pig mainline gas pipelines

Pig Mainline GasPipelines

Human DevelopmentConsultants Ltd.

Training Module

Pig Mainline Gas Pipelines

September, 2002

© HDC Human Development Consultants Ltd. All rights reserved. No part of this publication may be copied, reproduced, stored in a computer or retrieval system, published, distributed, or transmitted in any form or by any means whatsoever, including without limitation by mechanical means, photo copying, recording, digital or electronic media, the Internet, or otherwise, without the express prior written permission of HDC Human Development Consultants Ltd. (HDC). HDC grants to the purchaser of a Single User License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on one computer only and to make a single paper copy of this publication. HDC grants to the purchaser of a Site License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on one local area network server accessible by individual users' computers at one site or location only and to make paper copies of this publication for a company’s employees at the same site or location only. Each site or location must purchase a separate Site License for employees at that site. HDC grants the purchaser of a Corporate License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on its intranet and on computers at company sites or locations and to make paper copies for any or all employees. Nothing in the foregoing restricts, amends or abrogates the provisions of the agreement between HDC and the purchaser of the applicable license. Any copying or use other than pursuant to such a license is illegal. For further information, please consult the applicable license agreement. This publication is designed to provide general information regarding the subject matter covered. Care has been taken to ensure the accuracy of the information and that the instructions contained in this publication are clear and reflect sound practice. The user understands that HDC is not providing engineering services. The user understands that any procedures (task steps) that are published or referenced may have to be modified to comply with specific equipment, work conditions, company standards, company policies and practices, legislation, and user qualifications. HDC does not make any representations, guarantees, or warranties of any kind whatsoever with respect to the content hereof and the results to be achieved by implementing the procedures (task steps) herein. To the maximum extent permitted by applicable law, in no event shall HDC be liable for any damages whatsoever (including without limitation, direct or indirect damages for personal injury, damages to the environment, damages to business property, loss of business profit, or any other pecuniary loss). The use of the information and procedures (task steps) herein is undertaken at the sole risk of the user. ISBN 1-55338-013-4 Canadian Cataloguing in Publication Data 1. Pipeline pigging. 2. Gas pipelines. 3. Natural gas pipelines. I. HDC Human Development Consultants. TN880.5.P53 2002 665.5’44 C2002-901690-8 This training kit consists of the following parts: ♦ Training Module and Self-Check ♦ Knowledge Check and Answer Key

♦ Blank Answer Sheet ♦ Performance Check

Published by HDC Human Development Consultants Ltd. Published in Canada

HDC Human Development Consultants Ltd. Website: www.hdc.ca E-mail: [email protected] Phone: (780) 463-3909


September, 2002 Page i of ii

Human Development�Consultants Ltd.

Contents Training Objectives 1

1 Introduction 1

2 Reasons for Pigging Mainline Gas Pipelines 3

3 Types of Pigs 6

4

Pigging Components 9 4.1 Remote Operation 10 4.2 Pig Launchers and Receivers 11 4.3 Pig Signals 21 4.4 Station Bypass Facilities 22 4.5 Metering Facilities 25

5 Operator Roles 26

6

Pigging Practices 28 6.1 Safety and Environment 28 6.2 Pigging Frequency 30 6.3 Pre-Job Meeting 31 6.4 Launcher/Receiver On-Line or Isolated 31 6.5 Depressurizing, Venting, and Draining 33 6.6 Purging 34 6.7 Removing Pigs 34 6.8 Key Interlock Systems 34 6.9 Other Practices 35



Contents (continued)

7

Pig Loading and Launching Practices 35 7.1 Loading Pigs 36 7.2 Launching Pigs 39

8

Pig Receiving Practices 41 8.1 Receiving Pigs 42 8.2 Removing Pigs 44 8.3 Cleaning Pigs 47

9 Stuck and Lost Pigs 49

10

In-Line Inspection (ILI) Pigs 52 10.1 Metal Loss Detection Pigs 53 10.2 Geometry Pigs 54 10.3 Using Inspection Pigs 55 10.4 Field Operator Responsibilities 58

11 Self-Check 59

12 Self-Check Answers 65

September, 2002 Page ii of ii



Training Objectives

Upon completion of this training kit, you will be able to:

Describe the purpose and importance of pigging operations for mainline gas pipelines Describe reasons for pigging mainline gas pipelines Describe different types of pigs and their uses Describe components of mainline gas pipeline pigging systems Describe barrel-shaped pig launching and receiving equipment Describe pig launching and receiving practices Describe methods used to clean a pig Describe methods used to locate and free stuck pigs Launch and receive pigs

1 Introduction A vast network of pipelines transports natural gas in every part of the world. Pipelines gather gas from the field and transport these field products to gas plants for processing. After processing, pipelines transport the processed product—natural gas, liquefied petroleum gas, etc.—to markets and the end user. Maintaining pipeline integrity and ensuring the efficient, economical, and safe transportation of product is of highest importance to pipeline operators. Pigging is one of the principal methods used to ensure efficient pipeline operation. Pigs are tools that are inserted into the pipeline and that move in the pipeline, pushed by the flow of product. Pigs—also known as scrapers—have many uses. Pigs are used:

during pipeline construction and commissioning to clean the pipeline of construction debris and to test the pipeline

to inspect the pipeline integrity during routine operations to remove wax, standing liquids, and water, to treat the inner surfaces of pipelines with protective chemicals to separate product batches within the pipeline to prevent the batches from mixing

September, 2002 Page 1 of 65



This training kit focuses on pigging mainline natural gas pipelines (also known as transmission lines). There is great variation in the meaning of the term mainline pipeline, and the distinction between gathering system pipelines and mainline pipelines is not always well defined. In this kit, the term mainline pipelines refers generally to pipelines which have a compressor at the upstream end and which transport:

partially processed gas (including sour gas) from regional field processing facilities to central gas processing facilities for final processing

processed sales-quality gas from processing facilities over long distances to regional customers/gas distribution networks

NOTE Sales quality natural gas is mostly methane with trace amounts of ethane. Some natural gas pipelines operate at higher pressure so that increased amounts of ethane, propane, and butane may be shipped along in gas form. At the end of such pipelines, process facilities process the pipeline gas flow into:

sales quality natural gas (methane with trace ethane) individual hydrocarbon liquid products (ethane, propane, butane)

Most mainline gas pipelines feature:

centralized remote control

booster stations with compressors metering stations tie-ins for gas supply and delivery

Gas pipelines that are pigged more frequently are usually equipped with barrel-shaped pig launchers and receivers.

Figure 1— Pig in a Line




This training kit focuses on the safe and efficient launching and receiving of pigs in mainline gas pipelines. The kit is aimed primarily at pipeline Station/Field Operators who are responsible for local pigging operations. The kit also provides an overview of pigging operations which would be useful for Control Center Operators. The kit includes:

pigging applications

a description of pigs and pigging components and their operation roles and responsibilities of field personnel and Control Center Operators during pigging operations pigging practices for barrel-shaped pig launchers and receivers procedures related to pig launching, tracking, and receiving locating lost pigs and removing stuck pigs a description of inspection pigs

2 Reasons for Pigging Mainline Gas Pipelines

Pigging is an integral part of a company’s efforts to maintain pipeline integrity and transport product efficiently. Pigs are used for the following reasons:

to clean and test the pipeline after construction to inspect and gauge the line to improve flow by removing pockets of liquids/water and by cleaning deposits from internal surfaces to treat the line with protective chemicals

Line Cleaning and Testing After Construction After a pipeline is built or repaired, a pig is used to remove the dirt and debris which found its way into the line during construction. Dirt, mill scale, weld bead slag, rust, and debris left in the pipeline can contaminate the product and cause severe damage to filters, compressors, and valves. After a new pipeline is built and cleaned, a pig is used to gauge the line; gauging verifies internal diameter and may indicate pipeline damage during construction.




After gauging, the line is hydrotested: the line is filled with water and then pressurized to ensure line integrity. Before filling the pipeline with water, a pig is launched; this pig separates the air in the line from the water. After the hydrotest, the line is purged with air or nitrogen to displace the water. Another pig is used to separate the water and the purge gas. A series of pigs is used to dewater and thoroughly dry the line before the pipeline is filled with the product. After dewatering, a pig (and sometimes a nitrogen buffer) is used to separate the air in the line from the product. The pig prevents the air in the line and the product from forming a combustible mixture.

Line Inspection and Gauging Pigs can be configured with inspection tools to detect pipeline dents, buckles, wrinkles, cracks, diameter changes, slope changes, construction damage, corrosion, hard spots, and to determine wall thickness. Pigs can be used to inspect the internal surface of an entire pipeline and store the data in memory for interpretation of findings.

Figure 2— Pig Used for Gauging

Line Cleaning and Swabbing Residual well dust and trace amounts of oil from the compressors tend to build up on the pipeline walls, reducing flow and preventing protective chemicals from reaching the pipeline walls. Pigs are used to scrape the deposits from the pipe walls.





The natural gas transported in gathering system pipelines often contains natural gas liquids (NGLs)(such as butane and propane), well dust, and water. These lines must be pigged frequently to recover the NGLs and remove the water and debris. Mainline gas pipelines, however, usually transport drier, cleaner gas with none or varying amounts of NGLs, and very occasionally, trace amounts of water. Water is a major factor in line corrosion. Depending on the pressure and temperature of the line, liquids may drop out of the gas and settle in low-lying areas. Gas flow tends to be turbulent around the pooled liquids, causing a pressure drop, reduced throughput, and possible increased erosion. Pigs are used as squeegees to push the liquids ahead of the pig, removing pooled liquids.

Figure 3—Pigging to Remove Pooled Liquids

pooled water

gas flow

cast pig

The frequency of pigging depends on a number of factors, such as the amount of debris and liquids in the transported product, line pressures, delivery rates, and seasonal temperatures.

Batch Treating In batch treating, a protective chemical is batched between two pigs. The first pig removes liquids and sediment deposits and cleans the inside of the pipe. The protective chemical, isolated from the gas in the line by the two pigs, adheres to and protects the internal surface of the line. A scraper pig may be sent down the line before the first batch pig to remove wax deposits.



Figure 4—Batch Treating

gas flow

trailing

filming pig

chemical

batch

wax deposits still left over

after sending advance

scraper pig

inner surface coated

by the chemical batch

leading

cleaning pig

3 Types of Pigs Mainline pigs come in many different shapes, materials, and sizes:

spheres—Most sphere pigs are made of polyurethane; they may be solid or may be filled with a water/glycol mixture.

foam pigs—Foam pigs are made of an open cell polyurethane foam. Foam pigs may be coated with wire brush straps, silicone carbide chips, or steel studs. mandrel pigs—Discs are mounted on a central mandrel. The discs can be replaced or reconfigured, allowing for changing job requirements. Some discs have brushes to provide more scraping edges; these are called disc scraper pigs. Mandrel pigs can be equipped with specialty tools for gauging and inspection or with strong magnets to remove ferrous debris. Some mandrel pigs are equipped with bypass holes. Fluid from behind the pig pushes through the holes creating a jet action, keeping the scrapings ahead of the pig (see Figure5). Dual diameter pigs are available for pipelines that have two different pipe diameters.




Figure 5—Bypass Pig Jets Scrapings Ahead of the Pig

wax deposit scraped off walls�

is jetted ahead of the pig

cast pigliquid�

flow

�

solid cast pigs—Solid cast pigs are similar to mandrel pigs, but are cast in one piece and are usually made of urethane.

gel pigs—Gel pigs are viscous gelled fluids used alone or in conjunction with mechanical pigs.

Common Uses of Pigs The type of pig is chosen according to the specific requirements of the line. Common uses for each type of pig are:

spheres—sealing: batch separation, hydrostatic line testing, line maintenance (batch treating), meter proving. Sphere pigs are particularly useful for negotiating tight 90° bends. foam pigs—sealing and cleaning: drying, wiping, dewatering, scraping (especially when coated with brushes, chips, or studs) mandrel pigs—sealing and cleaning: brushing, dewaxing, descaling, gauging, inspecting – when fitted as gauging pigs: determining internal

diameter, locating dents and slope changes – when fitted as inspection pigs: detecting metal loss,

including corrosion and cracks – when fitted as magnetic pigs: removing ferrous debris

such as welding rods and mill scale after construction or before running an inspection pig

solid cast pigs—sealing, purging, and cleaning gel pigs—cleaning: picking up deposits and debris scraped off inner pipeline walls by mechanical pigs




Figure 6— Types of Pigs

Mandrel Pig Sphere Pig

Cast Pig Foam Pig

Pig Size and Fit Pigs must be able to:

negotiate bends, curves, and dents in the pipeline

pass check valves and tees without buckling, tearing, or shredding resist rapid wear and wear evenly

Pigs come in standard sizes to fit tightly into standard diameter mainline pipelines. Pigs must fit tightly in the line for several reasons:

A tight fit prevents transmitted gas from flowing past a pig. The gas builds up pressure behind a pig: the upstream pressure (behind the pig) becomes greater than the downstream pressure (in front of the pig). This difference in line pressure across a pig (differential pressure) pushes the pig down the line. Some pigs are equipped with small bypass holes, primarily to control the pig’s velocity.

On disc pigs, the upstream pressure pushes the discs forward. This action forces the discs tightly against the pipe walls. For disc pigs, the greater the differential pressure, the tighter the seal. A tight fit permits the edges of the pig to firmly scrape along the inner surface of the flow line, scraping off deposits. The scraped-off deposits collect ahead of the pig. For batch treating, a tight fit prevents the corrosion inhibitors, which are batched between two pigs, from mixing





with the pipeline gas flow and/or with the material that is being scraped off the inner surfaces of the flow line.

A disc pig used for line gauging is typically equipped with a metal gauge plate that is approximately 90 to 95% of the internal diameter of the pipeline.

4 Pigging Components The basic components related to pigging mainline pipelines include the following (see Figure7): remote operation from a control center via a data

communication system pig launchers pig signals station bypass facilities pig receivers metering facilities

Figure 7—Basic Pigging Components of a Mainline Gas Pipeline

continuing mainlineto other markets

mainline

hostcontroller

satellite

control centerwork station

plant

piglauncher

booster stationwith pig bypass

facilities

booster stationwith pig receive

& launch facilities

booster stationwith pig bypass

facilities

- metering- regulating- odorization

localdistributionto homes/

businesses

pig receiver

pig signal

city

gatestation



4.1 Remote Operation Most mainline pipelines are operated remotely from a central control center by means of a SCADA (supervisory control and data acquisition) system. SCADA systems:

monitor variables such as pressure, flow rate, temperature, density, and composition

control equipment such as compressors, valves, and pig launchers

SCADA systems consist of:

a host computer that supervises and manages data data transmission equipment that transmits and receives data signals between pipeline locations and the host computer, and includes land lines, microwave, or satellite facilities central control center workstation that receives data signals from the host computer local workstation (i.e., a workstation at a mainline compressor station) that receives data signals from the pipeline and from the host computer

Pipelines equipped with SCADA systems can be operated in the following ways:

remotely from the central control center workstation remotely from the local workstation manually at the equipment

Under remote control from the central control center workstation, the Control Center Operator uses the SCADA workstation to monitor and adjust pipeline operations, including launching pigs and tracking pig movement. (Note that on some pipelines, pig launchers and receivers can only be operated manually.) The SCADA system calculates and displays the movement of pigs through the pipeline, determining a pig’s current location and estimated time of arrival at various sites along the pipeline.




Figure 8— SCADA Workstation

Under remote control from a mainline station, a Station/Field Operator can monitor and adjust pipeline operations from the local workstation. The local workstation is used if communication is lost between the central control room and the mainline station, usually as a result of data transmission equipment or host computer failure. A Station/Field Operator can operate the pipeline equipment manually. Equipment is operated manually if communications are lost between the equipment and the station controller. At some stations, pig launchers and receivers are not linked with the station controller and can only be operated manually.

4.2 Pig Launchers and Receivers A pig launcher is located at the upstream end of a mainline pipeline; a pig receiver is located at the downstream end. Pipelines may have intermediate pig launch/receive stations and pig bypass stations (refer to Figure 7). Pipelines are designed with intermediate pig launch/receive stations to remove waste material in front of the pig and thus prevent excessively large buildups. For mainlines that are pigged infrequently, portable pig launchers and receivers may be used. These launchers and receivers are welded or bolted into place for the launch or receive operation and removed as soon as the operation is complete. Fixed pig launchers and receivers on mainline pipelines are generally barrel-shaped units (see Figures 8 and 10). The barrel diameter is larger than the diameter of the pipeline and




1.5 to 2.5 times longer than the pig. A pipe with a bypass valve connects barrel pig launchers and receivers to the mainline pipeline. Launchers and receivers are often called pig traps.

WARNING

Companies and manufacturers use different terms for pig trap piping and valves. The terms used in this training kit may be different from the terms your company uses. When working with pig traps, make sure you understand the use of terms at your site to prevent confusion.

Figure 9— Barrel-shaped Pig Launcher

vent

to mainline

upstream isolation valve(kicker)

upstream blowdownvalve

downstream blowdown valve

downstream isolation valve (fullopening)

pig signal

drain valve

bypass line

pig bars

mainlinebypass valve

fromplant or mainline

to flare or vapor recovery unit

vent

Figures 9 and 11 show a launcher and a receiver equipped with upstream and downstream blowdown valves to flare or to a gas recovery unit and two vent valves. This configuration ensures:

that the pressure is relieved on both sides of the pig should the isolation valve leak, the gas is directed out of the

barrel Figure 10 shows the vent valves mounted on the lines to flare. Some companies use this configuration to reduce the risk of the vent valve plugging with debris.




Figure 10—Launcher with Vent Valves on Lines to Flare or Vapor Recovery Unit vent

valvevent

valve

to mainline

upstream isolation valve(kicker)

upstream blowdownvalve

downstream blowdown valve

downstream isolation valve (fullopening)

pig signal

drain valve

bypass line

pig bars




Not all launchers and receivers are equipped with two blowdown valves or two vent valves:

some may be equipped with a single blowdown valve to flare and one vent to atmosphere

others may be equipped with a single vent, which may vent to a flare or gas recovery unit or to atmosphere, depending on jurisdictional requirements

When equipped with two blowdown valves, as illustrated in Figures 9, 10, and 11, the line between the two blowdown valve equalizes pressure at both ends of the barrel. To load a pig in the launcher, the launch barrel is isolated from the mainline. Before launching the pig, all air in the barrel must be purged so that air does not enter the pipeline and create a flammable mixture. To launch a pig, flow through the launch barrel is established. Depending on the pipeline, pigs can be launched remotely from the central control room, remotely from the local station, or manually.




Pig bars at the intersection of the bypass line prevent the launched pig from entering the bypass line. A pig signal is tripped when the pig enters the pipeline; the pig signal may be transmitted to the host computer at the central control center. When a pig arrives at the pig receiver, a pig signal is tripped. The signal may be transmitted to the host computer. Pig bars prevent an incoming pig from entering the bypass line. The receiver barrel is isolated to remove the pig. The barrel is then purged of air and repressurized.

Figure 11— Barrel-shaped Pig Receiver

vent

upstream isolation valve

upstream blowdown valve

down-stream

blowdownvalve

pig signal

drain valve

bypass line

pig bars


downstreamisolationvalve


vent


to mainline

NOTE Note: On the receiver, the downstream blowdown valve is closest to the trap door, whereas on the launcher, the upstream blowdown valve is closest to the trap door.

Mainline pipelines and the pigs used in the lines range in diameter from about 168 mm to 1220 mm (nominal 6 in. to 48 in.). Larger pigs can weigh more than 450 kg (1000 lbs.). Depending on the size and weight of a pig, pig launchers and receivers are equipped with jib arms, hoists, launch/receive trays, and hydraulic rams. All pig launchers and receivers are equipped with pressure gauges, vents, and drain valves.




Pig Trap Closures There are many different types of trap closures, some of which allow rapid access to the barrel. The most common are:

threaded

clamp ring band lock

Most pig trap closures are equipped with the following features:

an O-ring which provides a seal between the door (cap) and the barrel a strong hinge mechanism or jib arm-type system to support the door when it is open and allow the door to be positioned correctly when it is closed a pressure warning device that warns the operator if the barrel is still pressurized. Some pressure devices prevent the door from being opened until all pressure in the barrel has been relieved.

O-rings must be inspected every time the pig trap is opened. Look for blistering, swelling, and delamination. Make sure you have a correctly sized replacement before removing an O-ring from a closure because it is very difficult to re-install a swollen O-ring. Threaded Closures—Barrels with threaded closures are opened by rotating the end cap (door). Larger closures are equipped with a hinge mechanism or jib arm to support the open cap; smaller threaded closures may not have a hinge. Some Yale closures have a closure ratchet which aids the initial opening and final closing of the end cap. (See Figure 12.)




Figure 12—Yale Threaded Closure

closure ratchet

After a threaded closure has been newly installed, it is important to open and close the closure at least twelve times to remove any rough spots on the threads. Over-tightening threaded closures can damage the O-ring and threads. Close-tight arrows are placed on both the closure and the hub to indicate when a closure is sufficiently tight: when the arrows are aligned, the seal is sufficient. If a new closure does not have close tight arrows, follow this procedure to mark the closure:

Remove the O-ring.

Clean opposing surfaces thoroughly. Screw on the cap until it is in metal-to-metal contact. Use a low stress stamp to incise matching lines on both the hub and the cap.

CAUTION

Make sure the stamp is low stress rather than sharp. A sharp stamp can fracture the metal.




To open a threaded closure, after isolating, depressurizing, and draining the barrel:

If the closure is equipped with a pressure warning device on the cap, open the device. If the valve hisses, there is still pressure in the barrel. Check the status of all valves. Wait until the warning device stops hissing before proceeding.

Loosen the cap with a lug wrench, cat bar, or, if present, the closure ratchet.

CAUTION

Manufacturers discourage the use of hammers to open and close threaded caps. Hammer impact can cause surface stress cracks and severely reduce closure life.

CAUTION

Manufacturers discourage the use of backhoes to loosen or tighten threaded closures. Using a backhoe can damage the cap and related equipment. Companies who do use a backhoe use a sling to hook the cap to the hoe; a designated signal person directs the backhoe operator.

WARNING

Stand to one side when removing the cap. Pressure in the trap can cause the pig to shoot out at high velocities. The pig and the cap can cause serious injury.

After the cap is loosened, manually rotate the cap until it is disengaged from the barrel.

WARNING

If it is difficult to rotate the cap manually, the barrel may still be pressurized. Ensure all pressure in the barrel is relieved before removing the cap. Check the status of all valves.

For caps without a hinge device, after the cap is disengaged from the barrel, lift off the cap and place it on the ground.

For caps equipped with a hinge or jib arm mechanism, after the cap is disengaged, use the hinge to swing the cap open and away from the barrel opening.

To close a threaded closure:

Clean the O-ring and the threaded surfaces on the cap and barrel. Make sure the threads are cleaned to the bare metal.




Visually inspect the O-ring and threads on the cap and barrel. Replace O-ring if necessary. Lubricate the threads and seal with the lubricant recommended by the manufacturer. For smaller caps, position the cap and screw it on. For larger caps, use the hinge or jib arm to support the cap, position the cap on the barrel, and screw it on. Tighten the cap with a lug wrench, cat bar, or closure ratchet.

CAUTION

Do not over-tighten; over-tightening may damage the O-ring.

Clamp Ring Closures—Clamp ring (yoke) closures feature a hinged clamp which encircles the cap/barrel interface (see Figure 13). A latch mechanism locks and unlocks the clamp.

Figure 13—T.D.Williamson Clamp Ring Closure




To open a clamp ring closure, after isolating, depressurizing, and draining the barrel: Unlatch the latching mechanism.

WARNING

Stand to one side when removing the cap. Pressure in the trap can cause the pig to shoot out at high velocities. The pig and the cap can cause serious injury. Swing open the cap on its hinge.

To close a clamp ring closure: Clean the O-ring and the opposing surfaces on the cap and

barrel. Lubricate the seal and mating faces with the lubricant

recommended by the manufacturer. Close the cap. Latch the latching mechanism.

Bandlock Closures—Bandlock closures, manufactured by GD Engineering Inc., feature a locking band, fitted between the door and the barrel neck, which engages in a locking groove on the barrel (see Figure 14). To open the bandlock closure, after isolating, depressurizing, and draining the barrel:

End of Sample A full licensed copy of this kit includes: • Training Module and Self-Check • Knowledge Check and Answer Key • Blank Answer Sheet • Performance Check

pig mainline gas pipelines

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