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Comprehensive quantitative evaluation of shale gas content and the controlling factors in different occurrence states is of great significance for accurately assessing gas‐bearing capacity and providing effective well‐production strategies. A total of 122 core samples from well JY‐A in the Fuling shale gas field were studied to reveal the characteristics of S1l shale, 15 of which were selected to further predict the shale gas content in different occurrence states, which are dependent on geological factors in the thermal evolution process. Geological parameters were researched by a number of laboratory programs, and the factors influential in controlling shale gas content were extracted by both PCA and GRA methods and prediction models were confirmed by the BE method using SPSS software. Results reveal that the adsorbed gas content is mainly controlled by TOC, Ro, SSA, PD and pyrite content, and the free gas content is mainly controlled by S2, quartz content, gas saturation and formation pressure for S1l in well JY‐A. Three methods, including the on‐site gas desorption method, the empirical formula method, and the multiple regression analysis method were used in combination to evaluate the shale gas capacity of well JY‐A, all of which show that the overall shale gas content of well JY‐A is in the range of 2.0–5.0 m3/t and that the free gas ratio is about 50%, lower than that of well JY‐1. Cause analysis further confirms the tectonics and preservation conditions of S1l in the geological processes, especially the influence of eastern boundary faults on well JY‐A, as the fundamental reasons for the differences in shale gas enrichment in the Jiaoshiba area. [ABSTRACT FROM AUTHOR]

Abstract: Previous studies have postulated the contribution of present‐day low‐total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present‐day low‐TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low‐TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present‐day low TOC, using widely available Rock‐Eval data. First, we identify present‐day low‐TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock‐Eval data (IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present‐day low TOC carbonates. By applying the model to the Rock‐Eval dataset of the Tabei Uplift, we identify present‐day low‐TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×109 t oil. [ABSTRACT FROM AUTHOR]

The article discusses a study concerning the hydrocarbon generation and expulsion characteristics of Permian Lucaogou Formation source rocks in Jimusar Sag, Junggar Basin in China. Topics include the exploration practice in the basin, the organic matter abundance of the formation, and the maturity and characteristics of hydrocarbon generation and expulsion. Methods used in the study include well logging, core logging, and rock-evaluation.

Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T3×5) in the Western Sichuan Basin (WSD) are currentiy regarded as the most proiific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3×5 source rocks in the WSD, and investigated their hydrocarbon generation and e×pulsion characteristics, including intensity, efficiency and amount. The results show that, the T3×5 source rocks are thick (generally >200 m), and have a high total organic content (TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution (Ro>1.2%) in the area. In addition, an improved method of hydrocarbon generation potentiai is applied, indicating that the source rocks reached a hydrocarbon e×pulsion threshold with vitrinite reflectance (Ro) reaching 1.06%, and that the comprehensive hydrocarbon e×pulsion efficiency is about 60%. The amount of hydrocarbon generation and e×pulsion from T3×5 source rocks is 3.14×10 t and 1.86×10 t, respectiveiy, with a residual amount of 1.28×10 t within them. Continuous-type tight-sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas e×pelied from the T3x5 source rocks migrates for very short distances verticaliy and horizontaily. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×10 t. Geological resources of shale gas are up to 1.05×10 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales. [ABSTRACT FROM AUTHOR]

The Dongpu sag is located in the south of the Bohai Bay basin, China, and has abundant oil and gas reserves. To date, there has been no systematic documentation of its geothermal fields. This study measured the rock thermal conductivity of 324 cores from 47 wells, and calculated rock thermal conductivity for different formations. The geothermal gradient and terrestrial heat flow were calculated for 192 wells on basis of 892 formation-testing data from 523 wells. The results show that the Dongpu sag is characterized by a medium-temperature geothermal field between stable and active tectonic areas, with an average geothermal gradient of 32.0°C/km and terrestrial heat flow of 65.6 mW/m2. The geothermal fields in the Dongpu sag is significantly controlled by the Changyuan, Yellow River, and Lanliao basement faults. They developed in the Paleogene and the Dongying movement occurred at the Dongying Formation depositional period. The geothermal fields distribution has a similar characteristic to the tectonic framework of the Dongpu sag, namely two subsags, one uplift, one steep slope and one gentle slope. The oil and gas distribution is closely associated with the present geothermal fields. The work may provide constraints for reconstructing the thermal history and modeling source rock maturation evolution in the Dongpu sag. [ABSTRACT FROM AUTHOR]

Systematic analyses of the formation water and natural gas geochemistry in the Central Uplift of the Tarim Basin (CUTB) show that gas invasion at the late stage is accompanied by an increase of the contents of H2S and CO2 in natural gas, by the forming of the high total dissolved solids formation water, by an increase of the content of HCO−3, relative to Cl−, by an increase of the 2nd family ions (Ca2+, Mg2+, Sr2+ and Ba2+) and by a decrease of the content of SO2−4, relative to Cl−. The above phenomena can be explained only by way of thermochemical sulfate reduction (TSR). TSR often occurs in the transition zone of oil and water and is often described in the following reaction formula: σCH+CaSO4+H-2O→H2S+CO2+CaCO3. (1) Dissolved SO2−4 in the formation water is consumed in the above reaction, when H2S and CO2 are generated, resulting in a decrease of SO2−4 in the formation water and an increase of both H2S and CO2 in the natural gas. If formation water exists, the generated CO2 will go on reacting with the carbonate to form bicarbonate, which can be dissolved in the formation water, thus resulting in the enrichment of Ca2+ and HCO−3. The above reaction can be described by the following equation: CO2+H2O+CaCO3→Ca2++2HCO−3. The stratigraphic temperatures of the Cambrian and lower Ordovician in CUTB exceeded 120°C, which is the minimum for TSR to occur. At the same time, dolomitization, which might be a direct result of TSR, has been found in both the Cambrian and the lower Ordovician. The above evidence indicates that TSR is in an active reaction, providing a novel way to reevaluate the exploration potentials of natural gas in this district. [ABSTRACT FROM AUTHOR]