Heavy Hydrocarbon Gas Research Articles

Geochemical Characteristics and Geological Significance of Coalbed Methane in Suzhou Mining Area of the Huaibei Coalfield.

In this study, gas contents, geochemical features, and origins of coalbed methane (CBM) and their influence factors were investigated on nos. 7 and 8 CBM reservoirs from the Suzhou mining area of the Huaibei coalfield. Results have shown that the selected CBM reservoirs are characterized by various thickness (0.50-9.19 m) and buried depth (619-1226 m), but have relatively better lithology of surrounding rocks. Coal samples have similar maturity (Ro,max = 0.71-1.05%), but show differences in chemical composition and macerals. Gas content of nos. 7 and 8 CBM reservoirs ranges from 6.13-12.25 m3/t, but the value of former is lower than that of later one overall. In addition, CH4 is a predominantly component with a value of 88.23-99.00% (avg. 96.69%), and the heavy hydrocarbon gas (C2+) is 0.00-1.93% (avg. 0.41%). The δ13CCH4 value ranges from -64.54 to -46.36‰ (avg. -53.92‰), and the δ13DCH4 value is -224.36 to -211.75‰ (avg. -219.09‰). Based on the analysis of components and isotopic values, the CBM samples are thermogenic (20.92-71.30%; avg 50.09%) and secondary biogenic gases (28.70-74.49%; avg. 49.91%). Gas content shows changeable characteristics at a buried depth of 300-1300 m, which is affected by buried depth, reservoir temperature and pressure, Mad and vitrinite. However, the CH4 concentration shows no correlation with buried depth. Moreover, the buried depth is significantly positively correlated to δ13CCH4 and δ13DCH4. Based on the relationship between gas content and isotope values, it suggests that δ13CCH4 or δ13DCH4 may have a relationship with the main controlling factors of gas content.

Desorption Characteristics of CH4-C2H6 Mixed Gas in Heavy Hydrocarbon-Rich Coal Seams.

The gas desorption characteristics of coal are closely related to the gas content of the coal seam. The gas in heavy hydrocarbon-rich coal seams contains CH4 and C2H6 heavy hydrocarbons. However, most current research on the gas desorption characteristics of coal seams focuses on CH4 analysis, ignoring the influence of the C2H6 heavy hydrocarbon gas. To accurately determine the gas content of a heavy hydrocarbon-rich coal seam, methods based on CH4 analysis are inadequate and the desorption characteristics of CH4-C2H6 mixed gas must be clarified. This work experimentally and theoretically studies the desorption characteristics of single-component gas and CH4-C2H6 mixed gas from coal samples. The results show that increasing the adsorption-equilibrium pressure was found to increase the desorption quantity and desorption speed of single-component gas and increase the desorption quantity, desorption ratio, and diffusion coefficient of mixed gas. Under the same adsorption-equilibrium pressure, the desorption quantity and rate of single-component CH4 gas exceeded those of C2H6. The quantity and speed of mixed gas desorption increased with rising CH4 concentration and decreased with rising C2H6 concentration. The change in the mixed gas concentration during desorption reflects the distribution characteristics of light hydrocarbon components on the outer surface and heavy hydrocarbon components on the inner surface of coal. From the desorption characteristics of mixed gas, desorption models of mixed gas were obtained at different concentrations, laying a theoretical foundation for accurate determinations of gas contents in heavy hydrocarbon-rich coal seams.

Genesis and source of natural gas in Well Mitan-1 of Ordovician Majiagou Formation, middle-eastern Ordos Basin, China

The Well Mitan-1 has achieved a major breakthrough in the exploration of Ordovician subsalt natural gas in the mid-eastern Ordos Basin, demonstrating a high-yield industrial gas flow in fourth member of the Majiagou Formation of Ordovician (O1m4). Despite this success, there are ongoing disputes regarding the origin of the natural gas found in Well Mitan-1. Measured results show that the natural gas in Well Mitan-1 is mainly composed of alkane gas (95.18 %). The gas drying coefficient (C1/C1-5) is measured at 0.947, and the H2S content is 3.49 %, with a small amount of N2 and CO2 in the non-hydrocarbon gas. The carbon isotopic compositions of methane, ethane, and propane in the natural gas are −45.5 ‰, −26.4 ‰, and −24.3 ‰, respectively. Based on the regional geological background, the characteristics of potential source rocks and the geochemical characteristics of natural gas, it is considered that the natural gas in Well Mitan-1 is self-generated and self-accumulated oil-associated gas in Ordovician subsalt carbonate rocks. However, certain geochemical anomalies, such as the lighter methane carbon isotope value (δ13C1) and coal-type gas characteristics in ethane carbon isotope (δ13C2), raise questions. Further insights from thermal simulation experiments on hydrocarbon generation and the analysis of residual gas in rocks suggest a close relationship between the special geochemical characteristics of Well Mitan-1 and the presence of gypsum rocks. The ubiquitous gypsum rock serves a dual purpose: acting as an effective caprock, facilitating the retention of early-generated natural gas, and promoting the generation of heavy hydrocarbon gases (C2+) and H2S. The relatively low H2S content (less than 5 %) and higher C2+ content indicate that thermochemical sulfate reduction (TSR), if present, is not strong enough to significantly impact methane. The δ13C2 is identified as a potentially sensitive parameter for identifying TSR.

Experimental Characteristics of Hydrocarbon Generation from Scandinavian Alum Shale Carbonate Nodules: Implications for Hydrocarbon Generation from Majiagou Formation Marine Carbonates in China’s Ordos Basin

The hydrocarbon source rocks of the marine carbonates of the Ordovician Majiagou Formation in the Ordos Basin are generally in the high-overmature stage and are, therefore, not suitable for hydrocarbon thermal simulation experiments. Their hydrocarbon generation potential and hydrocarbon generation characteristics are not clearly understood. Meanwhile, Nordic Cambrian carbonates are similar in lithology, parent material type, and sedimentary age, and are in the low evolution stage, which is suitable for hydrocarbon thermal simulation experiments. Therefore, in this study, we selected the Nordic carbonates for the gold tube thermal simulation experiment to analyze the content and geochemical characteristics of the thermal simulation products. The experimental results are also compared and analyzed with the characteristics of thermal simulation products of Pingliang Formation mud shale (contemporaneous with the Majiagou Formation) and Shanxi Formation coal (in the upper part of the Majiagou Formation), which are similar to the Majiagou Formation in the Ordos Basin. The results showed that the Nordic carbonate has different hydrocarbon production characteristics from the mud shale of the Pingliang Formation of the same parent material type, and although the hydrocarbon production yields of the two are not very different, the carbonate still produces methane at 600 °C. The hydrocarbon production yield of the Nordic carbonates is almost equivalent to that of type-II2 kerogen, indicating that the hydrocarbon production yield is not related to lithology and only to the organic matter type; however, the Nordic carbonate can produce a large amount of H2S. The alkane carbon isotope changes are mainly controlled by the degree of thermal evolution, showing gradual heaviness with increasing temperature. No carbon isotope sequence reversal occurred during the thermal simulation, and its distribution range is roughly the same as that of the alkane carbon isotope composition of the mud shale of the Pingliang Formation. The ethane carbon isotope composition is as heavy as −21.2‰ at the high-temperature stage, showing similar coal-type gas characteristics. The addition of calcium sulphate (CaSO4) causes the TSR reaction to occur, which has a significant impact on the methane content under high maturity conditions, reducing its content by more than 50% at 600 °C. However, the addition of CaSO4 increases the yield of heavy hydrocarbon gases, such as ethane, and promotes the production of C6-14 hydrocarbons and C14+ hydrocarbons at high-temperature stages, and the addition of CaSO4 substantially increases the yield of H2, CO2, and H2S. The thermal simulation results have implications for the hydrocarbon formation mechanism of the early Paleozoic marine carbonate formation system in the stacked basins of the Ordos Basin and the Tarim Basin in China.

Molecular insights into the natural gas regulating tight oil movability

Unconventional reservoirs development by gas injection has gained extensive attentions in recent years. As an injector gas, natural gas is one of the most promising fluids that is used in EOR process. However, the effect of natural gas on tight oil movability in nano-pores is still ambiguous. In this study, molecular dynamics simulations have been employed to generate insights into the tight oil movability under different gas contents and gas types. Simulation results demonstrate that the higher the methane content, the lower the migration resistance of the system, despite the gradually decreased migration rate. By analyzing the dynamic pathway, threshold migration resistance, and interface characteristics, the optimum molar range of gas content range for mixing methane with tight oil is 0.4–0.6. On this basis, the effects of four kinds of heavy hydrocarbon gases were investigated. Compared with methane, the four heavy hydrocarbon gases have little effect on the migration resistance, but all four gases can significantly improve the oil-gas miscibility and migration rate. In addition, ethane and propane can further reduce the oil-gas-water IFT, and they are the best gases to promote tight oil migration. This study provides a more in-depth understanding of natural gas injection to develop tight oil.

Comparison of Geochemical Characteristics of Products from Thermal Simulation Experiments of Hydrocarbon Generation at Different Heating Rates in the Semiclosed System

Based on the thermal simulation experiment in a semiclosed system, the products of continental type II of the Chang 7 shale under slow and fast heating rates were studied. The results show that the yield of hydrocarbon gases (C1–C5) increases under the fast heating rate. Under the slow heating rate, the heavy hydrocarbon gas (C2–C5) begins to crack when the temperature exceeds 400 °C. The H2S and H2 have similar variation rules with hydrocarbon gases. Under the slow heating rate, the expelled oil is larger than that of the fast heating rate. C15+ constitutes the main component of retained oil, and the yield of retained oil at the fast heating rate is larger than that of the slow heating rate, which is different from the expelled oil. After 380 °C, the slow heating rate leads to the cracking of C15+, so the amount of C15+ generated by the fast heating rate is larger than that of the slow heating rate. After 340 °C, the proportion of expelled oil to total expelled hydrocarbons at a slow heating rate is larger than that of the fast heating rate. This study confirms that the fast heating rate can lead to a retardation effect, making the slow heating rate more favorable for the generation and discharge of hydrocarbons. The experimental results verify the compensation effect of time on temperature in the process of hydrocarbon generation.

Petrophysical Characterization and Gas Accumulation of Wufeng-Longmaxi Shale Reservoir in Eastern Margin of Sichuan Basin, SW China

Shale gas plays a significant role in meeting the increasing demand of energy resources, which enables the exploration and exploitation of gas from shale reservoir to be emphasized gradually. Aiming to serve a more responsible and efficient shale gas development, for example, to guide the hydraulic/nonaqueous fracturing operation, this work organized a comprehensive assessment on the petrophysical characterization and gas accumulation of the Upper Ordovician Wufeng-Lower Silurian Longmaxi shale reservoir (abbreviated as WL shale). Results indicate that the WL shale in Well-YC4 contains three third-order sequences (SS1-lower WL, SS2-middle WL, and SS3-upper WL), and each sequence contains a transgressive system tract (TST) and a high-stand system tract (HST), according to the logging information. Meanwhile, the SS1, SS2, and SS3 experienced variable sedimentary environment—with different relatively oxygenic and hydrodynamics. And the bottom section (SS1 and SS2) has a soft great brittle index (BI) value than the upper section (SS3), suggesting the bottom WL shale is better suited for hydraulic fracturing than the upper section. Besides, the organic matter indicates the WL shale has a decent hydrocarbon generation ability, and the thermal evolution degree is also conducive to the full generation of shale gas. The gas content of WL shale ranges in the scope of 0.76 m3/t~2.38 m3/t, in which CH4 is the primary composition and occupies 95.51%~99.36%, and the content of heavy hydrocarbon gases is limited. Besides, the drying coefficient indicates the dry gas is the dominate molecular composition in the gas content of WL shale. Hopefully, this work is instructive to a certain extent for the researchers and engineers who are working on WL shale gas in Sichuan basin.

Influence of oil structures on the component composition of free gases of potash reservoirs at the BPPU-4 mine field of PJSC “Uralkali”

The influence of oil structures on the content of heavy hydrocarbon gases in the component composition of free gases in the rocks of the overlying silvinite formations is considered. There is an assumption about the influence of reef formations on the overlying sedimentary deposits and the development of sub-vertical cracks, through which heavy hydrocarbon gases can penetrate into the overlying potash layers. The aim of the study is to study the relationship between the nature of the distribution of heavy hydrocarbon gases and geological disturbances and the subsequent prediction of the gas-dynamic situation during the development of potash reservoirs. The method consists of drilling holes into the roof of the mine, sealing the hole with a sealer, and then taking gas from the sealed part to the sampler and analyzing it on a gas chromatograph. The highest values of heavy hydrocarbon gases were determined for the Bc, AБ and KpII formations at the BPPU-4 mine field of PJSC Uralkali.

Origin and accumulation mechanisms of deep paleozoic oil and gas: A case study of the central Tarim basin, western China

Old strata and deep petroleum systems are becoming increasingly important. The Cambrian-Lower Ordovician petroleum reservoirs in the eastern Tazhong Uplift, central Tarim Basin, western China were studied comprehensively using various methods, including biomarkers, carbon isotopes of oil and gas, TOC and Rock-Eval pyrolysis of potential source rocks, as well as fluid inclusions, thin sections of dolomite rocks and Raman spectra of reservoir bitumen. The results show that the content of C 28 steranes among the C 27-29 steranes in most of the oil samples is greater than 0.25. The original hydrocarbon generation and expulsion potential of Cambrian and Lower Ordovician shale samples from the nearby Manjiaer Depression is considerable, and the oils are considered mainly derived from the Paleozoic shales in the Manjiaer Depression and the surrounding slops. Three notable types of oil and gas reservoirs were recognized in the Cambrian and Ordovician dolomite rocks: 1) the relatively well preserved primary reservoirs; 2) the residual reservoirs after deep oil-gas cracking with participation of thermochemical sulfate reduction (TSR); 3) the reformed reservoirs by the late charged high mature gas. In the vicinity of the No.1 fault zone, the effect of late gas charging and invasion is remarkable. They are mostly the mixture of gas cracked from both crude oil and heavy hydrocarbon gas in high mature stage. Oil and gas-liquid inclusions detected in the Cambrian reservoirs together with the Raman spectral characteristics of reservoir bitumen confirm the existed Cambrian paleo-oil reservoirs and oil cracking process. The gypsum-salt rock developed in Cambrian system is considered as a crucial factor for the primary oil and gas reservoirs, and the nearby areas within or below the strata where these gypsum-salt rock developed are suggested as favorable targets for deep to ultra-deep petroleum exploration. • Geochemistry characteristics of Cambrian and lower Ordovician oils were revealed. • Three modes of petroleum reservoirs in terms of formation mechanisms were proposed. • Major charging periods based on the fluid inclusions and burial-thermal history was suggested. • Hydrocarbon generation potential of Cambrian shale and Ordovician argillaceous dolomite was evaluated. • The sources and genesis of Cambrian and lower Ordovician oil and gas were clarified.

Geochemical characteristics, genetic types, and source of natural gas in the Sinian Dengying Formation, Sichuan Basin, China

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C1/C1+) of 0.9991, which reflected higher methane (CH4) content and lower heavy hydrocarbon gas (C2+) content. For nonhydrocarbon gas, CO2 (0.01%–26.34%), N2 (0.03%–24.95%), H2S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N2 content and lower CO2 content. Although the carbon isotopes had not been reversed, the values of δ13C2–δ13C1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N2 and He. H2S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich.

РАСПРЕДЕЛЕНИЕ ГАЗОВ В ДОННЫХ ОТЛОЖЕНИЯХ ЮГО-ЗАПАДНОГО СУББАССЕЙНА ЮЖНО-КИТАЙСКОГО МОРЯ

For the first time, this paper presents the distribution of gases (CO2, hydrocarbon C1-C4, H2, He) in 39 gas samples in bottom sediments from 19 gravity cores located in the southwestern sub-basin of the South China Sea (known as Bien Dong). The surface sediments in the studied area are mostly silty clay. In general, the concentration of methane varies in a wide range of 0.5–440 ppm. Anomalous values of methane were detected at many locations along the slope area of the southwest sub-basin of the South China Sea. The value of 2.2 ppm could be considered as a background concentration of methane in the studied region. The presence of a large-scale degassing zone of methane in the studied area was proposed. Besides, heavy hydrocarbon gases (ethylene, ethane, propane, and butane) were also determined with the highest values up to 70 ppm, 124 ppm, and 50 ppm for ethylene, ethane and propane, respectively. In addition, data of carbon dioxide, hydro and helium suggest some anomalous values of H2 up to 56.7 ppm.

Simulation Study of Hydrocarbon Generation Characteristics in Siliceous Rock

Late Triassic-early Jurassic silica rocks are widely developed in Northeast China. To evaluate the silica rock hydrocarbon generating capacity, we have simulated the hydrocarbon evolution process by thermal simulation experiments and analyzed the hydrocarbon generation characteristics. The experiments were carried out at six temperature points 250, 270, 290, 310, 330, and 350°C, and the content of the gaseous and liquid products was measured. The experiments results showed that the organic-rich siliceous rocks are characterized by a relatively high hydrocarbon-generating capacity. The gaseous products are generated at different temperatures, while natural gas is mainly generated when the peak period of oil generation is completed. Natural gas includes hydrocarbon and non-hydrocarbon gases. Hydrocarbon gases include methane, ethane, propane, butane, pentane, and other heavy hydrocarbon gases. Non-hydrocarbon gases include hydrogen, nitrogen, carbon monoxide, and carbon dioxide. Carbon dioxide is the main component of the gas products, followed by hydrogen, methane, nitrogen, and other gases, but the total content of other gases is extremely low. Carbon dioxide generated during all stages of the oil generation process accounts for the vast majority, but in geological conditions, it will eventually be consumed by hydration. Nitrogen is mainly produced in the early stage. The content of hydrogen and hydrocarbon gases increases with increase in temperature, but hydrogen is usually depleted in the actual reservoir due to its strong chemical activity.

METHOD FOR ADSORPTION PURIFICATION OF ASSOCIATED OIL GASES FROM MERCAPTANS

The paper examines methods of utilization of zeolite regeneration gases to assess the possibility of using them in an industrial adsorption unit for drying and purifying gases from hydrogen sulfide and mercaptans. The most promising is the method of decomposition of mercaptans to hydrogen sulfide and hydrogen on solid catalysts, which is carried out at a pressure and temperature of 200-350 °C, as well as the method of direct gas-phase catalytic oxidation of mercaptans with atmospheric oxygen. We carried out experiments on the purification of zeolite regeneration gases of the Orenburg GPP by oxidation with atmospheric oxygen using an iron oxide catalyst at a temperature of 180-250 °C. They showed that the gas purified from mercaptans contained elemental sulfur and disulfides as the main oxidation products, and 0.2% vol. of sulfur dioxide was present as a by-product. The method of purification from mercaptans and heavy hydrocarbon gases regeneration of composite adsorbent by thermocatalytic oxidation is also proposed. To reduce the yield of undesirable sulfur dioxide in the regeneration gas purified from mercaptans, it is proposed to divide the regeneration gas stream into two streams, while the larger part, comprising about 80-90% vol., is sent to oxidation on a zinc-iron catalyst at 200 °C, the second stream is mixed with oxidation products in a volume ratio in terms of mercaptans and sulfur dioxide equal to 1.5-2.2÷1, respectively, then the resulting mixture is passed at 160-200 °C through a titanium oxide catalyst with a gas volumetric velocity of 4000-6000 h-1. The proposed scheme for gas purification from mercaptans and heavy hydrocarbons on a composite adsorbent with oxidative regeneration makes it possible to carry out the subsequent process of amine purification of gas from hydrogen sulfide without the complications associated with foaming of the working solution. Furthermore, it becomes possible to transport gas purified from mercaptans and hydrogen sulfide through the pipeline without precipitation of condensate.

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.

Mechanisms of carbon isotopic fractionation in the process of natural gas generation: Geochemical evidence from thermal simulation experiment

Abstract Low maturity coal samples were taken from the Ordos Basin to conduct gold tube thermal simulation experiment in a closed system, and the characteristics of the products were analyzed to find out the fractionation mechanism of carbon isotopes and the causes of abnormal carbon isotopic compositions of natural gas. At the heating rates of 2 °C/h (slow) and 20 °C/h (rapid), the low maturity coal samples of the Ordos Basin had the maximum yields of alkane gas of 302.74 mL/g and 230.16 mL/g, the δ13C1 ranges of −34.8‰ to −23.6‰ and −35.5‰ to −24.0‰; δ13C2 ranges of −28.0‰ to −9.0‰ and −28.9‰ to −8.3‰; and δ13C3 ranges of −25.8‰ to −14.7‰ and −26.4‰ to −13.2‰, respectively. Alkane gas in the thermal simulation products of rapid temperature rise process showed obvious partial reversal of carbon isotope series at 550°C, and at other temperatures showed positive carbon isotope series. In the two heating processes, the δ13C1 turned lighter first and then heavier, and the non-monotonic variation of the δ13C1 values is because the early CH4 is from different parent materials resulted from heterogeneity of organic matter or the carbon isotope fractionation formed by activation energy difference of early enriched 12CH4 and late enriched 13CH4. The reversal of carbon isotope values of heavy hydrocarbon gas can occur not only in high to over mature shale gas (oil-type gas), but also in coal-derived gas. Through thermal simulation experiment of toluene, it is confirmed that the carbon isotope value of heavy hydrocarbon gas can be reversed and inversed at high to over mature stage. The isotope fractionation effect caused by demethylation and methyl linkage of aromatic hydrocarbons may be an important reason for carbon isotope inversion and reversal of alkane gas at the high to over mature stage.

The origin of high and variable concentrations of heavy hydrocarbon gases in coal from the Enhong syncline of Yunnan, China

The composition of coalbed methane (CBM) in the Enhong syncline of Yunnan China has abnormally high concentrations of heavy hydrocarbon gases (C2+). The distribution of the C2+ gases is variable in the syncline, some areas contain high concentration of C2+ gases from 2.9 to 36.98% which are called “wet gas area”, and in some areas, C2+ gases can't be examined which are called “dry gas area”. The reason for the high concentration of C2+ gases is connected with the coal maceral composition, the barkinites. The barkinites have the oil-prone character and have generated a lot of oil and exsudatinite in the process of coal maturation, which have been observed under the microscope. Accompanied by the oil and exsudatinite, many C2+ gases are generated from the coal, which can be proved by a large amount of C2+ gases generated from coal in Enhong syncline during the pyrolysis simulation experiments (Py-Gc). The reason of the uneven distribution of C2+ gases in the study area may be caused by different degrees of microbial degradation. The gases in the “dry gas area” become drier because of more microbial degradation and presenting biogenic gases character with little wet gas and lighter carbon isotopic methane, while gases in the “wet gas area” keep the character of thermogenic gases. The different degrees of microbial degradation may be caused by different gas preservation conditions such as coal pore structure. Mercury injection experiments show that coals in the “wet gas area” have larger pore specific surface areas and more micropores but fewer macropores. The larger pore volume of micropore and transitional pore may help the coal in the “wet gas area” protect the wet gases, maybe avoid the wet gases being degraded by the microorganisms.

Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature-based semi-open pyrolysis: Implications for in-situ conversion process

There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300–320 °C, 0.53–0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320–380 °C, 0.55–1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380–420 °C, 1.09–1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 °C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24–1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.

Hydrogen isotope of natural gas from the Xujiahe Formation and its implications for water salinization in central Sichuan Basin, China

Based on the analysis of the molecular composition as well as carbon and hydrogen isotopes of gases from the Upper Triassic Xujiahe and other formations in the Sichuan Basin in China, by combining previous research results and regional geological background, the gas origin, gas source, and significance of hydrogen isotopes are studied. The results show that gas from the Triassic Xujiahe Formation in the Sichuan Basin is mainly hydrocarbon gas. The methane content ranges 67.89%–98.05%, whereas the content of heavy hydrocarbon gas (C2+) ranges 0.42%–16.62%. Meanwhile, the non-hydrocarbon gas content (CO2, N2) is low. Except for the relatively high content of N2 and CO2 in Well Yue121, the average content of N2 and CO2 are 0.82% and 0.26%, respectively. The gas from the Xujiahe Formation in the Yuanba area has a high average dryness coefficient of 0.991, which indicates that it is dry gas. It is also worth noting that gases from other areas of central Sichuan have a dryness coefficient of less than 0.95, which is indicative of wet gas. The δ13C1 value varies from −43.8‰ to −29.2‰, the δ13C2 value ranges from −33.5‰ to −20.7‰, δ13C3 value ranges from −33.6‰ to −19.3‰, and the δ13C4 value ranges from −27.2‰ to −22.2‰. The δD1 value ranges from −191‰ to −148‰, δD2 value ranges from −165‰ to −115‰, and δD3 value ranges from −153‰ to −107‰. Methane and its homologues (C2-4) become more enriched in 13C and D as the carbon number increases (δ13C1 < δ13C2 < δ13C3 < δ13C4, δD1 < δD2 < δD3); the aforementioned is consistent with the carbon and hydrogen isotopic characteristics of thermogenic gases. The thermal maturity RO of the natural gas from the Xujiahe Formation in the Yuanba area ranges 1.09%–1.78%, whereas the RO value of the natural gas from the Xujiahe Formation in other areas of central Sichuan ranges 0.64%–0.92%. The natural gas from the Xujiahe Formation in central Sichuan is mainly from the coal measure source rocks of the Xujiahe Formation. The gas from the 2nd Member of the Xujiahe Formation (Xu-2 Member) in the Yuanba area is mixed gas; it is a mixture of the high-mature coal-derived gas from the coal measure source rock of the Xujiahe Formation and the oil-cracked gas from the Lower Cambrian (and Lower Silurian). The δD value of methane from the Xujiahe Formation in the Sichuan Basin is relatively high as it is higher than −200‰. Compared to the coal-derived gas from the source rocks formed in limnetic facies with freshwater in the Taibei Sag, Turpan-Hami Basin, though at similar thermal evolution stage, the difference of the δD values of methane can be as high as 90‰, indicating that the source rock of the Xujiahe Formation is formed in an environment with water salinization.

Geochemical response of produced water in the CBM well group with multiple coal seams and its geological significance-A case study of the Songhe well group in Western Guizhou

The geochemical response of produced water from coalbed methane (CBM) well group with multiple coal seams has rich geological significance. Taking 8 CBM wells of Songhe well group in western Guizhou as an example, the geochemical response characteristics and productivity significance of the CBM well group with multiple coal seams when inter-well interference or inter-layer interference appears have been examined mainly based on analyzing conventional ions, hydrogen and oxygen isotopes (δD and δ18O) of 7 batches of produced water samples in the stable production period of 1 year and 4 months, and dissolved inorganic carbon (DIC) stable isotopes (δ13CDIC) of 5 batches of produced water samples by cluster analysis and geological analysis methods. The study found that the change in dynamic fluid level has a good correlation with the Q-type clustering of δD-δ18O of produced water in the process of forming inter-well interference. With the formation of inter-well interference, the δD and δ18O clustering coefficient gradually decreases, and the fluids produced from the wells become more and more similar in property. In addition to the influence of drainage time, another main geological factor affecting inter-well interference is the buried depth of the coal seam. The larger the buried depth is, the larger the cumulative production of water, the faster the water circulation, the larger the Cl− concentration in produced water, the smaller the d-excess value (δD surplus index), and the smaller the cumulative production of CBM will be. In commingled CBM production of multiple coal seams, with larger span and multiple layers, inter-layer interference is likely to occur, resulting in unbalanced productivity contribution of the layers hard to tell. Because the δ13CDIC value in produced water from a well has a positive anomaly, the producing coal seams in the well are in the middle-upper layer of coal bearing strata; these coal seams have better permeability and higher water content, higher CO2 concentration and lower heavy hydrocarbon gas concentration offsetting each other, together with other geological conditions, it is concluded that the relatively large amount of CO2 formed by microbial reduction is the main cause of the positive δ13CDIC abnormality. Taking this well as the calibration well, combined with the Q-type clustering result of the δ13CDIC in produced water from the well group, considering the distribution of the developed coal seams and the change of the dynamical liquid level during the stable production period of the well group, the contribution of multi-coal layers in each well were estimated. If the cluster distance between the calibration well and another well is farther, the lower layer makes a larger contribution to the CBM productivity. If the cluster distance between the calibration well and another well is closer, the middle and upper layer contribute more to the CBM productivity, and it is mainly the production layers under the liquid level that produce CBM. This provides a unique hydrogeochemical analysis method for analyzing and identifying the contribution of production layers.

The catalytic effect of manganese carbonate on kerogen pyrolysis in the absence and presence of water

To investigate the effect of Mn ore on the chemical components and isotopic compositions of gas products during kerogen pyrolysis in the absence or presence of water, a series of pyrolysis experiments on Type-I kerogen with manganese carbonate and/or water were conducted in closed gold capsules at 325–600 °C for 72 h with 300 bar. The heavy hydrocarbon gas yields increased significantly over 450 °C due to the participation of manganese. As for isotopic compositions, the manganese catalysis caused a decrease in the 13CCH4 and an increase in the 13CC2H6 over 475 °C; the δD values of methane generated during anhydrous pyrolysis with manganese carbonate are much lower than those produced by the pyrolysis of kerogen alone. Furthermore, the δD values are the most negative during hydrous pyrolysis with manganese ore. In addition to the thermal decomposition of manganese carbonate to form carbon dioxide, water provides sources of hydrogen and oxygen to form H2 and CO2. Manganese carbonate inhibits the association of sulfur-free radicals to hydrogen to form H2S. The i-C4/n-C4 ratio for gas products was evidently higher due to the existence of manganese and water, they can enhance the carbocation mechanism.