Method for determining reasonable initial production pressure difference of single well in offshore medium-light oil reservoir

Abstract

The application discloses a method for determining a reasonable initial production pressure difference of a single well in a marine medium-light oil reservoir, and comprises the following steps: calculating an oil phase index and a water phase index; calculating a dimensionless liquid production index under different water cut; calculating a dimensionless liquid lifting multiple under different water cut according to the dimensionless liquid production index; calculating a maximum production pressure difference under the condition of formation sand production; calculating a maximum pressure difference under the condition of ensuring minimum submergence of an electric submersible pump; determining a single well maximum production pressure difference by comprehensively considering the conditions of sand production and pump submergence; determining an oilfield limit water cut according to economic parameters of oilfield operation; determining a single well initial water cut by a numerical simulation method; and determining a development initial reasonable production pressure difference according to the dimensionless liquid lifting multiple of the single well initial water cut and the limit water cut. The application can simply, rapidly and accurately determine the single well initial reasonable production pressure difference in the medium-light oil reservoir, realize liquid quantity stability in the single well initial stage and the high water cut stage, and guide oilfield development plan compilation and development adjustment.

Description

Technical Field

[0001] This invention belongs to the field of petroleum resource exploration and development technology, specifically relating to a method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir. Background Technology

[0002] Offshore oilfield exploration and development is a high-risk, high-investment, and high-return endeavor. Constrained by the marine environment, the area of ​​offshore platforms is extremely limited, and the size and weight of various facilities and equipment are strictly limited. Therefore, rational design is essential to ensure that all processing facilities can meet the oilfield's processing needs while fully utilizing their capacity and preventing waste. In medium-light oil reservoirs, due to their low underground viscosity, the dimensionless production index is lower during the high water-cut period than during the waterless production period. If wells maintain the same production pressure differential, the well fluid volume will decrease later, resulting in idle and wasted oilfield processing capacity designed based on initial production capacity. Furthermore, because the oilfield is at different stages and well locations at the time of well commissioning, the relationship between the dimensionless production index in the initial production phase and the dimensionless production index in the high water-cut period is not constant. The variation pattern of single-well production volume is complex. Therefore, a method for determining a reasonable initial production pressure differential for single wells in medium-light oil reservoirs is urgently needed to achieve stable fluid volume in the initial and high water-cut periods.

[0003] Currently, the conventional methods for determining the initial production pressure differential of a single well in medium-light oil reservoirs are: 1) the analogy method, which uses the production pressure differential of an already operational well or other similar operational oilfields as the initial production pressure differential of the single well. This method lacks a theoretical basis, and the value depends on the similarity of the analogy object, resulting in a large error. 2) directly using the maximum production pressure differential as the initial production pressure differential. This method aims for rapid oil production in the early stage, but it leads to serious waste of later processing facilities. Furthermore, a considerable proportion of oil in medium-light oil reservoirs is produced during the high water-cut period, so this method will affect the high-quality development of medium-light oil fields. Summary of the Invention

[0004] This invention is proposed to address the technical problems of the lack of theoretical basis and large value errors in the existing methods for determining the reasonable initial production pressure difference of a single well in a light oil reservoir. Its purpose is to provide a method for determining the reasonable initial production pressure difference of a single well in a medium-light oil reservoir at sea.

[0005] This invention is achieved through the following technical solution: A method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir includes the following steps: S1. Based on the relative permeability data of the oil field, calculate the oil phase index and water phase index, specifically including the following steps: S11. Establish the relationship between relative oil-water permeability and water saturation. The relationship between the relative permeability of oil and water and the water saturation is as follows: In the formula: The water phase permeability is dimensionless. The value is the oil phase permeability, dimensionless. The water saturation level is dimensionless. The slope It is the intercept, and and These are characteristic parameters, dimensionless; S12. Based on the oil-water relative permeability data from the oilfield's relative permeability data, draw... The relationship curve is linearly fitted to obtain its characteristic parameters. and ; S13, according to Calculate the oil phase index and water phase index using the characteristic parameters of the relationship curve and the endpoint values ​​of the relative permeability curve; The formula for calculating the oil phase index is as follows: In the formula: The oil phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are dimensionless characteristic parameters of the relationship curve. The formula for calculating the aqueous phase index is as follows: In the formula: The aqueous phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are dimensionless characteristic parameters of the relationship curve. S2. Based on the oil phase index, water phase index, and oil-water viscosity data of the oilfield, calculate the dimensionless production index at different water cuts, specifically including the following steps: S21. Based on the oil phase index and the water phase index, calculate the actual water saturation, relative permeability of the oil phase, and relative permeability of the water phase under different normalized water saturation. The formula for calculating the actual water saturation is as follows: In the formula: This represents the actual water saturation level, which is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; Normalized water saturation, dimensionless; The formula for calculating the relative permeability of the oil phase is: In the formula: The relative permeability of the oil phase is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; Normalized water saturation, dimensionless; The oil phase index is dimensionless. The formula for calculating the relative permeability of the aqueous phase is: In the formula: The relative permeability of the aqueous phase is dimensionless. The relative permeability of the water phase at residual oil saturation is dimensionless. Normalized water saturation, dimensionless; The aqueous phase index is dimensionless. S22. Calculate the water content under different normalized water saturation levels based on the relative permeability of the oil phase, the relative permeability of the water phase, and the oil-water viscosity data. The formula for calculating the water content under different normalized water saturation is as follows: In the formula: Moisture content, dimensionless; The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is dimensionless. The viscosity of the aqueous phase is expressed in mP·s. The viscosity is the oil phase viscosity, in mP·s. S23. Based on the relative permeability of the oil phase, the relative permeability of the water phase, and the viscosity of the oil and water, calculate the dimensionless liquid production index under different normalized water saturation. The formula for calculating the dimensionless liquid production index under different normalized water saturation is as follows: In the formula: The dimensionless liquid production index is a dimensionless quantity. The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is dimensionless. The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; The viscosity of the aqueous phase is expressed in mP·s. The viscosity is the oil phase viscosity, in mP·s. S3. Calculate the dimensionless extraction ratio at different water contents based on the dimensionless liquid production index, specifically including the following steps: S31. Specify the initial moisture content and use the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index. S32. Calculate the dimensionless extraction ratio at different moisture contents; The formula for calculating the dimensionless extract ratio at different moisture contents is as follows: In the formula: This is a dimensionless liquid extraction ratio, representing the multiple by which the liquid volume increases under the current water content conditions compared to the initial water content conditions. It is dimensionless. The baseline liquid production index is dimensionless. The dimensionless liquid production index is a dimensionless quantity. S4. Considering formation sand production, calculate the maximum production pressure differential, specifically including the following steps: S41. Collect reservoir geological parameters; The reservoir geological parameters include Poisson's ratio, P-wave velocity, rock density, elastic cutoff constant, internal friction angle, cohesion, formation static pressure, and overlying strata pressure. S42. Based on the rock failure criterion, calculate the maximum production pressure differential at the bottom of the well when the rock is sheared and sand is produced. The formula for calculating the maximum production pressure differential of sand produced at the bottom of the well is: In the formula: This represents the maximum production pressure differential at the bottom of the well where sand is produced, expressed in MPa. This represents the original static pressure of the formation, expressed in MPa. This represents the pressure of the overlying strata, expressed in MPa. Poisson's ratio is dimensionless. It is the elastic cutoff constant, which is dimensionless; Cohesion, measured in MPa; This is the internal friction angle, expressed in degrees (°). S5. Calculate the maximum pressure differential to ensure the minimum submersion degree of the electric submersible pump, specifically including the following steps: Offshore oil wells generally use electric submersible pumps (ESPs). During the ESP's lowering process, the total angle change rate of the wellbore must be considered to ensure smooth lowering. Typically, the deflection of the pump unit during lowering is required to be less than 3° / 30m. Simultaneously, to ensure successful wireline retrieval operations later, the well inclination angle at the pump hanger must be considered. Typically, when retrieving a blockage at the ESP's Y-tube, the well inclination angle at the pump hanger must be less than 60°. Furthermore, to ensure normal operation of the ESP and prevent overheating failures, it is necessary to ensure the ESP is submerged to a certain depth in the wellbore, typically requiring a minimum submersion depth of greater than 300 meters. S51. Based on the location of the offshore drilling platform, set the well depth trajectory, determine the deepest point depth with a total angle change rate of less than 3° / 30m and the deepest point depth with a well inclination angle of less than 60°, and the smaller of the two deepest point depths is the maximum depth that the electric submersible pump can enter. S52. Based on the maximum depth and minimum submersion requirements of the electric submersible pump, calculate the maximum bottom-hole flowing pressure to ensure the minimum submersion of the electric submersible pump. The formula for calculating the maximum bottom hole flowing pressure under the condition of ensuring the minimum submersion of the electric submersible pump is as follows: In the formula: The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. The density of the fluid in the wellbore is expressed in g / cm³. 3 ; The acceleration due to gravity is constant, which is 9.8 m / s². 2 ; The depth is in the middle of the reservoir, in meters (m). This is the maximum depth that an electric submersible pump can descend to, in meters (m). Minimum submersion depth, in meters (m). S53. Calculate the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump; The formula for calculating the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump is as follows: In the formula: The maximum pressure differential is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. This represents the original static pressure of the formation, expressed in MPa. The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. S6. Taking into account both sand production and pump submersion conditions, determine the maximum production pressure difference for a single well; The maximum production pressure difference of the single well The maximum production pressure differential for sand production at the bottom of the well. and the maximum pressure difference that ensures the minimum submersion degree of the electric submersible pump. The lower of the two values, if the production pressure differential exceeds this value, will lead to sand production in the formation or failure of the electric submersible pump; The formula for calculating the maximum production pressure differential of a single well is: In the formula: This represents the maximum production pressure differential of a single well, in MPa. The maximum production pressure differential at the bottom of the well where sand is produced, in MPa; The maximum pressure differential is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. S7. Determine the limiting water cut of the oilfield based on the economic parameters of oilfield operation, specifically including the following steps: S71. Collect economic parameters for daily operation of the oilfield; The daily operating economic parameters of the oilfield include the fixed daily operating cost per well, the cost of processing each cubic meter of produced fluid, the selling price of oil, the comprehensive tax rate, the crude oil commodity rate, the profit margin, and the average daily fluid production per well. S72. Calculate the minimum daily oil production limit of a single well; The formula for calculating the minimum daily oil production of a single well is as follows: In the formula: This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. The daily fixed operating cost per well is expressed in US dollars. Cost of processing per cubic meter of produced liquid, in US dollars; This represents the average daily fluid production per well, expressed in cubic meters per day. The selling price of oil is in US dollars per barrel. This is a comprehensive tax rate, dimensionless. The crude oil commodity rate is dimensionless and represents the proportion of crude oil that can be sold after deducting self-consumption such as oilfield power generation. Profit margin, dimensionless; S73. Calculate the limiting water cut of the oilfield based on the minimum daily oil production of a single well. The formula for calculating the limiting water cut of the oilfield is as follows: In the formula: The limiting water cut of the oilfield is dimensionless. This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. This represents the average daily fluid production per well, expressed in cubic meters per day. S8. Determine the initial water cut of a single well using numerical simulation, specifically including the following steps: S81. Based on the oilfield geological model, fluid parameters, and well trajectory data, establish a numerical simulation model of the oilfield. S82. Run the oilfield numerical simulation model and output production parameters such as oil production, water production, gas production, and water cut of a single well on an annual basis. The water cut of the first year is the initial water cut of the single well. Due to different stages of oilfield development and different well locations, the initial water cut of a single well is different. In the stage before the oilfield is put into development, a single well is often water-free in the early stage. In the development and adjustment stage, the lower the oil saturation at the well location, the higher the initial water cut of the single well. S9. Determine the reasonable production pressure differential in the initial stage of development based on the dimensionless fluid extraction ratio of the initial water cut of a single well and the limiting water cut of the oilfield. This includes the following steps: S91. Using the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index, and using the calculation formula for the dimensionless liquid extraction ratio at different moisture contents in step S3, calculate the dimensionless liquid extraction ratio at the initial moisture content. S92. Calculate the reasonable initial production pressure difference for a single well; The formula for calculating the reasonable initial production pressure difference of a single well is as follows: In the formula: The initial production pressure differential for a single well is expressed in MPa. This represents the maximum production pressure differential of a single well, in MPa. The extraction ratio at the limiting water cut of the oilfield is a dimensionless extraction ratio.

[0006] If the extraction ratio at the limiting water cut of the oilfield is greater than 1, it means that the fluid volume will increase in the later stage regardless of the initial production pressure difference of a single well. In this case, the reasonable production pressure difference should be the maximum production pressure difference to improve the initial production of a single well and obtain better economic benefits. If the extraction ratio at the limiting water cut of the oilfield is less than 1, it means that the fluid volume will decrease in the later stage. In order to make full use of the oilfield processing facilities and prevent waste of processing capacity, the initial production pressure difference should be controlled, and the pressure difference should be gradually increased to the maximum production pressure difference in the later stage to keep the fluid production of the oilfield stable in the early and later stages.

[0007] The beneficial effects of this invention are: This invention provides a method for determining the reasonable initial production pressure differential of a single well in a light to medium-grade offshore oil reservoir. This method can quickly and accurately determine the reasonable initial production pressure differential of a single well in a light to medium-grade offshore oil reservoir, thereby achieving stable liquid volume in the initial stage and during the high water-cut period, and guiding the preparation and adjustment of oilfield development plans.

[0008] This invention calculates the oil phase index and water phase index based on the relative permeability data of the oilfield. Combined with oil-water viscosity data, it calculates the dimensionless production index at different water cuts, clarifies the dimensionless fluid extraction ratio at different water cuts, and comprehensively considers formation sand production and pump submersion conditions to determine the maximum production pressure differential of a single well. Based on the economic parameters of the oilfield operation, it determines the limiting water cut of the oilfield. Through numerical simulation, it determines the initial water cut of a single well. Based on the dimensionless fluid extraction ratio of the initial water cut and the limiting water cut, it determines the reasonable production pressure differential in the initial development stage. The theoretical basis is clear, the accuracy is high, and the obtained initial production pressure differential of a single well is reasonable and reliable. Attached Figure Description

[0009] Figure 1 This is a flowchart of the method of the present invention; Figure 2 This is a graph showing the relationship between oil-water interpenetration and water saturation in this invention.

[0010] For those skilled in the art, other related figures can be obtained from the above figures without any creative effort. Detailed Implementation

[0011] To enable those skilled in the art to better understand the technical solution of the present invention, the technical solution of the present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0012] like Figure 1 As shown, a method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir includes the following steps: S1. Based on the relative permeability data of the oilfield (Table 1), calculate the oil phase index and water phase index, specifically including the following steps: Table 1: Oil-Water Relation Data of Bohai Z Oilfield S11. Establish the relationship between relative oil-water permeability and water saturation. The relationship between the relative permeability of oil and water and the water saturation is as follows: In the formula: The water phase permeability is dimensionless. The value is the oil phase permeability, dimensionless. The water saturation level is dimensionless. The slope It is the intercept, and and These are characteristic parameters, dimensionless; S12. Based on the oil-water relative permeability data from the oilfield's relative permeability data, draw... Relationship curve ( Figure 2Perform linear fitting to obtain the characteristic parameters of the relationship curve. and , It is 0.00009643. It is 16.212; S13, according to Calculate the oil phase index and water phase index using the characteristic parameters of the relationship curve and the endpoint values ​​of the relative permeability curve; The formula for calculating the oil phase index is as follows: In the formula: The oil phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are dimensionless characteristic parameters of the relationship curve. The formula for calculating the aqueous phase index is as follows: In the formula: The aqueous phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are dimensionless characteristic parameters of the relationship curve. Based on oil-water interpenetration data It is 0.327. It is 0.259. It is 0.470. It is 1.00, calculated according to the formula. It is 1.796. It is 1.560.

[0013] S2. Based on the oil phase index, water phase index, and oil-water viscosity data of the oilfield, calculate the dimensionless production index at different water cuts, specifically including the following steps: S21. Based on the oil phase index and the water phase index, calculate the actual water saturation, relative permeability of the oil phase, and relative permeability of the water phase under different normalized water saturation. The formula for calculating the actual water saturation is as follows: In the formula: This represents the actual water saturation level, which is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; Normalized water saturation, dimensionless; The formula for calculating the relative permeability of the oil phase is: In the formula: The relative permeability of the oil phase is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; Normalized water saturation, dimensionless; The oil phase index is dimensionless. The formula for calculating the relative permeability of the aqueous phase is: In the formula: The relative permeability of the aqueous phase is dimensionless. The relative permeability of the water phase at residual oil saturation is dimensionless. Normalized water saturation, dimensionless; The aqueous phase index is dimensionless. Will The values ​​from 0 to 1 are subdivided into 20 values, and the actual water saturation is calculated for each value. Relative permeability of oil phase Relative permeability of water phase (Table 2).

[0014] S22. Calculate the water content under different normalized water saturation levels based on the relative permeability of the oil phase, the relative permeability of the water phase, and the oil-water viscosity data. The formula for calculating the water content under different normalized water saturation is as follows: In the formula: Moisture content, dimensionless; The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is dimensionless. The viscosity of the aqueous phase is expressed in mP·s. The viscosity is the oil phase viscosity, in mP·s. Based on actual sampling data from the Z oilfield, the viscosity of the aqueous phase... The viscosity of the oil phase is 0.34 mP·s. The value is 0.59 mP·s. The values ​​from 0 to 1 are subdivided into 20 values, and the moisture content is calculated for each value. (Table 2); S23. Based on the relative permeability of the oil phase, the relative permeability of the water phase, and the viscosity of the oil and water, calculate the dimensionless liquid production index under different normalized water saturation. The formula for calculating the dimensionless liquid production index under different normalized water saturation is as follows: In the formula: The dimensionless liquid production index is a dimensionless quantity. The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is expressed in units of 1. The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; The viscosity of the aqueous phase is expressed in mP·s. The viscosity is the oil phase viscosity, in mP·s. Based on actual sampling data from the oilfield, the viscosity of the aqueous phase... The viscosity of the oil phase is 0.34 mP·s. The value is 0.59 mP·s. The range is subdivided into 20 values ​​from 0 to 1, representing dimensionless liquid production indices. (Table 2).

[0015] Table 2: Dimensionless liquid production index under different normalized water saturation levels S3. Calculate the dimensionless extraction ratio at different water contents based on the dimensionless liquid production index, specifically including the following steps: S31. Specify the initial moisture content and use the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index. S32. Calculate the dimensionless extraction ratio at different moisture contents; The formula for calculating the dimensionless extract ratio at different moisture contents is as follows: In the formula: This is a dimensionless liquid extraction ratio, representing the multiple by which the liquid volume increases under the current water content conditions compared to the initial water content conditions. It is dimensionless. The baseline liquid production index is dimensionless. The dimensionless liquid production index is a dimensionless quantity. Calculate the extraction ratio during the high water content period (water content greater than 40%) when the initial water content is specified as 0 and 40% respectively (Table 3).

[0016] Table 3: Extraction ratio during high water content at different initial water contents The calculation results show that when the initial water cut of the oil well is 0%, the liquid extraction ratio during the high water cut period is less than 1, indicating that under the same production pressure difference, the liquid volume will decrease in the later stage. However, when the initial water cut of the oil well is 40%, the liquid extraction ratio during the high water cut period is greater than 1, indicating that under the same production pressure difference, the liquid volume will increase in the later stage.

[0017] S4. Considering formation sand production, calculate the maximum production pressure differential, specifically including the following steps: S41. Collect reservoir geological parameters; The reservoir geological parameters include Poisson's ratio, P-wave velocity, rock density, elastic cutoff constant, internal friction angle, cohesion, formation static pressure, and overlying strata pressure. S42. Based on the rock failure criterion, calculate the maximum production pressure differential at the bottom of the well when the rock is sheared and sand is produced. The formula for calculating the maximum production pressure differential of sand produced at the bottom of the well is: In the formula: This represents the maximum production pressure differential at the bottom of the well where sand is produced, expressed in MPa. This represents the original static pressure of the formation, expressed in MPa. This represents the pressure of the overlying strata, expressed in MPa. Poisson's ratio is dimensionless. It is the elastic cutoff constant, which is dimensionless; Cohesion, measured in MPa; This is the internal friction angle, expressed in degrees (°). The original formation static pressure of Z oilfield is 28.82 MPa, the pressure of the overlying strata is 64.94 MPa, the Poisson's ratio is 0.29, the elastic cutoff constant is 0.74, the cohesion is 9.08 MPa, and the internal friction angle is 24.95°. Based on the above geological reservoir parameters, the maximum production pressure differential under sand conditions is calculated to be 9.66 MPa.

[0018] S5. Calculate the maximum pressure differential to ensure the minimum submersion degree of the electric submersible pump, specifically including the following steps: Offshore oil wells generally use electric submersible pumps (ESPs). During the ESP's lowering process, the total angle change rate of the wellbore must be considered to ensure smooth lowering. Typically, the deflection of the pump unit during lowering is required to be less than 3° / 30m. Simultaneously, to ensure successful wireline retrieval operations later, the well inclination angle at the pump hanger must be considered. Typically, when retrieving a blockage at the ESP's Y-tube, the well inclination angle at the pump hanger must be less than 60°. Furthermore, to ensure normal operation of the ESP and prevent overheating failures, it is necessary to ensure the ESP is submerged to a certain depth in the wellbore, typically requiring a minimum submersion depth of greater than 300 meters. S51. Based on the location of the offshore drilling platform, set the well depth trajectory, determine the deepest point depth with a total angle change rate of less than 3° / 30m and the deepest point depth with a well inclination angle of less than 60°, and the smaller of the two deepest point depths is the maximum depth that the electric submersible pump can enter. The design trajectory of well A6 in oilfield Z is shown in Table 4. The total angle change rate is less than 3° / 30m, the deepest point is 1542m, the maximum well inclination angle is 49.05°, and the entire well section is less than 60°. Therefore, the maximum depth that the submersible pump can enter is 1542m. S52. Based on the maximum depth and minimum submersion requirements of the electric submersible pump, calculate the maximum bottom-hole flowing pressure to ensure the minimum submersion of the electric submersible pump. The formula for calculating the maximum bottom hole flowing pressure under the condition of ensuring the minimum submersion of the electric submersible pump is as follows: In the formula: The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. The density of the fluid in the wellbore is expressed in g / cm³. 3 ; The acceleration due to gravity is constant, which is 9.8 m / s². 2 ; The depth is in the middle of the reservoir, in meters (m). This is the maximum depth that an electric submersible pump can descend to, in meters (m). Minimum submersion depth, in meters (m). The fluid density in the wellbore is taken as 1.0 g / cm³. 3 The reservoir has a central depth of 2890 m and a gravitational acceleration constant of 9.8 m / s². 2 The minimum submersion depth is taken as 300m, and the maximum bottom hole flowing pressure is calculated to be 16.15MPa to ensure the minimum submersion depth of the electric submersible pump. S53. Calculate the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump; The formula for calculating the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump is as follows: In the formula: The maximum pressure differential is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. This represents the original static pressure of the formation, expressed in MPa. The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. The original formation pressure of Z oilfield is 28.82 MPa. The maximum bottom hole flowing pressure to ensure the minimum submersion of the electric submersible pump is 16.15 MPa. Based on the above geological and reservoir parameters, the maximum pressure difference to ensure the minimum submersion of the electric submersible pump is calculated to be 12.67 MPa. S6. Taking into account both sand production and pump submersion conditions, determine the maximum production pressure difference for a single well; The maximum production pressure difference of the single well The maximum production pressure differential for sand production at the bottom of the well. and the maximum pressure difference that ensures the minimum submersion degree of the electric submersible pump. The lower of the two values, if the production pressure differential exceeds this value, will lead to sand production in the formation or failure of the electric submersible pump; The formula for calculating the maximum production pressure differential of a single well is: In the formula: This represents the maximum production pressure differential of a single well, in MPa. The maximum production pressure differential at the bottom of the well where sand is produced, in MPa; The maximum pressure differential is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. The maximum production pressure differential in Z oilfield under sand production conditions is 9.66 MPa, and the maximum pressure differential under minimum submersion conditions of the electric submersible pump is 12.67 MPa. Therefore, taking into account both sand production and pump submersion conditions, the maximum production pressure differential for a single well is determined to be 9.66 MPa. S7. Determine the limiting water cut of the oilfield based on the economic parameters of oilfield operation, specifically including the following steps: S71. Collect economic parameters for daily operation of the oilfield; The daily operating economic parameters of the oilfield include the fixed daily operating cost per well, the cost of processing each cubic meter of produced fluid, the selling price of oil, the comprehensive tax rate, the crude oil commodity rate, the profit margin, and the average daily fluid production per well. S72. Calculate the minimum daily oil production limit of a single well; The formula for calculating the minimum daily oil production of a single well is as follows: In the formula: This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. The daily fixed operating cost per well is expressed in US dollars. Cost of processing per cubic meter of produced liquid, in US dollars; This represents the average daily fluid production per well, expressed in cubic meters per day. The selling price of oil is in US dollars per barrel. This is a comprehensive tax rate, dimensionless. The crude oil commodity rate is dimensionless and represents the proportion of crude oil that can be sold after deducting self-consumption such as oilfield power generation. Profit margin, dimensionless; Based on the daily operating economic parameters of Oilfield Z, the fixed daily operating cost per well is US$1294.31, the processing cost per cubic meter of produced fluid is US$1.9654, the selling price of oil is US$64.3 / barrel, the oilfield has no self-consumption, the crude oil commercialization rate is 100%, the comprehensive tax rate is 6.6%, and the average daily fluid production per well is 200 cubic meters / day. When the oilfield profit rate is 0, the sales revenue of crude oil just covers the production cost. Based on the above parameters, the minimum limit oil production per well per day is calculated to be 4.47 cubic meters / day. S73. Calculate the limiting water cut of the oilfield based on the minimum daily oil production of a single well. The formula for calculating the limiting water cut of the oilfield is as follows: In the formula: The limiting water cut of the oilfield is dimensionless. This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. This represents the average daily fluid production per well, expressed in cubic meters per day. Based on the above parameters, the limiting water cut of the oilfield is calculated to be 97.7%.

[0019] S8. Determine the initial water cut of a single well using numerical simulation, specifically including the following steps: S81. Based on the oilfield geological model, fluid parameters, and well trajectory data, establish a numerical simulation model of the oilfield. S82. Run the oilfield numerical simulation model and output production parameters such as oil production, water production, gas production, and water cut of a single well on an annual basis. The water cut of the first year is the initial water cut of the single well. Well A6 is located in a high part of the oilfield. According to numerical simulation results, there is no water in the early stage of production, and the waterless oil production period lasts for 22 months. Therefore, the initial water cut is 0.

[0020] S9. Determine the reasonable production pressure differential in the initial stage of development based on the dimensionless fluid extraction ratio of the initial water cut of a single well and the limiting water cut of the oilfield. This includes the following steps: S91. Using the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index, and using the calculation formula for the dimensionless liquid extraction ratio at different moisture contents in step S3, calculate the dimensionless liquid extraction ratio at the initial moisture content. Based on the relative permeability data of Z oilfield, the dimensionless production index is 1.000 when the initial water cut is 0, the dimensionless production index is 0.709 when the limiting water cut is 97.7%, and the extraction ratio is 0.709 when the limiting water cut is 97.7%. S92. Calculate the reasonable initial production pressure difference for a single well; The formula for calculating the reasonable initial production pressure difference of a single well is as follows: In the formula: The initial production pressure differential for a single well is expressed in MPa. This represents the maximum production pressure differential of a single well, in MPa. The extraction ratio at the limiting water cut of the oilfield is a dimensionless extraction ratio.

[0021] Based on the correction S6, the maximum production pressure difference of well A6 is determined to be 9.66 MPa, and the liquid extraction ratio at the extreme water cut is 0.709. The reasonable production pressure difference for well A6 in the initial stage can be calculated to be 6.85 MPa. Well A6 should initially adopt a pressure difference of 6.85 MPa for production, and gradually increase it to the maximum production pressure difference of 9.66 MPa in the later stage to ensure stable liquid volume in the initial stage and during the high water cut period.

[0022] The applicant declares that the above description is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention fall within the protection and disclosure scope of the present invention.

Claims

1. A method for determining the initial reasonable production pressure differential of a single well in a marine medium-light oil reservoir, characterized in that: S1. Calculate the oil phase index and water phase index based on the relative permeability data of the oil field; S2. Based on the oil phase index, water phase index and oil-water viscosity data of the oilfield, calculate the dimensionless production index under different water cuts; S3. Calculate the dimensionless extraction ratio at different water contents based on the dimensionless liquid production index. S4. Considering formation sand production, calculate the maximum production pressure differential, specifically including the following steps: S5. Calculate the maximum pressure differential to ensure the minimum submersion degree of the electric submersible pump, specifically including the following steps: S6. Taking into account both sand production and pump submersion conditions, determine the maximum production pressure difference for a single well; S7. Determine the limiting water cut of the oilfield based on the economic parameters of oilfield operation; S8. Determine the initial water cut of a single well using numerical simulation. S9. Determine the reasonable production pressure difference in the early stage of development based on the dimensionless liquid extraction ratio of the initial water cut of a single well and the limiting water cut of the oilfield.

2. The method for determining the initial reasonable production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S1 specifically includes the following steps: S11. Establish the relationship between relative oil-water permeability and water saturation. The relationship between the relative permeability of oil and water and the water saturation is as follows: In the formula: The water phase permeability is dimensionless. The value is the oil phase permeability, dimensionless. The water saturation level is dimensionless. The slope It is the intercept, and and These are characteristic parameters, dimensionless; S12. Based on the oil-water relative permeability data from the oilfield's relative permeability data, draw... The relationship curve is linearly fitted to obtain its characteristic parameters. and ; S13, according to Calculate the oil phase index and water phase index using the characteristic parameters of the relationship curve and the endpoint values ​​of the relative permeability curve; The formula for calculating the oil phase index is as follows: In the formula: The oil phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are dimensionless characteristic parameters of the relationship curve. The formula for calculating the aqueous phase index is as follows: In the formula: The aqueous phase index is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; These are the characteristic parameters of the relationship curve, and are dimensionless.

3. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S2 specifically includes the following steps: S21. Based on the oil phase index and the water phase index, calculate the actual water saturation, relative permeability of the oil phase, and relative permeability of the water phase under different normalized water saturation. The formula for calculating the actual water saturation is as follows: In the formula: This represents the actual water saturation level, which is dimensionless. To constrain water saturation, dimensionless; Residual oil saturation, dimensionless; Normalized water saturation, dimensionless; The formula for calculating the relative permeability of the oil phase is: In the formula: The relative permeability of the oil phase is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; Normalized water saturation, dimensionless; The oil phase index is dimensionless. The formula for calculating the relative permeability of the aqueous phase is: In the formula: The relative permeability of the aqueous phase is dimensionless. The relative permeability of the water phase at residual oil saturation is dimensionless. Normalized water saturation, dimensionless; The aqueous phase index is dimensionless. S22. Calculate the water content under different normalized water saturation levels based on the relative permeability of the oil phase, the relative permeability of the water phase, and the oil-water viscosity data. The formula for calculating the water content under different normalized water saturation is as follows: In the formula: Moisture content, dimensionless; The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is dimensionless. The viscosity of the aqueous phase is expressed in mP·s. The viscosity is the oil phase viscosity, expressed in mP·s. S23. Based on the relative permeability of the oil phase, the relative permeability of the water phase, and the viscosity of the oil and water, calculate the dimensionless liquid production index under different normalized water saturation. The formula for calculating the dimensionless liquid production index under different normalized water saturation is as follows: In the formula: The dimensionless liquid production index is a dimensionless quantity. The relative permeability of the aqueous phase is dimensionless. The relative permeability of the oil phase is dimensionless. The relative permeability of the water phase at residual oil saturation is dimensionless. To constrain the relative permeability of the underwater oil phase, dimensionless; The viscosity of the aqueous phase is dimensionless. The viscosity is the oil phase viscosity, dimensionless.

4. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S3 specifically includes the following steps: S31. Specify the initial moisture content and use the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index. S32. Calculate the dimensionless extraction ratio at different moisture contents; The formula for calculating the dimensionless extract ratio at different moisture contents is as follows: In the formula: This is a dimensionless liquid extraction ratio, representing the multiple by which the liquid volume increases under the current water content conditions compared to the initial water content conditions. It is dimensionless. The benchmark liquid production index is dimensionless. The product index is dimensionless and has no specific volume.

5. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S4 specifically includes the following steps: S41. Collect reservoir geological parameters; S42. Based on the rock failure criterion, calculate the maximum production pressure differential at the bottom of the well when the rock is sheared and sand is produced. The formula for calculating the maximum production pressure differential of sand produced at the bottom of the well is: In the formula: This represents the maximum production pressure differential at the bottom of the well where sand is produced, expressed in MPa. This represents the original static pressure of the formation, expressed in MPa. This represents the pressure of the overlying strata, expressed in MPa. Poisson's ratio is dimensionless. It is the elastic cutoff constant, which is dimensionless; Cohesion, measured in MPa; The internal friction angle is expressed in degrees (°).

6. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S5 specifically includes the following steps: S51. Based on the location of the offshore drilling platform, set the well depth trajectory, determine the deepest point depth with a total angle change rate of less than 3° / 30m and the deepest point depth with a well inclination angle of less than 60°, and the smaller of the two deepest point depths is the maximum depth that the electric submersible pump can enter. S52. Based on the maximum depth and minimum submersion requirements of the electric submersible pump, calculate the maximum bottom-hole flowing pressure to ensure the minimum submersion of the electric submersible pump. The formula for calculating the maximum bottom hole flowing pressure under the condition of ensuring the minimum submersion of the electric submersible pump is as follows: In the formula: The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. The density of the fluid in the wellbore is expressed in g / cm³. 3 ; The gravitational acceleration constant is 9.8 m / s². 2 ; The depth is in the middle of the reservoir, in meters (m). This is the maximum depth that an electric submersible pump can descend to, in meters (m). Minimum submersion depth, in meters (m). S53. Calculate the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump; The formula for calculating the maximum pressure difference to ensure the minimum submersion degree of the electric submersible pump is as follows: In the formula: The maximum pressure differential is measured in MPa to ensure the minimum submersion depth of the electric submersible pump. This represents the original static pressure of the formation, expressed in MPa. The maximum bottom hole flowing pressure is measured in MPa to ensure the minimum submersion depth of the electric submersible pump.

7. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: The maximum production pressure difference of the single well The maximum production pressure differential for sand production at the bottom of the well. and the maximum pressure difference that ensures the minimum submersion degree of the electric submersible pump The lower of the two; The formula for calculating the maximum production pressure differential of a single well is: In the formula: This represents the maximum production pressure differential of a single well, in MPa. The maximum production pressure differential at the bottom of the well where sand is produced, in MPa; The maximum pressure difference is measured in MPa to ensure the minimum submersion depth of the electric submersible pump.

8. The method for determining the initial reasonable production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S7 specifically includes the following steps: S71. Collect economic parameters for daily operation of the oilfield; The daily operating economic parameters of the oilfield include the fixed daily operating cost per well, the cost of processing each cubic meter of produced fluid, the selling price of oil, the comprehensive tax rate, the crude oil commodity rate, the profit margin, and the average daily fluid production per well. S72. Calculate the minimum daily oil production limit of a single well; The formula for calculating the minimum daily oil production of a single well is as follows: In the formula: This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. The daily fixed operating cost per well is expressed in US dollars. Cost of processing per cubic meter of produced liquid, in US dollars; This represents the average daily fluid production per well, expressed in cubic meters per day. The selling price of oil is in US dollars per barrel. This is a comprehensive tax rate, dimensionless. The crude oil commodity rate is dimensionless and represents the proportion of crude oil that can be sold after deducting self-consumption such as oilfield power generation. Profit margin, dimensionless; S73. Calculate the limiting water cut of the oilfield based on the minimum daily oil production of a single well. The formula for calculating the limiting water cut of the oilfield is as follows: In the formula: The limiting water cut of the oilfield is dimensionless. This represents the minimum daily oil production limit for a single well, expressed in cubic meters per day. The average daily fluid production per well is expressed in cubic meters per day.

9. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S8 specifically includes the following steps: S81. Based on the oilfield geological model, fluid parameters, and well trajectory data, establish a numerical simulation model of the oilfield. S82. Run the oilfield numerical simulation model and output production parameters annually, with the water cut of the first year as the initial water cut of a single well. The production parameters include single-well oil production, water production, gas production, and water cut.

10. The method for determining the reasonable initial production pressure differential of a single well in a marine medium-light oil reservoir according to claim 1, characterized in that: Step S9 specifically includes the following steps: S91. Using the dimensionless liquid production index at the initial moisture content as the benchmark liquid production index, and using the calculation formula for the dimensionless liquid extraction ratio at different moisture contents in step S3, calculate the dimensionless liquid extraction ratio at the initial moisture content. S92. Calculate the reasonable initial production pressure difference for a single well; The formula for calculating the reasonable initial production pressure difference of a single well is as follows: In the formula: The initial production pressure differential for a single well is expressed in MPa. This represents the maximum production pressure differential of a single well, in MPa. The extraction ratio at the limiting water cut of the oilfield is a dimensionless extraction ratio.

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