Design method for dynamic regulation of reasonable oil nozzle size of shale oil horizontal well after pressure

Abstract

The present application provides a kind of shale oil horizontal well post-fracturing drainage reasonable choke size dynamic regulation and control design method, comprising: step 1, collecting fracturing data, well structure data and wellhead production data;Step 2, according to the data collected, calculate the bottom hole flowing pressure and the bottom hole flowback speed;Step 3, the calculation of the degree of proppant settlement is carried out;Step 4, the calculation of the critical flow velocity of proppant is carried out;Step 5, the preset choke bottom hole flowing pressure and bottom hole flow velocity calculation is carried out;Step 6, under different circumstances, adjust the choke, obtain the current reasonable choke size.The shale oil horizontal well post-fracturing drainage reasonable choke size dynamic regulation and control design method considers the proppant settlement and proppant backflow condition, and fully considers the existence of multiple fractures in the case of multi-stage fracturing of horizontal well, can carry out real-time regulation and control of flowback choke according to the actual flowback condition of the field, has broad application prospect.

Description

Technical Field

[0001] This invention relates to the field of unconventional shale oil resource development technology, and in particular to a design method for dynamically controlling the size of the nozzle in a horizontal shale oil well after pressure treatment. Background Technology

[0002] In recent years, shale oil resources have accounted for a gradually increasing proportion of the world's oil and gas reserves and production, and the development of shale reservoirs has gradually attracted widespread global attention. my country has abundant shale oil reserves, mainly concentrated in the medium-thick organic mudstone and shale areas of Hunan and Hubei provinces, such as the Ordos Basin, Junggar Basin, Songliao Basin, Sichuan Basin, and Jianghan Basin. Since 2019, my country's shale oil development has achieved major strategic breakthroughs in multiple depressions, various types of formations, and multiple strata, demonstrating the promising exploration and development prospects of shale oil.

[0003] For shale oil reservoirs, the combined application of horizontal wells and staged fracturing techniques can significantly improve oil recovery. Among these techniques, fracturing fluid flowback is a crucial factor determining the success of fracturing operations. A well-designed flowback regime can not only effectively shorten the construction cycle and reduce costs, but also increase the flowback rate and minimize damage to the reservoir caused by the fracturing fluid. During fracturing fluid flowback, the migration and settling of proppant are significantly affected. When the flowback rate is low, the fracture closure time increases, and the settling distance of the proppant within the fracture increases, potentially leading to proppant accumulation at the fracture bottom and ineffective fracture support. Conversely, when the flowback rate is high, the proppant may be dragged out of the fracture by the fracturing fluid, settling in the wellbore and clogging the perforation or being carried to the surface and eroding the nozzles. Therefore, optimizing the nozzle flowback regime is essential for improving shale oil recovery.

[0004] However, on-site fracturing fluid flowback relies heavily on past experience in conventional oilfield fracturing development, lacking relevant theoretical guidance. Currently, most methods for optimizing fracturing fluid flowback injection systems focus on predicting nozzle size, failing to adjust nozzle size based on real-time production dynamics.

[0005] Chinese patent application CN202010960120.1 discloses a method for controlling the size of a flowback nozzle after fracturing in a gas reservoir. The method includes the following steps: S1: Collecting wellbore structure data and fracturing engineering data; S2: Monitoring wellhead data to obtain the gas volumetric velocity, liquid volumetric velocity, and oil pressure at the wellhead; S3: Performing gas-liquid two-phase pipe flow simulation calculations to obtain the bottomhole flowing pressure and gas-liquid volumetric velocity; S4: Checking the flow pressure gradient at the bottomhole fracture opening by calculating and comparing the gas-liquid flow pressure gradient at the bottomhole fracture opening with the critical pressure gradient for proppant backflow within the fracture, and determining the possibility of proppant backflow; S5: Adjusting the nozzle size by assessing the possibility of proppant backflow under the next-stage nozzle and determining the nozzle control scheme. This invention can accurately guide the control or adjustment of nozzle size, avoiding proppant backflow caused by the flow pressure gradient at the bottomhole fracture opening exceeding the critical backflow pressure gradient during fracturing flowback, and has broad market prospects.

[0006] Chinese patent application CN202211142548.0 discloses a method and apparatus for regulating the post-fracturing production system throughout the entire lifecycle of a fracturing well. The method includes: during the fracturing stage, obtaining the fracturing stimulation volume of different shale wells; determining the fracturing stimulation scheme for the target well based on the fracturing stimulation volume of different wells; during the well-closing stage, obtaining the total well permeation and energy enhancement volume of different shale wells; determining the optimal well-closing conditions for the target well based on the total well permeation and energy enhancement volume of different wells; during the flowback stage, obtaining the oil-producing matrix pore volume of different shale wells; determining the flowback scheme for the target well based on the oil-producing matrix pore volume of different wells; during the well-opening production stage, obtaining the single-well recoverable reserves of different shale wells; and determining the production scheme for the target well based on the single-well recoverable reserves of different wells within a specified lifespan. This method can continuously optimize and regulate the subsequent fracturing, well-closing, flowback, and well-opening production stages during the fracturing well construction process, thereby improving the final recovery rate of a single well.

[0007] Chinese patent application CN202210693932.3 discloses an optimized method for on-site drainage testing of shale gas wells based on matrix flowback capacity. The method includes rock sample preparation, obtaining the porosity distribution of the rock sample through nuclear magnetic resonance (NMR) dry and wet sample testing and correction; based on the porosity distribution of the rock sample, the on-site development reservoir is equivalent to a capillary cluster model; based on the capillary cluster model and combined with the bottom hole pressure obtained on-site, the bottom hole flowback capacity under the current conditions is predicted, thereby determining the shale gas well production capacity; based on the production capacity, a suitable nozzle is selected for pressure control production, thereby achieving the goal of improving the final recovery rate of the shale gas well. This invention addresses the shortcomings of relying solely on empirical methods for nozzle replacement and pressure control production during shale gas well production. By testing on-site rock samples, the reservoir production capacity is quantified, and a suitable pressure control production method is developed to guide on-site production.

[0008] The existing technologies described above are significantly different from the present invention and have failed to solve the technical problem we want to address. Therefore, we have invented a new design method for dynamically controlling the size of the nozzle for reasonable oil production after pressure control in shale oil horizontal wells. Summary of the Invention

[0009] The purpose of this invention is to provide a design method for dynamically adjusting the size of the nozzle in shale oil horizontal wells after pressure control, taking into account real-time production data and proppant settling and backflow.

[0010] The objective of this invention can be achieved through the following technical measures: a design method for dynamically controlling the appropriate nozzle size during post-pressure drainage in shale oil horizontal wells, comprising:

[0011] Step 1: Collect fracturing data, wellbore structure data, and wellhead production data;

[0012] Step 2: Calculate the bottom hole flowing pressure and bottom hole flowback velocity based on the collected data;

[0013] Step 3: Calculate the degree of proppant settlement;

[0014] Step 4: Calculate the critical flow rate of the proppant;

[0015] Step 5: Calculate the preset nozzle bottom-hole flowing pressure and bottom-hole flowing velocity;

[0016] Step 6: Adjust the nozzle under different conditions to obtain the current reasonable nozzle size.

[0017] The objective of this invention can also be achieved through the following technical measures:

[0018] In step 1, the fracturing data includes fracture width, fracture height, fracture closure pressure, proppant density, average proppant particle size, and fracturing fluid viscosity, which are used to calculate the critical proppant flow rate and proppant settling degree; the wellbore structure data includes well trajectory data, pipe diameter, and roughness, which are used to calculate the bottom hole flowing pressure and bottom hole flow velocity; the wellhead production data is real-time monitoring data, including wellhead oil pressure, liquid volumetric flow rate, and gas volumetric flow rate.

[0019] In step 2, considering frictional losses and multiphase pipe flow characteristics, the bottom hole flowing pressure and bottom hole flow velocity are calculated, specifically including:

[0020] 2.1. Select a multiphase pipe flow calculation method, and use the Beggs-Brill method for calculation;

[0021] 2.2. Determine the current wellhead production data, including the current wellhead pressure, wellhead temperature, liquid volumetric velocity, and gas volumetric velocity. Starting from the wellhead, set a unit pipe segment ΔH, assuming that the wellhead to the bottom of the well is calculated in segments, and assuming the pressure drop ΔP in the unit pipe segment interval.

[0022] 2.3. Perform parameter calculations within the unit pipe section, including the average pressure and average temperature within the unit pipe section, and calculate the physical property parameters and flow pattern determination parameters within the pipe section;

[0023] 2.4. Identify the flow pattern and determine the flow regime of the unit pipe segment based on the flow pattern boundaries of the Beggs-Brill method;

[0024] 2.5. Calculate the gravity and friction loss gradients in the vertical section of the horizontal well;

[0025] 2.6. Perform pressure drop calculations for the horizontal section of the horizontal well;

[0026] 2.7. Starting from the wellhead, compare the calculated pressure drop ΔP′ of the pipe segment with the assumed pressure drop ΔP. If it exceeds the allowable error range, let ΔP = ΔP′, return to step 2.3 and re-iterate the calculation until the error range is met, and increase the depth by one unit pipe segment.

[0027] 2.8. Calculate the bottom hole flowing pressure and bottom hole flowing velocity, repeating steps 2.3, 2.4, 2.5 and 2.7 to the end of the vertical well section; in the horizontal well section, repeat steps 2.3, 2.4, 2.6 and 2.7 to the end of the horizontal section, and calculate the bottom hole flowing pressure and bottom hole flowing velocity at each fracture.

[0028] In step 2.5, the actual density, gravity loss gradient, frictional pressure drop gradient, and total pressure drop gradient of the mixture are calculated according to the calculation method corresponding to the flow regime.

[0029] (1) Gravity loss gradient

[0030]

[0031] (2) Frictional pressure drop gradient

[0032]

[0033] (3) Total pressure loss gradient

[0034]

[0035] in, The average density is kg / m³. 3 θ is the tilt angle; v t V represents the apparent velocity of the mixed fluid, in m / s; sg D is the apparent velocity of the gas, in m / s;p The diameter of the pipe is in meters (m). The average pressure of this pipe section is expressed in MPa.

[0036] In step 2.6, shale oil development often utilizes horizontal wells with multi-stage fracturing, resulting in multiple fractures. Each time the fluid passes through a fracture, its energy decreases to some extent, increasing the pressure drop along the pipeline. This pressure drop due to fluid loss in the horizontal well section is the sum of the pipeline friction pressure drop and the accelerated pressure drop, specifically expressed as:

[0037] ΔP′=ΔP acc +ΔP f 4)

[0038] in:

[0039]

[0040] In the formula: ΔP′ is the total pressure drop, MPa; ΔP acc To accelerate the pressure drop, MPa; ΔP f P1 is the frictional pressure drop, MPa; P2 is the accelerated pressure drop at crack 1, MPa; P3 is the accelerated pressure drop at crack 2, MPa; ρ m1 The density of the flowback fluid at crack 1 is kg / m³. 3 ;v t1 The flow velocity of the backflow fluid at fracture 1 is m / s; ρ m2 Density of the backflow fluid at crack 2, kg / m³ 3 ;v t2 The flow velocity of the backflow fluid at crack 2 is m / s.

[0041] In step 3, when the proppant settlement exceeds 60%, the conductivity at the fracture decreases significantly. Therefore, it is necessary to ensure that the proppant settlement does not exceed 60%. Ignoring the perforation pressure difference, the calculated bottom hole flowing pressure is the flowing pressure at the bottom hole fracture opening. Compare the bottom hole flowing pressure at each fracture with the fracture closure pressure. Perform step 3 on each fracture. If the proppant settlement exceeds 60% at any fracture, the nozzle must be increased to close the fracture as quickly as possible.

[0042] In step 3, comparing the bottom-hole flowing pressure and fracture closure pressure at each fracture includes:

[0043] 3.1. If the bottom hole flowing pressure is less than the fracture closure pressure, the fracture has been closed. At this point, there is no need to determine the degree of proppant settlement, and you can proceed directly to step 4.

[0044] 3.2. If the bottom hole flowing pressure is greater than the fracture closure pressure, and the fracture has not yet closed, calculate the time from the start of fracturing to this point, and calculate the degree of settlement at this time:

[0045]

[0046] The settling velocity of the proppant is:

[0047]

[0048] In the formula: v s The settling velocity of the proppant is expressed in m / s; t s The cumulative settlement time is expressed in seconds (s); H w f is the crack height, in meters (m); l For non-Newtonian fluid correction factors; f c f is the sand concentration correction factor; w K is the wall correction factor; K is the fluid consistency index, Pa·s n τ is the fluid flow index; n is the fluidity index. c Let d be the fluid relaxation time, in seconds; s ρ is the proppant particle size, m; g is the gravitational acceleration; ρ s The density of the proppant is kg / m³. 3 .

[0049] Step 3.2 includes:

[0050] 3.2.1. If the proppant settlement exceeds 60% at this time, backflow is impossible. Increase the oil nozzle size and skip directly to step 5 to close the crack as quickly as possible.

[0051] 3.2.2. If the proppant settlement does not exceed 60% at this time, proceed to step 4.

[0052] In step 4, when the bottom hole flowing pressure is greater than the fracture closure pressure, the fracture is not closed, and the critical flow velocity at which the proppant inside the fracture flows back is:

[0053] When N Re <2 hours:

[0054]

[0055] When 2 < N Re <500 hours:

[0056]

[0057] When N Re >500 hours:

[0058]

[0059] When the bottom hole flowing pressure is less than the fracture closure pressure, the fracture closes, and the proppant inside the fracture is squeezed by the fracture, making backflow more difficult. The critical flow velocity at this time is:

[0060] When NRe <2 o'clock:

[0061]

[0062] When 2 < N Re <500 hours:

[0063]

[0064] When N Re >500:

[0065]

[0066] Where: N Re v is the Reynolds number; c The critical flow rate of the proppant is in m / s; d s For proppant particle size, m; ρ s The density of the proppant is kg / m³. 3 β is the ratio of lift coefficient to drag coefficient, taken as 0.25; α is the direction of the closing stress acting on the proppant; δ is the liquid film coefficient, taken as 0.213 × 10⁻⁶. -6 h s ρ is the distance from the proppant to the crack tip, in meters (m); l The density of the liquid phase is kg / m³. 3 μ is the viscosity of the fracturing fluid, mPa·s; σ is the interfacial tension between oil and water, mN / m.

[0067] Each crack is operated in step 4. If the backflow rate of any crack exceeds the critical flow rate, the nozzle must be reduced.

[0068] Step 4 specifically includes:

[0069] 4.1. When the crack has been closed and the backflow velocity is less than the critical velocity of the proppant, increase the flow rate of the first-level nozzle and proceed to step 5.

[0070] 4.2. When the crack has closed and the backflow velocity is greater than the critical velocity of the proppant, reduce the nozzle size by one level and proceed to step 5.

[0071] 4.3. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is less than the critical proppant velocity, increase the pressure of the first-level nozzle and proceed to step 5.

[0072] 4.4. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is greater than the critical proppant velocity, reduce the nozzle size by one level and proceed to step 5.

[0073] In step 5, adjust the nozzle size (increase or decrease) and predict the gas and liquid production velocities corresponding to the preset nozzle size based on the nozzle flow velocity calculation formula. The nozzle flow velocity formula includes a pure liquid nozzle flow velocity calculation formula and a gas-liquid two-phase nozzle flow velocity calculation formula. The pure liquid nozzle flow velocity formula is as follows:

[0074]

[0075] in:

[0076]

[0077] In the formula: q is the volumetric flow rate, m 3 / s;C D A is the nozzle flow coefficient; A is the nozzle flow area, m 2 g c Unit conversion factor; Δp is the pressure difference before and after the nozzle, MPa; ρ is the liquid density, kg / m³ 3 d1 is the pipe diameter, in meters; d2 is the nozzle size, in meters; N Re The Reynolds number is based on the nozzle size;

[0078] The formula for calculating the flow velocity in a gas-liquid two-phase nozzle is:

[0079]

[0080] q g =q l R p 17)

[0081] In the formula: q l and q g The volumetric flow rates, in m, are for the liquid and gas phases, respectively. 3 / s;;R p To produce a gas-liquid ratio, m 3 / m 3 ;p t Oil pressure, MPa; f w Moisture content;

[0082] Repeat step 2 to obtain the bottom hole pressure and bottom hole velocity of the preset nozzle.

[0083] Step 6 includes:

[0084] 6.1. As described in case 3.2.1, repeat step 4 to obtain the critical flow velocity at this point;

[0085] If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.1 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found.

[0086] 6.2. As described in situation 4.1, repeat step 4 to obtain the critical flow velocity at this point;

[0087] If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.2 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found; if the backflow velocity is greater than the critical velocity, the nozzle size of the previous stage is the most suitable nozzle size at present, and the adjustment ends.

[0088] 6.3. As described in situation 4.2, repeat step 4 to obtain the critical flow velocity at this point;

[0089] If the backflow velocity is less than the critical velocity, then the nozzle is the most suitable nozzle at present; if the backflow velocity is greater than the critical velocity, then the nozzle size is adjusted again, and steps 5 and 6.3 are repeated until the nozzle size with the maximum backflow velocity less than the critical velocity is found.

[0090] 6.4. As described in situation 4.3, repeat step 3 to determine the crack closure status at this point;

[0091] 6.4.1. The crack has been closed. Repeat step 4 to obtain the critical flow rate at this time. If the backflow rate is greater than the critical flow rate, then the previous nozzle is the most suitable nozzle at this time. If the backflow rate is less than the critical flow rate, then increase the nozzle size and repeat steps 5 and 6.2.

[0092] 6.4.2. If the crack is not closed and the settlement exceeds 60%, increase the oil nozzle size and repeat steps 5 and 6.1.

[0093] 6.4.3. If the crack is not closed and the settlement does not exceed 60%, repeat step 4 to obtain the critical flow rate at this time. If the backflow velocity is less than the critical flow rate of the proppant, increase the nozzle size again and repeat steps 5 and 6.4 until the nozzle size with the maximum backflow velocity less than the critical flow rate is found. If the backflow velocity is greater than the critical flow rate, then the previous nozzle is the most suitable nozzle at this time.

[0094] 6.5. As described in situation 4.4, repeat step 3 to determine the crack closure status at this point.

[0095] Because the nozzle is small, the return flow rate is reduced, and the bottom hole flowing pressure cannot be smaller than that in the case described in 4.4. Therefore, the fracture must be in an unclosed state.

[0096] Furthermore, according to the situation described in 4.4, the degree of settlement does not exceed 60%, and the backflow velocity is greater than the critical velocity, indicating that the backflow velocity is too fast. Therefore, settlement is unlikely to occur in this step.

[0097] Repeat step 4 to obtain the critical flow rate at this time; if the backflow rate is greater than the critical flow rate, adjust the nozzle size again and repeat steps 5 and 6.5 until the nozzle size with the maximum backflow rate less than the critical flow rate is found; if the backflow rate is less than the critical flow rate, then the nozzle is the most suitable nozzle at this time.

[0098] Step 6 has already determined whether the new first-level nozzle is reasonable. Therefore, in step 6, the nozzle refers to the new first-level nozzle.

[0099] The objective of this invention can also be achieved through the following technical measures: a design system for dynamic control of the size of the nozzle for reasonable flowback in shale oil horizontal wells after pressure control. This design system for dynamic control of the size of the nozzle for reasonable flowback in shale oil horizontal wells after pressure control adopts a design method for dynamic control of the size of the nozzle for reasonable flowback in shale oil horizontal wells after pressure control to perform real-time control of the flowback nozzle based on the actual flowback situation on site.

[0100] This invention presents a design method for dynamically controlling the nozzle size during post-fracturing fluid flowback in shale oil horizontal wells. It monitors wellhead pressure and flow velocity changes in real time and assesses the appropriateness of the nozzle size at each time step. The process considers the impact of proppant backflow and settling on fracturing fluid flowback. Furthermore, considering the characteristics of shale oil horizontal wells (significant differences in flow velocity and pressure between the heel and toe ends), and the presence of multiple fractures in multi-stage fracturing, the invention optimizes the nozzle size during flowback. This invention enables real-time control of the flowback nozzle size based on actual field flowback conditions and has broad application prospects. Attached Figure Description

[0101] Figure 1 This is a graph showing the changes in bottom hole flowing pressure and production rate over time at the first fracture in a specific embodiment 1 of the present invention;

[0102] Figure 2 This is a graph showing the variation of the fluid production rate and critical flow rate of the first fracture over time in a specific embodiment 1 of the present invention;

[0103] Figure 3 A flowchart of a specific embodiment of the design method for dynamic control of reasonable nozzle size in shale oil horizontal well post-pressure production according to the present invention;

[0104] Figure 4 This is a graph showing the changes in bottom hole flowing pressure and production rate over time at the first fracture in a specific embodiment 2 of the present invention;

[0105] Figure 5 This is a graph showing the variation of the fluid production rate and critical flow rate of the first fracture over time in a specific embodiment 2 of the present invention;

[0106] Figure 6 This is a graph showing the changes in bottom hole flowing pressure and production rate over time at the first fracture in a specific embodiment 3 of the present invention;

[0107] Figure 7 This is a graph showing the change of the liquid production rate and critical flow rate of the first fracture over time in a specific embodiment 3 of the present invention. Detailed Implementation

[0108] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0109] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0110] like Figure 3 As shown, Figure 3 This is a flowchart illustrating the design method for dynamic control of the optimal nozzle size in shale oil horizontal well production after pressure control, according to the present invention. The design method for dynamic control of the optimal nozzle size in shale oil horizontal well production after pressure control includes:

[0111] 1. Data Collection

[0112] The fracturing data, wellbore structure data, and wellhead production data required for this invention are collected. The fracturing data includes fracture width, fracture height, fracture closure pressure, proppant density, average proppant particle size, and fracturing fluid viscosity, used to calculate the critical proppant flow velocity and proppant settling degree. The wellbore structure data includes well trajectory data, pipe diameter, and roughness, used to calculate bottom hole flowing pressure and bottom hole flow velocity. The wellhead production data is real-time monitoring data from the field, including wellhead oil pressure, liquid volumetric flow rate, and gas volumetric flow rate.

[0113] 2. Calculate the bottom hole flowing pressure and bottom hole flowback velocity.

[0114] The bottom hole pressure and bottom hole flow velocity are calculated considering frictional losses and multiphase pipe flow characteristics. The specific process is as follows:

[0115] 2.1. Selection of Multiphase Pipe Flow Calculation Method

[0116] Table 1. Multiphase Pipe Flow Methods and Their Applications

[0117]

[0118] Most current multiphase pipe flow calculation models are empirical or semi-empirical models based on experiments, and each model has its applicable range, as shown in Table 1. Since this well is a horizontal wellbore, the Beggs-Brill method is selected for calculation in this invention.

[0119] 2.2. Determine the current wellhead production data

[0120] Determine the current wellhead pressure, wellhead temperature, liquid volumetric velocity, and gas volumetric velocity. Starting from the wellhead, set a unit pipe segment ΔH, assuming that the calculation from the wellhead to the bottom of the well is segmented, and assume the pressure drop ΔP of the unit pipe segment interval.

[0121] 2.3. Calculation of parameters within a unit pipe section

[0122] Calculate the average pressure and average temperature within the unit pipe section, and calculate the physical property parameters and flow pattern determination parameters within the pipe section.

[0123] 2.4. Identification of Flow Patterns

[0124] The flow pattern is determined based on the flow pattern limits of the Beggs-Brill method, as shown in Table 2, to determine the flow pattern of the unit pipe section.

[0125] Table 2 Flow Pattern Determination

[0126]

[0127] Wherein, L1-L4 are the flow pattern boundaries, representing: E l N is the volumetric liquid holdup; Fr To be rich is to work hard and earn a lot.

[0128] 2.5. Calculation of Gravity and Friction Loss Gradients in Vertical Sections of Horizontal Wells

[0129] The actual density, gravity loss gradient, frictional pressure drop gradient, and total pressure drop gradient of the mixture are calculated based on the calculation method corresponding to the flow regime.

[0130] (1) Gravity loss gradient

[0131]

[0132] (2) Frictional pressure drop gradient

[0133]

[0134] (3) Total pressure loss gradient

[0135]

[0136] in, The average density is kg / m³. 3 θ is the tilt angle; v t V represents the apparent velocity of the mixed fluid, in m / s; sg D is the apparent velocity of the gas, in m / s; p The diameter of the pipe is in meters (m). The average pressure of this pipe section is expressed in MPa.

[0137] 2.6. Calculation of pressure drop in the horizontal section of a horizontal well

[0138] Shale oil development often utilizes horizontal wells with multi-stage fracturing, resulting in multiple fractures. Each time the fluid passes through a fracture, its energy decreases to some extent, increasing the pressure drop along the pipeline. This pressure drop due to fluid loss in the horizontal well section is the sum of the pipeline friction pressure drop and the accelerated pressure drop, specifically expressed as:

[0139] ΔP′=ΔP acc +ΔP f 4)

[0140] in:

[0141]

[0142] In the formula: ΔP' is the total pressure drop; ΔP acc To accelerate the pressure drop; ΔP f P1 is the pressure drop due to friction; P2 is the accelerated pressure drop at crack 1, MPa; P2 is the accelerated pressure drop at crack 2, MPa; ρ m1 The density of the flowback fluid at crack 1 is kg / m³. 3 ;v t1 The flow velocity of the backflow fluid at fracture 1 is m / s; ρ m2 Density of the backflow fluid at crack 2, kg / m³ 3 ;v t2 The flow velocity of the backflow fluid at crack 2 is m / s.

[0143] 2.7. Comparison of ΔP and ΔP′

[0144] Starting from the wellhead, compare the calculated pressure drop ΔP′ of the pipe segment with the assumed pressure drop ΔP. If it exceeds the allowable error range (generally between 1‰ and 1%), then set ΔP = ΔP′ and return to step 2.3 to re-iterate the calculation until the error range is met, and increase the depth by one unit pipe segment.

[0145] 2.8. Calculation of bottom hole flowing pressure and bottom hole flowing velocity

[0146] Repeat steps 2.3, 2.4, 2.5, and 2.7 to the end of the vertical well section. In the horizontal well section, repeat steps 2.3, 2.4, 2.6, and 2.7 to the end of the horizontal section, and calculate the bottom hole flowing pressure and bottom hole flow velocity at each fracture.

[0147] 3. Calculation of proppant settlement degree

[0148] Studies have shown that when proppant settlement exceeds 60%, the conductivity at the fracture site decreases significantly. Therefore, it is essential to ensure that proppant settlement does not exceed 60%. Ignoring the perforation pressure differential, the calculated bottomhole flowing pressure is the same as the flowing pressure at the fracture opening. Compare the bottomhole flowing pressure at each fracture with the fracture closure pressure:

[0149] 3.1. If the bottom hole flowing pressure is less than the fracture closure pressure, the fracture has been closed. At this point, there is no need to determine the degree of proppant settlement, and you can proceed directly to step 4.

[0150] 3.2. If the bottom hole flowing pressure is greater than the fracture closure pressure, and the fracture has not yet closed, calculate the time from the start of fracturing to this point, and calculate the degree of settlement at this time:

[0151]

[0152] The settling velocity of the proppant is:

[0153]

[0154] In the formula: v s The settling velocity of the proppant is expressed in m / s; t s The cumulative settlement time is expressed in seconds (s); H w f is the crack height, in meters (m); l For non-Newtonian fluid correction factors; f c f is the sand concentration correction factor; w K is the wall correction factor; K is the fluid consistency index, Pa·s n τ is the fluid flow index; n is the fluidity index. c Let d be the fluid relaxation time, in seconds; s ρ is the proppant particle size, m; g is the gravitational acceleration; ρ s The density of the proppant is kg / m³. 3 .

[0155] 3.2.1. If the proppant settlement exceeds 60% at this time, backflow is impossible. Increase the oil nozzle size and skip directly to step 5 to close the crack as quickly as possible.

[0156] 3.2.2. If the proppant settlement does not exceed 60% at this time, proceed to step 4.

[0157] It is worth noting that this step should be performed on all cracks. If the proppant settlement of any crack exceeds 60%, the oil nozzle should be increased to close the crack as quickly as possible.

[0158] 4. Calculation of critical flow rate of proppant

[0159] When the bottom hole pressure exceeds the fracture closure pressure, the fracture will not close, and the critical flow velocity at which the proppant inside the fracture will flow back is:

[0160] When N Re <2 hours:

[0161]

[0162] When 2 < N Re <500 hours:

[0163]

[0164] When N Re >500:

[0165]

[0166] When the bottom hole flowing pressure is less than the fracture closure pressure, the fracture closes, and the proppant inside the fracture is squeezed by the fracture, making backflow more difficult. The critical flow velocity at this time is:

[0167] When N Re <2 hours:

[0168]

[0169] When 2 < N Re <500 hours:

[0170]

[0171] When N Re >500:

[0172]

[0173] Where: N Re v is the Reynolds number; c δ is the critical flow velocity of the proppant, m / s; β is the ratio of the lift coefficient to the drag coefficient, taken as 0.25; α is the direction of the closing stress acting on the proppant; δ is the liquid film coefficient, taken as 0.213 × 10⁻⁶. -6 h s ρ is the distance from the proppant to the crack tip, in meters (m); l The density of the liquid phase is kg / m³. 3 μ is the viscosity of the fracturing fluid, mPa·s; σ is the interfacial tension between oil and water, mN / m.

[0174] 4.1. When the crack has been closed and the backflow velocity is less than the critical velocity of the proppant, increase the flow rate of the first-level nozzle and proceed to step 5.

[0175] 4.2. When the crack has closed and the backflow velocity is greater than the critical velocity of the proppant, reduce the nozzle size by one level and proceed to step 5.

[0176] 4.3. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is less than the critical proppant velocity, increase the pressure of the first-level nozzle and proceed to step 5.

[0177] 4.4. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is greater than the critical proppant velocity, reduce the nozzle size by one level and proceed to step 5.

[0178] It is worth noting that this step is performed on each crack. If the backflow velocity of any crack exceeds the critical flow velocity, the nozzle must be reduced.

[0179] 5. Calculation of bottom hole flowing pressure and velocity for pre-set nozzles

[0180] Adjusting the nozzle size (increase or decrease) predicts the gas and liquid production velocities corresponding to the preset nozzle size based on the nozzle flow velocity calculation formula. The nozzle flow velocity formula includes formulas for calculating the flow velocity of pure liquid nozzles and for gas-liquid two-phase nozzles. The formula for pure liquid nozzle flow is as follows:

[0181]

[0182] in:

[0183]

[0184] In the formula: q is the volumetric flow rate, m 3 / s;C D A is the nozzle flow coefficient; A is the nozzle flow area, m 2 g c Unit conversion factor; Δp is the pressure difference before and after the nozzle, MPa; ρ is the liquid density, kg / m³ 3 d1 is the pipe diameter, in meters; d2 is the nozzle size, in meters; N Re The Reynolds number is based on the nozzle size.

[0185] The formula for calculating the flow velocity in a gas-liquid two-phase nozzle is:

[0186]

[0187] q g =q l R p 17)

[0188] In the formula: q l and q g The volumetric flow rates, in m, are for the liquid and gas phases, respectively. 3 / s;;R p To produce a gas-liquid ratio, m3 / m 3 ;p t Oil pressure, MPa; f w This refers to the moisture content.

[0189] Repeat step 2 to obtain the bottom hole pressure and bottom hole velocity of the preset nozzle.

[0190] 6. Regulation methods

[0191] The control methods will be explained in detail depending on the specific circumstances:

[0192] 6.1. As described in 3.2.1, repeat step four to obtain the critical flow velocity at this point.

[0193] If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.1 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found.

[0194] 6.2. As described in situation 4.1, repeat step 4 to obtain the critical flow velocity at this point.

[0195] If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.2 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found. If the backflow velocity is greater than the critical velocity, the nozzle size of the previous stage is the most suitable nozzle size at present, and the adjustment ends.

[0196] 6.3. As described in situation 4.2, repeat step four to obtain the critical flow velocity at this point.

[0197] If the backflow velocity is less than the critical velocity, then the nozzle is the most suitable nozzle at present; if the backflow velocity is greater than the critical velocity, then the nozzle size is adjusted again, and steps 5 and 6.3 are repeated until the nozzle size with the maximum backflow velocity less than the critical velocity is found.

[0198] 6.4. As described in situation 4.3, repeat step 3 to determine the crack closure status at this point.

[0199] 6.4.1. The crack has been closed. Repeat step 4 to obtain the critical flow velocity at this point. If the backflow velocity is greater than the critical flow velocity, then the previous nozzle is the most suitable nozzle at present; if the backflow velocity is less than the critical flow velocity, then increase the nozzle size and repeat steps 5 and 6.2.

[0200] 6.4.2. If the crack is not closed and the settlement exceeds 60%, increase the oil nozzle size and repeat steps 5 and 6.1.

[0201] 6.4.3. If the crack is not closed and the settlement does not exceed 60%, repeat step 4 to obtain the critical flow velocity. If the backflow velocity is less than the critical proppant velocity, increase the nozzle size again and repeat steps 5 and 6.4 until the nozzle size that yields the maximum backflow velocity less than the critical velocity is found. If the backflow velocity is greater than the critical velocity, then the previous nozzle is the most suitable nozzle at this stage.

[0202] 6.5. As described in situation 4.4, repeat step 3 to determine the crack closure status at this point.

[0203] Because the flow rate is smaller due to the smaller nozzle size, the bottom hole pressure cannot be smaller than that described in section 4.4. Therefore, the fracture must be in an unclosed state.

[0204] Furthermore, according to the situation described in 4.4, the settlement degree does not exceed 60%, and the backflow velocity is greater than the critical flow velocity, indicating that the backflow velocity is too fast. Therefore, settlement is unlikely to occur in this step.

[0205] Repeat step 4 to obtain the critical flow rate at this point. If the backflow velocity is greater than the critical flow rate, reduce the nozzle size again and repeat steps 5 and 6.5 until the nozzle size with the maximum backflow velocity less than the critical flow rate is found. If the backflow velocity is less than the critical flow rate, then this nozzle is the most suitable nozzle at this point.

[0206] It is worth noting that step 6 already assesses the suitability of the new primary nozzle; therefore, in step 6, "nozzle" refers to the new primary nozzle. For example, if the nozzle in steps 1 to 4 is 4mm, its preceding nozzle is 3mm, and its next nozzle is 5mm, then in step 6, the nozzle will be 5mm, its preceding nozzle 4mm, and its next nozzle 6mm. Conversely, if the nozzle will be 3mm, its preceding nozzle 2mm, and its next nozzle 4mm.

[0207] The proposed method for dynamic control of the nozzle size in shale oil horizontal wells after hydraulic fracturing takes into account proppant settling and proppant backflow, and fully considers the situation where multiple fractures exist in multi-stage fracturing of horizontal wells.

[0208] The following are several specific embodiments of the application of the present invention.

[0209] Example 1

[0210] In a specific embodiment 1 of the present invention, the design method for dynamically controlling the size of the nozzle for post-pressure drainage in shale oil horizontal wells includes the following steps:

[0211] The invention is further illustrated below with a practical example. This well employs horizontal well fracturing in stages, with a total of fifteen fractures, each spaced 20m apart. Wellhead production data is shown in Table 3, wellbore structure data in Table 4, and fracturing data in Table 5.

[0212] Table 3 Wellhead Production Data

[0213]

[0214]

[0215] Table 4 Wellbore Structure and Fracturing Data

[0216] Pipe diameter / mm 62 Roughness / m 0.000016 Single pipe length / m 50 Current nozzle / mm 2

[0217] Table 5 Fracturing Data

[0218] Closing pressure / MPa 40 <![CDATA[Proppant density / (kg / m 3 )]]> 1480 Temperature / °C 133 proppant particle size / mm 0.56 Fracturing fluid viscosity (mPa·s) 42 Well sealing time / day 59

[0219] Using the method and steps of this invention, the bottom hole flowing pressure and bottom hole flow velocity are calculated using the Beggs-Brill method, and the results are as follows: Figure 1 As shown.

[0220] like Figure 1 As shown, on day 9, the bottom hole pressure is less than the fracture closure pressure. At this time, the fracture closes and the production rate is extremely low. The liquid phase pressure drop loss caused by the flow through the fracture in the horizontal section is negligible, and the production rate is not much different. Therefore, this example only analyzes the first fracture.

[0221] The crack closed on day 9, and the calculated closure time was 67 days. Referring to step 3, the proppant settlement at this point was 55.48%, which does not exceed 60%. Referring to step 3.2.2, the critical flow velocities before and after crack closure were calculated and compared. Figure 2 As shown.

[0222] like Figure 2 As shown, the production rate is less than the critical flow rate, and no proppant backflow occurs. Currently, it is day 24. The fracture has closed, proppant settling is less than 60%, and no backflow occurs. Referring to step 4.1, increase the nozzle size; the nozzle size is now 3mm. Proceed to steps 5 and 6.2. At this point, the bottomhole production rate is 0.0027m / s. 3 / s, which is less than the critical flow rate. Referring to step 6.3, the most suitable nozzle size is 4mm after iterative calculation.

[0223] Example 2

[0224] In a specific embodiment 2 of the present invention, the design method for dynamically controlling the size of the nozzle for post-pressure drainage in shale oil horizontal wells includes the following steps:

[0225] The invention is further illustrated below with a practical example. This well employs horizontal well fracturing in stages, with a total of fifteen fractures, each spaced 42m apart. Wellhead production data is shown in Table 6, wellbore structure data in Table 7, and fracturing data in Table 8.

[0226] Table 6 Wellhead Production Data

[0227]

[0228]

[0229] Table 7 Wellbore Structure and Fracturing Data

[0230] Pipe diameter / mm 88.6 Roughness / m 0.000016 Single pipe length / m 50 Current nozzle / mm 2

[0231] Table 8 Fracturing Data

[0232] Closing pressure / MPa 58 <![CDATA[Proppant density / (kg / m 3 )]]> 2650 Temperature / °C 126 proppant particle size / mm 0.6375 Fracturing fluid viscosity (mPa·s) 4 Well sealing time / day 14

[0233] Using the method and steps of this invention, the bottom hole flowing pressure and bottom hole flow velocity are calculated using the Beggs-Brill method, and the results are as follows: Figure 4 As shown.

[0234] like Figure 4 As shown, when the well is first opened and the flow is reversed, the bottom flow pressure is equal to the fracture closure pressure. At this time, the fracture is closed. Referring to step 3.1, there is no need to perform settlement analysis on this well. We can directly skip to step 4 to perform critical flow velocity analysis.

[0235] Because the production rate at the heel of a horizontal well is greater than that at the toe, proppant reflow analysis is only performed on fractures near the heel. Figure 5 As shown, the production rate is less than the critical flow rate, and no proppant backflow occurs. Referring to step 4.1, increase the nozzle size; the nozzle size is now 3mm. Proceed to steps 5 and 6.2; the bottom hole production rate is now 0.0041m / s. 3 / s, which is less than the critical flow rate. Referring to step 6.3, the most suitable nozzle size is 3mm after iterative calculation.

[0236] Example 3

[0237] In a specific embodiment 3 of the present invention, the design method for dynamically controlling the size of the nozzle for post-pressure drainage in shale oil horizontal wells includes the following steps:

[0238] The invention is further illustrated below with a practical example. This well employs horizontal well fracturing in stages, with a total of fifteen fractures, each spaced 50m apart. Wellhead production data is shown in Table 9, wellbore structure data in Table 10, and fracturing data in Table 11.

[0239] Table 9 Wellhead Production Data

[0240]

[0241]

[0242] Table 10 Wellbore Structure and Fracturing Data

[0243] Pipe diameter / mm 115 Roughness / m 0.000016 Single pipe length / m 50 Current nozzle / mm 5

[0244] Table 11 Fracturing Data

[0245] Closing pressure / MPa 65.14 <![CDATA[Proppant density / (kg / m 3 )]]> 1600 Temperature / °C 135 proppant particle size / mm 0.3185 Fracturing fluid viscosity (mPa·s) 3 Well sealing time / day 3

[0246] Using the method and steps of this invention, the bottom hole flowing pressure and bottom hole flow velocity are calculated using the Beggs-Brill method, and the results are as follows: Figure 6 As shown.

[0247] like Figure 6 As shown, the current bottom hole flowing pressure is greater than the fracture closure pressure, so the fracture is not closed. Calculations show that the current proppant settlement is 46.1%, which does not exceed 60%. Refer to step 3.2.2 and proceed to step 4 to analyze the proppant backflow.

[0248] Because the production rate at the heel of a horizontal well is greater than that at the toe, proppant reflow analysis is only performed on fractures near the heel. Figure 7 As shown, the production rate exceeds the critical flow rate, causing proppant backflow. Referring to step 4.4, reduce the nozzle size to 4mm. Proceed to steps 5 and 6.5; the bottom hole production rate is now 0.0007m / s. 3 / s, which is greater than the critical flow rate. Referring to step 6.5, the most suitable nozzle size is 2mm after iterative calculation.

[0249] Finally, it should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

[0250] Except for the technical features described in the specification, all other technologies are known to those skilled in the art.

Claims

1. A design method for dynamically adjusting the size of the nozzle in a shale oil horizontal well after pressure control and production, characterized in that... The design method for dynamic control of the appropriate nozzle size in the post-pressure production of horizontal shale oil wells includes: Step 1: Collect fracturing data, wellbore structure data, and wellhead production data; Step 2: Calculate the bottom hole flowing pressure and bottom hole flowback velocity based on the collected data; Step 3: Calculate the degree of proppant settlement; Step 4: Calculate the critical flow rate of the proppant; Step 5: Calculate the preset nozzle bottom-hole flowing pressure and bottom-hole flowing velocity; Step 6: Adjust the nozzle under different conditions to obtain the appropriate nozzle size. In step 3, when the proppant settlement exceeds 60%, the conductivity at the fracture decreases significantly. Therefore, it is necessary to ensure that the proppant settlement does not exceed 60%. Ignoring the perforation pressure difference, the calculated bottom hole flowing pressure is the flowing pressure at the bottom hole fracture opening. Compare the bottom hole flowing pressure at each fracture with the fracture closure pressure. Perform step 3 on each fracture. If the proppant settlement exceeds 60% at any fracture, the nozzle must be increased to close the fracture as quickly as possible. In step 3, comparing the bottom-hole flowing pressure and fracture closure pressure at each fracture includes: Step 3.

1. If the bottom hole flowing pressure is less than the fracture closure pressure, the fracture has been closed. At this point, there is no need to determine the degree of proppant settlement, and you can proceed directly to step 4. Step 3.

2. If the bottom hole flowing pressure is greater than the fracture closure pressure, and the fracture has not yet closed, calculate the time from the start of fracturing to this point, and calculate the degree of settlement at this time: The settling velocity of the proppant is: In the formula: The settling velocity of the proppant is in m / s; The cumulative settlement time is expressed in seconds. The crack height is in meters (m). For non-Newtonian fluid correction factors; This is the sand concentration correction factor; K is the wall correction factor; K is the fluid consistency index, Pa·s n , where n is the fluid flowability index; Let be the fluid relaxation time, in seconds; The particle size of the proppant is in meters (m); g is the acceleration due to gravity. The density of the proppant is kg / m³. 3 ; In step 4, when the bottom hole flowing pressure is greater than the fracture closure pressure, the fracture is not closed, and the critical flow velocity at which the proppant inside the fracture flows back is: when hour: when hour: when hour: When the bottom hole flowing pressure is less than the fracture closure pressure, the fracture closes, and the proppant inside the fracture is squeezed by the fracture, making backflow more difficult. The critical flow velocity at this time is: when hour: when hour: when hour: In the formula: It is the Reynolds number; The critical flow rate of the proppant is in m / s; The particle size of the proppant is in meters (m). The density of the proppant is kg / m³. 3 ; The ratio of the lift coefficient to the drag coefficient is taken as 0.25; The direction of the closing stress acting on the proppant; The liquid film coefficient is taken as 0.213 × 10⁻⁶. -6 ; The distance from the proppant to the top of the crack, in meters (m). The density of the liquid phase is kg / m³. 3 ; The viscosity of the fracturing fluid is mPa·s; The oil-water interfacial tension is expressed in mN / m. Step 4 is performed on each crack. If the backflow velocity of any crack exceeds the critical flow velocity, the oil nozzle must be reduced. Step 4 specifically includes: Step 4.

1. When the crack has closed and the backflow velocity is less than the critical velocity of the proppant, increase the flow rate of the first-level nozzle and proceed to step 5. Step 4.

2. When the crack has closed and the backflow velocity is greater than the critical velocity of the proppant, reduce the nozzle size by one level and proceed to step 5. Step 4.

3. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is less than the critical proppant velocity, increase the pressure of the nozzle by one level and proceed to step 5. Step 4.

4. When the crack is not closed, the proppant settlement does not exceed 60%, and the backflow velocity is greater than the critical proppant velocity, reduce the nozzle size by one level and proceed to step 5.

2. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 1, is characterized in that... In step 1, the fracturing data includes fracture width, fracture height, fracture closure pressure, proppant density, average proppant particle size, and fracturing fluid viscosity, which are used to calculate the critical proppant flow rate and proppant settling degree; the wellbore structure data includes well trajectory data, pipe diameter, and roughness, which are used to calculate the bottom hole flowing pressure and bottom hole flow velocity; the wellhead production data is real-time monitoring data, including wellhead oil pressure, liquid volumetric flow rate, and gas volumetric flow rate.

3. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 1, is characterized in that... In step 2, considering frictional losses and multiphase pipe flow characteristics, the bottom hole flowing pressure and bottom hole flow velocity are calculated, specifically including: Step 2.

1. Select a multiphase pipe flow calculation method, and use the Beggs-Brill method for calculation; Step 2.

2. Determine the current wellhead production data, including the current wellhead pressure, wellhead temperature, liquid volumetric velocity, and gas volumetric velocity. Starting from the wellhead, set the unit pipe segment ΔH, assuming that the wellhead to the bottom of the well is calculated in segments, and assuming the pressure drop ΔP in the unit pipe segment interval. Step 2.

3. Perform parameter calculations within the unit pipe section, including the average pressure and average temperature within the unit pipe section, and calculate the physical property parameters and flow pattern determination parameters within the pipe section. Step 2.

4. Identify the flow pattern and determine the flow pattern of the unit pipe segment based on the flow pattern boundaries of the Beggs-Brill method. Step 2.

5. Calculate the gravity and friction loss gradients in the vertical section of the horizontal well; Step 2.

6. Calculate the pressure drop in the horizontal section of the horizontal well; Step 2.

7. Starting from the wellhead, compare the calculated pressure drop of this pipe section. Compared with the assumed pressure drop If it exceeds the allowable error range, then let Return to step 2.3 and iterate again until the error range is met, then increase the depth by one unit segment; Step 2.

8. Calculate the bottom hole flowing pressure and bottom hole flowing velocity. Repeat steps 2.3, 2.4, 2.5 and 2.7 to the end of the vertical well section. In the horizontal well section, repeat steps 2.3, 2.4, 2.6 and 2.7 to the end of the horizontal section to calculate the bottom hole flowing pressure and bottom hole flowing velocity at each fracture.

4. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 3, is characterized in that... In step 2.5, the actual density, gravity loss gradient, frictional pressure drop gradient, and total pressure drop gradient of the mixture are calculated according to the calculation method corresponding to the flow regime. (1) Gravity loss gradient (2) Frictional pressure drop gradient (3) Total pressure loss gradient in, The average density is kg / m³. 3 ; The angle of inclination; The apparent velocity of the mixed fluid is given in m / s. The apparent velocity of the gas is in m / s; The diameter of the pipe is in meters (m). The average pressure of this pipe section is expressed in MPa.

5. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 3, is characterized in that... In step 2.6, shale oil development often utilizes horizontal wells with multi-stage fracturing, resulting in multiple fractures. Each time the fluid passes through a fracture, its energy decreases to some extent, increasing the pressure drop along the pipeline. This pressure drop due to fluid loss in the horizontal well section is the sum of the pipeline friction pressure drop and the accelerated pressure drop, specifically expressed as: in: In the formula: Total pressure drop, MPa; To accelerate the pressure drop, MPa; Frictional resistance voltage drop, MPa; The pressure drop at crack 1 is accelerated, in MPa; Accelerated pressure drop at crack 2, MPa; The density of the flowback fluid at crack 1 is kg / m³. 3 ; The flow velocity of the backflow fluid at crack 1 is m / s; Density of the backflow fluid at crack 2, kg / m³ 3 ; The flow velocity of the backflow fluid at crack 2 is m / s.

6. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 1, is characterized in that... Step 3.2 includes: Step 3.2.

1. If the proppant settlement exceeds 60% at this time, backflow is impossible. Increase the oil nozzle size and skip directly to step 5 to close the crack as quickly as possible. Step 3.2.

2. If the proppant settlement does not exceed 60% at this time, proceed to step 4.

7. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 1, is characterized in that... In step 5, adjust the nozzle size to increase or decrease, and predict the gas production rate and liquid production rate corresponding to the preset nozzle size based on the nozzle flow rate calculation formula. The nozzle flow velocity formulas include those for pure liquid nozzle flow velocity and those for gas-liquid two-phase nozzle flow velocity. The formula for pure liquid nozzle flow velocity is as follows: in: In the formula: q is the volumetric flow rate, m 3 / s; A is the nozzle flow coefficient; A is the nozzle flow area, m 2 ; Unit conversion factor; The pressure difference across the nozzle, in MPa; The density of the liquid is kg / m³. 3 ; Pipe diameter, in meters (m); The nozzle size is in meters (m). The Reynolds number is based on the nozzle size; The formula for calculating the flow velocity in a gas-liquid two-phase nozzle is: In the formula: and The volumetric flow rates, in m, are for the liquid and gas phases, respectively. 3 / s; To produce a gas-liquid ratio, m 3 / m 3 ; Oil pressure, MPa; Moisture content; Repeat step 2 to obtain the bottom hole pressure and bottom hole velocity of the preset nozzle.

8. The design method for dynamic control of reasonable nozzle size in shale oil horizontal well production after pressure control, as described in claim 7, is characterized in that... Step 6 includes: Step 6.

1. As described in Case 3.2.1, repeat step 4 to obtain the critical flow velocity at this point; If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.1 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found. Step 6.

2. As described in Case 4.1, repeat Step 4 to obtain the critical flow velocity at this point; If the backflow velocity is less than the critical velocity, increase the nozzle size again and repeat steps 5 and 6.2 until the nozzle size that has the maximum backflow velocity less than the critical velocity is found; if the backflow velocity is greater than the critical velocity, the nozzle size of the previous stage is the most suitable nozzle size at present, and the adjustment ends. Step 6.

3. As described in Case 4.2, repeat Step 4 to obtain the critical flow velocity at this point; If the backflow velocity is less than the critical velocity, then the nozzle is the most suitable nozzle at present; if the backflow velocity is greater than the critical velocity, then the nozzle size is adjusted again, and steps 5 and 6.3 are repeated until the nozzle size with the maximum backflow velocity less than the critical velocity is found. Step 6.

4. As described in situation 4.3, repeat step 3 to determine the crack closure status at this point; Step 6.4.

1. The crack has been closed. Repeat step 4 to obtain the critical flow rate at this time. If the backflow rate is greater than the critical flow rate, then the previous nozzle is the most suitable nozzle at this time. If the backflow rate is less than the critical flow rate, then increase the nozzle size and repeat steps 5 and 6.

2. Step 6.4.

2. The crack is not closed. At this time, the settlement exceeds 60%. Increase the oil nozzle size and repeat steps 5 and 6.

1. Step 6.4.

3. The crack is not closed. At this time, the settlement degree does not exceed 60%. Repeat step 4 to obtain the critical flow velocity at this time. If the backflow velocity is less than the critical flow velocity of the proppant, increase the nozzle size again and repeat steps 5 and 6.4 until the nozzle size with the maximum backflow velocity less than the critical flow velocity is found. If the backflow velocity is greater than the critical flow velocity, then the previous nozzle is the most suitable nozzle at this time. Step 6.

5. As described in situation 4.4, repeat step 3 to determine the crack closure status at this point; Because the nozzle is small, the return flow rate is reduced, and the bottom hole flowing pressure cannot be smaller than that in the case described in 4.

4. Therefore, the fracture must be in an unclosed state. Furthermore, according to the situation described in 4.4, the settlement degree does not exceed 60%, and the backflow velocity is greater than the critical flow velocity, indicating that the backflow velocity is too fast. Therefore, settlement is impossible in this step. Repeat step 4 to obtain the critical flow rate at this time; if the backflow rate is greater than the critical flow rate, adjust the nozzle size again and repeat steps 5 and 6.5 until the nozzle size with the maximum backflow rate less than the critical flow rate is found; if the backflow rate is less than the critical flow rate, then the nozzle is the most suitable nozzle at this time. Step 6 has already determined whether the new first-level nozzle is reasonable. Therefore, in step 6, the nozzle refers to the new first-level nozzle.

9. A design system for dynamic control of the appropriate nozzle size for post-pressure drainage production in shale oil horizontal wells, characterized in that: The design system for dynamic control of the reasonable nozzle size in the post-pressure drainage of shale oil horizontal wells adopts the design method for dynamic control of the reasonable nozzle size in the post-pressure drainage of shale oil horizontal wells as described in any one of claims 1-8, and performs real-time control of the drainage nozzle based on the actual drainage situation in the field.

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