Thermochemical Sulfate Reduction Reaction Research Articles

On the fate of hydraulic fracturing fluid additives: Thermochemical sulfate reduction reaction of sodium dodecyl sulfate

Hydraulic fracturing is a key technology for unlocking shale gas resources. While the compatibility and performance of fracturing fluid additives have been investigated, little research has been made on the post-fracturing fate of these components. Recently, the chemical additives used in hydraulic fracturing fluid were shown to undergo thermochemical sulfate reduction (TSR) reactions, leading to the delayed appearance of hydrogen sulfide (H2S) during production from a shale gas reservoir. Sodium dodecyl sulfate (SDS), an anionic surfactant used as a friction reducer and emulsion inhibitor, was shown to contain all the required reducing and oxidizing ingredients to participate in a TSR reaction. In this study, we demonstrate that the TSR reaction of SDS is an aqueous phase process with little dependence on the gas over-pressure. Furthermore, we demonstrate that presence of native sulfide (represented by sulfide anions) in the reservoir acts as a catalyst and significantly increases the rate of the produced H2S. Formation of organosulfur compounds also has been observed when SDS solution contains initial low concentrations (<500ppm) of sulfide anion.

Petroleum alteration by thermochemical sulfate reduction – A comprehensive molecular study of aromatic hydrocarbons and polar compounds

Thermochemical sulfate reduction (TSR) alters petroleum composition as it proceeds towards the complete oxidation of hydrocarbons to CO2. The effects of TSR on the molecular and isotopic composition of volatile species are well known; however, the non-volatile higher molecular weight aromatic and polar species have not been well documented. To address this deficiency, a suite of onshore Gulf coast oils and condensates generated from and accumulating in Smackover carbonates was assembled to include samples that experienced varying levels of TSR alteration and in reservoir thermal cracking. The entire molecular composition of aromatic hydrocarbons and NSO species were characterized and semi-quantified using comprehensive GC×GC (FID and CSD) and APPI–FTICR-MS.The concentration of thiadiamondoids is a reliable indicator of the extent of TSR alteration. Once generated by TSR, thiadiamondoids remain thermally stable in all but the most extreme reservoir temperatures (>180°C). Hydrocarbon concentrations and distributions are influenced by thermal cracking and TSR. With increasing TSR alteration, oils become enriched in monoaromatic hydrocarbons and the distribution of high molecular weight aromatic hydrocarbons shifts towards more condensed species with a decrease in the number of alkyl carbons. Organosulfur compounds are created by the TSR process. In addition to the increase in benzothiophenes and dibenzothiophenes noted in previous studies, TSR generates condensed species containing one or more sulfur atoms that likely are composed of a single or multiple thiophenic cores. We hypothesize that these species are generated from the partial oxidation of PAHs and dealkylation reactions, followed by sulfur incorporation and condensation reactions. The organosulfur species remaining in the TSR altered oils are “proto-solid bitumen” moieties that upon further condensation, oxidation or sulfur incorporation result in highly sulfur enriched solid bitumen, which is chemically distinct from pyrobitumen formed by thermal cracking reactions.Although TSR involves the oxidation of hydrocarbons to CO2, prior studies of TSR-altered oils have not identified intermediate products. Using NESI–FTIRC-MS, the presence and distribution of oxygenated species become evident. All oils possess minor amounts of O2 and O4 species, presumable mono- and di-naphthenic acids originating from the source. As TSR progresses, the distribution of oxygenated species shifts towards increasing species with higher oxygen content, up to O8. Similar trends are observed for the SOx species. We hypothesize that these are partially oxidized condensed hydrocarbons and that these species are likely formed by the reaction proposed by Püttmann et al. (1989) for the oxidation of PAHs associated with Kupferschiefer mineralization, whereby hydrocarbons with aryl–aryl bonds incorporate sulfur to form thiophenic species.The rate of TSR is influenced by reservoir temperature and the presence of H2S. Typically, high reservoir temperatures (>140°C) are needed for extensive TSR alteration to occur. Oil from the Gin Creek Field appears to have received a charge of H2S, presumably from TSR alteration of a down dip reservoir, which has accelerated the TSR reaction within a relatively cold reservoir (∼109°C). This condition has allowed for the generation and preservation of abundant sulfur containing species that would be thermally cracked at higher temperatures.

Hydraulic Fracturing Additives and the Delayed Onset of Hydrogen Sulfide in Shale Gas

As natural gas production has shifted further from deep prolific gas reservoirs to shale gas, several questions are being addressed regarding fracturing technologies and the fate of chemical additives. A less investigated issue is the unexpected increase in produced hydrogen sulfide (H2S) from hot shale gas reservoirs. Understanding the source of H2S in shale reservoirs and managing low-levels of recovered elemental sulfur affects plans for future treatment, corrosion mitigation, and fracture fluid formulations. In this work we demonstrate that some typical ingredients of hydraulic fracturing fluids are not as kinetically stable as one might expect. Surfactants and biocides such as sodium dodecyl sulfate and glutaraldehyde are shown to undergo hydrolysis and thermochemical sulfate reduction reactions under moderate reservoir conditions, with H2S as the final product accompanied with long chain alcohols and hydrogen sulfate as long-lived intermediate species. This finding suggests that fracture fluid addit...

Compositional and stable carbon isotopic fractionation during non-autocatalytic thermochemical sulfate reduction by gaseous hydrocarbons

The possibility of autocatalysis during thermochemical sulfate reduction (TSR) by gaseous hydrocarbons was investigated by examination of previously reported laboratory and field data. This reaction was found to be a kinetically controlled non-autocatalytic process, and the apparent lack of autocatalysis is thought to be due to the absence of the required intermediate species. Kinetic parameters for chemical and carbon isotopic fractionations of gaseous hydrocarbons affected by TSR were calculated and found to be consistent with experimentally derived values for TSR involving long-chain hydrocarbons. Model predictions based on these kinetic values indicate that TSR by gaseous hydrocarbon requires high-temperature conditions. The oxidation of C2–5 hydrocarbons by sulfate reduction is accompanied by carbon isotopic fractionation with the residual C2–5 hydrocarbons becoming more enriched in 13C. Kinetic parameters were calculated for the stable carbon isotopic fractionation of gaseous hydrocarbons that have experienced TSR. Model predictions based on these kinetics indicate that it may be difficult to distinguish the effects of TSR from those of thermal maturation at lower levels of hydrocarbon oxidation; however, unusually heavy δ13C2+ values (>−10‰) can be diagnostic of high levels of conversion (>50%). Stoichiometric and stable carbon isotopic data show that methane is stable under the investigated reaction conditions and is likely a product of TSR by other gaseous hydrocarbons rather than a significant reactant. These results indicate that the overall TSR reaction mechanism for oxidation of organic substrates containing long-chain hydrocarbons involves three distinct phases as follows: (1) an initial slow and non-autocatalytic stage characterized by the reduction of reactive sulfate by long-chain saturated hydrocarbons; (2) a second autocatalytic reaction phase dominated by reactions involving reduced sulfur species and partially oxidized hydrocarbons; (3) and a final, or late-stage, TSR reaction in which hydrocarbon oxidation continues at a slower rate via the non-autocatalytic reduction of sulfate by gaseous hydrocarbons.

Disproportionation and thermochemical sulfate reduction reactions in S–H2O–CH4 and S–D2O–CH4 systems from 200 to 340 °C at elevated pressures

Elemental sulfur, as a transient intermediate compound, by-product, or catalyst, plays significant roles in thermochemical sulfate reduction (TSR) reactions. However, the mechanisms of the reactions in S–H2O–hydrocarbons systems are not clear. To improve our understanding of reaction mechanisms, we conducted a series of experiments between 200 and 340°C for S–H2O–CH4, S–D2O–CH4, and S–CH4–1m ZnBr2 systems in fused silica capillary capsules (FSCCs). After a heating period ranging from 24 to 2160h (hrs), the quenched samples were analyzed by Raman spectroscopy. Combined with the in situ Raman spectra collected at high temperatures and pressures in the S–H2O and S–H2O–CH4 systems, our results showed that (1) the disproportionation of sulfur in the S–H2O–CH4 system occurred at temperatures above 200°C and produced H2S, SO42−, and possibly trace amount of HSO4−; (2) sulfate (and bisulfate), in the presence of sulfur, can be reduced by methane between 250 and 340°C to produce CO2 and H2S, and these TSR temperatures are much closer to those of the natural system (<200°C) than those of any previous experiments; (3) the disproportionation and TSR reactions in the S–H2O–CH4 system may take place simultaneously, with TSR being favored at higher temperatures; and (4) in the system S–D2O–CH4, both TSR and the competitive disproportionation reactions occurred simultaneously at temperatures above 300°C, but these reactions were very slow at lower temperatures. Our observation of methane reaction at 250°C in a laboratory time scale suggests that, in a geologic time scale, methane may be destroyed by TSR reactions at temperatures >200°C that can be reached by deep drilling for hydrocarbon resources.

Kinetics of uncatalyzed thermochemical sulfate reduction by sulfur-free paraffin

To determine kinetic parameters of sulfate reduction by hydrocarbons (HC) without the initial presence of low valence sulfur, we carried out a series of isothermal gold-tube hydrous-pyrolysis experiments at 320, 340, and 360°C under a constant confined pressure of 24.1MPa. The reactants used consisted of saturated HC (sulfur-free) and CaSO4 in an aqueous solution buffered to three different pH conditions without the addition of elemental sulfur (S8) or H2S as initiators. H2S produced in the course of reaction was proportional to the extent of the reduction of CaSO4 that was initially the only sulfur-containing reactant. Our results show that the in situ pH of the aqueous solution (herein, in situ pH refers to the calculated pH value of the aqueous solution at certain experimental conditions) can significantly affect the rate of the thermochemical sulfate reduction (TSR) reaction. A substantial increase in the TSR reaction rate was observed with a decrease in the in situ pH.Our experimental results show that uncatalyzed TSR is a first-order reaction. The temperature dependence of experimentally measured H2S yields from sulfate reduction was fit with the Arrhenius equation. The determined activation energy for HC (sulfur-free) reacting with HSO4- in our experiments is 246.6kJ/mol at pH values ranging from 3.0 to 3.5, which is slightly higher than the theoretical value of 227.0kJ/mol using ab initio quantum chemical calculations on a similar reaction. Although the availability of reactive sulfate significantly affects the rate of reaction, a consistent rate constant was determined by accounting for the HSO4− ion concentration. Our experimental and theoretical approach to the determination of the kinetics of TSR is further validated by a reevaluation of several published experimental TSR datasets without the initial presence of native sulfur or H2S. When the effect of reactive sulfate concentration is appropriately accounted for, the published experimental TSR data yield kinetic parameters that are consistent with our values. Assuming MgSO4 contact-ion-pair ([MgSO4]CIP) as the reactive form of sulfate in petroleum reservoir formation waters, a simple extrapolation of our experimentally derived HSO4− reduction kinetics as a proxy for [MgSO4]CIP to geologically reasonable conditions predicts onset temperatures (130–140°C) that are comparable to those observed in nature.

H2S—Origin in South Pars gas field from Persian Gulf, Iran

Hydrogen sulfide (H2S) is found in low concentration (less than 1%) as the undesirable component in Permo-Triassic evaporite/carbonate successions of the South Pars gas field, the largest gas accumulation in the world. Different isotopic analyses have been carried out on gas samples; gas condensates, and solid sulfate together with petrography to assess the origin of H2S. Anhydrite δ34S changed from about +10.1 to about +29.3‰ from the Permian to the Triassic, respectively, confirming the Phanerozoic sulfur curve and showing that diagenesis has generally not destroyed the initial sulfur isotope stratigraphy of anhydrite. The H2S δ34S is −5‰ in average in all the reservoir units.Reservoir is presently buried to depths ranging from 2600 to 3500m, representing present-day temperatures from 85 to 105°C (185 to 221°F). Hence, bacterial sulfate reduction (BSR) is the unlikely source because reservoir temperature is high for bacteria to be survived and H2S isotope signature does not show an effect of isotopic fractionation by bacteria.For the South Pars gases, Silurian's hot shale of the Sarchahan Formation is postulated as major source rock. Biomarker analysis of the gas condensate indicates the suboxic to oxic depositional environment for the source rock has been dominated that couldn't have noticeable organic sulfur. Long migration pass way of the gas and activity of the H2S and reaction with the carrier rocks cannot allow highly the contribution of the H2S to the gas reservoir by thermal decomposition of the organic matter. Moreover, the isotopic analyses deny the thermal decomposition of the organic matter for the H2S in the South Pars gas field.However, in the South Pars field, δ34S hydrogen sulfide is equal to −5‰, which is 15‰ lower than Permian solid sulfate (+10‰) and can be resulted by thermochemical sulfate reduction (TSR) of the Permian anhydrite at relevant temperature regime (100°C) during a long period of the geological time. The low concentration of the H2S can be indicated by the starting phase of TSR reactions.

Yields of H 2S and gaseous hydrocarbons in gold tube experiments simulating thermochemical sulfate reduction reactions between MgSO 4 and petroleum fractions

The aim of this work was to assess the ability of four representative fractions (saturated, aromatic, polar and asphaltene) of crude oils to participate in thermochemical sulfate reduction (TSR) and thus to evaluate their pyrolysis behaviors, which is of great relevance to the stability of reservoir hydrocarbons. Experiments simulating reactions between oil fractions and magnesium sulfates (anhydrous MgSO 4 and hydrated MgSO 4·7H 2O) at a constant temperature of 420 °C and under a pressure of 50 MPa were conducted over a period of 24 h using a gold tube confined system. The yields of non-hydrocarbon and hydrocarbon gases and their δ 13C values were measured and compared in order to reveal the main control factors on TSR under practical geological conditions. In pure blank pyrolysis experiments with oil fractions cracking without TSR, different pyrolysis rates were seen for the four petroleum fractions with a sequence of saturated > asphaltene > polar ≫ aromatic. Minimal yields of C 1–C 5 hydrocarbons in the aromatic fraction can mainly be attributed to the greater thermal stability of aromatic compounds, which was also reflected by their positive δ 13C signatures. Upon addition of anhydrous MgSO 4 to the saturated fraction, a small quantity of H 2S was generated, indicating that only a weak TSR occurred in this series. Upon addition of hydrated MgSO 4·7H 2O to the four petroleum fractions, high yields of H 2S were generated, indicating that water plays an important role in the occurrence of TSR. The presence of nitrogen and/or oxygen containing heteroatomic compounds in the polar fraction decreases the yields of H 2S when subjected to MgSO 4 TSR. Similar yields of H 2S from the saturated, aromatic and asphaltene fractions revealed that TSR occurring in the aromatic fractions is unlikely to be associated with the opening of benzene rings but closely related to availability of hydrogen atom in the alkyl moiety. The addition of MgSO 4·7H 2O, TSR can significantly enhance the yield of methane, also reflected in an increase in its δ 13C value. Besides methane, the other gaseous hydrocarbons (C 2, C 3) in the MgSO 4·7H 2O series also showed some less negative δ 13C values relative to the blank series, irrespective of the fraction type. Relative to the other fractions (saturated, polar and asphaltene), low yields of C 1–C 5 gaseous hydrocarbons derived from the aromatic fraction could be attributed to the greater stability of the benzene ring and indicate that paraffinic oils may be more susceptible to thermal or thermochemical alterations than aromatic oils under the conditions of real subsurface reservoirs.

Distribution and treatment of harmful gas from heavy oil production in the Liaohe Oilfield, Northeast China

The distribution and treatment of harmful gas (H2S) in the Liaohe Oilfield, Northeast China, were investigated in this study. It was found that abundant toxic gas (H2S) is generated in thermal recovery of heavy oil. The H2S gas is mainly formed during thermochemical sulfate reduction (TSR) occurring in oil reservoirs or the thermal decomposition of sulfocompounds (TDS) in crude oil. H2S generation is controlled by thermal recovery time, temperature and the injected chemical compounds. The quantity of SO42− in the injected compounds is the most influencing factor for the rate of TSR reaction. Therefore, for prevention of H2S formation, periodic and effective monitoring should be undertaken and adequate H2S absorbent should also be provided during thermal recovery of heavy oil. The result suggests that great efforts should be made to reduce the SO42− source in heavy oil recovery, so as to restrain H2S generation in reservoirs. In situ burning or desulfurizer adsorption are suggested to reduce H2S levels. Prediction and prevention of H2S are important in heavy oil production. This will minimize environmental and human health risks, as well as equipment corrosion.

Induced H2S formation during steam injection recovery process of heavy oil from the Liaohe Basin, NE China

H2S is generally very low in fresh water lacustrine origin oil and gas deposits, while unusual high amounts of H2S in thermal recovery pilot areas may be formed in situ during steam injection process. Present paper shows such kind of case study from the Liaohe Basin, NE China, where abundant heavy oil accumulated in the Eogene sandstone reservoirs with burial depth shallower than 1000 m. Qi 40 Block is one of pilot areas where steam injection was applied for heavy oil recovery. Almost no H2S can be detected in initial gas production, while up to 3% of H2S occurs in associated gas after thermal recovery. We proposed that most of H2S were derived from the TSR (thermochemical sulfate reduction) during thermal recovery, even though minor amount of H2S from thermal decomposition of organosulfur compound (TDS) within oil cannot be ruled out. Heavy oils in the Liaohe Basin contain very low amount of sulfur (generally < 0.3%), which cannot generate decent amount of H2S during thermal decomposition of heavy oil. However, the formation water in Eogene Shahejie Formation is rich in sulfate ions (SO42−), which can provide reactant for TSR reaction triggered by thermal stress from injected steam. Geochemical data including sulfur isotope of H2S, oil, sulfate, and natural gas, support the conclusion that the abundant H2S from the steam drive pilots of the Liaohe Basin are mainly originated from TSR effect under high temperature during the thermal recovery process. The observed δ34S variations lend support to the conclusion that in situ thermochemical sulfate reduction can occur during thermal recovery process. The intensity of TSR and amount of H2S occurring in pilot areas is controlled by methods of steam injection, temperature and times of treatment.

Chemical and petrographic evidence for thermal cracking and thermochemical sulfate reduction of paleo-oil accumulations in the NE Sichuan Basin, China

Significant extents of heterogeneity are observed in the optical properties, reflectance values and S/C atomic ratio values of solid bitumens in the carbonate reservoirs of the Lower Triassic Feixianguan and Changxing formations in the Puguang gas field, the largest in marine carbonates in China. The chemical and stable carbon isotope compositions of the gaseous alkanes in the produced gases also depend on field location, with no clear correlation with the hydrogen sulfate content. These data indicate that the gas reservoirs are highly compartmentalized. This manuscript describes an integrated chemical and petrographic approach for distinguishing solid bitumens formed by thermal cracking and by thermochemical sulfate reduction (TSR). The fact that most reservoir bitumens have only been partially affected by TSR suggests that sulfate supply appears to be a major limiting factor for the TSR reactions involving gaseous alkanes.

THE MIXING HYPOTHESIS AND THE ORIGIN OF MISSISSIPPI VALLEY-TYPE ORE DEPOSITS

Anderson (1991) proposed that methane generated from the heating of kerogen in the wall rocks of Mississippi Valley-type (MVT) deposits diffuses into the ore zone, reducing sulfate and precipitating the ore minerals. This hypothesis has been tested by calculating the diffusion of methane from wall rock into a flowing solution at 150°C. Methane pressures in the ore zone quickly reach a steady state which depends on the assumed methane pressure in the wall rock and the flow velocity. Calculated methane pressures in the ore solution are not sufficient to generate a gas phase, but other dissolved gases such as CO 2 may contribute sufficiently to make this happen. Sulfate reduction and sulfide precipitation will occur whether or not a gas phase forms, but many MVT ores have a tabular form or are located in the upper part of breccias, suggesting that there was a gas phase control. Recent experimental results (Chou and Burruss, 2007) offer an explanation for the fact that very light carbon isotopes are not commonly found in MVT deposits. The main obstacles to further development of these ideas is our lack of understanding of the thermochemical sulfate reduction reaction and the fact that little attention has been paid to possible sources of methane in the vicinity of ore deposits.

Experimental investigation on thermochemical sulfate reduction by H 2S initiation

Hydrogen sulfide (H 2S) is known to catalyze thermochemical sulfate reduction (TSR) by hydrocarbons (HC), but the reaction mechanism remains unclear. To understand the mechanism of this catalytic reaction, a series of isothermal gold-tube hydrous pyrolysis experiments were conducted at 330 °C for 24 h under a constant confining pressure of 24.1 MPa. The reactants used were saturated HC (sulfur-free) and CaSO 4 in the presence of variable H 2S partial pressures at three different pH conditions. The experimental results showed that the in- situ pH of the aqueous solution (herein, in- situ pH refers to the calculated pH of aqueous solution under the experimental conditions) can significantly affect the rate of the TSR reaction. A substantial increase in the TSR reaction rate was recorded with a decrease in the in- situ pH value of the aqueous solution involved. A positive correlation between the rate of TSR and the initial partial pressure of H 2S occurred under acidic conditions (at pH ∼3–3.5). However, sulfate reduction at pH ∼5.0 was undetectable even at high initial H 2S concentrations. To investigate whether the reaction of H 2S (aq) and HSO 4 - occurs at pH ∼3, an additional series of isothermal hydrous pyrolysis experiments was conducted with CaSO 4 and variable H 2S partial pressures in the absence of HC at the same experimental temperature and pressure conditions. CaSO 4 reduction was not measurable in the absence of paraffin even with high H 2S pressure and acidic conditions. These experimental observations indicate that the formation of organosulfur intermediates from H 2S reacting with hydrocarbons may play a significant role in sulfate reduction under our experimental conditions rather than the formation of elemental sulfur from H 2S reacting with sulfate as has been suggested previously (Toland W. G. (1960) Oxidation of organic compounds with aqueous sulphate. J. Am. Chem. Soc. 82, 1911–1916). Quantification of labile organosulfur compounds (LSC), such as thiols and sulfides, was performed on the products of the reaction of H 2S and HC from a series of gold-tube non-isothermal hydrous pyrolysis experiments conducted at about pH 3 from 300 to 370 °C and a 0.1-°C/h heating rate. Incorporation of sulfur into HC resulted in an appreciable amount of thiol and sulfide formation. The rate of LSC formation positively correlated with the initial H 2S pressure. Thus, we propose that the LSC produced from H 2S reaction with HC are most likely the reactive intermediates for H 2S initiation of sulfate reduction. We further propose a three-step reaction scheme of sulfate reduction by HC under reservoir conditions, and discuss the geological implications of our experimental findings with regard to the effect of formation water and oil chemistry, in particular LSC content.

Geochemical signatures of thermochemical sulfate reduction in controlled hydrous pyrolysis experiments

A series of gold tube hydrous pyrolysis experiments was conducted in order to investigate the effect of thermochemical sulfate reduction (TSR) on gas generation, residual saturated hydrocarbon compositional alteration, and solid pyrobitumen formation. The intensity of TSR significantly depends on the H 2O/MgSO 4 mole ratio, the smaller the ratio, the stronger the oxidizing conditions. Under highly oxidizing conditions (MgSO 4/hydrocarbon wt/wt 20/1 and hydrocarbon/H 2O wt/wt 1/1), large amounts of H 2S and CO 2 are generated indicating that hydrocarbon oxidation coupled with sulfate reduction is the dominant reaction. Starting with a mixture of C 21–C 35 n-alkanes, these hydrocarbons are consumed totally at temperatures below the onset of hydrocarbon thermal cracking in the absence of TSR (400 °C). Moreover, once the longer chain length hydrocarbons are oxidized, secondarily formed hydrocarbons, even methane, are oxidized to CO 2. Using whole crude oils as the starting reactants, the TSR reaction dramatically lowers the stability of hydrocarbons leading to increases in gas dryness and gas/oil ratio. While their concentrations decrease, the relative distributions of n-alkanes do not change appreciably from the original composition, and consequently, are non-diagnostic for TSR. However, distinct molecular changes related to TSR are observed, Pr/ n-C 17 and Ph/ n-C 18 ratios decrease at a faster rate under TSR compared to thermal chemical alteration (TCA) alone. TSR promotes aromatization and the incorporation of sulfur and oxygen into hydrocarbons leading to a decrease in the saturate to aromatic ratio in the residual oil and in the generation of sulfur and oxygen rich pyrobitumen. These experimental findings could provide useful geochemical signatures to identify TSR in settings where TSR has occurred in natural systems.

Effect of hydrocarbon type on thermochemical sulfate reduction

Thermochemical sulfate reduction (TSR) of model compounds and whole crude oils was investigated to determine the influence of hydrocarbon type on the reaction. A series of isothermal gold-tube hydrous pyrolysis experiments under a constant confining pressure of 24.1 MPa (3500 psi) was conducted where individual organic compounds containing different functional groups (sulfur free) were reacted in the presence of MgSO 4 and the amounts of generated hydrogen sulfide were measured. As MgSO 4 is the only sulfur source initially present in these experiments, any hydrogen sulfide formed must arise from TSR. The model compound experiments show that the type of hydrocarbon involved can significantly affect the extent of TSR reaction, and the difference in hydrocarbon reactivity involved in sulfate reduction mainly depends on the type of functional group present. For the model compounds studied, the relative reactivity during TSR is 1-octene > 1-octanol > 1-octanone > n-octane > octanoic acid > octylbenzene > xylene. An additional series of non-isothermal hydrous pyrolysis experiments, heated from 340 °C to 550 °C at 2 °C/h, were conducted involving MgSO 4 and three different crude oils with variable total sulfur contents ranging from 0.5% to 5.2% and with a sulfur-free paraffinic mixture. Comparison of H 2S generation as a function of temperature from these experiments suggests that crude oil composition can dramatically affect the onset temperature of TSR. Although the model compound experiments clearly demonstrate the variable reactivity of different hydrocarbon types during TSR reactions, the observed trends for sulfate reduction during the whole oil experiments indicate that the labile sulfur content in oil may be more significant in controlling TSR reaction rates than the hydrocarbon chemistry. The absence of intermediate reduced sulfur species (e.g., elemental sulfur, sulfites, etc.) in the solid residuals after TSR does not preclude the possibility that generated H 2S reacts with sulfate as these reactive sulfur species will rapidly react with the hydrocarbons.

Isotopic evidence of TSR origin for natural gas bearing high H2S contents within the Feixianguan Formation of the northeastern Sichuan Basin, southwestern China

The northeastern area of Sichuan Basin, southwestern China, is the area with the maximal reserve of natural gas containing higher hydrogen sulphide (H2S) that has been found among the petroliferous basins of China, with the proven and controlled gas reserve of more than 200 billion cubic meters. These gas pools, with higher H2S contents averaging 9%, some 17%, are mainly distributed on structural belts of Dukouhe, Tieshanpo, Luojiazhai, Puguang, etc., while the oolitic-shoal dolomite of the Triassic Feixianguan Fm. (T1f) is the reservoir. Although many scholars regard the plentiful accumulation of H2S within the deep carbonate reservoir as the re- sult of Thermochemical Sulfate Reduction (TSR), however, the process of TSR as well as its residual geological and geochemical evidence is still not quite clear. Based on the carbon iso- topic analysis of carbonate strata and secondary calcite, etc., together with the analysis of sulfur isotopes within H2S, sulphur, gypsum, iron pyrites, etc., as well as other aspects including the natural gas composition, carbon isotopes of hydrocarbons reservoir petrology, etc., it has been proved that the above natural gas is a product of TSR. The H2S, sulphur and calcite result from the participation of TSR reactions by hydrocarbon gas. During the process for hydrocarbons be- ing consumed due to TSR, the carbons within the hydrocarbon gas participate in the reactions and finally are transferred into the secondary calcite, and become the carbon source of secon- dary calcite, consequently causing the carbon isotopes of the secondary calcite to be lower (−18.2‰). As for both the intermediate product of TSR, i.e. sulfur, and its final products, i.e. H2S and iron pyrites, their sulfur elements are all sourced from the sulfate within the Feixianguan Fm. During the fractional processes of sulfur isotopes, the bond energy leads to the 32 S being re- leased firstly, and the earlier it is released, the lower δ 34 S values for the generated sulphide (H2S) or sulfur will be. However, for the anhydrite that participates in reactions, the higher the reaction degree, the more 32 S is released, while the less 32 S remains and the more δ 34 S is increased. The testing results have proved the process of the dynamic fractionation of sulfur isotopes.

Sulfur redox reactions and formation of native sulfur veins during low grade metamorphism of gypsum evaporites, Cameros Basin (NE Spain)

Vein deposits containing native sulfur, gypsum, quartz and rare sphalerite are described from Cervera del Rio Alhama, in the very low-grade metasediments of the Mesozoic Cameros Basin of NE Spain. The veins are hosted by lacustrine evaporites which comprise alternations of dolomite and gypsum (anhydrite during metamorphism) layers. Fluid inclusion homogenization temperatures and quartz–sulfate oxygen isotope geothermometry indicate formation of the veins at ≈225°C. Fluid inclusions contain S° along with a gas phase comprising H 2S, N 2, CO 2 and minor CH 4. These are all likely reactants and products of S° generation by thermochemical sulfate reduction (TSR) by organic matter, followed by partial re-oxidation of some H 2S by SO 4 2− to produce S°. TSR-type reactions during low grade metamorphism are thus concluded to be the origin of the S° veins. The TSR reactions we described differ from those observed in most petroleum-related sour gas settings. Firstly, there is no evidence for secondary carbonate precipitation. Secondly, significant S isotopic fractionations exist between sulfate (around +20‰) and reduced products (S° is around −11‰). This is attributed to relatively increased rates of isotopic equilibration compared to TSR that may be related to low availability of organic matter during the formation.

The Influence of Rock Fabric and Mineralogy on Thermochemical Sulfate Reduction: Khuff Formation, Abu Dhabi

ABSTRACT Thermochemical sulfate reduction (TSR) is the reaction between anhydrite and petroleum fluids at elevated temperatures to produce H2S and calcite. In this study of the dolomite-hosted hydrocarbon gas reservoirs in the Permo-Triassic Khuff Formation, Abu Dhabi, a geochemically well constrained rock-gas system, we demonstrate for the first time a clear influence of rock texture and mineralogy on the rate and extent of TSR reactions and thus on H2S concentration in the gas phase. The controls on the rate on H2S accumulation were: TSR reaction kinetics. TSR became significant as temperature exceeded 140°C, a critical threshold temperature for chemical reaction between aqueous sulfate and aqueous methane. Anhydrite dissolution rate. Once initiated, the subsequent reaction rate was controlled by the rate of supply of aqueous sulfate to the reaction site. Sulfate limitation is indicated by the lack of fractionation of sulfur isotopes between sulfate and sulfide (i.e., suggesting total reaction for each unit of sulfate that dissolves). Also, finely crystalline anhydrite began reacting at a lower temperature than coarse crystalline anhydrite (likely a result of relative surface area), suggesting that anhydrite dissolution was the rate-limiting step. Transport rates are unlikely to have been rate-limiting at the earliest stage of reaction because anhydrite was replaced in situ by calcite on the very edges of anhydrite nodules and crystals. Transport rate. Later, as TSR proceeded, it became transport controlled, as calcite, growing on the surface of anhydrite crystals, began to isolate them from dissolved methane. TSR ceased once calcite had effectively armor-plated (totally isolated) the remaining anhydrite. Finely crystalline anhydrite underwent more extensive and more rapid TSR than coarser anhydrite crystals because these had a greater ratio of surface area to volume, allowing more and faster dissolution and requiring more calcite to isolate them from methane. Localized loss of H2S occurred in the reservoir by reaction with indigenous Fe-bearing clays. Consequently, reservoirs with a relatively high siliciclastic content have less H2S than would be expected from the advanced state of anhydrite replacement by calcite. In order to predict TSR-related H2S concentration in hydrocarbon gases it is thus important to understand the diagenetic and textural characteristics of the reservoir as well as the thermal and petroleum-emplacement history.

The genesis of Colombian emeralds: a restatement

A renewal of metallogenetical studies of Colombian emerald deposits produced new geological and geochemical data that favour a hydrothermal-sedimentary genetic model for these deposits. A comprehensive model is presented which integrates both chemical and structural aspects and invalidates some aspects of the model recently presented by Ottaway et al. The deposits result from a two-stage process in which shortening tectonics affect the two borders of the Eastern Cordillera of Colombia and provoke decollement planes, thrusting, and thrust-fault related folds in the Early Cretaceous black shale series. Three major descriptive and interpretative aspects of the deposits are presented: (1) time relationships between the two different sets of barren and mineralized extensional veins; (2) the association of graphite and emerald mineralization, and (3) the thermochemical sulfate reduction reaction acting at the site of the emerald deposits to reduce sulfate of evaporitic origin from the hydrothermal brines into hydrogen sulfide by interaction with organic-rich strata.

Thermochemical sulfate reduction a review

The high concentrations of hydrogen sulfide found in many oil and gas fields is thought to arise from the oxidation of petroleum hydrocarbons by sulfate—a reaction that reduces the value of the resource. This review, undertaken in order to better understand the geochemistry of TSR reaction in oil field sediments, covers the relevant information on thermochemical sulfate reduction (TSR) to 1991. The theoretical and experimental aspects of TSR reactions (including sulfur and carbon isotope studies) are reviewed and their significance to the geochemical system discussed. The present review agrees with previous suggestions that biochemical reduction of sulfate dominates in sedimentary environments below 120°C, and supports the possibility that reactive sulfur species will oxidize certain organic molecules at meaningful rates in geochemically reasonable reaction periods at temperatures above 175°C. We conclude that under typical petroleum reservoir reaction conditions, both elemental sulfur and polysulfides are capable of oxidizing some organic molecules under basic conditions. But that sulfate alone will not react unless lower oxidation state sulfur is present. The possible interaction of low-valence-state sulfur with sulfate to form TSR active oxidants is examined. both H2S and SO 4 2− are required for the formation of active polysufide reductants (e.g. thiosulfate or polythionates) in TSR systems. Such intermediates can serve to lower the overall activation energy of the oxidation of hydrocarbons by sulfate via thermal generation of sulfur radicals that can function as TSR active oxidants in many oil field sediments. We suggest that some proposed chemical mechanisms for TSR need to be experimentally verified and the results re-interpreted with respect to TSR relations in geologic systems.