The paper illustrates, using a field example, how well test data can be used to evaluate matrix block size and fissure volume in fissured reservoirs. The method is based on type-curve analysis with a recently published type-curve for double porosity reservoirs, published type-curve for double porosity reservoirs, and is applied to two tests on the same well, performed at a few years interval, with reservoir pressure above and below the bubble point, respectively. Detailed analysis of the two tests is presented, that yields consistent values for fissuration parameters, w and X, although pressure behavior during the tests is very different. Interpretation results were used as inputs to a numerical reservoir simulator, which was then calibrated against actual performance history to yield the size of the matrix blocks. The result was in excellent agreement with that obtained from X, and with available geological information. Introduction Naturally fissured reservoirs are recognized as major contributors to the world oil reserves. As a result, they have been the subject of many studies over the last twenty years. Although several fissured reservoir models have been presented in the literature, field examples to support presented in the literature, field examples to support these models are scarce. In fact, there still is some debate on fissured reservoir behavior, and consequently, on the ability of well tests to provide specific information on fissure parameters, such as spacing and porosity. The general feeling appears to be that fissured reservoir behavior is too complex and too averse to be analyzed in a systematic and unique way. In this paper, field data from two different tests on the same well in a fissured reservoir are analyzed with the help of a recently published type-curve. It is shown that, although the well behavior was very different in the two tests, the same model could be used for analysis, and provided values of the parameters that were consistent with reservoir parameters that were consistent with reservoir information obtained from other sources. INTERPRETATION MODELS FOR FISSURED RESERVOIRS DIRECT PROBLEM The direct problem (i.e., predicting the pressure behavior of a fissured reservoir from the knowledge of pertinent reservoir parameters) has been investigated by many different authors. Most of them, however, used the same basic model to describe a fissured reservoir, and their solutions only differed by the nature of fissure-matrix interaction, the boundary conditions included in the model, and the computation techniques employed. Fissured formations are commonly represented by a double porosity reservoir (i.e. a reservoir with two porous regions of distinctly different porosities and permeabilities). One region (the porosities and permeabilities). One region (the fissures) has a high conductivity, and carries the reservoir fluid to the well, whereas the other region (the blocks) has a low conductivity and feeds the fluid only to the fissures. Parameters necessary to describe a fissured reservoir are the same as those used for homogeneous reservoirs, plus two specific ones, namely. (1) and (2) In Eqs 1 and 2, subscript f refers to the fissure system, m to the matrix and (f+m) to the total reservoir.
Field experience has shown that pressure data measured in extremely high permeability reservoirs (kh - 106md-ft) are affected by wellbore effects such as storage, temperature changes, reservoir pressure trend and noise in pressure measurements. pressure trend and noise in pressure measurements. These effects are particularly important in light of the small pressure response observed during a well test. The present work presents methods to analyze pressure drawdown and buildup tests performed under the pressure drawdown and buildup tests performed under the influence of unknown linear reservoir pressure trend (m*). For a drawdown test a graph of t dpwf/dt vs t yields a straight line of slope m* and intercept m (semilog slope); for a buildup test a graph of dp ws/d vs t p /delta t(tp + delta t) gives a straight line of slope m and intercept m*. Field cases are presented to illustrate the application of this method and the effects of different wellbore phenomena; both surface shutin and bottomhole shut-in examples are included. Introduction Pressure transient testing has become one of the best methods to estimate reservoir parameters and to detect heterogeneities of the formation. At present there is a wide variety of well tests each present there is a wide variety of well tests each one with different objectives. Modern methods of interpretation of transient test data uses not only pressure alone; in addition pressure derivatives are pressure alone; in addition pressure derivatives are now analized. The calculation of pressure derivatives has been possible because of the quality and quantity of the information taken by new pressure and flow rate measuring devices of high resolution. Graphical methods of analysis are usually developed for ideal situations such as no wellbore storage effects or constant wellbore storage coefficient, isothermal flow in homogeneous reservoirs, etc. In order to apply some techniques to estimate formation parameters it is neccessary that the reservoir dominates parameters it is neccessary that the reservoir dominates the wellbore pressure behavior during the test. In practice, this is not always the case because wellbore storage can control completely the pressure behavior. In very high permeability reservoirs, inertial effects appear to be important due to the high flow rates involved in a test. Furthermore, wellbore temperature effects and interference of neighbor wells produce pressure changes at the tested well of the produce pressure changes at the tested well of the same order of magnitude of the pressure changes generated by flow rate changes in the test itself. This situation requires that the effect of different phenomena be detected and evaluated to perform a phenomena be detected and evaluated to perform a comprehensive analysis. The present work discusses several field cases of well tests in extremely high permeability carbonate fractured reservoirs in which the effects mentioned in the previous paragraph are present. In addition a method is introduced to handle the effect of unknown linear reservoir pressure trend in both drawdown and buildup tests. GENERAL CHARACTERISTICS OF RESERVOIRS TESTED The reservoirs tested are in calcareous rocks of Cretaceous age. The formations are highly fractured with presence of vugs and caverns; these characteristics provide a good formation flow conductivity (kh) yielding high well flow rates (20,000-40,000 STB/D). At the time the tests presented in this work were conducted the reservoirs were undersaturated. Since the beginning of the exploitation of these reservoirs, it was found that the use of high resolution pressure gauges was necessary to measure pressure changes. Figure 1 presents a semilog graph for a buildup test run with intermediate resolution device (strain gauge); a stairwise behavior is observed and analysis appears to be difficult. In the following cases high resolution recorders were used and data were obtained at surface during the test.
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