The Middle Minagish Oolite Formation is 450 to 550 feet thick interval of porous limestone reservoir, composed of peloidal/skeletal grainstones with lesser amount of packstone, oolitic grainstone, wackstone and mudstone in Umm Gudair field, West Kuwait. It is characterized by small scale reservoir heterogeneity, primarily related to the depositional as well as diagenetic features. Capturing reservoir properties in micro scale and its spatial variation needs special attention in this reservoir due to its inherent anisotropy. Reservoir properties will depend on the level that we are analyzing on reservoir (millimeter to meter scale). Here we used Electrical Borehole Image (EBI) and Nuclear Magnetic Resonance (NMR) to capture small scale feature of Umm Gudair carbonate reservoir and compared them with core data In present work, reservoir properties (including texture, facies, porosity and permeability) interpreted by the EBI shows good match with NMR driven properties and core data. Textural changes in image logs also match well with pore size distribution from NMR logs. Further highly porous zones which are considered either due to primary porosity or vugs match with larger pores of NMR logs and these corroborates with also core derived porosity. A good match has been observed between EBI, NMR and cored derived porosity. Permeability calculations have also been made and compared with core data. A detail workflow has been developed here to interpret reservoir properties on un-cored wells, where only low vertical resolution data is available. This technique is quite useful to identify the characters and mode of origin highly porous zones in reservoir section which are generally not identifiable by low resolution standard logs. This workflow will allow us to interpret the heterogeneity at high resolution level in un-cored wells, as results are validated with integration of EBI, NMR and core data.
The Umm Gudair field is located in West Kuwait. Oil was discovered in the Lower Cretaceous Minagish Oolite in 1962 and around 180 wells have been drilled on the structure. The field has been geographically divided into three smaller sectors; East Umm Gudair (EUG), West Umm Gudair (WUG) and South Umm Gudair (SUG). It essentially consisits of two anticlines, EUG/SUG and WUG connected by a saddle; into a single accumulation. Overlying the Minagish Oolite is the Ratawi limestone reservoir of around 300 feet, and is composed of mudstone/wackstone rock, representing middle to inner ramp depositional setting. The reservoir is broadly defined by three units; Lower, Middle and Upper units. The Lower and Upper units are non-reservoir, while the Middle unit of an average thickness of around 50 feet, has moderate to high porosity, is hydrocarbon bearing and developed in EUG. Six wells have been tested till date, with relatively low productivity and rapid decline of pressure, suggesting that the unit is heterogeneous.Based on the recently acquired seismic data, an integrated study was conducted, encompassing geological, geophysical and petrophysical data to understand the reservoir complexity. Seismic attributes along with deterministic inversion techniques, utilizing the relationship of acoustic impedance and porosity have been employed to identify areas of good porosity development. The multidisplinary work has provided an understanding of the reservoir heterogeneity and is expected to be used in future development of this reservoir.
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.
This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model. Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty. Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability. Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.
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