MRI Tomography of Saturation Development in Fractures During Waterfloods at Various Wettability Conditions
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAt three different wettabilities, two stacked outcrop core plugs, separated by a 1 mm fracture, were waterflooded. During the experiment in-situ fluid saturations were monitored with Magnetic Resonance Imaging (MRI). The sequence of 2D MRI images corroborated earlier lower resolution, larger scale experimental results on the effect of fractures during waterflooding at various wettabilities. The MRI images of oil saturation development in the fracture clearly … Show more
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Cited by 5 publications
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The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions. Introduction Production of oil from naturally fractured reservoirs is commonly governed by co- and counter-current imbibition of water. Imbibition is dependent on wettability due to the controlling capillary forces, and waterflooding fractured reservoirs have been successful in many water-wet reservoirs. Extensive waterflooding over several years in the oil-wet field Ghaba North in Oman, however, resulted in very low oil recovery (around 2 %) as most of the oil was produced from the fractures only. Fractures generally exhibit a relatively small volume of the total porosity in fractured reservoirs (typically 1–3 %), but the fracture network is important for fluid flow due to much higher permeability and the augmentation of accessible surface in which imbibition may occur. In water-wet reservoirs, oil is produced from the matrix to the fracture system by capillary imbibition of water with subsequent oil expulsion. Capillary continuity between isolated matrix blocks is in general recognized as favorable in fractured reservoirs dominated by gravity drainage. Capillary continuity across fractures in preferentially oil-wet reservoirs may increase ultimate recovery during gas assisted gravity drainage. Capillary continuity in preferentially water-wet reservoirs increases the height of the continuous matrix column and reduces the amount of capillary trapped oil. For oil recovery in fractured reservoirs produced by viscous fluid displacement, establishing stable wetting phase bridges may contribute to added viscous pressure components over isolated matrix blocks, and thus may increase the oil recovery above the spontaneous imbibition potential. Several authors 1–3 have shown experimentally that vertical capillary continuity across fractures becomes important when gravity is the driving force. Saidi 4 (1987) introduced the idea of capillary continuity through stable liquid bridges. Labastie 5 (1990) found that the permeability of the fractured material influenced the ultimate recovery of the gravity drainage; increased permeability lead to increased oil recovery. Stones et al.6 (1992) investigated the effect of overburden pressure and the size of the contact area of the porous material across the fracture. They concluded that the size of the contact area controls the transmissibility of oil, and therefore the ability of the fracture to transport liquids across the fracture. O'Meara Jr. et al.7 (1992) investigated the film drainage along coreholder end-pieces in centrifuge capillary pressure measurements, where they argued that if the conductivity of the film was large enough, the assumption of zero capillary pressure at the outlet end of the plug could be disregarded. Firoozabadi and Markeset 8 (1994) observed capillary continuity between isolated matrix blocks by liquid film drainage along non-porous spacers placed inside the fracture, and by liquid bridging forming inside the fracture. They concluded that the film flow and the degree of fracture liquid transmissibility controlled the rate of drainage across a stacked matrix blocks.
The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions. Introduction Production of oil from naturally fractured reservoirs is commonly governed by co- and counter-current imbibition of water. Imbibition is dependent on wettability due to the controlling capillary forces, and waterflooding fractured reservoirs have been successful in many water-wet reservoirs. Extensive waterflooding over several years in the oil-wet field Ghaba North in Oman, however, resulted in very low oil recovery (around 2 %) as most of the oil was produced from the fractures only. Fractures generally exhibit a relatively small volume of the total porosity in fractured reservoirs (typically 1–3 %), but the fracture network is important for fluid flow due to much higher permeability and the augmentation of accessible surface in which imbibition may occur. In water-wet reservoirs, oil is produced from the matrix to the fracture system by capillary imbibition of water with subsequent oil expulsion. Capillary continuity between isolated matrix blocks is in general recognized as favorable in fractured reservoirs dominated by gravity drainage. Capillary continuity across fractures in preferentially oil-wet reservoirs may increase ultimate recovery during gas assisted gravity drainage. Capillary continuity in preferentially water-wet reservoirs increases the height of the continuous matrix column and reduces the amount of capillary trapped oil. For oil recovery in fractured reservoirs produced by viscous fluid displacement, establishing stable wetting phase bridges may contribute to added viscous pressure components over isolated matrix blocks, and thus may increase the oil recovery above the spontaneous imbibition potential. Several authors 1–3 have shown experimentally that vertical capillary continuity across fractures becomes important when gravity is the driving force. Saidi 4 (1987) introduced the idea of capillary continuity through stable liquid bridges. Labastie 5 (1990) found that the permeability of the fractured material influenced the ultimate recovery of the gravity drainage; increased permeability lead to increased oil recovery. Stones et al.6 (1992) investigated the effect of overburden pressure and the size of the contact area of the porous material across the fracture. They concluded that the size of the contact area controls the transmissibility of oil, and therefore the ability of the fracture to transport liquids across the fracture. O'Meara Jr. et al.7 (1992) investigated the film drainage along coreholder end-pieces in centrifuge capillary pressure measurements, where they argued that if the conductivity of the film was large enough, the assumption of zero capillary pressure at the outlet end of the plug could be disregarded. Firoozabadi and Markeset 8 (1994) observed capillary continuity between isolated matrix blocks by liquid film drainage along non-porous spacers placed inside the fracture, and by liquid bridging forming inside the fracture. They concluded that the film flow and the degree of fracture liquid transmissibility controlled the rate of drainage across a stacked matrix blocks.
Recovery mechanisms in fractured carbonate rocks have been investigated by comparing laboratory experiments with numerical simulations. The experimental data include waterfloods in blocks of carbonate rock with 2D, in-situ fluid saturation of the advancing waterfronts. The waterfloods were initially performed on the whole block, and then repeated on the same block with a fracture network containing both closed and open fractures to isolate the effect from fractures. The primary objective for the experiments was to investigate how the presence of fractures altered the dynamics of the propagating waterfront. A numerical, grid based model of the block was created and a sensitivity study of the representation of fractures was carried out. Especially the impact of the degree of capillary contact over fractures was studied. Matrix capillary pressure and relative permeability curves were determined by history matching both average oil production and the in-situ fluid saturation profiles from the unfractured block experiment. These were in turn used as input for the matrix properties in the fractured block simulations. The results show how the degree of capillary contact between matrix blocks controlled fluid saturation development and influenced the waterflood oil recovery in fractured limestone. Sensitivity studies on the degree of capillary contact over fractures showed this to be the most significant parameter for the frontal propagation during waterfloods. Numerical simulations together with experimental data gave increased understanding of the waterflood oil recovery mechanisms in fractured carbonate rock. Introduction Oil production from water flooded fractured reservoirs is generally considered to be governed by spontaneous imbibition of water from the water filled fractures into the matrix blocks, causing the oil to be expelled into the more conductive fractures by counter-current imbibition. In addition, laboratory observations have indicated that capillary contact between matrix blocks may extend a viscous pressure across fractures, thus increasing oil recovery above the spontaneous imbibition potential for each isolated matrix block. Graue et al.1,2,3, Viksund et al.4 and Moe et al.5 found this process to be dependent on wettability in low-permeability chalk samples. They reported fractures to be barriers to flow for water at strongly water-wet conditions reflecting that the recovery mechanisms are capillary dominated. For less water-wet conditions, however, capillary contact across fractures may be established during waterfloods. The capillary contact transmits viscous pressure gradients across the fracture through wetting phase bridges before the fracture is filled with water, thus accelerating and adding a viscous component to the recovery of oil. The viscous component has been shown to compensate for loss of oil production due to reduced spontaneous imbibition at less water-wet conditions. Aspenes et al.6 recently showed how fluid flow in fractures was dependent on the fracture surface wettability during waterfloods in chalk plugs ranging from strongly water-wet to neutrally-wet using high resolution MRI. At gradually less water-wet conditions the formation of wetting phase bridges was observed. The wetting phase bridges transported a flow of water and transmitted a viscous pressure component across fractures to adjacent matrix blocks across fractures up to 2 mm in aperture. Objective The primary aim for the experiments was to investigate how the presence of fractures altered the dynamics of the propagating waterfront. This was investigated in larger scale experiments in limestone blocks. In addition, the experimental results were used as basis for numerical simulations to perform a sensitivity study related to the importance of capillary contact across the fractures.
Surfactant Pre-Floods during CO2 Foam for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates
An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.
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