Oil Reservoir Model Research Articles

A NEW APPROACH OF COMPOSITIONAL SIMULATION FOR A VOLATILE OIL RESERVOIR MODELING

This paper proposes a new compositional simulation approach for a volatile oil reservoirmodelling. The proposed formulation has an implicit equation for the oil-phase pressureand water saturation, an explicit equation for the hydrocarbon saturation, and explicitequation for the overall composition of each hydrocarbon component that satisfiesthermodynamic equilibrium. An Equation of State for phase equilibrium and property calculationsis used in this new formulation. Interfacial tension effects are included in thisapproach to characterise the thermodynamically dynamic nature of the relative permeability.A two-dimensional relative permeability algorithm is included which handles lumpedhydrocarbon phase hydrocarbon phase as well as individual phase flows. For each gridblock two equations are required, namely total hydrocarbon and water-phase flow equations.These equations are highly non-linear and they are linearised by using Newton-Raphson method. The resulting equations are solved by an efficient Conjugate Gradientbased iterative technique to obtain pressures and saturations simultaneously, and hydrocarbon-phase saturations are deduced from their respective equations.The new compositional simulation approach is validated through analytical and numericalmethods. It is demonstrated in this present paper that the results are comparedfavourably with analytical techniques and published numerical results. They also confirmthat the proposed codified formulation is unconditionally stable and it is as stable as fullycompositional model yet the computational cost reduction was substantial.

A proposal for reservoir geostatistical modeling and uncertainty analysis of the Curimã Field, Mundaú Sub-Basin, Ceará Basin, Brazil

Geological modeling represents one of the most important phases in reservoir characterization, in terms of workload, uncertainties and impact on final results. Modeling of oil reservoirs consists of the construction of the structural, stratigraphic, and petrophysical models; the calculation of the volume of oil in place; and the analysis of uncertainties. This study integrates reservoir data obtained from a variety of disciplines (geophysics, petrophysics, sedimentology, geology, and engineering), with the purpose to build a reliable geological reservoir model. To better represent the reservoir heterogeneities and integrate geological concepts and observations, geostatistical principles were applied to geological modeling. Therefore, the main objective of this study is to characterize the geometry and petrophysical properties of the Curimã Field, a deltaic reservoir in the Paracuru Formation of the Mundaú sub-Basin (Ceará Basin), using advanced geostatistics in order to evaluate the uncertainties of the reservoir volume. The integration of reliable data using geostatistical techniques to simulate reservoir properties provided a reliable geological model that matches, in terms of original volume in place, with that published by the Brazilian National Agency of Oil, Natural Gas and Biofuels (ANP). In addition, the sensitivity and uncertainty analysis of the variables used to build the geological model allowed to rank them according to their impact on the volume calculation - thus, from greatest to the lowest impact: i) the porosity cutoff for the NTG calculation; ii) the mean porosity value for sandstones; iii) the depth of water-oil contact. The final results were based on the analysis of 500 simulation runs and generated pessimistic and optimistic probabilistic scenarios (P10, P50, and P90) of the volume in place. These results will aid a detailed dynamic assessment of the exploitation potential of the Curimã Field.

Construction of Comprehensive Geological Model for an Iraqi Oil Reservoir

The paper generates a geological model of a giant Middle East oil reservoir, the model constructed based on the field data of 161 wells. The main aim of the paper was to recognize the value of the reservoir to investigate the feasibility of working on the reservoir modeling prior to the final decision of the investment for further development of this oilfield. Well log, deviation survey, 2D/3D interpreted seismic structural maps, facies, and core test were utilized to construct the developed geological model based on comprehensive interpretation and correlation processes using the PETREL platform. The geological model mainly aims to estimate stock-tank oil initially in place of the reservoir. In addition, three scenarios were applied based on sensitivity and uncertainty of five variables to determine an accurate estimation of stock-tank oil initially in place of the reservoir. The oil-water contact appeared to be the major uncertain parameter for stock-tank oil initially in place estimation because the available geological and field data was not enough to demonstrate it confidently, and only 13% of the total wells have penetrated the water zone in the Mishrif formation. The results of all scenarios indicate that the reservoir has huge stock-tank oil initially in place. The importance of developing this oilfield is validated by its very high stock-tank oil. This is where the value of this study becomes obvious.

Stochastic-based liquid apparent permeability model of shale oil reservoir considering geological control

Shale is a complex porous medium composed of organic matter (OM) and inorganic minerals (iOM). Because of its widespread nanopores, using Darcy’s law is challenging. In this work, a two-fluid system model is established to calculate the oil flow rate in a single nanopore. Then, a spatial distribution model of shale components is constructed with a modified quartet structure generation set algorithm. The stochastic apparent permeability (AP) model of shale oil is finally established by combining the two models. The proposed model can consider the effects of various geological controls: the content and grain size distribution of shale components, pore size distribution, pore types and nanoconfined effects (slip length and spatially varying viscosity). The results show that slip length in OM nanopores is far greater than that in iOM. However, when the total organic content is less than 0.3 ~ 0.4, the effect of the OM slip on AP increases first and then decreases with the decrease in mean pore size, resulting in that the flow enhancement in shale is much smaller than that in a single nanopore. The porosity distribution and grain size distribution are also key factors affecting AP. If we ignore the difference of porosity between shale components, the error of permeability estimation is more than 200%. Similarly, the relative error can reach 20% if the effect of grain size distribution is ignored. Our model can help understand oil transport in shale strata and provide parameter characterization for numerical simulation.

Nonuniform grid upscaling method for geologic model of oil reservoir: A case study of the W block in the northern part of the Songliao Basin

At present, uniform upscaling division methods are routinely used to upscale geologic model grids, resulting in overly fine grids in some areas of the model. To improve computational efficiency, we have examined the effect of model upscaling with different upscaling parameters with the goal of producing a nonuniform grid with uniform accuracy. We based our nonuniform upscaling grid method on geologic characteristics including reservoir thickness, physical properties, reservoir spacing, and water flooding. Most of the logging curves of thin reservoirs are finger-like, allowing us to define the grid size according to the reservoir thickness. We use two different strategies to discretize uniform and composite reservoirs and represent reservoir thickness that exhibit bell- and funnel-shaped logging curves. Although one grid point accurately represents a uniform reservoir, we find that composite reservoirs require four or five points to accurately represent the physical properties of a composite reservoir. For the thick reservoirs (>5 m) with box- or composite-type logging curves, the physical properties inside the reservoir do not change much; therefore, we use a grid point to represent the reservoir thickness information. Using these metrics, we constructed alternative “moderate” and “efficient” vertical grid upscaling strategies. Taking the 15 sedimentary units with a total thickness of 72 m as an example, the statistical results show that the computational efficiency using our data-adaptive grid can be increased more than five times compared to the traditional uniform fine-grid method while retaining the same accuracy.

Characterization and development of marine natural gas hydrate reservoirs in clayey-silt sediments: A review and discussion

As a promising substitute for conventional fossil fuels with huge reserves, clayey-silt natural gas hydrate has been proved to be widely distributed in the continental margins of the marine environment. Characterization and development of this kind of natural gas hydrate reservoirs face unique challenges, compared with that of natural gas hydrate in marine sandy sediments. This review summarizes the basic methods for natural gas hydrate reservoir characterization and development, and discusses the applicability of these methods in marine clayey-silt natural gas hydrate reservoirs. Feasibilities of classical oil and gas reservoir characterization methods and models applied to hydrate-bearing stratum remain elusive, let alone clayey-silt hydrate deposits. Current natural gas hydrate development methods are restricted by low gas productivity, potential geomechanical instability, and extremely high costs. Economically feasible technologies considering the influences of geotechnical issues are needed for the commercialization of natural gas hydrate contained in clayey-silt sediment. Cited as : Li, Y., Liu, L., Jin, Y., Wu, N. Characterization and development of natural gas hydrate in marine clayey-silt reservoirs: A review and discussion. Advances in Geo-Energy Research, 2021, 5(1): 75-86, doi: 10.46690/ager.2021.01.08

3D-Printing Replication of Porous Media for Lab-Scale Characterization Research.

Simplifying fluid-flow physics in conventional reservoirs is convenient by assuming uniform lithology and system-geometry with minimal rock/hydrocarbon interactions. Such simplification restrains mathematical models’ ability to simulate unconventional reservoirs’ actual flow behavior and production performance. Researchers can achieve precise adaption for the physics of fluid flow in porous media if they geometrically characterize the system under study appropriately, and there are minimal interactions indeed. 3D-printed replicas of porous-rock samples obey this criterion. In this work, we used image-processing tools used for creating presentable porous and permeable replicas of different scales and configurations of the petroleum system from lab-scale to field-scale. The workflow of 3D-printed replicas creation is presented for replicas of conventional core samples, naturally and synthetically fractured cores, geological drilling units of multistage fractured horizontal wells, and full-field models, e.g., Norne field in Norway. These samples are ideal for experimentally testing the validity of the analytical or numerical models of oil and gas reservoirs in the laboratory, along with judging the quality of reservoirs’ characterization. These replicas’ ideality of these results from limited uncertainties of the geometry of the system under study and fluid/rock interactions because of the uniform composition. For validation purposes, 3D-printed replicas with different materials and 3D-printing technologies were created based on a reconstructed image-processed CT scan of their original Berea sandstone. These replicas were tested for storage capacity (porosity) and transport capacity (permeability) and compared with their original sample’s capacities. The matched results proved replicas’ ability to be used in oil and gas laboratory experimental research.

The design of high-viscosity oil reservoir model based on the inverse problem solution

We propose an approach to the solution of the automatic history-matching problem for constructing models of high-viscosity oil reservoirs. It is based on a special parameterization of the reservoir model with the use of not only the physical but also the geometric parameters and minimization of the functional of residual between observed and computed data of cumulative oil production, bottomhole pressure, oil rate, water and oil cut. In order to obtain physically reasonable values of parameters and reduce the number of iterations when solving the inverse problem, the adaptive regularization is used. We use the finite element method on non-conforming meshes with hexahedral cells to solve the forward problem. The forward problem solution is verified by comparison with the results presented in the 10th SPE Comparative Solution Project. The applicability and effectiveness of the proposed approach are demonstrated on the simulated and real field data obtained on the site of one of the high-viscosity oil fields. Using the simulated data obtained for the complex realistic petroleum reservoir model, we show that the proposed approach allows us to obtain distributions of absolute permeability, porosity, and oil in the reservoir volume as well as to estimate oil reserves and their changes with time. The results of numerical experiments performed using the real field data show that the approach proposed for the history-matching problem solution enables us to make reliable production forecasts. In the forecast period, the deviations of the predicted total oil production from the observed one do not exceed 1.5%.

APPLICATION OF A MULTIDIMENSIONAL DETERMINISTIC-STATISTICAL NUMERICAL CORRELATION MODEL TO REFINE THE STRUCTURE OF THE AS11 HORIZON OF THE ZAPADNO-KAMYNSKOYE FIELD

One of the primary and significant tasks in the construction of geological models of oil and gas reservoirs and development facilities is the problem of correlation of productive layers. This task, as a rule, is reduced to the identification and areal tracing of presumably even-aged oil and gas strata, horizons, and layers characterized by clear boundaries between sand strata and clay layers overlapping them. The practice of work related to modeling the structure of oil and gas horizons, layers and strata indicates that the correlation is not always unambiguous. The ambiguity is especially noticeable when correlating strata characterized by a clinoform structure, one of the examples is the Achimov strata. The most reliable basis for well correlation is GIS materials and lithological features of the interlayers forming individual layers. Clay interlayers and clay strata separating productive deposits provide valuable information when choosing a correlation model in sedimentary sections. These interlayers are characterized by the greatest consistency in area and are most clearly displayed on geophysical diagrams by the nature of the drawings of GIS curves. However, even in this case, i. e. when using the entire accumulated volume of the most diverse lithological and field-geophysical information, the correlation models of the sections turn out to be different and often even opposite. In this paper, the authors had to face a similar situation when correlating the horizon AS11 of the Zapadno-Kamynskoye field. The paper describes a method for clarifying the position of the chops of the productive horizon of oil and gas deposits using a multidimensional deterministic-statistical numerical model of the correlation of sedimentary strata. The proposed approach allows us to uniquely determine the positions of the chops in the conditions of a complex geological structure of the object, high thin-layered heterogeneity. A concrete example shows the advantages of the proposed approach in comparison with the traditional one.

Deciphering the Reservoir Rocks Lithology by Mineralogical Investigations Techniques for an Oilfield in South-West Romania

An important element of the geological modeling of oil reservoirs is represented by determining of the mineralogical composition and rock types as part of the reservoir characterization process. In the paper we provide a comprehensive mineralogo-petrographic study based on petrographic observations and X-rays diffraction investigations made on several Miocene rock samples collected in the wells spudded in an oil field belonging to the Getic Basin. Getic Basin is a prolific petroleum province in Romania and belongs to petroleum systems of the Carpathian Foredeep. The oil exploration in the Getic Basin started more than 100 years ago and resulted in thousands of wells drilled and tens of fields discovered. The oil field is located in the Gorj County, geologically belongs to the internal zone of the Getic Basin, and is a faulted anticline with hydrocarbon accumulations in Burdigalian and Sarmatian deposits. The petrographic study led to the interpreting of the rock samples analyzed as epiclastic sedimentary rocks represented by conglomerates, breccias, sands, sandstones, claystones and marlstones, and carbonate rocks (limestones). X-rays diffraction investigations indicated the phyllosilicates (smectite and illite) as main minerals in the Sarmatian samples, while in the Burdigalian samples were found as main minerals: quartz, feldspars and carbonate minerals. The paper provides detailed information (like petrographic types, composition and microtexture) on the Miocene reservoir rocks belonging to the Getic Basin. Also the data obtained may be used as basis for future reservoir modeling studies in the region.

An Experimental Device for Studying the Solubility of Carbon Dioxide in Hydrocarbons in Wide Ranges of Working Temperatures and Pressures

A device was designed to measure the solubility of carbon dioxide in hydrocarbons at temperatures up to 473 K and pressures up to 25 MPa. It can be used to study the solubility of CO2 at state parameters that are supercritical for CO2 in the presence of a porous medium in the oil reservoir model and in the absence of it. The results of the experiments on measuring the solubility of carbon dioxide in kerosene are described using the Peng–Robinson equation of state. This technique for measuring the solubility both of CO2 in a hydrocarbon and of a hydrocarbon in CO2 in the mode of dynamic filtration in a porous medium can be applied in power engineering and machine building to study changes in the thermophysical and physicochemical properties of hydrocarbons.

Petroleum geological characteristics and hydrocarbon accumulation patterns in the Melut Basin, South Sudan

The Melut Basin is a passive rift basin controlled by the Central African Shear Zone (CASZ), which contains numerous oil-rich rift sub-basins. After 20 years of large-scale hydrocarbon exploration, it has become increasingly difficult to find new discoveries, and it is necessary to deepen the understanding of petroleum geology, identifying new hydrocarbon accumulation patterns and establishing typical oil reservoir models to promote the future exploration in the Melut Basin. In the north Melut Basin, the far-source migration and accumulation pattern has been identified for the Paleogene main producing layer, which provided more than 95% oil reserves in the past years. For the Paleogene far-source accumulation pattern, the capability of hydrocarbon charge from the Al Renk source rocks and the development of oil-source faults connecting Al Renk source rocks and Paleogene reservoir rocks determine if the Paleogene traps can accumulate hydrocarbon. Using the model of the far-source accumulation pattern, numerous oil reservoirs have been discovered in the north Melut Basin, including the world-class Palogue oilfield. In addition to the Paleogene far-source accumulation pattern, three new near-source accumulation patterns have been identified in the Cretaceous, including the accumulation pattern of Galhak Formation, the accumulation pattern of Al Gayger Formation, and the accumulation patter of Al Renk Formation. Meanwhile, the typical oil reservoir models have been established for each near-source accumulation pattern. These new accumulation patterns and corresponding typical oil reservoir models should promote the exploration of the Cretaceous sequence in the Melut Basin. Compared to the north Melut Basin, the sub-basins in the south Melut Basin have smaller areas and coarser siliciclastic sediment infillings, which make the quality of Adar caprocks worse. Consequently, the Paleogene reservoir (Yabus and Samma Formations)-caprock (Adar Formation) pair is not an effective petroleum system combination in the south Melut Basin, and the near-source Cretaceous has better exploration potential. Affected by the movement of the East African Rift System in Paleogene, the Melut Basin widely developed inversion structures with numerous uplifts and faulted blocks, which provide good trap conditions for hydrocarbon accumulation. Three types of inversion structures have been identified, including the inner-basin inversion structures, the basin-margin inversion structures, and the inversion structures between sub-basins. The inner-basin inversion structures and the inversion structures between sub-basins have better oil-source and trap conditions and are important oil-bearing structures. However, the basin-margin inversion structure has big oil-source risk due to the long-distance migration from the basin center. The inversion movement makes the Cretaceous and basement shallower and therefore greatly increases the exploration potential of deep formations.

An experimental study on volumetric visualization of black oil reservoir models

Volume rendering techniques are essential to inspect volume data. In this work, we consider volume rendering for unstructured meshes. We focus on the visualization of black oil reservoir simulation models, represented by irregular hexahedral meshes with geometry distortions and discontinuities. We conduct an experimental study comparing three different strategies to compute the volume integration. The first strategy resamples the model in a regular grid; the second linearizes the model geometry and the variation of the scalar field within a hexahedron cell; the third uses an accurate evaluation of the scalar field at each sample. We compare performance and image quality delivered by each strategy by running a set of experiments with different models. We also investigate the gain in perception applying directional ambient occlusion shading effects. All strategies were entirely implemented on the graphics card.

Contourite vs Turbidite Outcrop and Seismic Architectures

The hydrocarbon exploration of oceanic depositional systems demands a better understanding of the role of bottom currents and their implications for petroleum systems such as reservoir and sealing rocks. Deep-marine bottom-current reworked sands (sandy contourites) have been recognized in hydrocarbon-bearing sands of the Kwanza Basin. Such understanding implies additional alternatives for the definition of exploration targets and prospect risk reduction. The southernmost part of the Kwanza Basin (Miradouro da Lua zone) comprises one of the best outcrops of contourites deposits, formed during the Miocene and Pliocene age. Laterally, coeval sandy deposits are found offshore Kwanza Basin along the continental margin, and have been one of the great challenges for the oil companies operating in Angola. Therefore, the aim of the current proposal is to characterize sandy contourite deposits at Miradouro da Lua and compare them with offshore deep-water sandy deposits, evaluating their conceptual and economic implication. Modern field sedimentology technique merged with reflection seismic data and other geographic information system (GIS) techniques, allow the characterization and proposal of a stratigraphic architecture diagram that explains the interaction of the deep-marine processes, especially gravitational (down-slope) and bottom current (along-slope) processes as well as its vertical and spatial association. Sonangol (Angolan State Oil Company) and Total (French Multinational Company) explore similar deposits in Block 48 in Ultra deep-sea, and they will also reactivate the exploration of the Iabe Formation in Block 4. The Tertiary Stratigraphic Architecture in Blocks 6, 7, 8, 19 and 20 are similar to the Lower part of the Miradouro da Lua zone. All these observations and data are very important to calibrate oil reservoir models.

Multiresolution Grid Connectivity-Based Transform for Efficient History Matching of Unconventional Reservoirs

Summary Proper characterization of heterogeneous rock properties and hydraulic fracture parameters is essential for optimization of well spacing and reliable estimation of estimated ultimate recovery (EUR) in unconventional reservoirs. High resolution characterization of matrix properties and complex fracture parameters require efficient history matching of well production and pressure response. We propose a novel reservoir model parameterization method to reduce the number of unknowns, regularize the ill-posed problem, and enhance the efficiency of history matching of unconventional reservoirs. The proposed method makes a low-rank approximation of the spatial distribution of reservoir properties taking into account the varying model resolution of the matrix and hydraulic fractures. Typically, hydraulic fractures are represented with much higher resolution through local grid refinements compared to the matrix properties. In our approach, the spatial property distribution of both matrix and fractures is represented using a few parameters via a linear transformation with multiresolution basis functions. The parameters in transform domain are then updated during model calibrations, substantially reducing the number of unknowns. The multiresolution basis functions are constructed by using Eigen-decomposition of an adaptively coarsened grid Laplacian corresponding to the data resolution. Higher property resolution at the area of interest through the adaptive resolution control while keeping the original grid structure improves quality of history matching, reduces simulation runtime, and improves the efficiency of history matching. We demonstrate the power and efficacy of our method using synthetic and field examples. First, we illustrate the effectiveness of the proposed multiresolution parameterization by comparing it with traditional methods. For the field application, an unconventional tight oil reservoir model with a multistage hydraulic fractured well is calibrated using bottomhole pressure and water cut history data. The hydraulic fractures as well as the stimulated reservoir volume (SRV) near the well are represented with higher grid resolution. In addition to matrix and fracture properties, the extent of the SRV and hydraulic fractures are also adjusted through history matching using a multiobjective genetic algorithm. The calibrated ensemble of models are used to obtain bounds of production forecast. Our proposed method is designed to calibrate reservoir and fracture properties with higher resolution in regions that have improved data resolution and higher sensitivity to the well performance data, for example the SRV region and the hydraulic fractures. This leads to a fast and efficient history matching workflow and enables us to make optimal development/completion plans in a reasonable time frame.

A mathematical model of the non-stationary filtration process for oil-supercritical CO2 system in a homogeneous porous medium under various modes of oil displacement

The phase diagram of the system “transformer oil-supercritical CO2” is built. The modes of miscible and microbubble displacement of oil are determined. Oil was displaced by carbon dioxide in a supercritical state on isotherms 313 and 333 K in the pressure range up to 12 MPa at the experimental bench created by the authors. New data have been obtained on the coefficient of oil displacement by supercritical CO2 from a model of a homogeneous oil reservoir in a miscible and micro-bubble mode of supercritical CO2 filtration. It was revealed that the miscible regime of oil displacement by supercritical CO2 has the greatest technological efficiency. For the region of a mixed filtration regime, a mathematical model was created and solved for the process of filtering the unsteady flow of “supercritical CO2-oil” in a homogeneous terrigenous porous medium in the pressure range up to 12 MPa, temperatures up to 333 K, the calculated curve agrees with the experimental data on the oil displacement coefficient. The convergence and stability of the difference scheme of the computational process is ensured. It was found that in the transition region of supercritical CO2 filtration on the boundary curve in the phase diagram and in the region of microbubble filtration of supercritical CO2, the process of oil displacement is more intense, which is associated with the appearance of a supercritical sublayer on the pore surface, which leads to slipping of the fluid inside the pore. For the transition-filtering region on the boundary curve in the phase diagram and in the region of the microbubble displacement of oil by supercritical carbon dioxide, a method for increasing technological efficiency is proposed based on the injection of supercritical CO2 and water rims to prevent the transition of microbubble carbon dioxide to the free phase.

Integrated multi-scale reservoir data representation and indexing for reservoir data management and characterization

Single-scale models cannot satisfy the requirements of oil reservoir researchers. The management of multi-scale data is thus important to ensure appropriate representation of geological structures and reservoir characterization. However, existing methods generally focus on two-dimensional maps. Moreover, existing multi-scale models and 3D indexing methods are not completely suitable for organizing and managing oil reservoir data; the relationship between spatial objects and the heterogeneity in spatial variations are not considered. To address this issue, this study aimed to develop a multi-scale oil reservoir model from the finest existing reservoir model, establish the relationship between models of different scales, and integrate multi-scale oil reservoir models. This paper proposes a multi-scale tree representation and generation method, based on corner point grid(CPG), that integrates multi-scale reservoir model representation and a spatial index. Experiments on integrated indexing and rendering were performed using the proposed method, and its performance was then evaluated via comparisons with existing methods. The results showed that the proposed integrated indexing method is significantly faster than one that does not use vertical geologic layer indexing. In addition, the proposed algorithm required much less time to render geological objects than a popular program and also performed operations such as translation and rotation more rapidly. Overall, the proposed algorithm allowed for efficient querying and visualization of arbitrary layers at arbitrary scales and regions.

ОПРЕДЕЛЕНИЕ И ХАРАКТЕРИСТИКА КОЭФФИЦИЕНТА СВЯЗНОСТИ КОЛЛЕКТОРА ГЕОЛОГО-ГИДРОДИНАМИЧЕСКИХ МОДЕЛЕЙ НЕФТЕГАЗОВЫХ ЗАЛЕЖЕЙ

Актуальность исследования обусловлена необходимостью количественной оценки связности коллектора геолого-гидродинамических моделей для классификации реализаций при многовариантной оценке неопределенностей и оптимизации выбора метода и параметров моделирования куба песчанистости. Цель: ввести понятие коэффициента связности коллектора, оценить репрезентативность предложенного параметра для моделей залежей различной детальности и геометрии; оценка влияния параметров неоднородности геологических моделей на коэффициент связности. Объекты: геолого-гидродинамические модели залежей нефтегазовых месторождений. Методы: геологическое и гидродинамическое моделирование, статистический анализ результатов геологического и гидродинамического моделирования. Результаты. Кратко рассмотрены существующие методы оценки связности коллектора в геолого-гидродинамических моделях, используемые для оценки ресурсов углеводородного сырья и выбора наиболее эффективных методов их разработки. На основе проведенного авторами анализа был предложен новый подход к определению параметра связанности как отношения перетока жидкости в исследуемой модели к модели с единичной песчанистостью. Рассмотрено влияние геометрии и детальности геолого-гидродинамических моделей на величину коэффициент связности. На примере синтетических стохастических моделей рассмотрены зависимости коэффициента связности от таких параметров, как песчанистость, ранги вариограмм, их анизотропия и эффект самородка. Введено понятие коэффициента гидродинамической связности коллектора, который характеризует способность модели фильтровать флюид, без учета влияния фильтрационно-емкостных характеристик. Этот параметр учитывает только распределение коллектора в объеме залежи и то, как ячейки коллектора расположены друг относительно друга. Предложенный способ расчёта позволяет оценить анизотропию перетоков флюида между ячейками по различным направлениям и оценить способность модели фильтровать этот флюид через себя. Коэффициент связанности, в отличие от перколяционных методов, позволяет получать непрерывную оценку гидродинамической связи между ячейками, не требует обязательного наличия истории работы залежи и не зависит от текущей системы разработки, реализуемой на месторождении.

Литолого-петрофизическое моделирование нефтегазоносных резервуаров терригенных отложений (на примере Северо-Лиманского месторождения)

Литолого-петрофизическое моделирование нефтегазоносных резервуаров терригенных отложений (на примере Северо-Лиманского месторождения)

Relationship between well pattern density and variation function of stochastic modelling and database establishment

For 3D geological modelling of oil and gas reservoirs, well pattern density is directly related to the number of samples involved in the calculation, which determines the variation function of stochastic modelling and has great impacts on the results of reservoir modelling. This paper focuses on the relationship between well pattern density and the variogram of stochastic modelling, selects the large Sulige gas field with many well pattern types as the research object, and establishes a variogram database of stochastic models for different well pattern densities. First, the well pattern in the study area is divided into three different types (well patterns A, B, and C) according to well and row space. Several different small blocks (model samples) are selected from each type of well pattern to establish the model, and their reasonable variogram values (major range, minor range and vertical range) are obtained. Then, the variogram values of all model samples with similar well pattern densities are analysed and counted, and the variogram database corresponding to each type of well pattern is established. Finally, the statistical results are applied to the modelling process of other blocks with similar well pattern density to test their accuracy. The results show that the reservoir model established by using the variation function provided in this paper agrees well with the actual geological conditions and that the random model has a high degree of convergence. This database has high adaptability, and the model established is reliable.