Iron Sulfide Scale: Formation, Removal and Prevention

Nasr‐El‐Din, Hisham A.; Al-Humaidan, A.Y.

doi:10.2118/68315-ms

Cited by 103 publications

(44 citation statements)

References 25 publications

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“…Differing from other types of scale, both iron and sulfide have multiple redox states and, depending on the formation conditions, they can form precipitates with various compositions and dramatically different properties [16]. The identified scale minerals in petroleum industry include mackinawite (FeS) and pyrrhotite (Fe 1-x S), troilite (FeS), greigite (Fe 3 S 4 ), and iron disulfide pyrite and marcasite (FeS 2 ) [17][18][19]. Each mineral has its distinct reactivity toward the dissolver.…”

Section: Introductionmentioning

confidence: 99%

Laboratory assessment of tetrakis(hydroxymethyl)phosphonium sulfate as dissolver for scales formed in sour gas wells

Wang¹,

Shen²,

Badairy³

et al. 2015

Int. J. Corros. Scale Inhib.

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Tetrakis(hydroxymethyl)phosphonium sulfate (THPS) is an environmental friendly biocide commonly used in oil fields. It also has been used to control iron sulfide precipitation for water injection and to remove deposits in oil production systems. In this study, THPS was examined as the dissolver for scale deposits formed on downhole tubular of high temperature sour gas wells. These deposits consisted of a wide range of mineral phases and are often dominated with various forms of iron sulfides and iron oxyhydroxides. The THPS based dissolvers were studied at various concentrations, pH values and with different additives. These additives included ammonium chloride, chelating agents and phosphonates. Experimental results indicated that the dissolving power was not proportional to THPS concentration. The maximum dissolution was observed in THPS concentration of 25 to 50%, depending on scale composition. Its dissolving power could be significantly increased with both ammonium chloride and chelating agents. The synergistic effect of ammonium chloride was largely attributed to pH decrease. As a result, the corrosivity of THPS solution to metallurgy was increased with the addition of ammonium chloride. The corrosion rate of mild steel was increased over three times with 4% ammonium chloride added. Contrary to previous reports, phosphonate additives decreased scale dissolution and induced new precipitation. Formation of calcium sulfate precipitates was also observed during dissolution of calcite, which will limit the THPS from scales containing calcium carbonate. This study also revealed the dissolution behavior of different minerals in the THPS solution. Iron oxyhydroxides had the highest dissolution rate, followed by calcite, siderite and pyrrhotite. Pyrite, marcasite and anhydrite were almost insoluble in the tested solutions. Results from this study can be used as guideline for the development and design of THPS based scale dissolvers.

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Section: Introductionmentioning

confidence: 99%

Laboratory assessment of tetrakis(hydroxymethyl)phosphonium sulfate as dissolver for scales formed in sour gas wells

Wang¹,

Shen²,

Badairy³

et al. 2015

Int. J. Corros. Scale Inhib.

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“…Depending on factors such as the age of the scale, environmental temperature, and pressure, iron sulfides exist in several distinct forms with different crystalline structures, different ratios of sulfur to iron and different properties. The most common iron sulfide crystalline forms are pyrite (FeS 2 ), troilite (FeS), pyrrhotite (Fe 7 S 8 ), mackinawite (Fe 9 S 8 ), and marcasite (FeS 2 ) as summarized by other researchers (Walker 1991, Nasr-El-Din 2001.…”

Section: Introductionmentioning

confidence: 95%

“…Downhole blockages also slow the flow of fluids thereby creating flow assurance issues. Since the surface of iron sulfide is oil-wet, the free-floating iron sulfide particles are often found at the oil-water interface to stabilize emulsions and interfere with the separation process (Przybylinski 2001, Nasr-El-Din 1996, Walker 1991, Nasr-El-Din 2001.…”

Section: Introductionmentioning

confidence: 99%

Iron Sulfide Removal: A Nonacidic Alternative to Hydrochloric Acid Treatment

Wang

Berry

et al. 2013

All Days

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Iron sulfide scale deposition is a common problem in sour oil and gas wells. Accumulation of iron sulfide in the production tubing causes reduction of well deliverability. Conventional chemical means to remove Iron sulfide scale usually involve hydrochloric acid and other mineral acids. The composition and crystalline structure of iron sulfide scales varies significantly. Although iron disulfide (FeS 2 ), which is found in the minerals such as marcasite and pyrite, is not soluble in acid, pyrrhotite (Fe 7 S 8 ) has a high solubility in hydrochloric acid. Therefore, although hydrochloric acid and other acids can be applied to remove iron sulfide scales, their effectiveness in different treatments could be quite different depending on the scale composition. Even in cases where hydrochloric acid could be applied for iron sulfide removal, the applied hydrochloric acid is very corrosive to downhole tubulars especially at high temperatures and high acid concentrations. In the meantime, the generated H 2 S poses a great threat because of its high toxicity and enhanced corrosion tendency due to the combination of hydrochloride acid and H 2 S.To overcome the drawbacks of hydrochloric acid treatment, i.e., the risk of H 2 S evolution and the corrosion tendency in standard carbon steel, an alternative chemical treatment to hydrochloric acid treatment is preferred. This paper illustrates the development of a new chemical treatment solution for iron sulfide removal. This polymer-based system demonstrated high dissolving capacity for iron sulfide scales in neutral or nearly neutral pH environments. Testing related to its performance also has revealed advantages such as low corrosion rate, and low H 2 S evolution. Additionally, laboratory testing demonstrated this polymer-based system is an effective general purpose stimulation fluid to stimulate carbonate and dolomite formations. IntroductionIt has been well documented that iron sulfide scales can cause various problems in the oil industry. Iron sulfide scale precipitation in the formation matrix and around screens and perforations can decrease production capacity. Accumulation of iron sulfide scale in the tubulars can result in reduced well deliverability. The build-up of iron sulfide scale could also interfere with the operation of pumps, valves and other associated equipment. Downhole blockages also slow the flow of fluids thereby creating flow assurance issues. Since the surface of iron sulfide is oil-wet, the free-floating iron sulfide particles are often found at the oil-water interface to stabilize emulsions and interfere with the separation process

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“…About 60% of the jobs resulted in tubing failure that required rig workover operation to replace the corrosion penetrated tubing 6,7,8 .…”

Section: Tubing Scale Removal Challengesmentioning

confidence: 99%

Saudi Aramco Downhole Corrosion/Scaling Operational Experience and Challenges in HP/HT Gas Condensate Producers

et al. 2014

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This paper shares Saudi Aramco's operational experience and challenges with downhole sweet and sour corrosion and scaling tendencies in the carbon steel (CS) completions. It also reports the company's approach to deal with these issues. Corrosion in wells drilled in sour gas bearing reservoirs commonly occurs in conjunction with iron sulfide scale deposits in the lowermost section of the production tubing and liner. Historically, the progression of sour corrosion has been relatively slow, so CS completions are cost-effective as the frequency of required workovers is low. Nevertheless, although scale deposits are not confirmed to curtail well productivity they reduce wellbore accessibility, which sometimes necessitates their removal by rig-less mechanical operation. Scale removal from old completions resulted in failure of the tubular integrity. In most sour gas wells corrosion starts posing scaling and obstruction problems inside the tubing far before any leaking risk. It is worth noting that this experience is consistent with field cases experienced by Total or other operators, as recently reported in the literature. The company experience with sweet gas producers have shown corrosion tendency to occur at shallow depths with no observed scale deposits. Corrosion was in the form of localized spaced scratches in the joints and metal loss in the pin-and box-ends. For these wells, the average life cycle of tubulars exceeds 10 years. The results from this field study might benefit the world gas producers of Saudi Aramco's intensive and diversified experience and of the completion practices that the company has adapted to develop the high temperature gas condensate fields. It is of particular interest to understand why the corrosion observed on these sweet wells is significantly lower than predicted by most carbon dioxide (CO 2 ) corrosion prediction models.

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Iron Sulfide Scale: Formation, Removal and Prevention

Cited by 103 publications

References 25 publications

Laboratory assessment of tetrakis(hydroxymethyl)phosphonium sulfate as dissolver for scales formed in sour gas wells

Laboratory assessment of tetrakis(hydroxymethyl)phosphonium sulfate as dissolver for scales formed in sour gas wells

Iron Sulfide Removal: A Nonacidic Alternative to Hydrochloric Acid Treatment

Saudi Aramco Downhole Corrosion/Scaling Operational Experience and Challenges in HP/HT Gas Condensate Producers

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