Black Powder

Managing Black Powder in Sales Gas Transmission Pipelines Authors: Dr. Abdelmounam M. Sherik, Dr. Arnold L. Lewis and Dr. Sebastien Duval

ABSTRACT

INTRODUCTION

Despite its common occurrence in the gas industry, black powder is a problem that is not well understood across the industry, in terms of its chemical and physical properties, sources, formation mechanisms, prevention or management of its impacts. To To prevent or effectively manage the impacts of black powder, it is essential to have knowledge of its chemical and physical properties, formation mechanisms and sources. This article is a follow-up to an earlier article published in the Saudi Aramco Journal of Technology Fall 2007 issue. In that issue, it was shown that black powder is regenerative, and is formed inside natural gas pipelines as a result of corrosion of the internal walls of the pipeline. More specifically, black powder forms through reactions of the pipelinee steel with condensed water containing oxygen (O 2), pipelin hydrogen sulfide (H2S), and carbon dioxide (CO 2). This article is divided into three parts. The first part of this articlee is a synops articl synopsis is of publis published hed literature literature includ including ing our earlier findings. findings. New field evidence showing the presen presence ce of excess moisture in the lines will be presented and discussed. The second part is a summary and short discussion of various black powder management philosophies and methods. Finally, the ongoing black powder research activities at the Saudi Aramco Research and Develop Development ment Center (R&DC) are briefly presented.

Black powder is a worldw worldwide ide phenomenon experienced experienced by most, if not all, Sales Gas pipeline operators 1-6. In the gas

Fig. 1. Shows wet tar-like black powder collected at the scraper door receiver of a Sales Gas pipeline.

Fig. 2. Dry fine black powder collected at the scraper door receiver of a Sales Gas pipeline.

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SAUDI ARAMCO ARAMCO JOURNAL JOURNAL OF TECHNOLOGY TECHNOLOGY

industry, the term “black powder” is a color-descriptive term loosely used to describe a grayish material that is generated inside the gas pipelines. Black powder can be found in several forms, such as wet with a tar-like appearance, Fig. 1, or dry in the form of a very fine powder, Fig. 2. Black powder was reported in recently commissioned as well as older Sales Gas transmission pipelines 1-6. Black powder could have major adversee effect advers effectss on customers by contami contaminating nating the custom customer er Sales Gas suppl supply y leading to an interr interruption uption of the custom customer’ er’ss operations and/or poor quality of products in which the Sales Gas is used as feedstock. It could also negatively affect gas pipelinee operat pipelin operations. ions. For example, it can lead to instrument scraping delays, reduced inline inspection accuracy, control valve erosion as well as flow reduction. reduction. Finall Finally y, black powder could present a major health and enviro environmenta nmentall hazard. This is because some black powder is contaminated with mercury and naturally occurring radioactive materials, such as radioactive Lead-210 (Pb-210). Iron sulfides are also potentially pyrophoric. These hazardous substances require special procedures procedures for handli handling ng and dispos disposal al of the removed black powder.

COMPOSITION AND SOURCES As used in the surveyed literature, “black powder” means various forms of iron sulfide (FeS), iron oxide (Fe 3O4, FeOOH) and iron carbon carbonate ate (FeCO3), mechanically mixed or chemically chemica lly combined with any number of contam contaminants inants,, such as salts, sand, liquid hydrocarbons hydrocarbons and metal debris debris.. Differ Different ent gas pipeline operators report different compositions for the black powder removed from their pipelines. pipelines. For example example,, whereass some literature wherea literature reports black powder as being predominantly iron sulfides 1-3, others repor reportt the complete absence of iron sulfides, but the presence of iron oxides and hydroxides such as Fe3O4 and FeOOH4, 6 , while others report a combination of all of these products (iron sulfides, iron carbonates and iron oxides) 5. These products have one common source, which is that they are formed inside natural gas pipelines as a result of corrosion of the internal walls of the pipeline1-6. More specif specifically ically,, they are formed by reacti reactions ons of iron (Fe) present in ferrous pipeline steel with condensed moisture containing oxygen (O2), hydrogen sulfide (H 2S) and carbon dioxide (CO2). Internal corrosion in “dry” gas pipelines is often overlooked due to an underestimation of the corrosion risk due to the perceived absence of condensed water in the line 1, 7 . Under normal conditions, conditions, gas pipeli pipelines nes are under minimal corrosion risk; however, it is generally not feasible to completely eliminate water from pipelines 7. Water vapor can potentially condense on the inner walls of the pipeline due to high dew points. It can also enter the pipeline through periodic upsets that cause moisture carry-over into the line. This water, water, coupled with corrosive corrosive species such as CO2, H2S and O2, even in small amounts, as low as ppm levels,, can result in unexpec levels unexpected ted internal corrosion corrosion with the formation of corrosion products, namely FeCO 3, FeS and iron oxides, respectively1, 5 . It should be noted that CO 2, H2S and O2 are benign in dry gas, but become corrosive in the presence of condensed water1.

FORMATION MECHANISMS Internal corrosion of Sales Gas pipelines is the main cause for the formation of black powder. Corrosion due to H 2S, CO2 and O2 in Sales Gas pipelines has well established mechanisms. Following are simplified electrochemical reactions that describe these corrosion processes and their respective respec tive corrosion corrosion produc products. ts. It is important to note that in all of these electrochemical electrochemical reactions, reactions, condensed water is a necessary necess ary condition for these reactions to proceed proceed.. Iron Carbonate Formation due to CO 2 Corrosion

Iron carbonate carbonate corros corrosion ion product found in black powder is formed by the chemical reaction of CO 2, a natura naturally lly occurring constituent const ituent of natur natural al gas, with condens condensed ed water producing carbonic carbon ic acid (H2CO3), which in turn reacts directly with steel to produce FeCO3, in accordance with these reactions 8:

H2O (condensed water) + CO 2 (in gas) → H2CO3

(1)

H2CO3 + Fe (pipeline steel) → FeCO3 + H2

(2)

Iron Sulfides Formation due to H 2S Corrosion

Hydrogen sulfide can be a natur Hydrogen naturally ally occurring constituent constituent of natural gas, or alternatively, produced by sulfate reducing bacteria (SRBs)1. These anaerobic bacteria use the reduction of sulfate as a source of energy and oxygen, in accordance with reaction such as1, 2 : 2H+ + SO4-2 + CH4 → H2S + CO2 + 2H2O

(3)

Iron sulfide corrosion corrosion products are usual usually ly forme formed d from H 2S dissolved disso lved in condens condensed ed moist moisture ure reacting directly with the steel wall of the pipeline shown in the following reactions 1, 2 : H2O (condensed water) + H 2S (in gas) → H3O+ + HS-

(4)

HS- + Fe (pipeline steel) → FeS + H2

(5)

Iron Oxides Formation due to Oxidation

The source of oxygen in gas pipelines is oxygen ingress through leaks at low-pressure points throughout the systems 1. Oxygen ingress in gas lines can cause significant corrosion in small concentrations concentrations and even combus combustion, tion, if presen present, t, in larger 9, 10 amounts . A 1988 survey of 44 natural gas transmission pipeline pipeli ne companies in North America indicated that their gas quality specifications allowed maximum O 2 concentrations ranging from 0.01 mol% to 0.1 mol% with a typical value of 0.02 mol%9, 10. It has been shown that oxygen content of approximatel approx imately y 0.01 mol% has little effect on steel corrosion corrosion in the presence of stagnant water inside Sales Gas transmissi trans mission on pipeli pipelines, nes, while 0.1 mol% produc produces es fairly high corrosion rates. As a general rule of thumb, it is recommended that transmission pipelines should consider limiting maximum oxygen concentrations to 10 parts per million by volume (ppmv) (0.001 mol %) 9, 10. In cyclical wet-dry environments with low dissolved oxygen, such as those experienced in gas pipelines, iron oxides are usually formed by the direct oxidation of pipeline steel walls, in accordance with the following reactions8: 2Fe + H2O (condensed water) + 3/2 O 2 → 2 Fe FeO( O(OH OH))

(6)

The FeO(OH) can be in α, β or γ form. In these type of environments, γFeO(OH) is unstable and will quickly transform to magnetite (Fe 3O4) and water by the following reaction8: 8γ -FeO(OH) + Fe → 3Fe3O4 + 4H2O

(7)

But if the water is nearly saturated with dissolved oxygen, then hematite (Fe2O3) is often present 8.


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Compound Fe3O4

Main Source Low Lo w di diss ssol olve ved d ox oxyge ygenn-in indu duce ced d corr co rros osio ion n (r (rea eact ctio ions ns 6 an and d 7) 7)..

α -FeOOH

Low dissolved oxygen-induced corrosion (reaction 6). CO2 corro corrosion sion (reactions (reactions 1 and 2).

FeCO3

Minor Source 1. Ba Bact cter eria iall-in indu duced ced cor corro rosi sion on (A (APB PB,, IO IOB) B).. 2. Co Conv nver ersi sion on of Fe FeCO CO3 and FeS (in-situ) due to oxygen ingress (reactions 8 and 9). 3. Mill scale (minor (minor and short-term) short-term)..

Table 1. Compounds in black powder and their respective potential sources

50.00

45.00

f 40.00 c s m35.00 m / b30.00 l , s 25.00 a G n20.00 i e r 15.00 u t s 10.00 i o M 5.00

f c 45.00 s m m40.00 / b l 35.00 , s 30.00 a G25.00 n i e 20.00 r u t 15.00 s i o 10.00 M

Average of Moi sture Contents during Upset Period

7 lb/mmscf

5.00

5.0 °C

0.00

0.00 6/12

25 lb/mmscf

8/11

10/10

12/9

2/7

4/8

-15

6/7

-10

-5

0

5

10

25 °C 15

20

25

30

35

40

Dew Point, °C

Time Ti me (Jul (July y 2006 2006 - June 200 2007) 7) Fig. 3. Actual reading of moisture content in the Sales Gas in plant A. Two extended upsets can also be seen. An average value of moisture content experienced during the latter upset is indicated.

Fig. 4. A variation of the dew point with moisture in the gas. The water content value experienced during process upset shown in Fig. 3 and corresponding dew point are indicated 14.

Alternatively, iron oxides may be formed due to microbiologically logical ly induced corrosion corrosion (MIC) resulting resulting from acid producing produc ing bacteria (APB) or iron oxidizing bacteria (IOB) 11. 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 water.. Magnetite found in black powder can also come from other sources, namely, (1) mill scale, which is expected to be a minor and short-term (in new pipelines) black powder 4 contributor, and (2) conversion, by oxidation inside the pipeline, of FeCO 3 and FeS corrosion products. The conversion of FeCO 3 to Fe3O4 is sluggish and takes place during the dry cycles in accordance with the following reaction12:

result of internal corrosion of the pipeline, (2) black powder particles are jagged in shape and exhibit a high hardness, which makes it highly erosive to the currently used pipeline control valves, and (3) is mainly composed of the corrosion products Fe3O4 and FeO(OH), with fewer samples showing small amounts of FeCO 3 in addition to the iron oxides. Table 1 summarizes summar izes black powder compounds and their potential sources. In addition, we found that some black powder samples contained mercury. Further, the reason for the internal corrosion was determined to be condensed water containing H 2S, CO2 and O2, with oxygen being the most critical element. The source of the condensed moisture is the inefficient gas dehydration processes in some of the gas treating plants. Inefficient dehydration causes the Sales Gas to contain high levels of moisture in excess of the maximum allowable level of 7 lb/mmscf (7 pounds of water in a million standard cubic feet of gas) as per Saudi Aramco Sales Gas Product Specification (SA-120). Figure 3 shows levels of moisture in the Sales Gas from one gas treating plant. It is clear from this Figure that two deviations (upsets) from the 7 lb/mmscf standard level have occurred for extended periods of time. Figure 4 14 shows dew point variations vs. moisture content in the gas at a line pressure of 900 psig. It can be seen from this Figure that strict adherence to the Saudi Aramco specification of 7 lb/mmscf (with a dew point of 5 °C) is sufficient, under typical ambient temperatures in Saudi Arabia, to ensure no water condensation. This Figure also shows that if excess moisture enters the gas grid

3 FeCO3 + 1/2 O 2 → Fe3O4 + 3CO2

(8)

The conversion of FeS is rapid and can occur during the wet cycles accordi according ng to the following reaction7: 2Fe9S8 + 9H2O + 27/2 O2 → 18γ -FeO(OH) + 2S8

(9)

The produc produced ed γ-FeO( -FeO(OH) OH) will quickl quickly y trans transform form to Fe 3O4 8 in accordance with reactio reaction n (7) .

SAUDI ARAMCO BLACK POWDER Our recent findin findings gs13 have shown that black powder: (1) is regenerative and is formed inside Sales Gas pipelines as a 44

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(as the case of inefficient dehydration experienced in plant A, Fig. 3) the dew point significantly increases and water condensation could potentially occur at 25 °C.

BLACK POWDER MANAGEMENT METHODS Generally, pipeline companies practice various methods to manage and control black powder in the gas line grid. These methods can broadly be divided into two categories: (a) Removal methods, and (b) Prevention methods. Removal Methods

For many years years,, pipelin pipelinee compani companies es have observ observed ed the presence of black powder and its effects, but have viewed it only as a nuisance and therefore have done little to understand it and prevent it. Because of this management philosophy, most efforts have focused on the removal of black powder. There are several removal methods: • Mechanical cleaning. Mechanic Mechanical al pigs are common commonly ly deployed into a pipeline to scrape debris from the pipeline wall and remove black powder. In cases 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 gives poor results when the black powder problem becomes major (large quantities). • Chemical cleaning. There are severa severall chemical cleaning cleaning agents used for the removal of black powder from gas pipelines. pipelin es. Gel and surfactant surfactant cleanin cleaning g are the most common solutions used. The gel shows an excellent capability to carry large amounts of solids, but in situations where cleaning has to be done online, dealing with large batches of gel becomes problematic. problematic. Also, removal of gel residues from the pipeline needs extra attention. attent ion. Surfactant Surfactant cleanin cleaning g 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 Surfac tants will have the abilit ability y to penetrate contaminants contaminants and lower the surface tension properties properties of the pipeline leading to the removal of large amounts of black powder. • Separators. The use of separators and cyclones is 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. This removal method is effective only if the concentration of solid particles is relatively high, and if the particle size is relatively large (larger than 8 μm to 10 μm). It should be noted that the Saudi Aramco black powder exhibited exhibited an average parti particle cle size of less than 1 μm. • Filters. These are usuall usually y cartri cartridge dge filters placed downstream of the gas pipeline to protect control valves and customers. The design and size of these filters will

depend on the amount of black powder, its particle size and hardness. • Cyclo-Filters. These 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 μm to 10 μm. The second stage of cartri cartridge dge filters removes the finer black powder particles. Each of the above methods can be applied separately or in combination. For example, mechanical cleaning by instrument scraping scrap ing can be combined with instal installation lation of filters downstream closest to the customer. This combination ensures that the scraped black powder gets filtered out from the gas supply before reaching the customer. Although the removal approach is successful in protecting downstream operations, including the customers from the impact of black powder powder,, the removal methods have severa severall common drawbacks: (a) they are after-the-fact treatments, i.e., they do not address the root cause of black powder formation, (b) these methods are not a one-time solution but require frequent applications, (c) multiple installations are most often necessary as in the case of filters and cyclones, (d) these methodss constitute and add on to the ongoing operational method operational costs of gas trans transport port systems, and (e) subseq subsequent uent handling and disposal procedures procedures and proces processes ses are requir required. ed. The handling handli ng and dispos disposal al proced procedures ures could become challenging and costly if the black powder contains health and environmentally mental ly hazardous materials, materials, such as mercury and any naturally occurring radioactive materials (NORM). Prevention Methods

This management philosophy has at its core, the belief that internal corrosion of gas pipelines is the source of black powder. As such, these methods are based on preventing corrosion from occurring. These methods include: • Internal coatings. These are organic coatings, such as high solids solvent solvent based epoxy polyamine films that have originally origin ally been applied to protect the inter internal nal surfaces of pipelines from corrosion during storage. Nowadays, they are typically used for reducing drag; however, prevention of black powder formation would be an added benefit. These coatings are typically applied with a thickness range of 2 mils to 3 mils (50 μm to 80 μm) to cover pipe roughness (Ry5 = 30μm). They have been in use for the last 55 years and are used in over 300,000 km of pipelines worldwide. They have demons demonstrated trated very good ageing properties properties (for example, no degradation after 30 years of exposure to Sales Gas). International Standards (API 5 L 2 and ISO 15741) cover the specif specification ication of internal coatings for gas pipelines. Internal coatings are considered a cost-effective means of prevention of black powder in new Sales Gas pipelines. They are very difficult to apply and are not costeffective for existing pipelines, particularly buried pipelines. Figure 515 shows an intern internally ally coated new pipeli pipeline. ne. SAUDI ARAMCO ARAMCO JOURNAL JOURNAL OF TECHNOLOGY TECHNOLOGY

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ensure that the pipeline is clean from loose debris and mill scale prior to starting operations.

BLACK POWDER RESEARCH AT SAUDI ARAMCO R&DC

Fig. 5. Sales Gas pipeline internally coated with solvent based organic coatings 15.

• Moisture control . Elimination of water condensation in the pipeline, particularly internally uncoated pipelines, is the most critical step in preventing black powder formation in a gas grid. This can be achieved by improving the efficiency of the gas dehydration process to ensure dry gas in the pipeline. Appropriately Appropri ately sized tri-ethy tri-ethylene lene glycol (TEG) dehydrati dehydration on units, coupled with the installation of appropriately sized refrigeration and knockout drum units upstream and downstream of TEG dehydrator units, respectively, will help ensure drier gas entering the gas lines. Controlling and minimizing process upsets, such as water carry-over, (i.e., sales gas with water levels in excess of the maximum allowable level of 7lb/mmscf) is also important in limiting moisture in the pipeline. The use of appropriately sized, designed and maintained molecular sieves and chillers might be an expensive capital expenditure (CAPEX), but it would ensure drier gas. In internally bare Sales Gas pipelines, strict adherence adherence to the Sales Gas standard would ensure elimination of condensed water,, and in turn the preven water prevention tion of black powder formation. formation. Nevertheless, Neverth eless, because of proces processs upset upsets, s, excess water may enter the line grid leading to potential condensation and internal corrosion. Moisture control in a gas grid with multiple connected gas treating plants (as in the case of Saudi Aramco) is especially challenging challenging becaus becausee of the potent potential ial additive effect of process upsets. For example, in a gas network networ k connect connected ed to seven treating plants, a threethree-day day upset per year in each plant results in a potential accumulative 21 days of moisture condensation. • Commissioning practices. This concept involves the improvement of the required hydrotesting. More specifically, during dewatering and drying procedures air drying should not be used, but flash drying with methanol or nitrogen gas should be used instead. The use of sweet water with biocides and corrosion inhibitors will ensure no corrosion takes place during the hydrotest wait-in periods. If sweet water is readily available in the field, such as the case in many Middle East regions, then fresh water slugs can be used between pigs to wash the line and remove salt water water.. Following hydrotesting, hydrotesting, chemical cleaning should be practiced in Sales Gas pipelines to 46

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In addition to our recent findings which led to the identification ficati on of the composition, composition, source and forma formation tion mechanism of the black powder in Saudi Aramco Sales Gas pipelines, there remains several fundamental unknowns that are critical for the succes successful sful prevention prevention and managem management ent of black powder. Four of these unknowns are: (a) the internal corrosion rate and corresponding black powder formation rate, (b) the erosive properties of black powder with respect to pipelinee contro pipelin controll valve candidate materials, materials, (c) the potent potential ial need for special handling handling and disposal procedures procedures of black powder, and (d) the potential of need for developing an inhibition inhibi tion method that would prevent black powder from forming is essential to investigate. To resolve these unknowns, the Upstream R&D program at the R&DC has launched a 4-year applied research study titled “Black Powder Management Manageme nt Projec Project.” t.” This projec projectt consis consists ts of several main R&D activities which collectively collectively are designed to enhance Saudi Aramco’s capability in preventing black powder and managing its impact. This project and its results will be the subject of a possible future Saudi Aramco Journal of Technology article. In addition, Saudi Aramco’s R&DC is leading a broad black powder program with severa severall Nation National al Oil Compani Companies es (NOCs). The NOCs of Brazil, China, Norway and Saudi Arabia are the current members of this program. The objective of this program is to share and develop knowledge and experience, and best practices among the parti participatin cipating g NOCs to improve the understanding of black powder formation mechanisms, predictions, mitigation and management, as well as development of new technologies for the prevention and management of black powder. The technical topics of this program and their results will also be presented presen ted in a futur futuree articl article. e.

CONCLUSIONS 1. Black powder is a worldwide worldwide phenomenon experienced experienced by most, if not all, gas pipeline operators. Black powder is regenerative and is formed inside natural gas pipelines as a result of corrosion of the internal walls of the pipeline. More specifically, black powder forms through chemical reactions of Fe present in ferrous pipeline steel with condensed water containing O2, H2S and CO2. These chemical species are benign in dry Sales Gas, but can become corrosive corrosive when dissolved in water moisture. 2. In Sales Gas pipelines that that experience oxygen oxygen contaminatio contam ination, n, black powder is compos composed ed mainly of iron hydroxides, hydrox ides, iron oxides and iron carbonates. carbonates. Contaminants, such as sand, dirt, hydrocarbons, elemental

sulfur and metal debris typically make up 20 wt% of black powder.. The jagged shape and high hardnes powder hardnesss of black powder make it very erosive to pipeline control valves. 3. There are several removal and prevention prevention methods available availab le to gas operators for mitigating the formation and managing the impact of black powder. 4. In the case of existing uncoated uncoated pipelines, strict strict adherence to the Sales Gas standard would ensure elimination of condensed condens ed water, water, and in turn the format formation ion of black powder. Because of process upsets; excess moisture may enter the line grid leading to potential condensation and internal intern al corros corrosion. ion. The best black powder management management practice practi ce usuall usually y consis consists ts of a combin combination ation of severa severall controll method contro methodss that are collectively collectively designe designed d to minimize its occurrance and manage its impacts. These measures include cost-effective minimization of water carry-over into the gas grid and in-pi in-pipeline peline removal and contro controll method methods. s. 5. In the case of new pipelines, organic organic solvent-based solvent-based internal coatings, coating s, primarily used for drag reduction, reduction, provid providee a costeffective effecti ve and economi economical cal method for the prevention of black powder. 6. The R&DC is currently engaged engaged in an extens extensive ive black powder research program program design designed ed to enhance Saudi Aramco’s capability for preventing black powder formation and reducing its impact impact..

ACKNOWLEDGEMENTS The authors would like to acknowledge the Saudi Arabian Oil Company Compan y (Saudi Aramco) for support and granti granting ng permission permi ssion to presen presentt and publis publish h this article. The authors would also like to thank Mr. Mater Al Dhafeeri, Lead Process Engineer, Khursaniyah Gas Plant Department for providing the field moisture measurements data.

6. Godoy, Godoy, J.M., Carvalho, F., Cordilha, A., Matta, L.E. and Godoy, M.L.: “(210)Pb Content in Natural Gas Pipeline Residuess (“Black Powder”) and its Correlation Residue Correlation with the Chemical Composition,” Journal of Environmental Radioactivity, 1985, pp. 101-111. 7. “Corrosion Solutions for Gas Transmission Transmission Pipelines,” Honeywell Solution Note, www.honeywell.com/ps. 8. Craig, B.: “Corrosion “Corrosion Product Product Analysis Analysis - A Road Map to Corrosion Corros ion in Oil and Gas Production,” Production,” Materials Performance, August 2002, pp. 56-58. 9. Sridhar Sridhar, N., Dunn, D.S., Anderko, Anderko, A.M., Lencka, M.M. and Schutt, H.U.: “Effec “Effects ts of Water and Gas Compositions Compositions on the Internal Corrosion of Gas Pipelines - Modeling and Experimental Studies,” Corrosion, Vol. 57, No. 3, 2001, pp. 221-235. 10. Lyle, F.F F.F.: .: “Carbon Dioxide/Hydrogen Sulfide Corrosion under Wet Low-Flow Gas Pipeline Conditions in the Presence Presen ce of Bicarb Bicarbonate, onate, Chloride Chloride and Oxygen,” PRCI Final Report PR-15-9313. 11. Zhu, X.: GTI Report Report No. 080306, Contract Contract No. with Saudi Aramco. 12. Davis, B.R. and Calabretta, Calabretta, D.: “Thermodynamic “Thermodynamic Analysis of Formation of Black Powder in Sales Gas Pipelines,” Pipeli nes,” Purchase No. 651021 6510217086 7086 for Saudi Aramco Report No. 6510217086, 2007. 13. Sherik, Sherik, A.M.: “Black Powder in Sales Gas Transmis Transmission sion Pipelines,” Saudi Aramco Journal of Technology, Fall 2007. 14. ISO 18453:2004 18453:2004 Natural Natural Gas - Correl Correlation ation between between Water Content and Water Dew Point. 15. Eupec Web site at http://www.eupechttp://www.eupecservices.com/html/onshore/line-pipe-coatings.php.

REFERENCES 1. Baldwin, Baldwin, R.M.: “Black Powder in the Gas Industry Industry Sources, Characteristics and Treatment,” GMRC, Report No. TA97-4, May 1998. 2. Baldwin, Baldwin, R.M.: “Here are Proced Procedures ures for Handling Persistent Black-Powder Contamination,” Oil & Gas 109-115. 5. Journal, October 1998, pp. 109-11 3. Baldwin, Baldwin, R.M.: “Black Powder Control Control Starts Locally, Locally, Works Back to Source,” Pipeline & Gas Industry, April 1998, pp. 81-87. 4. Tsochat sochatzidis, zidis, N.A. and Maroullis, K.E.: “Methods Help Remove Black Powder from Gas Pipeli Pipelines,” nes,” Oil & Gas Journal , March 2007, pp. 52-58. 5. Arrington, Arrington, S.: “Pipeline Debris Removal Requires Extensive Extensive Planning,” Pipeline & Gas Journal , November 2006, pp. 61-62.


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BIOGRAPHIES Dr. Abdelmounam M. Sherik joined Saudi Aramco in 2004 and is a Science Specialist with Saudi Aramco’s Research and Development Center, and is currently the project leader of R&DC’s Black Powder Management Project and the NOC Black Powder Project. In 1986 he received a B.Sc. in Materials Science and Engineering from Tripoli University, Libya and in 1990 and 1994 he received both his M.Sc. and Ph.D. in Materials and Metallurgical Engineering from Queen’s University, Canada. Abdelmounam has over 20 years of professional experience in the areas of materials and corrosion. Abdelmounam has authored or co-authored more than 50 publications and made many international presentations on the corrosion of sales gas pipelines, particularly the black powder phenomenon. He has several patents in the area of nanotechnology.. Abdelmounam is an active nanotechnology active member of the National Association of Corrosion Engineers (NACE). Dr. Arnold L. Lewis joined Saudi Aramco in 1988 and is a Research Science Consultant with Saudi Aramco’s Research and Development Center (R&DC). In 1975 Arnold received a B.A. in Chemistry from the Pacific Lutheran University University,, Tacoma, WA and in 1981, he received a Ph.D. in Analytical Chemistry from Oregon State University, Corvallis, OR. He has 30 years of professional experience in scientific research and development. Arnold’s current research focus is atomic hydrogen permeation studies in hydrogen sulfide environments. His other research interests are corrosion and corrosion inhibition technology, and cathodic protection processes. Arnold has authored or coauthored many publications in his areas of expertise and has four U.S. patents with Saudi Aramco. Dr. Sebastien Duval is a Lab Scientist at Saudi Aramco’s Research and Development Center (R&DC). He received his Ph.D. from the University of Paris IV in Electrochemistry in 2000. Prior to joining Saudi Aramco in 2006, Sebastien held the following positions: Research Scientist at Institut Français du Pétrole, Materials Selection and Corrosion Principal Engineer at Saipem SA, and then as a Consultant for Offshore Projects. He has authored and coauthored more than 30 papers and holds six patents. He is member of National Association of Corrosion Engineers (NACE) International and the Society of Petroleum Engineers (SPE).

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Black Powder

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