Method for evaluating maximum daily fluid production capacity of single well in extra-high water cut period

Abstract

The invention discloses a method for evaluating the maximum daily fluid production capacity of a single well in an extra-high water cut period. The method comprises the steps that static reservoir characteristic parameters and dynamic production data of a target block are collected; calculating dimensionless liquid production indexes of the oil well under different water contents, and drawing an actual dimensionless liquid production index curve; drawing a theoretical dimensionless liquid production index curve based on actually measured relative permeability data; correcting a theoretical dimensionless liquid production index curve according to an actual curve; based on the corrected theoretical dimensionless fluid production index curve, the maximum specific fluid production index of the oil well is calculated; calculating the maximum production pressure difference delta P (degassing) considering the degassing influence; a new critical sand production pressure difference calculation model is established based on a production actual correction cohesion calculation formula; calculating oil well critical sand production pressure difference based on the new model; the minimum value of delta P degassing and delta P sand production is selected and determined as the maximum extraction liquid production pressure difference of the oil well; and calculating the maximum daily fluid production capacity of the oil well. The method can effectively guide evaluation of the maximum liquid production capacity of the oil well in the ultrahigh water cut period, and the oilfield development effect is improved through liquid extraction.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas field development, and particularly relates to a method for evaluating the maximum daily liquid production capacity of a single well in the extra-high water cut period. Background Art

[0002] Bottom water reservoirs are important reservoir types in China. Taking the Bohai Oilfield as an example, the recoverable reserves of bottom water reservoirs account for more than 50% of the total recoverable reserves. After the oil wells in this type of reservoir are put into production, the water cut rises rapidly and the production decreases quickly. Greatly increasing liquid production in the extra-high water cut stage is one of the main ways to ensure stable production in the oilfield. For offshore oilfields, due to the limitation of the liquid treatment capacity of platform facilities, the oilfield cannot fully increase liquid production to release production capacity. Therefore, it is urgent to carry out the evaluation of the maximum daily liquid production capacity of the oilfield, improve the liquid treatment capacity through the transformation of platform facilities, fully release the production capacity of the oilfield, and improve the oilfield development effect.

[0003] At present, the evaluation of the maximum daily liquid production capacity of oil wells mainly determines the maximum specific liquid production index through the theoretical dimensionless liquid production index curve, and at the same time determines the maximum daily liquid production capacity of oil wells in combination with the maximum liquid production pressure difference. Due to the deviation between the theoretical dimensionless liquid production index curve and the actual situation in the extra-high water cut period, it is impossible to accurately predict the maximum specific liquid production index. On the other hand, the determination of the maximum production pressure difference mainly comprehensively considers the influence of formation gas evolution and sand production. There are mainly two methods for determining the critical sand production pressure difference. One is the field test of enlarging the pressure difference, and the post-judgment is carried out according to the actual sand production test results. Since this test often has a destructive impact on the normal production of oil wells, it is less used in practice. The other method is to predict according to the critical sand production bottom hole flowing pressure calculation model obtained from the Mohr-Coulomb rock failure criterion. Most of the parameters involved in the model are obtained through the test data of logging and geophysical exploration, and the cohesion force among them is mainly calculated through empirical formulas. The empirical formulas cannot well apply to the objective reality of different oilfields. Therefore, it is impossible to well determine the maximum production pressure difference. Summary of the Invention

[0004] The present invention is proposed to solve the problems existing in the prior art, and its purpose is to provide a method for evaluating the maximum daily liquid production capacity of a single well in the extra-high water cut period.

[0005] The present invention is achieved by the following technical solutions:

[0006] A method for evaluating the maximum daily liquid production capacity of a single well in the extra-high water cut period, comprising the following steps:

[0007] S1. Collect static reservoir characteristic parameters and dynamic production data of the target block, specifically:

[0008] S11. Based on the logging and geophysical exploration related test data of the target block, collect and collate the static reservoir characteristic parameters of oil wells in different horizons; the static reservoir characteristic parameters include rock density, shale content, longitudinal wave velocity, oil layer thickness, Poisson's ratio, elastic cutoff BIOT, relative permeability data, etc.

[0009] S12. Based on the production dynamic database of oil wells in the target block, collect the actual dynamic production data of oil wells in different horizons; the dynamic production data includes water cut, liquid production per day at different water cuts, and the dynamic data of production pressure difference changing with time at different water cuts.

[0010] S2. Calculate the dimensionless liquid production index of oil wells at different water cuts, and draw the actual dimensionless liquid production index curve, specifically:

[0011] Based on the actual dynamic production data of a large number of high water cut wells in the target block, calculate the actual dimensionless liquid production index of oil wells at different water cuts according to formulas (1 - 2), and draw the relationship curve of water cut f w ~actual dimensionless liquid production index to obtain the actual dimensionless liquid production index curve;

[0012]

[0013] In formulas (1 - 2): J L represents the specific liquid production index, with the unit of m 3 / (d·MPa·m); Q L is the liquid production per day, with the unit of m 3 / d; ΔP is the production pressure difference, with the unit of MPa; h is the oil layer thickness, with the unit of m; represents the actual dimensionless liquid production index, dimensionless; J L0 is the specific liquid production index at the water - free stage, with the unit of m 3 / (d·MPa·m); J L0 is obtained by calculating through formula (1), referring to the specific liquid production index when the water cut is 0.

[0014] S3. Based on the measured relative permeability data, draw the theoretical dimensionless liquid production index curve, specifically:

[0015] S31. Combine the measured relative permeability data of the target block to calculate the water cut at different oil saturation levels;

[0016] The calculation formula for the water cut is:

[0017]

[0018] In the formula: f w represents the water cut, in decimals, dimensionless; K ro represents the relative permeability of the oil phase, in decimals, dimensionless; Krw is the relative permeability of the water phase, in decimals, dimensionless; μ w is the viscosity of the formation water, in mPa·s; μ o is the viscosity of the formation crude oil, in mPa·s;

[0019] S32. Calculate the dimensionless liquid production index at different oil saturations;

[0020] The calculation formula for the dimensionless liquid production index at different oil saturations is:

[0021]

[0022] In the formula: represents the theoretical dimensionless liquid production index, dimensionless; K roc is the relative permeability of the oil phase during the water-free period, in decimals, dimensionless; K ro represents the relative permeability of the oil phase, in decimals, dimensionless; K rw is the relative permeability of the water phase, in decimals, dimensionless; μ w is the viscosity of the formation water, in mPa·s; μ o is the viscosity of the formation crude oil, in mPa·s;

[0023] S33. Combine the water cut at different oil saturations obtained in step S31 and the dimensionless liquid production index at different oil saturations obtained in step S32 to plot the water cut f w ~theoretical dimensionless liquid production index relationship curve to obtain the theoretical dimensionless liquid production index curve.

[0024] S4. Correct the theoretical dimensionless liquid production index curve according to the actual curve;

[0025] Due to the changes in the porosity and permeability of the reservoir after high-magnitude water flooding in the ultra-high water cut stage, there is a deviation between the theoretical dimensionless liquid production index curve and the actual curve, and it is impossible to accurately analyze the maximum specific liquid production index of oil wells in the ultra-high water cut stage. According to the actual dimensionless liquid production index of a large number of ultra-high water cut wells in the target oilfield, the present invention fits the dimensionless liquid production index curve in this stage to obtain a corrected theoretical dimensionless liquid production index curve pattern that conforms to the actual production of the oilfield.

[0026] S5. Based on the corrected theoretical dimensionless liquid production index curve in step S4, calculate the maximum specific liquid production index of the oil well, specifically:

[0027] Determine the maximum dimensionless liquid production index of the oil well and the dimensionless liquid production index at the current water cut according to the corrected theoretical dimensionless liquid production index curve pattern, combine with the specific liquid production index at the current water cut of the oil well, and determine the maximum specific liquid production index of the oil well, that is, the maximum liquid production capacity of the oil well, according to formula (5):

[0028]

[0029] In the formula: is the maximum dimensionless liquid production index in the corrected theoretical chart, dimensionless; represents the actual dimensionless liquid production index at any water cut in the corrected theoretical chart, dimensionless; J Lmax is the maximum specific liquid production index, with the unit of m 3 / (d·MPa); J L represents the specific liquid production index at any water cut, with the unit of m 3 / (d·MPa·m);

[0030] S6. Calculate the maximum production pressure difference ΔP considering the influence of gas liberation 脱气 , specifically as follows:

[0031] Based on the PVT test data of the target block, determine the formation saturation pressure and original static pressure of each layer. Referring to the provisions of the industry standard, considering the influence of gas liberation, the minimum bottom-hole flowing pressure allowed is 80% of the formation saturation pressure. Combining with the original static pressure of the formation, calculate the maximum production pressure difference considering the influence of gas liberation for each layer according to formula (6):

[0032] ΔP 脱气 = P e - P b × 0.8 (6)

[0033] In the formula: ΔP 脱气 represents the maximum production pressure difference considering the influence of gas liberation, with the unit of MPa; P e represents the original static pressure of the formation, with the unit of MPa; P b is the formation saturation pressure, with the unit of MPa.

[0034] S7. Based on the production practice of the target block, correct the empirical formula for calculating the cohesive force, and establish a new model for calculating the critical sand production pressure difference, specifically as follows:

[0035] Based on the critical sand production bottom-hole flowing pressure calculation model obtained from the Mohr-Coulomb rock failure criterion, combined with the production pressure difference and the tested reservoir characteristic parameters (the static reservoir characteristic parameters in step S1) of the oil wells in the target block when actual sand production occurs, calculate the cohesive force of the corresponding sand production oil wells, and according to the main influencing factors of the cohesive force, fit the empirical formula for calculating the cohesive force, and substitute it into the above calculation model to obtain a new model for calculating the critical sand production pressure difference applicable to the target block. The specific process is as follows:

[0036] S71. Investigate and obtain the critical sand production bottom-hole flowing pressure calculation model based on the Mohr-Coulomb rock failure criterion. The model expression is as follows:

[0037]

[0038] Where: P wcr represents the critical sand production bottom-hole flowing pressure, with the unit of MPa; σ Zo is the overburden pressure, with the unit of MPa; μ d is the Poisson's ratio, dimensionless; β is the Biot constant of the poroelastic medium, dimensionless; P e represents the original static formation pressure, with the unit of MPa; θ is the internal friction angle, with the unit of °; C represents the formation cohesion, with the unit of MPa;

[0039] The calculation formula for the critical sand production pressure differential (the pressure differential during actual sand production of the oil wells in the target block) is:

[0040] ΔP 出砂 =P e -P wcr (8)

[0041] Where: P wcr represents the critical sand production bottom-hole flowing pressure, MPa; ΔP 出砂 represents the critical sand production pressure differential, MPa, P e represents the original static formation pressure, with the unit of MPa;

[0042] S72. Combining with the actual production dynamics of the target block, sort out the critical production pressure differential during sand production of the oil wells;

[0043] S73. Based on the dimensionless liquid production index curve of the actual oil wells in the target block, sort out the oil wells where the dimensionless liquid production index decreases with the increase of water cut, and record the production pressure differential when the dimensionless liquid production index begins to decrease;

[0044] S74. Take the production pressure differential when sand appears at the wellhead of the oil well and the production pressure differential when the dimensionless liquid production index begins to decrease as the critical sand production pressure differential, and substitute the reservoir geological characteristic parameters obtained from the corresponding oil well tests into formulas (7) to (8), and combine with the cohesion and internal friction relational formula (9) to calculate the cohesion under the critical sand production pressure differential of different oil wells;

[0045] θ=2.564×Log 10 {[(58.93 - 1.785×C)+(58.93 - 1.785×C) 2 +1]+20} (9)

[0046] Where: θ represents the internal friction angle, with the unit of °; C represents the formation cohesion, with the unit of MPa;

[0047] S75. According to the cohesion under the critical sand production pressure differential of different oil wells, combine with the main factors affecting the cohesion recognized through research, and obtain the calculation formula for the cohesion applicable to the target block through fitting,

[0048]

[0049] Where: ρ b is the rock density, with the unit of g / cm 3 ; μ d is the Poisson's ratio, dimensionless; V p is the longitudinal wave velocity, with the unit of m / s; V e is the shale content, %, dimensionless;

[0050] The main factors affecting the cohesion include rock density, Poisson's ratio, longitudinal wave velocity and shale content;

[0051] S76. Substitute the cohesion calculation formula (9) under the critical sand production pressure difference of different oil wells and the cohesion calculation formula (10) applicable to the target block into the critical sand production pressure difference calculation model (7) based on the Mohr-Coulomb rock failure criterion and the calculation formula (8) of the critical sand production pressure difference to obtain a new calculation model for the critical sand production pressure difference of oil wells applicable to the target block.

[0052] S8. Calculate the critical sand production pressure difference of the oil well based on the new model;

[0053] Substitute the reservoir characteristic parameters obtained from the oil well test into formulas (7) to (10) to calculate the critical sand production pressure difference of the oil well;

[0054] The reservoir characteristic parameters obtained from the oil well test include rock density, shale content, overlying rock pressure, Poisson's ratio, elastic cutoff BIOT, etc.;

[0055] S9. Select the minimum value in ΔP 脱气 , ΔP 出砂 as the maximum liquid production pressure difference of the oil well;

[0056] Integrate the maximum production pressure difference ΔP 脱气 considering degassing determined in step S6 and the critical sand production pressure difference ΔP 出砂 determined in step S8. When ΔP 脱气 <ΔP 出砂 , select ΔP 脱气 as the maximum liquid production pressure difference of the oil well; when ΔP 脱气 >ΔP 出砂 , ΔP 出砂 is selected as the maximum liquid production pressure difference of the oil well.

[0057] S10. Calculate the maximum daily liquid production capacity of the oil well;

[0058] Based on the maximum specific liquid production index of the oil well determined in step S5 and the maximum liquid production pressure difference of the oil well determined in step S9, calculate the maximum daily liquid production potential of different oil wells according to formula (11):

[0059] Q Lmax = J Lmax ×ΔP max ×h (11)

[0060] Where: Q Lmax is the actual maximum daily liquid production potential of the oil well based on the production in the target block, with the unit of m 3 / d;

[0061] J Lmax is the maximum liquid production index ratio, with the unit of m 3 / (d·MPa);

[0062] ΔP max represents the maximum liquid production pressure difference of the oil well, with the unit of MPa;

[0063] h is the thickness of the oil reservoir, with the unit of m.

[0064] The beneficial effects of the present invention are as follows:

[0065] The present invention provides a method for evaluating the maximum daily liquid production capacity of a single well during the ultra-high water cut period, providing a basis for releasing the production capacity of oil wells through the expansion and transformation of offshore oilfield platforms; based on the actual production of a large number of ultra-high water cut oil wells in the target block, the present invention corrects the theoretical dimensionless liquid production index curve, determines the maximum liquid production index ratio of the oil well, and at the same time, according to the actual sand production pressure difference of the oil wells in the target block, fits the cohesive force in the commonly used critical sand production pressure difference calculation model to obtain a new calculation model applicable to the target block, realizing the innovation from ex post judgment to ex ante prediction for the determination of the maximum production pressure difference. Based on the above determined maximum liquid production index ratio and production pressure difference, the maximum daily liquid production capacity of the oil well is calculated, providing a basis for the transformation of offshore oilfield platform facilities. Description of the Drawings

[0066] Figure 1 is the flowchart of the method of the present invention;

[0067] Figure 2 is the measured relative permeability curve of the upper Ming formation in the target block in Embodiment 1 of the present invention;

[0068] Figure 3 is the actual production dynamic curve of Well J44H, a case well in Embodiment 1 of the present invention;

[0069] Figure 4 is the actual dimensionless liquid production index curve of the oil wells in the upper Ming formation in the target block in Embodiment 1 of the present invention;

[0070] Figure 5 is the theoretical dimensionless liquid production index curve of the upper Ming formation in the target block in Embodiment 1 of the present invention;

[0071] Figure 6It is the theoretical dimensionless liquid production index curve diagram modified based on the actual curve in Embodiment 1 of the present invention;

[0072] Figure 7 It is the comparison diagram between the calculation result of the new model of critical sand production pressure difference and the actual situation in Embodiment 1 of the present invention.

[0073] For those of ordinary skill in the art, without creative efforts, other related drawings can be obtained based on the above drawings. Detailed implementation manners

[0074] In order to enable those skilled in the art of the present technology 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 drawings in the specification and through specific implementation manners.

[0075] Embodiment 1

[0076] An evaluation method for the maximum liquid production capacity of oil wells in the extra-high water cut period is carried out with the basic parameters of a certain bottom water reservoir. The basic parameters are as follows: the reservoir burial depth is -700m to -1330m, the average porosity is 28.5%, and the average permeability is 3000×10 -3 μm 2 , the production horizons are Minghuazhen Formation and Guantao Formation. Among them, Minghuazhen Formation is divided into two sub-oil groups, namely the upper Minghuazhen sub-oil group and the lower Minghuazhen sub-oil group. The crude oil viscosity distribution range in the upper Minghuazhen formation is 200mPa·s to 350mPa·s, and the crude oil viscosity distribution range in the lower Minghuazhen formation is 40mPa·s to 142mPa·s. Guantao Formation is mainly composed of ordinary crude oil, and the formation crude oil viscosity is 30mPa·s.

[0077] As Figure 1 shown, an evaluation method for the maximum liquid production capacity of oil wells in the extra-high water cut period specifically includes the following steps:

[0078] S1. Collect static reservoir characteristic parameters and dynamic production data of the target block. Based on the well logging and geophysical exploration related test data of the target block, collect and sort out the reservoir characteristic parameters of oil wells in different horizons, including rock density, shale content, longitudinal wave velocity, oil layer thickness, Poisson's ratio, elastic cutoff BIOT and relative permeability data ( Figure 2 ), and based on the production dynamic database of oil wells in the target block, collect the actual production dynamic data of oil wells in different horizons, including the dynamic data of water cut, daily liquid production, and production pressure difference changing with time. Taking Well A44H on the upper Minghuazhen sand body as an example, its production dynamic curve is as Figure 3 shown.

[0079] S2. Calculate the dimensionless liquid production index at different water cut rates of the oil well and plot the actual dimensionless liquid production index curve. Based on the actual production dynamic data of a large number of high water cut wells in the target block, taking the oil wells in the upper Ming sand body as an example, calculate the actual dimensionless liquid production index at different water cut rates of the oil well according to formulas (1) - (2), and plot the relationship curve to obtain the actual dimensionless liquid production index curve. As Figure 4 shown, as the water cut rate increases, the dimensionless liquid production index gradually increases.

[0080]

[0081] In the formula: J L represents the specific liquid production index, m 3 / (d·MPa·m); Q L is the daily liquid production, m 3 / d; ΔP is the production pressure difference, MPa; h is the oil layer thickness, m; represents the actual dimensionless liquid production index; J L0 is the specific liquid production index during the water - free period;

[0082] S3. Based on the measured relative permeability data, plot the theoretical dimensionless liquid production index curve. Combining the measured relative permeability data of the target block ( Figure 2 ), calculate the water cut rate at different oil saturation levels according to formula (3), calculate the dimensionless liquid production index at different oil saturation levels according to formula (4), and comprehensively plot the relationship curve to obtain the theoretical dimensionless liquid production index curve. As Figure 5 shown, both the actual and theoretical dimensionless liquid production indices show the characteristic of gradually increasing as the water cut rate increases, and the coincidence degree between the two is good before the high water cut stage, but the theoretical curve deviates from the actual one at the extra - high water cut stage.

[0083]

[0084]

[0085] In the formula, f w represents the water cut rate, in decimals; K ro represents the relative permeability of the oil phase, in decimals; K rw is the relative permeability of the oil phase, in decimals; μ w is the viscosity of the formation water, mPa·s; μ o is the viscosity of the formation crude oil, mPa·s; represents the theoretical dimensionless liquid production index; K roc is the relative permeability of the oil phase during the water - free period, in decimals.

[0086] S4. Correct the dimensionless liquid production index curve based on the actual curve correction theory. According to the actual dimensionless liquid production index curve, correct the theoretical curve in the ultra-high water cut stage to obtain a pattern chart of the variation of the dimensionless liquid production index with water cut that conforms to the actual oilfield production, as shown in Figure 6 . After high-magnitude water flooding in the reservoir during the ultra-high water cut period, the pore structure and permeability change, resulting in the actual dimensionless liquid production index being greater than the theoretical value at the same water cut stage.

[0087] S5. Calculate the maximum liquid production index ratio of the oil well based on the corrected theoretical dimensionless liquid production index curve. Taking Well J44H as an example, the current water cut of this well is 97.4%, located in the sand body of the upper Ming section. The pattern chart of the corrected theoretical dimensionless liquid production index based on the actual production is as shown in Figure 6 . Based on this pattern chart, the maximum dimensionless liquid production index and the dimensionless liquid production index at the current water cut stage of the oil well are determined to be 27.9 and 25.0 respectively. Combining with formula (1), the current liquid production index ratio of the oil well is calculated to be 102.5 m 3 / (d·MPa·m). According to formula (5), the maximum liquid production index ratio of the oil well is determined to be 114.3 m 3 / (d·MPa·m):

[0088]

[0089] In the formula: is the maximum dimensionless liquid production index in the corrected theoretical pattern chart, dimensionless; represents the actual dimensionless liquid production index at any water cut in the corrected theoretical pattern chart, dimensionless; J Lmax is the maximum liquid production index ratio, with the unit of m 3 / (d·MPa); J L represents the liquid production index ratio at any water cut, with the unit of m 3 / (d·MPa·m).

[0090] S6. Calculate the maximum production pressure difference ΔP 脱气 considering the influence of gas liberation. Taking Well J44H as an example, based on the PVT test data of the target block, the formation saturation pressure and the original static pressure of the upper Ming section are determined to be 7.89 MPa and 5.14 MPa respectively. Referring to the regulations of the industry standard, the minimum bottom hole flowing pressure allowing for the influence of gas liberation is 80% of the formation saturation pressure. Combining with the original static pressure of the formation, the maximum production pressure difference considering the influence of gas liberation at this layer is calculated to be 3.78 MPa according to formula (6).

[0091] ΔP 脱气 = P e - P b × 0.8 (6)

[0092] In the formula: ΔP 脱气Indicates the maximum production pressure difference considering the effect of degassing, MPa; P e Indicates formation static pressure, MPa; P b is the formation saturation pressure, MPa.

[0093] S7. Based on the actual production fitting cohesion calculation formula, a new model for critical sanding pressure difference calculation is established. Based on the critical sanding pressure difference calculation model obtained by the Mohr-Coulomb rock failure criterion, combined with the actual production pressure difference when the oil wells in the target block produce sand and the tested reservoir characteristic parameters, the cohesion of the corresponding sanding oil wells is calculated, and according to the main influencing factors of cohesion, the empirical formula for cohesion calculation is fitted and brought into the above critical sanding pressure difference calculation model to obtain a new calculation model suitable for the target block. The specific process is as follows:

[0094] S71. The critical sand production pressure difference calculation model based on the Mohr-Coulomb rock failure criterion was obtained through investigation, as follows:

[0095]

[0096] ΔP 出砂 =P e -P wcr (8)

[0097] Where: P wcr represents the critical sand production well bottom flow pressure, MPa; σ Zo is the overburden pressure, MPa; β is the Biot constant of the pore elastic medium; μ d is Poisson's ratio; C represents the formation cohesion, MPa; θ is the internal friction angle, (°); ΔP 出砂 Indicates the critical sand production pressure difference, MPa.

[0098] S72. Combine the actual production dynamics of the target block to sort out the critical production pressure difference when the oil well produces sand;

[0099] S73. Based on the dimensionless liquid production index curve of the actual oil wells in the target block, sort out the oil wells whose dimensionless liquid production index decreases with increasing water content, and record the production pressure difference when the dimensionless liquid production index starts to decrease;

[0100] S74. The production pressure difference when sand is produced at the wellhead of the oil well and the production pressure difference when the dimensionless liquid production index begins to decrease are taken as the critical sand production pressure difference, and the reservoir geological characteristic parameters obtained from the corresponding oil well test are substituted into formula (7∽8), combined with the relationship between cohesion and internal friction (9), to calculate the cohesion under different critical sand production pressure differences of the oil well.

[0101] θ=2.564×Log 10 {[(58.93-1.785×C)+(58.93-1.785×C) 2+1]+20} (9)

[0102] By sorting out the critical sand - producing oil wells in the target block and the relevant reservoir characteristic parameters as shown in Table 1, and combining with formulas (7) - (9), the cohesive forces under critical sand production of different oil wells are calculated as shown in Table 1 below;

[0103] Table 1: Reservoir characteristic parameters of different oil wells and cohesive forces under critical sand - producing pressure differences

[0104]

[0105]

[0106] S75. According to the cohesive forces under critical sand - producing pressure differences of different oil wells, and combining with the main factors affecting the cohesive force recognized through research, including rock density, Poisson's ratio, longitudinal wave velocity, and shale content, a calculation formula for cohesive force applicable to the target block is obtained through fitting:

[0107]

[0108] In the formula: ρ b is the rock density, g / cm 3 ; V p is the longitudinal wave velocity, m / s; V e is the shale content, %.

[0109] S76. Combining formulas (7) - (10), a new calculation model for the critical sand - producing pressure difference of oil wells applicable to the target block is obtained. As Figure 7 shown, the results calculated by the new model basically conform to the actual sand production in the target block.

[0110] S8. Based on the new model, calculate the critical sand - producing production pressure difference of the oil well. Taking Well J44H as an example, substitute the reservoir characteristic parameters measured by this well, including rock density, shale content, overburden rock pressure, Poisson's ratio, elastic cutoff BIOT, etc. into formulas (7) - (10), and calculate the critical sand - producing production pressure difference of the oil well to be 2.50 MPa, as shown in Table 2.

[0111] Table 2: Reservoir characteristic parameters of A44H and critical sand - producing pressure difference

[0112]

[0113] S9. Select the minimum value in ΔP 脱气 , ΔP 出砂 to determine the maximum liquid - lifting production pressure difference of the oil well. Considering the maximum production pressure difference ΔP 脱气 of Well J44H determined in S6 to be 3.78 MPa after considering gas liberation and the critical sand - producing production pressure difference ΔP 出砂 determined in S8 to be 2.50 MPa, when ΔP脱气 <ΔP 出砂 , select ΔP 脱气 as the maximum liquid production pressure difference of the oil well; when ΔP 脱气 >ΔP 出砂 , select ΔP 出砂 as the maximum production pressure difference of the oil well. Therefore, the maximum production of Well J44H is 2.50 MPa.

[0114] S10. Calculate the maximum daily liquid production capacity of the oil well. Based on S5, the maximum specific liquid production index of Well J44H is determined to be 114.3 m 3 / (d·MPa·m), and based on S9, the maximum liquid production pressure difference of the oil well is determined to be 2.50 MPa. The oil layer thickness of this well is 12 m. According to formula (11), the maximum daily liquid production potential of this well is 3429 m 3 / d.

[0115] Q Lmax =J Lmax ×ΔP max ×h (11)

[0116] Where: ΔP max represents the maximum production pressure difference, MPa; Q Lmax is the maximum daily liquid production potential of the oil well, m 3 / d.

[0117] Based on the actual production of a large number of extra-high water cut oil wells in the target block, the present invention corrects the theoretical dimensionless specific liquid production index curve, determines the maximum specific liquid production index of the oil well, and at the same time, according to the actual sand production pressure difference of the oil wells in the target block, fits the cohesive force in the common critical sand production pressure difference calculation model to obtain a new calculation model applicable to the target block, realizing the innovation from ex post judgment to ex ante prediction in the determination of the maximum production pressure difference. Based on the determined maximum specific liquid production index and production pressure difference above, calculate the maximum daily liquid production capacity of the oil well. This invention patent has innovation.

[0118] 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 disclosure scope of the present invention.

Claims

1. A method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period, characterized by: The following steps are involved: S1. Collect static reservoir characteristic parameters and dynamic production data of the target block; S2. Calculate the dimensionless liquid production index of the oil well at different water cuts and draw an actual dimensionless liquid production index curve; S3. Based on the measured relative permeability data, a theoretical dimensionless liquid production index curve is drawn; S4. According to the actual dimensionless liquid production index curve, the theoretical curve of the ultra-high water content stage is corrected to obtain a regular chart of the dimensionless liquid production index changing with water content that conforms to the actual oil field production; S5, calculating the maximum specific liquid production index of the oil well based on the theoretical dimensionless liquid production index curve corrected in step S4; S6. Calculate the maximum production pressure difference considering the effect of degassing; S7. Based on the actual production of the target block, the empirical formula for calculating cohesion is corrected and a new model for calculating the critical sand pressure difference is established; S8, substituting the reservoir characteristic parameters obtained from the oil well test into the new model obtained in step S7 to calculate the critical sand production pressure difference of the oil well; S9, select the maximum production pressure difference ΔP determined in step S6 considering the degassing effect 脱气 and the critical sand production pressure difference ΔP of the oil well calculated based on the new model determined in step S8 出砂 The minimum value among them is taken as the maximum liquid extraction production pressure difference of the oil well; S10. Calculate the maximum daily fluid production capacity of the oil well.

2. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The static reservoir characteristic parameters are static reservoir characteristic parameters of oil wells in different layers obtained by collecting and collating the relevant test data of well logging and geophysical exploration in the target block; the static reservoir characteristic parameters include rock density, mud content, longitudinal wave velocity, oil layer thickness, Poisson's ratio, elastic cutoff BIOT and phase permeability data; the dynamic production data are actual dynamic production data of oil wells in different layers obtained by collecting based on the oil well production dynamic library in the target block; the dynamic production data include water content, daily liquid production at different water content and dynamic data of production pressure difference changing with time at different water content.

3. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The calculation formula of the actual dimensionless liquid production index under different water contents is: Where: represents the actual dimensionless liquid production index, dimensionless; J L0 is the liquid production index during the water-free period, in m 3 / (d·MPa·m);J L Indicates the specific liquid index, the unit is m 3 / (d·MPa·m); Specific fluid index J L The calculation formula is: In formula (1-2): J L Indicates the specific liquid index, the unit is m 3 / (d·MPa·m);Q L is the daily liquid output, in m 3 / d; ΔP is the production pressure difference, the unit is MPa; h is the oil layer thickness, the unit is m.

4. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The step S3 draws a theoretical dimensionless liquid production index curve based on the measured relative permeability data, and specifically comprises the following steps: S31. Calculate the water content at different oil saturations based on the measured relative permeability data of the target block; The calculation formula of the moisture content is: Where: f w Indicates moisture content, decimal, dimensionless; K ro Represents the relative permeability of the oil phase, decimal, dimensionless; K rw is the relative permeability of the water phase, decimal, dimensionless; μ w is the viscosity of formation water, in mPa·s; μ o is the viscosity of the formation crude oil, in mPa·s; S32, calculating the dimensionless liquid production index under different oil saturations; The calculation formula of the dimensionless liquid production index under different oil saturations is: Where: K represents the theoretical dimensionless liquid production index, dimensionless; roc is the relative permeability of the oil phase in the water-free period, decimal, dimensionless; K ro Represents the relative permeability of the oil phase, decimal, dimensionless; K rw is the relative permeability of the water phase, decimal, dimensionless; μ w is the viscosity of formation water, in mPa·s; μ o is the viscosity of the formation crude oil, in mPa·s; S33. Combining the water cut at different oil saturations obtained in step S31 and the dimensionless liquid production index at different oil saturations obtained in step S32, a water cut-theoretical dimensionless liquid production index relationship curve is plotted to obtain a theoretical dimensionless liquid production index curve.

5. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The calculation formula of the maximum specific liquid production index of the oil well is: Where: is the maximum dimensionless liquid extraction index in the modified theoretical plate, dimensionless; It represents the actual dimensionless liquid production index at any water content in the modified theoretical plate, dimensionless; J Lmax is the maximum specific liquid production index, in m 3 / (d·MPa);J L It indicates the specific production liquid index at any water content, in m 3 / (d·MPa·m).

6. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The calculation formula for the maximum production pressure difference considering the degassing effect of each layer is: ΔP 脱气 =P e -P b ×0.8 Where: ΔP 脱气 It indicates the maximum production pressure difference considering the effect of degassing, in MPa; P e Indicates the original static pressure of the formation, in MPa; P b is the formation saturation pressure, in MPa.

7. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The step S7 establishes a new model for calculating the critical sanding pressure difference based on the empirical formula for calculating the cohesion calculated by correcting the actual production of the target block, and specifically includes the following steps: S71. The critical sand-producing well bottom pressure calculation model based on the Mohr-Coulomb rock failure criterion was obtained through investigation. The model expression is as follows: Where: P wcr Indicates the critical sand-producing well bottom flow pressure, in MPa; σ Zo is the overburden pressure, in MPa; μ d is Poisson's ratio, dimensionless; β is the Biot constant of the poroelastic medium, dimensionless; P e represents the original static pressure of the formation, in MPa; θ is the internal friction angle, in degrees; C represents the cohesion of the formation, in MPa; The calculation formula for critical sand production pressure difference is: ΔP 出砂 =P e -P wcr Where: P wcr Indicates the critical sand production well bottom flow pressure, MPa; ΔP 出砂 Indicates the critical sand production pressure difference, MPa, P e Indicates the original static pressure of the formation, in MPa; S72. Combine the actual production dynamics of the target block to sort out the critical production pressure difference when the oil well produces sand; S73. Based on the dimensionless liquid production index curve of the actual oil wells in the target block, sort out the oil wells whose dimensionless liquid production index decreases with increasing water content, and record the production pressure difference when the dimensionless liquid production index starts to decrease; S74, taking the production pressure difference when sand is produced at the wellhead of the oil well and the production pressure difference when the dimensionless liquid production index begins to decrease as the critical sand production pressure difference, and bringing the reservoir geological characteristic parameters obtained from the corresponding oil well test into the critical sand production well bottom flow pressure calculation model based on the Mohr-Coulomb rock failure criterion and the critical sand production pressure difference calculation formula, and combining the relationship between cohesion and internal friction to calculate the cohesion under different critical sand production pressure differences of the oil well; The relationship between cohesion and internal friction is: θ=2.564×Log 10 {[(58.93-1.785×C)+(58.93-1.785×C) 2 +1]+20} Where: θ represents the internal friction angle, in degrees; C represents the formation cohesion, in MPa; S75. Based on the cohesion under the critical sand pressure difference of different oil wells, the main factors affecting the cohesion were identified in combination with research, and the cohesion calculation formula applicable to the target block was obtained through fitting; The cohesion calculation formula applicable to the target block is: Where: b is the rock density, in g / cm 3 ;μ d is Poisson's ratio, dimensionless; V p is the longitudinal wave velocity, in m / s; V e is the mud content, %, dimensionless; S76. Substitute the cohesive force calculation formula applicable to the target block into the critical sanding well bottom flow pressure calculation model based on the Mohr-Coulomb rock failure criterion and the calculation formula of the critical sanding production pressure difference to obtain a new calculation model for the critical sanding pressure difference of oil wells applicable to the target block.

8. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The reservoir characteristic parameters obtained from the oil well test include rock density, mud content, overlying rock pressure, Poisson's ratio and elastic cutoff BIOT.

9. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The maximum liquid extraction production pressure difference of the oil well ΔP max ΔP 脱气 and ΔP 出砂 The minimum value in .

10. The method for evaluating the maximum daily fluid production capacity of a single well in the ultra-high water cut period according to claim 1, characterized in that: The calculation formula for the maximum daily fluid production capacity of the oil well is: Q Lmax =J Lmax ×ΔP max ×h Where: Q Lmax The actual maximum daily production potential of the oil well based on the target block, in m 2 ; J Lmax is the maximum specific liquid production index, in m 3 / (d·MPa);ΔP max It represents the maximum production pressure difference in MPa; h is the oil layer thickness in m.

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