The Late Jurassic Arab Formation consists of complex carbonate and evaporite facies associations deposited along ramps and intra-shelf Arabian basins, which form large hydrocarbon fields. Most of the time, the 3D reservoir characterization of such reservoirs is challenging, due to superimposed diagenetic overprints. The aim of this paper is to present an integrated approach using original rock-typing and modeling methods for the characterization of the four main reservoirs of the Arab Formation in Maydan Mahzam Field (Qatar). A sedimentological study was conducted on cores, and a sequence stratigraphy framework was developed. Three depositional models are proposed to illustrate the progradation of the Arab D carbonate platform toward the Southeast and the deposition of inner ramp/sabkha facies of the Arab A, Arab B and Arab C reservoirs. Rock-types that are characterized by specific geological, petrophysical and Kr/Pc properties have been defined from cores and thin sections, taking into account log response and SCAL measurements. These rock-types have been extended to all the wells by mean of a semi-interactive statistical classification applied on log data. They have been propagated in a 3D grid using a non-stationary geostatistical approach guided by 3D probability cubes. The probability cubes calculation is based on local vertical proportion curves determined from well sets and from the sedimentological models which cover undrilled areas. This paper contributes to a better understanding of the sedimentology of the Arab Formation in Qatar and helps to refine the regional distribution of the Arab D reservoir facies. It demonstrates that an accurate rock-typing scheme combined with the definition of a sequence stratigraphy framework are of prime importance for building 3D static models, which honor geological concepts for carbonate reservoir simulation.

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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.