TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Description of PaperThis 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 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. The ratio of iron to sulfide in these species depends on temperature, pressure, pH, and hydrogen sulfide 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. Non-acid formulae can be used to remove iron sulfide scale, however, their ability to dissolve iron sulfide depends on the molar ratio of iron to 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. Results, ConclusionsExtensive 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, 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 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 to deal 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 are recommended for old iron sulfide scale, which has low acid solubility. Area of InterestIron sulfide scale is present in sour oil and gas wells and injectors that are contaminated with sulfate reducing bacteria (SRB). It enhances the corrosion rate of the downhole tubulars, and adversely affects the performance of various wells. It reduces the efficiency of oil-water separation in various GOSPs. Removing iron su...

This paper describes the development of acidizing systems that use several different aldehyde-based sulfide suppression chemicals in conjunction with new acid corrosion inhibitors. Specific combinations of these chemicals have allowed the acid to dissolve FeS, suppress H2S and still enable the acid to be inhibited to industry corrosion standards. Laboratory tests include dissolution of FeS, measurement of H 2S evolved, measurement of acid concentration and chloride ion concentrations. We also determined the effect of FeS and H2S on the corrosion of oilfield steels with these additives. Laboratory measurements covered the temperature range from 75 to 275°F (reservoir temperature). Experimental results were compared with that previously published data.1 The new system enabled the acid to dissolve more FeS than fluids containing previously tested suppressors, while controlling H2S evolution and corrosion. During field testing, samples of the spent acid were captured and were analyzed for [Fe], [S2-] and [HCl]. The data will contribute to an understanding of the corrosion processes and sulfide control during acid treatments. The field acid treatments were accomplished successfully without significant changes in procedures and resulted in large increase in gas production. This system is designed primarily for "tube cleaning" operations prior to acid stimulation (matrix and fracture acidizing), but the control chemicals have also been tested for use in the actual stimulation fluid stages. The new chemicals and procedures will allow the operators to safely remove large amounts of fouling deposits, while controlling the toxic and corrosive effects of H2S much more effectively than previously used products. Introduction In many wells, pipelines, or in the hydrocarbon processing units of refineries, iron-based surfaces may come into contact with sulfur-containing fluids. At the temperatures present in the various sections or reactors, and during long periods of contact, iron sulfide deposits (generally FeS, but sometimes, FeS2) will form. The reduced sulfur minerals with approximately 1:1 Fe/S mol ratios (makinawite, troilite, pyrrhotite) can be dissolved using mineral acids, while pyrite and marcasite (FeS2) have low acid solubility. While scale removal using mineral acids is a very effective procedure, it produces large amounts of hydrogen sulfide. FeS + 2H+ = Fe2+ + H2S (1). Hydrogen sulfide causes severe safety and operational problems once the acid leaves the system being treated, and H2S stimulates corrosion of the base metal. For pipelines or in refinery operations, surface cleaning is the major goal of the operation. Lawson et al.3reviewed the major procedures for safely removing iron sulfide deposits:mineral acids with an acid-gas scrubber;mineral acids with hydrogen sulfide suppression chemicals;multiple stages of oxidizing agents with acids; andalkaline cleaners. Several different suppression technologies have been developed for surface cleaning operations. Frenier and co-workers4–6 and Buske7 developed suppression chemicals that contain aldehydes. The most efficient agent is formaldehyde, which reacts stoichiometrically with hydrogen sulfide to produce trithiane, a very insoluble material.8 In treating sour oil and gas wells, as compared with treating surface equipment, corrosion suppression (not elimination of sulfide gas) and dissolution of FeS are of major concern. The inhibitor package must protect several types of steel at high temperatures in the presence of concentrated acid containing numerous additives. The various additives are required since the purpose of the treatment may include removal of inorganic and organic damage from producing formations (matrix treatments).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMany water injectors and oil producers are damaged due to the accumulation of iron sulfide deposits near the wellbore area. For example, iron sulfide is present in water supply and injection wells as a product of sulfate reducing bacteria (SRB). Hydrochloric acid can be used to remove iron sulfide, however this process can result in the release of hydrogen sulfide, a toxic and corrosive gas. Moreover, hydrogen sulfide reacts with ferric ions and precipitates elemental sulfur. Elemental sulfur is insoluble in acids, practically impossible to dissolve, and can damage the formation. The objectives of this study are to screen hydrogen sulfide scavengers, which can be used during well stimulation, and assess the performance of the selected chemical in the field.A simple, fast procedure was developed to evaluate hydrogen sulfide scavengers. Several types of scavengers, all aldehyde-based chemicals, were examined. The concentration of hydrogen sulfide scavenger was varied from 0 to 10 wt%. Reaction temperature was kept constant at 25 °C. A simple, fast procedure was developed to screen hydrogen sulfide scavengers used during well stimulation. The efficiency of capturing hydrogen sulfide was found to be a function of scavenger type and concentration. At scavenger concentrations greater than 0.5 wt%, a polymer-like material was observed with most scavengers examined; this material adversely affected acid reaction with iron sulfide and could cause formation damage. Low sulfide concentrations were obtained in the acid returns when S-1 was added in the acid formulation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIron sulfide scale is present in sour gas, oil and water wells. It is present in various chemical species with different iron to sulfur ratios. Iron sulfide species with high iron content is soluble in acids, whereas those rich in sulfur are almost insoluble in acids. Iron sulfide scale was detected in several water supply wells where a sour gas is used for gas lifting operation. The objectives of this study were to determine the mechanism that led to the formation of this type of scale, to characterize this scale and determine the most effective chemical treatments to remove and prevent reoccurrence. Lab work included characterization of the scale, and examine various acids and non-acids formulae to remove various iron sulfide species.Several wells in a sandstone aquifer are used to supply water needed for the operation of gas oil separation plants (GOSPs). The reservoir pressure is low, therefore the water is produced using gas lifting. The gas used is an associated gas that is produced with the oil from a carbonate reservoir. The gas is sour with a hydrogen sulfide content of 2 mol%. In addition, the supply water contains total iron at 5-10 mg/L. Hydrogen sulfide reacts with the iron present in the aquifer water and precipitates iron sulfide on the well tubulars and gas injection nozzles. Accumulation of iron sulfide has caused many operational problems.Lab results indicated that iron sulfide scale deposited on the inside wall of the well tubulars. The scale was uniform with a thickness that increased from 0.025" above the gas injection point to 0.25" at the well head. The composition of the scale changes with the length above the gas injection point. Just above the gas injection point, the scale was identified as FeS whereas close to wellhead, the scale was identified as FeS 2 . Acid solubility varied across the length of tubing. In areas where there is FeS, acid solubility in 20 wt% was 85-90 wt%. On the other hand, acid solubility was only 3-5 wt% in areas where FeS 2 was present. Experimental results showed that 20 wt% could be used to remove a portion of the scale, however a suitable hydrogen sulfide scavenger should be added to the acid. Several non-acid formulae were tested and some of them were effective in dissolving acid-insoluble scale.Unlike typical types of oilfield scales, iron sulfide is present in different species. The chemical structure of these species affects the method that should be used to remove this scale. This study addresses various types of iron sulfide and methods to remove and prevent the formation of this type of scale.

This paper describes the effect of chemical interactions on the efficiency of removing iron sulfide scale. Most types of iron sulfide can be removed by inorganic acids. A corrosion inhibitor (amine-type chemical) is added to the acid to protect the well tubulars. In addition, a hydrogen sulfide scavenger (aldehyde type) is used to prevent precipitation of elemental sulfur and iron sulfide. Other chemicals are also added to the acid to enhance acid-contact with the scale and prevent precipitation of iron once the acid is spent. Laboratory tests were conducted to evaluate the effect of chemical interaction on the efficiency of removing iron sulfide scale. The influences of various acid additives (anionic, cationic and non-ionic) on the dissolution power of the acid and the corrosion of oilfield steels were examined over a wide range of parameters. Results, Conclusions Laboratory data indicated for the first time that the ability of the acid to remove iron sulfide scale depends, among other factors, on the ionic character of the acid additives. Corrosion inhibitors, which are used to protect the casing and well tubulars from the acid, were found to adsorb on the iron sulfide scale and inhibit acid reaction with the scale. Hydrogen sulfide scavengers, aldehyde type chemicals, were found to inhibit acid reaction, especially at high concentrations. A similar trend was noted with methanol and citric acid. On the other hand, TX-100 (a nonionic surfactant) and SDS (an anionic surfactant) was found to enhance the dissolution of iron sulfide by the acid. Acid additives, especially anionic surfactants and mutual solvents were found to affect the ability of the corrosion inhibitor to protect the base metal. Introduction Iron sulfide scale is present in sour wells,1 seawater injectors,2 water injection,3–5 and supply wells6 that are contaminated with sulfate reducing bacteria (SRB). It is also present in produced water disposal wells7 where hydrogen sulfide present in crude oil partitions into the produced water. Hydrogen sulfide reacts with iron surfaces of uncoated vessels, pipelines and well tubulars and produces iron sulfide. Iron sulfide is present in various forms in the wellbore area. Analysis of the scale present in sour gas wells indicated that there are several types of iron sulfide species.1 Mackinawite, troilite, pyrrhotite, pyrite, and marcasite are found on tubular surfaces. Smith and Miller8 examined the crystalline structure and physical properties of various iron sulfide minerals. Hydrochloric acid can be used to dissolve iron sulfide deposits with varying degrees of success. In general, iron sulfide deposits with low sulfur content have higher solubility in acids.9 Acid reaction with iron sulfide produces hydrogen sulfide, as shown in Equation 1. (1) F e S + 2 H C I = H 2 S + F e C I 2 Hydrochloric acid is very reactive at temperatures encountered in most gas and oil reservoirs. Acidizing fluids contain a variety of special additives; the type and amount depend on the nature of the treatment. The fluids always contain corrosion inhibitors to suppress the attack of the acid on the tubulars and surface equipment. Other additives include wetting agents (surfactants), chelants or reducing agents for control of iron precipitation, anti-sludge agents and various solvents (methanol or glycol ethers). Sulfide suppressors will also be required in sour wells. 10–14 While required for a successful treatment, acid additives can affect scale dissolution characteristics15 and can also adversely affect corrosion inhibition.16