CN114638179A - Method for determining safe well shut-in period of drilling under trace gas invasion condition - Google Patents

Method for determining safe well shut-in period of drilling under trace gas invasion condition Download PDF

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CN114638179A
CN114638179A CN202210407997.7A CN202210407997A CN114638179A CN 114638179 A CN114638179 A CN 114638179A CN 202210407997 A CN202210407997 A CN 202210407997A CN 114638179 A CN114638179 A CN 114638179A
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郭艳利
孙宝江
王志远
高永海
李�昊
李俊
余承龙
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Abstract

The invention relates to a method for determining a safe well shut-in period of a drilling well under a trace gas invasion condition, which belongs to the field of petroleum and natural gas engineering and comprises the following steps: acquiring drilling measurement data; determining characteristic parameters of the gas after invasion of the bottom of the well, including: gas intrusion and initial equivalent diameter of the gas bubbles at the bottom of the well; constructing a bubble rising speed model of a shaft non-hydrate generation area and a hydrate film bubble rising speed model of a hydrate generation area; predicting a dynamic generation area of the natural gas hydrate in the shaft; and calculating the well safety shut-in period under given conditions. The invention overcomes the influence caused by the complex condition of the deep deepwater stratum and can more accurately obtain the safe well shut-in period under the trace gas invasion condition of the deep deepwater drilling.

Description

Method for determining safe well shut-in period of drilling under trace gas invasion condition
Technical Field
The invention belongs to the field of petroleum and natural gas engineering, and particularly relates to a method for determining a safe shut-in period of drilling under a trace gas invasion condition, in particular to a method for determining a safe shut-in period of deep-layer deep-water drilling under a trace gas invasion condition.
Background
The exploration and development of oil and gas resources in China have gradually advanced to the deep deepwater stage, and the 'three-high' (high temperature, high pressure and high acid content) or 'three-super' (ultra-deep, ultra-high pressure and ultra-high temperature) environment of deep deepwater stratum causes gas invasion to be easy to occur in the drilling process, so that the method is one of the difficult problems of restricting the drilling success rate and shortening the well construction period. When gas invasion occurs during drilling and well shut-in measures are taken, the pressure of the well bore can be continuously increased during the rising process of the gas, and even the pressure at the position of a casing shoe or the weak point of an open hole stratum can be exceeded, and the integrity of the well bore is damaged. The time when gas begins to rise downhole, to the point when the gas reaches the wellhead without the integrity of the wellbore being compromised, or to the point when the gas does not reach the wellhead with the integrity of the wellbore being compromised, is commonly referred to as a safe shut-in period. The determination of the safe shut-in period can provide basis for a safe time window of the well killing operation and also can provide criterion for determining whether long-time shut-in gas reaches a wellhead. For example, during long-time shut-in periods of typhoon-avoiding in deep water drilling in south China sea, well bottom gas may be gathered at a wellhead storm valve to form trap high pressure, so that potential safety hazards are brought to well opening operation, and the safe well shut-in period can be used for judging whether the gas reaches the wellhead, so that the well opening operation is guided reasonably.
The traditional safe well shut-in period solving method is mostly based on a gas-liquid two-phase flow theory, the existing method is lack of reliability due to the complex conditions of deep deepwater strata, and the main limiting factors are how to accurately determine gas invasion amount, bubble initial characteristic parameters, bubble hydrate phase change characteristic parameters, bubble upward migration characteristic parameters along a shaft and the like. Therefore, the method for determining the safe well shut-in period under the condition of micro gas invasion in deep deepwater drilling is constructed, and the method has important significance for guaranteeing the drilling safety.
Disclosure of Invention
Aiming at the defects of the prior art, the invention provides a method for determining the safe well shut-in period of drilling under the trace gas invasion condition, which overcomes the influence caused by the complex condition of deep deepwater stratum and can more accurately obtain the safe well shut-in period under the trace gas invasion condition of deep deepwater drilling.
The invention adopts the following technical scheme:
in order to achieve the purpose, the technical scheme adopted by the invention is as follows:
a method for determining a safe well shut-in period of a drilling well under a trace gas invasion condition comprises the following steps:
s1, obtaining drilling measurement data;
s2, determining characteristic parameters of the gas after the gas invades the bottom hole, comprising the following steps: gas intrusion and initial equivalent diameter of the gas bubbles at the bottom of the well;
s3, constructing a bubble rising speed model of a non-hydrate generating area of the shaft and a hydrate film bubble rising speed model of a hydrate generating area;
s4, predicting a dynamic generation area of the natural gas hydrate in the shaft;
and S5, calculating the well safety shut-in period under the given conditions.
Preferably, the drilling measurement data in step S1 is obtained according to the actual conditions of the drilling site, including the well bore structure, the drilling fluid density, the drilling fluid viscosity, the bottom hole pressure, the formation permeability, the formation pore diameter, and the ambient temperature field.
Preferably, the gas invasion amount model suitable for the complex conditions of the deep-water formation established in step S2 is as shown in formula (1):
Figure BDA0003602605320000021
formula (1)The method comprises the following steps: qgVolume flow of gas under standard conditions, m3/s；Ta-temperature of the gas at standard conditions, ° c; t-temperature of gas at formation conditions, deg.C; za-compression factor of the gas at standard conditions, dimensionless; z is the compressibility factor of the gas under formation conditions, dimensionless; mu is the local viscosity of the gas, Pa · s; kpIs the formation permeability, m2；Pa-pressure of the gas at standard conditions, Pa; pe-formation pressure, Pa; pw(h) -bottom hole pressure, Pa; h is0-wellbore open hole length, m; h-distance to the bottom of the well, m;
the initial equivalent diameter model of the established bubble at the bottom of the well is shown as the formula (2):
Figure BDA0003602605320000022
in formula (2): deq0-initial equivalent diameter of the bubble at the bottom of the well, m; d0-formation pore diameter, m;
Figure BDA0003602605320000023
Re＝(ρl-ρg)ug0D0/μl；ρldrilling fluid density, kg/m3；ρgGas density, kg/m3(ii) a σ -gas-liquid interfacial tension, N/m; g-local acceleration of gravity, m/s2；μlViscosity of drilling fluid, Pa s, ug0Gas invasion bottom hole velocity, m/s, ug0＝Qg/A，QgDetermined by equation (1), A-surface area of open hole section of wellbore, m2。
Preferably, the bubble rising speed model of the wellbore non-hydrate formation area constructed in step S3 is as shown in formula (3):
Figure BDA0003602605320000031
in the formula (3), ug-bubble rising velocityDegree, m/s; cD-bubble drag coefficient; reg＝(ρl-ρg)ugDeq/μl；DeqThe equivalent diameter of the bubbles in the local area, m,
Figure BDA0003602605320000032
T1-local temperature of the bubbles, c; p1-local pressure of the bubbles, Pa; z1-local compression factor of the bubbles, dimensionless; t is0-temperature of the bubbles entering the bottom of the well, ° c; p0-pressure of the bubbles entering the bottom hole, Pa; z0-compressibility factor of the bubble as it enters the bottom hole, dimensionless.
Preferably, the hydrate film bubble rising speed model of the hydrate formation area of the well bore constructed in the step S3 is as shown in formula (4):
Figure BDA0003602605320000033
in the formula (4), uhg-hydrate film bubble rise velocity, m/s; rhoeq-equivalent density of hydrate film bubbles, kg/m3；ρh-hydrate film density, kg/m3(ii) a δ — hydrate film thickness, m;
Figure BDA0003602605320000034
-hydrate film bubble drag coefficient; rehg＝(ρl-ρeq)uhgDeq/μl；
Figure BDA0003602605320000035
Preferably, the specific process of predicting the wellbore natural gas hydrate dynamic generation area in step S4 is as follows: when the temperature and the pressure of the shaft meet the conditions of the natural gas hydrate generation temperature and the pressure, the corresponding shaft position is a natural gas hydrate generation area, namely the temperature and the pressure of the current position of the shaft meet the following expression:
Figure BDA0003602605320000041
in formula (5): t (h) -wellbore temperature at distance h from the bottom of the well, ° C; p (h) -wellbore pressure at distance h from the bottom of the well, Pa; t ishPressure PhThe critical temperature of the formation of the natural gas hydrate is DEG C; p ishAt a temperature ThThe critical pressure, Pa, of the natural gas hydrate;
preferably, the wellbore temperature field during shut-in 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.
Preferably, the wellbore pressure p (h) in step S4 is calculated from the established wellbore pressure field prediction model, which is expressed by the following equations (6), (7) and (8):
Figure BDA0003602605320000042
Figure BDA0003602605320000043
Figure BDA0003602605320000044
in formulae (6), (7) and (8): p (h) -wellbore pressure at distance h from the bottom of the well, Pa; p is1-the pressure at the end position of the mixed gas liquid column, Pa; p2-the pressure, Pa, at the front end of the mixed gas-liquid column; h is1-distance from the end of the mixed gas liquid column to the bottom of the well, m; h is2-distance, m, from the front end of the mixed gas liquid column to the bottom of the well; h-well depth, m; eg-average gas fraction, dimensionless, of the mixed gas liquid column; pw-bottom hole pressure, Pa; δ t-time step, s; u. of1-bubble rise velocity, m/s, at the end position of the mixed gas liquid column; u. of2-gas rising velocity, m/s, at the front end position of the mixed gas-liquid column; if air bubblesIf the temperature and pressure at the current position do not satisfy the formula (5), u1、u2Calculated from equation (3), i.e. u1||u2＝ug(ii) a If the temperature and pressure of the current position of the bubble satisfy the formula (5), u1、u2Calculated from equation (4), i.e. u1||u2＝uhg。
Preferably, the process of calculating the safe well shut-in period under the given conditions in step S5 is as follows:
setting time step delta t, comprehensively considering calculation efficiency and calculation precision, wherein the value range of the delta t is 0.01-1 s;
estimating a certain bottom hole pressure variable quantity delta P, comprehensively considering calculation efficiency and calculation precision, wherein the value range of delta P is 0.1-1 MPa;
③ initial bottom hole pressure Pw0At bottom hole pressure Pw＝Pw0Calculating the front end position h of the mixed gas-liquid column in unit time step under the condition of + delta P1End position h2Front end position h of mixed gas-liquid column in unit time step delta t1End position h2Calculated by formula (8);
pressure P at bottom of wellw＝Pw0Calculating the gas volume change delta V of the mixed gas-liquid column caused by the pressure change of the shaft under the condition of + delta PgAnd calculating the volume change delta V caused by the fluid loss of the drilling fluidfVolume change V caused by drilling fluid compressionlClDelta P, volume change V caused by shaft expansion and contractioncCcδ P, the sum of the three is δ V';
judging whether | delta V is satisfiedg- δ V' | < epsilon, if satisfied, to proceed to the next step; if not, the bottom hole pressure variation delta P is estimated again, and the third step is returned;
theoretically, the gas volume change delta V of the mixed gas-liquid column caused by the pressure change of the shaftgEqual to the volume change delta V caused by the fluid loss of the drilling fluidfVolume change V caused by drilling fluid compressionlClDelta P, volume change V caused by shaft expansion and contractioncCcδ V' is the sum of δ P and δ P. In the calculation of the numerical value,δVgdelta V' calculation allows errors in a reasonable range, so the calculation efficiency and the calculation precision are comprehensively considered, and the value range of epsilon is 10-3～10-5；
Sixth at bottom hole pressure Pw＝Pw0Calculating the pressure distribution of the shaft under the condition of + delta P;
the wellbore pressure at any distance h from the bottom of the well is calculated by the formulas (6) and (7);
seventhly, judging whether the integrity of the shaft is damaged or not, and if the integrity of the shaft is damaged, obtaining a drilling safety period T ═ Σ dt; if not, the next step is carried out;
determining whether the front end of the mixed gas-liquid column reaches the wellhead or not, if yes, h2If the drilling safety period T is more than or equal to H, obtaining the drilling safety period T ═ Σ dt, and finishing the calculation; if h is not satisfied2And if the value is more than or equal to H, continuing the calculation in the next time step, and returning to the step two.
Preferably, in step (iv), δ Vgδ V' is determined by formula (9):
Figure BDA0003602605320000051
in the formula (9), δ VgGas volume change m of mixed gas-liquid column caused by pressure change of well bore3；Vg1Volume of wellbore gas, m, before a time step δ t3；T1-the temperature, c, of the bubble at the local site before the time step δ t; p1-the local pressure, Pa, of the bubble before the time step δ t; z1-the local compression factor of the bubble before the time step δ t, dimensionless; t is2-the temperature of the bubble at the location, c, after the time step δ t; p2-the local pressure, Pa, of the bubble after the time step δ t; z2-the local compression factor of the bubble after the time step δ t, dimensionless; delta VfVolume change due to drilling fluid loss, m3；VlClDelta P-volume change, m, caused by compression of drilling fluid3；VcCcDelta P-volume change, m, due to wellbore expansion3；VlVolume of drilling fluid in wellbore, m3；VcWell bore volume, m3；ClDrilling fluid compressibility factor, Pa-1；Cc-coefficient of compressibility of the wellbore, Pa-1；
Volume change delta V caused by drilling fluid lossfThe hydrostatic fluid loss equation is used as shown in equation (10):
Figure BDA0003602605320000061
in formula (10): f. ofsm-solid content in drilling fluid,%; f. ofsc-solid phase content in filter cake,%; kfPermeability of filter cake, 10-3μm2(ii) a S-area of open hole section of shaft, m2。
Preferably, in step (c), when the pressure at the weak point of the well bore and the pressure at the well head meet the following expression, the integrity of the well bore is not damaged; otherwise, it is destroyed;
Figure BDA0003602605320000062
in formula (11): pf-wellbore pressure, Pa, at wellbore weak points; pfshoe-formation fracture pressure at the casing shoe, Pa; p isfweak-formation fracture/loss pressure, Pa, at the formation weak points of the open hole; pc-wellhead back pressure, Pa; p iscmax-the pressure bearing capacity of the wellhead equipment, Pa; priInternal pressure resistance of the sleeve, Pa.
The invention has the beneficial effects that:
1. the invention overcomes the influence caused by the complex condition of the deep deepwater stratum and can more accurately obtain the safe well shut-in period under the trace gas invasion condition of the deep deepwater drilling.
2. The characteristic parameter calculation model after the gas invades the shaft bottom, the built bubble rising speed model of the shaft non-hydrate generation area and the built hydrate film bubble rising speed model of the hydrate generation area take coupling effect of the stratum and the shaft where the deep reservoir gas invades the shaft bottom into consideration, shaft hydrate phase change factors under a deep water special environment temperature field are taken into consideration, and well killing operation, well opening operation and the like of field drilling are reasonably guided through accurate prediction of a safe well closing period of drilling, so that safe and efficient drilling is guaranteed.
Drawings
FIG. 1 is a flow chart of a method for determining a safe shut-in period of a well under a trace gas invasion condition according to the present invention;
FIG. 2 is a flow chart of a numerical algorithm for calculating a safe shut-in period of drilling under given conditions in accordance with the present invention.
The specific implementation mode is as follows:
the present invention will be further described by way of examples, but not limited thereto, with reference to the accompanying drawings.
Example (b):
as shown in fig. 1-2, the present embodiment provides a method for determining a safe shut-in period of a drilling well under a trace gas invasion condition, including the following steps:
s1, obtaining drilling measurement data, wherein the drilling measurement data are obtained according to the actual conditions of a drilling site and comprise a well body structure, drilling fluid density, drilling fluid viscosity, bottom hole pressure, stratum permeability, stratum pore diameter and an environment temperature field;
s2, determining characteristic parameters of the gas after the gas invades the bottom hole, comprising the following steps: gas intrusion and initial equivalent diameter of the gas bubbles at the bottom of the well;
the gas intrusion amount model is shown in formula (1):
Figure BDA0003602605320000071
in formula (1): qgVolume flow of gas under standard conditions, m3/s；Ta-temperature of the gas at standard conditions, ° c; t-temperature of gas at formation conditions, deg.C; z is a linear or branched membera-compression factor of the gas at standard conditions, dimensionless; z is the compressibility factor of the gas under formation conditions, dimensionless; mu is a gas inLocal viscosity, Pa · s; kpIs the formation permeability, m2；Pa-pressure of gas at standard conditions, Pa; pe-formation pressure, Pa; pw(h) -bottom hole pressure, Pa; h is0-wellbore open hole length, m; h-distance to the bottom of the well, m;
the initial equivalent diameter model of the bubble at the bottom of the well is shown in equation (2):
Figure BDA0003602605320000072
in formula (2): deq0-initial equivalent diameter of the bubble at the bottom of the well, m; d0-formation pore diameter, m;
Figure BDA0003602605320000073
Re＝(ρl-ρg)ug0D0/μl；ρldrilling fluid density, kg/m3；ρgGas density, kg/m3(ii) a σ -gas-liquid interfacial tension, N/m; g-local acceleration of gravity, m/s2；μlViscosity of drilling fluid, Pa s, ug0Gas invasion bottom hole velocity, m/s, ug0＝Qg/A，QgDetermined by equation (1), A-surface area of open hole section of wellbore, m2；
S3, constructing a bubble rising speed model of a non-hydrate generating area of the shaft and a hydrate film bubble rising speed model of a hydrate generating area;
the model of the rising speed of bubbles in the non-hydrate formation area of the shaft is shown as the formula (3):
Figure BDA0003602605320000081
in the formula (3), ug-bubble rise velocity, m/s; cD-bubble drag coefficient; reg＝(ρl-ρg)ugDeq/μl；DeqThe bubbles being in placeThe equivalent diameter, m,
Figure BDA0003602605320000082
T1-local temperature of the bubbles, c; p1-local pressure of the bubbles, Pa; z1-local compression factor of the bubbles, dimensionless; t is0-temperature of the bubbles entering the bottom of the well, ° c; p0-pressure of the bubbles entering the bottom hole, Pa; z is a linear or branched member0-compressibility factor, dimensionless, of the bubbles as they enter the bottom of the well;
the model of the rising speed of the hydrate film bubbles in the hydrate generation area of the shaft is shown as the formula (4):
Figure BDA0003602605320000083
in the formula (4), uhg-hydrate film bubble rise velocity, m/s; rhoeq-equivalent density of hydrate film bubbles, kg/m3；ρh-hydrate film density, kg/m3(ii) a δ — hydrate film thickness, m;
Figure BDA0003602605320000084
-hydrate film bubble drag coefficient; rehg＝(ρl-ρeq)uhgDeq/μl；
Figure BDA0003602605320000085
S4, predicting a dynamic generation area of the natural gas hydrate in the shaft, wherein the specific process is as follows: when the temperature and the pressure of the shaft meet the conditions of the natural gas hydrate generation temperature and the pressure, the corresponding shaft position is a natural gas hydrate generation area, namely the temperature and the pressure of the current position of the shaft meet the following expression:
Figure BDA0003602605320000091
in formula (5): t (h) -at a distance h from the bottom of the wellWellbore temperature, deg.C; p (h) -wellbore pressure at distance h from the bottom of the well, Pa; t ishPressure PhThe critical temperature of the formation of the natural gas hydrate is DEG C; phAt a temperature ThThe critical pressure, Pa, of the natural gas hydrate;
the wellbore temperature field during shut-in 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.
The shaft pressure P (h) is calculated by the established shaft pressure field prediction model, and the shaft pressure field prediction model is shown as formulas (6), (7) and (8):
Figure BDA0003602605320000092
Figure BDA0003602605320000093
Figure BDA0003602605320000094
in formulae (6), (7) and (8): p (h) -wellbore pressure at distance h from the bottom of the well, Pa; p1-the pressure at the end position of the mixed gas-liquid column, Pa; p2-the pressure, Pa, at the front end of the mixed gas-liquid column; h is a total of1-distance from the end of the mixed gas liquid column to the bottom of the well, m; h is2-distance, m, from the front end of the mixed gas liquid column to the bottom of the well; h-well depth, m; eg-average gas fraction, dimensionless, of the mixed gas liquid column; pw-bottom hole pressure, Pa; δ t-time step, s; u. of1-bubble rise velocity, m/s, at the end position of the mixed gas-liquid column; u. of2-gas rising velocity, m/s, at the front end position of the mixed gas-liquid column; if the temperature and pressure of the current position of the bubble do not satisfy the formula (5), u1、u2Calculated from equation (3), i.e. u1||u2＝ug(ii) a If the temperature and pressure of the current position of the bubble satisfy the formula (5), u1、u2Calculated by equation (4)Go out, i.e. u1||u2＝uhg。
S5, calculating the safe well shut-in period under the given conditions, wherein the process is as follows:
setting time step delta t, and comprehensively considering the calculation efficiency and the calculation precision, wherein the value range of the delta t is 0.1 s;
estimating a certain bottom hole pressure variable quantity delta P, comprehensively considering the calculation efficiency and the calculation precision, wherein the value range of the delta P is 0.1 MPa;
initiating bottom hole pressure of Pw0At bottom hole pressure Pw＝Pw0Calculating the front end position h of the mixed gas-liquid column in unit time step under the condition of + delta P1End position h2Front end position h of mixed gas-liquid column in unit time step delta t1End position h2Calculated by formula (8);
pressure P at bottom of wellw＝Pw0Calculating the gas volume change delta V of the mixed gas-liquid column caused by the pressure change of the shaft under the condition of + delta PgAnd calculating the volume change delta V caused by the fluid loss of the drilling fluidfVolume change V caused by drilling fluid compressionlClDelta P, volume change V caused by shaft expansion and contractioncCcδ P, the sum of the three is δ V';
δVgδ V' is determined by formula (9):
Figure BDA0003602605320000101
in the formula (9), δ VgGas volume change m of mixed gas-liquid column caused by pressure change of well bore3；Vg1Volume of wellbore gas, m, before a time step δ t3；T1-the temperature, c, of the bubble at the local site before the time step δ t; p is1-the local pressure, Pa, of the bubble before the time step δ t; z1-the local compression factor, dimensionless, of the bubble before the time step δ t; t is a unit of2-the temperature of the bubble at the location, c, after the time step δ t; p2At the timeThe local pressure, Pa, of the bubbles after the intermediate step δ t; z2-the local compression factor of the bubble after the time step δ t, dimensionless; delta VfVolume change due to drilling fluid loss, m3；VlClDelta P-volume change, m, caused by compression of drilling fluid3；VcCcDelta P-volume change, m, caused by wellbore expansion3；VlVolume of drilling fluid in wellbore, m3；VcWell bore volume, m3；ClDrilling fluid compressibility factor, Pa-1；Cc-coefficient of compressibility of the wellbore, Pa-1；
Volume change delta V caused by drilling fluid lossfThe hydrostatic fluid loss equation is used as shown in equation (10):
Figure BDA0003602605320000102
in formula (10): f. ofsm-solid content in drilling fluid,%; f. ofsc-solid content in filter cake,%; k isfPermeability of filter cake, 10-3μm2(ii) a S-area of open hole section of shaft, m2。
Judging whether | delta V is satisfiedg- δ V' | < epsilon, if satisfied, to proceed to the next step; if not, the bottom hole pressure variation delta P is estimated again, and the third step is returned;
theoretically, the gas volume change delta V of the mixed gas-liquid column caused by the pressure change of the shaftgEqual to the volume change delta V caused by the fluid loss of the drilling fluidfVolume change V caused by drilling fluid compressionlClδ P, volume change V due to shaft expansion and contractioncCcδ V' is the sum of δ P and δ P. In the numerical calculation, δ VgDelta V' calculation allows errors in a reasonable range, so the calculation efficiency and the calculation precision are comprehensively considered, and the value range of epsilon is 10-3；
At bottom hole pressure Pw＝Pw0Calculating the pressure distribution of the shaft under the condition of + delta P;
the wellbore pressure at any distance h from the bottom of the well is calculated by the formulas (6) and (7);
seventhly, judging whether the integrity of the shaft is damaged or not, and if the integrity of the shaft is damaged, obtaining a drilling safety period T ═ Σ dt; if not, the next step is carried out;
when the pressure at the weak point of the shaft and the pressure at the wellhead meet the following expressions, the integrity of the shaft is not damaged; otherwise, it is destroyed;
Figure BDA0003602605320000111
in formula (11): pf-wellbore pressure, Pa, at wellbore weak points; pfshoe-formation fracture pressure at the casing shoe, Pa; p isfweak-formation fracture/loss pressure, Pa, at the formation weak points of the open hole; pc-wellhead back pressure, Pa; pcmax-the pressure bearing capacity of the wellhead equipment, Pa; priInternal pressure resistance of the sleeve, Pa.
Determining whether the front end of the mixed gas-liquid column reaches the wellhead or not, if yes, h2If the drilling safety period T is more than or equal to H, obtaining the drilling safety period T ═ Σ dt, and finishing the calculation; if h is not satisfied2And if the value is more than or equal to H, continuing the calculation in the next time step, and returning to the step two.
While the foregoing is directed to the preferred embodiment of the present invention, it will be understood by those skilled in the art that various changes and modifications may be made without departing from the spirit and scope of the invention as defined in the appended claims.

Claims (10)

1. A method for determining a safe well shut-in period of a well under a trace gas invasion condition is characterized by comprising the following steps:
s1, obtaining drilling measurement data;
s2, determining characteristic parameters of the gas after the gas invades the bottom hole, comprising the following steps: gas intrusion and initial equivalent diameter of the gas bubbles at the bottom of the well;
s3, constructing a bubble rising speed model of a non-hydrate generating area of the shaft and a hydrate film bubble rising speed model of a hydrate generating area;
s4, predicting a dynamic generation area of the natural gas hydrate in the shaft;
and S5, calculating the well safety shut-in period under the given conditions.
2. The method of claim 1, wherein the drilling measurement data in step S1 includes well bore structure, drilling fluid density, drilling fluid viscosity, bottom hole pressure, formation permeability, formation pore diameter, and ambient temperature field.
3. The method for determining the safe well shut-in period of the drilling under the micro gas invasion condition according to claim 1, wherein the gas invasion model established in the step S2 and applicable to the complex condition of the deep-water stratum is as shown in formula (1):
Figure FDA0003602605310000011
in formula (1): qgVolume flow of gas under standard conditions, m3/s；Ta-temperature of the gas at standard conditions, ° c; t-temperature of gas at formation conditions, deg.C; za-compression factor of the gas at standard conditions, dimensionless; z is the compressibility factor of the gas under formation conditions, dimensionless; mu is the local viscosity of the gas, Pa · s; k ispIs the formation permeability, m2；Pa-pressure of the gas at standard conditions, Pa; pe-formation pressure, Pa; pw(h) -bottom hole pressure, Pa; h is a total of0-wellbore open hole length, m; h-distance to the bottom of the well, m;
the initial equivalent diameter model of the established bubble at the bottom of the well is shown as the formula (2):
Figure FDA0003602605310000012
in formula (2): deq0-initial equivalent diameter of the bubble at the bottom of the well, m; d0-formation pore diameter, m;
Figure FDA0003602605310000013
Re＝(ρl-ρg)ug0D0/μl；ρldrilling fluid density, kg/m3；ρgGas density, kg/m3(ii) a σ -gas-liquid interfacial tension, N/m; g-local acceleration of gravity, m/s2；μlViscosity of drilling fluid, Pa s, ug0Gas invasion bottom hole velocity, m/s, ug0＝Qg/A，QgDetermined by equation (1), A-surface area of open hole section of wellbore, m2。
4. The method for determining the safe well shut-in period under the trace gas invasion condition according to claim 1, wherein the bubble rising speed model of the non-hydrate formation area of the well shaft constructed in the step S3 is as shown in the formula (3):
Figure FDA0003602605310000021
in the formula (3), ug-bubble rise velocity, m/s; cD-bubble drag coefficient; reg＝(ρl-ρg)ugDeq/μl；DeqThe equivalent diameter of the bubbles in the local area, m,
Figure FDA0003602605310000022
T1-local temperature of the bubbles, c; p1-local pressure of the bubbles, Pa; z is a linear or branched member1-local compression factor of the bubbles, dimensionless; t is0-temperature of the gas bubbles entering the bottom of the well, ° c; p0-pressure of the bubbles entering the bottom hole, Pa; z is a linear or branched member0-compressibility factor of the bubble as it enters the bottom hole, dimensionless.
5. The method for determining the safe well shut-in period of the well drilling under the micro gas invasion condition according to claim 4, wherein the hydrate film bubble rising speed model of the hydrate formation area of the well bore constructed in the step S3 is as shown in the formula (4):
Figure FDA0003602605310000023
in the formula (4), uhg-hydrate film bubble rise velocity, m/s; ρ is a unit of a gradienteq-equivalent density of hydrate film bubbles, kg/m3；ρhHydrate film density, kg/m3(ii) a δ — hydrate film thickness, m;
Figure FDA0003602605310000024
-hydrate film bubble drag coefficient; rehg＝(ρl-ρeq)uhgDeq/μl；
Figure FDA0003602605310000025
6. The method for determining the safe well shut-in period under the trace gas invasion condition is characterized in that the specific process of predicting the dynamic generation area of the natural gas hydrate in the shaft in the step S4 is as follows: when the temperature and the pressure of the shaft meet the conditions of the natural gas hydrate generation temperature and the pressure, the corresponding shaft position is a natural gas hydrate generation area, namely the temperature and the pressure of the current position of the shaft meet the following expression:
Figure FDA0003602605310000031
in formula (5): t (h) -wellbore temperature at distance h from the bottom of the well, ° C; p (h) -the wellbore pressure at distance h from the bottom of the well, Pa; t ishPressure PhTime and dayCritical temperature of formation of gas hydrate, deg.C; p ishAt a temperature ThThe critical pressure, Pa, of the natural gas hydrate;
preferably, the wellbore temperature t (h) is taken as the ambient temperature at a distance h from the bottom of the well.
7. The method for determining the safe well shut-in period under the micro gas invasion condition according to claim 6, wherein the wellbore pressure P (h) in the step S4 is calculated by establishing a wellbore pressure field prediction model, and the wellbore pressure field prediction model is as shown in the formulas (6), (7) and (8):
Figure FDA0003602605310000032
Figure FDA0003602605310000033
Figure FDA0003602605310000034
in formulae (6), (7) and (8): p (h) -wellbore pressure at distance h from the bottom of the well, Pa; p is1-the pressure at the end position of the mixed gas liquid column, Pa; p2-the pressure, Pa, at the front end of the mixed gas-liquid column; h is1-distance from the end of the mixed gas liquid column to the bottom of the well, m; h is2-distance, m, from the front end of the mixed gas-liquid column to the bottom of the well; h-well depth, m; eg-average gas fraction, dimensionless, of the mixed gas liquid column; p isw-bottom hole pressure, Pa; δ t-time step, s; u. of1-bubble rise velocity, m/s, at the end position of the mixed gas liquid column; u. of2-gas rising velocity, m/s, at the front end position of the mixed gas-liquid column; if the temperature and pressure of the current position of the bubble do not satisfy the formula (5), u1、u2Calculated from equation (3), i.e. u1||u2＝ug(ii) a If the bubble is currently at the location of the temperature sumWhen the pressure satisfies the formula (5), u1、u2Calculated from equation (4), i.e. u1||u2＝uhg。
8. The method for determining the safe shut-in period of the well drilling under the condition of trace gas invasion according to claim 7, wherein the process of calculating the safe shut-in period under the given condition in step S5 is as follows:
setting a time step delta t, wherein the value range of the delta t is 0.01-1 s;
estimating the variation delta P of a certain bottom hole pressure, wherein the value range of the delta P is 0.1-1 MPa;
③ initial bottom hole pressure Pw0At bottom hole pressure Pw＝Pw0Calculating the front end position h of the mixed gas-liquid column in unit time step under the condition of + delta P1End position h2Front end position h of mixed gas-liquid column in unit time step delta t1End position h2Calculated by formula (8);
pressure P at bottom of wellw＝Pw0Calculating the gas volume change delta V of the mixed gas-liquid column caused by the pressure change of the shaft under the condition of + delta PgAnd calculating the volume change delta V caused by the fluid loss of the drilling fluidfVolume change V caused by drilling fluid compressionlClδ P, volume change V due to shaft expansion and contractioncCcδ P, the sum of the three is δ V';
fifth, judge whether | δ V is satisfiedg- δ V' | < epsilon, if satisfied, to proceed to the next step; if not, the bottom hole pressure variation delta P is estimated again, and the third step is returned;
wherein epsilon has a value in the range of 10-3～10-5；
At bottom hole pressure Pw＝Pw0Calculating the pressure distribution of the shaft under the condition of + delta P;
seventhly, judging whether the integrity of the shaft is damaged or not, and if the integrity of the shaft is damaged, obtaining a drilling safety period T ═ Σ dt; if not, the next step is carried out;
determining whether the front end of the mixed gas-liquid column reaches the wellhead or not, if yes, h2Not less than H, obtaining well drilling safetyThe period T is equal to Σ dt, and the calculation is finished; if h is not satisfied2And if the value is more than or equal to H, continuing the calculation in the next time step, and returning to the step two.
9. The method for determining the safe shut-in period of the well drilling under the condition of trace gas invasion according to claim 8, wherein in the step (iv), δ Vgδ V' is determined by formula (9):
Figure FDA0003602605310000041
in the formula (9), δ VgGas volume change m of mixed gas-liquid column caused by pressure change of well bore3；Vg1Well bore gas volume, m, before time step δ t3；T1-the temperature, c, of the bubble at the local site before the time step δ t; p is1-the local pressure, Pa, of the bubble before the time step δ t; z1-the local compression factor of the bubble before the time step δ t, dimensionless; t is2-the temperature of the bubble at the location, c, after the time step δ t; p2-the local pressure, Pa, of the bubble after the time step δ t; z is a linear or branched member2-the local compression factor of the bubble after the time step δ t, dimensionless; delta VfVolume change due to drilling fluid loss, m3；VlClDelta P-volume change, m, caused by compression of drilling fluid3；VcCcDelta P-volume change, m, caused by wellbore expansion3；VlVolume of drilling fluid in wellbore, m3；VcWell bore volume, m3；ClDrilling fluid compressibility, Pa-1；Cc-coefficient of compressibility of the wellbore, Pa-1；
Volume change delta V caused by drilling fluid lossfThe hydrostatic fluid loss equation is used as shown in equation (10):
Figure FDA0003602605310000051
in formula (10): f. ofsm-solid content in drilling fluid,%; f. ofsc-solid content in filter cake,%; k isfPermeability of filter cake, 10-3μm2(ii) a S-area of open hole section of shaft, m2。
10. The method for determining the safe well shut-in period of the drilling under the micro gas invasion condition according to the claim 8, wherein in the step (c), when the pressure at the weak point of the well shaft and the pressure at the well head meet the following expression, the integrity of the well shaft is not damaged; otherwise, it is destroyed;
Figure FDA0003602605310000052
in formula (11): pf-wellbore pressure, Pa, at wellbore weak points; pfshoe-formation fracture pressure at the casing shoe, Pa; p isfweak-formation fracture/loss pressure, Pa, at the formation weak point of the open hole; p isc-wellhead back pressure, Pa; pcmax-the pressure bearing capacity of the wellhead equipment, Pa; p isri-internal pressure resistance of the bushing, Pa.
CN202210407997.7A 2022-04-19 2022-04-19 Method for determining safe well shut-in period of drilling under trace gas invasion condition Pending CN114638179A (en)

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