Summary In clastic reservoirs in the Oriente basin, South America, the rock-quality index (RQI) and flow-zone indicator (FZI) have proved to be effective techniques for rock-type classifications. It has long been recognized that excellent permeability/porosity relationships can be obtained once the conventional core data are grouped according to their rock types. Furthermore, it was also observed from this study that the capillary pressure curves, as well as the relative permeability curves, show close relationships with the defined rock types in the basin. These results lead us to believe that if the rock type is defined properly, then a realistic permeability model, a unique set of relative permeability curves, and a consistent J function can be developed for a given rock type. The primary purpose of this paper is to demonstrate the procedure for implementing this technique in our reservoir modeling. First, conventional core data were used to define the rock types for the cored intervals. The wireline log measurements at the cored depths were extracted, normalized, and subsequently analyzed together with the calculated rock types. A mathematical model was then built to predict the rock type in uncored intervals and in uncored wells. This allows the generation of a synthetic rock-type log for all wells with modern log suites. Geostatistical techniques can then be used to populate the rock type throughout a reservoir. After rock type and porosity are populated properly, the permeability can be estimated by use of the unique permeability/porosity relationship for a given rock type. The initial water saturation for a reservoir can be estimated subsequently by use of the corresponding rock-type, porosity, and permeability models as well as the rock-type-based J functions. We observed that a global permeability multiplier became unnecessary in our reservoir-simulation models when the permeability model is constructed with this technique. Consistent initial-water-saturation models (i.e., calculated and log-measured water saturations are in excellent agreement) can be obtained when the proper J function is used for a given rock type. As a result, the uncertainty associated with volumetric calculations is greatly reduced as a more accurate initial-water-saturation model is used. The true dynamic characteristics (i.e., the flow capacity) of the reservoir are captured in the reservoir-simulation model when a more reliable permeability model is used. Introduction Rock typing is a process of classifying reservoir rocks into distinct units, each of which was deposited under similar geological conditions and has undergone similar diagenetic alterations (Gunter et al. 1997). When properly classified, a given rock type is imprinted by a unique permeability/porosity relationship, capillary pressure profile (or J function), and set of relative permeability curves (Gunter et al. 1997; Hartmann and Farina 2004; Amaefule et al. 1993). As a result, when properly applied, rock typing can lead to the accurate estimation of formation permeability in uncored intervals and in uncored wells; reliable generation of initial-water-saturation profile; and subsequently, the consistent and realistic simulation of reservoir dynamic behavior and production performance. Of the various quantitative rock-typing techniques (Gunter et al. 1997; Hartmann and Farina 2004; Amaefule et al. 1993; Porras and Campos 2001; Jennings and Lucia 2001; Rincones et al. 2000; Soto et al. 2001) presented in the literature, two techniques (RQI/FZI and Winland's R35) appear to be used more widely than the others for clastic reservoirs (Gunter et al. 1997, Amaefule et al. 1993). In the RQI/FZI approach (Amaefule et al. 1993), rock types are classified with the following three equations: [equations]

In clastic reservoirs in the Oriente basin, South America, rock-quality-index (RQI) and flow-zone-indicator (FZI) prove to be an effective technique for rock type classifications. It has long been recognized that excellent permeability-porosity relationships can be obtained once the conventional core data are grouped according to their rock types. Furthermore, it was observed from this study that the capillary pressure curves as well as relative permeability curves also show close relationships with the defined rock types in the basin. These results lead us to believe that if rock type is properly defined, a realistic permeability model, a unique set of relative permeability curves as well as a consistent J function can be developed for a given rock type. The procedure for implementing this technique in our reservoir modeling is described in the paragraphs below. Conventional core data were first used to define the rock types for the cored intervals. The wireline log measurements at the cored depths were extracted, normalized, and subsequently analyzed together with the calculated rock types. A mathematical model was then built to predict the rock type in uncored intervals and in uncored wells. This allows the generation of a synthetic rock type log for all wells with modern log suites. Geostatistical techniques can then be used to populate the rock type throughout a reservoir. After rock type and porosity are properly populated, the permeability can be estimated using the unique permeability-porosity relationship for a given rock type. The initial water saturation for a reservoir can subsequently be estimated using the corresponding rock type, porosity, and permeability models as well as the rock-type-based J functions. It was observed in our study that a global permeability multiplier became unnecessary in our reservoir simulation models when the permeability model is constructed using this technique. Consistent initial water saturation models (i.e., calculated and log measured water saturations are in excellent agreement) can be obtained when the proper J function is used for a given rock type. As a result, the uncertainty associated with volumetric calculations is greatly reduced as a more accurate initial water saturation model is used. The true dynamic characterisitcs (i.e., the flow capacity) of the reservoir are captured in the reservoir simulation model as a more reliable permeability model is used. Introduction Rock typing is a process of classifying reservoir rocks into distinct units, each of which was deposited under similar geological conditions and undergone through similar diagenetic alterations1. When properly classified, a given rock type is imprinted by a unique permeability-porosity relationship, capillary pressure profile (or J function), and set of relative permeability curves[1–3]. As a result, when properly applied, rock typing can lead to accurate estimation of formation permeability in uncored intervals and in uncored wells; reliable generation of initial water saturation profile; and subsequently, consistent and realistic simulation of a reservoir dynamic behavior and production performance.

New analytical pressure-transient solutions for a horizontal well intersecting multiple random discrete fractures in both an infinite and a bounded reservoir are presented. The horizontal well is assumed to penetrate multiple randomly distributed vertical fractures. The infinite reservoir containing the horizontal well is bounded at the top and at the bottom. For the case of a bounded reservoir, all exterior boundaries are non-flow boundaries. New source functions for a random vertical fracture are first derived. The pressure-transient solutions are then obtained using the derived source functions, as well as superposition principles. A uniform flux is assumed along all fracture faces. An averaging technique is used to approximate the wellbore pressure. The new solutions provide a theoretical basis for the analysis of the pressure transient behavior of a horizontal well intersecting multiple random discrete fractures. Different flow regimes are identified. The effects of fracture characteristics, such as fracture orientation and length, on the pressure transient behavior of a horizontal well are investigated. New evaluation techniques using the derived pressure-transient solutions can be developed to determine reservoir properties and fracture characteristics from horizontal well test data.

SPE Members Abstract New analytical pressure-transient solutions and dynamic inflow performance equations for horizontal wells intersecting discrete fractures in an infinite reservoir are presented. The horizontal well is assumed orthogonally penetrating multiple identical and parallel fractures. The reservoir containing the horizontal well is bounded by non-flow parallel planes at the top and the bottom. The pressure-transient solutions are derived using the source and Green's functions developed by Gringarten and Ramey, as well as the superposition principle. The dynamic inflow performance equations are derived by applying the derived transient solutions. The derived analytical pressure-transient solutions may provide a theoretical basis for the analysis of the transient pressure behavior of horizontal wells intersecting discrete fractures. New evaluation techniques may be developed for determining reservoir properties and fracture characteristics from horizontal well testing. The dynamic inflow performance models presents a theoretical tool for evaluating the effects of fractures on horizontal well performance. They are particularly useful in the production modelling of horizontal wells in tight reservoirs with natural or induced fractures. Introduction The pressure-transient solutions and well testing techniques for evaluating the behavior of a single vertical fracture (a fractured vertical well, for example) have been well documented in the literature. The pressure-transient behavior for a horizontal well in a non-fractured reservoir with various boundary conditions has been investigated by numerous researchers. More recently, studies on the pressure-transient solutions of horizontal wells in more heterogeneous and more anisotropic reservoirs, such as stratified, laterally composite, and naturally fractured (dual porosity) reservoirs, have also been presented. All of these studies have contributed significantly to the understanding of horizontal well performance. It appears, however, that the information on the pressure-transient solutions for a horizontal well intersecting multiple discrete fractures has not become available in the literature. As horizontal well technology is becoming more suitable in developing naturally fractured reservoirs, and tight reservoirs when coupled with hydraulic fracturing, appropriate well testing techniques need to be developed for evaluating the fracture characteristics and reservoir properties, and accurate in flow performance equations derived for estimating the production potential of a horizontal well in such a system. P. 307^

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers.