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PETRONAS TECHNICAL STANDARDS

DESIGN AND ENGINEERING PRACTICE

MANUAL

PIPELINE LEAK DETECTION

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PREFACE

PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication,of PETRONAS OPUs/Divisions.

They are based on the experience acquired during the involvement with the design, construction,operation and maintenance of processing units and facilities. Where appropriate they are basedon, or reference is made to, national and international standards and codes of practice.

The objective is to set the recommended standard for good technical practice to be applied byPETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical

plants, marketing facilities or any other such facility, and thereby to achieve maximum technicaland economic benefit from standardisation.

The information set forth in these publications is provided to users for their consideration anddecision to implement. This is of particular importance where PTS may not cover everyrequirement or diversity of condition at each locality. The system of PTS is expected to besufficiently flexible to allow individual operating units to adapt the information set forth in PTS totheir own environment and requirements.

When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for thequality of work and the attainment of the required design and engineering standards. Inparticular, for those requirements not specifically covered, the Principal will expect them to followthose design and engineering practices which will achieve the same level of integrity as reflectedin the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from hisown responsibility, consult the Principal or its technical advisor.

The right to use PTS rests with three categories of users :

1) PETRONAS and its affiliates.2) Other parties who are authorised to use PTS subject to appropriate contractual

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TABLE OF CONTENTS

1. INTRODUCTION1.1 SCOPE1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS1.3 DEFINITIONS1.4 ABBREVIATIONS1.5 CROSS-REFERENCES1.6 SUMMARY OF CHANGES FROM PREVIOUS EDITION

2. REQUIREMENT FOR LEAK DETECTION

3. PERFORMANCE INDICATORS FOR LEAK DETECTION3.1 SENSITIVITY3.2 RELIABILITY3.3 ACCURACY3.4 LEAK LOCATION CAPABILITY3.5 ROBUSTNESS3.6 COST

4. SELECTION OF A LEAK DETECTION SYSTEM

4.1 PRIMARY FUNCTIONALITY4.2 SECONDARY FUNCTIONALITY4.3 ADDITIONAL FUNCTIONALITY

5. IMPLEMENTATION5.1 RESPONSIBILITY5.2 PERFORMANCE SPECIFICATION5.3 INSTRUMENTATION5.4 FACTORY ACCEPTANCE TESTING

5 5 DATA SAMPLING RATE

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1. INTRODUCTION

1.1 SCOPE

This PTS specifies requirements and gives recommendations for the application of LeakDetection Systems and gives an overview of available pipeline leak detection techniquesand their effectiveness for pipeline applications. This PTS is primarily aimed at continuouson-line leak detection systems. Discrete off-line systems are only briefly discussed.

This PTS provides guidance on the following:

- when to specify a leak detection system;

- how to specify performance parameters;

- what system to select;

- how to implement a system.

This PTS is a revision of the previous publication of the same number and title, datedSeptember 1994. A summary of changes from the previous edition is given in (1.6).

Although applicable to onsite lines, this PTS is intended for use with long, cross-country or

subsea transportation pipelines that are outside facility battery limits.

1.2 DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS

Unless otherwise authorised by PETRONAS, the distribution of this PTS is confined tocompanies forming part of PETRONAS or managed by a Group company, and toContractors nominated by.

This PTS is intended for use by all Functions in the Group that are involved in the designand operation of pipelines, but in particular for use during the conceptual design phasewhen the requirement for a leak detection system is being decided

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1.3.2 Specific definitions

Fluid - substances that are transported through a pipeline in liquid and/or gaseous phase.

Hard liquid - a liquid with a vapour pressure below the prevailing atmospheric pressure,e.g., gas oil.

Leak - an uncontrolled fluid release from a pipeline.

Pipeline - a system of pipes and other components used for the transportation of fluids,between (but excluding) plants. A pipeline extends from pig trap to pig trap (including thepig traps and associated pipework and valves), or, if no pig trap is fitted, to the first isolation

valve within the plant boundaries or a more inward valve if so nominated.Pipeline section - the user-selected subdivision of a pipeline.

Soft liquid - a liquid with a vapour pressure above the prevailing atmospheric pressure,e.g., ethylene, NGL, LPG, etc.

1.4 ABBREVIATIONS

ALARP - As Low as Reasonably Practicable

DCS - Distributed Control SystemFAT - Factory Acceptance TestingISDN - Integrated Service Digital NetworkLBV - Line Block ValveLDS - Leak Detection SystemMAOP - Maximum Allowable Operating PressureOPC - OLE (Object Linked Editing) for Process ControlPC - Personal ComputerPSTN - Public Subscriber Telephone Network

SCADA Supervisory Control and Data Acquisition

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2. REQUIREMENT FOR LEAK DETECTION

Group and public awareness of safety and environmental issues puts increasing emphasison the potential consequences of a pipeline leak for human safety and pollution of theenvironment. Proper pipeline management should ensure technical integrity of a pipeline inorder to prevent failures and fluid releases and to limit the consequences if a leak occurs.

An LDS reduces the consequences of failure by enabling fast emergency response. Theseconsequences comprise economic consequences, safety consequences, environmentalconsequences and the more intangible socio-political consequences. Pipeline leaks canresult in bad publicity and penalties, both of which can be reduced by having a proper

pipeline integrity management and emergency response system in place including an LDS.

Other measures should be in place to prevent and monitor degradation of the pipeline thatin the end may lead to failure, and to consequently reduce the probability of a leak to as lowas is reasonably practicable (the ALARP principle).

Most authorities do not specify an LDS for pipelines as part of the pipeline managementsystem. However, most countries have some form of legislation and regulations regardingpipeline safety, and installing an LDS may help to obtain appropriate authorisations. Inrecent years, governments have tended to move from specific rules to performance-based

regulations. The risk management concept has now been introduced in both Europe andthe USA. Because an LDS may help pipeline operators reduce the loss of containment andhence risks, it should be considered as part of the risk management programme.

As a consequence of the above, an LDS for a new pipeline should be specified in thefollowing cases:

- If leak detection is required by applicable mandatory legalisation. All mandatorylegislation and local codes shall be complied with in full, concessions notwithstanding. Ifthe requirements of said legislation and codes are less than those that could be

provided by use of SCADA based leak detection then the latter should be provided as

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3. PERFORMANCE INDICATORS FOR LEAK DETECTION

3.1 SENSITIVITY

Sensitivity is defined as a composite measure of the size of leak that a system is capable ofdetecting, and the time required for the system to issue an alarm in the event that a leak ofthat size should occur. Some LDSs have a wide variation in the response time as a functionof leak size; for others the response time is relatively independent of leak size.

Leak detection performance is usually defined in terms of detecting a particular leak flowrate within a specified minimum period of time. Adjustments made to improve sensitivity

can have a negative effect on other aspects of performance. For example, if the minimumleak detectable is set too low with a specified time period, then false alarms will occur morefrequently.

Sensitivity is generally insufficient to detect corrosion pinhole leaks.

3.2 RELIABILITY

Reliability is defined as a measure of an LDSs ability to make accurate decisions about thepossible existence of a leak in the pipeline. Reliability is directly related to the probability of

declaring a leak incorrectly, i.e., if none has occurred. A system is considered to beunreliable if it tends to declare leaks incorrectly.

Reliability pertains only to the functionality of the leak detection software without regard toSCADA system performance, availability of the pipeline instrumentation and communicationequipment, or any other factor beyond the control of the LDS vendor. Such factors involve aseparate category of performance, namely robustness.

System reliability is directly affected by factors such as instrument reliability/drift in signals,etc. Model based systems require periodic tuning to ensure the best results.

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3.5 ROBUSTNESSRobustness is defined as a measure of the LDSs ability to continue to function and provideuseful information, even under changing conditions of pipeline operation, or in conditionswhere data is lost or suspect. A system is considered to be robust if it continues to functionunder such less than ideal conditions.

The distinction between reliability and robustness is significant. Reliability is a measure ofperformance within a specified operational envelope. Robustness is a measure of theeffective size of the operational envelope as the following examples illustrate:

System I: This system employs a sensitive leak detection algorithm and is normally verysensitive, but will frequently generate false alarms during certain normal pipelineoperations. The designers of System I have sacrificed a degree of reliability in order tomaintain a high level of sensitivity. Nuisance alarms are not conducive to good operationand tend to dull the awareness of operations personnel. Therefore this system is normallynot recommended.

System II: This system employs an alternative algorithm which is somewhat less sensitivethan that of System I, but generates only a fraction of the false alarms. The designers of

System II have chosen to sacrifice a degree of sensitivity in order to achieve a high level ofreliability.

System III: This system employs the same sensitive leak detection algorithm as System I,but inhibits leak detection during pipeline operations that can cause it to generate falsealarms. The designers of System III have sacrificed a degree of robustness in order toachieve higher levels of reliability and sensitivity.

System IV: This system normally employs the same sensitive leak detection algorithm asSystem I, but switches to the less sensitive algorithm of System II when it senses

conditions that generate false alarms S stem IV represents an attempt to selecti el trade

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4. SELECTION OF A LEAK DETECTION SYSTEM

4.1 PRIMARY FUNCTIONALITY

The primary functionality is to detect the occurrence and/or presence of a leak. Unlessthere are substantial reasons for doing otherwise, the selected LDS shall be a real-time,corrected mass or volume balance system, see (6). The LDS can be totally integratedwithin the SCADA system, or the leak detection application can utilise a stand-aloneplatform and communicate via OPC or similar protocol with the SCADA system.

To preserve operators confidence in the system and ensure reliable operation of the plant

facilities, the LDS should not produce nuisance/false leak alarms. Reliability and robustnessshall be the essential performance factors, with sensitivity and accuracy having asecondary role.

4.2 SECONDARY FUNCTIONALITY

Depending upon requirements (which should be evaluated by cost benefit analysis), theLDS may have one or more of the following functionalities in addition to the primaryfunctionality of leak detection.

Leak location

Leak location identification is particularly useful where the location of a leak would bedifficult or expensive to determine by normal procedures.

Leak location identification is even more useful on longer pipelines where there are anumber of pipeline sections that can be shut in with isolation valves. Shutting the wholenetwork down may be highly undesirable.

Static leak detection

Th LDS h ld id ll d t St ti L k D t ti if thi i ti l

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5. IMPLEMENTATION

5.1 RESPONSIBILITY

The LDS should be designed and engineered in association with the SCADA system.Ideally the supply of the LDS and the SCADA system should be a single responsibility.Typically the SCADA system Supplier should be responsible for supplying the LDS as thiswill provide seamless factory acceptance testing, installation and commissioning.

Depending upon the contract philosophy, the choice of LDS type and Manufacturer may beselected by the responsible Supplier. However, regardless of the method used, the

Principal should be fully involved in the process and should be the approving authority inorder to ensure that the system will meet the performance specification.

5.2 PERFORMANCE SPECIFICATION

Some form of performance guarantee should be identified and incentivised, based onperformance monitoring against key targets. The LDS Supplier should provide baseperformance indicators as defined in (3), ideally prior to order placement, but otherwise aLeak Sensitivity Study should be carried out to formulate an agreed contractual

performance.If possible, a milestone payment should be linked to the validation of sensitivity and locationaccuracy performance by simulating a real physical leak. Ideally the leak should not besimulated close to an instrumented point on the pipeline.

Performance based on a guaranteed minimum of false alarms shall be combined with thedetection time for various leak sizes to dissuade the Supplier from desensitising the sytem.

As a minimum, a performance test period of 60 days shall be employed for systemacceptance testing purposes. During this period the system shall operate without

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intervention by the operator, in conjunction with the appropriate operating procedure,

should be the normal response to a leak alarm.

5.7 OPERATOR DISPLAYS

Data shall be presented in the form of displays, easily interpreted by the operator. Displaysshould comprise pipeline ingress (and egress) pressure and flow trends, imbalance trends,inventory trends and pressure vs. distance displays. Such displays will assist the Operatorif a leak alarm is issued by the LDS.

The operator shall not, therefore, be presented with masses of tabulated data that can

easily become incomprehensible, if not totally ignored. Displays may either reside on theSCADA system, or on the LDS if a stand-alone system is employed. Common symbols andpractices shall be employed across the SCADA and LDS operator interface.

5.8 OPERATIONAL CONSIDERATIONS

Consistent start-up/shutdown procedures greatly enhance leak detectability duringtransients.

Operational procedures shall be formulated that the pipeline operator is required to complywith in the event of a pipeline leak. Blind trials should be conducted at least once a year tocheck the response of operators and associated procedures.

5.9 REMOTE MAINTENANCE

Most LDS tuning and maintenance operations can now be performed remotely with acorresponding reduction in cost. A dial-up modem (PSTN or ISDN) or similarcommunication equipment should be supplied to allow remote diagnostics of the LDS.

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6. LEAK DETECTION TECHNIQUES

6.1 GENERAL

Leak detection techniques are based on either continuous or intermittent measurements ofspecific parameters. Intermittent leak detection methods are often able to detect smallerleak rates than continuous leak detection techniques can.

Some continuous techniques can only detect transient pipeline conditions during the onsetof a leak, and will not be able to identify the presence of a leak at a later time.

For some intermittent techniques, fluid transportation through the pipeline needs to be

interrupted. With intermittent techniques, the detection time of a leak will be completelydependent on the frequency of inspection.

Generally, LDSs work in single-phase pipelines only. Techniques for detection of leaks inliquid lines generally perform better than those for gas pipelines. LDS performance islimited in two-phase pipelines.

The conflicting balance of sensitivity to leaks and false alarms will determine the sensitivitysetting of the LDS. Large leaks can normally be detected more rapidly than small ones. Tomaintain the user's confidence in the system and the effectiveness of the operators

response, avoiding false alarms should have a higher priority than attempting to shorten theleak detection time or reducing the minimum detectable leak rate.

The performance of pipeline leak detection techniques is dependent on fluid type, operatingpressure including fluctuations, batch or continuous operation, pipeline length and size,metering accuracy and repeatability, etc.

The technique to be adopted should be determined by detailed evaluation. Generally, thecorrected mass or volume balance method or the SPLD method should be used. It may benecessary to deploy more than one leak detection technique in order to achieve the overall

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6.2.3 Corrected Mass or Volume Balance

In addition to inlet and outlet flow measurement, the corrected flow balance method uses acorrection factor for any changes in the pipeline inventory. Pressure and, if necessary,temperature measurements at intervals along the pipeline are used for calculating thecorrection factor. The ability to detect small leaks depends upon the number and accuracyof measurements along the length of the pipeline.

An alternative method is dynamic simulation (6.4), which is a model-assisted balancemethod. A real time computer model calculates the inventory of the pipeline and the linepack variations of the pipeline under steady state and transient operating conditions. It will

correct not only for pressure and temperature effects, but also for changes in fluidproperties, such as where different batches of fluids are present in the pipeline at the sametime. A difference between the flow balance predicted by the model and that actuallymeasured indicates the presence of a leak. Also, unexpected flow and/or pressure trendsare used as indicators of the occurrence of a leak.

The dynamic simulation method is similar to the corrected flow balance system. The maindifference is that the dynamic simulation method calculates the pipeline inventory whereasthe corrected mass balance method interpolates between the measurements along thepipeline. The latter is simpler although its accuracy is slightly lower than that of the dynamic

simulation method.

The sensitivity of these methods is generally good. Their disadvantage is that they arepoorly able to locate the leak.

6.2.4 Statistical Pipeline Leak Detection

Shell has developed a Statistical Pipeline Leak Detection (SPLD) system, which is also aform of the corrected flow balance system. The system does not need complicatedmodelling of the pipeline inventory. It continuously calculates the statistical probabilities of a

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6.3.3 Change in Pressure/Flow

A leak will result in an increase in flow upstream and a decrease in flow downstream of theleak. Consequently, the pressure gradient will increase upstream and decreasedownstream of the leak. The occurrence of a discontinuity in the pressure gradient, which iscalculated from the pressure readings along the pipeline, is an indication of a large leak.The rate of change of pressure and flow readings can also be monitored and used to detectsudden changes that indicate the occurrence of a leak.

The combined pressure decrease/flow increase method, commonly referred to as pressurepoint analysis, uses the fact that a leak in an operational pipeline will cause an increase in

the flow and a decrease in the pressure upstream of the leak. The simultaneous occurrenceof both is an indication of a leak. It is a relatively inexpensive solution and not model based.However, pressure decline is not unique to a leak event, and false alarms may be commonon transient lines.

6.4 DYNAMIC MODELS

The dynamic model method uses equations of state to mathematically emulate the fluidflow within the pipeline. Usually it has to solve three partial differential equations on-line:

conservation of mass, momentum and energy. Deviation between modelled variables andmeasured pipeline variables is theoretically indicative of a leak condition. This method,however, has historically proved difficult to successfully implement for online applications.This is due to the complexity of the modelling variables and calculations required. Typicallyproblems of tuning and a high false alarm rate have prevented the successfulimplementation of a reliable system of this type. Dynamic models have proved to be of highinitial cost with a high cost of ownership with no great improvement of sensitivity over thatof SPLD.

6 5 MONITORING OF CHARACTERISTIC SIGNALS GENERATED BY A LEAK

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properties will be changed due to the presence of an opening in the pipeline. The distance

between the transmitter and receiver is very short, usually a few hundred metres only.

6.5.3 Hydrocarbon-sensing Cables

Hydrocarbon-sensing cables can be laid along the pipeline. Electrical properties of thecable change when hydrocarbons come in contact with the cable. Contact with water doesnot affect the properties of the cable.

6.5.4 Other Development

A prototype system for the measurement of methane in seawater has been developed. Thedevice, which is mounted on a remotely operated vehicle, extracts dissolved gas from acontinuous flow of water and determines the methane content using infrared absorptiontechniques.

6.6 OFF-LINE LEAK DETECTION

6.6.1 Pipeline Patrolling

A pipeline patrolling program should be in place as a method of leak detection whether anon-line system is available or not. The frequency of this inspection should be based on thecriticality of the pipeline. A record of this inspection should be maintained throughout the lifeof the pipeline.

6.6.2 Static Pressure Test

The pressure in a blocked-in pressurised pipeline will drop when there is a leak. For a staticpressure leak test the pipeline (or a section of it) is pressurised with the transportedhydrocarbon fluid to the MAOP. If pressurising to a higher level is required, the leak test

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6.6.4 Sniffer Tube

A hydrocarbon-permeable tube (sniffer tube) can be laid in close proximity along thepipeline. Small leaks of hydrocarbons from the pipeline that have permeated into the tubewill be detected when the tube is periodically purged into a gas analyser.

6.6.5 Remote Sensing of Hydrocarbon Emissions

Remote sensing of hydrocarbon emissions, e.g., using an infrared technique from anaircraft, is becoming commercially available. Particularly for gas and multi-phase pipelines,this offers a powerful alternative to ground based patrolling techniques.

6.6.6 Acoustic Techniques

The sound that is generated when liquid is forced through a small opening during pressuretesting can be detected by acoustic monitoring. For pipelines transporting hard liquids, leakdetection by an acoustic reflectometry method is feasible. The technique is based on thephenomenon that a pressure wave travelling through a pipeline is reflected at the positionof a leak, due to a local change of acoustic properties. For lines that are used intermittently,this technique can be used during downtime when the level of disturbing noise is low.

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7. REFERENCES

In this PTS, reference is made to the following publications:

NOTE: Unless specifically designated by date, the latest edition of each publication shall be used, togetherwith any amendments/supplements/revisions thereto.

PETRONAS STANDARDS

Index to PTS publications and standard specifications PTS 00.00.05.05

Hydrostatic pressure testing of new pipelines PTS 31.40.40.38

http://00000505.pdf/http://31404038.pdf/http://31404038.pdf/http://00000505.pdf/

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8. BIBLIOGRAPHY

NOTE: The following documents are for information only and do not form an integral part of this PTS:

Jansen, H J M., Pipeline Leak Detection; State of the ArtReview as of May 1997. September 1997.

SIEP 97-5527

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APPENDIX 1 SUMMARY OF THE CAPABILITIES AND APPLICATION OF LEAK DETECTION TECHNIQUES

LEAK

DETECTIONMETHOD

LEAK TYPE MODE OF

OPERATION

RESPONSE TIME LEAK LOCATION

CAPABILITY

ROBUSTNESS RELIABILITY COST REMARKS

Low Pressure gas: full bore ruptures

liquid: major leaks

any seconds to minutes good poor low high thresholds

required to avoidfalse alarms

Change inpressure / flow

gas: major leakliquid: large leaks

steady state seconds to minutes Offshore: NoneOnshore: Betweenblock valves if

pressure readingsavailable

good poor low

Wave alert gas: medium to large leaks

liquid: small to mediumleaks

steady and

transient state

seconds to minutes within 1 km,

depending ontransducer spacing

good poor medium detects only the

onset of a leak

Mass or volume

balance

gas and liquid: medium to

large leaks

steady state minutes to hours none good poor low

Corrected mass or

volume balance

gas and liquid: small,

medium and large leaks

steady and

transient state

minutes to hours Offshore: None

Onshore: Betweenblock valves

good medium medium

Statistical pipeline

leak detection(SPLD)

gas and liquid: small,

medium and large leaks

steady and

transient state,shut in

minutes to hours at best within 5 % of

distance betweenpressure meters

good good medium low probability of

false alarm

Dynamic

simulation model

gas and liquid: small,

medium and large leaks

steady and

transient state,shut in

minutes to hours at best within 10 % of

pipeline length

poor poor high high false alarm rate

Acoustictechniques

liquids: large leaks (on-line), small to medium leaks(shut-in)

steady state depends onmonitoringfrequency

within 1 km good medium high hard liquids only

Static pressure test hard liquids: small leakssoft liquids: medium leaksgas: large leaks

during shut in hours to days none, between blockvalves

good poor low capabilities dependon length andtemperature effects

Sniffer tube,hydrocarbonsensing-cables

all fluids, includingmultiphase: small leaks

any hours within 100 m forhydrocarbon sensingcables

good good high short lines only

Full bore rupture: 100 % of flow Medium leak: 5 % - 25 % of flow

Major leak: 50 % - 100 % of flow Small leak: 1 % - 5 % of flowLarge leak: 25 % - 50 % of flow