A method for designing fracturing flowback system after segmented fracturing of horizontal well in compact gas reservoir

Abstract

The application provides a method for designing fracturing flowback system after segmented fracturing of a horizontal well in a compact gas reservoir, and belongs to the technical field of fracturing flowback after fracturing in an oil and gas field. A pressure initial value at a wellhead in a post-fracturing flowback stage is obtained, and a wellbore end pressure is calculated through a wellbore pressure drop and a pipe flow friction pressure drop model; the wellbore end pressure is taken as a fracture average pressure calculation initial value, the fracture average pressure is calculated, the fracture average pressure is subtracted by a pressure loss in a flowback process, and a new wellhead pressure is obtained; a critical flow velocity of a proppant at rest in a fracture is obtained, and a wellhead liquid discharge flow velocity under the corresponding critical flow velocity is calculated; according to a corresponding relationship between the pre-obtained wellhead pressure and the liquid discharge flow velocity and a choke diameter, the diameter of the choke to be used under the corresponding new wellhead pressure and the current critical liquid discharge flow velocity is determined, and in the post-fracturing flowback process, the above process is repeated, and the choke is continuously adjusted until the fracture average pressure reaches a closure pressure. The application can improve the fracture closure speed and reduce the proppant backflow.

Description

Technical Field

[0001] This invention provides a design method for a fracturing flowback system after staged fracturing in horizontal wells of tight gas reservoirs, belonging to the field of fracturing flowback technology in oil and gas fields. Background Technology

[0002] After years of development, horizontal well fracturing in tight oil and gas reservoirs has formed a fracturing technology in the Ordos work area that is dominated by soluble bridge plug fracturing and coiled tubing bottom-sealed fracturing, supplemented by multi-stage external packer fracturing and hydraulic jet-driven tubing string fracturing.

[0003] In recent years, the Ebei Gas Field has primarily focused on horizontal well development, with horizontal sections ranging from 800 to 1000 meters in length. The main reservoirs are the Shihezi, Shanxi, and Taiyuan Formations. Fracturing techniques mainly include soluble bridge plug staged fracturing, coiled tubing with bottom seal, and open-hole pre-installed tubing fracturing. Conventional guar gum fracturing fluid systems are commonly used. Through continuous exploration and improvement of fracturing techniques, the staged proppant fracturing technology for horizontal wells has become increasingly mature. However, the supporting post-fracturing flowback technology still has certain shortcomings.

[0004] (1) Relying on experience to determine the post-pressurization return system results in significant differences in the gas seepage period, which affects the construction progress;

[0005] (2) Some wells have low flowback rates, which affects the effectiveness of the treatment.

[0006] (3) Some wells experienced severe sand production during the backflow process.

[0007] Poor flowback directly prevents fracturing fluid from being quickly and timely discharged from the reservoir, damaging the reservoir and significantly impacting the effectiveness of production enhancement measures. In the past, determining the size of the fracturing nozzle was largely based on experience, with different people potentially providing different nozzle sizes. A nozzle that is too large may significantly reduce the flow capacity at the fracture opening due to proppant backflow; a nozzle that is too small may result in a higher proportion of proppant settling at the fracture bottom, also affecting the final fracturing effect.

[0008] In summary, after fracturing horizontal wells in tight oil and gas reservoirs in stages, if the appropriate size of the nozzle is not selected for flowback fracturing fluid, the flowback rate will be low, resulting in low oil and gas production. Summary of the Invention

[0009] The purpose of this invention is to provide a design method for the fracturing and flowback system after staged fracturing in horizontal wells of tight gas reservoirs, which can solve the problems of low flowback rate and low oil and gas production after staged fracturing in horizontal wells of tight gas reservoirs.

[0010] To achieve the above objectives, the present invention provides a method for designing a fracturing flowback regime after staged fracturing in a horizontal well of a tight gas reservoir, comprising the following steps:

[0011] 1) Obtain the initial value of the wellhead pressure, and calculate the pressure at the end of the well using the wellbore pressure drop and pipe flow friction pressure drop model;

[0012] 2) Using the wellbore end pressure as the initial value of the fracture average pressure, calculate the fracture average pressure, subtract the pressure loss during the flowback process from the fracture average pressure, and calculate the new wellhead pressure.

[0013] 3) Obtain the critical flow velocity of the proppant when it is stationary in the fracture during the flowback process, and perform forward calculation from the bottom of the well to the wellhead to obtain the critical flow velocity of the fracturing fluid at the wellhead;

[0014] 4) Based on the pre-obtained correspondence between the wellhead pressure and the critical flow velocity of the fracturing fluid at the wellhead and the nozzle diameter, determine the nozzle diameter required for the new wellhead pressure and the current critical flow velocity of the fracturing fluid at the wellhead.

[0015] 5) Using the new wellhead pressure in step 2) as the initial wellhead pressure, repeat steps 1) to 4) until the average fracture pressure reaches the closure pressure.

[0016] The initial pressure at the wellhead during the post-pressure flowback stage is obtained. The wellhead pressure is calculated using a wellbore pressure drop and tubing friction pressure drop model. This wellhead pressure is then used as the initial value for calculating the average fracture pressure. The average fracture pressure is calculated by subtracting the pressure loss during flowback from the average fracture pressure to obtain the new wellhead pressure. The critical velocity at which the proppant remains stationary in the fracture is obtained, and the corresponding wellhead drainage velocity is calculated. Based on the pre-obtained correspondence between wellhead pressure, drainage velocity, and nozzle diameter, the nozzle diameter required for the new wellhead pressure and the current critical drainage velocity is determined. During the post-pressure flowback process, this process is repeated, continuously adjusting the nozzle until the average fracture pressure reaches the closure pressure. This invention can improve fracture closure speed and reduce proppant backflow.

[0017] Furthermore, in the above method, in step 5), the correspondence between wellhead pressure and discharge flow rate and nozzle diameter is determined by the following method:

[0018] The flow rate at the nozzle was determined by experiments under different wellhead pressures and when using nozzles of different diameters for backflow, and this flow rate was used as the flow rate at the corresponding wellhead pressure and nozzle diameter.

[0019] By using experimental calibration methods and simulating different wellhead pressures with nozzles of different diameters, flowback experiments were conducted to determine the corresponding flow rates under different wellhead pressures and nozzle diameters. This experimental calibration method allows for adjustment of wellhead pressure and nozzle diameter based on actual conditions, facilitating observation and operation.

[0020] Furthermore, in the above method, in step 5), the critical flow velocity of the proppant when it is stationary in the fracture is calculated by the proppant fracturing flowback initiation model in the fracture.

[0021] A more accurate method for calculating the critical flow velocity of proppant when it is stationary in a fracture is proposed. This method analyzes the actual situation of proppant in fractures using a fracturing flow initiation model, resulting in a more accurate calculated critical flow velocity.

[0022] Furthermore, in the above method, in step 1), the pump stop pressure when the fracturing fluid injection is stopped is used as the initial value of the wellhead pressure.

[0023] The initial wellhead pressure is taken from the pump shutdown pressure when the fracturing fluid injection is stopped, which is easy to obtain.

[0024] Furthermore, in the above method, fiber proppant plus sand fracturing is used in the fracturing stage before the flowback process.

[0025] The added fiber proppant has strong stability, which helps prevent proppant backflow and thus improves the backflow rate.

[0026] Furthermore, in the above method, liquid nitrogen is injected during the fracturing stage before the flowback process. The fracturing stage includes an early fracturing stage and a later fracturing stage, and the amount of liquid nitrogen injected during the early fracturing stage is greater than the amount of liquid nitrogen injected during the later fracturing stage.

[0027] In horizontal well fracturing, increasing the liquid nitrogen injection rate in the first few stages of fracturing and gradually decreasing the liquid nitrogen injection rate in subsequent stages can improve the efficiency of fracturing fluid discharge during the drainage process, reduce the number of times the nozzle needs to be replaced, and improve the efficiency of post-fracturing flowback. Attached Figure Description

[0028] Figure 1 This is a flowchart illustrating the design method for the fracturing and flowback regime after staged fracturing of a horizontal well in a tight gas reservoir, as described in an embodiment of the present invention.

[0029] Figure 2 This is a schematic diagram of horizontal well fracturing and flowback in an embodiment of the present invention;

[0030] Figure 3 This is a schematic diagram of the wellhead oil pressure drop prediction curve in an embodiment of the present invention;

[0031] Figure 4 This is a schematic diagram of the post-pressure flowback curve of a high-yield well in an embodiment of the present invention;

[0032] Figure 5 This is a schematic diagram of the post-pressure flowback curve of a medium-yielding well in an embodiment of the present invention;

[0033] Figure 6 This is a schematic diagram of the post-pressure flowback curve of a low-yield well in an embodiment of the present invention;

[0034] Figure 7 This is a schematic diagram illustrating the mechanism of proppant backflow within the crack in an embodiment of the present invention;

[0035] Figure 8 This is a schematic diagram of the horizontal well shaft structure in an actual embodiment of the present invention;

[0036] Figure 9 This is a schematic diagram of the main interface of the horizontal well pressure-driven flowback software in an embodiment of the present invention;

[0037] Figure 10 This is a schematic diagram of the input / output interface of the horizontal well pressure recovery software in an embodiment of the present invention;

[0038] Figure 11 This is a schematic diagram illustrating the relationship between different wellhead pressures and the optimal return nozzle diameter in an embodiment of the present invention;

[0039] Figure 12 This is a schematic diagram of the wellhead pressure drop curves when different nozzles are selected for backflow in well DPH-3 in an embodiment of the present invention.

[0040] Figure 13 This is a schematic diagram showing the relationship between wellhead pressure and critical flow velocity in fractures when a 2mm nozzle is selected for backflow in well DPH-3 in an embodiment of the present invention.

[0041] Figure 14 This is a schematic diagram showing the relationship between wellhead pressure and critical flow velocity in fractures when a 4mm nozzle is selected for backflow in well DPH-3 in an embodiment of the present invention.

[0042] Figure 15 This is a schematic diagram showing the relationship between wellhead pressure and critical flow velocity in fractures when a 6mm nozzle is selected for backflow in well DPH-3 in an embodiment of the present invention.

[0043] Figure 16 This is a curve showing the relationship between bottom hole pressure and flowback time when using nozzles of different diameters for flowback in well DPH-3 according to an embodiment of the present invention.

[0044] Figure 17 This is a schematic diagram of the wellhead pressure change of well DPH-3 after selecting different nozzles according to the flowback time in an embodiment of the present invention;

[0045] Figure 18 This is a force analysis diagram of the proppant in an embodiment of the present invention. Detailed Implementation

[0046] To make the objectives, technical solutions, and advantages of the present invention clearer, the present invention will be further described in detail below with reference to the accompanying drawings and embodiments.

[0047] Method Example 1:

[0048] For hydraulic fracturing of horizontal wells in low-permeability tight reservoirs, relying solely on natural fracture closure after fracturing often takes a long time. Therefore, forced fracture closure technology is typically employed in hydraulic fracturing design and construction. This invention provides a design method for the fracturing flowback regime after staged fracturing of horizontal wells in tight gas reservoirs. Based on considerations of two-dimensional filtration loss of fracturing fluid and its flow within the wellbore, a mathematical model for forced fracture closure is established using the principles of mass balance, fluid mechanics, and rock fluid mechanics. The method analyzes the variation between different diameter blowout nozzles and corresponding wellhead pressures during forced fracture closure, providing a theoretical basis for field personnel to select appropriate flowback timing and nozzles during forced flowback.

[0049] like Figure 1 As shown, the method for designing a fracturing flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to the present invention includes the following steps:

[0050] Step S1: Establish a forced crack closure model. The forced crack closure model includes pressure iterative solution formulas, velocity inverse solution formulas, and proppant recirculation solution formulas.

[0051] When establishing a crack forced closure model, the following assumptions need to be set:

[0052] ① The height of the fracture front is constant and equal to the effective thickness of the fracturing layer;

[0053] ② The viscosity of the fracturing fluid changes linearly from the bottom of the well to the fracture end, or the viscosity of the fracturing fluid remains constant;

[0054] ③ The crack closes freely without being affected by the proppant, and the closure of the crack only reduces the crack width, while the crack height and length remain unchanged;

[0055] ④ After the pump is stopped, the crack immediately stops proliferating;

[0056] ⑤ Ignore the liquid breaking time after the addition of the breaking agent, that is, instantaneous breaking.

[0057] Based on the assumptions of the aforementioned forced fracture closure model, a comprehensive analysis and study of the fracture flowback mechanism after horizontal well fracturing is conducted. Furthermore, based on this analysis, [the study addresses...]. Figure 2 In the horizontal wellbore structure, a corresponding mathematical model is established to optimize the backflow effect.

[0058] The mathematical model is as follows:

[0059] Formula for the flow model of sand-carrying fluid in the wellbore:

[0060] According to the principle of volume balance, when fracturing fluid is forced to flow back, the change in fracture volume is equal to the sum of the total fracturing fluid loss and the flowback amount from the moment of flowback.

[0061]

[0062] During the flowback process, the fracturing fluid needs to overcome tubing resistance and gravity. When the fracturing fluid reaches the wellhead, the pressure drops, as shown in the following equation:

[0063]

[0064] In the formula: —Pressure of the tubing at the crack, MPa;

[0065] —Friction along the pipeline during fracturing fluid flowback, MPa;

[0066] —Represents the hydrostatic pressure in the wellbore, in MPa

[0067] The flowback rate and total fluid loss of the fracturing fluid are calculated below. If the flowback is uniform, the formula for the cumulative flowback rate is:

[0068]

[0069] The change in the return flow rate corresponds to the change in return flow rate Q per unit time and the change in cumulative return flow rate V. 排 The calculation formulas are as follows:

[0070]

[0071]

[0072] Since the wellhead pressure P(t) in the integral is a nonlinear function, a composite trapezoidal integral formula is used to solve it.

[0073]

[0074] in,

[0075] In the above formula, The time step is determined in the same way as the method for calculating the filter loss below; the superscript n indicates t. n Time; P(t) o P(t) represents the pressure at the wellhead immediately after the pump is stopped. If the pumping is started immediately after the pump is stopped, then P(t) represents the pressure at the wellhead immediately after the pump is stopped. o The pressure P is equal to the instantaneous pump stop pressure after fracturing. 停 .

[0076] During the backflow process, it follows the bottom pressure P f And what changes is in t n Time, from t1 to t n-1The crack pressure value at time t has been determined. Only Functions:

[0077]

[0078] During fracturing fluid flowback, many researchers neglect the wellbore friction pressure drop when calculating wellhead pressure for the sake of calculation convenience. Here, our model considers the wellbore friction pressure drop, making the calculation results more accurate and reliable.

[0079] Formula for calculating the frictional pressure drop of fracturing fluid:

[0080] ① Calculation of frictional pressure drop in Newtonian fluid flow:

[0081] Newtonian fluid friction is related to the fluid flow state, which is determined by the Reynolds number:

[0082]

[0083] when The fluid flow is laminar, and the friction coefficient is: .

[0084] when The fluid flow is turbulent, and the friction coefficient is: .

[0085] Friction coefficient along the friction line: .

[0086] Hydraulic pressure drop along the route: .

[0087] Where: N Re One Reynolds number, dimensionless;

[0088] — Viscosity of the fracturing fluid, mPa·s;

[0089] v is the fluid velocity inside the tubular column, in m / s;

[0090] D is the diameter of the tubing, in meters;

[0091] Fracturing fluid density, kg / m³ 3 .

[0092] Calculation of fracturing fluid friction pressure drop:

[0093] ② Calculation of power-law type fracturing fluid friction pressure drop:

[0094] Most fracturing fluids exhibit power-law liquid properties, and their apparent viscosity can be approximated by their flow characteristics within the tubing string. In place of Newton's fluid formula ,Right now:

[0095]

[0096] The Reynolds number for a power-law fluid is:

[0097] Where: Ka is the consistency coefficient of the fracturing fluid flowing in the wellbore. ;

[0098] n—Rheological index of fracturing fluid.

[0099] For the calculation of Reynolds number and flow regime determination of non-Newtonian veil-law fluid pipe flow, the calculation methods for Newtonian fluids are currently mostly used. When ≤2100, the fluid flow is laminar; when When the temperature is greater than 2100°C, the fluid flow is turbulent. The friction coefficient for different flow regimes can be approximately calculated using the Newtonian fluid friction pressure drop formula for a circular pipe, simply by changing N in the formula. Re Change to That's all.

[0100] Establish the coupling formula between horizontal well fractures and horizontal wellbore:

[0101] During the flow of fracturing fluid into the wellbore, the fracture and tubing form a connected system. Therefore, it is necessary to establish a coupling formula between the fracture and the wellbore in a horizontal well. When the flowback velocity of the fracturing fluid in the tubing is known, the approximate flowback velocity of the fracturing fluid in the fracture can be calculated based on this system.

[0102] From the continuity equation The flow rate of fracturing fluid in the fracture:

[0103]

[0104] Model of sand-carrying fracturing fluid producing sand in horizontal well fractures:

[0105] Schematic diagram of proppant recirculation model: If the last segment of proppant injected is not carried out of the fracture by the recirculated fracturing fluid during the flowback process, then the previously injected proppant will also not be carried out.

[0106] During fracturing fluid flowback, under the impact of the fracturing fluid, some proppant remains suspended in the fluid, while some flows towards the bottom of the well. Therefore, there must exist a critical flowback velocity in the fracturing fluid that drives proppant migration. Based on the following assumptions... Figure 18 As shown, the proppant rolls around point A as the fulcrum under the action of fluid impact force and effective gravity, and the drag resistance is:

[0107] In the design calculations for hydraulic fracturing, Cd The Novotny formula is generally used for calculation, that is: ;in, .

[0108] According to the principle of torque balance:

[0109]

[0110] For simplicity, assume that the lifting force equals the dragging force, that is:

[0111]

[0112]

[0113]

[0114] when When ≤2, k=24, τ=1. .

[0115] When 2 < When ≤500, k=18.5, τ=0.6. .

[0116] when When the value is greater than 500, k = 0.44, τ = 0. .

[0117] In the formula: d s — The diameter of a single proppant, in meters; — Density of the proppant, kg / m³ 3 A—Windward area of ​​the proppant, m 2 ; —Drag coefficient.

[0118] Step S2: In the proppant recirculation solution formula, the crack forced closure pressure and the critical flow velocity of the proppant when stationary in the crack are obtained by using the proppant initiation model in the crack.

[0119] In the pressure iteration solution formula, the pump stop pressure is taken as the starting point of the wellhead pressure. The pressure value at the end of the well is calculated by using the wellbore pressure drop and pipe flow friction pressure drop model. This pressure value at the end of the wellbore is used as the initial value for calculating the average fracture pressure. The average fracture pressure is calculated using the material balance equation: fracture volume change = fracturing fluid loss + wellhead flowback.

[0120] During the entire flowback process, the average fracture pressure is used to subtract the pressure loss during the flowback process to obtain the new wellhead pressure.

[0121] In the velocity inverse calculation formula, given different wellhead pressures, the fluid discharge velocity V1 at the wellhead is calculated based on the coupling model of the nozzle and wellbore. Then, using the continuity equation, the flowback velocity of the nozzle is calculated inversely from the wellhead to the bottom of the well, yielding the flowback velocity V2 of the fracturing fluid in the fracture during horizontal well fracturing. To ensure sand is not produced in the fracture, the flowback velocity V2 of the fracturing fluid in the fracture must be less than or equal to the critical velocity V3 at which the proppant remains stationary within the fracture.

[0122] The coupling model between the nozzle and the wellbore is as follows:

[0123] For the wellhead and the vent nozzle, Bernoulli's equation yields:

[0124]

[0125] The discharge rate at the oil pipe outlet is equal to the return flow rate from the nozzle, which can be obtained from the continuity equation:

[0126]

[0127] The backflow velocity at different times is obtained from formulas (2-6-1) and (2-6-2):

[0128]

[0129] In the formula: —Wellhead oil pressure, MPa;

[0130] —Pressure at the nozzle outlet, taken as standard atmospheric pressure, 0.1 MPa;

[0131] —The flow velocity of the backflow fracturing fluid at the wellhead is the same as the nozzle injection velocity, in m / s;

[0132] —Flow velocity of the fracturing fluid in the wellbore, m / s;

[0133] —Local drag coefficient, dimensionless, here taken as 0.5;

[0134] —radius of the injector, m; R —radius of the wellbore, m;

[0135] Fracturing fluid density, kg / m³ 3 ;

[0136] —Specific gravity of fracturing fluid. .

[0137] The nozzle flow rate increases with increasing wellhead pressure. Given a specific wellhead oil pressure, the nozzle velocity increases as the nozzle diameter decreases, but the nozzle discharge rate decreases. Therefore, to select a suitable nozzle size and ensure sand-free fractures during horizontal well fracturing and flowback, the flowback velocity V2 is set equal to the critical velocity V3. Then, the inverse velocity calculation formula is used to perform a forward calculation from the bottom of the well to the wellhead to obtain the critical discharge velocity V1 of the fracturing fluid at the wellhead.

[0138] Using the new wellhead pressure as the starting point, repeat the above steps and iterate repeatedly to calculate the new average fracture pressure after drainage until the average fracture pressure reaches the closure pressure.

[0139] Since the drainage velocity at the wellhead is controlled by both the wellhead pressure and the nozzle diameter, based on the pre-calibrated correspondence between wellhead pressure, drainage velocity, and nozzle diameter, a suitable return nozzle is selected for the new wellhead pressure and drainage velocity V1 obtained through iterative calculation. This ensures that sand is not discharged from the fractures, thereby achieving the goal of increased oil and gas production. Thus, through methods such as... Figure 3 The wellhead oil pressure drop prediction curve shown can help control the timing of nozzle replacement, and ensure that fracturing fluid is quickly returned from the fracture while ensuring that sand is not produced.

[0140] Method Example 2:

[0141] We collected and organized fracturing test data of horizontal wells in the Daniudi and Dongsheng gas fields in recent years. Based on the unobstructed flow rate for production testing, wells with an unobstructed flow rate above 10×10⁴ m³ / d were classified as high-yield wells, those with an unobstructed flow rate of 4–10×10⁴ m³ / d as medium-yield wells, and those with an unobstructed flow rate below 4×10⁴ m³ / d as low-yield wells. We summarized and analyzed the characteristics of post-fracturing fluid drainage of horizontal wells with different production capacities, providing a basis for optimizing the post-fracturing fluid drainage system.

[0142] Based on the exploration of the post-pressure flowback system for horizontal wells in the Ordos Gas Field in recent years, a preliminary working system has been established on-site, using 3mm-5mm nozzles as control nozzles for the forced closure stage of fractures (the specific size should be selected based on the wellhead pressure). This system basically meets the requirements of controlling fracture closure and preventing proppant backflow during post-pressure flowback.

[0143] The design method for the fracturing and flowback regime after staged fracturing in horizontal wells of tight gas reservoirs, based on the present invention, is implemented as follows during field operations of high, medium, and low-production wells:

[0144] High-yield wells have favorable formation properties, allowing fracturing fluid injected into the formation to easily diffuse into distant formations. During the ramp-up and release phase, the injected fracturing pressure is largely released, followed by a rapid rebound in oil pressure, which gradually increases to a high level at a relatively fast rate. Gas production gradually increases with wellhead pressure, and the daily fluid discharge typically decreases to 30 m³ / h. 3 the following.

[0145] like Figure 4 As shown, high-yield wells go through three stages during the venting and drainage phase: closed-loop control, increased drainage volume, and pressure rise. Generally, continuous drainage controlled by nozzles can meet the production requirements.

[0146] The working procedure for the closure control phase is as follows: First, a 3-5mm nozzle is selected, which usually takes 1-2 hours to force the fractures in the formation to close. When the bottom hole pressure is lower than the fracture closure pressure, the formation is closed. Then, the nozzle is enlarged appropriately to end the control closure phase.

[0147] The operating procedure during the scale-up drainage phase is as follows: 5-15mm nozzles are typically used for controlled or uncontrolled drainage, with the principle of ensuring no sand is produced in the formation (no sand particles are visible at the outlet of the venting line). This fully utilizes the elastic energy of the fracturing formation to drain the fluid, maximizing the drainage volume. The scale-up drainage phase has the following characteristics:

[0148] ①In the initial stage, the discharge is mainly liquid, forming a plug flow. Later, it becomes a two-phase flow of gas and liquid, with gas and water being sprayed simultaneously. Ignition of the gas is usually visible during this stage.

[0149] ②The crack is completely closed, and the proppant is clamped inside the crack wall by the compression of rock stress, and can be fixed in a relatively stable position.

[0150] ③ During this stage, the oil pressure goes through a process of first decreasing and then increasing (for wells with good geological conditions, the oil pressure only drops to about 2-3 MPa before starting to rise).

[0151] ④ The time required for this process varies greatly depending on the condition of the well, ranging from a few hours to more than ten hours.

[0152] ⑤ Due to the fingering effect of gas, nitrogen and natural gas in the fractures and formations migrate into the wellbore faster than liquids. The solubility of gas and liquid increases, the amount of gas entering the tubing increases, the jetting force increases, the wellhead oil pressure rises, the fluid is in a gas-liquid mixed state, and jetting force is seen at the outlet. This stage ends.

[0153] During the pressure rise phase, gas production and oil pressure generally increase rapidly. On-site, 6-10mm nozzles are typically used for control, and a test gas process is introduced to meter and control gas production and liquid volume. Controlled release during the pressure rise phase will prepare for the subsequent production stage.

[0154] The pressure escalation phase has the following characteristics:

[0155] In the early stage, it is a two-phase flow of gas and liquid. In the middle stage, it is a slug flow (first a section containing liquid gas, then a section containing gas liquid). In the later stage, due to the increased solubility of nitrogen and natural gas, water columns cannot be formed during the flow. Instead, it can only be discharged from the wellbore in the form of mist under the drive of high-speed airflow, which is a mist flow.

[0156] The oil pressure rose rapidly and then approached stability.

[0157] The amount of fluid discharged during this stage is significantly less than that during the scale-up stage, and the amount of fluid discharged shows a clear decreasing trend.

[0158] After this stage of return discharge is completed, the return discharge rate is generally around 30%, which is relatively low.

[0159] The characteristics of medium-yield wells are that after the blowout, the wellhead pressure drops to a very low level quickly and then rebounds, but the pressure rises relatively slowly. Gas production gradually increases with the increase of pressure. When the pressure and gas production do not increase significantly, the pressure usually shows a steady decline after the production pressure differential is increased, and the increase in gas production is not significant or basically does not increase.

[0160] like Figure 5 As shown, the venting and drainage stage of a medium-yield well typically lasts 1-5 hours and involves three phases: closure control, increased drainage volume, and pressure rise. On-site, continuous drainage is usually controlled by nozzles, combined with well-opening and shut-off stimulation drainage and unblocking measures to achieve the production conditions.

[0161] During the closure control phase, a 3mm nozzle is usually selected first. After 1-2 hours, the formation closes. Then, the nozzle is enlarged appropriately. When the bottom hole pressure is lower than the fracture closure pressure and the fracture is completely closed, the closure control phase ends. The post-pressure drainage data shows that after closure, a 5mm nozzle is used to control drainage. With an appropriate increase in nozzle size, there is no sand production.

[0162] The peak discharge phase is the optimal time to control the venting and drainage, as the amount of liquid discharged is relatively large, with a daily discharge volume of 500m³. 3 As described above, after increasing the displacement, the tubing pressure will drop rapidly. Once it reaches a certain level, it will gradually recover, and this stage ends. Most medium-yield wells begin to recover after the wellhead pressure drops to 2-4 MPa.

[0163] Pressure Rise Phase: After the increased production phase, the oil pressure typically drops significantly. As gas production increases, the oil pressure gradually recovers, but compared to high-production gas wells, the pressure recovery is noticeably slower, and the pressure drop is more pronounced during increased gas production. Generally, once the gas production and oil pressure stabilize after adjusting the nozzles on-site, this phase of fluid discharge ends, marking the start of the production recovery phase. During this phase, the daily fluid discharge is relatively low and shows a downward trend.

[0164] Low-production wells are characterized by a rapid drop in wellhead pressure after fracturing and venting, sometimes even to zero, with little or no rebound. The fluid discharge also decreases rapidly with the pressure drop, making drainage difficult or impossible, requiring manual lifting and drainage methods to achieve self-flow. Figure 6 As shown, low-production wells mainly rely on liquid nitrogen gas lift and pumping to assist in the drainage process during the venting and drainage phase, which includes the following stages:

[0165] ① Closure control stage: Use a 5mm nozzle;

[0166] ② Larger displacement stage: Use 6-12mm nozzles to allow for smooth drainage;

[0167] ③ Difficulty in draining fluid: Open the well, reduce the oil pressure to zero, and when the fluid column pressure in the wellbore equals the formation pressure, the draining process ends;

[0168] ④ Gas lift and pumping stage: After the induction of the flow, the formation pressure is higher than the wellbore fluid column pressure, and the fluid is pumped out.

[0169] After fracturing and venting, sand will be released from the formation. The sand will be unevenly dispersed at the vent, with low density per unit area. No sand line will appear at the bottom of the vent. At this point, the nozzle size should be gradually adjusted. The nozzle control should not be too drastic, otherwise it will inhibit the upward movement of the already released fracturing sand within the wellbore, causing settlement or even sand burial. The most important principle at this stage is to both remove residual sand from the wellbore and inhibit further sand release from the formation. Through on-site observation and changes in sand content, gradual control measures should be taken to ultimately eliminate the formation sand release phenomenon.

[0170] like Figure 7 As shown, the mechanism of proppant backflow in fractures is as follows: under the action of formation energy, the proppant in artificial fractures is carried into the wellbore by fracturing fluid or formation fluid.

[0171] Based on the survey, statistical analysis, and field tracking analysis of proppant backflow in horizontal fracturing wells in the Ordos region in recent years, the main reasons for sand production in fracturing wells in the Ordos region can be summarized as follows: ① Improper post-fracturing fluid drainage method; ② The scouring effect of high-speed flowing proppant-carrying fluid will lead to a larger fracture opening near the wellbore or in the near-wellbore formation; ③ Insufficient displacement of fracturing fluid, resulting in the proppant not being completely pushed into the formation; ④ Incomplete breaking of the fracturing fluid gel, during the post-fracturing fluid drainage process, the viscosity of the broken fracturing fluid residue is relatively high, and its ability to encapsulate, adsorb, and transport proppant is strong, making the proppant more prone to flow under the action of fluid backflow; ⑤ Improper drainage operation system, causing proppant backflow.

[0172] To address the various causes of sand production in fracturing wells, the following technical countermeasures are proposed to effectively prevent proppant backflow:

[0173] 1. Optimize the displacement fluid volume during fracturing operations

[0174] The fracture walls near the wellbore in fractured wells, under the erosion and scouring effects of high-pressure, high-speed proppant-carrying fluid, will cause excessively large fracture openings at the fracture entrance or in the near-wellbore formation, thus affecting the proppant's retention effect. Theoretically, injecting sufficient or slightly excessive displacement fluid should be an effective technological measure to prevent proppant backflow. Therefore, research on optimizing the displacement fluid volume should be conducted, appropriately increasing the displacement fluid volume to push the tail proppant a certain distance into the fracture, so that the fracture entrance has an effective retention effect on the proppant.

[0175] 2. Optimize the gel-breaking performance of fracturing fluid

[0176] If the fracturing fluid is not completely broken up, proppant backflow will be exacerbated. Under the same conditions, the higher the viscosity of the breaking fluid, the more severe the proppant backflow. It is necessary to study the influence of breaking fluid viscosity on the sand-carrying and transport patterns, and determine a critical viscosity at which proppant backflow can be effectively prevented. Further research should be conducted on the fracture temperature distribution during fracturing well construction to propose appropriate breaking agent addition patterns, ensuring the breaking effect of the fracturing fluid in the early, middle, and late stages of construction, especially in the later stages. This will effectively prevent proppant backflow in fracturing wells by improving the thoroughness of fracturing fluid breaking.

[0177] 3. Adjust the gas extraction work system appropriately.

[0178] During the production process, frequent well opening and closing, unblocking and venting can lead to drastic changes in production and bottom hole pressure differential. Production and bottom hole pressure differential should be appropriately controlled to reduce and prevent large-scale backflow of proppant.

[0179] 4. Using fiber-supported fracturing with sand.

[0180] To address the issues of low formation pressure, low fracturing fluid flowback rate, and low flowback ratio in the Ordos oil and gas field, a high-efficiency flowback technology combining liquid nitrogen and fiber fracturing was adopted to increase the flowback pressure differential of the fracturing fluid, prevent proppant backflow, and simultaneously increase the flowback rate. Due to the special immobilization properties of the fiber, even in high-yield gas wells, gas production can be increased without concern about large amounts of proppant being carried out.

[0181] Field experiments show that the addition of fibers to the proppant greatly improves its stability, which is beneficial for preventing proppant backflow. The fiber-reinforced fracturing technology significantly accelerates the fluid drainage rate, significantly improves the flowback rate, and significantly shortens the retention damage time of the fracturing fluid. Therefore, this technology is very effective in significantly increasing the critical sand flow rate of the proppant, significantly enhancing the stability of the proppant, achieving efficient and rapid flowback of the fracturing fluid after fracturing, and avoiding proppant backflow.

[0182] As shown in Table 1, four-stage fiber-reinforced fracturing was performed in well D66-145, with a total net fluid injection volume of 831.2 m³ into the formation. 3 Sand addition amount 110m 3 The drainage volume was 766.3 m³ after compression, with only 4 days of drainage. 3 The fracturing fluid flowback rate was 88.5%, a significant increase compared to adjacent wells, with no proppant backflow. This demonstrates the clear superiority of fiber fracturing.

[0183] Table 1 Comparison of Fiber Fracturing Construction Parameters and Conditions

[0184]

[0185] The purpose of liquid nitrogen co-injection during fracturing is to effectively lift the fluid and increase the flowback effect. The gas-liquid ratio and fusion effect of the flowback liquid are key to effective fluid drainage. In multi-stage fracturing operations in horizontal wells, due to the relatively long overall operation time, the previously fractured sections can only be flowed back after all fracturing is completed. By then, the fracturing fluid has broken down, the formation has closed, and as the liquid nitrogen converts to a gaseous state, it gradually separates from the fracturing fluid and rises further, thus forming a denitrification phenomenon. In many wells, the wellhead pressure remains high, the nitrogen volume at the drain outlet is large, but there is no substantial fluid drainage until the nitrogen is exhausted and the pressure drops to zero. At this point, the denitrified fluid begins to rise, has no effective viscosity, and the flow rate and temperature gradually decrease, indicating that the upward speed of the fluid is very slow, which may ultimately lead to unsuccessful blowout.

[0186] like Figure 8As shown, on the one hand, in horizontal well fracturing, the liquid nitrogen injection volume can be increased in the first few stages of fracturing, and then gradually reduced in subsequent stages. This way, the liquid nitrogen at the wellhead (point B) will have a good lifting effect on the fluid discharged from the upper part (point A) during the drainage process. As the production capacity of the end-stage formation is released, it will also effectively carry fluid to the upper producing formation. On the other hand, after the fracture is forcibly closed (or no sand returns from the outlet), the venting volume can be further increased to accelerate the upward speed of the denitrification fluid, greatly increasing the probability of a successful venting operation in one go.

[0187] Sand accumulation and removal from the wellbore occurs in sections where fracturing in horizontal wells is not progressing smoothly. This is when sand blocks the pump assembly, causing overpressure or the tool sleeve cannot be opened, leading to a large accumulation of sand in the wellbore. Timely sand removal is crucial. This sand cannot be controlled and must be removed quickly; otherwise, it will create sand column pressure within the wellbore, inhibiting fluid drainage. Ultimately, this will clog the tubing and flow path, causing blowout failure. This situation manifests in two ways on the surface: First, a clear sand line appears at the bottom of the drain outlet, with the sand ratio increasing and the sand line gradually thickening, accompanied by a sharp drop in wellhead pressure. In this case, it is advisable to quickly enlarge the nozzle size or even open the drain for sand removal, restoring control only after all sand has been removed. Second, sand blocks the manifold or even the flow path, causing a sharp drop in wellhead pressure, even returning to zero, resulting in pressure buildup in the well. In this situation, the manifold straight-through valve should be opened smoothly while observing the sand discharge from the drain outlet. As a large amount of sand is discharged, the pressure will rise sharply with significant impact. To prevent loss of control, shutting in the well may be necessary as a last resort.

[0188] Sand control is the opposite of sand removal. Both involve sand production, but this situation, known as formation sand production, indicates incomplete formation closure and sand ejection. In this case, timely flow control is necessary to allow sufficient closure time for the formation, creating a stable drainage channel and ensuring formation production efficiency. The team will then gradually reduce the backflow procedure (to remove residual sand from the wellbore while suppressing further sand ejection). The most crucial aspect of this stage is on-site observation and analysis. This involves observing the drainage situation after control measures are implemented and analyzing changes in sand content. Through gradual control measures, the formation sand ejection phenomenon can ultimately be eliminated.

[0189] Based on the horizontal well pressure-fed flowback model, horizontal well pressure-fed flowback software was developed, such as... Figure 9 , Figure 10 As shown in Table 2, the post-pressure flowback system for horizontal wells was determined based on the actual situation of post-pressure flowback on site.

[0190] Table 2 Optimized flowback relationship between nozzle diameter and wellhead pressure

[0191]

[0192] Drawing as Figure 11The diagram shows the optimal flowback nozzle diameter under different wellhead pressures. As can be seen from the figure, when the wellhead pressure P≤2MPa, the preferred nozzle diameter is 5mm-6mm; when the wellhead pressure 2MPa≤P≤MPa, the nozzle diameter is 3mm-4mm; when the wellhead pressure 6MPa≤P≤14MPa, the nozzle diameter is 2mm-3mm; and when the wellhead pressure P>14MPa, the nozzle diameter is 2mm.

[0193] The backflow system optimization design software was used to perform relevant calculations on ten wells, including DPH-3, DP42H, and DPH-15, and the results were compared with the actual production data measured in the field. The implementation effect was good. The following is a specific analysis using well DPH-3 as an example.

[0194] Input the calculation parameters shown in Table 3 into the return discharge system optimization design software and perform relevant calculations.

[0195] Table 3 Calculation Parameters

[0196]

[0197] The wellhead pressures corresponding to different diameter nozzles were calculated, as shown in Table 4:

[0198] Table 4. Wellhead pressure under different diameter nozzles

[0199]

[0200]

[0201]

[0202]

[0203] Based on Table 4, pressure drop curves for oil nozzle return flow in well DPH-3 with different diameter nozzles were plotted, such as... Figure 12 As shown in the figure. Analysis shows that different nozzles result in different wellhead pressure drop rates; the larger the nozzle diameter, the faster the return flow and the faster the corresponding wellhead pressure drop.

[0204] Given a flowback nozzle, the critical velocity of the fracturing fluid within the fracture can be calculated under different flowback wellhead pressures using the relationship between wellhead pressure and flowback nozzle. Flowback was performed using 2mm, 4mm, and 6mm nozzles, and the curves showing the relationship between wellhead pressure and critical velocity of the fracturing fluid under different nozzle sizes are as follows: Figure 13 , Figure 14 and Figure 15 As shown in the figure, to ensure that no sand is produced during the flowback process, the critical flow velocity V3 calculated by the proppant initiation model must be greater than the critical flow velocity V2 of the fracturing fluid in the fracture; otherwise, a smaller nozzle needs to be used.

[0205] Based on the critical starting flow rate of the proppant, the reasonable flowback nozzle diameter corresponding to different wellhead pressures was calculated using a comprehensive model, and the optimal flowback relationship between nozzle diameter and wellhead pressure was plotted.

[0206] A 2mm nozzle was selected, and the parameters of well DPH-3 were calculated using a comprehensive model. The results are shown in Table 5.

[0207] Table 5. Solution data of the comprehensive model for 2mm nozzle backflow.

[0208]

[0209]

[0210]

[0211] Analysis of the data in Table 5 shows that the bottom hole pressure and wellhead pressure decrease continuously with the flowback time, and the fracturing fluid loss rate decreases rapidly with the flowback.

[0212] A 4mm nozzle was selected, and the parameters of well DPH-3 were calculated using a comprehensive model. The results are shown in Table 6.

[0213] Table 6. Solution data of the comprehensive model for 4mm nozzle backflow

[0214]

[0215]

[0216]

[0217]

[0218] Analysis of Table 6 shows that the bottom hole pressure drop is positively correlated with the wellhead pressure drop, and the larger the diameter of the return nozzle, the faster the bottom hole pressure drops.

[0219] Drawing as Figure 16 Analysis of the curves showing the relationship between bottom hole pressure and flowback time indicates a positive correlation between bottom hole pressure drop and wellhead pressure drop; the larger the diameter of the flowback nozzle, the faster the bottom hole pressure drops.

[0220] Based on the above analysis, it can be concluded that to optimize the fracturing fluid flowback system, the nozzles should be replaced promptly for flowback according to the relationship curve between wellhead pressure and critical velocity of fracturing fluid in the fracture. Figure 17 As shown, the wellhead pressure drops faster and faster as the nozzle size increases.

Claims

1. A method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir, characterized in that, This includes calling a pre-built fracture forced closure model for determining the nozzle diameter during post-pressure flowback, outputting nozzles of different diameters to be used based on changes in wellhead pressure during the flowback process, and adjusting the nozzle diameter accordingly; the following steps are performed within the model: 1) Using the initial wellhead pressure, calculate the pressure at the end of the wellbore through the wellbore pressure drop and pipe flow friction pressure drop model, and use the pressure at the end of the wellbore as the initial value for calculating the average fracture pressure. Calculate the average fracture pressure using the material balance equation; then subtract the pressure loss during the flowback process from the average fracture pressure to obtain the new wellhead pressure. 2) Based on the stress analysis of the proppant in the fracture, the critical flow velocity for the proppant to remain stationary in the fracture is calculated, and the critical flow velocity is pushed forward from the bottom of the well to the wellhead using the continuity equation to obtain the critical flow velocity of the fracturing fluid at the wellhead. 3) By calibrating the flow rate at the nozzle under different wellhead pressures and using nozzles of different diameters for backflow, the flow rate at the nozzle is used as the flow rate at the corresponding wellhead pressure and nozzle diameter. The corresponding relationship between the critical flow rate of fracturing fluid backflow at the wellhead and the nozzle diameter is obtained. The current nozzle diameter is obtained by calling this relationship. 4) Using the new wellhead pressure obtained in 1) as the initial wellhead pressure value, repeat 1)-3) until the average fracture pressure reaches the closure pressure, and obtain the oil nozzles of different diameters required.

2. The method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to claim 1, characterized in that, In the wellbore pressure drop and tubing friction pressure drop model, the laminar or turbulent friction coefficient is selected based on the fracturing fluid flow regime, which is determined by the Reynolds number. Determine the friction coefficient when the fracturing fluid is in laminar flow. When the fracturing fluid is in a turbulent flow state, the friction coefficient is... .

3. The method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to claim 1, characterized in that, The material balance equation is: Change in fracture volume = Fracturing fluid loss + Wellhead flowback. The stress analysis of the proppant in the crack is performed using a moment balance equation, which is as follows: ； Among them, F x For drag force; F y W0 is the lifting force; L1, L2, and L3 are the torques corresponding to the forces.

4. The method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to claim 1, characterized in that, The backflow velocity is obtained through the following equation: ， in, This refers to the wellhead oil pressure. The pressure at the nozzle outlet; The flow rate of the fracturing fluid at the wellhead is the same as the nozzle discharge rate. The flow rate of the fracturing fluid in the wellbore; This is the local drag coefficient; R is the radius of the oil nozzle; R is the radius of the wellbore. This refers to the density of the fracturing fluid. This refers to the specific gravity of the fracturing fluid.

5. The method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to claim 1, characterized in that, The pump shutdown pressure is used as the initial wellhead pressure value.

6. The method for designing a fracturing and flowback regime after staged fracturing in a horizontal well of a tight gas reservoir according to claim 1, characterized in that, Liquid nitrogen is injected during the fracturing stage before the flowback process. The fracturing stage includes the early fracturing stage and the late fracturing stage. The amount of liquid nitrogen injected during the early fracturing stage is greater than that during the late fracturing stage.

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