Shale Gas Content Research Articles

Comparison of Three Key Marine Shale Reservoirs in the Southeastern Margin of the Sichuan Basin, SW China

This study performs a comprehensive comparison of three key marine shale reservoirs in the southeastern margin of the Sichuan Basin, and explains why commercial gas production was only achieved in the Lower Silurian Longmaxi (LSL) and Upper Ordovician Wufeng (UOW) formations, but not in the Lower Cambrian Niutitang (LCN) formation. The experimental methods included in situ gas content and gas composition tests, methane adsorption analysis, low-pressure N2 adsorption, field emission scanning electron microscopy (FE-SEM), and total organic carbon (TOC) and vitrinite reflectance (Ro) analyses to evaluate the lithology, mineralogy, physical properties of the reservoir, organic geochemistry, in situ gas content and methane adsorption capacity characteristics of the three shales. The LCN shale has lower quartz and clay mineral contents and a low brittleness index, but higher contents of feldspar, pyrite and carbonate minerals than the LSL and UOW shales. The porosity and permeability of the LSL and UOW shales are higher than those of the LCN shale. The primary contributions to the high permeability in the LSL shale are its well-developed fractures and organic matter pores. In contrast, the over-mature LCN shale is unfavorable for the development of organic pores and fractures. Although the LCN shale has a higher methane sorption capacity than the LSL and UOW shales, the gas content and methane saturation of the LCN shale are distinctly lower than those of the LSL and UOW shales. This is primarily due to gas migration from the LCN shale, resulting from the activities of tectonic uplift and the unconformable contact between the LCN shale and the Dengying formation. When compared with gas shale in North America, the LSL shale is the most favorable shale reservoir out of the three Sichuan shales, while the combination of the LSL and UOW shales is also potentially productive. However, the individual single layer production of the UOW or LCN shales is still limited due to poor resource potential and/or reservoir physical characteristics in the study area.

Reservoir characteristics and methane adsorption capacity of the Upper Triassic continental shale in Western Sichuan Depression, China

ABSTRACTThe well-developed continental shale sequences in the Western Sichuan Depression are characterised by extremely low porosity and permeability, complex lithologies and strong lateral facies changes. The overall lack of proper characterisation of the shale properties has restricted gas exploration and development in the region. In this study, shales from the fifth member of the Xujiahe Formation of the Upper Triassic (T3x5) are comprehensively characterised in terms of their organic geochemistry, mineral composition, microscopic pore structure and gas content. In addition, the influence of various geological factors on the adsorbed gas content is investigated. We proposed a new model for predicting the adsorption gas content of continental shale. The T3x5 shale sequence is found to be rich in organic matter but with variable mineral compositions, pore types and reservoir physical properties. The porosity and permeability of shales are better than those of siltstones and fine sandstones interbedded with the shale under an overall densification background. Mesopores (2–50 nm) are common in the shale sequence, followed by micropores and then macropores. The gas-adsorption capacity of organic-rich shales increases with increasing TOC and clay-mineral contents, maturity and pressure, but decreases with increasing quartz content, carbonate minerals and temperature. The gas-adsorption capacity can thus be expressed as a function of organic matter, clay-mineral content, temperature and pressure. The calculated results are in good agreement with the experiment results and indicate that adsorption gas in the studied shales accounts for 78.9% of the total gas content.

Investigation of gas content of organic-rich shale: A case study from Lower Permian shale in southern North China Basin, central China

Measuring gas content is an essential step in estimating the commerciality of gas reserves. In this study, eight shale core samples from the Mouye-1 well were measured using a homemade patented gas desorption apparatus to determine their gas contents. Due to the air contamination that is introduced into the desorption canister, a mathematical method was devised to correct the gas quantity and quality. Compared to the chemical compositions of desorbed gas, the chemical compositions of residual gas are somewhat different. In residual gas, carbon dioxide and nitrogen record a slight increase, and propane is first observed. This phenomenon may be related to the exposure time during the transportation of shale samples from the drilling site to the laboratory, as well as the differences in the mass, size and adsorptivity of different gas molecules. In addition to a series of conventional methods, including the USBM direct method and the Amoco Curve Fit (ACF) method, which were used here for lost gas content estimation, a Modified Curve Fit (MCF) method, based on the ‘bidisperse’ diffusion model, was established to estimate lost gas content. By fitting the ACF and MCF models to gas desorption data, we determined that the MCF method could reasonably describe the gas desorption data over the entire time period, whereas the ACF method failed. The failure of the ACF method to describe the gas desorption process may be related to its restrictive assumption of a single pore size within shale samples. In comparison to the indirect method, this study demonstrates that none of the three methods studied in this investigation (USBM, ACF and MCF) could individually estimate the lost gas contents of all shale samples and that the proportion of free gas relative to total gas has a significant effect on the estimation accuracy of the selected method. When the ratio of free gas to total gas is lower than 45%, the USBM method is the best for estimating the lost gas content, whereas when the ratio ranges from 45% to 75% or is more than 75%, the ACF and MCF methods, are the best options respectively.

Origin of shale gas in the Triassic Yanchang Formation, Ordos Basin, China

ABSTRACTThe Chang 7 Member shale gas of the Upper Triassic Yanchang Formation, Ordos Basin, is a representative of continental shale gas in China. The Chang 7 shale is currently in the oil window, suggesting it should primarily be producing oil, but an exploratory well found high levels of gas production. In addition, the methane carbon isotopic composition (δ13C1) of Chang 7 shale gas is generally depleted in 13C relative to that calculated by Ro, according to the δ13C-Ro equation. It is uncertain whether Chang 7 shale gas has mixed with biogenic gas or early thermogenic gas. In this study, over 100 samples of fresh shale cores were collected from the Yanchang Formation, and on-site gas desorption experiments and experimental analysis were carried out. Measured shale gas content was considerable, and was found to be proportional to the abundance of organic matter. Through comprehensive evaluation of the gas composition and δ13C1, it was concluded that there was no biogenic gas contribution to the shale gas in the study area. The negative δ13C1 of shale gas was due to the different formation mechanisms of shale gas and conventional natural gas. Methane in shale gas reservoirs is the result of methane accumulation at all stages, which increases the shale gas content.

An adsorbed gas estimation model for shale gas reservoirs via statistical learning

Shale gas plays an important role in reducing pollution and adjusting the structure of world energy. Gas content estimation is particularly significant in shale gas resource evaluation. There exist various estimation methods, such as first principle methods and empirical models. However, resource evaluation presents many challenges, especially the insufficient accuracy of existing models and the high cost resulting from time-consuming adsorption experiments. In this research, a low-cost and high-accuracy model based on geological parameters is constructed through statistical learning methods to estimate adsorbed shale gas content. The new model consists of two components, which are used to estimate Langmuir pressure (PL) and Langmuir volume (VL) based on their quantitative relationships with geological parameters. To increase the accuracy of the model, a “big data” set that consists of 301 data entries was compiled and utilized. Data outliers were detected by the K-Nearest Neighbor (K-NN) algorithm, and the model performance was evaluated by the leave-one-out algorithm. The proposed model was compared with four existing models. The results show that the novel model has better estimation accuracy than the previous ones. Furthermore, because all variables in the new model are not dependent on any time-consuming experimental methods, the new model has low cost and is highly efficient for approximate overall estimation of shale gas reservoirs. Finally, the proposed model was employed to estimate adsorbed gas content for nine shale gas reservoirs in China, Germany, and the U.S.A.

Differential fluid migration behaviour and tectonic movement in Lower Silurian and Lower Cambrian shale gas systems in China using isotope geochemistry

Isotope geochemistry has been introduced as a means to trace origin of the hydrocarbon and characterize highly productive shale gas systems recently. To assess the impact of tectonic movement and the sealing of shale gas systems, isotope geochemistry, pressure coefficients and the distribution of bitumens are analysed. Many samples yield isotope geochemical data with typical carbon isotopic reversals (δ13C1 > δ13C2) and hydrogen isotopic reversals (δ13DC2H6 > δ13DCH4) in the Lower Silurian shale gas. Isotopically reversed gases are considered to originate in sealed, self-contained petroleum systems. Besides, isotope “reversals order” degree of shale gas has positive correlation with gas production. Isotopically normal gases from the Lower Cambrian indicate that this formation was a continued relatively open petroleum system when oil and gas generated. The pressure coefficients of the Lower Silurian shale gas reservoir range from 1.45 to 2.03, indicating that the reservoir is overpressurized, whereas the Lower Cambrian shale gas reservoir possesses a normal pressure system. Overpressurization of the Lower Silurian shale gas reservoir also indicates that it is a well-sealed system. The distribution and isotope geochemistry of bitumens in the Sinian dolomite and Cambrian shale suggests that the source rock of the Sinian hydrocarbon is the Cambrian shale. An unconformity induced from tectonic movement during the Tongwan period is interpreted to be the fluid migration tunnel and the cause of the differential shale gas content and production. Finally, the isotopic reversals associated with maturity, pressure coefficients and tectonic evolution can both assess the preservation conditions of the reservoir and explain the differential fluid migration behaviour.

Shale gas sweet spot identification and precise geo-steering drilling in Weiyuan Block of Sichuan Basin, SW China

Based on drilling and production test data and the geological, geochemical, geophysical and rock mechanics achievements of Weiyuan Block of Sichuan Basin, “sweet spots” of shale gas were determined and geosteering technology was tested in drilling the sweet spots under complex structural background. The high quality Silurian Longmaxi Formation shale (with TOC≥2%) in the study area, thick (36.0−44.5 meters), is divided into four sublayers, from bottom to top, which differ widely in TOC (2.0%−8.1%), gas content (1.2−12.6 m3/t), porosity (0.66%−11.80%), and brittle mineral content (17.5%−98.5%). Considering gas content and fracability of shale, the layer Long 11a in Longmaxi Formation is the best “sweet spot” layer in vertical direction; horizontally, the areas with folding structure in shale reservoir have more natural fractures, and thus have better storage quality and permeability, are “sweet spots”. During drilling of the sweet spots, three-dimensional seismic and geological modeling was used to predict the depth of “sweet spot”, which was corrected in time with drilling data, and by controlling well trajectory this way, the drilling rate of “sweet spots” has been improved.

Sedimentary facies of marine shale gas formations in Southern China: The Lower Silurian Longmaxi Formation in the southern Sichuan Basin

Sedimentary facies is an important factor influencing shale gas accumulation. It not only controlls hydrocarbon generation, but also affects reservoir characteristics and distribution. This paper discusses the Lower Silurian Longmaxi Formation in the south of the Sichuan Basin. Outcrop, core, drilling and logging data identify the sedimentary facies of the formation as continental shelf facies, which is divided into two subfacies: an inner shelf and an outer shelf subfacies. These two subfacies can be further divided into seven microfacies: muddy silty shallow shelf, calcareous silty shallow shelf, muddy limy shallow shelf, storm flow, muddy deep shelf, silty muddy deep shelf and contour current microfacies. Vertical and horizontal distribution of microfacies establishes a sedimentation model of the continental shelf facies. Combined with analization or calculation of geochemical, mineralogical, physical and gas-bearing properties of samples, sedimentary microfacies is evaluated using nine parameters: total organic carbon content, effective shale continuous thickness, vitrinite reflectance, kerogen type, mineral components, porosity, permeability, water saturation and gas content. The evaluation revealed that the most favorable facies for shale gas exploration and development are the muddy deep shelf and part of the silty muddy deep shelf microfacies, with TOC more than 2%, siliceous component over 50%, clay less than 30%, porosity more than 3%, water saturation lower than 40%, gas content greater than 2 m3/t. These results provide a theoretical basis for deciston-making on the most promising areas for shale gas exploration in the Sichuan Basin and for marine shale gas exploration and development in South China.

Assessing shale gas resources of Wufeng-Longmaxi shale (O3w-S1l) in Jiaoshiba area, SE Sichuan (China) using Petromod II: Gas generation and adsorption

ABSTRACTTaking Well JY4 as example, the authors present petroleum system modeling with PetroMod software for shale gas resource assessment of Wufeng-Longmaxi shale in Jiaoshiba area, which takes account of hydrocarbon adsorption process within source rocks. On the basis of burial and thermal modeling, source rocks adsorption parameters obtained from isothermal adsorption of gas measurements were defined. The results show that the total gas content of Wufeng-Longmaxi shale is estimated in rang of 4.6–10.5 * 106 kg/km2, and the proportion of absorbed gas content is around 22–50% in Jiaoshiba area.

New method for prediction of shale gas content in continental shale formation using well logs

Shale needs to contain a sufficient amount of gas to make it viable for exploitation. The continental heterogeneous shale formation in the Yan-chang (YC) area is investigated by firstly measuring the shale gas content in a laboratory and then investigating use of a theoretical prediction model. Key factors controlling the shale gas content are determined, and a prediction model for free gas content is established according to the equation of gas state and a new petrophysical volume model. Application of the Langmuir volume constant and pressure constant obtained from results of adsorption isotherms is found to be limited because these constants are greatly affected by experimental temperature and pressures. Therefore, using measurements of adsorption isotherms and thermodynamic theory, the influence of temperature, total organic carbon (TOC), and mineralogy on Langmuir volume constants and pressure constants are investigated in detail. A prediction model for the Langmuir pressure constant with a correction of temperatures is then established, and a prediction model for the Langmuir volume constant with correction of temperature, TOC, and quartz contents is also proposed. Using these corrected Langmuir constants, application of the Langmuir model determined using experimental adsorption isotherms is extrapolated to reservoir temperature, pressure, and lithological conditions, and a method for the prediction of shale gas content using well logs is established. Finally, this method is successfully applied to predict the shale gas content of the continental shale formation in the YC area, and practical application is shown to deliver good results with high precision.

The pore size distribution and its relationship with shale gas capacity in organic-rich mudstone of Wufeng-Longmaxi Formations, Sichuan Basin, China

The pore size distribution for the 23 fresh outcrop shale samples collected from Shuanghe Town and Changning County, as well as the 14 core samples collected from the Qianqian 1 core well in southeast Chongqing, Sichuan Basin were investigated by means of low-pressure nitrogen adsorption. The main factors controlling pore development and gas accumulation in shales were discussed by integrating total organic carbon (TOC), mineralogy, and shale gas content. The results showed that open, slit-like, and parallel plate structure are major pore types that posses an average pore diameter of 3.76–8.53 nm; chiefly 2–30 nm for mesopores. The BET surface area and total pore volume are high in the Wufeng Formation and in the lower part of the Longmaxi Formation, and it's a bit lower in the upper part of the Longmaxi Formation. Consistent with the trends of TOC, that organic matter is the key controlling factor in the shale pore development. In addition, samples with higher content of clay minerals, but comparative TOC content have a larger specific surface area where clay mineral hosted pores are present. The Wufeng Formation and lower part of the Longmaxi Formation in the Sichuan Basin are preferred layers of shale reservoir fracturing due to high TOC, high rock brittleness, and high gas content.

Logging identification for the Lower Cambrian Niutitang shale reservoir in the Upper Yangtze region, China: A case study of the Cengong block, Guizhou Province

Currently, China has achieved a breakthrough in the Lower Silurian Longmaxi shale in Sichuan Basin and its surrounding areas. Compared to the Longmaxi shale, the Lower Cambrian Niutitang shale, which has a greater deposition thickness and wider distribution area, is another significant stratum for China's shale gas. Geophysical well logging is one of the most significant methods used for identification and evaluation of shale gas reservoirs throughout the process of shale gas exploration and development. In this paper, the logging response of the Niutitang shale is summarized to “four high and four low”, this was determined through a comparative analysis of three shale gas wells in the Cen'gong block. The Geochemical logging (GEM) data shows that as the depth goes deeper the content of Si (quartz) increases and the content of Al, Fe, K (Potassium), and Clay minerals decreases. In addition, the Niutitang shale mainly has the feature of a single peak or two continuous peaks in T2 spectrum on the nuclear magnetic resonance (NMR) logging response. This has a longer T2 time and greater amplitude than normal shales. The logging response of various lithology and preservation is summarized by overlapping and a cross-plot analysis with the spectral gamma-ray, resistivity, density, acoustic, and compensated neutron logging data, which are sensitive to organic-rich shales. Moreover, the resistivity and acoustic logging data are sensitive to gas content, fluid properties, and preservation conditions, which can be used as indicators of shale gas content and preservation.

The lithofacies and reservoir characteristics of the Upper Ordovician and Lower Silurian black shale in the Southern Sichuan Basin and its periphery, China

The black shale of the Upper Ordovician and Lower Silurian is a significant target for shale gas exploration in the Southern Sichuan Basin. In this study, we introduced a lithofacies classification for shale based on rock mineral composition. Because the pore structure of gas shale reservoirs are complex and greatly affect the gas storage and transport in shale, four different methods of low-pressure nitrogen gas adsorption, high-pressure mercury intrusion, scanning electron microscopy (SEM) and gas expansion methods were used to investigate the reservoir pore structure and storage space. Combined with X-ray diffraction, total organic matter content (TOC), gas content, methane adsorption, porosity and permeability and wireline data, the key factors that affect shale gas content and storage of shale gas were analyzed.According to our shale classification, three main lithofacies, i.e., calcareous mudstone (CM), high calcareous mixed mudstone (HCMM) and low calcareous mixed mudstone (LCMM), were identified in our study area. The experiment indicates that the shale has a high TOC, thermal maturity and gas content. The methane adsorption isotherms show that the sorbed gas content has a positive correlation with TOC. Difference of TOC between the three is small. Nitrogen adsorption indicates that mesopores dominate the shale pore composition and organic matter is the main source of mesopores. Mercury injection shows that the macropore volume accounts for approximately 14–22% of the total pore volume. No obvious pore structure differences were found for different lithofacies. However, taking the porosity into consideration, LCMM has the largest macropore volume. The SEM observations revealed that organic matter pores, interparticle pores and intraparticle pores are the main pore types. Interparticle pores mainly develop in LCMM which has a relatively high quartz and low carbonate content, it may be the major reason for high porosity, high macropore volume, and high free gas content of LCMM. Free gas and absorbed gas are the major storage form of shale gas. Given similar temperature and pressure conditions, the total organic matter content is the major factor that affects the adsorbed gas content. Therefore, with high free gas and adsorbed gas content, LCMMs with high total organic matter contents would be the most favorable type of lithofacies in this region.

Accumulation conditions of Lower Paleozoic shale gas from the southern Sichuan Basin, China

Based on the raw data of the organic-rich shale in the Lower Cambrian Qiongzhusi Formation and Lower Silurian Longmaxi Formation which were collected from the drilling core, we investigated the accumulation conditions of the Lower Paleozoic marine shale gas in the southern Sichuan Basin, China. The results indicate that the Qiongzhusi and the Longmaxi Formations' black shales in this region are mainly deposited in the deep water shelf sedimentary environment. Both the Qiongzhusi and Longmaxi Formations in the southern Sichuan Basin have great organic-rich shale thickness (mainly 50–300 m). The marine shales of the Qiongzhusi and the Longmaxi Formations are characterized by high total organic carbon contents (average TOC>2%), I–II1 kerogen types, highthermal maturity level (equivalent RO>1.9%), abundant rich brittle mineral (average > 50%), micro- and nanometer pore development, as well as high gas content of shale (average > 1.8 m3/t). All these features are favorable for marine shale gas generation and enrichment in the southern Sichuan Basin. Compared to the Barnett shale in North America, in which shale gas has been explored and developed successfully, it is suggested that the Lower Paleozoic in the southern Sichuan Basin would possess good conditions for shale gas accumulation. Therefore, the Qiongzhusi and the Longmaxi Formations are considered as potential targets for marine shale gas exploration, and favorable areas for shale gas enrichment are also purposed. The favorable areas for shale gas enrichment for the Qiongzhusi Formation in the southern Sichuan Basin are the Zhigong-Yibin, Changning-Gongxian, Jianwei-Muchuan, and Weiyuan areas. The favorable areas for shale gas enrichment for the Longmaxi Formation in the southern Sichuan Basin are the Longchang-Rongchang, Yibin-Luzhou-Changning, and Weiyuan areas.

Geological models of gas in place of the Longmaxi shale in Southeast Chongqing, South China

Gas-in-place (GIP) is one of the primary controlling factors in shale gas production, but studies examining GIP have been lacking for the Lower Silurian Longmaxi shale in South China. In the present study, a suite of Longmaxi shale samples was collected from an exploratory well in Southeast Chongqing, South China, and the adsorption parameters were fitted using a supercritical Dubinin-Radushkevich (SDR) model based on the high-pressure methane adsorption experiment data for the samples. The results show that the adsorbed phase density and the adsorbed gas capacity of the samples have a positive correlation with the content of total organic carbon (TOC) but a negative correlation with temperature. Combined with the geological characteristics of the Longmaxi shale in Southeast Chongqing, GIP models were constructed under three different fluid pressure conditions. The absolute adsorbed amount of the samples increases and later decreases with increasing depth with a maximum corresponding to depths between 800 and 1200 m. The fluid pressure coefficient has no obvious effect on the absolute adsorbed amount when burial depth is over 2000 m but controls the free gas content. Overpressure primarily increases the free gas content and thus increases the total gas content. The free gas content of the Longmaxi shale in the Pengshui Block is reduced to 47%–58% of that in the Fuling Block, which is the main reason for its low gas production. Further exploration of the Longmaxi Formation should be expanded to deeper burial shales in the eastern area of Southeast Chongqing.

Characterization of the reservoir in Lower Silurian and Lower Cambrian shale of south Sichuan Basin, China

Natural gas has become an important source of energy. In China, external dependency on natural gas reached 32.2%. China is rich in shale gas resources, and both government and oil companies have promoted the development of shale gas. Lower Silurian Longmaxi Formation (LSLF) shales and Lower Cambrian Qiongzhusi Formation (LCQF) shales are believed to be favorable shale gas targets in the Sichuan Basin. Oil companies have extracted gas from LSLF shale but not from LCQF shale in and around the Sichuan Basin. The total organic carbon content (TOC) increases with buried depth in LSLF shales and LCQF shales, but the organic matter (OM) in the LCQF shales is more compacted than LSLF shales. The mineral brittleness index of these shales means that they are favorable for hydraulic fracturing to generate the complex fracture geometry in both shales. The OM is rich in the pores and the surface porosity of OM is from 7.18 to 9.52% in the LSLF shale and LCQF shales with low TOC (TOC <1.0%). The LCQF shales with high TOC are poor in the OM host pores and surface porosity of OM is less than 0.1%. The gas contents of LSLF shales increase with the TOC contents, but there is a poor correlation in LCQF shales, especially in LCQF shales with TOC of greater than 3.0%. There was a linear correlation between gas content and VTOC in both shales, which was multiplied by the TOC and surface porosity. For the LCQF shales, the TOC and the surface porosity of OM are also important to the shale gas content and selection of favorable resource targets. The TOC of LCQF shales was less than 1.0% and greater than 3.0% in this paper, so the inflection point of surface porosity should be further examined in OM.

Main controlling factors and enrichment area evaluation of shale gas of the Lower Paleozoic marine strata in south China

The Lower Paleozoic shale in south China has a very high maturity and experienced strong tectonic deformation. This character is quite different from the North America shale and has inhibited the shale gas evaluation and exploration in this area. The present paper reports a comprehensive investigation of maturity, reservoir properties, fluid pressure, gas content, preservation conditions, and other relevant aspects of the Lower Paleozoic shale from the Sichuan Basin and its surrounding areas. It is found that within the main maturity range (2.5 % < EqR o < 3.5 %) of the shale, its porosity develops well, having a positive correlation with the TOC content, and its gas content is controlled mainly by the preservation conditions related to the tectonic deformation, but shale with a super high maturity (EqR o > 3.5 %) is considered a high risk for shale gas exploration. Taking the southern area of the Sichuan Basin and the southeastern area of Chongqing as examples of uplifted/folded and faulted/folded areas, respectively, geological models of shale gas content and loss were proposed. For the uplifted/folded area with a simple tectonic deformation, the shale system (with a depth > 2000 m) has largely retained overpressure during uplifting without a great loss of gas, and an industrial shale gas potential is generally possible. However, for the faulted/folded area with a strong tectonic deformation, the sealing condition of the shale system was usually destroyed to a certain degree with a great loss of free gas, which decreased the pressure coefficient and resulted in a low production capacity. It is predicted that the deeply buried shale (>3000 m) has a greater gas potential and will become the focus for further exploration and development in most of the south China region (outside the Sichuan Basin).

Whole-Aperture Pore Structure Characterization and Its Effect on Gas Content of the Longmaxi Formation Shale in the Jiaoshiba Area, Sichuan Basin

Whole-Aperture Pore Structure Characterization and Its Effect on Gas Content of the Longmaxi Formation Shale in the Jiaoshiba Area, Sichuan Basin

Geochemical and Reservoir Characteristics of the Upper Triassic Continental Shale in the Sichuan Basin, China

The drilling data and test results of a large number of shale samples collected from Upper Triassic Xujiahe Formation, in the Sichuan Basin were used to find out the distribution characteristics, geochemical characteristics, reservoir characteristics and gas-bearing property of the continental shale in Xujiahe Formation, to figure out its resource prospects. The shale reservoir of the Xujiahe Formation was high in organic matter content (with a TOC content of 0.06% to 14.8%, 2.36% on average), with an organic matter of type III kerogen, Ro% of 0.8% to 3.0% (1.62% on average). In the high maturity stage of large quantity gas generation, it is rich in brittle mineral (&gt;40%), and high in clay mineral content (average of 49.5%) which is mainly composed of mixed illite/smectite layer and illite. The shale is 1%–3% in porosity (2.73% on average). The pores are mainly nanoscale matrix ones (2 to 50 nm in size), and organic pores in local areas. The gas content of Xujiahe shale was measured at 3.01 m3/t, on average. This study suggests that Xujiahe shale has some gas resource potential; but, there are still a number of challenges and difficulties which need to be resolved in its exploration and development in the future.

Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China

This study characterizes the vertical heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin based on core description, thin sections observation, geological chemistry data interrogation, and QEMSCAN image analysis. Lithofacies associations, mineralogy, graptolite species occurrence, rock fabrics, as well as TOC (Total Organic Carbon) and gas content, change noticeably and regularly in the Lower Silurian Longmaxi marine shale within sequence stratigraphic framework. Lithofacies associations mainly include in-situ graptolite rich and siliceous shale in the transgressive systems tract (TST), micro-offsite graptolite rich shale and shale interbedded with siltstone laminaes in the early highstand systems tract (EHST), and micro-offsite graptolite rich and carbonate rich shale in the late highstand systems tract (LHST). The TST has a greater abundance of Diplogratus than EHST and LHST, and has a lesser level of Monograptus, which is conversely higher in the EHST and LHST. The TST shale is silica rich, while the LHST shale is generally clay rich. The EHST shale is more balanced in its silica and clay content than the TST and LHST are. The sedimentary structure and fabric of shale shows that shale is homogenous in the TST, with laminaes well developed in the EHST but decreasing in the LHST. TOC and gas content are highest in the TST and decrease upward. The TST, with high TOC, high gas content, high brittle minerals (silica rich) and anoxic-suboxic to dysoxic sedimentary environment, is the most potential shale gas target interval in the study area. Our research also shows that the TOC mainly controls shale gas accumulation and that the redox conditions mainly control the preservation of organic matter. The silica also plays a significant role in shale gas content due to its contribution to hydraulic fracturing. Finally, the study proposes a depositional and heterogeneity model for the Lower Silurian Longmaxi marine shale in the study area.