Method for determining the relative permeability curves of oil and water in low-permeability cores under low-velocity flow conditions

Abstract

This invention discloses a method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions. The method includes: weighing the core and measuring its length and cross-sectional diameter; sequentially evacuating the core, saturating it with gas, then evacuating again, and pressurizing it with saturated water; continuing to saturate the core with water at a set temperature and calculating the absolute permeability; saturating the oil phase and displacing it until no more water is produced, calculating the bound water saturation and relative permeability of the oil phase; aging the core; performing low-velocity water displacement and calculating the relative permeability of the water phase at residual oil saturation; removing the core, cleaning and drying it, and measuring the capillary force of the core using mercury intrusion porosimetry; and plotting the relative permeability curve of the oil and water phases. In this invention, the residual gas in the fine pores is replaced by the water phase during the step of adding saturated CO2. After subsequent saturation with crude oil, only oil-water two-phase flow occurs in the core. During this two-phase flow, capillary force adsorption and oil displacement occur, which is consistent with actual conditions, and the results obtained are accurate and reliable.

Description

Technical Field

[0001] This invention relates to the field of seepage technology in oil and gas field development, and in particular to a method for determining the relative permeability curve of oil and water in low-permeability core samples under low-velocity flow conditions. Background Technology

[0002] Tight and shale reservoirs with low permeability have become the focus of oil and gas exploration and development. Due to their narrow rock pores and complex pore-throat structure, low-permeability reservoirs exhibit oil-water flow characteristics that differ from conventional medium- and high-permeability reservoirs. The relative permeability curve of oil and water reflects the interaction between oil and water during flow and is a crucial basic data required for dynamic analysis of oilfield development, evaluation of remaining oil, and numerical simulation of reservoirs.

[0003] The determination of relative permeability curves between oil and water in conventional medium-to-high permeability reservoirs currently primarily follows the industry standard SYT 5345-2007. However, for determining the relative permeability curves of low-permeability reservoirs, this method neglects the capillary action in low-permeability reservoirs and requires a relatively high displacement rate, which is significantly inconsistent with the actual low adsorption-displacement rates of low-permeability oil reservoirs. Therefore, to reflect the characteristics of low-permeability reservoirs, existing methods for determining relative permeability curves in core samples need to be improved. However, in the improved experimental methods, the existing technology still uses the conventional core saturation fluid method when saturating low-permeability cores. Due to limitations in vacuum experimental equipment, after saturating simulated formation water, gas remains in the small pores and throats within the core, resulting in insufficient saturation. The internal flow of the core changes from a single-phase liquid flow to a two-phase gas-liquid flow. After further saturation with crude oil, it transforms into a more complex three-phase flow of oil, water, and gas, altering the reservoir properties that were originally intended to simulate two-phase oil-water flow. Therefore, the experimental results obtained using this method also contain significant errors or even inaccuracies. Furthermore, the presence of residual gas in the saturated aqueous phase of low-permeability cores causes nonlinear flow and the initiation of pressure gradients at low flow rates, resulting in substantial errors in the existing formulas for calculating the relative oil-water permeability of low-permeability cores. Summary of the Invention

[0004] The purpose of this invention is to overcome the shortcomings of the prior art and provide a method for determining the relative permeability curve of oil and water in low-permeability cores under low-speed flow conditions. By improving the displacement experiment, more accurate basic parameters of relative permeability of oil and water are obtained, and capillary force physical quantities are added to obtain more accurate relative permeability curves of oil and water in low-permeability cores under low-speed flow conditions.

[0005] To achieve the above objectives, the present invention adopts the following technical solution:

[0006] A method for determining the relative permeability curve of oil and water in low-permeability cores under low-velocity flow conditions includes the following steps:

[0007] S1. Weigh the core sample to be tested and measure its length and cross-sectional diameter;

[0008] S2. The core sample to be tested is evacuated, saturated with gas, and then evacuated again in sequence;

[0009] S3. Pressurize the core sample to be tested with saturated water;

[0010] S4. At the set temperature, continue to saturate the core sample with water, and calculate the absolute permeability of the core sample based on the pressure values ​​at both ends of the core sample.

[0011] S5. At a set temperature, the saturated oil phase of the core to be tested is displaced until no water is discharged. Based on the volume of water discharged and the pressure values ​​at both ends of the core to be tested, the bound water saturation of the core to be tested and the relative permeability of the oil phase under the bound water saturation are calculated.

[0012] S6. At a set temperature, the core sample to be tested is aged;

[0013] S7. At a set temperature, perform water flooding at a low speed until no oil phase is produced. Calculate the relative permeability of the water phase at the residual oil saturation of the core sample at different times, based on the pressure at both ends of the core sample and the cumulative water and oil production.

[0014] S8. Take out the core sample to be tested, clean and dry it, and determine the capillary force of the core sample by mercury intrusion porosimetry.

[0015] S9. Plot the relative permeability curves of the oil and water phases.

[0016] In one possible design, the gas in S2 is a gas that is easily soluble in water.

[0017] In one possible design, the gas is CO2.

[0018] In one possible design, weighing and measuring the length and cross-sectional diameter of the core sample in step S1 includes cleaning, drying, and baking the core sample with an organic solvent before weighing and measuring its length and cross-sectional diameter.

[0019] In one possible design, step S2 involves sequentially evacuating the core sample to be tested, saturating it with gas, and then evacuating it again. This includes sequentially evacuating the core sample to be tested for 10 hours, saturating it with gas for 10 hours, and then evacuating it again for 10 hours.

[0020] In one possible design, the core sample to be tested is further saturated with water in S4, including the core sample to be saturated with water at a constant rate.

[0021] In one possible design, in step S5, the saturated oil phase in the core sample is displaced at a constant rate until no water is produced.

[0022] In one possible design, the core sample to be tested is aged in step S6, which includes aging the core sample to be tested for 5 days.

[0023] In one possible design, water-driven oil is performed at low speeds in S7, including water-driven oil at constant low speeds.

[0024] In one possible design, plotting the relative permeability curves of the oil and water phases includes establishing a formula for calculating the relative permeability of oil and water in low-permeability core samples under low-velocity flow conditions:

[0025] Assumptions: The core is a homogeneous porous medium; the driving force is constant and water-driven; the properties of oil and water remain unchanged; there is no reaction between oil and water and no interphase mass transfer; the compressibility of the core and fluid is ignored; the effect of capillary force is considered.

[0026] Under low-velocity flow conditions, the fluid seepage in low-permeability cores is linear, and the Darcy flow equations for oil-water two-phase flow are Equations (1) and (2), respectively:

[0027]

[0028]

[0029] Among them, v o and v w The seepage velocities for the oil and water phases are respectively, in cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro and K rw The relative permeability of the oil phase and the water phase, respectively; μ o and μ w The oil phase and water phase viscosities are respectively, in mPa·s; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa; x is the flow distance, cm;

[0030] The expression for capillary force is given by equation (3):

[0031] P c =P o -P w (3)

[0032] Among them, P c Capillary force is the water saturation S. w The function, 10 -1 MPa; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa;

[0033] Combining equation (3), equation (1) is transformed into equation (4):

[0034]

[0035] Among them, v o The oil phase flow velocity is represented by cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro The relative permeability of the oil phase; μ o P represents the oil phase viscosity, in mPa·s; w For water phase pressure, 10 -1 MPa; P c Capillary force is the water saturation S. w The function, 10 - 1 MPa; x is the flow distance, cm;

[0036] The total fluid seepage velocity in the rock core is:

[0037] v = v o +v w (5)

[0038] Where v is the total fluid seepage velocity in the core, cm / s; v o The oil phase flow velocity is expressed in cm / s; v w Aqueous phase seepage velocity, cm / s;

[0039] The flow rates of oil and water can be expressed as follows:

[0040]

[0041] Among them, f o and f w The flow rates of the oil phase and the water phase are respectively; v o The oil phase flow velocity is expressed in cm / s; v w Aqueous phase seepage velocity, cm / s; v is the total fluid seepage velocity in the core, cm / s;

[0042] Equations (1) and (2) are transformed to obtain equations (7) and (8):

[0043]

[0044]

[0045] Among them, v o and v w The seepage velocities for the oil and water phases are respectively, in cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro and K rwThe relative permeability of the oil phase and the water phase, respectively; μ o and μ w The oil phase and water phase viscosities are respectively, in mPa·s; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa; x is the flow distance, cm;

[0046] Combining formulas (3), (6), (7), and (8), we obtain formula (9):

[0047]

[0048] Where v is the total seepage velocity of the fluid in the rock core, cm / s; f o and f w The flow rates of the oil phase and water phase are respectively; μ o and μ w The viscosity of the oil phase and the water phase are respectively, in mPa·s; K. ro and K rw These are the relative permeabilities of the oil phase and the water phase, respectively; P c Capillary force is the water saturation S. w The function, 10 -1 MPa; k is the permeability of the porous medium, μm 2 x represents the flow distance, in cm;

[0049] The material balance relationship has f o =1-f w Then equation (9) transforms into equation (10):

[0050]

[0051] Among them, f w t is the flow rate of the aqueous phase; t is the flow time, in seconds; μ o and μ w The viscosity of the oil phase and the water phase are respectively, in mPa·s; K. ro and K rw These represent the relative permeabilities of the oil and water phases, respectively; k is the permeability of the porous medium, in μm. 2 v represents the total fluid seepage velocity in the rock core, in cm / s; P c Capillary force is the water saturation S. w The function, 10 -1 MPa; x is the flow distance, cm;

[0052] Ignoring the compressibility of oil and water, the continuity equations for the oil and water phases in a one-dimensional homogeneous formation waterflooding process are Equations (11) and (12), respectively:

[0053]

[0054]

[0055] Among them, v o and v w , respectively, represent the seepage velocities of the oil phase and the water phase, in cm / s; x represents the flow distance, in cm; S represents the core porosity. w Water saturation; S o t represents oil saturation; t represents flow time, in seconds.

[0056] Combining equation (6), equation (12) transforms into equation (13):

[0057]

[0058] Where v is the total seepage velocity of the fluid in the core, cm / s; t is the flow time, s; f w The flow rate is denoted by water phase; x represents the flow distance in cm; S represents the flow rate of the water phase. w Water saturation;

[0059] Equation (13) is transformed to obtain equation (14) for the movement velocity of the isohydrated surface in the core:

[0060]

[0061] Where x is the flow distance, cm; t is the flow time, s; S w ρ represents water saturation; v represents the total fluid seepage velocity in the core, in cm / s. Porosity of porous media; f w For the aqueous phase flow rate;

[0062] The relationship between the pressure difference Δp at both ends of the core and the relative permeability is derived from formula (2) to form formula (15):

[0063]

[0064] Among them, P w For water phase pressure, 10 -1 MPa; x is the flow distance in cm; v w The velocity of the aqueous phase is expressed in cm / s; μ w ρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw The relative permeability of the aqueous phase;

[0065] Substituting equation (6) into equation (15), we obtain equation (16):

[0066]

[0067] Among them, Pw For water phase pressure, 10 -1 MPa; x is the flow distance, cm; v is the total fluid seepage velocity in the core, cm / s; f w The aqueous phase flow rate; μ w ρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw The relative permeability of the aqueous phase;

[0068] Assuming the porous medium of the rock is water-wet, the pressure difference across the core is expressed by the parameters of the aqueous phase as equation (17):

[0069]

[0070] Where Δp is the pressure difference between the two ends of the core, 10 -1 MPa; L is the core length, cm; P w For water phase pressure, 10 -1 MPa; x is the flow distance, cm;

[0071] Based on the propulsion speed of the surface with equal water saturation, equation (18) can be derived from equation (15):

[0072]

[0073] Where x is the flow distance, in meters; L is the core length, in meters; f' w f is the derivative of the flow rate with respect to water saturation. w '2' represents the derivative of the flow fraction at the end of the core with respect to water saturation, which can be expressed as:

[0074]

[0075] Among them, f' w2 This is the derivative of the flow rate at the end of the core with respect to water saturation. The cumulative injected pore volume multiple; A is the core cross-sectional area, cm². 2 L represents the core length, in cm. Porosity of porous media; Q Iw (t) represents the cumulative injected water volume, in cm. 3 ;

[0076] Substituting equations (16) and (18) into (17) yields equation (20):

[0077]

[0078] Where Δp is the pressure difference between the two ends of the core, 10 -1 MPa; f' w2ρ is the derivative of the flow fraction at the end of the core with respect to water saturation; v is the total fluid velocity in the porous reservoir medium, cm / s; f w The aqueous phase flow rate; μ w ρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw f' represents the relative permeability of the aqueous phase; L represents the core length in cm; f' w This is the derivative of the flow rate with respect to water saturation.

[0079] Substituting equation (18) into equation (20) and differentiating both sides, we obtain the formula for the relative permeability of the water phase (21):

[0080]

[0081] Among them, K rw2 f is the relative permeability of the water phase at the end saturation of the core. w2 This represents the water phase fraction at the end of the core sample. The cumulative injected pore volume multiple; k is the absolute permeability of the core, in μm. 2 ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; v is the total seepage velocity, cm / s; μ w L is the viscosity of the aqueous phase, mPa·s; L is the core length, cm.

[0082] Combining equations (21) and (11), we obtain the expression for the relative permeability of the oil phase (22):

[0083]

[0084] Among them, K ro2 K represents the relative permeability of the oil phase at the end-saturation of the core sample. rw2 The relative permeability of the aqueous phase; μ o Oil phase viscosity, mPa·s; μ w f is the viscosity of the aqueous phase, in mPa·s; w2 The water phase fraction at the end of the core is given by ; k is the absolute permeability of the core, in μm. 2 v is the total seepage velocity, cm / s; P c For capillary force, 10 -1 MPa; S w is the water saturation of the core; x is the flow distance, in cm.

[0085] As can be seen from equations (21) and (22), the calculation of relative oil-water permeability must first determine the water saturation and its gradient at the end of the core.

[0086] The expression for the average water saturation of the core is derived from the principle of mass balance (23):

[0087]

[0088] Among them, S wa S represents the average water saturation level. wc ∑Q represents the bound water saturation. o To accumulate oil production, cm 3 A represents the cross-sectional area of ​​the core sample, in cm². 2 ; Porosity of the porous medium; L is the core length, in cm;

[0089] The water saturation at the end of the core can be expressed as equation (24):

[0090]

[0091] Among them, S w2 S represents the water saturation at the end of the core sample. wa Q represents the average water saturation level. Iw (t) represents the cumulative injected water volume, in cm. 3 t is the flow time, in seconds; f o2 A is the oil phase fraction at the end of the core; A is the cross-sectional area of ​​the core, cm². 2 ; Porosity of the porous medium; L is the core length, in cm;

[0092] Core capillary force expression (25):

[0093]

[0094] Among them, P c For capillary force, 10 -1 MPa; σ is the oil-water interfacial tension, mN·m -1 θ is the core wetting angle (°); r is the pore radius (cm).

[0095] For the capillary force curve of mercury injection, the capillary force expression for different water saturation levels during water-driven oil recovery can be obtained by converting the capillary force between mercury gas and oil-water: (26)

[0096]

[0097] Among them, P cwo For the capillary force during water-driven oil recovery, 10 -1 MPa; P cHg For the capillary force during mercury injection (mercury-driven gas), 10 - 1 MPa; σ wo The oil-water interfacial tension is expressed in mN·m. -1 ;σ Hg The interfacial tension of mercury in the gas-liquid interface is mN·m.-1 ;θ w Let θ be the wetting angle of water on the rock core (°); Hg Let be the wetting angle of mercury on the core, (°);

[0098] The relative permeability curves of oil and water considering the effect of capillary force during oil-water seepage in low-permeability cores were calculated by combining equations (21), (22), (24) and (26).

[0099] The beneficial effects of this invention are:

[0100] In actual formations, capillary action is significant in low-permeability cores, and it occurs in the fine pores of the core. However, under experimental conditions, due to limitations of the vacuum equipment, after vacuuming and direct saturation with water, some air remains in some fine pores. This air is residual gas that has not been replaced by the water phase. Because of the presence of residual gas, capillary action will not occur during the flow of oil and water phases, which is inconsistent with the actual conditions of the oilfield.

[0101] In the process of determining the basic parameters of oil-water relative permeability in this invention, the addition of a saturated gas, especially CO2 which is easily soluble in water, after the vacuuming step, can remove residual gas and facilitate capillary adsorption oil displacement. This is because CO2 is miscible with air; after continued vacuuming, residual air in the small pores and blind throats of the core is replaced by CO2. After pressurizing and saturating the simulated formation water, because CO2 has good solubility in water, the residual CO2 in the small pores and blind throats of the core will dissolve in the simulated formation water under high pressure. The simulated formation water containing dissolved CO2 is then displaced from the core by the subsequent displacement of the simulated formation water, ensuring that only simulated formation water exists in the core pores, i.e., a single-phase flow of simulated formation water, thus solving the problem of insufficient core saturation fluid in existing technologies.

[0102] The role of CO2 in this invention differs from that of supercritical CO2 commonly used in oil fields. In supercritical CO2, CO2 is used as an oil displacement agent, injected into the formation during the oil displacement process to displace the oil. In this invention, during the simulation of core saturation, to saturate the core with both water and oil phases and ensure the absence of air in the core pores, making the core after saturation more like the actual state of the formation, a step of adding saturated CO2 after vacuuming is performed. The high diffusion coefficient of gases allows CO2 to replace the air in the core. Furthermore, taking advantage of CO2's high solubility in water, CO2 dissolves in water when saturating the core with the water phase, and then displaces the CO2-dissolved water phase when saturating the core with the oil phase, ensuring that only the oil and water phases exist in the core pores, free of air.

[0103] After adding saturated CO2, the residual gas in the fine pores is replaced by the water phase. Following subsequent saturation with crude oil, only a two-phase flow of oil and water occurs in the core. During this two-phase flow, capillary action and oil displacement occur, consistent with actual conditions. Furthermore, by calculating and plotting the relative permeability curve of oil and water in low-permeability cores under low-velocity flow conditions considering capillary action, the characteristics of oil-water seepage under low-velocity flow conditions can be more accurately characterized, leading to accurate and reliable experimental results. Attached Figure Description

[0104] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0105] Figure 1 This is a schematic diagram of the physical simulation experimental device for water-driven oil recovery from low-permeability cores provided in an embodiment of the present invention;

[0106] Figure 2 This is a schematic diagram of the capillary force curve when the mercury injection method is measured and converted into water-driven oil in step S8 of the embodiments of this application;

[0107] Figure 3 This is a schematic diagram of the relative permeability curves of the oil and water phases calculated in step S9 when the displacement rate is 0.001 ml / min, based on core A provided in this application embodiment.

[0108] Figure 4 This is a schematic diagram of the relative permeability curves of the oil and water phases calculated in step S9 when the displacement rate is 0.004 ml / min, based on core A provided in this embodiment of the application.

[0109] Figure 5 This is a schematic diagram of the relative permeability curves of the oil and water phases calculated in step S9 when the displacement rate is 0.001 ml / min, based on core B provided in this embodiment of the application.

[0110] Figure 6 This is a schematic diagram of the relative permeability curves of the oil and water phases calculated in step S9 when there is no CO2 saturation step, based on core B provided in this application embodiment, at a displacement rate of 0.004 ml / min.

[0111] Among them, 1. Gas cylinder, 2. Injection pump, 3. Gas storage intermediate container, 4. Water storage intermediate container, 5. Oil storage intermediate container, 6. Displacement fluid storage intermediate container, 7. Capillary tube, 8. Core, 9. Core holder, 10. First hand-cranked pump, 11. Safety bottle, 12. Vacuum pump, 15. Transparent hose, 16. Scale plate, 17. Back pressure valve, 18. Second hand-cranked pump, 21. Thermostatic device, 101. First pressure gauge, 102. Second pressure gauge, 104. Fourth pressure gauge, 201. First valve, 202. Second valve, 203. Third valve, 204. Fourth valve, 205. Fifth valve, 206. Sixth valve, 207. Seventh valve, 208. Eighth valve, 209. Ninth valve, 211. Eleventh valve, 212. Twelfth valve, 213. Thirteenth valve, 216. Sixteenth valve.

[0112] The accompanying drawings illustrate specific embodiments of this application, which will be described in more detail below. These drawings and descriptions are not intended to limit the scope of the concept in any way, but rather to illustrate the concept of this application to those skilled in the art through reference to particular embodiments. Detailed Implementation

[0113] For testing the relative oil-water permeability of conventional medium-to-high permeability reservoirs, the most commonly used method is the unsteady-state method. However, this method does not consider the effect of capillary pressure. Compared with conventional reservoirs, the capillary force in low-permeability reservoirs is significant and cannot be ignored. To minimize the influence of capillary force, the displacement rate is generally increased, which is the method currently used in China according to the SYT 5345-2007 industry standard. However, this is seriously inconsistent with the actual low permeability displacement rate of low-permeability reservoirs. Therefore, to conform to the characteristics of low-permeability reservoirs, it is necessary to improve the existing methods for determining the relative oil-water permeability curves in core samples.

[0114] However, in the improved experimental methods, the existing technology still uses the conventional core saturation fluid method when saturating low-permeability cores with fluid. Because the pores of low-permeability cores are extremely small, the vacuuming process cannot completely remove the air from the core. This results in gas remaining in the tiny pores after saturating simulated formation water, causing the flow to change from a single-phase liquid to a two-phase gas-liquid flow. After further saturation with crude oil, it becomes an even more complex three-phase oil-water-gas flow, altering the reservoir properties that were originally intended to simulate two-phase oil-water flow. Therefore, the experimental results obtained using this method contain significant errors, even inaccuracies. Furthermore, the presence of residual gas in the low-permeability core during water saturation causes nonlinear flow and pressure gradient initiation at low flow rates, leading to significant errors in the existing formulas for calculating the relative permeability of low-permeability cores.

[0115] An embodiment of the present invention provides a method for determining the relative permeability curve of oil and water in low-permeability core samples under low-velocity flow conditions, comprising the following steps:

[0116] S1. Weigh the core sample to be tested and measure its length and cross-sectional diameter;

[0117] S2. Vacuum the core sample to be tested in sequence, saturate it with gas, and then vacuum it again.

[0118] S3. Pressurize the core sample to be tested with saturated water;

[0119] S4. At the set temperature, continue to saturate the core sample with water, and calculate the absolute permeability of the core sample based on the pressure values ​​at both ends of the core sample.

[0120] S5. At a set temperature, the saturated oil phase of the core to be tested is displaced until no water is produced. Based on the volume of water displaced and the pressure values ​​at both ends of the core to be tested, the bound water saturation of the core to be tested and the relative permeability of the oil phase under the bound water saturation are calculated.

[0121] S6. At the set temperature, the core sample to be tested is aged;

[0122] S7. At a set temperature, perform water flooding at low speed until no oil phase is produced. Calculate the relative permeability of the water phase at the residual oil saturation of the core sample at different times, based on the pressure at both ends of the core sample and the cumulative water and oil production.

[0123] S8. Take out the core sample to be tested, clean and dry it, and determine the capillary force of the core sample by mercury porosimetry.

[0124] S9. Plot the relative permeability curves of the oil and water phases.

[0125] In one possible design, the gas in S2 is a gas that is easily soluble in water.

[0126] It is understandable that gas molecules can more easily enter the core pores through diffusion than liquid molecules. After saturating the core with water-soluble gas and then evacuating, the remaining air in the core pores is replaced by water-soluble gas. After saturating the core with simulated formation water, the remaining water-soluble gas dissolves in the simulated formation water more easily than air. The simulated formation water containing water-soluble gas is then displaced from the core by the subsequent simulated formation water, ensuring that only simulated formation water exists in the core pores.

[0127] In one possible design, the gas is CO2.

[0128] Understandably, CO2 is a common gas that is easily soluble in water, inexpensive, and readily available.

[0129] For indoor simulation of saturated fluids in low-permeability cores, conventional methods for core saturation in oil recovery involve immediately saturating the core with simulated formation water or crude oil after vacuuming, without an intermediate CO2 saturation process. Because the pores in low-permeability cores are extremely small, the vacuuming process cannot completely remove air due to limitations of the vacuum equipment. Furthermore, because air has limited solubility in water, saturated simulated formation water cannot enter the blind end pore throats to replace the gas. Therefore, after saturating simulated formation water, gas remains in the tiny pore throats within the core, causing the flow to change from a single-phase liquid to a two-phase gas-liquid flow. Subsequent saturation with crude oil further transforms the flow into a more complex three-phase oil-water-gas flow. During oil-water flow, the presence of bubbles generates the Jamin effect, altering the reservoir properties that were originally intended to simulate two-phase oil-water flow. Therefore, experimental results obtained based on this method contain significant errors and may even be erroneous.

[0130] In the method provided in this embodiment, saturated CO2 is added after vacuuming. Because CO2 is miscible with air, after continued vacuuming, the residual air in the small pores and blind throats of the core is replaced by CO2. After pressurizing and saturating the simulated formation water, because CO2 has good solubility in water, the residual CO2 in the small pores and blind throats of the core will dissolve in the simulated formation water under high pressure. The simulated formation water containing dissolved CO2 is then displaced from the core by the subsequent simulated formation water, ensuring that only simulated formation water exists in the core pores, i.e., a single-phase flow of simulated formation water. After subsequent saturation with crude oil, the core exhibits a two-phase flow of oil and water, and the oil-water distribution inside the core more closely resembles the actual state.

[0131] In one possible design, S1 involves weighing the core sample and measuring its length and cross-sectional diameter, including cleaning the core sample with an organic solvent, drying it, and then weighing and measuring its length and cross-sectional diameter.

[0132] In one possible design, in S2, the core sample to be tested is sequentially evacuated, saturated with gas, and then evacuated again, including evacuating the core sample to be tested for 10 hours, saturating with gas for 10 hours, and then evacuating again for 10 hours.

[0133] Optionally, S3 includes pressurizing and saturating the core sample with water for 24 hours.

[0134] In one possible design, the core sample to be tested is saturated with water in S4, including continuing to saturate the core sample with water at a constant rate.

[0135] It is understandable that the saturated water velocity should be consistent with the subsequent waterflooding rate. At a constant velocity, the aqueous phase containing a small amount of CO2 dissolved in the core can be slowly displaced by the pure aqueous phase, and the determination of the absolute permeability of the core must also be carried out under constant-rate pressurization and saturation conditions.

[0136] In one possible design, the oil phase in the core to be tested is kept at a constant rate and saturated until no water is produced.

[0137] It is understandable that the saturated oil rate is kept consistent with the subsequent water-drive oil rate, and the oil phase permeability under the core bound water saturation is measured under constant rate conditions.

[0138] In one possible design, the core sample to be tested is aged in S6, including aging the core sample for 5 days.

[0139] In one possible design, water-driven oil is performed at low speeds in the S7, including water-driven oil at constant low speeds.

[0140] It is understandable that the water-driven oil flow rate is the same as the saturated fluid rate mentioned earlier, thus obtaining permeability data under the same velocity conditions.

[0141] In one possible design, plotting the relative permeability curves of the oil and water phases involves establishing a formula for calculating the relative permeability of oil and water in low-permeability cores under low-velocity flow conditions.

[0142] Assumptions: The core is a homogeneous porous medium; the driving force is constant and water-driven; the properties of oil and water remain unchanged; there is no reaction between oil and water and no interphase mass transfer; the compressibility of the core and fluid is ignored; the effect of capillary force is considered.

[0143] Under low-velocity flow conditions, the fluid seepage in low-permeability cores is linear, and the Darcy flow equations for oil-water two-phase flow are Equations (1) and (2), respectively:

[0144]

[0145]

[0146] Among them, v o and v w The seepage velocities for the oil and water phases are respectively, in cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro and K rw The relative permeability of the oil phase and the water phase, respectively; μ o and μ w The oil phase and water phase viscosities are respectively, in mPa·s; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa; x is the flow distance, cm;

[0147] The expression for capillary force is given by equation (3):

[0148] P c =P o -P w (3)

[0149] Among them, P c Capillary force is the water saturation S. w The function, 10 -1 MPa; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa;

[0150] Combining equation (3), equation (1) is transformed into equation (4):

[0151]

[0152] Among them, v o The oil phase flow velocity is represented by cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro The relative permeability of the oil phase; μ o P represents the oil phase viscosity, in mPa·s; w For water phase pressure, 10 -1 MPa; P c Capillary force is the water saturation S. w The function, 10 - 1 MPa; x is the flow distance, cm;

[0153] The total fluid seepage velocity in the rock core is:

[0154] v = v o +v w (5)

[0155] Where v is the total fluid seepage velocity in the core, cm / s; v o The oil phase flow velocity is expressed in cm / s; v w Aqueous phase seepage velocity, cm / s;

[0156] The flow rates of oil and water can be expressed as follows:

[0157]

[0158] Among them, f o and f w The flow rates of the oil phase and the water phase are respectively; v o The oil phase flow velocity is expressed in cm / s; v w Aqueous phase seepage velocity, cm / s; v is the total fluid seepage velocity in the core, cm / s;

[0159] Equations (1) and (2) are transformed to obtain equations (7) and (8):

[0160]

[0161]

[0162] Among them, v o and v w The seepage velocities for the oil and water phases are respectively, in cm / s; k is the permeability of the porous medium, in μm. 2 ;K ro and K rw The relative permeability of the oil phase and the water phase, respectively; μ o and μ w The oil phase and water phase viscosities are respectively, in mPa·s; P o and P w The pressures of the oil phase and water phase are 10, respectively. -1 MPa; x is the flow distance, cm;

[0163] Combining formulas (3), (6), (7), and (8), we obtain formula (9):

[0164]

[0165] Where v is the total seepage velocity of the fluid in the rock core, cm / s; f o and f w The flow rates of the oil phase and water phase are respectively; μ o and μ w The viscosity of the oil phase and the water phase are respectively, in mPa·s; K. ro and K rw These are the relative permeabilities of the oil phase and the water phase, respectively; P c Capillary force is the water saturation S. w The function, 10 -1 MPa; k is the permeability of the porous medium, μm 2 x represents the flow distance, in cm;

[0166] The material balance relationship has f o =1-f w Then equation (9) transforms into equation (10):

[0167]

[0168] Among them, f w t is the flow rate of the aqueous phase; t is the flow time, in seconds; μ o and μ w The viscosity of the oil phase and the water phase are respectively, in mPa·s; K. ro and K rw These represent the relative permeabilities of the oil and water phases, respectively; k is the permeability of the porous medium, in μm. 2 v represents the total fluid seepage velocity in the rock core, in cm / s; P c Capillary force is the water saturation S.w The function, 10 -1 MPa; x is the flow distance, cm;

[0169] Ignoring the compressibility of oil and water, the continuity equations for the oil and water phases in a one-dimensional homogeneous formation waterflooding process are Equations (11) and (12), respectively:

[0170]

[0171]

[0172] Among them, v o and v w , respectively, represent the seepage velocities of the oil phase and the water phase, in cm / s; x represents the flow distance, in cm; S represents the core porosity. w Water saturation; S o t represents oil saturation; t represents flow time, in seconds.

[0173] Combining equation (6), equation (12) transforms into equation (13):

[0174]

[0175] Where v is the total seepage velocity of the fluid in the core, cm / s; t is the flow time, s; f w The flow rate is denoted by water phase; x represents the flow distance in cm; S represents the flow rate of the water phase. w Water saturation;

[0176] Equation (13) is transformed to obtain equation (14) for the movement velocity of the isohydrated surface in the core:

[0177]

[0178] Where x is the flow distance, cm; t is the flow time, s; S w ρ represents water saturation; v represents the total fluid seepage velocity in the core, in cm / s. Porosity of porous media; f w For the aqueous phase flow rate;

[0179] The relationship between the pressure difference Δp at both ends of the core and the relative permeability is derived from formula (2) to form formula (15):

[0180]

[0181] Among them, P w For water phase pressure, 10 -1 MPa; x is the flow distance in cm; v w The velocity of the aqueous phase is expressed in cm / s; μ wρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw The relative permeability of the aqueous phase;

[0182] Substituting equation (6) into equation (15), we obtain equation (16):

[0183]

[0184] Among them, P w For water phase pressure, 10 -1 MPa; x is the flow distance, cm; v is the total fluid seepage velocity in the core, cm / s; f w The aqueous phase flow rate; μ w ρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw The relative permeability of the aqueous phase;

[0185] Assuming the porous medium of the rock is water-wet, the pressure difference across the core is expressed by the parameters of the aqueous phase as equation (17):

[0186]

[0187] Where Δp is the pressure difference between the two ends of the core, 10 -1 MPa; L is the core length, cm; P w For water phase pressure, 10 -1 MPa; x is the flow distance, cm;

[0188] Based on the propulsion speed of the surface with equal water saturation, equation (18) can be derived from equation (15):

[0189]

[0190] Where x is the flow distance, in meters; L is the core length, in meters; f' w f' is the derivative of the flow rate with respect to water saturation. w2 The derivative of the flow fraction at the end of the core with respect to water saturation can be expressed as:

[0191]

[0192] Among them, f' w2 This is the derivative of the flow rate at the end of the core with respect to water saturation. The cumulative injected pore volume multiple; A is the core cross-sectional area, cm². 2 L represents the core length, in cm. Porosity of porous media; Q Iw (t) represents the cumulative injected water volume, in cm. 3 ;

[0193] Substituting equations (16) and (18) into (17) yields equation (20):

[0194]

[0195] Where Δp is the pressure difference between the two ends of the core, 10 -1 MPa; f' w2 ρ is the derivative of the flow fraction at the end of the core with respect to water saturation; v is the total fluid velocity in the porous reservoir medium, cm / s; f w The aqueous phase flow rate; μ w ρ is the viscosity of the aqueous phase, mPa·s; k is the permeability of the porous medium, μm. 2 ;K rw f' represents the relative permeability of the aqueous phase; L represents the core length in cm; f' w This is the derivative of the flow rate with respect to water saturation.

[0196] Substituting equation (18) into equation (20) and differentiating both sides, we obtain the formula for the relative permeability of the water phase (21):

[0197]

[0198] Among them, K rw2 f is the relative permeability of the water phase at the end saturation of the core. w2 This represents the water phase fraction at the end of the core sample. The cumulative injected pore volume multiple; k is the absolute permeability of the core, in μm. 2 ΔP is the pressure difference between the two ends of the core, 10 -1 MPa; v is the total seepage velocity, cm / s; μ w L is the viscosity of the aqueous phase, mPa·s; L is the core length, cm.

[0199] Combining equations (21) and (11), we obtain the expression for the relative permeability of the oil phase (22):

[0200]

[0201] Among them, K ro2 K represents the relative permeability of the oil phase at the end-saturation of the core sample. rw2 The relative permeability of the aqueous phase; μ o Oil phase viscosity, mPa·s; μ w f is the viscosity of the aqueous phase, in mPa·s; w2 The water phase fraction at the end of the core is given by ; k is the absolute permeability of the core, in μm. 2 v is the total seepage velocity, cm / s; P c For capillary force, 10 -1 MPa; S wis the water saturation of the core; x is the flow distance, in cm.

[0202] As can be seen from equations (21) and (22), the calculation of relative oil-water permeability must first determine the water saturation and its gradient at the end of the core.

[0203] The expression for the average water saturation of the core is derived from the principle of mass balance (23):

[0204]

[0205] Among them, S wa S represents the average water saturation level. wc ∑Q represents the bound water saturation. o To accumulate oil production, cm 3 A represents the cross-sectional area of ​​the core sample, in cm². 2 ; Porosity of the porous medium; L is the core length, in cm;

[0206] The water saturation at the end of the core can be expressed as equation (24):

[0207]

[0208] Among them, S w2 S represents the water saturation at the end of the core sample. wa Q represents the average water saturation level. Iw (t) represents the cumulative injected water volume, in cm. 3 t is the flow time, in seconds; f o2 A is the oil phase fraction at the end of the core; A is the cross-sectional area of ​​the core, cm². 2 ; Porosity of the porous medium; L is the core length, in cm;

[0209] Core capillary force expression (25):

[0210]

[0211] Among them, P c For capillary force, 10 -1 MPa; σ is the oil-water interfacial tension, mN·m -1 θ is the core wetting angle (°); r is the pore radius (cm).

[0212] For the capillary force curve of mercury injection, the capillary force expression for different water saturation levels during water-driven oil recovery can be obtained by converting the capillary force between mercury gas and oil-water: (26)

[0213]

[0214] Among them, P cwoFor the capillary force during water-driven oil recovery, 10 -1 MPa; P cHg For the capillary force during mercury injection (mercury-driven gas), 10 - 1 MPa; σ wo The oil-water interfacial tension is expressed in mN·m. -1 ;σ Hg The interfacial tension of mercury in the gas-liquid interface is mN·m. -1 ;θ w Let θ be the wetting angle of water on the rock core (°); Hg Let be the wetting angle of mercury on the core, (°);

[0215] The relative permeability curves of oil and water considering the effect of capillary force during oil-water seepage in low-permeability cores were calculated by combining equations (21), (22), (24) and (26).

[0216] It is understandable that capillary action is significant in low-permeability core samples, occurring within the fine pores. Without the addition of saturated CO2, some of the fine pores contain residual gas that has not been replaced by the aqueous phase, thus eliminating capillary adsorption for oil displacement during oil-water two-phase flow. After the addition of saturated CO2, the residual gas in the fine pores is replaced by the aqueous phase, resulting in capillary adsorption for oil displacement during oil-water two-phase flow. This aligns with actual conditions and allows for a more accurate characterization of oil-water seepage under low-velocity flow conditions, leading to accurate and reliable experimental results.

[0217] The present invention will be further described below through specific embodiments.

[0218] Unless otherwise specified, the experimental methods used in the following specific embodiments are conventional methods.

[0219] Unless otherwise specified, all operations described in the following specific embodiments are performed under standard conditions or conditions recommended by the manufacturer. Raw materials whose manufacturers and specifications are not specified are all commercially available products.

[0220] In the following specific embodiments: the gas phase was CO2, from Qingdao Tianyuan Gas Co., Ltd.; the oil phase was simulated oil (hexadecane), analytical grade, from Sinopharm Chemical Reagent Co., Ltd.; and the aqueous phase was simulated formation water with a salinity of 10561 mg·L⁻¹. -1 The solution was prepared from NaCl, KCl, CaCl2, MgCl2 and NaHCO3, all of which were of analytical grade and manufactured by Sinopharm Chemical Reagent Co., Ltd.; the displacement fluid was simulated formation water with the same composition as above; core A and core B were artificial low-permeability cores manufactured by Qingdao Yanke New Materials Co., Ltd., which were made of sandstone and dolomite cemented together with a cementing agent.

[0221] A method for determining the relative permeability curves of oil and water in low-permeability cores under low-velocity flow conditions, employing... Figure 1 The physical simulation experimental setup for water-driven oil recovery from low-permeability cores, as shown, is used to determine the basic parameters of relative oil-water permeability, including the following steps:

[0222] S1. The length of core A is 5.78 cm, the cross-sectional diameter is 2.5 cm, and the porosity is 10.7%.

[0223] S2. Load core A into core holder 9; load simulated formation water into intermediate water storage container 4 near the seventh valve 207; load simulated oil into intermediate oil storage container 5 near the eighth valve 208; load displacement fluid into intermediate fluid storage container 6 near the ninth valve 209; connect all pipelines and close all valves.

[0224] Open the twelfth valve 212, set the confining pressure for core A using the first hand-cranked pump 10, and close the twelfth valve 212; open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core 8 for 10 hours, and close the thirteenth valve 213.

[0225] Open the first valve 201, and CO2 from gas cylinder 1 enters the intermediate gas storage container 3, pushing the piston of the intermediate gas storage container 3 to the end near the third valve 203. Close the first valve 201. Open the second valve 202, the third valve 203, and the eleventh valve 211, start the injection pump 2, and push the piston of the intermediate gas storage container 3 away from the third valve 203. Pressurize core A with saturated gas at 6MPa for 10 hours. Close all valves.

[0226] Open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core A again for 10 hours, and then close the thirteenth valve 213.

[0227] S3. Pressurize and saturate core A with water;

[0228] Open the seventeenth valve 217, set the back pressure of the back pressure valve 17 to 10MPa through the second hand pump 18, and then close the seventeenth valve 217;

[0229] Open the fourth valve 204, the seventh valve 207, the eleventh valve 211 and the sixteenth valve 216, turn on the injection pump 2 and adjust it to constant speed mode, push the piston of the water storage intermediate container 4 towards the end closer to the seventh valve 207, and saturate the core A with water phase for 24 hours.

[0230] S4. Adjust the constant temperature device to 25℃, continue to saturate core A with water at a rate of 0.001 ml / min, and calculate the absolute permeability of the core to be tested based on the pressure values ​​at both ends of core A.

[0231] S5. At the set temperature, saturate the oil phase in core A at a saturation rate of 0.001 ml / min until no water is discharged. Calculate the bound water saturation of core A and the relative permeability of the oil phase at the bound water saturation based on the volume of water discharged and the pressure values ​​at both ends of core A.

[0232] Open the fifth valve 205, the eighth valve 208, the eleventh valve 211 and the sixteenth valve 216, turn on the injection pump 2 and adjust it to constant speed mode, push the piston of the oil storage intermediate container 5 towards the end near the eighth valve 208, saturate the core A with oil phase until no water comes out of the transparent hose 15.

[0233] The output of aqueous and oil phases is calculated using the produced fluid collection system, and the core bound water saturation is calculated.

[0234] The calculation process is as follows:

[0235] Core pore volume:

[0236] Core water output: V w = 2.13 ml, meaning the volume of saturated oil in the core is 2.13 ml;

[0237] Core bound water volume: V iw =PV-V w =3.03-2.13=0.90ml;

[0238] Core bound water saturation: S iw =V iw / PV×100%=0.90 / 3.03×100%=29.8%.

[0239] Where V is the core volume, ml; PV is the core pore volume, ml; V represents core porosity (%); r represents core cross-sectional radius (cm); L represents core length (cm); V represents core porosity (%). iw The volume of bound water in the core is expressed in ml; S iw The core bound water saturation is expressed as %.

[0240] S6. Close all valves and let the core A stand for 3 days at the set temperature to age it.

[0241] S7. Open valves 206, 209, 211, and 216. Turn on the injection pump 2 and set it to constant speed mode. Push the piston of the intermediate container 6 of the displacing fluid towards the end near valve 209 to inject the displacing fluid into core A at a displacement rate of 0.001 ml / min until no more oil flows out of the transparent tubing 15. Stop the injection. Read the flow distances of the oil and water phases in the transparent tubing 15 at different times and calculate the oil and water output at different times.

[0242] S8, Capillary Force Measurement

[0243] Core A was cleaned and dried. The core was then placed in a high-pressure mercury intrusion porosimeter, and mercury was injected into the core under a series of pressures. The volume of mercury entering the core at each pressure was recorded. The mercury saturation in the core was calculated using the mercury injection volume at different pressures, and the capillary force curve of the mercury intrusion porosimeter was plotted. The oil-water interfacial tension σ is known. wo = 33.9 mN·m -1 The surface tension of mercury is σ Hg = 480mN·m -1 The wetting angle θ of water on the rock core w =0°, the wetting angle θ of mercury on the core. Hg =140°. The capillary force is converted to capillary force at different water saturation levels during water-driven oil recovery using the capillary force conversion formula (26), such as... Figure 2 .

[0244] S9. Plot the relative permeability curves of the oil and water phases.

[0245] Substituting the amount of oil and water produced by water-driven oil recovery at different times and the capillary force parameters into the oil-water two-phase relative permeability calculation formulas (21), (22), (24) and (26), the oil-water two-phase relative permeability curves were plotted, as follows: Figure 3 As shown. Figure 3 The figure shows the relative permeability curves of the oil and water phases in core A, with a displacement rate of 0.001 ml / min. From the figure, we can obtain that the absolute permeability of core A is 0.04 × 10⁻⁶. -3 μm 2 The bound water saturation was 29.8%, and the isotonic point water saturation was 51.0%.

[0246] The displacement rate in S7 was changed to 0.004 ml / min, and steps S1-S9 were repeated to obtain the oil-water two-phase relative permeability curve of core A, as shown below. Figure 4 As shown. Figure 4 The figure shows the relative permeability curves of the oil and water phases in core A, with a displacement rate of 0.004 ml / min. From the figure, we can obtain that the absolute permeability of core A is 0.04 × 10⁻⁶. -3 μm 2 The bound water saturation is 27.7%, and the isotonic point water saturation is 52.5%.

[0247] Replace core A with core B, set the displacement rate in S7 to 0.001 ml / min, and repeat steps S1-S9 to obtain the oil-water two-phase relative permeability curve of core B, as shown below. Figure 5 As shown. Figure 5The figure shows the relative permeability curves of the oil-water two-phase system in core B, with a displacement rate of 0.001 ml / min. From the figure, we can obtain that the absolute permeability of core B is 0.02 × 10⁻⁶. -3 μm 2 The bound water saturation is 40.0%, and the isotonic point water saturation is 48.1%.

[0248] Change the displacement rate in S7 to 0.004 ml / min, and repeat steps S1-S9, except that step S2 is replaced with:

[0249] S2. Load core B into core holder 9; load simulated formation water into intermediate water storage container 4 near the seventh valve 207; load simulated oil into intermediate oil storage container 5 near the eighth valve 208; load displacement fluid into intermediate fluid storage container 6 near the ninth valve 209; connect all pipelines and close all valves.

[0250] Open the twelfth valve 212, set the confining pressure of core B using the first hand-cranked pump 10, and close the twelfth valve 212; open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core B for 20 hours, and close the thirteenth valve 213.

[0251] The relative permeability curves of the oil and water phases of core B were obtained, as follows: Figure 6 As shown. Figure 6 The figure shows the relative permeability curves of the oil-water two-phase system in core B, with a displacement rate of 0.004 ml / min. From the figure, we can obtain that the absolute permeability of core B is 0.02 × 10⁻⁶. -3 μm 2 The bound water saturation was 42.4%, and the isotonic point water saturation was 52.2%.

[0252] Rock property characterization results indicate that core A has weak hydrophilicity, while core B has weak oleophilicity. This method yielded similar results: the isopermeability point of the oil-water relative permeability curve for core A is between 50% and 60%, indicating weak hydrophilicity; the isopermeability point of the oil-water relative permeability curve for core B is between 40% and 50%, indicating weak oleophilicity. However, when there is no CO2 saturation process during fluid saturation, the isopermeability point of the oil-water relative permeability curve for core B shifts to the right, indicating weak hydrophilicity, which is inconsistent with actual conditions. Furthermore, this method also obtained the oil-water two-phase flow characteristics under different core wettability and displacement rate conditions, providing strong theoretical support for practical field applications.

[0253] The experimental method of this invention solves the problem of insufficient core saturation fluid in existing technologies. For indoor simulation of saturated fluid in low-permeability cores, conventional methods for core saturation fluid in oil production involve immediately saturating the core with simulated formation water or crude oil after vacuuming, without an intermediate CO2 saturation process. Because the pores of low-permeability cores are very small, the vacuuming process cannot completely remove the air from the core. Simultaneously, due to the limited solubility of air in water, saturated simulated formation water cannot enter the blind end pore throats to replace the gas. Therefore, after saturating the simulated formation water, gas remains in the small pore throats within the core, causing the flow to change from a single-phase liquid flow to a two-phase gas-liquid flow. Subsequent saturation with crude oil further transforms the flow into a more complex three-phase oil-water-gas flow, altering the reservoir properties that were originally intended to simulate two-phase oil-water flow. Therefore, the experimental results obtained based on this method contain significant errors or even inaccuracies. In this invention, after vacuuming, saturated CO2 is added. Because CO2 is miscible with air, continued vacuuming replaces residual air in the fine pores and blind pore throats of the core with CO2. After pressurizing and saturating with simulated formation water, the residual CO2 in the fine pores and blind pore throats of the core dissolves in the simulated formation water under high pressure due to the good solubility of CO2 in water. The CO2-dissolved simulated formation water is then displaced from the core by subsequent simulated formation water, ensuring that only simulated formation water exists in the core pores, i.e., a single-phase flow of simulated formation water. After subsequent saturation with crude oil, the core exhibits a two-phase flow of oil and water, more accurately simulating the physical properties of the oil reservoir and thus obtaining accurate and reliable experimental results.

[0254] The above embodiments are only used to illustrate the technical solutions of the present invention, and are not intended to limit it. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for determining the relative permeability curve of oil and water in low-permeability core samples under low-velocity flow conditions, characterized in that, Includes the following steps: S1. Weigh the core sample to be tested and measure its length and cross-sectional diameter; S2. The core sample to be tested is evacuated, saturated with gas, and then evacuated again. The gas is CO2, which is easily soluble in water. S3. Pressurize the core sample to be tested with saturated water; S4. At the set temperature, continue to saturate the core sample with water, and calculate the absolute permeability of the core sample based on the pressure values ​​at both ends of the core sample. S5. At a set temperature, the saturated oil phase of the core to be tested is displaced until no water is discharged. Based on the volume of water discharged and the pressure values ​​at both ends of the core to be tested, the bound water saturation of the core to be tested and the relative permeability of the oil phase under the bound water saturation are calculated. S6. At a set temperature, the core sample to be tested is aged; S7. At a set temperature, simulate formation water flooding is performed at a low speed until no oil phase is produced. Based on the pressure at both ends of the core sample and the cumulative water and oil production at different times, the relative permeability of the water phase under the residual oil saturation of the core sample is calculated. S8. Take out the core sample to be tested, clean and dry it, and determine the capillary force of the core sample by mercury intrusion porosimetry. S9. Calculate and plot the relative permeability curves of oil and water in low-permeability cores under low-velocity flow conditions considering capillary forces.

2. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, In step S1, the rock core to be tested is weighed and its length and cross-sectional diameter are measured, including cleaning the rock core to be tested with an organic solvent, drying it and then weighing it and measuring its length and cross-sectional diameter.

3. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, In step S2, the core sample to be tested is evacuated, saturated with gas, and then evacuated again, which includes evacuating the core sample to be tested for 10 hours, saturating with gas for 10 hours, and then evacuating again for 10 hours.

4. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, In step S4, the core sample to be tested is further saturated with water, including the core sample to be saturated with water at a constant rate.

5. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, In step S5, the saturated oil phase in the core sample is displaced at a constant rate until no water is produced.

6. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, In step S6, the core sample to be tested is aged, including aging the core sample for 5 days.

7. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, The S7 simulates formation water flooding at low speeds, including simulating formation water flooding at constant low speeds.

8. The method for determining the relative permeability curve of low-permeability core under low-velocity flow conditions as described in claim 1, characterized in that, The S9 section describes the plotting of the relative permeability curves of the oil and water phases, including establishing a formula for calculating the relative permeability of oil and water in low-permeability cores under low-velocity flow conditions. Assumptions: The core is a homogeneous porous medium; the driving force is constant and water-driven; the properties of oil and water remain unchanged; there is no reaction between oil and water and no interphase mass transfer; the compressibility of the core and fluid is ignored; the effect of capillary force is considered. Under low-velocity flow conditions, the fluid seepage in low-permeability cores is linear, and the Darcy flow equations for oil-water two-phase flow are Equations (1) and (2), respectively: （1） （2） in, and The seepage velocities for the oil phase and water phase are respectively, in cm / s; For porous media permeability, ; and These are the relative permeabilities of the oil phase and the water phase, respectively. and The viscosity of the oil phase and the viscosity of the water phase are respectively. ; and The pressures are for the oil phase and the water phase, respectively. ; The distance traveled is in centimeters. The expression for capillary force is given by equation (3): （3） in, Capillary force is the water saturation level. The function, ; and The pressures are for the oil phase and the water phase, respectively. ; Combining equation (3), equation (1) is transformed into equation (4): （4） in, The oil phase flow velocity is expressed in cm / s. For porous media permeability, ; This refers to the relative permeability of the oil phase. For oil phase viscosity, ; For water phase pressure, ; Capillary force is the water saturation level. The function, ; The distance traveled is in centimeters. The total fluid seepage velocity in the rock core is: （5） in, The total seepage velocity of the fluid in the rock core is given in cm / s. The oil phase flow velocity is expressed in cm / s. Aqueous phase seepage velocity, cm / s; The flow rates of oil and water can be expressed as follows: （6） in, and The flow rates of the oil phase and the aqueous phase are respectively; The oil phase flow velocity is expressed in cm / s. Aqueous phase seepage velocity, cm / s; The total seepage velocity of the fluid in the rock core is given in cm / s. Equations (1) and (2) are transformed to obtain equations (7) and (8): （7） （8） in, and The seepage velocities for the oil phase and water phase are respectively, in cm / s; For porous media permeability, ; and These are the relative permeabilities of the oil phase and the water phase, respectively. and The viscosity of the oil phase and the viscosity of the water phase are respectively. ; and The pressures are for the oil phase and the water phase, respectively. ; The distance traveled is in centimeters. Combining formulas (3), (6), (7), and (8), we obtain formula (9): （9） in, The total seepage velocity of the fluid in the rock core is given in cm / s. and The flow rates of the oil phase and the aqueous phase are respectively; and The viscosity of the oil phase and the viscosity of the water phase are respectively. ; and These are the relative permeabilities of the oil phase and the water phase, respectively. Capillary force is the water saturation level. The function, ; For porous media permeability, ; The distance traveled is in centimeters. Material balance relationship has Then equation (9) transforms into equation (10): （10） in, For the aqueous phase flow rate; Let the flow time be in seconds. and The viscosity of the oil phase and the viscosity of the water phase are respectively. ; and These are the relative permeabilities of the oil phase and the water phase, respectively. For porous media permeability, ; The total seepage velocity of the fluid in the rock core is given in cm / s. Capillary force is the water saturation level. The function, ; The distance traveled is in centimeters. Ignoring the compressibility of oil and water, the oil and water phase continuity equations in the one-dimensional homogeneous formation waterflooding process are Equations (11) and (12), respectively: （11） （12） in, and The seepage velocities for the oil phase and water phase are respectively, in cm / s; The distance traveled is in centimeters. Core porosity; Water saturation; Oil saturation; Let the flow time be in seconds. Combining equation (6), equation (12) transforms into (13): （13） in, The total seepage velocity of the fluid in the rock core is given in cm / s. Let the flow time be in seconds. For the aqueous phase flow rate; The distance traveled is in centimeters. Water saturation; Equation (13) is transformed to obtain equation (14) for the movement velocity of the isohydrate saturation surface in the core: （14） in, The distance traveled is in centimeters. Let the flow time be in seconds. Water saturation; The total seepage velocity of the fluid in the rock core is given in cm / s. Porosity of porous media; For the aqueous phase flow rate; Pressure difference at both ends of the core The relationship with relative permeability is transformed from formula (2) to obtain formula (15): （15） in, For water phase pressure, ; The distance traveled is in centimeters. The velocity of the aqueous phase is in cm / s; The viscosity of the aqueous phase is expressed in mPa × s. For porous media permeability, ; The relative permeability of the aqueous phase; Substituting equation (6) into equation (15), we obtain equation (16): （16） in, For water phase pressure, ; The distance traveled is in centimeters. The total seepage velocity of the fluid in the rock core is given in cm / s. For the aqueous phase flow rate; For the viscosity of the aqueous phase, ; For porous media permeability, ; The relative permeability of the aqueous phase; Assuming the porous medium of the rock is water-wet, the pressure difference across the core is expressed by the parameters of the aqueous phase as equation (17): （17） in, The pressure difference between the two ends of the core. ; The length of the rock core is in cm. For water phase pressure, ; The distance traveled is in centimeters. Based on the propulsion speed of the surface with equal water saturation, equation (18) can be derived from equation (15): （18） in, The distance traveled is in meters (m). L The length of the core sample is in meters (m). This is the derivative of the flow rate with respect to water saturation. The derivative of the flow fraction at the end of the core with respect to water saturation can be expressed as: （19） in, This is the derivative of the flow rate at the end of the core with respect to water saturation. This is the cumulative injected pore volume multiple; The cross-sectional area of ​​the rock core is in cm². 2 ; The length of the rock core is in cm. Porosity of porous media; To accumulate the injected water volume, cm 3 ; Substituting equations (16) and (18) into (17) yields equation (20): （20） in, The pressure difference between the two ends of the core. ; This is the derivative of the flow rate at the end of the core with respect to water saturation. The total fluid velocity in the porous reservoir medium is expressed in cm / s. For the aqueous phase flow rate; For the viscosity of the aqueous phase, ; For porous media permeability, ; The relative permeability of the aqueous phase; The length of the rock core is in cm. This is the derivative of the flow rate with respect to water saturation. Substituting equation (18) into equation (20) and differentiating both sides, we obtain the formula for the relative permeability of the water phase (21): （21） in, The relative permeability of the water phase at the end saturation of the core; This represents the water phase fraction at the end of the core sample. This is the cumulative injected pore volume multiple; The absolute permeability of the core. ; The pressure difference between the two ends of the core. ; The total seepage velocity is expressed in cm / s. The viscosity of the aqueous phase is... ; The length of the rock core is in cm. Combining equations (21) and (11), we obtain the expression for the relative permeability of the oil phase (22): （22） in, The relative permeability of the oil phase at the end-saturation of the core; The relative permeability of the aqueous phase; Oil phase viscosity, ; The viscosity of the aqueous phase is... ; This represents the water phase fraction at the end of the core sample. The absolute permeability of the core. ; The total seepage velocity is expressed in cm / s. For capillary force, ; This represents the water saturation level of the core sample. The distance traveled is in centimeters. As can be seen from equations (21) and (22), the calculation of relative oil-water permeability must first determine the water saturation and its gradient at the end of the core. The expression for the average water saturation of the core is derived from the principle of mass balance (23): （23） in, This represents the average water saturation level. To bind water saturation; To accumulate oil production, cm 3 ; The cross-sectional area of ​​the rock core is in cm². 2 ; Porosity of porous media; The length of the rock core is in cm. The water saturation at the end of the core can be expressed as equation (24): （24） in, This represents the water saturation at the end of the core sample. This represents the average water saturation level. To accumulate the injected water volume, cm 3 ; t Let the flow time be in seconds. This represents the oil phase fraction at the end of the core sample. The cross-sectional area of ​​the rock core is in cm². 2 ; Porosity of porous media; The length of the rock core is in cm. Core capillary force expression (25): （25） in, For capillary force, ; For oil-water interfacial tension, ; The core wetting angle is (°). Where is the pore radius, in cm; For the capillary force curve of mercury injection, the capillary force expression for different water saturation levels during water-driven oil recovery can be obtained by converting the capillary force between mercury gas and oil-water. (26) （26） in, The capillary force during water-driven oil displacement. ; For mercury to enter, that is, the capillary force when mercury drives gas, ; For oil-water interfacial tension, ; The interfacial tension of mercury at the gas-liquid interface. ; The wetting angle of water on the core is (°). θ represents the wetting angle of mercury on the core, in degrees (°). The relative permeability curves of oil and water considering the effect of capillary force during oil-water seepage in low-permeability cores were calculated by combining equations (21), (22), (24) and (26).

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