Quantitative evaluation method for energy of natural water body in subdivided region

Abstract

The invention belongs to the technical field of petroleum and natural gas development, and particularly relates to a quantitative evaluation method for natural water energy in a subdivided region. The invention discloses a method for quantitatively evaluating energy of a natural water body in a subdivided region. The method comprises the following steps: collecting geological parameters and production data of a to-be-evaluated region; under the stable production condition, the change value of the formation pressure is determined; obtaining oil well stratum water production and oil production data in the to-be-analyzed stage and water injection rate data of surrounding water injection wells, and determining single well absolute stratum liquid outlet amount; determining a natural water body energy coefficient of the to-be-evaluated region; and carrying out category distinguishing on the natural water body energy coefficient data by adopting a clustering analysis method, and carrying out natural energy region division on the to-be-evaluated region in combination with oil well coordinates. Geology, water injection, liquid production and flowing pressure factors are comprehensively considered, the material balance method, the statistical method and the numerical simulation technology are utilized, the size and distribution characteristics of the natural water body of the oil reservoir are determined, development areas are divided, and development policy making is effectively guided.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas development technology, and specifically relates to a method for quantitative evaluation of the energy of natural water bodies in subdivided areas. Background Technology

[0002] The Jurassic strata in the Ordos Basin are generally characterized by edge-and-bottom water reservoirs. Influenced by the energy of natural water bodies, these reservoirs exhibit high initial single-well oil production, but are prone to water flooding after 3-5 years of production. Since 2021, breakthroughs have been achieved in the exploration of the Chang 8 reservoir in the western Ordos Basin, discovering a similar reservoir with reserves exceeding 100 million cubic meters, representing a crucial area for future reserve and production increases. Due to the formation pressure coefficient of 0.7-1.0 in these reservoirs, simultaneous water injection and advanced water injection are generally employed for development. After development, the reservoir's driving energy consists of both natural and artificially supplemented energy. Therefore, evaluating the energy of natural water bodies in the reservoir is a crucial task in oil and gas development. The evaluation results are of great significance for formulating development technology policies in areas with abundant natural energy, extending the oil recovery period in low water-cut areas, and improving reservoir recovery rates.

[0003] Current traditional natural energy assessments typically use the dimensionless elasticity production ratio N. PR And the formation pressure drop D when 1% of the geological reserves are extracted pr Two indicators. However, in practical field applications, the calculated parameters (control reserves, compressibility factor, formation pressure) in the evaluation indicators are difficult to determine. Furthermore, the impact of energy replenishment on water energy and the differences in natural energy distribution and formation pressure caused by reservoir heterogeneity remain unresolved. For example, in the Huanqing Jurassic XX65 well area, the dimensionless elastic production ratio N... pr And the formation pressure drop D when 1% of the geological reserves are extracted pr Two indicators suggest that the reservoir has certain natural energy, but development dynamics show that water exists only at the periphery of the reservoir, and the formation energy in the main core area is insufficient, resulting in a lack of targeted water injection development policies. Summary of the Invention

[0004] To address the aforementioned problems, the purpose of this invention is to provide a quantitative evaluation method for the energy of natural water bodies in subdivided regions. This method comprehensively considers geological, water injection, fluid production, and flow pressure factors, and utilizes material balance, statistical, and numerical simulation techniques to clarify the size and distribution characteristics of natural water bodies in oil reservoirs, delineate development areas, and effectively guide the formulation of development policies.

[0005] The technical solution of this invention is: a method for quantitative evaluation of the energy of natural water bodies in subdivided areas, comprising the following steps:

[0006] S1: Collect geological parameters and production data for the area to be evaluated;

[0007] S2: Determine the change in formation pressure under stable production conditions;

[0008] S3: Obtain formation water and oil production data from oil wells at the beginning and end of the evaluation phase, as well as water injection data from surrounding injection wells, to determine the absolute formation fluid production rate of a single well. Specifically:

[0009]

[0010] In the formula, Q w To accumulate water production in the oil well, Q o To accumulate oil production from the oil well, B o Where ρ is the crude oil volume coefficient, ρ is the crude oil density, and Q is the crude oil volume coefficient. inj The cumulative amount of water injected into the oil well by the surrounding water injection wells;

[0011] S4: Based on the formation pressure change determined in step S2 and the absolute formation fluid production rate of a single well determined in step S3, determine the energy coefficient of the natural water body in the area to be evaluated. The specific formula is as follows:

[0012]

[0013] In the formula, I is the energy coefficient of the natural water body, Q is the absolute cumulative fluid production of the formation, and ΔP represents the change in formation pressure.

[0014] S5: Draw scatter plots and planar distribution maps of the energy coefficients of natural water bodies, use cluster analysis to classify the energy coefficient data of natural water bodies, and divide the area to be evaluated into natural energy regions by combining the oil well coordinates.

[0015] In step S1, the geological parameters collected for the area to be evaluated include oil layer thickness, permeability, oil layer depth, and well bottom coordinates. Production data includes daily water production, daily oil production, dynamic fluid level, and daily water injection from adjacent wells for a period of time under the condition that the oil well production regime remains unchanged. For fractured reservoirs, stable production is achieved for 7-10 days; for low-permeability reservoirs, stable production is achieved for 20-25 days; and for ultra-low permeability reservoirs, stable production is achieved for 30-40 days.

[0016] The specific calculation process for the change in formation pressure in step S2 is as follows:

[0017] For oil wells, the relationship between production rate and reservoir properties and formation pressure for radial formation oil wells is as follows:

[0018]

[0019] P wf =[(1-f w )ρ o +f w ρ w g(Hh)

[0020] Therefore, the expression for formation pressure is derived as follows:

[0021]

[0022] The change in formation pressure is:

[0023]

[0024] In the formula, P wf For the bottom hole flowing pressure, P wfi P wfn To evaluate the initial and final wellbore bottom flowing pressure, q i q n To evaluate the daily liquid production at the beginning and end of the period, μ i μ n To evaluate the initial and final crude oil viscosity, S i S n To evaluate the epidermal coefficient at the initial and final stages, k i k n To evaluate the initial and final penetration rates, f w H represents the water cut, H represents the depth (vertical depth) of the oil layer, and h represents the dynamic fluid level. o p is the oil layer thickness. o p is the density of crude oil. w Let g be the density of the formation water, g be the gravitational acceleration, and r be the velocity. e Let r be the oil drain radius. w Let denot be the well radius, and ΔP be the change in well pressure.

[0025] Since the single-well fluid production remains constant, and the skin coefficient, permeability, and fluid viscosity remain constant over a short period, the specific changes in formation pressure refer to the changes in well flowing pressure in the area to be evaluated at the beginning and end of the evaluation phase.

[0026] ΔP=(P wfi -P wfn )+

[0027] In the formula, P wfi P wfn To evaluate the bottom hole flowing pressure in the initial and final stages, ΔP represents the change in well pressure.

[0028] In step S3, the moisture content f w To calculate the overall water cut, stable daily water production and daily oil production data from single wells for 1-n consecutive days (n≥3) are selected from the initial and final stages of the evaluation phase. The specific formula is as follows:

[0029]

[0030] In the formula, Q wi For the daily water production on day i, m3 Q oi For the daily oil production on day i, t; p o Crude oil density, f w This refers to the moisture content.

[0031] In step S3, the cumulative water production and cumulative oil production data of oil wells are obtained by summing the daily water production and daily oil production of a single well from the production data of the area to be evaluated collected in step S1. The crude oil density and crude oil volume coefficient are obtained through test data. The cumulative injected water volume of the surrounding water injection wells on the oil wells is determined in the following specific process:

[0032] S31: With the injection well as the center, n oil wells of equal production rate are uniformly arranged on the plane along a circle with radius R.

[0033] S32: Considering the influence of oil layer thickness, the seepage capacity between water wells and oil wells in the model of step S31 is expressed as follows:

[0034] k=hKρg / η

[0035] In the formula, k is the seepage capacity, and h o Where ρ is the oil layer thickness, K is the permeability, ρ is the fluid density, g is the gravitational acceleration, and η is the viscosity.

[0036] S33: Since the fluid density, gravitational acceleration, and fluid viscosity are consistent in the model of step S31, the seepage capacity between water wells and oil wells is directly proportional to the oil layer thickness and permeability, i.e., k∝hK. According to the principle of mass balance, the cumulative water injection volume of the water injection well is uniformly applied to all oil wells in the water injection well group. Considering the differences in K and h for oil wells in each direction, the effective water injection volume of the water well on the surrounding single oil well is:

[0037]

[0038] In the formula, h i Let K be the thickness of the oil layer in the i-th oil well. i Let Q be the permeability of the i-th oil well, n be the number of oil wells in the water injection well group, and Q be the permeability of the i-th oil well. inj The cumulative water injection volume of the injection well.

[0039] In step S5, the clustering analysis methods used include Kriging difference, kmeans, FCM, KFCM, DBSCAN, or MeanShift.

[0040] The technical advantages of this invention are as follows: 1. By comprehensively considering formation production, injection volume, and pressure changes, this invention simplifies calculations and solves the problem of difficulty in obtaining various parameters in existing evaluation methods, making it suitable for field applications; 2. This invention fully considers the heterogeneity of the reservoir and can use single-well dynamic evaluation to describe the size characteristics and planar distribution patterns of natural water bodies, which can be used to subdivide reservoir areas and provide more guidance for the formulation of development policies; 3. This invention combines geological factors to establish a model to analyze the relative effective water injection volume of a single oil well in a water injection well group, solving the problem of existing technologies that simply aggregate and divide water injection volume based on the number of oil wells in the well group; 4. This invention comprehensively considers geological, water injection, fluid production, and flowing pressure factors, and uses material balance methods, statistical methods, and numerical simulation techniques to clarify the size and distribution characteristics of natural water bodies in the reservoir, delineate development areas, and effectively guide the formulation of development policies.

[0041] The following will provide further explanation in conjunction with the accompanying drawings. Attached Figure Description

[0042] Figure 1 This is a flowchart illustrating a method for quantitative evaluation of energy in subdivided natural water bodies according to an embodiment of the present invention.

[0043] Figure 2 This is a schematic diagram of the water injection volume model of the water well acting on the surrounding oil wells in an embodiment of the present invention.

[0044] Figure 3 This is a regional map of a bottom-water reservoir in Huanqing Oilfield, as described in an embodiment of the present invention, divided according to natural energy development. Detailed Implementation

[0045] Example 1

[0046] like Figure 1 As shown, the technical solution of the present invention is: a method for quantitative evaluation of the energy of natural water bodies in subdivided areas, comprising the following steps:

[0047] S1: Collect geological parameters and production data for the area to be evaluated;

[0048] S2: Determine the change in formation pressure under stable production conditions;

[0049] S3: Obtain formation water and oil production data from oil wells at the beginning and end of the evaluation phase, as well as water injection data from surrounding injection wells, to determine the absolute formation fluid production rate of a single well. Specifically:

[0050]

[0051] In the formula, Q w To accumulate water production in the oil well, Q o To accumulate oil production from the oil well, B o Where ρ is the crude oil volume coefficient, ρ is the crude oil density, and Q is the crude oil volume coefficient.inj The cumulative amount of water injected into the oil well by the surrounding water injection wells;

[0052] S4: Based on the formation pressure change determined in step S2 and the absolute formation fluid production rate of a single well determined in step S3, determine the energy coefficient of the natural water body in the area to be evaluated. The specific formula is as follows:

[0053]

[0054] In the formula, I is the energy coefficient of the natural water body, Q is the absolute cumulative fluid production of the formation, and ΔP represents the change in formation pressure.

[0055] S5: Draw scatter plots and planar distribution maps of the energy coefficients of natural water bodies, use cluster analysis to classify the energy coefficient data of natural water bodies, and divide the area to be evaluated into natural energy regions by combining the oil well coordinates.

[0056] In step S1, the geological parameters collected for the area to be evaluated include oil layer thickness, permeability, oil layer depth, and well bottom coordinates. Production data includes daily water production, daily oil production, dynamic fluid level, and daily water injection from adjacent wells for a period of time under the condition that the oil well production regime remains unchanged. For fractured reservoirs, stable production is achieved for 7-10 days; for low-permeability reservoirs, stable production is achieved for 20-25 days; and for ultra-low permeability reservoirs, stable production is achieved for 30-40 days.

[0057] The specific calculation process for the change in formation pressure in step S2 is as follows:

[0058] For oil wells, the relationship between production rate and reservoir properties and formation pressure for radial formation oil wells is as follows:

[0059]

[0060] P wf =[(1-f w )ρ o +f w ρ w g(Hh)

[0061] Therefore, the expression for formation pressure is derived as follows:

[0062]

[0063] The change in formation pressure is:

[0064]

[0065] In the formula, P wf For the bottom hole flowing pressure, P wfi P wfnTo evaluate the initial and final wellbore bottom flowing pressure, q i q n To evaluate the daily liquid production at the beginning and end of the period, μ i μ n To evaluate the initial and final crude oil viscosity, S i S n To evaluate the epidermal coefficient at the initial and final stages, k i k n To evaluate the initial and final penetration rates, f w H represents the water cut, H represents the depth (vertical depth) of the oil layer, and h represents the dynamic fluid level. o p is the oil layer thickness. o p is the density of crude oil. w Let g be the density of the formation water, g be the gravitational acceleration, and r be the velocity. e Let r be the oil drain radius. w Let denot be the well radius, and ΔP be the change in well pressure.

[0066] Since the single-well fluid production remains constant, and the skin coefficient, permeability, and fluid viscosity remain constant over a short period, the specific changes in formation pressure refer to the changes in well flowing pressure in the area to be evaluated at the beginning and end of the evaluation phase.

[0067] ΔP=(P wfi -P wfn )+

[0068] In the formula, P wfi P wfn To evaluate the bottom hole flowing pressure in the initial and final stages, ΔP represents the change in well pressure.

[0069] In step S3, the moisture content f w To calculate the overall water cut, stable daily water production and daily oil production data from single wells for 1-n consecutive days (n≥3) are selected from the initial and final stages of the evaluation phase. The specific formula is as follows:

[0070]

[0071] In the formula, Q wi For the daily water production on day i, m 3 Q oi For the daily oil production on day i, t; p o Crude oil density, f w This refers to the moisture content.

[0072] In step S3, the cumulative water production and cumulative oil production data of oil wells are obtained by summing the daily water production and daily oil production of a single well from the production data of the area to be evaluated collected in step S1. The crude oil density and crude oil volume coefficient are obtained through test data. The cumulative injected water volume of the surrounding water injection wells on the oil wells is determined in the following specific process:

[0073] S31: As Figure 2 As shown, n oil wells with equal production rates are uniformly arranged along a circle of radius R on a plane, with the water injection well as the center.

[0074] S32: Considering the influence of oil layer thickness, the seepage capacity between water wells and oil wells in the model of step S31 is expressed as follows:

[0075] k=hKρg / η

[0076] In the formula, k is the seepage capacity, and h o Where ρ is the oil layer thickness, K is the permeability, ρ is the fluid density, g is the gravitational acceleration, and η is the viscosity.

[0077] S33: Since the fluid density, gravitational acceleration, and fluid viscosity are consistent in the model of step S31, the seepage capacity between water wells and oil wells is directly proportional to the oil layer thickness and permeability, i.e., k∝hK. According to the principle of mass balance, the cumulative water injection volume of the water injection well is uniformly applied to all oil wells in the water injection well group. Considering the differences in K and h for oil wells in each direction, the effective water injection volume of the water well on the surrounding single oil well is:

[0078]

[0079] In the formula, h i Let K be the thickness of the oil layer in the i-th oil well. i Let Q be the permeability of the i-th oil well, n be the number of oil wells in the water injection well group, and Q be the permeability of the i-th oil well. inj The cumulative water injection volume of the injection well.

[0080] In step S5, commonly used clustering analysis methods include Kriging difference, kmeans, FCM, KFCM, DBSCAN, or MeanShift.

[0081] Example 2

[0082] Using the quantitative evaluation method for the energy of natural water bodies in a subdivided area as described in Example 1, a certain edge-bottom water reservoir in the Huanqing Oilfield was divided into regions based on the development of natural energy. The specific process is as follows:

[0083] S1: Collect geological parameters and production data for the area to be evaluated;

[0084] S2: Determine the change in formation pressure under stable production conditions;

[0085] In the initial stage, the dynamic fluid level of the Huanqing XX-1 single well was 238m, with an overall water cut of 23%. In the final stage, the dynamic fluid level reached 1074m, with an overall water cut of 25%. The vertical depth of the oil layer was 2600m, and the crude oil density was 826kg / m³. 3Formation water density 1000 kg / m³ 3 The pressure change value is:

[0086] ΔP=(0.23×1000+826×(1-0.23))×(2600-238) / 1000-(0.25×1000+826×(1-0.25))×(2600-1074) / 1000=0.72MPa;

[0087] S3: Obtain formation water production and oil production data of oil wells during the evaluation phase, as well as water injection data of surrounding injection wells, to determine the absolute formation fluid production of a single well, specifically:

[0088]

[0089] In the formula, Q is the absolute formation fluid yield of a single well, Q w To accumulate water production in the oil well, Q o To accumulate oil production from the oil well, B o ρ is the crude oil volume coefficient. o Q is the density of crude oil. inj The cumulative amount of water injected into the oil well by the surrounding water injection wells;

[0090] Evaluation stage of Huanqing XX-1 well Q w 792m 3 Q o For 2309t, B o ρ is 1.2 o It is 0.826×10 3 kg / m 3 Q inj 515m 3 (Q inj The calculation method is shown in S32-S33);

[0091] Therefore, Q = 792 + 1.2 × 2309 / 0.826 - 515 = 3631m 3 ;

[0092] S4: Based on the formation pressure change determined in step S2 and the absolute formation fluid production rate of a single well determined in step S3, determine the energy coefficient of the natural water body in the area to be evaluated. The specific formula is as follows:

[0093]

[0094] In the formula, I is the energy coefficient of the natural water body, Q is the absolute cumulative fluid production of the formation, and ΔP represents the change in formation pressure; During the evaluation stage of the Huanqing XX-1 well, the energy coefficient of the natural water body I = 3631 / 0.72 = 5043m 3 / Mpa;

[0095] Similarly, the natural energy coefficients of all oil wells in the area to be evaluated can be calculated, as shown in Table 1 below:

[0096] Table 1 Natural Energy Coefficient of Oil Wells in the Area to be Evaluated

[0097]

[0098]

[0099] S5: Draw scatter plots and planar distribution maps of the energy coefficients of natural water bodies, use cluster analysis to classify the energy coefficient data of natural water bodies, and divide the area to be evaluated into natural energy regions by combining the oil well coordinates.

[0100] In step S1, the geological parameters collected for the area to be evaluated include oil layer thickness, permeability, oil layer depth and well bottom coordinates. The production data include the daily water production, daily oil production, dynamic fluid level and daily water injection of adjacent wells during a period of stable production under the condition that the oil well production system remains unchanged.

[0101] The specific calculation process for the change in formation pressure in step S2 is as follows:

[0102] For oil wells, the relationship between production rate and reservoir properties and formation pressure for radial formation oil wells is as follows:

[0103]

[0104] P wf =[(1-f w )ρ o +f w ρ w g(Hh)

[0105] Therefore, the expression for formation pressure is derived as follows:

[0106]

[0107] The change in formation pressure is:

[0108]

[0109] In the formula, P wf For the bottom hole flowing pressure, P wfi P wfn To evaluate the initial and final wellbore bottom flowing pressure, q i q n To evaluate the daily liquid production at the beginning and end of the period, μ i μ n To evaluate the initial and final crude oil viscosity, S i S n To evaluate the epidermal coefficient at the initial and final stages, ki k n To evaluate the initial and final penetration rates, f w H represents the water cut, H represents the depth (vertical depth) of the oil layer, and h represents the dynamic fluid level. o p is the oil layer thickness. o p is the density of crude oil. w Let g be the density of the formation water, g be the gravitational acceleration, and r be the velocity. e Let r be the oil drain radius. w Let denot be the well radius, and ΔP be the change in well pressure.

[0110] Since the single-well fluid production remains constant, and the skin coefficient, permeability, and fluid viscosity remain constant over a short period, the specific changes in formation pressure refer to the changes in well flowing pressure in the area to be evaluated at the beginning and end of the evaluation phase.

[0111] ΔP=(P wfi -P wfn )+

[0112] In the formula, P wfi P wfn To evaluate the bottom hole flowing pressure in the initial and final stages, ΔP represents the change in well pressure.

[0113] In step S3, the moisture content f w To calculate the overall water cut, stable daily water production and daily oil production data from a single well for 1-n consecutive days (n≥3 days) are selected from the initial and final stages of the evaluation phase. The specific formula is as follows:

[0114]

[0115] In the formula, Q wi For the daily water production on day i, m 3 Q oi For the daily oil production on day i, t; p o Crude oil density, p w Formation water density, f w The overall water cut is calculated. During the initial evaluation phase of the Huanqing XX-1 well, the oil production and water production over the first three consecutive days were Q... w1 =1.3t / d, Q o2 = 3.3t / d; Q w2 =1.2t / d, Q o2 = 3.4t / d; Q w3 =1.2t / d, Q o3 = 3.5t / d; the oil production and water production for the three consecutive days at the end of the evaluation phase were Q w1 =1.3t / d, Q o2 = 3.3t / d; Q w2 =1.2t / d, Q o2= 3.4t / d; Q w3 =1.2t / d, Q o3 = 3.5t / d;

[0116] Then the initial comprehensive water content f w =(1.4+1.2+1.3) / (1.4+3.1 / 0.826+1.2+3.2 / 0.826+1.3+3.3 / 0.826)=23%, and similarly, the final comprehensive water content f can be obtained. wn =25%.

[0117] In step S3, the cumulative water production and cumulative oil production data of oil wells are obtained by summing the daily water production and daily oil production of a single well from the production data of the area to be evaluated collected in step S1. The crude oil density and crude oil volume coefficient are obtained through test data. The cumulative injected water volume of the surrounding water injection wells on the oil wells is determined in the following specific process:

[0118] S31: As Figure 2 As shown, n oil wells with equal production rates are uniformly arranged along a circle of radius R on a plane, with the water injection well as the center.

[0119] S32: Considering the influence of oil layer thickness, the seepage capacity between water wells and oil wells in the model of step S31 is expressed as follows:

[0120] k=hKρg / η

[0121] In the formula, k is the seepage capacity, and h o Let K be the oil layer thickness, K be the permeability, ρ be the fluid density, g be the gravitational acceleration, and η be the viscosity.

[0122] S33: Since the fluid density, gravitational acceleration, and fluid viscosity are consistent in the model of step S31, the seepage capacity between water wells and oil wells is directly proportional to the oil layer thickness and permeability, i.e., k∝hK. According to the principle of mass balance, the cumulative water injection volume of the water injection well is uniformly applied to all oil wells in the water injection well group. Considering the differences in K and h for oil wells in each direction, the effective water injection volume of the water well on the surrounding single oil well is:

[0123]

[0124] In the formula, h i Let K be the thickness of the oil layer in the i-th oil well. i Let Q be the permeability of the i-th oil well, n be the number of oil wells in the water injection well group, and Q be the permeability of the i-th oil well. inj The cumulative water injection volume of the injection well.

[0125] The Huanqing XX-1 well is affected by two injection wells, Huanqing XX-1W and Huanqing XX-2W, in terms of planar influence, with cumulative injection volumes of Q. inj1 =2264m3 Q inj2 =1581m 3 There are 8 oil wells in the Huanqing XX-1W well group and 5 oil wells in the Huanqing XX-2W well group. The parameters of the oil wells are shown in Table 2 below:

[0126] Table 2 Oil Well Parameters

[0127]

[0128] The effective water injection volume of Huanqing XX-1 well from surrounding wells is:

[0129] 2264×83 / (83+48+61+80+131+182+178+196)+1581×83 / (83+48+61+103+117)=515m 3 ;

[0130] In step S5, commonly used clustering analysis methods include Kriging interpolation, Kmeans, FCM, KFCM, DBSCAN, or MeanShift. In Example 2, step S5 uses ordinary Kriging interpolation to classify the obtained natural water body energy coefficient data. The specific process is as follows:

[0131] First, the energy coefficient data of the natural water body in each well is used as sample data, and the distance d between all sample data points is determined. There are n(n-1) / 2 different distances, and the specific formula for d is:

[0132]

[0133] In the formula, d is the distance between sample points, xi and y i Let xj and yj be the x and y coordinates of well i at the bottom. j Let be the x and y coordinates of well j at the bottom, and n be the number of paired samples separated by d;

[0134] Secondly, sort all distances d from smallest to largest and divide them into n groups, then calculate dist = (dmax - dmin) / n;

[0135] Finally, calculate the average distance of each of the n distance groups, substitute the average distance into the semivariogram formula, calculate the experimental variance corresponding to each distance group, and compile a distance-semivariogram scatter plot to obtain the fit coefficients and corresponding parameters. The specific formula for calculating the semivariogram is as follows:

[0136]

[0137] In the formula, z(x) i ) for the corresponding x iThe attribute value of the coordinate point is the energy coefficient of the natural water body; xi is the x-coordinate of the i-th well, d is the average distance between n sample points, and n is the number of data points;

[0138] Based on the obtained fitting coefficients and corresponding parameters, the energy coefficient data of natural water bodies are categorized, multiple data ranges are simulated and determined, and the area to be evaluated is divided into natural energy regions based on oil well coordinates. The final results are as follows: Figure 3 As shown in the figure, the natural energy index is high in the northern and southeastern parts of the well area, and the risk of flooding must be fully considered during development. Based on the distribution pattern of natural energy, the well area can be divided into three study areas: the northern, southeastern, and central parts. Due to the significant energy differences, development technology policies need to be formulated for each area.

[0139] The above description is only a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any changes or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for quantitative evaluation of energy in subdivided natural water bodies, characterized in that: Includes the following steps: S1: Collect geological parameters and production data for the area to be evaluated; S2: Determine the change in formation pressure under stable production conditions; S3: Obtain formation water and oil production data from oil wells at the beginning and end of the evaluation phase, as well as water injection data from surrounding injection wells, to determine the absolute formation fluid production rate of a single well. Specifically: In the formula, Q w To accumulate water production in the oil well, Q o To accumulate oil production from the oil well, B o Where ρ is the crude oil volume coefficient, ρ is the crude oil density, and Q is the crude oil volume coefficient. inj The cumulative amount of water injected into the oil well by the surrounding water injection wells; S4: Based on the formation pressure change determined in step S2 and the absolute formation fluid production rate of a single well determined in step S3, determine the energy coefficient of the natural water body in the area to be evaluated. The specific formula is as follows: In the formula, I is the energy coefficient of the natural water body, Q is the absolute cumulative fluid production of the formation, and ΔP represents the change in formation pressure. S5: Draw scatter plots and planar distribution maps of the energy coefficients of natural water bodies, use cluster analysis to classify the energy coefficient data of natural water bodies, and divide the area to be evaluated into natural energy regions by combining the oil well coordinates.

2. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 1, characterized in that: In step S1, the geological parameters collected for the area to be evaluated include oil layer thickness, permeability, oil layer depth, and well bottom coordinates. Production data includes daily water production, daily oil production, dynamic fluid level, and daily water injection from adjacent wells for a period of time under the condition that the oil well production regime remains unchanged. For fractured reservoirs, stable production is achieved for 7-10 days; for low-permeability reservoirs, stable production is achieved for 20-25 days; and for ultra-low permeability reservoirs, stable production is achieved for 30-40 days.

3. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 1, characterized in that: The specific calculation process for the change in formation pressure in step S2 is as follows: For oil wells, the relationship between production rate and reservoir properties and formation pressure for radial formation oil wells is as follows: P wf =[(1-f w )r o +f w r w ]g(Hh) Therefore, the expression for formation pressure is derived as follows: The change in formation pressure is: In the formula, P wf For the bottom hole flowing pressure, P wfi P wfn To evaluate the initial and final wellbore bottom flowing pressure, q i q n To evaluate the daily liquid production at the beginning and end of the period, μ i μ n To evaluate the initial and final crude oil viscosity, S i S n To evaluate the epidermal coefficient at the initial and final stages, k i k n To evaluate the initial and final penetration rates, f w H represents the water cut, H represents the depth (vertical depth) of the oil layer, and h represents the dynamic fluid level. o p is the oil layer thickness. o p is the density of crude oil. w Let g be the density of the formation water, g be the gravitational acceleration, and r be the velocity. e Let r be the oil drain radius. w Let denot be the well radius, and ΔP be the change in well pressure.

4. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 3, characterized in that: Since the single-well fluid production remains constant, and the skin coefficient, permeability, and fluid viscosity remain constant over a short period, the specific changes in formation pressure refer to the changes in well flowing pressure in the area to be evaluated at the beginning and end of the evaluation phase. ΔP=(P wfi -P wfn )+ In the formula, P wfi P wfn To evaluate the bottom hole flowing pressure in the initial and final stages, ΔP represents the change in well pressure.

5. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 3, characterized in that: In step S3, the moisture content f w To calculate the overall water cut, stable daily water production and daily oil production data from single wells for 1-n consecutive days (n≥3) are selected from the initial and final stages of the evaluation phase. The specific formula is as follows: In the formula, Q wi For the daily water production on day i, m 3 Q oi For the daily oil production on day i, t; p o Crude oil density, f w This refers to the moisture content.

6. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 1, characterized in that: In step S3, the cumulative water production and cumulative oil production data of oil wells are obtained by summing the daily water production and daily oil production of a single well from the production data of the area to be evaluated collected in step S1. The crude oil density and crude oil volume coefficient are obtained through test data. The cumulative injected water volume of the surrounding water injection wells on the oil wells is determined in the following specific process: S31: With the injection well as the center, n oil wells of equal production rate are uniformly arranged on the plane along a circle with radius R. S32: Considering the influence of oil layer thickness, the seepage capacity between water wells and oil wells in the model of step S31 is expressed as follows: k=hKρg / η In the formula, k is the seepage capacity, and h o Where ρ is the oil layer thickness, K is the permeability, ρ is the fluid density, g is the gravitational acceleration, and η is the viscosity. S33: Since the fluid density, gravitational acceleration, and fluid viscosity are consistent in the model of step S31, the seepage capacity between water wells and oil wells is directly proportional to the oil layer thickness and permeability, i.e., k∝hK. According to the principle of mass balance, the cumulative water injection volume of the water injection well is uniformly applied to all oil wells in the water injection well group. Considering the differences in K and h for oil wells in each direction, the effective water injection volume of the water well on the surrounding single oil well is: In the formula, h i Let K be the thickness of the oil layer in the i-th oil well. i Let Q be the permeability of the i-th oil well, n be the number of oil wells in the water injection well group, and Q be the permeability of the i-th oil well. inj The cumulative water injection volume of the injection well.

7. The method for quantitative evaluation of energy in subdivided natural water bodies according to claim 1, characterized in that: In step S5, the clustering analysis methods used include Kriging difference, kmeans, FCM, KFCM, DBSCAN, or MeanShift.

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