Interwell Space Research Articles

Lithofacial Zoning of Producing Horizons of Oil and Gas Fields Using Artificial Neural

The quality of an oil and gas field development project depends greatly on the accuracy of forecasting the processes that occur in the pore space of reservoirs during the extraction of hydrocarbons under certain technolo-gical conditions in production wells. The forecasting is possible if there is a geological model of the field. The more detailed the model is, the more accurate the prediction will be. The whole amount of information used to create a geological model of a field is of discrete nature, and its level of detail is determined by the number of wells that have discovered pay formations. One of the most important elements of the geological model is the nature of changes in reservoir properties of productive formations along their stretch and perpendicular to bedding. The creation of elements of this type requires information from laboratory studies of core material, interpretation of the wells logging results and methods for predicting the nature of changes in reservoir properties in the interwell space. The presence of these elements makes it possible to investigate the situation in which sedimentation (within the existing wells) took place and what types of facies the geological sections of the drilled producing intervals correspond to. Lithofacial zoning of the productive formation according to this information makes it possible to trace the regularities of distribution of facies of various types, to establish their mutual location, and accordingly to predict the nature of changes in reservoir properties in the interwell space. The lack of a sufficient amount of core material is a typical problem that makes it difficult to identify facies. There is another way to solve this problem – this is the identification of facies according to the morphology of logging curves. Nowadays, this problem is solved at a qualitative level. In this paper, it is proposed to apply a quantitative method for identifying facies using an artificial neural network. In particular, the morphology of curves is formalized by a number of parameters that form the input vector of an artificial neural network. At the output of the network, the clusters of logging curves with a similar morpho-logy are formed. The authors refer these clusters to a certain type of facies analytically. On the basis of the information obtained, lithofacial zoning of the productive formations is carried out.

Pre-Drilling Production Forecasting of Parent and Child Wells Using a 2-Segment Decline Curve Analysis (DCA) Method Based on an Analytical Flow-Cell Model Scaled by a Single Type Well

This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve).

SPATIAL VARIABILITY OF PHYSICAL AND MECHANICAL PROPERTIES OF ROCK MASS IN CENTRAL KAZAKHSTAN

The efficiency and quality of drilling and blasting operations in the development of mineral deposits largely depend on the variability of the properties of the rock mass. With a detailed study of various geological objectsmineral deposits or structural elements of the earth’s crust of any order, up to a single layer or block, it is possible to create three-dimensional digital models. The article considers the possibility of spatial variability of rock mass properties in Central Kazakhstan by means of mathematical modeling using data from the drilling process control file of the Aquila system of a DH-M drilling rig. To assess the structure and condition of the rock mass, it was constructed two-dimensional sections digital model, which shows the spatial variability of physical and mechanical properties. A pseudolinear approximation between the file vectors is chosen as a method for constructing twodimensional sections. The application of the mathematical method of pseudo-linear interpolation is shown, which allows with a sufficient degree of reliability to evaluate the physical and mechanical properties (PMP) of the rocks in the inter-well and inter-interval space of the rock mass. Based on the results of the study, the software was developed that provides an operational and effective assessment of the physical and mechanical properties of the rock mass with the visualization of the result. The developed approach and software can be used to improve the efficiency of drilling and blasting operations of existing mining enterprises, as well as in the implementation of scientific and industrial research on mathematical modeling of state of the rock mass.

Displacement of Viscous Fluids in a Set of Parallel Pipes

The process of pumping water in a formation filled with a more viscous fluid is considered using the simplest model of the interwell space described by a set of parallel pipes. The fluids are assumed to be immiscible with a sharp interface in each pipe. The main task is to recover the parameters of the interwell space from a given displacement characteristic, namely, displacement data for each fluid. An explicit solution of the direct problem is presented for the model under study. It is shown that the problem of medium recovery, which is, in fact, an inverse problem, can be solved up to a one-parameter family. Additionally, a topology is found in which the inverse problem is stable.

ПРОГНОЗ ГЕОЛОГИЧЕСКОГО РАЗРЕЗА НА ОСНОВЕ ДЕТАЛЬНОЙ ОБРАБОТКИ СЕЙСМИЧЕСКИХ МАТЕРИАЛОВ В ПРОГРАММНО-АЛГОРИТМИЧЕСКОМ КОМПЛЕКСЕ «ГЕОСЕЙФ»

Актуальность. Хорошо известно, что основными целями прогнозирования геологического разреза являются: определение вещественного состава осадконакопления, выделение продуктивных толщ и оценки их нефтегазоносности. Эти цели достигаются в том числе на основе детальной обработки и интерпретации сейсморазведочных данных с привязкой их к результатам геофизического исследования скважин. В современных программно-алгоритмических комплексах обработки и интерпретации сейсмической информации для прогноза геологического разреза в качестве диагностических признаков в основном применяются амплитудные и энергетические характеристики отраженных волн. Фазочастотные характеристики для этих целей прогноза практически не используются. Все это приводит к тому, что при решении задач прогноза геологического разреза процент ошибочных решений достаточно велик и выделение ложных аномалий динамических и кинематических параметров отражений встречается достаточно часто. Цель: на основе детальной обработки сейсмических материалов в программно-алгоритмическом комплексе «Геосейф» получить прогноз геологического разреза по новым информативным параметрам, извлекаемым из мгновенных фазовых спектров отраженных сейсмических волн. Методы и средства исследования: цифровая обработка сигналов и пространственно-временных полей, дискретное преобразование Фурье, методы математического моделирования, вычислительный эксперимент. Результаты. Подробно рассмотрен состав программно-алгоритмического комплекса «Геосейф» и перечень решаемых на нем задач. Показано, что общий подход к решению задач на комплексе «Геосейф» связан с формированием выбранного маршрута в соответствии с принятым графом обработки от имеющихся исходных данных к нужным результатам. Приведена структура детальной обработки сейсмических материалов при реализации алгоритмов фазочастотной деконволюции с целью прогноза геологического разреза. В результате применения рассмотренной методики проведен фазовременной анализ территории Двуреченско–Карандашовской зоны и построена карта районирования по выделенным типам геологического разреза. При этом выявленные корреляционные связи значений фазочастотной характеристики с зональными и локальными литологическими и тектоническими неоднородностями разреза интерполируются и экстраполируются в межскважинное пространство.

Analysis of the results of tracer tests for the monitoring of the development of super-viscous oil deposit

The article describes the results of implementation tracer studies at one of the super-viscous oil deposits in the Republic of Tatarstan. Accurate information on the flow of liquid in oil deposits is absent, this is an obstacle to the successful development of such deposits. The information obtained as a result of tracer studies is an addition to the general history of field development and is used to reduce uncertainties in the construction of geological and hydrodynamic models of deposits. The main tasks were the determination of the hydrodynamic connection between the wells along channels with low filtration resistance, the determination of the filtration rates of the condensate in the reservoir and the heterogeneity of the reservoir in the inter-well space of the investigated section of the oilfield. In order to determine the quality of the hydrodynamic connection within the bituminous deposit, the geological structure, as well as the direction of the filtration streams, a solution of the chemical eosin indicator was pumped into one of the steam injection wells, followed by registration in the samples of the surrounding production wells. To detect fluorescent indicators in the wells, unique equipment was used that significantly reduces the previous sample processing and detection time.

Experience of using seismoacoustic methods for a detailed modeling of geological environment at design of high criticallity objects of nuclear construction

Engineering surveys for the design of facilities with high criticality rating require a switch from methods with discrete assessment of environmental parameters (drilling and static / dynamic sounding), to methods that allow to obtain these values continuously in а massif. The most efficient way to solve this problem is by performing crosshole seismic tomography (CST). The article presents the results of CST during geophysical studies at the site of projected nuclear power plant (NPP). Four cross sections were obtained as a result of survey at distances from 24 to35 metersbetween the boreholes. Requirements for the boreholes preparation are specified in article, along with description of equipment for seismic signals excitation and registration, the examples of seismic records (gathers), methods of analysis and data processing are also shown. The velocity sections for compressional and shear waves obtained as a result of tomographic inversion are presented. The values of dynamic characteristics of soil properties (Young modulus, shear modulus, Poisson ratio) and their distribution in the inter-well space were calculated with the use of data on the soil density of the massif. Also, the article shows the result of applying the technique of incident and reflected waves fields allocation, which were obtained as a result of seismic cone penetration test (SCPT) to depths of 20–30 meters aiming to get detailed geological cross-section.

Using neural networks for predicting the dynamics of water cut of horizontal wells

This article presents the problem of determining the conditions of intensive flooding of horizontal wells for complicated geological structure strata, such as the Pokur formation at the Vostochno-Messoyakhskoye oil field. It corresponds to alluvial continental planes or to coastal-sea conditions of sedimentary rocks accumulation. The principal peculiarity of the geological structure of these strata is the high lateral heterogeneity, which is connected with riverbed migration by sedimentary rocks accumulation. Using the neural network method, the authors have developed an algorithm that allows explaining the different dynamics of displacement characteristics for the wells with identical geological and technological indicators. Having analyzed the dynamics and causes of water cut of 125 wells at East-Messoyahskoe oil field, the authors show that the geo-statistical methods do not apply to the task of describing continental accumulation objects with compound construction. However, the results of seismic data interpretation provide the basic volume of information about the inter-well space. The authors have developed an algorithm for complete regression analysis for the adaptation of the hydrodynamic model, which includes the method for constructing a cube of sandiness based on neural network modeling. It follows the basic factors, those exert influence on dynamics of water cut. They include distance at well’s tube to water-oil contact, and presence of impenetrable or semi penetrable interlayer between tube and water-oil contact. The neural network algorithm (Genetic Inversion) allowed performing the test calculations on one of group wells most operated. The suggested approaches in the construction of the reservoir distribution in the inter-well space allow achieving better integral convergence of the dynamics of water cut at the first iterations of the full-scale hydrodynamic model.

Выявление зон фильтрационной неоднородности в межскважинном пространстве работающих скважин

Выявление зон фильтрационной неоднородности в межскважинном пространстве работающих скважин

Implementing adaptive scaling and dynamic well-tie for quantitative 4-D seismic evaluation of a reservoir subjected to CO2 enhanced oil recovery and associated storage

History-matched simulation modeling can be used to estimate field dynamic reservoir properties and connectivity between wells. However, results are less accurate away from the well locations where the field data are obtained. 4-D seismic data can help improve the accuracy between wells and across the field. This study used data from an oil field undergoing active CO2 injection for enhanced oil recovery and associated CO2 storage. The change in seismic amplitude, changes in inverted P-wave velocity, and impedance in the reservoir layer are in turn correlated with the pore volume scaled changes in the dynamic reservoir properties at well locations. Impedance and velocity changes yielded the most robust correlations. The correlated linear relations at three injectors were used to invert for the pore volume scaled changes in saturations and pressure between wells and across the field. Validation at the producer yielded 69% accuracy. By tying the 4-D seismic with the reservoir properties at the injectors using repeat pulsed-neutron log data and the simulation models, a good level of confidence is established in the inverted pore volume scaled changes in the dynamic reservoir properties in the interwell spaces. The inverted reservoir properties can be used to further history-match the simulation model to improve the interwell prediction of the long-term fate of the associated CO2 storage.

High-resolution lithofacies and porosity modeling of the mixed siliciclastic–carbonate deposits of the Burdigalian Dam Formation, Eastern Saudi Arabia

Conventional subsurface models of reservoir bodies are limited with respect to the good understanding of small-scale heterogeneities at inter-well spacing. Uncertainties associated with data limitation of such large-scale models can be enhanced by information from small-scale modeling. These high-resolution models may provide a realistic three-dimensional insight into their relevant subsurface reservoir setting. In this context, outcrop studies are frequently used to produce high-resolution models. In this paper, the Burdigalian Dam Formation outcrop in eastern Saudi Arabia was targeted to construct high-resolution models of lithofacies and porosity variations. These models were used to identify small-scale heterogeneities in lithofacies and porosity distribution using geostatistical modeling. Ten different lithofacies were identified and modeled. Indicator semivariogram analysis of the lithofacies showed good continuity in NW–SE direction but less continuity in NE–SW. The porosity model showed differing porosity distributions in different carbonate lithofacies. Several realizations of lithofacies and porosity models were generated and ranked against the input data set. Furthermore, the porosity variation was investigated through detailed petrography and SEM analyses for each of the studied lithofacies. The models demonstrated the presence of patterns of lithofacies and porosity variation at a small scale that cannot be obtained from conventional subsurface models. The study indicated the importance of such models in reducing the uncertainty associated with subsurface modeling as a result of data limitation.

COMPARISON OF FRACTIONAL NOISE DISTRIBUTIONS FOR GENERATING HETEROGENEOUS PERMEABILITY FIELDS IN OIL RESERVOIR SIMULATIONS: A CASE STUDY

Prediction of reservoir rock properties, especially permeability distribution is needed for precise simulation of heterogeneous reservoirs. Interwell permeability fields have recently been considered for dynamic simulation using geostatistical models and fractal geometries. The geostatistical models employ experimentally observed variograms to characterize the spatial variability of regionalized variables such as permeability. Fractal models can be useful in assessing the spatial correlation of a property because their variogram can be characterized with a single parameter called the Hurst exponent. In this study, based on core permeability data of each well, Hurst exponent (using [Formula: see text] analysis) is assigned locally to each well by means of stream lines and as averaged value for interwell spaces. Then, permeability distributions are created using Fractional Brownian Motion (FBM) and Fractional Gaussian Noise (FGN) models by implementing fast Fourier transform (FFT). Through comparison between simulation results of these models, as well as real grid simulation results, the averaged distribution was shown to give better results over a locally assigned fractal distribution. Furthermore, predictions of field pressure using the FGN model were shown to function better than the FBM model for vertical wells.

Microseismic monitoring of a tight light oil reservoir: A case history in the Cardium Halo Play, Alberta

The effectiveness of hydraulic-fracturing completions in a tight-oil play is investigated by detailed interpretation of microseismicity. The microseismic programs were acquired in the Cretaceous Cardium light oil sandstone reservoirs in Alberta, Canada. Events with magnitudes between [Formula: see text] and [Formula: see text] are located by downhole monitor wells to a maximum distance of 525 m, enabling inference of the fracture wing length, height, and azimuth based on event distribution. The fracture ports, one per stage, were located in an open-hole configuration that used external packers for zonal isolation. During completions, the ports were opened with ball-actuated frac sleeves. Event distributions indicated that, in some cases, fractures grew preferentially away from the Rocky Mountain deformation front. This inferred that fracture asymmetry is independent of the position of the monitoring array, indicating that it cannot be ascribed to observation bias and suggesting that the direction of fracture growth was dominantly influenced by the preexisting stress conditions in the reservoir. The distribution of microseismicity further indicates that isolated event clusters occur 30–50 m above the reservoir. These out-of-zone events are interpreted to have occurred on unpropped fractures. In comparison with gelled oil or foamed water, slickwater fracturing fluids are shown to produce more diffuse and scattered microseismic expression accompanied by better cumulative oil production. Taken together, the results of these studies indicate that the use of slickwater fracturing fluid, along with the reduced stage spacing and tighter interwell spacing, is expected to lead to higher initial production as well as higher estimated ultimate recovery.

THE INACCURACY OF INTERPOLATION AT THE CONSTRUCTION OF BOUNDARIES ON THE ENGINEERING GEOLOGICAL SOIL PROFILES FOR THE GENERATION OF CALCULATED MODELS OF GEOLOGICAL MEDIUM

On the basis of the recent data, construction accuracy of geological boundaries on engineering geological soil profiles is studied. The concept of the interpolation error of geological boundaries is introduced. This error inevitably presents in all engineering geological soil profiles, as well as in hydrogeological and other geological soil profiles. The error is caused by uncertainty of the state of geological boundary between the wells. Geologists draw the line on the basis of the hypothesis about its genesis. The hypothesis is being checked at the next stage of the investigations, or at the opening of the foundation pit, or already during the examination of the accident. The interpolation error fundamentally influences the character of the engineering geological model of the geological medium, and through this, it influences the quality of the system’s calculation of the building-base. The article proposes methods for defining the interpolation error, based on the study of existing engineering geological soil profiles and outcrops of rocks. Using the example of analysis of engineering geological soil profiles for investigations’ objects located in the south-west of Moscow and the south of the Nizhny Novgorod region, it is shown that the interpolation error for the bottom of technogenetics soils and the shale drapes can reach 1 meter with a distance between wells of less than 40 meters and much more than 1 meter at the interwell spacing is 100 meters. Such inaccuracies in engineering geological information lead to an inaccuracy in the settlement calculation of the building exceeding 50% of the calculated value. The article presents, on the basis of mathematical-statistical analysis, the values of the interpolation error for seven geological boundaries of a different genetic type. The specified scientific and technical problem of assessing the accuracy of engineering geological survey information, in terms of the geometry of the engineering geological model of the geological medium, requires further research and reflection in normative documents, in particular in SP 47.13330.2016 « SNiP 11- 02-96 Engineering surveys for construction. Fundamentals », from which the table 6.2, which existed in previous editions of the document and was aimed at increasing the accuracy of geological soil profiles, are excluded.

АНАЛИЗ ПРИМЕНИМОСТИ АЛГОРИТМОВ МАШИННОГО ОБУЧЕНИЯ ДЛЯ ЗАДАЧ ИНТЕРПОЛЯЦИИ И ПРОГНОЗА ГЕОЛОГИЧЕСКИХ СВОЙСТВ В МЕЖСКВАЖИННОМ ПРОСТРАНСТВЕ

АНАЛИЗ ПРИМЕНИМОСТИ АЛГОРИТМОВ МАШИННОГО ОБУЧЕНИЯ ДЛЯ ЗАДАЧ ИНТЕРПОЛЯЦИИ И ПРОГНОЗА ГЕОЛОГИЧЕСКИХ СВОЙСТВ В МЕЖСКВАЖИННОМ ПРОСТРАНСТВЕ

Reservoir heterogeneity and quality of Khuff carbonates in outcrops of central Saudi Arabia

The Khuff carbonates host several main gas reservoirs in the Middle East. These reservoirs are known for their heterogeneity, both of sub-seismic scale and beyond the interwell spacing. To get a better insight in these reservoirs, the heterogeneity of the Upper Khartam Member, placed in a high-frequency sequence stratigraphic framework, was studied with a lateral resolution between logged sections of 5 m. The sedimentology and sequence stratigraphy of four outcrop localities were studied, and approximately 600 samples were collected for petrographic, porosity and permeability analyses.Seventeen lithofacies types were recognised and six major diagenetic processes could be differentiated in the studied outcrops. Dissolution is likely the result of intensive circulation of meteoric water undersaturated with respect to calcite. Significantly, cementation has blocked most of the original intergranular porosity. Pore lining detrital clay severely impacted reservoir permeability and complicated the pore geometry. Dolomitization is associated with the upper Khuff–Sudair boundary, and is likely the result of influx of water highly saturated with Mg+2 that developed during the deposition of the Sudair evaporites. Finally, stylolites are to a major extend controlled by lithofacies and geobody configuration. Ten porosity types could be namely: intergranular, intragranular, shelter, dissolution-enlarged, moldic, vuggy, micro-porosity, and porosity in relation to dolomite–dedolomite, dolomite-leaching, and fracture development. Overall intertidal creeks are characterized by a complex and heterogeneous pore geometry if compared to the intertidal channels, and this can be attributed to the geobody architecture, with intertidal creeks being composed of dense and small tidal bodies (1 m in length and 20 cm in thickness), while intertidal channels are composed of thick amalgamations of intertidal channels (5 m by 50 cm). Most critically, the horizontal reservoir quality was influenced differentially by diagenesis, which resulted in a lateral segmentation of single bodies into different, hydraulic units. The differential mold-filling calcite cements have significantly reduced porosity and permeability. Generally, mineral content has little impact on the reservoir quality, although clay minerals played a central role in lining the pore space and affecting permeability. Finally, horizontal reservoir heterogeneity seems to have been controlled by fractures and stylolites which respectively acted as conduits to and barriers for vertical fluid flow and, hence, controlled the differential cementation and dissolution processes.

Workflow of integration of digital outcrop modeling and sedimentology of the Early Triassic Upper Khartam Member of Khuff Formation, central Saudi Arabia

The Permian–Triassic Khuff Formation is considered to be the most prolific for the natural gas production in the world. The Khuff reservoirs exhibit vertical and lateral heterogeneities which cannot be fully captured within the interwell spacing from the subsurface data. The Upper Khartam Member in central Saudi Arabia represents an excellent outcrop analog for the upper parts of Khuff-B and the whole Khuff-A reservoirs. The main objective of this study is to reconstruct digital outcrop model of the Upper Khartam Member. This study included sedimentological data and digital laser scanning modeling. Four stratigraphic sections were measured to cover the whole outcrop of Upper Khartam, and a composite section was constructed. The investigations revealed that the studied outcrop of Upper Khartam comprises six lithofacies associations deposited in three depositional settings: offshore (deep–shallow subtidal zone), foreshoal, and shoal complex. The terrestrial laser scanner was used to scan the outcrop from four different scan positions. The Polyworks software was used for the processing and to produce the photorealistic model for Upper Khartam. ArcGIS combined with the Geo Analysis Tool was utilized to interpret the digital models. The digital modeling allows accurate structural and statistical measurements of lithofacies and integrated with the traditional field data on it and examined the lateral continuity and the architecture of the strata in the outcrop. Also, the model revealed the architecture and the continuity of the reservoir units as well as the barriers or the non-reservoir units within the studied outcrop. The integration of the results of this work with subsurface data might help to provide better understanding and prediction of the quality of Khuff reservoirs in the subsurface.

Application of Seismic Attribute Technique to estimate the 3D model of Hydraulic Flow Units: A case study of a gas field in Iran

One of the most important steps in evaluation and development of hydrocarbon reservoirs is the mapping of their characteristics. Nowadays, Seismic Attribute Technique is used to build parameters of hydrocarbon reservoirs in inter-well spaces. One of these parameters is the Flow Zone Index (FZI) that has a significant effect on different stages of evaluation, completion, primary and secondary production, reservoir modeling and reservoir management. The aim of this study is to introduce an equation using seismic attribute and FZI log in wells and then generalize it to predict FZI throughout the reservoir. For this purpose, acoustic impedance (AI) volume as an external attribute was created while internal attributes were computed from seismic data. After that, The best set of attributes was determined using stepwise regression after which seismic attributes were applied to multi-attribute analysis to predict FZI. Then, the attribute map resulted from multi-attribute analysis was used to interpret the spatial distribution of the gas bearing carbonate layers. Finally, the optimum number of Hydraulic Flow Units (HFU) was determined by analyzing the break point in the plot of cumulative frequency of FZI for wells and was generalized all over the reservoir by using the 3D HFU model. The results demonstrated that multi-attribute analysis was a striking technique for HFU estimation in hydrocarbon reservoirs that reduces cost and increases rate of success in hydrocarbon exploration. Distribution of producible hydrocarbon zones along with the seismic lines around the reservoir was characterized by studying this model which can help us in choosing the location of new wells and more economical drilling operations.

Prediction of Naturally Fractured Reservoir Performance using Novel Integrated Workflow

Generation of naturally fractured reservoir subsurface fracture maps and prediction its production potential are considered complex process due to insufficient data available such as bore hole images, core data and proper reservoir simulator model. To overcome such shortcomings, the industry has relied on geo-statistical analyses of hard and soft data, which are often referred to as static data. This paper presents an integrated workflow that models and predicting fractured reservoirs performance, through the use of gradient-based inversion techniques and discrete fracture network modelling (DFN), which—through the inversion of well test data (i.e., dynamic data)—aims to optimise fracture properties and then predicting of the reservoir production potential. The first step in the workflow is to identify flow contributing fracture sets by analysing available core descriptions, borehole images, conventional log data and production data. Once the fracture sets are identified, the fracture intensity is statistically populated in the inter-well space. In the second step, 3D block-based permeability tensors are calculated based on flow through discrete fractures, and the fracture intensity is then propagated away from the wellbore, i.e., by relating to permeability tensors with fracture intensity. In the final step (fracture optimisation), the fracture properties are computed by DFN modelling, which includes distribution, orientation and geometry in different realisations. Fluid flow is simulated in these discrete fractures to estimate pressure change and pressure derivatives. The production rate associated with drill stem test that performed within this reservoir area has been successfully simulated using the optimised subsurface fracture map that has been generated from the first step.

Synthetic Fractal Modelling of Heterogeneous and Anisotropic Reservoirs for Use in Simulation Studies: Implications on Their Hydrocarbon Recovery Prediction

Optimising production from heterogeneous and anisotropic reservoirs challenges the modern hydrocarbon industry because such reservoirs exhibit extreme inter-well variability making them very hard to model. Reasonable reservoir models can be obtained using modern geostatistical techniques, but all of them rely on significant variability in the reservoir only occurring at a scale at or larger than the inter-well spacing. In this paper we take a different, generic approach. We have developed a method for constructing realistic synthetic heterogeneous and anisotropic reservoirs which can be made to represent the reservoir under test. The main physical properties of these synthetic reservoirs are distributed fractally. The models are fully controlled and reproducible and can be extended to model multiple facies reservoir types. This paper shows how the models can be constructed and how they have been tested. Reservoir simulation results of a number of generated 3-D heterogeneous and anisotropic models show that heterogeneity, in terms of only the geometric distribution of reservoir properties, has a little effect on oil production from high and moderate quality reservoirs. However, if the effect of heterogeneity on capillary pressure is taken into account, the effect becomes striking, where varying the heterogeneity of reservoirs properties can lead to a 70 % change in the predicted oil production rate and a significant early shift of water breakthrough time. Hence, it is the heterogeneity consequences that are really substantial if not taken into account. These are very significant uncertainties for a hydrocarbon company if the heterogeneity of their reservoir is not well defined.