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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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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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=

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 Te