Pressure Transient Analysis for Naturally Fractured Reservoirs

Cinco-Ley, Héber; V., Fernando Samaniego

doi:10.2523/11026-ms

Cited by 32 publications

(9 citation statements)

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“…[13][14][15] The conditions of the existence of the various semilog straight lines have been the subject of much discussion. It is generally believed that the first straight line, representing the most permeable medium, can exist only at very early times and is likely to be shadowed by wellbore storage effects.…”

Section: The Double-porosity Modelmentioning

confidence: 99%

Interpretation of Tests in Fissured and Multilayered Reservoirs With Double-Porosity Behavior: Theory and Practice

Gringarten

1984

Journal of Petroleum Technology

142

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This paper summarizes current knowledge of reservoirs with double-porosity behavior. These include both naturally fissured reservoirs and multilayered reservoirs with high permeability contrast between layers. The first part presents available solutions to the direct problem (i.e., solutions to the diffusivity equation) that have appeared in the oil and groundwater literature over the past 20 years. The second part discusses methods for solving the inverse problem-i.e., identifying a double-porosity behavior and evaluating all corresponding well and reservoir parameters.Several field examples demonstrate various aspects of double-porosity behavior and illustrate how additional knowledge of the reservoir (e.g., fissured vs. multilayered, gas saturation, etc.) can be obtained from numerical values of the reservoir parameters. Practical considerations for planning tests in doubleporosity reservoirs also are included.

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Section: The Double-porosity Modelmentioning

confidence: 99%

Interpretation of Tests in Fissured and Multilayered Reservoirs With Double-Porosity Behavior: Theory and Practice

Gringarten

1984

Journal of Petroleum Technology

142

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“…Early work focused on studying naturally fractured reservoirs has provided the foundation on which shale gas reservoirs are described (Warren andRoot (1963), De Swaan (1976), Najurieta (1980), Kucuk and Sawyer (1980), Cinco-Ley and Samaniego (1982), Serra et al (1983), and Curtis (2002)). In addition, dual-porosity models have been developed to describe shale gas plays (Carlson and Mercer (1991), Hazlett et al (1986), and Javadpour et al (2007)).…”

Section: Introductionmentioning

confidence: 98%

Analysis of Mechanisms of Flow in Fractured Tight-Gas and Shale-Gas Reservoirs

Moridis

Blasingame

Freeman

2010

SPE Latin American and Caribbean Petroleum Engineering Conference

110

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In this paper we analyze by means of numerical simulation the mechanisms and processes of flow in two types of fractured tight gas reservoirs: shale and tight-sand systems. The numerical model includes Darcy's law as the basic equation of multiphase flow and accurately describes the thermophysical properties of the reservoir fluids, but also incorporates other options that cover the spectrum of known physics that may be involved: non-Darcy flow, as described by a multi-phase extension of the Forschheimer equation that accounts for laminar, inertial and turbulent effects; stress-sensitive flow properties of the matrix and of the fractures, i.e., porosity, permeability, relative permeability and capillary pressure; gas slippage (Klinkenberg) effects; and, non-isothermal effects, accounting for the consequences of energy balance and temperature changes in the presence of phenomena such as Joule-Thompson cooling in the course of gas production. The flow and storage behavior of the fractured media (shale or tight sand) is represented by various options of the Multiple Interactive Continua (MINC) conceptual model, in addition to an Effective Continuum Method (ECM) option, and includes a gas sorption term that follows the Langmuir isotherm. Comparison to field data, analysis of the simulation results and parameter determination through history matching indicates that (a) the ECM model is incapable of describing the fractured system behavior, and (b) shale and tight-sand reservoirs exhibit different behavior that can be captured (albeit imperfectly) using some of the more complex options of the multi-continua fractured-system models. The sorption term is necessary to describe the behavior of shale gas reservoirs, and significant deviations from the field data are observed if it is omitted. Conversely, production data from tight-sand reservoirs can be adequately represented without accounting for gas sorption. All the other processes and mechanisms allow refinement of the match between predictions and observations, but appear to have secondorder effects in the description of flow through fractured tight gas reservoirs. IntroductionBackground. Tight sand and shale gas reservoirs have recently emerged as a potentially huge resource, and production from such reservoirs has seen an explosive growth over the last few years. Ultratight reservoirs present numerous challenges to modeling and understanding. These reservoirs typically require fracture stimulation, which create complex flow profiles. Additionally, according to Hill and Nelson (2000), between 20 and 85 percent of total storage in shales may be in the form of adsorbed gas. Production from desorption follows a nonlinear response to pressure and results in unintuitive and difficult-tomodel pressure profile behavior. Closed or open natural fracture networks in ultratight reservoirs introduce further complexity through interaction with the induced fractures.The explosion in production has not been accompanied with the same level of understanding of the basic principles th...

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“…Ozkan et al (1987) used a more realistic influx model based on transient flow in infinite slabs. Transient influx models have been used widely in studies of the pressure response of constantrate wells (de Swaan 1976;Cinco-Ley and Samienego 1982;Serra et al 1983;Streltsova 1983). Because of the complexity of transient interporosity flow, these studies were limited to simple matrix blocks like slabs and spheres, so that transient influx could be treated as a 1D problem.…”

Section: Introductionmentioning

confidence: 99%

Production Performance of a Constant-Pressure Well in an Orthogonally Fractured Reservoir

Hagoort

2010

SPE Reservoir Evaluation &Amp; Engineering

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We have analyzed the production performance of a constant-pressure well in a naturally fractured reservoir made up of orthogonal matrix blocks. The fractured reservoir is modeled as a doubleporosity reservoir, in which interporosity flow is represented by an exact analytical transient influx function. Three distinct production modes can be recognized: Modes I, II, and III. In Mode I, the reservoir boundary is seen after flow in the matrix blocks has stabilized. In Mode II, this occurs while flow in the matrix blocks is still in the infinite-acting stage. In Mode III, the reservoir boundary is already seen before the influx from the matrix blocks has effectively set off. The effect of the natural fractures becomes increasingly evident with increasing mode number: from almost absent in Mode I, to significant in Mode II, and to dominant in Mode III. Mode I shows the best production performance, Mode III the worst. Each production mode can be subdivided into a number of distinct flow regimes. The production profiles in each of these regimes and the regime boundaries can be approximated by simple analytical formulas. These formulas may be used for production forecasting and for analyzing historical production decline. = , and t k t c c r D f f f m m w = + ( ) 2 .

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Pressure Transient Analysis for Naturally Fractured Reservoirs

Cited by 32 publications

References 0 publications

Interpretation of Tests in Fissured and Multilayered Reservoirs With Double-Porosity Behavior: Theory and Practice

Interpretation of Tests in Fissured and Multilayered Reservoirs With Double-Porosity Behavior: Theory and Practice

Analysis of Mechanisms of Flow in Fractured Tight-Gas and Shale-Gas Reservoirs

Production Performance of a Constant-Pressure Well in an Orthogonally Fractured Reservoir

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