Barrow Island's Windalia reservoir is Australia's largest onshore waterflooding operation and has been under active waterflood since 1967. The highly heterogeneous reservoir consists of fine-grained, bioturbated argillaceous sandstone that is high in glauconite clay. The high clay content results in a low average permeability (5 md) despite high porosities (25-30%) and hence fracture stimulation is required to achieve economic production rates.The Windalia reservoir and fluid properties preclude the use of traditional EOR technology, with thermal, miscible and mobility control processes all deemed unfeasible through screening studies. Consequently, the in-depth flow diversion mechanism was developed and applied, which utilizes a low molecular weight polymer to drive the growth of induced hydraulic fractures in the treated injection wells. A 3-injector pilot was executed involving polymer injection for two years, with no detrimental injectivity losses observed for polymer concentrations up to 750 ppm. Considerable fracture growth, oil production rate uplift and reduction in water cut were observed throughout the pilot pattern, in line with predictions: Fracture half-lengths increased from 6 ft to 400 ft in one injector and from 141 ft to 322 ft in another An initial oil rate uplift of 38% relative to the production baseline was observed; a more conservative estimate suggested that at least half of this was attributable to the tertiary recovery process The water-oil ratio was observed to fall from 15 to 11, similarly timed with the oil production increase.These improvements were observed consistently throughout the pilot area and were distinct from the waterflood behavior elsewhere in the field. This paper briefly summarizes the technology screening and pilot execution stages, after which the results from the pilot are presented and discussed. This technology may be of use in other low-permeability waterfloods with induced injector fractures, for which traditional EOR practices are believed to be unfeasible.
SUMMARYCore supported study of the heterogeneous Ungani dolomite reservoir architecture is driving development drilling and upgrades to field resource estimates. Vuggy connected and macro non-connected pore space was directly measured over a 70m continuous core using 3D structural analysis of CT-scans. Plug density measurements indicate non-connected or sub-140 micron resolution contribution of around 1% to 2.5% (pu) for the tight matrix, but all remaining porosity potentially contributes to oil production. The high resolution core porosity data is vertically repositioned and upscaled to calibrate neutron-density and sonic petrophysically derived porosities which are inadequate to resolve productive zones using conventional reservoir cut-offs. Conditioned resistivity image data correlated exceptionally with directly measured connected porosities. Reservoir properties were extrapolated to all wells across the Ungani field giving field net/gross estimates of up to 63% and porosities over 30% pu in some vuggy and brecciaed zones. The heterogeneity and prolific nature of the uppermost 17m of reservoir had not been previously recognised due to poor log data coverage and access at the casing points. Recent re-analysis of this section at Ungani-3 with Chemostrat ICP-OES-MS analysis of ditch cuttings was instrumental in proposing additional drilling to re-target this zone. Mineralogy analysis is used to calculate rock grain densities and help calibrate neutron-density derived porosity logs over the Ungani field. Up-scaled core porosity correlates well with density and sonic porosity logs. Resistivity logs adjusted for minerology can also be used to predict porosity and support the use of resistivity image logs to identify vuggy zones and estimate porosity at a higher resolution than conventional logging tools. A field static model was populated with three facies distributed over vertical zones according to the distribution encountered in the core porosity analysis and well logs, and iteratively matched to the dynamic pressure data and field production history which exhibits field scale multi-Darcy horizontal permeability and protection from vertical water cut. Further drilling and downhole artificial lift is planned to extend field production rates to 3000 bbls/day. Increased confidence in this regionally developed reservoir is supporting further exploration of undrilled prospects in this immature and under-explored trend
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