Hydrogen Sulfide In Oil Research Articles

TECHNOLOGICAL SOLUTION FOR COMBATING HYDROGEN SULFIDE AT THE FIELD

One of the urgent problems in the production of hydrogen sulfide-containing oils is the problem of increasing the efficiency of hydrogen sulfide removal. Optimization of costs associated with the production, transportation and preparation of oil is very important at the present time. In order to reduce the costs of oil preparation, the use of a differentiated approach to solving the problem of its purification from hydrogen sulfide at the Kashagan field depends on the volumes of oil preparation, the mass fraction of hydrogen sulfide in the oil, the presence of gas near the high-sulfur oil preparation unit (UPVSN) that does not contain hydrogen sulfide, the presence of a gas collection system and the possibility of transporting increased volumes of hydrogen sulfide-containing gas to the sulfur purification unit. Taking these factors into account, it is necessary to identify the maximum values ​​​​of the volume fractions of methane, ethane, nitrogen and carbon dioxide in the composition of the stripping gas, at which the mass of oil will be preserved, as well as the conditions under which it will be purified from hydrogen sulfide in the conditions of the Kashagan field. Studies have shown that with an increase in the oil heating temperature and a decrease in the pressure in the desorption column, the maximum total volume fraction of methane and nitrogen in the mixture in the composition of the stripping gas decreases. A decrease in the mass fraction of hydrogen sulfide in oil below 100 ppm and maintaining the mass yield of oil depending on the proportion of these components in the composition of the stripping gas is possible if the oil temperature and pressure in the column are optimized. An increase in the total volume fraction of methane and nitrogen in the composition of the stripping gas leads to a decrease in its required consumption to achieve a certain efficiency of oil purification from hydrogen sulfide at specified operating parameters of the column.

An ortho-rhom-bic polymorph of 2-(1,3,5-di-thia-zinan-5-yl)ethanol or MEA-di-thia-zine.

Substituted triazines are a class of compounds utilized for scavenging and sequestering hydrogen sulfide in oil and gas production operations. The reaction of one of these triazines under field conditions resulted in the formation of the title compound, 2-(1,3,5-di-thia-zinan-5-yl)ethanol, C5H11NOS2, or MEA-di-thia-zine. Polymorphic form I, in space group I41/a, was first reported in 2004 and its extended structure displays one-dimensional, helical strands connected through O-H⋯O hydrogen bonds. We describe here the form II polymorph of the title compound, which crystallizes in the ortho-rhom-bic space group Pbca as centrosymmetric dimers through pairwise O-H⋯N hydrogen bonds from the hydroxyl moiety to the nitro-gen atom of an adjacent mol-ecule.

Liquid-Phase Oxidation of Hydrogen Sulfide in Oil with Molecular Oxygen in the Presence of an Ammonia Solution of Cobalt Phthalocyanine

The results of studying the dependence of the reaction rate of the hydrogen sulfide oxidation in oil with molecular oxygen in the presence of an ammonia solution of cobalt phthalocyanine on the process temperature, the consumption of the catalyst complex, and the concentration of cobalt phthalocyanine in the catalyst complex are reported. It was shown that the rate of the hydrogen sulfide oxidation strongly depends on the consumption of the catalyst complex and the concentration of cobalt phthalocyanine in the catalyst complex. Based on experimental data, a mathematical model was derived that describes the hydrogen sulfide oxidation with satisfactory accuracy. The calculated values obtained using this mathematical model are in good agreement with the experimental data.

Влияние сероводорода в нефти на коррозионную стойкость магистральных нефтепроводов

Влияние сероводорода в нефти на коррозионную стойкость магистральных нефтепроводов

The presence of nitrate- and sulfate-reducing bacteria contributes to ineffectiveness souring control by nitrate injection

Nitrate injection has been widely used to minimize the production of biological hydrogen sulfide in oil and gas field industry, by controlling the growth of sulfate-reducing bacteria (SRB) chemically and biologically. This study aimed to investigate the changes in the bacterial community in response to nitrate addition used to control biological souring. Specifically, we examined the effect of nitrate addition in an artificial souring experiment, using diluted crude oil as substrate and electron donor. Desulfotignum sp. was the predominant SRB under all conditions tested. Addition of nitrate at the beginning (N0) repressed the growth of SRB, as revealed by chemical and bacterial community analysis, concomitant with significant growth of the nitrate-reducing bacteria (NRB) Thalassospira sp. Nitrate addition after SRB growth (at day 28, N28) successfully remediated the sulfide produced by SRB, but no significant reduction in sulfate was observed subsequently; moreover, the bacterial communities before and after nitrate addition remained identical. Isolation of Desulfotignum YB01 (D. YB01) proved the resistance of this predominant SRB in high nitrate environment. Simultaneous reduction of sulfate and nitrate by D. YB01 was also observed in this study. Therefore, the phenomenon in the N28 experiment might be the result of the role of Arcobacter sp. which are nitrate-reducing sulfide-oxidizing bacteria, and/or the ability of Desulfotignum sp. to reduce nitrate and/or nitrite as a stress response. Thus, SRB might persist after nitrate addition, potentially causing subsequent SRB outbreaks.

Study of Chemical Processes in the use of Absorbers of Hydrogen Sulfide in Oil

Results are presented for the mass spectral determination of the composition of hydrogen sulfide absorbers, the chemical processes occurring in them as a function of the components used and their concentration, the chemical processes leading to the formation of precipitates of organosulfur compounds resulting from reactions between the absorbers and hydrogen sulfide in oil, and the composition of these compounds.

A model for transport of hydrogen sulfide in oil- and water-saturated porous media

In several oilfields, reservoir souring by generation of hydrogen sulfide (H2S) occurs in secondary recovery during which seawater is injected into originally sweet reservoirs. At the production site, high concentrations of H2S can cause severe damage to both equipment and human personnel. Proper modeling of H2S concentration in produced fluids can be useful for decision-making during field development design. We present a model for the transport of H2S in an oil- and water-saturated, water-wet porous medium. The different retardation mechanisms for the H2S are described. For the adsorption of H2S to rock, we include two distinct phases of adsorption. In addition, we introduce a functional relationship between adsorption capacity and permeability. As H2S mixes with oil, fractions become immobile as part of the residual oil.

Producing Sour Oil and Gas in the Jay Field

The presence of hydrogen sulfide in oil from the Jay field required complex facilities to produce salable oil and gas. The modular-facility design concept permitted full allowable production to be attained in minimum time. Although expensive and potentially hazardous, production of sour oil and gas can be accomplished safely and without damaging the environment. Introduction Because of the presence of hydrogen sulfide in Jay field crude oil, complex facilities, including oil stabilization, gas sweetening, and sulfur-recovery units, were required to produce salable oil and gas. To initiate field production and to provide extended well tests, a small 2,000-B/D facility was installed initially. As development drilling proceeded, 6,500- and 12,000-B/D modules were built proceeded, 6,500- and 12,000-B/D modules were built when and where needed. By using the modular-facility design concept, the field producing capacity was more than 90,000 B/D within 2 1/2 years of discovery. Design concepts were used to minimize hazards to personnel, to prevent corrosion, and to protect the personnel, to prevent corrosion, and to protect the environment. Special operating procedures, personnel safety equipment, and training completed these design concepts. An extensive ambient-air monitoring network was established to insure that ambient-air standards were met to protect the environment. Initial Production The Jay field was discovered in June 1970 with the St. Regis No. 1 well, located about 35 miles north of Pensacola, Fla. (Fig. .1). Initial well testing confirmed Pensacola, Fla. (Fig. .1). Initial well testing confirmed that the reservoir oil contained an appreciable amount of hydrogen sulfide (Table 1). The approximate 9 mol percent hydrogen sulfide required treating facilities to percent hydrogen sulfide required treating facilities to make the oil and gas salable. Following testing of the St. Regis No. 1 well, studies were immediately undertaken for initiation of production from the field. Two alternatives were considered for sizing a treating facility:conduct a short-term productivity test using separation and storage facilities productivity test using separation and storage facilities for the crude, and bum all produced gas, andinstall a small treating and sulfur-recovery unit for an extended test. In both cases, a larger facility was proposed if and when development drilling so dictated. The decision to install a small testing and sulfur-recovery unit was made because of economic, environmental, and safety considerations. This alternative provided a means of initiating field production while continuing definition drilling. It was also advantageous to have extended tests under actual production operations to better establish reserves and productivity guidelines for evaluating a large plant. The small treating and sulfur-recovery unit also minimized the pollution problems associated with flaring sour gas containing about 15 mol percent hydrogen sulfide, and eliminated the potential hazards involved in disposing weathered crude with a sulfur content of 2,000 ppm. Less than 1 month after discovery, an engineering contractor was selected to dismantle a surplus amine-treating, Claus sulfur-recovery facility located in Cass County, Tex., and to reassemble the facility at Jay. This surplus facility consisted of an oil stripping unit to remove hydrogen sulfide from the crude oil, an MEA gas-treating unit to recover hydrogen sulfide gas from casinghead gas and stripping vapors, and a two-Stage Claus sulfur-recovery unit to convert the hydrogen sulfide to elemental sulfur. At that time, the State of Florida had not established air quality standards for Northwest Florida. JPT P. 701