Paleoenvironment, Geochemistry, and Pore Characteristics of the Postmature to Overmature Organic-Rich Devonian Shales in Guizhong Depression, Southwestern China

Investigating shale pore characteristics has deepened our understanding of shale reservoir, while that of postmature-overmature shales is yet to be revealed, which is especially critical for shale gas evaluation in southern China. Ten Middle-Upper Devonian organic-rich shale samples were collected from well GY-1 in the Guizhong Depression, and the paleoenvironment, geochemistry, and pore system were analyzed with a series of experiments, including trace element analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FESEM), low-pressure N2 adsorption, and source rock geochemistry. Results show that the Middle-Upper Devonian shales in the Guizhong Depression are organic-rich mudstones with TOC ranging from 0.14% to 6.21%, which is highest in the Nabiao Formation ( D 2 n ) and Lower Luofu Formation ( D 2 l ) that were deposited in the anoxic and weak hydrodynamic deep-water shelf. They are thermally postmature to overmature with equivalent vitrinite reflectance ( EqV R o ) of 3.40%~3.76% and type I kerogen. The lithofacies in D 2 n and D 2 l are primarily siliceous/argillaceous mixed shale as well as a few siliceous argillaceous shales and argillaceous siliceous shales as well. Organic matter- (OM-) hosted pores within bitumen are primary storage volume, rather than inorganic pores (interparticle and intraparticle) which are rare. The total helium porosity of samples varies between 1.20% and 4.49%, while total surface area and pore volume are 2.39-14.22 m2/g and 0.0036-0.0171 ml/g, respectively. Porosity, pore surface area, and pore volume are in accordance with increasing TOC, R o , and siliceous mineral contents. Considerable OM-macropores are found in shales with R o > 3.6 % in our study which demonstrates that the porosity at postmature to overmature stage ( R o = 3.5 − 4.0 % ) does not change fundamentally. The high level of maturity is not considered the main controlling factor that affects shale gas content, and more attention should be paid to preservation conditions in this area.

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Jurassic Terrestrial Shale Gas Potential of the Northern Kashi Sag in the Tarim Basin, Northwestern China

Geofluids ◽

10.1155/2021/5542447 ◽

2021 ◽

Vol 2021 ◽

pp. 1-16

Author(s):

Wei Wu ◽

Zhiwei Liao ◽

Honghan Chen ◽

Shaohu Li ◽

Ao Su ◽

...

Keyword(s):

Organic Matter ◽

Surface Area ◽

Tarim Basin ◽

Shale Gas ◽

Pore Volume ◽

Middle Jurassic ◽

Vitrinite Reflectance ◽

Mature Stage ◽

Average Pore ◽

Gas Potential

Evaluation of terrestrial shale gas resource potential is a hot issue in unconventional oil and gas exploration. Organic-rich shales are widely developed in the Jurassic strata of Tarim Basin, but their shale gas potential has not been described well. In the study, the Lower-Middle Jurassic fine-grained sedimentary rocks (Kangsu and Yangye Formations) in northern Kashi Sag, northwestern Tarim Basin, were taken as the study object. The comprehensive studies include petrology, mineralogy, organic geochemistry, and physical properties, which were used to characterize the organic matter and reservoir characteristics. Results show that the Jurassic terrestrial shale in the northern Kashi Sag was mainly deposited in lakes, rivers, and deltas. The thickness of black lacustrine shale developed in the Early-Middle Jurassic in the study area is generally over 100 m. The total organic carbon (TOC) content is rich, averaging 2.77%. The vitrinite reflectance ( R o ) values indicate that the Lower Jurassic shale organic matter is in the early mature–mature stage, while the Middle Jurassic is in the mature stage. Besides, organic matter is primarily II and III in kerogen types. The whole shale contains a large number of clay minerals, especially illite. The average brittle minerals such as quartz and feldspar are 28.67%, and the average brittleness index is 38.63%. Nanoscale pores containing intergranular pores, dissolution pores, and organic pores, coupled with microcracks, are well developed in Jurassic shale. The sample’s average pore volume is 0.017 cm3/g, and the specific surface area is 9.36 m2/g. Mesoporous contribute the most to pore volume, while the number of microporous is the largest. Both of them provide most of the surface area for the shale. Combined with regional geologic settings, we propose that the Jurassic terrestrial shale has good-excellent shale gas exploration potential and development prospects.

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Evaluation of coal and shale reservoir in Permian coal-bearing strata for development potential: A case study from well LC-1# in the northern Guizhou, China

Energy Exploration & Exploitation ◽

10.1177/0144598718807553 ◽

2018 ◽

Vol 37 (1) ◽

pp. 194-218 ◽

Cited By ~ 2

Author(s):

Hongjie Xu ◽

Shuxun Sang ◽

Jingfen Yang ◽

Jun Jin ◽

Huihu Liu ◽

...

Keyword(s):

Specific Surface ◽

Pore Size ◽

Surface Area ◽

Specific Surface Area ◽

Shale Gas ◽

Pore Volume ◽

Coalbed Methane ◽

Total Pore Volume ◽

Gas Content ◽

Bet Specific Surface Area

Indentifying reservoir characteristics of coals and their associated shales is very important in understanding the co-exploration and co-production potential of unconventional gases in Guizhou, China. Accordingly, comprehensive experimental results of 12 core samples from well LC-1# in the northern Guizhou were used and analyzed in this paper to better understand their vertical reservoir study. Coal and coal measured shale, in Longtan Formation, are rich in organic matter, with postmature stage of approximately 3.5% and shales of type III kerogen with dry gas generation. All-scale pore size analysis indicates that the pore size distribution of coal and shale pores is mainly less than 20 nm and 100 nm, respectively. Pore volume and area of coal samples influenced total gas content as well as desorbed gas and lost gas content. Obvious relationships were observed between residual gas and BET specific surface area and BJH total pore volume (determined by nitrogen adsorption). For shale, it is especially clear that the desorbed gas content is negatively correlated with BET specific surface area, BJH total pore volume and clay minerals. However, the relationships between desorbed gas and TOC (total organic carbon) as well as siderite are all well positive. The coals and shales were shown to have similar anoxic conditions with terrestrial organic input, which is beneficial to development of potential source rocks for gas. However, it may be better to use a low gas potential assessment for shales in coal-bearing formation because of their low S1+S2 values and high thermal evolution. Nevertheless, the coalbed methane content is at least 10 times greater than the shale gas content with low desorbed gases, indicating that the main development unconventional natural gas should be coalbed methane, or mainly coalbed methane with supplemented shale gas.

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Nanometer Pore Structure Characterization of Taiyuan Formation Shale in the Lin-Xing Area Based on Nitrogen Adsorption Experiments

Minerals ◽

10.3390/min11030298 ◽

2021 ◽

Vol 11 (3) ◽

pp. 298

Author(s):

Chenlong Ding ◽

Jinxian He ◽

Hongchen Wu ◽

Xiaoli Zhang

Keyword(s):

Specific Surface ◽

Pore Structure ◽

Surface Area ◽

Specific Surface Area ◽

Shale Gas ◽

Pore Volume ◽

Ordos Basin ◽

Total Pore Volume ◽

Nitrogen Adsorption ◽

Taiyuan Formation

Ordos Basin is an important continental shale gas exploration site in China. The micropore structure of the shale reservoir is of great importance for shale gas evaluation. The Taiyuan Formation of the lower Permian is the main exploration interval for this area. To examine the nanometer pore structures in the Taiyuan Formation shale reservoirs in the Lin-Xing area, Northern Shaanxi, the microscopic pore structure characteristics were analyzed via nitrogen adsorption experiments. The pore structure parameters, such as specific surface area, pore volume, and aperture distribution, of shale were calculated; the significance of the pore structure for shale gas storage was analyzed; and the main controlling factors of pore development were assessed. The results indicated the surface area and hole volume of the shale sample to be 0.141–2.188 m2/g and 0.001398–0.008718 cm3/g, respectively. According to the IUPAC (International Union of Pure and Applied Chemistry) classification, mesopores and macropores were dominant in the pore structure, with the presence of a certain number of micropores. The adsorption curves were similar to the standard IV (a)-type isotherm line, and the hysteresis loop type was mainly similar to H3 and H4 types, indicating that most pores are dominated by open type pores, such as parallel plate-shaped pores and wedge-shaped slit pores. The micropores and mesopores provide the vast majority of the specific surface area, functioning as the main area for the adsorption of gas in the shale. The mesopores and macropores provide the vast majority of the pore volume, functioning as the main storage areas for the gas in the shale. Total organic carbon had no notable linear correlation with the total pore volume and the specific surface area. Vitrinite reflectance (Ro) had no notable correlation with the specific surface area, but did have a low “U” curve correlation with the total pore volume. There was no relationship between the quartz content and specific surface area and total pore volume. In addition, there was no notable correlation between the clay mineral content and total specific surface area and total pore volume.

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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 ◽

10.1155/2019/9524507 ◽

2019 ◽

Vol 2019 ◽

pp. 1-14 ◽

Cited By ~ 1

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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Total Organic Carbon Enrichment and Its Impact on Pore Characteristics: A Case Study from the Niutitang Formation Shales in Northern Guizhou

Energies ◽

10.3390/en12081480 ◽

2019 ◽

Vol 12 (8) ◽

pp. 1480 ◽

Cited By ~ 2

Author(s):

Liu ◽

Tang ◽

Keyword(s):

Fractal Dimension ◽

Organic Carbon ◽

Total Organic Carbon ◽

Vitrinite Reflectance ◽

Guizhou Province ◽

Type I ◽

Pore Characteristics ◽

Hill Model ◽

Recovery Coefficient ◽

Niutitang Formation

This study analyzes samples from the Lower Cambrian Niutitang Formation in northern Guizhou Province to enable a better understanding of total organic carbon (TOC) enrichment and its impact on the pore characteristics of over-mature marine shale. Organic geochemical analysis, X-ray diffraction, scanning electron microscopy, helium porosity, and low-temperature nitrogen adsorption experiments were conducted on shale samples. Their original TOC (TOCo) content and organic porosity were estimated by theoretical calculation, and fractal dimension D was computed with the fractal Frenkel–Halsey–Hill model. The results were then used to consider which factors control TOC enrichment and pore characteristics. The samples are shown to be dominated by type-I kerogen with a TOC content of 0.29‒9.36% and an equivalent vitrinite reflectance value of 1.72‒2.72%. The TOCo content varies between 0.64% and 18.17%, and the overall recovery coefficient for the Niutitang Formation was 2.16. Total porosity of the samples ranged between 0.36% and 6.93%. TOC content directly controls porosity when TOC content lies in the range 1.0% to 6.0%. For samples with TOC < 1.0% and TOC > 6.0%, inorganic pores are the main contributors to porosity. Additionally, pore structure parameters show no obvious trends with TOC, quartz, and clay mineral content. The fractal dimension D1 is between 2.619 and 2.716, and D2 is between 2.680 and 2.854, illustrating significant pore surface roughness and structural heterogeneity. No single constituent had a dominant effect on the fractal characteristics.

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Classification and Evaluation on Shale Gas Reservoir for Wufeng-Longmaxi Formation in Chuannan Area, Sichuan Basin

Lithosphere ◽

10.2113/2021/3364731 ◽

2021 ◽

Vol 2021 (Special 1) ◽

Author(s):

Jianlin Guo ◽

Chengye Jia ◽

Dongbo He ◽

Fankun Meng

Keyword(s):

Shale Gas ◽

Sichuan Basin ◽

Gas Content ◽

Brittleness Index ◽

Type I ◽

Gas Reservoir ◽

Longmaxi Formation ◽

Positive Correlation ◽

Gas Saturation ◽

Shale Gas Reservoir

Abstract Based on the comprehensive statistic and analysis on some representative geological and physical data, the classification criteria on net pay for shale gas reservoir of the Wufeng-Longmaxi formation in Shunan area, Sichuan Basin, are proposed, which include porosity (φ), gas saturation (Sg), density of rock (DEN), brittleness index (BI), and gas content (Vt). When the porosity, gas saturation, brittleness index, and gas content are larger than 3%, 30%, 40%, and 1 m3/t, respectively, and the density of rock is lower than 2.7 g/cm3, then this formation can be seen as the net pay. The application of two key parameters, gas content and brittleness index, could reflect the reservoir resource basis and fracability, respectively. The gas content has a positive correlation with porosity and total organic volume, and the brittleness index has a positive correlation with siliceous and carbonate content. According to the range of these two parameters, the net pay can be classified into three types. For type I, the gas content and brittleness index are larger than 4 m3/t and 50%, respectively. For type II, either the gas content or the brittleness index is lower than 4 m3/t and 50%. For type III, the gas content should be larger than 1 m3/t and lower than 4 m3/t, and the brittleness index is between 40% and 50%. The field application case indicates that the Wufeng formation and low member of the Longmaxi formation have good quality and mainly consist of type I and II formations. In addition, it is found that there is a positive correlation between the penetration ratio for type I formation and the testing production and estimate ultimate recovery (EUR). While this ratio is larger than 50%, the testing production rate and EUR will be over 15×104 m3/d and 8000×104 m3 with a probability of 92%, which meet the requirement of exploitation with reasonable economic benefits.

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Well logging evaluation of the shale gas potential in the lower Silurian Longmaxi Formation, Weiyuan, southern Sichuan Basin, China

Interpretation ◽

10.1190/int-2020-0069.1 ◽

2021 ◽

pp. 1-64

Author(s):

Guangzhao Zhou ◽

Zhiming Hu ◽

Xiangui Liu ◽

Xianggang Duan ◽

Jin Chang

Keyword(s):

Spatial Distribution ◽

Shale Gas ◽

Sichuan Basin ◽

Vitrinite Reflectance ◽

Well Logging ◽

Carbonaceous Shale ◽

Organic Carbon Content ◽

Type I ◽

Longmaxi Formation ◽

Marine Shale

Recent observations of shale gas breakthroughs have in the Weiyuan marine shale gas play in the Sichuan Basin have attracted great interest. To better understand these breakthroughs, we use core description, FIB-SEM data, XRD data, organic geochemistry, and well logging data, to better understand the reservoir characteristics carbonaceous shale, calcareous shale, and siliceous shale lithology, with a focus on the organic-rich shale units. We find conventional well log methods are effective in mapping the spatial distribution of the organic-rich shale in the Weiyuan area where the. total organic carbon content in the Longmaxi Formation ranges from 1.35%-6.95%, averaging 4.42%. The kerogen is Type I-II and the vitrinite reflectance (Ro) is greater than 2.57%, which indicates that the formation is susceptible to shale gas accumulation. The clay mineral content ranges from 48 wt.% to 63 wt.% (avg. 51 wt.%).with illite and chlorite averaging 73.8% and 25.7%, respectively. The brittle mineral quartz and plagioclase content ranges from 32 wt.% to 61 wt.% (avg. 47 wt.%). Compared to the surrounding litholgic units, the marine shale exhibits relatively high GR, CNL, AC, RT, K, and U values and relatively low DEN, PE and Th/U values, allowing us to construct. Cross-plots to define the units of interest. Using the same process, we quantify the TOC content providing a spatial distribution of organic-rich shale using conventional well logging.

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Deflating the shale gas potential of South Africa’s Main Karoo basin

South African Journal of Science ◽

10.17159/sajs.2017/20160331 ◽

2017 ◽

Vol 113 (9/10) ◽

Cited By ~ 15

Author(s):

Michiel de Kock ◽

Nicolas Beukes ◽

Elijah Adeniyi ◽

Doug Cole ◽

Annette Götz ◽

...

Keyword(s):

Organic Carbon ◽

Total Organic Carbon ◽

Shale Gas ◽

Vitrinite Reflectance ◽

Gas Content ◽

Carbonaceous Shale ◽

Organic Carbon Content ◽

Hydrocarbon Generation ◽

Developmental Potential ◽

Karoo Basin

The Main Karoo basin has been identified as a potential source of shale gas (i.e. natural gas that can be extracted via the process of hydraulic stimulation or ‘fracking’). Current resource estimates of 0.4–11x109 m3 (13–390 Tcf) are speculatively based on carbonaceous shale thickness, area, depth, thermal maturity and, most of all, the total organic carbon content of specifically the Ecca Group’s Whitehill Formation with a thickness of more than 30 m. These estimates were made without any measurements on the actual available gas content of the shale. Such measurements were recently conducted on samples from two boreholes and are reported here. These measurements indicate that there is little to no desorbed and residual gas, despite high total organic carbon values. In addition, vitrinite reflectance and illite crystallinity of unweathered shale material reveal the Ecca Group to be metamorphosed and overmature. Organic carbon in the shale is largely unbound to hydrogen, and little hydrocarbon generation potential remains. These findings led to the conclusion that the lowest of the existing resource estimates, namely 0.4x109 m3 (13 Tcf), may be the most realistic. However, such low estimates still represent a large resource with developmental potential for the South African petroleum industry. To be economically viable, the resource would be required to be confined to a small, well-delineated ‘sweet spot’ area in the vast southern area of the basin. It is acknowledged that the drill cores we investigated fall outside of currently identified sweet spots and these areas should be targets for further scientific drilling projects.

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Micropore Characteristics and Gas-Bearing Characteristics of Marine-Continental Transitional Shale Reservoirs in the East Margin of Ordos Basin

Adsorption Science & Technology ◽

10.1155/2021/5593245 ◽

2021 ◽

Vol 2021 ◽

pp. 1-15

Author(s):

Yuanzhen Ma ◽

Meng Wang ◽

Ruying Ma ◽

Jiamin Li ◽

Asiya Bake ◽

...

Keyword(s):

High Pressure ◽

Specific Surface ◽

Surface Area ◽

Clay Minerals ◽

Pore Volume ◽

Ordos Basin ◽

Gas Content ◽

The Ordos Basin ◽

Shale Reservoirs ◽

Gas Bearing

In order to deeply study the exploration potential of Carboniferous-Permian marine-continental transitional shale reservoirs in the Ordos Basin, the shale samples from well Y1 in the central-southern part of the Hedong Coalfield were used as the research object. The organic geochemical test, scanning electron microscope, X-ray diffraction, and high pressure mercury injection and low-temperature nitrogen adsorption experiments have studied the microscopic characteristics and gas content characteristics of shale reservoirs. The results show that the organic matter type of the sample is type III; the TOC content ranges from 0.28% to 16.87%, with an average of 2.15%; R o is from 2.45% to 3.36%, with an average value of 2.86%; the shale pores in the study area are well developed, containing more organic pores and intergranular pores of clay minerals. Based on the two-dimensional SEM image fractal theory to study different types of pores, the fractal dimension of shale pore fracture morphology is between 2.34 and 2.50, and the heterogeneity is moderate. The high-pressure mercury intrusion experiment characterizes the pore size distribution of shale macropores and transition pores. The pore diameters are mostly nm-scale. Transition pores are the main pores of the shale in the study area. Based on the characteristics of the pore structure, the adsorption capacity and gas content of CH4 in shale reservoir were analyzed by methane isothermal adsorption and gas content experiments. The results showed that the pore volume and specific surface area were positively correlated with clay mineral content, TOC, and RO, but negatively correlated with the quartz content. In clay minerals and brittle minerals, pore volume and specific surface area are positively correlated with illite content and negatively correlated with the quartz and kaolinite content. The measured total gas content and desorbed gas content are significantly positively correlated with TOC, but are weakly positively correlated with the quartz and illite content. This study finely characterizes the physical properties, micropore characteristics, gas-bearing characteristics, and influencing factors of shale reservoirs, which has certain theoretical guiding significance for the research and development of coal-measure shale in the Ordos Basin.

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Imaging and quantification of the pore microstructure of gas shales using X-ray microtomography

10.5194/se-2017-52 ◽

2017 ◽

Author(s):

Mozhdeh Mehrabi ◽

Mehrdad Pasha ◽

Ali Hassanpour ◽

Paul W. J. Glover ◽

Xiaodong Jia

Keyword(s):

Aspect Ratio ◽

Pore Size ◽

Surface Area ◽

Shale Gas ◽

Pore Volume ◽

Ion Beam ◽

X Ray ◽

Aspect Ratios ◽

Gas Shales ◽

Pore Microstructure

Abstract. Optimisation of gas production from shale gas reservoirs depends critically upon a good understanding of the porosity and pore microstructure of the shale. Conventionally surface area measurements or mercury porosimetry have been used to measure the porosity in gas shales. However, these conventional methods have limited accuracy and only provide a bulk measurement for the samples. More recently, scanning electron micrography (SEM) and Focussed Ion Beam SEM (FIB-SEM) techniques have been applied in an attempt to address these limitations. Unfortunately, these two methods destroy the samples. In this research three-dimensional x-ray micro tomography (XRMT) imaging techniques were used to capture the structure of three samples and also compared to data from mercury porisimetry. The resulting data have been segmented in order to recognize individual pores down to a resolution of about 1 µm. Distributions of pore volume, pore size, pore aspect ratio, surface area to pore volume ratios and pore orientations were calculated from the XRMT data. It was found that the porosity obtained from XRMT measurements is smaller than that obtained using mercury porisimetry, the reason for which might be displacement of kerogen by the high pressures generated in the mercury technique, but is unlikely to be due to both techniques not being able to measure pores smaller that about 900 nm. Pore volume and size distributions showed all of the shales tested in this work to be multimodal with similar major modal values for volume and pore size. The pores also have a range of pore aspect ratios and surface area to pore volumes, including values indicating the presence of significant oblate spheroidal pores where the major axis is up to 330 times bigger than the minor axis. This has implications both for the connectedness of pores and the resultant gas permeability and the effectiveness of gas desorption processes into the gas shale's pores. These high aspect ratio pores were oriented both in dip and azimuth in preferential directions making it likely that the shale gas itself has significant anisotropy both for permeability and in its mechanical properties. Permeabilities calculated from the XRMT distribution data matched very well with permeabilities obtained by scaling considerations and typical values for similar gas shales.

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