The Minagish field covers an area of 90 km2, located in south-western part of Kuwait in onshore position. The studied Cretaceous Wara and Upper Burgan reservoirs, deposited in fluvio deltaic environment (clastic rocks), consist of vertically stacked sands with extensive lateral facies variation. Lower Burgan sands are more significant and blocky in nature with little variations in their properties. Reservoirs geometry, their heterogeneities and structural setting are the key issues for the development of the reservoirs. The geostatistical methodology used to simulate a high-resolution geological model representative of the reservoir heterogeneity will be described in this paper. The paper will particularly discuss the techniques used for the integration of seismic attributes to constrain the facies modeling, as well as a nested simulation workflow for a realistic representation of heterogeneities. The three dimensional structural grid was classically based on the seismic interpretation (faults and horizons) and the well correlations. Facies simulation was performed using PluriGaussian functions approach in a non-stationary frame based on vertical proportion curves (VPC) matrix. The distribution has been done separately in three zones: Wara, Upper Burgan and Lower Burgan. For Wara and Upper Burgan zones, nested simulations were used. The lithology (sand or shale) was simulated in a first step, under the constraint of proportion facies maps extracted from seismic data. In a second step, the depositional environment facies were simulated in the sand lithology. These simulations were based on two Gaussian functions to better integrate the various orientations of the different deposits, and their complex spatial relationship. For the Lower Burgan zone, because of the very low variability of the sand proportion, a stationary facies simulation was run, using a truncated Gaussian algorithm. Eventually, the paper underlines the capacity of the PluriGaussian Simulation approach to realistically mimic sedimentary bodies, and to easily incorporate seismic derived information.

The Middle Cretaceous Upper Burgan and Wara sandstone reservoirs in the Minagish field are exhibiting variable clastic depositional settings ranging from fluvial, fluvio-tidal to tidal wave sands. The sand bodies are highly heterogeneous in terms of the stratigraphic architecture implying extensive lateral facies variations, stacked sand bodies and varying petrophysical properties. Modeling the target sand channels and optimizing subsurface well placement and geo-steering requires high resolution geological and seismic data integration in order to minimize uncertainities related to correlations of multiple auto-cyclic ravinement surfaces, channels geometry and sub-seismic fault network. Within Upper Burgan and Wara sand bodies there are different lobes that have varying degree of minerals like glauconite, pyrite and hematite with other cementing materials such as calcite and dolomite. The presence of glauconite has a strong impact on petrophysical evaluation, whereas the presence of shale poses several challenges during geosteering. Geostatistical modeling for sand distribution were integrated using seismic data, core and sedimentological models, electrofacies and petrophysical intrepretations. High resolution seismic data including pre-stack depth mighration and pre-stack simultaneous inversion have been utilized with well log curve shales and elastic impedance to trace accurately the good quality sand. High resolution sequence stratigraphic model were attempted on this complex Upper Burgan and Wara formations. The formation evaluation and geosteering challenges were addressed to ensure the successful drilling and completion of horizontal producers. The wells drilled in this complex settings are geostreed with high definition inversion based distance to boundary technology having a higher precision and accuracy of resistivity contrasts. Formation capture cross section (sigma) saturation was of great value in "mixed lithologies" of Upper Burgan and Wara as resistivity frequently polarized from the proximity to bed boundaries and in these portions traditional resistivity logs proved ineffective for saturation evaluations. In addition the real time permeability estimation using spectroscopy analysis was very beneficial to ICD design.

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The karsted limestone of the Cretaceous Shuaiba formation in Kuwait represents a major challenge seismic imaging as well as drilling. The heterogeneity of the eroded limestone results in strong lateral velocity variations that distort the deeper seismic image and affect porosity estimates for the Minagish Oolite reservoirs. These reservoirs make up 80% of the hydrocarbon production from the Minagish field. The conventional approach using prestack time migration (PSTM) and prestack depth migration (PSDM) results in a strong reflection at the top of the Shuaiba, but without details of internal structure within this 100 m thick layer. The detailed structure of the karst features at the surface and inside the Shuaiba limestone was picked and inserted manually. The resulting velocity model was used to reprocess the seismic cube. The result of this method showed that the effect of the Shuaiba heterogeneities could not be removed. This paper outlines the challenges, and a new approach using a combination of seismic attributes to extract the Shuaiba limestone and the karst features. The resulting model of the Shuaiba porous layer appears to be geologically more meaningful. In parallel, a revised PSDM workflow was tested, and points towards an integrated workflow for future enhancements.

The Middle Cretaceous Burgan reservoir in Minagish Field exhibits variable depositional clastic settings ranging from "Fluvial", "Fluvio-tidaT to "tidal wave sands". The sand bodies of Upper Burgan reservoir are highly heterogeneous in terms of the stratigraphic architecture implying extensive lateral facies variations, stacked sand bodies and varying petrophysical properties. Modeling the target sand channels and optimizing subsurface well trajectory with maximum reservoir contact requires "high resolution" geological and seismic data integration in order to minimize uncertainties related to correlations of timeline surfaces, channels geometries and sub-seismic fault network. Since traditional logs could not capture the textural differences characterizing the reservoir zones, Real-time formation evaluation and geosteering challenges addressed to ensure the successful drilling and completion of level-4 "Multi-lateral" producers. A combination of the latest advanced geo-steering technology used in this well including Rotary Steerable, Distance to Boundary and Sourceless petrophysical evaluation while drilling. The uncertainties in the geostatistical models were further reduced while drilling the first lateral section (LAT-0) by deploying extra deep azimuthal resistivity measurements. It has a higher precision and accuracy to consistently mapping the rise in OWC due to production operations with depth of detection up to 100 feet TVD above and below the well path and maintaining a standoff from the top of onset transgression undulating surface with poor sand facies. The resultant mapping window provided accurate guides to update the geo-models. The formation evaluation along with borehole imaging and geo-correlation assisted in identifying a fault having a great impact on well positioning of the upper lateral due to a high amount of throw fault with significant formation dip changes. This is in turn eliminating risks of geosteering in such a complex heterogeneous reservoir. The integrated approach utilizing geological, seismic, petrophysical and geosteering data provided better understanding for well positioning while drilling and achieving the MRC without exiting the sweet zones of targeted upper and lower Burgan sandstone in Minagish field and enhanced water free oil production.