62.1 Introduction

In the oil and gas industry, the term “black powder” is a color-descriptive term typically used to describe the appearance of a blackish particulate material that collects in sales gas transmission pipelines [1–12]. Black powder is a worldwide menace experienced by most, if not all, transmission gas pipeline operators with internally uncoated pipelines. Black powder can be found in different forms, namely, dry fine powder, wet with tar-like texture, or as a slurry. Black powder has been found in recently commissioned as well as in long-service gas transmission pipelines. Figure 62.1 shows that black powder is composed of fine particles when examined at high magnification under the scanning electron microscope (SEM). Figures 62.2 and 62.3 show dry and wet tar-like black powder, collected at a filter station and scraper receiving door, respectively, of gas transmission pipelines.

Case histories show that large quantities of black powder can accumulate over a period of time inside pipelines and at pipeline filter stations. For example, 55,800 kg (123,018 lb) of black powder was removed by mechanical pigging from a 1210 mm (48 in.) 170 km (106 miles) sales gas pipeline by one operator in the Middle East, 3600 kg (7937 lb) of black powder was removed from a 400 mm (16 in.) 80 km (50 miles) gas pipeline in Houston, and approximately 7000 kg (15432 lb) of black powder was removed over a period of 6 months using cyclone separators from a 914 mm (36 in.) Greek sales gas transmission pipeline extending for a distance of 12 km (7.4 miles) [8]. The need to manage such large quantities of black powder can add millions of dollars in operating expenditures including repair and maintenance of control valves, pipeline cleaning, and handling and disposal, as well as require additional capital expenditures including installation of new separators (to be discussed in Section 62.7.1.2).

Black powder is mainly composed of various forms of corrosion products, typically iron sulfides, iron oxides, and iron carbonate, mechanically mixed or chemically combined with any number of contaminants such as salts, sand, liquid hydrocarbons, metal debris, and steel mill scale [1–12]. Typically, the corrosion products make up over 80 wt% of the black powder, and the remaining 20% is contaminants [8]. Different gas pipeline operators report different corrosion products for the black powder removed from their sales gas pipelines. For example, some gas operators reported their black powder as being predominantly iron sulfides [9]; others report the complete absence of iron sulfides, but the presence of iron oxides and hydroxides [1, 2, 4–8, 10–12], while others report a combination of all these products (iron sulfides, iron carbonates, and iron oxides) [3].

Regardless of its composition, black powder has a relatively high specific gravity (sp.gr. 4–5.1), is abrasive, and is typically difficult to remove in routine pipeline cleaning operations [8, 12]. The different forms of black powder have one common source: they are all formed inside sales gas pipelines as a result of corrosion of the internal walls of these lines. Although corrosion is the common cause for all forms of black powder, black powder is a complex phenomenon that is strongly affected by a multitude of factors, including pipeline construction history, dehydration process, commissioning practice, gas composition, service life of the line, and network design. These factors, in many cases, are unique to a specific line within a network. It is important to understand these complex factors to identify the source(s) of black powder, in a specific pipeline, and in turn to devise ways to manage it. Because of this stated complexity, generalized conclusions and “one-solution-fits-all” scenarios might not be valid for all situations.

62.2 Impacts on Operations and Customers

Black powder could have major adverse effects on pipeline operations and sales gas customers, alike [1–12]. For example, black powder could

• Cloud customers’ perception of natural gas as the “cleanest fossil fuel”
  
• Contaminate customers’ gas supply impacting customers’ operations (e.g., frequent replacement of customers’ cartridge filter elements) and customers’ product quality (where sales gas is a feed stock)
  
• Present a major health and environmental hazard (black powder contains Naturally Occurring Radioactive Materials (NORM), Naturally Occurring Mercury (NOM), and can be pyrophoric.)
  
• Cause under-deposit localized corrosion in gas pipelines.
  
• Trigger erosion and/or clogging of pressure control valves and metering instrumentations, leading to deviations in measured transmitted gas to customers. Figures 62.4 and 62.5 show casing and cage, respectively, of a control valve which were eroded by black powder.
  
• Delay in-line inspection (ILI) runs and/or reduce the accuracy of the data gathered by the ILI tools. Thus, timely revalidation of transmission gas pipelines could become an issue.
  
• Reduce gas flow and therefore decreases pipeline operational efficiency, leading to higher costs.
  
• Plug gas burner tips on devices ranging from large power plant burners to residential gas heaters.
  
• Lead to additional operating expenditures (OPEX) (e.g., removal and disposal costs) and capital expenditures (CAPEX) (e.g. installation of filters and cyclones)

62.3 Internal Corrosion of Sales Gas Transmission Pipelines

As stated earlier, black powder is formed inside sales gas pipelines as a result of corrosion of the internal walls of these pipelines. Water is a prerequisite for corrosion to occur, and therefore it is important to identify the potential sources of water moisture in these pipelines (transporting what should be dry gas). Also, it is important to understand the electrochemical reactions that lead to the various corrosion products in order to identify the corrosion mechanism responsible for black powder and develop appropriate mitigation methods.

In typical sales gas production, triethylene glycol (TEG) is used to remove water moisture from the produced natural gas to reduce its water dew point below the lowest temperature found in transportation operations. In the Middle East, and in similar temperature regions (for example, southern USA), transmission gas is dried to a maximum water moisture content of 7 lb/MMSCF. In contrast, in colder regions such as Canada and northern Europe, sales gas specifications are set to a maximum water content of 4 lb/MMSCF.

Because of this drying process, it is often perceived that the threat of internal corrosion in dry sales gas pipelines is highly unlikely, or non-existent, because it is believed that no water condensation will occur, and therefore no internal corrosion can occur. However, field observations show that even under dry sales gas specifications, general internal corrosion is widely encountered, leading to the formation of black powder in these lines [1–13]. The reason for internal corrosion in nominally dry gas pipelines can be attributed to the fact that it is not normally possible to completely eliminate moisture from these pipelines [1–13].

62.3.2 Formation Mechanisms

Internal corrosion of sales gas pipelines can occur when H₂S, CO_2, and O₂ gases present in the sales gas become dissolved in the condensed water moisture and TEG–water mixture solutions. The water moisture containing the dissolved gases reacts with the steel surface, leading to its corrosion (formation black powder). These reactions are electrochemical in nature and have well-established mechanisms. The following are simplified electrochemical reactions that describe these corrosion processes and their respective corrosion products. It is important to note that in all of these electrochemical reactions, condensed water is a necessary condition for these reactions to proceed.

62.3.2.1 Siderite-FeCO₃ (CO₂ Corrosion)

Carbon dioxide (CO₂) is a naturally occurring constituent of natural gas. The source of the siderite–FeCO₃ corrosion product is the chemical reaction of dissolved CO₂ in the condensed moisture, producing carbonic acid, which in turn reacts directly with the steel surfaces to produce FeCO₃, in accordance with these reactions [22–24].

62.3.2.2 Iron Sulfides (H₂S Corrosion)

Iron sulfide (FeS) corrosion products are usually formed from H₂S reacting directly with the steel wall of the pipeline as per the following reactions [25, 26].

Hydrogen sulfide (H₂S) can also be a naturally occurring constituent of natural gas or alternatively, produced by sulfate-reducing bacteria (SRBs). These anaerobic bacteria use the reduction of sulfate as a source of energy and oxygen, in accordance with reactions such as

It is important to note that condensed water is a prerequisite for these bacteria to thrive and multiply, and as such, the above reaction cannot occur in the absence of water.

62.3.2.3 Iron Oxides (O₂ Oxidation)

Oxygen is not a natural constituent of sales gas, but it can ingress during gas-treating operations and gas transportation. For example, oxygen could ingress through leaks at low pressure points throughout the pipeline network or is inevitably introduced due to the use of technical-grade nitrogen gas in blanketing of TEG storage tanks. Technical-grade nitrogen normally contains 3 wt% oxygen. Pipeline pigging operations are also another intermittent source of oxygen entry to the gas network. A 1988 survey of 44 natural gas transmission pipeline companies in North America indicated that their gas quality specifications allowed maximum O₂ concentrations ranging from 0.01 mol% (100 ppmv) to 0.1 mol% (1000 ppmv) with a typical value of 0.02 mol% (200 ppmv) [27]. The actual values of O₂ in the gas stream were low, ranging from 0.0 mol% (0.0 ppmv) to 0.02 mol% (200 ppmv). It has been shown that the oxygen content of approximately 0.001 mol% (10 ppmv) has little effect on steel corrosion in the presence of stagnant water inside gas transmission pipelines, while 0.01 mol% (100 ppmv) produces fairly high corrosion rates. As a general rule of thumb, it is recommended that gas transmission pipelines should consider limiting maximum oxygen concentrations to 0.001 mol% (10 ppmv) [14, 27].

In cyclical wet–dry low dissolved oxygen environments, as is the case in sales gas, iron oxides are usually formed by the direct oxidation of pipeline steel walls, in accordance with the following reactions [22, 28].

In waters containing low concentrations of dissolved oxygen, as is the case in the sales gas environment, the γ-FeO(OH) is unstable and will quickly transform to magnetite–Fe₃O₄ and water by the following reaction [22].

But if the water is nearly saturated with dissolved oxygen, then hematite (Fe₂O₃) is often present [23].

Alternatively, iron oxides may be formed due to microbiologically induced corrosion (MIC) resulting from acid-producing bacteria (APB). Once again, condensed water is a prerequisite for these bacteria to thrive and multiply, and as such, MIC cannot occur in the absence of water.

In reality, a combination of these three gases (H₂S, CO₂, and O₂) is typically present simultaneously in gas pipelines. Which corrosion product forms is mainly a function of the partial pressures of these gases. For example, concentrations of H₂S and CO₂ gases determine the corrosion type (H₂S and CO₂ corrosion) and the type of corrosion products (i.e., black powder). According to Kermani et al. [29], there are three corrosion domains for mixed carbon dioxide/hydrogen sulfide systems, which can be represented by the ratios of their partial pressures in the system:

The above ratios are based on the original work by Dunlop et al. [30] published in 1983. Smith [31, 32] has investigated the origins of the Dunlop ratios and reported that these ratios were developed for low ionic strength solutions at a temperature of 25 °C. These key assumptions cover a narrow range of oilfield environments. Smith proposed that a CO₂/H₂S ratio of below 1 (sour corrosion) and above 5000 (sweet corrosion) is more accurate.

Matters become more complicated when oxygen is present along with CO₂ and H₂S gases in the pipeline. In this case, the corrosion product (black powder) is composed of siderite, iron sulfides, iron oxides, and elemental sulfur. Elemental sulfur is formed by the reaction between O₂ and H₂S [33]. In general, the corrosion rate increases with increasing oxygen partial pressure [34].

Table 62.1 summarizes the main products of black powder and their potential sources.

Constituent	Potential Sources
Fe3O4	Low dissolved oxygen-induced corrosion Conversion of γ-FeOOH Bacterial-induced corrosion (APB and IOB) Conversion of FeCO3 and FeS (inside the pipeline) due to oxygen ingress. Minor Mill scale (minor and limited to newly commissioned pipelines)
α-FeOOH	Low dissolved oxygen-induced corrosion
Iron sulfides	H2S-induced corrosion Chemical source Bacterial source (SRB)
Siderite–FeCO3	CO2 corrosion
Elemental sulfur	Oxygen ingress leading to scavenging of H2S to elemental sulfur and water as per these reactions 2H2S + O2 ➞ 2H2O + 2S (elemental) 3FeS + 2O2 ➞ Fe3O4 + 3S (elemental)

62.4 Analysis Techniques

The importance of analysis and identification of the organic and inorganic contents and particle size range of black powder cannot be overemphasized. Accurate analysis of black powder is important for many reasons. For example, accurate analysis is essential in selecting the proper chemical cleaning procedure and chemistry, identifying the corrosion mechanism responsible for the formation of black powder and developing appropriate mitigation methods and also in developing a proper disposal strategy.

Results of the analysis are as good as the quality of the analyzed samples. Accurate sample analysis starts with accurate collection of representative black powder samples and their proper handling and storage [1, 3, 22].

62.5 Black Powder Movement

Black powder particles entrained in the gas can have a number of adverse impacts on pipeline operations and customers alike. Once black powder starts to move with the gas, it will continue to move until the gas flow rate is reduced or the gas is compressed. Operators report that when black powder moves, it shatters and becomes very small in size, in the range of 1 micron or less, making it difficult to filter and possibly easier to move [45].

Moving black powder particles can present major health and environmental hazards, trigger erosion and/or clogging of control valves and metering instrumentation, and impact customer operations and product quality in numerous ways. These together lead to significant increases in costs. Knowledge of the threshold gas velocity required for the dislodgment and entrainment of black powder particles can significantly assist gas operators in designing the proper filtration systems and in providing advance warning to downstream operations of incoming black powder particles.

According to Smart [46], when black powder is moved through the pipeline by the gas flow, the gas threshold velocity required to move dry solids in a pipeline can be calculated and depends on pipeline diameter, gas pressure, density, viscosity, and particle size and density. For instance, typical gas threshold velocities required at a gas pressure of 1000 psi are 10 ft/s for 8-in. pipelines, 13 ft/s in 24-in. pipelines, and 14 ft/s in 48-in. pipelines [46]. E. Elsaadawy and A. Sherik conducted a computational fluid dynamics (CFD) study to predict the movement and settlement of black powder particles in sales gas pipelines [47]. Pipe sizes in the range 24–56 in., gas velocities of 10 and 20 m/s, and black powder particles with sizes in the range between 2 and 20 μm were studied. The study showed that the particle distribution inside the pipelines was insensitive to the pipe size in the range of velocities and pipe sizes studied. Their work also showed that at the examined gas velocities, black powder particles will be suspended into the gas stream and continue to flow downstream, unless obstructed by a bend or a valve where the sudden changes in direction inside such components may promote particle segregation. They concluded that filter systems installed onto such pipelines should be sized considering the fact that all of the particles size spectrum should be collected in the filtration vessels.

The reader is encouraged to consult references [46–53] for more information on movement of black powder in sales gas pipelines.

62.6 Erosive Properties of Black Powder

The hardness and shape of eroding particles strongly determine the extent of the erosion damage that these particles can inflict on the impacted equipment. The hardness of black powder is an important mechanical property to understand the erosive properties of black powder particles and assists in the selection of equipment such as separator systems and pressure control valves. In one study [6], the hardness of black powder was measured using two different techniques: (1) microhardness measurement of solid-state sintered comingled black powder particles and (2) nano-indentation of individual black powder particles. Comingled and individual black powder particles were collected at a pig receiving door and in-inline using the iso-kinetic probe, respectively. Hardness values of 498 ± 62 VHN (49 ± 4 Rc) and 475 ± 164 VHN (47 ± 10 Rc) were measured by the microhardness and nano-indentation techniques, respectively [6]. The large standard deviation in hardness measurements using the nano-indentation technique is attributed to the fact that hardness indents were made into individual particles, which could be of differing compositions (iron oxides or iron carbonates), which are known to have different hardness values [6].

It is obvious from these hardness values and the jagged shape (Figure 62.1) of black powder that black powder particles can rapidly erode many engineering materials such as pressure control valves made of carbon steel (average hardness value of 87Rb), as can be seen in Figures 62.4 and 62.5. Akbarzadeh et al. [54] investigated the solid particle erosion behavior of 12 control valve candidate materials for use in the sale gas transmission pipeline. The erosion rates were measured using impinging jets of Fe₃O₄ particles at two different particle sizes (6.9 and 30.4 μm), two different velocities (90 and 130 m/s), and six different impingement angles (15°, 30°, 45°, 60°, 75°, and 90°). The most erosion-resistant materials were found to be tungsten carbide (WC) and Stellite 12, and the least erosion-resistant materials were nickel-plated A1018 carbon steel and A240 type 410 stainless steel plates. Elsaadawy and El-Sherik [55] conducted a computational fluid dynamics (CFD) analysis to investigate the erosive behavior of black powder on a pipeline ball control valve. The study showed that the maximum erosion rate takes place on the inside wall of the ball, directly downstream of the inlet, and on the wall just before the outlet on the body (this while the valve was partially closed at 45°). It was also shown that using Stellite 12, instead of A-105 carbon steel and A-505 carbon steels for the body and ball of the valve, respectively, could considerably reduce the erosion rate of the valve [55]. Based on these studies, Saudi Aramco has retrofitted CS control valves with trims designed to resist erosion, such as solid tungsten carbide for valve cages and tungsten carbide inserts for valve plugs and seat rings.

Another CFD study [56] published by the same authors examined the erosive effects of black powder particles on pipeline bends with different radius of curvature to pipe diameter ratios (R/D = 1.5 and 3.0). The study showed that a pipeline bend with a longer radius of curvature will have a more uniformly distributed erosion over the outer wall of the bend, which makes it a better candidate for applications in severe erosive service environments such as sale gas pipelines loaded with black powder. However, the erosion rates in both cases are negligible and should not affect the operational life of the bends.

62.7 Black Powder Management Methods

There are several removal and prevention methods available to gas pipeline operators to mitigate the formation of black powder and manage its impacts [1, 3, 41, 43, 57, 58]. Typically, there is no single best solution to control black powder. For example, in the case of existing uncoated pipelines, strict adherence to gas specifications namely, water moisture and TEG vapor loss contents in the gas entering the network, would ensure elimination of condensed moisture and in turn the formation of black powder. However, because of the inevitability of process upsets, excess moisture may enter the line grid, leading to potential condensation and internal corrosion. Therefore, the optimum black powder management practice usually consists of a combination of several control methods that must include moisture control coupled with downstream removal methods such as filtration. In contrast, in the case of new pipelines, internal coatings primarily used for drag reduction provide a cost-effective and economical solution for the prevention of black powder.

Generally, pipeline companies practice various methods to manage and control black powder in their gas networks. Management approaches can broadly be divided into two categories: (1) removal and (2) prevention strategies.

62.7.1 Removal Strategies

Black powder products tend to have a high density (e.g., approximately 4–5.1 g/cm³) and are abrasive and difficult to remove in cleaning operations, particularly when wet (for example, mixed with TEG and/or compressor oil). Removal strategies can be divided into two main approaches: (1) Cleaning of pipelines by pigging the lines to remove black powder accumulated at the bottom of the pipe and attached to the pipe’s internal surfaces and (2) Capture of moving black powder through the installation of separators, at strategic points along the network, to remove black powder particles entrained in the gas, ensuring solid-free gas downstream of these devices.

62.7.1.1 Pipeline Cleaning¹

Sales gas pipelines are pre-commission cleaned to remove mill scale, construction debris, sand, and other solids that make up a small portion of black powder and post-commission cleaned to remove black powder which forms due to corrosion while the line is in service.

Post-commission cleaning of in-service gas pipelines is performed mainly for the following reasons:

1. Increase operational efficiency.
   
2. Facilitate effective corrosion inspection (enhance the accuracy of ILI data).
   
3. Increase operational safety.
   
4. Alter operational parameters.

Pipeline cleaning is typically performed by dry pigging (mechanical cleaning) and/or chemical cleaning. When a cleaning plan is implemented, waste disposal must be considered up-front due to the large quantities of solids and solvents (in cased of chemical cleaning) used in the operation. This is especially important if the removed black powder is contaminated with naturally occurring radioactive materials (NORM) or naturally occurring mercury (NOM).

57.4.2.2 Mechanical Cleaning

Mechanical cleaning typically involves moving a pipeline inspection gauge (PIG), through the pipeline by means of a gas pressure differential for the purpose of removing solids and accumulated liquids. PIGs (also named scrapers) are generally made of polyurethane foam and shaped like oversized bullets. They are inserted into a pipeline by a specially designed launcher that is connected to a high-pressure medium to propel the scrapers. The polyurethane material used for the scrapers is sufficiently flexible that it will negotiate bends in the line. Depending on the required level of cleanliness, other types of pig (scraper) designs such as hard rubber, silicon carbide, and hardened steel wire can be used. The use of advanced mechanical cleaning tools to physically remove black powder can further improve the removal efficiency of the pigging operations. These advanced designs include bidirectional disks, brushes, magnets, front-end jet nozzles, and supporting wheels.

A significant portion of any pipeline cleaning job is performed by dry mechanical scrapers used to perform the cleaning job. In pipelines where black powder is not a major problem, this cleaning method may suffice to keep the pipeline in a fairly clean condition. However, this cleaning method is not effective when the black powder problem becomes major (large quantities). In addition, pipelines with large amounts of black powder could cause the pig to become stuck in the line, thus stopping operations.

For pipelines with serious black powder formation, dry mechanical cleaning is typically not effective in removing the black powder. In this case, a combined approach of mechanical and chemical cleaning is employed.

57.4.2.3 Chemical Cleaning

To achieve greater removal of black powder from gas pipelines with fewer cleaning runs liquid cleaning, referred more commonly to as chemical cleaning, is becoming the industry standard. Chemical cleaning is more effective than mechanical cleaning, but it is significantly more complex and expensive. Chemical cleaning is normally achieved by loading the cleaning chemicals between an aggressive scraper front pig and a sealing pig in the rear. It is typically used when the lines are suspected of having large quantities of black powder.

The addition of a chemical cleaner greatly improves the performance of the mechanical pigging operations. An easy analogy to consider is that the chemical cleaner acts as the liquid soap and the scraper acts as the brush. Chemical cleaners are used to

1. Enhance the penetration into the solid deposits
   
2. Soften and loosen the deposits
   
3. Lift and carry the solids out of the line

There are several chemical cleaning agents used for the removal of black powder from transmission gas pipelines. Gel cleaning and surfactant cleaning are the most common solutions used. Gel shows excellent capability to carry large amounts of solids, but in situations where cleaning has to be done online, dealing with large slugs of gel becomes problematic. Also, removal of gel residues from the pipeline needs extra attention. Surfactant cleaning has a proven record in removing black powder. These chemicals can be dissolved in diesel or organic solvents (dissolution in water should be avoided to ensure the pipeline is not exposed to water). Surfactants will have the ability to penetrate contaminants and lower the surface tension properties of the pipeline, leading to the removal of large amounts of black powder.

Table 62.4 compares mechanical and chemical pipeline cleaning methods. The reader is asked to consult references [59–63] for information on pipeline cleaning.

57.5 Pipeline Cleanliness

Regardless of which cleaning method (mechanical or chemical) is used, when is a pipeline is considered clean is the most difficult question. First of all, there is NO industry standard, but it is left to each pipeline operator to set its own cleanliness level and how to measure it to meet a specified objective [60, 62]. Generally, the objective of specifying the cleanliness acceptance criterion is to verify the efficiency of the cleaning procedure to meet “end-user” requirements. With this in mind, cleanliness can mean pipeline internal conditions that minimize or eliminate ILI sensor lift-off for the purpose of enhancing the accuracy of ILI inspection. It can also mean minimizing or eliminating the impact of contaminated gas on customers’ operations (e.g., frequent replacement of customers’ cartridge filter elements) and customers’ product quality (where sales gas is a feed stock) [1].

Method	Value/Applications
Dry/mechanical cleaning	Ease of application Effective in cleaning pipelines with small quantities of black powder Does not take the line off-stream or introduce liquids into the network Requires launching and receiving pig doors. Debris that have lodged against the inner pipe walls are very difficult to remove, which could lead to reduced accuracy of MFL ILI and a possible false assumption that the line is clean.
Chemical cleaning	Relatively expensive and more complex than dry mechanical cleaning Requires prior laboratory identification of black powder composition and evaluation of cleaning chemicals to select most effective cleaning chemistry. Very effective in removing all black powder in fewer runs than dry mechanical cleaning Does not take the line off-stream Requires launching and receiving pig doors Disposal of large quantities of black powder, and the cleaning chemicals is costly

Pipeline operators can utilize different tests to measure the cleanliness level of their pipelines. The most common measures are as follows: gas flow rates, differential pressure measurements, differential pressure drop across filters, visual inspection of filters and separators, geometry tool, and visual cleanliness of cleaning fluids or pigs during their removal from receivers [62]. Validation of the cleanliness level using these test methods should follow the “measure-until-clean” concept, which involves pipe cleaning and measuring with repetition of this sequence until an acceptable measurement set by the operator is attained.

Higher-resolution measurement of the level of cleanliness can be attained by measuring black powder loading in the cleaning solution. Solid loading is defined as the ratio of the weight of solids in a cleaning sample divided by the volume of that sample, typically expressed in mg/L.

In this case, validation of the cleanliness level should follow the “test-until-clean” concept, which involves pipe cleaning, sampling, and testing with repetition of this sequence until an acceptable “solids loading” limit set by the operator is attained. One oil and gas company in the Middle East sets as a maximum solid loading of 5 g/l for their sales gas pipelines to be considered clean.

62.7.1.2 Black Powder Capture Methods

Black powder particles entrained in the gas can be captured through the use of separators installed at strategic points along the network. As the name implies, separators are devices that separate out the solids (black powder) entrained in the gas from the gas for the purpose of producing solid-free gas downstream of these devices. There are several types of separators, each named after the separation principle on which it is based

• Cyclone separators
  
• Cartridge filters
  
• Cyclo-filters
  
• Magnetic separators
  
• Wringing separators

One common feature to all of these separation technologies is their modular design, which permits their installation at strategic points throughout the network to protect downstream assets and customers. There are many differences among these technologies that need to be considered during the decision-making stage of selecting the appropriate separation technology. The following sections provide a brief description of each technology, and Table 62.5 provides a comparison of the value and application of these technologies.

57.5.2 Cyclone Separators

These separators are based on the principle of centrifugal force. The black powder-laden gas passes through these devices, and the black powder particles are physically knocked out of the gas stream to the walls of the separator where they fall and are collected at the bottom in a collection hub. The separation efficiency of cyclone separators is not constant but decreases when the flow rate is variable. Cyclone separators are most effective when the concentration of solid particles is relatively high and the particle size is relatively large (larger than 8–10 μm) [45].

Separation Technology	Value/Applications
Cyclones	Separation efficiency of ≥99% of 8-μm size contaminates over a wide range of flows. Separation efficiency decreases when the gas flow rate is not constant. Highly effective for gas with a high concentration of dry solid particles with a particle size larger than 8 μm Less effective in separating sticky or tacky black powder Does not clog and therefore negligible differential pressure drop Low maintenance requirements (no moving parts)
Cartridge filters	Separation efficiency of ≥99% of 3-μm size contaminates over a wide range of flows. Effective separator for removal of submicron-sized solids Solid particles can build up and clog the filters, leading to high pressure drop Single use Disposal of black powder-filled cartridges is costly
Cyclo-filters	Large units and costly Separation efficiency of the cyclone stage decreases when the gas flow rate is not constant. Disposal issue of black powder-filled cartridges Could lead to reduced gas flow if filters are not replaced in timely manner.
Magnetic separators	Separation efficiency of ≥95% efficiency regardless of size (≤0.1 μm to >500 μm) for magnetic particles. Can also remove non-ferrous contaminates due to the principles of electrostatic charge and particle adhesion Does not clog and therefore negligible pressure drops Easy to clean Minimum maintenance requirements (no moving parts) Multiple use (the magnets typically have a 10+ year life) Less effective in large-diameter pipes
Wringing separators	Constant separation efficiency of ≥99% of 1-μm size contaminates over a wide range of flows. Lower capital and operating costs One-stage removal for solid and liquid contaminants from gas streams. No replaceable filter elements Minimum maintenance requirements (no moving parts). Online cleaning, which eliminates the need for sparing. Negligible differential pressure drops

57.5.3 Filters

The design and size of these filters will depend on the amount of black powder, its particle size, and hardness. This separation technology is generally successful in capturing dry fine black powder down to submicron particle sizes, but it is sensitive for handling wet black powder, which may result in vibration or premature blockage of the filters [42, 43]. A number of different filter materials are available. Cellulose, glass fiber, and polypropylene are the most common types [42, 43].

57.5.3.1 Cyclo-Filters

Cyclo-filters combine the best features of cyclones and filters in a two-stage removal process. The first stage of the removal is achieved by the cyclone, which knocks out black powder particles larger than 8–10 μm. The second stage which includes cartridge filters removes the finer black powder particles.

Although these separators have been generally successful in protection of downstream operations including major equipment and customers, this technology involves high capital and operating costs due to the need for redundancy and frequent maintenance to replace spent filter cartridges and eroded parts. Additionally, the cartridge filters are sensitive for handling wet black powder, which may result in vibration or premature blockage of the filters.

57.5.3.2 Magnetic Separators

Magnetic separators employ a powerful radial magnetic field technology that is capable of removing black powder particles (both ferrous and non-ferrous) to sub-micron levels without flow restriction. Magnetic separators offer high-efficiency removal of black powder contamination from all hydrocarbon systems without the need for extensive replacement of filter elements [3, 45]. These separators have a long operational life, have very little consumables, and have three levels of service from manual cleaning to fully automated systems designed for employment on all sizes of gas pipelines.

Wringing Separators

The operating principle of the wringing separator technology is based on the use of the boundary layer current generated by the main gas flow along the walls of a spiral duct. The separator’s geometry creates the necessary conditions for the fine black powder particle liquid droplets entrained in the flow to accumulate within the boundary layer current. The boundary layer current then transfers the separated particles and liquid droplets to a hub placed at the bottom of the separator. The reader can consult references [64, 65] for more information on wringing separators.

Each of the above removal methods can be applied separately or in combination. For example, mechanical cleaning by instrument scraping can be combined with installation of one of the separation technologies downstream closest to the customer. This combination ensures that the scraped black powder gets captured out from the gas supply before reaching the customer. If there are liquids or large amounts of black powder present in the gas, one of the best ways to remove them is to utilize the combination of cyclones (for bulk and liquid removal) and filters (for fine particle separation).

Although the black powder removal strategy is successful in protecting downstream operations, including protecting the customers from the impacts of black powder, the removal methods have several common drawbacks:

• Considered after-the-fact treatments, i.e., they do not address the root cause of black powder formation.
  
• Are not a one-time-solution but require frequent applications (i.e., frequent cleaning), and multiple location installations (i.e., separators) throughout the network are most often necessary
  
• Constitute an additional cost to the ongoing operational costs of gas transport systems
  
• Subsequent handling and disposal procedures and processes are required. The handling and disposal procedures could become challenging and costly if the black powder contains health and environmentally hazardous materials such as mercury and naturally occurring radioactive materials (NORM).

62.8 Monitoring Black Powder

Monitoring of black powder build-up in a pipeline is an important exercise to proactively manage black powder impacts. Black powder monitoring can serve multiple objectives, namely, to determine if the line and separators are due for cleaning, filter cartridges are due for replacement, and also to check the health of the TEG dehydration process. Pipeline operators utilize different measures to monitor black powder build-up in their pipeline network. Many of these measures are already built-in into the network with no or minimal additional cost. The most common measures are as follows: gas flow rates, differential pressure measurements, differential pressure drop across filters, visual inspection of filters and separators, geometry tool measurements, and visual cleanliness of cleaning fluids or pigs during their removal from receivers. Operators can also resort to introducing probes such as non-intrusive ClampOn sand meters and the intrusive laser iso-kinetic probe (already discussed in Section 62.4).

The ClampOn sand meters are used in oil and gas production piping to detect sand production. Two types are used, one which measures erosion caused by the sand and the other listening for the pings made by sand particles hitting the wall or probe. ClampOn sand probes are acoustical and can be mounted on the outside of the pipe, typically at a T-joint or a bend. These meters could also be used to detect black powder movement in pipelines as moving black powder particles will cause pings at the internal walls of the pipe bend, whose acoustical signatures can be monitored through the wall thickness.

62.9 Guidance on Handling and Disposal of Black Powder

Naturally occurring radioactive materials (NORM), principally the radionuclides Lead-210 (Pb-210) and Polonium-210 (Po-210), and naturally occurring mercury (NOM) have been identified in black powder found in many transmission gas lines [66–70]. Naturally occurring radionuclides are abundant in the Earth’s crust and originate from the presence of uranium or thorium. As gas, oil, or water is produced from ground formations, some radionuclides, such as radon in gas and radium in water, can migrate to surface facilities and create NORM or NOM as scales or deposits. The decay scheme for the most abundant uranium radionuclide, ²³⁸U, is shown in Figure 62.6.

Exposure or uncontrolled release of NORM and NOM is considered to represent potential exposure hazards to workers and the community. The importance of obtaining reliable data on these contaminants is considered essential for making informed decisions on the development of hazard evaluation and environmental control strategies. For this reason, Saudi Aramco set up a NORM and NOM mapping program of its sales gas transmission lines [69, 70]. Approximately 30 locations throughout the sales gas network were identified for sample collection. It is believed that these locations will address any geographical, temporal, or seasonal variations in radioactivity concentrations. A minimum of three samples were collected from each location separated by a long period of time (months) to ensure seasonal variations. This program was believed to provide the company with credible and representative data. The radionuclides ²¹⁰Pb and ²¹⁰Po were selected for the study due to their relatively long half-lives (22 years and 138 days, respectively) and confirmed radiotoxicity. Mercury, observed as a contaminant in produced gas and also an environmental concern, was included in the program. The analysis of the Pb-210 and Po-210 required extensive method development to attain satisfactory analyte recoveries from the black powder matrix. The main problem was to overcome the chemical interference of high levels of iron in the black powder acid extracts. The Po-210 method involved the deposition of polonium from dilute acidic solutions onto a silver disc, with the Po-210 determined using alpha spectrometry [69]. Two methods were identified for the determination of Pb-210, which decays by low-energy beta and low-energy gamma (46.5 keV) emissions. The method of choice for the Pb-210 analysis involved liquid scintillation counting, which was found to be suitable for the low levels encountered and provided acceptable sample throughputs. Exemption levels of 0.20 Bq/g were established for each radionuclide of concern (Pb-210 and Po-210) [69]. Exemption levels are defined as radiation activity concentration levels below which a material is considered exempt from control as NORM. These exemption levels for radionuclides of concern in sales gas pipelines are detailed in Table 62.6.

The results of this mapping campaign showed that over 70% of the samples collected indicate levels of Pb-210 and Po-210 above the exemption level and therefore would be regarded as having enhanced levels of NORM [69].

NOM analysis was conducted using the toxicity characteristic leaching procedure (TCLP) as per US Environmental Protection Agency Method 1310 and was used to establish whether a solid waste is hazardous, based on specified limits for selected metals. The TCLP data also indicate the relative environmental mobility of selected metals. Black powder samples were extracted with an amount of extraction fluid equal to 20 times the weight of the sample. The extraction fluid employed was determined based on the alkalinity of the solid phase of the waste. Following the extraction, the liquid TCLP extract was separated from the solid phase by filtration through a 0.6–0.8 nm glass fiber filter.

Exemption levels below which no action is required have been established for mercury. These exemption levels are as follows: total Hg of 0.4 mg/kg and TCLP Hg of 0.2 mg/l [69].

62.10 Solutions

The following measures can effectively mitigate black powder formation and manage its impacts

1. Good hydro-test practices. More specifically,
   
   
   
   • Perform pre-commission chemical cleaning to remove corrosion products, mill scale, construction debris, sand, and any other contaminants.
     
   • Use high-quality water (low TDS). If sweet water is not readily available in the field, then fresh water slugs can be used between pigs to wash the line and remove salt water prior to the drying stage.
     
   • Dry the lines with nitrogen or dry sales gas (do not use hot air for drying)
   
   
2. Strict adherence to water moisture and TEG content specifications in the exported gas. This can be achieved through
   
   
   
   • Proper sizing and operation of TEG dehydration units.
     
   • Installation of moisture analyzers at TEG units to accurately monitor water moisture content.
   
   
3. Strict adherence to company specifications of corrosive gases (H₂S, CO_2, and O₂)
   
4. Eliminate O₂ ingress to the pipeline network. This can be achieved through
   
   
   
   • Blanket TEG storage tanks and pigging operations with fuel gas instead of nitrogen gas.
     
   • Identify leakage points and fix them.
   
   
5. Install black powder separators at strategic locations along the network to protect downstream operations and customers.
   
6. Clean pipelines on-need basis
   
7. Use internally coated pipelines in new projects

62.11 Summary

The following summarizes key aspects of black powder in transmission sales gas pipelines:

• Black powder is a worldwide menace experienced by most, if not all, transmission gas pipeline operators with internally uncoated pipelines.
  
• Black powder is mainly composed of various corrosion products formed inside sales gas transmission pipelines as a result of low corrosion rates of the internal walls of these lines.
  
• Pipe wall thickness losses resulting from these low corrosion rates do not impact the integrity of the pipe, but the amount of generated black powder, especially in large and long pipelines, has major impacts on pipeline operations and customers alike.
  
• The jagged shape and high hardness of black powder particles make them erosive to many pipeline control valve materials.
  
• Some black powder contains NORM and NOM and can be pyrophoric, necessitating special handling and disposal procedures.
  
• Black powder is a complex phenomenon that is strongly affected by a multitude of operational parameters and network design, which, in many cases, are unique to a specific line within a network. Therefore, generalized conclusions and a “one-solution-fits-all” scenarios might not be valid for all situations.
  
• Pipeline operators and owners’ typically implement different management strategies to mitigate black powder formation and manage its impacts.

Acknowledgments

The author would like to thank Saudi Aramco for the permission to publish this work.

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