Shale condensate gas well composite discharging and mining method

Abstract

The invention discloses a shale condensate gas well composite drainage and mining method, and relates to the field of shale gas mining. The shale condensate gas well composite discharging and mining method comprises the following steps that fluid component data of a shale condensate gas well are collected and corrected, and corrected fluid component data are obtained; generating a component phase diagram by using the corrected fluid component data, and determining the temperature and the pressure in the reservoir and the intersection point pressure of the corresponding equal liquid volume lines through the component phase diagram; establishing a vertical shaft pipe flow model to obtain a pressure gradient formula; a pressure gradient formula obtained by the vertical shaft pipe flow model is verified on the basis of actual production data, and vertical pipe flow parameters with the best fitting degree are obtained; and a composite drainage and mining pipe column is used for drainage and mining according to the vertical pipe flow parameters with the best fitting degree. According to the shale condensate gas well composite discharging and mining method, the requirement for continuous discharging and mining production of the shale condensate gas well can be met, and the method is suitable for different discharging and mining stages.

Description

Technical Field

[0001] This application relates to the field of shale gas exploitation, and more particularly, to a composite production method for shale condensate gas wells. Background Art

[0002] Condensate gas is a gas generated by the retrograde evaporation of liquid hydrocarbons after the underground temperature and pressure exceed the critical conditions. After the condensate gas is produced, it will retrograde condense into light oil due to the decrease of surface pressure and temperature, making the well fluid in shale condensate gas wells with condensate phenomenon have the characteristics of three-phase flow of oil, gas and water, making the well flow more complex, resulting in the inapplicability of a single production method to the production of shale condensate gas wells. Summary of the Invention

[0003] The purpose of this application is to provide a composite production method for shale condensate gas wells, which can meet the requirements of continuous production of shale condensate gas wells and adapt to different production stages.

[0004] This application is implemented as follows:

[0005] This application provides a composite production method for shale condensate gas wells, including the following steps:

[0006] Collect the fluid component data of the shale condensate gas well for correction to obtain the corrected fluid component data;

[0007] Use the corrected fluid component data to generate a component phase diagram, and determine the intersection pressure of the temperature, pressure in the reservoir and the corresponding isovolume line through the component phase diagram;

[0008] Establish a vertical wellbore pipe flow model to obtain a pressure gradient formula;

[0009] Verify the pressure gradient formula obtained from the vertical wellbore pipe flow model based on the actual production data to obtain the vertical pipe flow parameters with the best fitting degree:

[0010] Use the composite production string to carry out production with the vertical pipe flow parameters with the best fitting degree.

[0011] In some alternative embodiments, when correcting the fluid component data of the shale condensate gas well, correct the critical pressure, critical temperature, OMEGA A, and OMEGA B data in the component data by fitting the constant volume expansion experiment and constant mass compression experiment data.

[0012] In some alternative embodiments, the pressure gradient formula of the vertical wellbore pipe flow model is:

[0013]

[0014] Where ρ L is the liquid phase density; HL is the liquid holdup, which is the volume fraction of the liquid phase in the flowing gas-liquid mixture, expressed as a decimal; ρ g is the gas-phase density; θ is the angle between the pipeline and the horizontal direction; λ is the flow resistance coefficient; G is the mass flow rate of the mixture; v is the average flow velocity of the mixture; D is the inner diameter of the pipe; A is the flow cross-sectional area of the pipe; v sg is the apparent gas-phase flow velocity;

[0015] The correlation formula for the inclination correction coefficient regressed according to the experimental results is as follows:

[0016]

[0017] where ψ is the inclination correction coefficient, dimensionless; the coefficient C is the no-slip liquid holdup, expressed as a percentage.

[0018] In some alternative embodiments, validating the pressure gradient formula obtained from the vertical wellbore flow model based on actual production data includes the following steps:

[0019] S1. Determine the wellbore boundary conditions;

[0020] S2. Use the actual production data to correct the pressure gradient formula of the vertical wellbore flow model;

[0021] S3. Compare the temperature and pressure of each well section with the actual values;

[0022] S4. If the calculated pressure of each well section is within the reasonable error range compared with the actual value, the correction is completed; if the two are not within the reasonable error range, adjust the correlation formula of the flowing pressure gradient, and repeat steps S2, S3, and S4 until the error is controlled within the reasonable range.

[0023] In some alternative embodiments, the wellbore boundary conditions include reservoir temperature, wellbore pressure, pressure gradient, temperature gradient, wellhead pressure, and wellhead temperature.

[0024] In some alternative embodiments, when validating the pressure gradient formula obtained from the vertical wellbore flow model based on actual production data, the influence of the phase change of the condensate gas fluid with temperature is added as a wellbore constraint condition.

[0025] In some alternative embodiments, the compound production string includes a tubing string, a casing sleeved outside the tubing string, a gas lift valve connected to the tubing string, a packer, and a rod pump. An annular channel for gas flow is formed between the tubing string and the casing. The packer is used to seal the annular channel. The gas lift valve is used to allow the gas injected into the annular channel to enter the tubing string. The rod pump is used to lift the liquid and discharge it to the ground from the tubing string.

[0026] In some alternative embodiments, the rod pump, the gas lift valve, and the packer are arranged in sequence from top to bottom.

[0027] In some alternative embodiments, a sand control structure is provided on the sucker rod pump.

[0028] In some alternative embodiments, the opening and closing time of the gas lift valve is determined by the intersection pressure of the temperature, pressure in the reservoir and the corresponding isochore line determined from the component phase diagram.

[0029] In some alternative embodiments, the opening and closing time of the gas lift valve is determined by the intersection pressure of the temperature, pressure in the reservoir and the corresponding isochore line determined from the component phase diagram.

[0030] The beneficial effects of the present application are as follows: The composite drainage and production method for shale condensate gas wells provided by the present application includes the following steps: collecting and correcting the fluid component data of the shale condensate gas well to obtain the corrected fluid component data; generating a component phase diagram using the corrected fluid component data, and determining the intersection pressure of the temperature, pressure in the reservoir and the corresponding isochore line through the component phase diagram; establishing a vertical wellbore pipe flow model to obtain a pressure gradient formula; verifying the pressure gradient formula obtained from the vertical wellbore pipe flow model based on actual production data to obtain the vertical pipe flow parameters with the best fitting degree; using a composite drainage and production string to perform drainage and production with the vertical pipe flow parameters with the best fitting degree. The composite drainage and production method for shale condensate gas wells provided by the present application can meet the requirements of continuous drainage and production of shale condensate gas wells and adapt to different drainage and production stages. Description of the Drawings

[0031] In order to more clearly illustrate the technical solutions of the embodiments of the present application, the following will briefly introduce the drawings required in the embodiments. It should be understood that the following drawings only show some embodiments of the present application, and therefore should not be regarded as limiting the scope. For those of ordinary skill in the art, other related drawings can be obtained based on these drawings without creative efforts.

[0032] Figure 1 It is a flow chart of shale condensate gas well fluid correction in the composite drainage and production method for shale condensate gas wells provided by the embodiments of the present application;

[0033] Figure 2 It is a result diagram of shale condensate gas well fluid correction in the composite drainage and production method for shale condensate gas wells provided by the embodiments of the present application;

[0034] Figure 3 It is a flow chart of wellbore model correction in the composite drainage and production method for shale condensate gas wells provided by the embodiments of the present application;

[0035] Figure 4 It is a result diagram of wellbore model correction in the composite drainage and production method for shale condensate gas wells provided by the embodiments of the present application;

[0036] Figure 5It is a schematic structural diagram of a composite production string in the composite production method for shale condensate gas wells provided by the embodiments of the present application;

[0037] Figure 6 It is a comparison chart of production increase before and after using the composite production method for shale condensate gas wells provided by the embodiments of the present application.

[0038] In the figure: 100, tubing; 110, casing; 120, gas lift valve; 130, packer; 140, rod pump; 150, annular channel; 160, central channel. Detailed implementation manners

[0039] To make the objectives, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present application. Obviously, the described embodiments are some, but not all, of the embodiments of the present application. Usually, the components of the embodiments of the present application described and illustrated in the accompanying drawings here can be arranged and designed in various different configurations.

[0040] Therefore, the following detailed description of the embodiments of the present application provided in the accompanying drawings is not intended to limit the scope of the present application claimed, but merely represents the selected embodiments of the present application. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present application without creative efforts shall fall within the protection scope of the present application.

[0041] It should be noted that: Similar reference numerals and letters denote similar items in the following drawings. Therefore, once an item is defined in one drawing, it does not need to be further defined and explained in subsequent drawings.

[0042] In the description of the present application, it should be noted that the orientation or positional relationship indicated by the terms "center", "upper", "lower", "left", "right", "vertical", "horizontal", "inner", "outer", etc. is based on the orientation or positional relationship shown in the drawings, or the orientation or positional relationship in which the product of this application is usually placed when in use. It is only for the convenience of describing the present application and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the present application. In addition, the terms "first", "second", "third", etc. are only used for distinguishing descriptions and cannot be understood as indicating or implying relative importance.

[0043] In addition, the terms "horizontal", "vertical", "overhanging", etc. do not mean that the components are required to be absolutely horizontal or overhanging, but can be slightly inclined. For example, "horizontal" only means that its direction is more horizontal relative to "vertical", and does not mean that the structure must be completely horizontal, but can be slightly inclined.

[0044] In the description of the present application, it should also be noted that, unless otherwise clearly specified and defined, the terms "arranged", "installed", "connected", and "coupled" should be understood in a broad sense. For example, it may be a fixed connection, a detachable connection, or an integral connection; it may be a mechanical connection or an electrical connection; it may be directly connected or indirectly connected through an intermediate medium, and it may be the communication inside two components. For those of ordinary skill in the art, the specific meanings of the above terms in the present application can be understood according to specific circumstances.

[0045] In the present application, unless otherwise clearly specified and defined, the first feature being "above" or "below" the second feature may include the direct contact between the first and second features, or may include the situation where the first and second features are not in direct contact but in contact through other features therebetween. Moreover, the first feature being "above", "over", and "on top of" the second feature includes that the first feature is directly above and obliquely above the second feature, or merely indicates that the horizontal height of the first feature is higher than that of the second feature. The first feature being "below", "beneath", and "underneath" the second feature includes that the first feature is directly below and obliquely below the second feature, or merely indicates that the horizontal height of the first feature is lower than that of the second feature.

[0046] The features and performance of the composite production method for shale condensate gas wells of the present application will be further described in detail below in conjunction with embodiments.

[0047] As Figure 1 、 Figure 2 、 Figure 3 、 Figure 4 、 Figure 5 shown, the embodiments of the present application provide a composite production method for shale condensate gas wells, including the following steps:

[0048] Step 1: Establish a reservoir component model, perform component separation through downhole fluid sampling data, and obtain the numerical values of each fluid component and its molar mass of the shale condensate gas well as shown in Table 1 below;

[0049] Table 1 Fluid Component Data of Shale Condensate Gas Wells

[0050]

[0051]

[0052] Step 2: Correct the critical pressure, critical temperature, OMEGA A, and OMEGA B data in the component data in Table 1 above by fitting the constant volume expansion experiment and constant mass compression experiment data to obtain corrected fluid component data and improve the accuracy of the component model;

[0053] Step 3: Generate a component phase diagram using the corrected fluid component data, and determine the intersection pressure between the temperature, pressure in the reservoir and the corresponding isovolume line through the component phase diagram;

[0054] Step 4: Establish a vertical wellbore flow model to obtain a pressure gradient formula; the pressure gradient formula for the vertical wellbore flow model is:

[0055]

[0056] where, ρ L is the liquid phase density; H L is the liquid holdup, which is the volume fraction of the liquid phase in the flowing gas-liquid mixture, in decimals; ρ g is the gas phase density; θ is the angle between the pipeline and the horizontal direction; λ is the flow resistance coefficient; G is the mass flow rate of the mixture; v is the average flow velocity of the mixture; D is the inner diameter of the pipe; A is the flow cross-sectional area of the pipe; v sg is the apparent gas flow velocity;

[0057] The correlation formula for the inclination correction coefficient regressed according to the experimental results is:

[0058]

[0059] where, ψ is the inclination correction coefficient, dimensionless; the coefficient C is the non-slip liquid holdup, in percentage.

[0060] Step 5: Verify the pressure gradient formula obtained from the vertical wellbore flow model based on the actual production data to obtain the vertical flow parameters with the best fitting degree; when verifying, add the influence of the phase change of the condensate gas fluid with temperature as the wellbore constraint condition: the verification includes the following steps:

[0061] S1. Determine the wellbore boundary conditions; the boundary conditions include the reservoir temperature, wellbore pressure, pressure gradient, temperature gradient, wellhead pressure, and wellhead temperature.

[0062] S2. Use the actual production data to correct the pressure gradient formula of the vertical wellbore flow model;

[0063] S3. Compare the temperature and pressure of each well section with the actual values;

[0064] S4. If the calculated pressures of each well section are within a reasonable error range from the actual values, the correction is completed; if the two are not within a reasonable error range, adjust the correlation formula of the flow pressure gradient, and repeat steps S2, S3, and S4 until the error is controlled within a reasonable range.

[0065] Step 6: Use the composite production string to conduct production with the vertical flow parameters having the best fit; the composite production string includes a tubing 100, a casing 110 sleeved outside the tubing 100, a gas lift valve 120 connected to the tubing 100, a packer 130, and a rod pump 140. An annular channel 150 for gas flow is formed between the tubing 100 and the casing 110. The packer 130 is used to seal the annular channel 150. The gas lift valve 120 is used to allow the gas injected into the annular channel 150 to enter the tubing 100. The rod pump 140 is used to lift the liquid and discharge it to the ground through the central channel 160 of the tubing 100. The rod pump 140, the gas lift valve 120, and the packer 130 are arranged in sequence from top to bottom. The rod pump 140 is provided with a sand control structure. The opening and closing time of the gas lift valve 120 is determined by the intersection pressure of the isochore corresponding to the temperature, pressure in the reservoir determined by the component phase diagram.

[0066] Use the above composite production method for shale condensate gas wells to conduct integrated production simulation calculations and production analysis on horizontal wells in a newly put into production block of a certain shale gas field for several years to accurately predict production changes. The prediction results are as Figure 6 shown.

[0067] The composite production method for shale condensate gas wells provided by the embodiments of the present application considers the influence of the phase state change of the shale condensate gas reservoir on production through multiple factors, uses the isochore of the fluid phase diagram to determine the start-up time of the composite production process, and realizes joint solution in terms of data through the phase state change of underground fluids to the temperature drop and pressure drop in the wellbore, more truly reflecting the production characteristics of the shale condensate gas reservoir. The composite production method for shale condensate gas wells provided by the embodiments of the present application combines the wellbore model, the well stream component model, and the composite production process model, uses a multi-model coupling method to establish the continuity between reservoir engineering and oil production engineering, conducts multi-faceted coupling with the production index of the oil and gas reservoir and the production index in the wellbore as the object, provides an accuracy guarantee for actual operation, selects a rod pump and a gas lift process to cooperate to achieve the final production effect, realizes the continuous production demand of shale condensate gas wells, and also adapts to different production stages. The method has a high accuracy rate, a clever structure, and a simple construction process.

[0068] The composite production method for shale condensate gas wells provided by the embodiments of the present application combines the fluid component model with the wellbore vertical flow model and the composite production model, uses actual production data as the accuracy index, determines an accurate production model through fitting and iteration, and then uses the pressure corresponding to the fluid isochore as the start-up condition of the composite production process, enabling the shale condensate gas well to realize the intervention of the full-cycle and full-stage production process, and being able to achieve full-stage production increase more accurately and quickly, thereby improving the goal of efficient production increase of the oil and gas reservoir.

[0069] The embodiments described above are some, but not all, of the embodiments of this application. The detailed description of the embodiments of this application is not intended to limit the scope of this application that is claimed, but merely represents selected embodiments of this application. All other embodiments obtained by those of ordinary skill in the art based on the embodiments in this application without making any creative efforts shall fall within the scope of protection of this application.

Claims

1. A composite production method for shale condensate gas wells, characterized in that, It includes the following steps: Collect the fluid component data of the shale condensate gas well for correction to obtain the corrected fluid component data; Generate a component phase diagram using the corrected fluid component data, and determine the intersection pressure of the temperature, pressure in the reservoir and the corresponding isovolume line through the component phase diagram; Establish a vertical wellbore flow model to obtain a pressure gradient formula; Verify the pressure gradient formula obtained from the vertical wellbore flow model based on the actual production data to obtain the vertical flow parameters with the best fitting degree: Use a composite production string to carry out production with the vertical flow parameters with the best fitting degree.

2. The composite production method for shale condensate gas wells according to claim 1, wherein When correcting the fluid component data of the shale condensate gas well, correct the critical pressure, critical temperature, OMEGA A, and OMEGA B data in the component data by fitting the constant volume expansion experiment and constant mass compression experiment data.

3. The composite production reduction method for shale condensate gas wells according to claim 1, wherein The pressure gradient formula of the vertical wellbore flow model is: where ρ L is the liquid-phase density; H L is the liquid holdup, which is the volume fraction of the liquid phase in the flowing gas-liquid mixture, in decimals; ρ g is the gas-phase density; θ is the angle between the pipeline and the horizontal direction; λ is the flow resistance coefficient; G is the mass flow rate of the mixture; v is the average flow velocity of the mixture; D is the inner diameter of the pipe; A is the flow cross-sectional area of the pipe; v sg is the superficial gas velocity; The correlation formula of the inclination correction coefficient regressed according to the experimental results is: Among them, ψ is the inclination correction coefficient, dimensionless; the coefficient C is the non-slip liquid holdup, in percentage.

4. The composite production method for shale condensate gas wells according to claim 1, characterized in that, Verifying the pressure gradient formula obtained from the vertical wellbore flow model based on the actual production data includes the following steps: S1. Determine the wellbore boundary conditions; S2. Correct the pressure gradient formula of the vertical wellbore flow model using the actual production data; S3. Compare the temperature, pressure of each well section with the actual values; S4. If the calculated pressure of each well section is within the reasonable error range compared with the actual value, the correction is completed; if the two are not within the reasonable error range, adjust the flow pressure gradient correlation formula, and repeat steps S2, S3, and S4 until the error is controlled within the reasonable range.

5. The composite production method for shale condensate gas wells according to claim 4, characterized in that, The wellbore boundary conditions include reservoir temperature, wellbore pressure, pressure gradient, temperature gradient, wellhead pressure, and wellhead temperature.

6. The composite production method for shale condensate gas wells according to claim 4, wherein, When verifying the pressure gradient formula obtained from the vertical wellbore flow model based on the actual production data, add the influence of the phase change of the condensate gas fluid with temperature as a wellbore constraint condition.

7. The composite production reduction method for shale condensate gas wells according to claim 1, characterized in that The composite production string includes a tubing string, a casing sleeved outside the tubing string, a gas lift valve connected to the tubing string, a packer, and a rod pump. An annular channel for gas flow is formed between the tubing string and the casing. The packer is used to seal the annular channel. The gas lift valve is used to make the gas injected into the annular channel enter the tubing string. The rod pump is used to lift the liquid and discharge it to the ground from the tubing string.

8. The composite production method for shale condensate gas wells according to claim 7, characterized in that, The rod pump, the gas lift valve, and the packer are arranged in sequence from top to bottom.

9. The composite production method for shale condensate gas wells according to claim 7, characterized in that, The rod pump is provided with a sand control structure.

10. The composite production method for shale condensate gas wells according to claim 7, characterized in that, The opening and closing time of the gas lift valve is determined by the intersection pressure of the temperature, pressure in the reservoir and the corresponding isovolume line determined by the component phase diagram.

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