A calculation method for optimizing the design of plunger lifting drainage and gas production

Abstract

The present invention discloses a plunger lifting drainage gas production optimization design calculation method. According to the basic parameters of the gas well, the target gas production is taken as the optimization target. In the process of plunger lifting upward, the influence of factors such as plunger leakage and annular water accumulation is considered, and more accurate calculation methods such as maximum casing pressure, maximum flow pressure, minimum casing pressure, and minimum flow pressure are proposed; according to the relationship between the lifting gas volume and the formation gas production, a shut-in flow pressure calculation method is proposed, and then the calculation methods of the self-flowing continuous flow time, the formation production during the self-flowing continuous flow period, the shut-in time, and the formation production during the shut-in period are proposed; the present invention proposes strict and scientific plunger lifting drainage gas production feasibility judgment conditions, and proposes plunger drainage gas production parameter optimization cycle iterative calculation logic steps; by better analyzing the technical adaptability problems of the plunger drainage gas production process, the plunger drainage gas production process parameters can be better optimized, and then the gas well production can be more effectively improved.

Description

Technical Field

[0001] The invention relates to the field of gas production engineering, and in particular to a plunger lifting drainage gas production optimization design calculation method. Background Art

[0002] Plunger lifting drainage gas production is a major method of drainage gas production in low-yield natural gas wells. Plunger lifting drainage gas production is a periodic intermittent drainage gas production method. There are generally three production stages in one cycle: ① In the first stage, the wellbore reserves energy. After the well is shut down, the plunger falls from the wellhead to the bottom of the well, the formation still produces gas, and the gas energy is continuously stored in the wellbore. ② In the second stage, the plunger lifts to drain water. After the well is opened, the high-pressure gas stored in the wellbore casing annulus pushes the plunger in the oil pipe to the wellhead through pressure reduction expansion, and finally the water in the wellbore is discharged to the ground. ③ In the third stage, the self-flow continues. After the plunger discharges the wellbore liquid, the production flow pressure decreases, and the formation produces natural gas and water. The formation water continues to accumulate in the wellbore. After the wellbore is watered, the production flow pressure will gradually decrease, and the formation production will gradually decrease. When the wellbore accumulates water to a certain extent, the well is shut down and enters the first stage, and the cycle continues.

[0003] At present, the plunger drainage gas production optimization design calculation method is mainly based on the foreign Foss-Gaul calculation model. Based on the Foss-Gaul model, China National Petroleum Corporation issued the "Plunger Gas Lift Technical Specification" (Enterprise Standard Q / SY01014-2017) on June 28, 2017, and the plunger drainage gas production optimization design calculation method was specified in this standard specification. Through the analysis of the relevant plunger lift drainage gas production optimization design calculation method in the "Plunger Gas Lift Technical Specification", it is found that there are three problems in its calculation model: ① The influence of water accumulation in the annulus of the casing in the plunger lift drainage gas production is ignored; ② The influence of plunger leakage in the plunger lift drainage gas production is ignored; ③ The influence of natural gas compression factor changes with temperature and pressure is ignored. Summary of the invention

[0004] The purpose of the present invention is to provide a plunger lifting drainage and gas production optimization design calculation method, which solves the technical problem that there is a large deviation between the existing plunger lifting drainage and gas production optimization design results and the actual application effect, resulting in the daily gas production of the plunger lifting drainage and gas production cannot be further optimized and improved.

[0005] Another aspect of the present invention provides a plunger lifting drainage gas production method, which solves the technical problem that the existing plunger lifting drainage gas production cannot further increase the daily gas production. Another aspect of the present invention provides a computer device, which solves the technical problem of the practical execution of the plunger lifting drainage gas production optimization design calculation method provided above. Another aspect of the present invention provides a computer readable storage medium, which solves the technical problem of the storage of the plunger lifting drainage gas production optimization design calculation method provided above.

[0006] The present invention is achieved through the following technical solutions:

[0007] One aspect of the present invention provides a plunger lifting drainage and gas production optimization design calculation method, comprising the following steps:

[0008] S1. Setting basic parameter information of plunger lifting, drainage and gas collection;

[0009] S2. Calculate the fluid distribution in the wellbore when the plunger is lifted upward based on the basic parameter information;

[0010] S3, preset the initial values ​​of the minimum flow pressure and the maximum flow pressure, calculate the water accumulation distribution in the wellbore when the plunger is lifted to the wellhead based on the wellbore fluid distribution, the preset minimum flow pressure and the maximum flow pressure according to the formation productivity equation, and then calculate the wellbore pressure distribution, the minimum flow pressure and the first wellbore gas volume when the plunger is lifted to the wellhead based on the wellbore water accumulation distribution and basic parameter information according to the natural gas state equation;

[0011] S4. According to the plunger lifting principle, based on the wellbore water accumulation distribution and the first wellbore gas volume, the wellbore pressure distribution, the maximum flow pressure and the second wellbore gas volume when the plunger lifting upward is started are calculated;

[0012] S5. Calculate the lifting gas volume and lifting gas-water ratio required for single drainage and gas production by the plunger according to the first wellbore gas volume, the second wellbore gas volume and the single drainage volume in the basic parameter information;

[0013] S6. Calculate the production flow pressure when shutting in the well according to the relationship between the lifting gas volume and the formation gas production corresponding to the single drainage volume;

[0014] S7. Calculate the daily gas production of plunger lifting drainage gas production based on the production flow pressure, and output the optimized daily gas production and optimization parameters.

[0015] Furthermore, when calculating the wellbore fluid distribution when the plunger is lifted upward based on the basic parameter information, it includes calculating the wellbore fluid distribution when the plunger is lifted upward based on the factors of water accumulation in the casing annulus and plunger leakage; when calculating the wellbore pressure distribution and the first wellbore gas volume when the plunger is lifted to the wellhead based on the wellbore water accumulation distribution and the basic parameter information according to the natural gas state equation, it includes calculating the wellbore pressure distribution and the first wellbore gas volume when the plunger is lifted to the wellhead based on the relationship between the natural gas compression factor, pressure and temperature.

[0016] Furthermore, before step S5, it also includes judging whether the minimum flow pressure or the maximum flow pressure is within the error range. If so, step S5 is executed. If not, the process returns to step S3 and starts execution, and the calculated minimum flow pressure and maximum flow pressure are set as initial values.

[0017] Further, in step S7, the daily gas production of plunger lifting drainage gas production is calculated based on the production flow pressure, including the following steps:

[0018] B1. Preset the continuous flow time, and calculate the formation gas and water production during the continuous flow period based on the continuous flow time, the production flow pressure when the well is shut in, and the minimum flow pressure according to the gas well productivity equation;

[0019] B2. Calculate the fluid distribution and pressure distribution in the wellbore when the well is shut in based on the formation gas production and water production during the period of continuous flow;

[0020] B3. Calculate the shut-in time, the formation gas production and water production during the shut-in period based on the wellbore pressure distribution and fluid distribution when the well is shut in and the wellbore pressure distribution and fluid distribution when the plunger is lifted and started;

[0021] B4. Calculate the daily gas and water production of plunger drainage gas production based on the formation gas and water production during the plunger upward movement, self-flowing and well shut-in periods.

[0022] Furthermore, before step B4, it also includes: calculating the formation water production of a single cycle of plunger drainage and gas production based on the formation water production during the self-flowing continuation period, the formation water production during the well shut-in period, and the formation water production during the plunger lifting and upward movement, and then calculating the difference between the formation water production of a single cycle of plunger drainage and gas production and the single drainage of the plunger, and judging whether the difference is less than the allowable error range, if so, executing step B4, if not, returning to step B1 to start execution.

[0023] Furthermore, before step S6, it also includes judging whether the gas-water ratio of the gas well formation is greater than the required lifting gas-water ratio, and whether the formation pressure is greater than the maximum flow pressure. If so, execute step S6; if not, return to step S1 to start execution.

[0024] Furthermore, before outputting the optimized daily gas production and related optimization parameters in step S7, it also includes calculating the difference between the daily gas production and the target gas production of the basic parameter information, and judging whether the difference is within the error range. If so, outputting the optimized daily gas production and optimization parameters; if not, returning to step S1 to start execution.

[0025] The second aspect of the present invention provides a plunger lifting drainage gas production method, including obtaining an optimized daily gas production and optimized parameters according to a plunger lifting drainage gas production optimization design calculation method provided by one aspect of the present invention, and performing gas production according to the optimized parameters.

[0026] A third aspect of the present invention provides a computer device, including a processor and a memory for storing processor executable instructions, wherein the processor is configured to execute a plunger lifting drainage and gas production optimization design calculation method provided in one aspect of the present invention.

[0027] A fourth aspect of the present invention provides a computer-readable storage medium, including a stored computer program, which, when running, executes a plunger lifting drainage and gas production optimization design calculation method provided in one aspect of the present invention.

[0028] Compared with the prior art, the present invention has the following advantages and beneficial effects:

[0029] The present invention provides a plunger lifting drainage and gas production optimization design calculation method. Compared with the existing plunger lifting drainage and gas production optimization method, in the plunger lifting drainage process, plunger leakage and formation water production and formation gas production are taken into account; in the calculation of wellbore water accumulation distribution, annular space water accumulation is taken into account; in the calculation of wellbore pressure distribution, the change of natural gas compression factor with temperature and pressure is taken into account. Therefore, the plunger lifting drainage and gas production optimization design method provided by the present invention is more in line with reality, and the results are more accurate and reliable, which is helpful to optimize the plunger drainage and gas production process parameters and help to increase the gas well production. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] In order to more clearly illustrate the technical solutions of the exemplary embodiments of the present invention, the following briefly introduces the drawings required for use in the embodiments. It should be understood that the following drawings only illustrate certain embodiments of the present invention and should not be regarded as limiting the scope. For those of ordinary skill in the art, other relevant drawings can be obtained based on these drawings without creative work. In the drawings:

[0031] Figure 1 The main process of the calculation algorithm for optimizing the design of plunger lifting drainage and gas production;

[0032] Figure 2 It is a schematic diagram of the fluid distribution and pressure distribution in the wellbore when the plunger is lifted upward;

[0033] Figure 3 A schematic diagram of the fluid distribution and pressure distribution in the wellbore when the plunger is lifted to the wellhead;

[0034] Figure 4 Schematic diagram of the fluid distribution and pressure distribution in the wellbore when the plunger is lifted to shut in the well. DETAILED DESCRIPTION

[0035] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with embodiments and drawings. The exemplary embodiments of the present invention and their description are only used to explain the present invention and are not intended to limit the present invention.

[0036] Embodiment 1: The present invention provides a plunger lifting drainage gas production optimization design calculation method, such as Figure 1-Figure 4 As shown, the following steps are included:

[0037] S1. Setting basic parameter information of plunger lifting for drainage and gas production, the basic parameter information includes formation production parameters, wellbore string parameters, plunger lifting parameters and optimization target parameters.

[0038] (1) Formation production parameters mainly include: reservoir depth Hr (meter), formation pressure Pr (MPa), formation temperature Tr (degrees Celsius), wellbore temperature gradient Tgradpm (degrees / meter), gas production index Cp (standard cubic meter / (MPa) 2 .day)), gas-water ratio Rgw (standard cubic meter / cubic meter).

[0039] (2) Wellbore string parameters mainly include: tubing inner diameter Dt (m), tubing inner diameter Dto (m), casing inner diameter Dc (m) and tubing foot depth Ht (m).

[0040] (3) The plunger lifting parameters include: plunger lifting additional force Pz (MPa), plunger lifting upward speed v (m / min), plunger downward speed vDownGas (m / min) in the gas of the tubing string, plunger downward speed vDownWater (m / min) in the liquid accumulation section of the tubing string, liquid loss rate VWaterLoss (m3 / min) through the plunger when the plunger is lifted, gas loss rate VGasLoss (standard m3 / min) through the plunger when the plunger is lifted, and RjyCT (dimensionless) ratio of the casing annulus above the tubing foot to the liquid accumulation height in the tubing.

[0041] (4) The optimization design parameters of plunger lift include: target daily gas production Qgpd (standard cubic meters / day), single displacement VwLift (cubic meters / time), drainage depth Hz (meters), and minimum production oil pressure Ptmin (MPa).

[0042] S2. Calculate the water accumulation distribution in the wellbore when the plunger is lifted upward based on the basic parameter information, such as Figure 2 When calculating the distribution of water accumulation in the wellbore, the amount of water accumulated in the annulus when the plunger starts to move upward and the amount of water lost during the plunger's upward movement are taken into account. The relevant calculations are as follows:

[0043] (1) Calculation of plunger upward time Tup (minutes):

[0044] Tup=Hz / vUp

[0045] (2) Calculation of gas loss VgLoss (standard square) during the upward lifting of the plunger:

[0046] VgLoss=TUp*QgLoss

[0047] (3) Calculation of water loss VwLoss (cubic meters) during the upward lifting of the plunger:

[0048] VwLoss=TUp*QwLoss

[0049] (4) Calculation of water depth HtJyUpStart (m) in the oil pipe:

[0050] HtJyUpStart=Hz-(VwLiftPt-VwLoss) / (3.14 / 4*Dti^2)

[0051] (5) Calculation of water accumulation depth HcJyUpStart (m) in the casing annulus:

[0052] HcJyUpStart=Ht-(Ht-HtJyUpStart)*RJyct

[0053] (6) Calculation of the water volume VwcJyUpStart (square) in the annulus of the oil casing on the oil pipe foot:

[0054] VwcJyUpStart=3.14 / 4*(Dci^2-Dto^2)*(Ht-HcJyUpStart)

[0055] S3. Preset the initial values ​​of the minimum flow pressure and the maximum flow pressure when the plunger is lifted. According to the formation productivity equation, the formation gas production and formation water production during the plunger's upward movement can be calculated, and then the water accumulation distribution in the wellbore when the plunger is lifted to the wellhead can be calculated, such as Figure 3 As shown, according to the set plunger lifting drainage gas production basic parameter information, the natural gas state equation (taking into account the relationship between the natural gas compression factor and pressure and temperature) can be used to calculate: the wellbore pressure distribution when the plunger is lifted to the wellhead, the minimum casing pressure, the minimum flow pressure and the first wellbore gas volume. The relevant calculations are as follows:

[0056] 1. Calculation of formation gas and water production during the upward movement of the plunger:

[0057] (1) Calculation of average production flow pressure PwfUpavg (MPa):

[0058] PwfUpavg=(PwfmaxSet+PwfminSet) / 2

[0059] Where PwfmaxSet is the preset maximum flow pressure (MPa);

[0060] PwfminSet is the preset minimum flow pressure (MPa).

[0061] (2) Calculation of formation gas production VgpUp (standard cubic meter):

[0062] VgpUp=C*(Pr^2-PwfUpavg^2)*Tup / 1440

[0063] (3) Calculation of formation water production VwpUp (cubic meters):

[0064] VwpUp=VgpUp / Rgw

[0065] 2. When the plunger moves upward to the wellhead, the distribution of water accumulation in the wellbore is calculated as follows:

[0066] (1) Calculation of the depth of the liquid on the plunger HtPyUpEnd (m):

[0067] HtPyUpEnd=VwLiftPt / (3.14 / 4*Dti^2)

[0068] (2) Calculation of water depth HtJyUpEnd (m) in the oil pipe:

[0069] HtJyUpEnd=HtJyUpStart-(VwcJyUpStart+VwLoss+VwpUp) / (3.14 / 4*Dti^2).

[0070] 3. When the plunger moves upward to the wellhead, the wellbore pressure distribution and gas volume are calculated, such as Figure 2 As shown:

[0071] (1) Calculation of the pressure PtGTopUpEnd (MPa) at the bottom of the plunger and the top of the oil pipe gas column:

[0072] PtGTopUpEnd=HtPyUpEnd*RdWater*9.8*10^(-3)+PfPy+Pzx+Ptmin.

[0073] Where PfPy (MPa) is the friction resistance of the water column above the plunger, which can be calculated using the relevant formula for pipe flow resistance. The relevant calculation formula is relatively complex, but very mature, and can be found in relevant textbooks, so this article will not list them in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0074] (2) Calculation of the bottom pressure of the gas column in the oil pipe PtGBottomUpEnd (MPa) and the gas volume of the gas column VgtUpEnd (standard cubic meter):

[0075] According to the state equation of natural gas (taking into account the characteristics of the natural gas compression factor changing with temperature and pressure), the pressure at the bottom of the gas column PtGBottomUpEnd (MPa) and the standard volume of the gas column in the oil pipe VgtUpEnd (standard cubic meter) can be calculated from the pressure at the top of the gas column in the oil pipe PtGTopUpEnd (MPa). The relevant calculation formula is relatively complicated, but very mature, and can be found in relevant textbooks. This article will not list it in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0076] (3) At this time, the bottom hole pressure is the minimum flow pressure Pwfmin (MPa) during the plunger drainage gas production process:

[0077] Pwfmin=(Hr-HtJyUpEnd)*RdWater*9.8*10^(-3)+PtGBottomUpEnd

[0078] (4) At this time, the pressure at the oil pipe foot is calculated as Pttmin (MPa):

[0079] Pttmin=((Ht-HtJyUpEnd)*RdWater*9.8*10^(-3)+PtGBottomUpEnd

[0080] (5) Calculation of minimum casing pressure Pcmin (MPa) and annular gas volume VgcUpEnd (standard cubic meter):

[0081] When the plunger moves up to the wellhead, the pressure Pttmin at the foot of the oil pipe is exactly the bottom pressure of the air column in the oil casing annulus. According to the state equation of natural gas (considering the characteristics of the natural gas compression factor changing with temperature and pressure), the top pressure of the annular air column (i.e., the minimum casing pressure) Pcmin (MPa) and the standard volume of the gas column in the annulus VgcUpEnd (standard volume) can be calculated from the bottom pressure of the annular air column Pttmin (MPa). The relevant calculation formula is relatively complicated, but very mature, and can be found in relevant textbooks. This article will not list them in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0082] S4. Based on the distribution of water accumulation in the wellbore when the plunger is lifted upward and the first wellbore gas volume when the plunger is lifted to the wellhead, according to the plunger lifting principle, the annular gas volume when the plunger is lifted upward can be calculated, and then: the wellbore pressure distribution, the maximum casing pressure value, the maximum flow pressure value and the second wellbore gas volume when the plunger is lifted upward can be calculated.

[0083] 1. When the plunger starts to move upward, the wellbore pressure distribution and gas volume calculation are as follows: Figure 2 As shown:

[0084] (1) Calculation of standard volume of oil sleeve annulus air VgcUpStart (standard volume):

[0085] According to the principle of plunger lifting and drainage gas production, the power to push the plunger upward comes from the expansion of the annular gas in the casing. Considering the influence of plunger leakage and formation gas production, the gas volume VgcUpStart (standard square) in the casing annular space when the plunger starts to move upward can be calculated, that is:

[0086] VgcUpStart=VgcUpEnd+VgtUpEnd+VgLoss-VgpUp

[0087] Where, VgcUpEnd and VgtUpEnd are the gas volume in the tubing and the annular gas volume when the plunger is lifted to the wellhead, respectively. The relevant calculations are as mentioned above. VgLoss and VgpUp are the plunger gas loss and formation gas production during the upward process of the plunger lifting, respectively. The relevant calculations are as mentioned above.

[0088] (2) Calculation of maximum casing pressure Pcmax (MPa) and annular air column bottom pressure PcGBottomUpStart (MPa):

[0089] According to the state equation of natural gas (taking into account the characteristics of the natural gas compression factor changing with temperature and pressure), the pressure at the top of the annular gas column (i.e., the maximum casing pressure) Pcmax (MPa) and the pressure at the bottom of the annular gas column PcGBottomUpStart (MPa) can be calculated from the annular gas column volume VgcUpStart (standard square). The relevant calculation formula is relatively complex, but very mature, and can be found in relevant textbooks. This article will not list them in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0090] (3) At this time, the pressure at the oil pipe foot is calculated as Pttmax (MPa):

[0091] Pttmax=((Ht-HcJyUpStart)*RdWater*9.8*10^(-3)+PcGBottomUpStart

[0092] (4) Calculation method of maximum flow pressure Pwfmax (MPa):

[0093] The bottom hole pressure when the plunger is lifted upward is the maximum flow pressure Pwfmax (MPa), which can be calculated based on the pressure Pttmax at the oil pipe foot, that is:

[0094] Pwfmax=(Hr-Ht)*RdWater*9.8*10^(-3)+Pttmax

[0095] (5) At this time, the calculation method of the pressure PtJyUpStart (MPa) at the water surface of the oil pipe is:

[0096] PtJyUpStart=Pttmax-(Ht-HtJyUpStart)*RdWater*9.8*10^(-3)

[0097] (6) Calculation of maximum oil pressure Ptmax (MPa) and gas volume in oil pipe VgtUpStart (standard square):

[0098] The pressure at the water surface of the oil pipe PtJyUpStart (MPa) is exactly the bottom pressure of the gas column in the oil pipe. According to the state equation of natural gas (considering the characteristics of the natural gas compression factor changing with temperature and pressure), the top pressure of the gas column (i.e., the maximum oil pressure) Ptmax (MPa) and the gas volume of the gas column VgtUpStart (standard square) can be calculated from the bottom pressure of the gas column in the oil pipe. The relevant calculation formula is relatively complicated, but very mature, and can be found in relevant textbooks. This article will not list it in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0099] 2. Before step S5, it also includes judging whether the minimum flow pressure or the maximum flow pressure is within the error range. If so, execute step S5. If not, return to step S3 to start execution, and set the calculated minimum flow pressure and maximum flow pressure as initial values. Since the calculation of the minimum flow pressure and the maximum flow pressure depends on the gas production and water production of the formation during the plunger lifting process, and the gas production and water production of the formation depend on the minimum flow pressure and the maximum flow pressure. Through repeated iterative calculations of steps S3 and S4, the minimum flow pressure and the maximum flow pressure can converge within the allowable error range.

[0100] 3. Pressure determination conditions for the feasibility of plunger lifting drainage and gas production:

[0101] According to the technical principle of plunger lifting drainage gas production, the gas volume in the wellbore when the well is shut in comes from the formation gas production. Therefore, the pressure determination condition for the feasibility of plunger lifting drainage gas production is proposed as follows:

[0102] Maximum flow pressure Pwfmax < formation pressure Pr

[0103] If the calculated result cannot meet the above conditions, it is necessary to adjust the basic parameter S1 of plunger lifting drainage and gas production, and repeat the calculation steps S2, S3, and S4 until the conditions are met.

[0104] S5. According to the gas volume of the second wellbore when the plunger is lifted upward and the gas volume of the first wellbore when the plunger is lifted to the wellhead, the required lifting gas volume for the plunger to drain gas once can be calculated, and then the required lifting gas-water ratio can be calculated;

[0105] (1) Calculation of the gas volume VgLift (standard cubic meter) required for plunger lifting and drainage:

[0106] VgLift=(VgcUpStart+VgtUpStart)-(VgcUpEnd+VgtUpEnd).

[0107] (2) Calculation of the lift gas-water ratio RgwLift (standard cubic meters / cubic meter) required for plunger lift to drain gas:

[0108] RgwLift=VgLift / VwpLift

[0109] (3) Determination conditions of the gas-water ratio for the feasibility of plunger lifting drainage and gas production:

[0110] Furthermore, it also includes judging whether the gas-water ratio of the gas well formation is greater than the required lifting gas-water ratio and whether the formation pressure is greater than the maximum production flow pressure. If so, execute step S6, otherwise return to step S1 to start execution. According to the technical principle of plunger lifting drainage gas production, the lifting gas volume of plunger lifting drainage gas production comes from formation gas production. At the same time, the formation will produce water while producing gas. In order to ensure the coordination of formation water production and wellbore drainage supply and drainage, the plunger lifting drainage gas production feasibility pressure judgment condition is proposed as follows:

[0111] Lifting gas-water ratio RgwLift< formation production gas-water ratio Rgw

[0112] If the calculated result cannot meet the above conditions, it is necessary to adjust the basic parameter S1 of plunger lifting drainage and gas production, and repeat the calculation steps S2, S3, S4, and S5 until the conditions are met.

[0113] S6. According to the relationship between the lifting gas-water ratio and the formation gas production corresponding to the single drainage volume, the production flow pressure PwfClose (MPa) when the well is closed can be calculated:

[0114] PwfClose=Pwfmax-VgLift / (VwpLift*Rgw)*(Pwfmax-Pwfmin)

[0115] S7. Based on the production flow pressure when the well is shut in, the formation production capacity equation is applied, and according to the plunger lifting principle, the following can be calculated: the duration of the self-flowing flow and the formation gas and water production during the flow period; the shut-in time and the formation gas and water production during the shut-in time, and then the daily gas production of the plunger lifting drainage gas production can be calculated. The specific calculation method is as follows:

[0116] B1. Preset the self-flowing continuous flow time Taf (minutes). Based on the production flow pressure PwfClose and the minimum flow pressure Pwfmin mentioned above when the well is shut in, and according to the gas well productivity equation, the formation gas production VgpAf (standard cubic meters) and water production VwpAf (cubic meters) during the self-flowing continuous flow period can be calculated;

[0117] (1) Calculation of formation gas production VgpAf (standard cubic meter) during self-flowing continuous flow:

[0118] VgpAf=C*(Pr^2-PwfAfavg^2)*Taf / 1440

[0119] Where PwfAfavg (MPa) is the average bottom flow pressure during the continuous flow period, which is calculated by the following formula:

[0120] PwfAfavg=(PwfClose+Pwfmin) / 2

[0121] (2) Calculation of formation water production VwpAf (cubic meters) during the period of continuous flow:

[0122] VwpAf=VgpAf / Rgw

[0123] B2. Calculate the wellbore pressure distribution and fluid distribution when shutting in based on the formation gas and water production, such as Figure 4 shown.

[0124] (1) Calculation of the depth of water accumulated on the tubing when the well is shut in (HtJyClose (m)):

[0125] HtJyClose=HtJyUpStart-VwpAf / (3.14 / 4*(Dti^2+RJyct*(Dci^2-Dto^2)))

[0126] (2) Calculation of the depth of water in the annulus when the well is closed HcJyClose (m):

[0127] HcJyClose=Ht-(Ht-HtJyUpStart)*RJyct

[0128] (3) Calculation of the pressure PtJyClose (MPa) at the water surface of the tubing when the well is shut in:

[0129] PtJyClose=PwfClose-(Hr-HtJyClose)*RdWater*9.8*10^(-3)

[0130] (4) When the well is shut in, the calculation of the shut-in oil pressure PtClose (MPa) and the gas volume VgtClose (standard cubic meters) in the oil pipe is:

[0131] When the well is shut in, the pressure at the water surface of the oil pipe PtJyClose (MPa) is exactly the pressure at the bottom of the gas column in the oil pipe. According to the state equation of natural gas (considering the characteristics of the natural gas compression factor changing with temperature and pressure), the pressure at the top of the gas column (i.e. the shut-in oil pressure) PtClose (MPa) and the gas volume VgtClose (standard cubic meter) can be calculated from the pressure at the bottom of the gas column in the oil pipe. The relevant calculation formula is relatively complicated, but very mature, and can be found in relevant textbooks. This article will not list them in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0132] (5) Calculation of the pressure PcJyClose (MPa) at the annular water surface when the well is closed:

[0133] PcJyClose=PwfClose-(Hr-HcJyClose)*RdWater*9.8*10^(-3)

[0134] (6) When the well is shut in, the calculation of the shut-in casing pressure PcClose (MPa) and the gas volume in the annulus VgcClose (standard cubic meters):

[0135] When the well is shut in, the pressure at the water surface of the annulus PcJyClose (MPa) is exactly the bottom pressure of the gas column in the annulus. According to the state equation of natural gas (considering the characteristics of the natural gas compression factor changing with temperature and pressure), the top pressure of the gas column (i.e. the shut-in casing pressure) PcClose (MPa) and the gas volume of the gas column VgcClose (standard cubic meter) can be calculated from the bottom pressure of the gas column in the annulus. The relevant calculation formula is relatively complicated, but very mature, and can be found in relevant textbooks. This article will not list them in detail. Relevant textbooks include: "Gas Production Engineering Handbook (Natural Gas Engineering Handbook)", edited by Zhang Shouliang, Ma Faming, and Xu Yonggao, Petroleum Industry Press: Beijing, 2016.

[0136] B3. Based on the wellbore pressure distribution and fluid distribution when the well is shut in, and the wellbore pressure distribution and fluid distribution when the plunger lift is started, the shut-in time, the formation gas production and the formation water production during the shut-in period can be calculated.

[0137] (1) Calculation of formation gas production VgpClose (standard square) during the well closing period:

[0138] VgpClose=(VgcUpStart+VgtUpStart)-(VgcClose+VgtClose)

[0139] (2) Calculation of formation water production VwpClose (cubic meters) during the well closure period:

[0140] VwpClose=VgpClose / Rgw

[0141] (3) Calculation of closing time Tclose (minutes):

[0142] Tclose=1440*VgpClose / C / (Pr^2-PwfCloseavg^2)

[0143] Where PwfCloseavg (MPa) is the average flow pressure during the well closing period, which can be calculated by the following formula:

[0144] PwfCloseavg=(Pwfmax+PwfClose) / 2

[0145] Furthermore, the sum of the formation water production during the upward period of the plunger lifting, the formation water production during the self-flowing continuous flow, and the formation water production during the shut-in period is calculated, that is, the formation water production of a single cycle of plunger drainage and gas production. If the difference between the formation water production of a single cycle of plunger drainage and gas production and the plunger single drainage is greater than the allowable error range, it is necessary to adjust the self-flowing continuous flow time of step B1, and recalculate steps B1, B2, and B3 until the aforementioned difference is less than the allowable error range.

[0146] (1) Calculate the single-cycle formation water production VwpCal (cubic meters) of plunger drainage gas production:

[0147] VwpCal=VwpUp+VwpAf+VwpClose

[0148] (2) Compare the calculated single-cycle formation water production VwpCal with the single-time drainage VwLift. If the two do not match, it is necessary to adjust the self-flow continuation time and recalculate B1, B2, and B3 until the two are completely consistent.

[0149] B4. Based on the plunger upward time, the self-flowing continuation time, the well shut-in time, as well as the formation production during the plunger upward process, the formation production during the self-flowing continuation period, and the formation production during the well shut-in period, the daily gas production and water production of the plunger drainage gas production can be calculated.

[0150] Furthermore, before outputting the optimized daily gas production and optimized parameters in step S7, it also includes calculating the difference between the daily gas production and the target gas production of the basic parameter information, and judging whether the difference is within the error range. If so, the optimized daily gas production and optimized parameters are output; if not, the process returns to step S1 to start execution, that is, if the calculated daily gas production deviates from the target daily gas production, it is necessary to adjust the set basic parameter S1, recalculate S1, S2, S3, S4, S5, S6, and S7 until the calculated daily gas production is consistent with the target daily gas production, and then output the optimized daily gas production and optimized parameters. The optimized parameters include: drainage depth, single drainage volume of plunger drainage and gas production, plunger lifting upward time, self-flowing continuous flow time, and shut-in time; minimum casing pressure, maximum casing pressure; minimum flow pressure, shut-in flow pressure, and maximum flow pressure; formation production during upward period, formation production during self-flowing continuous flow period, and production during shut-in time; daily gas production, daily water production, and the like.

[0151] (1) Calculate the daily gas production of plunger drainage gas production QgpdCal (standard cubic meters / day):

[0152] QgpdCal=(VgpUp+VgpAf+VgpClose) / (Tup+Taf+Tclose)*1440

[0153] (2) Calculate the daily water production of plunger drainage gas production QwpdCal (cubic meters / day):

[0154] QwpdCal=QgpdCal / Rgw

[0155] (3) Compare the calculated daily gas production QgpdCal with the target gas production Qgpd. If the two do not match, it is necessary to adjust the set basic parameter S1 and recalculate S1, S2, S3, S4, S5, S6, and S7 until the calculated daily gas production matches the target daily gas production.

[0156] Embodiment 2: The present invention also provides a computer device, including a processor and a memory for storing processor executable instructions, wherein the processor is configured to execute a plunger lifting drainage and gas production optimization design calculation method, and the computer device may be a desktop computer, a notebook, a PDA, a cloud server, etc.

[0157] Example 3: The present invention also provides a computer-readable storage medium, including a stored computer program, which, when running, executes a plunger lifting drainage and gas production optimization design calculation method in the above-mentioned Example 1. The computer-readable storage medium may include a high-speed random access memory, and may also include a non-volatile memory, such as a hard disk, a memory, a plug-in hard disk, a smart memory card (Smart Media Caed, SMC), a secure digital (Secure Digital, SD) card, a flash card (Flash Card), at least one disk storage device, a flash memory device, or other volatile solid-state storage devices.

[0158] The specific implementation methods described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific implementation method of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A plunger lifting drainage gas production optimization design calculation method, characterized in that: The steps include: S1. Setting basic parameter information of plunger lifting for drainage and gas production, the basic parameter information including formation production parameters, wellbore string parameters, plunger lifting parameters and optimization target parameters; S2. Calculate the fluid distribution in the wellbore when the plunger is lifted upward based on the basic parameter information; S3, preset the initial values ​​of the minimum flow pressure and the maximum flow pressure, calculate the water accumulation distribution in the wellbore when the plunger is lifted to the wellhead based on the wellbore fluid distribution, the preset minimum flow pressure and the maximum flow pressure according to the formation productivity equation, and then calculate the wellbore pressure distribution, the minimum flow pressure and the first wellbore gas volume when the plunger is lifted to the wellhead based on the wellbore water accumulation distribution and basic parameter information according to the natural gas state equation; S4. According to the plunger lifting principle, based on the wellbore water accumulation distribution and the first wellbore gas volume, the wellbore pressure distribution, the maximum flow pressure and the second wellbore gas volume when the plunger lifting upward is started are calculated; S5. Calculate the lifting gas volume and lifting gas-water ratio required for single drainage and gas production by the plunger according to the first wellbore gas volume, the second wellbore gas volume and the single drainage volume in the basic parameter information; S6. Calculate the production flow pressure when shutting in the well according to the relationship between the lifting gas volume and the formation gas production corresponding to the single drainage volume; S7, calculating the daily gas production of plunger lifting drainage gas production based on the production flow pressure, and outputting the optimized daily gas production and optimization parameters; Among them, when calculating the wellbore fluid distribution when the plunger is lifted upward according to the basic parameter information, it includes calculating the wellbore fluid distribution when the plunger is lifted upward based on the factors of water accumulation in the casing annulus and plunger leakage; when calculating the wellbore pressure distribution and the first wellbore gas volume when the plunger is lifted to the wellhead based on the wellbore water accumulation distribution and the basic parameter information according to the natural gas state equation, it includes calculating the wellbore pressure distribution and the first wellbore gas volume when the plunger is lifted to the wellhead based on the relationship between the natural gas compression factor and the pressure and temperature. Furthermore, before performing step S6, it is also included to determine whether the gas-water ratio of the gas well formation is greater than the required lifting gas-water ratio, and whether the formation pressure is greater than the maximum flow pressure. If so, execute step S6; if not, return to step S1 to start execution.

2. The plunger lifting drainage and gas production optimization design calculation method according to claim 1 is characterized in that: Before step S5, it also includes judging whether the minimum flow pressure or the maximum flow pressure is within the error range. If so, step S5 is executed. If not, the process returns to step S3 and starts execution, and the calculated minimum flow pressure and maximum flow pressure are set as initial values.

3. The plunger lifting drainage and gas production optimization design calculation method according to claim 1 is characterized in that: In step S7, the daily gas production of plunger lifting drainage gas production is calculated based on the production flow pressure, including the following steps: B1. Preset the continuous flow time, and calculate the formation gas and water production during the continuous flow period based on the continuous flow time, the production flow pressure when the well is shut in, and the minimum flow pressure according to the gas well productivity equation; B2. Calculate the fluid distribution and pressure distribution in the wellbore when the well is shut in based on the formation gas production and water production during the period of continuous flow; B3. Calculate the shut-in time, the formation gas production and water production during the shut-in period based on the wellbore pressure distribution and fluid distribution when the well is shut in and the wellbore pressure distribution and fluid distribution when the plunger is lifted and started; B4. Calculate the daily gas and water production of plunger drainage gas production based on the formation gas and water production during the plunger upward movement, self-flowing and well shut-in periods.

4. The plunger lifting drainage and gas production optimization design calculation method according to claim 3 is characterized in that: Before step B4, it also includes: calculating the formation water production of a single cycle of plunger drainage and gas production based on the formation water production during the self-flowing continuation period, the formation water production during the well shut-in period, and the formation water production during the plunger lifting and upward period, and then calculating the difference between the formation water production of a single cycle of plunger drainage and gas production and the single drainage of the plunger, and judging whether the difference is less than the allowable error range, if so, executing step B4, if not, returning to step B1 to start execution.

5. The plunger lifting drainage and gas production optimization design calculation method according to claim 1 is characterized in that: Before outputting the optimized daily gas production and optimized parameters in step S7, the process also includes calculating the difference between the daily gas production and the target gas production of the basic parameter information, and judging whether the difference is within the error range. If so, the process outputs the optimized daily gas production and optimized parameters; if not, the process returns to step S1 to start execution.

6. A plunger lifting drainage and gas production method, characterized in that: According to the plunger lifting drainage gas production optimization design calculation method described in any one of claims 1 to 5, the optimized daily gas production and optimized parameters are obtained, and gas production is carried out according to the optimized parameters.

7. A computer device, characterized in that: It includes a processor and a memory for storing processor executable instructions, and the processor is configured to execute a plunger lifting drainage and gas production optimization design calculation method as described in any one of claims 1-5.

8. A computer-readable storage medium, characterized in that: It includes a stored computer program, which, when running, executes a plunger lifting drainage and gas production optimization design calculation method as described in any one of claims 1 to 5.

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