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Environmental (E), social (S), and governance (G) concepts have become a global consensus. Therefore, exploring the motivation mechanism adopted by companies to carry out ESG practices to promote sustainable social and economic development is of far-reaching significance. This study investigated whether there was a peer effect in the ESG practices of A-share listed companies and explored its mechanism of action and economic consequences using the data of Chinese A-share listed companies from 2010 to 2021. The empirical results show that there is a significant regional and industry peer effect on the ESG practices of A-share listed companies, which still holds when the average stock trait return is used as the instrumental variable. Furthermore, the mechanism test indicates that the information learning motive and agency cost are potential reasons for the peer effect of ESG practices. On the one hand, followers with information disadvantages tend to imitate the ESG practices of leaders with information advantages, but the converse is invalid. On the other hand, a worse external information environment leads to a higher degree of uncertainty, while a higher agency cost leads to a stronger peer effect of ESG practices. Lastly, the peer effect of corporate ESG practices helps create corporate value and increases corporate risk-taking to some extent. This paper provides a new micro perspective for understanding the occurrence mechanism and economic consequences of ESG practices, as well as crucial empirical evidence for firms to make sustainable development investment decisions.

Lab experiments, field pilots, and numerical modeling focusing on fluid flow aspects have indicated that multi-branch wells are technically effective and promising. Several researchers have conducted some experiments for a fishbone well strategy with mixed results. Our objective in this work is to study the impact of the different fishbone well patterns, such as branch angle, on the distribution of remaining oil after water flooding. In this paper, the interference effect between branches on oil recovery is studied in three steps. First, the interferences between fishbone wells with different branch angles were measured by hydro-electric simulation experiments. Second, two-dimensional visualization water flooding experiments were carried out to clarify the remaining oil distribution at different branch angles. Third, the distribution of oil and water in fishbone wells was verified by establishing a numerical model. The modeling results agree well with the experimental phenomena. At the same time, the variation trend of water and oil production in each branch is analyzed by numerical simulation results. The results indicate that the production is strongly dependent on the branch angles, and the highest recovery was 60.2% at a 45° branch angle.

Highly thermally conductive but electrically insulating polymer composites play an increasingly important role in thermal management applications due to their features of easy processing and lightweight. Herein, a unique segregated network, which consists of graphene nanoplatelets (GNP) and boron nitride fibers (BNF), was constructed in polypropylene (PP)-based composites via two-screw extrusion. The thermal conductivity and electrical insulation characteristic of the composites could be well controlled by adjusting the content and size of GNP and BNF. When PP was filled with 9wt% GNP and 30wt% short BNF, the highest thermal conductivity of 1.32 W/(m·K) was achieved in this work, which is about six times higher than the value of neat PP, while remained a good electrical insulating (as low as 2.98 × 10−9 S/m). It proposed that the unique segregated network, where the BNF play as a bridge to connect the scattered GNP, could benefit for phonons transmission but effectively interrupt electron conduction. Our work provides a facile method to design and fabricate the highly thermally conductive but electrically insulating composites applied in thermal management materials.

This paper conducts the front wheel angle tracking compensation control of the electro-hydraulic coupling power steering system (EHCPS) of the intelligent heavy vehicle (IHV). It has been found from the results of mathematic analysis, simulation and open-loop frequency test of the EHCPS that front wheel angle slightly lags behind handwheel angle at low frequencies. In this paper, a kind of fuzzy neural network controller (FNNC) based on model reference adaptive control (MRAC) is designed. Fuzzy neural network is also used to identify the EHCPS on-line. Membership function and inference rules of the FNNC and fuzzy neural network identification (FNNI) are renewed by the self-learning function of neural network to achieve on-line regulation of controller’s parameters. Reference model with certain bandwidth and control algorithm are designed to ensure that actual front wheel angle follows desired front wheel angle. Finally, the hardware-in-the-loop experiment and simulation results indicate that the control strategy presented in this paper is effective in compensating front wheel angle tracking within certain bandwidth of EHCPS.

Summary The boundary-element method (BEM) is widely used in modeling fluid flow in fractured reservoirs. However, the computation is extremely expensive when real heterogeneity and large numbers of fractures are modeled. This paper presents a novel edge-based Green element method (GEM) (eGEM) for this problem, and two significant modifications are made to the classical GEM. An edge-based discretization scheme is proposed to improve accuracy of the GEM. The eGEM technique is further enriched for simulating discrete fractures. The mathematical model is transformed into the Laplace domain, which makes it convenient to incorporate multiporosity models because the form of the boundary integral equation is the same. The matrix is meshed using Cartesian grids, and discrete fractures are handled flexibly by embedding into the matrix grids. In eGEM, the matrix/matrix flow is coupled at the common edge, so the unknown flux can be eliminated by using the edge-based scheme. In each matrix block, the matrix/fracture flow is modeled by treating the fracture elements as sources or sinks, as with BEM. The finite-difference method (FDM) is used to handle the fracture/fracture flow. In this paper, we tested the numerical accuracy and computational efficiency of the eGEM using several cases. First, the technique was shown to have higher accuracy than the classical corner-based GEM for transient problems in the petroleum industry. This shows the advantage of the edge-based discretization approach in handling the unknown flux of each solution point. The ability of the eGEM to handle discrete fractures was validated with the several models for transient-flow problems. The computation of the proposed eGEM is much less expensive than that for BEM in modeling the transient behavior of fractured media. Compared with the commercial numerical simulator in handling discrete fractures, the eGEM is shown to be less grid sensitive and to maintain a relatively high precision even with coarse grids near the discrete fractures. A detailed grid-sensitivity analysis was performed. The fracture grids are recommended to be refined to capture the early-time-flow behavior in pressure-transient analysis, especially in modeling low-conductivity fractures. For the first time, an efficient edge-based discretization scheme for GEM is presented, which handles the unknown flux of each solution point and at the same time uses eGEM to enrich simulation of discrete-fracture networks. This method serves as a new efficient approach for reservoir simulation and numerical well testing. Because of the high precision of eGEM with coarse grids, it would be efficient in larger field applications.

A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.

Steam-assisted gravity drainage (SAGD) is an efficient technology that has been used to develop oil sand resources, and it has been successfully and maturely applied in Canada. However, oilfield production has demonstrated that reservoir heterogeneity has a serious impact on SAGD development, among which the most drastic impact is caused by multiple barrier layers in the reservoir. These barrier layers can severely impede the development of a steam chamber and the drainage of oil. Hence, it is important to investigate their influence mechanism. In this study, oil samples from the Long Lake oil field were used in laboratory experiments to study the development of the steam chamber and the residual oil distribution under the effect of multiple barrier layers. Then, a theoretical numerical simulation model was established to describe the fluid flow more precisely. In addition, the production characteristics of SAGD under the influence of different numbers of barrier layers were analyzed by comparing the development of the steam chamber. Finally, the impacts of multiple barrier layers with different modes of combinations were studied for their effects on SAGD production. The results indicated that for impermeable barrier layers of the same length, the steam primarily developed upward after flowing around the first barrier layer. After the steam chamber reached the top of the reservoir, the steam began to enter into the interbedded zone. Based on an unchanged first barrier layer, the number of barrier layers had little influence on the overall shape of the steam chamber and SAGD production, which confirmed that the first barrier layer played a dominant role in the influence of multiple barrier layers. In addition, characteristic points (P1, P2, P3), which corresponded to changes in the stage of steam chamber development, were established and used to evaluate the effect of the barrier layers. Different combinations of barrier layers were realized by changing the relative properties of the first barrier layer. The results showed that the longer the length of the first barrier layer, the closer it was to the steam injection well and the lower the permeability; hence, the more obvious its hysteresis effect on the SAGD process.

An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts.

Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility.

Summary Steam-assisted gravity drainage (SAGD) is the most-effective thermal recovery method to exploit oil sand. The driving force of gravity is generally acknowledged as the most-significant driving mechanism in the SAGD process. However, an increasing number of field cases have shown that pressure difference might play an important role in the process. The objective of this paper is to simulate the effects of injector/producer-pressure difference on steam-chamber evolution and SAGD production performance. A series of 2D numerical simulations was conducted using the MacKay River and Dover reservoirs in western Canada to investigate the influence of pressure difference on SAGD recovery. Meanwhile, the effects of pressure difference on oil-production rate, stable production time, and steam-chamber development were studied in detail. Moreover, by combining Darcy's law and heat conduction along with a mass balance in the reservoir, a modified mathematical model considering the effects of pressure difference is established to predict the SAGD production performance. Finally, the proposed model is validated by comparing calculated cumulative oil production and oil-production rate with the results from numerical and experimental simulations. The results indicate that the oil production first increases rapidly and then slows down when a certain pressure difference is reached. The pressure difference has strong effects on steam-chamber-rising/expansion stages. However, at the expansion stage, lower pressure difference can achieve the same effect as high pressure difference. In addition, it is shown that the steam-chamber-expansion angle is a function of pressure difference. Using this finding, a new mathematical model is established considering the modification of the expansion angle, which (Butler 1991) treated as a constant. With the proposed model, production performance such as cumulative oil production and oil-production rate can be predicted. The steam-chamber shape is redefined at the rising stage, changing from a fan-like shape to a hexagonal shape, but not the single fan-like shape defined by (Butler 1991). This shape redefinition can clearly explain why the greatest oil-production rate does not occur when the steam chamber reaches the caprock. Literature surveys show few studies on how pressure difference influences steam-chamber development and SAGD recovery. The current paper provides a modified SAGD production model and an entirely new scope for SAGD enhanced oil recovery (EOR) that makes the pressure difference a new optimizable factor in the field.

Steam flooding (SF) is an effective technology to exploit thin heavy-oil reservoirs. Long-term indoor experiments and field tests, however, show that SF has the problems of great heat loss and a limited steam-chamber affected area, which severely limits steam utility and the ultimate economic benefit of thin heavy-oil reservoirs. In this paper, based on a specific oil field in China, we designed a two-dimensional experimental model to investigate the effect of solvents on steam-chamber distribution and production dynamics, and the effect of heat-solvent coupling (molar ratio of steam and solvent) on steam-chamber front expansion. Then, based on the parameters of indoor experiments, we built a numerical model by CMG STARS to further study the influence of solvent migration in steam chambers under different injection molar ratios of steam and solvent. The results show that: i) According to experimental results, for SF, steam-chamber affected area is limited and oil recovery is low which is only 21.3%. After the solvent is added, steam-chamber affected area can be largely enlarged and displacement efficiency can be enhanced. Compared with SF, oil recovery of Solvent-Enhanced Steam Flooding (SESF) can be enhanced to 34.3%–58.3%; ii) According to the results of the numerical simulation, oil viscosity can be greatly reduced after the solvent is added. As a result, steam-chamber expansion can be improved, steam-chamber affected area can be enlarged, and displacement efficiency can be enhanced; iii) the optimal injection molar ratio of steam and solvent was around 8:1 for SESF.

Summary Carbonate reservoirs comprise fractures, vugs, and cavities. Vugs have a large contribution to reserves of oil and gas, and the fractures provide effective paths for fluid flow in the reservoir. The triple-porosity (TP) model is an effective conceptual method for capturing rock matrix and vugs and the microfractures connecting them. However, these fractures and vugs are always nonhomogeneous. Macrofractures and vugs cannot be handled with a continuum scheme because of their low density and high conductivity. In this approach, the TP conceptual model is implemented to characterize rock matrix, microvugs, and fractures. To capture the heterogeneity of fractures and vugs, macrofractures and vugs are represented explicitly with the discontinuum model. The boundaries of macrovugs and macrofractures are discretized into several elements. The boundary-element method (BEM) is used to handle flow into macrofractures and vugs. The finite-difference method is applied to handle flow within macrofractures. The flow within macrovugs is assumed to be pseudosteady state. With a simple discretization of the boundaries of macrovugs and macrofractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model and numerical simulation. On the basis of the proposed model, the effect of the heterogeneity of macrofractures and vugs on pressure-transient behavior is analyzed. The results show that macrofractures and vugs cannot be handled with triple-continuum models analytically. There will be several “dips” on the derivative of the pressure curve if macrovugs are discretely handled. Also, discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative pressure lower than those calculated with the triple-continuum models. After increasing the porosity of macrovugs, the pressure and the derivative will go down in the flow regimes dominated by macrovugs. The conductivity of macrofractures has a great impact on almost all the flow regimes except for boundary-dominated flow. Finally, a field case is used to show the application of the proposed semianalytical model. The novelty of the new model is its ability to model the transient behavior of carbonate reservoirs with nonhomogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multiscaled fractures and vugs.

The productivity of shale gas well is often with high uncertainty because of the uncertainties in the characterization of formation properties, fracture properties, gas adsorption, and flow mechanisms. This paper provides an efficient method to probabilistically forecast shale gas production by combining the Markov chain Monte Carlo method (MCMC) and a semi-analytical model. A trilinear flow model is used to predict shale gas production with the consideration of gas desorption and multiple flow mechanisms. The parameters in the model are sampled with the MCMC. A workflow is proposed to predict the gas production and characterize the uncertainties. To make the study results helpful for the field use, a field case from a shale gas field in Southwestern China is applied in the analysis. In this case, we chose ten uncertain parameters to study their effects on eventual ultimate recoveries. Shale gas production is shown to be closely related to the properties of formation, fracture, and flow mechanisms. The fracture half-length and BHP have strong effects on gas production, particularly the production within 5 years. BHP also influences the production after 5 years because of the gas PVT properties and gas adsorption. The results also show that enough iteration number is needed to get a reasonable uncertainty quantification. The sensitivity analysis shows that at least 2000 iterations are required for this case. After that, the probable production could be predicted with a range rather than only one value, and P10, P50, and P90 can be obtained. For the case studied in this paper, there is 90% probability that the EUR for a well is ranging from 0.62 × 108 to 1.48 × 108 m3.

The addition of solvent to steam injection, known as Solvent-Assisted Steam-Gravity Drainage (SA-SAGD), has recently been regarded as a more economically-efficient and environmentally-friendly alternative to Steam-Assisted Gravity Drainage (SAGD). In this paper, we present a mathematical model for estimating greenhouse gas (GHG) emissions and chamber evolution considering non-uniform property distribution along the horizontal well for SA-SAGD. In addition, oil price, carbon tax and liquid pool corresponding to the influences of the market, environmental needs and technology are incorporated into the model to analyze the economic benefits. The calculated results show that, when the liquid-pool level is 3 m, the reduction in GHG emissions is 30% by injecting C3/C5 solvents and 16.5% when the solvent is C7. If the liquid level is as high as 5 m, there will be no reduction in carbon emissions for the C5/C7 solvent injection. When both oil price and the carbon tax are at high levels, the C5/C7-assisted SAGD has the best economic performance. The C3-assisted SAGD is best when the oil price is low and the carbon tax is high. When the oil price and carbon tax are low, there is no economic advantage for the solvent-assisted SAGD.

SAGD is an effective technology that was devised for the development of oil sand. However, nowadays, most research is focused on the two-dimensional (2D) vertical profile, which ignores the non-uniformity of steam along the horizontal well occurring in an oilfield. In this paper, based on the properties in MacKay River oil sands, an experimental device for SAGD is well-designed to investigate steam-chamber expansion along the horizontal well. Then, based on experimental results, a new 3D mathematical model considering steam non-uniformity was established to predict production performance and steam-chamber expansion. Next, the calculated production performance and steam-chamber evolution were compared with numerical data to verify the accuracy of the model. Finally, the model was compared with previous models to assess its quality. Results show the following. (a) The steam distribution along the horizontal direction is non-uniform; even the preheating of SAGD is uniform using the modified pre-heating method, which, when switched to formal SAGD production, also presents the same non-uniform steam distribution. (b) The comparisons reveal that the proposed 3D model is reasonably more accurate than previous models in predicting cumulative oil prediction and steam-chamber expansion. (c) Factors influencing steam distribution along the horizontal well are also discussed, and it is believed that steam quality is the deciding factor that determines the degree of steam non-uniformity.

In recent years, analysis of flowback data has provided an early opportunity to evaluate key fracture parameters (e.g. fracture permeability and fracture volume) in unconventional reservoirs. A combination of diagnostic plots, straight-line methods and simulation model history-matching techniques have been used for this purpose. For many shale gas wells, immediate gas and water production occurs on flowback. In this paper, a novel method is developed and demonstrated for analysis of water data during two-phase (gas + water) flowback and early-time production of shale gas wells. In previous studies, it has been demonstrated that, during the late-time water flow period, the water phase exhibits boundary-dominated flow (BDF) characteristics due to the limited volume of water in fractures or surrounding matrix. The gas phase exhibits transient linear flow (TLF) characteristics within matrix, which is one of the first flow-regimes typically observed after flowback during online production. By introducing a new pseudotime with a modified total compressibility, the water flow equation during two-phase (gas + water) flow period is linearized. Accordingly, a modified flowing material balance (FMB) equation is developed for analyzing water boundary-dominated flow which considers water relativity permeability and the saturation- and pressure-dependent total compressibility. Thus, a novel method is developed by combination of the water FMB equation and an iteration technique, to estimate the facture half-length and fracture permeability during flowback of shale gas wells. The approach is validated using several numerically-simulated cases. Results show that the accuracy of the new method is influenced by the pressure and saturation gradient in the fracture. With an increase in fracture permeability, the calculated fracture parameters become very close to the expected values. The calculated fracture half-length starts to deviate from the expected values with an increase in fracture half-length. However, the derived fracture permeability values are in excellent agreement for all cases studied. The matrix permeability has little effect on the calculated fracture parameters (half-length and permeability). Although there are some deviations between the interpreted and excepted values, both the values generally agree within 5%. Finally, practical application of the method is demonstrated using a Marcellus Shale well in northeast US north-east and a Changning Shale well in southwest China. The new techniques demonstrate the importance of accounting for phase relative permeability and correcting total compressibility, even when the gas phase dominates the flowback period.

In this paper, a novel model is proposed to study the variable mass flow process in a long horizontal well and to predict the distribution of thermophysical properties along the horizontal wellbore. First, a physical simulation device is designed to carry out a steam-injection experiment. Second, considering both the uneven distribution of steam and the effect of wellbore stock liquid, a steam-absorption model and a pressure drop model are proposed to predict the distribution of steam and pressure along the horizontal wellbore. Third, the effects of different parameters on steam distribution are analyzed in detail. The results indicate that: (1) an uneven employment phenomenon exists along the wellbore; (2) the pressure distribution along the wellbore is higher when wellbore stock liquid is taken into consideration; (3) the length of the unemployed section along the wellbore increases with an increase in the wellbore stock liquid viscosity; (4) the length of the unemployed section along the wellbore decreases with an increase in the steam injection rate; and (5) the reasonable wellbore length can prevent an unemployed section along the wellbore. This paper presents a basic reference for engineering for parameter optimization as well as for the prediction of steam distribution along the horizontal wellbore.

In shale gas reservoirs, the production data analysis method is widely used to invert reservoir and fracture parameter, and productivity prediction. Compared with numerical models and semianalytical models, which have high computational cost, the analytical model is mostly used in the production data analysis method to characterize the complex fracture network formed after fracturing. However, most of the current calculation models ignore the uneven support of fractures, and most of them use a single supported fracture model to describe the flow characteristics, which magnifies the role of supported fracture to a certain extent. Therefore, in this study, firstly, the fractures are divided into supported fractures and unsupported fractures. According to the near-well supported fractures and far-well unsupported fractures, the SRV zone is divided into outer SRV and inner SRV. The four areas are characterized by different seepage models, and the analytical solutions of the models are obtained by Laplace transform and inverse transform. Secondly, the material balance pseudotime is introduced to process the production data under the conditions of variable production and variable pressure. The double logarithmic curves of normalized production rate, rate integration, the derivative of the integration, and material balance pseudotime are established, and the parameters are interpreted by fitting the theoretical curve to the measured data. Then, the accuracy of the method is verified by comparison the parameter interpretation results with well test results, and the influence of parameters such as the half-length and permeability of supported and unsupported fractures on gas production is analyzed. Finally, the proposed method is applied to four field cases in southwest China. This paper mainly establishes an analytical method for parameter interpretation after hydraulic fracturing based on the production data analysis method considering the uneven support of fractures, which is of great significance for understanding the mechanism of fracturing stimulation, optimization of fracturing parameters, and gas production forecast.