Experimental investigation on thermochemical sulfate reduction in the presence of 1-pentanethiol at 200 and 250 °C: Implications for in situ TSR processes occurring in some MVT deposits

Organic sulfur compounds are ubiquitous in natural oil and gas fields and moderate-low temperature sulfide ore deposits. Previous studies have shown that organic sulfur compounds are important in enhancing the rates of thermochemical sulfate reduction (TSR) reactions, but the details of these reaction mechanisms remain unclear. In order to assess the extent of sulfate reduction in the presence of labile sulfur species at temperature conditions near to those where TSR occurs in nature, we conducted a series of experiments using the fused silica capillary capsule (FCSS) method. The tested systems containing labile sulfur species are MgSO₄ + 1-pentanethiol (C₅H₁₁SH) + 1-octene (C₈H₁₆), MgSO₄ + 1-octene (C₈H₁₆), MgSO₄ + 1-pentanethiol (C₅H₁₁SH), 1-pentanethiol (C₅H₁₁SH)+H₂O, and MgSO₄ + 1-pentanethiol (C₅H₁₁SH) + ZnBr₂ systems. Our results show that: (1) intermediate oxidized carbon species (ethanol and acetic acid) are formed during TSR simulation experiments when 1-pentanethiol is present; (2) in the presence of ZnBr₂, 1-pentanethiol can be oxidized by sulfate to CO₂ at 200 °C, which is within the temperature range observed in natural TSR; and (3) the precipitation of sulfide minerals may significantly promote the rate of TSR, indicating that the rates of in situ TSR reactions in ore deposits could be much faster than previously thought. This may be important for understanding the possibility of in situ TSR as a mechanism for the precipitation of metal sulfides in some ore deposits. These findings provide important experimental evidence for understanding the role of organic sulfur compounds in TSR reactions and the pathway of TSR reactions initiated by organic sulfur compounds under natural conditions.     

Experimental investigation on thermochemical sulfate reduction by H2S initiation

Hydrogen sulfide (H₂S) 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 CaSO₄ in the presence of variable H₂S 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 H₂S occurred under acidic conditions (at pH ∼3-3.5). However, sulfate reduction at pH ∼5.0 was undetectable even at high initial H₂S concentrations. To investigate whether the reaction of H₂S_(aq) and occurs at pH ∼3, an additional series of isothermal hydrous pyrolysis experiments was conducted with CaSO₄ and variable H₂S partial pressures in the absence of HC at the same experimental temperature and pressure conditions. CaSO₄ reduction was not measurable in the absence of paraffin even with high H₂S pressure and acidic conditions. These experimental observations indicate that the formation of organosulfur intermediates from H₂S reacting with hydrocarbons may play a significant role in sulfate reduction under our experimental conditions rather than the formation of elemental sulfur from H₂S 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 H₂S 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 H₂S pressure. Thus, we propose that the LSC produced from H₂S reaction with HC are most likely the reactive intermediates for H₂S 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.     

Characterization of solid bitumens originating from thermal chemical alteration and thermochemical sulfate reduction

Solid bitumen can arise from several reservoir processes acting on migrated petroleum. Insoluble solid organic residues can form by oxidative processes associated with thermochemical sulfate reduction (TSR) as well as by thermal chemical alteration (TCA) of petroleum. TCA may follow non-thermal processes, such as biodegradation and asphaltene precipitation, that produce viscous fluids enriched in polar compounds that are then altered into solid bitumens. It is difficult to distinguish solid bitumen formed by TCA from TSR since both processes occur under relatively high temperatures. The focus of the present work is to characterize solid bitumen samples associated with TSR- or TCA-processes using a combination of solid-state X-ray Photoelectron Spectroscopy (XPS), Sulfur X-ray Absorption Near Edge Structure Spectroscopy (S-XANES), and ¹³C NMR. Naturally occurring solid bitumens from three locations, Nisku Formation, Brazeau River area (TSR-related); La Barge Field, Madison Formation (TSR-related); and, the Alaskan North Slope, Brooks Range (TCA-related), are compared to solid bitumens generated in laboratory simulations of TSR and TCA.The chemical nature of solid bitumens with respect to organic nitrogen and sulfur can be understood in terms of (1) the nature of hydrocarbon precursor molecules, (2) the mode of sulfur incorporation, and (3) their concentration during thermal stress. TSR-solid bitumen is highly aromatic, sulfur-rich, and nitrogen-poor. These heteroatom distributions are attributed to the ability of TSR to incorporate copious amounts of inorganic sulfur (S/C atomic ratio >0.035) into aromatic structures and to initial low levels of nitrogen in the unaltered petroleum. In contrast, TCA-solid bitumen is derived from polar materials that are initially rich in sulfur and nitrogen. Aromaticity and nitrogen increase as thermal stress cleaves aliphatic moieties and condensation reactions take place. TCA-bitumens from the Brooks Range have <75% aromatic carbon. TCA-bitumens exposed to greater thermal stress can have a higher aromaticity, like that observed in TSR-bitumens. Organic sulfur in TCA-organic solids remains relatively constant with increasing maturation (S/C atomic ratio <0.035) due to offsetting preservation and H₂S elimination reactions. Although S-XANES and ¹³C NMR provide information needed to understand changes in structure and reactivity that occur in the formation of petroleum solids, in some cases XPS analysis is sufficient to determine whether a solid bitumen is formed by TCA or TSR.     

Origin of the unusually high dibenzothiophene oils in Tazhong-4 Oilfield of Tarim Basin and its implication in deep petroleum exploration

Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S₁ species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H₂S in the gases associated with the oils. Obviously low concentrations of the DBE = 9 S₁ species (mainly equivalent to C₀–C₃₅ DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE = 9 S₁ species with only small amounts of sulfur compounds with low thermal stability (DBE = 0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ¹³C₂H₆–δ¹³C₄H₁₀ was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area.     

硫酸盐热化学还原作用的启动机制研究

硫酸盐热化学还原作用(TSR)是导致高含硫化氢天然气生成和聚集、碳酸岩盐储层酸化和溶蚀的重要因素,是地质盆地内烃-水-岩三者之间的复杂反应。本文利用黄金管热模拟实验,对TSR反应的可能启动机制及控制因素进行了研究。通过不同盐溶液与原油的热解实验,证实了硫酸盐的存在是启动TSR反应的必要因素,MgSO4比CaSO4和Na2SO4更容易启动TSR反应,体系中盐度的增加会加速H2S的生成。实验结果表明,不同水介质条件下,TSR反应的程度与溶液的离子强度呈正相关,弱酸性环境并不足以启动TSR反应;原油中不稳定含硫化合物的含量越高越有利于TSR反应的发生,饱和链烷烃比原油中其它组分更容易引发TSR反应,且大分子烷烃比小分子烷烃更容易被硫酸盐氧化。     

Proto-solid bitumen in petroleum altered by thermochemical sulfate reduction

Thermochemical sulfate reduction (TSR) involves a complex series of redox reactions whereby petroleum is oxidized by sulfate forming H₂S and CO_2. A highly aromatic, sulfur rich carbonaceous residue, which we define as TSR-solid bitumen, is commonly seen in reservoir rocks where TSR has occurred. Using atmospheric pressure photoionization (APPI) Fourier transform ion cyclotron resonance (FTICR) mass spectrometry, we find that TSR altered oils and condensates contain highly condensed polynuclear aromatic and naphthenoaromatic species with 0–3 S atoms. These chemical species are not present in petroleum fluids of equivalent maturity that have not experienced TSR and must have been formed by the TSR process. We call these species proto-solid bitumen as they represent the type of organic compounds that could easily precipitate from the TSR altered oils with slight chemical alteration or changes in reservoir conditions.     

硫酸盐热化学还原作用对原油裂解成气和碳酸盐岩储层改造的影响及作用机制

硫酸盐热化学还原作用(Thermochemical sulfate reduction, TSR)是发生在油气藏中复杂的有机-无机相互作用,它不仅会引起含H₂S天然气的富集,其产生的酸性气体对碳酸盐岩储层还具有明显的溶蚀改造作用。本文基于黄金管热模拟实验,研究了TSR反应对原油裂解气的生成的影响,发现这种氧化还原反应的存在能明显降低原油的稳定性,促进具高干燥系数的含H₂S天然气的生成。结合原位激光拉曼实验结果,证实了实际油藏中启动TSR反应的最可行的氧化剂应该是硫酸盐接触离子对(CIP)。全面探讨了影响TSR反应的地质和地球化学因素,提出除了初始原油的组分特征、不稳定含硫化合物(LSC)的含量外,地层水的含盐类型及盐度同样是控制TSR反应的关键因素。同时,基于大量地质分析,发现TSR对碳酸盐岩储层具有明显的溶蚀改造作用。结合溶蚀模拟实验,提出了酸性流体对碳酸盐储层溶蚀改造的机制,且深层碳酸盐岩层存在一个由TSR作用形成的次生孔隙发育带。研究认为,烃类与硫酸盐矿物的氧化还原反应与其产物对碳酸盐岩储层的改造是TSR作用的两个不可分割的部分,它们相互依存和制约。     

Thiadiamondoids as proxies for the extent of thermochemical sulfate reduction

Thiadiamondoids have been analyzed in a suite of Smackover-derived oils from the US Gulf Coast to determine whether their abundance and distribution reflect alteration by thermochemical sulfate reduction (TSR). The sample suite includes oils and condensates having various thermal maturities that are characterized as being unaltered by TSR, altered by TSR, or of uncertain affinities due to inconsistencies between conventional geochemical indicators of TSR. Nearly all samples contain thiadiamondoids, indicating that small amounts of these compounds can be generated from sulfur rich kerogen. TSR results in the generation of H₂S, sulfides and thiophenic aromatic hydrocarbons, either by reaction with sulfate or by back reactions with the evolved H₂S. Evidence shows that thiadiamondoids originate exclusively from reactions involving TSR. Once generated, their high thermal stability permits thiadiamondoids to accumulate with little further reaction and their abundance reflects not only the occurrence of TSR, but the extent of the alteration. The abundance of thiaadamantanes (1-cage structures) is particularly diagnostic of the onset of TSR. Examination of condensates from reservoirs >180 °C indicates that the thiadiamondoids can be thermally degraded. They are more thermally stable than the dibenzothiophenes, but are less stable than diamondoid hydrocarbons. Their stability appears to increase with increasing cage number, suggesting that the thiatriamantanes are the best proxy for the extent of TSR alteration in very high temperature reservoirs. Polythiadiamondoids (diamondoids with multiple sulfur substitutions) were detected in trace amounts and are also indicators of TSR.     

Stable sulfur isotope partitioning during simulated petroleum formation as determined by hydrous pyrolysis of Ghareb Limestone, Israel

Hydrous pyrolysis experiments at 200 to 365°C were carried out on a thermally immature organic-rich limestone containing Type-IIS kerogen from the Ghareb Limestone in North Negev, Israel. This work focuses on the thermal behavior of both organic and inorganic sulfur species and the partitioning of their stable sulfur isotopes among organic and inorganic phases generated during hydrous pyrolyses. Most of the sulfur in the rock (85%) is organic sulfur. The most dominant sulfur transformation is cleavage of organic-bound sulfur to form H₂S_(gas). Up to 70% of this organic sulfur is released as H₂S_(gas) that is isotopically lighter than the sulfur in the kerogen. Organic sulfur is enriched by up to 2‰ in ³⁴S during thermal maturation compared with the initial δ³⁴S values. The δ³⁴S values of the three main organic fractions (kerogen, bitumen and expelled oil) are within 1‰ of one another. No thermochemical sulfate reduction or sulfate formation was observed during the experiments. The early released sulfur reacted with available iron to form secondary pyrite and is the most ³⁴S depleted phase, which is 21‰ lighter than the bulk organic sulfur. The large isotopic fractionation for the early formed H₂S is a result of the system not being in equilibrium. As partial pressure of H₂S_(gas) increases, retro reactions with the organic sulfur in the closed system may cause isotope exchange and isotopic homogenization. Part of the δ³⁴S-enriched secondary pyrite decomposes above 300°C resulting in a corresponding decrease in the δ³⁴S of the remaining pyrite. These results are relevant to interpreting thermal maturation processes and their effect on kerogen-oil-H₂S-pyrite correlations. In particular, the use of pyrite-kerogen δ³⁴S relations in reconstructing diagenetic conditions of thermally mature rocks is questionable because formation of secondary pyrite during thermal maturation can mask the isotopic signature and quantity of the original diagenetic pyrite. The main transformations of kerogen to bitumen and bitumen to oil can be recorded by using both sulfur content and δ³⁴S of each phase including the H₂S_(gas). H₂S generated in association with oil should be isotopically lighter or similar to oil. It is concluded that small isotopic differentiation obtained between organic and inorganic sulfur species suggests closed-system conditions. Conversely, open-system conditions may cause significant isotopic discrimination between the oil and its source kerogen. The magnitude of this discrimination is suggested to be highly dependent on the availability of iron in a source rock resulting in secondary formation of pyrite.     

The role of metal sulfates in thermochemical sulfate reduction (TSR) of hydrocarbons: Insight from the yields and stable carbon isotopes of gas products

The mechanism of thermochemical sulfate reduction (TSR) was investigated by separately heating n-C₂₄ with three different sulfates (CaSO₄, Na₂SO₄, MgSO₄) in sealed gold tubes at 420 °C and measuring the stable carbon isotope values of hydrocarbon (C₁-C₅) and non-hydrocarbon (CO₂) products. Extensive TSR was observed with the MgSO₄ reactant as reflected by increasing concentrations of H₂S, ¹³C depleted CO₂ and relatively low concentrations of H₂ (compared to the control). H₂S yields were already very high at the first monitoring time (12 h) when the temperature had just reached 420 °C, suggesting that TSR had commenced well prior to this temperature. Only trace amounts of n-C₂₄ and secondary C₃-C₅ alkanes were detected at 12 h, reflecting the efficient TSR utilization of the reactant and lower molecular weight alkane products. Ethane levels were still relatively high at 12 h, but declined thereafter as it was subject to TSR in the absence of higher molecular weight alkanes which had already been utilized. Methane yields were consistently high throughout the 48 h MgSO₄ treatment. The temporal decrease in the concentrations of alkanes available for TSR may also contribute to the sharp enhancement of CO₂ after 36 h. Absence or dampening of the molecular and isotopic trends of MgSO₄ TSR was observed with Na₂SO₄ and CaSO₄ respectively, directly reflecting the levels of TSR reached using these sulfate treatments.For all treatments, the δ¹³C values of C_1-5n-alkanes showed an increase with both molecular weight and treatment time. MgSO₄ TSR led to a 5-10‰ increase in the δ¹³C values of the C₁-C₅ hydrocarbons and a 20‰ decrease in the δ¹³C value of CO₂. The significant ¹³C depletion of the CO₂ may be due to co-production of ¹³C enriched MgCO₃, although this remains unproven as the δ¹³C of MgCO₃ was not measured. The difference in the δ¹³C values of ethane and propane (Δδ¹³C_EP) increased in magnitude with the degree of TSR, and this trend could be used to help evaluate the occurrence and extent of TSR in subsurface gas reservoirs.     

High H2S contents and other effects of thermochemical sulfate reduction in deeply buried carbonate reservoirs: a review

The accumulation of high H₂S concentrations in oil and gas fields is usually associated with deeply buried high-temperature carbonate reservoirs and is attributed to the abiological oxidation of hydrocarbons by sulfate – thermochemical sulfate reduction (TSR). This review aims at providing an overview of the literature and assessing existing uncertainties in the current understanding of TSR processes and their geological significance. Reaction pathways, various reaction products, the autocatalytic nature of TSR, and reaction kinetics are discussed. Furthermore, various criteria for recognizing TSR effects, such as petrographic/diagenetic alterations and stable isotope geochemistry of the inorganic as well as the organic reactants, are summarized and evaluated. There is overwhelming geological evidence of TSR taking place at a minimum temperature of 110–140?°C, but the temperature discrepancy between experimental data and nature still exists. However, the exact nature and mechanisms of catalysts which influence TSR are not known. Local H₂S variations may reflect steady-state conditions dominated by H₂S buildups and flux out of the system. The latter is controlled by lithological and geological factors.     

川东宣汉地区天然气地球化学特征及成因

依据10余口探井60多个气样的化学成份和碳同位素组成数据,结合烃源岩和储层沥青分析资料,系统剖析了四川盆地东部宣汉地区普光、毛坝场等构造带天然气地球化学特征,并探讨了其成因及来源。研究结果表明:这些构造带中飞仙关组—长兴组天然气为高含硫化氢的干气,天然气化学成份表现出古油藏原油裂解气的特点。其烃类气体中以甲烷为主(高于99.5%);富含非烃气体,CO₂和H₂S平均含量分别达5.32%和11.95%。甲烷碳同位素较重(-33‰～-29‰),表征高热演化性质;乙烷δ¹³C值主要分布在-33‰至-28‰范围,属油型气。这些天然气与川东邻近气田的同层位天然气具有同源性,而与石炭系气藏天然气在化学成份、碳同位素组成上有所不同,意味着有不同的气源。硫化物硫同位素和沥青元素组成证实高含量的H₂S是气藏发生TSR作用所致。δ³⁴S值表征层状沉积成因的硬石膏是TSR作用的反应物,而脉状硬石膏则是其残余物。储层的孔隙类型可能与TSR作用强度和H₂S含量高低有联系,裂缝型气层中H₂S少,孔洞型储层中H₂S丰富。乙烷、沥青和各层系烃源岩干酪根碳同位素对比表明研究区飞仙关组—长兴组气藏天然气主要来自二叠系烃源层。     

Gas genetic type and origin of hydrogen sulfide in the Zhongba gas field of the western Sichuan Basin, China

Natural gases and associated condensate oils from the Zhongba gas field in the western Sichuan Basin, China were investigated for gas genetic types and origin of H₂S by integrating gaseous and light hydrocarbon geochemistry, formation water compositions, S isotopes (δ³⁴S) and geological data. There are two types of natural gas accumulations in the studied area. Gases from the third member of the Middle Triassic Leikoupo Formation (T₂l³) are reservoired in a marine carbonate sequence and are characterized by high gas dryness, high H₂S and CO₂ contents, slightly heavy C isotopic values of CH₄ and widely variable C isotopic values of wet gases. They are highly mature thermogenic gases mainly derived from the Permian type II kerogens mixed with a small proportion of the Triassic coal-type gases. Gases from the second member of the Upper Triassic Xujiahe Formation (T₃x²) are reservoired in continental sandstones and characterized by low gas dryness, free of H₂S, slightly light C isotopic values of CH₄, and heavy and less variable C isotopic values of wet gases. They are coal-type gases derived from coal in the Triassic Xujiahe Formation.The H₂S from the Leikoupo Formation is most likely formed by thermochemical SO₄ reduction (TSR) even though other possibilities cannot be fully ruled out. The proposed TSR origin of H₂S is supported by geochemical compositions and geological interpretations. The reservoir in the Leikoupo Formation is dolomite dominated carbonate that contains gypsum and anhydrite. Petroleum compounds dissolved in water react with aqueous SO₄ species, which are derived from the dissolution of anhydrite. Burial history analysis reveals that from the temperature at which TSR occurred it was in the Late Jurassic to Early Cretaceous and TSR ceased due to uplift and cooling thereafter. TSR alteration is incomplete and mainly occurs in wet gas components as indicated by near constant CH₄ δ¹³C values, wide range variations of ethane, propane and butane δ¹³C values, and moderately high gas dryness. The δ³⁴S values in SO₄, elemental S and H₂S fall within the fractionation scope of TSR-derived H₂S. High organo-S compound concentrations together with the occurrence of 2-thiaadamantanes in the T₂l reservoir provide supplementary evidence for TSR related alteration.     

Experiments on δS mixing between organic and inorganic sulfur species during thermal maturation

Reduced sulfur species were studied to constrain isotopic exchange-mixing with synthetic polysulfide cross-linked macromolecules (PCLM), model sulfur containing molecules and natural sulfur-rich kerogen, asphalt and oil of the Dead Sea area. PCLM represents protokerogens that are rich in sulfur and thermally unstable. Mixing rates of PCLM with (added as (NH₄)₂S_(aq)) at low to moderate temperatures (50-200 °C) are rapid. Elemental sulfur and H₂S_(gas) fully mix isotopes with PCLM during pyrolysis conditions at 200 °C. During these reactions significant structural changes of the PCLM occur to form polysulfide dimers, thiolanes and thiophenes. As pyrolysis temperatures or reaction times increase, the PCLM thermal products are transformed to more aromatic sulfur compounds. Isotopic mixing rates increase with increasing pyrolysis temperature and time. Polysulfide bonds (S-S) in the PCLM are responsible for most of these structural and isotopic changes because of their low stability. Conversely, sulfur isotope mixing does not occur between dibenzothiophene (aromatic S) or hexadecanthiol (C-SH) and at 200 °C after 48 h. This shows that rates of sulfur isotope mixing are strongly dependent on the functionality of the sulfur in the organic matter. The order of isotopic mixing rates for organic matter is kerogen > asphalt > oil, which is inverse to their sulfur thermal stability. Asphalt and oil with more refractory sulfur show significantly lower isotopes mixing rates than the kerogen with more labile sulfur. Based on the findings of the present study we suggest that sulfur isotopes mixing can occur from early diagenesis into catagenesis and result in isotopic homogenization of the inorganic and organic reduced sulfur pools.     

Interactions between Volatile Reduced Sulfur Compounds and Metals in the Seine Estuary (France)

Concentrations of volatile hydrogen sulfide (H₂S), carbonyl sulfide (OCS), methane thiol (MeSH), dimethyl sulfide (DMS), and dimethyl disulfide (DMDS) in the Seine estuary (France) were investigated in spring 2005 using samples collected from the first meter beneath the surface. Levels of dissolved metals (Ag, Cd, Cu, Zn, Ni, Co, Pb), suspended particulate matter, and particular organic carbon were also assessed. Maximum concentrations were 0.80 nM for H₂S, 0.64 nM for OCS, 3.06 nM for MeSH, 11.06 nM for DMS, and 1.18 nM for DMDS, and different features were observed for the five volatile reduced sulfur compounds (VRSCs). Experiments were conducted to determine silver–VRSC conditional stability constants. Major interactions were observed between H₂S and Ag, which may partially account for the absence of volatile H₂S at the lowest salinities. OCS, MeSH, and DMS did not interact with Ag, as revealed by their insignificant K′ values. Variations in concentrations along the salinity gradient may be explained by the influence of phytoplanktonic compounds.     

Mineralogic and sulfur isotopic effects accompanying oxidation of pyrite in millimolar solutions of hydrogen peroxide at temperatures from 4 to 150 °C

Oxidation of pyrite by hydrogen peroxide (H₂O₂) at millimolar levels has been studied from 4 to 150 °C in order to evaluate isotopic effects potentially associated with radiolytic oxidation of pyrite. Gaseous, aqueous, and solid phases were collected and measured following sealed-tube experiments that lasted from 1 to 14 days. The dominant gaseous product was molecular oxygen. No volatile sulfur species were recovered from any experiment. Sulfate was the only aqueous sulfur species detected in solution, with sulfite and thiosulfate below the detection limits. X-ray diffraction patterns and images from scanning electron microscopy reveal solid residues composed primarily of hydrated ferric iron sulfates and sporadic ferric-ferrous iron sulfates. Hematite was detected only in solid residue produced during high temperature experiments. Elemental sulfur and/or polysulfides are inferred to be form on reacting pyrite surface based on extraction with organic solvents. Pyrite oxidation by H₂O₂ increases in rate with increasing H₂O₂concentration, pyrite surface area, and temperature. Rates measured in sealed-tube experiments at 25°C, for H₂O₂ concentration of 2 × 10⁻³ M are 8.8 × 10⁻⁹ M/m²/sec, which are higher than previous estimates. A combination of reactive oxygen species from H₂O₂ decomposition products and reactive iron species from pyrite dissolution is inferred to aggressively oxidize the receding pyrite surface. Competing oxidants with temperature-dependent oxidation efficiencies results in multiple reaction mechanisms for different temperatures and surface conditions. Sulfur isotope values of remaining pyrite were unchanged during the experiments, but showed distinct enrichment of ³⁴S in produced sulfate and depletion in elemental sulfur. The Δ_{sulfate-pyrite} and Δ_{elemental sulfur-pyrite} was +0.5 to +1.5‰ and was −0.2 to −1‰, respectively. Isotope data from high-temperature experiments indicate an additional ³⁴S-depleted sulfur fraction, with up to 4‰ depletion of ³⁴S, in the hematite. Sulfur isotope trends were not influenced by H₂O₂ concentration, temperature, or reaction time. Results of this study indicate that radiolytically produced oxidants, such as hydrogen peroxide and hydroxyl radicals, could efficiently oxidize pyrite in an otherwise oxygen-limited environment. Although H₂O₂ is generally regarded as being of minor geochemical significance on Earth, the H₂O₂ molecule plays a pivotal role in Martian atmospheric and soil chemistry. Additional experimental and field studies are needed to characterize sulfur and oxygen isotope systematics during radiolytical oxidation of metallic sulfides and elemental sulfur.     

An integrated sulfur isotope model for Namibian shelf sediments

In this study the sulfur cycle in the organic-rich mud belt underlying the highly productive upwelling waters of the Namibian shelf is quantified using a 1D reaction-transport model. The model calculates vertical concentration and reaction rate profiles in the top 500 cm of sediment which are compared to a comprehensive dataset which includes carbon, sulfur, nitrogen and iron compounds as well as sulfate reduction (SR) rates and stable sulfur isotopes (³²S, ³⁴S). The sulfur dynamics in the well-mixed surface sediments are strongly influenced by the activity of the large sulfur bacteria Thiomargaritanamibiensis which oxidize sulfide (H₂S) to sulfate () using sea water nitrate () as the terminal electron acceptor. Microbial sulfide oxidation (SOx) is highly efficient, and the model predicts intense cycling between and H₂S driven by coupled SR and SOx at rates exceeding 6.0 mol S m⁻² y⁻¹. More than 96% of the SR is supported by SOx, and only 2-3% of the pool diffuses directly into the sediment from the sea water. A fraction of the produced by Thiomargarita is drawn down deeper into the sediment where it is used to oxidize methane anaerobically, thus preventing high methane concentrations close to the sediment surface. Only a small fraction of total H₂S production is trapped as sedimentary sulfide, mainly pyrite (FeS₂) and organic sulfur (S_org) (∼0.3 wt.%), with a sulfur burial efficiency which is amongst the lowest values reported for marine sediments (<1%). Yet, despite intense SR, FeS₂ and S_org show an isotope composition of ∼5 ‰ at 500 cm depth. These heavy values were simulated by assuming that a fraction of the solid phase sulfur exchanges isotopes with the dissolved sulfide pool. An enrichment in H₂S of ³⁴S towards the sediment-water interface suggests that Thiomargarita preferentially remove H₂³²S from the pore water. A fractionation of 20-30‰ was estimated for SOx (ε_SOx) with the model, along with a maximum fractionation for SR (ε_SR-max) of 100‰. These values are far higher than previous laboratory-based estimates for these processes. Mass balance calculations indicate negligible disproportionation of autochthonous elemental sulfur; an explanation routinely cited in the literature to account for the large fractionations in SR. Instead, the model indicates that repeated multi-stepped sulfide oxidation and intracellular disproportionation by Thiomargarita could, in principle, allow the measured isotope data to be simulated using much lower fractionations for ε_SOx (5‰) and ε_SR (78‰).     

Estimates of the second dissociation constant of H2S from the surface sulfidation of crystalline sulfur

The adsorption of hydrogen sulfide (Γ_H2S) and protons (Γ_H⁺) on the surface of crystalline sulfur was investigated experimentally in H₂S-bearing solutions at temperatures of 25, 50, and 70°C, NaCl concentrations of 0.1 and 0.5 mol/dm⁻³ and log C_H⁺ values in the range −2.3 to −5. At all temperatures, the dominant process on the surface of the sulfur was deprotonation, and the average values of Γ_H2S were very close to the highest values determined for Γ_H⁺. This finding, combined with the lack of detectable proton adsorption in H₂S-free solutions, suggests that proton adsorption/desorption on the surface of sulfur occurs through formation of ≡ S − H₂S complexes in the presence of H₂S.We propose that this complexation represents sulfidation of the sulfur surface, a process analogous to hydroxylation of oxide surfaces, and that the sulfidation can be described by the reaction: ≡ S + H₂S = ≡SSH₂⁰ β° The deprotonation of the ≡ SH° complex occurs via the reaction: ≡ SSH₂⁰ = ≡SSH⁻ + H⁺ β⁻ Values of 2.9, 2.8, and 2.9 (± 0.23) were obtained for −log β⁻ at 25, 50, and 70°C, respectively. These data were employed to estimate the second dissociation constant for hydrogen sulfide in aqueous solutions using the extrapolation method proposed by Schoonen and Barnes (1988) and yielded corresponding values for the constant of 17.4 ± 0.3, 15.7, and 14.5, respectively. The value for 25°C is in very good agreement with the experimentally determined values of Giggenbach (1971) at 17 ± 0.1; Meyer et al. (1983) at 17 ± 1; Licht and Manassen (1987) at 17.6 ± 0.3; and Licht et al. (1990) at 17.1 ± 0.3.     

Organic Sulfides in Hydrothermal Solution: Standard Partial Molal Properties and Role in Organic Geochemistry of Hydrothermal Environments

Thermodynamic properties for aqueous alkyl sulfides have been compiled and/or estimated through established methods. These properties are used to investigate reactions among various sulfur compounds in a variety of geological environments, ranging from sea floor hydrothermal systems to organic-rich sludge. Using thermodynamic data and the revised Helgeson-Kirkham-Flowers (HKF) equations of state, along with geochemical constraints imposed by the environment, it is possible to estimate the abiotic production of this class of organic sulfur compounds. For example, in hydrothermal systems in which H₂ and H₂S concentrations are buffered by the pyrite–pyrrhotite–magnetite (PPM) mineral assemblage, calculated equilibrium activities of dimethyl sulfide (DMS) are as high as 10⁻³ through formation reactions in which the environment contains millimolal concentrations of CO₂. Higher activities are obtained when DMS formation from CO is considered and when more reducing mineral assemblages are present.     

Elucidating microbial processes in nitrate- and sulfate-reducing systems using sulfur and oxygen isotope ratios: The example of oil reservoir souring control

Sulfate-reducing bacteria (SRB) are ubiquitous in anoxic environments where they couple the oxidation of organic compounds to the production of hydrogen sulfide. This can be problematic for various industries including oil production where reservoir “souring” (the generation of H₂S) requires corrective actions. Nitrate or nitrite injection into sour oil fields can promote SRB control by stimulating organotrophic nitrate- or nitrite-reducing bacteria (O-NRB) that out-compete SRB for electron donors (biocompetitive exclusion), and/or by lithotrophic nitrate- or nitrite-reducing sulfide oxidizing bacteria (NR-SOB) that remove H₂S directly. Sulfur and oxygen isotope ratios of sulfide and sulfate were monitored in batch cultures and sulfidic bioreactors to evaluate mitigation of SRB activities by nitrate or nitrite injection. Sulfate reduction in batch cultures of Desulfovibrio sp. strain Lac15 indicated typical Rayleigh-type fractionation of sulfur isotopes during bacterial sulfate reduction (BSR) with lactate, whereas oxygen isotope ratios in unreacted sulfate remained constant. Sulfur isotope fractionation in batch cultures of the NR-SOB Thiomicrospira sp. strain CVO was minimal during the oxidation of sulfide to sulfate, which had δ¹⁸O_SO4 values similar to that of the water-oxygen. Treating an up-flow bioreactor with increasing doses of nitrate to eliminate sulfide resulted in changes in sulfur isotope ratios of sulfate and sulfide but very little variation in oxygen isotope ratios of sulfate. These observations were similar to results obtained from SRB-only, but different from those of NR-SOB-only pure culture control experiments. This suggests that biocompetitive exclusion of SRB took place in the nitrate-injected bioreactor. In two replicate bioreactors treated with nitrite, less pronounced sulfur isotope fractionation and a slight decrease in δ¹⁸O_SO4 were observed. This indicated that NR-SOB played a minor role during dosing with low nitrite and that biocompetitive exclusion was the major process. The results demonstrate that stable isotope data can contribute unique information for understanding complex microbial processes in nitrate- and sulfate-reducing systems, and offer important information for the management of H₂S problems in oil reservoirs and elsewhere.