An efficient flowback device and method for testing an ultra-deep water and ultra-shallow gas horizontal well

Abstract

The application relates to an efficient flowback device and method for testing a horizontal well of super-deep water and super-shallow gas, which comprises a wellhead device, a first data monitoring device, a replacement slurry water injection device, a coiled tubing, a coiled tubing gas injection device, a data processing and response device and a flowback fluid treatment device; the coiled tubing is connected with the replacement slurry water injection device and the coiled tubing gas injection device through the wellhead device; the first data monitoring device is arranged on the lower side of the wellhead device, and the flowback fluid treatment device is connected with the side of the wellhead device; the data processing and response device is connected with the replacement slurry water injection device, the coiled tubing gas injection device, the flowback fluid treatment device and the first data monitoring device through transmission optical fibers. The application adopts a collaborative scheme of pre-reducing liquid column pressure by using replacement slurry water and injecting gas through the coiled tubing to realize efficient removal of liquid accumulation in the whole horizontal section under the premise of protecting the reservoir and avoiding well leakage, thereby providing technical support for testing and development connection of super-deep water and super-shallow gas reservoirs.

Description

TECHNICAL FIELD

[0001] The application relates to an efficient flowback device and method for a super-deep water super-shallow gas horizontal well test, and belongs to the technical field of marine oil and gas resource development. BACKGROUND

[0002] With the extension of global oil and gas resource exploration to deep sea extreme environment, super-deep water super-shallow gas reservoirs have become the focus of some domestic marine energy development due to their huge resource potential. Such gas reservoirs have the characteristics of shallow reservoir burial depth, low energy level and poor reservoir physical properties, and the length of the horizontal well section is large. The test flowback operation is a key link between testing and development. Through efficient discharge of various fluids remaining in the wellbore and reservoir, the reservoir productivity channel can be restored, the real dynamic parameters can be obtained, and the development economy can be directly determined. However, the extreme environment and complex structure of the super-deep water super-shallow gas horizontal well make the test flowback face the dual challenges of low efficiency and high safety risk, and the existing technology cannot meet the needs. At present, a single flowback method cannot meet the actual engineering needs due to its limitations. The advantages and disadvantages of common flowback methods are introduced as follows. First, the formation pressure natural flowback method relies on the reservoir energy to drive fluid discharge, and the operation is simple but the efficiency is extremely low. The super-shallow reservoir energy is weak, and the liquid accumulation in the horizontal section is easy to remain due to gravity separation, and the flowback period can last for several days to several weeks. The fluid retention in the low-temperature environment easily causes hydrate blockage, further prolonging the operation period. Second, the conventional coiled tubing gas lift flowback method improves the liquid discharge power by injecting gas on the ground. However, the open hole section of the super-deep water horizontal well is long, and the traditional fixed gas injection parameters are difficult to adapt to the differences in pressure loss along the horizontal section, resulting in too fast liquid discharge near the wellbore and liquid accumulation remaining at the far end, poor flowback uniformity, and no consideration of the sensitive properties of the super-shallow low-permeability reservoir, which easily causes reservoir damage due to excessive gas injection pressure. Finally, the depressurization flowback method strengthens the gas expansion liquid discharge by reducing the wellhead pressure. However, the safety density window of the super-shallow gas reservoir is narrow, and excessive depressurization easily induces wellbore instability or reservoir damage, and the sudden pressure drop will aggravate the risk of hydrate generation, which requires additional investment in a large amount of inhibitors, and the economy is poor.

[0003] The main problems of the existing flowback methods are the dual constraints of super-deep water low-temperature high-pressure environment and super-shallow sensitive reservoir, large static design error of flowback parameters; significant gravity differentiation and friction loss along the horizontal section, dynamic change of gas-liquid two-phase flow state, existing models cannot accurately predict the liquid accumulation position and amount, and there is a flowback blind area; relying on artificial intermittent adjustment of parameters, unable to respond to wellbore dynamic changes in real time, and lagging regulation and control easily causes operation interruption.

[0004] In summary, there is currently a lack of an efficient method for flowback of super-deep water super-shallow gas horizontal well testing, which is also a key difficulty restricting the safe and efficient development of such resources. SUMMARY

[0005] In view of the deficiencies of the prior art, especially the problems of low flowback efficiency, high safety risk and difficult reservoir protection of the ultra-deep water ultra-shallow gas horizontal well testing, the application provides an efficient flowback device and method for ultra-deep water ultra-shallow gas horizontal well testing, which is combined with the core working conditions of the long horizontal section, low formation pressure, easy well leakage and fluid accumulation retention of the ultra-deep water ultra-shallow gas horizontal well, and adopts a collaborative scheme of pre-fluid column pressure reduction by replacement slurry water and continuous oil pipe gas injection and liquid discharge, so as to realize efficient removal of fluid accumulation in the whole horizontal section under the premise of protecting the reservoir and avoiding well leakage, and provide technical support for the testing and development connection of the ultra-deep water ultra-shallow gas reservoir.

[0006] The technical scheme of the application is as follows:

[0007] An efficient flowback device for ultra-deep water ultra-shallow gas horizontal well testing, comprising a wellhead device, a first data monitoring device, a replacement slurry water injection device, a continuous oil pipe, a continuous oil pipe gas injection device, a data processing and response device and a flowback fluid treatment device.

[0008] The continuous oil pipe is connected with the replacement slurry water injection device and the continuous oil pipe gas injection device through the wellhead device respectively.

[0009] The first data monitoring device is arranged on the lower side of the wellhead device, and the flowback fluid treatment device is connected to the side of the wellhead device.

[0010] The data processing and response device is connected with the replacement slurry water injection device, the continuous oil pipe gas injection device, the flowback fluid treatment device and the first data monitoring device through transmission optical fibers respectively.

[0011] According to the application, the wellhead device comprises a wellhead injection interface, a flowback interface and an electrically adjustable flow valve.

[0012] The replacement slurry water injection device is connected to the wellhead injection interface, and the flowback fluid treatment device is connected to the flowback interface, and the electrically adjustable flow valve is arranged between the flowback interface and the flowback fluid treatment device.

[0013] The replacement slurry water injection device comprises a replacement slurry water storage tank and a replacement slurry water pump connected in sequence.

[0014] According to the application, the first data monitoring device comprises a testing pipe column, a bottom hole pressure and temperature sensor, a wellhead temperature sensor and a wellhead pressure sensor.

[0015] The continuous oil pipe is arranged inside the testing pipe column, and the bottom hole pressure and temperature sensor is arranged at the bottom of the continuous oil pipe.

[0016] The wellhead temperature sensor and the wellhead pressure sensor are arranged at the upper end of the testing pipe column through the transmission optical fiber.

[0017] Further preferably, a riser is arranged outside the testing pipe column, a blowout preventer is arranged on the lower side of the riser, and a cementing cement sheath is arranged on the lower side of the blowout preventer.

[0018] According to the application, the backflow fluid treatment device comprises a density detector, a second wellhead flowmeter, a gas component detector, a separator, a backflow valve, a metering device and a backflow pipeline.

[0019] The density detector, the second wellhead flowmeter, the gas component detector, the separator and the metering device are connected in sequence through the backflow pipeline, and the backflow valve is arranged between the separator and the metering device.

[0020] According to the application, the coiled tubing gas injection device comprises a gas injection compressor, a gas injection pipeline, a first wellhead flowmeter, a gas injection valve and a nitrogen gas injection point.

[0021] The wellhead injection interface of the wellhead device is connected to the gas injection compressor through the gas injection pipeline, and the nitrogen gas injection point is arranged in the coiled tubing.

[0022] The first wellhead flowmeter is arranged on the gas injection pipeline.

[0023] The gas injection valve is arranged on the gas injection pipeline between the gas injection compressor and the first wellhead flowmeter.

[0024] Further preferably, the data processing and response device comprises a computer, an instruction transmission optical fiber and a signal receiving and executing system.

[0025] The signal receiving and executing system is connected to the computer through the instruction transmission optical fiber.

[0026] The backflow method of the efficient backflow device for testing the ultra-deep water ultra-shallow gas horizontal well comprises the following steps.

[0027] Step 1: obtaining target well data, calculating core parameters of the replacement water and the coiled tubing gas injection, including the replacement water density, the replacement water injection volume, the coiled tubing gas injection amount and the gas injection pressure.

[0028] Step 2: performing backflow operation based on the core parameters, collecting real-time data in the backflow operation process, and dynamically adjusting the backflow operation; the backflow operation comprises a replacement water injection stage, a coiled tubing lowering and gas injection stage and a backflow fluid treatment stage.

[0029] According to the application, step 1 specifically comprises the following steps.

[0030] The monitoring data are collected by the first data monitoring device, the density detector, the second wellhead flowmeter, the gas component detector, the first wellhead flowmeter, the second wellhead flowmeter and the metering device, and the target well data are obtained, including the initial temperature and pressure field of the wellbore, the formation breakdown pressure, the residual fluid volume of the horizontal section, the drilling fluid density, the borehole structure parameter, the reservoir pressure, the reservoir permeability and the fluid viscosity.

[0031] The rate of change of pressure along the depth of the wellbore is calculated based on the real-time monitoring of the gas-liquid volume fraction, flow rate, gas composition, and wellbore temperature data by the downhole sensor during the flowback process As shown below:

[0032] ;

[0033] wherein, is the average density of the gas-liquid mixed fluid, is the volume fraction of the gas phase, is the density of the gas phase, is the volume fraction of the liquid phase, is the density of the liquid phase, is the angle between the wellbore and the vertical direction, is the acceleration of gravity, is the friction coefficient, is the average flow rate of the mixed fluid, is the total flow rate, A is the cross-sectional area of the flow passage, and d represents the hydraulic equivalent diameter;

[0034] The rate of change of pressure along the depth is integrated to obtain the liquid column pressure at the target depth z:

[0035] ;

[0036] wherein, is the liquid column pressure at the target depth z, is the wellhead pressure;

[0037] The density of the replacement water is calculated, and the density of the replacement water satisfies: ; wherein, is the original drilling fluid density, is the formation breakdown pressure, is the initial liquid column pressure, , H is the total depth of the wellbore, is the flow friction coefficient of the drilling fluid; is the flow velocity of the drilling fluid before it is stationary;

[0038] It is assumed that the replacement water completely replaces the same volume of drilling fluid, i.e. , the injection volume of the replacement water satisfies the formula:

[0039] ;

[0040] wherein, is the target replacement volume, , is the liquid column pressure to be reduced, is the safe liquid column pressure, which is 80% of the formation breakdown pressure, i.e. =0.8 A is annulus cross-sectional area, A is annulus cross-sectional area,

[0041] After the completion of the slurry water, the coiled tubing gas injection flowback, coiled tubing gas injection gas mass conservation equation is , the gas injection amount is:

[0042] ;

[0043] Wherein, is the gas injection amount; is the residual liquid volume of the horizontal section; is the planned drainage time; is the liquid density; is the injected gas density, which is corrected in real time according to the injection pressure and temperature, and the correction formula is: , is the nitrogen density under standard conditions, is the injection pressure, is the injection temperature, , is the standard state pressure and temperature; t represents the planned drainage time, represents the gas flow rate; represents the gas phase volume fraction;

[0044] The injection pressure satisfies the following:

[0045] ;

[0046] Wherein, is the injection pressure; is the liquid column pressure; z0, z1 is the starting and ending depth of the injection point to the target drainage section.

[0047] According to the present application, the slurry water injection stage comprises:

[0048] Before starting the slurry water pump, the initial wellhead pressure is collected by the wellhead pressure sensor, the initial liquid column pressure is calculated combined with the pressure collected by the downhole vertical section bottom sensor, and compared with the reservoir fracture pressure , and then the slurry water density is checked again to see whether it meets If the slurry water density is high, i.e. does not meet the density condition, low-density adjusting agent is added for adjustment;

[0049] During the injection of replacement fluid, the injection flow rate is tracked in real time, and the cumulative injection volume is calculated synchronously using a built-in computer program. The density of the returned fluid is monitored in real time using a density meter installed at the wellhead. When the density of the returned fluid in the annulus differs from the density of the injected replacement fluid by ±10%, and the cumulative injection volume reaches more than 80% of the target injection volume, the bottom hole pressure and temperature sensor transmits the detected pressure in real time. Based on the rate of change of pressure along the wellbore depth, the fluid column pressure at each depth is calculated. If the fluid column pressure at a certain depth... ≥0.95 Immediately reduce the displacement of the slurry pump by 20% to 30% and open the annular pressure relief valve to adjust the pressure; if ≤1.02 , To compensate for reservoir pressure, the discharge rate increases by 10% to 15%.

[0050] When the density of the fluid returning from the annulus differs from the density of the injected displacement water by ±3%, it is determined that the displacement water injection has been completed, and the displacement water pump is shut down. The liquid column pressure is calculated, and the formation pressure is detected by the bottom hole pressure and temperature sensor. If the formation pressure is greater than the liquid column pressure, it is determined that the target well can be naturally flushed out by the formation pressure and does not need to be flushed out with coiled tubing. Otherwise, the coiled tubing running and gas injection stage is carried out.

[0051] According to a preferred embodiment of the present invention, the coiled tubing installation and gas injection stage includes:

[0052] Acquire basic data of the target well, set multiple sets of gas injection volume, gas injection pressure, and coiled tubing length, and conduct numerical simulation of the target well. With the goal of reducing the wellhead liquid holdup to below 5%, the flowback efficiency to >95%, and the flowback cycle to <72h, select the combination with the best simulation results, namely the combination of gas injection volume, gas injection pressure, and coiled tubing length.

[0053] Run the coiled tubing into the upper part of the directional section, and place the gas injection point at the end of the coiled tubing.

[0054] After ensuring that all equipment has been installed and is in normal working order, start the gas injection compressor and initially inject high-temperature nitrogen gas according to the optimal combination of injection volume and injection pressure.

[0055] After gas injection begins, the bottomhole pressure and temperature sensor located near the injection point collects the pressure and temperature at the injection point in real time, while the wellhead flow meter simultaneously collects the flow rate of the return fluid. With exhaust flow Then, the gas components are monitored in real time by an installed gas component detector, and the computer uses the collected data to apply formulas. Real-time calculation of wellhead liquid holdup After running for 20 hours, if the liquid holdup rate at the wellhead continuously and rapidly decreases to approach 0 finally, and the gas component detector detects a certain proportion of methane, the pressure of the oil and gas layer is recovered, and the oil and gas has begun to flow back; the nitrogen content gradually decreases and approaches the nitrogen content in the formation gas finally and is stabilized to the initial concentration;

[0056] If the liquid holdup rate at the wellhead decreases slowly and finally > the target liquid holdup rate, and the methane content in the gas component is extremely low, the coiled tubing length is increased to extend from the deflecting section to the horizontal section, and the corresponding gas injection amount is increased according to , and the adjustment range is controlled to be 5%-15% of the original gas injection amount; wherein, is the accumulated liquid volume, represents the gas injection adjustment amount, represents the liquid volume fraction, and t represents time, is the liquid phase density, is the injected gas density;

[0057] The adjusted gas injection amount is substituted into the gas injection pressure formula to check whether the gas injection pressure meets the requirements, if the pressure is insufficient, the output pressure of the gas injection compressor is simultaneously increased; if the gas injection point pressure , the gas injection amount is immediately reduced; if the wellhead pressure fluctuation range exceeds 5%, the opening degree of the electric adjustable flow valve of the wellhead device is adjusted to control the wellhead back pressure to be stable and to inhibit the generation of slug flow;

[0058] Finally, the change of the liquid holdup rate at the wellhead and the methane content in the gas component are monitored in real time to determine whether the flow back effect is good, if the flow back effect is still poor, the above adjustment steps are repeated until the liquid holdup rate at the wellhead rapidly decreases to 0, and stable methane output is obtained in the gas component detection;

[0059] In addition, the cumulative flow back liquid volume is counted in real time through the metering device When the cumulative flow back liquid volume reaches more than 95% of the residual liquid volume in the horizontal section, and the liquid holdup rate at the wellhead approaches 0, and the liquid content in the wellhead flow back gas is ≤5%, it is determined that the flow back effect meets the requirements, the gas injection amount is gradually reduced until the gas injection amount is reduced to 20% of the initial value and the liquid holdup rate does not change, and the gas injection compressor is closed.

[0060] According to the present application, preferably, the flow back fluid treatment stage comprises:

[0061] After the flow back fluid enters the separator through the wellhead device, the liquid level meter and the gas flow meter built in the separator monitor the gas flow after separation in real time and the liquid flow The computer calculates the gas-liquid mixed fluid density by , and takes as Substitute the wellbore pressure gradient equation , adjust the friction coefficient ;

[0062] If the oil content or the concentration of pollutants in the separated liquid exceeds the standard, adjust the separator parameters to ensure that the oil content and the concentration of suspended solids in the treated liquid are lower than the discharge standard; and the gas is recovered or burned according to the purity.

[0063] The beneficial effects of the present application are:

[0064] 1. The present application innovatively adopts slurry water pre-decompression and coiled tubing gas injection to cooperate with the flowback mode, low-density slurry water is injected into the wellbore through the coiled tubing to realize the pre-decompression of the liquid column pressure, and then high-temperature nitrogen is precisely injected through the coiled tubing, the cooperation of the two can not only reduce the gas injection and pressure reduction load, but also promote the efficient flow of residual liquid in the horizontal section, and solve the problem that a single flowback method cannot consider the liquid discharge efficiency and safety.

[0065] 2. The present application constructs a multi-parameter real-time monitoring system for the whole well section, data are collected through the linkage of an online density detector, an online gas component detector, a pressure temperature sensor and a wellhead flowmeter, the distribution of liquid is accurately calculated in combination with the gas-liquid two-phase flow theory and the wellbore pressure gradient model, and then the equipment parameters are dynamically regulated and controlled through a signal transmission and execution system, so that the intelligent adaptation of the flowback process is realized, and the operation risk caused by the lag of manual adjustment is avoided.

[0066] 3. The present application adopts the cooperative design of sectional flowback and fluid treatment, the coiled tubing can be flexibly adjusted to be lowered to a depth according to the flowback effect, the electrically adjustable flow valve is controlled to suppress the plug flow of the wellhead back pressure, and the separator and the metering device are simultaneously used to realize the gas-liquid separation and standard treatment, so that the horizontal section liquid accumulation blind area is efficiently removed, the super-shallow sensitive reservoir is protected, and the operation economy and environmental protection requirements are considered. BRIEF DESCRIPTION OF DRAWINGS

[0067] Figure 1 It is a schematic diagram of the efficient flowback device for the super-deep water and super-shallow gas horizontal well of the present application;

[0068] Wherein: 1, computer; 2, signal receiving and execution system; 3, slurry water storage tank; 4, slurry water pump; 5, gas component detector; 6, coiled tubing; 7, gas injection compressor; 8, separator; 9, metering device; 10, riser; 11, bottom hole pressure temperature sensor; 12, blowout preventer; 13, cement sheath; 14, nitrogen injection point; 15, subsea shallow layer; 16, shallow gas reservoir; 17, transmission optical fiber; 18, first wellhead flowmeter; 19, wellhead device; 20, wellhead temperature sensor; 21, wellhead pressure sensor; 22, test string; 23, second wellhead flowmeter; 24, density detector; 25, flowback valve; 26, slurry water valve; 27, gas injection valve. DETAILED DESCRIPTION

[0069] The application is further described below by way of examples and with reference to the accompanying drawings, without being limited thereto.

[0070] Example 1

[0071] The present embodiment provides a high-efficiency flowback device for testing an ultra-deep water ultra-shallow gas horizontal well, which comprises Figure 1 as shown, comprising:

[0072] A high-efficiency flowback device for testing an ultra-deep water ultra-shallow gas horizontal well comprises a wellhead device 19, a first data monitoring device, a replacement slurry water injection device, a coiled tubing 6, a coiled tubing gas injection device, a data processing and response device, and a flowback fluid treatment device.

[0073] The coiled tubing 6 is connected with the replacement slurry water injection device and the coiled tubing gas injection device through the wellhead device 19.

[0074] The first data monitoring device is arranged on the lower side of the wellhead device 19, and the flowback fluid treatment device is connected to the side of the wellhead device 19.

[0075] The data processing and response device is connected with the replacement slurry water injection device, the coiled tubing gas injection device, the flowback fluid treatment device, and the first data monitoring device through transmission optical fibers.

[0076] The wellhead device 19 comprises a wellhead injection interface, a flowback interface, and an electrically adjustable flow valve (for real-time control of wellhead back pressure and suppression of plug flow).

[0077] The wellhead injection interface is connected with the replacement slurry water injection device, the flowback interface is connected with the flowback fluid treatment device, and the electrically adjustable flow valve is arranged between the flowback interface and the flowback fluid treatment device.

[0078] The replacement slurry water injection device comprises a replacement slurry water storage tank 3, a replacement slurry water pump 4, and a replacement slurry water valve 26 connected in sequence.

[0079] The replacement slurry water pump 4 receives signals and executes instructions of the system, and pushes the low-density replacement slurry water in the replacement slurry water storage tank into the coiled tubing through the wellhead device 19, to push the high-density drilling fluid out from the annulus, thereby reducing the initial liquid column pressure of the wellbore.

[0080] The first data monitoring device comprises a test string 22, a bottom-hole pressure and temperature sensor 11, a wellhead temperature sensor 20, and a wellhead pressure sensor 21.

[0081] The coiled tubing 6 is arranged inside the test string 22, and the bottom-hole pressure and temperature sensor 11 is arranged at the bottom of the coiled tubing 6 to collect pressure and temperature data in the wellbore.

[0082] The upper end of the test string 22 is provided with a wellhead temperature sensor 20 and a wellhead pressure sensor 21 through a transmission optical fiber (to measure the wellhead temperature and wellhead pressure obtained by the test string 22);

[0083] The test string 22 is provided with a riser 10 (a blowout preventer group ensures safety of operation, and an electrically adjustable flow valve controls wellhead back pressure in real time to avoid slug flow caused by too fast gas expansion) outside; the riser 10 is provided with a blowout preventer 12 at the lower side, and the blowout preventer 12 is provided with a cement sheath 13 at the lower side.

[0084] The flowback fluid treatment device includes a density detector 24, a second wellhead flowmeter 23, a gas component detector 5, a separator 8 (to separate the flowback fluid into gas and liquid), a flowback valve 25, a metering device 9 (to monitor the separated liquid and gas amounts), and a flowback pipeline; (the density detector 24 measures the density of the liquid flowing back, the second wellhead flowmeter 23 monitors the wellhead flow, and the gas component detector 5 monitors the gas component flowing back); the separator 8 separates the flowback fluid into gas and liquid, and after detection by the metering device 9, the gas is treated by recovery or combustion, and the liquid is treated to meet the standard and then discharged or reused;

[0085] The density detector 24, the second wellhead flowmeter 23, the gas component detector 5, the separator 8, and the metering device 9 are connected in sequence through the flowback pipeline, and the flowback valve 25 is arranged between the separator 8 and the metering device 9.

[0086] The coiled tubing gas injection device includes a gas injection compressor 7 (to provide high-pressure nitrogen gas), a gas injection pipeline, a first wellhead flowmeter 18, a gas injection valve 27, and a nitrogen gas injection point 14;

[0087] The wellhead injection interface of the wellhead device is connected to the gas injection compressor 7 through the gas injection pipeline, and the wellhead injection interface is provided with the nitrogen gas injection point 14 through the coiled tubing 6;

[0088] The first wellhead flowmeter is arranged on the gas injection pipeline;

[0089] The gas injection valve 27 is arranged on the gas injection pipeline between the gas injection compressor 7 and the first wellhead flowmeter 18;

[0090] The pipeline connecting the wellhead device 19 and the gas injection compressor 7 is used to transport high-pressure nitrogen gas; the coiled tubing is first lowered into the build-up section, and then adjusted according to the flowback effect to consider whether to extend the coiled tubing to the horizontal section; after receiving the instruction, the gas injection compressor injects high-temperature nitrogen gas into the wellbore through the gas injection pipeline and the nitrogen gas injection point 14 to push the residual liquid in the horizontal section to move towards the wellhead;

[0091] The data processing and response device includes a computer 1, an instruction transmission optical fiber, and a signal receiving and executing system 2;

[0092] The signal receiving and executing system 2 is connected with the computer 1 through an instruction transmission optical fiber; the computer receives pressure, temperature and flow data transmitted by the monitoring data transmission optical fiber, calculates the liquid column pressure distribution in the wellbore, the amount and distribution of the liquid accumulation in the horizontal section by a built-in calculation program (based on the gas-liquid two-phase flow theory and the wellbore pressure gradient model), and further obtains the replacement slurry water injection amount and the coiled tubing gas injection parameters (gas injection amount and gas injection pressure);

[0093] The backflow parameter adjustment instruction output by the computer 1 is transmitted to the signal receiving and executing system 2; after receiving the instruction, the signal receiving and executing system controls the displacement and pressure of the replacement slurry water pump, the gas injection rate and pressure of the gas injection compressor, and the opening of the electric adjustable flow valve, so as to realize real-time regulation and control in the backflow process.

[0094] Embodiment 2:

[0095] The backflow method of the device for testing the high-efficiency backflow of the ultra-deep water and ultra-shallow gas horizontal well according to Embodiment 1 comprises the following steps:

[0096] Step 1: obtaining the target well data, calculating the core parameters of the replacement slurry water and the coiled tubing gas injection, including the replacement slurry water density, the replacement slurry water injection volume, the coiled tubing gas injection amount and the gas injection pressure, to ensure the safety and efficiency of the backflow; including:

[0097] The target well data are obtained by collecting and monitoring the data through the first data monitoring device, the density detector, the second wellhead flowmeter, the gas component detector, the first wellhead flowmeter, the second wellhead flowmeter and the metering device, including the initial temperature and pressure field of the wellbore, the formation breakdown pressure, the residual liquid accumulation amount in the horizontal section, the drilling fluid density, the borehole structure parameters (such as the borehole diameter, the annular size, the horizontal section length, the angle of the build-up section, etc.), the reservoir pressure, the reservoir permeability, the fluid viscosity (gas phase viscosity, liquid phase viscosity);

[0098] The initial temperature and pressure field of the wellbore: the real-time data are collected by the bottom hole pressure and temperature sensor 11 (near the gas injection point), the wellhead temperature sensor 20 and the wellhead pressure sensor 21, and are comprehensively determined in combination with the logging curves (such as temperature logging and pressure logging);

[0099] The formation breakdown pressure: based on the experimental data of the formation mechanics (such as the core compression strength test), the formation pressure monitoring data, and the formula calculation in combination with the pressure test data (the breakdown pressure value recorded in the wellhead pressure test process): (wherein is the formation pore pressure, is the breakdown pressure coefficient, is the horizontal ground stress, is the formation breakdown pressure);

[0100] Residual liquid loading in horizontal section: Identify the liquid loading section by well logging interpretation (such as neutron porosity logging, acoustic logging), and calculate by numerical model (gas-liquid two-phase flow liquid loading prediction model): is the cross-sectional area of the horizontal section, is the length of the segmented liquid loading, is the segmented liquid holdup, is the residual liquid loading in the horizontal section);

[0101] Drilling fluid density: Directly obtained from the drilling fluid test report, or measured by online density detector 24 before operation;

[0102] Wellbore structure parameters: From the drilling engineering design file, including wellbore diameter, annulus (annular space between test string and well wall) cross-sectional area, horizontal section length, build-up section angle, etc.;

[0103] Reservoir pressure: Obtained by formation testing (such as DST test), or calculated from the monitored bottom hole pressure and temperature sensor 11 at the beginning of the operation;

[0104] Reservoir permeability, fluid viscosity: Obtained by core experiment analysis (permeability test, viscosity test);

[0105] Combined with the gas-liquid volume fraction, flow rate, gas component, wellbore temperature data monitored by the downhole sensor in the flowback process (the gas-liquid volume fraction is obtained after separation by the separator 8, the flow rate is obtained by the second wellhead flowmeter 23; the gas component is obtained by the gas component detector 5; the wellbore temperature is obtained by the bottom hole pressure and temperature sensor 11 and the wellhead temperature sensor 20), the rate of change of pressure along the depth of the wellbore is calculated as follows:

[0106]

[0107] where, is the average density of the gas-liquid mixed fluid, is the gas volume fraction, is the gas phase density, is the liquid volume fraction, is the liquid phase density, is the angle between the wellbore and the vertical direction, is the acceleration of gravity, is the friction coefficient, is the average flow rate of the mixed fluid, is the total flow rate, A is the cross-sectional area of the flow channel, and d represents the hydraulic equivalent diameter (m);

[0108] Integrate the rate of change of pressure along the depth to obtain the liquid column pressure at the target depth z: ​​

[0109] ;

[0110] wherein, P(z) is the liquid column pressure at the target depth z, P(z) is the wellhead pressure, which provides a pressure reference for subsequent gas injection and slurry water parameter adjustment;

[0111] In order to prevent problems such as well leakage during flowback, slurry water is first used to reduce formation pressure; the density of the slurry water (low-density water-based fluid (seawater, freshwater, salted water, etc.), used to replace drilling fluid) is calculated to ensure that the slurry water can effectively reduce the liquid column pressure after injection and not collapse the formation, and the slurry water density satisfies: ; wherein, P0 is the original drilling fluid density (kg / m 3 ), σ is the formation fracture pressure (Pa), P0 is the initial liquid column pressure (Pa), H is the total depth of the wellbore (from the wellbore structure parameters), f is the drilling fluid flow friction coefficient (calculated according to the drilling fluid viscosity and flow rate); V0 is the drilling fluid flow speed before standing (obtained from drilling records), to ensure that the slurry water density is low enough to make the liquid column pressure after injection lower than the formation fracture pressure, avoiding well leakage;

[0112] Assuming that the slurry water completely replaces the same volume of drilling fluid, i.e. the slurry water injection volume satisfies the formula:

[0113] ;

[0114] wherein, V is the target replacement volume (m 3 ), , P0 is the liquid column pressure to be reduced, P0 is the safe liquid column pressure, which is 80% of the formation fracture pressure, i.e. =0.8 A is the annulus cross-sectional area, L is the open hole section (referring to the well section after drilling without casing or cementing, usually referring to the uncemented area from the end of the build-up section to the end of the horizontal section in ultra-deep water and ultra-shallow gas horizontal wells, which is the main area of fluid accumulation and retention), A is the annulus cross-sectional area (m 2), according to the target pressure reduction range, the required replacement water injection amount is calculated to ensure that the pressure reduction effect meets the standard;

[0115] After the replacement water is completed, the gas injection and flowback is carried out through the coiled tubing, and the gas mass conservation equation of the coiled tubing gas injection amount is , the gas injection amount is:

[0116] ;

[0117] Among them, is the gas injection amount (m 3 / s, standard state); is the residual liquid volume in the horizontal section (m 3 ); is the planned drainage time (s); is the liquid phase density (kg / m 3 ); is the injection gas density (kg / m 3 ), which is corrected in real time according to the injection pressure and temperature, and the correction formula is: , is the nitrogen density under standard state, is the injection pressure, is the injection temperature, , is the standard state pressure and temperature; according to the residual liquid volume in the horizontal section and the target drainage time, the required gas injection amount is calculated to ensure that the gas injection rate can promote the efficient drainage of the liquid; t represents the planned drainage time (s), represents the gas flow rate;

[0118] In addition to the gas injection amount, the injection pressure needs to be calculated to make the liquid drain smoothly; the injection pressure needs to overcome the liquid column pressure and the friction resistance, and the simplified gas phase momentum equation is: , combined with the liquid column pressure , the injection pressure satisfies the following:

[0119] ;

[0120] Among them, is the injection pressure (Pa); is the liquid column pressure (Pa); z0, z1 are the starting and ending depths of the injection point to the target drainage section (m), which are combined with the liquid column pressure and the injection section friction resistance to calculate the lower limit of the injection pressure, to avoid insufficient pressure leading to poor drainage, or excessive pressure causing well leakage.

[0121] Step 2: Based on the core parameters, the flowback operation is carried out, and real-time data during the flowback operation is collected to dynamically adjust the flowback operation; the flowback operation includes: slurry water injection stage, coiled tubing running and gas injection stage, and flowback fluid treatment stage.

[0122] The slurry water injection stage includes:

[0123] Before starting the slurry water pump, the initial wellhead pressure is collected through the wellhead pressure sensor, and the pressure collected by the downhole vertical section bottom sensor (the bottom of the vertical section near the starting point of the build-up section is collected by the bottom hole pressure and temperature sensor) is combined to calculate the initial liquid column pressure (the initial liquid column pressure , is the downhole vertical section bottom pressure, is the distance from the wellhead to the bottom hole pressure and temperature sensor, H is the total depth of the wellbore, is the wellhead pressure), and is compared with the reservoir fracture pressure , and the slurry water density is checked again to see if it meets If the slurry water density is too high, i.e., the density condition is not met, a low-density adjusting agent is added to adjust (an additive that reduces the density of slurry water, such as a physical adjusting agent: hollow glass microbeads (density 0.3~0.6g / cm³), floating beads (density 0.4~0.8g / cm³); a chemical adjusting agent: polyethylene glycol (PEG-200, density 1.12g / cm³, which reduces the density after dilution with water), methanol (density 0.79g / cm³, which can reduce the density of water-based slurry water in appropriate amounts)), to avoid well leakage caused by initial parameter errors;

[0124] Slurry water injection is carried out (relying on coiled tubing for injection), and the slurry water injection flow rate is tracked in real time during the injection process. The cumulative injection amount is calculated simultaneously through the built-in program of the computer, and the density detector installed at the wellhead is used to monitor the density of the returned fluid in real time. When the annulus (the annular space formed between the outer wall of the test pipe column and the well wall (or the inner wall of the casing) is the flow channel for drilling fluid, slurry water, and other flowback fluids) returned fluid density differs from the injected slurry water density by ±10% and the cumulative injection amount reaches more than 80% of the target injection amount, the slurry water injection process enters the finishing stage. The bottom hole pressure and temperature sensor transmits the detected pressure in real time, and the liquid column pressure at each depth is calculated according to the pressure change rate along the wellbore depth. If the liquid column pressure at a certain depth ≥0.95 , the slurry water pump displacement is immediately reduced by 20%~30%, and the annular pressure relief valve is opened to adjust the pressure; if ≤1.02 , is the reservoir pressure, then the displacement is increased by 10%~15% to prevent reservoir fluid from flowing backward;

[0125] When the annular backflow fluid density and the density of the injected replacement water differ by ±3%, it is determined that the replacement water injection has been completed, and the replacement water pump is closed. At this time, the liquid column pressure is reduced through the replacement water operation, the liquid column pressure is calculated, and the formation pressure is detected according to the downhole pressure and temperature sensor. If the formation pressure is greater than the liquid column pressure, it is determined that the target well can be naturally flowed back by the formation pressure, and continuous oil pipe flow back is not needed. Otherwise, the continuous oil pipe is lowered and the gas injection stage is performed.

[0126] The continuous oil pipe lowering and gas injection stage includes:

[0127] The target well basic data (such as well depth, horizontal section length, well diameter, reservoir pressure, temperature, fluid properties, etc.) is obtained, a plurality of gas injection amounts (300-800 m³ / h), gas injection pressures, and continuous oil pipe lengths (from the build-up section to the horizontal section) are set, numerical simulation is performed on the target well (using gas-liquid two-phase flow software such as OLGA), and the optimal combination of the simulation results, i.e., the combination of the gas injection amount, the gas injection pressure, and the continuous oil pipe length, is selected as the target, with the wellhead liquid holdup rate reduced to below 5%, the flow back efficiency (flow back liquid amount / accumulated liquid amount) >95%, and the liquid discharge period <72h.

[0128] The continuous oil pipe is lowered to the upper end of the build-up section (the build-up section refers to the well section that gradually increases from 0° to 90° in the angle between the vertical well section and the horizontal well section, which is the key area connecting the vertical section and the horizontal section, and the initial lowering position of the continuous oil pipe is the upper end of the build-up section (at an angle of about 30°-45°)), the gas injection point is located at the end of the continuous oil pipe, and the gas injection point valve is controlled by a computer and is in a closed state before the gas injection starts.

[0129] After ensuring that all devices have been installed and are in normal state, the gas injection compressor is started, and high-temperature nitrogen gas (80-120°C) is injected at the optimal combination of the gas injection amount (such as nitrogen injection amount 600 m³ / h) and the gas injection pressure, wherein the injection temperature is controlled in real time by a heating device.

[0130] After the gas injection starts (relying on the continuous oil pipe for injection), the downhole pressure and temperature sensor near the gas injection point collects the pressure and temperature of the gas injection point in real time, and the wellhead flowmeter synchronously collects the flow back liquid flow and the flow back gas flow The gas component is monitored in real time by the installed gas component detector, and the computer calculates the wellhead liquid holdup rate in real time using the formula ​If, after 20 hours of operation, the wellhead liquid holdup continues to decrease rapidly and eventually approaches 0 (the wellhead liquid holdup continues to decrease rapidly to ≤5% (the value approaching 0 is in the range of 0~3%)), and the gas component detector detects a certain proportion of methane (methane content ≥10% (volume fraction)), then the pressure of the oil and gas reservoir is restored, oil and gas have begun to flow back, and the nitrogen content first gradually decreases and approaches the nitrogen content in the formation gas, and finally stabilizes at the initial concentration (nitrogen content in the original formation gas). This indicates that the well cleaning was carried out thoroughly, the continuous tubing length and gas injection volume were appropriate, and the flowback effect was good.

[0131] If the wellhead fluid holdup decreases slowly and finally... The target liquid holdup (10%) and extremely low methane content in the gas composition (≤1%) indicate poor backflow performance. Therefore, the length of the coiled tubing should be increased, extending from the build-up section to the horizontal section. Simultaneously, based on... Increase the corresponding gas injection volume, with the adjustment range controlled at 5%-15% of the original gas injection volume; among which, The volume of the accumulated liquid is calculated from the volume of each horizontal segment. This indicates the adjustment amount of the gas injection volume. The volume fraction of the liquid phase is represented by t, and time is represented by t. The density of the liquid phase is... Density of the injected gas;

[0132] Substitute the adjusted gas injection volume into the gas injection pressure formula. (The amount of gas injected will affect the gas injection pressure formula) (Gas flow rate) Check if the injection pressure meets the requirements. If the pressure is insufficient, simultaneously increase the output pressure of the injection compressor to avoid insufficient pressure causing poor liquid drainage; if the injection point pressure... If the wellhead pressure fluctuates by more than 5%, the opening of the electrically adjustable flow valve of the wellhead device should be adjusted to control the wellhead back pressure and suppress the generation of slug flow.

[0133] Finally, real-time monitoring of wellhead liquid holdup changes and methane content in gas components is used to determine the effectiveness of the flowback (wellhead liquid holdup ≤5% after 20 hours, eventually approaching 0 (0~3%); methane content ≥10% (volume fraction), stable production; cumulative flowback volume ≥95% × residual liquid volume in the horizontal section; wellhead flowback liquid phase content ≤5% (volume fraction) indicates a good flowback effect). If the flowback effect is still poor (wellhead liquid holdup >10% after 20 hours; methane content ≤1% (volume fraction), no significant increase; cumulative flowback volume <80% × residual liquid volume in the horizontal section; wellhead flowback liquid phase content >15% (volume fraction) indicates a poor flowback effect), repeat the above adjustment steps until the wellhead liquid holdup rapidly decreases to 0, and stable methane production is detected in the gas component analysis.

[0134] In addition, the cumulative volume of returned liquid is counted in real time using a metering device. When the cumulative backflow volume reaches more than 95% of the residual liquid volume in the horizontal section, and the wellhead liquid holdup is close to 0, and the liquid phase content in the wellhead backflow gas is ≤5%, the backflow effect is judged to be up to standard. The gas injection volume is gradually reduced (each reduction is 10%-20%, with an interval of 15 minutes) until the gas injection volume drops to 20% of the initial value and the liquid holdup remains unchanged. Then the gas injection compressor is turned off.

[0135] The backflow fluid treatment stage includes:

[0136] After the backflow fluid enters the separator through the wellhead device, the separator's built-in level gauge and gas flow meter monitor the gas flow rate after separation in real time. With liquid flow rate Computer through Calculate the density of a gas-liquid mixture and will As Substitute into the wellbore pressure gradient equation Adjust the friction coefficient ;

[0137] If the oil content or pollutant concentration of the separated liquid exceeds the standard (oil content ≥10mg / L, or suspended solids concentration ≥50mg / L), the separator parameters (demulsifier addition rate, filtration accuracy, backwashing cycle, and separator level setpoint, etc.) are adjusted to ensure that the oil content and suspended solids concentration of the treated liquid are lower than the emission standards (e.g., oil content ≤5mg / L, suspended solids ≤20mg / L). The gas is then recovered or burned according to its purity. The entire process achieves coordinated monitoring and optimization of return parameters and fluid treatment effects.

Claims

1. A highly efficient flowback method for testing ultra-deepwater and ultra-shallow gas horizontal wells, characterized in that, Includes the following steps: Step 1: Obtain target well data and calculate the core parameters of displacement water and coiled tubing gas injection, including displacement water density, displacement water injection volume, coiled tubing gas injection volume and gas injection pressure; Step 2: Perform backflow operation based on core parameters, and collect real-time data during the backflow operation to dynamically adjust the backflow operation; the backflow operation includes: slurry water injection stage, coiled tubing installation and air injection stage, and backflow fluid treatment stage; Step 1 is as follows: Data is collected and monitored using a first data monitoring device, a density meter, a second wellhead flow meter, a gas component detector, a first wellhead flow meter, a second wellhead flow meter, and a metering device to obtain target well data, including the initial temperature and pressure field of the wellbore, formation fracture pressure, residual fluid volume in the horizontal section, drilling fluid density, wellbore structural parameters, reservoir pressure, reservoir permeability, and fluid viscosity. By combining the gas-liquid integral number, flow rate, gas composition, and wellbore temperature data monitored in real time by downhole sensors during the flowback process, the rate of pressure change along the wellbore depth is calculated. As shown below: ； in, The average density of the gas-liquid mixture. This refers to the gas phase volume fraction. For gas phase density, It is the liquid volume fraction. The density of the liquid phase is... The angle between the wellbore and the vertical direction. It is the acceleration due to gravity. The coefficient of friction, The average velocity of the mixed fluid. Where A is the total flow rate, d is the cross-sectional area of ​​the flow channel, and d represents the hydraulic equivalent diameter. Integrating the rate of pressure change along the depth, we obtain the liquid column pressure at the target depth z: ； in, Let z be the liquid column pressure at the target depth z. This refers to the wellhead pressure. Calculate the density of the slurry; slurry density. satisfy: ;in, The original drilling fluid density, For formation fracture pressure, The initial liquid column pressure, H is the total depth of the wellbore. The coefficient of friction of the drilling fluid; The velocity of the drilling fluid before it comes to rest; Assuming the displacement fluid completely replaces the same volume of drilling fluid, i.e. , replacement slurry injection volume Satisfying the formula: ； in, For the target displacement volume, , To reduce the liquid column pressure, For the safety fluid column pressure, take 80% of the formation fracture pressure, i.e. =0.8 A is the cross-sectional area of ​​the annulus. The density of the slurry is given by L, which is the length of the naked eye segment, and A is the cross-sectional area of ​​the annulus. After the slurry is replaced, coiled tubing is used for gas injection and backflow. The gas mass conservation equation for the coiled tubing gas injection volume is as follows: The gas injection volume is: ； in, This refers to the gas injection volume; This represents the volume of residual liquid in the horizontal section. For the planned drainage time; The density of the liquid phase; The injected gas density is adjusted in real time based on the injection pressure and temperature. The adjustment formula is as follows: , The density of nitrogen under standard conditions. Injection pressure, This refers to the gas injection temperature. , Standard pressure and temperature; t represents the planned drainage time. Indicates gas flow rate; Indicates the volume fraction of the gas phase; Injection pressure The following conditions must be met: ； in, This refers to the injection pressure; Z is the liquid column pressure; Z0 and Z1 are the starting and ending depths from the injection point to the target discharge section.

2. The efficient flowback method for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 1, characterized in that, The plasma replacement injection stage includes: Before starting the displacement pump, the initial wellhead pressure is collected using a wellhead pressure sensor. Combined with the pressure collected by the sensor at the bottom of the downhole vertical section, the initial fluid column pressure is calculated and compared with the reservoir fracture pressure. Compare and recheck whether the density of the pulping water meets the requirements. If the density of the pulping water is too high and does not meet the density requirements, a low-density regulator should be added to adjust it. During the injection of replacement fluid, the injection flow rate is tracked in real time, and the cumulative injection volume is calculated synchronously using a built-in computer program. The density of the returned fluid is monitored in real time using a density meter installed at the wellhead. When the density of the returned fluid in the annulus differs from the density of the injected replacement fluid by ±10%, and the cumulative injection volume reaches more than 80% of the target injection volume, the bottom hole pressure and temperature sensor transmits the detected pressure in real time. Based on the rate of change of pressure along the wellbore depth, the fluid column pressure at each depth is calculated. If the fluid column pressure at a certain depth... ≥0.95 Immediately reduce the displacement of the slurry pump by 20% to 30% and open the annular pressure relief valve to adjust the pressure; if ≤1.02 , To compensate for reservoir pressure, the discharge rate increases by 10% to 15%. When the density of the fluid returning from the annulus differs from the density of the injected displacement water by ±3%, it is determined that the displacement water injection has been completed, and the displacement water pump is shut down. The liquid column pressure is calculated, and the formation pressure is detected by the bottom hole pressure and temperature sensor. If the formation pressure is greater than the liquid column pressure, it is determined that the target well can be naturally flushed out by the formation pressure and does not need to be flushed out with coiled tubing. Otherwise, the coiled tubing running and gas injection stage is carried out.

3. The efficient flowback method for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 2, characterized in that, The coiled tubing installation and gas injection phase includes: Acquire basic data of the target well, set multiple sets of gas injection volume, gas injection pressure, and coiled tubing length, and conduct numerical simulation of the target well. With the goal of reducing the wellhead liquid holdup to below 5%, the flowback efficiency to >95%, and the flowback cycle to <72h, select the combination with the best simulation results, namely the combination of gas injection volume, gas injection pressure, and coiled tubing length. Run the coiled tubing into the upper part of the directional section, and place the gas injection point at the end of the coiled tubing. After ensuring that all equipment has been installed and is in normal working order, start the gas injection compressor and initially inject high-temperature nitrogen gas according to the optimal combination of injection volume and injection pressure. After gas injection begins, the bottomhole pressure and temperature sensor located near the injection point collects the pressure and temperature at the injection point in real time, while the wellhead flow meter simultaneously collects the flow rate of the return fluid. With exhaust flow Then, the gas components are monitored in real time by an installed gas component detector, and the computer uses the collected data to apply formulas. Real-time calculation of wellhead liquid holdup If, after 20 hours of operation, the wellhead liquid holdup continues to decrease rapidly to 0-3% and methane is detected by the gas component detector, then the pressure of the oil and gas reservoir is restored, the oil and gas have begun to be discharged, and the nitrogen content gradually decreases and approaches the nitrogen content in the formation gas before stabilizing at the initial concentration. If the wellhead fluid holdup decreases slowly and finally... If the target liquid holdup is achieved and the methane content in the gas composition is extremely low, then the length of the coiled tubing should be increased, extending from the build-up section to the horizontal section, while also considering... Increase the corresponding gas injection volume, with the adjustment range controlled at 5%-15% of the original gas injection volume; among which, This represents the volume of the accumulated fluid. This indicates the adjustment amount of the gas injection volume. The volume fraction of the liquid phase is represented by t, and time is represented by t. The density of the liquid phase is... Density of the injected gas; Substitute the adjusted gas injection volume into the gas injection pressure formula. Check if the injection pressure meets the requirements; if the pressure is insufficient, simultaneously increase the output pressure of the injection compressor; if the injection point pressure... If the wellhead pressure fluctuates by more than 5%, the opening of the electrically adjustable flow valve of the wellhead device should be adjusted to control the wellhead back pressure and suppress the generation of slug flow. Finally, real-time monitoring of wellhead liquid holdup and methane content in gas components is used to determine whether the backflow effect is good. If the backflow effect is still poor, i.e., the cumulative backflow volume is <80% × the residual liquid volume in the horizontal section, and the liquid phase content of the backflow gas at the wellhead is >15%, then repeat the above adjustment steps until the wellhead liquid holdup drops rapidly to 0, and there is stable methane production in the gas component detection. In addition, the cumulative volume of returned liquid is counted in real time using a metering device. When the cumulative backflow volume reaches more than 95% of the residual liquid volume in the horizontal section, and the wellhead liquid holdup is 0~3%, and the liquid phase content in the wellhead backflow gas is ≤5%, the backflow effect is judged to be up to standard. The gas injection volume is gradually reduced until the gas injection volume drops to 20% of the initial value and the liquid holdup remains unchanged, and the gas injection compressor is shut down.

4. The efficient flowback method for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 3, characterized in that, The backflow fluid treatment stage includes: After the backflow fluid enters the separator through the wellhead device, the separator's built-in level gauge and gas flow meter monitor the gas flow rate after separation in real time. With liquid flow rate Computer through Calculate the density of a gas-liquid mixture and will As Substitute into the wellbore pressure gradient equation Adjust the friction coefficient ; If the oil content or pollutant concentration of the separated liquid exceeds the standard, the separator parameters are adjusted to ensure that the oil content and suspended solids concentration of the liquid after treatment are lower than the emission standards; the gas is then recovered or treated by combustion according to its purity.

5. A high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells, realizing the high-efficiency flowback method for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 4, characterized in that... It includes wellhead equipment, first data monitoring equipment, slurry water injection equipment, coiled tubing, coiled tubing gas injection equipment, data processing and response equipment, and backflow fluid treatment equipment; The coiled tubing is connected to a slurry injection device and a coiled tubing gas injection device via wellhead equipment. A first data monitoring device is installed on the lower side of the wellhead device, and a backflow fluid treatment device is connected to the side of the wellhead device. The data processing and response device is connected to the slurry water injection device, the coiled tubing gas injection device, the return fluid treatment device, and the first data monitoring device via optical fiber.

6. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 5, characterized in that, Wellhead equipment includes a wellhead injection port, a return port, and an electrically adjustable flow valve; The wellhead injection interface is connected to a slurry water injection device, the return interface is connected to a return fluid treatment device, and an electrically adjustable flow valve is installed between the return interface and the return fluid treatment device. The slurry water injection device includes a slurry water storage tank and a slurry water pump connected in sequence.

7. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 6, characterized in that, The first data monitoring device includes a test string, a bottom hole pressure and temperature sensor, a wellhead temperature sensor, and a wellhead pressure sensor; The test string is equipped with a continuous tubing, and a bottom hole pressure and temperature sensor is installed at the bottom of the continuous tubing. The test string is equipped with a wellhead temperature sensor and a wellhead pressure sensor via a transmission optical fiber.

8. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 6, characterized in that, A riser is installed on the outside of the test string, a blowout preventer is installed below the riser, and a cementing sheath is installed below the blowout preventer.

9. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 8, characterized in that, The backflow fluid treatment device includes a density meter, a second wellhead flow meter, a gas component analyzer, a separator, a backflow valve, a metering device, and a backflow pipeline; The density meter, the second wellhead flow meter, the gas component detector, the separator, and the metering device are connected in sequence through a return pipeline, and a return valve is installed between the separator and the metering device.

10. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 9, characterized in that, The coiled tubing gas injection system includes a gas injection compressor, a gas injection line, a first wellhead flow meter, a gas injection valve, and a nitrogen injection point; The gas injection compressor is connected to the wellhead injection port of the wellhead device via a gas injection pipeline. The wellhead injection port is equipped with a nitrogen injection point via a continuous tubing. A first wellhead flow meter is installed on the gas injection pipeline; An injection valve is installed on the injection pipeline between the injection compressor and the first wellhead flow meter.

11. The high-efficiency flowback device for testing ultra-deepwater and ultra-shallow gas horizontal wells as described in claim 6, characterized in that, The data processing and response device includes a computer, an instruction transmission fiber optic signal receiving and execution system; The signal receiving and execution system is connected to a computer via fiber optic command transmission.

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