GP 43-50 31 January 2009

GP 43-50

Pigging, Pig Launchers, and Receivers

Group Practice

Document No. GP 43-50 Applicability Group Date 31 January 2009

BP GROUP ENGINEERING TECHNICAL PRACTICES

31 January 2009 GP 43-50 Pigging, Pig Launchers, and Receivers

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Foreword

This revision of Engineering Technical Practice (ETP) GP 43-50 is the result of extensive operational comment and consultation as well as significant lessons learned from recent pig trap failures. The document has been restructured to bring relevant topics together while adding information on ATEX requirements and the Global ILI Framework Agreement. The new structure is as follows:

Guidance on pig selection. Basic requirements for pigging operations. Design of pipelines and facilities for pigging. Specific guidance on design, inspection, and maintenance of pig trap closures.

Because revisions were so extensive, revisions have not been identified in the margin as is normal practice.

Copyright 2009 BP International Ltd. All rights reserved. This document and any data or information generated from its use are classified, as a minimum, BP Internal. Distribution is intended for BP authorized recipients only. The information contained in this document is subject to the terms and conditions of the agreement or contract under which this document was supplied to the recipient's organization. None of the information contained in this document shall be disclosed outside the recipient's own organization, unless the terms of such agreement or contract expressly allow, or unless disclosure is required by law.

In the event of a conflict between this document and a relevant law or regulation, the relevant law or regulation shall be followed. If the document creates a higher obligation, it shall be followed as long as this also achieves full compliance with the law or regulation.


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Table of Contents Page Foreword ........................................................................................................................................ 2 1. Scope .................................................................................................................................... 5 2. Normative references............................................................................................................. 5 3. Symbols and abbreviations .................................................................................................... 6 4. Pigging overview.................................................................................................................... 7

4.1. Reasons to pig............................................................................................................ 7 4.2. Pig types..................................................................................................................... 7 4.3. Pig selection, design, and maintenance ...................................................................... 9 4.4. In-line inspection pigging requirements ..................................................................... 12 4.5. Pigging operational considerations ........................................................................... 13 4.6. Pig trap operations, inspection and maintenance...................................................... 16

5. Pipeline design for pigging................................................................................................... 20 5.1. General..................................................................................................................... 20 5.2. Internal diameters of linepipe .................................................................................... 21 5.3. Bends for pigging...................................................................................................... 21 5.4. Valves, check valves, tees, and wyes ....................................................................... 22 5.5. Pig handling equipment............................................................................................. 23

6. Design of pig trap installations ............................................................................................. 24 6.1. General..................................................................................................................... 24 6.2. Service conditions and code requirements................................................................ 27 6.3. Layout requirements ................................................................................................. 28 6.4. Structural supports and lifting lug design................................................................... 29 6.5. Pipework and pressure and instrumentation requirements........................................ 30 6.6. Valves....................................................................................................................... 34 6.7. Barrel design............................................................................................................. 35 6.8. Pig trap end closures ................................................................................................ 36 6.9. Materials, fabrication, welding, and marking.............................................................. 41

7. Special applications ............................................................................................................. 42 7.1. Subsea traps............................................................................................................. 42 7.2. Pigging of flexibles .................................................................................................... 43 7.3. Tanker/barge loading lines........................................................................................ 43 7.4. Temporary pig traps.................................................................................................. 43

Annex A (Informative) Recommended pig trap closures................................................................ 44 Annex B (Informative) Tie rod type design pig trap closures ......................................................... 45 B.1 Qualification of use requirements for FAI, LTS, and TDW.................................................... 45

B.1.1 Introduction............................................................................................................... 45 B.1.2 What are the main issues?........................................................................................ 45 B.1.3 Design of tie rod and associated fittings.................................................................... 46


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B.1.4 Gasket compression ................................................................................................. 46 B.1.5 Tie rod loading .......................................................................................................... 46 B.1.6 Clamp angles............................................................................................................ 47 B.1.7 Acceptable tie rod type design pig trap closures ....................................................... 49

Annex C (Informative) Onshore gas terminal incident at 16 in sphere receiver ............................. 50 C.1. Incident ................................................................................................................................ 50 C.2. Cause of the incident ........................................................................................................... 50 C.3. Recommendations............................................................................................................... 51 C.4. Comment ............................................................................................................................. 51 Bibliography .................................................................................................................................. 52

List of Tables

Table 1 - Managing risks of pig trap purging operations................................................................ 18 Table 2 - Recognised purging practices across the BP Group ...................................................... 19 Table 3 - Pig trap closure design requirements ............................................................................. 39 Table 4 - Pig trap closure test requirements.................................................................................. 40 Table A.1 - GD Engineering (GD): Type BANDLOCK 2 ................................................................ 44 Table A.2 - Pipeline engineering (PE) ........................................................................................... 44

List of Figures

Figure 1 - Barred tee design detail ................................................................................................ 23 Figure 2 - Typical pig launcher...................................................................................................... 25 Figure 3 - Typical pig receiver ....................................................................................................... 26


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1. Scope

a. This GP provides requirements for: 1. Pigging practice. 2. Pipeline design to accommodate pigging. 3. Selection and design of pig traps, end closures, and appurtenances.

Requirements on the need for pig traps and the locations within facilities are given in GP 43-20, GP 43-21, and GP 43-22.

b. The scope of this GP includes: 1. Onshore, offshore, and subsea pipeline systems. 2. Horizontal and vertical launcher and receiver pig traps. 3. Oil, gas, chemical, and liquid petroleum gas (LPG) service conditions. 4. All pig types (i.e., utility pigs, intelligent pigs, and spheres). 5. New and existing facilities.

c. This GP is relevant to the pipeline technical authority (TA), as well as design, installation, and operations personnel.

2. Normative references

The following referenced documents may, to the extent specified in subsequent clauses and normative annexes, be required for full compliance with this GP:

For dated references, only the edition cited applies. For undated references, the latest edition (including any amendments) applies.

BP GP 06-20 Materials for Sour Service. GP 43-52 Inspection and Integrity Assessment of Pipeline Systems.

American Society of Mechanical Engineers (ASME) ASME Boiler and Pressure Vessel Code Section II - Part A - Ferrous

Material Specifications. ASME Boiler and Pressure Vessel Code Section II - Part B - Nonferrous

Material Specifications. ASME Boiler and Pressure Vessel Code Section II - Part D - Properties. ASME Boiler and Pressure Vessel Code Section VIII - Rules for

Construction of Pressure Vessels Division 1. ASME Boiler and Pressure Vessel Code Section VIII - Rules for

Construction of Pressure Vessels Division 2 - Alternative Rules. ASME B16.5 Pipe Flanges and Flanged Fittings: NPS 1/2 through NPS 24. ASME B16.9 Factory-Made Wrought Buttwelding Fittings. ASME B31.3 Process Piping.


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International Standards Organization (ISO) ISO 13628-1 Petroleum and natural gas industries - Design and operation of subsea

production systems - Part 1: General requirements and recommendations.

Manufacturers Standardization Society of the Valves and Fittings Industry (MSS) MSS SP-44 Steel Pipeline Flanges. MSS SP-75 Specification for High Test Wrought Butt Weld Fittings.

3. Symbols and abbreviations

For the purpose of this GP, the following symbols and abbreviations apply:

ATEX Explosive atmosphere (EU standards).

D Diameter.

ESD Emergency shutdown.

FEA Finite element analysis.

GIS Geographical information system.

HIC Hydrogen induced cracking.

ID Internal diameter.

ILI In-line inspection.

LEL Lower explosive limit.

LPG Liquid petroleum gas.

MAOP Maximum allowable working pressure.

MFL Magnetic flux leakage.

NDE Nondestructive examination.

NGL Natural gas liquids.

OD Outer diameter.

PPE Personal protective equipment.

ROC Rapid opening closure.

ROV Remotely operated vehicle.

UT Ultrasonic technique.


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4. Pigging overview

4.1. Reasons to pig Use of a proper pigging program with the correct pig helps maintain the integrity and optimum efficiency of the pipeline while safeguarding both the environment and the pipeline asset. Maintenance of a clean pipeline is important, as build up of solids impacts throughput. Build-up of deposits can also create conditions for corrosion by reducing the effectiveness of inhibitors.

a. Pipeline pigging is a key part of managing the integrity of pipeline systems. Pipelines require pigging at the start and end of life. Pipelines are normally pigged for: 1. Commissioning and decommissioning. 2. Cleaning or wax removal. 3. Inventory management (sweeping out liquids, batching products, etc.). 4. Corrosion and scale control. 5. Inspection. 6. Isolation and special operations.

b. New pipeline designs may consider permanent or temporary pig launcher and receiver facilities. 1. Requirements shall be agreed with operations. 2. The project shall provide necessary equipment to facilitate pigging. 3. If traps are removed after commissioning, safe isolations and space for re-instatement

of pig traps should be left such that future inspection pigging can be safely achieved. c. Pipelines should be pigged for operational and inspection purposes on a regular basis.

1. The timing for inspection is dependent on the corrosion risk assessment and the effectiveness of detection.

2. Requirements on frequency of inspection are given in GP 43-52. d. Projects shall hand over new pipelines to operations that have been verified to be free of

debris, defects, and obstructions. A baseline ILI inspection should have been completed prior to handover.

Further guidance on ILI requirements is given in GP 43-52.

4.2. Pig types Pigs come in many different shapes and sizes, each of which requires care and attention for its selection, design, and use. Utility Utility pigs perform gaging of the internal bore, cleaning and debris removal, batch separation of products, and sweeping of liquids from the line. Pigs can either be unidirectional or bidirectional. Utility pigs are of the following types: Foam: moulded from polyurethane foam in various densities with various

configurations of solid polyurethane strips and/or abrasive materials permanently bonded to their surface.

Elastomer: moulded from solid elastomer.


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Mandrel: a central metal body with various components (cups, discs, wire brushes/scraper blades, gaging plates) attached.

Utility pigs may be run as a dual module to facilitate negotiation of tight bends or wye configurations. The coupling may be subject to high transient and fatigue loads. Specialty pigs may be used for: Wax detection. Removing hard scale with a pinwheel. Magnetic cleaning. Internal coating. Leak detection. Other functions. Gel There are four main types of gel that are used in pipeline applications: Batching or separator gel. Debris pickup gel. Hydrocarbon gel. Dehydrating gel. If used with conventional pigs (e.g., constrained between two utility pigs), gel pigs can improve overall performance. Gel is normally a diesel based highly viscous product but can be made with water and a range of chemicals, depending on chemical compatibility requirements. Gel pigs can be susceptible to dilution and gas mixing. Sphere Sphere pigs are normally used to sweep liquids from gas lines. Sphere pigs are normally either made from foam throughout or consist of elastomer skin inflated with glycol and/or water. See 4.3.1.e for more detail. Soluble spheres are sometimes used in crude pipelines and are made from a microcrystalline wax and amorphous polyethylene that acts as a paraffin inhibitor. Soluble spheres are broken up by the crude oil and do not require a receiver trap. Inspection Simple gaging plate and calliper type pigs are used to detect small and large scale geometric variations in pipeline cross section, respectively. An intelligent pig is able to detect the presence of metal loss, cracks, and pipeline features (valves, fittings, etc.) within the pipe wall, normally using either MFL or UT.

Some pigs may require an umbilical or fibre optic cable for detailed inspection close to the facility. These are called tethered pigs. Specialised pigs are also used to perform leak detection and mapping (GIS). Eddy current and video based techniques are also available. Isolation Isolation pigs are used to temporarily plug the line and may require a tether back to the launching facility.


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The differential pressure that can be resisted depends on the type of pig. Some pigs are dual module. Dual or multi-diameter A dual diameter pig functions in two distinct diameters, for example 200 mm (8 in) and 255 mm (10 in), and is able to negotiate both 200 mm (8 in) and 255 mm (10 in) pipe.

4.3. Pig selection, design, and maintenance

4.3.1. General a. The selection and type of pig to be used and its optimum configuration for a particular task

in a pipeline shall be based upon several criteria, including: 1. Purpose (e.g., linefill, batching, cleaning, or inspection). 2. Type of information to be gathered (e.g., from an ILI pig run) and data requirements. 3. Line contents (e.g., gas, oil, or water), with or without contaminants (e.g., wax) that

may need to be displaced or removed during conventional pigging operations. 4. Required driving pressure versus available pressure. 5. Minimum and maximum internal diameter, including diameter restrictions or changes

(e.g., corrosion probes, coupons, instrument taps, valves, check valves, barred or sphere tees). When multi-diameter pipelines are pigged, excessive wear of components in the smaller diameter line section shall be considered.

6. Presence of tees and wyes that may require a longer pig to ensure that the pressure driving force is maintained as the pig traverses the connection.

Foam pigs can be easily damaged and lose drive. They can also compress and enter smaller diameter connections, laterals, valves, and tappings.

7. Minimum bend radius, bend angles, and position of back to back bends. 8. Distance the pig needs to travel and the internal condition of the pipe, with regard to

wear on the cups or discs. Large diameter pigs in gas pipelines may require wheeled supporting structure.

9. Operating velocity range of the pig. Some pigs have bypass ports that enable the speed of the pig to be reduced below that of the pipeline fluid velocity. See 5.1.f.

10. Elevation profile (e.g., pig acceleration during linefill, slack line conditions for operating oil pipelines).

11. Maximum temperature and/or fluid pressure permitted. Due to onboard electronics, the maximum temperature for the UT and MFL inspection vehicles is approximately 60C (140F). Inspection tools may tolerate higher temperatures (approximately 80C [176F]) for short periods and can be launched in a batch of cold fluid.

12. Ability to drive pig in the reverse direction (e.g., for a bidirectional pig). 13. Requirements to track or communicate with the pig.

Pigs can be fitted with transponders to enable external tracking of the pig and sensors to detect external electromagnetic or radioactive systems to improve positional accuracy for inspection pigs and to trigger setting and unsetting of isolation pigs.


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b. Cleaning and brush/scraper pigs shall be configured to limit the amount of material that can be removed in a single pass to the amount that can be contained in the receiver.

Bypass ports on the pig are commonly used. Otherwise, there is a risk of blocking the line or preventing entry of the pig into the receiver trap due to the overfilling of the pig trap with solids.

c. Some pigs should be run in combination with other pigs (e.g., cleaning pig ahead of a batch pig) to determine wax quantities and number of cleaning runs required.

Where gel pigs or chemicals are used for cleaning or commissioning, separation pigs can help minimize fluid bypass. Separation pigs are usually bi-directional utility pigs incorporating a number of discs.

d. If multiple module pigs are used, the components shall be designed to allow removal if the toll separates into component parts.

This may be avoided if the rear module includes a drive cup or disk. Alternatively, the tool can be designed to allow it to be pushed from behind.

e. If inflatable spheres are utilized the following shall apply: 1. Spheres shall be filled with a water/glycol mix and ring gaged to ensure that they are

of the correct diameter. Water/glycol mix ratios are, typically 50:50 or 60:40 in accordance with manufacturer recommendations. Sphere diameters should typically be 1% to 3% greater than the ID, in accordance with manufacturer recommendations. If hydrate formation is a concern following rupture of a sphere, an increased percentage of glycol can be effective. Use of 100% glycol may deteriorate the sphere material. It is recommended that a sphere removal tool be available to remove spheres that may become stuck in launcher or receivers.

2. Inspected to ensure that the filling plugs do not leak and are replaced, if necessary. Leaking plugs have resulted in safety incidents.

4.3.2. Pig design requirements The basic design of a pipeline pig should be simple and efficient as experience has shown the more complicated the pig the more prone it is to failure. Often the features incorporated into the design is based on experience and not readily apparent. The following components should be considered when designing a pig.

a. Pig body and materials 1. The pig body shall have sufficient strength to resist the load imposed on it, including

fatigue. This includes proper design of the body attachments, pig nose, and lifting lugs.

2. Materials shall be selected to suit the pipeline contents. This may include sour service or the special selection of plastic components when used in chemical service.

b. Cups and seals The correct material shall be specified for the cups and seals based on the pipeline service,

temperature, and travel distance. The shape of the cup and seal are important to achieve the desired cleaning results.


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c. Pig Connections Nuts, bolts, and welds shall be appropriately sized and designed to avoid failure due to

direct loading conditions or fatigue. A number of pigs have failed due to improper selection and installation of components requiring special operations to recover debris left in the pipeline.

d. Bypass By utilizing differential pressure across the pig, a fluid path is created front to back of the

pig creating turbulence in front of the pig. This assists in the cleaning process and can be used to optimize cleaning.

Excessive bypass may cause pig to stall in the pipeline. e. Cleaning elements A number of types of cleaning elements are available to suit the application if pipeline

cleaning is required. Expert advice should be sought for difficult or unusual cleaning problems.

When starting a pigging program several successive runs are required to achieve best efficiency. The first run may provide the most dramatic results but improvements are seen in each additional run. It is essential that good records are maintained to determine when the maximum cleaning benefit has been achieved. This also assists in determining the frequency of future runs.

4.3.3. ATEX requirements for potentially explosive atmosphere service Operation of launching and receiving pigs has the potential to introduce pigs to hazardous environment.

a. Pigs and associated equipment containing electronics shall have the correct certification for area of operation. 1. This shall be consistent with ATEX regulations. 2. Pigs used in hydrocarbon service or pigs deploying high powered lithium batteries

shall comply with Zone 1 ATEX requirements. European regulations include requirements for ATEX certificates as a declaration of conformance for explosive atmosphere service. Pigging operations may introduce hazards due to high powered lithium batteries and there is potential for static build-up. These are covered by ATEX regulations. Guidance on application of ATEX requirements and application for pigging operations can be obtained from the ILI sector strategy team.

b. If ATEX compliant tools are not available or do not meet this classification, additional procedures shall apply.

If ATEX rated tools are not available, additional purging and isolation requirements may be needed. Requirements may be met if pigging operations can effectively remove hydrocarbons and valves seat effectively.

c. A suitable cross bonding shall be used between the pig trap and any equipment necessary to perform the pigging operation (e.g., launch/receipt tray). To facilitate this, the pig trap should be designed with suitable lugs onto which the bonding cables can be attached.

d. Pigging procedures shall address potential of ILI tools being damaged during operation, thereby exposing cables and/or components.


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4.3.4. Maintenance and inspection of pigs a. Formal maintenance and inspection procedures shall be developed for multi-use pigs to

ensure optimum performance and reduce the chance of failure during operations. b. Each pig should have a unique reference number to facilitate record keeping on number of

runs and maintenance/repair. c. The pig should be cleaned after each run with debris and cleaning materials disposal

according to regulatory and HSSE requirements. d. The pig manufacturers recommendations shall be followed for disassembly and

maintenance and/or replacement of components. Components should be inspected for fatigue and unusual wear patterns.

e. Pigs should be stored either in cradles or on end prior to use to prevent damage to cups/disks.

4.4. In-line inspection pigging requirements The main technologies for detecting pipe wall loss defects and circumferential cracks are:

MFL. UT.

Factors that affect choice of technology include: Accuracy of result: UT provides a direct measurement, while MFL readings

require processing and interpretation. Pipeline product: UT generally requires to be run in a liquid to provide an

acoustic couplant. This is less convenient for gas and multiphase lines in which arrangements have to be made to enable the pig to run within a slug of liquid. MFL is unaffected.

Cleanliness of line: UT requires a higher level of pipe wall cleanliness than MFL.

Pig speed: MFL technology may be run at higher speeds compared to UT. Wall thickness: The magnets of MFL pigs may be unable to fully saturate heavy

wall thickness pipes with magnetic flux, resulting in incomplete pipe wall inspection. Heavy wall thickness pipelines can reduce the reflection time of UT signals, causing data loss.

Effectiveness of MFL inspection in thick wall, small diameter pipes is reduced due to the small volumetric space for magnets and ability to fully magnetise the pipe wall. Thick wall lines may require a separate run to magnetise the pipe wall. An MFL tool that is set up to inspect the heavy wall pipe could over saturate thinner wall pipe, resulting in the inability to inspect the thin wall pipe. Specialised inspection pigs are required to detect cracks or laminations.

a. The performance standards for the inspection run(s) and reporting requirements shall be agreed between the operator and the ILI supplier.

The BP Global Contract for ILI sets clear expectations and requirements on both the operator and the ILI supplier. The Contract provides a common approach to the supply of ILI services with a focus on tool performance, while providing the opportunity to obtain these services through a cost efficient and transparent selection process.


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b. Operational requirements of the (pre-inspection) pigs and inspection vehicles shall be reviewed in conjunction with operational envelope of the pipeline.

This includes consideration of pipeline product (and/or specified pigging medium), vehicle material, vehicle wear, in addition to temperature, pressure, and flow (velocity) limitations. ILI tools should, at a minimum, meet the specifications required under the BP Global Contract for ILI.

c. Operator and ILI supplier shall agree on acceptable cleanliness levels ahead of the inspections and verify the cleanliness before launching the inspection pig.

d. Pipeline cleaning programme may require modifying, depending on the quantity of debris being removed from the pipeline and the condition of the pigs being recovered.

Inspection pigs require a clean pipeline to function correctly. e. A final calliper or gaging pig run shall be performed just before launch of the ILI tool to

verify that the inspection tool will not get stuck. ILI tools should only be launched if the gage/calliper run indicates no adverse features, such as valves not fully open, corrosion probes left in the line, or mechanical damage.

4.5. Pigging operational considerations

4.5.1. General a. Pigging operations shall be carried out using formally documented operating procedures. b. Only competent personnel who have had the necessary training, experience and assessment

shall be used in pigging operations. c. There are specific requirements associated with the operation, maintenance, and inspection

of pigging facilities. These are addressed in 4.6.

4.5.2. Safety and risk assessment a. Pigging operations shall have a suitably documented operating and risk assessment. b. Personnel involved in the pigging activities shall be fully informed and aware of the

associated hazards and risks. Pigging is one of the most hazardous operations undertaken during operation of a pipeline.

c. The risk assessment shall include: 1. Operating procedures including:

a) Understanding of pipeline condition and facilities. b) Previous pigging experience. c) Level of available documentation. d) Previous successful use of the procedures. e) Competency of personnel. f) Management of Change procedures. g) Simultaneous operations.

2. Pig selection and handling including: a) Pig performance (refer to 4.3). b) ATEX requirements.


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c) Cleaning requirements and assessment of pipeline condition. d) Effect of pipeline fluid on pig components. e) Potential for separation of multi-module pigs. f) Handling of pigs. g) Effect of pigging on pipeline pressure fluctuations during pigging operation.

3. Effect of pigging operations on upstream and downstream process facilities including: a) Handling the pig and any associated materials and fluids (e.g., inhibitor slugs). b) Effect on batch processes (e.g., introduction of methanol, biocide, and inhibitor

slugs) and requirements for product separation. c) Impact on processing requirements and filtration systems.

There may be an increased volume of liquids received in multiphase lines or unplanned shut-down due to filter blockages.

d) Impact of pigging operations on alarms, trips, and shutdown systems. e) Impact of process conditions on pigging operations.

Process conditions may require a shut down of the pipeline. f) Handling and disposing of waste from the pipeline found in the receiver pig trap

(e.g., wax, contaminants, such as mercury and radioactive scale and pyrophoric material).

4. Pig trap facilities including: a) Effectiveness of isolations. b) Purging of pig traps. c) Flammability of deposits. d) Operation and maintenance of trap end closures/doors. e) Lighting (may be required for 24 hour operation). f) Access and lifting.

5. Potential failure of operation requiring a contingency plan including: a) A stuck, damaged or lost pig. b) Pig location. c) Removal or recovery of a stuck or damaged pig or pig components. d) Communications.

4.5.3. Operating procedures a. A survey shall be performed to establish the physical constraints and condition of

equipment found along the system, including valves position, sealing, and maintenance. b. A review shall be carried out of previous operating history, including any operating limits

or restrictions. c. A pigging plan, including documented operating procedures, shall be developed for each

pipeline based on the risk assessment. Special consideration shall be given to new and existing pipelines: 1. That have not been pigged before or recently.


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2. That have been modified since the last pigging operation (e.g., hot tapped or repaired).

3. If there is uncertainty about the condition of line (e.g., corrosion or excessive buildup of deposits, such as hydrates and wax, or the potential of water ingress into dry gas lines, illegal hot taps, and other third party interference).

d. The pigging plan shall address the number and sequence of pigs to be used in the pipeline. Pigs may need to run in a sequential and progressive manner to build a picture of the pipeline conditions and minimise the risk to the pipeline operations and the potential for a stuck pig. Examples of a pigging sequence are: A foam pig may be run before a gaging pig. An additional gage plate larger than the initial gage plate can subsequently be

run on one of the cleaning pigs to further increase the known bore of the pipeline.

There could be a requirement for multiple cleaning runs and possible special procedures to achieve a successful inspection. Debris collected and/or damaged pigs/gage plates should be evaluated as an ongoing process and the pigging programme adjusted to achieve the best results.

1. If there is any doubt about condition of the bore, a foam pig should be initially run in pipeline.

2. Only one pig should be allowed in the pipeline (or a pipeline section between pig traps) at any time, and pig should be received and evaluated before running the next pig.

3. If two pigs, including a dual module pig, are run in the line at the same time, second pig should be capable of driving first pig in the event of seal failure of the pig.

4. Multiple pigs should only be deployed for specific reasons, such as commissioning, line purges, and special cleaning operations.

e. Pipeline inlet and outlet pressures and flows shall be monitored and recorded throughout the pigging operation.

f. Effects of pigging on the downstream process shall be assessed in design process and prior to commencement of any pigging operation.

g. Pigging operations shall be formally recorded, including the quantity of material removed from the pipeline and the condition of the pig.

h. Pigging procedures shall address what actions are to be taken in event of a stuck pig or loss of components from the pig before pigging operations begin.

i. If the known location of the pig is required, transponders should be fitted to a pig to aid detection. The type of transponder used should consider the length of time required to mobilize and detect the pig.

This is preferable on early pig runs and if there is a change in pig size. If response could be delayed due to accessibility, the use of radioactive isotopes with half life of up to 12 mo is recommended.

4.5.4. Contingency plans a. Potential contingencies available in the event of a stuck or damaged pig include:

1. Increasing the driving pressure (this shall not exceed the MAOP) and/or reducing the downstream pressure in order to place a higher differential pressure across the pig.


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2. Monitoring pressure and flows carefully. a) If the pig moves, it may accelerate and drive a high speed slug of debris

downstream. b) This may damage the inspection tool or downstream facilities and therefore

requires assessment before pigging operations begin such that procedures are clear and can be effectively communicated to all personnel involved.

c) If hydrates are the likely cause of restriction, decreasing the pressure on both sides of the pig should melt the hydrate plug.

Differential pressure across the hydrate plug should be avoided to prevent sudden plug movement.

3. Sending a driving pig behind the stuck pig, if the first pig has become stuck as a result of loss of sealing and hence driving pressure.

A foam pig is often chosen on the basis that if it too gets stuck it can be broken up by applying a high differential pressure.

4. Reversing the direction of flow if the stuck pig is of the bidirectional type. 5. Detection of the pig and investigation of the pipeline in the vicinity to establish the

cause of the blockage. 6. In an extreme case, selecting the option to resort to cutouts, replacement pipelines, or

abandonment. b. A contingency plan shall be prepared to cover loss of components from the pig. The plan

may require installation of strainers and use of a pig to sweep out the components.

4.6. Pig trap operations, inspection and maintenance

4.6.1. General a. Operators shall have formal training of pig trap operation, maintenance, and door interlock

system.

There have been fatalities worldwide associated with incorrect operation or inadequate maintenance of the door.

b. Detailed launch or receive procedure shall be developed for each location and for the type of pig being launched and/or received.

c. Detailed procedures shall be developed and used for each pig trap door type, pig trap facility, and associated fittings and equipment. These shall include the relevant manufacturers operating, maintenance, and inspection requirements.

d. Manufacturers requirements and recommendations shall be reviewed and supplementary information shall be developed if these are vague or unclear.

e. Procedures shall be prepared to address the inspection, maintenance, and replacement of components with recommended frequencies.

f. Elastomeric and polymeric seals shall be selected for suitability with process conditions, including any trace media, such as methanol, glycol, and corrosion inhibitors. Seals used in gas service shall also be selected for resistance to explosive decompression.

g. Pig trap end closures shall comply with the requirements of 6.8.

4.6.2. Operating procedures a. Pig traps shall be regularly inspected to ensure containment and verify that the pressure

within the trap is in accordance with operating procedures.


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This is due to the potential for valves to pass over time and for the trap to pressurise.

The practice of leaving the pig trap pressurised and online depends on operational circumstances. For multiproduct pipelines, pig traps are often left online to prevent contamination of batches. Keeping a flow through the pig traps can reduce the effect of dead legs, solid drop out, and corrosion risk. Each case is subject to local conditions.

b. Spheres shall not be left in pressurised launchers/receivers for extended periods. Gas from the pipeline may enter the spheres through leaking plug seals, causing spheres to expand in the enlarged diameter of the launcher/receiver, resulting in a tight fit. This could result in a serious injury if the pig trap depressurised and gas was trapped behind the over inflated sphere. See lesson learned in Annex C.

c. Risks of leaving the pig trap pressurised and online shall be assessed, including appropriate settings for relief valves.

d. When pig traps are left offline, a path for thermal pressure relief, complete with suitable discharge, shall be included to protect against temperature and pressure changes.

e. Air that may have been introduced into a pig trap from loading pigs or spheres should be removed before repressurising the pig trap. Removal can be achieved through direct gas or liquid purging or with nitrogen.

This applies to pig traps used for hydrocarbon gas systems and volatile hydrocarbon liquids.

f. Pig trap door seals shall be tested before the pig trap is left unattended. This can be done as an initial seal test followed by a full in service product test.

g. Sour gas or wet gas service traps should be left purged and depressurised.

4.6.3. Flushing and purging of pig traps a. Selection of flushing and purging method shall depend on the:

1. Fluid or product transported. N2 can be used with NGL pipelines and ethylene and dense phase CO2 pipelines to manage the phase transition temperatures on depressurisation. Extreme cold temperatures generated can cause damage to pigs and reducing pressures in nitrogen rather than with product can mitigate this effect. For multi-product lines, a higher flash point liquid is often used as a flush medium with a N2 purge.

2. Expected contents of pig trap receiver. Pigs shall be cleaned immediately on removal from the pig trap if pyrophoric material is present.

Pyrophoric material can be a hazard in some systems. These require purging and facilities to keep any solids wet.

3. Design of the pig trap. Effectiveness of purging depends on the design of the pig trap and the presence of hydrocarbon liquids or solids. Liquids or solids can become trapped in dead legs in the bottom of the trap or between the drain point and the pig trap door. In some systems, residual gas pressure is used to aid sweep out of liquids. N2 has been used in some cases. Effectiveness of purging also depends on the effectiveness of the pig trap valve seals.


Page 18 of 52

4. Frequency of pigging operations. 5. ATEX rating of pigs and equipment used.

b. Risks associated with the use of the selected purging medium shall be assessed. N2 can introduce additional risks and has limited benefit if hydrocarbon liquids or solids are present. Nitrogen may be available from onsite generation or bottles. There have been a significant number of incidents with N2 asphyxiation, and N2 may not be the most appropriate medium for purging or flushing pig traps. Flushing with hot fluids, particularly water and steam, can introduce other problems of static discharge. On tanker cleaning operations, these are combined with inert blanket systems.

c. For a gas pipeline that has potential for water dropout (which would be disturbed by pig, leading to hydrate blockage), a slug of hydrate inhibitor should be introduced in front of pig. 1. Availability of purge medium onsite.

Alternative purging and flushing media to N2, including air, water, or C02, may be possible. Such a sequence may include water flush followed by an air purge.

2. Competency of personnel. d. For managing risks associated with pig trap operations, purging shall not be taken in

isolation to the other mitigation measures available. See Table 1.

Table 1 - Managing risks of pig trap purging operations

Media Hazard Mitigation Explosion Design to zone.

Natural venting. Purge. Procedures.

Gas

Asphyxiation or narcotic

PPE (breathing apparatus). Purging to give safe atmosphere O2 rich (can still cause asphyxiation). Remote actuation. Procedures. As above for gas. Zone design.

Explosion plus asphyxiation or narcotic plus spillage Verify empty before opening door.

Containment. Flush trap.

Liquids

Mercury Flush and use of protective clothing and equipment. General Flush.

Zone design. Pyrophoric material Purge/flush and keep wet.

Solids

Radioactive scales Flush and use of protective clothing and equipment.

The volume of purging medium required for large diameter pig trap can be considerable. This can introduce additional risks of transporting multiple packs of nitrogen bottles or from generation equipment with pressure vessels. The risks from these activities can exceed the risks associated with the initial operational risk of free hydrocarbons at the pig trap.

e. Specialised equipment shall be used to determine effectiveness of an inert gas purge.


Page 19 of 52

If monitoring LEL limits, it is important to recognise that gas monitors may not work accurately in atmospheres that are deficient in oxygen.

f. Subject to local conditions, equipment available, and risk assessment outcomes, Table 2 summarises recognised practices.

Table 2 - Recognised purging practices across the BP Group

Product Comment Sour gas Purge to bring toxicity levels down. Chemicals Product specific - purge if highly flammable or toxic. Dry gas (sales gas - water and hydrocarbon liquid dry)

Purging can be effective, but should be site specific, as it depends on frequency of operation and introduces new risks. Purging needs a risk evaluation.

Wet gas (hydrocarbon liquids and water present)

Limited effect depending upon pig trap design.

NGL/gas condensate Limited effect depending upon pig trap design. Aviation fuel Purging has limited effect, as it is difficult to remove

hydrocarbons. N2 may introduce additional risks. Multi products Purging has limited effect, as it is difficult to remove

hydrocarbons. N2 may introduce additional risks. Live crude Light oil flush followed by water flush. Stabilised crude Water flush. Pyrophoric material Purge and keep wet. Radioactive scale Flush and use containment.

4.6.4. Inspection and maintenance a. End closure

1. The end closure shall be included in the pipeline or facility integrity management system and shall be maintained in accordance with the manufacturers recommendations.

2. The pig trap and end closure shall be regularly inspected for damaged or worn parts in accordance with the manufacturers recommendations. The trap shall not be used unless it meets these requirements or is repaired.

Particular attention should be given to potential defects in any securing bolts, nuts, and nut housing, their method of attachment, and buildup of corrosion products that interfere with the correct operation of the mechanism. Particular attention should be taken to ensure that water/moisture cannot collect in the crevice at the bottom of the door, which may affect seal faces.

3. Some surfaces on clamp type designs should not be greased because the retention of the pig is part based on friction.

4. Dismantling and close visual inspection of main load bearing components for any sign of deterioration, including corrosion, distortion, deformation, cracking, wear or loss of surface finish on sealing surfaces, shall be undertaken as recommended by the closure manufacturer.

5. Seals shall be inspected each time door is opened and shall be replaced as necessary. 6. Replacement is required if seals show signs of compression set (permanent

deformation), extrusion, splitting, blistering, softening, hardening, aging, and/or any mechanical damage, such as scuffing.

7. If failures are repeated, a failure investigation shall be conducted, with a view of selecting alternative materials.


Page 20 of 52

8. Seals shall be replaced in accordance with manufacturer recommendations. 9. Spare seals shall be stored in accordance with manufacturer recommendations. 10. If there are problems in obtaining leak tightness of end closure, causes should be

investigated and, if appropriate, a leak test should be performed. Bolting shall not be over tightened.

11. Bolts and threaded fittings shall not be tightened or loosened under pressure.

4.6.5. Inspection and revalidation of pig traps a. Pig traps shall be inspected and revalidated for continued operation at regular intervals not

normally exceeding 5 yr. Local regulations, requirements, or service conditions may require more frequent inspection and testing.

b. Inspections shall be performed by a competent engineer, who shall make reference to the manufacturer recommendations for inspection and maintenance of end closures.

c. Revalidation may require periodic hydrotesting in accordance with manufacturers recommendations.

5. Pipeline design for pigging

5.1. General The following design requirements shall be considered for pigging: a. Strategy for selecting equipment should be developed early in the project to ensure that

equipment will operate as intended (pig compatibility with wyes and tees, etc). b. Design of pig trap facilities should include input from operations personnel. c. Type of pigging activities required (construction, operation/inspection/maintenance,

shutdown, or repair). Preference for permanent or temporary pig launchers/receiver depends on size, pipeline risk assessment, and frequency of pigging. Portable traps may be appropriate for use in pipelines that form part of a network and if pigging is required only for inspection and not routine operations. Temporary pig traps for pipelines larger than 600 mm (24 in) may not be practical because of difficulties in transport and lifting.

d. The beginning and end of a pipeline shall have pig launchers and receivers. Intermediate pigging station requirements should be dictated by changes in pipeline diameter, pig driver cup wear, and the quantities of solids or liquids likely to build up in front of a pig.

Other factors for consideration that could influence the wear rate of the pig seal mechanics include pipe wall condition, pipe wall lining, if any, pig material compatibility with the product, pigging medium, and pigging speed.

e. Type of product, including any contaminants or additives. f. Minimum and maximum design velocities for oil and gas service are driven by pressure

drop, noise, and vibration. The optimum pig speed is typically 1 m/s to 3 m/s (3 ft/s to 10 ft/s).

Use of variable speed control systems or bypass arrangements may be considered to achieve this range. If pig speeds are outside of this range, effectiveness of the pigging operation may be compromised. Specialised advice is normally required from ILI vendors on the maximum pig speed range to achieve the inspection requirements.


Page 21 of 52

Flow rates may need to be adjusted for the time of pigging operation. Pig speeds may be achieved in high velocity lines by using variable flow bypass controls or fixed bypass arrangements. Some inspection pigs cannot operate at low velocities. This depends on the type of signal generated and if the signal is recorded by time or distance. The minimum speed for some tools is typically 0,3 m/s (1 ft/s). Receipt of pigs may be controlled by having no flow or low flow through the kicker line such that the pigs stop in the main line tee before entry into the receiver trap. Inspection pigs require a restricted flow range to ensure smooth passage along the pipeline, avoiding any tendency for stick and slip.

g. Relative position and distance between valves, tees and/or laterals, type of bends (cold, heat inducted, fabricated), and bend radii.

h. Pipelines should be designed to allow deployment of isolation pigs for safe pipeline and facilities maintenance.

Deployment of isolation plugs may impose greater restrictions on changes to internal diameter close to the facility. Deployment of isolation plugs has been necessary on some installations when pig trap isolation valves or the facility Isolation or Emergency Shut Down valves need maintenance work. The ability to deploy an isolation plug can reduce pipeline shut down times.

i. Proven capability of a multidiameter pig to pass through pipeline system if significant bore changes are present in the pipeline system.

j. Potential for enhanced internal corrosion if the pipeline requires frequent use of scraper pigs.

k. Use of temporary tankage to collect debris.

5.2. Internal diameters of linepipe a. Consideration should be given to minimize changes to the internal diameter of the pipeline,

including ovality tolerances. b. Internal diameter changes should be made with a minimum transition slope of 1:4. c. If the use of plugs is anticipated, required tolerances on ID should be strictly controlled. d. New pipelines should be designed to allow deployment of an isolation plug beyond the

ESD valve. e. Diameter changes should occur only at the ends of the pipeline system or pipeline section

(at pig traps, valves, subsea sleds, etc.). Since nominal pipe sizes are based on outside diameter, changes in wall thickness result in changes to the internal diameter. Typical limits for deviation of internal diameter from the normal is approximately 4 mm (0,16 in) and 20 mm (0,8 in) for a 100 mm (4 in) and 500 mm (20 in) pipeline, respectively. For thick wall pipe applications (e.g., deep water), consideration may be given to specifying pipe based on a constant ID to avoid large transition changes.

5.3. Bends for pigging a. Bends for pigging should be limited to an out of roundness of 5% of diameter. b. Bends for pigging should be 3D or greater (where the radius is three times the nominal

pipe diameter).


Page 22 of 52

Longer radii may need to be considered if thick wall bends are used. Most ILI vehicles will pass a three dimensional radius bend, and some are available that will pass a tighter radius. Pipelines less than 100 mm (4 in) diameter may require longer bend radii for ILI.

c. Offset bends of 30 degrees or greater should have a minimum straight length between them of 2D. Back to back bends should not be used, as they may limit suitability for ILI.

d. Mitred bends shall not be used. e. If there is the potential need for the use of a tethered pig for inspection, use of bends

should be kept to a minimum to avoid excessive loads on the cable connection.

5.4. Valves, check valves, tees, and wyes a. Valves specified for pigging purposes should be full bore, with specified minimum internal

diameter, limited or zero bypass, and compatible with product. Valves shall facilitate uninterrupted passage of pig.

b. Check valves should be through conduit (full bore) type valves or have method of externally locking flapper in fully open position for inline inspections.

c. Check valves and wyes shall be verified to confirm that pig length between front and rear cups is longer than any opening or cavity.

d. Barred or sphere tees shall be installed on branches larger than 50% of pipeline diameter and if sphere or foam pigs are intended to be used.

If there is a risk of corrosion, consideration should be given to using alternative materials or providing a drain connection on the sphere tee, since dead leg areas of sphere tees are more susceptible to corrosion.

e. If spheres or foam pigs are to be used, sphere tees should be installed in preference to barred tees.

f. Wyes shall have a demonstrated capability for passage of inspection pigs (i.e., test at full scale before using the pig in the pipeline).

The bore may be 10% oversized to reduce friction within the wye. A wye may be arranged such that gravity assists the pig passage. Convergence angles of 30 degrees have been found to be optimal.

g. Barred tees 1. Barred tees shall be designed such that the barring does not cause excessive stresses

at the junction of bars and tee crotch area as the tee dilates under pressure. 2. A minimum of two guide plates should be used to prevent the pig from entering the

branch pipe. 3. Guide plates shall be welded across the tee branch pipe and along the flow direction

to prevent pigs from becoming stuck at the junction or from being wrongly diverted with the flow.

4. Welds shall be ground to avoid stress concentrations where tee branch pipe connects to main pipe and where guide plates are welded to and tapered along blend radius.

5. Guide plates and weldments shall be smooth and free from sharp edges to prevent damage to pipeline pigs.

6. Guide plate thickness and plate to plate spacing varies depending on tee branch size. A nominal guide plate thickness of 9 mm to 19 mm (0,375 in to 0,750 in) and guide plate spacing of 64 mm to 76 mm (2,5 in to 3,0 in) are typical.


Page 23 of 52

7. Optimum guide plate spacing is equidistant from adjacent plates and tee branch pipe walls.

8. Figure 1 provides barring design details.

Figure 1 - Barred tee design detail

5.5. Pig handling equipment a. Permanent pig handling facilities, such as anchor points, winches, and a lifting gantry or

hoist to facilitate loading or removal of pigs from the pig trap, may be required, depending on the size and type of pigs used and frequency of operation.

The requirements for pig handling depend on the type and weight of pig and the pipeline size. Pigs less than 30 kg (66 lb) (corresponding to approximately 300 mm [12 in] and smaller pipe size) may be manually loaded into or out of the pig traps. Davit and branch refers to a manually operated system consisting of a cradle bench with a winch and a free standing swing jib crane, with the cradle bench either trolley mounted or suitable for fixing structurally adjacent to the trap end closure.

NOTES: MAX. CLEARANCE = 6 mm () AND MIN. CLEARANCE = 0. SCRAPER BARS SHALL BE EQUALLY SPACED OVER THE INTERNAL

DIAMETER OF THE TEE. SCRAPER BAR MATERIAL SHALL BE THE SAME MATERIAL AS THE TEE. MATERIAL SHALL BE APPROPRIATE TO PIPELINE DESIGN CODE

6 2 (9.5) 1 (25.4)

8 2 (9.5) 1 (25.4)

10 3 (9.5) 1 (38.1)

12 3 (9.5) 1 (238.1)

14 3 (9.5) 1 (38.1)

16 4 (12.7) 2 (50.8)

18 4 (12.7) 2 (50.8)

20 4 (12.7) 2 (50.8)

24 5 (19) 3 (76.2)

30 6 1 (25.4) 5 (127)

36 7 1 (25.4 5 (127)

NOM. PIPE SIZE

NO. OF SCRAPER

BARST

IN. (MM)H

IN. (MM)


Page 24 of 52

Cassettes enable the pig or spheres to be preloaded in multiples and loaded into a launching trap in one operation. Cradles, if used with launching traps, can be loaded externally and allow pig to be moved into its launch position via a winch/plunger mechanism, and for receiving traps, the incoming pig comes to rest in the internal cradle, allowing for its removal from the trap.

b. Cassette and cradle pig handling equipment shall be designed and installed as an integrated part of the trap to preserve its integrity as a pressure vessel.

Consideration should be given to ensuring unimpaired use of any high pressure cleaning nozzles located within the barrel to facilitate removal of debris and wax from the trap.

6. Design of pig trap installations

6.1. General a. Design of pig trap facilities shall include input from operations personnel and take account

of layout, access, lighting, equipment handling, cleaning, etc. b. Typical pig launchers should be configured as shown in Figure 2 and pig receivers as

shown in Figure 3.


Page 25 of 52

Figure 2 - Typical pig launcher

*

!

"#

"

$

%

%&%

%

LONGEST ILI PIG SHORT AS POSSIBLE

XI

LONGEST ILI PIG

*

XI

3 M IF REQUIRED FOR ISOLATION PLUG BUT MAY NOT BE NEEDED IN MOST INSTALLATIONS

*

TO CONFIRM PIG CLEARED TRAP VALVE

TO CONFIRM PIG ENGAGED

TRAP

IS

OLA

TIO

N VA

LVE

LONGEST ILI PIG SHORT AS POSSIBLE

XI

LONGEST ILI PIG

*

XI

3 M IF REQUIRED FOR ISOLATION PLUG BUT MAY NOT BE NEEDED IN MOST INSTALLATIONS

*


TO CONFIRM PIG ENGAGED

TRAP

IS

OLA

TIO

N VA

LVE

Note: Kicker and balance lines and purge points omitted to simplify drawing.


Page 26 of 52

Figure 3 - Typical pig receiver

c. In addition to the factors for pipeline design, in 5, design of pig traps should incorporate the following: 1. Applicable design codes. 2. Service conditions. 3. Minimum temperature. 4. Physical interface with pipeline (e.g., insulation flange).

*

"

%&%

%

%&%

%

%

TRAP

IS

OLA

TIO

N VA

LVE

LONGEST ILI PIG + 0.5 M

XI

MORE THAN LONGEST ILI PIG


XITO CONFIRM PIG ARRIVAL

*

BARREL LONG ENOUGH TO HOLD DRIVE MODULE + DEBRIS. (SOME PIGS MAY HAVE DRIVE ON LAST MODULE)

*

TRAP

IS

OLA

TIO

N VA

LVE

LONGEST ILI PIG + 0.5 M

XI

MORE THAN LONGEST ILI PIG


XITO CONFIRM PIG ARRIVAL

*

BARREL LONG ENOUGH TO HOLD DRIVE MODULE + DEBRIS. (SOME PIGS MAY HAVE DRIVE ON LAST MODULE)

*Note: Kicker and balance lines and purge points omitted to simplify drawing.

Relief Valve

Bypass Valve

Balance Line

"


Page 27 of 52

5. Types of pigs to be run. 6. Pigging schedule. 7. Materials of construction (compatibility with product, brittle fracture). 8. External loadings (from pipework, particularly subsea). 9. Operating cyclic loading and nozzle reinforcements (e.g., as a result of repeated trap

pressurisation and depressurisation). 10. Structural supports and lifting lugs. 11. Wind and seismic loadings. 12. Snow and ice loadings. 13. Blast loading, if applicable. 14. Transportation loads. 15. Pig handling systems (e.g., lifting gantry, pig trays). 16. Permanent or modular skid mounted unit. 17. Trap closure mechanism. 18. Barrel venting/draining rate. 19. Volume of debris (e.g., wax) to be removed and capable of being retained in the trap.

Inspection pigs usually require longer pig traps than utility pigs, which in turn affects the volume of product that may need to be disposed of before the trap is opened following a utility pig run.

6.2. Service conditions and code requirements a. Pig trap is part of the pipeline system, and applicability of pipeline design code should

extend to the trap, pipework, and up to and including the first isolation valve out of the pig trap.

Local regulations may influence selection of the code break point. b. Pig traps, including barrel, fittings, and attachments, shall be designed, fabricated, and

tested as part of pipeline system. Pig trap door closure shall be designed in accordance with relevant pressure vessel codes.

Requirements for pressure vessels are given in GP 46-01, and standard details are in GIS 46-020. Pressure vessel codes include ASME Boiler and Pressure Vessel Code Section VIII, Division 1, PD 5500, or BS EN 13445.

c. Design pressure of pig trap shall be no less than pressure of pipeline. d. Pig trap shall be:

1. Suitable for testing with pipeline. 2. Assessed for stresses during pipeline hydrotest condition and pressure vessel

hydrotest condition, whichever is greater. e. Pig trap system may be hydrostatically tested either together with or separately from

pipeline. f. Cyclic loading shall be considered for trap and trap closure mechanism due to temperature

and pressure. Cases are on record for which there has been pipeline movement due to ratchetting caused by successive temperature cycles over time.


Page 28 of 52

g. Maximum design temperature shall not be less than maximum temperature that the pig trap system could attain or to which it could be exposed during operation, startup, or shutdown.

h. Consideration shall be given to pressure increases arising from thermal gain in the event of shut-in conditions (e.g., due to solar radiation).

i. A minimum design temperature shall be stated and shall be based on minimum ambient temperature and on the conditions (e.g., blowdown, which could occur during operations).

j. An internal corrosion allowance should be considered, even if such an allowance has not been made for pipeline to which it is connected. A corrosion allowance may be required because of the different internal and external conditions associated with the trap.

6.3. Layout requirements

6.3.1. General a. Pig traps shall be designed to allow access to the pipeline for inspection and maintenance. b. Pig traps shall generally be:

1. Located based on overall site risk assessments, considering potential release of hydrocarbons, potential for ignition, and classification of areas.

2. Adjacent to each other for ease of pigging operations. Separation distance from launcher closure to receiver closures should be at least 1,5 times the length of the longest inline inspection tool anticipated.

3. Orientated with their end closures pointing away from personnel and critical items of equipment.

Accidents have occurred resulting in door failure and pigs exiting the pig trap at high speed.

c. Suitable access space should be provided beyond the end closure door for pig handling. A covered protection to the trap enclosure area may be required, depending on the climatic conditions.

d. Suitable access space should be provided for maintenance of equipment. e. The trap should normally be horizontal, with vertical traps used if space is a premium.

Vertical orientation of the pig receiver is not normally recommended, as debris can fall and accumulate in the pig trap valve.

f. The elevation of the bottom of the end closure on horizontal pig traps should be approximately 700 mm (28 in) and not more than 1 100 mm (43 in) above the working surface to provide sufficient room to slope the drain lines, as well as facilitate easy handling of end closure and pigs.

g. A platform shall be provided adjacent to any equipment (e.g., valve, pig signallers) that is: 1. More than 1 500 mm (60 in) above grade (centre of the handwheel in the case of a

valve). 2. Used during pigging operations and/or for maintenance.

h. Consideration shall be given to the requirements for handling of contaminated pigs and displaced solids.

There may be a need for sumps, containment areas, cleaning facilities, and an ergonomic layout such that contaminated pigs can readily be transferred from the receiver to the cleaning area.


Page 29 of 52

i. Pig trap layout should be such that operation and maintenance of equipment, valves, and instruments shall be possible without temporary ladders and scaffolding.

j. Access ways shall be provided to and from pig storage area. k. Pig traps shall drain by gravity into appropriate drainage area. l. Consideration should be given to potential blockage of permanent drains and tanks. m. If a drain system is not available, provision shall be made for waste to be collected for

disposal to designated disposal area. n. Adequate lighting shall be provided for pigging operations if 24 hr operations are required. o. Spading is not recommended as a regular method of providing positive isolation of the

launcher/receiver vessel. p. Protection of door and locking mechanism from the elements/weather should be

considered for traps in exposed locations and may be subjected to sea spray or debris from drilling operations.

6.3.2. Onshore additional requirements a. Pig traps generally should be located at least 15 m (50 ft) away from any type of

equipment that could provide a source of ignition. b. Pig trap systems should be fenced (either separately or as part of adjoining facilities), and

facilities should be provided for vehicle access. Access may also be required for lifting equipment, etc.

c. If the facility is unattended, valves shall be secured and locked in their proper position. d. A catch pit or tray shall be constructed directly underneath end closure with sufficient

volume and surface area to prevent any oil or debris contamination of surrounding ground. Pit or tray shall be easy to empty and clean and shall have a safe means of access.

The use of a sump instead of a closed drain system may be appropriate if significant volumes of wax, debris, and unwanted liquids, etc., are removed from the pipeline.

6.3.3. Offshore additional requirements and vertical pig traps a. Pig traps shall be installed in open areas to ensure adequate ventilation. b. Vertical pig traps shall have a pig lifting facility. c. Convenient access to the door locking mechanism should be provided, particularly for

vertical traps in which the barrel and end enclosure are above deck level. d. A vertical ladder or local stairway shall be provided to allow access between deck levels

local to pig trap. e. Barrel drain port should be located near main trap valve on vertical launchers. f. Any branch connection reinforcement shall be designed for minimum weight. g. Vertical vessels shall have lifting lugs or trunnions to facilitate handling during transport

and erection at site. h. During each operation, door centralising mechanism/lugs should be inspected to ensure

correct landing of door each time it is used. Any damage to this system shall be repaired as soon as possible.

6.4. Structural supports and lifting lug design a. Permanent supports/clamps shall be used to support and restrain pig traps.


Page 30 of 52

b. Supports/clamps shall be designed to carry the weight of the pig trap system filled with highest density fluid likely in service (usually water), together with the weight of intelligent pigs, if applicable.

c. Saddle supports shall be designed to applicable pipeline code or vessel code being applied to trap.

For ASME Boiler and Pressure Vessel Code Section VIII vessels, see GIS 46-010, AA 7.2.e.

d. Supports under the barrel should normally be sliding/clamp type to compensate for expansion of unrestrained part of pipeline.

e. Welded supports, if used, shall comply with applicable pipeline design codes. f. If there would normally be a potential for corrosion occurring under clamps, isolation

material shall be used between clamp and pipe and provisions shall be made to facilitate inspection.

Other support requirements may apply to vertical traps. g. Piping supports may be fixed if design calculations indicate that sufficient flexibility is

incorporated in pipework to compensate for axial and transverse movements of trap. h. Electrical isolation joints, if used, shall allow sufficient movement to avoid stressing of

joint above its design limit. i. Supports may need to be electrically isolated if isolated joints are not used.

Typical earthing (grounding) details are given in GIS 46-020. j. Supports should be positioned such that pig trap valves can be removed for maintenance or

replacement without removal of barrel. k. Lifting lugs and trunnions shall comply with GIS 46-010. l. Launchers and receivers shall be bonded into earthing (grounding) grid for facility.

Integrity of the pipeline cathodic protection system shall be maintained. m. Electrical surge arrestor installation should be considered for insulation joints in

launcher/receiver pipework.

6.5. Pipework and pressure and instrumentation requirements

6.5.1. General a. Pipework not designed to the pipeline code should comply with ASME B31.3. b. Closed drain systems should be designed to handle debris flushed from pig traps. c. Pipework connections should be flanged to allow maximum flexibility during

commissioning and future modification, if required. d. Pipework should be a minimum of 50 mm (2 in) for robustness. Sizing of drains, vent

lines, and pressure gage tappings shall take account of trapped volume, phase of product, and risk of blockage.

Pressure gages have produced false readings because of blockage. e. For pipelines above 350 mm (14 in) and any prone to waxing or other blockage,

consideration shall be given to using 100 mm (4 in) connections off trap to first valve, even if it is reduced thereafter.

The size of the pipework may be dictated by use of the pig trap during pipeline testing. In these circumstances, a larger diameter connection may be needed with a reducer fitted to the line, if necessary.


Page 31 of 52

f. System interlocks 1. System interlocks or special provisions shall be used to ensure the safety of personnel

operating the pig trap and prevent accidental release of pressure from the pig trap. Well written, risk assessed, operating procedures executed by competent operating personnel qualified on the procedures are needed to satisfy the definition of special provisions.

2. Interlocks should be provided between the closure and isolating valves, namely main inlet and outlet, vent, and drain isolating valves.

3. System interlocks or special provisions may be incorporated to prevent accidental opening of both end closure and any valves (e.g., particularly remotely operated pig trap valves and isolating valves) exposed to pipeline pressure while the trap vessel is open.

4. The interlock mechanism should allow for precommissioning and commissioning of the system (e.g., by providing additional keys).

6.5.2. Kicker and bypass lines The kicker line enables diversion of the pipeline fluid through the barrel to launch and through the bypass line to receive a pig.

a. For launch traps the kicker line shall be connected to major barrel as close as possible to the end closure.

b. For receiver traps the bypass line shall be connected as close as possible to the reducer. For bidirectional pig traps, the kicker line could be located approximately halfway along the major barrel, or twin kicker lines could be provided.

c. Kicker line should be at least 25% of the pipeline diameter and not positioned at bottom of the barrel.

The usual positions are 9 oclock, 12 oclock, or 3 oclock on the barrel but not at 6 o'clock.

d. For receive traps where the kicker and bypass lines are more than 50% of the pipe diameter a barred tee or sphere tee design shall be used.

6.5.3. Balance line

Balance lines prevent the pig from moving forward from the launch position, hitting and potentially damaging the main trap valve, or moving backwards and losing its seal in the trap reducer. On receivers, the balance line ensures that the pressure across the pig is balanced throughout the depressurisation of the trap such that there is no risk of trapped pressure which could eject the pig if the door is opened. There have been fatal accidents because of this.

a. Launchers shall have product balance lines to enable barrel to be filled and pressurised on both sides of pig at the same time.

b. Receivers shall have balance lines or vents as specified in 6.5.6 to ensure depressurisation on both sides of pig.

c. Balance line that branches off from kicker line shall be connected to minor barrel as close as possible to the pig trap valve.

6.5.4. Pressurising lines a. Pressurising lines should be provided around kicker valve and mainline bypass valve to

facilitate pressurisation of pig trap.


Page 32 of 52

b. Size of pressurisation lines should be appropriate for line size.

6.5.5. Drain line

a. Drain lines that may be prone to blockage and minimum size of pipework shall comply with 6.5.1.d and 6.5.1.e.

b. Potential for blockage shall be addressed in the risk assessment and pressure rating for the system.

c. For pipelines larger than 305 mm (12 in), minimum size of pipework shall be 100 mm (4 in).

If line is in clean service products, a smaller diameter may be used. d. Provision shall be made for flanges and break points to add extra connections and

temporary tankage or to clear blockages. e. Dead legs shall be avoided. f. The barrel drains shall:

1. Be located near trap end closure on horizontal launchers. 2. Be located near main trap valve on horizontal receivers susceptible to presence of

liquids. 3. Have two drain points located together near the trap end closure and be separated by

half a sphere diameter on receivers that are sloped for sphere pigs such that drains cannot be blocked by the spheres.

g. Barrel drain lines should be sloped at least (1:300) towards closed drain system or designated open drain.

h. Drain point near end closure shall have a 50 mm (2 in) branch connection incorporating a 25 mm (1 in) telltale valve to provide a means to check that liquid is drained before opening the end closure.

i. If pig traps are used for both launch and receive operations, special requirements apply.

6.5.6. Vent/flare/blowdown lines a. A vent line shall be provided to vent/purge the barrel. The vent should be connected to a

drain or vent system to minimise the potential for ignition. The position of vent lines on vertical traps may result in pockets of trapped air if operating in liquid service. Operational procedures may require bleeding air from the system prior to full pressurisation.

b. Barrel blowdown/vent lines shall be at least 50 mm (2 in) and positioned near trap end closure or the highest point on the trap barrel assembly.

c. Vent lines shall also be positioned near pig trap valve to ensure depressurisation behind a pig in the event of being stuck in minor barrel.

The latter recommendation particularly applies to horizontal pig traps and sphere launchers/receivers.

d. High pressure gas systems shall have a blowdown line, incorporating a globe valve or restriction orifice, for controlled depressurisation.

Note: If a restriction orifice is used in the vent line, pipework upstream of orifice should be designed and hydrotested to withstand full line pressure.


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e. Pig traps can contain air or air/hydrocarbon mixtures, which shall be taken into account if connecting to flare systems.

6.5.7. Other service lines and storage facilities Service lines may be required for air, water, steam, and nitrogen for purging of the pig trap, etc.

a. Facilities shall be provided for cleaning and purging of sand, wax, and debris from receivers and launchers. Facilities may include nozzles for the injection of steam or hot oil for the removal of residual wax.

Dedicated tankage may be required to receive contaminated product at the receiver trap.

For example, chemical treatment slugs and pig clouds generated at the interface between different refined products.

b. Chemical injection points shall be fitted as illustrated in Figure 2. See 6.1. This is required for injection of chemicals used in batch processes, etc., product separation, and gel pigs.

6.5.8. Thermal relief and pressure gages a. Thermal relief valve shall be provided at trap locations in which the anticipated shutin

pressure of the product could possibly exceed the design pressure of the trap (e.g., as might arise from solar radiation in liquid pipelines).

b. Pressure gages with a gage dial of 100 mm to 150 mm (4 in to 6 in) diameter shall be located at the 12 oclock position on the barrel to be visible to trap operator.

The gage is normally positioned near the end closure, but other locations to consider include positioned on the neck piping, downstream/upstream of the trap bypass valve, and downstream of the mainline trap valve. Requirements about fitting details are given in GIS 46-020.

6.5.9. Pig passage indicators a. Pig passage indicators shall have a mechanism that provides a position indication that a pig

has passed and that can be installed, removed, or replaced without pipeline shutdown. Optional types of indicators to consider include temporary external nonintrusive electrical, manual/electrical, extended lengths.

b. Pig passage indicators shall be bidirectional, installed flush with the internal pipe wall, and retractable/replaceable under pressure.

They may have a micro switch for remote signalling and may include an external temporary mount for pig tracking.

c. Pig passage indicators 1. Pig passage indicators shall be considered on both sides of the main trap valve. 2. On launchers, one sited upstream of the mainline trap valve and one sited downstream

of the mainline valve at a distance at least the length of longest pig anticipated to confirm the pig has left the trap and valve.

3. On receivers, one sited on the trap neck piping and separated upstream from the mainline trap valve by a distance that is equal to the length of the longest pig anticipated to confirm receipt of the pig and that the pig has cleared the valve.

4. An indicator should be provided upstream of the main pig trap isolation valve to confirm arrival of the pig at the installation.


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6.6. Valves

6.6.1. General The general issues of isolation and valve type selection for pig trap valves are covered in detail in GP 43-35, GIS 43-351, and GIS 43-352. General requirements on valve type selection are provided in GP 62-01.

a. Double block and bleed isolation is required for any pigging operation. Preference is always for two separate pig trap isolation valves, especially for pipelines in which pigging is a frequent activity or critical to ongoing operations and failure of a seal cannot be tolerated.

b. A strategy shall be developed to facilitate maintenance or replacement of pig trap isolation valves.

c. Isolation of the main pig trap should be designed to facilitate maintenance and/or future modifications to the pig trap and pig trap isolation valve without a pipeline shutdown.

This can mean inclusion of sufficient distance between the receiver/launcher main trap valve and the local bypass tee to allow setting of a remote setting plug to provide isolation, if a second valve is not available.

d. Appropriate valve seats shall be selected for the particular service conditions. This is affected by the type of service (e.g., solids content and chemical) and degree of leak tightness required (e.g., LPG).

6.6.2. Pig trap valve For mainline valves on sphere traps, consideration shall be given to designing for multisphere launching with or without automated valve actuation.

Such arrangements require careful design and have proven troublesome in the past due to spheres hitting the valve and damaging the seats.

6.6.3. Other valves a. The bypass valve shall be a tight shutoff ball, lubricated balanced plug valve, or slab type

gate valve. b. Kicker line valves in gas service shall be capable of withstanding high velocities if used in

throttling mode against differential pressure. Kicker line valves shall also be capable of opening against differential pressure and providing acceptable shutoff.

c. Lubricated balanced plug valves are recommended. Metal seated ball valves are also acceptable.

d. If there may be a throttling requirement, soft seated ball valves and gate valves of any kind shall not be used for this duty.

Gate valves have no effect on flow until they are almost closed but generate high velocities. Soft seated ball valves may suffer damage to the soft seat insert.

e. Pressurising valve arrangements shall include an isolating valve and, preferably, include a throttling valve.

f. Isolating valve shall be installed on bypass line side for tight shutoff of the pressurising line, and the throttling valve shall be installed on the balance line side to control the flow in the pressurising line.

g. A balance valve shall be provided in the balance line such that flow can be diverted behind the pig by closing balance valve.


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h. Drain valves for receivers shall be quarter turn valves having a high degree of abrasion resistance, such as tungsten carbide coated ball valves and stellite/carbide coated balanced plug valves.

Receiver drain valves usually have to cope with highly abrasive service. i. Vent valves may be globe type but shall have a tight shutoff isolation valve (soft seated

ball or balanced plug) in series. j. For gas service, blowdown valve shall be a tight shutoff ball or balanced plug valve with a

downstream globe valve or orifice restriction. k. A 50 mm (2 in) isolating valve and a 50 mm (2 in) check valve shall be installed in purge

connection, if applicable. The isolating valve shall be installed on the barrel side for tight shutoff of purge connection.

The check valve is intended to prevent hydrocarbons entering the purge/flush line. l. Chemical injection connection, if required, shall include a tight shutoff valve of minimum

diameter of 50 mm (2 in). Diameter of the connection shall be at least 50 mm (2 in). m. For LPG service, a double valve arrangement shall be installed in each drain and vent.

Second valve in a double valve arrangement shall be placed sufficient distance apart from the first to provide an alternative means of closing the line.

This is because the first valve may freeze, preventing it from being closed. n. Unless isolating valves are provided on each side, modified ball valves having a side entry

point that allows the insertion and removal of pigs shall not be used on a live system. At least one valve manufacturer offers such modified ball valves that, while offering some operational facility, only provide single isolation between operator and the live process.

6.7. Barrel design

6.7.1. General a. Trap barrel shall be capable of launching one and receiving two standard cleaning or

batching pigs. b. For launchers, the length of the barrel shall be sufficient to launch the longest ILI pig

anticipated (See Figure 2). Development of crack detection tools may require the use of longer

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GP 43-50 31 January 2009

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