Geochemistry and origin of sour gas accumulations in the northeastern Sichuan Basin, SW China

Significant natural gas reserves have recently been discovered in the Lower Triassic oolitic reservoirs from northeastern Sichuan Basin, SW China. In the wake of the December 2003 sour gas well blow-out, this study presents an overview on the petroleum geology and geochemistry of the sour gas accumulations in the study area. Two types of natural gas accumulations were identified in the Lower Triassic oolitic reservoirs, both containing highly mature thermogenic gases, with their hydrocarbon source rocks in Upper Permian strata. Natural gases from the area south of the ancient Kaijiang-Liangping Seaway are generally sweet gases formed as the result of thermal maturation, whereas those discovered from north of the Seaway are products of both thermal maturation and thermochemical sulfate reduction of early accumulated oils in the Feixianguan Formation reservoirs. The proposed origins of the gases are supported by their chemical and stable carbon isotope compositions, as well as the presence or absence of pyrobitumens in the reservoir. The distribution of gas accumulations is controlled predominantly by the combination of lithologic and structural factors. The regional variation in the concentrations of H₂S in the gases appears related to the presence and thickness of anhydrite-bearing evaporitic rocks interbedded or intercalated with the oolitic reservoirs.     

Chemical and isotopic evidence for secondary alteration of natural gases in the Hetianhe Field, Bachu Uplift of the Tarim Basin

H₂S and CO₂ are found in elevated concentrations in the reservoirs near the Carboniferous–Ordovician unconformity in the Hetianhe Field of the Tarim Basin, NW China. Chemical and isotopic analyses have been performed on produced gases, formation waters and reservoir rocks to determine the origin of CO₂ and H₂S and to explain the heterogeneous distribution of isotopic and geochemical characteristics of petroleum fluids. It is unlikely that H₂S and CO₂ had a mantle component since associated helium has an isotope ratio totally uncharacteristic of this source. Instead, H₂S and CO₂ are probably the result of sulphate reduction of the light hydrocarbon gases (LHG). Increasing H₂S concentrations and CO₂/(CO₂+ΣC_1–4) values to the west of the Hetianhe Field occur commensurately with increasingly heavy hydrocarbon gas δ¹³C values. However, thermochemical sulphate reduction is unlikely because the temperatures of the reservoirs are too low, no H₂S or rare pyrite was detected in deeper reservoirs (where more TSR should have occurred) and inferred δ³⁴S values of H₂S (from late-stage pyrite in the Carboniferous and Ordovician reservoirs) are as low as −24.9‰. Such low δ³⁴S values discount the decomposition of organic matter as a major source of H₂S and CO₂. Bacterial sulphate reduction of the light hydrocarbon gases in the reservoir, possibly coupled indirectly with the consumption of organic acids and anions is most likely. The result is the preferential oxidation of ¹²C-rich alkanes (due to the kinetic isotope effect) and decreasing concentration of organic acids and anions. Modern formation water stable isotope data reveal that it is possible that sulphate-reducing bacteria were introduced into the reservoir by an influx of meteoric water from the west by way of an inversion-related unconformity. This may account for the apparently stronger influence of bacterial sulphate reduction to the west of the Hetianhe Field, and the consequent greatest decrease of the δ¹³C-CO₂ values and the greatest increase in δ¹³C values of the alkane gases.     

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.     

The geochemical and isotopic record of evaporite recycling in spas and salterns of the Basque Cantabrian basin, Spain

Evaporite outcrops are rare in the Basque Cantabrian basin due to a rainy climate, but saline springs with total dissolved solids ranging from 0.8 to 260 g/L are common and have long been used to supply spas and salterns. New and existing hydrochemistry of saline springs are used to provide additional insight on the origin and underground extent of their poorly known source evaporites. Saline water hydrochemistry is related to dissolution of halite and gypsum from two evaporitic successions (Triassic “Keuper” and Lower Cretaceous “Wealden”), as supported by rock samples from outcrops and oil exploration drill cuttings. The δ³⁴S value of gypsum in the Keuper evaporites and sulfate in the springs is δ³⁴S_SO4 = 14.06 ± 1.07‰ and δ¹⁸O_SO4 = 13.41 ± 1.44‰, and the relationship between Cl/Br ratio of halite and water shows that waters have dissolved halite with Br content between 124 and 288 ppm. The δ³⁴S value of gypsum in the Wealden evaporites and sulfate in the springs is δ³⁴S_SO4 = 19.66 ± 1.76‰, δ¹⁸O_SO4 = 14.93 ± 2.35‰, and the relationship between Cl/Br ratio of halite and water shows that waters have dissolved halite with Br content between 15 and 160 ppm. Wealden evaporites formed in a continental setting after the dissolution of Keuper salt. Gypsum δ³⁴S_SO4 and δ¹⁸O_SO4 modification from Keuper to Wealden evaporites was due mainly to bacterial SO₄ reduction in an anoxic, organic matter-rich environment. Saline springs with Wealden δ³⁴S_SO4 values are present in a 70 × 20 km wide area. Saline water temperatures, their δ²H_H2O and δ¹⁸O_H2O values, and the geological structure defines a hydrogeological model, where meteoric water recharges at heights up to 620 m above spring levels and circulates down to 720 m below them, thereby constraining the height range of evaporite dissolution. Groundwater flow towards saline springs is driven by gravity and buoyancy forces constrained by a thrust and fault network.     

Enrichment of nitrogen and 13C of methane in natural gases from the Khuff Formation,Saudi Arabia,caused by thermochemical sulfate reduction

Permian Khuff reservoirs along the east coast of Saudi Arabia and in the Arabian Gulf produce dry sour gas with highly variable nitrogen concentrations. Rough correlations between N₂/CH₄, CO₂/CH₄ and H₂S/CH₄ suggest that non-hydrocarbon gas abundances are controlled by thermochemical sulfate reduction (TSR). In Khuff gases judged to be unaltered by TSR, methane δ¹³C generally falls between −40‰ and −35‰ VPDB and carbon dioxide δ¹³C between −3‰ and 0‰ VPDB. As H₂S/CH₄ increases, methane δ¹³C increases to as much as −3‰ and carbon dioxide δ¹³C decreases to as little as −28‰. These changes are interpreted to reflect the oxidation of methane to carbon dioxide.Khuff reservoir temperatures, which locally exceed 150 °C, appear high enough to drive the reduction of sulfate by methane. Anhydrite is abundant in the Khuff and fine grained nodules are commonly rimmed with secondary calcite cement. Some cores contain abundant pyrite, sphalerite and galena. Assuming that nitrogen is inert, loss of methane by TSR should increase N₂/CH₄ of the residual gas and leave δ¹⁵N unaltered. δ¹⁵N of Paleozoic gases in Saudi Arabia varies from −7‰ to 1‰ vs. air and supports the TSR hypothesis. N₂/CH₄ in gases from stacked Khuff reservoirs varies by a factor of 19 yet the variation in δ¹⁵N (0.3–0.5‰) is trivial.Because the relative abundance of hydrogen sulfide is not a fully reliable extent of reaction parameter, we have attempted to assess the extent of TSR using plots of methane δ¹³C versus log(N₂/CH₄). Observed variations in these parameters can be fitted using simple Rayleigh models with kinetic carbon isotope fractionation factors between 0.98 and 0.99. We calculate that TSR may have destroyed more than 90% of the original methane charge in the most extreme instance. The possibility that methane may be completely destroyed by TSR has important implications for deep gas exploration and the origin of gases rich in nitrogen as well as hydrogen sulfide.     

Stable carbon isotope compositions and source rock geochemistry of the giant gas accumulations in the Ordos Basin, China

Ordos Basin, the second largest sedimentary basin in China, contains enormous natural gas resources. Each of the four giant gas fields discovered so far in this basin (i.e., Sulige, Yulin, Wushenqi and Jingbian) has over 100 billion cubic meters (bcm) or 3.53 trillion cubic feet (tcf) of proven gas reserves. This study examines the stable carbon isotope data of 125 gas samples collected from the four giant gas fields in the Ordos Basin. Source rocks in the Upper Paleozoic coal measures are suggested by the generally high δ¹³C values of C₁–C₄ gaseous hydrocarbons in the gases from the Sulige, Yulin and Wushenqi gas fields. While the δ¹³C_iC4 value is higher than that of the δ¹³C_nC4, the dominant ranges for the δ¹³C₁, δ¹³C₂, and δ¹³C₃ values in these Upper Paleozoic reservoired gases are −34 to −32‰, −27 to −23‰, and −25 to −24‰, respectively. The δ¹³C values of methane, benzene and toluene in gases from the Lower Paleozoic reservoirs of the Jingbian field indicate a significant contribution from humic source rocks, as they are similar to those in the Upper Paleozoic reservoirs of the Sulige, Yulin and Wushenqi gas fields. However, the wide variation and reversal in the δ¹³C₁, δ¹³C₂ and δ¹³C₃ values in the Jinbian gases cannot be explained using a single source scenario, thus the gases were likely derived dominantly from the Carboniferous-Permian coal measures with some contribution from the carbonates in the Lower Permian Taiyuan Formation. The gas isotope data and extremely low total organic carbon contents (<0.2% TOC) suggest that the Ordovician Majiagou Formation carbonates are unlikely to be a significant gas source rock, thus almost all of the economic gas accumulations in the Ordos Basin were derived from Upper Paleozoic source rocks.     

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。     

Factors Controlling Precipitation of Barite and Witherite and Genesis of the Ankang–Xunyang Barium Deposits, Shaanxi, China

The barium deposits in Ankang and Xunyang counties,Shaanxi Province,China,occur in the northernmost part of the world-class barium metallogenic belt in south Qinling.The deposits are hosted by the Lower Silurian carbonaceous siliceous rocks,with a unique combination of barite and witherite.The homogenization temperatures of fluid inclusions in the barite are mainly concentrated between 135 and 155 ℃,whereas those from the witherite have two peaks of 165-175 ℃,and 215-225℃,respectively.Laser Raman analysis of fluid inclusions indicates that the vapor phase of fluid inclusions in barite is dominated by H_2O,although some contains N_2,H_2S,and CH_4.The compositions of the vapor and liquid phases of fluid inclusions in witherite can be divided into two end-members,one dominated by H_2O without other volatiles,and the other containing CH_4,C_2H_6,C_3H_8,C_2H_4,and C_6H_6 in addition to H_2O.CO_2,H_2S,and some CH_4 are interpreted as products of chemical reactions during mineralization.Organic gases(CH_4,C_2H_6,C_3H_8,C_2H_4,and C_6H_6) in the fluids were critical in the formation of barium sulfate versus carbonate.The δ~(34)S values of barite range from 38.26‰ to54.23‰(CDT),the δ~(34)S values of sulfides coexisting with barium minerals vary from 22.44‰ to25.11‰(CDT),and those in the wall rock from 11.60‰ to 19.06‰(CDT).We propose that the SO_4~(2-)generally experienced bacterial sulfate reduction in seawater before mineralization,and some SO_4~(2-)also experienced thermochemical sulfate reduction in hydrothermal system during mineralization.The δ~(13)C values of witherite range from-27.30‰ to-11.80‰(PDB),suggesting that carbon was sourced from organic substances(like CH_4,C_2H_4,and C_2H_6).The formation of witherite was possibly associated with thermochemical sulfate reduction,which caused the consumption of the organic gases and SO_4~(2-) in the hydrothermal solutions,consequently inhibiting barite formation.The important conditions for forming witherite include high fluid temperatures,high Ba~(2+) concentrations,CO_2 in the fluids,low HS~- concentrations,and the subsequent rapid diffusion of H_2S during thermochemical sulfate reduction of the fluids.     

Sulfur isotopic compositions of the Huize super-large Pb–Zn deposit, Yunnan Province, China: Implications for the source of sulfur in the ore-forming fluids

The Huize Pb–Zn deposit of Yunnan Province, China, is located in the center of the Sichuan–Yunnan–Guizhou Pb–Zn–Ag district. Four primary orebodies (orebody No. 1, No. 6, No. 8 and No. 10), with Pb + Zn reserves from 0.5 Mt to 1 Mt, have been found at depth in this deposit. This paper provides new data on the sulfur isotopic compositions of the four orebodies. The data show that the principal sulfide minerals (galena, sphalerite and pyrite) in the four orebodies are enriched in heavy sulfur, the δ³⁴S values between 10.9‰ and 17.7‰ and where δ³⁴S_pyrite > δ³⁴S_sphalerite > δ³⁴S_galena. The δ³⁴S values of sulfide are close to that of the sulfates from the carbonate strata within the region. The similarity in sulfur isotope composition between sulfides and sulfates indicates the sulfur in the ore-forming fluids was likely derived by thermochemical sulfate reduction of sulfates contained within carbonate units.     

Mud volcanic natural phenomena in the South Caspian Basin: geology,fluid dynamics and environmental impact

The South Caspian sedimentary basin is a unique area with thick Mesozoic-Cenozoic sediments (up to 30–32 km) characterized by an extremely high fluid generation potential. The large amount of active mud volcanoes and the volumes of their gas emissions prove the vast scale of fluid generation. Onshore and offshore mud volcanoes annually erupt more than 10⁹ cubic meters of gases consisting of CH₄ (79–98%), and a small admixture of C₂H₆, C₃H₈, C₄H₁₀, C₅H₁₂, CO₂, N, H₂S, Ar, He. Mud volcanism is closely connected to the processes occurring in the South Caspian depression, its seismicity, fluctuations of the Caspian Sea level, solar activity and hydrocarbon generation.The large accumulations of gas hydrates are confined to the bottom sediments of the Caspian Sea, mud volcanoes crater fields (interval 0–0.4 m, sea depth 480 m) and to the volcanoes body at the depth of 480–800 from the sea bottom. Resources of HC gases in hydrates saturated sediments up to a depth of 100 m and are estimated at 0.2×10¹⁵–8×10¹⁵ m³. The amount of HC gases concentrated in them is 10¹¹–10¹² m³.The Caspian Sea, being an inland closed basin is very sensitive to climatic and tectonic events expressed in sea level fluctuations. During regressive stages as a result of sea level fall and the reducing of hydrostatic pressure the decomposition of gas hydrates and the releasing of a great volume of HC gases consisting mainly of methane are observed.From the data of deep drilling, seismoacoustics, and deep seismic mud volcanic activity in the South Caspian Basin started in the Lower Miocene. Activity reached its highest intensity at the boundary between the Miocene and Pliocene and was associated with dramatic Caspian Sea level fall in the Lower Pliocene of up to 600 m, which led to the isolation of the PaleoCaspian from the Eastern ParaTethys. Catastrophic reduction of PaleoCaspian size combined with the increasing scale of mud volcanic activity caused the oversaturation and intoxication of water by methane and led to the mass extinction of mollusks, fishes and other groups of sea inhabitants. In the Upper Pliocene and Quaternary mud volcanism occurred under the conditions of a semi-closed sea periodically connected with the Pontian and Mediterranean Basins. Those stages of Caspian Sea history are characterized by the revival of the Caspian organic world.Monitoring of mud volcanoes onshore of the South Caspian demonstrated that any eruption is predicted by seismic activation in the region (South-Eastern Caucasus) and intensive fluid dynamics on the volcanoes.     

Geochemistry and genesis of brine emanations from Cretaceous strata of the Mamfe Basin, Cameroon

The geochemistry of 5 salt springs in the southwestern Mamfe Basin was investigated in order to infer the mineral content of their source and to relate the genesis of the springs to the local geology. Field observations revealed that, they are cold springs (23–28 °C), and are composed of secondary brines that are neutral to alkaline with pH values ranging from 7 to 8.7. Results of chemical analysis show that the springs contain major ions that form evaporite minerals, as well as chalcophile elements. The dominant cation is Na⁺ (>96%), and the dominant anion is Cl⁻ (>99%). Based on correlation coefficients between ions that form evaporites and field occurrence of efflorescences of halite, it is suggested that the ancient evaporites in the Mamfe Basin are composed entirely of carbonate and chloride salts. Meteoric and convective fluid flow processes are responsible for the dissolution of ancient evaporites and subsequent migration of brines to the surface from underground. The brines migrate through permeable strata with migration pathways resulting from a combination of fracture porosity created by post––Cretaceous tectonism and intergranular porosity enhanced by the chemically aggressive migrating brines.     

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.     

Gas systems in the Kuche Depression of the Tarim Basin: Source rock distributions, generation kinetics and gas accumulation history

Six petroleum source beds have been developed in the Kuche Depression (also known as “Kuqa Depression”) of the Tarim Basin, including three lacustrine source rocks (Middle and Upper Triassic Kelamayi and Huangshanjie formations, and Middle Jurassic Qiakemake Formation) and three coal measures (Upper Triassic Taliqike Formation, Lower Jurassic Yangxia Formation, and Middle Jurassic Kezilenuer Formation). While type I–II organic matter occurs in the Middle Jurassic Qiakemake Formation (J₂q), other source beds contain dominantly type III organic matter. Gas generation rates and stable carbon isotopic kinetics of methane generation from representative source rocks collected in the Kuche Depression were measured and calculated using an on-line dry and open pyrolysis system. Combined with hydrocarbon generation history modelling, the formation and evolution processes of the Jurassic–Triassic highly efficient gas kitchens were established. High sedimentation rate in the Neogene and the fast deposition of the Kuche Formation within the Pliocene (5 Ma) in particular have led to the rapid increase in Mesozoic source rock maturity, resulting in significant dry gas generation. The extremely high gas generation rates from source kitchens have apparently expedited the formation of highly efficient gas accumulations in the Kuche Depression. Because different Mesozoic source rocks occur in different structural belts, the presence of both lacustrine and coaly gas kitchens during the Cenozoic time can be identified in the Kuche Depression. As shown by the chemical and stable carbon isotope compositions of the discovered gases, the formation of the giant gas pools in the Kela 2, Dina 2, Yaha and Wucan 1 have involved very different geological processes due to the difference in their gas source kitchens.     

Geochemistry and episodic accumulation of natural gases from the Ledong gas field in the Yinggehai Basin, offshore South China Sea

The Ledong gas field, consisting of three gas pools in a shale diapir structure zone, is the largest gas discovery in the Yinggehai Basin. The gases produced from the Pliocene and Quaternary marine sandstone reservoirs show a considerable variation in chemical composition, with 5.4–88% CH₄, 0–93% CO₂, and 1–23.7% N₂. The CO₂-enriched gases often display heavier methane δ¹³C values than those with low CO₂ contents. The δ¹⁵N values of the gases range from −8 to −2‰, and the N₂ content correlates negatively with the CO₂ content. The high geothermal gradient associated with a relatively great burial depth in this area has led to the generation of hydrocarbon and nitrogen gases from the Lower–Middle Miocene source rocks and the formation of abundant CO₂ from the Tertiary calcareous-shales and pre-Tertiary carbonates. The compositional heterogeneities and stable carbon isotope data of the produced gases indicate that the formation of the LD221 gas field is attributed to three phases of gas migration: initially biogenic gas, followed by thermogenic hydrocarbon gas, and then CO₂-rich gas. The filling processes occurred within a short period approximately from 1.2 to 0.1 Ma based on the results of the kinetics modeling. Geophysical and geochemical data show that the diapiric faults that cut through Miocene sediments act as the main pathways for upward gas migration from the deep overpressured system into the shallow normal pressure reservoirs, and that the deep overpressure is the main driving force for vertical and lateral migration of the gases. This gas migration pattern implies that the transitional pressure zone around the shale diapir structures was on the pathway of upward migrating gases, and is also a favorable place for gas accumulation. The proposed multiple sources and multiple phases of gas migration and accumulation model for the Ledong gas field potentially provide useful information for the future exploration efforts in this area.     

Gas accumulation from oil cracking in the eastern Tarim Basin: A case study of the YN2 gas field

Oil and gas exploration in eastern Tarim Basin, NW China has been successful in recent years, with several commercial gas accumulations being discovered in a thermally mature to over-mature region. The Yingnan2 (YN2) gas field, situated in the Yingnan structure of the Yingjisu Depression, produces gases that are relatively enriched in nitrogen and C₂₊ alkanes. The δ¹³C₁ (−38.6‰ to −36.2‰) and δ¹³C₂ values (−30.9‰ to −34.7‰) of these gases are characteristic of marine sourced gases with relatively high maturity levels. The distributions of biomarkers in the associated condensates suggest close affinities with the Cambrian–Lower Ordovician source rocks which, in the Yingjisu Sag, are currently over-mature (with 3–4%Ro). Burial and thermal maturity modeling results indicate that paleo-temperatures of the Cambrian–Lower Ordovician source rocks had increased from 90 to 210 °C during the late Caledonian orogeny (458–438 Ma), due to rapid subsidence and sediment loading. By the end of Ordovician, hydrocarbon potential in these source rocks had been largely exhausted. The homogenization temperatures of hydrocarbon fluid inclusions identified from the Jurassic reservoirs of the YN2 gas field suggest a hydrocarbon emplacement time as recent as about 10 Ma, when the maturity levels of Middle–Lower Jurassic source rocks in the study area were too low (<0.7%Ro) to form a large quantity of oil and gas. The presence of abundant diamondoid hydrocarbons in the associated condensates and the relatively heavy isotopic values of the oils indicate that the gases were derived from thermal cracking of early-formed oils. Estimation from the stable carbon isotope ratios of gaseous alkanes suggests that the gases may have been formed at temperatures well above 190 °C. Thus, the oil and gas accumulation history in the study area can be reconstructed as follows: (1) during the late Caledonian orogeny, the Cambrian–Lower Ordovician marine source rocks had gone through the peak oil, wet gas and dry gas generation stages, with the generated oil and gas migrating upwards along faults and fractures to form early oil and gas accumulations in the Middle–Upper Ordovician and Silurian sandstone reservoirs; (2) since the late Yanshanian orogeny, the early oil accumulations have been buried deeper and oil has undergone thermal cracking to form gas; (3) during the late Himalayan orogeny, the seals for the deep reservoirs were breached; and the gas and condensates migrated upward and eventually accumulating in the relatively shallow Jurassic reservoirs.     

Hydrochemistry and hydrogen sulfide generating processes in the Malm aquifer,Bavarian Molasse Basin,Germany

Knowledge about the hydrochemical conditions of deep groundwater is crucial for the design and operation of geothermal facilities. In this study, the hydrochemical heterogeneity of the groundwaters in the Malm aquifer, Germany, is assessed, and reasons for the extraordinarily high H₂S concentrations in the central part of the Bavarian Molasse Basin are proposed. Samples were taken at 16 sites, for a total of 37 individual wells, to analyze cations, anions, gas loading and composition. The hydrochemical characteristics of the Malm groundwater in the center of the Molasse Basin are rather heterogeneous. Although the groundwater in the central basin is dominated by meteoric waters, there is a significant infiltration of saline water from higher strata. Care has to be taken in the interpretation of data from geothermal sites, as effects of chemical stimulation of the boreholes may not be fully removed before the final analyses. The distribution of H₂S in the gas phase is correlated to the gas loading of the water which increases in the central basin. Temperatures, isotopic data and the sulfur mass balance indicate that H₂S in the central basin is related to thermochemical sulfate reduction (south of Munich) and bacterial sulfate reduction (north of Munich).     

Origins of High H_2S-bearing Natural Gas in China

Natural gas containing hydrogen sulphide （H2S） has been found in several petroliferous basins in China, such as the Sichuan Basin, Bohai Bay Basin, Ordos Basin, Tarim Basin, etc. Natural gas with higher HES contents （HES 〉5 % mol.） is mostly distributed in both the gas reservoirs of Dukouhe, Luojiazhai, Puguang and Tieshanpo, which belong to the Triassic Feixianguan Formation in the northeastern Sichuan Basin and those of the Kongdian-Shahejie formations in the northeastern Jinxian Sag of the Jizhong Depression, Bohai Bay Basin. In the Sichuan Basin, the HES contents of natural gas average over 9% and some can be 17 %, while those of the Bohai Bay Basin range from 40 % to 92 %, being then one of the gas reservoirs with the highest H2S contents in the world. Based on detailed observation and sample analysis results of a total 5000 m of core from over 70 wells in the above-mentioned two basins, especially sulfur isotopic analysis of gypsum, brimstone, pyrite and natural gas, also with integrated study of the geochemical characteristics of hydrocarbons, it is thought that the natural gas with high HES contents resulted from thermochemical sulfate reduction （TSR） reactions. Among them, the natural gas in the Feixianguan Formation resulted from TSR reactions participated by hydrocarbon gas, while that in the Zhaolanzhuang of the Jinxian Sag being the product of TSR participated by crude oil. During the consumption process of hydrocarbons due to TSR, the heavy hydrocarbons were apt to react with sulfate, which accordingly resulted in the dry coefficient of natural gas increasing and the carbon isotopes becoming heavier.     

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.     

Carbon isotopes of Middle–Lower Jurassic coal-derived alkane gases from the major basins of northwestern China

Coal-derived hydrocarbons from Middle–Lower Jurassic coal-bearing strata in northwestern China are distributed in the Tarim, Junggar, Qaidam, and Turpan-Harmi basins. The former three basins are dominated by coal-derived gas fields, distributed in Cretaceous and Tertiary strata. Turpan-Harmi basin is characterized by coal-derived oil fields which occur in the coal measures. Based on analysis of gas components and carbon isotopic compositions from these basins, three conclusions are drawn in this contribution: 1) Alkane gases with reservoirs of coal measures have no carbon isotopic reversal, whereas alkane gases with reservoirs not of coal measures the extent of carbon isotopic reversal increases with increasing maturity; 2) Coal-derived alkane gases with high δ¹³C values are found in the Tarim and Qaidam basins (δ¹³C₁: − 19.0 to − 29.9‰; δ¹³C₂: − 18.8 to − 27.1‰), and those with lowest δ¹³C values occur in the Turpan-Harmi and Junggar basins (δ¹³C₁: − 40.1 to − 44.0‰; δ¹³C₂: − 24.7 to − 27.9‰); and 3) Individual specific carbon isotopic compositions of light hydrocarbons (C_5–8) in the coal-derived gases are lower than those in the oil-associated gases. The discovered carbon isotopic reversal of coal-derived gases is caused by isotopic fractionation during migration and secondary alteration. The high and low carbon isotopic values of coal-derived gases in China may have some significance on global natural gas research, especially the low carbon isotope value of methane may provide some information for early thermogenic gases. Coal-derived methane typically has much heavier δ¹³C than that of oil-associated methane, and this can be used for gas–source rock correlation. The heavy carbon isotope of coal-derived ethane is a common phenomenon in China and it shed lights on the discrimination of gas origin. Since most giant gas fields are of coal-derived origin, comparative studies on coal-derived and oil-associated gases have great significance on future natural gas exploration in the world.