Summary A geostatistical reservoir study provides an ensemble of possible reservoir models, with a variability reflecting the uncertainty of the geology and fluid-flow properties. A production test links the static geostatistical model with dynamic fluid-flow data and thus provides possible means of validation and selection. We used a highly efficient 3D single-phase simulator to simulate pressure transients without compromising the fine-grid resolution typical for geostatistical models. This simulator was applied to Boolean and Gaussian geostatistical models that represent reservoirs consisting of heterogeneous fluviodeltaic deposits. Simulated buildup and interference tests were analyzed and related to 3D permeability and connectivity patterns. Effective well-test permeability was compared with 3D averages obtained from different volumes within the geostatistical model. The cases studied show that combining geostatistical models and well tests can reduce uncertainty with respect to geometric connections and the permeability distribution. However, the study also confirms that well tests have a limited capability to assess lateral continuity precisely and uniquely. Simulation of an interference test has the potential to screen the geostatistical model for high-permeability connections between wells. This pragmatic integration of pressure transients and detailed heterogeneous reservoir models through forward simulation provides a simple means to evaluate these models. It allows testing a model based on small-scale (core-plug) permeabilities and qualitative geologic information vs. routine field measurements representing large-scale hydraulic behavior of a reservoir. Introduction During the early stage of field development, production tests are the only data providing information about fluid flow in oil reservoirs and about permeability in the wider volume surrounding a well. At the same stage, construction of a geostatistical reservoir model is now a viable option. The main purpose of this model is to assess the uncertainty of reservoir performance resulting from incomplete knowledge of the heterogeneous reservoir. Geologic data and core measurements are honored at the wells, and models are created between wells that are statistically similar to those inferred from geologic analogs. These are static data, and subjecting the geostatistical model to verification on the basis of dynamic fluid-flow data (i.e., pressure-transient production tests) is a logical step. The pressure transient reaches faraway boundaries in a relatively short time.
The ability of SHDT processing techniques to produce detailed sedimentological information has been evaluated by comparing the data with 3000 ft of cores covering shallow marine, deltaic, lacustrine, fluvial and aeolian sedimentary environments. It has been shown previously that, by using side-by-side processing, realistic sedimentary dip sequences through sedimentary bodies can be obtained from SHDT data under normal conditions. However, optimum results require processing parameters to be chosen compatible with the scale of the sedimentary structures present. Furthermore, post-processing selection procedures are required to remove noise and to identify dips representing foreset inclination which can be interpreted in terms of flow direction and sand body orientation. The sedimentological interpretation of downhole dips is often difficult. It may be improved by comparison with vertical dip sequences from outcrops. Sedimentary dip profiles have been measured as part of field work carried out in the Pocahontas Basin of Kentucky. Extensive roadcuts not only enable an unambiguous sedimentological interpretation, but also exhibit numerous relict blast-boreholes, in which vertical dip profiles can be measured under conditions similar to downhole logging. The data now available show that even contradictory dip sequences may be a proper representation of the reality. Systematic collection of sedimentary dip sequences will provide guidelines for a realistic interpretation of downhole records of sedimentary dips.
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