Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

Graue, A.; Bognø, Thomas; Baldwin, B.A.; Spinler, E.A.

doi:10.2118/74335-pa

Cited by 33 publications

(14 citation statements)

References 19 publications

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“…2 and 5 show that diffusion as an oil-recovery mechanism is effective at the laboratory scale with R F ¼ 86% original oil in place (OOIP) during first-contact-miscible CO 2 injection with small cylindrical core plugs. The recoverable oil by CO 2 is higher than that of waterflooding when the same rock type is used, in which oil recoveries between 30 and 60% OOIP are observed depending on wettability (Graue et al 2001(Graue et al , 2002. It also indicates that the diffusion could be important in a highly fractured reservoir.…”

Section: Discussion and Numerical Analysismentioning

confidence: 97%

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

et al. 2016

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This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO 2 ) for enhanced oil recovery, depending on the CO 2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO 2 injection (R F ¼ 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 Â10 À9 m 2 =s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO 2 injection declined exponentially with increasing diffusion lengths from the CO 2 -filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oilrecovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.

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Section: Discussion and Numerical Analysismentioning

confidence: 97%

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

et al. 2016

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“…This provides us with the opportunity to test the influence of the initial wetting saturation used in the model. We used n-decane in experiment SSE A and decahydronaphthalene in experiment SSE B , because decahydronaphthalene (also called decalin) is a commonly used mineral oil in core-scale experiments [38]. The flow rate was then set to 0.02 ml/min.…”

Section: Steady-state Imbibition Experimentsmentioning

confidence: 99%

Validation of model predictions of pore-scale fluid distributions during two-phase flow

et al. 2018

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Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.

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“…The role of wettability on recovery from fractured rock was discussed in (Graue et al, 2001, Haugen et al, 2010. Blocks of porous media with defined fracture surfaces were flooded with brines and the importance of wettability was demonstrated by increased tendency to adsorb water into the more water-wet blocks as observed using MRI techniques.…”

Section: Experimental Brine-dependent Oil-recoverymentioning

confidence: 99%

A Model for Wettability Alteration in Fractured Reservoirs

et al. 2015

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Many of the world's oil reservoirs are naturally fractured. Injected water will flow into this highly permeable network and not sweep the matrix containing most of the oil. Spontaneous imbibition can drive oil into the fractures by capillary forces. However the wettability of the reservoir is critical for the ultimate potential of oil recovery. Experimental results indicate that exposing chalk cores to seawater or similar brines may alter the wettability towards a more water-wet state. In a fractured reservoir this exposure will happen by molecular diffusion and by water imbibing into the matrix. The injected brine is not in chemical equilibrium with the in-situ rock, water and oil so that chemical reactions occur. Experiments have shown that for chalk rocks the relevant processes are adsorption/desorption of ions on the mineral surface, precipitation/dissolution of minerals or ion exchange. We have developed a model where a reservoir is defined by a fracture surrounded by matrix on both sides. The injected brine contains a component that can adsorb on the matrix surface. These changes of the mineral surface are assumed to alter the wettability towards a more water-wet state. The wettability alteration is described by shifting curves for relative permeability and capillary pressure from curves representing oil-wet conditions towards curves representing more water-wet conditions. The model can make predictions regarding the effect of matrix properties such as wettability and external parameters such as schedule of brine compositions and injection rate. The understanding of the coupling between wettability alteration controlled by water-rock chemistry and fracture-matrix flow is highly relevant for gaining more insight into the observed high recovery in the North Sea chalk field Ekofisk. TX 75083-3836, U.S.A., fax +1-972-952-9435

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Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

Cited by 33 publications

References 19 publications

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

Validation of model predictions of pore-scale fluid distributions during two-phase flow

A Model for Wettability Alteration in Fractured Reservoirs

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