WELL TESTING AND FLUID HANDLING
AN INDUSTRY RECOMMENDED PRACTICE (IRP)
FOR THE CANADIAN OIL AND GAS INDUSTRY
VOLUME 4 – 2009
SANCTIONED
Edition
3.1
Sanction
Date
October
2009
COPYRIGHT/RIGHT TO REPRODUCE
Copyright for this Industry Recommended Practice is held by Enform, 2009. 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
Enform Canada
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Calgary, AB T2E 8N4
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Fax: 403.516.8166
Website: www.enform.ca
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Well Testing and Fluid Handling
IRP4
TABLE OF CONTENTS
Table of Contents ..................................................................... i
List of Tables .......................................................................... iv
List of Figures.......................................................................... v
4.0
Scope and Contents ....................................................... vi
4.0.1
4.0.2
4.0.3
4.0.4
4.0.5
4.0.6
4.0.7
4.0.8
4.0.9
4.0.10
4.0.11
4.0.12
4.0.13
Purpose ....................................................................................... vi
Audience ..................................................................................... vi
Scope and Limitations ................................................................... vi
Revision Process ........................................................................... vi
Revision History .......................................................................... vii
Sanction .................................................................................... viii
Acknowledgement ....................................................................... viii
Copyright Permissions .................................................................... x
Scope ........................................................................................... x
Introduction .................................................................................. x
Symbols and Abbreviations ............................................................ xi
Abbreviations and Definitions ........................................................ xii
Common Terms of Reference and IRP’s For All Operations In This Volume
xix
Appendix I .............................................................................. lii
Atmospheric Fluid Scrubber Selection Guidelines ........................................ lii
Appendix II ........................................................................... liii
Pressure Rating Formula for Seamless Pipe ............................................... liii
4.1
Drill Stem Testing ........................................................... 1
4.1.1
4.1.2
4.1.3
4.1.4
4.1.5
Scope ...........................................................................................1
Planning a Drill Stem Test ...............................................................1
On-Site Pre-Test Guidelines ............................................................2
Drill Stem Testing Guidelines...........................................................3
Sour Drill Stem Test Guidelines .......................................................6
Appendix III............................................................................ 9
Recommended Drill Stem Testing Services Inspection Checklist .....................9
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4.2
Well Testing and Fluid Handling
Well Testing .................................................................. 13
4.2.1
4.2.2
4.2.3
4.2.4
4.2.5
4.2.6
4.2.7
4.2.8
4.2.9
Wellhead Control ......................................................................... 13
Well Testing Equipment Capacities and Pressure Ratings .................. 16
H2S Service Equipment Requirements ............................................ 21
Well Testing Equipment Material Conformance ................................ 23
Equipment Inspections ................................................................. 24
Well Testing Equipment Spacing .................................................... 25
Pre – Test Equipment Check and Pressure Test................................ 28
Operational Safety ....................................................................... 30
Well Testing Workers ................................................................... 33
Appendix IV .......................................................................... 39
Lease Layout Schematics ........................................................................ 39
Sweet Wells .......................................................................................... 40
Frac Flowback with Pressure Tank Minimum Spacing Requirements .............. 40
Cold Separators Minimum Spacing Requirements ....................................... 41
Heated Test Unit Minimum Spacing Requirements...................................... 42
Sour Wells ............................................................................................ 43
Frac Flowback with Pressure Tank Minimum Spacing Requirements .............. 43
Heated Test Unit, Pressure Tank and Closed Pressure Storage Tanks Minimum
Spacing Requirements ..................................................................... 44
Heated Test Unit and Pressure Tank Minimum Spacing Requirements ........... 46
Appendix V ............................................................................ 47
Production Testing Services Inspection Checklist ....................................... 47
Appendix VI .......................................................................... 53
FLARESTACK MAXIMUM AND MINIMUM FLARE RATES ...................................... 53
Gas Exit Velocity of 50.8 mm (2”) Pipe ..................................................... 54
Gas Exit Velocity of 76.2 mm (3”) Pipe ..................................................... 55
Gas Exit Velocity of 101.6 mm (4”) Pipe ................................................... 56
Gas Exit Velocity of 152.4 mm (6”) Pipe ................................................... 57
Gas Exit Velocity from 203.2 mm (8”) Pipe ............................................... 58
Gas Exit Velocity from 254 mm (10”) Pipe ................................................ 59
Appendix VII ......................................................................... 60
Hydrate Charts ...................................................................................... 60
4.3
Other Flowbacks ........................................................... 63
4.3.1
4.3.2
4.3.3
4.3.4
4.3.5
4.3.6
4.3.7
4.3.8
ii
Flowing to Open Top Tank............................................................. 63
Pumping or Circulating a Well to an Open Tank System .................... 65
Wellhead Control ......................................................................... 67
Location of The Rig Pump ............................................................. 67
Well Killing Operations ................................................................. 67
Snubbing Operations .................................................................... 70
High Reid Vapour Fluid Recovery and Handling ................................ 73
Well Site Workers Competency ...................................................... 78
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4.4
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Loading, Unloading and Transportation of Fluids .......... 79
4.4.1 Fluid Hauling Company Procedures ................................................ 79
4.4.2 Fluid Characteristics ..................................................................... 80
4.4.3 Loading, Unloading and Transportation Practices ............................. 80
4.4.4 Fluid Hauling Company Worker Qualifications .................................. 84
4.4.5 Hydrocarbon Transportation: Class & Packing Group (Boiling Point, Flash
Point & Vapour Pressure) .................................................................. 85
Appendix VIII ....................................................................... 86
BIBLIOGRAPHY ....................................................................................... 86
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LIST OF TABLES
Well Testing Review Committee Members .................................................. ix
Table 1: Flammable Limits .................................................................. xxviii
Table 2: Pressure Rating of Seamless Pipe ................................................. lv
Table 2: IRP 15.3.1.5 Reserve Circulation Sand Cleanout Equipment ............ 72
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LIST OF FIGURES
Figure
Figure
Figure
Figure
October 2009
1:
2:
3:
4:
Code for Electrical Installations at Oil and Gas Facilities ................ 28
Propane Saturation Curve ......................................................... 75
Propane - Heat of Vaporization Volume Basis ............................... 76
Liquid Vapour Chart.................................................................. 77
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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
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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,
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.
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4.0.6
Well Testing and Fluid Handling
SANCTION
The following organizations have sanctioned this document:
• British Columbia Workers Compensation Board (WorkSafeBC)
• Canadian Association of Oilwell Drilling Contractors
• Canadian Association of Petroleum Producers
• Employment, Immigration and Industry, Alberta
• Energy Resources Conservation Board, Alberta
• International Intervention and Coil Tubing Association (Canada)
• National Energy Board
• Oil and Gas Commission, British Columbia
• Petroleum Services Association of Canada
• Saskatchewan Energy Resources
• Saskatchewan Labour
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.
Acknowledgments of the following individuals is in recognition of their time and effort in
any and all of the meeting and work sessions, and acknowledgement of the corporate
entities that allowed these individuals to take time away from their busy desks to help
complete this project.
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Well Testing Review Committee Members
Name
Company
Organization
Represented
Craig Marshall, Chair
Canadian Sub-Surface Energy Services Inc
PSAC
Nicole Axelson
Petroleum Services Association of Canada
PSAC
Frank A Barlow
Conoco Phillips Canada
CAPP
Glenn Berry
Enseco
PSAC
Dustin Brodner
Petro-Canada
CAPP
Lonnie Campbell
Concord Well Servicing Ltd
CAODC
Bruce Cazes
BC Oil and Gas Commission
Lyle Gallant
Weatherford Canada Partnership
PSAC
Robert Knowles
Weatherford Canada Partnership
PSAC
Kevin Kostrub
Alberta Energy Utilities Board
Manuel Macias
Enform
Lyle Nelson
Grant Production Testing Services Ltd
PSAC
Greg Onushko
Grant Production Testing Services Ltd
PSAC
Don Pack
Precision Drilling Corporation
CAODC
Matthew Ritchie
Enseco
PSAC
Colby Ruff
Alberta Energy Utilities Board
Garth Sampson
Weatherford Canada Partnership
PSAC
David W Smith
Am-Gas Scrubbing Systems (1989) Ltd
PSAC
Jack W Thacker
Husky Energy Inc
CAPP
Emerson Vokes
Lonkar Well Testing Ltd
PSAC
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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 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
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.
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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)
IRP: Industry Recommended Practice
JSA: Job Safety Analysis
LEL: Lower Explosive Limit
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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.
(Waiting on IRP 23 Lease Lighting Standards adequate lighting exists when the
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site is illuminated sufficiently to ensure that the worker is able to perform routine
duties safely.)
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
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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.
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.
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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.
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.
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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
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
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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.
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.
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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
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References/Links
Section IRP 4.2 Well Testing
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
October 2009
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Well Testing and Fluid Handling
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
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.
xx
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)
October 2009
Well Testing and Fluid Handling
IRP
IRP4
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
• 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 prejob 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:
October 2009
•
The purpose of the operation
•
Relevant well data
•
Identify any potential hazards
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IRP
xxii
•
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.
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
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
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Well Testing and Fluid Handling
IRP4
understanding of the hazards related to the physical properties of
the fluid being handled, prior to conducting the operation
4.0.13.2
IRP
4.0.13.3
IRP
4.0.13.4
IRP
October 2009
•
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
Drilling Service Company Responsibilities
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.
Drill Stem Testing Company Responsibilities
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.
Pressure test certification, material inspections, and sour service
specifications shall be made available when requested.
Safety Service Company Responsibilities
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
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Well Testing and Fluid Handling
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
IRP
4.0.13.6
IRP
4.0.13.7
IRP
xxiv
Well Testing Company Responsibilities
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.
Fluid Hauling Company Responsibilities
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.
Well Designation for Worker Safety in H2S Environments
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
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
October 2009
Well Testing and Fluid Handling
IRP4
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
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.
October 2009
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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
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
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Well Testing and Fluid Handling
4.0.13.9
IRP4
Gas Detection Monitoring for Explosive and Flammable Limits
(Further information see IRP 18- 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.
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.
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Flammable limits for some common flammable gases and vapours are in listed
below.
Table 1: Flammable Limits
Explosive
Limits (% by
vol. In air)
LEL
Ammonia
UEL
Vapour
Density Air
= 1.0
Flash Point
Degrees
Celsius
Ignition
Temp.
Degrees
Celsius
15.0
28.0
Gas
0.58
630
1.8
9.0
Gas
2.0
410
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
Butane
Carbon Monoxide
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.
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
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Well Testing and Fluid Handling
IRP4
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
such as drain channels, pipe and cableways, and storage pits, then these heavier
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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
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IRP4
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.
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.
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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.
• 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:
4.0.13.10
IRP
xxxii
Refer to CAPP Flammable Environments Guideline and IRP 18 - Fire and
Explosion Hazard Management
Monitoring for Explosive Mixtures
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
October 2009
Well Testing and Fluid Handling
IRP4
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.
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
October 2009
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Well Testing and Fluid Handling
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.
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.
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October 2009
Well Testing and Fluid Handling
IRP
IRP4
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
• 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:
October 2009
Sour gas more readily forms a hydrate than sweet gas
xxxv
IRP4
Well Testing and Fluid Handling
4.0.13.13
IRP
Worker Safety
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
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
IRP
Minimum Worker Wear Requirements
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
xxxvi
October 2009
Well Testing and Fluid Handling
IRP4
• 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:
4.0.13.15
IRP
•
Hardhats: CSA Z94.1
•
Footwear: CSA Z195 Grade 1
•
Eyewear, Goggles: CSA Z94.3
•
Hearing Protection: CSA Z94.2
Minimum General Safety Standards
The following minimum standards must be followed:
• No smoking within 50 m of potentially flammable vapours
• 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
October 2009
xxxvii
IRP4
Well Testing and Fluid Handling
• 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
• 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
to IRP 23 Lease Lighting Standards currently under construction)
• 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
xxxviii
October 2009
Well Testing and Fluid Handling
IRP4
• 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
IRP
Pre-Job Safety Meeting
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
• Responsibilities and work programs
• Safety procedures, general, and specific to the job
• Safety equipment location and operation
• Emergency response plan
• Hazard Assessment
NOTE:
October 2009
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
xxxix
IRP4
Well Testing and Fluid Handling
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
• 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
xl
October 2009
Well Testing and Fluid Handling
IRP4
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
NOTE:
October 2009
Optimal combustion and plume dispersion modelling as outlined in ERCB
Directive 060 dictates velocities between 10.6 and 95.4 m/second
xli
IRP4
Well Testing and Fluid Handling
4.0.13.19
NOTE:
4.0.13.20
IRP
4.0.13.21
IRP
Venting Gas to Atmosphere
Venting of gas vapours while flowing, circulating, or pumping to open
tank systems is covered in Section 4.3 Other Flowbacks.
Flare Pits
Flare pits may only be used in an emergency.
H2S Scrubbers
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
xlii
October 2009
Well Testing and Fluid Handling
4.0.13.22
IRP4
Produced Fluids
4.0.13.22.1.
IRP
General Fluids
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.
IRP
Fluid Properties and Characteristics
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.
IRP
Oils
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:
October 2009
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.
xliii
IRP4
Well Testing and Fluid Handling
4.0.13.22.4.
IRP
Gas
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.
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.
xliv
Water
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.
October 2009
Well Testing and Fluid Handling
NOTE:
4.0.13.23.2.
IRP4
See Section 4.3 Other Flowbacks for flowing to open top tanks.
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
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.
IRP
4.0.13.23.4.
IRP
October 2009
Certified Pressurized Flowback Tanks
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.
Non – certified Pressurized Storage Tanks
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.
xlv
IRP4
Well Testing and Fluid Handling
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
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.
IRP
xlvi
Location of Rig Tanks
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.
October 2009
Well Testing and Fluid Handling
4.0.13.24.2.
IRP
Location of Atmospheric Tanks (64m3 style)
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.
IRP
Location of Certified Pressurized Flowback Tanks
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.
IRP
4.0.13.25
IRP4
Location of Non-certified Pressurized Storage Tanks
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
data must be available when requested by the well owner. Government
departments may also request this data.
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
October 2009
xlvii
IRP4
Well Testing and Fluid Handling
• 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.
4.0.13.25.2.
xlviii
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.
October 2009
Well Testing and Fluid Handling
4.0.13.25.3.
IRP
IRP4
Purge Mediums for Purging Surface Equipment
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.
IRP
Pre – Purging Procedures and Checks
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
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
October 2009
xlix
IRP4
Well Testing and Fluid Handling
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.
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.
IRP
4.0.13.25.10.
IRP
l
Purging Sequence
Ending the Purge
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.
Intermediate Purging
Vessels/tanks should be re-purged whenever air is accidentally or
operationally introduced during the test.
October 2009
Well Testing and Fluid Handling
4.0.13.26
IRP
IRP4
Opening a Well with Air in the Flow string
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 bypass 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:
October 2009
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)
li
IRP4
Well Testing and Fluid Handling
APPENDIX I
Atm o s p h e ric Flu id S c ru b b e r S e le c tio n Guid e lin e s
lii
October 2009
Well Testing and Fluid Handling
IRP4
APPENDIX II
P re s s u re Ra tin g Fo rm u la fo r S e a m le s s P ip e
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
October 2009
liii
IRP4
Well Testing and Fluid Handling
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:
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.
liv
October 2009
Table 2: Pressure Rating of Seamless Pipe
Welded Carbon
Steel
NPT Threaded Carbon Steel
Welded 4130 HRC 1822 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
Psi
Psi
Psi
Pipe
Size
Inches
Actual
O.D.
Inches
Pipe
Schedule
Nominal
Wall
Inches
Nominal
I.D.
Inches
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
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
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
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
28.36
8000
55.16
XXH
0.436
1.530
7373
50.83
5750
39.65
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
40 (STD)
0.216
3.068
---
0.254
2.992
2676
18.45
80 (XH)
0.300
2.900
3191
22.01
---
0.375
2.750
4054
27.95
160
0.438
2.624
4801
33.10
XXH
0.600
2.300
6818
47.01
5264
---
0.750
2.000
8824
60.84
7160
---
1.000
1.500
12500
86.19
10625
73.26
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*)
1
1 1/2
2
2 1/2
3
3 1/2
1.315
1.9
2.375
2.375
3.5
4
5641
Mpa
38.90
Mpa
4114
Mpa
(5000*)
(5000*)
(5000*)
(3000*)
10450
15400
72.05
14189
97.83
11319
78.04
2258
15.57
940
6.48
3200
22.06
1338
9.22
3800
26.20
1827
12.60
4500
31.03
2646
18.24
5750
39.65
3354
23.12
(3000*)
6800
46.89
36.30
(3000*)
9700
66.88
49.37
(3000*)
12400
85.50
(3000*)
17000
18700
106.18
117.22
128.94
Welded Carbon
Steel
NPT Threaded Carbon Steel
Welded 4130 HRC 1822 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
Psi
Psi
Psi
Pipe
Size
Inches
Actual
O.D.
Inches
Pipe
Schedule
Nominal
Wall
Inches
Nominal
I.D.
Inches
4
4.5
40 (STD)
0.237
4.026
1914
13.20
897
---
0.250
4.000
2023
13.95
1002
---
0.312
3.875
2550
17.59
80(XH)
0.337
3.826
2766
19.07
---
0.364
3.772
3001
20.69
120
0.438
3.624
3656
25.21
---
0.500
3.500
4217
29.08
160
0.531
3.458
4502
31.04
XXH
0.674
3.152
5856
40.38
4681
---
0.750
3.000
6604
45.53
5397
---
1.000
2.500
9211
63.51
7891
---
1.250
2.000
---
1.500
1.500
40 (STD)
0.247
4.506
1791
12.35
878
---
0.250
4.500
1813
12.50
900
80(XH)
0.355
4.290
2615
18.03
---
0.375
4.250
2770
19.10
---
0.500
4.000
3763
25.95
XXH
0.710
3.580
5519
38.05
---
0.750
3.500
5866
40.45
4805
---
1.000
3.000
8140
56.12
6992
---
1.250
2.500
10606
73.13
9360
---
1.500
2.000
13291
91.64
11933
82.28
(3000*)
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
0.250
6.125
0.280
6.065
1524
10.51
0.312
6.001
1704
11.75
0.375
5.875
2063
14.22
1364
0.432
5.761
2391
16.49
0.500
5.625
2789
19.23
0.562
5.501
3156
21.76
0.719
5.189
4111
28.34
0.864
4.897
5023
34.63
4243
1.000
4.625
5907
40.73
5102
1.125
4.375
1.250
4.125
4 1/2
5
6
5
5.563
6.625
Mpa
Mpa
Mpa
6.18
2700
18.62
6.91
2850
19.65
1509
10.40
3600
24.82
1716
11.83
3900
26.89
1941
13.39
4250
29.30
2570
17.72
5200
35.85
3109
21.43
(3000*)
6000
41.37
3382
23.32
(3000*)
6400
44.13
32.27
(3000*)
8300
57.23
37.21
(3000*)
9350
64.47
54.41
(3000*)
12900
88.95
16500
113.77
12069
83.22
10621
73.23
(3000*)
15217
104.92
13620
93.91
(3000*)
19950
137.56
6.05
2550
17.58
6.20
2550
17.58
1673
11.54
3700
25.51
1823
12.57
3900
26.89
2780
19.17
5350
36.89
4471
30.83
(3000*)
7800
53.78
33.13
(3000*)
8300
57.23
48.21
(3000*)
11500
79.29
64.54
(3000*)
14700
101.36
(3000*)
17900
11900
123.42
7197
49.62
6196
42.72
1357
9.35
676
4.66
1900
13.10
840
5.79
2150
14.82
1015
7.00
2400
16.55
9.40
2900
20.00
1684
11.61
3400
23.44
2070
14.27
3950
27.24
2428
16.74
4450
30.68
3356
23.14
(3000*)
5800
39.99
29.25
(3000*)
7100
48.95
35.18
(3000*)
8350
57.57
9600
66.19
6745
46.51
5916
40.79
(3000*)
7609
52.46
6754
46.57
(3000*)
10800
82.05
74.47
Well Testing and Fluid Handling
IRP
October 2009
IRP4
Also refer to entire Section 4.2.2.2 Pressure Rating on maximum
allowable pressure rating for line pipe
li
Well Testing and Fluid Handling
IRP4
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
4.1.2.2
IRP
4.1.2.3
IRP
October 2009
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.
Lithological and Reservoir Information
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.
Qualifications
Workers conducting drill stem testing operations shall have the
minimum qualifications required by legislation and the industry.
1
IRP4
Well Testing and Fluid Handling
4.1.3
ON-SITE PRE-TEST GUIDELINES
4.1.3.1
Pre-test Safety Meeting
IRP
4.1.3.2
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
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.
Pre-Test Inspection
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
2
October 2009
Well Testing and Fluid Handling
4.1.3.3
IRP
IRP4
Pre-test Training
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
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.
October 2009
3
IRP4
Well Testing and Fluid Handling
• 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
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.
4.1.4.3
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
IRP
4
DST Tool Retrieval during Darkness
Test Line
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
October 2009
Well Testing and Fluid Handling
IRP4
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:
4.1.4.6
IRP
4.1.4.7
IRP
4.1.4.8
IRP
4.1.4.9
IRP
October 2009
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.
Floor Manifold
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.
Swivel Joints and Flexible Pipe
All swivel joints and flexible pipe shall be secured with a safety cable.
The integrity of flexible piping should be ensured through pressure
testing.
Fire Prevention
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.
Pipe Tally
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.
5
IRP4
Well Testing and Fluid Handling
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
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.
6
October 2009
Well Testing and Fluid Handling
IRP4
• 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
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
IRP
October 2009
Corrosion Inhibition While Sour Drill Stem Testing
Inhibit water based drilling fluids by maintaining a pH above 10. Inhibit
oil based muds with the addition of commercially available scavengers.
7
IRP4
Well Testing and Fluid Handling
IRP
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
IRP
8
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.
Neutralizing H2S during Trip out Hole
When pulling drill stem test tools out of the hole, use a mixture of aquaammonia 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.
October 2009
Well Testing and Fluid Handling
IRP4
APPENDIX III
Re c o m m e n d e d Drill S te m Te s tin g S e rvic e s In s p e c tio n Ch e c klis 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:
Yr
Mo
Day
Hrs
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)
____
____
October 2009
9
IRP4
10
Well Testing and Fluid Handling
09
Safety footwear
____
____
10
Eye Protection
____
____
11
Ear Protection
____
____
12
First Aid supplies
____
____
13
Certificates
a) H2S
____
____
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
____
____
October 2009
Well Testing and Fluid Handling
27
IRP4
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
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
October 2009
11
Well Testing and Fluid Handling
IRP4
4.2 WELL TESTING
4.2.1
WELLHEAD CONTROL
4.2.1.1
General
IRP
4.2.1.2
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
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.
October 2009
13
IRP4
Well Testing and Fluid Handling
• 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.
4.2.1.3
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.
14
Wellhead Minimum Requirements
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
October 2009
Well Testing and Fluid Handling
4.2.1.3.3.
IRP
4.2.1.3.4.
IRP4
Flow Tee and Flow Cross
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.
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
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.
October 2009
15
IRP4
Well Testing and Fluid Handling
4.2.1.3.6.
IRP
Temporary Wellheads
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.
16
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.
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.
October 2009
Well Testing and Fluid Handling
NOTE:
IRP4
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.
IRP
4.2.2.1.3.
IRP
4.2.2.1.4.
IRP
October 2009
Separator Systems
Separator capacities should be at planned operating pressures and
should be sized for all well effluent phases.
Heat Requirements
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.
Liquid Storage
The upstream system and the liquid storage stage must be designed to
reduce, eliminate or control the escape of vapours to the environment.
17
IRP4
Well Testing and Fluid Handling
4.2.2.2
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.
18
Pressure Ratings
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.
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
October 2009
Well Testing and Fluid Handling
IRP4
available at the wellhead, special precautions must be taken a hazard
assessment must be completed.
IRP
4.2.2.2.3.
IRP
4.2.2.2.4.
IRP
All wells to be flowed having a surface pressure greater than 1379kPa
and a H2S content greater than 1% requires an ESD.
Flanges
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.
Other Connections
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:
4.2.2.2.5.
In British Columbia, documentation regarding working pressure must be
available on site.
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.
IRP
Certified flexible pressure piping can be used where well effluent internal
pressure could exceed 103.4 kPa (15 Psig) but not the maximum
October 2009
19
IRP4
Well Testing and Fluid Handling
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.
IRP
4.2.2.2.7.
IRP
Welding of Pipe and Fittings
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.
Pipe and Fitting Threading
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.
20
Pipe / Fitting Size
Working Pressure
To 21 mm (½")
68.9 MPa (10,000 psig)
October 2009
Well Testing and Fluid Handling
IRP4
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)
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.
IRP
4.2.3.1.3.
IRP
October 2009
Welding of Carbon and Low Alloy Steels
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.
ExceptionsProduction lines to non-certified storage tanks, flare lines and vent lines
may be exempted from complete conformance to NACE MR 01750175/ISO15156-1 LATEST EDITION if:
21
IRP4
Well Testing and Fluid Handling
• 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.
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
IRP
Internal Trims of Valves, Controllers, Ect.
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:
22
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.
October 2009
Well Testing and Fluid Handling
4.2.4
WELL TESTING EQUIPMENT MATERIAL CONFORMANCE
4.2.4.1
General
IRP4
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.
4.2.4.2
IRP
4.2.4.3
IRP
4.2.4.4
IRP
October 2009
Pressure Vessels
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.
Pipe, Forging, and Fittings
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.
Valves, Controllers Meters, Etc.
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.
23
IRP4
Well Testing and Fluid Handling
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.
NOTE:
Union Figure Number
or Name
Colour
RAL
Colour
Code
602
1502
Guiberson / 607
Red
Blue
White
3020
5002
9010
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.
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.
24
October 2009
Well Testing and Fluid Handling
4.2.5.2
IRP
IRP4
Inspection Guidelines
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
• 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
October 2009
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
25
IRP4
Well Testing and Fluid Handling
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
IRP
Equipment Spacing For Propane Tanks
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
• 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.
26
October 2009
Well Testing and Fluid Handling
IRP4
• 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:
4.2.6.2
Reference the appropriate provincial department of transport for
guidance when transporting oilfield skid mounted propane tanks with
product in the tanks.
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-byside.
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
4.2.6.4
IRP
October 2009
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).
Electrical and Electronic Area Classification
The following diagrams are from the Code for Electrical Installations at
Oil and Gas Facilities published by The Safety Code Council of Alberta.
27
IRP4
Well Testing and Fluid Handling
Figure 1: Code for Electrical Installations at Oil and Gas Facilities
NOTE:
4.2.7
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.
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
28
October 2009
Well Testing and Fluid Handling
IRP4
• 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:
4.2.7.1
A Production Testing Services Inspection Check List is included in
Appendix V. Applicable details of the checklist are recommended.
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
IRP
October 2009
Wellhead to Choke
It is the owners responsibility to specify the pressure test medium.
Hydraulic testing is recommended over the use of wellhead gas or
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.
29
IRP4
Well Testing and Fluid Handling
4.2.7.3
IRP
4.2.7.4
IRP
4.2.7.5
IRP
Pressure Testing on Critical Sour Wells
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).
Downstream of Choke
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.
Open Ended Piping and Production Tanks
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
30
October 2009
Well Testing and Fluid Handling
IRP4
representative after consultation with the well testing supervisor/
manager
• The crew is well rested
NOTE:
4.2.8.2
IRP
IRP 23 Lease Lighting Standards currently under development
General Start Up Procedure
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:
4.2.8.3
IRP
October 2009
A rate preceding the actual test is appropriate to cleanup the well and to
re-evaluate the programmed well performance.
Test Performance
The test should be performed according to the following generalized
guidelines:
31
IRP4
Well Testing and Fluid Handling
• Perform and record measurements according to the program and
provincial guidelines
• Continuously monitor safety systems and equipment
• 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
4.2.8.4
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.
Shut In and Post – Test Procedures
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
32
October 2009
Well Testing and Fluid Handling
IRP4
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
4.2.9.1
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
operations safely. The following identifies key situations and
recommends a minimum number of workers required to conduct the
operation safely and efficiently.
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
October 2009
33
IRP4
Well Testing and Fluid Handling
• 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
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
IRP
Two Qualified Well Testing Workers per Shift
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
34
October 2009
Well Testing and Fluid Handling
IRP4
• 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
• The H2S concentration does not exceed 5% (50 moles per kilomole)
4.2.9.4
IRP
Three Qualified Well Testing Workers per Shift
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
October 2009
35
IRP4
Well Testing and Fluid Handling
• 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.
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
36
October 2009
Well Testing and Fluid Handling
IRP4
• 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
• 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):
October 2009
37
IRP4
Well Testing and Fluid Handling
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:
38
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.
October 2009
Well Testing and Fluid Handling
IRP4
APPENDIX IV
Le a s e La yo u t S c h e m a tic s
October 2009
39
IRP4
Well Testing and Fluid Handling
S we e t We lls
Fra c Flowb a c k with P re s s u re Ta n k Min im um S p a c in g Re q u ire m e n ts
40
October 2009
Well Testing and Fluid Handling
IRP4
Co ld S e p a ra to rs Min im u m S p a c in g Re q u ire m e n ts
October 2009
41
IRP4
Well Testing and Fluid Handling
He a te d Te s t Un it Min im u m S p a c in g Re q u ire m e n ts
42
October 2009
Well Testing and Fluid Handling
IRP4
S o u r We lls
Fra c Flowb a c k with P re s s u re Ta n k Min im um S p a c in g Re q u ire m e n ts
October 2009
43
IRP4
Well Testing and Fluid Handling
He a te d Te s t Un it, P re s s u re Ta n k a n d Clo s e d P re s s u re S to ra g e Ta n ks Min im u m
S p a c in g Re q u ire m e nts
44
October 2009
Well Testing and Fluid Handling
IRP4
He a te d Te s t Un it Min im u m S p a c in g Re q uire m e n ts
October 2009
45
IRP4
Well Testing and Fluid Handling
He a te d Te s t Un it a n d P re s s u re Ta nk Min im u m S p a c in g Re q u ire m e n ts
46
October 2009
Well Testing and Fluid Handling
IRP4
APPENDIX V
P ro d u c tio n Te s tin g S e rvic e s In s p e c tio n Ch e c klis 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:
October 2009
47
IRP4
Well Testing and Fluid Handling
Mark a check if adequate or inadequate or if not applicable
(NOTE:
A
Signs
01
Any “INADEQUATE” must have an explanation and be corrected)
Adeq.
Inadeq
B
Personal Safety
con’
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
Adeq.
Inadeq
b) first aid
c) WHMIS
d) TDG
15
Fire retardant clothing
16
Facial Hair
48
October 2009
Well Testing and Fluid Handling
D
Flowline
32
Pipe schedule
IRP4
Adeq.
Inadeq
H
Other con’d
51
Flame arrestor
Adeq.
Inadeq
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
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
October 2009
m
49
IRP4
Well Testing and Fluid Handling
K
Tanks Con’d
71
Adeq.
Inadeq
L
Stack (Dia.
mm. X m. con’d
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
Adeq.
Inadeq
(1” apart)
78
Vertical line
99
Camps correct
posirion
79
Flames arrestor
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.
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
91
Flare catcher
Vaporizer to
Propane tanks
25m
50
in.
in.
mm. X
October 2009
Well Testing and Fluid Handling
N
Circulating Punp and
System
112
Check valve working
press.
IRP4
Adeq.
Inadeq
P
Separator Con’d
132
Instrument supply
system checked
133
BP valve stroked
and ser
Adeq.
Inadeq
MPA
113
Storm chokes working
press.
MPA
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 bypassed
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
October 2009
51
IRP4
Well Testing and Fluid Handling
Q
Lease Trailer light
plant Con’d
154
Adeq.
Inadeq
R
General
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
Adeq.
Inadeq
S. Comments / Explanations:
Owner Representative:
Signature
Contractor:
Signature
Representative
Service Company:
Signature
Representative
52
October 2009
Well Testing and Fluid Handling
IRP4
APPENDIX VI
F LARES TACK MAXIMUM AND MINIMUM F LARE R ATES
October 2009
53
IRP4
Well Testing and Fluid Handling
Ga s Exit Ve lo c ity o f 50.8 m m (2”) P ip e
Gas Exit Velocity of 50.8 mm (2") Pipe
450
400
350
Velocity m/sec
300
250
200
150
100
50
75
70
65
60
55
50
45
40
35
30
25
20
15
10
5
0
0
Gas Rate 103 M 3
54
Velocity m/sec
Speed of sound @ 0 oC
>1% H2S Gas Max Exit Velocity
>1% H2S Gas Min Exit Velocity
October 2009
Well Testing and Fluid Handling
IRP4
Ga s Exit Ve lo c ity o f 76.2 m m (3”) P ip e
Gas Exit Velocity of 76.2 mm (3") Pipe
450
400
350
Velocity m/sec
300
250
200
150
100
50
150
140
130
120
110
100
90
80
70
60
50
40
30
20
10
0
0
Gas Rate 103 M 3
Velocity m/sec
October 2009
Speed of sound @ 0 oC
>1% H2S Gas Max Exit Velocity
>1% H2S Gas Min Exit Velocity
55
IRP4
Well Testing and Fluid Handling
Ga s Exit Ve lo c ity o f 101.6 m m (4”) P ip e
Gas Exit Velocity of 101.6mm (4") Pipe
400
350
Gas Velocity m/sec
300
250
200
150
100
50
250
225
200
175
150
125
100
75
50
25
0
0
3
3
Gas Rate 10 M
Velocity m/sec
>1% H2S Gas Max Exit Velocity
56
Speed of Sound @ 0 oC
>1% H2S Gas Min Exit Velocity
October 2009
Well Testing and Fluid Handling
IRP4
Ga s Exit Ve lo c ity o f 152.4 m m (6”) P ipe
Gas Exit Velocity from 152.4mm (6") Pipe
450
400
Gas Velocity m/sec
350
300
250
200
150
100
50
600
500
400
300
200
100
0
0
Gas Rate 103 M3
Gas Velocity m/sec
>1% H2S Gas Max Exit Velocity
October 2009
Speed of sound @ 0 oC
>1% H2S Gas Min Exit Velocity
57
IRP4
Well Testing and Fluid Handling
Ga s Exit Ve lo c ity fro m 203.2 m m (8”) P ip e
Gas Velocity From 203.2mm (8") Pipe
450
400
350
Gas Velocity m/sec
300
250
200
150
100
50
1100
1000
900
800
700
600
500
400
300
200
100
0
0
3
Gas Rate 103 M
Gas Velocity m/sec
>1% H2S Gas Max Exit Velocity
58
Speed of sound @ 0 oC
>1% H2S Gas Min Exit Velocity
October 2009
Well Testing and Fluid Handling
IRP4
Ga s Exit Ve lo c ity fro m 254 m m (10”) P ip e
Gas Exit Velocity from 254mm (10") Pipe
400
350
300
Gas Velocity m/sec
250
200
150
100
50
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
Gas Rate 103 M3
October 2009
Gas Velocity m/sec
Speed of sound @ 0 oC
>1% H2S Gas Max Exit Velocity
>1% H2S Gas Min Exit Velocity
59
IRP4
Well Testing and Fluid Handling
APPENDIX VII
Hyd ra te Ch a rts
Natural Gas Hydrate Chart
100000
In hydrate zone
10000
Pressure
(Kpa)
1000
100
0.00
Out of hydrate zone
5.00
10.00
15.00
20.00
25.00
30.00
Temparture (0C)
Gas Gravity 0.9
Gas Gravity 0.8
60
Gas Gravity 0.6
Gas Gravity 1.0
Gas Gravity 0.7
October 2009
Well Testing and Fluid Handling
October 2009
IRP4
61
Well Testing and Fluid Handling
IRP4
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:
4.3.1.1
Refer to Alberta ERCB Directive 60 Upstream Petroleum Industry
Flaring, Incinerating, and Venting and ERCB Directive 64 Section 14 for
off site odour emissions.
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.
October 2009
63
IRP4
Well Testing and Fluid Handling
4.3.1.2
IRP
4.3.1.3
IRP
4.3.1.4
IRP
Safety Equipment
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)
Tank Placement
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
Well Control to Open Top Tanks
Well control must conform to the following:
•
64
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.
October 2009
Well Testing and Fluid Handling
4.3.2
IRP4
•
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.
•
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
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 IRP 23 Lease Lighting Standards, under development
at time of publication).
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.
October 2009
65
IRP4
66
Well Testing and Fluid Handling
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
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.
October 2009
Well Testing and Fluid Handling
IRP
4.3.3
IRP4
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.
WELLHEAD CONTROL
IRP
4.3.4
Well control equipment should be selected having regard for Section 4.2
Well Testing.
LOCATION OF THE RIG PUMP
IRP
4.3.5
Refer to ERCB Directive 037 Service Rig Inspection Manual.
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
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:
October 2009
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
67
IRP4
Well Testing and Fluid Handling
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
• Ensure that all the air has been displaced from the well, after the job,
before shutting in or producing the well
68
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
October 2009
Well Testing and Fluid Handling
4.3.5.2
IRP4
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:
IRP 23 Lease Lighting Standards is currently under development and
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.
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.
October 2009
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Well Testing and Fluid Handling
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
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
70
Flowing Casing While Snubbing
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
pressure is reduced to near atmospheric conditions and will not have the
October 2009
Well Testing and Fluid Handling
IRP4
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.
October 2009
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Well Testing and Fluid Handling
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.
•
72
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
October 2009
Well Testing and Fluid Handling
4.3.7
IRP4
HIGH REID VAPOUR FLUID RECOVERY AND HANDLING
High Vapour Pressure Hydrocarbons: Hydrocarbon mixtures with a Reid
Vapour Pressure (RVP) greater than 14 KPa.
IRP
For all field estimates with a Hydrometer an API gravity greater than 50
are considered to be High Reid Vapour Pressure hydrocarbons. Unless a
current MSDS of the fluid injected into the well documents it does not
have a High Reid Pressure value.
IRP
Fluid recovered after injected into the well must be monitored for
change in properties to determine if the Reid Vapour Pressure is
increasing.
Note.
Reid Vapor Pressure (RVP) is determined in a laboratory test. American
Petroleum Institute (API) gravity (Hydrometer reading) 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 must be reviewed. Fluid and ambient
temperatures should be considered.
Note.
An increasing API gravity (Hydrometer) reading of the produced fluid is
an acceptable indication of an increasing Reid Vapour Pressure.
Note.
Not all HRVP Fluid are flammable. Some non-flammable fluids are liquid
carbon dioxide, liquid oxygen and liquid nitrogen.
IRP
Handling of liquids with high RVP values 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 Reid Vapour Pressure Fracturing
Fluids
Note.
High RVP fracturing fluids include: propane, butane, isobutene, etc.
IRP
Material Safety Data Sheets (MSDS) for fracturing fluids must be on
location and reviewed.
IRP
An ESD meets or exceeds the wellhead design criteria must be installed
on the wellhead.
October 2009
73
IRP4
Well Testing and Fluid Handling
IRP
Separator capacities should be at planned operating pressures and
should be sized for all well effluent phases.
IRP
Fluid from the primary vessel must be handled in one of the following
ways:
• Produced to a pressurized storage vessel with a minimum working
pressure of 1379 KPa for recovery/conservation
• Diverted to pipeline
• Vapourized to flare
74
IRP
When vapourizing fluid for flaring, minimum heat requirements must be
met. Refer to Figure 3: Propane - Heat of Vaporization Volume Basis for
heat required for proper vapourization
IRP
A minimum temperature of the fluid in the vessel is required to maintain
vapourization of the high RVP fluids. Refer to Figure 2: Propane
Saturation Curve and Figure 4: Liquid Vapour Chart for other high RVP
fluids.
IRP
For storage or transportation of fluid off location, in a non pressurized
tank a fluid sample must be taken from the pressurized vessel and
tested for stability. The fluid must have an Air Pollutant Index (API)
reading of less than 50o C at 15.6o C
October 2009
Well Testing and Fluid Handling
IRP4
Figure 2: Propane Saturation Curve
October 2009
75
IRP4
Well Testing and Fluid Handling
Figure 3: Propane - Heat of Vaporization Volume Basis
76
October 2009
Well Testing and Fluid Handling
IRP4
Figure 4: Liquid Vapour Chart
October 2009
77
IRP4
Well Testing and Fluid Handling
Note.
General Information
General Liquefied Petroleum Gas (LPG) Properties:
Critical Pressure
=
4247.66
kPa
Critical Temperature
=
96.675
o
-44
o
Boiling Point at Atm. Pressure
=
C
C
Freezing Point
=
-188
o
Specific Gravity of Liquid
=
0.51
(water = 1.00)
Specific Gravity of Vapour
C
=
1.53
(air = 1.00)
3
1.0 M liquid
=
510
Kg
3
1.0 M 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.
LPG Composition:
Frac typically utilizes LPG provided to a specification denoted as ‘HD5’. A summary
of the HD5 LPG composition specification is as follows (vol%):
C3H
8
90%
minimum
5%
maximum
2%
maximum
Iso-Butane
C4H
10
1.5%
maximum
Methane
CH4
1.5%
maximum
Propane
Propylene
Butane
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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October 2009
Well Testing and Fluid Handling
IRP4
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
October 2009
79
IRP4
Well Testing and Fluid Handling
• Prior to loading fluid ensure all equipment has a bonding device in place
(grounding) and is used
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.
80
October 2009
Well Testing and Fluid Handling
IRP4
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
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:
October 2009
•
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
81
IRP4
Well Testing and Fluid Handling
•
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:
•
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.
82
October 2009
Well Testing and Fluid Handling
IRP4
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.
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:
IRP
October 2009
•
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.
A gas blanket (positive pressure) must be maintained on closed system
production tanks.
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Well Testing and Fluid Handling
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
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.
4.4.4
84
Transportation – Sour Fluids
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.
October 2009
Well Testing and Fluid Handling
4.4.5
IRP4
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
Boilers & Pressure Vessel Exemption Order
ASME Section VIII
ASME B31.3
October 2009
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Well Testing and Fluid Handling
APPENDIX VIII
B IBLIOGRAP HY
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).
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Well Testing and Fluid Handling
IRP4
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.
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..
October 2009
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IRP4
Well Testing and Fluid Handling
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.
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.
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Well Testing and Fluid Handling
IRP4
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.
October 2009
89