A well selection method and system suitable for composite row mining process of tight gas reservoir

Abstract

This invention discloses a well selection method and system applicable to composite drainage and production processes in tight gas reservoirs, relating to the field of oil and gas field development technology. The method includes: collecting wellbore structure and production parameters of gas wells in tight gas reservoirs; calculating the wellbore production pressure drop under different gas production rates; calculating the production pressure drop corresponding to the composite drainage and production process based on the given drainage and production process efficiencies of different processes; calculating the pressure drop reduction amplitude corresponding to the composite drainage and production process by subtracting the production pressure drop corresponding to the composite drainage and production process from the wellbore production pressure drop; and drawing a gas production-pressure drop reduction composite drainage and production process chart based on the pressure drop reduction amplitude to determine the optimal composite drainage and production process. The method of this invention can use computer equipment for data processing and calculation, providing technical theoretical support for well selection using composite drainage and production processes in tight gas reservoirs, supplementing the currently lacking well selection methods for composite drainage and production processes in tight gas reservoirs, and possessing high accuracy and timeliness.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and in particular to a well selection method and system suitable for the composite drainage and production process of tight gas reservoirs. Background Technology

[0002] Tight gas reservoirs are characterized by typical low pressure, low production, and low water volume. With continuous development, the proportion of low-pressure, low-production gas wells is increasing year by year. Complex well conditions lead to a gradual decline in the effectiveness of single drainage and gas production technologies, and the lack of clear technology for stabilizing production poses a significant challenge to economically and effectively maintaining stable production. Composite drainage and production technologies combine the advantages of individual technologies, compensating for their respective shortcomings, expanding the application scope of individual technologies, and improving the efficiency of the lift system. Based on the water production and production characteristics of tight gas reservoir wells, a suitable composite drainage and production technology has been developed in the field, primarily using foam drainage and gas production, supplemented by velocity tubing, wellhead pressurization, and gas lift. These three types of composite drainage and production technologies are still in the exploratory stage, and the optimal combination and selection of technologies for practical application remain unclear. Therefore, it is crucial to develop a well selection method suitable for composite drainage and production technologies in tight gas reservoirs. This invention addresses this problem by calculating the pressure drop in gas wells before and after implementing a combined drainage and production process in tight gas reservoirs. Based on this calculation theory, a set of optimal charts for the combined drainage and production process is established, and a well selection method suitable for combined drainage and production processes in tight gas reservoirs is proposed. Literature review revealed no publicly available related theories or methods in China. Summary of the Invention

[0003] The purpose of this invention is to provide a well selection method and system applicable to the composite drainage and production process in tight gas reservoirs. It aims to focus on the composite drainage and production process in tight gas reservoirs, enabling more accurate selection of the optimal composite drainage and production process based on the well's own production conditions. The method of this invention can utilize computer equipment for data processing and calculation, providing technical theoretical support for well selection in the composite drainage and production process of tight gas reservoirs, and supplementing existing methods.

[0004] This method offers a previously lacking approach to selecting wells for combined drainage and production processes in tight gas reservoirs, boasting high accuracy and timeliness.

[0005] To achieve the above objectives, the present invention provides the following technical solution:

[0006] According to one aspect of this disclosure, a well selection method suitable for combined drainage and production processes in tight gas reservoirs is provided, the method comprising the following steps:

[0007] Collect information on the wellbore structure and production parameters of tight gas reservoirs;

[0008] Calculate the wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters;

[0009] Based on the given efficiencies of different bubble drainage processes, calculate the production pressure drop corresponding to the composite drainage process;

[0010] The pressure drop corresponding to the composite drainage process is calculated by subtracting the production pressure drop from the wellbore production pressure drop, and then calculating the pressure drop amplitude corresponding to the composite drainage process.

[0011] Based on the pressure drop, a composite drainage process diagram of gas production and pressure drop is drawn to determine the optimal composite drainage process.

[0012] In one possible implementation, the calculation of wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters includes:

[0013] Based on the gas well structure and production parameters, a series of gas production rates (Q1, Q2, ..., Q) are given before the drainage process. N ), calculate the wellbore production pressure drop at the corresponding gas production rate of the gas well.

[0014] In one possible implementation, the formula for calculating the wellbore production pressure drop is as follows:

[0015]

[0016]

[0017] In the formula, ΔP represents the wellbore production pressure drop, Pa; P represents the pressure, Pa; θ represents the well inclination angle (the angle between the well axis and the horizontal direction); v m The velocity of the gas-liquid two-phase mixture is expressed in m / s; D represents the inner diameter of the oil pipe in m; f m ρ represents the friction coefficient between the gas and liquid phases; m This represents the average density of a gas-liquid two-phase mixture at any cross-section Z, in kg / m³. 3 Z represents the gas well depth, in meters; ΔZ represents the unit gas well depth, in meters.

[0018] In one possible implementation, the step of calculating the production pressure drop corresponding to the composite drainage process based on the given drainage process efficiency of different processes includes:

[0019] Under velocity column technology, given the bubble discharge efficiency E1 under velocity column conditions, calculate a series of gas production rates. Production pressure drop ΔP N1 ;

[0020] Under wellhead pressurization technology, given the bubble discharge efficiency E2 under wellhead pressurization conditions, a series of gas production rates are calculated. Production pressure drop ΔP N2 ;

[0021] Under the gas lift process, given the bubble removal efficiency E3 under given gas lift conditions, calculate a series of gas production rates. Production pressure drop ΔP N3 .

[0022] In one possible implementation, the step of calculating the pressure drop amplitude corresponding to the combined drainage process by subtracting the production pressure drop from the wellbore production pressure drop includes:

[0023] The production pressure drop ΔP under the velocity tube composite drainage process N1 The pressure drop ΔP in the wellbore production process is calculated by subtracting the pressure drop ΔP from the pressure drop ΔP in the velocity pipe combined drainage process;

[0024] The production pressure drop ΔP under the wellhead pressurization combined drainage process N2 The pressure drop ΔP2 of the wellhead pressurization and combined drainage process is calculated by subtracting the wellbore production pressure drop ΔP from the wellbore production pressure drop ΔP.

[0025] The production pressure drop ΔP under the airlift combined drainage process N2 The pressure drop ΔP3 of the gas lift combined drainage process is calculated by subtracting the pressure drop ΔP from the wellbore production pressure drop ΔP.

[0026] In one possible implementation, the step of drawing a composite gas production-pressure drop process diagram based on the pressure drop magnitude includes:

[0027] Based on the pressure drop amplitude ΔP1 of the velocity tube composite drainage process, plot the Q~ΔP1 curve on the coordinate system Q—ΔP;

[0028] Based on the pressure drop ΔP2 of the wellhead pressurization and combined drainage process, plot the Q~ΔP2 curve on the coordinate system Q—ΔP;

[0029] Based on the pressure drop ΔP3 of the gas lift combined drainage process, plot the Q~ΔP3 curve on the coordinate system Q—ΔP;

[0030] Based on the Q~ΔP1, Q~ΔP2 and Q~ΔP3 curves, draw a composite drainage process diagram of gas production and pressure drop.

[0031] According to one aspect of this disclosure, a well selection system suitable for combined drainage and production processes in tight gas reservoirs is provided. The system includes: a collection unit, a first calculation unit, a second calculation unit, a third calculation unit, and a plotting unit; wherein,

[0032] The collection unit is used to collect information on the wellbore structure and production parameters of tight gas reservoirs.

[0033] The first calculation unit is used to calculate the wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters.

[0034] The second calculation unit is used to calculate the production pressure drop corresponding to the composite drainage process based on the given drainage process efficiency of different processes.

[0035] The third calculation unit is used to calculate the pressure drop amplitude corresponding to the composite drainage process by subtracting the production pressure drop from the wellbore production pressure drop.

[0036] The drawing unit is used to draw a composite drainage process diagram of gas production and pressure drop based on the pressure drop reduction, and to determine the optimal composite drainage process.

[0037] In one possible implementation, the first computing unit is specifically used for,

[0038] Based on the gas well structure and production parameters, a series of gas production rates (Q1, Q2, ..., Q) are given before the drainage process. N ), calculate the wellbore production pressure drop at the corresponding gas production rate of the gas well.

[0039] In one possible implementation, the formula for calculating the wellbore production pressure drop in the first calculation unit is as follows:

[0040]

[0041]

[0042] In the formula, ΔP represents the wellbore production pressure drop, Pa; P represents the pressure, Pa; θ represents the well inclination angle (the angle between the well axis and the horizontal direction); v m The velocity of the gas-liquid two-phase mixture is expressed in m / s; D represents the inner diameter of the oil pipe in m; f m ρ represents the friction coefficient between the gas and liquid phases; m This represents the average density of a gas-liquid two-phase mixture at any cross-section Z, in kg / m³. 3 Z represents the gas well depth, in meters; ΔZ represents the unit gas well depth, in meters.

[0043] In one possible implementation, the second computing unit includes: a first computing module, a second computing module, and a third computing module; wherein,

[0044] The first calculation module is used to calculate a series of gas production rates under a given velocity tube condition and bubble discharge efficiency E1 in a velocity tube process. Production pressure drop ΔP N1 ;

[0045] The second calculation module is used to calculate a series of gas production rates under a given wellhead pressurization condition and a bubble discharge efficiency E2. Production pressure drop ΔP N2 ;

[0046] The third calculation module is used to calculate a series of gas production rates under a given gas lift efficiency E3. Production pressure drop ΔP N3 .

[0047] In one possible implementation, the third computing unit includes: a fourth computing module, a fifth computing module, and a sixth computing module; wherein,

[0048] The fourth calculation module is used to calculate the production pressure drop ΔP under the velocity tube combined drainage process. N1 The pressure drop ΔP in the wellbore production process is calculated by subtracting the pressure drop ΔP from the pressure drop ΔP in the velocity pipe combined drainage process;

[0049] The fifth calculation module is used to calculate the production pressure drop ΔP under the wellhead pressurization and drainage combined process. N2 The pressure drop ΔP2 of the wellhead pressurization and combined drainage process is calculated by subtracting the wellbore production pressure drop ΔP from the wellbore production pressure drop ΔP.

[0050] The sixth calculation module is used to calculate the production pressure drop ΔP under the gas lift combined drainage process. N2 The pressure drop ΔP3 of the gas lift combined drainage process is calculated by subtracting the pressure drop ΔP from the wellbore production pressure drop ΔP.

[0051] In one possible implementation, the drawing unit includes: a first drawing module, a second drawing module, a third drawing module, and a first drawing module; wherein,

[0052] The first drawing module is used to draw the Q~ΔP1 curve on the coordinate system Q—ΔP based on the pressure drop amplitude ΔP1 of the velocity tube composite drainage process.

[0053] The second drawing module is used to draw the Q~ΔP2 curve on the coordinate system Q—ΔP based on the pressure drop ΔP2 of the wellhead pressurization and combined drainage process.

[0054] The third plotting module is used to plot the Q~ΔP3 curve on the coordinate system Q—ΔP based on the pressure drop amplitude ΔP3 of the gas lift combined drainage process.

[0055] The fourth drawing module is used to draw a composite drainage process diagram of gas production and pressure drop based on the Q~ΔP1, Q~ΔP2, and Q~ΔP3 curves. The technical effects and advantages of this invention are as follows:

[0056] First, the present invention has a certain theoretical basis, and the determination method can be well consistent with the field situation;

[0057] Secondly, this invention supplements the currently lacking well selection methods for composite drainage and production processes in tight gas reservoirs, and can guide on-site construction and production;

[0058] Third, the entire calculation and judgment process of this invention can be carried out on computer equipment, enabling digital control at the construction site and achieving high accuracy.

[0059] Other features and advantages of the invention will be set forth in the following description, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures pointed out in the description and the drawings. Attached Figure Description

[0060] Figure 1 This is a flowchart of a well selection method applicable to the composite drainage and production process of tight gas reservoirs according to the present invention;

[0061] Figure 2 This is a diagram of the combined gas production and pressure drop reduction process of the present invention;

[0062] Figure 3 This is a schematic diagram of a well selection system applicable to the composite drainage and production process of tight gas reservoirs according to the present invention. Detailed Implementation

[0063] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0064] Furthermore, the flowchart shown in the accompanying drawings is merely illustrative and does not necessarily include all steps. For example, some steps may be broken down, while others may be combined or partially combined; therefore, the actual execution order may change depending on the specific circumstances.

[0065] The terms "first," "second," etc., used in the specification, claims, and accompanying drawings of this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this application described herein can be implemented, for example, in orders other than those illustrated or described herein.

[0066] The terms “comprising” and “having”, and any variations thereof, are intended to cover non-exclusive inclusion, such that a process, method, system, product, or device that includes a series of steps or sub-modules is not necessarily limited to those steps or sub-modules that are explicitly listed, but may include other steps or sub-modules that are not explicitly listed or that are inherent to such process, method, product, or device.

[0067] The design concept of this invention includes: calculating the production pressure drop of tight gas reservoir wells at different production rates based on the wellbore structure and production parameters; comparing this pressure drop with the pressure drop of velocity tube combined drainage process, wellhead pressurization combined drainage process, and gas lift combined drainage process; using the reduction in wellbore pressure drop before and after the combined drainage process as an evaluation index; drawing a combined drainage process effect chart to clarify the reduction in wellbore pressure drop after construction under different processes; selecting the optimal combined drainage process based on its production range; and establishing a boundary chart applicable to the combined drainage process for tight gas reservoirs at different production rates. Implementing drainage processes during the low-production stage of tight gas reservoirs can further increase production. Combining the optimal combined drainage process boundary chart as a benchmark, tight gas wells within the parameter range of this chart can implement combined drainage and gas production processes to achieve the goal of increasing production, thereby realizing the selection of tight gas wells and improving gas well production.

[0068] Figure 1 This is a flowchart of a well selection method applicable to the composite drainage and production process of tight gas reservoirs according to the present invention, as shown in the figure. Figure 1 As shown, this invention provides a well selection method suitable for combined drainage and production processes in tight gas reservoirs, the specific steps of which are as follows:

[0069] Step S1: Collect relevant data on tight gas reservoir wells, including gas and liquid densities, gas-liquid ratio, local gravitational acceleration, wellhead pressure and temperature, well depth, gas-water interfacial tension, tubing and casing dimensions, daily gas and water production, etc.

[0070] Step S2: Based on existing gas well production data, determine a series of gas production rates (Q1, Q2, ..., Q) before the drainage process. N ), calculate the wellbore production pressure drop ΔP at the corresponding gas production rate of the gas well, the expression of which is as follows:

[0071]

[0072]

[0073] In the formula, ΔP represents the wellbore production pressure drop, Pa; P represents the pressure, Pa; θ represents the well inclination angle (the angle between the well axis and the horizontal direction); v m The velocity of the gas-liquid two-phase mixture is expressed in m / s; D represents the inner diameter of the oil pipe in m; f m ρ represents the friction coefficient between the gas and liquid phases; m This represents the average density of a gas-liquid two-phase mixture at any cross-section Z, in kg / m³. 3 Z represents the gas well depth, in meters; ΔZ represents the unit gas well depth, in meters.

[0074] In equation (1), the friction coefficient f between the gas and liquid phases is... m The calculation formula is as follows:

[0075]

[0076]

[0077]

[0078]

[0079]

[0080] In equations (3)-(7), e represents absolute roughness, which is dimensionless; N Re Indicates no-slip Reynolds number, dimensionless; D represents the tubing inner diameter, in meters; v m The velocity of a gas-liquid two-phase mixture is expressed in m / s; ρ ns Indicates the density of a non-slip mixture; μ ns Indicates the viscosity of a non-slip mixture; H′ l Indicates the non-slippage liquid holdup; ρ g This represents the density of the gas phase, in kg / m³. 3 ;ρ l This represents the density of the liquid phase, in kg / m³. 3 Q g Indicates gas phase flow rate, m 3 / d;Q l The value in m represents the liquid phase flow rate. 3 / d;μ g Indicates the gas phase viscosity, m 2 / s; μ1 represents the liquid phase viscosity, m 2 / s;v sl This represents the apparent velocity in the gas phase, in m / s.

[0081] In equation (1), the average density ρ of the gas-liquid two-phase mixture on any cross section Z is... m The calculation formula is as follows:

[0082]

[0083]

[0084]

[0085]

[0086] In equations (8)-(11), H L ρ represents liquid holdup, dimensionless; L This represents the density of the liquid phase, in kg / m³. 3 ;ρ G This represents the density of the gas phase, in kg / m³. 3 N vl Nv represents the liquid phase index, dimensionless;g表 The volumetric index of the gas phase is dimensionless; v sl V represents the apparent flow rate of the liquid phase, in m / s; sg ρ represents the apparent velocity of the gas phase, in m / s; l This represents the density of the liquid phase, in kg / m³. 3 g represents gravitational acceleration, m / s² 2 ;ρ g This represents the density of the gas phase, in kg / m³. 3 c1 = -1.089, c2 = 1.319, c3 = -0.961, c4 = 0.362, c5 = 0.061; σ is the gas-water interfacial tension, N / m; θ represents the well inclination angle (the angle between the well axis and the horizontal direction), °;

[0087] Step S3: Considering the bubble discharge efficiency E1 under the given velocity tubing process, change the gas well production pipe diameter to the velocity tubing size, and then calculate a series of gas production rates using formula (1). Production pressure drop ΔP N1 Then it is compared with a series of gas production rates (Q1, Q2, ..., Q) before the given drainage process. N The difference between the calculated production pressure drop ΔP and the pressure drop ΔP1 of the velocity tube composite drainage process can be obtained. Finally, the Q-ΔP1 curve is plotted on the coordinate system Q-ΔP.

[0088] Step S4: Considering the wellhead pressurization process, given the bubble discharge efficiency E2 under the wellhead pressurization conditions, change the wellhead oil pressure of the gas well, and then calculate a series of gas production rates using formula (1). Production pressure drop ΔP N2 Then it is compared with a series of gas production rates (Q1, Q2, ..., Q) before the given drainage process. N The difference between the calculated production pressure drop ΔP and the pressure drop ΔP2 of the wellhead pressurization and drainage process can be used to obtain the pressure drop amplitude ΔP2. Finally, the Q-ΔP2 curve is plotted on the coordinate system Q-ΔP.

[0089] Step S5: Considering the gas lift process, given the bubble removal efficiency E3 under given gas lift conditions, and given the series of gas production rates (Q1, Q2, ..., Q) before the gas removal and extraction process. N For each gas production rate, starting from 0.1 × 10⁻⁶ 4 m 3 Starting with / d, and beginning with 0.1×10 4 m 3Given an injection rate of / d, calculate the wellbore pressure drop under different injection rate conditions. If the wellbore pressure drop first decreases and then increases with the injection rate, the lowest point of the wellbore pressure drop is taken as the production pressure drop of the gas lift under that production rate condition. If the wellbore pressure drop shows a continuous increase, it indicates that the gas lift foam drainage combined drainage process is not applicable and is not recommended. At this time, given the foam drainage efficiency E3 under the gas lift condition, calculate a series of gas production rates using formula (1). Production pressure drop ΔP N3 Then, by subtracting this from the optimal gas lift production pressure drop ΔP determined by the above method, the pressure drop amplitude ΔP3 of the gas lift combined drainage process can be obtained. Finally, the Q-ΔP3 curve is plotted on the coordinate system Q-ΔP.

[0090] Step S6: Combining the above calculation steps, calculate a series of gas production rates (Q1, Q2, ..., Q) before the given drainage process. N Based on the calculated pressure drop ΔP1 of the velocity-tube combined drainage process, the pressure drop ΔP2 of the wellhead pressurization combined drainage process, and the pressure drop ΔP3 of the gas lift combined drainage process, a diagram of the gas production versus pressure drop of the combined drainage process is created, as shown below. Figure 2 As shown, the optimal composite drainage process is identified under different gas volume ranges, so as to achieve the goal of optimizing well selection for composite drainage process in tight gas reservoirs.

[0091] Based on the above method, the present invention also provides a well selection system suitable for the combined drainage and production process of tight gas reservoirs. Figure 3 This is a schematic diagram of a well selection system applicable to the combined drainage and production process of tight gas reservoirs according to the present invention, as shown below. Figure 3 As shown, the system includes: a collection unit, a first calculation unit, a second calculation unit, a third calculation unit, and a drawing unit; wherein, the collection unit is used to collect the wellbore structure and production parameters of tight gas reservoir gas wells; the first calculation unit is used to calculate the wellbore production pressure drop under different gas production rates based on the wellbore structure and production parameters; the second calculation unit is used to calculate the production pressure drop corresponding to the composite drainage process based on the given foam drainage process efficiency of different processes; the third calculation unit is used to calculate the pressure drop reduction amplitude corresponding to the composite drainage process by subtracting the production pressure drop corresponding to the composite drainage process from the wellbore production pressure drop; the drawing unit is used to draw a composite drainage process chart of gas production rate and pressure drop reduction amplitude based on the pressure drop reduction amplitude, and to determine the optimal composite drainage process.

[0092] As one embodiment of the present invention, the first calculation unit is specifically used to determine a series of gas production rates (Q1, Q2, ..., Q) before the drainage process based on the gas well structure and production parameters. N ), calculate the wellbore production pressure drop ΔP at the corresponding gas production rate of the gas well. In the first calculation unit, the formula for calculating the wellbore production pressure drop ΔP is as follows:

[0093]

[0094]

[0095] In the formula, ΔP represents the wellbore production pressure drop, Pa; P represents the pressure, Pa; θ represents the well inclination angle (the angle between the well axis and the horizontal direction); v m The velocity of the gas-liquid two-phase mixture is expressed in m / s; D represents the inner diameter of the oil pipe in m; f m ρ represents the friction coefficient between the gas and liquid phases; m This represents the average density of a gas-liquid two-phase mixture at any cross-section Z, in kg / m³. 3 Z represents the gas well depth, in meters; ΔZ represents the unit gas well depth, in meters.

[0096] In one embodiment of the present invention, the second calculation unit includes: a first calculation module, a second calculation module, and a third calculation module; wherein, the first calculation module is used to calculate a series of gas production rates under a given velocity tube condition and a bubble discharge efficiency E1 in a velocity tube process. Production pressure drop ΔP N1 The second calculation module is used to calculate a series of gas production rates under a given wellhead pressurization condition and a given bubble discharge efficiency E2. Production pressure drop ΔP N2 The third calculation module is used to calculate a series of gas production rates under a given bubble removal efficiency E3 in the gas lift process. Production pressure drop ΔP N3 .

[0097] In one embodiment of the present invention, the third calculation unit includes: a fourth calculation module, a fifth calculation module, and a sixth calculation module; wherein, the fourth calculation module is used to calculate the production pressure drop ΔP under the velocity tube combined drainage process. N1 The difference between the wellbore production pressure drop ΔP and the pressure drop ΔP1 of the velocity-tube combined drainage process is calculated; the fifth calculation module is used to calculate the production pressure drop ΔP under the wellhead pressurization combined drainage process. N2 The difference between the wellbore production pressure drop ΔP and the pressure drop at the wellhead pressurization combined with drainage is used to calculate the pressure drop amplitude ΔP2 of the gas lift combined drainage process; the sixth calculation module is used to calculate the production pressure drop ΔP under the gas lift combined drainage process. N2 The pressure drop ΔP3 of the gas lift combined drainage process is calculated by subtracting the pressure drop ΔP from the wellbore production pressure drop ΔP.

[0098] In one embodiment of the present invention, the drawing unit includes: a first drawing module, a second drawing module, a third drawing module, and a fourth drawing module; wherein, the first drawing module is used to draw the Q-ΔP1 curve on the coordinate system Q-ΔP based on the pressure drop amplitude ΔP1 of the velocity tube combined drainage and production process; the second drawing module is used to draw the Q-ΔP2 curve on the coordinate system Q-ΔP based on the pressure drop amplitude ΔP2 of the wellhead pressurization combined drainage and production process; the third drawing module is used to draw the Q-ΔP3 curve on the coordinate system Q-ΔP based on the pressure drop amplitude ΔP3 of the gas lift combined drainage and production process; and the fourth drawing module is used to draw a gas production-pressure drop amplitude combined drainage and production process diagram based on the Q-ΔP1, Q-ΔP2, and Q-ΔP3 curves.

[0099] Finally, it should be noted that the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A well selection method suitable for combined drainage and production processes in tight gas reservoirs, characterized in that, The method includes the following steps: Collect information on the wellbore structure and production parameters of tight gas reservoirs; Calculate the wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters; Based on the given efficiencies of different bubble drainage processes, calculate the production pressure drop corresponding to the composite drainage process; The pressure drop corresponding to the composite drainage process is calculated by subtracting the production pressure drop from the wellbore production pressure drop, and then calculating the pressure drop amplitude corresponding to the composite drainage process. Based on the pressure drop, draw a composite drainage process diagram of gas production and pressure drop to determine the optimal composite drainage process. The calculation of wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters includes: Based on the wellbore structure and production parameters, a series of gas production rates (Q1, Q2, ..., Q) are given before the drainage process. N ), calculate the wellbore production pressure drop at the corresponding gas production rate of the gas well; The calculation of the production pressure drop corresponding to the composite drainage process based on the given drainage process efficiency of different processes includes: Under velocity column technology, given the bubble discharge efficiency E1 under velocity column conditions, calculate a series of gas production rates ( , … Production pressure drop P N1 ; Under wellhead pressurization technology, given the bubble discharge efficiency E2 under wellhead pressurization conditions, calculate a series of gas production rates ( , … Production pressure drop P N2 ; Under the gas lift process, given the bubble removal efficiency E3 under given gas lift conditions, calculate a series of gas production rates ( , … Production pressure drop P N3 ; The step of calculating the pressure drop reduction corresponding to the combined drainage process by subtracting the production pressure drop from the wellbore production pressure drop includes: Production pressure drop under the speed tube composite drainage process P N1 Pressure drop in wellbore production P is used to calculate the pressure drop of the combined drainage and extraction process in the velocity pipe. P1; Production pressure drop under wellhead pressurization combined with drainage process P N2 Pressure drop in wellbore production P is used to calculate the pressure drop of the wellhead pressurization and combined drainage process. P2; The production pressure drop under the airlift combined drainage process P N2 Pressure drop in wellbore production P is used to calculate the pressure drop in the combined gas lift and drainage process. P3.

2. The well selection method for a combined drainage and production process in tight gas reservoirs according to claim 1, characterized in that, The formula for calculating the wellbore production pressure drop is as follows: ；（1） ；（2） In the formula, P Indicates wellbore production pressure drop, in Pa; P Pressure is expressed in Pa. θ This indicates the well inclination angle, the angle between the well axis and the horizontal direction; v m Expresses the flow velocity of a gas-liquid two-phase mixture, in m / s; D Indicates the inner diameter of the oil pipe, in meters (m). f m Indicates the friction coefficient between the gas and liquid phases; ρ m Represents any cross section Z The average density of the gas-liquid two-phase mixture above, kg / m³; Z Indicates the depth of a gas well, in meters (m). Z represents the unit gas well depth, in meters.

3. The well selection method for a combined drainage and production process in tight gas reservoirs according to claim 1, characterized in that, The aforementioned process of drawing a composite gas production-pressure drop analysis diagram based on the pressure drop amplitude includes: Based on the pressure drop of the velocity tube combined drainage process P1, in coordinate system Q— Draw Q on P~ P1 curve; According to the pressure drop of the wellhead pressurization and combined drainage process P2, in coordinate system Q— Draw Q on P~ P2 curve; Based on the pressure drop of the airlift combined drainage process P3, in coordinate system Q— Draw Q on P~ P3 curve; According to Q~ P1, Q~ P2 and Q~ P3 curve, plot the gas production-pressure drop composite drainage process diagram.

4. A well selection system suitable for combined drainage and production processes in tight gas reservoirs, characterized in that, The system includes: a collection unit, a first calculation unit, a second calculation unit, a third calculation unit, and a drawing unit; wherein, The collection unit is used to collect information on the wellbore structure and production parameters of tight gas reservoirs. The first calculation unit is used to calculate the wellbore production pressure drop under different gas production rates based on the gas well structure and production parameters. The second calculation unit is used to calculate the production pressure drop corresponding to the composite drainage process based on the given drainage process efficiency of different processes. The third calculation unit is used to calculate the pressure drop amplitude corresponding to the composite drainage process by subtracting the production pressure drop from the wellbore production pressure drop. The drawing unit is used to draw a composite drainage process diagram of gas production and pressure drop based on the pressure drop reduction, and to determine the optimal composite drainage process. The first computing unit is specifically used for, Based on the wellbore structure and production parameters, a series of gas production rates (Q1, Q2, ..., Q) are given before the drainage process. N ), calculate the wellbore production pressure drop at the corresponding gas production rate of the gas well; The second computing unit includes: a first computing module, a second computing module, and a third computing module; wherein, The first calculation module is used to calculate a series of gas production rates under a given velocity tube condition and bubble discharge efficiency E1 in a velocity tube process. , … Production pressure drop P N1 ; The second calculation module is used to calculate a series of gas production rates under a given wellhead pressurization efficiency E2. , … Production pressure drop P N2 ; The third calculation module is used to calculate a series of gas production rates under a given gas lift efficiency E3. , … Production pressure drop P N3 ; The third computing unit includes: a fourth computing module, a fifth computing module, and a sixth computing module; wherein, The fourth calculation module is used to calculate the production pressure drop under the velocity tube combined drainage process. P N1 Pressure drop in wellbore production P is used to calculate the pressure drop of the combined drainage and extraction process in the velocity pipe. P1; The fifth calculation module is used to calculate the production pressure drop under the wellhead pressurization and drainage combined process. P N2 Pressure drop in wellbore production P is used to calculate the pressure drop of the wellhead pressurization and combined drainage process. P2; The sixth calculation module is used to calculate the production pressure drop under the gas lift combined drainage process. P N2 Pressure drop in wellbore production P is used to calculate the pressure drop in the gas lift combined drainage process. P3.

5. A well selection system suitable for combined drainage and production processes in tight gas reservoirs according to claim 4, characterized in that, In the first calculation unit, the formula for calculating the wellbore production pressure drop is as follows: ；（1） ；（2） In the formula, P Indicates wellbore production pressure drop, in Pa; P Pressure is expressed in Pa. θ This indicates the well inclination angle, the angle between the well axis and the horizontal direction; v m Expresses the flow velocity of a gas-liquid two-phase mixture, in m / s; D Indicates the inner diameter of the oil pipe, in meters (m). f m Indicates the friction coefficient between the gas and liquid phases; ρ m Represents any cross section Z The average density of the gas-liquid two-phase mixture above, kg / m³; Z Indicates the depth of a gas well, in meters (m). Z represents the unit gas well depth, in meters.

6. A well selection system suitable for combined drainage and production processes in tight gas reservoirs according to claim 4, characterized in that, The drawing unit includes: a first drawing module, a second drawing module, a third drawing module, and a first drawing module; wherein, The first drawing module is used to calculate the pressure drop based on the velocity-tube composite drainage process. P1, in coordinate system Q— Draw Q on P~ P1 curve; The second drawing module is used to calculate the pressure drop based on the wellhead pressurization and drainage process. P2, in coordinate system Q— Draw Q on P~ P2 curve; The third plotting module is used to calculate the pressure drop based on the gas lift combined drainage process. P3, in coordinate system Q— Draw Q on P~ P3 curve; The fourth drawing module is used to draw according to the Q~ P1, Q~ P2 and Q~ P3 curve, plot the gas production-pressure drop composite drainage process diagram.

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