Shale Core Research Articles

Effect of fluid–shale interaction on hydraulic fracture effectiveness

The effectiveness of hydraulic fractures is one of the critical factors determining the production performance of shale oil wells. To investigate the influence of fluid–shale interaction during formation stimulation on the effectiveness of hydraulic fractures and shale oil production, first, a series of conductivity tests were performed on shale cores after soaking in different fluids, revealing the evolution rules of conductivity of propped fracture under different fluid-shale interaction mechanisms. Furthermore, by considering the fluid–shale interaction in the reservoir numerical simulation model, the impact of hydraulic fracture effectiveness evolution on shale oil well productivity and its differences in reservoirs with different permeability anisotropy were analyzed. The research results indicate that the softening of fracture surfaces caused by fluid-shale interaction causes fracture conductivity damage, and the longer the soaking time, the more severe the damage. Generally, the degree of damage on the fracture conductivity caused by water–shale interaction is higher than that caused by supercritical CO2 shale interaction under the same soaking time. When considering the damage of hydraulic fracture effectiveness caused by fluid–shale interaction, the production of shale oil wells is significantly reduced. For shale reservoirs with strong permeability anisotropy, the cumulative oil production loss caused by fluid–shale interaction is more severe than that with weak permeability anisotropy.

Nanoscale Pore Evolution of Terrestrial Shale with Thermal Maturation Level Increase Induced by Hydrous Pyrolysis

A series of terrestrial shale samples with different thermal maturities were subjected to hydrous artificial pyrolysis to study the evolution of terrestrial shale pores. The original shale was obtained from the terrestrial interval of a core sample, the total organic carbon (TOC) content was 8.34 wt%, and the vitrinite reflectance (Ro) was 5.31%. The original shale core was cut into eight parts, which were heated at temperatures of 300, 350, 400, 420, 450, 500, 550, and 600 °C to obtain samples with different thermal maturities. The pore size distribution (PSD), pore volume (PV), specific surface area (SSA), and pore types were investigated via CO2 and N2 adsorption tests and field emission scanning electron microscopy (FE-SEM). Many organic matter (OM) pores and mineral pores were observed via FE-SEM with increasing thermal maturity. The total PV and SSA increased until the sample reached 500 °C and then decreased, and the mesopore volume followed this trend. The micropore volume first decreased, increased until the sample reached 500 °C, and then decreased; the macropore volume increased to a peak in the sample pyrolyzed at 420 °C and then remained stable. Pores with sizes ranging from 10 to 30 nm were the predominant contributors to the shale pore volume. The SSA was affected by pores with diameters less than 20 nm, which accounted for approximately 54% of the SSA. The rate of OM conversion influenced pore creation.

Spontaneous imbibition characteristics and influencing factors of shale oil reservoir in Qintong depression

This study integrates one-dimensional and two-dimensional nuclear magnetic resonance (NMR) techniques to conduct spontaneous imbibition experiments on two distinct lithologies (laminated calcareous shale and bulk clay-rich shale) from the Qintong Depression using four different fluid types. Field emission scanning electron microscopy (FE-SEM) and computed tomography (CT) scanning were employed to observe and track the dynamic changes in shale microstructures at specific intervals allowing for a comprehensive analysis of induced microfractures and their propagation patterns. These methods enabled a deeper understanding of the underlying mechanisms, enriching the interpretation of the imbibition results. The study reveals that anionic surfactants demonstrate exceptional performance during the imbibition process, and the combination of surfactants further enhanced oil recovery. The imbibition process can be divided into three stages: the imbibition diffusion stage, the transition stage, and the equilibrium stage, with the diffusion stage serving as the primary contributor, driven predominantly by capillary pressure. The calcareous shale cores exhibited the highest imbibition rates in the early stages, approaching equilibrium in the middle stages. Conversely, the clay-rich shale cores maintained relatively high imbibition rates throughout the second stage, indicating different imbibition dynamics based on lithology. NMR, CT scanning, and SEM analysis highlighted significant lithology-dependent differences in the mechanisms driving induced microfracture development during the imbibition and hydration. In laminated calcareous shale, imbibition and hydration primarily proceeded through the dissolution of calcareous minerals, resulting in pore expansion and induced microfractures along pre-existing fractures. In contrast, clay-rich shale exhibited similar mineral dissolution but also experienced clay swelling due to its high clay content, leading to the formation of bedding-parallel fractures with distinct directional patterns along weak mineral-matrix bonds. The experimental results underscored the pivotal role of lithology in determining final imbibition efficiency, with high-clay-content shales demonstrating superior recovery rates under spontaneous imbibition conditions. This study provides critical experimental data and insights into the microscopic mechanisms governing spontaneous imbibition across varied lithologies and fluid types in the Qintong Depression. The results offer foundational knowledge for optimizing oilfield development strategies.

Integrated experimental studies of pore structure and fluid uptake in the Bossier Shale in eastern Texas, USA

Within the Haynesville-Bossier Shale complex, the Bossier Shale has not been extensively studied by either industry and academia, despite it being an unconventional gas reservoir and a potential caprock for carbon storage in the underlaying Haynesville Shale. The lack of knowledge of the complex pore structures and fluid-rock interactions hinders the effective extraction of gas and the characterization of fluid reservoirs and sealing capacity. Integrated experimental studies of pore structure and fluid-rock interactions were conducted in seven Bossier Shale core samples collected in eastern Texas. Petrographic, geochemical, and petrophysical properties such as mineral composition, organic richness, thermal maturity, porosity, pore/pore throat diameter distribution, water-accessible pores, liquid water imbibition, and water vapor adsorption were characterized using complementary approaches of thin-section petrography, scanning electron microscopy, X-ray diffraction, total organic matter, pyrolysis, mercury intrusion porosimetry, nuclear magnetic resonance, (Ultra-) small angle X-rays scattering as well as small angle neutron scattering with deuterated liquids and contrast variation. The results show that the thermally mature Bossier Shales are composed of mixed argillaceous mudstone, mixed mudstone, and mixed carbonate mudstone. The shale contains both organic and inorganic pores, with porosities of 3.24–9.37 %, pore-to-throat ratios of 1.65 to 19.4, and water-accessible pores accounting for 28.7–72.6 % of total pores. Approaches of liquid water imbibition and water vapor adsorption, with and without direct contact of water with shale samples, indicate that liquid water first enters the nano-sized pores under high capillary pressures, and water vapor adsorption is mainly controlled by both clay minerals and pores with diameters less than 10 nm. These findings contribute to a better understanding of pore structures and water-shale interactions and their controlling factors in the Bossier Shale.

Natural Gas Liquid Huff ’n’ Puff in Ultratight Shale Reservoirs: An Experimental and Modeling Study

Summary Solvent huff ’n’ puff (HnP) is becoming a common enhanced oil recovery (EOR) practice in unconventional tight and ultratight reservoirs. For an effective HnP operation, achieving miscibility is essential for promoting solvent transport into the reservoir matrix and subsequent oil production. This is typically achieved by either increasing the injection pressure or enriching the solvent. However, injection pressure is constrained by compressor capacity, formation fracture pressure, and lateral/vertical containment. In this study, we experimentally assess the feasibility of using natural gas liquid (NGL) for HnP in an ultratight Eagle Ford (EF) shale sample, providing insights into extreme solvent enrichment scenarios in an HnP process. We hypothesize that NGL extracts oil from an oil-saturated shale core through a counterdiffusion process, primarily governed by first-contact miscibility (FCM) between NGL and oil. In this study, we explore the impact of solvent injection on the phase envelope of both dead oil and live oil during the HnP process. We present a critical comparison between C1 HnP, representing the lower limit of solvent enrichment, and NGL HnP, representing the upper limit, focusing on their respective oil recovery mechanisms and in-situ solvent-oil interactions. Using a high-pressure and high-temperature (HPHT) visualization apparatus, we investigate the interactions between NGL and oil, as well as their compositional variations, under bulk-phase conditions and in the core during the HnP process. We propose an analytical theory for the transport of NGL and oil into and out of an ultratight porous medium, explaining the experimental oil recoveries observed from the shale core. NGL and oil transport is modeled under a diffusion-dominated scenario, with FCM playing a crucial role in enhancing diffusion. Compositional analysis indicates that, contrary to C1, NGL extracts heavier oil components during the soaking stage. Core visualization demonstrates a gradual color change of NGL from clear to amber during soaking, indicating oil production via counterdiffusion. NGL expands the two-phase envelope of the dead oil, making it more volatile, while suppressing the phase envelope of the live oil. This potentially extends the duration of single-phase oil flow during the depletion stage in a live-oil system and enhances the oil production through diffusion. NGL achieves significantly lower FCM pressure (FCMP) with oil compared with C1, C1/C2 (70/30), C2, and separator gas, explaining its higher diffusion into the oil-saturated core. The analytical model demonstrates that NGL diffuses to the end of the core by the end of soaking. NGL recovers significantly more oil than C1 in the HnP process. Most of the oil is produced during soaking due to counterdiffusion, with solution-gas drive contributing additional recovery at later stages of depletion, though not as markedly as in C1 HnP.

Splitting tensile strength of shale cores: intact versus fractured and sealed with ureolysis-induced calcium carbonate precipitation (UICP)

Ureolysis-induced calcium carbonate precipitation (UICP) is a biomineral solution where the urease enzyme converts urea and calcium into calcium carbonate. The resulting biomineral can bridge gaps in fractured shale, reduce undesired fluid flow, limit fracture propagation, better store carbon dioxide, and potentially enhance well efficiency. The mechanical properties of shale cores were investigated using a modified Brazilian indirect tensile strength test. An investigation of intact shale using Eagle Ford and Wolfcamp cores was conducted at varying temperatures. Results show no significant difference between shale types (average tensile strength = 6.19 MPa). Eagle Ford displayed higher strength at elevated temperature, but temperature did not influence Wolfcamp. Comparatively, cores with a single, lengthwise heterogeneous fracture were sealed with UICP and further tested for tensile strength. UICP was delivered via a flow-through method which injected 20–30 sequential patterns of ureolytic microorganisms and UICP-promoting fluids into the fracture until permeability reduced by three orders of magnitude or with an immersion method which placed cores treated with guar gum and UICP-promoting fluids into a batch reactor, demonstrating that guar gum is a suitable inclusion and may reduce the number of flow-through injections required. Tensile results for both delivery methods were variable (0.15–8 MPa), and in some cores the biomineralized fracture split apart, possibly due to insufficient sealing and/or heterogeneity in the composite UICP-shale cores. Notably in other cores the biomineralized fracture remained intact, demonstrating more cohesion than the surrounding shale, indicating that UICP may produce a strong seal for subsurface application.

Numerical Simulation of Seepage in Shale Oil Reservoirs Under Hydraulic Fracturing: From Core-Scale Experiment to Reservoir-Scale Modeling

In this study, finite element software was used to simulate seepage at the core scale, the stress sensitivity of the shale core of the stripe layer and fractures was evaluated, and the production optimization design of reservoir C in block B of the oilfield under different fracturing parameters and wellbore parameters was simulated. The coupled finite element model of reservoir seepage stress was established; the pore elasticity model was used to determine the reservoir deformation; the seepage followed Forchheimer’s law and Darcy’s law; and finally, the liquid production was calculated to optimize the production plan. The results showed that the permeability under the same stress conditions increased nonlinearly with the increase in the striatal angle at the core scale, the permeability under the same effective stress conditions decreased gradually with the increase in the shale/fringe thickness ratio, and the elastic modulus and Poisson’s ratio of the proppant decreased. The permeability stress sensitivity was stronger. In the reservoir-scale model, the production pressure difference was the most significant factor affecting shale oil production, followed by the number of fractures and the length of the horizontal zone wellbore, and the elastic modulus of the proppant and Poisson’s ratio had the least impact on production.

Unconventional reservoir stimulation method based on electrohydraulic discharge shock and frequency resonance technology

To increase the production of unconventional oil and gas, it is necessary to improve reservoir porosity through reservoir reconstruction. High voltage electro-hydraulic discharge can generate strong shock waves, which not only meets the requirements of reservoir reconstruction, but also has the advantages of high efficiency and environmental protection, and has become a research hotspot. In order to further improve the effectiveness of reservoir transformation, a reservoir stimulation method based on electrohydraulic discharge shock and frequency resonance is proposed. Firstly, an electrohydraulic discharge equipment was designed, and according to the material and structure of the designed rod plate electrode, a theoretical electrohydraulic discharge model was built based on the bubble theory. The high voltage breakdown process under the condition of applied voltage of 12 kV and electrode gap of 2 mm is simulated in detail. The simulation results show that the discharge time is within 0.3 μs, and the extremely short discharge time not only produces strong shock waves, but also forms an arc channel to cause circuit damping oscillation. Then, an electrohydraulic discharge experimental platform was built according to the developed equipment. The discharge process was recorded by a high-precision oscilloscope, and the arc formation was photographed by a high-speed camera. The experimental results not only verify the correctness of the theoretical analysis, but also confirm that the developed electro-hydraulic discharge device can generate 0–60 Hz adjustable electrical pulses and has the ability to cause reservoir resonance. Finally, a comparative experiment was carried out with shale core samples to test the influence of resonance factors on the development of internal fractures in unconventional reservoir rocks. The CT scan images show that the shale fracture porosity in the resonance group increased by 46.4 %, which is much higher than that in the non-resonance group (11.8%). To further test the frequency resonance effect on reservoir reconstruction, a field test was carried out on the coalbed methane wells in Shanxi using the developed equipment. The experimental results show that the average gas production rate after on-site construction is increased from 11.46 m3/h to 12.49 m3/h, an increase of 8.99 %, indicating that the proposed technology can significantly promote the development of rock fractures and enhance the production recovery.

A modified surface to volume (SVR) method to calculate nuclear magnetic resonance (NMR) surface relaxivity: Theory and a case study in shale reservoirs

Surface relaxivity (ρ2) is a critical parameter for converting nuclear magnetic resonance (NMR) T2 data to pore size distribution (PSD). The surface-to-volume ratio (SVR) method, known for its simplicity and ease of operation, has been widely used for ρ2 calculation in unconventional reservoirs. However, previous studies often overlooked the equivalence of pore ranges characterized when directly applying the classical SVR model. Moreover, shale reservoirs generally develop layered fractures, whose ρ2 values are different from matrix pores. The logarithmic mean value of the T2 distribution (T2LM) is significantly influenced by layered fractures, therefore, relying solely on the T2LM value of a whole sample under fluid-saturated state will lead to inaccurate ρ2 values of matrix pores, particularly in laminated shales where fractures are well developed. However, insufficient attention has been paid to the effect of fractures on the ρ2 calculation. In this study, a modified SVR method based on the theory of NMR relaxation in partially fluid-saturated pores was proposed to characterize the ρ2 of shale matrix pores. Twenty-four shale core samples from the Shahejie Formation in the Jiyang Depression, China were selected, and subjected to series of NMR experiments at varying oil-bearing conditions, and low-temperature nitrogen adsorption (LTNA) analysis. The results indicate a strong linear correlation (R2 > 0.85) between the inverse T2LM (1/T2LM) and the inverse fluid saturation (1/f) when oil molecules across the entire surface layer participate in the exchange process. For a whole core sample, ρ2 values obtained using the modified SVR model are higher than those obtained using the classical SVR model, especially in samples with numerous fractures. The modified SVR method effectively reduces the impact of fractures on the characterization of ρ2 of matrix pores. For shale pore ρ2 characterization, the classical SVR model may be more suitable for pores smaller than 300 nm, with a recommended T2 range of <33 ms. Additionally, ρ2 values for different pore ranges (<25 nm, 25–100 nm, and >100 nm) within individual samples were estimated. It is found that the ρ2 values of smaller pores is greater than those of larger pores, which may be due to differences in mineralogy of the pores across various size ranges. The small pores are more associated with clay minerals while large pores are surrounded by quartz and rigid minerals. In addition, ρ2 is lower in larger pores and fractures that do not contain organic matter and clays, thus the underestimation of ρ2 by the classical SVR method can be corrected by modified SVR method. This study represents the first attempt to examine ρ2 variations across different pore ranges in shale reservoirs. The methodology presented can be applied to other formations, enhancing NMR data application in both laboratory settings and well logging.

The impact of pore heterogeneity on pore connectivity and the controlling factors utilizing spontaneous imbibition combined with multifractal dimensions: Insight from the Longmaxi Formation in Northern Guizhou

The heterogeneity of shale pores, a crucial factor in the occurrence and migration of shale gas, exerts a significant impact on the pore connectivity. Pores exhibiting a range of structural attributes to the complexity of pore connectivity. A comprehensive study into the impact of pore heterogeneity on pore connectivity in shale is lacking. This study aims to explore the impact of pore heterogeneity on pore connectivity in shale and the primary controlling factors of pore connectivity. Shale pore connectivity, pore structures, mineral composition, and geochemical parameters were assessed using various tests, including spontaneous imbibition, adsorption, mercury intrusion capillary pressure (MICP), focus ion beam-scanning electron microscopy (FIB-SEM), sulfur and carbon analysis, vitrinite reflectivity, and X-ray diffraction (XRD). Pore heterogeneity was quantitatively analyzed using the multifractal dimensions method. Results show that the increased heterogeneity of pore structure and surface roughness facilitating the potential for increased connectivity. The presence of well-developed micro-mesopores within the organic matter, alongside numerous disconnected and independent pores, contributes to an increase in pore heterogeneity. Micro-mesopore structures have a more pronounced impact on pore heterogeneity than macropores. The heterogeneity of the pores is predominantly influenced by variations in the PV and SSA of micro-mesopores. Furthermore, the heightened heterogeneity of pore structure (D1) and surface roughness (D2) leads to a more complex pore structure with increased roughness, promoting the potential for enhanced connectivity through additional throats and facilitating the formation of secondary microfractures. Shale cores characterized by high total organic carbon (TOC) content, porosity, and clay mineral content are conducive to improved pore connectivity. Conversely, the increase of thermal evolution maturity of shale in the over-mature stage is not conducive to the increase of pore connectivity. Thermal evolution maturity, TOC content, and clay mineral are key factors that control pore heterogeneity, further affecting the connectivity of shale pores. High pore connectivity is conducive to spontaneous imbibition capacity and the formation of hydraulic microfractures, promoting the migration of shale gas.

High-resolution chemofacies and pore system characterization of the Pennsylvanian Cline Shale, Midland Basin, Texas

The connections between the depositional environment, sediment chemistry, and pore structure of deep-water mudstones are still not completely understood. This study: 1) investigates the sediment chemistry and the depositional conditions of the Pennsylvanian Cline Shale chemofacies in the center of the Midland Basin, 2) characterizes the conditions favorable to organic matter accumulation of each mudstone chemofacies, and 3) examines the connection between the pore structure and the mudstones’ paleo-environmental and paleo-geochemical context and processes. This study uses X-ray fluorescence (XRF) and statistical methods (Isolation Forest, Principal Component Analysis, and K-means) to identify four chemofacies of 127 m of Cline Shale core from the Matthew 'D' 0906 well located in the Midland Basin depocenter in Glasscock County, Texas. In addition, petrographic and scanning electron microscopy and measurements by dual-energy computed tomography, X-ray diffraction, Rock-Eval pyrolysis, N2 isothermal adsorption tests, and mudrock reservoir properties were conducted on thin-sections, core slabs, and samples to understand the bulk geochemistry and petrophysical properties of the mudstones. Four chemofacies are identified: (1) Siliceous Mudstone with high Zr and low Ca and P, (2) Calcareous-argillaceous Mudstone I with high Ca and Zr, and low P, (3) Argillaceous Mudstone with high P and low Ca and Zr, and (4) Calcareous-argillaceous Mudstone II with high Ca and P, and low Zr. Based on elemental distribution, the first two and last two chemofacies are interpreted as low sea-level deposits and high sea-level deposits, respectively. Water stratification and P regeneration accounted for the highest total organic carbon (TOC) content, which resulted in the high porosity and pore volume of the low sea-level Siliceous Mudstone chemofacies, especially visible in the 8 nm–186 nm organic matter pores. Carbonate input hinders the development of the inorganic pore system, especially for organic lean Calcareous-argillaceous Mudstones. Nine sea-level cycles were observed in the cores and correlated to nine US mid-continent cycles attributed to the 405-kyr Milankovitch parameter (long orbital eccentricity) during the late Pennsylvanian. We hypothesize that late Pennsylvanian climate change, paced by orbital cycles, controlled the distribution and stacking pattern of mudstone chemofacies, which also controlled source rock quality and consequent pore system development.

Evaluation of Post-fracturing Imbibition Oil Displacement Efficiency in Shale Reservoirs

In order to clarify the imbibition law of shale oil after fracturing with guanidine gum and nano-slickwater, this study quantitatively analyzed the imbibition efficiency of shale core under different time periods of two kinds of fracturing fluids through the imbibition experiment of natural shale core and nuclear magnetic resonance test technology, and preliminarily understood the microscopic crude oil production characteristics of pore throat of shale imbibition. The experimental results show that the imbibition oil removal efficiency of nano-slick water reaches 34.7 %, which is higher than that of guanidine gum fracturing fluid. In the high imbibition efficiency stage of rock samples, within 6 h of the beginning of the experiment, the small pore porosity reaches 20.8 %, the large pore and fracture reach 30 %, and the final imbibition oil displacement rate can reach 31.7% and 39.6 %. The development of micro-fractures and bedding fractures is beneficial to improve the imbibition efficiency. With the extension of time, the imbibition rate gradually decreases, and the utilization degree of pore throat is limited.

EXPERIMENTAL STUDY ON THE FRACTURE CONDUCTIVITY IN SHALE OIL PRODUCTION

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

Simulation of in-situ steam-driven oil seepage in single-fracture oil shale CT digital cores after pyrolysis at different temperatures

Based on digital cores of oil shale obtained from high-temperature steam in-situ pyrolysis and micro-CT scanning experiments, the real structures of oil shale after pyrolysis at different temperatures were seamlessly integrated into COMSOL through precise grid partitioning. This enabled the simulation of in-situ steam-assisted oil recovery two-phase flow fields. The study examines the dynamic evolution of phase interfaces, pressure fields, velocity fields, and oil displacement efficiency during the in-situ two-phase flow process in pore structures with varying degrees of development. The research indicates that: Firstly, the development and connectivity of pore structures significantly influence the advancement speed of the phase interface — the better the pore structure development, the faster the phase interface advances. Secondly, as seepage progresses, the stability of phase interface advancement improves, with the difference between the peak δa value before stabilization and the stabilized δa value decreasing over time. Thirdly, at the moment of steam injection, a surge in Pa within the seepage zone occurs. The complexity of the pore structure effectively mitigates the surge in Pa caused by the instantaneous gas drive effect. Finally, the total seepage volumetric flow rate Qtotal increases with time. The oil production ratio α at the outlet decreases slightly with time, but remains above 97.6 %, demonstrating the effectiveness of steam-assisted oil recovery.

End-Member Mixing Model for Methane Carbon Isotope Fractionation During Shale Gas Desorption and Its Application.

Unlike conventional natural gas reservoirs, shale gas development involves systematic changes in methane carbon isotopes that cannot be effectively described by existing isotope fractionation models and mechanisms. Therefore, based on fundamental theories such as Rayleigh fractionation, mass transfer flow, and mass conservation, this study established isotopic fractionation equations for methane in adsorbed and free gas. By considering adsorbed and free gases as two end-members and using an isotope mixing model, a fractionation model for methane carbon isotopes during shale gas desorption was constructed. This model quantifies the isotopic fractionation effects during shale gas desorption and elucidates the mechanism of methane carbon isotope fractionation. Using on-site desorbed gas content and isotope data, parameter fitting and model calculations were conducted to characterize methane carbon isotope variations throughout the process of shale core field desorption. The results show a pattern of "initially negative and then turning positive," consistent with those of physical simulation experiments. It was clarified that differences in mixing the two end-members and isotopic fractionation play key roles in the variation of methane carbon isotopic composition in shale gas. By applying the methane carbon isotope fractionation model, the contribution of adsorbed gas during shale gas production was explored. It was found that in the early stage of development, the adsorbed gas in Well JY 1 was negligible. After nearly seven years of development, the contribution of adsorbed gas in the later stage has only reached nearly 15%, indicating that the production contribution of adsorbed gas is still less than 0.3 million cubic feet per day. The open flow of Well JY 6-2 is more conducive to the production of adsorbed gas, but the production capacity is still mainly contributed by free gas, indicating that the shale gas production capacity in the later stage in the Jiaoshiba gas field is still primarily dominated by free gas.

Compositional controls on the Lower Cretaceous Rodby Shale pore structure and surface area: a planned CCS top seal caprock for the Acorn storage site

Fine-grained lithologies above CCS reservoirs cannot automatically be assumed to be mineralogically stable, or high quality top-seals to highly pressured CO2 as saline aquifer have previously contained hydrostatically pressured water. We have investigated the mineralogy, pore systems and surface area characteristics of the Lower Cretaceous Rodby Shale, the caprock to the Captain Sandstone at the UK's planned Acorn/Goldeneye CCS site. Rodby Shale core was logged and analysed by XRD, light microscopy, and SEM. Grain size was measured using laser particle size analysis. Mercury intrusion porosimetry and nitrogen adsorption analysis were used to characterise the pore network. The Rodby is smectite-rich and contains abundant calcite as well as quartz silt with small quantities of chlorite and plagioclase. Calcite was sourced from benthic microfossils, locally recrystallised to create a pore-filling cement. The mean pore throat and pore body diameter are about 17 nm putting the Rodby in the mesopore range and suggesting a predominance of slit-like pores. There are three lithofacies in the Rodby Shale: (i) high surface area clay-rich shale, (ii) low surface area calcite-rich shale, (iii) intermediate surface area quartz-rich. if the second lithotype encountered CO2, then the resulting calcite dissolution would lead to increasing surface area of the remaining shale. The Rodby Shale has good potential to be an effective barrier for CO2 escape, based on assessments of diffusion rate and post-breakthrough advection rate as well as stability and sealing assessments.

Environmentally friendly and temperature resistant water-based drilling fluids with highly inhibitory synthetic nanocellulose polymers for deep sea drilling

The ocean is rich in sustainable hydrocarbon. The process of extracting these resources poses challenges such as coexistence of low temperature and high temperature, high pressure of deepwater and unpredictable shale formations. A kind of ionic crosslinking polymer consisting of N, N-dimethylacrylamide (DMA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and Cellulose Nanofibers (CNF) (PADC), was synthesized to address these challenges. Cellulose was first oxidized to nanocellulose (CNF) through 2,2,6,6-tetramethylpiperidinyl-1-oxide (TEMPO) oxidation. Subsequently, the ionic crosslinking polymer, consisting of DMA, AMPS, and CNF, was synthesized using ionic crosslinking polymerization. The surface characteristics and morphology were characterized by transmission electron microscopy (TEM), nanoparticle size analysis, and zeta potential analysis. The structural composition was analyzed by Fourier Transform Infrared Spectroscopy (FT-IR). The shale inhibition mechanism was investigated through contact angle and pressure transmission experiments. The results indicated that the average length of PADC is approximately 1450 nm, with an average diameter of less than 100 nm and contains sulfonic acid groups. The shale contact angle increased from 16.75° to 82°, indicating that PADC increased the hydrophobicity of the shale by 390%. Pressure transfer experiments show that PADC can reduce shale permeability by 37%, which means PADC has good hydration inhibition performance. In addition, a drilling fluid system suitable for deep sea drilling was proposed. The drilling fluid system exhibits good rheological properties at 160 °C and 0 °C. The fluid loss after hot rolling at 160 °C is less than 12 mL. The linear expansion of shale core after 16 h is only 0.7%, and the rolling recovery rate at 160 °C is as high as 99.48%. Luminescent bacteria EC50 is 2.0 × 105 mg/L, which means it is non-toxic and environmentally friendly. And drilling fluid conforms to the power law flow model. Therefore, the drilling fluids proposed in this paper can meet the requirements of deep sea drilling in terms of rheological properties and filtration loss properties at 0–160 °C, and can seal shale pores and inhibit shale hydration through the ionic cross-linking PADC. This research offers insights into the utilization of cellulose in well drilling processes and provides references for designing deep sea drilling fluids.

Investigating the potential of unconventional resources in the Midland Basin: A comprehensive chemostratigraphic analysis of a Cline Shale (Wolfcamp-D) core

Basinal mudrocks assigned to the Wolfcamp Group in the Midland Basin are prolific producers of oil and gas. Technological advancements in horizontal drilling and hydraulic fracturing have been successful in the exploitation of oil and gas from these tight mudrocks. However, many challenges remain unsolved in capturing their macroscale compositional variations to enhance recovery factors and delineate “sweet spots”. To gain improved insights into this fine-grained system, high resolution chemostratigraphic (XRF) data was integrated with mineralogical measurements (XRD), logs, thin sections, and TOC readings, as well as hierarchical cluster analysis to: 1) develop a sequence stratigraphic framework, and 2) reconstruct paleo-redox, as well as ancient water-mass, conditions within the Cline Shale (Wolfcamp-D) from a core in the Midland Basin.This study revealed the presence of three chemo-stratigraphically distinct depositional sequences in the Cline Shale, herein termed Lower, Middle, and Upper Cline from the base upwards. All three units exhibit distinct mineralogical and petrophysical characteristics, were correlated across the basin, and interpreted as third-order sequences. Superimposed onto the three interpreted third-order sequences within the Cline, are potential higher frequency (fourth-order) sequences. These fourth-order sequences typically consist of a lower interval, interpreted as lowstand deposits and an upper interval, which is interpreted as transgressive and highstand deposits. The lower interval is interpreted to be deposited during highly reducing conditions while the upper interval is interpreted to be deposited under suboxic conditions. The highest organic matter preservation is associated with the interpreted lowstand deposits, especially in the Upper Cline. Optimal landing zones (20 ft) are recognized in the upper zone of the Cline Shale based on their high resistivity, total organic richness, elevated siliceous content, and reduced percentage of clay minerals. These zones have been correlated with several nearby wells.The current study demonstrates the wealth of information that can be gained from a single core/well when properly investigated at high resolution with measurements on a cm-scale. The observed shifts in the chemistry of the sediments character and composition are distinct, with implications for sequence stratigraphic analysis, the reconstruction of ancient water-mass conditions, and the identification of “sweet spots” for hydrocarbon resources. The provided analysis lays a foundational basis for further studies in the region, serving as critical data input for expansive regional research efforts.

Fracture stratigraphy in oil-rich shale of the Upper Xiaganchaigou Formation (upper Eocene), western Qaidam Basin

Natural fractures in wells from oil-rich shale of the Upper Xiaganchaigou Formation in Qaidam Basin, the largest Cenozoic sedimentary basin in the Tibetan Plateau, vary systematically by stratigraphic position, allowing reconstruction of fracture generation processes during regional tectonic deformation. Compacted fractures, layer-bounded fractures, and low-angle (or bed-parallel) fractures were widely identified in oil-rich shale cores obtained from vertical wells. The layer-bounded fractures can be subdivided into two sets: one prevalent in light-colored (low gamma-ray) stiff layers and arrested by dark-colored (high gamma-ray) compliant layers, the other set primarily confined to the dark-colored compliant layers. The strikes of layer-bounded fractures, revealed by horizontal well FMI logs, are dominantly N60°-80°E and N10°-30°E within the light and dark intervals respectively. These strikes are consistent with natural hydraulic fracturing of the light layers during the Oligocene and the dark layers during the Middle Miocene-Holocene, based on a regional anticlockwise rotation of the compressional strain orientation. The abutment of layer-bounded fractures against low-angle (or bed-parallel) fractures in dark layers implies that the low-angle fractures were hydraulically fractured under a vertical least compressive stress during the Early Miocene, which produced the most intense tectonic compression. Layer-bounded fractures generally remain unmineralized in the dark layers but were mineralized in the light layers, suggesting that fractures confined in light layers would not decrease the sealing capacity of the shale oil system and fractures confined in dark layers can increase the pore space of shale oil storage. The Oligocene and Early Miocene fractures represented mechanical flaws that affected the initiation of Middle Miocene-Holocene fractures, implying that all natural fractures may alter hydraulic fracture stimulations to some extent.

Pore-scale probing CO2 huff-n-puff in extracting shale oil from different types of pores using online T1–T2 nuclear magnetic resonance spectroscopy

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.