Reservoir Modeling to Characterize Dual Porosity, Tengiz Field, Republic Of Kazakhstan (Russian)
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Cited by 16 publications
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Carbonate oil reservoirs are sometimes regarded with apprehension in the petroleum industry since it can be difficult to predict the quality of, and ensure high recovery factors from, this rock family. Particular problems are the complex and heterogeneous nature of porosity in carbonate rocks, often leading to large ranges in permeability for any given porosity, and the organization of carbonate successions most commonly as vertically heterogeneous, but laterally persistent, layers.Important issues that arise time and again in carbonate reservoir description include (a) predicting reservoir quality at inter-well scales and in uncored wells, (b) recognizing problematic high-permeability layers, (c) determining the permeability component to allocate to fractures and connected vug systems, and (d) populating reservoir models with representative physical parameters. Because porosity in carbonate rocks generally presents as diverse and heterogeneous, conventional core plugs are seldom representative of large rock volumes and significant issues remain in terms of the scale-compatibility of the various datasets for measured physical parameters that are used in carbonate reservoir description.Many of the world's largest carbonate reservoirs were discovered and developed shortly after the Second World War and are now showing signs of maturity, expressed variously as poor pressure support, water or gas breakthrough and stranded resources. The proportion of the world's ‘conventional’ petroleum that is reservoired in carbonate rocks is commonly estimated at around 50–60% and many large carbonate reservoirs are likely to have a production lifetime beyond 50 years. It is no coincidence then that the petroleum industry has been the primary source of funding of and promotion of research into carbonate rocks and depositional systems, often with impacts extending well beyond oil and gas exploitation.
Carbonate oil reservoirs are sometimes regarded with apprehension in the petroleum industry since it can be difficult to predict the quality of, and ensure high recovery factors from, this rock family. Particular problems are the complex and heterogeneous nature of porosity in carbonate rocks, often leading to large ranges in permeability for any given porosity, and the organization of carbonate successions most commonly as vertically heterogeneous, but laterally persistent, layers.Important issues that arise time and again in carbonate reservoir description include (a) predicting reservoir quality at inter-well scales and in uncored wells, (b) recognizing problematic high-permeability layers, (c) determining the permeability component to allocate to fractures and connected vug systems, and (d) populating reservoir models with representative physical parameters. Because porosity in carbonate rocks generally presents as diverse and heterogeneous, conventional core plugs are seldom representative of large rock volumes and significant issues remain in terms of the scale-compatibility of the various datasets for measured physical parameters that are used in carbonate reservoir description.Many of the world's largest carbonate reservoirs were discovered and developed shortly after the Second World War and are now showing signs of maturity, expressed variously as poor pressure support, water or gas breakthrough and stranded resources. The proportion of the world's ‘conventional’ petroleum that is reservoired in carbonate rocks is commonly estimated at around 50–60% and many large carbonate reservoirs are likely to have a production lifetime beyond 50 years. It is no coincidence then that the petroleum industry has been the primary source of funding of and promotion of research into carbonate rocks and depositional systems, often with impacts extending well beyond oil and gas exploitation.
Probabilistic production forecasting at Tengiz is largely driven by reservoir uncertainty. Reservoir uncertainty is most effectively synthesized and quantified through simulation modeling. Early in the construction of a new Tengiz dynamic model, fundamental reservoir uncertainties were identified and evaluated. This allowed for model 'building blocks' to be developed with different characterizations to encompass key uncertainties.Key uncertainties, which can significantly impact future production under primary depletion and sour gas injection, have been described. These include typical uncertainties such as porosity, irreducible water saturation, hydrocarbon fluid properties, oilwater contact levels, rock compressibility, geologic baffles, and relative permeability. Unique uncertainties specific to Tengiz include geometry and density of the natural fractures, and reservoir heterogeneity.Considerable production history and a large reservoir surveillance database provided input for rigorously characterizing and subsequently validating the range of each uncertainty. After ranges were established, appropriate model realizations were created. A wide range of reservoir models were obtained by selecting combinations of high/mid/low realizations for each uncertainty. Using experimental design (ED), reservoir simulations were conducted to test uncertainty ranges against field history. A quantitative history match and statistical analysis were developed to objectively judge the appropriateness of uncertainty values. Uncertainties with the largest overall impact on the history match are: fracture density, platform horizontal permeability, compressibility, and platform heterogeneity.This case study demonstrates how analysis of reservoir uncertainties can be: (1) captured in static and dynamic reservoir models and (2) validated through ED and quantitative history matching. This study employs state-of-the-art technologies to evaluate model uncertainties of a giant carbonate reservoir undergoing both depletion and miscible gas drives. The range of reservoir models subsequently developed will be of great value in creating robust probabilistic reservoir forecasts to optimize field operation and future development.
Fractures are common features of many well-known reservoirs. Naturally fractured reservoirs consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix) and formations. Faults in many naturally fractured carbonate reservoirs often have high permeability zones, and are connected to many fractures with varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (i.e., not a connected-network fracture system). To understand the pressure behavior of these continuously and discretely fractured reservoirs, semianalytical solutions are presented. These solutions are used for transient well test interpretation of formations containing a network of discrete and/or connected (continuous) finite- and infinite-conductivity fractures. In this paper we present an extensive literature review of the pressure transient behavior of fractured reservoirs. First, we show that the Warren and Root (1963) dual-porosity model is a fictitious homogenous porous medium because it does not contain any fractures. Second, using the new solutions, we show that for most naturally fractured reservoirs the Warren and Root (1963) dual-porosity model is inappropriate and fundamentally incomplete for the interpretation of pressure transient well tests because it does not capture the behavior of these reservoirs. We examined many field well tests published in the literature. With few exceptions, none of them shows the behavior of the Warren and Root (1963) dual-porosity model. These examples exhibit the very rich pressure behavior of discretely and continuously fractured reservoirs. Unlike the single derivative shape of the Warren and Root (1963) model, the derivatives of these examples exhibit many different flow regimes depending on fracture distribution, and on their intensity and conductivity. We show these flow regimes using our new model for discretely and continuously fractured reservoirs. These derivatives will be a valuable diagnostic tool for well test interpretation. Most well tests published in the literature do not exhibit the Warren and Root (1963) dual-porosity reservoir model behavior. If we interpret them this dual-porosity model, then the estimated permeability, skin factor, interporosity flow coefficient (λ), and storativity ratio (ω) will not represent the actual reservoir parameters.
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