Method for determining the normalization of reservoir capillary pressure curves

Abstract

The application belongs to the field of oil and gas reservoir evaluation research, and discloses a method for determining the normalization of a reservoir capillary pressure curve, which comprises the following steps: S01: obtaining the normalized porosity and permeability parameters of a target unit from the test porosity and permeability parameters of a single sample; S02: changing a plunger sample with a diameter of d and a length of h into a square equivalent sample with a side length of a and a length of h, and a 2 h = π(d / 2) 2 h, stacking multiple square equivalent samples of the target unit; S03: calculating the mercury injection and withdrawal saturations of each pressure point of the normalized capillary pressure curve; and S04: calculating the normalized curve characteristic parameters by using the mercury injection and withdrawal saturation data and the porosity and permeability parameters of the normalized capillary pressure curve. The application can avoid the constraints of J function fitting operation, accurately calculate the average capillary pressure curve, merge multiple sample curves into a simple curve consistent with the sample parent curve, and has both characteristic parameters and pore distribution diagrams, so that the sample capillary pressure curve parameter evaluation system can be used to intuitively compare the advantages and disadvantages of the target unit.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas reservoir evaluation research, specifically involving a method for determining the normalization of reservoir capillary pressure curves. Background Technology

[0002] Capillary pressure curves are widely used in oilfield research. A single-point capillary pressure curve obtained in the laboratory only represents the situation at that point in the reservoir. Multiple capillary pressure curves must be normalized to compare the advantages and disadvantages between oilfields or target layers / blocks (target units), providing a basis for decision-making such as scheme formulation and perforation principles. The J function is currently the main method for curve normalization. In the normalization process, the J function undergoes a power function fitting operation, reducing the capillary pressure curve from two curves to one with no parameters. Its normalization process is only related to the mercury intrusion porosimetry curve, omitting information from the mercury removal curve.

[0003] Chinese patent document CN106338592A discloses a new method for calculating reservoir average capillary pressure. However, numerous other documents and patents, such as the journal article "Classification of Average Capillary Pressure Functions and Its Application in Fluid Saturation Calculation" (Hu Yong et al., Petroleum Exploration and Development, 2012.12, 39(6), 733-738), have not fundamentally escaped the constraints of fitting calculations when discussing the normalization of reservoir capillary pressure curves, resulting in low accuracy. Therefore, it is necessary to seek a new method for accurately calculating the normalized curve, utilizing a parameter evaluation system for the sample to evaluate the pore structure of the target unit and define its quality.

[0004] The specific problems encountered when using the J-function to normalize reservoir capillary pressure curves are summarized as follows:

[0005] Currently, the J function is used to analyze different capillary pressure curves P. c -S w Convert to JS wn The coordinates are used to derive the J function from the concentrated points. This method only involves mercury injection data and the values ​​of porosity (φ) and permeability (K), as shown in Formula 1. Its accuracy is not high, therefore, this method is limited in practical applications. The main reasons are as follows:

[0006]

[0007] In Formula 1: J(S wn The -J function is dimensionless; P c - Capillary pressure, MPa; σ - Interfacial tension, N·m -1 ; - Porosity, %; θ - Contact angle, (°); k - Permeability, 10 -3 μm 2 S wn-Standardized saturation of the sample

[0008] 0≤S wn ≤1; S w - Sample water saturation, %; S wi - Sample bound water saturation, %.

[0009] ①The J function is a semi-empirical formula derived based on the rock capillary bundle model. However, research has found that the capillary bundle model differs significantly from the pore structure of actual rock cores (see...). Figure 1 A more accurate pore network model should be described; however, the J-function expression, which only introduces two parameters, porosity and permeability, cannot fully reflect the differences in pore structure between different samples; especially in conglomerate reservoirs and volcanic reservoirs, the correlation between porosity and permeability is extremely poor (taking the Kexia Formation in a certain area of ​​the Karamay Oilfield as an example: data points were not screened, see...). Figure 2 The goodness of fit is too small, making it difficult to obtain a unified J function;

[0010] ② The accuracy of the J function is not high: The J function is based on finding a trend line from scatter points, and is a graphical representation of a power function, using the goodness-of-fit R-squared. 2 To determine the reliability of a trend line, the goodness of fit generally deviates from 1 (see...). Figure 3 The improved model of the J function is still based on the J function's representation model and does not fundamentally improve upon it. Therefore, in actual scientific research and production, it is common to use K-MEANS cluster analysis on individual sample curves, based on well sections and lithology, or on reservoir quality coefficients of samples. The classification is used to improve the goodness of fit of the J function so that the capillary pressure curves of these different samples are parallel or coincident with each other on the semi-logarithmic coordinate system. Therefore, it is not suitable to conduct normalized comparative studies by oil field, zone, or stratum, because good, medium, and poor samples exist in a target unit.

[0011] ③ Because permeability is directional, the permeability at the same point varies depending on the direction of the flow: the permeability at the same point can have multiple different values. In sample selection, permeability in different directions will inevitably differ; the permeability along the flow direction can differ by several times or even tens of times from the permeability perpendicular to the flow direction. Many studies use the J function to calculate oil saturation. Clearly, permeability sampling analysis at the same point in different directions will result in different saturation values ​​for the same reservoir or the same point, which is obviously a paradox.

[0012] ④ The J function only covers the mercury ingress curve information and does not simultaneously normalize the mercury exgress curve. The resulting J function curve does not provide the pore size, permeation situation and corresponding characteristic parameters of the curve like the sample curve, which is not convenient for intuitive comparison between target units.

[0013] ⑤ The J function can only normalize curves with the same maximum injection pressure. Curves with different maximum injection pressures will have different meanings of their standardized saturation. That is, the meanings of their J functions are different, and they cannot be normalized. For the same sample, changes in the maximum experimental pressure will lead to variations in S... wi The dynamic changes in the value result in different J function values ​​at the same pressure point for the same sample. Obviously, the meaning of normalization (averaging) is not scientific enough.

[0014] Since Leverrett invented the J-function in 1941, its drawbacks have drawn increasing criticism from industry professionals. However, due to the lack of a more suitable normalization method for capillary pressure curves, the J-function continues to be used in mines. Therefore, there is an urgent need to develop a precise normalization method for capillary pressure curves that can encompass information on the mercury ingress and egress curves of samples. This normalized curve should have accurate porosity and permeation data and their corresponding characteristic parameters, and the sample's parameter evaluation system (porosity and permeation data and their corresponding characteristic parameters) should be used to provide technical support for the effective comparison of target units. Summary of the Invention

[0015] This invention aims to solve at least one technical problem existing in the prior art or related technologies, and provides a method for determining the normalization of reservoir capillary pressure curves. This method can avoid the constraints of J-function fitting operations and accurately calculate an average capillary pressure curve that can represent the target unit reservoir. This allows complex multiple curves to be merged into a simple curve, and this normalized capillary pressure curve is consistent with the parent capillary pressure curve of the sample. It has corresponding characteristic parameters and a matching pore distribution map, so that the parameter evaluation system of the sample capillary pressure curve can be used to intuitively compare the quality of the target unit.

[0016] To achieve the above technical objectives, the present invention adopts the following technical solution:

[0017] A method for determining the normalization of reservoir capillary pressure curves, the method comprising the following steps:

[0018] Step S01: Transform the plunger sample with diameter d and length h into a square equivalent sample with side length a and length h, and a 2 *h=π(d / 2) 2 *h means that the porosity and permeability of the square equivalent sample are exactly the same as those of the plunger sample. Stacking multiple square equivalent samples of the target unit is equivalent to increasing the volume of the mercury porosimeter sample tube.

[0019] Step S02: Calculate the normalized pore permeability parameters of the target unit from the test pore permeability parameters of a single sample. The pore permeability parameters include pore volume, porosity, and permeability.

[0020] Step S03: Calculate the mercury saturation at each pressure point on the normalized capillary pressure curve;

[0021] Step S04: Directly calculate the characteristic parameters of the normalized curve using the mercury saturation data of the ingress and egress of the normalized capillary pressure curve and the pore permeability parameters.

[0022] Furthermore, in step S01, stacking multiple square equivalent samples of the target unit together is equivalent to increasing the volume of the mercury porosimeter sample tube, which is completely consistent with the principle used for direct analysis of a single sample. The principle conforms to the standard requirements of "Determination of Capillary Pressure Curves in Rocks", that is, mercury is a non-wetting phase for most solid interfaces, and the pore radius is inversely proportional to the capillary pressure. The higher the test pressure, the smaller the measured capillary radius. The relationship conforms to the following formula:

[0023]

[0024] In the formula: p c - The numerical value of capillary pressure, in MPa;

[0025] σ - interfacial tension, N / m;

[0026] θ - contact angle, °;

[0027] r - capillary radius, μm.

[0028] Further, in step S02, the normalized penetration rate of the target unit is calculated, which specifically includes the following steps:

[0029] According to Darcy's law, the average permeability of a single well is treated as an equivalent physical model of a parallel mercury injection plunger sample; the average permeability of the target unit is determined based on the average permeability of a single well, and multiple wells are treated as an equivalent physical model of a heterogeneous series mercury injection plunger sample.

[0030] Parallel model:

[0031] Series model:

[0032] The combined formula of the parallel and series models is as follows. The average permeability of the target unit is obtained from the combined formula.

[0033] Comprehensive:

[0034] In the above formula: k - the permeability of the target unit, mD;

[0035] y - The number of wells in the target unit;

[0036] k x - Average permeability of a single well, mD;

[0037] k i - Permeability of the sample point, mD;

[0038] x - The number of samples to be calculated for a single well;

[0039] μ - Viscosity of injected mercury, (mPa·s);

[0040] In the parallel model: ΔP is the pressure drop of the core, ΔP1, ΔP2, ..., ΔP x Pressure drop of core samples 1, 2, and x, in MPa; ΔP = ΔP1 = ΔP2 ... = ΔP x Q = Q1 + Q2 + Q x , (cm 3 );

[0041] In the series model: Q is the seepage flow rate of the core, Q1, Q2...Q y The seepage flow rate (cm) of core samples 1, 2, ..., y. 3 ), Q = Q1 = Q2....... = Q y The total pressure drop ΔP = ΔP1 + ΔP2 + ... + ΔP y , MPa.

[0042] Furthermore, in step S02, the calculation of the normalized pore volume of the target element specifically includes the following steps:

[0043] The normalized pore volume is calculated as the arithmetic mean of the pore volumes of the target unit sample:

[0044]

[0045] In the formula: v i - The pore volume of the i-th core sample, in cm³ 3 ;

[0046] v-Normalized pore volume, cm 3 ;

[0047] n - the total number of normalized core samples, in units.

[0048] Furthermore, in step S02, the normalized porosity of the target unit is calculated, which specifically includes the following steps:

[0049] Normalized porosity is calculated by weighting the volume of the target unit sample:

[0050]

[0051] In the formula: Ф i - Porosity of the i-th core sample, %;

[0052] Ф - Porosity of the normalized report, %;

[0053] n - the total number of normalized core samples, in units.

[0054] Furthermore, in step S03, the mercury saturation at each pressure point of the normalized capillary pressure curve is calculated using the following formula:

[0055]

[0056] Where: n - the total number of normalized core samples;

[0057] V i - represents the pore volume of the i-th sample, in cm³. 3 ;

[0058] J- represents the serial number of the mercury entry and exit analysis record point, J∈{1,……,13,15};

[0059] S Ji进、退 - are respectively the i-th sample corresponding to r J Record the mercury saturation at the entry and exit points, in %;

[0060] S J进 -The target unit corresponds to r J Average injected mercury saturation at the recording points, %;

[0061] S J退 -The target unit corresponds to r J Average exit mercury saturation at the recording points, %.

[0062] Furthermore, in step S03, all samples of a target unit are connected in parallel to obtain a single result. During mercury injection, the sample tube of the mercury porosimeter is expanded using an equivalent physical model of the mercury porosimeter plunger sample, even though such a type of mercury porosimeter is impossible in reality, and the sample cup used in the experiment cannot be made infinitely large. However, through the equivalent physical model of the mercury porosimeter plunger sample, each sample can be considered as having an invisible non-permeable barrier. When the mercury saturation at one pressure measurement point is completed, the next mercury saturation can only begin, until the maximum mercury injection pressure loading and the maximum mercury saturation measurement are completed. Mercury removal is similar, with one sample completing the experiment. The samples can be considered as independent experiments, with no interference between them.

[0063] In this way, the analysis results recorded for each experimental sample are superimposed with the amount of mercury entering and leaving the sample, which is equivalent to analyzing a "large plunger sample". The superimposed amount of mercury entering and leaving the sample is divided by the normalized total pore volume of the sample, and the resulting mercury saturation is the mercury saturation of the normalized capillary pressure curve of a target unit.

[0064] Further, in step S04, the characteristic parameters include, but are not limited to: displacement pressure, median pressure, maximum connected pore radius, median pore radius, average pore radius, mean radius, maximum mercury saturation, final residual mercury saturation, maximum instrument exit efficiency, sorting coefficient, structural coefficient, porosity peak position, permeability peak position, permeability peak value, porosity peak value, skewness, relative sorting coefficient, characteristic structural parameters, homogeneity coefficient, and permeability contribution value.

[0065] Compared with the prior art, the beneficial effects of the present invention are:

[0066] (1) The direct normalization method of capillary pressure curve can be used as an effective means to reflect the pore structure characteristics of the target unit. It is applicable to reservoir evaluation between target units of various oil and gas reservoirs; especially for conglomerate reservoirs and volcanic reservoirs with poor correlation between porosity and permeability, the effect is more direct.

[0067] (2) The direct normalization method of capillary pressure curve ignores the influence of poor fit of pore and permeability on the normalization results. It introduces the test standard GB / T29171-2012 of a single sample into the normalization process, which expands the capacity of the sample tube. It is equivalent to the results obtained by direct analysis and testing of the core selected by a target unit. It can achieve the purpose of summarizing the mercury intrusion curves of multiple samples in a target unit by the analysis results of a large sample of a target unit.

[0068] (3) The direct normalization method is based on the equivalent physical model of the rock core, which is superior to the J-function capillary bundle model and the results obtained are more intuitive than those of the J-function.

[0069] (4) The normalized capillary pressure curve obtained based on the equivalent physical model is the result of accurate calculation, not the result of fitting operation; the result obtained by this method is independent of the directionality of permeability, and its final display result is completely consistent with the original curve of the sample. It does not lose the information of the mercury removal curve and has matching pore structure characteristic parameters. The sample's parameter evaluation system can be used to directly quantify and evaluate the quality of the target unit. Attached Figure Description

[0070] Figure 1 This is a comparison diagram of real core images and capillary bundle models, in which... Figure 1 (a) is a large-screen scan image of SEM; Figure 1 (b) is a step-by-step CT scan image. Figure 1 (c) is a thin section diagram of the casting. Figure 1 (d) is a model diagram of the capillary bundle;

[0071] Figure 2 This is a porosity-permeability relationship diagram for a certain area.

[0072] Figure 3A comparison graph showing the fitting relationship between the power function and the exponential function of the J function in a certain well area of ​​a certain oilfield;

[0073] Figure 4 This is a flowchart illustrating the method for determining the normalization of reservoir capillary pressure curves in an embodiment of the present invention.

[0074] Figure 5 This is a physical model equivalent to multiple plunger samples in the embodiments of the present invention, wherein Figure 5 (a) is a plunger sample. Figure 5 (b) is an equivalent physical model;

[0075] Figure 6 This is a parallel model of a single mercury injection well according to an embodiment of the present invention;

[0076] Figure 7 This is a multi-well series model for mercury injection according to an embodiment of the present invention;

[0077] Figure 8 This is a graph showing the normalized curve results of an embodiment of the present invention;

[0078] Figure 9 This is a composite graph of the capillary pressure curve and the normalized curve of the sample in the embodiment of the present invention. Detailed Implementation

[0079] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0080] Example 1

[0081] Combination Figure 4-9 As shown in the figure, this invention provides a method for determining the normalization of reservoir capillary pressure curves, the method comprising the following steps:

[0082] Step S01: Transform the plunger sample with diameter d and length h into a square equivalent sample with side length a and length h, and a 2 *h = π(d / 2) 2 *h means that the porosity and permeability of the square equivalent sample are exactly the same as those of the plunger sample. Stacking multiple square equivalent samples of the target unit is equivalent to increasing the volume of the mercury porosimeter sample tube.

[0083] Specifically, the sample capillary pressure curve is a characteristic parameter calculated based on saturation data and pore and permeation experimental data. It also includes capillary pressure curves (mercury ingress and regression curves) and pore distribution diagrams. It should be the template for the normalized curve.

[0084] In this embodiment of the invention, a plunger sample with a diameter of 2.5cm x 2.5cm is used, which is then transformed into a 4.9cm plunger sample. 2 *2.5cm (where 1.25 * 1.25 * 3.14 = 4.9cm) 2 A square equivalent sample, meaning a square equivalent sample with the same porosity and permeability as the plunger sample, is stacked to enlarge the volume of the mercury porosimeter sample tube. Figure 5 As shown in (b). This method is entirely consistent with the principle used in direct analysis of a single sample, and the principle fully complies with the standard requirements of "Determination of Capillary Pressure Curves in Rocks". That is, mercury is a non-wetting phase at most solid interfaces, and the pore radius is inversely proportional to the capillary pressure. The higher the test pressure, the smaller the measured capillary radius, as shown in Formula 2.

[0085]

[0086] In the formula: p c - The numerical value of capillary pressure, in MPa;

[0087] σ - interfacial tension, N / m;

[0088] θ - contact angle, °;

[0089] r - capillary radius, μm.

[0090] Step S02: Calculate the normalized pore permeability parameters of the target unit from the test pore permeability parameters of a single sample. The pore permeability parameters include pore volume, porosity, and permeability.

[0091] (1) Calculate the normalized pore volume of the target element:

[0092] Normalized pore volume is calculated as the arithmetic mean of the pore volumes of the target unit sample:

[0093]

[0094] In the formula: v i - The pore volume of the i-th core sample, in cm³ 3 ;

[0095] v-Normalized pore volume, cm 3 .

[0096] n - the total number of normalized core samples, in units.

[0097] (2) Calculate the normalized porosity of the target element:

[0098] Normalized porosity is calculated based on the volume tradeoff of the target unit sample:

[0099]

[0100] In the formula: Ф i - Porosity of the i-th core sample, %;

[0101] Ф - Porosity of the normalized report, %;

[0102] n - the total number of normalized core samples, in units.

[0103] (3) Calculate the normalized penetration rate of the target unit:

[0104] According to Darcy's law, the average permeability of a single well is calculated as follows: Figure 6 Physical model processing of parallel mercury injection plunger sample plungers (Formula 5); the average permeability of the target unit is determined based on the average permeability of a single well, according to... Figure 7 Physical model processing of heterogeneous series mercury injection plunger sample plunger (Formula 6); the combined formula of the two models is calculated according to Formula 7, and the average permeability of the target unit is obtained from Formula 7.

[0105] Parallel model:

[0106] Series model:

[0107] Comprehensive:

[0108] In the above formula: k - the permeability of the target unit, mD;

[0109] y - The number of wells in the target unit;

[0110] k x - Average permeability of a single well, mD;

[0111] k i - Permeability of the sample point, mD;

[0112] x - The number of samples to be calculated for a single well;

[0113] μ - Viscosity of injected mercury, mPa·s.

[0114] Parallel model: ΔP is the pressure drop of the core, ΔP1, ΔP2, ..., ΔP x Pressure drop of core samples 1, 2, and x, in MPa; ΔP = ΔP1 = ΔP2 ... = ΔP x Q = Q1 + Q2 + Q x , (cm 3 ).

[0115] Series model: seepage flow rate of core Q, Q1, Q2...Q y The seepage flow rate (cm) of core samples 1, 2, ..., y. 3 ), Q = Q1 = Q2....... = Q y The total pressure drop ΔP = ΔP1 + ΔP2 + ... + ΔP y MPa;

[0116] Step S03: Calculate the mercury saturation at each pressure point on the normalized capillary pressure curve, using the following formula:

[0117]

[0118] Where: n - the total number of normalized core samples;

[0119] V i - represents the pore volume of the i-th sample, in cm³. 3 ;

[0120] J- represents the serial number of the mercury entry and exit analysis record point, J∈{1,……,13,15};

[0121] S Ji进、退 - are respectively the i-th sample corresponding to r J Mercury saturation during entry and exit, %;

[0122] S J进 -The target unit corresponds to r J Average injected mercury saturation at the recording points, %;

[0123] S J退 -The target unit corresponds to r J Average exit mercury saturation at the recording points, %.

[0124] The principle of this method is as follows:

[0125] The direct calculation method for the normalized capillary pressure curve can be understood as obtaining a result by connecting all samples of a target unit in parallel. See [link to relevant documentation]. Figure 1Although such a mercury porosimeter is impossible in reality, and the sample cups used in the experiment cannot be made infinitely large, an equivalent physical model using a Φ2.5cm*2.5cm mercury porosimeter plunger sample can be used. Each sample can be considered as having an invisible non-permeable barrier. Under this hypothetical model, after the mercury saturation at one pressure measurement point is completed, the next mercury saturation can only begin, until the maximum mercury ingress pressure and maximum mercury saturation are measured. Similarly, mercury removal is performed on a single sample; samples can be considered as independent experiments without interference. Thus, by superimposing the mercury ingress and removal amounts recorded for each experimental sample, it is equivalent to analyzing a large plunger sample. Dividing the superimposed mercury ingress and removal amounts by the normalized total pore volume of the sample yields the mercury ingress and removal saturation of the normalized capillary pressure curve for a target unit. The principle of this method is completely consistent with the results obtained from direct analysis of a single sample, and the principle fully complies with the requirements of "Determination of Rock Capillary Pressure Curves". Moreover, the results obtained are theoretically independent of the directionality of the experimental sample, and the normalized saturation at different pressure points should be unique.

[0126] Based on this, the characteristic parameters of other normalized curves can be directly calculated using the mercury saturation data of the ingress and egress from the normalized capillary pressure curve and the pore permeability parameters. These parameters include: displacement pressure, median pressure, maximum connected pore radius, median pore radius, average pore radius, mean radius, maximum mercury saturation, final residual mercury saturation, maximum instrument exit efficiency, sorting coefficient, structural coefficient, porosity peak position, permeability peak position, permeability peak value, porosity peak value, skewness, relative sorting coefficient, characteristic structural parameters, homogeneity coefficient, and permeability contribution value. The calculation formulas are derived from the relevant formulas built into the mercury porosimeter of China National Petroleum Corporation (CNPC), see Table 1.

[0127] Table 1. Calculation Formulas for Main Parameters of Capillary Pressure Curve

[0128]

[0129] Among them, P d - Threshold pressure; r - Average pore throat radius, μm; W e - Mercury removal efficiency, %; S i - Mercury saturation at a certain point, %; Ф p - Structural coefficient, dimensionless quantity; S kp - Skewness, a dimensionless quantity; α - Homogeneity coefficient, a dimensionless quantity; S p - Sorting coefficient, dimensionless quantity; △S i - Corresponding to a certain range of mercury saturation, %, in calculus it is equivalent to ds; K j - Penetration contribution value, %; r max - Maximum throat radius, μm; D - Relative sorting coefficient, dimensionless; DM - Mean radius, dimensionless quantity; D i - Diameter of the pore throat at point i, in μm; r i - Radius of the pore throat at point i, μm; ψ i - The dimensionless throat radius at point i; D r - Coefficient of variation, dimensionless quantity; ds - Mercury saturation corresponding to a certain interval, %; K p - Peak state, dimensionless quantity; S max - Cumulative mercury saturation (%) at the highest experimental pressure; S min - Residual mercury saturation, %; R M - Main throat radius, μm; Ψ a i - represents the ψ value corresponding to a cumulative mercury saturation of Si% on the normal probability curve; j m - The injection point number when the cumulative penetration contribution reaches 80%.

[0130] Methods for comparing the quality of samples using these parameters are detailed in various mercury porosimetry literature and textbooks. These are specific methods for comparing the quality of capillary pressure curves of samples, and also specific methods for quantitatively comparing different target units using normalized curves.

[0131] Example 2

[0132] Taking three samples from two wells in the **group** section of the **well area** as an example, Table 2 shows the original data of the three samples from the two wells. The normalization results obtained using the above normalization method are shown in Table 3. A template diagram of the results is shown below. Figure 8 This is consistent with the template image of the samples. The normalized curve extracted from the template image always lies in the middle of the three experimental sample curves, exhibiting the characteristics of averaging three samples. See [link to template image]. Figure 9 .

[0133] Table 2. Original data of 3 samples from 2 wells

[0134]

[0135]

[0136] Table 3. Normalization results of three samples from two wells

[0137]

[0138] The reservoir properties of the **series** in the **well area** are far superior to those of the underlying layers. Developing with a single layer system would result in differential water flooding and water channeling, thus reducing recovery. Therefore, layered development is necessary. Since the reservoir pore structure parameters of this section are similar to those of the X oilfield, and drawing on the successful experience of the 300m reverse five-point well pattern development in the X oilfield, the **series** in the **well area** should also adopt a 300m reverse five-point well pattern development.

[0139] The above description is merely an embodiment of this application and is not intended to limit the invention. Any modifications, equivalent substitutions, and improvements made within the scope of this application should be included within the protection scope of this invention.

Claims

1. A method for determining the normalization of reservoir capillary pressure curves, characterized in that, The method includes the following steps: Step S01: Transform the plunger sample with diameter d and length h into a square equivalent sample with side length a and length h, and a 2 *h=π(d / 2) 2 *h means that the porosity and permeability of the square equivalent sample are exactly the same as those of the plunger sample. Stacking multiple square equivalent samples of the target unit is equivalent to increasing the volume of the mercury porosimeter sample tube. Step S02: Calculate the normalized pore permeability parameters of the target unit from the test pore permeability parameters of a single sample. The pore permeability parameters include pore volume, porosity, and permeability. Step S03: Calculate the mercury saturation at each pressure point on the normalized capillary pressure curve; Step S04: Directly calculate the characteristic parameters of the normalized curve using the mercury saturation data of the ingress and egress of the normalized capillary pressure curve and the pore permeability parameters.

2. The method for determining the normalization of reservoir capillary pressure curves according to claim 1, characterized in that, In step S01, multiple square equivalent samples of the target unit are stacked together, which is equivalent to increasing the volume of the mercury porosimeter sample tube. This is completely consistent with the principle used for direct analysis of a single sample. The principle meets the requirements of the standard "Determination of Capillary Pressure Curves in Rocks", that is, mercury is a non-wetting phase at most solid interfaces, and the pore radius is inversely proportional to the capillary pressure. The higher the test pressure, the smaller the measured capillary radius. The relationship conforms to the following formula: In the formula: p c - Capillary pressure value, MPa; σ -Interfacial tension, N / m; θ -Contact angle, °; r - Capillary radius, μm.

3. The method for determining the normalization of reservoir capillary pressure curves according to claim 1, characterized in that, In step S02, the normalized penetration rate of the target unit is calculated, which specifically includes the following steps: According to Darcy's law, the average permeability of a single well is treated as an equivalent physical model of a parallel mercury injection plunger sample; the average permeability of the target unit is determined based on the average permeability of a single well, and multiple wells are treated as an equivalent physical model of a heterogeneous series mercury injection plunger sample. Parallel model: Series model: The combined formula of the parallel and series models is as follows. The average permeability of the target unit can be obtained from the combined formula. Comprehensive: In the above formula: k - The penetration rate of the target unit, mD; y - The number of wells in the target unit; k x - Average permeability of a single well, mD; k i - Permeability of the sample point, mD; x - The number of samples to be calculated per well; μ - Viscosity of injected mercury, mPa s; In the parallel model: ΔP is the pressure drop of the core, ΔP1, ΔP2, ..., ΔP x Pressure drop of core samples 1, 2, and x, in MPa; △P=△P1=△P2......=△P x ,Q=Q1+Q2.......+Q x ,(cm 3 ); In the series model: Q represents the seepage flow rate of the core, Q1, Q2, ..., Q... y The seepage flow rate (cm) of core samples 1, 2, ..., y. 3 ), Q=Q1=Q2.......=Q y The total pressure drop ΔP = ΔP1 + ΔP2 + ... + ΔP y , MPa.

4. The method for determining the normalization of reservoir capillary pressure curves according to claim 3, characterized in that, In step S02, the calculation of the normalized pore volume of the target element specifically includes the following steps: The normalized pore volume is calculated as the arithmetic mean of the pore volumes of the target unit sample: In the formula: v i -No. i Pore ​​volume of rock core, cm 3 ; v - Normalized pore volume, cm³ 3 ; n - The total number of normalized core samples.

5. The method for determining the normalization of reservoir capillary pressure curves according to claim 4, characterized in that, In step S02, the normalized porosity of the target unit is calculated, which specifically includes the following steps: Normalized porosity is calculated based on the volume tradeoff of the target unit sample: In the formula: Ф i -No. i Porosity of the rock core, % Ф - Porosity in the normalized report, % n - The total number of normalized core samples.

6. The method for determining the normalization of reservoir capillary pressure curves according to claim 5, characterized in that, In step S03, the mercury saturation at each pressure point of the normalized capillary pressure curve is calculated using the following formula: In the formula: n- Total number of normalized core samples; V i -for the first i Pore ​​volume of block sample, cm 3 ; J - represents the serial number of the mercury entry and exit analysis record point, J∈{1,……,13,15}; S Ji进、退 - are respectively the i block sample corresponding to r J Record the mercury saturation at the entry and exit points, % S J进 -Target unit corresponds to r J Average injected mercury saturation at the recording points, % S J退 -Target unit corresponds to r J Average mercury saturation at the recording points, %.

7. The method for determining the normalization of reservoir capillary pressure curves according to claim 6, characterized in that, In step S03, all samples of a target unit are connected in parallel to obtain a single result. During mercury injection, the sample tube of the mercury intrusion porosimeter is expanded using an equivalent physical model of the mercury intrusion plunger sample. Each sample can be considered as having an invisible non-permeable barrier. Once the mercury saturation at one pressure measurement point is completed, the next mercury saturation can only begin, until the maximum mercury injection pressure loading and maximum mercury saturation measurement are completed. Mercury removal is similar, with one sample completing the experiment. The samples can be considered as independently conducted experiments, with no interference between them. In this way, the analysis results recorded for each experimental sample are superimposed with the amount of mercury entering and leaving the sample, which is equivalent to analyzing a "large plunger sample". The superimposed amount of mercury entering and leaving the sample is divided by the normalized total pore volume of the sample, and the mercury saturation obtained is the mercury saturation of the normalized capillary pressure curve of a target unit.

8. The method for determining the normalization of reservoir capillary pressure curves according to any one of claims 1-7, characterized in that, In step S04, the characteristic parameters include: displacement pressure, median pressure, maximum connected pore radius, median pore radius, average pore radius, mean radius, maximum mercury saturation, final remaining mercury saturation, maximum instrument exit efficiency, sorting coefficient, structural coefficient, porosity peak position, permeability peak position, permeability peak value, porosity peak value, skewness, relative sorting coefficient, characteristic structural parameters, homogeneity coefficient, and permeability contribution value.

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