Method for quantitatively judging liquid extraction opportunity in later stage of water flooding

Abstract

The invention belongs to the technical field of oil-gas exploration, and relates to a method for quantitatively judging the liquid extraction opportunity in the later stage of water flooding, which comprises the following steps: S1, determining the distribution condition of remaining oil by using logging information; s2, based on oil reservoir geological conditions and remaining oil distribution conditions, a liquid extraction and oil increase geological mode is selected; s3, single-well production data in the liquid extraction and oil increase geological mode are obtained, and a single-well relative permeability curve and dimensionless liquid production and oil production indexes are calculated; and comprehensively evaluating the liquid extraction opportunity by utilizing a single-well relative permeability curve and dimensionless liquid production and oil production indexes, and determining the liquid extraction opportunity of a single well and the reasonable liquid extraction amount of the single well. The method for comprehensively evaluating the liquid extraction time and the liquid extraction amount is established, powerful technical support is provided for stable production of a research area, and the method has important theoretical guiding significance for development of oil reservoirs of the same type.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas exploration, and particularly relates to a method for quantitatively judging the timing of liquid production increase in the later stage of water flooding. Background Art

[0002] In recent years, new breakthroughs have been continuously made in deep and ultra-deep oil and gas exploration, which has become an important part of oil and gas reserves. Hudong Oilfield is the largest low-amplitude marine sandstone oil reservoir in the desert area of western China. The main oil-bearing layer, the Carboniferous Donghe Sandstone, is a typical marine barrier-free wave-controlled sandy shore deposit with strong reservoir heterogeneity. There are multiple stages and complex genetic calcareous interlayers developed inside, and the oil-water distribution law is complex. At present, it has entered the middle and later stages of water flooding development, with a high comprehensive water cut, a low oil production rate of geological reserves, and an increasing decline, which has become a restricting factor for the stable production of Donghe Sandstone.

[0003] The latest research trends show that domestic and foreign scholars have carried out a series of studies from aspects such as hydrocarbon accumulation mechanism, water flooding law, and physical property changes in the later stage of water flooding:

[0004] (1) Jiang Tongwen et al. based on physical simulation experiments and fine structural evolution analysis, believed that there is no unified oil-water interface in the Donghe Sandstone oil reservoir, and proposed that there are significant differences in the main characteristics such as the hydrocarbon enrichment position, occurrence state, and oil-water relationship in different development stages;

[0005] (2) Liu Qiang et al. used various core analysis data and logging water flooding interpretation conclusions to carry out a discussion on the mechanism of reservoir water flooding changes, and clarified the pore and permeability change laws of different pore sizes during water flooding development;

[0006] (3) Liu Guangwei et al. discriminated the water flooding mode of horizontal wells according to different water production mechanisms and using the inflection point characteristics of the water-oil ratio derivative curve;

[0007] (4) Shi Shubin et al. studied the effects of liquid production increase under different geological and development conditions on the basis of analyzing the mechanism of enhanced oil recovery by liquid production increase, and determined the policy boundaries for liquid production increase;

[0008] (5) Xu Bing et al. proposed a method for selecting the timing of single-well liquid production increase in horizontal wells by means of dimensionless oil production and liquid production index analysis methods;

[0009] (6) Huang Wei studied the influence of different liquid production increase timing and permeability ratio on the liquid production increase effect by establishing a numerical model of one injection and four productions;

[0010] (7) Zhang Chao et al. studied the influencing factors of liquid production increase effect and the mechanism of enhanced oil recovery in the ultra-high water cut period through indoor physical simulation experiments. The results show that liquid production increase can significantly improve the crude oil recovery rate, and its effect is mainly affected by reservoir heterogeneity, liquid production increase amplitude, and injection volume.

[0011] On the basis of previous studies, based on the characteristics of ultra-deep marine sandstone reservoirs in the Tahadduson Oilfield, the mechanism of liquid production increase was mainly studied to demonstrate the feasibility of liquid production increase in the late high-water cut stage of marine sandstone reservoirs. The current research mainly uses core scanning data to study the microscopic characteristics of reservoir bedding and laminar interfaces, reveals the changing laws of tilted oil-water interfaces in bottom water and edge water reservoirs before and after water flooding, and describes the distribution characteristics of remaining oil. Combining dimensionless liquid production, oil production index and production data, an optimization method for liquid production parameters in the late stage of water flooding development of marine sandstone is proposed. Main problems: First, with the increase of water injection development years, the physical properties of the reservoir have changed. It is inevitable to make mistakes in judging the timing by only using static data to determine the optimal liquid production time; second, the water cut of some wells has increased sharply, and liquid production has become a "water production measure". For some other wells, the effect of liquid production is not obvious, or even worse. Therefore, it is necessary to determine the reasonable policy boundary of liquid production according to the reservoir's own conditions and development stages, and it is necessary to further semi-quantitatively or quantitatively determine the liquid production timing. Summary of the Invention

[0012] The purpose of the present invention is to provide a method for quantitatively judging the timing of liquid production increase in the late stage of water flooding, which solves the problems of easy misjudgment of timing selection and poor liquid production effect existing in the existing methods.

[0013] The present invention is realized through the following technical solutions:

[0014] The present invention discloses a method for quantitatively judging the timing of liquid production increase in the late stage of water flooding, including the following steps:

[0015] S1. Determine the remaining oil distribution status by using logging data;

[0016] S2. Select the geological model for increasing oil production by liquid production based on the reservoir geological conditions and the remaining oil distribution status;

[0017] S3. Obtain the single-well production data under the geological model for increasing oil production by liquid production, and calculate the single-well relative permeability curve and dimensionless liquid production and oil production indexes;

[0018] Comprehensively evaluate the liquid production timing by using the single-well relative permeability curve and dimensionless liquid production and oil production indexes, and determine the single-well liquid production timing and the reasonable liquid production volume of the single well.

[0019] Further, S1 is specifically:

[0020] S1.1. Use core analysis data to explore the development characteristics of preferential flow channels, and clarify the well selection area for liquid production based on the development characteristics of preferential flow channels;

[0021] S1.2. In the well selection area for liquid production, obtain the remaining recoverable reserves based on formation test logging data;

[0022] S1.3. Numerically simulate the wells with large remaining recoverable reserves in the fluid-lifting well selection area to further clarify the affected range, affected shape, and saturation numerical distribution of horizontal wells by bottom water coning.

[0023] S1.4. Based on the remaining recoverable reserves obtained in S1.2 and the affected range, affected shape, and saturation numerical distribution of horizontal wells by bottom water coning obtained in S1.3, determine the remaining oil distribution.

[0024] Furthermore, in S1.1, based on the development characteristics of the dominant seepage channels, clarify the fluid-lifting well selection area, specifically:

[0025] In the area with well-developed dominant seepage channels, there is less remaining oil. To tap the remaining oil, clarify the area with more remaining oil as the fluid-lifting well selection area.

[0026] Furthermore, S1.2 is specifically as follows: In the fluid-lifting well selection area, use formation test logging data to obtain the controlled reserves of all single wells, and obtain the cumulative oil production of single wells based on the controlled reserves of single wells; use the water drive characteristic curve method to calculate the ultimate cumulative oil production of single wells, and combine the current cumulative oil production of single wells to obtain the remaining recoverable reserves.

[0027] The specific method of using formation test logging data to obtain the controlled reserves of all single wells is as follows:

[0028] Perform high-resolution processing on the logging data to obtain the average effective thickness.

[0029] Based on the distance between two connected single wells, use the deconvolution method, combined with well testing and dynamic analysis, to determine the drainage radius of a single well.

[0030] Use the average effective thickness, reservoir physical property parameters, and the drainage radius of a single well to calculate the controlled reserves of a single well by the volume method.

[0031] Volume method formula: N = 【100AheΦ(1 - Swi)Po】 / Boi;

[0032] In the formula, N represents the geological oil reserves; A represents the oil-bearing area; he represents the average effective thickness; Φ represents the average effective porosity; Swi represents the average irreducible water saturation; Po represents the average ground-degassed crude oil density; Boi represents the average formation crude oil volume factor.

[0033] Furthermore, the specific method of using the water drive characteristic curve method to calculate the ultimate cumulative oil production is as follows:

[0034] Use the semi-logarithmic relationship curve between the cumulative oil production Np and the cumulative water production Wp in the Type A water drive characteristic curve, input the ultimate water cut, and then calculate the ultimate cumulative oil production.

[0035] Combined with the current cumulative oil production of a single well, the remaining recoverable reserves are calculated as follows:

[0036] Subtract the current cumulative oil production of a single well from the ultimate cumulative production to obtain the remaining recoverable reserves.

[0037] Furthermore, in S1.3, it is obtained based on numerical simulation that the affected range of the horizontal well by bottom water coning is limited. The horizontal section extends 50 - 150 m to the left and right, showing a trapezoidal shape longitudinally and an elliptical shape horizontally. The saturation gradually increases outward with the well as the center. By increasing the liquid production to enlarge the production pressure difference, the water flooding affected volume can be expanded and the recovery factor can be improved.

[0038] Furthermore, in S2, the geological models for increasing oil production by liquid production include the geological model for increasing oil production by liquid production in the injection-production area, the geological model for increasing oil production by liquid production at the reservoir edge, and the geological model for increasing oil production by liquid production in the secondary bottom water area.

[0039] Furthermore, in S3, based on the single well production data, the water flooding curve is regressed, and combined with the split flow equation, the single well relative permeability curve and the dimensionless liquid production and oil production indices are calculated;

[0040]

[0041]

[0042] J o = K rw (S w )

[0043] J L = K rw (S w ) + K ro (S w )μ o / μ w

[0044] In the formula, Krw is the current water phase permeability; Kro is the current oil phase permeability; Krw(Sor) is the water phase permeability under residual oil conditions; Kro(Swi) is the oil phase permeability under irreducible water conditions; SW is the current oil saturation; n w is the water phase index; n o is the oil phase index; J o is the dimensionless oil production index; J L is the dimensionless liquid production index; Krw(Sw) is the water phase permeability under the current oil saturation; Kro(Sw) is the oil phase permeability under the current oil saturation; u o is the oil phase viscosity; u w is the oil phase viscosity.

[0045] Further, in S3, the liquid production timing is comprehensively evaluated by using the single-well relative permeability curve and the dimensionless liquid production and oil production indexes to determine the liquid production timing of a single well and the reasonable liquid production volume of the single well. The specific process is as follows:

[0046] When the water cut reaches 85% or more, the liquid production index greater than 1 meets the liquid production condition. At the same time, when the water cut exceeds 98%, the water-phase permeability increases, the oil-phase permeability decreases, and the water-phase seepage capacity exceeds the oil-phase;

[0047] The best liquid production timing is the period when the water cut is 85%-98%.

[0048] Further, the determination of the reasonable liquid production volume of a single well is as follows:

[0049] Q = ΔPJ L ;

[0050] In the formula, Q is the reasonable liquid production volume; Δp is the reasonable production pressure difference; J L is the dimensionless liquid production index.

[0051] Compared with the prior art, the present invention has the following beneficial technical effects:

[0052] The present invention discloses a method for quantitatively judging the liquid production timing in the later stage of water flooding, explores the development characteristics of the dominant seepage channels, clarifies the distribution law of microscopic remaining oil, forms a geological model for increasing oil production by liquid production, calculates the dynamic parameters of the single-well relative permeability curve and the dimensionless liquid production and oil production indexes, comprehensively evaluates the liquid production timing by using the single-well relative permeability curve and the dimensionless liquid production and oil production indexes, and determines the liquid production timing of a single well and the reasonable liquid production volume of the single well. The present invention establishes a comprehensive evaluation method for the liquid production timing and the liquid production volume, provides strong technical support for the stable production of the research area, and has important theoretical guiding significance for the development of the same type of oil reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] Figure 1 is a diagram of the mechanism for increasing oil production by liquid production;

[0054] Figure 2 are various geological models for increasing oil production by liquid production; a is a geological model for increasing oil production by liquid production in the injection-production area; b is a geological model for increasing oil production by liquid production at the edge of the oil reservoir; c is a geological model for increasing oil production by liquid production in the secondary bottom water area;

[0055] Figure 3 is a diagram of the relationship between the remaining oil saturation and the initial oil saturation;

[0056] Figure 4 is a diagram of the swept range of horizontal well numerical simulation;

[0057] Figure 5 is a relationship curve between the dimensionless liquid production and oil production indexes and the water cut of the Donghe sandstone oil reservoir;

[0058] Figure 6It is the relative permeability curve of Donghe sandstone reservoir;

[0059] Figure 7 It is the cross-plot of water cut and water cut rising rate;

[0060] Figure 8 It is the relationship between water cut rising rate and production pressure difference;

[0061] Figure 9 It is the bottom water coning model diagram;

[0062] Figure 10 It is the calculation diagram of reasonable liquid production rate;

[0063] Figure 11 It is the flow chart of a method for quantitatively judging the timing of increasing liquid production in the later stage of water flooding according to the present invention. Detailed implementation manners

[0064] In order to make the purpose, technical solutions and advantages of the present invention clearer, the following further describes in detail with reference to the drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention, that is, the described embodiments are only a part of the embodiments of the present invention, rather than all the embodiments.

[0065] The components described and shown in the drawings and embodiments of the present invention can be arranged and designed in various different configurations. Therefore, the detailed description of the embodiments of the present invention provided in the following drawings is not intended to limit the scope of the claimed invention, but only represents a selected embodiment of the present invention. Based on the drawings and embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative efforts fall within the protection scope of the present invention.

[0066] It should be noted that: the term "comprising", "including" or any other variant is intended to cover non-exclusive inclusion, so that a process, element, method, article or device including a series of elements not only includes those elements, but also includes other elements not expressly listed, or also includes the elements inherent in the process, element, method, article or device.

[0067] The features and performance of the present invention are further described in detail below with reference to the embodiments.

[0068] As Figure 11 shown, the present invention discloses a method for quantitatively judging the timing of increasing liquid production in the later stage of water flooding, including the following steps:

[0069] S1. Using logging data, determine the remaining oil distribution; specifically:

[0070] S1.1. Explore the development characteristics of the dominant seepage channels using core analysis data, and clarify the well selection area for liquid production based on the development characteristics of the dominant seepage channels;

[0071] S1.2. In the well selection area for liquid production, calculate the remaining recoverable reserves based on formation test logging data;

[0072] S1.3. Conduct numerical simulation calculations on the individual wells with large remaining recoverable reserves in the well selection area for liquid production to further clarify the affected range, affected shape, and saturation numerical distribution of the horizontal well affected by bottom water coning;

[0073] S1.4. Determine the remaining oil distribution based on the remaining recoverable reserves obtained in S1.2, the affected range, affected shape, and saturation numerical distribution of the horizontal well affected by bottom water coning obtained in S1.3.

[0074] S2. Select the geological model for liquid production and oil increment based on the reservoir geological conditions and the remaining oil distribution;

[0075] S3. Obtain the individual well production data under the geological model for liquid production and oil increment, and calculate the relative permeability curve of the individual well and the dimensionless liquid production and oil production indices;

[0076] Comprehensively evaluate the timing of liquid production using the relative permeability curve of the individual well and the dimensionless liquid production and oil production indices, and determine the timing of liquid production and the reasonable liquid production volume of the individual well.

[0077] Research on the mechanism of liquid production: As Figure 1 shown, the part below the dashed line is the remaining oil mobilized by expanding the swept volume. The water flooding of oil is a dynamic process. When the water flooding front reaches the bottom of the oil well, the water cut increases under the same production pressure difference as the oil saturation decreases near the production well.

[0078] Based on the research on the mechanism of liquid production, conduct an evaluation of the geological model for liquid production and oil increment, which is specifically divided into the geological model for liquid production and oil increment in the injection-production area, the geological model for liquid production and oil increment at the reservoir edge, and the geological model for liquid production and oil increment in the secondary bottom water area:

[0079] As Figure 2 shown in a, affected by reservoir heterogeneity between the injection and production wells, the injection water plane advances unevenly, showing a phenomenon of unidirectional breakthrough. Usually, in the weak water flooding direction, the production well shows mild response or no response, and the remaining oil is relatively enriched. Liquid production can be used to achieve water injection induction and improve the water flooding effect.

[0080] As Figure 2 shown in b, there is a strong edge water energy supply at the reservoir edge. Affected by the thin oil layer thickness and strong heterogeneity, the utilization is uneven and the cumulative production is low. By increasing the liquid production rate, the oil washing intensity can be enhanced to achieve the effect of increasing oil production.

[0081] As Figure 2As shown in Figure c, in the top part of the secondary bottom water coning area where the physical properties of thin layers are poor, the remaining oil is difficult to produce, resulting in rapid water cut increase in oil wells. By increasing liquid production to enlarge the production pressure difference, the contradiction between thin layers can be improved and the oil production can be increased.

[0082] Carry out petrophysical experiments on the Donghe sandstone in the Hudong Oilfield, and use the relative permeability curve and dimensionless liquid production and oil production indices to comprehensively evaluate the timing of increasing liquid production.

[0083] Using Figure 7 As shown in the water cut and water cut increase rate cross plot, compare the theoretical value and actual value of the water cut increase rate in different water cut periods to judge the rationality of the liquid production parameters of a single well.

[0084] It can be seen from experimental data such as core scanning electron microscopy and CT scanning that, as Figure 3 shown, the initial oil saturation is high. Under the condition of a limited displacement multiple, its remaining oil saturation is also high. Under the condition of basically the same displacement multiple, the water flooding effect of the massive bedding reservoir is relatively good, and the movable oil saturation is the highest. The parallel bedding is the second, and the inclined bedding is slightly worse.

[0085] Therefore, the richness of the material basis directly affects the effect of increasing liquid production. The wells with poor liquid production effect are mainly concentrated in the areas with thin oil layer thickness and low remaining reserves; the development degree of the interlayer below the trajectory of the liquid production well determines whether bottom water coning occurs after increasing liquid production. A typical well is Well HD1-1. After increasing liquid production, the pressure of the main production layer of this well decreases, the interlayer is broken through, and the water cut increases in a stepwise manner, resulting in a worse liquid production effect.

[0086] After statistics, as shown in Table 1 below, the wells with good liquid production effect are basically located in the areas where the remaining oil is relatively enriched, and their characteristics are large original oil layer thickness, high oil saturation, and strong reservoir heterogeneity.

[0087] Table 1 Statistical table of basic data and effects of liquid production wells

[0088]

[0089] In the well selection area for increasing liquid production, use formation test logging data to obtain the controlled reserves of all single wells, and obtain the cumulative oil production of a single well based on the controlled reserves of a single well;

[0090] Adopt the water drive characteristic curve method to calculate the ultimate cumulative oil production of a single well, combined with the current cumulative oil production situation of a single well.

[0091] Use logging data to obtain the controlled reserves of a single well, specifically:

[0092] Perform high-resolution processing on logging data to obtain the average effective thickness;

[0093] Based on the distance between two connected single wells, use the deconvolution method, combined with well testing and dynamic analysis, to determine the drainage radius of a single well;

[0094] The volumetric method is used to calculate the controlled reserves of a single well using the average effective thickness, reservoir physical parameters and single well drainage radius;

[0095] Volumetric method formula: N = [100AheΦ(1-Swi)Po] / Boi

[0096] Where, N is the geological reserves of oil, 104t;

[0097] A——Oil-bearing area, km 2 ;

[0098] he——average effective thickness; m;

[0099] Φ——average effective porosity, %;

[0100] Swi - average bound water saturation, %;

[0101] Po——average surface degassed crude oil density, 1×10*kg / m';

[0102] Boi——average formation crude oil volume coefficient.

[0103] The Type A water drive characteristic curve method is then used to calculate the ultimate cumulative oil production, and combined with the current single well cumulative oil situation, the remaining recoverable reserves are calculated.

[0104] Table 2

[0105]

[0106] Specifically, as shown in Table 2 above, by using the semi-logarithmic relationship curve between the cumulative oil production Np and the cumulative water production Wp in the type A water drive characteristic curve, the maximum cumulative oil production can be calculated by inputting the maximum water cut of 98%.

[0107] like Figure 4 As shown in the figure, according to numerical simulation, the horizontal well is affected by bottom water coning and has a limited sweep range. The horizontal section extends about 100m to the left and right, presents a trapezoidal shape in the vertical direction and an elliptical shape in the plane. The saturation increases gradually outward from the well center. By carrying out liquid lifting to amplify the production pressure difference, the water drive sweep volume can be expanded and the recovery rate can be improved.

[0108] Based on the single well production data regression water drive curve, combined with the flow diversion equation, the following is calculated: Figure 6 The single well phase permeability curve and dimensionless fluid production and oil production index are shown.

[0109]

[0110]

[0111] J o =K rw (S w )

[0112] J L = K rw (S w ) + K ro (S w )μ o / μ w

[0113] Wherein, Krw is the current water-phase permeability; Kro is the current oil-phase permeability; Krw(Sor) is the water-phase permeability under the condition of residual oil; Kro(Swi) is the oil-phase permeability under the condition of irreducible water; SW is the current oil saturation; n w is the water-phase index; n o is the oil-phase index; J o is the dimensionless oil production index; J L is the dimensionless liquid production index; Krw(Sw) is the water-phase permeability at the current oil saturation; Kro(Sw) is the oil-phase permeability at the current oil saturation; u o is the oil-phase viscosity; u w is the oil-phase viscosity.

[0114] As Figure 5 shown, the timing of increasing liquid production is comprehensively evaluated by using the single-well relative permeability curve and the dimensionless liquid production and oil production indexes. When the water cut reaches 85% or more, the liquid production index is greater than 1, meeting the condition for increasing liquid production. At the same time, when the water cut exceeds 98%, the water-phase permeability rises sharply, the oil-phase permeability drops sharply, and the water-phase seepage capacity far exceeds that of the oil phase. Therefore, the best timing for increasing liquid production is the period when the water cut is 85% - 98%;

[0115] The bottom water coning mode diagram is as Figure 9 shown. For oil wells with a water cut rising rate higher than the theoretical value and at the best timing for increasing liquid production, consider increasing liquid production for stable production; for wells with a water cut rising rate lower than the theoretical value and having the potential for increasing liquid production, consider increasing the production pressure difference by increasing liquid production to improve the degree of reserve utilization. A typical well is Well HD1-1. The critical production pressure difference of 3.8 MPa is obtained according to the calculation method of the critical production rate of a horizontal well affected by bottom water, and the determined liquid production rate is 51.8 t / d.

[0116] Critical production pressure difference:

[0117] Critical liquid production rate:

[0118] At the same time, based on the relationship between the water cut rising rate and the production pressure difference ( Figure 8 ), as Figure 10 shown, combined with the liquid production index, determine the reasonable liquid production volume of a single well.

[0119] Q = ΔPJ L ;

[0120] In the formula, Q is the reasonable liquid production volume; △p is the reasonable production pressure difference; J L is the dimensionless liquid production index.

[0121] This achievement can be applied to the regulation, optimization measures and effect evaluation of water injection in the later stage of sandstone water flooding. The oil increment effect of each well group shows that the liquid production effect is better in the areas where the remaining oil is enriched and the physical properties vary greatly. The cumulative oil increment of each well group is more than 600 tons, while the cumulative oil increment in the areas where the remaining oil is dispersed is generally less than 400 tons. It realizes the identification of the liquid production timing in the later stage of water flooding development and the quantitative evaluation of liquid production parameters, combines static and dynamic analysis, effectively guides the oilfield production practice, and provides technical support for liquid production in the later stage of high water cut.

[0122] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and not to limit them. Although the present invention has been described in detail with reference to the above embodiments, those of ordinary skill in the art should understand that: the specific implementation manners of the present invention can still be modified or equivalently replaced, and any modification or equivalent replacement without departing from the spirit and scope of the present invention shall be covered by the protection scope of the claims of the present invention.

Claims

1. A method for quantitatively determining the timing of fluid production increase in the late stage of water flooding, characterized in that, It includes the following steps: S1. Determine the remaining oil distribution status using logging data; S2. Select a geological model for increasing oil production by fluid lifting based on the reservoir geological conditions and the remaining oil distribution status; S3. Obtain the single-well production data under the geological model for increasing oil production by fluid lifting, and calculate the single-well relative permeability curve and dimensionless liquid production and oil production indices; Comprehensively evaluate the timing of fluid lifting using the single-well relative permeability curve and dimensionless liquid production and oil production indices, and determine the timing of fluid lifting for the single well and the reasonable fluid lifting volume for the single well.

2. The method for quantitatively determining the timing of fluid production increase in the late stage of water flooding according to claim 1, wherein Specifically, S1 is as follows: S1.

1. Explore the development characteristics of the dominant seepage channels using core analysis data, and clarify the well selection area for fluid lifting based on the development characteristics of the dominant seepage channels; S1.

2. In the well selection area for fluid lifting, obtain the remaining recoverable reserves based on the formation test logging data; S1.

3. Conduct numerical simulation calculations on the single wells with more remaining recoverable reserves in the well selection area for fluid lifting to further clarify the affected range, affected shape, and saturation numerical distribution of the horizontal well by bottom water coning; S1.

4. Determine the remaining oil distribution status based on the remaining recoverable reserves obtained in S1.2, the affected range, affected shape, and saturation numerical distribution of the horizontal well by bottom water coning obtained in S1.

3.

3. The method for quantitatively determining the timing of fluid production increase in the late stage of water flooding according to claim 2, characterized in that, In S1.1, to clarify the well selection area for fluid lifting based on the development characteristics of the dominant seepage channels, specifically: In the area with well-developed dominant seepage channels, there is less remaining oil. To tap the remaining oil, clarify the area with more remaining oil as the well selection area for fluid lifting.

4. The method for quantitatively determining the timing of fluid production increase in the later stage of water flooding according to claim 2, wherein Specifically, S1.2 is as follows: In the well selection area for fluid lifting, obtain the controlled reserves of all single wells using the formation test logging data, and obtain the cumulative oil production of the single well based on the controlled reserves of the single well; use the water drive characteristic curve method to calculate the ultimate cumulative oil production of the single well, and combine the current cumulative oil production of the single well to obtain the remaining recoverable reserves; The specific method for obtaining the controlled reserves of all single wells using the formation test logging data is as follows: Perform high-resolution processing on the logging data to obtain the average effective thickness; Based on the distance between two connected single wells, use the deconvolution method, combined with well testing and dynamic analysis, to determine the drainage radius of the single well; Use the average effective thickness, reservoir physical property parameters, and the drainage radius of the single well to calculate the controlled reserves of the single well using the volumetric method; Volumetric method formula: N = 【100AheΦ(1 - Swi)Po】 / Boi; In the formula, N represents the geological reserves of petroleum; A represents the oil-bearing area; he represents the average effective thickness; Φ represents the average effective porosity; Swi represents the average irreducible water saturation; Po represents the average ground-degassed crude oil density; Boi represents the average formation crude oil volume factor.

5. The method for quantitatively determining the timing of liquid production increase in the later stage of water flooding according to claim 4, wherein The specific method for calculating the ultimate cumulative oil production using the water drive characteristic curve method is as follows: Use the semi-logarithmic relationship curve between the cumulative oil production Np and the cumulative water production Wp in the type A water drive characteristic curve, input the ultimate water cut, and then calculate the ultimate cumulative oil production; The specific method for combining the current cumulative oil production of the single well to obtain the remaining recoverable reserves is as follows: Subtract the current cumulative oil production of the single well from the ultimate cumulative oil production to obtain the remaining recoverable reserves.

6. The method for quantitatively determining the timing of liquid production increase in the late stage of water flooding according to claim 2, wherein In S1.3, it is obtained based on numerical simulation that the affected range of the horizontal well by bottom water coning is limited. The horizontal section extends about 50 - 150 m to the left and right. Vertically, it presents a trapezoidal shape, and horizontally, it presents an elliptical shape. The saturation gradually increases outward with the well as the center. By increasing the liquid production to enlarge the production pressure difference, the swept volume of water flooding can be expanded and the recovery factor can be improved.

7. The method for quantitatively determining the timing of fluid production increase in the later stage of water flooding according to claim 1, wherein In S2, the geological models for increasing oil production by liquid boosting include the geological model for increasing oil production by liquid boosting in the injection-production area, the geological model for increasing oil production by liquid boosting at the reservoir edge, and the geological model for increasing oil production by liquid boosting in the secondary bottom water area.

8. The method for quantitatively determining the timing of fluid production increase in the late stage of water flooding according to claim 1, characterized in that, In S3, the water drive curve is regressed according to the production data of a single well, and the relative permeability curve and dimensionless liquid production and oil production indexes of a single well are calculated by combining with the split-flow equation. J o = K rw (S w ) Wherein, Krw is the current water-phase permeability; Kro is the current oil-phase permeability; Krw(Sor) is the water-phase permeability under the condition of residual oil; Kro(Swi) is the oil-phase permeability under the condition of irreducible water; SW is the current oil saturation; n w is the water-phase index; n o is the oil-phase index; J o is the dimensionless oil production index; J L is the dimensionless liquid production index; Krw(Sw) is the water-phase permeability at the current oil saturation; Kro(Sw) is the oil-phase permeability at the current oil saturation; u o is the oil-phase viscosity; u w is the oil-phase viscosity.

9. The method for quantitatively determining the timing of fluid production increase in the late stage of water flooding according to claim 1, wherein In S3, the relative permeability curve of a single well and the dimensionless liquid production and oil production indexes are used to comprehensively evaluate the timing of liquid boosting, and the timing of liquid boosting and the reasonable liquid production volume of a single well are determined. The specific process is as follows: When the water cut reaches more than 85%, the liquid production index greater than 1 meets the condition of liquid boosting. At the same time, when the water cut exceeds 98%, the water phase permeability increases and the oil phase permeability decreases, and the seepage capacity of the water phase exceeds that of the oil phase. The optimal timing of liquid boosting is the period when the water cut is 85% - 98%.

10. The method for quantitatively determining the timing of fluid production increase in the later stage of water flooding according to claim 1, characterized in that, The determination of the reasonable liquid production volume of a single well is as follows: Q = ΔPJ L ; Wherein, Q is the reasonable liquid production rate; Δp is the reasonable production pressure difference; J L is the dimensionless liquid production index.

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