Device and method for testing wellbore pressure in simulated gas cut shut-in period

Abstract

The invention belongs to the technical field of petroleum and natural gas drilling engineering, and discloses a device and method for testing wellbore pressure during simulated gas cut shut-in, and the device comprises a gas-liquid conveying and backflow system, a wellbore simulation system and a control and data acquisition system; the shaft simulation system comprises a simulation drill string, a simulation sleeve and an electric flat valve; the gas-liquid conveying and backflow system comprises a liquid injection pipeline, a liquid conveying pump, a liquid inlet pipeline, a liquid storage tank, a liquid return pipeline, a gas-liquid separator, an exhaust pipeline, a suction pump, a liquid discharge pipeline, a gas return pipeline, a nitrogen compressor, a gas injection electromagnetic valve and a gas injection pipeline; the control and data acquisition system comprises a control cabinet and a data acquisition unit. According to the invention, the pressure change of the shaft under different factors during the gas cut shut-in period can be effectively simulated, the pressure data is restored through the similarity principle, the pressure data is compared with the actual pressure grade of the wellhead blowout preventer, the maximum internal pressure resistance strength of the casing and the formation fracture pressure, and the safety and reliability of overflow shut-in are evaluated.

Description

Technical Field

[0001] The invention relates to a device and a method for testing wellbore pressure during a well shut-in period of simulating gas invasion, and belongs to the technical field of oil and natural gas drilling engineering. Background Art

[0002] As deep oil and gas exploration continues to extend to deep and ultra-deep formations, gas invasion and overflow during oil drilling are becoming more frequent and serious. Gas invasion is much more harmful than overflow. The primary treatment method after gas invasion is to shut down the well. If the well is shut down for a long enough time, the invading gas will slip and rise to the wellhead, increasing the wellbore pressure, which may cause accidents such as leakage of weak formations, casing rupture, and damage to well control equipment, seriously endangering life and property safety.

[0003] In the development of high-temperature, high-pressure and high-yield gas wells, unstable formation gas supply, temperature changes, valve operation and other factors lead to unstable flow of fluid inside the wellbore. If the well is shut in too quickly, the fluid pressure will change instantly to form a water hammer effect, thereby generating a large fluctuation pressure, affecting the integrity of the wellbore. Moreover, if the wellhead casing pressure is greater than the safety casing pressure value, it will be impossible to ensure safe well killing operations.

[0004] In summary, the impact of shutting in a well after gas invasion may be very serious. However, most of the research on the shut-in wellbore pressure due to gas invasion is based on data obtained through numerical simulation or simulation calculation, which cannot be verified. Therefore, it is necessary to use experiments to analyze the changes in shut-in wellbore pressure under different gas invasion rates, different throttle valve openings, different drill string positions, and different shut-in times and modes. The wellbore pressure restored after the test is closer to the actual situation through the combination of the non-proportional similarity principle correction method and the comparison of numerical simulation data, which provides reference for the selection of wellhead well control devices, the design of casing internal pressure safety factor, and the operation of preventing formation rupture. Summary of the invention

[0005] The purpose of the present invention is to address the problems existing in the prior art and provide a device and method for testing the wellbore pressure during a simulated gas invasion well shut-in period. The present invention can effectively simulate the changes in the wellbore pressure tested under different factors during the gas invasion well shut-in period, and restore the pressure data through a similar principle, and compare it with the actual wellhead blowout preventer pressure level, the maximum internal pressure resistance of the casing and the formation fracture pressure to evaluate the safety and reliability of overflow well shut-in.

[0006] The technical solution provided by the present invention to solve the above technical problems is: a device for testing the wellbore pressure during the period of simulating gas invasion and well shut-in, comprising a gas-liquid transmission and return system, a wellbore simulation system, and a control and data acquisition system;

[0007] The wellbore simulation system includes a simulated drill string, a simulated casing, and an electric flat valve. The electric flat valve is installed on the simulated casing. The simulated drill string is vertically installed in the simulated casing, and its upper end extends out of the electric flat valve. A plurality of wireless pressure sensors are arranged in the simulated casing. A throttle valve is arranged on the electric flat valve.

[0008] The gas-liquid delivery and reflux system includes a liquid injection pipeline, a liquid infusion pump, a liquid inlet pipeline, a liquid storage tank, a liquid return pipeline, a gas-liquid separator, an exhaust pipeline, a suction pump, a liquid discharge pipeline, a gas return pipeline, a nitrogen compressor, a gas injection solenoid valve, and a gas injection pipeline;

[0009] One end of the injection pipeline is connected to the upper end of the simulated drill string, and the other end is connected to the infusion pump, the liquid inlet pipeline, the liquid storage tank, the liquid return pipeline, the gas-liquid separator, the exhaust pipeline, and the suction pump in sequence. The inlet of the suction pump is connected to the upper end of the inner cavity of the simulated casing through a pipeline; an injection solenoid valve is provided on the injection pipeline;

[0010] The liquid discharge pipeline, gas-liquid separator, gas return pipeline, nitrogen compressor, gas injection solenoid valve, and gas injection pipeline are connected in sequence; the gas injection pipeline and liquid discharge pipeline are both connected to the bottom of the inner cavity of the simulation casing;

[0011] The control and data acquisition system comprises a control cabinet and a data collector; the control cabinet is electrically connected to the gas injection solenoid valve, the liquid injection solenoid valve, and the electric flat valve respectively; the data collector is electrically connected to the wireless pressure sensor.

[0012] A further technical solution is that the gas injection solenoid valve and the liquid injection solenoid valve are respectively provided with a gas phase flow meter and a liquid phase flow meter.

[0013] A further technical solution is that a top pressure gauge and a bottom pressure gauge are respectively provided on the throttle valve and the gas injection pipeline.

[0014] A further technical solution is that a check valve is provided between the nitrogen compressor and the gas injection solenoid valve.

[0015] A further technical solution is that a discharge valve is provided on the discharge pipeline; and an exhaust valve is provided between the suction pump and the simulation casing.

[0016] A further technical solution is that a circular fixed clamp is provided in the simulated casing, and the simulated drill string is vertically fixed in the simulated casing through the circular fixed clamp.

[0017] A further technical solution is that a support frame is provided at the bottom of the simulation casing.

[0018] A method for testing wellbore pressure during a shut-in period of simulated gas invasion specifically comprises the following steps:

[0019] Step S1, according to the casing and drill string sizes in actual oil and gas well engineering and existing experimental conditions, determine the reduced size of the wellbore pressure test device during the gas invasion shut-in period, and calculate the experimental gas phase injection rate and liquid phase injection rate;

[0020] Step S2, after determining each scale, connect the test device and select deionized water as the liquid transport medium;

[0021] Step S3, close all valves except the injection solenoid valve and the electric flat valve, start the infusion pump, pump out the mixed liquid in the liquid storage tank, and adjust the injection solenoid valve according to the calculated liquid phase injection rate, so that the liquid phase flowmeter reaches the target flow rate, and the injection pipeline, the simulated drill string and the simulated casing are completely filled with liquid;

[0022] Step S4, open the gas injection solenoid valve, adjust the gas injection solenoid valve according to the calculated gas phase injection rate, then start the nitrogen compressor to inject gas into the wellbore simulation system, observe the pressure of the wireless pressure sensor at the bottom collected by the data collector, and when it is less than the displayed data of the bottom pressure gauge, close the liquid injection solenoid valve through the control cabinet;

[0023] Step S5, fully open the throttle valve, and adjust the closing speed of the electric flat valve through the control cabinet. When the sum of the top pressure data, the bottom pressure data and the display data of the top pressure gauge of the wireless pressure sensor is equal to the display data of the bottom pressure gauge, close the gas injection solenoid valve, and record the pressure data transmitted during this period;

[0024] Step S6, first open the drain valve to discharge all the liquid, then open the exhaust valve, and use the suction pump to drain the gas in the wellbore simulation system, and finally separate the gas and liquid phases through the gas-liquid separator and reuse them for the next round of shut-in wellbore pressure test;

[0025] Step S7, using the Euler number to process the pressure data to obtain actual bottom hole pressure data;

[0026] Step S8, by numerical simulation, the simulated bottom hole pressure data in the wellbore continuous flow process and the gas slippage rising process under actual engineering conditions can be obtained;

[0027] Step S9, compare the actual bottom hole pressure data with the simulated bottom hole pressure data to see whether they meet the requirements. If not, improve the correction coefficient and re-obtain the restored actual bottom hole pressure data to obtain the wellbore pressure data that is closest to the actual gas invasion and well shut-in during oil and gas well production.

[0028] A further technical solution is that the calculation formulas for the gas phase injection rate and the liquid phase injection rate are:

[0029]

[0030] Where: u p is the actual fluid flow velocity; u m is the flow velocity of the test fluid; l m is the characteristic length of the test fluid; l p is the characteristic length of the actual fluid.

[0031] A further technical solution is that the calculation formula of the actual bottom hole pressure data in step S10 is:

[0032] p p =p m ·K·K bc

[0033]

[0034] Where: K is the comprehensive correction coefficient; K bc is the correction factor; μ p is the fluid viscosity of the actual fluid; μ m is the fluid viscosity of the test fluid; p p is the actual bottom hole pressure data; p m The bottom hole pressure data of the test.

[0035] The present invention has the following beneficial effects: the present invention can design a device for simulating gas invasion and shut-in to test wellbore pressure in a reduced size according to the principle of similarity based on actual on-site conditions, and calculate the corresponding fluid properties according to the velocity scale, viscosity scale and density scale, so as to better simulate the influence of different gas invasion rates, different throttle valve openings, different drill string positions, different shut-in times and modes on the shut-in wellbore pressure during the gas invasion and shut-in period.

[0036] In addition, the present invention adopts a wireless pressure sensor to make data transmission more flexible and remote operation and setting more convenient. It does not require wiring and has a long service life. In particular, its high-precision measurement can be more in line with the actual situation, thereby laying a good foundation for further research on shut-in wellbore pressure. BRIEF DESCRIPTION OF THE DRAWINGS

[0037] Figure 1 Schematic diagram of the overall structure of a device for testing wellbore pressure during a shut-in period simulating gas invasion in an embodiment of the present invention;

[0038] Figure 2 It is a wellhead schematic diagram of a wellbore simulation system in a wellbore pressure testing device in an embodiment of the present invention.

[0039] As shown in the figure: 1-liquid discharge valve; 2-nitrogen compressor; 3-liquid discharge pipeline; 4-gas return pipeline; 5-gas-liquid separator; 6-suction pump; 7-liquid storage tank; 8-liquid inlet pipeline; 9-infusion pump; 10-liquid return pipeline; 11-exhaust pipeline; 12-exhaust valve; 13-liquid injection pipeline; 14-liquid injection solenoid valve; 15-liquid flow meter; 16-control cabinet; 17-electric flat valve; 18-throttle valve; 19-top pressure gauge; 20-circular fixed clamp; 21-simulated drill string; 22-simulated casing; 23-wireless pressure sensor; 24-data acquisition device; 25-support frame; 26-bottom pressure gauge; 27-gas injection pipeline; 28-gas flow meter; 29-gas injection solenoid valve; 30-check valve. DETAILED DESCRIPTION

[0040] The technical solution of the present invention will be described clearly and completely below in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the invention, not all of them. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0041] In the description of the present invention, it should be noted that the terms "center", "upper", "lower", "left", "right", "vertical", "horizontal", "inner", "outer", etc., indicating the orientation or positional relationship, are based on the orientation or positional relationship shown in the drawings, and are only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore cannot be understood as limiting the present invention. In addition, the terms "first", "second", and "third" are used for descriptive purposes only, and cannot be understood as indicating or implying relative importance.

[0042] In the description of the present invention, it should be noted that, unless otherwise clearly specified and limited, the terms "installed", "connected" and "connected" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0043] In addition, the technical features involved in the different embodiments of the present invention described below can be combined with each other as long as they do not conflict with each other.

[0044] like Figure 1-Figure 2As shown, the present invention provides a device for testing the wellbore pressure during the period of simulating gas invasion and well shut-in. The device is based on the actual situation of oil and gas well engineering, and determines the dimensions of its simulated casing and simulated drill string, the physical properties of the fluid, etc. according to the similarity principle, and further simulates the changes in the wellbore pressure of the oil and gas wellbore during the period of gas invasion and well shut-in, at different gas invasion rates, different throttle valve openings, different drill string positions, and different well shut-in times and modes, so as to study out an effective solution to the problem of damaging the wellbore integrity that may occur during gas invasion and well shut-in, and at the same time pay attention to the requirements of low-carbon emission reduction policies and complete the recycling of test materials;

[0045] Specifically, it includes a gas-liquid transportation and reflux system, a wellbore simulation system, and a control and data acquisition system; the wellbore simulation system includes a simulated drill string 21, a simulated casing 22, and an electric flat valve 17, the electric flat valve 17 is installed in the simulated casing 22, the simulated drill string 21 is vertically installed in the simulated casing 22, and its upper end extends out of the electric flat valve 17; a plurality of wireless pressure sensors 23 are symmetrically and evenly distributed on the inner wall of the simulated casing 22; a throttle valve 18 is provided on the electric flat valve 17;

[0046] The simulated drill string 21 is located at the center of the simulated casing 22, and the annulus between the two is used to load gas and liquid phases. The throttle valve 18 is located at the upper right part of the simulated casing 22 and is connected to the wellbore annulus. The electric flat valve 17 is located at the upper port of the simulated casing. The two work together to simulate different shut-in modes.

[0047] In this embodiment, the closing sequence and opening size of the throttle valve 18 and the electric flat valve 17 are adjusted to simulate different modes of shutting in the well (first fully opening the throttle valve 18 and then closing the electric flat valve 17 for soft shut-in; keeping the throttle valve 18 closed and directly closing the electric flat valve 17 for hard shut-in; first half-opening the throttle valve 18 and then closing the electric flat valve 17 for semi-soft shut-in);

[0048] The wireless pressure sensor 23 converts the pressure signal into an electrical signal and transmits it to the data collector 24 through Bluetooth, WiFi or LoRa technology to obtain data on the downhole wellbore pressure simulated by gas intrusion. The wireless pressure sensor is flexible, convenient and has high accuracy.

[0049] The gas-liquid delivery and reflux system includes a liquid injection pipeline 13, a liquid infusion pump 9, a liquid inlet pipeline 8, a liquid storage tank 7, a liquid return pipeline 10, a gas-liquid separator 5, an exhaust pipeline 11, a suction pump 6, a liquid discharge pipeline 3, a gas return pipeline 4, a nitrogen compressor 2, a gas injection solenoid valve 29, and a gas injection pipeline 27;

[0050] One end of the injection pipeline 13 is connected to the upper end of the simulated drill string 21, and the other end is connected to the infusion pump 9, the liquid inlet pipeline 8, the liquid storage tank 7, the liquid return pipeline 10, the gas-liquid separator 5, the exhaust pipeline 11, and the suction pump 6 in sequence. The inlet of the suction pump 6 is connected to the upper end of the inner cavity of the simulated casing 22 through a pipeline; the injection pipeline 13 is provided with an injection solenoid valve 14;

[0051] The liquid discharge pipeline 3, the gas-liquid separator 5, the gas return pipeline 4, the nitrogen compressor 2, the gas injection solenoid valve 29, and the gas injection pipeline 27 are connected in sequence; the gas injection pipeline 27 and the liquid discharge pipeline 3 are both connected to the bottom of the inner cavity of the simulation casing 22;

[0052] The control and data acquisition system includes a control cabinet 16 and a data acquisition device 17; the control cabinet 16 is electrically connected to the gas injection solenoid valve 29, the liquid injection solenoid valve 14, and the electric flat valve 17 respectively; the data acquisition device 17 is electrically connected to the wireless pressure sensor 23; the control cabinet 16 accurately adjusts the gas-liquid output flow rate and the closing speed of the electric flat valve 17 by controlling the solenoid valve, and the data acquisition device 17 is responsible for collecting the gas-liquid output flow rate and the pressure change data in the wellbore simulation system;

[0053] The gas injection solenoid valve 29 and the liquid injection solenoid valve 14 are respectively provided with a gas phase flow meter 28 and a liquid phase flow meter 15; wherein the solenoid valve and the flow meter are respectively used to adjust and monitor the flow of the gas and liquid phases;

[0054] The throttle valve 18 and the gas injection pipeline 27 are respectively provided with a top pressure gauge 19 and a bottom pressure gauge 26; the top pressure gauge 19 is used to record the throttle pressure; the bottom pressure gauge 26 is used to record the formation pressure of the simulated wellbore system;

[0055] A check valve 30 is provided between the nitrogen compressor 2 and the gas injection solenoid valve 29, wherein the check valve 30 is used to prevent the liquid in the wellbore simulation system from flowing back;

[0056] A discharge valve 1 is provided on the discharge pipeline 3 ; and an exhaust valve 12 is provided between the suction pump 6 and the simulation sleeve 22 .

[0057] In the whole device, the nitrogen compressor 1 and the infusion pump 9 are used to supply gas and liquid, which are respectively transported to the wellbore simulation system through the gas injection pipeline 27 and the liquid injection pipeline 13 for testing. After the test is completed, the gas and liquid are respectively transported through the exhaust pipeline 11, the exhaust valve 12 and the discharge pipeline 3, and the discharge valve 1 to the gas-liquid separator 5 for gas-liquid separation reaction. Finally, the gas returns to the nitrogen compressor 1 through the return gas pipeline 4, and the liquid flows back to the liquid storage tank 7 through the return liquid pipeline 10, and the next liquid injection operation is carried out through the liquid inlet pipeline 8.

[0058] In this embodiment, the simulated drill string 21 and the simulated casing 22 can be made of PC tube or plexiglass, the gas medium in the exhaust valve 12 and the gas injection solenoid valve 29 is nitrogen, and the liquid medium in the liquid injection solenoid valve 14 and the drain valve 1 is a mixture of deionized water and xanthan gum of different concentrations.

[0059] In this embodiment, if Figure 1 As shown, a circular fixed clamp 20 is provided in the simulated casing 22, and the simulated drill string 21 is vertically fixed in the simulated casing 22 through the circular fixed clamp 20; the size of the circular fixed clamp 20 can be adjusted by rotating the nut on the side to fit the simulated drill string 21.

[0060] In this embodiment, if Figure 1 As shown, a support frame 25 is provided at the bottom of the simulated casing 22, and the support frame 25 is used to lift the entire wellbore simulation system to facilitate gas injection and liquid discharge.

[0061] In this embodiment, taking the soft shut-in mode as an example, since the horizontal and vertical dimensions of the drilling wellbore in actual engineering are extremely different, it is almost impossible to use proportional similarity processing, so a non-proportional similarity processing correction method is used.

[0062] The method for testing the wellbore pressure during the shut-in period of simulating gas invasion includes the following steps:

[0063] Step S1, according to the casing and drill string sizes in actual oil and gas well engineering and existing experimental conditions, determine the reduced size of the wellbore pressure test device during the gas invasion shut-in period, and calculate the experimental gas phase injection rate and liquid phase injection rate;

[0064] In this embodiment, the actual size (p) and the test device size (m) are recorded as data set p n and m n The geometric dimensions involved are the simulated drill string outer diameter (A), simulated drill string inner diameter (B), simulated casing outer diameter (C), simulated casing inner diameter (D), and the relative height of the simulated casing and the simulated drill string (E), a total of five key dimension data. The actual dimensions and test device dimensions are expressed as:

[0065] p n =(p A ,p B ,p C ,p D ,p E )

[0066] m n =(m A ,m B ,m C ,m D ,mE )

[0067] According to the Euclidean distance calculation method, the standard deviation S of the actual size of the sample set (p) and the size of the test device (m) are calculated respectively. n :

[0068]

[0069] Where: are the standardized variables of actual size and test device size, respectively; are the means of the corresponding dimensional parameters of the actual size and the test device size respectively; s n is the standard deviation of the corresponding size parameter.

[0070] Euclidean distance between actual size and test device size:

[0071]

[0072] The size of the simulation device is designed according to the above design method. When the Euclidean distance E(p,m)∈[0,1] between the actual size and the test device size is calculated, it indicates that the actual size and the test device size meet the similarity design requirements;

[0073] In order to ensure that the test device has a high degree of similarity with the flow field in the actual wellbore, in addition to the geometric shape, it is also necessary to further perform dynamic similarity processing. Dynamic similarity processing requires satisfying the gravity similarity criterion, that is, the Froude number and Reynolds number of the two types of flow fields are equal. The two parameter expressions are as follows:

[0074]

[0075] Where: Fr is the Froude number, dimensionless; Re is the Reynolds number, dimensionless; g is the acceleration due to gravity, 9.81 m / s 2 ; l is the characteristic length, m; u is the flow velocity of the fluid, m / s; ρ is the density of the fluid, kg / m 3 ; μ is the fluid viscosity, Pa·s.

[0076] According to the expression of Froude number, the test speed correction formula can be obtained as follows:

[0077]

[0078] Where: u p is the actual fluid flow velocity; u m is the flow velocity of the test fluid; l m is the characteristic length of the test fluid; l p is the characteristic length of the actual fluid.

[0079] The correction formula for the test fluid density is:

[0080]

[0081] Where: p is the density of the actual fluid; ρ m is the density of the test fluid; μ p is the fluid viscosity of the actual fluid; μ m is the fluid viscosity of the test fluid.

[0082] Step S2, after determining each scale, connect the test device and select deionized water as the liquid transport medium;

[0083] Step S3, close all valves except the injection solenoid valve 14 and the electric flat valve 17, start the infusion pump 9, pump out the mixed liquid in the liquid storage tank 7, and adjust the injection solenoid valve 14 according to the calculated liquid phase injection rate, so that the liquid phase flowmeter reaches the target flow rate, and the injection pipeline 8, the simulated drill string 21 and the simulated casing 22 are completely filled with liquid;

[0084] Step S4, open the gas injection solenoid valve 29, adjust the gas injection solenoid valve 29 according to the calculated gas phase injection rate, then start the nitrogen compressor 2 to inject gas into the wellbore simulation system, observe the pressure of the wireless pressure sensor 23 at the bottom collected by the data collector 24, and when it is less than the displayed data of the bottom pressure gauge 26, close the liquid injection solenoid valve 14 through the control cabinet 16;

[0085] Step S5, fully open the throttle valve 18, and adjust the closing speed of the electric flat valve 17 through the control cabinet 16. When the sum of the top pressure data, the bottom pressure data of the wireless pressure sensor 23 and the display data of the top pressure gauge 19 is equal to the display data of the bottom pressure gauge 26, close the gas injection solenoid valve 29, and record the pressure data transmitted during this period;

[0086] Step S6, first open the drain valve 1 to discharge all the liquid, then open the exhaust valve 12, and use the suction pump 6 to drain the gas in the wellbore simulation system, and finally separate the gas and liquid phases through the gas-liquid separator 5 and reuse them to carry out the next round of shut-in wellbore pressure test;

[0087] Step S7, using the Euler number to process the pressure data to obtain actual bottom hole pressure data;

[0088] The Euler number (Eu) is the ratio of pressure to inertial force and is defined as:

[0089]

[0090] Where: p0 is the pressure reference; u0 is the characteristic velocity.

[0091] The Euler number of the actual working condition and the test must be equal, that is:

[0092]

[0093] Substituting the velocity correction formula and density correction formula into the above formula, we can get:

[0094]

[0095] After simplification, the pressure reduction formula is:

[0096]

[0097] The comprehensive correction coefficient expression is:

[0098]

[0099] Where: K is the comprehensive correction coefficient.

[0100] Consider the influence of wall friction, inlet conditions and outlet conditions on pressure in the test device and actual working conditions. Correct the differences of these boundary effects through numerical simulation or experimental calibration to obtain the correction factor K bc , the actual pressure data restoration formula is:

[0101] p p =p m ·K·K bc

[0102] Where: K bc is the correction factor; p p is the actual bottom hole pressure data; p m The test bottom hole pressure data;

[0103] Step S8, obtaining the simulated bottom hole pressure data in the wellbore continuous flow process and the gas slippage rising process under actual engineering conditions through numerical simulation;

[0104] Solution for bottom hole pressure during wellbore continuous flow:

[0105] According to the law of conservation of mass, and combined with the fact that the fluid in the wellbore will not penetrate into the formation at this stage, the following formula can be established:

[0106]

[0107] In the above formula: Q g is the gas flow rate invading the wellbore, m 3 / d; B g is the gas volume coefficient; V g is the gas volume, m 3 ; C gis the gas compressibility coefficient, MPa -1 ; V l is the volume of liquid, m 3 ; C l is the liquid compressibility coefficient, MPa -1 ;p w is the shut-in bottom hole pressure, MPa; t is the shut-in time, h.

[0108] Process the right side of the above equation and set ΔV = V h [αC g +(1-α)C l ]+V H C l , we can get:

[0109]

[0110] Where: ΔV is the volume change of the wellbore fluid per unit pressure change, m 3 , where α is the cross-sectional gas content.

[0111] Among them, the natural gas intrusion velocity into the wellbore is:

[0112]

[0113] Where: k is the effective permeability of the gas layer, 10 -3 μm 2 ; μ is gas viscosity, mPa·s; h is effective thickness of gas layer, m; T is formation temperature, K; z is natural gas compression factor; r e is the supply frontier, m; r w is the wellbore radius, m; p e is the formation pressure, MPa.

[0114] The initial conditions are t = 0, p w =p w0 , using the separation of variables method we can get:

[0115]

[0116] Where: p w0 It is the bottom hole pressure when the well is just shut in, MPa.

[0117] Solution for bottom hole pressure during gas slippage and ascent:

[0118] The volume increased by gas expansion is equal to the sum of the volume decreased by drilling fluid compression and the volume of drilling fluid lost to the formation. According to the principle of conservation of mass:

[0119]

[0120] Where: A is the cross-sectional area of ​​the annulus between the drill string and the wellbore, m2; is the average cross-sectional gas content of the gas-liquid two-phase segment after the gas rises for t time; ΔV is the average cross-sectional gas content of the gas-liquid two-phase section when the well is just shut in; f is the volume of drilling fluid lost to the formation within time t, m 3 ; A' is the filtration area, m 2 ;k b is the filter cake permeability, 10 -3 μm 2 ;f sc is the solid content in the filter cake; f sm is the solid content in the drilling fluid; Δp is the pressure difference, MPa; t is the filtration time, min; μ l is the drilling fluid viscosity, mPa·s.

[0121] Calculate the length of the gas-liquid mixing section according to the following formula:

[0122] h gx =u g2 t-h+h g0

[0123] Where h = u g1 t,u g1 ,u g2 They are the rising velocities at the upper and lower ends of the gas-liquid mixing section, m / s.

[0124] The average cross-sectional gas content of the gas-liquid mixing section is calculated according to the following formula:

[0125]

[0126] Where: M g is the mass of gas invading the wellbore, kg.

[0127] For non-Newtonian drilling fluids, when the cross-sectional gas content is greater than 0.07, the bubbly flow is transformed into a slug flow. The gas slip velocity under different flow states is:

[0128] Bubble flow gas slip velocity: u gr =1.53[g(ρ l -ρ g )σ / ρ l 2 ] 1 / 4

[0129] Slug flow gas slip velocity: u gr =0.35[gd(ρ l -ρ g ) / ρ l ] 1 / 2

[0130] Where: u gr is the slip velocity between gas and liquid, m / s; σ is the surface tension of gas and liquid, mN / m; d is the inner diameter of the casing, m.

[0131] According to the knowledge of fluid mechanics, the following formula is established to solve the bottom hole pressure:

[0132]

[0133] p c =p h2 -ρ l g(Hhh gx )

[0134] p c =p h2 -ρ l g(Hhh gx )

[0135] Step S9, compare the actual bottom hole pressure data with the simulated bottom hole pressure data to see whether they meet the requirements. If not, improve the correction coefficient and re-obtain the restored actual bottom hole pressure data to obtain the wellbore pressure data that is closest to the actual gas invasion and well shut-in during oil and gas well production.

[0136] The present invention evaluates the safety and reliability of the wellbore by determining the wellbore pressure data when the well is shut in due to gas invasion in actual production, such as whether weak formations are compressed and leaked, whether the casing is ruptured, whether the well control equipment is damaged, etc. Conversely, it can also provide basic data for the selection of wellhead well control devices, the design of the casing's safety factor against internal pressure, and the operation of preventing formation rupture.

[0137] In this method, steps S1 to S6 are repeated to change the closing speed of the electric flat valve 17, so as to test the change of wellbore pressure at different shut-in times for gas invasion shut-in;

[0138] In this method, steps S1 to S6 are repeated to change the relative positions of the simulated drill string 21 and the simulated casing 22, and the change of the wellbore pressure at different drill string positions can be tested;

[0139] In this method, the gas invasion rate is changed, and steps S1 to S7 are repeated to test the shut-in wellbore pressure at different gas invasion rates.

[0140] The above description is not intended to limit the present invention in any form. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A device for testing wellbore pressure during a shut-in period simulating gas intrusion, characterized in that: Including gas and liquid transportation and return system, wellbore simulation system and control and data acquisition system; The wellbore simulation system comprises a simulated drill string (21), a simulated casing (22), and an electric flat valve (17); the electric flat valve (17) is installed on the simulated casing (22); the simulated drill string (21) is vertically installed in the simulated casing (22), and its upper end extends out of the electric flat valve (17); a plurality of wireless pressure sensors (23) are arranged in the simulated casing (22); and a throttle valve (18) is arranged on the electric flat valve (17); The gas-liquid transport and reflux system comprises a liquid injection pipeline (13), a liquid infusion pump (9), a liquid inlet pipeline (8), a liquid storage tank (7), a liquid return pipeline (10), a gas-liquid separator (5), an exhaust pipeline (11), a suction pump (6), a liquid discharge pipeline (3), a gas return pipeline (4), a nitrogen compressor (2), a gas injection solenoid valve (29), and a gas injection pipeline (27); One end of the injection pipeline (13) is connected to the upper end of the simulated drill string (21), and the other end is connected to the infusion pump (9), the liquid inlet pipeline (8), the liquid storage tank (7), the liquid return pipeline (10), the gas-liquid separator (5), the exhaust pipeline (11), and the suction pump (6) in sequence, and the inlet of the suction pump (6) is connected to the upper end of the inner cavity of the simulated casing (22) through a pipeline; the injection pipeline (13) is provided with an injection solenoid valve (14); The liquid discharge pipeline (3), the gas-liquid separator (5), the gas return pipeline (4), the nitrogen compressor (2), the gas injection solenoid valve (29), and the gas injection pipeline (27) are connected in sequence; the gas injection pipeline (27) and the liquid discharge pipeline (3) are both connected to the bottom of the inner cavity of the simulation casing (22); The control and data acquisition system comprises a control cabinet (16) and a data acquisition device (17); the control cabinet (16) is electrically connected to the gas injection solenoid valve (29), the liquid injection solenoid valve (14), and the electric flat valve (17), respectively; and the data acquisition device (17) is electrically connected to the wireless pressure sensor (23).

2. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: The gas injection solenoid valve (29) and the liquid injection solenoid valve (14) are respectively provided with a gas phase flow meter (28) and a liquid phase flow meter (15).

3. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: The throttle valve (18) and the gas injection pipeline (27) are respectively provided with a top pressure gauge (19) and a bottom pressure gauge (26).

4. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: A check valve (30) is provided between the nitrogen compressor (2) and the gas injection solenoid valve (29).

5. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: A liquid discharge valve (1) is provided on the liquid discharge pipeline (3); and an exhaust valve (12) is provided between the suction pump (6) and the simulation casing (22).

6. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: A circular fixing clamp (20) is provided in the simulated casing (22), and the simulated drill string (21) is vertically fixedly installed in the simulated casing (22) through the circular fixing clamp (20).

7. The device for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 1, characterized in that: A support frame (25) is provided at the bottom of the simulation sleeve (22).

8. A method for testing wellbore pressure during shut-in period of simulated gas invasion, characterized in that: The method uses a device for testing wellbore pressure during a shut-in period of simulated gas invasion as described in any one of claims 1 to 7 for testing, and specifically comprises the following steps: Step S1, according to the casing and drill string sizes in actual oil and gas well engineering and existing experimental conditions, determine the reduced size of the wellbore pressure test device during the gas invasion shut-in period, and calculate the experimental gas phase injection rate and liquid phase injection rate; Step S2, after determining each scale, connect the test device and select deionized water as the liquid transport medium; Step S3, closing all valves except the injection solenoid valve (14) and the electric flat valve (17), starting the infusion pump (9), pumping out the mixed liquid in the liquid storage tank (7), and adjusting the injection solenoid valve (14) according to the calculated liquid phase injection rate, so that the liquid phase flow meter reaches the target flow rate, and the injection pipeline (8), the simulated drill string (21) and the simulated casing (22) are completely filled with liquid; Step S4, open the gas injection solenoid valve (29), adjust the gas injection solenoid valve (29) according to the calculated gas phase injection rate, then start the nitrogen compressor (2) to inject gas into the wellbore simulation system, observe the pressure of the wireless pressure sensor at the bottom collected by the data collector (24), and when it is less than the displayed data of the bottom pressure gauge (26), close the liquid injection solenoid valve (14) through the control cabinet (16); Step S5, fully open the throttle valve (18), and adjust the closing speed of the electric flat valve (17) through the control cabinet (16). When the sum of the top pressure data of the wireless pressure sensor (23), the bottom pressure data and the display data of the top pressure gauge (19) is equal to the display data of the bottom pressure gauge (26), close the gas injection solenoid valve (29), and record the pressure data transmitted during this period; Step S6, first open the drain valve (1) to drain all the liquid, then open the exhaust valve (12), and use the suction pump (6) to drain the gas in the wellbore simulation system, and finally separate the gas and liquid phases through the gas-liquid separator (5) and reuse them for the next round of shut-in wellbore pressure test; Step S7, using the Euler number to process the pressure data to obtain actual bottom hole pressure data; Step S8, obtaining the simulated bottom hole pressure data in the wellbore continuous flow process and the gas slippage rising process under actual engineering conditions through numerical simulation; Step S9, compare the actual bottom hole pressure data with the simulated bottom hole pressure data to see whether they meet the requirements. If not, improve the correction coefficient and re-obtain the restored actual bottom hole pressure data to obtain the wellbore pressure data that is closest to the actual gas invasion and well shut-in during oil and gas well production.

9. A method for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 8, characterized in that: The calculation formulas for the gas phase injection rate and the liquid phase injection rate are: Where: u p is the actual fluid flow velocity; u m is the flow velocity of the test fluid; l m is the characteristic length of the test fluid; l p is the characteristic length of the actual fluid.

10. The method for testing wellbore pressure during shut-in period of simulated gas invasion according to claim 8, characterized in that: The calculation formula of the actual bottom hole pressure data in step S10 is: p p =p m ·K·K bc Where: K is the comprehensive correction coefficient; K bc is the correction factor; μ p is the fluid viscosity of the actual fluid; μ m is the fluid viscosity of the test fluid; p p is the actual bottom hole pressure data; p m The bottom hole pressure data of the test.

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