Digital imaging technology-based method for calculating relative permeability of tight core

Abstract

The invention discloses a digital imaging technology-based method for calculating relative permeability of tight core, comprising the following steps: step S1: preparing a small column sample of tight core satisfying resolution requirements; step S2: scanning the sample by MicroCT-400 and establish a digital core; step S3: performing statistical analysis on parameters reflecting the characteristics of rock pore structure and shape according to the digital core; step S4: calculating tortuosity fractal dimension DT and porosity fractal dimension Df by a 3D image fractal box dimension algorithm; step S5: performing statistical analysis on maximum pore equivalent diameter λmax and minimum pore equivalent diameter λmin by a label. The present invention solves the problems of time consumption of experiment, instrument accuracy, incapability of repeated calculation simulations and resource waste by repeated physical experiment.

Claims

1. A digital imaging technology-based method for calculating relative permeability of tight core, comprising the following steps: Step S1: preparing a small column sample of tight core satisfying resolution requirements; Step S2: scanning the sample by MicroCT-400 and establishing a digital core; Step S3: performing statistical analysis on parameters reflecting rock pore structures and shape characteristics according to the digital core; Step S4: calculating a tortuosity fractal dimension D.sub.T and a porosity fractal dimension D.sub.f by a 3D image fractal box dimension algorithm; Step S5: performing statistical analysis on maximum pore equivalent diameter λ.sub.max and minimum pore equivalent diameter λ.sub.min by a label; Step S6: simulating a water-oil displacement in single fractal capillary, calculating a critical capillary diameter λ.sub.cr, and obtaining the critical capillary diameter at a displacement time t; Step S7: determining a fluid type at an outflow end with the critical capillary diameter, calculating a water-phase fluid volume V.sub.w and a pore volume V.sub.p in the tight core at the time t, and then calculating a water saturation S.sub.w of the core; Step S8: calculating a flow rate Q.sub.s of a single phase flow; Step S9: simulating the water-oil displacement in the low-permeability tight core, and calculating the oil phase flow rate Q.sub.o and water phase flow rate Q.sub.w at the outflow end at the time t; Step S10: calculating the relative permeability k.sub.rw of water phase and the relative permeability k.sub.ro of oil phase at the displacement time t; Step S11: changing the time t and judging whether the water saturation S.sub.w remains unchanged; if so, go to Step S12; if not, return to Step S6; and Step S12: plotting a relative permeability curve.

2. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the tight core in Step S1 is 5 to 10 mm in diameter, and greater than 10 mm in length.

3. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein Step S2 comprises the following sub-steps: Step S21: performing CT scanning with appropriate lens and reconstruct 3D image data according to a size of the core; Step S22: defining and selecting Region of Interest (ROI) in 3D image data; and Step S23: performing filtering and threshold segmentation on ROI to obtain 3D digital core of pore structure distribution.

4. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the 3D image fractal box dimension algorithm in Step S4 comprises the following sub-steps: Step S41: based on the graph statistics parameters obtained in Step S3, drawing N(r)˜r diagram in log-log coordinates and a negative slope of the line is the value of fractal dimension D.sub.f,
lgN(r)=lga−D.sub.flgr; where, D.sub.f is porosity fractal dimension, r is pore equivalent diameter, N(r) is the number of pores with radius greater than r, a is a constant coefficient; Step S42: the porosity p of the core is obtained by image statistics and the average tortuosity is calculated by the following formula: $\tau =\frac{1}{2}\left[1+\frac{1}{2}\sqrt{1-\phi }+\sqrt{1-\phi }\sqrt{{\left(\frac{1}{\sqrt{1-\phi }}-1\right)}^2+\frac{1}{4}}/\left(1-\sqrt{1-\phi }\right)\right];$ where, τ is tortuosity, φ is porosity; and Step S43: calculating the tortuosity fractal dimension D.sub.T by the following formula: $D_T=1+\frac{\ln \tau }{\ln \left(\frac{L_m}{2r_{\mathrm{av}}}\right)};$ where, D.sub.T is the tortuosity fractal dimension, r.sub.av is a mean pore radius, L.sub.m is a characteristic length obtained by: $L_m=\sqrt{\frac{1-\phi }{\phi }\frac{\pi D_f{r}_{\max }^2}{2-D_f}};$ where, r.sub.max is a maximum pore radius.

5. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein Step S6 comprises the following sub-steps: Step S61: at a given time t, for a single capillary with the capillary equivalent diameter λ≥λ.sub.cr, determining that there is only single-phase water flow, and the fluid at the outflow end is water; Step S62: for a single equivalent capillary with the capillary equivalent diameter λ<λ.sub.cr, determining that there is oil and water flow, and the fluid at the outflow end is oil; and Step S63: dividing the capillary in the porous medium into two parts for analysis: the single capillary with λ≥λ.sub.cr and the single capillary with λ<λ.sub.cr.

6. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 4, wherein the calculation formula of the critical capillary diameter in Step S6 is: ${\lambda }_{\mathrm{cr}}^{2D_T}+4{\lambda }_{\mathrm{cr}}^{2D_T-1}\frac{\delta \cos \theta }{\Delta p}-\frac{{\lambda }_{\mathrm{cr}}^{D_T+1}{J}_o{L}^{D_T}}{\Delta p}-\frac{16\left({\mu }_w+{\mu }_o\right)L^{2D_T}}{\Delta \mathrm{pt}}=0;$ where, J.sub.o is a threshold pressure gradient of oil phase, δ is a surface tension; θ is a contact angle, μ.sub.w is a water phase viscosity, μ.sub.o is an oil phase viscosity, Δ.sub.cr is the critical capillary diameter, Δp is a pressure difference between the two ends of the core, t is the time, in s, L is a core length, and D.sub.T is the tortuosity fractal dimension.

7. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the calculation formula of the water phase volume V.sub.w in Step S7 is: $V_w=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{\pi {\lambda }^2}{4}{X}_T\mathrm{dN}-{\int }_{{\lambda }_{\mathrm{cr}}}^{{\lambda }_{\max }}\frac{\pi {\lambda }^2}{4}{L}_T\mathrm{dN};$ the calculation formula of the pore volume V.sub.p is: $V_P=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\max }}\frac{\pi {\lambda }^2}{4}{L}_T\mathrm{dN}=\frac{\pi D_f{\lambda }_{\max }^{3-D_r}{L}^{D_f}}{4\left(3-D_T-D_f\right)}\left[1-{\left(\frac{{\lambda }_{\min }}{{\lambda }_{\max }}\right)}^{3-D_T-D_f}\right];$ the calculation formula of the water saturation S.sub.w of the core is: $S_w=\frac{V_w}{V_p}=\frac{\frac{\left(3-D_T-D_f\right)}{L^{D_f}{\lambda }_{\max }^{3-D_T-D_f}}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}{X}^{D_T}{\lambda }^{3-D_T-D_f}d\lambda +\left[1-{\left(\frac{{\lambda }_{\mathrm{cr}}}{{\lambda }_{\max }}\right)}^{\left(3-D_T-D_f\right)}\right]}{\left[1-{\left(\frac{{\lambda }_{\min }}{{\lambda }_{\max }}\right)}^{3-D_T-D_f}\right]};$ where, D.sub.T is the tortuosity fractal dimension, D.sub.f is the porosity fractal dimension, λ.sub.max is the maximum pore equivalent diameter, λ.sub.min is the minimum pore equivalent diameter, λ.sub.cr is the critical capillary diameter, L.sub.T is actual length of the fractal capillary bundle, X.sub.T is a linear length of a fractal capillary tube bundle, and N is a number of capillary bundles.

8. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the calculation formula of single-phase fluid flow rate Q.sub.s in Step S8 is: $Q_s=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\max }}\mathrm{qdN}={\int }_{{\lambda }_{\max }}^{{\lambda }_{\min }}\frac{\pi {\lambda }^4}{128}.Math.\frac{{\lambda }^{D_T-1}\Delta p-J_w{L}^{D_T}}{{\mu }_w{L}^{D_f}}{D}_f{\lambda }_{\max }^{D_f}{\lambda }^{-\left(D_f+1\right)}d\lambda ;$ where, D.sub.T is the tortuosity fractal dimension, D.sub.f is the porosity fractal dimension, λ.sub.max is the maximum pore equivalent diameter, λ.sub.min is the minimum pore equivalent diameter, μ.sub.w is the water phase viscosity, and Δp is the pressure difference between the two ends of the core.

9. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the calculation formula of oil phase flow rate Q.sub.o at the outflow end mentioned in Step S9 is: $Q_o=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\mathrm{qdN}=\frac{\pi D_f{\lambda }_{\max }^{D_f}\Delta p}{128}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{{\lambda }^{2+D_T-D_f}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda +\frac{\pi D_f{\lambda }_{\max }^{D_f}\delta \cos \theta }{32}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{{\lambda }^{1+D_T-D_f}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda -\frac{\pi D_f{\lambda }_{\max }^{D_f}}{128}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{\left(X^{D_T}\left(J_w-J_o\right)+J_o{L}^{D_T}\right){\lambda }^{3-D_f}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda ;$ the calculation formula of water phase flow rate Qw is: $Q_w=-{\int }_{{\lambda }_{\mathrm{cr}}}^{{\lambda }_{\max }}\mathrm{qdN}=\frac{\pi D_f{\lambda }_{\max }^{D_f}\Delta p}{128{\mu }_w{L}^{D_T}\left(D_T+3-D_f\right)}\left({\lambda }_{\max }^{D_T+3-D_j}-{\lambda }_{\mathrm{cr}}^{D_T+3-D_f}\right)-\frac{\pi D_f{\lambda }_{\max }^{D_f}{J}_w}{128{\mu }_w\left(4-D_f\right)}\left({\lambda }_{\max }^{4-D_f}-{\lambda }_{\mathrm{cr}}^{4-D_f}\right);$ where, λ.sub.cr is the critical capillary diameter, D.sub.f is the porosity fractal dimension, λ.sub.cr is the critical capillary diameter, μ.sub.w is the water phase viscosity, and J.sub.w is the threshold pressure gradient of water phase.

10. The digital imaging technology-based method for calculating relative permeability of tight core according to claim 1, wherein the relative permeability k.sub.rw of water phase and the relative permeability k.sub.ro of oil phase at the displacement time t in Step S10 is obtained according to Darcy's law of single-phase flow $k=\frac{Q_s\mu L}{A\Delta p}$ and Darcy's law of two-phase flow $k_i=\frac{Q_i{\mu }_{i}L}{A\Delta p}:$ $k_{\mathrm{rw}}=\frac{k_w}{k}=\frac{Q_w}{Q_s}{k}_{\mathrm{ro}}=\frac{k_o}{k}=\frac{{\mu }_o}{{\mu }_w}\frac{Q_o}{Q_s};$ where, Q.sub.w is water phase flow rate, Q.sub.o is oil phase flow rate at outflow end, Q.sub.s is single-phase fluid flow rate, μ.sub.w is water phase viscosity, and μ.sub.o is oil phase viscosity.

Description

BRIEF DESCRIPTION OF DRAWINGS

(1) FIG. 1 is a flow chart for calculating relative permeability of tight core provided for the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

(2) FIG. 2 is a digital core diagram obtained by an embodiment of the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

(3) FIG. 3 is a schematic diagram of single fractal capillary flow involved in the calculation with the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

(4) FIG. 4 is a schematic diagram of core water-oil displacement fractal capillary flow involved in the calculation with the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

(5) FIG. 5 is a comparison diagram of the measured data and the relative permeability curve obtained in Embodiment 1 of the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

(6) FIG. 6 is a comparison diagram of relative permeability curve corresponding to different fractal dimensions obtained in Embodiment 2 of the digital imaging technology-based method for calculating relative permeability of tight core in the present invention.

DETAIL DESCRIPTION

(7) The following is a description of the preferred embodiments of the present invention to facilitate those skilled in the art to understand the present invention. However, it should be understood that the present invention is not limited to the scope of the preferred embodiments. For persons of ordinary skill in the art, these changes are obvious without departing from the spirit and scope of the present invention defined and determined by the appended claims, and all inventions and creations using the concept of the present invention are protected.

(8) A digital imaging technology-based method for calculating relative permeability of tight core, as shown in FIG. 1, comprising the following steps: Step S1: preparing a small column sample of tight core satisfying resolution requirements; Step S2: scanning the sample by MicroCT-400 and establishing a digital core; Step S3: performing statistical analysis on parameters reflecting rock pore structures and shape characteristics according to the digital core; Step S4: calculating a tortuosity fractal dimension D.sub.r and a porosity fractal dimension D.sub.f by a 3D image fractal box dimension algorithm; Step S5: performing statistical analysis on maximum pore equivalent diameter Amax and minimum pore equivalent diameter λ.sub.min by a label; Step S6: simulating a water-oil displacement in single fractal capillary, calculating a critical capillary diameter λ.sub.cr, and obtaining the critical capillary diameter at a displacement time t; Step S7: determining a fluid type at an outflow end with the critical capillary diameter, calculating a water-phase fluid volume V.sub.w and a pore volume V.sub.p in the tight core at the time t, and then calculating a water saturation S.sub.w of the core; Step S8: calculating a flow rate Q.sub.s of a single phase flow; Step S9: simulating the water-oil displacement in the low-permeability tight core, and calculating the oil phase flow rate Q.sub.o and water phase flow rate Q.sub.w at the outflow end at the time t; Step S10: calculating the relative permeability k.sub.rw of water phase and the relative permeability k.sub.ro of oil phase at the displacement time t; Step S11: changing the time t and judging whether the water saturation S.sub.w remains unchanged; if so, go to Step S12; if not, return to Step S6; and Step S12: plotting a relative permeability curve.

(9) In this embodiment, the tight core mentioned in Step S1 is 5 to 10 mm in diameter, and greater than 10 mm in length.

(10) In this embodiment, Step S2 including the following sub-steps: Step S21: performing CT scanning with appropriate lens and reconstruct 3D image data according to a size of the core; Step S22: defining and selecting Region of Interest (ROI) in 3D image data; and Step S23: performing filtering and threshold segmentation on ROI to obtain 3D digital core of pore structure distribution.

(11) In this embodiment, the 3D image fractal box dimension algorithm mentioned in Step S4 includes the following sub-steps: Step S41: based on the graph statistics parameters obtained in Step S3, drawing N(r)˜r diagram in log-log coordinates and a negative slope of the line is the value of fractal dimension D.sub.f,
lgN(r)=lga−D.sub.flgr;

(12) where, D.sub.f is porosity fractal dimension, r is pore equivalent diameter, N(r) is the number of pores with radius greater than r, a is a constant coefficient; Step S42: the porosity φ of the core is obtained by image statistics and the average tortuosity is calculated by the following formula:

(13) $\tau =\frac{1}{2}\left[1+\frac{1}{2}\sqrt{1-\phi }+\sqrt{1-\phi }\sqrt{{\left(\frac{1}{\sqrt{1-\phi }}-1\right)}^2+\frac{1}{4}}/\left(1-\sqrt{1-\phi }\right)\right];$

(14) where, τ is tortuosity, φ is porosity; and Step S43: calculating the tortuosity fractal dimension D.sub.T by the following formula:

(15) $D_T=1+\frac{\ln \tau }{\ln \left(\frac{L_m}{2r_{\mathrm{av}}}\right)};$

(16) where, D.sub.T is the tortuosity fractal dimension, r.sub.av is a mean pore radius, L.sub.m is a characteristic length obtained by:

(17) $L_m=\sqrt{\frac{1\phi }{\phi }\frac{\pi D_f{r}_{\max }^2}{2-D_f}};$

(18) where, r.sub.max is a maximum pore radius.

(19) As shown in FIG. 3, in this embodiment, Step S6 includes the following sub-steps: Step S61: at a given time t, for a single capillary with the capillary equivalent diameter λ≥λ.sub.cr, determining that there is only single-phase water flow, and the fluid at the outflow end is water; Step S62: for a single equivalent capillary with the capillary equivalent diameter λ <λcr, determining that there is oil and water flow, and the fluid at the outflow end is oil; and Step S63: dividing the capillary in the porous medium into two parts for analysis: the single capillary with λ≥λ.sub.cr and the single capillary with λ<λ.sub.cr.

(20) In this embodiment, the calculation formula of the critical capillary diameter mentioned in Step S6 is:

(21) ${\lambda }_{\mathrm{cr}}^{2D_T}+4{\lambda }_{\mathrm{cr}}^{2D_T-1}\frac{\delta \cos \theta }{\Delta p}-\frac{{\lambda }_{\mathrm{cr}}^{D_T+1}{J}_o{L}^{D_T}}{\Delta p}-\frac{16\left({\mu }_w+{\mu }_o\right)L^{2D_T}}{\Delta \mathrm{pt}}=0;$

(22) where, Jo is threshold pressure gradient of oil phase, δ is surface tension; θ is contact angle, w is water phase viscosity, μo is oil phase viscosity, λcr is critical capillary diameter, Δp is pressure difference between the two ends of the core, t is time, in s, L is core length, and DT is tortuosity fractal dimension.

(23) In this embodiment, the calculation formula of water phase volume Vw mentioned in Step S7 is:

(24) $V_w=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{\pi {\lambda }^2}{4}{X}_T\mathrm{dN}-{\int }_{{\lambda }_{\mathrm{cr}}}^{{\lambda }_{\max }}\frac{\pi {\lambda }^2}{4}{L}_T\mathrm{dN}.$

(25) The calculation formula of pore volume Vp is:

(26) $V_P=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\max }}\frac{\pi {\lambda }^2}{4}{L}_T\mathrm{dN}=\frac{\pi D_f{\lambda }_{\max }^{3-D_T}{L}^{D_f}}{4\left(3-D_T-D_f\right)}\left[1-{\left(\frac{{\lambda }_{\min }}{{\lambda }_{\max }}\right)}^{3-D_T-D_f}\right]$

(27) The calculation formula of water saturation Sw of the core is:

(28) 0$S_w=\frac{V_w}{V_p}=\frac{\frac{\left(3-D_T-D_f\right)}{L^{D_f}{\lambda }_{\max }^{3-D_T-D_f}}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}{X}^{D_T}{\lambda }^{2-D_T-D_f}d\lambda +\left[1-{\left(\frac{{\lambda }_{\mathrm{cr}}}{{\lambda }_{\max }}\right)}^{\left(3-D_T-D_f\right)}\right]}{\left[1-{\left(\frac{{\lambda }_{\min }}{{\lambda }_{\max }}\right)}^{3-D_T-D_f}\right]};$

(29) where, DT is tortuosity fractal dimension, Df is porosity fractal dimension, λmax is maximum pore equivalent diameter, λmin is minimum pore equivalent diameter, λcr is critical capillary diameter, LT is actual length of the fractal capillary bundle, XT is linear length of a fractal capillary tube bundle, and N is the number of capillary bundles.

(30) In this embodiment, the calculation formula of single-phase fluid flow rate Qs mentioned in Step S8 is:

(31) $Q_s=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\max }}\mathrm{qdN}={\int }_{{\lambda }_{\min }}^{{\lambda }_{\max }}\frac{\pi {\lambda }^4}{128}.Math.\frac{{\lambda }^{D_T-1}\Delta p-J_w{L}^{D_T}}{{\mu }_w{L}^{D_T}}{D}_f{\lambda }_{\max }^{D_f}{\lambda }^{-\left(D_f+1\right)}d\lambda$

(32) where, DT is tortuosity fractal dimension, Df is porosity fractal dimension, λmax is maximum pore equivalent diameter, λmin is minimum pore equivalent diameter, pw is water phase viscosity, and Δp is pressure difference between the two ends of the core.

(33) In this embodiment, the calculation formula of oil phase flow rate Qo at the outflow end mentioned in Step S9 is:

(34) $Q_o=-{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\mathrm{qdN}=\frac{\pi D_f{\lambda }_{\max }^{D_f}\Delta p}{128}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{{\lambda }^{2+D_T-D_j}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda +\frac{\pi D_f{\lambda }_{\max }^{D_f}\delta \cos \theta }{32}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{{\lambda }^{1+D_T-D_j}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda -\frac{\pi D_f{\lambda }_{\max }^{D_f}}{128}{\int }_{{\lambda }_{\min }}^{{\lambda }_{\mathrm{cr}}}\frac{\left(X^{D_T}\left(J_w-J_o\right)+J_o{L}^{D_T}\right){\lambda }^{3-D_f}}{\left({\mu }_w-{\mu }_o\right)X^{D_T}+{\mu }_o{L}^{D_T}}d\lambda ;$

(35) The calculation formula of water phase flow rate Qw is:

(36) $Q_w=-{\int }_{{\lambda }_{\mathrm{cr}}}^{{\lambda }_{\max }}\mathrm{qdN}=\frac{\pi D_f{\lambda }_{\max }^{D_f}\Delta p}{128{\mu }_w{L}^{D_T}\left(D_T+3-D_f\right)}\left({\lambda }_{\max }^{D_T+3-D_f}-{\lambda }_{\mathrm{cr}}^{D_T+3-D_f}\right)-\frac{\pi D_f{\lambda }_{\max }^{D_f}{J}_w}{128{\mu }_w\left(4-D_f\right)}\left({\lambda }_{\max }^{4-D_f}-{\lambda }_{\mathrm{cr}}^{4-D_f}\right);$

(37) where, λcr is critical capillary diameter, Df is porosity fractal dimension, λcr is critical capillary diameter, μw is water phase viscosity, and Jw is threshold pressure gradient of water phase.

(38) In this embodiment, the relative permeability krw of water phase and the relative permeability kro of oil phase at displacement time t mentioned in Step S10 can be obtained according to Darcy's law of single-phase flow

(39) $k=\frac{Q_s\mu L}{A\Delta p}$
and Darcy's law of two-phase flow

(40) $k_i=\frac{Q_i{\mu }_{i}L}{A\Delta p}:$

(41) $k_{\mathrm{rw}}=\frac{k_w}{k}=\frac{Q_w}{Q_s};k_{\mathrm{ro}}=\frac{k_o}{k}=\frac{{\mu }_o}{{\mu }_w}\frac{Q_o}{Q_s};$

(42) where, Qw is water phase flow rate, Qo is oil phase flow rate at outflow end, Qs is single-phase fluid flow rate, μw is water phase viscosity, and μo is oil phase viscosity.

(43) When the embodiments are implemented, in Embodiment 1: (1) Select low-permeability tight sandstone sample, prepare a small column sample satisfying resolution requirements, with a size of 8 mm (diameter)×20 mm, and then scan the sample and establish a digital core by MicroCT-400, as shown in FIG. 2. (2) Calculate tortuosity fractal dimension DT=1.1 and porosity fractal dimension Df=1.3 by 3D image fractal box dimension algorithm, and perform statistical analysis on maximum pore equivalent diameter λmax=2.6×10−5 m and minimum pore equivalent diameter λmin=4.3×10−8 m by a label. (3) Taking t=0 as the starting time, calculate associated critical capillary diameter, and judge the distribution of all capillary fluids in the core at that time. (4) Simulate and calculate single-phase fluid flow rate Qs, then calculate water phase flow rate Qw and oil phase flow rate Qo at t=0. (5) Simulate and calculate water-phase fluid volume, pore volume and water saturation in the core at t=0. (6) Calculate relative permeability kro and krw corresponding to water saturation. (7) Repeat the steps (3) to (6) of Embodiment 1, calculate the parameters at the next time Step St=1, and then t+1, until the calculated core water saturation remains unchanged, and plot a relative permeability curve, as shown in FIG. 5.

(44) Comparing the relative permeability curve based on calculated values with the measured data, it can be seen that the calculation reliability is high. The embodiment provides a convincing evidence for the beneficial effects of the present invention.

(45) In Embodiment 2: (1) Select different porosity fractal dimensions Df=1.3, 1.4 and 1.5, the same tortuosity fractal dimension DT, maximum pore equivalent diameter λmax and minimum pore equivalent diameter λmin as the characteristic values of the core pore structure parameters, and use them to calculate the influence of difference porosity fractal dimensions on the relative permeability curve. (2) Taking t=0 as the starting time, calculate associated critical capillary diameter, and judge the distribution of all capillary fluids in the core at that time. (3) Simulate and calculate single-phase fluid flow rate Qs, then calculate water phase flow rate Qw and oil phase flow rate Qo at t=0. (4) Simulate and calculate water-phase fluid volume, pore volume and water saturation in the core at t=0. (5) Calculate relative permeability kro and krw corresponding to water saturation. (6) Repeat the steps (3) to (5) of Embodiment 2, calculate the parameters at the next time Step St=1, and then t+1, until the calculated core water saturation remains unchanged, and plot a relative permeability curve, as shown in FIG. 6.