A Case Study of Reservoir Characterization From DST and Seismic Data

Abstract

Abstract Reservoir heterogeneity can be created by complex sedimentary and diagenetic processes and modified by a sequence of tectonic changes. Integrated information from geophysical, petrophysical, geological and reservoir engineering studies could enhance reservoir characterization even at the discovery-appraisal stage which is vital for oil company sound development and economic planning. This paper presents a dynamic characterization of a gas-condensate reservoir from well-test interpretation in conjunction with the static description obtained from reflection seismics, well-logging, core and other studies. Introduction The most critical point in exploitation of oil and gas reservoirs is the early stage of discovery and appraisal when the least data are available. Using information from seismics, geology, cores, well-logs, and well-tests, one has to rapidly assess reservoir size and reserves, and then plan the new well locations and commission surface facilities that may cost billions. Thus, at the appraisal stage one is concerned with determining reservoir boundaries and possible heterogeneities, such as linear fluid barriers and radial discontinuities. Reservoir heterogeneities may be small-scale, as in carbonate reservoirs where the rock has two constituents, matrix and fractures, vugs or solution cavities. They also may be large-scale, such as physical barriers, faults, fluid-filled contacts, thickness changes, lithology changes, several layers with different properties in each layer, etc. Reservoir boundaries and patterns of faults are usually determined by seismics in conjunction with geological information. However, use of well-test interpretation could provide gross reservoir size, distances to boundaries and also support or not the seismic and geological model chosen. In recent years attention has been given to the use of reservoir characterization and modelling from computerized well-test interpretation as means of investigating the nature and lateral extend of hydrocarbon reservoirs both near to and away from the borehole. However, even when using the computer and regression techniques, it is often difficult to evaluate specific heterogeneities from well tests. This is because many different conditions can cause the same or similar pressure transient response. In other words, it is often possible to find several interpretation reservoir models each of which provides a satisfactory match to a given pressure transient. For example, for complex fault systems there is often a lack of mathematical uniqueness in choosing between one fault pattern or another. It is not just that different systems will produce similar Pd-functions but also that quite distinct Pd-functions can produce similar differences and as a result different fault configurations can produce similar theoretical test responses (Dake). Moreover, Dake notes, that sometimes it is even not so easy to distinguish between the effects of faults or other models such as dual porosity, which can also cause upward curvature in the late time pressure buildup behaviour. Thus, it is dangerous and poor engineering practice to evaluate reservoir heterogeneity based solely on well-testing. Due to the lack of mathematical uniqueness additional information from seismic, geological, well-logging, core, and petrography data should be utilized in order to assist in the selection of the most appropriate model (Ehlig-Economides et al.). Ershagi and Woodbury mention that real time examples of pressure data are often non-existent. Consequently, many authors use synthetic data to demonstrate the use of their proposed method or model. In fact, practising engineers are now reading about many techniques and models for which there may never be examples of actual data to fit. Here, we present a case study of reservoir characterization at the discovery-appraisal phase, from well-test, seismic, geological, open-hole logging, PVT and core data. This systematic study confirms that if well-test interpretation and modelling is used in conjunction with all other information available, a more confident reservoir characterization could be achieved. In this investigation a reservoir model which has the best history match to the DST data and also satisfies the seismic and geological interpretation is that of a "two-zone radially changing mobility and diffusivity". The following section explains the acquisition of all data available and also includes the results and interpretation of the seismic, geologic and well-logging information. Following this, there is the section of well-test analysis and modelling along with the discussion. Finally, we present the conclusions drawn from this integrated approach. INTEGRATED INFORMATION: Well-logging, core, seismics, geology, DST and PVT data Well K1 is located in the Bredasdorp basin of South Africa and was drilled in a water depth of 114m to a TD of 3144.2 mbkB. Recent discovery wells in the Bredasdorp basin have intersected hydrocarbon bearing sandstones within late Aptian deep marine sediments. These reservoirs consist of submarine fan lobe and/or channel fill sandstones. Potentially commercial oil flow rates up to 10,000 stb/d of oil have been recorded in a number of wells. The hydrocarbon trapping mechanisms appear to be structural; however, the possibility of larger stratigraphic traps cannot be ruled out at this stage P. 63^