No abstract

In complex and heterogeneous carbonate reservoirs, computing an accurate log derived water saturation (SW) where more than one pore type is present, poses a challenge for log analysts and geomodelers. Despite the application of a large number of log based techniques, log derived SW in these situations fails to compensate for the effects of microporosity because it does not accurately represent moveable hydrocarbon pore volume. Alternative techniques must be developed and implemented to reduce the uncertainty in hydrocarbon estimation and for use in dynamic simulation. Failing to account for the affects of microporosity can have a major impact on hydrocarbon reserve estimation because the capillary bound water contained in the microporosity can cause SW estimates using conventional open hole logs to be inaccurate and this can lead to inaccurate estimation of moveable hydrocarbons. Such errors lead to the possibility that some potentially productive intervals could be bypassed or confused as water productive, when in fact they produce dry oil in production tests. Furthermore, substantial errors in calculation of Original Oil in Place (OOIP) can also be made. We present the results of core based saturation height modeling for the Uwainat Member which has been applied to compensate for the dynamic effects of microporosity in simulation. Introduction The Uwainat Member is the main Mid-Jurassic carbonate reservoir in Bul Hanine (BH) Field, offshore Qatar. The Uwainat Member has an oil rim with an API gravity of approximately 37°, and fairly dry gas cap. The oil rim is about 140 ft thick and the gas cap column is approximately 260 ft. The oil saturation pressure at the Gas-Oil-Contact (GOC) is 4367 psia. Gas cap expansion provides the main energy for the reservoir flow. The Uwainat Member consists of a variety of carbonate rock types which are characterized by the occurrence of various pore types and complex pore geometry with varying proportions of microporosity. Complex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of reservoirs. Pervasive internal microporosity associated with micrite in packstone, wackestone, mudstone and even composite grainstone lithofacies affects the petrophysical properties of these rocks and challenges conventional modeling techniques. The presence of microporosity suppresses the resistivity response of induction and laterolog logging tools, leading to a low contrast in resistivity between water saturated and oil saturated rocks. Quantification of microporosity is critical in these lithotypes, to understand capillary behavior and why they appear to have such thick transition zones. In reservoirs such as the Uwainat at BH, primary drainage processes preferentially displace brine from pore network paths with the largest pore throat radii at the lowest elevations above the free water level (FWL). Microporosity remains brine saturated until much higher capillary pressures are reached. Internal micropores occur within fine grained particles which have high internal surface area. In microporosity, high surface area and the small pore size ensure that micropores remain water-wet at low capillary pressures. By contrast, the larger pores (macropores) are more susceptible to wettability alteration and can become oil-wet. In addition, drainage capillary pressure curves for rocks with a high proportion of microporosity tend to suggest or give the impression of a thick transition zone. This kind of apparent transition zone can be modeled by superposition of the capillary trends of two porosity systems, a micro and a macro system. Modeling the capillary pressure system in this way helps to explain the dynamic flow behavior of dry oil production in some of the Mid-Jurassic Uwainat intervals which have very low measured e-log resistivity (~ 1 ohm.m), and high apparent SW.

No abstract

No abstract