A method and system for water drainage gas recovery

Abstract

The application provides a preferred method and system for drainage gas recovery, and belongs to the technical field of gas recovery in oil and gas fields.The method determines whether to select a non-energy-supplement drainage gas recovery process according to wellhead pressure, external transmission pressure and full wellbore critical liquid carrying; if the non-energy-supplement drainage gas recovery process is selected, the non-energy-supplement drainage gas recovery process is initially selected according to applicability, and the pressure applicable range and the liquid carrying applicable range of each non-energy-supplement drainage gas recovery process are determined according to the inflow performance curve of the gas well and the working curve of each non-energy-supplement drainage gas recovery process, and finally the preferred non-energy-supplement drainage gas recovery process is obtained according to the pressure applicable range and the liquid carrying applicable range of each non-energy-supplement drainage gas recovery process. The application overcomes the deficiency that the current drainage gas recovery process selection method considers insufficient factors and cannot quantitatively optimize, improves the effectiveness of the drainage gas recovery process, and effectively guides the selection of the drainage gas recovery process and the intervention time of the process for the gas well.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil and gas field gas production, and particularly relates to a drainage gas production process optimization method and system, which is suitable for quantitative optimization of drainage gas production process of water-containing gas wells. BACKGROUND

[0002] Development of water-containing gas reservoirs is of great significance to energy security. At present, many conventional and unconventional gas reservoirs have the problem of wellbore liquid loading in water-producing gas wells. For example, with the increase in the number of producing wells in Fuling shale gas field, the number of liquid loading wells also increases year by year. At present, the number of liquid loading wells is about 100, and it is urgent to select appropriate drainage gas production process to control liquid loading. However, the selection of drainage gas production process at present mainly depends on field experience method, macro control chart method and dynamic analysis chart method, and the influencing factors are not comprehensive, so that only the drainage gas production process can be selected qualitatively, and quantitative optimization of multiple drainage gas production processes cannot be realized, resulting in poor application effect.

[0003] Chinese patent publication CN110610435A discloses a drainage gas production process selection method and control system for liquid-producing natural gas wells, which comprises the following steps: in the coordinate system constituted by daily gas production and bottom hole flowing pressure, draw the inflow curve of different production stages, the tubing dynamic curve corresponding to the minimum wellhead oil pressure, the critical liquid carrying curve and the critical foam carrying curve, and constitute a dynamic analysis chart; select the related intersection points of the four types of curves, divide the chart into several intervals with different liquid carrying capacity characteristics, and determine the drainage gas production process corresponding to each interval; map the gas well production history data to the chart to determine the corresponding interval of the current production stage, and find the corresponding drainage gas production process. Although the chart method proposed in the patent application file can initially select the drainage gas production process, it only proposes a qualitative analysis chart, lacks consideration of factors, does not consider the pressure applicability and liquid carrying applicability of different drainage gas production processes, and can only initially select the drainage gas production process according to the applicability of the drainage gas production process, so that the applicable production limit of different drainage gas production processes cannot be quantitatively determined, and the optimization method for quantitatively optimizing different drainage gas production processes is not proposed, so that the reliability is low.

[0004] Chinese patent publication CN106570273B discloses a method for establishing a three-parameter gas well drainage gas production process optimization model, which first collects production parameters of water-producing gas wells in a gas field block; then calculates the critical liquid carrying flow rate of natural gas under different daily gas production and water-gas ratio for a given tubing diameter at different well depths, draws the natural gas critical liquid carrying flow rate surface a, b of the maximum and minimum tubing diameter on the three-dimensional model of daily gas production, water-gas ratio and well depth, and draws the liquid production of 95m 3The three-parameter three-dimensional plate method proposed by the method can be used to preliminarily select the drainage gas production process, but it lacks considerations and only considers the production and well depth parameters. It can only preliminarily select the process qualitatively based on the applicability of the drainage gas production process, but cannot quantitatively determine the applicable limits of different drainage gas production processes, and does not propose an optimization method for quantitatively selecting different drainage gas production processes.

[0005] The current method for optimizing drainage gas production technology is still imperfect, and there is a lack of a quantitative boundary determination and process optimization method for drainage gas production technology. Summary of the Invention

[0006] The purpose of the present invention is to solve the difficulties existing in the above-mentioned prior art and provide a method and system for optimizing the drainage gas production process, which comprehensively considers the production limit of applicable pressure (i.e., pressure applicable limit) and the production limit of applicable liquid carrying (i.e., liquid carrying applicable limit), quantitatively determines the applicable limit of the drainage gas production process, quantitatively optimizes the drainage gas production process, effectively guides the selection of drainage gas production process and the timing of process intervention in on-site gas wells, improves the effectiveness of the drainage gas production process, and realizes long-term stable production of water-containing gas wells.

[0007] The present invention is achieved through the following technical solutions:

[0008] A first aspect of the present invention provides a method for optimizing a drainage gas production process, wherein the method determines whether to use a drainage gas production process without energy replenishment based on the wellhead pressure, the external transmission pressure, and the critical liquid carrying capacity of the entire wellbore; if a drainage gas production process without energy replenishment is used, the drainage gas production process without energy replenishment is preliminarily selected based on its applicability, and the pressure applicable limit and liquid carrying capacity applicable limit of each drainage gas production process without energy replenishment are determined based on the gas well inflow performance curve and the working curve of each drainage gas production process without energy replenishment; finally, the preferred drainage gas production process without energy replenishment is obtained based on the pressure applicable limit and liquid carrying capacity applicable limit of each drainage gas production process without energy replenishment.

[0009] A further improvement of the present invention is that the method comprises:

[0010] Step 1: Collect field parameters of water-bearing gas wells;

[0011] Step 2: Determine whether the wellhead oil pressure is greater than or equal to the wellhead external transmission pressure. If yes, go to step 3; if not, go to step 10;

[0012] Step 3: Determine whether the gas phase flow rate under standard conditions is greater than or equal to the maximum critical liquid carrying flow rate of the entire wellbore. If so, the gas well can produce normally and does not need to adopt the water drainage gas recovery process. If not, preliminarily select n non-energy-replenishing water drainage gas recovery processes based on their applicability.

[0013] Step 4: Calculate the gas well inflow performance curve;

[0014] Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas recovery processes;

[0015] Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0016] Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0017] Step 8: Determine the applicable limits of liquid carrying for the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0018] Step 9: Quantitatively select and optimize the drainage and gas recovery process;

[0019] Step 10: Select the energy replenishment and drainage gas production process.

[0020] A further improvement of the present invention is that the field parameters of the water-bearing gas well include: flow pressure test data, static pressure test data, wellhead oil pressure P t , wellhead casing pressure P c , wellhead output pressure P tr , wellhead temperature T t , gas phase flow rate Q under standard conditions g , liquid flow rate Q l , gas phase relative density γ g , liquid density ρ l , surface tension σ, inner diameter of production string D, depth of production string H t , wellbore trajectory data.

[0021] A further improvement of the present invention is that the maximum critical liquid carrying rate in step 3 is obtained as follows:

[0022] Calculate the critical liquid carrying velocity v at different well depths using formula (1) c :

[0023]

[0024] Calculate the critical liquid flow rate Q at different well depths using formula (2) c :

[0025]

[0026] Calculate the maximum critical liquid flow rate Q of the entire wellbore using formula (3) cmax :

[0027]

[0028] Where, v c is the critical liquid carrying velocity, m / s; σ is the surface tension, N / m; Q l is the liquid phase flow rate, m 3 / s;ρ l is the liquid density, kg / m 3 ρ g is the gas phase density, kg / m 3 ; D is the inner diameter of the production string, m; R is the build rate, ° / 30m; Q c is the critical liquid carrying flow rate under standard conditions, m 3 / d; P is pressure, MPa; Z is the gas phase deviation coefficient, dimensionless; T is temperature, K.

[0029] A further improvement of the present invention is that the non-energy-replenishing water drainage gas production process includes: small oil tubing optimization string, bubble drainage, plunger gas lift and wellhead pressurization.

[0030] A further improvement of the present invention is that the operation of step 4 includes:

[0031] The gas well inflow performance curve is calculated using formula (4):

[0032]

[0033] Among them, P R is the formation pressure, MPa; P wf is the bottom hole pressure, MPa; C is the coefficient, m 3 / d·MPa -2n ; n is an exponential and dimensionless.

[0034] A further improvement of the present invention is that the operation of step five includes:

[0035] For the optimal string selection of small oil tubing, the wellhead oil pressure is taken to be equal to the wellhead external transmission pressure, and a multiphase flow model suitable for water and gas wells is used to calculate the wellbore pressure drop to obtain the small oil tubing working curve;

[0036] For bubble drainage, the wellhead oil pressure is taken to be equal to the wellhead external transmission pressure, and the wellbore pressure drop is calculated using formula (5) to obtain the bubble drainage working curve;

[0037]

[0038] Where ΔP is the wellbore pressure drop, MPa; ρ m is the density of the mixed fluid, kg / m 3 ; g is the acceleration due to gravity, m / s 2 θ d is the well inclination angle, °; f m is the friction coefficient, dimensionless; v m is the velocity of the mixed bubble fluid, m / s; dz is the length of the wellbore segment, m;

[0039] For plunger gas lift, the wellhead oil pressure is taken to be equal to the wellhead external pressure, and the wellbore pressure drop is calculated using formula (6) to obtain the plunger gas lift working curve;

[0040]

[0041] h=(P ts -P cs ) / ρ l g-h2 (7)

[0042] Where G p is the plunger weight, N; h is the height of the liquid accumulation section from the plunger retainer, m; H is the height of the plunger retainer from the wellhead, m; A p is the cross-sectional area of ​​the plunger, m 2 ; γ g is the relative density of the gas phase, dimensionless; P ts The depth of the tubing shoe is H t The pressure in the oil pipe at the position, MPa; P cs is the casing pressure at the tubing shoe, MPa; h2 is the height of the liquid accumulation section from the tubing shoe to the plunger retainer, m.

[0043] For wellhead boosting, the wellhead oil pressure is equal to the original wellhead oil pressure minus the boosting pressure. The multiphase flow model suitable for water and gas wells is used to calculate the wellbore pressure drop and obtain the wellhead boosting working curve.

[0044] A further improvement of the present invention is that the operation of step six includes:

[0045] In the rectangular coordinate system, the horizontal axis is the gas phase flow rate, and the vertical axis is the pressure. According to formula (4), the gas well inflow dynamic curve is drawn, and the working curve of the i-th process among the n preliminarily selected non-energy-replenishing drainage gas production processes is drawn respectively, i = 1, ..., n;

[0046] Draw a straight line perpendicular to the horizontal axis through the intersection of the working curve of the i-th process and the gas well inflow performance curve. The intersection of this straight line and the horizontal axis is the pressure applicable limit Q of the i-th non-energy-replenishing drainage gas production process. gpi ;

[0047] If the working curve of the i-th non-energy-replenishing drainage gas production process has no intersection with the gas well inflow performance curve, the i-th non-energy-replenishing drainage gas production process is not applicable.

[0048] A further improvement of the present invention is that the operation of step seven includes:

[0049] Calculate the liquid accumulation limit curve of the i-th process among the n preliminarily selected non-energy-replenishing drainage gas production processes, i = 1, ..., n;

[0050] For the optimal string of small oil tubing, the critical liquid carrying flow rate of small oil tubing under different pressures is calculated using formula (2), and the liquid accumulation limit curve of small oil tubing is obtained;

[0051] For foam displacement, the critical foam-carrying flow rate under different pressures is calculated by using formula (8) to obtain the foam displacement liquid loading limit curve;

[0052]

[0053] Q cb is the critical foam-carrying flow rate (standard state), m 3 / d.

[0054] For plunger gas lift, the current string critical liquid-carrying flow rate under different pressures is calculated by using formula (2) to obtain the plunger gas lift liquid loading limit curve;

[0055] For wellhead pressure boosting, the critical liquid-carrying flow rate after different pressures minus the pressure boosting pressure is calculated by using formula (2) to obtain the wellhead pressure boosting liquid loading limit curve;

[0056] Further improvement of the present application is that the step eight operation includes:

[0057] In the rectangular coordinate system, taking the horizontal coordinate as the gas phase flow rate and the vertical coordinate as the pressure, the liquid loading limit curve of the i th process in the initially selected n kinds of no-energy-supplement drainage gas recovery processes is plotted according to the calculation results of step seven;

[0058] The intersection of the liquid loading limit curve of the i th process and the gas well inflow dynamic curve is vertically connected to the horizontal coordinate, and the intersection of the straight line and the horizontal coordinate is the liquid-carrying applicable limit Q gci of the i th no-energy-supplement drainage gas recovery process.

[0059] The step nine operation includes:

[0060] If the gas phase flow rate Q g under standard conditions is between the pressure applicable limit Q gpi and the liquid-carrying applicable limit Q gci of the i th process in the initially selected n kinds of no-energy-supplement drainage gas recovery processes, the i th no-energy-supplement drainage gas recovery process is applicable, and the specific process is as follows:

[0061] For the three processes of small oil pipe preferred string, foam displacement and wellhead pressure boosting, it is respectively judged whether Q gc < Q g < Q gp is established, if yes, the process meeting Q gc < Q g < Q gp is applicable;

[0062] For plunger gas lift, it is judged whether Q gp < Q g < Q gc is established, if yes, the plunger gas lift process is applicable;

[0063] If the gas phase flow rate Q under standard conditions g Less than the applicable pressure limit Q of the n preselected non-energy-replenishing drainage gas recovery processes gpi and liquid carrying limit Q gci The minimum value of Q g <min(Q gci ,Q gpi ), then the non-energy replenishment drainage gas production process is not applicable, and go to step ten.

[0064] A second aspect of the present invention provides a system for determining process limits and optimizing process optimization for drainage gas production. The system comprises: a memory, a processor, and a computer program stored in the memory. When the computer program is executed by the processor, the processor performs the following steps:

[0065] Step 1: Collect field parameters of water-bearing gas wells;

[0066] Step 2: Determine whether the wellhead oil pressure is greater than or equal to the wellhead external transmission pressure. If yes, go to step 3; if not, go to step 10;

[0067] Step 3: Determine whether the gas phase flow rate under standard conditions is greater than or equal to the maximum critical liquid carrying flow rate of the entire wellbore. If so, the gas well can produce normally and does not need to adopt the water drainage gas recovery process. If not, preliminarily select n non-energy-replenishing water drainage gas recovery processes based on their applicability.

[0068] Step 4: Calculate the gas well inflow performance curve;

[0069] Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas recovery processes;

[0070] Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0071] Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0072] Step 8: Determine the applicable limits of liquid carrying for the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0073] Step 9: Quantitatively select and optimize the drainage and gas recovery process;

[0074] Step 10: Select the energy replenishment and drainage gas production process.

[0075] Compared with the existing technology, the beneficial effect of the present invention is that the applicable limits of different drainage gas production processes can be quantitatively determined by using the present invention, thereby quantitatively optimizing different drainage gas production processes, overcoming the shortcomings of the current drainage gas production process selection method that lacks consideration of factors and cannot be quantitatively optimized, improving the effectiveness of the drainage gas production process, effectively guiding the selection of drainage gas production processes and the timing of process intervention in on-site gas wells, and realizing long-term stable production of water-containing gas wells. BRIEF DESCRIPTION OF THE DRAWINGS

[0076] Figure 1 It is a schematic flow diagram of the method of the present invention;

[0077] Figure 2 It is a schematic diagram for determining the applicable limit of the drainage gas production process and optimizing the process;

[0078] Figure 3 It is a diagram showing the determination of the limits of the drainage gas production process and the preferred embodiment of the process;

[0079] Figure 4 This is an example diagram of the calculation results of the critical liquid carrying flow rate. DETAILED DESCRIPTION

[0080] The present invention is further described in detail below with reference to the accompanying drawings:

[0081] The present invention establishes a method for determining the limits of drainage gas production processes and optimizing processes by comprehensively considering pressure limits and liquid carrying limits. The method can quantitatively optimize drainage gas production processes, effectively guide the selection of drainage gas production processes and the timing of process intervention in on-site gas wells, overcomes the deficiency of current drainage gas production process selection methods that cannot be quantitatively optimized, improves the effectiveness of drainage gas production processes, and realizes long-term stable production of water-containing gas wells. The method has very broad application prospects.

[0082] The method of the present invention comprises the following steps:

[0083] Step 1: Collect field parameters of water-bearing gas wells;

[0084] The field parameters of the water-bearing gas well include: flow pressure test data, static pressure test data, wellhead oil pressure P t , wellhead casing pressure P c , wellhead output pressure P tr , wellhead temperature T t , Gas flow rate Q under standard conditions (0.101MPa, 20℃) g , liquid flow rate Q l , gas phase relative density γ g , liquid density ρ l , surface tension σ, inner diameter of production string D, depth of production string H t , wellbore trajectory data.

[0085] Step two: judging the relationship between wellhead oil pressure and wellhead delivery pressure

[0086] Judging whether wellhead oil pressure P t is greater than or equal to wellhead delivery pressure P tr , if yes (i.e. P t ≥ P tr ), go to step three; if no (i.e. P t < P tr ), go to step ten;

[0087] Step three: judging critical liquid carrying of whole wellbore;

[0088] Judging whether gas phase flow rate Q g under standard condition is greater than or equal to maximum critical liquid carrying flow rate Q cmax of whole wellbore, if yes (i.e. Q g ≥ Q cmax ), the gas well can be produced normally without adopting drainage gas recovery process; if no (i.e. Q g < Q cmax ), n kinds of non-supplemental energy drainage gas recovery processes according to applicability preliminary selection are adopted, i.e. non-supplemental energy drainage gas recovery processes relying on self energy of gas well to drain liquid are selected, and the non-supplemental energy drainage gas recovery processes include: small tubing string, foam drainage, plunger gas lift and wellhead pressure boosting.

[0089] Specifically, the critical liquid carrying flow rate v c at different well depths is calculated by using formula (1):

[0090]

[0091] The critical liquid carrying flow rate Q c at different well depths is calculated by using formula (2):

[0092]

[0093] The maximum critical liquid carrying flow rate Q cmax of whole wellbore is calculated by using formula (3):

[0094]

[0095] In formula (3), Q represents finding the maximum value from all critical liquid carrying flow rates Q c at different well depths as Q cmax .

[0096] In the formula, v c is the critical liquid carrying flow rate, m / s; σ is the surface tension, N / m; Q l is the liquid phase flow rate, m 3 / s; ρ lis the liquid density, kg / m 3 ρ g is the gas phase density ( ), kg / m 3 ; D is the inner diameter of the production string, m; R is the build rate, ° / 30m; Q c is the critical liquid carrying flow rate (standard condition), m 3 / d; P is pressure, MPa; Z is the gas phase deviation coefficient, which is dimensionless and can be determined using the Hall-Yarbough method; T is temperature, K.

[0097] The calculation method of P is as follows:

[0098] According to the wellhead oil pressure P t , the Mukherjee-Brill multiphase flow model applicable to horizontal gas wells can be used to calculate P.

[0099] T is calculated as follows:

[0100] According to the wellhead temperature T t , the Hasan-Kabir method can be used to calculate T.

[0101] R is calculated as follows:

[0102] The following formula is used to calculate the inclination angle between adjacent wellbore trajectory data test points: R = 30 × Δθ / ΔH, where Δθ is the difference in well inclination angle between adjacent wellbore trajectory data test points, in degrees; and ΔH is the difference in well depth between adjacent wellbore trajectory data test points, in meters.

[0103] The operation of preliminarily selecting n non-energy-replenishing drainage gas recovery processes according to their applicability includes: preliminarily selecting the non-energy-replenishing drainage gas recovery processes according to applicable pressure gradients and applicable liquid phase flow rates in Table 1, wherein the pressure gradient can be calculated by the following formula:

[0104] P grad =100×P wf / H t ,

[0105] Where, P grad is the pressure gradient, MPa / 100m; P wf is the bottom hole pressure, MPa; H t is the tubing shoe depth, m.

[0106]

[0107] Table 1

[0108] Step 4: Calculate the gas well inflow performance curve;

[0109] According to the flow pressure test data and static pressure test data, the gas well productivity equation is fitted, as shown in formula (4). The gas well inflow performance curve is calculated using formula (4):

[0110]

[0111] Where, P R is the formation pressure (obtained from static pressure test data), MPa; P wf is the bottom hole flow pressure (obtained from the flow pressure test data), MPa; C is the coefficient, m 3 / d·MPa -2n ; n is an exponential and dimensionless.

[0112] The gas flow rate Q under standard conditions (0.101 MPa, 20°C) collected in step 1 g It refers to the actual gas phase flow rate during production of water-bearing gas wells. Q in formula (4) gp It refers to the gas well productivity under standard conditions (0.101MPa, 20℃), and also refers to a gas phase flow rate, with the unit of m 3 / d.

[0113] Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas production processes;

[0114] The working curve of the i-th (i=1,…,n) process among the n preliminarily selected non-energy-replenishing drainage gas production processes is calculated respectively.

[0115] a. For the optimal string selection of small oil tubing, the wellhead oil pressure is equal to the wellhead external transmission pressure. A multiphase flow model suitable for water and gas wells is used to calculate the wellbore pressure drop and the working curve of the small oil tubing is calculated.

[0116] The operations for calculating the small oil pipe working curve include:

[0117] Taking the wellhead oil pressure as the starting point for calculation, a set of gas flow rates (standard conditions) is set, and the Mukherjee-Brill multiphase flow model suitable for horizontal gas wells is used to calculate the wellbore pressure drop under different gas flow rates. The bottomhole flowing pressure corresponding to different gas flow rates is obtained, thereby obtaining the small tubing working curve.

[0118] b. For bubble drainage, take the wellhead oil pressure equal to the wellhead external pressure, use formula (5) to calculate the wellbore pressure drop, and calculate the bubble drainage working curve;

[0119] The operations for calculating the bubble working curve include:

[0120] Taking the wellhead oil pressure as the starting point for calculation, a set of gas flow rates (standard conditions) is set, and the wellbore pressure drop under different gas flow rates is calculated using formula (5). The bottom hole flowing pressure corresponding to different gas flow rates is obtained, and thus the bubble drainage working curve is obtained.

[0121]

[0122] where ΔP is the wellbore pressure drop, MPa; ρ m is the mixed fluid density, kg / m 3 ; g is the gravitational acceleration, m / s 2 ; θ d is the deviation angle, °; f m is the friction factor, dimensionless; v m is the mixed fluid velocity, m / s; and dz is the wellbore subsection length, m, where ρ m can be calculated by the following formula: ρ m = 0.5 ρ l , θ d is obtained from the well trajectory data, f m can be obtained by looking up the Moody chart, and v m can be calculated by the following formula: dz is the self-defined wellbore subsection length.

[0123] c. For the plunger gas lift, the wellhead oil pressure is equal to the wellhead delivery pressure, the wellbore pressure drop is calculated by using formula (6), and the plunger gas lift operating curve is calculated.

[0124] The operation of calculating the plunger gas lift operating curve includes:

[0125] The wellhead oil pressure is taken as the starting point for calculation, a group of gas phase flow rates (standard conditions) are set, the wellbore pressure drops under different gas phase flow rates are calculated by using formula (6), the bottom hole flowing pressures corresponding to different gas phase flow rates are obtained, and thus the plunger gas lift operating curve is obtained.

[0126]

[0127] h = (P ts -P cs ) / ρ l g-h2 (7)

[0128] where G p is the plunger weight, N; h is the height of the accumulated liquid section from the plunger retainer, m; H is the height of the plunger retainer from the wellhead, m; A p is the cross-sectional area of the plunger, m 2 ; γ g is the relative density of the gas phase, dimensionless; P ts is the tubing internal pressure at the tubing shoe depth H t , MPa, which can be calculated according to the wellhead oil pressure by using a wellbore multiphase flow model suitable for water-producing gas wells; P cs is the casing internal pressure at the tubing shoe, MPa, which can be calculated according to the wellhead casing pressure by using the Cullender-Smith static gas column model; and h2 is the height of the accumulated liquid section from the tubing shoe to the plunger retainer, m.

[0129] Among them, G p ,H,A p is the known parameter of plunger gas lift, H t are known parameters of the tubing.

[0130] P ts The calculation method is as follows: According to the wellhead oil pressure, the Mukherjee-Brill multiphase flow model suitable for horizontal gas wells can be used for calculation.

[0131] P cs The calculation method is as follows: According to the wellhead casing pressure, the Cullender-Smith static air column model is used for calculation.

[0132] h2 can be calculated by the following formula: h2 = H t -H.

[0133] d. For wellhead boosting, the wellhead oil pressure is equal to the original wellhead oil pressure minus the boosting pressure. A multiphase flow model suitable for water and gas wells can be used to calculate the wellbore pressure drop and the wellhead boosting working curve.

[0134] The operations for calculating the wellhead boosting working curve include:

[0135] Taking the wellhead oil pressure as the starting point for calculation, a set of gas flow rates (standard conditions) is set, and the Mukherjee-Brill multiphase flow model suitable for horizontal gas wells is used to calculate the wellbore pressure drop under different gas flow rates. The bottomhole flowing pressure corresponding to different gas flow rates is obtained, thereby obtaining the wellhead pressurization working curve.

[0136] Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0137] In the rectangular coordinate system, the abscissa is the gas phase flow rate and the ordinate is the pressure. According to formula (4), the gas well inflow performance curve is drawn, and the working curve of the i-th (i=1,…,n) process among the n preliminarily selected non-energy-replenishing drainage gas production processes is drawn respectively (that is, the four working curves obtained in step 5 are drawn respectively). A straight line perpendicular to the abscissa is drawn through the intersection of the working curve of the i-th (i=1,…,n) process and the gas well inflow performance curve. The intersection of this straight line and the abscissa is the pressure applicable limit Q of the i-th (i=1,…,n) non-energy-replenishing drainage gas production process. gpi If the working curve of the i-th (i=1,…,n) non-energy-replenishing drainage gas production process has no intersection with the gas well inflow performance curve, the i-th (i=1,…,n) non-energy-replenishing drainage gas production process is not applicable.

[0138] Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0139] The liquid accumulation limit curve of the i-th (i=1,…,n) process among the n preliminarily selected non-energy-replenishing drainage gas production processes is calculated respectively.

[0140] a. For the optimal string of small oil tubing, use formula (2) to calculate the critical liquid carrying flow rate of small oil tubing under different pressures and calculate the liquid accumulation limit curve of small oil tubing;

[0141] The operations for calculating the liquid accumulation limit curve of a small oil pipe include:

[0142] A set of pressures is set, and the critical liquid carrying flow rate of the small oil pipe under different pressures is calculated using formula (2). The gas phase flow rate corresponding to different pressures (i.e., the critical liquid carrying flow rate of the small oil pipe) is obtained, thereby obtaining the liquid accumulation limit curve of the small oil pipe.

[0143] b. For bubble drainage, use formula (8) to calculate the critical bubble flow rate under different pressures and obtain the bubble drainage effusion limit curve.

[0144]

[0145] Where Q cb is the critical bubble flow rate (standard condition), m 3 / d.

[0146] c. For plunger gas lift, use formula (2) to calculate the current critical liquid flow rate of the string under different pressures and calculate the plunger gas lift liquid accumulation limit curve;

[0147] The operations for calculating the plunger gas lift liquid accumulation limit curve include:

[0148] Set a set of pressures and use formula (2) to calculate the current critical liquid carrying flow rate of the string under different pressures. The gas phase flow rate corresponding to different pressures (i.e., the current critical liquid carrying flow rate of the string) is obtained, thereby obtaining the plunger gas lift liquid accumulation limit curve.

[0149] d. For wellhead pressurization, use formula (2) to calculate the current critical liquid flow rate of the string after subtracting the boost pressure at different pressures, and calculate the wellhead pressurization liquid accumulation limit curve;

[0150] The operations for calculating the wellhead pressurization liquid accumulation limit curve include:

[0151] Set a set of pressures and use formula (2) to calculate the current critical liquid carrying flow rate of the string after subtracting the boost pressure at different pressures to obtain the gas phase flow rate corresponding to different pressures (i.e., the current critical liquid carrying flow rate of the string after subtracting the boost pressure at different pressures), thereby obtaining the wellhead boost liquid accumulation limit curve.

[0152] The "current tubing" in the above steps refers to the production tubing currently used by the water-bearing gas well in step 1. For example, if 2-7 / 8in tubing is currently used for production, the "current tubing" is the 2-7 / 8in tubing.

[0153] Step eight: determine the liquid carrying applicable limit of the preliminary selected n kinds of no energy supplement drainage gas recovery processes;

[0154] In the rectangular coordinate system, taking the horizontal coordinate as the gas phase flow rate and the vertical coordinate as the pressure, the liquid loading limit curve of the i th (i = 1, …, n) process among the preliminary selected n kinds of no energy supplement drainage gas recovery processes is plotted according to the calculation results of step seven respectively, a straight line perpendicular to the horizontal coordinate is drawn through the intersection point of the liquid loading limit curve of the i th (i = 1, …, n) process and the gas well inflow performance curve, and the intersection point of the straight line and the horizontal coordinate is the liquid carrying applicable limit Q gci of the i th (i = 1, …, n) no energy supplement drainage gas recovery process.

[0155] Step nine: quantitatively optimize the drainage gas recovery process.

[0156] If the gas phase flow rate Q g under the standard condition is between the pressure applicable limit Q gpi and the liquid carrying applicable limit Q gci of the i th (i = 1, …, n) process among the preliminary selected n kinds of no energy supplement drainage gas recovery processes, the i th (i = 1, …, n) no energy supplement drainage gas recovery process is applicable, and the no energy supplement drainage gas recovery process is optimized according to the applicable limit and the economy, which is as follows:

[0157] a. For the three processes of small tubing string, foam drainage and wellhead pressure boosting, it is respectively judged whether Q gc < Q g < Q gp is established, if yes, the process meeting Q gc < Q g < Q gp is applicable;

[0158] b. For the plunger gas lift, it is judged whether Q gp < Q g < Q gc is established, if yes, the plunger gas lift process is applicable.

[0159] If the gas phase flow rate Q g under the standard condition is less than the minimum value of the pressure applicable limit Q gpi and the liquid carrying applicable limit Q gci of the preliminary selected n kinds of no energy supplement drainage gas recovery processes, i.e. Q g < min(Q gci , Q gpi )(i = 1, …, n), then the no energy supplement drainage gas recovery process is not applicable, and step ten is entered.

[0160] Step 10: Select the energy-replenishing drainage gas production process. The existing energy-replenishing drainage gas production processes include: gas lift, electric submersible pump, jet pump, rod pump. The energy-replenishing drainage gas production process can be selected based on applicability and economy, and will not be repeated here.

[0161] The four non-energy-replenishing drainage gas production processes provided in the present invention are the non-energy-replenishing drainage gas production processes that are widely used in shale gas wells. For other non-energy-replenishing drainage gas production processes, the same method as above can be referred to for optimization.

[0162] Figure 2 It is a schematic diagram of determining the applicable limits and process optimization of the drainage gas production process in an embodiment of the present invention. Figure 2 The horizontal axis is the gas flow rate, and the vertical axis is the pressure. The applicable limits of different drainage gas recovery technologies are marked below the horizontal axis. Figure 2 The curves are: inflow dynamic curve 1, current string liquid accumulation limit curve 2 (curve 2 is the plunger gas lift liquid accumulation limit curve, obtained from step seven c), wellhead boosting working curve 31, wellhead boosting liquid accumulation limit curve 32, bubble drainage working curve 41, bubble drainage liquid accumulation limit curve 42, small tubing working curve 51, small tubing liquid accumulation limit curve 52, plunger gas lift working curve 6.

[0163] The present invention also provides a system for determining drainage gas production process limits and optimizing the process, the system comprising: a memory, a processor, and a computer program stored in the memory, the computer program executing the following steps when executed by the processor:

[0164] Step 1: Collect field parameters of water-bearing gas wells;

[0165] Step 2: Determine whether the wellhead oil pressure is greater than or equal to the wellhead external transmission pressure. If yes, go to step 3; if not, go to step 10;

[0166] Step 3: Determine whether the gas phase flow rate under standard conditions is greater than or equal to the maximum critical liquid carrying flow rate of the entire wellbore. If so, the gas well can produce normally and does not need to adopt the water drainage gas recovery process. If not, preliminarily select n non-energy-replenishing water drainage gas recovery processes based on their applicability.

[0167] Step 4: Calculate the gas well inflow performance curve;

[0168] Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas recovery processes;

[0169] Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0170] Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0171] Step 8: Determine the applicable limits of liquid carrying for the n preliminarily selected non-energy-replenishing drainage gas recovery processes;

[0172] Step 9: Quantitatively select and optimize the drainage and gas recovery process;

[0173] Step 10: Select the energy replenishment and drainage gas production process.

[0174] The embodiments of the inventive method are as follows:

[0175] The process of the drainage gas production process optimization method and system of the present invention is as follows: Figure 1 As shown in the figure, the applicable limit determination and process optimization diagram of drainage gas production process is shown in the figure. Figure 2 , the specific implementation process of this method is given below for each step.

[0176] Step 1: Collect field parameters of water-bearing gas wells. A horizontal gas well in the embodiment has liquid accumulation in the wellbore and is currently in the intermittent production stage. The field parameters of the well include: flow pressure test data (bottom hole flow pressure 5.5MPa, daily gas production 16000m 3 / d; bottom hole pressure 4.2MPa, daily gas production 32000m 3 / d), test formation static pressure 6.4MPa, wellhead oil pressure 2.4MPa, wellhead casing pressure 4.8MPa, wellhead external pressure 2MPa, wellhead temperature 301K, gas flow rate under standard conditions 15000m 3 / d, liquid flow rate 2m 3 / d, gas phase relative density 0.57, liquid phase density 1030kg / m 3 , surface tension 70mN / m, production tubing is 2-7 / 8in oil pipe (inner diameter 62mm), tubing depth is 2540m, and the build-up rate is determined based on the wellbore trajectory data.

[0177] Step 2: The wellhead oil pressure of the embodiment well is 2.4 MPa, which is greater than the wellhead external transmission pressure of 2 MPa. No energy replenishment and water drainage gas production process is required, so go to step 3.

[0178] Step 3: Use equations (1) and (2) to calculate the critical liquid flow rate at different well depths in the example well. The calculation results are as follows: Figure 4 shown. Figure 4 This is an example diagram of the calculation results of the critical liquid carrying flow rate. Figure 4 The solid line in the figure is the critical liquid flow rate at different well depths calculated using equations (1) and (2), and the dotted line is the gas flow rate under standard conditions in the well. cmax Located at the bottom of the well, 19150m 3 / d.

[0179] Figure 4The data table corresponding to the solid line critical liquid carrying flow rate curve is shown in Table 2. It can be seen that the maximum value of the critical liquid carrying flow rate is 19150m 3 / d, the corresponding well depth is 2540m, and the tubing depth of 2540m is the well bottom position, that is, the maximum critical liquid flow rate Q cmax At the bottom of the well.

[0180] Well depth / m Critical liquid entrainment flow rate / (10 4 m 3 / d)]]> 0 1.4847 8 1.4486 100 1.3931 211 1.4481 405 1.4698 411 1.5246 415 1.5355 604 1.5336 615 1.5801 709 1.5245 815 1.5856 999 1.6468 1014 1.8816 1214 1.9007 1319 1.8282 1411 1.5848 1517 1.7585 1603 1.8164 1624 1.9092 1929 1.7727 2110 1.7687 2233 1.7981 2540 1.9150

[0181] Table 2

[0182] Gas phase flow rate Q under standard conditions g 15000m 3 / d is less than the maximum critical liquid carrying flow rate Q of the entire wellbore cmax 19150m 3 / d, the non-energy-supplemented drainage gas production process that relies on the gas well's own energy to drain liquid is selected. Based on applicability, four non-energy-supplemented drainage gas production processes are initially selected, including 2-3 / 8in small oil tubing, bubble drainage, plunger gas lift and wellhead pressurization.

[0183] Use formula (1) to calculate the critical liquid carrying velocity v at different well depths c :

[0184]

[0185] Calculate the critical liquid flow rate Q at different well depths using formula (2) c :

[0186]

[0187] Calculate the maximum critical liquid flow rate Q of the entire wellbore using formula (3) cmax :

[0188]

[0189] Where, v c is the critical liquid carrying velocity, m / s; σ is the surface tension, N / m; Q l is the liquid phase flow rate, m 3 / s;ρ l is the liquid density, kg / m 3 ρ g is the gas phase density, kg / m 3 ; D is the inner diameter of the production string, m; R is the build rate, ° / 30m; Q c is the critical liquid carrying flow rate (standard condition), m 3 / d; P is pressure, MPa; Z is the gas phase deviation coefficient, which is dimensionless and can be determined using the Hall-Yarbough method; T is temperature, K.

[0190] Step four: According to the flow pressure test data and static pressure test data, the gas well productivity equation (4) is fitted, the coefficient C = 1940 and the index n = 0.89 in the example well, and the gas well inflow performance curve is calculated, as curve 1 in Figure 3 .

[0191]

[0192] wherein, P R is the formation pressure, MPa; P wf is the bottom hole flowing pressure, MPa; C is the coefficient, m 3 / d·MPa -2n ; n is the index, dimensionless.

[0193] Step five: the working curves in the four initially selected water drainage gas recovery processes without energy supplement in the example well are calculated respectively.

[0194] a. For 2-3 / 8in small tubing, the wellhead oil pressure is equal to the wellhead delivery pressure 2MPa, the Mukherjee-Brill multiphase flow model suitable for horizontal gas wells is used to calculate the wellbore pressure drop, and the 2-3 / 8in small tubing working curve is calculated, as curve 51 in Figure 3 .

[0195] b. For foam flooding, the wellhead oil pressure is equal to the wellhead delivery pressure 2MPa, the wellbore pressure drop is calculated by using formula (5), and the foam flooding working curve is calculated, as curve 41 in Figure 3 .

[0196]

[0197] wherein, ΔP is the wellbore pressure drop, MPa; ρ m is the mixed fluid density, kg / m 3 ; g is the gravity acceleration, m / s 2 ; θ d is the inclination angle, °; f m is the friction coefficient, dimensionless; v m is the foam fluid velocity, m / s; dz is the wellbore segment length, m.

[0198] c. For plunger gas lift, the wellhead oil pressure is equal to the wellhead delivery pressure 2MPa, the plunger stopper position is at the tubing shoe, the wellbore pressure drop is calculated by using formula (6), and the plunger gas lift working curve is calculated, as curve 6 in Figure 3 .

[0199]

[0200] h = (P ts -P cs ) / ρ l g-h2 (7)

[0201] G p is the weight of the plunger, N; h is the height of the accumulated liquid section from the plunger retainer, m; H is the height of the plunger retainer from the wellhead, m; A p is the cross-sectional area of the plunger, m 2 ; γ g is the relative density of the gas phase, dimensionless; P ts is the tubing pressure at the depth H t of the tubing shoe, MPa, which can be calculated according to the wellhead oil pressure by using the Mukherjee-Brill multiphase flow model; P cs is the casing pressure at the depth of the tubing shoe, MPa, which can be calculated according to the wellhead casing pressure by using the Cullender-Smith static gas column model; h2 is the height of the accumulated liquid section from the tubing shoe to the plunger retainer, m.

[0202] d、For wellhead pressurization, the wellhead oil pressure is equal to the original wellhead oil pressure 2.4 MPa minus the pressurization pressure 1 MPa, the wellbore pressure drop can be calculated by using the Mukherjee-Brill multiphase flow model, and the wellhead pressurization operating curve is calculated, as the curve 31 in Figure 3 .

[0203] Step six: In the rectangular coordinate system, the horizontal coordinate is the gas phase flow rate, and the vertical coordinate is the pressure, as shown in Figure 3 , the gas well inflow performance curve 1 of the example well is plotted, and the operating curves of the four initially selected no-energy-supplement drainage gas recovery processes are plotted respectively, a straight line perpendicular to the horizontal coordinate is drawn through the intersection of the operating curve of the i-th (i = 1, …, 4) process and the gas well inflow performance curve, and the intersection of the straight line with the horizontal coordinate is the pressure application limit Q gpi of the i-th (i = 1, …, 4) no-energy-supplement drainage gas recovery process. Figure 3 The pressure application limit of the 2-3 / 8in small tubing in

[0204] Step seven: The accumulated liquid limit curve of the i-th (i = 1, …, 4) process in the four initially selected no-energy-supplement drainage gas recovery processes is calculated respectively.

[0205] a、For the 2-3 / 8in small tubing, the critical liquid-carrying flow rate of the 2-3 / 8in small tubing under different pressures is calculated by using equation (2), and the accumulated liquid limit curve of the 2-3 / 8in small tubing is calculated, as the curve 52 in Figure 3 .

[0206] b. For bubble drainage, use formula (8) to calculate the critical bubble flow rate under different pressures and calculate the bubble drainage effusion limit curve, as shown in Figure 3 Curve 42 in .

[0207]

[0208] Where Q cb is the critical bubble flow rate (standard condition), m 3 / d.

[0209] c. For plunger gas lift, use formula (2) to calculate the critical liquid carrying flow rate of the current 2-7 / 8in oil pipe under different pressures, and calculate the plunger gas lift liquid accumulation limit curve, as shown in Figure 3 Curve 22 in .

[0210] d. For wellhead pressurization, use formula (2) to calculate the critical liquid flow rate of the current 2-7 / 8in oil pipe after subtracting the boost pressure of 1MPa at different pressures, and calculate the wellhead pressurization liquid accumulation limit curve, as shown in Figure 3 Curve 32 in .

[0211] Step 8: In the rectangular coordinate system, take the abscissa as the gas phase flow rate and the ordinate as the pressure, and draw the liquid loading limit curve of the i-th (i=1,…,4) process among the four preliminarily selected non-energy-recharged drainage gas production processes. Draw a straight line perpendicular to the abscissa through the intersection of the liquid loading limit curve of the i-th (i=1,…,4) process and the gas well inflow performance curve. The intersection of this straight line and the abscissa is the liquid carrying applicable limit Q of the i-th (i=1,…,4) non-energy-recharged drainage gas production process. gci . Figure 3 The applicable limit of liquid carrying for 2-3 / 8in small oil pipe is intersection point 54, the applicable limit of liquid carrying for bubble drainage is intersection point 44, the applicable limit of liquid carrying for wellhead pressurization is intersection point 34, and the applicable limit of liquid carrying for plunger gas lift is intersection point 24.

[0212] Step 9: If the gas phase flow rate Q under standard conditions g The pressure applicable limit Q of the i-th (i=1,…,4) process among the four preliminarily selected non-energy-replenishing drainage gas recovery processes gpi and liquid carrying limit Q gci If , then the i-th (i=1,…,4) non-energy-replenishing drainage gas production process is applicable, and the non-energy-replenishing drainage gas production process is preferred according to the applicable limit and economy.

[0213] a. For small oil pipes, the preferred pipe string, bubble drain and wellhead pressurization are: gc <Q g <Q gp When the oil is flowing, small tubing, bubble pumping and wellhead pressurization technology are applicable. Figure 3 As shown, in this embodiment, Q g 15000m3 / d, only bubble row meets Q gc <Q g <Q gp , but 2-3 / 8in small oil pipe and wellhead booster do not meet Q gc <Q g <Q gp Therefore, the foam drainage process is applicable, but the 2-3 / 8in small oil pipe and wellhead pressurization are not applicable.

[0214] b. For plunger gas lift, when Q gp <Q g <Q gc When the plunger gas lift process is applicable. Figure 3 As shown, in this embodiment, Q g 15000m 3 / d, plunger gas lift does not meet Q gp <Q g <Q gc , so the plunger gas lift process is not applicable.

[0215] If the gas phase flow rate Q under standard conditions g Less than the applicable pressure limit Q of the four preselected non-recharged drainage gas recovery processes gpi and liquid carrying limit Q gci The minimum value of Q g <min(Q gci ,Q gpi )(i=1,…,4), the non-energy-replenishing drainage gas production process is not applicable, and the energy-replenishing drainage gas production process needs to be selected. The energy-replenishing drainage gas production process is selected based on applicability and economy.

[0216] The well in the current embodiment uses 2-7 / 8in oil pipe. Figure 3 This is a diagram showing an example of determining the boundaries of the drainage gas production process and the preferred implementation of the process. ​ The curves and intersection points are: inflow performance curve 1, working curve 21 of 2-7 / 8-inch tubing, liquid accumulation limit curve 22 of 2-7 / 8-inch tubing (i.e., the current working curve and liquid accumulation limit curve of plunger gas lift), pressure applicable limit 23 of 2-7 / 8-inch tubing, liquid carrying applicable limit 24 of 2-7 / 8-inch tubing and plunger gas lift, working curve 31 of wellhead boosting, liquid accumulation limit curve 32 of wellhead boosting, pressure applicable limit 33 of wellhead boosting, liquid carrying applicable limit 34 of wellhead boosting, working curve 41 of bubble drainage, liquid accumulation limit curve 42 of bubble drainage, pressure applicable limit 43 of bubble drainage, liquid carrying applicable limit 44 of bubble drainage, working curve 51 of 2-3 / 8-inch small tubing, liquid accumulation limit curve 52 of 2-3 / 8-inch small tubing, pressure applicable limit 53 of 2-3 / 8-inch small tubing, liquid carrying applicable limit 54 of 2-3 / 8-inch small tubing, working curve 6 of plunger gas lift.

[0217] According to the preferred method and system for drainage and gas production technology of the present invention, the drainage and gas production technology of the well in this embodiment is finally selected as foam drainage. The application effect of foam drainage in the well in this embodiment is shown in Table 3.

[0218]

[0219] Table 3

[0220] As can be seen from Table 3, after the well in this example was subjected to foam drainage, the intermittent production was changed to continuous production, and the daily gas production increased from 15000m 3 / d increased to 18000m 3 / d, and at the same time, the daily water production increased, the oil pressure decreased, and the oil-casing pressure difference decreased. It can be seen that the well in this embodiment achieved a good drainage effect after applying the foam drainage process, which can effectively remove the accumulated liquid in the wellbore and restore normal production.

[0221] Finally, it should be noted that the above technical solution is only one embodiment of the present invention. For those skilled in the art, it is easy to make various types of improvements or modifications based on the application methods and principles disclosed in the present invention, and it is not limited to the method described in the above specific embodiment of the present invention. Therefore, the method described above is only preferred and does not have a restrictive meaning.

Claims

1. A method for optimizing drainage gas production process, characterized by: The method comprises: Step 1: Collect field parameters of water-bearing gas wells; Step 2: Determine whether the wellhead oil pressure is greater than or equal to the wellhead external transmission pressure. If yes, go to step 3; if not, go to step 10; Step 3: Determine whether the gas phase flow rate under standard conditions is greater than or equal to the maximum critical liquid carrying flow rate of the entire wellbore. If so, the gas well can produce normally and does not need to adopt the water drainage gas recovery process. If not, preliminarily select n non-energy-replenishing water drainage gas recovery processes based on their applicability. Step 4: Calculate the gas well inflow performance curve; Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas recovery processes; Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 8: Determine the applicable limits of liquid carrying for the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 9: Quantitatively select and optimize the drainage and gas recovery process; Step 10: Select the energy replenishment and drainage gas recovery process; The non-energy-replenishing drainage gas recovery process includes: small tubing string optimization, bubble drainage, plunger gas lift and wellhead pressurization; The operation of step five includes: For the optimal string selection of small oil tubing, the wellhead oil pressure is taken to be equal to the wellhead external transmission pressure, and a multiphase flow model suitable for water and gas wells is used to calculate the wellbore pressure drop to obtain the small oil tubing working curve; For bubble drainage, the wellhead oil pressure is taken to be equal to the wellhead external transmission pressure, and the wellbore pressure drop is calculated using formula (5) to obtain the bubble drainage working curve; Where ΔP is the wellbore pressure drop; ρ m is the density of the mixed fluid; g is the acceleration due to gravity; θ d is the well inclination angle; f m is the friction coefficient; v m is the velocity of the mixed bubble fluid; dz is the length of the wellbore segment; For plunger gas lift, the wellhead oil pressure is taken to be equal to the wellhead external pressure, and the wellbore pressure drop is calculated using formula (6) to obtain the plunger gas lift working curve; h=(P ts -P cs ) / ρ l g-h2 (7) Where G p is the plunger weight; h is the height of the liquid accumulation section from the plunger retainer; H is the height of the plunger retainer from the wellhead; A p is the cross-sectional area of ​​the plunger; γ g is the relative density of the gas phase; P ts The depth of the tubing shoe is H t The pressure in the oil pipe at cs is the casing pressure at the tubing shoe; h2 is the height of the liquid accumulation section from the tubing shoe to the plunger retainer; Z is the gas phase deviation coefficient; T is the temperature; For wellhead pressurization, the wellhead oil pressure is equal to the original wellhead oil pressure minus the boost pressure. A multiphase flow model suitable for water and gas wells is used to calculate the wellbore pressure drop and obtain the wellhead pressurization working curve.

2. The method for optimizing drainage gas production according to claim 1, characterized in that: The field parameters of the water-bearing gas well include: flow pressure test data, static pressure test data, wellhead oil pressure P t , wellhead casing pressure P c , wellhead output pressure P tr , wellhead temperature T t , gas phase flow rate Q under standard conditions g , liquid flow rate Q l , gas phase relative density γ g , liquid density ρ l , surface tension σ, inner diameter of production string D, depth of production string H t , wellbore trajectory data.

3. The method for optimizing drainage gas production according to claim 2, characterized in that: The maximum critical liquid carrying rate in step 3 is obtained as follows: Use formula (1) to calculate the critical liquid carrying velocity v at different well depths c : Calculate the critical liquid flow rate Q at different well depths using formula (2) c : Calculate the maximum critical liquid flow rate Q of the entire wellbore using formula (3) cmax : Where, v c is the critical liquid carrying velocity; σ is the surface tension; Q l is the liquid phase flow rate; ρ l is the liquid density; ρ g is the gas phase density; D is the inner diameter of the production string; R is the slope rate; Q c is the critical liquid carrying flow rate under standard conditions; P is the pressure.

4. The method for optimizing drainage gas production according to claim 3, characterized in that: The operation of step 4 includes: The gas well inflow performance curve is calculated using formula (4): Among them, P R is the formation pressure; P wf is the bottom hole flowing pressure; C is the coefficient; n is the exponent.

5. The method for optimizing drainage gas production according to claim 4, characterized in that: The operation of step six includes: In the rectangular coordinate system, the horizontal axis is the gas phase flow rate, and the vertical axis is the pressure. According to formula (4), the gas well inflow dynamic curve is drawn, and the working curve of the i-th process among the n preliminarily selected non-energy-replenishing drainage gas production processes is drawn respectively, i = 1, ..., n; Draw a straight line perpendicular to the horizontal axis through the intersection of the working curve of the i-th process and the gas well inflow performance curve. The intersection of this straight line and the horizontal axis is the pressure applicable limit of the i-th non-energy-replenishing drainage gas production process. If the working curve of the i-th non-energy-replenishing drainage gas production process has no intersection with the gas well inflow performance curve, the i-th non-energy-replenishing drainage gas production process is not applicable.

6. The method for optimizing drainage gas production according to claim 5, characterized in that: The operation of step seven includes: Calculate the liquid accumulation limit curve of the i-th process among the n preliminarily selected non-energy-replenishing drainage gas production processes, i = 1, ..., n; For the optimal string of small oil tubing, the critical liquid carrying flow rate of small oil tubing under different pressures is calculated using formula (2), and the liquid accumulation limit curve of small oil tubing is obtained; For bubble drainage, the critical bubble carrying flow rate under different pressures is calculated using formula (8) to obtain the bubble drainage effusion limit curve; Among them, Q cb is the critical bubble flow rate, m 3 / d; For plunger gas lift, use formula (2) to calculate the current critical liquid flow rate of the string under different pressures and obtain the plunger gas lift liquid accumulation limit curve; For wellhead pressurization, the critical liquid carrying flow rate after subtracting the boost pressure at different pressures is calculated using formula (2) to obtain the wellhead pressurization liquid accumulation limit curve.

7. The method for optimizing drainage gas production according to claim 6, characterized in that: The operation of step eight includes: In the rectangular coordinate system, the horizontal axis is the gas phase flow rate, and the vertical axis is the pressure. According to the calculation results of step 7, the liquid accumulation limit curve of the i-th process among the n preliminarily selected non-energy-replenishing drainage gas recovery processes is drawn; Draw a straight line perpendicular to the horizontal axis through the intersection of the liquid loading limit curve of the i-th process and the gas well inflow performance curve. The intersection of this straight line and the horizontal axis is the applicable limit of liquid carrying for the i-th non-energy-replenishing drainage gas recovery process.

8. The method for optimizing drainage gas production according to claim 7, characterized in that: The operation of step nine includes: If the gas phase flow rate Q under standard conditions g The pressure applicable limit of the i-th process among the n preselected non-energy-replenishing drainage gas recovery processes and applicable limits for liquid carrying If the value is between , then the i-th non-energy-replenishing drainage gas recovery process is applicable, as follows: For small oil pipes, the three processes of pipe string, bubble drainage and wellhead pressurization are selected to judge Q respectively. gc g gp Is it true? If so, then Q is satisfied. gc g gp The process is applicable;​​​​ For plunger gas lift, determine Q gp g gc Is it true? If so, the plunger gas lift process is applicable;​​ If the gas phase flow rate Q under standard conditions g Less than the applicable pressure limit of n preselected non-energy-replenishing drainage gas recovery processes and applicable limits for liquid carrying The minimum value of Q g <min(Q gci ,Q gpi ), then the non-energy-replenishing drainage gas recovery process is not applicable, and go to step ten.

9. A system for determining process limits and optimizing process for water drainage and gas production, for implementing the method according to any one of claims 1 to 8, characterized in that: The system includes: a memory, a processor, and a computer program stored in the memory, wherein the computer program, when executed by the processor, performs the following steps: Step 1: Collect field parameters of water-bearing gas wells; Step 2: Determine whether the wellhead oil pressure is greater than or equal to the wellhead external transmission pressure. If yes, go to step 3; if not, go to step 10; Step 3: Determine whether the gas phase flow rate under standard conditions is greater than or equal to the maximum critical liquid carrying flow rate of the entire wellbore. If so, the gas well can produce normally and does not need to adopt the water drainage gas recovery process. If not, preliminarily select n non-energy-replenishing water drainage gas recovery processes based on their applicability. Step 4: Calculate the gas well inflow performance curve; Step 5: Calculate the working curves of n pre-selected non-energy-replenishing drainage gas recovery processes; Step 6: Determine the applicable pressure limits of the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 7: Calculate the liquid accumulation limit curves of the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 8: Determine the applicable limits of liquid carrying for the n preliminarily selected non-energy-replenishing drainage gas recovery processes; Step 9: Quantitatively select and optimize the drainage and gas recovery process; Step 10: Select the energy replenishment and drainage gas production process.

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