IRP 04-Well Testing and Fluid handling_final 2012.pdf

Edition 3.2

Sanction June Date 2012

WELL TESTING AND FLUID HANDLING

AN INDUSTRY RECOMMENDED PRACTICE (IRP) FOR THE CANADIAN OIL AND GAS INDUSTRY

VOLUME 4 – 2012

SANCTIONED

COPYRIGHT/RIGHT TO REPRODUCE

Copyright for this Industry Recommended Practice is held by Enform, 2012. All rights reserved. No part of this IRP may be reproduced, republished, redistributed, stored in a retrieval system, or transmitted unless the user references the copyright ownership of Enform.

DISCLAIMER

This IRP is a set of best practices and guidelines compiled by knowledgeable and experienced industry and government personnel. It is intended to provide the operator with advice regarding the specific topic. It was developed under the auspices of the Drilling and Completions Committee (DACC).

The recommendations set out in this IRP are meant to allow flexibility and must be used in conjunction with competent technical judgment. It remains the responsibility of the user of the IRP to judge its suitability for a particular application.

If there is any inconsistency or conflict between any of the recommended practices contained in the IRP and the applicable legislative requirement, the legislative requirement shall prevail.

Every effort has been made to ensure the accuracy and reliability of the data and recommendations contained in the IRP. However, DACC, its subcommittees, and individual contributors make no representation, warranty, or guarantee in connection with the publication of the contents of any IRP recommendation, and hereby disclaim liability or responsibility for loss or damage resulting from the use of this IRP, or for any violation of any legislative requirements.

AVAILABILITY

This document, as well as future revisions and additions, is available from

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Well Testing and Fluid Handling IRP4

June 2012 i

TABLE OF CONTENTS Table of Contents ..................................................................... i List of Tables .......................................................................... iv

List of Figures.......................................................................... v

4.0 Scope and Contents ....................................................... vi 4.0.1 Purpose ....................................................................................... vi 4.0.2 Audience ..................................................................................... vi 4.0.3 Scope and Limitations ................................................................... vi 4.0.4 Revision Process ........................................................................... vi 4.0.5 Revision History .......................................................................... vii 4.0.6 Sanction .................................................................................... viii 4.0.7 Acknowledgement ....................................................................... viii 4.0.8 Copyright Permissions ................................................................. viii 4.0.9 Scope ........................................................................................ viii 4.0.10 Introduction ................................................................................. ix 4.0.11 Symbols and Abbreviations ............................................................ ix 4.0.12 Abbreviations and Definitions .......................................................... x 4.0.13 Common Terms of Reference and IRP’s For All Operations In This Volume

................................................................................................ xvi

Appendix I ........................................................................... xlvi Atmospheric Fluid Scrubber Selection Guidelines ..................................... xlvi

Appendix II ........................................................................ xlvii Pressure Rating Formula for Seamless Pipe ............................................. xlvii

4.1 Drill Stem Testing ........................................................... 1

4.1.1 Scope ...........................................................................................1 4.1.2 Planning a Drill Stem Test ...............................................................1 4.1.3 On-Site Pre-Test Guidelines ............................................................1 4.1.4 Drill Stem Testing Guidelines...........................................................2 4.1.5 Sour Drill Stem Test Guidelines .......................................................5

Appendix III ............................................................................ 8

Recommended Drill Stem Testing Services Inspection Checklist .....................8

IRP4 Well Testing and Fluid Handling

ii June 2012

4.2 Well Testing .................................................................. 11

4.2.1 Wellhead Control ......................................................................... 11 4.2.2 Well Testing Equipment Capacities and Pressure Ratings .................. 13 4.2.3 H2S Service Equipment Requirements ............................................ 18 4.2.4 Well Testing Equipment Material Conformance ................................ 19 4.2.5 Equipment Inspections ................................................................. 21 4.2.6 Well Testing Equipment Spacing .................................................... 22 4.2.7 Pre – Test Equipment Check and Pressure Test................................ 25 4.2.8 Operational Safety ....................................................................... 26 4.2.9 Well Testing Workers ................................................................... 28

Appendix IV .......................................................................... 34

Lease Layout Schematics ........................................................................ 34 Sweet Wells .......................................................................................... 35 Frac Flowback with Pressure Tank Minimum Spacing Requirements .............. 35 Cold Separators Minimum Spacing Requirements ....................................... 36 Heated Test Unit Minimum Spacing Requirements ...................................... 37 Sour Wells ............................................................................................ 38 Frac Flowback with Pressure Tank Minimum Spacing Requirements .............. 38 Heated Test Unit, Pressure Tank and Closed Pressure Storage Tanks Minimum

Spacing Requirements ..................................................................... 39 Heated Test Unit and Pressure Tank Minimum Spacing Requirements ........... 41

Appendix V ............................................................................ 42

Production Testing Services Inspection Checklist ....................................... 42

Appendix VI .......................................................................... 48

FLARESTACK MAXIMUM AND MINIMUM FLARE RATES ...................................... 48 Gas Exit Velocity of 50.8 mm (2”) Pipe ..................................................... 49 Gas Exit Velocity of 76.2 mm (3”) Pipe ..................................................... 50 Gas Exit Velocity of 101.6 mm (4”) Pipe ................................................... 51 Gas Exit Velocity of 152.4 mm (6”) Pipe ................................................... 52 Gas Exit Velocity from 203.2 mm (8”) Pipe ............................................... 53 Gas Exit Velocity from 254 mm (10”) Pipe ................................................ 54

Appendix VII ......................................................................... 55

Hydrate Charts ...................................................................................... 55

4.3 Other Flowbacks ........................................................... 57

4.3.1 Flowing to Open Top Tank............................................................. 57 4.3.2 Pumping or Circulating a Well to an Open Tank System .................... 59 4.3.3 Wellhead Control ......................................................................... 60 4.3.4 Location of The Rig Pump ............................................................. 60 4.3.5 Well Killing Operations ................................................................. 60 4.3.6 Snubbing Operations .................................................................... 63 4.3.7 Recovery and Handling of High Vapour Pressure Fluids ..................... 66 4.3.8 Well Site Workers Competency ...................................................... 76


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4.4 Loading, Unloading and Transportation of Fluids .......... 77

4.4.1 Fluid Hauling Company Procedures ................................................ 77 4.4.2 Fluid Characteristics ..................................................................... 78 4.4.3 Loading, Unloading and Transportation Practices ............................. 78 4.4.4 Fluid Hauling Company Worker Qualifications .................................. 82 4.4.5 Hydrocarbon Transportation: Class & Packing Group (Boiling Point, Flash

Point & Vapour Pressure) .................................................................. 82

Appendix VIII ....................................................................... 84

BIBLIOGRAPHY ....................................................................................... 84


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LIST OF TABLES Table 1: Flammable Limits .................................................................... xxiv Table 2: Pressure Rating of Seamless Pipe .............................................. xlix Table 2: IRP 15.3.1.5 Reserve Circulation Sand Cleanout Equipment ............ 65


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LIST OF FIGURES Figure 1: Code for Electrical Installations at Oil and Gas Facilities ................ 24 Figure 2: Propane Saturation Curve ......................................................... 69 Figure 3: Heat of Vapourization ............................................................... 70 Figure 4: Liquid Vapour Chart .................................................................. 71 Figure 5: Butane Saturation Curve ........................................................... 72 Figure 6: Propane/Butane Mixtures Saturation Curves ................................ 73 Figure 7: Other Saturation Curves ........................................................... 74 Figure 8: Propane/Methane ..................................................................... 75


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4.0 SCOPE AND CONTENTS 4.0.1 PURPOSE The purpose of this document is to ensure that guidelines for well testing and fluid handling operations are in place and readily available for all personnel.

Industry Recommended Practice (IRP) 4 is intended to supplement existing standards and regulations. It is also intended to establish guidelines in areas where none existed previously.

4.0.2 AUDIENCE The intended audience of this document includes oil and gas company engineers, field consultants, well testing and fluid hauling personnel, other specialized well services personnel, and regulatory bodies.

4.0.3 SCOPE AND LIMITATIONS This IRP includes pertinent information about well testing, including the following:

• Personnel Requirements

• Drill Stem Testing

• Loading, Unloading, and Transportation of Fluids

• Operational Procedures

IRP 4 supplements existing standards and regulations, and provides guidelines and recommendations where none existed previously. It also refers to other pertinent standards where appropriate, and provides information on how to access them. A full list of the documents referred to in this IRP plus other useful reference material is provided in APPENDIX VIII.

4.0.4 REVISION PROCESS Industry recommended practices (IRPs) are developed by Enform with the involvement of both the upstream petroleum industry and relevant regulators. IRPs provide a unique resource outside of direct regulatory intervention.

This is the second revision to IRP 4. Those who have been familiar with the first two editions of IRP 4 should take the time to review this edition thoroughly, as it has been completely redeveloped to address issues brought forward since the last edition by industry and government stakeholders.

Technical issues brought forward to the Drilling and Completions Committee (DACC) as well as scheduled review dates can trigger a re-evaluation and review of this IRP, in whole or in part. For details on the specific process for the creation and revision of IRPs,


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visit the Enform website at www.enform.ca.

4.0.5 REVISION HISTORY In 1988 a Well Testing and Fluid Handling Subcommittee (WTFHSC) consisting of representatives from CAODC, CAPP, PSAC, Alberta OH&S, and the Alberta ERCB were formed. Under the auspices of the Drilling and Completion Committee (DACC), the WTFHSC mandate was to investigate and develop minimum recommended practices respecting equipment, procedures and workers for the safe testing of wells and handling of fluids. The Recommended Practice (ARP) documents were developed during well testing and fluids handling operations at wells in Alberta; and were fully supported by the Alberta ERCB and Alberta OH&S.

In 1999, the scope and breath of recommended practices encompasses many more issues, companies, associations and governments. The reference to Alberta in the title of these practices is changed to industry (IRP ) to better reflect the broader scope. Where industry has grown to other regions of western Canada, these IRP’s continue to assist companies in their daily operations; These IRP’s are intended to follow the user to any site, anywhere in the world, as a minimum operating practice.

In 2005 IRP 4 needed a review and update to reflect the changes in industry and legislation. With approval from DACC a new committee was formed to address the need for a complete review and update of the document.

In 2009 IRP 4 added a new section 4.3.7 High Reid Vapour Fluid Recovery and Handling Hyperlinks were updated on all other sections.

In 2012 IRP 4 revised section 4.3.7 High Reid Vapour Fluid Recovery and Handling Hyperlinks were updated on all other sections.

http://www.enform.ca/publications/IRP/default.aspx�


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4.0.6 SANCTION The following organizations have sanctioned this document:

• Canadian Association of Oilwell Drilling Contractors (CAODC)

• Canadian Association of Petroleum Producers (CAPP)

• Petroleum Services Association of Canada (PSAC)

• Small Explorers & Producers Association of Canada (SEPAC)

4.0.7 ACKNOWLEDGEMENT This IRP under the auspices of the Drilling and Completions Committee (DACC), was originally developed as an Alberta Recommended Practice (ARP) by the Well Testing and Fluid Handling subcommittee, and subsequently updated by the Well Testing Committee in 1999.

4.0.8 COPYRIGHT PERMISSIONS This IRP includes documents or excerpts of documents as follows, for which permission to reproduce has been obtained:

Copyrighted Information Used In Permission from

Figure 1 Page 28 Safety Code Council of Alberta

4.0.9 SCOPE The purpose of this series of IRPs is to enhance safety during well testing and fluid handling operations of gas and oil wells.

4.1 Drill Stem Testing Guidelines contains recommended practices for DST operations including: test planning, as well as pre-test, post-test, and sour testing guidelines.

4.2 Well Testing details recommended practices for Well Testing operations, including: equipment design and operation, worker requirements and qualifications, purging and pressure testing, operational safety, and safety equipment.

4.3 Other Flowbacks addresses recommended practices for service rig operations involving the flowback of fluids from the well. Matters addressed include: produced fluids, venting, well control, equipment, procedures, and well site workers.

4.4 Loading, Unloading, and Transportation of Fluids provides recommended procedures for the safe transfer of fluids from temporary and permanent production facility tanks to trucks. The procedures emphasize sour fluids and high vapour pressure hydrocarbon mixtures. The IRP also addresses transportation.

The practices described in the IRPs should be considered in conjunction with other industry recommended practices, individual operator’s well testing and fluid handling


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practices, and site specific considerations. It is recognized that other procedures and practices as well as new technological developments may be equally effective in promoting safety and efficiency.

4.0.10 INTRODUCTION An integral part of the exploration and development of oil and gas resources is reservoir evaluation. Evaluation methods with the greatest inherent environmental and safety concerns are those which remove reservoir fluids by means of drill stem testing, well testing or any other methods of flowback.

The avoidance of developing a combustible hydrocarbon gas/air mixture, and the safe handling of highly volatile reservoir or stimulation fluids, and corrosive or toxic fluids are of concern when evaluating a well.

The environmental, safety, and health risks associated with well testing and fluid handling can be minimized by properly trained workers implementing prudent procedures and using properly designed equipment.

4.0.11 SYMBOLS AND ABBREVIATIONS

ASME: American Society of Mechanical Engineers

ASTM: American Society of Testing and Materials

API: American Petroleum Institute

ERCB: Energy Resource Conservation Board (formerly AEUB)

CAPP: Canadian Association of Petroleum Producers

CBM: Coalbed Mehane

CAODC: Canadian Association of Oilwell Drilling Contractors

CPA: Canadian Petroleum Association

CSA: Canadian Standards Association

CRN: Canadian Registration Number

CTU: Coil Tubing Units

DACC: Drilling and Completions Committee

DST: Drill Stem Test

ESD: Emergency Shut Down (valve)


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IRP: Industry Recommended Practice

JSA: Job Safety Analysis

LEL: Lower Explosive Limit

MAWP: Maximum Allowable Working Pressure

MSDS: Materials Safety Data Sheet

NACE: National Association of Corrosion Engineers

NORM: Naturally Occurring Radioactive Material

OEL: Occupational Exposure Limit

OH&S: Occupational Health & Safety

OEM: Original Equipment Manufacturer

PSV: Pressure Relief Valve

PSAC: Petroleum Services Association of Canada

PPE: Personal Protective Equipment

SABA: Supplied Air Breathing Apparatus

SCBA: Self-contained Breathing Apparatus

SITHP: Shut In Tubing Head Pressure

SICHP: Shut In Casing Head Pressure

TDG: Transportation of Dangerous Goods

UEL: Upper Explosive Limit

WHMIS: Workplace Hazardous Materials Information System

4.0.12 ABBREVIATIONS AND DEFINITIONS

Adequate: For the purposes of this IRP adequate is defined as the result of conducting a hazard assessment and mitigating risks associated with the job to be performed.

Adequate Lighting: The visibility must be such that the worker will be able to exit the worksite to a secure area in the event of an emergency. Flashlights, rig lights, and vehicle lights can be considered as emergency back-up lighting. (See Lease Lighting Guideline.)

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References/Links

Workers Compensation Board of British Columbia

Saskatchewan Dept of Labour, Occupational Health and Safety

NOTE: Regulations in the provinces of British Columbia and Saskatchewan define lighting with specific measurement criteria. This should be referred to when operating in these provinces

NOTE: Consideration must be given to additional lighting on complex operations.

Bleed Off: Where pressure is present in the well, or piping systems, and separating systems and needs depressurizing is required before work can commence.

Caution: Caution must be exercised on wells known to contain lower levels of H2S or have harmful or toxic substances, have severe abrasives (e.g., frac sand), have other unusual hazards, and are high pressure. The term caution does not categorize a well outside of Sweet or Sour.

It is intended to alert owners, employers, and workers to dangers that may exceed those of routine sweet wells and wells with minimal H2S concentration where prescriptive equipment requirements are not provided.

Certified Pressurized Vessel: A pressurized vessel which has been constructed following a program of quality control, designed for the application, and is registered with the provincial agency that applies a stamp of certification on the vessel nameplate. All vessels must have a Canadian Registration Number (CRN) registered in all provinces of intended use.

Closed System: A closed system refers to a handling system in which the odours or emissions from the wellbore effluent are either flared or vented to atmosphere through an H2S scrubber, in a controlled manner.

Coiled Tubing Unit Operations: Coiled tubing units (CTU) are commonly used in other flowbacks to recover wellbore effluent. Nitrogen, carbon dioxide or air is used to move and lift proppant, produced sand or stimulation fluids such as acid, chemicals or hydraulic fracture treatment fluids from the wellbore. Coiled tubing unit operations may also be undertaken to evaluate well production capability.

Confined Space: A space which is enclosed or partially enclosed. Has limited or restricted means for entry/exit. Is not designed or intended for continuous human occupancy. Is or may become partially hazardous to a worker entering or that may complicate the provision of first aid, evacuation, rescue or other emergency response services. Refer to applicable OHS Regulations

Drilling Company: An individual or company that enters into a contract with an owner of a wellsite to drill for oil and gas.

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Drill Stem Test: A method of determining the producing potential of a formation. This is done by removing the hydrostatic pressure of the drilling fluid column and allowing formation fluids or gas to flow into an evacuated or partially evacuated drill string or production string. This allows the formation pressures to be monitored and measured to calculate flow and depletion rates. A drill stem tester represents the company responsible for the downhole and surface equipment used in identifying the content and production capability of the formations to be tested.

Employer: Means a person, firm, association or body that has, in connection with the operation of a place of employment, one or more workers in the service of the person, firm, association or body.

Emergency Shutdown Devise Valve: It is a hydraulically or pneumatically operated, high-pressure valve installed on the wellhead with remote or automatic shutdowns. Its purpose is to provide a means to remotely shut in the well in an emergency. An ESD is required on wells to be flowed having a surface pressure greater than 1379 kPa and a H2S content greater than 1% or release of one tonne of sulfphur per day.

Flowback: Where pressure on a well is bled off and the well continues to flow, and is allowed to flow to establish a rate of gas and fluid from the well.

High Vapour Pressure Hydrocarbons: Hydrocarbon mixtures with a Reid vapour pressure greater than 14 kPa or an API gravity greater than 50O are considered to be high vapour pressure hydrocarbons.

NOTE: Reid Vapour Pressure is determined in a laboratory test. API gravity can be readily measured in the field. C1-C7 content can also be indicative of a fluid’s flammability. Flammability increases with increasing C1-C7 content. Fluid analyses, if available should be reviewed. Fluid and ambient temperatures should be considered.

Inline Test: An inline test is closed when well effluents measured at the test separator are diverted to the pipeline in some occasions fluids are produced to storage.

Mud Can: A device used to contain fluids and direct them away from the drill pipe when breaking connections.

Non - Certified Pressurized Vessel: A vessel that does not require certification for use in pressure applications. The vessel must have some form of pressure relief valve (PSV). If the tank is to be used as the primary vessel, the tank must have been constructed under a quality control program. Construction, design, and material specification data must be available when requested by the well owner. Government departments may also request this data.

Caution: The vessel must be designed for its intended use.


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Example: A vessel designed to operate below 103.4 kPa (15 psi) working pressure does not require provincial certification from local jurisdictions but is required to be constructed under a registered quality control program in this IRP.

Occupational Exposure Limits – Worker Safety Consideration

The Occupational Exposure Limit (OEL of H2S is, eight hour OEL: 10 ppm)

In most cases when well testing, workers are in open-air environments and work shifts longer than eight hours. Therefore planning consideration must review situations when workers are exposed to short-term levels of H2S greater than 10ppm and longer-term levels less than 10ppm. The ceiling limits vary through the various regulatory authorities. The two most common ceiling limits are 10 ppm and 15ppm.

Refer to your local and federal Occupational Exposure Limits for Chemical Substances for more information on exposure limits to other chemicals.

References/Links

Alberta Occupational Health and Safety Act – Chemical Hazards

Saskatchewan Occupational Health and Safety Act

Workers Compensation Board of British Columbia – OHS & Regulation

Open System: An open system refers to a handling system, such as a rig tank, in which any gas vapours produced from fluids are vented to atmosphere in an uncontrolled manner. This type of system requires constant monitoring to ensure transient vapours/gas are maintained below 20% of LEL and 10 ppm H2S.

Other Flowbacks: Other flowbacks refers to operations, other than production testing and drill stem testing, in which gas or fluids are flowed or induced to flow from the wellbore. This includes well killing operations and the recovery of well stimulation fluids and solids by flowing, pumping, swabbing or by the circulation of fluids (i.e., coiled tubing.) Refer to Section 4.3 Other Flowbacks for information specific to testing.

Owner: A person, partnership, company or group of persons who, under contract and agreement of ownership, direct the activities of one or more employers involved at a worksite.

Personal Protective Equipment (PPE): Equipment designed and used to protect workers.

Positive Pressure: Positive pressure refers to a pressure greater than atmospheric pressure (0 kPa gauge).

Pressurized Truck Tank: A pressurized truck tank must comply with all the CSA B620 requirements as determined by CSA B621. If the maximum allowable

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working pressure (MAWP) is greater than 101.3 kPa (15 psi) then ABSA/ASME certification is also required. The MAWP is specified on the nameplate of most oilfield production equipment such as all transport and pressure vessel equipment.

Purge: Where a vessel, container or piping system is evacuated of its gas and/or fluid contents and replaced with another gas and/or fluid. The general purpose of purging is to remove explosive and/or flammable fluids and gases from a closed piping system prior to opening the system to atmosphere or prior to entry of the system by workers. The practice of purging usually entails replacing the explosive/flammable contents with a product that is non-explosive/flammable or to create an atmosphere with an acceptable Lower Explosive Limit (LEL) and Upper Explosive Limit (UEL) for workers. Purging is also used to aid the removal hazardous gases and fluids from vessels and piping systems prior to shipment of equipment or transportation of fluids.

Qualified Well Testing Person: An individual who has had a minimum of three months previous experience with a service company or well owner and understands the concept of gas and liquid separation using pressure equipment and flaring. Without this prior experience, the individual is considered “in training”. The individual must be able to provide documented evidence, when requested, of this experience. The individual must have all certifications required by provincial regulatory agencies and/or listed in this IRP. Section 4.2.9 of this IRP identifies the qualifications required for a well testing worker to handle various levels of responsibility.

Supplied Air Breathing Apparatus (SABA): It consists of a small air cylinder (less than 5 minutes of breathing air) and air mask intended to be carried on the hip of a worker with the ability to connect, by hose, to numerous larger air cylinders. This type of configuration is used for extended work periods where a worker is exposed to an H2S or other hazardous breathing environment.

Self-Contained Breathing Apparatus (SCBA): It consists of an air cylinder and mask intended to be carried on the back of the worker and has (+)(-) 30 minutes of breathing air contained in the cylinder. This device is used for short work periods where a worker is in an H2S or other hazardous breathing environment. Also used for emergency situations to aid in the rescue of injured personnel.

Safety Service Company: A company that provides one or more of the following: equipment, workers, training, and neutralising chemicals to reduce the risk to onsite workers and equipment during various well operations.

Safety Standby Method: Where a person outside of the hazardous area monitors the work of persons inside the hazardous area, with no other purpose than to monitor personnel and their safety equipment, and implement rescue procedures when necessary.


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Service Company: Means a person, corporation or association who is contracted to supply, sell, offer or expose for sale, lease, distribute or install a product or service to another company, usually the owner of the worksite.

Shut In Tubing Head Pressure (SITHP): The pressure at surface on the tubing in the well.

Shut In Casing Head Pressure (SICHP): The pressure at surface on the casing in the well.

Stimulations: Stimulations are operations designed to improve well production capability or, in the case of injection or disposal wells, to improve the ability of a well to accept fluid. These operations may include the use of hydrocarbon and water based fracturing fluids, acids, various chemicals, and proppants.

Swabbing: Swabbing is an operation conducted to reduce the hydrostatic pressure of the fluid in the wellbore to initiate flow from a formation.

Swivel Joint (Chiksan): A series of short steel pipe sections that are joined by swivel couplings. The unit functions as a flexible flow line that provides a flow path between the control head and the floor manifold.

Test Line: A flow line from the drill stem tester's floor manifold to move fluid or gas to flare, test separator or storage.

Stabbing Valve: A full opening safety valve that can be installed to the top of any joint of pipe being pulled out of or inserted into the well to prevent flow up the pipe and out to atmosphere.

Well Killing Operations: Well killing operations are operations in which well effluent is circulated from the wellbore using a fluid of sufficient density to prevent further influx of reservoir fluids. The process is continued until the well is incapable of flow.

Well Testing: Well Testing is an operation where a company supplies equipment and the continuous presence of qualified test workers for the purpose of measuring and handling wellbore effluents through production equipment. Such operations include, but are not limited to:

• Flowing a well to production equipment or tank

• Flow measurement with chokes, flow provers or other devices

• Initiating flow by swabbing, coiled tubing or any such artificial lift method

• Flowing a well while drilling operations are in progress, known as Underbalanced Drilling

References/Links

Section IRP 4.2 Well Testing


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IRP 6.0 Critical Sour Underbalanced Drilling

Worker: Means a person who is engaged in an occupation in the service of an employer.

Underbalanced Drilling: Entails allowing a well to flow oil, gas, and formation fluids to surface as it is being drilled as opposed to conventional or overbalanced drilling where one of the prime considerations is in preventing hydrocarbons from flowing during the drilling process.

References/Links

IRP 6.0 Critical Sour Underbalanced Drilling

Alberta Energy and Utilities Board Interim Directive ID94-3 and Directive 36, Section 10, 20, 23, 24

4.0.13 COMMON TERMS OF REFERENCE AND IRP’S FOR ALL OPERATIONS IN THIS VOLUME

4.0.13.1 Responsibilities of Owners and Service Contractors

IRP The wellsite owner is responsible for all activities on a lease. The safety of on-site workers and environmental protection take precedence over well testing data requirements. Owners shall maintain general health and safety at the well site by coordinating all activities and ensuring proper equipment, materials, and workers are provided to accomplish the program and to satisfy all applicable regulatory requirements.

IRP The well site owner shall ensure the following breathing equipment is provided as a minimum:

On all wells, regardless of designation, two Self-Contained Breathing Apparatus (SCBA) must be on location at all times. (Additional SCBA may be required as per local authorities).

• When well testing wells where the H2S concentration is greater than 100 ppm, the owner must provide supplied air breathing apparatus (SABA’s) in addition to the self-contained breathing apparatus (SCBA). As a minimum this package must contain an adequate air supply system complete with air cylinders, manifold, work lines and egress packs (SABA’s) and a minimum of two back packs (SCBA’s).

• On simple well-servicing operations (such as rod jobs, tubing changes, bleed-offs, plug retrieval, abandonment’s, swab cleanouts) where the H2S concentration is greater than 10 ppm and where the venting of gas to atmosphere is minimal and the bleed-off period is short in duration and where more than two workers are present at the same time, an additional two back packs would be adequate instead of a supplied air

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system. (This does not apply to well testing.) Therefore a minimum of four back packs are required on the well site. Two of the back packs must be designated for emergency use only. The other packs are for use by workers where breathing equipment is necessary to complete operational tasks. Protection for the workers on the site and nearby residents, from over-exposure to H2S, must be maintained when considering this option.

IRP Refer to CSA standard CSA-Z94.4-02 Selection, care and use of respiratory equipment.

IRP Where an owner representative is assigned to the site, the representative shall be present during all operations where gas will be vented from open tank systems. Where an owner representative is not assigned to the site, the contractor assigned to flow the well to open tank systems must have a supervisor present during the operation.

IRP The owner shall ensure a gas detection meter is available to the site workers and that they are properly trained in the use and operation of the meter.

IRP The owner’s representative shall have a trained and competent person onsite in the operation of an LEL meter. The owner’s representative shall ensure availability of an LEL meter on all sites. (Reference IRP 7 Standards for Wellsite Supervision of Drilling, Completions and Workovers, Alberta ERCB BM 033, CAPP Flammable Environments Guidelines and IRP 18 Upstream Petroleum Fire and Explosion Hazard Management)

IRP The owner shall or instruct the service contracting company to:

• Provide signage ordering vehicles to stop at the lease entrance on all sites where gas is being vented to atmosphere

• Ensure there are an adequate number of qualified workers on the well site at all times to conduct operations safely

• Provide fluid hauling companies with shipping documents such as a waste manifest that describes the properties and potential hazards associated with fluids to be transported in appropriate Transportation of Dangerous Goods (TDG) terms

References/Links

Transport Canada TDG Act, Sections 5, 6, 8 & 14.

Transport Canada TDG Regulations, Part 3.

Transport Canada TDG Act, Section 40(Clear language).

• Ensure fluid hauling workers are oriented to site-specific procedures




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• Ensure sour fluids are transported during normal hours of operations unless special arrangements and precautions have been made between the owner and the truck operator. This may include standby workers, equipment, and monitoring devices

• Ensure appropriate safety equipment (i.e., H2S monitor, explosive mixture monitor, and respiratory protective equipment) is available

• Maintain a contingency plan including procedures for truck loading, unloading, and transportation-related spills.

IRP The owner’s representative is responsible for conducting an on-site pre-job equipment inspection to ensure the equipment is operational and as ordered.

IRP Owners shall prepare a program of operations. The program should include but not be limited to:

• The purpose of the operation

• Relevant well data

• Identify any potential hazards

• Equipment requirements and layout having regard for pressures and flows expected

• Environmental and safety considerations, relative to on-site workers and the public

• Special procedures to be employed

• Emergency contacts

• Minimum worker requirements and qualifications

• Test objectives

• Test sequence in appropriate detail

• Technical contact in case of unexpected program deviations

• Emergency response plan, contacts and procedures

• Shall ensure the program is available for viewing by all participating contractors prior to job commencement.

IRP The prime contractor shall ensure that their representative is able to provide competent and effective supervision of the operations being carried out. The owner’s representative shall have the following:

• For well site supervision of drilling completions and workovers, the prime contractors representative must be certified in IRP 7



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Standards for Wellsite Supervision of Drilling, Completions and Workovers

• First Aid Certificate

• If well servicing, an appropriate blow-out prevention (BOP) certificate

• If drilling, an appropriate blow-out prevention (BOP) certificate

• H2S Training and Certification for sour wells ( > 10 ppm)

• Transportation of Dangerous Goods Certificate where hazardous materials will be shipped

• WHMIS training

• Complete awareness of IRP 4Well Testing and Fluids Handling as they pertain to the operation being carried out and a full understanding of the hazards related to the physical properties of the fluid being handled, prior to conducting the operation

• Shall make available and be competent in the operation of equipment used to detect hazardous or explosive mixtures

• An understanding of section 8.110 of the ERCB Regulations when hydrocarbon mixtures with a Reid vapour pressure greater than 14 kPa or with an API gravity exceeding 50 degrees, are encountered

4.0.13.2 Drilling Service Company Responsibilities

IRP The drilling service company shall ensure that all required rig workers are available during operation and that the workers are physically capable and have been properly trained to carry out their designated responsibilities. The drilling service company shall ensure that the equipment and facilities it is contracted to supply are available during operation and it is designed for the parameters of the project. Pressure test certification, material inspections, and sour service specifications shall be made available when requested.

4.0.13.3 Drill Stem Testing Company Responsibilities

IRP The drill stem testing company shall ensure that the workers it provides are available during the drill stem test, the workers are physically capable, and have been properly trained to carry out their designated responsibilities during the drill stem test at the worksite. The drill stem testing company shall ensure that the equipment and facilities it is contracted to supply are available during the drill stem test, are in good working order and is designed for the parameters of the project.


xx June 2012

Pressure test certification, material inspections, and sour service specifications shall be made available when requested.

4.0.13.4 Safety Service Company Responsibilities

IRP The safety service company shall ensure that the workers it provides are available during operations, the workers are physically capable, and have been properly trained to carry out their designated responsibilities. The safety service company shall ensure that the equipment it is contracted to supply is available during the operation, is in good working order, and is designed for the parameters of the project. The safety service company must ensure proper equipment for respiratory protection, H2S gas detection, breathing-air supply, determining explosive limits, and neutralising chemicals is in sufficient quantities at the worksite. Consideration should be given to having spare H2S and LEL meter.

The safety service company must provide training of all workers on the worksite in the specific use of this equipment as required.

4.0.13.5 Well Testing Company Responsibilities

IRP The well testing company shall ensure their employees are physically capable to carry out their designated responsibilities during the operation. Well testing personnel must carry certificates of training with them. The well testing company shall ensure the equipment and facilities it is contracted to supply are designed and suited for the application. Pressure test certification, material inspections, and sour service specifications shall be made available when requested.

4.0.13.6 Fluid Hauling Company Responsibilities

IRP Fluid hauling companies shall ensure the workers it provides are available during the operations, the workers are physically capable to carry out their designated responsibilities, and the workers carry certificates of training with them. The fluid hauling company shall ensure that the equipment and facilities it is contracted to supply are available during the operation, are in good working order, and are designed for the parameters of the project. Pressure test certification, material inspections, and sour service specifications shall be made available when requested.

4.0.13.7 Well Designation for Worker Safety in H2S Environments

IRP Sweet and Sour designations are used by industry and legislative bodies as a reference for administrative purposes. For technical purposes specific concentrations of hydrogen sulphide will dictate appropriate


June 2012 xxi

equipment requirements to conduct a task safely, maintaining the health and safety of the worker while ensuring the integrity of the equipment. The well designations of this IRP are centred on hydrogen sulphide (H2S) content, which through inhalation, is the most frequently encountered hazardous substance by well testing workers. There may be other substances as onerous for maintaining worker safety and must be considered when planning work programs. Provincial Occupational Health and Safety Acts define the exposure limits for numerous substances. Those documents should be referred to when substances other than hydrogen sulphide (H2S) are known to be present at the well site. The well designations in this IRP are designed for worker safety when working in hydrogen sulphide (H2S) environments.Sweet Well

• 10 ppm hydrogen sulphide content or less: Designated as sweet.

• A well with a hydrogen sulphide (H2S) content of 0.01 moles / kilomole (10 ppm) or less is designated as sweet.

• The hazards of sweet gas to the worker, from exposure or inhalation, are less than those imposed by sour gas and therefore require a minimum of two SCBA’s on all wells to aid in protecting the worker.

• Other requirements are detailed throughout these IRP’s. Material specifications relative to metallurgy for equipment used to flow wells containing zero H2S content are not as stringent as those required for wells containing H2S.

References/Links

Section 4.2 Well Testing

NACE (National Association of Corrosion Engineers)

ASME B31.3

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4.0.13.7.1. Sour Well

• More than 10 ppm hydrogen sulphide content: Designated as sour.

• Any well with a hydrogen sulphide (H2S) concentration greater than 0.01 moles/ kilomole (10ppm) is designated as sour.

• Sour gas hazards relative to worker safety requires specific equipment to protect the worker.

• Prescriptive guidelines for the quantity and use of breathing equipment to protect the worker are outlined in this IRP and other provincial regulations.

• Additionally, gas, containing H2S, is more corrosive to metals and thus, requires precautions when selecting equipment to perform well testing operations.

• Section 4.2.3 H2S Service Equipment Requirements of this IRP provides guidelines relating to equipment selection for use in H2S environments.

References/Links

Section 4.2 Well Testing

Provincial Occupation Health and Safety Acts

Alberta Chemical Hazards Regulation Sections 2 & 9

NACE MR 01-75 LATEST EDITION

ASME B31.3

4.0.13.7.2. Critical Sour Well

• Critical Sour Wells are defined by appropriate Provincial Regulatory Agencies.

• They generally include all the elements of a sour well plus an amplified concern for residents in close proximity to the well site along with environmental issues.

• In Alberta Directive 071: Emergency Preparedness and Response Requirements for the Petroleum Industry


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June 2012 xxiii

4.0.13.8 Metallurgy considerations for H2S environments

• H2S affects the integrity of metals not designed for use in H2S environments.

• Other elements such as CO2 also have corrosive affects on metals. The requirement for special metallurgy in equipment is not related to a sour designation of a well.

• It is related to H2S Partial Pressure and Sulphide Stress Cracking as defined by the National Association of Corrosion Engineers (NACE).

References/Links

Section 4.2.3 H2S Service Equipment Requirements

NACE MR 01-75 LATEST EDITION specifications

4.0.13.9 Gas Detection Monitoring for Explosive and Flammable Limits

(Further information see IRP 18 Upstream Petroleum Fire and

Explosion Hazard Management)

IRP The owner’s site representative must be trained and competent in the use of gas detection meters. The site representative must possess or make available at the wellsite, a gas detection meter capable of measuring LEL.

IRP Where the owner does not have a site representative, the owner shall ensure a gas detection meter is available to the site workers.

IRP One person per shift must be trained and competent in the use of gas detection meters where gas vapours will be vented to atmosphere or there is a potential of gas vapours to be released to the atmosphere. All users must be properly trained and competent.

IRP No worker shall enter the 50 metre safety zone around an open tank system where gas vapours have been vented to atmosphere until cleared to do so by the owner’s site representative or the worker who is responsible for monitoring the area with a gas detection meter.

NOTE: Refer to Section 4.3 Other Flowbacks, for more detail on the requirement of gas detection and flowing wells to open tank systems.

Introduction: Gas detectors have become an everyday part of equipment requirements on an oil and gas site. There must be accurate methods of detecting the absence or presence of various gases, so the workplace can be maintained safe and productive.

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xxiv June 2012

Explosive or Flammability Limits:

The term limits of flammability or explosive limits, refers to the percentage by volume of a fuel in a fuel/air mixture which will burn. The flammable range spreads between the lower flammable limit and the upper flammable limit. Fuel /air mixtures outside the flammable range will not burn or explode.

Flammable limits for some common flammable gases and vapours are in listed below.

Table 1: Flammable Limits

Explosive Limits (% by vol. In air) LEL

UEL

Flash Point Degrees Celsius

Vapour Density Air = 1.0

Ignition Temp. Degrees Celsius

Ammonia 15.0 28.0 Gas 0.58 630

Butane 1.8 9.0 Gas 2.0 410

Carbon Monoxide 12.5 74.0 Gas 0.97 570

Diesel 0.3 10.0 52 > 3.0 < 171

Ethane 3.0 12.5 Gas 1.0 472

Hydrogen Sulphide 4.0 45.0 Gas 1.19 260

Ethyl Alcohol 3.3 19.0 +13 1.59 365

Methanol 6 7.6 16c 1.1 464

Methane 5.0 15.0 Gas 0.55 538

Propane 2.2 10.0 Gas 1.5 450

Toluene 1.3 7.0 +4 3.14 535

Common Frac Oils 1.0 7.0 (less than 1.0)

200

Gasoline 1.3 8.0 3.2

NOTE: To caution about methanol vapours affecting sensors. Please refer to your MSDS for all chemicals

A flammable gas is considered to be a gas that will burn when there is a concentration of oxygen in the air. Flammable mixtures cannot be ignited and continue to maintain a flame, unless the concentration of fuel is greater than the LEL and lower than the UEL.

A methane/air mixture must contain more than 5% methane by volume for the mixture to burn. If the mixture contains more than 15% methane by volume, it is considered to be too rich and will not burn. The concentration must be within the flammable range to ignite or sustain a fire.


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Oxygen

The normal concentration of oxygen in ambient air is 20.9%. Abnormal circumstances can cause this level to be increased or decreased. Oxygen deficiency refers to abnormally low oxygen levels that can be serious and is often an undetected risk to human life. Reduction of oxygen levels is usually caused by the consumption of oxygen by some chemical reaction or combustion within a confined area or by displacement by other gases.

Oxygen enrichment refers to abnormally high concentrations of oxygen that can be dangerous because of its tendency to increase the flammability and explosiveness of materials and fuels. The leaking of compressed oxygen containers in confined areas usually causes enrichment.

For safe entry, oxygen levels must be between 19.5% and 23.0%.

Flammable and Explosive Gases

Explosions occur when a flammable mixture of gas comes into contact with a heat source that exceeds the ignition temperature of the gas mixture. Not all concentrations of flammable gases will explode. The Lower Explosive Limit (LEL) determines the minimum concentration of the flammable gas in air that will burn. Concentrations below the LEL and above the Upper Explosive Limit (UEL) will not burn. Unfortunately, gas/air mixtures are seldom uniform so it is likely that if any amount of combustible gas is detected then at some point in the system or container, the concentration may be explosive. Flammable liquids normally have a low flash point. This refers to the temperature at which the liquid releases vapours at a rate sufficient to form an explosive mixture with air. Liquids with flash points below ambient temperature will immediately release dangerous concentrations of gas. Liquid leaks can be as hazardous as gas leaks.

Vapour Density

When monitoring for the presence of gases or vapours, it is important to understand vapour density, which provides valuable clues as to where to locate gas sensors. Density is a characteristic of materials and is similar to weight. For gases and vapours, air is considered to be the standard reference and its density is set at 1.0. Gases and vapours lighter than air have densities less than 1.0 while those heavier than air have densities greater than 1.0.

Assuming that air currents are negligible, it can be said that gases and vapours with densities less than 1.0, such as methane, will tend to rise from the point of escape and subsequently disperse into the atmosphere or accumulate in spaces under roof structures of buildings.

Heavier-than-air gases such as propane and H2S tend to fall from the point of escape, perhaps to floor level where some mixing with air occurs thus creating pockets of mixtures, some explosive, others not. If there are sub-floor spaces


xxvi June 2012

such as drain channels, pipe and cableways, and storage pits, then these heavier than air gases tend to accumulate there. A suitable source of ignition in such areas will surely result in explosion and fire. Refer to Flammable limits for some common flammable gases and vapours table above.

Ignition Temperature

Ignition temperature is the temperature that will cause a combustible mixture of gas vapour to explode or burst into flame. Various fuels mixed in a variety of concentrations can be explosive when ignited by the presence of a spark, flame or hot surface that exceeds the ignition temperature. Variables such as concentrations, pressure, and temperature all have an effect on ignition temperature.

Pyrophoric Iron Sulphides

Pyrophoric Iron Sulphides are created when rust and H2S combine in an oxygen free environment

Pyrophoric meaning they can spontaneously ignite when exposed to oxygen.

They are created in oxygen free environments such as piping systems, reservoirs, wellbore, and vessels where H2S has been present without oxygen.

Essentially rust (or Iron Oxide) is converted in Iron Sulphide, when these Iron Sulphides are exposed to oxygen; an oxidation process begins that eventually turns the iron sulphides back into iron oxide form.

This process creates an enormous amount of heat causing (in some cases) the iron particles to illuminate and possibly glow. This is when nearby fuel sources such as propane from a purge or other hydrocarbons can be ignited.

There is no set H2S content at which Pyrophoric Iron Sulphides will form or be present, however there are some heavily researched indicators to the presence of Iron Sulphides. They include

• Scaling

• Asphaltines

• Sludge

• Rust

• Solids

The age of a sour well, and long periods of time with equipment on sour operations such as multizone sour completions can also be factors in determining whether or not Iron Sulphides may be present

With an auto ignition temperature below that of room temperature, they pose a definite hazard.


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IRP A hazard assessment should be completed on iron sulphides for sour locations. The operating company’s site representative must be present. The above mentioned indicators should be addressed if applicable. Previous well analysis information if applicable, or operating company technical/physical judgment of possible Iron Sulphides should be addressed.These hazard assessments may be able to identify a operating company or your company’s Pyrophoric Iron Sulphide procedures and safety guidelines. Local or federal legislation may also be valid.

Location of Gas Sensors

Location of the gas sensor is very important. In general, lighter than air gases requires the sensor to be positioned near the ceiling and heavier than air gases require sensors positioned at low levels or in pits or trenches. Some things to consider include:

• Hydrogen sulphide mixed with methane in a process stream may follow the same migration patterns as methane during a gas leak

• Temperature, humidity, and air ventilation patterns

• Mounting detectors close to the entrance of buildings, on the outside wall.

Gas Detectors Measuring Percent LEL

Some gas detectors have two scales; the 100% scale measuring the % of a flammable gas in a mixture, and the 4% scale for measuring the % of the LEL Assume that the meter has been designed to measure hydrogen in a mixture. The LEL of hydrogen is 4%. If a reading taken on the 100% scale indicates 10%, then the mixture is 10% hydrogen and is above the LEL of hydrogen. If a reading on the 4% range indicates 10%, then the mixture contains 10% of the hydrogen necessary to produce a flammable mixture. The mixture actually contains 4% x 0.1 = 0.4% hydrogen by volume.

The equipment operator must understand the difference between measuring the % LEL and the % of flammable gas.

Always consult the manufacturers operating instructions and procedures prior to interpreting the results.

Caution:

• No person shall remain in or enter into an area containing more than 20% LEL, unless it is for an emergency or rescue situation by trained and competent individual(s)

• When testing gas for LEL remember that the H2S concentration is important relative to the safety of the worker conducting the LEL test.


xxviii June 2012

• The LEL of hydrogen sulphide is 4% gas by volume, which equates to 40,000 parts per million H2S.

• Anytime the H2S exceeds 10 ppm special safety precautions must be implemented.

• At 40,000 ppm H2S, a worker would be immediately overcome while testing for LEL.

• These devices must not be used for continuous monitoring or for testing H2S concentration in the gas

Preparing the Meter

• Be sure to follow the directions supplied by the manufacturer of your gas detector.

• Testing the atmospheres for the safety of workers requires that the gas detection equipment be in perfect condition, properly calibrated, and will be operated by trained and competent people.

• Some portable equipment is designed to test for a combination of any of the following: oxygen, hydrogen sulphide, carbon dioxide, and flammable levels.

NOTE: Refer to CAPP Flammable Environments Guideline and IRP 18 - Fire and Explosion Hazard Management

4.0.13.10 Monitoring for Explosive Mixtures

IRP Monitoring for explosive mixtures with a suitable calibrated monitoring device in the vicinity of potential ignition sources (e.g., pump) during pumping/flowback operations is recommended. The monitoring device must be calibrated using an appropriate calibration gas. The operations must be suspended or an alternate method of flowback initiated to eliminate an explosion risk around potential ignition sources.

IRP Wind direction devices must be strategically located around the lease.

NOTE: Monitoring for explosive mixtures with a suitable device is the only practical method of determining safe operating conditions. Judging conditions based on sight, smell, wind directions, etc., may be very deceiving in that explosive mixture levels can change rapidly during a flow back situation. Portable monitoring devices are available that give direct readout of combustible gas explosive limits. A fixed sensor could be located in an enclosed area such as rig pump house, separator building etc.

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June 2012 xxix

4.0.13.11 Calibration of Explosive Mixture Monitors

IRP Explosive mixture monitors must be calibrated regularly by a qualified individual (see IRP 18). Monitoring devices must be calibrated using an appropriate calibration gas. Defective devices must be replaced or serviced prior to commencing a flow back operation where monitoring for explosive mixture will be required. The owner’s representative must be aware of the limitations of the monitor for the gases and fluids expected.

NOTE: As with any safety device, the degree of dependability of a gas detector is directly proportional to the care it receives. All explosive mixture monitors require routine maintenance on a regular basis, which includes cleaning the device and its sampling system, checking voltage supply to the unit and performing regular calibrations. Some of this servicing may require the services of a qualified technician.

4.0.13.12 Hydrates: Awareness and Handling

Gas hydrates are crystalline compounds formed, by the chemical combination of natural gas and water, under pressure at temperatures considerably above the freezing point of water. In the presence of free water, hydrates will form when the temperature of the gas is below a certain temperature, called the hydrate temperature. Hydrate formation is often confused with condensation and the difference between the two must be clearly understood. Condensation of water from natural gas under pressure occurs when the temperature is at or below the dew point at that pressure. Hence, the hydrate temperature would be below and perhaps the same as, but never above the dew point temperature. (Dew point is the state of a system characterized by the coexistence of a vapour phase with an infinitesimal quantity of liquid phase in equilibrium. Dew point pressure is the fluid pressure in a system at its dew point.)

While conducting tests, it becomes necessary to define, and thereby avoid, conditions that promote the formation of hydrates. This is essential to the proper field conduct of tests since hydrates may choke the flow string, surface lines, and the well testing equipment. Hydrate formation in the flow string would result in a lower value for measured wellhead pressures. In a flowrate-measuring device, hydrate formation could result in a lower or higher gas flow rate. Excessive hydrate formation may also completely block flowlines and surface equipment.



xxx June 2012

In summary, conditions promoting hydrate formation are:

Primary conditions:

• Gas must be at or below its water dew point with free water present

• Low temperature

• High pressure

Secondary conditions:

• High velocities

• Pressure pulsations

• Any type of agitation

• Presence of H2S and C02

• Introduction of a small hydrate crystal

• High specific gas gravity

For the purpose of well testing it is convenient to divide hydrate formation into two categories:

1) Hydrate formation due to decrease in temperature, with no sudden drop in pressure, such as in flow string or surface lines.

2) Hydrate formation where a sudden expansion occurs and/or pressure drops such as in flow provers, orifices, backpressure regulators, and chokes.

If ambient temperature is low enough, ice build up may occur on the inside of pipe when left idle, after flowing, due to condensation residue left on the inside walls of piping systems. This is not a hydrate although it could lead to the formation of a hydrate by the introduction of a hydrate crystal to the flow stream.

IRP For the awareness and prevention of hydrates:

• Programs supplied by the well owner should identify potential hydrate problems by way of bottomhole temperatures, presence of free water, H2S and CO2 content, gas gravity, and downhole restrictions

• Pre job safety meetings should reference the possibility of hydrates

• Incorporate the primary and secondary conditions listed above

• Provision for the injection of methanol should be planned prior to flowing of the well

• Consideration should be given to batching or injecting methanol down the tubing and/or the annulus, if applicable, prior to flowing


June 2012 xxxi

• Methanol should be batched or injected into the wellhead flowline before opening the well to flow and during any future shutdown periods so as to prevent ice build up on the inside walls of piping systems

• Flowlines should be purged with a gas medium (propane/N2), where available and when extended shut down periods are anticipated, especially during cold weather operations

• The introduction of surface heating facilities, such as line heaters, will assist in the prevention of hydrates in surface equipment

• Staging pressure drops will assist in the prevention of hydrates in surface equipment.

• Hydrate charts/tables must be available on the well site. The well test supervisor must be trained and competent on the use of these charts and tables.

IRP Where hydrate formation or ice build up is suspected in surface flow lines, the lines must be proven to be clear by purging with methanol or a warm gas or fluid before the lines are broken apart.

IRP During the pressure testing procedure and start up, all non-essential workers must vacate the surrounding area of the testing equipment, flow lines, and wellhead.

See Appendix VII for hydrate graphs

Caution: Hydrates travelling through pipes have a high potential for plugging, overpressuring, or rupturing lines.

NOTE: Sour gas more readily forms a hydrate than sweet gas

4.0.13.13 Worker Safety

IRP Before commencing any operation a pre-job safety meeting must be held and hazard assessment performed and communicated. Suggested topics are:

• Scope of work

• Procedures to be followed

• Pertinent well and fluid characteristics

• Responsibilities of each person involved in the operation

• Emergency procedures, special hazards, and safe briefing areas

NOTE: Equipment must be routinely serviced and tested by qualified/competent workers as per the manufacturer's specifications or regulatory requirements. The owner’s representative is responsible to ensure an


xxxii June 2012

onsite pre-job safety equipment inspection is completed (see Appendix V Production Testing Services Inspection Checklist).

IRP All applicable federal and provincial regulations must be adhered to, such as TDG, WHMIS and Occupational Health and Safety, and WCB.

4.0.13.14 Minimum Worker Wear Requirements

IRP A written protective clothing policy must be available onsite. The following minimum work wear requirements must be followed:

• A hardhat must be worn in the work area

• Safety (steel toed) footwear must be worn in the work area

• Safety goggles, safety glasses or safety prescription glasses with side shields must be worn

• Where hazardous chemicals exists, consult MSDS

• Hearing protection where over exposure to noise may occur

• Gloves must be worn as required, (e.g., specialty gloves for chemicals, leather gloves for handling pipe, etc)

• Un-torn, fitted clothing must be worn in the work area

• Outer or covering apparel must be fire retardant where the potential for fires exists

• Natural fibres for innerwear is preferred over synthetic fibres as synthetic fibres do not provide adequate protection from heat related exposure and they contribute to static electricity generation

• All clothing that becomes contaminated with hazardous chemicals or flammable fluids must be removed and replaced

• Minimum safe standards for hard hats, footwear, eye wear, and ear protection should be determined by the well testing company. The following standards are appropriate:

• Hardhats: CSA Z94.1

• Footwear: CSA Z195 Grade 1

• Eyewear, Goggles: CSA Z94.3

• Hearing Protection: CSA Z94.2

4.0.13.15 Minimum General Safety Standards

IRP The following minimum standards must be followed:

• No smoking within 50 m of potentially flammable vapours


June 2012 xxxiii

• Facial hair must not impede the sealing of respiratory equipment

• Intoxicating substances and intoxicated persons are not allowed on location

• General fatigue management

• Firearms are not allowed on location except for emergency ignition of uncontrolled gases.

• An adequate supply of potable water must be on location (i.e., for drinking, and emergency washing)

• Good housekeeping practice is required for all of the location

• The requirements of Workplace Hazardous Material Information System and TDG must be followed

• A form of wind direction indicators must be present on location (e.g., windsocks, flagging tape, etc.)

• An operational field phone must be present on location

• A list of emergency contacts must be conspicuously posted on location

• A means of transport for injured persons must be on location in accordance with local jurisdictions

• An unobstructed exit path must be available

• The safety standby method must be employed for all hazardous work

• A properly calibrated gas detection apparatus must be on location. Personnel must be properly trained in the use of this apparatus

• H2S determinations must be performed while wearing breathing apparatus. A minimum of two positive pressure type apparatus must be at location and maintained in accordance with the manufacturer's specifications and regulatory requirements

• On sour well sites where the H2S concentration is greater than 10 ppm, the owner must provide SABA’s in addition to SCBA.

• When a significant volume of wellhead gas is produced, either to an orifice device, or through a separator, notification should be given as required by the local provincial authority.

• See Section 4.0.13.18 Gas Flares

• First Aid equipment and/or attendants must be supplied as specified by the provincial OH&S authority


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• Appropriate fire fighting equipment must be available as determined by the Hazard Assessment, Fire and Explosion Control Plan, and applicable regulations.

• Cold separator or pressure tank rig-up: Minimum 2 Class ABC, 9 kg

• Heated Unit and flare stack or line heater, pressure tank and flare stack: Minimum 3 Class ABC, 9 kg

• Heated unit or line heater/pressure tank combination with second stage separation or more than one item of auxiliary flow equipment: Minimum 4 Class ABC, 9 kg

• Wellsite illumination must be sufficient to safely perform the job (Refer Lease Lighting Guideline)

• Safety stairs (or equivalent devices that would allow a rescue at the top of a tank other than by ladder access) are required whenever breathing apparatus is required at the top of a tank

• Fall arrest equipment and a fall protection plan must be available as required by OH&S regulations

• An ESD valve must be installed on wells with more than 1379 kPa pressure and an H2S content greater than 1% or one tone of sulphur per day. Additional considerations for use of an ESD valve are wells that:

• have harmful or toxic substances

• have severe abrasives (i.e., frac sand)

• have high operating pressure

• have other unusual hazards.

NOTE: These points are by no means all of the general safety standards that should be followed. The points are listed as having special relevance to well testing. Provided that it does not contradict the well owners policy, well testing companies may use a fixed period to orientate and train newer employees while on the job, provided that such persons are adequately protected by other certified workers on location.

NOTE: These points are minimum standards and contractors should determine whether the well owner has additional standards.

4.0.13.16 Pre-Job Safety Meeting

IRP A pre-job safety meeting must be held involving all workers who will be on location during operations. The meeting should be recorded and the agenda should include the following:

• A list of personnel on location

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June 2012 xxxv

• Responsibilities and work programs

• Safety procedures, general, and specific to the job

• Safety equipment location and operation

• Emergency response plan

• Hazard Assessment

NOTE: Holding the safety meeting prior to purging could be appropriate depending on workers present and the time between purging and well opening. The contractors daily shift change is considered, in part, a safety meeting. The agenda should include a complete de-briefing of the previous shift and the noting of any new hazards. It is appropriate to hold interim safety meetings at any time when conditions or job scope have changed from initial expectations. The flare permit, if applicable, must be reviewed and conspicuously posted.

4.0.13.17 Opening a Closed Tank System after Flowing or after Purging

with a Flammable or Inert Medium

It is recognized that it is not always practical to have an inert purge medium for all operations. Flammable purge mediums, such as propane, are successfully used throughout the industry as long as workers follow special precautions and procedures. An inert medium also presents its own hazard; lack of oxygen and non-breathable. The following is meant to assist the worker in assessing the hazards:

IRP Closed tanks must be depressurized and not be on vacuum before opening the system. If available on site, purge the system with inert gas. Evacuate as much fluid (and solid) as possible before opening the system.

IRP A confined space entry permit must be completed prior to opening of a system that allows for the entry or partial entry of a person

IRP Prior to opening a closed tank system to check its contents, a hazard assessment must be conducted by the systems owner representative on shift. The assessment must be documented and signed by both the systems owner representative and, if present, the well owner representative.

IRP The individual who completes the confined space entry permit must have Confined Space Entry Training.

• Eliminate all potential ignition sources

• Remove all non-essential people from the immediate area


xxxvi June 2012

• Ensure individuals involved in opening the closed system have proper personal protective equipment such as fire retardant coveralls and breathing apparatus

• Where workers are preparing to enter a closed system, confined space legislation must be followed

References/Links

Confined space legislation in the jurisdiction you are working in.

Consideration should be given to the use of purge mediums such as N2, CO2, and water flood. The use of combination flush/vacuum pump trucks will help to clean out the system as much as possible prior to opening for inspection.

4.0.13.18 Gas Flares

Well Test Supervisors must confirm with the operator the presence of a flare permit or ensure that proper notification has been done, if required.

Gas flares must be designed with the following considerations:

• H2S / SO2 hazards. Owners are required to define flare stack diameters and height to prevent H2S emissions and reduce SO2 fallout, within regulatory requirements. Flare Permits are required for Critical Sour Wells, and when H2S content exceeds 50 mole / kilomole (5%). From 10 to 50 moles / kilomole (1 - 5%), a minimum flare stack height of 12 metres is required

• Nearby combustible material. Flare stacks should be designed to prevent combustion of vegetation

• Flare stacks must be adequately anchored.

• Maximum velocity of the gas from the flare stack on sweet gas and sour wells less than 1% H2S must not exceed 331.4 metres per second.

• Velocity of the gas from the flare stack on sour gas greater than 1% H2S should not exceed 95.4 metres per second or be less tan 10.6 metres per second.

• It is recognized that velocities on sour gas above 1% H2S may exceed 95.4 m for a short term.

• Flame arrestors within the flare line are not required under a manned operation while flowing and other forms of flashback control are acceptable. See ERCB Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting, Section 7.7

• See Appendix VI on pipe size versus velocity graphs




June 2012 xxxvii

NOTE: Optimal combustion and plume dispersion modelling as outlined in ERCB Directive 060 dictates velocities between 10.6 and 95.4 m/second

4.0.13.19 Venting Gas to Atmosphere

NOTE: Venting of gas vapours while flowing, circulating, or pumping to open tank systems is covered in Section 4.3 Other Flowbacks.

4.0.13.20 Flare Pits

IRP Flare pits may only be used in an emergency.

4.0.13.21 H2S Scrubbers

IRP Where H2S scrubbers are used, the scrubber must be sized such that the concentrations and volume of H2S vapour present are adequately handled. The frequency of chemical change-out is dependent on the H2S concentration and gas volume flowing through the scrubbing system. Periodic checks as per suppliers’ recommendation of the vent gas and chemical properties are required to ensure no H2S is released to atmosphere.

• Fluid pH and liquid level must be maintained at all times. It is recommended that ammonia be changed out if the pH drops below 10.5. It is also recommended that potassium hydroxide based fluids be changed out when the Ph drops below 9.5

• SulfatreatTM systems must have vent gas checked for the presence of H2S

• Use appropriate breathing apparatus when checking for Ph or H2S.

• A Hazard Assessment must be done for all flammable gases leaving the scrubber

• See Appendix I Atmospheric Fluid Scrubber Selection Guidelines




xxxviii June 2012

4.0.13.22 Produced Fluids

4.0.13.22.1. General Fluids

IRP Where fluid is produced, steps must be taken to ensure the safety of site workers from vapours allowed to escape to atmosphere from the fluid.

4.0.13.22.2. Fluid Properties and Characteristics

IRP The properties of any produced fluids or solids should be evaluated to:

• Identify any potential hazards

• Select appropriate fluid handling procedures, see MSDS on fluids

• Establish criteria for shutdown when using an open tank system

• Establish disposal methods

• Toxic effects

• Radioactive material

• Environmental impact of escaped fluids

• Corrosive effects

• Possible degradation of elastomers

• Naturally Occurring Radioactive Material (NORM)

4.0.13.22.3. Oils

IRP The properties of the produced oils should be evaluated for the following hazards:

• Flammability; ignition of oil, and oil vapours

• Solid deposition problems (e.g., paraffin)

NOTE: There is a general relationship between flammability and the C1-C7 content of a hydrocarbon fluid. Flammability increases with C1-C7. Also Reid vapour pressure increases with increasing C1-C7 content.


June 2012 xxxix

4.0.13.22.4. Gas

IRP The properties of the produced gases should be evaluated for the following hazards:

• Ignition of contained and escaped vapours

• Solid deposition problems (e.g., sulphur)

• Hydrate potential

• H2S content

4.0.13.22.5. Water

IRP The properties of the produced water should be evaluated for possible gas entrainment and ignition potential.

NOTE: If it is necessary to locate tanks next to the lease road exit, for example on small leases or remote locations, to comply with other spacing requirements, ensure adequate transportation for workers is available in the event of an emergency. This transportation should be off the lease when no other means of egress are available.

4.0.13.23 Tanks

4.0.13.23.1. Rig Tanks

IRP Where gas vapours are vented to atmosphere from an open tank system, the tank must be a minimum of 50 metres from the wellhead (shallow wells, coalbed methane (CBM) 35 metres from wellhead)

IRP Where a degasser is used to separate gases and liquids, it should be located in a separate compartment of the rig tank. The degasser should be configured such that a sufficient head of fluid in the tank is maintained for efficient gas separation

IRP Flowback operations must be discontinued if liquid carry over from the degasser vent line occurs, and an appropriately sized separator or pressurized tank must be employed

NOTE: IRP 1 Critical Sour Drilling; 1.7 Mud Gas Separators, provides an overview of degasser design factors including vent line sizing.

NOTE: See Section 4.3 Other Flowbacks for flowing to open top tanks.

4.0.13.23.2. Atmospheric Tanks (64m3 style)

IRP Atmospheric tanks are predominantly used for storage of fluids and are not considered capable of containing pressure. Most atmospheric tanks



xl June 2012

are designed with 7 kPa (16oz) hatches and the roof is typically designed to shear at 14 kPa (2 psi).

IRP When producing sour fluids, atmospheric tanks must be equipped with a suitable vapour gathering, flaring or scrubbing system to ensure that H2S vapours are not released to atmosphere. The system may also include a pressurized tank

IRP Fluid storage tanks require an external fluid level indicator that can be used for level measurement.

IRP The tops/lids of atmospheric storage tanks are not designed to serve as a work platform. Any maintenance/work required on top of these tanks must be conducted while the tank is in a horizontal position.

4.0.13.23.3. Certified Pressurized Flowback Tanks

IRP Pressurized tanks used for flowback or storage of fluids produced from a sour well must be manufactured under a quality program to ensure conformance with design specifications utilizing materials meeting the requirements of NACE MR 01-75 LATEST EDITION.

4.0.13.23.4. Non – certified Pressurized Storage Tanks

IRP If using a non-certified tank or vessel for primary separation and storage of fluids while swabbing, flowing to establish a rate, circulating, pumping or bleeding off rather than using a certified tank or vessel, the non-certified tank or vessel must be constructed under a quality control program. Construction, design, and material specification data must be available when requested by the well owner. Government departments may also request this data.

4.0.13.23.5. Other Tanks

IRP Owners must have regard for the volume of the various fluids to be utilized and where possible, provide sufficient tank storage to provide for a suitable retention time or provide for other measures such as heating or agitation to allow for separation of entrained gas, prior to transportation.

IRP Pressurized tanks or a closed system should be used for flowbacks, storing, producing, pumping, swabbing or killing wells with high vapour pressure hydrocarbons (see Abbreviations and Definitions).

IRP When flow testing from a sour well (>10 ppm) during servicing, drilling or testing operations, a closed system must be used to prevent the escape of sour gas to the atmosphere. Flowback duration, proximity to, and notification of area residents must be considered. H2S scrubbers


June 2012 xli

must be operated within the manufacturers operating parameters and chemical used in that scrubbing system monitored and changed accordingly.

NOTE: Hydrometers are readily available to determine the density of hydrocarbons to be pumped as well as fluids subsequently returned during the flowback. ERCB inspection policies regarding the handling of sour effluents are included in ERCB Directive 037 Service Rig Inspection Manual.

IRP 2 Completing and Servicing Critical Sour Wells; 2.5 Fluids and Circulating System, contains additional information regarding necessary fluid handling equipment for critical sour wells. Section 2.10 Quality Programs for Pressure Containing Equipment includes basic information regarding quality programs.

NACE MR 01-75 LATEST EDITION, Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment has a 350 kPa pressure limit below which the requirements do not apply.

4.0.13.24 Location of Tanks

4.0.13.24.1. Location of Rig Tanks

IRP The rig tank(s) must be 50 metres from the wellhead and any open flame and it is only S.E. Alberta shallow gas wells where the rig tank can be 35 meters from the well.

4.0.13.24.2. Location of Atmospheric Tanks (64m3 style)

IRP Where gas vapours are anticipated, or the tank is rigged with a venting/scrubbing system, atmospheric tank(s) must be 50 metres from the wellhead and any open flame.

4.0.13.24.3. Location of Certified Pressurized Flowback Tanks

IRP It is recommended to place certified pressurized flowback tanks 25 metres from the wellhead even though there is no regulated distance requirement. Where the tank is preceded by a flame arrested line heater, the line heater and tank must be a minimum of 25 metres from the wellhead.

4.0.13.24.4. Location of Non-certified Pressurized Storage Tanks

IRP Non-certified pressurized tanks must be 50 metres from the wellhead. The tank must be designed for its intended use. If the tank is to be used as the primary vessel, the tank must have been constructed under a quality control program. Construction, design, and material specification





xlii June 2012

data must be available when requested by the well owner. Government departments may also request this data.

4.0.13.25 Air Entrainment and Purging

4.0.13.25.1. General

IRP Owners and service contractors must understand and attempt to eliminate or mitigate explosive hazards due to air entrainment in pipes, vessels, and tanks, etc.

NOTE: Air entrainment explosions occur upstream of the flowline choke and downstream of the flowline choke (usually in storage tanks). The fuel source is the well product, or it can be the purge medium if propane or natural gas is used to purge. Ignition sources are not always identifiable, but possibilities include:

• Flashbacks from flares

• Static electricity

• Friction heat (from valve operation or high velocity debris)

• Localized hot spots in partially open (unbalanced) valves

• Spontaneous combustion at critical pressures and temperatures

• Spontaneous combustion of compounds such as sulphides

• Electrical currents from lightning and power sources (including cathodic protection).

Air sources upstream of the choke include:

• Air from dry run tubing (i.e., for under balanced perforating)

• Coiled tubing unit operations using air

• Swabbing, when the well goes on vacuum

• Reaction productions (i.e., hydrogen peroxide washes)

Air sources downstream of the choke include:

• Initial air, as the equipment arrived

• Air re-introduced from the wellhead side

• Air pulled into production tanks through open or leaking hatches when a vacuum condition exists. The vacuum can be caused by fluid withdrawal and by excessive venturi action at flare stacks when tanks are vented to flare.


June 2012 xliii

4.0.13.25.2. Purging the Well String and Wellhead

IRP Dry tubing should be displaced by N2 or CO2 or alternatively the procedures of Section 4.0.13.26 should be employed. When dry tubing with air is opened to the formation, a fluid cushion should be run in the string. If the well has enough energy, the cushion can be brought back to a tank. The returning cushion purges the tubing string. Wellhead pressure should not be allowed to build up prior to the cushion return.

NOTE: It is recognized that it is not always practical to displace tubing air prior to operations such as under balanced perforating or drill stem testing.

NOTE: Owners and well testing companies must assess the planned procedure when air exists in the well string.

4.0.13.25.3. Purge Mediums for Purging Surface Equipment

IRP Purging should be performed by a purge medium vapour displacing air. Non-flammable vapours are preferred. Propane or sweet gas is acceptable with extra precautions, recognizing that the purge medium will create explosive mixtures before air purging is complete.

4.0.13.25.4. Pre – Purging Procedures and Checks

IRP The following pre-purging procedures and checks are required:

• Production tanks should be clean

• Production tanks must have hatch seals and pre-set pressure thief hatches

• All system elements must be electrically bonded to each other, with the wellhead or ground rods as ground or common

• A wellhead may be used a grounding device

4.0.13.25.5. Purge Vapour Measurement

IRP The purge vapour should be measured.

NOTE: Liquid-volume-to-vapour or mass-to-vapour conversions are allowed if the liquid-volume or mass vaporized is measured accurately, and if it is ensured that all of the liquid is vaporized. Numerous measurement devices are available.

4.0.13.25.6. Purge Amounts

IRP The volume to be purged must be calculated prior to purging. For purge mediums heavier than air, purging should be a minimum of 1.5 times calculated volume, and purging should be from the bottom up. For


xliv June 2012

purge mediums lighter than air, purging should be a minimum of 2.5 times calculated volume, and purging should be from the top down.

NOTE: Top down purging is impractical in some situations. If bottom up purging is employed with purge mediums lighter than air, a minimum of five times calculated volume should be displaced. Small lines and vessels may be purged for a number of minutes instead of rigorous calculations if it is certain that the time chosen would exceed the overpurge guidelines.

4.0.13.25.7. Purging With Wellhead Gas (Sweet or Low

Concentration of H2S)

IRP The well should be flowed slowly to the separator unit, then to the flareline, then to downstream vessels/tanks. Downstream vessels/ tanks must be isolated and purged one at a time.

NOTE: Production tanks that will not be vented to flare do not require purging.

4.0.13.25.8. Purging Sequence

IRP Purging should be in a downstream sequence, flow line, and heater, if present, then separator, then flare line, then to downstream vessels/ tanks. Downstream vessels/tanks must be isolated and purged one at a time.

NOTE: The flow line would be purged from the wellhead to the separator unit, if the vapour was introduced at the wellhead. It is also acceptable to use the separator as a point of origin for the purge vapour. In that case, the flow line would be purged back to the wellhead (with the line disconnected at the wellhead).

4.0.13.25.9. Ending the Purge

IRP Where practical, oxygen meters are recommended for large vessel/tanks, regardless of the calculated over purge. The sensing should be performed at points other than the purge exit of the component (in case of air bypassing instead of displacement). Oxygen content must be such that the gas mixture is below its lower explosive limit.

4.0.13.25.10. Intermediate Purging

IRP Vessels/tanks should be re-purged whenever air is accidentally or operationally introduced during the test.


June 2012 xlv

4.0.13.26 Opening a Well with Air in the Flow string

IRP It is recognized that, sometimes, wells are required to be opened when there is air behind the wing valve. Owners and well testing companies should consider some or all of the following procedures:

• All non-essential workers should be removed from the test area

• Manifolding should exist so that all vessels/tanks can be bypassed

• It is not necessary to purge an open tank system where gas is vented to atmosphere

• It is important that the tubing be flow-purged of explosive mixtures as soon as possible after operations such as tubing conveyed perforating. The well should not be shut-in for buildup until the purge is completed because pressuring up the volatile mixture increases the danger of an in-line explosion

• On sour wells, the well can initially be flowed through a choke to a by-pass directly to a flare until the air is displaced from the tubing and the flare is burning steadily. This will contain possible fires in open-ended pipe. The well can then be shut-in or directed to pre-purged vessels prior to liquids arriving at surface. An operator could also obtain permission from the local authority for short term flow to an unlit flare to displace air from the tubing. The flow should be sampled with an LEL

or gas detector to verify the mixture is out of the explosive limits

• The wing or master valve should be balanced by downstream pressure (N2, CO2 or H2O) prior to opening, to reduce friction and initial inrush

• Where a well could go on vacuum during swabbing, a check valve must be inserted in the flowline system. A manual valve should also be in the system. The saver-sub should be tightened. A regulated purge vapour to follow the swab cups back down the hole should be considered

• All suspect lines/vessels/tanks must be repurged when the wellstring air is eliminated.

NOTE: Owners should notify nearby residents before commencing operations respecting the potential for short-term odours that may occur during start up. This must not include H2S (see ERCB Directive 064 section 14) odour emissions)



xlvi June 2012

APPENDIX I

Atmos pheric Flu id Scrubber Se lec tion Guide lines


June 2012 xlvii

APPENDIX II

Pres s ure Ra ting Formula for Seamles s P ipe

The standard is ANSI/ASME B31.3, "Chemical Plant & Petroleum Refinery Piping".

From Section 304.12 (3b):

P=2SEt / D-2Yt

Where:

P – is a maximum allowable working pressure, in psi,

S – is the basic allowable stress, in psi, for a given material, as defined in ANSI / ASME B31.3 Table A-1,

NOTE: For the common piping materials A 53 Gr. B, A106 Gr. B, A 333 Gr. 6, A 334 Gr. 6, and API 5L Gr. B, the allowable stress below 204 Celsius (400 Fahrenheit) is 20,000 psi

E – is the basic quality factor for longitudinal welds, as defined in ANSI / ASME B31.3 Table A – 1B,

NOTE: For seamless pipe, forgings and fittings E = 1.00, and for electric resistance welded pipe, E = 0.850

t – is the minimum pipe wall thickness, in inches. t = (tnominal x 0.875) - H, where:

tnominal – is the nominal wall thickness, in inches, of the pipe as defined in ASME B36.10M (see attached table for common pipe sizes, thicknesses and diameters).

0.875 - represents the manufacturers allowable under tolerance of 12.5% for seamless pipe.

H - is thread depth. For NPT threads, H = 0.07531 "up to 50.8 mm (2in) pipe ”, and

H = 0.10825 "above 50.8 mm (2in) pipe”.

D – is the outside diameter, in inches (see attached table for common pipe sizes, thicknesses and diameters) ,

NOTE: The above calculation does not include corrosion allowance. If a corrosion allowance is required to be added:


xlviii June 2012

t – (tnominal x 0.875) – H – c, where c is the required corrosion allowance, in inches.

Y = 0.4 Coefficient as per table (304.1.1 )

Tables – Pressure Rating Of Seamless Pipe

The attached tables do not include a corrosion allowance. In well testing, sudden and violent erosion is certain to destroy well test pipe before corrosion. The values for welded 4130 HRC in the following table have been rounded up to the nearest 50 psi. This table is for reference only.

Table 2: Pressure Rating of Seamless Pipe

Pipe Size Inches

Actual O.D. Inches

Pipe Schedule

Nominal Wall Inches

Nominal I.D. Inches

Welded Carbon Steel NPT Threaded Carbon Steel Welded 4130 HRC 18-

22 Max

P=2SEt / D-2Yt IRP recommends max. 17.24 Mpa on threaded pipe 33mm or larger

Limited By API 6A

Rounded to nearest 50 Psi

Psi Mpa Psi Mpa Psi Psi Mpa

½ 0.84 40 (STD) 0.109 0.622 4995 34.44 974 6.72 80 (XH) 0.147 0.546 6980 48.13 2675 18.44 160 0.187 0.466 9230 63.64 4592 31.66 XXH 0.294 0.252 16225 111.87 10480 72.26

1 1.315 40 (STD) 0.133 1.049 3810 26.27 1281 8.83 80 (XH) 0.179 0.957 5266 36.31 2602 17.94 160 0.250 0.815 7675 52.92 4780 32.96 XXH 0.358 0.599 11772 81.17 8463 58.35 (5000*)

1 1/2 1.9 40 (STD) 0.145 1.610 2822 19.46 1110 7.65 80 (XH) 0.200 1.500 3977 27.42 2191 15.10 160 0.281 1.338 5774 39.81 3869 26.67 XXH 0.400 1.100 8642 59.59 6539 45.09 (5000*)

2 2.375 40 (STD) 0.154 2.067 2377 16.39 1022 7.04 3400 23.44 80 (XH) 0.218 1.939 3433 23.67 2023 13.95 4900 33.79 160 0.344 1.689 5641 38.90 4114 28.36 8000 55.16 XXH 0.436 1.530 7373 50.83 5750 39.65 (5000*) 10450 72.05

2 1/2 2.375 40 (STD) 0.203 2.469 3182 21.94 1196 8.25 3700 25.51 80 (XH) 0.276 2.323 4428 30.53 2350 16.20 5100 35.16 160 0.375 2.125 6213 42.84 3999 27.58 (3000*) 7100 48.95 XXH 0.552 1.771 9715 66.99 7223 49.81 (3000*) 11000 75.85 XXXH 0.750 1.375 14189 97.83 11319 78.04 (3000*) 15400 106.18

3 3.5 40 (STD) 0.216 3.068 2258 15.57 940 6.48 3200 22.06 - - - 0.254 2.992 2676 18.45 1338 9.22 3800 26.20 80 (XH) 0.300 2.900 3191 22.01 1827 12.60 4500 31.03 - - - 0.375 2.750 4054 27.95 2646 18.24 5750 39.65 160 0.438 2.624 4801 33.10 3354 23.12 (3000*) 6800 46.89 XXH 0.600 2.300 6818 47.01 5264 36.30 (3000*) 9700 66.88 - - - 0.750 2.000 8824 60.84 7160 49.37 (3000*) 12400 85.50 - - - 1.000 1.500 12500 86.19 10625 73.26 (3000*) 17000 117.22

3 1/2 4 40 (STD) 0.226 3.548 2059 14.20 911 6.28 2900 20.00 80 (XH) 0.318 3.364 2946 20.32 1760 12.13 4200 28.96 - - - 0.500 3.000 4795 33.06 3525 24.30 (3000*) 6800 46.89 XXH 0.636 2.728 6262 43.18 4924 33.95 (3000*) 8850 61.02 - - - 0.750 2.500 7554 52.08 6155 42.44 (3000*) 10700 73.78 - - - 1.000 2.000 10606 73.13 9056 62.44 (3000*) 14700 101.36 - - - 1.250 1.500 14000 96.53 12274 84.63 (3000*) 18700 128.94

Pipe Size Inches

Actual O.D. Inches

Pipe Schedule

Nominal Wall Inches

Nominal I.D. Inches

Welded Carbon Steel NPT Threaded Carbon Steel Welded 4130 HRC 18-

22 Max

P=2SEt / D-2Yt IRP recommends max. 17.24 Mpa on threaded pipe 33mm or larger

Limited By API 6A

Rounded to nearest 50 Psi

Psi Mpa Psi Mpa Psi Psi Mpa

4 4.5 40 (STD) 0.237 4.026 1914 13.20 897 6.18 2700 18.62 --- 0.250 4.000 2023 13.95 1002 6.91 2850 19.65 --- 0.312 3.875 2550 17.59 1509 10.40 3600 24.82 80(XH) 0.337 3.826 2766 19.07 1716 11.83 3900 26.89 --- 0.364 3.772 3001 20.69 1941 13.39 4250 29.30 120 0.438 3.624 3656 25.21 2570 17.72 5200 35.85 --- 0.500 3.500 4217 29.08 3109 21.43 (3000*) 6000 41.37 160 0.531 3.458 4502 31.04 3382 23.32 (3000*) 6400 44.13 XXH 0.674 3.152 5856 40.38 4681 32.27 (3000*) 8300 57.23 --- 0.750 3.000 6604 45.53 5397 37.21 (3000*) 9350 64.47 --- 1.000 2.500 9211 63.51 7891 54.41 (3000*) 12900 88.95 --- 1.250 2.000 12069 83.22 10621 73.23 (3000*) 16500 113.77 --- 1.500 1.500 15217 104.92 13620 93.91 (3000*) 19950 137.56

4 1/2 5 40 (STD) 0.247 4.506 1791 12.35 878 6.05 2550 17.58 --- 0.250 4.500 1813 12.50 900 6.20 2550 17.58 80(XH) 0.355 4.290 2615 18.03 1673 11.54 3700 25.51 --- 0.375 4.250 2770 19.10 1823 12.57 3900 26.89 --- 0.500 4.000 3763 25.95 2780 19.17 5350 36.89 XXH 0.710 3.580 5519 38.05 4471 30.83 (3000*) 7800 53.78 --- 0.750 3.500 5866 40.45 4805 33.13 (3000*) 8300 57.23 --- 1.000 3.000 8140 56.12 6992 48.21 (3000*) 11500 79.29 --- 1.250 2.500 10606 73.13 9360 64.54 (3000*) 14700 101.36 --- 1.500 2.000 13291 91.64 11933 82.28 (3000*) 17900 123.42

5 5.563 40 (STD) 0.258 5.047 1678 11.57 859 5.93 2400 16.55 80(XH) 0.375 4.813 2476 17.07 1633 11.26 3500 24.13 120 0.500 4.563 3357 23.15 2485 17.13 4750 32.75 160 0.625 4.313 4268 29.43 3366 23.21 (3000*) 6050 41.71 XXH 0.750 4.063 5210 35.93 4277 29.49 (3000*) 7400 51.02 --- 1.000 3.563 7197 49.62 6196 42.72 (3000*) 11900 82.05

6 6.625 0.250 6.125 1357 9.35 676 4.66 1900 13.10 0.280 6.065 1524 10.51 840 5.79 2150 14.82 0.312 6.001 1704 11.75 1015 7.00 2400 16.55 0.375 5.875 2063 14.22 1364 9.40 2900 20.00 0.432 5.761 2391 16.49 1684 11.61 3400 23.44 0.500 5.625 2789 19.23 2070 14.27 3950 27.24 0.562 5.501 3156 21.76 2428 16.74 4450 30.68 0.719 5.189 4111 28.34 3356 23.14 (3000*) 5800 39.99 0.864 4.897 5023 34.63 4243 29.25 (3000*) 7100 48.95 1.000 4.625 5907 40.73 5102 35.18 (3000*) 8350 57.57 1.125 4.375 6745 46.51 5916 40.79 (3000*) 9600 66.19 1.250 4.125 7609 52.46 6754 46.57 (3000*) 10800 74.47


June 2012 li

IRP Also refer to entire Section 4.2.2.2 Pressure Rating on maximum allowable pressure rating for line pipe


June 2012 1

4.1 DRILL STEM TESTING 4.1.1 SCOPE

Normal drilling procedures, control formation pressures and fluids through the use of a hydrostatic head. Drill stem testing brings these formation pressures and fluids to the surface, thereby presenting a unique set of conditions since pressure control is then maintained by mechanical systems. Safe work guidelines, such as those set out in this IRP, minimize the probability of either the mechanical or human systems failing during a test, as well as establishing minimum health and operating standards. This IRP is intended to supplement existing standards and regulations rather than replace them, and is directed mostly towards drill stem tests that are to be run on onshore wells.

4.1.2 PLANNING A DRILL STEM TEST 4.1.2.1 Drill Stem Test

IRP Owners shall provide a plan for all drill stem tests. This plan shall include at least: the zones to be tested, the depths of tests, the method of testing, the type of equipment to be used, the duration of the test, and a reference to an emergency response plan, where applicable. The emergency response plan shall be discussed with all employers and workers involved with the drill stem test.

4.1.2.2 Lithological and Reservoir Information

IRP Operators shall provide litho logical and reservoir information on the zones to be tested. This shall include potential H2S zones, possible well problems, anticipated recovery, anticipated flow rates, H2S rates, and anticipated pressures. This information shall be discussed with all employers and workers involved with the drill stem test.

4.1.2.3 Qualifications

IRP Workers conducting drill stem testing operations shall have the minimum qualifications required by legislation and the industry.

4.1.3 ON-SITE PRE-TEST GUIDELINES 4.1.3.1 Pre-test Safety Meeting

IRP The worksite owner or designated representative shall hold a pre-test safety meeting with all workers on the site who may be involved with the drill stem test. This meeting shall review the testing plan, testing procedures, test prognosis, operation of surface equipment, and assign


2 June 2012

specific worker responsibilities. The pre-test safety meeting shall be recorded, along with a record of those who attended the meeting. The pre-test safety meeting will include a discussion of the emergency response plan where applicable, including any revisions or recommendations to accommodate the specific well environment.

4.1.3.2 Pre-Test Inspection

IRP The worksite owner or designated representative shall visually inspect all equipment and facilities that may be used during the drill stem test including:

• The drilling floor and hoisting equipment

• Safety equipment

• Surface equipment and lines

• Drill stem test tools including test head and floor manifold

• Drill pipe, drill collars, drilling fluid, and additives

• Blow-out prevention equipment

• Fluid containment or storage equipment

The inspection shall ensure proper distances are used in placing the equipment on the worksite.

IRP Swivel joints and flow lines upstream of the choke manifold shall be subjected, prior to the drill stem test, to a pressure test. The lines shall be visually inspected for leaks at both low pressures and high pressures. The high pressure test shall be to the maximum anticipated surface pressure. Lines downstream of the manifold should be secured to restrict them from movement.

Reference: Safety Checklist - see Appendix V

4.1.3.3 Pre-test Training

IRP The worksite owner or designated representative shall ensure that all workers involved with a drill stem test are properly trained in the operation of drill stem testing equipment, safety equipment, and personal safety equipment.

4.1.4 DRILL STEM TESTING GUIDELINES 4.1.4.1 DST Tool Retrieval during Daylight

IRP Liquids recovered during drill stem tests should be reverse circulated from the drill pipe. Prior to reversing out, drill pipe may be pulled from


June 2012 3

the hole until fluids are encountered at surface. Test plugs should be utilized if liquid recovery is expected. When using test plugs, they should be used from the very first stand pulled, then continuously throughout trip. If reverse circulation is not possible, the trip may be continued using test plugs and mud can with extreme caution.

IRP When testing sour wells a certified pressurized tank and flare stack should be used to ensure efficient separation and burn of all gases. A flare permit from the local authority may be required.

Cautions:

• A pump-out-sub or downhole circulating device should be run in the test string to reverse.

• Reverse circulation requires proper disposal of the contents of the drill string. Pump to a tank truck or a vacuum truck.

• Ensure that all lines are secured so as to restrict their movement, engines are off, and the receiving vessel is properly grounded and vented.

• Refer to Section IRP 4.1.5 if the recovery is sour.

• See IRP 4.2 Well Testing and IRP 4.3 Other Flowbacks for other information.

• Extra care must be taken once the pump-out-sub has reached the rig floor since hydrocarbons may be present below the pump-out-sub.

• Reverse circulation may not always be possible if a pump-out-sub fails to operate, or the owner chooses not to reverse circulate liquid recoveries in order to obtain better quality formation fluid samples.

• Owners may choose to reverse circulate prior to encountering fluids depending on the fluid recovery expected. The use of telemetry for surface readout will indicate potential fluid recovery. Monitoring the flare through final shut-in may also show indications of fluid in the drill pipe.

4.1.4.2 DST Tool Retrieval during Darkness

IRP Drill stem tests may be conducted during darkness until liquid recovery is encountered, if IRP 4 is followed. Special emphasis will be placed on lighting requirements referenced to in Abbreviations and Definitions At this point the recovery must be reverse circulated. If reverse circulation is not possible, pulling drill pipe shall not be continued until daylight

NOTE: Extra care must be taken once the pump-out-sub has reached the rig floor since hydrocarbons may be present below the pump-out sub.


4 June 2012

4.1.4.3 Annulus Fluid Level

IRP The fluid level in the annulus shall be monitored at all times. Should the packer seat fail and the level of fluid in the annulus drop, a method for filling the hole shall be in place at all times.

NOTE: A drop in the fluid level would reduce hydrostatic pressure and could allow zones above the packers to kick. Such a loss could be caused by a packer seat failure or fluid loss to an upper formation.

4.1.4.4 Workers on Rig Floor

IRP All workers shall be fully aware of their responsibilities during the test including what to do in an emergency.

IRP Clear all non-essential workers from the rig floor during the drill stem test.

4.1.4.5 Test Line

IRP A separate drill stem test line shall be rigged up to the floor manifold and run to the flare pit or other area to dispose of or to store the fluid. The flare line must be adequately secured and the igniter lit prior to the start of the test, if applicable. Do not use the BOP blow down line as the test line. When testing sour wells, a certified pressurized tank and flare stack should be used to ensure efficient separation and to burn of all gases.

NOTE: If a hydrate or sulphur plug is suspected in the drill pipe, be very cautious before disconnecting any of the pipe. Plugging can be monitored best by the use of telemetry, surface readout system. Monitoring the flare through the final shut-in may also aid in identifying plugging.

4.1.4.6 Floor Manifold

IRP The line of flow shall be directed through a floor manifold to allow for control and measurement of flow. The manifold shall have a pressure rating which exceeds that of the maximum anticipated surface pressure to be encountered. A floor manifold may also be referred to as a choke manifold on the rig floor. The floor manifold must be secured so as to restrict it from movement in the event of a break in the piping system.

4.1.4.7 Swivel Joints and Flexible Pipe

IRP All swivel joints and flexible pipe shall be secured with a safety cable. The integrity of flexible piping should be ensured through pressure testing.


June 2012 5

4.1.4.8 Fire Prevention

IRP Non-essential electrical systems, motors and engines within 25 m of the wellhead shall be shut down. Any essential diesel motor within 25 m of the wellbore should be equipped with an exhaust extension and emergency shut-off system. The rig floor and sub area shall be well ventilated. This may include opening man-doors in pre-fabs during winter operations.

4.1.4.9 Pipe Tally

IRP A pipe tally shall be taken while pulling out of the hole for the drill stem test and a tally shall be taken while running the test to depth. This tally shall be reviewed and checked by the well site owner before starting the test.

4.1.4.10 Flow Checks

IRP After completion of the drill stem test, flow checks should be done prior to starting the test string out of the hole and should be done at appropriate intervals while pulling out of the hole. A flow check is when the pulling of pipe is stopped and a waiting period is used to see if there is any inflow into the annulus. Ensure the test string is pulled slowly to avoid a swabbing effect. Follow rigorous hole filling procedures. Appropriate intervals for flow checks are:

• After pulling the first 3-5 stands

• When half way out of the hole

• When the test tools are at the casing shoe

• At any warning sign

• When the drill collars are reached

• When totally out of the hole

• Flow checks should be 10-15 minutes in length, with flow temporarily diverted to the trip tank

4.1.5 SOUR DRILL STEM TEST GUIDELINES 4.1.5.1 Safety Guidelines

IRP The safety of the worker and equipment takes precedence over any test information to be collected. Prior to starting a sour drill stem test, it is essential that all workers on the lease understand the dangers of H2S. They should be fully informed of and trained in appropriate safety


6 June 2012

procedures, including the use of safety equipment and breathing apparatus.

IRP A safety company representative must be on-site during the testing of any well that has the potential of producing sour gas.

Caution:

• Hydrogen sulphide gas is colourless, heavier than air, and is extremely toxic.

• It is explosive when mixed with air in the range of 4.0% to 45%, and it is soluble in fluids.

• The principal danger to the worker is poisoning by inhalation.

• Tubular and metals in an H2S environment can be very susceptible to hydrogen embitterment and sulphide stress cracking.

4.1.5.2 Sour Drill Stem Testing Equipment

IRP A drill stem test that may encounter H2S shall have sour service surface equipment meeting the requirements of NACE MR 01-75 latest edition, Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment. A certified pressurized tank and flare stack for efficient separation and handling of sour gas or fluids must be used.

NOTE: Hydrogen embitterment and sulphide stress cracking are influenced by a complex interaction of parameters, including:

• Metal chemical composition, strength, heat treatment, and microstructure

• Type and pH of the drilling fluid

• H2S concentration and total pressure

• Total tensile stress

• Temperature of the interval being tested

• Length of time tools are exposed to H2S

• Other factors

The decision on which surface equipment, downhole equipment and testing tubular to run for a sour drill stem test should include an evaluation of the above parameters to best combat the corrosive effects of hydrogen sulphide. The selection of tubular is especially critical, and consideration should be given to using sour service tubing instead of drill pipe. Numerous charts and graphs are available to demonstrate, both theoretically and empirically, conditions where drill pipe may potentially be used safely for sour drill stem testing. An in-depth


June 2012 7

examination of using drill pipe in a sour gas environment can be found in Section 1.2 of IRP 1 Critical Sour Drilling

4.1.5.3 Corrosion Inhibition While Sour Drill Stem Testing

IRP Inhibit water based drilling fluids by maintaining a pH above 10. Inhibit oil based muds with the addition of commercially available scavengers.

IRP Use a filming amine inhibitor to protect the interior of the test string when running a sour drill stem test. If no water cushion is used, the inhibitor should be dumped down the test string. If a water cushion is used, mix the inhibitor with the cushion, and also put inhibitor on top of the cushion. Both water soluble and oil soluble inhibitors are available from safety service companies.

4.1.5.4 Limitations of Sour Drill Stem Testing

IRP Drill stem tests that produce sour fluids to surface shall be shut-in immediately unless equipment used in the hole and at surface is adequate for the conditions.

NOTE: A closed chamber drill stem test will prevent fluid flow at surface during a sour test. IRP 4.2 Well Testing, provides additional recommendations about handling sour fluids using surface well testing equipment.

4.1.5.5 Sour Hydrocarbon Recovery

IRP All sour gas shall be flared. Install a constant pilot light or ignition device in the flare stack to ensure combustion of all gas sent to the flare stack. Refer to Provincial Regulations regarding flaring.

IRP Sour liquid recovery shall be reversed to a certified pressurized tank with a flare stack.

4.1.5.6 Neutralizing H2S during Trip out Hole

IRP When pulling drill stem test tools out of the hole, use a mixture of aqua-ammonia and water to neutralize any H2S in vapour phase. Use caution when putting the mixture down the test string. A small amount of fluid may unload due to displacement from the ammonia. Ammonia is available from safety service companies.



8 June 2012

APPENDIX III

Recommended Drill S tem Tes ting Services Ins pec tion Checklis t

Worksite Owner Drilling Company

Lease Location and LSD Critical Sour Well(Y/N)

DST Service Company Service Company Rep

Inspected By Date 20 Time: Hrs

Yr Mo Day 24 hrs Clock

Well Activity

Mark A Check If "Adequate or Inadequate" or ' - ' If Not Applicable

(NOTE: Any Inadequate Must have an Explanation and be Corrected)

Adeq Inadeq

A. SIGNS

01 No Smoking ____ ____

02 Designated Smoking Area ____ ____

03 No Vehicles or Unauthorised Persons ____ ____

04 Danger High Pressure ____ ____

05 H2S (if required) ____ ____

B. PERSONAL SAFETY

06 Emergency Response Plan complete ____ ____

07 Pre-start up Safety Meeting ____ ____

08 Hard hats (CSA approved) ____ ____

09 Safety footwear ____ ____

10 Eye Protection ____ ____

11 Ear Protection ____ ____

12 First Aid supplies ____ ____

13 Certificates

a) H2S ____ ____


June 2012 9

b) WHMIS ____ ____

c) First Aid ____ ____

d) Transportation of Dangerous Goods ____ ____

14 Fire retardant clothing ____ ____

15 Facial hair ____ ____

16 Fire Extinguishers ____ ____

17 H2S gas detector (manual) ____ ____

18 Back packs checked ____ ____

19 Air supply checked ____ ____

C. GENERAL

20 Motor kills checked ____ ____

21 Motor exhaust water manifolds operational ____ ____

22 Safety valve connection checked ____ ____

23 Control valve actuated ____ ____

24 Flowline including lead to manifold to flare line, pressure

tested ____ ____

25 B.O.P. operation tests ____ ____

26 Well kill fluid adequate ____ ____

27 Pumping/tripping practices observed according to

Government regulations ____ ____

28 Emergency lighting ____ ____

29 Rig floor ventilation system ____ ____

30 Equipment integrity for H2S ____ ____

31 Manifold valves set for flow ____ ____

32 Flare pit properly dug 50 m from wellbore ____ ____

33 Flare ignition system ____ ____

COMMENTS / EXPLANATIONS


10 June 2012

NOTE:

• If separation equipment and oil storage is used, refer to production testing inspection list in Section 4.2 Well Testing.

• For rig safety, refer to drilling rig inspection checklist in IRP 2.0 Completing and Servicing Critical Sour Wells

Owner Representative Signature

Drilling Company Rep. Signature

DST Service Company Rep. Signature




June 2012 11

4.2 WELL TESTING 4.2.1 WELLHEAD CONTROL 4.2.1.1 General

IRP Well testing operations should be conducted with a wellhead installed or with a temporary wellhead as per IRP 4.2.1.3.6 Temporary Wellheads

4.2.1.2 Standard

IRP Wellheads should be selected, designed, and manufactured in accordance with the applicable portions of:

IRP Personnel on location should confirm compliance.

API 6A, Specification for Wellhead and Christmas Tree Equipment or the relevant parts of the ASME/ANSI Series:

• B16.4, Pipe Flanges and Flanged Fittings

• B16.9, Wrought Steel Buttwelding Fittings

• B16.11, Forged Steel Fittings, Socket-Welding and Threaded

• B16.34, Valves-Flanged, Threaded and Welded End

or

Registered Fittings as defined in the Provincial Regulatory Agency

or

IRP 5 Minimum Wellhead Requirements

or

A combination of the above, so that wellhead components meet recognized standards.

NOTE: Auxiliary documents should be applied where applicable:

• NACE MR 01-75 MR0175/ISO 15156-1 LATEST EDITION - Sulphide Stress Cracking Resistance Metallic Materials for Oilfield Equipment.

• IRP 2.0 Completing and Servicing Critical Sour Wells

• Provincial/federal regulations

Wellhead components must be manufactured by suppliers with an appropriate quality program. Shop and field welding quality programs are also required to ensure that welding meets the requirements of ASME Section IX, Welding and Brazing Qualifications.




12 June 2012

4.2.1.3 Wellhead Minimum Requirements

4.2.1.3.1. Pressure Rating

IRP All wellhead components must have a working pressure rating that is equal to or greater than the maximum bottomhole pressure in the wellbore

NOTE: In Alberta, ERCB Regulation 7.050 calls for wellhead components not to be less than the bottom hole pressure of the producing formation for wells with greater than 50 moles / kmol H2S (5%).

NOTE: In British Columbia (WCB Regulation 23.69(7)): when flow piping exceeds 3500kPa (500 psi), connections must be welded, flanged or hammer unions. If there is only a threaded connection available at the wellhead, special precautions must be taken.

4.2.1.3.2. Master Valves

IRP Where practical, all well tests must be performed using wellheads with a master valve. Master valves should be of the full bore, round opening type. Wells where the H2S content of the wellbore effluent is 50 moles/kilomole (5%) or greater require two master valves. Master valves for critical sour wells must be API 6A flanged.

NOTE: Master valves are used to allow the servicing of the wing valve and to allow the connection of treatment lines, lubricators and other temporary connections. Master valves are used to isolate other components, and should not be used to initiate or shut off flow.

NOTE: On dual master valved wellheads the upper master valve must be used as the working valve for operations

4.2.1.3.3. Flow Tee and Flow Cross

IRP All wells must be provided with a flow tee or cross above the master valve, to connect wing valves to the master valve(s). Sour and critical sour wells must be provided with an API 6A flanged flow tee. A top connector should be considered where applicable.

4.2.1.3.4. Wing Valve

IRP A wing valve must be attached to the flow or cross tee. Sour and critical sour wells must have API 6A flanged wing valves.

NOTE: The wing valve is used to initiate or shut off flow. The flow sequence is always: open the lower master valve (if applicable), then the upper


June 2012 13

master valve, then the wing valve. The shut off sequence is the reverse.

NOTE: Consideration must be given to the use of Emergency Shutdown Valves (ESD’s) on all wells classed as sour (above 10 ppm). In Alberta, all wells to be flowed having a surface pressure greater than 1379 kPa and an H2S content greater than 1% requires an ESD.

4.2.1.3.5. Pressure Testing

IRP All primary and secondary seals in the wellhead must be hydrostatically tested upon installation. All wellhead components should be pressure tested to a pressure that is at least equal to the bottomhole pressure of the producing zone or 1.3 x SITHP. Check with the wellhead manufacturer for maximum test values between the primary and secondary seals (limited to the collapse value of the casing.)

IRP This pressure test must be documented and recorded.

NOTE: The minimum stabilization criteria is detailed in API 6A Appendix F, which is a change rate of no more than 5% of the testing pressure per hour (10 minute minimum) or 3500 kPa/hour (500 Psig/hour) whichever is less.

4.2.1.3.6. Temporary Wellheads

IRP Temporary wellheads used in well testing, such as drilling or servicing Blowout Preventers, Tree Savers and Frac Heads must be designed with control systems that are essentially as outlined in that of IRP 4.2.1.3.1 through 4.2.1.3.4. BOP rams are not considered to be master valves and should not be used for securing or controlling the well (except in case of emergency).

4.2.2 WELL TESTING EQUIPMENT CAPACITIES AND PRESSURE RATINGS 4.2.2.1 Capacities

4.2.2.1.1. General

IRP Equipment flow capacities should be sized for the flow rates of the program, and need not be sized for the maximum capacity of the well. Flow capacities may be derived from detailed calculations, nomographs, and experience.

IRP Pop or Pressure safety valves (PSV) and burst heads must be piped to a system to take discharged product away from the vessel and workers in the immediate area.


14 June 2012

IRP On critical sour wells, PSV must be piped with a separate line to a flare stack that has a separate line for that PSV on the flare stack. At no point can the line pipe from the PSV be smaller than the outlet on the PSV.

IRP A hazard assessment must be completed with the client to determine when the PSV must be piped with a separate line to a flare stack

IRP Piping downstream of the PSV must comply with ASME Section VIII Div. I.

IRP Unrestricted access to the wellhead wing valve and master valve must be ensured.

IRP Pressure vessels and piping systems must be protected by pressure relief safety devices, as defined by the provincial regulatory agency must protect pressure vessels and piping.

NOTE: Conventional pressure safety valves are designed for block- in pressure protection and to operate without allowing the relieving pressure to rise greater than 10% over the set pressure of the PSV. ASME Section VIII Division 1 requirements are that the safety valve cannot be set greater than the vessel’s Maximum Allowable Working Pressure (MAWP) and must have adequate capacity to ensure that the maximum rise of pressure after the valve opens is limited to 10% of the MAWP. Backpressure on a safety valve is not a function of its operation to relieve pressure but is a function of any external produced pressures on the outlet side of the safety valve. If this backpressure is constant then the conventional safety valve can be cold set at a lower pressure, set to compensate for the backpressure. If the backpressure is variable, a pilot or balanced bellows pressure safety valve is required to maintain constant pop pressure.

If the pressure safety valve is installed to prevent overpressure due to thermal (fire) exposure only and there is no source of external pressure that would cause the vessel to exceed its MAWP, a thermal relief valve can be installed. This safety valve can be set at 110% of the vessel MAWP and pressure rise to maximum 25% over the MAWP is allowed.

A pressure shutdown device is not an acceptable means of overpressure protection for pressure vessels – a safety relief valve is required.

4.2.2.1.2. Separator Systems

IRP Separator capacities should be at planned operating pressures and should be sized for all well effluent phases.


June 2012 15

4.2.2.1.3. Heat Requirements

IRP Heat requirements address the hazards that can be encountered during flowbacks such as (but not limited to);should consider hydrate inhibition, CO2 content, inhibition of solid deposition, and the reduction of solution gas and foam at the separation and liquid storage stage, and ambient temperatures.

4.2.2.1.4. Liquid Storage

IRP The upstream system and the liquid storage stage must be designed to reduce, eliminate or control the escape of vapours to the environment.

4.2.2.2 Pressure Ratings

4.2.2.2.1. Pressure Vessels

NOTE: Refer to the Definitions section in this IRP for clarification on certified versus non-certified vessels.

IRP Pressure vessels are defined by the Provincial Regulatory Agency. All pressure vessels must be designed and registered to their requirements. All certified vessels must have a CRN registered for the province where the vessel is used. Pressure vessels or pressurized tanks used for flow back or storage of fluids produced from a sour well must be manufactured under a quality program to ensure conformance with design specifications utilizing materials meeting the requirements of NACE MR 01-750175/ISO 15156-1 LATEST EDITION.

4.2.2.2.2. Pressure Piping Appendix II

IRP ASME B31.3 Pressure Piping should be used as the design pressure standard for pressure piping. Appendix II summarizes the maximum allowable working pressure calculation and nominal dimensions of common carbon and low alloy steels. Section 4.2.5 Equipment Inspections must be considered for the inspection of all pressure retaining equipment. Also see Section 4.2.2.2.7 Pipe and Fitting Threading

NOTE: Table 2: Pressure Rating of Seamless Pipe in Appendix II has no corrosion allowance. It is the well testing company’s responsibility to ensure that piping systems are de-rated or replaced when pipe wall thickness is reduced below 0.875 multiplied by the nominal pipe thickness.


16 June 2012

NOTE: In Alberta (OHS Code, Part 37 Section 783(1)): The Manufacturer’s specifications or the certified specifications of a professional engineer must be followed.

NOTE: In British Columbia (WCB Regulation 23.69(7)): when flow piping exceeds 3500 kPa (500 psi), pipe terminations connections must be welded, (flanged or hammer unions) must be either welded to OEM specs or integral connections. If there is only a threaded connection available at the wellhead, special precautions must be taken a hazard assessment must be completed.

IRP All wells to be flowed having a surface pressure greater than 1379kPa and a H2S content greater than 1% requires an ESD.

4.2.2.2.3. Flanges

IRP ASME flanges have the pressure rating defined in ASME B16.5 Pipe Flanges and Flanged Fittings. Also refer to CSA Z245.12. Unless higher temperatures are encountered, the nominal pressure rating is that at 38 degrees C (100 degrees F). API flanges have the pressure rating stamped on the flange. API 6H fitting use the same class designation as ANSI B16.5 however the pressure / temperature ratings are different.

4.2.2.2.4. Other Connections

IRP Other connections that are not defined by standards such as ASME, API, CSA, etc. may be acceptable (e.g., hammer unions, Unibolt connections, etc.) provided that:

• The Working Pressure Temperature rating is clearly stated by the manufacturer

• The manufacturer has established the Working Pressure according to proper engineering standards

• Materials shall be as listed in ASME, API or CSA

• Fabricated components shall be welded using welding procedures qualified per ASME Section IX. Inspection and testing shall be per ASME B31.3 normal (sweet) or severe cyclic (sour) requirements.

NOTE: In British Columbia, documentation regarding working pressure must be available on site.

4.2.2.2.5. Flexible Piping

IRP Non-certified flexible pressure piping (e.g., swivel joints, pressure hose, etc.) should not be used where well effluent internal pressure could exceed 103.4 kPa (15 Psig) in well testing operations.



June 2012 17

IRP Certified flexible pressure piping can be used where well effluent internal pressure could exceed 103.4 kPa (15 Psig) but not the maximum certified pressure in well testing operations(certified to the weakest point that can be exposed to the given pressure).

IRP Where lines of 33 mm O.D. (1" nominal) or less are normally filled with a stable fluid (e.g., pressure gauge lines filled with methanol), flexible lines are acceptable as long as they are rated for that fluid and do not exceed the maximum working pressure of that line.

IRP All flexible piping must be secure at the ends in the event of connection failure to prevent whipping of the line.

IRP Consideration should be given to the use of steel lines where flexible piping could be subject to excessive heat such as flare stacks, incinerators, and vapourizers. A hazard assessment must be conducted when using flexible piping near heat producing devices.

NOTE: Refer to Section 4.3.6.4 Through Tubing Clean Outs With Snubbing Units when 50.8 mm (2”) hose is acceptable for pressures above 103.4 kPa (15 Psig)

4.2.2.2.6. Welding of Pipe and Fittings

IRP Pipe and fitting welding should be to the meet requirements of ASME Section IX. Post-weld stress relieving is required for H2S service systems (as defined in Section 4.2.3.1.2 Welding of Carbon and Low Alloy Steels) unless special hardness control procedures as defined in NACE MR 01-75 0175/ISO 15156-1 LATEST EDITION are observed. Radiography to ASME B31.3 is recommended.

4.2.2.2.7. Pipe and Fitting Threading

IRP Line pipe threading should not be used above 17.24 MPa (2500 Psig), for pipe sizes above 33 mm (1" nominal).

At a maximum, the line pipe threading ratings of API 6A shall apply, provided that the thread depth ratings of Table 2 Pressure Rating of Seamless Pipe in Appendix II are not exceeded.

Pipe / Fitting Size Working Pressure

To 21 mm (½") 68.9 MPa (10,000 psig)

27 mm (¾") - 60 mm (2") 34.5 MPa (5,000 psig)

73 mm (2 ½ ") - 168 mm (6") 20.7 MPa (3,000 psig)

EUE Tubing Threads 34.5 MPa (5,000 psig)


18 June 2012

Refer to the formula for pressure rating seamless pipe on Appendix II, Pressure Rating Formula for Seamless Pipe

4.2.3 H2S SERVICE EQUIPMENT REQUIREMENTS 4.2.3.1 Metallic Materials

4.2.3.1.1. General

IRP Metallic equipment in H2S service must be designed to prevent Sulphide Stress Cracking (SSC). NACE MR 01-75 0175/ISO 15156-1LATEST EDITION, Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, defines the requirements as a minimum standard. The "Sour Gas" definition outlined in NACE of an H2S environment is encouraged (although Sour Oil and Multiphases may be used where applicable). A H2S environment exists when the H2S partial pressure exceeds 0.35 kPa (0.05 Psia), and the total pressure exceeds 448 kPa (65 psia). H2S Partial Pressure = Mole Fraction H2S x Maximum Operating Pressure.

NOTE: Owners and service companies should note that this definition of partial pressure is not related to definitions of sour by any provincial regulatory body and that partial pressure introduces an additional planning consideration.

4.2.3.1.2. Welding of Carbon and Low Alloy Steels

IRP Post weld stress relieving is mandatory for low alloy steel and mandatory for carbon steels unless a weld procedure qualification ensures HRC 22 maximum throughout the weld. Radiography to ASME B31.3 is recommended where applicable.

4.2.3.1.3. Exceptions-

IRP Production lines to non-certified storage tanks, flare lines and vent lines may be exempted from complete conformance to NACE MR 01-750175/ISO15156-1 LATEST EDITION if:

• The lines will not normally be exposed to pressures in excess of 448 kPa (65 psia), and the lines have an adequate pressure rating for short term abnormal service.

4.2.3.2 Elastomers

IRP Elastomers for H2S service must be chosen by a combination of manufacturers' recommendations and industry experience, with regard for other products in the well effluent that may degrade elastomers.


June 2012 19

NOTE: Elastomers are not addressed by NACE MR 01-750175/ISO 15156-1 LATEST EDITION, but are required to be chosen carefully to contain well effluents. A reference for elastomer selection is IRP 2.11 Guidelines for Selecting Elastomeric Seals or NACE TM 0187-87 (Standard Method for Evaluating Elastomeric Materials in Sour Gas Environments).

4.2.3.3 Internal Trims of Valves, Controllers, Ect.

IRP Valves, controllers, etc. should be examined to analyze the possibility of H2S sulphide stress cracking (SSC) (i.e., components in tension are generally subject to SSC, components in compression are generally not). Secondly, the consequences of an SSC failure should be analyzed for the item. If an SSC failure would compromise workers or environmental safety, replacement trims should meet the requirements of NACE MR 01-750175/ISO 15156-1, LATEST EDITION. The following equipment items must have internal trims that meet the requirements of NACE MR 0175/ISO 15156-101-75, LATEST EDITION, regardless:

• Wellhead Emergency Shut Down Valves (ESD's)

• Pressure Vessel Pressure Relief Devices

• Sleeve or Disc-type Chokes.

NOTE: The internal trims of some components exposed to H2S have a much higher possibility of compromising safety and control when they are subject to erosive well products. These components include level control valves, meters, and block / bypass valves. Contractors should carefully consider the practical details of the equipment service.

4.2.4 WELL TESTING EQUIPMENT MATERIAL CONFORMANCE 4.2.4.1 General

IRP Equipment fabrication standards must be sufficient to ensure conformance to Sections 4.2.2 and Section 4.2.3 (when used in sour service)

NOTE: Per Section 4.0.13.5 Well Testing Company Responsibilities, it is the well testing company’s responsibility to meet pressure ratings and H2S requirements when the owner has given the proper information; therefore, the well testing company warrants material conformance to the owner. IRP’s 4.2.2 through 4.2.5 are minimum standards for material identification. More rigid identification systems are appropriate, and are sometimes specified by the owner.


20 June 2012

4.2.4.2 Pressure Vessels

IRP The manufacturer's tag must be affixed to the pressure vessel. The Manufacturer's Data Report shall be on file along with the latest Provincial Regulatory Agency inspection certificate and latest pressure safety valve record.

4.2.4.3 Pipe, Forging, and Fittings

IRP Forgings and fittings should be identifiable by API, ANSI, CSA, and Original Equipment Manufacturer (OEM) markings. Pipe should be identifiable by fabrication standards, drawings, or purchase orders. Pipe marking by low stress dies is discretionary.

4.2.4.4 Valves, Controllers Meters, Etc.

IRP Such components should be identifiable through API, ANSI, CSA, and OEM markings, or catalogues of OEM products if such catalogues uniquely identify and are traceable to the component.

4.2.4.5 Connections (Hammer Unions, Flanges, Etc.)

IRP Such components should be identifiable through OEM markings or catalogues of OEM products if such catalogues uniquely identify and are traceable to the component.

IRP All 50.8 mm (2”) unions of the following design must be identifiable through a unique colour coded as listed below.

Union Figure Number or Name Colour

RAL Colour Code

602 Red 3020 1502 Blue 5002

Guiberson / 607 White 9010

NOTE: RAL is a colour space system developed in 1927 by Reichsausschuß für Lieferbedingungen (und Gütesicherung)—German for Commission for Delivery Terms and Quality Assurance, nowadays called Deutsches Institut für Gütesicherung und Kennzeichnung e.V. RAL started off with only 40 colours, but has since expanded to cover over 1,900. That colour system is mainly used to describe paint colours.

http://en.wikipedia.org/wiki/Color_space�

http://en.wikipedia.org/wiki/1927�


June 2012 21

4.2.5 EQUIPMENT INSPECTIONS 4.2.5.1 General

IRP Well testing companies should establish a routine equipment inspection program, structured to reject or repair service related defects and improper field replacements. The following should be replaced or repaired:

• Components severely worn or damaged (so that they cannot safely perform their operating function)

• Welds weakened by fatigue cracking or sulphide stress cracking

• Components subjected to uncontrolled field repairs

• Components that compromise the pressure rating

• Components that compromise the H2S service rating.

4.2.5.2 Inspection Guidelines

IRP Annual or regularly scheduled equipment inspection should consist of the following:

• Detailed visual internal and external inspection, where possible

• Random thickness tests on pressure vessels and piping components focused on areas most likely to erode, corrode or deteriorate

• Repair / replacement of rejected components

• Hydrostatic testing of each pressure component to 1.5 times maximum working pressure

NOTE: Several inspection frequency processes are available, for example on a calendar or usage basis. Well testing work can subject equipment to exceptional short term corrosion and erosion, which may necessitate additional inspection. Exceptional corrosion can be caused by acids, solvents, high chloride content, and CO2 with H2S. Where exceptional corrosion could be expected, programs should be modified to eliminate as many system elements as possible (without compromising safety).

Exceptional erosion can be caused by any well debris, and is common with frac sand returns. Programs in high erosive situations should be modified to include elements of the following:

• Reduce the rate to minimize erosion

• Direct well flow to a 2-choke manifold, followed by a combination separator / storage vessel with large cleanout openings: extra methanol injection may be required for hydrate inhibition


22 June 2012

• Direct well flow to a solids separator or filter

Equipment should be designed, fabricated, inspected, and tested to the intended most severe service to minimize the effects of corrosion, erosion, and stress cracking, etc. Use of treated (cobalt cased) or coated components should be evaluated to minimize the effects of erosion.

4.2.6 WELL TESTING EQUIPMENT SPACING IRP The schematics of the Appendix IV Lease Layout Schematics should be

used as general guidelines to meet spacing requirements and provincial regulations. If the spacing cannot be met, it is the owner’s responsibility to obtain permission from the local authority for changes. Some spacing requirements are listed below.

NOTE: The water tank solution gas hazard should be evaluated before reducing the distances. The appendices are intended to specify minimum spacing and not equipment layout or piping details. IRP 4.3 Other Flowbacks must be referenced when well testing is combined with other flow back operations.

NOTE: refer to IRP 20 Wellsite Design Recommendations

4.2.6.1 Equipment Spacing For Propane Tanks

IRP Distances for placement of skid mounted or free standing propane storage vessels should not be located within 25 metres of the flare stack. The following also shall be considered before placing this equipment.

When in use with a vaporizer the equipment placement distance must meet the minimum distance requirement of the local authority for open flame equipment from the wellhead. Consideration must be given to all other potential sources of vapour when selecting a site to position the vaporizer to prevent a fire or explosion.

• Propane tanks must not be located within any tank dyke

• The vaporizer must be a minimum eight metres from the propane storage tank(s)

• The interconnecting pipe from the propane storage tanks to the vaporizer should be hard-piped and the interconnecting material must be manufactured to maintain integrity for short periods in a fire.

• The vaporizer should be inspected and cleaned regularly by a certified propane equipment supplier.

• Filling of propane tanks above 80% capacity is not allowed

http://www.enform.ca/publications/IRP/wellsite_design_spacing.aspx�


June 2012 23

• Position of supply and filling lines to be outside of high traffic areas( i.e., foot and vehicular)

• Tarping propane vessels for use with external heat sources to vapourize liquid propane during cold weather operations are only allowed with equipment that has been manufactured and certified for that application. It must also meet all equipment spacing requirements.

• Valved ports on the propane storage tanks should be plugged prior to transport.

• Propane tanks should have clearly visible certification labels.

• Consideration should be given to the pressure safety valve (psv) on the propane storage vessel as to the direction of discharge if triggered.

NOTE: Reference the appropriate provincial department of transport for guidance when transporting oilfield skid mounted propane tanks with product in the tanks.

4.2.6.2 Equipment Spacing For More Than One Certified Pressurized

Tank

IRP Where two or more certified pressurized tanks are used as either a primary flow vessel or for storage of fluids, the tanks must be a minimum of 25 metres from the wellhead and can be placed side-by-side.

NOTE: Provincial jurisdictions may vary in the distance requirement. Refer to the appropriate regulatory agency for clarification.

4.2.6.3 Equipment Spacing for Non – Certified, Non – Registered

Vessels or Pressure Tanks

IRP All non-registered non-certified vessels or pressure tanks must be at least 50 metres from the wellhead and 50 metres from the flare stack or any open flame and 25 m from flame arrested equipment (i.e., line heater).


24 June 2012

4.2.6.4 Electrical and Electronic Area Classification

IRP The following diagrams are from the Code for Electrical Installations at Oil and Gas Facilities published by The Safety Code Council of Alberta.

NOTE: Further consideration must also be given to the temperature classification of any electrical or electronic device within the classified area in regards to the auto-ignition point of the gases or chemical vapours that may be present.

Figure 1: Code for Electrical Installations at Oil and Gas Facilities


June 2012 25

4.2.7 PRE – TEST EQUIPMENT CHECK AND PRESSURE TEST IRP The following pre-test checks should be performed:

• Ensure that an inspection check list is followed

• Ensure that all connections are tightened

• Ensure the wellhead flowline is adequately secured to restrict movement of the line in the event of failure

• Ensure gas flaring lines and fluid production lines are adequately secured

• Ensure the wellhead ESD (if applicable) is function tested

• Ensure the purging is completed per 4.0.13.25

• Ensure the safety meeting has been completed per 4.0.13.12.

NOTE: A Production Testing Services Inspection Check List is included in Appendix V. Applicable details of the checklist are recommended.

4.2.7.1 Pressure Testing in Daylight/Darkness

IRP Following the rig in of test equipment and associated flowlines, pressure testing of the lines and equipment using a gaseous medium must be conducted in daylight hours only. If the integrity of the piping system has been broken at anytime after the initial pressure test, subsequent pressure tests using a gaseous medium must be done in daylight hours only.

IRP Hydraulic pressure testing may be conducted at night provided the conditions of Section 4.2.8 are met.

IRP The pressure test must be documented.

NOTE: See Section 4.2.8 Operational Safety, for night time start up procedures.

NOTE: In British Columbia hydraulic pressure testing is a requirement on all high pressure piping systems up to the first pressure control choke. The pressure test must be not less than 10% above the maximum anticipated operating pressure as determined by the well owner. When nitrogen is used in well stimulation, the piping system may be pressure tested with nitrogen. See British Columbia WCB regulation Section 23.72 for more detail.

4.2.7.2 Wellhead to Choke

IRP It is the owners responsibility to specify the pressure test medium. Hydraulic testing is recommended over the use of wellhead gas or


26 June 2012

pressurized vapour (e.g., CO2 or N2). The test must be to the maximum expected wellhead shut-in pressure. No leaks are to be tolerated. Pressure testing with a gaseous medium must be conducted in daylight hours only.

4.2.7.3 Pressure Testing on Critical Sour Wells

IRP On wells defined as critical sour, the flow line from the wellhead to the choke must be hydraulically pressure tested to the maximum expected Shut in Tubing Head Pressure (SITHP).

4.2.7.4 Downstream of Choke

IRP An inert medium or wellhead gas should be used to pressure test vessels to a minimum of planned operating pressure and a maximum of 90% of pressure relief device set pressure. Any interconnecting piping must be included. No leaks are to be tolerated. Where water is used for a hydrotest, ensure a product to negate ice build up is used in sub-zero operations.

4.2.7.5 Open Ended Piping and Production Tanks

IRP Open ended piping (e.g., flare lines, vent lines) and production tanks should not be isolated by valves and pressured tested. Closed valves should not be in the system. Instead, leak tests of open ended piping and production tanks must be part of initial operational checks after start up. Visual inspection of connections is an alternative.

4.2.8 OPERATIONAL SAFETY 4.2.8.1 Start Up at Night

IRP If required through necessity to start up at night, after a daylight pressure test was conducted, or a night time hydraulic pressure test was conducted, the following conditions must be met:

• Provisions are in place for lease lighting of a capacity to maintain safety of the site workers, allow the worker to perform his routine duties safely and to ensure visibility for the worker to safely exit an area in an emergency

• A hazard assessment has been conducted and documented

• The hazard assessment deems the start up safe for the worker

• All non-essential workers are vacated from the immediate area of the testing equipment, flowlines and wellhead. These workers shall not return to the area until cleared to do so by the owner’s wellsite


June 2012 27

representative after consultation with the well testing supervisor/ manager

• The crew is well rested

NOTE: Lease Lighting Guideline

4.2.8.2 General Start Up Procedure

IRP The following generalized start up sequence should be performed:

• All non-essential workers must vacate the surrounding area of the testing equipment, flowlines and wellhead. These workers shall not return to the area until cleared to do so by the owner’s wellsite representative after consultation with the well test supervisor/ manager

• The use of an ESD valve has been considered. In Alberta, all wells with a pressure greater than 1379 kPa and an H2S content greater than 1% require an ESD valve on the wellhead

• With wing valve closed, open the master valve and record pressures

• Close the choke (if applicable) and open the wing valve to the choke. Perform a detailed leak check

• Open the choke slowly to the pressure vessel. Set operating pressures immediately, and set liquid levels as soon as possible

• Begin vessel leak checks immediately, closely followed by downstream checks. For sour wells, those performing detailed leak checks must wear respiratory equipment

• Check H2S concentration as soon as possible, and at regular intervals thereafter. Shut in the well if additional equipment or workers are required

• Check equipment capacities. If pressures or rates exceed capacity, decrease the rate or shut in the well

NOTE: A rate preceding the actual test is appropriate to cleanup the well and to re-evaluate the programmed well performance.

4.2.8.3 Test Performance

IRP The test should be performed according to the following generalized guidelines:

• Perform and record measurements according to the program and provincial guidelines

• Continuously monitor safety systems and equipment



28 June 2012

• Continuously monitor air entrainment in tanks connected to a flare stack (per 4.0.13.25 Air Entertainment and Purging)

• Utilize the Safety Standby Method for all hazardous operations, and utilize a second back-up worker during sour hazardous operations

• Monitor flare rates and volumes according to the flare permit (if applicable)

• Monitor, assess, and act on new or unanticipated hazards

• Hold complete de-briefing/safety meetings sessions at shift changes per 4.0.13.12 Pre-job Safety Meeting

IRP If the equipment or the procedure cannot safely accommodate the flow, the well testing company’s supervisor of the shift has the ultimate authority to reduce the flow or shut in the well, after consultation with the well owner’s representative. If the representative is not available, the well testing supervisor will assume the responsibility to reduce the flow or shut the well in.

4.2.8.4 Shut In and Post – Test Procedures

IRP The following generalized procedures should be followed:

• Shut in by closing the choke followed by the wing valve

• Monitor shut in wellhead pressures per the program

• Shut in master valve(s)

• Displace all produced fluids to storage (or pipeline)

• For sour or toxic wells, purge the sour or toxic vapours to flare

• Shut down flares

• Rig out and remove equipment from location

• Chain and lock wellhead valves

• It is recommended all solid bullplugs in the wellhead be replaced with tapped plugs with a needle valve to check for pressure leakage past all wellhead valves. Ensure the pressure rating of the fittings meet or exceed the maximum wellhead shut in pressure

• Inform well operator of status of stored fluids still on location

• Remove debris and garbage from location.

4.2.9 WELL TESTING WORKERS IRP The owner of the well must ensure there are an adequate number of

qualified well testing workers on the wellsite at all times to conduct


June 2012 29

operations safely. The following identifies key situations and recommends a minimum number of workers required to conduct the operation safely and efficiently.

4.2.9.1 Recommended Minimum Well Testing Workers on a Wellsite

during Testing Operations

IRP All owners and well testing companies must exercise caution and good safety judgement in the selection of well testing equipment components and the number of qualified well testing workers. Gas/liquid deliverability, pressure, and toxic vapours such as H2S must be considered. Test equipment should be selected which reduces the risk of workers being exposed to toxic vapours. Pressurized storage for the liquid phase is one method of significantly reducing the toxic vapour hazard. Per 4.2.2.2 Pressure Rating, vessels for pressurized storage must meet the requirements of Provincial Regulatory Agencies. Unregistered non-certified All vessels must have adequately sized pressure relief devices to prevent bursting overpressure.

IRP For well testing, a minimum of two (working) qualified test workers per shift are recommended. If an owner chooses to conduct a continuously manned testing operation without the services of a well testing company, the minimum worker recommendations still apply.

4.2.9.2 One Qualified Well Testing Worker per Shift

One qualified well testing person per shift may be used on sweet or sour wells in the following circumstances:

• A Hazard Assessment/JSA has been completed to define all worker’s roles and responsibilities and the chain of command

• The individual has the knowledge and qualifications to perform as required

• The individual is in a well test supervisory capacity only, supervising two other workers at the site, in non-flowing operations such as swabbing, circulating, venting or bleeding off a well directly to a certified registered pressurized tank

• The workers at the site assigned to the well testing supervisor are willing and capable of operating well testing equipment as instructed

• The well is not flowed continuously to establish gas or fluid rates

• Where equipment rigged in a sour inline mode is automated and remotely controlled, the well owner may summon one qualified representative from the well testing company to the location for


30 June 2012

consultation or calibration of equipment as long as a qualified owning operating company representative is present on the location at the same time

• Where the well tester is installing electronic data gathering equipment on existing facilities and is in contact with the operator’s representative.

4.2.9.3 Two Qualified Well Testing Workers per Shift

IRP Regardless of well parameters, consideration must be given to the amount of equipment the crew is expected to operate effectively and safely. The workers ability to maintain a safe work environment and efficient operations is the prime consideration.

A minimum of two qualified well testing workers per shift are recommended required in the following circumstances:

• All sweet wells flowed through test equipment

• The operation is a sour inline test, with all measured well effluents at the separator diverted back to the pipeline

• A sour operation with essentially no inflow from the producing zone, such as the servicing of a hydraulically killed well, or where the formation is mechanically isolated

• A sour operation where the final sour liquid storage stage for produced fluids is a certified registered pressurized vessel or tank and the pressure vessel or tank is not preceded by more than one separation stage

• A sour operation where the final liquid storage vessel is a non-registered non-certified vessel preceded by a certified registered vessel or tank, provided the operating pressure of the non-certified non-registered vessel or tank does not exceed 50% of the design pressure

• A sour operation where the final sour liquid storage stage is an atmospheric tank system where; the tank(s) and thief hatches are designed for a maximum of 7 kPa working pressure, and there is a maximum of two atmospheric tanks

• The operating pressure at the atmospheric tank system does not exceed 50% of the design pressure

• The atmospheric tank system is not preceded by more than two one (21) separation stages including a gas boot

• The atmospheric tank system is gauged only by gauge boards or electronic system at shift changes where more than two workers are present


June 2012 31

• The H2S concentration does not exceed 5% (50 moles per kilomole)

4.2.9.4 Three Qualified Well Testing Workers per Shift

IRP Regardless of well parameters, consideration must be given to the amount of equipment the crew is expected to operate effectively and safely. The workers ability to maintain a safe work environment and efficient operations is the prime consideration. Additional procedures such as tank gauging flare enrichment, circulating fluids, operating line heaters, use of tank-farms, and operation of choke manifolds in erosive environments will require additional personnel. Consideration must be given having an adequate number of workers to effectively respond to any emergencies that may arise.

If the conditions in Section 4.2.8.3 cannot be met, a minimum of three qualified well testing workers per shift are recommended.

NOTE: On wells having shut-in pressures over 35 mPa, consideration should be given to the number of personnel required.

NOTE: If maintaining the atmospheric tank pressure below 50% of the thief hatch operating pressure becomes a problem, excess solution gas may be reduced by some or all of the following methods:

• Use of pressurized tanks

• Reducing the well effluent flow rate (i.e., reduce choke)

• Reducing the operating pressure of the separation stage(s) upstream of the tanks

• Adding heat upstream of the last separation stage

• Increasing the tank vent line and tank vent line flame arrestor size.

IRP If such operation cannot rapidly eliminate excess toxic vapours, the well must be shut in and additional equipment and/or workers called out.

NOTE: When storage stage gas is flared, additional precautions to prevent air entrainment are required, per Section 4.0.13.25.

4.2.9.5 Minimum Well Testing Workers Qualifications

The following is the minimum qualifications well testing workers must possess in training, certification and competence. Petroleum Services Standards of Competence (PSAC) have been developed for supervisory job classifications. These standards are registered with Enform and are recognized by the Petroleum Services Association of Canada (PSAC). Well testing companies should consider these Standards of Competence when qualifying their workers.

IRP Workers must have the listed minimum qualifications.


32 June 2012

Assistant Operator (Reports to Shift Leader):

Individual Must Have:

• H2S Alive® (or equivalent)

• IRP Volume 16 Basic Safety Awareness Training compliance training (PST)

• IRP Volume 18 Upstream Petroleum Fire and Explosion Hazard Management basic or advanced training

• WHMIS

• TDG

Within a reasonable amount of time after initial hire be trained in the following:

• Standard First Aid Certificates and C.P.R training

• Company-specific training

• Be qualified to drive

• Be able to and perform routine maintenance repairs on service vehicles

• Have basic knowledge of employers safety policies and emergency procedures

• Have knowledge of understand IRP 4 Well Testing and Fluid Handling, as it applies to the individual's job function

• Have basic knowledge of equipment functions

• Have basic knowledge of safety equipment

Shift Foreman/Operator/Shift Supervisor (Leads One Shift and Reports to Test or Job Supervisor/ Project Manager)

(In addition to Assistant Operator qualification)

Individual Must:

• Command of basic testing skills (in order to be able to lead a shift with minimum supervision)

• IRP 18 Upstream Petroleum Fire and Explosive Hazard Management advanced training

• Be qualified in confined space entry/rescue training

• Have thorough knowledge of employer’s safety policies and emergency procedures

• Know pressure ratings of system elements

• Be thoroughly trained in use of safety equipment





June 2012 33

• Be able to identify and assess hazardous conditions and act accordingly

• Understand safety responsibilities of assistants

• Be able to train subordinates

• Have basic knowledge of local, provincial, and federal regulations

Test or Job Supervisor/ Project Manager (Well Testing Company’s Overall Supervisor)

(In addition to Shift Foreman/Operator/Shift Supervisor qualifications):

Individual Must be able to:

• Command entire test with no direct supervision

• Coordinate test with well owner or owner’s representative

• Train assistants subordinates , and monitor progress/ deficiencies

• Be knowledgeable in local, provincial, and federal regulations

NOTE: Petroleum Competency Program (PCP) Standards of Competence have been developed for supervisory job classifications. Well testing companies should consider these Standards of Competence when qualifying their workers.

http://www.petrohrsc.ca/english/docs/library/Welltest-Book.pdf�


34 June 2012

APPENDIX IV

Leas e La yout Schematics


June 2012 35

Swee t Wells

Frac Flowback with Pres s ure Tank Minimum Spac ing Requirements


36 June 2012

Cold Separa tors Minimum Spac ing Requirements


June 2012 37

Heated Tes t Unit Minimum Spac ing Requirements


38 June 2012

Sour Wells

Frac Flowback with Pres s ure Tank Minimum Spac ing Requirements


June 2012 39

Heated Tes t Unit, P res s ure Tank and Clos ed Pres s ure S torage Tanks Minimum

Spac ing Requirements


40 June 2012

Heated Tes t Unit Minimum Spacing Requirements


June 2012 41

Heated Tes t Unit and Pres s ure Tank Minimum Spac ing Requirements


42 June 2012

APPENDIX V

Produc tion Tes ting Services Ins pec tion Checklis t

Contractor:

Operator:

Lease Location and LSD:

Critical Sour Well (Y/N)

Service Company:

Service Company Rep:

Inspected By: Date: 20___ ____ ____ Yr. Mo. Day Time: _______ (24 hr clock)

Well Activity:


June 2012 43

Mark a check if adequate or inadequate or if not applicable

(NOTE: Any “INADEQUATE” must have an explanation and be corrected)

A Signs Adeq. Inadeq B Personal Safety con’

Adeq. Inadeq

01 No Smoking 17 Fire Extinguishers #

02 Designated Smoking Area

18 Floor lights #

03 No Vehicles or Unauthorized Persons

19 H2S gas detector (manual)

04 Danger High Pressure 20 Work masks worn outside

05 H2S (if required) 21 Side packs checked

06 Signs with Operator name or phone #

22 Back Packs checked

B Personal Safety 23 Air Supply checked

07 Emergency Response Plan completed

24 Two air lines reach tanks

08 Pre-start up Safety meeting

25 Wind direction indicators

09 Hard hats (CSA approved)

C Wellhead

10 Safety footwear 26 Clean

11 Ear protection 27 Working pressure MPA

12 Eye protection 28 All valves seal

13 First aid supplies 29 ESD Valve Working Pressure MPA

14 Certificate: 30 Remote Shutdowns (OST)

a) H2S 31 Gage in place

b) first aid

c) WHMIS

d) TDG

15 Fire retardant clothing

16 Facial Hair


44 June 2012

D Flowline Adeq. Inadeq H Other con’d Adeq. Inadeq

32 Pipe schedule 51 Flame arrestor in.

33 Working pressure ____ MPA

52 Flame arrestor checked

34 Pressure Tested (Hydro)

53 Purge system in place for tank trucks

35 Blocked Level 54 H2S scrubber in place for 400bbl tanks

E Deadweight Line 55 H2S scrubber in place on tank trucks

36 Pipe Schedule 56 Tank lines checked

37 Working pressure ____MPA

57 Tank manifold checked

38 Pressure tested (hydro) 58 Tank manifold Bonded to tanks

39 Secured I Shipping Line

40 Blocked valve 59 Bonded to Tank

F Gas, Oil and Waterline

60 Length m

41 Secured 61 Blocked Level

42 Blocked level 62 Dip Pail

G Pop line 63 Valve

43 Pipe size __ 64 Truck Bonding

44 Secured 65 Fore Extinguisher

45 Blocked Level J Propane Line

46 Pop riser pilot in place 66 Hard pipe to vaporizer

47 Riser secured 67 Bloked level

H Other 68 Bonded

48 Check valve in place on pipeline

K Tanks

49 Plant operators notified of procedure

69 Bonded to wellhead

50 Flame arrestors in place 70 On planks


June 2012 45

K Tanks Con’d Adeq. Inadeq L Stack (Dia. mm. X m. con’d

Adeq. Inadeq

71 Level 92 Igniter checked

72 Valves work 93 No. guy wires

73 Valves set 94 0 – 15 meters wires (3)

74 Tank stairs 95 15 – 35 meters wires (3 min.)

75 Thief hatch 96 35 – 60 meters wires (6 min.)

76 Gas Blanket 97 Correct angels flagged

77 Tanks Purged 98 3 clamps/cable (1” apart)

78 Vertical line in. 99 Camps correct posirion

79 Flames arrestor in. 100 Shackles straight

80 Flame arrestor checked 101 Stack straight

81 Block valve 102 Fire hazard checked

82 Vertical line secured M Spacing

83 Drain at low point 103 Wellhead to Separator 25m

84 Stack line clear 104 Separator to Tank 25m Min

85 Vertical line bonded 105 Separator to Stack 25m Min

86 Berm checked 106 Wellhead to tanks 50m

87 Pressure alarm 107 Tanks to Flare 50m

L Stack (Dia. mm. X m.

108 Flare to Wellhead 50m

88 Lines clear 109 Certified Ptank to Wellhead 25m

89 Pilot checked 110 Non-certified Ptank to wellhead 50m

90 Shooter tube checked 111 Vaporizer to Propane tanks 25m

91 Flare catcher


46 June 2012

N Circulating Punp and

System Adeq. Inadeq P Separator Con’d Adeq. Inadeq

112 Check valve working press. MPA

132 Instrument supply system checked

113 Storm chokes working press. MPA

133 BP valve stroked and ser

114 Reservoir full 134 Front manifold set

115 Flowlines blocked 135 Inside valve set

116 Heater checked 136 Deadweight manifold set

O Heater 137 Deadweight line full

117 Upper coil schedule 138 Methanol barrel safe

118 Upper coil working prs. MPA

139 Liquid meters by-passed

119 Stack gasket checked 140 Floats checked

120 Bath full 141 Dump controllers set

121 Choke inspected 142 Hi-low’s checked

122 Supply gas checked Q Lease Trailer light plant

123 Pilot checked 143 Safety board

124 Main burner checked 144 Portable water

125 Flame arrestor checked 145 Safety binder

126 Heater preheated 146 WHMIS labelling

P Separator 147 Safety meeting posted

127 Separator working prs. MPA

149 Flare permit posted

128 Relief valve checked 150 Fire extinguisher

129 Pressure tested 151 Fire blanker

130 Valves Operational 152 Furnace lit

131 Lines clear 153 Office area clean


June 2012 47

Q Lease Trailer light plant Con’d

Adeq. Inadeq R General Adeq. Inadeq

154 Lockers clean 158 Flash lights C1-D1

155 Bench area clean 159 Test program available

156 Floor clean 160 Chemical clothing

157 Step level 161 Mobile phone good working order

162 Test kits checked

163 Purging completed

164 Government notified

165 Flaring permit obtained

166 Area residents notified

S. Comments / Explanations:

Owner Representative: Signature

Contractor: Signature

Representative

Service Company: Signature

Representative


48 June 2012

APPENDIX VI

FLARESTACK MAXIMUM AND MINIMUM FLARE RATES


June 2012 49

Gas Exit Velocity of 50.8 mm (2") Pipe

0

50

100

150

200

250

300

350

400

450

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75

Gas Rate 103 M3

Velo

city

m/s

ec

Velocity m/sec Speed of sound @ 0 oC

>1% H2S Gas Max Exit Velocity >1% H2S Gas Min Exit Velocity

Gas Exit Ve loc ity of 50.8 mm (2”) P ipe


50 June 2012


Gas Exit Velocity of 76.2 mm (3") Pipe

0

50

100

150

200

250

300

350

400

450

0 10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

Gas Rate 103 M3

Velo

city

m/s

ec

Velocity m/sec Speed of sound @ 0 oC >1% H2S Gas Max Exit Velocity >1% H2S Gas Min Exit Velocity


June 2012 51


Gas Exit Velocity of 101.6mm (4") Pipe

0

50

100

150

200

250

300

350

400

0 25 50 75 100

125

150

175

200

225

250

Gas Rate 103 M3

Gas

Vel

ocity

m/s

ec

Velocity m/sec Speed of Sound @ 0 oC>1% H2S Gas Max Exit Velocity >1% H2S Gas Min Exit Velocity


52 June 2012


Gas Exit Velocity from 152.4mm (6") Pipe

0

50

100

150

200

250

300

350

400

450

0

100

200

300

400

500

600

Gas Rate 103 M3

Gas

Vel

ocity

m/s

ec

Gas Velocity m/sec Speed of sound @ 0 oC>1% H2S Gas Max Exit Velocity >1% H2S Gas Min Exit Velocity


June 2012 53

Gas Exit Ve loc ity from 203.2 mm (8”) P ipe

Gas Velocity From 203.2mm (8") Pipe

0

50

100

150

200

250

300

350

400

450

0

100

200

300

400

500

600

700

800

900

1000

1100

Gas Rate 103 M3

Gas

Vel

ocity

m/s

ec



54 June 2012

Gas Exit Ve loc ity from 254 mm (10”) P ipe

Gas Exit Velocity from 254mm (10") Pipe

0

50

100

150

200

250

300

350

400

100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600

Gas Rate 103 M3

Gas

Vel

ocity

m/s

ec



June 2012 55

Natural Gas Hydrate Chart

100

1000

10000

100000

0.00 5.00 10.00 15.00 20.00 25.00 30.00 Temparture ( 0 C)

Pressure (Kpa)

Gas Gravity 0.9 Gas Gravity 0.6 Gas Gravity 0.7 Gas Gravity 0.8 Gas Gravity 1.0

In hydrate zone

Out of hydrate zone

APPENDIX VII

Hydra te Charts


56 June 2012


June 2012 57

4.3 OTHER FLOWBACKS 4.3.1 FLOWING TO OPEN TOP TANK

IRP At no time must flowing to an open top tank be undertaken if one or more of the following criteria exists:

• Operators must burn all nonconserved volumes of gas if volumes and flow rates are sufficient to support stable combustion.

• BC H2S exceeds 10 ppb (parts per billion)

• AB H2S exceeds 10 ppm, or as otherwise specified

• The gas or vapours have a toxic effect that is above the occupational exposure limit

• The vapours or gasses from the well effluent are heavier than air (Fluid API greater than 50 or Gas has a gravity of over 1.0)

• There are human residents within 500 metres

• There are other human activities 200 metres downwind of location

• May adversely affect the environment.

• Hydrocarbon gas cumulative volume to atmosphere exceeds 2.0 103 m3

total in a 24 hour period

• The actual flowing duration is more than 24 hours.

• Flowing or startup after dark is permitted only where absolutely necessary. Adequate lighting must be available (refer to IRP 23 Lease Lighting Standards, under development at time of publication).

NOTE: Refer to Alberta ERCB Directive 60 Upstream Petroleum Industry Flaring, Incinerating, and Venting and ERCB Directive 64 Section 14 for off site odour emissions.

4.3.1.1 Open Top Tank Design

IRP The open top tank must be designed with an inlet diffuser and a device to prevent splashing and misting of the fluid.

IRP There should also be a device for indicating the fluid level in the tank that can be read from over 50 metres away.



http://www.eub.ca/portal/server.pt/gateway/PTARGS_0_0_201_0_0_35/http%3B/extContent/publishedcontent/publish/eub_home/industry_zone/rules__regulations__requirements/directives/directive064.aspx�


58 June 2012

4.3.1.2 Safety Equipment

IRP The following additional safety equipment must be on location prior to flow:

• LEL metre with bump gas

• Spill containment kit

• A highly visible device to prevent flow of traffic onto location advising of Gas Vapours are Venting To Atmosphere Wind direction indicators ( Wellhead, Open Top Tank, Lease Entrance, and Safety Areas)

4.3.1.3 Tank Placement

IRP Placement of the open top tank must conform to the following:

• 50 metres from the lease site primary access point

• 50 metres from the wellhead (shallow wells, coalbed methane (CBM) 35 metres from wellhead)

• 25 metres from any other equipment in use

• 50 metres from safety meeting and muster areas

• 50 metres from any potential ignition source

• 60 metres from any road or right of way not owned by primary operator

• Prevent any possible spill from the tank from migrating off location

• When possible, on down wind side of location

4.3.1.4 Well Control to Open Top Tanks

IRP Well control must conform to the following:

• A choke with a bypass must be installed on the wellhead to initiate, control and shut in flow to the open top tank at a safe distance of 35 metres.

• There should be a pressure gauge, temperature reading device, and a methanol injection point installed upstream and a pressure gauge installed downstream of the choke.

• The line to the tank must be hard piped and no hoses shall be used.

• The line must have restraining devices to prevent movement of the line in case of failure.


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• No personnel shall enter the hazard zone around the tank that is to be 25 metres while flowing to the tank.

• After the flow to the tank has been shut down, an appropriate wait time must be allowed to let any gas or vapours dissipate before the area is swept with an LEL metre

• When abrasives are present the additional hazard of flow line washing must be considered

4.3.2 PUMPING OR CIRCULATING A WELL TO AN OPEN TANK SYSTEM NOTE: See Section 4.2.9 for IRPs on Monitoring and Supervision of Open Tank

Systems.

IRP Circulating or pumping to open tank systems after dark is not recommended. However, if required, adequate lighting must be available (refer to Lease Lighting Guideline).

IRP In operations where well site personnel or nearby residents have the potential to be exposed to sour gas or fluids (AB greater than 10 ppm, BC greater than 10 ppb (parts per billion), or otherwise specified by jurisdiction), the fluids must be contained in a closed system.

IRP In operations where gas vapours are expected from produced fluid, the hazards to on-site workers, equipment, and the public must be assessed and deemed safe before proceeding. Hold and document a hazard assessment/JSA meeting on the site with all personnel prior to beginning operations. The meeting should include discussion of procedures, sources of ignition, personal protective equipment, and identification of hazardous atmospheres. The report must be posted on the site.

NOTE: The Canadian Association of Oilwell Drilling Contractors (CAODC) has a standard hazard assessment form for use in daily operations.

IRP All open tanks shall be positioned a minimum of 35 meters from the wellhead, 25 metres from any flame arrested equipment and 50 metres from any open flame sources.

IRP A hazard zone of 25 metres in all directions from the open tank must be established and relayed to all persons on the site, when circulating or pumping to an open tank system.

IRP No worker(s) shall enter the hazard zone while, circulating or pumping to an open tank system, the only exception being the pump operator or person monitoring the tank who must be in the zone to operate the pump if fluid transfer or circulation is required. Precautions must be



60 June 2012

taken to ensure the safety of the personnel working within the hazardous zone, such as wind direction flags and H2S/LEL monitoring.

NOTE: The use of an external gauge on the tank will aid in monitoring tank levels from outside the, hazard zone

IRP Personnel responsible for monitoring the atmosphere for hazardous gases must be trained in the selection, use, and care of detection devices

IRP All workers involved with circulating or pumping operations to open tank systems shall wear the appropriate personal protective equipment (PPE)

IRP All sources of ignition must be eliminated and locked out where possible.

IRP Smoking is only allowed in designated areas.

IRP The operation shall be shutdown before fluids are splashed or flowed over the sides of the open tank system.

IRP All flows must be controlled using a device other than the wellhead wing valve.

IRP The piping system must be designed to accommodate pressure, H2S, erosion, and any other products that may compromise the integrity of the piping system. The piping system must be properly secured to restrict movement of the line.

IRP Physical gauging of open tank systems will only be done after the area is proven safe by the gas detection device.

IRP Any loading/unloading of fluids from open tank systems shall be done with the well shut in and there is no flow to the open-top tank and can only be done after the area is proven safe by the gas detection device.

4.3.3 WELLHEAD CONTROL IRP Well control equipment should be selected having regard for Section 4.2

Well Testing.

4.3.4 LOCATION OF THE RIG PUMP IRP Refer to ERCB Directive 037 Service Rig Inspection Manual.

4.3.5 WELL KILLING OPERATIONS IRP During well killing operations, where possible, the well should be flowed

into the facility pipeline, or production facility or pressurized vessel. If the facility pipeline is utilized, the backpressure imposed by the line-pac should be considered. If production facilities or pressurized vessels are



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used, the pump rate should not create a pressure exceeding the burst rating of the system.

NOTE: The use of pipelines, production facilities or pressurized vessels are alternatives to reduce explosion hazards. Flowlines, pressurized vessels or atmospheric tanks equipped with suitable vapour gathering - flaring/scrubbing systems are alternatives to eliminate any H2S releases to atmosphere (nuisance odours and public or personal safety).

In Alberta, ERCB inspection policies regarding the handling of sour effluent are included in ERCB Directive 037 Service Rig Inspection Manual.

NOTE: In British Columbia, the Oil and Gas Waste Regulation of the Waste Management Act, Section 3 states, “The owner or operator of a piece of equipment or a facility referred to in section 4 or 6 (1) must ensure that the one hour average ambient ground level concentration of hydrogen sulphide due to the discharge of air contaminants from that equipment or facility does not, at the perimeter property on which the equipment or facility is located, exceed 10 parts per billion by volume.” The Oil and Gas Waste Regulation also in section 4 (g) authorizes discharges to the air of contaminants by owners or operators of “equipment or facilities that vent to the air, for the purpose of maintenance of the equipment or facilities, (i) natural gas that contains less than 230 milligrams of total sulphur per cubic meter of natural gas, or (ii) natural gas that contains at least 230 milligrams of total sulphur per cubic meter of natural gas if the natural gas is combusted in a flare or equivalent.”

4.3.5.1 Coiled Tubing Unit (CTU) Operations Using Air

CAUTION: The use of air with coiled tubing operations is NOT RECOMMENDED. Extreme hazard exists with this operation.

Nitrogen gas is recommended.

Air is sometimes used in coiled tubing clean outs in shallow gas wells with low formation pressure, where no condensate or H2S is present in the formation fluid, and there is a low flow rate expectation from the well.

NOTE: Nitrogen gas is recommended for higher risk wells.

IRP A safe operating procedure should be followed. A written procedure including a hazard assessment/JSA should be available on-site with consideration given to the following:

• Wind direction

• Proper grounding of equipment

• Safe and effective control and handling of well effluent



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• Ensure that all the air has been displaced from the well, after the job, before shutting in or producing the well

IRP Coil Tubing Operations with air can only be performed to an open top tank.

IRP Air and well effluent must not be flowed into a pressure vessel. It can only be directed to a pressure vessel after all the air is out of the system and the well effluent has been checked for any oxygen content. This can be done with a gas monitor.

NOTE: Refer to IRP Section 4.3.1 Flowing to Open Top Tank

NOTE: Refer to IRP 18 Fire and Explosion Hazard Management

4.3.5.2 Operations at Night

IRP Where possible, flowback, swabbing, and coiled tubing operations should be conducted during daylight hours. Adequate lighting must be provided if it is necessary to continue operations into the night.

IRP Operations that will involve the bleeding of gas to open systems under the cover of darkness must proceed only where absolutely necessary. This will include flowback, swabbing, and coiled tubing operations.

NOTE: Lease Lighting Guideline should be referenced once complete.

NOTE: Refer to Section 4.2.8.1 Start Up at Night

4.3.5.3 Swabbing

IRP A check valve and an additional shut-off valve must be installed on the flow line. The shut-off valve must be closed while running in the hole if the hole is on vacuum. Consideration should be given to using a purge medium to follow swab cups while running in the hole.

NOTE: Check valves do not always seal 100%. The manual shut-off valve is a backup for the check valve.

The purpose of this procedure is to prevent drawing air or the flame from the flare into the production tank or into the tubing when running the swab cup back into the well. The introduction of air into the system can lead to a combustible mixture. Section 4.0.13.25 details other considerations for the prevention of air entrainment. Where gases produced are being flared, appropriate backflash control measures must be taken. Refer to ERCB Directive 060 Section 7.7 Backflash Control.





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4.3.5.4 Control of Potential Ignition Sources

IRP Shut down of potential ignition sources on location, for example the rig pump, boiler, heaters, and vaporizers, if not required for the operation, must be considered during the swabbing of hydrocarbons.

IRP Review and/or create a JSA/Hazard Assessment for the proper procedure to be performed.

IRP While swabbing to an open tank system where gas vapours are vented to atmosphere a highly visible device must be used to prevent flow of traffic onto location advising of Gas Vapours Are Venting to Atmosphere.

NOTE: Refer to Section 4.3.1 Flowing to Open Top Tank

NOTE: Refer to IRP 18 Fire and Explosion Hazard Management

4.3.6 SNUBBING OPERATIONS 4.3.6.1 Handling Bleed Offs From the Snubbing Unit

IRP The bleed off line from the snubbing unit to the separator must be equipped with a choke manifold in case of loss of control of the remote control valve on the snubbing stack.

IRP The line upstream of this choke manifold must be pressure tested to the anticipated maximum well pressure.

4.3.6.2 Flowing Casing While Snubbing

IRP The flowline must be an independent line from the casing to a choke or choke manifold and must be pressure tested for the maximum wellhead pressure. Refer to Section 4.2.7

IRP No other line can be connected to this line except for the line that was used for the pressure test. The pressure testing line should be disconnected during flowing operations and the connection point plugged.

IRP The flowline must have a temperature and pressure data acquisition points to mitigate the hazard of down-hole and surface hydrate conditions. This must be discussed during the pre-job safety meeting.

4.3.6.3 Handling Bleed off Snubbing Unit While Flowing Casing

IRP The bleed off line from the snubbing unit must not be connected to the same choke/manifold or separator as the flowline from the casing.

IRP The bleed off line can be piped to a second separator such as a low stage downstream of the primary separator provided its operational



64 June 2012

pressure is reduced to near atmospheric conditions and will not have the condition impeded by the primary separator that is handling the flow from the casing.

IRP If only one separator is on location or the secondary separator cannot meet the condition as laid out in this document, then the bleed off can be directed to an independent vent line on the flare stack and must have a choke manifold in the flowline and the upstream side of this choke manifold pressure tested to the maximum wellhead pressure. A Flapper style check valve that has been tested shall be installed in this line. There also must be an evaluation of the possibility of liquids being produced to this line and if the possibility exists, this procedure must not be done.

IRP The possibility of running the bleed off line to a rig tank can be considered if it meets the requirements as laid out in Section 4.3.1 Flowing to Open Top Tank.

4.3.6.4 Through Tubing Clean Outs With Snubbing Units

IRP This operation must only be conducted during daylight hours taking into account environmental weather conditions

IRP All involved services must attend a documented safety meeting to review procedures and communications protocol.


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Table 2: IRP 15.3.1.5 Reserve Circulation Sand Cleanout Equipment

• Flow back lines from the tubing and the snubbing unit bleed off line

must be rigged in, in such a way that if the upper snubbing BOP needs to be opened at any time, the snubbing stack can be bled off to zero before opening the upper snubbing BOP.

• Sources of pressure include back pressure from the test vessel, or line pressure from the flowing tubing.

• The lines must terminate according to oil company policy or applicable jurisdictional regulation.

Typical surface sand cleanout equipment consists of the following equipment, which must have a working pressure equal to or greater than the bottomhole pressure:

• A 15 m by 50 mm double- or triple-braided hose • An emergency shutdown (ESD) valve • Several slim hole valves • A tubing swivel • A Chiksan or heavy-walled elbow

All the surface equipment used for sand cleanouts must be dedicated solely for that purpose. This equipment must be an addition to normal rig inventory. The valves must be lubricated and pressure tested after each use. When leaks are detected, they must be sent for repair and recertification to OEM specifications. Hose ends must be integral crimped unit style

To help predict when repair or replacement will be needed, the equipment owner must maintain a logbook detailing the following:

• Each valve’s serial number • Date of use • Volume of sand flowed through the valve body • The working pressure it was exposed to

Hoses will typically bubble before failing and must be replaced, not repaired, when this is noticed. The swivel and Chiksan must be monitored for erosion wear after each use and repaired as needed.

All components of the sand cleanout system must be hydraulically pressure tested to at least 10% above the maximum anticipated operating pressure.

• For reverse sand cleanouts, a remote-activated fail-close shut-off must be installed on a valve upstream of all flow back equipment at the top of the tubing string. This device must be function tested before use

http://www.enform.ca/publications/IRP/snubbing_operations.aspx�


66 June 2012

4.3.7 RECOVERY AND HANDLING OF HIGH VAPOUR PRESSURE FLUIDS High Vapour Pressure Hydrocarbons: Hydrocarbon mixtures with a Reid Vapour Pressure (RVP) greater than 14 KPa.

Reid Vapour Pressure (RVP):

RVP: Reid Vapour Pressure; an indirect measure of the evaporation rate of volatile petroleum solvents using standard analytical method ASTM D323 or D5191. These test methods are used to determine vapour pressure of volatile petroleum liquids at 37.8oC (100oF) with an initial boiling point above 0oC (32oF). <<API RP>>

The well licensee is required to have all applicable approvals on site in each jurisdiction.

IRP A Hydrometer is not an acceptable device for measuring RVP. An RVP test must be performed by qualified personnel using equipment which meets ASTM D323 or D5191.

IRP Fluid produced from the wellbore must be continuously monitored for changes until the properties have stabilized.

Note. An increasing API gravity (Hydrometer) reading of the produced fluid is an indication of an increasing Reid Vapour Pressure. Fluids may require lab analysis.

Note. Not all HRVP Fluids are flammable. Some non-flammable fluids are liquid carbon dioxide, liquid oxygen and liquid nitrogen.

IRP Handling of liquids with high vapour pressures must be conducted in compliance with established safe work procedures. Safe work procedures must be reviewed prior to commencing work.

4.3.7.1 Recovering Flammable High Vapour Pressure Fracturing

Fluids

Note. High vapour pressure hydrocarbon fracturing fluids include: propane, butane, isobutane, or mixtures that are defined as liquefied petroleum gas (LPG).

IRP Material Safety Data Sheets (MSDS) for fracturing fluids must be on location and reviewed for each change in the composition of the LPG fracturing fluid.

IRP An ESD system must be connected to the wellhead that meets or exceeds the wellhead design criteria.


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IRP A remote LEL system shall be utilized on location to protect personnel and equipment. Low lying areas and confined spaces shall be taken into consideration for the proper placement of LEL detection devices.

IRP Minimum flare stack of 18.3 m (60 foot) with ignition system must be utilized, when recovering LPG fluids. Forested areas or where complex terrain exists, additional stack height may be required to minimize heat radiation.

IRP It is recommended that a flame suppression system be utilized at the flare stack during fracturing and flowback operations.

IRP Separators must be sized accordingly for all well effluent phases and planned operating conditions.

IRP All essential flame generating equipment must have a remotely operated flame suppression and/or fuel gas ESD. All essential and non-essential flame generating equipment must be adequately distanced and/or protected from process.

IRP Wellbore fluid must go through initial stage of heat (line heater).

IRP Minimum heat requirements must be maintained when vapourizing fluid for flaring and/or re-liquification process. Refer to Figure 3: Heat of Vaporization for heat required for proper vapourization.

A minimum 2 million BTU/hr line heater must be utilized for vapourization during propane flowbacks.

IRP Primary separators for initial frac flowback are recommended to be one of the given sizes:

• Greater than 1,379 kPa and a minimum volume of 18 m3




IRP Liquid from the primary vessel must be handled in one of the following ways:

• Produced through a secondary line heater to a secondary vessel with a minimum design pressure of 690 kPa and a minimum volume of 18 m3

and this separator must be connected to an appropriate flaring system.

• Produced to pipeline with appropriate pipeline protection systems in place (i.e., temperature and pressure shut-downs with check valve)


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IRP For proper vapourization of high vapour pressure fluids refer to

• Figure 2: Propane Saturation Curve

• Figure 3: Heat of Vapourization

• Figure 4: Liquid Vapour Chart

• Figure 5: Butane Saturation Curve

• Figure 6: Propane/Butane Mixtures Saturation Curves

• Figure 7: Other Saturation Curves

• Figure 8: Propane/Methane

IRP For storage or transportation of fluid off location,

Transfer to a pipeline.

Any fluids that have not had a reid vapour pressure test must be treated as high vapour pressure fluids.

Any fluids classified as HVP must be stored in a pressurized vessel and transported in an appropriate transport vessel as per TDG requirements.

To utilize a non pressurized tank truck a fluid sample must be taken from the pressurized vessel and tested to ASTM D323 or D5191. This is to ensure the fluids are stable and do not flash off creating a hazard during transport

IRP All PSV’s on flow back equipment must be tied back into the flare system.


0

500

1000

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4000

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-20 -10 0 10 20 30 40 50 60 70 80 90 100

Pres

sure

(kPa

) gau

ge

Temperature (°C)

Propane Saturation Curves

Liquid Phase

Saturation

Seperator Operating Range

Vapour (Gas) Region

Figure 2: Propane Saturation Curve


70 June 2012

0

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50000

75000

100000

125000

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175000

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-20 -10 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210

Hea

t of V

apou

rizat

ion

(KJ/

m3 )

Temperature (°C)

Heat of Vapourization Volume Basis

Propane Butane

Figure 3: Heat of Vapourization


0

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-45

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Pres

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Liquid Vapour Chart

Propane Vapourization Chart Pentane Butane Isobutane Propylene/Propene

* The Gas Region is down to the right of the labeled line. * The liquid region is to the upper left of the labeled line. Example: Butane under 125 kPa of pressure was stored at 50 degrees Celsious it would exist as a Gas. If the Butane temperature dropped to - 10 degrees Celsius it would exist as a liquid.

Figure 4: Liquid Vapour Chart


72 June 2012

Figure 5: Butane Saturation Curve


0

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-40 -30 -20 -10 0 10 20 30 40 50 60 70 80 90 100

Pres

sure

(kPa

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ge

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Propane / Butane Mixtures Saturation Curves

Liquid

Saturation

Vapour (Gas) Region

Figure 6: Propane/Butane Mixtures Saturation Curves


74 June 2012

0

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-40 -20 0 20 40 60 80 100 120 140 160 180 200

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Other Saturation Curves

Propane

Iso-Butane Butane

Pentane

Propene

Liquid Region

Vapour (Gas) Region

Figure 7: Other Saturation Curves


0

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Propane-Methane Mixture - 100% Vapour Lines

100% Methane

90% Methane

80% Methane

50% Methane/Propane

60% Propane

70% Propane

80% Propane

90% Propane

100% Propane

Figure 8: Propane/Methane


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Note. General Information

General Propane Properties:

Critical Pressure = 4247.66 kPa

Critical Temperature = 96.675 oC

Boiling Point at Atm. Pressure = -44 oC

Freezing Point = -188 oC

Specific Gravity of Liquid = 0.51 (water = 1.00)

Specific Gravity of Vapour = 1.53 (air = 1.00)

1.0 M3 liquid = 510 Kg

1.0 M3 liquid = 272 m3 vapour

1.0 kg = 0.534 m3 vapour

Above factors are based upon atmospheric pressure, 101.3 kPa, and at ambient temperature, 15o C, as applicable. Physical properties of LPG will vary little within the allowed HD5 composition.

General Butane Properties:

Critical Pressure = 3796.00 kPa

Critical Temperature = 151.975 oC

Boiling Point at Atm. Pressure = -0.5 oC

Freezing Point = -138 oC

Specific Gravity of Liquid = 0.58 (water = 1.00)

Specific Gravity of Vapour = 2.00 (air = 1.00)

1.0 M3 liquid = 580 Kg

1.0 M3 liquid = 223 m3 vapour

1.0 kg = 0.406 m3 vapour

Propane Composition:

Fracturing typically utilizes propane provided to a specification denoted as ‘HD5’. A summary of the HD5 propane composition is as follows (liquid vol%):

Propane C3H8

C3H6

90% minimum

Propylene 5% maximum

Butanes C4H10

2.5% maximum

and heavier

4.3.8 WELL SITE WORKERS COMPETENCY Refer to IRP 7 Standards for Well Site Supervision of Drilling Completions and Workovers




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4.4 LOADING, UNLOADING AND TRANSPORTATION OF FLUIDS

4.4.1 FLUID HAULING COMPANY PROCEDURES IRP Fluid Hauling companies must adhere to the following procedures and

practices.

• Stop at the entrance to all sites, put on the appropriate PPE, do a hazard assessment then report to the onsite supervisor if available, and/or assigned representative before entering work area.

• Ensure the consignor (shipper/owner) has provided appropriately completed shipping documents and that the transport company vehicle has the appropriate placarding as required by law

• Ensure that tank specification is acceptable for fluid characteristics defined in shipping documents. The design and construction of the tank must be capable of handling the sour fluid to be hauled, if applicable

• Ensure drivers are properly trained and educated on the Transportation of Dangerous Goods (TDG) and Workplace Hazardous Materials Information System (WHMIS) and fluid they are expected to haul

• Provide proper PPE as designated for the job to be performed

• All trucks should be equipped with a 30 minute SCBA

• Treat sweet fluids being hauled immediately after a sour load as a sour load with respect to worker safety

• List all necessary H2S equipment on a pre-trip check list

• Maintain all equipment valves, fittings, hoses, and hatch seals in good working order

• Ensure trucks with diesel engines have intake air shut-offs

• Maintain a contingency plan including procedures for trucking-related spills.

• All drivers should be trained in the selection, use and care of gas detection equipment

• Drivers should be competent to their company standards

• Prior to loading fluid ensure all equipment has a bonding device in place (grounding) and is used


78 June 2012

4.4.2 FLUID CHARACTERISTICS IRP The properties of any fluids to be loaded, unloaded or transported are to

be evaluated for the following hazards from information in the shipping documents:

• Toxicity

• Flammability

• Corrosive effects

• Environmental impact of escaped fluids

• Flash point and auto ignition

• Solid deposition

IRP Well Owners and transporters of fluid must make or have available Material Safety Data Sheets (MSDS) to workers. Refer to Section 4.0.13.22 for more information.

NOTE: Current MSDS and TDG information may provide valuable information to assess any toxicological or flammability hazards.

Other sources of produced fluid properties information includes well testing and reservoir fluid analysis, regulatory production reports or custody transfer (point of sale) measurements.

4.4.3 LOADING, UNLOADING AND TRANSPORTATION PRACTICES 4.4.3.1 Closed Systems

The use of a closed system (pressurized tanks or atmospheric tanks equipped with suitable vapour gathering – flaring / scrubbing systems) may be necessary to eliminate any H2S releases to atmosphere (nuisance odorous and public or personal safety). The duration of operation, proximity to, and notification of area residents, should be considered. Inspection policies regarding the handling of sour effluent in Alberta are included in ERCB Directive 037, Service Rig Inspection Manual.

Closed systems can also be utilized to enhance the safe handling of high vapour pressure hydrocarbons on the well site.

4.4.3.2 Tank Truck Loading and Unloading – Temporary Production

Testing Operations – Sweet and Sour Fluids

IRP Atmospheric tank trucks should only be used to haul sweet and sour fluids where the fluid is non-gaseous and there is minimal possibility of vapour breakout due to agitation or ambient temperature increases. An




June 2012 79

H2S scrubber must be used while loading, unloading and transporting sour fluids where an atmospheric tank truck is used to haul sour fluids.

IRP Operators of trucks equipped with on-board scrubbers must ensure that their units are maintained as per manufacturer recommendations. Refer to Section 4.0.13.17.

IRP Where there is the possibility of vapour breakout and pressure build up on the tank truck due to agitation or increased ambient temperature, the sour fluid must be transported in a certified tank truck.

4.4.3.3 Using Atmospheric or Pressure Certified Tank Trucks

IRP A well must not be flowed directly to a tank truck.

IRP To haul sour gaseous fluids the pressurized tank truck must arrive at the well site with a purge in the tank or be equipped to be purged at the well site.

IRP All vents must be closed and all fluid transfer lines capped while transporting the fluid

IRP Tank trucks may be vented to a flare stack only when:

• Proper procedures are in place and documented (pre-job hazard assessment/JSA)

• The tank has been purged and been tested with an LEL meter to determine the oxygen content in the tank

• The tank truck is able to maintain the purge in a sealed tank

• There is a positive flow of gas to the flare stack to produce a venturi on the vent line from the tank truck

• There is a back flash control mechanism in the vent line to the stack

• The system, including the tank truck and the tanks being emptied will not allow air into the system

IRP The facility where the fluids will be off-loaded should be equipped with a purge gas make-up system so as to purge the tank while fluid is being pumped off, allowing the tank truck to have a purge on board when returning to the well site.

IRP When loading and unloading fluids from pressurized flowback or atmospheric storage tanks, precautions must be taken in the placement of the truck relative to the tank(s) location on the well site.

IRP When loading and unloading fluids from a pressurized flowback or storage tank that a live well is flowing to, the following precautions must be taken:


80 June 2012

• The tank truck to be loaded or unloaded must be parked 25 meters from the pressurized flowback or storage tank

• A fluid head must be maintained in the pressurized flowback or storage tank at all times – gas must not be allowed to escape to the tank truck being loaded or unloaded

• The pressure of the pressurized flowback or storage tank system must be reduced to the minimum pressure required to transfer the fluid to the tank truck

• The pressure capabilities of the piping and hose system to the tank truck must meet the operating pressure of the shipping vessel

• Where a certified pressurized tank truck is used, the pressure capabilities of the tank on the truck must not be exceeded.

NOTE: Where possible, shut-off the truck while loading. The pressure on the flowback or storage tank will transfer the fluid to the tank truck. The use of a pump will also agitate fluids resulting in additional gas vapour from the fluid.

IRP When loading fluids produced from a sour well where testing operations are in progress the following procedures must be adhered to:

1) Where an atmospheric tank truck is used, connect the trucks atmospheric tank vent line to an adequately sized H2S scrubber. The scrubber may be truck mounted or a stand alone skid mounted unit.

2) Where a truck equipped with a pressurized tank is used, ensure the tank specification including pressure rating is sufficient for the nature of the fluids being loaded. See Venting Tanks to Flare Stacks below.

IRP The tank to be filled or unloaded should be separated (blocked) from any other tanks being used while the tank truck is loading or unloading. A gas blanket (positive pressure) must be maintained on closed system production tanks.

IRP Tank trucks must be a minimum of 7 metres from the atmospheric tank to be filled or unloaded.

IRP Tank trucks must be electrically bonded to the tank to be filled or unloaded prior to and during fluid transfers. The wheels must be chocked while transferring the liquids and must be equipped with a minimum of 25 metres of bonding cable.


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4.4.3.4 Permanent Production Facilities – Sweet or Sour Fluids

IRP A well must not be flowed directly into a tank truck.

IRP When loading sour fluids, tank truck vapours may be directed into a flare system as long as the trucks tank contains no oxygen, otherwise tank truck vapours should be scrubbed through an H2S scrubber and vented to atmosphere. Eliminating oxygen can be achieved by the following:

• An adequate positive pressure is maintained on the production tanks at a closed system multi-well facility where the fluid is to be unloaded

• Ensure the maximum allowable working pressure (MAWP) of the truck tank is not less than the MAWP of the production facility components being connected to properly sized vent lines should be provided at the multi-well facility where the fluid is to be unloaded; this will allow the void left in the tank truck after unloading to be replaced with adequate gas vapours from the positive pressure production tanks

• Thief hatches on trucks must be in good working condition.

IRP A gas blanket (positive pressure) must be maintained on closed system production tanks.

IRP Tank trucks must be a minimum of 7 metres from the tank to be filled or unloaded (25 metres from pressurized vessel).

IRP Tank trucks must be electrically bonded to the tank to be filled or unloaded prior to and during fluid transfers. The wheels must be chocked while transferring the liquids and must be equipped with a minimum of 25 metres of bonding cable.

4.4.3.5 Transportation – Sour Fluids

IRP Transportation of Dangerous Goods (TDG) legislation must be consulted for selecting equipment to transport sour fluids.

NOTE: Refer to the definitions in this IRP for information relative to TDG legislation and tank construction.

IRP Trucks transporting sour fluid must be equipped with a functional H2S scrubber to adequately control odour emissions or be a sealed tank.

IRP The tank vent must be sealed during storage and during transport when the truck is empty.


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4.4.4 FLUID HAULING COMPANY WORKER QUALIFICATIONS IRP Workers transporting sour fluids shall have valid H2S Alive®, WHMIS,

and TDG certificates.

IRP Workers operating fluid hauling trucks must have a valid operator’s license and a permit for the province/territory of operation.

IRP Workers must be trained in proper procedures and practices for operating vehicles while transporting fluids.

IRP Workers must be properly trained in loading and unloading procedures and practices.

IRP Workers must be properly trained in the use of safety equipment used in the course of the operation, including breathing equipment, gas detection, and explosive monitoring devices.

4.4.5 HYDROCARBON TRANSPORTATION: CLASS & PACKING GROUP (BOILING POINT, FLASH POINT & VAPOUR PRESSURE)

TDG Class 3, Flammable Liquids, Packing Group I: Hydrocarbon mixtures with an initial boiling point of 37.8 o C (100o F) or less at an absolute pressure of 101.325 kPa (14.7 psi) are a Class 3, Packing Group I, and flammable liquid for the purposes of transportation.

TDG Class 2, Gasses Hydrocarbon mixtures with a Reid Vapour Pressure of 275 kPa (40 psi) or greater at 37.8o C (100o F) are gasses for the purposes of transportation.

NOTE: Reid Vapour Pressure is determined in a laboratory test. API gravity can be readily measured in the field. C1-C7 content can also be indicative of flammability. Flammability increases with increasing C1-C7 content. Fluid analyses, if available, should be reviewed. Fluid and ambient temperatures should also be considered.

References/Links

Transport Canada TDG Regs, Part 3

Transport Canada TDG Regs, Schedule VI, Part I (Class 3, Flammable Liquids, Packing Group Test Methods)

Transport Canada TDG Regs, Schedule VI, Part III (Class 2, Gases, Reid Vapour Pressure, Test Methods)

CSA B621, Selection & Use for TDG

Transport Canada TDG Regs, 7.33.1 (GrandFathering)

Alberta Safety Codes Act






June 2012 83

Boilers & Pressure Vessel Exemption Order

ASME Section VIII

ASME B31.3


84 June 2012

APPENDIX VIII

BIBLIOGRAPHY

American Petroleum Institute (API), Recommended Practices for Drill Stem Design and Operating Limits, Thirteenth Edition, April 1, 1989, RP7G, Dallas, Texas

API, Recommended Practices for Occupational Safety and Health for Oil and Gas Well Drilling and Servicing Operations First Edition, January, 1981, RP54, Dallas, Texas.

API, Specification for Wellhead and Christmas Tree Equipment, Spec. 6A Edition, Dallas, Texas

American Society Of Mechanical Engineers (ASME), Code for Pressure Piping, B31, Chemical and Petroleum Refinery Piping, ASME B31.3, 1990 Edition, 345 East 47th Street, New York, N.Y. 10017.

ASME, B16.5 Pipe Flanges and Flanged Fittings, 1988 Edition, 345 East 47th Street, New York, N.Y. 10017.

ASME, Boiler & Pressure Vessel Code, Section VIII, Div I, 345 East 47th Street, New York, N.Y. 10017.

American Society of Testing And Materials (ASTM), Standard Test Method for Vapour Pressure of Petroleum Products (Reid Method), Philadelphia, PA.

ASTM, D56-79: Standard Test Method for Flash Point by Tag Closed Tester, Philadelphia, PA.

ASTM, D93-80: Standard Test Method for Flash Point by Penski-Martens Closed Tester, Philadelphia, P.A.

ASTM, D3278-82: Standard Test Method for Flash Point of Liquids by Setaflash Closed Tester, Philadelphia, P.A.

Canadian Association of Petroleum Producers (CAPP) Publication #1994-0002 Guideline for Prevention and Safe Handling of Hydrates (1994).

CAPP Publication #1999-0002 Occupational Health and Safety of Light Hydrocarbons.

CAPP Publication #1999-0005 Consumer Guideline for the Selection of Fire Resistant Workwear for Protection Against Hydrocarbon Flash Fires.

CAPP Publication #1999-0014 Recommended Practices for Flaring of Associated and Solution Gas at Oil Production Facilities.


June 2012 85

CAPP Publication #1999-0015 CAPP Safety Guideline for Ground Disturbance in the Vicinity of Underground Facilities.

Canadian Petroleum Association (CPA), 1987 Tank Vapour Flaring Committee Report Recommendations Surrounding Tank Vapour Flaring During Sour Well Testing, Calgary, Alberta.

CPA, DRILL STEM TESTING SAFETY GUIDELINES 1986, Calgary, Alberta.

Canadian Standards Association (CSA), Industrial Protective Headwear, Z94.1, Rexdale, Ontario.

CSA, Hearing Protectors, Z94.2, Rexdale, Ontario.

CSA, Industrial Eye & Face Protectors, Z-94.3, Rexdale, Ontario.

CSA, Protective Footwear, Z195, Rexdale, Ontario.

CSA, B620-1987: Highway Tanks and Portable Tanks for the Transportation of Dangerous Goods, Rexdale, Ontario.

CSA, B621-1987: Selection and Use of Highway Tanks, Portable Tanks, Cargo Compartments and Containers for the Transportation of Dangerous Goods, Classes 3, 4, 5, 6, and 8 in Bulk by Road, Rexdale, Ontario.

CSA, B622-1987: Selection and Use of Highway Tanks, Multi-unit Tank Cars and Portable Tanks for the Transportation of Dangerous Goods, Class 2, by Road, Rexdale, Ontario.

CSA, B620-98: Highway Tanks and Portable Tanks for the Transportation of Dangerous Goods, Rexdale, Ontario..

CSA, B621-98: Selection and Use of Highway Tanks, Portable Tanks, Cargo Compartments and Containers for the Transportation of Dangerous Goods, Classes 3, 4, 5, 6.1, 8 and 9, Rexdale, Ontario..

CSA, B622-98: Selection and Use of Highway Tanks, Multi-unit Tank Cars and Portable Tanks for the Transportation of Dangerous Goods, Class 2, Rexdale, Ontario.

IRP 1 Review- Subcommittee, “IRP Volume 1 –Critical Sour Drilling” (Volume 1 - 2004), 2004, DACC, Calgary, Alberta.

Well Services Review Committee, “IRP Volume 2 - Completing and Servicing Critical Sour Wells”, (Volume 2 – 2006), 2007, DACC, Calgary, Alberta.

Alberta Heavy Oil and Oil Sands Practices Steering Committee, “IRP Volume 3 -Heavy Oil and Sands Operations” (Volume 3 - 2002), 2002, Drilling and Completions Committee, Calgary, Alberta.

Minimum Wellhead Requirements Subcommittee of DACC, “IRP Volume 5 – Minimum Wellhead Requirements”, (Volume 5), 2002, DACC, Calgary, Alberta.


86 June 2012

Critical Sour Underbalanced Drilling Committee, “IRP Volume 6 – Critical Sour Underbalanced”, (Volume 6 - 2004), 2004, DACC, Calgary, Alberta.

DACC Sub-Committee Members, “IRP Volume 7 – Standards for Wellsite Supervision of Drilling, Completions and Workovers”, (Volume 7 - 2002), 2002, DACC, Calgary, Alberta.

2005 IRP Review Committee, “IRP Volume 15 – Snubbing Operations”, (Volume 15- 2007), 2007, DACC, Calgary, Alberta.

Canadian Petroleum Safety Council, “IRP Volume 16 – Basic Safety Awareness Training”, (Volume 13- 2003), 2003, Enform, Calgary, Alberta.

IRP 18 Development Committee, “IRP Volume 18 – Fire and Explosion Hazard Management”, (Volume 18 – 2006), 2007, DACC, Calgary, Alberta.

IRP 20 Development Committee, “IRP Volume 20 – Wellsite Design Spacing Recommendations”, (Volume 20 - 2008), 2008, DACC, Calgary, Alberta.

IRP 23 Development Committee, “IRP Volume 23 – Lease Lighting Standards”, (Volume unknown), TBD, DACC, Calgary, Alberta.

Energy Resources Conservation Board (ERCB) AEUB, Guide G-37 Service Rig Inspection Manual, 1988, ERCB, Calgary, Alberta.

ERCB, Directive 037 Informational Letter IL 91-2 Sour Gas Flaring Requirements and Change to Regulations.

Government of Alberta, Alberta Occupational Health and Safety (AOH&S), Alberta Occupational Health and Safety Act and Regulations, Edmonton, Alberta.

AOH&S, Well Testing – Minimum Guidelines for Enhanced Field Operations, June 1990, Edmonton, Alberta.

AOH&S, Safety Codes Act.

AOH&S, Boiler & Pressure Vessel Exemption Order.

AOH&S, Transportation of Dangerous Goods Control Act & Regulation.

Government of Canada, Transportation of Dangerous Good Act and Regulations

Government of Canada, WHMIS

Government of Canada, National Safety Code

National Association of Corrosion Engineers (NACE), MR0175 Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, Houston, Texas.

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