Natural gas well drainage and gas production pressure loss minimum theory and shaft flow state control method

Abstract

The invention relates to a natural gas well drainage gas production pressure loss minimum theory and a shaft flow state control method, and relates to the field of gas well gas production, and the method comprises the following steps: adopting a pressure supply principle and a critical liquid carrying principle to establish shaft drainage gas production process boundary conditions; the weight values of the technical indexes and the weight values of the economic indexes are substituted into a TOPSIS method for calculation, and the optimal drainage and gas production process is selected from six drainage and gas production processes including a speed pipe column, foam drainage, gas lifting, mechanical pumping, an electric submersible pump and a jet pump; according to the selected drainage and gas production process, in combination with the established boundary conditions, establishing a multi-objective planning model comprising a maximum yield objective function and a minimum compressor unit energy consumption objective function in the drainage and gas production process, and determining constraint conditions to obtain compressor working parameters with minimum pressure loss; the method has the advantage that the gas production efficiency can be maximized under the condition that the pressure of the compressor is minimum.

Description

Technical Field

[0001] The invention relates to the technical field of gas well production, and in particular to a theory of minimum pressure loss in natural gas well drainage production and a wellbore flow state control method. Background Art

[0002] In the later stage of liquid production in water-producing gas wells, the liquid carrying capacity is insufficient, resulting in liquid accumulation in the wellbore, increasing the wellbore pressure loss and sharply reducing the production. In order to restore the production of natural gas wells and improve the recovery rate, water drainage and gas production process measures such as velocity string, bubble drainage, plunger, gas lift, electric submersible pump, and jet pump are generally adopted. The optimization of water drainage and gas production process and various process parameters of water-producing gas wells are of great significance for minimizing the wellbore pressure loss, controlling the wellbore flow state, and increasing the gas well production. At present, the wellbore water drainage and gas production process usually adopts the field experience method, which has the problem of poor pertinence in the selection of water drainage and gas production process, resulting in poor on-site process implementation effect and high cost.

[0003] Therefore, in view of the above shortcomings, it is necessary to provide a theory of minimum pressure loss for drainage and gas production in natural gas wells and a method for controlling wellbore flow patterns. Summary of the invention

[0004] 1. Technical issues to be resolved

[0005] The technical problem to be solved by the present invention is to solve the problem of the current lack of theoretical methods and quantitative analysis of process optimization decisions, the poor targeting of drainage gas production process selection, and the poor on-site process implementation effect and high cost.

[0006] (II) Technical solution

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

[0008] Ⅰ. Use the pressure supply principle and critical liquid carrying principle to establish the boundary conditions of the wellbore drainage gas production process;

[0009] Ⅱ. Substitute the weight values ​​of technical indicators and economic indicators into the TOPSIS method to calculate and select the best drainage gas production process from the six drainage gas production processes: velocity string, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump;

[0010] III. According to the selected drainage gas production process and the established boundary conditions, a multi-objective planning model is established for the drainage gas production process, including the maximum output objective function and the minimum energy consumption objective function of the compressor unit, and the constraint conditions are determined to obtain the compressor operating parameters with the minimum pressure loss.

[0011] As a further illustration of the present invention, preferably, the pressure applicable principle is:

[0012] Pwf -Δp=P t >P tr

[0013] in:

[0014] P wf is the bottom hole flowing pressure, in MPa;

[0015] Δp is the total wellbore pressure drop, in MPa;

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

[0017] P tr It is the output pressure at the wellhead, in MPa.

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

[0019] P tr +Δp <P wf <P wfc

[0020] Q cmax g gp

[0021] in:

[0022] P wfc The bottom hole pressure to meet the critical liquid carrying rate, in MPa;

[0023] Q cmax is the upper limit of the critical liquid carrying flow rate of the whole wellbore, in m 3 / d;

[0024] Q g is the actual output, in m 3 / d;

[0025] Q gp is the horizontal coordinate of the intersection point of the inflow curve.

[0026] As a further explanation of the present invention, preferably, the weight value of the technical indicators is composed of the weight values ​​of eight indicators: process adaptability, discharge volume, increase in production ratio, sand control, scale resistance, ground installation, energy supply form and maintenance management; the weight value of the economic indicators is composed of the weight values ​​of five indicators: net present value, net present value rate, profit, payback period and cost.

[0027] As a further illustration of the present invention, preferably, the comprehensive weight values ​​of the six drainage gas production processes satisfy:

[0028] ​​

[0029] in:

[0030] Q i The i in the figure corresponds to the six drainage gas production technologies: velocity column, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump. i is the comprehensive weight value of this type of drainage gas production process;

[0031] v i is the weight value of technical indicators and economic indicators;

[0032] w i is the weight value calculated by entropy method;

[0033] α i is the subjective weight value;

[0034] β i is the objective weight value.

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

[0036]

[0037] Objective weight value β i satisfy:

[0038]

[0039] The weight calculation result is rounded to four decimal places.

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

[0041] Compare each drainage gas production process to obtain the comparison matrix X ij , and normalize it to get:

[0042]

[0043] Determine the positive ideal solution V + and negative ideal solution V - , respectively:

[0044]

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

[0046]

[0047] Calculate the closeness of each drainage gas production, specifically:

[0048]

[0049] in:

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

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

[0052]

[0053] in:

[0054] P0 i It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa;

[0055] Prod_W i (P0 i ) is the single well production, that is, wellhead pressure increase P0 i The single well production at that time.

[0056] As a further illustration of the present invention, preferably, the compressor energy consumption minimum objective function is:

[0057]

[0058] in:

[0059] P0 i It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa;

[0060] WS i (P0 i ,P1 i ,q wi ) is the compressor power for wellhead boosting;

[0061] NS i (P1 i ,P2 i ,q ni ) is the compressor power of the node boost;

[0062] CS i (P2 i ,P3 i ,q ci ) is the power of the centralized supercharging compressor.

[0063] As a further illustration of the present invention, preferably, the constraints are:

[0064]

[0065] (III) Beneficial effects

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

[0067] The present invention establishes wellbore multiphase flow and foam flow models, and carries out comprehensive optimization of natural gas well drainage and gas production technology based on pressure supply and critical liquid carrying principles, combined with economic benefit evaluation. The optimal two-phase flow model is used to calculate the pressure distribution of natural gas wellbore, determine the pressure applicable limit of drainage and gas production technology, and at the same time conduct quantitative analysis of process optimization decisions, establish a multi-objective planning model, optimize various process parameters, and achieve wellbore flow state control and minimize system pressure loss. DETAILED DESCRIPTION

[0068] In order to make the purpose, technical solution and advantages of the embodiments of the present invention clearer, the technical solution in the embodiments of the present invention will be clearly and completely described below. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0069] The minimum pressure loss theory for gas well drainage and gas production and the wellbore flow pattern control method include the following steps:

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

[0071] Due to the special wellbore structure of horizontal gas wells, the liquid accumulation conditions in different well sections are different. It is necessary to comprehensively consider the liquid flow rate of the gas well, the change of wellbore flow pattern, pressure and liquid holdup distribution, study the gas-liquid two-phase flow law in the horizontal wellbore, and analyze the liquid accumulation characteristics of horizontal wells.

[0072] The gas-liquid two-phase flow law of the ideal model of different sections of horizontal wells is analyzed, but there is no mature theory of liquid carrying in horizontal gas wells. The model is combined with the wellbore structure of horizontal gas wells to establish a gas-liquid two-phase flow model in the horizontal wellbore, laying the foundation for modeling the drainage and gas production measures of horizontal gas wells and constructing the wellbore lifting flow model, thus providing a theoretical basis for guiding the rational production of horizontal gas wells.

[0073] Based on the horizontal, inclined and vertical pipe gas-liquid two-phase flow models, the model establishes a foam mechanism model, collects measured data from downhole pressure gauges, and applies artificial intelligence algorithms for optimization and calibration.

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

[0075] The drainage gas production technology of natural gas wells includes: non-energy-replenishing drainage gas production technology measures such as velocity string, wellhead pressurization, and bubble drainage, as well as energy-replenishing drainage gas production technology measures such as continuous gas lift, mechanical pumping, electric submersible pumps, and jet pumps. The selection of drainage gas production technology measures gives priority to non-energy-replenishing drainage gas production technology measures. When non-energy-replenishing drainage gas production technologies are not applicable, energy-replenishing drainage gas production technologies are preferred.

[0076] The optimization of non-energy-replenishing drainage gas production technology requires consideration of both the pressure supply principle and the critical liquid carrying principle, so as to determine the pressure applicable limit and liquid carrying applicable limit of the process.

[0077] The applicable principles for pressure are:

[0078] P wf -Δp=P t >P tr

[0079] in:

[0080] P wf is the bottom hole flowing pressure, in MPa;

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

[0082] P t is the wellhead oil pressure, in MPa;

[0083] P tr It is the output pressure at the wellhead, 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 The bottom hole pressure to meet the critical liquid carrying rate, in MPa;

[0089] Q cmax is the upper limit of the critical liquid carrying flow rate of the whole wellbore, in m 3 / d;

[0090] Q g is the actual output, in m 3 / d;

[0091] Q gp ​​is the horizontal coordinate of the intersection point of the inflow curve.

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

[0093] Using the AHP hierarchical analysis method, the technical indicators and economic indicators are subdivided into 13 indicators and the corresponding weight values ​​are calculated, as shown in the following table:

[0094]

[0095] The matrix method uses the relative importance of subjective weight and objective weight to represent the relative importance of subjective weight and objective weight, and defines the importance coefficients of subjective weight and objective weight as α and i and β i , the calculation formula is as follows:

[0096]

[0097] The weight calculation result is rounded to four decimal places.

[0098] The calculation formula for the comprehensive weight value of the six drainage gas production processes is as follows:

[0099]

[0100] in:

[0101] Q i The i in the figure corresponds to the six drainage gas production technologies: velocity column, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump. i is the comprehensive weight value of this type of drainage gas production process;

[0102] v i is the weight value of technical indicators and economic indicators;

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

[0104]

[0105] in:

[0106]

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

[0108] 4. Optimize gas recovery process

[0109] Substitute the calculated comprehensive weight value into the TOPSIS method to calculate and select the best drainage gas production process from the six drainage gas production processes: velocity string, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump. Specifically:

[0110] Compare each drainage gas production process to obtain the comparison matrix X ij , and normalize it to get:

[0111]

[0112] Determine the positive ideal solution V + and negative ideal solution V - , respectively:

[0113]

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

[0115]

[0116] Calculate the closeness of each drainage gas production, specifically:

[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, and the closer it is to 0, the closer it is to the worst level.

[0120] 5. Obtain the minimum pressure increase method for ground gathering and transmission pressure loss

[0121] The surface boosting process reduces the wellhead oil pressure, thereby reducing the bottomhole flow pressure, increasing the production pressure difference, and increasing the gas well production. The lower the wellhead pressure, the greater the gas well production. However, this also increases the compressor pressure and processing gas volume, the compressor load will increase, and the energy consumption will increase. Under the condition of meeting the production requirements (there are boundary conditions), two or more objective functions need to be optimized at the same time, and they cannot be explicitly balanced (there is no solution to optimize each objective function at the same time). This is a constrained multi-objective planning problem.

[0122] Reducing the wellhead oil pressure will increase the gas well production. The increase in production by reducing the unit wellhead oil pressure is different for different well conditions, and the lower the wellhead pressure is in the later stage, the less the increase in production is. How to maximize gas production under the conditions of limited number of compressors or insufficient compressor power, and the maximum power of a single compressor is limited to 160Kw, requires the establishment of a multi-objective planning model. Taking the objective functions of maximum gas production and minimum compressor energy consumption as an example, the objective function for maximum production is:

[0123]

[0124] in:

[0125] P0 i It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa;

[0126] Prod_W i (P0 i ) is the single well production, that is, wellhead pressure increase P0 i The single well production 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 It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa;

[0134] WS i (P0 i ,P1 i ,q wi ) is the compressor power for wellhead boosting;

[0135] NS i (P1 i ,P2 i ,q ni ) is the compressor power of the node boost;

[0136] CS i (P2 i ,P3 i ,q ci ) is the power of the centralized supercharging compressor.

[0137] The present invention provides two application examples, specifically:

[0138] Well A (vertical depth of 4450 meters, in October 2017, the bottom hole pressure gradient was about 0.1MPa / 100m when flooded), the corresponding TOPSIS calculated values ​​of {velocity string, bubble drainage, gas lift, mechanical pumping, electric submersible pump, jet pump} are: {0.1205, 0.2035, 0.7412, 0.4123, 0.5680, 0.5568}. And according to the lowest system pressure loss, gas lift drainage and gas production process measures were adopted to successfully activate the well, with a daily production of 50,000-60,000 cubic meters, and it has been producing steadily for more than a year.

[0139] Well B (underpressure shale gas well, vertical depth 3700 meters), with a total investment of more than 100 million yuan, produced only 1.33 million cubic meters of gas and was shut down for more than two years due to less than 4000 cubic meters of daily gas volume. The calculated values ​​of {velocity string, bubble drainage, gas lift, mechanical pumping, electric submersible pump, jet pump} obtained by TOPSIS method correspond to: {0.1123, 0.4598, 0.4120, 0.4014, 0.5647, 0.4125}, according to the lowest system pressure loss, the electric submersible pump drainage gas production process was adopted, successfully activated, and a stable production of 15,000 cubic meters / day was achieved under production restriction conditions.

[0140] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, rather than to limit it. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein. However, these modifications or replacements do not deviate the essence of the corresponding technical solutions from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. The theory of minimum pressure loss in natural gas well drainage and gas production and a method for controlling wellbore flow pattern, characterized by: The following steps are involved: Ⅰ. Use the pressure supply principle and critical liquid carrying principle to establish the boundary conditions of the wellbore drainage gas production process; Ⅱ. Substitute the weight values ​​of technical indicators and economic indicators into the TOPSIS method to calculate and select the best drainage gas production process from the six drainage gas production processes: velocity string, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump; III. According to the selected drainage gas production process and the established boundary conditions, a multi-objective planning model is established for the drainage gas production process, including the maximum output objective function and the minimum energy consumption objective function of the compressor unit, and the constraint conditions are determined to obtain the compressor operating parameters with the minimum pressure loss.

2. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 1 is characterized by: The applicable principles for pressure are: P wf -Δp=P t >P tr in: P wf is the bottom hole flowing pressure, in MPa; Δp is the total wellbore pressure drop, in MPa; P t is the wellhead oil pressure, in MPa; P tr It is the output pressure at the wellhead, in MPa.

3. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 2 is characterized by: The critical liquid carrying principle is: P tr +Δp<P wf <P wfc Q cmax <Q g <Q gp in: P wfc The bottom hole pressure to meet the critical liquid carrying rate, in MPa; Q cmax is the upper limit of the critical liquid carrying flow rate of the whole wellbore, in m 3 / d; Q g is the actual output, in m 3 / d; Q gp is the horizontal coordinate of the intersection point of the inflow curve.

4. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 3 is characterized by: The weight value of technical indicators is composed of the weight values ​​of eight indicators: process adaptability, discharge volume, increase in production ratio, sand control, scale prevention, ground installation, energy supply form and maintenance management; the weight value of economic indicators is composed of the weight values ​​of five indicators: net present value, net present value rate, profit, investment payback period and cost.

5. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 4 is characterized by: The comprehensive weight values ​​of the six drainage gas production technologies meet the following requirements: in: Q i The i in the figure corresponds to the six drainage gas production technologies: velocity column, bubble drainage, gas lift, mechanical pumping, electric submersible pump and jet pump. i is the comprehensive weight value of this type of drainage gas production process; v i is the weight value of technical indicators and economic indicators; w i is the weight value calculated by entropy method; α i is the subjective weight value; β i is the objective weight value.

6. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 5, characterized in that: Subjective weight value α i satisfy: Objective weight value β i satisfy: The weight calculation result is rounded to four decimal places.

7. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 1, characterized in that: The TOPSIS method includes the following steps: Compare each drainage gas production process to obtain the comparison matrix X ij , and normalize it to get: Determine the positive ideal solution V + and negative ideal solution V - , respectively: Calculate the Euclidean distance from each drainage gas production process to the positive ideal solution and the Euclidean distance to the negative ideal solution They are: Calculate the closeness of each drainage gas production, specifically: in: C i The value is between 0 and 1.

8. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 1, characterized in that: The objective function for maximizing output is: in: P0 i It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa; Prod_W i (P0 i ) is the single well production, that is, wellhead pressure increase P0 i The single well production at that time.

9. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 8, characterized in that: The objective function for minimizing compressor energy consumption is: in: P0 i It is the pressure at the wellhead during pressurization, i.e. the compressor inlet pressure, in MPa; WS i (P0 i ,P1 i ,q wi ) is the compressor power for wellhead boosting; NS i (P1 i ,P2 i ,q ni ) is the compressor power of the node boost; CS i (P2 i ,P3 i ,q ci ) is the power of the centralized supercharging compressor.

10. The natural gas well drainage gas production pressure loss minimum theory and wellbore flow pattern control method according to claim 9, characterized in that: The constraints are:

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