SPE 68315 Iron Sulfide Scale: Formation, Removal and Prevention H.A. Nasr-El-Din, SPE, A.Y. Al-Humaidan, SPE, Saudi Aramco
Copyright 2001, Society of Petroleum Engineers Inc.
Results, Conclusions
This paper was prepared for presentation at the 2001 SPE International Symposium on Oilfield Scale held in Aberdeen, Aberdeen, UK, 30-31 January 2001.
Extensive field work was conducted to identify the type of iron sulfide scale present, and the mechanisms that lead to its formation. Iron sulfide species were present in gas, gas, oil and water supply wells. The chemical and physical characteristics of iron sulfide scale were found to be a function of temperature, pressure, pH and the age of the the scale. Other properties of the scale, density and thickness, were found to vary with the scale depth and age. Various mechanical and chemical treatments to remove iron sulfide scale were examined in detail. Advantages and disadvantages of each method were identified. The best method method to deal with with iron sulfide scale is to avoid its formation in the first place. Chemical squeeze treatments were found to be effective in this regard. Once iron sulfide scale is formed, then it is recommended to remove the scale using acid washes with appropriate additives. Mechanical means means are recommended for old iron sulfide scale, which has low acid solubility.
This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract
Description of Paper This paper discusses various mechanisms that can lead to the formation of iron sulfide scale downhole, techniques that can be used to prevent its formation and methods to remove it. Iron sulfide scale is present in oil and gas producing wells, water injection and supply wells. There are various mechanisms that can lead to the formation of iron sulfide. However, all of these mechanisms require sources of hydrogen sulfide and iron. Hydrogen sulfide sulfide can result from sulfate reducing bacteria, thermal decomposition of sulfate, or being introduced into the well as in gas lift operations. Iron can be produced from the formation, especially sandstone reservoirs and is also present downhole as a result of various corrosion processes. Combination of hydrogen sulfide and iron will cause formation of various iron sulfide species. species. The ratio of iron to sulfide in these species depends on temperature, pressure, pH, and hydrogen hydrogen sulfide concentration. concentration. This ratio plays a key role in determining the best method to remove iron sulfide scales. Hydrochloric acid can be used to dissolve iron sulfide species that contain iron and sulfur at a molar ratio close to unity. unity. Non-acid formulae can be used to remove iron sulfide scale, however, their ability to dissolve iron sulfide depends on the molar molar ratio of iron to sulfide. sulfide. To prevent the formation of iron sulfide, squeeze treatments to the formation were found to be very effective. This paper discusses various mechanisms that can lead to the formation of iron sulfide, chemical and mechanical methods to remove it and chemical squeeze treatments to prevent its formation and/or deposition.
Area of Interest Iron sulfide scale is present in sour oil and gas wells and injectors that are contaminated with sulfate reducing bacteria (SRB). It enhances enhances the the corrosion corrosion rate rate of the downhole tubulars, and adversely affects the performance of various wells. It reduces the efficiency efficiency of oil-water oil-water separation separation in various GOSPs. Removing iron sulfide scale is a complex process, especially at downhole conditions. Optimizing this process will require full understanding of various chemical interactions.
Introduction Iron sulfide species have been known to cause operational problems in the oil industry. The presence of iron sulfide particles in the injected water can cause loss of injectivity in power water injectors 1-3 and water disposal wells. 4 Accumulation of iron sulfide and biomass around downhole screens and perforations can cause loss of productivity of water supply wells. 5 Build-up of iron sulfide sulfide scale scale in the tubing can create problems during wireline work and can reduce well deliverability. 6-7 The presence of fine particles of iron sulfide in the produced crude oil can cause many operational problems in oil-gas separation plants (GOSPs). 8 Recently, Nasr-El-Din et al. 9 found that iron sulfide scale deposited in the nozzles of gas mandrels reduced the productivity of water supply wells with gas lift.
2
H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
Iron sulfide deposits are also present in many types of refining and process equipment. 10-12 These deposits can significantly reduce the efficiency of heat exchangers, furnaces, and other similar equipment. Iron sulfide scale forms as a result of the reaction of hydrogen sulfide or mercaptans with carbon steel. 11 According to Seto and Beliveau, 13 the known mechanisms of reservoir souring fall under two main categories: biotic and abiotic. An example of the biotic mechanism is the hydrogen sulfide produced in injectors that utilize waters with high sulfate contents, e.g., seawater3 or shallow water aquifers. 5 In these injectors, hydrogen sulfide is produced due to the activities of sulfate reducing bacteria (SRB). For abiotic mechanisms, hydrogen sulfide is produced due to thermochemical sulfur reduction, thermal hydrolysis of organic sulfur compounds, or hydrolysis of metal sulfides. 13 Another unexpected source of hydrogen sulfide is acid treatments. Kasnick and Engen 6 found iron sulfide scale in well tubulars following acid treatments of deep sour gas wells. The downhole sources of iron ions are the corrosion products or the iron present in the produced brines. 14 Unlike common oilfield scales (calcium carbonate, calcium, barium or strontium sulfate), iron sulfide scale has several unique characteristics that should be carefully considered. First, iron sulfide can cause crevice or bimetallic corrosion.14 According to Smith and Miller, 15 iron sulfide scale can cause bimetallic corrosion of iron in the presence of water. Secondly, Iron sulfide is present in several crystalline forms that have different sulfur to iron ratios ( Table 1).7,15,16 These species have different crystalline forms and, as a result, have different solubilities in mineral acids. 7,9 Iron sulfide particles are oil-wet and, as a result, they will be coated with oil, condensate, or heavy hydrocarbons. These hydrocarbons will act as a diffusion barrier that will retard acid reaction with the scale. 14 Another important characteristic of iron sulfide scale is aging. Continuous exposure of FeS species to hydrogen sulfide will result in the formation of iron sulfide species that are rich in sulfur. 7,9,17 Finally, iron sulfide scale is heterogeneous where other corrosion products can be present with it. The composition of iron sulfide scale varies within the scale layer. Several investigators found significant variations in the composition of the scale layer close to the tubing wall and that close to the flow streams. 6,14 Iron carbonate and iron oxides are commonly found with the iron sulfide scale. These non-sulfide species may affect the ability of some non-acid formulae in dissolving iron sulfide scale, as will be discussed later in this paper. In addition to the above characteristics, the physical texture and appearance of iron sulfide scale depend on well type. For gas wells, iron sulfide scale is porous, loose, and does not protect the base metal. On the other hand, in water wells, or in the presence of aqueous medium, iron sulfide scale is dense, adherent and protective to the base metal.18 As can be seen, iron sulfide scale is present in different forms and, as a result, various methods are available to remove it. The objectives of this study are to: (1) identify the nature and composition of iron sulfide scale present in oil, gas
SPE 68315
and water wells, (2) assess the effectiveness of various methods to remove it, and (3) determine an effective method to mitigate this type of scale. To the best of the authors knowledge, no similar and comprehensive study was conducted before on this type of scale.
Experimental Studies Scale samples were collected from oil producers, gas wells, water supply wells, and wells contaminated with SRB. The scale was collected from different depths, that depend on well type. The mineralogy and elemental composition of the scale samples were determined by X-ray diffraction (XRD) and Xray fluorescence (XRF) techniques, respectively. The solubility of the scale sample was determined by soaking the sample in 20 wt% HCl for four hours. This acid concentration was selected based on previous work done by Nasr-El-Din et al.19 The weight ratio of the scale to acid was 1:10. At the end of the solubility test, acid-insoluble solids were separated by filtration. Chemical analysis was performed on the supernatant. Moreover, the acid insoluble portion of the scale was analyzed using XRD and XRF techniques. Chemical Analysis Samples of the supernatant following acid solubility tests were separated and the concentrations of key ions were measured. Total iron, manganese, calcium and magnesium, concentrations were measured by inductively coupled argon plasma emission spectroscopy (ICP). Chloride ion was measured by titration with a 0.1N silver nitrate solution using a Mettler DL 70 ES autotitrator. Acid concentration was measured by titration of a known volume of the acid with a 0.1N NaOH solution to an endpoint pH of 4.2. To measure pH, an Orion model 720A meter and Cole Parmer Ag/AgCl single junction pH electrodes were used.
Results and Discussion Typical Iron Sulfide Scale As mentioned earlier, iron sulfide scale has several important characteristics that need to be considered before designing proper treatments to remove the or mitigate scale. To determine these characteristics, various scale samples were collected from oil and gas producers (carbonate and sandstone reservoirs) and water supply wells. The mineralogy, thickness, and acid solubility of the scale were determined. Several interesting findings were noted as follows. Iron sulfide scale was found in sour oil and gas wells and injectors that utilize high-sulfate waters. Iron sulfide scale was detected in several producers in a carbonate reservoir in Saudi Arabia. Reservoir fluids in this field contain 5 mol% CO 2 and 1 to 5 mol% H 2S. The scale was found on the inside wall of the production tubing or as loose particles accumulated in the rat hole. Photo 1 shows scale particles collected from Well-75 at a depth of nearly 4,060 ft, an oil well with very low water cut (less than 1 vol%). Iron sulfide scale was also detected in oil producers present in sandstone reservoirs. Photo 2 shows the scale sample collected from Well-10, a wet oil producer. Photos 3 and 4 show scale samples collected from a water supply well
SPE 68315
IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
with a gas lift. The scale was obtained from 7-inch joints that were retrieved from this well at a depth of 34 and 680 ft, respectively. The scale was consolidated, dense, and adhered to the tubing wall. A hammer was needed to dislodge scale samples from the tubing. Iron sulfide deposits were detected by Kasnick and Engen6 in sour gas wells in deep carbonate reservoirs. It is clear from these observations that the texture and composition of the iron sulfide scale depends on well type, which confirm the results obtained by Claassen. 14 Another point regarding iron sulfide scale is the variation in scale thickness along the length of the tubing. Scale thickness was measured in various wells by using gauge cutters or by measuring the thickness of the scale found in the tubing joints retrieved from various wells following workover. The thickness of the scale was found to be a function of depth. For example, in a water supply well with a gas lift (Well-895), the scale thickness was 0.25 inch at 34 ft and nearly 0.05 inch at 680 ft (Photos 3 and 4). In oil wells, the scale thickness varied with depth and several severe constrictions were noted. In deep gas wells, iron sulfide scale was detected in the lower sections of the tubing. Drop out of condensate did help in reducing iron sulfide scale in the upper sections of the tubing.6,14 Scale density may vary from one well to another. In water supply wells, Nasr-El-Din et al. 9 found that the scale density varied from 4.7 to 5.1 g/cm 3. Kasnick and Engen6 found that the average density of the scale samples collected from gas wells was 2 g/cm3. This lower density reflects the porous nature of the scale that Kasnick and Engen collected from the gas wells that they examined. Iron sulfide scale is heterogeneous and is usually present with other corrosion products. Table 2 shows the mineralogy of a scale sample collected from Well-227, an oil well in the carbonate reservoir. The sample contains various iron sulfide species and iron carbonate. Well-75 is an oil producer in the same field. The well produces sour crude with less than 1 vol% water cut. Analysis of a scale sample collected from this well is given in Table 2. Similar to Well- 227, the scale consisted of various iron sulfide species, and iron carbonate. Table 2 also gives the XRD analysis of a scale sample collected from Well-10, an oil producer in the sandstone reservoir. The scale comprised iron sulfide, iron carbonate, calcium carbonate and quartz. Analysis of scale samples collected from Well-895, a water supply well, showed that various iron sulfide species were present in the scale samples. Of interest to note is the variation in the composition of the scale with respect to depth. A sample collected from 34 ft contained pyrite, whereas that collected from 680 ft contained mainly makinawite. Another important point to note is that all of the scale samples contained various amounts of hydrocarbons. For example, the scale sample collected from Well-75 contained up to 10 wt% hydrocarbons. The presence of these hydrocarbons should be carefully considered when designing a chemical treatment to remove the scale. Surfactants and mutual solvent should be included with the treatment fluids. Xylene and other aromatic solvents should be included if the
3
hydrocarbons contain significant amounts of asphaltene particles. Source of Iron Sulfide in Sour Wells Identifying the source of iron sulfide in sour wells is a d ifficult task. Iron sulfide present in well tubulars can result from tubing corrosion or simply be deposited on the surface of the tubing. One way to identify the formation mechanism of iron sulfide is to examine the elemental composition of the scale and to compare it with that of the well tubing. For example, J55 is a low-carbon steel that is used to manufacture most of the tubing stingers used downhole. Elemental analysis was conducted on tubing joints that were retrieved from several wells. The analysis was conducted using an optical emission analyzer (Arc-Met 900). The analysis indicated that the tubing consisted of 98.46 wt% iron, 1.28 wt% manganese, 0.24 wt% carbon and 0.02 wt% silicon. It is important to note that the weight ratio of iron to manganese in this steel was nearly 77:1. It is worth noting that manganese was not detected in any of the scale samples examined in this study. As was mentioned before, J-55 contains 1.28 wt% manganese. Had the scale contained manganese, this would indicate that corrosion of the tubing did contribute to the scale formation in these wells. The scale noted in these wells formed due to the deposition of iron sulfide particles on the wall of the tubing.
Solubility of the Scale in Acids Solubility of scale samples in acids is an important test, and is strongly recommended before performing field treatments. This is especially true for old iron sulfide deposits. Several researchers noted significant variations in acid solubility of iron sulfide species with acids. 7,9 Solubility tests were conducted on various scale samples collected from oil and water supply wells. The results varied from one well to another. For example, the solubilities of the scale samples collected from oil producers: Wells -75, 227, and 10 were 15, 79, and 25 wt%, respectively. Acid solubility of Wells 75 and 10 were relatively low. This is especially true when considering the fact that these scale samples contained acidsoluble materials (Table 2). It is most likely that these samples contained a hydrocarbon phase that coated the acid soluble minerals. Iron sulfide is an oil-wet material and it is expected that this type of scale be coated with oil. These results highlight the need to add surfactants and other water-wetting agents to enhance acid-scale contact. If these materials were not available, then the scale should be removed using mechanical means. It is interesting to note that the scale samples collected from water supply wells exhibited significant variations in acid solubility with depth. The scale sample collected from Well-895 at 34 ft had a solubility of only 3 wt%, whereas the scale collected from the same well at 680 ft had a solubility of nearly 85 wt%. This variation in acid solubility from 3 to more than 85 wt% is significant and reflects the effect of Fe/S molar ratio on the acid solubility of the scale. As the Fe/S ratio approaches unity, acid solubility increases. 7,9
4
H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
Removal of Iron Sulfide Scale 20
Iron sulfide scale can be removed either by mechanical or chemical means. 21-30 In general, old iron sulfide scale (mainly FeS2 species) has low acid solubility. Therefore, this type of scale cannot be effectively removed using mineral acids. On the other hand, new or fresh scale (mainly FeS species) has a high solubility in mineral acids and can be effectively removed by acids. It is very important to note that old scale consists of several iron sulfide species where the location of a given species depends on several operational conditions. For example, several investigators 7,14 mentioned that iron sulfide deposited close to the tubing wall is FeS, whereas FeS 2 species are concentrated close to the surface of the scale that is exposed to the stream that contains hydrogen sulfide. This radial variation in the scale composition should be considered when designing a treatment to remove it. Acid Cleaning - Background Mineral acids can be used to remove fresh scale and can be used in combination with mechanical means to remove old scale. Mineral acids react with iron sulfide (FeS) as follows: +
FeS + 2H
→
H2S(g)
2+
+ Fe
(1).
The rate of this reaction was given by Lawson et al. 10, Equation 2: +
2+ 0.5
0.5
Rate = kf [H ]– kr[Fe ] (PH2S)
(2).
Where k f and k r are the rates of the forward and reverse reactions, respectively. Several important points can be inferred from Equation 2. The rate of dissolution of iron sulfide can be increased by using concentrated acids. This finding was confirmed by Lawson et al. 10 using sulfuric acid and by Nasr-El-Din et al. 19 using hydrochloric acid. Accumulation of hydrogen sulfide will reduce the rate of acid reaction with the scale. Therefore, it is very important to scavenge hydrogen sulfide to be able to dissolve iron sulfide scale. It may be also useful to use an iron chelating agent to maintain the forward reaction. Based on the experimental work performed by Nasr-El-Din et al.,19 HCl at 20 wt% was recommended for field application. Higher acid concentrations are not recommended because the acid becomes very corrosive at high concentrations, especially at high temperatures. High acid concentrations will require large amounts of corrosion inhibitors, which many adversely affect the ability of the acid to dissolve iron sulfide scale. 19 Based on Equation 2, and the nature of iron sulfide scale, the acid should contain the following additives. First, the acid should contain a corrosion inhibitor to protect the base metal. Secondly, a water-wetting surfactant should be added to the acid to remove condensate and other hydrocarbons from the surface of iron sulfide scale. The surfactant will enhance acid-scale contact. Thirdly, the acid should contain a suitable hydrogen sulfide scavenger. Hydrogen sulfide released during acid reaction with iron
SPE 68315
sulfide scale is present in a molecular form. It is toxic gas, corrosive and can react with ferrous irons and precipitate elemental sulfur and iron sulfide once the acid is spent and the pH increases above a value of 1.9. 27 Elemental sulfur can precipitate if ferric iron is present: 31 3+
Fe
+
S
2-
=
2+
Fe
o
+
S
(3).
Precipitation of elemental sulfur in the formation can cause formation damamge. 32 Elemental sulfur is insoluble in hydrochloric acid and can be removed by using expensive organic solvents. 33 Therefore, a suitable hydrogen sulfide scavenger should be added to the acid. 34 Hydrogen sulfide scavengers that can be used during acid cleaning include: aldehydes, 10,11,35 ketones,30 and oximes.36 The performance of various aldehyde-based scavengers was examined by several investigators. Al-Humaidan and Nasr-ElDin,37 recommended that the scavenger to be added to the acid just before pumping. They should not be used at high concentrations and should be compatible with other acid additives. Another important point is the solubility of the reaction product with reservoir fluids. For example, formaldehyde reacts with hydrogen sulfide and produces trithiane.
H
S
S + 3 H 2O
3 CH2O + 3 H2S
S Formaldehyde Hydrogen Sulfide
Trithiane
(4).
Trithiane is not soluble in acid, water or hydrocarbons. Precipitation of trithiane in the formation can cause formation damage. Other aldehydes, especially those with -hydrogen (e.g., acetaldehyde) can react with hydrogen sulfide and form oily material. 11 These aldehydes should not be used in power water injectors or water supply wells. More details on the performance of hydrogen sulfide scavengers are given by AlHumaidan and Nasr-El-Din et al. 37 Finally, an iron control agent should be used if the spent acid will enter the formation.38 There is no need to use an iron control agent if the acid is circulated in the tubing and is not allowed to enter the formation. Field Application. A relatively new iron sulfide scale was detected in Well-A, a water supply well. A solubility test conducted on a scale sample collected from this well indicated that the scale had a solubility of nearly 80 wt% in 20 wt% HCl. Based on this result, an acid treatment was designed to remove this scale. Several factors were considered when designing the acid treatment. First, the thickness of the scale varied with depth. Therefore, the exact volume of the scale was estimated. Secondly, acid reaction with the scale will produce hydrogen sulfide. Hydrogen sulfide is a toxic and
SPE 68315
IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
corrosive gas and every effort should be made to scavenge it as soon as it forms. The scale also contained less than 10 wt% of hydrocarbons. A final factor was that the acid should not corrode the well tubing (J-55). Based on these concerns, the well was treated with alternating slugs of gelled water and acid. The gelled water contained 40 lb/1000 gals of a biopolymer and 1-2 wt% of sodium carbonate. Sodium carbonate was added to raise the pH of the gelled water to 10-11. This high pH is needed to scavenge any hydrogen sulfide that was not captured by the scavenger added to the acid. The gelled water contained 1-2 gals/1000 gals of a water wetting surfactant. The objective of using this surfactant is to ensure that the scale is water wet. The acid slug was based on 20 wt% HCl and contained a hydrogen sulfide scavenger at 10 gals/1000 gals, a corrosion inhibitor at 1-2 gals/1000 gals of acid, a water wetting surfactant at 2 gals/1000 gals and a friction reducer at 2 gals/1000 gals of acid. A coiled tubing was used to circulate these slugs in the tubing and samples of the flow back were collected. Figures 1-5 show the concentration of key ions as a function of flow back time. The pH of the flowback fluids was fluctuating between zero and 8 (Fig. 1). This variation reflects the sequence of gelled water and acid circulated in the tubing. Variation of acid concentration is shown in Fig. 2. Acid concentration varied from 0 to nearly 20 wt%. Chloride ion concentration, shown in Fig. 3, is parallel to acid concentration shown in Fig. 2. The acid reacted with the scale and produced iron, as shown in Fig. 4. Iron concentrations up to 65,000 mg/L were noted in the flowback samples. The highest iron concentration appeared after 200 minutes of flowback, reflecting the high solubility of the scale in the lower sections of the tubing. Figure 5 depicts the concentration of manganese in the flowback samples. The average concentration of manganese in the flowback samples was less than 10 mg/L. However, manganese concentrations up to 60 mg/L were noted after nearly 200 mins of well flowback. The main source of manganese is the tubing (J-55) that contained up to 1.28 wt% of manganese. It is not known for sure whether this manganese was present in the scale or produced due to acid reaction with the tubing. There was no manganese detected in all scale samples collected from this well. The treatment was successful and removed most of the scale present in the tubing. It is clear from these results that fresh iron sulfide scale can be effectively removed by mineral acids. Mechanical Cleaning Mechanical means include jetting using a coiled tubing. A special slurry is prepared using particles with hardness greater than that of the scale, but less than that of the tubing. The slurry is jetted into the scale where the scale starts to break. The scale fragments are lifted from the wellbore by circulating a gelled fluid. The process can continue until most of the scale is removed. A major concern with this method is removing the scale from unexposed areas. The scale in these areas cannot be
5
removed by mechanical means. A chemical means should be used to remove the scale from these areas. Field Application. Iron sulfide scale was detected in Well-B. However, unlike Well-A, the scale accumulated over a long period of time (more than five years). This scale was old, therefore, removing this scale by an acid treatment was not recommended. The scale was removed using a rotating jet nozzle and a special slurry that contained special particles. Gelled water was used to lift scale fragments from the well bore. The treatment was also monitored in the field and samples were collected from the well flowback. To ensure complete cleaning of the wellbore, an acid wash, similar to that used in Well-A, was performed on Well-B. Samples of the well flowback were collected and analyzed. Figures 6 to 8 show the concentrations of HCl, total iron and manganese in the flowback samples. These results indicated several trends that were not observed with Well-A. First, higher acid concentrations were noted in the returns of Well-B. Significant iron concentrations were seen in the flowback of Well-B. Finally, higher manganese concentrations were noted with Well-B. These results indicated that the mechanical cleaning did remove most of the scale present in Well-B. But it did not remove all of the scale present. It is obvious from the acid cleaning performed on Well-A and the mechanical/acid cleaning conducted on Well-B that new iron sulfide deposits can be effectively removed by a carefully designed acid treatment. On the other hand, old iron sulfide scale can be removed by mechanical means followed by an acid wash. Analysis of the performances of the two wells is underway and a full comparison between mechanical and chemical cleaning will be presented in a future publication. Mitigation of Iron Sulfide Scale Iron sulfide scale requires a source of iron and another one for hydrogen sulfide. To mitigate iron sulfide scale, these sources should first be identified. The sources of iron are the formation brines (especially in sandstone formations) and the well tubulars. Iron produced by corrosion processes can be minimized by employing various corrosion protection techniques. However, iron produced with the formation brines cannot be eliminated. The sources of hydrogen sulfide are the formation fluids and sulfate present in the injected/produced waters (produced by SRB activities). Hydrogen sulfide produced by SRB can be controlled by using biocides, 39 injection of nitrites, or by removing sulfate ions present in the injection water. However, hydrogen sulfide present in the crude or gas is difficult to remove. Based on this discussion, the amount of iron sulfide scale present downhole can be reduced, but cannot be eliminated. Another important point is that mitigation of iron sulfide by removing iron or hydrogen sulfide from the system is not economically feasible in most cases. Mitigation of iron sulfide scale should be based on the fact that iron sulfide scale is present in the system. To mitigate iron sulfide scale, a downhole squeeze treatment was examined. The treatment is based on a combination of
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H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
three chemicals: a corrosion inhibitor, tetrakis hydroxymethyl phosphonium sulfate (THPS) and a surfactant. The corrosion inhibitor is used to minimize the amount of iron released into the system. THPS is used to dissolve or chelate iron sulfide (FeS) once it is formed. 40 It is also used as a biocide to control the growth rate of SRB. The surfactant is used to change the wettability of iron sulfide particles from oil-wet to water-wet. Two important points should be considered when THPS is used. THPS oxidizes in air and becomes an ineffective biocide.40 Nasr-El-Din et al. 41 found that using THPS at high concentrations can cause formation damage in sandstone reservoirs. The squeeze treatment was applied in several water supply wells that produce water from a shallow sandstone aquifer. The treatment was applied without encountering any operational problems. Initial results indicated that the rate of scale deposition is significantly reduced. Work is underway to develop similar treatments for gas and oil wells in carbonate and sandstone reservoirs.
2.
3. 4.
5.
6.
Conclusions 1.
2. 3.
4.
Iron sulfide scale is present in sour wells and water injectors where the injected water has a high sulfate content. The composition, texture, physical properties and acid solubility of the scale depend on well type and depth. Fresh iron sulfide scale can be effectively removed using mineral acids with suitable additives. On the other hand, old iron sulfide scale can be effectively removed using mechanical means followed by an acid wash. The squeeze treatment was effective and reduced the amount of iron sulfide scale deposited in the tubing of several water supply wells that produce water from a shallow sandstone aquifer.
7.
8.
9.
Based on the results obtained in this study, it is recommended to frequently examine sour wells. Scale samples should be collected from different depths and locations. Acid solubility of all of samples should be considered before selecting a method to remove this type of scale.
10.
Acknowledgments The authors wish to acknowledge the Saudi Arabian Oil Company (Saudi Aramco) for granting permission to present and publish this paper. The authors would like to thank the Chemistry and the Advanced Instruments Units of the LR&DC for performing various analyses. A.A. Al-Zahrani, and M. Al-Modra attended field treatments and conducted acid solubility tests. Special thanks go to many production engineers in Abqaiq and Udhailiyah areas for useful discussions.
12.
11.
13.
14.
15.
References 1.
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16.
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Cusack, F., McKinley, V.L., Lappin-Scott, H.M., Brown, D.R., Clementz, D.M., and Costerton, J.W.: “Diagnosis and Removal of Microbial/Fines Plugging in Water Injection Wells,” paper SPE 16907 presented at the 1987 Annual Technical Conference and Exhibition held in Dallas, TX, 27-30 September. Patton, C.M.: “Corrosion Control in Water Injection Systems,” Materials Performance, 32 (Aug. 1993) 46-49. Nasr-El-Din, H.A. and Al-Taq, A.A.: “Water Quality Requirements and Restoring the Injectivity of Water Disposal Wells,” paper SPE 39487 presented at the 1998 SPE International Symposium on Formation Damage Control held in Lafayette, LA, 18-19 February. Nasr-El-Din, H.A., Rosser, H.R. and Hopkins, J.A.: “Stimulation of Water Supply Wells in Central Arabia,” paper SPE 36181 presented at the 1996 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 13-16 October. Kasnick, M.A. and Engen, R.J.: “Iron Sulfide Scaling and Associated Corrosion in Saudi Arabian Khuff Gas Wells,” paper SPE 17933 presented at the 1989 SPE Middle East Oil Technical Conference and Exhibition held in Manama, Bahrain, 11-14 March. Walker, M.L., Dill, W.R., Besler, M.R., and McFatridge, D.G.: “Iron Control in West Texas Sour-Gas Wells Provides Sustained Production Increases”, JPT (May 1991) 603. Brownless, J.K., Dougherty, J.A., Tauseef, S., Hausler, R.H.: “Solving Iron Sulfide Problems in an Offshore Gas Gathering System,” paper NACE # 104 presented at the NACExpo 2000, Orlando, FL, 26-31 March. Nasr-El-Din, H.A., Al-Humaidan, A., Mohammed, S.K. and Salman, A.: “Iron Sulfide Scale Formation in Water Supply Wells with Gas Lift”, paper SPE 65028 to be presented at the 2001 SPE Oilfield Chemistry, Houston, TX, 13-16 February. Lawson, M.B., Martin, L.D. and Arnold, G.D.: “Chemical Cleaning of FeS Scales,” Paper NACE 219, Corrosion/80, held in Houston, TX, March. Ball, C.L. and Frenier, W.W.: “An Improved Solvent for Iron Sulfide Deposits,” Paper 2, Corrosion/84, NACE, New Orleans, LA, 2-6 April. Frenier, W.W.: “20 Years of Advances in Technology for Chemically Cleaning Industrial Equipment: A Critical Review” paper NACE 338, Corrosion/98. Seto, C.J. and Beliveau, D.A.: “Reservoir Souring in the Caroline Field,” paper SPE 59778 presented at the 2000 SPE/CERI Gas Technology Symposium held in Calgary, Alberta, 3-5 April. Claassen, E.J.: “Iron Sulfide as a Water-Deposited Scale in Sour Gas Wells,” paper NACE 191, Corrosion/88, held in St. Louis, MO, 21-25 March. Smith, J.S. and Miller, J.D.A.: “Nature of Sulfides and their Corrosive Effect on Ferrous Metals: A Review ”, Br. Corrosion J., 10 (1975) 136. Anthony, J.W., Bideaux, R.A., Bladh, K.W. and Nicholos, M.C., 1990. Handbook of Mineralogy:
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IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
Elements, Sulfides and Sulfosalts, Vol 1., Mineral Data Publishing, Tucson, Arizona. Anderko, A. and Shuler, P.J.: “Modelling the Formation of Iron Sulfide Scale Using Thermodynamic Simulation Software,” paper NACE 64 , Corrosion/98. Zamanzadeh, M., Iyer, R.N., and Pickering, H.W.: Hydrogen Sulfide Corrosion in the Oil Industry and Application to the IPZ Model for its Analysis, ” paper NACE 209, Corrosion/90. Nasr-El-Din, H.A., Al-Humaidan, A., Fadel, B.A., and Saleh, R.: “Effect of Acid Additives on the Efficiency of Dissolving Iron Sulfide Scale,” paper NACE # 439 presented at the NACExpo 2000, Orlando, FL, March 2631. Bittner, S.D., Zemlak, K.R., and Korotash, B.D.: “Coiled Tubing Scale Removal of Iron Sulfide – A Case Study of the Kaybob Field in Central Alberta,” paper SPE 60695 presented at the 2000 SPE/IcoTA Coiled Tubing Round Table held in Houston, TX, 5-6 April. Lawson, M.B.: “Method for Removing Iron Sulfide Scale from Metal Surfaces,” US Patent 4,381,950, 1983. Lawson, M.B.: “Method for Removing Iron Sulfide Scale from Metal Surfaces,” US Patent 4,381,673, 1982. Frenier, W.W. et al.: “Composition and Method for Removing Sulfide-Containing Scale from Surfaces, ” US Patent 4,220,550, 1980. Frenier, W.W.: “Method and Composition for Removing Sulfide-Containing Scale from Metal Surfaces, ” US Patent 4,310,435, 1982. Buske, G.R.: “Method and Composition for Removing Sulfide-Containing Scale from Metal Surfaces, ” US Patent 4,289,639, 1981. Ford, W.G.F., Walker, M.L., Halterman, M.P., Parker, D.L., Brawley, D.G., and Fulton, R.G.: “Removing a Typical Iron Sulfide Scale: The Scientific Approach, ” paper SPE 24327 presented at the 1992 SPE Rocky Mountain Regional Meeting held in Casper, WY, 18-21 May. Crowe, C.W.: "Method of Preventing Precipitation of Ferrous Sulfide and Sulfur During Acidizing," US patent 4,633,949, 1987. Hall, B.E. and Dill, W.R.: “Iron Control Additives for Limestone and Sandstone Acidizing of Sweet and Sour Wells,” paper SPE 17157 presented at the 1988 SPE Formation Damage Control Symposium held in Bakersfield, CA, 8-9 February. Dill, W.R. and Walker, M.L.: "Composition and Method for Controlling Precipitation When Acidizing Sour Wells," US Patent 4,888,121, 1989. Williamson, C.D.: "Precipitation Control," US patent 5,126,059, 1992. Crowe, C.W.: “Evaluation of Agents for Preventing Precipitation of Ferric Hydroxide from Spent Treating Acid,” JPT (April 1985) 691. Roberts, B.E.: “The Effect of Sulfur Deposition on Gas Well Inflow Performance,” paper SPE 36707 presented at the 1996 SPE Annual Conference and Exhibition held in
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38.
39.
40.
41.
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Denver, CO, 6-9 October. Roof, J.G.: “Solubility of Sulfur in Hydrogen Sulfide and in Carbon Disulfide at Elevated Temperature and Pressure,” SPEJ (1971) 272. Nasr-El-Din, H.A., Al-Humaidan, A., Fadel, B., Frenier, W., and Hill, D.: “Investigation of Sulfide Scavengers in Well Acidizing Fluids”, paper SPE 58712 presented at the 2000 SPE International Symposium on Formation Damage Control held in Lafayette, LA, 23-24 February. Kalpakci, B., Margi, N.F., Ravenscroft, P.D., and McTeir, M.D.K.: “Mitigation of Reservoir Souring - Decision Process,” paper SPE 28947 presented at the 1995 SPE International Symposium on Oilfield Chemistry held in San Antonio, TX, 14-17 February. Brezinski, M.M. and Gdnaski, R.D.: “Methods of Reducing Preipiation from Acid Solutions, ” US Patent # 5,264,141, 1993. Al-Humaidan, A.Y. and Nasr-El-Din, H.A.: "Optimization of Hydrogen Sulfide Scavengers Used During Well Stimulation," paper SPE 50765 presented at the 1999 SPE Oilfield Chemistry held in Houston, TX, 16-19 February. Taylor, K.C., Nasr-El-Din, H.A. and Al-Alawi, M.: “Systematic Study of Iron Control Chemicals Used During Well Stimulation”, SPEJ , 4 (1999) 19-24. Rosser, H.R., Nasr-El-Din, H.A., Al-Shamri, N., AlDhafeeri, A.: "Propagation of Biocides in a Sandstone Reservoir in Saudi Arabia", paper SPE 50740 presented at the 1999 SPE Oilfield Chemistry held in Houston, TX, 16-19 February. Nasr-El-Din, H.A., Rosser, H.R. and Al-Jawfi, M.: “Formation Damage Resulting from Biocide/Corrosion Squeeze Treatments,” paper SPE 58803 presented at the 2000 SPE International Symposium on Formation Damage Control, Lafayette, LA, 23-24 February. Larsen, J., Sanders, P.F., Talbot, R.E.: “Experience with the Use of Tetrakis Hydroxymethyl Phosphonium Sulfate (THPS) for the Control of Downhole Hydrogen Sulfide, ” paper NACE # 123 presented at the NACExpo 2000, Orlando, FL, 26-31 March.
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H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
SPE 68315
Table 1: Iron sulfide species common in the oil industry and their solubility in mineral acids . Parameter
Mackinawite
Marcasite
Pyrite
Pyrrhotite
Troilite
Fe9S8
FeS2
FeS2
Fe7S8
FeS
Tetragonal
Orthorhombic
Cubic
Monoclinic
Hexagonal
Bronzy
Tin-White
Pale
Bronze Yellow
Light Grayish Brown
7
Chemical Formula Crystalline 16 Structure 16
Color
Brassy Yellow 16
Hardness 16
Density
3
(g/cm ) 7
Solubility in Acids
Soft
6- 6.5
6- 6.5
3.5- 4.5
3.5- 4.5
4.30
4.875
5.013
4.69
4.85
Fast
Slow and Difficult
Slow and Difficult
Moderate
Rapid and Easy
Table 2: Mineralogy of iron sulfide scale samples collected from various wells.
Mineral FeS FeS2 FeCO3 Fe7S8 Fe3S4 Fe2O3 CaCO3 Others
Well-75 36 26 35 2 1
Well-227 9 13 33 45 -
Well-10 30 56 6 8
Well-895 (34ft) 6 86 7 1
Well-895 (680ft) 85 10 4 1
SPE 68315
IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
Photo 1. Scale collected from Well – 75 at 4055 ft.
Photo 3. Scale sample collected from Well-895 at 34 ft.
9
Photo 2. Scale collected from Well-10.
Photo 4. Scale sample collected from Well-895 at 680 ft.
10
H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
SPE 68315
12 10 8
H 6 p 4 2 0 0
100
200
300
400
500
600
Flowback Time, min Figure 1. pH of flowback samples, Well-A.
25
% t w20 , n o i t a r 15 t n e c 10 n o C l 5 C H 0 0
100
200
300
400
500
Flowback Time, min
Figure 2. Acid Concentration in flowback samples, Well-A.
600
SPE 68315
IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
300000
L / g 250000 m , n o i t 200000 a r t n 150000 e c n o C 100000 e d i r o l h 50000 C 0 0
100
200
300
400
500
600
Flowback Time, min
Figure 3. Chloride concentration in flowback samples, Well-A.
80000
60000 L / g m , n o r 40000 I l a t o T20000
0 0
100
200
300
400
500
Flowback Time, min Figure 4. Total iron concentration in flowback samples, Well-A.
600
11
12
H.A. NASR-EL-DIN, A.Y. AL-HUMAIDAN
SPE 68315
70
L / g m60 , n o i t 50 a r t 40 n e c n o 30 C e s e 20 n a g 10 n a M 0 0
100
200
300
400
500
600
Flowback Time, min
Figure 5. Manganese concentration in flowback samples, Well-A.
25
% t w20 , n o i t 15 a r t n e c 10 n o C l 5 C H 0 0
100
200
300
Flowback Time, min Figure 6. HCl concentration in flow back samples, Well-B.
400
SPE 68315
IRON SULFILE SCALE: FORMATION, REMOVAL AND PREVENTION
16000 14000
L / 12000 g m10000 , n o r 8000 I l 6000 a t o T 4000 2000 0 0
100
200
300
400
Flowback Time, min Figure 7. Total iron concentration in flowback samples, Well-B.
L / 60 g m , n 50 o i t a r 40 t n e c 30 n o C 20 e s e n a 10 g n a M 0
0
100
200
300
400
Flowback Time, min
Figure 8. Manganese concentration in flowback samples, Well-B.
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