Thermochemical Sulfate Reduction Reaction Research Articles

Analysis of the mechanism for H2S generation and the main factors controlling gas production in coal seams

H2S is a poisonous and reactive gas found in coal mines, and it brings serious risks to coal mining. However, research on the mechanism for H2S generation in coal seams is rare, and information on the causes of the concentration anomalies is relatively limited. Simulations of coal thermal evolution and the mechanism for coal thermochemical sulfate reduction (TSR) are also scarce. Herein, the processes for H2S generation from coal under different conditions were simulated by combining high-temperature and high-pressure sealed simulations of TSR under different conditions. Gas formation in the TSR reactions occurring during pyrolysis, different sulfate types, salinities and coal particle sizes were discussed, H2S and other gas products were compared, the assumptions regarding TSR reactants and the product generation from coal were illustrated, and the H2S generation mechanism occurring during coal pyrolysis and the TSR reaction were revealed. H2S, CH4, C2-C5, and nonhydrocarbon gases were detected after the pyrolyses. The TSR reaction was the main source of thermogenic H2S and can be divided into the TSR starting stage, the TSR and coal pyrolysis symbiotic H2S stage, and the TSR autocatalytic reaction stage. TSR reactions exhibit different reactivities under different sulfate conditions and starting temperatures. The concentrations and yields of the H2S generated by the TSR reactions of MgSO4, CaSO4 and Na2SO4 decreased successively. The stronger the electronic induction effect of a cation was, the lower the energy barrier for the TSR reaction. High salinity led to contact ion pairs (CIP) involving sulfates and then accelerated the TSR reaction and H2S generation. Smaller coal particle sizes promoted heat and mass transfer during the TSR reaction, which enhanced H2S production.

TSR Action and Genesis Mechanism of Antimony Deposit: Evidence from Aromatic Hydrocarbon Geochemistry of Bitumen from Paleo-Oil Reservoir in Qinglong Ore Field, Southwestern Guizhou Depression, China

In Qinglong ore field, the paleo-oil reservoir is found to be associated with antimony deposits, and they have a close genetic relationship. In this study, the aromatics geochemistry of paleo-oil reservoir bitumen was studied to further discuss the thermochemical sulfate reduction (TSR) reaction and the mechanism of antimony mineralization. A total of 124 aromatic compounds were identified by gas chromatography–mass spectrometry (GC–MS) analysis in bitumen samples, including abundant phenanthrene series, dibenzothiophene series, fluoranthene series, chrysene series, and a small number of fluorene series, naphthalene series, dibenzofuran series, biphenyl series, and triaromatic steroid series. Aromatic parameters such as trimethylnaphthalene index (TMNr), methylphenanthrene index (MPI), methylphenanthrene distribution fraction (MPDF, F1, and F2), methyldibenzothiophene parameter (MDR), C28TAS-20S/(20R + 20S), and benzofluoranthene/benzo[e]pyrene indicate that the Qinglong paleo-oil reservoir is in over maturity level. The abundance of phenanthrene and chrysene aromatic compounds and a small amount of naphthalene series, benzofluoranthene, fluoranthene, pyrene, anthracene, retene, perylene, and biphenyl suggest that the organic matter source of the paleo-oil reservoir was mainly low aquatic organisms, mixed with a small amount of higher plant. They detected a certain number of compounds, such as retene, triaromatic steroid series, and perylene, the ternary diagram of DBF–DBT–F and binary plot of Pr/Ph–DBT/P, DBT/(F + DBT)–DBF/(F + DBF), and Pr/Ph–DBT/DBF reveal that the source rock of the paleo-oil reservoir was formed in the marine environment of weak oxidation and weak reduction. The comprehensive analysis shows that the Qinglong paleo-oil reservoir originated from Devonian source rocks, just like other paleo-oil reservoirs and natural gas reservoirs in the Nanpanjiang basin. Abundant dibenzothiophene series were detected, indicating that the paleo-oil reservoir underwent a certain degree of TSR reaction. We believe that the gas reservoir formed by the evolution of the oil reservoir in the ore field participated in antimony mineralization; that is, hydrocarbon organic matter acted as a reducing agent and transformed SO42− in oilfield brine into H2S through TSR, providing reduced sulfur and creating environmental conditions for mineralization.

The effect of thermochemical sulfate reduction of n-pentane and condensate on the chemical and isotopic compositions of gases: Implications for the organic reactant and reaction extent

Evaluating the composition of organic reactants initially involved in thermochemical sulfate reduction (TSR) reaction and better understanding the chemical and isotopic compositions of gases are helpful to minimize the risks involved in exploration of natural sour gas reservoirs. Variations in the chemical and carbon isotopic compositions of the gas produced during high pressure (50Mpa), isothermal (360 °C) hydro-pyrolysis experiments of the TSR reaction and thermal cracking involving n-pentane (n-C5) and condensate were investigated using a high-pressure gold tube system. The results show that the yields of CH4, CO2 and H2S increased with reaction time, and that the yields of C2–C4 firstly increased and then decreased. The δ13C value of alkane gases increased with reaction time. The δ13C value of CO2 produced from the TSR reaction involving n-C5 became less negative. The yields of alkane gas, CO2 and H2S from the TSR reaction of n-C5 were up to two times higher than that those from the TSR reaction of condensate. This indicates that lighter liquid hydrocarbons with higher hydrogen content produce more hydrocarbon and non-hydrocarbon gases. The relationship between the dryness, δ13C values of alkane gases and sourness could help to estimate whether the organic reactant was liquid or gaseous hydrocarbons. The value of ln(C2/C3) at the early stage of TSR reaction can be used to roughly estimate the composition of the liquid hydrocarbons involved in the TSR reaction. Our analysis also shows that the value of ln(C2/C3) firstly increased and then decreased with increasing gas dryness during the TSR reaction, which could be an effective index to assess the TSR reaction extent and provide new clues for identifying gas origin. The δ13C values of methane and ethane produced in the TSR reaction involving n-C5 reversed to δ13C1 > δ13C2 during the 48–60h period, which could be related to the oxidation of alkanes by HSO4−. This could help explain the δ13C1 > δ13C2 in TSR influenced gas reservoirs with low H2S content.

Characterization of chemical and carbon isotopic compositions of gases during thermochemical sulfate reduction and implications for gas origin and content

For identifying the occurrence and extent of thermochemical sulfate reduction (TSR) reaction of natural gas and better understanding the chemical and carbon isotopic variations in natural gas reservoirs, high-pressure hydro-pyrolysis with a special designed apparatus was performed using natural gas and various amounts of MgSO4·7H2O at up to 360 °C. The yields, chemical and isotopic compositions of the gases produced during TSR and thermal cracking were measured. As the extent of TSR reaction increased, the concentrations of CH4, CO2 and H2S increased in a nonlinear way, while those of C2H6 and C3H8 decreased. According to the variation of gas content, the TSR reaction of alkane gases can be divided into an uncatalyzed and a catalyzed stage, which is different from previous studies that treated the TSR reaction of alkane gases as a non-autocatalytic reduction process. As the concentration of MgSO4·7H2O increased, the rate of TSR reaction with hydrocarbon gases increased. The concentrations of HSO4− and volume of aqueous phase could be responsible for the different TSR reaction rates in the catalyzed stage. The co-variation of ln(C1/C2) and ln(C2/C3) could be related to the TSR reaction of alkane gases. Our study provides clues for understanding the compositional variations in natural conditions.

Effects of gas saturation and reservoir heterogeneity on thermochemical sulfate reduction reaction in a dolomite reservoir, Puguang gas field, China

Varying concentrations of H2S have been found in the carbonate reservoir, Puguang gas field, China. Thermochemical sulfate reduction (TSR) is considered the most important process to generate a high level of hydrogen sulfide (H2S) in the reservoir. Although TSR has been intensively studied in this field, it is still not clear on (1) the controls of H2S concentration variations in the reservoir, (2) effects of variable gas and water saturations and reservoir heterogeneity on the TSR reactions, (3) reservoir quality changes during the TSR reactions, (4) potential sources and sinks of sulfur and carbon and their quantification. In this study, we conducted reactive transport modeling to quantitatively simulate the TSR and H2S generation processes in the Upper Permian Changxing Formation and Lower Triassic Feixianguan Formation in Puguang gas field, using log-based depth and thickness, paleo mineralogy assemblages and paleo temperature in late Jurassic, and hydrostatic pressure. The modeling results are relatively reliable as the predicted H2S and CO2 concentrations are comparable with the observed ones in the wells after calibration. The results indicated that both mineralogical composition and gas saturation in the reservoir affect the local efficiency and extent of TSR reactions, of which the abundance of effective anhydrite is an important control on the extent of the TSR reactions. The modeling durations of TSR reactions were ∼6 m.y. and TSR had a small impact on the reservoir porosity (porosity changes generally less than 0.1 porosity unit). The sources and sinks of carbon and sulfur were locally balanced with each other, respectively, and the minor imbalances were likely due to the molecular diffusion. The calibrated models have predictive potential on the H2S and CO2 concentrations changes and porosity modifications during the TSR processes in the subintervals with limited samples. The validated TSR models will facilitate the investigation of organic-inorganic interactions and their impacts on both non-hydrocarbon (H2S and CO2) generation and reservoir qualities.

Influence of carbonate minerals on the pyrolysis and phase behavior of oil

The concept that reservoir minerals can affect oil cracking behavior is widely accepted by geochemists. However, the role of carbonate minerals on the thermal evolution of oil is still not well understood. This is especially true for dolomite, which is one of the most important carbonate cements. To investigate its influence, a series of laboratory simulation experiments of a crude oil with various carbonate minerals, including calcite, magnesite, and dolomite was conducted. The simulation experiments were carried out using a closed system of flexible gold capsules at temperatures of 250–600°С at a heating rate of 20 °C/h and a constant pressure of 50 MPa. The results indicate that dolomite/magnesite might promote the generation of sulfate radical ion (SO42−). Subsequently, the presence of SO42− can initiate thermochemical sulfate reduction reaction with the help of minor water and H2S, resulting in the destruction of gaseous hydrocarbons. Meanwhile, the influence of dolomite on the composition of oil can further affect its phase behavior, especially in the gas window (Easy Ro range of 1.19–1.47% in the experiments). For the investigated oil, at Easy Ro of 1.47%, the presence of dolomite will increase the cricondentherm (ca. 35 °C) and decrease the cricondenbar (ca. 1.3 MPa) compared to those of pure oil.

Species of Sulfur in Sour Gas Reservoir: Insights from In Situ Raman Spectroscopy of S–H2S–CH4–H2O System and Its Subsystems from 20 to 250°C

Thermochemical sulfate reduction (TSR) is the most important mechanism for the generation of high-concentration H2S in gas reservoirs. Sulfur speciation in sour gas is one of the key factors controlling the rate and extent of TSR in gas reservoirs. However, experimental studies on S species in sour gas are limited due to the toxicity and corrosion of S and H2S. Fused silica capillary capsules (FSCCs) are inert to S and H2S and, therefore, were employed in this study as microreactors containing the S–H2S–CH4–H2O system and its subsystems, representing the composition of sour gas. The in situ Raman spectra of each system were collected continuously during the process of heating from 20°C to 250°C. The results showed the following: (1) a Raman peak at 2500 cm−1 was detected in the liquid S phase of the S–H2S–CH4 –H2O system at 120–250°C, which was attributed to H2Sn. A Raman band at ~533 cm−1 was detected in the aqueous phase of the S–H2S–H2O–CH4 system at 250°C and was assigned to S3−, suggesting that S3− and H2Sn are important S species in sour gas reservoirs at elevated temperatures. (2) The Raman peak at 2500 cm−1 disappeared at 20°C, indicating that H2Sn decomposes into S and H2S. During gas extraction, the decomposition of H2Sn will cause S deposition in pipelines. (3) In addition to S3−, H2Sn could be the intermediate valence S species involved in the TSR reaction.

Recognition of in situ oil cracking in the Precambrian–Lower cambrian petroleum systems of sichuan basin, southwestern China

Determining the place of paleo-oil cracking is crucial to understanding the formation mechanism of the gas reservoirs in the Precambrian–Cambrian strata. For the old strata the attainable information is limited because most paleo-oil have been cracked to gas at high thermal maturity, such as the Anyue giant gas field in the Moxi–Gaoshiti Bulge of Sichuan Basin, Southwestern China. In this study, the place of paleo-oil cracking was discussed based on solid bitumen found in the reservoirs. Numerous solid bitumen from the deep boreholes in the Precambrian Dengying (Z2dn2 and Z2dn4) and Lower Cambrian Longwangmiao (Є1l) formations of the Moxi–Gaoshiti Bulge were analyzed. Elemental and carbon isotope analyses and optical microscopic observations, such as Raman spectroscopy, scanning electron microscopy, and electronic probe, were performed on these solid bitumen samples. The obtained parameters, including the reflectance of the solid bitumen, parameters I(D)/I(G) and S(D)/S(G) from the Raman spectra, the compositions and carbon isotope of gas, burial history, and the predicted “equivalent vitrinite reflectance Ro” (EqVRo) for reservoirs, jointly support that solid bitumen are epigenetic bitumen in reservoirs other than primary bitumen in source rocks. This study provides a relatively solid evidence of in situ cracking of paleo-oil and the thermochemical sulfate reduction reaction between paleo-oil and dolomite reservoirs. Pyrite were found both in carbonate rocks and argillaceous rock, and the sulfur in pyrite is perceived as a pathway of H2S formation. The results provide a basis for understanding the formation mechanism of the deep huge gas field that was derived from paleo-oil cracking, and may contribute to future petroleum exploration in deep Precambrian–Lower Cambrian systems.

The role of exogenous oxygen in organic acid generation in deep reservoirs of petroleum-producing basins: Progress and prospects

The source, yield, and distribution of organic acids in oilfield waters in petroleum-producing basins have not been satisfactorily explained by previous studies that have focused on oxygen-containing functional groups in kerogen as the major source of such acids. This study reviews four possible mechanisms by which exogenous oxygen can participate in petroleum or organic acid generation. Biodegradation and mineral oxidation generate organic acids in oilfield waters, leading to an increase in the oxygen content of altered oils, which then have greater potential for producing organic acids. Hydrolytic disproportionation reaction and thermochemical sulfate reduction reactions at high temperatures lead to the in situ generation and accumulation of organic acids in deep reservoirs. The incorporation of exogenous oxygen increases the yield and expands the distribution of organic acids in reservoirs at various depths. The acids derived from exogeneous oxygen play critical roles in the development and preservation of deep reservoirs. Further research is required to determine the volumes and compositions of organic acids produced by these reactions, and to further understand the role of organic acids in the alteration of deep reservoirs under more realistic conditions.

Effect of thermochemical sulfate reduction on carbonate reservoir quality: Cambrian and Ordovician oilfield, Tazhong area, Tarim basin, China

Deep (4000–6000 m) and ultra-deep burial (>6000 m) carbonate reservoirs are becoming important petroleum exploration targets of China and worldwide basin. Thermochemical sulfate reduction (TSR) may be pervasive in the deep and ultra-deep burial petroliferous carbonate strata associated with evaporite. However, there is still considerable confusion on the effect of TSR on reservoir quality. Petrography, geochemistry and fluid inclusion data from carbonate reservoirs of Tarim Basin were integrated to resolve the disagreement. Based on distribution of sulfur-bearing mineral, SO42− concentrations and SO42−/Cl− ratios in both formation water and fluid trapped in fluid inclusion, we propose that SO42− in formation water is likely major reactant involved in TSR reaction of North Slope, whereas coarsely diagenetic anhydride is likely major sulfate reactant involved in TSR reaction of East Burial Hill Belt. Silurian fracture-filling pyrite has δ34S values similar to those of Ordovician fracture-filling pyrite, H2S and sulfur, suggesting that TSR dissolved sulfate involved in (North Slope) may occur in a partly open system for H2S and CO2. However, TSR diagenetic anhydride involved in (East Burial Hill Belt) may occur in a closed diagenetic system. TSR in a partly open-system, associated with gas charge and flow of cross formational fluids, probably increased fluid pressure, and further transported H2S, CO2 and solute from dissolution through fracture. A closed system of anhydrite-bearing strata seems to hinder transports of TSR-derived CO2 or bicarbonate, and result in precipitation of TSR calcite, pyrite and bitumen close to the TSR sites. In combination with petrographic observations, intense dissolution in North Slope have released more inorganic CO2 leading to TSR calcite and CO2 in the natural gas showing δ13C values much heavier relative to δ13C values of TSR calcites in East Burial Hill Belt as light as −13.4‰. TSR-induced dissolution of carbonate minerals during oil-dominated TSR may be related to the reaction of dolomite with anhydride and release of H+ due to pyrite precipitation, rather than new formed water during TSR. Similar to geological settings of Ordovician TSR, anhydrite-poor Lower Cambrian dolostones underlying evaporites seals may thus be the most promising target for future exploration success in ultra-deep Cambrian reservoirs of Tarim Basin. The controversy about the effects of TSR on reservoir quality can partly be ascribed to differently geological settings where TSR occurred.

Evolution of the Igarapé Bahia Cu-Au deposit, Carajás Province (Brazil): Early syngenetic chalcopyrite overprinted by IOCG mineralization

The Igarapé Bahia IOCG Cu–Au deposit, located in the Carajás Domain, the northern part of the Carajás Province in the Amazon Craton, is one of the most economically important deposits in the province. The deposit is hosted in the metavolcanosedimentary Igarapé Bahia Group and the metasedimentary Águas Claras Formation. The Igarapé Bahia Group encompasses a lower unit with metavolcanic rocks and metagabbros, and metasedimentary rocks (metarhythmites, epiclastic rocks, and banded iron formation) of the upper unit. Epiclastic rocks are predominant in the Águas Claras Formation. Basement xenoliths within the lower unit yielded an U–Pb zircon age of 2935 ± 36 Ma, suggesting that a sialic crust was present prior to basin installation likely due to rifting. The U–Pb dating of detrital zircons yielded maximum deposition age at 2784 ± 27 Ma for the upper unit, and 2763 ± 32 Ma and 2774 ± 19 Ma for the Águas Claras Formation. Chalcopyrite nodules and layers are found within metarhythmites, concordant to primary structures, but without hydrothermal alteration halos and iron oxide. This chalcopyrite generation seems to have precipitated synchronously to the deposition of the Igarapé Bahia Group. Chalcopyrite nodules and layers show δ34SVCDT values ranging from +0.29 to +1.56‰. These data indicate that most of its sulfur is likely derived from the metavolcanic rocks of the lower unit. Host rocks and chalcopyrite nodules and layers were overprinted by the IOCG mineralization. The latter formed extensive halos of hydrothermal alteration and was accompanied by ductile deformation and hydrothermal brecciation. These processes resulted in (tourmaline)–carbonate–magnetite, (tourmaline)–carbonate–chlorite and (tourmaline)–(biotite)–chlorite mylonites and breccias. Chalcopyrite from magnetite-rich zones (i.e. IOCG mineralization) displays δ34SVCDT values from +1.36 to +5.35‰. In addition to magmatic sulfur, seawater-derived sulfate may have been incorporated in sulfides via thermochemical sulfate-reduction reactions. Trace element geochemistry in distinct copper ores (i.e. nodules and layers versus magnetite-rich) also point to different origins of both styles of mineralization. The timing of the IOCG mineralization was constrained at 2559 ± 34 Ma in the Alemão orebody. These data suggest that an IOCG-type metallogenetic event at ca. 2.5 Ga overprinted an older syngenetic-exhalative type copper mineralization. They also indicate that precipitation of early sulfide minerals within the Itacaiúnas Supergroup may have created Cu-rich sequences that could have been remobilized, generating the broad group of the IOCG deposits at Carajás.

Constraining the Fluid History of a CO2‐H2S Reservoir: Insights From Stable Isotopes, REE, and Fluid Inclusion Microthermometry

AbstractReservoirs that host CO2‐H2S‐bearing gases provide a key insight into crustal redox reactions such as thermochemical sulfate reduction (TSR). Despite this, there remains a poor understanding of the extent, duration, and the factors limiting this process on a reservoir scale. Here we show how a combination of petrography, fluid inclusion, rare earth element (REE), and carbon (δ13C), oxygen (δ18O), and sulfur (δ34S) stable isotope data can disentangle the fluid history of the world's largest CO2 accumulation, the LaBarge Field in Wyoming, USA. The carbonate‐hosted LaBarge Field was charged with oil around 80 Ma ago, which together with nodular anhydrite represent the reactants for TSR. The nodules exhibit two distinct trends of evolution in δ13C with both δ34S and δ18O that may be coupled to two different processes. The first trend was interpreted to reflect the coupled dissolution of anhydrite and reduction to elemental sulfur and the oxidation of organic compounds and associated precipitation of calcite during TSR. In contrast, the second trend was interpreted to be the result of the hydrothermal CO2 influx after the cessation of TSR. In addition, mass balance calculations were performed to estimate an approximate TSR reaction duration of 80 ka and to identify the availability of organic compounds as the limiting factor of the TSR process. Such an approach provides a tool for the prediction of TSR occurrence elsewhere and advancing our understanding of crustal fluid interactions.

Geochemical characteristics and origin of natural gas and gas -filling mode of the Paleozoic in the Yanchuannan gas field, Ordos Basin, China

In order to determine the origin of Carboniferous-Permian (C-P) coal measure gas and Ordovician weathered crust gas, and their gas-filling modes, the chemical and isotopic compositions of the natural gas along with the co-produced groundwater from Paleozoic in the Yanchuannan (YCN) gas field of the Ordos Basin, China, were analyzed. It was found in this work that the gas in the upper gas group of weathered crust (O1m51+2) reservoirs and the C-P gas had similar δ13C1 and δ13C3 compositions and they were less negative than those of the gas in the lower gas group (O1m54). While all weathered crust gases had δ13C2 values that are more negative than the C-P gases. The O1m54 gas and C-P gas had a very clear boundary in δDCH4 value, while the O1m51+2 gas had the δDCH4 ranges intersecting with the two others. The C-P gas is inferred derived from coal measures. The O1m51+2 gas near erosional valley-form is a mixture of coal-derived gas and marine sapropelic gas, and the remaining Ordovician gases are inferred to originate from marine sapropelic source rock. Both gases were characterized by secondary cracking gas, and thermochemical sulfate reduction (TSR) altered the chemical and isotopic composition of weathered crust gas to a lesser extent due to short TSR reaction time. The changes in water type and total dissolved solids from the Permian to the Ordovician and the D shift phenomenon of O1m51+2 water, reveals the fluid vertical migration between the Upper and Lower Paleozoic. Coupled with geological evolution analysis, the ancient erosional valley-form and the surrounding solution cavities and fractures are inferred the main migration channels for coal-derived gas into weathered crust reservoir. Moreover, three vertical gas-filling modes are proposed, i.e., gas seepage in free phase, diffusion phase and water-solution phase, with the importance in descending order.

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.

The Effect of Water Chemistry on Thermochemical Sulfate Reduction: A Case Study from the Ordovician in the Tazhong Area, Northwest China

Formation water chemistry, sulfate sulfur isotopes, and associated H2S contents and sulfur isotopes were measured from the Ordovician in Tazhong area, Tarim Basin. The aim is to elucidate the effects of geochemical composition of formation water on thermochemical sulfate reduction (TSR) and potential usage of SO4/Cl ratios as a new proxy for TSR extents in areas, where H2S and thiaadamantanes (TAs) data are not available. The formation water has SO4/Cl ratios from 0.0002 to 0.016, significantly lower than 0.04 to 0.05 from 3 to 7 times evapoconcentrated seawater. Thus, the low values are explained to result from TSR. Furthermore, the SO4/Cl ratios show negative correlation relationships to TAs and H2S concentrations, indicating that TSR occurred in a relatively closed system and SO4/Cl ratio can be used to indicate TSR extents in this area. Extensive TSR in the Cambrian in the Tazhong area, represented by low SO4/Cl ratios and high H2S and TAs concentrations, is accompanied by formation water with high TDS and Mg concentrations, indicating the effects of water chemistry on TSR under a realistic geological background. In contrast, the low TSR extent in the Ordovician may have resulted from limited TSR reaction duration and total contribution of aqueousSO42-.

The First Report of Thermochemical Sulfate Reduction Reaction in the Upper Paleozoic Carbonate Rocks of Southeastern Ordos Basin

The First Report of Thermochemical Sulfate Reduction Reaction in the Upper Paleozoic Carbonate Rocks of Southeastern Ordos Basin

Genetic origin of sour gas condensates in the Paleozoic dolomite reservoirs of the Tazhong Uplift, Tarim Basin

Twenty gas condensates, six oils and their associated formation water from the Tazhong Uplift in the Tarim Basin, NW China were characterized for their molecular and isotopic compositions and water chemistry to elucidate the origins of the sour condensates. Thermochemical sulfate reduction (TSR) is the main secondary alteration process relevant to the generation of sour gas condensates. Those condensates are slightly heavier than regular condensates with a wide range of physical property and chemical composition variations. The hydrogen sulfide (H2S) concentrations in gas phase show a strong positive correlation to gas/oil ratio, organosulfur compound (OSC) concentrations in the liquid phase. While methane isotopic values are mainly controlled by thermal maturity, wet gas components show unusual 13C enrichment at a low degree of thermal cracking. Geochemical anomalies occur mainly in the Lower Ordovician Yingshan Fm. where more H2S has been discovered, while the Upper Ordovician Lianglitage Fm. shows less irregularity and H2S concentration is much lower. Generation of sour gas condensate is most likely caused by TSR alteration, which could oxidize liquid hydrocarbons and form a large quantity of OSCs. Isotopic enrichment of 34S in formation water sulfate and elevated OSC concentrations provide supplemental evidence of TSR alteration. Both burial history reconstructions based on fluid inclusion analysis and PVT simulation indicate that in situ TSR reactions mainly occurred around last 10 Ma during the late Himalayan orogeny and overall TSR extent is relatively low in the Tazhong Uplift.

Compound-specific sulfur isotope analysis of thiadiamondoids of oils from the Smackover Formation, USA

Thiadiamondoids (TDs) are diamond-like compounds with a sulfide bond located within the cage structure. These compounds were suggested as a molecular proxy for the occurrence and extent of thermochemical sulfate reduction (TSR). Compound-specific sulfur-isotope analysis of TDs may create a multi-parameter system, based on molecular and δ34S values that may be sensitive over a wider range of TSR and thermal maturation stages. In this study, we analyzed a suite of 12 Upper Jurassic oil and condensate samples generated from source rocks in the Smackover Formation to perform a systematic study of the sulfur isotope distribution in thiadiamondoids (one and two cages). For comparison we measured the δ34S composition of benzothiophenes (BTs) and dibenzothiophenes (DBTs). We also conducted pyrolysis experiments with petroleum and model compounds to have an insight into the formation mechanisms of TDs. The δ34S of the TDs varied significantly (ca 30‰) between the different oils depending on the degree of TSR alteration. The results showed that within the same oil, the one-cage TDs were relatively uniform, with 34S enriched values similar to those of the coexisting BTs. The two-cage TDs had more variable δ34S values that range from the δ34S values of BTs to those of the DBTs, but with general 34S depletion relative to one cage TDs. Hydrous pyrolysis experiments (360°C, 40h) with either CaSO4 or elemental S (equivalent S molar concentrations) and adamantane as a model compound demonstrate the formation of one cage TDs in relatively low yields (<0.2%). Higher concentrations of TDs were observed in the elemental sulfur experiments, most likely because of the higher rates of reaction with adamantane under these experimental conditions. These results show that the formation of TDs is not exclusive to TSR reactions, and that they can also form by reaction with reduced S species apart from sulfate reduction, though at low yields. Oxygenated compounds, most notably 2-thiaadamantanone and phenol, were also formed during these pyrolysis experiments. This may represent the first stage in the formation of sulfurized compounds and the oxidation of organic matter under TSR conditions. Pyrolysis experiments with elemental S and a TD-enriched oil showed that the δ34S values of the TDs did not change, whereas the BTs did change significantly. It is therefore concluded that TDs do not exchange S atoms with coexisting inorganic reduced sulfur species. They can only change their δ34S values via addition of newly generated TDs that form predominantly during TSR. We therefore suggest that TDs will preserve their δ34S values even under high-temperature reservoir conditions and will reflect the original sulfates δ34S value. The combination of TDs, BTs, and DBTs δ34S values and concentrations allowed for a more reliable detection of the occurrence and extent of TSR than either proxy alone. It showed that except for two oils, all of the oils that were measured in this study were affected by TSR or TSR-sourced H2S, to some degree. It is still not known if some of the oils with the lower concentrations of TDs and enriched δ34S values (close to sulfate minerals) were affected by TSR or by a secondary charge of 34S-enriched H2S.

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.