Randy L. Roberts* N-SPEC Pipeline Services, Business Unit of Coastal Chemical Co., L.L.C./A Brenntag Company, Broussard, LA, USA Internal pipeline cleaning requires knowledge of any given segment(s) and their operating parameters, for example, pipe length, pipe diameter, bend radiuses, single or multidiameter, types of valves, taps (in/out) and their o’clock position on the pipe, gas/liquid volume (velocity), operating pressure and maximum allowable operating pleasure (MAOP), and of course pig traps. The decision then is to determine if cleaning should be on-line or off-line or if mechanical cleaning or liquid (chemical) cleaning should be used. What type of pigs and cleaners should be used, and what is to be removed? The list can go on and on requiring multiple decisions and a great deal of time. Thankfully, there are pipeline cleaning vendors available to guide one through this maze of obstacles and requirements. Additional factors in the cleaning decision should be based on the overall thought of what intelligent tool(s) are to be used and what data are required. The question to be answered is “how clean do I need to be for that particular in-line inspection (ILI) tool to secure a good run and receive maximum data?” A frequently asked question is what kind of debris is in the pipeline and how much? This question is unanswerable; clean is subjective, and the pipeline is dirty. There are no required industry standards to date, only actual cleaning results known throughout the industry, which have generally been found to be acceptable. This chapter contains information on seven general topics on internally cleaning pipelines to prepare for running ILI tools and also to increase pipeline efficiency. Topics included in this chapter are contaminates, progressive pigging, pig types, mechanical versus liquid (chemical) cleaning, suggested typical pigging procedures, pipeline cleaners and diluents, and “how clean do I need to be?” The pipeline operator is advised to include the local or known pipeline cleaner vendor for assistance and guidance on practices that the vendors encounter on a daily basis. In liquid lines (crude, NPL, product, or other) and natural gas (production, gathering, or transmission spec gas), the one common contaminates are iron compounds, commonly known as black powder. Black powder is by far the number one contaminate experienced in 99% of all pipelines [1]. Black powder is a name given in the pipeline industry in the early 1990s [2]. Black powder can consist of the following compounds in any combination and percentages by weight and/or volume (Cormier, Danny, Coastal Chemical Co., Broussard, Louisiana, Multiple analytical lab results, personal communication): Black powder is brittle and abrasive. The more the pipelines are mechanically (dry) pigged, the finer the black powder becomes, causing not only downstream nuisance problems but also the compressing of these fine iron compounds into any pits and/or anomalies that may exist in the pipelines. The results of iron compound packing could deflect actual magnetic flux leakage (MFL) data indicating potential pipeline problems, or at a minimum, have the potential to mask the severity of possible anomalies.1 Other contaminates not listed in the previous paragraph are welding rods, wooden skids, hard hats, grinders, animal bones, tools, pry-bars, bolts and studs, workman’s gloves, sand, rocks, stuck pigs, parts of pigs, and others too numerous to list. Any and all these objects and contaminates must be removed prior to running any ILI tools, to protect the tool and to eliminate or minimize ILI sensor liftoff. Progressive pigging, simply stated, is running less aggressive pigs to more aggressive pigs in a sequential order based on the amount of debris found in the pipeline. The question then is to decide what is the least aggressive pig to start with? The general rule is, if the pipeline has never been mechanically pigged, then start with a 2-pound (0.91 kg) poly criss-cross pig. Pig types will be discussed in Section 40.4. The 2-pound poly pig is one of the least aggressive types to run in the pigging world. They, as well as other poly pigs, can traverse 1.0D bends, require minimum pressure to launch, run on 5–10 ΔP pressure drop, and can be destroyed if lodged in the line with approximately 50–60 ΔP pressure exerted. Poly pigs are made using open cell urethane technology and are characterized in pounds of urethane per cubic foot (lb/ft3). The higher the pounds, the tighter or harder the urethane. The physical condition of the 2-pound poly should be assessed, looking particularly for deep folds, cuts, amount of debris, gashes, and wear of the pig. Mechanical pigging in gas and liquid lines is generally good for 100 km (~60 miles) to 130 km (~80 miles). When liquid (chemical) cleaning (synergistically using mechanical pigs and cleaning liquid products) is used, approximately 25% additional usage over mechanical is the rule-of-thumb. Once the pig condition evaluation is done, the same type of pig can be run again or the next level of aggressiveness type can be used. An example would be using a 5-pound (~2.27 kg) poly criss-cross wire brush pig, and then a 10-pound (~4.54 kg) type. After running various types of poly pigs, then the next step would be to utilize steel body mandrel discs/cup type pigs. Careful attention should be noted that before running steel body pigs, the minimum bend radius must be at least 1.5D bends. Most pig manufacturers design their steel body pigs to have a pig length of 1.5 times the diameter, thus, the 1.5D minimum bends. In using the steel body types, the characteristics of discs/cup polyurethanes and durometer measurements [3] need to be understood. Polyurethanes and durometer tests will be discussed further in Section 40.4. Within the steel body pig family of polyurethane type and durometer types, progress is normally from least aggressive to more aggressive and from sealing type to scraping type. Basically, the pipeline operator should work with the pig supplier to assist in these decisions. There are many pig types and functions. As a rule, most pigs, of any type, are a standard designed length-to-diameter ratio of 1.5 times the OD of the pipe, that is, the 24 in. (~61 cm) pig is 36 in. (~91 cm) in length. This is why the lowest bend of 1.5D is important. If the pipeline has <1.5D bends, then consideration may be required to replace such bends with greater radius bends if the objective is to make the line piggable for ILI tools or specially designed tandem pigs may be used. Pig types are of three basic designs: poly foam, unibody urethane, and steel mandrel discs/cups. Poly open cell polyurethane foam types are usually made the full OD of the pipeline, with little to no concerns for wall thickness. Poly pigs have the ability to negotiate short radius L-shaped bends, miter bends, tees, multidimensional piping, and reduced port valves. Foam pigs come in various densities determined in pounds of urethane per cubic foot, but the most common ranges are 2, 5–8, and 9–10 lb/ft3 (1 lb/ft3 equals 16 kg/m3). These densities are usually color coded: yellow for 2 lb, red for 5 lb, and scarlet or blue for 10 lb depending on the manufacturer, but most follow these rules. The poly 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 types of 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. Because of the many available configurations (poly criss-cross, poly criss-cross wire brush, bidirectional, bullet shape, and bare swab) of each density, the pipeline operator should check with the manufacturer’s representative and the pipeline cleaning service company for help in developing a design to meet the requirements. The single-body cast-polyurethane pigs are designed to be more aggressive than polys but more forgiving than the steel body mandrel type. These pigs are effective in removing liquids from wet gas systems and in removing denser liquids from liquid pipelines (e.g., water from crude oil lines) and/or for displacement, and they also can be used to help control paraffin buildup in crude oil lines as well as for separation of refined products, pipeline commissioning, and product evacuation. The unibody design can also maneuver in <1.5D radius L-shaped bends and is usually, but not limited to, a multidisc cup configuration. The multidisc design in a bullet concave nose type or bidirectional type can have wire brushes attached along with other configurations and add-ons. The unibody cast polyurethane with hollow shaft can handle up to a 20% reduction in pipe ID [4]. These pigs can be cast in material of various durometer strengths, as will be discussed in Section 40.5. Steel body mandrel type pigs are the most aggressive type available made by 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. In this chapter, only the cleaning pig type is discussed. Cleaning pigs can be configured 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 urethane scraper blades. Any of the cast polyurethane products can also be made from material of various strength levels as measured using a durometer. Polyurethane discs are cast and molded to the desired diameter of the pipeline. There are basically three types of discs: sealing disc, scraping disc, and slotted disc. The sealing disc is usually thinner, ≤1 in. (25 mm), and is designed for low to medium scraping characteristics, but high on liquid sealing. The scraping disc is usually >1 in. (25 mm) in thickness and compared with the description of the sealing disc functions, just the opposite. Sometimes, a combination of both types is required. A slotted disc (or feathered type disc) is generally used on multidiameter pipelines. A special design may be required for each pipeline condition. Considerations of pipeline length and pipe wall roughness to be pigged will also determine the type required. When all multitype discs are used, the pig can also be used bidirectionally. Just like the disc, cups come in two basic types: scraper cups 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 out-of-round pipe while maintaining the ability to seal. These cups can reduce on average 15–20% of the design diameter. Conical cups allow for maximum sealing with minimum scraping to remove solids. This type is normally seen on gauging plate pigs and multidiameter and out-of-round pipelines. This type of cup can reduce up to approximately 30–35% and maintain adequate seal. Again, conical and scraper cups can be made in materials of various durometer hardness levels. There are many types of polyurethanes but only cast elastomers are discussed in this chapter. For more detailed information on various types of polyurethanes; see Ref. [3]. Mixing and pouring together two liquids, a prepolymer and a curative, make castable urethanes. There are basically two chemical structure types of polyurethane prepolymers: Both types use a curative and a prepolymer that, when mixed together, cause a chemical reaction forming the castable urethane. Each manufacturer has their own guarded ratio mixture, other additives, dyes, and process that differentiate them from each other in the market. Following are some advantages of the polyurethane [3]: Some disadvantages are as follows: A few differences between MDI and TDI are chemical makeup, but in general, MDI urethane is a little more expensive but is more durable, for example, on longer cleaning runs, >75 miles (>121 km), than TDI. However, TDI has a better compression set than MDI and functions at higher temperatures better than MDI. Which type is best to use depends on the application. Polyurethanes are characterized mostly by the Shore (durometer) test or Rockwell hardness test [5]. The Rockwell test is usually used for “harder” elastomers, such as nylons, polycarbonate, polystyrene and acetyl, and so on. Shore hardness uses the Shore A or Shore D scale as the preferred method of testing for rubbers/elastomers (polyurethanes). The durometer Shore test indicates only 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. The durometer measurement is expressed by a number system. The higher the durometer number, the harder the urethane. TDI urethane is good in the range from 50 to 90A [3], MDI type in the 70–85A range. Combinations of materials with different durometer readings can be incorporated in a pig design to maximize desired conditions and/or results. The rule-of-thumb is the harder the durometer measurement, the better scraping capability; the softer the durometer measurement, the better the sealing characteristics. ILI tool companies require that data on all bends, diameters, 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 information. The multichannel tool identifies 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 different tolerances for different tools, and pipeline operators need to discuss the 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. Once the decision to clean a pipeline is made, a decision is made on whether the line is to be cleaned on-line or off-line. On-line is defined as operating the pipeline under normal conditions while cleaning and off-line with the pipeline out of service and depressurized using other propellants to run the pigs. As a rule, off-line cleaning can be twice as expensive as on-line cleaning due to additional required equipment and lost revenues from the out-of-service line. In general, the extra costs are caused by 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 the use of natural gas at low pressure to propel the pig cleaning trains instead of nitrogen and compressed air. In either option, a cleaning program of a pipeline section <100 miles (~161 km) long can be expected to take 4–6 days of actual cleaning runs. Of course, this depends on the cleanliness condition of the pipeline that is required. On-line cleaning allows the pipeline company to continue to operate and service their customers with uninterrupted service while cleaning their pipeline. This cleaning procedure is usually quicker, safer, and less costly than off-line. The general rule-of-thumb—velocity, for any size diameter pipeline, is >4 ft/s (1.2 m/s) but <15 ft/s (4.6 m/s). Although velocities >15 ft/s. (4.6 m/s) can be used, experience and pig manufacturers’ studies have shown that, at those elevated speeds, hydroplaning 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 objective is to remove the solids and minimize free liquids in the pipeline, and so special cleaning procedures must be designed with the cleaning service company to address this concern. There are two types of pipeline cleaning programs available. One type is referred to as mechanical cleaning (the running of mechanical pigs dry progressively) and is the most common answer when asked, “Do you clean your pipelines?” The other cleaning program is liquid (chemical) cleaning, discussed later. Most debris in a pipeline is in the 4–7 o’clock position due to gravity. In most cases, mechanical cleaning will only displace the debris from the 6 o’clock position to 360° around the pipe walls. Even if more mechanical pigs are run, the solids (i.e., black powder), iron compounds, and other organic and inorganic compounds can be broken down to submicroparticles causing downstream problems, such as plugged meters, fouled turbine/compressor inlet filter elements, and the customer’s treating process equipment. Again, the more one mechanically dry pigs, the smaller the particles can become. If the solids are iron compounds (iron sulfides, iron carbonate, iron oxides, etc.), these particles and submicroparticles will be pressed by the pig’s disc and cups, at pipeline pressure, into any pipe wall anomalies and/or pits, possibly interfering with the magna-flux readability of the actual pipe wall metal loss areas, especially if those iron compounds are magnetite. Achieving greater solids removal from pipelines with fewer pig runs requires liquid (chemical) cleaning. This type of cleaning is becoming more popular in the industry. Liquid cleaning in tandem with mechanical pigs will remove a greater volume of debris with fewer cleaning runs. Liquid cleaning by definition means the use of liquid cleaners mixed in a diluent (water, diesel, methanol, isopropyl alcohol [IPA], methyl ethyl ketone [MEK], etc.), to form a cleaning solution pushed through a pipeline using mechanical pigs. Most cleaning companies will calculate the volume of liquid solution to coat the interior walls based on a given diameter and length of pipeline with a coating thickness of 2–3 mils (0.051–0.076 mm). A volume of 10–20% of that calculated would be used as pipeline cleaner. A minimum of 10% by volume of pipeline cleaner is suggested not only to allow the cleaner to penetrate and permeate the solids but also to have enough percentage volume to be able to carry the solids out of the pipeline. Usually, a minimum of 10% by volume is suggested. Diluents alone have no to little solids-carrying capabilities. The cleaner mixed with a diluent should be enough in volume to form a froth to keep the solids in suspension so as not to allow the solids to settle before being expelled from the pipeline. The other criterion for calculating the amount of cleaning solution is based on residence time to allow for enough contact time to penetrate the debris. A 10 s or greater resident time is the suggested required time, with 10 s being the minimum. This liquid column length is based on percent liquid cleaner in the solution, gas velocity, and/or liquid barrels per hour rate. For liquid product and crude oil lines, the minimum cleaner percent should be 20% by volume of the calculated 2–3 mil (0.051–0.076 mm) film based on the diameter and length of the pipeline, taking into consideration also the flow rates to achieve the minimum 10-s residence time. There are various manufacturers of cleaners. However, a careful choice of designed pipeline cleaners should be based upon the following suggested characteristics: Pipeline acid cleaners that completely dissolve solids can be used but may release harmful gases and could also attack pipe wall metals. Other liquid cleaners that dissolve iron sulfide MUST have water in them in order to facilitate the reaction. One popular liquid cleaner contains an active ingredient called tetrakis (hydroxymethyl) phosphonium sulfate (THPS) and can be formulated with an ammonium ion or organic phosphonate to speed up the dissolution of iron compounds [6]. THPS is well known as a highly effective biocide for various water treatment applications, including oilfield downhole treating. However, in those applications, THPS was used in parts per million by volume (ppmv) quantities and only lately is being used in percentages with ethylene glycol to mask the water dew point effects in natural gas for the dissolution of some iron sulfide compounds. THPS dissolves certain iron sulfides by the mechanism of chelation, thereby avoiding the production of any insoluble by-products and any significant amounts of hydrogen sulfide. Tests have shown that 1000 ml of 20% concentrate of formulated THPS solution will dissolve approximately 120 g of iron sulfides (two types tested: trolite [FeS] and pyrite [FeS2]) [6]. In other words, 1 gallon of 20% THPS solution dissolves approximately 1 pound of iron sulfide. Although THPS is environmentally benign and is completely and rapidly deactivated in the presence of free oxygen and/or contact with high-pH products (including alkaline corrosion inhibitors), there may be at least a few hazards associated with its use as a pipeline cleaner. Customers have reported that the use of THPS has coincided with increased volumes of natural gas odorants being added downstream of the cleaning process. THPS is suspected of neutralizing ethyl or methyl-mercaptans and tert-Butyl mercaptan odorants. A second issue has been that the THPS may, in the presence of arsenic, form arsine gas. “THPS under elevated water pressure, inside the pipeline, without question will cause the sulfates to easily ionize. Bacteria, if present, will consume the sulfate ion and convert it to a sulfide ion, which will cause any arsenic present to precipitate. Because phosphorus and arsenic have the same group characteristics, ion exchange will occur if arsenic is present. Phosphorus is unique since it can support five bonds while arsenic can support only four bonds. This is why there is a positive charge on the ion. In the presence of arsenic, the methylene hydroxide molecules will likely polymerize and form glycols or methyl alcohol. Also, if welding on a pipeline with arsenic and THPS has been used, and arsenic has precipitated, arsine gas will easily be formed” (Charles W. Williams Ph.D., Gibsons Environmental Services, USA Personal Communication, 2005 and 2013). Another liquid cleaner is the gel type. Gels are very good carriers, due to their viscosity, but rely heavily on mechanical pigs to disassociate solids from the pipe walls, and then the gels carry the debris out of the line. Thousands of feet, even miles of gel used with mechanical pigs are not unusual while cleaning. Temperature, concentration, and pH can affect the stability of the gel formation. Liquid cleaning can be carried out with two types of cleaning products, liquid and gel, with distinct physical property advantages/disadvantages of both. The term liquid cleaning is used because the term chemical cleaning implies the use of acids and caustics. Even though inhibited acids may be required under special conditions, most liquid cleaners are based on a surfactant and on the relationship between the viscosity and shear rate of the gel [7]. Both types, liquid and gel, require different cleaning procedures, number of personnel, amount of equipment for the project, and the disposal/recycle cost concerns of spent cleaners and solids. Both disposal and recycling, considered off-pipeline costs, are issues that must also be discussed as parts of an overall total package. Off-pipeline costs consist of cleaning of contractor’s separation equipment, cleaning of frac tanks, disposal of urethane pig parts, and any third-party confined space service charges to complete these tasks. This brings us to another most asked question in our industry. “What does ‘clean’ mean?” A more realistic question would be, “What degree of cleanliness is required?” Today, there is no known required level of cleanliness; only a suggested level depending on pipeline diameter and type of ILI tool to be run, which at best is a suggestive opinion. Also, pipeline companies are realizing, as a result of cleaning prior to ILI tool runs, that an additional benefit of cleaning is the cost saving realized due to increased gas and liquid flow with less horsepower required. Service pipelines can be cleaned to a level better than mill-grade new pipe steel and internally coated pipelines [8]. Typical surface roughness data are given in Table 40.1. Table 40.1 Typical Surface Roughness of Internal Pipeline Surfaces Source: Data in μ-inches from Ref. [9]. Note: 1000 μ-in. = 1.0 mil (1/1000 of an in.) [0.0254 mm]. Pipeline companies are performing precleaning efficiency tests and postcleaning efficiency tests, and the results have been very revealing. The degree of cleanliness on single diameter lines is the least stringent for most ILI tool venders. Field experience, of this author’s pipeline cleaning company, has been based on the appearance of cleaning pig(s), both for mechanical cleaning only and synergetic liquid (chemical) cleaning using both cleaning solutions and mechanical cleaning pigs. The appearance for mechanical cleaning is little to no solids in the brushes, little to no folds or major creases on the poly pigs, wear and tear on the steel body discs/cups urethane, and no large metal objects on the magnets. Also, the amount of or lack of solids and/or liquids (appearance) on the back of the pig is also an indicator along with zero to little objects brought in by the pig(s). The appearance of the cleaning pigs used while liquid (chemical) cleaning is the same as mechanical mentioned earlier, but with an obviously cleaner appearance. These pigs may look as good as they were before launching. The added detection indicator in liquid cleaning is the spent cleaning solution itself. Generally, any solids level below 10% by volume, with the degree of clean pig appearance mentioned earlier, is considered acceptably clean for MFL tool runs. Again, the pig magnets should also be void of any large metal objects that could cause sensor liftoff. Cleanliness for ultrasonic type and some circumferential tools is the most stringent. All the aforementioned conditions for liquid cleaning apply, but with the exception of two areas. First, the percent of solids in the spent cleaning solution should be 2% by volume or less versus 10% or less. Second, the magnets on cleaning pigs, in conjunction with the 2% or less solids in the cleaning solution, must be visibly very clean with only US quarter size (~25 mm) or less spots of metal fines on the magnets. The metal fines will look like buttons on the surfaces of the magnets. In multidiameter pipeline segments, cleanliness is equal to that in single diameter lines in mechanical cleaning, with the exception that the transitional areas will be hard to clean but not impossible. Standard designed poly foam pigs have an open cell urethane memory, and the transition zone from smaller pipe diameter to larger diameter means that the cleanliness area will depend on the urethane density and pig speed velocity. Coming from the smaller size diameter, the poly pig requires time to expand to its original size. The distance not cleaned by the pig is based on the gas velocity (pig speed). It is not uncommon for the pig to travel 60–80 ft (18–24 m) before fully expanding. These results have been proven by caliper tool data on these segments after cleaning. One recommendation when using poly foam pigs is to utilize multidensity pigs with the heavier density in the core and the lighter urethane density surrounding the core. Less dense open cell urethane expands quicker. Down side, multidensity polies are not as aggressive. More mechanical cleaning runs may be required. The concerns expressed earlier while using poly pigs also relate to steel body discs/cup cleaning pigs for these multidiameter lines. Designed flexibility in the discs and cups means less aggressiveness, but the upside is the shorter transition zones due to the quick ability of the pig to expand. On average, caliper data have shown the uncleaned transitional areas to be in single digit feet (<2 m). For mechanical cleaning, the cleanliness of the segment is still based on pig appearance and caliper data. Again, all things being equal, the appearance of metal fines on magnets is the same as previously mentioned for the single diameter parameters, both for mechanical and liquid cleaning procedures. The big difference between the two types of cleaning programs (mechanical only versus liquid synergetic cleaning) is that on liquid cleaning the appearance of the cleaning pigs remains the same during the cleaning process2, but the solids loadings of the cleaning solution is 4% or less with again the magnets having only quarter-size metal deposits attached. For ultrasonic and some circumferential tools, the acceptance is the same as for single diameter segments. In summary, the pigging process consists of the following steps: The overall objective in pipeline integrity is to retrieve accurate data on the internal and external condition(s) of the pipeline. For maximum data results, the internal condition(s) of the pipeline can be improved by liquid cleaning to greatly increase the chances of a more reliable and accurate ILI tool performance. Cleaner pipelines yield better data from successful ILI tool runs. Given the aforementioned field cleanliness parameters for both single and/or multidiameter pipelines, the end results are still based on subjective visual appearance(s) of cleaning pigs along with field tests of solids removed in cleaning solutions. These are the best practices today, based on the confirmation from caliper tool data. It is also true that the cleaner the requirement, the higher the cleaning cost. The higher the degree of cleanliness achieved, the higher the pipeline efficiency. The higher the efficiency, the lower the operating cost will be. The cleaner the pipeline, the better the chances for greater ILI tool data results, with better pipeline efficiency operating conditions as an added benefit.
40
Pipeline Cleaning
40.1 Introduction
40.2 Contaminates
40.3 Progressive Pigging
40.4 Pig Types
40.4.1 Poly Foam
40.4.2 Unibody
40.4.3 Steel Mandrel
40.4.4 Polyurethanes
40.5 Durometer
40.6 Mechanical and Liquid (Chemical) Cleaning
40.7 On-Line or Off-Line
40.8 Cleaning a Pipeline
40.8.1 Typical Pigging Procedures
40.8.2 Pipeline Cleaners and Diluents
40.9 How Clean Do I Need To Be?
Pipeline Condition
Surface Roughness
μ-in.
μm
Internally coated (new)
<250
6.3
Standard non-coated (new)
<1800
46
Non-coated after 10 years (average)
±4200
110
Potential corroded pipe (internal)
~18,000
460
40.9.1 Single Diameter Pipelines
40.9.2 Multi-Diameter Pipelines
40.10 Summary
References
Notes