Longmaxi Marine Shale Research Articles

Comparative Study of Pore Structure Response in Longmaxi Marine Shale and Yanchang Continental Shale under the Combined Action of CO2 and Slickwater

Comparative Study of Pore Structure Response in Longmaxi Marine Shale and Yanchang Continental Shale under the Combined Action of CO₂ and Slickwater

Influences of shale microstructure on mechanical properties and bedding fractures distribution

The difference in microstructure leads to the diversity of shale mechanical properties and bedding fractures distribution patterns. In this paper, the microstructure and mechanical properties of Longmaxi marine shale and Qingshankou continental shale were studied by X-ray diffractometer (XRD), field emission scanning electron microscope (FE-SEM) with mineral analysis system, and nanoindentation. Additionally, the typical bedding layers area was properly stratified using Focused Ion Beam (FIB), and the effects of microstructure and mechanical properties on the distribution patterns of bedding fractures were analyzed. The results show that the Longmaxi marine shale sample contains more clay mineral grains, while the Qingshankou continental shale sample contains more hard brittle mineral grains such as feldspar. For Longmaxi marine shale sample, hard brittle minerals with grain sizes larger than 20 μm is 18.24% and those with grain sizes smaller than 20 μm is 16.22%. For Qingshankou continental shale sample, hard brittle minerals with grain sizes larger than 20 μm is 40.7% and those with grain sizes smaller than 20 μm is 11.82%. In comparison to the Qingshankou continental shale sample, the Longmaxi marine shale sample has a lower modulus, hardness, and heterogeneity. Laminated shales are formed by alternating coarse-grained and fine-grained layers during deposition. The average single-layer thickness of Longmaxi marine shale sample is greater than Qingshankou continental shale sample. The two types of shale have similar bedding fractures distribution patterns and fractures tend to occur in the transition zone from coarse-grained to fine-grained deposition. The orientation of the fracture is usually parallel to the bedding plane and detour occurs in the presence of hard brittle grains. The fracture distribution density of the Longmaxi marine shale sample is lower than that of the Qingshankou continental shale sample due to the strong heterogeneity of the Qingshankou continental shale. The current research provides guidelines for the effective development of shale reservoirs in various sedimentary environments.

Differences in Pore Type and Pore Structure between Silurian Longmaxi Marine Shale and Jurassic Dongyuemiao Lacustrine Shale and Their Influence on Shale-Gas Enrichment

The Silurian Longmaxi (S1l) marine shale and Jurassic Dongyuemiao (J1d) lacustrine shale in the Sichuan Basin, West China have attracted considerable attention from the oil-and-gas industry in China. Currently, the differences in pore types and pore structures between them are poorly understood, which has limited shale-resource exploration in the Sichuan Basin. This paper systemically compares the pore characteristics of Longmaxi shale and Dongyuemiao shale and investigates their impact on shale-gas enrichment by integrating field-emission scanning electron microscopy (FE–SEM), X-ray diffraction (XRD), low-pressure gas (CO2 and N2) adsorption and mercury-intrusion porosimetry, high-pressure sorption isotherms, gas-saturation measurement, molecular-dynamics simulation, etc. The results show that the S1l organic-rich marine shale and the J1d lacustrine shale have different pore types and pore structures. The S1l shale is dominated by organic pores, mainly micropores and mesopores with ink-bottle-like pore shapes, while the J1d shale is primarily composed of clay-mineral pores, mainly mesopores and macropores with slit- or plate-like pore shapes. Organic pores can provide considerable storage space for shale-gas enrichment in S1l marine shale, which also determines the adsorption capacity of shale reservoirs. Although organic pores are not the most prevalent in the Dongyuemiao lacustrine shale, they also play an important role in enhancing reservoir quality and absorbed-gas enrichment. Clay-mineral pores contribute weakly to the storage space of J1d-lacustrine-shale reservoirs. Mesopores are the most important form of storage space in both S1l shale and J1d shale, contributing significantly to shale-gas enrichment. Micropores are secondary in importance in S1l marine shale, while macropores are secondary contributors to pore volume in J1d lacustrine shale.

Factors Controlling Brittleness of the Wufeng–Longmaxi Shale in the Yangtze Platform, South China: Insights from Geochemistry and Shale Composition

Brittleness index is an important parameter used to select favorable fracturing intervals during shale gas exploitation. Mineral compositions exert a significant influence on rock brittleness, and various grain assemblages can be deposited under different paleo-environmental conditions. The Wufeng–Longmaxi marine shale is a hot spot of shale gas exploitation in China. However, for the Wufeng–Longmaxi shale, the relationship between sedimentary environments, grain assemblages, and shale brittleness are rarely discussed. To address these problems, a series of experiments including petrographic observations, mineral compositions, rock mechanics, and major (trace) element analyses were carried out on shale samples from the Wufeng–Longmaxi formations. The Wufeng–Longmaxi formations are divided into upper Longmaxi formation (ULMX), lower Longmaxi formation (LLMX), and Wufeng formation (WF). The results show that WF shale samples deposited under a sedimentary environment with low terrigenous detrital influx, suboxic depositional water, and high paleoproductivity are characterized by the highest energy-based BI, compared to ULMX and LLMX shale samples. Dolomite in the samples grew in situ during early diagenesis. Redox conditions, terrigenous detrital flux control authigenic carbonate contents, and the oxic depositional water of the ULMX formation restrain carbonate mineral formation. In contrast, the suboxic sedimentary environment of the LLMX and WF allowed the generation of carbonate minerals. Compared with the WF, the larger terrigenous detrital flux of LLMX formation do favor more authigenic carbonate formation. The paleoproductivity affects biogenic quartz generation, and abundant biogenic quartz, primarily occurring in the form of micron-size microcrystalline quartz in the shale matrix, and can connect the silt-size brittle minerals to form a mechanical framework, which makes a strong positive contribution to shale brittleness. Terrigenous detrital influx decreases brittleness because the weakening effect of terrigenous clay minerals on shale brittleness is greater than the strengthening effect of terrigenous brittle minerals on shale brittleness.

Differences in micromechanical properties of shales from different depositional environment: A case study of Longmaxi marine shale and Yanchang continental shale using nanoindentation

An understanding of the mechanical properties of reservoir shale is of great significance for the efficient development of shale gas. Both marine and continental shale gas reservoirs in China have considerable development potential, but their different depositional environments may lead to substantial differences in their mechanical properties, which can result in production efficiency differences. In this study, nanoindentation, X-ray diffraction, backscattered electron imaging, and energy-dispersive X-ray spectroscopy were used to determine and analyze the mechanical properties and microtexture of marine and continental shale samples. The geogenesis of the microtexture of marine and continental shales and its influence on the mechanical properties were discussed. The results show that the elastic modulus of marine and continental shale samples are similar, but the hardness of latter is greater. The similar elastic modulus of the two shale samples may result from similar mineralogy. Due to differences in deposition and diagenesis, the marine shale sample forms a clay support matrix and the continental shale sample forms a rigid clastic support matrix, which results in lower hardness in the former and higher hardness in the latter. The low hardness of the shale with a clay support matrix indicates that it may be subject to more severe proppant embedment issue. The experimental results provide a useful reference for the development of these two types of shale gas reservoirs.

Pore Characterization of Pyrite in the Longmaxi Formation Shale in the Upper Yangtze Area of China

Pyrite is widely distributed in the Longmaxi marine shale in the Upper Yangtze area of China. Pyrite, one of the important components of shale, has an important influence on the enrichment of shale gas. However, there are currently only a few studies on this topic. Based on shale samples from drilling cores using field emission scanning electron microscopy, the pore characteristics of pyrite from the Longmaxi Formation in the Upper Yangtze area of China are studied. The results showed that the intergranular pores of pyrite and abundant organic pores in the organic matter pyrite assemblages are developed in the Longmaxi Formation shale in the study area. Most pyrite framboid pores have triangular or irregular quadrilateral shapes, with pore diameters ranging from 0 to 240 nm. Pores with diameters of 80–240 nm are the major reservoir spaces for shale gas within the pyrite framboids. The average contribution rate of pyrite framboids to shale pores reaches 3.21%, and the highest contribution is 5.66%, indicating that the pyrite pores may have a favorable contribution to the shale reservoir pore system, but the contribution degree is low.

Experimental Investigation on the Crack Evolution of Marine Shale with Different Soaking Fluids

Hydration induced cracks could promote the complexity of hydraulic fractures in marine shale gas reservoir. But the evolution process and forming mechanism has not been fully investigated. In this paper, Longmaxi marine shale were collected and immersed in three types of fluids (distilled water, fracturing fluid, and mineral oil) for more than 10 days. The spatial-temporal evolution of soaking fractures was recorded and analyzed. A fracture mechanical model was established, considering the effects of in-situ stress, fluid pressure, hydration stress, and capillary force. The promotion mechanism of hydration cracks in forming complex fracking network was discussed. Results showed that hydration fractures were extremely developed and evenly distributed in a state of network for specimens immersed in distilled water. For specimens soaked in fracturing fluid, the hydration cracks were moderately developed for the addition of anti-swelling agent. Fractures were rarely developed for specimens treated in mineral oil. The hydration fractures were mainly formed in the first 5 h and showed strong anisotropy. Cracks parallel to the bedding planes accounted for the vast majority, with a small proportion developed in vertical direction. Theoretical calculations indicated that the stress intensity factor (SIF) caused by hydration stress and capillary force was greater than the measured fracture toughness. The micro crack would probably propagate along bedding planes and grow up into macro horizontal fractures, which promoted the formation of crisscrossing fracture network in shale gas formation.

High-quality marine shale reservoir prediction in the lower Silurian Longmaxi Formation, Sichuan Basin, China

For the lower Silurian Longmaxi marine shale reservoir in the Jiaoshiba area, Sichuan Basin, China, the traditional P-impedance ([Formula: see text]) is insensitive for predicting good reservoirs. As an integral indicator of borehole radioactivity that is substantially corresponding to the organic richness, the uranium curve is qualified to identify the abundance of organic matter. Therefore, to efficiently comprehend the shale distribution in the Jiaoshiba area, we have adopted a so-called pseudo-P-impedance ([Formula: see text]), which is constructed from the P-impedance and the uranium (U) log and spatially computed from impedance inversion of the zero-offset seismic. The [Formula: see text] log shows an obvious correlation with the organic richness of the shale. The thickness of the high-quality shale derived from the inverted [Formula: see text] cube shows a higher correlation with the log data compared to the traditional P-impedance cube. The distribution of predicted high-quality shale is strongly influenced by the fault systems: (1) Although the fault development zone might lead to a distorted image of the seismic and weak shale evaluation, the shale gas cannot be efficiently preserved in these places, and (2) high-quality shale reservoirs are mainly distributed in the not-faulted area and show a general northeast–southwest trend. Generally, the introduced [Formula: see text] inversion is suitable for the seismic frequency range and could be applied to other similar exploration areas.

Applying isotopic geochemical proxy for gas content prediction of Longmaxi shale in the Sichuan Basin, China

Abstract Numerous studies have been conducted on the isotopic geochemical characteristics of shale gas. However, a systematic study of the relationship between the isotopic geochemical characteristics and gas content has not been addressed to date. In this study, we investigated the geochemical and isotopic compositions of shale gas samples, and the gas content of the Lower Silurian Longmaxi marine shale in the Huangjinba area, southern Sichuan Basin, China. In addition, we analyzed the quantitative relationship between the geochemical parameters and the gas content. The Longmaxi shale gas is a dry gas with a low wetness (0.12%–0.67%), dominated by methane (89.49%–99.00%) with a small amount of ethane (0.11%–0.61%). The average values of δ13Cmethane, δ13Cethane and δ13Cpropane are −29.8‰, −35.0‰, and −33.2‰, characterized by a partial isotopic reversal (δ13Cmethane > δ13Cpropane > δ13Cethane) with a maturity level (Ro ≈ 2.30%–2.51%). The total gas content of the Longmaxi shale varies widely from 0.42 m3/t to 3.88 m3/t. Correlation analyses revealed that the ethane isotope (δ13Cethane) and the magnitude of isotopic reversal (δ13Cmethane - δ13Cethane) exhibit strong correlations with the total gas content and the free gas content. This study demonstrates that carbon isotopic reversal of shale gas largely depends on the secondary cracking, and thermal maturity and residual liquid hydrocarbons content are important factors affecting the magnitude of carbon isotopic reversal. Based on the quantitative study conducted in this paper, we provide a new proxy for predicting the gas content of high maturity shale using an isotopic method.

川东南龙马溪组海相页岩纹层发育特征

川东南龙马溪组海相页岩纹层发育特征

Marine shale reservoir evaluation in the Sichuan Basin-A case study of the Lower Silurian Longmaxi marine shale of the B201 well in the Baoluan area, southeast Sichuan Basin, China

Based on the total organic matter (TOC) content, brittle minerals (quartz + feldspar) content, total gas content, porosity and production data of eight vertical and twenty-three horizontal shale gas wells in the Sichuan Basin, a new reservoir evaluation method for the marine shale reservoirs of the Sichuan Basin is developed. In this study, based on the analytic hierarchy process (AHP) and deviation method, a comprehensive evaluation index (CEI) was proposed to evaluate the marine shale reservoir. According to the CEI and the production data, three type marine shale reservoirs were proposed. The CEI was applied to evaluate the Wufeng-Longmaxi marine shale of the B201 well. The results show that the Wufeng-Longmaxi marine shale is the low quality shale reservoir. The comprehensive evaluation criteria proposed in this study can also be applied to evaluate the marine shale reservoirs in other areas in the Sichuan Basin through the verification of several other shale gas wells in the Sichuan Basin.

Comparative study on the Lower Silurian Longmaxi marine shale in the Jiaoshiba shale gas field and the Pengshui area in the southeast Sichuan Basin, China

The Jiaoshiba shale gas field and Pengshui area are both located in the southeast Sichuan Basin with only 100 km apart. Although these two areas obtained shale gas flow from the Lower Silurian Longmaxi marine shale, there is a huge difference of production in these two areas where the Jiaoshiba shale gas field is more productive than the Pengshui area. In order to figure out the reason that caused this difference, this study analyzed the Longmaxi marine shale in these two areas by using drilling cores, and mineralogical and geochemical data. The results show that the Jiaoshiba shale gas field has a higher quality shale reservoir (higher content of quartz, higher porosity, higher permeability and higher TOC (Total Organic Carbon)) in the Lower Silurian Longmaxi Formation than that of the Pengshui area. The Lower Silurian Longmaxi marine shale in the Jiaoshiba shale gas field contains a higher total gas content (3.65 m3/ton in average) than that of the Pengshui area (1.19 m3/ton in average). Through structure analysis, this study found that the Jiaoshiba shale gas field and the Pengshui area located in the different tectonic units. The Jiaoshiba shale gas filed is located in the East Sichuan fold belt (wide spaced anticlines area) at the west side of the Qiyue mountain fault where less fractures are developed and the pressure coefficient is more than 1.5, resulting in much more free gas preserved in the shale reservoirs in the Lower Silurian Longmaxi Formation (the ratio of free gas content and absorbed gas content is 1.6), while the Pengshui area is located in the Hunan-Hubei-Guizhou thrust belt area at the east side of the Qiyue mountain fault where much more fractures are developed and the pressure coefficient is less than 1.0, leading to less free gas preserved in the Longmaxi marine shale (the ratio of free gas content and absorbed gas content is 0.6), that is why the shale reservoir in the Pengshui area has a lower total gas content than that in the Jiaoshiba shale gas field.

Study on acoustic emission and X-ray computed-tomography characteristics of shale samples under uniaxial compression tests

The acoustic-emission (AE) nondestructive monitoring method was used to investigate the deformation–failure of Longmaxi marine shale samples from the Sichuan Basin in uniaxial compression tests. Millions of AE ring counts were recorded by six sensors that were mounted on the surface of cylindrical specimens. The AE ring counts rate and energy rate were applied to study crack development during fracturing. AE locations at different stress stages during the loading process were obtained to study the fracture spatial distribution and the crack-propagation tendency. An X-ray computed tomography (CT) system was used to scan samples after damage. CT images were reconstructed to acquire three-dimensional pictures that show the internal invisible-fault system. The combination of AE method and CT technique helps explain temporal and spatial crack evolution. Variable damage evolution was determined by the number of AE ring counts, which demonstrates the degradation behavior of shale.

Heterogeneity characterization of the lower Silurian Longmaxi marine shale in the Pengshui area, South China

The heterogeneity of shale is significant for the evaluation and “sweet spot” prediction of a shale gas reservoir. Core observations, thin sections, field emission scanning electron microscopy (FE-SEM), nitrogen gas adsorption (N2GA) and geochemical analyses were performed on shale samples from the Lower Longmaxi Formation in the Pengshui area of South China. In this study, the macroscopic and microscopic heterogeneities of the Longmaxi shale are revealed, and their origins and inner link are also discussed. The results show that three systems tracts were developed in the Lower Longmaxi Formation: a transgressive systems tract (TST), early highstand systems tract (EHST) and late highstand systems tract (LHST). From TST to LHST, TOC (total organic carbon), siliceous minerals (quartz+feldspar), and pyrite show an upward decreasing trend in weight content, while the clay minerals and carbonate contents increase upward. Hence, the TST, EHST and LHST shales are generally characterized by organic-rich shale lithofacies, organic-moderate shale lithofacies, and organic-lean shale lithofacies, respectively. The in situ gas content decreases from TST to LHST and primarily depends on TOC content. The sedimentary environment of the TST shale is an anoxic environment with high paleoproductivity, which then evolves to a dysoxic-oxic environment in the EHST shale and an oxic environment in the LHST shale with relatively low paleoproductivity. Organic matter pores are the primary contributors to the total pore volume in the TST shale, and then, the pore content and role in porosity decrease upward from EHST to LHST. However, the proportions of clay-related pores and brittle mineral-related pores gradually elevate from the TST shale to the LHST shale. The sedimentary environment, including water depth, redox conditions, paleoproductivity, terrigenous input and hydrodynamics, etc., control the development of organic matter, mineral composition, lithofacies association, color, bedding and palaeobios in the Lower Longmaxi shales, which constitute the macroscopic heterogeneity. Nevertheless, the microscopic heterogeneity of shale originates from diagenesis/catagenesis. Specifically, shales are primarily composed of interparticle pores and clay-related pores during deposition, and the porosity is reduced primarily under mechanical compaction and chemical cementation. As the burial depth and diagenetic degree increase, a large number of organic matter pores and dissolution pores begin to appear, which are associated with the hydrocarbon generation process. Moreover, macroscopic shale composition plays a crucial role in development levels of microscopic shale pores.

Experimental Investigation of Evolution of Pore Structure in Longmaxi Marine Shale Using an Anhydrous Pyrolysis Technique

To better understanding the evolutionary characteristics of pore structure in marine shale with high thermal maturity, a natural Longmaxi marine shale sample from south China with a high equivalent vitrinite reflectance value (Ro = 2.03%) was selected to conduct an anhydrous pyrolysis experiment (500–750 °C), and six artificial shale samples (pyrolysis products) spanning a maturity range from Ro = 2.47% to 4.87% were obtained. Experimental procedures included mercury intrusion, nitrogen adsorption, and carbon dioxide adsorption, and were used to characterize the pore structure. In addition, fractal theory was applied to analyze the heterogeneous pore structure. The results showed that this sample suite had large differences in macropore, mesopore, and micropore volume (PV), as well as specific surface area (SSA) and pore size distributions (PSD), at different temperatures. Micropore, mesopore, and macropore content increased, from being unheated to 600 °C, which caused the pore structure to become more complex. The content of small diameter pores (micropores and fine mesopores, <10 nm) decreased and pores with large diameters (large mesopores and macropores, >10 nm) slightly increased from 600 to 750 °C. Fractal analysis showed that larger pore sizes had more complicated pore structure in this stage. The variance in pore structure for samples during pyrolysis was related to the further transformation of organic matter and PSD rearrangement. According to the data in this study, two stages were proposed for the pore evolution for marine shale with high thermal maturity.

Characterization of the Lower Silurian Longmaxi marine shale in Changning area in the south Sichuan Basin, China

On the basis of the core description, thin sections, and geochemistry data, we characterized the Lower Silurian Longmaxi marine shale in the Changning area in the south Sichuan Basin. Ten lithofacies were identified in the Lower Silurian Longmaxi marine shale: (a) massive silty shale (Lithofacies A); (b) laminated siliceous calcareous shale (Lithofacies B); (c) calcareous shale (Lithofacies C); (d) silty dolomitic shale (Lithofacies D); (e) argillaceous siltstone (Lithofacies E); (f) siltstone (Lithofacies F); (g) laminated silty shale (Lithofacies G); (h) silty calcareous shale (Lithofacies H); (i) argillaceous lime shale (marl) (Lithofacies I); and (j) bentonite (Lithofacies J). Obvious heterogeneity occurred in different lithofacies in terms of mineralogy, total organic carbon (TOC) content, porosity, permeability, pore surface area, total pore volume, and total gas content. Among these lithofacies, Lithofacies B has the highest porosity (5.4%), pore surface area (12.79 m2/g), total pore volume (0.015 cc/g), TOC content (4.37%), total gas content (3.4 m3/ton), and relatively high brittle minerals, suggesting great shale gas potential. Lithofacies A, C, and D have a relatively high brittle minerals, porosity, pore surface area, total pore volume, TOC content, and total gas content, which means that these 3 lithofacies show relatively good potential for shale gas. The rest of the lithofacies have low brittle minerals content, porosity, pore surface area, total pore volume, TOC content, and total gas content, representing poor shale gas potential.

Continental shale pore structure characteristics and their controlling factors: A case study from the lower third member of the Shahejie Formation, Zhanhua Sag, Eastern China

Since shale oil and gas primarily occur in micro-nano pores and fractures, research on pore structure characteristics is important to understand shale oil and gas accumulation mechanisms. Studies on the pore structure of the lower third member of the Shahejie (Es3l) Formation in Zhanhua Sag, Jiyang Depression, Bohai Bay Basin, Eastern China, are quite limited, thereby, restricting further investment on shale oil and gas exploration. We studied continental shale pore structure characteristics and their controlling factors by using a series of laboratory experiments on core samples taken from the Luo-69 Well. The results demonstrate that the Es3l continental shale has a high proportion of calcareous minerals, low siliceous minerals, and low clay minerals. It is characterized by low total organic carbon (TOC) content, low thermal maturity, and Type I and II organic matter. Five different kinds of pore spaces are developed in the shale samples: organic matter-hosted pores, intergranular pores, intercrystalline pores, dissolution pores, and micro-fractures, with the majority of slit-shaped and ink-bottle-shaped pores. Macropores make the greatest contribution to the total pore volume, whereas micropores provide the major surface area. As the organic-rich laminated calcareous shale (ORLCS) presents a larger pore volume, surface area, and mercury withdrawal efficiency, it is a favourable shale lithofacies for shale oil and gas storage and flow. Compared with the Longmaxi marine shale, macropores well-developed in the Es3l shale make great contribution for free hydrocarbon accumulation. Samples with different TOC contents, mineral compositions, thermal maturities, and lamellar layers exhibit distinct differences in pore structure. Mineral composition and thermal maturity primarily affect micropores and mesopores. Macropores are influenced by mineral composition, TOC content, thermal maturity, and lamellar layers.

The application of geostatistical inversion in shale lithofacies prediction: a case study of the Lower Silurian Longmaxi marine shale in Fuling area in the southeast Sichuan Basin, China

Based on cores, well logs and seismic data, we established the isochronous sequence stratigraphic framework of the Lower Silurian Longmaxi Formation and predicted the shale lithofacies distribution within the sequence stratigraphic framework using geostatistical inversion. The results of our study show that the Lower Member of the Longmaxi Formation is a third order sequence that includes a transgressive systems tract (TST), an early highstand systems tract (EHST) and a late highstand systems tract (LHST). Four lithofacies units have been recognized, specifically siliceous shale, argillaceous shale, calcareous shale and mixed shale. The results of geostatistical inversion reveal that the TST is characterized by flaky siliceous shale and some sparsely distributed calcareous shale. The EHST is dominated by mixed shale with minor amounts of siliceous shale, which occurs in only a small area. Moreover, in the LHST, argillaceous shale occupies almost the entire study region. Comparing to traditional geological research with geophysical research, the vertical resolution of the predictive results of geostatistical inversion could reach 1–2 m. Geostatistical inversion effectively solves the problem of precisely identifying the lithofacies in the Fuling shale gas field and predicting their spatial distribution. This successful study showcases the potential of this method for carrying out marine shale lithofacies prediction in China and other locations with similar geological backgrounds.

Ono–Kondo Model for Supercritical Shale Gas Storage: A Case Study of Silurian Longmaxi Shale in Southeast Chongqing, China

Shale gas storage is a dominant factor to economically evaluate the shale play. A series of Lower Silurian Longmaxi marine shale samples in southeast Chongqing, China, were collected to investigate the reservoir characteristics, and a suit of methane adsorption isotherms were fitted using a supercritical Ono–Kondo model to better understand the adsorption capacity of Longmaxi shale. The saturated adsorption of a monolayer presents a greatly positive relationship with the total organic carbon (TOC) content. A negative relationship with clay was observed due to the predominant influence of organic matter on the methane adsorption. Methane adsorption also increases with increasing pressure and decreases with increasing temperature. On the basis of the relationships, one new estimation algorithm related to TOC content, pressure, and temperature was established to calculate the methane adsorption capacity on the basis of the Ono–Kondo model. Furthermore, with higher TOC content, the adsorption capacity of shal...

Molecular and carbon isotopic variation in 3.5 years shale gas production from Longmaxi Formation in Sichuan Basin, China

A time series of produced shale gas samples from Lower Silurian Longmaxi Formation (Fm.) were collected from six production wells during 3.5 years production period from the Weiyuan and Changning shale gas pilots in Sichuan basin, China. The molecular compositions and carbon isotopes of CH4, C2H6, C3H8 and CO2, and the hydrogen isotope of methane were analyzed for these samples by an integrated method of gas chromatography combined with mass spectrometry. The results showed that the produced shale gases are dominated by CH4 (90.1–99.3%) with minor C2H6 (0.3–0.8%) and non-hydrocarbon gases, and have low wetness (0.3–0.8%). The non-hydrocarbon gases are mainly CO2 and N2, and trace amount of He. The Longmaxi shale gases display completed reversal pattern of carbon isotopic compositions with carbon number (i.e., δ13C1 > δ13C2 > δ13C3) except for Wells W201 and W201-H1 with normal patterns between C2H6 and C3H8 (i.e., δ13C2 < δ13C3), and it is a mixture of oil cracking gas and kerogen cracking gas at high-over level of thermal maturity. Some CO2 (δ13CCO2 ranging from −2.5 to −6.0‰) is mainly derived from the decomposition of carbonate minerals.CH4 concentration and the carbon isotopes of methane and ethane during 3.5 years shale gas production from year 2012 to 2016 displayed small fluctuations, which possibly suggested that gas supply from shale matrix to fracture network after hydraulic fracturing is abundant. The Weiyuan shale gases show larger decrease of CH4 content than the Changning shale gases, indicated more adequate supply in the Changning area. The difference in δ13C1 values between horizontal and vertical wells on the same drilling site in the Weiyuan pilot indicated that the vertical heterogeneity of Lower Silurian Longmaxi shale plays an important role to shale gas production. Interestingly, the shale gases in the Weiyuan pilot display much lighter δ13C1 (−34.46 to −36.82‰) and δ13C2 (−37.59 to −41.89‰) values than those (δ13C1 = −27.18–−27.27‰, δ13C2 = −33.70–−34.14‰) in the Changning pilot. The difference in carbon isotopic compositions in Weiyuan and Changning pilots mainly attributes to mixing between varied proportion of oil cracking gas and kerogen cracking gas because of the regional heterogeneity of the Longmaxi marine shale, in particular amount of residual oil retained in organic matter rich shale. The isotopic difference between Weiyuan and Changning shale gases doesn't disappear in the period about 3.5 years of shale gas development, which further suggests the regional heterogeneity of retained residual oil exists in the Longmaxi Fm. marine shale.