Method and system for optimizing deep coal and rock gas horizontal well pressure back mining working system

Abstract

The invention discloses a deep coal and rock gas horizontal well pressure drainage working system optimization method and system, and the method comprises the steps: building a dynamic relation between the pressure drop and the flow of an oil nozzle based on a Gilbert model, and predicting the change of the gas-water ratio at different stages in combination with a double logarithmic segmentation fitting formula of the flow-back rate and the gas-water ratio; constructing a fracture quasi-steady-state flowing substance balance equation, and deducing an inflow dynamic curve of the flowing bottomhole pressure and the water yield; a Gray multiphase flow model is adopted to calculate the wellbore pressure gradient, and an outflow dynamic curve of the flowing bottomhole pressure and the liquid production capacity is generated; a reservoir, a shaft and an oil nozzle pressure system are coupled through a node system analysis method, an inflow-outflow coordination point is matched, and the size range of the oil nozzle is dynamically optimized. The method realizes accurate prediction and real-time regulation and control of drainage and mining parameters, solves the problem of rapid attenuation of fracture conductivity caused by high stress sensitivity of coal rocks, reduces the risk of pulverized coal blockage, improves the gas recovery efficiency, and is suitable for efficient development of deep coal rock gas wells.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development engineering, and particularly relates to a method and system for optimizing the production work system after pressure relief in horizontal wells of deep coalbed methane. Background Art

[0002] As a strategic replacement resource for the stable production and increase of natural gas, deep coalbed methane has a resource volume of several trillion cubic meters and great development potential. However, due to the characteristics of low pressure, low permeability, and low saturation commonly existing in deep coalbed methane reservoirs, traditional coalbed methane development technologies and production systems are difficult to be directly applicable. This is mainly reflected in the following aspects:

[0003] Deep coalbed methane reservoirs have the characteristics of "dual pore structure and two gas occurrences". Conventional reservoir stimulation and production methods are difficult to achieve efficient gas desorption and stable gas production in such reservoirs. Since most deep coalbed methane wells adopt large-scale fracturing horizontal well technology, the fracture network and the contact area with the reservoir are relatively limited, resulting in significant differences in gas production rules between deep coalbed methane wells and traditional coalbed methane wells.

[0004] The current production system mainly divides the production process based on indicators such as drainage volume, gas production volume, water production volume, and pressure, such as the stage from drainage and pressure reduction to before gas production, the gas-liquid two-phase flow stage, the gas well stable production stage, and the gas well depletion stage. Although this method can reflect production dynamics to a certain extent, for deep coalbed methane wells, due to the complex interaction among the wellbore, choke, and reservoir and the fracture seepage effect, the existing stage division and control measures have deficiencies and are difficult to accurately predict the bottom hole pressure and daily gas production volume.

[0005] In the prior art, the division of production stages and corresponding pressure reduction control are proposed, but the optimal configuration of the wellbore and choke is not fully considered, nor is the influence of reservoir fracture seepage on the flowback process. In addition, most methods rely on empirical data or single indicators, and it is difficult to construct an integrated model of the reservoir, wellbore, and choke, resulting in large deviations when coordinating the inflow and outflow dynamics, which restricts the long-term stable high production of deep coalbed methane wells.

[0006] Therefore, in order to improve the development efficiency and production capacity stability of deep coalbed methane wells, it is urgent to develop a new production work system that considers reservoir fracture seepage and the dynamic coupling of the wellbore and choke. By establishing an integrated model of choke - wellbore - reservoir and using the nodal system analysis method to achieve coordinated control of the inflow and outflow processes, a more scientific and reasonable production design and optimization basis can be provided for deep coalbed methane wells. Summary of the Invention

[0007] Aiming at the defects of the prior art, the present invention provides a method and system for optimizing the production work system after pressure relief in horizontal wells of deep coalbed methane.

[0008] To achieve the above invention objectives, the technical solution adopted by the present invention is as follows:

[0009] An optimization method for the production work system after pressure drainage in horizontal wells of deep coalbed methane includes the following steps:

[0010] Step 1: Establish a choke model based on well data and fluid mechanics principles. Determine the gas-water ratio at different flowback stages by fitting the relationship between the flowback rate and the gas-water ratio, and calculate the relationship curve between the choke pressure drop and the flow rate.

[0011] Step 2: Establish a pseudo-steady state flow material balance equation for the fracture system, and derive the inflow performance curve of the bottom-hole flowing pressure and the daily water production by combining the linear flow and radial flow diffusion equations.

[0012] Step 3: Use a multiphase flow wellbore flow model to calculate the bottom-hole flowing pressure at different liquid production rates, and establish an outflow performance curve for the wellbore.

[0013] Step 4: Couple the reservoir, wellbore, and choke pressure systems, conduct inflow-outflow coordination analysis with the bottom hole as the node, match the coordination points under different choke sizes through the nodal system analysis method, and determine the optimal choke size range based on pressure decline and cumulative gas production assessment.

[0014] Furthermore, the specific content of Step 1 includes:

[0015] Step 1.1: Use the Gilbert model to fit the relationship equation between the production rate, wellhead pressure, and choke size:

[0016]

[0017] where q w is the water production; P wh is the wellhead pressure; D 64 is the choke size; GLR is the gas-water ratio; a, b, c, and d are the parameters of the formula.

[0018] Step 1.2: Establish a double logarithmic piecewise fitting relationship between the flowback rate and the gas-water ratio, and obtain the gas-water ratio prediction formula at different flowback stages through piecewise regression.

[0019] Step 1.3: Calculate the two-phase flow choke pressure drop by combining the Chisholm model corrected for the slip effect.

[0020] Furthermore, the specific content of Step 2 includes:

[0021] Step 2.1: Define the dimensionless pressure parameter RNP and the cumulative water production parameter MBT:

[0022]

[0023]

[0024] Among them, P i represents the original formation pressure, and P wf represents the bottom-hole flowing pressure, and Q w represents the water production rate.

[0025] Step 2.2, establish the material balance equation for the pseudo-steady state flow of fractures:

[0026]

[0027] Among them, C t represents the comprehensive compressibility, V p represents the fracture pore volume, and t represents time;

[0028] Step 2.3, determine the slope of the inflow performance curve at different flowback rates through fitting the PNR-LR relationship curve.

[0029] Furthermore, the specific steps of step 3 include:

[0030] Step 3.1, calculate the liquid holdup using the Gray multiphase flow model:

[0031]

[0032] Among them, H l represents the liquid holdup, dimensionless, representing the proportion of the liquid volume in the total fluid volume in the pipeline, ranging from 0 to 1, υ sg represents the superficial gas velocity, and υ sl represents the superficial liquid velocity;

[0033] Step 3.2, establish the wellbore pressure gradient equation:

[0034]

[0035] Among them, ρ m represents the mixture density, g represents the acceleration due to gravity, θ represents the pipeline inclination angle, f represents the Darcy friction factor, and υ m represents the mixture flow velocity, and D represents the inner diameter of the pipeline;

[0036] Obtain the bottom-hole flowing pressure distribution curve at different liquid production rates through iterative calculation.

[0037] Furthermore, the specific steps of step 4 include:

[0038] Step 4.1, establish a coordination point matching model for the inflow performance curve and the outflow performance curve at the bottom-hole node;

[0039] Step 4.2, plot the pressure-production coordination curves at different choke sizes and determine the choke size optimization chart;

[0040] Step 4.3, combine the relationship between the flowback rate and the logarithm of time to predict the cumulative gas production curves for different nozzle sizes.

[0041] Further, the optimization of the nozzle size specifically includes:

[0042] Step 5.1, when the flowback rate is in the range of 0.5 - 0.6, the nozzle size and the pressure drop at the coordination point satisfy:

[0043] ΔP 8mm -ΔP 10mm < 1MPa

[0044] Step 5.2, the nozzle size corresponding to the inflection point of the cumulative gas production curve is the optimal value.

[0045] The present invention also discloses an optimization system for the post - fracturing production work system of deep coal - rock gas horizontal wells. This system can be used to implement the above - mentioned optimization method for the post - fracturing production work system of deep coal - rock gas horizontal wells. Specifically, it includes:

[0046] Nozzle dynamic modeling module: Based on the wellhead pressure sensor, nozzle size parameters, and gas - water ratio monitoring data, establish a dynamic relationship model between the nozzle pressure drop and the flow rate by fitting the double - logarithm segmented relationship between the flowback rate and the gas - water ratio.

[0047] Fracture dynamic analysis module: Calculate the pseudo - steady - state flow parameters of the fracture system through the material balance equation and the diffusion equation, combined with the formation pressure sensor data.

[0048] Wellbore multiphase flow calculation module: Adopt the Gray multiphase flow model, combined with the wellbore inclination angle sensor and gas - liquid flow rate monitoring data, calculate the liquid holdup and the wellbore pressure gradient, and generate the outflow dynamic curve of the bottom - hole flowing pressure and the liquid production rate.

[0049] Nozzle - reservoir coupling optimization module: Take the bottom - hole as the node, and match the coordination point of the inflow dynamic curve and the outflow dynamic curve through the node system analysis algorithm.

[0050] Based on the relationship between the flowback rate and the logarithm of time, predict the cumulative gas production curves for different nozzle sizes.

[0051] Output the optimal nozzle size range and the corresponding pressure control threshold.

[0052] The present invention also discloses a computer device, including a memory, a processor, and a computer program stored on the memory and executable on the processor. When the processor executes the program, it implements the above - mentioned optimization method for the post - fracturing production work system of deep coal - rock gas horizontal wells.

[0053] The present invention also discloses a computer - readable storage medium, on which a computer program is stored. When the program is executed by a processor, it implements the above - mentioned optimization method for the post - fracturing production work system of deep coal - rock gas horizontal wells.

[0054] Compared with the prior art, the advantages of the present invention are as follows:

[0055] 1. Achieve precise design of the drainage and production system: By coupling the reservoir fracture seepage model, the wellbore multiphase flow model, and the choke dynamic pressure drop model, an integrated analysis framework is established, breaking through the limitations of the traditional method of analyzing each link in isolation, and significantly improving the accuracy and adaptability of the prediction of drainage and production parameters.

[0056] 2. Dynamically optimize the choke control strategy: Based on the nodal system analysis method, the liquid supply capacity of the reservoir and the drainage efficiency of the wellbore are matched in real time, the choke size is intelligently adjusted, the high gas production demand and reservoir pressure protection are balanced, and the fracture closure or gas escape caused by improper drainage rate is avoided.

[0057] 3. Effectively reduce the risk of coal powder plugging: By combining the staged water injection dilution process of gas-liquid two-phase flow and the dynamic calculation model of liquid holdup, the sand-carrying capacity of the wellbore fluid is optimized, problems such as pump sticking and equipment wear caused by coal powder aggregation are reduced, and the operation stability of the system is improved.

[0058] 4. Extend the effective period of fracture conductivity: By accurately controlling the bottom-hole flow pressure drop rate through the fracture pseudo-steady state flow model, suppressing the coal-rock stress sensitivity effect, maintaining the fracture network conductivity, and extending the stable production period of the gas well.

[0059] 5. Improve the comprehensive recovery rate of dual gases: Based on the segmented fitting relationship between the flowback rate and the gas-water ratio, the release processes of adsorbed gas and free gas are differentially regulated, the desorption-seepage synergistic mechanism is optimized, and the efficient development of coal-rock gas resources is realized.

[0060] 6. Reduce the comprehensive development and operation and maintenance costs: By dynamically optimizing the choke size, the frequency of manual intervention is reduced. Combining with the strategy of compressing the ineffective drainage time, the equipment maintenance, energy consumption, and manual management costs are reduced.

[0061] 7. Enhance the adaptability to complex reservoirs: Aiming at the characteristics of deep coal-rock gas reservoirs with low pressure, low permeability, and high stress sensitivity, a customized drainage and production system design method is provided to solve the problem of production capacity prediction deviation caused by physical property differences in conventional technologies.

[0062] 8. Be compatible with the requirements of various well structures: Support the drainage and production optimization of different completion methods such as horizontal wells, multi-branch wells, and vertical wells. The system modular design can be flexibly integrated into the existing intelligent drainage and production control platform without large-scale hardware transformation.

[0063] 9. Improve the environmental protection benefits of green development: By optimizing the choke blowdown system and real-time monitoring of pressure, methane escape and fracturing fluid residue pollution are reduced, promoting the low-carbon and sustainable development of clean energy.

[0064] 10. Strengthen the whole-cycle safety production guarantee: Establish an early warning mechanism for abnormal fluctuations in bottom-hole pressure, and combine multi-source data fusion analysis technology to identify risks such as wellbore blockage and reservoir damage in advance, ensuring the safety and controllability of the drainage operation. Description of the Drawings

[0065] Figure 1 It is a flowchart of the optimization method for the post-drainage work system of horizontal wells in deep coalbed methane of the embodiment of the present invention.

[0066] Figure 2 It is a physical model diagram of nozzle flow of the embodiment of the present invention.

[0067] Figure 3 It is a diagram showing the relationship between nozzle pressure drop and flow rate under different nozzle sizes in the embodiment of the present invention.

[0068] Figure 4 It is a comparison diagram between the calculation results of the nozzle flow model and actual data in the embodiment of the present invention. The dotted line in the figure is y = x.

[0069] Figure 5 It is a double-logarithmic stage division diagram of the backflow rate and gas-water ratio of Well NL1 in the embodiment of the present invention;

[0070] Figure 6 It is a fitting relationship diagram between the backflow rate and gas-water ratio in Stage 1 of Well NL1 in the embodiment of the present invention;

[0071] Figure 7 It is a fitting relationship diagram between the backflow rate and gas-water ratio in Stage 2 of Well NL1 in the embodiment of the present invention;

[0072] Figure 8 It is a diagram showing the relationship between the flow rate and the wellhead pressure outflow curve under different nozzle sizes in the embodiment of the present invention;

[0073] Figure 9 It is a comparison diagram of fitting RNP and MBT in the embodiment of the present invention;

[0074] Figure 10 It is a comparison diagram of fitting PNR and LR in the embodiment of the present invention;

[0075] Figure 11 It is an inflow performance curve diagram under different backflow rates in the embodiment of the present invention;

[0076] Figure 12 It is a relationship curve diagram between the bottom-hole flowing pressure and the liquid production under gas-liquid two-phase flow conditions in the embodiment of the present invention;

[0077] Figure 13 It is a theoretical nodal method to determine the coordinated production capacity curve diagram in the embodiment of the present invention;

[0078] Figure 14 It is a typical diagram for optimizing the nozzle size under gas-liquid two-phase flow conditions in the embodiment of the present invention.

[0079] Figure 15 is the pressure drop change diagram under different nozzle sizes in the embodiments of the present invention;

[0080] Figure 16 is the cumulative gas production change diagram under different nozzle sizes in the embodiments of the present invention. Detailed implementation manners

[0081] To make the objectives, technical solutions and advantages of the present invention clearer and more understandable, the following further describes the present invention in detail with reference to the drawings and by way of examples.

[0082] The present invention provides an optimization method for the production work system after pressure drainage of deep coalbed methane horizontal wells, as Figure 1 shown, the method includes:

[0083] Step 101, based on well data and fluid mechanics principles, establish the fitting relationship between the fluid return rate and the gas-water ratio and the nozzle model for different fluid return stages to describe the process of the outflow dynamics of the nozzle, and determine the outflow curve relationship between the flow rate and the wellhead pressure.

[0084] Step 102, establish the diffusion equation and boundary conditions for linear flow and radial flow in the fracture system, and combine the material balance to form the flowing material balance equation in the quasi-steady state stage in the fracture, and determine the inflow IPR curve relationship.

[0085] Step 103, according to data and fluid mechanics principles, establish a multiphase flow wellbore flow model to describe the outflow dynamics process of the wellbore during the production drainage stage, and combine the IPR curve to determine the relationship curve between the bottom-hole flowing pressure and the liquid production rate.

[0086] Step 104, couple the pressures of the reservoir, wellbore and nozzle, establish an integrated model of the production drainage nozzle-wellbore-reservoir, use the nodal system analysis method, take the bottom hole as the node for inflow and outflow analysis, and optimize the optimal nozzle range. Among them, the inflow dynamics is mainly the flowing material balance model of the fracture system, and the outflow is divided into two parts, namely the nozzle and wellbore flow models established above. Use the integrated model to determine the inflow and outflow curves of various nozzles under different fluid return rates, find the coordination point under this fluid return rate to predict the bottom-hole pressure and daily water production under this fluid return rate, and combine the gas-water ratio to determine the daily gas production under this fluid return rate, and obtain the evaluation of the production drainage system of deep coalbed methane wells.

[0087] (1) The specific method for establishing the nozzle model in Step 101 to determine the outflow curve relationship between the flow rate and the wellhead pressure is as follows:

[0088] The physical model is as Figure 2As shown, the nozzle flow process can be divided into two stages. The first stage starts from position ① and ends at position ②, corresponding to the sudden contraction device; the second stage starts from position ② and ends at position ③, corresponding to the sudden expansion device. Here, position ① represents the upstream point of the nozzle flow, position ② represents the throat of the nozzle flow, position ③ represents the downstream of the nozzle flow (i.e., the pressure recovery point), and position B represents the outlet position of the nozzle flow.

[0089] For the first part, according to the principle of force balance:

[0090] -Adp = Mdu e (1)

[0091] -dp = Gdu e (2)

[0092] Substituting the equivalent velocity in the presence of slippage into the above equation gives:

[0093] -ν e dep = u e du e (3)

[0094] Integrating the above equation gives:

[0095]

[0096] In the formula, the subscripts 1 and 2 respectively represent Figure 1 the cross-sectional positions in

[0097] Neglecting u e1 , the above equation can be changed to:

[0098]

[0099] In the formula, σ = A2 / A1

[0100] The fluid flows from position ① through the throttling of the nozzle to position ②, and then through the suddenly expanding pipe section to position ③. For the fluid flow from position ② to position ③, applying the principle of force balance gives the following equation:

[0101]

[0102] where A3 is the cross-sectional flow area of the pipe section downstream of the nozzle, m 2 .

[0103] When the fluid in the nozzle is in the critical flow state, the outlet pressure p B of the nozzle and the throat pressure p2 are in different pressure systems, that is, p2 ≠ p B , p B is a free variable; when the fluid in the nozzle is in the subcritical state, the outlet pressure p of the nozzleB In the same pressure system as the throat pressure p2, i.e., p2 = p B .

[0104] From the above equation, the recovery pressure is obtained as follows:

[0105]

[0106] When flowing through the choke, the flow rates of the gas-liquid mixture both increase, but the gas velocity increases significantly faster than the liquid, resulting in the liquid being retained behind the gas, which causes the slippage phenomenon. After researching relevant literature, the Chisholm model is used to calculate the slippage factor.

[0107]

[0108] Using the gas-liquid two-phase choke flow model in the middle stage of flowback, the pressure drop curves at different flow rates of typical wells are calculated, as Figure 3 shown. Under the conditions of gas-liquid two-phase flow, the pressure drop across the choke is nearly linearly positively correlated with the flow rate.

[0109] The Gilbert model is selected for fitting the relationship between the wellhead pressure and the choke:

[0110]

[0111] where q w is the water production, m 3 / d; P wh is the wellhead pressure, MPa; D 64 is the choke size, mm; GLR is the gas-water ratio, m 3 / m 3 ; a, b, c, and d are the parameters of the formula.

[0112] Using the Gilbert model to fit the relationship between the production, wellhead pressure, and choke, the values of the four fitting parameters a, b, c, and d are determined. The calculated liquid production results of the above choke model are compared with the actual liquid production results. The fixed choke data during the 8-hour drainage period are screened, and a total of 3856 data points are obtained, and the fitting effect is good (R 2 reaches above 0.9), as Figure 4 shown.

[0113] Therefore, it is determined that a = 510.9; b = 0.7983; c = 0.8897; d = 0.863;

[0114] According to the above choke model, the fitting relationship between the wellhead pressure and the choke is determined:

[0115]

[0116] Substituting the fitting parameters, we get

[0117]

[0118] The specific method for obtaining the outflow curve relationship between flow rate and wellhead pressure based on the choke flow model is as follows:

[0119] 1) Use the gas-water ratio and flowback rate data in the early stage of production to fit the relationship between the gas-water ratio and the flowback rate. However, it should be noted that there are cases where gas lift exists in some wells or the gas-water ratio has a multi-stage situation. Therefore, the change trend of the gas-water ratio should be monitored in real time. For example, Figure 5 As shown, after the string was run in the NL1 well, the gas-water ratio changed significantly, and there were two stages showing an upward trend;

[0120] 2) Fit the relationship between the flowback rate and the gas-water ratio in these two stages to obtain the fitting formulas ( Figure 6 and Figure 7 ), and determine the gas-water ratio at each flowback rate for fitting;

[0121] 3) Using the gas-water ratio fitting formula, the gas-water ratio at a given flowback rate can be estimated, and further the daily gas production at different liquid production rates can be calculated. From the choke model, the wellhead pressure at different chokes corresponding to the liquid production and gas-water ratio at this flowback rate can be determined. Using the wellbore model, the bottom-hole pressure at different liquid production rates can be calculated. The calculation results of the outflow curve with a flowback rate of 0.5 are shown in Figure 8 as follows;

[0122] (2) The specific method for establishing the fracture pseudo-steady state model to obtain the inflow IPR curve described in step 102 is as follows:

[0123] Establish the diffusion equation and boundary conditions for linear flow and radial flow in the fracture system, and combine the material balance to form the flow material balance equation in the pseudo-steady state stage within the fracture. The premise for the derivation of the radial flow and linear flow models is that the gas well adopts a constant water production mode during the flowback stage. However, during flowback, the blowout method is mostly used for production, and the water production cannot be kept constant. At this time, it is necessary to establish a seepage mathematical model for variable production rate production of the gas well and when the flow enters the boundary control flow stage.

[0124] Perform dimensionless processing on the pressure solutions of the radial flow and linear flow models, and respectively obtain:

[0125]

[0126] The dimensionless forms used include:

[0127]

[0128] Analysis shows that regardless of the shape of the fracture, the dimensionless pressure can be written as:

[0129] p fD = Mt DTaking the Laplace transform of equation (16) and combining with Duhamel's principle, we get:

[0130]

[0131] Different from the pressure change law, with the passage of time, the water production rate decreases exponentially. Integrating the water production rate gives the cumulative water production as:

[0132]

[0133] Equation (18) is further simplified to:

[0134]

[0135] Similarly, for linear flow, then:

[0136]

[0137] Define two variables:

[0138]

[0139]

[0140] Combining the material balance method of liquid-phase flow in the fracture, most of the deep coalbed methane wells in the target blocks follow the fracture pseudo-steady-state flow, and RNP and MBT show a linear relationship in the rectangular coordinate system. Combining the definitions of RNP and MBT, the bottom-hole flowing pressure can be further derived as a function of the daily water production and the flowback rate (LR) as follows:

[0141]

[0142] where P i refers to the formation pressure.

[0143] According to the above model, select the relationship curves of RNP vs MBT and PNR vs LR based on the fracture pseudo-steady-state model fitting in the initial flowback period or test data (as shown in Figure 9 and Figure 10 ).

[0144] Combining the definitions of RNP and MBT and the flow material model, establish the relationship model between the bottom-hole flowing pressure and the daily water production, where the slope of the bottom-hole flowing pressure and the daily water production is a function of the flowback rate. Therefore, the inflow performance curve at different flowback rates can be drawn using this model (as shown in Figure 11 ).

[0145] (3) The specific method for establishing the wellbore flow model and determining the relationship curve between the bottom-hole flowing pressure and the liquid production rate in step 103 is:

[0146] Based on the wellbore flow model, the relationship curve between the bottom-hole flowing pressure and the liquid production rate is obtained by combining with the IPR curve.

[0147] Through the investigation of the applicable ranges of various multiphase flow models, the Gray model, which is commonly used in current engineering for wellbore pressure prediction, is selected.

[0148] The Gray model was initially proposed in the computer program manual for the sizing of surface-controlled subsurface safety valves (SCSSVs) and is applicable to lean condensate gas wells with liquid as the dispersed phase (mist flow). The relevant calculation formulas are as follows.

[0149] The liquid holdup is:

[0150]

[0151]

[0152]

[0153]

[0154]

[0155]

[0156] The corrected value of the pipe roughness k is:

[0157]

[0158]

[0159] where k eff ≥2.77*10 -5

[0160] Calculation steps for the bottom-hole flowing pressure:

[0161] 1) Denote the calculation node number i = 1, and select the pipe length pressure increment Δz and the corresponding initial pressure value Δp0;

[0162] 2) Calculate the pressure p at the i-th node i and its temperature, which is calculated from the geothermal gradient;

[0163] 3) Calculate the average temperature and average pressure in the Δz i section:

[0164] 4) Calculate the relevant physical property parameters at T and p;

[0165] 5) Calculate the volume flow rates q g 、q l of each phase, and the superficial velocity υsg , υ sl and the mixture flow rate υ m ;

[0166] 6) Calculate dimensionless quantities, liquid holdup, mixture density, friction factor, pressure gradient, etc.;

[0167] 7) p i -Δp0| ≤ ε, then continue the calculation, otherwise set Δp0 = Δp i , and turn to calculation step (2);

[0168] 8) Output the position and pressure of the i-th node;

[0169] 9) Repeat the above steps until the calculation is completed.

[0170] Based on the wellbore flow model, combined with the IPR curve, obtain the relationship curve between the bottom-hole flowing pressure and the liquid production rate (as Figure 12 shown).

[0171] (4) In step 104, the specific method of using the nodal system analysis method to optimize the optimal choke range is as follows:

[0172] The nodal analysis method is a method of establishing models separately for several parts by setting a solution node in the oil well system and then conducting a summary analysis. Its initial design purpose was not for oilfield services, but for complex circuit and pipeline design. Subsequently, Gilibert and Brown introduced this method in the study of oil well production and established a theoretical basis for future nodal method productivity prediction. With the continuous development of technology, with the assistance of computers, the nodal method productivity prediction has been more widely used in actual work.

[0173] The solution node of the nodal analysis method is generally set at the bottom of the well, dividing the entire system into the reservoir inflow section and the vertical pipe outflow section. However, some people set two solution nodes, that is, an additional solution node at the wellhead, and divide the outflow section into the vertical pipe outflow section and the surface horizontal pipe outflow section. The setting of the node has little relation to the final calculation, but only the analysis purpose and analysis method are different. In this study, we mainly study the natural productivity, and at the same time analyze the coordinated productivity to a certain extent, so we use the former method to set the node.

[0174] Through the above analysis and derivation, the inflow performance model and outflow performance model under different conditions have been obtained, which respectively represent the relationship between the production rate flowing into the bottom of the well and the flowing pressure, and the relationship between the flow rate in the barrel and the flowing pressure. By calculating the different production rates at different flowing pressures, the curves of the two can be plotted, and observing their intersection points in the same coordinate system can obtain the theoretically coordinated productivity of this layer and the natural productivity under different flowing pressures (as Figure 13 ).

[0175] Using the node system analysis method, the intersection points of the inflow and outflow curves of different chokes at different flowback rates are determined, and an optimized chart for determining the choke size through production and bottom-hole pressure gradient is obtained ( Figure 14 as shown)

[0176] By changing the flowback rate and calculating the above process cyclically, the bottom-hole pressure and liquid production corresponding to the intersection points of the inflow and outflow curves of different chokes at different flowback rates can be obtained, that is, the bottom-hole pressure and flow rate at the coordination points under different flowback rates. Further, combined with the gas-water ratio at their respective flowback rates, the daily gas production corresponding to the coordination points is obtained; among them, the comparison results between the calculated bottom-hole pressure of different chokes during drainage and the actual values are as Figure 15 shown. During the period when the flowback rate is between 0.525 and 0.56, the actual choke size is 10 - 12 mm, and the calculation results are in good agreement with the actual results. However, if a choke with a size below 6 mm is used during this stage, the pressure maintenance level is relatively high. The difference in the bottom-hole pressure between the 8-mm choke and the 10-mm choke is close to 1 MPa, and the difference in the calculated results of the bottom-hole pressure at the coordination points for chokes above 12 mm is relatively small.

[0177] Combined with the relationship between the gas-water ratio and the flowback rate, the daily gas production when using different chokes at each flowback rate can be determined. At the same time, considering that the water production basically follows the law of harmonic decline and the flowback rate follows a logarithmic increase relationship with time, based on the fitting relationship between the flowback rate and time from the previous data, the time can be calculated inversely from the flowback rate, so as to calculate the change of the cumulative gas production with time under different choke sizes. As Figure 16 shown, the predicted cumulative gas production is in good agreement with the actual situation. Comparing the cumulative gas production results of different chokes shows that the difference in choke sizes above 8 mm is relatively small. Considering the comprehensive control of the pressure situation and the cumulative gas production situation, the reasonable choke size at this stage is between 8 and 10. Combining the pressure decline situation and the cumulative gas production situation, the reasonable choke size for the later stage can be further designed.

[0178] In another embodiment of the present invention, an optimized system for the post-fracturing drainage working system of a deep coalbed methane horizontal well is provided. This system can be used to implement the optimized method for the post-fracturing drainage working system of the above deep coalbed methane horizontal well. Specifically, it includes:

[0179] Choke dynamic modeling module: Based on the wellhead pressure sensor, choke size parameters, and gas-water ratio monitoring data, by fitting the double logarithmic segmented relationship between the flowback rate and the gas-water ratio, a dynamic relationship model between the choke pressure drop and the flow rate is established;

[0180] Fracture dynamic analysis module: By using the material balance equation and the diffusion equation, combined with the formation pressure sensor data, the pseudo-steady-state flow parameters of the fracture system are calculated;

[0181] Wellbore multiphase flow calculation module: Adopt the Gray multiphase flow model, combine with the wellbore inclination angle sensor and the gas-liquid flow velocity monitoring data, calculate the liquid holdup and the wellbore pressure gradient, and generate the outflow performance curve of the bottomhole flowing pressure and the liquid production rate;

[0182] Choke-reservoir coupling optimization module: Take the bottomhole as the node, and match the coordination point of the inflow performance curve and the outflow performance curve through the nodal system analysis algorithm;

[0183] Based on the relationship between the flowback rate and the logarithm of time, predict the cumulative gas production curve of different choke sizes;

[0184] Output the optimal choke size range and the corresponding pressure control threshold.

[0185] Hardware support: The module is integrated into an embedded controller or an industrial computer, and is connected to the wellhead pressure sensor, the flowmeter, the formation pressure sensor and the choke regulating valve to form a closed-loop control system.

[0186] Data interface: Real-time receive the monitoring data of the wellhead pressure, the water production, the gas-water ratio and the bottomhole flowing pressure.

[0187] In another embodiment of the present invention, a terminal device is provided. The terminal device includes a processor and a memory. The memory is used to store a computer program. The computer program includes program instructions. The processor is used to execute the program instructions stored in the computer storage medium. The processor may be a Central Processing Unit (CPU), or may also be other general-purpose processors, Digital Signal Processors (DSPs), Application Specific Integrated Circuits (ASICs), Field-Programmable Gate Arrays (FPGAs) or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc. It is the computing core and control core of the terminal, and is suitable for implementing one or more instructions. Specifically, it is suitable for loading and executing one or more instructions to implement the corresponding method flow or the corresponding function; the processor described in the embodiment of the present invention can be used for the operation of the optimization method of the post-fracturing production regime of deep coalbed methane horizontal wells.

[0188] In another embodiment of the present invention, a storage medium is provided, specifically a computer-readable storage medium (Memory). The computer-readable storage medium is a memory device in a terminal device and is used to store programs and data. It can be understood that the computer-readable storage medium here can include both the built-in storage medium in the terminal device and, of course, the extended storage medium supported by the terminal device. The computer-readable storage medium provides a storage space, and this storage space stores the operating system of the terminal. Moreover, in this storage space, one or more instructions suitable for being loaded and executed by a processor are also stored. These instructions can be one or more computer programs (including program codes). It should be noted that the computer-readable storage medium here can be a high-speed RAM memory or a non-volatile memory, such as at least one disk memory.

[0189] One or more instructions stored in the computer-readable storage medium can be loaded and executed by the processor to implement the corresponding steps of the method for optimizing the production work system after pressure drainage in horizontal wells of deep coalbed methane in the above embodiment; one or more instructions in the computer-readable storage medium are loaded and executed by the processor.

[0190] Those skilled in the art should understand that the embodiments of the present invention can be provided as a method, a system, or a computer program product. Therefore, the present invention can take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present invention can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk memories, CD-ROMs, optical memories, etc.) containing computer-usable program codes.

[0191] The present invention is described with reference to the flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to the embodiments of the present invention. It should be understood that each process and / or block in the flowchart and / or block diagram, and the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing devices generate a device for implementing the specified functions in Figure 1 one process or multiple processes and / or blocks Figure 1 one block or multiple blocks.

[0192] These computer program instructions can also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to operate in a particular manner, such that the instructions stored in the computer-readable memory produce a manufacture including an instruction device that implements the functions specified in one or more of the processes and / or blocks Figure 1 one or more of the processes and / or blocks Figure 1 specified in the function.

[0193] These computer program instructions can also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer-implemented process, so that the instructions executed on the computer or other programmable apparatus provide steps for implementing the functions specified in one or more of the processes and / or blocks Figure 1 one or more of the processes and / or blocks Figure 1 specified in the function.

[0194] Those of ordinary skill in the art will appreciate that the embodiments described herein are provided to assist the reader in understanding the implementation of the present invention and should be understood that the scope of protection of the present invention is not limited to such specific statements and embodiments. Those of ordinary skill in the art can make various other specific deformations and combinations without departing from the essence of the present invention based on the technical revelations disclosed in the present invention, and these deformations and combinations are still within the scope of protection of the present invention.

Claims

1. An optimization method for the production work system after pressure relief in horizontal wells of deep coalbed methane, characterized in that, It includes the following steps: Step 1: Establish a choke model based on well data and fluid mechanics principles. Determine the gas-water ratio at different flowback stages by fitting the relationship between the flowback rate and the gas-water ratio, and calculate the relationship curve between the choke pressure drop and the flow rate. Step 2: Establish a pseudo-steady-state flow material balance equation for the fracture system, and derive the inflow performance curve between the bottom-hole flowing pressure and the daily water production by combining the linear flow and radial flow diffusion equations. Step 3: Use a multiphase flow wellbore flow model to calculate the bottom-hole flowing pressure at different liquid production rates, and establish an outflow performance curve for the wellbore. Step 4: Couple the reservoir, wellbore, and choke pressure systems, conduct an inflow-outflow coordination analysis with the bottom hole as the node, match the coordination points under different choke sizes through the nodal system analysis method, and determine the optimal choke size range based on pressure decline and cumulative gas production assessment.

2. The optimized method for the post-fracturing production work system of deep coalbed methane horizontal wells according to claim 1, wherein: The specific content of Step 1 includes: Step 1.1: Use the Gilbert model to fit the relationship equation between production rate, wellhead pressure, and choke size. where q w is the water production rate; P wh is the wellhead pressure; D 64 is the choke size; GLR is the gas-water ratio; a, b, c, and d are the parameters of the formula; Step 1.2: Establish a double logarithmic piecewise fitting relationship between the flowback rate and the gas-water ratio, and obtain the gas-water ratio prediction formula at different flowback stages through piecewise regression. Step 1.3: Calculate the two-phase flow choke pressure drop by combining the Chisholm model modified by the slip effect.

3. The optimized production work system for post-fracturing of deep coalbed methane horizontal wells according to claim 1, wherein: The specific content of Step 2 includes: Step 2.1: Define the dimensionless pressure parameter RNP and the cumulative water production parameter MBT. Among them, P i represents the original formation pressure, P wf represents the bottom-hole flowing pressure, Q w represents the water production rate; Step 2.2: Establish a pseudo-steady-state flow material balance equation for the fracture. Among them, C t represents the comprehensive compression coefficient, V p represents the fracture pore volume, and t represents time; Step 2.3: Determine the slope of the inflow performance curve at different flowback rates by fitting through the PNR-LR relationship curve.

4. The optimized production work system method for post-fracture production of deep coalbed methane horizontal wells according to claim 1, wherein: The specific content of Step 3 includes: Step 3.1: Use the Gray multiphase flow model to calculate the liquid holdup. Among them, H l represents the holdup, dimensionless, indicating the proportion of the liquid volume in the pipeline to the total fluid volume, ranging from 0 to 1, υ sg represents the superficial gas velocity, υ sl represents the superficial liquid velocity; Step 3.2: Establish a wellbore pressure gradient equation. Among them, ρ m represents the mixed density, g represents the acceleration of gravity, θ represents the pipe inclination angle, f represents the Darcy friction factor, υ m represents the mixed fluid velocity, and D represents the inner diameter of the pipe; Obtain the bottom-hole flowing pressure distribution curve at different liquid production rates through iterative calculation.

5. The optimization method of the post - fracturing production work system for deep coal - bed methane horizontal wells according to claim 1, wherein: The specific content of Step 4 includes: Step 4.1: Establish a coordination point matching model for the inflow performance curve and the outflow performance curve at the bottom-hole node. Step 4.2: Plot the pressure-production coordination curves under different choke sizes to determine the choke size optimization chart. Step 4.3: Predict the cumulative gas production curves under different choke sizes by combining the flowback rate-time logarithm relationship.

6. The optimized production work system method after pressure relief for deep coalbed methane horizontal wells according to claim 1, characterized in that: The specific content of the choke size optimization includes: Step 5.1: When the flowback rate is in the range of 0.5 - 0.6, the relationship between the choke size and the pressure drop at the coordination point satisfies: ΔP 8mm -ΔP 10mm <1MPa Step 5.2: The choke size corresponding to the inflection point of the cumulative gas production curve is the optimal value.

7. An optimization system for the production work system after pressure relief in a deep coalbed methane horizontal well, characterized in that: This system can be used to implement the optimization method for the post-fracturing production regime of deep coalbed methane horizontal wells described in any one of claims 1 to 6. Specifically, it includes: Choke dynamic modeling module: Based on the wellhead pressure sensor, choke size parameters, and gas-water ratio monitoring data, establish a dynamic relationship model between the choke pressure drop and the flow rate by fitting the double logarithmic piecewise relationship between the flowback rate and the gas-water ratio. Fracture dynamic analysis module: Calculate the pseudo-steady-state flow parameters of the fracture system through the material balance equation and diffusion equation, combined with formation pressure sensor data. Wellbore multiphase flow calculation module: Use the Gray multiphase flow model, combined with the wellbore inclination angle sensor and gas-liquid flow rate monitoring data, calculate the liquid holdup and the wellbore pressure gradient, and generate an outflow performance curve between the bottom-hole flowing pressure and the liquid production rate. Nozzle-reservoir coupling optimization module: Taking the bottom hole as a node, matching the coordination point of the inflow performance curve and the outflow performance curve through the node system analysis algorithm; Predicting the cumulative gas production curves of different nozzle sizes based on the relationship between the flowback rate and the logarithm of time; Outputting the optimal nozzle size range and the corresponding pressure control threshold.

8. A computer device, characterized in that: Including a memory, a processor, and a computer program stored on the memory and executable on the processor, and when the processor executes the program, implementing the optimization method for the post-fracturing production work system of the deep coalbed methane horizontal well according to one of claims 1 to 6.

9. A computer-readable storage medium, characterized in that: Stored thereon is a computer program, and when the program is executed by the processor, implementing the optimization method for the post-fracturing production work system of the deep coalbed methane horizontal well according to one of claims 1 to 6.

Images