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Abstract Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N 2 GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 μm to 1 μm in radius, followed by pores ranging from 1 μm to 10 μm. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area. Highlights • Study on the characteristics of microscopic pore structure with different methods. • Imbibition test and NMR technology are used to investigate the fluid distribution. • The effects of different factors on imbibition recovery are statistically analyzed. • Grey relational analysis is applied to sequence the imbibition influence factors. • Imbibition recovery is the most affected by average pore radius. [ABSTRACT FROM AUTHOR]

Tight gas is a major gas resource which accounts for 14% of the total gas resources and 29% of unconventional gas in the world. The natural production of tight reservoir is very low, and multi-stage fracturing technology is widely used in horizontal wells. Multi-stage hydraulic fracturing for stimulating tight gas reservoirs requires a significant amount of fracturing fluid, which is usually water-based. Water blocking is considered as a potential type of damage in tight gas reservoirs. There are many factors affecting the production decline caused by the water blocking in fractures. However, the water blocking and fluid segregation in fractures are ignored. This study investigates the characteristics of water blocking in fractures and the effects of wettability, fracture fluid viscosity and fracture fluid filtration on water blocking and gas production. Numerical simulation is used to show that three stages can be used to describe the change of water saturation at the top and bottom of fractures, where the second stage indicates water blocking in hydraulic fractures. The results demonstrate that the stronger the interfacial tension, the more obvious the water wettability is, and the more water traps in the reservoir matrix. Decreasing interfacial tension improves the load recovery, and reduces the formation damage, and further enhances the gas production. A higher fracturing fluid viscosity causes more water traps at the bottom of fractures and intensifies the formation damage on tight gas wells. Results indicate that the fracturing fluid filtration has a great impact on the flowback performance and later gas production. Results suggest that increasing the filter cake thickness decreases the gas production peak value, and delays the time showing the peak of gas production, and further reduces the cumulative gas production. [ABSTRACT FROM AUTHOR]

Horizontal well drilling and hydraulic fracturing technologies play an essential role in improving gas recovery from shale reservoirs. However, they are expensive technologies and resource intensive production strategies. Optimization design of horizontal well spacing and fracture stage placement helps in striking a balance between gas production and economic benefits. However, previous researches relied mainly on numerical simulation technique which is computationally expensive and time-consuming. To reduce the computational burden, a novel multi-fidelity support vector regression (MFSVR) surrogate model assisted horizontal well spacing and fracture stage placement integrated optimization method, namely WSF-MFSVR, is proposed in this study. In the WSF-MFSVR method, both low-fidelity (LF) and high-fidelity (HF) numerical simulation models were applied to establish the multi-fidelity (MF) surrogate model so as to lessen the computational burden and guarantee its quality. In order to enhance the evaluation accuracy, the particle swarm optimization (PSO) algorithm was adopted to find the optimal hyper-parameters of the MFSVR model. Two cases with different wells and fracture types based on the shale gas reservoir with Barnett shale properties were employed to verify the WSF-MFSVR method. The results indicated that a combination of 300 H F and 3500 LF samples was the most suitable for establishing the MFSVR model to approximate the numerical simulation model. In terms of computational efficiency, the WSF-MFSVR method was about 50 times faster than the HF numerical simulation model-based method. Furthermore, the relative hyper-area difference (RHD) and overall spread (OS) of the WSF-MFSVR method were similar to that of the HF numerical simulation model-based method. However, the RHD and OS of the WSF-MFSVR method were superior to that of the LF numerical simulation model-based and single-fidelity support vector regression model-assisted methods. The data of these indexes quantitatively showed the superior convergence and diversity of the final optimal solutions obtained by WSF-MFSVR method. • A novel integrated optimization design method for shale gas is established. • The multi-fidelity support vector regression is proposed to assist well spacing and fracture optimization. • This method provides a fast optimization approach for shale gas well space and fracture scheme. [ABSTRACT FROM AUTHOR]

Micro-pore structural characteristics are complex in tight gas reservoirs, and it affects the fluid flow. Hydraulic fracturing is the key technique for economic gas production from tight reservoirs. In the fracturing process, fracturing fluid imbibes into reservoir matrix driven by capillary force and affects the dynamic distribution of reservoir fluid. It is thus of great interests to investigate the micro-pore structural characteristics, and its relationship with the dynamic distribution of fluid. In this study, cores from the Yanchang tight sandstone reservoirs in the Ordos basin were selected to evaluate the micro-pore structural characteristics and dynamic distribution of fluid. High-pressure mercury injection (HPMI), constant-rate mercury injection (CRMI), and low-pressure nitrogen gas adsorption (LP-N 2 GA) are used to evaluate the structural characteristics of micro-pores. The results show that average pore radius of samples ranges from 131.25 μm to 191.10 μm, with an average value of 170.42 μm, and the average throat radius ranges from 1.15 μm to 4.07 μm, with an average value of 2.489 μm. The pores are mainly closed small pores, and some H3-type crack-type pores are present. Imbibition, centrifugation experiment and nuclear magnetic resonance (NMR) techniques were used to study the dynamic distribution of fluid. The results show that imbibition recovery ranges from 40.04% to 87.29%, with an average of 62.14%, and movable fluid saturation ranges from 48.20% to 94.74%, with an average of 76.61%. The fluid during imbibition and the movable fluid during saturation were primarily distributed in mesopores and macropores. Results of statistical analysis suggests that the pore-throat structure is among the key factors impacting the imbibition recovery and movable fluid saturation. • HPMI, CRMI, LP-N 2 GA and NMR are used as experiment methods. • Micro pore structure and fluid distribution are combined to study. • Influence factors on imbibition recovery and movable fluid saturation are analyzed. • Pore-throat structure is primarily factor which affects imbibition and drainage. • Fluid saturation and imbibition recovery can affect the gas well production. [ABSTRACT FROM AUTHOR]

The filtration property of fracturing fluid and fracture conductivity are among the key parameters for stimulation in coalbed methane (CBM) reservoirs, and ultimately play important roles in the production of CBM wells. This study evaluates the overall filtration property of fracturing fluid in high-rank coal reservoirs, and proposes a model considering the stress-sensitivity effects to estimate the overall filtration coefficient. This study also investigates the effects of effective stress, porosity, permeability, viscosity of fracturing fluid, and reservoir pressure on the overall filtration coefficient of fracturing fluid. The results show that, with the increases of effective stress and fracturing fluid viscosity, the overall filtration coefficient of fracturing fluid in CBM reservoirs shows a monotonous downward trend; with the increase of the porosity/permeability and reservoir pressure, the overall filtration coefficient of fracturing fluid increases. Based on the Carman-Kozeny formula, this study established a model to estimate facture conductivity under different conditions. During the hydraulic fracturing of CBM reservoirs, comparative analysis suggests that increasing proppant size and number of paved layers increases fracture conductivity. The flow conductivity of fractures filled with multiple-layer proppants is significantly larger than that of fractures with single-layer proppants; with the increasing closure pressure, fracture conductivity decreases, and fracture width reduces due to the embedding of the proppant, and thereby the fracture conductivity declines. In the early stage of fracturing, small-size proppants with low emission are typically employed, which is conducive to the extension of the hydraulic fracture. In the later stage of fracturing, the flow conductivity of near wellbore can be improved by using large-size proppants. • Model of filtration coefficient considering stress sensitivity in coal reservoir was established. • Influencing factors of filtration property for fracturing fluid in coal reservoir were analyzed. • Calculation models of the facture conductivity in different conditions were established. • Influencing factors of fracture conductivity in coal reservoir were analyzed. [ABSTRACT FROM AUTHOR]

During hydraulic fracturing, there is a temperature difference between the injected water and formation rock for shale gas wells. The objective of this study is to investigate how this temperature difference changes with time, and how it affects multiphase-flow modeling during the shut-in and flowback periods. We conducted numerical simulations to investigate the behaviors of fracture temperature in shale gas wells. The results show a significant increase in fracture temperature during the shut-in and flowback periods. Sensitivity analysis suggests that this temperature increase is strongly related to the thermal conductivity of formation rock, matrix permeability, and initial reservoir temperature. Simulation scenarios were further compared to investigate the effect of temperature on flowback data analysis. Without considering the thermal effect, flowback data analysis may yield an earlier fracture cleanup and overestimated fracture volume. In addition, this study suggests that the thermal effect may also have implications for optimizing flowback operations. [ABSTRACT FROM AUTHOR]

Advanced production decline analysis methods have become more economic and efficient options due to technical and time limitations of well-testing operations in shale gas reservoirs. By normalizing rate with material balance pseudo-time, Blasingame type decline analysis can be applied to variable rate/variable pressure drop system, making the methodology more widely applicable. Blasingame decline analysis of variable rate/variable pressure drop case for multi-fractured horizontal well (MFHW) in shale has been less investigated, because of multi-scale storage spaces and multi-flow mechanisms. This article presents a semi-analytical Blasingame decline analysis model incorporating multi-flow mechanisms with shale's modified material balance pseudo-time. Laplace transformation, point source function, numerical discrete method, perturbation method, and Gaussian elimination method were employed to solve the mathematical problem caused by multi-flow mechanisms. Besides, the material balance pseudo-time was modified by considering adsorption and desorption. In this study, a workflow to investigate the effects of properties of hydraulic fracture (fracture half-length, number of fractures and fracture spacing) and multi-flow mechanisms (diffusion and desorption) on production decline behaviors through diagnostic Blasingame type curves is proposed. The results indicate that productivity is greater with a larger scale of fracture treatment, and better desorption of adsorbed gas is also beneficial to production. The decline rates affected by the fracture treatment scale and supplement capacity show two opposite trends, which is caused by interference between the fractures and boundary, respectively. Except that the data in the diffusion early flow period do not match very well, because the use of diffusion coefficient as a constant, the good fitting results on the whole verifies the model's validity and reliability. • A new Blasingame decline model of shale accommodating multi-mechanisms is established. • Effects of fracture and flow mechanism on production behaviors are analyzed. • Simulated result matches well with rate data. • Considering diffusivity as a constant may result in poor fitting result. [ABSTRACT FROM AUTHOR]

Horizontal well drilling and hydraulic fracturing are the most frequently adopted technologies for the commercial development of shale reservoirs. However, expensive production strategies are still implemented which results in high risk in investment. Integrated optimization of horizontal well spacing and hydraulic fracture stage placement helps in striking a balance between gas production and economic benefits. Previous studies relied heavily on numerical simulation models which are computationally expensive. In this study, a novel hybrid surrogate-assisted shale gas horizontal well spacing and hydraulic fracture stage placement multi-objective optimization method based on transfer stacking (SATS-WSF) is proposed to lessen the computational burden of the numerical simulation model run. In the SATS-WSF method, three widely used machine learning models, namely Gaussian process regression (GPR), radial basis function network (RBFN), and support vector regression (SVR) were applied to approximate the numerical simulation model as the source tasks. Then, a hybrid surrogate model transferring the three source tasks to the computationally expensive numerical simulation model was adopted to guide the optimization process of shale gas horizontal well spacing and hydraulic fracture stage placement. In addition, two sampling infill strategies called promising and uncertain were used to accelerate the searching process and to improve the quality of the final optimal solutions. Furthermore, two cases with different wells and fracture types based on the Barnett shale gas reservoir properties were employed to verify the effectiveness and efficiency of the SATS-WSF method. This method provides an intelligent approach for efficient decision-making of shale gas well space and fracture scheme. • A hybrid surrogate-assisted optimization method named SATS-WSF is proposed. • Infill sampling strategies are adopted to improve the performance of the hybrid surrogate model. • The optimization results demonstrated the superior performance of the proposed SATS-WSF method. [ABSTRACT FROM AUTHOR]