Pipeline pigging

Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline.

Uses

Pigs may be used in hydrostatic testing and pipeline drying, internal cleaning, internal coating, liquid management, batching, and inspection. Fig. 1 shows several types of pipeline pigs.

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  Fig. 1—Types of pigs (courtesy of AMEC Paragon).

Hydrostatic testing

Pigs are used during hydrostatic testing operations to allow the pipeline to be filled with water, or other test medium, without entrapping air. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.

Pipeline cleanup

Operations may conduct pigging on a regular basis to clean solids, scale, wax buildup (paraffin), and other debris from the pipe wall to keep the pipeline flow efficiency high. In addition to general cleaning, natural-gas pipelines use pigs to manage liquid accumulation and keep the pipe free of liquids. Water and natural-gas liquids can condense out of the gas stream as it cools and contacts the pipe wall and pocket in low places, which affects flow efficiency and can lead to enhanced corrosion.

Batch transportation

Pigs are used in product pipelines to physically separate, or “batch,” the variety of hydrocarbons that are transported through the line. Product pipelines may simultaneously transport gasoline, diesel fuel, fuel oils, and other products, which are kept separated by batching pigs.

Prevention of solid accumulation and corrosion

Crude-oil pipelines are sometimes pigged to keep water and solids from accumulating in low spots and creating corrosion cells. This can be especially necessary when flow velocities are less than 3 ft/sec. Multiphase pipelines may have to be pigged frequently to limit liquid holdup and minimize the slug volumes of liquid which can be generated by the system.

Coating

Pigs may be used to apply internal pipe coatings, such as epoxy coating materials, in operating pipelines. Pigs may also be used with corrosion inhibitors to distribute and coat the entire internal wetted perimeter.

Inspection

Pigs are being used more frequently as inspection tools. Gauging or sizing pigs are typically run following the completion of new construction or line repair to determine if there are any internal obstructions, bends, or buckles in the pipe. Pigs can also be equipped with cameras to allow viewing of the pipe internals. Electronic intelligent, or smart, “pigs” that use magnetic and ultrasonic systems have been developed and refined that locate and measure internal and external corrosion pitting, dents, buckles, and any other anomalies in the pipe wall.

Intelligent pigs

The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process.

Pig launchers and receivers

Pigging facilities and considerations should be incorporated into the pipeline system design. Basic pigging facilities require a device to launch the pig into the pipeline and a receiver system to retrieve the pig as shown in Fig. 2. The launcher barrel is typically made from a short segment of pipe that is one to two sizes larger than the main pipeline and is fitted with a transition fitting (eccentric reducer) and a special closure fitting on the end. The barrel is isolated from the pipeline with full-port gate or ball valves. A “kicker” line, a minimum of 25% capacity of the main line, is tied from the main pipeline to the barrel, approximately 1 1/2 to 2 pig lengths upstream of the transition reducer, to provide the fluid flow to “launch” the pig into the pipeline. The barrel is fitted with blowdown valves, vent valves, and pressure gauges on the top and drain valves on the bottom. The length of the barrel is determined by the length and number of pigs to be launched at any one time. Receivers have many of the same features.

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  Fig. 2—Typical sphere launcher and receiver traps (courtesy of AMEC Paragon).

Hinge type closure

A typical hinge-type closure for pig launching and receiving traps consists of a forged hub, a hinged blanking head, split-yoke clamps, operating bolts, and a self-energizing O-ring gasket. Materials of construction are in accordance with American Society for Testing and Materials (ASTM) specifications and manufacture complies with applicable rules of the American National Standards Institute (ANSI) code for pressure piping and with the American Society of Mechanical Engineers (ASME) boiler and pressure vessel code.

Most important is the pressure warning safety device with yoke positioning plate. This safety device provides visual and mechanical assurance that the yokes are in the correct position over the head for commencement of operations. Additionally, the devices serve the purpose of alerting the operator to any residual pressure in the pig launcher or receiver trap should he inadvertently attempt to open the closure before all pressure has been relieved. A pressure warning device is located at each of the yoke splits with one of the positioning lugs attached to each yoke half. Tightening the holding screw on the nipple provides a seal and locks the hinged positioning plate on the positioning lugs. Loosening the holding screw breaks the seal and provides a means by which the operator can determine whether the pig launcher or receiver trap has been completely relieved of internal pressure. Continued loosening of the hold screw will allow disengagement of the positioning plate from the positioning lugs, permitting the yoke halves to be spread and the closure to be opened. There are several manufacturers of end closures, but most often Tube Turns or Modco closures are used worldwide.

Elbows and bends

Elbows and pipe bends installed in the pipeline should have a minimum radius of three times the main-line pipe diameter—3D bends. Intelligent pigs may require greater radius to diameter elbows and bends because of the longer length of the pigs. Tees installed in the pipeline with an outlet size 75% of the main-line inner diameter (ID) should be equipped with bars across the tee outlet to prevent the pigs from attempting to turn into the tee and lodging in the line. Hot taps greater than 6-in. diameter added to the pipeline should be barred. If possible, tees should not be installed adjacent to one another. Check valves should be full open, and the pigs or spheres should be sized such that the pig or sphere is larger than the “bowl” cavity of the check valve.

Pig selection

Pig runs of between 50 to 100 miles are normal, but pig runs exceeding 200 miles should be avoided as the pig may wear and get stuck in the line. Cleaning pigs may be constructed of steel body with polyurethane cups or discs and foam pigs with polyurethane wrapping, solid urethane disc, and steel body with metallic brushes. Drying pigs are usually low-density foam or multicup urethane. The intelligent pigs may be:

• Magnetic flux leakage
• Ultrasonic
• Elastic/shear wave
• Transponder/transducer
• Or combinations thereof

Internal-coating pigs are generally multicup urethane type. Batching pigs are typically bidirectional, multidisk rubber, which maintain efficiency up to 50 miles. Pigs used for obstruction inspection are typically urethane, multicup type fitted with an aluminum gauge plate or a gel type.

Spheres are generally sized to be approximately 2% greater diameter than the pipe internal diameter. Cups and discs are typically sized to be 1/16 to 1/8 in. larger in diameter than the pipe ID. Foam pigs have to be significantly oversized. Foam pigs 1 to 6 in. in diameter should be oversized by 1/4 in.; foam pigs 8 to 16 in. in diameter should be oversized 3/8 to 1/2 in.; foam pigs 18 to 24 in. in diameter should be oversized 1/2 to 1 in.; and foam pigs 28 to 48 in. in diameter should be oversized 1 to 2 in.

Slug catchers

The receiving end of the pipeline should have surge containment to accommodate the slugs of liquid carried by the pigs. For liquid lines, additional storage capacity (tankage) will provide surge containment. Gas and multiphase lines need specially designed "slug" catcher systems to handle the intermittent liquid slugs generated by the pigging activities. When a normal gas flow is pushing the pig through a gas pipeline, the velocity can be quite large and the flow rate of liquids being pushed ahead is given by
(Eq. 1)
where

QL	=	liquid-flow rate in front of the pig, B/D,
Qg	=	gas-flow rate behind the pig, MMscf/D,
T	=	temperature, °R,
P	=	line pressure, psia,
and
Z	=	compressibility factor, dimensionless.

In most systems, the instantaneous liquid-flow rate and "energy" surge ahead of the pig will exceed the processing design capacity and capability of the receiving facility. The slug catcher provides excess storage capacity within the receiving facility and helps dissipate the excess energy generated by the high-velocity liquid slug. The basic slug catcher is essentially a liquid-separation system where the incoming liquid enters a larger-diameter pipe or a vessel, which provides additional volume for the liquid surge and provides for separation of the vapor from the liquid stream. The additional volume provided by the slug catcher reduces the stream velocity and dissipates the excess energy produced by the liquid slug.

Another typical slug-catcher design employs an inline liquid header system attached to a series of horizontal liquid accumulators which may be several hundred feet in length. The liquid-slug stream enters the header and disperses into the accumulators, while the gas continues through the system and exits at the vapor-outlet collection header. The slug catcher may incorporate vortex breakers or other impingement devices to slow the liquid and mist extractors at the vapor outlet to capture entrained liquids. The liquid is transferred from the accumulators to the facility processing or storage. Fig. 3 shows an example slug-catcher design.

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  Fig. 3—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).

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  Fig. 3—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).

The volume of the slug catcher is expressed as
(Eq. 2)
where

(Vol)SC	=	volume of slug catcher, bbl,
Vol	=	volume of liquid holdup, bbl,
and
Qd	=	design liquid dump rate from the slug catcher, B/D.

(Eq. 3)
where T_R = time during which slug is processed, in days. The volume of the slug catcher should be designed with a minimum 25% safety factor.

Nomenclature

QL	=	liquid-flow rate in front of the pig, B/D,
Qg	=	gas-flow rate behind the pig, MMscf/D,
T	=	temperature, °R,
P	=	line pressure, psia,
Z	=	compressibility factor, dimensionless.
(Vol)SC	=	volume of slug catcher, bbl
Vol	=	volume of liquid holdup, bbl
Qd	=	design liquid dump rate from the slug catcher, B/D.
TR	=	time during which slug is processed, in days

References

Use this section for citation of items referenced in the text to show your sources. [The sources should be available to the reader, i.e., not an internal company document.]

Noteworthy papers in OnePetro

Chin, J., & Fakas, E. 2004. Evaluations of Surface And Subsea Pig Launching Systems. International Society of Offshore and Polar Engineers. SOPE-2-04-177

Combe, D. G., & Hair, D. 2011. Problems with Operational Pigging In Low Flow Oil Pipelines. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/143748-MS

Fung, G., Backhaus, W. P., McDaniel, S., & Erdogmus, M. 2006. To Pig or Not to Pig: The Marlin Experience With Stuck Pig. Offshore Technology Conference. http://dx.doi.org/doi:10.4043/18387-MS

Li, D., Ai, M., Zhang, P., Miao, Q., & Wang, Y. 2011. How to Determine the Gas Pipeline Pigging Cycle. International Petroleum Technology Conference. http://dx.doi.org/doi:10.2523/15180-MS

Zainal Abidin, S., Norman, A., Khairil Hing, A., Juzaimi, N., Ismail, M., & Alias, M. 2014. Condition-Based Pigging for Pipeline Network. Offshore Technology Conference. http://dx.doi.org/doi:10.4043/24927-MS

External links

How does pipeline pigging work by Rigzone

Pigging By Wikipedia

What do we really know about pipeline pigging and cleaning? By Randy L. Roberts

See also

Piping and pipeline systems

Pipelines

Pipeline design consideration and standards

Pressure drop evaluation along pipelines

PEH:Piping_and_Pipelines