Organic-rich Shale Reservoirs Research Articles

Evolution of Pore Spaces in Marine Organic-Rich Shale: Insights from Multi-Scale Analysis of a Permian–Pennsylvanian Sample

The quantitative evolution pattern of pore space and genetic pore types along the maturation process in organic-rich shale reservoirs is unclear, which affects the assessment of shale storage capacity and petroleum production. A black shale outcrop sample from Kansas that is of Permian–Pennsylvanian age was collected and subjected to thermal simulation experiments at 10 different maturity stages to understand the pore sizes and pore types. Scanning electron microscopy (SEM) and image processing were used to characterize the full-scale pore-size distribution and volume evolution of this shale sample by combining low-temperature gas (CO2 and N2) physisorption and mercury intrusion porosimetry (MIP) in order to discuss the effects of hydrocarbon generation and diagenesis (HG&D) on pore development at different pore sizes. The study showed that the original shale sample is dominated by slit-like pores, with mainly organic matter (OM) pores distributed in 0–100 nm, intraparticle pores (Intra-P) of clays distributed in 30–100 nm, and interparticle pores (Inter-P) distributed in 100–1000 nm. With the increase in maturity or Ro, the OM pores increased gradually, and the OM pore-size distribution diverged to the two poles. In the oil generation stage, the OM pores were distributed in the range of 30–100 nm, while in the gas generation stage, the OM-hosted pores were mainly distributed in the range of 10–20 nm and 100–500 nm. Further into the over-maturity stage, the OM pores were mainly distributed in the range of 0–10 nm and >100 nm. The pore volume distribution across the whole pore sizes showed that the pore volume of low-maturity shale samples was mainly provided by 100–1000 nm (macropores), and the pore volumes of 0–2 nm, 30–100 nm and 1000+ nm pores gradually increase with increasing thermal maturity, with the final pore-size distribution having four peaks at 0–2, 30–100, 500–1000 nm, and 10–100 µm. Hydrocarbon generation mainly affects the pore volume in the 0–2 nm and 100–1000 nm intervals, with a positive correlation. The 2–30 nm and 30–100 nm pores were likely controlled by diagenesis, such as mineral transformation, illitization, and cementation during the maturation process.

Organic Mesopore and Micropore Structures and Their Effects on Methane Adsorption in Marine Organic-Rich Shales

Organic pores in organic-rich shale reservoirs can provide major pore space for adsorbed and free gas storage. In this study, the organic micropore and mesopore structures in organic-rich shale reservoirs and their influence on gas adsorption are investigated by comparing CO2, N2, and methane adsorption isotherms for organic matter-combusted and non-combusted organic-rich shale samples taken from the Wufeng–Longmaxi Formation in the Sichuan Basin. Experimental results show that organic pores in organic-rich shales from the Wufeng–Longmaxi Formation in Sichuan Basin are mainly smaller than 15 nm in diameters. Volumes of organic micropores and mesopores are mainly distributed in the diameter size ranges of 0.3–0.9 and 2–8 nm, respectively. Specific surface areas of organic micropores and mesopores are mainly distributed in the diameter size ranges of 0.3–0.7 and 2–4 nm, respectively. Organic pores dominate in the organic-rich shales from the Wufeng–Longmaxi Formation, contributing 49–77% and 50–84% of the entire micropore and mesopore volumes and specific surface areas, respectively. Organic micropores contribute 42–84% and 44–85% of the entire micropore volume and specific surface area, respectively, and organic mesopores contribute 48–84% and 59–89% of the entire mesopore volume and specific surface area, respectively. Organic pores are dominant pore spaces for adsorbed methane in organic-rich shale reservoirs and contribute 75–87% of the total amount of adsorbed methane in shales from the Wufeng–Longmaxi Formation. Outcomes of this study demonstrate that organic matter combustion is a useful method for evaluating organic pores in organic-rich shales mainly according to following lines of evidence: (1) after combustion, samples have low volumes and specific surface areas for micropores and mesopores as well as extremely low contents of adsorbed methane. This suggests that combustion does not result in the generation of <15 nm inorganic micropores and mesopores in clay minerals to provide pore space for adsorbed methane. (2) The total organic carbon content (TOC) positively correlates with the organic pore volume and specific areas as well as the absolute amount of methane adsorption, suggesting that organic pores determined in this study are mainly controlled by TOC values and combustion caused the removal of organic micropores and mesopores.

New Insight into Enhancing Organic-Rich Shale Gas Recovery: Shut-in Performance Increased through Oxidative Fluids

Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components’ dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery.

H2, CO2, and CH4 Adsorption Potential of Kerogen as a Function of Pressure, Temperature, and Maturity.

We performed molecular dynamics simulation to elucidate the adsorption behavior of hydrogen (H2), carbon dioxide (CO2), and methane (CH4) on four sub-models of type II kerogens (organic matter) of varying thermal maturities over a wide range of pressures (2.75 to 20 MPa) and temperatures (323 to 423 K). The adsorption capacity was directly correlated with pressure but indirectly correlated with temperature, regardless of the kerogen or gas type. The maximum adsorption capacity was 10.6 mmol/g for the CO2, 7.5 mmol/g for CH4, and 3.7 mmol/g for the H2 in overmature kerogen at 20 MPa and 323 K. In all kerogens, adsorption followed the trend CO2 &gt; CH4 &gt; H2 attributed to the larger molecular size of CO2, which increased its affinity toward the kerogen. In addition, the adsorption capacity was directly associated with maturity and carbon content. This behavior can be attributed to a specific functional group, i.e., H, O, N, or S, and an increase in the effective pore volume, as both are correlated with organic matter maturity, which is directly proportional to the adsorption capacity. With the increase in carbon content from 40% to 80%, the adsorption capacity increased from 2.4 to 3.0 mmol/g for H2, 7.7 to 9.5 mmol/g for CO2, and 4.7 to 6.3 mmol/g for CH4 at 15 MPa and 323 K. With the increase in micropores, the porosity increased, and thus II-D offered the maximum adsorption capacity and the minimum II-A kerogen. For example, at a fixed pressure (20 MPa) and temperature (373 K), the CO2 adsorption capacity for type II-A kerogen was 7.3 mmol/g, while type II-D adsorbed 8.9 mmol/g at the same conditions. Kerogen porosity and the respective adsorption capacities of all gases followed the order II-D &gt; II-C &gt; II-B &gt; II-A, suggesting a direct correlation between the adsorption capacity and kerogen porosity. These findings thus serve as a preliminary dataset on the gas adsorption affinity of the organic-rich shale reservoirs and have potential implications for CO2 and H2 storage in organic-rich formations.

Experimental investigation on the pyrolysis process and product distribution characteristics of organic-rich shale via supercritical water

Low-medium maturity organic-rich shale reservoirs have garnered increasing attention due to their enormous oil and gas generation potential. In this study, the pyrolysis conversion process and product distribution characteristics of shale core samples via supercritical water (SCW) were investigated. The yield of shale oil increased from 4.5 wt% at 385 °C to 15.13 wt% at 425 °C, with the maximum formation rate of shale oil ranging from temperatures of 405 °C to 425 °C. The thermal bitumen reached 15.11 wt% at 405 °C before rapidly decreasing to 3.2 wt% at 425 °C. In the pyrolysis process of shale cores via SCW, the intermediate thermal bitumen produced by thermal cracking of kerogen was retained in the cores and continued to be decomposed into shale oil and gas with the increase of SCW temperature. Simultaneously, a large number of pores were formed in the core matrix due to the massive decomposition of kerogen and thermal bitumen. The increase in SCW temperature greatly decreased the heavy components as well as increased the light components in shale oil. Additionally, aliphatic hydrocarbon cracking or Diels-Alder type aromatization reactions resulted in an increase in aromatic hydrocarbons and a decrease in the H/C atomic ratio of shale oil. Raising SCW temperature increased the content of C2-C5 hydrocarbon gases and the alkenes/alkanes ratio, which was related to the secondary cracking. The important findings of the pyrolysis conversion process and product distribution characteristics of shale cores via SCW not only enrich the theoretical basis in this area, but also provide strong support for the use of SCW in the in-situ conversion of low-medium maturity organic-rich shale reservoirs.

Microstructure Characterization Techniques for Shale Reservoirs: A Review

The microstructure of shale reservoirs refers to the distribution of mineral–organic matter, pore–fracture features, diagenetic processes, and their interrelations. The comprehensive and accurate analysis of the shale microstructure plays a critical role in formulating a reasonable development plan and optimizing measures to enhance oil or gas recovery. To explore the microstructure characterization, the mineral and organic matter compositions as well as the pore types and distributions of organic-rich shale reservoirs were investigated using a series of advanced techniques, including focused ion beam–scanning electron microscopy and atomic force microscopy. This review establishes a model of pore distribution of the layered structure of shale reservoirs based on ideal shale laminae model. Among them, quartz and carbonate laminae can be classified as grain laminae clay minerals and organic matter and pyrite can be combined into organic matter aggregate due to the symbiotic relationship between pyrite, organic matter and clay minerals. Microcracks of diverse diagenetic origins can be classified together. This review also systematically summarizes the microcharacterization techniques and different characteristics of organic-rich shale reservoirs, thereby paving the way for the establishment of shale cross-scale characterization techniques.

Microstructural analysis of organic matter in shale by SAXS and WAXS methods

Characterizing the kerogen-hosted pore structures is essential to understand the adsorption, transport and storage potential in organic-rich shale reservoirs. In this paper, we first separated the organic matter (kerogen) from the mineral matrix in four different shale samples of the Bakken Formation with different thermal maturities and then analyzed their chemical compositions using the wide-angle X-ray scattering (WAXS) method. Next, we acquired small-angle X-ray scattering (SAXS) to characterize the structure of the organic matter and see how these two will relate. The WAXS results showed that the isolated kerogens have high purity (free of inorganic minerals) and retain different chemical compositions. Moreover, SAXS analysis revealed that the isolated kerogens have similar radius of gyration (Rg) which is around 90 Å and the molecules are in the compact mode. Based on the pore size distribution analysis from the SAXS data, two main peaks were found in all of these four samples with one peak less than 40 Å and the other one larger than 1000 Å. Also, the TEM images revealed that Sample 1 is abundant in pores with sizes around 20 nm while Sample 2 does not have pores of that size, which agrees with the results from the pore size distribution that was obtained from the SAXS method. Ultimately, this study exhibits how different analytical instruments can provide us with useful information from complex structures of geomaterials.

Origin of Dolomite in Lacustrine Organic-Rich Shale: A Case Study in the Shahejie Formation of the Dongying Sag, Bohai Bay Basin

In most organic-rich shale reservoirs, dolomite is widely distributed and has different types and crystal sizes. However, the characteristics and formation mechanism of the dolomites in organic-rich shale are still poorly understood. Petrographic and geochemical analyses were performed to interpret the formation of dolomite in the lacustrine organic-rich shale of the Shahejie Formation, Dongying Sag, Bohai Bay Basin. Four types of dolomites, which represent episodic recrystallization, were classified based on crystal size and shape: 1) micritic dolomite (Dol-1), 2) sub-to euhedral (cloudy cores with clear rims) dolomite (planar-e) (Dol-2), 3) anhedral dolomite (coarse planar-s to nonplanar crystals) in phosphatic particles (Dol-3), and 4) fracture-filling anhedral dolomite (Dol-4). Dol-1 has nonplanar mosaic micritic crystals with irregular intercrystalline boundaries and dull cathodoluminescence (CL), suggesting dolomitization during the early burial stage. Dol-1 tends to occur under high paleosalinity and warm conditions. Furthermore, the syngenetic relationship, with abundant framboidal pyrite and gypsum, suggests that bacterial sulfate reduction (BSR) may influence the formation of Dol-1. The high content of Sr and low content of Mn/Sr also indicate less influence on burial. The Dol-2 crystals show cloudy cores with clear rims attributed to progressive dolomitization during burial. Dol-2 is always associated with the organic matter within the organic matter-rich lamina. The anhedral crystals and undulate (sweeping) extinction of Dol-3, which is usually encased by phosphatic particles in the organic-rich lamina, reflect the recrystallization affected by bacteria and the subsequent thermal evolution of organic matter. Dol-4 fulfills the abnormal pressure fractures crosscutting the earlier phases (Dol-1 and Dol-2) with undulate (sweeping) extinction and different rare earth element (REE) patterns. Dol-4 may be affected by hydrothermal fluids, which are influenced by the thermal evolution of organic matter. The 87Sr/86Sr values of the four types of dolomites similarly demonstrate the same dolomitizing fluids. Dol-1 to Dol-3 have similar REE patterns but are different from Dol-4, suggesting that Dol-4 likely resulted from circulation through basinal sediments instead of different fluids. Focusing on the origin of dolomite has been instrumental in understanding the diagenetic evolution, fluid flow, and organic-inorganic interactions in organic-rich shale and, hence, the reservoir formation of shale oil.

Characteristics and Main Controlling Factors of Fractures within Highly-Evolved Marine Shale Reservoir in Strong Deformation Zone

Based on the systematical observations of cores, thin sections, and scanning electron microscope (SEM) sections, together with the testing data and characteristic parameters, this paper discussed the characteristics and controlling factors of fractures, and their control on shale gas accumulation in the Lower Cambrian Niutitang Formation black shale reservoir of Well YX1 in the northern Guizhou Province. The results show that macro structural fractures are common in the Niutitang Formation, which can be divided into shear fractures (e.g., high dip-angle shear fractures and low dip-angle slip fractures), tensional fractures, and tension-shear fractures. Non-structural fractures in microfractures can be divided into organic-related fractures and inorganic mineral-related fractures. Most of the structural fractures were filled and the types of fillings are diverse. The staggered relationships of fractures confirm the complexity of tectonic movement in the study area. The formation of structural fractures in Well YX1 is mainly controlled by the major fault. The influence of mineral composition and content, mechanical properties, brittleness, and organic matter content of rocks on the characteristics of the fractures are from the external manifestation of sedimentary environment. Affected by diagenetic evolution, organic matter-related fractures are not common. Compared with other shale gas reservoirs in China and abroad, the organic-rich shale reservoir of Well YX1 is characterized by both “geological sweet spots” and “engineering sweet spots”; however, strong deformation and faulting have led to the loss of shale gas and damage of the overpressure environment. Therefore, it is suggested that small-scale fractures, caused by tectonic movements but without large penetrating faults, are the most favorable for shale gas reservoirs. Based on the complicated tectonic setting in northern Guizhou, the formation pressure should be taken into account.

Nanopore Size Distribution Heterogeneity of Organic-Rich Shale Reservoirs Using Multifractal Analysis and Its Influence on Porosity–Permeability Variation

The shale nanopore size (diameter [less than] 100 nm) distribution heterogeneity (SNDH) is one of the important factors affecting gas production. However, quantitative analysis of the SNDH and the applicability of single and multifractal models need to be further studied. Here, based on low-temperature liquid nitrogen and carbon dioxide tests of organic-rich shale in Qinshui Basin, multifractal dimension variation of micropores ([less than] 2 nm) and mesopores (2–100 nm) are studied, and the multifractal factors that affect the distribution of nanopores are determined. Additionally, the differences between single fractal and multifractal results are compared. Based on this, dynamic variation of porosity and permeability under the constraints of the nanopore structure is discussed from the perspective of multifractal variation. The results of this study are as follows: (1) The pore size distribution of micropores and meso–macropores in shale samples exhibit typical multifractal behavior. The overall distribution heterogeneity of meso–macropores is mainly affected by the distribution of pores in the low-value area of pore volume (LAPV), while the overall distribution heterogeneity of micropores is affected by the distribution of the high-value area of the pore volume. The multifractal parameters and influencing factors of micropores and meso–macropores are clearly different. (2) The single fractal dimension D2 calculated using the Frenkel–Halsey–Hill model has a negative correlation with the multifractal parameters, implying that the distribution heterogeneity of the LAPV gradually decreases with the increase of the D2 value, indicating that the physical meaning of the two models is obviously different. (3) The pore distribution heterogeneity affects permeability variation and diffusion process of shale reservoir. With the increase of the multifractal dimension of meso–macropores, the damaging effect of stress on permeability is stronger. The more heterogeneous the micropore size distribution, the smaller is the ″modification effect″ of stress on the diffusion coefficient.

Investigating the effects of stress creep and effective stress coefficient on stress-dependent permeability measurements of shale rock

Rock permeability is an essential factor for production prediction and economic evaluation, which is often measured based on core samples in laboratory. However, several phenomena such as stress creep and path-dependent stress still present difficulties in correctly measuring and interpreting permeability under varying compaction stresses for core measurements. In this study, an improved stress-dependent permeability model is proposed to consider the effect of time-dependent compaction behavior on permeability measurements by incorporating the stress creep mechanism. Besides, how to correctly interpret stress-dependent permeability results with effective stress coefficient is introduced in detail. A coupled flow-geomechanics model is also developed to investigate the impact of effective stress coefficient on permeability change and cumulative production. Due to the stress creep phenomenon, rock permeability could be significantly overestimated if not enough measurement time is provided. The creep strain is highly related to the content of clay and kerogen. This is because the increasing creep strain over time is mainly from the closure of pre-existed micro-fractures and the compression of Nano-pores inside the soft materials, such as clay and kerogen. The creep strain model and improved stress-dependent permeability model were validated by comparing with multiple experimental data. Effective stress coefficient cannot be simply assumed one for organic-rich or clay-rich shale reservoirs, especially when pore pressure is changed to alter net effective stress in permeability measurements. A large effective stress coefficient amplifies the sensitivity of pore pressure change on the variation of both effective stress and permeability. The simulation results show a larger effective stress coefficient could provide higher cumulative production because of stronger compression from effective stress. The improved knowledge of stress creep and effective stress coefficient enables the development of best practices for permeability measurement of tight rock and provides more accurate permeability results for reservoir management and field development.

Comparison of Chemical-Induced Fracturing by Na2S2O8, NaClO, and H2O2 in Marcellus Shale

Shale–oxidant reactions can enhance the permeability of organic-rich shale reservoirs through chemical-induced fracturing. Choosing the best oxidant for this purpose is explored in this study. To c...

Application of horizontal wells in three-dimensional shale reservoir modeling: A case study of Longmaxi–Wufeng shale in Fuling gas field, Sichuan Basin: Reply

Three-dimensional reservoir modeling is an important aspect to determine the heterogeneity of organic-rich shale reservoirs, an area of study that continues to be explored and refined. A large proportion of data acquired from horizontal wells causes issues in the structural and property modeling for shale reservoirs. Since horizontal wells are designed to drill into a specific, narrow zone, their horizontal section tends to parallel or nearly parallel formation surfaces. As a result, formation surfaces have a much more complex spatial location relationship with horizontal wellbores than with vertical wellbores. The existing algorithms are not good at addressing this issue during structural modeling. The major problem of using horizontal well data in property modeling is the biased data set because their horizontal section tends to stay within a narrow zone. The property distribution feature estimated from this biased data set, as a significant, default input of geostatistical simulation algorithms, causes the constructed property models to deviate away from the real case in the subsurface. A method to infer more formation tops in pseudovertical wells according to a series of assumptions was developed to provide more constraint points for structural modeling within the areas of the horizontal well section. To use the biased database from horizontal wells, distribution function and trend model methods were developed for continuous property modeling, and percentage and probability trend models were developed for discrete property modeling. The Longmaxi–Wufeng shale in the Fuling gas field of Sichuan Basin was used as an example to express and verify these methods.

An Advanced Well Log and an Effective Methodology to Evaluate Water Saturation of the Organic-Rich Cambay Shale

Water saturation (Sw) is a vital parameter in the evaluation of hydrocarbon reservoir. Realistic estimation of Sw in shale reservoir is a challenging problem because of the presence of significant clay minerals and organic matter. The present study aims to estimate Sw of organic-rich Cambay Shale, Jambusar–Broach block, Cambay Basin, India, using an effective methodology and improved equation (TOC–clay equation), considering the appropriate corrections to counter the effect of clay minerals and organic matter in modifying resistivity. Advanced log like Litho-scanner has been utilized for the continuous estimation of clay content and total organic carbon (TOC), required for the estimation of Sw. Elemental capture spectroscopy and support vector regression were also applied for evaluation of clay content and TOC in one well where Litho-scanner log is not available. To investigate the effectiveness and applicability of the TOC–clay equation, results of Sw estimated from this equation and various other models have been compared with core Sw for a well. The analysis indicates that Sw derived from TOC–clay equation is having the closest agreement to core Sw data with an average absolute percentage error of 7.9% and coefficient of correlation 0.95. For other models, average absolute errors are significantly higher (16.8–32.7%). The application of TOC–clay equation will be useful for evaluation of the Cambay Shale reservoir. In addition, the resistivity-based TOC–clay equation used in this study is simple with a practical approach; it can be applied easily and efficiently for any organic-rich shale reservoir elsewhere.

Petrophysical properties difference of organic-rich and organic-poor shale reservoir using low-field nuclear magnetic resonance experiment in the Sangzhi block, South China

The petrophysical properties of rocks have an important influence on shale quality. To characterize the difference of petrophysical properties between organic-rich and organic-poor shale reservoirs, we used the low-field nuclear magnetic resonance (NMR) technique and field emission scanning electron microscopy analysis after argon-ion polishing or natural section to measure porosity and permeability from six core samples from well SY6 in the Sangzhi block, Northwest Hunan province. Some information about pore types, pore structure, residual porosity, movable porosity, and permeability based on the T2 spectrums’ difference of organic-rich and organic-poor shale samples were discussed. The shale sample test results show that the main pores size is mesopore, which provide most of shale gas reservoir space. The continuous peaks demonstrated the pores’ connectivity better than the isolated peaks, and shale gas can migrate freely between these connected pores and fractures. The permeability of all samples calculated by the classic Coates model is extremely low, which is not conducive to the migration of shale gas. We evaluated the dominating factors of NMR porosity and permeability and found that the relationships between NMR porosity and permeability and total organic carbon content, quartz minerals, and clay minerals are not clear, which may be a comprehensive influence. The research results have important guiding significance for shale reservoir quality evaluation in this area.

Microstructure Characterization of a Biogenic Shale Gas Formation—Insights from the Antrim Shale, Michigan Basin

Biogenic gas shales, predominantly microbial in origin, form an important class of organic-rich shale reservoirs with a significant economic potential. Yet large gaps remain in the understanding of their gas generation, storage, and transport mechanisms, as previous studies have been largely focused on mature thermogenic shale reservoirs. In this study, the pore structure of 18 Antrim Shale samples was characterized using gas adsorption (CO2 and N2). The results show that most of the Antrim Shale samples are rich in organic matter content (0.58 wt.% to 14.15 wt.%), with highest values found in the Lachine and Norwood members. Samples from the Paxton Member, characterized by lower organic content, have smaller micropore surface area and micropore volume but larger meso-macro pore surface area and volume. The deconvolution results of the pore size distribution from the N2 adsorption indicate that all of the tested Antrim Shale samples have similar pore groups. Organic matter in the Antrim Shale hosts micro pores instead of meso-macro pores, while clay minerals host both micro and meso-macro pores. Mineral-related pores play a primary role in the total porosity. The biogenic Antrim Shale, therefore, has different pore structures from other well-studied thermogenic gas shales worldwide.

“Exploring petroleum inside source kitchen”: Shale oil and gas in Sichuan Basin

The Sichuan Basin is rich in shale oil and gas resources, with favorable geological conditions that the other shale reservoirs in China cannot match. Thus, the basin is an ideal option for fully “exploring petroleum inside source kitchen” with respect to onshore shale oil and gas in China. This paper analyzes the characteristics of shale oil and gas resources in the United States and China, and points out that maturity plays an important role in controlling shale oil and gas composition. US shale oil and gas exhibit high proportions of light hydrocarbon and wet gas, whereas Chinese marine and transitional shale gas is mainly dry gas and continental shale oil is generally heavy. A comprehensive geological study of shale oil and gas in the Sichuan Basin reveals findings with respect to the following three aspects. First, there are multiple sets of organic-rich shale reservoirs of three types in the basin, such as the Cambrian Qiongzhusi Formation and Ordovician Wufeng Formation-Silurian Longmaxi Formation marine shale, Permian Longtan Formation transitional shale, Triassic Xujiahe Formation lake-swamp shale, and Jurassic lacustrine shale. Marine shale gas enrichment is mainly controlled by four elements: Deep-water shelf facies, moderate thermal evolution, calcium-rich and silicon-rich rock association, and closed roof/floor. Second, the “sweet section” is generally characterized by high total organic carbon, high gas content, large porosity, high brittle minerals content, high formation pressure, and the presence of lamellation/bedding and natural microfractures. Moreover, the “sweet area” is generally characterized by very thick organic-rich shale, moderate thermal evolution, good preservation conditions, and shallow burial depth, which are exemplified by the shale oil and gas in the Wufeng-Longmaxi Formation, Longtan Formation, and Daanzhai Member of the Ziliujing Formation. Third, the marine, transitional, and continental shale oil and gas resources in the Sichuan Basin account for 50%, 25%, and 30% of the respective types of shale oil and gas geological resources in China, with great potential to become the cradle of the shale oil and gas industrial revolution in China. Following the “Conventional Daqing-Oil” (i.e., the Daqing oilfield in the Songliao Basin) and the “Western Daqing-Oil & Gas” (i.e., the Changqing oilfield in the Ordos Basin), the Southwest oil and gas field in the Sichuan Basin is expected to be built into a “Sichuan-Chongqing Daqing-Gas” in China.

Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China

Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01–2 μm. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micro-pores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.

Experimental evaluation of oxidation sensitivity in organic-rich shale reservoir

Organic-rich shale reservoirs are rich in reductive minerals, such as pyrite and other organic matters. The working fluid for the development of shale gas reservoirs contains large amount of dissolved oxygen. Once the working fluid enters the organic shale reservoir, it will oxidize the reducing components, cause mineral transformation, release solid phase particles, change the pore structures, and damage the seepage capacity of organic-rich shale reservoirs. The understanding and evaluation of the oxidation sensitivity is of great significance for improving the productivity of shale reservoirs. Therefore, organic shale of the Longmaxi Formation in the Pengshui area of the southeastern Sichuan Basin (China) was taken as the research object in the current work. In order to evaluate the reservoir fluid sensitivity, experiments were conducted to evaluate the oxidation sensitivity of the organic-rich shale reservoir. The experimental results showed that oxic fluids had the highest degree of damage on the permeability of shale than the reductive and degassed fluids. The oxidation sensitivity indices, Sox, of the shale samples were found to be 65.62% and 54.88%, respectively, which are moderately strong. The mechanism for the damage of the oxidation sensitivity of shale involves the production of Fe2O3, Fe(OH)3, FeCO3 (siderite), CaSO4·2H2O (dihydrate gypsum), MgSO4, other precipitated solid particles (chemicals), and the shale debris. Therefore, the pores and fractures were blocked by solid particles, resulting in the decrease in fracture width as well as the number of solid particles, which could be expelled. An appropriate concentration of oxidants has a positive effect on the permeability of organic-rich shale. The oxidation will produce macroscopic cracks and a large number of dissolution pores that significantly improved the transport capacity of the pore fracture system, and increased the permeability of the organic-rich shale.

Interval inversion as innovative well log interpretation tool for evaluating organic-rich shale formations

The identification and detailed evaluation of unconventional hydrocarbon reservoirs require the application of advanced well logging data processing techniques. Since the number of the petrophysical properties such as porosity, water and hydrocarbon saturation, kerogen content, and fractional volumes of matrix components may exceed that of the observed wireline log types, currently used quick-look methods based on few well logs provide approximate solution to a part of the above petrophysical quantities. For instance, Passey's method basically utilizes two well logs for identifying the sweet spots and estimating the total organic content (TOC). Local inversion techniques estimating the petrophysical parameters in a given depth are also limited because of low overdetermination (data-to-unknowns) ratio and hence are very sensitive to data noises. Instead of using traditional empirical methods and to avoid ambiguous solutions by local inversion evaluations, data of all wireline logs measured in a longer depth interval are simultaneously inverted to give more accurate estimate to the petrophysical parameters in a highly overdetermined inverse problem. The suggested interval inversion approach allows the determination of the fractional volumes of rock constituents with their estimation errors in a joint inversion procedure. As part of the inversion process, the forward problem is improved by using kerogen and pyrite effects corrected probe response functions. Synthetic modeling tests are made to detect the noise sensitivity and outlier resistance of the proposed inversion algorithm, while a float-encoded genetic algorithm variant of the interval inversion method is applied to invert real data measured in an organic-rich shale reservoir in Alaska, USA. The feasibility is demonstrated by a well agreement between the inversion derived TOC values and those of measured on core samples. The interval inversion method not only works reliably in the presented shale gas formations, but it can be extended to evaluating other types of unconventional reservoirs.