AN EXPERIMENTAL STUDY OF THE MOVEMENTS OF HERRING AND OTHER MARINE FISHES

"The corrosion protection effect of the new S-1 reagent in media with the pH values of 2.0, 4.0, 6.0, as well as carbon dioxide and hydrogen sulfide added separately and combined to the mentioned media, was first tested under laboratory conditions. The protective effect of reagent S-1 was weak in the corrosion medium without hydrogen sulfide and carbon dioxide. However, as the acidity of the medium and the concentration of the reagent increases, the corrosion protection efficiency of the inhibitor also increases. The highest effect is observed at pH = 2.0 and reagent concentration of 30 mg/l. The corrosion protection effect of the reagent reaches 97% under these conditions. In the media with pH = 4.0 and pH = 6.0 without carbon dioxide and hydrogen sulfide, the protective effect of the inhibitor at the optimal concentration of 30 mg/l is 66% and 64%, respectively. In the medium with added carbon dioxide, the protective effect of inhibitor S-1 decreases at pH = 2.0 and, on the contrary, increases at the values of pH = 4.0 and pH = 6.0. Also, as the pressure of carbon dioxide in the medium increases, the protective effect of inhibitor S-1 increases. When hydrogen sulfide is added to the medium, it causes an increase in the corrosion rate and the protection efficiency of inhibitor S-1. However, in the medium without inhibitor, the increase of hydrogen sulfide concentration only up to CH2S = 400 mg/l is accompanied by an increase in the corrosion rate at all values of pH. The addition of 1000 mg/l of hydrogen sulfide to the corrosion medium leads to the decrease in the corrosion rate in the medium without inhibitors and a slight decrease in the protective effect at the concentration of the inhibitor Cinh = 10 mg/l. As the concentration of inhibitor S-1 increases in the medium with the addition of carbon dioxide and hydrogen, its corrosion protection effect also increases. In the range of Cinh = 10–30 mg/l, when PCO2 = 0.5 atm and CH2S = 200 mg/l, the protective effect is estimated at 38–99%, and when CH2S = 1000 mg/l, it is estimated at 17–79%. At PCO2 = 1.0 atm, the value of protective effect is 22–95% and 14–76%, and finally at PCO2 = 2.0 atm, the value of the corrosion protection effect of inhibitor S-1 is estimated at 44–92% and 15–75%, respectively. The coexistence of carbon dioxide and hydrogen sulfide in an aggressive medium leads to an increase in the protective effect of inhibitor S-1 compared to the medium containing only carbon dioxide, and reduces it in comparison to the medium with hydrogen sulfide. An increase in carbon dioxide pressure in the presence of hydrogen sulfide causes a decrease in the protective effect of inhibitor S-1. The protective effect of inhibitor S-1 is lower in the medium with hydrogen sulfide concentration of 1000 mg/l compared to a concentration of 200 mg/l. This case is also observed in the carbon dioxide free medium."

A knowledge of the equilibrium water content of hydrocarbon systems under pressure is important to the national gas industry. The information available on the solubility of water in hydrocarbon, hydrogen sulfide, and carbon dioxide systems is reviewed in this paper and the influence of the more important variables such as temperature, pressure and molecular structure on solubility in liquids and gases is discussed. A suitable chromatographic technique bas been developed for determining low concentrations of water. Tailing of the water peaks bas been eliminated by adding water to the carrier gas stream The method is applicable for both gas or liquid samples and is effective in the presence of hydrogen sulfide. The experimental study of water solubility in methane-hydrogen sulfide systems at a temperature of 16F has shown that the presence o/ hydrogen sulfide causes only a modest increase in water content at pressures up to 1,400 psia. Theoretical considerations and data on pure hydrogen sulfide and carbon dioxide suggest that the effect of both these compounds will be greater at higher pressures and in the liquid phase. Introduction Before transporting or processing natural gases and gas condensates, it is usually necessary to dry them using suitable dehydration equipment. The design and operation of this equipment requires a knowledge of the amount of water present in the fluid at the reservoir and operating conditions. This is influenced by temperature, pressure and composition, particularly when certain nonhydrocarbon components are present. Field experience indicates that hydrogen sulfide and carbon dioxide, for example, alter the usual water solubility relationships appreciably. However, an extensive search of the literature does not reveal any quantitative data on such systems. For sweet natural gases, generalized empirical correlations such as the one proposed by Katz, et al, can be used to predict water solubility with confidence at most temperatures and pressures of interest. However, existing theoretical relationships do not permit a calculation of the deviation from these curves when polar substances like hydrogen sulfide are present in the system. Thus one must resort to an experimental approach to obtain the necessary information. The fact that laboratory experimental methods frequently involve the use of mercury which reacts with hydrogen sulfide in the presence of water, and that hydrogen sulfide interferes with many chemical reactions specific for water has contributed to the difficulty of studying water solubility in systems containing hydrogen sulfide. In this investigation the water content of a limited member of methane-hydrogen sulfide mixtures was determined using a special technique with gas chromatography. REVIEW OF PUBLISHED DATA Experimentally determined water solubility data have been reported for methane, ethane, propane, n-butane, 1-butene, hydrogen sulfide and carbon dioxide. These studies report the effect of pressure, temperature and molecular structure on water solubility in single component gases and liquids. SPEJ P. 293^

The beneficial effect of antibiotics in pouchitis suggests that an unidentified fecal bacterial product causes this condition. A candidate compound is hydrogen sulfide, a highly toxic gas produced by certain fecal bacteria, which causes tissue injury in experimental models. We investigated hydrogen sulfide release and sulfate-reducing bacterial counts in pouch contents to determine whether hydrogen sulfide production correlates with pouchitis. During incubation at 37 degrees C, the production of hydrogen sulfide, methylmercaptan, carbon dioxide, and hydrogen were studied using fresh fecal specimens obtained from 50 patients with ileoanal pouches constructed after total proctocolectomy for ulcerative colitis (n = 45) or for familial adenomatous polyposis (n = 5). Patients with ulcerative colitis were divided into five groups: a) no history of pouchitis (pouch for at least 2 years; n = 8); b) past episode(s) of pouchitis but no active disease for the previous year (n = 9); c) pouchitis in the past year but presently inactive (n = 9); d) ongoing antibiotic treatment (metronidazole or ciprofloxacin) for pouchitis (n = 11); e) currently suffering from pouchitis (n = 8). Release of hydrogen sulfide when pouchitis was active (6.06 +/- 1.03 micromol g(-1) 4 h(-1)) or had occurred in the past year (4.71 +/- 0.41 pmol g(-1) 4 h(-1)) was significantly higher (P < 0.05) than when pouchitis had never occurred (1.71 +/- 0.43 micromol g(-1) 4 h(-1)) or had been inactive in the past year (2.62 +/- 0.49 micromol g(-1) 4 h(-1)). Antibiotic therapy was associated with very low hydrogen sulfide release (0.68 +/- 0.29 micromol g(-1) 4 h(-1)). Pouch contents from familial adenomatous polyposis patients produced significantly less hydrogen sulfide (0.75 +/- 0.09 micromol g(-1) 4 h(-1)) than did any group of nonantibiotic-treated ulcerative colitis patients. Sulfate-reducing bacterial counts in active pouchitis (9.5 +/- 0.5 log10/g) were significantly higher than in those who never experienced pouchitis (7.38 +/- 0.32 log10/g), and these counts fell dramatically with antibiotic treatment. No statistically significant differences in carbon dioxide and hydrogen were observed among the groups not receiving antibiotics. Pouch contents of patients with ongoing pouchitis or an episode within the previous year released significantly more hydrogen sulfide than did the contents of patients who never had an attack of pouchitis and those with longstanding inactive disease. The response to therapy with metronidazole or ciprofloxacin was associated with marked reductions in hydrogen sulfide release and sulfate-reducing bacteria. These results provide a rationale for additional studies to determine whether the high sulfide production is a cause or effect of pouchitis. The lower hydrogen sulfide production by pouch contents of familial adenomatous polyposis vs. patients with ulcerative colitis suggests a fundamental difference in gut sulfide metabolism that could have implications for the etiology of ulcerative colitis as well as the pouchitis of patients with ulcerative colitis.

Inflammation plays a critical role in kidney ischemia–reperfusion injury but mechanisms of increased proinflammatory cytokine expression are not completely understood. Kidney has a high expression of cystathionine‐β‐synthase (CBS) and cystathionine‐γ‐lyase (CSE) that can synthesize hydrogen sulfide. CBE and CSE are also responsible for the synthesis of cysteine, an essential precursor for glutathione, an antioxidant. Reduced hydrogen sulfide and glutathione production is associated with multiple organ injury. Although pro‐ and anti‐inflammatory effects of hydrogen sulfide have been reported, its role in ischemia–reperfusion‐induced inflammation in the kidney has not been well addressed. The aim of this study was to investigate the effect of CBS and CSE‐mediated hydrogen sulfide and glutathione production on kidney inflammatory response and the mechanism involved. The left kidney of Sprague‐Dawley rat was subjected to 45‐min ischemia followed by reperfusion for 24 h. Ischemia–reperfusion caused a significant decrease in CBS and CSE mRNA and protein levels with a concomitant reduction of glutathione and hydrogen sulfide production in the kidney while the expression of proinflammatory cytokine expression (MCP‐1, IL‐6) was elevated. Hypoxia–reoxygenation of proximal tubular cells led to a decrease in CBS and CSE expression and an increase in proinflammatory cytokine expression. Supplementation of glutathione or hydrogen sulfide donor (NaHS) effectively attenuated cytokine expression in tubular cells. These results suggested that ischemia–reperfusion impaired CBS and CSE‐mediated glutathione and hydrogen sulfide production in the kidney, which augmented the expression of proinflammatory cytokines. Regulation of CBS and CSE expression may be therapeutically relevant in alleviating ischemia–reperfusion‐induced inflammation and improving kidney function.

The production of hydrogen sulphide and carbon dioxide is a feature common to all SAGD projects. Both gases are formed by a chemical reaction of steam condensate with bitumen in the SAGD steam zone in Athabasca; they are not normally present as solution gases. The production rates of these gases are therefore strongly dependent on operating characteristics of individual projects, primarily the steam pressure. The potential need for sulphur recovery plants in the larger SAGD project expansions creates the need for first order predictions of H2S production rates, so that appropriate sulphur recovery technologies can be identified. A simple method for prediction of hydrogen sulphide production has been derived, such that, for most Athabasca projects in the 180 to 240 °C range of steam zone temperatures, a probable production rate estimate can be read off a simple graph. This graph is presented. The graph is built from laboratory data on aquathermolysis, first provided by Hyne, and the assumption of pseudo-zero order kinetics of the aquathermolysis reaction that generates hydrogen sulphide. A temperature dependency is predicted, and is confirmed by field measurements of projects in the 180–240 degree range. Introduction The solvolytic reaction of Athabasca bitumen with steam condensate has been observed since the earliest days of piloting the recovery of this bitumen resource. The first laboratory studies were performed by Hyne et.al.1, who coined the now widely-used term "aquathermolysis". More detailed mechanistic studies followed from Hyne's group, and also from the group led by Strausz at the University of Alberta 2. The quantitative aspect of Hyne's work has been largely ignored, possibly because Hyne's work was for the most part done at 240 °C steam temperatures, whereas the steam zone temperatures in SAGD pilots and commercial operations have varied from that. Obviously, the steam zone temperature must have an effect on production of the acid gases because the kinetics of generation are temperature dependent. A previously published method of estimating hydrogen sulphide production in SAGD is provided by the method of Thimm3, which is based on the Henry's Law behaviour of gases in a SAGD steam zone. That method is capable of prediction of produced gas and steam zone gas compositions over time, including situations where the steam zone pressure changes or where gas is injected. However, it involves relatively lengthy computations in solution thermodynamics. For the purpose of identifying potential sulphur recovery technologies, a quicker method of estimating hydrogen sulphide production is required, as an at least approximate guide. Moreover, it would be useful to express the hydrogen sulphide production on a mass or volume per unit bitumen basis, to provide a simple guide for expansion planning. Reaction Order Although neither Hyne nor Strausz have published a reaction order, the following considerations suggest a zero order reaction in the SAGD steam zone. Consider that one might expect a reaction rate equation of the type rate = k [sulphur] [steam condensate] where the concentrations may be expressed in terms of various terms suitable for reservoir engineering.

The production of hydrogen sulphide and carbon dioxide is a feature common to all SAGD projects. Both gases are formed by a chemical reaction of steam condensate with bitumen in the SAGD steam zone in Athabasca; they are not normally present as solution gases. The production rates of these gases are therefore strongly dependent on operating characteristics of individual projects, primarily the steam pressure. The potential need for sulphur recovery plants in the larger SAGD project expansions creates the need for first order predictions of H2S production rates, so that appropriate sulphur recovery technologies can be identified. A simple method for the prediction of hydrogen sulphide production has been derived, such that, for most Athabasca projects in the 180 to 240 ºC range of steam zone temperatures, a probable production rate estimate can be read off a simple graph. The graph is built from laboratory data on aquathermolysis, first provided by Hyne, and the assumption of pseudo-zero order kinetics of the aquathermolysis reaction that generates hydrogen sulphide. A temperature dependency is predicted, and is confirmed by field measurements of projects in the 180 to 240 ºC range. Introduction The solvolytic reaction of Athabasca bitumen with steam condensate has been observed since the earliest days of piloting the recovery of this bitumen resource. The first laboratory studies were performed by Hyne et al.(1–3), who coined the now widely-used term "aquathermolysis". More detailed mechanistic studies followed from Hyne's group, and also from the group led by Strausz at the University of Alberta(4). The quantitative aspect of Hyne's work has been largely ignored, possibly because his work was, for the most part, done at 240 ºC steam temperatures, whereas the steam zone temperatures in SAGD pilots and commercial operations have varied from that. Obviously, the steam zone temperature must have an effect on production of the acid gases because the kinetics of generation are temperature dependent. A previously published method of estimating hydrogen sulphide production in SAGD is provided by the method of Thimm(5), which is based on the Henry's Law behaviour of gases in a SAGD steam zone. That method is capable of prediction of produced gas and steam zone gas compositions over time, including situations where the steam zone pressure changes or where gas is injected. However, it involves relatively lengthy computations in solution thermodynamics. For the purpose of identifying potential sulphur recovery technologies, a quicker method of estimating hydrogen sulphide production is required; at least, as an approximate guide. Moreover, it would be useful to express the hydrogen sulphide production on a mass or volume per unit bitumen basis to provide a simple guide for expansion planning. Reaction Order Although neither Hyne nor Strausz have published a reaction order, the following considerations suggest a zero order reaction in the SAGD steam zone. Consider that one might expect a reaction rate equation of the type: (1) rate = k [ sulphur ] [ steam condensate ] where the concentrations may be expressed in terms of various terms suitable for reservoir engineering.

Inhibition of Sulfate Reduction to Sulfide by 9,10-Anthraquinone in In Vitro Ruminal Fermentations

Management practices from large-scale swine production facilities have resulted in the increased collection and storage of manure for off-season fertilization use. Odor and emissions produced during storage have increased the tension among rural neighbors and among urban and rural residents. Production of these compounds from stored manure is the result of microbial activity of the anaerobic bacteria populations during storage. In the current study, the inhibitory effects of condensed quebracho tannins on in vitro swine manure for reduction of microbial activity and reduced production of gaseous emissions, including the toxic odorant hydrogen sulfide produced by sulfate-reducing bacteria (SRB), was examined. Swine manure was collected from a local swine facility, diluted in anaerobic buffer, and mixed with 1% w/v fresh feces. This slurry was combined with quebracho tannins, and total gas and hydrogen sulfide production was monitored over time. Aliquots were removed periodically for isolation of DNA to measure the SRB populations using quantitative PCR. Addition of tannins reduced overall gas, hydrogen sulfide, and methane production by greater than 90% after 7days of treatment and continued to at least 28days. SRB population was also significantly decreased by tannin addition. qRT-PCR of 16S rDNA bacteria genes showed that the total bacterial population was also decreased in these incubations. These results indicate that the tannins elicited a collective effect on the bacterial population and also suggest a reduction in the population of methanogenic microorganisms as demonstrated by reduced methane production in these experiments. Such a generalized effect could be extrapolated to a reduction in other odor-associated emissions during manure storage.

The issue of using oil gases is considered because the removal of harmful substances from gases produced during oil refining, and thus and purification of these gases, are critical issues. In the catalytic cracking purification system, where hydrogen-containing gas circulates, the presence of hydrogen sulfide in the gas fractionation unit poses a challenge. Additionally, corrosion of equipment and pipelines during transportation causes environmental pollution. The presence of hydrogen sulfide and carbon dioxide in the gas complicates processing process, making their removal from the gas composition essential. To achieve this, methods such as chemical absorption, physical absorption, combined absorption, oxidation, and absorption by solid absorbents are employed. The use of amines is one of the important indicators of wastewater treatment plants. The presence of a certain amount of H2S in the hydrogen-containing gas circulating in the hydrotreating unit reduces catalyst activity in reactors and leads to equipment failure. In a catalytic cracking unit, harmful components are absorbed by absorbents. Technological calculations of the indicators and modes of the main apparatuses of the absorption and desorption processes were carried out, with the results presented in tables. These calculations focus on column-type devices, separators, heat exchangers, and coolers, enabling the purification of gas contents using cold absorption and desorption processes. The use of a 15% aqueous solution of monoethanolamine proved most effective for hydrogen sulfide separation. The operating modes of the blocks in which these processes are carried out have been studied. The study also examines the transformation of sulfur compounds into paraffin, naphthenic and aromatic hydrocarbons, depending on the structure of the hydrocarbon chain, with hydrogen sulfide being released during hydrogenation under pressure. Improvements in the quality of dry gas transportation have significantly enhanced the efficiency of both transportation and processing.

During development of high sulfur-content natural gas fields, gaseous sulfur is likely to precipitate and deposit in the reservoir and transmission pipelines owing to changes in the temperature, pressure, and gas components. It is important to accurately predict the elemental sulfur solubility in hydrogen sulfide, carbon dioxide, and methane because these are the three main components of high-sulfur-content natural gas. The binary interaction coefficients between sulfur and hydrogen sulfide, carbon dioxide, and methane are the key parameters for predicting the sulfur solubility with a thermodynamic model. In this work, we show that the binary interaction coefficients are not constant, but temperature dependent. Three-parameter temperature-dependent equations for the binary interaction coefficients between sulfur and solvents are proposed. The corresponding regression equations for calculating the binary interaction coefficients between sulfur and hydrogen sulfide, carbon dioxide, and methane are obtained using experimental sulfur solubility data. The average relative errors of the sulfur solubility predicted using the experimental data in hydrogen sulfide, carbon dioxide, and methane using the thermodynamic model with the improved binary interaction coefficients are 6.30%, 1.69%, and 4.34%, and the average absolute relative errors are 7.90%, 13.12%, and 14.98%, respectively. Comparing the improved binary interaction coefficients with four other sets of reported values shows that the solubility values predicted by the thermodynamic model with improved binary interaction coefficients fit the experimental data better.

The effect of the loading rate and temperature on the damage of pipe steels in environments containing hydrogen sulfide and carbon dioxide is studied. The results of accelerated tests at slow deformation rate for the resistance of steels to stress corrosion cracking are analyzed. The deformation rate is justified for conducting reliable tests for stress corrosion cracking and temperature effect on pipe steels is revealed. The criteria for the tendency assessing of pipe steels to stress corrosion cracking in accelerated tests are the fracture stress or the ratio of stresses in corrosive environment and in air and the elongation or the ratio of elongations in corrosive environment and in air.

A new method of measuring hydrogen sulphide concentrations in gas streams, suitable for SAGD operations, is reported. The method is independent of the steam content up to 70 mole %, the composition, temperature and pressure of the gas, and has been tested and validated in the field. The method has a standard error of about 5%. By contrast, the stain tube (Draeger) measurements performed routinely on various gas streams at SAGD pilots are shown to be correct only within an order of magnitude of thereading by the new method. Factors between two to ten were common between stain tube readings and the corresponding truereadings taken immediately after or before the stain tube readings. The results have implications for plant safety procedures. It is suggested that certain plant streams be sampled only by operators wearing self-contained breathing apparatus; stain tube readings of the past have suggested this to be not necessary. There are further implications for understanding of partitioning of produced hydrogen sulphide in process streams. Introduction The production of hydrogen sulphide and carbon dioxide together with other minor gases in thermal recovery projects such as Steam Assisted Gravity Drainage is a common observation. The process giving rise to these gases is a high temperature hydrolysis of aliphatic sulphur linkages in the bitumen, dubbed " aquathermolysis" by Hyne et. al(1–3). For Athabasca, the amount of hydrogen sulphide typically produced per tonne of bitumen varies between 6 and 75 litres. Considerably more carbon dioxide is produced, usually in the range from 900 - 10,000 litres per tonne. It is shown elsewhere(4) that such production rates of hydrogen sulphide can easily give rise to H2S concentrations of about 20,000 ppm in the produced gases of a SAGD production project. Hydrogen sulphide measurement has usually been performed by means of stain tubes. The reason is that laboratory analysis of gas from a normal stainless steel gas cylinder will not give meaningful results. It has therefore been customary to measure the main gases from a cylinder in the laboratory, but to measure H2S concentrations in the field by means of stain tubes. This technique, while probably suitable for the natural gas industry, is problematic in SAGD work. It has been shown that hydrogen sulphide is highly soluble in steam condensate at temperatures of interest in SAGD(4). Moreover, the solubility goes through a minimum at approximately 180 °CDATA [C. As a produced gas line or facility with a significant steam pressure is being sampled, the quality of the steam must necessarily change in the sampling line and in the stain tube itself. Hydrogen sulphide will re-partition accordingly. It is improbable that hydrogen sulphide is quantitatively determined by the stain tube from both phases. Therefore it is doubtful whether strain tube measurements are reliable in this situation. Design of Sampling Train A sampling train suitable for the purpose at hand would ideally be easy to assemble from conventional sampling equipment, but would still be able to determine the composition of gas in terms of water vapour, hydrogen sulphide, and non-condensible gas content.

A new method of measuring hydrogen sulphide concentrations in gas streams, suitable for SAGD operations, is reported. The method is independent of the steam content up to 70 mole %, the composition, temperature and pressure of the gas, and has been tested and validated in the field. The method has a standard error of about 5%. By contrast, the stain tube (Draeger) measurements performed routinely on various gas streams at SAGD pilots are shown to be correct only within an order of magnitude of the reading by the new method. Factors between two to ten were common between stain tube readings and the corresponding true readings taken immediately after or before the stain tube readings. The results have implications for plant safety procedures. It is suggested that certain plant streams be sampled only by operators wearing self-contained breathing apparatus; stain tube readings of the past have suggested this to be not necessary. There are further implications for understanding of partitioning of produced hydrogen sulphide in process streams. Introduction The production of hydrogen sulphide and carbon dioxide together with other minor gases in thermal recovery projects such as Steam Assisted Gravity Drainage is a common observation. The process giving rise to these gases is a high temperature hydrolysis of aliphatic sulphur linkages in the bitumen, dubbed "aquathermolysis" by Hyne et. al.1,2,3 For Arthabasca, the amount of hydrogen sulphide typically produced per tonne of bitumen varies between 6 and 75 litres. Considerably more carbon dioxide is produced, usually in the range 900-10,000 litres per tonne. It is shown elsewhere4 that such production rates of hydrogen sulphide can easily give rise to H2S concentrations of about 20,000 ppm in the produced gases of a SAGD production project. Hydrogen sulphide measurement has been usually performed by means of stain tubes. The reason is that laboratory analysis of gas from a normal stainless steel gas cylinder will not give meaningful results. It has therefore been customary to measure the main gases from a cylinder in the laboratory, but to measure H2S concentrations in the field by means of stain tubes. This technique, while probably suitable for the natural gas industry, is problematic in SAGD work. In reference 4 it is shown that hydrogen sulphide is highly soluble in steam condensate at temperatures of interest in SAGD. Moreover, the solubility goes through a minimum at approximately 180 °C. As a produced gas line or facility with a significant steam pressure is being sampled, the quality of the steam must necessarily change in the sampling line and in the stain tube itself. Hydrogen sulphide will re-partition accordingly. It is improbable that hydrogen sulphide is quantitatively determined by the stain tube from both phases. Therefore it is doubtful whether stain tube measurements are reliable in this situation. DESIGN OF SAMPLING TRAIN A sampling train suitable for the purpose at hand would ideally be easy to assemble from conventional sampling equipment, but would still be able to determine the composition of gas in terms of both water vapour, hydrogen sulphide and non-condensible gas content.

BackgroundHydrogen sulphide is a gas signalling molecule which is produced endogenously from L-cysteine via the enzymes cystathionine beta-synthase (CBS) and cystathionine gamma-lyase (CSE). The possible role of hydrogen sulphide in reproduction has not yet been fully investigated. It has been previously demonstrated that hydrogen sulphide relaxes uterine smooth muscle in vitro. The aim of the present study was to investigate the endogenous production of hydrogen sulphide in rat and human intrauterine tissues in vitro.MethodsThe production of hydrogen sulphide in rat and human intrauterine tissues was measured in vitro using a standard technique. The expression of CBS and CSE was also investigated in rat and human intrauterine tissues via Western blotting. Furthermore, the effects of nitric oxide (NO) and low oxygen conditions on the production rates of hydrogen sulphide were investigated.ResultsThe order of hydrogen sulphide production rates (mean +/- SD, n = 4) for rat tissues were: liver (777 +/- 163 nM/min/g) > uterus (168 +/- 100 nM/min/g) > fetal membranes (22.3 +/- 15.0 nM/min/g) > placenta (11.1 +/- 4.7 nM/min/g), compared to human placenta (200 +/- 102 nM/min/g). NO significantly increased hydrogen sulphide production in rat fetal membranes (P < 0.05). Under low oxygen conditions the production of hydrogen sulphide was significantly elevated in human placenta, rat liver, uterus and fetal membranes (P < 0.05). Western blotting (n = 4) detected the expression of CBS and CSE in all rat intrauterine tissues, and in human placenta, myometrium, amnion and chorion.ConclusionRat and human intrauterine tissues produce hydrogen sulphide in vitro possibly via CBS and CSE enzymes. NO increased the production of hydrogen sulphide in rat fetal membranes. The augmentation of hydrogen sulphide production in human intrauterine tissues in a low oxygen environment could have a role in pathophysiology of pregnancy.

Natural gas of Tazhong-1 gas field contains 7.7% carbon dioxide and 2.31% hydrogen sulfide, and produced water salinity is up to 140000mg/L,the well-bore tube has seriously potential corrosion destructive with natural gas being exploited. Based on the corrosion type partition of down-hole tube for eighteen production wells of Tazhong-1 gas field, P110,P110S and P110SS corrosion behavior were investigated under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide/carbon dioxide, and corrosion inhibitors were chosen to meet need of anticorrosion of Tazhong-1 gas field. The results show that fifteen wells in eighteen production wells belong to hydrogen sulfide corrosion of both hydrogen sulfide and carbon dioxide influence. Other wells are singular carbon dioxide corrosion. The most severe corrosion of three types of down-hole tubes all occurs at 90°C in both corrosion media, and their corrosion resistance order is respectively P110&gt;P110S&gt;P110SS and P110S&gt;P110SS&gt;P110 under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide and carbon dioxide. The selected anti-temperature corrosion inhibitors (YU-1、YU-4) can control the corrosion rate of three types of down-hole tubular goods within 0.076mm/a in simulated formation water media with carbon dioxide (PCO2=0.08～4.64MPa) or hydrogen sulfide and carbon dioxide (PH2S/Pco2=1.3/4.64Mpa) while added amount of the inhibitor is 120～300mg/L or 200mg/L. All of these provide technical support for safe and fast development of Tazhong-1 gas field.