Effects of the laminated-structure and mixed wettability on the oil/water relative permeabilities and oil productions in shale oil formations

Oil–water relative permeability curve is an important parameter for analyzing the characters of oil and water seepages in low-permeability reservoirs. The fluid flow in low-permeability reservoirs exhibits distinct nonlinear seepage characteristics with starting pressure gradient. However, the existing theoretical model of oil–water relative permeability only considered few nonlinear seepage characteristics such as capillary pressure and fluid properties. Studying the influences of reservoir pore structures, capillary pressure, driving pressure and boundary layer effect on the morphology of relative permeability curves is of great significance for understanding the seepage properties of low-permeability reservoirs. Based on the fractal theory for porous media, an analytically comprehensive model for the relative permeabilities of oil and water in a low-permeability reservoir is established in this work. The analytical model for oil–water relative permeabilities obtained in this paper is found to be a function of water saturation, fractal dimension for pores, fractal dimension for tortuosity of capillaries, driving pressure gradient and capillary pressure between oil and water phases as well as boundary layer thickness. The present results show that the relative permeabilities of oil and water decrease with the increase of the fractal dimension for tortuosity, whereas the relative permeabilities of oil and water increase with the increase of pore fractal dimension. The nonlinear properties of low-permeability reservoirs have the prominent significances on the relative permeability of the oil phase. With the increase of the seepage resistance coefficient, the relative permeability of oil phase decreases. The proposed theoretical model has been verified by experimental data on oil–water relative permeability and compared with other conventional oil–water relative permeability models. The present results verify the reliability of the oil–water relative permeability model established in this paper.

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Spatially resolved wettability measurements using nmr wettability index

E3S Web of Conferences ◽

10.1051/e3sconf/20198903001 ◽

2019 ◽

Vol 89 ◽

pp. 03001

Author(s):

M. J. Dick ◽

D. Veselinovic ◽

D. Green

Keyword(s):

Oil And Gas ◽

Gas Reservoirs ◽

Bulk Oil ◽

Partially Saturated ◽

Spatially Resolved ◽

Industry Standard ◽

Least Squares Fit ◽

Mixed Wettability ◽

Petrophysical Parameter ◽

Oil Water

Wettability is a crucial petrophysical parameter for determining accurate production rates in oil and gas reservoirs. However, industry standard wettability measurements (Amott Test and USBM) are expensive and time consuming. It is known that NMR response varies as a function of wettability change in rock core plug samples. This information was used to develop an NMR wettability index (NWI) based on T2 distributions. This NWI is capable of measuring changes in wettability as a function of oil/water saturations unlike traditional methods which are based on measurements at Swi and Sor only. In addition, these oil/water saturations are determined without the aid of any special oil or brine, such as D2O. This allows the NMR method to nondestructively monitor changes in wettability in real time (i.e. during a flooding experiment or an aging procedure). In this work, we have coupled this T2-based NWI to spatially resolved T2 NMR measurements to monitor changes in wettability and saturation along rock core plugs. In order to derive an NMR wettability index, NMR T2 spectra of 100% brine saturated, 100% oil saturated, bulk oil and bulk brine are needed. These spectra are then mixed to give a predicted T2 spectrum which is compared (via a least squares fit) to a T2 spectrum recorded from a sample partially saturated with both water and oil and whose wettability is to be determined. For initial testing, three sandstone samples were employed along with 2% KCl brine and dodecane. To achieve sample states of mixed wettability, 100% brine saturated samples had dodecane pushed into them via centrifugation. Centrifugation at different speeds resulted in samples of varying bulk and spatial wettabilities from which NWI parameters and oil/water saturations were determined. The bulk wettabilities were compared to measurements done using the standard Amott test and oil/water saturations were confirmed by repeating experiments using NMR invisible D2O.

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An Improved Model For Estimating Three-Phase Oil-Water-Gas Relative Permeabilities From Two-Phase Oil-Water And Oil-Gas Data

Journal of Canadian Petroleum Technology ◽

10.2118/90-02-07 ◽

1990 ◽

Vol 29 (02) ◽

Cited By ~ 5

Author(s):

Sunil Kokal ◽

Brij B. Maini

Keyword(s):

Relative Permeabilities ◽

Two Phase ◽

Three Phase ◽

Oil Water ◽

Improved Model ◽

Water Gas ◽

Oil Gas

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An Improved Three-Phase Relative Permeability and Hysteresis Model for the Simulation of a Water-Alternating-Gas Injection

SPE Journal ◽

10.2118/152218-pa ◽

2013 ◽

Vol 18 (05) ◽

pp. 841-850 ◽

Cited By ~ 15

Author(s):

H.. Shahverdi ◽

M.. Sohrabi

Keyword(s):

Relative Permeability ◽

Oil Recovery ◽

Gas Injection ◽

Phase Flow ◽

Relative Permeabilities ◽

Water Alternating Gas ◽

Three Phase ◽

Three Phase Flow ◽

Oil Water ◽

Wag Injection

Summary Water-alternating-gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of relative permeability (kr) and capillary pressure (Pc) functions for each fluid phase, in a three-phase-flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most important phenomena manipulating the performance of WAG injection, and hence, it has to be carefully accounted for. In this study, we have benefited from the results of a series of coreflood experiments that we have been performing since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular, we focus on a WAG experiment carried out on a water-wet core to obtain three-phase relative permeability values for oil, water, and gas. The relative permeabilities exhibit significant and irreversible hysteresis for oil, water, and gas. The observed hysteresis, which is a result of the cyclic injection of water and gas during WAG injection, is not predicted by the existing hysteresis models. We present a new three-phase relative permeability model coupled with hysteresis effects for the modeling of the observed cycle-dependent relative permeabilities taking place during WAG injection. The approach has been successfully tested and verified with measured three-phase relative permeability values obtained from a WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas relative permeability during consecutive water-and-gas-injection cycles as well as the increase in oil relative permeability happening in consecutive water-injection cycles.

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