Cost Effective Removal of Iron Sulfide and Hydrogen Sulfide from Water Using Acrolein

Abstract

Iron sulfide (FeS) and hydrogen sulfide (H2S) pose serious operational and safety problems in water injection systems. While H2S can cause corrosion and toxicity problems, the most common problems associated with iron sulfide are plugging of equipment, filters, injection lines and the formation face. Iron sulfide is frequently formed under oilfield conditions from the interaction of iron with hydrogen sulfide in produced water. Different forms of iron sulfide are produced as a result of both chemically and biologically mediated complex reactions. Furthermore these different forms of iron sulfide undergo various transformations as they are subjected to different environmental conditions. Acrolein acts on H2S and iron sulfide through an irreversible chemical reaction with the sulfide entity, producing nontoxic, water soluble, low molecular weight products. Acrolein is being used successfully in oilfield applications both land-based and offshore for removing H2S and iron sulfide from produced water. Acrolein treatments have been shown to be highly effective in terms of cost and performance. This paper presents field data on the performance of acrolein in mitigating iron sulfide and H2S problems in water injection systems and compares acrolein performance to that of other chemicals. The parameters monitored in the field to determine performance were frequency of injection filter replacement, water quality, and Millipore filtration times. Results from extended field tests demonstrated that acrolein was the most efficient and cost effective chemical of those tested in removing iron sulfide and hydrogen sulfide from the injection water system. Introduction The presence of Iron sulfide (FeS) and hydrogen sulfide (H2S) can cause several operational problems in water injection systems. H2S can cause corrosion of pipelines and equipment and formation of iron sulfide and creates safety and toxicity concerns. Iron sulfide in injection water results in corrosion and plugging of the lines and formation, lower water throughput, and/or resulting in higher injection pressures and frequent filter changes at the well head, plant and other locations in the system. An operator of a large water injection system in West Texas was injecting approximately 14.78×106 liters of water per day using 11 different plants. H2S and FeS were present in varying concentrations in the water system at different locations, which if left untreated, resulted in corrosion and plugging of the lines and marginal performance of injection wells. Acrolein had provided an effective solution to the aforementioned problem in the existing water system for several years. However in 1998, the operator wanted to evaluate available technology to identify a cost-effective replacement for acrolein in the water injection system. This paper discusses the selection and performance of new and existing chemistries from a series of field trials conducted at two different locations in this water injection system. Iron Sulfide Overview. Iron sulfide is frequently formed under oil field-related conditions from interaction of iron with H2S in produced water. The stability of various iron sulfides depends on conditions such as pH, availability of oxygen, concentration of sulfur-bearing species, composition of the aqueous electrolyte environment and mechanism of biological activity [1]. It has been demonstrated that bacterially produced ferrous sulfides are identical with chemically prepared ferrous sulfides. The initial iron sulfide, stable at pH 7, formed by either bacterial or chemical action, is mackinawite. This is a sulfur-deficient tetragonal crystalline compound, FeS1-x where x = 0 to 0.11. In acid conditions or in the presence of free sulfide ions, mackinawite is converted to greigite, Fe3S4, and eventually to pyrrhotite, Fe1-xS, where x = 0 to 0.125 [2]. For the purpose of this study it was assumed that iron sulfide present in the water injection system was mackinawite based on literature review [1–3], laboratory experience, and field observations. Iron Sulfide Overview. Iron sulfide is frequently formed under oil field-related conditions from interaction of iron with H2S in produced water. The stability of various iron sulfides depends on conditions such as pH, availability of oxygen, concentration of sulfur-bearing species, composition of the aqueous electrolyte environment and mechanism of biological activity [1]. It has been demonstrated that bacterially produced ferrous sulfides are identical with chemically prepared ferrous sulfides. The initial iron sulfide, stable at pH 7, formed by either bacterial or chemical action, is mackinawite. This is a sulfur-deficient tetragonal crystalline compound, FeS1-x where x = 0 to 0.11. In acid conditions or in the presence of free sulfide ions, mackinawite is converted to greigite, Fe3S4, and eventually to pyrrhotite, Fe1-xS, where x = 0 to 0.125 [2]. For the purpose of this study it was assumed that iron sulfide present in the water injection system was mackinawite based on literature review [1–3], laboratory experience, and field observations.

New Environmentally Friendly Acid System for Iron Sulfide Scale Removal

“…Using less corrosive acids such as formic acid, thioglycolic acid, glyoxylic acid, or maleic acid can help in dissolving iron sulfide scales at high temperatures [19,27]. Acrolein (2-propenal) was claimed to be an iron sulfide scales dissolver and also acted as an H 2 S scavenger and biocide [28,29]. However, acrolein should be carefully handled due to its high acute toxicity and also it is supposed to be a carcinogen [30].…”

Combination Package Development of Scale Inhibitors and Hydrogen Sulfide Scavengers for Sour Gas Production in Barnett Shale

“…These include metal based scavenger for controlling H 2 S during the drilling, nitrite/nitrate solution, acrolein, tetrakis hydroxymethyl phosphonium sulfate (THPS), caustic scrubbing, and amine-aldehyde condensates. Direct injection scavengers, including oil-soluble and water-soluble amine-aldehyde condensates, are both efficient and cost-effective (Davidson 2004;Aften 2011;Salma 2000;Moore et al 2010;Garcia and Lordo 2007). During oil production, removing low level of H 2 S through amine based scavengers is the most common strategy.…”

Matrix Acid Stimulation - A Review of the State-Of-The-Art

“…The most likely is ferric hydroxide, which forms a gelatinous, plugging precipitate when the acid pH rises about pH 2.2 (19,27) . In sour wells, iron sulphide (FeS) and even colloidal sulphur can precipitate from acid when the pH is in the range of pH 1.9 (24,25,26,28) . Much less likely to form is ferrous hydroxide, which only precipitates at close to pH 7, a value unlikely to be encountered even with completely spent acid.…”