Overflow well killing method in process of controlled pressure drilling of hydrate layer and shallow gas layer

Abstract

The invention discloses an overflow well killing method in the process of controlled pressure drilling of a hydrate layer and a shallow gas layer. Comprising the steps of well shut-in data collection and basic parameter calculation, ocean temperature field model construction, formation pressure distribution solution, gas production rate calculation, shaft multiphase flow parameter calculation, natural gas physical property parameter calculation, drilling fluid physical property parameter calculation, bubble rising speed calculation, shaft annulus gas-liquid two-phase dynamic flow basic equation and flow pattern and flow state analysis. And gas-liquid two-phase flow pressure drop calculation and dynamic parameter calculation are carried out, and finally, an actual optimization well killing method and construction parameters are combined. According to the method, through accurate calculation and dynamic analysis, the bottom hole pressure is effectively controlled, overflow well killing is efficiently carried out, the well drilling cost is reduced, and technical support is provided for the well drilling method of the natural gas hydrate and the underfloat shallow gas layer.

Description

Technical Field

[0001] This invention relates to the field of natural gas hydrate and shallow gas drilling and production technology, and particularly to an overflow control method in the process of controlled pressure drilling of hydrate layers and shallow gas layers. Background Technology

[0002] Natural gas hydrates (combustible ice) are non-stoichiometric, cage-like crystalline substances formed from natural gas and water under low temperature and high pressure conditions. The formation of marine natural gas hydrates is essentially the same as that of conventional oil and gas. Faults arise on the seabed due to compression, stretching, or lateral compression deformation of sediments caused by tectonic activity. Underlying trapped free gas migrates upwards and forms natural gas hydrates under high pressure and low temperature conditions. Shallow and medium-deep hydrates have a vertically coupled symbiotic relationship with the underlying free gas.

[0003] Due to the low cementation strength and narrow safety density window of hydrate layers and shallow gas reservoirs, high precision is required for bottomhole pressure control. Inaccurate bottomhole pressure control can easily lead to lost circulation and overflow during drilling in these reservoirs. The narrow safety density window makes precise bottomhole pressure control difficult, and situations where bottomhole pressure cannot balance formation pressure are common during controlled-pressure drilling. In hydrate layer drilling, the influence of drilling fluid or a bottomhole pressure lower than the formation pressure can easily cause hydrate decomposition, resulting in overflow as decomposed gas enters the wellbore. In shallow gas layer drilling, a bottomhole pressure lower than the reservoir pressure can also cause shallow gas to enter the wellbore, leading to overflow. To ensure drilling safety, timely and precise well control is necessary in the event of an overflow. However, based on current research and construction methods… Although methods exist to prevent well kicks, hydrate intrusion, and shallow gas intrusion into the wellbore, overflow accidents can still occur due to various factors during actual construction. Therefore, there is currently no effective solution for overflow problems that have already occurred during controlled-pressure drilling of hydrate layers and underlying shallow gas layers. Thus, there is an urgent need to propose a new method for overflow control during controlled-pressure drilling of hydrate layers and underlying shallow gas layers, effectively solving the problem of precise overflow control during controlled-pressure drilling of hydrate layers and underlying shallow gas layers, thereby ensuring safe and smooth construction of controlled-pressure drilling of hydrate layers and underlying shallow gas layers. Summary of the Invention

[0004] To address the aforementioned technical problems, this invention provides a method for controlling overflow well control during the controlled drilling process involving hydrate formations and shallow gas formations.

[0005] This invention is achieved using the following technical solution: A method for controlling well overflow during pressure drilling processes involving hydrated layers and shallow gas formations includes the following steps: Step S1: After the overflow occurs, quickly shut in the well, collect the shut-in casing pressure and standpipe pressure data, and calculate the initial formation pressure basic parameters in combination with the well structure and formation parameters; Step S2: By defining the wellbore radius and drilling fluid density parameters and related equations, the formula for the temperature field distribution inside the wellbore during gas invasion is obtained, and a marine temperature field model is constructed. Step S3: Using the bottom hole pressure as the inner boundary condition, and combining Darcy flow, non-Darcy flow theory and hydrate decomposition gas production model, obtain the formation pressure distribution; Step S4: Based on the formation pressure distribution and pressure conditions, calculate the total formation gas production, wellbore multiphase flow parameters, natural gas physical property parameters, and drilling fluid physical property parameters respectively; Step S5: Calculate the bubble rising velocity based on the gas-liquid density, gas density, and bubble diameter parameters, and establish the basic equation for the dynamic two-phase flow of air and liquid in the wellbore annulus based on the calculated parameters; Step S6: Flow pattern analysis, determine the transition boundaries of bubbly flow, slug flow, agitated flow and annular mist flow by using critical pipe diameter and porosity parameters; calculate the pressure drop under different flow patterns by analyzing different flow patterns in the wellbore; Step S7: Grid the time and wellbore, iteratively calculate the dynamic parameters of bottom hole pressure, gas production and heavy slurry return height, optimize the well control construction parameters, and restart the construction.

[0006] Specifically, the solution of the temperature field distribution formula in step S2 treats the gas intrusion process as a superposition of the normal circulation temperature field model of the wellbore and the gas intrusion annular temperature field model within the formation section. The wellbore radius, drilling fluid density parameters, and related equations are as follows: ; ; in, , , , , , ; The radius of the wellbore. For drilling fluid density, This represents the volume fraction of the gas and liquid phases. For the annular area, This is the gas phase volumetric flow rate. This refers to the liquid phase volumetric flow rate; The solution yields the following expression for the temperature field distribution inside the wellbore during gas intrusion: ; in, Z represents the temperature at any well depth within the annulus, in °C; Z is the well depth coordinate, in meters. Total well depth, in meters (m). This refers to the wellhead temperature, expressed in °C. This refers to the bottom-hole temperature, expressed in °C. The normal circulating annular temperature is expressed in °C.

[0007] Specifically, step S3, obtaining the formation pressure distribution, includes: Set the initial conditions as P(t=0)=P 0 The outer boundary conditions are P(r=r e )=P 0 And set internal boundary conditions according to actual working conditions. P 0 Given the original formation pressure values, we use Taylor series expansion to discretize the values, and then use the finite difference method to solve the pore pressure distribution equation at any location and time in the formation, taking into account the initial and boundary conditions.

[0008] Specifically, the total formation gas production in step S4 is the sum of shallow gas seepage production and hydrate decomposition production, wherein: For shallow gas reservoirs without Darcy flow, the formula for calculating gas production is: ; in, This represents the output under standard gas conditions. Pressure is supplied to the boundary of the infinitesimal element; Bottom hole flowing pressure; Formation permeability; This refers to the viscosity of the gas. The radius of the outer boundary of the gas reservoir; Where is the wellbore radius; The gas production from hydrate decomposition is calculated based on a hydrate decomposition gas production model, which is expressed as follows: ; in, The mass of the decomposed hydrate is expressed in kg. The molar mass of natural gas hydrate is expressed in kg / mol. The surface area of ​​the hydrate in the decomposition zone is expressed in m². 2 ; This is the equilibrium pressure of the hydrate phase, expressed in Pa. This refers to the gas phase pressure in the decomposition zone, expressed in Pa. This is the rate constant for hydrate decomposition, in units of mol / (m). 2 ·Pa·s), and: ,in, This is the frequency factor, with units of mol / (m). 2 ·Pa·s); The activation energy for decomposition is expressed in kJ / mol. It is the ideal gas constant; The decomposition temperature is expressed in Kelvin (K).

[0009] Specifically, step S4, the calculation of the multiphase flow parameters in the wellbore, includes the calculation of various basic parameters of the gas-liquid two-phase flow, specifically: Apparent velocity in the gas phase: ;in, This is the apparent velocity in the gas phase, expressed in m / s. This refers to the gas phase mass flow rate, expressed in kg / m³. 2 s, This refers to the gas phase density, expressed in kg / m³. 2 ; Apparent velocity of the liquid phase: ;in, The apparent velocity of the liquid phase is expressed in m / s. This refers to the liquid phase mass flow rate, expressed in kg / m³. 2 s; This refers to the liquid phase density, expressed in kg / m³. 2 ; Volume fraction of liquid phase in a two-phase flow: ; Volume fraction of gas phase: ; Mass fraction of gas phase: ; Mass fraction of liquid phase: ; Porosity of gas-liquid two-phase flow: ;in, This represents the true volume fraction of the gas phase. The cross-sectional area occupied by the gas phase, in meters. 2 ; Total cross-sectional area, in meters. 2 ; The actual velocity of the gas phase is: ;in, Gas phase velocity, in m / s; Gas flow rate, unit: m³ / s 2 / s; The cross-sectional area occupied by the gas phase is expressed in meters. 2 ; The unit for gas viscosity is mPa. ; This represents the true volume fraction of the gas phase. True volume fraction of liquid phase : ;in, This represents the true volume fraction of the liquid phase. The cross-sectional area occupied by the liquid phase, in meters. 2 ; This represents the true volume fraction of the gas phase. The actual velocity of the liquid phase: ;in, This refers to the liquid phase velocity, measured in m / s. Liquid flow rate, unit: m³ 2 / s; The unit for the cross-sectional area occupied by the liquid phase is m. 2 ; This represents the actual velocity of the liquid, in m / s. This represents the true volume fraction of the liquid phase. The velocity of a gas-liquid two-phase mixture: ;in, The velocity of the gas-liquid two-phase mixture is expressed in m / s. The actual velocity in the gas phase is expressed in m / s. The actual velocity of the liquid phase is expressed in m / s. Liquid holdup; ;in, Liquid holdup; The cross-sectional area of ​​the liquid phase is expressed in m². 2 ; The cross-sectional area of ​​the gas phase is expressed in m². 2 ; Gas content: ; Slip speed: ;in, This is the slip velocity, expressed in m / s; The velocity of the gas phase is expressed in m / s. The velocity of the liquid phase is expressed in m / s. This represents the actual velocity of the gas phase, in m / s. This represents the actual velocity of the liquid phase, in m / s. This refers to the liquid holdup.

[0010] Specifically, the calculation of the physical properties of the natural gas is based on different pressure conditions, including the calculation of the viscosity and density of the natural gas and drilling fluid, specifically including: For low-pressure natural gas mixtures, the viscosity of each component of the natural gas is expressed as: ,in, Natural gas components Viscosity, in Pa s; A, B, and C are empirical formula parameters for calculating the viscosity of each component of natural gas; For high-pressure natural gas mixtures, the viscosity of each component of the natural gas is expressed as: ; in: ; ; ; ; ; ; ; in, The viscosity of a high-pressure natural gas mixture is expressed in Pa. s, a, b, c, d, and e are the coefficients in the formula for calculating the viscosity of natural gas. The calculation of drilling fluid physical properties in step S4 uses an exponential model to describe the influence of drilling fluid on temperature and pressure, expressed as: ; in, The value of drilling fluid viscosity is a function of temperature and pressure, expressed in mPa·s; P is pressure, expressed in MPa; and T is temperature, expressed in °C. V represents the drilling fluid viscosity under normal temperature and pressure conditions, in mPa·s; A is the temperature coefficient; B is the pressure coefficient. By treating drilling fluid density as a function of temperature and pressure, the density prediction formula is obtained as follows: ; in, Density at room temperature and pressure, unit: kg / m³ 3 ; , , These are the density fitting coefficients for oil-based and water-based drilling fluids, respectively.

[0011] Specifically, the formula for calculating the bubble rising speed in step S5 is: ; in, This refers to the density of the liquid, expressed in kg / m³. 3 ; This refers to the density of a gas, expressed in kg / m³. 3 ; The viscosity of a liquid is expressed in Pa. s; The viscosity of the gas is expressed in Pa. s; is the diameter of the bubble, in meters; is the surface tension, in N / m.

[0012] Specifically, step S5 establishes the basic equations for the dynamic flow of the gas-liquid two-phase gas in the wellbore annulus based on the mass conservation equations and momentum conservation equations for liquids and gases, analyzing the flow law of the gas-liquid two-phase gas; the specific formula is expressed as follows: The mass conservation equation for a liquid is: ; The mass conservation equation for a gas is: ; in, The velocity of the liquid, measured in m / s; The velocity of the gas is expressed in m / s. This refers to the density of the liquid, expressed in g / cm³. 3 ; This refers to the density of a gas, expressed in g / cm³. 3 ; The volume coefficient of the liquid; This is the gas volume coefficient; Formation gas production, expressed in L / s; The overall momentum conservation equation for a fluid is: ; in, G is the bottom hole pressure, in MPa; G is the acceleration due to gravity, in m / s². 2 .

[0013] Specifically, step S6, flow pattern analysis, includes: The discriminant for bubbly flow is: ; in, and , ; The slug flow discrimination relation is: ; Among them, if ,but ;like ,but ; The discriminant for turbulent flow is: ; Among them, if ,but ;like ,but ; The discriminant relationship for annular fog flow is: ; in, This is the gas phase reduced velocity, in m / s; The velocity is the liquid phase conversion velocity, in m / s; Let be the rising velocity of a single bubble in an infinitely large medium; , Here are the densities of the gas and liquid phases, respectively, in kg / m³. 3 ; This is the acceleration due to gravity, measured in m / s². 2 ; The surface tension between the gas and liquid phases is expressed in N / m. This represents the limiting upward velocity of the bubble, expressed in m / s. The diameter is the borehole diameter, in meters (m).

[0014] Specifically, the pressure drop calculation under different flow regimes is as follows: For bubbly flow, the total pressure drop gradient includes the gravitational pressure drop gradient, the frictional pressure drop gradient, and the acceleration pressure drop gradient, expressed as: ; This is the gravity pressure gradient. ; For frictional pressure drop gradient, Indicates the Fanning friction coefficient; And calculate the friction coefficient of the two-phase flow as follows: ; For slug flow: The formula for calculating the liquid holdup in annular slug flow is: ; The frictional pressure drop gradient is: ; The calculation of friction coefficient is the same as that for bubbly flow; For stirred flow: The formula for calculating the liquid holdup in annular stirred flow is: ; Frictional pressure drop gradient: ; The friction coefficient is calculated in the same way as for bubbly flow.

[0015] For the annular mist flow: The formula for calculating the liquid holdup of the annular mist flow is: ; The formula for calculating frictional voltage drop is: ; ; in, This refers to the fluid density in the central region of the pipe, expressed in kg / m³. 3 ; It is the friction coefficient when gas flows along the rough surface of the liquid film.

[0016] The beneficial effects of this invention are as follows: This invention provides a method for controlling well overflow and controlling well pressure during drilling of hydrate formations and underlying shallow gas formations. When an overflow occurs, the well is first shut in to collect data and calculate basic parameters. Then, the formation pressure distribution is solved by setting boundary conditions within the partial differential equations, thereby calculating the formation gas production. At the same time, various parameters of the multiphase flow in the wellbore are calculated, including basic parameters, physical properties of natural gas and drilling fluid, bubble rise velocity, etc. Then, basic equations are established to analyze the flow pattern and iteratively calculate dynamic parameters. After that, the well control method is selected and the construction parameters are optimized according to the actual situation. Finally, experiments are designed to verify the correctness and reliability of the calculation method, thereby ensuring the safe and efficient execution of the natural gas hydrate overflow well control process.

[0017] The overflow control method proposed in this invention, used during controlled-pressure drilling of hydrate layers and underlying shallow gas layers, effectively solves the overflow control problem caused by shallow gas intrusion and hydrate decomposition during natural gas hydrate drilling. By accurately calculating formation gas production and wellbore multiphase flow parameters, it rationally selects the control method and optimizes construction parameters. The reliability of the calculation method has been verified experimentally. It innovatively couples wellbore multiphase flow with reservoir gas production. By calculating the pressure drop of each flow pattern, it can dynamically and accurately calculate the position of the heavy slurry level. By calculating the relationship between bottom hole and formation pressure over time, it visually presents the well control time, ensuring safe and efficient drilling operations, reducing drilling costs, and providing strong technical support for overflow control schemes during natural gas hydrate drilling. Furthermore, it effectively solves the deficiency of existing technologies that can only prevent overflows during drilling of hydrate layers and underlying shallow gas layers, but cannot handle overflows that have already occurred. Attached Figure Description

[0018] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on the structures shown in these drawings without creative effort.

[0019] Figure 1 This is a flowchart of the overflow control method for drilling hydrate layers and underlying shallow gas layers during controlled pressure drilling according to the present invention; Figure 2 This is a schematic diagram of the overflow control method for drilling hydrate layers and underlying shallow gas layers during controlled pressure drilling according to the present invention; Figure 3 This is a graph showing the change in bottom hole pressure over time in an embodiment of the present invention; Figure 4 This is a graph showing the change in gas production over time in an embodiment of the present invention. Figure 5This is a graph showing the density distribution as a function of well depth and well-killing time in an embodiment of the present invention; Figure 6 This is a graph showing the variation of gas content distribution with well depth and well kill time in an embodiment of the present invention; Figure 7 The curve of the return height of the heavy pulp over time in the embodiment of the present invention; Figure 8 A graph showing the change in bottom hole pressure over time in an embodiment of the present invention. Detailed Implementation

[0020] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0021] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0022] The following is in conjunction with the appendix Figures 1-8 The following describes some embodiments of the present invention in detail. Unless otherwise specified, the following embodiments and features can be combined with each other.

[0023] This invention proposes a method for controlling well overflow during pressure-controlled drilling processes involving hydrate formations and shallow gas layers. In a preferred embodiment, the method includes the following steps: 1) Well shut-in data acquisition and basic parameter calculation; 2) Construction of ocean temperature field model; 3) Solving for formation pressure distribution; 4) Gas production calculation; 5) Calculation of multiphase flow parameters in the wellbore; 6) Calculation of natural gas physical properties; 7) Calculation of drilling fluid physical properties; 8) Calculation of bubble rising speed; 9) Basic equations for dynamic two-phase flow of air and liquid in the wellbore annulus; 10) Flow pattern and flow regime analysis; 11) Calculation of pressure drop in gas-liquid two-phase flow; 12) Calculation of dynamic parameters.

[0024] In this embodiment, in step 1, after a spill, the well is quickly shut in, and key data such as shut-in casing pressure and standpipe pressure are accurately recorded. Based on this data, combined with information such as wellbore structure and formation parameters, the basic data required for well control, such as initial formation pressure, are calculated. This step provides basic data support for subsequent well control operations, ensuring the accuracy of subsequent calculations and operations.

[0025] In step 2, the process of gas invasion can be viewed as a formation segment where the wellbore temperature field model during normal circulation and the annular temperature field model during gas invasion are formed. The following model can be used to solve this: ; ; in: ; ; ; ; ; ; In the formula: The radius of the wellbore; Density of drilling fluid; This represents the volume fraction of the gas and liquid phases. The area of ​​the annular space; This refers to the gas phase volumetric flow rate; This represents the liquid phase volumetric flow rate.

[0026] Solving the formula yields the following temperature field distribution inside the wellbore during gas intrusion: ; In the formula: is the temperature at any well depth within the annulus, in °C; z is the well depth coordinate, in meters. The total well depth is in meters (m). The wellhead temperature is in °C. The bottom hole temperature is in °C. This is the normal circulating annular temperature.

[0027] This step treats the gas invasion process as a superposition of the normal circulation temperature field model and the gas invasion annular temperature field model within the formation. By defining a series of parameters (such as wellbore radius and drilling fluid density) and related equations, the formula for the temperature field distribution in the wellbore during gas invasion is obtained. This provides a key basis for in-depth analysis of the temperature change law in the wellbore during gas invasion and for assisting in the formulation of overflow control strategies.

[0028] In step 3, by setting the bottom-hole pressure as the inner boundary condition of the partial differential equation, the partial differential equation for unsteady formation seepage is numerically solved to obtain the formation pressure distribution. Taking the formation pore pressure distribution near the wellbore in non-Darcy seepage as an example, according to the radial partial differential equation for non-Darcy transient seepage: ; Initial conditions are The outer boundary conditions are The internal boundary conditions are determined based on actual conditions. Taylor series expansion is used to discretize the numerical values, and combined with the initial and boundary conditions, the finite difference method is employed to solve the pore pressure distribution equation at any location and time in the formation.

[0029] In step 4, the seepage of shallow gas and natural gas hydrate under normal conditions is non-Darcy flow. An annular micro-element is taken near the well wall, and the transient gas production under variable bottom hole pressure is calculated based on the non-Darcy flow flow calculation theory and the formation pressure distribution obtained in the previous step.

[0030] For non-Darcy flow, the formula for calculating gas production is:

[0031] In the formula: This represents the output under standard gas conditions. Pressure is supplied to the boundary of the infinitesimal element; Bottom hole flowing pressure; Formation permeability; This refers to the viscosity of the gas. The radius of the outer boundary of the gas reservoir; Where is the radius of the wellbore.

[0032] The gas production model for hydrate decomposition uses the following formula: ; In the formula: The mass of the decomposed hydrate, in kg; The value represents the molar mass of natural gas hydrate, in kg / mol. Let be the rate constant for hydrate decomposition, mol / (m 2 ·Pa·s); m is the surface area of ​​the hydrate in the decomposition zone. 2 ; The equilibrium pressure of the hydrate phase is Pa; The pressure in the gas phase of the decomposition zone is Pa.

[0033] The hydrate decomposition rate constant is determined by the following formula: ; In the formula: For frequency factor, mol / (m 2 ·Pa·s); The activation energy for decomposition is kJ / mol. It is the ideal gas constant; The decomposition temperature is K.

[0034] This step accurately calculates the formation gas production, providing crucial information for optimizing subsequent well control parameters.

[0035] In step 5, the basic parameters of the gas-liquid two-phase flow are calculated, such as apparent velocity, volume fraction, mass fraction, porosity, and liquid holdup.

[0036] The apparent velocity of multiphase flow refers to the velocity assuming that the gas or liquid phase completely occupies the cross-sectional area of ​​the flow channel.

[0037] The apparent velocity of the gas phase is equal to the ratio of the mass of gas flowing per unit cross-section of the channel to its density:

[0038] In the formula: The apparent velocity of the gas phase is m / s; The gas phase mass flow rate is kg / m³. 2 s; The density is in the gas phase, kg / m³ 2 .

[0039] The apparent velocity of the liquid phase is equal to the ratio of the mass of liquid flowing per unit cross-section of the flow channel to the density of the liquid: ; In the formula: The apparent velocity of the liquid phase is m / s; The liquid phase mass flow rate is kg / m³. 2 s; The density of the liquid phase is kg / m³. 2 .

[0040] In a wellbore gas-liquid two-phase flow, the same flow channel cross-section simultaneously accommodates gas and liquid fluids. The cross-sectional area occupied by each phase fluid must be smaller than the total cross-sectional area. Therefore, the actual velocities of the gas and liquid phases must be greater than their apparent velocities.

[0041] In a two-phase flow, the volume fraction of the liquid phase is equal to the ratio of the volumetric flow rate of the liquid phase at the same cross-section of the flow channel to the total volumetric flow rate of the gas and liquid phases.

[0042] .

[0043] Similarly, the volume fraction of the gas phase is equal to the ratio of the volumetric flow rate of the gas phase at the same cross-section of the flow channel to the total volumetric flow rate of the gas and liquid phases. .

[0044] mass fraction of gas phase It is equal to the ratio of the mass flow rate of the gas phase to the total mass flow rate of the gas-liquid mixture at the same cross-section of the flow channel. .

[0045] Similarly, the mass fraction of the liquid phase can be determined. It is equal to the ratio of the mass flow rate of the liquid phase to the total mass flow rate of the gas-liquid mixture at the same cross-section of the flow channel. .

[0046] The sum of the mass fractions of the gas and liquid phases equals 1: .

[0047] In controlled pressure drilling and well control, the gas-liquid two-phase porosity is one of the important parameters.

[0048] The porosity (true volume fraction of the gas phase) of a gas-liquid two-phase flow refers to the ratio of the cross-sectional area occupied by the gas phase to the total cross-sectional area. ; In the formula This is the true volume fraction of the gas phase, dimensionless; The cross-sectional area occupied by the gas phase, m 2 ; The total cross-sectional area is m. 2 .

[0049] Therefore, the actual velocity of the gas phase is... ; In the formula: The velocity is the gas phase velocity, in m / s; For gas flow rate, m 2 / s; The cross-sectional area occupied by the gas phase, m 2 ; Here is the gas viscosity, in mPa. ; This represents the true volume fraction of the gas phase, which is dimensionless.

[0050] Similarly, in a gas-liquid two-phase flow, the true volume fraction of the liquid phase... It is defined as: ; In the formula: This represents the true volume fraction of the liquid phase, which is dimensionless. The cross-sectional area occupied by the liquid phase, m 2 ; This represents the true volume fraction of the gas phase, which is dimensionless.

[0051] The actual velocity of the liquid phase: ; In the formula: The velocity is the liquid phase velocity, in m / s; For liquid flow rate, m2 / s; The cross-sectional area occupied by the liquid phase, m 2 ; The actual velocity of the liquid is in m / s; This represents the true volume fraction of the liquid phase, which is dimensionless.

[0052] The velocity of a gas-liquid two-phase mixture: ; In the formula: The velocity of the gas-liquid two-phase mixture is in m / s; The actual velocity in the gas phase is given in m / s. The velocity is the actual velocity in the liquid phase, in m / s.

[0053] Liquid holdup, also known as true liquid content or cross-sectional liquid content, refers to the cross-sectional area of ​​the liquid phase during gas-liquid two-phase flow. Total flow area The ratio, that is: ; In the formula: This is the liquid holdup, dimensionless; The cross-sectional area of ​​the liquid phase is m. 2 ; The cross-sectional area of ​​the gas phase is m. 2 .

[0054] From the above formula, we can see that: ; In the formula: This is the gas content, dimensionless; This represents liquid holdup, which is dimensionless.

[0055] Due to the density difference between the gas and liquid phases, the gas with lower density moves at a faster speed than the gas with higher density. This speed difference caused by the density difference between the two phases is called the slip velocity. ; In the formula: The slip velocity is in m / s; The velocity of the gas phase is m / s; The velocity of the liquid phase is in m / s; The actual velocity of the gas phase is in m / s; The actual velocity of the liquid phase is in m / s; This represents liquid holdup, which is dimensionless.

[0056] In step 6, the viscosity and density of natural gas, as well as the viscosity and density of drilling fluid, are calculated according to different pressure conditions. For the viscosity calculation of low-pressure natural gas mixtures, the Chung method is used, with the viscosity formulas for each component of natural gas as follows: ; In the formula: Natural gas components viscosity, Pa s; A, B, and C are empirical formula parameters for calculating the viscosity of each component of natural gas.

[0057] Viscosity calculation formula for low-pressure natural gas mixtures: For high-pressure natural gas mixtures, the Lu-Cas method is used for viscosity calculation. The formula is more complex, involving the calculation of multiple coefficients and parameters. The general formula for calculating natural gas density is: ; In the formula: The viscosity of a low-pressure natural gas mixture, Pa s; Natural gas components The molar amount, kg / mol.

[0058] Table 1. Empirical formula parameters for the viscosity of each component of natural gas.

[0059] The empirical formula parameters for the viscosity of each component of natural gas are shown in Table 1. There are many methods for calculating the viscosity of high-pressure natural gas mixtures, among which the Lu-Cas method, Chung method, and residual viscosity method are widely used. After comparing the above three methods experimentally, this scheme concludes that the Lu-Cas method has the smallest error in calculating the viscosity of high-pressure natural gas mixtures.

[0060] Formula for calculating the viscosity of high-pressure natural gas mixtures using the Lu-Cas method: ; ; ; ; ; ; ; ; In the formula: The viscosity of the high-pressure natural gas mixture is expressed in Pa. s; a, b, c, d, and e are coefficients used in the formula for calculating the viscosity of natural gas.

[0061] General formula for calculating natural gas density: ; ; ; In the formula: The absolute pressure of the natural gas system is expressed in MPa. The molar volume of natural gas. ; is the compressibility coefficient of natural gas, dimensionless; The absolute temperature of the natural gas system. ; For gaseous constants, ; The molar mass of natural gas, ; For the density of natural gas, .

[0062] In step 7, drilling fluid physical properties are calculated, and an exponential model is used to describe the effects of drilling fluid on temperature and pressure: ; In the formula: is the viscosity of drilling fluid as a function of temperature and pressure, mPa·s; P is pressure, MPa; T is temperature, °C; denoted as Drilling fluid viscosity under normal temperature and pressure conditions, in mPa·s; A is the temperature coefficient, dimensionless; B is the pressure coefficient, dimensionless.

[0063] By treating drilling fluid density as a function of temperature and pressure, a density prediction formula is derived experimentally: ; In the formula: Density at room temperature and pressure, kg / m³ 3 ; , , are the density fitting coefficients for oil-based and water-based drilling fluids, respectively.

[0064] In step 8, the bubble rising speed is calculated using the following formula: ; In the formula: The density of the liquid is kg / m³. 3 ; The density of the gas is kg / m³. 3 ; Pa is the viscosity of the liquid. s; Pa is the viscosity of the gas. s; Let be the diameter of the bubble, in meters (m). ρ represents surface tension, in N / m.

[0065] In step 9, the mass conservation equation for the liquid is: ; The mass conservation equation for a gas is: ; In the formula: The velocity of the liquid is in m / s; The velocity of the gas is in m / s; The density of the liquid is expressed in g / cm³. 3 ; The density of the gas is in g / cm³. 3 ; This is the liquid volume coefficient, which is dimensionless; This is the gas volume coefficient, which is dimensionless. The value represents the formation gas production, in L / s.

[0066] The overall momentum conservation equation for a fluid is: ; In the formula: The pressure at the bottom of the well is MPa; g is the acceleration due to gravity, m / s². 2 .

[0067] In step 10, the flow patterns of the gas-liquid two-phase flow in the wellbore can be divided into four types: bubbly flow, slug flow, agitated flow, and annular mist flow. The limiting relationships between the four flow patterns are as follows: 1) Bubble flow The discriminant for bubbly flow is: and ;in, Determined by the following formula: ; According to Nicklin's formula, we have: .

[0068] 2) Slug Flow The discriminant relation for slug flow: and (if )or (if ).

[0069] 3) Agitated flow The discriminant for turbulent flow: and (if )or (if ).

[0070] 4) Circulating mist flow The discriminant relation for annular fog flow: ; In the formula: The velocity is the gas phase reduced velocity, in m / s; The velocity is the liquid phase reduced velocity, in m / s; Let be the rising velocity of a single bubble in an infinitely large medium; , Let be the densities of the gas phase and liquid phase, respectively, in kg / m³. 3 ; The acceleration due to gravity, in m / s² 2 ; The surface tension between the gas and liquid phases is N / m; Let be the limiting upward velocity of the bubble, in m / s; The diameter of the wellbore is in meters (m).

[0071] In step 11, after the flow pattern is identified, it is necessary to study the flow patterns under various flow patterns, propose individual models to predict the flow characteristics under various flow patterns, and finally calculate the pressure gradient under each flow pattern.

[0072] (1) Bubble flow In bubbly flow, due to the significant relative velocity between the gas and liquid phases, the effect of the phase slippage velocity between the two phases on the bubbly flow is considered based on the drift flow method. The phase slippage in bubbly flow is defined by the following formula: ; In the above formula The rising velocity of a single bubble in an infinitely large medium should be corrected for the rising velocity of a single bubble in a bubble swarm: ; Summarized as follows: .

[0073] For toroidal spaces: .

[0074] After knowing the velocities of each phase at the previous node, the gas-liquid ratio can be calculated using the above formula. With the obtained gas-liquid ratio, the viscosity, density, and other multiphase fluid parameters of the mixture can be obtained according to the formula. The total pressure drop gradient can then be calculated. For steady-state flow, the total pressure drop gradient includes three parts: gravity pressure drop gradient, friction pressure drop gradient, and acceleration pressure drop gradient.

[0075] ; Gravitational pressure gradient: ;in, ; Frictional pressure drop gradient: ;in, is the Fanning friction coefficient.

[0076] The friction coefficient of a two-phase flow can be determined by the following formula: .

[0077] (2) Slug flow: The formula for calculating the liquid holdup in annular slug flow is: ; Frictional pressure drop gradient: ; The friction coefficient is calculated in the same way as in bubbly flow.

[0078] (3) Stirred flow The formula for calculating the liquid holdup in annular stirred flow is: ; Frictional pressure drop gradient: ; The friction coefficient is calculated in the same way as in bubbly flow.

[0079] (4) Circulating mist flow ; The formula for calculating frictional voltage drop is: ; ; In the formula: This refers to the fluid density in the central region of the pipe, expressed in kg / m³. 3 ; is the friction coefficient when gas flows along the rough surface of the liquid film, and it is dimensionless.

[0080] definition EF This represents the percentage of the total liquid volume carried into the gas core. When the liquid phase Reynolds number is greater than 3000, EF is... The function is defined as follows: ; ; if : .

[0081] if : .

[0082] Therefore, we can conclude that: .

[0083] The coefficient of friction is given by the formula proposed by Wallis, as follows: ; Gas phase Reynolds number It can be expressed by the following formula: ; It can be calculated based on the Lockhart-Martinelli transformation rules, that is: ; Where: X-Lockhart-Martinelli parameter, dimensionless; ; In the formula: The hydraulic diameter is in meters (m). The interfacial tension is expressed in N / m. The viscosity is the liquid phase viscosity, in mPa•s; The velocity of the mixture is in m / s; Let m be the pipe wall roughness.

[0084] In step 12, a dual-grid division is performed on time and wellbore. Dynamic flow parameters of the wellbore, such as bottomhole pressure, formation gas production, heavy slurry rise height, wellbore density distribution, and wellbore gas cut distribution, are obtained through iterative calculation. First, an initial gas cut is calculated based on parameters such as initial drilling gas injection rate, initial formation gas production, initial bottomhole pressure, and pump discharge rate. Then, the height of the light and heavy slurry interface formed in the first second is calculated based on the initial gas cut. Next, the bottomhole pressure is calculated based on the height of the light and heavy slurry interface, and the corresponding gas production is obtained. The gas cut of each step length in the wellbore is calculated using different flow patterns. Through iterative calculation and averaging, the average gas cut value is obtained, and then the heavy slurry rise height is calculated. This step comprehensively calculates the dynamic flow parameters of the wellbore, reflecting the dynamic flow of the gas and liquid phases in the wellbore during well control, providing data support for optimizing well control construction parameters. The heavy slurry interface height is calculated using the following formula: ; Based on the above theory, by coupling different gas production rates in the formation and using MathCAD computer programming, the changes in important gas-liquid two-phase flow parameters in the wellbore under controlled pressure drilling conditions were obtained.

[0085] The following provides a specific embodiment to illustrate this solution in detail.

[0086] When encountering a high-pressure gas layer requiring well control, the well is first quickly shut in to collect key data. Basic parameters are then calculated by combining wellbore structure, formation, and drilling fluid performance data. Next, the bottom hole pressure is set as the boundary condition within a partial differential equation to solve for the formation pressure distribution, thereby calculating the formation gas production. Following this, the basic parameters of the multiphase flow in the wellbore, the physical properties of natural gas and drilling fluid, and the bubble rise velocity are calculated. Then, fundamental equations such as mass and momentum conservation are established to analyze the flow pattern, and dynamic parameters such as bottom hole pressure and gas production are iteratively calculated using a dual-grid system of time and wellbore. Finally, the positive circulation well control method is selected, and after optimizing parameters such as mud density, pump flow rate, and wellhead back pressure, suitable construction parameters are determined to provide guidance for on-site well control operations.

[0087] The controlled pressure drilling method for controlling well overflow during drilling of hydrate formations and underlying shallow gas formations includes the following steps: Step 1: Well shut-in data acquisition and basic parameter calculation In controlled pressure drilling operations, when an ST well encounters a high-pressure gas layer and the requirements for tripping in / out without well control are not met, well control operations are necessary. At this time, the well is quickly shut in, and key data such as shut-in casing pressure and standpipe pressure are accurately recorded. Combining the ST well's wellbore structure data, formation parameters, and drilling fluid performance data, the basic data required for well control are calculated. For example, using relevant pressure calculation formulas, combined with shut-in data and wellbore structure, parameters such as initial formation pressure can be calculated, providing a basis for subsequent well control operations. The target layer is drilled using a 165.1mm drill bit, and the drill string assembly is: 165.1mm drill bit + check valve + 24 120.6mm drill collars + bypass valve + 101.6mm G105 drill pipe + 114.3mm G105 drill pipe; (The text abruptly ends here, likely due to an incomplete sentence or missing information.) Figure 1 , 2 As shown.

[0088] Controlled pressure drilling parameters: Gas injection rate is 20 m³ / s. 3 / min, drilling mud density is 1.52g / cm³ 3 Pump displacement 15 L / s, formation pressure coefficient 1.6 g / cm³ 3 .

[0089] Well control parameters: wellhead back pressure 10 MPa, pump flow rate 40 L / s, well control mud density 2.16 g / cm³. 3 Formation pressure coefficient 2.2 g / cm 3 .

[0090] Step 2: Construction of Ocean Temperature Field Model In controlled pressure drilling operations, when encountering hydrate layers and underlying shallow gas layers, gas invasion necessitates well control, a marine temperature field model needs to be constructed to analyze the impact of wellbore temperature changes on the well control process. The specific implementation is as follows: The gas intrusion process is considered as a superposition of the temperature field model during normal circulation within the wellbore and the annular temperature field model during gas intrusion within the formation section. The temperature field distribution within the wellbore during gas intrusion is solved by the following simultaneous equations: ; ; in: , , , , , ; In the formula: The radius of the wellbore; Density of drilling fluid; This represents the volume fraction of the gas and liquid phases. The area of ​​the annular space; This refers to the gas phase volumetric flow rate; This represents the liquid phase volumetric flow rate.

[0091] Solving the formula yields the following temperature field distribution inside the wellbore during gas intrusion: ; In the formula: is the temperature at any well depth within the annulus, in °C; z is the well depth coordinate, in meters. The total well depth is in meters (m). The wellhead temperature is in °C. The bottom hole temperature is in °C. This is the normal circulating annular temperature.

[0092] The wellbore radius, drilling fluid density, and annular area are determined based on the drill bit size. Furthermore, the gas phase volumetric flow rate is dynamically adjusted according to the formation gas production during well control, while the liquid phase volumetric flow rate is determined based on specific construction parameters. The annular temperature at different well depths z and times t is calculated using a model. The influence of the temperature field on drilling fluid viscosity and natural gas physical properties was analyzed, and the parameter calculation results in steps 5 and 6 were corrected. Based on the temperature field distribution, the well control mud injection strategy was optimized, and the mud density or pump discharge rate was appropriately adjusted in high-temperature well sections to avoid instability in the flow pattern caused by temperature changes.

[0093] Step 3: Solving for formation pressure distribution

[0094] Using bottom hole pressure as the internal boundary condition of the partial differential equation, the partial differential equation for unsteady formation seepage is numerically solved. For the formation pore pressure distribution near the wellbore in Darcy flow, based on the radial partial differential equation for transient seepage: initial conditions... P0 represents the known original formation pressure value, and the outer boundary conditions are... Internal boundary conditions were set. The Taylor series expansion was used to discretize the numerical values. Combining the initial and boundary conditions, the finite difference method was used to solve the pore pressure distribution equation at any location and time in the formation. A similar method can be used to solve the pore pressure distribution near the wellbore in high-velocity non-Darcy flow. These calculations provide information on the variation of formation pressure with time and space, providing a basis for subsequent gas production calculations.

[0095] From the appendix Figure 3 It can be seen that the bottom pressure during normal controlled drilling gradually increases with the well control time, and at the 83-minute mark, the bottom pressure equals the formation pressure.

[0096] Step 4: Gas Production Calculation An annular micro-element is taken near the wellbore. Based on the calculation theories of non-Darcy flow and Darcy flow flow rate, as well as the formation pressure distribution obtained in the previous step, the transient gas production under varying bottom hole pressure conditions is calculated.

[0097] For non-Darcy flow: ; For Darcy flow: ; The values ​​of each parameter in the formula are: formation permeability K =2 mD gas viscosity μ g Based on natural gas physical properties calculations h (Thickness of the producing layer) Pe Pressure is supplied to the boundary of the micro-element (calculated based on the formation pressure distribution). P wf This refers to the bottom hole flowing pressure (which varies with the well control process). r e The radius of the outer boundary of the gas reservoir. r w Where is the wellbore radius. D The non-Darcy permeability coefficient.

[0098] Considering the gas production from hydrate decomposition, the following formula is used: , .

[0099] Molar mass of natural gas hydrate M H Decomposition rate constant K d Through frequency factor K 0. Decomposition activation energy ΔE Ideal gas constant R and decomposition temperature T The surface area of ​​the hydrate in the decomposition zone was calculated. A Based on the hydrate layer thickness and wellbore radius, the equilibrium pressure of the hydrate phase is estimated. Peq Gas phase pressure in the decomposition zone P g Based on the formation pressure distribution, the gas production from hydrate decomposition was calculated. This gas production was then added to the gas production from shallow gas-bearing layers to obtain the total formation gas production, providing crucial data for optimizing subsequent well control parameters.

[0100] Controlled pressure drilling parameters: Gas injection rate is 20m³. 3 / min, drilling mud density is 1.52g / cm³ 3 Pump displacement 15 L / s, formation pressure coefficient 1.6 g / cm³ 3 .

[0101] Well control parameters: wellhead back pressure 10 MPa, pump flow rate 40 L / s, well control mud density 2.16 g / cm³. 3 Formation pressure coefficient 2.2 g / cm³ 3 .

[0102] The calculated gas production over time, based on formation pressure distribution, is shown in the attached figure. Figure 4 As shown, the initial gas production of the formation is 7.75 × 10⁻⁶. 4 m 3 / d, as the well-killing mud is injected, the formation gas production gradually decreases, and at 83 minutes the gas production drops to 0, and the formation stops producing gas, which is consistent with the theoretical model.

[0103] Step 5: Calculation of multiphase flow parameters in the wellbore Apparent velocity calculation: The apparent velocity of the gas phase is calculated using the following formula: ; Gas mass flow rate (Based on actual calculations or measurements), gas phase density (Based on calculations of natural gas properties), the calculation yields... The same applies to the apparent velocity in the liquid phase.

[0104] Volume fraction and mass fraction calculation: Calculation of liquid phase volume fraction Liquid phase volumetric flow rate gas phase volume flow Then we get Then the gas phase volume fraction Gas phase mass fraction Gas phase mass flow rate Liquid phase mass flow rate Then we get Liquid phase mass fraction .

[0105] Porosity and liquid holdup calculation: Let the cross-sectional area occupied by the gas phase be... Given the total cross-sectional area A, we can then derive... True volume fraction of liquid phase Actual velocity in the gas phase True velocity in the liquid phase For the apparent velocity of the liquid phase, the calculation method is the same as for the apparent velocity of the gas phase. (Velocity of a gas-liquid two-phase mixture) Liquid holdup gas content slip speed .

[0106] Step 6: Calculation of natural gas physical properties The viscosity of low-pressure natural gas mixtures is calculated using the Chung method. For example, to calculate the viscosity of a certain natural gas component (CH4), given A, B, C, and temperature T, the viscosity of that component can be obtained. The formula for calculating the viscosity of low-pressure natural gas mixtures is as follows: The calculation for high-pressure natural gas is similar.

[0107] Natural gas density calculation Given the natural gas system with absolute pressure p, molar mass M, compressibility coefficient Z, absolute temperature T, and gas constant R, then substituting these values ​​into the equations allows for the calculation of... .

[0108] Step 7: Calculation of drilling fluid physical properties An exponential model is used to describe the effects of drilling fluid on temperature and pressure: The viscosity of drilling fluid at normal temperature and pressure is The temperature coefficient is A, the pressure coefficient is B, the temperature of a certain well section is T, the pressure is P, and the ambient temperature and pressure are... The pressure is Then the calculation yields .

[0109] Density prediction formula Its density at room temperature and pressure is In determining , Substituting the temperature and pressure values ​​above, we can calculate... .

[0110] The designed drilling fluid density is 1.45-1.68 g / cm³. 3 Detailed performance data is shown in Table 2 below.

[0111] Table 2 Drilling Fluid Performance Data

[0112] From the appendix Figure 5As the kill mud is injected, the heavy mud continuously displaces the light mud, and the boundary between the light and heavy mud shifts from the bottom of the well to the wellhead. The density inflection point in the figure indicates the location of this boundary. The mud density is higher below the boundary and lower above it. Furthermore, the density changes are complex near the wellhead due to the lower wellhead pressure, which causes bubble expansion, aggregation, and slippage, resulting in complex flow patterns. At different times, not only are the inflection points of the density curves different, but the curves above and below the inflection points do not completely overlap. This is a result of the continuous slippage and migration of bubbles in the annulus during kill mud injection, coupled with the continuous decrease in formation gas production.

[0113] Step 8: Calculation of bubble rising speed The formula for the bubble's rising speed is: The liquid density is The gas density is The bubble diameter is d, and the surface tension is... The drag coefficient is calculated based on relevant empirical formulas. Then, substituting into the calculation yields... The rising velocity of bubbles affects the flow pattern and various parameters of the gas-liquid two-phase flow. Accurate calculation of this velocity is helpful in analyzing the flow conditions within the wellbore.

[0114] Step 9: Basic Equations for Dynamic Flow of Air-Liquid Two-Phase in Wellbore Annulus The mass conservation equation for a liquid is: The mass conservation equation for a gas is: At a certain moment and in a certain well section, by substituting the relevant parameters into the equations for calculation and analysis, we can understand how the mass of the gas-liquid two phases changes with time and space.

[0115] Controlled pressure drilling parameters: Gas injection rate is 20m³. 3 / min, drilling mud density is 1.52g / cm³ 3 Pump displacement 15 L / s, formation pressure coefficient 1.6 g / cm³ 3 .

[0116] Well control parameters: wellhead back pressure 10 MPa, pump flow rate 40 L / s, well control mud density 2.16 g / cm³. 3 Formation pressure coefficient 2.2 g / cm³ 3 .

[0117] The gas content distribution in the wellbore annulus is shown in the attached figure. Figure 6As shown, at the 10-minute mark, the boundary between light and heavy mud shifted from the bottom of the well to a depth of 6280m. At this point, the gas content in the heavy mud column was higher, showing a clear inflection point compared to the light mud. This is because the gas in the light mud is the amount injected to control the mixing density of the drilling fluid during normal controlled pressure drilling, while the gas content in the heavy mud is the amount of natural gas produced from the formation. As kill mud was injected, the heavy mud continued to rise. At the 30-minute mark, the boundary between light and heavy mud shifted to a depth of 4613m. At this point, the bottom hole pressure increased compared to the initial value, the amount of gas produced from the formation decreased, and the gas content in the heavy mud decreased. Kill mud continued. At the 1-hour mark, the heavy mud returned to a depth of 2231m, the bottom hole pressure increased further, and the formation gas production decreased further. At the 1.5-hour mark, the heavy mud in the annulus returned to the wellhead, formation gas production ceased, and the gas content in the annulus was 0.

[0118] The overall momentum conservation equation for a fluid is: Given the values ​​of each parameter, substituting them into the equation allows for the analysis of fluid momentum changes and related forces.

[0119] Step 10: Flow Pattern and Flow Regime Analysis 1) Determining bubbly flow The discriminant for bubbly flow is: and ; in, Determined by the following formula: ; According to Nicklin's formula, we have: .

[0120] 2) Criterion for slug flow: and (if )or (if ).

[0121] 3) Criterion for turbulent flow: and (if )or (if ).

[0122] 4) Criterion for the determination of annular fog flow: ; In the formula: The velocity is the gas phase reduced velocity, in m / s; The velocity is the liquid phase reduced velocity, in m / s; Let be the rising velocity of a single bubble in an infinitely large medium; , Let be the densities of the gas phase and liquid phase, respectively, in kg / m³. 3 ; The acceleration due to gravity is m / s². 2 ; The surface tension between the gas and liquid phases is N / m; Let be the limiting upward velocity of the bubble, in m / s; The diameter of the wellbore is in meters (m).

[0123] Analyzing flow patterns and flow regimes helps to understand the changes in gas-liquid two-phase flow within the wellbore, providing guidance for controlling the well control process.

[0124] Controlled pressure drilling parameters: Gas injection rate is 20m³. 3 / min, drilling mud density is 1.52g / cm³ 3 Pump displacement 15 L / s, formation pressure coefficient 1.6 g / cm³ 3 .

[0125] Well control parameters: wellhead back pressure 10 MPa, pump flow rate 40 L / s, well control mud density 2.16 g / cm³. 3 Formation pressure coefficient 2.2 g / cm³ 3 .

[0126] As attached Figure 7 As shown, before the 73rd minute, the annulus was filled with bubbly flow. After the 73rd minute, pure liquid flow appeared at the bottom of the well. At this time, the formation stopped producing gas, but there was still some gas in the annulus. There was also bubbly flow near the wellhead, but the length of the bubbly flow decreased as the heavy slurry rose. After the 84th minute, it was all pure liquid flow. At this time, the heavy slurry had completely displaced the light slurry from the annulus, and the heavy slurry filled the entire well.

[0127] Step 11: Calculation of pressure drop in two-phase flow During controlled pressure well control, the gas-liquid two-phase flow pattern within the wellbore dynamically changes with time and well depth. The pressure drop gradient needs to be calculated separately for different flow patterns (bubble flow, slug flow, agitated flow, and annular mist flow) to provide a basis for bottomhole pressure control. Taking the control parameters of well ST in Example 1 as an example (control mud density 2.16 g / cm³, pump flow rate 40 L / s, wellhead back pressure 10 MPa), the specific calculation process is as follows: 1) Calculation of pressure drop in bubbly flow: Gravitational pressure gradient: When the flow pattern inside the wellbore is bubbly (such as in the early stages of well control when the heavy slurry does not completely cover the wellbore), the pressure drop gradient consists of gravity, friction, and acceleration pressure drop. ; Among them, the mixing density liquid holdup It is determined by the flow pattern discrimination formula.

[0128] For example, at the 10th minute of well control, the gas cut at a depth of 6280m is approximately 0.03. Liquid phase density gas phase density but: .

[0129] Gravitational pressure gradient: ; Frictional pressure drop gradient: ; Among them, Fanning friction coefficient The Reynolds number Re and the pipe wall roughness Sure: ; Mixed flow rate Liquid phase reduced velocity Gas phase conversion velocity .

[0130] For example, the inner diameter of the annulus Circular area Liquid phase flow rate but

[0131] Gas phase flow rate ,but Mixing flow rate Drilling fluid viscosity Reynolds number: Coefficient of friction: Frictional pressure drop gradient: Acceleration pressure drop gradient: Since the flow velocity change is small in the initial stage of well control, the acceleration pressure drop can be ignored.

[0132] Total pressure drop gradient .

[0133] 2) Slug flow pressure drop calculation When the flow pattern changes to slug flow (such as when heavy slurry returns to a depth of 4613m, see appendix) Figure 7 The formula for calculating liquid holdup is simplified to: ; Example calculation: At the 30th minute of well control, , (After the gas production decreases), then: ; The calculation of the frictional pressure drop gradient is the same as for bubbly flow, but the mixing density needs to be updated to: ; Frictional pressure drop gradient: ; Gravitational pressure gradient: ; Total pressure drop gradient: .

[0134] 3) Formula for pressure drop in annular mist flow When the heavy slurry approaches the wellhead (e.g., 80 minutes after well control), the flow pattern may change to annular mist. At this time, the liquid holdup Hl = 1, and the frictional pressure drop formula simplifies to: ; Among them, the fluid density in the center of the pipe coefficient of friction Determined by the Reynolds number: ; Example calculation: , , ; so: ; Frictional pressure drop gradient: ; Gravitational pressure gradient: ; Total pressure drop gradient: .

[0135] Combined with appendix Figure 8 Data on the height of the medium-heavy slurry return shows that at the 83rd minute of well control, the heavy slurry covers the entire wellbore. At this point, the flow pattern inside the wellbore changes to pure liquid flow, and the pressure drop gradient is determined only by gravity and friction.

[0136] Step 12: Calculation of dynamic parameters A dual grid is used for both time and wellbore, and dynamic flow parameters of the wellbore are obtained through iterative steps. Time grid division: Based on known wellbore structural parameters, drill string assembly parameters, and mud pump displacement parameters, the time required for heavy mud to completely displace light mud from the wellbore and for heavy mud to occupy the entire wellbore is calculated. A time step is set, with the starting time value being the beginning of heavy mud entering the bottom of the well and timing starting there. The time ends when the heavy mud displaces the light mud and reaches the wellhead, and the termination value is obtained.

[0137] Wellbore mesh generation: For each time node, the wellbore is divided from the wellhead according to the set step length until the bottom of the well. Based on the wellbore mesh generation, the changes in the wellbore flow cross section caused by the well structure and drill string assembly can be obtained.

[0138] An initial gas cut is obtained by considering parameters such as initial drilling gas injection rate, initial formation gas production, initial bottom hole pressure, and pump discharge rate. After determining the initial drilling gas injection rate, initial formation gas production, initial bottom hole pressure, and pump discharge rate, the initial gas cut is calculated using relevant formulas. Then, the height of the light and heavy slurry interface formed in the first second is calculated based on the initial gas cut using the following formula: , converted .

[0139] The volume of injected heavy slurry is The outer radius of a certain well section is Inner radius is The initial liquid phase volume fraction was... Then the calculation yields Next, the bottom hole pressure is calculated based on the height of the light and heavy slurry boundary, and the corresponding gas production is obtained. The gas cutoff for each step length in the wellbore is calculated using different flow patterns. Through iterative calculations and averaging, the average gas cutoff value is obtained, and then the heavy slurry rise height is calculated. These calculations reveal the dynamic changes of bottom hole pressure, formation gas production, heavy slurry rise height, wellbore density distribution, and wellbore gas cutoff distribution over time and well depth, providing data support for optimizing well control parameters.

[0140] Controlled pressure drilling parameters: Gas injection rate is 20m³. 3 / min, drilling mud density is 1.52g / cm³ 3 Pump displacement 15 L / s, formation pressure coefficient 1.6 g / cm³ 3 .

[0141] Well control parameters: wellhead back pressure 10 MPa, pump flow rate 40 L / s, well control mud density 2.16 g / cm³. 3 Formation pressure coefficient 2.2 g / cm³ 3 .

[0142] From the appendix Figure 8 It can be seen that the height of the heavy mud rises gradually as the well control mud is injected. At 87 minutes, the heavy mud returns to the wellhead and fills the entire wellbore. The bottom hole pressure equals the formation pressure, the formation gas production will be 0, and the well control is successful.

[0143] After completing the above calculations and analyses, a suitable well control method (such as the positive circulation well control method) is selected based on the actual conditions of the ST well, and the construction parameters (such as mud density, pump flow rate, and wellhead back pressure) are optimized. For example, through calculation and analysis of different combinations of mud density, pump flow rate, and wellhead back pressure, it is concluded that under the well conditions, when the pump flow rate, wellhead back pressure, and mud density are known, the bottom hole pressure can be made equal to the formation pressure for a certain period of time, the formation gas production drops to 0, the heavy mud fills the entire wellbore, and the well control is successful. This parameter combination is determined based on the previously calculated dynamic parameter changes, comprehensively considering factors such as bottom hole pressure control, formation gas production changes, and heavy mud return height, providing scientific and reasonable guidance for on-site well control operations.

[0144] For the foregoing embodiments, in order to simplify the description, they are all described as a series of actions. However, those skilled in the art should understand that this application is not limited to the described order of actions, because according to this application, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions involved are not necessarily essential to this application.

[0145] The above embodiments describe the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely illustrative of the principles of the invention. Modifications and variations made by those skilled in the art without departing from the spirit and scope of the invention should be within the protection scope of the appended claims.

Claims

1. A method for controlling well overflow and killing during pressure-controlled drilling processes involving hydrated layers and shallow gas formations, characterized in that, Includes the following steps: Step S1: After the overflow occurs, quickly shut in the well, collect the shut-in casing pressure and standpipe pressure data, and calculate the initial formation pressure basic parameters in combination with the well structure and formation parameters; Step S2: By defining the wellbore radius and drilling fluid density parameters and related equations, the formula for the temperature field distribution inside the wellbore during gas invasion is obtained, and a marine temperature field model is constructed. Step S3: Using the bottom hole pressure as the inner boundary condition, and combining Darcy flow, non-Darcy flow theory and hydrate decomposition gas production model, obtain the formation pressure distribution; Step S4: Based on the formation pressure distribution and pressure conditions, calculate the total formation gas production, wellbore multiphase flow parameters, natural gas physical property parameters, and drilling fluid physical property parameters respectively; Step S5: Calculate the bubble rising velocity based on the gas-liquid density, gas density, and bubble diameter parameters, and establish the basic equation for the dynamic two-phase flow of air and liquid in the wellbore annulus based on the calculated parameters; Step S6: Flow pattern analysis, determine the transition boundaries of bubbly flow, slug flow, agitated flow and annular mist flow by using critical pipe diameter and porosity parameters; calculate the pressure drop under different flow patterns by analyzing different flow patterns in the wellbore; Step S7: Grid the time and wellbore, iteratively calculate the dynamic parameters of bottom hole pressure, gas production and heavy slurry return height, optimize the well control construction parameters, and restart the construction.

2. The method for controlling well overflow and killing during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 1, characterized in that, The solution to the temperature field distribution formula in step S2 treats the gas intrusion process as a superposition of the normal circulation temperature field model and the gas intrusion annular temperature field model within the formation section. Specifically, the wellbore radius, drilling fluid density parameters, and related equations are as follows: ； ； in, , , , , , ; The radius of the wellbore. For drilling fluid density, This represents the volume fraction of the gas and liquid phases. For the annular area, This is the gas phase volumetric flow rate. This refers to the liquid phase volumetric flow rate; The solution yields the following expression for the temperature field distribution inside the wellbore during gas intrusion: ； in, Z represents the temperature at any well depth within the annulus, in °C; Z is the well depth coordinate, in meters. Total well depth, in meters (m). This refers to the wellhead temperature, expressed in °C. This refers to the bottom-hole temperature, expressed in °C. The normal circulating annular temperature is expressed in °C.

3. The method for controlling well overflow and well control during controlled pressure drilling of hydrated layers and shallow gas layers as described in claim 1, characterized in that, The acquisition of formation pressure distribution in step S3 includes: Set the initial conditions as P(t=0)=P 0 The outer boundary conditions are P(r=r e )=P 0 And set internal boundary conditions according to actual working conditions. P 0 Given the original formation pressure values, we use Taylor series expansion to discretize the values, and then use the finite difference method to solve the pore pressure distribution equation at any location and time in the formation, taking into account the initial and boundary conditions.

4. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 3, characterized in that, The total gas production in step S4 is the sum of the shallow gas seepage production and the hydrate decomposition production, wherein: For shallow gas reservoirs without Darcy flow, the formula for calculating gas production is: ； in, This represents the output under standard gas conditions. Pressure is supplied to the boundary of the infinitesimal element; Bottom hole flowing pressure; Formation permeability; This refers to the viscosity of the gas. The radius of the outer boundary of the gas reservoir; Where is the wellbore radius; The gas production from hydrate decomposition is calculated based on a hydrate decomposition gas production model, which is expressed as follows: ； in, The mass of the decomposed hydrate is expressed in kg. The molar mass of natural gas hydrate is expressed in kg / mol. The surface area of ​​the hydrate in the decomposition zone is expressed in m². 2 ; This is the equilibrium pressure of the hydrate phase, expressed in Pa. This refers to the gas phase pressure in the decomposition zone, expressed in Pa. This is the rate constant for hydrate decomposition, in units of mol / (m). 2 ·Pa·s), and: ,in, This is the frequency factor, with units of mol / (m). 2 ·Pa·s); The activation energy for decomposition is expressed in kJ / mol. It is the ideal gas constant; The decomposition temperature is expressed in Kelvin (K).

5. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 1, characterized in that, Step S4, the calculation of multiphase flow parameters in the wellbore, includes the calculation of various basic parameters of gas-liquid two-phase flow, specifically: Apparent velocity in the gas phase: ;in, This is the apparent velocity in the gas phase, expressed in m / s. This refers to the gas phase mass flow rate, expressed in kg / m³. 2 s, This refers to the gas phase density, expressed in kg / m³. 2 ; Apparent velocity of the liquid phase: ;in, The apparent velocity of the liquid phase is expressed in m / s. This refers to the liquid phase mass flow rate, expressed in kg / m³. 2 s; This refers to the liquid phase density, expressed in kg / m³. 2 ; Volume fraction of liquid phase in a two-phase flow: ; Volume fraction of gas phase: ; Mass fraction of gas phase: ; Mass fraction of liquid phase: ; Porosity of gas-liquid two-phase flow: ;in, This represents the true volume fraction of the gas phase. The cross-sectional area occupied by the gas phase, in meters. 2 ; Total cross-sectional area, in meters. 2 ; The actual velocity of the gas phase is: ;in, Gas phase velocity, in m / s; Gas flow rate, unit: m³ / s 2 / s; The cross-sectional area occupied by the gas phase is expressed in meters. 2 ; The unit for gas viscosity is mPa. ; This represents the true volume fraction of the gas phase. True volume fraction of liquid phase : ;in, This represents the true volume fraction of the liquid phase. The cross-sectional area occupied by the liquid phase, in meters. 2 ; This represents the true volume fraction of the gas phase. The actual velocity of the liquid phase: ;in, This refers to the liquid phase velocity, measured in m / s. Liquid flow rate, unit: m³ 2 / s; The unit for the cross-sectional area occupied by the liquid phase is m. 2 ; This represents the actual velocity of the liquid, in m / s. This represents the true volume fraction of the liquid phase. The velocity of a gas-liquid two-phase mixture: ;in, The velocity of the gas-liquid two-phase mixture is expressed in m / s. The actual velocity in the gas phase is expressed in m / s. The actual velocity of the liquid phase is expressed in m / s. Liquid holdup; ;in, Liquid holdup; The cross-sectional area of ​​the liquid phase is expressed in m². 2 ; The cross-sectional area of ​​the gas phase is expressed in m². 2 ; Gas content: ; Slip speed: ;in, This is the slip velocity, expressed in m / s; The velocity of the gas phase is expressed in m / s. The velocity of the liquid phase is expressed in m / s. This represents the actual velocity of the gas phase, in m / s. This represents the actual velocity of the liquid phase, in m / s. This refers to the liquid holdup.

6. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 5, characterized in that, The calculation of the natural gas physical properties parameters is based on different pressure conditions, including the viscosity and density of natural gas and drilling fluid, specifically including: For low-pressure natural gas mixtures, the viscosity of each component of the natural gas is expressed as: ,in, Natural gas components Viscosity, in Pa s; A, B, and C are empirical formula parameters for calculating the viscosity of each component of natural gas; For high-pressure natural gas mixtures, the viscosity of each component of the natural gas is expressed as: ； in: ； ； ； ； ； ； ； in, The viscosity of a high-pressure natural gas mixture is expressed in Pa. s; a, b, c, d, and e are the coefficients in the formula for calculating the viscosity of natural gas. The calculation of drilling fluid physical properties in step S4 uses an exponential model to describe the influence of drilling fluid on temperature and pressure, expressed as: ； in, The value of drilling fluid viscosity is a function of temperature and pressure, expressed in mPa·s; P is pressure, expressed in MPa; and T is temperature, expressed in °C. V represents the drilling fluid viscosity under normal temperature and pressure conditions, in mPa·s; A is the temperature coefficient; B is the pressure coefficient. By treating drilling fluid density as a function of temperature and pressure, the density prediction formula is obtained as follows: ； in, Density at room temperature and pressure, unit: kg / m³ 3 ; , , These are the density fitting coefficients for oil-based and water-based drilling fluids, respectively.

7. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 1, characterized in that, The formula for calculating the bubble rising speed in step S5 is: ； in, This refers to the density of the liquid, expressed in kg / m³. 3 ; This refers to the density of a gas, expressed in kg / m³. 3 ; The viscosity of a liquid is expressed in Pa. s; The viscosity of the gas is expressed in Pa. s; is the diameter of the bubble, in meters; is the surface tension, in N / m.

8. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 7, characterized in that, The establishment of the basic equations for the dynamic flow of the gas-liquid two-phase gas in the wellbore annulus in step S5 is based on the mass conservation equations and momentum conservation equations for liquids and gases, and analyzes the flow law of the gas-liquid two-phase gas; the specific formula is expressed as follows: The mass conservation equation for a liquid is: ; The mass conservation equation for a gas is: ; in, The velocity of the liquid, measured in m / s; The velocity of the gas is expressed in m / s. This refers to the density of the liquid, expressed in g / cm³. 3 ; This refers to the density of a gas, expressed in g / cm³. 3 ; The volume coefficient of the liquid; This is the gas volume coefficient; Formation gas production, expressed in L / s; The overall momentum conservation equation for a fluid is: ； in, G is the bottom hole pressure, in MPa; G is the acceleration due to gravity, in m / s². 2 .

9. The method for controlling well overflow and killing during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 1, characterized in that, The flow pattern analysis in step S6 includes: The discriminant for bubbly flow is: ; in, and , ; The slug flow discrimination relation is: ; Among them, if ,but ;like ,but ; The discriminant for turbulent flow is: ; Among them, if ,but ;like ,but ; The discriminant relationship for annular fog flow is: ; in, This is the gas phase reduced velocity, in m / s; The velocity is the liquid phase conversion velocity, in m / s; Let be the rising velocity of a single bubble in an infinitely large medium; , Here are the densities of the gas and liquid phases, respectively, in kg / m³. 3 ; This is the acceleration due to gravity, measured in m / s². 2 ; The surface tension between the gas and liquid phases is expressed in N / m. This represents the limiting upward velocity of the bubble, expressed in m / s. The diameter is the borehole diameter, in meters (m).

10. The method for controlling well overflow and well control during pressure-controlled drilling of hydrated layers and shallow gas layers as described in claim 9, characterized in that, The pressure drop calculation under different flow conditions is specifically as follows: For bubbly flow, the total pressure drop gradient includes the gravitational pressure drop gradient, the frictional pressure drop gradient, and the acceleration pressure drop gradient, expressed as: ； This is the gravity pressure gradient. ; For frictional pressure drop gradient, Indicates the Fanning friction coefficient; And calculate the friction coefficient of the two-phase flow as follows: ； For slug flow: The formula for calculating the liquid holdup in annular slug flow is: ; The frictional pressure drop gradient is: ; The calculation of friction coefficient is the same as that for bubbly flow; For stirred flow: The formula for calculating the liquid holdup in annular stirred flow is: ; Frictional pressure drop gradient: ; The calculation of friction coefficient is the same as that for bubbly flow; For the annular mist flow: The formula for calculating the liquid holdup of the annular mist flow is: ; The formula for calculating frictional voltage drop is: ; ; in, This refers to the fluid density in the central region of the pipe, expressed in kg / m³. 3 ; It is the friction coefficient when gas flows along the rough surface of the liquid film.

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