Metamorphic rock buried hill fractured reservoir imbibition characteristic curve calculation method

Abstract

The invention discloses a metamorphic rock buried hill fractured reservoir imbibition characteristic curve calculation method. The method comprises the steps that samples of different matrix rock mass types in a target area are collected; the novel reverse imbibition experiment device is used for carrying out an imbibition experiment; drawing an experimental imbibition recovery ratio change scatter diagram; establishing an oil and water relative permeability and capillary pressure curve representation function; establishing an imbibition mathematical model under the cylindrical coordinate system, and calculating a theoretical imbibition recovery ratio; fitting by adopting a least square method and a genetic algorithm to obtain imbibition characteristic parameters; drawing imbibition characteristic curves of different types of matrix rock blocks; establishing a geologic model; and carrying out numerical simulation by adopting a relative permeability zoning mode, and the like. The method is reliable in technical principle and clear in logic, prediction of the relative permeability curve and the capillary force curve of the matrix rock core is more accurate, and the method has important significance in research on fine numerical simulation, remaining oil prediction, water injection strategy optimization and the like of a double-hole single-permeability oil reservoir.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil exploitation, and particularly relates to a method for calculating the imbibition characteristic curve of a fractured metamorphic buried hill reservoir. Background Art

[0002] The geological structure of a fractured metamorphic buried hill reservoir is complex, with a strong degree of heterogeneity, and two sets of systems of macroscopic fractures and matrix rock blocks are developed. Among them, the matrix rock block system mainly develops two types of reservoir spaces: microscopic pore throats and microfractures (the crack width opening ratio is less than 50 μm). Compared with conventional reservoirs, the pore throat radius of the matrix rock block is smaller and the pore structure is complex. In a water-wet reservoir, the driving force for oil displacement in the matrix rock block mainly relies on capillary force reverse imbibition to squeeze out water and drain oil. Therefore, the imbibition effect is an important oil production mechanism for the matrix rock block.

[0003] At present, there are mainly two methods for studying the imbibition effect of matrix rock blocks. One is to carry out research through spontaneous imbibition experiments. At present, many experts at home and abroad have carried out a large number of experimental studies on the influence of parameters such as the wettability of rocks, crude oil viscosity, and rock block size on the imbibition effect. However, there are few studies on the influence of the microscopic pore throat structure and the degree of microfracture development of matrix rock blocks on the imbibition effect. The main reason is that the pore throats of matrix rock blocks are relatively dense and the oil content is small. When the existing experimental devices carry out imbibition experiments, the oil droplets exuded from the core inside often adsorb on the rock surface, resulting in large experimental errors. Therefore, the existing imbibition experimental devices are difficult to accurately describe the influence of the differences in the pore throat structure of matrix rock blocks on the imbibition recovery rate.

[0004] The other mainly conducts research through numerical simulation technology. Among them, the relative permeability curves of oil and water and the capillary pressure curve are the key characteristic curves for describing the imbibition characteristics of matrix rock blocks in numerical simulation. For the convenience of description, this application collectively refers to the relative permeability curves of oil and water and the capillary force curve as the imbibition characteristic curve. At present, when domestic and foreign scholars use numerical simulation technology to study the imbibition effect, the imbibition characteristic curves used are generally obtained by analogy or indoor experiments. Due to the relatively dense matrix core, problems such as long time consumption and large human influence exist in mercury injection and displacement experiments, resulting in relatively large uncertainties in the imbibition characteristic curves. Therefore, there are doubts about whether the existing numerical simulation technology can accurately express the seepage characteristics of matrix rock blocks.

[0005] Considering that the reservoir of the metamorphic buried hill oil reservoir is affected by various factors such as tectonic movement, weathering, and leaching, resulting in different microscopic pore throat structures and degrees of microfracture development of matrix rock blocks in different reservoir structures, accurately obtaining the imbibition characteristic curve of matrix rock blocks is of great significance for studying the underground seepage characteristics, remaining oil characterization, recovery rate prediction, and formulating optimized water injection strategies for this type of oil reservoir. Summary of the Invention

[0006] The present invention is proposed to solve the problems existing in the prior art that the matrix core is relatively dense, the pore-throat structure is complex, and the diversity of core types leads to time-consuming and large errors in obtaining the percolation characteristic curve by the existing methods. Its purpose is to provide a method for calculating the imbibition characteristic curve of a fractured reservoir in a metamorphic buried hill.

[0007] The present invention is realized through the following technical solutions:

[0008] A method for calculating the imbibition characteristic curve of a fractured reservoir in a metamorphic buried hill, comprising the following steps:

[0009] S1. Collect core samples at different depth sections in the target area and classify the matrix rock block types;

[0010] S2. Select matrix cores of different matrix rock block types, drill core plugs, and conduct reverse imbibition experiments on the matrix rock blocks of different matrix rock block types;

[0011] S3. Draw a scatter plot of the experimental imbibition recovery rate versus the production time;

[0012] S4. Respectively establish the characterization functions of the oil-water relative permeability and the capillary pressure curve based on the Willhite model and the J-function model;

[0013] S5. Establish an imbibition mathematical model in a cylindrical coordinate system to obtain the theoretical imbibition recovery rate;

[0014] S6. Use the least squares method and the genetic algorithm to fit and obtain reasonable imbibition characteristic parameters (M, N, n o 、n w ).

[0015] S7. Draw the imbibition characteristic curves of different types of matrix rock blocks;

[0016] S8. Establish a geological model and conduct numerical simulation by means of permeability zoning.

[0017] In the above technical solution, the method for classifying the matrix rock block types in step S1 is specifically as follows: perform CT scanning on the core samples at different depth sections in the target area, and classify different matrix rock block types based on the degree of pore-throat development and the degree of micro-fracture development.

[0018] In the above technical solution, the relationship between the imbibition recovery rate of the core determined in the imbibition experiment and the change in the core mass in step S2 is as follows in formula (1):

[0019]

[0020] In the formula: m t+1 、m t are respectively the increased values of the core sample mass at t + 1 and t moments, with the unit of g; ρw To simulate the formation water density, the unit is g / cm 3 ; ρ w To simulate the crude oil density, the unit is g / cm 3 ; V o Is the volume of the rock sample saturated with oil, the unit is cm 3 .

[0021] In the above technical solution, in step S3, the scatter plot of the experimental imbibition recovery rate changing with the production time converts the experimental time into the field production time according to the similarity criterion. Taking the field production time as the X-axis and the experimental imbibition recovery rate as the Y-axis, a scatter plot E(t) of the experimental imbibition recovery rate changing with the field production time is drawn.

[0022] In the above technical solution, in step S4, the oil-phase relative permeability k ro The expression is as follows in Equation (2):

[0023]

[0024] Where: S w Is the water saturation, in decimals; S wi Is the irreducible water saturation, in decimals; S or Is the residual oil saturation, in decimals; k ro Is the oil-phase relative permeability, in decimals; n o Is the characteristic parameter of the oil-phase relative permeability;

[0025] The water-phase relative permeability k rw Established according to the Willhite model is expressed as follows in Equation (3):

[0026]

[0027] Where: k rw Is the water-phase relative permeability, in decimals; S w Is the water saturation, in decimals; S wi Is the irreducible water saturation, in decimals; S or Is the residual oil saturation, in decimals; n w Is the characteristic parameter of the water-phase relative permeability;

[0028] The expression of the capillary pressure curve of the core established according to the J-function model is as follows in Equation (4):

[0029]

[0030] Where: p c Is the capillary pressure, the unit is MPa; S w Is the water saturation, in decimals; S wiis the irreducible water saturation, in decimals; M and N are the characteristic parameters of the capillary pressure curve; is the porosity, in decimals; k is the absolute permeability, 10 -3 μm 2 .

[0031] In the above technical solution, in step S5, taking the axial direction of the core as the z direction and the radial direction as the r direction, the expression of the imbibition mathematical model in the cylindrical coordinate system is as follows in formula (5): The expression of the imbibition mathematical model in the cylindrical coordinate system is as follows in formula (5):

[0032]

[0033] where: The expression of ψ is:

[0034]

[0035] In the formula: u w is the viscosity of water, in units of mPa·s; u o is the viscosity of crude oil, in units of mPa·s; k rw is the relative permeability of the water phase, in decimals; k ro is the relative permeability of the oil phase, in decimals; p c is the capillary pressure, in units of MPa; S w is the water saturation, in decimals; k is the absolute permeability, in units of 10 -3 μm 2 ; t is the displacement time, in units of h.

[0036] Differentially discretizing the expression of the imbibition mathematical model in the cylindrical coordinate system, the numerical solution expression of imbibition is obtained as follows in formula (7):

[0037]

[0038] where:

[0039]

[0040] c ij = 1 - a ij - b ij - d ij - e ij (12)

[0041] Assume that the imbibition characteristic parameters (M, N, n o , n w ) of the matrix core are known parameters, and the relative permeability k ro of the oil phase, the relative permeability k rw of the water phase, and the capillary pressure P c are calculated from formulas (2 - 4);

[0042] The obtained oil-phase relative permeability k ro , water-phase relative permeability k rw and capillary pressure P c are substituted into the discretized imbibition mathematical model (Formulas 7 - 12), and the change of the theoretical imbibition recovery rate with time R(t) is calculated.

[0043] In the above technical solution, the imbibition characteristic parameters of the matrix core in step S6 include the oil-phase relative permeability characteristic parameter n o , water-phase relative permeability characteristic parameter n w and capillary force curve characteristic parameters M, N.

[0044] In the above technical solution, the specific method for fitting and obtaining reasonable imbibition characteristic parameters in step S6 using the least squares method and genetic algorithm is as follows: Given a set of initial values of imbibition characteristic parameters, a set of curves of the change of the theoretical imbibition recovery rate with time R0(t) is calculated from steps S4 and S5; Taking the scatter plot E(t) of the experimental imbibition recovery rate with time obtained in step S3 as the fitting target, and using the imbibition characteristic parameters as the optimization variables, the theoretical imbibition recovery rate R(t) and the experimental imbibition recovery rate E(t) are continuously iteratively fitted using the least squares method, and the fitting error model is If σ ≤ 0.01, the error meets the standard, and reasonable imbibition characteristic parameters (n o , n w , M, N) are output; If σ > 0.01, the genetic algorithm is used to optimize the imbibition characteristic parameters (M, N, n o , n w ) until σ ≤ 0.01, and the characteristic parameters within the error range are obtained; According to step S6, the imbibition characteristic parameters of different types of matrix cores are obtained respectively.

[0045] In the above technical solution, the specific method for drawing the imbibition characteristic curves of different types of matrix blocks in step S7 is as follows: The imbibition characteristic curves take the water saturation S w as the X-axis, k ro , k rw and P c as the Y-axes respectively, and the oil-phase relative permeability curve, water-phase relative permeability curve and capillary pressure curve of different types of cores are drawn respectively according to the expressions of the oil-phase relative permeability k ro established according to the Willhite model, the expressions of the water-phase relative permeability k rw and the expressions of the water-phase relative permeability k rw established according to the Willhite model (Formulas 2 - 4).

[0046] In the above technical solution, in step S8, the geological model includes a three-dimensional structural model, a fracture density model, a fracture network model, a fracture property parameter model, a matrix system property model, and a fluid model; the geological model is established by using Petrel software in combination with data such as logging, coring, seismic, and stress analysis in the target area; the specific method for carrying out numerical simulation by adopting the method of phase permeability zoning is as follows: for the matrix system, the method of phase permeability zoning is adopted, and the oil-water relative permeability and capillary pressure curves of different types of matrix cores obtained are respectively brought into the corresponding reservoir to carry out history matching and predict the recovery factor.

[0047] The beneficial effects of the present invention are as follows:

[0048] The present invention provides a method for calculating the imbibition characteristic curves (oil-water relative permeability curves and capillary force curves) of fractured metamorphic buried hill reservoirs considering different matrix rock block types. Combining with the relatively easy-to-implement reverse imbibition experiment, a new method for obtaining the imbibition characteristic curves (oil-water relative permeability curves and capillary force curves) is established, realizing an accurate and objective description of the imbibition effect of matrix rock blocks, and overcoming the disadvantages that matrix cores are relatively dense, the pore throat structure is complex, and the existing experiments for obtaining the seepage characteristic curves take a long time and have large errors.

[0049] The present invention considers that the difference in the pore permeability structure of matrix rock blocks has a great influence on the shape of the imbibition characteristic curves, and proposes a method for establishing seepage characteristic curves by classifying core types, realizing the influence of the vertical zoning of fractured buried hill reservoirs on the imbibition effect of matrix cores, and more accurate prediction of remaining oil description and recovery factor. The present invention adopts a new type of reverse imbibition experimental device, and by adding a rotary motor to the experimental device, overcomes the experimental error caused by the adhesion of the reverse imbibition oil output on the core surface and cannot be excluded. The technical principle of the present invention is reliable and the logic is clear, which is more accurate for predicting the relative permeability curve and capillary force curve of matrix cores, and has important significance for the research on fine numerical simulation, remaining oil prediction, and optimized water injection strategy of dual-porosity single-permeability reservoirs. The present invention is not only applicable to fractured buried hill reservoirs, but also applicable to low-permeability or tight oil reservoirs with mainly imbibition effect and relatively complex microscopic pore throat structures. Description of the Drawings

[0050] Figure 1 is the method flow chart of the present invention.

[0051] Figure 2 is the schematic diagram of core data collection in the target area in Embodiment 1 of the present invention;

[0052] Figure 3 is the CT scan core interface diagram in the target area in Embodiment 1 of the present invention;

[0053] Figure 4 is the schematic diagram of the reverse imbibition experimental device in the target area in Embodiment 1 of the present invention;

[0054] Figure 5 It is the curve graph showing the change of the experimental and theoretical core imbibition recovery rates in the target area with time in Embodiment 1 of the present invention;

[0055] Figure 6 It is the relative permeability curve graph of oil and water obtained in the target area in Embodiment 1 of the present invention;

[0056] Figure 7 It is the capillary pressure curve graph obtained in the target area in Embodiment 1 of the present invention;

[0057] Figure 8 It is the fracture distribution map of 3D modeling in the target area in Embodiment 1 of the present invention;

[0058] Figure 9 It is the porosity distribution map of the matrix system in the target area in Embodiment 1 of the present invention;

[0059] Figure 10 It is the permeability distribution map of the matrix system in the target area in Embodiment 1 of the present invention;

[0060] Figure 11 It is the porosity distribution map of the fracture system in the target area in Embodiment 1 of the present invention;

[0061] Figure 12 It is the permeability distribution map of the fracture system in the target area in Embodiment 1 of the present invention;

[0062] Figure 13 It is the measured relative permeability distribution map of the core in the target area in Embodiment 1 of the present invention;

[0063] Figure 14 It is the measured capillary force distribution map of the core in the target area in Embodiment 1 of the present invention;

[0064] Figure 15 It is the schematic diagram of the phase permeability zoning in the target area in Embodiment 1 of the present invention;

[0065] Figure 16 It is the schematic diagram of the fitting of the water cut curves before and after optimization in the target area in Embodiment 1 of the present invention.

[0066] For those of ordinary skill in the art, without creative efforts, other relevant drawings can be obtained according to the above drawings. Detailed implementation manners

[0067] In order to enable the personnel in the technical field to better understand the technical solution of the present invention, the technical solution of the present invention will be further described below with reference to the accompanying drawings of the specification and through specific implementation manners.

[0068] Such as Figure 1As shown in the figure, a method for calculating the imbibition characteristic curves (oil-water relative permeability curves and capillary pressure curves) of a fractured reservoir in a metamorphic buried hill includes the following steps:

[0069] S1. Collect core samples in different depth intervals of the target area and classify the matrix rock block types;

[0070] The method for classifying the matrix rock block types is specifically as follows: perform CT scans on the core samples in different depth intervals of the target area, and classify different matrix rock block types based on the development degrees of pore throats and microfractures.

[0071] The types of conventional matrix rock blocks include pore-fracture type, fracture-pore throat type, dissolved pore developed type, pore throat dense type, and microfracture developed type. The classification principle of conventional matrix rock block types is mainly based on the development degrees of pores and fractures and the physical property sizes.

[0072] S2. Select matrix cores of different matrix rock block types, drill core plugs with a diameter of 25 mm, and conduct reverse imbibition experiments on matrix rock blocks of different matrix rock block types;

[0073] The experimental steps of the imbibition experiment are carried out according to the literature "Li Shikui, Liu Weidong, Zhang Haiqin, et al. Experimental study on spontaneous imbibition displacement in low-permeability oil reservoirs [J]. Acta Petrolei Sinica, 2007, 28(2): 109-112";

[0074] The relationship between the core imbibition recovery rate and the change in core mass is as follows in formula (1):

[0075]

[0076] In the formula: m t+1 、m t are the increased values of the core sample mass at times t + 1 and t respectively, with the unit of g; ρ w is the density of the simulated formation water, with the unit of g / cm 3 ; ρ w is the density of the simulated crude oil, with the unit of g / cm 3 ; V o is the volume of the core sample saturated with oil, with the unit of cm 3 ;

[0077] The reverse imbibition experiment on matrix rock blocks uses a new type of reverse imbibition experiment device, and the new type of reverse imbibition experiment device is carried out using the device disclosed in the patent "CN106769752A - Rotatable Imbibition Experiment Device"; compared with the conventional imbibition experiment device, the experimental device adopted in this application selects an appropriate rotation speed during the process of the reverse imbibition experiment to timely discharge the crude oil adsorbed on the core surface, making the experimental results more in line with the actual underground situation.

[0078] S3. Plot a scatter diagram of the experimental imbibition recovery rate versus the production time;

[0079] The scatter diagram of the experimental imbibition recovery rate versus the production time converts the experimental time into the field production time according to the similarity criterion. Taking the field production time as the X-axis and the experimental imbibition recovery rate as the Y-axis, plot the scatter diagram E(t) of the experimental imbibition recovery rate versus the field production time.

[0080] S4. Respectively establish the characterization functions of the relative permeability of oil and water and the capillary pressure curve based on the Willhite model and the J-function model;

[0081] The expression of the relative permeability of the oil phase k ro established based on the Willhite model is as follows in Equation (2):

[0082]

[0083] In the formula: S w is the water saturation, in decimals; S wi is the irreducible water saturation, in decimals; S or is the residual oil saturation, in decimals; k ro is the relative permeability of the oil phase, in decimals; n o is the characteristic parameter of the relative permeability of the oil phase;

[0084] The expression of the relative permeability of the water phase k rw established based on the Willhite model is as follows in Equation (3):

[0085]

[0086] In the formula: k rw is the relative permeability of the water phase, in decimals; S w is the water saturation, in decimals; S wi is the irreducible water saturation, in decimals; S or is the residual oil saturation, in decimals; n w is the characteristic parameter of the relative permeability of the water phase;

[0087] The expression of the capillary pressure curve of the core established based on the J-function model is as follows in Equation (4):

[0088]

[0089] In the formula: p c is the capillary pressure, in MPa; S w is the water saturation, in decimals; S wi is the irreducible water saturation, in decimals; M and N are the characteristic parameters of the capillary pressure curve; is the porosity; k is the absolute permeability, 10-3 um 2 ;

[0090] The characteristic parameter n of the oil-phase relative permeability o and the characteristic parameter n of the water-phase relative permeability w as well as the characteristic parameters M and N of the capillary pressure curve are collectively referred to as the imbibition characteristic parameters of the matrix core.

[0091] S5. Establish an imbibition mathematical model in the cylindrical coordinate system to obtain the theoretical imbibition recovery factor;

[0092] Taking the axial direction of the core as the z-direction and the radial direction as the r-direction, the expression of the imbibition mathematical model in the cylindrical coordinate system is as follows in Equation (5):

[0093]

[0094] Among them: The expression of ψ is:

[0095]

[0096] In the formula: u w is the viscosity of water, with the unit of mPa·s; u o is the viscosity of crude oil, with the unit of mPa·s; k rw is the water-phase relative permeability, in decimal; k ro is the oil-phase relative permeability, in decimal; p c is the capillary pressure, with the unit of MPa; S w is the water saturation, in decimal; t is the displacement time, with the unit of h;

[0097] Differentially discretize the expression of the imbibition mathematical model in the cylindrical coordinate system to obtain the expression of the imbibition numerical solution as follows in Equation (7):

[0098]

[0099] Among them:

[0100]

[0101] c ij = 1 - a ij - b ij - d ij - e ij (12)

[0102] Assume that the imbibition characteristic parameters of the matrix core (M, N, n o , n w ) are known parameters, and calculate the oil-phase relative permeability k ro , the water-phase relative permeability k rw and the capillary pressure P from formulas (2 - 4)c 。

[0103] Substitute the obtained oil-phase relative permeability \(k\) ro , water-phase relative permeability \(k\) rw and capillary pressure \(P\) c into the discretized imbibition mathematical model (Formulas 7 - 12) to calculate the variation of the theoretical imbibition recovery factor with time \(R(t)\).

[0104] S6. Use the least squares method and genetic algorithm to fit and obtain reasonable imbibition characteristic parameters (\(M\), \(N\), \(n\) o , \(n\) w ), specifically as follows:

[0105] Given a set of initial values of imbibition characteristic parameters (\(n\) o0 , \(n\) w0 , \(M_0\), \(N_0\)), a set of curves of the variation of the theoretical imbibition recovery factor with time \(R_0(t)\) is calculated from Steps S4 and S5. Taking the scatter plot of the experimental imbibition recovery factor with time \(E(t)\) obtained in Step S3 as the fitting target, and using the imbibition characteristic parameters (\(n\) o , \(n\) w , \(M\), \(N\)) as optimization variables, continuously iterate and fit the theoretical imbibition recovery factor \(R(t)\) and the experimental imbibition recovery factor \(E(t)\) using the least squares method. The fitting error model is If \(\sigma\leq0.01\), the error meets the standard, and output reasonable imbibition characteristic parameters (\(n\) o , \(n\) w , \(M\), \(N\)). If \(\sigma > 0.01\), optimize the imbibition characteristic parameters (\(M\), \(N\), \(n\) o , \(n\) w ) using the genetic algorithm until \(\sigma\leq0.01\) to obtain the characteristic parameters (\(n\) o , \(n\) w , \(M\), \(N\)) within the error range.

[0106] According to Step S6, respectively obtain the imbibition characteristic parameters (\(n\) o , \(n\) w , \(M\), \(N\)) of different types of matrix cores.

[0107] S7. Plot the imbibition characteristic curves of different types of matrix blocks;

[0108] The imbibition characteristic curves take the water saturation \(S\) w as the X-axis, and \(k\) ro , \(k\) rw and \(P\) c as the Y-axis respectively. Respectively, according to the expression of the oil-phase relative permeability \(k\) ro established by the Willhite model, the water-phase relative permeability \(k\) rwThe expression and the relative water permeability k established according to the Willhite model rw Based on the expressions (Formulas 2 - 4), draw the relative oil permeability curves, relative water permeability curves, and capillary pressure curves of different types of cores.

[0109] S8. Establish a geological model and conduct numerical simulation by means of phase permeability zoning;

[0110] The geological model includes a three - dimensional structural model, a fracture density model, a fracture network model, a fracture property parameter model, a matrix system property model, and a fluid model;

[0111] The geological model is established by combining data such as logging, coring, seismic, and stress analysis in the target area and using Petrel software. The specific establishment method is based on the literature "Zheng Xu, Zhao Chunming, Lei Yuan, etc. Research and Application of the Integration Technology of Geological Modeling and Numerical Simulation in Fractured Reservoirs - Taking the Archaeozoic Buried Hill Reservoir in the South of Jinzhou 25 - 1 Oilfield as an Example [J]. Acta Petrolei Sinica, 2011, 32(4): 626 - 632."

[0112] The specific method of conducting numerical simulation by means of phase permeability zoning is as follows: For the matrix system, use the method of phase permeability zoning. Substitute the obtained relative oil and water permeabilities and capillary pressure curves of different types of matrix cores into the corresponding reservoirs respectively to conduct history matching and predict the recovery factor.

[0113] Example 1

[0114] Taking Jinzhou A Oilfield in the Bohai Bay as an example, as Figure 1 shown, a calculation method for the imbibition characteristic curves (relative oil and water permeability curves and capillary force curves) of a metamorphic rock buried hill fractured reservoir includes the following steps:

[0115] S1: Collect core samples at different depth intervals in the target area and divide the types of matrix rock blocks.

[0116] Through core description, rock geochemical elements, and logging response characteristics, it is analyzed that the reservoir in Jinzhou A Oilfield has obvious vertical zonation. From the top to the bottom of the buried hill, it is divided into the upper semi - weathered crust section, the lower semi - weathered crust section, and the inner - part basement rock section. Collect core samples under different reservoir types in Jinzhou A Oilfield respectively, conduct CT scans, and based on the pore - throat development characteristics and the degree of micro - fracture development, it is obtained that the matrix rock blocks in Jinzhou A Oilfield can be divided into 3 types, namely, partially connected pore - throat type, reticularly connected pore - throat type, and isolated pore - throat type, as shown in Table 1 and Figures 2 - 3 shown.

[0117] In Example 1 of this application, the pore-throat isolated type corresponds to the pore-throat dense type of the conventional matrix rock block type, the pore-throat network-connected type corresponds to the micro-fracture developed type, and the pore-throat partially connected type corresponds to the pore-fracture type. Only these three main types are considered in Example 1 of this application, which is based on the degree of cutting of micro-fractures on pore-throats, that is, the division is carried out according to the degree of micro-fracture development. In this paper, the micro-fracture density ≤ 1 piece / cm is defined as the pore-throat isolated type, the micro-fracture density between 2 - 4 pieces / cm is defined as the pore-throat partially connected type, and the micro-fracture density between 5 - 10 pieces / cm is defined as the pore-throat network-connected type.

[0118] Table 1 Pore-throat characteristics of different types of cores in the target oilfield

[0119]

[0120] S2: Carry out the reverse imbibition experiment on different types of matrix rock blocks by using a new type of reverse imbibition experimental device.

[0121] Select 3 types of typical matrix cores from Jinzhou A Oilfield, drill core plugs with a diameter of 25 mm, and carry out imbibition experiment research. Compared with the existing imbibition experimental device, improve the experimental device by adding a rotary motor to the imbibition experimental device. During the process of carrying out the reverse imbibition experiment, select an appropriate rotation speed to timely discharge the crude oil adsorbed on the core surface, making the experimental results more in line with the actual underground situation, as Figure 4 shown.

[0122] The steps of the imbibition experiment refer to the literature "Li Shikui, Liu Weidong, Zhang Haiqin, etc. Experimental study on spontaneous imbibition displacement in low-permeability oil reservoirs [J]. Acta Petrolei Sinica, 2007, 28(2): 109 - 112". Record the change of core mass every 4 hours to obtain the imbibition recovery rate (the 1st, 3rd, 4th, and 5th columns in Table 2). The relationship between the core imbibition recovery rate and the change of core mass is:

[0123]

[0124] In the formula: m t+1 , m t are the increased values of the core sample mass at t + 1 and t moments respectively, g; ρ w is the density of the simulated formation water, g / cm 3 ; ρ w is the density of the simulated crude oil, g / cm 3 ; V o is the volume of the core sample saturated with oil, cm 3 .

[0125] S3: Draw a scatter plot of the experimental imbibition recovery rate varying with the production time.

[0126] According to the similarity criterion (Equation 2), the experimental time is converted into the field production time (the second column of Table 2). Taking the field production time as the X-axis and the imbibition recovery rate as the Y-axis, a scatter plot of the imbibition recovery rate varying with the field production time under different matrix types is plotted ( Figure 5 ).

[0127]

[0128] where t m is the time of the imbibition experiment, h; t n is the actual field production time, h; k is the permeability, 10 -3 μm 2 ;; is the porosity, in decimal; σ is the oil-water interfacial tension, mN / m; θ is the wetting angle, °; μ o is the viscosity of the crude oil, mPa·s;; L m is the length of the experimental rock sample, cm; D m is the diameter of the experimental rock sample, cm; L n is the length of the equivalent matrix rock sample in the field, cm; D n is the diameter of the equivalent matrix rock sample in the field.

[0129]

[0130]

[0131] Table 2 Imbibition recovery rates from experiments and theoretical calculations for different types of cores in the target area

[0132] S4: Establish the characterization functions of the relative permeability curves of oil and water and the capillary pressure curve from the Willhite model and the J-function model.

[0133] Based on the mathematical model of the relative permeability of the oil phase k ro , the mathematical model of the relative permeability of the water phase k rw , and the mathematical model of the capillary pressure curve of the core (Equation 5), given the imbibition characteristic parameters M, N, n o , and n w of the matrix core, substituting into the above mathematical models, the relative permeability of the oil phase k ro , the relative permeability of the water phase k rw , and the capillary pressure P c can be obtained.

[0134] The expression of the relative permeability of the oil phase k ro is as follows:

[0135]

[0136] The relative permeability of the water phase k rwThe expression is:

[0137]

[0138] The expression of the capillary pressure curve of the core is:

[0139]

[0140] In the formula, S w is the water saturation, in decimals; S wi is the irreducible water saturation, in decimals; S or is the residual oil saturation, in decimals; k rw is the relative permeability of the water phase, in decimals; k ro is the relative permeability of the oil phase, in decimals; n o is the characteristic parameter of the relative permeability of the oil phase; n w is the characteristic parameter of the relative permeability of the water phase; p c is the capillary pressure, in MPa; M and N are the characteristic parameters of the capillary pressure curve. For the convenience of subsequent description, (M, N, n o , n w ) are collectively referred to as the imbibition characteristic parameters of the matrix core.

[0141] S5: Establish an imbibition mathematical model in the cylindrical coordinate system to obtain the theoretical imbibition recovery factor.

[0142] Assume that the axial direction of the core is the z direction and the radial direction is the r direction. The imbibition mathematical equation in the cylindrical coordinate system can be expressed as:

[0143]

[0144] In the formula, ψ can be expressed as:

[0145]

[0146] In the formula, u w is the viscosity of water, in mPa·s; u o is the viscosity of crude oil, in mPa·s.

[0147] Discretize the formula (6) by difference to obtain the expression of the imbibition numerical solution as:

[0148]

[0149] In the formula:

[0150]

[0151] c ij = 1 - a ij - b ij - d ij - e ij(13)

[0152] Assume that the imbibition characteristic parameters of the matrix core (M, N, n o , n w ) are known parameters, and the relative permeability of the oil phase K ro , the relative permeability of the water phase k rw and the capillary pressure P c are calculated from formulas (2 - 4).

[0153] Substitute the obtained relative permeability of the oil phase k ro , the relative permeability of the water phase k rw and the capillary pressure P c into the discretized imbibition mathematical model (formulas 8 - 13) to calculate the change of the theoretical imbibition recovery rate with time R(t).

[0154] S6: Use the least - squares method and genetic algorithm to obtain reasonable imbibition characteristic parameters (M, N, n o , n w ).

[0155] The implementation scheme is as follows:

[0156] (1) Given a set of initial parameter values (n o0 , n w0 , M0, N0), calculate a set of curves of the change of the theoretical imbibition recovery rate with time R0(t) from steps S4 and S5.

[0157] (2) Take the scatter plot of the change of the recovery rate with time E(t) obtained from the imbibition experiment as the fitting target, and take the imbibition characteristic parameters (n o , n w , M, N) as the optimization variables, and fit the experimental imbibition recovery rate E(t) with the theoretical imbibition recovery rate R0(t).

[0158] (3) Use the least - squares method to determine the curve fitting error model

[0159] (4) If σ ≤ 0.01, the error meets the standard, and output reasonable characteristic parameters (n o , n w , M, N.

[0160] (5) If σ > 0.01, use the genetic algorithm to optimize the characteristic parameters (n o , n w , M, N) until σ ≤ 0.01 to obtain the characteristic parameters (n o , n w , M, N) within the error range.

[0161] (6) According to the above method, the imbibition characteristic parameters (n o , n w , M, N) of different types of matrix cores are obtained respectively.

[0162] See Table 2 (the 1st column, the 6th column, the 7th column, the 8th column), Table 3 and Figure 5 .

[0163] Table 3 Imbibition characteristic parameters of 3 types of cores in the target oilfield

[0164]

[0165] S7: Plot the oil-water relative permeability curves and capillary pressure curves of different types of matrix blocks.

[0166] Taking the water saturation S w as the X-axis, k ro , k rw and P c as the Y-axes respectively, according to Formulas (3 - 5), plot the oil-phase relative permeability curves, water-phase relative permeability curves and capillary pressure curves of the three types of matrix cores respectively, as shown in Figures 6 - 7 and Table 4.

[0167] Table 4 Oil-water relative permeability curves and capillary pressure curves of 3 types of cores in the target oilfield

[0168]

[0169] S8: Establish a geological model and carry out numerical simulation by means of permeability partitioning.

[0170] Due to the influence of the heterogeneity of the reservoir longitudinal structure, the imbibition process and its changes control the oil production of the matrix system. In order to study the influence of imbibition on residual oil and production during water flooding, using Petrel software and combining the logging, coring, seismic, stress analysis and other data in the study area, a 3D structural model, fracture density model, fracture network model, fracture property parameter model, matrix system property model and fluid model of Well Block 2 in Jinzhou A Oilfield are established in sequence. By integrating the oil well and water well information and production history, a numerical model is constructed to simulate the exploitation and water flooding process in the study area, as shown in Figures 8 - 12 . During the history matching process, the injected water volume and oil production observed in the injection wells and production wells are constrained respectively, and the water cut is set as the history matching target.

[0171] In Scheme 1, a set of laboratory-measured relative permeability and capillary pressure curves of Jinzhou A Oilfield are used, which are the relative permeability curve and capillary pressure curve measured in the cored well of the inner basement section, as shown in Figures 13 - 14 . In Scheme 2, according to the principle of permeability partitioning, the lower-phase permeability curves and capillary pressure curves of different types of cores are respectivelyFigures 6 - 7 and Table 4) are introduced into the reservoirs in the upper part of the semi-weathered crust, the lower part of the semi-weathered crust, and the bedrock section inside the formation. The method of phase permeability zoning is as Figure 15 shown.

[0172] From the historical matching results, the water cut rising rate of Plan 1 is significantly higher than the observed data. This is because the phase permeability and capillary pressure curves obtained from the bedrock section inside the formation are used, and the matrix pores are in an isolated state. The influence of the micro-fracture development section on the imbibition effect is not considered, resulting in low oil displacement efficiency and difficulty in exerting the imbibition effect, which does not conform to the actual production and makes it difficult to achieve historical matching. Plan 2 considers the differences in the vertical structure of the reservoir and adopts the method of phase permeability zoning, fully considering the promotion of matrix imbibition by micro-fractures in the upper part and the lower part of the semi-weathered crust. The observed data (blue dots) match well with the simulation results (red line), and historical matching is better achieved, as Figure 16 shown.

[0173] The calculation method of the imbibition characteristic curve of the matrix rock block in the fractured metamorphic buried hill reservoir of the present invention considers the differences in the vertical structure of the buried hill reservoir, selects different matrix cores for classification research; establishes a new type of reverse imbibition experimental device to improve the accuracy of imbibition recovery rate; combines the imbibition mathematical model and the imbibition experiment, and uses the least squares method and the genetic algorithm to establish a new method for obtaining the seepage characteristic curve under different matrix rock block types. The method principle of the present invention is reliable and the logic is clear. Only by carrying out the relatively easy imbibition experiment can the oil and water phase permeability curves and capillary pressure curves of different types of matrix cores be obtained, overcoming the problems of time-consuming and large errors in obtaining the seepage characteristic curve by the existing methods due to the relatively dense matrix core, complex pore throat structure, and diversity of core types.

[0174] The applicant declares that the above is only the specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention fall within the protection scope and the disclosure scope of the present invention.

Claims

1. A calculation method for the imbibition characteristic curve of a fractured reservoir in a metamorphic buried hill, characterized in that: It includes the following steps: S1. Collect core samples in different depth intervals of the target area and classify the types of matrix rock blocks; S2. Select matrix cores of different matrix rock block types, drill core plugs, and conduct reverse imbibition experiments on the matrix rock blocks of different matrix rock block types; S3. Plot a scatter diagram of the experimental imbibition recovery rate varying with production time; S4. Respectively establish characterization functions of oil and water relative permeability and capillary pressure curves based on the Willhite model and the J-function model; S5. Establish an imbibition mathematical model in a cylindrical coordinate system to obtain the theoretical imbibition recovery rate; S6. Use the least squares method and genetic algorithm to fit and obtain reasonable imbibition characteristic parameters (M, N, n o , n w ). S7. Plot the imbibition characteristic curves of different types of matrix rock blocks; S8. Establish a geological model and conduct numerical simulation by means of permeability zoning.

2. The method for calculating the imbibition characteristic curve of a fractured metamorphic buried hill reservoir according to claim 1, characterized in that: The method for classifying matrix rock block types in step S1 is specifically as follows: Perform CT scans on the core samples in different depth intervals of the target area, and classify different matrix rock block types based on the degrees of pore-throat development and micro-fracture development.

3. The calculation method of the imbibition characteristic curve of the fractured metamorphic buried hill reservoir according to claim 1, wherein: The relationship between the imbibition recovery rate of the core determined in the imbibition experiment and the change in core mass in step S2 is as follows in formula (1): Where: m t+1 and m t are the increased values of the mass of the rock sample at times t + 1 and t respectively, with the unit of g; ρ w is the density of the simulated formation water, with the unit of g / cm 3 ; ρ w is the density of the simulated crude oil, with the unit of g / cm 3 ; V o is the volume of the rock sample saturated with oil, with the unit of cm 3 .

4. The imbibition characteristic curve calculation method for fractured metamorphic buried hill reservoirs according to claim 1, characterized in that: In step S3, the scatter diagram of the experimental imbibition recovery rate varying with production time converts the experimental time into field production time according to the similarity criterion, takes the field production time as the X-axis, and the experimental imbibition recovery rate as the Y-axis, and plots the scatter diagram of the experimental imbibition recovery rate varying with the field production time.

5. The method for calculating the imbibition characteristic curve of fractured metamorphic buried hill reservoirs according to claim 1, wherein: The expression of the oil-phase relative permeability established based on the Willhite model in step S4 is as follows in formula (2): where: S w is the water saturation, in decimal; S wi is the irreducible water saturation, in decimal; S or is the residual oil saturation, in decimal; k ro is the relative permeability of the oil phase, in decimal; n o is the characteristic parameter of the relative permeability of the oil phase; k ro (S wi ) is the relative permeability of the oil phase corresponding to the irreducible water saturation, in decimal; The aqueous-phase relative permeability k established according to the Willhite model rw has the following expression as formula (3): where: k rw is the relative permeability of the aqueous phase, in decimals; S w is the water saturation, in decimals; S wi is the irreducible water saturation, in decimals; S or is the residual oil saturation, in decimals; n w is the characteristic parameter of the relative permeability of the aqueous phase; k rw (S or ) is the relative permeability of the aqueous phase at the residual oil saturation, in decimals; The expression of the capillary pressure curve of the core established based on the J-function model is as follows in formula (4): where: p c is the capillary pressure, with the unit of MPa; S w is the water saturation, dimensionless; S wi is the irreducible water saturation, dimensionless; M and N are capillary pressure curve characteristic parameters, dimensionless; is porosity, dimensionless; k is absolute permeability, with the unit of um 2 .

6. The method for calculating the imbibition characteristic curve of a fractured metamorphic buried hill reservoir according to claim 1, wherein: In step S5, taking the axial direction of the core as the z direction and the radial direction as the r direction, the expression of the imbibition mathematical model established in a cylindrical coordinate system is as follows in formula (5): Where: The expression of ψ is: where: u w is the viscosity of water, with the unit of mPa·s; u o is the viscosity of crude oil, with the unit of mPa·s; k rw is the relative permeability of the water phase, dimensionless; k ro is the relative permeability of the oil phase, dimensionless; p c is the capillary pressure, with the unit of MPa; S w is the water saturation, dimensionless; k is the absolute permeability, with the unit of um 2 ; t is the displacement time, with the unit of h; The expression of the imbibition mathematical model in the cylindrical coordinate system is discretized by difference to obtain the expression of the imbibition numerical solution as follows in formula (7): Where: c ij = 1 - a ij - b ij - d ij - e ij (12) Assume that all the imbibition characteristic parameters of the matrix core are known parameters, and the relative permeability of the oil phase $k$ ro , the relative permeability of the water phase $k$ rw and the capillary pressure $P$ c are calculated from Formulas 2 - 4; Substitute the obtained oil-phase relative permeability \(k\) ro , water-phase relative permeability \(k\) rw and capillary pressure \(P\) c into the discretized imbibition mathematical model composed of Formulas 7 - 12 to calculate the variation of the theoretical imbibition recovery factor with time.

7. The imbibition characteristic curve calculation method for fractured metamorphic buried hill reservoirs according to claim 1, characterized in that: The imbibition characteristic parameters of the matrix core in step S6 include the oil-phase relative permeability characteristic parameter n o , the water-phase relative permeability characteristic parameter n w and the capillary force curve characteristic parameters M and N.

8. The method for calculating the imbibition characteristic curve of a fractured metamorphic buried hill reservoir according to claim 1, wherein: The specific method for fitting and obtaining reasonable imbibition characteristic parameters in step S6 by using the least square method and the genetic algorithm is: Given a set of initial values of imbibition characteristic parameters, a set of curves of the theoretical imbibition recovery factor varying with time, R0(t), is calculated by steps S4 and S5; taking the scatter plot of the experimental imbibition recovery factor varying with time, E(t), obtained in step S3 as the fitting target, using the imbibition characteristic parameters as the optimization variables, and continuously iteratively fitting the theoretical imbibition recovery factor, R(t), and the experimental imbibition recovery factor, E(t), by the least squares method, the fitting error model is If σ ≤ 0.01, the error meets the standard, and reasonable imbibition characteristic parameters are output; if σ > 0.01, the genetic algorithm is used to optimize the imbibition characteristic parameters until σ ≤ 0.01, and the characteristic parameters within the error range are obtained; According to step S6, respectively obtain the imbibition characteristic parameters of matrix cores of different types.

9. The calculation method of the imbibition characteristic curve of the fractured metamorphic buried hill reservoir according to claim 1, characterized in that: The step S7 is to draw the imbibition characteristic curves of different types of matrix rock blocks, specifically: the imbibition characteristic curves take the water saturation S w as the X-axis, and k ro , k rw and P c as the Y-axis respectively. The oil-phase relative permeability k ro curve, the water-phase relative permeability k rw curve and the capillary pressure curve of different types of cores are drawn respectively according to the expressions of the oil-phase relative permeability k rw established based on the Willhite model, the expressions of the water-phase relative permeability k rw established based on the Willhite model, and the expression of the water-phase relative permeability k rw established based on the Willhite model.

10. The method for calculating the imbibition characteristic curve of fractured metamorphic buried hill reservoirs according to claim 1, wherein: The geological model in step S8 includes a three-dimensional structural model, a fracture density model, a fracture network model, a fracture property parameter model, a matrix system property model, and a fluid model; the geological model is established by using Petrel software in combination with data such as logging, coring, seismic, and stress analysis in the target area; the specific method for conducting numerical simulation by means of permeability zoning is as follows: The matrix system adopts the method of permeability zoning, and the obtained oil and water relative permeabilities and capillary pressure curves of matrix cores of different types are respectively brought into the corresponding reservoirs to conduct history matching and predict the recovery rate.

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