TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents an in depth study for a field-wide application of Maximum Reservoir Contact (MRC) wells along with smart well completions complemented by openhole expandable tubular to develop Haradh Increment-3, the southernmost area of the greater Ghawar Field. The reservoir represents a heterogeneous matrix permeability background, with geological discontinuities such as faults, fractures, and stratiform high permeability streaks. An MRC is a multi-lateral horizontal well with more than 5 km. of total contact with the reservoir rock (1,2) .This paper illustrates how an MRC well with smart completion was designed with objectives for higher productivity, better pressure transfer between laterals, delay in water encroachment by down hole control, and higher cumulative production. The design was based on highly detailed dual porosity and dual permeability cross-sectional, sector and full field simulation models in addition to field trials.

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SPE Members Abstract Development of water coning in naturally fractured reservoirs and the issues of critical rates and cone breakthrough times are examined in terms of appropriate reservoir properties. A correlation is proposed to account for fracture acceleration effects in the computation of critical rates and the breakthrough times for uniformly distributed fractures. For a fractured systems with non-uniform fracture distribution, cone development is asymmetrical and the concept of partial completion to prevent coning becomes inapplicable. As such, for heterogeneously fractured reservoirs, estimation of critical rate and breakthrough time requires modeling with an understanding of fracture pattern around the producing wells. Introduction Optimization of completion interval and production scheduling requires consideration of factors affecting cone development in bottom water drive reservoirs. Water coning is a phenomena caused by an imbalance between the gravitational and viscous forces around the completion interval. From a force balance relationship, an estimation can be made of the maximum rate above which a cone may develop for a particular wellbore and reservoir configuration. Additionally, correlations have been developed for estimation of water breakthrough time for wells producing at a constant rate and above the critical rates. Furthermore, the water oil ratio behavior after cone breakthrough has been discussed in the literature. Correlations published for homogeneous reservoirs incorporate the effect of vertical permeability in terms of an anisotropy ratio; kv/kh. Presence of shale breakers and the effect of compaction cause reductions in the vertical permeability. There are, however, cases where the kv/kh can be larger than unity. A prime example is the situation with naturally fractured reservoirs. High vertical permeabilities in fractures are bound to accelerate the coning process resulting in lowering of the critical rates and more rapid breakthrough times. Additionally, the preferential path for fluid flow through the fractures and the uneven fracture conductivities commonly observed in naturally fractured reservoirs is expected to affect wells regardless of their structural position. Furthermore, the role of the tight matrix in controlling the interporosity flow needs to be studied. For naturally fractured reservoirs that can be represented by a dual porosity model of the type described by Warren and Root, two interporosity parameters, and are convenient means for representation of the storativity and transmissivity of the system. Intuitively, the critical rates for such systems should be influenced by the storativity of the fracture network. The saturation profiles developed in matrix and fractures are expected to be non-similar in extent and breakthrough times. The issue of coning behavior in naturally fractured reservoirs has received limited attention. The purpose of this paper is to examine the nature of cone development in naturally fractured reservoirs, to scrutinize the application of conventional correlations for such systems and to propose alternative correlations and guidelines for completion strategies and optimal rate determinations. PREDICTION METHODS Early work on analysis of critical rates to prevent coning, such as the method published by Muskat and Wyckoff focused on a force balance between the gravitational and viscous effects. P. 551^

This paper discusses a field example of capillary pressure effects on down hole formation tester pressure measurements and oil-water contact estimation. Capillary pressure effects are investigated as functions of mud invasion, mobile formationwater, and rock wettability. Specifically, the effects of mudfiltrate invasion on formation tester probe pressures are quantified in terms of the error margin on the oil-water contact estimate. In the field example, a fluidpressure gradientof about .45psi/ft was established from the bottom to the top of the reservoir, which is indicative of a water bearing formation. On the other hand, bottom hole fluid samples with the Modular Formation Dynamics Tester (MDTTM) showed a 100%oil recovery in shallow intervals, moderate oil-cut recovery in the intermediate intervals, and lowoil-cut recovery in the deep intervals. The purpose of this paper is to use formation tester information from the field example well, offset delineation wells, and reservoir behavior information, to support and explain that the apparent gradient in this case is not a true representative of the fluid gradient in the reservoir, rather, it represents the water phase gradient created by filtrate invasion and mobile water. A simulation model was developed, based on reservoir properties and laboratory measured capillary pressures, to simulate the formation saturation as a function of mud filtrate invasion and mobile water. Log-derived water saturations were used as a guidance, and ultimately, the model was used to predict the apparent pressure readings by the formation tester. Together with the understanding of reservoir behavior derived from the simulation model, field data from all delineation wells were used to define the effects of mud filtrate invasion on formation tester pressure measurements. Consequently, the error margin on the oil-water contact estimate is benchmarked. Based on the field evidence, the paper also discusses which methodology is most accurate to use in the oil-water contact delineation in the field area of interest. Introduction In our field case example, oil-cut samples were retrieved from the formation with apparent water gradient in well A2, located in Haradh Increment-3 area, Arab-D reservoir. In order to shed some light on the observed phenomenon we shall present the results of the MDT job, identify the pressure points and zonations that samples were collected from, prior to the discussion and explanation of the observations. Firstly in the discussion, the definition of the oil-water contact, free water level, capillary pressure, and all relevant technical attributes will be presented. Secondly, the wettability of Haradh Arab-D rocks must be established. Then a field case will be used to illustrate the capillary effects of filtrate and mobile water upon the measured pressures using data from well A2 as well as data from relevant wells, e. g. A1, A3 and A4. Lastly, all reservoir parameters are put together in amodel to simulate the impact of capillarity on measured pressures.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a successful integration of sparsely distributed permeability data including core-derived permeability and welltest-derived permeability into a viable geocellular model of 3.96 million cells for a giant carbonate reservoir.The resulting model required minimum permeability modification to achieve a 40-year history match. Fracture intensity trend was derived by carefully comparing the curvature of the structure, detailed matrix permeability, and welltest-derived permeability. This approach, although intuitive, allows for a better and realistic characterization of this large reservoir in the absence of seismic and other fracture identification tools like image logs while preserving vertical and lateral variation in permeability. Moreover, the paper presents statistical analysis of core-derived permeability illustrating lateral variation of permeability distribution.