Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad Sami (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
A fully-implict mimetic finite difference method (MFD) for fractured carbonatereservoir simulation is presented. MFD, as a novel discritization, has been applied to many fields due to its local conservativeness and applicability of any shape of polygon. Here we extend it to fractured reservoirs. Our scheme is based on MFD method and discrete fracture model (DFM). This scheme supports general polyhedral meshes, which gives an advantage for reservoir simulation application. The principle of the MFD method and the corresponding numerical formula for discrete fracture model are described in details. In order to assure flux conservation, fully implicit method is employed. We test our method through some examples to show the accuracy and robustness.
Acidizing in un-fractured carbonate reservoirs has been well studied through modeling and simulation. Since carbonate reservoirs are often naturally fractured, fractures should be modeled for realistic acidizing operations. We present adaptive enriched Galerkin (EG) methods to simulate acidizing in fractured carbonate reservoirs. We adopt a two-scale continuum model for the acid transport. The coupled flow and reactive transport systems are spatially discretized by EG methods. Fractures are introduced using local grid refinement (LGR) technique. Adaptive mesh refinement (AMR) is implemented around wormhole interfaces. Simulation results show that acidizing in fractured carbonate reservoirs is largely dependent on the fracture system while acidizing in unfractured carbonate reservoirs is mainly determined by operation parameters such as acid injection rate. Computationally, the proposed EG scheme has less numerical dispersion and grid orientation effects than standard cell center finite difference/volume methods. AMR is very efficient to track the wormhole growth and speed up acidizing simulations.
Wu, Yonghui (China University of Petroleum, Beijing) | Cheng, Linsong (China University of Petroleum, Beijing) | Huang, Shijun (China University of Petroleum, Beijing) | Fang, Sidong (Sinopec Petroleum Exploration and Production Research Institute, Beijing) | Jia, Pin (China University of Petroleum, Beijing) | Wang, Suran (China University of Petroleum, Beijing)
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 design process of carbonate matrix acidizing treatments requires coring and conducting linear, radial core-flood experiments. With the current environment revolving around cutting costs, it becomes increasingly more important to accurately design cost effective acidizing treatments. This work aims to introduce a novel approach to predicting the performance of acid treatments in the field using log data only. A radial reactive flow simulator, using porosity distributed from logs, is utilized to provide accurate predictions without the need for experiments.
Core-flood acidizing experiments at two temperatures (150 and 200°F) with two acid concentrations were studied. A reactive flow simulator was built using porosity distribution derived from computed tomography (CT) scan and tuned to match experimental data. A new radial simulation model of 3.25 ft. radius was utilized to study acid propagation under field conditions. For accurate predictions, porosity was distributed using cores CT scan derived values. Simulation results were compared with traditional 1-D models. Different porosity distributions, including gamma distributions, were used in the radial model.
The reactive flow simulator was able to accurately capture wormhole propagation inside the linear core. A greater than 90% match between experimental and simulated acid pore volume to breakthrough (PVBT) was obtained using two different temperatures and acid concentrations. The simulation results from the radial field scale model show that the optimum velocity can be higher or lower than those predicted from lab experiments. Accordingly, caution must be taken when linear core flood data is used to predict acid propagation in the field. The simulations showed that traditional upscaling models overpredict acid volumes, as the predicted volumes are double at moderate to high injection rates. Models using statistically distributed porosity can provide accurate acid propagation predictions, with a relative percentage error less than 25% at extremely high injection rates.
This work introduces an accurate model using porosity directly from logs to predict acid performance while avoiding expensive designs. The simulation results revealed that traditional designs overpredict acid volumes required for field treatments. The statistically distributed porosity can be used as a substitute for CT scan derived porosity with low effect on model predictability. The reactive flow simulator can accurately match experimental data.
Wang, Min (Texas A&M University) | Wei, Chenji (Research Institute of Petroleum Exploration & Development, PetroChina) | Song, Hongqing (University of Science and Technology Beijing) | Efendiev, Yalchin (Texas A&M University) | Wang, Yuhe (Texas A&M University)
In this paper, we couple Discrete Fracture Network (DFM) and multi-continuum model with Generalized Multiscale Finite Element Method (GMsFEM) for simulating flow in fractured and vuggy reservoir. Various scales of fractures are treated hierarchically. Fractures that have global effect are modeled by continua while the local ones are embedded as discrete fracture network based on the geologic observation. For independent vugs, a continuum is used to represent their effects with specific configuration that there's no intra-flow of this continua. GMsFEM enables us to systematically develop an approximation space that contains prominent sub-grid scale heterogeneous background information based on the multi-continuum and DFM model. Conforming unstructured mesh is used to surrender the application of random discrete fracture networks. This paper targets on the improvement of the flow simulation performance in complex high-contrast domain by extending the ability of multiscale method to modeling arbitrary discrete fracture network. This advancement by GMsFEM is motivated by the limited capability of Multiscale Finite Element Method (MsFEM) on modeling discrete fractures when multiple fracture networks present in same coarse block. Multiple numerical results are shown to validate the efficiency of our coupled method.
Kanevskaya, R. D. (BashNIPIneft LLC, RF, Ufa) | Isakova, T. G. (BashNIPIneft LLC, RF, Ufa) | Korobkin, S. V. (BashNIPIneft LLC, RF, Ufa) | Budkin, K. D. (BashNIPIneft LLC, RF, Ufa) | Markova, A. Yu. (BashNIPIneft LLC, RF, Ufa) | Lyubimova, O. V. (BashNIPIneft LLC, RF, Ufa) | Rafikov, R. Ya. (BashNIPIneft LLC, RF, Ufa)
The PDF file of this paper is in Russian.
Rock wettability and its transformation in the process of formation and development of oil deposits is a crucial factor influencing fluid content and many aspects of reservoir performance, especially during water flooding and application of enhanced oil recovery techniques. The concept of saturation of the complex carbonate reservoir with the variable wettability is presented. This concept is applied to the Kizelovsky horizon of Tuymazinskoye field. The results of analysis of the geophysical characteristics show that the cross section is divided into three geological units with significantly different values of the electrical resistivity. By means of joint analysis of core examination and geophysical well logging it is demonstrated that zones of the low-resistivity geological unit are chiefly characterized by hydrophilic type of rock wettability, while limestone of the high-resistivity geological unit – by hydrophobic. Oil saturation model is designed with the assistance of field data and core data based on the capillary gravitational equilibrium concept taking into account variable rock wettability. The results of the relative permeability experiments together with information about the initial water cut of well production, in correspondence with geological unit and perforation depth, allow to identify initial saturation distribution in reservoir. The presented approach to the creating of the saturation model enables to consider previously ignored factors that affect the efficiency of the reservoir pressure maintenance system and recovery of reserves of particular areas, such as the electrical resistivity of the geological units, the presence of bridges between them, etc. In particular, the identification of the thick lower unit with high water saturation makes it possible to explain the reasons of watering rates of the production wells. Development of detailed reservoir simulation model, that takes into account the presence of three geological units with the variable wettability, helps to clarify the distribution of oil reserves, adequately perform history matching, predict well performance and improve the recovery of reserves.
Смачиваемость породы и трансформация этого свойства в процессе формирования и эксплуатации залежей являются основополагающими фактором, влияющими на характер насыщения пласта, его поведение при заводнении, применении методов интенсификации добычи и увеличения нефтеотдачи. Предложена концепция насыщения сложного карбонатного коллектора переменной смачиваемости. Концепция рассмотрена на примере кизеловского горизонта Туймазинского месторождения. В результате анализа геофизической характеристики разреза выделены три пачки, существенно различающиеся по величинам удельного электрического сопротивления. Путем совместного анализа результатов изучения кернова и материалов геофизических исследований скважин показано, что преимущественно гидрофильный тип смачиваемости пород характерен для интервалов низкоомных пачек, а гидрофобный - для известняков высокоомной пачки. Модель нефтенасыщения построена с привлечением промысловых и керновых данных на основе концепции капиллярно-гравитационного равновесия с учетом представлений о переменной смачиваемости коллектора. Использованы также результаты лабораторных экспериментов по определению фазовых проницаемостей, которые совместно с информацией о начальной обводненности продукции скважин, привязанной к пачке и глубине расположения интервала вскрытия пласта, позволяют идентифицировать начальное распределение насыщенности. Представленный подход к построению модели насыщения турнейского объекта позволил рассмотреть не учитывавшиеся ранее факторы, влияющие на эффективность системы поддержания пластового давления и выработки запасов отдельных участков, такие как удельное электрическое сопротивление пачек, наличие перемычки между ними и др. В частности, выделение мощной нижней пачки с высокой водонасыщенностью дало возможность объяснить характер обводнения добывающих скважин. Построение детальной гидродинамической модели, учитывающей наличие трех пачек с различной смачиваемостью, позволяет уточнить распределение запасов нефти, адекватно воспроизвести историю разработки, прогнозировать поведение скважин и планировать более эффективную выработку остаточных запасов.
Sebastian Geiger, SPE, director of the Institute of Petroleum Engineering and Foundation CMG chair at Heriot-Watt University, was awarded the 2017 Alfred Wegener Award by the European Association of Geoscientists and Engineers (EAGE). The Alfred Wegener award recognizes EAGE members for outstanding contribution over a period of time to the scientific and technical advancement of one or more of the disciplines in EAGE, particularly petroleum geoscience and engineering. Geiger’s award citation mentioned his contributions to the field of carbonate reservoir modeling and simulation as head of the Carbonate Reservoir Group at Heriot-Watt, co-director of the International Centre for Carbonate Reservoirs in Edinburgh, and Foundation CMG chair in carbonate reservoir simulation. His open, accessible teaching and supervision and publication of more than 120 technical papers and an edited book were also emphasized in the citation. Geiger holds a PhD degree in computational geosciences from the ETH Zurich and an MSc degree in geosciences from Oregon State University.
Sebastian Geiger, SPE, director of the Institute of Petroleum Engineering and Foundation CMG chair at Heriot-Watt University, was awarded the 2017 Alfred Wegener Award by the European Association of Geoscientists and Engineers (EAGE). The Alfred Wegener award recognizes EAGE members for outstanding contribution over a period of time to the scientific and technical advancement of one or more of the disciplines in EAGE, particularly petroleum geoscience and engineering. Geiger’s award citation mentioned his contributions to the field of carbonate reservoir modeling and simulation as head of the Carbonate Reservoir Group at Heriot-Watt, co-director of the International Centre for Carbonate Reservoirs in Edinburgh, and Foundation CMG chair in carbonate reservoir simulation.
In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.
The pdf file of this paper is in Russian.
Reservoir studies, including preparation of field development plan, are processes typically dominated by time constraints. In general, reservoir studies consist in multiple geoscience activities integrated to build a fine geological model that eventually leads to an upscaled numerical model suitable for history matching and forecast simulations. In the simulation stage, the quality and effectiveness of the activity is highly dependent on the computational efficiency of the numerical model. This is particularly true for complex, supergiant carbonate reservoirs. Often, even with today's simulators, upscaling is still needed and simplifications can be implemented to allow computationally intensive history matching and risk analysis workflows. This paper provides some real field examples where these issues were faced and successfully managed, without applying further simplifications to the geological concept of the model: principles of reservoir simulations and common sense reservoir engineering were used to adjust properties of the model and then speed-up numerical simulation. Tuning included a combination of various solutions, such as deactivating critical cells whenever possible, calibrating convergence and time stepping control, tweaking field management to prevent instability in the computation, optimization of number of cores and cells split among cores to optimize load balancing and scalability.
These solutions were used on two super-giant carbonate fields, a triple porosity (matrix, karst and fractures) undersaturated light oil reservoir and a supercritical gas and condensate reservoir. The former field was described using an upscaled model of about 700,000 active cells and a dual porosity - dual permeability formulation; the latter was described by a relatively coarse model of about 400 thousand active cells using a single porosity formulation. Large speed-up, up to five times with respect to reference simulations, was achieved without simplifying the geology and losing accuracy perceivably. Benefits were achieved for both conventional and high-resolution simulators.