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Complex bedding properties and in situ stress conditions of shale formation lead to complex hydraulic fracturing morphologies. However, due to the limitations of traditional numerical methods, the simulation of hydraulic fracturing in shale formation still needs further development. Based on this, the liquid–solid interaction modes and the SPH governing equations considering liquid–solid interaction force have been introduced. The smoothing kernel function in the traditional SPH method is improved by introducing the fracture mark ξ, which can realize the simulation of rock hydraulic fracturing processes. The stress boundary of the SPH method is applied by stress mapping of "stress particles", and the feasibility and correctness of the method are verified by two numerical examples. Then, the simulation of hydraulic fracturing processes of bedding shale formations are carried out. With the increase of horizontal stress ratio, the total number of damaged particles decreases, but the initiation and extension pressure increase gradually. The initiation stress of small bedding dip angles (θ < 45°) is larger than that of big bedding dip angles (θ > 45°). The hydraulic fracture propagation range at low horizontal stress ratio is wider and the fracture is along the direction of maximum principal stress, while the hydraulic fracture propagation range at high horizontal stress ratio is limited to the perforation. The hydraulic fracture will propagate through the bedding with small dip angles. However, when the bedding dip angle is larger, the hydraulic fracture will propagate along the bedding direction. [ABSTRACT FROM AUTHOR]

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]

Abstract 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 (P d ). Regardless of aging fluids, the maximum deviatoric stress (Δσ d) of most Mowry Shale specimens increases with the increase in P d . At a lower P d , the USGS specimen aged with brine and stimulation fluid exhibits higher maximum Δσd than those aged with brine only. However, at a higher P d , 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 P d 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.

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]

Methods presently in use for evaluating the performance of many kinds of plugging agents in nanometer and micrometer levels still lack the required accuracy and effectiveness, and no commonly followed standards are available. To deal with these problems, a mesoporous membrane and a dense sand-bed are selected as the media to simulate the microfractures in shale formations, and the filtration rate and the wetted depth of the sand-bed are used as the indices for evaluating the performance of a nanometer or micrometer plugging agents. The mesoporous membrane method uses a filter membrane with pore sizes between 100 nm and 450 nm, the fitting lines of the parallel experimental data have minimal fluctuations, and this method is thus suitable for evaluating the performance of the plugging agents with particle sizes distributed between 35 nm and 450 nm. The dense sand-bed method uses 200- mesh quartz sands as the packing material, and the variance of several experimental data is 0.2131, meaning that the parallelism of the experiments is good. This method is suitable for evaluating plugging agents with particle sizes distributed between 500 nm and 24.6 μm. Using this method, three ultra-fine plugging agents with big differences in particle sizes, which are ultra-fine calcium carbonate, emulsified rubber MORLF and ULIA, were evaluated for their performance, and the MORLF with deformability, was finally selected as the most suitable nanometer plugging agent. The evaluation methods presented and the nanometer-sized plugging agents have been applied on 7 wells drilled in the Changning block. Compared with other wells drilled with conventional oil based drilling fluids, the average percent hole washout of the 7 wells is reduced by 12.74%, and average drilling time reduced by 12 d, further proving that the methods presented have good parallelism and high accuracy. [ABSTRACT FROM AUTHOR]

Complex bedding properties and in situ stress conditions of shale formation lead to complex hydraulic fracturing morphologies. However, due to the limitations of traditional numerical methods, the simulation of hydraulic fracturing in shale formation still needs further development. Based on this, the liquid–solid interaction modes and the SPH governing equations considering liquid–solid interaction force have been introduced. The smoothing kernel function in the traditional SPH method is improved by introducing the fracture mark ξ, which can realize the simulation of rock hydraulic fracturing processes. The stress boundary of the SPH method is applied by stress mapping of “stress particles”, and the feasibility and correctness of the method are verified by two numerical examples. Then, the simulation of hydraulic fracturing processes of bedding shale formations are carried out. With the increase of horizontal stress ratio, the total number of damaged particles decreases, but the initiation and extension pressure increase gradually. The initiation stress of small bedding dip angles (θ < 45°) is larger than that of big bedding dip angles (θ > 45°). The hydraulic fracture propagation range at low horizontal stress ratio is wider and the fracture is along the direction of maximum principal stress, while the hydraulic fracture propagation range at high horizontal stress ratio is limited to the perforation. The hydraulic fracture will propagate through the bedding with small dip angles. However, when the bedding dip angle is larger, the hydraulic fracture will propagate along the bedding direction.

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.

Wellbore instability is always inevitable in shale formation due to hydration, swelling, and dispersion of clay, especially when using water-based drilling fluids (WBDFs). To mitigate the wellbore instability of shale formation and avoid correlative detriments such as formation damage, various nano-silica particles (nano-SiO2) were employed to plug the nano-sized pores, inhibit water invasion into shale, and prevent shale swelling. Firstly, the influence of various nano-SiO2 on rheological and filtration properties of a set WBDF was evaluated. Then, the linear swelling test, shale recovery test, zeta potential test, imbibition test, contact angle measurement, scanning electron microscopy (SEM) observation, and computed tomography (CT) analysis were conducted to assess the characteristic of nano-SiO2. Experimental results showed that solid phase nano-SiO2 could dramatically increase the viscosity and yield point while liquid phase nano-SiO2 only caused small fluctuations on these parameters. Besides, hydrophobic nano-SiO2 displayed better filtration performance than hydrophilic nano-SiO2. On the whole, the hydrophobic nano-SiO2 dispersion, called as nano-2, showed the best performance in WBDFs. Furthermore, nano-2 exhibited better inhibition than hydrophilic nano-SiO2, KCl, and polyether amine (PA). Mechanism analysis demonstrated that nano-2 could improve the hydrophobic degree of shale surface and prevent water from contacting with the shale. Meanwhile, nano-2 plugged the pores and throats in the shale. As a consequence, water in the drilling fluid was prevented from invading the shale, and the shale was inhibited. Nano-2 could form a thin barrier in the surface of shale, and mitigate the damage degree of shale cores after perforation operation. As a result, nano-2 displayed great potential to stabilize shale and protect formation in WBDFs.

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]

This study establishes a calculation method for the critical disturbance pressure and activation angle of fractures and quantitatively simulates the influence of geological and mechanical factors on the critical disturbance pressure. Based on the established method, it predicts the risk of casing deformation in well X2. The following primary conclusions are drawn from this study. Multiple factors affect the critical disturbance pressure of fractures. The lower the critical disturbance pressure of fractures, the higher the risk of shear failure and casing deformation. The optimal orientation and strike of a dominant slip fault vary for different fault stress states. The higher the formation pore pressure, the lower the critical disturbance pressure of fractures; the greater the difference between the maximum and minimum principal stresses, the lower the critical disturbance pressure of fractures; and the smaller the friction coefficient of the fracture surface, the lower the critical disturbance pressure of fractures. The average critical disturbance pressure of the optimal dominant slip fault in well X2 is approximately 2.24 MPa, and multiple fracture activations are displayed throughout the well section, indicating a higher risk of casing deformation at the wellbore. When the critical disturbance pressure of the optimal dominant slip fault in well X2 is greater than 4.5 MPa, casing deformation will not occur. When the critical disturbance pressure of the optimal dominant slip fault in well X2 is low, and even if there is fracture activation, casing deformation might not occur at the wellbore. The case of fracture activation display but no casing deformation might be because no fractures are developed in the formation or that the orientation of the developed fractures is not within the activation angle range. [ABSTRACT FROM AUTHOR]

Wellbore instability is the primary technical problem that restricts the low-cost drilling of long-interval horizontal wells in the shale formation of the Jidong Oilfield. Based on the evaluation of the mineral composition, structure and physicochemical properties of shale, this paper investigates the mechanical behavior and instability characteristics of shale under fluid action by combining theoretical analysis, experimental evaluation and numerical simulation. Due to the existence of shale bedding and microcracks, the strength of shale deteriorates after soaking in drilling fluid. The conductivity of the weak surface of shale is much higher than that of the rock matrix. The penetration of drilling fluid into the formation along the weak surface directly reduces the strength of the structural surface of shale, which is prone to wellbore collapse. The collapse pressure of the shale formation in the Nanpu block of the Jidong oilfield was calculated. The well inclination angle, azimuth angle and drilling fluid soaking time were substituted in the deterioration model of rock mechanics parameters, and the safe drilling fluid density of the target layer was given. This work has important guiding significance for realizing wellbore stability and safe drilling of hard brittle shale in the Jidong Oilfield. [ABSTRACT FROM AUTHOR]

The shale formation contains a large amount of oil & gas resources. Therefore, the efficient and safe development of shale reservoirs is crucial, and the stability of wellbore is the primary factor related to the development of shale reservoirs. This paper studies the stability of wellbore caused by invasion of drilling fluid. By establishing the rule model of invasion of drilling fluid into wellbore, it studies the change rule of pore density equivalent of different well spacing distance. With the increase of drilling time, the pore pressure of shale water layer increases, the distance of invasion of drilling fluid into formation increases, and the invasion amount of drilling fluid increases. On this basis, the stress model of wellbore shale is established, and the variation rules of the radial stress, circumferential stress and circumferential stress of the wellbore are studied. The research shows that after considering the hydration, the radial stress, circumferential stress and axial stress first decrease with the increase of the radial distance in the hydration zone, then suddenly increase at the outer edge of the hydration zone, and finally gradually decrease with the increase of the radial distance. With the increase of drilling time, the circumferential stress and axial stress at the wellbore increase, the minimum and maximum values of radial stress, circumferential stress and circumferential stress decrease, and the corresponding radial distance increases. Couple the change rule with the change rule of radial stress, circumferential stress and circumferential stress of the wellbore, establish the collapse cycle model, and finally study the collapse condition and cycle of the wellbore, which has certain guiding significance for the optimization of wellbore stability. [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.

Horizontal drilling and multistage hydraulic fracturing applied in shale formations over the past decade. The operators are trying even closer cluster spacing to increase the initial rate, but it is at the expense of higher operation costs and complexity. This study presents an integrated workflow to investigate the effect of cluster interference on well performance. Analytical rate transient analysis (RTA) was combined with reservoir numerical simulation to calculate the effective fracture surface area (ACe) for hydrocarbon production. A proxy model was built to estimate the effective to actual stimulated fracture area ratio as a function of completion and reservoir parameters. The integrated workflow was applied to actual field data for two shale gas wells. An economic study was conducted to investigate the optimum spacing based on the well profitability. The well with a higher stage number and tighter cluster spacing had high cluster interference with a low ACe/ACa ratio. The well will drain the production area near the wellbore faster with a high initial production rate but with high production declining rate. Increasing the cluster spacing, with the same injected proppant volume, showed an increase in the ACe/ACa ratio, and a decrease in cluster interference. A lower initial rate was observed with a low production declining rate. Economic study showed optimum spacing of 60 ft based on the formation properties, capital cost, and gas price. As the interest rate, gas prices, and increases or low capital costs, the optimum completion tends to be with the tighter spacing to accelerate the production. [ABSTRACT FROM AUTHOR]

Wellbore instability in shale formations has always been a concern in oil exploration field. According to the Mohr–Coulomb criterion, a new model for evaluating and classifying the collapse of horizontal wellbore in shale formation is established. In this model, the temperature field and the pore pressure field affected by hydraulic pressure, thermal potential, and chemical potential difference between the drilling fluid and formation fluid are considered. Using the model, the influences of the temperature and solute concentration of drilling fluid on the failure degree of horizontal wellbore in shale formation with weak planes are simulated and analyzed. Based on the research results, weak planes that exist in shale formation will cause a significant wellbore collapse and using cool drilling fluid with high solute concentration can reduce the collapse degree of horizontal wellbore. The model established may help drilling engineers in practice to take effective measures for reducing wellbore instability and avoiding possible wellbore collapse during drilling in shale formations. [ABSTRACT FROM AUTHOR]

In this study, super-amphiphobic nano-silica nanoparticles (SA-NPs) were used to enhance the shale stabilization performance of water-based drilling fluids (WBDFs) by altering the surface wettability, preventing the capillary self-priming effect, and plugging the nano-micro pores of shale. The results of transmission electron microscopy, particle size distribution, and scanning electron microscopy characterization revealed that SA-NPs exhibited a nanoscale “coalesce” structure, which is composed of spherical particles joined together, and could form a nano-papillary structure on the shale surface. Due to the presence of nano-micro scale rough structures and ultra-low surface energy components, the shale treated by SA-NPS exhibited super-amphiphobic surface property in the contact angle test. Contact angles of water and hexadecane on the shale surface reached up to 154.13° and 151.34° after being treated with SA-NPs, respectively. Furthermore, the addition of 1% SA-NPs in WBDFs could reduce the linear swelling rate from 40.5 to 6.0%, increase the shale cuttings recovery percentages from 82.5 to 95.6%, increase the plugging rate of low permeability shale core from 81.25 to 94.00%, and raise the high-temperature and high-pressure uniaxial compressive strength from 3.45 to 4.87 MPa. Compared with the polyether amine and fumed nano-silica, the addition of SA-NPs produced the best performance. Based on the excellent shale stabilization performance of SA-NPs, a high-performance WBDF was developed and applied in Dagang Oilfield. During the drilling operation， no wellbore instability, sticking, and other complex situations occurred. The results indicate that SA-NPs could better address the issue of wellbore instability in shale formations and have a great application prospect in shale well drilling.

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/NaAlO2 = 7/3, T = 75℃, time = 30 min, and those for Al-HA-2 as pH = 10.0, HA/ NaAlO2 = 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.

A variety of methods are examined in this study in order to improve oil recovery from low-permeability heterogeneous reservoirs in oil-saturated shale deposits. Calculations based on the fluid flow model revealed that water and gas injection was effective, and that horizontal and directional wells, including those employing hydraulic fracturing are evaluated in this study. Moreover, hydraulic fracturing in directional wells with vertical completions was found to be one of the most effective methods for water injection in this study. However, when hydraulic fracture length is hard to achieve, the gas injection has been found to be a more efficient way to enhance oil recovery than water injection. Furthermore, horizontal drilling technology was most effective in the central part of the reservoir. [ABSTRACT FROM AUTHOR]

Abstract Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical’s efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock.

In view of the extremely developed bedding of shale formations, which are dominated by micro-nano pores and fractures, traditional sealing agents make it difficult to produce a tight seal on shale formations due to their huge particle sizes. Combining the bridging effect of inorganic nanoparticles and the deformation properties of organic particles, this article synthesized a core-shell structure nano-blocking agent through emulsion polymerization, which was called P(MMA-St-BD)/KH570-SiO2. The structure of the synthesized nano-plugging agent was characterized utilizing Fourier transform infrared spectroscopy (FT-IR), particle size distribution, thermogravimetric analysis (TGA), and transmission electron microscopy (TEM). Performance characterization was carried out through the effect of nano-blocking agents on emulsion stability, rheological properties, microporous filter membrane plugging experiments, and core pressure-bearing capacity tests. The findings demonstrate that P(MMA-St-BD)/KH570-SiO2’s structure satisfies design specifications, and that the nano-plugging agent has outstanding thermal stability, homogeneous particle size distribution, and good dispersion. Its decomposition temperature also exceeds 400 °C. This study analyzed the plugging efficiency of nano-blocking agents from the temperature perspective, indicating that the nano-blocking agents seal shale formations tightly. Ultimately, through mechanism analysis, nanomaterials can squeeze and deform through the polymer shell and enter the shale micropores and micro-cracks for sealing, forming a high-strength sealing zone. [ABSTRACT FROM AUTHOR]

Wellbore instability is the primary technical problem that restricts the low-cost drilling of long-interval horizontal wells in the shale formation of the Jidong Oilfield. Based on the evaluation of the mineral composition, structure and physicochemical properties of shale, this paper investigates the mechanical behavior and instability characteristics of shale under fluid action by combining theoretical analysis, experimental evaluation and numerical simulation. Due to the existence of shale bedding and microcracks, the strength of shale deteriorates after soaking in drilling fluid. The conductivity of the weak surface of shale is much higher than that of the rock matrix. The penetration of drilling fluid into the formation along the weak surface directly reduces the strength of the structural surface of shale, which is prone to wellbore collapse. The collapse pressure of the shale formation in the Nanpu block of the Jidong oilfield was calculated. The well inclination angle, azimuth angle and drilling fluid soaking time were substituted in the deterioration model of rock mechanics parameters, and the safe drilling fluid density of the target layer was given. This work has important guiding significance for realizing wellbore stability and safe drilling of hard brittle shale in the Jidong Oilfield.

Based on the comprehensive analysis of wellbore characteristics in a deep shale gas field, the in-situ stress state of the shale reservoir was assessed in this study for the Longmaxi formation in the Dingshan area, Southwestern China. The data obtained from hydraulic fracturing, drilling-induced fractures, and in-situ core testing were used to determine the magnitude and direction of the maximum principal horizontal stress in five wells. Besides, hydraulic fracturing and cross-multipole array acoustic logging (XMAC) were employed to determine the vertical variation of the in-situ stress. Based on the logging interpretation and mechanical test results, the spatial distribution of rock mechanical parameters in the Dingshan area was assessed by the amplitude variation versus offset (AVO) seismic inversion. A 3D heterogeneous mechanical inversion model was realized via the ANSYS and CATIA3D finite element software packages, providing the area in-situ stress field simulation. The depth, fault strike, and position change effects on the main stress, horizontal stress difference, and horizontal stress difference coefficient were numerically simulated. The results show that the maximum principal stress azimuth was mainly concentrated in the NE20°-NE80° sector. Moreover, the development zone of natural fractures was related to the area with the highest principal stress differences. The maximum principal stress variation in the study area was mainly in the compressive range from −135 to −45 MPa, gradually increasing from east to west and south to north. The stress type mainly depended on the depth, fault strike, and rock mechanical parameters, while the stress difference and stress difference coefficient near the fault structure were relatively small. This study’s findings are considered instrumental in improving the borehole stability, determining the casing setting point, and optimizing the well location in deep shale reservoirs with similar geological conditions.

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]

In the process of drilling in shale formation, borehole wall instability occurs frequently, and most of the existing borehole wall stability analyses only consider the stress action, ignoring the influence of heat, flow and solid multi-field coupling action on the yield and failure of the rock around the well. In this paper, the wellbore stability analysis model of heat-fluid-solid multi-field coupling is established, and a series of studies are carried out on the distribution of stress, temperature and pore pressure near the well zone and the instability model of the rock around the well, so as to explore the mechanism of shale wellbore instability. It is found that the pore pressure near the well zone increases sharply in the direction of the minimum principal stress due to the stress concentration effect, while the temperature distribution is not affected by the stress, evenly distributed around the well and expands at a faster rate. In addition, under the action of heat-fluid-solid coupling, the effective radial stress around the well decreases sharply near the well zone and turns into tensile stress, leading to cracks, spalling and dropping of the borehole wall, which leads to complicated drilling conditions and even accidents. The results reinterpret the mechanism of borehole wall instability in shale formation and are of certain value to the efficient exploration and development of shale oil and gas resources. [ABSTRACT FROM AUTHOR]

Storing CO 2 in shale formations is an essential complement to the resources of geological CO 2 sequestration and the achievement of carbon neutrality. However, previous estimations have reported significant discrepancies in estimating CO 2 storage resources. To rationalize and address the broad range of these resource estimates, we introduce a categorization framework inspired by the SRMS (CO 2 Storage Resources Management System). Thus, we reclassify estimates according to the categories of prospective storage resources, contingen t storage resources, and capacity estimates for CO 2 storage in shales, in rank order considering the decreasing challenge associated with their attainment (such as energy/pressure requirements and time-consumed in injection). Classical volumetric and production-based methods are employed for assessing prospective and contingent storage resources, respectively. The capacity is estimated by analyzing the historical records of hydraulic fracturing, focusing on the dominant role of fractures in the storage process. A significant disparity (two to three orders of magnitude) is revealed between capacity and contingent or prospective storage resources, which aligns with known challenges encountered during field injections. This disparity highlights the importance of further efforts and advanced techniques to secure CO 2 injection in fields and recalibrate the geological CO 2 inventories to achieve carbon neutrality. • CO 2 storage in shales is reclassified into prospective , contingent and capacity. • Volumetric and production-based methods are used for prospective and contingent. • Capacity is estimated by analyzing fracturing records using a data-driven method. • Contingent or prospective far exceed capacity by two to three orders of magnitude. • Notable disparity is revealed between theoretical capacity and practical limits. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical's efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock. [ABSTRACT FROM AUTHOR]

Shale gas, which predominantly consists of methane, is an important unconventional energy resource that has had a potential game‐changing effect on natural gas supplies worldwide in recent years. Shale is comprised of two distinct components: organic material and clay minerals, the former providing storage for hydrocarbons and the latter minimizing hydrocarbon transport. The injection of carbon dioxide in the exchange of methane within shale formations improves the shale gas recovery, and simultaneously sequesters carbon dioxide to reduce greenhouse gas emissions. Understanding the properties of fluids such as methane and methane/carbon dioxide mixtures in narrow pores found within shale formations is critical for identifying ways to deploy shale gas technology with reduced environmental impact. In this work, we apply molecular‐level simulations to explore adsorption and diffusion behavior of methane, as a proxy of shale gas, and methane/carbon dioxide mixtures in realistic models of organic materials. We first use molecular dynamics simulations to generate the porous structures of mature and overmature type‐II organic matter with both micro‐ and mesoporosity, and systematically characterize the resulting dual‐porosity organic‐matter structures. We then employ the grand canonical Monte Carlo technique to study the adsorption of methane and the competing adsorption of methane/carbon dioxide mixtures in the organic‐matter porous structures. We complement the adsorption studies by simulating the diffusion of adsorbed methane, and adsorbed methane/carbon dioxide mixtures in the organic‐matter structures using molecular dynamics. [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]

The objective of this work was to develop nanomaterial inhibitor with long squeeze life for oil and gas production. Different surfactants, such as trisodium citrate (Na3Cit), cetyltrimethyl ammonium bromide, benzethonium chloride (Hyamine), and bipyridinium dibromide (Gemini), were added to synthesize nanoparticle Ca-DTPMP inhibitor at pH 9.0. The inhibitors were characterized by scanning electron microscope and dynamic light scattering. All these surfactants significantly decreased the particle size, but Gemini was the most effective one to control the calcium phosphonate salt particle size to be about 500 nm. Long-term squeeze experiments (∼3000 PV) saturated with calcite at 70°C and 75 psi back pressure through a glass column packed with Fayetteville shale rock show that the return DTPMP concentration was as high as 3 ppm for the Gemini–Ca-DTPMP colloidal inhibitor. This is an unprecedented improvement in comparison with the squeeze return of DTPMP only inhibitor where the inhibitor return concentration dropped to below 1 ppm within 400 pore volumes. The Ca-DTPMP speciation, potential field application, and the SqueezeSoftPitzer model prediction are also discussed.

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]

Hydraulic fracturing (fracking) operations, associated with horizontal drilling for oil/gas production, are known to induce earthquakes from fluid injection in disposal wells. In recent years, numerous studies have shown a close relationship between induced seismic activities and the high-pressure injection of wastewater, especially in Texas, Kansas, and Oklahoma. Detailed analysis of 17 major fracking locations across the USA has been carried out to study the impact of horizontal wells and the corresponding injected wastewater on earthquake activities. Earthquake data for the period 1998–2018 obtained from the USGS earthquake catalog shows an increase in frequency of earthquakes within a radius of 150 km at fracking locations, prominently in south-central USA. The stimulation of earthquakes depends on the amount of injected water in both horizontal and disposal injected wells, and the geology, hydrological, and geophysical settings nearby the drilling site. The observed seismicity increases with the number of horizontal wells in Texas (correlation R2 = 0.726) and Oklahoma (correlation R2 = 0.636) at the fracking locations. [ABSTRACT FROM AUTHOR]

This case study is about a landslide that occurred after 4 days of heavy rainfall, in the morning of June 29, 2012, in Cengong County, Guizhou Province of China, geographical coordinated 108°20′-109°03′E, 27°09′-27°32′N, with an estimated volume of 3.3×106 m3. To fully investigate the landslide process and formation mechanism, detailed geotechnical and geophysical investigations were performed including borehole drilling, sampling, and laboratory tests coupled with monitoring of displacement. Also, a combined seepage-slope stability modeling was performed to study the behavior of the landslide. After the heavy rainfall event, the sliding process started in this area. The landslide development can be divided into different parts. The man-made fill area, spatially distributed in the south side of the landslide area with low elevations, slid first along the interface between the slope debris and the strongly weathered bedrock roughly in the EW direction. Consequently, due to severe lateral shear disturbance, the slope in the main sliding zone slid next towards the SW direction, along the sliding surface developed within the strongly weathered calcareous shale formation located at a depth of 25-35 m. This means it was a rainfall triggered deep-seated landslide. Finally, retrogressive failure of a number of upstream blocks occurred, which moved in more than one direction. The initial failure of the man-made fill area was the 'engine' of the whole instability framework. This artificial material with low permeability, piled up in the accumulation area of surface and sub-surface and destroyed the drainage capacity of the groundwater. The numerical modeling results agreed with the analysis results obtained from the laboratory and field investigations. A conceptual model is given to illustrate the formation mechanism and development process of the landslide. [ABSTRACT FROM AUTHOR]

The shale formation in the Changning area is prone to complex engineering problems such as collapse of the wellbore, falling off the block and leakage during the drilling process. The reason is that the drilling fluid cannot effectively block the micro-cracks in the formation, and it is impossible to effectively suppress the internal hydration of the shale. In this paper, from the direction of improving the plugging and inhibition ability of the drilling fluid system, the strong plugging capacity plugging agent HXSZ-1 was added to the system to improve the plugging capacity of the system. Through the synergistic action of KCl, polyamine inhibitor and silicate, the inhibition performance of the system could be further improved. The indoor evaluation showed that the system had excellent plugging ability. The reduction rate of mud cake permeability at room temperature was 68.24%, and the HTHP static filtration loss was 2.7 mL, which was equivalent to the plugging performance of oil-based drilling fluid. The secondary recovery rate of shale was as high as 96.89% with the linear expansion rate of less than 4.8%, and the anti-pollution ability was strong. The EC50 value of the system was 11500 mg/L, which was non-toxic and could meet environmental protection requirements. The field application results showed that the system had stable performance during the drilling process. The average enlargement rate of well diameter was controlled within 4%, and the drilling cycle was shortened by 20%. The purpose of excellent and fast drilling was realized, and the field application effect was good. [ABSTRACT FROM AUTHOR]

The Sidoarjo mudflow in East Java, Indonesia, has been erupting since May 29th, 2006. The eruption has been known as the Lusi (lumpur Sidoarjo), which was previously considered as a remote seismic event consequence, but current geyser-like activities show an association with a geothermal phenomenon. A method of characterizing rare earth elements (REE) is commonly an effective tool for recognizing a geothermal system, and here it is adapted to particularly indicate the environmental origin of the Lusi mud. Results show that the Lusi hot mud is made of a porous smectite structure of a shale rock type, which becomes an ideal tank for trapping the REE, especially the light REE. Volcanic activities seem to be an important influence in the eruption; however, since there is a lack of significant isotopic evidences in the mobilization of the REE during the eruption, the chloride neutral pH water of the Lusi may hardly contain the REE. The moderate Ce and Eu anomalies found in the REE patterns of the mud strongly indicate a sea-floor basin as the most probable environment for the REE fractionation during the sedimentary rock formation, in which the weathering processes of volcanic rock origin enriched the Lusi shale with the REE.

In this study, we propose a novel workflow to predict the production of existing and new multi-wells. To perform reliable production forecasting on heterogeneous shale formations, the features of these formations must be analyzed by classifying the formations into various groups; the groups have different production characteristics depending on the key factors that affect the shale formation. In addition, the limited data obtained from nearby existing multi-wells should be used to estimate the production of new wells. The key factors that affect shale formation were derived from the correlation and principal component analysis of available production-related attributes. The production of existing wells was estimated by classifying them into groups based on their production characteristics. These classified groups also identified the relationship between hydraulic fracturing design factors and productivity. To estimate the production of new wells (blind wells), we generated groups with different production characteristics and leveraged their features to estimate the production. Probabilistic values of the group features were entered into the input layer of the artificial neural network model to consider the variation in the production of shale formations. All the estimated productions exhibited less error than the previous analytical results, suggesting the utilization potential of the proposed workflow.

Accounting for the morphology of shale formations, which represent highly heterogeneous porous media, is a difficult problem. Although two- or three-dimensional images of such formations may be obtained and analyzed, they either do not capture the nanoscale features of the porous media, or they are too small to be an accurate representative of the media, or both. Increasing the resolution of such images is also costly. While high-resolution images may be used to train a deep-learning network in order to increase the quality of low-resolution images, an important obstacle is the lack of a large number of images for the training, as the accuracy of the network's predictions depends on the extent of the training data. Generating a large number of high-resolution images by experimental means is, however, very time consuming and costly, hence limiting the application of deep-learning algorithms to such an important class of problems. To address the issue we propose a novel hybrid algorithm by which a stochastic reconstruction method is used to generate a large number of plausible images of a shale formation, using very few input images at very low cost, and then train a deep-learning convolutional network by the stochastic realizations. We refer to the method as hybrid stochastic deep-learning (HSDL) algorithm. The results indicate promising improvement in the quality of the images, the accuracy of which is confirmed by visual, as well as quantitative comparison between several of their statistical properties. The results are also compared with those obtained by the regular deep learning algorithm without using an enriched and large dataset for training, as well as with those generated by bicubic interpolation. [ABSTRACT FROM AUTHOR]

The Ordos Basin is the largest oil and gas producing basin in China, where tight oil, shale gas, oil shale, and other unconventional oil and gas resources have been found in the Chang7 subsection of the Triassic Yanchang Formation. However, the mechanism of formation and the distribution of unconventional oil and gas resources in the shale layers have not been systematically investigated until now. According to the type of unconventional oil and gas resources, main controlling factors, and the maturity, depth and abundance of organic matters, the shale oil and gas resources from Chang7 region are divided into five zones that include an outcrop-shallow oil shale zone, a middle-matured and medium-burial shale oil zone, a medium-matured and medium-burial in situ conversion process (ICP) shale oil zone, a high-maturity and deep-burial shale gas zone, and an adjacent-interbedded tight sandstone oil zone. By the distribution of resources, orderly evolution of oil and gas resources and coexistences in lacustrine shale formations have been put forward, and also a strategy of integrated exploration and development of resources in the shale formations is proposed. Overall, the outcome of this study may guide on the effective utilization of unconventional oil and gas resources in other shale formations. [ABSTRACT FROM AUTHOR]

Nowadays, the widespread application of formate fluids in petroleum industries due to its feasibility and its high potential to have more compatibility with the several formation characteristics would become a revolution to control the drilling inefficiencies and provide lower drilling expenditures. Formate fluids have the ability to maintain the property of drilling fluid on the high temperatures and high pressures, reduce the resistance of hydraulic flow, and decrease the rate of corrosion rate for the contact of drilling pipe with drilling fluid. The objective of this comprehensive study is to investigate the visual laboratory measurements of rheological characteristics, consider the profound impact of different types of pollutants on the rheological property, pore pressure transmission (henceforth; PPT) tests to measure formation pressure, and analyze the different concentration of salts for each drilling fluid. The drilling fluids are utilized in this study are silicate muds, glycol muds, sodium and potassium formate muds, and base muds. Consequently, regarding the results of this investigation, it is clarified that NaoH has performed the least impact on the rheological properties of formate fluids and sodium/potassium formate fluids has the minimum formation pressure (PPT tests) which leads to be operated as the best choice in drilling operations. Moreover, the more concentration of salts in the drilling fluid would be a weakening point which indicated that formate fluids would not be appropriate in higher salts concentration. [ABSTRACT FROM AUTHOR]

An experimental study was conducted to investigate the effect of fracturing fluid/shale rock interaction on the rock physical and mechanical properties, the proppant embedment depth, and the fracture conductivity. The rich organic shale samples obtained from the Longmaxi (LMX) and Wufeng (WF) shale gas reservoirs, both located in Southern Sichuan Basin in China, were used for the experiments. The degree of proppant embedment upon rock/fluid interaction and resultant conductivity loss was directly measured in both types of rocks. Results show that the degree of alteration of the rock mechanical properties upon rock/fluid interaction depends on the mineral composition and the cementation of the shale matrix. The rock matrix cemented by clay minerals (e.g., LMX shale) was softer and more susceptible to alteration upon the rock/fluid interaction than that of the rock matrix cemented mostly by calcareous materials (e.g., WF shale). The conductivity tests carried out under 60 MPa closure stress have shown that the proppant embedment caused 47.55% reduction in the fracture conductivity of LMX shale samples with 34% clay content. While the fracture conductivity reduction due to proppant embedment was 25.94% in WF shale samples with 7% clay content. Based on the experimental results, it was concluded that upon rock/fluid interaction more significant reduction is expected in the rock physical and mechanical properties of the shale rocks with richer clay contents resulting greater proppant embedment depth and the higher fracture conductivity loss. [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]

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• Calcite precipitation occurred after hydrogen treatment due to the presence of organic contents. • Minor alteration in pore spaces is observed after hydrogen treatment. • The reactivity of calcite-rich shales to hydrogen is minor, which is favorable for UHS. • The integrity of shale-caprocks containing calcite is not affected by hydrogen injection. • Neither considerable H 2 loss nor CH 4 or CO 2 generation occurred during the experiments. Underground Hydrogen Storage (UHS) is an effective technique that provides safe storage and recovery of the stored hydrogen for long-term energy storage. Shale caprocks are regarded as effective seals of the stored gas, however, one of the key challenges is the in-situ geochemical shale/hydrogen reactions that can impact the seal integrity during injection/production of hydrogen. To address this issue, this work investigates the geochemical reactions between hydrogen and shales, and evaluates the possible alterations in shales' petro-physical properties. Calcite-rich shale samples are collected from EagleFord (EFS) and Wolfcamp (WCS) shale formations and exposed to pure hydrogen for 108 days under 9.65 MPa at 348 K. Analytical methods including X-ray diffraction, X-ray fluorescence and Scanning Electron Microscope analysis are performed. The results indicate calcite precipitation after hydrogen treatment in both samples due to the presence of organic contents. Sulfate and pyrite reduction reactions with hydrogen are not observed as hydrogen did not all react with sulfate minerals. Consequently, minor changes in the surface pore structure and pore spaces are observed after the treatment, confirming the low reactivity of calcite-rich shale rocks with hydrogen. Gas chromatography analysis shows neither considerable hydrogen loss nor the generation of other gases such as CH 4 or CO 2 occurred during the experiments. The obtained results suggest that the integrity of shale-caprocks are expected to remain strong during the injection and production of hydrogen, which is favorable for UHS. This work can be a suitable experimental framework to assist in evaluating the hydrogen reactivity to different types of shales with various mineralogy, and assessing the suitability of shale rock for UHS. [ABSTRACT FROM AUTHOR]

Relevance Development of shale-oil as a potential crude hydrocarbon source is the most pressing issue for production depression areas with well-developed infrastructure. This regards West Siberian petroleum province, where «shale oil» is associated with Bazhenov suite bituminous shale, indicating proven commercial productivity within several areas. The aim of the research is to estimate the role of planetary fracturing in Bazhenov suite bituminous shale deposits for enhancing shale-oil development efficiency and to identify auto-generation conditions of planetary fracturing based on Bazhenov suite sampling results. Research target: Jurassic-Cretaceous bituminous shale in Bazhenov suite, southeast West Siberian Plate. Research methodology is based on the following correlation: abstract theorem of planetary fracturing to both surveys of fractured Bazhenov suite deposits, sampling results from Glukhovsky well № 2 and fundamental features of shale formation Bakken end Barnet development in North America. Results. The analysis performed, being based on published sources and core data, indicated a significant development of vertical rupture within Bazhenov suite formation section. The geological age correlation between the identified fracture systems and global rotation stress field traces within Eurasia territories was revealed. Identical oil inflow dynamics was determined on the basis of Bazhenov suite sampling data via both powder generator of pressure in Glukhovsky area and shale formation hydrofracturing in USA 42-24A well within Bakken formation (North America).

Abstract: In order to effectively solve shale instability problems in the drilling process, the remarkable capillary effect of shale formations cannot be ignored. In this paper, we report the development and characterization of a nano‐polymer emulsion (SDPE) as a shale self‐imbibition control agent in water‐based drilling fluids. Spontaneous imbibition experiments, surface tension measurements, contact angle measurements, particle size distribution analysis, linear swelling tests, and hot‐rolling cuttings dispersion tests were conducted to evaluate the comprehensive performance of SDPE. The results show that the water absorption of shale samples in SDPE emulsions is significantly less than in deionized water. At a concentration of 2.0%, the absorption mass decreased from 7.51 to 2.59%. Reducing the surface tension of the testing fluids, increasing the contact angle of the shale samples, and maintaining the nanoscale size were the important considerations for SDPE to greatly decrease the capillary effect. The low swelling rate and high recovery rate indicate that SDPE also exhibits strong shale hydration inhibition performance. Compared with water‐based drilling fluids without SDPE, drilling fluids with SDPE present higher yield point/plastic viscosity values, and also decrease the filtration loss. Based on our findings, SDPE has the potential to be a good shale self‐imbibition control agent and to help mitigate the shale instability problems. [ABSTRACT FROM AUTHOR]

Due to its complex structure, production form a shale-gas formation requires more drillings than those for the traditional reservoirs. Modeling of such reservoirs and making predictions for their production also require highly extensive datasets. Both are very costly. In-situ measurements, such as well-logging, are one of most indispensable tools for providing considerable amount of information and data for such unconventional reservoirs. Production from shale reservoirs involves the so-called fracking, i.e. injection of water and chemicals into the formation in order to open up flow paths for the hydrocarbons. The measurements and any other types of data are utilized for making critical decisions regarding development of a potential shale reservoir, as it requires hundreds of millions of dollar initial investment. The questions that must be addressed include, does the region under study can be used economically for producing hydrocarbons? If the response to the first question is affirmative, then, where are the best places to carry out hydro-fracking? Through the answers to such questions one identifies the sweet spots of shale reservoirs, which are the regions that contain high total organic carbon (TOC) and brittle rocks that can be fractured. In this paper, two methods from data mining and machine learning techniques are used to aid identifying such regions. The first method is based on a stepwise algorithm that determines the best combination of the variables (well-log data) to predict the target parameters. However, in order to incorporate more training, and efficiently use the available datasets, a hybrid machine-learning algorithm is also presented that models more accurately the complex spatial correlations between the input and target parameters. Then, statistical comparisons between the estimated variables and the available data are made, which indicate very good agreement between the two. The proposed model can be used effectively to estimate the probability of targeting the sweet spots. In the light of an automatic input and parameter selection, the algorithm does not require any further adjustment and can continuously evaluate the target parameters, as more data become available. Furthermore, the method is able to optimally identify the necessary logs that must be run, which significantly reduces data acquisition operations. [ABSTRACT FROM AUTHOR]