A method for determining the minimum fracture length of a production well in a low permeability reservoir under gas drive conditions

Abstract

The present application relates to a kind of methods for determining the minimum fracture length of production well of low permeability reservoir under gas drive condition, belong to the field of reservoir engineering;Its technical scheme is that gas drive oil experiment is carried out to different permeability cores under different experimental injection flow, and the optimal experimental injection pressure and flow are determined;The optimal experimental injection flow is converted into optimal field injection flow, and then the relationship between permeability and optimal field injection pressure, optimal field injection flow is obtained by regression;Within the range of reservoir permeability, select permeability at equal intervals multiple times, and calculate the injection well pressure drop curve and production well pressure drop curve under different permeability conditions according to the regression relationship, the minimum fracture length is determined by adjusting the fracture length so that the two curves intersect at the reservoir pressure point;Finally, the minimum fracture length curve corresponding to different permeability is drawn.The present application can give a unique optimal solution, and the minimum fracture length can be directly read from the curve, which is convenient for field personnel to operate.

Description

TECHNICAL FIELD

[0001] The present application relates to a method for determining the minimum fracture length of a production well in a low-permeability reservoir under gas drive conditions, and belongs to the field of reservoir engineering. BACKGROUND

[0002] Low-permeability reservoirs have low porosity and low permeability, and conventional production techniques cannot achieve efficient development. Gas drive, as an effective tertiary oil recovery technology, can significantly reduce the viscosity of crude oil and improve its flow capacity by injecting N2, CO2, natural gas, or mixed gas into the reservoir, thereby increasing the production of the reservoir. In low-permeability reservoirs, gas drive has the problems of high injection pressure, slow pressure wave propagation speed, and slow reservoir response, so it often needs to be combined with fracturing technology. One of the main challenges in implementing gas drive in low-permeability reservoirs is to determine the reasonable fracture parameters, especially the minimum fracture length. Too short a fracture may not effectively connect the reservoir, while too long a fracture will increase unnecessary costs and environmental risks. Traditional fracture design methods rely heavily on numerical simulation, but this method has multiple solutions. Therefore, the present application proposes a new method that systematically evaluates the minimum fracture length of production wells in different permeability reservoirs under gas drive conditions by combining experimental research with mathematical modeling, providing scientific basis and technical support for the efficient development of low-permeability reservoirs. SUMMARY

[0003] The purpose of the present application is to overcome the shortcomings of the prior art, determine the optimal injection pressure and optimal field injection flow rate of different permeability reservoirs according to gas drive oil experiments, and determine the minimum pressure fracture length of different permeability reservoirs by combining the injection well pressure drop curve and the production well pressure drop curve, thereby providing a method for determining the minimum fracture length of a production well in a low-permeability reservoir under gas drive conditions.

[0004] To achieve the above-mentioned purpose, the present application provides a method for determining the minimum fracture length of a production well in a low-permeability reservoir under gas drive conditions, characterized in that the method comprises the following steps:

[0005] S1. Selecting at least 5 cores with different permeabilities to perform gas drive oil experiments at experimental injection flow rates of 0.5 mL / min, 0.75 mL / min, 1 mL / min, 1.25 mL / min, 1.5 mL / min, 1.75 mL / min, and 2 mL / min, wherein the outlet pressure is the reservoir pressure, determining the recovery rate corresponding to different experimental injection flow rates, and determining the optimal experimental injection pressure corresponding to the maximum recovery rate as the optimal field injection pressure, and the corresponding injection flow rate as the optimal experimental injection flow rate;

[0006] S2. The optimal experimental injection pressure is the optimal field injection pressure, and the relationship between permeability and optimal field injection pressure is regressed according to the permeability and optimal field injection pressure data ,in p in The pressure injected into the optimal mining area is measured in Pa. k Reservoir permeability, in meters (m). 2 ; a 1. b 1 is the fitting constant, which is dimensionless;

[0007] S3. The parameters of the gas-driven oil production experiment are transferred to the field. The experiment is a unidirectional flow, and the production pressure difference calculation formula is: The mine operates on a planar radial flow pattern, and the production pressure differential is calculated using the following formula: Since the experimental production pressure differential is the same as the mine production pressure differential, the optimal experimental injection flow rate is converted into the optimal mine injection flow rate. , where △ p The production pressure differential is expressed in Pa. μ g This refers to the viscosity of a gas, measured in Pa·s. q Optimal flow rate for the mining field, in meters. 3 / s; Q The optimal experimental flow rate is given in m³. 3 / s; h The reservoir thickness is expressed in meters (m). L This refers to the core length, in meters (m). R The core radius is in meters. r e The oil drain radius is in meters. r w The radius of the wellbore is in meters (m).

[0008] S4. Based on the permeability and the optimal mine injection flow rate data calculated in S3, linear regression is used to obtain the relationship between permeability and optimal mine injection flow rate. ,in a 2. b 2 is the fitting constant, which is dimensionless;

[0009] S5. Determine the reservoir permeability range, select 25 permeability values ​​at equal intervals, and repeat the following steps:

[0010] (1) Given the permeability, the optimal injection pressure and optimal injection flow rate are calculated using the linear regression relationship obtained from S2 and S4. The injection well pressure drop curve is calculated using the following formula: ,in r This represents the distance from the reservoir to the injection well, in meters (m). p Distance injection well r The formation pressure at that location, expressed in Pa;

[0011] (2) using the bottom hole flowing pressure of the production well and the oil production of the production well to calculate the pressure drop curve of the production well, wherein the calculation formula of the fracture area is , and the calculation formula of the non-fracture area is , wherein p out is the bottom hole flowing pressure of the production well, and the unit is Pa; q out is the oil production of the production well, and the unit is m 3 / s; μ o is the viscosity of the crude oil, and the unit is Pa.s; k f is the fracture permeability, and the unit is m 2 ; x is the distance between the injection well and the production well, and the unit is m; x f is the fracture length, and the unit is m; and if there is no production data before the gas well is fractured, the bottom hole flow of the production well and the oil production of the production well are selected as the average bottom hole flow and the average oil production of the current block; if there is production data before the gas well is fractured, the bottom hole flow of the production well and the oil production of the production well are selected as the stable bottom hole flow and the stable oil production at the latest time before the fracturing;

[0012] (3) adjusting the fracture length so that the injection well pressure drop curve intersects with the production well pressure drop curve, and the intersection pressure is the reservoir pressure, and the fracture length at this time is the minimum fracture length;

[0013] S6, a minimum fracture length curve corresponding to different permeabilities is drawn, and the minimum fracture length corresponding to any permeability can be obtained according to the curve.

[0014] Compared with the prior art, the present application has the following beneficial effects: (1) a unique optimal solution can be given; (2) after drawing the minimum fracture length curve corresponding to different permeabilities, the minimum fracture length can be directly read from the curve, which is convenient for field personnel to operate; (3) the present application has strong generalizability. BRIEF DESCRIPTION OF DRAWINGS

[0015] Figure 1 is the technical roadmap of the method;

[0016] Figure 2 is the experimental injection pressure and the experimental injection flow corresponding to different permeabilities;

[0017] Figure 3 is the regression relationship between the permeability and the optimal mine injection pressure;

[0018] Figure 4 is the regression relationship between the permeability and the optimal mine injection flow;

[0019] Figure 5is the injection well and production well pressure drop curve under the permeability of 0.8 mD;

[0020] Figure 6 is the minimum fracture length curve corresponding to different permeability. DETAILED DESCRIPTION

[0021] The present application is further described below in conjunction with embodiments and drawings.

[0022] The present application provides a method for determining the minimum fracture length of a production well in a low permeability reservoir under gas drive conditions, Figure 1 The technical roadmap of the present method is to improve the recovery efficiency of a certain domestic reservoir using CO2 flooding, the reservoir permeability is 0.02 mD~9.56 mD, the average is 0.63 mD, the crude oil viscosity at 50℃ is 17.7 mPa·s, the CO2 viscosity is 2 mPa·s, the reservoir pressure is 44 MPa, the reservoir thickness is 66.53 m, the wellbore radius is 0.1 m, the injection well and production well distance is 280 m, and the following steps are implemented:

[0023] S1, select 0.56 mD, 1.52 mD, 2.16 mD, 3.56 mD, 5.31 mD, a total of 5 cores with different permeability, respectively, under the experimental injection flow rate of 0.5 mL / min, 0.75 mL / min, 1 mL / min, 1.25 mL / min, 1.5 mL / min, 1.75 mL / min, 2 mL / min, CO2 flooding experiment, the core length is 20 cm, the core diameter is 3 cm, the outlet pressure is 44 MPa, determine the recovery efficiency corresponding to different experimental injection flow rate, the experimental injection pressure corresponding to the maximum recovery efficiency is the optimal experimental injection pressure, the corresponding injection flow rate is the optimal experimental injection flow rate, the experimental injection pressure and the optimal experimental injection pressure corresponding to different permeability, the experimental injection flow rate and the optimal experimental injection flow rate, as shown in Figure 2 ;

[0024] S2, the optimal experimental injection pressure is the optimal field injection pressure, according to the permeability and optimal field injection pressure data, the relationship between permeability and optimal field injection pressure is regressed , as shown in Figure 3 , wherein p in is the optimal field injection pressure, the unit is Pa; k is the reservoir permeability, the unit is m 2 ;

[0025] S3, convert the parameters of CO2 flooding experiment to the field to determine the optimal field injection flow rate, the calculation formula is: , wherein q is the optimal field injection flow rate, the unit is m 3 / s;Q Optimal injection rate, unit: m 3 / s; h Reservoir thickness, unit: m; L Core length, unit: m; R Core radius, unit: m; r e Drainage radius, unit: m; r w Wellbore radius, unit: m;

[0026] S4, optimal field injection rate data calculated according to permeability and S3, linear regression to obtain the relationship between permeability and optimal field injection rate , as shown in Figure 4 ;

[0027] S5, select 0.02, 0.4, 0.8, 1.2, …, 8.4, 8.8, 9.2, 9.56, a total of 25 permeabilities at intervals of 0.4 mD, repeat the following steps:

[0028] (1) Given the permeability, the optimal field injection pressure and the optimal field injection rate calculated by the linear regression relationship obtained by S2 and S4, calculate the injection well pressure drop curve, the calculation formula is , wherein μ g Gas viscosity, unit: Pa·s; r Distance from the reservoir to the injection well, unit: m; p Formation pressure at a distance of 100 m from the injection well r , unit: Pa;

[0029] (2) Calculate the production well pressure drop curve using the production well bottom hole flowing pressure and the production well oil production, wherein the calculation formula for the fracture area is , and the calculation formula for the non-fracture area is , wherein p out Production well bottom hole flowing pressure, unit: Pa; q out Production well oil production, unit: m 3 / s; μ o Crude oil viscosity, unit: Pa·s; k f Fracture permeability, unit: m 2 ; x Distance between the injection well and the production well, unit: m; x f Fracture length, unit: m; The stable bottom hole flow rate of the gas well before fracturing is 32 MPa, and the stable oil production is 25 m3 / d; fracture permeability is 1200 mD;

[0030] (3) adjust the fracture length, so that the injection well pressure drop curve and production well pressure drop curve intersect, and the intersection point pressure is the reservoir pressure, at this time the fracture length is the minimum fracture length, found that the permeability is greater than 5.6 mD, no need to fracture, wherein the permeability is 0.8 mD injection well and production well pressure drop curve, as shown in Figure 5 ;

[0031] S6, draw the minimum fracture length curve corresponding to different permeability, according to the curve can obtain the minimum fracture length corresponding to any permeability, as shown in Figure 6 .

[0032] Any modification or partial replacement of the present application without departing from the spirit and scope of the present application should be covered in the scope of claims of the present application.

Claims

1. A method of determining the minimum fracture length of a production well in a low permeability reservoir under gas drive conditions, characterized by, The method comprises the following steps: S1, selecting at least 5 different permeability cores to respectively conduct gas drive oil experiments at 0.5 mL / min, 0.75 mL / min, 1 mL / min, 1.25 mL / min, 1.5 mL / min, 1.75 mL / min and 2 mL / min experimental injection flow rates, wherein the outlet end pressure is the reservoir pressure, to determine the recovery rates corresponding to different experimental injection flow rates, the experimental injection pressure corresponding to the maximum recovery rate is the optimal experimental injection pressure, and the corresponding injection flow rate is the optimal experimental injection flow rate; S2, the optimal experimental injection pressure is the optimal in-situ injection pressure, and the relationship between the permeability and the optimal in-situ injection pressure is regressed according to the permeability and the optimal in-situ injection pressure data wherein p in is the optimal in-situ injection pressure, and has a unit of Pa; k is the reservoir permeability, and has a unit of m 2 ; a 1, b 1 is a fitting constant, and is dimensionless; S3, convert the parameters of the gas drive oil experiment to the mine field, determine the optimal mine field injection flow rate, the calculation formula is: Wherein q is the optimal mine field injection flow rate, the unit is m 3 / s; Q is the optimal experimental injection flow rate, the unit is m 3 / s; h is the reservoir thickness, the unit is m; L is the core length, the unit is m; R is the core radius, the unit is m; r e is the drainage radius, the unit is m; r w is the wellbore radius, the unit is m; S4, linear regression of the permeability and the optimal mine injection flow rate data calculated from the permeability and S3 to obtain the relationship between the permeability and the optimal mine injection flow rate wherein a 2, b 2 is a fitting constant, dimensionless; S5, determining the reservoir permeability range, selecting 25 permeabilities at equal intervals, and repeating the following steps: (1) Given the permeability, the optimal mine injection pressure and the optimal mine injection flow rate calculated by the linear regression relationship obtained by S2 and S4, the injection well pressure drop curve is calculated, and the calculation formula is wherein μ g is the gas viscosity, with the unit of Pa·s; r is the distance from the reservoir to the injection well, with the unit of m; p is the distance from the injection well r to the formation pressure, with the unit of Pa; (2) The pressure drop curve of the production well is calculated by using the bottom hole flowing pressure and the oil production of the production well, wherein the calculation formula of the fracture area is , and the calculation formula of the non-fracture area is , wherein p out is the bottom hole flowing pressure of the production well, and the unit is Pa; q out is the oil production of the production well, and the unit is m 3 / s; μ o is the viscosity of the crude oil, and the unit is Pa·s; k f is the fracture permeability, and the unit is m 2 ; x is the distance between the injection well and the production well, and the unit is m; x f is the length of the fractured fracture, and the unit is m; (3) adjusting the fracture length so that the injection well pressure drop curve intersects the production well pressure drop curve, and the intersection pressure is the reservoir pressure, at which the fracture length is the minimum fracture length; S6, drawing a minimum fracture length curve corresponding to different permeabilities, and according to the curve, the minimum fracture length corresponding to any permeability can be obtained.

2. The method of determining the minimum fracture length of a production well in a low permeability reservoir under gas drive conditions according to claim 1, wherein, In step S5, if there is no production data before the gas well is fractured, the bottom hole flow rate of the production well and the oil production of the production well are selected as the average bottom hole flow rate and the average oil production of the block at present; if there is production data before the gas well is fractured, the bottom hole flow rate of the production well and the oil production of the production well are selected as the stable bottom hole flow rate and the stable oil production at the latest time before fracturing.

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