Appraisal of the Use of Polymer Injection To Suppress Aquifer Influx and To Improve Volumetric Sweep in a Viscous Oil Reservoir
- D.S. Hughes | D. Teeuw | C.W. Cottrell | J.M. Tollas
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1990
- Document Type
- Journal Paper
- 33 - 40
- 1990. Society of Petroleum Engineers
- 5.6.5 Tracers, 5.4.10 Microbial Methods, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.3.2 Multiphase Flow, 4.1.9 Tanks and storage systems, 5.5 Reservoir Simulation, 4.1.5 Processing Equipment, 6.5.2 Water use, produced water discharge and disposal, 1.8 Formation Damage, 2.4.3 Sand/Solids Control, 5.2 Reservoir Fluid Dynamics, 5.1 Reservoir Characterisation, 5.1.2 Faults and Fracture Characterisation, 1.2.3 Rock properties, 4.3.4 Scale, 5.6.4 Drillstem/Well Testing, 5.2.1 Phase Behavior and PVT Measurements, 6.6.2 Environmental and Social Impact Assessments, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 5.3.1 Flow in Porous Media
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A novel way to use polymer injection to suppress the influx of a strong edge aquifer in a shallow, dipping reservoir containing a 15-cp [15-mPa.s] oil and thereby to improve volumetric sweep has been investigated. Experimental studies were undertaken to determine the appropriate polymer properties. which were then used in simulation studies to establish oil-recovery profiles.
Most, but not all. North Sea oil reservoirs contain low-viscosity crudes. One exception is Gannet South, which contains oil with an in-situ viscosity of about 15 cp [15 MPa.s]. With such a viscosity, the water/oil endpoint mobility ratio is unfavorable (M = 7), and a possibility exists of improving the recovery at realistic oil rates by viscosifying the injected seawater with polymer. This paper describes the acquisition of biopolymer data and the simulation of natural waterdrive and polymer injection in the Gannet South reservoir. The performances of alternative displacement mechanisms and conceptual reservoir development scenarios are reported.
The reservoir interval is contained in the Upper Paleocene Forties formation and is overlain by Lower Eocene shales. The Forties formation comprises a sequence of submarine fan deposits, and this reservoir is located in the proximal. inner (interbedded sand/shale) to middle (mainly massive sand) fan region. The formation has been subdivided into three intervals. the Upper Sand. the Mid-Reservoir Shale, and the Lower Sand. The basic reservoir structure is anticlinal with some faulting, primarily at the crest of the structure (Fig. 1). The vertical throw, however, is normally less than 100 ft [30 m] and is not expected to affect the continuity of the Mid-Reservoir Shale. The flanks of the structure have fairly gentle dips with a maximum of about 8 observed over the reservoir section. A large aquifer exists. probably with good communication. The bulk of the hydrocarbons are located in the Upper Sand Unit. and this is the only interval considered in the simulation study. It is about 200 ft [61 m] thick and consists of a variable sequence of locally clean. massive, fine-to-medium-grained sands that are separated by relatively thin shales. The reservoir quality of the sands is very good and relatively uniform, with average porosity of 28% and permeability from 300 to 2.400 md. The effective vertical permeability is reduced by the presence of the shales. These shales generally are expected to have limited lateral extent. the majority ranging from a few tens of feet up to several hundred feet and occasionally up to several thousand feet. For modeling purposes the dimensions have been estimated from the depositional setting and the observed shale frequency and thicknesses in the exploration wells. Although the possibility that a shale could extend over the whole field cannot be ruled out. it is likely that some communication would be maintained by minor faulting. The effective vertical permeability has been estimated by using the statistical approach of Begg and King and by constructing a simulation model with the shales distributed randomly within the geological and observed constraints. In both cases, the kv/kH ratio is estimated at just above 0.01. The basic data used in the simulation models were determined from analyses of logs, cores, and well tests. Table 1 gives the general field data. The permeability profile (Table 2) was derived from core plugs recovered from one well. While relatively high permeabilities are observed throughout, a reduced-permeability zone is located in the center of the cross section, and slightly higher permeabilities are found at the top and bottom.
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