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Pipeline pigging & cleaning: what do we really know about it? Part 1 of 2.

Pigging technology today has been advancing exponentially and what we mean by technology is not so much the hardware side but the application side. This article will address the application side of pigging while discussing rules-of-thumb for liquid and dry pipeline cleaning in tandem with mechanical pigs and the effectiveness of their respective results. Due to the length of this article P&GJ will print Part 2 under the same heading in a later issue.

Topics to be covered include: pig types, urethane durometer usages and types, recommended pig velocity, liquid cleaning vs. dry mechanical cleaning, types of pipeline contaminates, suspected causes, maintenance, advantages and disadvantages of various pipeline cleaners on the market, and suggested pigging procedures for natural gas lines.

These delineated topics will be in an order, hopefully, of usable procedures that will guide you to successful, economical, practical, safe, cost-effective and reliable data for your inline inspection integrity program.


What is it that we really know or understand about pigging a pipeline? If just running any type of mechanical pig through your pipeline at any speed and getting it out in one piece constitutes a clean or good run and now you're ready for the MFL tool, then the answer is not much, respectfully. Pigging of any type requires planning and assistance by pig manufactures and/or qualified pipeline-cleaning service companies. Specialty of others can be an excellent degree of assistance and knowledge. The goal of pipeline cleaning is to minimize or eliminate sensor liftoff of the ILI tool. A side benefit is increased pipeline efficiency and will be discussed in Part 2.

Technology today allows for a proven product in pig manufacturing to assist companies in achieving maximum results, whether mechanically dry pigging or liquid cleaning using mechanical pigs. Mechanical pigs have come a long way from bails of rags wrapped with barbed wire to today's formulated polyurethanes.


There are many types of polyurethanes but this article will only discuss castable elastomers. For more on various types of polyurethanes read: "What Polyurethane? Where? Selecting The Right Polyurethane for Various Applications" by Dr. Ronald W. Fuest, Uniroyal Chemical Company.

Mixing and pouting together two liquids, a prepolymer and a curator, make castable urethanes. There are basically two chemical structure types of polyurethane prepolymers:

1. MDI (methylenebisdiphenyl diisocyanate)

2. TDI (tolylenediisocyanate)

Both types use a curative and a prepolymer that, when mixed together, cause a chemical reaction forming the castable urethane. Manufacturers have their own guarded ratio mixture, other additives, dyes, and processes that differentiate them from each other in the market.

Some advantages of polyurethane:

1. Non-brittle

2. Elastomeric memory

3. Abrasion resistance

Some disadvantages:

1. Breakdown in high temperature, 220[degrees]-225[degrees]F

2. Moist hot environment (hydrolysis in the presents of moisture and elevated temperatures)

3. Certain chemical environments dissolve urethane, (Very strong acids & bases, aromatic solvents: i.e. toluene, ketones, methanol, & esters)

4. UV exposure greater than six months as a rule. (covered and stored inside prolongs life)

A few differences between MDI vs. TDI are chemical makeup but, in general, MDI urethane is a little more expensive but more durable, for example, on longer cleaning runs >75 miles, than TDI. However, TDI has a better compression set than MDI and handles higher temperatures. Various application(s) will determine which type is best to use.

Durometer (ref: www.matweb. com "Material Property Data")

Polyurethanes are mostly measured by the Shore (Durometer) test or Rockwell hardness test. The Rockwell test is usually for "harder" elastomers such as nylons, polycarbonate, polystyrene and acetyl. Shore hardness uses the Shore A or Shore D scale as the preferred method of testing for rubbers/elastomers (polyurethanes). The Durometer Shore test only indicates the indentation made by the indenter foot upon the urethane. Other properties such as strength or resistance to scratches, abrasion, and/or wear are not indicated.

Durometer is expressed by a number system. The higher the durometer number the harder the urethane. TDI urethane is good in the range from 50A to 90A1 with MDI in the 70A to 85A range. Combinations of each durometer can be incorporated in a pig design to maximize desired conditions and/ or results. The rule-of-thumb is, the harder the durometer, the better scraping capability; the softer the durometer, the better the sealing characteristics.

Pig Types

Pig types and functions are as numerous as people's opinions on politics. As a rule, most pigs of any type are a standard designed length-to-diameter ratio 1.5 times the OD of the pipe, i.e. 24" pig is 36" in length. This is why the lowest ell bend of 1.5d is important. If your line has less than 1.5d ells, then consideration may be required to replace with greater radius ells if you're trying to get to the point of making the line piggable for ILI tools or use specially designed tandem pigs. Pig types are of three basic designs: polly foam, unibody urethane, and steel mandrel discs/cups.

Polly Foam Type

Polly open cell polyurethane foam types are usually made the full OD of the pipeline, requiring most concerns for various internal diameters nonlimiting. Polly pigs have the ability to negotiate short radius ells and bends, miter bends, tees, multi-dimensional piping, and reduced port valves. Foam pigs come in various densities determined in pounds of urethane per cubit foot but most common are ranges from 2-lbs/[ft.sup.3]; 5-8 lbs/[ft.sup.3]; and 9-10 lbs/ [ft.sup.3]. These densities are usually color coded: yellow for 2 lbs, red for 5 lbs, and scarlet or blue for 10 lbs, depending on each manufacturer, but most follow these rules.

The polly open cell is the least aggressive of the pig design family. They are great for sealing and light abrasion removal and can reduce in diameter up to approximately 35%. Length can be increased to allow maneuverability through large tees, some older designed orbit valves, and other type gate valves.

Wire strip brushes, nose pull rope, transmitter cavity, and jetting ports can be incorporated in each density and type of poly foam pigs. Assorted selections of various configurations (polly criss cross, polly criss cross wire brush, bi-directional, bullet shape, and bare swab), of each density are as numerous as there are requirements so check with your manufacturer's representative and pipeline-cleaning service companies for help in designing to meet your requirements.


Also popular are the single-body cast polyurethane pigs designed to be more aggressive than pollys but more forgiving than the steel body mandrel type. They are effective in removing liquids from wet gas systems and liquid pipelines and help control paraffin buildup in crude oil lines, separation of refined products, pipeline commissioning, and product evacuation. The unibody design can also maneuver in less than 1.5d radius ells and bends and are usually, but not limited, to a multi-disc cup configuration. The multidisc designed in a bullet concave nose type or bi-directional type can have wire brushes attached along with other aforementioned configurations and add-ons. The unibody cast polyurethane with hollow shaft can handle up to a 20% reduction in pipe ID. These pigs can be cast from various durometer strengths as discussed previously.

Steel Mandrel

Steel-body mandrel-type pigs are the most aggressive type available from any manufacturer. The configuration of the steel body allows for multiple designs for multiple usages.

Steel-body mandrel pigs are built around a steel-constructed mandrel. Three basic designs: cleaning pigs, batch and gauging, and conical cup are usually available. We will only discuss the cleaning pig type.

Cleaning pigs can be made with all discs, disc with scraping cups, disc with conical cups, with any combination of all, and all types with various kinds of wire brushes and scraper urethane blades. Any of the cast-polyurethane products can be made from various durometer material strengths.

Polyurethane discs are cast and molded to the desired diameter of your pipeline. There are basically three types of discs, sealing, scraping and slotted disc. The sealing disc is usually thinner, [less than or equal to] 1-inch and designed for low-to-medium scraping characteristics but high on liquid sealing. The scraping disc is usually > 1-inch in thickness and compared to the description of the sealing disc functions just the opposite. Sometimes a combination of both types is required. Slotted disc or feathered type disc are generally used on multi-diameter pipelines. Special design may be required for each pipeline condition.

Considerations of pipeline length and pipe wall roughness to be pigged will also determine the kind of disc required for each type. When all multi-type discs are used, the pig can also be used as bi-directional.

Just like the disc, cups come in two basic types: scraper and conical cups. Scraper cups are as the name implies, but allow for greater surface forces to be exerted on the pipe walls, especially in less than oval shape pipe, while maintaining its ability to seal. These cups can reduce on average 15-20% of design diameter. Conical cups allow for maximum sealing with minimum scraping to remove solids. This type is normally seen on gauging plate pigs and multi diameter and out of round pipelines. These types of cups can reduce up to approximately 30-35% and maintain adequate seal. Again, conical and scrapper cups can be made in various durometer.

How To Get Started

ILI tool companies require that data on all ells, types of ells, bends, other types of bends, wall thicknesses, ovality, and pipeline cleanliness be known before running their tool. Generally, either the ILI companies or other caliper companies will offer a caliper pig to be run first to retrieve this data. The multichannel tool gives multiple data points, welds, taps, valves, types of nineties, bends, direction of bends, wall thicknesses, and other data--all in the o'clock position with pipeline linear footage location.

The ILI tool companies have varied tolerances for different tools and you will need to discuss required data for each. Once tolerances are known and approved by an ILI company, a date is scheduled to run their dummy tool, then the ILI tool. Most pipeline companies discover their pipeline is contaminated with solids and debris and needs cleaning during the installation of launcher/receiver and/or block-valve replacement.

Online Or Offline

Once the decision to clean a pipeline is made, you need to evaluate whether this line is to be cleaned online or offline. Online is defined as operating the pipeline under normal conditions while cleaning and offline with the pipeline out of service and depressurized. As a rule, offline cleaning can be twice as expensive as online cleaning due to additional required equipment, not to mention loss of gas revenues. In general, the extra costs are due to several factors: slower pig runs--generating more man hours, more cleaning runs, continuous nitrogen and air to propel the cleaning trains, and the fuel cost to generate that propellant over the duration of cleaning.

An exception would be if natural gas at low pressure was used to propel the pig-cleaning trains instead of nitrogen and compressed air. In either option, expect a cleaning program of a pipeline section less than 100 miles long to take four to six days of actual cleaning runs. Of course, this depends on the condition of the pipeline.

Online cleaning allows the pipeline company to continue to operate and service customers during the process. This cleaning procedure is quicker, safer, and less costly than offline, as a rule. The general rule-of-thumb--velocity for any size diameter pipeline is (>4-ft./sec.) but (<15-ft./sec.). See Figure C in Part 2 later issue. It is not that at velocities greater than 15-ft./sec. it cannot be used, but experience and pig manufacturer studies indicate, at that elevated speed, hydro-plane of the pigs will occur in the presence of liquids, which causes greater blow-by, leaving greater volumes of liquid and entrained solids in the pipeline. Of course, the object is to remove the solids and minimize free liquids in the pipeline so special cleaning procedures must be designed with your cleaning service company to counteract this concern.

What Is Considered Clean?

First, there is no industry standard. Cleanliness can mean internal conditions that minimize or eliminate ILI sensor liftoff. However, the industry from a proposal request must tell the cleaning service company bidders to propose a given amount of cleaning runs for all to be on an even playing field. Our experience has shown that three liquid-cleaning runs are the minimum. Usually the third liquid-cleaning train removes the greatest amount of solids and extra sequential runs are for polishing.

Fewer runs can be achieved but the concern is always the probability of removing too much, too fast, resulting in possible plugging of the pipeline and/or receiving equipment used to separate the liquid/solids from the gas or liquid stream. The rule is to remove the pipeline contaminates a layer at-a time by using a combination of the right liquid cleaner in a diluent and the right choice of pig type as mentioned earlier. Pipeline-cleaning companies, in conjunction with many customers; have set a standard of four cleaning runs with a final cleaning run solution solids percent at 6% by volume or less.

Some pipeline companies say 10%v or less and the pipeline is considered clean for smart pigging. However, 6%v or less has been the norm for single-diameter pipelines. In multi-diameter segments, a greater degree of cleanliness usually is required due to ILI sensor contact tighter tolerances. Other factors such as pig condition and residual of solids on pigs combined with the field test percent assist in a combined pipeline company and cleaning-service company's agreed-upon satisfactory cleaning performance.
Figure A:
Mass Balance Calculations

Pipeline Specifications:

4 ppm H2S
< 3% CO2
< 7 lbs/MMscf Water
1 MMscf/d
H2S (Hydrogen Sulfide: molecular weight: [H2: 2 + S: 32 = 34])
(1.0 MMscf/d / 379.5 scf/mol) x 1.0 ppm H2S (0.000001) x 34 mol wt.
H2S = ~ 0.09 lbs of H2S/day
FeS (Iron Sulfide: molecular weight: [Fe: 56 + S: 32 = 88])
(1.0 MMscf/d/379.5 scf/mol) x FeS formed from 1.0 ppm of H2S in the
gas (0.000001) x 88 mol wt. FeS =
~ 0.232 lbs of FeS/day
10 MMscf/d
10 MMscf/d x 0.232 lbs. FeS/MMscf/d x 365 days/year = ~ 847 lbs of
FeS per year

NOTE: Rule of Thumb: ~ 0.1 lb of H2S in the presents of Fe converts
to ~ 0.23 lbs of FeS or for every 1 lb of H2S converted to FeS, 2.3
lbs of FeS is formed.

Again, on multi-diameter pipelines, all the aforementioned conditions will apply, but with the addition of minimum iron compound deposits on magnet pigs. Measures are available to lesson the 1-mil volume or less generally left behind after cleaning and should be discussed with the pipeline service company if further pigging is required to remove free liquids.
Figure B:
Estimated Iron Oxides 1-mil Inch Buildup Calculations

1-mil Inch = 0.001 inches = 0.0000833 feet
d = ID of Pipe in Feet
Estimated Mass Density of Iron Oxide-Rust (Fe203): ~ 319 lbs Per
Cubic Foot
Fe2O3 specific gravity: 5.12
Example: 30" OD Pipe, Wall Thickness: 0.344", 50 Miles in Length,
1-mil inch buildup.
(2.443ft. ID)([??])(0.0000833ft.)(5,280 ft./mile)(50 miles)(~319
Pounds FeOx/[ft.sup.3]) = ~ 53,839 lbs of Fe2O3

False Paradigms

But you say we only have clean-treated gas, therefore, our pipelines should be clean. Consider this: if glycol dehydration is upstream of your system, it is safe to say you have free liquid triethylene glycol (TEG) in your pipeline, not to mention various types of lubricants, scavengers, flow promoters, corrosion inhibitors, methanol, hard hats, wooden skids, pig bars, chill rings, welding rods, and electric grinders. Dr. John Smart III, assisted by this author, has written a paper presented at NACE in 2006 entitled, "Possible Glycol Corrosion In Nominally Dry Gas Pipelines".

Dr. Smart discusses the theory that liquids will travel short distances through the pipeline close to the point of introduction but TEG vapor will travel greater distances than originally thought. The rule of thumb is, you lose 1 pound of liquid glycol per MMscf of gas treated. Triethylene glycol weighs ~9.36 pounds per gallon and is usually acidic when it leaves the glycol dehydrator. All glycols (EG, DEG, TEG, TTEG), in the presence of H2S, COS, CS2, RHS, CO2, O2, and water, in the gas stream, naturally become acidic. Once acidic, the glycol starts digesting the dehydrator unit components, causing free iron loss suspended in the glycol, which can cause stabilized foaming, then large amounts of glycol carryover into the pipelines can occur.

In this author's opinion and experience, the iron carryover greatly accelerates the formation of long chain polymers (shoe polish-looking substances), and contributes to black powder fouling. Using mass balance calculations See Fig. A: Hydrogen sulfide (H2S) at 1 part per million (ppm) (0.25 grains per 100 cubic feet is 4 ppm) in a continuous gas stream of 10 MMscf/D, if all converted to iron sulfide (FeS), will produce over 800 pounds of iron sulfide in a year. Thus, even pipeline-quality gas has the potential to cause internal problems.

Even a 1-mil inch (0.001 inches) film buildup of iron oxides can produce quantum amounts of solids. See Fig. B: Notably, less free iron on the pipe walls will ensure greater accuracy from the ILI tool.

Part 2 will discuss topics such as: Cleaning a Pipeline; Liquid Cleaning with Surfactant Base Cleaners; Other Liquid Cleaner Types; and Pipeline Efficiency.

By Randy L. Roberts, N-SPEC[R] Pipeline Services, Business Unit of Coastal Chemical Co., L.L.C. a Brenntag Company
COPYRIGHT 2009 Oildom Publishing Company of Texas, Inc.
No portion of this article can be reproduced without the express written permission from the copyright holder.
Copyright 2009 Gale, Cengage Learning. All rights reserved.

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Title Annotation:2009 P&G & PPSA Pigging Special Section
Author:Roberts, Randy L.
Publication:Pipeline & Gas Journal
Geographic Code:1USA
Date:Aug 1, 2009
Previous Article:Acquiring land rights for pipelines by negotiation and not condemnation.
Next Article:A new angle on solving unpiggable pipeline challenges.

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