Gas Genesis Research Articles

Differences in the Genesis and Sources of Hydrocarbon Gas Fluid from the Eastern and Western Kuqa Depression

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ13C1, δ13C2 and δ13C3 values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO2 in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH4) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH4 from highly evolved, underlying coal-bearing source rocks. Consequently, the CH4 content in the mixed gas is generally high (Ln (C1/C2) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area.

Natural Gas Geochemistry in Jambanan Area, Sidoharjo, Sragen, Central Java, Indonesia

Natural gas was encountered on PAMSIMAS well drilling in the Jambanan area. Geochemical studies are needed to determine gas genesis in this area. Geochemical studies were carried out using the GC gas composition method on gas samples located at three locations, namely SRG-01, SRG-02, and SRG-03. The three gas samples had a methane content of 47.61 - 87.97mol.%. All three have a low wettability level (0.03-0.05%) which indicates that the gas is very dry. GC-IRMS Method was also used on SRG-01 and SRG-02 gas sample. Those gas samples have δ13C Methane characteristics of -40.7‰ (SRG-01) and -45.6‰ (SRG-02) with δD methane values ​​of -171‰ (SRG-01) and -178‰ (SRG-02). This shows that the gas at those are thermogenic gas and it comes from different levels of maturity, where the gas at SRG-01 is more mature than the gas at SRG-02.

Helium resource and play classification systems, effective reservoir control elements, and enrichment patterns in China

The classification system, effective reservoir control elements, and major enrichment and exploration modes of helium resources in China are analyzed based on the source of helium, carrier, geological background, and anatomy of typical helium-rich fields. Firstly, based on the special characteristics of helium and the correlation analysis of natural gas accumulation and reservoir formation, we analyzed and sorted out the helium resource and play type classification scheme and classification system in China from nine aspects, namely, the source of helium parental sources, helium type diversities, the storage and carrier types, the technically and economically recoverable characteristics of carrier gases, the carrier gas genesis, the main components of carrier gases, the matching combination of helium sources and reservoirs, background of prototype basin structure, and helium content, to lay the foundation for the subsequent targeted and detailed studies and evaluation programs in different categories. Secondly, the analysis points out the characteristics of helium resource types in the east, middle, and west of China in terms of longitudinal and transverse distribution, tectonic dynamics, geological and geochemical characteristics, and key conditions for the formation of helium deposits. Thirdly, from the perspective of the helium “generation-migration-accumulation” system and the controlling elements and effectiveness of helium-rich reservoir formation, we analyze the effective controlling elements of helium accumulation and the related problems that deserve attention in geological evaluation and point out the misunderstandings in helium reservoir formation and exploration evaluation. Last but not least, from the perspective of basin tectonic background, helium enrichment controlling mechanism and exploration direction, the exploration and evaluation direction and classification scheme for the four element combination zones of “original basin–structure–lithology–carrier gas” helium accumulation in China have been proposed, based on which, four types of basins and eight types of helium-rich zones in China have been sorted out. In these eight types of helium-rich zones, eight typical helium-rich field enrichment and exploration patterns, including the ancient uplift type of China's craton, fracture-fold variant of the craton margin, fracture-rise type of depression basin, slope bulge and uplift type of foreland basin, fracture-convex type of fracture basin, and U/Th-rich basement type of basin were analyzed, and the main controlling factors of the formation of different types of helium-rich deposits were analyzed, which will provide a reference for the subsequent exploration and discovery of similar helium-rich areas and exploration target evaluation.

Geochemistry and accumulation of the ultra-deep Ordovician oils in the Shunbei oilfield, Tarim Basin: Coupling of reservoir secondary processes and filling events

Ultra-deep (7300 m–8900 m) condensed and volatile oil reservoirs have been discovered in the Ordovician reservoirs of the Shunbei oilfield, in the Tarim Basin. This study describes the petroleum accumulation process in the Shunbei oilfield by combining an analysis of its geochemical characteristics with seismic section observations and an analysis of petroleum filling events. Geochemical techniques are used to determine the sources, maturity, secondary processes, accumulation periods, and timing of petroleum filling. Analysis of fluid inclusion homogenization temperatures and burial-thermal histories indicates distinct petroleum filling events. Specifically, the north sub-section of the No. 5 fault zone experienced two petroleum filling periods during the late Caledonian and Indosinian epochs while the No. 1 fault zones and the mid-south sub-sections of the No. 5 fault zones experienced three distinct filling periods, encompassing the late Caledonian, Indosinian, and Himalayan periods. The CO2 concentrations and δ13CCO2 values suggest the presence of secondary microbial gases, primarily thermogenic gases. Gas component analysis reveals a transition from kerogen degradation gas to oil cracking gas from north to south. The detection of intact n-alkanes and compounds of the 25-norhopanes series in oil samples suggests a mixture of early biodegradable oil with late fresh oil in the area. Seismic sections reveal diabase intrusions with strong axial reflections. Local hydrothermal activities during the Permian era rapidly cracked saturated hydrocarbon biomarkers, forming polycyclic aromatic hydrocarbons in the oil. Hydrothermal activity in the south sub-section of the No. 5 fault zone depleted the hydrocarbon-generating capacity of the underlying source rocks. Petroleum charged during the Indosinian period likely originated from potential petroleum reservoirs in the Cambrian system. This explains the comparatively low temperature of the SHB57X reservoir (163.32 °C) and the lack of strong hydrothermal activity in the late stage, but no biomarkers of the second-stage charged oil have been detected. Biomarker detection and gas genesis in the mid-south sub-section of the No. 5 fault zone and in the No. 1 fault zone suggest weak or no hydrothermal activity, with Cambrian source rocks maintaining their hydrocarbon generation capacity. Gas filling in the Himalayan period caused evaporative fractionation in the original reservoirs, resulting in a disproportionate (2-MH+2,3-DMP)/(3-MH+2,4-DMP), producing high K1 values in the light hydrocarbons in the present petroleum reservoirs. Differences in gas charging events in the Himalayan period led to the present distribution of petroleum phases.

Combining methane clumped and bulk isotopes, temporal variations in molecular and isotopic composition, and hydrochemical and geological proxies to understand methane's origin in the Ronda peridotite massifs (Spain)

In serpentinised peridotite and ultramafic rock systems, methane (CH4) origin is frequently considered abiotic, but variable microbial and thermogenic components can also exist. Typically, the origin of CH4 is studied using bulk, 13C/12C and 2H/H isotopic composition, molecular gas composition, occasionally radiocarbon (14C), microbiology and geological context. Recent advances in CH4-clumped isotope methods have yielded novel insights into the formation of CH4: nonetheless, their interpretation in natural gas samples is often uncertain and requires additional research. Here, we study the origin of the gas released in hyperalkaline (pH > 10) springs in the Ronda Peridotite Massifs (southern Spain), combining bulk and clumped CH4 isotopes with molecular gas composition, hydrochemical (Total Organic Carbon and Platinum Group Elements in water), geothermal and geo-structural data. Five springs analysed in 2014 have been re-examined for changes in gas chemistry over time, and three newly discovered gas-bearing springs are analysed for the first time. Regardless of whether springs have microbial or abiotic isotopic fingerprints, we find that bulk CH4 isotopes are fairly stable over a seven-year period. This suggests that the CH4 source(s) or postgenetic processes (such as oxidation and diffusion) have not undergone significant temporal changes. Major variations in H2 and CH4 concentrations in certain springs may be the result of changes in gas pressure and migration intensity. Paired CH4 clumped isotopes (Δ12CH2D2 - Δ13CH3D) were analysed in two bubbling springs, where the presence of CH4 can be interpreted as non-microbial based on 13C enrichment, absence of 14C, and the presence of ethane and propane. However, these isotopes are in disequilibrium, which prevents the quantification of the gas formation temperature. Within the Δ12CH2D2 - Δ13CH3D diagram, the data lie within both the microbialgenic zone, suggested by previous authors, and the abiotic zone that results combining data from laboratory gas synthesis and other natural gas samples. Therefore, attributing a microbial origin to CH4 based only on clumped isotopes is less definite than previously assumed. The amount of Total Organic Carbon appears to be correlated with the origin of CH4, as it is higher in 13C-depleted CH4 samples and lower in 13C-enriched samples. Palladium (Pd) and Rhodium (Rh) dissolved in water (the more soluble Platinum Group Elements) can be a proxy for the chromitite ore deposits contained in plagioclase tectonite layers throughout the investigated area, which may act as catalysts for abiotic CO2 hydrogenation. Clumped isotope disequilibrium and the reported absence of diffuse CH4-bearing fluid inclusions in the peridotites appear to rule out high temperature gas genesis in post-magmatic inclusions. These observations, along with the moderate temperatures at the base of the peridotite massifs and the consistent occurrence of gas along tectonic contacts between serpentinised (H2-bearing) peridotite and carbon-bearing rocks, are compatible with the theory of low-temperature CO2 hydrogenation.

Significance of organo-mineralogical constituents on pore distribution, fractals and gas sorption mechanism of Permian shale beds in Korba sub-basin of the Son-Mahanadi Valley, India

In this study, shale samples obtained from the Korbasub-basin of Central India have been evaluated for the significance of organo-inorganic constituents in terms of their source potential of gas genesis, pore-matrix setup, and gas adsorption and desorption. The samples were analysed for various properties, such as megascopic features, lithological variations, depositional facies, and sources of organic and inorganic sediments. Also, maceral content, mineralogical constituents, kerogen type, pore distribution, pore structure, fractal characteristics and gas storage capacity were examined. The analysis revealed a trend of alternating bands of carbonaceous matter, silts, intercalations, and fluvial bedding lithofacies patterns indicating that the sediments were deposited under fluvio-terrestrial-lacustrine depositional conditions. Ternary facies analysis of maceral composition and van Krevelen diagram suggested the evolutionary path of type IV kerogen and are thermally matured source material located within the dry hydrocarbon generation window. Evaluation of pore types and pore structures using BET sorption plots (hysteresis H3 and isotherm type IV) revealed the presence of cylindrical, slit and combined cylindrical-slit pores with two distinct fractal characteristics. The discrete macerals underwent partial decomposition during transportation and mixing with inorganic components (clay and minerals), which influenced organic matter preservation, gas genesis, pore fractals and storage mechanism. The chemical index of alteration (CIA – 88.36 to 91.97), weathering (CIW – 96.60 to 98.80) and compositional variation (ICV – 0.31 to 0.70) demonstrated the influence of partial decomposition and strong weathering patterns on the organo-inorganic matter. A significant correlation was observed between pore fractals and elemental composition, particularly related to the resistance of weathering elements such as MgO, Al2O3, Fe2O3, SiO2, P2O5, TiO2, etc., which partially contributed to the formation of pore rugged surfaces. Microscopic and XRD analyses were employed to determine the mineral type, grain shape and size, and their amount leading to the development of the shales brittleness index (MBI). The importance of brittle characteristics, governed by minerals and clays within the shale, is discussed in relation to the hydro-fracturing technique for permeability enhancement. The results of high-pressure methane sorption indicated a moderate gas storage potential. The variation in sorption capacity (VL – 6.65 to 8.25 cc/g) is described through relationships with the ICV, pore diameter, pore volume, liptinite and total maceral content. Fractal dimensions D1 (2.4571–2.5611) and D2 (2.5804–2.7529) exhibited a direct relationship with adsorption properties, indicating the presence of rugged surfaces associated with meso- and macro-scale pores, which primarily control gas storage in shale. This research offers detailed insights into shale gas, providing valuable information for CBM and petroleum operators engaged in methane gas exploration and production. While commercial CBM production has been ongoing in India for over a decade, the exploration and understanding of shale gas reservoir characteristics are still in progress. This investigation adds significant value and highlights the extensive opportunities for research and potentially commercially recovering shale gas in the Korba sub-basin.

Natural Gas Genesis, Source and Accumulation Processes in Northwestern Qaidam Basin, China, Revealed by Integrated 3D Basin Modeling and Geochemical Research

Natural Gas Genesis, Source and Accumulation Processes in Northwestern Qaidam Basin, China, Revealed by Integrated 3D Basin Modeling and Geochemical Research

Carbon-hydrogen isotopic systematics of gases generated in semi-closed hydrous pyrolysis of type I source rock with the presence of formation water: Implications for gas isotope partitioning under supercritical conditions

Hydrocarbon gas is a significant type of clean energy, and understanding its carbon-hydrogen (C–H) isotopic behaviour during hydrocarbon generation is essential for determining the gas genesis. Hydrous pyrolysis is an artificial method to simulate natural gas generation process with the presence of water. Formation water is a type of ubiquitous saline water in oilfields, whereas not commonly utilized in hydrous pyrolysis. To determine the influence of formation water on C–H isotopic systematics of hydrocarbon gas (methane, ethane and propane), two series of semi-closed hydrous pyrolysis experiments were conducted in 275–550 °C for the type I Green River Shale source rock using distilled water and formation water. Hydrocarbon gases generated in two series of experiments have similar δ13C ratios yet slightly different δD ratios at individual temperatures, which is likely attributed to the water-organic interaction as formation water has a different δD ratio compared to distilled water. The δ13C and δD ratios of gas increase with the rising of thermal maturity level, and exhibit quadratic correlations with vitrinite reflectance (VR) values in both series of experiments. The presence of supercritical water in hydrous pyrolysis does not significantly affect the gas C–H isotopic partitioning behaviour because gases collected below and above the critical temperature (374.2 °C) display consistent δ13C (δD)-VR patterns. Partial C–H isotopic reversals (δ13C2>δ13C3, δD2>δD3 or δD1>δD2) are observed during the pre-oil to oil generation peak and gas generation stages, which are likely mainly affected by gas mixing as evidenced by rigorous correlations between δ13Cn (δDn) ratios and reciprocals of the gas proportion (1/Cn).

Physical characteristics and gas genesis of the C25 coal reservoir in the Guxu colliery in the South Sichuan coalfield

Physical characteristics and gas genesis of the C25 coal reservoir in the Guxu colliery in the South Sichuan coalfield

Petrographic and Geochemical Controls on Methane Genesis, Pore Fractal Attributes, and Sorption of Lower Gondwana Coal of Jharia Basin, India.

The Barakar coal seams of Jharia Basin have been evaluated for the geochemical and petrographic control of coalbed methane (CBM) reservoir characteristics. The coal core samples are analyzed for the total gas content, gas chromatography, stable isotopes (δ13C1), and geochemical, petrographic and vitrinite reflectance. The significant face (1.6–7.6%) and butt (0.9–5.3%) cleat intensities specify the brittle characteristics of coal seams and also favor the gas flow mechanism. The thermal cracking position of hydrocarbon compounds was evaluated, which signifies the excellent source rock potential of coal for gas genesis. The inputs of type III and IV organic matter illustrated by the van Krevelan diagram signify thermally matured coal seams. The low values of sorption time (τ) between 2.1 and 5.6 days designate excellent diffusion characteristics that is favored by the cleat intensities. The values of total gas content and sorption capacity (VL) reveal that moderate saturation indicates a higher gas content, attributed to the seam thickness and thermal maturity. Similarly, the CH4 concentrations (89.4–96.6 vol %) display that the genesis pattern is a function of thermal maturity; however, some samples fall under the mixed type substantiated by the stable isotope (δ13C1) (−25.40 to −64.90‰), emphasizing bacterial hold by seasonal influx of freshwater. The ternary facies diagram (Vmmf, Immf, Lmmf) also supports notable generation of methane gas and storage in the coal seams of the Jharia Basin. The volume percentage of each maceral determined from petrographic study was used to estimate the fraction of conversion (f) of the organic content (0.19–0.97). The values of “f” indicate that the Barakar coal has undergone maximum conversion, which may be attributed to the older early Permian coal and placed at a greater depth after deposition due to the basin sink. The high fraction of conversion and thermal maturity may also be explained due to the existence of volcanic intrusion (sills and dykes). The uniformity in the distribution of functional groups is shown by Fourier transform infrared spectra representing moderate to stronger peaks of aromatic carbon (CO and C=C) between 1750 and 1450 cm–1, which indicates that the presence of a larger total organic carbon content likely validates the removal of aliphatic compounds during gas genesis. The variations in the BET curve have been categorized as H1 hysteresis following the type II adsorption pattern, suggesting that cylindrical pores and some of the coal samples have a type IV H4 hysteresis pattern, characterized as the slit type of pores. The average values of the pore diameter indicate the dominance of mesopores suitable for gas storage and release and hence a major part of the pore volume is contributed by the mesopores having a width mainly between 2.98 and 4.48 nm. The significant role of the meso-macropore network (D1 fractals) in methane storage of the coal matrix is represented by a moderate positive relationship of VL with D1, which accentuated that meso-macropores developed due to devolatilization and dehydration of organic matter and also by geochemical alteration of macerals and minerals formed heterogenetic inner surfaces suitable for gas adsorption. The estimated recoverable resource applying Mavor Pratt methods is 8.78 BCM, which is found to be a more realistic resource value for the studied CBM block.

Accumulation conditions and exploration directions of Ordovician lower assemblage natural gas, Ordos Basin, NW China

Based on drilling cores, well logging and seismic data, source rocks and reservoirs are evaluated; and the natural gas genesis is identified through the analysis of natural gas isotopes, components and fluid inclusions, to study the gas accumulation conditions of the gypsum salt rock related strata of the Ordovician lower assemblage in Ordos Basin. (1) The natural gas from Ordovician lower assemblage is high thermal evolution dry gas from marine source rock, characterized by relatively light δ 13 C value of methane and heavy δ 13 C value of ethane. The natural gas is identified as gas cracking from crude oil according to component analysis. Thermochemical sulfate reduction (TSR) reaction has happened between the hydrocarbon fluid and sulfate as sulfur crystals are found in the cores, hydrogen sulfide is found in the natural gas, and hydrocarbon and hydrogen sulfide fluid inclusions are widespread in secondary minerals. (2) Around the gypsum-salt lows, argillaceous rocks are extensive in the Ordovician lower assemblage, reaching a cumulative thickness of 20–80 m. The effective source rocks include argillaceous rock rich in organic laminae, algal clump and algal dolomite. Analysis shows that the source rocks have a dominant TOC of 0.1%–0.5%, 0.31% on average and 3.24% at maximum. The source rocks have an average TOC of 0.58% after recovered through organic acid salt method, indicating the source rocks have high hydrocarbon supply potential. (3) In the sedimentary period, the palaeo-uplift controlled the distribution of reservoirs. The inherited secondary palaeo-uplift in Wushenqi–Jingbian east of the central palaeo-uplift and the low uplift formed by thick salt rocks near Shenmu–Zizhou area controlled the distribution of penecontemporaneous grain shoal dolomite reservoirs. The salinization sedimentary environment of gypsum salt rock can promote the development of reservoir. There are three types of dolomite reservoirs, the one with intercrystalline pore, with dissolution pore, and with fracture; intercrystalline and dissolution pores are main reservoir spaces. (4) There are two types of cap rocks, namely tight carbonate rock and gypsum-salt rock, constituting two types of source-reservoir-cap assemblages respectively. The general accumulation model is characterized by marine source rock supplying hydrocarbon, beach facies limy dolomite reservoir, small fractures acting as migration pathways, and structural-lithologic traps as accumulation zones. (5) The third and fourth members of Majiagou Formation are major target layers in the lower assemblage. The Wushengqi–Jingbian secondary paleo-uplift area and Shenmu–Zizhou low uplift are dolomite and limestone transition zone, there develops tight limestone to the east of the uplift zone, which is conducive to the formation of gas reservoir sealed by lithology in the updip. Two risk exploration wells drilled recently have encouraging results, indicating that the two uplift zones are important prospects.

Occurrence of fluids in high dip angled coal measures: Geological and geochemical assessments for southern Junggar Basin, China

The Junggar Basin, Xinjiang has abundant coalbed methane (CBM) resources, and most of the CBM is found in the coal reservoirs with high dip angle (>50°), where the generation, accumulation and extraction of CBM significantly differs with flat coal reservoirs. This study clarifies the effect of high dip angle on the fluid pressure field, in situ stress field, permeability and gas bearing capacity of CBM reservoir in the southern Junggar Basin. The studies show that the high dip angle results in the fluid pressure differentiation of CBM reservoirs at 800–1000 m. The shallow opened fluid pressure system is in an ultralow-normal pressure state, while the deep closed system is characterized by overpressure. The self-sealing property of high dip CBM reservoirs can prevent the gas escaping upward along the inclined bedding. The larger the dip angle, the higher the gas column sealed by the self-physical property. The overburden compaction is reduced for dip formation, which causes the in situ stress of inclined coal seam to decrease but the anisotropy to increase. Furthermore, the high dip angle decreases the gas content per meter of coal seam, and diversifies the gas genesis, which causes the secondary biogenic gas to generate in the shallow seam under the effect of active hydrodynamics, and the thermogenic gas to be better accumulated in the deep coal seam. Due to the desorption hysteresis of the coal seam in downdip direction, the gas production curve of high dip coal seam has obvious bimodal characteristics, and the second peak is significantly higher than the first.

Insights of Cleat Attribute of Barakar Coal Deposits of Son Valley Basin, India: Implication for Coal Bed Methane Exploration

Cleat attributes and coal quality have been evaluated through field observation, SEM images analysis and proximate-ultimate analyses on representative coal samples collected from four different underground coal mines of Son-Valley coal Basin of central India for the characterization of coal bed methane prospective. The coal samples were characterized as durainic-clarodurainic-vitrainic type to durocalrainic-clarainic type based on litho-type composition. Cleats were identified as face cleat and butt cleat range 5-10 cm-1 to 2–3 cm-1 depending on the litho-types whereas, cleat density ranges 7-16 cm-2 revealed that cleat development is influenced by litho-types. The cleat orientation shows two main strikes almost NW-SE to NNW-SSE and NE-SW to ENE-WSW elucidates the face cleat and butt cleats are perpendicular to each other. SEM images for coal samples were analysed to validate the cleat geometry at micro-scale, illustrates that face cleat and butt cleats are orthogonal to each other. The technological properties viz. moisture (Wa), volatile matter yield (VMdaf) ash yield (Ad) of coal samples are placed in the range of 0.66–11.80, 32.0–50.05 and 13.23–43.73 wt.% respectively. The fuel ratios of all the samples varied from 1.05–2.35 indicating that coal samples were of sub-bituminous to bituminous rank. The carbon and hydrogen (Cdaf, Hdaf) content of samples ranges from 68.89–86.08 and 5.22–6.60 wt.% respectively. The atomic ratio H/C and O/C through van-Krevelen diagram demonstrate the predominance of type-III/IV kerogens usually derived from terrestrial source in studied coal belongs to the gas genesis window.

Effect of organic maturity on shale gas genesis and pores development: A case study on marine shale in the upper Yangtze region, South China

Abstract The marine shale in southern China has undergone complex tectonic evolution with a high thermal evolution degree. Excessive thermal evolution brings certain risks to shale gas exploration and development. With the advancement of experimental methods, the evolution process of shale reservoirs can be better understood from the micro-nanoscale. This work takes the Ordovician-Silurian Wufeng and the first member of Longmaxi Formation in the Sichuan Basin and Lower Cambrian Niutitang Formation in Outer Margin of the Sichuan Basin to study the impact of maturity upon the genesis of shale gas and development features of the reservoir. A series of geochemical research methods, including TOC, gas component and gas isotope, were adopted to study the impact of different thermal evolution stages of organic matter upon the genesis of shale gas. The nanoscale micro-imaging technique, such as FIB-SEM and FIB-HIM, was used to analyze the development of OM-hosted pores. As shown from the results, when R o = 1.2–3.5%, the marine shale gas is dominated by methane and other hydrocarbon gases, since the mixture of cracking gas from liquid hydrocarbons and kerogen-cracking gas cause the carbon isotope reversal. Besides, the pyrobitumen pores characterized by the strong connectivity and storage capacity were primarily developed. When R o > 3.5%, the organic matter is at the graphitization stage. The shale gas is mainly composed of nitrogen at this stage. The nitrogen is originated from the atmosphere and the thermal evolution process, and the OM-hosted pores (pyrobitumen and kerogen pores) characterized by the bad connectivity and storage capacity are developed. Finally, the main component of shale gas, the genesis of shale gas and the pattern of OM-hosted pores under different thermal evolution stages of organic matter are summarized, which provide technical support for the exploration and development of shale gas.

Geochemical characteristics and genesis of the Upper Paleozoic natural gas in Longdong area, Ordos Basin, NW China

The Upper Paleozoic gases from the Longdong areas in the Ordos Basin are characterized by low contents of heavy hydrocarbon gases, the mean value of wetness as 2%, relatively heavy δ13C1(δ13C1 value -28.3‰), and large variations in δ13C2 +. The distribution pattern of carbon isotopic sequence of natural gas is mainly characterized by the abnormal light δ13C2 + values and carbon isotopic reversal. According to the organic geochemical characteristics of natural gas and the development of gas-source rocks, the upper Paleozoic natural gas in Longdong area belongs to high mature and over-mature “coal-formed gas”. In theory, only the mixture of highly mature gas with extremely low contents of heavy hydrocarbon gases and a small amount of natural gas with higher contents and lighter carbon isotopic composition of heavy hydrocarbon gases can lead to the occurrence of abnormally light δ13C2 + and the carbon isotope reversal between methane and ethane. The mixed gas is probably derived from the thermal cracking of a small amount of residual soluble organic matter in the gas-source rocks and reservoirs during the initial stage of the uplift movement at the end of Early Cretaceous. Key words: Ethane carbon isotope; Inverted sequence of carbon isotopic composition; Natural gas of high maturity; natural gas genesis; Ordos Basin.

Structure- and hydrology-controlled isotopic coupling and heterogeneity of coalbed gases and co-produced water in the Yanchuannan block, southeastern Ordos Basin

Gas and water geochemistry in the No.2 coal reservoir of the Yanchuannan CBM block in the southeastern Ordos basin reflects a complex interaction of tectonic, hydrodynamic, thermogenic, and biogenic processes. Stable isotope and component analyses of gas and water samples from the No. 2 coal seam of 17 CBM wells were performed to determine the correlations between stable isotopes of gases and co-produced water, and to understand the controls of structure and hydrology on isotope distribution. The results show that the co-produced water continuously ranges from brackish, isotopically lighter Na-HCO3/Na-HCO3-Cl water to hypersaline, isotopically heavier Na-Cl/Na-Ca-Cl brine. Based on the hydrochemical features, fault development, and burial depth of coal seam, four structure-controlled hydrodynamic zones are distinguished, including strong through-flow, medium through-flow, weak through-flow, and stagnant zones. The gas isotope analysis shows that thermogenic methane is the dominant source of CBM, and secondary biogenic gases only exist in the strong through-flow zone. δ2H-CH4 is ultimately inherited from formation water, and more 2H can be transferred during the formation of thermogenic gases. δ13C-CH4 and δ13C-CO2 are mainly controlled by thermal maturity and gas genesis respectively, and there is a negative correlation between them. The stable isotopes of coalbed gases and water show strong spatial heterogeneity with the changing hydrodynamic strength. Owing to the influence of water recharge, gas leakage, and secondary biogas formation, the strong through-flow zone is characterized by the most negative δ13C-CH4, δ2H-CH4, δ18O-H2O, δ2H-H2O and the most positive δ13C-CO2, Δ2H-(H2O-CH4) and Δ13C-(CO2-CH4). However, the stagnant zone has maintained stable in a long geological period, which leads to the high concentration of original connate water and mass preservation of coalbed gases, and hence its isotopic feature is completely opposite to the strong through-flow zone. This study confirms the significant controls of hydrogeological conditions on the migration of water and gas and the application of isotopic indicators in the exploration of deep CBM.

Effects of igneous intrusions on source rock in the early diagenetic stage: A case study on Beipiao Formation in Jinyang Basin, Northeast China

Abstract Mesozoic intrusive bodies play an important role in the temperature history and hydrocarbon maturation of the Jinyang Basin in northeastern China. The Beipiao Formation, which is the main source rock in Jinyang Basin, was intruded by numerous igneous bodies and dykes in many areas. The effects of igneous intrusive bodies on thermal evolution and hydrocarbon generation and migration in the Beipiao Formation were investigated. A series of samples from the outcrop near the intrusive body were analyzed for vitrinite reflectance (R 0%) and other organic geochemical parameters to evaluate the lateral extension of the thermal aureole. The R 0 values of the samples increase from a background value of ∼0.9% at a distance above 200 m from the intrusive body to more than 2.0% at the vicinity of the contact zone. The width of the altered zone is equal to the thickness of the intrusive body outcropped in the field. Organic geochemical proxies also indicate the intrusive body plays a positive and beneficial role in the formation of regional oil and gas resources. Due to the influence of the anomalous heat from the intrusive body, the hydrocarbon conversion rate of the source rocks of the Beipiao Formation was significantly improved. The accumulation properties and the storage capacity of the shales also greatly improved due to the intrusive body as indicated by the free hydrocarbon migration in the shales. This new understanding not only provides a reliable scientific basis for the accurate assessment of oil and gas genesis and resources in the Jinyang Basin but also provides guidance and reference for oil and gas exploration in the similar type of basin.

Изотопно-геохимические показатели глубинности процессов нефтегазообразования и нефтегазонакопления

Изотопно-геохимические показатели глубинности процессов нефтегазообразования и нефтегазонакопления

Characteristics of Permian volcanism in the western Sichuan Basin and its natural gas exploration potential

It was previously deemed that volcanic rocks in the western Sichuan Basin were not developed, which restricted the exploration of volcanic gas reservoirs in this area. Recently, however, Sinopec's wildcat well, Well YS1 encounters Upper Permian volcanic rocks about 300 m thick in the western Sichuan Basin, the reservoir physical properties of which are good with strong gas shows. In order to evaluate the exploration prospect of volcanic gas reservoirs in western Sichuan Basin, we studied the Permian volcanic rocks in this area from the aspects of formation and development characteristics, reservoir characteristics, gas genesis and plays based on the new understandings on exploration wells, combined with the analysis on tectonic evolution and its controlling effect on volcanism. Then, the volcanic eruption mechanism, the distribution mode of volcanic edifice and the hydrocarbon accumulation pattern of volcanic gas reservoir were figured out. Finally, the exploration potential of natural gas was evaluated. The following research results were obtained: (1) the Permian volcanic rocks in western Sichuan Basin are well developed and its tectonic setting is consistent with that of Emeishan basalt, which is the product of the Emeishan mantle plume. (2) Under the control of vertical faults, a great number of volcanic edifices are developed and there are many eruption cycles. Volcanic rocks are superimposed vertically and connected laterally. (3) The volcanic rocks in western Sichuan Basin are different to some extent from those in southwestern Sichuan Basin in terms of lithology, lithofacies and reservoir characteristics. In the western Sichuan Basin, the tuff of explosive facies is dominant with some basalt of effusive facies, and the reservoir space of volcanic rocks is mainly acted by inter-breccia skeletal pores, dissolved pores and matrix micro-pores. In conclusion, multiple sets of effective source rocks are developed around the volcanic intervals in western Sichuan Basin, and together they constitute effective natural gas plays. Therefore, it has a better natural gas exploration prospect, and it is a new field worthy of attention.

Technical strategies for effective development and gas recovery enhancement of a large tight gas field: A case study of Sulige gas field, Ordos Basin, NW China

Abstract Based on the analysis of influencing factors of tight gas recovery and reservoir geological characteristics, the types of remaining tight gas reserves in the Sulige gas field are summarized from the perspective of residual gas genesis to estimate residual gas reserves of different types and provide corresponding technical strategies for enhancing gas recovery. The residual gas reserves in the Sulige gas field can be divided into four types: well pattern uncontrollable, horizontal well missing, imperfect perforation, blocking zone in composite sandbodies. Among them, the uncontrolled remaining gas of well pattern and blocking zone in composite sandbodies are the main body for tapping potential and improving recovery factor, and well pattern infilling adjustment is the main means. Taking into account reservoir geological characteristics, production dynamic response and economic benefit requirements, four methods for infilling vertical well pattern, i.e., quantitative geological model method, dynamic controlled range of gas well method, production interference method and economic and technical index evaluation method, as well as a design method of combined vertical well pattern with horizontal well pattern are established. Under certain economic and technological conditions, the reasonable well pattern density of enrichment zone of gas field is proved to be 4 wells per square kilometers, which can increase the recovery rate of the gas field from 32% to about 50%. Meanwhile, five matching techniques for enhancing gas recovery aimed at interlayer undeveloped residual gas have been formed, including tapping potential of old wells, technological technology optimizing of new wells, rational production system optimizing, drainage and gas producing, and reducing waste production, which could increase the recovery rate for 5% based on well pattern infilling. The research results provide effective support for the long-term stable production of 230×108 m3/a of the Sulige gas field and production growth in the Changqing gas area.