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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.

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.

The purpose of this paper is to present a detailed algorithm for simulating three-dimensional hydrocarbon reservoirs using the blackoil model.

The numerical algorithm uses a cell-centred structured grid finite volume method. The blackoil formulation is written in a way that an Implicit Pressure Explicit Saturation approach can be used. The flow field is obtained by solving a general gas pressure equation derived by manipulating the governing equations. All possible variations of the pressure equation coefficients are given for different reservoir conditions. Key computational details including treatment of non-linear terms, expansion of accumulation terms, transitions from under-saturated to saturated states and vice versa, high gas injection rates, evolution of gas in the oil production wells and adaptive time-stepping procedures are elaborated.

It was shown that using a proper linearization method, less computational difficulties occur especially when free gas is released with high rates. The computational performance of the proposed algorithm is assessed by solving the first SPE comparative study problem with both constant and variable bubble point conditions.

While discretization is performed and implemented for unstructured grids, the numerical results are presented only for structured grids, as expected, the accuracy of numerical results are best for structured grids. Also, the reservoir is assumed to be non-fractured.

The proposed algorithm can be efficiently used for simulating a wide range of practical problems wherever blackoil model is applicable.

A complete and detailed description of ingredients of an efficient finite volume-based algorithm for simulating blackoil flows in hydrocarbon reservoirs is presented.

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.

In reservoir history matching the least square objective function is usually used to minimize the mismatch between the predicted production data and the observations. However, as history matching is an ill-posed inverse problem with non-unique solutions, the reservoir model after calibrating may be far from the real geology model by only matching the production data. In order to solve this problem, a regularization method for reservoir history matching is implemented, in which not only the production data is matched, but prior geological information is also used to correct and update the current reservoir model so that the updated model will be consistent with the geologic model. In this paper, the simultaneous perturbation stochastic approximation method (SPSA) coupled with fast streamline simulation provides an effective method (SLSPSA) to optimize the objective function. As a stochastic approximation algorithm, SLSPSA can guarantee the convergence of the algorithm. Compared to the gradient-based algorithms, it avoids the massive calculation and storage for adjoint or sensitivity matrix. In the calculation process of algorithm, parallel computing is implemented, which reduces the simulation time and improves the computational efficiency. The method was verified by matching an example test.

Because of the increasing global oil demand, efforts have been made to further extract oil using chemical enhanced oil recovery (CEOR) methods. However, unlike water flooding, understanding the physicochemical properties of crude oil and its sandstone reservoir makeup is the first step before embarking to CEOR projects. These properties play major roles in the area of EOR technologies and are important for the development of reliable chemical flooding agents; also, they are key parameters used to evaluate the economic and technical feasibilities of production and refining processes in the oil industries. Consequently, this paper aims to investigate various important physicochemical properties of crude oil (specific gravity; American Petroleum Institute [API]; viscosity; pour point; basic sediment and water; wax; and saturate, aromatic, resins and asphaltenes components) and sandstone reservoir makeup (porosity, permeability, bulk volume and density, grain volume and density, morphology and mineral composition and distributions) obtained from Malaysian oil field (MOF) for oil recovery prediction and design of promising chemical flooding agents.

Three reservoir sandstones from different depths (CORE 1; 5601, CORE 2; 6173 and CORE 3; 6182 ft) as well as its crude oil were obtained from the MOF, and various characterization instruments, such as high temperature gas chromatography and column chromatography for crude’s fractions identification; GC-simulated distillation for boiling point distribution; POROPERM for porosity and permeability; CT-Scan and scanning electron microscopy-energy dispersive X-ray for morphology and mineral distribution; wax instrument (wax content); pour point analyser (pour point); and visco-rheometre (viscosity), were used for the characterizations.

Experimental data gathered from this study show that the field contains low viscous (0.0018-0.014 Pa.s) sweet and light-typed crude because of low sulfur content (0.03 per cent), API gravity (43.1o), high proportion of volatile components (51.78 per cent) and insignificant traces of heavy components (0.02 per cent). Similarly, the rock permeability trend with depth was found in the order of CORE 1 < CORE 2 < CORE 3, and other parameters such as pore volume (Vp), bulk volume (Vb) and grain volume (Vg) also decrease in general. For grain density, the variation is small and insignificant, but for bulk density, CORE 2 records lower than CORE 3 by more than 1 per cent. In the mineral composition analysis, the CORE 2 contains the highest identified mineral content, with the exception of quarts where it was higher in the CORE 3. Thus, a good flow crude characteristic, permeability trend and the net mineral concentrations identified in this reservoir would not affect the economic viability of the CEOR method and predicts the validation of the MOF as a potential field that could respond to CEOR method successfully.

This paper is the first of its kind to combine the two important oil field properties to scientifically predict the evaluation of an oil field (MOF) as a step forward toward development of novel chemical flooding agents for application in EOR. Hence, information obtained from this paper would help in the development of reliable chemical flooding agents and designing of EOR methods.

This paper aims to present a computationally efficient finite element model for the simulation of isothermal immiscible two-phase flow in a rigid porous media with a particular application to CO₂ sequestration in underground formations. Focus is placed on developing a numerical procedure, which is effectively mesh-independent and suitable to problems at regional scales.

The averaging theory is utilized to describe the governing equations of the involved unsaturated multiphase flow. The level-set (LS) method and the extended finite element method (XFEM) are utilized to simulate flow of the CO₂ plume. The LS is employed to trace the plume front. A streamline upwind Petrov-Galerkin method is adopted to stabilize possible occurrence of spurious oscillations due to advection. The XFEM is utilized to model the high gradient in the saturation field front, where the LS function is used for enhancing the weighting and the shape functions.

The capability of the proposed model and its features are evaluated by numerical examples, demonstrating its accuracy, stability and convergence, as well as its advantages over standard and upwind techniques. The study showed that a good combination between a mathematical model and a numerical model enables the simulation of complicated processes occurring in complicated and large geometry using minimal computational efforts.

A new computational model for two-phase flow in porous media is introduced with basic requirements for accuracy, stability, and convergence, which are met using relatively coarse meshes.

The purpose of this paper is to describe the ongoing shift in sustainable engineering and the approaches used by universities for engineering students. At the United Nations Earth Summit, in Rio de Janeiro, in 1992, participating nations agreed to work together to achieve the goal of sustainable development. Twenty years on, great progress has been made, but many challenges remain and overcoming them and ensuring a sustainable future will require the knowledge, skills and input of engineering professionals. Ethics and costs have long been part of engineering, but broader understanding is now needed because the skill set those engineers will need has grown dramatically.

In this paper, the authors describe the ongoing shift to sustainable engineering and discuss a variety of approaches that universities are currently using to introduce engineering students and practitioners to sustainability principles and practice and how those can be utilized in mining and petroleum high education institutions.

The authors first place sustainability in an engineering context and vice versa, and then review alternative approaches to incorporating sustainability in engineering curricula, briefly highlighting a few key concepts and documenting an example.

The authors first place sustainability in an engineering context and then review alternative approaches to incorporating sustainability in engineering curricula, briefly highlighting a few key concepts and documenting an example.

The challenge to educators is to ensure that new concepts addressing sustainability are not only instilled in the next generation of engineers but are also being communicated to practicing engineers. Incorporating sustainability into mining and petroleum engineering education is identified as a way to engage students, encourage their enthusiasm and interest them in pursuing engineering as a career that is not only interesting but also contributes to society. Distance education is identified as a way to education practicing engineers about sustainability concepts.

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.