A method for determining the safe shut-in period of drilling under trace gas invasion conditions

Abstract

The present invention relates to a method for determining a safe shut-in period of drilling under trace gas invasion conditions, belonging to the field of petroleum and natural gas engineering, and includes: obtaining drilling measurement data; determining characteristic parameters after gas invasion into the bottom of the well, including: gas invasion volume and initial equivalent diameter of bubbles at the bottom of the well; constructing a bubble rise velocity model in the non-hydrate formation area of ​​the wellbore and a hydrate membrane bubble rise velocity model in the hydrate formation area; predicting the dynamic formation area of ​​natural gas hydrate in the wellbore; and calculating the safe shut-in period of drilling under given conditions. The present invention overcomes the influence of complex conditions of deep deepwater formations, and can more accurately obtain the safe shut-in period of deep deepwater drilling under trace gas invasion conditions.

Description

Technical Field

[0001] The present invention belongs to the field of petroleum and natural gas engineering, and in particular, relates to a method for determining a safe shut-in period for drilling under conditions of trace gas invasion, especially a method for determining a safe shut-in period for deep-layer deepwater drilling under conditions of trace gas invasion. Background Art

[0002] The exploration and development of oil and gas resources in my country has gradually moved towards the deep-water stage. The "three highs" (high temperature, high pressure, and high acid content) or "three supers" (ultra-deep, ultra-high pressure, and ultra-high temperature) environment of deep-water formations makes it very easy for gas invasion to occur during drilling, which is one of the problems that restrict the success rate of drilling and shorten the well construction cycle. When gas invasion occurs during drilling and shut-in measures are taken, the wellbore pressure will continue to increase during the ascent of the gas, and may even exceed the pressure at the casing shoe or the weak point of the open hole formation, destroying the integrity of the wellbore. The time from when the gas starts to rise at the bottom of the well to when the gas reaches the wellhead and the integrity of the wellbore is not destroyed, or when the gas does not reach the wellhead and the integrity of the wellbore is destroyed, is usually called the safe shut-in period. The determination of the safe shut-in period can provide a basis for the safe time window of the well killing operation, and can also provide a criterion for determining whether the gas reaches the wellhead after a long shut-in. For example, during the long period of closure to avoid typhoons in deep-water drilling in the South my country Sea, the bottom hole gas is likely to accumulate at the storm valve at the wellhead, forming a closed high pressure, which poses a safety hazard to the well opening operation. The safe well closing cycle can be used to determine whether the gas has reached the wellhead, thereby reasonably guiding the well opening operation.

[0003] Traditional methods for obtaining safe shut-in periods are mostly based on gas-liquid two-phase flow theory, but the complex conditions of deep water formations make existing methods unreliable. The main limiting factors are how to accurately determine the amount of gas invasion, initial characteristic parameters of bubbles, characteristic parameters of bubble hydrate phase change, characteristic parameters of bubble migration upward along the wellbore, etc. Therefore, constructing a method for determining safe shut-in periods under trace gas invasion conditions in deep water drilling is of great significance to ensure drilling safety. Summary of the invention

[0004] In view of the shortcomings of the prior art, the present invention provides a method for determining the safe shut-in period of drilling under trace gas invasion conditions. The method overcomes the influence of complex conditions of deep deepwater formations and can more accurately obtain the safe shut-in period of deep deepwater drilling under trace gas invasion conditions.

[0005] The present invention adopts the following technical solutions:

[0006] To achieve the above purpose, the technical solution adopted by the present invention is as follows:

[0007] A method for determining a safe shut-in period of drilling under trace gas invasion conditions comprises the following steps:

[0008] S1, obtain drilling measurement data;

[0009] S2, determining characteristic parameters of gas after invading the bottom of the well, including: gas invading amount and initial equivalent diameter of the bubble at the bottom of the well;

[0010] S3, constructing a bubble rising velocity model in the non-hydrate formation area of ​​the wellbore and a hydrate film bubble rising velocity model in the hydrate formation area;

[0011] S4, predicting the dynamic formation area of ​​gas hydrate in the wellbore;

[0012] S5, calculate the safe shut-in period of drilling under given conditions.

[0013] Preferably, the drilling measurement data in step S1 is obtained according to the actual situation at the drilling site, including wellbore structure, drilling fluid density, drilling fluid viscosity, bottom hole pressure, formation pressure, formation permeability, formation pore diameter, and ambient temperature field.

[0014] Preferably, the gas intrusion model applicable to complex conditions in deep water formations established in step S2 is as shown in formula (1):

[0015]

[0016] In formula (1): Q g —Volume flow rate of gas under standard conditions, m 3 / s;T a —gas temperature under standard conditions, °C; T—gas temperature under formation conditions, °C; Z a —Compression factor of gas under standard conditions, dimensionless; Z—Compression factor of gas under formation conditions, dimensionless; μ is the viscosity of gas at the local location, Pa·s; K p is the formation permeability, m 2 ;P a —Gas pressure under standard conditions, Pa; P e —formation pressure, Pa; P w (h)—bottom hole pressure, Pa; h 0 — open hole length of wellbore, m; h— distance to the bottom of the well, m;

[0017] The established initial equivalent diameter model of the bubble at the bottom of the well is shown in formula (2):

[0018]

[0019] In formula (2): D eq0 —The initial equivalent diameter of the bubble at the bottom of the well, m; D 0 —diameter of formation pores, m; Re=(ρ l-ρ g ) g0 D 0 / μ l ρ l —Drilling fluid density, kg / m 3 ρ g —Gas density, kg / m 3 ;σ—gas-liquid interfacial tension, N / m; g—local gravitational acceleration, m / s 2 ;μ l —Drilling fluid viscosity, Pa·s, u g0 —Gas intrusion rate at the bottom of the well, m / s, u g0 =Q g / A,Q g Determined by formula (1), A is the surface area of ​​the open hole section of the wellbore, m 2 .

[0020] Preferably, the bubble rising velocity model of the wellbore non-hydrate formation area constructed in step S3 is as shown in formula (3):

[0021]

[0022] In formula (3), u g —bubble rising speed, m / s; C D —bubble rising drag coefficient; Re g =(ρ l -ρ g ) g D eq / μ l ;D eq —Equivalent diameter of the bubble at the local location, m, T 1 —Local temperature of the bubble, °C; P 1 —Local pressure of the bubble, Pa; Z 1 —The local compression factor of the bubble, dimensionless; T 0 —Temperature of the bubble when it enters the bottom of the well, °C; P 0 —Pressure when the bubble enters the bottom of the well, Pa; Z 0 —Compression factor of the gas bubble as it enters the well bottom, dimensionless.

[0023] Preferably, the hydrate film bubble rising velocity model of the wellbore hydrate formation area constructed in step S3 is as shown in formula (4):

[0024]

[0025] In formula (4), u hg ——rise velocity of hydrate film bubbles, m / s; ρ eq——Equivalent density of hydrate membrane bubbles, kg / m 3 ρ h ——Hydrate film density, kg / m 3 ;δ——hydrate film thickness, m; ——Drag coefficient of hydrate film bubble rise; Re hg =(ρ l -ρ eq ) hg D eq / μ l ;

[0026] Preferably, the specific process of predicting the dynamic formation area of ​​natural gas hydrate in the wellbore in step S4 is: when the wellbore temperature and pressure meet the natural gas hydrate formation temperature and pressure conditions, the corresponding wellbore position is the natural gas hydrate formation area, that is, the temperature and pressure at the current position of the wellbore meet the following expression:

[0027]

[0028] In formula (5): T(h) is the wellbore temperature at a distance h from the bottom of the well, °C; P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; T h ——Pressure is P h The critical temperature of natural gas hydrate formation, ℃; P h ——Temperature is T h Critical pressure of natural gas hydrate formation at , Pa;

[0029] Preferably, during the shut-in period, the wellbore temperature field is close to the ambient temperature field, and the wellbore temperature T(h) is taken as the ambient temperature at a distance h from the bottom of the well.

[0030] Preferably, the wellbore pressure P(h) in step S4 is calculated by an established wellbore pressure field prediction model, and the wellbore pressure field prediction model is shown in equations (6), (7), and (8):

[0031]

[0032]

[0033]

[0034] In formula (6), (7) and (8), P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; P 1 —Pressure at the end of the mixed gas-liquid column, Pa; P 2 —Pressure at the front end of the mixed gas-liquid column, Pa; h 1 —Distance from the end of the mixed gas-liquid column to the bottom of the well, m; h 2—The distance from the front end of the mixed gas-liquid column to the bottom of the well, m; H—Well depth, m; E g —average gas content of the gas-liquid column, dimensionless; P w —bottom hole pressure, Pa; δt—time step, s; u 1 —The rising velocity of the bubble at the end of the mixed gas-liquid column, m / s; u 2 —The rising velocity of the gas at the front end of the mixed gas-liquid column, m / s; If the temperature and pressure at the current location of the bubble do not satisfy equation (5), then u 1 、u 2 Calculated by formula (3), that is, u 1 ||u 2 =u g ; If the temperature and pressure at the current location of the bubble satisfy equation (5), then u 1 、u 2 Calculated by formula (4), that is, u 1 ||u 2 =u hg .

[0035] Preferably, the process of calculating the safe shut-in period under given conditions in step S5 is as follows:

[0036] ① Set the time step δt, taking into account the calculation efficiency and calculation accuracy, and the value range of δt is 0.01~1s;

[0037] ② Estimate the change in bottom hole pressure δP. Considering the calculation efficiency and accuracy, the value range of δP is 0.1~1MPa;

[0038] ③The initial bottom hole pressure is P w0 , at the bottom hole pressure P w =P w0 +δP condition, calculate the front position h of the mixed gas-liquid column within a unit time step 1 , end position h 2 , the front position h of the mixed gas-liquid column within the unit time step δt 1 , end position h 2 Calculated by formula (8);

[0039] ④ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the volume change of the mixed gas-liquid column δV caused by the change in wellbore pressure g , calculate the volume change δV caused by drilling fluid loss f , Volume change V caused by drilling fluid compression l C l δP, volume change V caused by wellbore expansion and contraction c C cδP, the sum of the three is calculated as δV';

[0040] ⑤ Determine whether |δV is satisfied g -δV'|<ε, if satisfied, proceed to the next step; otherwise, re-estimate the bottom hole pressure change δP and return to ③;

[0041] Theoretically, the volume change of the gas-liquid column caused by the change in wellbore pressure is g Equal to the volume change δV caused by drilling fluid loss f , Volume change V caused by drilling fluid compression l C l δP, volume change V caused by wellbore expansion and contraction c C c The sum of the three δP is δV'. In numerical calculations, δV g The calculation of δV' allows a reasonable range of error. Therefore, considering the calculation efficiency and accuracy, the value range of ε is 10 -3 ~10 -5 ;

[0042] ⑥ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the wellbore pressure distribution;

[0043] The wellbore pressure at any distance h from the bottom of the well is calculated by equations (6) and (7);

[0044] ⑦ Determine whether the wellbore integrity is damaged. If damaged, obtain the drilling safety period T = ∑dt; if not damaged, proceed to the next step;

[0045] ⑧ Determine whether the front end of the mixed gas-liquid column reaches the wellhead. If h 2 ≥H, the drilling safety period T=∑dt is obtained, and the calculation ends; if h is not satisfied 2 ≥H, continue the calculation in the next time step and return to ②.

[0046] Preferably, in step ④, δV g , δV' is determined by formula (9):

[0047]

[0048] In formula (9), δV g —Volume change of mixed gas-liquid column caused by wellbore pressure change, m 3 ; V g1 —The wellbore gas volume before time step δt, m 3 ; T 1 —The local temperature of the bubble before the time step δt, °C; P 1—the local pressure of the bubble before the time step δt, Pa; Z 1 —the local compressibility factor of the bubble before the time step δt, dimensionless; T 2 —The local temperature of the bubble after the time step δt, °C; P 2 —the local pressure of the bubble after the time step δt, Pa; Z 2 —the local compressibility factor of the bubble after time step δt, dimensionless; δV f —Volume change caused by drilling fluid loss, m 3 ; V l C l δP—Volume change caused by drilling fluid compression, m 3 ; V c C c δP—Volume change caused by wellbore expansion and contraction, m 3 ; V l —Drilling fluid volume in the wellbore, m 3 ; V c — Wellbore volume, m 3 ; C l —Drilling fluid compressibility, Pa -1 ; C c —Wellbore compression coefficient, Pa -1 ;

[0049] Volume change δV caused by drilling fluid loss f The static liquid loss equation is shown in formula (10):

[0050]

[0051] In formula (10): f sm —Solid content in drilling fluid, %; f sc —Solid content in filter cake, %; K f —Filter cake permeability, 10 -3 μm 2 ; S—area of ​​open hole section of wellbore, m 2 .

[0052] Preferably, in step ⑦, when the pressure at the weak point of the wellbore and the wellhead pressure satisfy the following expression, it indicates that the integrity of the wellbore is not damaged; otherwise, it is damaged;

[0053]

[0054] In formula (11): P f —Wellbore pressure at the weak point of the wellbore, Pa; P fshoe — Formation fracture pressure at casing shoe, Pa; P fweak— Formation breakdown / loss pressure at the weak point of the open hole formation, Pa; P c —Wellhead back pressure, Pa; P cmax —Pressure bearing capacity of wellhead equipment, Pa; P ri —Casing internal pressure resistance, Pa.

[0055] The beneficial effects of the present invention are:

[0056] 1. The present invention overcomes the influence of complex conditions in deep deepwater formations and can more accurately obtain the safe shut-in period under the conditions of trace gas invasion in deep deepwater drilling.

[0057] 2. The characteristic parameter calculation model after gas invasion into the bottom of the well established by the present invention, as well as the bubble rising velocity model in the non-hydrate formation area of ​​the wellbore and the hydrate membrane bubble rising velocity model in the hydrate formation area, take into account the coupling effect of the formation and the wellbore caused by the invasion of deep reservoir gas into the bottom of the well, and take into account the phase change factors of wellbore hydrates under the special environmental temperature field of deep water. By accurately predicting the safe shut-in period of drilling, reasonable guidance is provided for the well pressure operation and well opening operation of on-site drilling, so as to ensure safe and efficient drilling. BRIEF DESCRIPTION OF THE DRAWINGS

[0058] Figure 1 This is a flow chart of a method for determining a safe shut-in period for drilling under trace gas invasion conditions of the present invention;

[0059] Figure 2 The present invention is a flow chart of a numerical algorithm for calculating a safe shut-in period of drilling under given conditions. DETAILED DESCRIPTION

[0060] The present invention will be further described below by way of embodiments in conjunction with the accompanying drawings, but is not limited thereto.

[0061] Example:

[0062] like Figure 1-2 As shown, this embodiment provides a method for determining a safe shut-in period of drilling under trace gas invasion conditions, comprising the following steps:

[0063] S1, obtain drilling measurement data. The drilling measurement data is obtained according to the actual situation of the drilling site, including wellbore structure, drilling fluid density, drilling fluid viscosity, bottom hole pressure, formation pressure, formation permeability, formation pore diameter, and ambient temperature field;

[0064] S2, determining characteristic parameters of gas after invading the bottom of the well, including: gas invading amount and initial equivalent diameter of the bubble at the bottom of the well;

[0065] The gas intrusion model is shown in formula (1):

[0066]

[0067] In formula (1): Q g —Volume flow rate of gas under standard conditions, m 3 / s;T a —gas temperature under standard conditions, °C; T—gas temperature under formation conditions, °C; Z a —Compression factor of gas under standard conditions, dimensionless; Z—Compression factor of gas under formation conditions, dimensionless; μ is the viscosity of gas at the local location, Pa·s; K p is the formation permeability, m 2 ;P a —Gas pressure under standard conditions, Pa; P e —formation pressure, Pa; P w (h)—bottom hole pressure, Pa; h 0 — open hole length of wellbore, m; h— distance to the bottom of the well, m;

[0068] The initial equivalent diameter model of the bubble at the bottom of the well is shown in formula (2):

[0069]

[0070] In formula (2): D eq0 —The initial equivalent diameter of the bubble at the bottom of the well, m; D 0 —diameter of formation pores, m; Re=(ρ l -ρ g ) g0 D 0 / μ l ρ l —Drilling fluid density, kg / m 3 ρ g —Gas density, kg / m 3 ;σ—gas-liquid interfacial tension, N / m; g—local gravitational acceleration, m / s 2 ;μ l —Drilling fluid viscosity, Pa·s, u g0 —Gas intrusion rate at the bottom of the well, m / s, u g0 =Q g / A,Q g Determined by formula (1), A is the surface area of ​​the open hole section of the wellbore, m 2 ;

[0071] S3, constructing a bubble rising velocity model in the non-hydrate formation area of ​​the wellbore and a hydrate film bubble rising velocity model in the hydrate formation area;

[0072] The bubble rising velocity model in the non-hydrate formation area of ​​the wellbore is shown in formula (3):

[0073]

[0074] In formula (3), u g —bubble rising speed, m / s; C D —bubble rising drag coefficient; Re g =(ρ l -ρ g ) g D eq / μ l ;D eq —Equivalent diameter of the bubble at the local location, m, T 1 —Local temperature of the bubble, °C; P 1 —Local pressure of the bubble, Pa; Z 1 —The local compression factor of the bubble, dimensionless; T 0 —Temperature of the bubble when it enters the bottom of the well, °C; P 0 —Pressure when the bubble enters the bottom of the well, Pa; Z 0 —Compression factor of the gas bubble when it enters the bottom of the well, dimensionless;

[0075] The hydrate film bubble rising velocity model in the wellbore hydrate formation area is shown in formula (4):

[0076]

[0077] In formula (4), u hg ——rise velocity of hydrate film bubbles, m / s; ρ eq ——Equivalent density of hydrate membrane bubbles, kg / m 3 ρ h ——Hydrate film density, kg / m 3 ;δ——hydrate film thickness, m; ——Drag coefficient of hydrate film bubble rise; Re hg =(ρ l -ρ eq ) hg D eq / μ l ;

[0078] S4, predicting the dynamic formation area of ​​natural gas hydrate in the wellbore. The specific process is: when the wellbore temperature and pressure meet the natural gas hydrate formation temperature and pressure conditions, the corresponding wellbore position is the natural gas hydrate formation area, that is, the temperature and pressure at the current position of the wellbore meet the following expression:

[0079]

[0080] In formula (5): T(h) is the wellbore temperature at a distance h from the bottom of the well, °C; P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; T h ——Pressure is P h The critical temperature of natural gas hydrate formation, ℃; P h ——Temperature is T h Critical pressure of natural gas hydrate formation at , Pa;

[0081] During the shut-in period, the wellbore temperature field is close to the ambient temperature field, and the wellbore temperature T(h) is taken as the ambient temperature at a distance h from the bottom of the well.

[0082] The wellbore pressure P(h) is calculated by the established wellbore pressure field prediction model. The wellbore pressure field prediction model is shown in equations (6), (7), and (8):

[0083]

[0084]

[0085]

[0086] In formula (6), (7) and (8), P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; P 1 —Pressure at the end of the mixed gas-liquid column, Pa; P 2 —Pressure at the front end of the mixed gas-liquid column, Pa; h 1 —Distance from the end of the mixed gas-liquid column to the bottom of the well, m; h 2 —The distance from the front end of the mixed gas-liquid column to the bottom of the well, m; H—Well depth, m; E g —average gas content of the gas-liquid column, dimensionless; P w —bottom hole pressure, Pa; δt—time step, s; u 1 —The rising velocity of the bubble at the end of the mixed gas-liquid column, m / s; u 2 —The rising velocity of the gas at the front end of the mixed gas-liquid column, m / s; If the temperature and pressure at the current location of the bubble do not satisfy equation (5), then u 1 、u 2 Calculated by formula (3), that is, u 1 ||u 2 =u g ; If the temperature and pressure at the current location of the bubble satisfy equation (5), then u 1 、u 2 Calculated by formula (4), that is, u 1 ||u 2 =u hg .

[0087] S5, calculate the safe shut-in period of drilling under given conditions, the process is as follows:

[0088] ① Set the time step δt, taking into account the calculation efficiency and calculation accuracy, and the value range of δt is 0.1s;

[0089] ② Estimate the change in bottom hole pressure δP. Considering the calculation efficiency and accuracy, the value range of δP is 0.1MPa;

[0090] ③The initial bottom hole pressure is P w0 , at the bottom hole pressure P w =P w0 +δP condition, calculate the front position h of the mixed gas-liquid column within a unit time step 1 , end position h 2 , the front position h of the mixed gas-liquid column within the unit time step δt 1 , end position h 2 Calculated by formula (8);

[0091] ④ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the volume change of the mixed gas-liquid column δV caused by the change in wellbore pressure g , calculate the volume change δV caused by drilling fluid loss f , Volume change V caused by drilling fluid compression l C l δP, volume change V caused by wellbore expansion and contraction c C c δP, the sum of the three is calculated as δV';

[0092] δV g , δV' is determined by formula (9):

[0093]

[0094] In formula (9), δV g —Volume change of mixed gas-liquid column caused by wellbore pressure change, m 3 ; V g1 —The wellbore gas volume before time step δt, m 3 ; T 1 —The local temperature of the bubble before the time step δt, °C; P 1 —the local pressure of the bubble before the time step δt, Pa; Z 1 —the local compressibility factor of the bubble before the time step δt, dimensionless; T 2 —The local temperature of the bubble after the time step δt, °C; P 2—the local pressure of the bubble after the time step δt, Pa; Z 2 —the local compressibility factor of the bubble after time step δt, dimensionless; δV f —Volume change caused by drilling fluid loss, m 3 ; V l C l δP—Volume change caused by drilling fluid compression, m 3 ; V c C c δP—Volume change caused by wellbore expansion and contraction, m 3 ; V l —Drilling fluid volume in the wellbore, m 3 ; V c — Wellbore volume, m 3 ; C l —Drilling fluid compressibility, Pa -1 ; C c —Wellbore compression coefficient, Pa -1 ;

[0095] Volume change δV caused by drilling fluid loss f The static liquid loss equation is shown in formula (10):

[0096]

[0097] In formula (10): f sm —Solid content in drilling fluid, %; f sc —Solid content in filter cake, %; K f —Filter cake permeability, 10 -3 μm 2 ; S—area of ​​open hole section of wellbore, m 2 .

[0098] ⑤ Determine whether |δV is satisfied g -δV'|<ε, if satisfied, proceed to the next step; otherwise, re-estimate the bottom hole pressure change δP and return to ③;

[0099] Theoretically, the volume change of the gas-liquid column caused by the change in wellbore pressure is g Equal to the volume change δV caused by drilling fluid loss f , Volume change V caused by drilling fluid compression l C l δP, volume change V caused by wellbore expansion and contraction c C c The sum of the three δP is δV'. In numerical calculations, δV g The calculation of δV' allows a reasonable range of error. Therefore, considering the calculation efficiency and accuracy, the value range of ε is 10-3 ;

[0100] ⑥ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the wellbore pressure distribution;

[0101] The wellbore pressure at any distance h from the bottom of the well is calculated by equations (6) and (7);

[0102] ⑦ Determine whether the wellbore integrity is damaged. If damaged, obtain the drilling safety period T = ∑dt; if not damaged, proceed to the next step;

[0103] When the pressure at the weak point of the wellbore and the wellhead pressure satisfy the following expression, it means that the integrity of the wellbore is not damaged; otherwise, it is damaged;

[0104]

[0105] In formula (11): P f —Wellbore pressure at the weak point of the wellbore, Pa; P fshoe — Formation fracture pressure at casing shoe, Pa; P fweak — Formation breakdown / loss pressure at the weak point of the open hole formation, Pa; P c —Wellhead back pressure, Pa; P cmax —Pressure bearing capacity of wellhead equipment, Pa; P ri —Casing internal pressure resistance, Pa.

[0106] ⑧ Determine whether the front end of the mixed gas-liquid column reaches the wellhead. If h 2 ≥H, the drilling safety period T=∑dt is obtained, and the calculation ends; if h is not satisfied 2 ≥H, continue the calculation in the next time step and return to ②.

[0107] The above is a preferred embodiment of the present invention. It should be pointed out that for ordinary technicians in this technical field, several improvements and modifications can be made without departing from the principles of the present invention. These improvements and modifications should also be regarded as the scope of protection of the present invention.

Claims

1. A method for determining the safe shut-in period of drilling under trace gas invasion conditions, characterized in that: The steps include: S1, obtain drilling measurement data; S2, determining characteristic parameters of gas after invading the bottom of the well, including: gas invading amount and initial equivalent diameter of the bubble at the bottom of the well; S3, constructing a bubble rising velocity model in the non-hydrate formation area of ​​the wellbore and a hydrate film bubble rising velocity model in the hydrate formation area; S4, predicting the dynamic formation area of ​​gas hydrate in the wellbore; S5, calculating the safe shut-in period of drilling under given conditions; The gas intrusion model established in step S2 and applicable to complex conditions in deep water formations is shown in formula (1): In formula (1): Q g —Volume flow rate of gas under standard conditions, m 3 / s;T a —gas temperature under standard conditions, °C; T—gas temperature under formation conditions, °C; Z a —Compression factor of gas under standard conditions, dimensionless; Z—Compression factor of gas under formation conditions, dimensionless; μ is the viscosity of gas at the local location, Pa·s; K p is the formation permeability, m 2 ;P a —Gas pressure under standard conditions, Pa; P e —formation pressure, Pa; P w (h)—bottom hole pressure, Pa; h0—open hole length of wellbore, m; h—distance to the bottom of the well, m; The established initial equivalent diameter model of the bubble at the bottom of the well is shown in formula (2): In formula (2): D eq0 —initial equivalent diameter of the bubble at the bottom of the well, m; D0—formation pore diameter, m; Re=(ρ l -ρ g ) g0 D0 / μ l ρ l —Drilling fluid density, kg / m 3 ρ g —Gas density, kg / m 3 ;σ—gas-liquid interfacial tension, N / m; g—local gravitational acceleration, m / s 2 ;μ l —Drilling fluid viscosity, Pa·s, u g0 —Gas intrusion rate at the bottom of the well, m / s, u g0 =Q g / A,Q g Determined by formula (1), A is the surface area of ​​the open hole section of the wellbore, m 2 ; The bubble rising velocity model of the wellbore non-hydrate formation area constructed in step S3 is shown in formula (3): In formula (3), u g —bubble rising speed, m / s; C D —bubble rising drag coefficient; Re g =(ρ l -ρ g ) g D eq / μ l ;D eq —Equivalent diameter of the bubble at the local location, m, T1—the temperature of the bubble at the local location, ℃; P1—the pressure of the bubble at the local location, Pa; Z1—the compression factor of the bubble at the local location, dimensionless; T0—the temperature of the bubble when it enters the bottom of the well, ℃; P0—the pressure of the bubble when it enters the bottom of the well, Pa; Z0—the compression factor of the bubble when it enters the bottom of the well, dimensionless; The hydrate film bubble rising velocity model in the wellbore hydrate formation area constructed in step S3 is shown in formula (4): In formula (4), u hg ——rise velocity of hydrate film bubbles, m / s; ρ eq ——Equivalent density of hydrate membrane bubbles, kg / m 3 ρ h ——Hydrate film density, kg / m 3 ;δ——hydrate film thickness, m; ——Drag coefficient of hydrate film bubble rise; Re hg =(ρ l -ρ eq ) hg D eq / μ l ; 2. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 1 is characterized in that: The drilling measurement data in step S1 include wellbore structure, drilling fluid density, drilling fluid viscosity, bottom hole pressure, formation pressure, formation permeability, formation pore diameter, and ambient temperature field.

3. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 1 is characterized in that: The specific process of predicting the dynamic formation area of ​​natural gas hydrate in the wellbore in step S4 is: when the wellbore temperature and pressure meet the natural gas hydrate formation temperature and pressure conditions, the corresponding wellbore position is the natural gas hydrate formation area, that is, the temperature and pressure at the current position of the wellbore meet the following expression: In formula (5): T(h) is the wellbore temperature at a distance h from the bottom of the well, °C; P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; T h ——Pressure is P h The critical temperature of natural gas hydrate formation, ℃; P h ——Temperature is T h Critical pressure of natural gas hydrate formation at , Pa; The wellbore temperature T(h) is taken as the ambient temperature at a distance h from the bottom of the well.

4. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 3 is characterized in that: The wellbore pressure P(h) in step S4 is calculated by the established wellbore pressure field prediction model, which is shown in equations (6), (7), and (8): In formulas (6), (7) and (8): P(h) is the wellbore pressure at a distance h from the bottom of the well, Pa; P1 is the pressure at the end of the mixed gas-liquid column, Pa; P2 is the pressure at the front end of the mixed gas-liquid column, Pa; h1 is the distance from the end of the mixed gas-liquid column to the bottom of the well, m; h2 is the distance from the front end of the mixed gas-liquid column to the bottom of the well, m; H is the well depth, m; E g —average gas content of the gas-liquid column, dimensionless; P w —bottom hole pressure, Pa; δt—time step, s; u1—bubble rising speed at the end of the mixed gas-liquid column, m / s; u2—gas rising speed at the front end of the mixed gas-liquid column, m / s; If the temperature and pressure at the current location of the bubble do not satisfy equation (5), u1 and u2 are calculated by equation (3), that is, u1||u2=u g ; If the temperature and pressure at the current location of the bubble satisfy equation (5), then u1 and u2 are calculated by equation (4), that is, u1||u2=u hg .

5. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 4 is characterized in that: The process of calculating the safe shut-in period under given conditions in step S5 is as follows: ① Set the time step δt, the value range of δt is 0.01~1s; ② Estimate the change in bottom hole pressure δP, where the value range of δP is 0.1~1MPa; ③The initial bottom hole pressure is P w0 , at the bottom hole pressure P w =P w0 +δP condition, the front position h1 and the end position h2 of the mixed gas-liquid column in the unit time step are calculated. The front position h1 and the end position h2 of the mixed gas-liquid column in the unit time step δt are calculated by formula (8); ④ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the volume change of the mixed gas-liquid column δV caused by the change in wellbore pressure g , calculate the volume change δV caused by drilling fluid loss f , Volume change V caused by drilling fluid compression l C l δP, volume change V caused by wellbore expansion and contraction c C c δP, the sum of the three is calculated as δV'; ⑤ Determine whether |δV is satisfied g -δV'|<ε, if satisfied, proceed to the next step; otherwise, re-estimate the bottom hole pressure change δP and return to ③; The value range of ε is 10 -3 ~10 -5 ; ⑥ At bottom hole pressure P w =P w0 Under +δP conditions, calculate the wellbore pressure distribution; ⑦ Determine whether the wellbore integrity is damaged. If damaged, obtain the drilling safety period T = ∑dt; if not damaged, proceed to the next step; ⑧ Determine whether the front end of the mixed gas-liquid column reaches the wellhead. If h2≥H is satisfied, the drilling safety period T=∑dt is obtained and the calculation ends. If h2≥H is not satisfied, continue the calculation in the next time step and return to ②.

6. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 5 is characterized in that: In step ④, δV g , δV' is determined by formula (9): In formula (9), δV g —Volume change of mixed gas-liquid column caused by wellbore pressure change, m 3 ; V g1 —The wellbore gas volume before time step δt, m 3 ; T1—the local temperature of the bubble before the time step δt, °C; P1—the local pressure of the bubble before the time step δt, Pa; Z1—the local compressibility factor of the bubble before the time step δt, dimensionless; T2—the local temperature of the bubble after the time step δt, °C; P2—the local pressure of the bubble after the time step δt, Pa; Z2—the local compressibility factor of the bubble after the time step δt, dimensionless; δV f —Volume change caused by drilling fluid loss, m 3 ; V l C l δP—Volume change caused by drilling fluid compression, m 3 ; V c C c δP—Volume change caused by wellbore expansion and contraction, m 3 ; V l —Drilling fluid volume in the wellbore, m 3 ; V c — Wellbore volume, m 3 ; C l —Drilling fluid compressibility, Pa -1 ; C c —Wellbore compression coefficient, Pa -1 ; Volume change δV caused by drilling fluid loss f The static liquid loss equation is shown in formula (10): In formula (10): f sm —Solid content in drilling fluid, %; f sc —Solid content in filter cake, %; K f —Filter cake permeability, 10 -3 μm 2 ; S—area of ​​open hole section of wellbore, m 2 .

7. The method for determining the safe shut-in period of drilling under trace gas invasion conditions according to claim 6 is characterized in that: In step ⑦, when the pressure at the weak point of the wellbore and the wellhead pressure satisfy the following expression, it means that the integrity of the wellbore is not damaged; On the contrary, it is destroyed; In formula (11): P f —Wellbore pressure at the weak point of the wellbore, Pa; P fshoe — Formation fracture pressure at casing shoe, Pa; P fweak — Formation breakdown / loss pressure at the weak point of the open hole formation, Pa; P c —Wellhead back pressure, Pa; P cmax —Pressure bearing capacity of wellhead equipment, Pa; P ri —Casing internal pressure resistance, Pa.

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