Seventy nine HPMI (high pressure mercury injection) derived saturation height function curves are used to create nine different capillary bundles for Minagish Oolite carbonate reservoir. Each capillary bundle is tied up with its sedimentological and petrophysical attributes to create a discrete pore type/porefacies. The best pore type (Type 0) has well connected pore throat with lesser tortuosity as represented by very low entry point, low irreducible water saturation (Swirr) and wide plateau of the function curve. The worst one (Type 8) is very fine pore throats with high restriction of flow due to high entry point and very high irreducible water saturation. Good porefacies (Type 0, 1 and 2) represent mostly intergranular pore dominated samples, not much affected by subsequent cementation and dissolution. Intermediate pore types (Type 3,4 and 5) are found to have both primary intergranular and secondary solution rich pore spaces. The bad porefacies (Type 6,7 and 8) are either mud dominated or highly cemented rocks with restricted pore spaces. HPMI based poro-perm clusters are also used to create porefacies in the uncored wells and subsequently populated in 3D grid using variogram. Saturation height function of each representative capillary bundle is then used to tie the saturation value of individual porefacies along the well path in more than 250 wells. The newly constructed saturation grid is well tied with specific pore type of each facies and thus suitable to explain the fluid flow behavior within the reservoir. Well wise production behaviour and certain issues of anomalous production rate as well as water cut are satisfactorily explained through this workflow.
A 3D reservoir geomechanics study was conducted in the Lower Cretaceous Minagish Oolite reservoir, Umm-Gudair field, West Kuwait, using coupled modelling. A series of parametric studies was performed to understand the impact of permeability changes on pressure, water production, and oil production at a selection of key wells. The evolution of fieldwide water saturation during more than 40 years of production was examined. The anisotropy between vertical and horizontal permeabilities was investigated. The coupled modelling demonstrated the impact of geomechanics changes (alterations in stress and strain) on both well and overall field performance. A 3D geomechanical model was developed based on an existing dynamic reservoir model and static geological model. The 3D model consisted of 3,993,134 grid-cells and included the reservoir, its surrounding formations, and 10 seismically interpreted faults. Mechanical properties derived from well data, in situ measurements, and triaxial test data were populated within the 3D model. A preproduction stress calculation was performed to obtain a representative initial stress state before production, with calibration against measurements along various wells. The effective stress changes caused by depletion were simulated at various intervals over the production time; the reservoir displacements, both horizontally and vertically, were computed. To simulate the impact of reservoir rock deformation on reservoir performance, permeability updating was simulated considering the pore volume change of intact rock, the induced plastic shear strain of formed microcracks, and the dilation/opening of preexisting nonconductive fractures. This resulted in the variation of well performance in terms of pressure, water production, and oil production.Four permeability updating scenarios were tested to understand the impact of dynamic permeability updating on well performance and field behaviour. The results show (a) an improved history matching of well pressure at almost all examined wells, (b) an improved history matching of water and oil productions at most of the examined wells, and (c) an insignificant impact on those wells along the flanks, despite significant improvements at the core of the anticlines. The results of this study provided guidance for optimal field development planning.
Ratawi Limestone is a fairly low permeability reservoir in the Umm Gudair field of Kuwait. Production history shows low liquid rate and fast pressure depletion around the wellbore. To understand the causatives for flow restriction, this study captures systematically different pore types, their relationship, distribution, connectivity and their impact on reservoir fluid flow behavior. It is observed that pores are not related to any depositional surface and are rather formed due to mesogenetic corrosion of highly micritized, tight carbonate rock bodies. Primary pores are almost completely destroyed during the process of shallow burial diagenesis. Separate vug pores are both fabric as well as nonfabric selective type and are the main contributor of pore volume within an overall pervasive (micritic) matrix pore dominated system of wackestone and packstone. Five porefacies are created on the basis of capillarity within a wider range of pore throat size variation. Type 1 is represented by macropores, Type 2 and 5 are mesopore and rests are micropore dominated. Each porefacies is assigned a linear equation on core calibrated porositypermeability transform. The resultant permeability shows about 20% less value compared to permeabilities of corresponding intergranular Lucia class 2 pore type. This gap is specially pronounced within the reservoir rocks with high porosity and intermediate permeability values. Seven years of production history of this reservoir shows low rate of production with rapid pressure depletion around wellbore within a few months of production. Logical option to improve production is to increase the reservoir contact using horizontal multilaterals along with reduced well spacing and aggressive pressure support through water injection.
Integrated field development studies were performed to increase oil recovery from the Marrat reservoir in the Umm Gudair field, a large, low permeability, complex, naturally fractured and highly faulted carbonate reservoir. The studies involved rebuilding the static model, creating and history matching a new dynamic model and using it to examine redevelopment scenarios. These included well interventions and workovers under primary depletion, secondary waterflood and, following a screening exercise, low salinity flooding (LSF). A new structural interpretation of 3D seismic data provided a revised static geological model and yielded insight into the number, geometry and origin of the many faults intersecting the reservoir. Rock types defined from core analysis were distributed in the static geological model using trends from Bayesian lithofacies classification based on pre-stack inversion of seismic data. Porosity and permeability were modelled by rock type. Saturation-height functions for each rock type were developed from mercury injection capillary pressure (MICP) data; and the reservoir free water level was varied so that these functions honoured the log-based water saturation interpretation. The dynamic model input description was based on available and interpreted data for the assumed oil wet reservoir. The history matching was aided by sophisticated application of decline curve analysis (DCA) and used an Opportunity Index approach to optimise well placement. The history matching led to a simplified and effective solution for characterising the locally naturally fractured reservoir nature. The effect of high permeabilities associated with increased fracture density was accommodated by introducing facies-based and distance from fault-related permeability modifiers, while maintaining geological rigour. The dynamic model was used to examine a range of field redevelopment scenarios. This showed that LSF could enhance field recovery and achieve a three-fold increase in estimated ultimate recovery, in conjunction with other improved reservoir management strategies. The results provided support for specialised laboratory and dynamic modelling investigations as a precursor to LSF pilot trials. A low cost source of LSF injectant was identified which could contribute to lowering the overall carbon footprint.
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