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This paper aims to review the quad-porosity shale system from a production standpoint. Understanding the complex but coupled flow mechanisms in such reservoirs is essential to design appropriate completions and further, optimally produce them. Dual-porosity and dual permeability models are most commonly used to describe a typical shale gas reservoir.

Characterization of such reservoirs with extremely low permeability does not aptly capture the physics and complexities of gas storage and flow through their existing nanopores. This paper reviews the methods and experimental studies used to describe the flow mechanisms of gas through such systems, and critically recommends the direction in which this work could be extended. A quad-porosity shale system is defined not just as porosity in the matrix and fracture, but as a combination of multiple porosity values.

It has been observed from studies conducted that shale gas production modeled with conventional simulator/model is seen to be much lower than actually observed in field data. This paper reviews the various flow mechanisms in shale nanopores by capturing the physics behind the actual process. The contribution of Knudson diffusion and gas slippage, gas desorption and gas diffusion from Kerogen to total production is studied in detail.

The results observed from experimental studies and simulation runs indicate that the above effects should be considered while modeling and making production forecast for such reservoirs.

This paper aims to present the implementation of a multi-layer radiation propagation model in simulations of multi-phase flow and heat transfer, for a dissociating methane hydrate reservoir subjected to microwave heating.

To model the induced heterogeneity due to dissociation of hydrates in the reservoir, a multiple homogeneous layer approach, used in food processes modelling, is suggested. The multi-layer model is incorporated in an in-house, multi-phase, multi-component hydrate dissociation simulator based on the finite volume method. The modified simulator is validated with standard experimental results in the literature and subsequently applied to a hydrate reservoir to study the effect of water content and sand dielectric nature on radiation propagation and hydrate dissociation.

The comparison of the multi-layer model with experimental results show a maximum difference in temperature estimation to be less than 2.5 K. For reservoir scale simulations, three homogeneous layers are observed to be sufficient to model the induced heterogeneity. There is a significant contribution of dielectric properties of sediments and water content of the reservoir in microwave radiation attenuation and overall hydrate dissociation. A high saturation reservoir may not always provide high gas recovery by dissociation of hydrates in the case of microwave heating.

The multi-layer approach to model microwave radiation propagation is introduced and tested for the first time in dissociating hydrate reservoirs. The multi-layer model provides better control over reservoir heterogeneity and interface conditions compared to existing homogeneous models.

To assess the impacts of climate change on stream flow and evaluation of reservoir performances, reliability, resilience and vulnerability (RRV) indices are contemplated. Precipitation, temperature (Tmax, Tmin), relative humidity and solar radiation are the hydrological and meteorological data which have been used extensively. Climate data like RCP2.6, RCP4.5 and RCP8.5 were evaluated for the base period 1976–2005 and future climate scenario for 2021–2050 and 2051–2080 as per the convenience.

The hydrologic engineering center hydrologic modeling system (HEC-HMS) model was used to simulate the current and future inflow volume into the reservoir. The model performance resulted as 0.76 Nash-Sutcliffe efficiency (NSE), 0.78 R2 and −3.17 D and during calibration the results obtained were 0.8 NSE, 0.82 R2 and 2.1 D. The projected climate scenario illustrates an increasing trend for both maximum and minimum temperature though a decreasing trend was documented for precipitation. The average time base reliability of the reservoirs was less than 50% without reservoir condition and greater than 50% for other conditions but volumetric reliability and resilience varies between 50% and 100% for all conditions. The vulnerability result of reservoirs may face shortage of flow ranging from 5.7% to 33.8%.

Evaluating reservoir simulation and hydropower generation for different climate scenarios by HEC-ResSim model, the energy generated for upper dam ranges from 349.4 MWhr to 331.2 MWhr and 4045.82 MWhr and 3946.74 MWhr for short and long-term future scenario, respectively. RCP for Tmax and Tmin goes on increasing whereas precipitation and inflow to reservoir decreases owing to increase in evapotranspiration. Under diverse climatic conditions power production goes on varying simultaneously.

This paper is original and all the references are properly cited.

The purpose of this paper is to give an explanation of the new data available about surface subsidence above the depleted gas reservoir Ravenna Terra. These data confirm the existence after end of exploitation of a reversed subsidence bowl with minimum subsidence above the reservoir, as opposed to conventional subsidence bowls during exploitation which show maximum subsidence in the same location.

The paper analyses these new data about the existence after end of exploitation of a reversed subsidence bowl. The observed behaviour is reproduced successfully with a fully coupled two phase flow code in deforming reservoir rocks which incorporates a constitutive model for partially saturated porous media.

The paper provides successful simulations. These allow affirming with confidence that the explanation for the peculiar behaviour is reservoir flooding and partially saturated rock behaviour.

Further research: other case studies where similar behaviour is expected, e.g. Ekofisk.

The paper includes implications for better management of reservoir exploitation schedules to minimize the observed phenomenon.

This paper explains the peculiar behaviour of subsidence above the depleted gas reservoir Ravenna Terra and confirms the conjecture that constitutive behaviour of partially saturated rocks is the origin of the observed phenomenon.

This paper aims to establish a mathematical model for water-flooding considering the impact of fluid–solid coupling to describe the process of development for a low-permeability reservoir. The numerical simulation method was used to analyze the process of injected water channeling into the interlayer.

Some typical cores including the sandstone and the mudstone were selected to test the permeability and the stress sensitivity, and some curves of the permeability varying with the stress for the cores were obtained to demonstrate the sensitivity of the formation. Based on the experimental results and the software Eclipse and Abaqus, the main injection parameters to reduce the amount of the injected water in flowing into the interlayer were simulated.

The results indicate that the permeability of the mudstone is more sensitive to the stress than sandstone. The injection rate can be as high as possible on the condition that no crack is activated or a new fracture is created in the development. For the B82 block of Daqing oilfield, the suggested pressure of the production pressure should be around 1–3MPa, this pressure must be gradually reached to get a higher efficiency of water injection and avoid damaging the casing.

This work is beneficial to ensure stable production and provide technical support to the production of low permeability reservoirs containing an interlayer.

The purpose of this paper is to present detailed algorithms for simulation of individual and group control of production wells in hydrocarbon reservoirs which are implemented in a finite volume-based reservoir simulator.

The algorithm for individual control is described for the multi-lateral multi-connection ones based on the multi-segment model considering cross-flow. Moreover, a general group control algorithm is proposed which can be coupled with any well model that can handle a constraint and returns the flow rates. The performance of oil production process based on the group control criteria is investigated and compared for various cases.

The proposed algorithm for group control of production wells is a non-optimization iterative scheme converging within a few number of iterations. The numerical results of many computer runs indicate that the nominal power of the production wells, in general, is the best group control criterion for the proposed algorithm. The production well group control with a proper criterion can generally improve the oil recovery process at negligible computational costs when compared with individual control of production wells.

Although the group control algorithm is implemented for both production and injection wells in the developed simulator, the numerical algorithm is here described only for production wells to provide more details.

The proposed algorithm can be coupled with any well model providing the fluid flow rates and can be efficiently used for group control of production wells. In addition, the calculated flow rates of the production wells based on the group control algorithm can be used as candidate solutions for the optimizer in the simulation-optimization models. It may reduce the total number of iterations and consequently the computational cost of the simulation-optimization models for the well control problem.

A complete and detailed description of ingredients of an efficient well group control algorithm for the hydrocarbon reservoir is presented. Five group control criteria are extracted from the physical, geometrical and operating conditions of the wells/reservoir. These are the target rate, weighted potential, ultimate rate and introduced nominal power of the production wells. The performance of the group control of production wells with different group control criteria is compared in three different oil production scenarios from a black-oil and highly heterogeneous reservoir.

Simultaneous hydrofracturing of multiple perforation clusters in vertical wells has been applied in the stimulation of hydrocarbon resources reservoirs. This technology is significantly impeded due to the challenges in its application to the multilayered reservoirs that comprise multiple interlayers. One of the challenges is the accurate understanding and characterization of propagation and deflection of the multiple hydraulic fractures between reservoirs and embedded interlayers.

Numerical models of the tight multilayered reservoirs containing multiple interlayers were established to study hydrofracturing of multiple perforation clusters and its influencing factors on unstable propagation and deflection of hydraulic fractures. Brittle and plastic multilayered reservoirs fully considering the influences of different in situ stress ratio and physical attributes for reservoir and interlayer strata on propagations of hydraulic fractures were investigated. The combined finite element–discrete element method and mesh refinement strategy were adopted to guarantee the accuracy of stress solutions and reliability of fracture path in computation.

Results show that the shear stress fields between adjacent multiple hydraulic fractures are superposed to cause fractures deflection. Stress shadows induce the shielding effects of hydraulic fractures and inhibit fractures growth to emerge unstable propagation behaviors, and a main single fracture and several minor fractures develop. As the in situ stress ratio increases, hydraulic fractures more easily deflect toward the direction of maximum in situ stress, and stress shadow and mutual interaction effects between them are intensified. Compared to brittle reservoir, plastic-enhanced reservoir may limit fracture growth and cannot form long fracture length; nevertheless, plastic properties of reservoir are prone to induce more microseismic events with larger magnitude.

The obtained fracturing behaviors and mechanisms based on engineering-scale multilayered reservoir may provide effective schemes for controlling and estimating the unstable propagation of multiple hydraulic fractures.

This paper seeks to add to our understanding of how entrepreneurs can build “knowledge reservoirs” to achieve competitive advantage. The study focus upon the following issues: what kind of actors can be found in various entrepreneurs' knowledge reservoirs, and what business knowledge do these actors possess.

The author employs a longitudinal case study approach, involving a sample of seven entrepreneurs in new technology‐based firms, each interviewed two times during the period from 1999 to 2001.

Evidence suggests that entrepreneurs should build knowledge reservoirs, segmented into internal, semi‐internal and external knowledge reservoirs. These reservoirs should be a means to gain competition advantage.

The conceptual model has both empirical and theoretical backing, but the empirical backing is limited to seven cases. It would be useful to test the conceptual model on larger sample sizes.

Practitioners can focus on how to build knowledge reservoirs, while the model helps to increase awareness of the holistic view of entrepreneurial knowledge and which actors can contribute to it. Policy makers should encourage entrepreneurs to build knowledge reservoirs, and support systems could require a plan for this activity before entrepreneurs get access to public funds.

The paper makes four main contributions: model generation, development of terminology, further development of the field of entrepreneurial research, and development of RBT.

The purpose of this paper is to investigate the performance of a specific class of high‐resolution central schemes in conjunction with the black oil models for hydrocarbon reservoir simulation.

A generalized black oil model is adopted, in which the solubility of gas in both oil and water and evaporation of oil are considered, leading to a system of equations prone to degeneracy. A computer code is generated and three test cases are solved to evaluate the performance of various schemes in terms of accuracy and discontinuity handling.

It is shown that, although some of the central schemes are highly sensitive to the choice of Courant‐Friedrich‐Levy (CFL) number and produce overly diffusive results, a certain type of this class is insensitive to the CFL number and can conveniently handle degenerate equations appearing in the reservoir simulation. The obtained results are compared with those available in the literature, showing merits of this class of schemes in complex reservoir simulation models.

This paper gives the one‐dimensional implementation of the above‐mentioned schemes. Extension to higher dimensional black oil model is currently under development by the authors.

The specific class of high‐resolution central schemes investigated here presents the same level of accuracy as more complicated numerical methods, yet keeping it much more simple, by avoiding Riemann solvers.

The high‐resolution central scheme used in this work has been newly developed and applied to simple scalar hyperbolic equations. It has been adopted for the black oil for the first time.

This paper is concerned with the estimation of reservoir parameters in the presence of noise and outliers using neural network (NN) and Bayesian algorithm. The paper aims to discuss these issues.

Outlier detection is of great importance to prediction of time series data. A reliable predictive methodology is proposed based on NN and Bayesian algorithm to efficiency estimates of the parameters of a petroleum reservoir. This strategy is applied to estimate the parameters of Marun reservoir located in Ahwaz, Iran utilizing available geophysical well log data.

For an evaluation purpose, the performance and generalization capabilities of Bayes-ANN are compared with the common technique of back propagation (BP).

The experimental results demonstrate that the proposed hybrid Bayes-NN algorithm is able to reveal a better performance than conventional BP NN algorithms.

Helped oil and gas companies to estimation of petroleum reservoir parameters more accurate than other methods in the presence of noise and outliers.