Theoretical and wellbore flow regime control method for minimizing pressure loss in natural gas well drainage

Abstract

The present application relates to natural gas well drainage gas production pressure loss minimum theory and wellbore flow state control method, relates to gas well gas production field, including the following steps: adopting pressure supply principle and critical liquid carrying principle to establish wellbore drainage gas production process boundary condition;The weight value of technical index and the weight value of economic index are substituted into TOPSIS method to calculate, and the best drainage gas production process is selected in six drainage gas production processes of velocity string, foam drainage, gas lift, machine pumping, electric submersible pump and jet pump;According to the selected drainage gas production process, combined with the established boundary condition, the multi-objective programming model including the maximum yield objective function and the lowest compressor set energy consumption objective function in the drainage gas production process is established, the constraint condition is determined to obtain the compressor working parameter with minimum pressure loss, and the present application has the advantages that the gas production efficiency can be maximized under the condition of minimum compressor pressure.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of gas well production, in particular to a natural gas well drainage gas production pressure loss minimum theory and wellbore flow regime control method. BACKGROUND

[0002] In the late stage of liquid-carrying production of water-producing gas wells, the liquid-carrying capacity is insufficient, causing wellbore fluid accumulation, increasing wellbore pressure loss, and sharply reducing production. In order to restore natural gas well production and improve recovery, speed string, foam drainage, plunger, gas lift, electric submersible pump, and jet pump drainage gas production process measures are generally adopted. The optimization of drainage gas production process and various process parameters are of great significance to achieve minimum wellbore pressure loss, control wellbore flow regime, and increase gas well production. At present, the drainage gas production process is usually selected by using field experience method, which has poor drainage gas production process selection pertinence, resulting in poor field process implementation effect and high cost.

[0003] Therefore, in view of the above problems, a natural gas well drainage gas production pressure loss minimum theory and wellbore flow regime control method are needed. SUMMARY

[0004] (I) Technical problem to be solved

[0005] The technical problem to be solved by the present application is to solve the problem that there is a lack of quantitative analysis of theoretical methods and process optimization decision-making at present, and the drainage gas production process selection has poor pertinence, resulting in poor field process implementation effect and high cost.

[0006] (II) Technical scheme

[0007] In order to solve the above technical problems, the present application provides a natural gas well drainage gas production pressure loss minimum theory and wellbore flow regime control method, comprising the following steps:

[0008] I. Establishing wellbore drainage gas production process boundary conditions by using pressure supply principle and critical liquid-carrying principle;

[0009] II. Substituting the weight values of technical indicators and the weight values of economic indicators into the TOPSIS method to calculate, and selecting the best drainage gas production process from the six drainage gas production processes of speed string, foam drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump;

[0010] III. According to the selected drainage gas production process, combining the established boundary conditions, establishing a multi-objective programming model including the maximum production target function and the lowest compressor energy consumption target function in the drainage gas production process, and determining the constraint conditions to obtain the compressor working parameters with minimum pressure loss.

[0011] As a further description of the present application, preferably, the pressure application principle is:

[0012] Pwf Delta P = P t P tr

[0013] Wherein:

[0014] P wf is the wellhead pressure, unit: MPa;

[0015] Delta P is the total wellbore pressure drop, unit: MPa;

[0016] P t is the wellhead oil pressure, unit: MPa;

[0017] P tr is the wellhead external delivery pressure, unit: MPa.

[0018] As a further description of the present application, preferably, the critical liquid carrying principle is:

[0019] P tr + Delta P < P wf P wfc

[0020] Q cmax Q g Q gp

[0021] Wherein:

[0022] P wfc is the wellhead pressure, unit: MPa;

[0023] Q cmax is the full wellbore critical liquid carrying flow upper limit, unit: m 3 / d;

[0024] Q g is the actual production, unit: m 3 / d;

[0025] Q gp is the intersection abscissa of the inflow curve.

[0026] As a further description of the present application, preferably, the weight value of the technical index is composed of the weight values of the process adaptability, liquid discharge amount, yield increase ratio, sand prevention, scale prevention, ground installation, energy supply form and maintenance management eight indexes; the weight value of the economic index is composed of the weight values of the net present value, net present value rate, profit, investment return period and cost five indexes.

[0027] As a further description of the present application, preferably, the comprehensive weight value of the six drainage gas recovery processes satisfies:

[0028]

[0029] in:

[0030] Q i In this context, 'i' corresponds to one of six drainage and gas production processes: velocity tubing, bubble drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump. Q i This is the comprehensive weighting value for this type of drainage gas extraction technology;

[0031] v i These are the weighted values ​​for technical and economic indicators.

[0032] w i The weight values ​​are calculated using the entropy method.

[0033] α i This is a subjective weighting value;

[0034] β i This is an objective weight value.

[0035] As a further explanation of the present invention, preferably, the subjective weight value α i satisfy:

[0036]

[0037] Objective weight value β i satisfy:

[0038]

[0039] The weight values ​​are calculated and retained to four decimal places.

[0040] As a further explanation of the present invention, preferably, the TOPSIS method includes the following steps:

[0041] The various drainage gas production processes were compared to obtain the comparison matrix X. ij And after standardization, we get:

[0042]

[0043] Determine the ideal solution V + and negative ideal solution V - They are respectively:

[0044]

[0045] Calculate the Euclidean distance from each drainage gas extraction process to the positive ideal solution. Euclidean distance to the negative ideal solution They are respectively:

[0046]

[0047] The proximity of each type of drainage gas extraction is calculated as follows:

[0048]

[0049] in:

[0050] C i The value is between 0 and 1.

[0051] As a further explanation of the present invention, preferably, the objective function for maximizing output is:

[0052]

[0053] in:

[0054] P0 i The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa;

[0055] Prod_W i (P0 i The figure represents the production rate of a single well, i.e., the wellhead pressurization rate P0. i The production output of a single well at that time.

[0056] As a further explanation of the present invention, preferably, the objective function for minimizing compressor energy consumption is:

[0057]

[0058] in:

[0059] P0 i The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa;

[0060] WS i (P0 i P1 i ,q wi The compressor power for wellhead pressurization;

[0061] NS i (P1 i P2 i ,q ni The compressor power for node pressurization;

[0062] CS i (P2 i P3 i ,q ci ) represents the power of the compressor with centralized pressurization.

[0063] As a further explanation of the present invention, preferably, the constraints are as follows:

[0064]

[0065] (III) Beneficial Effects

[0066] The above-described technical solution of the present invention has the following advantages:

[0067] This invention establishes multiphase flow and foam flow models for wellbore drainage and gas production, and conducts comprehensive optimization of natural gas well drainage and gas production processes based on pressure supply and critical liquid carrying principles, combined with economic benefit evaluation. The optimized two-phase flow model is used to calculate the pressure distribution in the natural gas wellbore, determine the pressure applicable limits of the drainage and gas production process, and simultaneously perform quantitative analysis of process optimization decisions. A multi-objective programming model is established to optimize various process parameters, achieving wellbore flow control and minimizing system pressure loss. Detailed Implementation

[0068] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. 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.

[0069] The theory of minimizing pressure loss during natural gas well drainage and the method of wellbore flow control include the following steps:

[0070] 1. Establish a gas-liquid two-phase flow model in the wellbore.

[0071] Given the unique structure of horizontal gas wells, the liquid accumulation situation varies in different well sections. It is necessary to comprehensively consider factors such as the gas well's liquid carrying capacity, wellbore flow pattern changes, pressure and liquid holdup distribution, etc., to study the gas-liquid two-phase flow law in horizontal wells and conduct liquid accumulation characteristic analysis.

[0072] The gas-liquid two-phase flow characteristics of ideal models for different sections of horizontal wells are analyzed, but a mature theory of liquid carrying capacity for horizontal gas wells has not yet been established. A gas-liquid two-phase flow model for horizontal gas wells is established by combining the wellbore structure with the model, laying the foundation for modeling drainage and gas production measures for horizontal gas wells and constructing wellbore lifting flow models, thereby providing a theoretical basis for guiding the rational production of horizontal gas wells.

[0073] Based on horizontal, inclined, and vertical pipe gas-liquid two-phase flow models, a foam mechanism model was established, measured data from downhole pressure gauges were collected, and artificial intelligence algorithms were applied for optimization and calibration.

[0074] 2. Establish the boundary conditions for wellbore drainage gas production process.

[0075] Natural gas well drainage and production technologies include: non-replenishment drainage and production technologies such as velocity tubing, wellhead pressurization, and bubble drainage; and replenishment drainage and production technologies such as continuous gas lift, mechanical pumping, electric submersible pumps, and jet pumps. Non-replenishment drainage and production technologies are preferred when selecting drainage and production technologies; however, replenishment drainage and production technologies are preferred when all other non-replenishment technologies are unsuitable.

[0076] The optimal selection of non-rechargeable drainage gas production technology requires simultaneous consideration of the pressure supply principle and the critical liquid carrying principle, so as to determine the applicable pressure limit and the applicable liquid carrying limit of the technology.

[0077] The applicable principle for pressure is as follows:

[0078] P wf -Δp=P t >P tr

[0079] in:

[0080] P wf This refers to the bottom hole flowing pressure, expressed in MPa.

[0081] Δp is the total pressure drop in the wellbore, in MPa;

[0082] P t This refers to the wellhead oil pressure, expressed in MPa.

[0083] P tr This represents the pressure delivered from the wellhead, expressed in MPa.

[0084] The critical liquid carrying principle is:

[0085] P tr +Δp <P wf <P wfc

[0086] Q cmax g gp

[0087] in:

[0088] P wfc Bottomhole flowing pressure required to meet critical fluid carrying capacity, in MPa;

[0089] Q cmax This represents the upper limit of the critical fluid carrying capacity of the entire wellbore, in meters (m³). 3 / d;

[0090] Q g This refers to actual output, in meters (m). 3 / d;

[0091] Q gp ​​The x-coordinate of the intersection point of the inflow curves.

[0092] 3. Obtain the weight values ​​of the process evaluation system

[0093] Using the Analytic Hierarchy Process (AHP), technical and economic indicators were subdivided into 13 indicators and their corresponding weights were calculated, as shown in the table below:

[0094]

[0095] The matrix method uses subjective and objective weights to represent their relative importance, defining the importance coefficients for subjective and objective weights as α and α, respectively. i and β i The calculation formula is as follows:

[0096]

[0097] The weight values ​​are calculated and retained to four decimal places.

[0098] The formula for calculating the comprehensive weight value of the six drainage gas extraction technologies is as follows:

[0099]

[0100] in:

[0101] Q i In this context, 'i' corresponds to one of six drainage and gas production processes: velocity tubing, bubble drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump. Q i This is the comprehensive weighting value for this type of drainage gas extraction technology;

[0102] v i These are the weighted values ​​for technical and economic indicators.

[0103] w i The weight value is calculated using the entropy method, and the calculation formula is as follows:

[0104]

[0105] in:

[0106]

[0107] p ij The weight of the secondary indicators under each indicator.

[0108] 4. Optimize gas extraction technology

[0109] The calculated comprehensive weight value is substituted into the TOPSIS method to select the optimal drainage and gas production process from six drainage and gas production processes: velocity tubing, bubble drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump. Specifically:

[0110] The various drainage gas production processes were compared to obtain the comparison matrix X. ij And after standardization, we get:

[0111]

[0112] Determine the ideal solution V + and negative ideal solution V - They are respectively:

[0113]

[0114] Calculate the Euclidean distance from each drainage gas extraction process to the positive ideal solution. Euclidean distance to the negative ideal solution They are respectively:

[0115]

[0116] The proximity of each type of drainage gas extraction is calculated as follows:

[0117]

[0118] in:

[0119] C i The value is between 0 and 1, C i The closer the value is to 1, the closer it is to the optimal level; the closer it is to 0, the closer it is to the worst level.

[0120] 5. Obtain the minimum pressurization method for ground gathering and transportation pressure loss

[0121] Surface pressurization technology reduces wellhead oil pressure, thereby lowering bottomhole flowing pressure and increasing production pressure differential, thus increasing gas well production. Lower wellhead pressure results in higher production. However, this also increases compressor pressure and gas throughput, leading to increased compressor load and energy consumption. Under the condition of meeting production requirements (with boundary conditions), it is necessary to simultaneously optimize two or more objective functions, and they cannot be explicitly balanced (there is no solution that simultaneously optimizes each objective function). This is a constrained multi-objective programming problem.

[0122] The effect of reducing wellhead oil pressure on increasing gas well production varies depending on well conditions. Furthermore, the increase in production from reducing unit wellhead oil pressure is less pronounced as wellhead pressure decreases. To maximize gas production under conditions where the number of compressors is limited or their power is insufficient (with the maximum power of a single compressor limited to 160kW), a multi-objective programming model is needed. Taking the objective functions of maximizing gas production and minimizing compressor energy consumption as an example, the objective function for maximizing production is:

[0123]

[0124] in:

[0125] P0 i The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa;

[0126] Prod_W i (P0 i The figure represents the production rate of a single well, i.e., the wellhead pressurization rate P0. i The production output of a single well at that time.

[0127] The objective function for minimizing compressor energy consumption is:

[0128] Establish a nonlinear programming model for minimizing the energy consumption of the compressor unit:

[0129]

[0130] Constraints:

[0131]

[0132] in:

[0133] P0 i The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa;

[0134] WS i (P0 i P1 i ,q wi The compressor power for wellhead pressurization;

[0135] NS i (P1 i P2 i ,q ni The compressor power for node pressurization;

[0136] CS i (P2 i P3 i ,q ci ) represents the power of the compressor with centralized pressurization.

[0137] This invention provides two application examples, specifically:

[0138] Well A (vertical depth 4450 meters, October 2017, bottomhole pressure gradient approximately 0.1 MPa / 100m during water flooding) has the following TOPSIS calculated values ​​for the following systems: {velocity tubing, bubble drainage, gas lift, mechanical pumping, ESP, jet pump}: {0.1205, 0.2035, 0.7412, 0.4123, 0.5680, 0.5568}. By employing a gas lift drainage gas production process to minimize system pressure loss, the well was successfully activated, producing 50,000-60,000 cubic meters per day, and has maintained stable production for over a year.

[0139] Well B (underpressured shale gas well, vertical depth 3700 meters), with a total investment of over 100 million yuan, only produced 1.33 million cubic meters of gas before being shut down for more than two years due to a daily gas production of less than 4000 cubic meters. The calculated values ​​obtained using the TOPSIS method for the following pumps (velocity tubing, bubble drainage, gas lift, mechanical pumping, ESP, jet pump) are: {0.1123, 0.4598, 0.4120, 0.4014, 0.5647, 0.4125}. Based on minimizing system pressure loss, an ESP drainage gas production process was adopted, successfully activating the well and achieving a stable production of 15,000 cubic meters per day under limited production conditions.

[0140] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. The theory of minimizing pressure loss during natural gas well drainage and production, and the wellbore flow control method, characterized by: Includes the following steps: I. Establish the boundary conditions for wellbore drainage and gas production process using the pressure supply principle and the critical fluid carrying principle; wherein, the pressure supply principle is: in: This refers to the bottom hole flowing pressure, expressed in MPa. The total pressure drop in the wellbore is expressed in MPa. This refers to the wellhead oil pressure, expressed in MPa. This refers to the pressure supplied from the wellhead, expressed in MPa. The critical liquid carrying principle is: in: Bottomhole flowing pressure required to meet critical fluid carrying capacity, in MPa; This represents the upper limit of the critical fluid carrying capacity of the entire wellbore, in meters (m³). 3 / d; This refers to actual output, in meters (m). 3 / d; The x-coordinate of the intersection point of the inflow curves; II. Substitute the weighted values ​​of technical indicators and economic indicators into the TOPSIS method for calculation. The weighted values ​​of technical indicators consist of the weighted values ​​of eight indicators: process adaptability, drainage volume, production increase ratio, sand control, scale prevention, ground installation, energy supply form, and maintenance management. The weighted values ​​of economic indicators consist of the weighted values ​​of five indicators: net present value, net present value ratio, profit, investment payback period, and cost. Select the optimal drainage gas production process from six drainage gas production processes: velocity tubing, bubble drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump. III. Based on the selected drainage gas extraction process and the established boundary conditions, a multi-objective programming model is established for this process, including the objective function of maximizing output and the objective function of minimizing compressor energy consumption. Constraints are determined to obtain the compressor operating parameters with minimum pressure loss. The objective function for minimizing compressor energy consumption is: in: The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa; The power of the compressor used to pressurize the wellhead; The compressor power used to boost pressure at the node; The power of the compressor with centralized pressurization; The constraints are: 。 2. The theory of minimum pressure loss during natural gas well drainage and gas production, and the wellbore flow control method according to claim 1, are characterized in that: The comprehensive weighting values ​​of the six drainage gas extraction technologies satisfy the following: in: In These correspond to six drainage and gas production processes: velocity tubing, bubble drainage, gas lift, mechanical pumping, electric submersible pump, and jet pump. This is the comprehensive weighting value for this type of drainage gas extraction technology; These are the weighted values ​​for technical and economic indicators. The weight values ​​are calculated using the entropy method. This is a subjective weighting value; This is an objective weight value.

3. The theory of minimum pressure loss during natural gas well drainage and gas production, and the wellbore flow control method according to claim 2, are characterized in that: Subjective weight value satisfy: Objective weight value satisfy: The weight values ​​are calculated and retained to four decimal places.

4. The theory of minimum pressure loss during natural gas well drainage and gas production, and the wellbore flow control method according to claim 1, are characterized in that: The TOPSIS method includes the following steps: A comparison matrix was obtained by comparing various drainage gas production processes. And after standardization, we get: Determine the ideal solution and negative ideal solution They are respectively: Calculate the Euclidean distance from each drainage gas extraction process to the positive ideal solution. Euclidean distance to the negative ideal solution They are respectively: The proximity of each type of drainage gas extraction is calculated as follows: in: The value is between 0 and 1.

5. The theory of minimum pressure loss during natural gas well drainage and gas production, and the wellbore flow control method according to claim 1, are characterized in that: The objective function that maximizes output is: in: The pressure used to pressurize the wellhead, i.e., the compressor intake pressure, in MPa; This refers to the production rate of a single well, i.e., the pressurization at the wellhead. The production output of a single well at that time.

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