The Successful Implementation of a Novel Polymer EOR Pilot in the Low Permeability Windalia Field
- Andrew Kenneth Haynes (Chevron Australia Pty Ltd) | Martyn David Clough (Chevron Australia Pty Ltd) | Alistair J. P. Fletcher (Chevron Australia Pty Ltd) | Stuart Weston (Chevron Australia Pty Ltd)
- Document ID
- Society of Petroleum Engineers
- SPE Enhanced Oil Recovery Conference, 2-4 July, Kuala Lumpur, Malaysia
- Publication Date
- Document Type
- Conference Paper
- Society of Petroleum Engineers
- 5.5.8 History Matching, 1.10 Drilling Equipment, 1.2.2 Geomechanics, 1.8 Formation Damage, 4.1.5 Processing Equipment, 5.4.10 Microbial Methods, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.6 Thermal Methods, 6.5.2 Water use, produced water discharge and disposal, 3 Production and Well Operations, 4.1.2 Separation and Treating, 5.4.1 Waterflooding, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.4.2 Gas Injection Methods, 4.3.4 Scale, 1.2.3 Rock properties, 5.7.2 Recovery Factors, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 6.3.7 Safety Risk Management, 4.2 Pipelines, Flowlines and Risers, 5.6.4 Drillstem/Well Testing
- polymer, low permeability, EOR, low molecular weight, in-depth flow diversion
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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.
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