A high-yield horizontal well gas lift assisted drainage optimization method

Abstract

This invention discloses an optimized method for gas lift-assisted drainage in high-water-yield horizontal wells, belonging to the field of oil and gas field development technology. It aims to address the problems of unclear pressure distribution in the tubing and annulus wellbore of high-water-yield gas wells, limited optimization of gas lift and annulus drainage synergy, and a lack of systematic optimization of the production regime for the drainage channel. The method first collects wellbore structure and production data of the target gas well, introduces dimensionless numbers in the form of Froude numbers to characterize the operating conditions of high-pressure gas wells, and establishes tubing and annulus wellbore pressure drop models for high-water-yield gas wells based on experimental test data. It then introduces nodal analysis to compare tubing and annulus production methods, selects the production channel that can effectively reduce bottom hole flowing pressure, and determines the reasonable gas injection rate based on the TPR curve characteristics under tubing or annulus production conditions. This method requires no tubing string replacement, is simple to operate, provides accurate pressure calculations, and has strong adaptability, providing theoretical and technical support for the optimization of high-water-yield gas well processes.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to an optimized method for gas lift-assisted drainage in high-yield horizontal wells. Background Technology

[0002] High-yield gas wells, after entering the mid-to-late stages of production, generally face problems such as formation energy depletion and severe fluid accumulation in the wellbore. This leads to increased bottomhole back pressure, obstructed gas flow, and a significant reduction in production, severely impacting the high efficiency of gas well production. Gas lift, as a mainstream drainage aid, effectively lifts accumulated fluid by injecting gas into the wellbore to replenish energy, and is suitable for gas wells of different depths and production scales. Determining the gas injection rate is crucial to improving gas lift efficiency. Insufficient gas injection results in insufficient lift energy, making it difficult to remove accumulated fluid, while excessive injection increases gas-liquid mixing friction, negatively impacting gas well production and wasting gas lift resources.

[0003] In the nodal system analysis method, the IPR curve is the formation inflow dynamic curve, describing the relationship between the gas reservoir's ability to supply gas to the wellbore and the bottom hole flowing pressure, reflecting the formation's production capacity characteristics. The TPR curve is the tubing flow dynamic curve, reflecting the relationship between the bottom hole flowing pressure and gas volume when gas flows in the wellbore, embodying the resistance characteristics of tubing flow. By analyzing these two curves and their intersection, production dynamics can be explained and gas injection volume optimized. The plotting of the TPR curve is closely related to the calculation of wellbore pressure drop. However, for high-yield water-producing gas wells, conventional wellbore pressure drop models often fail to meet the accuracy requirements of the planned gas lift regime. Low-pressure experimental data is needed to characterize the high-pressure flow state of the gas well, and through experimental simulation, a wellbore pressure drop model that can adapt to high-yield water-producing conditions can be established. In addition, high-yield water-producing gas wells usually use tubing production during the production process. Due to its small flow area, the flow friction is large under high gas-liquid flow velocities, which easily increases the bottom hole flowing pressure and reduces gas well production. Annular production, with its larger flow area and lower friction, provides a new approach for optimizing the production of high-yield water-producing gas wells.

[0004] Invention patent (CN120145937B) divides the wellbore into two parts: a liquid-accumulating section and a non-liquid-accumulating section, and establishes a wellbore pressure drop model that considers the influence of liquid accumulation. However, it does not consider the influence of pipe diameter on liquid holdup, and the method for field testing of liquid holdup is still unclear. Invention patent (CN117738624A) determines the optimal gas lift injection rate by coupling the optimal gas injection rate with the minimum energy loss in the wellbore, the minimum gas injection rate with critical liquid carrying capacity, and the minimum gas injection rate coupled with the reservoir. However, it lacks specificity for pressure drop calculation and is difficult to adapt to high water production conditions. Invention patent (CN120211694A) uses field operating parameters to measure liquid volume, gas volume, and injection time. The relationship judgment and the relationship judgment between liquid volume, gas volume and start-up pressure are used to obtain the injection working gas volume applicable to the current working conditions. Its focus is on calculating the gas injection volume when the gas well is started, but it does not involve the optimization calculation of the gas injection volume of the gas well. The invention patent (CN120373534A) uses the Gray model to calculate the wellbore pressure gradient and obtains the outflow dynamic curve of bottom hole flowing pressure and production volume. The nozzle size is dynamically optimized through the node system analysis method. Therefore, for the gas lift production process of high water production gas wells, the wellbore pressure distribution in the tubing annulus is still unclear, there are few methods for co-optimization of gas lift and annulus drainage, and there is a lack of systematic optimization methods for the production system of different drainage channels.

[0005] Therefore, this invention provides an optimized method for gas lift-assisted drainage in high-yield horizontal wells. It utilizes dimensionless numbers in the form of Froude numbers to characterize the operating conditions of high-pressure gas wells. Based on experimental test data, it establishes a wellbore pressure drop model for tubing and annulus in high-yield gas wells, introduces node analysis, compares tubing and annulus production methods, selects a production channel that effectively reduces bottom hole flowing pressure, and then determines a reasonable gas injection rate based on the TPR curve characteristics under tubing or annulus production conditions. This provides theoretical and technical support for the process optimization of high-yield gas wells. Summary of the Invention

[0006] This invention provides an optimized method for gas lift-assisted drainage in high-yield horizontal wells. By introducing the Froude number as a dimensionless similarity criterion to characterize the operating conditions of high-pressure gas wells, an experimentally based pressure drop model for tubing and annulus wellbores is established. IPR and TPR curves are plotted, and the two production methods of tubing and annulus production are compared to select a production channel that can effectively reduce bottom hole flowing pressure. Then, based on the characteristics of the TPR curve under tubing or annulus production conditions, a reasonable gas injection rate is determined, providing theoretical and technical support for the process optimization of high-yield gas wells.

[0007] To achieve the above objectives, the specific steps of the high-yield horizontal well gas lift-assisted drainage optimization method described in this invention are as follows:

[0008] Step 1: Collect target gas well structure and production data, including well inclination angle, tubing inner diameter, tubing outer diameter, casing inner diameter, wellhead oil pressure, casing pressure, temperature, gas production, liquid production, gas phase density, liquid phase density, and pressure measurement data.

[0009] Step 2: Based on the production data collected in Step 1, preliminarily plot the IPR curve and TPR curve;

[0010] The calculation of the IPR curve uses the empirical formula for gas well productivity commonly used in engineering:

[0011] (1)

[0012] In the formula, Q SC For gas production, m 3 / d; J The gas production index, m 3 / (d×MPa 2 ); p r The mean formation pressure is expressed in MPa. p wf The bottom hole flowing pressure is in MPa.

[0013] Specifically, based on the pressure measurement data collected in step 1, the formation pressure is estimated. p r and production capacity index J By sensing the bottom hole flowing pressure under different gas production rates, a preliminary formation inflow curve relating bottom hole flowing pressure to gas production rate was obtained.

[0014] The plotting of the TPR curve requires the use of a wellbore pressure drop model, and the key to calculating the wellbore pressure drop is the calculation of the wellbore liquid holdup.

[0015] Specifically, a tubing holdup model for high-yield water-gas wells was established. This model is based on the Mukehejee-Brill holdup model and uses the Froude number as a dimensionless criterion to more accurately achieve flow similarity between the experiment and high-pressure gas wells. It also considers the range of gas production and liquid production parameters for high-yield water-gas wells. Experimental tests were conducted, and the tubing holdup formula was obtained after fitting and correcting the experimental results. The formula is as follows:

[0016] (2)

[0017] In the formula, H L tu This represents the tubing holdup, which is dimensionless. θ The inclination angle is °; N LV The apparent flow rate of the dimensionless liquid phase is dimensionless. N GVThe apparent velocity of the gas phase is dimensionless and dimensionless. t 1. t 2. t 3. t 4. t 5 represents the fitting coefficient for the simulation experiment of high-water-yield gas well tubing production;

[0018] Furthermore, experimental data show a clear logarithmic relationship between annular flow liquid holdup and dimensionless liquid holdup. The formula for calculating annular liquid holdup, obtained from experimental test results, is as follows:

[0019] (3)

[0020] In the formula, H L an The annular liquid holdup is dimensionless. N λ , where is the dimensionless, slip-free liquid holdup, and is dimensionless; a1, a2, a3, a4, a5, a7, a8, and a9 are the fitting coefficients of the simulation experiment of annular production in high-water-yield gas wells;

[0021] Among them, the dimensionless gas and liquid apparent velocities and the dimensionless no-slip holdup take into account the effects of density, flow velocity, and pipe diameter, so that the holdup calculation results can characterize high-pressure flow conditions and show good applicability in pipes of different sizes. The calculation formula is as follows:

[0022] (4)

[0023] (5)

[0024] (6)

[0025] In the formula, ρ L The density is in the gas phase, kg / m³ 3 ; ρ G The density of the liquid phase is kg / m³. 3 ; v SG The apparent airflow velocity is in m / s; v SL The apparent fluid velocity is given in m / s. D The hydraulic diameter is in meters (m). g The acceleration due to gravity is expressed in m / s².

[0026] After determining the tubing and annular holdup models, substituting them into the gas-liquid two-phase pipe flow pressure drop formula yields the tubing and annular pressure drop models, allowing for the further plotting of the TPR curve. The gas-liquid two-phase pipe flow pressure drop formula is as follows:

[0027] (7)

[0028] (8)

[0029] In the formula, dp Pressure, Pa; ρ m For mixed density, kg / m³ 3 ; f m The coefficient of friction is a mixed friction factor, dimensionless; v m The velocity is the gas-liquid mixing velocity, in m / s; dz H is the distance along the central axis of the wellbore, in meters (m). L This is the liquid holdup, dimensionless;

[0030] After clarifying the pressure drop model, based on the well structure and oil pressure, casing pressure, gas production, and fluid production data collected in step 1, the pressure drop model of the tubing or annulus production wellbore can be used to calculate the pressure value at a distance dz from the wellhead, starting from the wellhead oil pressure or casing pressure. Then, based on this pressure value, the pressure value at the next dz distance position can be calculated. The calculation is iterated step by step until the bottom hole flowing pressure is obtained. By sensing the gas production, the bottom hole flowing pressure under different gas production conditions can be obtained, and finally the TPR curve is completed.

[0031] Step 3: Adjust the formation pressure based on the intersection of the IPR curve and the TPR curve from Step 2. p r and production capacity index J This makes the gas production at the intersection of the IPR curve and the TPR curve close to the gas production of the target gas well.

[0032] Specifically, by adjusting formation pressure p r and production capacity index J This ensures that the gas production at the intersection of the IPR curve and the TPR curve drawn in step 2 deviates from the actual gas production within ±2000 m³ / d, thus making the obtained IPR curve more representative of the formation's supply capacity.

[0033] Step 4: Based on the data collected in Step 1 and the annular production wellbore pressure drop model established in Step 2, plot the TPR curve under annular production conditions. Compare the gas production corresponding to the intersection of the tubing production TPR curve and the annular production TPR curve with the IPR curve obtained in Step 3, and select the production channel that can effectively reduce bottom hole flowing pressure as the recommended production channel.

[0034] Step 5: Determine the recommended gas injection rate for the target well based on the characteristics of the TPR curve of the tubing or annulus production.

[0035] Step 5.1: If the recommended production method is tubing production, then calculate the gas production Q based on the lowest point of the TPR curve for tubing production. min Gas production Q at the intersection with IPR-TPR tu The difference determines the injection volume, and the recommended injection volume is Q. min -Q tu ;

[0036] Step 5.2: If the recommended production method is annular production, then the gas production rate Q at the recommended injection point is determined based on the annular production TPR curve. T Gas production Q at the intersection with IPR-TPR an The difference determines the injection volume, and the recommended injection volume is Q. T -Q an ;

[0037] Among them, the recommended gas injection point for annular production is selected as the point on the annular production TPR curve where the gas production increases by 10,000 cubic meters per day when the flowing pressure decreases by 1 MPa. This point can be adaptively adjusted according to the gas well production characteristics and equipment process conditions.

[0038] This is because the lowest point of the annular production TPR curve corresponds to a large gas production volume, and the lowest point of the flowing pressure can no longer be used as the basis for determining the gas injection volume of the annular production. Therefore, it is stipulated that the point where the production increases by 10,000 cubic meters per 1 MPa decrease in flowing pressure is the recommended gas injection point, which is used as the gas injection judgment boundary. When the production is greater than this point, it is considered that increasing production by gas injection is no longer economical. Attached Figure Description

[0039] Figure 1 A technical roadmap for an optimized gas lift-assisted drainage method for high-yield horizontal wells;

[0040] Figure 2 A schematic diagram illustrating the determination of gas injection volume during annular production;

[0041] Figure 3 Schematic diagram for optimizing production channels and determining the gas injection volume during tubing production; Detailed Implementation

[0042] To make the objectives and calculation process of this invention clearer, the invention will be further described in detail below with reference to the accompanying drawings, so as to highlight the advantages of this invention.

[0043] like Figure 1 As shown, Figure 1 This is a technical roadmap for the present invention. First, collect the target gas well's wellbore structure and production data, including well inclination angle, tubing inner diameter, tubing outer diameter, casing inner diameter, wellhead oil pressure, casing pressure, temperature, gas production, liquid production, gas phase density, liquid phase density, pressure measurement data, etc.; based on the collected production data, preliminarily plot the IPR curve and TPR curve;

[0044] The calculation of the IPR curve uses the empirical formula for gas well productivity commonly used in engineering:

[0045] In the formula, Q SC For gas production, m 3 / d; J The gas production index, m 3 / (d×MPa 2 ); p r The mean formation pressure is expressed in MPa. p wf The bottom hole flowing pressure is in MPa.

[0046] Estimate formation pressure based on pressure measurement data. p r and production capacity index J By sensing the bottom hole flowing pressure under different gas production rates, a preliminary formation inflow curve relating bottom hole flowing pressure to gas production rate was obtained.

[0047] The plotting of the TPR curve requires the use of a wellbore pressure drop model, and the key to calculating the wellbore pressure drop is the calculation of the wellbore liquid holdup.

[0048] The formula for calculating tubing holdup is:

[0049] In the formula, H L tu This represents the tubing holdup, which is dimensionless. θ The inclination angle is °; N LV The apparent flow rate of the dimensionless liquid phase is dimensionless. N GV The apparent velocity of the gas phase is dimensionless and dimensionless. t 1 , t 2 , t 3 , t 4 , t 5 ;

[0050] The formula for calculating the annular liquid holdup is:

[0051] In the formula, H L an The annular liquid holdup is dimensionless. N λ , where is the dimensionless, slip-free liquid holdup, and is dimensionless; a1, a2, a3, a4, a5, a7, a8, and a9 are the fitting coefficients of the simulation experiment of annular production in high-water-yield gas wells;

[0052] Among them, the dimensionless gas and liquid apparent velocities and the dimensionless no-slip holdup take into account the effects of density, flow velocity, and pipe diameter, so that the holdup calculation results can characterize high-pressure flow conditions and show good applicability in pipes of different sizes. The calculation formula is as follows: , , In the formula, ρ L The density is in the gas phase, kg / m³ 3 ; ρ G The density of the liquid phase is kg / m³. 3 ; v SG The apparent airflow velocity is in m / s; v SL The apparent fluid velocity is given in m / s. D The hydraulic diameter is in meters (m). g The acceleration due to gravity is expressed in m / s².

[0053] After determining the tubing and annular holdup models, substituting them into the gas-liquid two-phase pipe flow pressure drop formula yields the tubing and annular pressure drop models, allowing for the further plotting of the TPR curve. The gas-liquid two-phase pipe flow pressure drop formula is as follows:

[0054] , In the formula, dp Pressure, Pa; ρ m For mixed density, kg / m³ 3 ; f m The coefficient of friction is a mixed friction factor, dimensionless; v m The velocity is the gas-liquid mixing velocity, in m / s; dz The distance along the central axis of the wellbore is in meters (m). H L This is the liquid holdup, dimensionless;

[0055] Furthermore, by adjusting formation pressure p r and production capacity index J This ensures that the gas production at the intersection of the IPR curve and the TPR curve deviates from the actual gas production within ±2000 m³ / d, thus making the obtained IPR curve more representative of the formation's supply capacity.

[0056] Plot the TPR curve under annular production conditions, compare the gas production corresponding to the intersection of the tubing production TPR curve and the annular production TPR curve with the IPR curve obtained in step 3, and select the production channel that can effectively reduce bottom hole flowing pressure as the recommended production channel; a lower bottom hole flowing pressure corresponds to a larger production pressure difference from the formation to the bottom of the well, which is more conducive to the flow of formation fluid into the wellbore.

[0057] Furthermore, if the recommended production method is pipeline production, then the gas production Q at the lowest point of the pipeline production TPR curve should be used. min Gas production Q at the intersection of IPR and TPR tu The difference determines the injection volume, and the recommended injection volume is Q. min -Q tu If the recommended production method is annular production, then the recommended gas production rate Q at the injection point is based on the annular production TPR curve. T Gas production Q at the intersection with IPR-TPR an The difference determines the injection volume, and the recommended injection volume is Q. T -Q an .

[0058] like Figure 2 As shown, since the lowest point of the annular TPR curve corresponds to a large gas production, the lowest point of the flowing pressure can no longer be used as the basis for determining the gas injection volume of the annular production. Therefore, it is stipulated that the point where the production increases by 10,000 cubic meters per 1 MPa decrease in flowing pressure is the recommended gas injection point, which is used as the gas injection judgment boundary. When the production exceeds this point, it is considered that increasing production by gas injection is no longer economical.

[0059] Example 1: Well X1 is a high-yield gas well in Block X of the Sichuan Basin. The well has a casing inner diameter of 139.7 mm, an outer diameter of 60 mm, and an inner diameter of 50 mm. It uses tubing for production. As of June 2024, its average daily gas production was 16,000 cubic meters / day, daily water production was 30 cubic meters / day, oil pressure was 2.3 MPa, and casing pressure was 10.1 MPa.

[0060] Based on the production data of the block corresponding to the well, the Froude number was introduced as a similarity criterion to calculate the production conditions of the block. A gas-water two-phase pipe flow experiment was designed and carried out in a targeted manner. The liquid holdup formula was fitted with the experimental data to establish a pressure drop model for the tubing and annulus wellbore.

[0061] Two-phase flow experiments were conducted on the production data of high-yield water-gas wells in Block X. Based on the experimental data, coefficients in the formulas for tubing and annular liquid holdup were fitted to obtain a wellbore pressure drop calculation model for tubing and annulus. The values ​​of the fitting coefficients are as follows: t 1 = -2.05 t 2 = 0.15 t 3 = -0.14, t 4 = 0.10, t 5 = 0.15;a 1 = 0.33 a 2 = 0.04 a 3 = 0.5 a 4 = -0.04 a 5 = 0.4 a 6 = 0.51 a 7 = 0.74 a 8 = 0.29 a 9 = 1.06;

[0062] like Figure 3 As shown, the IPR curve corresponding to this block is plotted according to steps 2-3. Simultaneously, the TPR curves for tubing and annulus production are calculated and plotted using the tubing and annulus wellbore pressure drop calculation model. The IPR curve intersects the tubing and annulus production TPR curves at two points. Comparing the bottomhole flowing pressure values ​​corresponding to the two intersection points, the bottomhole flowing pressure for tubing production is lower than that for annulus production; therefore, tubing production is selected, meaning there is no need to change the production method. The lowest point of the tubing production TPR curve in the figure corresponds to the gas production rate Q. min =2.2×10 4 m 3 / d, the gas production Q corresponds to the intersection of the TPR curve and the IPR curve in tubing production. tu =1.6×10 4 m 3 / d, therefore the recommended gas injection rate for this well at this time is Q. min -Q tu =6000m 3 / d.

[0063] Compared with the shortcomings and deficiencies of existing technologies, the present invention has the following beneficial effects:

[0064] (1) The gas lift-assisted exhaust optimization method proposed in this invention includes the selection of the production channel and the determination of the gas injection volume, the optimization system is more complete, and the process does not require the replacement of the tubing column, and the process is simple and easy to operate;

[0065] (2) Establish a calculation model for tubing and annulus liquid holdup for high-yield water and gas wells, and provide a more accurate and adaptable calculation method for pressure calculation of high-yield water and gas wells;

[0066] (3) A method for determining the gas injection volume was designed for tubular production and annular production, providing specific implementation standards for the selection of production channels.

[0067] Obviously, the above description is only an implementation idea of ​​the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for optimizing production and determining gas injection volume in high water-cut gas wells, characterized in that, Includes the following steps: Step 1: Collect the target gas well's wellbore structure and production data, including well inclination angle, tubing inner diameter, tubing outer diameter, casing inner diameter, wellhead oil pressure, casing pressure, temperature, gas production, liquid production, gas phase density, liquid phase density, and pressure measurement data. Step 2: Based on the production data collected in Step 1, preliminarily plot the IPR curve and TPR curve; The plotting of the TPR curve requires a wellbore pressure drop model, and the key to calculating the wellbore pressure drop is the calculation of the wellbore fluid holdup; the formula for calculating the tubing fluid holdup is: In the formula, H L tu This represents the tubing holdup, which is dimensionless. θ The inclination angle is °; N LV The apparent flow rate of the dimensionless liquid phase is dimensionless. N GV The apparent velocity of the gas phase is dimensionless and dimensionless. t 1. t 2. t 3. t 4. t 5 represents the fitting coefficient for the simulation experiment of high-water-yield gas well tubing production; The formula for calculating the annular liquid holdup is: In the formula, H L an The annular liquid holdup is dimensionless. N λ Dimensionless, slip-free liquid holding capacity, dimensionless; a 1. a 2. a 3. a 4. a 5. a 7. a 8. a 9 represents the fitting coefficient for the simulation experiment of high-yield water-producing gas well annulus production; The formulas for calculating the dimensionless apparent flow velocities of the gas and liquid phases and the dimensionless non-slip liquid holdup are as follows: , , In the formula, ρ L The density is in the gas phase, kg / m³ 3 ; ρ G The density of the liquid phase is kg / m³. 3 ; v SG The apparent airflow velocity is in m / s; v SL The apparent fluid velocity is given in m / s. D The hydraulic diameter is in meters (m). g The acceleration due to gravity is expressed in m / s². After determining the tubing and annular holdup models, substituting them into the gas-liquid two-phase pipe flow pressure drop formula yields the tubing and annular pressure drop models, allowing for the further plotting of the TPR curve. The gas-liquid two-phase pipe flow pressure drop formula is as follows: , In the formula, dp Pressure, Pa; ρ m For mixed density, kg / m³ 3 ; f m The coefficient of friction is a mixed friction factor, dimensionless; v m The velocity is the gas-liquid mixing velocity, in m / s; dz The distance along the central axis of the wellbore is in meters (m). H L This is the liquid holdup, dimensionless; Step 3: Adjust the formation pressure based on the intersection of the IPR curve and the TPR curve from Step 2. p r and production capacity index J This makes the gas production at the intersection of the IPR curve and the TPR curve close to the gas production of the target gas well. Step 4: Based on the data collected in Step 1 and the annular production wellbore pressure drop model established in Step 2, plot the TPR curve under annular production conditions. Compare the gas production corresponding to the intersection of the tubing production TPR curve and the annular production TPR curve with the IPR curve obtained in Step 3, and select the production channel that can effectively reduce bottom hole flowing pressure as the recommended production channel. Step 5: Determine the recommended gas injection rate for the target well based on the characteristics of the TPR curve of the tubing or annulus production. Step 5.1: If the recommended production method is tubing production, then calculate the gas production Q based on the lowest point of the TPR curve for tubing production. min Gas production Q at the intersection with IPR-TPR tu The difference determines the injection volume, and the recommended injection volume is Q. min -Q tu ; Step 5.2: If the recommended production method is annular production, then the gas production rate Q at the recommended injection point is determined based on the annular production TPR curve. T Gas production Q at the intersection with IPR-TPR an The difference determines the injection volume, and the recommended injection volume is Q. T -Q an ; Since the lowest point of the annular production TPR curve corresponds to a large gas production volume, the lowest point of the flowing pressure can no longer be used as the basis for determining the gas injection volume of the annular production. Therefore, it is stipulated that the point where the production increases by 10,000 cubic meters per 1 MPa decrease in flowing pressure is the recommended gas injection point. This is used as the gas injection judgment boundary. When the production exceeds this point, it is considered that increasing production by gas injection is no longer economical.

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