Gas-bearing Shale Research Articles

Giant Effect of CO2 Injection on Multiphase Fluid Adsorption and Shale Gas Production: Evidence from Molecular Dynamics.

Carbon dioxide (CO2) injection in unconventional gas-bearing shale reservoirs is a promising method for enhancing methane recovery efficiency and mitigating greenhouse gas emissions. The majority of methane is adsorbed within the micropores and nanopores (≤50 nm) of shale, which possess extensive surface areas and abundant adsorption sites for the sequestration system. To comprehensively discover the underlying mechanism of enhanced gas recovery (EGR) through CO2 injection, molecular dynamics (MD) provides a promising way for establishing the shale models to address the multiphase, multicomponent fluid flow behaviors in shale nanopores. This study proposes an innovative method for building a more practical shale matrix model that approaches natural underground environments. The grand canonical Monte Carlo (GCMC) method elucidates gas adsorption and sequestration processes in shale gas reservoirs under various subsurface conditions. The findings reveal that previously overlooked pore slits have a significant impact on both gas adsorption and recovery efficiency. Based on the simulation comparisons of absolute and excess uptakes inside the kerogen matrix and the shale slits, it demonstrates that nanopores within the kerogen matrix dominate the gas adsorption while slits dominate the gas storage. Regarding multiphase, multicomponent fluid flow in shale nanopores, moisture negatively influences gas adsorption and carbon storage while promoting methane recovery efficiency by CO2 injection. Additionally, saline solution and ethane further impede gas adsorption while facilitating displacement. Overall, this work elucidates the substantial effect of CO2 injection on fluid transport in shale formations and advances the comprehensive understanding of microscopic gas flow and recovery mechanisms with atomic precision for low-carbon energy development.

Seismic attributes and instantaneous spectral analysis-based temperature-porosity simulations: An example of imaging shale gas-bearing basin floor fans of early-cCretaceous delta sequences, Southeast Asian Basin

Basin floor fans (BFF) of deltaic depositional systems are important stratigraphic traps, which are sourced by the regionally developed meandering channel belts and associated deposits of point bar facies. The vertical and lateral changes in the tectonics and sea level adversely affect the temperature (θ) and porosity constraints of petroleum plays within BFF of the lowstand system tracts. These fluctuations impact the sedimentary controls on thickness, lithology-impedance contrast, phase, and frequency of BFF. As a result of the reliance on full-spectrum seismics, quantifying thin-bedded stratigraphic wet gas-bearing intervals (WGI) and light oil-bearing intervals of petroleum systems becomes extremely difficult. This study utilizes seismic attributes and instantaneous spectral analysis-based temperature-porosity reservoir simulations (TPRS) to quantify the BFF of the Early-Cretaceous delta of the Miano gas field, Central Pakistan. The 47-Hz peak-tuned frequency component of spectral decomposition [SpecDecomp] images a 154 km2 NEE-SWW traversed and regionally developed stratigraphic prospect. Linear regression of R2 > 0.80 between spectral decomposition-based tuning frequency of 47-Hz and gross reservoir thickness of BFF validates the presence of gas-bearing shales. The 47-Hz wavelet-based TPRS has resolved the phase reversals and seismic-doublet signatures for thin-bedded shale PETROS at θ of 170°F to 200°F and porosities of 22 % to 32 % of WGI within BFF. TPRS at 47-Hz SpecDecomp profile between the frequency bandwidth spectrums of 12–62-Hz has reappraised the exact morphology of the continental shelf, shelf-slope, and BFF. A 21 m thick aggradational parasequence of BFF was deposited at an angle of 2° during the onset of subsidence and rapid fall, followed by a subsequent standstill of sea-level at θ of 170 to 200°F, ∼26 to 35 % porosities, and laterally fractured subsidized regimes of WGI.. A 20 m thick retrogradational fluvial-dominated facies was deposited at an angle of 35° during a rising followed by a standstill of sea level at a θ of 140 to 165°F, ∼08 % to 18 % porosity, and poorly fractured uplifted compressional regimes of light oil-bearing intervals. The aggradational WGI of Lowstand System Tracts was completely embedded by retrogradational shales of transgressed system tracts from the top of the aggradational and laterally. The uncertainty analysis has prevailed with a moderate-to-good R2 > 0.75 for BFF and a very poor R2 < 0.1 for fluvial-dominated point bar traps. Our workflow has implications in terms of exploring the tectonics and stratigraphic frameworks within the petroleum systems for imaging the most productive zones in a single snapshot of 47-Hz tuning frequency.

Understanding roles of moisture in CO2 adsorption and desorption hysteresis on deep gas-bearing shales under high temperature and pressure

To understand injectivity and storage stability of CO2 into gas-bearing shale reservoirs, CO2 adsorption and desorption on the dry and moist shales with diverse properties were conducted at 353.15 K and pressures up to 14 MPa. Multiple characterizations were combined to examine pore characteristics of the shales before and after CO2 adsorption/desorption. The resultant CO2 adsorption and desorption hysteresis on the shales was revealed ultimately. Results indicated that both the excess and absolute adsorption isotherms of CO2 witness slow increase stage, rapid increase stage, and decrease stage. The adsorption capability of the shales positively depends on the TOC content and pore abundance. Moreover, the clay minerals and oxygenic functional groups also benefit CO2 adsorption. The moisture significantly reduces the experimentally-determined maximum absolute adsorption capacity of the shales by 5.78–46.39 % due to pore space occupation. During the adsorption/desorption, the CO2 molecules could interact with the shales, thereby initiating extraction of partial organic matter, transformation of CO2 from supercritical state to gas state, and dissolution of inorganic minerals. Those effects consume CO2 and dominantly change the micropore structure of the dry shales and the mesopore structure of the moist shales, thus leading to CO2 adsorption and desorption hysteresis. Notably, the moisture dramatically raises the hysteresis degree on the shales by 8.42–59.45 % because of its solubility to CO2 and promotion to mineral dissolution. Overall, shale reservoir moisture could weaken injectivity but strengthen storage stability of CO2. Hence, the critical moisture content and occurrence pattern of organic matter and clay minerals are required for target shale reservoir selection.

Fluid evolution and gas enrichment in the Wufeng-Longmaxi shale reservoirs of the eastern Sichuan Basin, SW China

Abundant calcite and quartz veins have been developed in the Wufeng-Longmaxi (O3w-S1l) shale reservoirs, which are direct records of fluid flow events in the southern Jiaoshiba area, Sichuan Basin. To investigate their origin and timing, multiple in-situ analytical approaches were conducted on selected calcite and quartz veins. Three stages of calcite veins and two stages of quartz veins are identified in the studied region as: stage 1 calcite veins (Cal-1 veins), stage 2 quartz veins (Qtz-1 veins), stage 3 calcite veins (Cal-2 veins), stage 4 quartz veins (Qtz-2 veins), and stage 5 calcite veins (Cal-3). The Cal-1, Qtz-1, Cal-2, Qtz-2, and Cal-3 veins were formed at 177–166 Ma, 167–145 Ma, 156–145 Ma, 84–83 Ma, and 65 Ma, respectively, as indicated by combining with fluid inclusions data in both the calcite and quartz veins and burial-thermal history reconstruction. Intra-layer diagenetic fluid in the O3w-S1l shale was responsible for the formation of Cal-1, Qtz-1, Cal-2, and Qtz-2 veins. The Cal-3 veins were only identified in the O3w-S1l shale reservoirs of the Zilichang zone, and the vein-forming fluid was derived from extraneous fluids under an oxidative environment. In addition, methane inclusions in the calcite and quartz veins show three episodes of natural gas expulsion in the southern Jiaoshiba area. Due to the effective sealing capabilities of shale, the three episodes of gas expulsion were transported for a short distance within the O3w-S1l shale reservoirs in the Piangqiao zone. The last episode of gas expulsion occurred in the Zilichang zone during the Late Yanshanian uplift was corresponded to the formation of Cal-3 veins. Extraneous fluid can infiltrate the reservoir through the local fault-fracture systems in the Zilichang zone, indicating the destruction of sealing capability. Our methane inclusion data analysis indicates the loss of shale gas in the Zilichang zone, which was potentially associated with the fluid flow responsible for the formation of Cal-3 vein in the O3w-S1l shale reservoirs. Fluid evolution in different gas-bearing shale reservoirs reveals preservation conditions during the process and has an implication for the differential enrichment of shale gas.

Geochemical Characteristics of Elements and Main Controlling Factors of Organic Matter Enrichment in Shale from Wufeng Formation to Submember Long-11 in Southern Sichuan

A total of 70 shale samples from seven core holes, namely, N203, N208, N209, N210, N211, N215 and N217, in Changning area, south Sichuan, were analyzed for major and trace elements. Based on an analysis of longitudinal variation characteristics of major and trace elements, the REDOX conditions, paleoproductivity, relative sea level height and terrigenous detrital injection amount of gas-bearing shale in Wufeng Formation–Submember Long-11 in the Changning area were studied. And, the main controlling factors of organic matter enrichment in Wufeng Formation–Submember Long-11 were discussed. The results show the following: (1) Trace elements Mo, U, Ba and Ni are relatively enriched in the shale of Wufeng Formation–Submember Long-11 in the Changning area, while the Co element is deficient. The flat distribution pattern of rare earth in Wufeng Formation–Submember Long-11 shows that the shale deposits are weakly influenced by terrigenous materials. The amount of terrigenous injection in Wufeng Formation is higher than that in Submember Long-11, and the amount of terrigenous injection increased gradually from the lower part of Bed Long-111 to the lower part of Bed Long-114. (2) The REDOX environment discrimination indexes such as U/Th, Ni/Co, V/Sc and δU show that the water REDOX conditions of Wufeng Formation–Submember Long-11 in the Changning area have changed many times during the shale sedimentary period, and the overall REDOX conditions are dominated by an anaerobic environment. The REDOX indexes at the boundary between Long-111 and Wufeng Formation are relatively small and in the oxidizing environment range. The REDOX index from Bed Long-111 to Bed Long-114 decreases gradually, and the anaerobic environment of Bed Long-111 and Bed Long-112 gradually changes to the oxygen-poor environment of Bed Long-113; and, the REDOX index of Bed Long-114 is the lowest, which is generally oxygen rich. (3) Organic matter enrichment in Wufeng Formation Submember Long11 in the Changning area is mainly controlled by REDOX conditions. Low terrigenous injection and a relatively high sea level have positive effects on organic matter enrichment, but there is no obvious relationship between the paleoproductivity and organic matter enrichment.

Rock physics model for velocity—pressure relations and its application to shale pore pressure estimation

Acoustic wave velocity has been commonly utilized to predict subsurface geopressure using empirical relations. Acoustic wave velocity is, however, affected by many factors. To estimate pore pressure accurately, we here propose to use elastic rock physics models to understand and analyze quantitatively the various contributions from these different factors affecting wave velocity. We report a closed-form relationship between the frame flexibility factor (γ) in a rock physics model and differential pressure, which presents the major control of pressure on elastic properties such as bulk modulus and compressional wave velocity. For a gas-bearing shale with abundant micro-cracks and fractures, its bulk modulus is much lower at abnormally high pore pressure (high γ values) where thin cracks and flat pores are open than that at normal hydrostatic pressure (low γ values) where pores are more rounded on average. The developed relations between bulk modulus and differential pressure have been successfully applied to the Upper Ordovician Wufeng and Lower Silurian Longmaxi formations in the Dingshan area of the Sichuan Basin to map the three-dimensional spatial distribution of pore pressure in the shale, integrating core, log and seismic data. The estimated results agree well with field measurements. Pressure coefficient is positively correlated to gas content. The relations and methods reported here could be useful for hydrocarbon exploration, production, and drilling safety in both unconventional and conventional fields.

Physical property differences of source rocks in the Lucaogou Formation and adsorption ability variation under their influence

Shale gas exploration is very important for the China in the further. There are many findings of shale gas in Northwest China, especially in Junggar Basin Permian Lucaogou Formation of the Xinjiang Uygur Autonomous Region. However the basic geological characteristics of Lucaogou Formation is not still clear. In order to solve this problems, Quanzijie shale gas collected from the southern margin of the Junggar Basin is taken as the study area, and shale gas resources are investigated and evaluated using the organic-rich shale section. On this basis, the investigation and evaluation of shale gas resources in the Lucaogou Formation is performed. The reservoir performance, preservation conditions, compressibility, and gas-bearing properties of gas-bearing shale intervals are identified. The results are as follows: The vertical and horizontal lithological and lithofacies variations of the source rocks of the Lucaogou Formation are clarified. This layer is characterized by the upward thinning of grain size and the upward darkening of color in the vertical direction. The layer can be divided into upper and middle-lower sections, with organic shale being most developed in the upper section, and sandstone and dolomite being more developed in the middle and lower area. The main hydrocarbon source rocks are developed in the upper area of the Lucaogou Formation. The total thickness of the hydrocarbon source rocks is 78.12–513.73 m. The lithology is mainly gray-black shale, silty mudstone, and oil shale. The average organic carbon content is 4.86%. The maturity of the organic matter is mainly 0.7–0.8%. The shale reservoirs have a high content of brittle minerals, but the physical properties both of the shale and sandstone reservoirs are poor. These are generally ultra-low porosity and ultra-low permeability reservoirs, in which the oil and gas reservoir space is mainly fractures.

Occurrence of moisture in deep gas-bearing shale matrix and its impacts on methane adsorption/desorption capability under favorable reservoir conditions.

To comprehend impacts of moisture on exploring and producing shale gas, the rules of pseudo-in situ moisture occurrence in deep shales were revealed through low-pressure N2 adsorption and desorption, and CO2 adsorption measurements. The influences of pseudo-in situ moisture on CH4 adsorption/desorption in the shales were explored at 353.15 K and pressures up to 30 MPa by using the volumetric method. Results showed that the pseudo-in situ moisture content of the shales ranges between 0.57% and 0.94%, which positively correlates with clay mineral content but negatively correlates with organic matter and quartz. The clay minerals contribute more to moisture occurrence mainly via adsorption effect. The pores with the diameters of 1.10-4.10 nm of the shales serve as dominant space for accommodating moisture. Moreover, the pseudo-in situ moisture reduces saturated adsorption capacity and isosteric adsorption heat of CH4 on the shales, suggesting the weakened adsorption affinity toward CH4-shale system. Typically, the minor pseudo-in situ moisture could significantly weaken CH4 adsorption capability of the shales with low clay mineral content through blocking pore throats of organic matter-hosted pores. However, the abundant pseudo-in situ moisture only slightly reduces CH4 adsorption capability of the shales with high clay mineral content due to continuous distribution of organic matter-hosted pores. The aforementioned different roles are dominated by the difference in occurrence characteristics of organic matter-hosted pores and clay mineral-hosted pores between the shales with low clay mineral content and the shales with high clay mineral content. Furthermore, the pseudo-in situ moisture strengthens CH4 adsorption/desorption hysteresis on the shales associated with moisture uptake-induced clay mineral swelling, thereby raising difficulty for CH4 desorption from the shales.

Macro- and micro-fractures and their controls of the Ordovician–Silurian Wufeng–Longmaxi gas-bearing shale in Sichuan Basin and its periphery, south China

Macro- and micro-fractures and their controls of the Ordovician–Silurian Wufeng–Longmaxi gas-bearing shale in Sichuan Basin and its periphery, south China

Mitigating water blockage in shale matrix by acidizing or oxidizing treatment: Evidence from transport pathway change and diffusivity enhancement

A relatively large number of pH-sensitive minerals (e.g., calcite, dolomite, siderite) and redox-sensitive compositions (e.g., organic matter, siderite, pyrite, and chlorite) are present in gas-bearing shale formations. During hydraulic fracturing, some of these compositions can be dissolved under acidic or oxic condition and may generate critical transport pathways to bypass water blockage within the fracture-matrix interface. This paper reports the effects of 5% HCl or 15% H2O2 reactive fluids on transport pathway and methane diffusion capacity of Longmaxi shale samples. Experiments show that these sensitive minerals are distributed evenly throughout the shale matrix as dispersed or isolated grains. Reactivity differences between sensitive compositions and non-sensitive minerals cause heterogeneous dissolution at micrometer scale and generate substantial new pore space in the reaction zones, giving an overall pore volume increase by 4.6–6.6 vol % calculated using μCT data. Apart from dissolution pores, many oxidation-related microfractures with a spacing less than 10 μm are also observed in H2O2-treated shale. Due to resolution limitations of SEM and μCT imaging, these new transport pathways appearing as separated void spaces are actually connected by much smaller pores at nanoscale, leading to a greater than 3.7-fold increase in macropore diffusivity. Despite more water imbibition into the H2O2-treated shales, the largest increase in diffusivity is also observed post oxidizing treatment. Our study clearly demonstrates that the newly formed transport pathways can reduce the diffusion pathway length and tortuosity of nanopore systems, thereby significantly improving wet shales’ diffusivity. These observed changes in transport pathway and diffusivity indicate that acidizing or oxidizing treatment may be a possible method for mitigating water blockage within fracture-matrix interface of hydraulically fractured Longmaxi shale gas formation.

From Seismic Pre-Stack Elastic Attributes to Rock Properties. A Case Study in the Permian Basin, Onshore USA

The Permian Basin contains significant oil and gas-bearing shale deposits. Extending over 55 counties in West Texas and southeast New Mexico, it covers a vast region. It is the largest contributor to the oil shale boom in the US and in February 2022 accounted for more than 40% of US oil, Figure 1 (Federal Reserve Bank of Dallas 2022). Figure 2 displays the increase in produced oil from this basin from 2018 to 2022, Chevron News Room 2022. During the first years of production from these tight shales, seismic data weren’t considered to be essential for locating and drilling high-producing wells. However, the value of seismic data are now recognized and extensively used to design and execute lateral drilling programmes into the most prolific shale units. The shale deposits are widespread but highly heterogeneous in composition. Specifically notable is the lateral variability of Total Organic Content (TOC) and rock properties, such as porosity within the formations. In addition to varying shale properties, carbonate units were deposited simultaneously and are difficult to distinguish when only using reflectivity. Traditionally, the sonic and density values were inputted into supervised and non-supervised neural network applications to estimate rock properties. However, it is difficult to calculate density from conventional seismic data, and the results are typically questionable and have a high uncertainty element. To calculate density from seismic data, we need long offsets that are usable; most of the time, these data are not available (Aki, K., 1980). This study showcases a unique approach and its application using the LambdaRho-MuRho cross plot to estimate rock properties. The LambdaRho and MuRho values are derived from pre-stack inversions and are correlated to existing well data over the zone of interest. The results indicate that this is a more elegant and valid methodology, especially since it seems to produce a better, more accurate distinction between shale and carbonate domains.

Effect of different lithological assemblages on shale reservoir properties in the Permian Longtan Formation, southeastern Sichuan Basin: Case study of Well X1.

Various types of marine-continental transitional facies are present in the gas-bearing shales of the southeastern Sichuan Basin. A review of the different lithological assemblages in these rocks is important for assessing the likely shale gas content and the development of the storage space. This study of the lithological assemblages of the Permian Longtan Formation in the southeastern Sichuan Basin at Well X1 used core observations, optical thin-section observations, Ar-ion polishing, scanning electron microscopy, and nitrogen adsorption tests to compare and analyze storage space types and pore structures in the shale to determine the sedimentary paleoenvironment, petromineralogy, and organic content. The marine-continental transitional facies in the study area were deposited in a warm climate that favored enrichment by organic matter. The kerogen is type II2-III (average vitrinite reflectance 2.66%), which is within the favorable thermal maturity range for the presence of shale gas. The lithology mainly consists of shale, siltstone, and limestone (with bioclasts), as well as a coal seam. The lithological development divides the Longtan Formation into lower (swamp), middle (tidal flat/lagoon), and upper (delta) sub-members. From lower to upper divisions, the lithofacies evolved from silty shale to clay shale and then to shale intercalated with siltstone or calcareous layers. The proportions of intergranular and dissolution pores in the clay minerals decrease gradually from lower to upper sub-members, and pore size sizes also tend to decrease. Relatively large-diameter pores and microfractures occur in the inorganic matter in the lowest sub-member. Quartz and clay are the main constituents of the shale, respectively contributing to the specific surface area and specific pore volume of the reservoir space.

Accumulation and exploration of continental shale gas resources of Cretaceous Shahezi Formation in Lishu fault depression, Songliao Basin, NE China

Distribution characteristics, organic matter development characteristics, gas-bearing characteristics, reservoir characteristics, and preservation conditions of the Shahezi Formation shale of Lower Cretaceous in the Lishu fault depression, Songliao Basin, NE China, are analyzed using organic geochemical, whole rock, and SEM analysis data, and CO2 and N2 adsorption and high-pressure mercury injection experiment data in combination with the tectonic and sedimentation evolution of the region to reveal the geological conditions for enrichment and resource potential of continental shale gas. The organic-rich shale in the Lower Cretaceous of the Lishu fault depression is mainly developed in the lower submember of the second member of the Shahezi Formation (K1sh21 Fm.) and is thick and stable in distribution. The shale has high TOC, mainly types II1 and II2 organic matter, and is in the mature to the over-mature stage. The volcanic activity, salinization, and reduction of the water environment are conducive to the formation of the organic-rich shale. The shale reservoirs have mainly clay mineral intergranular pores, organic matter pores, carbonate mineral dissolution pores, and foliated microfractures as storage space. The pores are in the mesopore range of 10–50 nm, and the microfractures are mostly 5–10 μm wide. Massive argillaceous rocks of lowland and highstand domains are deposited above and below the gas-bearing shale separately in the lower submember of the K1sh21 Fm., act as the natural roof and floor in the process of shale gas accumulation and preservation, and control the shale gas enrichment. Based on the above understandings, the first shale gas exploration well in Shahezi Formation was drilled in the Lishu fault depression of Songliao Basin. After fracturing, the well tested a daily gas production of 7.6×104 m3 marking a breakthrough in continental shale gas exploration in the Shahezi Formation (K1sh Fm.) of the Lishu fault depression in Songliao Basin. The exploration practice has reference significance for the exploration of continental shale gas in the Lower Cretaceous of Songliao Basin and its periphery.

Pore Characteristics and Gas Preservation of the Lower Cambrian Shale in a Strongly Deformed Zone, Northern Chongqing, China

The Lower Paleozoic marine shale in southern China has undergone several strong tectonic transformations in an extensive region outside the Sichuan Basin. Although some shale strata underwent strong deformation, they still contain a significant amount of shale gas. The gas preservation mechanism in the strongly deformed shale has become the focus of attention. In this paper, the Lower Cambrian gas-bearing shale samples with a strong deformation taken from an exploration well in northern Chongqing, China, were investigated on their pore types and structure, with the aim to reveal the reason for the gas preservation. The pore types of the Lower Cambrian shale are dominated by microfractures and interparticle (interP) pores occurring mainly between clay minerals and between organic matter (OM) and clay minerals, while pores within OM that can be observed by FE-SEM (field emission-scanning electron microscopy) are rare. The shale has a low porosity, with an average of 1.56%, which is mainly controlled by the clay mineral content. The adsorption experiments of low pressure N2 (LPNA) and CO2 (LPCA) indicate that the shale is rich in micropores and small mesopores (&lt;2–3 nm) provided mainly by OM, but mesopores with a size range of 3–50 nm are underdeveloped. The shale, as revealed by LPNA data, has dominant slit-like or plate-like pores and an obvious low-pressure hysteresis (LPH), indicating a low gas diffusion. The deformed shale samples with a removal of OM by oxidation and their isolated kerogen further indicate that the LPH is completely related to OM, without any relationship with minerals, while an undeformed shale sample, taken from another well for a comparison, has no obvious LPH for both of its OM-removed sample and kerogen. Based on a comprehensive analysis of the relative data, it is suggested that the nanopores related to OM and clay minerals in the shale were significantly altered owing to the deformation, with a result of the pores being squeezed into the slit-like shape and converted into micropores. This extraordinary pore structure of the shale formed during the deformation process should be the main preservation mechanism of shale gas.

The Viscosity of Methane in Organic Slit Nanopore of Gas-Bearing Shale by Molecular Dynamic Simulation

Non-Darcy flow is observed in the shale gas reservoir because it is rich in organic nanopores. Generally, the permeability of shale gas reservoirs is modified because of non-Darcy flow. However, the viscosity is much less concerned. It has been verified that the viscosity of dilute gas depends on the size of the pore. In this paper, the viscosity of methane in organic slit nanopore is determined with equilibrium molecular dynamics (EMD) simulation. The result shows that the viscosity of bulk methane would decrease with dropping down pressure, while the confined effect would make the viscosity of methane in the organic slit nanopore lesser than that of the bulk phase, and it decreases severely at low pressure. The confined dense gas viscosity model is obtained by theoretical derivation. The EMD results were fitted with this model to obtain the viscosity correction method for dense methane in organic slit nanopores. The dimensionless viscosity (μeff/μb) would decrease sharply with the Knudsen number between 0.1 and 10. Unlike the confined effect on the dilute gas, the potential contribution of the dense gas and the wall also affects its viscosity. Because of the confined effect on the dense methane, the flow capacity of methane is enhanced 1.5 times at least with the pore being smaller than 10 nm and the pressure being lower than 5 MPa. It means that keeping a low reservoir pressure helps to improve the flow of shale gas. This work can improve the understanding of the importance of gas viscosity with the non-Darcy flow in shale gas reservoirs.

Variation in the brittle-ductile transition of Longmaxi shale in the Sichuan Basin, China: The significance for shale gas exploration

The Longmaxi Formation has abundant shale gas resources. High-yield wells have been obtained in medium-shallow and deep areas in the Sichuan Basin. Quantitative research on the brittle-ductile change in rocks is a basic geological component for caprock evaluation, and it can also be applied to shale gas exploration. This paper fully considers the difference between the lower shale (N1) and upper shale (N2) of the Longmaxi gas-bearing shale. Through total organic carbon (TOC), mineral components, field emission scanning electron microscopy (FE-SEM), and triaxial mechanics experiments, the two groups of shale samples, N1 and N2, were compared and analyzed, and the brittle-ductile transition was quantitatively studied. Based on previous work, a method for the fast calculation of the key over consolidation ratio (OCR) was proposed. The results show that N1 is mainly organic-rich siliceous shale, N2 is primarily organic-poor clay shale and mixed shale, and N1 is generally more brittle than N2. The key OCRs of N1 and N2 are 2.16 and 2.60, respectively. The key confining pressures at which N1 and N2 become fully ductile are 87.87 MPa and 70.28 MPa, respectively. Therefore, the key depths of the brittle zones of N1 and N2 (H b1 and H b2 ) and the key depths of the ductile zones of N1 and N2 (H d1 and H d2 ) are obtained. On this basis, a comprehensive model for the Longmaxi shale gas' brittle-ductile transition exploration zone in the Sichuan Basin and H b1 and H b2 maps of the Longmaxi gas-bearing shale have been established. Through comprehensive vertical and horizontal analysis, Longmaxi shale gas exploration risks in different blocks of the Sichuan Basin have been clarified. Therefore, this study of the variation in the brittle-ductile transition has an important guiding role in refining the exploration of Longmaxi shale gas in the Sichuan Basin. • There are obvious differences between the lower shale and the upper shale. • Difference of brittle-ductile transition makes shale gas exploration more complicated. • The new method can quickly calculate the threshold value of over consolidation ratio. • The new model provides more comprehensive guidance for shale gas exploration.

Role of H2O of Gas-Bearing Shale in Its Physicochemical Properties and CH4 Adsorption Performance Alteration Due to Microwave Irradiation

Role of H₂O of Gas-Bearing Shale in Its Physicochemical Properties and CH₄ Adsorption Performance Alteration Due to Microwave Irradiation

Impact of de-ionized water on changes in porosity and permeability of shales mineralogy due to clay-swelling

Hydraulic fracturing is widely applied for economical gas production from shale reservoirs. Still, the swelling of the clay micro/nano pores due to retained fluid from hydraulic fracturing causes a gradual reduction of gas production. Four different gas-bearing shale samples with different mineralogical characteristics were investigated to study the expected shale swelling and reduction in gas permeability due to hydraulic fracturing. To simulate shale softening, these shale samples were immersed in deionized (DI) water heated to 100 °C temperature and subjected to 8 MPa pressure in a laboratory reactor for 72 hours to simulate shale softening. The low-temperature nitrogen adsorption and density measurements were performed on the original and treated shale to determine the changes in micro and nano pore structure. The micro and nano pore structures changed, and the porosity decreased after shale treatment. The porosity decreased by 4% for clayey shale, while for well-cemented shale the porosity only decreased by 0.52%. The findings showed that the initial mineralogical composition of shale plays a significant role in the change of micro and nano pores and the pore structure alteration due to retained fluid from hydraulic fracturing. A pore network model is used to simulate the permeability of shale used in this study. To define pore structure properties, specific factors such as porosity, pore size, pore throat distribution, and coordination number were used. Furthermore, the anisotropy characteristics of shale were integrated into the model via a coordination number ratio. Finally, the change in permeability due to shale softening was determined and compared with untreated with the progress of shale softening. The simulation showed that the permeability of Longmaxi shale could decrease from 3.82E–16 m2 to 4.71E–17 m2 after treatment.

Estimation of Brittleness and Anisotropy Parameters in Transversely Isotropic Media With Vertical Axis of Symmetry

In the absence of fracture, the strata with horizontal interbedding structure can be approximately equivalent to transversely isotropic media with vertical axis of symmetry (VTI) in the sedimentary basin. Accurate estimation of Young’s modulus, Poisson’s ratio, and weak anisotropy (WA) parameters can provide basic information for further prediction of shale reservoir rock brittleness and <italic xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">in situ</i> stress. Based on the scattering theory and Born approximation, we derive the P-wave reflection coefficients involving Young’s modulus and Poisson’s ratio and WA parameters for an interface separating two elastic VTI media. Assuming in the case of shale, we modify this reflection coefficient to involve only three model parameters through a series of integration and simplification for stabler inversion. A Bayesian amplitude versus offset (AVO) inversion method is implemented to estimate the three attributes, which are then converted to calculate the brittleness-related and WA parameters. The numerical simulation results show that for AVO of III in the case of gas-bearing shale, the derived approximation has more accuracy than the Young’s modulus, Poisson’s ratio and density (YPD) equation, especially at large angle. Tests on synthetic and real seismic data verify that the established inversion strategy for VTI shale reservoirs is stable and accurate in the estimation of brittleness-related and WA parameters.

Influences of controlled microwave field radiation on pore structure, surface chemistry and adsorption capability of gas-bearing shales

Aiming to explore the feasibility of using microwave field radiation to produce shale gas via temperature swing. The heating behaviors and alterations in physicochemical properties and adsorption capability of gas-bearing shales under the controlled microwave field are preliminarily investigated. Results indicate that the shales can significantly absorb microwave energy. The bulk temperature of shales increases with the duration of microwave radiation. The heating behaviors of shales under the controlled microwave field are probably associated with pyrite and marcasite contained in shales, which greatly determine the complex permittivity and thermal conductivity of shales. Next, the microwave radiation decreases the adsorption pores with pore width below 10 nm, and fractal dimensions of pore surface and pore structure of the shales determined from the Neimark model and the FHH model, while increases the amount of meso- and macropores with pore width above 10 nm, MIP total pore volume and porosity of shales. These alterations in pore structure promote desorption and migration of shale gas within reservoirs. Furthermore, the microwave radiation changes the surface chemistry property of shales. The FTIR analysis reveals that the total content of CO and COOH of shales grows after the microwave radiation, whereas the aromaticity decreases. The alterations in both oxygenic functional groups and aromaticity are prone to promote shale gas desorption from shale matrix by weakening the intermolecular force between shale gas and shale matrix. Finally, the microwave radiation decreases the maximum CH4 adsorption capacity of the shales, the decreasing amplitude of which is 12.70–47.83%. In conclusion, the aforementioned heating behaviors and alterations in physicochemical property and adsorption capability of shales under the controlled microwave field imply that microwave radiation is an alternative option to enhance shale gas production.