RP for Preventing Internal Corrosion of Sweet Gas Lines

Technical document

Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems

February 2002

2002-0013

Disclaimer

This publication was prepared for the Canadian Association of Petroleum Producers (CAPP) by the Pipeline Technical Committee members. While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, CAPP does not guarantee its accuracy. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP or its co-funders.

2100, 350 – 7th Ave. S.W.Calgary, AlbertaCanada T2P 3N9Tel (403) 267-1100Fax (403) 261-4622

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Email: [email protected] Website: www.capp.ca

The Canadian Association of Petroleum Producers (CAPP) represents 140 companies that explore for, develop and produce natural gas, natural gas liquids, crude oil, synthetic crude oil, bitumen and elemental sulphur throughout Canada. CAPP member companies produce approximately 95 per cent of Canada's natural gas and crude oil. CAPP also has 120 associate members who provide a wide range of services that support the upstream crude oil and natural gas industry. Together, these members and associate members are an important part of a $60-billion-a-year national industry that affects the livelihoods of more than half a million Canadians.

Review by July, 2005

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February 2002Recommended Practice for Mitigation of Internal

Corrosion in Sweet Gas Gathering Systems

Contents

1 Project Scope 1-1

2 Failure Statistics 2-1

3 Corrosion Mechanisms and Mitigation 3-1

4 Recommended Practices 4-1

5 Corrosion Mitigation Techniques 5-1

6 Corrosion Monitoring Techniques 6-1

7 Corrosion Inspection Techniques 6-1

8 Leak Detection Techniques 7-1

9 Repair and Rehabilitation Techniques 8-1

10 Pipeline Integrity Management Systems 9-1

11 PLRTG Participants and Acknowledgements 10-1

Figures

Figure 2-1: Natural Gas Pipeline Operating Failures—Total Failures and Failure Frequency by Reporting Year 2-1

Figure 3-1: An Example of Internal Corrosion in a Sweet Gas Pipeline 3-1

Tables

Table 3-1: Contributing Factors and Prevention of Internal Sweet Gas Corrosion 3-2Table 4-1: Recommended Practices 4-1Table 5-1: Corrosion Mitigation Techniques 5-1Table 6-1: Corrosion Monitoring Techniques 6-1Table 7-1: Corrosion Inspection Techniques 7-1Table 8-1: Leak Detection Techniques 8-1Table 9-1: Repair and Rehabilitation Techniques 9-1

Page 4Page 4Page 4February 2002 Recommended Practice for Mitigation of Internal

Corrosion in Sweet Gas Gathering Systems

1.1.1

Project Scope2

This recommended practice addresses design, maintenance and operating considerations for the mitigation of internal corrosion in sweet gas gathering systems constructed with carbon steel materials. For the purpose of this document, sweet gas service is considered to be where the CO2 to H2S ratio is greater than 500:1 (this limit is supplied as a guideline only and may not be absolute). Typically, these would be systems where the H2S concentration is in the low ppm level. This document does not address the deterioration of aluminum and non-metallic materials.

Corrosion is the dominant contributing factor to failures and leaks in pipelines in the province of Alberta. To deal with this issue, the Pipeline Leak Reduction Task Group (PLRTG) of the CAPP Pipeline Technical Committee has developed industry recommended practices to improve and maintain the mechanical integrity of upstream pipelines. They are intended to assist upstream oil and gas producers in recognizing the conditions that contribute to pipeline corrosion failures, and identify effective measures that can be taken to reduce the likelihood of corrosion failures.

These documents are intended for use by corrosion specialists involved with the development and execution of corrosion mitigation programs, engineering teams involved in the design of gathering systems, and operations personnel involved with the implementation of corrosion mitigation programs and operation of wells and pipelines in a safe and efficient manner to mitigate the risk of internal corrosion.

Additional recommended practices being developed by the PLRTG are given below:

Recommended Practice for Mitigation of Internal Corrosion in Sour Gas •Gathering SystemsRecommended Practice for Mitigation of Internal Corrosion in Multiphase •Emulsion Gathering SystemsRecommended Practice for Mitigation of Internal Corrosion in Produced •Water Injection SystemsRecommended Practice for Mitigation of External Corrosion of Pipelines•

For guidance on the standardized approach the Alberta Energy and Utilities Board (EUB) uses for dealing with corrosion-related failures, the reader should refer to the EUB publication Guide 66 – Pipeline Inspection Manual.

Failure Statistics3

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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems

Over the period 2000-2001, failures on natural gas pipelines accounted for 420 •(44%) of the 952 pipeline failures recorded by the EUB. Natural gas as defined for the EUB reporting statistics is gas containing 10 moles per kilomole (1%) or less H2S by volume.In the last three years, internal corrosion has been responsible for •approximately 63% of the failures occurring on natural gas pipelines.In the last three years, over 82% of all pipeline failures have occurred on 2", 3" •or 4" lines.Most of the increase in failures has been occurring on shallow, low pressure •gas systems as commonly found in South Eastern Alberta.

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Figure 2-1: Natural Gas Pipeline Operating Failures—Total Failures and Failure Frequency by Reporting Year

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Corrosion Mechanisms and Mitigation4

Pitting corrosion along the bottom of the pipeline is the primary corrosion mechanism leading to failures in sweet gas pipelines. The common features of this mechanism are:

the presence of water containing any of the following; CO2, bacteria, O2, or •solids.pipelines carrying higher levels of free-water production with no means of •water removal, i.e. well site separation or dehydration.the presence of fluid traps where water and solids can accumulate.•

Vapor phase corrosion is a less common mechanism that has also led to failures. Although not specifically addressed in this recommended practice, many of the preventative measures described in this document will also mitigate this mechanism.

Figure 3-1: An Example of Internal Corrosion in a Sweet Gas Pipeline

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Table 3.1 describes the most common contributors, causes and effects of internal corrosion in sweet gas pipelines. The table also contains corresponding industry mitigative measures being used to reduce sweet gas corrosion.

Table 3-1: Contributing Factors and Prevention of Internal Sweet Gas Corrosion

Contributor Cause/Source Effect MitigationWater Holdup Low gas velocity and •

poor pigging practices allow water to stagnate in the pipelines

Absence of water •separation equipment leads to water wet pipelines

Water acts as the •electrolyte for the corrosion reaction

Chlorides increase the •conductivity of water and may increase the localized pitting rate

Install pigging •facilities and maintain an effective pigging program

Remove water at the •wellsite by separation or dehydration

Control corrosion •through effective inhibition

Solids Deposition

Mainly produced from •the formation

Originate from drilling •fluids, workover fluids and scaling waters

Insufficient gas •velocities and poor pigging practices

Can contribute to under-•deposit corrosion

Scaling can interfere •with corrosion monitoring and inhibition

Install pigging •facilities and maintain an effective pigging program

Initially, flow the •wells to tanks to minimize the effects of work over and completion activities

Scale suppression •

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Oxygen Ingress from •compressors or vapor recovery units (VRU)

Introduced through •endless tubing (ETU) well clean-outs

Ingress from portable •test equipment

Injection of methanol•

Oxygen can accelerate •pitting corrosion at concentrations as low as 50 parts per billion

Typical organic •inhibitor effectiveness can be reduced by the presence of oxygen

Use gas blanketing •and oxygen scavengers

Batch oxygen •scavenger downhole following ETU work overs

Avoid purging test •equipment into the pipeline

Optimize methanol •injection and/or use inhibited methanol

Critical Gas Velocity

Critical gas velocity is •reached when there is insufficient flow to sweep the pipeline of water and solids

A buildup of water and •solids accelerates corrosion

Design pipeline to •exceed critical velocity

Establish operating •targets based on critical gas velocity to trigger appropriate mitigation requirements e.g. pigging, batch inhibition

Detrimental Operating Practices

Ineffective pigging •

Ineffective inhibition•

Inadequate pipeline •suspension

Commingling of •incompatible produced fluids

Accelerated corrosion• Design pipelines to •allow for effective shut-in and isolation

Develop and •implement proper suspension procedures, including pigging and inhibition

Implement and follow •a Pipeline Operation and Maintenance Manual

Test for fluid •incompatibilities

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Carbon Dioxide

Produced with gas from •the reservoir

CO2 concentration can •be increased through fracturing and miscible floods

CO2 dissolves in water •to form carbonic acid

Corrosion rates •increase with increasing CO2 partial pressures

Effective pigging and •inhibition

Bacteria Contaminated drilling •and completion fluids

Contaminated •production equipment

Produced fluids from •the reservoir

Acid producing and •sulfate reducing bacteria can lead to localized pitting attack

Solid deposits provide •an environment for growth of bacteria

Effective pigging •program

Eliminate •introduction of free water into pipelines

Treat with inhibitors •and biocides

Methanol Excessive quantities of •methanol

Use of contaminated •methanol

Methanol injection can •introduce oxygen into the system

High quantities of •methanol may reduce inhibitor effectiveness

Avoid over-injection •of methanol

Effective pigging and •inhibition

Remove free water•

Eliminate the use of •contaminated methanol

Drilling and Completion Fluids

Introduction of bacteria•

Introduction of spent •acids and kill fluids

Introduction of solids•

Accelerated corrosion• Produce wells to •surface test facilities until drilling and completion fluids and solids are recovered

Supplemental pigging •and inhibition of pipelines before and after work over activities

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Management of Change (MOC)

Change in production •characteristics or operating practices

Well re-completions •and work overs

Lack of system •operating history and practices

Changing personnel •and field ownership

Unmanaged change •may result in accelerated corrosion

Implement an •effective MOC process

Implement and follow •a Pipeline Operation and Maintenance Manual

Maintain integrity of •pipeline operation and maintenance history and records

Re-assess corrosivity •on a periodic basis

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Recommended Practices5

Table 4-1 describes the recommended practices for mitigation of internal corrosion in sweet gas pipelines. This table contains a consolidation of industry experience and knowledge used to reduce sweet gas corrosion.

The Alberta Pipeline Act and Pipeline Regulation adopt the requirements of the CSA Z662 Standard, Oil and Gas Pipeline Systems, except where the Act or Regulation specifies otherwise. This Recommended Practice provides some references to certain CSA Z662 sections for information and clarity. This recommended Practice further supports the development of corrosion control practices, and the development of a Pipeline Operation and Maintenance Manual, as required by CSA Z662 and the Alberta legislation.

A pipeline integrity management system provides a framework to document, implement and assure compliance to recommended practices. It is not the intention of this section to describe all components of an integrity management system (refer to section 10).

Table 4-1 Recommended Practices

Element Recommended Practice

Benefit Comments

Dehydration Install gas dehydration •facilities

Ensure dehydration •units are operating properly

Elimination of water •from the system eliminates corrosion

Consider mitigation •requirements for upset conditions

Water Removal

Install water separation •and removal

Removal of free water •from the system reduces the potential for corrosion

Only free water is •being removed therefore pigging and mitigation measures may still be required

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Materials of Construction

Use normalized ERW •line pipe that meets the requirements of CSA Z245.1 Steel Pipe

Use corrosion resistant •materials such as High Density Polyethylene (HDPE) or fiber reinforced composite materials as per CSA-Z662, Clause 13 Plastic Pipelines

Normalized ERW •prevents preferential corrosion of the weld zone

Non-metallic materials •are corrosion resistant

ERW seams should be •placed on the top half of the pipe to minimize preferential corrosion

Non-metallic •materials may be used as a liner or a free standing pipeline depending on the service conditions

Pipeline Isolation

Install valves that •allow for effective isolation of pipeline segments

Allows the effective •suspension and discontinuation of pipeline segments

Reduces the amount of •lost production and flaring during maintenance activities

Removes potential •“deadlegs” from the gathering system

Pipeline Sizing

Design pipeline system •to maintain flow above critical velocity

Using smaller lines •where possible increases gas velocity and reduces water holdup and solids deposition

Consider future •operating conditions such as changes in well deliverability

Consider the future •corrosion mitigation cost of oversized pipelines

Consider the impact •of crossovers, line loops and flow direction changes

Pigging Capability

Install or provide •provisions for pig launching and receiving capabilities

Use consistent line •diameter and wall thickness

Use piggable valves, •flanges, and fittings

Pigging is one of the •most effective methods of internal corrosion control

Multi-disc/cup pigs •have been found to be more effective than ball or sponge type pigs

Receivers and •launchers can be permanent or mobile

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Inspection Capability

Install or provide •capability for inspection tool launching and receiving

Use consistent line •diameter and wall thickness.

Use piggable valves, •flanges, and fittings

Internal inspection •using intelligent pigs is the most effective method for confirming overall pipeline integrity

Proper design allows •for pipeline inspection without costly modifications or downtime

Consideration should •be given to the design of bends, tees, and risers to allow for navigation by the inspection devices

Corrosion Assessment

Evaluate operating •conditions (temperature, pressure, well effluent and volumes) and prepare a corrosion mitigation program

Integrate corrosion •mitigation program into a Pipeline Operation and Maintenance Manual

Communicate •corrosion assessment, operating parameters and the mitigation program to field operations and maintenance personnel

Re-assess corrosivity •on a periodic basis and subsequent to a line failure

Understand and •document design and operating parameters to effectively manage corrosion

Refer to CSA Z662 •Clause 9 – Corrosion Control

Define acceptable •operating ranges consistent with the mitigation program (See Section 10)

Consider the effects of •oxygen, methanol, bacteria and solids

Consider •supplemental requirements for completions and workover fluids

Completion and Workover Practices

Produce wells to •surface test facilities until drilling and completion fluids and solids are recovered

Removal of stimulation •and workover fluids reduces the potential for corrosion

Supplemental pigging •and inhibition of pipelines before and after workover activities

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Corrosion Inhibition and Monitoring

Integrate a corrosion •inhibition and monitoring strategy into a Pipeline Operation and Maintenance Manual

Communicate the •corrosion inhibition and monitoring program to field operations and maintenance personnel

Develop suspension •and lay up procedures

Allows for an effective •corrosion mitigation program

Refer to Section 5 for •Corrosion Mitigation Techniques

Refer to Section 6 for •Corrosion Monitoring Techniques


Number and location •of monitoring devices is dependent on the predicted corrosivity of the system

Consider provisions •for chemical injection, monitoring devices, and sampling points

Inspection Program

Integrate an inspection •strategy into a Pipeline Operation and Maintenance Manual

Communicate the •inspection program to field operations and maintenance personnel

Provides assurance that •the corrosion mitigation program is effective

Refer to Section 7 for •Corrosion Inspection Techniques


Management of Change

Implement an effective •MOC process

Maintain integrity of •pipeline operation and maintenance records

Ensures that change •does not impact the integrity of the pipeline system

Unmanaged change •may result in accelerated corrosion

Leak Detection

Integrate a leak •detection strategy into a Pipeline Operation and Maintenance Manual

Permits the detection of •leaks

Refer to Section 8 for •Leak Detection Techniques

Technique utilized •depends on access and ground conditions

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Repair and Rehabilitation

Inspect to determine •extent and severity of damage prior to carrying out any repair or rehabilitation

Based on inspection •results, use CSA Clause 10.8.2 to determine extent and type of repair required

Implement or make •modifications to corrosion control program after repairs

Prevents multiple •failures on the same pipeline

Prevents reoccurrence •of problem

Refer to Section 7 for •Corrosion Inspection Techniques

Refer to Section 9 for •Repair and Rehabilitation Techniques

Refer to CSA Z662 •Clause 10.8.5 for repair requirements

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Corrosion Mitigation Techniques6

This section describes common techniques that should be considered for the mitigation of internal corrosion in sweet gas pipelines.

Table 4-1 Corrosion Mitigation Techniques

Technique Description CommentsPigging Periodic pigging of pipeline •

segments to remove liquids, solids and debris

Common practice to help •producibility of low volume gas wells

Can be an effective method of •cleaning pipelines and reducing potential for bacteria colonization and under-deposit corrosion

Selection of pig type and sizing •is important if cleaning of the line desired

Requires facilities for launching •and receiving pigs

Batch Corrosion Inhibitor Chemical Treating

Periodic application of a batch •corrosion inhibitor to provide a protective barrier on the inside of the pipe

Provides a barrier between •corrosive elements and pipe surface

Application procedure is •important in determining effectiveness (eg. volume of chemical, diluent used, contact time, and application interval)

Should be used in conjunction •with pigging to remove fluids and clean line.

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Bactericide Chemical Treating

Periodic application of a •bactericide to kill bacteria in the pipeline system.

Effective in killing bacteria in •systems known to contain bacteria

Batch application typically most •effective (e.g. application down-hole leads to ongoing treatment of produced fluids)

The use of improperly selected •bactericides can create a foam that can be a serious operational issue

Oxygen Control

Use gas blanketing and oxygen •scavengers

Batch oxygen scavenger •downhole following ETU work overs

Avoid purging test equipment into •the pipeline

Optimize methanol injection •and/or use inhibited methanol

Oxygen ingress will accelerate •the corrosion potential

Continuous Corrosion Inhibitor Chemical Treating

Continuous injection of a •corrosion inhibitor to reduce the corrosivity of the transported fluids or provide a barrier film

Less common technique due to •low treatment volumes and equipment requirements (pumps and tanks)

Chemical pump reliability is •important in determining effectiveness

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Corrosion Monitoring Techniques7

This section describes the most common techniques for monitoring corrosion and operating conditions associated with internal corrosion in sweet gas pipelines.

Table 6-1: Corrosion Monitoring Techniques

Technique Description CommentsWell Effluent Testing

Initial and periodic testing of well •effluent constituents and production rates

Fluids analysis and production rates •are used to initially determine corrosion potential and should be periodically re-assessed

Water Analysis Ongoing monitoring of water for •chlorides, dissolved metals, bacteria, suspended solids and chemical residuals

Changes in water chemistry will •influence the corrosion potential

Trends in dissolved metal •concentration can indicate changes in corrosion activity

Chemical residuals can be used to •confirm the level of application

Sampling location and proper •procedures are critical for accurate results

Production Monitoring

Ongoing monitoring of production •conditions such as pressure, temperature and flow rates

Changes in operating conditions will •influence the corrosion potential. Production information can be used to assess corrosion susceptibility based on fluid velocity and corrosivity

Mitigation Program Compliance

Ongoing monitoring of mitigation •program implementation and execution

The corrosion mitigation program •must be properly implemented to be effective

The impact of any non-compliance to •the mitigation program must be evaluated to assess the effect on corrosion

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Corrosion Coupons

Used to indicate general corrosion •rates, pitting susceptibility, and mitigation program effectiveness

Coupon type, placement, and data •interpretation are critical to successful application of this method

Coupons should be used in •conjunction with other monitoring and inspection techniques

Bio-spools Used to monitor for bacteria presence •and mitigation program effectiveness

Bio-spool placement and data •interpretation are critical to successful application of these methods

Bio-spools should be used in •conjunction with other monitoring and inspection techniques

Electrochemical Monitoring

There are a variety of methods •available such as electrochemical noise, linear polarization, electrical resistance, and field signature method

The device selection, placement, and •data interpretation are critical to successful application of these methods

Continuous or intermittent data •collection methods are used

Electrochemical monitoring should be •used in conjunction with other monitoring and inspection techniques

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Corrosion Inspection Techniques8

This section describes common techniques that should be considered for the detection of internal corrosion in sweet gas pipelines.

Table 7-1: Corrosion Inspection Techniques

Options Technique CommentsIntelligent pigging

Magnetic flux leakage is the most •common technique

Effective method to accurately •determine location and severity of corrosion

Intelligent pigging can find internal •and external corrosion defects

The tools are available as self •contained or tethered

The pipeline must be designed or •modified to accommodate intelligent pigging

Non-Destructive Examination (NDE)

Ultrasonic inspection, radiography or •other NDE methods can be used to measure metal loss in a localized area

Evaluation must be done to •determine potential corrosion sites prior to conducting NDE

NDE is commonly used to verify •intelligent pig results, corrosion at excavation sites and above ground piping

The use of multi-film radiography is •an effective screening tool prior to using ultrasonic testing

Corrosion rates can be determined •by performing periodic NDE measurements at the same locations

Video Camera Used as a visual inspection tool to •locate internal corrosion

Can be used to determine the •presence of corrosion damage, but it is difficult to determine severity

This technique may be limited to •short inspection distances

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Boroscope Used as a visual inspection tool to •locate internal corrosion

Can be used to determine the •presence of corrosion damage, but it is difficult to determine severity

This technique is limited to short •inspection distances

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Leak Detection Techniques9

This section describes common techniques that should be considered for the detection of pipeline leaks caused by internal corrosion in sweet gas pipelines. Proactive leak detection can be an effective method of finding small leaks and mitigating the consequences of a major product release or spill.

Table 8-1: Leak Detection Techniques

Technique Description CommentsFlame Ionization Survey

Electronic instrumentation used to •detect very low concentrations of gas

Equipment is portable and very •sensitive

Infrared Thermography

Thermal imaging is used to detect •temperature change on Right-of-Way due to escaping gas

Need sufficient volume of escaping •gas to create an identifiable temperature difference

Normally completed using aerial •techniques

Right-of-Way (ROW) Surveillance

Visual inspection by ground access or •aerial surveillance to look for indications of leaks

Indications include soil subsidence, •gas bubbling, and water, soil, or vegetation discoloration

Can be used in combination with •infrared thermography and flame ionization surveys

Odor Detection Odorant detection using trained •animals and patented odorants

Capable of detecting pinhole leaks •that may be otherwise non-detectable

Production Monitoring

Volume balancing or pressure •monitoring to look for indications of leaks

Changes in production volumes or •pressure can indicate a pipeline failure

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Repair and Rehabilitation Techniques10

This section describes common techniques used for repair and rehabilitation of pipelines damaged by internal sweet gas corrosion.

Prior to the repair or rehabilitation of a pipeline the appropriate codes and guidelines should be consulted, including:

CSA Z662-99, Oil and Gas Pipeline Systems, Section 10.8, “Permanent and •Temporary Repair Methods”CSA Z662-99, Oil and Gas Pipeline Systems, Section 13, “Plastic Pipelines” •for requirements for polymer liners, polymer pipes, and composite pipes EUB Guide 66 Pipeline Inspection Manual, Appendix 3 “EUB Pipeline •Inspectors' Guide to Corrosion Failure Procedures” for pipeline restoration follow up activities

Table 9-1: Repair and Rehabilitation Techniques

Technique Description CommentsPipe Section Replacements

Remove damaged section(s) and •replace.

When determining the quantity of pipe •to replace consider the extent of corrosion and the condition of the remaining pipeline

Impact on pigging capabilities must •be considered (use same pipe diameter and similar wall thickness)

The replaced pipe section should be •coated with corrosion inhibitor prior to commissioning

Repair Sleeves Reinforcement and pressure-•containing sleeves may be acceptable for temporary or permanent repairs of internal corrosion as per the limitations stated in CSA Z662

For internal corrosion it may be •possible in some circumstances for the damaged section to remain in the pipeline as per the requirements in CSA Z662 Section 10.8

Different repair sleeves are available •including composite, weld-on and bolt-on types. The sleeves must meet the requirements of CSA Z662 Section 10.8

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Polymer Liners A polymer liner is inserted in the steel •pipeline

The steel pipe must provide the •pressure containment capability

A variety of materials are available •with different temperature and chemical resistance capabilities

Impact on pigging capabilities must •be considered

Polymer liners may eliminate the need •for internal corrosion mitigation, corrosion monitoring and inspection

Reduction of inhibition programs may •impact the integrity of connecting headers and facilities constructed from carbon steel

Composite or Plastic Pipeline

Freestanding composite or plastic •pipe can be either plowed-in for new lines, or pulled through old pipelines

This pipe must be designed to provide •full pressure containment

A variety of materials are available •with different temperature and chemical resistance capabilities

Freestanding plastic pipelines may be •limited to low-pressure service

Freestanding composite pipelines may •not be permitted for gas service

Impact on pigging capabilities must •be considered

Composite or plastic pipelines may •eliminate the need for internal corrosion mitigation, corrosion monitoring and inspection

Reduction of inhibition programs may •impact the integrity of connecting headers and facilities constructed of carbon steel

Pipeline Replacement

Alteration or replacement of pipeline •allows proper mitigation and operating practices to be implemented

Must be piggable and inspectable•

Refer to Section 4 “Recommended •Practices ” in this document for details

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Pipeline Integrity Management Systems11

Describing an entire pipeline integrity management system is outside the scope of work undertaken by the PLRTG. One fundamental component of such a system is valid practices to mitigate corrosion. Compiling these recommended practices was the primary goal of the PLRTG. However, to properly manage corrosion of pipelines, the operator should develop and implement a pipeline integrity management system. The pipeline integrity management system should encompass all aspects of the pipeline design, operation and maintenance. Some of the aspects that need to be considered include:

Design•Risk Assessment Methodology•Deterioration, Corrosion and Failure Modes Assessments•Maintenance Strategies•Operating Practices•Corrosion Control Strategy•

Inspection •Mitigation •Monitoring •

Repair Strategies•

Two key processes that need to be in place to support an effective pipeline integrity management system are:

Management of Change (MOC) Process11.1

MOC should address not only mechanical changes to the design, but all •types of change including mechanical, process, operating and personnel changes that could impact on the safe operation of the pipeline. The MOC process provides the opportunity for the key operating, maintenance, technical and management groups to assess the impact of a potential change, and address any additional measures that need to be implemented and documented as part of the change.

Operating Parameters Monitoring Process11.2

It is essential to establish a set of operating parameters that form the •premises used for the design of the pipeline and the required corrosion control strategy and program. It is important to have the capability to monitor the key operating parameters and limits, notify the necessary personnel when a deviation from the specified operating limits has occurred, and implement the required corrective actions to address the variance.

The key operating parameters include:•Gas, water and hydrocarbon compositions•

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Gas, water and hydrocarbon flow rates•Inhibitor, methanol and biocide application rates•Operating temperatures and pressures •Pigging, monitoring and inspection frequencies •

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PLRTG Participants and Acknowledgements12

The members of the CAPP Pipeline Leak Reduction Task Group (PLRTG) included:

Alan Miller – PanCanadian Resources•Randy Damant – Skystone Engineering Inc.•Ray Goodfellow – Chevron Texaco•Colin McGovern – Devon Energy Canada•Kevin Goerz – Shell Canada Limited•Dave Grzyb – Alberta Energy and Utilities Board•Ray Price – BP Canada Energy Company•Scott Oliphant – Rio Alto Exploration•Gordon Tunnicliffe – Anadarko Canada Corporation •Joe Dusseault – AEC Oil & Gas•Bob Shapka – Talisman •

The members of the PLRTG would like to express their gratitude and appreciation to Ms. Tanis Jenson, Ms. Christianne Street and Ms. Camila McKenna for their assistance in the preparation of the Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems.

Documents

RP for Preventing Internal Corrosion of Sweet Gas Lines