CN-116877047-B - Method for measuring oil-water relative permeability curve of low-permeability core under low-speed flow condition

CN116877047BCN 116877047 BCN116877047 BCN 116877047BCN-116877047-B

Abstract

The invention discloses a method for measuring an oil-water relative permeability curve of a low-permeability core under a low-speed flowing condition, which comprises the steps of weighing the core to be measured, measuring the length and the section diameter, sequentially vacuumizing the core to be measured, saturating gas, vacuumizing, pressurizing saturated water, continuing saturated water at a set temperature, calculating the absolute permeability of the core, displacing a saturated oil phase until no water is discharged, calculating the saturation of water and the relative permeability of the oil phase, ageing the core to be measured, displacing water at a low speed, calculating the relative permeability of an aqueous phase under the saturation of residual oil, taking out the core, cleaning, drying, measuring capillary force of the core by a mercury-pressing method, and drawing an oil-water two-phase relative permeability curve. In the invention, in the step of adding saturated CO 2 , residual gas in fine pores is replaced by water phase, after the subsequent saturated crude oil, the core is only oil-water two-phase flow, and capillary force imbibition oil displacement effect exists when the oil-water two-phase flow, so that the result is consistent with the actual situation, and is accurate and reliable.

Inventors

XU LONG
DONG MINGZHE
LIU ZIQING
LIU SEN
YANG ZHIHONG
LIU XU
WANG KE
LI PENGCHENG
GONG HOUJIAN
SUN HAI

Assignees

中国石油大学(华东)

Dates

Publication Date: 20260505
Application Date: 20221115

Claims (8)

1. The method for measuring the oil-water relative permeability curve of the hypotonic rock core under the low-speed flow condition is characterized by comprising the following steps of: s1, weighing a core to be measured, and measuring the length and the section diameter; S2, sequentially vacuumizing the rock core to be tested, saturating gas, and vacuumizing again, wherein the gas is CO2 which is easily dissolved in water; s3, pressurizing saturated water of the core to be tested; s4, continuously saturating the core to be measured at a set temperature, and calculating the absolute permeability of the core to be measured according to the pressure values of the two ends of the core to be measured; S5, displacing the saturated oil phase of the core to be measured until no water is discharged at a set temperature, and calculating the irreducible water saturation of the core to be measured and the relative permeability of the oil phase under the irreducible water saturation according to the volume of the discharged water and the pressure values of the two ends of the core to be measured; S6, aging the core to be measured at a set temperature; S7, carrying out simulated formation water flooding at a set temperature and a low speed until no oil phase is produced, and calculating the relative permeability of the water phase under the saturation of the residual oil of the core to be measured according to the pressure at the two ends of the core to be measured and the accumulated water and oil output at different moments; S8, taking out the core to be measured, cleaning, drying and measuring capillary force of the core to be measured by a mercury intrusion method; And S9, calculating and drawing an oil-water two-phase relative permeability curve through a low-permeability core oil-water relative permeability calculation formula under the low-speed flow condition considering the capillary force effect.
2. The method for determining the oil-water relative permeability curve of the hypotonic core under the low-speed flowing condition according to claim 1, wherein the step of weighing the core to be measured and measuring the length and the section diameter in the step S1 comprises the steps of cleaning the core to be measured by an organic solvent, drying and oven-drying, then weighing and measuring the length and the section diameter.
3. The method for determining the oil-water relative permeability curve of the hypotonic core under the low-speed flowing condition as claimed in claim 1, wherein in the step S2, the core to be measured is sequentially vacuumized, saturated gas is pumped out, and then vacuumized, and the core to be measured is sequentially vacuumized for 10 hours, saturated gas is pumped out for 10 hours, and then vacuumized for 10 hours.
4. The method for determining a low permeability curve of oil and water of a core under low-velocity flow conditions as set forth in claim 1, wherein continuing to saturate the core to be measured with water in S4 includes continuing to saturate the core to be measured with water at a constant velocity.
5. The method for determining the oil-water relative permeability curve of the hypotonic core under the low-speed flowing condition as claimed in claim 1, wherein the step S5 is to displace the constant-speed saturated oil phase of the core to be measured until no water is discharged.
6. The method for determining an oil-water relative permeability curve of a hypotonic core under a low-speed flowing condition as set forth in claim 1, wherein aging the core to be measured in S6 includes aging the core to be measured for 5 days.
7. The method for determining the permeability curve of low permeability core oil-water under the condition of low flow according to claim 1, wherein the step of performing simulated formation water flooding at a low speed in S7 comprises performing simulated formation water flooding at a constant low speed.
8. The method for determining the oil-water relative permeability curve of the hypotonic core under the low-speed flowing condition as set forth in claim 1, wherein the drawing of the oil-water two-phase relative permeability curve in S9 includes establishing a calculation formula of the oil-water relative permeability of the hypotonic core under the low-speed flowing condition: The conditions are assumed that the core is a uniform porous medium, the driving force is unchanged, the oil-water property is kept unchanged, the oil-water does not react, and no inter-phase mass transfer phenomenon exists, the compressibility of the core and the fluid is ignored, and the influence of capillary force is considered; under the low-speed flow condition, the low-permeability core fluid seepage is linear flow, and the oil-water two-phase Darcy flow equation of motion is shown as formula (1) and formula (2): (1) (2) Wherein, the And The seepage speeds of the oil phase and the water phase are respectively cm/s; In order to achieve the permeability of the porous medium, ; And The relative permeability of the oil phase and the water phase is respectively; And The viscosity of the oil phase and the water phase are respectively, ; And The pressure of the oil phase and the water phase are respectively, ; Is the flow distance, cm; The expression of capillary force is formula (3): (3) Wherein, the Is capillary force, water saturation Is a function of (a) and (b), ; And The pressure of the oil phase and the water phase are respectively, ; In combination with formula (3), formula (1) is deformed to formula (4): (4) Wherein, the The oil phase seepage speed is cm/s; In order to achieve the permeability of the porous medium, ; Is the relative permeability of the oil phase; is the viscosity of the oil phase, ; Is the pressure of the water phase, ; Is capillary force, water saturation Is a function of (a) and (b), ; Is the flow distance, cm; The total seepage velocity of the fluid in the core is as follows: (5) Wherein, the The total seepage velocity of the fluid in the core is cm/s; the oil phase seepage speed is cm/s; Water phase seepage speed, cm/s; The oil and water flow rates can be expressed as: (6) Wherein, the And The split flow of the oil phase and the water phase is respectively; the oil phase seepage speed is cm/s; Water phase seepage speed, cm/s; The total seepage velocity of the fluid in the core is cm/s; the formula (7) and the formula (8) are obtained by deforming the formula (1) and the formula (2): (7) (8) Wherein, the And The seepage speeds of the oil phase and the water phase are respectively cm/s; In order to achieve the permeability of the porous medium, ; And The relative permeability of the oil phase and the water phase is respectively; And The viscosity of the oil phase and the water phase are respectively, ; And The pressure of the oil phase and the water phase are respectively, ; Is the flow distance, cm; the simultaneous formulas (3) (6) (7) (8) give formula (9): (9) Wherein, the The total seepage velocity of the fluid in the core is cm/s; And The split flow of the oil phase and the water phase is respectively; And The viscosity of the oil phase and the water phase are respectively, ; And The relative permeability of the oil phase and the water phase is respectively; is capillary force, water saturation Is a function of (a) and (b), ; In order to achieve the permeability of the porous medium, ; Is the flow distance, cm; The material balance relation is that Then formula (9) is modified to formula (10): (10) Wherein, the The water phase is divided into water phase flow; flow time, s; And The viscosity of the oil phase and the water phase are respectively, ; And The relative permeability of the oil phase and the water phase is respectively; In order to achieve the permeability of the porous medium, ; The total seepage velocity of the fluid in the core is cm/s; is capillary force, water saturation Is a function of (a) and (b), ; Is the flow distance, cm; neglecting the compressibility of oil and water, the continuity equations of oil and water phases in the one-dimensional homogeneous stratum water displacement process are respectively shown as a formula (11) and a formula (12): (11) (12) Wherein, the And The seepage speeds of the oil phase and the water phase are respectively cm/s; Is the flow distance, cm; is the core porosity; is water saturation; is oil saturation; flow time, s; in combination with formula (6), formula (12) is deformed into (13): (13) Wherein, the The total seepage velocity of the fluid in the core is cm/s; flow time, s; the water phase is divided into water phase flow; Is the flow distance, cm; is water saturation; the movement velocity formula (14) of the water saturation surface in the core, which is obtained by the deformation of formula (13): (14) Wherein, the Is the flow distance, cm; flow time, s; is water saturation; The total seepage velocity of the fluid in the core is cm/s; is the porosity of the porous medium; the water phase is divided into water phase flow; Differential pressure between two ends of core The relation with the relative permeability is deformed by the formula (2) to obtain the formula (15): (15) Wherein, the Is the pressure of the water phase, ; Is the flow distance, cm; The water phase seepage speed is cm/s; Is the viscosity of water phase, mPa×s; In order to achieve the permeability of the porous medium, ; Relative permeability of the aqueous phase; Substituting formula (6) into formula (15) to obtain formula (16): (16) Wherein, the Is the pressure of the water phase, ; Is the flow distance, cm; The total seepage velocity of the fluid in the core is cm/s; the water phase is divided into water phase flow; Is the viscosity of the water phase, ; In order to achieve the permeability of the porous medium, ; Relative permeability of the aqueous phase; Assuming that the rock porous medium is wet, the pressure difference between two ends of the core is expressed as a parameter of an aqueous phase as shown in the formula (17): (17) Wherein, the Is the pressure difference between two ends of the core, ; The length of the core is cm; Is the pressure of the water phase, ; Is the flow distance, cm; from equation (15), equation (18) can be derived based on the constant water saturation surface thrust rate: (18) Wherein, the L is the length of the core, m; The derivative of the shunt volume with respect to the water saturation; the derivative of shunt volume at the end of the core with respect to water saturation can be expressed as: (19) Wherein, the The derivative of shunt volume at the end of the core with respect to water saturation; to accumulate injected pore volume times; is the cross-sectional area of the core, cm 2 ; the length of the core is cm; is the porosity of the porous medium; cm 3 for accumulating the injected water quantity; substituting formulas (16) and (18) into (17) to obtain formula (20): (20) Wherein, the Is the pressure difference between two ends of the core, ; The derivative of shunt volume at the end of the core with respect to water saturation; the total seepage velocity of the fluid in the porous medium of the reservoir is cm/s; the water phase is divided into water phase flow; Is the viscosity of the water phase, ; In order to achieve the permeability of the porous medium, ; Relative permeability of the aqueous phase; the length of the core is cm; The derivative of the shunt volume with respect to the water saturation; substituting the formula (18) into the formula (20) to obtain two ends for derivation, and finishing to obtain a formula (21) of relative permeability of water phase: (21) Wherein, the Relative permeability of the aqueous phase at the saturation of the end of the core; the water phase shunt quantity at the tail end of the rock core; to accumulate injected pore volume times; As the absolute permeability of the core, the water is mixed with the water, ; Is the pressure difference between two ends of the rock core, ; Is the total seepage velocity, cm/s; Is the viscosity of the water phase, ; The length of the core is cm; The combination of (21) and (11) gives the oil phase relative permeability expression (22): (22) Wherein, the The relative permeability of the oil phase at the saturation of the tail end of the core; relative permeability of the aqueous phase; Is the viscosity of the oil phase, ; Is the viscosity of the water phase, ; The water phase shunt quantity at the tail end of the rock core; As the absolute permeability of the core, the water is mixed with the water, ; Is the total seepage velocity, cm/s; For the force of the capillary tube, ; Water saturation for the core; Is the flow distance, cm; from formulas (21) and (22), the calculation of the relative oil-water permeability first requires the determination of the water saturation and gradient of the core end; obtaining a core average water saturation expression (23) according to a material balance principle: (23) Wherein, the Is the average water saturation; to irreducible water saturation; cm 3 for cumulative oil production; is the cross-sectional area of the core, cm 2 ; is the porosity of the porous medium; the length of the core is cm; the water saturation at the end of the core can be expressed as formula (24): (24) Wherein, the Water saturation at the end of the core; Is the average water saturation; for accumulating the injected water quantity, cm 3 , t is the flowing time, s; the oil phase shunt quantity at the tail end of the core; is the cross-sectional area of the core, cm 2 ; is the porosity of the porous medium; the length of the core is cm; core capillary force expression (25): (25) Wherein, the For the force of the capillary tube, ; Is the tension of the oil-water interface, ; Wetting angle for core, (°); is pore radius, cm; For the mercury-pressing capillary force curve, the capillary force expression (26) under different water saturation can be obtained by converting the capillary force between mercury gas and oil water during water flooding: (26) Wherein, the Is the capillary force during water flooding, ; For mercury feeding, i.e. capillary force during mercury flooding, ; Is the tension of the oil-water interface, ; Is the gas-liquid interfacial tension of mercury, ; Wetting angle of water to core, (°); wetting angle of mercury to core, (°); and (4) calculating an oil-water relative permeability curve considering the influence of capillary force when oil and water in the hypotonic core permeate.

Description

Method for measuring oil-water relative permeability curve of low-permeability core under low-speed flow condition Technical Field The invention relates to the technical field of oil and gas field development seepage, in particular to a method for measuring a low-permeability rock core oil-water relative permeability curve under a low-speed flow condition. Background Compact, shale and other low permeability reservoirs are currently becoming important points for oil and gas exploration and development, and low permeability reservoirs are complex in pore throat structure due to narrow rock pores, and oil-water seepage characteristics are different from those of conventional medium-high permeability reservoirs. The oil-water relative permeability curve is the reflection of interaction of oil and water in the flowing process, and is a key basic data necessary for dynamic analysis of oil field development, evaluation of residual oil and numerical simulation of oil reservoirs. For the measurement of the oil-water relative permeability curve of a conventional medium-high permeability reservoir, SYT 5345-2007 industry standard is mainly adopted at present. However, for the determination of the oil-water relative permeability curve of a hypotonic reservoir, this method ignores the capillary force effect of the hypotonic reservoir and requires that the displacement rate not be too low, which is severely inconsistent with the actual lower imbibition displacement rate of the hypotonic reservoir. Therefore, in order to meet the characteristics of the hypotonic reservoir, the existing method for determining the oil-water relative permeability curve of the core needs to be improved. However, in the improved experimental method, the prior art adopts a conventional core saturated fluid method when the low-permeability core is saturated with fluid, and is limited by vacuumizing experimental equipment, after saturated simulated formation water, gas is stored in the fine pore throats in the core, the saturated fluid is insufficient, the inside of the core is changed from a liquid single-phase flow to a gas-liquid two-phase flow, and after saturated crude oil is continued subsequently, the fluid state of the more complex oil-water-gas three-phase flow is changed, so that the oil layer physical property of the oil-water two-phase seepage characteristics to be simulated originally is changed. Therefore, the experimental result obtained by the experimental method has larger error and even error. Meanwhile, due to the existence of residual gas when the hypotonic core is in a saturated water phase, the phenomenon of nonlinear flow and starting pressure gradient is shown when fluid flows at a low speed, and a calculation formula of the oil-water relative permeability of the hypotonic core obtained by the prior art is also larger in error. Disclosure of Invention The invention aims to overcome the defects of the prior art, and provides a method for measuring the oil-water relative permeability curve of a low-permeability core under the condition of low-speed flow. In order to achieve the above purpose, the present invention adopts the following technical scheme: A method for measuring the oil-water relative permeability curve of a hypotonic rock core under the condition of low-speed flow comprises the following steps: s1, weighing a core to be measured, and measuring the length and the section diameter; s2, sequentially vacuumizing the core to be tested, saturating the gas, and vacuumizing again; s3, pressurizing saturated water of the core to be tested; s4, continuously saturating the core to be measured at a set temperature, and calculating the absolute permeability of the core to be measured according to the pressure values of the two ends of the core to be measured; S5, displacing the saturated oil phase of the core to be measured until no water is discharged at a set temperature, and calculating the irreducible water saturation of the core to be measured and the relative permeability of the oil phase under the irreducible water saturation according to the volume of the discharged water and the pressure values of the two ends of the core to be measured; S6, aging the core to be measured at a set temperature; S7, performing water flooding at a low speed at a set temperature until no oil phase is produced, and calculating the relative permeability of the water phase under the saturation of the residual oil of the core to be measured according to the pressure at the two ends of the core to be measured and the accumulated water and oil output at different moments; S8, taking out the core to be measured, cleaning, drying and measuring capillary force of the core to be measured by a mercury intrusion method; and S9, drawing an oil-water two-phase relative permeability curve. In one possible design, the gas in S2 is a readily water-soluble gas. In one possible design, the gas is CO 2. In one possible design, the step S1 of weighing the