CN116877047A - Method for measuring oil-water relative permeability curve of low-permeability core under low-speed flow condition - Google Patents

Method for measuring oil-water relative permeability curve of low-permeability core under low-speed flow condition Download PDF

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CN116877047A
CN116877047A CN202211424321.5A CN202211424321A CN116877047A CN 116877047 A CN116877047 A CN 116877047A CN 202211424321 A CN202211424321 A CN 202211424321A CN 116877047 A CN116877047 A CN 116877047A
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water
core
oil
phase
formula
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徐龙
刘子青
刘森
杨志鸿
刘旭
王珂
李鹏程
宫厚健
孙海
董明哲
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China University of Petroleum East China
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20—Displacing by water
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F30/00—Computer-aided design [CAD]
    • G06F30/20—Design optimisation, verification or simulation
    • G06F30/28—Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F2113/00—Details relating to the application field
    • G06F2113/08—Fluids
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F2119/00—Details relating to the type or aim of the analysis or the optimisation
    • G06F2119/08—Thermal analysis or thermal optimisation
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F2119/00—Details relating to the type or aim of the analysis or the optimisation
    • G06F2119/14—Force analysis or force optimisation, e.g. static or dynamic forces

Abstract

The invention discloses a method for measuring a low-permeability rock core oil-water relative permeability curve under a low-speed flow condition, which comprises the steps of weighing a rock core to be measured and measuring the length and the section diameter; sequentially vacuumizing the core to be tested, saturating gas, vacuumizing again, and pressurizing saturated water; continuously saturating water at a set temperature, and calculating the absolute permeability of the core; saturated oil phase, displacing until no water is discharged, and calculating the saturation of the irreducible water and the relative permeability of the oil phase; core to be measuredAging; the displacement of reservoir oil is carried out at low speed, and the relative permeability of the water phase under the saturation of the residual oil is calculated; taking out the core, cleaning, drying and measuring the capillary force of the core by a mercury-vapor method; and drawing an oil-water two-phase relative permeability curve. The invention adds saturated CO 2 The residual gas in the fine pores is replaced by water phase, after the subsequent saturated crude oil, the core is only oil-water two-phase flow, when the oil-water two-phase flow, capillary force imbibition displacement oil effect exists, and the obtained result is accurate and reliable according with the actual situation.

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 core to be measured and measuring the length and the section diameter includes cleaning the core to be measured with an organic solvent, drying and oven drying, and then weighing again and measuring the length and the section diameter.
In one possible design, in S2, the core to be tested is sequentially vacuumized, saturated and vacuumized again, including sequentially vacuuming the core to be tested for 10h, saturated and vacuumized for 10h again.
In one possible design, continuing to saturate the core to be tested in S4 includes continuing to saturate the core to be tested at a constant rate.
In one possible design, in S5, the core to be tested is displaced from the constant-speed saturated oil phase until no water is discharged.
In one possible design, the aging the core to be measured in S6 includes aging the core to be measured for 5 days.
In one possible design, the step S7 is performed at a low speed, including performing the water flooding at a constant low speed.
In one possible design, the drawing the oil-water two-phase relative permeability curve includes creating a hypotonic core oil-water relative permeability calculation formula under low-velocity flow conditions:
assume the condition: the core is a uniform porous medium; the driving force is unchanged, and is water drive; the oil-water property is kept unchanged; the oil and water do not react, and no interphase mass transfer phenomenon exists; neglecting compressibility of the core and fluid; considering the influence of capillary force;
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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw The relative permeability of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa; x is the flow distance, cm;
the expression of capillary force is formula (3):
P c ＝P o -P w (3)
wherein P is c Is capillary force, is water saturation S w 10 -1 MPa；P o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa；
In combination with formula (3), formula (1) is deformed to formula (4):
wherein v is o The oil phase seepage speed is cm/s; k is the permeability of the porous medium, mum 2 ；K ro Is the relative permeability of the oil phase; mu (mu) o Is the viscosity of oil phase, mPa.s; p (P) w Is the water phase pressure, 10 -1 MPa；P c Is capillary force, is water saturation S w 10 - 1 MPa; x is the flow distance, cm;
the total seepage velocity of the fluid in the core is as follows:
v＝v o +v w (5)
wherein v is the total seepage velocity of the fluid in the core, cm/s; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s;
the oil and water flow rates can be expressed as:
wherein f o And f w The split flow of the oil phase and the water phase is respectively; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s; v is the total seepage velocity of the fluid in the core, cm/s;
the formula (7) and the formula (8) are obtained by deforming the formula (1) and the formula (2):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw The relative permeability of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa; x is the flow distance, cm;
the simultaneous formulas (3) (6) (7) (8) give formula (9):
wherein v is the total seepage velocity of the fluid in the core, cm/s; f (f) o And f w The split flow of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the x is the flow distance, cm;
the material balance relation is f o ＝1-f w Then formula (9) is modified to formula (10):
wherein f w The water phase is divided into water phase flow; t is the flow time, s; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity of the fluid in the core, cm/s; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; x 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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; x is the flow distance, cm; Is the core porosity; s is S w Is water saturation; s is S o Is oil saturation; t is the flow time, s;
in combination with formula (6), formula (12) is deformed into (13):
wherein v is the total seepage velocity of the fluid in the core, cm/s; t is the flow time, s; f (f) w The water phase is divided into water phase flow; x is the flow distance, cm; s is S w 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):
wherein x is the flow distance, cm; t is the flow time, s; s is S w Is water saturation; v is the total seepage velocity of the fluid in the core, cm/s;is the porosity of the porous medium; f (f) w The water phase is divided into water phase flow;
the relation between the differential pressure deltap at the two ends of the core and the relative permeability is deformed into a formula (15) through a formula (2):
wherein P is w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v w The water phase seepage speed is cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase;
substituting formula (6) into formula (15) to obtain formula (16):
wherein P is w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v is the total seepage velocity of the fluid in the core, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw 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):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa; l is the length of the core, cm; p (P) w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm;
from equation (15), equation (18) can be derived based on the constant water saturation surface thrust rate:
wherein x is the flow distance, m; l is the length of the core and m; f's' w The derivative of the shunt volume with respect to the water saturation; f (f) w ' 2 The derivative of shunt volume at the end of the core with respect to water saturation can be expressed as:
wherein f' w2 The derivative of shunt volume at the end of the core with respect to water saturation;to accumulate injected pore volume times; a is the cross-sectional area of the core, cm 2 The method comprises the steps of carrying out a first treatment on the surface of the L is the length of the core, cm; />Is the porosity of the porous medium; q (Q) Iw (t) is the cumulative injected water amount, cm 3 ；
Substituting formulas (16) and (18) into (17) to obtain formula (20):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa；f' w2 The derivative of shunt volume at the end of the core with respect to water saturation; v is the total fluid seepage velocity in the reservoir porous medium, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase; l is the length of the core, cm; f's' w 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:
wherein K is rw2 Relative permeability of the aqueous phase at the saturation of the end of the core; f (f) w2 The water phase shunt quantity at the tail end of the rock core;to accumulate injected pore volume times; k is rockAbsolute permeability of heart, μm 2 The method comprises the steps of carrying out a first treatment on the surface of the ΔP is the pressure difference between two ends of the core, 10 -1 MPa; v is the total seepage velocity, cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; l is the length of the core, cm;
the combination of (21) and (11) gives the oil phase relative permeability expression (22):
wherein K is ro2 The relative permeability of the oil phase at the saturation of the tail end of the core; k (K) rw2 Relative permeability of the aqueous phase; mu (mu) o Is the viscosity of oil phase, mPa.s; mu (mu) w Is the viscosity of water phase, mPa.s; f (f) w2 The water phase shunt quantity at the tail end of the rock core; k is the absolute permeability of the core, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity, cm/s; p (P) c Is the capillary force, 10 -1 MPa；S w Water saturation for the core; x 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:
wherein S is wa Is the average water saturation; s is S wc To irreducible water saturation; sigma Q o Cm for cumulative oil production 3 The method comprises the steps of carrying out a first treatment on the surface of the A is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
the water saturation at the end of the core can be expressed as formula (24):
wherein S is w2 Water saturation at the end of the core; s is S wa Is the average water saturation; q (Q) Iw (t) is the cumulative injected water amount, cm 3 The method comprises the steps of carrying out a first treatment on the surface of the t is the flow time, s; f (f) o2 The oil phase shunt quantity at the tail end of the core; a is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
core capillary force expression (25):
wherein P is c Is the capillary force, 10 -1 MPa; sigma is the interfacial tension of oil and water, mN.m -1 The method comprises the steps of carrying out a first treatment on the surface of the θ is core wetting angle, (°); r is the radius of the pore, 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:
wherein P is cwo Capillary force in water flooding, 10 -1 MPa；P cHg For capillary force at the time of mercury intake (mercury purge), 10 - 1 MPa；σ wo Is the interfacial tension of oil and water, mN.m -1 ；σ Hg Is the gas-liquid interfacial tension of mercury, mN.m -1 ；θ w Wetting angle of water to core, (°); θ Hg 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.
The beneficial effects of the invention are as follows:
in the actual stratum, capillary force effect in the hypotonic core is obvious and occurs in the tiny pores of the core; under experimental conditions, because the vacuum equipment is used for limiting, after the water phase is directly saturated after the vacuum pumping, part of air is remained in part of fine pores, and is residual gas which is not replaced by the water phase, and capillary force imbibition oil displacement effect can not occur when oil-water two-phase flows due to the existence of the residual gas, so that the oil displacement effect is inconsistent with the actual condition of an oil field.
In the process of measuring the basic parameters of the oil-water relative permeability, the saturated gas is added after the step of vacuumizing, especially the CO gas which is easy to dissolve in water 2 The purpose of removing residual gas and being beneficial to capillary force imbibition and displacement of reservoir oil can be achieved. This is due to CO 2 Can be mixed with air, and residual air in the core tiny pores and blind end pore throats is subjected to CO after the vacuum pumping is continued 2 Substituted. After pressurizing saturated simulated formation water because of CO 2 The solubility in water is good, the core has tiny pores and residual CO in the blind end pore throat 2 Will dissolve in simulated formation water at higher pressure, dissolving CO 2 The simulated formation water is driven out of the core under the displacement of the subsequent simulated formation water, so that only the simulated formation water existing in the pores of the core is ensured to be single-phase flow of the simulated formation water, and the problem of insufficient saturated fluid of the core in the prior art is solved.
CO in the present invention 2 Is different from supercritical CO commonly used in oil fields 2 They are to CO 2 As an oil displacement agent, the oil is injected into the stratum in the process of oil displacement, and the oil is displaced. In the process of simulating the stratum saturated rock core, in order to saturate the water phase and the oil phase into the rock core and ensure that no air exists in the pores of the rock core, the rock core after the water phase and the oil phase are saturated more like the actual state in the stratum, so that saturated CO is added after vacuumizing 2 Uses CO with larger diffusion coefficient of gas 2 Replace the air in the core and utilize CO 2 Is easy to be dissolved in water, and when the core is saturated with water phase, CO is allowed to be reacted with water 2 Dissolving in water, and dissolving CO when the core is saturated with oil phase 2 Is driven out by the water phase of (2)To ensure that no air exists in the core pores and only oil-water two phases exist.
At the time of adding saturated CO 2 After the step (2), the residual gas in the fine pores is replaced by water phase, and after the subsequent saturated crude oil, the core is only oil-water two-phase flow. The capillary force imbibition displacement oil function exists when the oil-water two-phase flow is carried out, the capillary force imbibition displacement oil is consistent with the actual situation, meanwhile, the oil-water relative permeability curve is calculated and drawn through a low-permeability core oil-water relative permeability calculation formula under the low-speed flow condition considering the capillary force function, the oil-water seepage characteristic under the low-speed flow condition can be more accurately represented, and further, an accurate and reliable experimental result is obtained.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present application, the drawings required for the description of the embodiments will be briefly described below, and it is apparent that the drawings in the following description are only some embodiments of the present application, and other drawings may be obtained according to these drawings without inventive effort for a person skilled in the art.
FIG. 1 is a schematic diagram of a low permeability core water flooding physical simulation experiment device provided by an embodiment of the application;
FIG. 2 is a schematic drawing of capillary force curve measured by mercury intrusion method in step S8 and converted into water flooding according to the present application;
FIG. 3 is a schematic diagram of the oil-water two-phase relative permeability curve calculated in step S9 when the displacement speed of the core A is 0.001 ml/min;
fig. 4 is a schematic diagram of a relative permeability curve of oil-water two phases calculated in step S9 when the displacement speed of the core a provided in the embodiment of the present application is 0.004 ml/min;
FIG. 5 is a schematic diagram of the oil-water two-phase relative permeability curve calculated in step S9 when the displacement speed of the core B is 0.001 ml/min;
FIG. 6 shows a core B without saturated CO according to an embodiment of the present application 2 Step, at a displacement speed of 0.004ml/min, the oil calculated in step S9A water two-phase relative permeability curve schematic;
the hydraulic oil storage device comprises a cylinder 1, an injection pump 2, a gas storage intermediate container 4, a water storage intermediate container 5, an oil storage intermediate container 6, a displacement liquid storage intermediate container 7, a capillary tube 8, a core holder 9, a first hand-operated pump 10, a safety bottle 12, a vacuum pump 15, a transparent hose 16, a scale plate 17, a back pressure valve 18, a second hand-operated pump 21, a thermostatic device 101, a first pressure gauge 102, a second pressure gauge 104, a fourth pressure gauge 201, a first valve 202, a second valve 203, a third valve 204, a fourth valve 205, a fifth valve 206, a sixth valve 207, a seventh valve 208, an eighth valve 209, a ninth valve 211, an eleventh valve 212, a twelfth valve 213, a thirteenth valve 216 and a sixteenth valve.
Specific embodiments of the present application have been shown by way of the above drawings and will be described in more detail below. The drawings and the written description are not intended to limit the scope of the inventive concepts in any way, but rather to illustrate the inventive concepts to those skilled in the art by reference to the specific embodiments.
Detailed Description
For the oil-water relative permeability test of a conventional medium-high permeability reservoir, the most commonly used method at present is an unsteady state method. However, this method does not take into account the effect of capillary pressure. Compared with the conventional reservoir, the capillary force of the hypotonic reservoir has remarkable and non-negligible effect. In order to reduce the influence of capillary force as much as possible, a method for improving the displacement speed is generally adopted, namely SYT 5345-2007 industry standard used at present in China. But this is severely inconsistent with the actual lower imbibition displacement rate of a 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. However, because the pores of the hypotonic core are very small, the air in the core cannot be completely pumped out in the vacuumizing process, so that after the formation water is saturated and simulated, gas is stored in the fine pore throats in the core, the liquid single-phase flow in the core is changed into a gas-liquid two-phase flow, and after the saturated crude oil is continued subsequently, the liquid-liquid two-phase flow is changed into a more complex flow state of the oil-water-gas three-phase flow, and the physical properties of the oil layer of the oil-water two-phase seepage characteristics to be simulated originally are 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.
The embodiment of the invention discloses a method for measuring a low-permeability rock core oil-water relative permeability curve under a low-speed flow condition, which comprises 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 measured, 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 at 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 at different moments and the accumulated water and oil output;
s8, taking out the core to be measured, cleaning, drying and measuring the capillary force of the core to be measured by a mercury-vapor 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.
It can be appreciated that, because gas molecules enter the core pores more easily than liquid molecules by diffusion, the residual air in the core pores is replaced by water-soluble gas by saturation of water-soluble gas and then vacuumizing, after the subsequent saturation of simulated formation water, the residual water-soluble gas is more soluble in simulated formation water than air, and the simulated formation water dissolved with water-soluble gas is displaced out of the core under the displacement of the subsequent simulated formation water, so that only the simulated formation water existing in the core pores is ensured.
In one possible design, the gas is CO 2 。
It will be appreciated that CO 2 Is a common gas which is easy to dissolve in water, and has low cost and easy acquisition.
For the indoor simulated saturated fluid of the hypotonic rock core, the conventional rock core saturated fluid method for oil extraction in the prior art is that simulated formation water or crude oil is saturated immediately after vacuumizing, and no saturated CO exists in the middle 2 Is a process of (2). Because the pores of the hypotonic core are very small and limited by the vacuum equipment, the air in the core cannot be completely pumped out in the vacuum process. Meanwhile, because the solubility of air in water is limited, saturated simulated formation water cannot enter the blind-end hole throat to replace gas. Therefore, after saturated simulated formation water, gas is stored in the fine pore throats in the rock core, so that the liquid single phase flow in the rock core is changed into a gas-liquid two-phase flow, and after the saturated crude oil is continued in the follow-up process, the gas-liquid three-phase flow is changed into a more complex flow state of the oil-water three-phase flow, and a gas-sensitive effect is generated due to the existence of bubbles when the oil-water flows, so that the physical properties of an oil layer of the oil-water two-phase seepage characteristic to be simulated originally are changed. Therefore, the experimental result obtained on the basis has larger errors and even mistakes.
In the method provided in this example, saturated CO was added after the evacuation 2 Is a process of (2). Because of CO 2 Can be mixed with air, and residual air in the core tiny pores and blind end pore throats is subjected to CO after the vacuum pumping is continued 2 Substituted. After pressurizing saturated simulated formation water because of CO 2 In waterHas better solubility, and residual CO in the small pore of the rock core and the blind end pore throat 2 Will dissolve in simulated formation water at higher pressure, dissolving CO 2 The simulated formation water is driven out of the core under the displacement of the subsequent simulated formation water, so that only the simulated formation water existing in the pores of the core is ensured to be the single-phase flow of the simulated formation water. After the subsequent saturated crude oil, the oil-water two-phase flow is arranged in the core, and the oil-water distribution in the core is more in line with the actual state.
In one possible design, in S1, the core to be measured is weighed and the length and the section diameter are measured, including cleaning the core to be measured with an organic solvent, drying and oven drying, then weighing again and measuring the length and the section diameter.
In one possible design, the step S2 of sequentially evacuating the core to be measured and then evacuating the core to be measured with saturated gas includes sequentially evacuating the core to be measured for 10 hours and then evacuating the core to be measured with saturated gas for 10 hours and then evacuating the core to be measured for 10 hours.
Optionally, S3 pressurizing the core to be measured with saturated water includes pressurizing the core to be measured with saturated water for 24h.
In one possible design, continuing to saturate the core to be tested in S4 includes continuing to saturate the core to be tested at a constant rate.
It is understood that the saturated water velocity is consistent with the subsequent water displacement velocity. At a constant rate, a small amount of CO is dissolved in the core 2 The aqueous phase of (2) can be slowly displaced by the pure water phase, and the absolute permeability of the core is measured under the condition of constant-speed pressurized saturation.
In one possible design, the core to be tested is displaced in S5 with a constant velocity saturated oil phase until no water is discharged.
It is understood that the saturated oil velocity is consistent with the subsequent water displacement velocity, and the oil phase permeability at the core-bound water saturation is measured at a constant velocity.
In one possible design, aging the core under test in S6 includes aging the core under test for 5 days.
In one possible design, the water flooding is performed at a low speed in S7, including at a constant low speed.
It will be appreciated that the water flooding rate is consistent with the previous saturated fluid rate, resulting in permeability data at the same rate.
In one possible design, plotting the oil-water two-phase relative permeability curve includes establishing a hypotonic core oil-water relative permeability calculation formula under low flow conditions:
assume the condition: the core is a uniform porous medium; the driving force is unchanged, and is water drive; the oil-water property is kept unchanged; the oil and water do not react, and no interphase mass transfer phenomenon exists; neglecting compressibility of the core and fluid; consider the effect of capillary forces.
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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw The relative permeability of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa; x is the flow distance, cm;
the expression of capillary force is formula (3):
P c ＝P o -P w (3)
wherein P is c Is capillary force, is water saturation S w 10 -1 MPa；P o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa；
In combination with formula (3), formula (1) is deformed to formula (4):
wherein v is o The oil phase seepage speed is cm/s; k is the permeability of the porous medium, mum 2 ；K ro Is the relative permeability of the oil phase; mu (mu) o Is the viscosity of oil phase, mPa.s; p (P) w Is the water phase pressure, 10 -1 MPa；P c Is capillary force, is water saturation S w 10 - 1 MPa; x is the flow distance, cm;
the total seepage velocity of the fluid in the core is as follows:
v＝v o +v w (5)
wherein v is the total seepage velocity of the fluid in the core, cm/s; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s;
the oil and water flow rates can be expressed as:
wherein f o And f w The split flow of the oil phase and the water phase is respectively; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s; v is the total seepage velocity of the fluid in the core, cm/s;
the formula (7) and the formula (8) are obtained by deforming the formula (1) and the formula (2):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw Respectively oil phase and water phasePermeability to water; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa; x is the flow distance, cm;
the simultaneous formulas (3) (6) (7) (8) give formula (9):
wherein v is the total seepage velocity of the fluid in the core, cm/s; f (f) o And f w The split flow of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the x is the flow distance, cm;
the material balance relation is f o ＝1-f w Then formula (9) is modified to formula (10):
wherein f w The water phase is divided into water phase flow; t is the flow time, s; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity of the fluid in the core, cm/s; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; x 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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; x is the flow distance, cm;is the core porosity; s is S w Is water saturation; s is S o Is oil saturation; t is the flow time, s;
in combination with formula (6), formula (12) is deformed into (13):
wherein v is the total seepage velocity of the fluid in the core, cm/s; t is the flow time, s; f (f) w The water phase is divided into water phase flow; x is the flow distance, cm; s is S w 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):
Wherein x is the flow distance, cm; t is the flow time, s; s is S w Is water saturation; v is the total seepage velocity of the fluid in the core, cm/s;is the porosity of the porous medium; f (f) w The water phase is divided into water phase flow;
the relation between the differential pressure deltap at the two ends of the core and the relative permeability is deformed into a formula (15) through a formula (2):
wherein the method comprises the steps of，P w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v w The water phase seepage speed is cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase;
substituting formula (6) into formula (15) to obtain formula (16):
wherein P is w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v is the total seepage velocity of the fluid in the core, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw 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):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa; l is the length of the core, cm; p (P) w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm;
from equation (15), equation (18) can be derived based on the constant water saturation surface thrust rate:
wherein x is the flow distance, m; l is the length of the core and m; f's' w The derivative of the shunt volume with respect to the water saturation; f's' w2 The derivative of shunt volume at the end of the core with respect to water saturation can be expressed as:
wherein f' w2 The derivative of shunt volume at the end of the core with respect to water saturation;to accumulate injected pore volume times; a is the cross-sectional area of the core, cm 2 The method comprises the steps of carrying out a first treatment on the surface of the L is the length of the core, cm; />Is the porosity of the porous medium; q (Q) Iw (t) is the cumulative injected water amount, cm 3 ；
Substituting formulas (16) and (18) into (17) to obtain formula (20):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa；f' w2 The derivative of shunt volume at the end of the core with respect to water saturation; v is the total fluid seepage velocity in the reservoir porous medium, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase; l is the length of the core, cm; f's' w 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:
wherein K is rw2 Relative permeability of the aqueous phase at the saturation of the end of the core; f (f) w2 The water phase shunt quantity at the tail end of the rock core;to accumulate injected pore volume times; k is the absolute permeability of the core, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the ΔP is the two ends of the corePressure difference, 10 -1 MPa; v is the total seepage velocity, cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; l is the length of the core, cm;
the combination of (21) and (11) gives the oil phase relative permeability expression (22):
wherein K is ro2 The relative permeability of the oil phase at the saturation of the tail end of the core; k (K) rw2 Relative permeability of the aqueous phase; mu (mu) o Is the viscosity of oil phase, mPa.s; mu (mu) w Is the viscosity of water phase, mPa.s; f (f) w2 The water phase shunt quantity at the tail end of the rock core; k is the absolute permeability of the core, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity, cm/s; p (P) c Is the capillary force, 10 -1 MPa；S w Water saturation for the core; x 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:
wherein S is wa Is the average water saturation; s is S wc To irreducible water saturation; sigma Q o Cm for cumulative oil production 3 The method comprises the steps of carrying out a first treatment on the surface of the A is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
the water saturation at the end of the core can be expressed as formula (24):
wherein S is w2 Water saturation at the end of the core; s is S wa Is the average water saturation; q (Q) Iw (t) is the cumulative injected water amount, cm 3 The method comprises the steps of carrying out a first treatment on the surface of the t is the flow time, s; f (f) o2 The oil phase shunt quantity at the tail end of the core; a is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
core capillary force expression (25):
/>
wherein P is c Is the capillary force, 10 -1 MPa; sigma is the interfacial tension of oil and water, mN.m -1 The method comprises the steps of carrying out a first treatment on the surface of the θ is core wetting angle, (°); r is the radius of the pore, 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:
wherein P is cwo Capillary force in water flooding, 10 -1 MPa；P cHg For capillary force at the time of mercury intake (mercury purge), 10 - 1 MPa；σ wo Is the interfacial tension of oil and water, mN.m -1 ；σ Hg Is the gas-liquid interfacial tension of mercury, mN.m -1 ；θ w Wetting angle of water to core, (°); θ Hg 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.
It can be appreciated that the capillary force effect is obvious in the hypotonic core and occurs in the tiny pores of the core without adding saturated CO 2 When the step (2) is carried out, residual gas which is not replaced by water phase is in part of the fine pores, so that capillary force imbibition oil displacement effect is avoided when oil-water two-phase flows. At the time of adding saturated CO 2 After the step (2), residual gas in the fine pores is replaced by water phase, capillary force imbibition displacement oil is generated when oil-water two-phase flows, and the characteristic of oil-water seepage under the low-speed flow condition can be more accurately represented according to the actual situation. And further obtaining accurate and reliable experimental results.
The invention will be further described by means of specific examples.
The experimental methods used in the following specific examples are conventional methods unless otherwise specified.
The operations referred to in the following specific examples were performed under conventional conditions or conditions recommended by the manufacturer, without any reference to the conditions. The raw materials used are not specified by the manufacturer and the specification are all conventional products which can be obtained by commercial purchase.
In the following specific examples: the gas phase is CO 2 Qingdao Tianyuan gas Co., ltd; the oil phase is simulated oil (hexadecane), analytically pure, national medicine group chemical reagent company, inc.; the water phase is simulated stratum water, and the mineralization degree is 10561 mg.L -1 From NaCl, KCl, caCl 2 、MgCl 2 NaHCO (NaHCO) 3 The preparation is analytically pure, national drug group chemical reagent company; the displacement fluid is simulated formation water, and the components are the same as the above; the core A and the core B are artificial hypotonic cores, are manufactured by cementing sandstone and dolomite by cementing agents, and are manufactured by new materials of Qingdao research departments, inc.
A method for measuring the oil-water relative permeability curve of a low-permeability core under the condition of low-speed flow adopts a low-permeability core water flooding physical simulation experiment device shown in figure 1 to measure the basic parameters of the oil-water relative permeability, and comprises the following steps:
S1, measuring the length of a rock core A to be 5.78cm, the diameter of a section to be 2.5cm and the porosity to be 10.7%;
s2, loading the core A into a core holder 9; loading simulated formation water into the end of the water storage intermediate container 4 close to the seventh valve 207; loading the simulated oil into the end of the intermediate reservoir 5 adjacent to the eighth valve 208; filling displacement fluid into one end of the displacement fluid storage intermediate container 6 close to the ninth valve 209; connect all lines and close all valves;
opening a twelfth valve 212, setting confining pressure to the core A through the first hand-operated 10 pump, and closing the twelfth valve 212; opening a thirteenth valve 213, opening a vacuum pump 12 to vacuumize the interior of the core 8 for 10h, and closing the thirteenth valve 213;
the first valve 201 is opened and the CO in the gas cylinder 1 2 Into the air storage intermediate container 3, causing the piston of the air storage intermediate container 3 to be pushed to one end close to the third valve 203, closing the first valve 201; opening the second valve 202, the third valve 203 and the eleventh valve 211, opening the injection pump 2, pushing the piston of the gas storage intermediate container 3 to one end far away from the third valve 203, pressurizing saturated gas for 10h by 6MPa on the core A, and closing all the valves;
opening a thirteenth valve 213, opening the vacuum pump 12 to vacuumize the core A for 10 hours again, and closing the thirteenth valve 213;
S3, pressurizing saturated water for the core A;
a seventeenth valve 217 is opened, a back pressure of 10MPa is set to the back pressure valve 17 by the second swing pump 18, and the seventeenth valve 217 is closed;
opening a fourth valve 204, a seventh valve 207, an eleventh valve 211 and a sixteenth valve 216, starting the injection pump 2 and adjusting to a constant speed mode, pushing a piston of the water storage intermediate container 4 to one end close to the seventh valve 207, and saturating the core A with water phase for 24h;
s4, adjusting the constant temperature device to 25 ℃, continuously saturating the core A with saturated water at a saturated water speed of 0.001ml/min, and calculating the absolute permeability of the core to be measured according to the pressure values of the two ends of the core A;
s5, at a set temperature, displacing the saturated oil phase of the core A until no water is discharged, and calculating the irreducible water saturation of the core A and the oil phase relative permeability under the irreducible water saturation according to the volume of the discharged water and the pressure values of the two ends of the core A;
opening a fifth valve 205, an eighth valve 208, an eleventh valve 211 and a sixteenth valve 216, opening the injection pump 2 and adjusting to a constant speed mode, pushing a piston of the oil storage intermediate container 5 to one end close to the eighth valve 208, and saturating the oil phase of the core A until no water is discharged from the transparent hose 15;
Calculating the liquid outlet amounts of the water phase and the oil phase through a produced liquid collecting system, and calculating the core irreducible water saturation;
the calculation process is as follows:
core pore volume:
water yield in core: v (V) w =2.13 ml, i.e. the core saturated oil volume is 2.13ml;
core bound water volume: v (V) iw ＝PV-V w ＝3.03-2.13＝0.90ml；
Core irreducible water saturation: s is S iw ＝V iw /PV×100％＝0.90/3.03×100％＝29.8％。
Wherein V is the volume of the core, ml; PV is the pore volume of the core, ml;core porosity,%; r is the radius of the section of the core, cm; l is the length of the core, cm; v (V) iw Binding the water volume for the core, ml; s is S iw Water saturation for core tie,%.
S6, closing all valves, standing for 3 days at a set temperature, and aging the core A;
and S7, opening a sixth valve 206, a ninth valve 209, an eleventh valve 211 and a sixteenth valve 216, opening the injection pump 2 and adjusting to a constant speed mode, pushing a piston of the displacement fluid intermediate container 6 to one end close to the ninth valve 209, injecting the displacement fluid into the core A, wherein the displacement speed is 0.001ml/min until no oil is discharged in the transparent hose 15, and stopping injection. Reading the flowing distances of the oil phase and the water phase in the transparent hose 15 at different moments, and calculating the oil output and the water output at different moments;
s8, capillary force measurement
Cleaning and drying the core A . And (3) placing the rock core into a high-pressure mercury porosimeter, filling mercury into the rock core under a series of pressures, recording the mercury volume entering the rock core under each pressure, calculating the mercury saturation in the rock core through the mercury inlet volumes under different pressures, and drawing a mercury-pressing capillary force curve. Knowing the oil-water interfacial tension sigma wo ＝33.9mN·m -1 Mercury surface tension sigma Hg ＝480mN·m -1 Wetting angle θ of water to core w =0°, wetting angle θ of mercury to core Hg =140°. The capillary force at different water saturation levels at the time of water flooding is converted by the capillary force conversion formula (26) as shown in fig. 2.
S9, drawing an oil-water two-phase relative permeability curve
Substituting the oil-water amount and capillary force parameters extracted from water flooding at different moments into oil-water two-phase relative permeability calculation formulas (21), (22), (24) and (26), and drawing an oil-water two-phase relative permeability curve, as shown in figure 3. FIG. 3 is a graph showing the relative permeability of the oil and water phases of a core A, the displacement rate being 0.001ml/min, as can be seen from the graph, the absolute permeability of the core A being 0.04X 10 -3 μm 2 The irreducible water saturation was 29.8% and the isotonic point water saturation was 51.0%.
And (4) changing the displacement speed in the step (S7) to 0.004ml/min, and repeating the steps (S1-S9) to obtain an oil-water two-phase relative permeability curve of the core A, as shown in figure 4. FIG. 4 is a graph showing the relative permeability of the oil and water phases of core A, the displacement rate being 0.004ml/min, as can be seen from the graph, the absolute permeability of core A being 0.04X 10 -3 μm 2 The irreducible water saturation was 27.7% and the isotonic point water saturation was 52.5%.
Changing the core A into the core B, setting the displacement speed in the step S7 to be 0.001ml/min, and repeating the steps S1-S9 to obtain an oil-water two-phase relative permeability curve of the core B, as shown in figure 5. FIG. 5 is a graph showing the relative permeability of oil and water phases of core B, the displacement rate being 0.001ml/min, as can be seen from the graph, the absolute permeability of core B being 0.02X10 -3 μm 2 The irreducible water saturation was 40.0% and the isotonic point water saturation was 48.1%.
Changing the displacement speed in the step S7 to be 0.004ml/min, and repeating the steps S1-S9, wherein the step S2 is replaced by:
s2, loading the core B into a core holder 9; loading simulated formation water into the end of the water storage intermediate container 4 close to the seventh valve 207; loading the simulated oil into the end of the intermediate reservoir 5 adjacent to the eighth valve 208; filling displacement fluid into one end of the displacement fluid storage intermediate container 6 close to the ninth valve 209; connect all lines and close all valves;
opening a twelfth valve 212, setting confining pressure to the core B through the first hand-operated 10 pump, and closing the twelfth valve 212; the thirteenth valve 213 is opened, the vacuum pump 12 is turned on to vacuumize the core B for 20h, and the thirteenth valve 213 is closed.
An oil-water two-phase relative permeability curve of core B was obtained as shown in fig. 6. FIG. 6 is a graph showing the relative permeability of oil and water phases of core B, displacement rate of 0.004ml/min, from which it can be seen that the absolute permeability of core B is 0.02X10 -3 μm 2 The irreducible water saturation was 42.4% and the isotonic point water saturation was 52.2%.
The results of the rock physical properties are known: the wettability of the core A is weak hydrophilic, and the wettability of the core B is weak parent oil. Similar results were obtained by testing with the present method: the isoosmotic point of the oil-water relative permeability curve of the core A is between 50% and 60%, which indicates that the wettability of the core is weak and hydrophilic; the oil-water relative permeability curve isoosmotic point of the core B is between 40% and 50%, which indicates that the wettability of the core is weak parent oil. No CO during fluid saturation 2 In the saturation process, the isoosmotic point of the oil-water relative permeability curve of the core B moves to the right, and the wettability of the core is weak hydrophilic and is not in accordance with the reality. Meanwhile, the method also obtains the oil-water two-phase flow condition under different rock core wettability and displacement speed conditions, and provides powerful theoretical support for field practical application.
The experimental method solves the problem of insufficient core saturated fluid in the prior art. For the indoor simulated saturated fluid of the hypotonic rock core, the conventional rock core saturated fluid method for oil extraction in the prior art is that simulated formation water or crude oil is saturated immediately after vacuumizing, and no saturated CO exists in the middle 2 Is a process of (2). Because the pore space of the hypotonic core is very small, the vacuumizing processThe air in the core cannot be completely pumped out. Meanwhile, because the solubility of air in water is limited, saturated simulated formation water cannot enter the blind-end hole throat to replace gas. Therefore, after saturated simulated formation water, gas is stored in the fine pore throats in the rock core, so that the liquid single phase flow in the rock core is changed into a gas-liquid two-phase flow, and after the saturated crude oil is continued subsequently, the gas-liquid three-phase flow is changed into a more complex flow state of the oil-water-gas three-phase flow, and the physical properties of an oil layer of the oil-water two-phase seepage characteristic to be simulated originally are changed. Therefore, the experimental result obtained on the basis has larger errors and even mistakes. In the present invention, saturated CO is added after the vacuum is drawn 2 Because of CO 2 Can be mixed with air, and residual air in the core tiny pores and blind end pore throats is subjected to CO after the vacuum pumping is continued 2 Substituted. After pressurizing saturated simulated formation water because of CO 2 The solubility in water is good, the core has tiny pores and residual CO in the blind end pore throat 2 Will dissolve in simulated formation water at higher pressure, dissolving CO 2 The simulated formation water is driven out of the core under the displacement of the subsequent simulated formation water, so that only the simulated formation water existing in the pores of the core is ensured to be the single-phase flow of the simulated formation water. After the subsequent saturated crude oil, the oil-water two-phase flow is in the core, so that the physical properties of the oil layer are simulated more accurately, and further accurate and reliable experimental results are obtained.
The above embodiments are only for illustrating the technical solution of the present invention, and are not limiting; although the invention has been described in detail with reference to the foregoing embodiments, it will be understood by those of ordinary skill in the art that: the technical scheme described in the foregoing embodiments can be modified or some technical features thereof can be replaced by equivalents; such modifications and substitutions do not depart from the spirit of the invention.

Claims (10)

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:
(1) Measuring basic parameters of oil-water relative permeability;
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.
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 gas in the step S2 is a gas which is easily dissolved in water.
3. The method for determining the oil-water relative permeability curve of a hypotonic core under the condition of low-speed flow according to claim 2, wherein the gas is CO 2 。
4. 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.
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 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.
6. 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.
7. 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.
8. 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.
9. 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 performing water flooding at the low speed in the step S7 comprises performing water flooding at a constant low speed.
10. 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:
assume the condition: the core is a uniform porous medium; the driving force is unchanged, and is water drive; the oil-water property is kept unchanged; the oil and water do not react, and no interphase mass transfer phenomenon exists; neglecting compressibility of the core and fluid; considering the influence of capillary force;
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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw The relative permeability of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa; x is the flow distance, cm;
the expression of capillary force is formula (3):
P c ＝P o -P w (3)
wherein P is c Is capillary force, is water saturation S w 10 -1 MPa；P o And P w Oil phase and water phase pressures, respectively, 10 - 1 MPa；
In combination with formula (3), formula (1) is deformed to formula (4):
Wherein v is o The oil phase seepage speed is cm/s; k isPorous Medium permeability, μm 2 ；K ro Is the relative permeability of the oil phase; mu (mu) o Is the viscosity of oil phase, mPa.s; p (P) w Is the water phase pressure, 10 -1 MPa；P c Is capillary force, is water saturation S w 10 -1 MPa; x is the flow distance, cm;
the total seepage velocity of the fluid in the core is as follows:
v＝v o +v w (5)
wherein v is the total seepage velocity of the fluid in the core, cm/s; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s;
the oil and water flow rates can be expressed as:
wherein f o And f w The split flow of the oil phase and the water phase is respectively; v o The oil phase seepage speed is cm/s; v w Water phase seepage speed, cm/s; v is the total seepage velocity of the fluid in the core, cm/s;
the formula (7) and the formula (8) are obtained by deforming the formula (1) and the formula (2):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; k is the permeability of the porous medium, mum 2 ；K ro And K rw The relative permeability of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; p (P) o And P w Oil phase and water phase pressures, respectively, 10 -1 MPa；x is the flow distance, cm;
the simultaneous formulas (3) (6) (7) (8) give formula (9):
wherein v is the total seepage velocity of the fluid in the core, cm/s; f (f) o And f w The split flow of the oil phase and the water phase is respectively; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the x is the flow distance, cm;
the material balance relation is f o ＝1-f w Then formula (9) is modified to formula (10):
wherein f w The water phase is divided into water phase flow; t is the flow time, s; mu (mu) o Sum mu w The viscosity of the oil phase and the viscosity of the water phase are respectively mPa.s; k (K) ro And K rw The relative permeability of the oil phase and the water phase is respectively; k is the permeability of the porous medium, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity of the fluid in the core, cm/s; p (P) c Is capillary force, is water saturation S w 10 -1 MPa; x 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):
wherein v is o And v w The seepage speeds of the oil phase and the water phase are respectively cm/s; x is the flow distance, cm;is the core porosity; s is S w Is water saturation; s is S o Is oil saturation; t is the flow time, s;
in combination with formula (6), formula (12) is deformed into (13):
wherein v is the total seepage velocity of the fluid in the core, cm/s; t is the flow time, s; f (f) w The water phase is divided into water phase flow; x is the flow distance, cm; s is S w 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):
wherein x is the flow distance, cm; t is the flow time, s; s is S w Is water saturation; v is the total seepage velocity of the fluid in the core, cm/s;is the porosity of the porous medium; f (f) w The water phase is divided into water phase flow;
the relation between the differential pressure deltap at the two ends of the core and the relative permeability is deformed into a formula (15) through a formula (2):
wherein P is w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v w The water phase seepage speed is cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase;
substituting formula (6) into formula (15) to obtain formula (16):
wherein P is w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm; v is the total seepage velocity of the fluid in the core, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw 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):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa; l is the length of the core, cm; p (P) w Is the water phase pressure, 10 -1 MPa; x is the flow distance, cm;
from equation (15), equation (18) can be derived based on the constant water saturation surface thrust rate:
Wherein x is the flow distance, m; l is the length of the core and m; f (f) w ' is the derivative of shunt volume with respect to water saturation; f (f) w ' 2 The derivative of shunt volume at the end of the core with respect to water saturation can be expressed as:
wherein f w ' 2 The derivative of shunt volume at the end of the core with respect to water saturation;to accumulate injected pore volume times; a is the cross-sectional area of the core, cm 2 The method comprises the steps of carrying out a first treatment on the surface of the L is the length of the core, cm; />Is the porosity of the porous medium; q (Q) Iw (t) is the cumulative injected water amount, cm 3 ；
Substituting formulas (16) and (18) into (17) to obtain formula (20):
wherein Δp is the pressure difference between two ends of the core, 10 -1 MPa；f w ' 2 The derivative of shunt volume at the end of the core with respect to water saturation; v is the total fluid seepage velocity in the reservoir porous medium, cm/s; f (f) w The water phase is divided into water phase flow; mu (mu) w Is the viscosity of water phase, mPa.s; k is the permeability of the porous medium, mum 2 ；K rw Relative permeability of the aqueous phase; l is the length of the core, cm; f (f) w ' is the derivative of shunt volume with respect to 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:
wherein K is rw2 Relative permeability of the aqueous phase at the saturation of the end of the core; f (f) w2 The water phase shunt quantity at the tail end of the rock core;to accumulate injected pore volume times; k is the absolute permeability of the core, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the ΔP is the pressure difference between two ends of the core, 10 -1 MPa; v is the total seepage velocity, cm/s; mu (mu) w Is the viscosity of water phase, mPa.s; l is the length of the core, cm;
the combination of (21) and (11) gives the oil phase relative permeability expression (22):
wherein K is ro2 The relative permeability of the oil phase at the saturation of the tail end of the core; k (K) rw2 Relative permeability of the aqueous phase; mu (mu) o Is the viscosity of oil phase, mPa.s; mu (mu) w Is the viscosity of water phase, mPa.s; f (f) w2 The water phase shunt quantity at the tail end of the rock core; k is the absolute permeability of the core, mum 2 The method comprises the steps of carrying out a first treatment on the surface of the v is the total seepage velocity, cm/s; p (P) c Is the capillary force, 10 -1 MPa；S w Water saturation for the core; x 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:
wherein S is wa Is the average water saturation; s is S wc To irreducible water saturation; sigma Q o Cm for cumulative oil production 3 The method comprises the steps of carrying out a first treatment on the surface of the A is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
the water saturation at the end of the core can be expressed as formula (24):
wherein S is w2 Water saturation at the end of the core; s is S wa Is the average water saturation; q (Q) Iw (t) is the cumulative injected water amount, cm 3 The method comprises the steps of carrying out a first treatment on the surface of the t is the flow time, s; f (f) o2 The oil phase shunt quantity at the tail end of the core; a is the cross-sectional area of the core, cm 2 ；Is the porosity of the porous medium; l is the length of the core, cm;
core capillary force expression (25):
wherein P is c Is the capillary force, 10 -1 MPa; sigma is the interfacial tension of oil and water, mN.m -1 The method comprises the steps of carrying out a first treatment on the surface of the θ is core wetting angle, (°); r is the radius of the pore, 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:
wherein P is cwo Capillary force in water flooding, 10 -1 MPa；P cHg For capillary force at the time of mercury intake (mercury purge), 10 -1 MPa；σ wo Is the interfacial tension of oil and water, mN.m -1 ；σ Hg Is the gas-liquid interfacial tension of mercury, mN.m -1 ；θ w Wetting angle of water to core, (°); θ Hg 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.
CN202211424321.5A 2022-11-15 2022-11-15 Method for measuring oil-water relative permeability curve of low-permeability core under low-speed flow condition Pending CN116877047A (en)

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN117664804A (en) * 2024-02-01 2024-03-08 中国地质大学（北京） Relative permeability curve correction method considering end face effect and application thereof
CN117664804B (en) * 2024-02-01 2024-04-26 中国地质大学（北京） Relative permeability curve correction method considering end face effect and application thereof

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN117664804A (en) * 2024-02-01 2024-03-08 中国地质大学（北京） Relative permeability curve correction method considering end face effect and application thereof
CN117664804B (en) * 2024-02-01 2024-04-26 中国地质大学（北京） Relative permeability curve correction method considering end face effect and application thereof

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