Моделирование неравновесного фазового поведения углеводородных смесей О.А. Лобанова, И.М. Индрупский, ИПНГ РАН Авторское право 2015 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Российской нефтегазовой технической конференции SPE, 26 -28 октября, 2015, Москва, Россия.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами реферате. Экспертиза содержания доклада Обществом инженеров нефтегазовой промышленности не выполнялась, и внесение исправлений и изменений является обязанностью авторов. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения SPE, его должностных лиц или участников. Электронное копирование, распространение или хранение любой части данного доклада без предварительного письменного согласия SPE запрещается. Разрешение на воспроизведение в печатном виде распространяется только на реферат объемом не более 300 слов; при этом копировать иллюстрации не разрешается. Реферат должен содержать явно выраженную ссылку на авторское право SPE.

A physically-consistent method is suggested for calculation of coexistent hydrocarbon phases' compositions in flow simulations with non-equilibrium phase transitions. The method preserves standard flow terms' formulation and can be incorporated in existing commercial simulators without principal modifications to flow simulation algorithms.Through the analysis of laboratory experiments data and computational studies, we show that the necessity for non-equilibrium phase behavior model depends on simulation scale. We introduce an upscaling algorithm to estimate parameters of a non-equilibrium coarse grid model.An algorithm is proposed to calculate non-equilibrium phase compositions with desired level of non-equilibrium behavior and model different speeds of relaxation of fluids' compositions to their equilibrium states. Relaxation dynamics is determined by pressure changing rate as well as initial phase compositions and pressure. These effects are essential for consistent history matching of a flow simulation model of an oil or gas-condensate reservoir with minimal number of matching parameters.Examples of using the method to simulate non-equilibrium phase behavior of real oil and gascondensate mixtures are presented.

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The work substantiates the location of liquid hydrocarbons (LH – oil and retrograde condensate) in the dynamic, filtering part of the capacitive volumes of gas-saturated productive deposits of gas condensate and oil and gas condensate fields (GCF and OGCF). The necessity of the development and bench modeling of the production of LH from gas-saturated deposits of GCF and OGCF in the late stages of field development is shown due to the high geological reserves of LH in them and the need to develop them with the aim of component recovery increasing and extending the life of the fields. The experience of bench modeling on the experimental installation of the life cycle of the oil and gas condensate system of the Vuktyl OGCF for the period of its development on the “depletion” mode is described. On the basis of a highly permeable core model, a simulation of the initial fluid saturation was successfully held which fits the initial state of the reservoir system of the Vuktyl OGCF, including the LC (reservoir oil), and also the current thermobaric state and fluid saturation of the reservoir system were simulated. The total mass of LH (reservoir oil and retrograde condensate) in the reservoir model is determined which can be taken as a basis for calculating the LH extraction rate while carrying out further research on bench modeling of LH production technologies in the late stages of Vuktil field development on the core model created. As a result of the works described above, an oil and gas condensate system was created in a highly permeable bench core model which is the model of depleted to maximum condensation pressure reservoir of Vuktyl OGCF.

Comprehensive geological analysis at the stage of 3D geological modeling is necessary to obtain a high-quality flow model. The next important step is history matching to dynamic well data without distortion of the initial geological basis of the model. It is necessary to preserve static data on facies indexes, porosity and other parameters in the well gridcells, adjusting their distributions in the inter-well space, while maintaining the geological concepts of the object. The purpose of the study presented in this paper was the development of automated computationally efficient algorithms for solving this problem. Earlier, based on the computationally efficient adjoint methods, we developed algorithms and their implementation in the in-house SimMatch® simulator for geologically consistent history matching with identification of parameters of the variograms and porosity-to-permeability relations for a given distribution of facies in the inter-well space. In this study, we make transition from the discrete representation of facies at wells to the continuous values in the inter-well space reflecting the fractional contribution of the facies in the formation of model cell properties. Considering implicit parametric dependencies on static data at wells and variogram parameters for properties and facies, a computationally efficient algorithm was developed for consistent adjustment of the distributions of facies and reservoir properties during history matching of the 3D model. The algorithms developed are implemented within the frameworks of the forward and inverse problems. In the forward problem, a distribution of a continuous facies parameter is constructed, taking into account well data and the variogram for the facies. In current implementation, the continuous "facie" value is interpreted as being transitional (weighted) between the adjacent integer values, which is typical for geological environments with sequential change of facies usually modeled by methods such as the truncated Gaussian simulation. Further, for each facie, distribution of the reservoir parameters (porosity, permeability) is independently constructed, taking into account the variogram for porosity and the porosity-to-permeability relation for this facie. The resulting property value in each cell is determined by weighing by the portions of the "pure" facies. Within the framework of the inverse problem, the parameters of anisotropic variograms for the facies and for the reservoir properties within each facie, as well as the coefficients in the porosity-to-permeability relation for each facie, serve as the control parameters. For efficient implementation of the automated gradient procedure for adjustment control parameters, the adjoint problem is solved at each iteration, and the object function gradient with respect to the control parameters is calculated taking into account the implicit dependencies of the reservoir properties in the model cells on the variogram parameters for the facies and reservoir properties. The results of approbation of the approach on a realistic example of the 3D reservoir model and on a 3D model of a real deposit section are presented. During the study, effecient algorithms for consistent adjustment of the facies and reservoir properties distributions in a 3D model were for the first time constructed on the basis of adjoint methods and implemented in the in-house simulator. The advantage of the approach is the significant reduction in computational costs (number of simulator runs) for solution of the inverse problem in comparison with alternative methods of automated history matching, while preserving the consistency of the facies and reservoir properties distributions with the original principles of the geological model construction.