shoe guide, as shown below.

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A) Locator: The locator is attached at the top of the seal assembly and at the bottom of the tubing. It is designed to prevent any further downward travel of the seal assembly once the locator encounters the top of the packer. A Halliburton straight slot locator used by Saudi Aramco is shown above. It is used when a free-to-move seal assembly is required. The jay-slot locator is used when small tubing movement or forces are expected. The jay slots of the locator latch onto the lugs in the packer's head preventing tubing movement.

B) Spacer Bar:

A spacer bar is a length of pipe without seals attached to the bottom of the locator and above the seals. It is used as an extension to space out the locator above the packer and at the same time keep the seals inside the bore of the packer and sealbore extension.

C) Seals:

The seal unit forms a seal in the bores of the packer and sealbore extension. A Halliburton standard molded seal unit is used in most Saudi Aramco completions. The seal is made of nitrile rubber and is used in wells where the pressure is less than 10,000 psi and

temperatures are less than 275?F. Each seal unit is one foot long and longer seal assemblies can be made by simply attaching the seal units together. Premium seals are used for harsh conditions of high temperatures, high pressures and in severe environments such as hydrogen sulfide, carbon dioxide and amine inhibitors. The Kalrez/Chemraz-Teflon-Rytex, (KTR) premium, self-energized, Chevron “V” shaped seals are currently used on all Khuff Gas Well PBR and Tubing-Packer completions.

D) Mule Shoe:

A Mule shoe is installed at the bottom of the seal assembly to facilitate entry into the packer bore. The shape of the mule shoe is designed such that if the seal assembly hangs up at the top of the packer or liner hanger, a simple rotation of the assembly will allow it to pass through.

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1.3 TAIL PIPE ASSEMBLY The tailpipe assembly is the part of the tubing that is connected to the bottom of the packer. It serves the following functions:

A) Provides a seal bore for the seal assembly.

B) Contains landing nipples for setting wireline plugs used for well control

and pressure testing tubing.

C) Contains no-go landing nipples used for hanging bottom hole pressure gauges.

d) Facilitates re-entry of wireline tools.

The standard tailpipe assembly used in Saudi Aramco oil producers consists of the following components: ? Sealbore extension ? Millout extension ? Selective landing nipples ? No-go landing nipples ? Re-entry guide A) Sealbore Extension: A sealbore extension is a length of pipe with polished bore that is connected at the bottom of the packer. It is designed to extend the polished surface of the packer bore to permit use of longer sealing units to compensate for the contraction and elongation of the tubing. A Halliburton sealbore extension used by Saudi Aramco is shown in Fig 4A-6. It is ±12' long and has the same bore ID as the packer. B) Millout Extension: A millout extension is a length of pipe ±5' long which is connected to the bottom of the sealbore extension. The purpose of the millout extension is to facilitate the retrieval of the packer and tailpipe assembly after the packer is milled. It has a larger inside diameter than that of the sealbore extension. The difference in the diameters provides a shoulder where a special plucking tool can engage and retrieve the packer and tailpipe assembly. The use of a millout extension is

Figure 4A-6 – Halliburton

Sealbore Extension

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optional. When not used the packer can be milled out and then retrieved by taper tap or spear.

C) Landing Nipples:

A landing nipple is a device connected to the tubing or tailpipe assembly used for setting wireline plugs or flow control devices. Halliburton selective nipples are used in Saudi Aramco's well completions. Type 'X' nipple shown in Fig 4A-7 is used for standard weight tubing, type 'R' nipple is used for heavy weight tubing. The bore size of the nipple should be compatible with the size and weight of the tubing. The first 'X' nipple in the tailpipe assembly is installed at the bottom of a tubing pup joint which is connected to the sealbore extension or millout extension. The nipple is used for setting wireline tubing plugs to stop the flow into the tubing. This is normally done during workovers before the tree is removed or when Well Services replaces a damaged tubing master valve.

Figure 4A-7 - Landing Nipples used in Saudi Aramco's Well Completions

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In Southern Area well completions two 10' perforated tubing pup joints are connected below the 'X' nipple. During flow tests pressure gauges are hung inside the tailpipe below the ‘X’ nipples, which partially block the flow into the tailpipe. The purpose of the perforated pup joint is to

Figure 4A-8 - Halliburton Re-entry Guide

allow the fluids to enter into the tubing during the flow test. A second 'X' nipple is installed at the bottom of the perforated joints. This nipple is used by S. A. Wireline Services for hanging bottom hole pressure gauges (Normally 'X' nipples are not designed for hanging pressure gauges).

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D) No-Go Landing Nipples: The no-go or 'XN' landing nipple is installed on a 10' tubing pup joint below the bottom 'X' nipple. Like the 'X' nipple it has a polished bore for setting wireline tubing 'PXN' plugs. In addition, the 'XN' nipple has a no-go ID at the bottom to prevent pressure gauge hangers from dropping to the bottom of the well. The nipple is used for hanging pressure gauges and other flow control devices. E) Re-entry Guide: The re-entry guide is installed at the bottom of the tailpipe assembly. Its bell shaped design facilitates re-entry of wireline tools into the tailpipe. An Otis re-entry guide is shown in Fig 4A-9 Fig. 4A-9 Packer Seal and Tailpipe Assemblies

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2.0 PBR COMPLETION

A polished bore receptacle (PBR) is another type of packer system that can be used in place of a permanent packer. It is frequently used in deep gas well completions or other situations where casing or liner diameter is limited and maximum packer bore is desired. The PBR accepts an inner seal assembly that seals off between the tubing and the PBR Fig 4A-10 and 4A-11. The PBR is commonly used in a liner completion, where it is installed as an integral part of the liner hanger. When the completion string is run, the seal assembly, similar to that used on a permanent packer, is run on the end of the tubing string. The seal assembly is either latched onto the PBR, or left floating to allow tubing movement. Frequently tubing weight is slacked off on the PBR to eliminate seal movements during the producing life of the well, while allowing free upward movement during stimulation treatments. The bore of the seal assembly is equal to the ID of liner below, which facilitates free passage of wireline tools. Normally, the PBR diameter is larger than the diameter of the liner below it. Most workover tools and procedures can be run through the PBR with ease.

Figure 4A-10 - PBR installed in Liner Completion

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In a PBR completion, the sealing characteristics and capabilities between the tubing and PBR are the same as between the tubing and packer body of a permanent packer completion.

The PBR has a disadvantage that the permanent packer does not. The position of the PBR is fixed in the hole, generally in the liner hanger, which may be several hundred feet above the zone of interest. As stated previously, one of the functions of the packer system is to protect the casing string from the corrosivity of wellbore fluids by sealing off the tubing annulus. Since the PBR is set at the top of the liner, the entire length of the liner is exposed to potentially corrosive fluids when the well is produced. For example, in a well with a 500 ft. liner and a producing interval 50 ft in length, the entire liner is exposed to the effect of the production fluids, as opposed to a typical installation in which the packer would be located just above the pay. Figure 4A-11 - PBR and Seal Assembly

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PACKER AND PBR SELECTION 1.0 SELECTION CRITERIA

1.1 Cost 1.2 Well Conditions 1.3 Running and Setting Considerations 1.4 Retrieving Considerations 1.5 Production & Treating Considerations 1.6 Compatibility with Downhole Equipment 1.7 Maximum Packer Bore

2.0 TYPICAL COMPLETION DIAGRAMS

2.1 Onshore Arab-D Horizontal 2.2 Offshore Arab-D Vertical 2.3 Onshore Arab-D Vertical 2.4 Dual Arab-D Horizontal /Vertical 2.5 Shaybah Horizontal 2.6 Vertical Khuff Packer Completion 2.7 Vertical Khuff PBR Completion

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PACKER AND PBR SELECTION

1.0 SELECTION CRITERIA

The best approach for selecting a packer is to first examine well conditions and desired operational capabilities and then determine which packer features meet those well conditions and best fulfill those operational requirements. Some of the factors that should be considered in selecting a packer are:

1.1 Cost

The packer of minimum cost that will accomplish the objective should be selected. Initial packer price should not be used as the only criterion. Rig time cost for running and retrieving the packer should also be taken into consideration.

1.2 Well Conditions

1.2.1 Packer should be selected to withstand the pressure differentials

between the tubing-casing annulus and wellbore below packer during producing and acidizing.

1.2.2 Packer should be made of alloys that will withstand the corrosivity of

well fluids.

1.3 Running and Setting Considerations

Packer setting mechanisms are tubing-set, electric-line-set or hydraulic-set. Tubing-set packers should not be used in deep wells because of increased possibility of tubing manipulation problems with increased depth. Electric line set packers should not be used in highly deviated holes (greater than 50- 55O) because it is not possible to run the packer to the required depth.

1.4 Retrieving Considerations

Retrievable packers can be retrieved by a rotational release mechanism or straight pickup release mechanism. A rotation release packer should be avoided in deviated wells because of difficulty in transmitting rotation downhole.

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1.5 Production & Treating Considerations

Packers must be able to accommodate tubing movements (elongation and contraction) as a result of changes in temperatures and pressures. Packers set in tension allow for tubing movement due to expansion whereas packers set in compression accommodate tubing contraction. Tubing movement due to both expansion and contraction can be accommodated using a floating seal assembly with sealbore extension.

1.6 Compatibility with other Downhole Equipment

If wireline equipment or perforating guns are to be run in the tubing, it is desirable to use packers that do not require weight to keep them set. Wireline operations can be more successfully completed if tubing is kept straight by landing it in tension or neutral. Furthermore, the bore of the packer or the seal assembly should be large enough to allow for running through-tubing, perforating guns, production logs and tubing plugs.

1.7 Maximum Packer Bore.

In deep gas wells or other situations where casing or liner diameter is limited and maximum packer bore is required, the PBR Completion may have application.

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2.1 Typical Onshore Arab-D Horizontal Completion with 7” Baker FB-1

Permanent Packer

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2.2 Typical Offshore Arab-D Vertical Completion with Permanent Packer and Subsurface Safety Valve at + 300’.

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2.3 Typical Onshore Arab-D Vertical Completion with DOT 7” Magnum GT Permanent Packer

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2.4 Dual Arab-D Horizontal/Vertical Producer Dual Arab-D Horizontal/Vertical Producer

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2.5 Typical Shaybah Horizontal Completion with Baker FB-1 Permanent Packer

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2.6 Typical Khuff Vertical Completion with 9-5/8” Halliburton TWS Permanent Packer and Ratch-Latch Assembly

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2.7 Typical Khuff Vertical 7” Liner/PBR Completion

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RUNNING AND SETTING PROCEDURES 1.0 GENERALIZED PACKER RUNNING PROCEDURE

1.1 Onshore Arab-D Well With Permanent Hydraulic-Set Packer 1.2 Dual with Upper Retrievable/Lower Permanent Packer - Workover

Procedure for Dual Arab-D Horizontal Producer/Vertical Arab-D Vertical Observation Well

1.3 Khuff Completion with 9-5/8" Permanent Packer with Tubing Anchor Seal Assembly

2.0 GENERALIZED RUNNING PROCEDURE FOR KHUFF PBR COMPLETION

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RUNNING AND SETTING PROCEDURES

The minimum requirement for barriers/shut-offs to be in place prior to rig release for all completions shall adhere to (G.I. #1853.001) as follows:

Oil Wells (GOR less than 850 scf/bbl); 2 shut-offs (1 mechanical) Oil Wells (GOR more than 850 scf/bbl): 3 shut-offs (2 mechanical) Gas Wells: 3 shut-offs (2 mechanical)

The packer fluid density used in the TCA shall never be less than kill mud weight. If annular operated tools are required, a brine of kill weight density (CaCl2/CaBr2 for Khuff/Pre-Khuff wells) is recommended to avoid mud solids settling, which can result in operational problems with the annular operated tools and freeing the packer. 1.0 GENERALIZED PACKER RUNNING PROCEDURE

1.1 Onshore Arab-D Well With Permanent Hydraulic-Set Packer.

COMPLETION PROCEDURE

A) After logging at TD, RIH with 6” bit, 7", 26# casing scraper and two 6-

1/8" string mills. Space out scraper to be at 100’ above the 7” liner shoe, when bit at TD. Ream and clean 7" liner hanger and circulate hole clean. Make a wiper trip to check for fill, circulate out if any.

B) Before POH, sweep with HV polymer pills & spot 100 bbl of clean acidic water (pH 5-6) treated w/ 0.5 drum of MORFLO-II surfactant across the open hole. POH.

Note: i) The estimated acid required to reduce pH from 7.3 to 5 is

approximately 1.0 bbl of 15% HCL per 100 bbl of water. ii) Add 1/2 drum of MORFLO-II to water just prior to pumping

downhole to avoid foaming. iii) Pass water through 200 mesh screen. Install strainer screen at

pump intake.

C) RU WL and run 5.95" AC-DC for 7", 26 # liner to 7400' MD (at 50? inclination). Run until two clean runs.

D) RIH and set 7", 26 # Baker FB-1 packer & tailpipe assembly on DP as follows:

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AMOUNT DESCRIPTION 1 3-1/2 " Wireline re-entry guide w/fluted guide 650 3-1/2" 9.3 lb/ft, J-55, EUE Tubing 1 3-1/2" “XN” Nipple (2.635" No Go ID) 30' 3-1/2" 9.3 lb/ft, J-55, EUE Tubing as above 1 3-1/2" ‘X’ Nipple (2.75" ID) 2 x 10' 3-1/2" 9.3 lb/ft, J-55, EUE Perforated pup joints 1 3-1/2" ‘X’ Nipple (2.75" ID) 1 x 10' 3-1/2" 9.3 lb/ft, J-55, EUE Pup Joint 1 3-1/2" EUE Pin X-Over to seal bore extension 1 Millout Extension 1 Seal Bore Extension 1 7" Baker FB-1 Packer (ID = 4.0", OD = 5.875")

Note: ?? Drift the tail pipe with a 2.867" x 3' drift except the 'X' & 'XN'

nipples. ?? Caliper all nipples before installation. ?? Run with the XPO (Pump Thru) plug in place in the first

X-nipple below the packer. (2500 psi pressure is required to shear the XPO plug with diesel in the tubing)

E) Set the packer at ± 7180' (MD), 6486' (TVD), angle ? 46?. Make sure the end of tubing is ± 30' below the liner shoe into the horizontal section. Test the packer to 1000 psi. POH. Do not rotate the pipe while pulling out and laying down drill pipe.

Note: Nipple above the perforated pup joints should not be set at an angle greater than 55?.

F) RIH with the seal assembly on 3-1/2" x 4-1/2" tubing as follows:

AMOUNT DESCRIPTION 1 Mule Shoe guide (OD = 3.95" ID = 3.0” ) 1 Packer Seals (set of 3), OD = 4" ID = 3.0” 1 Spacer Bar, OD = 3.95" ID = 3.0” 1 G – 22 Locator (OD = 4.5”, ID = 3.0”) 1-jt 3-1/2", 9.3 lb/ft, J-55, EUE Tubing 1 3-1/2" , Otis X Nipple (2.813" ID) 1-jt 3-1/2", 9.3 lb/ft, J-55, EUE Tubing as above 1 3-1/2" x EUE x 4-1/2" NEW VAM x-over As required 4-1/2", 11.6 lb/ft, J-55, NEW VAM Tubing 1 – 2 jts 4-1/2”, 12.6#, J-55 VAM pups 1 11" x 4-1/2 " Tubing Hanger with Polish Nipple

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Note: ?? Inspect EUE and NEW VAM threads while on the rack, and clean

the threads using degreasing solvent (AMS 26-301-798) and nylon brushes just prior to job.

?? Apply the dope evenly and ensure the use of a stabbing guide. ?? Drift the 3-1/2 inch tubing with a 2.867" x 3' drift. Drift seal

assembly with 2.867" x 5.5' except 'X' nipple. ?? Drift the 4-1/2 inch tubing with a 3.875" x 5.5' drift every 1000' & at

landing depth. ?? Have various lengths of 4-1/2", 12.6 lb/ft NEW VAM pup joints on

location for space out.

G) Tag packer. Pick up and circulate hole clean to remove any debris and pipe dope. Sting into the packer until the locator bottoms out. Pick up 3' and space out.

H) Unsting from the packer. Displace tubing to diesel with 3% Coat-415. Sting into packer and bleed U- tube pressure and observe well for 15 minutes. If test is good, unsting from packer, displace TCA to inhibited diesel and tubing to diesel. Sting into packer and land tubing. Test TCA to 1500 psi and tubing to 1000 psi separately.

I) Install BPV. ND BOPE. NU 4", 3000 psi tree. Orient the wing valve to the West. Pack off and pressure test bonnet and tree to 2500 psi. Plug the control line outlet. Retrieve the BPV. Complete the wellhead report and return to Drilling Engineering.

J) RU and pump down the tubing to shear out the XPO plug at 2500 psi with diesel in tubing. (Do not exceed 3000 psi surface pressure).

Note: After displacing the hole to diesel, the estimated BHP below the plug is 2483 psi with brine below the packer.

K) RU SAWL. Pressure test lubricator to 1000 psi. RIH and retrieve lock

mandrel. RD SAWL. Flow the well for clean-up until the flow parameters stabilize. Record the flow parameters and collect representative fluid samples. Shut in and record the SIWHP.

L) Secure wellhead, fill cellar with sand & release rig.

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1.2 Dual with Upper Retrievable/Lower Permanent Packer - Workover Procedure for Dual Arab-D Horizontal Producerl/Vertical Arab-D Vertical Observation Well

WORKOVER PROCEDURE

A) The well is first decompleted. B) The Wellbore integrity is tested to 2000 psi. C) Orient and set 5-1/2" Whipstock in 7" casing 16' below the base of

Arab-C Reservoir. D) Cut 2' window in 7" casing with starting mill. Cut an additional 6' with

window mill. E) Drill 6' of open hole to Kick off point and circulate hole clean. F) Pressure test formation to 1500 psi to insure isolation from the Arab-C

reservoir. G) Displace hole to 69 pcf Gypsum mud. H) Ream window with tandem window mill and watermelon mills. I) Drill short radius curve with short radius angle build BHA with 80?/100'

BUR until 66.4? is reached. POH. J) RIH with short radius angle holding BHA. Ream curve section, then

build to 90? at 10?/100'. Hold 90? inclination to the end of build section. K) RIH with Smith Whipstock retrieving tool and retrieve Whipstock. L) Run back in parent hole (vertical hole below sidetrack). Mill and push

Bridgeplug to bottom. M) Ream out window with string mills. Run AC-DC tool to 16' above

window. N) RIH with 7" Dresser "Slim GT" Packer and lower 3-1/2" Tailpipe

assembly with "PX" plug in place, on Drillpipe. O) Set Packer and Tailpipe assembly +71 above 7" shoe (26' below casing

window). Release hydraulic setting tool and POH. P) A 7" HDCH-5 test packer is run and set 14' below the 7" casing in order

to test the Slim GT packer (12' below) to 1000 psi. The Hydraulic test packer is then POH.

Q) The upper packer assembly including a 7" Dresser G-10 packer with tailpipe assembly, Lateral Re-entry sub with self locator tool with isolation sleeve installed and 7" G-10 torque locked retrievable packer is RIH. This assembly is RIH to 12' above setting depth, then slowly rotated until the self-locator enters the window and locks in place. At this point the landing coupling should be 5' above the 7" Slim-GT packer. The assembly is then released, POH 13' and the locating procedure repeated to insure proper orientation.

R) The assembly is pressure tested to 1000 psi after which a 1-1/4" steel ball is dropped and the packer set. The packer is re-tested to 1000 psi, setting tool released and POH.

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S) The seal assembly for the upper G-10 packer is then RIH on the 4-1/2" production tubing. The packer is located, stung into and the TCA and tubing tested to 1000 psi.

T) The isolation sleeve is Wireline retrieved from the LRS and a DOT Tubing Exit Whipstock set at the LRS sub.

U) The Whipstock facilitates entry into the upper zone with coiled tubing such that the entire horizontal section can be stimulated with acidic brine.

V) The Whipstock is then retrieved on Wireline with a GS-pulling tool. A "XPO” plug is set in the X-nipple above the LRS.

W) The seal assembly is unstung from the upper packer. The tubing is displaced to diesel and TCA to inhibited diesel. TCA and tubing are tested to 1500 psi.

X) Install BPV in tubing hanger. ND BOPE and NU single 4-1/16" 3M tree. Y) After testing the tree and tubing to 3000 psi, the XPO plug is removed

and the well brought on production. The "PX" plug set in the tailpipe of the lower packer is left in place to isolate the original vertical open hole.

1.3 Khuff Completion with 9-5/8" Permanent Packer with Tubing Anchor Seal Assembly

COMPLETION PROCEDURE

After pressure testing the 9-5/8” casing to 4000 psi with mud at PBTD, proceed as follows:

A) Flush hole clean with High-Vis pill and circulate hole clean with water.

Observe well for one hour. POH. B) RIH with 8-3/8” bit and 9-5/8”, 58.4# scraper with 9-5/8”, 58.4# Hedge-

Hog brush and work same one stand across packer setting depth of 10,784’.

C) Cont. RIH to PBTD @ 11,615’. Pump and circulate 25 gal Rinse-Aid mixed with 20 bbl fresh water. Circulate clean. Spot 100 bbl of inhibited water (1% Coat B-1400) on bottom POH.

D) RU SAWL 5M lubricator and WL BOPE. Test lubricator to 5000 psi with water. Run the following: i) 8.25” ACDC to 10,884’ (100’ below packer setting depth) until two

clean runs. ii) 8.25” x 3’ drift to to 10,884’.

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E) RIH with Halliburton 9-5/8” TWS packer and tail pipe assembly on

DP as follows:

WL guide, 4-1/2” 15.1# L-80 N-VAM Box (ID=3.826”, OD=5.68”) Pup joint 4-1/2” 13.5# N-VAM Box x Pin (10’ long) (ID=3.920”, OD=4.98”) RN nipple 4-1/2” Halliburton (No Go ID=3.343”, OD=5.03) Perf. Pup jt. 4-1/2” 13.5#N-VAM Box x Pin (20’ long) (ID=3.920”, OD=4.98”) R nipple 4-1/2” (ID=3.688”, OD=5.030) Pup Joint 4-1/2” 13.5# New VAM Box x Pin (ID=3.92”, OD=5.0”) X-Over 5” 18# N-VAM Box x 4-1/2” 15.1# Pin (ID=3.826”, OD=5.587”) M/Exten. 5” Halliburton 18# N-VAM Pin X Pin (ID=4.23”, OD=5.00”) Packer Halliburton 9-5/8” TWS (AMS# 45-735-760) (ID=3.72”, OD=8.12”)

Position tail pipe at + 10,838’ (150’ above the top of the Khuff-B, with Packer 204’ above the Khuff-B). Drop ball, apply +2500 psi surface pressure, and set packer at 10,784’. PT packer to1500 psi. Shear out of packer. POH with drill string and setting tool.

Note:

?? Exercise caution while RIH with the Packer assembly. ?? Packer depth at 10,784’ in vertical hole. ?? Prior to running the 5-1/2” production tubing, ensure the following

procedures have been carried out:

Full Vetco inspection, including API drift, and hydroblast the tubing at the Vetco yard (to remove any rust and scale build up).

?? Clean the threads w/ a nylon brush and cleaning solvent. ?? Visually inspect all threads. ?? Have Franks inspect and clean the threads prior to make-up.

F) Prior to RIH with tubing, install test plug and test tubing hanger bowl to

8000 psi with water. Mark test assembly at rotary. Measure from this mark to bottom of test plug while POH to obtain accurate measurement from the rotary table to the tubing hanger bowl.

G) Pick up PBR/Seal Assembly and RIH on 5-1/2” 20 # NK-AC95ST w/NK-3SB Connections to top of packer as follows:

i) Hal. Ratch/Latch with KTR Seals,

4-1/2”, 15.1# L-80 (H2S) N-VAM Box (OD=5.25”, ID=3.720”) ii) Hal. PBR (5.875” OD x 5.00” seal bore ID) PBR-30’ unit, 15.1#, L-

80, N-VAM pin DN complete with “KTR” seals for 25’ stroke w/3.72” min ID and 4-1/2”, 15.1# L-80 (H2S) locator N-VAM Box up. (AMS# 45-753-150).

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iii) Adapter, 5-1/2” 23.0# New Vam Box x 4-1/2” 15.10 # New Vam Pin AMS# 45-666-545 & AMS PEND 0706.

iv) Pup joint 5-1/2” 20# N-VAM Box x Pin (6’) (ID=4.778”, OD=6.1”). v) X/O 5-1/2” 20# N-VAM Pin x 5-1/2” 20# NK-3SB Box vi) As required.(+8200’) 5-1/2”, 20#, NK-AC95ST/NK-3SB tbg.

(AMS# 45-950-740) vii) X/O 5-1/2” 20# NK-3SB Pin x 20# N-VAM Box viii) 1 each Flow Cplg; 5”, 23.0# N-VAM, (OD=6.10, ID=4.56”)

(AMS# 45-664-998) ix) 1 each Hal. “R” landing nipple, (OD=6.1”, ID=4.313”)

(AMS# 45-717-310) x) 1 each (6’) Flow Cplg; 5-1/2”, 20# N-VAM, (OD-6.1”, ID=4.56”). xi) X/O 5-1/2” 20# N-VAM Pin x 5-1/2” 20# NK-3SB Box xii) + 2,500’ 5-1/2”, 20#,. NK-AC95ST/NK-3SB tubing

(AMS# 45-950-740) xiii) X/O 5-1/2” 20# NK-3SB Pin x 20# N-VAM Box xiv) Tubing Hanger; 11” x 5-1/2” 20.1# N-VAM P X ACME

(AMS# 401-822-45-9915-005).

Note: ?? Have Enough 5-1/2” 20# NK-AC95ST/NK-3SB pup joints for

space out. ?? Optimum make-up torque for 5-1/2” 20#NK-3SB =7200 ft-lb;

N-Vam = 6800 ft-lb ?? Drift tubing w/4.653” x 3’ every 2000’ and @ landing depth. ?? Caliper “R” nipple before installing. ?? Use API modified tubing dope. Apply to pin ends using paint

brush. ?? Use Franks torque-turn service to run the tubing.

H) RIH to + 100’ above packer. Circulate @ 1-2 BPM to clean packer top.

Slowly lower and latch into packer. Slack off + 10,000 lb. Pick up + 30,000 lb over string weight to shear from PBR. Wait two hours for temperature to stabilize if bottoms up were circulated. PU and space out. As per SAGED recommendations the final space out will be with 24” of slack-off from neutral weight. Test the annulus to 1500 psi. Bleed off pressure and mark tubing at the rotary (Mark-1).

I) PU and measure from the mark made in step #8 (Mark – 1), the distance from rotary table to the tubing hanger bowl. Mark the tubing at this point (Mark-2).

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J) PU and measure the length between Mark – 2 and the next tubing collar below Mark –2. This length less the length of the pup joint on the bottom of the tubing hanger will be the length of the pup joints needed for space out. Install two (2) full joints below the tubing hanger.

K) Land tubing and check space out. L) RU WL Lubricator and WL BOP on top of Landing joint and test same

to 6500 psi. M) RIH with Halliburton 3.688” Selective Test Tool and set same in “R”

nipple in Tailpipe Assembly @ +10,805’. N) Pressure test tubing to 6000 psi with water for 15 minutes. O) WL retrieve 3.688” Selective Test Tool and RD WL. P) Unsting from PBR. Q) Mix and pump the following pickling treatment down the tubing.

i) 25 gal Rinse Aid mixed with 20 bbl water; followed by, ii) 5 drums (6.55 bbl) of Super Pickle. iii) Displace Super Pickle with water ½ bbl short of Seal Assembly. Do

not over displace. Reverse Super Pickle and Rinse Aid solution out. Check returns for debris and dissolved pipe dope. Collect representative samples (Lab R&D will send technician).

iv) Pump 1000 gal of 15% HCl Acid Pickle solution with the following Halliburton additives:

Acid Pickle Formulation 442 gal Raw HCl (20 Be?) 20 gal HAI-85, Corrosion Inhibitor 55 lb HII-124C, Corrosion Inhibitor Intensifier 20 lb Fercheck, Iron Control 2.00 gal Losurf-300, Surfactant 536 gal Fresh Water

v) Displace acid with water ½ bbl short of Seal Assembly. Do not over displace.

vi) Reverse out the spent acid pickle from tubing until hole is clean. Note: All the above will be performed using the choke manifold holding back pressure.

R) Reverse circulate 240 bbl of diesel in tubing and 445 bbl of diesel

inhibited with 3% SA- 193 in TCA. Observe well for one hour.

Note: Pump + 50 bbl weighted (65 pcf) EZ-Spot spacer ahead of the diesel when reversing out. Formulate as follows: 25 bbl diesel + 20 bbl H20 + (3) 55 gal drums EZ-Spot.

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S) Sting back into packer and land tubing. Screw in the lock down screws on the tubing spool. Test tubing to 6,000 psi with diesel & monitor TCA for 10 minutes. Re-test the TCA to 6,000 psi and observe tubing for 10 minutes.

T) RU WL w/5M lubricator and test to 5000 psi with water. RIH and set “RO” plug in “R” nipple at + 2500’. POH and RD WL.

U) Install BPV in Tubing Hanger. ND BOPE. V) NU 11” 10M Tubing Bonnet with 5” 10M Manual Lower Master Valve

(MLMV gear box facing East with hand wheel facing North). NU 5” 10M Block Tree Assembly. Orientation of tree: Wing Valve to face East; Hydraulic actuator to face North and Tubing Kill Valve to face West (See Attachment). Pack off and test to 7500 psi with N2. Note: Have N2 unit with 4000 gal N2 available.

W) Secure well and release rig. 2.0 GENERALIZED RUNNING PROCEDURE FOR KHUFF PBR COMPLETION

COMPLETION PROCEDURE

After running & cementing the 7” liner w/PBR (AMS# 45696-060), proceed as follows:

A) RIH with 8-3/8” bit. Ta g top of cement. Clean out to 7” liner top @ ?9,410’

MD/9,256’ TVD. Check for flow. Test TOL and 9-5/8” casing to 145 pcf EMW (3,700 psi surface pressure with 88 pcf mud). POH.

B) RIH with 5-7/8” bit and drill out 7” liner to LC @ ?13,054’ MD/12,335’ TVD (PBTD). Test to 145 pcf EMW (4,920 psi with 88 pcf mud). Flush hole with High-Vis pill and circulate hole clean. Circulate well to water. Observe well for 1 hour. Pressure test well to 5000 psi with water.

Note: Exercise caution when entering the 7” liner top. RIH slowly inside 7” liner.

C) RIH with 5-7/8” bit, 7”, 35# scraper with 7”, 35# Hedge Hog brush and 9-5/8”, 53.5#

scraper w/9-5/8”, 53.5 # Hedge Hog brush to PBTD @ ?13,054’ MD (spaced out such that 9-5/8” scraper is at TOL when 5-7/8” bit is at PBTD). Circulate hole clean. Pump and circulate 25 gal of Rinse Aid mixed with 20 bbl of fresh water and circulate hole clean. Spot 140 bbl of 87 pcf saturated CaCl2 Brine (7” liner volume) on bottom. POH.

D) RIH with 7-23/32” polish mill and ream the TIW LG-12 TBR (12’ X 7.75” ID). POH. E) RIH with 6-15/32” polish mill and ream the TIW PBR (24’ X 6.5” ID). Observe well for

1 hour. POH & LDDP. F) Prior to running the 5-1/2” production tubing, ensure the following procedures have

been carried out: ?? Full Vetco inspection, including API drift, and hydroblast the tubing at the Vetco

Yard to remove any rust and scale build up.

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Perform the following pipe inspection on the racks at the rig site: ?? Clean the threads with nylon brush and cleaning solvent. ?? Visually inspect all threads. ?? Have Weatherford inspect and clean the threads prior to make-up.

G) Prior to RIH with tubing, install test plug and test tubing hanger bowl to 8,000 psi with water. Mark test assembly at rotary. Measure from this mark to bottom of test plug while POH to obtain accurate measurement from the rotary table to the tubing hanger bowl.

RIH with 5-1/2”, 20.0#, C-95, N-VAM completion tubing to top of packer PBR @ ?9,410’ as follows: A) TIW PBR Seal assembly, 24’ w/KTR seal (3 sets), 8.25” OD x 4.778” Min ID,

7”, +35#, N-Vam -MS Locator Box X 5.5”, 23# Spacer Bar, L-80 (H2S) - 10M. (AMS# 45-696-062).

B) 1 each X-Over, 7” 35#, L-80, N-VAM Pin X 5-1/2”, 20#, N-Vam L-80 Box. C) As required + 6,900’ 5-1/2”, 20 #, C-95 N-VAM tubing (AMS # 45-950-77-00) D) 1 each (6’) Flow Cplg; 5-1/2”, 23# C-95, N-VAM, Box X Pin (OD=6.098”,

ID=4.560”) (AMS#45-664-998) E) 1 each Halliburton “R” landing nipple, 23# N-Vam(OD=5.5”, ID=4.313”)

(AMS#45-717-310) F) 1 each (6’) Flow Cplg; 5-1/2, 23#, C-95 N-VAM. G) 2,500’ 5-1/2”, 20#, C-95 N-VAM tubing. H) 1 each Tubing Hanger; 11” x 5-1/2” 20# N-VAM P X ACME (AMS# 401-822-

45-9915-005).

Note: i) Have enough 5-1/2” 20# N-VAM pup joints for space out. ii) Optimum torque for 5-1/2” 20# N-VAM = 6,800 ft/lb. iii) Drift tubing with 4.653” x 3’ Drift every 2,000’ and @ landing depth. iv) Caliper “R” nipple before installing. v) Use Weatherford Lubeseal API modified tubing dope. Apply the dope to

the pin ends using paint brush. vi) Use Weatherford JAM service to run the tubing. vii) Pump 25 gallons of Rinse Aid mixed with 20 bbl of fresh water, followed

by 5 drums (6.55 bbl) of Super Pickle. viii) Displace the Super Pickle with water to the end of tubing.

Note: Avoid Super Pickle contact with PBR seals. ix) Reverse circulate at maximum rate. Check returns for debris and

dissolved pipe dope. Collect representative samples. x) Acid pickle the tubing string with 1,000 gal 15% HCl + additives.

Reverse circulate the hole until it is clean.

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Formulate Acid Pickle as follows: 442 gal Raw HCl (20 Be?) 20 gal HAI-85, Corrosion Inhibitor 55 lb HII-124C, Corrosion Inhibitor Intensifier 20 lb Fercheck, Iron Control 2.00 gal Losurf-300, Surfactant 536 gal Fresh Water

xi) Sting into the PBR seal assembly. Set down 10-15,000 lb of tubing

weight on PBR. The final space out measurement will be at Neutral Weight. Test the annulus to 5,000 psi. Bleed off pressure and mark tubing at the rotary (Mark - 1).

xii) PU and measure from the mark just made (Mark - 1), the distance from rotary table to the tubing hanger bowl. Mark the tubing at this point (Mark-2).

xiii) PU and measure the length between Mark - 2 and the next tubing collar below Mark - 2. This length less the length of the pup joint on the bottom of the tubing hanger will be the length of the pup joints needed for space out. Install two (2) joints below the tubing hanger.

xiv) Unsting from the PBR and reverse circulate 210 bbl diesel (one tubing volume) followed by 400 bbl diesel inhibited with 3% SA-193 (TCA volume). Observe well for one hour.

xv) Sting back into packer and land tubing. Screw in the lock down screws on the tubing spool. Test tubing to 5,000 psi with diesel & monitor TCA for 10 minutes. Re-test the TCA to 5,000 psi and observe tubing for 10 minutes.

xvi) RU WL w/5M lubricator and test to 5000 psi with water. RIH and set “RO” plug in “R” nipple at + 2500’. POH and RD WL.

xvii) Install BPV in tubing hanger. ND BOPE. xviii) NU 11”, 10M tubing bonnet with 5” MLMV. NU 5”, 10M production tree

with wing valve orientation to the EAST. Pack off & test to 7,500 psi with Nitrogen.

Note: Have Nitrogen unit with 4,000 gal N2 available.

xix) Secure well and release rig.

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TUBING DESIGN 1.0 SAUDI ARAMCO DESIGN FACTORS 2.0 DESIGN CONSIDERATIONS

2.1 Tubing Size Selection 2.2 Anticipated Production Rate 2.3 Nature of Produced Fluids 2.4 Accommodation of Through Tubing Tools 2.5 Economic Considerations 2.6 Tubular Availability

3.0 PICK-UP AND SLACK-OFF GUIDELINES

3.1 Tubing Movement and Force Analysis 3.1.1 Basic Pressure and Temperature Effects 3.1.2 Piston Effect 3.1.3 Pressure Buckling Effect 3.1.4 Ballooning Effect 3.1.5 Temperature Effect

3.2 Tubing Movement Formulas 4.0 SAUDI ARAMCO TUBING AND CASING TABLES 5.0 EXAMPLE TUBING MOVEMENT/FORCE PROBLEM

5.1 Landing Condition 5.2 Well Condition Prior to Acid Job 5.3 Acidizing Condition

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TUBING DESIGN 1.0 SAUDI ARAMCO DESIGN FACTORS

Tubing, like casing, must fulfill the design requirements dictated by the internal and external pressure loading conditions the tubing will be subjected to. In addition to satisfying the internal yield, collapse and tensile requirements the design must meet additional criteria. Saudi Aramco utilizes the same design factors for tubing as those used for casing which are:

Burst: 1.33 Collapse: 1.125 Tension: 1.6

2.0 DESIGN CONSIDERATIONS

2.1 Tubing Size Selection Since the tubing usually contains the production stream, it must be sized accurately. Several factors are considered when selecting the correct tubing size for a well. Some of the main factors are:

2.2 Anticipated Production Rate

The tubing must be of sufficient size to accommodate the expected production rate. Small tubing may cause high erosional velocities, a high pressure drop and low production rates. This is an important design consideration in high capacity reservoirs like those in Saudi Aramco.

2.3 Nature of Produced Fluids

In practice, oil wells produce fluids in either two-phase (oil/water or oil/gas) or three phase (oil/water/gas) flow. Gas wells can also carry liquid in the flow stream. These multi-phase flow regimes complicate the modeling of fluid flow in tubing strings. When wells become water-cut for example, the water may break out and load up in the tubing string if the fluid velocity is too low. A smaller tubing string may be required to maintain a higher fluid velocity to carry the water to surface. Tubing size selection requires several reservoir and production parameters as input to the calculations. Saudi Aramco uses a computer program called "Pipe-Flow" to accurately model these complicated production streams. It is extensively used by Saudi Aramco Production Engineering Departments to determine tubing sizes required for new wells and workover wells. To

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accurately calculate tubing size, it is recommended to review the "Pipe-Flow" program.

2.4 Accommodation of Through Tubing Tools

Another consideration is the minimum acceptable through-bore for survey, servicing, production logging and coiled tubing unit (CTU) operations. Slim logging tools are typically 1-11/16" in diameter and can be accommodated with 2-3/8" production tubing. However wells with special logging requirements, such as the 3-5/8" Carbon-Oxygen log or Induction log, need tubing strings sized large enough to accommodate them. Some wells may require landing nipples with no-go profiles which may further restrict through-bore diameter. It is therefore important to communicate with the production engineer to determine the size of tools which will be run in the well after the completion operation.

2.5 Economic Considerations

Larger tubing sizes typically cost more. An incentive toward smaller diameter tubing is the savings in tubular costs. Tubing sizes should be as small as practical, yet still fulfill the production requirements of the well.

2.6 Tubular Availability

Once the accurate tubing size is determined (4" tubing for example), it may be found that the particular tubing size is not available. Saudi Aramco maintains a stock of tubulars of standard sizes and are listed in Appendix A. Some tubulars may have been discontinued (at the time of this printing) and new ones may appear which are not on the list. An up-to-date Aramco Material Supply (AMS) list should be reviewed when checking tubular availability. If the exact size tubing is not available, then either one size smaller or larger must be chosen. Since 4" tubing is not an Aramco stock item, then either 3-1/2" or 4-1/2" must be chosen. The 3-1/2" or 4-1/2" tubing may also be out of stock, further restricting the choice of tubulars available. It is therefore important to determine the size of tubulars required (and what tubulars are available) well in advance of any drilling or workover project. For new wells, once the tubing size is selected, the outer casing sizes may then be determined to accommodate the tubing. For older existing wells, the casing size frequently dictates the maximum tubing size which can be run in the well. Wells completed with 4-1/2" casings are very limited as to the size of tubing which can be run.

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3.0 PICK-UP AND SLACK-OFF GUIDELINES

3.1 Tubing Movement and Force Analysis

The typical Saudi Aramco oil producers have standard tubing landing procedures which accommodate anticipated tubing movement and forces. However, in extraordinary circumstances all possible conditions may need to be reviewed when designing tubing strings. For example, high internal pressure loading may be caused by several different well pressures such as producing, shut-in, stimulation treatments, testing, well killing operations (bull heading), artificial lift operations, etc. In addition to pressure forces, thermal forces may elongate or shrink the tubular beyond acceptable limits. This section wi ll review the basics of tubing movement and force analysis. When the completion tubing is spaced-out and landed, the conditions affecting the tubing and packer are known. These conditions include tubing size and length, casing size, fluid inside and outside the tubing, temperatures, surface pressures and any mechanical forces applied. This point is used as a "reference point" to calculate the changes in forces and length for future conditions. In a tubing string, sealed off in a packer, there are four factors that cause length and force changes. These factors are dependent on well conditions, tubing/packer/casing configuration, and tubing restraint. Each factor acts independently and may either add to or cancel the effects of the other factors. Therefore it is important to keep the direction of the length changes and forces correct. Furthermore, mechanically applied tension or compression may be used to negate the combined effect of the pressure and temperature changes.

3.1.1 Basic Pressure and Temperature Effects

The four pressure and temperature effects which should be investigated for future well operating conditions are:

3.1.2 Piston Effect

Changes in pressure at the packer act on the inside and outside piston areas to produce length and force changes. These changes may be either up or down depending on the tubing/packer configuration.

3.1.3 Pressure Buckling Effect

Changes in pressure that cause a higher pressure inside the tubing than outside, at the packer, cause pressure buckling. Pressure buckling is a shortening of the effective length of the tubing string because the tubing bends into a spiral (or helix) within the casing. It can only shorten the tubing and only exerts a negligible force.

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Although pressure buckling and mechanical buckling appear to have the same mechanics, they must be considered separately as they are produced by completely different factors

3.1.4 Ballooning Effect

Changes in average pressure cause a radial swelling (ballooning) or contraction (reverse-ballooning) and a corresponding shortening or lengthening of the tubing string.

3.1.5 Temperature Effect

Changes in the average temperature of the tubing string cause thermal expansion or contraction of the tubing. Thermal forces are prominent in tubing strings in deep hot wells such as the Khuff gas wells.

3.2 Tubing Movement Formulas

The terms and simplified formulas for calculating tubing movement are given below. These formulas give the length and force changes for common wells of one tubing and one casing size. More than one tubing or casing size requires that the calculations be made on each section and combined for a final condition. Length changes are in feet and force changes are in pounds. The terms in each of the equations are defined in the following section "Length and Force Terms".

Piston Effect

a) Length change The length change due to the piston effect ? L1 , is expressed with the following formula:

_____________(1)

b) Force change

The force change due to the piston effect is expressed as follows:

_______________________(2)

Pressure Buckling Effect a) Length change

The length change due to the pressure buckling effect is expressed with the following formula

(only if ? Pi is greater than ? Po ):

? ?? ? ?L LEA

A A P A A PS

p i i p o o1 ? ? ? ? ?? ? ? ?

F A A P A A Pp i i p o o1 ? ? ? ?? ? ? ?? ?

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_________________________(3)

b) Force change The force change is negligible since this effect mainly shortens the tubing. Ballooning Effect

a) Length change The length change due to the ballooning effect is expressed as follows:

_________________________(4)

b) Force change The force change due to the ballooning effect is expressed as follows:

_______________________(5)

Temperature Effect

a) Length change The length change due to the temperature effect is expressed as follows:

_______________________(6)

b) Force change The force change due to the temperature effect is expressed as follows:

_______________________(7)

Since the stresses involved with tubing movement are three dimensional and require complex calculations, the formulas for stress are not included.

Length and Force Terms

L = Depth, feet

E = Modulus of elasticity, psi (30 x 106 psi for steel)

As = Cross-sectional area of the tubing wall, sq. in.

A p = Area of packer ID, sq. in.

A i = Area of tubing ID, sq. in.

A o = Area of tubing OD, sq. in.

? Pi = Change in tubing pressure at the packer, psi.

? Po = Change in annulus pressure at the packer, psi

?? ?

Lr A P P

EI W W Wp i o

s i o

2

2 2 21 5?

? ?

? ?

? ? ?

? ?

?? ?

LL

E

P R P

Ria oa

3

2

2

2

1?

? ?

?

?

???

?

???

?

F P A P Aia i oa o3 0 6? ? ?? ? ?? ?

? L L T4 ? ??

F A Ts4 207? ?

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? Pia = Change in average tubing pressure, psi

? Poa = Change in average annulus pressure, psi

? T = Change in average tubing temperature, oF

r = Radial clearance between tubing OD and casing ID, inches

l = Moment of inertia of tubing about its diameter

=

?64

4 4? ?D Do i? where Do is outside diameter and D i is inside diameter

Ws = Weight of tubing, lb/ft

Wi = Weight of fluid in tubing, lb/ft

Wo = Weight of displaced fluid, lb/ft

R = Ratio of tubing OD to ID

? = Coefficient of thermal expansion (6.9 x 10-6 in/in/oF for steel)

? = Poisson's ratio (0.3 for steel)

Sign Convention In tubing movement and force calculations it is important to be consistent with the sign conventions (positive or negative numbers) used in the formulas and calculation results. For example, if a negative length change occurred, does that mean the tubing moved upward or downward? If a positive force change occurred, does that mean the tubing is in tension or compression? The following sign conventions are used by the majority of the industry:

A) Length Changes Negative length changes refer to the upward tubing movement Positive length changes refer to the downward tubing movement

B) Force Negative forces refer to tension Positive forces refer to compression

C) Pressure Changes Negative pressure changes refer to pressure reduction Positive pressure changes refer to pressure increase

P = Pfinal - Pinitial

D) Temperature Changes Negative temperature changes refer to temperature reduction Positive temperature changes refer to temperature increase

T = Tfinal - Tinitial

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4.0 SAUDI ARAMCO TUBING AND CASING TABLES

Table 4D-1 RECOMMENDED MAKE-UP TABLE SAUDI ARAMCO NON-PREMIUM CASING/TUBING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

CONDUCTOR CASING 48” 0.500" wt. 253.65# GR-B, R-3, BE - WELD - 36” 0.625" wt. 236.15# GR-B, R-3, BE - WELD -

30” 0.500" wt. 157.50# X-42, 55/60', SJ - WELD - 30” 0.750" wt. 234.30# X-42, 55/50', SJ - WELD - 30” 0.750" wt. 239.00# X-42, 55/60', JV-LW 26,000 29,000 32,000 24” 97.00# GR-B, R-3, SJ - WELD - ? 24” 0.688” wt. 176.00# X-42, R-3, V-LS 24,000 26,000 28,000 24” 0.688” wt. 176.00# X-42, R-3, V-RL4S 24,000 26,000 28,000 CASING and TUBING 18-5/8” 87.50# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 18-5/8” 115.00# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

13-3/8” 61.00# J-55, R-3, STC 4,460 5,950 7,440 13-3/8” 61.00# K-55, R-3, STC 4,750 6,330 7,910 13-3/8” 68.00# K-55, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 13-3/8” 72.00# L-80, R-3, STC 7,720 10,290 12,860 13-3/8” 72.0 0# S-95, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

9-5/8” 36.00# J-55, R-3, LTC 3,400 4,530 5,660 9-5/8” 36.00# K-55, R-3, LTC 3,670 4,890 6,110 9-5/8” 40.00# J-55, R-3, LTC 3,900 5,200 6,500 9-5/8” 40.00# K-55, R-3, LTC 4,210 5,610 7,010 9-5/8” 40.00# L-80, R-3, LTC 5,450 7,270 9,090 9-5/8” 43.50# L-80, R-3, LTC 6,100 8,130 10,160 9-5/8” 47.00# L-80, R-3, LTC 6,700 8,930 11,160 9-5/8” 53.50# S-95, R-3, BTC Base of Triangle Base of Triangle Base of Triangle

7” 23.00# J-55, R-3, LTC 2,350 3,130 3,910 7” 26.00# J-55, R-3, LTC 2,750 3,670 4,590 7” 26.00# K-55, R-3, LTC 3,010 4,010 5,010 7” 26.00# K-55, R-3, NVAM 6,510 7,230 7,950 ? 7” 26.00# K-55, R-3, OLD VAM 8,000 8,700 10,100

5” 15.00# K-55/L-80, R-3, BTC Base of Triangle Base of Triangle Base of Triangle 4-1/2” 11.60# J-55, R-3, STC 1,160 1,540 1,930

4-1/2” 11.60# L-80, R-3, LTC 1,670 2,230 2,790 4-1/2” 11.60# J-55, R-3, OLD VAM 4,300 4,700 5,100 ? 4-1/2” 12.60# J-55, R-2, NVAM 3,190 3,540 3,890 ? 4-1/2” 12.60# J-55, R-3, OLD VAM 4,300 4,700 5,100 4-1/2” 12.60# L-80-13CR, R-3, FOX - 4,120 -

3-1/2” 9.30# J-55, R-2, EUE 1,710 2,280 2,850 2-7/8” 6.50# J-55, R-2, EUE 1,240 1,650 2,060 2-3/8” 4.70# J-55, R-2, EUE 970 1,290 1,610

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SAUDI ARAMCO Table 4D-2 PREMIUM CASING and TUBING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

? 13-3/8” 72.00# C -95VT/ SM-95T, R-3, NVAM 14,400 15,900 17,400 13-3/8” 72.00# NKHC-95, R-3, NK-3SB 16,000 20,000 24,000 13-3/8” 72.00# NT-95HS, R-3, NS-CC 13,100 14,800 16,600 ? 13-3/8” 86.00# C -95VT/ SM-95T, R-3, NVAM 14,400 15,900 17,400 13-3/8” 86.00# NKHC-95, R-3, NK-3SB 16,000 20,000 24,000 13-3/8” 86.00# NT-95HS, R-3, NS-CC 13,100 14,800 16,600 ? 9-5/8” 53.50# C-95VTS/SM-95TS, R-3, NVAM 14,400 15,900 17,400 9-5/8” 53.50# NKAC-95T, R-3, NK-3SB 13,200 16,500 19,800 9-5/8” 53.50# NT-90HSS, R-3, NS-CC 9,500 10,800 12,300 ? 9-5/8” 58.40# P-110VT/ SM-110T, R -3, NVAM 14,400 15,900 17,400 9-5/8” 58.40# NKHC-110, R-3, NK-3SB 14,400 18,000 21,600 9-5/8” 58.40# NT-105HS/-110HS, R-3, NS-CC 10,200 11,700 13,300 ? 7” 26.00# K-55, R-2, NVAM 6,510 7,230 7,950

? 7” 32.00# C-95VTS/ SM-95TS, R-3, NVAM 9,850 10,850 11,850 7” 32.00# NKAC-95T, R-3, NK-3SB 8,800 11,000 13,200 7” 32.00# NT-95HSS, R-3, NS-CC 6,600 7,600 8,600 ? 7” 35.00# L-80, R-3, NS-CC 6,900 8,000 9,000 ? 7” 35.00# L-80, R-3, NK-3SB 9,600 12,000 14,400 ? 7” 35.00# L-80, R-3, NVAM MS 9,500 10,500 11,500 ? 7” 35.00# L-80, R-3, HYDRIL SUPER-EU 8,500 9,560 10,625 ? 7” 35.00# L-80, R-3, AB IJ-4S - 10,000 - ? 5-1/2” 20.00# C-95VTS/SM-95TS, R -3, NVAM 6,120 6,800 7,480 5-1/2” 20.00# NKAC-95T, R-3, NK-3SB 5,760 7,200 8,640 5-1/2” 20.00# NT-95HSS, R-3, NS-CC 5,100 5,900 6,800 ? ? 5-1/2” 23.00# L-80, R-3, NVAM 7,170 7,960 8,750

? 4-1/2” 12.60# J-55, R-2, NVAM 3,190 3,540 3,890 ? 4-1/2” 13.50# L-80, R-3, NVAM 4,430 4,920 5,410 ? 4-1/2” 13.50# C-95VTS/ SM-95TS, R-3, NVAM 5,080 5,640 6,200 4-1/2” 13.50# NKAC-95T, R-3, NK-3SB 3,520 4,400 5,280 4-1/2” 13.50# NT-95HSS, R-3, NSCT 2,900 3,600 4,300 ? 4-1/2” 13.50# KO-105T, R-3, HTS 4,200 4,725 5,250 ? ? 4-1/2”15.10# L-80, R-3, NVAM 5,210 5,790 6,370 3-1/2” 12.95# L-80, R-2, HYDRIL PH-6 5,500 6,185 6,875

2-7/8” 6.40# J-55, R-2, NSCT-SC 1,160 1,340 1,520 2-7/8” 8.70# L-80, R-2, HYDRIL PH-6 3,000 3,375 3,750

? 2-3/8” 4.70# L-80, R-2, AB FL-4S - 500 - 2-3/8” 4.70# L-80, R-2, HYDRIL CS 1,500 1,685 1,875 2-3/8” 5.80# L-80, R-2, NVAM 1,500 1,660 1,820 2-3/8” 5.90# L-80, R-2, HYDRIL PH-6 2,200 2,475 2,750 Note: ? Tubulars that are being phased out.

? Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]. The use of a make-up monitoring system (Jam, Torque/Tu rn, etc.) should be used on all production

tubing strings with specialty connections to ensure a more accurate make-up.

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Table 4D-3 - SAUDI ARAMCO NON-PREMIUM TUBING & CASING DATA

SIZE WEIGHT GRADE CONNECTION I.D. DRIFT CONN. O.D. BURST COLLAPSE JT/ YLD STRENGTH

in. ppf in. in. in. psi psi 1,000's lbs.

24 97.00 B SJ 23.25 - - - - - 24 176.00 X-42 VETCO-LS 22.624 22.250 25.500 2170 1080 2,116

18-5/8 87.50 J-55 BTC 17.755 17.567 19.625 2250 630 1,329 18-5/8 87.50 K-55 BTC 17.755 17.567 19.625 2250 630 1,367

13-3/8 61.00 J-55 STC 12.515 12.359 14.375 3090 1540 595 13-3/8 61.00 K-55 STC 12.515 12.359 14.375 3090 1540 633 13-3/8 68.00 J-55 STC 12.415 12.259 14.375 3450 1950 675 13-3/8 68.00 K-55 STC 12.415 12.259 14.375 3450 1950 718 13-3/8 68.00 J-55 BTC 12.415 12.259 14.375 3450 1950 1,069 13-3/8 68.00 K-55 BTC 12.415 12.259 14.375 3450 1950 1,069 13-3/8 72.00 L-80 STC 12.347 12.191 14.375 4550 2670 1,040 13-3/8 72.00 S-95 BTC 12.347 12.250 14.375 4930 * 3470 1,935

9-5/8 36.00 J-55 LTC 8.921 8.765 10.625 3520 2020 453 9-5/8 36.00 K-55 LTC 8.921 8.765 10.625 3520 2020 489 9-5/8 40.00 J-55 LTC 8.835 8.679 10.625 3950 2570 520 9-5/8 40.00 K-55 LTC 8.835 8.679 10.625 3950 2570 561 9-5/8 40.00 L-80 LTC 8.835 8.679 10.625 5750 3090 727 9-5/8 40.00 13CR L-80 LTC 8.835 8.679 10.625 5750 3090 727 9-5/8 43.50 L-80 LTC 8.755 8.599 10.625 6330 3810 813 9-5/8 47.00 L-80 LTC 8.681 8.525 10.625 6870 4760 893 9-5/8 53.50 S-95 BTC 8.535 8.500 10.625 9160 * 8850 1,477

7 23.00 J-55 STC 6.366 6.241 7.656 4360 3270 284 7 26.00 J-55 LTC 6.276 6.151 7.656 4980 4320 367 7 26.00 K-55 LTC 6.276 6.151 7.656 4980 4320 401 7 26.00 J-55 VAM 6.276 6.151 7.681 4980 4320 415 7 26.00 K-55 VAM 6.276 6.151 7.681 4980 4320 415 7 26.00 J-55 NVAM 6.276 6.151 7.681 4980 4320 415 7 26.00 K-55 NVAM 6.276 6.151 7.681 4980 4320 415 7 26.00 13CR L-80 LTC 6.276 6.151 7.656 7240 5410 511 7 35.00 L-80 LTC 6.004 5.879 7.656 9240 10180 734 7 35.00 L-80 VAM 6.004 5.879 7.681 9960 10180 725

5 15.00 K-55 Spec. Cl. BTC 4.408 4.283 5.375 5130 5560 241 5 15.00 13CR L-80 Spec. Cl. BTC 4.408 4.283 5.375 7460 7250 350

4-1/2 11.60 J-55 STC 4.000 3.875 5.000 5350 4960 154 4-1/2 11.60 J-55 LTC 4.000 3.875 5.000 5350 4960 162 4-1/2 11.60 13CR L-80 LTC 4.000 3.875 5.000 7780 6350 212 4-1/2 12.60 J-55 VAM 3.958 3.833 4.892 5790 5720 198 4-1/2 13.50 L-80 VAM 3.920 3.795 4.862 8540 9020 211

NOTE:

[1] Internal yield values (*) listed above reflect the lower value for buttress couplings. [2] Value provided is the minimum value, either pipe body strength or joint strength.

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Table 4D-4 - SAUDI ARAMCO PREMIUM TUBING AND CASING DATA

SIZE WEIGHT GRADE CONN LENGTH wt. I.D. DRIFT CONN. O.D. BURST COLLAPSE JT/ YLD STRENGTH

in. ppf range in. in. in. in. psi psi 1,000's lbs.

48 253 B BE 40’ 0.500 47.000 - 48.000 - - - 36 236 X-60 BE 40' 0.625 34.750 - 36.000 1822 254 - 30 234 X-42 SJ 55-60' 0.750 28.500 - - 1890 768 - 24 176 X-42 LS R-3 0.688 22.624 22.250 25.500 2170 1080 2,116 24 176 X-42 RL-4S R-3 0.688 22.25 (con) 22.125 25.250 2170 1080 2,116

18-5/8 115 K-55 BTC R-3 0.594 17.437 17.249 20.000 3070 1511 1,850

13-3/8 72 S-95 BTC R-3 0.514 12.347 12.250 14.375 4930 * 3470 1,935 13-3/8 72 NT-95HS NS-CC R-3 " " " 14.375 6390 3680 1,935 13-3/8 72 C-95VT N-VAM R-3 " " " 14.398 6390 3900 1,935 13-3/8 72 SM-95T N-VAM R-3 " " " 14.398 6390 3680 1,935 13-3/8 72 NKHC-95 NK-3SB R-3 " " " 14.375 6390 3890 1,973

13-3/8 86 NT-95HS NS-CC R-3 0.625 12.125 12.000 14.375 7770 6260 2,333 13-3/8 86 C-95VT N-VAM R-3 " " " 14.398 7770 6560 2,333 13-3/8 86 SM-95T N-VAM R-3 " " " 14.398 7770 6240 2,333 13-3/8 86 NKHC-95 NK-3SB R-3 " " " 14.375 7760 6500 2,333

9-5/8 53.5 S-95 BTC R-3 0.545 8.535 8.500 10.625 9160 * 8850 1,477 9-5/8 53.5 NT-90HSS NS-CC R-3 " " " 10.625 8920 9330 1,386 9-5/8 53.5 C-95VTS N-VAM R-3 " " " 10.650 9410 8960 1,477 9-5/8 53.5 SM-95TS N-VAM R-3 " " " 10.650 9410 9350 1,477 9-5/8 53.5 NKAC-95T NK-3SB R-3 " " " 10.625 9410 8940 1,477

9-5/8 58.4 NT-

105HSS NS-CC R-3 0.595 8.435 8.375 10.625 11900 12050 1,739

9-5/8 58.4 NT-110HS NS-CC R-3 " " " 10.625 11960 12870 1,857 9-5/8 58.4 P-110VT N-VAM R-3 " " " 10.650 11900 11880 1,857 9-5/8 58.4 SM-110T N-VAM R-3 " " " 10.650 11900 12800 1,857 9-5/8 58.4 NKHC-110 NK-3SB R-3 " " " 10.625 11900 12860 1,857

7 32 NT-95HSS NS-CC R-3 0.453 6.094 6.000 7.656 10760 11380 885 7 32 C-95VTS NVAM-MS R-3 " " " 7.732 10760 11160 885 7 32 SM-95TS NVAM-MS R-3 " " " 7.732 10760 11190 885 7 32 NKAC-95T NK-3SB R-3 " " " 7.772 10760 11150 885

? 7 35 L-80 NS-CC R-3 0.498 6.004 5.879 7.656 9960 10180 814

? 7 35 L-80 NVAM-MS R-3 " " " 7.805 9960 10180 814

? 7 35 L-80 NK-3SB R-3 " " " 7.772 9960 10180 814

? 5-1/2 23 L-80 N-VAM Tbg. Hngr 0.415 4.670 4.545 6.075 10560 11160 478

5-1/2 20 NT-95HSS NS-CC R-3 0.361 4.778 4.653 6.050 10910 11580 554 5-1/2 20 C-95VTS N-VAM R-3 " " " 6.075 10910 11410 554 5-1/2 20 SM-95TS N-VAM R-3 " " " 6.075 10910 11450 554 5-1/2 20 NKAC-95T NK-3SB R-3 " " " 6.050 10910 11400 554

? 4-1/2 15.1 L-80 N-VAM Tbg. Hngr 0.337 3.826 3.701 5.010 10480 11080 353

4-1/2 13.5 NT-95HSS NS-CC R-3 0.290 3.920 3.795 5.000 10710 11330 364 4-1/2 13.5 C-95VTS N-VAM R-3 " " " 4.961 10710 11090 364 4-1/2 13.5 SM-95TS N-VAM R-3 " " " 4.961 10710 11120 364 4-1/2 13.5 NKAC-95T NK-3SB R-3 " " " 5.000 10710 11080 364 4-1/2 13.5 L-80 N-VAM R-3 0.290 3.920 3.795 4.961 9020 8540 307 4-1/2 13.5 D-95HC HYDRIL TS R-3 " " " 4.719 10720 12070 300

? 4-1/2 13.5 KO-105T HYDRIL TS R-3 " 3.840(con) " " 10710 11280 295

3-1/2 12.95 L-80 HYDRIL PH -6 R-2 0.375 2.687(con) 2.625 4.313 15000 15310 295

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______________________________________________________________________________________ 11 of 19

NOTE: [1] Internal yield values (*) listed above reflect the lower value for buttress couplings. [2] Value provided is the minimum value, either pipe body strength or joint strength. [3] The RL-4S connector ID is less than that of the LS connector (RL-4S = 22.250” ID, LS = 22.624” ID) .

[4] The Hydril PH-6 connector ID is less than that of the pipe body (Conn. = 2.687” ID, Body = 2.750” ID)

? Tubulars that are being phased out. ? Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]

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5.0 EXAMPLE TUBING MOVEMENT / FORCE PROBLEM

The following example takes a typical Saudi Aramco oil producer and calculates the tubing movements and forces which result when the well is acidized. It is provided here to show how the basic tubing movement and force equations are used. It does not cover the three dimensional (or triaxial) stresses since these equations are very complicated12. Acidization is one of the most stressful operations performed on a well. If not designed properly the well could be damaged to the point that an expensive workover is required to repair it. High surface pumping pressures balloon the tubing, causing it to contract, or shrink. Since the acid is normally pumped at ambient temperature, it is much cooler than the fluid (oil or gas) which was originally in the tubing. This causes the tubing to shrink due to thermal contraction. A combination of these movements, if large enough, may cause the tubing to disengage or "unsting" from the packer allowing the acid, the wellhead injection pressure and subsequent production fluid to be in contact with the tubing/casing annulus. In older wells, it may be possible that the seal assembly is stuck in the packer, not allowing the free movement of the seals in the seal bore extension. Since the tubing cannot move, tensile forces are imparted to the tubing string. These forces, if high enough, may part the tubing. The piston effect at the packer also plays a role in tubing movement and forces, depending on the tubing and packer configuration. Three basic well conditions are reviewed:

5.1 Landing Condition:

This condition describes the well when the tubing string was initially installed or landed. For this example the following landing conditions, typical of Saudi Aramco onshore oil producers will be used (refer to Figure 11 for the well cross section): ?? Production casing is 7" 26# J-55 (6.276" ID from casing tables) ?? Production tubing is 4-1/2" 12.6# J-55 VAM (3.958" ID from tubing

tables) ?? Packer depth is 7000' ?? Packer seal bore is 4.00" in diameter and is 12' long

1 Two classic papers have been presented on this subject:

- D. J. Hammerlindl (Arco) "Movement, Forces and stress Associated with Combination Tubing Strings Sealed with Packers" published in JPT February, 1977.

- Arthur Lubinski (Amoco) et al "Helical Buckling of Tubing Sealed in Packers" JPT June, 1962. 2 Saudi Aramco maintains an in-house computer program called the "Tubing Distortion Program" which

can be accessed on the mainframe by selecting ISPF option P.6.25. It calculates tubing movement, forces and triaxial stresses. It was developed by Allen Blanke during the Khuff drilling campaign in 1984 for the Khuff gas completions.

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?? Seal assembly spaced out 3' ?? Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) ?? Tubing fluid is diesel (51 pcf) ?? Shut in tubing pressure (SITP) = 0 psi ?? Shut in casing pressure (SICP) = 0 psi ?? Wellhead temperature = 80 oF ?? Bottom hole (stabilized) temperature = 220 oF

5.2 Well Condition Prior to Acid Job:

This condition describes the well before the acid job. It is provided as background information and is not used in the calculations: ?? Inhibited diesel packer fluid (51 pcf) ?? Tubing fluid is oil and gas (~53 pcf) ?? Shut in tubing pressure (SITP) = 400 psi ?? Shut in casing pressure (SICP) = 0 psi ?? Wellhead temperature = 80 oF ?? Bottom hole temperature = 220 oF

5.3 Acidizing Condition:

This condition describes the well during the acid job. Refer to Figure below. ?? Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) ?? Tubing fluid is 15% HCl acid (67 pcf) ?? Tubing injection pressure (TIP) = 3000 psi ?? Shut in casing pressure (SICP) = 500 psi ?? Wellhead temperature = 80 oF ?? Bottom hole temperature = 100 oF

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Assignment of Length and Force Terms:

The length and force change terms (as defined in the previous section) can be defined as follows:

L = Depth

= 7000'

E = 30 x 106 psi (Modulus of elasticity for steel)

As = Cross-sectional area of the tubing wall

INJECTION PRESSURE3000 PSI

CASING PRESSURE500 PSI

FROM PUMPER TRUCKS

4-1/2" PRODUCTION TUBING

7" PRODUCTION PACKER @ 7000'

7" PRODUCTION CASING

6-1/8" OPEN HOLE

TYPICAL SAUDI ARAMCO ONSHORE OIL PRODUCER

FIGURE 11

INHIBITED DIESEL TUBING-CASINGANNULUS FLUID (51 PCF)

15% HCl ACID (67 PCF)

with 4.00" SEAL BORE EXTENTION

(26# J-55)

(12.6# J-55 VAM)

WELLHEAD

(TUBING MOVEMENT / FORCES EXAMPLE)

3-1/2" TAILPIPE

4-1/2" X 3-1/2" CROSSOVERABOVE PACKER

FIGURE 4D-1

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= ?4

4 5 3 9582 2? ? ? ??

= 3.6 sq. in. A p = Area of packer ID

= ?4

4 002? ?

= 12.56 sq. in.

A i = Area of tubing ID

= ?4

3 9852? ?

= 12.47 sq. in.

A o = Area of tubing OD

= ?4

4 52? ?

= 15.90 sq. in.

? Pi = Change in tubing pressure at the packer

= change in hydrostatic pressure + change in wellhead pressure

= ? ?67 51

1447000 3000

??

?

???

?

???

?

= 3778 psi

? Po = Change in annulus pressure at the packer

= change in hydrostatic pressure + change in wellhead pressure

= 0 + 500

= 500 psi

? Pia = Change in average tubing pressure

= avg. tubing press while acidizing - avg. initial tubing condition press

= ? ? ? ?BH press surf press BH press surf pressacidizing acidizing initial initial? ? ? ? ? ? ? ??

??

2 2

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______________________________________________________________________________ 16 of 19

=

67

1447000 3000 3000

2

51

1447000 0 0

2

? ??

??

?

?? ?

?

???

?

???

?

? ??

??

?

?? ?

?

???

?

???

= 3389 psi

? Poa = Change in average annulus pressure

= avg. annulus press while acidizing - avg. initial annulus condition press

=

51

1447000 500 500

2

51

1447000 0 0

2

? ??

??

?

?? ?

?

???

?

???

?

? ??

??

?

?? ?

?

???

?

???

= 500 psi

? T = Change in average tubing temperature

= avg. tubing temp while acidizing - avg. initial tubing condition temp

= ? ? ? ?BH temp surf temp BH temp surf tempacidizing acidizing initial initial? ? ? ? ? ? ? ??

??

2 2

= ? ? ? ?100 80

2

220 80

2

??

?

= -60 oF

r = Radial clearance between tubing OD and casing ID

= (6.276" - 4.5")/2

= 0.888"

I = Moment of inertia of tubing about its diameter

=

?64

4 4? ?D Do i? where Do is outside diameter and D i is inside diameter

= ?64

4 5 3 9584 4? ? ? ??

= 8.08 in.

Ws = Weight of tubing

= 12.6 lb/ft

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Wi = Weight of fluid in tubing

= Acid Wt A i?

144

= 67 12 47

144? ?

= 5.8 lb/ft

Wo = Weight of displaced fluid

= Diesel Wt Ao?

144

= 51 15 9

144? ?

= 5.6 lb/ft

R = Ratio of tubing OD to ID

= 4.5/3.958

= 1.14

? = Coefficient of thermal expansion for steel

= 6.9 x 10-6 in/in/oF ? = Poisson's ratio for steel

= 0.3

Substitution of Length and Force Terms into Equations

1. Piston Effect

a) Length change

? L1 = ? ?? ? ? ?LEA

A A P A A PS

p i i p o o? ? ? ?? ?

= ? ??? ?

? ? ?7000

30 10 3 612 56 12 47 3778 12 56 15 90 500

6 ?? ? ? ? ? ? ? ?

= -0.13' (upward since the answer is negative)

b) Force change

F1 = ? ? ? ?A A P A A Pp i i p o o? ? ?? ?

= (12.56-12.47)3778-(12.56-15.90)500

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= +340 psi (tubing side) +1670 psi (annular side) = +2010 psi (compression since the answer is positive)

2. Pressure Buckling Effect a) Length change

Since ? Pi (3778 psi) is greater than ? Po (500 psi) the length change due to buckling is

b) Force change The force change is negligible since this effect mainly shortens the tubing.

3. Ballooning Effect

a) Length change

b) Force change

F3 = -0 6? ? ?? ?P A P Aia i oa o?

= -0 6 3389 12 47 500 15 90? ? ? ? ?? ? ? = -20,586 lb (tension since the sign is negative)

4. Temperature Effect

a) Length change

? L 2 = ? ?

? ?

r A P P

EI W W Wp i o

s i o

2 2 2

8

? ?

? ?

? ?

= ? ? ?

? ? ? ? ?

0 888 12 56 3778 500

8 30 10 8 08 12 6 5 8 5 6

2 2 2

6

? ? ? ?

? ? ? ? ? ?

= -0.053' (or 0.64" upward since the sign is negative)

? L 3 = ? ?

?

?

???

?

???

2

1

2

2

L

E

P R P

Ria oa? ? ?

= ? ? ?

?

? ?

?

?

???

?

???

2 7000 0 3

30 10

3389 114 500

114 16

2

2

? ?

?

= -1.28' (upward since the sign is negative)

? L 4 = L T? ?

= 7000 6 9 10 606? ? ? ??? ? ? = -2.90' (upward since the sign is negative)

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b) Force change

F4 = 207A Ts?

= 207 3 6 60? ? ?? ? ? = -44,712 lb (tension since the sign is negative)

Summation of Movements and Forces

The total movement of the tubing string is summarized by the following table. Since the summation of each effect results in a negative number, the movement is upward.

Table 4D-5

Movement (ft) Piston Effect - 0.13 Pressure Buckling Effect - 0.05 Ballooning Effect - 1.28 Temperature Effect - 2.90 TOTAL - 4.36

If the tubing seal assembly was not allowed to move or if the seals were anchored into the production packer, a tubing to packer force would be exerted. This force would be the sum of all the individual forces as shown by the following table. Since the answer is a negative number, the force is tensile.

Table 4D-6

Force (lbs) Piston Effect + 2010 Pressure Buckling Effect (negligible) Ballooning Effect - 20586 Temperature Effect - 44712 TOTAL - 63288

Page 409: Saudi Aramco - WorkOver Manual

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CHAPTER 5 WIRELINE LOGGING AND EXPLOSIVES

SECTION A ELECTRIC LOGGING ___________________________________________________________________________________________________________________________

LECTRIC LOGGING 1.0 INTRODUCTION 2.0 OPEN AND CASED HOLE LOGS

2.1 PDIL/MSFL/CAL OR DPIL/MLL/CAL 2.2 LDT/CNL/GR/CAL OR ZDL/CN/GR/CAL 2.3 FMI RO STAR 2.4 ATI/MSFL/SP/CAL/DSI-SONIC OR HDIL/MLL/SP/CA/MAC 2.5 CSI-Sidewall Core Gun 2.6 Induction/DLL 2.7 Cross-reference of Selected SCHLUMBERGER and WESTERN

ATLAS Logs. 3.0 MISCELLANEOUS LOGGING SERVICES

3.1 Sidewall Core Guns 3.2 Borehole Profile and Cement Volume Log 3.3 Flowmeter/Gradio/FCAP/CAL/HRT 3.4 Others

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ELECTRIC LOGGING 1.0 INTRODUCTION

1.1 Schlumberger and Western Atlas are on contract to Saudi Aramco to provide all electric logging services, with and without a rig on the well. Both companies have the basic and somewhat comparable logging tools. Each company also provides unique specialty logging services with the provision that some of the tools have to be brought into the Kingdom on short notice. The electric logging requirements for all rigs are split between the two Service Companies such that each is assigned or responsible for all the logging work on a particular rig. If the situation arises where the rig-assigned Service Company cannot meet its obligation to log a well for any reason, then the Foreman has the option to call on the other Service Company.

1.2 It is important for the Workover/Drilling Foreman to give ample advanced

notice to the Service Companies when requesting logging service. Ten to twelve-hour notice is not uncommon since the tools have to be inspected and functionally tested prior to usage. For specialty tools and services, notification should be made weeks or even months in advance to insure availability when needed.

2.0 OPEN AND CASED HOLE LOGS

Cased hole logs are usually run in wells during workover operations to obtain information about the reservoir, tubulars, aquifers, or to assist in resolving a downhole problem. Open hole logs may also be required on re-entry sidetracks or re-logging open hole completions. These logs are run individually or in combination, depending on the type of information desired. The logging program is included in every drilling program, as dictated by Reservoir Engineering and Geology Department. Open hole logging tools are commonly run in combination. These logs are usually run from total depth (TD) to between 50’ and 100’ above the 7” liner shoe. The following sections, 2.1 through 3.4, list the most common combination of logs run in Saudi Aramco during drilling operations.

2.1 PDIL/MSFL/CAL or DPIL/MLL/CAL

2.1.1 PDIL or PI (Schlumberger’s Phasor Induction) or DPIL (Western

Atlas’s Dual Phase Induction Log). This log measures formation

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resistivity/conductivity with three depths of investigation. This means that the undisturbed formation can be measured even in the presence of deep invasion. Main applications of the tool include:

A) Correlation and reservoir modeling. B) Filtrate invasion Profiles. C) Formation evaluation, including hydrocarbon/water contact. D) Thin bed resolution. E) Interpretation of deeply invaded formations.

Company Tool OD

Inches Maximum

Temperature (oF)

Maximum Pressure (psi)

Schlumberger 3.63 350 20,000 Western Atlas 3.63 400 20,000

This tool is applicable in all wells drilled with low salinity or non-conductive drilling fluids. If the fluid salinity is rather high, then DLL (Dual Laterolog) might be run instead of the PI or DPIL. Reservoir Description Department will make this decision prior to logging.

2.1.2 DLL (Dual Laterolog): This tool measures deep and shallow formation resistivity in boreholes containing saline drilling fluids. With the measured information, the following reservoir parameters can be obtained: A) True formation resistivity in saline mud systems and high

formation resistivities. B) Qualitative indication of permeability. C) Formation evaluation, including hydrocarbon/water contact. D) Correlation.

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure

(psi)

Schlumberger 5.25 350 20,000 Western Atlas 3.36 400 20,000

2.1.3 MSFL (Schlumberger’s Microspherically Focused Log) or MLL

(Western Atlas’s Microlaterolog):

A) Schlumberger is the sole provider of the MSFL service and Western Atlas does not have a comparable tool. The MSFL

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records resistivities of small volumes near the borehole in wells drilled with conductive muds. The data is used to

1. Determine the resistivity of the flushed zone. 2. Identify location of the porous and permeable zones. 3. Identify movable Hydrocarbon

Company Tool OD

Inches Maximum

Temperature (oF) Maximum Pressure

(psi) Schlumberger 4 and 5.25 350 20,000

B) Saudi Aramco uses Western Atlas’s MLL as a substitute for the

MSFL even though it is not a true replacement. The MLL has a limited depth of lateral investigation and good vertical resolution. It responds primarily to the resistivity of the flushed zone adjacent to the wellbore. Although usually run in salt mud, the MLL can also be run in fresh mud where mudcake is thin.

Company Tool OD

Inches Maximum

Temperature (oF) Maximum Pressure

(psi) Western Atlas 3.38 350 20,000

C) CAL (Caliper Log, available from Schlumberger and Western

Atlas). This log is a continuous profile of the borehole wall showing variations in diameter. Caliper logs can be recorded using 1, 2, 4 or 6 arm tools. The measurements and their average accurately describe the shape of the hole and size (I.D.), especially in deviated and elliptically shaped holes. When the hole is straight and round, all calipers read the same value. In an elliptical hole, the 2-arm caliper lines up with the long axis. The 4-arm caliper measures both the short and long axes of the hole and provides the most accurate description of true internal diameter.

The primary uses of a Caliper Log include: 1. Determining borehole profile for cement volume

calculations. 2. Provide information on build-up of mudcake adjacent to

permeable zones.

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3. Determine hole size for fluid flow calculations, particularly in irregular boreholes.

4. Locate packer-seating areas in open hole. 5. Locate breaks in parted tubing or casing. 6. Locate gas lift mandrels, landing nipples, and other

restrictions in tubular goods.

2.2 LDT/CNL/GR/CAL or ZDL/CN/GR/CAL

After logging with the LDT/CNL/GR/CAL or ZDL/CNL/GR/CAL to above the 7” liner shoe, it is common Saudi Aramco practice to continue logging with only the CNL/CCL to 100’ above the 9-5/8” casing shoe. The logging speed should not exceed 60 fpm and the log should be recorded at 2” per 100-foot scale. This log is required by Geology in order to correlate the various formation tops above the Arab-D.

2.2.1 LDT (Schlumberger’s Litho-Density Tool) or ZDL (Western Atlas’s

Compensated Z-Density). These tools use a gamma ray source to measure the bulk density and the photoelectric effect (Pe) of the formation. The Pe measurement is related to the formation composition and lithology, and the bulk density measurement can be related to the porosity. The two detectors compensate for mudcake effects and hole rugosity. Principal applications include:

1. Porosity analysis 2. Lithology determination. 3. Abnormal pressure identification

Company Tool OD

Inches Maximum

Temperature (oF) Maximum

Pressure (psi)

Schlumberger 4.5 350 20,000 Western Atlas 3.63

4.88 350

20,000

2.2.2 CNL or CN (Schlumberger’s Compensated Neutron Log or Western

Atlas’s Compensated Neutron): This tool contains a radioactive source that bombards the formation with fast neutrons. These neutrons are slowed and then captured, primarily by hydrogen atoms in the formation. The slowed neutrons deflected back to the tool are counted by the detectors.

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Neutron logs are primarily used for identification of porous formations and for the estimation of their porosities. Other uses of the CNL tool include lithology identification, clay analysis and gas detection. The CNL is affected by very few borehole effects, which makes this instrument very desirable in rough or washed out boreholes. CNL tools are combinable and are usually run simultaneously with other services.

Company Tool OD

Inches Maximum

Temperature (oF) Maximum

Pressure (psi)

Schlumberger 2.75 3.375

500 400

25,000 20,000

Western Atlas 2.75 3.625

450 400

25,000 20,000

2.2.3 GR (Gamma Ray). This instrument measures the natural radioactivity

of the formation and can be run in any liquid or air filled hole, either cased on uncased. The main applications of the log are 1. Make depth correlation with other logs. Effective in any

environment, it is the standard device for correlating cased hole logs with open hole logs.

2. Determine stratigraphic profiles. 3. Estimate shale content in reservoir rocks. 4. Recognize radioactive minerals.

In cased hole, a Casing Collar Log is usually recorded simultaneously. The GR tool can be run in combination with other services.

Company Tool OD

Inches Maximum

Temperature (oF)

Maximum Pressure (psi)

Schlumberger 1.688 3.375

350 350

20,000 25,000

Western Atlas 1.688 – 3.625 300 – 450 15,000 – 25,000

2.2.4 CAL: See section 2.1.1 above for details.

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2.3 FMI or STAR (Schlumberger’s Formation Microscanner Imager or Western Atlas’s Simultaneous Acoustic & Resistivity Imager):

2.3.1 The FMI tool provides electrical images in conductive mud and offers

quantitative information on fracture analysis; it hardly gets influenced by borehole effects. The tool is primarily used for 1. Structural analysis. 2. Characterization of sedimentary bodies. 3. Complete fracture network evaluation. 4. Depth matching, orientation and core studies. 5. Reservoir characterization.

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Schlumberger 5 350 20,000

2.3.2 The STAR log is similar to the FMI. It has the added advantage of acoustic imaging capabilities, which extends its application to wells containing non-conducting fluids

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Western Atlas 5.0 350 20,000

2.4 AIT/MSFL/SP/CAL/DSI-SONIC OR HDIL/MLL/SP/CA/MAC

2.4.1 AIT (Schlumberger’s Array Induction Tool) or HDIL (Western Atlas’s High Definition Induction Log): This tool provides a resistivity image of the formation that reflects bedding, hydrocarbon content and invasion features. The tool can operate in any wellbore fluid, including oil-base mud.

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Schlumberger 3.88 350 20,000 Western Atlas 3.63 400 20,000

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2.4.2 MSFL: See section 2.1.1 above for details

2.4.3 SP (Spontaneous Potential): This is a curve that is recorded in conductive mud by resistivity logs to differentiate between potential reservoir rocks and shales, and to determine formation water resistivity.

2.4.4 CAL: See section 2.1.1 above for details

2.4.5 DSI-Sonic (Dipole Shear-Sonic Imager) or MAC (Western Atlas’s Multipole Array Acoustic): This tool measures shear, compression and Stoneley sound waves in all formations. The main applications of this tool are 1. Seismic correlation. 2. Wellbore stability. 3. Sanding analysis. 4. Prediction of rock strength for fracture stimulation and fracture

height estimation. 5. Mobility. 6. Improved estimation of porosity and lithology in slow formations. 7. Through-casing acquisition of shear-wave (S-Wave) and

compressional-wave (P-wave) data.

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Schlumberger 3.63 350 20,000 Western Atlas 3.63 400 20,000

2.5 CSI-Sidewall Core Guns

2.5.1 CSI (Schlumberger’s Combinable Seismic Imager): This tool

measures compressional, vertical and horizontal shear seismic waves in open or cased hole. There are a number of applications for this tool, however, the main ones include: 1. Vertical seismic profile and offset recording in open or cased

hole. 2. Horizontal well surveys in tough logging conditions. 3. Deviated well vertical seismic profile

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2.5.2 Sidewall Core Guns: See section 3.1.1 below for description and details.

2.6 Induction/DLL

When the drilling program calls for running an Induction log, it is the same as running PI or DPIL (see section 2.1.1). The DLL (Dual Laterolog) is run in lieu of DPIL only if the drilling fluid salinity is high.

2.7 Standard Logs

The following is a cross reference of the common logs run by Schlumberger and Western Atlas. It is important to note that the contracts with each Service Company calls for 1000 ft. minimum logging interval for all services. The exceptions include 300 ft. for the FMI log and 500’ for the STAR.

Schlumberger Western Atlas

Log Name Log Name

PI Phasor Induction DPIL Dual Phase Induction Log

AIT Array Induction Tool HDIL High Definition Induction Log

DLL Dual Laterolog DLL Dual Laterolog

ARI Azimuthal Resistivity Imager - -

MSFL Microspherically Focused Log MLL Microlaterolog

CMR Combinable Magnetic Resonance MRIL Magnetic Resonance Imager Log

NGS Natural Gamma Ray Spectroscopy SL Spectralog

LDL Litho Density Log ZDL Compensated Z-Densilog

CNL Compensated Neutron Log CN Compensated Neutron

FMI Formation Microscanner Imager STAR Simultaneous Acoustic & Resistivity Imager

UBI Ultrasonic Borehole Imager CBIL Circumferential Borehole Imager Log

DSI Dipole Shear-Sonic Imager MAC Multipole Array Acoustic

DSI-BCR Both Cross-dipole Receivers X-MAC Cross Dipole MAC

TDT-P Thermal Decay Time PDK-100 Pulse Decay Tool

RST Reservoir Saturation Tool RMS Reservoir Monitoring Service

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3.0 MISCELLANEOUS LOGGING SERVICES

Open and cased hole logs are run in a well during drilling operations to obtain information about the reservoir in order to better define the parameters. 3.1. Sidewall Core Guns

Schlumberger’s CST (Chronological Sample Taker) or Western Atlas’s SWC (Sidewall Coregun)

A core barrel, which is a hollow cylinder, is shot into the formation by a surface controlled powder charge ignited by an electric current. The core barrel, containing a formation sample, is retrieved by means of a steel cable(s) attached between the gun and the core barrel. Only one core barrel is fired at a time. A tandem gun can selectively core multiple (over 40) samples on a single run. Sidewall formation samples are used to

A) Determine porosity and permeability. B) Confirm hydrocarbon shows. C) Determine clay content. D) Determine grain density. E) Determine Lithology.

3.1.1 The CST tool can obtain up to 90 core samples in one trip.

Recovered samples are generally large enough for a core analysis.

Core Bullet

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Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Schlumberger 4 & 4.38 450 20,000 5.25 450 20,000

3.1.2 The SWC obtains cores ranging in size from 0.85 in. to 0.69 in.

diameter and up to 2 in. in length. Up to 50 core samples can be obtained on a single run using the 4 in. Coregun.

Company Tool OD Inches

Maximum Temperature (oF)

Maximum Pressure (psi)

Western Atlas 3 400 20,000 4 400 20,000

Western Atlas’s SWC Coreguns

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3.2. Borehole Profile and Cement Volume Log When using the 4-arm caliper tool such as a dipmeter or Borehole Geometry Tool, the Borehole Profile-Cement Volume log can be generated. This Schlumberger log is computed using caliper and deviation data, which allows calculation of the amount of cement needed to set a particular size of casing. The log information is used for A) Casing cementation B) Borehole and annular cement volume C) Drillstem testing

3.3 Flowmeter/Gradio/FCAP/CAL/HRT

Both Schlumberger and Western Atlas are able to offer this Production Logging service.

3.3.1 Flowmeter: Continuous Spinner or Folding Impeller flowmeter

surveys are used to meter fluid flowrates within cased hole or open hole wellbores. Velocity and direction of fluid movement in the borehole can be determined by the movement of the impeller. Units of measurement are revolutions per second, which can be converted to barrels per day and percentage of full flow.

3.3.2 Gradio and FCAP:

A) Schlumberger uses a Gradio-manometer which works by measuring the pressure 2 foot apart and calculating the pressure differential to determine the density of the liquid. This measurement is valid for 20 to 80% water cut. The HUM (hold-up meter) and DEFT tool is also used for water cuts less than 20% and greater than 80%.

B) Western Atlas uses the FDN (Fluid Density Log – Nuclear)

which measures fluid density by injecting a gamma ray source in the flow stream. This tool is good for measuring densities up to 60% water cut. The FCAP (Fluid Capacitance), also referred to as WHI (Water Hold-Up Indicator), complements the FDN and can accurately measure water cuts greater than 60%

3.3.3 CAL: The Caliper log is needed to determine hole size for flow

calculations, particularly in irregular boreholes.

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3.3.4 HRT: A High Resolution Temperature log provides a continuous record of borehole fluid temperatures. In producers, the data is used to:

A) Detect gas entry in open and cased holes. B) Distinguish zones that are producing from those that are non-

producing. C) Determine the geothermal gradient.

3.4 OTHERS

Other logging services are provided by both in-Kingdom Electric Logging Service Companies. Details of these logs are covered in other sections of this Workover Manual as follows:

3.4.1 Freepoint Indicator: See Chapter 5, Section D (Explosives).

3.4.2 String Shot: Back-off: See Chapter 5, Section D (Explosives).

3.4.3 Chemical Cutter: See Chapter 7, Section A (Fishing Tools).

3.4.4 Jet Cutter: See Chapter 7, Section A (Fishing Tools).

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LOGGING GUIDELINES 1.0 GENERAL 2.0 LOGGING TOOLS RUNNING SPEED 3.0 LOGER’S DEPTH VERSUS DRILLER’S DEPTH

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LOGGING GUIDELINES 1.0 GENERAL

The following general guidelines will be observed during logging operations: 1.1 When drilling a new open-hole section, logging should be conducted as soon

as possible to minimize the effects of filtrate invasion and minimize the thickness of the filter cake.

1.2 Collect two one-gallon mud samples of the drilling fluid from the effluent of

the flowline, immediately after circulating and prior to pulling out of hole for logging. Give one sample to the logging engineer and send the other to the P.E. Laboratory for measurement of mud and filtrate resistivities. The results should be sent to Reservoir Description Department.

1.3 When logging with a combination logging tool and one of the sections in the

tool malfunctions, the option whether to continue logging will depend on the usefulness of the data being recorded or obtained. Contact Reservoir Description Department for consultation and advice.

1.4 When running a suite of logs, always insure that the sonic or resistivity log is

the first one and the radioactive tool is the second one. The reason is that the hole conditions across the interval to be logged are not known. If the logging tool becomes stuck in the hole, fishing operations can proceed on a non-radioactive tool. Once the stability of the hole is established, then it becomes less risky to run a tool with a radioactive source.

1.5 Per contract agreement with Schlumberger and Western Atlas, most logs

have a minimum charge of 1000 feet regardless of the actual logged interval. Repeat sections of any log are a necessity to insure the reliability of the survey. The length of repeat section is dependent on many factors, such as (a) the type of log, (b) number of anomalies detected, (c) interval length, and other factors. Generally, 200’ repeat section is not uncommon. As an example, logging Arab-D vertical wells in Southern Area Producing involves a short +400 foot interval. The repeat log covers the total +400 interval since the minimum log footage charge is not exceeded.

1.6 When logging operations are competed, the Service Company provides the

Workover/Drilling Foreman with a field-copy of all logs. Additional copies are provided to other Saudi Aramco organizations as stipulated.

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2.0 LOGGING TOOLS RUNNING SPEED The following table lists the logging speeds that are recommended for the commonly used logging tools used during drilling operations:

SURVEY RUNNING SPEED

Generic Name Service Company Log Name

Schlumberger Feet/Min

Western Atlas

Feet/Min Phased Induction PI or DPIL 60 60 Special Induction AIT or HDIL 60 60 Azimuthal Resistivity Imager ARI 60 60 Dual Laterolog DLL 60 60 Compensated Density LDL or ZDL 30 25 Compensated Neutron CNL or CN 30 30 Dipmeter HDT or HDIP 30 60 Gamma-Ray (Evaluation) GR 30 30 Gamma-Ray (Correlation) GR 60 30 Spectroscopic Gamma-Ray NGS or SL 15 30 Microspherically Focused log MSFL 30 60 Microlaterolog MLL 30 60 Formation Imager FMI or STAR 30 30 Acoustic Imager DSI or MAC 30-60 30 Combinable Seismic Imager CSI Stations Stations Borehole Imager UBI or CBIL 30 15 Borehole Compensated Sonic BHC Sonic or BHC Acoustic 60 60 Platform Express AIT/TDD/CNL/GR/MCFL 60 -

Note: A) For a given combination of tools, the logging speed is dictated by the slowest

component in order to preserve good log definition. B) The downhole acoustic environment determines Sonic or Acoustic logging

speeds; the signal-to-noise ratio is the determining factor. If the ratio is low, then the logging speed is reduced, and vice versa.

C) Special care should be taken when running a pad-type log since the rugged borehole conditions could damage the logging tool if run too fast. Logging speeds in the range of 1500 ft/hr are normal and should not be exceeded.

D) Logging speeds for radioactive surveys should be based on wellbore rugosity and resolution requirements. Greater statistical errors and lower log resolutions are a result of higher logging speed.

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3.0 LOGGING VERSUS DRILLER DEPTH The following procedures should be followed when reporting Electric Logging and Perforating depths: 3.1 All casing, tubing and associated equipment, such as packers, SSSVs, etc.,

will be reported as Driller’s Depth (DD) and measured in feet from DF, Derrick Floor.

3.2 All depths associated with electric line operations, such as logging,

perforating, setting packers, setting plugs, etc. during drilling of a well, should be reported as Logged Depth or Loggers Depth (LD) and referenced to the DF.

3.3 All measurements that have both a DD and LD should be properly labeled to

differentiate between them. As an example, a packer is set on electric line at a particular depth and is tagged when landing the tubing at a different depth. It is therefore imperative for all reports, such as Daily Drilling reports, Well Completion Reports, etc., to contain the proper depth labeling to eliminate possible confusion.

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STUCK TOOL PROCEDURES 1.0 GENERAL 2.0 FREEING STUCK TOOL

2.1 Tool Stuck During Logging 2.2 Tool Stuck on Bottom

3.0 STRIPPING OVER 4.0 BREAKING AT THE WEAK-POINT 5.0 FISHING FOR RADIOACTIVE TOOLS

5.1 Fishing Operations 5.2 Handling of a Radioactive Source 5.3 Abandonment of Source

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STUCK TOOL PROCEDURES 1.0 GENERAL

Tool sticking usually occurs in open hole when the electric cable or tool itself becomes stuck due to differential sticking, getting hung up on junk, key-seating in a dogleg, and other reasons.

The following are general electric cable logging field practices that should be observed:

1.1 Prior to rigging up the electric wireline unit for logging, ensure fishing tools

are available on short notice. 1.2 Know the size/type of the cable, maximum allowable pull (50% of line

breaking strength), and weak point rating. 1.3 For large cable where the breaking strength is 16,000 lbs., do not exceed

8000 lbs. pull. On smaller cable where the breaking strength is 4000 to 5100 lbs., do not exceed 2000 to 2500 lbs. pull.

1.4 The weak point setting (rope socket) is selected prior to running the logging

tools. It is a function of the depth of the well, tool weight, and line breaking strength. The weak point setting + tool weight in mud + line weight at TD should be less than or equal to 50% of the breaking strength.

1.5 Permission shall be obtained from Saudi Aramco management prior to

intentionally breaking the cable.. 1.6 All standard logging tools use the same cable head, shown in Figure 5C-1.

Note: The maximum pull on a standard logging head (3-3/8 inch thread) is 120,000 lbs.

1.7 The Schlumberger or Western Atlas engineer should consult the Drilling

Foreman and their office before pulling beyond the weak point strength.

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Figure 5C-1 Standard Schlumberger Logging Head

Rope Socket

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2.0 FREEING STUCK TOOL

2.1 Tool Stuck During Logging Close tool, and attempt to go down if tool is free to descend; make several attempts if necessary. If tool is not free to descend, pull to maximum safe tension and hold at that level of tension until the tool becomes free. 2.1.1 If this action does not free the tool, stripping-over should be

performed. 2.1.2 The RFT tools stick easily and consequently the following precautions

should be taken:

1) A dummy run prior to RFT logging is highly recommended. 2) Adding friction reducer to the mud is desirable, if possible. 3) If an excessive differential pressure situation exists across a

formation, B-FREE pills or similar products should be spotted prior to taking RFT readings or samples.

2.2 Tool Stuck on Bottom

If tool becomes stuck on bottom of the hole, close tool and pull to maximum safe tension and hold at that level of tension until the tool becomes free. If this action does not free the stuck tool, then stripping-over should be attempted.

3.0 STRIPPING OVER

If the tool fails to unstick or come free, stripping over should normally be attempted. Remember to obtain approval prior to breaking the weak-point. If stripping-over is to be performed, proceed as follows:

3.1 Apply 2000 lbs. tension to the cable. 3.2 Land cable and cut above rotary table. 3.3 Connect spearhead to the hole end of the cable and a spearhead overshot to

the unit end. 3.4 Strip over wire with Bowen overshot and drill pipe, stand by stand,

maintaining 2000 lbs. tension in the cable.

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3.5 Prior to latching on the fish, install a circulating sub and special bushing at surface to catch the cable; the cable is landed in this bushing.

3.6 Install the Kelly and circulate to clean the overshot, prior to latching on the

fish. After circulating, remove the Kelly, connect spearhead overshot to spearhead and apply 2000 lbs. tension.

3.7 Lower string and latch onto the fish. A tension decrease when lowering or

tension increase when pulling the string indicates the fish to be connected. Note: While running in hole with the overshot, a decrease in cable tension

may occur, indicating that the tool has become free. In such a case, the cable is connected and the tool pulled up until the overshot latches onto the fish head

3.8 After latching onto the fish, part the cable at the weak-point with the travelling

block. Remove the spearhead-overshot combination, connect the cable together and wind in. Pull the string and recover the fish. Do not rotate the string while pulling out.

4.0 BREAKING WEAK-POINT

4.1 The following are precautionary measures when attempting to recover a stuck tool by breaking at the weak-point:

A) If the open hole is in reasonable condition or in casing, there is a good

chance the tool can be fished out by breaking at the weak-point and fishing with an overshot (with an OD slightly smaller than the bit size).

B) This technique should not be used for tools with radioactive source. If a

radioactive logging tool is stuck in the hole, do not continue to work the tool since this may reduce the weak-point strength. Inform the concerned parties of the details of the situation.

C) At no time should cable tension be suddenly released. This action can

cause “bird-cages” and broken cables. Tension should be released slowly and should never drop below 50% of the normal logging tension.

D) The Schlumberger or Western Atlas engineer should always direct the

operation when applying and releasing tension on the cable. 5.0 FISHING FOR RADIOACTIVE TOOLS

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5.1 Fishing Operations

The following are precautionary measures when attempting to recover a stuck tool by breaking at the weak-point:

A) Circulate once around prior to latching on to fish. B) Monitor the mud returns constantly with the Gamma-Ray tool placed in

the return line. C) Do not locate engage-tool with more than 10,000 lbs. weight. D) Ensure the maximum allowable pull is not exceeded. E) No personnel other than Schlumberger or Western Atlas are to be near

the mud pit or return lines. F) Check to ensure that with the tool engaged in the overshot, circulation

remains impossible. Use a circulating sub in the fishing assembly one stand above the overshot.

5.2 Handling of a Retrieved Source

The following safety precautions should be adhered to when handling a retrieved source: A) Limit personnel to the minimum required on the rig floor. B) Pull the source as far as possible in the derrick (minimum 50’). C) Cover the rotary table, close rams, etc., then all rig personnel shall

leave the rig floor except the Driller. D) The Driller will assist Schlumberger or Western Atlas in laying down

equipment.

5.3 Abandonment of Source

The radioactive source will be abandoned in place (in hole) if all of the above actions fail to recover the source (see Chapter 2, Section G for details).

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EXPLOSIVES 1.0 PERFORATING

1.1 Types of Guns 1.2 Specifications 1.3 Log correlation 1.4 General Perforating Guidelines and Tips 1.5 Pressure Control Equipment & Testing 1.6 Procedures for Ordering Explosive Charges 1.7 Safety Concerns and Precautions

2.0 TUBULAR PUNCHERS

2.1 Types of Punchers 2.2 Suppliers and Specifications 2.3 Safety Concerns and Precautions

3.0 PIPE CUTTERS

3.1 Types of Cutters 3.2 Suppliers and Specifications 3.3 Safety Concerns and Precautions

4.0 PIPE BACK-OFF

4.1 Suppliers and Specifications 4.2 Procedures 4.3 Safety Concerns and Precautions

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1.0 PERFORATING Perforating is a critical part of the well completion process and provides the means of communication between the reservoir and the wellbore. Shaped charges are used to perforate casing and thus create a path for the fluids to flow from the reservoir into the wellbore.

1.1. Types of Guns

1.1.1 Retrievable Hollow Carrier Gun

These guns are reusable, wireline or tubing conveyed, with normal 4 shots-per-foot perforating density at 90o or 120o phasing. Penetration of the charges into the formation is usually not as deep as an expendable type because of stand-off (distance between charge and casing). Advantages: 1. Essentially no debris left in the hole. 2. No deformation of casing when detonated. 3. Shot density can be varied. 4. High gun reliability. 5. High running speeds. 6. High temperature ratings up to 470 oF. Disadvantages: 1. Gun length is limited by weight 2. Rigid carrier is not good for passing through

crooked hole sections. 3. Difficulties perforating under-balanced. 4. No way to verify if charges are fired.

Note: Hollow carrier guns with High Shot Density (HSD, up to 12 shots-per-foot) are available. They are not reusable but are recovered from the well.

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1.1.2 Expendable Hollow Carrier and Strip Gun These type of guns are either classified as fully or semi-expendable. They are run on wireline or tubing conveyed, with normal 4 shots-per-foot at 0o or 45o phasing. It is common practice to magnetically orient the guns to one side of the casing in order to maximize formation penetration in one direction.

A) Fully expendable guns are designed to shatter when fired.

The debris falls to bottom and is left in the well. The case, which houses the explosive charge and liner, is made of aluminum because it is light and can be cast into integral casings.

Advantages: 1. High flexibility permits handling long

lengths (200 feet). 2. Explosive charges penetrate deeper

into the formation than equivalent slim hollow carrier guns.

Disadvantages: 1. Debris left in well. 2. Under balanced perforating can result

in gun blowing up the hole causing a fishing job.

3. Aluminum case is not resistant to HCl. 4. Lower pressure and temperature

ratings as compared to Hollow Carrier guns.

5. Running speed limited to 10,000 ft/hr versus 30,000 ft/hr for other guns. The soft aluminum wears quicker than steel.

6. No way to verify if charges are fired. 7. Can cause casing deformation,

especially in old wells. 8. Cannot push gun through bridge since

it will ball up or break.

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B) Semi-expendable guns are destroyed when fired. Actually, only the perforator casings are destroyed when the gun is fired. The carrier, either wire or strip-type, remains intact and is removable from the wellbore. The tougher strip carriers are preferred over the seldom-used wire type. A conventional strip gun can fire charges at 0 or 180 degree phasing, while an angled strip gun enables consecutive charges to be fired 90 degrees apart. This phasing places the perforations +45 degrees on either side of the magnetic positioning tool’s central axis. By providing some phasing, the angled strip gun is believed to limit a well’s tendency to produce sand by reducing the pressure drop across the perforations. Advantages: 1. The debris left in the hole is generally

reduced as the strips and wiring are recovered.

2. In the case of glass and ceramic cases, the type of debris left is more like sand and less apt to cause problems.

3. Explosive charges penetrate deeper into the formation than equivalent slim hollow carrier gun due to magnetic positioning.

4. Flexibility of gun improves chances of passing through rigid tubing.

5. Lower cost than Hollow Carrier gun. 6. Head and accessories easily retrievable. 7. Lower shot density can be run on same

strip. 8. Spacing out of the charges in the field is

easy to accomplish.

Disadvantages: 1. Debris left in the well. 2. No way to verify if all the charges are fired. 3. Limited to less than 40’ of gun length due to

maximum lubricator length. 4. Has the potential of hanging up after

perforating when pulling out of hole. 5. Coiled tubing conveyed not recommended. 6. In old or corroded wells, may damage or

deform the casing.

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1.1.3 Tubing Conveyed Gun Tubing Conveyed Perforating or TCP is the placement of a hollow carrier gun on the end of a string of tubing or drill pipe. In Saudi Aramco, TCP guns have been run on drill pipe (without a packer) in horizontal wells, and on tubing in exploration/test wells (with a packer). Since TCP carriers are non-ported and can only be used once, they are classified as expendable guns.

Advantages: 1. Can perforate under-balanced without the fear of being blown out

of the hole 2. Pressure and temperature ratings are the same as the hollow

carrier guns 3. Very long intervals can be perforated in a single trip 4. Can selectively perforate two separate zones in one run 5. Can perforate surge and gravel pack in a single trip. 6. No debris if gun is recovered

TUBING CONVEYED PERFORATING

DRILL PIPE TO SURFACE

RADIOACTIVE MARKERSUB±500' OF DRILLPIPE

RADIOACTIVE PIP TAG

CIRCULATING SUBDIFFERENTIALPRESSURE FIRING HEAD

4-1/2" O.D. HIGH SHOTDENSITY GUNS AT5 SHOTS-PER-FOOT &SPACERS AS REQUIRED

BOTTOM NOSE

±500' OF DRILLPIPE

SAFETY SPACER

Typical Horizontal TCP String

DRILL PIPE ORTUBING TO SURFACE

RADIOACTIVE MARKERSUB

DRILLPIPE OR TUBING

DIFFERENTIALPRESSURE AND/OR DROPBAR FIRING HEAD

4-1/2" O.D. HIGH SHOTDENSITY GUNS AT5 SHOTS-PER-FOOT &SPACERS AS REQUIRED

BOTTOM NOSE

SAFETY SPACER

PACKER W/ BYPASS

Typical TCP String(A) (B)

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Disadvantages: 1. If the guns are left in the well, they may hinder future workover

operations. 2. Verifying the firing of charges can only be done by tripping out of

the hole with the guns 3. More expensive by as much as 40% over through-tubing methods.

Th initial higher cost for TCP is offset by the associated rig time required to perforate longer than 50’ zones.

4. Well control has become an issue of concern when retrieving the perforated hollow carriers. A gas kick reaching surface while the +1000’ expended hollow carrier gun is being unscrewed, section-by-section, cannot be controlled by simply closing the pipe rams. The only quick solutions are: (a) Quickly make up a joint or stand of drill pipe (with a check

valve) on top of the hollow carrier, stab the drill pipe into the well, and close the pipe rams on the drill pipe

(b) Drop the hollow carrier gun into the well and close the blind rams, in the hopes of retrieving the fish after the well is brought under control.

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1.2. Gun Specifications

The following table lists the commonly used gun systems, associated explosive charges and performance supplied by the two In-Kingdom service companies:

1.2.1 Schlumberger

Gun System NominalTool OD,

inch.

Min. Restrict.

inch. *

Shot Density

& Phasing

Hole size inch.

Conveyance Method

Penetration Depth

Inches **

Most Common Use in Saudi

Aramco

Pivot FullyExpendable Laser Cut Carrier

1-11/16 1.78 4 spf 180o

0.32 to

0.38

Wireline 32.8 to

27.78

New tool, not used to date

Enerjet Semi -Expendable Strip Gun

1-11/16 1.69 4 & 6 spf 0o

0.28 to

0.26

Wireline 16.84 to

16.67

For perforating 4-1/2 & 5” liners, through tubing

Enerjet Semi -Expendable Strip Gun

2-1/8 2.25 4 & 6 spf 0o

0.30 to

0.31

Wireline 27.52 to

21.94

For perforating 7” casing or 4-1/2” liners, through tubing

Phased Enerjet Semi -Expendable Strip Gun

2-1/8

2.25 4 & 6 spf 45o

0.29 Wireline 22.9 For perforating 4-1/2 to 7” liners, through tubing

High Shot Density Expendable Hollow Carrier

2-1/2 2.80 1 to 6 spf 60o

0.29 Wireline TCP CTU

17.32 Through-Tubing Perforating

High Shot Density Expendable Hollow Carrier

2-7/8 3.25 1 to 6 spf 60 or 180o

0.3 to

0.29

Wireline TCP CTU

21.97 to

20.57

Not used

High Shot Density Expendable Hollow Carrier

2-7/8” 3.25 1 to 6 spf 60 or 180o

0.27 to

o.69

TCP Drill Pipe

CTU

8.4 to

20.00

Used @ 6spf to perforate horizontal wells

High Shot Density Retrievable Hollow Carrier

3-3/8

4.00 1 to 6 spf 60 or 180o

0.37 to

0.4

TCP Drill Pipe

CTU

23.34 to

21.90

5-1/2” to 7” Liner

* Minimum Restricted ID tool can be run in. Values vary with different gun systems. ** Penetration test is conducted in cement per API RP 43, fifth edition.

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1.2.2 Western Atlas Gun System Nominal

Tool OD, inch.

Min. Restrict.

inch.

Shot Density

& Phasing

Hole size, inch.

Conveyance Method

Penetration Inches

*

Most Common Use in Saudi

Aramco

Silver Jet Semi-Expendable Strip Gun

1-11/16 1.78 4 & 6 spf 0o

0.37 to

0.36

Wireline 15.6 to

13.2

For perforating through tubing

Silver Jet Semi-Expendable Strip Gun

2-1/8 2.25 4 & 6 spf 0o

0.42 to

0.72

Wireline 18.3 to 6.1

For perforating through tubing

Predator Semi-Expendable Strip Gun

2-1/8 2.25 4 & 6 spf 0o

0.29 to

0.32

Wireline 28.4 to

25.2

For perforating through tubing

Phased Predator Semi-Expendable Strip Gun

2-1/8

2.25 4 & 6 spf 30o

0.28 Wireline 26.8 For perforating through tubing

Alpha Jet Ported Hollow Carrier

3-1/8 3.8 4 spf 120 &

90o

0.31 Wireline 18.9 Used to perforate 4-1/2” casing or liner

Alpha Jet Ported Hollow Carrier

4 4.7 4 spf 120 &

90o

0.48 Wireline & TCP

29.4 For perforating 5” & larger casing or liner (Prod. & GWI).

Alpha Jet Expendable Hollow Carrier

3-3/8 3.8 1 to 6 spf 60o

0.47 Wireline & TCP

22.8 Used to perforate 4-1/2” casing or liner

Alpha Jet (Deep Penetrator) Expendable Hollow Carrier

4-1/2

5.0 5 spf 135/45o

0.45 Wireline & TCP

38.1 Used in Central Area sandstone reservoirs

Alpha Jet (HSD charges) Expendable Hollow Carrier

4-1/2

5.0 1 to 12 spf

135/45o

0.37 Wireline & TCP

20.2 Used at 8 & 12 spf in Central Area sandstone reservoirs

Jumbo Jet BH Expendable Hollow Carrier

4-1/2

5.0 1 12 spf 135/45o

0.74 Wireline & TCP

5.8 Used in Central Arabia for gravel packing

Alpha Jet (Deep Penetrator) Expendable Hollow Carrier

4

4 spf 90o

0.44 Wireline & TCP

25.08 Used in Central Area sandstone reservoirs

JRC TP Expendable Hollow Carrier

4-1/2

4 spf 0o

0.29 Wireline & TCP

0.61

Super Hole Expendable Hollow Carrier

4-1/2

1 to 12 spf

135/45o

0.96 Wireline & TCP

5.9

* Penetration test is conducted in cement per API RP 43, fifth edition.

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1.3 Log Correlation

When selecting the interval to be perforated, it is common to utilize the original open hole formation logs (LDT/CNL/GR or ZDL/CN/GR). These logs have been run prior to cementing casing and therefore do not have casing markers such as collars, shoe, DV collars, liner tops etc. In order to insure perforating the appropriate interval in the right location, a Gamma Ray log (or Neutron) along with a casing collar locator log is run in conjunction, and the new log is correlated with the original log.

1.3.1 Conventional Perforating with Wireline

i) Obtain the original open hole log and mark the interval(s) to be

perforated. ii) Run a new Gamma Ray or Neutron log and CCL log. If a

previously run GR/CCL or NL/CCL log is available, a new log is not necessary. The selection of whether to run GR or NL depends on the how well defined the formation features are on the original logs.

iii) Place the original Gamma Ray log alongside the new log along

the same depths. iv) Slide the new log up or down to match the Gamma Ray or

Neutron characteristics. v) Transfer the perforation interval(s) from the open hole log to the

cased hole log. vi) Run the perforating gun containing a CCL on electric line and

identify the collars in the vicinity of the perforation interval(s). vii) Adjust the electric line depth such that the collars on the cased

hole log match with the collars of the perforating gun. Verify by running the electric line up and down across the collars in the vicinity of the perforating interval(s). Do not forget to compensate for the distance between the CCL and the top-most perforations.

viii) Using the cased hole log as the guide, run down to the bottom

most interval and start perforating from the bottom up. Insure that the perforations have been shot and are on depth by examining the perforation log.

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1.3.2 Tubing Conveyed Perforating

Saudi Aramco has two distinct applications of Tubing Conveyed Perforating (TCP), Horizontal wells and Exploration/Test wells.

A) Horizontal oil related wells are perforated using TCP guns on

drill pipe without a packer. It is usually conducted with overbalanced fluid in the wellbore. In horizontal wells where the producing zone is long and homogeneous, it becomes unnecessary to run correlation logs. The TCP assembly is usually run to TD, raised a few feet and the guns fired. Close to 2400’ of horizontal liner has been perforated in one trip using this technique. If selective perforating of the horizontal section is desired without the use of a packer, then the procedures are as follows:

i) Displace the hole across the 4-1/2” liner to CaCl2 brine

(containing 1% surfactant and 34% HCl acid to lower the pH to +5) and clean CaCl2 brine (viscosified with 2 ppb HEC) from top of the liner hanger to surface. Pull out of hole with bit.

ii) Run in hole with TCP guns loaded at 4 SPF shot density alternating with spacer guns on tool string.

iii) Run in hole on drill pipe and tag total depth. Pick up the

drill pipe such that the bottom-most charge is at the deepest perforating depth.

iv) Rig up circulating head and break circulation. Close

annular BOP. v) Pressure up on drill pipe to 1500 psi and hold for 1 minute.

Bleed off the pressure to 100 psi and observe well. Guns are expected to fire after approximately 10 minutes.

vi) Record shut-in wellhead pressure. Open the annular BOP

and observe the well. Circulate hole through circulation sub if required.

vii) Pull out of hole if well is stable and insure all shots have

been fired.

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Note: If gas or oil has entered the wellbore creating an unstable well, then make a bit trip to PBTD to circulate and condition the well prior to running the completion.

B) Exploration/test Khuff/Pre -Khuff wells in Saudi Aramco are

perforated using TCP guns, run on the bottom of packer assembles, and are subsequently production tested. The tubing strings are made up with a retrievable packer on 3-1/2”, 12.95 lbs/ft., L-80, PH-6 tubing, with the desired length of TCP guns hanging below the packer. This approach is favorable when under-balanced perforating is desirable. After being fired, if the completion does not have a permanent tail pipe, the well can be killed and the guns pulled out of hole. Otherwise, the guns can be left or dropped into the rathole by means of a special sub below the packer, which disconnects and drops the expended guns. The following procedures incorporate a packer-equipped TCP gun assembly:

i) Obtain the original open hole log and mark the interval(s)

to be perforated. ii) Run in hole with retrievable packer/TCP gun assembly on

tubing to the approximate depth the packer is to be set. iii) Note: The assembly should contain the necessary

Radioactive marker-sub, circulating-subs, firing head and other necessary subs/equipment.

iv) Run Gamma Ray & Casing Collar Locator tools in tandem

through the tubing and obtain a log. Rig down logging truck.

v) Place the original Gamma Ray/Neutron log alongside the

new log, along the same depths. vi) Slide the new log up or down to match the Gamma

Ray/Neutron characteristics. vii) Transfer the perforation interval(s) from the open hole log

to the cased hole log. viii) Correct for depth differences between the original open

hole log and the new log by adding or subtracting footage to the electric line depth counter. Also, note and correct for

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the difference between the Radioactive Marker-sub depth on the TCP assembly with that of the collar depths of the new log.

ix) Space out the tubing such that the top shot (perforating

charge) is at the desired depth in relation to the Radioactive Marker sub.

x) Rig up control head, break circulation and condition mud.

Set packer. Slack off weight and close 1-1/2 slip-joints to position the EZ Valve across pipe rams.

xi) Close the pipe rams and pressure up on the TCA to +1000

psi while observing the tubing for leaks. Open pipe rams and pressure test tubing with mud while observing the annulus for leaks.

xii) Reduce the hydrostatic pressure in the tubing by intruding

lighter kill fluid. This can be accomplished by running coiled tubing inside the tubing or opening the packer by-pass for displacing the test string to lighter fluid.

xiii) Close the by-pass and close the rams on the EZ valve.

Pressure up on the tubing (primary firing method) or drop firing bar (secondary firing method) to activate the firing head. Perforate the well.

xiv) Flow-test well per testing program. Following completion

of well testing, kill well as directed in the program. Confirm that the well is dead.

xv) Unseat packer. Reverse out with mud, circulate, lay down

Control Head and EZ valve. Pull out of hole with tubing and TCP/packer assembly.

xvi) Examine hollow carriers to insure all shots have been fired.

1.4 General Perforating Guidelines and Tips.

1.4.1 At any time during perforating, if unsure or the information is questionable, then do not continue with the perforating operations. Seek assistance and clarification. Once the casing is perforated, it is too late to reverse the process.

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1.4.2 Perforating under-balanced is desirable since the differential pressure

across the perforation interval (between the reservoir and the wellbore) is beneficial in cleaning the debris left in the perforation tunnel. Under-balanced perforating is only practiced in cases where there is no danger of the downhole perforating gun from being blown out of the hole (e.g. TCP guns, with and without packer). In Saudi Aramco, horizontal wells are perforated using TCP guns on drill pipe without a packer; however, exploration wells are tested using TCP strings made up on the tailpipe of a retrievable packer.

1.4.3 When selecting gun phasing and intentional de-centralization, it is

important to consider the objective of attaining deepest possible penetration into the formation. For example, in deviated wells, the cement thickness is typically at a minimum on the low side of the hole because of the casing’s tendency to eccenter. The proper gun selection could take into account the need for magnetic positioning and phasing.

1.4.4 The witnessing engineer will submit a detailed record of all perforating

activities, with diagrams and correlation steps clearly explained. The purpose of this report is to retrace the perforating activities in case of doubt. The Service Company perforating log, as it stands, is incomplete and cannot be used to recreate the perforating sequence of events. The engineer will prepare a Completion Report, documenting well activities, within a maximum of two weeks after the job.

1.4.5 Whenever expended guns are pulled out of the hole, the Saudi

Aramco representative should visually inspect all charges to ensure all the explosives have been fired.

1.5. Pressure Control Equipment and Testing

A lubricator and BOPs are essential equipment to be used during perforating operations for pressure control. The lubricator must accommodate the entire length of the perforating gun and accessories. After nippling up the electric line BOPs and lubricator, the equipment should be pressure tested (to 1.2 times the expected wellhead pressure) prior to use by inserting a 7/32” or 3/16” test rod between the rams. Testing the BOPs with the logging cable is not acceptable due to possible leaks through the cable armor. Also, the lubricator should never be pressure tested with an armed perforating gun inside because a pressure leak in the gun or detonator could result in gun detonation.

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1.6. Procedures for Ordering Explosive Charges.

When a rig foreman notifies the service company (Schlumberger or Western Atlas) to provide a services which requires explosive charges, the following procedures apply depending on the area of operations:

1.6.1 Eastern Province:

A) The service company submits a written request to the Explosives

Police office in Dammam indicating the explosive charges required to perform the job.

B) Upon approval, a 1-day valid permit is issued to the Service Company.

C) This permit is presented to the Police Department in Abqaiq at which point a policeman is assigned to accompany the Service Company to the Gun Shop.

D) At the Gun Shop, the service company retrieves the explosive charges required and transports them to the rig (while a policeman is present at all times) to perform the job.

E) Prior to start of the job, the explosives are counted and run in hole.

F) After detonating the explosive charges, the downhole equipment is retrieved and the explosive charges are inspected to insure they have been fired. All unexploded charges are returned to the gun shop for reuse on a future job.

1.6.2 Remote Areas outside the Eastern Province Jurisdiction:

A) Four to five months prior to moving in a drilling rig to drill an

exploratory well in an area outside the Eastern Province, the Manager of Drilling & Workover Services sends a letter to Government Affairs requesting assistance in obtaining blanket approval to transport explosive charges. The letter should contain

1. The location of the proposed well 2. All the necessary explosive charges which might be needed

(such as perforations, tubing punch, casing cutter, packer setting charges and pipe back-off)

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3. The approximate start of operations 4. The statement “the explosives to be transported to the rig site

belong to Schlumberger or Western Atlas on consignment to Saudi Aramco”.

B) Government Affairs then contacts the Explosives Police department in Dammam who in turn communicates with Riyadh.

C) Upon approval, the explosives Police department contacts the respective police departments in each province and notifies them of the fact.

D) A written blanket approval to transport explosive charges is then issued to the Service Company.

E) When the rig foreman or drilling engineer contacts the service company for notification of upcoming explosive charge service, mobilization starts 3 to 4 days in advance to reach location on time.

In both cases where explosive charges are required for well operations with a rig on the well, it is essential to notify the Service Company well in advance to overcome unavoidable delays and prevent rig standby time.

1.7 Safety Concerns and Precautions

1.7.1 Radio Silence

A) Onshore: All radio transmitters, stationary or mobile (cars &

facilities), within the vicinity of the rig will be turned off prior to arming of the detonator, running the explosive charges in the hole, pulling out of hole, retrieving the tool at surface and inspecting for unfired charges. The operation of radio transmitters could cause inadvertent detonation and firing of the explosive charges.

B) Offshore: All radio transmitters, stationary or mobile (platforms,

boats & other nearby facilities), within the vicinity of the rig will be turned off prior to and during arming of the detonator, running the explosive charges in hole, pulling out of hole, retrieving the tool at surface and inspecting for unfired charges. The operation of radio transmitters could cause inadvertent detonation and firing of the explosive charges.

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C) Helicopter Service: Flights should be rescheduled to avoid

flying into the vicinity of the well while perforating activities are in progress. The operation of radio transmitters in the helicopter could cause inadvertent detonation and firing of the explosive charges.

D) In situations such as perforating a well in proximity to a gas

plant, where complete radio silence is impractical or impossible, the Service Companies can provide, for an additional charge, safety equipment which prevent inadvertent detonation of explosive charges due to radio transmission, RF-induced stray voltages, and voltages induced by cathodic protection and welding. Schlumberger’s Slapper-Actuated Firing Equipment (S.A.F.E.) and Western Atlas’s Guardian are currently available for In-Kingdom use. Caution should be used when selecting these tools due to their pressure and temperature limitations.

1.7.2 Voltage Around the Rig

After grounding the casing, rig structure, pipe rack and logging unit, the Service Company representative will measure the voltage difference between the casing and the rig structure. For Schlumberger, the reading should not exceed 0.25 volts, and for Western Atlas, 0.20 volts. If the readings are higher, a search should be made to identify the source and turn it off immediately. The reason for these voltage limits is to avoid inadvertent detonation of the charges.

1.7.3 Safety Meeting

Prior to every job where explosive charges are to be used, the Saudi Aramco foreman will hold a safety meeting with all site personnel in attendance. The following safety items will be discussed:

A) Barriers: The erected barriers will be identified and off-limits

areas indicated to unauthorized personnel. The objective is to minimize risk to personnel not required for this activity.

B) Signs: The foreman will insure that Arabic & English signs

indicating the silence of radio transmission are posted around the location and at the entrance to the rig road. He will insure that all radios and other equipment, which could generate RF-

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induced stray voltage at the rig site, have been turned off and everyone on location understands the impact.

C) Smoking: Designated smoking areas will be clearly identified. D) Weather conditions: The foreman should alert all present of

his intention to suspend the explosive charge detonation if weather conditions (sand storms, electrical storms, etc.) change for the worse. The foreman can suspend operations at any time if in his judgement adverse weather conditions create a hazard to personnel or equipment.

E) Emergency exit: In case of a mishap, alternate escape routes

should be pointed out to the attendees.

1.7.4 Perforating after Dark

If an oil or gas well is expected to have high wellhead pressure after perforating, then perforating should only be conducted during daylight hours. It is unacceptable to perforate high pressure wells in the dark unless a waiver is obtained from the General Manager of Drilling & Workover or the Vice President of Petroleum Engineering and Development. This policy has been in effect since it is difficult to detect a wellhead leak should it occur at night.

1.7.5 Arming the Detonator

Prior to arming the detonator, the Service Company representative will inform the Saudi Aramco rig foreman or engineer in charge of his intention to insure it is safe to do so. Also, at the conclusion of the job when all explosive charges are either detonated or safely locked away, the Service Company representative will inform the rig foreman of job termination in order to turn on the radios and resume communication.

2.0 TUBULAR PUNCHERS

2.1 Types of Punchers

Punchers are used to create a hole or orifice in tubulars to establish communication between the inside and outside. Punchers are often used to punch holes in tubing or drill pipe to establish circulation, in casing to

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squeeze cement behind pipe, and other uses. Mechanical, and explosive tubing punchers are currently available in Saudi Arabia.

2.1.1 Explosive Type:

A one-foot section of tubular is usually perforated with 4 or 6 shots per foot of explosive charges as desired. The important criteria for explosive punching is creating holes large enough and with the desired penetration objective (i.e. between one and four casing strings) to .be able to pump fluid or cement through them with ease.

2.1.2 Mechanical Type

A mechanical puncher or perforator which can be used with wireline, under pressure, to perforate both standard and heavyweight tubing. Saudi Aramco wireline provides this service to the rigs when called upon.

2.2 Suppliers & Specifications

Schlumberger and Western Atlas are the two In-Kingdom suppliers of explosive tubular punchers. When requesting Tubing Puncher service, the same requirements apply as perforating service. See Chapter 5, Section 1.4.

2.2.1 Western Atlas

Puncher Tool OD inches

Max. Tubular Wall Thickness to

be penetrated inches

Average Exit Hole Size in Inner Pipe

inches

Maximum Penetration in

outer pipe, inches

1-9/16” 0.61 0.29 Not Available

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2.2.2 Schlumberger:

Puncher Tubing/Casing Wall Thickness

inches

Average Exit Hole Size in Inner Pipe

inches

Maximum Penetration in

outer pipe, inches

1-3/8” HNS 16DS

Minimum Maximum

0.19

0.375

0.30 0.23

0.10 0.05

16CL Minimum Maximum

0.375 0.50

0.22 0.13

0.10 0.05

1-11/16” HNS 20ES

Minimum Maximum

0.19

0.375

0.32 0.24

0.10 0.05

20DM Minimum Maximum

0.375 0.50

0.30 0.23

0.10 0.05

20DL Minimum Maximum

0.5 0.58

0.25 0.17

0.10 0.05

2.3 General Comments

There is a concern that a second outer pipe (usually casing) can get penetrated or deformed if excessive explosive charges are used and the pipes are in contact with each other at the perforating location.

2.4 Safety Concerns and Precautions

Since explosive charges are used to punch holes in tubulars, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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3. PIPE CUTTERS

3.1 Types of Cutters

Cutters are primarily used to cut or sever tubulars for retrieving out of hole. Common uses include cutting tubing or drill pipe after becoming stuck in the hole, cutting and salvaging casing when economical and feasible, etc. Explosive, mechanical and chemical cutters are currently available in the industry, however, only mechanical and explosive cutters are used in Saudi Aramco’s operations.

3.2 Suppliers and specifications

Schlumberger and Western Atlas are the two In-Kingdom suppliers of explosive tubular cutters. When requesting explosive tubing cutters, the same requirements apply as perforating service. See Chapter 5, Section 1.7. Additional ordering lead-time is needed since the cutters usually have to be shipped in from out-of-Kingdom.

3.2.1 Explosive or Jet Type:

A cut is made by an explosive, shaped with a concave face and formed in a circle. It is run and fired on electric line. When the cut is made the end of the pipe is flared and requires mill over to dress off for fishing operations. The jet cutter is often used when retrieving stuck tubing or drill pipe, abandoning a well during salvage operations or when low fluid level, heavy mud, or cost would prevent the use of the chemical cutter. There is a possibility of damage to an adjacent string or to a casing if the pipe to be cut is touching at the point where the cut is made.

Shap ed Char geEx plos iv e

Explosive Jet Cutter

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3.2.2 Mechanical Type

A mechanical cutter is designed to cut pipe with a set of knives installed in a tool and run on a small diameter work string. Internal Mechanical pipe cuts are most common when removing sections of casing and wellhead equipment during final well abandonment operations. See Chapter 7, Section A for tool operating details.

3.2.4 Chemical Type

The use of a propellant and a chemical (halogen fluoride) is used to burn a series of holes in the pipe, thus weakening and making it easy to pull the pipe apart with slight pull. See Chapter 7, Section A.

Specifications

A) Schlumberger

Pipe Recovery Systems cutters are available in-Kingdom for cutting 2-3/8”, 2-7/8” 3-1/2” and 4-1/2’ tubing. In addition, a cutter is available for 3-1/2” drill pipe, ranging from 12.95 to 15.50 lbs/ft. If CT cutters are required, they will have to be brought in from out-of-Kingdom.

B) Western Atlas

GOEX and JRC cutters and severing tools are available in different sizes to cut various tubing, casing and drill pipe from 2-3/8” to 10” OD. To find out the exact cutter sizes on hand, Western Atlas should be contacted when the need arises.

3.3 General Comments

When cutting pipe, a concern is raised regarding the damaging or cutting of the outside casing, particularly if the two are in contact with each other at that point.

3.2 Safety Concerns and Precautions

Since Explosive charges are used to cut or sever tubulars, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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4. DRILL PIPE BACK-OFF

When drill pipe becomes stuck in the wellbore, the depth at which drill pipe is stuck is determined by either calculations or more accurately through Free-Point instruments run on electric line inside the stuck drill pipe. Upon determining the drill pipe stuck depth, it is desirable to part the drill pipe above the stuck point so that fishing tools can be run to retrieve the remainder of the pipe. Pipe back-off is the unscrewing of the drill pipe at a selective threaded joint above the stuck point by using prima cord explosive which is run on electric line. Reverse torque applied to the drill pipe from surface along with the explosive shock generated by the prima cord across a collar most often results in unscrewing of threads.

4.1 Suppliers and Specifications

Both Schlumberger and Western Atlas provide pipe back-off service. When requesting Back-Off service, the same requirements apply as perforating service. See Chapter 5, Section 1.4.

4.1.1 Specifications

Pipe O.D. Depth From Surface (Feet) (inches) 0

to 3000

3000 to

6000

6000 to

9000

9000 to

12,000

Over 12,000

Tubing 2-3/8 1 1 1 2 2 2-7/8 1 1 2 2 3 4 to 4-1/2 2 2 2 3 3 Drill Pipe 2-3/8 to 2-7/8 1 2 2 to 3 3 to 4 4 to 6 3-1/2 to 4 2 3 3 to 4 4 to 6 5 to 6 4-1/2 to 6–9/16 2 3 to 4 4 to 6 5 to 9 6 to 12 6-5/8 3 4 to 5 5 to 7 6 to 10 7 – 14 Drill Collars 3-1/2 to 4 2 to 4 2 to 5 3 to 7 3 to 8 4 to 9 4-1/8 to 5-1/2 2 to 4 3 to 6 4 to 8 4 to 10 5 – 12 5-3/4 to 7 3 to 6 4 to 8 5 to 10 6 to 12 7 to 15 Casing 4-1/2 to 5-1/2 3 3 3 3 3 6 to 7 3 3 3 4 4 7-5/8 4 4 4 4 5 8-5/8 5 5 5 5 5 9-5/8 5 5 5 6 6 13-3/8

Note:

The table above shows the quantity of 80 gms/ft RDX prima cord strands to be used according to the depth and pipe size, and assumes a well full of 0.52 psi/ft. mud. Where two values are given, the higher value indicates the

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maximum explosive load that normally will not damage pipe in heavy mud. Such high loads may, however, be detrimental to the electric wireline toolstring, e.g. CCL, cable head, etc.

4.2 Procedures

4.2.1 General Comments

A) The weight of the drill string at the point of back-off should be

correctly calculated. Normally, the buoyancy effect of the mud is ignored, and the weight of the drill string in air is used. The ideal weight condition at the point of back-off is a neutral condition. Determining this condition requires careful calculation, however, where there is any uncertainty, the calculation must be made so as to leave the break in tension

The following information is necessary for an accurate calculation: ? ? The weight of the string when it became stuck (Weight up

and down should be recorded). ? ? Does the string weight include the kelly, and or the

traveling block assembly? ? ? What was the pump pressure prior to sticking? The applied pull is equivalent to the indicated string weight before sticking, minus the buoyant weight of the fish to be left in the hole.

B) Sufficient back-off torque. The amount of reverse torque to be

applied depends on the pipe used, hole depth and deviation and so no hard and fast rule can be laid down. As a general guide, the following figures are recommended:

Drill Pipe Length Turns/1000 ft. Under 4000 ft. 1/4 to 1/2 4000 to 9000 ft. 1/2 to 3/4 Over 9000 ft. 3/4 to 1

It is important to take into account the age and condition of the pipe prior to torquing.

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C) Successful back-offs between drill collars is statistically low. The best string joints for back-off therefore is at the crossover from the drill collars to the HWDP (if unstuck). This enables fishing assemblies to be jarred directly on the drill collar string.

D) Tong and slip dies must be sharp, clean and the correct size to

bite and hold the pipe, kelly or whatever other part of the string protrudes above the rotary table.

E) When applying torque with the pipe in the hand slips (prior to

installing tongs), the slip handles must be tied with soft line to prevent them from slipping or jumping during this operation.

F) When applying torque, the elevators should be latched around the pipe and free below the tool joint so that the pipe can rotate freely through the elevators. The hook should be unlocked when the pipe is being rotated in the slips.

G) If the pipe is to be lifted out of the slips without the tongs

engaged and biting, ensure that there is no residual torque present to rotate the pipe and create a hazard.

H) The bull plug at the top of the swivel must be well maintained so

that if a string shot has to be run through the kelly, it is not necessary to remove the gooseneck.

I) If operational conditions do not allow application of back-off

torque, it may be necessary to “jump a box” using explosive charges run on wireline.

4.2.2 Applying Torque & Working it down to the Stuck Point

It is often necessary to work the back-off torque down the string to the desired back-off depth, especially in crooked or deviated holes. To accomplish this task, the following procedures should be followed: A) Prior to applying the back-off torque, torque the string to the

recommended level. Check the torque amount on the ammeter. When later applying back-off torque, the reading on the ammeter should not exceed the maximum observed while applying initial torque.

B) Set the string at the calculated back-off weight.

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C) Mark the pipe at the top of the slips and refer to this datum mark at all times. Thereafter, do not use the weight indicator because wall friction may cause an inaccurate reading.

D) Apply 50% of the back-off torque required for the back-off and

lock the rotary. E) Use a jerk-line and the rotary tongs to pull off the rotary lock and

hold. F) Pick up the string off the slips and work the pipe vertically a few

times. Do not go lower than the “weight mark” since the pipe may break at random.

G) Set the pipe back on the slips at the “weight mark” and pull on

the tongs to relock the rotary. H) If it is believed that the pipe will accept the remaining torque,

then apply it. If not, apply 50% of the remaining torque and keep repeating steps (C) through (F) until the full amount of the reverse torque is in the pipe.

Note: Using the rotary on the pipe to apply the full back-off torque can damage the pipe and cause the sting to break prematurely. Therefore, use the rotary to apply 50% of the back-off torque and complete the operation using the rotary tongs.

4.2.3 Detonating the Prima Cord

A) Rig up the service company lubricator and pressure test. B) Arm the string shot and run in hole to target depth with the help

of the CCL, as dictated by the Saudi Aramco rig foreman. Note: The tables in section 4.2 above should be used to determine the correct quantity of prima cord strands needed to obtain a successful back-off.

C) Detonate the prima cord while observing the rotary tongs and

torque gauge on the control. D) Pull out of hole with the electric line.

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4.2.4 Completing the Back-off

A) Check for back-off. Usually the pipe has spun free with the box and pin completely unscrewed. In some cases, however, the pipe may only partially back-off and when picking up, no indication of back-off will be observed.

B) Complete the back-off by applying approximately 50% of the

calculated back-off torque to the string and work the pipe up and down while ensuring that the neutral point passes beyond/below the point where the back-off was shot.

C) If any torque is lost, repeat step (a) until the back-off is

completed. D) If no torque is lost, then increase the torque an increment and

observe. E) Reassess the string weight and back-off point, and prepare to

attempt another back-off.

Note: i) Based on experience, if the pipe fails to back-off the first

time after detonating the prima cord, no additional torquing effort will unscrew the selected joint. The next attempt should be at least 1 or preferably 2 joints higher. If the hole is filling rapidly, the string should be backed out of the hole and washover commenced a quickly as possible so that the hole can be brought under control and washover time minimized.

ii) On completion of a successful back-off, pull out of the hole

while checking all connections for the correct make-up torque.

iii) When out of the hole, do not rotate the pipe and do not

circulate unless necessary. iv) When pulling the electric line tool out of the hole, observe

for breaks on the CCL. Also, observe the tension meter in case the tool hangs up.

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4.3 Safety Concerns and Precautions

Since explosive prima cord strand(s) are used to back-off pipe, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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FISHING TOOLS 1.0 INTRODUCTION TO DOWNHOLE FISHING 2.0 TYPES OF FISHING TOOLS

2.1 Overshot 2.1.1 Releasing Overshot

2.2 Spears 2.2.1 Releasing Spear 2.2.2 Wireline Spears

2.3 Safety Joints 2.3.1 Drill Pipe Safety Joint 2.3.2 Washover Safety Joint

2.4 Fishing Bumper Sub 2.5 Fishing Jars 2.6 Jar Intensifier 2.7 Surface Jars 2.8 Impression Blocks 2.9 Die Collars 2.10 Taper Tap 2.11 Junk Baskets

2.11.1 Core-Type Junk Basket 2.11.2 Reverse Circulation Junk Basket

2.12 Fishing Magnets 2.13 Cutters

2.13.1 Jet Cut 2.12.2 Chemical Cut 2.13.3 Mechanical Cut

A) K-Mill B) Internal Casing Cutter C) External Pipe Cutter

2.14 Junk Subs 2.15 Keyseat Wiper or Reamer 2.16 Washover Pipe & Accessories 2.17 Free Point Instrument and Pipe Back-Off 2.18 Casing Scrapers 2.19 Swages and Casing Rollers

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FISHING TOOLS 1.0 INTRODUCTION TO DOWNHOLE FISHING

The word ‘fish’ describes any undesired object in the well bore that must be removed. The equipment required to clean out the hole or to remove an unwanted object is called a fishing tool. When a fishing job develops, all drilling progress ceases and tools and procedures must be utilized to remove the fish. Failure to recover the fish can require redrilling or even abandoning the well. The costs and inherent risks when fishing make it imperative that the operations and engineering personnel involved communicate freely. Predicted additional cost and risk in certain types of fishing operations may make it necessary to change the whole job plan and objective. A) Factors that should be considered when planning a fishing job are: B) The mechanical condition of the wellbore tubulars and the fluids or solids

that they contain. C) Knowledge of the size, amount, and type of fish (all dimensions are

important). D) Location of the fish. E) Predicted cost, probability of success, and risks of failure. One of the most common types of fishing jobs is created when the drilling string parts or is twisted in two. By carefully measuring the pipe that has been removed from the hole, the operator knows the depth at which he must engage the fish. By carefully examining the end piece brought from the hole, the operator can determine if the fish is a drill collar, a tool joint, an external upset section or plain pipe. Although the outside diameters are generally known, it is good practice to caliper the drill collar, the nearest tool joint to the fish, and the drill pipe at the lowermost end to ascertain whether or not the pipe, tool joints or drill collars have been worn to a smaller size than their original outside diameter. The size of the hole being drilled at the time of failure will provide information regarding the amount of room that is available to accommodate the required fishing tool or tools. The first requirement will be to select a suitable tool to engage the fish. If there is sufficient operating clearance, the fishing tool selected should be one that will engage the fish externally. If there is not sufficient clearance to externally catch the tool an internal catching tool should be used.

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For relatively simple, straightforward fishing jobs such as the recovery of pipe inadvertently dropped or left in the hole, an overshot can be used for fast, inexpensive recovery. For a more complicated job-such as recovery of stuck, cemented, or plasticized pipe, or recovery of several wireline tools with the wireline on top of them-special fishing tools and skills will be required. When cases such as these arise, an experienced fishing-tool operator should be considered.

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2.0 TYPES OF FISHING TOOLS 2.1 Overshots

2.1.1 Releasing Overshot

The Releasing Overshot is used to externally engage and retrieve all sizes of tubing, drill pipe, and casing. The overshot is designed to assure positive external engagement over a large area of the fish and is ruggedly built to withstand severe jarring and pulling strains without damage or distortion to either tool or fish. Most overshots consist of a bowl, top sub, guide and the grapple or slip, a control, and packoff. The overshot bowl is turned with a taper on a helical spiral internally and then the grapple, which is turned with an identical spiral and taper, is fitted to it. Overshots are very versatile and may be fitted for a variety of problems. Mill controls may be used to dress the area that the grapple will catch in order to remove burrs and splinters on the pipe. When the pipe has been "shot off" or parted in such a way to heavily damage it, it may be necessary to fit a mill extension, or mill guide, to the overshot bowl so that extensive milling can be accomplished for the catch to be made on the same trip in the hole. These extensions, or guides, are "dressed" inside with tungsten carbide and can mill off a substantial amount of material so that the "fish" is trimmed down to the grapple size. Controls may also be designed with a pack-off, or packer, that seals off around the fish and allows the circulating fluid to be pumped through the fish to aid in freeing the stuck fish.

Top Sub

Packer

Bowl

SpiralGrapple

GrappleControl

Guide

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To properly engage an overshot on a fish, slowly rotate the overshot as it is lowered onto the fish. The pump may be engaged to help clean the fish and also to indicate when the overshot goes over the object. Once this has been indicated by an increase in pump pressure, stop the pump, as there may be a tendency to kick the overshot off the fish. Set the grapple with gradually increasing light upward blows. An excessively hard upward impact may strip the grapple off the fish and cause the wickers to be dulled, resulting in a misrun and trip to replace the grapple. To release overshots, it is first necessary to free the two tapered surfaces, bowl, and grapple, from each other. This freeing of the grapple or "shucking" can be accomplished by jarring down with the fishing string. Usually a bumper sub is run just above the overshot and is used for this purpose. After bumping down on the overshot the grapple is usually free and the overshot can be rotated to the right and released from the fish. If a large amount of the fish has been swallowed, it may be necessary to free or " shuck" the grapple more than once. 2.1.2 Bowen Series 150 Circulating and Releasing Overshots

The following is a complete list of the Saudi Aramco Releasing Overshot inventory: OD TYPE GRAPPLE No. 2-5/8” S.H. B-10204 3-3/8” S.H. B-5091 3-5/8” X.S.H. 9272 3-3/4” S.H. 37591 5-5/8” S.H. B-2201 5-5/8” F.S. 1135 5-3/4” F.S. 6112 5-7/8” S.H. B-4369 7-5/8” S.H. 9863 7-5/8” S.F.S. 1644 7-3/4” S.F.S. 5503 8-1/8” F.S. B-2374 8-1/8” S.H. 9222 8-3/8” S.H. C-5354 11-1/4 F.S. B-12827 11-3/4 F.S 5334 12-3/4 F.S. 15803 13-3/4 F.S. 33009

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2.1.2 Bowen Series 70 Short Catch Overshots

The following is a complete list of the Saudi Aramco Short Catch Overshot inventory: OD TYPE GRAPPLE No. 3-3/4” S.H. 13538 4-1/8” S.H. 10437 5-5/8” F.S. 11300 5-7/8” S.H. 10563 7-5/8” F.S. 11633 7-7/8” F.S. 16978 9-3/4” F.S. 20063 11-1/4” F.S. 33881

2.2 Spears

2.2.1 Releasing Spear

The Releasing Spear is used to internally engage and to retrieve all sizes of tubing, drill pipe, and casing as opposed to overshots which catch on the outside. It is designed to assure positive internal engagement with the fish and is ruggedly built to withstand severe jarring and pulling strains without distorting the fish. Usually a spear is not the first choice, as the spear will have a smaller internal bore than an overshot which limits running of some tools and instruments through it for cutting, free-pointing, and in some cases, backing-off. Spears, however, are popular for use in pulling liners, picking up parted or stuck casing, or fishing any pipe that has become enlarged when parted due to explosive shots, fatigue, or splintering. The most popular spears in use today are built on the same principles as overshots with a tapered helix on the mandrel and a matching surface on the inside of the grapple. The slip or gripping surface is on the outside surface of the spear so that it will catch and grip the inside of the pipe that is being fished. Due to the design with the small bore in the mandrel, spears are usually very strong.

Mandr el

ReleaseRi ng

Gr apple

Nut

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The spear is run inside the fish and positioned. The slips are released by action of the J-slot by using left-hand torque, moving the drill string down a short distance, and then picking it back up slowly. This action releases the slips so they can slide up over a taper on the body of the spear, as the spear is moved uphole. The slips move outward engaging the inner wall of the fish. In order to release a spear, it is rotated to the right. If the grapple is frozen to the mandrel, it may be necessary to bump down to free or 'shuck' the grapple. Usually a bumper sub is run just above the spear and this can be used to effectively jar down and free the grapple. The spear is a very versatile tool, in that it can be run in the string above an internal cutting tool if desired or in combination with other tools. Milling tools may be run below the spear to open up the pipe so that the spear can enter and catch the fish. The following is a complete list of the Saudi Aramco Releasing Spear inventory:

A) Bowen ITC) Releasing Spear

1.660” Shoulder Mandrel Spear Assy. No. 11195 2-7/8” Shoulder Mandrel Spear Assy. No. 17231 3-1/2” Shoulder Mandrel Spear Assy. No. 9410 4-1/2” Flush Mandrel Spear Assy. No. 17475 5” Flush Mandrel Spear Assy. No. 9680 7” Flush Mandrel Spear Assy. No. 9266 8-5/8” Shoulder Mandrel Spear Assy. No. 9380 9-5/8” Shoulder Mandrel Spear Assy. No. 17246

B) Tri-State Releasing Spear

4-1/2” Casing Pack-Off Tools 7” Casing Pack-Off Tools 9-5/8” Casing Pack-Off Tools

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2.2.2 Wireline Spears One of the most challenging of fishing operations may be the recovery of wireline and the tools or instruments run with it. Often times wireline has been parted. When this occurs, wireline slumps down the hole in a coil. The wireline center spear or the two-pronged wire grab, shown at left, is used frequently to remove parted wireline from the wellbore. When the tools are used in casing, a guide should be run above the tool to prevent the wire from getting above the spear.

TWO-PRONGEDWIRELINE GRAB

WIRELINECENTER SPEAR

Crank-shaft

Wireline Spear

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2.3 Safety Joints 2.3.1 Drill Pipe Safety Joint The Safety Joint is a two-piece special connection that can be located at any desired point in a string of pipe. It will withstand all of the normal operation of the string, transmit full torque in either direction or, at the will of the operator, it can be easily released to salvage all of that portions of the string above it. Made up at any desired point in a drilling, fishing, testing, wash-over or tubing string, the Safety Joint operates as a unit unaffected by vibration, inertia of the bit or drill collars, or while rotating out of the well. No movement can occur between the two sections of the Safety Joint nor can it be released without a specific mechanical procedure. When the need arises, it is simple to release and to reengage. A Safety joint is used in a drilling, fishing, testing, wash-over or tubing string whenever and wherever a releasing safety connection is considered to be desirable In Drilling Strings, the Safety Joint is usually located far enough above the drill collars to prevent compression loading and to avoid sticky or heaving formation. Drill pipe Safety Joints have drill pipe box and pin connections with the O.D. and I.D. corresponding to the drill pipe tool joints. The Safety Joint consists of an upper Pin Section, a lower Box Section and two Packers. The upper Pin Section has a box connection up for connecting to the tool joint and abroad helical male thread down for connection to the Box Section. The Box Section has a broad helical female thread matching

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the male thread of the Pin Section and has a tool joint pin connection down for connecting to the pipe. The broad helical matching threads of the Pin and Box Sections allow speed and ease of engagement since they are relatively free of contact as the two sections are made up. However when the Safety Joint is bade up tightly, the reversely pitched surfaces of the joining shoulders grip each other securely, pulling the mating helical surfaces into complete contact and therefore form the Safety Joint into a rigid unit. The Pin Section is grooved at the top and bottom to accommodate the “O” ring type Top and Bottom Packers which seal the Safety Joint from both internal and external fluid pressures. Both Packers are rated for high-pressure operation, capable of withstanding in excess of 10,000 psi in continuous service. 2.3.2 Washover Safety Joint The washover safety joint is used in connecting drill pipe to your washover string. It provides a dependable means of releasing the drill pipe from the washover pipe if the washover string becomes stuck. The lower half of the washover safety joint remains with the washpipe when parted and is full bore to match the washpipe, making subsequent re-entry of other tools possible. A coarse pitch safety thread, in combination with the friction ring, assures proper release when required. Washover safety joints are made from heat -treated alloy steel and are stronger than the pipe that they are designed to run on. The safety joint should be made up properly in the string. This is done by making up the lower half into the washpipe. Make up the top half into the lower half with the same torque as applied to the washpipe connections. To release the safety joint, bump down sharply on the safety joint with drill string while holding a safe, left hand torque. Raise the string slowly while maintaining

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torque. The upper half will unscrew from the lower half, and the friction ring will remain with the retrieved upper half. To re-engage the joint, carefully feel for contact with the lower half, then apply a small amount of weight. Make one revolution to the left, then turn slowly to the right, while maintaining the small amount of weight. An increase in torque will signify that the joint has made up.

2.4 Fishing Bumper Sub To make up a proper fishing string, it is very important that a Bumper Sub be included as one of the components. There are numerous other applications where a Bumper Sub is a required item, such as when drilling in sticking or heaving formations. In these cases the ability to deliver downward blows is necessary to keep the string from sticking. The Fishing Bumper Sub is an inexpensive device designed primarily for use in a fishing string. Under normal conditions, its use is not prolonged over a considerable period of time. Fishing Bumper Subs are installed on fishing strings immediately above the fishing tool or safety joint. Its presence in the string assures the operator of the ability to release the fishing tool in the event it becomes impossible to pull the fish. This device will deliver the sharp downward blow and transmit the torque that is required to break the fishing tool’s engagement and releases it from the fish.

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2.5 Fishing Jars Jars are impact tools used to strike heavy blows either up or down upon a fish that is stuck. Jars fall into two categories as to use: drilling jars and fishing jars. Jars can further be classified as to the basic principle of operation; either hydraulic or mechanical. Most jarring strings used in conjunction with fishing operations consist of hydraulic "Oil" jars. Oil Jars are very effective in freeing stuck fish as the energy stored in the stretched drill pipe or tubing is converted to an impact force, which can be varied according to the pull exerted on the string. The oil jar is designed to strike a blow upward only, while an additional tool; the bumper sub is designed to strike a blow downward on the fish. The oil jar consists of a mandrel and piston operating within a hydraulic cylinder. When the oil jar is in the closed position, the piston is in the down position in the cylinder where it provides a very tight fit and restricts the movement of the piston within the cylinder. The piston is fitted with a set of packing which slows the passage of oil from the upper chamber to the lower chamber of the cylinder when the mandrel is pulled by picking up on the work string at surface. About half way through the stroke, the piston reaches an enlarged section of the cylinder and is no longer restricted so the piston moves up very quickly and strikes the mandrel body. The intensity of this impact can be varied by the amount of strain taken on the work string. This variable impact is the main advantage of the oil jar over the mechanical jar for fishing.

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2.6 Jar Intensifier The Jar Intensifier is perhaps one of the most outstanding devices designed to aid in the successful completion of difficult fishing jobs. The tool is designed to become a component part of a fishing string and to work in conjunction with a Hydraulic Jar to positively insure that the jarring blows are concentrated at the stuck point. The restraining mechanism in a Hydraulic Jar (an expansion joint with a limited longitudinal stroke) permits the buildup of extreme energy in the drill pipe and the ability to suddenly release the energy to drive a mass of weight upwardly to strike a heavy jarring blow. The mass of weight is composed of those drill collars which are installed above the Jar. The energy which has been built up in the stretched drill pipe is often partially dissipated by hole friction, crooked holes, etc. If the tremendous energy stored in the drill pipe can be concentrated at a point close to where the fish is stuck and released in a forceful manner at that point, the net result of the jarring effort is greatly increased. Therefore, the Jar Intensifier is installed immediately above the drill collars. The design of an effective tool of this type is possible because of the development of a good compressible fluid and the unique and extremely effective Seal Ring Assembly similar to that used in the Hydraulic Rotary Jar. The Intensifier is essential in shallow holes when there is insufficient pipe to achieve the necessary stretch to strike a blow.

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2.7 Surface Jars Jars are tools designed to deliver frequent and hammer-like blows to drive a fish toward the surface. The Surface Jar is designed to deliver a heavy downward blow against a stuck fish. The tool performs outstanding service in areas where keyseating is a problem. It is virtually impossible to pull large diameter drill collars up through keyseats; therefore, the solution lies in being able to drive them back down into the open hole. The tool is unusual in that to strike downward blows, the operator actually pulls upward against the tool. The Surface Jars, in fact, reverses the direction of force that is obtained from a Rotary Jar used in a downhole jarring operation. A point of difference between the Surface Jar and a conventional rotary jar lies in the fact that the Surface Jar has a long 48” stroke. In a jarring operation, when the tool trips, the energy that has been built up and stored in the drill pipe creates a force that travels away from the point of release. Since a Surface Jar is installed at the surface, the drill pipe below is stretched and when the Jar trips, the stretched drill pipe will move rapidly to regain its original length. Because the stretched drill pipe is below the Jar, the force will travel in a downward direction, resulting in the weight of the drill pipe being hammered downward against the stuck fish. In this reverse action, it is not necessary that two striking surfaces meet and ordinarily this would never occur unless there was a very great length of pipe between the surface and the stuck point. The purpose of the 48” stroke in a Surface Jar is to permit the drill string to fall heavily against the stuck point. The short stroke in a conventional rotary jar makes it ineffective in a Surface Jar application. The tripping tonnage of the Surface Jar is adjustable, but it should be set so that the pull necessary to trip it does not exceed the weight of the drill pipe between the surface and the stuck point. This is necessary to avoid pulling a stuck drill collar further into a keyseat. Repeating the jarring operations several times normally knocks the drill collars out of the keyseat. Also, a single blow usually is ample to cause the release of a fishing tool when the Surface Jar is used to provide the downward blow required to cause effective disengagement from a fish.

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2.8 Impression Blocks Impression Blocks, which consist of a soft lead insert in the lower end of a steel housing, are used in fishing operations. They are designed to enable the operator to determine the configuration of the top of the fish and to locate its position in the well bore. Its use enables the operator to more precisely assess the fishing conditions and to more accurately select the proper tool or tools needed to successfully complete the fishing operations. The Impression Block is lowered into the well on the lower end of a fishing string of pipe. After the Block contacts the upper end of the fish, the weight of the string is further lowered straight down (never rotate) against the fish which indents into the soft lead lower end of the Block. When the fishing string is withdrawn from the well, the impression in the lead will reveal the condition of the fish.

Impression Block with Transporting Cap

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2.9 Die Collars Rotary Die Collars are the most economical external catch tools for freeing stuck fish. The shallow-tapered, hardened teeth provide excellent engagement. Die Collars are available with plain or lipped bottom or threaded bottom for attaching a lipped guide. The principal advantage of a Die Collar is that it is inexpensive and that it requires virtually no maintenance. The disadvantage of a Die Collar lies in the fact that it cannot be disengaged from the fish in the event that it proves impossible to pull the fish. Furthermore, it is difficult to gauge the amount of torque required for its operation. Insufficient torque results in an insecure hold; too much torque can result in distortion of the fish and damage the tool to such an extent that engagement is lost. Operating Procedure - Tag fish and pick up approximately 2 feet. Rotate slowly while lowering the pipe. (Rotate to the LEFT for left-hand taper tap or die collar; rotate to the RIGHT for right-hand taper tap or die collar). When rotary torque indicates that fish has been engaged, release the torque slowly. Do not allow the pipe to spin freely or fishing tool may back off and disengage from fish. Proceed with recovery operations. Die Collar

Lip Guide

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2.10 Taper Tap The Taper Tap is used to engage a tubular fish internally. This tool screws into the fish and cuts threads as it goes. Cutting new threads is a more positive engagement than attempting simply to screw on or into existing threads on a fish that may be damaged, misaligned, or incomplete. New threads can also be cut on blank pipe. Frequently, the Taper Tap is used to retrieve a production packer after the slip segments and packer elements have been milled with conventional mills.

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2.11 Junk Baskets 2.11.1 Core-Type Junk Basket The Core-Type Junk Basket, as shown, was the old stand-by for years for fishing bit cones and similar junk from the open hole. It consists of the top sub, a barrel, a shoe, and usually two sets of finger-type catchers. This tool is still used quite often, and it is made to circulate out the fill and to cut a core in the formation. The two sets of fingers help to break the core off and retrieve it. Any junk that is in the bottom of the hole is retrieved on top of the core. 2.11.2 Reverse Circulation Junk Basket

The reversing action is extremely helpful in lifting junk into the barrel and catcher that might otherwise be held away from the catcher by fluid flow. The reverse circulation junk basket design incorporates an inner barrel with the fluid flow between the outer and inner barrels when a ball is dropped and closes off the center flow through the seat. With this design, when the ball is circulated down, the flow is diverted between the two barrels and reverse circulation flow is created back up the inside of the junk catcher with the fluid exiting into the annulus through the upper ports near the top of the barrel.

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2.12 Fishing Magnets Fishing magnets are either permanent magnets fitted into a body with circulating ports or electromagnets which are run on a conductor line. Permanent magnets, as shown, have circulating ports around the outer edge so that fill and cuttings can be washed away and contact made with the fish. Ordinarily the magnetic core is fitted with a brass sleeve between it and the outer body so that all of the magnetic field is contained and there is no drag on the pipe or casing. Permanent magnets have the advantage of the circulation washing away any fill so that the junk is exposed. Ordinarily, by rotation, one can detect when contact is made with the fish. The operator should then thoroughly circulate the hole, shut the pump off, and retrieve the fish without rotation

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2.13 Cutters 2.13.1 Jet Cut

A cut made by an explosive shaped with a concave face and formed in a circle. It is also run and fired on an electric line. For details, see Chapter 5, section D.

2.13.2 Chemical Cut

An electric wireline tool and procedure that uses a propellant and a chemical, halogen fluoride, to burn a series of holes in the pipe thereby weakening it so that it easily pulls apart with a slight pull. This method of cutting pipe is the most recent innovation. It was patented and for years was an exclusive process of one wireline company. Today it is available through most electric wireline service companies for practically all sizes of tubing and drill pipe and most popular sizes of casing. All wireline cuts are generally economical because rig time is reduced to a minimum. The big advantage of the chemical cut is that there is no flare, burr, or swelling of the pipe that is cut. Therefore, no dressing of the cut is necessary in order to catch it on the outside with an overshot or on the inside with a spear. The chemical cutting tool consists of a body having a series of chemical flow jets spaced around the lower part of the tool. The tool contains a propellant which forces the chemical reactant through the jets under high pressure and at high temperature to react with the metal of the pipe. Electric current ignites the propellant which forces the chemical, halogen fluoride or bromide trifluoride, through the reaction section which heats the chemical and forces it out the jets. The tool also contains pressure-actuated slips to prevent a vertical movement of the tool up the hole and insure a successful cut. The chemical cutting tool may also be explained as producing a series of perforations around the periphery of the pipe. The reaction of the chemical produces harmless salts which do not damage adjacent casing. The products of the chemical reaction are harmless and are rapidly dissipated in the well fluid. The chemical cutter will not operate successfully in dry pipe and requires at least one hundred feet of fluid above the tool when a cut is made. Since it is not necessary to apply torque to the pipe when chemically cutting as compared with the string shot back-off, it is a safer process for rig personnel.

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Pipe cut wi th aChemical Cutter .

Chemi cal Cut ter

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2.13.3 Mechanical Cut A) K-Mill The K-Mill is a hydraulically actuated tool used to mill a section in casing or tubing. The K-Mill is a simple design, easy to operate, and has an outstanding reputation for milling performance. The Milling knives are dressed with tungsten carbide. The Mill is effective for milling casing, which is poorly cemented, split or corroded. Upon circulation through the tool, a pressure drop is created across the piston. This forces the cam down and expands the cutter knives into contact with the casing. Cut-out knives part the casing then all the knives participate in milling. When circulation is stopped, the piston spring will lift the piston, making the cam withdraw from between the knives. The knives are now free to collapse back into the body and the tool can be retrieved. The tool’s cutting action is very effective with 100’ sections possible with one set of knives.

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B) Internal Casing Cutter Stuck casing can be cut internally with a casing cutter for sizes 1-1/2” up to 20-3/4”. They may be run on macaroni strings, tubing or drill pipe. The Internal Consists of Wiper Block or Drag Spring assembly to accomplish setting the tool in the pipe that is to be cut A) Slips and Cone assembly to anchor the

tool B) Main spring to assist in maintaining

uniform feed to the Knives C) Wedge-like Knife Blocks to drive the

Knives upward and outward into contact with the pipe

D) Hardened and ground Knives for easy and efficient cutting

An outstanding feature of the Internal Cutter is the automatic bottom. This feature permits the operator to set the Cutter at any desired depth, without coming out of the hole. When the cutter reaches a point were a cut is to be made, lowering and rotation to the right unscrews the Mandrel from the Grip Jaw while friction is maintained by the Wiper Blocks against the inside of the pipe. With a wedging action, the cone expands the Slips to engage the Knife Blocks then force the Knives outward, continuing until the cut has been completed. When the string is raised, the Slips are disengaged, the Knives retract, and the cutter returns automatically to its run-in position.

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C) External Pipe Cutter The Hydraulic External Cutters are hydraulically actuated mechanical tubing and drill pipe cutters. The cutters are fast, smooth cutting, efficient, and are capable of cutting and recovering stings of tubing or drill pipe. The Cutter Knives are fed entirely by pump pressure, thus giving the operator sensitive control. To operate, assemble the cutter using the proper size and type of Piston Assembly. Run the cutter into the hole to cutting depth. When cutting depth is reached, open the fill-up and standpipe valves just enough to shear the shear pins. Begin slow rotation, 15 to 25 RPM. Slowly close the bypass valve again to pump fluid down the working string. This will begin feeding the knives to start the cut. The amount of pressure and gallons per minute required depends on the size cutter and piston assembly being used. Use extreme caution to avoid surging or pump pressure when starting a cut. Pressure surging causes the string length to contract and expand, moving the cutter up and down. This motion prevents the knives from remaining in one position when starting a cut. A rough chattering action followed by the smoothing of the rotary will signal the completion of the cut.

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2.14 Junk Subs Junk Subs, which are normally run just above the drill bit, have a cup for catching objects too heavy to be completely circulated out of the hole. This is particularly advantageous in junk milling operations, By running a Junk Sub above the scraper, operators can get quicker, cleaner scraping jobs. Junk Subs are constructed from high quality steel, completely stress-relieved after cup and rib guides have been welded to the main body. Rib guides prevent the Cup from becoming crushed and help guide the tool through tight places upon withdrawal from the hole. There are three main types of Junk Subs, as follows: ?? Boot Type normally run just above the drill bit, utilizing a cup for

catching objects too heavy to be completely circulated out of the hole such as cuttings from milling operations. The boot basket is available in a complete range of sizes from 2 1/4" to 18" and larger, with API Reg. connections.

?? Finger Type utilizes free-spinning finger type catchers to retrieve all

types of small objects in the wellbore. Used with a variety of mill shoes to mill over and retrieve objects. Available in sizes from 3 3/4" to 20" OD.

?? Reverse Circulating Type the principle of reverse circulation ensures

complete recovery of junk in the wellbore. Available in a "full flow" design which permits circulation through the center of the tool while running in the hole. The tool is available in sizes from 3 3/4" to 20" OD.

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2.15 Keyseat Wiper or Reamer One of the major causes of fishing is keyseating. A keyseat is a section of hole where a smaller hole is cut into the wall of the well bore by the movement of the downhole drilling assembly. It usually occurs where the hole changes direction. A section of the downhole drilling assembly can get wedged into the keyseat. Keyseats almost always can be detected in time to take preventive action before the pipe sticks. Proper prevention means observing the signs that a keyseat is developing and immediately eliminate it. The Keyseat Wiper or Reamer, which consists of a mandrel and sleeve with spiraling Tungsten Carbide strips, is located in the string immediately above the drill collars. The Sleeve is slightly larger in diameter than the drill collars. After locating the keyseat, the Wiper or Reamer is raised to engage it. The tool is then rotated causing the Tungsten Carbide strips to cut clearance for the drill collars. During drilling operations, the sleeve remains engaged with the Positive Clutch and rotates with the drill pipe. Should the sleeve become stuck and impossible to rotate, an Overriding Clutch at the upper end will produce a downward blow to assist in dislodging the Sleeve

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2.16 Washover Pipe & Accessories Very often it is not enough merely to catch hold of the fish and pull. In those cases, washpipe and a rotary shoe can be used to rotate over the fish to remove annular material that may be causing it to stick and free up a section of stuck pipe so that it may be retrieved. The outside diameter of the washpipe must be small enough to run inside the casing, and its inside diameter must be large enough to fit over the fish. Washpipe is therefore thin walled and the length of it run in the well must normally be limited to a few hundred feet. The rotary shoe is placed on the end of the washpipe to drill-up and circulate out any material around the fish.

Tubing Fish

Casing

Rotary Shoe

Washover Pipe

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2.17 Free Point Instrument and Pipe Back-off The most common method of parting a downhole assembly is backing it off. The procedure includes the following steps: A) Running a free-point indicator to

determine the free point. B) Placing left hand torque in the drill pipe

downhole assembly and working it down to the point to be baked off

C) Running a string shot across the depth to be backed off and detonating

D) Rotating the pipe until it is backed off and pulled out of hole.

For detailed step-by-step procedures of Pipe Back-off, see Chapter 5, Section D of this manual.

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2.18 Casing Scrapers Casing Scrapers are used for all types of scraping operations. They wil remove cement, mud cakes and asphaltines, as well as perforation burrs and similar obstructions. The Scraper is simple and rugged. It employs hardened steel blades, set in a pattern, which provides 360 degrees of coverage three times, in its working length. No springs, screws or other small parts are used in these tools which could get damage or lost during operations. The tool may be either rotated during operation or spudded up or down with equal effectiveness. Full circulation may be maintained at all times through the tool, although circulation is not required for its operation. The tool allows it to easily enter liners down-hole or re-enter the bottom of the liner, should it pass through the bottom.

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2.19 Swages and Casing Rollers Casing swages are heavily tapered cones which can be driven through the collapse and jarred back out. It is usually necessary to run several sizes in sequence, as the pipe must be swaged out in small increments, sometimes as little as ¼ inch. Most collapsed casing can be swaged out to approximately 1/8 of an inch below the drift diameter. Casing rollers were first made as adaptations of the swage mandrel by merely adding a series of rollers. It is a simple tool for restoring buckled, collapsed or dented casing to its normal diameter and roundness. The tool is rotated slowly and lowered gradually through the casing until the damaged area is located. Upon contact with the collapsed casing, the rotary speed is increased to between 50 and 75 rpm, circulation is established and the roller lowered slowly. The operation of swaging or rolling is rather sever. One should always run the jars and drill collars in either procedure since they can become wedged in the collapsed pipe and must be jarred loose. Once the casing is opened sufficiently, it is usually squeeze cemented or an inner liner run to support the weak casing.

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MILLING 1.0 DOWNHOLE MILLING SUMMARY 2.0 GENERAL DESCRIPTION OF HARDFACING

2.1 Uses of Hardfacing 2.2 Hardfaced Milling Shoes and Rotary Shoes

3.0 OPERATION OF MILLING SHOES AND ROTARY SHOES

4.0 MILLING TOOLS

4.1 Use of Milling Tools 4.2 Recommended Weights and Speeds 4.3 Cuttings 4.4 Mill Stability and Rough Operation

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MILLING 1.0 DOWNHOLE MILLING SUMMARY

“Milling” means to cut, grind, pulverize, or break down metal into smaller particles. These particles are then circulated up the annulus. Mills are used to cut objects that either fall into the hole or get stuck and require removal from the hole or can mill away entire casing sections. Mills are normally built with high quality tungsten carbide called hardfacing.

2.0 GENERAL DESCRIPTION OF HARDFACING

Hardfacing material is composed of crushed sintered tungsten carbide particles compounded with a matrix of nickel-silver alloy. Hardfacing is applied with oxygen acetylene welding equipment. During milling operations, when a hardfaced tool is lowered and rotated against an object, a fish, formation or cement, small tungsten carbide particles imbed themselves into the object. Each tungsten carbide particle creates a small chip along the edge as it is moved along the object, cutting the object. As a particle’s cutting edge becomes dulled, pressures and strains increase causing the particle to fracture and fall off. Such fractures then create a new cutting structure. Once the particle falls off, a new particle in the matrix takes its place as the cutting edge. This process continues until all the hardfacing is exhausted. The hardness of tungsten carbide is almost that of diamonds. It retains its hardness at high temperatures and is not affected by the heat generated by cutting operations. The resilient nickel-silver alloy matrix securely holds the tungsten carbide particles together and in place and cushions the particles against impact forces. Hardfacing is made in two types, cutting type and wear type.

2.1 Uses of Hardfacing

Cutting type tungsten carbide hardfacing is used as the cutting surface in mill shoes, rotary shoes, junk mills, and milling stabilizer construction. Tools dressed with hardfacing are used to mill away all kinds of junk including drill pipe, drill collars, bit cones, casing, liners, and liner hangers. Wear type is used for wear resistance on stabilizers, roller reamer bodies and hole opener saddles and bodies.

2.2 Hardfaced Milling Shoes and Rotary Shoes

Milling shoes and rotary shoes can be designed in various sizes and styles to meet various conditions encountered in well fishing and washover operations.

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Following are examples of mill shoes, and Type A through K rotary shoes, with a brief explanation of their intended applications. Note: When ordering out mill shoes and rotary shoes specify the type from Saudi Aramco Drilling Manual, or Bowen, or Servco, etc. Different manuals describe Types A, B, C, etc. differently so be sure and specify which model is required and which reference the source originated.

Overshot Milling Shoe

Overshot milling shoes are used to mill away jagged metal from the top of fish so that the fish will pass easily into an overshot bowl.

Packer Retrieving Milling Shoe

Packer retrieving milling shoes are used to mill away the slips of a production packer without damage to the casing so that the remainder of the packer can be retrieved. When planning packer milling, specific information must be known concerning packer size, packer type, casing size and weight.

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Junk Basket Milling Shoes

Junk basket milling shoes are used to capture and trap junk too heavy to circulate and mill away jagged edges from small junk or bit cones so that the junk will pass into the basket and be retrieved, or for formation cutting to cut small cores.

Type A Rotary Shoe

Type A rotary shoes are used to cut metal on the fish without cutting casing. It cuts only on the inside diameter (I.D.) and the bottom, does not cut on the outside diameter (O.D.). It can be used with washpipe when washing over drillpipe and tubing.

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Type B Rotary Shoe

Type B rotary shoes are used for washing over a fish and metal and formation in the open hole. It cuts only on the outside diameter (O.D.) and the bottom, and does not cut on the inside diameter (I.D.).

Type C Rota ry Shoe

Type C rotary shoes are used for washing over and cutting metal, formation or cement. It cuts freely only on the inside diameter (I.D.) the outside diameter and the bottom.

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Type D Rotary Shoe

Type D rotary shoes are used to cut metal on the fish without cutting the casing where clearances are limited. It cuts only on the inside diameter (I.D.) and the bottom, and does not cut on the outside diameter (O.D.).

Type E Rotary Shoe

Type E rotary shoes are used for washing over a fish and cutting metal, formation or cement in the open hole casing where clearances are limited. It cuts only on the outside diameter (O.D.) and the bottom, and does not cut on the inside diameter (I.D.).

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Type F Rotary Shoe

Type F rotary shoes are used to size and dress the top of a fish inside the casing. It makes a tapered cut on the inside diameter (I.D.) and cuts on the bottom, and does not cut on the outside diameter (O.D.).

Type G Rotary Shoe

Type G rotary shoes are used for washing over and cutting metal, formation or cement in the open hole casing with limited inside clearances. It cuts on the outside diameter (O.D.), the bottom, and on the inside diameter (I.D.).

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Type H Rotary Shoe

Type H rotary shoes are used for washing over and cutting metal in the open hole casing where clearances are limited. It cuts on the outside diameter (O.D.), the inside diameter (I.D.), and on the bottom.

Type I Rotary Shoe

Type I rotary shoes are used for washing over and cutting formation only. Saw toothed design permits maximum circulation. It cuts on the bottom only. Does not cut on the outside diameter (O.D.) or the inside diameter (I.D.).

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Type J Rotary Shoe

Type J rotary shoes are used for washing over and cutting formation only. Saw toothed design permits maximum circulation. It cuts on the bottom and on the outside diameter (O.D.). Does not cut the inside diameter (I.D.).

Type K Rotary Shoe

Type K rotary shoes are used for washing over and cutting on the bottom face only. Does not cut on the outside diameter (O.D.) or the inside diameter (I.D.).

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3.0 OPERATION OF MILLING SHOES AND ROTARY SHOES

Milling shoes are used to mill over and free stuck packers, spears, stabilizers, string reamers, rock bits or any metal objects which cannot be removed from the well by conventional fishing methods. Milling shoes and rotary shoes are used primarily to dress a fish so that grappling or a retrieving tool may engage the fish. Rotary shoes are excellent for washing over stuck pipe to cut away shales, clay, sand salt or limestone, cement, anhydrite, red beds and other formations. Prior to milling always inspect the ID of subs to insure they are full-bore. While milling, the penetration rate is affected by the hole condition, the rotary speed, the weight of the drill string upon the milling shoe, the weight and viscosity of the drilling fluid, the dimensional size of the milling shoe, and finally the size and hardness of the material to be milled. Based on all of these variables, the optimum weight and RPM cannot be stated to obtain the most efficient penetration rate. Therefore the most efficient weight and RPM must be determined by actual operating conditions. Revolutions may vary from 75 to 150 RPM. Washover or milling operations should begin at a moderate speed and low weight, increasing both until the desired or optimum penetration rate is attained. Lower the washover string into the well until the mill shoe is a few feet above the top of the fish. Begin the pumps and circulate the hole until the top of the fish is clean. Either conventional or reverse circulation can be used. Reverse circulation is often desired because the velocity of the returns is greater and less settling of cuttings will take place. Normal pump pressures are recommended with the mud weight and viscosity being sufficient to circulate the cuttings out of the hole. If many metal cuttings are anticipated, a ditch magnet or other method of surface cutting removal should be considered to prevent damage to surface equipment like pumps. The volume and characteristics of the returned cuttings should be checked frequently since they will provide valuable information on what is being cut and the washover procedure. In the event that penetration rate declines, it is advisable to change the weight or the rotary speed and in some cases spudding on the fish might become necessary to reestablish the desired rate of progress.

4.0 MILLING TOOLS

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Milling tools are designed to mill away a stuck fish that cannot be retrieved by conventional fishing methods. Since milling is usually a follow-up operation (after several fishing attempts), the fish to be milled should be familiar to the operator and therefore the selection of the milling tool should be relatively easy to determine, since the dimensional restrictions of the well should be known. The milling tool selected should provide maximum exposure of the milling edge to the material to be milled, maximum replacement of the milling edge as wear occurs and maximum circulation to remove the cuttings.

4.1 Use of Milling Tools

Most milling tools are simple to operate. Relatively fast rotary speeds should be available as well as drill pipe and drill collars. Rotary speeds may vary from 60 to 175 RPM. Higher rotary speeds are used with smaller diameter mills and slower RPM with larger mills. Rotary speeds are best determined in the field during operations, being dependent on the size and the type of mill, hole conditions and depth, and the material to be milled. For maximum results, the mill should be run beneath a string of drill collars weighing anywhere between 10,000 and 15,000 lbs., depending on the size of the mill. Weight applied to the mill during operations like RPM, will vary due to the size and type of mill, hole condition and depth, and material to be milled. The volume and characteristics of the cutting should be checked frequently since they will provide a great deal of information about the milling progress. Best results are achieved with high volume pumps since high circulation rates will both flush and cool the milling surfaces and circulate the metal cuttings more efficiently to the surface. Annular velocity should be maintained at 80 to 120 ft. per minute. The mud weight and viscosity should be adequate to lift the metal cuttings to the surface. Oil base mud should be avoided whenever possible. Ordinarily, no difficulty is encountered in circulating drilled cuttings under normal drilling practices. Milled cuttings are much heavier than normal drilled formation cuttings, therefore a ratio of plastic viscosity to yield point (PV/YP) as close to 1.0 is ideal for steel cutting removal. If the ratio is higher than 1.5, a common remedy is to add LCM to the mud. This will help to sweep the hole and aid in carrying the cuttings up the annulus and out of the well. Polymer muds are best for milling operations with clay based muds being a second choice and oil base mud being third. A ditch magnet or other method of surface metal cutting removal should be considered to prevent damage to surface equipment when the metal cuttings become excessive. If the cutting cannot be brought to the surface with the circulating system being used, then boot or junk baskets should be run just above the mill or drill collars to catch the cuttings.

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Milling operations begin by lowering the drill string down to within a few feet of the object to be milled. Start the pumps and circulate to remove any debris that might have fallen on top of the fish. Rotate at a moderate speed and slowly lower the drill string until the mill makes contact with the object to be milled. The first 30 minutes should determine how fast the penetration rate will be. The first 4 to 5 ft. of a milling job are extremely critical, especially during section milling. Cuttings tend to accumulate at the cutting knife. This can cause bird nesting. Slowly increase the RPM and gradually increase the weight until an optimum penetration rate is achieved. Too much weight will merely grind down the carbide and matrix and prematurely dull the mill. Never mill faster than it is possible to remove cuttings. If bird nesting occurs, pull up and circulate until proper cutting return is achieved. The following are some examples of milling tools,

Junk Mill

A) Junk mills are used to mill away metal objects in the hole that cannot

be retrieved with grappling tools or junk baskets. These mills are the toughest mills and referred to as workhorses of downhole milling operations. The blade forms of all junk baskets are designed so that they hold the junk in place to be milled under the milling face. Therefore the mill continuously cuts rather than sweeping the junk ahead of the blades. The junk mills selected should be 1/8 to ¼ in. less than the minimum inside diameter of the casing or open hole through which it is

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to be run. Run a junk sub directly above the mill. Have a minimum of 10,000 lbs. of drill collar weight available. Frequent spudding may be required to break up loose junk, this action will pound the junk down into the bottom, positioning it better for effective milling. Never allow a piece of junk to lodge next to the mill. Force it down by spudding the mill. A noticeable increase in torque will indicate that junk is alongside.

B) Special Design Junk Mill Aramco and Weatherford have designed an

8 bladed junk mill with a 3-deg. lay back on the cutters and a ½ in. offset nose from the center (in the 12-in. size). This mill has proven very reliable when milling up drillpipe. It can be used with a skirt on the outside to protect the casing when milling drillpipe inside casing. See pictures below.

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Round Nose Mill

Round nose mills are used primarily to mill out the bottom of liners or casing which have been set with a bull plug during original completion. Round nose mills cut on the leading edge or nose, along the taper but not full circumference of the mill.

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Taper Mill

Taper mills are used primarily to mill collapsed pipe, to restore elliptical pipe to full bore, and to remove restrictions from the inside diameter such as landing seats, bushings, and other metal objects that might restrict the well bore. Taper mills have cutting structures along the taper.

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Flat Bottom Mill

Flat bottom mills are used to mill bits cones and other pieces of junk if they cannot be recovered by other means of recovery. Flat bottom mills normally have a concave face on the bottom to keep the junk centered under the mill.

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Watermelon Mills or String Mills

Watermelon mills or string mills are used to open up tight spots in pipe, to enlarge and clean up a window cut in casing, or in some circumstances, to run in collapsed casing that has been partially opened up. With a guide below the mill, it will not go outside as is possible with a tapered mill.

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Piranha Mills

Piranha mills are used solely for the removal of downhole casing strings. The effecting milling weight has been found to be 5,000-10,000 lbs. with Piranha mills. Stabilization is necessary with this mill. A sleeve type stabilizer is included in the tool’s design. The OD and stabilizer diameter is sized to prevent damage to the outer casing strings. Refer to the mill handbook for further details.

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Pilot Mills

Pilot mills are used primarily to mill up wash pipe, safety joints, crossover swages, drill pipe, casing, liners and washover shoes in the hole. The stinger can be equipped with a retrieving tool on the bottom. In selecting a pilot mill, the blade OD should be about 1/4 in. larger than the OD of the tool joint or coupling to be milled. The pilot OD should be about the same as the drift diameter of the tubular.

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Section or K-Mills

Section or K-mills are hydraulically actuated tools that are used to mill a section of casing or tubing. Circulation through the tool creates a pressure drop across the piston. This forces a cam down, expanding the knives into contact with the casing. Cut out knives part the casing then all knives are used to mill. When circulation is stopped, the piston spring will lift the piston,

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withdrawing the cam from between the knives. The knives are now free to collapse back into the body and the tool can be retrieved.

It is important to insure that the mill completely cuts through the casing (cutting out) so the blades can be firmly seated on casing while milling. If you experience a sudden drop off of penetration rate of the mill, this may be attributed to a loose ring of steel from the casing coupling. This ring will rotate with the section mill. Lightly spudding the section mill should break up the ring. Pump rates for the K-Mill are pre-determined and depend on the tool size, refer to a Servco handbook for the required flow rates for different K-Mill sizes. The correct GPM must be selected to produce the desired pressure drop through the K-Mill providing efficient tool operation. The most common cause of difficulty in cutting out is insufficient pressure at the tool. Approximately 300 psi is required to keep the cutting knives open and part the casing.

4.2 Recommended Weights and Speeds

Usually the most efficient rotary speeds are obtained by running the rotary at 80 to 100 RPM. Milling with washover shoes is an exception, they are usually more efficient when run at 60 to 80 RPM. High speed can burn or damage the tungsten carbide, which is critical to milling steel. Tungsten carbide cuts steel best at 3000 to 4000 surface inches per minute. The following formula determines the recommended rule of thumb minimum and maximum milling RPM’s,

MIN/MAX RPM = Surface Speed/(Tool OD x 3.14)

For example, for a 12 in. mill,

Min RPM = 3,000/(12 x 3.14) = 80 RPM

Max RPM = 4,000/(12 x 3.14) = 106 RPM

For optimum penetration rates, it will be necessary to try different rotary speeds, weights, and pump pressures. When the penetration rate slows down varying one or more of the above variables might be required to attain the desired penetration rate. Occasionally spudding on the fish might help. If the penetration rate cannot be increased to what it should be by varying

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some of the above mentioned variables or by light spudding, the mill might need to be pulled out of the hole because the hardfacing might be worn off.

4.3 Cuttings

Ideally cuttings should be 1/32 to 1/16 in. thick ands 1” to 2” long. If cuttings are long thin stringers, increase the milling weight. If fish scale type cuttings are being returned when pilot or section milling, the penetration rates will improve by decreasing weight and increasing RPM.

4.4 Mill Stability and Rough Operation

A mill that moves eccentrically does a poor job. Stabilize above the mill at 60 ft. or 90 ft. intervals. The stabilizer OD should not exceed the dressed OD of the mill. Section and pilot mills should also be stabilized to the drift diameter of the casing. When rough running and bouncing occurs, decrease weight, then slowly increase speed and weight until an acceptable ROP is obtained. If rough running reoccurs, once again decrease and then gradually increase to a maximum ROP.

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SECTION A TRAINING REQUIREMENTS __________________________________________________________________________________________________________________________

TRAINING REQUIREMENTS 1.0 HYDROGEN SULFIDE

2.0 WELL CONTROL

3.0 CRANES AND HEAVY EQUIPMENT

4.0 OFFSHORE SURVIVAL

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TRAINING REQUIREMENTS 1.0 HYDROGEN SULFIDE

1.1 Upon reporting to any rig, all persons must receive basic H2S training from the H2S safety service contractor assigned to that rig OR provide proof (i.e. a valid & current training card) that they have already received this orientation.

1.2 The H2S safety service contractor will conduct basic H2S training as required to ensure that the training standards listed below are met.

1.3 All basic H2S training will include the actual donning and breathing from each different type of breathing apparatus in use on that particular rig. Each person must be able to don and breathe from the breathing apparatus within 45 seconds.

1.4 A training card will be issued to each person completing the basic H2S training. This card will remain valid for 2 years, following which the person must retake the basic H2S training.

1.5 All personnel on all rigs must be capable of the following: 1.5.1 Don & breath from breathing apparatus within 45 seconds. 1.5.2 Identify the H2S alarm. 1.5.3 Identify wind direction.

1.5.4 Evacuate to the upwind safe briefing area immediately upon hearing

the H2S alarm (on land rigs).

1.5.5 Muster to the Safe Briefing Area (onshore) or their boat station (offshore), and enter/fasten seat belts in their assigned boat while wearing both their PFD and breathing apparatus.

1.6 In addition to the basic skills listed above, anyone whose duties include working on the rig package must be fully competent perform the tasks assigned to them by to the rig’s H2S emergency plan.

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1.7 All drilling contractor rig crew must be able to perform mouth-to-mouth resuscitation. (Mouth-to-mouth resuscitation is the basic lifesaving technique to revive someone who has succumbed to H2S poisoning. Therefore, it is critically important that each rig have an adequate number of people trained in this technique.)

1.8 The Workover/Drilling Foreman is responsible to verify that H2S training requirements are met. This will be done by observing H2S drills, and by random testing to verify competence in breathing apparatus use.

2.0 WELL CONTROL 2.1 Anyone assigned to the following positions must have a current well control

certificate meeting IWCF requirements: 2.1.1 Assistant Driller 2.1.2 Driller 2.1.3 Toolpusher (or Rig Manager, or any other senior contractor

supervisor) 2.1.4 Workover/Drilling Foreman 2.1.5 Workover/Drilling Engineer

2.2 The drilling contractor is responsible to ensure that all drilling crew are fully competent in the tasks assigned to them by the rig’s well control plans (e.g. BOP drill duties).

2.3 The Workover/Drilling Foreman is responsible to verify that well control training requirements are met. This will be done by the following: 2.3.1 Maintaining copies of current well control training certificates in the

rig’s training file.

2.3.2 Observing BOP drills.

2.3.3 Randomly questioning the drillcrew to verify their understanding of their role in BOP drill and well killing procedure.

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3.0 CRANES & HEAVY EQUIPMENT 3.1 All crane and heavy equipment operators shall have a valid Saudi Aramco

operator certificate as per G.I. 7.025 requirements.

3.2 The drilling contractor is responsible to ensure that all crane and heavy equipment operators have valid certificates, by arranging for testing with the Saudi Aramco Vehicle & Heavy Equipment Training & Testing Unit (Tel. 874-1857).

3.3 The Workover/Drilling Foreman is responsible to verify that crane and heavy equipment operators have valid Saudi Aramco operator certificates by maintaining copies of current certificates in the rig’s training file.

3.4 The Workover/Drilling Foreman is responsible to ensure that no one operates cranes or heavy equipment without a valid Saudi Aramco operator certificate.

4.0 OFFSHORE SURVIVAL CRAFT & HELICOPTER SAFETY All Saudi Aramco employees working offshore on a regular basis shall complete the Saudi Aramco Survival Craft and Helicopter Safety training programs offered by N.A. Job Skills Satellite Training Unit.

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SECTION B RIG SAFETY INSPECTIONS & MEETINGS __________________________________________________________________________________________________________________________

RIG SAFETY INSPECTIONS & MEETINGS 1.0 PHYSICAL CONDITIONS INSPECTIONS

2.0 SPECIALIZED INSPECTIONS

2.1 Rig Accommodations, Camp, and Kitchen 2.2 Crane & Hoisting Equipment Inspections 2.3 Marine Inspections

3.0 SERVICE COMPANY INSPECTIONS

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RIG SAFETY INSPECTIONS & MEETINGS 1.0 PHYSICAL CONDITIONS INSPECTIONS

1.1 The Workover/Drilling Foreman is responsible to verify that the rig complies

with Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations.

1.2 Workover/Drilling Superintendent will verify compliance by conducting Quarterly Safety Inspections (QSI) on each rig in their Division. Loss prevention shall also be invited to participate in each QSI.

1.3 Workover/Drilling Foremen are encouraged to submit their comments to Drilling management with respect to improving Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations, by identifying omissions, recommending new policy, etc.

2.0 SPECIALIZED INSPECTIONS 2.1 Rig Accommodations, Camp, and Kitchen

2.1.1 The appropriate Environmental Health Unit (EHU) of the Preventive

Medicine Services Division will conduct an inspection of every rig camp once per quarter.

2.1.2 The Workover/Drilling Foreman is responsible to contact the appropriate Environmental Health Unit to arrange the camp inspection:

Northern Area EHU.................. Tel: 678-4868, 678-4914 ................. Fax: 678-4910 Central Area EHU .................... Tel: 877-8426, 877-8371 ................... Fax: 877-8444 Southern Area EHU ................. Tel: 572-2076, 574-6796 ................. Fax: 572-2220 2.1.3 Following the EHU inspection and report, the Workover/Drilling

Foreman will follow up with the Toolpusher or Camp Boss to ensure corrective actions are taken to comply with EHU requirements.

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2.1.4 Copies of EHU camp inspection reports will be kept on file at the rig

for 2 years. 2.1.5 Workover/Drilling Superintendent will verify compliance by reviewing

EHU inspection documentation during rig Quarterly Safety Inspections.

2.2 Crane & Hoisting Equipment Inspections 2.2.1 The Crane Inspection Unit shall inspect all hoisting equipment on

each rig as per G.I. 7.027 requirements.

2.2.2 The Workover/Drilling Foreman is responsible to contact the appropriate Crane Inspection Unit office to arrange for crane inspection.

2.2.3 No hoisting equipment shall be operated on a drilling rig without a valid crane inspection certificate.

2.2.4 Workover/Drilling Superintendent will verify compliance by reviewing crane inspection documentation during rig Quarterly Safety Inspections.

2.3 Marine Inspections

2.3.1 The specialized marine equipment (e.g. life boats) shall be inspected by a representative of the Saudi Aramco Marine department once per quarter.

2.3.2 The Workover/Drilling Foreman is responsible to contact the Marine Department to arrange for the inspection.

2.3.3 Workover/Drilling Superintendent will verify compliance by reviewing Marine inspection documentation during rig Quarterly Safety Inspections.

3.0 SERVICE COMPANY INSPECTION The Workover/Drilling Foreman is responsible to ensure all service company equipment meets Saudi Aramco standards before work begins. Specific requirements for the various services will be found in sections of this Workover Manual dealing with each activity, e.g. logging, perforating, etc.

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SECTION C H2S CONTINGENCY PLAN ____________________________________________________________________________________________________________

H2S CONTINGENCY PLAN 1.0 INTRODUCTION

2.0 PREPLANNING FOR WORKOVERS (PRIOR TO MOVING ON LOCATION) 2.1 Responsibilities

3.0 COMPLIANCE FOR WORKOVERS (PRIOR TO NIPPLING DOWN THE TREE) 3.1 Training 3.2 Safety Equipment 3.3 BOPE, Surface Equipment & Downhole Tools

4.0 OPERATIONAL CONDITIONS (ALERT LEVELS)

4.1 Level 0: [H2S] = 0, Normal Operations in Potential H2S Zones 4.2 Level 1: 0 < [H2S] < 10 ppm, Acceptable amount of H2S is present 4.3 Level 2: 10 < [H2S] < 100 ppm, Anywhere but on the drill floor 4.4 Level 3: 10< [H2S] < 100 ppm, On the drill floor 4.5 H2S Emergency, [H2S] > 100 ppm 4.6 H2S Orientation Requirements

5.0 SPECIAL OPERATIONS 5.1 Well Control 5.2 Highly Deviated and Horizontal Wells 5.3 Lost Circulation 5.4 Stuck Pipe

6.0 ATTACHMENTS (FOR A SITE SPECIFIC PLAN)

6.1 Well Coordinates, Expected H2S Zones and Potential Contact Points List 6.1.1 Re-Entry Sidetracks

6.2 Map Showing Potential Contact Points, Highways and Roads 6.3 Rig Layout Showing Access Roads, Flare Pits, etc.

Note: For an offshore rig, this would be drawings for each deck.

7.0 APPENDIX 7.1 Saudi Aramco Standard Safety Equipment for H2S Operations on all

Onshore Drilling and Workover Rigs 7.2 Safe Briefing Area Equipment List 7.3 Typical H2S Drill 7.4 Attachment for Offshore Wells 7.5 Saudi Aramco Standard Safety Equipment for H2S Operations on all

Offshore Drilling and Workover Rigs 7.6 G. I. 1850.001, Onshore Contingency Plan (for emergencies and

disasters) 7.7 G. I. 1851, Offshore Contingency Plan (for emergencies and disasters) 7.8 Physical Properties of H2S and Toxicity Table

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H2S CONTINGENCY PLAN 1.0 INTRODUCTION

This H2S contingency plan includes precautionary measures, safety equipment, emergency procedures, responsibilities and duties pertaining to well work where Hydrogen Sulfide (H2S) is known or suspected to be present. The plan specifies preliminary preparations prior to moving on location and full compliance prior to nippling down the tree on a H2S well. These preparations either reduce the risk of an H2S incident or lessen the response time should an incident occur. It specifies what should be done during normal well work and completion operations to reduce the risk of controlled or uncontrolled H2S release. It also defines the three types of releases as commonly accepted by the industry (Condition I, II and III), slightly modified to fit existing Saudi Aramco policy and how to respond to each. This plan was developed because of the potential hazards involved when working and completing in formations that contain Hydrogen Sulfide (H2S). Saudi Aramco’s priorities are the preservation and protection of human life first and foremost, with the rig and well having second priority. Every effort will be made to provide adequate safeguards against harm to persons both on location and in the vicinity from the effects of H2S. To be effective, this plan requires the cooperation and effort of each individual involved in the workover operation. Each individual should know his responsibilities and duties in regard to normal operating procedures and emergency operating procedures. He should thoroughly understand and be able to use each type of breathing apparatus in use on the rig and any other safety equipment that he might be required to operate, monitor or service and know where each piece of equipment is stored. The ideas and suggestions of each individual involved in the workover/completion of the well are highly welcomed and necessary for providing absolutely the safest working conditions possible.

2.0 PREPLANNING FOR WORKOVERS (PRIOR TO MOVING ON LOCATION)

Special consideration should be given to the “Workover Program” of a well that will contain H2S. It is beyond the scope of this contingency plan to go into detailed well planning. However, the Workover/Drilling Engineer should plan the workover on the concept that any release of H2S is hazardous to human life, that the risk of such a release should be minimized and that an uncontrolled release is intolerable and should be avoided at all costs. Selection of the workover fluid system and the barriers required for isolation create the most obvious impact on this risk. 2.1 Responsibilities

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2.1.1 Drilling and Workover Management will decide if a site-specific H2S plan is warranted. Proximity to the general public and to other Aramco facilities should be considered. Wells with manned facilities, residences etc., within a 5km radius and anticipated H2S should have a site-specific plan. H2S wells falling outside the above categories would be a judgement call. Under the generally accepted definition of an H2S well (capable of producing atmospheric concentrations of 20ppm or greater), even an Arab-D oil well would be considered an H2S well.

2.1.2 Once it is decided that a site-specific plan is warranted, it shall be the

responsibility of the Workover/Drilling Engineer, with assistance from Facilities and Projects, to obtain the surveyed well location and prepare a list and map showing that location, distances and directions to all manned facilities and points of possible contact within a 5 km radius. This map should show all roads and highways.

2.1.3 A phone list will be compiled by the Workover/Drilling Engineer giving

the contact phone numbers (a 24 hour contact for any facility that is not manned 24 hours per day) of any facilities near the location and the phone number of the nearest Saudi Aramco Industrial Security main gate. The phone list, location map, and H2S Contingency Plan should be attached to the Workover Program and sent to each facility listed. The map and phone list should also be sent to Industrial Security, Loss Prevention and Government Affairs to assist them in carrying out their duties under GI’s 1850 and 1851, should an emergency be declared. The cover letter to each of the above with the map and phone list should give Drilling and Workover contact names and phone numbers and it should reference the above G. I. See G. I. 1850 and 1851 in Appendix.

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2.1.4 It shall be the responsibility of Government Affairs to give advanced notice to the general public and prepare any evacuation plans if deemed necessary. They shall also be responsible for notifying any interested Saudi Arabian Government Authorities.

2.1.5 Drilling & W/O Operations (Supt. or Foreman) shall be responsible for

surveying the rig to assure that tubulars, BOP’s, choke manifolds, degassers, flares lines etc. meet the requirements for H2S service set forth in the Aramco Well Control Manual. This will be especially critical if it is the first H2S well for the rig in question. Operations will also be responsible for assuring that the location is built to specifications for H2S wells and that the rig camp is the required 3km from the wellsite.

2.1.6 The “H2S Safety Representative” (whether a drilling contractor safety

man, drilling contractor Toolpusher, Loss Prevention safety man, a second Saudi Aramco Workover/Drilling Foreman in charge of H2S safety, or a third party consulting H2S specialist) shall be responsible for inventorying all H2S Safety Equipment, repair or replacement as needed. He shall be a certified trainer and shall be responsible for conducting H2S training in safety, the use of breathing equipment, and competency drills. Regardless who is the designated “H2S Safety Representative”, the Workover/Drilling Foreman is ultimately responsible for confirming that the training and drills have been properly carried out. See “Saudi Aramco Standard Safety Equipment for H2S Operations”, Appendix 1 (onshore) and 5 (offshore) and “Training Requirements” in Chapter IX, Section A of this Workover Manual.

3.0 COMPLIANCE FOR WORKOVERS (PRIOR TO NIPPLING DOWN THE TREE)

Full compliance with the H2S Contingency Plan is required prior to nipple down of the tree on workovers. This will result in less preparation time to check all H2S safety equipment and prepare rig personnel.

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3.1 Training

3.1.1 The “H2S Safety Representative” (as defined in Section I) will immediately begin training crews, ensuring that everyone on the rig site has received an H2S orientation and that it has been recorded in the training file.

3.1.2 Everyone on the rig site shall be trained in the proper response to H2S

alarms. Drills should be held as often as deemed necessary by the Aramco Foreman and the “H2S Safety Representative” until satisfactory performance is obtained, then once per week per crew thereafter. These weekly drills will be documented in the IADC morning report book. See Appendix , “Typical H2S Drill”.

3.1.3 The Workover/Drilling Foreman will designate two safe-briefing areas

such that at least one will always be upwind of the wellbore under prevailing wind conditions. The primary area will be near the Saudi Aramco/ Contractors offices (generally upwind). This upwind location will be a gathering point for the above drills.

3.1.4 Everyone who might work on or come in contact with the rig package

shall be trained in breathing apparatus use and user inspection with a record kept in the training file. See “Training Requirements” in Chapter IX, Section A, of the Drilling Manual.

3.1.5 The Workover/Drilling Foreman will ensure that a sign is posted,

notifying all visitors to report to the Aramco office to verify that they receive or already have H2S orientation. This must be documented as per item 1, above. The Foreman may delegate these duties, but he remains responsible.

3.1.6 Following H2S orientation, all visitors will be able to recognize the H2S

alarm and will proceed to the upwind safe briefing area upon hearing the alarm. If a visitor is required to work on the rig package, he must also be able to properly don and use the breathing apparatus.

3.2 Safety Equipment

3.2.1 The primary “Safe Briefing Area” will be near the Saudi Aramco and

Drilling Contractors offices and should include the equipment listed in “Equipment Requirements” Appendix 2, “Safe Briefing Area Equipment List”. When not in use, this equipment may be stored in the adjacent offices, the Aramco Storehouse etc., as long as it is readily available.

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3.2.2 The H2S Safety Representative should ensure that all safety equipment for H2S operations is in place prior to removing the tree, as required by “Saudi Aramco Standard Safety Equipment for H2S Operations”, Appendix 1.

Note: There is a separate list for Offshore Rigs in Appendix 4.

3.2.3 The Saudi Aramco Workover/Drilling Foreman with assistance from

the H2S Safety Representative will ensure that sensors and warning devices listed in Appendix 1and 4, and referenced above, are rigged up and properly working prior to removing the tree. Occasionally, more stringent monitoring may be required, in which case the actual requirements should be included under Appendix 1, under a sub-heading of “Additional Monitoring Equipment and Warning Devices”.

3.3 BOP, Surface Equipment , Downhole Tools

3.3.1 The Saudi Aramco Workover/Drilling Foreman with assistance from

the Toolpusher or senior contractor representative will inspect and insure that BOP and surface equipment meets the standards set forth in the “Saudi Aramco Well Control Manual” for H2S service (NACE Standard MR-01-75-96). This should be done well in advance of nipple-up so that changes can be made if necessary. This will be a second check since most equipment should have been checked out prior to spud.

3.3.2 The Workover/Drilling Foreman should verify that drill pipe and all

downhole tools to be used are of metallurgy suitable for H2S service and order replacement equipment as needed. This will also be a second check.

3.3.3 The Workover/Drilling Foreman and wellsite mud engineer should

confirm that an H2S Scavenger (zinc oxide or an equivalent scavenger) is available and sufficient quantity is on location to treat the entire mud system with 2 lb/bbl., or as required.

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4.0 OPERATING CONDITIONS (ALERT LEVELS)

The Workover/Drilling Foreman is responsible to take every practical precaution to maintain a safe working environment while these remedial actions are being taken to reduce the amount of H2S circulated to surface. This section outlines drilling operations when drilling through zones known or suspected to contain H2S. While drilling these zones, the rig will conduct operations based on the following classifications of H2S risk. Note: [H2S], using square brackets, refers to H2S concentration, usually

measured in ppm (parts per million). Alert Level H2S Concentration [H2S] Comments

Level 0: [H2S] = 0 ppm Normal operations

Level 1: 0 ppm < [H2S] < 10 ppm Normal operations, but increased alertness, preparing for next level. Restricted access to affected areas.

Level 2: 10 ppm < [H2S] < 100 ppm (but not on drill floor)

Restricted access & breathing apparatus required in affected areas [H2S] > 10 ppm. Non-essential personal removed from rig package. Immediate action taken to reduce mud H2S levels.

First alarm at 10 ppm, high alarm at 20 ppm.

Level 3: 10 ppm < [H2S] < 100 ppm (on the drill floor)

Approaching an emergency situation.

First alarm at 10 ppm, high alarm at 20 ppm.

H2S Emergency

[H2S] > 100 ppm Actions taken to reduce H2S concentrations have failed and an emergency situation has been reached. This is not necessarily an uncontrolled release but would include uncontrolled releases.

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4.1 Level 0: [H2S] = 0, Normal Operations in Potential H2S Zones

The following items shall be done even when no H2S has been detected:

4.1.1 All H2S detection equipment will be function tested daily and documented in the IADC book.

4.1.2 H2S detection equipment will be calibrated weekly and documented in the rig PM file.

4.1.3 All breathing apparatus will be ready for immediate use and in place as per contract specifications and Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations.

4.1.4 All breathing apparatus on the rig (SCBA & SABA) will be inspected weekly, documented in rig PM file. A quick release (e.g. string) tag is used to seal each container, and the inspection date and inspector initials are written on the tag.

4.1.5 Each stored breathing apparatus (i.e. not on the rig package) will be inspected and containers sealed with a quick release (e.g. string) tag. The inspection date and inspector initials are to be written on the tag. The tag/seal on stored breathing apparatus will be inspected monthly to ensure the container has not been opened. If tags are missing or disturbed, the stored apparatus will be re-inspected and re-tagged.

4.1.6 Supplied air (cascade) manifold gauges are checked for proper pressure and air lines checked for proper operation every tour (i.e. at every crew change). This is documented in the IADC book.

4.1.7 Windsocks are in place such that the wind direction can be readily identified from anywhere on the location.

4.1.8 All other safety equipment (e.g. bug blowers, etc.) is in place as specified by Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations, Appendix XX.

4.1.9 Two safe briefing areas have been marked out and identified and the entrance sign has been posted as specified in Section III.

4.1.10 The drills specified in Section III will continue a minimum of once per week per crew and will be documented in the IADC book. Orientation and training on breathing apparatus will continue so that new arrivals and visitors are covered. Following their H2S orientation, all visitors will be able to recognize the H2S alarm and will proceed to the upwind safe briefing area upon hearing the alarm. Note: If visitors are required to work on the rig package they must also be able to properly don and use breathing apparatus.

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4.2 Level 1: 0 < [H2S] < 10 ppm, Acceptable amount of H2S is present

Level 1 begins whenever H2S is detected anywhere on the rig. Typically, this will be at the shale shaker, when safe concentrations (i.e. less than 10 ppm) of H2S are being released to the atmosphere. Although this is a safe H2S concentration, everyone must be alert to the fact that the H2S concentration could increase at any time. Upon reaching Level 1 conditions, the Workover/Drilling Foreman shall take the following actions.

4.2.1 All of the previous H2S level precautions are already in place.

4.2.2 The area around the shale shaker and the rig cellar will be declared “restricted areas”. No one may approach these areas without the following:

A) Ready access to breathing apparatus,

B) Continuous awareness of current H2S concentration (e.g. personal H2S monitor giving continuous readouts.

C) Continuously observed by a stand-by man who also has immediate access to breathing apparatus (e.g. “buddy system”).

4.2.3 Appropriately rated (i.e. “explosion-proof”) bug blowers will be positioned to provide adequate ventilation to H2S contaminated areas and the rig floor.

4.2.4 The Toolpusher or designated “H2S Representative” (as defined in Section II) shall conduct an initial H2S safety meeting with each crew. H2S safety will be discussed at a brief tool-box safety meeting at every shift change.

4.2.5 The H2S concentration in the mud is checked a minimum of every 24 hours, more often at the Saudi Aramco Foreman’s discretion. The Garret Gas Train Kit will be used for this determination.

4.2.6 The Workover/Drilling Foreman shall identify possible courses of action to take should the H2S concentration increase to higher levels (e.g. treat mud with H2S scavenger).

4.2.7 The Drilling Foreman shall take appropriate actions to maintain H2S levels below 10 ppm. The objective is to minimize the number of times the H2S alarms sound. (If the 10 ppm H2S alarm becomes excessive, it will contribute to complacency and lose its effect as a warning sign.)

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4.3 Level 2: 10 < [H2S] < 100 ppm anywhere but on the drill floor.

Saudi Aramco policy requires breathing apparatus to be worn when working in an atmospheric H2S concentration higher than 10 ppm. Therefore, every practical precaution shall be taken to either reduce atmospheric H2S levels to less than 10 ppm, or to declare “off-limits” those areas with an atmospheric H2S concentration higher than 10 ppm. When drilling through H2S bearing zones, it is not uncommon to have H2S breaking out at the shale shaker as drilled gas. This can be addressed by treating the mud with scavenger, weighting up to increase overbalance and restricting access to the shaker area. The rate of penetration can be controlled or even halted until corrective measures have been taken. Upon reaching Level 2 conditions, the Workover/Drilling Foreman shall take the following actions.

4.3.1 Ensure that all of the previous H2S level precautions are already in

place.

4.3.2 The rig crew shall respond to the low level (H2S >10 ppm) alarm with their H2S drill (as previously trained).

4.3.3 The Workover/Drilling Foreman, assisted by the Senior drilling contractor representative, shall identify the source of the H2S, and respond accordingly (As stated above, if the H2S release is confined to the shale shaker area only, this is not as critical a situation as [H2S] > 10 on the drill floor).

4.3.4 Hand-held H2S monitors shall be used to continuously measure atmospheric H2S concentrations.

4.3.5 The Workover/Drilling Foreman shall implement appropriate procedures to reduce atmospheric H2S levels in the affected areas (e.g. treat mud with H2S scavenger, increase overbalance, increase ventilation to area, etc.).

4.3.6 The H2S concentration in the mud shall be checked every 4 hours or as directed by the Workover/Drilling Foremen. The Garret Gas Train Kit will be used for this determination.

4.3.7 Breathing apparatus must be worn when entering an area with atmospheric H2S concentration higher than 10 ppm. No one shall remain in an area with [H2S] >10 ppm unless their presence is absolutely necessary to regain a safe working environment

4.3.8 A strict “buddy system” shall be enforced throughout the rig package, and immediately downwind of the rig.

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4.3.9 The rig substructure, shale shaker area, and any other areas with H2S > 10 ppm shall be roped off and identified as a restricted area. No one shall enter these areas without specific Workover/Drilling Foreman approval.

4.3.10 If the Level 2 condition occurs only at the shale shaker, and only as a result of drilled gas, then after access to the shaker area has been restricted, the Workover/Drilling Foreman may, at his discretion, disable the low level (H2S >10 ppm) alarm in the shaker area only.

Note: This may be done only to prevent repeated alarms during the time it takes to reduce the H2S concentration in the mud; and only if the H2S concentrations in the shaker area are continuously monitored by a competent person.

4.4. Level 3: 10< [H2S] < 100 ppm on the drill floor

Since the drill floor is a critical work area and cannot be easily evacuated, H2S concentrations higher than 10 ppm are far more critical on the drill floor than in more remote areas of the rig. Upon reaching Level 3 conditions, the Workover/Drilling Foreman shall take the following actions.

4.4.1 All of the previous H2S level precautions are already in place.

4.4.2 Upon initial low alarm (H2S > 10 ppm), everyone on the drill floor shall either evacuate or mask up as per established H2S drill.

4.4.3 No one shall remain on the drill floor unless their presence is absolutely necessary to regain a safe working environment.

4.4.4 An H2S monitor shall be placed on the drill floor to provide continuous atmospheric H2S concentrations.

4.4.5 Workover operations shall stop and unless well conditions dictate against it, the well shall be immediately circulated bottoms-up. The Workover/Drilling Foreman shall use his discretion whether to circulate through the choke or through the shakers.

4.4.6 The Workover/Drilling Foreman shall immediately implement appropriate procedures to reduce H2S concentration in the mud (e.g. treat mud with H2S scavenger, increase overbalance, increase ventilation, etc.).

4.4.7 Two men shall be placed at each entrance to the location to turn back non-essential personnel and to direct essential personnel to the appropriate safe briefing area. These teams shall be equipped with breathing apparatus and H2S monitors.

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4.4.8 The Workover/Drilling Foreman shall discuss longer-term procedures to reduce H2S levels with his Superintendent and Workover/Drilling Engineering.

4.4.9 Workover operations shall not recommence until drill floor H2S levels have been reduced to less than 10 ppm, and adequate action has been taken to maintain safe H2S levels during subsequent drilling.

4.5 H2S Emergency, [H2S] > 100 ppm

An H2S emergency is defined as having lost the capability to control the amount of H2S being released at the wellsite. Under this condition, the Workover/Drilling Foreman must identify the problem and take immediate corrective action. The specific response will depend upon the specific problem. However, at the same time, the Workover/Drilling Foreman must implement the following precautions and work procedures to provide an adequate level of safety for the men working on the rig.

4.5.1 Immediately implement a strict “buddy system”. No one is to ever do

anything alone. Everything is done in pairs. 4.5.2 As per the GI’s, the Workover/Drilling Foreman will notify the

Workover/Drilling Superintendent of an emergency, and the Superintendent will decide whether or not to activate the (Disaster) Contingency Plan. Should the Superintendent decide to activate the Plan, he will notify the facilities identified in Attachment 1 & 2 of this plan and provide them with pertinent data. The Superintendent will also call the appropriate Saudi Aramco Industrial Security main gate and request security patrols be dispatched. See GI 1850.001 (2.4.1.2). See G.I.1851 for notification requirements on offshore wells.

4.5.3 Communicate to the Superintendent what outside resources the rig

needs, or may need in the immediate future (e.g. gas monitors, gas monitoring teams, increased breathing apparatus re-fill capacity, mobile radios, walkie-talkie etc.). The Superintendent will contact the outside resources needed to assist the rig.

4.5.4 Establish a Command Post (CP), typically in the Workover/Drilling

Foreman’s office, equipped with the following: ?? Telephone & radio. ?? Continuous contact with the Superintendent. ?? Flare gun and one box of flare gun shells. ?? Fluorescent orange vest to identify the Command Post

Commander.

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?? Walkie-Talkies to communicate with the Safe Briefing Area and work parties throughout the rig.

?? Continuously manned by either a Workover/Drilling Foreman, or a highly reliable, experienced and competent individual, plus at least 2 pairs of runners.

4.5.5 Man the primary safe briefing area (SBA), typically near the Workover/Drilling Foreman’s office, equipped as specified in “Safe Briefing Area Equipment List”, Appendix 2.

4.5.6 Establish and mark off a “hot” zone, where H2S concentration is greater than 10 ppm. This is done by assigning pairs of individuals, masked up and equipped with a continuous H2S monitor, to measure H2S concentrations throughout the location.

4.5.7 Maintain at least one 2-man team to continuously check that the “hot” zone is adequately identified. (Winds can vary and change conditions rapidly).

4.5.8 Assign an individual to gather all vehicles and park them in a safe upwind location, parked facing their escape route, with the motor off and with the keys left in the ignition.

4.5.9 Alert the rig camp of the emergency, and to stand by for further instructions.

4.5.10 Organize small work teams of at least 2, but usually not more than 5 men. Assign one man as leader of every work team. (Under emergency conditions, it may be difficult for one man to directly supervise more than 4 people, hence the 5 person maximum.)

?? All work is assigned to individual teams at the Safe Briefing Area.

?? The Safe Briefing Area commander keeps a written log of all assigned tasks.

?? Each work team is assigned one task and one task only. ?? An “estimated time of completion” is identified for each assigned

task. ?? Each work team reports back to the Safe Briefing Area

immediately upon completion of their assigned task. (This allows the Commander to be fully up-to-date on the progress being made.)

?? If a work team has not completed their task by their “estimated time of completion”, they shall report back to the Safe Briefing Area (or send a pair of runners to report in).

?? Each work team will have an individual to be assigned to check the air supply of all team members and to monitor H2S levels

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using a continuous monitor. This should be his primary responsibility: he should not be assigned other duties that could interfere with this vital safety function.

4.6 H2S Orientation Requirements

The level of orientation or training required will vary, depending upon the role each individual is expected to take in the event of an H2S release.

Personnel Minimum H2S Training Requirement Offshore: All personnel 1. Able to don & use breathing apparatus.

2. Able to identify H2S alarm.

3. Able to identify wind direction.

1. Able to muster to the Safe Briefing Area or their boat station, and enter and buckle-up in their assigned boat while wearing breathing apparatus.

Onshore: Occasional visitors: never (or very rarely) on the rig package

1. Able to identify H2S alarm.

2. Able to identify wind direction.

3. Know to evacuate to the upwind safe briefing area immediately upon hearing the alarm.

Onshore: Visitors who may work on the rig package

1. Able to don & use breathing apparatus.

2. Able to identify H2S alarm.

3. Able to identify wind direction.

4. Know to evacuate to the upwind safe briefing area immediately upon hearing the alarm.

Onshore: Rig crew 1. Able to don & use breathing apparatus.

2. Able to identify H2S alarm.

3. Able to identify wind direction.

4. Know how to perform the tasks assigned to them, according to the rig’s H2S Drill.

Also refer to “Training Requirements, H2S” in Chapter X, Section A of the drilling manual.

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5.0 SPECIAL OPERATIONS

5.1 Well Control

The following well control practices should be initiated on all workovers. See also the Aramco Well Control Manual. Well control procedures are basically the same in the presence of H2S, but the added risk has a definite impact on the decision making process in handling a given well control situation. Extra consideration should be given to items such as remote kill lines, remote adjustable choke control panels and remote BOP controls. A second flare pit has recently been added to all Khuff and Pre-Khuff wells. This pit will be to the easterly or westerly direction and will be used when wind conditions make the pit to the south unsafe to use. This would be primarily for uncontrolled flows or when the gas buster cannot handle the flow.

5.1.1 Any influx into the wellbore (kick) should be assumed to contain H2S.

The size of the influx, amount of under balance, amount of open hole, depth and EMW test of last casing shoe, formation character, weather conditions and proximity to contact points (in other words, all factors) should enter into the decision to circulate out or pump away the influx.

5.1.2 If the decision is made to circulate out the kick, clear the rig floor and

shaker/choke/gas buster area of all unnecessary personnel and take the following precautions.

A) The rig substructure, BOP, choke line, choke manifold, and mud

return areas shall be roped off and identified as a restricted area. No one shall enter these areas without breathing apparatus, H2S monitor, and specific Drilling Foreman approval.

B) The H2S concentration in the mud returns shall be monitored continuously.

C) The Workover/Drilling Foreman shall alert affected downwind facilities as identified in the well program.

D) The Workover/Drilling Foreman shall implement any other precautions he deems prudent.

E) All personnel involved in the well control operation will mask-up at least 30 minutes prior to bottoms up. The flow from the choke should be diverted through the gas buster and the gas should be flared. The mud stream will return to the active system where any remaining gas can be removed by the degasser and the use of H2S scavenger.

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5.1.3 If the decision is made to pump away the influx, a procedure should be furnished by the Workover/Drilling Engineer based on actual conditions at the time. This will usually involve pumping down the drill pipe at a slow rate while bullheading on the annulus with the same mud weight as in the hole or with kill weight mud if weight up can be accomplished with little delay. When drill pipe and casing pressure are equal it can be assumed that the influx is pumped away (an additional volume of mud should be pumped for safety). Kill weight mud can then be circulated in the well holding the appropriate back pressure on the choke. If the drill pipe and casing pressure fail to equalize while bullheading it is likely that the casing seat or a formation above the point of influx has broken down.

5.1.4 Stripping operations in the presence of H2S are particularly hazardous

due to increased stress cracking at low temperatures and high stress levels. If an influx occurs while out of the hole or off bottom, pumping away the influx should be considered prior to initiating stripping operations.

5.1.5 Heavy trip or drill gas concentrations should be diverted through the

gas buster and flared, if possible.

5.2 Highly Deviated and Horizontal Wells

The workover program may include re-entering a well and sidetracking, with a highly deviated or horizontal section through a H2S zone. Everyone involved in the operation should be aware that a highly deviated or horizontal well in an H2S bearing formation increases all risks relative to a straight hole in the same formation. All the risks mentioned above, associated with coring, well testing, well control, lost circulation and stuck pipe are compounded when a highly deviated hole situation is added to the presence of H2S. All preventative measures recommended in the five sections above should be taken as well as some mentioned below.

5.2.1 Twenty four (24) hour supervision must be provided in this portion of

the hole. This would require two Workover/Drilling Foremen, two Directional Drillers and two Mud Engineers while drilling the horizontal or highly deviated section in an H2S zone or with an H2S zone open. Change out of these personnel should not be made with both on the same day (for instance, both Directional Drillers should not be relieved together). Many problems on critical wells develop right after a change of senior personnel.

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5.2.2 Pumping out of the hole should become a routine operation in the horizontal section. This allows back-reaming with the bit and motor, keeps cuttings moving up the hole to prevent packing off and prevents swabbing in formation fluid.

Note: A 1000’ column of gas (or oil) swabbed into a horizontal

section would give no pressure differential between drill pipe and annulus and no flow. The only indication would be improper fill volume.

5.2.3 Slide drilling with no pipe rotation and the pipe laying on the low side

of the hole is obviously very conducive to differential sticking. All preventative measures mentioned under stuck drill pipe should be considered. Maintain maximum mud lubricity with synthetic or oil based lubricants. Consider the use of lubricating beads (under various trade names) while sliding. Plan the well so that sliding is minimized in the later stages of the horizontal section.

5.2.4 To prevent packing off and mechanical sticking, mud properties

should be maintained for maximum hole cleaning benefit. Alternating low/high viscosity sweeps have been found to aid in hole cleaning as well as high viscosity sweeps weighted slightly above the mud weight in use (sweep tends to stay on low side of the hole and specific gravity difference between mud and cuttings is reduced).

5.2.5 More frequent wiper trips also help keep the hole clean and may give

hints of hole problems that are developing.

It should be kept in mind that reducing the incidence of hole problems in general reduces the chances of an H2S incident.

5.3 Lost Circulation

Lost circulation becomes a much more serious problem when it occurs with a formation containing H2S open, especially if that formation has a minimal overbalance. As with well control, the presence of H2S does not change the way you combat losses, rather it impacts the decision making process on which options to take. A more conservative approach is warranted with more attention given to preventative maintenance

5.3.1 If the hole will not stand full, it is very important to keep the hole filled

with mud, water or diesel and record the exact volume pumped so that an accurate hydrostatic head can be calculated if the well becomes static.

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5.3.2 The most serious situation would be losses up hole while drilling into or weighting up to kill a higher pressure H2S zone. In this situation, a barite plug can be pumped through the bit to shut off the high pressure zone and allow lost circulation up hole to be remedied. See “Barite Plug” in Chapter II, Section F, of this Workover Manual. If the losses cannot be controlled serious consideration should be given to setting a casing string across the loss zone before drilling out the barite plug and into the H2S zone.

5.3.3 A more common situation encountered by Saudi Aramco is loss on

bottom with a higher pressure H2S zone open up hole with minimal overbalance. An example would be losses in the Khuff-C (partially depleted by production) with the Khuff-B (or L. Jilh) open with original pressure. If conventional LCM pills are not successful and the hole will not stand full, there are LC plugs that can be pumped through the bit under various trade names. These type plugs are usually polymer based and acid soluble. If the hole is static and only dynamic losses are being experienced, the pipe can be tripped and run open ended in order to spot higher concentrations of LCM, marble chips or other plugs. See “Types of Plugs” in Chapter II, Section F, of this Workover Manual. Again, serious consideration should be given to setting a casing string across the higher pressure zone so that the mud weight can be reduced to a minimal overbalance. This reduces the chance of losses, differentially stuck pipe and well control incidents.

5.3.4 As with well control, all well parameters should be considered in

making the decision on how to proceed after encountering loss circulation. The Workover/Drilling Engineer should be consulted and should furnish the rig with a general procedure and specific recipes for any plugs required. Serious consideration should be given to setting casing prior to encountering the situations outlined in “2” and “3” above.

5.4 Stuck Pipe

Stuck pipe in an H2S zone or with an H2S zone open becomes a much more serious problem because the presence of H2S limits your options in freeing the pipe. Diesel based fluids and acids used to free differentially stuck pipe may bring H2S to the surface in solution. Reducing the hydrostatic head below formation pressure will also bring H2S to the surface and is presently against Saudi Aramco policy. As before, the presence of H2S has more impact on the decision making process in reducing the risk of stuck pipe and on how to proceed after pipe is stuck than it does on the actual methods of freeing stuck pipe. These methods remain basically the same.

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5.4.1 The Workover/Drilling Foreman should make the Mud Engineer aware that more extreme measures should be taken to prevent stuck pipe than would normally be done on a non-H2S well. Reduction of water loss, filter cake thickness, carrying a minimum overbalance, addition of lubricants, etc., can all reduce the possibility of differentially stuck pipe. The Mud Engineer will not normally be aware of an overbalance situation and potential for stuck pipe unless informed by the foreman.

5.4.2 When planning BHA’s, consideration should be given to minimizing

the risk of mechanically stuck pipe. 5.4.3 Consideration should be given to running a mechanical jar in the

string well above the hydraulic jars. This jar would be used to free the hydraulic jars if they became stuck. It should have the capability to be locked out if the hydraulic jars are free.

5.4.4 Consideration should be given to keeping a weighted grease pill ready

for pumping should stuck pipe occur. 5.4.5 Where differential sticking appears to be a problem, a minimum over-

balance, as recommended by the drilling engineer, may be carried. If differentially stuck pipe does occur, the mud weight may be further reduced to a near balanced condition with approval from the superintendent. An under-balanced situation should not be induced as this procedure is against Saudi Aramco policy.

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6.0 ATTACHMENTS

6.1 Well Coordinates, Expected H2S and Potential Contact Points

6.1.1 Re-Entry Sidetrack Well

This plan is specifically for ___________ Well No. _____ with actual surface location of North _______________, East _____________, UTM Zone ____ Compliance depth is ____________. This well is a Development well in a known area with a total depth (TVD) that will penetrate a horizon no deeper than other wells in the immediate area (or structure), with known H2S occurring at:

HORIZON DEPTH

MD DEPTH

TVD DEPTH

SS

The nearest points of contact are:

DESCRIPTION Direction Deg. (N=0o)

Distance Km.

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List all contact points including but not limited to: Public Highways, manned GOSP or plant, rig camp (if no alarms and permanent communication with rig), residences, gas stations, stores or other businesses, towns or villages.

The attached map (Attachment B) shows the location of the well and each contact point. This map has been furnished to Industrial Security, Loss Prevention and Government Affairs, should they be required to carry out duties under G.I. 1850 and 1851. See applicable G.I.’s in Appendix 1 and 4. Note: On the map, list only those contact points 5 Km. or less from the surface

location. If multiple contact point exist in a particular direction such as a village or group of businesses, they may be combined and shown as one contact point as long as it is so noted on the map key and list. This map should be updated if any additional contact points are noted during drilling and completion operations (such as seismic camp or temporary residence or business).

Attachments B and C, Map of potential contact points and Rig Layout, should follow.

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7.0 APPENDIX

7.1 Saudi Aramco Standard Safety Equipment for H2S Operations on All Onshore Drilling and Workover Rigs 7.1.1 H2S and Combustible Gas Monitors.

A) H2S Monitor and Alarm System A four channel H2S monitoring system with two visual-audio alarm system shall be installed and fully operational on all land drilling rigs operating on known or suspect H2S locations. Each sensor and alarm system shall have a portable reel with 200 feet of neoprene covered electrical cable with cannon connectors at each end for hookup of cable to monitor, cable to sensor and cable to alarm (a total of six cables on reels).

1. The sensors shall be located as near as practical to:

?? The top of the bell nipple. ?? The flowline opening to the shale shaker. ?? The Driller's position and about three feet above the

floor. ?? The cellar or underneath the choke manifold, above

the choke manifold skid floor. This sensor should be easily moveable so that it can be used around the BOP stack or at the well testing equipment when necessary.

2. The alarm system (amber strobe lights and horn) shall be

set for first alarm at 10 ppm and high alarm at 20 ppm H2S. The alarm system shall be located in clearly visible locations so that personnel in any work area can see and/or hear at least one set.

3. The monitor shall be located in the doghouse. 4. There shall be minimum of one spare sensor.

B) Combustible Gas Monitor and Alarm System

A continuous combustible gas monitor and single sensor with a portable reel holding 200 feet of neoprene covered electrical cable with two pairs of cannon connectors (monitor to cable and cable to sensor) shall be provided. An alarm system with similar reel, cable and connectors is required

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1. The sensor shall be located at either:

?? The top of the bell nipple, or The flowline opening to the shale shaker when a rotating head is in use.

2. The alarm system (red strobe light and horn) shall be set at

20% of the Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. The alarm system shall be clearly visible from work areas on location. The alarm system (light and horn) shall be located on the rig floor above the doghouse. Note: This setting criterion applies to cold work situations only.

3. The monitor shall be located in the doghouse. 4. There shall be a minimum of one spare sensor.

C) Two personal portable H2S monitors, alarm to be set at 10 ppm.

D) Two portable H2S detectors (hand pump suction type) with high

level and low-level H2S and SO2 tubes.

E) Two portable combustible gas or vapor monitors.

F) Drager Test Kit for checking mud returns for H2S.

7.1.2 Required Breathing Apparatus A) Hose-line work units, with emergency escape cylinders, shall be

provided as follows: ?? Rig floor - six ?? On handrail near shale shaker - two ?? On rack near mud mixing area - two

?? Near choke manifold - one In derrick for Derrickman (at monkey board) - one

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B) Self contained breathing apparatus (SCBA's) shall be provided as follows:

?? Toolpusher's office/quarters – two ?? Company Foreman's office/quarters – two ?? Logging Unit (when used) - two ?? SCR room - one ?? Rig Floor - three

C) At least one fully-charged spare cylinder shall be provided

for each unit of all type listed.

7.1.3 Emergency First Aid and Other Safety Equipment

A) Two "Bug Blowers" explosion proof, high volume (40,000 cfm) and moveable.

B) Three wind socks, two in service, plus streamers to be located so all personnel will know wind direction. One windsock is to be held as a spare.

C) Flare line ignition system (Alex-500 or equivalent) with backup flare guns or pencil flares.

D) Two portable oxygen resuscitator units, each with a spare

oxygen cylinder.

E) Two 25 man First Aid Kits, one at rig site and one at campsite.

F) Four eye wash stations located in the following areas: ?? On the rig floor or in the rig floor doghouse. ?? In the mud mixing area. ?? In the rig medic's office or the rig supervisor's office. ?? In the rig camp mess hall.

G) Two safety harnesses with two 250 foot retrieval ropes. H) Two basket-type stretchers (Stokes or Navy type litter) with

blankets and securing straps.

I) Two Quick-Air splint kits.

J) One portable bull horn with extra battery pack.

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K) Six small chalk boards with clamps for mounting with an adequate supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards].

L) Flashlights - explosion proof with an extra set of batteries and

extra bulb for each (number to be at least one for each two persons in the operation but not less than five).

Note: Sanitation and care of Respiratory Protection Equipment is covered in Section B-5 of Saudi Aramco Safety Requirements for Drilling and Workover Rig Operations.

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7.2 Safe Briefing Area Equipment List

The purpose of a safe briefing area is to provide the following:

?? A safe area from which the Aramco drilling foreman can direct operations. ?? A safe area where personnel can gather to receive briefings on the

present situation and further orders. ?? A safe area where personnel can receive first aid, change out air bottles

and repair or replenish other equipment.

The safe briefing area is usually near the Aramco office unless wind conditions require that the secondary site be used. The following equipment must be kept at or near the safe briefing area. It is understood that most equipment will be kept inside and brought out only for drills or actual H2S incidents.

A) Saudi Aramco radio (radio in Foreman’s truck or a portable unit). B) Walkie-Talkie (if available) or rig PA unit. C) Fluorescent orange vest to identify the Safe Briefing Area Commander. D) All extra SCBA’s not in use elsewhere on the rig. E) One breathing air compressor/recharge station complete, as near as

practical to Safe Briefing Area. F) A minimum of one charged, spare cylinder for each SCBA on the rig. G) A minimum of two personal portable H2S monitors (alarm set at 10 ppm)

and equipment and power for recharging it. H) A minimum of two portable H2S/SO2 detectors (hand pump suction type)

with high and low level tubes for both gases. I) A minimum of two portable combustible vapor monitors. J) One Drager Test Kit. K) A minimum of two portable oxygen resuscitator units and two spare

oxygen cylinders. L) A minimum of one 25 man First Aid Kit (a second at the camp/quarters)

and additional first aid supplies in the rig medics office. M) Two basket type stretches with blankets and securing straps. N) Two safety harnesses with two 250 foot retrieval ropes. O) Two Quick-Air splint kits. P) A minimum of two portable bull horns with extra battery packs. Q) One flare gun with minimum of 25 flare shots (kept in foreman’s office). R) A minimum of six dry eraser boards or chalk boards S) A minimum of six explosion proof flashlights or at least one for each two

men on the rig site at any given time. T) Continuously manned by either a Workover/Drilling Foreman, Toolpusher

or other experienced and competent individual, plus two pair of runners.

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7.3 Typical H2S Drill

Low level alarm sounds for 10 ppm or more (amber light and horn). At this time two Safe Briefing Areas have been designated with the Primary area near the Aramco Workover/Drilling Foreman’s office and the secondary area near the entrance to the rig site. It is understood that all the equipment listed in the “Safe Briefing Area Equipment List” cannot be kept out in the weather, but these items should be readily available from the offices and storeroom nearby.

A) Driller and one floorman (or assistant driller, if there is one) don 5 minute

SCBA’s and plug into cascade system. All other personnel proceed directly to the Safe Briefing Area.

B) Driller proceeds to flow-check and shut-in the well if flowing as per the

Aramco Well Control Manual (BOP Drill). If no flow, circulate until receiving orders from Drilling Foreman.

C) Workover/Drilling Foreman and Toolpusher don 30 minute SCBA’s and

proceed to the rig floor with at least one portable H2S monitor. They are to first confirm the well is properly secured if flow was detected, then locate the source of the alarm (shaker area, bell nipple, cellar, etc.). If no flow was detected, it will usually be prudent not to shut-in the well and risk stuck DP (shutting in the well can actually concentrate H2S just below the annular or ram). The area of the alarm should then be checked with the portable monitor to confirm that it was not a false alarm. If the alarm is confirmed, the Drilling Foreman and Toolpusher should come up with a plan of action. Superintendent should be informed at this point and drilling engineer consulted if there is any doubt about how to proceed.

?? If the well was flowing and had to be shut in, this would become a well

kill operation and handled according to the Saudi Aramco Well Control Manual. However, Section V., Special Operations/Well Control of the H2S Contingency Plan should be consulted. The option of pumping the kick away down the annulus should be considered. If the decision is made to kill the well conventionally, the listed precautions in this plan should be taken.

?? If the well did not flow, there are several options open to reduce H2S

concentrations in the atmosphere that are a result of gas breaking out of the drilling mud. These include reducing drilling rate or pulling off bottom to circulate the use of H2S scavengers in the mud, increasing overbalance (increasing mud weight) and additional ventilation in the area of the alarm. Stopping circulation completely is only a temporary

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measure and the resulting reduction in ECD can actually worsen the situation.

D) The person acting as the “H2S Safety Representative” will collect any

equipment not already at the “Safe Briefing Area” and see that it is in place. He will then proceed to take a head count with the assistance of the medic. He will assume command of the “Safe Briefing Area” reporting directly to the Workover/Drilling Foreman. Note: If the Toolpusher is the designated “H2S Safety Representative”, the medic will assume this command until relieved by the Toolpusher.

E) Chief Roustabout dons a 30 minute SCBA and checks all rooms and

offices for anyone who did not hear the alarm. He then proceeds to Safe Briefing Area for the head count.

F) Medic proceeds to Safe Briefing Area with portable resuscitators, first aid

kit and any other required medical equipment not already at the “Safe Briefing Area”. He then will assist the person acting as the “H2S Safety Representative” in the head count.

G) If anyone is missing, the “Safe Briefing Area” commander will select a two

man team to mask up on SCBA’s, report the missing personnel to the Toolpusher and continue with the search unless directed otherwise by the Toolpusher.

H) The above condition shall continue until an H2S level of less than 10 ppm

is confirmed and alarms cease or until the Workover/Drilling Foreman announces that all unsafe areas with H2S levels in excess of 10 ppm have been roped off (shaker shake and choke area only) and continuous monitoring with portable monitors is being done.

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7.4 Attachment for Offshore Wells

More stringent requirements are necessary when H2S is anticipated offshore. This is due to the nature of offshore operations, being on a small confined rig or platform with the only means of evacuation being by boat, helicopter or escape capsule. The crew quarters being in direct proximity to the rig package also presents problems that are not encountered on onshore wells. The operational levels (alarm levels) remain the same as onshore and all precautions taken for onshore wells should be observed on offshore wells. In addition, the following precautions and additional equipment requirements should be observed. Note: Additional equipment requirements are detailed below under “Saudi Aramco Standard Safety Equipment for H2S Operations on all Offshore Drilling and Workover Rigs”.

A) There shall be two Safe Briefing Areas, the same as for onshore. If

possible, they should be located on the port and starboard sides of the rig near the escape boats or capsules. Wind direction and proximity to the Aramco foreman’s office should determine which one is the primary area. A Public Address system audible from any point on (or within) the vessel or platform is required in order to give assembly and evacuation instructions

B) Due to the close proximity to the quarters and the rig package, H2S

orientation, instruction with breathing equipment and evacuation drills will be required of all persons on board, including visitors. Every person on board will be issued a SCBA. See below, “Standard Safety Equipment for H2S Operations on All Offshore Drilling and Workover Rigs”.

C) Since mud pumps, mud pits, shakers, cement pumps and other

equipment are usually in enclosed or partially enclosed areas, ventilation is critical on an offshore operation where H2S might be present. Even though extra sensors are required in most of these areas, loss of below deck ventilation fans is a critical situation and these areas should be evacuated until ventilation is restored. If repairs in the non-ventilated deck are required, a portable H2S detectors and 30 minute SCBA’s (for each worker) will be available for immediate use.

D) Mask-up and evacuation of non-essential personnel from the rig package

shall be at level 2, the same as for onshore. Evacuation of non-essential personnel from the vessel should be at the Saudi Aramco Foreman’s discretion. It should be considered after a sustained level 3 alert, when efforts to reduce the H2S levels on the drill floor have been unsuccessful. Weather conditions and the time required to evacuate by boat or helicopter should be considered in making this decision.

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E) All work boats and crew boats should approach the rig from up wind maintaining radio contact. When red lights are flashing, the rig should not be approached except on request for evacuation. When on standby, anchorage should be in the general upwind direction. SCBA’s should be issued to the crews of all work boats and crew boats servicing the rig.

F) Helicopters should make radio contact with the rig prior to approach and

landing to confirm operations are normal. During a level two or higher alert, when visual alarms are active, landings will generally not be made. Any exception to this should be for evacuation only. The pilot should be appraised of the situation in as much detail as possible and the final decision on whether to land will be his.

G) Two flare lines (offshore type burner booms), situated so that at least one

is always down wind, will be operational by compliance depth. This should be the case even when no testing is planned. The choke manifold outlet and the gas buster outlet should remain connected to both flare lines with the ability to quickly switch from either outlet or either fare line.

H) When declaring an emergency or disaster, refer to GI 1851, “Offshore

Contingency Plan” attached as Appendix 6. The reporting procedure is very similar to an onshore incident with the main difference being response and responding support groups.

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7.5 Saudi Aramco Standard Safety Equipment for H2S Operations on All Offshore Drilling and Workover Rigs

7.5.1. A continuous monitoring system with eight sensors and six red

beacon light/siren alarm systems, each with conductor cable, shall be provided. A) All sensors must have protective housings capable of protecting

the sensor from accidental spray from rig wash down hoses and accidental mud and/or oil splashes.

B) Sensors shall be located as near as practical to:

1. The top of the bell nipple. 2. The flowline opening to the shale shaker. 3. The Drillers position and about three feet above the rig

floor. 4. The mud pit in the pump area. 5. The motorman's work area in the motor room. 6. The living quarters area nearest the most likely source of

hydrogen sulfide. 7. The breathing apparatus compressor package, near the rig

floor.

Note: The eight sensor with 200 feet of cable on portable reel shall be extra and will be used to monitor any other potential source of hydrogen sulfide or kept on standby in designated safety equipment storage area.

C) There shall be at least four spare sensors in addition to the eight in the monitoring system.

D) The H2S alarm system (red beacon and siren) shall be set at 10 ppm H2S for the first alarm and 20 ppm H2S for the second alarm.

The combustible gas alarm system shall be set at 20% of the

Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. [Note: This setting criteria applies to cold work situations only.]

E) The alarm system shall be located in a clearly visible area so

that personnel in any work area can see and/or hear at least one set. They shall be located:

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1. On the rig floor and at least eight feet above the floor. 2. On the port side at the corner of and above the quarters. 3. On the starboard side at the corner of and above the

quarters. 4. Below deck in the pump-motor room area. 5. In crew quarters. 6. In the galley area.

F) The monitor shall be located in the Supervisor's office, Control

Room or Radio Room.

7.5.2 A minimum of one hundred 30 minute SCBA's will be located on any offshore rig operating in known or suspected H2S areas. There shall always be at least 25% more SCBA onboard than the number of personnel.

A) The 30 minute SCBA's shall be stored ready for use as follows:

1. There shall be one SCBA assigned to each person on

board, regardless of his affiliation, contractor, service contractor, Aramco, or any visitor. These will be stored under the head-end of the assigned bunk when the person is in the bunk and during any period considered safe by the Supervisor. (If there is no bunk assignment, the person will be assigned a SCBA and a designated area for storage during his time on board.) Before assignment of a SCBA to any person, he will demonstrate that he is capable of donning it, adjusting the face piece, and turning on the pressure demand air. This requirement shall be waived for any personnel with documentation from his employer that he has received training within the past 12 months in H2S safety, including practice in donning respiratory protection equipment.

2. Ten SCBA's shall be stored in the dining area. 3. Four SCBA's shall be stored in the motor room or pump

area. 4. Four SCBA's, each with clip on communication device.

Two shall be in Aramco Foreman's office and two in the Rig Supervisor’s office.

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5. All remaining SCBA's and extra cylinders will be stored in

an air conditioned designated safety equipment storage area near the Supervisor's office.

B) The hose-line work units with escape cylinders shall be stored

as follows:

1. Six work units (three with clip on communication devices) on the rig floor in a convenient location.

2. Two work units each with a clip on communication device

in the Supervisor's office. 3. Two work units each with a clip on communication device

in the Aramco Foreman's office. 4. One work mask shall be located in the derrick at the

Derrickman's position, finger board or stabbing board. 5. Five work units and 16 spare cylinders shall be stored in

an air-conditioned designated safety equipment storage area near the Rig Supervisor's office.

6. Nine spare clip communication devices units with supply of

spare batteries will be stored with the five work units as above in #4.

7.5.3 Three cascade systems with 12 - 300 cubic foot cylinders each or

equivalent capacity; three air compressors each with purification system and capacity of 26 scfm at 2400 psi; one 3 outlet manifold and three 12 outlet manifolds; two 200 foot hoses; two - 150 foot hoses; twelve - 50 foot hoses; two 5000 psi working pressure hoses (250 foot and 300 foot respectively).

A) One cascade system with air compressor powered by an

explosion proof electric motor will be located near the rig floor

1. There shall be two six outlet manifold on the derrick floor. 2. There shall be a three outlet manifold at the Derrickman's

position. 3. There shall be a three outlet manifold in the mud room. 4. There shall be a three outlet manifold in the motor room. 5. There shall be a one six outlet manifold for recharging

portable cylinders, one at each cascade system. 6. There shall be a double tee with check valves for tying in

either or both of the other two systems.

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B) There shall be two cascade systems with diesel powered air

compressors, located as remotely from the rig floor as practical, one on the upper starboard deck, the other on the upper port deck

1. There shall be one six outlet manifold for recharging

portable cylinders at each cascade system, as well as regulators and low pressure manifolds for hose line units.

2. There shall be a double tee with check valves for tying in

either or both of the other two systems.

C) There shall be one 250 foot of 5000 psi w.p. hose; one 300 foot of 5000 psi w.p. hose; two 150 foot and twelve 50 foot hoses stored and ready for immediate use in an air conditioned designated storage area.

7.5.4 Five personal portable H2S monitors, as well as stock of lead acetate

sampling devices.

7.5.5 One hydrogen sulfide calibrator with two permeation tubes, portable and AC/DC.

7.5.6 Continuous H2S mud monitor (Mud Duck). Garret Gas Train with supply of accessory equipment for testing mud, plus Drager Test Kits for checking mud return.

7.5.7 Four portable oxygen resuscitators with eight spare oxygen cylinders.

7.5.8 Four portable H2S - SO2 detectors, suction type with H2S and SO2 tubes.

7.5.9 Four portable combustible gas detectors - hand pump suction type.

7.5.10 Six bug blowers, explosion proof, high volume (25,000 cfm or larger) and movable.

7.5.11 Wind socks (4 minimum), streamers, and flags to be located on various places on rig so all personnel will know the wind direction.

7.5.12 Remote flare line ignition system (Alex-500 or equivalent). 7.5.13 Two emergency ignitors, preferably a flare type with a supply of flares

(25 minimum). Emergency ignitors to be stored ready for use in lower right hand drawer of Aramco Foreman's desk.

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7.5.14 Four safety harnesses and four 250 feet retrieval ropes. 7.5.15 Four stretchers (Stokes litter - Navy type basket or equivalent) with

blankets and securing straps. 7.5.16 Four first aid kits (each 25 man size). 7.5.17 Four Quick-Air splint kits or equivalent. 7.5.18 Six portable electronic bull horn speakers with six extra battery packs. 7.5.19 Six small chalk boards with clamps for mounting with an adequate

supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA.

Note: Dry eraser boards may be substituted for chalk boards.

7.5.20 Flashlights - explosion proof with extra set of batteries and extra bulb

for each (minimum number shall be 10 flashlights).

Note: All safety equipment with rubber, plastic or other parts like to deteriorate shall be stored in an air conditioned, dark and designated area, near the Supervisor's office. Adequate supplies of sanitizing material shall be available for sanitizing face masks and other body contact equipment.

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7.6 GI 1850.001 – Onshoreore Contingency Plan (for Emergencies and Disasters)

Refer to Appendix of this manual for a copy of the GI 7.7 GI 1851.001 – Offshore Contingency Plan (for Emergencies and

Disasters)

Refer to Appendix of this manual for a copy of the GI

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7.8 Physical Properties of H2S and Toxicity Table

Hydrogen Sulfide (H2S) a colorless, transparent gas that is slightly heavier than air. It will tend to accumulate in low places if the air is still. It is flammable from 4.3% to 47% vapor by volume in air. It is soluble in both water and oil with solubility decreasing as temperature increases. Low concentrations have an unpleasant “rotten egg” odor but it rapidly kills the sense of smell above 0.01%, therefore odor should not be relied upon for detection. It is extremely toxic as can be seen in the table below.

1 ppm (0.0001%) Easily noticeable smell.

10 ppm (0.001%) Threshold limit value (TLV) for a time-weighted average (TWA) 8-hour day. Essentially, the maximum allowable concentration in which one can safely work, 8 hours a day, day in and day out.

Breathing apparatus required when working in concentrations greater than 10 ppm.

20 ppm (0.002%) Ceiling concentration (no worker may ever be exposed to 20 ppm for any period of time.

Causes irritation or burning sensation in eyes, and irritation to upper respiratory tract if exposed for one hour or more.

50 ppm (0.005%) Loss of sense of smell after about 15 minutes. Increased eye irritation or burning sensation.

Exposure more than one hour may cause headache, dizziness, and/or staggering.

100 ppm (0.01%) Coughing, eye irritation, loss of sense of smell after 3 to 5 minutes. Altered respiration, pain in eyes, and drowsiness after 15 to 20 minutes, followed by throat irritation after one hour.

200 ppm (0.02%) Burns eyes and throat, rapid loss of sense of smell.

250 ppm (0.025%) Between 250 ppm and 500 ppm, pulmonary edema, which can be life threatening, almost always occurs.

500 ppm (0.05%) Loss of consciousness within 15 minutes, breathing stops if nor treated quickly – resuscitation required. Dizziness, loss of sense of reasoning and balance.

700 ppm (0.07%) Immediate unconsciousness, seizures, loss of bowel and bladder control, breathing will cease. Death will result if immediate resuscitation is not administered.

1000 ppm (0.1%) Immediate unconsciousness, death or permanent brain damage may result.

10,000 ppm (1%) Instant death.

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SAFETY EQUIPMENT 1.0 FIRE PROTECTION EQUIPMENT 2.0 BREATHING APPARATUS 3.0 GAS DETECTION EQUIPMENT

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SAFETY EQUIPMENT

1.0 FIRE PROTECTION EQUIPMENT

1.1 All fire protection equipment (e.g. fire extinguishers) on Saudi Aramco

operated rigs shall be maintained in accordance to G.I. 1781.001 (Inspection, Testing and Maintenance of Fire Protection Equipment). G.I. 1781.001 clearly details these requirements.

1.2 All fire protection equipment (e.g. fire extinguishers) on contractor rigs shall be maintained to the same standards as stipulated in G.I. 1781.001 (Inspection, Testing and Maintenance of Fire Protection Equipment). G.I. 1781.001 clearly details these requirements. Note however, that the drilling contractor is responsible to maintain his own equipment, not the Saudi Aramco Fire Protection Department, as listed in the G.I.

1.3 The Workover/Drilling Foreman is responsible to ensure that G.I. 1781.001 requirements are met. Should any questions arise, concerning Saudi or contractor fire protection equipment, the Workover/Drilling Foreman should contact the Saudi Aramco Fire Protection Department.

2.0 BREATHING APPARATUS

2.1 All breathing apparatus on Saudi Aramco operated rigs shall be maintained in

accordance to G.I. 1780.001 (Atmosphere Supplying Respirators). G.I. 1780.001 clearly details these requirements.

2.2 All breathing apparatus on contractor rigs shall be maintained to the same

standards as stipulated in G.I. 1780.001 (Atmosphere Supplying Respirators). G.I. 1780.001 clearly details these requirements. Note however, that the drilling contractor is responsible to maintain his own equipment, not the Saudi Aramco Fire Protection Department, as listed in the G.I.

2.3 On workover rigs where the breathing apparatus is supplied by a third-party

contractor contracted to directly to Saudi Aramco, this third-party contractor is responsible for all aspects of breathing apparatus maintenance.

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2.4 The Workover/Drilling Foreman is responsible to ensure that G.I. 1780.001 requirements are met. Should any questions arise, concerning Saudi Aramco or contractor breathing apparatus, the Workover/Drilling Foreman should contact the Saudi Aramco Fire Protection Department.

3.0 GAS DETECTION EQUIPMENT

This section is incomplete, pending further research in Saudi Aramco Engineering Standards (SAES) for combustible gas and H2S detection equipment. The relevant SAES were written for plant applications and their requirements must be studied and possibly adapted for mobile workover rig use.

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SAFE HANDLING PROCEDURES 1.0 CAUSTIC SODA

1.1 Hazards 1.2 Required Protective Equipment 1.3 Safe Work Procedures 1.4 First Aid Instructions 1.5 Spill or Leak Procedures

2.0 ACID

2.1 Hazards 2.2 Required Protective Equipment 2.3 Safe Work Procedures 2.4 Pre-Job Safety Meeting 2.5 Equipment Inspection 2.6 First Aid Instructions 2.7 Spill or Leak Procedures

3.0 EXPLOSIVES

3.1 Uses 3.2 Hazards 3.3 Safe Work Procedures 3.4 Pre-Job Safety Meeting 3.5 Lease & Traffic Control

4.0 RADIOACTIVE MATERIALS

4.1 Hazards 4.2 Safe Work Procedures 4.3 Applicable Documents 4.4 Saudi Aramco Abandonment of A Radioactive Source

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SAFE HANDLING PROCEDURES 1.0 CAUSTIC SODA

1.1 Major Hazards

1.1.1 Caustic soda is extremely corrosive to skin and eyes, and all contact

with skin and eyes must be avoided.

1.1.2 Severe eye splashes can cause blindness.

1.1.3 Solid caustic soda absorbs moisture from the atmosphere, and dissolves in it, creating liquid caustic. A small piece can lodge in the clothing and later cause burns as it dissolves.

1.1.4 Dust from caustic flakes is not usually a problem when flakes are big. However, a dust mask must be worn if flakes are small, or if flakes are being broken up by sweeping or other actions.

1.2 Required Protective Equipment 1.2.1 Chemical face shield.

1.2.2 Elbow length gloves, either PVC or neoprene, in good condition.

1.2.3 PVC apron.

1.2.4 Eye wash station in immediate vicinity.

1.2.5 Wet weather (waterproof plastic) trousers worn with cuffs over boots.

1.2.6 Optional: dispensable dusk mask (3M type 8710 or equivalent).

Note: Dust masks are mandatory for cleaning up caustic spills.

1.3 Safe Work Procedures 1.3.1 Caustic must be stored where it can remain dry.

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1.3.2 Caustic flakes or pellets must be added to water. It is absolutely forbidden to add water to caustic. (Adding water to caustic will cause an extremely concentrated and dangerously hot caustic solution to splash about.)

1.3.3 Sleeves and trousers must hang over gloves and boots, not tucked in.

(If sleeves and trousers are tucked in, caustic can get into the glove or boot and cause burns.).

1.3.4 There must be no obstructions around either the mixing tank or the

safety shower/eyewash.

1.3.5 Split, torn or leaking caustic containers must not be used.

1.3.6 A suitable waste container (dedicated for emptied caustic containers) must be readily accessible and used.

1.3.7 Partially used bags of caustic must be placed inside a fresh clear

plastic bag, tied off, and returned to store.

1.3.8 Gloves and apron must be washed well with water after use.

1.4 First Aid Instructions 1.4.1 Respond immediately to any skin or eye contact with caustic by

flushing with copious quantities of water.

1.4.2 In the case of eye contact with caustic, use eyewash immediately, and wash eyes with running water for at least 15 minutes.

1.4.3 Notify rig medic to examine and treat as appropriate.

1.5 Spill or Leak Procedures 1.5.1 The Workover/Drilling Foreman must be notified of a major spill or

leak.

1.5.2 Spills must be roped off or otherwise marked.

1.5.3 Full PPE must be used to clean up spills, including a dust mask if solid caustic is spilled. Liquid caustic spills require the use of a wet weather jacket.

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1.5.4 Gather up spilled solid caustic using dust pan and hand broom, placing spilled caustic in the dedicated caustic waste container. Clear away whatever cannot be swept by be washing with plenty of water. This will create heat and splashing, so extreme caution must be used.

1.5.5 Liquid spills must be cleaned by gentle application of large amounts of water. This will create heat and splashing, so extreme caution must be used. When washing down, ensure no one is in the vicinity where the water will run off. Guards may have to be posted to prevent entry while clean-up is underway.

2.0 ACID 2.1 Hazards

2.1.1 Hydrochloric acid is a very corrosive liquid, skin contact will cause

serious burns. Eye splashes could cause serious eye damage, even blindness. Even diluted acid can cause burns.

2.1.2 Burns may take some time to be felt. By this time, the burn could be serious.

2.1.3 Hydrochloric Acid fumes can also cause skin and lung burn injuries.

2.1.4 Strong (concentrated) acid contact with metal releases hydrogen, a very explosive gas.

2.1.5 Acidizing uses high pressure lines, therefore also presenting all the risks associated with pressurized piping.

2.2 Required Protective Equipment

2.2.1 Rubber gloves.

2.2.2 Plastic apron.

2.2.3 Full face mask.

2.2.4 Rubber boots (steel toed).

2.2.5 Fire retardant acid suits (wet gear) must be available for emergency use.

2.2.6 An emergency shower must be readily accessible.

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2.3 Safe Work Procedures

2.3.1 All acid accidents or near misses must be reported to the

Workover/Drilling Foreman.

2.3.2 Only the acid contractor crew will handle acid tank and pump equipment.

2.3.3 Correct PPE to be worn at all times.

2.3.4 Hot work is prohibited in acid storage or handling areas.

2.3.5 Rig crew must stay outside security-taped area or clear of acid tank and pump at all times.

2.3.6 No unauthorized personnel are allowed adjacent to, or in the vicinity of pressurized lines. No personnel may cross over pressurized lines at any time.

2.3.7 Keep personnel well clear when acid is being pumped FROM the well, gas may cause the acid to spray or spurt.

2.3.8 Flush pumping lines with water after acid pumped.

2.3.9 Treat displaced acid with caustic or soda ash before disposal.

2.4 Pre-Job Safety Meeting Before acidizing operations or pressure testing of any lines is started, a safety meeting with all personnel must be held. At minimum, such a meeting will cover: 2.4.1 Scope of work, including an explanation of the treatment and

procedures to be followed.

2.4.2 Specific identification/designation of contractor and operator personnel in charge of the operation.

2.4.3 Specific hazards associated with each stage of work (pressure ruptures, corrosive contacts, toxicity, flammability, etc).

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2.4.4 Specific safety procedures for the control of these hazards (fresh water sources, flushing procedures for corrosive contact, line approach restrictions, etc).

2.4.5 Dangers associated with pressures and energized lines. Any approach to pressurized lines is prohibited.

2.4.6 Safety equipment (PPE, eyewash stations, fire equipment, etc.).

2.4.7 Restrictions and restricted areas (essential personnel only, no ignition sources, no smoking, etc.).

2.4.8 Emergency arrangements (action plan in the event of fire or serious leak, review of strategic equipment, placement, fresh water sources, emergency actions).

2.4.9 Evacuation procedures (escape paths, follow up actions, re-entry conditions, etc.).

2.4.10 It must be stressed that actual handling of acid, including repair of acid leaks in injection lines must be left to the acid company's employees.

2.5 Equipment Inspection The following equipment should be available and inspected for leaks: 2.5.1 Chicksans

2.5.2 Swivels

2.5.3 Valves

2.5.4 By pass line

2.5.5 Choke manifold

2.5.6 Vent line

2.5.7 Wash down hoses

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2.6 First Aid Instructions 2.6.1 Respond immediately to any skin or eye contact by flushing with

copious quantities of water. Use the emergency shower for for large body splashes.

2.6.2 In the case of eye contact, use eyewash immediately, and wash eyes

with running water for at least 15 minutes. 2.6.3 Notify rig medic to examine and treat as appropriate.

2.7 Spill or Leak Procedures

2.7.1 The Workover/Drilling Foreman must be notified of a major spill or leak.

2.7.2 Spills must be roped off or otherwise marked.

2.7.3 Large acids spills require a well-trained responder. Therefore, only the acid contractor crews will clean up large acid spills.

2.7.4 Full PPE must be used to clean up spills, including acid suits.

2.8 Access 2.8.1 The immediate area required for surface equipment should be cleared

to permit adequate spacing of surface equipment, with regard to personnel, safety and regulations.

2.9 Minimum Recommended Breathing Air Equipment Placement 2.9.1 1/4" airlines with 3 SABA should be provided to cover personnel

requirements at the wellhead.

2.9.2 1 - 1/4" airline with 1 SABA is required to cover the operator's cab.

2.9.3 1 - 1/4" airline with 1 SABA is required to cover the acid pumper.

2.9.4 1 - 1/4" airline with 1 SABA is required for the N2 operator.

2.9.5 SCBA are required, one each for the operator's representative and the contractor safety representative.

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2.10 Safety Representative 2.10.1 The acidizing contractor shall provide a safety representative. During

the acidizing operation, the safety representative will be equipped, at minimum, with: 2.10.1.1 One gas detector.

2.10.1.2 Fire retardant slicker suit.

2.10.1.3 Full rubber gloves.

2.10.1.4 Steel toed rubber boots.

2.10.1.5 Self contained breathing apparatus.

2.10.2 The safety representative duties include:

2.10.2.1 Pedestrian traffic control.

2.10.2.2 Monitoring of all work stations and personnel movements.

2.10.2.3 Verification of safe work practices.

2.10.2.4 Verification of PPE use.

2.10.2.5 Monitoring and control of SABA use during rig in, installation

of/removal of injector or endless tubing related equipment.

2.10.2.6 Checking wellhead for leaks prior to/after rig in and throughout operation.

2.10.2.7 Monitoring under mask of any H2S returns.

2.10.2.8 Shut down of operations upon detection of imminent danger, substandard practices and/or conditions.

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3.0 EXPLOSIVES 3.1 Uses

The most common use of explosives in drilling is casing perforation. Other uses include making a hole in the drillstring, backing off from stuck pipe, sidewall coring, and small charges associated with setting plugs and packers.

3.2 Hazards 3.2.1 Failure to observe, radio silence and explosives safety measures.

3.2.2 Incorrect storage or transportation of explosives.

3.2.3 Mishandling of mechanical firing system for explosives.

3.2.4 Loss of explosives at the rig site.

3.3 Safety Procedures

3.3.1 Only the explosives contractor engineer and crew are permitted to

handle explosives at the rig site.

3.3.2 All other crew must keep well away, 50m or more is recommended during all explosives operations.

3.3.3 Preparation of explosive devices must be done in an area marked with red and white tape and with “Explosives-No Smoking- Keep Out” signs set out.

3.3.4 To stop stray electric currents, all non-essential equipment must be turned off during gun connection for example the mobile telephone.

3.3.5 All welding must be stopped before explosive connection.

3.3.6 The Explosives Engineer must check the rig grounding. (Must be less than 25v difference).

3.3.7 All mobile and fixed radios shall be switched off and not used.

3.3.8 Radio silence warning signs must be posted on access roads 200m from the rig.

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3.4 Pre-Job Safety Meeting Before rigging up, a safety meeting must be conducted jointly by the Workover/Drilling Foreman and perforating contractor representatives for all personnel on location. This meeting must address: 3.4.1 Scope of work.

3.4.2 Assignment of tasks.

3.4.3 Work permit and relevant requirements.

3.4.4 Hazards and means of reducing the hazards.

3.5 Lease and Traffic Control

3.5.1 Clear the lease of all non-essential personnel.

3.5.2 Post a worker at least 70 metres from the wellhead to monitor traffic

and stop unnecessary personnel wishing to enter the job site.

3.5.3 Shut off all mobile radios and telephones before rigging up begins until perforating is completed, as the units may otherwise set off charges. If it is necessary to use a radio or telephone, drive off the lease a minimum of 1 km.

3.5.4 Place signs saying "Perforating, Shut Off Radio Transmitting Equipment" at the lease entrance and on the lease roadway at least 70 metres from the perforating gun.

3.5.5 Personnel assigned to stop vehicles must be adequately protected from vehicle traffic under existing conditions. Reflective traffic vests should be used.

3.6 Procedures for Retrieving and Disarming a Misfired Perforating Gun 3.6.1 Do not permit a gun to be retrieved during a lightning storm.

3.6.2 No one but members of a trained perforating crew are allowed to

handle misfired guns.

3.6.3 The Workover/Drilling Foreman shall review with the perforating crew their procedure for handling misfired guns.

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3.6.4 Hold a safety meeting to determine a strategy and discuss procedures.

3.6.5 Establish who the essential personnel will be during the retrieving of the live gun. When the gun is at the surface, all other personnel are to be off the lease until the gun is disarmed.

3.6.6 Shut off the wireline generator and rig generators.

3.6.7 Turn off the main circuit breakers.

3.6.8 Disconnect all panels used in the gun firing procedure.

3.6.9 Ensure the casing-to-rig voltage monitor is reading less than 0.25 V.

3.6.10 Pull the gun up to 30 metres from the surface. Check all two-way radios and mobile phones and ensure they are turned off. Post a guard at the lease entry to prevent any vehicles or personnel from entering. All non-essential personnel must move to a pre-established distance off location.

3.6.11 Have the gun pulled up into the lubricator and have the valve closed. Have the lubricator broken out and carefully lowered.

3.6.12 With the exception of a trained perforating crew, all personnel will be required to remain in a safe location until the gun has been effectively disarmed and an all clear signal has been issued.

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4.0 RADIOACTIVE MATERIALS Radioactive equipment uses a radioactive source to make a measurement. Examples of such equipment are the Schlumberger logging tools to measure rock density and rock porosity. Halliburton has a radioactive source in a tool on their truck to measure the density of the cement. Inspection crews sometimes use a radioactive source in a tool to measures steel thickness on the standpipe. 4.1 Hazards

4.1.1 Radioactive sources are extremely dangerous. They emit tiny

particles and rays that can pass through rock and steel. When these particles pass through the human body, they kill or change cells that make up the body. A person exposed to radioactive source radiation could become very sick, get cancer, or die. Very strict precautions against radiation exposure must be applied.

4.1.2 Loss of a radioactive source at the rig site.

4.1.3 Radioactive source lost or stuck in the hole.

4.2 Safety Procedures: 4.2.1 At all times, radioactive sources or tools are in use, keep all crew far

away.

4.2.2 Drilling crew should keep clear of the fluid end of the cement unit if radioactive sources or tools are in unit.

4.2.3 Only the radioactive tool operators are allowed to be present in the rig floor during radioactive source handling.

4.2.4 Radioactive sources must be stored in sealed containers and in a radiation shielded box.

4.2.5 The Schlumberger (Contractor) source box must only be removed from the truck when the sources are required.

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CHAPTER 8 HEALTH, SAFETY & ENVIRONMENTAL ISSUES

SECTION F EMERGENCY RESPONSE PLANNING & DRILLS __________________________________________________________________________________________________________________________

EMERGENCY RESPONSE PLANNING & DRILLS 1.0 INTRODUCTION

1.1 Definitions 1.2 Objectives of Emergency Response Plans 1.3 Objectives of Drills

2.0 GENERAL REQUIREMENTS 3.0 TYPES OF DRILLS / EMERGENCY PLANS

3.1 Well Control (BOP) Drills 3.2 H2S Release Drills 3.3 H2S Rescue Drills 3.4 Fire Attack Plans 3.5 Fire Drills 3.6 Man Down (Injury) Drills 3.7 (Offshore) Lifeboat Drills 3.8 (Offshore) Man-Overboard Drills

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EMERGENCY RESPONSE PLANNING & DRILLS 1.0 INTRODUCTION

"Emergency planning" means considerably more than providing a first aid kit,

stretcher, or fire blanket. Instead, there must be written action plans detailing (to the extent possible) those actions to be taken when an emergency occurs. This will ensure more effective responses when it becomes necessary to face extraordinary circumstances. The effectiveness of the plan will usually be proportionate to the thoroughness and soundness of the planning effort.

Emergency response plans cannot anticipate every event. However, plans can

anticipate the types of emergencies that may occur, and plans can outline a communications network and a decision-making process that provides support to those who must handle the emergency. Those on the site will have to make many decisions on the spot, based on the situation at hand. One purpose of the plan is to take care of as many (administrative) issues as possible, to allow the site commander to focus on the matters of prime importance.

The time devoted to the preparation of an adequate plan will enhance speedy

decisions and actions at the time of an emergency. It can result in lives saved and limits to the extent of damage. The plan will provide the means for supervisors to concentrate on solving major problems rather than spending an undue amount of time trying to bring some organization out of chaos. A properly developed plan includes procedures which enable people to make balanced and considered decisions during an emergency. This opportunity to weigh and consider beforehand reduces the need for spur-of-the-moment decisions. The plan also makes it easier for supervisors to delegate in advance, to establish who does what, and to save the precious time that otherwise would be wasted in deciding and re-deciding actions to be taken during an emergency.

1.1 Definitions

Emergency: A dangerous situation, arising with little or no warning, and causing or threatening death, injury, or serious disruption to people, property or process. A condition needing immediate treatment to mitigate hazards and minimize loss.

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Emergency Response Plan: An organized response, planned in advance to counter a specific potential emergency, that identifies the command structure, lines of communication, and specific actions to prevent damage and control the situation. Drills: An on-site rehearsal of the emergency response plan that tests the ability of responders to meet their responsibilities, and tests the plan itself for effectiveness.

These definitions make it clear that the emergency response plans are the critical feature. Drills are conducted to provide practice, and to ensure the emergency response plans are effective to meet the possible emergency.

1.2 Objectives of Emergency Response Plans

1.2.1 Ensure the safety of workers, responders, and the public.

1.2.2 Reduce the potential for the destruction of property or for further

losses of products.

1.2.3 Assist response personnel to determine and perform proper remedial actions quickly.

1.2.4 Reduce recovery times and costs.

1.2.5 Inspire confidence in response personnel, industry, and the public.

1.3 Objectives of Drills

1.3.1 Drills allow the Workover/Drilling Foreman to evaluate the

preparedness of each individual participating in the drill. For large scale drills this includes outside agencies and support services.

1.3.2 Drills provide practice for participants to perform their assigned tasks

and responsibilities, and to improve their proficiency and response time.

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1.3.3 Drills test the communications between the command center and the local emergency scene.

1.3.4 Drills identify and correct shortcomings in the Emergency Response

Plans.

2.0 GENERAL REQUIREMENTS

2.1 All rigs shall develop emergency response plans against those emergencies

that can be reasonably foreseen, including fire, injured personnel (man down), H2S release, H2S poisoning, and kicks.

2.2 Each rig will designate a primary and back-up command center, continually

manned during the emergency by the Workover/Drilling Foreman or senior Toolpusher. The command center must be readily identifiable to both outside responders and the drill crew.

2.3 Each workover rig shall conduct regular drills to ensure that all personnel are

fully able to carry out their assigned duties. 2.4 Each drill will have a maximum acceptable response time. The rig crew must

complete their assigned tasks within this time limit. If crews are not able to respond within the time limit, drills must be conducted more frequently until the crew is able to meet the time limit.

2.5 During drills, the Workover/Drilling Foreman shall observe and verify that:

2.5.1 The emergency response plan is adequate to address the emergency.

2.5.2 There are adequate numbers of knowledgeable people in appropriate areas to ensure the Workover/Drilling Foreman will get the information he needs to make informed decisions on how to counter the emergency.

2.5.3 Each responder in the drill carries out his assigned duties

competently, quickly, with confidence, and reports in to the command center as appropriate.

2.6 Following each drill, the Workover/Drilling Foreman shall conduct a debriefing

with the rig crew, outlining both what was well done and what needs improvement. If necessary, the Workover/Drilling Foreman and the Toolpusher shall develop and implement action plans to ensure an adequate response.

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3.0 TYPES OF DRILLS / PLANS 3.1 Well Control (BOP) Drills

3.1.1 Each crew shall conduct a BOP drill at least once per week

(depending on the type/duration of workover). The Workover/Drilling Foreman will decide if more frequent BOP drills are required to ensure adequate response.

3.1.2 BOP drills will be varied to cover all possible kick scenarios, including on bottom, hoisting, running in the hole, out of the hole, trip drills with different size pipe (or collars) in the hole, wireline logging, cementing, etc.

3.1.3 The Workover/Drilling Foreman will time crew response during BOP drills and verify they meet minimum requirements.

3.1.4 BOP drill procedures should ensure that adequately trained individuals are posted to check on and report on the status of the following key areas: • Kill line • HCR position • Choke manifold set-up • Choke position(s) • Stack configuration • Stack closing pressure • Pit gain • SIDPP & SICP, (all gauges) • Mud weight in and out • Shaker box • Pump strokes • Mixing hopper & mud supply

3.1.5 Each BOP drill will be documented on both the IADC sheet and the

Saudi Aramco morning report. Documentation will include the type of BOP drill (e.g. pit, trip, etc.) and the response time to secure the well.

3.1.6 Further details regarding BOP drills will be found in the Saudi Aramco Well Control Manual.

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3.2 H2S Release Emergency Planning & Drills 3.2.1 Every person boarding an offshore rig must be able to don breathing

apparatus and breath bottled air within 45 seconds.

3.2.2 Every person who may be required to work on a land rig must be able to don breathing apparatus and breath bottled air within 45 seconds. All other persons working near a land rig must be able to recognize the H2S alarm and know to proceed to the safe briefing area.

3.2.3 Each crew of each rig operating in a known or suspected H2S area will conduct an H2S drill at least once per week. The Workover/ Drilling Foreman will decide if more frequent H2S drills are required to ensure adequate response.

3.2.4 The H2S drill will be announced by the standard siren & strobe light alarm. There must be no prior warning of the drill.

Note: The rig PA system shall immediately and repeatedly

announce “This is a drill! This is a drill!”

3.2.5 H2S drill procedure will include the following: 3.2.5.1 Masking up and breathing bottled air for those crew

members whose assigned tasks require breathing apparatus.

3.2.5.2 Requiring all non-essential personnel (i.e. no specific assigned tasks in the drill) muster at upwind safe briefing area.

3.2.5.3 Conducting a head count or other means to account for all personnel.

3.2.5.4 Rescuing procedures for rescuing potentially injured persons from the H2S contaminated site or vicinity (see “H2S Rescue Drills” below).

3.2.6 Following the drill, the contractor Toolpusher and the Workover/ Drilling Foreman shall randomly select (non-essential) crew members mustered at the safe briefing area and verify that they know how to don and breath from breathing apparatus.

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3.2.7 Each H2S drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time (to complete the drill).

3.3 H2S Rescue Drills

3.3.1 Each crew of each rig operating in a known or suspected H2S area will conduct an H2S rescue drill at least once per month (as part of their weekly H2S drill). The Workover/Drilling Foreman will decide if more frequent H2S rescue drills are required to ensure adequate response.

3.3.2 There must be no prior warning of the drill, nor any warning whatsoever that someone is missing. It is critically important to verify that the standard H2S drill procedure is adequate to identify who is missing and locate and rescue him.

3.3.3 H2S Rescue Drills will proceed as per normal H2S drills, with the following additions: 3.3.3.1 Rig management will assign one crew member to act as an

“H2S victim” and place this individual at an appropriate location.

3.3.3.2 No other crew member will be given advance notice of either

the drill or that someone may be missing.

3.3.3.3 Following their normal H2S drill procedure, the rig crew must be able to identify that someone is missing, locate the missing person, rescue him by bringing him to the safe briefing area and administering appropriate first aid within 7 minutes after the alarm first sounded.

3.4 Fire Attack Plans

3.4.1 On each rig (land and offshore), the drilling contractor will develop

written site–specific Fire Attack Plans for each of the following areas: 3.4.1.1 Engine rooms or skids.

3.4.1.2 SCR rooms.

3.4.1.3 Fuel tank storage areas. 3.4.1.4 Rig and camp accommodations.

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3.4.1.5 Any other site on the rig where a fire may be reasonably

thought possible.

3.4.2 In addition to the above, each offshore rig will develop Fire Attack Plans for the following areas: 3.4.2.1 Pit room.

3.4.2.2 Accumulator deck.

3.4.2.3 Helideck.

3.4.3 The Workover/Drilling Superintendent is responsible to ensure that

adequate Fire Attack Plans are in place for each rig under his supervision.

3.4.4 As a minimum, Fire Attack Plans will include the following: 3.4.4.1 Identify the primary and secondary Fire Attack Team that will

fight and contain the fire (the secondary Fire Attack Team is held in reserve in case the primary team needs relief or assistance).

3.4.4.2 Identify the Fire Attack Team composition (consisting, as a minimum, of a commander, 2 fire fighters, and one messenger).

3.4.4.3 Identify specific fire fighting equipment and procedures to fight the fire in that specific area.

3.4.4.4 Identify the maximum acceptable response time for the Fire Attack Team to assemble and begin to fight the fire.

3.4.4.5 Include procedures for conducting a head count or other means to account for all personnel.

3.4.4.6 Include rescue procedures for rescuing potentially injured persons from the fire site or vicinity.

3.4.5 The drilling contractor shall provide adequate training to ensure his personnel are competent to perform their assigned tasks.

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3.5 Fire Drills 3.5.1 Each rig will conduct a fire drill at least once per quarter. The

Workover/Drilling Foreman will decide if more frequent fire drills are required to ensure adequate response.

3.5.2 Fire drill locations will be varied to provide practice in all Fire Attack Plans.

3.5.3 The Workover/Drilling Foreman will observe and time crew response during fire drills and verify that the Fire Attack Plan and Fire Attack Teams are adequate to address the fire risk.

3.5.4 Each fire drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the location and type of fire drill and the response time to assemble and begin to fight the fire.

3.6 Man Down (Injury) Drills 3.6.1 Each rig will develop a Medical Evacuation (MEDEVAC) Plan that

complies and coordinates with Saudi Aramco GI 1321.015 (Request for Air Medical Evacuation). Even if air medevacs are unlikely, GI 1321.015 contains other critically important procedures to ensure a rapid and effective response to a medical emergency.

3.6.2 Each rig will have the telephone number of the following posted in the rig clinic, the rig office, and the radio room (if applicable, e.g. offshore rigs): 3.6.2.1 Nearest medical facility. 3.6.2.2 Nearest Saudi Aramco medical clinic. 3.6.2.3 Saudi Aramco Aviation.

3.6.3 Each rig will develop Man Down (Injury) Drill procedures to address and treat an immobilizing injury occurring anywhere on the rig location, including an immobilized injured man on the monkey board.

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3.6.4 As a minimum, Man Down (Injury) Drill procedure will address the following: 3.6.4.1 Prompt notification of the Medic.

3.6.4.2 First aid at the injury site.

3.6.4.3 Placing and securing the injured person in a basket

stretcher.

3.6.4.4 Transferring the injured person to the rig clinic.

3.6.5 Each rig will conduct a Man Down (Injury) Drill at least once per quarter. The Workover/Drilling Foreman will decide if more frequent Man Down (Injury) drills are required to ensure adequate response.

3.6.6 Each rig will conduct a vertical rescue drill, for example getting an immobilized injured man safely down from the monkey board, once per year.

Note: A suitably weighted dummy must be used to simulate the

injured person.

3.6.7 The Workover/Drilling Foreman will observe and time crew response during Man Down (Injury) drills and verify that the procedures are adequate to provide prompt and effective treatment.

3.6.8 Each Man Down (Injury) drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the location and type of drill and the response time to bring the injured person to the clinic.

3.7 (Offshore) Lifeboat Drills

3.7.1 Each offshore rig will conduct a lifeboat drill within 24 hours of a crew change, and at least once per month. The Workover/Drilling Foreman will decide if more frequent lifeboat drills are required to ensure adequate response.

3.7.2 Lifeboat drills must include everyone aboard the rig, with the possible exception of only those crew members absolutely essential to maintain a safe watch over the ongoing operation.

3.7.3 Lifeboat drills may be combined with fire and/or H2S drills.

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3.7.4 The maximum acceptable response time for lifeboat drills must take

into account the possibility that evacuation may have to proceed in a hazardous H2S environment. Therefore, everyone aboard the rig must be able to muster to their boat stations and enter their boats with enough time left to lower the boats and sail to a safe upwind area before their SCBA’s run out of air. With a standard 30-minute SCBA, everyone must be aboard their assigned boat within 12 minutes of the alarm first sounding.

3.7.5 Fully occupied lifeboats shall not be lowered into the water as part of the boat drill. (Testing and operating the boats shall be done as routine maintenance items.)

3.7.6 Lifeboat drill procedure must include the following: 3.7.6.1 Command center manned by senior rig management.

3.7.6.2 Immediate and repeated PA announcement “This is a drill!

This is a drill!”

3.7.6.3 Two trained and competent lifeboat men assigned to each lifeboat.

3.7.6.4 Headcount procedure to verify/report to the command center that all persons are accounted for.

3.7.6.5 Search and rescue procedure to locate all missing persons.

3.7.6.6 Maximum acceptable response time for all persons to report to their boat stations.

3.7.6.7 Verification that everyone aboard the rig is capable of entering the lifeboat and securely fastening his seat belt while wearing both a PFD and SCBA.

3.7.7 Each lifeboat drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time for all aboard to muster to their assigned boat stations.

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3.8 (Offshore) Man-Overboard Drills 3.8.1 Each offshore rig will develop Man-Overboard rescue procedures and

train a sufficient number of crewmen to effect a safe and prompt rescue.

3.8.2 Each offshore rig will conduct a man-overboard drill at least once per quarter. The Workover/Drilling Foreman will decide if more frequent man-overboard drills are required to ensure adequate response.

3.8.3 A suitably weighted dummy will be used to simulate a man overboard.

3.8.4 Man overboard drills will involve either (or both) the standby boat or the rig’s own rescue boat, depending upon equipment available on that specific rig.

3.8.5 If no standby boat is readily available, the rig must launch a rescue boat to retrieve the dummy.

3.8.6 Each man-overboard drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time to rescue the man overboard.

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CHAPTER 9 APPENDIX

TABLE OF CONTENTS __________________________________________________________________________________________________________________________

TABLE OF CONTENTS 1.0 GIs, LETTERS, AND REFERENCES

1.1 Onshore Contingency Plan 1.2 Offshore Contingency Plan 1.3 Rig Site Flare Gun and Communication Equipment 1.4 Isolation Barriers for Wells During Drilling and Workover 1.5 Onshore Wellsite Safety 1.6 Installation of Slip-on/Weld-on Casing Heads

2.0 SAUDI ARAMCO FORMS

2.1 Daily Workover Report 2.2 Casing/Liner Landing Details 2.3 Wellhead and Tree Details 2.4 Transportation Department Waybill 2.5 Drilling & Workover Services Department Waybill 2.6 Material Request 2.7 Motor Vehicle Accident Report Form 2.8 Petroleum Products Requisition 2.9 Staged Material Transfer

3.0 WELL ACCOUNT CHARGE NUMBERS

3.1 Accounting Location Code 3.2 Item Number Description

4.0 SAFETY REQUIREMENTS FOR DRILLING AND WORKOVER RIGS 5.0 RIG INSPECTION CHECKLIST FOR ONSHORE RIGS 6.0 RIG INSPECTION CHECKLIST FOR OFFSHORE RIGS

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ISSUE DATE REPLACES

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DRILLING & WORKOVER SERVICES

ONSHORE CONTINGENCY PLAN

1850.001

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MYR 1 14

14

Approved

CONTENT:This General Instruction contains the Contingency Plan for a disaster occurring at any onshore wellsite duringdrilling or workover operations, or when Producing has turned over responsibility for well control to theDrilling and Workover organization. The text includes:

1. OBJECTIVE2. IMPLEMENTATION3. ORGANIZATION4. WELL CONTROL5. RESTORATION OR ABANDONMENT OPERATIONS6. COST ACCOUNTING7. SUPPORT SERVICES8. DOCUMENTING AND CRITIQUE9. DISASTER DRILLS

APPENDIX I - DUTIES AND RESPONSIBILITIESAPPENDIX II - DUTIES AND RESPONSIBILITIES, SUPPORT ORGANIZATIONSAPPENDIX III - ORGANIZATION CHART, WELLS WITHOUT RIG ON LOCATIONAPPENDIX IV - ORGANIZATION CHART, WELLS WITH RIG ON LOCATION

1.0 OBJECTIVE

The objective of this Contingency Plan is to handle well control operations when an onshore welldisaster or major blowout occurs during drilling or workover operations or when Producing has turnedover responsibility for well control to Drilling and Workover. This plan will complement the existingProducing Disaster Contingency Plans and will become effective only when a well blowout causes orthreatens to cause a major emergency.

2.0 IMPLEMENTATION

2.1 Well Emergency During Production Operations

If a well emergency or disaster occurs while the well is the responsibility of one of the ProducingDepartments, notification that a well emergency exists or that a disaster has occurred will bemade through the normal chain of command. The Area Producing Vice President or Manager (ifthe Vice President cannot be reached) may request Drilling and Workover to take over wellcontrol operations by contacting (by priority):

• Vice President, Petroleum Engineering and Development or

• General Manager, Drilling and Workover or

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• Manager, Drilling & Workover Services.

2.2 Well Emergency During Drilling or Workover Operations

If an emergency or disaster occurs during drilling or workover operations on a well, the situationwill be reported by dialing 110 and contacting the Manager, Drilling and Workover Operationsor the General Manager, Drilling and Workover. The responsibility of the well control will bewith Drilling and Workover.

2.3 Reporting of Emergency During Drilling or Workover Operations

2.3.1 The drilling/workover Foreman or Senior drilling representative will report theemergency by dialing 110.

2.3.2 The proper method for reporting an emergency is that the person reporting speaksslowly, calmly, distinctly in a clear voice and gives information in the followingsequence:

a. State: “There is an emergency at Rig , on Well at _______area.”When reporting a disaster, include the statement: “This is a disaster.”

b. Identify yourself by name and badge number.

c. Give your location.

d. Describe the emergency briefly, i.e. blowout, fire, leak, etc.

e. State if there is any injured person.

f. Repeat the above information.

g. Ask the person receiving the call to repeat the information to make sure it iscomplete and correct.

2.3.3 The drilling/workover Foreman will also contact the Superintendent, Manager orGeneral Manager of Drilling and Workover to report the emergency.

2.4 Order of Priorities

2.4.1 Rescue and Protection of Personnel

2.4.1.1 The first objective of this plan is the preservation and protection of human life.In the event that there are any injured or dead, the drilling or workover foremanon the rig will be responsible for obtaining emergency treatment and forambulance or helicopter transportation. This will be done by notifying medicalservices when calling the emergency number 110. He should state the numberof injuries and/or deaths.

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2.4.1.2 Security patrols will be dispatched to restrict access to the area to SaudiAramco authorized personnel only.

2.4.1.3 The drilling/workover Foreman or senior drilling representative will designatea team to immediately begin monitoring the area for flammable gas andhydrogen sulfide (H2S) or other potential hazards.

2.4.1.4 Persons in any endangered area near the emergency site will be alerted and/orevacuated.

2.4.1.5 Fire Protection Division will respond to the emergency by dispatching thenecessary personnel and equipment. Level of assistance will depend onremoteness of the site.

2.5 Safeguarding of Company Property

Fire fighting and special well control equipment from the Drilling Equipment & Water WellMaintenance in Abqaiq will be dispatched as quickly as possible. Water or foam will reduce thedanger of ignition if the well is not on fire, or it will cool and help protect the wellhead if theblowout should catch fire.

Specialized fire fighting equipment will be utilized as necessary2.5.1 Well Control

The Site Leader of the Well Control Team (with rig on well) or Special Well ActionTeam (without rig on well) will supervise the on-site well control operations. No otherleader or site commander, designated by a different organization, will have the authorityto interfere or take charge.

2.5.2 Ignition

Should uncontrolled flow from a well occur without being accidentally ignited, thedecision to ignite will be based on the following criteria:

A) If flow from a gas well contains H2S in excess of 20 ppm ignite the flowimmediately.

B) If the flow presents immediate and serious danger to the inhabited areas orfacilities, ignite the flow immediately.

C) Any flow condition other than that described in item (A) & (B) will be evaluatedon a case-by-case basis. The decision to ignite will be made by the GeneralManager, Drilling and Workover, after evaluating all the facts. If there is nocommunication with higher levels of Mangement or the time factor becomes

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critical, then the decision to intentionally ignite can be made by a Drilling orWorkover foreman, Superintendent or Manager.

3.0 ORGANIZATION

The organization for the Well Control Contingency Plan is described in appendix III & IV. Personnelassigned to the organization will be relieved of current responsibilities by other personnel who willcarry on regular Company business.

3.1 In the event that the well has a drilling or workover rig on it, the Manager of Drilling andWorkover Operations will be responsible for well control operations. He will appoint the SiteLeader of the Well Control Team. The Well Control Team will consist of necessary drilling andworkover foreman and the rig crew of the rig on location. Support services such as the SpecialWell Action Team, will be provided as needed.

3.2 In the event that Producing turns over a well to Drilling and Workover, the Manager of Drillingand Workover Services will be responsible for well control operations. The Superintendent ofDrilling Equipment & Water Well Maintenance Division will assume the job of Site Leader ofthe Special Well Action Team. The team will be made up of the Special Well Services Unitplus Drilling /Workover foreman as required to provide the necessary expertise. Arepresentative from the Producing Organization will be part of the team and will provide adviceand assistance as needed. Labor crews will be provided by Water Well Rig Operations Unit.

3.3 Prior to any rig move to drill or workover a well, the Drilling Superintendent or designatedrepresentative will contact the respective Producing counterpart and others that may haveinterest in the area in order to:

- Ensure that the concerned Organizations are familiar with the responsibilities described inthe Drilling & Workover Contingency Plan in case of a disaster,

- Establish a contact point in case the Contingency Disaster Plan has to be activated. Thiscommunication channel will serve as the information pipeline to keep Producing Operationsabreast of the latest developments, and to request assistance if required.

4.0 WELL CONTROL

The Site Leader of the Well Control Team (with rig on well) or the Special Well Action Team (withoutrig on well) will work closely with the respective Manager and the General manager, Drilling andWorkover. He will participate in the immediate evaluation of the emergency to determine the plan forcontrol of the well.

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5.0 RESTORATION OR ABANDONMENT OPERATIONS

As a well is brought under control, safety equipment will be installed. Debris must be removed andconstruction plans will be implemented to repair the site and return the well to its previous operatingstatus. If necessary, the well will be abandoned.

6.0 COST ACCOUNTING

Drilling and Workover, Planning & Accounting Services Unit, will obtain a special project numberfrom the Finance and Insurance Claims Administrator, Treasurers Department, Dhahran, toaccumulate costs related to the disaster. The Treasurers Department will determine the properdisposition of the costs accumulated in the SP.

The Planning and Accounting Services Unit of the Drilling and Workover Department will review thecharges and make corrections or adjustments as necessary and issue a final financial cost report ifrequired.

7.0 SUPPORT SERVICES

Support services provided by various departments as well as those performed by services companieswill be coordinated by the Site Leader, Well Control Team and the Manager, Drilling and WorkoverServices. Each department providing a support service will be responsible for adequate preparation toprovide prompt and efficient service during the emergency.

8.0 DOCUMENTING AND CRITIQUE

Complete daily logs will be maintained from the time of the initial report and the activation of theemergency control organization. The responsible persons in the central emergency group Manager’scontrol room (Room 200, Bldg. 3193) will act as liaison with all of the various groups to maintaincontinuous documentation of the emergency. A complete factual report of each day’s activities will bemaintained as permanent record. The final report shall be prepared by the Drilling and WorkoverEngineering Department and shall contain a complete record of facilities and wells involved, planning,decisions, photographs, etc. Upon completion of the final report, a critique will be held to evaluate allthe causes, actions and reactions of the various phases up to the final restoration or disposition.

9.0 DISASTER DRILLS

9.1 Drilling and Workover will conduct an annual “Primary” rig emergency drill to better preparefor unexpected well disasters when they occur. This drill will be coordinated with the disasterplan drills of Southern or Northern Area Producing and other operating organizations so that allparties will become familiar with the respective responsibilities and response plans. By

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conducting joint drills, the response time to activate the disaster plans for a blowout willdecrease, resulting in rapid control of the well. This Primary drill will require full mobilizationof equipment and personnel. Other organizations such as Loss Prevention, Medical, FireDepartment, Transportation, etc will also participate in the drill.

9.2 Drilling and Workover will also conduct annual “Secondary” rig emergency drills with eachdivision of a Producing area. The “Secondary” drills will evaluate readiness to respond to adisaster and will require minimal mobilization of equipment and personnel.

Recommended By:

______________________________F. A. Al-MoosaGeneral Manager, Drilling. & Workover

Concurred By:

______________________________H. J. KassemManager, Loss Prevention Department

______________________________A.A. GhabbaniManager, Fire Protection Department

______________________________S. S. RaslanGeneral Manager, Industrial Security Operations

______________________________A. M. Al-SabtiVice President, Southern Area Producing

______________________________Y. A. Al-AiderousVice President, Northern Area Producing

Approved By:______________________________M. Y. RafieVice President, Petroleum Engineering and Development

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APPENDIX IDUTIES AND RESPONSIBILITIES

Many of the duties and responsibilities of the members of the Contingency Plan Organization are listed inorder to clarify the various functions. This list is not intended to describe all the actions necessary for anyparticular emergency.

Vice President, Petroleum Engineering and Development

1. Assume executive authority over the well control emergency and report conditions and operatingprogress to the Executive Vice President or President.

2. Advise Vice President, Government Affairs of Statements for news release.

3. Appoint investigating committee.

General Manager, Drilling and Workover

1. Decide on activation of the Contingency Plan and formulate a plan for controlling the well.

2. Make decision on ignition of well effluent, if required.

3. Provide Vice President with details of well and field.

4. Notify Vice President of Exploration.

Manager, Drilling and Workover Operations

1. Assume responsibilities for well control operations on wells involving drilling or workover rigs.

2. Advise staff that Contingency Plan has been activated.

3. Provide support and direction to the Site Leader of the Well Control Team and advise if the decisionon ignition must be made.

Superintendent Drilling or Workover Operation

1. Notify Dept. Manager of the emergency.

2. May act as Site Leader of the Well Control Team.

3 Insure that the drilling/workover Foreman or senior drilling representative has designated a team tomonitor the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

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Manager, Drilling and Workover Services

1. Notify Government Affairs Representative.

2. If necessary call Boots & Coots (281) 931-8884 Fax No. (281) 931-8302

or Neal Adams (713) 937-8320 Fax No. (713) 937-6503

3. Notify Department Managers of support services departments.

4. Assume responsibilities for well control operations on wells turned over to Drilling and Workover byProducing Operations.

5. Advise staff that Contingency Plan has been activated.

6. Provide support and direction to the Site Leader of the Special Well Action Team.

7. Arrange for on-site inspection for Vice President and General Manger, Drilling and Workover.

8. Coordinate services provided by other department.

9. Maintain the emergency equipment in a ready manner and arrange movement to location.

Superintendent, Drilling Equipment & Water Well Maintenance Division

1. Send Emergency Well Control Equipment to the well location.

2. Provide personnel to work in the DE&WWM yard to help assemble, operate and repair equipment.

3. Act as head of Special Well Action Team.

4. Hook up nearby water wells for use during onshore well control operations.

5. Provide skilled and semi-skilled personnel to work at the disaster location.

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Approved

Site Leader, Well Control Team (w/ rig on well) or Site Leader, Special Well Action Team (w/o rig on well)

1. Advise Foreman of immediate action to be taken.

2. Assist with evacuation and rescue operation if needed.

3. Advise staff that Contingency Plan has been activated.

4. Proceed to location and take the position of Site Leader.

5. Maintain on-scene control and keep Manager advised of any change in condition.

6. Contact Area Loss Prevention Superintendent and arrange for safety equipment surveys and servicingneeds.

7. Set up security as required.

Accounting Services

1. Maintain a record of costs incurred and appropriate documentation as directed.

2. Maintain inventory of all Equipment and Materials delivered to disaster site.

Superintendent, Drilling Rig Support Division

1. Obtains all materials and equipment needed for use at the disaster site.

2. Coordinates with Transportation to ensure prompt delivery of materials and equipment.

Superintendent, Wellsites Division

1. Provides a location for emergency equipment and camp to be set up.

2. Provides a roadway for movement of material and equipment to reach the location.

3. Provides stand-by equipment for use during well control operations to construct pits or dikes.

Government Affairs Representative

1. Notify Government officials of situation. All communications will be cleared through Vice President,Petroleum Engineering & Development.

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Manager, Drilling and Workover Engineering

1. Inform Manager, Reservoir Engineering Department of situation and conditions. Obtain relevant welldata including:

(a) Bottom-hole pressure, productivity index, water cut and oil-water contact.

(b) Preferred relief well drilling location(s) subject to wind and terrain considerations.

(c) Preferred intercept interval.

(d) Contour dip and strike.

2. Request flow rate and pressure profile calculations to be run (computer) for given conditions.

3. Transmit copies of well configuration sketch, wellhead drawing, Morning Reports, and other pertinentdocumentation to the General Manager, Petroleum Engineering, General Manager, Drilling andWorkover and to the Vice President, Petroleum Engineering and Development.

4. Assemble well data and distribute copies as required. Include drilling program, well cross-sectionalsketch, reports, known information - formation tops, final elevation etc.

5. Have large-scale sketch (flip chart size) of well configuration prepared for use in review meetings.Denote casing sizes/depths, drill string configuration, formation tops, hole problems encountered andother relevant information which may be of use.

6. Designate qualified and experienced engineer (s) to go to the wellsite to:

(a) Keep accurate log of on-site operations and well/environmental/weather conditions.

(b) Assist technically as required.

7. Prepare kill program including fluid type, density and pumping rates.

8. Review available rig(s) to drill relief well(s). Recommend rig(s) from optimum technical viewpoint.

9. Once survey location(s) for relief well(s) are received, prepare directional drilling program.

10. Monitor drilling progress on relief well(s) and provide technical liaison among engineering servicesgroup(s) and operations.

11. Prepare relief well kill program(s).12. Prepare management reviews of progress as required.

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APPENDIX IIDUTIES AND RESPONSIBILITIES OF SUPPORT SERVICES DEPARTMENT

Communications

1. Implement communications system at Disaster Control Center.2. Provide for maintenance of system on the scene and at control center.3. Monitor system to see that it is functioning properly.

Aviation

1. Provide emergency transportation for evacuation.

2. Aerial surveillance for security and well conditions.

3. Provide for movement of authorized personnel and materials.

Land Transportation

1. Provide for movement of materials and equipment.

Loss Prevention

1 Provide Personnel at the well site and Disaster Control Center to advise the site leader or commanderon safety related issues.

Fire Protection

1. Provide onsite personnel and equipment to support emergency operations as requested. Level ofassistance will depend on remoteness of the emergency site.

Medical

1. Provide emergency medical services as required (on-the-scene and at clinic).

Community Services

1. Provide accommodations and food services as needed.

Security

1. Provide on-site personnel for security control.

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Producing

1. Handle all liaison with oil and gas dispatcher, plants, pipelines and other groups concerned with oilmovement and gas production.

2. Coordinate with the Site Leader of the Well Control Team on all activities within the field.

3. Supervise all shut-in and start-up activities of nearby wells when the need arises.

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APPENDIX III WELLS WITHOUT RIG ON LOCATION

PET. ENGR. & DEVELOPMENTVICE PRESIDENT

PETROLEUM ENGINEERINGGENERAL MANAGER

GOVT. AFFAIRS

DRILLING & WORKOVERGENERAL MANAGER

DRILLING & WORKOVER SVCS. DEPT. MANAGER

DRLG. EQUIP & WATER WELL MAINT. DIV.SUPERINTENDENT/

SPECIAL WELL ACTIONTEAM LEADER

DRLG. RIG SUP. DIV.SUPERINTENDENT

WELLSITES SVCS. DIV.SUPERINTENDENT

PLANNING & ACCT. SERVICESSUPERVISOR

SUPPORTSVCS.

SPECIAL WELL ACTION TEAM

RESERVOIRMGMT DEPT.

MANAGER

DRLG. & WORKOVERENGINEERS

DRLG. & WORKOVER ENGR. DIV

GEN. SUPERVISOR

PRODUCING ENGR. DEPT.MANAGER

NAPE OR SAPE

DRILLING & WORKOVER ENGR. DEPT. MANAGER

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APPENDIX IVWELLS WITH RIG ON LOCATION

PET. ENGR. & DEVELOPMENTVICE PRESIDENT

PETROLEUM ENGINEERINGGENERAL MANAGER

GOVT. AFFAIRS

DRILLING & WORKOVERGENERAL MANAGER

DRILLING & WORKOVER SVCS. DEPT. MANAGER

DRLG. RIG SUP. DIV.SUPERINTENDENT

DRLG & WORKOVER ENGR DEPARTMENT

MANAGER

WELLSITES SVCS. DIV.SUPERINTENDENT

PLANNING & ACCT. SERVICES

SUPERVISOR

WELL CONTROL TEAMSITE LEADER

SUPPORTSVCS.

WELL CONTROL TEAM

RESERVOIRMGMT. DEPT.

MANAGER

DRLG. & WORKOVERENGINEERING DIV(S).GEN. SUPERVISOR(S)

DEV. DRILL. & OFFSHORE W/O DEPT. OR

DEEP DRILL.& ONSHORE W/O DEPTMANAGER

DRLG. & WORKOVERENGINEERS

DRLG. EQUIP & WATER WELL MAINT. DIV.SUPERINTENDENT

PRODUCTION ENGR. DEPT.MANAGER

NAPE OR SAPE

SPECIAL WELL ACTION TEAM

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CONTENT:This General Instruction contains the Contingency Plan for a disaster occurring at an offshore wellsite duringdrilling or workover operations, or when Producing has turned over responsibility for well control to theDrilling and Workover organization. The text includes:

1. OBJECTIVE2. IMPLEMENTATION3. ORGANIZATION4. WELL CONTROL5. RESTORATION OR ABANDONMENT OPERATIONS6. COST ACCOUNTING7. SUPPORT SERVICES8. DOCUMENTING AND CRITIQUE9. DISASTER DRILL

APPENDIX I DUTIES AND RESPONSIBILITIESAPPENDIX II DUTIES AND RESPONSIBILITIES, SUPPORT ORGANIZATIONSAPPENDIX III ORGANIZATION CHART

1.0 OBJECTIVE:

The objective of this Contingency Plan is to handle well control operation when an offshore welldisaster or major blowout occurs during drilling or workover operations, or when Producing has turnedover well control responsibilities to Drilling and Workover. This plan will complement the existingMarine and Producing Departments’ Disaster Contingency Plans and the Saudi Aramco Oil SpillContingency Plan. It will become effective only when a well blowout causes or threatens to cause amajor emergency.

2.0 IMPLEMENTATION:

2.1 Well Emergency During Production Operations

If a well emergency or disaster occurs while the well is the responsibility of one of the ProducingDepartments, notification that a well emergency exists or that a disaster has occurred will bemade through the normal chain of command.

The Area Producing Vice President or Manager (if the Vice President cannot be reached) mayrequest Drilling and Workover to take over well control operations by contacting the VicePresident, Petroleum Engineering and Development or the General Manager, Drilling andWorkover (if the Vice President is not immediately available).

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2.2 Well Emergency During Drilling, or Workover Operations

If an emergency or disaster occurs during drilling or workover operations on a well, the situationwill be reported by dialing 110 and contacting the Manager, Drilling and Workover Operationsor the General Manager, Drilling and Workover. The responsibility for well control will be withDrilling and Workover.

2.3 Reporting of Emergency During Drilling or Workover Operations

2.3.1 The drilling/workover Foreman or senior drilling representative will report theemergency by dialing 110. The drilling/workover Foreman will be the onsitecommander unless and until relieved by the Well Control Team Site Leader (WCTSL)designated in the ORGANIZATION section (paragraph 3) of this document. If thedrilling/workover Foreman is incapacitated prior to the onsite arrival of the WCTSL,then the next senior Saudi Aramco individual on-board will assume responsibility asonsite commander until properly relieved. If no viable Saudi Aramco personnel are on-board, then the Senior Contractor individual on-board will assume responsibility asonsite commander until properly relieved.

2.3.2 The proper method for reporting an emergency is that the person reporting speaksslowly, calmly, distinctly in a clear voice and gives information in the followingsequence:

a. State: "There is an emergency at Rig ___________., on Well/Platform _______/______."When reporting a disaster, include the statement: "This is a disaster".

b. Identify yourself by name and badge number.c. Give your location.d. Describe the emergency briefly, i.e. blowout, fire, leak, etc.e. State if there is any injured person.f. Repeat the above information.g. Ask the person receiving the call to repeat the information to make sure it is

complete and correct.2.3.3 The drilling/workover Foreman will also contact the Superintendent, Manager or

General Manager of Drilling and Workover to report the emergency.

2.4 Order of Priorities

2.4.1 Rescue and Protection of Personnel

2.4.1.1 The first objective of this plan is the preservation and protection of human life.In the event that there are any injured or dead, the drilling or workover foremanon the rig, or the Production Superintendent of the area, if no rig is involved,

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will be responsible for obtaining emergency treatment and helicopter/marine00transportation. This will be done by notifying medical services when callingthe emergency number 110. He should state the number of injuries and/ordeaths. Search and rescue efforts will be coordinated between the RigForeman, the Marine Rig Move Coordinator, Offshore Security and Aviation.In addition, the Rig Foreman should contact the Marine Rig Move Coordinatorfor any advice and assistance not covered by this instruction.

2.4.1.2 The rig standby vessel(s) will receive instructions directly from the rig. If amajor problem on the rig is obvious, the vessel master(s) shall prepare to renderimmediate assistance by maintaining an appropriate position upwind of the rigwith all available engines running, unless specifically ordered otherwise by therig.

2.4.1.3 Helicopters and boats will be dispatched for assistance and deployment insearch and rescue efforts as required.

2.4.1.4 Concurrent with the dispatch of helicopters/boats, the Medical Chief forEmergency Services will be alerted to dispatch Medical Evacuation Team(s)to assist in transporting and to prepare for handling the injured.

2.4.1.5 Next of kin of the dead, missing or injured will be notified by the PersonnelDepartment, with the assistance, if required, of the Manager, Drilling andWorkover Operations if the dead, missing or injured person is a Drilling andWorkover Operations employee.

2.4.1.6 The Rig Foreman shall contact the Tanajib Toolhouse to begin coordination ofsupply vessels and materials.

2.4.2 A "Notice to Mariners" should be broadcast immediately by the Marine ShiftCoordinator.

2.4.3 The drilling/workover Foreman or senior drilling representative will designate a team toimmediately begin monitoring the area for flammable gas and hydrogen sulfide (H2S) orother potential hazards.

2.4.4 Persons in any endangered area near the emergency site will be alerted and/or evacuated.The drilling/workover Foreman is responsible for personnel on the rig while the rig isworking on a well. The Producing Superintendent, working closely with the MarineDepartment, will be responsible for alerting and evacuating personnel from the platform.

2.5 Safeguarding of Company Property

2.5.1 Northern Area Marine Offshore Operation Division will dispatch pollution control boatsas quickly as possible.

2.5.2 Northern Area Marine Offshore Operation Division will dispatch fire fighting vesselswhen called upon. Large volumes of seawater will be spread to reduce the ignitionpotentials (if the platform /well in not on fire) or to cool the platform and protectwellheads of other wells if the blowout should ignite. Dispersant will be added to thewater streams if necessary.

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2.5.3 Aviation Department may be requested to provide an Air Tractor to assist in containingthe oil spill if the need arises.

2.5.4 Forecasts of tide, wind and other weather conditions that will affect the direction inspread of hazardous discharges can be obtained from the Saudi Aramco Intranet on a 24-hour basis. The Disaster Control Center will provide up-to-date weather forecastinformation to the site leader or commander.

2.6 Well Control

The Site Leader of the Well Control Team (with rig on well) or Special Well Action Team(without rig on well) will supervise the on-site well control operations. No other leader or sitecommander, designated by a different organization, will have the authority to interfere or takecharge.

2.7 Ignition

Should uncontrolled flow from a well occur without being accidentally ignited, the decision toignite will be made on a case-by-case basis after evaluating all the facts.

Since the impact of intentional ignition on an offshore platform can be significant, it isimperative that the decision to ignite be made by Management of Drilling and Producingorganizations.

3.0 ORGANIZATION

The organization for the Well Control Contingency Plan is described in Appendix III. Personnelassigned to the organization will be relieved of current responsibilities by other personnel who willcarry on regular Company business.

3.1 In the event that the well has a drilling or workover rig on it, the Manager of Drilling andWorkover Operations will be responsible for well control operations. He will appoint the SiteLeader of the Well Control Team. The Well Control Team will consist of necessary drilling, andworkover foreman and the rig crew of the rig on location. Support sevices such as the SpecialWell Action Team, will be provided as needed.

3.2 In the event that a well is turned over to Drilling and Workover by Producing, the Manager ofDrilling and Workover Operations will again be responsible for well control operations. He willappoint the Site Leader of the Well Control Team. The Well Control Team will consist of theneccessary drilling and workover foreman and the rig crew of a nearby rig. Support servicessuch as the Special Well Action Team, will be provided as needed.

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3.3 Prior to any rig move to drill or workover a well, the Drilling and Workover Manager,Superintendent or Foreman will contact the respective Producing counterpart and others thatmay have interest in the area in order to:

- Ensure that the concerned Organizations are familiar with the responsibilities described inthe Drilling & Workover Contingency Plan in case of a disaster,

- Establish a contact point in case the Contingency Disaster Plan has to be activated. Thiscommunication channel will serve as the information pipeline to keep ProducingOperations abreast of the latest developments, and to request for assistance if required.

4.0 WELL CONTROL:

The Site Leader of the Well Control Team will work closely with the respective Manager and theGeneral Manager, Drilling and Workover. He will participate in the immediate evaluation of theemergency to determine the plan for control of the well.

5.0 RESTORATION OR ABANDONMENT OPERATIONS:

As a well is brought under control, safety equipment will be installed. Debris must be removed andconstruction plans will be implemented to repair the site and return the well to its previous operatingstatus. If necessary, the well will be abandoned

6.0 COST ACCOUNTING:

Drilling and Workover, Planning & Accounting Services Unit, will obtain a special project numberfrom the Finance and Insurance Claims Administrator, Treasurers Department, Dhahran, toaccumulate costs related to the disaster. The Treasurers Department will determine the properdisposition of the costs accumulated in the SP.

The Planning and Accounting Services Unit of the Drilling and Workover Department will review thecharges and make corrections or adjustments as necessary and issue a final financial cost report ifrequired.

7.0 SUPPORT SERVICES:

Support services provided by various departments as well as those performed by service companieswill be coordinated by the Site Leader, Well Control Team and the Manager, Drilling and WorkoverServices. Each department providing a support service will be responsible for adequate preparation toprovide prompt and efficient service during the emergency.

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MYR 6 13

13

Approved

8.0 DOCUMENTING AND CRITIQUE

Complete daily logs will be maintained from the time of the initial report and the activation of theemergency control organization. The responsible persons in the central emergency group Manager'scontrol room (Room-200, Bldg. 3193) will act as liaison with all of the various groups to maintaincontinuous documentation of the emergency. A complete factual report of each day's activities will bemaintained as permanent record. The final report shall be prepared by the Drilling and WorkoverEngineering Department and shall contain a complete record of facilities and wells involved, planning,decisions, photographs, etc. Upon completion of the final report, a critique will be held to evaluate allthe causes, actions and reactions of the various phases up to the final restoration or disposition.

9.0 DISASTER DRILLS

9.1 Drilling and Workover will conduct an annual “Primary” rig emergency drill to better preparefor unexpected well disasters when they occur. This drill will be coordinated with the disasterplan drills of Northern Area Producing, Marine Department and other operating organizationsso that all parties will become familiar with the respective responsibilities and response plans.By conducting joint drills, the response time to activate the disaster plans for a blowout willdecrease, resulting in rapid control of the well. This Primary drill will require full mobilizationof equipment and personnel.

9.2 Drilling and Workover will also conduct annual “ Secondary” rig emergency drills with eachdivision of a Producing area. The “Secondary” drills will evaluate readiness to respond to adisaster and will require minimal mobilization of equipment and personnel.

**

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1851.001

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MYR 7 13

13

Approved

Recommended By:

________________________________F. A. Al-MoosaGeneral Manager, Drilling & Workover.

Concurred By:

__________________________ __________________________A. A. Mohyiddin H. J. KassemManager, Marine Department Manager, Loss Prevention Department

___________________________ __________________________Y. A. Al-Aiderous S. S. RaslanV. P. Northern Area Producing General Manager, Industrial Security

_______________________Approved By: M. Y. RafieV. P. Petroleum Engineering and Development

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MYR 8 13

13

APPENDIX I

Approved

APPENDIX IDUTIES AND RESPONSIBILITIES

Many of the duties and responsibilities of the members of the Contingency Plan organization are listed in orderto clarify the various functions. This list is not intended to describe all the actions necessary for any particularemergency.

Vice President, Petroleum Engineering and Development

1. Assume executive authority over the well control emergency and report conditions and operatingprogress to the Executive Vice President or President.

2. Advise Vice President, Government Affairs of statements for news release.

3. Appoint investigating committee.

General Manager. Drilling and Workover

1. Decide on activation of the Contingency Plan and formulate a plan for controlling the well.

2. Make decision on ignition of well effluent, if required.

3. Provide Vice President with details of well and field.

4. Notify Vice President of Exploration.

Manager, Drilling and Workover operations

1. Assume responsibilities for well control operations on wells involving drilling or workover rigs andwells turned over to Drilling and Workover by Producing.

2. Advise staff that Contingency Plan has been activated.

3. Provide support and direction to the Site Leader of the Well Control Team and advise if the decisionon ignition must be made.

4. Arrange for on-site inspection by Vice President and General Manager, Drilling and Workover.

Superintendent Drilling or Workover operations

1. Notify Department Manager of the emergency.

2. May act as Site Leader of the Well Control Team.

3. Insure that the drilling/workover Foreman or senior drilling representative has designated a team tomonitor the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

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APPENDIX I

Approved

Manager, Drilling and Workover Services

1. Notify Government Affairs Representative.

2. If necessary call Boots & Coots (281) 931-8884 Fax No. (281) 931-8302Telex No. 790-161 A/B BOOTSCOUTS HOU.

or Neal Adams (713) 937-8320 Fax No. (713) 937-6503Telex No. 701-106

3. Notify Department Managers of support services departments.

4. Advise staff that Contingency Plan has been activated.

5. Provide support to the Site Leader of the Well control Team.

6. Arrange for on-site inspection by Vice President.

7. Coordinate services provided by other department.

8. Maintain the emergency equipment in a ready manner and arrange movement to Offshore Tanajib asrequired.

Superintendent, Drilling Equipment and Water Well Maintenance Division

1. Send emergency well control equipment to Offshore Tanajib as required.

2. Provide personnel to work in various locations as required.

Site Leader, Well Control Team

I. Participate in formulation of immediate plans to control the well.

2. Advise Foreman (if a rig on the well) of immediate action to be taken.

3. Assist with evacuation and rescue operation if needed.

4. Advise staff that Contingency Plan has been activated.

5. Proceed to location and take the position of Site Leader.

6. Maintain on-scene control and keep Manager advised of any change in condition.

7. Contact Superintendent, Dhahran Area Loss Prevention or Supervisor, L. P. Exploration &Development Unit and arrange for site coverage, as required.

8. Set up security as required.

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MYR 10 13

13

APPENDIX I

Approved

Accounting Services

I Maintain a record of costs incurred and appropriate documentation as directed.

2. Maintain inventory of all Equipment and Materials delivered to disaster site.

Superintendent, Drilling Rig support Division

1. Obtains all materials and equipment needed for use at the disaster site.

2. Coordinate with Transportation to ensure prompt delivery of materials and equipment.

Government Affairs Representative

Notify Government officials of situation. All communications will be cleared through Vice President,Petroleum Engineering Development.

Manager, Drilling and Workover Engineering Department

1. Inform Manager, Reservoir Engineering Department of situation and conditions. Obtain relevant welldata including:

(a) Bottom-hole pressure, productivity index, water cut and oil-water contact.

(b) Preferred relief well drilling locations subject to wind and terrain considerations.

(c) Preferred intercept interval.

(d). Contour dip and strike.

2. Request computer flow rate and pressure profile-calculations to be run for given conditions.

3. Transmit copies of well configuration sketch, wellhead drawing, Morning Reports, and other pertinentdocumentation to the General Manager, Petroleum Engineering, General Manager, Drilling andWorkover and to the Vice President, Petroleum Engineering and Development.

4. Assemble well data and distribute copies as required. Include drilling program, well cross-sectionalsketch, bottom-hole pressure and directional survey data, reports, known information - formation tops,final elevation etc.

5. Have large-scale sketch (flip chart size) of well configuration prepared for use in review meetings.Denote casing sizes/depths, drill string configuration, formation tops, hole problems encountered andother relevant information which may be of use.

6. Designate qualified and experienced engineer(s) to go to the wellsite to:

(a) Keep accurate log of on-site operations and well/environmental/weather conditions.

(b) Assist technically as required.

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MYR 11 13

13

APPENDIX I

Approved

7. Prepare kill program including fluid type, density and pumping rates.

8. Review available rig(s) to drill relief well(s). Recommend rig(s) from optimum technical viewpoint.

9. Once survey location(s) for relief well(s) are received, prepare directional drilling program.

10. Monitor drilling progress on relief well(s) and provide technical liaison among engineering servicesgroup(s) and operations.

11. Prepare relief well kill program(s).

12. Prepare management reviews of progresses required.

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MYR 12 13

13

APPENDIX II

Approved

APPENDIX IIDUTIES AND RESPONSIBILITIES OF SUPPORT SERVICES DEPARTMENTS

Marine

1. Provide marine transportation, communication, offshore fire fighting to combat oil pollution, andsupport as necessary.

Communications

1. Implement communications system at Disaster Control Center.

2. Provide for maintenance of system on the scene and at control center.

3. Monitor system to see that it is functioning properly.

Aviation

1. Provide emergency transportation for evacuation.

2. Aerial surveillance for security and well conditions.

3. Provide for movement of authorized personnel and materials.

Land Transportation

1. Provide for movement of materials and equipment.

Loss Prevention

1. Provide Personnel at the well site and Disaster Control Center to advise the site leader or commanderon safety related issues.

Security

1. Assist in the marine evacuation of personnel using Security Patrol Boats as directed by the DisasterControl Center.

2. Assist in the marine search and rescue operations as directed by the Disaster Control Center.3. Keep the disaster area clear of any Saudi Aramco, Contractor or local fishing boats.4. Coordinate with Northern Area Government Affairs and other Government Agencies.Medical

1. Provide emergency medical services as required on-scene and at clinic(s).

Community Services

1. Provide accommodation and food services as needed.

Producing

1. Handle all liaison with oil dispatcher, plants pipelines and other groups concernedl with oilmovements.

2. Coordinate with the Site Leader of the Well Control Team on all activities within the field.3. Supervise all shut-in and start-up activities of nearby wells when the need arises.

*

*

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MYR 13 13

13

APPENDIX III

Approved

APPENDIX III

PETROLEUM ENGINEERING & DEVELOPMENTVICE PRESIDENT

DRILLING & WORKOVER GENERAL MANAGER

DRLG & WKVR SVCS DEPTMANAGER

RESVR MGMTDEPARTMENT

MANGER

DRLG EQPT & WTRWELL MTCE DIV

SUPERINTENDENT

GOV’T AFFAIRS

SUPPORTSERVICES

PROD ENGRDEPARTMENT

MANAGER,NAPE

WELL CONTROL TEAM

PETROLEUM ENGINEERING GENERAL MANAGER

DEV. DRILL & OFFSHORE WORKOVER DEPT.

MANAGER

WELL CONT TEAMSITE LEADER

ACCT SERVICESSUPERVISER

DRLG & WKVRENGR DEPTMANAGER

DRLG RIG SUPP DIVSUPERINTENDENT

APPENDIX III

ORGANIZATION CHART

SPECIAL WELLACTION TEAM

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RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

1852.001

03/10/1999 NEW

FAM 1 2

X 2

Approved

CONTENT:This General Instruction contains policy for equipping a rig with a Flare Gun and standard CommunicationEquipment.

1. OBJECTIVE2. BACKGROUND3. FLARE GUN4. COMMUNICATION EQUIPMENT

1.0 OBJECTIVE

The purpose of this policy is to ensure that every rig is fully equipped with a Flare Gun andCommunication Equipment in case of an uncontrolled surface well flow (blowout) or otheremergency.

2.0 BACKGROUND

2.1 During Drilling and Workover operations, with a rig on the well, an uncontrolled surface flow(blowout) may occur, requiring immediate ignition of the well effluent to protect human life andcompany assets. In such a case, a Flare Gun is fired to ignite the effluent before spreading.

2.2 During the blowout emergency, it becomes imperative to have reliable means of communicationat the rig site and with headquarters, especially when all power is turned off at the well site toavoid uncontrolled ignition. The use of mobile car radios and portable communication devices(such as Walkie-Talkies) become essential in effective transmittal of instructions and expedientcontrol of the well.

3.0 FLARE GUN

Drilling & Workover will have a Flare Gun on each rig site, as well as a box of at least 24 cartridgeswith long shelf life. The Flare Gun and cartridges will be locked up in a clearly marked wooden box inthe Foreman's office, and the location of the key will be known only to the Foreman and the rigContract Supervisor. The Foreman and Contract Supervisor should be proficient in operation of theFlare Gun.

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4.0 COMMUNICATION EQUIPMENT

4.1 Mobile Radio

Drilling & Workover and Computer & Communications Services Department will worktogether to forecast, acquire and install a single side-band mobile radio in every rig Foreman'svehicle to provide the capability to communicate with the Superintendent in case of anemergency. The radio will only be used when at a safe distance from the well site in case ofunignited hydrocarbon accumulation since the vehicle and radio are both sources of ignition.

4.2 Walkie-Talkie

Drilling & Workover and Computer & Communications Services Department will worktogether to forecast and acquire at least two portable communication devices, such as Walkie-Talkies. The devices are needed on every rig site during an emergency or critical operation. Theportable communication devices will be locked up in a clearly marked wooden box in theForeman’s office, and the location of the key will be known only to the Foreman and the RigContract Supervisor. The Foreman is responsible for the proper operation and charging of thedevices. The Walkie-Talkies must be rated for use in Class I, Div. I electrically classified areas(i.e. explosion proof).

Approved by:

F. A. Al-MoosaGeneral Manager, Drilling and Workover.

N. H. Al-RabehManager, Computer and Communications Services Department.

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ISOLATION BARRIERS FOR WELLS DURING DRILLING& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

1853.001

02/14/1999 NEW

MYR 1 5

X 5

Approved

CONTENT:This document contains instructions for providing adequate isolation barriers (or shut-offs) when removingsurface control equipment while drilling or working over wells. These instructions are also applicable for wellrepair work, performed by the Drilling & Workover organization without a rig on location.

1. OBJECTIVE2. BACKGROUND3. MINIMUM REQUIREMENT4. TYPES OF ISOLATION BARRIERS5. RELIABILITY OF ISOLATION BARRIER6. WAIVER

1.0 OBJECTIVE:

The purpose of this GI is to ensure safe operations during drilling and well repair work by strictcompliance to the guidelines. Short cuts to compromise these guidelines will not be permitted unless awaiver is obtained from the Vice President of Petroleum Engineering & Development or designatedrepresentatives.

2.0 BACKGROUND:

When drilling or working over wells, with or without a rig, situations arise where surface equipmentsuch as Blow Out Preventers (BOPs), wellheads, master valves and trees have to be removed forvarious reasons. In these situations, surface well control is temporarily removed and is substitutedwith downhole isolation barriers so that the reservoir pressure is isolated and work can continuearound the wellhead safely. More than one isolation barrier or shut-off is normally required in certainwells in case of unexpected failure of the primary barrier. Adequate back-up barriers reduce thechances of uncontrolled surface flow (blowout) and costly repair work.

3.0 MINIMUM REQUIREMENT:

The following guidelines will apply at all times unless a waiver has been obtained from Management(as described in paragraph 6.2). The mandatory number of barriers or shut-offs in each case is theminimum; any additional barriers are optional, dictated by the well condition and downholecompletion equipment.

3.1 Oil Wells (GOR less than 850 scf/bbl)

2 shut-offs, one of which is mechanical.

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3.2 Oil Wells (GOR more than 850 scf/bbl)

3 shut-offs, two of which are mechanical.

Note: For tubing and packer completed wells, the 3 shut-off guideline is applicable to thetubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus(tubing hanger and packer seals). If one of the two shut-offs is deemed to beineffective or questionable, then the annulus will have to be filled with overbalancedkill fluid to act as a reliable shut-off.

3.3 Water Injection Wells

- If positive WH pressure, 2 shut-offs are required, one of which is mechanical.

- If no WH pressure, 1 shut-off is required.

Note: It is acceptable to nipple up or nipple down the BOPs on top of the injection tree byonly closing the 10" ball valve. No additional shut-offs are required as long as the treewas never removed or the tree has been pressure tested after nippling up.

3.4 Gas Wells

3 shut-offs, two of which are mechanical.

Note: For tubing and packer completed wells, the 3 shut-off guideline is applicable to thetubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus(tubing hanger and packer seals). If one of the two shut-offs is deemed to beineffective or questionable, then the annulus will have to be filled with overbalancedkill fluid to act as a reliable shut-off.

3.5 Water Supply Wells (with or without submersible pump)

- If well flows to surface, 1 shut-off is required.

- If well does not flow to surface, no shut-off is required.

4.0 TYPES OF ISOLATION BARRIERS:

4.1 A number of acceptable isolation barriers or shut-off alternatives are available and can be usedunder different operating conditions. These barriers can be separated into two main groups:Mechanical and Non-Mechanical.

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4.2 The following are examples of Mechanical and Non-Mechanical isolation barriers. The type ofbarrier to utilize will depend on the well condition and downhole completion equipment. Thesebarriers include, but are not limited to:

Mechanical:- Drillable or Retrievable Bridge Plug- Retrievable Tubing Plug- Back Pressure Valve- Valve Back-Seat- Surface Valve- Subsurface Safety Valve (SSSV)- Unperforated Casing

Non-Mechanical:- Kill Fluid- Cement

5.0 RELIABILITY OF ISOLATION BARRIERS:

5.1 Equipment Testing

5.1.1 Vendor Testing: Prior to delivery of a new mechanical pressure isolation device, thevendor must conduct the required and appropriate hydrostatic pressure tests per SaudiAramco Materials System Specification (SAMSS) to insure that the device meets designspecifications.

5.1.2 Field-Testing: Whenever a mechanical isolation barrier is installed in a well, every effortshould be made to field test and insure the barrier is holding. Since plugs are designedto hold pressure from above, below or from both directions, the field test should bedesigned according to the plug functionality.

5.2 Kill Fluid

5.2.1 A kill fluid can be used as one of the isolation barriers as mentioned in section 4.2 above.In order for the kill fluid to be effective as an isolation barrier, two conditions must bemet:

a) The hydrostatic pressure of the kill fluid column must exceed the reservoirpressure.

b) The wellbore kill fluid must remain static at surface for a period of time ( as peritem 5.2.2 below) to insure the presence of a competent barrier.

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1853.001

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X 5

Approved

5.2.2 The following are the minimum mandatory observation times for a kill fluid to bedeclared static:

Oil Well (GOR less than 850 scf/bbl): 1 hourOil Well (GOR more than 850 scf/bbl): 2 hourGas Well 3 hoursWater Injector 1 hourWater Supply Well 30 minutes

6.0 WAIVER:

6.1 The above instructions will be mandatory when drilling or working over a well (with or withouta rig) by the Drilling & Workover organizations, unless prior management approval has beensecured. A written waiver to divert from the established guidelines must be obtained when anunusual well situation dictates the need for fewer barriers than stipulated. Obtaining a waiver toreduce the number of isolation barriers or shut-offs is highly discouraged and should only beconsidered when there are no other alternatives.

6.2 The waiver will be requested by submitting Waiver Request Form Waiver - 01 (see Appendix I)documenting the well situation, explaining why a waiver is necessary and explaining the impactof the waiver. Waiver signature approval level will be Vice President of Petroleum Engineering& Development or designated representaive.

Recommende by:

F. A. Al-MoosaGeneral Manager, Drilling and Workover

Approved by:

M. Y. RafieVice President, Petroleum Engineering & Development

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WAIVER REQUEST FOR ISOLATION BARRIERDate Requested Waiver Request #

Saudi Aramco Form: Waiver 01(10/98)

Well Name & Number Plant # Facility Connected to

Include number, paragraph, and issue date of this affected GI

Waiver requested Y NAfter-the-Fact

Justification (Include discussion of impact assessment) Impact Assessment

Y N

R Financial Impact

OT

A Safety Impact

NI

GR

OR

EV Discuss under Justification

I Alternatives to waiving requirements

AW

Originating Organization (Originator's Name) (Signature) Date

Phone:Originator's Supervisor (Signature) Date

Phone

REMARKS

LA

VO

RP

PA

Vice President or Designated Representative Signature Date

Name

Appendix I GI 1853.001Page 5 of 5

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WELL ACCOUNT CHARGE NUMBER

13 DIGITS 66-50125-065-299

66 - 50 125 - 0 65 - 299 WELL TYPE FIELD CODE WELL NUMBER TYPE OF WORK (Table 1) W Supply 800-999 (Table 2)

Others 1-799

NOT USED BY DESCRIPTION OF COST DRLG 100-199 S.Aramco Labor Always 0 200-299 Materials 400-699 Support Services 800-998 Rc-Allocation Cost

58 Drilling done for other organization 59 Offshore Workover of a non-producer well 61 Onshore Workover of a producer well 62 Water Supply well for water injection 63 Water Supply well for drilling support 64 Offshore Workover of a producer well 65 Onshore Workover of a non-producer well 66 Devclopmcnt Wells (other than water wells) 75 Exploration Wells (other than water wells)

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WELL ACCOUNT CHARGE NUMBER

Table 1 Development Accounting Location Code

ACCT. CODE

FIELD CODE

FIELD NAME

ACCT CODE

FIELD CODE

FIELD NAME

01 FRHH Farhan 49 JAWB Jawb 02 FRDH Faridah 50 ABQQ Abqaiq 04 SMIN Samin 51 KHRS Khurais 05 LGFH Lughfah 52 SUHL Suhul 06 MGRB Magrhib 53 HWYH Hawiyah~Ghwr 07 HAMR Hamur (Offs) 54 SDGM Shedgum-Ghwr 08 SAHB Sahba 55 FZRN Fazran-Ghwr 09 WIBN Watban 56 ANDR Aindar-Ghwr 10 DHRN Dhahran 57 UIMN Uthmaniyah-Ghwr 11 DMMM Dammam 58 HRDH Hardh-Ghwr 12 QTIF Qatif 59 DILAM Dilam 13 SFNY Safaniya (Offs) 60 ABU-Rakiz Abu-Rakiz 14 ABHD Abu-Hadriya 62 ZULF (Offs) Zuluf t•fli') 15 KRSN Khursaniyah 65 HWTH Hawtah 16 MNIF Manifa (Offs) 66 KIDN Kidan 17 SFNY Safaniyah (Ons) 67 KARN Karan 18 FDHL Fadhili 68 NYYM Nuayyim 19 ABSF Abu Safah (Offs) 69 JAUF Jauf 20 LAYL Layla 70 UYRS Uhayrish 21 HABA El Haba 71 JRBT Juraibi’at 22 ABMK Abu-Markah 72 SHYB Shaybah 23 HSBH Hasbah (Offs) 73 MRJN Marjan (Offs) 24 BRRI Berri (Off) 76 HZMY Hazmiyah 25 BRRI Berri (Ons) 77 RMLH Ramlah 26 MNIF Manifah (Offs) 78 UTMN Uthmaniyah (1000+) 27 LWHH Lawhah(Offs) 79 ZUML Zumul 28 DBDB Dibdibah 81 HLWH Hilwah 30 RSTR Ras Tanura 82 GHNH Ghinah 31 SUBN Suban 83 MDYN Midyan 32 SHRR Sharar 85 HRML Harmaliyah 33 SDWI Sadawi 86 MZIJ Mazalij 34 JDLI Jaladi 87 AB]F Abu Jifan 36 HBRI Habari 88 NSLH Nislah 38 QTIF Qtif (Offs) 90 AMAD Amad 39 HRUR Haruri 91 Q1RD Oirdi 40 HRQS Harqus (Offs) 92 MAQL Ma'aqla 41 UMJF Umm Jurf 93 MHRH Meharah (Offs) 42 WRIH Wari’ah 95 RMTN Rimthan 44 RGHB Raghib 96 TINT Tinat 47 DHYN Duhaynah 97 BAKR Bakr 48 DHIB Dhib 98 KRYN Kurayn (Offs)

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Table 2 Item Number Description

ITEM NUMBER DESCRIPTION 10 Contractor Rig Move I 1 Contractor Camp Move 12 Contractor Rig Operation - Modified Day Rate 13 Contractor Rig Operation - Footage Bonus 14 Contractor Rig Operation – Daywork Rate 15 Contractor Rig Operation - Downtime Rate 16 Contractor Camp – Saudi-Aramco Accommodation 17 Other Contractor Cost (On wells drilled by Contractors) 19 Other Contractor Cost (On wells drilled to Saudi-Aramco) 40 Location Work 41 Roads 42 Aramco Rig Move (Aramco Charges) 43 Special Rig Up/Rig Down 44 Water Supply 46 Equipment Hauling And Handling 47 Transportation 49 Drilling and Coring Bits SO Cement Handling and Pumping 51 Cement and Additives 52 Drilling Fluids S3 Welihead Equipment S4 Well pipe and Downhole Equipment SS Intangible Costs 63 Contractor Invoices Costs 64 Testing 65 Acidizing 66 Logging and Perforating 67 Nitrogen and associated pumping charges 68 Coil Tubing and antler associated charges 73 Technical Services 74 Rig Operations and Drilling Overhead 78 Demobilization 79 Mobilization 84 Camp Operations - Drilling 89 Drilling Equipment Depreciation 90 Development Seismic Activity

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SAFETY REQUIREMENTS FOR DRILLING & WORKOVER RIGS

Revised, updated, and re-issued by the Drilling and Workover Operations Departments, Saudi Aramco

REVISED APRIL 1999

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SAFETY REQUIREMENTS FOR DRILLING & WORKOVER RIGS

Revised, updated, and re-issued by the Drilling and Workover Operations Departments, Saudi Aramco

REVISED APRIL 1999

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SAFETY REQUIREMENTS FOR DRILLING & WORKOVER RIGS

© COPYRIGHT 1996, 1999

SAUDI ARABIAN OIL COMPANY (SAUDI ARAMCO)

All rights reserved. No part of this book may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the Saudi Arabian Oil Company (Saudi Aramco).

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TABLE OF CONTENTS

Page #

DRILLING & WORKOVER MANAGEMENT

LOSS PREVENTION POLICY STATEMENT …………………………….. 08

SECTION A-INTRODUCTION

A-1 Objectives of this Safety Manual ………………………………………

A-2 Definitions ………………………………………………………………..

A-3 Reference Material ………………………………………………………

A-4 Glossary of Abbreviations ………………………………………………

A-5 Rig Operator’s Responsibilities for Loss Prevention ………….………

A-6 Inspection and Preventive Maintenance ………………………………. 15

SECTION B-GENERAL

B-1 Medical ……………………………………………………………………

B-2 Communications …………………………………………………………

B-3 Personal Protective Equipment …………………………………………

B-4 Clothing …………………………………………………………………..

B-5 Respiratory Protection …………………………………………………..

B-6 Hydrogen Sulfide Safety ……………………………………………….. 24

B-7 Housekeeping …………………………………………………………….

B-8 Rig Camps: Kitchens and Accommodations …………………………. 35

B-9 Fire Extinguishing Equipment …………………………………………. 35

B-10 Truck Loading and Unloading …………………………………………. 38

B-11 Fuel Tanks ……………………………………………………………….

B-12 Bulk Storage Tanks ..…………………………………………………….

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B-13 Control of Static Electricity ……………………………………………. 39

B-14 Handling and Storage of Compressed Gas Cylinders ………………… 39

B-15 Electric Wiring and Equipment ……………………………………….. 39

B-16 Illumination .. …………………………………………………………… 41

B-17 Tools -- Hand and Power …………………………………………..……

B-18 Abrasive Wheel Machinery ……………………………………………..

B-19 Welding and Cutting …………………………………………………….

B-20 Air Compressors …………………………………………………………

B-21 Hot Work …………………………………………………………………

B-22 Lockouts and Tagging …………………………………………………...

B-23 Confined Spaces …………………………………………………….……

B-24 Use of Potentially Hazardous Chemicals ……………………………… 49

SECTION C-RIG EQUIPMENT AND PROCEDURES

C-1 Spudding In ………………………………………………………….…...

C-2 Derricks and Masts ……………………………………………………...

C-3 Anchoring – Alterations …………………………………………………

C-4 Crown Blocks ……………………………………………………………

C-5 Traveling Blocks . ……………………………………………………….

C-6 Auxiliary Escape …………………………………………………………

C-7 Guards ……………………………………………………………………

C-8 Derrick Exits, Ladders, Stairways, Floors,

and Platforms ……………………………………………………………

C-9 Pipe Racks ……………………………………………………………….

C-10 Pipe Handling ……………………………………………………………

C-11 Drawworks Controls . …………………………………………………...

C-12 Brake ……………………………………………………………………..

C-13 Rotary Table ….………………………………………………………….

C-14 Cathead Lines and Spinning Chains ………………………………….. 57

C-15 Spinning, Hoisting and Rotary Operations …………………………… 58

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C-16 Slips ……………………………………………………………………… 58

C-17 Hoisting Lines …………………………………………………………… 59

C-18 Riding Hoisting Equipment ……………………………………………. 60

C-19 Elevators …………………………………………………………………

C-20 Manual Tongs ……………………………………………………………

C-21 Tong Counterweights ……………………………………………………

C-22 Making Up and Breaking Joints ………………………………………..

C-23 Mud Bucket or Saver ……………………………………………………

C-24 Power Tongs ……………………………………………………………..

C-25 Racking Pipe in Derricks ………………………………………………..

C-26 Finger Boards . …………………………………………………………..

C-27 Stabbing Platforms and Boards ………………………………………... 64

C-28 Safety Belts and Harnesses ……………………………………………...

C-29 Blowout Preventors ………………………………………………………

C-30 Safety Valves …………………………………………………………….

C-31 Weight Indicators ………………………………………………………. 67

C-32 Test Plugs …………………………………………………………………

C-33 Rig Tanks or Pit Enclosures …………………………………………… 67

C-34 Pressure Relief Devices, Rig Mud Pumps, Piping, and Hoses ………………………………………………………..

C-35 Cellars ……………………………………………………………………

SECTION D-SPECIAL OPERATIONS

D-1 Crane Operations ………………………………………………………..

D-2 Rigging, Material Handling and Slings ………………………………..

D-3 Drill Stem Testing ………………………………………………………. 73

D-4 Swabbing …………………………………………………………………

D-5 Cementing ………………………………………………………………..

D-6 Well Servicing and Well Stimulation …………………………………..

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D-7 Stripping and Snubbing ……………………………………………….. 75

D-8 Flare Pits and Flare Lines ……………………………………..……… 75

SECTION E-OFFSHORE

E-1 Overwater Operations ………………………………………………… 76 E-2 Life Saving Equipment -- Offshore Rigs …………………………….. 77 E-3 Heliports and Helicopter Operations ………………………………… 80 E-4 Personnel Transfer: Boat and Rig ………………………………….… 82

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SAUDI ARABIAN OIL COMPANY (SAUDI ARAMCO)

DRILLING AND WORKOVER OPERATIONS DEPARTMENT

LOSS PREVENTION POLICY STATEMENT

The Drilling and Workover Organization is committed to the protection of Saudi Aramco resources against human distress and financial loss resulting from accidental occurrences. Reduced drilling/workover efficiency and property losses resulting from accidental occurrences can be controlled through good management. Loss prevention is one aspect of this process and is the direct responsibility of line management. To fulfill this commitment, we will provide and maintain a safe and healthy work environment as well as protect the public against foreseeable hazards resulting from our operations. All Saudi Aramco drilling and workover activities and functions, including onshore and offshore activities, will comply with Saudi Arab Government and Saudi Aramco loss prevention requirements as applied to the design, operation and maintenance of our facilities and equipment. If the application of any of these requirements is not practical a waiver will be sought. Reviews for compliance with this policy will be performed on a selective basis at regular intervals. Dedication and cooperation of all Saudi Aramco and Contractor personnel associated with drilling and workover is required and expected to fulfill this Loss Prevention commintment. N.A. AL-AJMI, Manager (A) J.D. LAYTON, Manager (A) Development Drilling and Offshore W/O Department Deep Drilling and Onshore W/O Dep. ___________________________________________ _________________________________

Z.A. AL-HUSSAIN, General Manager (AA)

Drilling & Workover

_______________________________________

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SECTION A: INTRODUCTION A-1 OBJECTIVES OF THIS SAFETY MANUAL

The objectives of this manual are to: 1. Establish Saudi Aramco safety rules directly applicable to drilling and workover

activities, and 2. Establish a uniform and comprehensive set of safety requirements that are equally

applicable to Contractor and Company-owned drilling and workover rigs.

A-2 DEFINITIONS

RIG OPERATOR: In this document, the term "RIG OPERATOR" means the agency or company responsible for operating any drilling or workover rig, and/or providing any drilling or workover rig services on behalf of the Saudi Arabian Oil Company (Saudi Aramco). COMPANY: The term, "COMPANY", as used throughout this document, shall be understood to mean the Saudi Arabian Oil Company (Saudi Aramco). It shall include the management of the Drilling and Workover Operations Departments of Article but can also include all other of management of Saudi Aramco. LOSS PREVENTION: The definition of the term, "LOSS PREVENTION," as used in these “Safety Requirements” is stated in the Saudi Aramco Corporate Loss Prevention Manual”: “Loss in productivity and property resulting from accidental occurrences that can be controlled through good management. Loss prevention is one aspect of this process and is the direct responsibility of line management.” The Dhahran Area Loss Prevention Division, Exploration, Development & Manufacturing Unit (ED&MU) has the responsibility for Loss prevention Department (LPD) technical assistance to the COMPANY, Drilling and Workover, Exploration and Petroleum Engineering organizations throughout the Kingdom of Saudi Arabia.

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A-3 REFERENCE MATERIAL In addition to this publication, the RIG OPERATOR shall have available for reference to drilling or workover personnel the most recent publications as follows:- IADC Drilling Manual IADC Accident Prevention API SPEC 4A Steel Derricks API SPEC 4E Drilling and Well Servicing Structures API BULL 5C2 Performance Properties of Casing, Tubing, and Drill Pipe API BULL 5C4 Round Thread Casing Joint Strength With Combined Internal Pressure

and Bending API SPEC 6A Wellhead Equipment API SPEC 7 Rotary Drilling Equipment

API SPEC 7 B-11C Internal Combustion Reciprocating Engines For Oil Field Service

API RP 7G Drill Stem Design And Operating Limits

API RP 7H Drilling Machinery

API SPEC 8 Drilling and Production Hoisting Equipment

API RP 8B Hoisting Tool Inspection and Maintenance Procedures

API SPEC 9A Wire Rope

API RP 9B Application, Care and Use of Wire Rope For Oil Fields

API SPEC 13A Oil Well Drilling Fluid Materials

API BULL 13C Drilling Fluid Processing Equipment

API RP 49 Recommended Practice for Safe Drilling of Wells Containing

Hydrogen Sulfide

API RP 52 Recommended Land Drilling Operating Practices for Protection of the Environment

API RP 54 Recommended Practices for Occupational Safety and Health for Oil and Gas Drilling and Servicing Operation

API RP 500 Recommended Practice for Classification of Location for Electrical

Installation at Petroleum Facilities.

API RP 2020 Safe Practices in Drilling Operations

ANSI Z88.2 American National Standard Practices for Respiratory Protection

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ANSI Z89.1 Protective Headware for Industrial Workers - Requirements

ANSI Z41.83 Protective Footwear G.I. 2.100 Work Permit System

G.I. 2.104 Leak and Spill Reporting - Arabian Gulf G.I. 2.400 Offshore Oil Spill Contingency Plan G.I. 2.401 Inland Oil Spill Contingency Plan G.I. 6.012 Isolation, Lockout and Use of Hold Tags

G.I. 6.020 Personal Flotation Devices for Work Over, On or Near Water

G.I. 6.025 Control of Remote Area Travel and Search/Rescue Procedures

G.I. 8.003 Air Supplied Breathing Apparatus

G.I. 7.025 Mobile Heavy Equipment Operator Testing and Certification

G.I. 7.026 Cranes and Heavy Equipment Accident Reporting Procedures

G.I. 7.027 Personnel Work Platform Operations

G.I. 7.028 Heavy Crane Lift, Multiple/Tandem Crane Lift, etc.

G.I. 7.029 Inspection, Testing and Maintenance of Wire Rope Slings

G.I. 7.030 Inspection & Testing Requirements of Elevating/Lifting Equipment

G.I. 151.006 Implementing the Saudi Aramco Sanitary Code G.I. 355.020 Control of Compressed Gas Cylinders. G.I. 520.001 Confined Space Entry Procedures

G.I. 1780.001 Atmosphere-Supplying Respirators G.I. 1781.001 Inspection and Maintenance of Fire Protection Equipment

G.I. 1850.001 Onshore Contingency Plan G.I. 1851.001 Offshore Contingency Plan G.I. 1852.001 Rig site Flare Gun and Communication Equipment G.I. 1853.001 Isolation Barriers for Wells During Drilling & Workover Operations

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Rig & Equipment Operations and Maintenance Manuals for the Drilling Rig Manufacturers and Other Major Equipment Items Saudi Aramco Crane Safety Handbook Saudi Aramco Construction Safety Manual Saudi Aramco Safe Drilling and Workover Operations in Known or Suspected

Hydrogen Sulfide Areas Schedule ‘D” Contractor’s Safety & Loss Prevention Requirements SAES-A-103 Discharges to the Marine Environment SAES-A-105 Noise Control SAES-B-019 Portable, Mobile and Special Fixed Firefighting Equipment SAES-B-062 Onshore Wellsite Safety SAES-B-063 Aviation Obstruction Marketing and Lighting SAES-B-067 Safety Identification and Color Coding SAES-B-068 Electrtical Area Classification SAES-B-069 Emergency Eyewashes and Showers SAES-J-505 Combustile Gas and Hydrogen Sulfide in Air Detection Systems SAES-L-070 Technically Acceptable Manufacturers of API 6A 10000 PSI Gate Valves and Chokes NOTE: ASSISTANCE IN OBTAINING COPIES OF THESE DOCUMENTS IS PROVIDED BY THE DHAHRAN AREA LOSS PREVENTION DIVISION - Westpark 3, Room 244A, Telephone 874-8419, Dhahran.

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A-4 GLOSSARY OF ABBREVIATIONS

SAES Saudi Aramco Engineering Standards

ANSI American National Standards Institute

API American Petroleum Institute

BOP Blowout Preventer

G.I. (Saudi Aramco) General Instruction

IADC International Association of Drilling Contractors

MODU Mobile Offshore Drilling Unit

NEC (American) National Electrical Code

NFPA (American) National Fire Protection Association

SCECO Saudi Consolidated Electric Company

SCR Silicon Controlled Rectifier

SWL Safe Working Load (Limit)

UKDOT United Kingdom Department of Trade

USCG United States Coast Guard A-5 RIG OPERATORS' RESPONSIBILITIES FOR LOSS PREVENTION Throughout all phases of any drilling or workover operation the RIG OPERATOR will be held accountable for the prevention of accidental losses, the protection of COMPANY interests and resources, and the avoidance of any contamination of the environment. The following minimum guidelines are provided to aid the RIG OPERATOR in meeting this responsibility. Assistance in complying with the requirements set forth in these guidelines is available from Drilling and Workover Management or from the Loss Prevention Department of the COMPANY. 1. The RIG OPERATOR shall establish a written loss prevention program that fulfills all the

requirements stated in this Manual. 2. Any loss prevention program of the RIG OPERATOR shall provide for frequent and

regular inspections of the rig equipment, materials, and accommodations by competent persons designated by the RIG OPERATOR. This inspection shall be completed on a monthly basis and submitted to the COMPANY Drilling Superintendent with responsibility for the oversight of each rig.

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3. The RIG OPERATOR shall provide at each drilling and workover rig a copy of the reference materials (listed earlier on page 10) necessary for the safe operation of the rig.

4. The RIG OPERATOR shall be thoroughly familiar with the drilling or workover program.

He shall inform the rig crew of any potential adverse conditions (i.e., lost circulation zones, high reservoir pressure, high H2S concentrations, etc.) that require special safety precautions, training, equipment, or additional personnel.

5. The RIG OPERATOR shall clearly indicate the "SMOKING PERMITTED" areas

around each rig location. All other areas on the location will be considered as "NO SMOKING" areas and shall be marked accordingly. Smoking shall be closely controlled throughout the rig location.

6. The RIG OPERATOR shall take all reasonable safety precautions to prevent oil spills or

pollution both onshore and offshore. If an accidental spill or discharge does occur, every effort shall be made to (a) protect human life, including both employees and the public, and (b) minimize the impact on the environment. Should an accidental spill occur, it shall be reported immediately to the COMPANY representative so that he can take the necessary steps to contain the spill and implement the applicable reporting requirements of G.I. 2.104, G.I. 2.400, or G.I. 2.401.

7. The RIG OPERATOR shall adequately train each of his employees in the recognition and

avoidance of unsafe conditions and in all COMPANY loss prevention standards applicable to his work environment. He shall also adequately train his employees in methods to control or eliminate any hazards or other exposures resulting in injury or illness.

8. The RIG OPERATOR's employees, who are required to handle or use poisons, caustics,

acids and other harmful substances, shall be adequately trained regarding their safe handling and use. The RIG OPERATOR's supervisors shall discuss the potential hazards, personal hygiene, and necessary personal protective equipment prior to their employees handling any harmful materials. The RIG OPERATOR will maintain water stations for washing chemicals spills and Material Safety Data Sheets for all potentially hazardous chemicals the RIG OPERATOR orders onto the rig. Note: Saudi Aramco will supply MSDS for materials Saudi Aramco orders.

9. The RIG OPERATOR shall allow only those personnel qualified by training and/or

experience to operate equipment and machinery. The RIG OPERATOR shall also ensure that any personnel requiring operator's certificates have them, or copies thereof, in their possession and have completed any training which may be required by the laws of the Kingdom of Saudi Arabia or by the COMPANY.

10. RIG OPERATORS providing offshore rigs shall ensure that their rigs are kept in

compliance with all applicable maritime/MODU standards of the country in which the rig is registered as well as any applicable laws and regulations of the Kingdom of Saudi Arabia or the COMPANY.

11. A RIG OPERATOR providing offshore rigs shall ensure that all required certifications are

current and that re-certification inspections are completed by an approved certification authority prior to the expiration of the existing certificate.

12. On all offshore rigs, a copy of the Barge Marine Operations Manual shall be kept readily

available in the control room for consultation and use. The manual shall include a

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complete set of operating instructions, control systems diagrams, and stability characteristics.

13. Any special or unusual towing characteristics of an offshore rig shall be included in the

operating instructions and communicated to the towing vessel operators before towing operations begin.

14. A RIG OPERATOR providing offshore rigs shall ensure that all navigation and transit

lights are operable and used as required by International Rules and Regulations for Aids to Navigation.

15. Should a conflict arise between a RIG OPERATOR's safety requirement and a

COMPANY requirement, the most restrictive requirement shall apply. A-6 INSPECTION AND PREVENTIVE MAINTENANCE The RIG OPERATOR is responsible for providing drilling or workover rig(s), including all auxiliary equipment, that is structurally and mechanically capable of performing according to the agreement between the RIG OPERATOR and the COMPANY. In order to assure the COMPANY that all equipment is in good working condition, the RIG OPERATOR shall conduct a physical inspection of its rig and all auxiliary equipment on a regular basis – no less than once per month. The RIG OPERATOR will implement a comprehensive preventive maintenance program to keep equipment in good working condition.

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SECTION B: GENERAL B-1 MEDICAL 1. Each RIG OPERATOR shall comply with the Saudi Arabian Ministry of Labor and

Social Affairs Decision Number 404, dated 7 July 1974, entitled "First Aid Facilities at Work Sites". A copy of this document or an English language translation is available from the Drilling and Workover Operations Manager or from Dhahran Area Loss Prevention Exploration, Development & Manufacturing (ED&M) Unit.

2. The RIG OPERATOR, with the assistance of the COMPANY as required, prior to

the start of drilling or workover operations, shall identify the nearest trauma clinic or physician or hospital and shall make provisions for the PROMPT transportation of a victim of injury or sudden illness to the physician, hospital or clinic or to summon emergency medical personnel to the location. Also, prior to the start of operations, the COMPANY shall provide an effective communication system for contacting necessary medical and emergency agencies with written posted procedures for medical evacuation [Medivac].

3. The RIG OPERATOR, with the assistance of the COMPANY as required, shall furnish

to any person injured in his employment who is in need of medical attention immediate transportation to a hospital, physician, or clinic for the purpose of treatment.

4. Telephone numbers of the physician, hospital, ambulance, and helicopter services shall

be conspicuously posted in the COMPANY Representative’s office, Rig Manager's office, the rig medic station, and the radio room. These numbers shall be posted as soon as possible after moving to a new location.

5. The vehicle or conveyance used for transport of the injured shall:

(a) Be of sufficient size and suitabe to accommodate a stretcher and accompanying

person entirely within the body of the vehicle or conveyance. (b) Be clean and well maintained.

(c) Protect the injured worker and the accompanying person. (d) Be designed and equipped such that verbal communication between the

operator of the vehicle or conveyance and the injured worker or accompanying person is possible.

6. When immediate transport of the injured is necessary and circumstances do not allow

compliance with Item #5 (above), the senior supervisor at the site shall use any available means of suitable transportation.

7. A reliable means of communication shall be provided by the company from the rig site

to base of operations and other outside locations. 8. The RIG OPERATOR shall provide at each rig, qualified medic on the rig, adequate

first aid equipment and emergency treatment facilities.

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9. Each rig shall be equipped with two stretchers (Stokes, Navy, Scoop) with blankets and securing straps that are capable of being carried on the helicopter or transportation serving the rig.

10. While being transported, all victims shall be accompanied by the rig medic in addition to

the driver or pilot. If a rig medic is not available, the accompanying person shall have valid up-to-date first aid certification.

11. The RIG OPERATOR shall complete Saudi Arabian Government Form 11 for each of

his injured employees requiring medical treatment and submit the completed form(s) within three days to the nearest Social Insurance Office. The RIG OPERATOR shall also comply with any other reports or investigations required by the laws of the Kingdom of Saudi Arabia. He shall advise the responsible Aramco Government Affairs Office of all pertinent information on a timely basis.

12. All RIG OPERATOR employee injuries shall be reported promptly to the COMPANY

Representative. A RIG OPERATOR accident/injury form will be completed at the rig site, reviewed by the COMPANY Representative and sent to the appropriate COMPANY Superintendent within 24 hours.

13. Conduct Disaster Drills as specified in the procedures published by the company. B-2 COMMUNICATIONS 1. Reliable communications, radio and/or telephone, shall be maintained at all times

between the rig and operations base. Offshore rigs must also be able to communicate with other rigs, helicopters, and vessels in the vicinity.

2. On all offshore rigs, on-site communication shall be done using an intercom type system

and necessary in an emergency must be provided by the RIG OPERATOR. 3. Every rig shall be equipped with a general alarm system capable of providing an alarm

audible throughout the entire installation. In areas of high noise levels, visual warning signals such as flashing lights shall be provided in addition to the audible alarms. The RIG OPERATOR shall ensure that visual warning signals are not screened or hidden by equipment, machinery, or structure.

4. Each rig shall be equipped with a public address system capable of clearly transmitting

emergency instructions. 5. Both the general alarm system and the public address system shall be operable from the

main control room and from other control positions on the installation. 6. The general alarm and public address system shall be supplied with power from both

the normal and emergency power supply. B-3 PERSONAL PROTECTIVE EQUIPMENT Personal protective equipment can never prevent an accident. It does, however, serve to minimize the effects of an accident if an accident does occur. The RIG OPERATOR is responsible to require the wearing of approved personal protective equipment at all times where

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its use could protect personnel. 1. The RIG OPERATOR shall post warning signs in areas where the use of personal

protective equipment is required. 2. Protective headgear and gloves shall be worn by all personnel working at a drilling or

workover well site. 3. Protective headgear shall meet or exceed the requirements of ANSI Z89.1. Metal hard

hats are forbidden per Saudi Aramco Construction Safety Manual. 4. Properly fitting goggles, face-shields, or other eye protection equipment appropriate to

the work being done, shall be worn by all personnel who are handling or exposed to any material capable of causing injury or irritation to the eyes, or engaged in any work in which there is an eye hazard from flying objects, injurious light, heat rays, or radiation.

5. Safety steel-toe boots or shoes shall be worn by all personnel when working on or

about a drilling or workover rig as per ANSI Z41.83. 6. The RIG OPERATOR shall provide, and all personnel will wear, suitable protective

clothing and equipment including appropriate respiratory protection, when handling acids, caustics, or other harmful substances which are potentially injurious to the skin. Any rig employee handling dry mud material must wear adequate personal protective clothing, including proper eye and face protection. This requirement includes those personnel handling "super-sacks".

7. The RIG OPERATOR shall ensure that, when the clothing or skin of any personnel

becomes contaminated with any flammable or harmful substance, those exposed shall get in the shower and then remove their clothing and wash the affected part of the body. The clothing shall be decontaminated before re-use.

8. The RIG OPERATOR shall provide hearing protection in areas where the noise levels

are above 90 DBA. RIG OPERATOR shall post warning signs informing all personnel that hearing protection is required while working in that area.

9. Hearing protection equipment, including head phone type hearing protection or soft ear

plugs, shall be readily available to personnel working in high noise level areas. 10. All personal protective equipment shall be kept in a sanitary condition and maintained to

perform satisfactorily the function for which it was designed. 11. The RIG OPERATOR shall provide emergency eye wash stations where necessary to

provide immediate relief to any personnel who may be contaminated with a harmful substance. These eye wash stations shall be capable of providing a minimum of 15 minutes of fresh, clean water to irrigate eyes that have been contaminated by some hazardous material. The RIG OPERATOR shall maintain these eye wash stations in good condition continually ready for use per SAES-B-69, “Eye Wash Station and Showers”.

12. The RIG OPERATOR shall post identification signs to mark the location of all

emergency equipment such as emergency eye wash stations.

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WORK SMART Your Personal Protective Equipment (PPE) is your final protection against accidents and injuries. Your special skills and safety attitude is your primary protection against accidents and injuries.

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B-4 CLOTHING 1. The RIG OPERATOR shall ensure that all his personnel wear clothing suitable for the

existing conditions and the work being performed. The RIG OPERATOR shall specifically prohibit his personnel from working without shirts or in short trousers.

2. RIG OPERATOR personnel shall not unnecessarily expose any part of the body to

substances which may be injurious to the skin. 3. Where there is danger of contact with moving parts of machinery or in any work

process where a similar hazard exists:

(a) Close fitted clothing shall be worn,

(b) Head and facial hair shall be completely confined or cut short, and

(c) Dangling neckwear, jewelry, or other similar items shall not be worn.

B-5 RESPIRATORY PROTECTION 1. The RIG OPERATOR shall ensure that all respiratory protection equipment, needed by

or reasonably anticipated to be needed by his employees, is provided. Those employees required to use this equipment must be trained in its effective use. This training MUST include practice in the maintenance and use of this equipment. This equipment may be provided by the Contractor or by the COMPANY, depending upon the terms and conditions of the contract.

2. The RIG OPERATOR shall ensure that the required respiratory protection equipment is

maintained and used as intended, and that it provides all personnel with adequate protection against all anticipated hazardous atmospheres.

3. Such respiratory protection equipment shall be readily available, maintained in good

working order, in a sanitary condition, and inspected every 30 days per GI-1780.001. 4. Unless protected by respiratory protection equipment, no personnel shall be allowed to

enter any area: (a) Where the oxygen content of the atmosphere is less than 20 per cent by volume,

or

(b) Where the atmosphere is contaminated or in danger of being contaminated by any airborne substance that may be considered to be harmful.

5. All respiratory protection equipment shall be supplied air apparatus in the form of:

(a) Self-Contained Breathing Apparatus (SCBA), or

(b) Hose-line work masks, including an emergency escape cylinder.

6. On all drilling and workover rigs operating in known hydrogen sulfide areas or on any

rig drilling a wildcat well, there shall be on each rig at least the minimum amount of respiratory protection equipment required in the drilling/workover contract.

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7. Where respiratory protection equipment is or may be required to be worn in areas which are or may be contaminated with substances immediately dangerous to life or health, RIG OPERATOR shall ensure that excessive facial hair which prevents effective sealing of the face shall be removed.

8. Refer to Section B-5, Appendix I for further information regarding Respiratory

Protective Equipment.

Section B-5 Appendix I:

REQUIREMENTS FOR MINIMAL ACCEPTABLE RESPIRATORY PROTECTION PROGRAM

EACH RIG OPERATOR SHALL DEVELOPE AND PUT INTO PRACTICE A

RESPIRATORY PROTECTION PROGRAM THAT MEETS OR EXCEEDS THE FOLLOWING CRITERIA AS PER G.I. 1780.001.

1. Written standard operating procedures governing the selection and use of respiratory protective equipment shall be established.

2. Respiratory protective equipment shall be selected on the basis of the hazards to which

the worker is exposed. The airborne hazards most likely to be encountered in drilling and workover operations are: (a) Immediately dangerous to life or health (IDLH) atmospheres that require the use

of supplied-air respiratory protection equipment. This equipment includes the hose-line work masks, including an escape cylinder, and self-contained breathing apparatus (SCBA). The most likely IDLH atmospheres that may be encountered at drilling and workover locations are: (1) Toxic vapors and gases, such as H2S.

(2) Atmospheres containing less than 20 per cent oxygen, by

volume.

(b) Corrosive or irritating particulate matter for which full-face filter mask protection is required. It is very important the proper filters be used.

3. The user shall be instructed and trained in the proper use of respiratory protective

equipment and their limitations. This training must include: (a) Instructions on the selection of the proper respiratory protection equipment for

each potential hazard an employee may encounter.

(b) Instructions in the wearing and use of this equipment. This training MUST include drills in which the equipment is used and worn under simulated emergency conditions. (BOP drills while wearing work masks, for instance.)

(c) Proper cleaning and sanitizing of the equipment after it is worn and used. It is very important each user of this equipment understands how important it is to properly clean and sanitize this equipment after each wearing, even for equipment that may be permanently assigned to him.

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4. Where possible, respiratory protective equipment should be assigned to individual

workers for their exclusive use. 5. Respiratory protective equipment shall be regularly cleaned and disinfected. Those

issued for the exclusive use of one worker should be cleaned after each day's use, or more often if necessary. Those used by more than one worker shall be thoroughly cleaned and disinfected after each use. Cleaning this equipment must be included in the training and use of the equipment. Aside from understanding how to use the equipment for maximum possible protection, cleaning is of paramount importantance.

6. A log shall be maintained that documents the cleaning and maintenance of respiratory

protective equipment. 7. Respiratory protective equipment shall be stored in a convenient, clean and sanitary

location. One practical method for keeping this equipment clean and ready for use is to cover the storage cases with a tear-away plastic trash bags. This equipment must always be ready for immediate emergency use. This is possible only if it is stored properly.

8. Respiratory protective equipment shall be inspected during cleaning. Worn or

deteriorated parts shall be replaced. Respiratory protective equipment for emergency use, such as self-contained devices, shall be thoroughly inspected at least once a month and after each use. Every rig inspection must include a careful inspection of all respiratory protection equipment.

9. Appropriate surveillance of work area conditions and the degree of employee exposure

or stress shall be maintained. The RIG OPERATOR is responsible for knowing what respiratory exposures may be present and must alert all personnel when protective equipment is required. The level of exposure to a given substance is determined by continuous area monitoring, personal monitoring and warning devices, or from studying the Material Safety Data Sheets (MSDS) for each substance used on the location, The RIG OPERATOR is responsible for requiring the use of the proper equipment at all times when exposure limits exceed acceptable limits.

10. There shall be regular inspection and evaluation to determine the continued effectiveness

of the program. The RIG OPERATOR is responsible for his respiratory protection program. In meeting that responsibility a RIG OPERATOR must know that all equipment is in good condition and is ready for use when needed. A part of every LOSS PREVENTION inspection will be to evaluate the state of the entire respiratory protection program of each location visited.

11. Persons should not be assigned to tasks requiring the use of respiratory protective

equipment unless it has been determined that they are physically able to work while wearing the equipment. Any employee who may, in the course of his employment, be required to wear respiratory protection equipment must pass an annual examination by a competent medical staff. This examination must include a pulmonary function test.

12. Compressed air used for breathing purposes shall comply with the standards

recommended in G.I. 1780.001.

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COMPRESSORS

THE COMPRESSOR FOR SUPPLYING BREATHING AIR SHOULD MEET THE REQUIREMENTS OF G.I. 1780.001.

1. Breathing air compressors should be equipped with necessary safety and standby

devices. 2. Breathing air compressors should be situated so as to avoid entry of contaminated air. 3. They should be equipped with purifying sorbent beds and filters to further assure greater

air quality. 4. They must be equipped with alarms to indicate compressor failure and/or overheating. 5. Oil lubricated compressors must have a high-temperature or carbon monoxide alarm or

both. If only a high-temperature alarm is used, the air must be frequently tested for carbon monoxide to insure that the air meets the specifications as described in G.I. 1780.001.

AIR PURITY STANDARDS Limits have been established for breathing air quality. Air suitable for human respiration must meet minimum standards as established by various governing bodies, including the Compressed Gas Association. The following chart provides the maximum allowable contaminant allowed under the C.G.A. standard. COMPONENT C.G.A. STANDARD Oxygen % by volume 19 - 23% Carbon Dioxide, by 0.10% max. volume (1000 ppm) Carbon Monoxide 10 ppm Oil Vapor (< 1 mg/liter @ STP) Water Saturated Odor None Particulates and Solids None The standards cited above are usually referred to as "Grade D", in reference to the Compressed Gas Association Table No.1 These standards apply to compressed air for use in filling open circuit breathing systems.

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HOW MUCH BREATHING AIR? In reality, each man should be trained and drilled to determine his own duration by using the Self-contained Breathing Apparatus (SCBA) under extremely strenuous working conditions. Many factors come into play that may greatly reduce the rated duration; therefore, one should not expect to obtain the exact time rating, without taking into consideration the size of the person, physical condition, breathing habits, adequate mask seal, etc.

DECIMAL SYSTEM (CUBIC FEET)

METRIC SYSTEM (LITERS)

1 Cubic Foot of Air

28.3 Liters

One - 30 Minute Air Cylinder is Equivalent to 45 Cubic Feet

1,273.5 Liters by Volume

300 Cubic Feet of Air

8,490.0 Liters by Volume

1 Cascade of 6-300 Cubic Foot of Air Cylinders is equivalent to 1,800 Cubic Feet

50,940.0 Liters by Volume

An Air Compressor with a 9.2 Cubic Foot Delivery per Minute

260.3 Liters by Volume

It takes an air compressor, delivering 9.2 cubic feet of air per minute, 32 minutes to fill one 300 cubic foot air cylinder, or 3 hours and 12 minutes to fill six 300 cubic foot air cylinders without considering line fill time if compressor is more than 10 feet from cylinders.

ONE MAN

One man using one 300 cu. ft. cylinder at medium heavy work would last approx. 3 hrs. 50 min.

One 300 cu. ft. cylinder contains 8,490 liters of air.

One man using one 300 cu. ft. cylinder at maximum work would last approx. 1 hour.

Six 300 cu. ft. cylinders contain 50,940 liters of air

21 hrs. & 20 minutes 6 hrs. & 30 minutes

SIX MEN One 300 cu. ft. cylinder contains 8,490 liters of air.

Six men using one 300 cu. ft. cylinder at medium heavy work would last approx. 35 minutes.

Six men using one 300 cu. ft. cylinder at maximum work would last approx. 10 minutes.

Six 300 cu. ft. cylinders contain 50,940 liters of air.

3 hrs. & 50 minutes One hour

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B-6 HYDROGEN SULFIDE SAFETY

1. All drilling and workover operations in known or suspect hydrogen sulfide areas shall be

conducted according to API RP 49, "Recommended Practices for Safe Drilling of Wells Containing Hydrogen Sulfide" and with any COMPANY rules. Also, these RIG OPERATORS shall comply with the requirements of the following Appendices to this Section:

(Appendix I) SAUDI ARAMCO H2S CONTINGENCY PLAN (For More Details, see chapter 8, section-C of the Drilling Manual.) (Appendix II) SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL ONSHORE DRILLING AND WORKOVER RIGS (Appendix III) SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL OFFSHORE DRILLING AND WORKOVER RIGS 2. On all drilling and workover operations in known or suspect hydrogen sulfide areas,

there shall also be some method for the passive monitoring of returns, both gaseous and liquid, to anticipate the likely need for wearing protective equipment. In all instances where there is no provision for adequately monitoring the returns to anticipate the likely need for wearing protective equipment, the ambient atmosphere shall be monitored: (a) on the rig floor at the Driller's position and about 3 feet above the floor.

(b) at the top of the bell nipple.

(c) at the flowline opening to the shale shaker.

(d) the cellar or underneath the choke manifold, above the choke manifold skid

floor. 3. Wind indicating devices, such as wind socks, shall be provided and maintained in good

condition. They shall be conspicuously located so they are visible from anywhere on the location.

4. The RIG OPERATOR shall adequately train all his personnel in the basic fundamentals

of hydrogen sulfide safety. This training must include: (a) Characteristics of hydrogen sulfide and its toxicity.

(b) Detection and warning systems peculiar to the location.

(c) Emergency procedures consisting of,

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*** Designation of safe briefing areas.

*** Wearing and use of emergency breathing equipment.

*** Evacuation procedures. *** Rescue procedures. *** First aid for victims.

(d) Instructions in the inspection, maintenance, and use of assigned respiratory

protection equipment.

(e) This training MUST include drills in all these procedures so all personnel on the location can quickly and effectively follow each of these instructions when there is an actual, life-threatening emergency.

5. Refer to Section B-6, Appendices I, II and III for specific details regarding H2S Safety

Equipment and procedures.

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Section B-6 Appendix I:

SAUDI ARAMCO H2S CONTINGENCY PLAN

I. The scope of the Aramco H2S Contingency Plan is to cover operations while drilling,

testing, and completing oil and gas wells that have a potential H2S hazard. A. The Drilling and Workover Operations Departments shall have the responsibility

for executing the plan.

1. The on-site Drilling Foreman shall be responsible for carrying out the plan.

2. Drilling Engineering will develop and coordinate the procedures. 3. Loss Prevention can be consulted for training and H2S surveillance.

B. Other Organizations will be appraised of the operations.

1. Camp Management will be notified prior to starting operations. 2. Government Relations will be given a map covering the surrounding area

that might be affected in the event of an emergency.

a. Government Relations may notify any possibly interested SAG Authorities.

b. Drilling Engineering will coordinate this notification. 3. The Medical Department will be notified by the Drilling Operations

Department. 4. The Fire Department will be notified by the Drilling Operations

Department. 5. All installations within the area of Operations shall be noted and the

Management of possibly affected installations notified. 6. A detailed evacuation plan will be developed for any residential area that

might be remotely endangered if an emergency condition develops.

C. Flaring of sour gas wells at night must be done with extreme caution because:

1. Wind normally diminishes at sundown. 2. With little or no wind, it is impossible to disperse any escaped H2S or

SO2 from flares.

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II. The BOP equipment, the wellhead equipment, the test equipment and the safety

equipment shall all conform to presently developed standards. A. The Class A 10,000 psi and 5,000 BOP equipment shall meet NACE Standard

MR-01-75 (1980 Revision) for sour service.

B. The tree, wellhead and all fittings exposed to H2S shall meet NACE Standard MR-01-75 (1980 Revision) for sour service.

C. The wellhead, chokes, manifolds and flowlines shall meet the standards for sour

service.

D. The heater, test unit and all connections shall meet sour service standards.

E. All flare lines and emergency blowdown lines will be staked or otherwise secured against movement in the event of a mechanical failure.

F. The heater, if required, will be a minimum of 150 feet from the wellhead and the test separator.

G. Wellhead gas will not be used for controller gas, bottled nitrogen is preferred over supply air for controls.

H. During gas well production tests, two flare pits will be constructed down wind

from the location in the direction of prevailing wind and at least 180º apart and 600 feet from the wellhead manifolds or any test equipment. Minimum flare line size shall be two 3-1/2" J-55 lines to each pit.

I. Explosion-proof bug blowers shall be positioned to move air around well and equipment.

III. Emergency Safety and First Aid Equipment shall be on location and conveniently

located. A. Self-contained breathing apparatus will be located for emergency work and

escape.

B. Cascade systems for work and recharge will be set up on location.

C. Resuscitators, safety harnesses, safety ropes, first aid kits, splints and litters will be on location.

D. An H2S monitor with alarm systems and sensors at various locations will be installed.

E. Personal electronic H2S monitors, explosimeters, spot checks, hand pump type H2S - SO2 detectors will be used.

F. Wind socks, warning signs and flags as well as streamers in localized areas will be in use.

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Section B-6 Appendix II:

SAUDI ARAMCO STANDARD SAFETY EQUIPMENT

FOR H2S OPERATIONS ON

ALL ONSHORE DRILLING AND WORKOVER RIGS I. H2S and Combustible Gas Monitors . (See also SAES-J-505 Combustible Gas

and Hydrogen Sulfide in Air Detection Systems).

A. H2S Monitor and Alarm System

A four channel H2S monitoring system with two visual-audio alarm system shall be installed and fully operational on all land drilling rigs operating on known or suspect H2S locations. Each sensor and alarm system shall have a portable reel with 200 feet of neoprene covered electrical cable with cannon connectors at each end for hookup of cable to monitor, cable to sensor and cable to alarm (a total of six cables on reels). 1. The sensors shall be located as near as practical to:

a. The top of the bell nipple. b. The flowline opening to the shale shaker. c. The Driller's position and about three feet above the floor. d. The cellar or underneath the choke manifold above the choke

manifold skid floor. This sensor should be easily moveable so that it can be used around the BOP stack or at the well testing equipment when necessary.

2. The alarm system (amber strobe lights and horn) shall be set for first

alarm at 10 ppm and high alarm at 20 ppm H2S. The alarm system shall be located in clearly visible locations so that personnel in any work area can see and/or hear at least one set.

3. The monitor shall be located in the doghouse. 4. There shall be minimum of one spare sensor.

B. Combustible Gas Monitor and Alarm System

A continuous combustible gas monitor and single sensor with a portable reel holding 200 feet of neoprene covered electrical cable with two pairs of cannon connectors (monitor to cable and cable to sensor) shall be provided. An alarm system with similar reel, cable and connectors is required 1. The sensor shall be located at either:

a. The top of the bell nipple, or

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b. The flowline opening to the shale shaker when a rotating head is in use.

2. The alarm system (red strobe light and horn) shall be set at 20% of the

Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. The alarm system shall be clearly visible from work areas on location. The alarm system (light and horn) shall be located on the rig floor above the doghouse. Note: This setting criteria applies to cold work situations only.

3. The monitor shall be located in the doghouse. 4. There shall be a minimum of one spare sensor.

C. Two personal portable H2S monitors, alarm to be set at 10 ppm.

D. Two portable H2S detectors (hand pump suction type) with high level and low

level H2S and SO2 tubes.

E. Two portable combustible gas or vapor monitors.

F. Drager Test Kit for checking mud return for H2S. II. Required Breathing Apparatus

A. Hose-line work units, with emergency escape cylinders, shall be provided as

follows: 1. Rig floor - six 2. On handrail near shale shaker - two 3. On rack near mud mixing area - two 4. Near choke manifold - one

5. In derrick for Derrickman (at monkey board) - one

B. Self contained breathing apparatus (SCBA's) shall be provided as follows:

1. Toolpusher's office/quarters - two

2. Company Foreman's office/quarters - two

3. Logging Unit (when used) - two

4. SCR room - one

5. Rig Floor - three

C. At least one fully-charged spare cylinder shall be provided for each unit of all

type listed.

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III. Emergency First Aid Safety Equipment

A. Two "Bug Blowers" explosion proof, high volume (40,000 cfm) and moveable.

B. Three wind socks, two in service, plus streamers to be located so all personnel will know wind direction. One wind sock is to be held as a spare.

C. Flare line ignition system (Alex-500 or equivalent) with backup flare gun and supply of 24 long self life cartridge.

D. Two portable oxygen resuscitator units, each with a spare oxygen cylinder.

E. Two 25 man First Aid Kits, one at rig site and one at camp site.

F. Four eye wash stations located in the following areas:

1. On the rig floor or in the rig floor doghouse. 2. In the mud mixing area. 3. In the rig medic's office or the rig supervisor's office. 4. In the rig camp mess hall.

G. Two safety harnesses with two 250 foot retrieval ropes. H. Two basket-type stretchers (Stokes or Navy type litter) with blankets and

securing straps.

I. Two Quick-Air splint kits. J. One portable bull horn with extra battery pack.

K. Six small chalk boards with clamps for mounting with an adequate supply of

chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards].

L. Flashlights - explosion proof with an extra set of batteries and extra bulb for

each (number to be at least one for each two persons in the operation but not less than five).

NOTE: All safety equipment with rubber, plastic or other parts likely to

deteriorate shall be stored in a dark air conditioned room near the supervisor's office. Adequate supplies of sanitizing materials shall be available for sanitizing face masks and other body contact equipment.

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Section B-6 Appendix III:

SAUDI ARAMCO STANDARD SAFETY EQUIPMENT

FOR H2S OPERATIONS ON

ALL OFFSHORE DRILLING AND WORKOVER RIGS I. A continuous monitoring system with eight sensors and six red beacon light/siren alarm

systems, each with conductor cable, shall be provided. A. All sensors must have protective housings capable of protecting the sensor from

accidental spray from rig wash down hoses and accidental mud and/or oil splashes.

B. Sensors shall be located as near as practical to: 1. The top of the bell nipple. 2. The flowline opening to the shale shaker. 3. The Drillers position and about three feet above the rig floor. 4. The mud pit in the pump area. 5. The motorman's work area in the motor room. 6. The living quarters area nearest the most likely source of hydrogen

sulfide. 7. The breathing apparatus compressor package, near the rig floor.

Note: The eight sensor with 200 feet of cable on portable reel shall be extra

and will be used to monitor any other potential source of hydrogen sulfide or kept on standby in designated safety equipment storage area.

C. There shall be at least four spare sensors in addition to the eight in the monitoring system.

D. The H2S alarm system (red beacon and siren) shall be set at 10 ppm H2S for the first alarm and 20 ppm H2S for the second alarm.

The combustible gas alarm system shall be set at 20% of the Lower Explosive

Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. [Note: This setting criteria applies to cold work situations only.]

E. The alarm system shall be located in a clearly visible area so that personnel in

any work area can see and/or hear at least one set. They shall be located: 1. On the rig floor and at least eight feet above the floor. 2. On the port side at the corner of and above the quarters. 3. On the starboard side at the corner of and above the quarters. 4. Below deck in the pump-motor room area. 5. In crew quarters.

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6. In the galley area.

F. The monitor shall be located in the Supervisor's office, Control Room or Radio

Room. II. A minimum of one hundred 30 minute SCBA's will be located on any offshore rig

operating in known or suspected H2S areas. There shall always be at least 25% more SCBA onboard than the number of personnel.

A. The 30 minute SCBA's shall be stored ready for use as follows:

1. There shall be one SCBA assigned to each person on board, regardless

of his affiliation, contractor, service contractor, Aramco, or any visitor. These will be stored under the head-end of the assigned bunk when the person is in the bunk and during any period considered safe by the Supervisor. (If there is no bunk assignment, the person will be assigned a SCBA and a designated area for storage during his time on board.) Before assignment of a SCBA to any person, he will demonstrate that he is capable of donning it, adjusting the face piece, and turning on the pressure demand air. This requirement shall be waived for any personnel with documentation from his employer that he has received training within the past 12 months in H2S safety, including practice in donning respiratory protection equipment.

2. Ten SCBA's shall be stored in the dining area. 3. Four SCBA's shall be stored in the motor room or pump area. 4. Four SCBA's, each with clip-on communication device. Two shall be in

the Saudi Aramco Foreman's office and two in the Rig Supervisor’s office.

5. All remaining SCBA's and extra cylinders will be stored in an air

conditioned designated safety equipment storage area near the Supervisor's office.

B. The hose-line work units with escape cylinders shall be stored as follows:

1. Six work units (three with clip-on communication devices) on the rig

floor in a convenient location. 2. Two work units each with a clip-on communication device in the

Supervisor's office. 3. Two work units each with a clip-on communication device in the Saudi

Aramco Foreman's office. 4. One work mask shall be located in the derrick at the Derrickman's

position, finger board or stabbing board.

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5. Five work units and 16 spare cylinders shall be stored in an air-conditioned designated safety equipment storage area near the Rig Supervisor's office.

6. Nine spare-clip communication device units with supply of spare

batteries will be stored with the five work units as above in #4. III. Three cascade systems with 12 - 300 cubic foot cylinders each or equivalent capacity;

three air compressors each with purification system and capacity of 26 scfm at 2400 psi; one 3 outlet manifold and three 12 outlet manifolds; two 200 foot hoses; two - 150 foot hoses; twelve - 50 foot hoses; two 5000 psi working pressure hoses (250 foot and 300 foot respectively).

A. One cascade system with air compressor powered by an explosion proof

electric motor will be located near the rig floor

1. There shall be two six outlet manifold on the derrick floor. 2. There shall be a three outlet manifold at the Derrickman's position. 3. There shall be a three outlet manifold in the mud room. 4. There shall be a three outlet manifold in the motor room. 5. There shall be a one six outlet manifold for recharging portable cylinders,

one at each cascade system. 6. There shall be a double tee with check valves for tying in either or both

of the other two systems.

B. There shall be two cascade systems with diesel powered air compressors, located as remotely from the rig floor as practical, one on the upper starboard deck, the other on the upper port deck

1. There shall be one, six outlet manifold for recharging portable cylinders

at each cascade system, as well as regulators and low pressure manifolds for hose line units.

2. There shall be a double tee with check valves for tying in either or both

of the other two systems.

C. There shall be one 250 foot of 5000 psi w.p. hose; one 300 foot of 5000 psi w.p. hose; two 150 foot and twelve 50 foot hoses stored and ready for immediate use in an air conditioned designated storage area.

IV. Five personal portable H2S monitors, as well as stock of lead acetate sampling devices.

V. One hydrogen sulfide calibrator with two permeation tubes, portable and AC/DC.

VI. Continuous H2S mud monitor (Mud Duck). Garret Gas Train with supply of accessory

equipment for testing mud, plus Drager Test Kits for checking mud return.

VII. Four portable oxygen resuscitators with eight spare oxygen cylinders.

VIII. Four portable H2S - SO2 detectors, (suction type) with H2S and SO2 tubes.

IX. Four portable combustible gas detectors - hand pump suction type.

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X. Six bug blowers, explosion proof, high volume (25,000 cfm or larger) and movable.

XI. Wind socks (4 minimum), streamers, and flags to be located on various places on rig so all personnel will know the wind direction.

XII. Remote flare line ignition system (Alex-500 or equivalent). XIII. One emergency flare gun with a supply of 24 cartridge will long shelf life will be stored

in a locked-up wooden box in in the Company Foreman’s office. XIV. Four safety harnesses and four 250 feet retrieval ropes. XV. Four stretchers (Stokes litter - Navy type basket or equivalent) with blankets and

securing straps. XVI. Four first aid kits (each 25 man size). XVII. Four Quick-Air splint kits or equivalent. XVIII Six portable electronic bull horn speakers with six extra battery packs. XIX. Six small chalk boards with clamps for mounting with an adequate supply of chalk and

erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards.]

XX. Flashlights - explosion proof with extra set of batteries and extra bulb for each

(minimum number shall be 10 flashlights). Note: All safety equipment with rubber, plastic or other parts like to deteriorate shall be stored

in an air conditioned, dark and designated area, near the Supervisor's office. Adequate supplies of sanitizing material shall be available for sanitizing face masks and other body contact equipment.

B-7 HOUSEKEEPING

1. Work areas, stairs and walkways shall not be obstructed by debris or stored materials. 2. All walking and working surfaces shall be kept in good repair and free from oil, mud,

and other potentially slippery material. 3. The area around the base of the derrick ladder shall be kept clear to provide

unhampered access to the ladder. 4. The area around the rotary table shall be kept clear of obstacles; clean, and free of

tools, materials and any accumulation of oil, water, or circulating fluids. 5. Storage of material shall not create a hazard. Bags, containers, bundles, etc., stored in

tiers shall be stacked, blocked, and limited in height so they are stable and secure against sliding or collapse.

6. Storage areas shall be kept free from accumulation of materials that constitute hazards

from tripping, fire, or explosion.

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7. Combustible materials, such as oily rags and waste, shall be stored in approved covered metal containers.

B-8 RIG CAMPS: KITCHENS AND ACCOMMODATIONS (See Also G.I.

151.006 Implementing the Saudi Aramco Sanitary Code)

1. In addition to complying with applicable requirements for housekeeping and fire extinguishing equipment, the RIG OPERATOR shall ensure that: (a) Exhaust fans, hoods, filters, grease trays, and ductwork are cleaned regularly to

prevent a buildup of cooking grease and other flammable material. (b) Blades of exhaust and ventilation fans, if within 2.1 meters (7 feet) of the floor,

are equipped with proper guards to prevent employee exposure. (c) Each walk-in freezer is equipped with a working audible alarm to alert other

personnel should the door become stuck. (d) Sanitation requirements published by the Saudi Aramco Preventive Medicine

Department are fully complied with. 2. Each cooking, sleeping, washing and toilet facility shall be kept clean and sanitary. 3. The plumbing and mechanical appliances shall be kept in good working order.

B-9 FIRE EXTINGUISHING EQUIPMENT

1. On every drilling or workover rig, the RIG OPERATOR shall have readily accessible

not less than the fire extinguishing equipment specified in the Drilling/Workover Contract.

2. The RIG OPERATOR shall inspect fire extinguishers monthly, or more frequently if

necessary to ensure they are fully charged, kept in their designated locations, and free from any obstructions. Inspection shall be documented in an inspection log.

3. Fire fighting equipment shall not be tampered with and shall not be removed for other

than for fire fighting or for servicing. Extinguishers removed from the premises to be recharged shall be replaced by spare extinguishers during the period they are missing.

4. Carbon tetrachloride and other toxic vaporizing liquid fire extinguishers are prohibited. 5. For each offshore rig, the RIG OPERATOR shall prepare a fire control plan and the

plan shall be permanently exhibited on the rig. 6. Fixed fire extinguishing systems for each offshore rigs (including water, carbon dioxide,

dry powder, Halon, or foam) shall be kept in good working order and available for immediate use at all times while engaged in drilling operations or in transit.

7. Manual fire alarm stations shall be conspicuously located on each deck level of offshore

rigs.

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8. A fire hose shall not be used for any purpose other than fire fighting, fire drills, and testing.

9. Each fire hose shall be completely unrolled and inspected by the RIG OPERATOR

once each month and defective parts should be replaced. Fire hoses shall be pressure-tested annually. (Refer to G.I. 1781.001-1 and SAES-B-19).

10. The access to any fire hydrant shall not be blocked. 11. Each fire hydrant shall be equipped with a spanner wrench. 12. Each fire hose shall be properly stored on a rack or reel when not in use. 13. Each fire nozzle shall either be attached to the hose or stored next to the fire hydrant to

which the fire hose is attached. 14. Each hose water nozzle provided shall be of an approved dual purpose type (i.e. spray

jet type) incorporating a shutoff. 15. Each hose on a helicopter deck that discharges foam shall have a nozzle that has a foam

stream, foam spray, and off position. 16. Each fire station on an offshore rig shall be properly identified by marking: "FIRE

STATION NO.____" next to the station in letters at least 5 centimeters (2 inches) high. 17. On each offshore rig, there shall be,at all times at least two RIG OPERATOR personnel

who are trained in the use of a Fire Fighter Aircraft Crash Rescue Equipment. 18. A crash rescue box should be permanently located in an area readily accessible to the

heliport. This box should be highly visible and designated exclusively for crash equipment. The required contents shall comply with current Saudi Aramco Aviation policy.

19. Additional information on requirements is available in specific Rig Contracts (See

Schedule ‘G’ Attachment 1) and the following Section B-9 Appendix I.

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Section B-9 (Appendix I)

FIRE PROTECTION AND CONTROL EQUIPMENT

A. Nine 30-lb dry chemical ‘UL’ listed per (GI 1981 & SAES-B-19) BC

extinguishers provided for extinguishing of localized fires located and mounted as follows: ?? Two on rig floor at control station.

?? One in shaker area.

?? One on mud pump skid.

?? Two in drawworks area.

?? One on generator trailer.

?? One inside tool room.

?? One in the area of the gasoline fuel tank.

B. Two 10-lb carbon dioxide extinguishers located and mounted as follows:

1. Two on the generator trailer.

C. One 150-lb wide wheel type ‘UL’ Listed BC type "Purple K" dry chemical fire

extinguisher located at a minimum of 75 feet from the wellhead and/or mud, diesel tanks.

D. One fixed 1-1/4" live hose reel with 125 feet of 1-1/4" hose for delivery of water to the rig floor, cellar and mud tank area. The unit should be centrally mounted to adequately cover the rig and associated equipment. E. One Type 2A 10 BC extingusiher located in Foreman’s trailer. B-10 TRUCK LOADING AND UNLOADING 1. Before pumping hydrocarbons between two units, the units shall first be electrically

bonded together and grounded. 2. The bonding connector and the grounding conductor from the unit to earth shall remain

effectively attached until all pumping connections have been removed. 3. While tank trucks containing flammable, vaporizing liquids are being connected or

disconnected, no vehicle shall start up or have its motor running in the loading area.

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4. When liquid in a tank contains or is likely to contain hydrogen sulfide, personnel required to gauge the liquid shall be provided with and shall wear proper respiratory protective equipment.

B-11 FUEL TANKS

1. Except for diesel fuel and the fuel in the tanks of operating equipment, no gasoline or

other liquid fuel shall be stored within 22.9 meters (75 feet) of a rig or its auxiliary equipment that could be a potential ignition source.

2. The RIG OPERATOR shall ensure that all fuel tanks are conspicuously marked as to

contents. 3. The RIG OPERATOR shall ensure that neither smoking nor open flame is allowed

within 7.6 meters (25 feet) of the handling of flammable liquids. A notice shall be conspicuously posted.

4. Dispensing nozzles and valves shall be of the self-closing type. Drip pans shall be

provided and used when needed. 5. Fuel tanks shall be located where they are not subject to physical damage from vehicles.

Where this is not possible, barrier protection shall be provided. 6. Drainage from any fuel storage shall be in a direction away from the rig. Rig "day tanks"

may be located on the level well site but they must be so located that, should they rupture, the resulting fuel spillage will not drain toward the well.

7. A fire extinguisher, approved for extinguishing petroleum fires, shall be readily

accessible at a permanently designated and highly visible location at each fuel storage tank.

8. Label Emergency fuel shut off. 9. Recommend all valves on fuel tank be (1/4 turn) Ball Type. 10. Fuel tanks should be supplied with appropriate vents without any bends. B-12 BULK STORAGE TANKS 1. All bulk storage tanks shall be equipped with safety relief valves and/or rupture discs so

as to prevent excess pressure. Rupture discs can only be used for bulk storage tanks in open areas where drainage would be to a safe area.

2. Bulk storage tanks in enclosed areas shall be equipped with testable safety relief valves

which can be vented out of the area. Such enclosed areas shall be ventilated so that a pressure build-up will not occur if a break or a leak in the air supply system occurs.

3. All safety relief valves shall be function tested at least every three months. 4. A proper means of access shall be provided to each bulk storage tank.

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5. Each bulk storage tank shall be clearly marked as to contents. B-13 CONTROL OF STATIC ELECTRICITY 1. When transferring flammable liquids or finely divided flammable or explosive materials

from one container to another the containers shall be in firm contact with each other or be continuously electrically bonded throughout the transfer so as to prevent the accumulation of a static charge.

2. When tanks, mixers, or processing vessels are used for flammable liquids or flammable

or explosive compounds, they shall be electrically bonded and grounded while being filled or emptied.

B-14 HANDLING AND STORAGE OF COMPRESSED GAS CYLINDERS

1. Reference G.I. 355.020 and attachment must comply with it. 2. Gas cylinders shall be secured in an upright position and shall be separated in storage as

to full and empty cylinders. All oxidizers shall be separated from fuel gases by at least 6.1 meters (20 feet).

3. Valve protection caps shall be installed on all cylinders at any time a regulator is not

attached. 4. When gas cylinders are hoisted, they shall be secured on a cradle, sling board, or pallet.

They shall not be hoisted or transported by means of magnets or choker slings applied directly to the cylinders.

5. When gas cylinders are transported by powered vehicles they shall be secured and

protected in such a manner to prevent physical damage. Cylinders that contain acetylene must be transported, used, and stored vertically to prevent the liquid acetone collecting in the neck of the cylinder.

6. Valve protection caps shall not be used for lifting gas cylinders. 7. Damaged or defective gas cylinders must not be used. Since these cylinders can be

especially hazardous, it is important to exercise great care when removing them from the rig area.

8. Freon cylinders shall be stored in an area protected from the direct rays of the sun. B-15 ELECTRICAL WIRING AND EQUIPMENT 1. The installation, use, and maintenance of any fixed or portable electric wiring or

equipment shall comply with the provisions of NFPA 70, "National Electrical Code", and of API RP 500, "Classification of Areas for Electrical Installations at Drilling Rigs

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and Production Facilities on Land and on Marine Fixed and Mobile Platforms" and SAES-B-68.

2. All diesel engines used to generate electrical or mechanical power on a rig shall be

equipped with spark arresting devices or water sprays. The exhaust stacks shall be directed so that hot exhaust gases and noise will not endanger nearby personnel.

3. Warning signs that prohibit unauthorized access shall be conspicuously displayed on the

housing or other enclosure around high voltage electrical equipment. 4. Lead-in cables from the generators to the derrick shall be placed in trays, suitcased, or

adequately protected from physical damage by other means. In those instances where these methods are impossible or impractical, all wiring must be bundled and secured to fixed structural members.

5. A non-conductive floor mat shall be provided in front of each switch panel in the

generator or SCR room. 6. Each SCR room shall be equipped with emergency lighting for at least two of the exits

from the room.

7. All switch box, junction box, and connector box covers shall be in place and properly labeled.

8. Each onshore generator skid shall be grounded together to the well cellar. 9. Each onshore generator skid shall be equipped with a secure system for pinning the

doors open. It shall also have warning signs posted to alert workers of the high voltage. 10. Auxiliary/emergency standby generators for offshore rigs shall be installed so they will

start automatically when "auto start" circuits are activated. The RIG OPERATOR shall test "auto start" circuits on at least on a weekly basis. A sign that says “DANGER – AUTOSTART.”, Must be posted.

11. The power available from the emergency generator shall be sufficient to supply,

simultaneously, all those services that are essential for safety in an emergency. 12. Auxiliary and emergency standby generators shall be run at full load for a minimum of

two hours every week and logged. 13. All skids shall be securely electrically bonded together to the rig cellar. Refer to

National Electrical Code ANSI/NFPA 70 (latest edition) Article 250-26, “Grounding Separately Derived Alternating-Current Systems” and SAES-P-111, “Grounding”.

“A separately derived system is a premises wiring system where power is derived from a generator, a transformer, or converter windings, and there is no direct electrical connection, including a solidly grounded circuit conductor, to supply conductors originating in another system.”

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B-16 ILLUMINATION 1. Rig lighting shall at all times provide a minimum illumination of:

(a) 53.8 lux (5 foot-candle) power on the entire derrick floor,

(b) 53.8 lux (5 foot-candle) power at the monkey board, mud pumps, catwalk, and

(c) 21.5 lux (2 foot-candle) power at the shale shaker, stairways and other working

areas.

2. The installation of the rig lights shall be according to NFPA requirements for electrical installations in classified areas (see API RP-500).

3. Each lighting fixture in a derrick shall be independently attached to the derrick by a

safety cable to prevent it from falling to the rig floor should it be torn loose. 4. Lighting fixtures shall be kept sufficiently clean, adjusted, and repaired so as to provide

the illumination required for the safety of RIG OPERATOR personnel. 5. Light beams shall be directed toward the objects to be illuminated and away from the

eyes of rig personnel. 6. Except in an emergency, vehicle lights shall not be used for the lighting of onshore rig

operations. 7. Emergency lighting shall be kept in good repair and ready for immediate emergency use.

It shall be tested on a regular basis to be certain it will function properly in an emergency.

B-17 TOOLS -- HAND AND POWER 1. All tools, hand and power, and similar equipment, whether furnished by Saudi Aramco

or by a contractor, shall be kept in good operating condition. 2. All hand-held power tools shall be equipped with a constant pressure ("dead-man")

switch that will shut off the power when the pressure on it is released. Switches or triggers which can be locked in the "ON" position are expressly forbidden. Note: Such locks are very common on power tools and must be disabled before use on a Saudi Aramco Company or Contract Rig.

3. Impact tools, such as drift pins, wedges, and chisels, shall be kept free of mushroomed

heads. 4. Sledge hammers having a square face shall not be used. 5. Wooden handles of tools shall be kept free from splinters or cracks and shall be kept

tight in the tool. 6. Electric power operated tools shall be either of the approved types: Double-insulated

or grounded. 120V AC Max Voltage with GFCI (See construction Safety Manual 10.6.1.1,2).

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7. Pneumatic power tools shall be secured to the hose or whip to prevent the tool being accidentally disconnected.

8. Safety clips or retainers shall be securely installed and maintained on pneumatic impact

(percussion) tools to prevent attachments from being accidentally expelled. 9. The manufacturer's safe operating pressure for hoses, pipes, valves, filters, and other

fittings shall not be exceeded. 10. The use of hoses or electrical cords for hoisting or lowering tools is prohibited. 11. All hoses exceeding 12.7 millimeters (1/2 inch) inside diameter with a pressure greater

than 1034 kilopascals (150 pounds per square inch) shall have a safety device at the source of supply or branch line to reduce pressure if a hose fails.

12. The fluid used in hydraulic powered tools shall be fire resistant and shall retain its

operating characteristics at the most extreme temperature to which it will be exposed. B-18 ABRASIVE WHEEL MACHINERY 1. Abrasive wheels used on bench or pedestal mounted grinding machines shall have

spindle-end, tongue, and work rest guards. 2. Work rests shall be kept adjusted closely to the wheel face with a maximum opening of

3.2 millimeters (1/8 inch) to prevent the work from being jammed between the wheel and the rest, causing possible wheel damage.

3. Tongue guards shall be kept adjusted so the distance between the wheel periphery and

the adjustable tongue guard never exceeds 6.4 millimeters (1/4 inch).

4. All contact surfaces of grinding wheels shall be kept properly dressed and free of foreign material.

5. Before installing a new grinding wheel, the maximum approved speed stamped on the

wheel blotter shall be checked against the arbor speed of the machine to ensure that the safe peripheral speed is not exceeded. A grinding wheel shall not be operated at peripheral speeds that exceed the manufacturer's recommendations.

6. Mounting blotters supplied by the grinding wheel manufacturer shall always be used

when mounting a new wheel. 7. Bench grinders shall be securely mounted to a bench in order to prevent vibration and

movement. 8. All abrasive wheel machinery that is electrically powered shall be adequately grounded

or of the approved double-insulated type. 9. Safety guards used on machines known as right angle head or vertical portable grinders

shall have a maximum exposure angle of 180 degrees, and the guard shall be located so as to be between the operator and the wheel during use.

10. Eye and face protection must be worn while using grinders.

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B-19 WELDING AND CUTTING 1. No welding or cutting shall be done:

(a) On any pipe or vessel containing pressurized fluid or gas.

(b) On any tank or container which contains or has previously contained flammable fluids or gases until such containers or vessels have been filled with water or are otherwise suitably purged. Used 55 gallon drums are specifically included in this instruction.

(c) In a confined space and until a properly trained person has first tested the atmosphere with proper instrumentation to ensure it is free from combustible gases (i.e. 0% LEL) and contains at least 20% oxygen, all requirements for confined tank entry shall be strictly followed. (refer to section B-32)

(d) On any automobile or truck wheel rim upon which a tire is mounted. 2. Welding, cutting, or brazing shall not be done on any certified pressure vessel except by

code qualified personnel following code procedures and techniques. 3. No field welding shall be performed on any load handling tools or equipment. Tools

requiring this type of repair shall be sent to a shop for properly controlled repair conditions.

4. Welders and cutters must be trained in all the safe operating procedures that are

applicable to their work. 5. Welding, cutting, or brazing shall not be done in the presence of explosive gas or fumes,

or combustible materials.

6. Suitable eye protection shall be worn by welders and helpers when welding or cutting operations are being performed or scale is being cleaned from welds. Ref CSM Figure 1.4A.

7. Acetylene cylinder valves shall not be opened more than one and one-half turns. The

wrench must be left on the stem. The maximum optional gauge pressure for acetylene cylinders must not exceed 103 kilopascals (15 pounds per square inch).

8. All gauges and regulators shall be maintained in good condition. Regulator gauges shall

not be used if the glass cover is broken or cracked. 9. A friction lighter, not matches or hot work, shall be used to light a torch. 10. Hoses showing leaks, burns, worn places, or other defects rendering them unfit for

service shall be repaired or replaced. 11. When gas welding equipment is not in use, the cylinder valves shall be closed and the

pressure in the hoses released. 12. Arc welding cables with damaged insulation or exposed bare conductors shall be

replaced.

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13. Cables with splices within 3 meters (10 feet) of the electrode holder shall not be used. 14. When in use, electrode holders shall be placed so that they cannot make electrical

contact with persons, conducting objects, fuel tanks, or compressed gas tanks. 15. Portable arc welding machines shall have the frames properly grounded. 16. Welders shall place welding cable and other equipment so that it presents no

obstruction of passageways, ladders, and stairways. The ground lead should be placed as close to the work as practical.

17. Welding helmets shall be worn by all welders during arc welding operations. Personnel

shall not be permitted to observe arc welding operations unless they are wearing proper eye protection.

18. When arc welding under wet conditions, special insulating protection shall be supplied.

in order to prevent an electrical shock. 19. After welding operations are completed, the welder shall mark the hot metal or provide

some other means to warn people of the hazard.

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SECTION B-19 APPENDIX I PROTECTIVE GOGGLES, SPECTACLES, FACE SHIELDS AND HELMETS TYPICAL EYE PROTECTION APPLICATIONS

Operation Hazards Protection Acetylene-welding cutting burning Sparks, molten metal, harmful rays,

flying particles D, E, F

Electric arc welding Sparks, molten metal, intense rays, flying particles

I

Chemical handling Splash, acid burns, fumes G, H (Severe +C) Chipping Flying particles A, B, C, E, F, G

Furnace operations Glare, heat, molten metal D, E, F Grinding (light) Flying particles A, B, C, G

Grinding (heavy) Flying particles C, D, E, G Laboratory Chemical splash, glass breakage G, H (A or B +C) Machining Flying particles A, B, C, G

Molten metals Heat, glare, sparks, splash D, E (A or B tinted +C)

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Spot welding Flying particles, sparks A, B, C, G

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Protection against Radiant Energy Protection against radiant energy requires the selection and use of the proper shades of welding filter lens or plate. The table below shall be used as a guide for the selection of the proper shade numbers of filter lenses or plates used in welding. Shades more dense than those listed may be used to suit the individual’s needs.

Welding Operation Comfort Shade Number Shielded metal-arc welding 1/16-, 3/32, 1/8-, 5/32- inch

diameter electrodes. 10

Gas-tungsten are welding and gas-metal arc welding (nonferrous) 1/16-, 3/32-, 1/8-, 5/32- inch diameter

electrodes.

11

Gas-tungsten arc welding and gas-metal arc welding (ferrous) 1/16-, 3/32-, 1/8-, 5/32-inch diameter

electrodes

12

Shielded metal-arc welding 3/16-, 7/32-, ¼- inch diameter electrodes

12

Shielded metal-arc welding 5/16-, 3/8-inch diameter electrodes

14

Atomic hydrogen welding 10-14 Carbon-arc welding 14

Soldering 2 Torch brazing 3 or 4

Light oxy fuel gas cutting, up to 1 inch 3 or 4 Medium oxy fuel gas cutting, 1 inch to 6 inches 4 or 5

Heavy oxy fuel cutting, over 6 inches 5 or 6 Gas welding (light), up to 1/8- inch 4 or 5

Gas welding (medium), 1/8-inch to ½ inch 5 or 6 Gas welding (heavy), over ½- inch 6 or 8

Air-carbon arc cutting 12 B-20 AIR COMPRESSORS

1. All air compressors shall have at least one air pressure regulator to control proper air

flow. 2. The safety relief valve on the main air tank shall be checked at least every three months

and kept in proper working order. 3. No valves shall be allowed upstream or downstream from any safety relief valve. 4. The piping connected to the pressure side and discharge side of a safety relief valve

shall not be smaller than normal pipe size openings of the device. 5. The piping from the discharge side of the safety relief device shall be securely anchored

to prevent any movement of the pipe when venting air. 6. All valves and pressure control devices shall be kept in proper working order and

inspected as required.

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B-21 HOT WORK

1. No hot work, welding or cutting, open flames, smoking or other potential source of

ignition will be allowed within any electrically classified areas, as defined in API RP 500, until the measured lower explosive limit (LEL) of the ambient atmosphere is zero.

2. Before the hot work begins and as it continues, all potential sources of ignitable material

- liquids or gases - shall be prevented by some positive means from entering into the work area. When possible all such sources shall be locked and tagged to prevent their being opened.

3. Monitoring of the LEL shall be continuous until the hot work is completed. 4. All electrically classified areas shall be marked, with signs in Arabic and English: "NO

SMOKING". "NO WELDING, CUTTING, OR OTHER SOURCE OF IGNITION EXCEPT UNDER THE DIRECT SUPERVISION OF THE RIG SUPERINTENDENT".

B-22 LOCKOUTS, TAGGING AND WORK PERMITS

1. Where there is danger of machinery being started or electrical circuits being energized

while repairs or maintenance work is being done the RIG OPERATOR shall ensure that the electrical circuits are locked open and tagged. Where there is danger of machinery being started or of compressed gases creating a hazard to RIG OPERATOR personnel while repairs or maintenance work is being done, the RIG OPERATOR shall: (a) Disconnect the lines, or

(b) Lock and tag the main valve closed, or

(c) Blank the lines on all hydraulic or air driven machinery, pressurized lines, or any

lines connected to such equipment if they could create a hazard to personnel. (d) The craftsman doing the actual work should have the lock out key in his

possession. B-23 CONFINED SPACES

1. DEFINITION OF A CONFINED SPACE: A confined space is any space that can

be entered by personnel that: (a) has limited openings for entry or exit,

(b) inadequate ventilation or the presence of a harmful atmosphere is likely, and

(c) the space is not designed for personnel occupancy. Note: "confined space" includes, but is not limited to, tanks, vessels, cellars, compartments, piping geometry, or building and facility ‘dead ends’ that limit access or escape.

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2. Whenever possible, work shall be planned so as to circumvent entry into a confined space.

3. The RIG OPERATOR must never allow any person to enter a confined space until

ALL the following criteria have been met: (a) The atmosphere in the confined space must be sampled by a supervisor for the

presence of harmful or toxic materials, for the likelihood of a flammable atmosphere during the time the space is entered, and for a minimum 20% oxygen concentration.

(b) In confined spaces where toxic materials such as hydrogen sulfide are present, those entering the space shall be required to wear the proper respiratory protective equipment as prescribed in Section B-6, "Hydrogen Sulfide Safety", of this Manual.

(c) If a potentially flammable atmosphere (a reading of anything above "zero percent" of the lower explosive limit) is encountered, the flammable material shall be removed from the area or all work shall be done with non-sparking hand tools and pneumatic power tools. If pneumatic tools are not available the electromotive force to the tools shall not exceed 32 volts.

(d) If the oxygen level inside the confined space is less than 20% the area shall be adequately ventilated or the persons entering the area shall wear respiratory protective equipment (as required in Section B-5, "Respiratory Protection", of this Manual).

(e) No personnel shall be allowed to enter a confined space until positive means are established to prevent all energy sources from entering the confined space area or causing associated equipment to operate while work continues.

4. Each person entering the confined space shall wear a safety harness with an attached

life-line. 5. A stand-by man shall be assigned the duty of watching the persons working inside the

confined space during the time they are inside. This duties of the stand-by man are: (a) He shall have no responsibilities other than to continually watch those inside the

confined space and observe their condition and, also, be alert to any need for rescue or other assistance by those inside.

(b) He shall be in such a position as to physically observe the condition of every person inside the confined space.

(c) He shall have the means (winching equipment or adequate nearby personnel) to rescue any personnel from inside the space.

(d) He shall have adequate personal protective equipment available so if it should become necessary to aid those inside the confined space, he can enter the area safely.

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6. These are minimum requirements which must always be met any time personnel are required to enter a confined space (see Item #1) for ANY length of time.

B-24 USE OF POTENTIALLY HAZARDOUS CHEMICALS

1. Rig personnel must be informed regarding the potential harmful effects of all chemicals used in drilling and workover operations. The COMPANY will ensure that the least hazardous chemicals are used in Company operations.

2. Before requesting any chemicals that are potentially hazardous (low flash point, strong

oxidizers, corrosives, toxic, highly flammable, etc.) the COMPANY will research the available chemicals to determine if it is possible to use chemicals that may be safer. The COMPANY should utilize the safest possible chemicals available that will adequately perform according to the operations requirements.

3. The COMPANY shall make every effort to ensure that current material safety data

sheets (MSDS) are available at the rig site for all chemicals that are used. 4. For unusually hazardous chemicals, those for which extraordinary safety measures are

necessary, the MSDS must be in the hands of the rig operator at the location where it will be used at least 24 hours prior to delivery of that chemical. This is important in instances of chemical use where protective gear, special handling and storage requirements, or other preparations must be made before the chemicals arrive at the location.

5. The RIG OPERATOR will be responsible to insure that the proper protective

equipment and first aid measures are available, when necessary, at the location. Also, the RIG OPERATOR will ensure the proper protective equipment is used properly and consistently in order to properly protect rig personnel.

6. All Hazardous Materials shall be segregated from normal stores and clearly identified.

Hazardous Materials Labels shall not be removed from containers.

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SECTION C: RIG EQUIPMENT AND PROCEDURES C-1 SPUDDING IN

1. Spudding in shall not begin until:

(a) all machinery guards are in place,

(b) appropriate platforms, stairways, handrails, and guardrails are installed and

securely fastened in position,

(c) the derrick or mast is secured and all assembly pins and keepers are in place, and

(d) the escape line and safety buggy are properly installed. C-2 DERRICKS AND MASTS

1. Derricks and masts shall have a permanent nameplate either attached to the structure, or

available at the site indicating the following: (a) Name of manufacturer.

(b) Model number and serial number.

(c) Load rating including hook load capacity with number of lines and wind load

rating both with and without pipe standing in the derrick.

(d) Whether external guying is required and, if so, the recommended guying pattern.

2. The derrick or mast shall not be loaded beyond its design capacity. 3. All girts, legs, and braces shall be maintained in good condition, properly secured, and

free from damage, bowing, or deflection. 4. Chain hoists and snatch blocks shall not be fastened to girts and braces. Any bending

of the girts and braces weakens the derrick or mast. 5. Any girt, brace, or derrick member having enlarged or distorted bolt holes shall be

replaced. 6. Girts, braces, and other members of the derrick or mast shall never be removed while

the derrick or mast is under a load. 7. To withstand operating vibration, the mud standpipe shall be attached to the derrick leg

rather than the girts and braces, unless the derrick is specifically designed otherwise by the manufacturer.

8. All substructure members shall be free from damage and all securing bolts, nuts, pins,

and safety pins shall be in place.

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9. Before subjecting the derrick or mast to unusually heavy loads, connecting pins and keepers, bolts, and nuts shall be checked to ensure that they have not been loosened or worn excessively by vibration.

10. The weep holes in the "A" legs of the derrick or mast shall be kept clear of dirt, debris,

gloves, rags, etc., that could block the drain holes and permit water to accumulate resulting in corrosion of the legs.

11. An aircraft warning light on the crown shall be provided and shall be maintained in

satisfactory operating condition. C-3 ANCHORING -- ALTERATIONS

1. Derrick or mast guy lines, when required, shall be installed according to the

manufacturer's specifications and shall be properly fastened to adequate ground anchors.

2. No structural change or addition to a derrick or mast shall be made unless approved in

writing beforehand by the manufacturer of the equipment or the manufacturer's representative.

3. No holes shall be drilled, punched, or burned in a load carrying member of a derrick,

mast, or substructure. C-4 CROWN BLOCKS

1. There shall be no opening between the beams of main support members or frame work

of the crown large enough to permit a worker to fall through. 2. Where wood bumper blocks are attached to the underside of crown block beams, a

wire rope safety line or wire mesh shall be fastened along the beam and attached to the derrick at both ends, thereby safely retaining the wood bumper blocks should a crown-out occur.

3. When the crown block is to be lubricated, the drawworks shall be shut down, and the brake chained down. C-5 TRAVELING BLOCKS

1. Traveling blocks shall be equipped with securely attached sheave guards. Any traveling

block hook to which equipment is directly or indirectly attached shall be equipped with a safety latch or a wire rope safety line.

2. Safety latches on hooks shall be maintained rigid so that a jar from the elevator links will

not drive the latch aside and unhook the line. 3. All traveling blocks, hooks, elevators, elevator links, and traveling equipment shall be

free of projecting bolts, nuts, pins, or parts.

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4. An upward travel limiting device (crown protector, such as a Crown-O-Matic) shall be installed, properly adjusted, and used on all drilling and workover rigs.

5. The upward travel limiting device shall disengage all power to the hoisting drum and

apply the brakes to prevent the traveling blocks from contacting the crown structure. C-6 AUXILIARY ESCAPE

1. On every drilling and workover derrick or mast an auxiliary means of escape shall be

provided by the installation of a specially rigged and securely anchored escape line attached to the derrick. (Offshore rigs are exempt from this requirement until an escape device becomes available that meets the criteria contained in Requirement Number 2, below.)

2. The emergency means of escape shall be located in such a manner that the escape line itself does not create a hazard to helicopter rotors, crane booms, or other moving equipment. The rate of descent of any safety buggy must be controllable by the rider.

3. An escape line shall consist of a wire rope not less than 12.7 millimeters (1/2 inch) in

diameter and shall be free from kinks, splices, and broken wires. 4. On land-based rigs, all escape lines shall be securely anchored with either an iron stake

or deadman that will withstand a 1361 kilogram (3000 pound) static cable pull. The ground end of the escape line shall be staked out so that the escape route and landing area are unobstructed. If space limitations are such that the escape line is, or may be, exposed to motorized traffic, it shall be conspicuously marked at eye level with a visible flag or streamer.

5. Tension on an escape line and configuration of the landing area shall be such that a

worker sitting in a safety buggy will touch the ground, deck, or water approximately 6.1 meters (20 feet) from the anchor.

6. The length of an escape line for onshore rigs shall be at least double the vertical distance

between the ground and the point at which it is attached to the derrick (normally the first girt above the monkey board).

7. An approved safety buggy shall be properly installed on the escape line and kept at the derrickman's principal working platform for instant emergency use. It shall be inspected by a qualified person at least once each week.

8. The escape buggy shall be secured to the monkey board in a manner to ensure easy

release in an emergency. C-7 GUARDS

1. Sturdy machinery guards shall be installed on all drawworks and rotary table drives to

prevent personnel being injured by rotating machinery or by disintegrated or broken parts.

2. A metal guard not less than 3.2 millimeters (1/8 inch) thick shall enclose the tops and

outer sides of all hoisting drum brake flanges.

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3. Every rotary table shall have a substantially constructed metal guard with a non-skid

surface that adequately covers the outer edge of the table and extends downward to completely cover all of the exposed rotating sides of the table, including the pinion gear.

4. Guards shall be installed on all hoisting drums to prevent personnel coming in contact

with the rotating drum. 5. Rig machinery shall not be operated unless all guards are properly maintained and in

position, except during maintenance, repair, or rig-up work, or when limited testing is being performed by an authorized and qualified person.

6. If it is necessary to remove guards to reach lubrication fittings for oiling and greasing,

machinery shall be fully stopped. All guards shall be replaced prior to resuming operations.

7. Air hoists shall be equipped with a guard and a line guide. 8. All V-belt drives shall be guarded. 9. All engine fan blades shall be equipped with shrouds to protect against personnel injury. 10. All hot surfaces of equipment shall be suitably guarded or insulated to prevent possible

injury to personnel. C-8 DERRICK EXITS, LADDERS, STAIRWAYS, FLOORS, AND

PLATFORMS

1. Safe exits shall be provided directly to the outside on at least two sides of the derrick floor. An exit that leads directly to the mud pits prior to reaching ground level shall not be counted as one of the required exits.

2. Exit doors from the doghouse shall open outward and shall not be held closed with a

lock or outside latch when RIG OPERATOR personnel are working on the derrick floor.

3. Floors, stairways, and platforms shall be free from dangerous projections and

obstructions and shall be maintained in good repair, clean, and free from oil, grease, water, or other materials of similar nature. Where any type of operation necessitates working on slippery floor areas, such surfaces shall be protected against slipping by use of mats, grates, cleats, or other means to provide reasonable protection.

4. Every flight of stairs having four or more risers shall be equipped with standard stair railings on open sides.

5. Standard guardrails shall be installed on the outer perimeter of all working platforms and

walkways that are over 1.2 meters (4 feet) above ground level. A standard guard rail consists of a top rail 1.1 meters (42 inches) in height, a mid-rail, located an even distance between the top rail and the floor, and a 10.2 centimeter (4 inch), toe board mounted flush with the floor. The guardrails shall be mounted on centers and designed to withstand the weight of a 90.7 kilogram (200 pound) person.

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6. When it is not possible, during a temporary condition to provide adequate railing all personnel working within 3.1 meters (10 feet) of the edge must be tied off with a safety harness.

7. On drilling and workover rigs, a stairway shall be installed beside the pipe ramp which

shall extend from the ground to the derrick floor at the V-door. 8. A sturdy guard rail shall be provided at the V-door. It shall be in place at all times

except when the pipe ramp is being used. The use of chains on wide spans, such as V-doors, is discouraged.

9. Every opening in a derrick floor shall be covered or guarded when not being used. 10. Unless the rathole or mousehole extends at least 30.5 centimeters (12 inches) above the

rig floor, the opening in the floor above the pipe shall be covered when a kelly or joint of pipe is not in the hole.

11. Catwalks shall be provided with a stairway at the outer end. 12. Guardrails shall be installed on both sides of walkways located over open mud tanks. 13. When a chain or wire rope is used as a temporary substitute for a guardrail on mud tank

walkways, the chain or wire rope shall be adequately secured and kept taut. 14. Cages having hoop type back supports shall be provided on all fixed ladders of more

than 3.1 meters (10 feet) unless a climbing device is used. When a cage is used, the maximum unbroken length between resting points shall be 6.1 meters (20 feet).

15. The area around the base of the derrick ladder shall be kept clear to provide

unhampered access to the ladder. 16. Ladder safety devices may be used on ladders over 3.1 meters (10 feet) in unbroken

length in lieu of cage protection. All ladder safety devices, such as those that incorporate climbing belts, sheaves, and sliding counterweight attachments shall be properly installed to meet the design requirements of the ladders which they serve. Where possible, the sliding counterweight shall be installed on the off-ladder side of the derrick.

17. Climbing devices, when used in lieu of caged ladders, shall be properly rigged with a

minimum of three cable clips. The counterweights should approximate the weight of the derrickman.

18. Derrickmen shall always use the climbing device. They must climb or descend the

ladder rung by rung and not "ride" the climbing device. 19. No personnel shall slide down any pipe, kelly hose, cable, or rope line except in an

extreme emergency. 20. Platforms shall be located at the monkey board, tubing board, and crown of all drilling

and workover rigs. The requirement for a platform at the crown may be deleted for masts which are frequently lowered as a normal part of operations (i.e., carrier-mounted workover rigs).

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21. All landing platforms shall be equipped with standard railings and toe boards, so arranged as to give safe access to the ladder. The step-across distance from the nearest edge of the ladder to the nearest edge of equipment or structure shall not be more than 30.5 centimeters (12 inches).

22. The side rails of a ladder shall extend at least 91.5 centimeters (3 feet) above a landing

platform. 23. All ladders, fixed or portable, shall be maintained in good condition with no bent,

broken, or damaged siderails or steps. 24. Defective ladders shall be immediately removed from service and repaired or replaced. 25. When portable ladders are used, they shall be secured against slippage by the use of

safety feet and tied-off. 26. Portable aluminum ladders shall not be used by electricians or by any other personnel

where they may come into contact with electrical circuits. 27 Tools or other materials shall not be carried up or down a ladder unless properly

secured to the body. C-9 PIPE RACKS

1. Pipe racks shall be level and firmly butted and fixed together with no gaps or elevation

differences between each rack or the catwalk. 2. Outer ends of each pipe rack shall have sturdy stop pins in place to prevent pipe from

rolling off the rack. Pins should be permanently attached to the rack to prevent loss. 3. The catwalk shall be level and free from tripping hazards with a stairway to the ground

at each end. 4. Every pipe rack shall be flush at top and bottom to prevent pipe hang-up.

5. When pipe is to be stored in layers on the rack, spacers shall be used between the

layers and each layer shall be choked. 6. Provision shall be made for the storage of thread protectors. 7. Thread protectors shall be lowered from the rig floor in a container or lashed together.

They shall not be dropped or rolled down the pipe ramp. C-10 PIPE HANDLING

1. Tag line must be used when transferring tubulars. 2. When pipe is being transferred between pipe racks, catwalks, or trucks, the temporary

supports or skids shall be so constructed, placed, and anchored that they will support the load placed upon them.

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3. All driveways alongside pipe racks shall be level so that the truckbed is parallel and even with the racks.

4. During loading, unloading, and transferring of pipe or other similar tubular goods, no

workers shall be required or permitted to be on top of the load, or between the load and the pipe racks.

5. Manual pipe loading, unloading, and transferring operations shall be done only from the

pipe ends, and pipe shall be loaded or unloaded from trucks one layer at a time. 6. When transferring drill collars, tubular goods, or other similar materials which are not

provided with shoulders, pickup subs shall be used during the transfer of those materials into the derrick. Subs shall be secured completely into the drill collars before the collars are lifted.

7. Thread protectors shall be left on tubular goods and downhole equipment when it is

being pulled up the pipe ramp. A lifting bail, sub or nubbin screwed into the box end is acceptable in lieu of a thread protector.

8. A multi-purpose safety clamp (dog collar) shall always be available for use on the rig

floor. 9. When a nubbin or lift sub is used as a lift point in handling drill collars or other tubular

goods, the nubbin shall be made up with positive torque using chain tongs. Nubbins installed "hand tight" are not sufficient. All such nubbins or lift subs must be bored full "ID" and have a box connection to accept a stabbing valve.

10. Trailers used for transporting pipe or as a pipe rack during drilling, workover, or pipe

salvaging operations shall be equipped with a guard the full length of both sides of the trailer.

11. Trailers used for transporting pipe shall be equipped with side stakes adequate to

prevent the pipe from rolling off. Also, the entire load of pipe shall be secured with chains or straps that are sufficient to hold the pipe in place on the trailer if there is a complete failure of the stakes. All pipe trailers shall use stakes and adequate binding.

12. Guards on trailer sides shall be so designed and constructed to ensure that when pipe is

being hoisted into the derrick the lower end of the pipe will not roll off the trailer. 13. Provision shall always be made to prevent pipe, tubular goods, or similar round material

from accidentally rolling off a pipe rack. C-11 DRAWWORKS CONTROLS

1. Each automatic cathead on the drawworks shall have a separate control. Dual controls

may be used only where a locking device is installed to prevent one automatic cathead from being accidentally engaged while the other is in operation.

2. All drilling controls on the console shall be clearly identified. 3. Except during drilling with automatic driller engaged, drawworks controls shall not be

left unattended while the hoisting drum is in motion. When drilling with an automatic driller, it is permissible for the driller to step out of arms reach of the controls; however,

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he must always be in a position to simultaneously see the drilling controls, associated gauges, and drill floor.

4. Before putting the drawworks in motion, the worker in charge of the drawworks shall

ensure that all other workers are clear of the machinery and lines. 5. When there is a danger of the controls being engaged by accidental contact with catlines

or other equipment, the controls shall be protected by a guard. 6. There shall be an emergency kill switch at the driller's console for the emergency

shutdown of the rig motors and mud pumps. This switch shall be checked periodically by the rig electrician to ensure that it is ready for immediate use.

7. All instrumentation at the driller's console, including pit level indicator, mud rate return

flow, and pump stroke counter, shall be installed, used and maintained according to its manufacturer's specifications. All warning alarms shall be kept turned on.

C-12 BRAKES

1. The RIG OPERATOR shall ensure that the brakes on the drawworks of every drilling

rig are tested by each driller when he comes on tour to determine whether they are in good working order. Both the mechanical brake and the auxiliary brake shall also be examined by the toolpusher at weekly intervals to determine the condition of the brake blocks, linkage, seals, and other operating parts.

2. Unless the drawworks is equipped with an automatic driller, the brake shall not be left

unattended without first being tied down. [Note: Meaning of "unattended" in context of automatic usage]

3. Where a hold down chain is used in securing the drawworks brake handle, the slot for

holding the chain shall be provided with a seat or, where a side lug is provided, it shall be curved upwards to prevent accidental disengagement of the hold down chain.

C-13 ROTARY TABLE

1. Water hoses, lines, or chains shall not be handled or used near a rotary table while it is

in motion. 2. When visibility on a rig floor is obscured, personnel shall not be required or permitted to

work on the rig floor while the rotary table is in motion. 3. The rotary table shall not be engaged until all personnel and materials are clear of it. 4. During tripping operations, personnel setting the slips shall be cautioned to keep their

feet well clear of the rotary table and the rotating slip handles.

5. When the kelly bushing drive, pipe, or other tubular equipment are not in it the opening in the rotary table shall be covered with a metal plate.

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C-14 CATHEAD LINES AND SPINNING CHAINS

1. Cathead Lines and Spinning Chains are NOT to be utilized in Saudi Aramco drilling and workover operations.

C-15 HOISTING AND ROTARY OPERATIONS

1. A driller going off duty shall inform his relief of any special hazards or ongoing work that

may affect the safety of the crew. Oncoming tour personnel shall be alerted by the driller to ongoing work that could affect their safety.

2. The driller shall never engage the rotary clutch unless he is watching the rotary table.

The rotary clutch shall not be engaged until the turntable is clear of personnel and material.

3. Drill pipe or casing shall not be picked up suddenly so that the bottom end whips about,

endangering employees working on the floor. 4. The driller shall never begin hoisting drill pipe until he has ascertained that the pipe is

latched in the elevator or the derrickman has signaled that he may safely hoist the drill pipe.

5. The derrickman shall ensure that the elevators are properly clamped onto all pipe joints

and locked prior to signaling the driller to engage the load. 6. During instances of unusual loading of the derrick or mast, such as when making an

unusually hard pull, only the driller and other essential supervisory personnel shall be allowed on the rig floor; and as well, no one shall be allowed in the derrick or mast. Such precautions shall always be undertaken when loading exceeds ninety percent (90%) of the manufacturer's rated load for the derrick or mast or any component of the hoisting gear, or attached drilling or casing string.

7. Personnel shall never be permitted to stand in front of hoisting drums or line spoolers; slack line may form and entangle the personnel standing there.

8. Personnel shall never stand near the well bore when any wireline device is being run. 9. Hoisting control stations shall be kept clean and the controls labeled as to their function. C-16 SLIPS

1. All slip handles shall be in place, in good condition, and not project beyond the rotating

top of the turntable. 2. Slips shall be inspected by RIG OPERATOR personnel before each trip to check for

worn dies, keeper pins, presence of retaining ring, worn hinge pins, rib cracks, and segment deformation.

3. The tapered side of the slips shall always be lubricated to facilitate slip removal. 4. No one shall be allowed to kick the slips into place when tripping.

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5. Slips shall not be allowed to ride the pipe while tripping out. 6. The RIG OPERATOR must not, for any reason, allow other than the proper size slips

to be used. 7. No field welding shall be permitted on slips which have been heat treated. C-17 HOISTING LINES

1. The working load on hoisting lines, chains, slings, and fittings shall not exceed the safe

working load recommended by the manufacturers. 2. Ton-mile records shall be maintained by the toolpusher for all drilling lines. Drilling lines

shall be slipped and cut according to established RIG OPERATOR policy unless the line develops unusual wear, damage, or wickering before it is due to be slipped and cut. When the wire rope is slipped and cut, it shall be recorded on the tour report as to date and length of wire rope removed.

3. In no event shall the hoisting line or sand line be allowed to remain in service if it shows

evidence of kinking, crushing, cutting, wearing, bird caging, or unstranding. 4. Hoisting lines shall be securely fastened to every winding drum and at least five full

wraps of wire rope shall remain on a drum when the traveling block is in its lowest position.

5. Knots or cable clips shall not be used as stoppers on rope ends which pass through an

opening in a winding drum.

6. Before the hoisting line is removed from a drum, the traveling block shall be laid on the derrick floor or held suspended by means of a separate wire rope adequate to support the load.

7. A hoisting line under load shall never be allowed to come in direct contact with any

derrick member, stationary equipment, or material in the derrick unless specifically designed or intended for line contact.

8. A dead-line anchor for a drilling line shall be so constructed, installed, and maintained

that its strength shall at least equal the working strength of the hoisting line. 9. All safety pins shall be kept in place at the outer periphery of the drilling line anchor to

prevent the line from jumping off the anchor during slack loading. 10. Excess drilling line shall always be kept properly protected and spooled. 11. A cable cutter shall be available on the rig for cutting the drilling line. The use of a

cutting torch for cutting the drilling line is prohibited. 12. Making loops or eyes in wire rope should be avoided, use manufactured slings. If used,

clips shall be installed with U-bolts on the dead or short end of the rope. 13. The number of cable clips shall be according to the following table. The minimum

spacing between clips shall be six times the diameter of the wire rope.

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CABLE CLIPS

ROPE DIAMETER

(Millimeters)

ROPE DIAMETER

(Inches)

NUMBER OF CLIPS

11 to 15.9

7/16 to 5/8

3

19 to 25.4

3/4 to 1

4

28.6 to 31.7

1 1/8 to 1 1/4

6

34.9 to 44.4

1 3/8 to 1 3/4

7

50.8 to 57.2 2 to 2 1/4

8

63.5

2 1/2

9

14. All clip bolts shall be retorqued after new clips have been in use one hour. 15. The use of "Flemish eye", "farmer's eye", or "rig operator's standby", or any other knot

shall not be permitted in any wire rope. Knots in wire rope often lead to premature failure.

C-18 RIDING HOISTING EQUIPMENT

1. Derrickman and other personnel required to work in the derrick or mast shall ascend and descend the derrick or mast by means of the ladder provided. Riding the pipe hoisting gear is forbidden.

2. No personnel shall slide down any pipe, kelly hose, cable, or rope line other than the

escape line in an emergency. 3. In an emergency, personnel may be lowered from the derrick by means of the traveling

blocks or catline. In this case the rotary table shall be stopped and an experienced person, designated by the RIG OPERATOR, shall operate the controls.

4. The use of a boatswain’s chairs is prohibited. The use of riding type safety belts is

permissible for duties, such as inspection or lubrication, that require a person to work in an elevated position. This is allowed if, in the judgment of the senior RIG OPERATOR supervisor, a higher risk of personnel injury would be incurred by workers erecting and working on scaffolding than by hoisting or lowering a man in a riding belt. When a person is to be hoisted or lowered in a riding belt, the following conditions must all be met:

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(a) Any personnel to be hoisted must be familiar with the task to be performed and be willing to perform the task. No person can be compelled to ride or work from a belt.

(b) The riding belt used must be of such design that no effort is required by the person being hoisted to remain inside the belt and in an upright position.

(c) The hoisting mechanism must have controls which allow the speed of ascent or descent to be controlled by the hoist operator, have a positive brake or lock that will automatically stop and suspend a load at any instant the hoist controls are released, and the hoist operator must be experienced in the operation of the hoist. Use of a cathead to hoist personnel is specifically prohibited.

(d) A meeting shall be held immediately prior to the hoisting operation to review the task to be accomplished. A means of communication must be established between the person being suspended in the riding belt and the hoist control operator. All lifting and lowering shall be at the direction of the person suspended in the riding belt, NOT the hoist control operator.

(e) All hand tools carried by the person suspended in the riding belt shall be attached to the riding belt by safety lines to prevent them from falling should they be dropped.

(f) All other operations on the rig, such as the rotation of the kelly, should be suspended while personnel are working from a hoisting line.

C-19 ELEVATORS

1. Elevators shall be equipped with a positive latch or safety latch combination designed to

prevent drill pipe or other tubular goods from prematurely disengaging. 2. Drill pipe, casing, and tubing elevators shall be provided with a complimentary (to the

elevator latch) collar or protrusion designed to prevent elevator links or latches from becoming accidentally disengaged.

3. With the exception of the latch handles, elevators shall be free of projections that could

catch on the derrick structure or rigging equipment. 4. Elevators shall be inspected by RIG OPERATOR personnel before each trip to ensure

that they are in good operating condition. If defects are found, elevators shall be removed from service until repaired or replaced.

5. When the kelly is in the rathole, the swivel bail shall be positioned so that it does not

interfere with or damage the elevators during tripping operations. C-20 MANUAL TONGS

1. Each rotary tong shall be attached to the derrick or a backup post by means of a wire

rope snub line. The breaking strength of the snub line shall be above the capacity of the pull that is exerted on the tongs by means of the automatic cathead. Both ends of the

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snub line shall be secured by the required number of wire rope clips, properly installed, or other equivalent fittings. (Refer to Section C-17 on "HOISTING LINES")

2. Tong backup posts, kelly pull-back posts, tong backup lines, and safety lines shall not

be secured to derrick or mast girts or to derrick or mast legs unless the legs are so constructed and the lines so attached that the stresses imposed will not result in structural damage to the legs.

3. The wire rope and connections on tongs shall be frequently inspected for wear, broken

wires, and wire rope rot, and shall be replaced when necessary. 4. Tong dies shall be inspected regularly by RIG OPERATOR personnel and replaced as

they become damaged or worn. 5. Die keepers shall always be kept in place to prevent dies from becoming displaced from

the retainer grooves. 6. All threaded hinge pins shall be equipped with a nut and cotter pin. 7. Tongs shall be inspected and greased by RIG OPERATOR personnel before each trip. 8. Tongs that fail to latch properly because of worn jaws, hinge pins, or other defects shall

be removed from service until either repaired, rebuilt, or replaced. 9. No field welding shall be done on tongs which have been heat treated. 10. RIG OPERATOR personnel shall handle the tongs only by the appropriate handles. 11. When not in use, tongs shall be hooked back on the rig floor in such a manner as to

present no obstruction to personnel passing between the tongs and the rotary table.

C-21 TONG COUNTERWEIGHTS

1. A tong counterweight above a derrick floor, when not fully encased or running in

permanent guides, shall be held to the frame of the derrick with a wire rope safety line, not less than 15.9 millimeters (5/8 inch) in diameter, which will prevent the counterweight from coming within 2.4 meters (8 feet) of the floor.

2. The wire rope connecting a tong to a counterweight shall have a minimum diameter of

12.7 millimeters (1/2 inch). C-22 MAKING UP AND BREAKING JOINTS

1. Spinning chains shall not be used. 2. The rotary table shall not be used for the final making up or initial breaking out of a pipe

connection. The potential forces that can be delivered by the rotary table far exceed the breaking strength of the safety or snub lines used to restrain the tong handles. When the snub or safety line breaks, the contained energies are suddenly released and the tong handles whip around the drill pipe.

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3. The snapping up of a tool joint by using an automatic cathead or pipe joint breaker of

the jaw-clutch type, which automatically disengages its clutch at the completion of the fixed stroke, shall not be permitted.

C-23 MUD BUCKET OR SAVER 1. Whenever a wet joint or stand of pipe or tubing is being broken and disconnected

above a derrick floor, a mud bucket or mud saver shall be used to carry all liquids away from the rig floor to the mud tanks or sump.

2. The mud bucket or mud saver shall be checked regularly to ensure that the rubber seals

are in good condition, latches are working properly, and that it is safely suspended in the derrick in such a manner that it can be easily moved to and from the drill pipe.

C-24 POWER TONGS

1. The control device on power tongs shall be either designed or guarded to prevent

accidental activation. 2. The discharge end of hoses used on power tongs shall be disconnected before any

repair, replacement, or other similar work is done on tongs, chains, dies, or other component parts.

3. High pressure lines (hydraulic or air) shall have a safety pressure relief valve that shall

never be set higher than the manufacturer's specifications for the working pressure of the lines or valve.

C-25 RACKING PIPE IN DERRICKS

1. Whenever drill pipe, drill collars, or tubing are racked in a derrick, provision shall be

made for the complete drainage of any fluids or gases in the stands. 2. Drill pipe, collars, or tubing shall be racked to safely distribute the load in the finger

boards. 3. Stands of drill pipe, drill collars, tubing, casing, and rods shall be secured at the top

ends by means of a tie-back rope or an equivalent device to prevent them from falling out of or across the derrick.

4. A pipe hook or tag line shall be available for use by the derrickman to assist in

maneuvering, stacking, and securing pipe in the derrick. 5. If pipe hooks are used above the derrick floor, the pipe hook shall be secured to the

derrick in a manner that will prevent the hook from falling. C-26 FINGER BOARDS

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1. Fingers, finger boards, and finger braces shall be installed in the derrick or mast in a workmanlike manner to safely withstand the stresses imposed on them by pipe or other tubular equipment racked in the derrick or mast. Fingers shall be kept in good repair, free from bending, cracks, or other defects.

2. The unsupported ends of the monkey board fingers shall be connected to the monkey

board frame with a wire rope or chain of sufficient strength to hold the weight of the fingers in case of failure.

C-27 STABBING PLATFORMS AND BOARDS

1. The RIG OPERATOR shall ensure that each drilling rig is equipped with a safe stabbing

platform for the stabber to use when running casing, tubing, or during well servicing operations.

2. The stabbing platform shall not be located opposite the V-door if there is a likelihood

that either the stabber or the platform could be struck by a joint of casing as it is being pulled into the derrick.

3. Before casing is to be run, the stabbing platform shall be inspected by the rig mechanic

to ensure that the platform is in good operating condition, free from damage, lubricated, and all safety devices working.

4. Each fold down extension platform shall be either counterbalanced so that a minimum

amount of force is required to lift the platform, or the platform must be powered. 5. Every pneumatic or electric powered stabbing platform shall be equipped with:

(a) An automatic fail-safe brake.

(b) Shock absorbers at the bottom of the track that will withstand maximum speed

descent into the stop without damage.

(c) The safe working load (SWL) marked on the platform.

(d) Upper and lower travel limit switches.

(e) Standard guard rail, intermediate rail, and toeboard protection on each side and back of the platform.

(f) A non-skid floor surface. (g) A rail assembly that is securely fastened to the rig structure. (h) A platform control lever that automatically returns to the neutral position when

released.

(i) A secondary safety system to support the carriage if the winch or winch cable fails.

(j) A belly-belt for the stabber on the platform.

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(k) A fixed ladder for access to and exit from the platform. 6. Any electrically operated stabbing platform shall meet the requirements of the electrical

classification for the area in which it is located. 7. Each stabbing platform on a rig shall be installed, used, and maintained according to the

manufacturer's instructions. 8. In those areas where hydrogen sulfide is a possible hazard, breathing air shall be

available for personnel on the stabbing platform. 9. On onshore workover rigs where only a stabbing board can be used, the board shall

consist of at least one 7.6 centimeters (3 inches) by 30.5 centimeter (12 inch) construction grade lumber or metal plank of the same width or and strength.

10. When lumber is used for a stabbing board, expanded metal or a wire rope shall be

fastened to the underside of the plank across its full width. 11. Each end of a stabbing board shall be fastened to the derrick or mast with a wire rope

at least 12.7 millimeters (1/2 inch) in diameter. 12. On single stand rigs where there is insufficient room for 30.5 centimeter (12 inch) wide

stabbing boards, a special stabbing board shall be designed and used. 13. Personnel shall not be allowed to stand on the girts to stab casing.

C-28 SAFETY BELTS AND HARNESSES

1. When working 3.1 meters (10 feet) or more above the derrick floor, personnel shall use

a safety harness attached to a lifeline adequately secured to the structure, unless they are protected by another approved method.

2. Personnel engaged in racking pipe at the monkey board, rod board, or other platform

shall be provided with and shall wear a safety harness fitted with shoulder straps, and the shoulder straps shall be in place at all times.

3. The lifeline attached to the safety harness shall be at least 15.9 millimeters (5/8 inch)

manila rope, in good condition with no splices. It shall be securely fastened to the derrick.

4. The safety harness lifeline at the stabbing board shall be securely attached to the derrick

structure. 5. Synthetic rope shall not be used as a substitute for manila rope. 6. Safety harnesses and lifelines shall be maintained in good condition. Damaged

harnesses or lines shall be replaced immediately. 7. A spare safety harness in good condition shall be available for use on every rig.

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C-29 BLOWOUT PREVENTERS

1. Blowout preventors and ancillary equipment shall be installed, used, maintained, and tested as prescribed in the "ARAMCO BLOWOUT PREVENTION STANDARDS" unless specified differently in the approved drilling or workover program for the work in progress.

2. During the installation of the blowout preventor assembly, no personnel shall be

permitted or required to be in an area where they may be injured due to the swinging or dropping of the blowout preventor assembly. Tag lines shall be used for initial alignment and control until the BOP and wellhead flange are within 2.5 centimeters (1 inch) of mating. In those cases where the structural arrangement of the rig and wellhead are such that the exact position of the BOP stack relative to the wellhead can only be determined by an observer, it is permissible for a single observer to approach the wellhead for the purpose of directing the movement of the BOP. All other personnel are to remain clear of the BOP stack until directed by the person in charge to rest the stack on the wellhead.

3. When removing blowout preventors from the wellhead, either tag lines, tugger lines, or

other equipment shall be utilized to control BOP stack movement. Until the stack is securely at rest, all personnel shall remain a safe distance from it in case it should suddenly rotate or fall.

4. Wire rope, not chains, shall be used to lift preventors, diverters, and stack assemblies. 5. To avoid sudden overturning of the equipment when being moved lifting lines shall be

attached well above the center of gravity of the BOP.

6. When BOP stacks are installed on a wellhead, they shall be braced to prevent lateral or vertical movement that could impair the integrity of the wellhead structure, four turnbuckles attached to the rig substructure are normally required.

7. The accumulator unit shall be regularly inspected by RIG OPERATOR personnel to

ensure that the required pressure is being maintained, the gauges are in good working order, and the unit is free from leaks and spills.

8. Areas around the blowout preventor controls shall always be kept clear, unobstructed,

and well-lighted. 9. The accumulator shall be located at least 100 feet from the well bore for exploratory

and Khuff gas wells and 60 feet from the wellbore for development oil wells. Also, it should be shielded using corrugated metal, or equivalent, to provide protection for the accumulator and its operator, not only from the wellhead and other operations around the rig but from raining liquids as well.

10. There shall be at least two sets of controls for operating the accumulator. The master

controls shall be at the accumulator, and the remote controls shall be located on the rig floor where they are accessible to, and visible by, the driller.

11. All operating controls shall be clearly marked according to their function and ram sizes.

Accumulator controls shall be in either the open or closed position, not in the neutral position.

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12. Welding is not permitted on BOP's. 13. Hydraulic lines from the accumulator to the BOP's shall be either steel pipe or approved

equivalent armored hose. 14. The RIG OPERATOR shall train all crew personnel in the proper operation of BOP

equipment in emergencies. Such training shall be according to the "ARAMCO BLOWOUT PREVENTION STANDARDS", plus any additional training the RIG OPERATOR may direct. The RIG OPERATOR shall also ensure that all its floor personnel are capable of timely response to situations requiring the use of BOP equipment, and that emergency procedures for drills and actual emergencies are conspicuously posted in the doghouse.

15. The RIG OPERATOR will conduct BOP drills on each rig often enough for each

member of each crew to experience one drill per month. These drills shall be entered into the driller's log.

C-30 SAFETY VALVES

1. All required safety valves (ball type) and inside BOP's (check valve type) with tool joint

O.D. and the largest available bore plus any necessary subs to fit drill collars, drill pipe, or tubing in use, shall be kept on the rig floor at all times.

2. All safety valves, inside BOP, and subs, as well as closing wrenches and setting tools,

shall be stored (valves open) in a highly visible and convenient permanent location. 3. An additional small size safety valve and inside BOP shall be required with a tapered

drill string. THE SAFETY VALVE SHALL ALWAYS BE INSTALLED FIRST, PROPERLY MADE UP AND CLOSED, BEFORE INSTALLING THE INSIDE BOP.

C-31 WEIGHT INDICATORS

1. Every drilling rig shall be equipped with a reliable weight indicator that is readily visible

to the driller. 2. When the weight indicator is hung above the rig floor, it shall be secured by means of a

wire rope safety line. C-32 TEST PLUGS

1. Every test plug used above a derrick floor shall be attached to the links by a wire rope

safety line. C-33 RIG TANKS OR PIT ENCLOSURES

1. Rig tanks or pits used for the circulation of drilling fluids containing flammable material

shall be protected from sources of ignition.

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2. When rig mud tanks or pits are enclosed, adequate mechanical ventilation shall be provided.

3. Any rig tank including void tanks, ballast tanks, bilge tanks, etc., are enclosed spaces

and no personnel shall be required or permitted to enter without following established procedures for confined tank entry. (Refer to Section B-32, "CONFINED SPACES")

C-34 PRESSURE RELIEF DEVICES, RIG MUD PUMPS, PIPING, AND HOSES

1. A pressure relief device shall be installed on all power driven rig mud pumps that

directly service the drilling or maintenance of the well. There shall be no valve between the rig mud pump and the pressure relief device.

2. The pressure relief device shall be set to discharge at a pressure not in excess of the

manufacturer's recommended maximum working pressure of the rig mud pumps and all connecting pipes and fittings.

3. Shear pins used in pressure relief devices shall be those specified by the manufacturer.

Tools, welding rod tips, etc., shall not be used for shear pins. 4. All pressure relief devices of the shear pin type shall be provided with guard or barrier

placed around the shear pin and spindle of the device. 5. All fluids or materials discharged through a pressure relief device shall be piped in a

direction that will not endanger workers. 6. There shall be no valve in the discharge opening of a pressure relief device or in the

discharge pipe connected to it.

7. The piping connected to the pressure side and discharge side of a pressure relief device shall not be smaller than the normal pipe size openings of the device.

8. The piping on the discharge side of the pressure relief device shall be adequately

secured to prevent movement during discharge. 9. The pressure relief devices lines shall be flushed at the beginning of each well or on a

monthly basis. 10. The piping from the discharge side of the pressure relief device shall be continuously

sloped downward to the suction pit in order to drain liquids. 11. All mud guns used for jetting shall be securely anchored. 12. Quick-closing valves shall not be used on the discharge line from a positive

displacement type mud pump. 13. Clamps and wire rope safety lines or chains shall be used to fasten a kelly hose at the

stand-pipe end to the derrick and at the swivel end to the swivel housing. The safety chains shall never be attached to the goosenecks as they are subject to washing out and may be the point of failure.

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14. Mud line system hoses, which may be subject to whipping in case of failure, shall be equipped with clamps and wire rope safety lines or chains of sufficient strength and secured to an adequate support.

C-35 CELLARS

1. Cellars for onshore rigs that are 1 meter (39.4 inches) or more in depth shall be

provided with a safe means of access and exit, (i.e. ladder, stairs, ramp, etc.). Barrier protection shall be provided around open cellars.

2. Every cellar and means of entry and exit shall be soundly constructed and shall be kept

in a safe condition. 3. Because of the hazards of hydrogen sulfide, flammable gases, and oxygen deficiency,

the atmosphere of the cellar for onshore rigs shall be tested by a competent person designated by the RIG OPERATOR before any personnel are permitted to enter.

4. When personnel are required to work in a cellar, the cellar and the exits from it shall be

kept reasonably free from water, oil, drilling fluid, and other substances that may endanger the personnel.

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SECTION D: SPECIAL OPERATIONS D-1 CRANE OPERATIONS

1. The RIG OPERATOR is responsible for crane operations at Saudi Aramco drilling and

workover locations. This responsibility includes, but is not limited to, ensuring the following: (a) Each operator of a crane or other hoisting device must be thoroughly trained

and properly licensed to operate that equipment. The required licenses are (1) a valid Saudi Arabian Government crane operator's license for the type equipment being operated, and (2) a Saudi Aramco crane operator's license.

(b) Each crane, mechanical hoisting device, or other associated equipment, must have a current Saudi Aramco inspection sticker. Using a crane that has received a "REJECTED" sticker from a Saudi Aramco crane inspector shall be considered as placing any personnel on that location into an IMMINENT DANGER situation.

(c) All crane operations shall be directly supervised by the RIG OPERATOR supervisor in charge at the location. The direction of sitting the crane on a stable bed, rigging of the load, movement of the load, and landing of the load shall be the responsibility of the RIG OPERATOR supervisor in charge. The RIG OPERATOR supervisor in charge can delegate this responsibility but he shall be accountable for any mishap that may occur due to error such as improper rigging, faulty direction, or operator miscalculation.

2. The RIG OPERATOR supervisor in charge shall read and be completely familiar with

the requirements of all Saudi Aramco written safe crane operations procedures and general instructions. This material consists of G.I. 7.025, G.I. 7.026, G.I. 7.027, G.I. 7.028, G.I. 7.029, and G.I. 7.030, plus the Saudi Aramco Crane Safety Handbook and the Saudi Aramco Construction Safety Manual Section III. Copies of this material is available through Saudi Aramco Drilling and Workover Operations or Dhahran Area Loss Prevention Division.

3. Rated load capacities, recommended operating speeds, special hazard warnings, and

any instructions such as those describing use of outriggers, shall be in a language readily understood by the crane operator and conspicuously posted on all equipment. Instructions or warnings shall be visible to the operator while he is at this control station.

4. All crane controls shall be properly marked to show their function. 5. Crane operators shall follow lifting directions ONLY from assigned signalers.

However, an "emergency stop" signal from anyone on the location must be obeyed immediately.

6. The crane directors shall use the international standard hand signals. 7. A durable chart showing these hand signals shall be conspicuously posted in the cab of

each crane. 8. Crane windows shall be kept clean and free from defects that could affect visibility.

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9. All safety devices provided on cranes such as boom stops, boom angle indicators, and anti-two-blocking switches shall be kept in proper working order.

10. All lighting installed on a crane by the manufacturer, including boom lights, travel lights,

instrument panel lights, and warning lights shall be properly maintained and used. 11. Before attempting any lift with a crane, RIG OPERATOR shall first determine the

weight of the load. No lift shall be attempted if load is beyond crane’s rated lifting capacity as listed on chart for current boom angle, radius, configuration, and position of outriggers.

12. Onshore mobile cranes shall not be permitted on any drill site if the fully extended crane

boom or load line can contact an electric power line FROM ANY POINT ON THE DRILL SITE.

13. Until SCECO authorities indicate that a line is not an energized line, and it has been visibly grounded, any overhead wire shall be considered to be energized.

14. Cranes shall not be used for dragging loads sideways. 15. Each crane hook shall be provided with a safety latch. 16. All cranes shall be equipped with a horn. Offshore cranes shall also be equipped with a

two-way means of communication. 17. Personnel shall never be permitted to ride the hook or ball of a crane. 18. Tag lines shall be used to guide and steady equipment being loaded or unloaded. 19. Floating cranes and floating derricks shall meet the applicable requirements for design,

construction, installation, testing, maintenance, and operation as prescribed by the manufacturer.

20. An approved life vest shall be worn by the operator of any crane operating over water. 21. Deck cranes shall be shut down and cradled when wind speeds exceed 32 knots (20

mph). Use of a crane in wind speeds shall be restricted to emergency operations only and the proposed use shall be thoroughly reviewed and approved by the senior on-site RIG OPERATOR’s supervisor.

22. Winds speeds shall be monitored at all times by the control room operator on offshore

rigs. 23. All crane operations shall be suspended during any helicopter movement on or around

an offshore rig.

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D-2 RIGGING, MATERIAL HANDLING AND SLINGS SEE ALSO: CONSTRUCTION SAFETY MANUAL, SECTION III, PART 2.0 ‘SLINGS AND LIFTING GEAR’

1. The operator of any vehicle, such as cranes, loaders, bulldozers, forklifts, or tractors,

shall not move the vehicle or otherwise manipulate its equipment until signaled to do so by the designated signalman.

2. The signalman shall ensure that no personnel are in the path of the vehicle or load. 3. For any equipment that may slide or roll off a loaded truck or trailor, the lifting slings

and hoist line must be attached and the slack taken out before the tie down securing devices are removed.

4. Personnel shall not ride on any load or part of a load being raised or lowered. 5. A tag line shall be used to control the movement of a load being raised or lowered. 6. A tag line shall be long enough for the worker controlling it to avoid being struck by any

movement of the load. 7. Personnel shall not be required or permitted to work, stand, or pass under a suspended

load.

8. Personnel shall not be permitted to work, stand, or pass between the winch mechanism and a load being winched, nor in an area where the worker may be injured due to winch line or winch line mechanism failure.

9. Personnel shall not be required or permitted to work, stand, or pass within the length of

a cable under tension. 10. The working load on winch mechanisms, gin poles, hoists, lines, slings, grommets,

hooks, and fittings shall not exceed the safe working load (SWL) recommended by the manufacturer. SWL shall be displayed on each device.

11. Winch mechanisms, lines, slings, grommets, hooks, and fittings shall be thoroughly

inspected by the operator of the equipment before use for evidence of overloading, excessive wear, or damage. Any rigging equipment found to be defective shall be immediately removed from service and either repaired or destroyed.

12. The safe working load (SWL) of a sling shall be marked on the sling. If the SWL is

exceeded the sling shall be taken out of service and destroyed per G.I. 7.02, ‘Wire Rope Slings.’

13. When using slings, softeners shall be provided between the sling and sharp unyielding

surfaces of the load to be lifted. 14. A sling shall not be pulled from under a load when the load is resting on the sling.

Cribbing consisting of cut drill line, lumber, etc., shall be used to support the load and provide a space for sling removal.

15. In order to eliminate shock loading, all slack in the sling shall be taken up carefully by

the crane operator before beginning the lift.

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16. When using other than single leg slings for straight vertical lifts, the rigger shall be aware

of the loading changes that occur when different hitches are used (i.e., basket, choker, etc.) or when the angle of loading is changed in multiple leg bridle slings.

17. When using a choker hitch, the sling shall be equipped with either a protective thimble,

protector arc or sliding choker hook in order to reduce wear and abrasion at the point where the loop contacts the sling body.

18. When not in use, slings shall be stored in such a manner that will protect the slings from

damage by moisture, extreme heat, corrosion, or physical abuse. D-3 DRILL STEM TESTING

1. Initial flowing of formation fluids to surface during a drill stem test shall be restricted to

daylight hours only. 2. During drill stem testing or the removal of pipe after a drill stem test, the Rig Supervisor

or some other equally qualified person shall remain on the rig and shall exercise continuous supervision over all operations.

3. When oil or gas or both have been encountered during a drill stem test, the drill stem contents should be replaced with drilling fluid. Fluid recovered from the mud saver shall flow back to the tanks or to a reserve pit.

4. During drill stem testing, motors and engines not required in the operation shall be shut

off. All engine exhausts shall be equipped with water sprays or spark arrestors for spark suppression. The RIG OPERATOR shall ensure that water on engine exhausts is shut off when engines are not operating.

5. During drill stem testing, no motor vehicle shall be permitted within 22.9 meters (75

feet) of the well bore. D-4 SWABBING

1. Swabbing operations shall not be carried out during the hours of darkness. 2. Auxiliary swabbing units shall be anchored securely during swabbing operations. 3. Where swabbing tanks are not provided with an external means of gauging, any

personnel physically gauging the tanks shall be provided with, and shall wear, approved respiratory protective equipment. In addition, they shall be continuously monitored during this procedure by another person.

4. Oil savers shall be equipped with controls which can be readily operated from the rig

floor. 5. During swabbing operations, the fluids shall be piped directly to a battery, flare pit, skid

tank, or mobile trailer tank located 45.7 meters (150 feet) or more from the well bore.

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6. The air intake and exhaust of the pump engine shall be located 7.6 meters (25 feet) or more from the rig tank when a well is being circulated with hydrocarbon or hydrocarbon based fluid.

7. During loading or unloading, the tank truck exhaust shall be located at a distance of not

less than 7.6 meters (25 feet) from the rig fuel tank and a minimum of 22.9 meters (75 feet) away from the well bore.

8. Fluids used in or as a result of swabbing operations shall not be piped to a tank truck

under any circumstances. D-5 CEMENTING

1. During cementing all piping systems which will be exposed to either pump or well

pressure shall be securely staked down or secured in such a manner as to prevent any undue whipping or flailing of the pipe if a failure occurs.

2. The cementing head shall be secured to the elevator links (bales) with a wire rope safety

line. 3. The leadoff chicksan from the cementing head shall be secured to either the head or

elevators with a wire rope safety line.

4. After completion of cementing work, all cementing lines shall be flushed with fresh water.

D-6 WELL SERVICING AND WELL STIMULATION

1. During drill stem testing and well stimulation, all piping systems, which will be exposed

to either pump or well pressure, shall be securely staked down or secured in such a manner as to prevent any undue whipping or flailing of the pipe should a failure occur.

2. Swivel joints provided with lugs for hammer tightening shall not be used in a well

servicing operation unless they are manufactured from steel. 3. Hammering or tightening of unions or connections while under pressure shall not be

permitted. 4. Any tool or equipment other than normal drilling equipment, which is connected to the

top of the drill string, casing, or tubing while it is in the hole, shall be secured against falling by means of a wire rope safety line or safety chain.

5. All piping, pumps, valves, and fittings used in servicing operations shall be hydraulically

pressure-tested prior to the commencement of each well cementing or servicing operation. Subsequent pumping pressure shall not exceed the test pressure.

6. On any well service job involving pressure only the minimum number of people

necessary to perform the task shall be exposed to the equipment under pressure. 7. Before transferring hydrocarbons, all pumps, tanks, and trucks shall be bonded together

and electrically grounded.

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8. No vehicle shall be allowed to cross surface flowlines on a location. D-7 STRIPPING AND SNUBBING

1. An emergency escape system shall be provided for personnel working atop hydraulic

snubbing equipment. 2. Prior to starting snubbing operations, the snubbing tower shall be guyed according to

the manufacturer's specifications to prevent it from collapse or turnover. 3. Flow lines or bleed-off lines shall be located away from areas frequented by personnel

and adequately secured to prevent whipping or flailing if these lines should burst. 4. Gasoline engines shall not be used on snubbing operations. 5. Diesel engines used for snubbing operations shall be equipped with spark arrestors and

located a sufficient distance away from the wellhead to ensure that any inadvertently released well fluids do not come in contact with the engines.

6. Two-way communications shall be provided between the snubbing operator and the

pump operator. This may be accomplished by hand signals, voice communication, or other effective means.

7. A safe means of access shall be provided to the tower platforms. 8. Well surface pressure shall be monitored at all times during stripping and snubbing

operations. 9. All personnel involved in a stripping operation shall be informed of the maximum

working pressure that is safe for the work. The RIG OPERATOR shall provide blowdown lines with remote control valves as needed to relieve pressure from the wellhead equipment if the working pressure exceeds the established limit.

D-8 FLARE PITS AND FLARE LINES

1. A reliable and safe means of remote ignition shall be provided when hydrocarbon gases

are released to the atmosphere through a flare system. 2. No personnel shall enter a flare pit to light the flare or any waste material therein. 3. When lighting a flare pit, the lighting shall be done from the upwind side. 4. When there is no wind or when the wind direction is uncertain, no attempt shall be made

to light the pit unless the man can locate himself in a position known to be free of flammable concentrations of gases or vapors.

5 All sources of ignition in the flare pit and surrounding areas shall be extinguished while any vessel is being completely drained to the flare pit, unless the system is designed and constructed to prevent flashback.

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6. All lines connecting any vessel to a flare pit shall be blanked off before any work is performed within the vessel.

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SECTION E: OFFSHORE E-1 OVERWATER OPERATIONS

1. When work is performed over water, the RIG OPERATOR shall instruct all personnel

in the proper water entry and survival procedures to be used. 2. While working over water an emergency means of escape from platforms shall be

provided. 3. U.S.C.G. or U.K.D.I.T. approved life preservers and buoyant work vests (personal

flotation devices (PFD's)) shall be readily available on an offshore rig or platform. 4. Oil-soaked or otherwise damaged personal flotation devices (PFD's) shall be removed

from service and destroyed. 5. Approved PFD's shall be worn:

(a) When being transported by personnel basket between an offshore drilling rig or

platform and a crew boat.

(b) When performing work from a work basket that is suspended over water.

(c) When moving either a blowout preventor or a diverter stack on or off the wellhead where the suspended work platform on which personnel are working is over open water.

(d) When being lowered to the water in a davit-launched life raft, life boat, survival craft, rescue craft, or inspection boat.

(e) When being transported by helicopter over water.

6. Employees wearing PFD's shall keep them snugly fitted and securely fastened. 7. Decks of all rig platforms shall be kept clean of oil, grease, debris, and free of all excess

equipment that poses a tripping or fire hazard. 8. Wireline units, power packs, tool boxes, and other equipment to be transported to or

from offshore water locations shall be securely tied down once the cargo has been loaded on a vessel.

9. It shall be the responsibility of the person skippering a vessel to determine when it is

safe or unsafe to tie up or jack up on a well site. 10. Fire drills, abandon rig drills, hydrogen sulfide drills, and man overboard drills shall be

held by the RIG OPERATOR at least twice each month and recorded on the log or tour report. The RIG OPERATOR shall brief all newly arriving personnel on all emergency procedures.

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E-2 LIFE SAVING EQUIPMENT -- OFFSHORE RIGS

1. There shall always be enough personal flotation devices (PFD's) aboard to provide 125% coverage of persons on board at any time.

2. The PFD's shall be maintained in good condition, U.S.C.G. or U.K.D.I.T. approved,

and labeled with the name of the rig. 3. Spare PFD's shall be stored in marked containers throughout the rig. 4. Each cabin shall be equipped with the proper number of PFD's stored on top of the

lockers. 5. PFD's shall be equipped with salt water activated lights, whistles and reflector tape. 6. Each offshore rig shall be equipped with at least eight ring life buoys maintained in

satisfactory condition, and mounted so that they are easily removable from their brackets.

7. At least one ring life buoy on each side of the offshore rig shall have attached to the ring

a buoyant life line that is at least 1-1/2 times the distance from the deck of stowage to the waterline at low tide and maximum air gap of 27.4 meters (90 feet), whichever is greater. The end of the line must not be secured to the rig.

8. At least four of the ring buoys on an offshore rig shall have a water light attached to the ring, and two of those rings must also be equipped with a smoke signal.

9. All ring life buoys shall be in their proper location, and each shall be marked with the rig

name and port of registry. 10. Escape ladders shall be provided and maintained. 11. Inflatable life rafts and their containers shall be intact and not damaged, rubber seals

shall be free of breakage or damage, and the container bands intact. 12. Operating instructions shall be posted at each life raft. 13. Annual certification by an authorized third party and servicing inspections shall be

required for all life rafts and containers. 14. All life raft containers shall be kept clean and free of oil and gas, and shall be clearly

marked with "inflatable life raft", date of next servicing, and capacity. 15. Access to each raft shall be free of obstructions that would interfere with launching. 16. The cradle for each raft shall be of proper size and the release mechanism kept free of

rust and corrosion. 17. Inflatable life raft containers shall be stored with the top straight up so the drain holes on

the bottom are properly positioned for drainage of any moisture. 18. Temporary lashing bands used in transporting the inflatable life raft containers shall be

removed before stowage on the rig.

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19. The RIG OPERATOR shall ensure that the length of the painter line for each manually

launched inflatable life raft is greater than the distance from the deck of stowage to the waterline at low tide and maximum air gap.

20. The exit point for the painter line shall be pointed aft of the rig when possible to protect

it from the on-coming water during towing. 21. The painter line for each inflatable life raft which is not davit-launched shall have its

external end secured to a strong point on the platform. 22. Each life raft station shall be clearly marked to conform to the Station Bill. 23. Station Bills shall be kept current and posted in conspicuous locations. 24. The launching equipment for davit-launched inflatable life rafts must include:

(a) A means to hold it securely while personnel enter the life raft.

(b) A means to rapidly retrieve the falls if the station has more than one life raft.

(c) The capability of being operated from either the life raft or from the rig.

(d) Winch controls located where the operator can observe the life raft launching.

(e) A system whereby a loaded life raft does not have to be lifted before it is

lowered. 25. Not more than two davit-launched life rafts may be launched from the same launching

equipment. 26. Survival craft and life rafts shall be manufactured to a recognized international standard. 27. The access route and launching platform from which survival craft are to be launched

shall be kept clear of any obstruction that interferes with the immediate launching of the craft.

28. Emergency lighting shall be provided at the launching area and it shall be maintained in

good working order. 29. Each survival craft shall be marked with the number of the craft, name of the rig, port of

registry, and the number of persons allowed in the craft. This marking shall be with letters at least 7.6 centimeters (3 inches) high and in a color that contrasts to the background color of the craft (international orange).

30. The watertight doors of all survival craft shall seal properly in order to maintain

watertight integrity. 31. Spare life preservers shall be stored in a storage box outside both lifeboats. 32. A compass shall be mounted in the craft where it will be readily visible to the operator.

It shall be maintained in good working order.

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33. The gear shift and throttle control shall always be kept in the neutral position until made ready for starting the engines.

34. The salt water inlet valve and fuel shut-off valve shall always be in the open position. 35. The fuel tank shall be kept full. The fuel shall be changed out annually. 36. All survival craft shall be checked weekly and recorded in a log book by a qualified

mechanic to ensure that: (a) Compressed air tanks are full.

(b) Drain plug is in place.

(c) Battery and battery connections are in good condition.

(d) Belts and hoses are in good condition.

(e) Transmission fluid, hydraulic fluid, and oil levels are in the full range of the

dipstick. 37. Emergency lifeboat drills, including launching all motorized survival craft and starting

their engines, shall be conducted monthly.

38. All survival craft engines shall be started weekly and run for no longer than five minutes (or until the engine becomes warm) if the craft is not placed in the water.

39. All emergency supplies required in the survival craft shall be visually inspected weekly to

ensure that they are still safely stored in the craft. 40. Emergency food rations and drinking water in each survival craft shall be replaced prior

to their expiration date. They shall be replaced sooner if the vacuum seal of the container is lost. Signal flares shall be replaced prior to their expiration date.

41. The complete launching system for all survival craft shall be visually inspected weekly by

a qualified mechanic to ensure that the hand stop, wire rope, U-clamps, motor and motor starter, supports, sheaves and blocks, falls, release pins, and limit switches are in good order.

42. When any survival craft is launched in the water during boat drills, the sprinkler system

shall be checked to ensure that it works properly. 43. A survival craft operator and alternate operator shall be assigned to each craft. Both

shall be trained in the operation of the survival craft. 44. Two Transponders (McMurdo Marine Model RT9-3 or equivalent) shall be available

at each lifeboat. 45. Each offshore rig will be inspected by representatives of Saudi Aramco organizations as

required.

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E-3 HELIPORTS AND HELICOPTER OPERATIONS

1. The RIG OPERATOR shall ensure that a fully equipped fire equipment storage box is

available at the heliport for fire fighting and rescue. The contents of this box are listed in Requirement Number B-9-18.

2. Fire-fighting equipment, adequate to control and extinguish the largest foreseeable fire,

shall be available at the heliport. In addition, a 30lb 120B:C UL Listed dry chemical or equivalent, portable type extinguisher shall be located at each exit. This equipment shall be properly maintained for emergency use.

3. Unless the heliport is a continuous extension of a rig deck with unrestricted entry and

exit to it, there shall be at least two exit routes from the heliport. One exit may be designated for emergency use only.

4. Each access to the heliport area shall be marked with warning signs in Arabic and

English saying "Beware of the Tail Rotor". 5. The primary access should have a passenger waiting area at least seven feet below

helideck level. This area should have a passenger briefing sign, a clear deck policy sign, and a scale for weighing passengers.

6. Each shift must have a designated helicopter attendant to meet landing aircraft. The

helideck attendant will wear an orange vest to identify himself. His duties include the following: a. Inform the crane operator to cease operations.

b. Inform the fire and crash rescue team on helicopter operations.

c. Check the helideck for loose objects. d. Obtain the exact weight of passengers, baggage, and cargo and log this

information on the passenger manifest for the pilot.

e. Do not load any cargo until directed by the pilot.

f. Assist passengers in loading and unloading baggage and entering and exiting the aircraft. Assure life vests and seat belts are correctly worn.

7. There shall be a minimum of eight perimeter lights, alternating blue and yellow. These

lights should be not be frangible, and the upper portion of the light guard should be no greater than six inches above the helideck. Exits should be marked with red lights.

8. If the highest points on the rig exceeds the elevation of the helideck by more than fifty

feet, an Omni-directional red light should be fitted at that point, with additional such lights fitted at thirty five foot intervals down to the interval of the flight deck.

9. An emergency power supply should provide power to the perimeter and obstruction

lighting and lighting along heliport access and egress routes.

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10. A rotating or flashing beacon should be installed on the cab of any crane boom that can

reach the helideck. The beacon should be illuminated whenever the crane engine is operating. Crane operators must be knowledgeable about proper procedures to use around helicopters.

11. The helideck safety fence should be at least five feet wide. It should be attached six

inches below the helideck and incline to the outer edge at one to ten. The outer edge must not protrude above the level of the flight deck.

12. Each heliport shall have a minimum of four recessed tie-down points arranged to secure

one helicopter in the middle of the deck. 13. Each heliport shall be constructed so that rain or spilled fluids will drain from the deck. 14. Each heliport should have a windsock that is easily visible to the pilot. It must be

illuminated for night operations and not constitute an obstacle to helicopter operations. 15. The heliport markings shall be in accordance with the Saudi Aramco Offshore Helideck

Standard Drawing # AA-036248 (latest revision). a. A sixteen inch wide stripe to mark the boundary of the load bearing portion of

the helideck surface.

b. A three foot wide rectangular red border to mark the primary stairway opening designating a tail rotor hazard.

c. Aiming circle, twenty feet in diameter and using a sixteen inch wide stripe

containing the "H" designation to mark the center of the helideck.

d. A thirty six inch wide walkway should be marked from the aiming circle to the primary access route.

e. The secondary access route will be used and marked in Arabic and English as an "Emergency Exit'.

f. Limitation markings shall show the maximum allowable weight to the nearest thousand pounds. The helideck dimension is shown to the nearest foot.

g. The rig identification shall be marked on the heliport. h. Obstruction markings are as follows:

1. Any obstruction four feet or higher is a main rotor obstruction and must

have a solid red arc one third the rotor diameter of the largest helicopter expected to land there.

2. Any obstruction six inches or higher is a tail rotor obstruction and must

be marked with a three foot solid red rectangular border. 3. Any obstruction on the deck less than six inches high is a skid hazard

and must be marked with an eight inch red circular band.

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16. Painting requirements are as follows: a. Flight deck - Non skid light gray b. Flight deck border - Yellow

c. Aiming circle - Yellow d. Walkways - Alternating yellow and light gray e. "H" designation - Yellow

f. Limitations - Yellow numbers with black borders g. Identification - Yellow letters with black borders h. Stairway - Red border i. Obstruction - Red arc, rectangle or circle

17. The rig must be equipped with a VHF radio capable of reaching 138.25 and 138.20 to

allow for direct communications with the helicopter. E-4 PERSONNEL TRANSFER: BOAT AND RIG

1. An offshore crane operator shall not be required or permitted to transfer personnel by

personnel basket if the wind force is above 30 knots or the wave height above 1.8 meters (6 feet).

2. Personnel shall be transferred by basket to or from a rig only when visibility is good. 3. The lifting and lowering of personnel in a personnel basket shall be over open water

whenever possible. 4. A safety line shall be used on each personnel basket. The crane hook shall be equipped

with a safety latch. 5. Each personnel basket used for transferring personnel by crane between an offshore rig

and crew boat shall be in good condition, provided with an adequate number of approved life preservers or buoyant work vests. It should be stored out of the way when not being used.

6. The offshore crane operator shall not be required or permitted to transfer more than

four persons by personnel basket each crane trip. 7. When employees are transported by personnel basket, they shall wear approved life

preservers or buoyant work vests. They shall stand on the outer rim of the basket facing inward.

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8. Only light hand luggage shall be permitted inside the personnel basket when the basket is occupied by personnel.

9. Rig supplies shall not be transported by personnel basket at any time.

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LOSS PREVENTION STATISTICS BY ORGANIZATIONS AND DEPARTMENTS Definitions of Statistical Terms Industrial Disabling Injury (IDI): An on-job injury resulting in or more full days away from work, plus on-job fatalities. IDI Frequency: The number of IDI’s for every 200,000 on-job man-hours, including overtime. IDI Frequency = Number of IDI’s x 200,000 On-job Man-hours Restricted Duty Injury (RDI): An on-job injury resulting in one or more full days of restricted duty. RDI Frequency: The number of RDIs for every 200,000 on-job man-hours, including overtime. RDI Frequency = Number of RDI’s x 200,000 On-job Man-hours Off-job Disabling Injury (ODI): An off-job injury resulting in one or more full days away from work. ODI Frequency: The number of ODI’s for every 200,000 off-job man-hours, which DO NOT include nonexposure hours (8 hours per day for sleeping). ODI Frequency = Number of ODI’s x 200,000 On-job Man-hours Motor Vehicle Accident (MVA): Any recordable accident involving a Saudi Aramco fleet vehicle, whether preventable or non-preventable. MVA Frequency: The number of fleet MVA’s for every 1,000,000 kilometers driven. MVA Frequency = Number of MVA’s x 1,000,000 Kilometers driven Note: U-Drive MVA’s are included only in the overall company frequency calculation, not in any organizational frequency calculations. Upper Control Limit (UCL): The UCL is calculated for each category of injury or MVA for a given year and is the average of the experience of the previous three years, minus a 5% improvement factor. All UCL calculations are made during October-November of the previous year (for example, UCLs for 1997 were determined in October-November of 1996). The detailed formulas are available from the Loss Prevention Department’s Technical Services Unit. Safety Performance Index (SPI): The SPI is a combined indicator of performance which relates the current year’s frequency to the UCL (essentially past performance) in each category. SPI = 0.35 (IDI Freq.) + 0.15 (RDI Freq.) + 0.15 (ODI Freq.) + 0.35 (MVA Freq.)

(IDI UCL) (RDI UCL) (ODI UCL) (MVA UCL)

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General Comments 1. Statistics such as UCL’s and SPI’s are means to identify safety-related problems, not an

end in themselves. 2. Do not use UCL’s and SPI’s to compare one organization’s performance with that of

another. These statistics indicate the organization’s performance now with respect to the organization’s performance in the past three years.

3. To compare current performance of one organization with that of another organization, use the frequencies in each category.

4. (a) A Saudi Aramco IDI is equivalent to the US Occupational Safety & Health Administration (OSHA) definition of lost workday cases involving days away from work. (b) A Saudi Aramco RDI is equivalent to the US OSHA definition of lost workday cases involving days of restricted work activity.

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DHALPD ED&M LAND RIG INSPECTION CHECKLIST 10/23/01 [CHEKLAND.DOC]

Page 1

DHAHRAN AREA LOSS PREVENTION (DHALPD) RIG INSPECTION CHECKLIST FOR LAND RIGS

DATE: RIG: FOREMAN: WELL NAME:

OPERATION:

PERSONNEL CERTIFICATIONS:

Enter "T" if date entered indicates date training was taken. Enter "E" if date entered indicates date training expires.

POSITION NAME BADGE # BOP FIRST AID H2S OTHER Foreman

Foreman

Toolpusher

Toolpusher

Driller

Driller

POSITION

NAME

BADGE #

SAG ARAMCO

Cert # ARAMCO

Cert Expiry

OTHER Crane Op

Crane Op

Forklift Op

Forklift Op

Dozer Op

Dozer Op

1. Rig Site Accommodations .................2 2. Genset & Engines ............................2 3. SCR Room .......................................2 4. Accumulator ....................................3 5. Mud Pumps.....................................3 6. Mud Tanks......................................4 7. Substructure ...................................4 8. Rig Floor .........................................5 9. Dog House .......................................6 10. Derrick............................................7

11. Catwalk & Pipe Racks .....................8 12. Manifold, Flare Lines, & Flare Pit....9 13. Fuel Tanks......................................10 14. Fire Fighting Equipment .................10 15. Compressed Gas Cylinders ...............10 16. Hand & Power Tools ........................10 17. Welding & Cutting...........................11 18. Cranes & Slings...............................11 19. General ...........................................11 20. H2S Protection (Land Rigs) ..............12

Note: Where applicable, inspection items are referenced to published Aramco policy. "SASR" refers to Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations

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1. RIG SITE ACCOMMODATION YES NO N/A

1-1 ? ? ? Site accommodation trailers located at least 25 metres (75 ft) from well bore

1-2 ? ? ? Power cables to trailers from light plant

suspended or otherwise protected from vehicular traffic

1-3 ? ? ? Electrical junction boxes on trailers weather

proofed, and closed [SASR B-15 (7) p.39] 1-4 ? ? ? Electrical cords and fittings free of defects [SASR

B-15 (1) p.38] 1-5 ? ? ? Protective covers on all lights 1-6 ? ? ? ABC fire extinguisher in each trailer 1-7 ? ? ? Escape window or door in sleeping room 1-8 ? ? ? Smoke alarm present and functioning 1-9 ? ? ? For an H2S locations, rig medic or

Toolpusher’s office has an eyewash station [SASR B-6 III F3 p.26]

2. GENSET & ENGINES YES NO N/A

2-1 ? ? ? Grounded to casing or cellar [SASR B-15 (8) p.39 & updated D&WOOD policy].

2-2 ? ? ? Ground cable securely fastened with bolted

clamps [SASR B-15 (1) p.38] 2-3 ? ? ? Buildings bonded together to common ground 2-4 ? ? ? Fans and belts guarded [SASR C-1 (1a) p.45] 2-5 ? ? ? Electrical junction boxes identified and kept in

closed position [SASR B-15 (7) p.39] 2-6 ? ? ? Electrical outlets labeled, voltage identified [SASR

B-15 (7) p.39]

2-7 ? ? ? All knockouts in panels (no open knockouts) [SASR B-15 (1) p.38]

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YES NO N/A

2-8 ? ? ? Electrical cords, plugs, receptacles etc. in good condition [SASR B-15 (1) p.38]

2-9 ? ? ? Switches capable of being locked out

2-10 ? ? ? Lockout procedures in place [SASR B-31 p.43]

2-11 ? ? ? Lights have protective coverings

2-12 ? ? ? Suitable emergency lighting available on location and working [SASR B-16 (7) p.39]

2-13 ? ? ? For H2S locations, 10-pound CO2 fire extinguisher in place [SASR Onshore H2S Std. (IV B-1) p.27]

2-14 ? ? ? Noise hazard sign in place [SASR B-3 (8) p.17]

2-15 ? ? ? Hearing protection provided and used by workers [SASR B-3 (9) p.17]

2-16 ? ? ? Exits free of obstruction [SASR B-7 (1) p.34]

2-17 ? ? ? Floors and equipment free of oil or grease [SASR B-7 (2) p.34]

2-18 ? ? ? Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

2-19 ? ? ? "High Voltage" sign posted [SASR B-15 (9) p.39]

2-20 ? ? ? All engine exhausts equipped with water sprays or spark arrestors for spark suppression [SASR B-15 (2) p.38]

2-21 ? ? ? Auxiliary and emergency standby generators run at full load for 2 hours every week [SASR B-15 (12) p.39]

3. SCR ROOM YES NO N/A

3-1 ? ? ? Emergency lighting installed and working at TWO exits [SASR B-15 (6) p.38]

3-2 ? ? ? Non-conductive mats placed on floor [SASR B-

15 (5) p.38] 3-3 ? ? ? Halon fire extinguisher available (only Halon is

permitted in the SCR room) [SASR B-9 (4) p.35]

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Page 5

4. ACCUMULATOR YES NO N/A

4-1 ? ? ? Located at least 18.3 m. (60 ft) from wellbore [SASR C- 30 (9) p.63]

4-2 ? ? ? Accumulator bottles precharged to 1200 psi

[SASR C- 30 (7) p.63] 4-3 ? ? ? No leaks in system [SASR C- 30 (7) p.63] 4-4 ? ? ? Gauges in good condition and readable [SASR

C- 30 (7) p.63] 4-5 ? ? ? Controls free of any obstruction [SASR C- 30 (8)

p.63] 4-6 ? ? ? Controls in OPEN or CLOSED position, not

neutral [SASR C- 30 (11) p.63] 4-7 ? ? ? Accumulator function tests conducted Date of last

test:__________________ 4-8 ? ? ? Fire extinguisher in place and serviceable 4-9 ? ? ? Compressor free of dirt, grease or oil [SASR B-7

(2) p.34]

5. MUD PUMPS YES NO N/A

5-1 ? ? ? Fans and belts guarded [SASR C-1 (1a) p.45] 5-2 ? ? ? Lubricator pump belt and pulleys guarded

[SASR C-1 (1a) p.45] 5-3 ? ? ? Shock hoses safety chained [SASR C-35 (13)

p.65] 5-4 ? ? ? Pop (relief) valve capped, proper size pins

inserted (set @ _____psi) [SASR C-35 (2, 3, 4) p.64]

5-5 ? ? ? NO valves installed between pump and pop

valve [SASR C-35 (1) p.64]

YES NO N/A

5-6 ? ? ? NO valves installed between pop valve and its discharge [SASR C-35 (6) p.64]

5-7 ? ? ? Discharge line sloped downward [SASR C-35

(9) p.65] 5-8 ? ? ? Discharge line properly secured [SASR C-35

(8) p.65] 5-9 ? ? ? Electrical connections in good condition [SASR

B-15 (1) p.38] 5-10 ? ? ? Used electrical receptacles capped [SASR B-15

(7) p.39] 5-11 ? ? ? Electrical lights have protective covers 5-12 ? ? ? For H2S locations, 30 pound dry chemical fire

extinguisher serviced and in place [SASR B-6 (IV A-3) p.26]

5-13 ? ? ? Sign posted identifying remote startup of

equipment (if applicable) 5-14 ? ? ? Noise hazard sign posted [SASR B-3 (8) p.17] 5-15 ? ? ? Hearing protection provided and used [SASR B-

3 (9) p.17] 5-16 ? ? ? Floor and equipment free of grease, oil and

debris [SASR B-7 (2) p.34] 5-17 ? ? ? No oily rags or tools laying about [SASR B-7 (7)

p.34] 5-18 ? ? ? Housekeeping acceptable, no accumulations that

present a hazard [SASR B-7 (6) p.34]

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Page 6

6. MUD TANKS (Class 1, Div. 1 & 2) YES NO N/A

6-1 ? ? ? All pulleys, belts, couplings on motors properly guarded [SASR C-1 (1a) p.45]

6-2 ? ? ? Eyewash facilities at mixing area serviced and

operable [SASR B-3 (11) p.17; B-6 III F2 p.26] 6-3 ? ? ? Goggles provided at mixing area, and worn

[SASR A-5 (8) p.13; SASR B-3 (4) p.17] 6-4 ? ? ? Respirators provided for employees working

with oil-based mud system 6-5 ? ? ? Degasser installed and vented to flare pit 6-6 ? ? ? Hazardous products (i.e. caustic) used in barrel

mixer or mud tank adequately identified 6-7 ? ? ? Mud products Material Safety Data Sheets

(MSDS) available [SASR B-33 (3, 4, 5,) p.45] 6-8 ? ? ? MSDS stored at _____________ 6-9 ? ? ? Pumps, motors in good condition 6-10 ? ? ? Explosion-proof motors and fittings if applicable

[SASR B-15 (1) p.45] 6-11 ? ? ? Electrical connections, plugs, receptacles, and

lights in good condition and properly sealed [SASR B-15 (1) p.38]

6-12 ? ? ? Lights have protective covers [SASR B-15 (1)

p.38] 6-13 ? ? ? Grommets & electrical cables with proper fit

[SASR B-15 (1) p.38] 6-14 ? ? ? Guard rails in place [SASR C-1 (1b) p.45] 6-15 ? ? ? For H2S locations, 30 pound dry chemical fire

extinguisher serviced and in place at shaker [SASR B-6 (IV A-2) p.26]

YES NO N/A

6-16 ? ? ? Floor coverings in place to prevent tripping or falling [SASR C-1 (1b) p.45]

6-17 ? ? ? Walkways, stairs and platforms in good condition

[SASR C-1 (1b) p.45; SASR C-8 (3) p. 48] 6-18 ? ? ? No tools or tripping hazards on walking/working

surfaces [SASR C-8 (3) p. 48] 6-19 ? ? ? Bottom of stairs within 9" of ground level, and

unobstructed

7. SUB-STRUCTURE (Cl.1, Div. 1&2) YES NO N/A

7-1 ? ? ? Cellar protected from workers falling into it [SASR C-36 (1) p.65]

7-2 ? ? ? BOP properly turnbuckled (4 lines) [turnbuckles

recommended by SASR C-30 (6) p.63] 7-3 ? ? ? BOP scaffolding or working platforms in good

condition 7-4 ? ? ? Kill and choke lines connected, pressure tested 7-5 ? ? ? Fire resistant kill and flare lines 7-6 ? ? ? Steel or approved equivalent armored hose

accumulator lines [SASR C-30 (13) p.63] 7-7 ? ? ? All electrical junction boxes and conduit sealed

[SASR B-15 (7) p.39] 7-88 ? ? ? Electrical equipment and cables in good condition

[SASR B-15 (1) p.38] 7-9 ? ? ? Unused electrical receptacles covered [SASR B-

15 (7) p.39] 7-10 ? ? ? Lights sealed with protective covers [SASR B-15

(1) p.38] 7-11 ? ? ? Guards on pulleys and belts [SASR C-1 (1a)

p.45]

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Page 7

YES NO N/A

7-12 ? ? ? All pins and safety pins in place [SASR C-2 (9) p.46]

8. RIG FLOOR (Class 1, Division 1 & 2 Area) YES NO N/A

8-1 ? ? ? A loudspeaker system is installed that can be heard throughout the working area [SAMIR requirement]

8-2 ? ? ? Two unobstructed exits from rig floor, not

counting the exit leading directly to mud pits [SASR C-8 (2) p.48]

8-3 ? ? ? Doors open outward from floor and dog house

[SASR C-8 (2) p.48] 8-4 ? ? ? V-door closed or chained when not in [SASR C-

8 (8) p.49] 8-5 ? ? ? Handrails in place [SASR C-8 (5) p.49] 8-6 ? ? ? Floor openings covered when not in use [SASR

C-8 (9) p.49] 8-7 ? ? ? Walkways and work areas unobstructed and

clean [SASR C-8 (3) p.48] 8-8 ? ? ? Drawworks and rotary drive guarded [SASR C-

7 (4, 5) p.48] 8-9 ? ? ? Stabbing valves (or crossovers) on floor (or

doghouse) for each thread type used in string 8-10 ? ? ? Handles for kelly cocks and stabbing valve in

easily accessible place 8-11 ? ? ? Rough tread plate installed around rotary table 8-12 ? ? ? Tong dies sharp and die keepers installed

[SASR C-21 (6) p.58] 8-13 ? ? ? Tong body and tong jaws in good condition

[SASR C-21 (5) p.58]

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Page 8

YES NO N/A

8-14 ? ? ? Snub line on each tong [SASR C-21 (1) p.58] 8-15 ? ? ? Tong snub lines in good condition [SASR C-21

(4) p.58] 8-16 ? ? ? Tong snub lines properly triple clamped (or

have factory-made eyes) [SASR C-21 (1) p.58] 8-17 ? ? ? Tong snub lines minimum 5/8 " (15.9 mm)

diameter 8-18 ? ? ? Tong chain in good condition, no evidence of

excess wear, gouging, or grooving 8-19 ? ? ? NO spinning chain installed [D&WOOD SOC] 8-20 ? ? ? Mud can and line installed and in good condition

[SASR C-24 (2) p.59] 8-21 ? ? ? Driller's controls adequately labeled [SASR C-11

(2) p.51] 8-22 ? ? ? Driller's controls adequately guarded [SASR C-

11 (5) p.52] 8-23 ? ? ? Lockouts on rotary and cathead clutches

[DHALPD ED&M recommendation] 8-24 ? ? ? Ends of Driller’s headache post contained [SASR

C-13 (12) p.53] 8-25 ? ? ? Brake handle slotted c/w tiedown [SASR C-12

(3) p.52] 8-26 ? ? ? Brakes in good condition [SASR C-12 (1) p.52] 8-27 ? ? ? Hydromatic, Dynamatic, or El Magco functioning

properly and checked weekly [SASR C-12 (1) p.52]

8-28 ? ? ? Weight indicator safety tied [SASR C-32 (21)

p.64]

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YES NO N/A

8-29 ? ? ? Engine shut-offs working [SASR C-11 (6) p.52] 8-30 ? ? ? Date of last engine kill switch test:___________ 8-31 ? ? ? Slip and cut program in place, documented

[SASR C-18 (2) p.55] 8-32 ? ? ? Line spooler on fast line adequately secured 8-33 ? ? ? Crown stop properly set [SASR C-5 (4) p.47] 8-34 ? ? ? Drill line properly spooled on drum and

anchored [SASR C-18 (4) p.55] 8-35 ? ? ? Tugger line in good condition, not kinked,

crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8-36 ? ? ? Tugger line with safety hook or shackle on end

(recommended by DHALPD) 8-37 ? ? ? Swivel used on tugger line (recommended by

DHALPD) 8-38 ? ? ? All wire rope fittings properly clamped, clamps

properly spaced [SASR C-18 (13) p.55] 8-39 ? ? ? No wire ropes are knotted, or have "Flemish

eye splice", "farmer's eye splice" or "rig operator's standby" [SASR C-18 (15) p.55]

8-40 ? ? ? All other wire ropes and slings free from wickers,

not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8-41 ? ? ? Signal man used with tugger line 8-42 ? ? ? NO rope installed on cat head (cat head not

used) [D&WOOD SOC] 8-43 ? ? ? Maximum allowable casing pressure posted at

remote choke control panel

YES NO N/A

8-44 ? ? ? All electrical connections, plugs, receptacles and cords comply with Classification for the area [SASR B-15 (1) p.38]

8-45 ? ? ? Electrical connections, cords, plugs and

receptacles in good condition (no electrician's tape used to splice or repair) [SASR B-15 (1) p.38]

8-46 ? ? ? Proper fit between electrical cables and

grommets [SASR B-15 (1) p.38] 8-47 ? ? ? Lights with proper sealed coverings free of

cracks or breaks, properly sealed [SASR B-15 (1) p.38]

8-48 ? ? ? For an H2S locations, eyewash facilities on rig

floor (or doghouse) serviced and operable [SASR B-3 (11) p.17; B-6 III F1 p.26]

8-49 ? ? ? For H2S locations, two 30 pound dry chemical

fire extinguishers serviced and in place at drawworks [SASR B-6 (IV A-4) p.26]

9. DOGHOUSE YES NO N/A

9-1 ? ? ? "No Smoking", hard hat, and safety footwear signs posted at foot of stairs leading to doghouse [SASR A-5 (5) p.13]

9-2 ? ? ? Doghouse doors free of locking devices [SASR

C-8 (2) p.48] 9-3 ? ? ? Blowout prevention procedures posted [SASR

C-30 (14) p.63] 9-4 ? ? ? BOP function tests done every trip [Saudi

Aramco Well Control Handbook: K 1.0 (5), p. K-3]; and documented in IADC book

9-5 ? ? ? BOP pressure tested at least every 2 weeks

[Saudi Aramco Well Control Handbook: K 2.1 (5), p. K-4]; and documented in IADC book

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9-6 ? ? ? Drills held and documented in IADC book (BOP,

H2S, fire, evacuation) [SASR C-30 (15) p.63]

YES NO N/A

9-7 ? ? ? Safety meeting topics and attendance documented

9-8 ? ? ? Trip records (measured hole-fill volumes) kept 9-9 ? ? ? For H2S locations, two 25-man first aid kit in

good condition present: one at the rig site, and one at the camp [SASR B6 (III E) p.26]

9-10 ? ? ? Two stretchers readily available [SASR B-1 (III

B) p.26] [location:_______________] 9-11 ? ? ? Employees know location of stretcher and

blankets 9-12 ? ? ? Bulletin board used to post current safety material 9-13 ? ? ? Date of last safety item posted on the bulletin

board:________________ 9-14 ? ? ? Spare derrick belt [SASR C-29 (7) p.47],

goggles, face shields and other personal protective equipment kept in doghouse

9-15 ? ? ? Electrical plugs, receptacles, cords, conduit

junction boxes comply with electrical code for such atmospheres [SASR B-15 (1) p.38]

9-16 ? ? ? Light covers sealed [SASR B-15 (1) p.38] 9-17 ? ? ? For H2S locations, three SCBA available and

in good condition in doghouse (or rig floor) [SASR B6 (II B5) p.25]

9-18 ? ? ? Remote BOP controls free of obstruction and

accidental operation [SASR C-30 (8) p.63] 9-19 ? ? ? Housekeeping acceptable, no accumulations that

present a hazard [SASR B-7 (6) p.34]

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10. DERRICK YES NO N/A

10-1 ? ? ? Derrick has a permanent nameplate attached (or available in-site) stating: manufacturer, model number, serial number, hook load capacity, wind load capacity (both with and without pipe in the derrick), and (if applicable) the recommended guying pattern. [SASR C-2 (1) p.45]

10-2 ? ? ? Operating within prescribed limits [SASR C-2 (2)

p.46] 10-3 ? ? ? Derrick ladder extends down to rig floor (no

need to climb up standpipe, etc.) 10-4 ? ? ? Base of ladder clear of obstructions [SASR C-8

(15) p.49] 10-5 ? ? ? Derrick ladder extends at least 3 feet (91 cm)

above each landing platform (including the crown)[SASR C-8 (23) p.50]

10-6 ? ? ? Platforms provided at regular intervals on ladder,

or climbing device provided [SASR C-8 (14) p.49]

10-7 ? ? ? Climbing belt always used [SASR C-8 (18) p.49] 10-8 ? ? ? Derrick girts in good condition [SASR C-2 (4)

p.46] 10-9 ? ? ? All derricks pins in place c/w safety pins [SASR

C-2 (4, 10) p.46] 10-10 ? ? ? Tong counterweight weight ropes minimum 1/2"

(12.7 mm) diameter [SASR C-22 (2) p.59] 10-11 ? ? ? Unguided tong counterweights safety tied with

minimum 5/8" (15.9 mm) diameter wire rope [SASR C-22 (1) p.59]

10-12 ? ? ? Safety line prevents counter weight from

dropping within 8 ft. (2.4 m) of floor [SASR C-22 (1) p.59]

YES NO N/A

10-13 ? ? ? All sheaves, lights, and other fixtures safety -tied [SASR B-16 (3) p.39 (for lights only)]

10-14 ? ? ? Standpipe adequately anchored 10-15 ? ? ? Kelly hose safety chained at both ends, (chained

to the swivel, not chained to the gooseneck) [SASR C-35 (12) p.65]

10-16 ? ? ? Traveling blocks have sheave guards [SASR C-

5 (1) p.47] 10-17 ? ? ? Traveling blocks free of projections [SASR C-5

(3) p.47] 10-18 ? ? ? Kelly hook safety latched [SASR C-5 (1) p.47] 10-19 ? ? ? Safety belt c/w shoulder harness in derrick

[SASR C-29 (2) p.47] 10-20 ? ? ? Safety belt lanyard minimum 5/8" (15.9 mm)

manila rope (not synthetic) with no splices [SASR C-29 (3) p.47]

10-21 ? ? ? Monkey board secured and in good condition 10-22 ? ? ? Adequate tie back and pull back ropes 10-23 ? ? ? Fingers and pads properly pinned and safety

chained [SASR C-27 (2) p.60] 10-24 ? ? ? Geronimo or other escape mechanism installed

[SASR C-6 (1) p.47] 10-25 ? ? ? • Easily accessible [SASR C-6 (9) p.48] 10-26 ? ? ? • Inspected weekly [SASR C-6 (8) p.48] 10-27 ? ? ? • Quick release knots on geronimo tie back

[SASR C-6 (9) p.48] 10-28 ? ? ? Geronimo (escape) line is minimum 1/2" (12.7

mm) diameter [SASR C-6 (3) p.47]

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YES NO N/A

10-29 ? ? ? Crown has no openings large enough for a worker to fall through [SASR C-4 (1) p.46]

10-30 ? ? ? Crown bumper blocks (wooden planks) safety

tied, or covered with expanded metal, or suitable screen or mesh [SASR C-4 (2) p.46]

10-31 ? ? ? Crown sheaves in good condition and well

lubricated 10-32 ? ? ? Derrick lights have adequately sealed protective

covers [SASR B-15 (1) p.38] 10-33 ? ? ? All electrical connections, plugs, receptacles,

cords etc. are in good condition [SASR B-15 (1) p.38]

10-34 ? ? ? Electrician's tape not used in splices or at

grommets [SASR B-15 (1) p.38]

11. CATWALK & PIPE RACKS YES NO N/A

11-1 ? ? ? Catwalk level, in good condition [SASR C-9 (3) p. 50]

11-2 ? ? ? Catwalk free of tripping hazards [SASR C-9 (3)

p. 50] 11-3 ? ? ? Stairs at end of catwalk [SASR C-9 (3) p. 50] 11-4 ? ? ? Pipe racks/tubs level and in good condition

[SASR C-9 (1) p. 50] 11-5 ? ? ? Pipe racks butted against catwalk, and secured

to catwalk [SASR C-9 (1) p. 50] 11-6 ? ? ? Pipe racks chained or pinned together [SASR C-

9 (1) p. 50] 11-7 ? ? ? Adequate spacing between layers of pipe [SASR

C-9 (5) p. 50]

YES NO N/A

11-8 ? ? ? Workers stand out of the way when rolling, loading, or unloading pipe [SASR C-10 (3) p. 51]

11-9 ? ? ? Pipe key, crowbar, or other safe method used

when rolling pipe 11-10 ? ? ? Blocks, pins, or chocks used to prevent pipe from

rolling off rack [SASR C-9 (1) p. 50] 11-11 ? ? ? Tag line used when loading or unloading pipe

[SASR D-2 (5) p. 67] 11-12 ? ? ? From the derrick, the Geronimo (escape) line is

minimum 1/2" (12.7 mm) diameter [SASR C-6 (3) p.47]

Geronimo (escape) line (from the derrick): 11-13 ? ? ? • Twice vertical length from attachment on

derrick to the ground [SASR C-6 (7) p.47] 11-14 ? ? ? • When used, the worker will touch ground 20

feet (6.1 m) from the escape line anchor point [SASR C-6 (6) p.47]

11-15 ? ? ? • Regular check of escape line anchor to

ensure load bearing ability (3000 lb. static cable pull) [SASR C-6 (4) p.47]

11-16 ? ? ? • Anchor staked in opposite direction of pull 11-17 ? ? ? • Escape line touchdown area free of

obstruction or vehicular traffic [SASR C-6 (4) p.47] (DHALPD recommends 50 feet (16 m) clearance)

11-18 ? ? ? • Escape line does not impede access to

crown stand or pipe racks

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12. MANIFOLD, FLARE LINES, & FLARE PIT YES NO N/A

12-1 ? ? ? Electrical connections, plugs, receptacles Class I, Div. II and lights are properly sealed with a protective cover [SASR B-15 (1) p.38]

12-2 ? ? ? Manifold and valves free of obstruction 12-3 ? ? ? Valves wheels turn easily 12-4 ? ? ? Valve handles kept 1/4 turn from the open or

closed position 12-5 ? ? ? Casing and drillpipe pressure gauges installed 12-6 ? ? ? Casing and drillpipe pressure gauges easily

visible from manual choke operator's position 12-7 ? ? ? Maximum allowable casing pressure posted at

manual choke 12-8 ? ? ? Flare lines properly and adequately staked 12-9 ? ? ? Safety chains used for pressure hoses, lines with

hammer unions, or chiksans 12-10 ? ? ? Flare line sloped toward flare pit 12-11 ? ? ? Flare pit minimum 60 metres from well bore, on

an arc from 60º to 225º [SAES B-62 (7.2)] 12-12 ? ? ? Flare pit adequate size, with proper backwall 12-13 ? ? ? Flare pit not used as garbage disposal 12-14 ? ? ? Reliable and safe means of remote ignition of

gases at flare pit [SASR D-8 (1) p. 71]

13. FUEL TANKS YES NO N/A

13-1 ? ? ? Flammable liquid containers are bonded or in firm contact with each other before transfers occur [SASR B-13 (1) p.37]

13-2 ? ? ? Fuel dispensing nozzles and valves are self-

closing [SASR B-11 (4) p.37] 13-3 ? ? ? Fuel tanks have a fire extinguisher nearby

[SASR B-11 (4) p.37] 13-4 ? ? ? Fuel tanks conspicuously marked as to contents

[SASR B-11 (2) p.37]

14. FIRE FIGHTING EQUIPMENT YES NO N/A

14-1 ? ? ? 30 lb. ABC fire extinguishers provided throughout the rig at strategic areas

14-2 ? ? ? • Readily accessible

14-3 ? ? ? • Locations identified

14-4 ? ? ? • Inspected weekly [SASR B-9 (2) p.35] 14-5 ? ? ? Fire drills held regularly and logged 14-6 ? ? ? Fire hoses kept on rack or reel when not in use

[SASR B-9 (13) p.35] 14-7 ? ? ? Fire hoses not used for any other purpose than

fighting fires, drills, or testing [SASR B-9 (9) p.35] 14-8 ? ? ? Fire hoses completely unrolled and inspected

monthly [SASR B-9 (10) p.35]

15. GAS CYLINDERS YES NO N/A

15-1 ? ? ? Cylinders stored upright [SASR B-14 (1) p.38] 15-2 ? ? ? Acetylene bottles (empty or full) always stored

upright [SASR B-14 (4) p.38]

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YES NO N/A

15-3 ? ? ? Empty and full gas cylinders stored separately [SASR B-14 (1) p.38]

15-4 ? ? ? Oxidizers stored at least 20 ft. (6.1 m) from fuel

gases [SASR B-14 (1) p.38] 15-5 ? ? ? Valve protection caps on all cylinders (without a

regulator) [SASR B-14 (2) p.38] 15-6 ? ? ? Gas cylinders hoisted only in a cradle, pallet, or

slingboard [SASR B-14 (3) p.38]

16. HAND & POWER TOOLS YES NO N/A

16-1 ? ? ? Hand held power tools have "dead-man" auto-shutoff devices (tools that can be locked "ON" are expressly forbidden) [SASR B-17 (2) p.40]

16-2 ? ? ? Hand held power tools are double insulated or

grounded [SASR B-17 (2) p.40] 16-3 ? ? ? Impact tools (such as drift pins, chisels, hammer

wrenches) do not have mushroomed striking surfaces [SASR B-17 (3) p.40]

16-4 ? ? ? Pneumatic power tools are secured to the air line

to prevent accidental disconnection [SASR B-17 (7) p.40]

Bench grinders: 16-5 ? ? ? • Tool rests no more than 1/8" (3.2 mm) from

abrasive wheel [SASR B-18 (2) p.40] 16-6 ? ? ? • Grinding wheel is rated for the machine rpm

(grinder rpm stamped on nameplate; wheel rpm rating identified on the wheel blotter) [SASR B-18 (5) p.41]

16-7 ? ? ? • Eye hazard sign 16-8 ? ? ? • Goggles or face mask available and used

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17. WELDING & CUTTING YES NO N/A

No welding or cutting performed on: [SASR B-19 (1) p.41]:

17-1 ? ? ? • any pipe/vessel containing pressurized fluid or gas

17-2 ? ? ? • any container which contains or did contain flammable liquids or gases, until the container is filled with water or otherwise suitably purged. Used 55-gallon drums are specifically included.

17-3 ? ? ? • or in a confined space until the atmosphere has been tested "safe for fire" (DHALPD recommends 0% LEL)

17-4 ? ? ? No welding or cutting on load handling tools or

equipment (slips, tongs, elevators, bales, etc.) [SASR B-19 (3) p.41]

17-5 ? ? ? Suitable eye/face protection used when welding,

cutting, or grinding [SASR B-19 (6) p.42] 17-6 ? ? ? Maximum acetylene gauge pressure less than

15 psi (103 kPa) [SASR B-19 (7) p.42] 17-7 ? ? ? Acetylene cylinder valves not opened more than

1 1/2 turns [SASR B-19 (7) p.42] 17-8 ? ? ? All gas bottle regulator gauges are in good

condition (no cracked glass covers) [SASR B-19 (8) p.42]

17-9 ? ? ? All welding hoses are free from cracks, leaks,

burns, worn spots [SASR B-19 (10) p.41] 17-10 ? ? ? No arc-welding cable with damaged insulation or

exposed conductors [SASR B-19 (12) p.42] 17-11 ? ? ? No splices in arc-welding cables within 10 ft. (3

m) of the electrode holder [SASR B-19 (13) p.42]

17-12 ? ? ? Portable arc-welding machines are suitably

grounded [SASR B-19 (15) p.42]

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18. CRANE OPERATIONS AND SLINGS YES NO N/A

Note: ? ? ? The heavy equipment operator certification information on the title page of this inspection checklist must be completed in full.

18-1 ? ? ? Cranes have valid Aramco Crane Inspection

Certificate [SASR D-1 (1b) p.65]

Crane 1 Crane 2

Crane #: ________________

________________

Certificate Expiry:

________________

________________

18-2 ? ? ? Tag lines used [SASR D-2 (5, 6) p.67] 18-3 ? ? ? All slings identified with Manufacturer name or

logo, a unique identifier number, and safe working limit (SWL) [S.A. G.I. 7.029 (4.1)]

18-4 ? ? ? All slings have a detailed visual inspection every

6 months, recorded in a sling inspection log [S.A. G.I. 7.029 (7.2)]

18-5 ? ? ? Spreader bars identified with Manufacturer

name, serial number, date of load test certification, and (in English and Arabic) safe working limit (SWL) [S.A. G.I. 7.029 (6.2)]

18-6 ? ? ? Spreader bars have a semi-annual documented

inspection [S.A. G.I. 7.029 (6.2)]

19. GENERAL YES NO N/A

19-1 ? ? ? All stairs with more than 4 risers have handrails [SASR C-8 (4) p.49]

19-2 ? ? ? All working surfaces higher than 4 feet (1.2 m)

have standard handrails (42" handrail, 21" knee rail, 4" toe board) [SASR C-8 (5) p.49]

19-3 ? ? ? Safety harnesses used when working higher

than 10 feet (3.1 m) above grade [SASR C-8 (6) p.49]

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YES NO N/A

19-4 ? ? ? All ladders (fixed and portable) in good shape with no bent, broken, or damaged side rails and steps [SASR C-8 (24) p.50]

19-5 ? ? ? Portable ladders are safety tied [SASR C-8 (26)

p.50] 19-6 ? ? ? Noise protection signs posted where required

[SASR B-3 (8) p.17] 19-7 ? ? ? At least one qualified First Aid person on each

shift [GI 150.002] 19-8 ? ? ? Telephone numbers of physician, hospital, &

ambulance posted in the office & clinic [SASR B1 (4) p.15]

19-9 ? ? ? Overall housekeeping acceptable, no

accumulations that present a hazard [SASR B-7 (6) p.34]

19-10 ? ? ? Rig signs posted at strategic road intersections 19-11 ? ? ? Warning signs, information signs, and signs

posted requiring visitors to report to drilling supervisor posted at location entrance

19-12 ? ? ? Safety orientation given to all personnel entering

location 19-13 ? ? ? Workers wear appropriate protective equipment

at all times 19-14 ? ? ? Pre-job safety meetings conducted &

documented (e.g. casing, testing, laydown) 19-15 ? ? ? No rings, necklaces, long hair, or loose clothing 19-16 ? ? ? Self contained breathing apparatus available

? ? ? • Pressure demand ? ? ? • Extra air cylinders ? ? ? • Readily accessible ? ? ? • Adequately maintained

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H2S PROTECTION: LAND RIGS All drilling or workover rigs will have the following equipment on location when operating in known or suspected H2S areas. The reference term "H2S Std (Land)" refers to the Saudi Aramco Standard Safety Equipment for H2S Operations on All Onshore Drilling and Workover Rigs, a document included in the Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations. The page numbers refer to the Safety Requirements Manual. YES NO N/A

20-1 ? ? ? Crews trained in the following [SASR B6 (4) p.23]

• H2S characteristics and toxicity • Detection and warning systems on location • Safe briefing area locations • Evacuation procedures • Rescue procedures • First aid for victims • Inspection, maintenance, and use of

emergency breathing equipment • Drill procedure 20-2 ? ? ? One 4-channel H2S monitoring system [H2S

STD. (LAND) (I-A) p.24] 20-3 ? ? ? H2S first alarm set for 30 ppm; high alarm set for

50 ppm [H2S STD. (LAND) (I-A-2) p.24] Note: All ED&M reports will always

recommend Drilling change their policy to 10 & 20 ppm, in line with Saudi Aramco policy and general industry practice.

20.4 Monitor sensor heads placed at [SASR B6 (2)

p.23]:

? ? ? • driller's position (about 3 feet off the rig floor)

? ? ? • top of bell nipple

? ? ? • flowline opening to shale shaker

? ? ? • cellar, or underneath the choke manifold above the choke manifold skid floor

20-5 ? ? ? One spare H2S sensor [H2S STD. (LAND) (I-

A-4) p.24]

YES NO N/A

20-6 ? ? ? Four personal H2S monitors [H2S STD. (LAND) (I-C) p.25]

20 -7 ? ? ? Two hand-held pump-type H2S detectors, with

high and low level H2S and S02 tubes [H2S STD. (LAND) (I-D) p.25]

20-8 ? ? ? One Hach Test Kit for checking H2S in the mud

returns [H2S STD. (LAND) (I-F) p.25] 20-9 ? ? ? One continuous combustible gas monitor

installed, with the sensor at either the top of the bell nipple (or the flowline opening to the shale shaker if a rotating head is in use) [H2S STD. (LAND) (I-B) p.24]

20-10 ? ? ? Combustible gas first alarm set for 20% LEL;

high alarm set for 40% LEL [H2S STD. (LAND) (I-B-2) p.24]

20-11 ? ? ? One spare combustible gas sensor [H2S STD.

(LAND) (I-B-4) p.25] 20-12 ? ? ? Two portable combustible gas monitors [H2S

STD. (LAND) (I-E) p.25] 20-13 SABA installed (manifold outlets and SABA) [H2S

STD. (LAND) (II-A) p.25]:

? ? ? • 6 on rig floor

? ? ? • 2 at shale shaker

? ? ? • 2 at mud mixing area

? ? ? • 1 at choke manifold

? ? ? • 1 in monkey board 20.14 SCBA located as follows [H2S STD. (LAND) (II-

B) p.25]:

? ? ? • 2 in toolpusher's office

? ? ? • 2 in Aramco representative's office

? ? ? • 2 in mud logging unit

? ? ? • 1 in SCR room

? ? ? • 3 on rig floor

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YES NO N/A

20-15 ? ? ? Two 40,000 cfm bug blowers on drillfloor [H2S STD. (LAND) (III-A) p.25]

20-16 ? ? ? Three windsocks (2 mounted, 1 spare) [H2S

STD. (LAND) (III-B) p.25] 20-17 ? ? ? Windsock or streamer visible from anywhere on

the location [SASR B6 (3) p.23] 20-18 ? ? ? Two safe briefing areas marked out [SASR B6

(4c) p.23] 20-19 ? ? ? Flare ignition system (and a backup) [H2S STD.

(LAND) (III-C) p.25] 20-20 ? ? ? Two portable oxygen resuscitator units, each

with a spare oxygen cylinder [H2S STD. (LAND) (III-D) p.26]

20-21 ? ? ? Two safety harnesses with two 250-foot retrieval

ropes [H2S STD. (LAND) (III-G) p.26] 20-22 ? ? ? One basket stretcher [Stokes litter or Navy type)

[H2S STD. (LAND) (III-H) p.26] 20-23 ? ? ? Two quick air splints [H2S STD. (LAND) (III-I)

p.26] 20-24 ? ? ? Two portable bullhorns with three extra battery

packs [H2S STD. (LAND) (III-J) p.26] 20-25 ? ? ? Three chalk boards with clamps for mounting,

and a supply of chalk and erasers [H2S STD. (LAND) (III-K) p.26]

20-26 ? ? ? Explosion-proof flashlights with an extra set of

batteries and extra bulb for each (one flashlight for every two persons on location, with a minimum of 25 flashlights) [H2S STD. (LAND) (III-L) p.26]

Page 736: Saudi Aramco - WorkOver Manual

DHALPD E&D RIG INSPECTION CHECKLIST FOR OFFSHORE RIGS DATE: RIG: FOREMAN: WELL NAME:

OPERATION:

PERSONNEL CERTIFICATIONS: Enter "T" if date entered indicates date training was taken.

Enter "E" if date entered indicates date training expires. POSITION NAME BADGE # BOP FIRST AID H2S OTHER

Foreman

Foreman

Toolpusher

Toolpusher

Driller

Driller

POSITION

NAME

BADGE #

SAG ARAMCO

Cert # ARAMCO

Cert Expiry

OTHER Crane Op

Crane Op

1. Accommodations ....................... 1 2. Deck ......................................... 2 3. SCR & Emergency Generator...... 3 4. Accumulator .............................. 4 5. Mud Pumps & Pump Room......... 4 6. Pit Room ................................... 5 7. Substructure & Spider Deck ........ 6 8. Rig Floor.................................... 6 9. Dog House................................. 8 10. Derrick ...................................... 9

11. Catwalk & Pipe Racks...............10 12. Manifold & Flare Lines,..............10 13. Helideck...................................10 14. Fire Fighting Equipment.............11 15. Compressed Gas Cylinders .......11 16. Hand & Power Tools..................11 17. Welding & Cutting.....................12 18. Cranes & Slings........................12 19. General....................................13 20. Engine Room............................13

Note: Where applicable, inspection items are referenced to published Aramco policy.

"SASR" refers to Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations

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1. ACCOMMODATIONS & GALLEY YES NO N/A YES NO N/A

??? 1-1 Electrical junction boxes weather proofed and closed [SASR B-15 (7) p.39]

??? 1-2 Electrical cords and fittings free of defects [SASR B-15 (1) p.38]

??? 1-3 Protective covers on all lights

??? 1-4 ABC fire extinguishers adequately placed

??? 1-5 Smoke alarms present and functioning

??? 1-6 Qualifications of workers posted or available on site (first aid, CPR, BOP, crane, rigger)

??? 1-7 Escape routes posted, marked and kept clear

??? 1-8 Station bills posted

??? 1-9 Drills conducted on a regular basis:

Date of last fire drill:________________________

Date of last abandon drill:___________________

Date of last BOP drill:______________________

Date of last man overboard drill:______________

??? 1-10 Life jacket for each bunk in every stateroom

??? 1-11 One 30-minute SCBA assigned to each person on the rig, stored under the head end of his assigned bunk. [H2S Std. (Offsh) (II-A-1) p.31]

??? 1-12 If no assigned bunk, that person's assigned SCBA is stored in a designated area [H2S Std. (Offsh) (II-A-1) p.31]

??? 1-13 Ten 30-minute SCBA in the dining area [H2S Std. (Offsh) (II-A-2) p.31]

??? 1-14 Two 30-minute SCBA, each with a clip-on communication device, in the Aramco Foreman's office [H2S Std. (Offsh) (II-A-4) p.31]

??? 1-15 Two 30-minute SCBA, each with a clip-on communication device, in the Toolpusher's office [H2S Std. (Offsh) (II-A-4) p.31]

??? 1-16 All remaining SCBA and extra cylinders stored in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-A-5) p.31]

??? 1-17 Two Hose line SABA (with escape bottles and clip-on communication devices) stored in the supervisor's office. [H2S Std. (Offsh) (II-B) p.31]

??? 1-18 Two Hose line SABA (with escape bottles and clip-on communication devices) stored in the Aramco Foreman's office. [H2S Std. (Offsh) (II-B) p.31]

??? 1-19 Five SABA and 16 spare cylinders stored in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-B 5) p.31]

??? 1-20 Nine spare clip-on communication devices are stored with the 5 spare SABA in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-B 6) p.31]

??? 1-21 Ten personal H2S monitors present [H2S Std. (Offsh) (IV) p.32]

??? 1-22 One H2S calibrator with 2 permeation tubes, portable and AC/DC [H2S Std. (Offsh) (V) p.32]

??? 1-23 Four portable oxygen resuscitator units, with 8 spare oxygen cylinders [H2S Std. (Offsh) (VII) p.36]

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??? 1-24 Four hand-held pump-type H2S detectors, with high and low level H2S and S02 tubes [H2S Std. (Offsh) (VIII) p.32]

??? 1-25 Four portable hand-pump suction-type combustible gas detectors [H2S Std. (Offsh) (IX) p.32]

??? 1-26 Flare ignition system (and a backup) [H2S Std. (Offsh) (XII) p.32]

??? 1-27 Two emergency igniters (preferably flares) with a minimum 25 spare flares, stored in the Aramco foreman's lower right hand desk drawer [H2S Std. (Offsh) (XIII) p.33]

??? 1-28 Four safety harnesses and four 250-foot retrieval ropes [H2S Std. (Offsh) (XIV) p.33]

??? 1-29 Four basket stretcher [Stokes litter, Navy type, or equivalent) [H2S Std. (Offsh) (XV) p.33]

??? 1-30 Four 25-man first aid kits [H2S Std. (Offsh) (XVI) p.33]

??? 1-31 Four Quick-Air splints (or equivalent) [H2S Std. (Offsh) (XVII) p.33]

??? 1-32 Six portable bullhorns with six extra battery packs [H2S Std. (Offsh) (XVIII) p.33]

??? 1-33 Six chalk boards with clamps for mounting, and a supply of chalk and erasers [H2S Std. (Offsh) (XIX) p.33]

??? 1-34 Minimum 7 explosion-proof flashlights with an extra set of batteries and extra bulb for each [H2S Std. (Offsh) (XX) p.33]

??? 1-35 The H2S alarm system is located where personnel can see/hear it, e.g. crew quarters, galley area, etc. [H2S Std. (Offsh) (I-E) p.30]

??? 1-36 The H2S monitor is located in the Supervisor's office. [H2S Std. (Offsh) (I-F) p.30]

??? 1-37 Cooking range exhaust fans, filters and ducts clean and operable

??? 1-38 Electrical appliances grounded and intact

??? 1-39 Thermostats operable and regularly checked

??? 1-40 Freezer doors operable from inside

??? 1-41 First aid kit and fire blanket available

??? 1-42 Fire extinguishing system in place and charged

??? 1-43 Personal sanitation rules posted and followed

??? 1-44 Adequate sanitation and housekeeping

??? 1-45 Galley inspected by Industrial Hygiene / Environmental Health; Date of last inspection:_________________

2. MAIN DECK YES NO N/A YES NO N/A

??? 2-1 Main decks in good condition, clean, and not slippery

??? 2-2 Oil spills and slick spots cleaned immediately

??? 2-3 Hand rails, kick plates in place

??? 2-4 Hatch openings guarded

??? 2-5 Deck loads properly secured

??? 2-6 Routes to life boats, rafts marked

??? 2-7 Safety signs posted and legible

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??? 2-8 Fire fighting equipment, hose stations, etc. properly maintained, marked, accessible

??? 2-9 Sprinkler, deluge, Halon, etc. Systems inspected regularly [G.I. 1781.001, 1782.001]

??? 2-10 Lifeboats, emergency stores, and equipment maintained and inspected

Date of last Inspection:_____________

Expiry date on stores:______________

??? 2-11 Boats checked and started regularly, recorded in logbook.

Frequency:______________________

Date of last Inspection:_____________

??? 2-12 Windsocks or streamers visible from anywhere on the rig [H2S Std. (Offsh) (XI) p.32]

??? 2-13 H2S monitor sensor heads placed as near as practical to living quarters area nearest the most likely source of H2S [H2S Std. (Offsh) (I-B) p.30]

??? 2-14 A spare H2S sensor with 200 feet of cable on a portable reel kept on standby in a designated safety equipment storage area. (There are supposed to be eight sensors rigged up: 7 already in position and this eighth ready to go). [H2S Std. (Offsh) (I-B) p.30]

??? 2-15 Four spare H2S sensors available [H2S Std. (Offsh) (I-C) p.30]

??? 2-16 H2S low alarm (red beacon and siren) set for 10 ppm; and high alarm set for 20 ppm [H2S Std. (Offsh) (I-D) p.30]

??? 2-17 The alarm system is located where personnel in any work area can see/hear at least one set. Specifically [H2S Std. (Offsh) (I-B) p.30]:

??port side at the corner of and above the quarters

??starboard side at the corner of and above the quarters

??? 2-18 One hundred 30-minute SCBA located on the rig [H2S Std. (Offsh) (II-A-1) p.31]

??? 2-19 Three cascade systems with twelve 300 cu. ft. cylinders each (or equivalent) [H2S Std. (Offsh) (III) p.32]

??? 2-20 Three air compressors each with purification system and 26 scfm capacity at 2400 psi [H2S Std. (Offsh) (III) p.32]

??? 2-21 One 3-outlet cascade manifold [H2S Std. (Offsh) (III) p.32]

??? 2-22 Three 12-outlet cascade manifolds [H2S Std. (Offsh) (III) p.32]

??? 2-23 Two 150-ft. cascade hoses [H2S Std. (Offsh) (III) p.32]

??? 2-24 Twelve 50-ft. cascade hoses [H2S Std. (Offsh) (III) p.32]

??? 2-25 Two 5000 psi cascade hoses (250-ft. and 300-ft.) [H2S Std. (Offsh) (III) p.32]

??? 2-26 Two cascade systems with diesel-powered air compressors are located as remotely from the rig floor as practical, one on the upper port deck, the other on the upper starboard deck [H2S Std. (Offsh) (III-B) p.32]

These remote cascades have:

??? 2-26a) one 6-outlet cascade manifold for recharging portable cylinders at each cascade system, as well as regulators and low pressure manifolds for hoseline units [H2S Std. (Offsh) (III-B-1) p.32]

??? 2-26b) double Tee with check valves for tying in either or both of the other 2 cascade systems [H2S Std. (Offsh) (III-B-2) p.32]

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3. SCR & EMERGENCY GENERATOR YES NO N/A YES NO N/A

??? 3-1 Emergency lighting installed and working at TWO exits [SASR B-15 (6) p.38]

??? 3-2 Non-conductive mats placed on floor [SASR B-15 (5) p.38]

??? 3-3 Halon fire extinguisher available (only Halon is permitted in the SCR room) [SASR B-9 (4) p.35]

??? 3-4 Fans and belts guarded [SASR C-1 (1a) p.45]

??? 3-5 Auxiliary and emergency standby generators run at full load for 30 minutes every week [SASR B-15 (12) p.39]

??? 3-6 Electrical junction boxes identified and kept in closed position [SASR B-15 (7) p.39]

??? 3-7 Electrical outlets labeled, voltage identified [SASR B-15 (7) p.39]

??? 3-8 All knockouts in panels (no open knockouts) [SASR B-15 (1) p.38]

??? 3-9 Electrical cords, plugs, receptacles etc. in good condition [SASR B-15 (1) p.38]

??? 3-10 Switches capable of being locked out

??? 3-11 Lockout procedures in place [SASR B-31 p.43]

??? 3-12 Lights have protective coverings

??? 3-13 Noise hazard sign in place [SASR B-3 (8) p.17]

??? 3-14 Hearing protection provided and used by workers [SASR B-3 (9) p.17]

??? 3-15 Exits free of obstruction [SASR B-7 (1) p.30]

??? 3-16 Floors and equipment free of oil or grease [SASR B-7 (2) p.34]

??? 3-17 Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

??? 3-18 "High Voltage - Use No Water" sign posted [SASR B-3 (2) p.16]

4. ACCUMULATOR YES NO N/A YES NO N/A

??? 4-1 Accumulator area clean and tidy

??? 4-2 Accumulator bottles precharged to 1200 psi [SASR C- 30 (7) p.63]

??? 4-3 Spare nitrogen bottles available & pressurized

??? 4-4 No leaks in system [SASR C- 30 (7) p.63]

??? 4-5 Gauges in good condition and readable [SASR C- 30 (7) p.63]

??? 4-6 Controls free of any obstruction [SASR C- 30 (8) p.63]

??? 4-7 Controls in OPEN or CLOSED position, not neutral [SASR C- 30 (11) p.63]

??? 4-8 Accumulator function tests conducted Date of last test:_________

??? 4-9 Emergency lighting installed and working [SASR B-16 (7) p.39]

??? 4-10 Fire extinguisher in place and serviceable

??? 4-11 Compressor free of dirt, grease or oil [SASR B-7 (2) p.34]

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5. MUD PUMPS & PUMP ROOM YES NO N/A YES NO N/A

??? 5-1 Fans and belts guarded [SASR C-1 (1a) p.45]

??? 5-2 Lubricator pump belt and pulleys guarded [SASR C-1 (1a) p.45]

??? 5-3 Shock hoses safety chained [SASR C-35 (13) p.65]

??? 5-4 Pop (relief) valve capped, proper size pins inserted (set @ _____psi) [SASR C-35 (2, 3, 4) p.64]

??? 5-5 No valves installed between pump and pop valve [SASR C-35 (1) p.64]

??? 5-6 No valves installed between pop valve and its discharge [SASR C-35 (6) p.64]

??? 5-7 Pop valve discharge line is horizontal or sloped downward [SASR C-35 (9) p.65]

??? 5-8 Discharge line properly secured [SASR C-35 (8) p.65]

??? 5-9 Electrical connections in good condition [SASR B-15 (1) p.38]

??? 5-10 Used electrical receptacles capped [SASR B-15 (7) p.39]

??? 5-11 Electrical lights have protective covers

??? 5-12 Emergency lighting installed and operable [SASR B-16 (7) p.39]

??? 5-13 30 pound dry chemical fire extinguisher serviced and in place [SASR B-6 (IV A-3) p.26]

??? 5-14 Sign posted identifying remote startup of equipment (if applicable)

??? 5-15 Noise hazard sign posted [SASR B-3 (8) p.17]

??? 5-16 Hearing protection provided and used [SASR B-3 (9) p.17]

??? 5-17 Floor and equipment free of grease, oil and debris [SASR B-7 (2) p.34]

??? 5-18 No oily rags or tools laying about [SASR B-7 (7) p.34]

??? 5-19 Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

??? 5-20 Gas detection equipment present, functioning, can be seen and heard

6. PIT ROOM (CLASS 1, DIV. 1 & 2) YES NO N/A YES NO N/A

??? 6-1 All pulleys, belts, couplings on motors properly guarded [SASR C-1 (1a) p.45]

??? 6-2 Eyewash facilities at mixing area serviced and operable [SASR B-3 (11) p.17; B-6 III F2 p.26]

??? 6-3 Goggles provided at mixing area, and worn [SASR A-5 (8) p.13; SASR B-3 (4) p.17]

??? 6-4 Mud tanks and shale shakers ventilated if enclosed [SASR C-34 (2) p.64]

??? 6-5 Hazardous products (i.e. caustic) used in barrel mixer or mud tank adequately identified

??? 6-6 Mud products Material Safety Data Sheets (MSDS) available [SASR B-33 (3, 4, 5,) p.45]

??? 6-7 MSDS stored at _____________

??? 6-8 Explosion-proof motors and fittings if applicable [SASR B-15 (1) p.45]

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??? 6-9 Electrical connections, plugs, receptacles, and lights in good condition and properly sealed [SASR B-15 (1) p.38]

??? 6-10 Lights have protective covers [SASR B-15 (1) p.38]

??? 6-11 Grommets & electrical cables with proper fit [SASR B-15 (1) p.38]

??? 6-12 Guard rails in place [SASR C-1 (1b) p.45]

??? 6-13 30 pound dry chemical fire extinguisher serviced and in place at shaker [SASR B-6 (IV A-2) p.26]

??? 6-14 Floor coverings in place to prevent tripping or falling [SASR C-1 (1b) p.45]

??? 6-15 Walkways, stairs and platforms in good condition [SASR C-1 (1b) p.45; SASR C-8 (3) p. 48]

??? 6-16 No tools or tripping hazards on walking/working surfaces [SASR C-8 (3) p. 48]

??? 6-17 Bottom of stairs within 9" of ground level, and unobstructed

??? 6-18 H2S monitor sensor head placed as near as practical to: [H2S Std. (Offsh) (I-B) p.30]:

??? 6-18a) flowline opening to shale shaker ??? 6-18b) mud pit

??? 6-19 Rig floor cascade system connected to one 3-outlet cascade manifold in the mud room [H2S Std. (Offsh) (III-A-3) p.32]

7. SUB-STRUCTURE/ SPIDER DECK (CLASS 1, DIV. 1&2) YES NO N/A YES NO N/A

??? 7-1 All pins and safety pins in place [SASR C-2 (9) p.46]

??? 7-2 BOP properly turnbuckled (4 lines) [turnbuckles recommended by SASR C-30 (6) p.63]

??? 7-3 BOP scaffolding or working platforms in good condition

??? 7-4 Steel or approved equivalent armored hose accumulator lines [SASR C-30 (13) p.63]

??? 7-5 All electrical junction boxes and conduit sealed [SASR B-15 (7) p.39]

??? 7-6 Electrical equipment and cables in good condition [SASR B-15 (1) p.38]

??? 7-7 Unused electrical receptacles covered [SASR B-15 (7) p.39]

??? 7-8 Hand rails in place

??? 7-9 Work vests available & used

??? 7-10 Tugger lines in good condition, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

??? 7-11 H2S monitor sensor heads placed as near as practical to top of bell nipple [H2S Std. (Offsh) (I-B) p.30]

??? 7-12 Lights sealed with protective covers [SASR B-15 (1) p.38]

8. RIG FLOOR (CLASS 1, DIVISION 1 & 2 AREA) YES NO N/A YES NO N/A

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??? 8-1 A loudspeaker system is installed that can be heard throughout the working area [SAMIR requirement]

??? 8-2 Two unobstructed exits from rig floor, not counting the exit leading directly to mud pits [SASR C-8 (2) p.48]

??? 8-3 Doors open outward from floor and dog house [SASR C-8 (2) p.48]

??? 8-4 V-door closed or chained when not in use [SASR C-8 (8) p.49]

??? 8-5 Handrails in place [SASR C-8 (5) p.49]

??? 8-6 Floor openings covered when not in use [SASR C-8 (9) p.49]

??? 8-7 Walkways and work areas unobstructed, and clean [SASR C-8 (3) p.48]

??? 8-8 Drawworks and rotary drive guarded [SASR C-7 (4, 5) p.48]

??? 8-9 Stabbing valves (or crossovers) on floor (or doghouse) for each thread type used in string

??? 8-10 Handles for kelly cocks and stabbing valve in easily accessible place

??? 8-11 Rough tread plate installed around rotary table

??? 8-12 Tong dies sharp and die keepers installed [SASR C-21 (6) p.58]

??? 8-13 Tong body and tong jaws in good condition [SASR C-21 (5) p.58]

??? 8-14 Snub line on each tong [SASR C-21 (1) p.58]

??? 8-15 Tong snub lines in good condition [SASR C-21 (4) p.58]

??? 8-16 Tong snub lines properly triple clamped (or have factory-made eyes) [SASR C-21 (1) p.58]

??? 8-17 Tong snub lines minimum 5/8 " (15.9 mm) diameter

??? 8-18 Make-up tong chain not unduly worn, gouged, or grooved

??? 8-19 No spinning chain on drill floor [Revised D&WOOD policy 10-01-96]

??? 8-20 Mud can and line installed and in good condition [SASR C-24 (2) p.59]

??? 8-21 Driller's controls adequately labeled [SASR C-11 (2) p.51]

??? 8-22 Driller's controls adequately guarded [SASR C-11 (5) p.52]

??? 8-23 Lockouts on rotary and cathead clutches (recommended by DHALPD E&D)

??? 8-24 Ends of Driller’s headache post contained [SASR C-13 (12) p.53]

??? 8-25 Brake handle slotted c/w tiedown [SASR C-12 (3) p.52]

??? 8-26 Brakes in good condition [SASR C-12 (1) p.52]

??? 8-27 Hydromatic, Dynamatic, or El Magco functioning properly and checked weekly [SASR C-12 (1) p.52]

??? 8-28 Weight indicator or transducer safety tied on deadline [SASR C-32 (21) p.64]

??? 8-29 Slip and cut program in place, documented [SASR C-18 (2) p.55]

??? 8-30 Line spooler on fast line adequately secured

??? 8-31 Crown stop properly set [SASR C-5 (4) p.47]

??? 8-32 Drill line properly spooled on drum and anchored [SASR C-18 (4) p.55]

??? 8-33 Tugger line in good condition, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

??? 8-34 Tugger line with safety hook or shackle on end (recommended by DHALPD E&D)

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??? 8-35 Swivel used on tugger line (recommended by DHALPD E&D)

??? 8-36 All wire rope fittings properly clamped, clamps properly spaced [SASR C-18 (13) p.55]

??? 8-37 No wire ropes are knotted, or have "Flemish eye splice", "farmer's eye splice" or "rig operator's standby" [SASR C-18 (15) p.55]

??? 8-38 All other wire ropes and slings free from wickers, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

??? 8-39 Signal man used with tugger, when required

??? 8-40 Maximum allowable casing pressure posted at remote choke control panel

??? 8-41 All electrical connections, plugs, receptacles and cords comply with Classification for the area [SASR B-15 (1) p.38]

??? 8-42 Electrical connections, cords, plugs and receptacles in good condition (no electrician's tape used to splice or repair) [SASR B-15 (1) p.38]

??? 8-43 Proper fit between electrical cables and grommets [SASR B-15 (1) p.38]

??? 8-44 Lights with proper sealed coverings free of cracks or breaks, properly sealed [SASR B-15 (1) p.38]

??? 8-45 Eyewash facilities on rig floor (or doghouse) serviced and operable [SASR B-3 (11) p.17; B-6 III F1 p.26]

??? 8-46 Two 30 pound dry chemical fire extinguishers serviced and in place at drawworks [SASR B-6 (IV A-4) p.26]

??? 8-47 Six movable, explosion-proof, 25,000 cfm bug blowers are available [H2S Std. (Offsh) (X) p.32]

??? 8-48 A continuous monitoring system with 8 sensors and 6 red beacon light-siren alarms is installed [H2S Std. (Offsh) (I) p.30]

??? 8-49 H2S monitor sensor heads placed as near as practical to [H2S Std. (Offsh) (I-B) p.30]:

? ? ? 8-49a) Driller’s position (about 3 ft off the rig floor)

? ? ? 8-49b) breathing apparatus compressor package, near the rig floor

??? 8-50 H2S low alarm (red beacon and siren) set for 10 ppm; and high alarm set for 20 ppm [H2S Std. (Offsh) (I-D) p.30]

??? 8-51 The alarm system is at least 8 feet high and can be seen/heard on the floor [H2S Std. (Offsh) (I-B) p.30]

??? 8-52 Six SABA on rig floor, 3 of which have clip-on communication devices [H2S Std. (Offsh) (II-B) p.31]

??? 8-53 One cascade system is located near the rig floor with air compressor powered by an explosion-proof motor [H2S Std. (Offsh) (III-A) p.32]

This rig floor cascade is connected to:

? ? ? 8-53a) two 6-outlet cascade manifolds on the derrick floor [H2S Std. (Offsh) (III-A-A) p.32]

? ? ? 8-53b) one 3-outlet cascade manifold at the Derrickman's position [H2S Std. (Offsh) (III-A-2) p.32]

? ? ? 8-53c) one 3-outlet cascade manifold in the mud room [H2S Std. (Offsh) (III-A-3) p.32]

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? ? ? 8-53d) one 3-outlet cascade manifold in the motor room [H2S Std. (Offsh) (III-A-4) p.32]

? ? ? 8-53e) one 6-outlet cascade manifold for recharging portable cylinders, one at each cascade system [H2S Std. (Offsh) (III-A-5) p.32]

? ? ? 8-53f) a double Tee with check valves for tying in either or both of the other 2 cascade systems [H2S Std. (Offsh) (III-A-6) p.32]

9. DOGHOUSE YES NO N/A YES NO N/A

??? 9-1 "No Smoking", hard hat, and safety footwear signs posted at foot of stairs leading to doghouse [SASR A-5 (5) p.13]

??? 9-2 Doghouse doors free of locking devices [SASR C-8 (2) p.48]

??? 9-3 Blowout prevention procedures posted [SASR C-30 (14) p.63]

??? 9-4 Two stretchers readily available [SASR B-1 (III B) p.26]

[location:_______________]

??? 9-5 Employees know location of stretcher and blankets

??? 9-6 Bulletin board used to post current safety material

??? 9-7 Date of last safety item posted on the bulletin board:________________

??? 9-8 Three SCBA available and in good condition in doghouse (or rig floor) [SASR B6 (II B5) p.25]

??? 9-9 Spare derrick belt [SASR C-29 (7) p.47]

??? 9-10 Goggles, face shields and other personal protective equipment kept in doghouse

??? 9-11 BOP function tests done regularly and documented in IADC book

??? 9-12 Drills held and documented in IADC book (BOP, H2S, fire, evacuation) [SASR C-30 (15) p.63]

??? 9-13 Safety meeting topics and attendance documented

??? 9-14 Trip records kept

??? 9-15 Electrical plugs, receptacles, cords, conduit junction boxes comply with API RP-500 C [SASR B-15 (1) p.38]

??? 9-16 Light covers sealed [SASR B-15 (1) p.38]

??? 9-17 Remote BOP controls free of obstruction and accidental operation [SASR C-30 (8) p.63]

??? 9-18 Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

10. DERRICK YES NO N/A YES NO N/A

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??? 10-1 Derrick has a permanent nameplate attached (or available in-site) stating: manufacturer, model number, serial number, hook load capacity, wind load capacity (both with and without pipe in the derrick), and (if applicable) the recommended guying pattern. [SASR C-2 (1) p.45]

??? 10-2 Operating within prescribed limits [SASR C-2 (2) p.46]

??? 10-3 Derrick ladder extends down to rig floor (no need to climb up standpipe, etc.)

??? 10-4 Base of ladder clear of obstructions [SASR C-8 (15) p.49]

??? 10-5 Derrick ladder extends at least 3 feet (91 cm) above each landing platform (including the crown) [SASR C-8 (23) p.50]

??? 10-6 Platforms provided at regular intervals on ladder , or climbing device provided [SASR C-8 (14) p.49]

??? 10-7 Climbing belt always used [SASR C-8 (18) p.49]

??? 10-8 Derrick girts in good condition [SASR C-2 (4) p.46]

??? 10-9 All derricks pins in place c/w safety pins [SASR C-2 (4, 10) p.46]

??? 10-10 Tong counterweight weight ropes minimum 1/2" (12.7 mm) diameter [SASR C-22 (2) p.59]

??? 10-11 Unguided tong counterweights safety tied with minimum 5/8" (15.9 mm) diameter wire rope [SASR C-22 (1) p.59]

??? 10-12 Safety line prevents counter weight from dropping within 8 ft. (2.4 m) of floor [SASR C-22 (1) p.59]

??? 10-13 All sheaves, lights, and other fixtures safety-tied [SASR B-16 (3) p.39 (for lights only)]

??? 10-14 Standpipe adequately anchored

??? 10-15 Kelly hose safety chained at both ends, (chained to the swivel, not chained to the gooseneck) [SASR C-35 (12) p.65]

??? 10-16 Traveling blocks have sheave guards [SASR C-5 (1) p.47]

??? 10-17 Traveling blocks free of projections [SASR C-5 (3) p.47]

??? 10-18 Kelly hook safety latched [SASR C-5 (1) p.47]

??? 10-19 Safety belt c/w shoulder harness in derrick [SASR C-29 (2) p.47]

??? 10-20 Safety belt lanyard minimum 5/8" (15.9 mm) manila rope (not synthetic) with no splices [SASR C-29 (3) p.47]

??? 10-21 Monkey board secured and in good condition

??? 10-22 Adequate tie back and pull back ropes

??? 10-23 Fingers and pads properly pinned and safety chained [SASR C-27 (2) p.60]

??? 10-24 Crown has no openings large enough for a worker to fall through [SASR C-4 (1) p.46]

??? 10-25 Crown bumper blocks (wooden planks) safety tied, or covered with expanded metal, or suitable screen or mesh [SASR C-4 (2) p.46]

??? 10-26 Derrick lights have adequately sealed protective covers [SASR B-15 (1) p.38]

??? 10-27 All electrical connections, plugs, receptacles, cords etc. are in good condition [SASR B-15 (1) p.38]

??? 10-28 Electrician's tape not used in splices or at grommets [SASR B-15 (1) p.38]

??? 10-29 SABA in the derrick (monkey board) [H2S Std. (Offsh) (II-B) p.31]

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??? 10-30 The rig floor cascade system is connected to one 3-outlet cascade

manifold on the monkeyboard [H2S Std. (Offsh) (III-A-2) p.32]

11. CATWALK & PIPE RACKS YES NO N/A YES NO N/A

??? 11-1 Catwalk level, in good condition [SASR C-9 (3) p. 50]

??? 11-2 Catwalk free of tripping hazards [SASR C-9 (3) p. 50]

??? 11-3 Stairs at end of catwalk [SASR C-9 (3) p. 50]

??? 11-4 Pipe racks/tubs level and in good condition [SASR C-9 (1) p. 50]

??? 11-5 Adequate spacers between layers of pipe [SASR C-9 (5) p. 50]

??? 11-6 Workers stand out of the way when rolling, loading, or unloading pipe [SASR C-10 (3) p. 51]

??? 11-7 Pipe key, crowbar, or other safe method used when rolling pipe

??? 11-8 Blocks, pins, or chocks used to prevent pipe from rolling off rack [SASR C-9 (1) p. 50]

??? 11-9 Tag line used when loading or unloading pipe [SASR D-2 (5) p. 67]

12. MANIFOLD & FLARE LINES YES NO N/A YES NO N/A

??? 12-1 Manifold and valves free of obstruction

??? 12-2 Valves wheels turn easily

??? 12-3 Valve handles kept 1/4 turn from the open or closed position

??? 12-4 Casing and drillpipe pressure gauges installed

??? 12-5 Casing and drillpipe pressure gauges easily visible from manual choke operator's position

??? 12-6 Maximum allowable casing pressure posted at manual choke

??? 12-7 Safety chains used for pressure hoses, lines with hammer unions, or chiksans

??? 12-8 Electrical connections, plugs, receptacles Class I, Div. II and lights are properly sealed with a protective cover [SASR B-15 (1) p.38]

13. HELIDECK YES NO N/A YES NO N/A

??? 13-1 Regularly inspected by Aviation

Date of last inspection:_____________

??? 13-2 Non-skid material on helideck

??? 13-3 Outside perimeter lattice in place and in good condition

??? 13-4 Crash box properly equipped box [SASR B-9 (9) p.35] (Note: ONLY Aviation will inspect crash box)

??? 13-5 Fire fighting equipment inspected and operable

Date of last inspection:_____________

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??? 13-6 Safe arrival/boarding procedures used

??? 13-7 Fire team in position for landing/take-off

??? 13-8 Cranes secured (not working) during landing/take-off

14. FIRE FIGHTING EQUIPMENT YES NO N/A YES NO N/A

??? 14-1 30 lb. ABC fire extinguishers provided throughout the rig at strategic areas

??? 14-2 Extinguishers readily accessible

??? 14-3 Extinguisher locations identified

??? 14-4 Extinguishers inspected weekly [SASR B-9 (2) p.35]

??? 14-5 Fire drills held regularly and logged

??? 14-6 Fire hoses kept on rack or reel when not in use [SASR B-9 (13) p.35]

??? 14-7 Fire hoses not used for any other purpose than fighting fires, drills, or testing [SASR B-9 (9) p.35]

??? 14-8 Fire hoses completely unrolled and inspected monthly [SASR B-9 (10) p.35]

??? 14-9 Offshore rigs have a Fire Control Plan permanently exhibited [SASR B9 (6) p.35]

15. COMPRESSED GAS CYLINDERS YES NO N/A YES NO N/A

??? 15-1 Gas cylinders stored upright [SASR B-14 (1) p.38]

??? 15-2 Acetylene bottles (empty or full) always stored upright [SASR B-14 (4) p.38]

??? 15-3 Empty and full gas cylinders stored separately [SASR B-14 (1) p.38]

??? 15-4 Oxidizers stored at least 20 ft. (6.1 m) from fuel gases [SASR B-14 (1) p.38]

??? 15-5 Valve protection caps on all cylinders (without a regulator) [SASR B-14 (2) p.38]

??? 15-6 Gas cylinders hoisted only in a cradle, pallet, or slingboard [SASR B-14 (3) p.38]

16. HAND & POWER TOOLS YES NO N/A YES NO N/A

??? 16-1 Hand held power tools have "dead-man" auto-shutoff devices (tools that can be locked "ON" are expressly forbidden) [SASR B-17 (2) p.40]

??? 16-2 Hand held power tools are double insulated or grounded [SASR B-17 (2) p.40]

??? 16-3 Impact tools (such as drift pins, chisels, hammer wrenches) do not have mushroomed striking surfaces [SASR B-17 (3) p.40]

??? 16-4 Pneumatic power tools are secured to the air line to prevent accidental disconnection [SASR B-17 (7) p.40]

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Bench grinders:

??? 16-5 Tool rests no more than 1/8" (3.2 mm) from abrasive wheel [SASR B-18 (2) p.40]

??? 16-6 Grinding wheel is rated for the machine rpm (grinder rpm stamped on nameplate; wheel rpm rating identified on the wheel blotter) [SASR B-18 (5) p.41]

??? 16-7 Eye hazard sign

??? 16-8 Goggles or face mask available and used

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17. WELDING & CUTTING YES NO N/A YES NO N/A

No welding or cutting performed on: [SASR B-19 (1) p.41]

??? 17-1 …any pipe/vessel containing pressurized fluid or gas

??? 17-2 …any container which contains or did contain flammable liquids or gases, until the container is filled with water or otherwise suitably purged. Used 55-gallon drums are specifically included.

??? 17-3 … in a confined space until the atmosphere has been tested "safe for fire" (0% LEL)

??? 17-4 No welding or cutting on load handling tools or equipment (slips, tongs, elevators, bales, etc.) [SASR B-19 (3) p.41]

??? 17-5 Suitable eye/face protection used when welding, cutting, or grinding [SASR B-19 (6) p.42]

??? 17-6 Maximum acetylene gauge pressure less than 15 psi (103 kPa) [SASR B-19 (7) p.42]

??? 17-7 Acetylene cylinder valves not opened more than 1 1/2 turns [SASR B-19 (7) p.42]

??? 17-8 All gas bottle regulator gauges are in good condition (no cracked glass covers) [SASR B-19 (8) p.42]

??? 17-9 All welding hoses are free from cracks, leaks, burns, worn spots [SASR B-19 (10) p.41]

??? 17-10 No arc-welding cable with damaged insulation or exposed conductors [SASR B-19 (12) p.42]

??? 17-11 No splices in arc-welding cables within 10 ft. (3 m) of the electrode holder [SASR B-19 (13) p.42]

??? 17-12 Portable arc-welding machines are suitably grounded [SASR B-19 (15) p.42]

18. CRANE OPERATIONS AND SLINGS YES NO N/A YES NO N/A

Note: The crane operator certification information on the title page of this inspection checklist must be completed in full.

???18-1 Crane has valid Aramco Crane Inspection Certificate [SASR D-1 (1b) p.65]

Crane #:____________________

Cert. Expiry:_________________

Crane #:____________________

Cert. Expiry:_________________

???18-2 Tag lines used [SASR D-2 (5, 6) p.67]

???18-3 All slings identified with Manufacturer name or logo, a unique identifier number, and safe working limit (SWL) [S.A. G.I. 7.029 (4.1)]

???18-4 All slings have a detailed visual inspection every 6 months, recorded in a sling inspection log [S.A. G.I. 7.029 (7.2)]

???18-5 Spreader bars identified with Manufacturer name, serial number, date of load test certification, and (in English and Arabic) safe working limit (SWL) [S.A. G.I. 7.029 (6.2)]

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???18-6 Spreader bars have a semi-annual documented inspection [S.A. G.I. 7.029

(6.2)]

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19. GENERAL YES NO N/A YES NO N/A

???19-1 All stairs with more than 4 risers have handrails [SASR C-8 (4) p.49]

???19-2 All working surfaces higher than 4 feet (1.2 m) have standard handrails (42" handrail, 21" knee rail, 4" toe board) [SASR C-8 (5) p.49]

???19-3 Safety harnesses used when working higher than 10 feet (3.1 m) above grade [SASR C-8 (6) p.49]

???19-4 All ladders (fixed and portable) in good shape with no bent, broken, or damaged side rails and steps [SASR C-8 (24) p.50]

???19-5 Portable ladders are safety tied [SASR C-8 (26) p.50]

???19-6 PFD's worn when working over water [SASR E-1 (5) p.50]

???19-7 Noise protection signs posted where required [SASR B-3 (8) p.17]

???19-8 Sign posted requiring visitors to report to radio room immediately upon arrival

???19-9 Safety and abandonment procedures orientation given to all arriving newcomers, visitors, etc.; and documented in a log book

???19-10 Workers wear appropriate protective equipment at all times

???19-11 Pre-job safety meetings conducted & documented (e.g. casing, testing, laydown)

???19-12 No rings, necklaces, long hair, or loose clothing

???19-13 Overall housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

???19-14 At least one qualified First Aid person on each shift [GI 150.002]

???19-15 Telephone numbers of physician, hospital, ambulance, and helicopter service posted in the Toolpusher’s office, the nurse's station, and the radio room [SASR B1 (4) p.15]

???19-16 Crews trained in the following [SASR B6 (4) p.23]

???19-16a) H2S characteristics and toxicity ???19-16b) Detection and warning systems on

location ???19-16c) Safe briefing area locations ???19-16d) Evacuation procedures ???19-16e) Rescue procedures ???19-16f) First aid for victims ???19-16g) Inspection, maintenance, and use of

emergency breathing equipment ???19-16h) Drill procedure

???19-17 Two safe briefing areas marked out [SASR B6 (4c) p.23]

20. ENGINE ROOM YES NO N/A YES NO N/A

???20-1 H2S monitor sensor heads placed as near as practical to motor man's work area in the motor room [H2S Std. (Offsh) (I-B) p.30]

???20-2 The H2S/gas alarm can be seen or heard [H2S Std. (Offsh) (I-E) p.30]

???20-3 The rig floor cascade system is connected to one 3-outlet cascade manifold in the motor room [H2S Std. (Offsh) (III-A-4) p.32]

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???20-4 One SABA in the motor man's work area in the motor room [H2S Std. (Offsh) (II-B) p.31]

???20-5 Emergency shut off for fuel lines located in an area where they can be safely operated in the event of an engine room fire

???20-6 Fire protection equipment tested, date of last inspection:___________________

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Previous Issue: 1 December, 1996 Next Planned Update: 1 February, 1998 Revised paragraphs are indicated in the right margin. Page 1 of 10

Engineering Standard

SAES-B-062 30 June, 1997

Onshore Wellsite Safety

Loss Prevention Standards Committee Members Lamp, W.P., Chairman Baghabrah, M.A. Buck, R.A. Fadley, G.L. Mullen, M.A. Mustafa, S.G. Terris, T.M.

Saudi Aramco DeskTop Standards Table of Contents 1 Scope............................................................ 2 2 Conflicts And Deviations............................... 2 3 References.................................. ................. 2 4 Determination Of Rupture Exposure Radius. 3 5 Wellsite In Populated Area........................... 3 6 Population Analysis Procedure..................... 4 7 Wellsites....................................................... 4

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8 Well Safety Valves And Wellsite Hardware.. 6 9 Abandoned Wells......................................... 8 10 Drilling Rig Access Routes........................... 8

1 Scope

1.1 This Standard covers requirements for site layout, wellhead protection, access, and flow isolation related to oil/gas production wells, hydrocarbon injection wells, delineation/monitoring wells, abandoned/suspended wells, and wellsite facilities located onshore. Water injection and supply wells which are open to or pass through a geological zone which could produce hydrocarbons are also included.

1.2 This standard shall apply in the following circumstances:

1.2.1 All new wellsites.

1.2.2 All new wells drilled at existing wellsites.

1.2.3 Existing wells located in areas which have become populated per this standard shall be upgraded as necessary during workovers.

2 Conflicts And Deviations

2.1 Any conflicts between this Standard and other applicable Saudi Aramco Engineering Standards (SAESs), Saudi Aramco Materials System Specifications (SAMSSs), Saudi Aramco Standard Drawings (SASDs), or industry standards, codes, and forms shall be resolved in writing by the Company or Buyer Representative through the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

2.2 Direct all requests to deviate from the Standard in writing to the Company or Buyer Representative, who shall follow internal company procedure SAEP-302 and forward such requests to the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

3 References

All referenced specifications, standards, codes, forms, drawings, and similar material shall be of the latest issue (including all revisions, addenda, and supplements) unless stated otherwise.

3.1 Saudi Aramco References

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Saudi Aramco Engineering Procedure

SAEP-302 Instructions for Obtaining a Waiver of a Mandatory Saudi Aramco Engineering Requirement

Saudi Aramco Engineering Standards

SAES-B-055 Plant Layout

SAES-M-006 Fencing

Saudi Aramco Materials System Specification

45-SAMSS-005 Wellhead Equipment

Saudi Aramco Standard Drawings

AD-036010 Wellhead Guard Posts

AB-036685 Wellhead Guard Barrier

AA-036247 Windsock Pole

AA-036454 Remote Controls for Onshore Wells

3.2 Industry Codes and Standards

American Petroleum Institute

API RP 14B Design, Installation, Repair and Operation of Subsurface Safety Valve Systems.

API SPEC 6A Specification for Wellhead and Tree Equipment

4 Determination Of Rupture Exposure Radius (RER)

The appropriate rupture exposure radius (100 ppmv hydrogen sulfide (H2S) or lower flammable limit (LFL) basis) shall be plotted from the wellhead at the distance indicated in Table 1. For fields, reservoirs, or service not listed, the rupture exposure radius shall be obtained from the Saudi Aramco Loss Prevention Department's Technical Services Unit.

5 Wellsite In Populated Area

5.1 A well is in a populated area if the population density index within the rupture exposure radius exceeds 20, or if a school, hospital, hotel, penal institution, or retail complex, existing or planned, is included within the rupture exposure radius of that well.

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Table 1 - RER For Oil/Gas Wells In Populated Areas

Field Reservoir RER (m) Ain Dar Arab-D 1630 Abqaiq Arab-D 980 Berri Arab-C 1650 Central Arabia Unayzah 200 Dammam Arab-D 1500 Manifa Lower Ratawi 2400 Qatif Arab-C 2400 Shedgum Arab-D 375 Uthmaniyah Arab-D 1350 Shedgum Khuff Gas -B 1200 Shedgum Khuff Gas -C 1500 Uthmaniyah Khuff Gas -C 1620

5.2 For purposes of this Standard, roads are not deemed to generate populated areas. Where wells are located near areas of potential concern, such as roads, parking areas, or camp sites, the Proponent Operating/Engineering Department shall determine whether additional precautionary measures, such as subsurface safety valves, fencing, etc., are required.

6 Population Analysis Procedure

6.1 The boundaries of Saudi Aramco and non-Saudi Aramco development areas, present and planned, within the rupture exposure radius of a well location shall be obtained from the Land and Lease Division of Government Affairs Services Department.

6.2 The population density index at a well location is defined as the sum of the existing density index and the virtual density index values for the site.

6.3 Buildings having more than 4 stories shall be included in the population density index as a number of equivalent buildings. The number of equivalent buildings shall be calculated by dividing the number of stories in the building by 3 and rounding up to a whole number.

6.4 To determine the existing density index for a well location, count the number of buildings lying within the rupture exposure radius of the well. The resulting whole number is the existing density index value.

6.5 For areas within the rupture exposure radius of a well which are planned for development, the virtual density index shall be calculated as follows:

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6.5.1 Calculate the land area in square meters (m²) of each development which is included within the rupture exposure radius of the well.

6.5.2 Multiply the included area by 0.00075 (exact) and round up. The resulting whole number is the virtual density index for this well location.

6.6 Not to be included in these calculations are temporary facilities which will be in place for less than 6 consecutive months.

7 Wellsites

7.1 A wellsite is defined as the well(s), prepared drilling pad, well flare/burnpit area, and buffer zone. The entire wellsite constitutes an exclusive land use. No other uses are permitted in this area. See Figure 1, page 10.

7.2 For oil/gas wells, the following layout and spacing requirements apply to individual low-pressure wells, which for purposes of this Standard are defined as wells for which the shut-in wellhead pressure is not expected to exceed 25000 kPa (3600 psig). For oil/gas wells that are expected to have shut-in wellhead pressures in excess of 25000 kPa, and for all gas injection wells, layout and spacing requirements are to be determined case by case, with concurrence by the Chief Fire Prevention Engineer. For multiple low-pressure oil/gas wells to be drilled in one location, layout and spacing requirements are to be determined case by case, with concurrence by the Chief Fire Prevention Engineer.

7.2.1 The minimum distance from a well to the outer edge of the wellsite shall be 105 m.

7.2.2 Well burnpit shall be located on a bearing between 60 degrees through 225 degrees true and at a minimum distance of 60 m from the well.

Commentary Note:

A 60 m buffer zone shall be maintained around the burnpit. For additional burnpit spacing requirements, see paragraph 7.7.

7.3 Vehicular Crash Protection and Fencing

7.3.1 In populated areas, where the wellsite is already enclosed by a fence, or where the well is located more than 150 m from an existing or planned public road, the wellhead shall be protected with guard posts per Saudi Aramco Drawing AD-036010. All other wellheads shall be protected with a guard barrier per Saudi Aramco Standard Drawing AB-036685. Guard barriers (AB-036685) may be used in place of the guard posts at the request of the Proponent.

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7.3.2 Wellsites in populated areas shall be enclosed by a fence meeting the specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant. Two gates shall be 18 m wide rig-access gates. The locations of these rig-access gates shall permit access to all wells on the wellsite from either gate.

7.4 The drilling pad shall be level.

7.5 A wind sock pole per Saudi Aramco Standard Drawing AA-036247 and a wind sock per SAMS Catalog Number 47-947-030-00 are to be permanently installed at each active production or injection wellsite in a populated area.

7.6 Following are minimum spacing requirements from low-pressure oil/gas wells.

- 450 m minimum spacing between oil/gas wells and any of the following: process areas; major shipping pump, blending/booster pump, or fire pump areas; tetraethyl lead (TEL) facilities; LPG loading racks; atmospheric or pressure storage vessels; boilers and power generation facilities; major electric distribution centers; buildings, property lines, and residential areas; elevated flare stacks, unrelated ground flares, and unrelated burn pits.

- 200 m minimum spacing between oil/gas wells and main overhead power lines.

- 105 m minimum spacing between oil/gas wells and cathodic protection (CP) and other noncritical power lines.

- 105 m minimum spacing between oil/gas wells and right-of-way or camel fence, whichever is greater, of Saudi Aramco or Government highways, paved roads, or railroads.

- 105 m minimum spacing between oil/gas wells and pipelines.

7.7 Flares and burnpits for low-pressure oil/gas wells are viewed as infrequently-used facilities that are under constant attendance and supervision of drilling personnel during the drilling of the well. Hence, spacing requirements are less than normal minimums specified for burnpits in SAES-B-055. Minimum requirements for well burnpits are as follows:

- Well burnpits shall be no closer than 150 m to main overhead power lines or residential areas.

- Well burnpits shall be no closer than 105 m to CP and other noncritical power lines.

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- Well burnpits shall be no closer than 105 m to highway right-of-way/camel fence, paved road, or railroad.

- Well burnpits shall be no closer than 60 m to aboveground pipelines or 15 m to buried lines.

7.8 Water gravity injector, power injector, or supply wells have a basic 105 m spacing requirement from all other facilities. For gas injection wells, see paragraph 7.2.

8 Well Safety Valves And Wellsite Hardware

8.1 Hydrocarbon Producing and/or Hydrocarbon Injection Wells - General Requirements

8.1.1 All well installations shall be in accordance with the specifications prepared by Saudi Aramco Drilling and Workover Engineering. Naturally flowing wells shall be completed in a manner which permits flow only through a tubing string. They shall be equipped with a downhole packer or polished bore receptacle.

8.1.2 The specification break point from the high pressure rated wellhead piping to the lower pressure rated flowline piping shall be within the wellsite, upstream of any scraper launcher.

8.1.3 A manual isolation block valve to API SPEC 6A and Saudi Aramco wellhead equipment specifications shall be installed at the downstream end of the wellhead piping of each well. This valve shall be pressure rated equal to the wellhead piping. (Refer to 45-SAMSS-005).

Where required by the Proponent Operating Department, a second block valve shall be installed on the wellsite, downstream of the valve in 8.1.3, for flowline isolation. Pressure rating of the valve shall either match the API SPEC 6A valve or the downstream flowline pipe specification, as required by the Proponent Operating Department.

8.1.4 All wells shall have a manual lower master valve.

At the discretion of the Proponent Operating Department, oil wells may be equipped with manual remote operators attached to the master valve and/or wing valve. If manual remote operators are installed on oil wells, they shall be in accordance with AA-036454.

8.1.5 Any lockout device used to hold a surface safety valve in the open position by restricting movement of the valve stem shall be constructed

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of fusible materials with a melting point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature.

8.1.6 All gas production wells shall have three spring-assisted failsafe surface safety valves (SSV), triggered when an abnormally high or low pressure is sensed in the high pressure piping downstream of the choke. Fusible devices with a set point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSVs.

8.1.7 Hydrocarbon injection well flowlines shall each be provided with a check valve in the wellhead piping.

8.2 Producing Wells in Populated Areas

8.2.1 Supplemental to the general requirements, wells in populated areas shall comply with the following:

8.2.2 On oil wells the upper wellhead master valve shall be a spring-assisted fail-safe surface safety valve (SSV), triggered when an abnormally low pressure is sensed. Triggering by abnormally high pressure is required only when necessary to protect the downstream flowline. A fusible device with a melting point 30 Celsius degrees above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSV.

8.2.3 A Subsurface Safety Valve (SSSV) per API RP 14B specification shall be installed more than 60 m below ground level in oil wells. The SSSV shall be controlled by the low pressure pilot. Closure triggered by an abnormal condition in the high pressure piping downstream of the choke shall be provided when required by the Proponent Operating Department. A fusible device with a melting point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature, shall be installed on the wellhead to separately trigger the SSSV.

8.3 Power Water Injection Wells

Power water injection well flowlines shall each be provided with a check valve in the wellhead piping.

8.4 Observation Wells

Wells shall be equipped with the relevant safety devices equivalent in function to those that would be required for a producing well at the same location.

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Page 9 of 10

8.5 Suspended Wells

Wells shall be suspended in accordance with Producing Operations requirements. Suspension procedures for wells shall be documented by Producing Operations and shall be available for review.

9 Abandoned Wells

The following requirements apply to a wellsite only if all its wells have been permanently plugged and if it is located in a populated area.

9.1 The perimeter of the drilling pad shall be provided with a fence (SAES-M-006, Type III) if there is no fence at the perimeter of the buffer zone.

9.2 The fence shall have one lockable vehicle gate 10 m wide.

9.3 One access route 10 m wide shall be maintained to the wellsite gate.

10 Drilling Rig Access Routes

Two access routes shall be available to each wellsite. These shall meet the following requirements:

10.1 Each access route shall be 18 m wide, terminating at a rig access gate.

10.2 Vertical clearance over the access routes shall be 14 m minimum.

10.3 An access route shall not include grades or transverse slopes of more than 5 percent.

10.4 No obstruction is allowed on an access route.

10.5 The minimum radius of curvature of access routes shall be 70 m. The center point of all access route curves shall be outside the wellsite served.

10.6 One of the access routes required by paragraph 10.1 above shall have within it a prepared roadway consisting of a compacted marl running surface 0.3 m thick and 7.0 m wide with 3.5 m wide shoulders, giving a total clear road width of 14 m.

Revision Summary 1 December, 1996 Editorial revision to convert document to new format. 30 June, 1997 Editorial revision in paragraph 7.1.

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Figure 1 - Wellsite Location Spacing

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PREPARED BY: S.W. SMITH REVIEWED BY: S. AL-DOSSARY APPROVED BY: G.K. SHAMMARY

SAUDI ARAMCO

DRILLING MAINTENANCE

DIVISION

PROCEDURE

NUMBER

WRS-602 REVISION

0 TYPE

WELDING PROCEDURE DATE

7 MAY, 1996 SUPERSEDES SPEC. DATED

NONE

TITLE:

INSTALLATION OF SLIP ON/WELD ON CASING HEADS

Page 1 of 4

1.0 SCOPE

This procedure applies to the installation of all slip on casing heads both in the field and in the shop.

2.0 INDEX

1.0 SCOPE 2.0 INDEX 3.0 REQUIRED MATERIALS 4.0 PROCEDURE

4.1 PREPARATION 4.2 CASING CUT OFF 4.3 LEVELING HEAD AND TACK WELDING 4.5 WELDING TECHNIQUE 4.6 POSTHEATING AND COOLING 4.7 TESTING

3.0 REQUIRED MATERIALS

Welds shall be performed using Shielded Metal Arc. Low hydrogen electrodes shall be used. These are classes EXX15, EXX16, EXX18, or EXX28 of AWS 5.1 latest edition. SAMS catalog numbers for acceptable electrodes, temperature sticks and fire blankets are given below.

Item Description SAMS Number 1 Electrode, E-6010 AWS A5.1, 1/8” Dia. 20-484-024 2 Electrode, E-7018 AWS A5.1, 5/32” Dia. 20-483-074 3 Electrode, E-7018 AWS A5.1, 3/16” Dia. 20-483-078 4 Temperature Stick, 400 oF 20-477-135 5 Blanket, Silica Cloth (rated to 3,000 oF) 20-532-460

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4.0 PROCEDURE

4.1 PREPARATION 4.1.1 Avoid anyone working above the welder on the drill floor. 4.1.2 The wellhead should be protected from dripping mud, water or oil and from

adverse weather conditions such as wind or rain. 4.1.3 The head and casing in the weld area shall be dry and free from paint, grease,

scale, rust or dirt. 4.1.4 Fire extinguishers shall be placed in convenient reach of a stand-by/fire watch

man.

4.2 CASING CUT OFF 4.2.1 Cut two holes in the top 1 foot of the last casing joint. 4.2.2 Install cable and shackles into the holes to hold casing when rough cut is

made. 4.2.3 Determine from Rig Foreman the height required for the final cut. 4.2.4 Cut window in casing 6 to 8 inches above final cut height. Let mud and fluids

drain. 4.2.5 Complete rough cut. 4.2.6 Bail or siphon fluids 6 to 8 inches below final cut height. 4.2.7 Mark and make final cut. 4.2.8 Grind off the top 3/32” of casing to remove the HAZ (Heat Affected Zone).

DO NOT BEVEL THE CASING.

4.3 LEVELING HEAD AND TACK WELDING 4.3.1 Bail or siphon fluids/mud from casing to 1 foot below the weld area. Check

fluid level continuously throughout procedure to ensure that fluid level stays ? 1 foot below weld area, bailing or siphoning as necessary.

4.3.2 Remove the test plug and ensure that the test port is open. 4.3.3 Pick up Casing Head and slip on to casing stub. 4.3.4 Welding cable should be firmly clamped to the wellhead. 4.3.5 Level head and tack-weld in place.

4.4 PREHEATING 4.4.1 The Casing Head and casing shall be preheated to a temperature of 400 oF

for at least 3 inches above and below the weld. 4.4.2 Preheating temperature shall be verified by using 400 0F Temperature stick.

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4.4.3 The rosebud heating torch shall be continuously used during welding to keep

the head at approximately 400 0F.

4.5 WELDING TECHNIQUE

4.5.1 Use 1/8” E-6010 Electrode and step weld first bead (root pass). That is weld 2” to 4” (WELD 1), then move 1800 weld another 2” to 4” (WELD 2). Then move 1/2 way between the first two welds and weld 2” to 4” (WELD 3) then move 1800 and weld 2” to 4” (WELD 4) and continue (WELDS 5, 6, 7, 8 etc.), as shown in Figure 4.5-1A. Continue welding 2” to 4” 1/2 way between two welds then 2” to 4” 1800 opposite until the first pass is completed (as shown in Figure 4.1-5B).

4.5.2 The second pass shall be made with a 5/32” E-7018 electrode and may be continuous. The balance of the welding groove shall be filled using 3/16” E-7018 electrodes.

4.5.3 All beads shall be stringer beads with good penetration and should be thoroughly peened before applying the next bead. There should be no undercutting and welds shall be workmanlike in appearance.

4.5.4 Complete inside welds by repeating steps 4.5.1 through 4.5.3.

4.5.5 Grind inside welds as necessary to leave the required drift diameter (as per Rig Foreman).

4.6 POSTHEATING AND COOLING

4.6.1 Verify that temperature of the weld area is 400 0F using temperature stick. If temperature is below 400 0F reheat.

1

3 4

5

6

7

8

2

Figure 4.5-1A: Begin Step Weld Figure 4.5-1B: Finish Weld

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4.6.2 Wrap casing head with Silica cloth blanket to protect from wind and allow

the head to slowly cool.

4.7 TESTING

4.7.1 After the casing head has cooled to ? 150 0F (cool enough to be able to lay your hand on the head. Test the weld using oil to the pressure required by the Drilling Program. DO NOT EXCEED 80% OF CASING COLLAPSE PRESSURE.

4.7.2 Re-install the test plug.

4.8 REPAIR OF DEFECTS

4.8.1 If any leaks are detected one of three methods shall be used to repair the leak. The method used will be determined by the type of leak.

4.8.1.1 Blow Hole/Pin Hole Leak: e.g.: Single leak through small hole

4.8.1.1.1 Grind out hole to good metal at least 1” to each side.

4.8.1.1.2 Preheat area to 400 0F at least 3” to each side of ground area and re-weld. Wrap casing head with silica blanket and let cool. Test as in section 4.7.

4.8.1.2 Multiple Blow Hole/Pin Hole Leak:

4.8.1.2.1 Grind out holes to good metal ? 2” to each side of each hole to ensure no communication between holes.

4.8.1.2.2 Preheat area to 400 0F at least 3” to each side of ground area and re-weld. Wrap casing head with silica blanket and let cool. Test as in section 4.7.

4.8.1.3 Crack:

4.8.1.3.1 If a crack is detected grind out to good metal 3600 around. Preheat entire head, either inside or outside as required, as in section 4.4. Re-weld number of beads as

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necessary to completely fill ground area. Post heat and cool as per section 4.6. Test as in section 4.7.


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