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CO2 pre-injection fracturing is a promising technology for shale reservoirs development, with multiple advantages for improving the complexity of fractures, the production of crude oil, and the sequestration of CO2. Previous research mostly focused on the CO2 effect on macroscopic mechanical properties of shale. However, there are many phenomena closely related to shale micro mechanical behavior. Therefore, this study presents a systematic investigation into the effects of CO2 on both macro and micro mechanical properties, as well as pore-fracture structures during CO2 pre-injection fracturing in shale reservoirs. The results show that CO2 can significantly decrease the tensile strength, uniaxial compressive strength, and elastic modulus of shale. With the increasing CO2 treatment time, the macro mechanical properties of shale decrease gradually. The microscopic experiments show that this significant decrease may be due to two mechanisms. The first is the significant decrease in the micro-mechanical properties of shale. The results of indentation analysis show that the microscopic elastic modulus and hardness of shale decrease by 51.3% and 63.3% after CO2 treatment. The second is the changes of the original shale framework. Pore-fractures structure analysis showed that after CO2 treatment, a large number of dissolution pores are generated in the shale matrix. Meanwhile, there are propagation of original fractures and opening of structural weak planes, which lead to the form of new fractures. Under the action of these two mechanisms, the macro mechanical strength of shale is reduced significantly. Therefore, in the field application, proper soaking following CO2 injection could lead to a significant overall reduction in mechanical strength, potentially lowering formation breakdown pressure, easing the requirements for treatment equipment, and enhancing fracturing effects. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing of shale reservoirs is one of the important technologies in the oil and gas industry. To ensure the safe operation of oil and gas recovery, it is important to study the shale-fluid interactions on the geomechanical behavior of shale. This study investigated the effect of fracturing fluid treatment on the mechanical and elastic properties of the Mowry Shale formation, Wyoming, USA. Cylindrical Mowry Shale specimens with a diameter of 12.5 mm collected from the United States Geological Survey (USGS) and School of Energy Resources (SER) of the University of Wyoming were treated with brine and brine + stimulation fluid for one month each at pressures of 9 and 11.7 MPa and temperatures of 96 and 66 °C, respectively. Triaxial compression experiments were conducted on the specimens. Results showed that all Mowry Shale specimens experienced an increase in maximum volumetric strain with the increase in effective confining pressure (Pd). Regardless of aging fluids, the maximum deviatoric stress (Δσd) of most Mowry Shale specimens increases with the increase in Pd. At a lower Pd, the USGS specimen aged with brine and stimulation fluid exhibits higher maximum Δσd than those aged with brine only. However, at a higher Pd, the USGS specimen aged with brine exhibits a higher maximum Δσd. SER specimens aged with brine and stimulation fluid exhibit higher maximum Δσd values than those aged with brine for all three Pd values. Regardless of the aging fluids, most USGS specimens experience a brittle failure mode, while SER specimens aged with brine and stimulation fluid experienced a more ductile behavior. [ABSTRACT FROM AUTHOR]

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO2) injection technology is crucial for efficient shale oil development. When CO2 is dissolved in reservoir formation water, it undergoes a series of physical and chemical reactions with various rock minerals present in the reservoir. These reactions not only modify the reservoir environment but also lead to precipitation that impacts the development of the oil reservoir. In this paper, the effects of water–rock interaction on core porosity and permeability during CO2 displacement are investigated by combining static and dynamic tests. The results reveal that the injection of CO2 into the core leads to reactions between CO2 and rock minerals upon dissolution in formation water. These reactions result in the formation of new minerals and the obstruction of clastic particles, thereby reducing core permeability. However, the generation of fine fractures through carbonic acid corrosion yields an increase in core permeability. The CO2–water–rock reaction is significantly influenced by the PV number, pressure, and temperature. As the injected PV number increases, the degree of pore throat plugging gradually increases. As the pressure increases, the volume of larger pore spaces gradually decreases, resulting in an increase in the degree of pore blockage. However, when the pressure exceeds 20 MPa, the degree of carbonic acid dissolution will be enhanced, resulting in the formation of small cracks and an increase in the volume of small pores. As the temperature reaches the critical point, the degree of blockage of macropores gradually increases, and the blockage of small pores also occurs, which eventually leads to a decrease in core porosity. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an indispensable technology for the development of shale oil and shale gas. Knowing the changes in the rock mechanical properties and failure modes during hydraulic fracturing is the key to improving the efficiency of hydraulic fracturing. Based on experiments and simulations, it can be concluded that the injection of fracturing fluid in the hydraulic fracturing caused deformation of the fracture surface, and the rock mechanical properties experienced degradation with a maximum reduction in the rock mechanical properties of 44.24%. As indicated in the experiments, the displacement of the measurement point was decreased with the distance increase between the injection point and the measurement point. According to the numerical simulations, tensile failure is the main failure mode in hydraulic fracturing, but the percentage of shear failure had an obvious increase with the increase in distance between the injection point and the measurement point. Comparing DDS #1 and DDS #5, the DDS #5 measurement point was farther away from the injection point, and the average percentage of shear failure increased from 21.94 to 52.72%. Meanwhile, the increase in the branch fractures also caused shear failure to occur. Comparing Sample 1 and Sample 3, in Sample 3, which had more branch fractures, the average percentage of shear failure increased from 33.12 to 37.58%. Due to the porous medium of the reservoir rock, the enormous pressure generated during the injection of fracturing fluid caused significant deformation of the fracture surface, leading to the tensile failure of the rock. The displacement of the fracture surface caused by the fracturing fluid injection also led to the deformation of the pore throat structure; thus, the shear failure increased when the measurement point was away from the injection point. [ABSTRACT FROM AUTHOR]

Drilling fluid loss is an important factor restricting oil and gas production. The development of pores and micro-fractures in shale formations is the main cause of drilling fluid loss. In this study, silane coupling agent modified nano-SiO 2 was used as the rigid core, and N-isopropylacrylamide and 2-hydroxyethyl methacrylate were used as the flexible outer shell. The temperature-sensitive blocking agent PKSHN was synthesized by inverse microemulsion polymerization method. PKSHN was analyzed and tested through Fourier transform infrared spectroscopy, simultaneous thermal analysis, transmission electron microscopy, dynamic laser scattering and other methods. The results show that PKSHN can achieve a hydrophilic/hydrophobic transition under the response temperature, with a median particle size of 189.35 nm, which can form a hydrophobic layer on the shale surface and reduce fluid intrusion into the shale formation. This study tested the performance of three drilling fluids with different densities by adjusting the amount of weighting agent. The results showed that the high-temperature and high-pressure filter losses of the three different densities of drilling fluids were all less than 10 mL. The addition of PKSHN can effectively reduce fluid loss. The rolling recovery experiment and linear expansion experiment show that after aging for 16 h at 150 °C, the rolling recovery rate is above 90 % and the linear expansion rate is below 7 %, indicating that the addition of PKSHN can effectively control the hydration expansion of shale. [Display omitted] [ABSTRACT FROM AUTHOR]

To provide a better alternative to the current shale inhibitors, this paper designs a novel aluminum-based shale inhibitor by complexing aluminum with humic acid (HA), which is expected to enhance wellbore stability in drilling. Firstly, the alkali dissolution and acid precipitation (ADAP) method was chosen to extract HA from lignite from Shanxi and Yunnan, China. Next, the complexation conditions for aluminum-humic acid (Al-HA) were optimized through orthogonal tests, including reaction ratio, temperature, time, and pH. The best complexation conditions for Al-HA-1 were determined as pH = 5.0, HA/NaAlO 2 = 7/3, T = 75℃, time = 30 min, and those for Al-HA-2 as pH = 10.0, HA/ NaAlO 2 = 3/7, T = 65℃, and time = 30 min. Further, several tests were conducted to evaluate the inhibition performance of our inhibitors. The results show that the hot rolling recovery of shale sample in 1.2 wt% Al-HA-2 solution was up to 90.52% after hot rolling for 16 h at 120℃; the linear swelling rate of artificial bentonite core in 1.2 wt% Al-HA-2 solution was merely 20.38% after 16 h. The inhibition mechanism of Al-HA mainly consists of flocculation on shale surface and chemical reverse osmosis. Both phenomena suppress filtrate intrusion and reduce pore pressure transmission. These superior properties make the proposed inhibitors a promising choice for wellbore stabilization, especially in shale oil/gas formations. [ABSTRACT FROM AUTHOR]

A novel experimental study is conducted to reveal the effect of pore structure and salinity on spontaneous imbibition of shale samples using field emission scanning electron microscopy and low-field nuclear magnetic resonance (NMR). Core samples selected from Chang 7 shale, Ordos basin, contain different proportions of mineral components and exhibit different pore structures, as demonstrated by scanning electron microscopy. During the imbibition process, T 2 spectra are obtained for each core sample under different salinities and imbibition time periods using NMR. The results are then used to characterize and compare the water imbibition process in different shale samples, with a focus on investigating the effects of pore structure and salinity. The results show that the amount of absorption water is positively correlated with the development of microcracks and with large pores in shale samples. The shale samples are shown to develop more microcracks as the imbibition time increases and the salinity decreases. These microcracks can improve the samples' capacity of imbibition effectively, therefore increasing water absorption. Moreover, it is indicated that the imbibition capacity increases with an increasing content of illite clay minerals in the shale samples. Furthermore, the greatest amount of adsorbed water is seen when the water salinity is as high as the synthetic formation water. This is important in choosing hydraulic fracturing fluids, knowing that high-salinity fracturing fluids can effectively reduce water absorption in shale, therefore contributing to low flow-back and better fracturing performance. [ABSTRACT FROM AUTHOR]

Among the several problems encountered in drilling, wellbore instability has been regarded as the most adverse and the problem becomes more peculiar when the drilled formation is shale. Because of the predominance of clay minerals in shale there is much tendency for water absorption and swelling in clays which causes wellbore instability. Oil-based mud has good potential as a remediation for wellbore instability but its cost and environmental implication has affected the choice of its usage. In this study, three shale samples from shale formation of Niger Delta were utilized. Three mud samples were formulated: mud sample SK1 without nanoparticles (NPs), mud samples SK2 and SK3 with 6 wt% and 12 wt % of NPs addition respectively. Mud rheology, measurement of density, filtration loss, spontaneous imbibition (SI) and rate of swelling tests were conducted on the prepared mud samples. The results showed that, addition of NPs to water-based drilling muds (WBDM) did not significantly changed the mud density before and after barite addition but addition of NPs to WBDMs increased yield point and plastic viscosity, and gave better filtration control with improved mud capacity to lift extra cuttings and enormous shear stress provided for circulation in the space of the annulus.. Also addition of NPs to the WBDM decreases the amount of imbibition of shale. NPs showed great capacity to swiftly plug the pore throats and decrease rate of swelling of shale when added to WBDMs. [ABSTRACT FROM AUTHOR]

Abstract Shale oil refers to oil stored in organic-rich shale. It is an important part of unconventional oil and provides a large amount of resources. Based on the systematic study of the geological characteristics of shale oil in China's major continental basins, the geological connotation of the "sweet area (section)" in shale oil is proposed in this paper, and it refers to areas (sections) that can be preferentially explored and developed in oil-bearing shale formations under current economic and technical conditions. The formation conditions and distribution characteristics of continental shale oil in China are analyzed with a focus on the geological properties of the Triassic Yanchang Formation in the Ordos Basin, the Cretaceous Qingshankou Formation in the Songliao Basin and the Permian Lucaogou Formation of the Jimusar Sag in the Junggar Basin. It is found that the "sweet areas" of shale oil with medium-high maturation are mainly located in thick shales with a Ro greater than 0.9%, and the "sweet sections" are mainly located in the middle and lower parts of the shale formation. The geological resources of continental shale oil in the major continental basins in China are estimated to be approximately 3700 × 108 tons. The in situ conversion process (ICP) may be a key technology for the effective development of medium-to low-mature shale oil. The scale, maximum burial depth and present depth of the organic-rich shale are proposed as the three key parameters for the optimization of pilot sites by taking the Triassic Yanchang Formation in the Ordos Basin as an example. Using ICP, it is expected that the recoverable resources of China's continental shale oil will be approximately (400–500) × 108 tons. The terminology of "man-made reservoir" is proposed in this paper. In an "man-made reservoir", the overall industrial output of the "sweet areas (sections)" is formed by artificial intervention and the construction of an underground fracture network system with "man-made permeability". Continental shale oil may be another revolutionary source of unconventional oil and is expected to be first successfully produced in China. Highlights • The "sweet areas(sections)" of continental shale oil with medium-high maturation are illustrated with examples and the resources are assessed. • The formation conditions and distribution characteristics of continental shale oil in China are analyzed. • Some important concepts are proposed, including "exploring oil into source kitchen", "source rock oil", "man-made oil reservoir", etc. [ABSTRACT FROM AUTHOR]

As an abundant type of unconventional hydrocarbon resources on the earth, shale oil has been widely concerned by scholars across the world. During flowback period, flow-back resistance of fracturing fluids increases because of the existence of shale oil. Therefore, it is of practical significance to study the flow-back capability of fracturing fluid for high well performance. In this paper, fractal method of porous media has been used for calculation of relative permeability of oil-water two phase flow in shale pores. First, we built up flow equation of single nanopore with four layers: boundary layer, bulk wetting phase layer, oil-water two phase layer, and nonwetting phase layer. Furthermore, boundary slip, boundary, viscosity change in boundary layer and threshold pressure gradient is considered for correction flow rate equation. The pores of shale matrix can be simplified into capillary bundle model, and fractal theory is suitable for this model. Aperture fractal dimension and tortuosity fractal dimension is used to expand its scale to porosity media with fractal method. Then the model is verified by experimential results and classic models. Furthermore, serval main factors affecting the relative permeability of water are primarily analyzed, and the more essential factors out of the aforementioned ones are extracted and further studied. The results show that with the increase in the thickness of oil-water two phase layer, the relative permeability of water is affected more seriously; The relative permeability of water is positively correlated with slip length and thickness of boundary layer. This work provides a more convenient approach to calculate relative permeability with no experiments, and provide permeability for numerical simulation in flow back period. • A new model is developed for calculating oil-water two-phase relative permeability of shale formation during flowback period. • The effects of boundary layer thickness, oil-water two-phase layer thickness, threshold pressure gradient and slip length on relative permeability are studied. • Relative permeability can be calculated rapidly with high accuracy. [ABSTRACT FROM AUTHOR]

Abstract: This study aims to characterize the Laffan Shale Formation in Sirri oil fields from a borehole stability point of view. This paper describes the process and workflow for data-acquisition and interpretation in a shale formation characterization program and not only demonstrates the benefits of acquiring specific data, but also highlights the uses of the data to aid the exploration decision process. The next purpose of this paper is to provide a research process that can be applied in similar geological settings. In the study process, we collected a complete set of information and samples from the fields and presented a detailed case study, including laboratorial studies of formation samples and interpretation of the information. Available samples and information sources from Laffan Formation include drillhole core samples, daily drilling and geology reports and petrophysical logs of drilled wells and structural geological data of the area. Type and quantity of minerals were determined by direct and indirect methods. Bulk XRD analyses performed on core samples showed presence of traces of clay minerals. For determination of the exact clay mineral type, clay minerals were extracted and treated by heat and ethylene glycol saturation. Treated samples were subjected to XRD analyses. Interpretation of the gamma ray and natural gamma spectrometry logs allowed the determination of the type and content of clay minerals. In a next step, in order to study the distribution of minerals types and fabric of the shale samples, SEM photomicrographs were acquired. Cation exchange capacity of the samples was determined by methylene blue method and hot roll dispersion test in a water based drilling fluid was carried out to experimentally confirm the results. The caliper logs show washouts in the Laffan Formation in most wells. Pore pressure of the Laffan Formation was determined by using data obtained from both acoustic and resistivity logs. From the identification results it can be concluded that Laffan is not a swelling but a hard and brittle shale formation. The instability problem is not due to the dispersion or high pore pressure and cannot be completely solved by drilling fluid design and mechanical causes must be addressed. A noticeable point in this study is the similar results of direct and indirect methods of mineralogy determination. The practical conclusions of the study can be used in the field by engineers. [Copyright &y& Elsevier]