Fracture-vug type oil and gas reservoir recovery ratio prediction method

Abstract

The invention provides a fracture-vug type oil and gas reservoir recovery ratio prediction method. According to the method, a new water drive coefficient and a new Children's curve chart suitable for fracture-vug type oil and gas reservoir recovery ratio prediction are adopted; the method specifically comprises the steps of inverting a well mouth quasi-relative permeability form according to production history, selecting a water drive curve according to different geological backgrounds, and explaining water drive control reserves according to a new water drive coefficient; predicting the recovery ratio of the fractured-vuggy oil and gas reservoir according to the well mouth quasi-relative permeability form and the new Child curve chart; compared with the prior art, the problems that in the prior art, the applicability of fracture-vug type oil and gas reservoir water drive reserve calculation is not high, and the fracture-vug type oil and gas reservoir water drive dynamic reserve cannot be accurately calculated are solved.

Description

Technical Field

[0001] The present invention belongs to the technical field of development of fractured-vuggy hydrocarbon reservoirs, and particularly relates to a method for predicting the recovery factor of a fractured-vuggy hydrocarbon reservoir. Background Art

[0002] Fractured-vuggy hydrocarbon reservoirs have complex pore structures, various fracture-vug connection forms, and various flow mechanisms. The reservoirs have extremely strong heterogeneity and anisotropy. The research on fractured-vuggy hydrocarbon reservoirs has become the focus of current hydrocarbon reservoir development. At present, the Tong's chart widely used in the development of waterflooding oilfields was proposed by Tong Xianzhang in the late 1970s and early 1980s. It is commonly used to analyze the water cut rising law of natural waterflooding or artificial water injection reservoirs, evaluate the adjustment effect of waterflooding development, and predict the waterflooding recovery factor. It is an important reservoir engineering method.

[0003] With the gradual increase in the exploration and development scale of fractured-vuggy hydrocarbon reservoirs, the problems existing in Tong's chart and its adaptability to fractured-vuggy hydrocarbon reservoirs have gradually emerged, mainly in two aspects: ① The water cut of fractured-vug reservoirs shows a stepwise increase, and the water cut rising law in the low water cut period does not conform to the theory and practice; ② The recovery factors predicted by Tong's chart are generally on the high side, especially for fractured-vuggy hydrocarbon reservoirs.

[0004] This is because in the waterflooding curve and Tong's chart, there are characteristics related to the seepage of porous media, while the flow in fractured-vug reservoirs does not conform to this characteristic. The inventor found through research that the waterflooding curve itself is not completely derived from existing theories. It is the existing field statistical law first, and then verified through theoretical derivation. At the same time, in the research and attempt of the waterflooding curves of existing fractured-vuggy hydrocarbon reservoirs, most wells have an effective waterflooding curve segment.

[0005] In summary, there is a great possibility that the technical system of the waterflooding curve can be improved and applied to fractured-vuggy hydrocarbon reservoirs.

[0006] Chinese Patent CN111611704B discloses a method, device, and readable storage medium for establishing a water drive series curve chart. The method for establishing the water drive series curve chart includes the following steps: obtaining the actual cumulative water production and actual cumulative oil production data of several fracture-cavity units with a water cut greater than a preset water cut; selecting a fracture-cavity unit to obtain the values of each parameter in the expression of the Type A water drive characteristic curve corresponding to the current fracture-cavity unit; determining the type of the current fracture-cavity unit; selecting a type of fracture-cavity unit to obtain a fitting curve expressing the relationship between the water cut and the recovery degree of the current fracture-cavity unit type; and establishing a water drive series curve chart. The technical solution provided by the invention combines the Type A water drive characteristic curve with the displacement curve method to derive a displacement series curve applicable to fracture-cavity oil and gas reservoirs; and classifies according to the morphological characteristics of the new displacement series curve to establish a water drive series chart, solving the problem that the traditional displacement series method and water drive characteristic curve method are limited in application in fracture-cavity oil and gas reservoirs.

[0007] The above-mentioned invention patent further expands and improves the water drive curve based on fracture-cavity oil and gas reservoirs, which proves from the side that improving the water drive curve to meet the needs of recovery rate prediction in fracture-cavity oil and gas reservoirs is one of the important issues in the field of research; however, the above-mentioned invention mainly expands the water drive curve based on existing data and methods, without considering the geological characteristics and real-time production dynamics of fracture-cavity oil and gas reservoirs; resulting in obvious room for improvement in the prediction of the recovery rate of fracture-cavity oil and gas reservoirs.

[0008] Patent Application CN114658425A provides a method for calculating the water drive dynamic reserves for fracture-cavity oil and gas reservoirs, which includes: plotting the water drive characteristic curve corresponding to a single target well in a semi-logarithmic coordinate system and determining the curve type of the water drive characteristic curve; dimensionless processing the cumulative oil production data and cumulative water production data of the single target well and plotting them in a dimensionless curve chart to obtain the first type of coefficient corresponding to the single target well at each water drive stage; calculating the first type of coefficient corresponding to all target wells at each water drive stage; calculating the second type of coefficient corresponding to all target wells at each water drive stage through the cumulative oil production data and cumulative water production data of the single target well; and calculating the dynamic reserves corresponding to all target wells at each water drive stage. The invention further improves the Type A water drive characteristic curve model in the prior art, overcoming the problem that the use of a unified proportionality coefficient in the prior art will lead to large errors in the calculation results.

[0009] The above application mainly improves the calculation process of the water drive curve and reduces the errors existing in the prior art. However, in actual production, both the water drive curve and the Tong's chart are tools for predicting the recovery factor of water drive oilfields, but they are different in application scope and specific operations. Therefore, it is very necessary to effectively combine the advantages of the two, and the above application does not actually make further improvements by combining the technical inspiration of the Tong's chart.

[0010] The inventors have conducted research on three aspects: how to determine the underlying basis for the selection of the water drive curve, how to determine the accurate water drive constant based on the water drive mode and fracture-cavity structure, and how to provide a new Tong's curve applicable to fracture-cavity type oil and gas reservoirs, in order to expect to provide a reliable and effective method for predicting the recovery factor of fracture-cavity type oil and gas reservoirs by combining the technical means to solve the above technical problems. Summary of the Invention

[0011] Aiming at the defects existing in the current fracture-cavity type oil and gas reservoirs, such as unclear basis for the selection of the water drive curve, unclear value of the water drive constant, and non-conformance of the shape of the Tong's curve, resulting in poor prediction accuracy of the recovery factor of fracture-cavity type oil and gas reservoirs, the present invention provides a method for predicting the recovery factor of fracture-cavity type oil and gas reservoirs based on the water drive curve.

[0012] To achieve the above object, the technical solution adopted by the present invention is as follows:

[0013] A method for predicting the recovery factor of fracture-cavity type oil and gas reservoirs, comprising the following steps:

[0014] S1. Perform reverse calculation on the pseudo relative permeability curve of the fracture-cavity type oil and gas reservoir to be analyzed according to the production history dynamic data, and obtain the morphology of the pseudo relative permeability;

[0015] S2. Select the water drive curve according to the morphology of the pseudo relative permeability obtained in step S1 in combination with the geological background;

[0016] S3. Interpret the water drive controlled reserves according to the water drive curve selected in step S2 in combination with the water drive constant of the geological background;

[0017] S4. Calculate the recovery degree of the oil reservoir according to the water drive controlled reserves interpreted in step S3;

[0018] S5. Form the Tong's curve according to the water drive controlled reserves and the recovery degree of the oil reservoir described in step S4;

[0019] S6. Evaluate and predict the recovery factor according to the morphology of the Tong's curve formed in step S5 by selecting different new Tong's curve charts.

[0020] Preferably, the form of the fracture-cavity type oil and gas reservoir to be analyzed is a single well, a well group or a unit.

[0021] Preferably, the morphology of the pseudo relative permeability in step S1 is divided into a linear type, an upward-curving type, and a downward-curving type according to the relationship between the logarithm of the ratio of the oil-phase relative permeability to the water-phase relative permeability and the function saturation.

[0022] Preferably, the geological background in step S2 includes weathered crust karst, channel compound denudation karst, and fault-controlled karst.

[0023] Preferably, the method for selecting the water drive curve in step S2 is as follows: for the geological background of weathered crust karst, select the type D water drive curve; for the geological background of channel compound denudation karst, select the type A water drive curve; for the geological background of fault-controlled karst, select the type D water drive curve.

[0024] Preferably, the geological background in step S3 includes weathered crust karst, channel compound denudation karst, and fault-controlled karst.

[0025] Further preferably, under the geological background of channel compound karst, the water drive constant of natural water drive is 9.16, and the water drive constant of artificial water drive is 5.6494;

[0026] Under the geological background of weathered crust karst, the water drive constant of natural water drive is 9.16, the water drive constant of natural water drive is 5.60, and the water drive constant of artificial water drive is 8.0272;

[0027] Under the geological background of fault-controlled karst, the water drive constant of natural water drive is 6.54, and the water drive constant of artificial water drive is 6.82.

[0028] Preferably, in step S3, the interpretation of the water drive controlled reserves includes calculating the dynamic reserves of artificial water drive and the dynamic reserves of natural water drive.

[0029] Further preferably, the injection material balance curve is used to calculate the dynamic reserves of artificial water drive; the material balance method is used to calculate the dynamic reserves of natural water drive.

[0030] Preferably, in the process of interpreting the water drive controlled reserves in step S3, there are cases with wellhead pressure data and cases where the wellhead pressure data is missing.

[0031] Further preferably, when in the case with wellhead pressure data, the flowing material balance method is used to interpret the water drive controlled reserves;

[0032] When in the case where the wellhead pressure data is missing, the conventional decline analysis method is used to interpret the water drive controlled reserves.

[0033] Preferably, in the Tong's curve in step S6, it includes the upward-curving type and the downward-curving type of the relationship curve between the logarithm of the ratio of the oil-phase relative permeability to the water-phase relative permeability and the function saturation.

[0034] Preferably, the method for selecting different new Tong's curve charts in step S6 is as follows:

[0035] When the curve of the logarithm of the ratio of oil-phase relative permeability to water-phase relative permeability versus the function of saturation is upward-curving, the upward-curving trend of the curve is fitted using the following formula:

[0036]

[0037] In the formula, k ro is the relative permeability curve of the oil phase, dimensionless; k rw is the relative permeability curve of the water phase, dimensionless; S w is the average water cut saturation of the reservoir, dimensionless. a, b, c, d are the parameters for fitting relative permeability, dimensionless;

[0038] Select the step-type Tong's curve expression:

[0039]

[0040] In the formula, f w is the water cut of the oil well, dimensionless; R o is the recovery degree of the reservoir, dimensionless; E R is the recovery efficiency of the reservoir, dimensionless;

[0041] Among them, the recovery degree R of the reservoir o is expressed by the relationship of the average water cut saturation:

[0042]

[0043] In the formula, R o is the recovery degree of the reservoir, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; S wi is the initial water saturation of the reservoir, dimensionless; N p is the cumulative oil production, 10,000 m³; N w is the water drive controlled reserve, 10,000 m³;

[0044] Graph the Tong's curve expression to obtain a new step-type Tong's curve chart;

[0045] Even more preferably, when the curve of the logarithm of the ratio of oil-phase relative permeability to water-phase relative permeability versus the function of saturation is downward-curving, the downward-curving trend of the curve is fitted using the following formula:

[0046]

[0047] In the formula, k ro is the relative permeability curve of the oil phase, dimensionless; k rw is the relative permeability curve of the water phase, dimensionless; Sw is the average water saturation of the reservoir, dimensionless. a, b, and c are parameters for fitting relative permeability, dimensionless;

[0048] Select the Tong's curve expression of the single-channel type:

[0049]

[0050] In the formula, f w is the water cut of the oil well, μ o is the viscosity of the oil phase, mPa·s; μ w is the viscosity of the water phase, mPa·s; b is a parameter for fitting relative permeability, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; R o is the recovery factor of the reservoir, dimensionless; R e is the recovery efficiency of the reservoir, dimensionless.

[0051] Among them, the recovery factor R of the reservoir o is expressed by the relationship of the average water saturation:

[0052]

[0053] In the formula, R o is the recovery factor of the reservoir, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; S wi is the initial water saturation of the reservoir, dimensionless; N p is the cumulative oil production, 10,000 m³; N w is the water drive controlled reserve, 10,000 m³;

[0054] Graph the Tong's curve expression to obtain a new chart of the single-channel Tong's curve.

[0055] Compared with the prior art, the present invention has the following beneficial effects:

[0056] (1) The method for predicting the recovery efficiency of fractured-vuggy oil and gas reservoirs proposed by the present invention does not require frequent tests. Based on the existing production history data, important data such as water drive dynamic reserves and recovery factor can be obtained during the prediction process, which can simultaneously meet other actual requirements.

[0057] (2) Aiming at solving the three problems in the prior art that the selection basis of the water drive curve for fractured-vuggy oil and gas reservoirs is unclear, the value of the water drive constant is not clear, and the existing Tong's curve is not applicable to fractured-vuggy oil and gas reservoirs, the present invention proposes a method for predicting the recovery efficiency of fractured-vuggy oil and gas reservoirs. This method overcomes the problem that the prior art is not applicable to calculating the water drive reserves of fractured-vuggy oil and gas reservoirs and cannot accurately calculate the water drive dynamic reserves of fractured-vuggy oil and gas reservoirs, and can accurately predict the recovery efficiency of fractured-vuggy oil and gas reservoirs. Description of the Drawings

[0058] Figure 1 It is a flow chart of the recovery factor prediction method for fractured-vuggy hydrocarbon reservoirs based on water drive curves provided by the present invention;

[0059] Figure 2 It is the pseudo relative permeability law diagram of three types of fractured-vuggy reservoirs in the embodiments of the present invention;

[0060] Figure 3 It is the relationship chart of the stepped Tong's curve provided in the embodiments of the present invention;

[0061] Figure 4 It is the relationship chart of the single-channel Tong's curve provided in the embodiments of the present invention; Detailed Description of the Invention

[0062] Embodiment A recovery factor prediction method for fractured-vuggy hydrocarbon reservoirs

[0063] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are only used to illustrate and explain the present invention and are not used to limit the present invention.

[0064] In this embodiment, the same symbols have the same meanings unless otherwise specified.

[0065] As Figures 1-3 shown, the recovery factor prediction method for fractured-vuggy hydrocarbon reservoirs based on water drive curves provided by the present invention comprises the following steps:

[0066] (1) First, reverse calculate the pseudo relative permeability curve of a single well, well group or unit based on the production history dynamic data to obtain the shape of the pseudo relative permeability, which is used as one of the bases for selecting the water drive curve. The shapes of the pseudo relative permeability include three types: conventional relative permeability curve, stepped relative permeability curve, and single-channel relative permeability curve, as Figure 2 shown.

[0067] (2) Select the water drive curve according to different shapes of the pseudo relative permeability in combination with different geological backgrounds;

[0068] The carbonate fractured-vuggy hydrocarbon reservoir in Tahe Oilfield is mainly composed of tectonic fractures formed by tectonic deformation and pores, caves and fractures formed by karstification. Among them, large caves are the main storage spaces, and fractures are both storage spaces and the main communication channels. Affected by the comprehensive action of paleogeomorphology, paleo-water system and deep major faults, karst types controlled by structures, karst dominated by faults controlled by fractures and river channel composite denudation karst controlled by paleo-water system are formed. There are differences in the main karstification modes and intensities under different karst backgrounds, showing a zoned and belted distribution characteristics on the plane.

[0069] If the shape of the pseudo relative permeability curve (Log(Kro / Krw) ~ Sw) is linear, the Type A water drive curve is selected; if the shape of the pseudo relative permeability curve is non-linear, the Type D water drive curve is selected;

[0070] For the geological background of weathered crust karst, the Type D water drive curve is selected; for the geological background of channel compound denudation karst, the Type A water drive curve is selected; for the geological background of fault-controlled karst, the Type D water drive curve is selected.

[0071] (3) Interpret the water drive controlled reserves according to the water drive constants of different geological karst backgrounds.

[0072] For the geological background of channel compound karst, the water drive constant of natural water drive is 9.16, and the water drive constant of artificial water drive is 5.6494. For the geological background of weathered crust karst, the water drive constant of natural water drive is 5.60, and the water drive constant of artificial water drive is 8.0272. For the geological background of fault-controlled karst, the Type D water drive curve can be well applied, the water drive constant of natural water drive is 6.54, and the water drive constant of artificial water drive is 6.82.

[0073] (4) Calculate the recovery degree of the oil reservoir according to the water drive controlled reserves, and form the Tong's curve. According to the shape of the Tong's curve, select different new Tong's curve charts to evaluate and predict the recovery rate, as follows

[0074] During the development process of fractured-vuggy oil reservoirs, the relationship between the water cut and the recovery degree is usually completely inconsistent with the existing Tong's curve, and it is difficult to fit and judge the recovery rate through the Tong's curve. Therefore, in the present invention, a calculation method for the recovery degree of the oil reservoir, a derivation method for a new Tong's curve chart, and the derived new Tong's curve chart are provided.

[0075] The derivation method of the new Tong's curve chart is as follows:

[0076] (1) The logarithm of the pseudo relative permeability calculated from the wellhead data of some wells (the relationship curve between the logarithm of the ratio of oil-phase relative permeability to water-phase relative permeability and the function saturation) is upwardly curved. Theoretically, if it is upwardly curved, the traditional Tong's chart cannot be used. For the case where the logarithmic relationship of the relative permeability curve is upwardly curved, the following model is used to fit the upward trend of the curve:

[0077]

[0078] In the formula, k ro is the relative permeability curve of the oil phase, dimensionless; k rw is the relative permeability curve of the water phase, dimensionless; S w is the average water saturation of the oil reservoir, dimensionless. a, b, c, and d are the parameters for fitting the relative permeability, dimensionless.

[0079] The relationship between the oil production rate and water production rate at the wellhead is derived as follows

[0080]

[0081] In the formula, q w is the water production rate of the oil well, m 3 / d; q o is the oil production rate of the oil well, m 3 / d; f w is the water cut of the oil well, dimensionless; μ o is the viscosity of the oil phase, mPa·s; μ w is the viscosity of the water phase, mPa·s.

[0082] Substitute the relationship between the relative permeability curve and the wellhead production rate into the relationship between production rate and water cut to obtain

[0083]

[0084] Simplify the above formula to obtain

[0085]

[0086] Take the reciprocal of the above formula and then simplify to obtain

[0087]

[0088] The recovery factor is expressed by the relationship of the average water saturation, From this, we get

[0089] S oi R o +S wi =S w

[0090] In the formula, R o is the recovery factor of the reservoir, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; S wi is the initial water saturation of the reservoir, dimensionless.

[0091] After taking the logarithm again, the expression of the step-shaped Tong's curve is obtained:

[0092]

[0093] In the formula, E R is the recovery efficiency of the reservoir, dimensionless.

[0094] Graph the formula to obtain the relationship chart of the step-shaped Tong's curve, as Figure 3 shown.

[0095] (2) The logarithm of the pseudo relative permeability calculated from the wellhead data of some wells is downwardly curved. Theoretically, the traditional Tong's chart cannot be used for the downwardly curved curve either. For the case where the logarithmic relationship of the relative permeability curve is downwardly curved, the following model is used to fit the downward trend of the curve:

[0096]

[0097] a, b, and c are the parameters for fitting the relative permeability, dimensionless;

[0098] The relationship between the oil production rate and the water production rate at the wellhead is derived as follows

[0099]

[0100] Substituting the relationship between the relative permeability curve and the wellhead production rate into the relationship between the production rate and the water cut, we get

[0101]

[0102] The recovery factor is expressed by the relationship of the average water saturation, From this, we get:

[0103] S oi R o +S wi =S w

[0104] Substituting the relationship of the recovery factor from the average water saturation into the water cut relationship, we get

[0105]

[0106] By transposing terms and taking the logarithm on both sides, we get

[0107]

[0108] Taking the water cut of 0.98 as the check data point for the recovery factor, the Tong's curve of the single-channel type is obtained as

[0109]

[0110] Graphing this formula, the relationship chart of the Tong's curve of the single-channel type is obtained, as Figure 4 shown.

[0111] Finally, based on the new Tong's curve chart and the conventional technical means in this field, the recovery factor of the fracture-vug type oil and gas reservoir can be evaluated and predicted.

[0112] By calculating the production data of the S67 unit in the above embodiments to invert the pseudo relative permeability curve, it presents as a conventional relative permeability curve and is applicable to the Type A water drive curve; interpreting the reserves: through the Type A water drive curve after modifying the parameters, the recoverable reserves of the water drive recoverable reserve calculation unit are 6.5 million tons;

[0113] The S67 unit has a background of combined karst of underground river + residual hill. The water drive swept volume calculated by the numerical simulation method is 6.18 million tons. The numerical simulation method is the reservoir numerical simulation calculation. This method requires the establishment of a geological model, a fluid model and a flow model, depicting the flow channels, and performing production history matching. The required working hours are dozens of times that of this method. The calculated result of 6.18 million tons can be considered more refined, not completely accurate, but still considered one of the most refined existing methods, with a recovery rate of 24.7%. Using the "single channel" prediction recovery rate chart for calculation, finally the predicted recovery rate of the embodiments of the present invention is between 25% - 30%, which is basically consistent with the actual understanding.

[0114] It can be seen that the result obtained by the present invention is basically consistent with the conventional recovery rate prediction method in the art. The method provided by the present invention can be considered to be able to effectively predict the recovery rate of fracture - cave type oil and gas reservoirs and has been greatly simplified compared with the traditional numerical simulation method.

[0115] The above are only the preferred embodiments of the present invention and do not impose any form of limitation on the present invention. Although the present invention has been disclosed above with preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to equivalent embodiments by using the disclosed technical content within the scope of the technical solution of the present invention. However, as long as it does not depart from the content of the technical solution of the present invention, any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present invention still fall within the scope of the technical solution of the present invention.

Claims

1. A prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir, characterized in that, It includes the following steps: S1. Reverse-calculate the pseudo relative permeability curve of the fractured-vuggy hydrocarbon reservoir to be analyzed based on the production history dynamic data to obtain the morphology of the pseudo relative permeability. S2. Select the water drive curve according to the morphology of the pseudo relative permeability obtained in step S1 in combination with the geological background. S3. Interpret the water drive controlled reserves according to the water drive curve selected in step S2 in combination with the water drive constant of the geological background. S4. Calculate the recovery degree of the reservoir according to the water drive controlled reserves interpreted in step S3. S5. Form the Tong's curve according to the water drive controlled reserves and the recovery degree of the reservoir described in step S4. S6. Evaluate and predict the recovery rate by selecting different new Tong's curve charts according to the morphology of the Tong's curve formed in step S5.

2. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, It includes the following steps: The morphology of the pseudo relative permeability described in step S1 includes the conventional relative permeability curve, the step-type relative permeability curve, and the single-channel relative permeability curve.

3. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, It includes the following steps: The geological background described in step S2 includes weathered crust karst, channel composite erosion karst, and fault-dominated karst.

4. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 3, characterized in that, It includes the following steps: The method for selecting the water drive curve described in step S2 is as follows: for the geological background of weathered crust karst, select the type D water drive curve; for the geological background of channel composite erosion karst, select the type A water drive curve; for the geological background of fault-dominated karst, select the type D water drive curve.

5. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, It includes the following steps: The geological background described in step S3 includes weathered crust karst, channel composite erosion karst, and fault-dominated karst.

6. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, Under the geological background of channel composite karst, the water drive constant of natural water drive is 9.16, and the water drive constant of artificial water drive is 5.6494; Under the geological background of weathered crust karst, the water drive constant of natural water drive is 9.16, the water drive constant of natural water drive is 5.60, and the water drive constant of artificial water drive is 8.0272; Under the geological background of fault-dominated karst, the water drive constant of natural water drive is 6.54, and the water drive constant of artificial water drive is 6.

82.

7. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, The interpretation of the water drive controlled reserves described in step S3 includes calculating the dynamic reserves of artificial water drive and the dynamic reserves of natural water drive.

8. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 7, characterized in that, The calculation of the dynamic reserves of artificial water drive uses the injection material balance curve; the calculation of the dynamic reserves of natural water drive uses the material balance method.

9. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, In the process of interpreting the water drive controlled reserves described in step S3, there are situations with wellhead pressure data and situations where the wellhead pressure data is missing.

10. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 9, characterized in that, When in the situation with wellhead pressure data, use the flowing material balance method to interpret the water drive controlled reserves; When in the situation where the wellhead pressure data is missing, use the conventional decline analysis method to interpret the water drive controlled reserves.

11. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 1, characterized in that, The morphology of the relative permeability curve described in step S6 includes the cases of upward curvature in the logarithmic relationship and downward curvature in the logarithmic relationship.

12. The prediction method for the recovery factor of a fracture-vuggy hydrocarbon reservoir according to claim 11, characterized in that, The method for selecting different new Tong's curve charts described in step S6 is as follows: When the curve of the logarithm of the ratio of oil-phase relative permeability to water-phase relative permeability versus the function saturation is of the upward curvature type, use the following formula to fit the upward trend of the curve: where k ro is the relative permeability curve of the oil phase, dimensionless; k rw is the relative permeability curve of the water phase, dimensionless; S w is the average water saturation of the reservoir, dimensionless; a, b, c, and d are the parameters for fitting the relative permeability, dimensionless; Select the step-type Tong's curve expression: where f w is the water cut of the oil well, dimensionless; R o is the recovery degree of the oil reservoir, dimensionless; E R is the recovery factor of the oil reservoir, dimensionless; Graphing the expression of the Tong's curve results in a new plate of the stepped Tong's curve; When the curve of the logarithm of the ratio of oil-phase relative permeability to water-phase relative permeability versus the function saturation is of the downward curvature type, use the following formula to fit the downward trend of the curve: where k ro is the relative permeability curve of the oil phase, dimensionless; k rw is the relative permeability curve of the water phase, dimensionless; S w is the average water saturation of the reservoir, dimensionless; a, b, and c are the parameters for fitting relative permeability, dimensionless; Select the single-channel type Tong's curve expression: where f w is the water cut of the oil well, μ o is the viscosity of the oil phase, mPa·s; μ w is the viscosity of the water phase, mPa·s; b is the parameter for fitting relative permeability, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; R o is the recovery factor of the reservoir, dimensionless; R e is the recovery efficiency of the reservoir, dimensionless. Graph the Tong's curve expression to obtain a new chart of the single-channel Tong's curve.

13. The prediction method for the recovery factor of a fractured-vuggy oil and gas reservoir according to claim 12, wherein, When in the case of the logarithmic relationship of the relative permeability curve showing a downward slope, the recovery factor R of the reservoir o can all be expressed by the relationship of the average water saturation: Wherein, R o is the recovery factor of the reservoir, dimensionless; S oi is the initial oil saturation of the reservoir, dimensionless; S wi is the initial water saturation of the reservoir, dimensionless; N p is the cumulative oil production, 10,000 m³; N w is the water drive controlled reserves, 10,000 m³.

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