Shale Samples Research Articles

Comparison of Methods for Determining the Oil Content in Medium-Mature Shale—A Case Study from the Fourth Member of the Shahejie Formation in the Dongying Depression

The oil content of shale oil reservoirs is a key parameter for reserve evaluation and “sweet spot” selection. However, discrepancies in the oil contents obtained by different methods have led to considerable disparities in the selection of exploration well locations and development strategies for shale oil. This study focuses on low to moderately mature sealed coring samples from the Dongying Depression in the Bohai Bay Basin. Three methods—NMR, Dean–Stark, and Rock-Eval—were employed to measure the oil content of shale. The results indicate that the oil content obtained by NMR is the highest, followed by the Dean–Stark distillation extraction method, while the pyrolysis method yields the lowest value. The study found that (1) the efficiency of the solvent extraction effect on moderately to low-mature shale is low since the occurrence of numerous closed pores leads to a lower yield when using the Dean–Stark method. (2) The exposure of shale samples to the air, sample crushing, and lag time for temperature increase cause a significant loss of light hydrocarbon components, resulting in the lowest oil content when measured by the Rock-Eval method. The NMR method, with its advantages of a short analysis time and non-destructive nature, appears to be the most advantageous method for shale oil content evaluation.

Organic geochemical characteristics of Jurassic Yan ’an Formation source rock in Pengyang area of southwestern Ordos basin

The Jurassic Yan ’an Formation in the southwestern margin of Ordos Basin has developed many sets of coal-associated and non-associated mudstone as well as oil shale. Different analytical methods including total organic carbon (TOC), Rock-Eval pyrolysis, and conventional biomarker analyses were applied on the mudstone, the coal and the oil shale extracts to unravel their organic geochemical characteristics and the paleo depositional environment. Results reveal that all the source rock samples are immature to mature with good petroleum generation potentials. The redox environment is generally reducing. The organic matter input is mainly terrestrial higher plants. The low Ga/C30 hopane ratio of all the samples indicate the low salinity of the paleo-water column. The oil shale samples show much higher thermal maturity than the coals and mudstones as indicated by the higher C31 homohopane isomerization indexes, C32 homohopane isomerization indexes and the C29 sterane ααα20S/(S + R) ratios. The depositional environment of the oil shale is more reduced compared to the coals and mudstones as can be reflected by the low oxygen index and the higher C35 hopane/(C31-C35 homohopanes) ratios. Thus, the oil shale layers should be the target of the next exploration and development. And the Oil shale and coal can be exploited simultaneously in Pengyang area.

Temperature Dependence Evaluation of CO2 Adsorption on Eagle Ford Shale using Isothermal Models: A Comparative Study

This study investigates the CO2 adsorption capacity of the Eagle Ford (EF) shale under varying temperatures, utilizing six isothermal adsorption models: Langmuir, Freundlich, Dubinin-Radushkevich (D-R), Sips, Toth, and Brunauer-Emmett-Teller (BET). The shale sample was characterized through Total Organic Carbon (TOC) analysis, X-ray diffraction (XRD), BET surface area analysis, and Field Emission Scanning Electron Microscopy (FESEM) to assess its organic content, mineral composition, pore structure and elemental composition. CO2 adsorption experiments were conducted using a volumetric method at pressures up to 12 MPa and temperatures of 35°C, 55°C, and 70°C. The results revealed that the adsorption capacity increased with pressure but decreased with rising temperature, which is consistent with the exothermic nature of CO2 adsorption. Among the models, Freundlich and Sips provided the best fit for most temperature conditions, highlighting the heterogeneous nature of the shale surface, while the Langmuir, Toth, and D-R models performed well but with slight deviations. The BET model exhibited the poorest fit. Overall, the findings suggest that the EF shale has significant potential for CO2 storage, especially at lower temperatures, with Freundlich and Sips models being the most reliable for predicting adsorption behavior in EF shale formations.

Anisotropy in shear failure of shale: An insight from microcracking to macrorupture

Anisotropic shear failure in shale is crucial to wellbore instability and hydraulic fracturing. While previous studies have examined bedding angles ranging from 0° to 90°, the intermediate angles have not been thoroughly investigated, with limited quantitative analysis from microcracking to macrorupture. To address this gap, we conducted direct shear tests on cubic shale samples with seven bedding angles (α = 0°, 15°, 30°, 45°, 60°, 75°, and 90°) using an innovative combination of acoustic emission (AE) and digital image correlation (DIC) techniques. This approach allowed us to gain a comprehensive understanding of the cracking damage process from the interior to the surface. Under various normal stresses, the minimum peak shear strengths occurred at α = 0°, while the maximum values were observed at α = 45° or 60°, rather than remaining constant. The internal friction angle peaked at α = 45°, not at α = 30° as previously reported. Furthermore, the shear failure pattern was influenced by complex interactions among nominal shear plane, bedding structure, and normal stress. The primary strain concentration zones and microfractures formed not only along the nominal shear plane but also along the bedding planes. Notably, microcracking damage initiated most readily at α = 0°, where the b value in AE events was higher and the fractal dimension was lower. At α = 30°–60°, the b value reached its minimum, while the fractal dimension peaked. The more random distribution of larger-scale microcracks was associated with an increase in the shear strength. These findings provide critical insights into the anisotropy of shear failure in shale and demonstrate the potential of microcracking analysis in predicting critical macrorupture and shear resistance. The identification of three distinct shear failure mechanisms further enhances our understanding of shale anisotropy.

Three-dimensional reconstruction and connectivity analysis of REV-size organic matter in shales

Organic matter (OM) serves as a crucial site for shale gas generation and occurrence. Its content and spatial connectivity significantly influence gas flow ability and gas occurrence. However, in characterizing the three-dimensional (3D) connectivity of OM, current imaging techniques such as FIB-SEM and nano-CT cannot balance field of view (FoV) and image resolution. To address this gap, in this work, we develop a novel workflow for numerical reconstruction of REV-size digital rocks of OM that integrates high-resolution information of pore structures in large-view MAPS (modular automated processing system) images. Specifically, the open source code, SliceGAN, is used in the 3D reconstruction of digital rocks of OM, while the high-resolution information of OM pore structures is integrated into the digital rocks in terms of the classification of OM in the MAPS images. The classification of OM is solely based on the surface or 2D porosity of individual OM watersheds. As a first attempt, we propose three types of OM including Type A with high porosity (>20%), Type B with medium porosity (10%∼20%), and Type C with low porosity (<10%). Based on the case studies of three in-situ shale samples with different OM contents, we show that at the REV size the three types of OM, as a whole, can form conducting pathways throughout the domains, but each type of OM is disconnected. Type A and Type B OM have poor connectivity, while Type C OM holds the best connectivity dominating gas transport at the REV scale. Moreover, the reconstructed 3D digital rocks of OM can be used in the numerical modeling of REV-size gas transport in shales.

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.

Remarkable improvement in drilling fluid properties with graphitic-carbon nitride for enhanced wellbore stability.

This study examines the viability of using graphitic-Carbon Nitride (g-C3N4) nanomaterial as shale stabilizer drilling fluid additive having applications in the oil and gas wells drilling. Shale stability is important especially when drilling horizontal and extended reach wells with water-based muds (WBM) to tap unconventional reservoirs namely shale oil and shale gas. For this study, the g-C3N4 nanomaterial was produced by melamine pyrolysis, and characterized by X-Ray Diffraction, Scanning Electron Microscopy and Fourier Transform Infrared spectroscopy techniques. The developed g-C3N4 was used to formulate the WBM and its impact on the formulated mud system's rheological and filtration control characteristics as well as on shale stability was examined. In comparison to the base mud, the treated mud showed lower Fluid Loss (FL) and higher thermal stability. FL was reduced by 41.8% and 68% under Before Hot Rolling (BHR) and After Hot Rolling (AHR) conditions, respectively, with a maximum cake thickness of 1mm. The Yield Point was improved by 52% and 66% under BHR and AHR conditions, respectively. The increase in Plastic Viscosity, and Apparent Viscosity was 23.8%, and 38%, respectively. Shale recovery was 99.6% in g-C3N4 treated fluid compared to 88% in the base fluid. The treated shale Brunauer-Emmett-Teller (BET) surface area and the pore volume were significantly reduced compared to the pure shale, indicating significant plugging of shale nano- and micro-pores. The BET surface area of the g-C3N4 treated shale sample was 0.0405m2/g compared to pure shale sample's surface area 0.3501m2/g. Correspondingly, the pore volume of treated shale was 0.000029cm3/g compared to the pure shale sample's pore volume 0.000911cm3/g. Therefore, based on the experimental results obtained, it is inferred that the developed g-C3N4 nanomaterial has potential applications in WBM systems for drilling long shale sections.

Hydrocarbons, Hydrogen, and Organic Acids Generation by Ball Milling and Batch Incubation of Sedimentary Rocks

Pulverized rock samples are widely used in laboratory experiments, e.g., to assess microbial or abiotic processes in batch incubation tests. However, it is unclear if ball-milled samples accurately reflect in-situ conditions and if observed processes are affected by by-products artificially generated during the sample preparation procedure. As such, this study examined the effects of dry ball milling on the release of gases, which include C1-C4 hydrocarbons, carbon dioxide (CO2), hydrogen (H2), and low molecular weight organic acids (LMWOAs) from different sedimentary rocks. The experiments involved pulverization using a gas-tight zirconium oxide planetary ball mill followed by wet and dry batch incubation and thermal desorption up to 200 o C. During milling, all sedimentary rocks, except a low organic carbon sandstone sample, yielded methane (CH4), ethane (C2H6), propane (C3H8), butane (C4H10), H2, CO2, and unsaturated hydrocarbons, e.g., ethene (C2H4). Sandstones only yielded H2, CH4, and CO2. Stable carbon isotope signatures of these products are similar to thermogenic gases. The gases were also detected in subsequent wet incubation experiments (after gases from milling had been removed). Additionally, formate, acetate, and citrate, were detected in all samples except for sandstone. Pyruvate, malate, and succinate were also detected in some samples. Thermal desorption products of powdered limestone, shale, and pyrite concretion samples included organic acids, such as acetate and formate, which were higher in milled samples than in crushed particles (∼1 mm). The original geological thermal maturity of the studied sedimentary rock samples was low (below “oil window”) and, thus, considerably below “gas window”, suggesting that most of the detected gases were generated during ball milling. H2 generated during ball milling may be derived from the reduction of water from fluid inclusion or phyllosilicates, involving the formation of reactive mineral surfaces or radicals. Notably, the concentrations of gaseous hydrocarbons derived from milling are relatively high and comparable to “wet” gases. At the same time, these data indicate that substantial amounts of gases and LWMOAs might be artificially generated during laboratory batch experiments with milled samples. Hence, ball milled rock samples must be used with caution if assessing (bio-)geochemical processes for natural environments.

TG-MS Analysis for Elemental Composition of Organic Matters and Their Structural Properties.

A novel approach for determining the elemental content of organic matter through thermal gravimetric analysis coupled online with a mass spectrometer (TG-MS) is disclosed. This method not only yields results equivalent to ASTM analysis but also provides insight into the covalent bond structure within the sample. The principle of this technique consists of the combustion of organic matter in an oxygen-enriched environment within the thermogravimetric (TG) system. The gases generated during combustion, including carbon-containing gases such as CO2 and CO, hydrogen-containing gases such as H2O, nitrogen-containing gases such as NO2 and NO, and sulfur-containing gases such as SO2, are then analyzed using online MS. Quantitative analysis of these gases is accomplished via an external standard method, facilitating the determination of the elemental content of the organic matters. The experiment employed a temperature-programmed heating rate of 10 °C/min, a carrier gas flow rate of 100 mL/min, and an oxygen concentration of 50% by volume. We conducted tests on a range of 23 samples, including coal, heavy oil, oil shale, and biomass. The results for coal, oil shale, and biomass samples were consistent with ASTM standards, while the heavy oil samples demonstrated slightly lower values compared with ASTM methods. Furthermore, we probed into the mass loss and gas generation processes that occur during the combustion of samples, and these results enhance the understanding of the mechanism of organic matter combustion as well as that of the covalent bond structure of organic matters.

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.

Characteristics and main controlling factors for the development of shale micro pore-fracture in Tiemulike Formation, Yining Basin

Research on the type, size, structure, and other characteristics of shale micro pore-fracture and their genesis is one of the core index for Shale gas study. Based on systematically collected shale samples from outcrop profiles and well cores, the experiments of thin-section observation, scanning electron microscopy, energy-dispersive X-ray spectroscopy, whole-rock analysis, rock–eval pyrolysis and basin simulation analysis were performed to study the micro pore-fracture characteristics and its main controlling factors for the development of shale pores in Tiemulike Formation in Yining Basin. The results show that four types of micro pore-fractures were identified: organic hydrocarbon-generating micro pores, granular dissolved micro pores, intergranular micro pores, and micro-fracture. The development of micro pores in shales is influenced by the internal material composition of the shale reservoir and external temperature conditions. The high organic carbon content with a high degree of thermal evolution led to the development of numerous micro pores, and the main micro pores were produced by shrinking the hydrocarbon generation volume due to the thermal evolution of organic matter. The development of micro-fractures was found to be favoured by the high content of brittle minerals and overpressure in the formation.

Influence of quartz types on mechanical parameters in the early silurian Longmaxi shale, Sichuan Basin

Quartz is one of the most abundant minerals in shales, occurring predominantly in three forms: biogenic quartz (BQ), detrital quartz (DQ) and clay-transformed quartz (CTQ). The content of quartz is typically correlated with the fracability of shale gas reservoirs. However, the origins of quartz and its influence on mechanical properties remain not fully elucidated. To address this gap, this study examines shale samples from LM1-LM8 graptolite zones in well W202 of the Weiyuan shale gas field, the Sichuan Basin as the research object. After systematic analysis of organic geochemistry, mineral composition, cathodoluminescence observation, major/trace elements, and log interpretation and calculation of shale mechanical parameters, the genetic mechanism of quartz was analyzed and the percentage of quartz of different origins and the influence on rock mechanical properties were evaluated quantitatively. The results indicate that the three types of quartz (BQ, DQ and CTQ) were variably present in the Longmaxi shale across different graptolite zones. The LM1-LM3 graptolite zones exhibit the highest abundance of BQ, with contents ranging from 58.3 to 79.6%, with an average of 65.7%. DQ predominates in the LM4-LM5 and LM6-LM8 graptolite zones, with average contents of 38.7% and 34.9%, respectively. The BQ content is marginally higher in the LM4-LM5 zone compared to the LM6-LM8 zone, averaging 12.7% and 6.1%, respectively. The three types of quartz exert a dual influence on Young’s modulus, and a single linear effect on Poisson’s ratio. An increase BQ content correlates with a decreased in Poisson’s ratio, whereas increased contents of DQ and CTQ correlate with an increased Poisson’s ratio. With the highest Young’s modulus and the lowest Poisson’s ratio, the LM1-LM3 shale is the most favorable interval for hydraulic fracturing. Furthermore, BQ is positively correlated with the Brittleness index (BI), whereas the contents of DQ and CTQ are negatively correlated with BI. When the quartz content falls between 52% and 85%, the ratio of DQ to BQ is optimal for fracture development coinciding with high BI values, which are most conducive to fracturing stimulation.

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.

Anisotropy study based on uniaxial compression experiments

Abstract Due to the striated sedimentary structure of laminated shale and the weak cementation between the layers, the damage patterns of laminated shale with different laminar angles have obvious anisotropy after being damaged by uniaxial compression experiments. In this paper, numerical simulations of uniaxial compression experiments are carried out based on GDEM-PDyna on laminated shale with laminar angles (0°, 15°, 30°, 45°, 60°, 75°, 90°) to explore the anisotropy of compression parameters of laminated shale. The results show that: (1) the uniaxial compressive strength of laminated shale with the increase of the angle of the laminate shows a “U” type change rule which decreases first and then increases, and the uniaxial compressive strength is the smallest when the angle of the laminate reaches 60°; (2) the Poisson’s ratio of the specimen of laminated shale with the increase of the angle of the laminate shows a process which decreases first and then increases, and the change of Poisson’s ratio with the angle of the laminate has the same relationship with the elasticity of the specimen, and it is the same as the change of the compression parameters. The change of Poisson’s ratio with the increase of lamination angle and the change of modulus of elasticity show a similar law, all of them have experienced the “U” type change rule of decreasing first and then increasing, and all of them reach the minimum value when the lamination angle is 30°. (3) The brittleness index of the laminated shale samples showed a “stepwise” decrease with the increase of the laminated angle.

Improvement of Shear Strength Parameters on Clay Shale Using Calcite Precipitation Method

Abstract Clay shale, known for its expansive and weathered characteristics, poses challenges in construction when exposed. The calcite precipitation method offers a viable solution to bolster load-bearing capacity and counteract potential soil expansion while ensuring reversible changes. This study aims to evaluate improvements in the shear strength parameters of clay shale through the calcite precipitation method. The research involved soil properties tests, hydrolysis rate and precipitation ratio analyses, and direct shear tests on both saturated and dry soil specimens. Results showed clay shale samples with PL, LL, and PI values of 41.60%, 21.97%, and 19.62%, respectively, categorizing them as low to medium plasticity clayey soils (CL). The optimal treatment concentration was determined at 20 g/L soybean concentration with a precipitation ratio of 93%. In treated-saturated conditions, cohesion (c′) increased from 4.10 kPa to 12.07 kPa, and the internal friction angle (φ′) rose from 0.54° to 2.87°. Remarkable enhancements were observed in treated-dry samples, with c′ increasing from 7.53 kPa to 183.84 kPa, and φ′ rising from 2.31° to 19.25°. The SCU-CP method effectively improved the properties of dry clay shale.

Experimental and numerical simulation study on the CO2 pre-injection fracturing optimization parameters in continental shale oil

The CO2 pre-injection fracturing technique is widely used in the development of shale oil. To address the unclear mechanism of fracture creation in CO2 pre-injection fracturing, a study was conducted on the multi-fracture propagation model for lacustrine shale oil using CO2 pre-injection fracturing. This study revealed the changes in rock mechanical parameters during CO2 pre-injection fracturing, clarified the mechanisms of shale failure and fracture propagation, and optimized the parameters for CO2+water-based fluid fracturing to guide field operations. The research findings indicate that water-based fracturing fluid has a greater impact on the tensile strength and fracture toughness of shale samples compared to CO2+water-based fracturing fluid. CO2 can mitigate the adverse effects of water-based fracturing fluid on the rock's tensile strength and fracture toughness. Introducing CO2 before slickwater can partially restore the brittleness of shale, which is conducive to increasing the complexity of fracture networks. Reducing the viscosity of the water-based fracturing fluid and increasing the volume of CO2 injection are effective measures to enhance the modified volume. Increasing the stage spacing can improve the modified volume but may reduce fracture complexity. As the angle between natural fractures and the maximum horizontal principal stress decreases, the complexity of fractures created by CO2 pre-pad fracturing initially increases and then decreases, while the modified volume initially decreases and then increases.

Biodegradable Shale Inhibitors for Water Based Fluids

Swelling of shale formations is the main challenge may be encountered during the drilling operations. To address this challenge, the potassium chloride (KCl) is traditionally added as an inhibitor to the drilling mud for controlling its chemical reaction with the shale formations. However, environmental concerns surrounding the non-biodegradability and detrimental effects of chloride ions necessitate the exploration of alternative solutions. This study focuses on evaluating the efficiency of biodegradable and environmentally friendly additives in mitigating the shale swelling. Potassium sorbate, potassium citrate, and potassium bicarbonate are the selective additives with different concentrations (1%-7%). Different tests, including X-ray diffraction and X-ray fluorescence, were conducted to characterize the shale type and determine its chemical composition or the major mineral abundances. Additionally, scanning electron microscopy was employed to analyze the microstructure of shale cuttings and identify the small-scale pore features. Furthermore, cation exchange capacity measurements were performed to ascertain the shale samples' ion exchange capabilities. The effectiveness of the additives was evaluated using the Linear Swell Test. The results revealed that potassium sorbate exhibited a remarkable performance in reducing shale swelling, its consistently yielding the lowest swelling percentage compared to other tested materials. A concentration of 4% of potassium sorbate demonstrated the lowest reduction in swelling that reaches to 3.938%. Additionally, potassium citrate and potassium bicarbonate exhibited swelling rates close to those observed with KCl. The lowest swelling percentage achieved at different concentrations of potassium citrate (4% and 5%) was 12.019%. In contrast, a 11.819% of swelling percent was observed when 5% concentration of potassium bicarbonate was added to the drilling mud. This research introduces innovation biodegradable materials added to the drilling mud for mitigating the shale swelling.

Evaluation of solid bitumen created from marine oil shale bituminite under hydrous and anhydrous pyrolysis conditions

To test the influence of environmental conditions on aromaticity of solid bitumen generated during petroleum generation, four organic-rich (26–36 wt% total organic carbon) oil shale samples collected from the Neoproterozoic–Lower Cambrian restricted marine Salt Range Formation in the upper Indus Basin, Pakistan, were pyrolyzed under hydrous and anhydrous conditions. Experiments used closed system batch reactors at subcritical water temperatures between 300 and 370°C for 72 h. Thermal conversion of bituminite in the Salt Range oil shales created a newly formed solid bitumen, similar to previous observations from experiments on the Eocene lacustrine Green River Formation Mahogany zone oil shale. Newly formed solid bitumen in the Salt Range Formation oil shales generally has higher reflectance (Ro) in hydrous residues compared to anhydrous experiments subjected to the same time-temperature conditions, also similar to prior observations. This finding supports the hypothesis that radical disproportionation is favored in the presence of hydrogen contributed by water, promoting aromatization in the solid bitumen residue with concomitant increased expulsion of saturated hydrocarbons. Indigenous solid bitumen (and vitrinite in a comparison sample) also shows higher reflectance values in hydrous versus anhydrous residues, indicating that additional aromatization in the presence of exogenous hydrogen occurs both in newly formed organic matter and in organic matter that is present throughout the experiment. Despite similarities in their bulk rock geochemical screening parameters, Ro evolution shows different trajectories amongst the four Salt Range oil shales, suggesting as-yet undetermined differences in kinetic properties which are probably related to differences in a priori chemical composition. These results have implications for the use of solid bitumen reflectance (BRo) as a thermal proxy, suggesting BRo values and appearance could vary as a function of the concentration of water. Variation in water concentration may be present at the reservoir or formation scale, but may also be present at a much finer scale in tight oil shales where permeability is several orders of magnitude lower than conventional reservoirs. Therefore, local variations in the presence of water potentially could explain substantial variation in BRo values and appearance in closely spaced source rock samples and even within an individual microscope field.

Rock Physics Modeling Studies on the Elastic and Anisotropic Properties of Organic-Rich Shale

Shale gas reservoirs have a large amount of resources, a wide range of burial, and great development potential. In order to evaluate the elastic properties of the shale, elastic wave velocity and anisotropy measurements of Longmaxi shale samples were carried out in the laboratory. Combined with the results of back scattering scanning electron microscopy (SEM) and digital mineral composition tests, the relationship between the anisotropy and the mineral components of the shale samples is discussed. It is found that the clay and kerogen combination distributed with an inorganic mineral background is the main cause of anisotropy. Then, the elastic properties of the organic-rich shale are analyzed with the anisotropic differential equivalent medium model (DEM). The clay and kerogen combination is established with kerogen as the background medium and clay mineral as the additive phase. The bond transformation is used to rotate the combination so that its directional arrangement is consistent with the real sedimentary situation of the stratum. Then, the clay and kerogen combination is added to the inorganic mineral matrix, with the organic and inorganic pores added to characterize the anisotropy of the shale to the greatest extent. It is found that the error between the wave velocity results calculated from the model and measured in the laboratory is less than 10%, which means the model is reliable. Finally, the effects of the microcracks and aspect ratio, kerogen content, and maturity on the elastic and anisotropic properties of shale rocks are simulated and analyzed with this model. The degree of anisotropy increases with the decrease in the pore aspect ratio and the increase in the microcracks content. The greater the kerogen content and maturity, the greater the anisotropy of rock. This study is of great significance for predicting the “sweet spot” of shale gas and optimizing hydraulic fracturing layers.

NMR based fractal analysis in shale under different confining pressure, and its correlation to Archie's cementation exponents

This study delves into the complexity of shale pore structures through fractal dimension analysis of nuclear magnetic resonance (NMR) data under varying confining pressures. Focusing on nine illite-rich shale samples, we investigate how confining pressure influences the pore size distribution, particularly narrowing meso- and macropores. Our analysis utilizes two distinct models to calculate fractal dimensions: Model 1 categorizes pores into micro and meso + macro based on T2 cutoffs, while Model 2 considers all pore sizes collectively. Results show that fractal dimensions increase with confining pressure, indicating enhanced pore complexity. Notably, Model 2 proves more adept for shales, revealing no significant correlation with quartz or total clay content or NMR porosity. However, a robust correlation (R2 = 0.9416) between fractal dimension and Archie's cementation exponent m suggests a novel method for estimating Archie's m through pore distribution analysis without electrical resistivity evaluation. This approach offers new insights for petroleum exploration and pore structure characterization in shales, particularly within the Goldwyer Formation and similar geological settings.