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Collaborating Authors
Vik, Bartek
Viscous Oil Recovery by Polymer Injection; Impact of In-Situ Polymer Rheology on Water Front Stabilization
Vik, Bartek (Uni Research, CIPR) | Kedir, Abduljelil (Uni Research, CIPR) | Kippe, Vegard (Statoil ASA) | Sandengen, Kristian (Statoil ASA) | Skauge, Tormod (Uni Research, CIPR) | Solbakken, Jonas (Uni Research, CIPR) | Zhu, Dingwei (Uni Research, CIPR)
Abstract Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray. Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties. Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated. An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability. Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate. The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution. Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough. These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front. The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths. This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.
- Asia > Middle East (0.46)
- North America > Mexico (0.28)
- North America > United States (0.28)
- Geology > Mineral > Silicate (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
2-D Visualisation of Unstable Waterflood and Polymer Flood for Displacement of Heavy Oil
Skauge, Arne (CIPR, Uni Research and Univ. of Bergen, Norway) | Ormehaug, Per Arne (CIPR, Uni CIPR, Norway) | Gurholt, Tiril (Uni CIPR and Univ. of Bergen, Norway) | Vik, Bartek (CIPR, Uni CIPR, Norway) | Bondino, Igor (Total E&P, France) | Hamon, Gerald (Total E&P, France)
Abstract Waterflooding and polymer assisted waterflood in heavy oil reservoirs has currently gaining great attention. Enhanced water injection schemes represent an alternative in cases where thermal methods are either impractical or uneconomic. This study describes and analyses the oil mobilization by imaging the oil displacement at adverse mobility by injection of brine and polymer. The objectives were to improve description of viscous instabilities, mechanisms for finger growth, water channeling at adverse mobility ratio, and oil mobilization by polymers. Experiments have been made on 2D (30cmx30cm Bentheimer slabs) studying waterflooding and tertiary polymer injection in extra heavy oils (2000cp and 7000cp). The sandstone represents a relatively homogeneous and high permeability porous medium. The experiments utilize gamma and X-ray source for porosity and saturation measurements, and an X-ray imaging system to visualize displacements and thereby quantify the underlying flow mechanisms and oil recovery. At water wet condition capillary smears the front and prevents viscous fingers even at high adverse viscosity ratio. Changes in wettability (aging the rock material) dampen the capillarity and fingers then become more pronounced. High microscopic recovery to waterfloods (up to 30% after 5 PV injected) were achieved, and most importantly a rather impressive further gain in oil recovery after polymer flooding reaching final recoveries of more than 60%. The waterflood creates multiple thin sharp fractal-like fingers that propagate in the Bentheimer sandstone material. The 2D X-ray imaging describes the finger formation, growth, and also the later water channels formed. Polymer injection gives a fast increase in oil production, and analysis from the imaging proves that the oil is mainly produced through the established water channels. The 2-D experiments demonstrate the mechanisms of how heavy oil is mobilized by polymer injection. Saturation maps were accurately measured by means of X-ray scans and this enabled the visualization of flow instability, establishment of water channels and oil mobilization with high resolution.
- Europe (0.69)
- North America > United States (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
Abstract Vuggy carbonates are an important pore class for carbonate oil reservoirs. The determination of fluid flow properties like relative permeability from laboratory core floods in not trivial for this heterogeneous type of material. In many cases unusual responses have been observed, showing that several basic assumptions used for the interpretation of laboratory core floods are violated for vuggy material. Since the fluid properties can be attributed to the internal structure of the material it is important to highlight rock characterization. The local vug-matrix heterogeneity and connectivity of vuggs leads also to question about representative elementary volume for petrophysical and fluid flow properties. We focus in this paper on vuggy carbonate rock characterization based on Nuclear Magnetic Resonance (NMR), Micro Computed Tomography (µCT) and Computed Tomography (CT) measurements. The objectives of the research have been to establish a basis for estimates of fluid flow and oil recovery efficiency in vuggy carbonate rocks. Introduction About 50% of the world's hydrocarbon reserves are in carbonate rock formations. When compared to most sandstone material the carbonate rocks are however more challenging for estimation of petrophysical properties and understanding of fluid flow and recovery mechanisms. Carbonate rocks differ with aspect of heterogeneity and a wide range of different pore classes. The study reported in this paper is performed on a vuggy carbonate rock, originating from outcrop from the Prebetic subzone of the Betic range (Spain). The pore space of the vuggy material studied here is divided into two main groups, matrix and vuggy. Nuclear Magnetic Ressonance (NMR) measurements are used to quantify the average porous volume represented by the vugs and the matrix. NMR measurements indicated that 65% of the total porosity could be attributed to vugs, while 35% was matrix porosity. The total porosity of the vuggy material was 29%. Based on the assumption that a large difference in pore size for the two groupings influences fluid properties a Micro Computed Tomography (µCT) on one- and two-phase saturated sample was carried out. The µCT measurements show difference for spontaneous imbibition properies between vuggy and matrix pore types. The µCT data show also that mostly of the vuggy pore space is at and above the millimetre scale. Since medical CT instruments scan can reproduce the spatial distribution of porosity below the millimeter scale a 10cm diameter cylindrical core was scanned. The voxel size was 0.305 x 0.305 x 1.5mm. Treating the material as a two segment material consisting of vugs and matrix, each voxel in these images must be classified as either a vug or matrix. For the segmentation of a 3D model a priori information about matrix-vug ratio is applied. This is done by defining a CT threshold value which gives the wanted matrix-vug ratio for the 3D model. Voxels with a higher CT value are defined as vugs while those with a lower CT value are defined as matrix. The CT data was subsequently quantified and subject to simple statistical analysis giving: vug fraction to total porosity, distance to nearest neighbour, and vug size distribution. The permeability and porosity measurements, that are used as average values for this material, have been made on epoxy coated cylindrical core with diameter of 10cm and length of 38cm. Absolute permeability was found to be 33.9Darcy and porosity 28.9%.
- North America > United States (0.95)
- Europe (0.66)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)