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.

Hydrogen sulfide (H2S), a corrosive and toxic gas, when present in produced fluids such as condensate, gas and water, poses serious health and operational hazards. Non-regenerable H2S scavengers have been in use for H2S removal from sour gas and condensate for over a decade. Selection of an appropriate non-regenerable chemistry is dictated by the downstream treatment processes that the gas or condensate will be subjected to after H2S removal is accomplished. Successful selection and application of non-regenerable H2S scavengers requires a thorough evaluation of operating conditions such as temperature, pressure, mixing, etc., that affect H2S removal from sour fluids. Most of the applications require on-site optimization to achieve maximum scavenging performance. This paper presents results and observations from a field trial for sweetening a large volume of sour condensate held in a 70,000 bbl storage tank using a water-soluble triazine-based scavenger. Mode of application of the triazine-based scavenger was found to be one of the most important factors for successful reduction of H2S in liquid hydrocarbons held in large tanks. Another important factor affecting H2S scavenger performance was the presence of sulfide species other than H2S in the sour fluid. Experiences gained from the trial illustrate the importance of a systematic approach required for effective sweetening in liquid hydrocarbons. Introduction Non-regenerable type liquid H2S scavengers are being widely used for removal of H2S in a variety of applications in the oil and gas industry[1–6]. However, limited information is available in the literature on actual case studies and optimization techniques on the application of non-regenerable H2S scavengers in liquid hydrocarbons. This paper reports the results and observations from a field test using a non-regenerable liquid H2S scavenger in a difficult operational setting. Scavenger Selection Criteria. Operating conditions such as condensate temperature, pressure, volume, composition, degree of mixing and contact time with the scavenger strongly influence the selection of an H2S scavenger for removal of H2S from a given fluid[7]. One factor demanding particular consideration in scavenger selection for hydrocarbon liquids is the downstream processing of the condensate after the H2S has been removed. For example, processing of condensate in a refinery often requires maintaining a low nitrogen content in the condensate to avoid poisoning of the catalysts in the reforming process. Most of the non-regenerable liquid H2S scavengers are amine based. An oil-soluble scavenger will remain dissolved in the oil phase, which may cause an increase in the nitrogen content of the hydrocarbon liquids depending on the volume of scavenger used in the treatment. On the other hand, a water-soluble scavenger can separate from the hydrocarbon phase relatively easily due to solubility and density differences. Therefore, water-soluble scavengers tend to offer a chemical treatment option for H2S removal with little or no interference with the downstream refining processes.

Continuous increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from existing wells. In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become "loaded" with liquids. A method commonly used to deliquify these wells is through the application of chemical "foamers". However, these traditional foamers tend to be ineffective as the condensate-to-water ratio increases. This paper describes the performance of a novel foamer specifically designed to unload condensate from wells. This foamer helped unload a gas well that produced condensate via intermittent production at 2:1 condensate-to-water ratio. Parameters for well selection are described, as well as operational processes to maximize continous production. As a result of this treatment, the daily average gas production rate increased significantly and shifted the daily on:off production cycle from 1:1 to 11:1. This minimized well down time and increased the overall daily production averages by 60 percent. Introduction Gas producers traditionally have observed that increasing amounts of liquid hydrocarbon (condensate) significantly affect the ability of conventional foamers to deliquify liquid loaded gas wells. This situation is prevalent in several wells in South Texas. This work describes the results from a trial using a foamer specifically designed for condensates. Because of the difficulties in treating liquid-loaded wells with higher condensate cuts, the operator at this location uses a variety of methods to prevent liquid loading in marginal gas wells. These methods include: the use of intermitters; velocity strings; adding additional compressor capacity; and applying chemical foamers. The newly-developed condensate foamer was designed to provide a more cost-effective way to unload condensate-loaded gas wells. Intermitters allow for periodic gas flow interruptions that enable the formation to temporarily increase down-hole gas pressure in the reservoir during the shut-in phase. This accumulated pressure provides sufficient gas velocity to unload liquids from the well when opened. This continues until the actual gas velocities decrease below the critical velocities where loading occurs. The disadvantage of this type of production method is the loss of gas (and condensate) production during the "off" periods. Velocity strings are inserted tubing strings that are narrower than the existing tubing (typically a wide capillary string) that enable the user to physically increase the linear velocity of the gas and, in turn, prevent liquid loading. The disadvantage of this type of production method is the possible loss of production, due to the restriction the string creates. Added compression capacity reduces the overall wellhead pressure and thus increases the differential pressure with the down-hole pressure. This removes gas back-pressure restrictions that are conducive to liquid loading. The disadvantage of this option is the large capital expenditure required to add compressors. For this trial, the condensate foamer was applied to a well where an intermitter was being used to prevent liquid loading. This paper discusses the well selection criteria used to identify candidate wells, in addition to presenting the performance results of the condensate foamer applied to this well.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEffective removal of hydrogen sulfide (H 2 S) is one of the challenging problems associated with the production of natural gas. Since H 2 S is often present in natural gas along with varying levels of carbon dioxide (CO 2 ), selective removal of H 2 S from sour gas in the presence of CO 2 is very important for cost effectiveness of a scavenging operation. For over ten years, triazine based scavengers have been successfully applied in the sweetening of natural gas. However, observations of the effect of CO 2 on the scavenging capacity of triazine based scavengers have not been very consistent. Initial documentation and case histories on performance of triazine based scavengers by Dillon [1,2] reported that CO 2 did not have any effect on the H 2 S scavenging capacity of triazine. However, recent studies by GRI [3] indicate that CO 2 significantly reduces the H 2 S removing capacity of triazine. To address this discrepency, this paper critically evaluates the effect of CO 2 on the scavenging performance of a triazine based H 2 S scavenger. Results from controlled laboratory experiments, using a wide range of CO 2 partial pressure and H 2 S to CO 2 ratios indicate that CO 2 has very little effect on the H 2 S scavenging performance of a triazine based H 2 S scavenger. Field data supports the observations made in the laboratory experiments.

The toxicity of hydrogen sulphide in hydrocarbon streams is well known in the industry and considerable expense and efforts are expended annually to remove hydrogen sulphide to a safe level. In large production facilities, it is generally economical to install a regenerative system for treating sour gas streams. However, during the development stages of relatively small low-sour gas fields at remote and normally unmanned locations where regenerative systems are not practical nor economical, it is necessary to treat the sour gas production with non-regenerable scavenging processes. In the development of its low-sour Zechstein gas reserves in the Coevorden field in the North-East The Netherlands, the Nederlandse Aardolie Maatschappij (a Shell operating unit, hereafter referred to as NAM) decided to adopt continuous direct-injection of liquid scavenging agents as the lowest overall cost process having the least environmental impact and the highest energy efficiency. At the inception of the project, the operating parameters controlling the scavenging efficiency using direct injection of liquid scavengers in this system were largely unknown. Consequently, numerous field trials using different chemistries and different injection mechanics had to be carried out. In this paper we present the results of these field trials, which ultimately led to a very successful and profitable field development strategy. A variety of very challenging operational problems were encountered, and solved. Reference is made to injection nozzle blockages, fouling of glycol gas dehydration systems, severe scaling problems in production and downstream water treatment/injection facilities, inadequate hydrogen sulphide removal efficiencies and HS&E related issues. A better understanding of the fundamental relationships between operating parameters governing direct-injection processes and associated chemical development and application methods has been gained. Communication and integration of experience and knowledge between the operating unit and its chemical supplier were key success factors in this achievement, as was the endurance and continuing support of field operations staff in facilitating the resolution of difficult problems. Introduction NAM's Ten Arlo system (Fig. 1) produces gas from 32 satellite locations and four gas treatment / compression plants. The majority of the fields in the system produce sweet gas from the Limburg reservoir. However, the system's heavily compartmentalized Coevorden field also contains gas accumulations in the Zechstein reservoir with H2S concentrations up to 300 ppm(v). Developing these accumulations would require extensive modifications to existing (sweet) gas production / treatment facilities to ensure safe operations and the prevention of H2S emissions. The producible reserves were small yet economically attractive. However, due to their geographical scatter, a pipeline grid connecting these low-sour accumulations to an existing nearby plant utilizing a regenerative solvent process for gas sweetening was found to be economically unfeasible. In-field desulpherisation with, for example, a solid-bed adsorption process, was found to be technically feasible, but the required capital investment and perceived life-cycle costs could not be justified. In order to allow production of the low-sour gas without violating the Ten Arlo sales gas specification for maximum allowable H2S concentration (5 mg H2S/Nm3 or 3 ppm(v)), in-field desulpherisation utilizing a commercially attractive alternative technology was looked for.