A method for determining the location of ion-matched water flooding front in heterogeneous reservoirs

Abstract

The present invention provides a method for determining the position of the ion-matching water drive front in a heterogeneous reservoir. The method includes: obtaining the formation water drive and ion-matching water drive relative permeability curves of each layer of the target reservoir, and then determining the standardized relative permeability curves within the effective salinity range of the ion-matching water drive of each layer of the target reservoir; based on the formation water drive relative permeability curves of each layer of the target reservoir and the standardized relative permeability curves within the effective salinity range of the ion-matching water drive, determining the formation water drive and ion-matching water drive fractional flow curves of each layer of the target reservoir, and then determining the water saturation and fractional flow of the formation water drive front and the ion-matching water drive front of each layer of the target reservoir; based on the water saturation of the formation water drive front of each layer of the target reservoir and the formation water drive relative permeability curve, determining the formation water drive front position of the remaining layers at the moment of water breakthrough in the formation water drive of the layer with the highest permeability in the target reservoir, and then determining the ion-matching water drive front position of each layer of the target reservoir.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a method for determining the position of an ion-matched water drive front in a heterogeneous oil reservoir. Background Art

[0002] Marine porous carbonate reservoirs are one of the important reservoir types. Currently, marine porous carbonate reservoirs have great potential for improving oil recovery. At present, the main marine carbonate oil fields are gradually entering the stage of large-scale water injection, but efficient development faces many difficulties, mainly in the following four aspects: (1) The reservoir has serious lateral and vertical heterogeneity, with a large number of hidden interlayers and high-permeability "thief layers" developed, and the vertical utilization of the oil layer is very different; (2) The pressure drop is large and the decline is fast, resulting in early water breakthrough in production wells and prominent water channeling; (3) The pore structure is complex, and the microscopic water drive efficiency is low, only 40%-60%; (4) The formation water mineralization is high, usually at 13×10 4 -29×10 4 mg / L, the water quality is acidic and the pipe column is severely corroded.

[0003] Traditional water-flooding oilfield EOR technologies (such as polymer flooding and ternary composite flooding) face huge challenges such as poor reservoir adaptability and compatibility in industrial applications in the Middle East, and the application effects in mines vary greatly. Indoor experiments and numerical simulation studies have shown that wetting control of carbonate reservoirs, so that the rock surface changes from oil-wet or mixed-wet to water-wet, can significantly reduce the residual oil saturation and improve the efficiency of water flooding. For carbonate reservoirs, the chemical agents that can currently achieve wetting control are mainly nanofluids, alkalis, surfactants and salts. At present, research on nanofluids is still limited to indoor experiments, and the stability of nanofluids in high-temperature and high-salinity reservoirs is the main problem in field applications. Affected by factors such as precipitation and scaling, alkali has poor adaptability to high-temperature and high-mineralization reservoirs. Surfactants have been widely used in the practice of chemical flooding to enhance oil recovery in water-flooded sandstone reservoirs. They can effectively reduce the oil-water interfacial tension and change the rock surface wettability from oil-wet or mixed-wet to water-wet, thereby reducing the residual oil saturation and improving the oil recovery efficiency. However, carbonate formation water contains high concentrations of divalent ions such as Ca 2+ Mg 2+ The chemical reaction with the surfactant molecular groups causes precipitation and reservoir damage. In addition, the strong adsorption of surfactant molecules on the rock surface will also cause a single plug to be unable to migrate to the deep reservoir. The field application and indoor evaluation results are quite different. The electrolytes contained in the salt, especially SO4 2- Mg 2+ , Ca 2+The main ion of iso-Zeta potential has excellent wetting control ability. By adjusting the salinity and ion composition of the injected water, the recovery rate of marine carbonate reservoirs can be improved. Both indoor experiments and field tests have achieved remarkable results. This new oil recovery technology is called ion-matched water flooding. Compared with conventional water flooding, the indoor oil recovery efficiency of ion-matched water flooding can be increased by 30%, and the residual oil saturation can be reduced by 2%-50% in field tests. Considering the high salinity of seawater and formation water in the Middle East, it is economically feasible to use seawater desalination technology to adjust its ion composition and significantly reduce the salinity of injected water. The technical application prospects of ion-matched water flooding are very broad.

[0004] The mechanism of ion-matched water flooding to improve oil recovery is complex. In addition to wetting control, there are also multi-ion exchange, double-electron expansion, alkali-like flooding, rock dissolution, particle migration, etc. How to optimize the design and effect evaluation of oil and gas field development plans involving ion-matched water flooding, which includes a variety of complex physical and chemical phenomena, is an engineering problem that scholars at home and abroad urgently need to solve. Some scholars have proposed numerical simulation methods for ion-matched water flooding reservoirs, but the reliability of mathematical models and simulation results remains to be verified. In the process of numerical simulation of ion-matched water flooding, the more complex the physical and chemical processes involved, the longer the numerical simulation takes. The number of grids in actual marine carbonate reservoir models is often as high as millions or even tens of millions. Refined reservoir numerical simulation cannot meet the urgent needs of optimizing the design of oil and gas field development plans and evaluating the effects of ion-matched water flooding.

[0005] Indoor monitoring experiments show that when ion-matched water is injected into high-mineralization formations, the active ions (Ca 2+ Mg 2+ ) adsorption, there is a chemical hysteresis effect in the formation, that is, there are often two shock fronts in the formation, one is the formation water drive front, and the other is the ion matching water drive front. The transition area of ​​these two shock fronts mainly depends on the reservoir properties and the effective salinity range. At present, the calculation of the position of the ion matching water drive front in multi-layer heterogeneous reservoirs is highly dependent on reservoir numerical simulation. The calculation results have large errors, which brings great uncertainty to the evaluation of mine effects and optimization and regulation. The method for determining the position of the ion matching water drive front in multi-layer heterogeneous reservoirs based on reservoir engineering theory has not been reported. Summary of the invention

[0006] The object of the present invention is to provide a method capable of determining the position of the ion-matched water flooding front in a multi-layer heterogeneous reservoir.

[0007] In order to achieve the above object, the present invention provides a method for determining the position of the ion matching water flooding front in a heterogeneous reservoir, wherein the method comprises:

[0008] Obtaining formation water flooding oil-water two-phase relative permeability curves and ion-matching water flooding oil-water two-phase relative permeability curves of each layer of the target reservoir; wherein the salinity of formation water is higher than that of ion-matching water;

[0009] Based on the formation water flooding oil-water two-phase relative permeability curve and the ion-matching water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir, determine the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion-matching water flooding of each layer of the target oil reservoir;

[0010] Based on the formation water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir and the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion matching water flooding, the formation water flooding fractional flow curve and the ion matching water flooding fractional flow curve of each layer of the target reservoir are determined;

[0011] Based on the formation water drive fractional flow curve and ion matching water drive fractional flow curve of each layer of the target reservoir, the water saturation and fractional flow of the formation water drive front (i.e., the formation water drive shock wave front) and the ion matching water drive front of each layer of the target reservoir are determined;

[0012] Based on the water saturation of the formation water flooding front of each layer of the target reservoir and the relative permeability curve of oil-water phase in formation water flooding, the positions of the formation water flooding fronts of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir are determined;

[0013] Based on the formation water flooding front positions of the other layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir, the water saturation and fractional flow rate of the ion matching water flooding front, the ion matching water flooding front positions of each layer in the target reservoir are determined.

[0014] According to the method provided in the first aspect, preferably, obtaining the formation water flooding oil-water two-phase relative permeability curve and the ion matching water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir includes:

[0015] Obtain typical rock samples from each layer of the target reservoir;

[0016] For typical rock samples from each layer of the target reservoir, non-steady-state unidirectional flow core flooding experiments of formation water and non-steady-state unidirectional flow core flooding experiments of ion-matched water were carried out to obtain dynamic data of pressure, flow rate and water content during the unidirectional flow core flooding experiments;

[0017] Based on the obtained dynamic data of pressure, flow rate and water content during the unidirectional flow core flooding experiment, the formation water flooding oil-water two-phase relative permeability curve and the ion-matched water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir are determined.

[0018] According to the method provided in the first aspect, preferably, the determination of the standardized oil-water two-phase relative permeability curve within the effective salinity range of ion matching water flooding of each layer of the target reservoir is achieved by introducing a linear weight function;

[0019] More preferably, the step of determining the normalized oil-water two-phase relative permeability curve within the effective salinity range of ion-matched water flooding at each layer of the target reservoir comprises:

[0020] For each layer of the target reservoir, the following formula is used to determine the standardized oil-water two-phase relative permeability within the effective salinity range of ion matching water flooding in the layer:

[0021]

[0022] when hour

[0023] When θ=1 hour

[0024] When θ=0 hour

[0025] In the formula, is the lower limit of the effective salinity range; is the upper limit of the effective salinity range; k ro (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matching water flooding effective salinity range normalized oil phase relative permeability; k rw (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matches the normalized water phase relative permeability within the effective salinity range of water flooding; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the water phase in the formation water drive; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the formation water-driven oil phase; is the water saturation S of the layer to be analyzed * The corresponding ion matches the relative permeability of the water phase in water flooding; is the water saturation S of the layer to be analyzed * The corresponding ion matching water flooding oil phase relative permeability; θ is the weight coefficient; S * is the normalized water saturation; S w is water saturation; S wc is the irreducible water saturation of the layer to be analyzed; S or is the residual oil saturation of the stratum to be analyzed.

[0026] According to the method provided in the first aspect, preferably, the upper limit of the effective salinity range does not exceed 10000 mg / L, and the lower limit is not less than 1000 mg / L; more preferably, the upper limit of the effective salinity range is 10000 mg / L, and the lower limit is 1000 mg / L.

[0027] According to the method provided in the first aspect, preferably, the water saturation and fractional flow of the formation water drive front and the ion matching water drive front of each layer of the target oil reservoir are determined based on the formation water drive fractional flow curve and the ion matching water drive fractional flow curve of each layer of the target oil reservoir by a fractional flow plate interpretation method;

[0028] More preferably, the determining the water saturation and fractional flow of the formation water flooding front and the ion matching water flooding front of each layer of the target oil reservoir based on the formation water flooding fractional flow curve and the ion matching water flooding fractional flow curve of each layer of the target oil reservoir comprises:

[0029] For each layer of the target reservoir, on the flow relationship chart of the formation water drive flow curve and the ion matching water drive flow curve containing the layer (the chart with water saturation and flow rate as the horizontal and vertical coordinates, respectively), a tangent line is drawn to the ion matching water drive flow curve through the origin (i.e., the point where both the horizontal and vertical coordinates are 0). The water saturation and flow rate corresponding to the tangent point are the water saturation and flow rate of the ion matching water drive front of the layer, and the water saturation and flow rate corresponding to the intersection of the tangent line and the formation water drive flow curve are the water saturation and flow rate of the formation water drive front of the layer.

[0030] According to the method provided in the first aspect, preferably, the determining the positions of the formation water flooding fronts of the remaining layers at the time of water breakthrough in the formation water flooding of the layer with the highest permeability in the target oil reservoir based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve comprises:

[0031] Based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve, determine the total mobility ratio of the formation water flooding front during the non-piston flooding process of each layer of the target oil reservoir;

[0032] Based on the total mobility ratio of the formation water flooding front during the non-piston displacement process of each layer in the target reservoir, the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir is determined;

[0033] More preferably, the determining of the total mobility ratio of the formation water flooding front during the non-piston displacement process of each stratum of the target oil reservoir based on the water saturation of the formation water flooding front of each stratum of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve comprises:

[0034] For each layer of the target reservoir, the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer is determined by the following formula:

[0035]

[0036] in, Specifically:

[0037]

[0038] In the formula, M F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the analyzed layer; is the water saturation of the formation water flooding front during the water flooding process of the formation to be analyzed The total fluid flow rate under t (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc Total fluid flow rate under is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the water phase in the formation water drive; k rw (S wc ) is the irreducible water saturation S of the formation to be analyzed wc The corresponding relative permeability of the water phase in the formation water drive; is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the formation water-driven oil phase; k ro (S wc ) is the irreducible water saturation S of the layer to be analyzed wc The corresponding relative permeability of the formation water-driven oil phase; μ w is the viscosity of the water phase; μ o is the oil phase viscosity; t (S w ) is the arbitrary water saturation S during the water flooding process of the layer to be analyzed w The total fluid flow rate under k rw (S w ) is the arbitrary water saturation S of the layer to be analyzed w The corresponding relative permeability of the water phase in the formation water drive; k ro (S w ) is the arbitrary water saturation S of the layer to be analyzed w The corresponding relative permeability of the formation water-driven oil phase;

[0039] More preferably, the determining of the positions of the formation water flooding fronts of the remaining layers at the moment of water breakthrough in the formation water flooding of the highest permeability layer in the target oil reservoir based on the total mobility ratio of the formation water flooding front in the non-piston displacement process of each layer in the target oil reservoir comprises:

[0040] For each layer of the target reservoir, the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer is determined by the following formula:

[0041]

[0042] in,

[0043] In the formula, M is the water breakthrough moment of the highest permeability layer and the position of the formation water flooding front of the layer to be analyzed; F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer to be analyzed; φ is the formation porosity of the layer to be analyzed; k is the permeability of the layer to be analyzed; Δs w is the difference between the water saturation at the water flooding front and the irreducible water saturation of the formation to be analyzed, that is, in is the water saturation of the water flooding front in the layer to be analyzed, S wc is the irreducible water saturation of the layer to be analyzed; is the total mobility ratio of the formation water flooding front during non-piston displacement in the highest permeability layer; φ h k is the porosity of the highest permeability layer; h is the permeability of the highest permeability layer; is the difference between the water saturation at the water flooding front of the highest permeability layer and the irreducible water saturation, that is, in is the water saturation at the water flooding front of the highest permeability layer is the irreducible water saturation of the highest permeability layer.

[0044] According to the method provided in the first aspect, preferably, determining the ion matching water flooding front position of each layer of the target reservoir based on the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir, the water saturation and the fractional flow of the ion matching water flooding front, comprises:

[0045] Based on the Buckley-Leverett equation, the ion-matched waterflood front motion model considering the chemical hysteresis effect is determined;

[0046] Based on the ion-matching water flooding front movement model considering the chemical hysteresis effect, the dimensionless distance of the ion-matching water flooding relative to the formation water flooding front is introduced. The positions of the formation water flooding fronts of the target reservoir at each layer are determined by using the water saturation and fractional flow of the ion-matching water flooding front at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir.

[0047] More preferably, the determined ion matching water flooding front motion model considering the chemical hysteresis effect is:

[0048]

[0049] Where φ is the formation porosity, a decimal; v t is the injection speed of ion matching water, m 3 / d; D is the dimensionless hysteresis effect coefficient; To match the water saturation of the water flooding front for ions; To match the split flow rate of the water flooding front for ions; Match the instantaneous rate of the water drive front for ions;

[0050] More preferably, the front advancement speeds of the formation water flooding and the ion matching water flooding are related and satisfy the following functional relationship:

[0051]

[0052] In the formula, v C v is the advancing speed of the formation water flooding front; F Match the water drive front propulsion velocity to the ions.

[0053] According to the method provided in the first aspect, preferably, the ion matching water drive front position is determined by the following formula:

[0054]

[0055] In the formula, The water breakthrough moment of the formation water flooding in the highest permeability layer is the position of the water flooding front edge of the layer to be analyzed; v is the position of the formation water flooding front edge of the layer to be analyzed at the time of water breakthrough in the formation water flooding of the layer with the highest permeability; C v is the advancing speed of the formation water flooding front; F S is the ion matching water drive front advancing speed; wc is the irreducible water saturation of the layer to be analyzed; is the water saturation of the water flooding front of the formation to be analyzed; The flow rate of water flooding front in the formation to be analyzed; Match the fractional flow rate of the water flooding front to the formation ions to be analyzed; is the water saturation of the water flooding front of the ion matching layer to be analyzed; D is the hysteresis effect coefficient.

[0056] The technical solution provided by the present invention is easy to implement and has high accuracy, and can provide a basis for optimizing the design of ion-matched water flooding schemes, analyzing development dynamic laws, and optimizing production control in marine carbonate reservoirs. The technical solution provided by the present invention realizes the determination of the front position of ion-matched water flooding in multi-layer heterogeneous reservoirs, and solves the technical problem that numerical simulation of ion-matched water flooding reservoirs is difficult and difficult to meet the urgent needs of dynamic control on the spot of oil fields. BRIEF DESCRIPTION OF THE DRAWINGS

[0057] Figure 1 A flow chart of a method for determining the position of an ion-matched water flooding front in a heterogeneous reservoir provided by an embodiment of the present invention.

[0058] Figure 2 Schematic diagram of the model of the heterogeneous oil reservoir including two layers in Example 1.

[0059] Figure 3A This is a graph showing the relative permeability of oil-water phases in high permeability formation water flooding and ion matching water flooding in Example 1 of the present invention.

[0060] Figure 3B This is a graph showing the relative permeability of oil-water phases in low permeability formation water drive and ion matching water drive in Example 1 of the present invention.

[0061] Figure 4A It is a graph of the water flooding fractional flow rate curve of the high permeability layer formation and the ion matching water flooding fractional flow rate curve in Example 1 of the present invention.

[0062] Figure 4B It is a graph of the water flooding fractional flow rate curve of the low permeability layer formation and the ion matching water flooding fractional flow rate curve in Example 1 of the present invention.

[0063] Figure 5 This is a position diagram of the water flooding front of each layer of the heterogeneous oil reservoir formation and the ion matching water flooding front in Example 1 of the present invention.

[0064] Figure 6 This is a schematic diagram of a model of a heterogeneous oil reservoir comprising five layers according to Example 2 of the present invention.

[0065] Figure 7 This is a position diagram of the water flooding front of each layer of the heterogeneous oil reservoir formation and the ion matching water flooding front in Example 2 of the present invention. DETAILED DESCRIPTION

[0066] In order to make the purpose, technical solution and advantages of the embodiment of the present invention clearer, the technical solution in the embodiment of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiment of the present invention. Obviously, the described embodiment is a part of the embodiment of the present invention, not all of the embodiments. Based on the embodiment of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work belong to the protection scope of the present invention.

[0067] See also Figure 1 A specific embodiment of the present invention provides a method for determining the position of the ion-matched water flooding front in a heterogeneous reservoir, wherein the method comprises:

[0068] Step S1: obtaining a formation water flooding oil-water two-phase relative permeability curve and an ion-matching water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir; wherein the salinity of the formation water is higher than the salinity of the ion-matching water;

[0069] Step S2: determining a standardized oil-water two-phase relative permeability curve within an effective salinity range of ion-matching water drive at each layer of the target oil reservoir based on the formation water drive oil-water two-phase relative permeability curve and the ion-matching water drive oil-water two-phase relative permeability curve at each layer of the target oil reservoir;

[0070] Step S3: determining the formation water flooding fractional flow curve and the ion matching water flooding fractional flow curve of each layer of the target oil reservoir based on the formation water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir and the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion matching water flooding;

[0071] Step S4: determining the water saturation and fractional flow of the formation water drive front (i.e., the formation water drive shock wave front) and the ion matching water drive front of each layer of the target oil reservoir based on the formation water drive fractional flow curve and the ion matching water drive fractional flow curve of each layer of the target oil reservoir;

[0072] Step S5: based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve, determine the formation water flooding front position of the remaining layers in the target oil reservoir at the time of water breakthrough in the formation water flooding of the highest permeability layer;

[0073] Step S6: Determine the ion matching water flooding front position of each layer in the target reservoir based on the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir, the water saturation and fractional flow of the ion matching water flooding front, and the ion matching water flooding front position.

[0074] Further, in step S1, obtaining the formation water flooding oil-water two-phase relative permeability curve and the ion matching water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir includes:

[0075] Step S11: obtaining typical rock samples of each layer of the target reservoir;

[0076] Among them, typical rock samples are preferably deoiled and dried before displacement experiments, and rock physical parameters such as porosity and permeability are determined by gas adsorption test experiments;

[0077] Step S12: for typical rock samples of each layer of the target reservoir, conduct formation water non-steady-state unidirectional flow core displacement experiment and ion-matched water non-steady-state unidirectional flow core displacement experiment respectively, and obtain dynamic data of pressure, flow rate and water content during the unidirectional flow core displacement experiment;

[0078] Among them, during the process of conducting the core displacement experiment of formation water non-steady unidirectional flow and the core displacement experiment of ion-matched water non-steady unidirectional flow, the indoor experimental conditions such as fluid viscosity, temperature, and displacement speed should be kept consistent as much as possible; the core displacement experiment of formation water non-steady unidirectional flow and the core displacement experiment of ion-matched water non-steady unidirectional flow can be carried out according to the non-steady unidirectional flow core displacement experiment method commonly used in determining the phase permeability curve in this field;

[0079] Step S13: Based on the obtained dynamic data of pressure, flow rate and water content during the unidirectional flow core displacement experiment, the formation water flooding oil-water two-phase relative permeability curve and the ion matching water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir are determined;

[0080] Among them, the Johnson-Bossler-Naumann (JBN) method can be used to invert and interpret the pressure and flow dynamic data of the single-phase flow core experiment to determine the formation water drive oil-water two-phase relative permeability curve and the ion-matched water drive oil-water two-phase relative permeability curve of each layer of the target reservoir.

[0081] Among them, the formation water flooding oil-water two-phase relative permeability curve and the ion matching water flooding oil-water two-phase relative permeability curve of the same layer usually show the following characteristics:

[0082] Compared with the oil-water relative permeability curve of high-salinity formation water drive, the oil phase relative permeability of low-salinity ion-matched water drive at the same water saturation is higher, the water phase relative permeability is lower, and the oil-water isopyknosis point shifts to the right, that is, the water-wetting degree increases and the residual oil saturation decreases.

[0083] Among them, determining the normalized oil-water two-phase relative permeability curve within the effective salinity range of ion-matched water flooding can better reflect the effect of wettability change on the oil flooding effect of ion-matched water;

[0084] Further, in step S2, the determination of the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion matching water flooding of each layer of the target reservoir is achieved by introducing a linear weight function;

[0085] Furthermore, in step S2, determining the standardized oil-water two-phase relative permeability curve within the effective salinity range of ion matching water flooding of each layer of the target reservoir includes:

[0086] For each layer of the target reservoir, the following formula is used to determine the standardized oil-water two-phase relative permeability within the effective salinity range of ion matching water flooding in the layer:

[0087]

[0088] when hour

[0089] When θ=1 hour

[0090] When θ=0 hour

[0091] In the formula, is the lower limit of the effective salinity range; is the upper limit of the effective salinity range; k ro (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matching water flooding effective salinity range normalized oil phase relative permeability; k rw (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matches the normalized water phase relative permeability within the effective salinity range of water flooding; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the water phase in the formation water drive; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the formation water-driven oil phase; is the water saturation S of the layer to be analyzed * The corresponding ion matches the relative permeability of the water phase in water flooding; is the water saturation S of the layer to be analyzed * The corresponding ion matching water flooding oil phase relative permeability; θ is the weight coefficient; S * is the normalized water saturation; S w is water saturation; S wc is the irreducible water saturation of the layer to be analyzed; S or is the residual oil saturation of the stratum to be analyzed.

[0092] Furthermore, the upper limit of the effective salinity range is not more than 10000 mg / L, and the lower limit is not less than 1000 mg / L; further, the upper limit of the effective salinity range is 10000 mg / L, and the lower limit is 1000 mg / L.

[0093] Wherein, in step S3, the formation water drive fractional flow curve and the ion matching water drive fractional flow curve of each layer of the target reservoir are determined in a conventional manner;

[0094] For example, ignoring the effects of gravity and capillary force, the split flow rate can be determined using the following formula:

[0095]

[0096] In the formula, f w (S w ) is the water saturation S w The corresponding split flow; k ro (S w ) is the water saturation S w Corresponding oil phase relative permeability; k rw (S w ) is the water saturation S w Corresponding water phase relative permeability; μ w is the viscosity of the water phase; μ o is the oil phase viscosity; Q w is the water production per unit time; Q o is the oil production per unit time.

[0097] Further, in step S4, the formation water drive fractional flow curve and the ion matching water drive fractional flow curve of each layer of the target oil reservoir are used to determine the water saturation and fractional flow of the formation water drive front and the ion matching water drive front of each layer of the target oil reservoir by using the fractional flow plate interpretation method;

[0098] Furthermore, in step S4, determining the water saturation and fractional flow rate of the formation water flooding front of each stratum of the target oil reservoir based on the formation water flooding fractional flow rate curve and the ion matching water flooding fractional flow rate curve of each stratum of the target oil reservoir includes:

[0099] For each layer of the target reservoir, on the flow relationship chart of the formation water drive flow curve and the ion matching water drive flow curve containing the layer (the chart with water saturation and flow rate as the horizontal and vertical coordinates, respectively), a tangent line is drawn to the ion matching water drive flow curve through the origin (i.e., the point where both the horizontal and vertical coordinates are 0). The water saturation and flow rate corresponding to the tangent point are the water saturation and flow rate of the ion matching water drive front of the layer, and the water saturation and flow rate corresponding to the intersection of the tangent line and the formation water drive flow curve are the water saturation and flow rate of the formation water drive front of the layer.

[0100] Further, in step S5, the formation water flooding front positions of the remaining layers in the target oil reservoir at the time of water breakthrough in the formation water flooding of the layer with the highest permeability in the target oil reservoir are determined based on the water saturation of the formation water flooding front of each layer in the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve, including:

[0101] Step S51: determining the total mobility ratio of the formation water flooding front in the non-piston flooding process of each layer of the target oil reservoir based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve;

[0102] Step S52: based on the total mobility ratio of the formation water flooding front in each layer of the target oil reservoir during the non-piston displacement process, determine the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target oil reservoir;

[0103] Furthermore, in step S51, the total mobility ratio of the formation water flooding front in each layer of the target oil reservoir during the non-piston displacement process is determined based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve, including:

[0104] For each layer of the target reservoir, the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer is determined by the following formula:

[0105]

[0106] in, Specifically:

[0107]

[0108] In the formula, M F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the analyzed layer; is the water saturation of the formation water flooding front during the water flooding process of the formation to be analyzed The total fluid flow rate under t (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc Total fluid flow rate under is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the water phase in the formation water drive; k rw (S wc ) is the irreducible water saturation S of the formation to be analyzed wc The corresponding relative permeability of the water phase in the formation water drive; is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the formation water-driven oil phase; k ro (S wc ) is the irreducible water saturation S of the layer to be analyzed wc The corresponding relative permeability of the formation water-driven oil phase; μ w is the viscosity of the water phase; μ o is the oil phase viscosity; t (S w ) is the arbitrary water saturation S during the water flooding process of the layer to be analyzed w The total fluid flow rate under k rw (S w ) is the arbitrary water saturation S of the layer to be analyzed w The corresponding relative permeability of the water phase in the formation water drive; k ro (S w ) is the arbitrary water saturation S of the layer to be analyzed w The corresponding relative permeability of the formation water-driven oil phase;

[0109] Furthermore, in step S52, the determination of the positions of the formation water flooding fronts of the target reservoir at the moment of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir based on the total mobility ratio of the formation water flooding front in the non-piston flooding process of each layer in the target reservoir comprises:

[0110] For each layer of the target reservoir, the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer is determined by the following formula:

[0111]

[0112] in,

[0113] In the formula, M is the water breakthrough moment of the highest permeability layer and the position of the formation water flooding front of the layer to be analyzed; F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer to be analyzed; φ is the formation porosity of the layer to be analyzed; k is the permeability of the layer to be analyzed; Δs w is the difference between the water saturation at the water flooding front and the irreducible water saturation of the formation to be analyzed, that is, in is the water saturation of the water flooding front in the layer to be analyzed, S wc is the irreducible water saturation of the layer to be analyzed; is the total mobility ratio of the formation water flooding front during non-piston displacement in the highest permeability layer; φ h k is the porosity of the highest permeability layer; h is the permeability of the highest permeability layer; is the difference between the water saturation at the water flooding front of the highest permeability layer and the irreducible water saturation, that is, in is the water saturation at the water flooding front of the highest permeability layer is the irreducible water saturation of the highest permeability layer.

[0114] Further, in step S6, the determination of the ion matching water flooding front position of each layer of the target reservoir based on the formation water flooding front position of the other layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir, the water saturation and the fractional flow of the ion matching water flooding front position includes:

[0115] Step S61: Based on the Buckley-Leverett equation, determine an ion matching water flooding front motion model that takes into account the chemical hysteresis effect;

[0116] Step S62: Based on the ion matching water flooding front movement model considering the chemical hysteresis effect, the dimensionless distance of the ion matching water flooding relative to the formation water flooding front is introduced, and the formation water flooding front positions of the remaining layers at the time of water breakthrough of the formation water flooding of the highest permeability layer in the target reservoir, the water saturation of the ion matching water flooding front and the fractional flow rate are used to determine the ion matching water flooding front positions of each layer in the target reservoir;

[0117] In this preferred technical solution, the classical Buckley-Leverett equation is improved by considering the diffusion of ion-matched water solutes, chemical hysteresis and wetting change mechanism, and the position of the ion-matched water flooding front is determined by a semi-analytical method;

[0118] Furthermore, in step S61, the ion matching water flooding front motion model considering the chemical hysteresis effect is determined as:

[0119]

[0120] Where φ is the formation porosity; v t is the injection speed of ion matching water; D is the hysteresis effect coefficient; To match the water saturation of the water flooding front for ions; To match the split flow rate of the water flooding front for ions; Match the instantaneous rate of the water drive front for ions;

[0121] Furthermore, in step S62, the front advancement speeds of the formation water drive and the ion matching water drive are related and satisfy the following functional relationship:

[0122]

[0123] In the formula, v C v is the advancing speed of the formation water flooding front; FMatch the water drive front propulsion velocity to the ions.

[0124] Furthermore, the ion matching water flooding front position is determined by the following formula:

[0125]

[0126] In the formula, The water breakthrough moment of the formation water flooding in the highest permeability layer is the position of the water flooding front edge of the layer to be analyzed; v is the position of the formation water flooding front edge of the layer to be analyzed at the time of water breakthrough in the formation water flooding of the layer with the highest permeability; C v is the advancing speed of the formation water flooding front; F S is the ion matching water drive front advancing speed; wc is the irreducible water saturation of the layer to be analyzed; is the water saturation of the water flooding front of the formation to be analyzed; The flow rate of water flooding front in the formation to be analyzed; Match the fractional flow rate of the water flooding front to the formation ions to be analyzed; is the water saturation of the water flooding front of the ion matching layer to be analyzed; D is the hysteresis effect coefficient.

[0127] Based on the position of the ion-matched water flooding front in each layer of the target reservoir, the effectiveness of ion-matched water flooding in each layer of a multi-layer heterogeneous reservoir can be evaluated.

[0128] Example 1

[0129] Taking a certain reservoir of a certain heterogeneous oil reservoir in a certain area as the target reservoir, the method for determining the position of the ion matching water flooding front of the heterogeneous oil reservoir according to the present invention is described;

[0130] The target reservoir is a heterogeneous reservoir consisting of two layers, such as Figure 2 As shown in Figure 2, the length, width and height of each layer in the target reservoir are 1066.8 m, 548.6 m and 45.7 m respectively, and the average permeability of the high permeability layer is 200×10 -3 μm 2 The average permeability of the low permeability layer is 100×10 -3 μm 2 The porosity is 0.2, the viscosity of the oil phase and water phase fluids is 1.0cP, the formation water salinity is 200000mg / L, the ion matching water salinity is 1000mg / L, and the effective salinity range is 1000-7000mg / L.

[0131] The method for determining the location of the target reservoir ion matching water flooding front includes:

[0132] 1. Obtain the formation water flooding oil-water two-phase relative permeability curve and ion matching water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir;

[0133] Specifically: obtain typical rock samples from each layer of the target reservoir, de-oil and dry the typical rock samples, and use gas adsorption test experiments to determine rock physical parameters such as porosity and permeability; on the premise of ensuring that the indoor experimental conditions such as fluid viscosity, temperature, and displacement rate are consistent, conduct formation water non-steady-state unidirectional flow core displacement experiments and ion-matched water non-steady-state unidirectional flow core displacement experiments on typical rock samples from each layer of the target reservoir, and obtain the pressure, flow rate, and water content dynamic data during the unidirectional flow core displacement experiment; use the Johnson-Bossler-Naumann (JBN) method to invert and interpret the pressure and flow rate dynamic data of the single-phase flow core experiment to determine the formation water drive oil-water two-phase relative permeability curve and ion-matched water drive oil-water two-phase relative permeability curve of each layer of the target reservoir;

[0134] For high permeability layers, the oil-water two-phase relative permeability curves of formation water drive and ion matching water drive are as follows: Figure 3A As shown; for low permeability layers, the oil-water two-phase relative permeability curves of formation water drive and ion matching water drive are as follows Figure 3B shown.

[0135] 2. Based on the formation water flooding oil-water two-phase relative permeability curves and ion-matching water flooding oil-water two-phase relative permeability curves of each layer of the target reservoir, determine the standardized oil-water two-phase relative permeability curves within the effective salinity range of ion-matching water flooding of each layer of the target reservoir;

[0136] Specifically, for each layer of the target reservoir, the following formula is used to determine the standardized oil-water two-phase relative permeability within the effective salinity range of ion matching water flooding in the layer:

[0137]

[0138] when hour

[0139] When θ=1 hour

[0140] When θ=0 hour

[0141] In the formula, is the lower limit of the effective salinity range; is the upper limit of the effective salinity range; k ro (S w ) is the water saturation S of the layer to be analyzed wThe corresponding ion matching water flooding effective salinity range normalized oil phase relative permeability; k rw (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matches the normalized water phase relative permeability within the effective salinity range of water flooding; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the water phase in the formation water drive; is the water saturation S of the layer to be analyzed * The corresponding relative permeability of the formation water-driven oil phase; is the water saturation S of the layer to be analyzed * The corresponding ion matches the relative permeability of the water phase in water flooding; is the water saturation S of the layer to be analyzed * The corresponding ion matching water flooding oil phase relative permeability; θ is the weight coefficient; S * is the normalized water saturation; S w is water saturation; S wc is the irreducible water saturation of the layer to be analyzed; S or is the residual oil saturation of the layer to be analyzed.

[0142] 3. Based on the formation water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir and the standardized oil-water two-phase relative permeability curve within the effective salinity range of ion-matching water flooding, determine the formation water flooding fractional flow curve and ion-matching water flooding fractional flow curve of each layer of the target reservoir;

[0143] Specifically: Ignore the influence of gravity and capillary force and determine the split flow rate using the following formula:

[0144]

[0145] In the formula, f w (S w ) is the water saturation S w The corresponding split flow; k ro (S w ) is the water saturation S w Corresponding oil phase relative permeability; k rw (S w ) is the water saturation S w Corresponding water phase relative permeability; μ w is the viscosity of the water phase; μ o is the oil phase viscosity; Q w is the water production per unit time; Q o is the oil production per unit time.

[0146] For high permeability layers, the formation water drive fractional flow curve and the ion matching water drive fractional flow curve are as follows: Figure 4A As shown; for low permeability layers, the formation water drive flow rate curve and the ion matching water drive flow rate curve are as follows Figure 4B As shown;

[0147] like Figure 4A and Figure 4B As shown, compared with water flooding in high-salinity formations, the water-free oil recovery period of the ion-matched water flooding process is longer and the residual oil saturation is greatly reduced.

[0148] 4. Determine the water saturation and fractional flow of the formation water drive front (i.e., the formation water drive shock wave front) and the ion matching water drive front in each layer of the target reservoir;

[0149] Specifically, for each layer of the target reservoir, on the flow relationship chart of the formation water drive flow curve and the ion matching water drive flow curve containing the layer (the chart with water saturation and flow rate as the horizontal and vertical coordinates, respectively), a tangent line is drawn to the ion matching water drive flow curve through the origin (i.e., the point where both the horizontal and vertical coordinates are 0), and the tangent point is The water saturation and fractional flow rate corresponding to the tangent point are the water saturation and fractional flow rate of the ion-matched water flooding front in the layer; the intersection of the tangent line and the formation water flooding fractional flow rate curve is The corresponding water saturation and fractional flow are the water saturation and fractional flow at the formation water flooding front of the layer.

[0150] 5. Determine the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir;

[0151] Specifically, based on the water saturation of the formation water flooding front of each layer of the target reservoir and the formation water flooding oil-water two-phase relative permeability curve, the total mobility ratio of the formation water flooding front during the non-piston flooding process of each layer is determined by the following formula for each layer of the target reservoir:

[0152]

[0153] in,

[0154] Where M F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the analyzed layer; is the water saturation of the formation water flooding front during the water flooding process of the formation to be analyzed The total fluid flow rate under t (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc Total fluid flow rate under is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the water phase in the formation water drive; k rw (S wc ) is the irreducible water saturation S of the formation to be analyzed wc The corresponding relative permeability of the water phase in the formation water drive; is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the formation water-driven oil phase; k ro (S wc ) is the irreducible water saturation S of the layer to be analyzed wc The corresponding relative permeability of the formation water-driven oil phase; μ w is the viscosity of the water phase; μ o is the viscosity of the oil phase;

[0155] Based on the total mobility ratio of the formation water flooding front during the non-piston displacement process of each layer of the target reservoir, the formation water flooding front positions of the remaining layers at the moment of water breakthrough in the formation water flooding of the layer with the highest permeability are determined by the following formula for each layer of the target reservoir:

[0156]

[0157] in,

[0158] In the formula, M is the water breakthrough moment of the highest permeability layer and the position of the formation water flooding front of the layer to be analyzed; F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer to be analyzed; φ is the formation porosity of the layer to be analyzed; k is the permeability of the layer to be analyzed; Δs w is the difference between the water saturation at the water flooding front and the irreducible water saturation of the formation to be analyzed, that is, in is the water saturation of the water flooding front in the layer to be analyzed, S wc is the irreducible water saturation of the layer to be analyzed; is the total mobility ratio of the formation water flooding front during non-piston displacement in the highest permeability layer; φ h k is the porosity of the highest permeability layer; h is the permeability of the highest permeability layer; is the difference between the water saturation at the water flooding front of the highest permeability layer and the irreducible water saturation, that is, in is the water saturation at the water flooding front of the highest permeability layer is the irreducible water saturation of the highest permeability layer.

[0159] 6. Determine the ion-matching water flooding front position of the highest permeability layer in the target reservoir at the time of water breakthrough in the ion-matching water flooding of the remaining layers;

[0160] Specifically: Based on the Buckley-Leverett equation, the ion-matched water flooding front motion model considering the chemical hysteresis effect is determined as follows:

[0161]

[0162] Where φ is the formation porosity; v t is the injection speed of ion matching water; D is the hysteresis effect coefficient; To match the water saturation of the water flooding front for ions; To match the split flow rate of the water flooding front for ions; Match the instantaneous rate of the water drive front for ions;

[0163] Based on the ion-matched water drive front movement model considering the chemical hysteresis effect, the dimensionless distance of the ion-matched water drive relative to the formation water drive front is introduced to determine the position of the ion-matched water drive front in each layer of the target reservoir; among them, the front advancement speeds of the formation water drive and the ion-matched water drive are related and satisfy the following functional relationship:

[0164]

[0165] In the formula, v C v is the advancing speed of the formation water flooding front; F Match the water drive front propulsion velocity for ions;

[0166] The ion matching water flooding front position is determined by the following formula:

[0167]

[0168] In the formula, The water breakthrough moment of the formation water flooding in the highest permeability layer is the position of the water flooding front edge of the layer to be analyzed; v is the position of the formation water flooding front edge of the layer to be analyzed at the time of water breakthrough in the formation water flooding of the layer with the highest permeability; C v is the advancing speed of the formation water flooding front; F S is the ion matching water drive front advancing speed; wc is the irreducible water saturation of the layer to be analyzed; is the water saturation of the water flooding front of the formation to be analyzed; The flow rate of water flooding front in the formation to be analyzed; Match the fractional flow rate of the water flooding front to the ions in the layer to be analyzed; is the water saturation of the water flooding front of the formation ion matching in the layer to be analyzed; D is the dimensionless hysteresis effect coefficient;

[0169] The results are as follows Figure 5 As shown, where xd It represents the position of the normalized water drive front. The place where the saturation jumps represents the water drive front position. There are two water drive front positions in each small layer. The right one represents the formation water drive front position, and the left one represents the ion matching water drive front position. The area between the two represents the effective salinity range. Sw represents the average water saturation at a certain position in the formation. The saturation at the jump position corresponds to the water saturation at the water drive front.

[0170] In order to verify the accuracy of the results, conventional reservoir numerical simulation is used to determine the positions of the formation water flooding front and the ion matching water flooding front.

[0171] Example 2

[0172] Taking a certain reservoir of a certain heterogeneous oil reservoir in a certain area as the target reservoir, the method for determining the position of the ion matching water flooding front of the heterogeneous oil reservoir according to the present invention is described;

[0173] The target reservoir is a heterogeneous reservoir consisting of five layers, such as Figure 6 As shown, the length, width and height of each small layer of the target reservoir are 3502ft, 3502ft and 30ft respectively, the average permeability of each layer is 200md, 50md, 100md, 150md and 75md respectively, the porosity is 0.2, the viscosity of oil phase and water phase fluid is 1.0cP, the formation water mineralization is 200000mg / L, the ion matching water mineralization is 1000mg / L, and the effective salinity range is 1000-7000mg / L.

[0174] The specific method is the same as that in Example 1. The final determined ion matching water drive front position is as follows: Figure 7 shown.

[0175] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principle of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for determining the location of the ion-matched water flooding front in a heterogeneous reservoir, wherein: The method includes: Obtaining formation water flooding oil-water two-phase relative permeability curves and ion-matching water flooding oil-water two-phase relative permeability curves of each layer of the target reservoir; wherein the salinity of formation water is higher than that of ion-matching water; Based on the formation water flooding oil-water two-phase relative permeability curve and the ion-matching water flooding oil-water two-phase relative permeability curve of each layer of the target oil reservoir, determine the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion-matching water flooding of each layer of the target oil reservoir; Based on the formation water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir and the standardized oil-water two-phase relative permeability curve within the effective salinity range of the ion matching water flooding, the formation water flooding fractional flow curve and the ion matching water flooding fractional flow curve of each layer of the target reservoir are determined; Based on the formation water drive fractional flow curve and ion matching water drive fractional flow curve of each layer of the target oil reservoir, determine the water saturation and fractional flow of the formation water drive front and ion matching water drive front of each layer of the target oil reservoir; Based on the water saturation of the formation water flooding front of each layer of the target reservoir and the relative permeability curve of oil-water phase in formation water flooding, the positions of the formation water flooding fronts of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir are determined; Based on the formation water flooding front positions of the other layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir, the water saturation and fractional flow rate of the ion matching water flooding front, the ion matching water flooding front positions of each layer in the target reservoir are determined.

2. The method according to claim 1, wherein: Obtaining the formation water flooding oil-water two-phase relative permeability curve and ion matching water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir includes: Obtain typical rock samples from each layer of the target reservoir; For typical rock samples from each layer of the target reservoir, non-steady-state unidirectional flow core flooding experiments of formation water and non-steady-state unidirectional flow core flooding experiments of ion-matched water were carried out to obtain dynamic data of pressure, flow rate and water content during the unidirectional flow core flooding experiments; Based on the obtained dynamic data of pressure, flow rate and water content during the unidirectional flow core flooding experiment, the formation water flooding oil-water two-phase relative permeability curve and the ion-matched water flooding oil-water two-phase relative permeability curve of each layer of the target reservoir are determined.

3. The method according to claim 1, wherein: The determination of the standardized oil-water two-phase relative permeability curve within the effective salinity range of ion matching water flooding at each layer of the target reservoir includes: For each layer of the target reservoir, the following formula is used to determine the standardized oil-water two-phase relative permeability within the effective salinity range of ion matching water flooding in the layer: when hour When θ=1 hour When θ=0 hour In the formula, is the lower limit of the effective salinity range; is the upper limit of the effective salinity range; k ro (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matching water flooding effective salinity range normalized oil phase relative permeability; k rw (S w ) is the water saturation S of the layer to be analyzed w The corresponding ion matches the normalized water phase relative permeability within the effective salinity range of water flooding; is the normalized water saturation S of the horizon to be analyzed * The corresponding relative permeability of the water phase in the formation water drive; is the normalized water saturation S of the horizon to be analyzed * The corresponding relative permeability of the formation water-driven oil phase; is the normalized water saturation S of the horizon to be analyzed * The corresponding ion matches the relative permeability of the water phase in water flooding; is the normalized water saturation S of the horizon to be analyzed * The corresponding ion matching water flooding oil phase relative permeability; θ is the weight coefficient; S * is the normalized water saturation; S w is water saturation; S wc S is the irreducible water saturation during water flooding in the layer to be analyzed; or is the residual oil saturation of the stratum to be analyzed.

4. The method according to claim 1 or 3, wherein: The upper limit of the effective salinity range shall not exceed 10000 mg / L, and the lower limit shall not be less than 1000 mg / L.

5. The method according to claim 4, wherein: The upper limit of the effective salinity range is 10000 mg / L, and the lower limit is 1000 mg / L.

6. The method according to claim 1, wherein: Determining the water saturation and fractional flow of the formation water drive front and the ion matching water drive front of each layer of the target oil reservoir based on the formation water drive fractional flow curve and the ion matching water drive fractional flow curve of each layer of the target oil reservoir includes: For each layer of the target reservoir, on the flow rate relationship plate of the formation water drive flow rate curve and the ion matching water drive flow rate curve containing the layer, a tangent line is drawn through the origin to the ion matching water drive flow rate curve, and the water saturation and flow rate corresponding to the tangent point are the water saturation and flow rate of the ion matching water drive front of the layer, and the water saturation and flow rate corresponding to the intersection of the tangent line and the formation water drive flow rate curve are the water saturation and flow rate of the formation water drive front of the layer.

7. The method according to claim 1, wherein: The method of determining the positions of the formation water flooding fronts of the target oil reservoir at the moment of water breakthrough in the formation water flooding of the highest permeability layer in the target oil reservoir based on the water saturation of the formation water flooding front of each layer in the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve comprises: Based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve, determine the total mobility ratio of the formation water flooding front during the non-piston flooding process of each layer of the target oil reservoir; Based on the total mobility ratio of the formation water flooding front during the non-piston displacement process of each layer in the target reservoir, the formation water flooding front positions of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir are determined.

8. The method according to claim 7, wherein: The method of determining the total mobility ratio of the formation water flooding front in the non-piston displacement process of each layer of the target oil reservoir based on the water saturation of the formation water flooding front of each layer of the target oil reservoir and the formation water flooding oil-water two-phase relative permeability curve comprises: For each layer of the target reservoir, the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer is determined by the following formula: Where M F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the analyzed layer; is the water saturation of the formation water flooding front during the water flooding process of the formation to be analyzed The total fluid flow rate under t (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc Total fluid flow rate under is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the water phase in the formation water drive; k rw (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc The corresponding relative permeability of the water phase in the formation water drive; is the water saturation of the water flooding front in the layer to be analyzed The corresponding relative permeability of the formation water-driven oil phase; k ro (S wc ) is the irreducible water saturation S during water flooding in the layer to be analyzed wc The corresponding relative permeability of the formation water-driven oil phase; μ w is the viscosity of the water phase; μ o is the oil phase viscosity.

9. The method according to claim 7, wherein: The method of determining the positions of the formation water flooding fronts of the target reservoir at the time of water breakthrough in the formation water flooding of the highest permeability layer in the target reservoir based on the total mobility ratio of the formation water flooding front in the non-piston flooding process of each layer in the target reservoir comprises: For each layer of the target reservoir, the formation water flooding front position of the remaining layers at the time of water breakthrough in the formation water flooding of the highest permeability layer is determined by the following formula: in, In the formula, M is the water breakthrough moment of the highest permeability layer and the position of the formation water flooding front of the layer to be analyzed; F is the total mobility ratio of the formation water flooding front during the non-piston displacement process of the layer to be analyzed; φ is the formation porosity of the layer to be analyzed; k is the permeability of the layer to be analyzed; Δs w is the difference between the water saturation at the water flooding front and the irreducible water saturation of the formation to be analyzed, that is, in is the water saturation of the water flooding front in the layer to be analyzed, S wc is the irreducible water saturation during water flooding of the formation to be analyzed; is the total mobility ratio of the formation water flooding front during non-piston displacement in the highest permeability layer; φ h k is the porosity of the highest permeability layer; h is the permeability of the highest permeability layer; is the difference between the water saturation at the water flooding front of the highest permeability layer and the irreducible water saturation, that is, in is the water saturation of the water flooding front at the highest permeability layer, It is the irreducible water saturation during water flooding in the highest permeability layer.

10. The method according to claim 1, wherein: Determining the ion matching water flooding front position of each layer in the target oil reservoir based on the formation water flooding front position of the highest permeability layer in the target oil reservoir at the time of water breakthrough, the water saturation and fractional flow of the ion matching water flooding front, comprises: Step S61: Based on the Buckley-Leverett equation, determine an ion matching water flooding front motion model that takes into account the chemical hysteresis effect; Step S62: Based on the ion-matching water drive front movement model considering the chemical hysteresis effect, the dimensionless distance of the ion-matching water drive relative to the formation water drive front is introduced, and the formation water drive front positions of the remaining layers at the time of water breakthrough in the formation water drive of the highest permeability layer in the target reservoir, the water saturation of the ion-matching water drive front and the fractional flow rate are used to determine the ion-matching water drive front positions of each layer in the target reservoir.

11. The method according to claim 10, wherein: The determined ion-matched water flooding front motion model considering the chemical hysteresis effect is: Where, φ is the formation porosity of the layer to be analyzed, a decimal; v t is the injection speed of ion matching water, m 3 / d; D is the dimensionless hysteresis effect coefficient; To match the water saturation of the water flooding front for ions; Divide the flow rate of the water flooding front for ion matching; The instantaneous velocity of the water drive front for ion matching.

12. The method according to claim 1 or 10, wherein: The ion matching water flooding front position is determined by the following formula: In the formula, The water breakthrough moment of the formation water flooding in the highest permeability layer is the position of the water flooding front edge of the layer to be analyzed; v is the position of the formation water flooding front edge of the layer to be analyzed at the time of water breakthrough in the formation water flooding of the layer with the highest permeability; C v is the advancing speed of the formation water flooding front; F S is the ion matching water drive front advancing speed; wc is the irreducible water saturation during water flooding of the formation to be analyzed; is the water saturation of the water flooding front of the formation to be analyzed; The flow rate of water flooding front in the formation to be analyzed; Match the fractional flow rate of the water flooding front to the formation ions to be analyzed; is the water saturation of the water flooding front of the formation ion matching to be analyzed; D is the dimensionless hysteresis effect coefficient.

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