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With the increasing demands on energy and environmental domains, not only high oil production but also its accurate quantification has become one of the most important topics in academia and industry. This paper initially proposes a comprehensive workflow in which an integrated hierarchy-correlation model is used to thoroughly evaluate the influences of all relevant reservoir parameters on the ultimate oil recovery for water-flooding oil reservoirs. More specifically, the analytic hierarchy process, grey relation, and entropy weight are combined through the multiplicative weighting method to quantitatively describe the production parameters. Accordingly, novel multivariable linear and nonlinear correlations are developed to predict the production performance and validated through comparisons with numerical reservoir simulations. Seven factors, including five reservoir parameters, namely, permeability and its contrast, porosity, thickness, and saturation, and two production parameters, namely, the injection-production ratio and the operating pressure, have been identified as the most influential factors on recovery performances and thus are employed in the proposed correlations to predict the ultimate oil recovery factor. The results obtained by the proposed method are quite close to the real-time simulation data, while the accuracy is retained. The numerical results show that the recovery factors of water-flooding oil reservoirs are about 33.5-59.5%, and the corresponding linear and nonlinear correlation coefficients are 0.903 and 0.789, respectively. In comparison with the numerical simulation, the approximation error by the linear correlation is about 0.5%, which is lower than that of nonlinear correlation, for example, 12.3%. This study will be beneficial to analyze the reservoir-related parameters and provide a useful tool for rapid production performance evaluation of the water-flooding production scenario.

Shale gas resources (SGR), as a representative of natural gas hydrate reservoirs, have been the main energy supply for the energy consumption currently. The multi-scale pore structure of shale, complicated seepage mechanisms, including Knudsen diffusion, matrix deformation, stress sensitivity, non-Darcy flow and spatial fracture network stimulated by hydraulic fracturing technology have posed huge challenges to an accurate prediction and assessment of shale gas recovery. A full understanding of gas seepage mechanism of shale gas is the critical and scientific issue to develop carbon hydrogen energy resources effectively. It is very urgent to establish a comprehensive mathematical model to analyze the productivity capacity through simultaneously considering various flow mechanisms and fractures network system. To fill this gap, this paper presents a comprehensive numerical model of hydraulic fracturing horizontal well with discrete fracture network where embedded discrete fracture model (EDFM) is employed to characterize the coupled phenomenon between discrete fracture network and fractured SGR. And then two numerical discretization methods, e.g., finite difference and finite-volume, are used to numerically discretize the equations, subsequently, the Newton-Raphson iterative method is adopted to obtain the final solutions. Finally, the sensitivity analysis experiments are employed to investigate the effects of the key parameters. The results can provide some certain guidance for the optimization of stimulated treatment in natural gas hydrate reservoirs.

CO2 flooding can effectively enhance the recovery of low-permeability reservoirs and realize CO2 geological storage. During the displacement process, the minimum miscible pressure (MMP) of CO2 and oil is an important parameter that affects the displacement effect and storage efficiency. However, the microscopic pore-throat structure of low-permeability reservoirs has significant influences on the fluids and phase behaviors. This paper presented a method to determine the miscible state of CO2 flooding based on the microscopic pore-throat structure. Firstly, a physic model was established to quantitatively characterize the microscopic pore-throat structure. Secondly, taking into consideration the P-R equation of state, the gas-liquid equilibrium in the narrow pore-throat was calculated. On this basis, a MMP prediction model was established correspongdingly by considering the multi-stage contact and mass transfer of CO2-oil. Finally, the results obtained by the proposed model were compared with the experimental results of CO2 flooding, and then the model was applied to the actual reservoir to predict plane distribution of MMP. The curves of MMP distribution and pressure drawdown between wells were combined to determine the position of miscible front and non-miscible area at different production stages. The results have shown that the MMP of core sample calculated by the model was 20.3 MPa, which was comparable to that of CO2 flooding experiment, e.g., 20 MPa, and thus indicatesd a high accuracy of the model. The MMP in the well control area of the Y29-101 well group was 19.8 MPa. During the unsteady flow stage, the miscible-phase front was 430 m from the injection well, while it was 310 m from the injection well during the stable flow stage. This method can accurately determine the specific phase distribution of CO2-oil in the formation, which is of great significance to promote the development of CO2 flooding and storage technology, improve the recovery of low permeability reservoirs, ensure energy supply and reduce carbon emission.

Understanding and manipulating wettability alterations has tremendous implications in theoretical research and industrial applications. This study proposes a novel idea of applying ultrasonic for wettability alterations and also provides its quantitative characterizations and in-depth analyses. More specifically, with pretreatment of ultrasonic, mechanisms of wettability alteration were characterized from the contact angle measurements, as well as the in-depth analyses from atomic force microscopy (AFM), X-ray diffraction (XRD), and Fourier-transform infrared spectroscopy (FTIR). After ultrasonic treatments, the wettability of mineral with low permeability is determined to altered from strong hydrophilic to intermediate wettability. The mechanism interpretations are conducted by means of the AFM, XRD, and FTIR. Basically, as the time of ultrasonic treatment increases, the AFM results indicate that the roughness of rock surface and oil/rock interface (contact area) with surroundings of brine is enhanced. Meanwhile, the XRD results show the diffusions of clays from the rock surface to the aqueous phase, and FTIR indicates that the number of functional groups of Si-O-Si, C-O-C, C-O, C═O, and OH decreases while the number of COOH and C═C═O groups increases. This study clearly reveals the surface chemistry of oil-rock wettability alteration in the subsurface conditions, which would provide technical support for subsurface usage of geo-energy productions and carbon sequestrations.

It is complex and obviously different for the production characteristics of CO2 water-alternating-gas (WAG) flooding in tight reservoir and influenced by quite a few factors. Therefore, the prediction of oil production is a key matter of efficient development of CO2 WAG to be solved in tight reservoirs. In order to cope with this issue, in this paper, the production characteristics of CO2 WAG flooding are analyzed and classified in tight oil reservoir of block A as an example. On this basis, properties of reservoir, fracture factors, and operational factors are taken into account and the sensitivity of the influencing factors is carried out. Subsequently, the gray relation analysis is used to confirm the primary influencing factors. Finally, the evaluated model is established to predict oil production rapidly. The results illustrate that the wells of CO2 WAG flooding in tight reservoirs can be divided into four types of fluid production characteristics. The production is affected by permeability, reservoir thickness, amount of sand entering the ground, amount of liquid entering the ground, gas/water ratio, the injection rate, injection pressure, permeability variation coefficient, water sensitive index, acid sensitive index, and expulsion pressure. And the primary influencing factors are the amount of sand entering the ground, reservoir thickness, and amount of liquid entering the ground. The oil production can be predicted quickly based on the relation between production and comprehensive evaluation factor of production. The average relative error between the predicted results and the actual production is 8%, which proves the reliability and accuracy of this method.

Summary Finding multiple posterior realizations through a reservoir history-matching procedure is of significance for uncertainty quantification, risk analysis, and decision making in the course of reservoir closed-loop management. Previously, an efficient, distributed, optimization algorithm—global linear-regression (GLR) with distributed Gauss-Newton (GLR-DGN)—has been proposed in the literature to iteratively minimize multiple objective functions by performing Gauss-Newton (GN) optimizations concurrently while dynamically sharing information between dispersed regions in a reduced parameter space. However, theoretically, the required number of initial training models should be larger than the number of parameters to guarantee a unique solution for the GLR equation for sensitivity-matrix estimation. This limitation makes the large-scale reservoir history-matching problem with a large amount of parameters almost intractable. We enrich the previous history-matching framework by integrating our recently proposed smooth local parameterization (SLP) and DGN for the sensitivity-matrix calculation. Motivated by the fact that one specific flow response mainly depends on a few influential or local parameters, which can be generally identified by the physical position of the wells (e.g., the parameters in the zone surrounding the wells), which is particularly true for large-scale reservoir models, this paper presents a new integration of subdomain linear-regression (SLR) with DGN, referred to as SLR-DGN. This SLP allows us to independently represent the globally spatial parameter field within low-order parameter subspaces in each subdomain. On the basis of the SLP procedure, only a few training models are required to compute local sensitivity of the response functions using a subdomain linear regression. SLP is a linear transformation with smoothness and differentiability, which makes it particularly compatible with Newton-like gradient-based optimization algorithms. Furthermore, we also introduce an adaptive scheme, named weighting smooth local parameterization (WSLP), in which the minimization algorithm adaptively determines the weighting coefficients and the optimal domain decomposition (DD) correspondingly, to mitigate the negative effects of an inappropriate DD strategy. We support our framework with numerical experiments for a four-variable toy model and a modified version of the sensitivity analysis of the impact of geological uncertainties on production (SAIGUP) model with spatially dependent parameters. Comparisons with previous GLR-DGN have shown that our new framework can generate comparable and even better results with significantly reduced computational cost. This SLP has high scalability, because the number of training models depends primarily on the number of local parameters in each subdomain and not on the dimension of the underlying full-order model. Activating more subdomains results in fewer local parameter patterns and enables us to run fewer training models. For a large-scale case study in this work, to optimize 412 global parameters, SLR-DGN needs only 100 initial-model simulations. In comparison to GLR-DGN where the parameters are defined over the entire domain, the central-processing-unit cost is reduced by a factor of several orders of magnitude, while retaining reasonable accuracy.

Five-spot well pattern (FSWP) scheme has shown appealing potentialities to enhance the recovery of coal-bed methane (CBM) from methane hydrocarbon reservoirs (MHR). In this paper, a new framework aimed at systematically investigating productivity performance of FSWP scheme with inter-well pressure interference (IWPI) is presented. First, mathematical models which are used to characterize the fluid flow within MHR and hydraulic fractures (HFs) are separately derived. Second, Laplace transformation and Stehfest numerical algorithm are utilized to couple those two flow systems and obtain the pressure-transient solutions of FSWP scheme. Finally, pressure characteristics are discerned and sensitivity analysis of key parameters is implemented as well. This semi-analytical approach outperforms numerical simulation from the point of computational efficiency. Several common flow regimes, e.g., linear and bi-linear flow regimes, are essentially deformed induced by IWPI. Several significant parameters, including gas rate, fracture half-length, and well spacing on the occurrence of IWPI are systematically analyzed. This work gains some new knowledge about the productivity performance of FSWP scheme with the existence of IWPI when extracting CBM from methane hydrate reservoirs (MHR), which provides energy engineers considerable instructions on optimizing the development of methane hydrate reservoirs.

CO2 enhanced oil recovery (EOR) has been proven its capability to explore the unconventional tight oil reservoirs and potential for geological carbon storage. Meanwhile, the extremely low permeability pores exaggerate the difficulty CO2 EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate the oil-gas miscibility development and finally contribute to unlock more tight oils. First, the physical properties of crude oil with and without ultrasonic treatments were experimentally analysed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Second, the oil-gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Third, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40KHz and 200W for 8 hours) was found to substantially change the oil properties, with viscosity (at 60°C) reduced from 4.1 to 2.8mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum shows the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9MPa from the slim-tube test and the oil recovery factor increased by over 10%. This study reveals the mechanisms of ultrasonic-assisted CO2 miscible EOR in producing tight oils.

At present, the main development mode of “horizontal well + volume fracturing” is adopted in a tight glutenite reservoir. Due to the existence of conglomerate, the seepage characteristics are more complex, and the production capacity after volume fracturing is difficult to predict. In order to solve this problem, a dual media unstable seepage model was established for matrix seepage and discrete fracture network seepage when considering the trigger pressure gradient. By considering the Poisson's ratio of stress sensitivity in an innovative way, the coupling model of permeability and stress is improved, and the production prediction model of volume fracturing horizontal well in a tight glutenite reservoir based on the fluid-solid coupling effect is formed. The finite element method is used to numerically solve the model, and the fitting verification of the model is carried out; the impact of stress sensitivity, producing pressure difference, fracture length, number of fracture clusters and fracture flow capacity conductivity on productivity is analyzed, which has certain guiding significance for the efficient development of volume fracturing in a tight glutenite reservoir.

Based on fractal theory (FT) and fractional calculus (FC), a new fractally fractional diffusion model (FFDM) of composite dual-porosity has been developed to evaluate performance of multiple fractured horizontal wells (MFHWs) with stimulated reservoir volume (SRV) in tight gas reservoirs (TGRs). More specifically, FT is used to characterize the complex and heterogeneous fracture network (FN) both inside and outside of SRV, while anomalous behavior of diffusion processes both inside and outside of SRV is quantified by applying the temporal fractional derivatives. The FFDM is then solved by the Laplace transformation, line source function, the numerical discrete method, and superposition principle. The transient pressure responses are then inversely converted from Laplace domain into real time domain with the Stehfest algorithm, and the FFDM is also validated, and type curves are generated as well. Flow stages are subsequently identified together with analysis on characteristics of the type curves, especially the anomalous features different with those generated from the conventional Euclidean model. Sensitivity analyses of some related parameters have also been discussed as well. And the FFDM is then also matched with the real field well-testing data of a MFHW with SRV in a TGR. The proposed FFDM provides a new understanding of the performance of MFHWs with SRV in TGRs, which can be used to interpret the field pressure data more accurately and appropriately.

Understanding and manipulating geological pore structures is of paramount importance for geo-energy productions and underground energy storages in porous media. Nevertheless, research emphases for long time have been focused on understanding the pore configurations, while few work conducted to modify and restructure the porous media. This study deploys ultrasonic treatments on typical geological in-situ core samples, with follow-up processes of high-pressure mercury injections and nitrogen adsorptions and interpretations from nuclear magnetic resonance and x-ray diffraction. The core permeability and porosity are found to increase by 8.3 mD, from 4.1 to 12.4 mD, and by 0.95%, from 14.03% to 14.98%, respectively. Meanwhile, the number and size of the micro- and mesopore are increased with progressing of ultrasonic treatment, while those of the macropore decrease, which finally increase the permeability and porosity. The increase of micro- and mesopore number, from x-ray diffraction results, is attributed to the migration and precipitation of clay minerals caused through ultrasonic wave. The relocation of clay minerals also helps to improve the pore-throat connectivity and modify the micro-scale heterogeneity. Basically, this study reveals the characterizations of geological pore reconfigurations post-ultrasonic treatments and interprets the associated mechanisms, which provides guidance to manipulate the geological pores and be of benefit for further porous media use in science and engineering.

In this paper, the equilibrium two-phase compositions are predicted and analyzed to elucidate the pressure dependence of the equilibrium interfacial tensions (IFTs) of three different light crude oil–CO2 systems. First, three series of the dynamic IFT tests for a dead light crude oil–pure CO2 system, a live light crude oil–pure CO2 system, and a dead light crude oil–impure CO2 system at different equilibrium pressures from the literature are used. Second, the modified Peng–Robinson equation of state (PR-EOS) is tuned by using measured pressure–volume–temperature (PVT) data to predict the equilibrium two-phase compositions of the three light crude oil–CO2 systems. Such tuned PR-EOS together with the parachor model is applied to predict the equilibrium IFTs, which are compared with and validated by the measured IFT data. Third, the pressure dependence of the equilibrium IFTs, the initial oil and gas composition effects, and the initial gas fraction effect are examined. The density difference between the light crude oil and gas phase is found to be a key factor in the parachor model for the IFT predictions. The equilibrium IFT vs. pressure curve is found to have three different pressure ranges, which correspond well to those for the density difference. Moreover, the initial oil and gas compositions affect the equilibrium two-phase compositions and IFTs to different extents. The live light crude oil–pure CO2 equilibrium IFT is reduced with an increased initial gas fraction. For the dead light crude oil–pure/impure CO2 system, the miscibility with zero IFT can be achieved only if the initial gas phase has more than 0.70 mol fraction. Otherwise, it is the complete gas dissolution into the light crude oil that leads to zero IFT.

In this paper, a generalized and pragmatic framework has been developed to optimize the vector well pattern in tight sandstone reservoirs. More specifically, the maximum principal formation stress, natural fracture orientation, and principal permeability orientation are identified as the three key factors associated with well productivity, while both micro-elements of fractures are summed up and coefficients of the same fracture are combined according to the angle between the principal permeability orientation and direction of the hydraulic fractures to form an equation matrix. The sensitivity analysis is then conducted to examine effect of the maximum horizontal principal stress and the principal permeability on horizontal well production while determining the optimal orientation of the horizontal wellbore. Subsequently, theoretical calculation is performed to design and optimize the well pattern as well as fracture properties. It is found that the orientation of a horizontal wellbore should be perpendicular to the direction of the maximum horizontal principal stress if the angle (θ) between the orientation of the principal permeability k x and the direction of the maximum horizontal principal stress is less than 30 ° . If 30 ° ≤ θ ≤ 60 ° , the orientation of the horizontal wellbore should be perpendicular to the direction of the maximum horizontal principal stress for a weak anisotropic reservoir k x / k y 2 , while it should be perpendicular to the orientation of principal permeability k x for a strong anisotropic reservoir k x / k y ≥ 2 . The orientation of a horizontal wellbore needs to be perpendicular to the orientation of the principal permeability (kx) if 60 ° ≤ θ ≤ 90 ° . In addition to improving the recovery factor compared with that of the conventional well spacing, it is found from a field application that the optimized vector well pattern can effectively extend the stable production period, reduce water-cut, increase oil recovery up to 4.5%, and improve the overall reservoir performance.

Carbon dioxide miscible flooding has been proven to be one of the most effective enhanced oil recovery (EOR) technologies, particularly for light and medium oil reservoirs. However, specific effects of pore structure on CO2 miscible flooding recovery in low permeability reservoir lack in-depth understandings. In this paper, pore structures are specifically studied by means of the molecular mechanics to evaluate their effects on the CO2 EOR in the low permeability reservoir. First, a series lab experiments are performed for the pore and fluid characterization. More specifically, the pore throat size and distribution frequency are measured from the high-pressure mercury injection and nuclear magnetic resonance. The minimum miscibility pressure is determined from the slim-tube tests with known oil compositions tested from gas chromatography analysis. Second, the regularity of CO2 extraction is explored on the basis of molecular mechanics and the thickness of raffinate is calculated. Finally, the raffinate volume and recovery ratio in the pores are calculated after the CO2 miscible flooding. The results show that a raffinate-layer with thickness of 0.13 μm remains on the surface of the pore after the CO2 miscible flooding, which would cause the oil to be immobile since the throat could be blocked when the throat radius is smaller than 0.26 μm. The recoveries of cores C-1 and C-2 are 70.1 % and 61.4 % from calculations and 68.4 % and 59.8 % from experiments, whose errors are 2.5 % and 2.7 %, respectively. This study would be beneficial to analyze the CO2 miscible flooding in reservoirs with different pore structures and provide technical support for improving CO2 utilization efficiency.

CO2 enhanced oil recovery (EOR) has proven its capability to explore unconventional tight oil reservoirs and the potential for geological carbon storage. Meanwhile, the extremely low permeability pores increase the difficulty of CO2 EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate oil–gas miscibility development and finally contributes to excavating more tight oils. Firstly, the physical properties of crude oil with and without ultrasonic treatments were experimentally analyzed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Secondly, the oil–gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Thirdly, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40 KHz and 200 W for 8 h) was found to substantially change the oil properties, with viscosity (at 60 °C) reduced from 4.1 to 2.8 mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum showed that the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from the ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9 MPa from the slim-tube test and the oil recovery factor increased by an additional 11.7%. This study reveals the mechanisms of ultrasonic-assisted CO2 miscible EOR in producing tight oils.

Summary Recently, a multiwell-pad-production (MWPP) scheme has been the center of attention as a promising technology to improve shale-gas (SG) recovery. However, the increasing possibility of multiwell pressure interference (MWPI) in the MWPP scheme severely distorts flow regimes, which strongly challenges the traditional pressure-transient analysis methods that focus on single multifractured horizontal wells (SMFHWs) without MWPI. Therefore, a methodology to identify pressure-transient response of the MWPP scheme with and without MWPI is urgent. To fill this gap, a new semianalytical pressure-transient model of the MWPP scheme is established by use of superposition theory, Gauss elimination, and the Stehfest numerical algorithm. Type curves are generated, and flow regimes are identified by considering MWPI. Finally, a sensitivity analysis is conducted. Our results show that there are good agreements between our proposed model and numerical simulation; moreover, our semianalytical approach also demonstrates a promising calculation speed compared with numerical simulation. Some expected flow regimes are significantly distorted by MWPI. In addition, well rate determines the distortion of pressure curves, whereas fracture length, well spacing, and fracture spacing determine when the MWPI occurs. The smaller the gas rate, the more severely flow regimes are distorted. As the well spacing increases, fracture length decreases, fracture spacing decreases, and the occurrence of MWPI occurs later. The stress-sensitivity coefficient has little to no influence on the occurrence of MWPI. Similar to the concept of the dual-porosity model, three new flow regimes—the single-well flow regime, MWPI flow regime, and MWPP flow regime—are artificially defined to systematically characterize the flow regimes of the MWPP scheme. This work offers some additional insights on pressure-transient response for the MWPP scheme in the SG reservoir, which can provide considerable guidance for fracture-properties estimation and well-pattern optimization for the MWPP scheme.

Summary The detection of interacting behavior between the hydraulic fracture (HF) and the natural fracture (NF) is of significance to accurately and efficiently characterize an underground complex-fracture system induced by hydraulic-fracturing technology. This work develops a semianalytical pressure-transient model in the Laplace domain to detect interacting behavior between HF and NF depending on pressure-transient characteristics. Our results have shown that no matter what the flow state (compressible or incompressible flow) within a hydraulically induced fracture system, we can easily detect interacting behavior between HF and NF depending on whether the “dip” shape occurs at the formation radial-flow regime. Referring to sensitivity analysis, distance between NF and well, horizontal distance between NF and HF, and NF length are the three most sensitive factors to detect fracture-interacting behavior. Depending on interference analysis, although the pressure-transient characteristics of a pseudosteady-state dual-porosity model can interfere with our proposed methodology, the difference between our model and a pseudosteady-state dual-porosity system lies in whether the value of the horizontal line of dimensionless pressure derivative is equal to 0.5 at the formation radial-flow regime. Our work obtains some innovative insights into detecting fracture-interacting behavior, and the valuable results can provide significant guidance for refracturing operations and fracture detection in an underground fracture system.

Abandonment pressure of shale gas reservoirs has been in the center of attention to evaluate the CO 2 storage in such reservoirs. However, the evaluation of abandonment pressure in shale gas reservoirs is not clearly defined. To quantitatively determine the abandonment pressure for CO 2 storage in depleted shale gas reservoirs, we introduced two effective and reasonable semi-analytical models, named pressure transient analysis (PTA) and rate transient analysis (RTA), based on a free-simulator approach. Firstly, by line source function, CO 2 seepage models for an injection well with constant injection rate or constant injection pressure were simultaneously proposed in consideration of gas adsorption, diffusion flow, stress sensitivity and non-Darcy flow effects. Then, we solved seepage models using Laplace transformation, perturbation method, superposition principle and numerical discretization method, thus obtained transient-pressure and transient-rate solutions of the injection well. Further, we compared the proposed mathematical models with existing models. Furthermore, we systematically examined the sensitivity of the parameters, thereby constraining the intrinsic uncertainty to evaluate the abandonment pressure. Finally, we applied the proposed method to study a real case from Sichuan Basin in China, thus demonstrating the promising prosperity of this new quantitative determination of abandonment pressure for CO 2 storage in depleted shale gas reservoirs. Our results showed that the maximum difference between our proposed method and numerical method was lower than 5%, suggesting a good agreement between the two methods. Moreover, our results also showed that free-simulator approach gave much faster calculation speed compared to numerical method. As a result, we provided a framework for the quantitative determination of abandonment pressure, by coupling pressure transient analysis (PTA) and rate transient analysis (RTA) during CO 2 injection at constant injection pressure and injection rate. Moreover, our results also showed that the abandonment pressure has power law relationship with the injection pressure using PTA method, and the abandonment pressure has logarithm relationship with CO 2 injection volume using RTA method.

In this paper, a pragmatic and consistent framework has been developed and validated to accurately predict reservoir performance in tight sandstone reservoirs by coupling the dynamic capillary pressure with gas production models. Theoretically, the concept of pseudo-mobile water saturation, which is defined as the water saturation between irreducible water saturation and cutoff water saturation, is proposed to couple dynamic capillary pressure and stress-induced permeability to form an equation matrix that is solved by using the implicit pressure and explicit saturations (IMPES) method. Compared with the conventional methods, the newly developed model predicts a lower cumulative gas production but a higher reservoir pressure and a higher flowing bottomhole pressure at the end of the stable period. Physically, a higher gas production rate induces a greater dynamic capillary pressure, while both cutoff water saturation and stress-induced permeability impose a similar impact on the dynamic capillary pressure, though the corresponding degrees are varied. Due to the dynamic capillary pressure, pseudo-mobile water saturation controlled by the displacement pressure drop also affects the gas production. The higher the gas production rate is, the greater the effect of dynamic capillary pressure on the cumulative gas production, formation pressure, and flowing bottomhole pressure will be. By taking the dynamic capillary pressure into account, it can be more accurate to predict the performance of a gas reservoir and the length of stable production period, allowing for making more reasonable development schemes and thus improving the gas recovery in a tight sandstone reservoir.

Recently, Multi-Well-Pad-Production (MWPP) scheme has been in the center of attention as a promising technology to improve Shale Gas (SG) recovery. However, Inter-Well Pressure Interference (IWPI) induced by MWPP scheme severely distorts flow regimes, which strongly challenges the traditional pressure-transient analysis methods, which focus on Single Multi-Fractured Horizontal Wells (SMFHW) without IWPI. Therefore, a methodology to identify pressure-transient response of MWPP scheme without and with IWPI is urgent. To fill this gap, by utilizing superposition theory, Gauss elimination and Stehfest numerical algorithm, the pressure-transient solution of MWPP scheme was established, as a result, type flow regimes can be identified by considering MWIP. Our results show that our proposed model demonstrates promising calculation speed and acceptable accuracy compared to numerical simulation. Part of flow regimes are significantly distorted by IWPI. In addition, well rate mainly determines the distortion of pressure curves, while fracture length, well spacing, fracture spacing mainly determine when the IWPI occurs. The smaller the gas rate, the more severely flow regimes are distorted. As the well spacing increases, fracture length decreases, fracture spacing decreases, occurrence of IWPI becomes later. Stress sensitivity coefficient approximately has no influences on distortion of pressure curves and occurrence of IWPI. This work gains some additional insights on pressure-transient response for MWPP scheme in SG reservoir, which can provide considerable guidance on fracture properties estimation as well as well pattern optimization for MWPP scheme.

Power amplifier is an important component of wireless communication transmitter, the nonlinear distortion of the RF power amplifier leads to a new frequency component, thereby causing interference to the transmitted signal, Cause signal distortion and increase of receiver error rate. Therefore, it is necessary to eliminate the nonlinear effects of the amplifier as much as possible. This paper mainly focuses on the power amplifier power amplifier output signal with respect to the nonlinear input signal possible distortion phenomenon research, construct a memory less predistortion mathematical model based on polynomial, the amplifier signal pre distortion compensation processing. And on the basis of the use of matlab programming to input and output data memory model of the pre distortion compensation processing, the negative impact of the predistortion model processing method can interfere with the power amplifier nonlinear about adjacent channel consumption significantly, significantly improve the linearity of the power amplifier.

Shale gas reservoir is typical unconventional reservoir, it's necessary to take advantage of multi-stage fractured horizontal well so as to develop those kinds of reservoirs, which can form high conductivity hydraulic fractures and activate natural fractures. Due to the existence of concentration gap between matrix and fractures, desorption gas can simultaneously diffuse into the natural fractures and hydraulic fractures. This process can be called dual diffusion. Based on the triple-porosity cubic model, this paper establishes a new well testing model of multi-stage fractured horizontal well in shale gas reservoir with consideration of the unique mechanisms of desorption and dual diffusion in matrix. Laplace transformation is employed to solve this new model. The pseudo pressure transient responses are inverted into real time space with stehfest numerical inversion algorithm. Type curves are plotted, and different flow regimes in shale gas reservoirs are identified and the effects of relevant parameters are analyzed as well. Considering the mechanism of dual diffusion in matrix, the flow can be divided into five regimes: early linear flow; pseudo-steady state inter-porosity flow; the diffusion from matrix into micro-fractures; the diffusion from matrix into hydraulic fractures and boundary-dominated flow. There are large distinctions of pressure response between pseudo steady state diffusion and unsteady state diffusion under different value of pore volume ratio. It's similar to the feature of pseudo-steady state inter-porosity flow, diffusion coefficient and Langmuir parameters reflect the characters of pseudo-steady state diffusion. The numbers of stage of hydraulic fractures have certain impact on the shape factor of matrix and the inter-porosity coefficient. This new model is validated compared with some existing models. Finally, coupled with an application, this mew model can be approximately reliable and make some more precise productivity prediction.

Currently, most models for multiple fractured horizontal wells (MFHWs) in naturally fractured unconventional reservoirs (NFURs) are based on classical Euclidean models which implicitly assume a uniform distribution of natural fractures and that all fractures are homogeneous. While fractal theory provides a powerful method to describe the disorder, heterogeneity, uncertainty and complexity of the NFURs. In this paper, a fractally fractional diffusion model (FFDM) for MFHWs in NFURs is established based on fractal theory and fractional calculus. Particularly, fractal theory is used to describe the heterogeneous, complex fracture network, with consideration of anomalous behavior of diffusion process in NFURs by employing fractional calculus. The Laplace transformation, line source function, dispersion method, and superposition principle are used to solve this new model. The pressure responses in the real time domain are obtained with Stehfest numerical inversion algorithms. The type curves of MFHW with three different outer boundaries are plotted. Sensitivity analysis of some related parameters are discussed as well. This new model provides the relatively more accurate and appropriate evaluation results for pressure transient analysis for MFHWs in NFURs, which could be applied to accurately interpret the real pressure data of an MFHW in field.

China has large volumes of low-permeability reservoirs, distributed widely in the Ordos, Karamay and Songliao basins. In the recent decade, a new technology called advanced water injection (AWI), which is to inject water into formation to increase or maintain pressure for 3 to 6 months before oil production, has been applied to efficiently develop low-permeability reservoirs. This paper studies mechanisms and applications of AWI in China. Especially, its resent application in Xifeng oilfield has been described in detail. Most importantly, this paper proposes a simple equation to calculate optimal injected volume of water and pressure rise.

With the continuous development, the gas well productivity will decrease. The deliverability test can be used to evaluate gas well productivity, but this method always needs long test which will affect daily production seriously, especially for low permeability gas wells, also there always isn’t enough data in the field. Aiming at this problem, this article presents a new real time method to get the gas well productivity. This new method avoids deliverability test and only needs daily production and wellhead pressure data, so the analysis process is easy and this method has strong practicality. It is proved that this new method works well in the field case.