scholarly journals Influencing Factors and Mathematical Prediction of Shale Adsorbed Gas Content in the Upper Triassic Yanchang Formation in the Ordos Basin, China

Minerals ◽  
2019 ◽  
Vol 9 (5) ◽  
pp. 265 ◽  
Author(s):  
Ling Tang ◽  
Yan Song ◽  
Zhenxue Jiang ◽  
Xiongqi Pang ◽  
Zhuo Li ◽  
...  
Keyword(s):  
Shale Gas ◽  
Influence Factors ◽  
Economic Benefits ◽  
Gas Content ◽  
Analysis Method ◽  
Isothermal Adsorption ◽  
Resource Potential ◽  
Yanchang Formation ◽  
Geological Factors ◽  
Factor Regression

Evaluating absorbed gas content (AGC) in shales is crucial for accurately characterizing shale gas reservoirs and calculating resource potential. To investigate geological factors influencing AGC, 15 shale samples collected from the Yanchang Formation underwent related experiments. Then geochemistry features, mineral compositions, pore structure parameters and external factors were analyzed. The actual AGC was calculated using the Langmuir equation. Single geological factors acting on the AGC were discussed by the single-factor correlation analysis. Finally, four main influence factors (total organic carbon, S1, quartz content and formation temperature) were selected out from the 12 influence factors to establish the mathematical prediction model through the multi-factor regression statistical analysis method using SPSS software. The model was verified as being reliable with R2 as high as 0.8046 and relative error less than ±20%. Comparisons show that both the CH4 isothermal adsorption experimental method and the multi-factor regression analysis method have their own applicability and disadvantages, and they can complement each other in evaluating AGC in shales. Synthetic evaluation of AGC indicates that the Yanchang shale has an overall moderate AGC occupying about 58% of the total, which is helpful to extend shale gas production time of the Yanchang reservoir. Though under the present conditions, economic benefits of the continental shale gas are not obvious, the shale resource potential of Yanchang formation can’t be ignored.

scholarly journals Shale Gas Content Calculation of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China

Energies ◽  
2017 ◽  
Vol 10 (12) ◽  
pp. 1949 ◽  
Author(s):  
Jiao Su ◽  
Yingchu Shen ◽  
Jin Hao ◽  
Bo Liu
Keyword(s):  
Shale Gas ◽  
Ordos Basin ◽  
Gas Content ◽  
Yanchang Formation

scholarly journals Shale Gas Productivity Predicting Model and Analysis of Influence Factors

2015 ◽  
Vol 8 (1) ◽  
pp. 203-207 ◽  
Author(s):  
Yin Daiyin ◽  
Wang Dongqi ◽  
Zhang Chengli ◽  
Duan Yingjiao
Keyword(s):  
Mathematical Model ◽  
Pressure Gradient ◽  
Shale Gas ◽  
Diffusion Mechanism ◽  
Influence Factors ◽  
Mass Conservation ◽  
Isothermal Adsorption ◽  
Start Up ◽  
Gas Seepage ◽  
The Impact

In order to find the dynamic characteristics of shale gas reservoirs and improve shale gas well production, it is very important to research on shale gas seepage mechanism and production evaluation. Based on the shale gas seepage mechanism, adsorption and desorption characteristics, the diffusion mechanism and mass conservation theory in shale gas development, the dual pore medium shale gas reservoir mathematical model is set up. The mathematical model is built by the finite difference method based on start-up pressure gradient, slippage effect and the isothermal adsorption principle, and then programmed to solve it. Finally, this paper analyzed the impact of Langmuir volume, Langmuir pressure, start-up pressure gradient and slippage coefficient and other factors on shale gas wells production.

scholarly journals Shale Gas Content Calculation of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China

2017 ◽  
Author(s):  
Jiao Su ◽  
Yingchu Shen ◽  
Bo Liu ◽  
Jin Hao
Keyword(s):  
Shale Gas ◽  
Calculation Method ◽  
Indirect Method ◽  
Ordos Basin ◽  
Gas Content ◽  
Dissolved Gas ◽  
Yanchang Formation ◽  
Free Gas ◽  
Shale Reservoirs ◽  
Method Show

Shale gas content is the key parameter for shale gas potential evaluation and favorable area prediction. Therefore, it is very important to determine shale gas content accurately. Generally, we use the USBM method for coal reservoirs to calculate gas content of shale reservoirs. However, shale reservoirs are different from coal reservoirs in depth, pressure, core collection, etc. This method would inevitably cause problems. In order to make the USBM method more suitable for shale reservoir, an improved USBM method is put forward on the basis of systematic analysis of core pressure history and temperature history during shale gas desorption. The improved USBM method modifies the calculation method of the lost time, and determines the temperature balance time of water heating. In addition, we give the calculation method of adsorption gas content and free gas content, especially the new method of calculating the oil dissolved gas content and water dissolved gas content which are easily neglected. We used the direct method (USBM and the improved USBM) and the indirect method (adsorption gas, free gas and dissolved gas) to calculate the shale gas content of 16 shale samples of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China. The results of the improved USBM method show that the total shale gas content is high, with an average of 3.97 m3/t, and the lost shale gas content is the largest proportion with an average of 62%. The total shale gas content calculated by the improved USBM method is greater than that of the USBM method. The results of the indirect method show that the total shale gas content is large, with an average of 4.11 m3/t, and the adsorption shale gas content is the largest proportion with an average of 71%.  The oil dissolved shale gas content which should be taken attention accounts for about 7.8%. The relative error between the improved USBM method and indirect method is much smaller than that between USBM method and indirect method, which verifies the accuracy of the improved USBM method.

A gas-content calculation model for terrestrial shales in the Kuqa Depression, the Tarim Basin, Western China

2019 ◽  
Vol 7 (2) ◽  
pp. T513-T524 ◽  
Author(s):  
Yiqian Qu ◽  
Wei Sun ◽  
Song Guo ◽  
Shuai Shao ◽  
Xiuxiang Lv
Keyword(s):  
Tarim Basin ◽  
Shale Gas ◽  
Calculation Model ◽  
Influential Factors ◽  
Gas Content ◽  
Western China ◽  
Isothermal Adsorption ◽  
Kuqa Depression ◽  
Target Layer ◽  
Gas Potential

Because shale gas content plays a very important role in the evaluation of gas shale potential, its calculation and prediction become obligatory. We used two predictive models, namely, the Langmuir and Ambrose models, to calculate the shale gas content. The parameters involved in these two models are calculated by various experiments and analytic methods, including indirect prediction, the isothermal adsorption test, X-ray diffraction analysis, total organic carbon (TOC) measurement, pyrolysis, and porosity measurement. Then, a new calculation model that is applicable to shales in the Kuqa Depression, Tarim Basin, is established. Further research on influential factors of gas content in well YN2 is implemented. The result indicates that the gas content of terrestrial shales is more influenced by TOC abundance than by the content of clay minerals and quartz. The main parameters in the new calculation model are the TOC, depth, porosity, and gas saturation. The Jurassic shale gas in well YN2 is speculated to be mainly adsorption gas, with a dominant proportion of 75%–90% in the total gas content. As the formation depth increases, the free-gas content rises continuously, whereas the adsorption gas content first increases and then approaches the equilibrium value or even tends to decrease slightly. Based on the foregoing results, the target layer, the Yengisar Formation, is predicted to possess an enormous amount of shale gas potential, with an average total gas content of [Formula: see text].

scholarly journals Gas Desorption of Low-Maturity Lacustrine Shales, Trassic Yanchang Formation, Ordos Basin, China

2018 ◽  
Vol 10 (1) ◽  
pp. 688-698 ◽  
Author(s):  
Bojiang Fan ◽  
Xiangzeng Wang ◽  
Liang Shi
Keyword(s):  
Shale Gas ◽  
Gas Adsorption ◽  
Ordos Basin ◽  
Isotopic Fractionation ◽  
Gas Content ◽  
Gas Generation ◽  
Desorption Process ◽  
Yanchang Formation ◽  
Gas Desorption ◽  
Process Gas

AbstractRecent exploration activities on Triassic Yan-chang Formation has indicated significant potential for shale-gas resources. Even though some areas have been put into pilot production, challenge exists in effectively determining shale-gas content, whichmake it difficult to estimate reserve and forecast production. This is primarily due to the low maturity of the shale and complicated relationships between oil, water and gas. However, studies on the gas generation and accumulation of low-maturity shales are lacking in the literature and previous desorption experiments did not consider the effects of oil and water. In this study, eight core samples are used to run the gas-desorption experiment. Shale-gas composition and isotopic fractionation data are analyzed to provide insights on gas adsorption, expulsion and accumulation processes in the Yanchang Formation. The experiment results indicate that the overall methane content decreases (from 68.8% to 58.9%), heavy hydrocarbon-gas content (from 20.30% to 36.12%) and δ13C1 increase (from -51.43% to - 34.63%) during the desorption process. Gas yield reached up to 3.89 m3/t shale, and the content of lost gas can account for more than 20% of total desorbed gas during the coring process. The recoverable shale gas content is estimated to be 80% of the total gas-desorption volume. Desorbing the rest 20% requires extra heating under much higher temperature.

scholarly journals Impact of Geological Factors on Marine Shale Gas Enrichment and Reserve Estimation: A Case Study of Jiaoshiba Area in Fuling Gas Field

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Siyu Yu ◽  
Xixin Wang ◽  
Shaohua Li ◽  
Yuming Liu ◽  
Liming Xiao ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Shale Gas ◽  
Gas Content ◽  
Accurate Estimation ◽  
Gas Field ◽  
Adsorbed Gas ◽  
Marine Shale ◽  
Geological Factors ◽  
The Impact

Geological factors are key elements to control shale gas enrichment and influence the accurate estimation of shale gas reserve. However, the impact of the main geological factors, such as porosity, mineralogy, and organic matter, on marine shale gas enrichment and reserve calculation has not yet been fully clarified. Herein, we measured gas adsorption, porosity, mineralogical composition, and total organic carbon content of the marine shale samples from the Jiaoshiba area of Fuling gas field in Sichuan Basin, South China, and investigate the relationships between the geological factors and the adsorbed gas content. The results show that adsorbed gas content is positively correlated with total organic carbon and porosity; the larger specific surface area of samples with more clay minerals essentially contributes to shale gas enrichment. Additionally, the sealing of faults imposes a significant impact on shale gas accumulation. The probability volume method was applied to calculate the shale gas reserve. The reserves of P90 (the most pessimistic reserve), P50 (the most likely reserve), and P10 (the most optimistic reserve) were calculated, respectively, which provides useful information to reduce the risk in shale gas development.

Economic benefit of shale gas exploitation based on back propagation neural network

2020 ◽  
Vol 39 (6) ◽  
pp. 8823-8830
Author(s):  
Jiafeng Li ◽  
Hui Hu ◽  
Xiang Li ◽  
Qian Jin ◽  
Tianhao Huang
Keyword(s):  
Neural Network ◽  
Shale Gas ◽  
Bp Neural Network ◽  
Large Scale ◽  
Linear Prediction ◽  
Back Propagation ◽  
Back Propagation Neural Network ◽  
Economic Benefits ◽  
Gas Well ◽  
Well Production

Under the influence of COVID-19, the economic benefits of shale gas development are greatly affected. With the large-scale development and utilization of shale gas in China, it is increasingly important to assess the economic impact of shale gas development. Therefore, this paper proposes a method for predicting the production of shale gas reservoirs, and uses back propagation (BP) neural network to nonlinearly fit reservoir reconstruction data to obtain shale gas well production forecasting models. Experiments show that compared with the traditional BP neural network, the proposed method can effectively improve the accuracy and stability of the prediction. There is a nonlinear correlation between reservoir reconstruction data and gas well production, which does not apply to traditional linear prediction methods

scholarly journals Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2679
Author(s):  
Yuying Zhang ◽  
Shu Jiang ◽  
Zhiliang He ◽  
Yuchao Li ◽  
Dianshi Xiao ◽  
...  
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Content ◽  
Potential Zone ◽  
Hydrocarbon Generation ◽  
Gas Generation ◽  
Longmaxi Formation ◽  
Siliceous Shale ◽  
Organic Pores

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m3/t and 3.719 m3/t, and the total gas contents were between 0.44 m3/t and 5.19 m3/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas.

scholarly journals Difference Analysis of Organic Matter Enrichment Mechanisms in Upper Ordovician-Lower Silurian Shale from the Yangtze Region of Southern China and Its Geological Significance in Shale Gas Exploration

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-14 ◽  
Author(s):  
Ming Wen ◽  
Zhenxue Jiang ◽  
Kun Zhang ◽  
Yan Song ◽  
Shu Jiang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Shale Gas ◽  
Southern China ◽  
Sedimentary Organic Matter ◽  
Gas Content ◽  
Silicon Isotope ◽  
Upper Ordovician ◽  
Lower Silurian ◽  
Excess Silicon ◽  
Lower Yangtze

The upper Ordovician-lower Silurian shale has always been the main target of marine shale gas exploration in southern China. However, the shale gas content varies greatly across different regions. The organic matter content is one of the most important factors in determining gas content; therefore, determining the enrichment mechanisms of organic matter is an important problem that needs to be solved urgently. In this paper, upper Ordovician-lower Silurian shale samples from the X-1 and Y-1 wells that are located in the southern Sichuan area of the upper Yangtze region and the northwestern Jiangxi area of the lower Yangtze region, respectively, are selected for analysis. Based on the core sample description, well logging data analysis, mineral and elemental composition analysis, silicon isotope analysis, and TOC (total organic carbon) content analysis, the upper Ordovician-lower Silurian shale is studied to quantitatively calculate its content of excess silicon. Subsequently, the results of elemental analysis and silicon isotope analysis are used to determine the origin of excess silicon. Finally, we used U/Th to determine the characteristics of the redox environment and the relationship between excess barium and TOC content to judge paleoproductivity and further studied the mechanism underlying sedimentary organic matter enrichment in the study area. The results show that the excess silicon from the upper Ordovician-lower Silurian shale in the upper Yangtze area is derived from biogenesis. The sedimentary water body is divided into an oxygen-rich upper water layer that has higher paleoproductivity and a strongly reducing lower water that is conducive to the preservation of sedimentary organic matter. Thus, for the upper Ordovician-lower Silurian shale in the upper Yangtze region, exploration should be conducted in the center of the blocks with high TOC contents and strongly reducing water body. However, the excess silicon in the upper Ordovician-lower Silurian shale of the lower Yangtze area originates from hydrothermal activity that can enhance the reducibility of the bottom water and carry nutrients from the crust to improve paleoproductivity and enrich sedimentary organic matter. Therefore, for the upper Ordovician-lower Silurian shale in the lower Yangtze region, exploration should be conducted in the blocks near the junction of the two plates where hydrothermal activity was active.

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