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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]

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]

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]

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]

Copyright of Drilling Fluid & Completion Fluid is the property of Drilling Fluid & Completion Fluid Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

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]

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]

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]

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]

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 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]

Copyright of Journal of Engineering Geology / Gongcheng Dizhi Xuebao is the property of Journal of Engineering Geology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

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]

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

As the exploration and development of domestic shale gas continue, the complex incidents we encountered during drilling are also increasingly prominent. For the shale formations which is leaky and have complex lithology in South China, MPD is necessary to learn to drill through the complicated shale interval in a fast, safe and efficient manner and to break these common technical challenges of drilling. Currently, southern Yangtze region mainly develops two sets of shale formations, Silurian Longmaxi and Cambrian Niutitang. However, there are less pure shale section, complicated lithology and serious fragmentation. According to the data of shale gas drilling, the limy, silty and siliceous shale is often met during drilling, frequently accompanied with overflow and lost circulation. For the target interval with thickly developed shale bed, the density window of drilling fluid is small and the well wall is extremely unstable. According to the lithologic development of shale bed, technical characteristics of MPD, lab analysis, current MPD supporting equipment and other relevant factors, the MPD in bottom hole constant pressure method can be used to drill through the large and complicated shale interval. [ABSTRACT FROM AUTHOR]

Wellbore instability problems are often encountered while drilling in water active shales due to changes in pore pressure. The change in pore pressure is caused by hydraulic, thermal, chemical, and electrical potential gradients. In all previous studies it has been found that the effects of ion advection and thermal convection have a negligible effect on changes in pore pressure for a range of very low permeable shale formations (> 10-5 md). This is an appropriate assumption for very low permeable shale formations. For high permeable shale formations (e.g., shale with a disseminated microfissure network), however, thermal convection and ion advection can play a significant role. The authors present a hydro-chemo-thermo-electrical model based on finite element method to investigate the effect of advection on ion transfer and thermal convection on temperature and their combined effect on pore pressure in shale formations. All equations are based on the thermodynamics of irreversible processes in a discontinuous system. The characteristic Galerkin discretization method is used to stabilize the solution of advection and convection equations in the finite element approach. Results of this study revealed that ion and heat transfer are controlled primarily by permeability of the shale formations. Movement of fluid into or out of the formation is due to a combination of hydraulic, chemical, electrical, and thermal osmotic flow. Results have also shown that in high permeable shale formations the chemical potential gradient between the pore fluid and drilling fluid reaches equilibrium faster than in low permeable shale formations. This is mainly due to the advection of ion from drilling fluid to the shale formation. [ABSTRACT FROM AUTHOR]

Change in pore pressure in chemically active rocks such as shale is caused by several mechanisms and numerous studies have been carried out to investigate these mechanisms. However, some important coupling terms or driving forces have been neglected in these studies due to simplifying assumptions. In this study, a hydro-chemo-thermo-electrical model based on finite element method is presented to investigate the change in pore pressure in shale formations resulted from thermal, hydraulic, chemical and electric potential gradients. The change in pore pressure is induced by hydraulic conduction, chemical, electrical and thermal osmotic flow. In order to solve the problem of ion transfer under the influence of an electrical field, the Nernst-Planck equation is used. In addition, ion advection is considered to investigate its possible effect on ion transfer for the range of shale permeability. All equations are derived based on the thermodynamics of irreversible processes in a discontinuous system. The numerical results are compared against existing and derived uncoupled analytical solutions and good agreement is observed. The numerical results showed that the ion transfer and pore pressure are considerably affected by the electric field in the vicinity of the wellbore. It was also found that advection can play a remarkable role in ion transfer in shale formations. It was further shown that the change in pore pressure in shale formation is characterized by the combined effect of hydraulic, chemical, thermal and electro osmotic flow. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Rate of penetration (ROP) means how fast the drilling bit is drilling through the formations. It is known that in the petroleum industry, most of the well cost is taken by the drilling operations. Therefore, it is very crucial to drill carefully and improve drilling processes. Nevertheless, it is challenging to predict the influence of every single parameter because most of the drilling parameters depend on each other and altering an individual parameter will have an impact on the rest. Due to the complexity of the drilling operations, up to the present time, there is no reliable model that can adequately estimate the ROP. Artificial intelligence (AI) might be capable of building a predictive model from a number of input parameters that correlate to the output parameter. A real field dataset, of shale formation, that contains records of both drilling parameters such as, rotation per minute (RPM), weight on bit (WOB), drilling torque (τ), standpipe pressure (SPP) and flow pump (Q) and mud properties such as, mud weight (MW), funnel and plastic viscosities (FV) (PV), solid (%) and yield point (YP) were used to predict ROP using artificial neural network (ANN). A comparison between the developed ANN-ROP model and the number of selected published ROP models were performed. A novel empirical equation of ROP using the above-mentioned parameters was derived based on ANN technique which is able to estimate ROP with excellent precision (correlation coefficient (R) of 0.996 and average absolute percentage error (AAPE) of 5.776%). The novel ANN-based correlation outperformed three published empirical models and it can be used to predict the ROP without the need for artificial intelligence software. [ABSTRACT FROM AUTHOR]

Gas permeability model of natural fracture network in shale formation is one of the emphases for shale gas development research. In this paper, we adopted fractal binary tree capillary bundle model to simulate natural fracture network in formation, and got gas spherical oriented flow function in binary tree fractal model based on Hagen-Poiseulle equation. We analyzed rectangle, triangle, oval fracture section and facture structure parameters such as fracture bifurcation angle θ, fracture fractal dimension Df, caplillary length coefficient α, rectangle fracture section width-height ratio x1, oval fracture section major axis-minor axis ratio x3 influence on fracture fractal permeability Kf. Fracture fractal permeability Kf sorts by values in descending order is circle tube model, oval section model, rectangle section model, triangle section model. Kf increases as Df increases; Kf shows a non-monotonous behavior with the increase and then decrease of θ and Kf gets the minimal value when θ equals 90°;Kf decreases as α, x3 increase;Kf increases at first then deceases as rectangle fracture section width-height ratio x1 increases and Kf gets maximum value when x1 equals to 1. [ABSTRACT FROM AUTHOR]