CN109403957B - High-pressure formation pressure acquisition method - Google Patents
High-pressure formation pressure acquisition method Download PDFInfo
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- CN109403957B CN109403957B CN201710701652.1A CN201710701652A CN109403957B CN 109403957 B CN109403957 B CN 109403957B CN 201710701652 A CN201710701652 A CN 201710701652A CN 109403957 B CN109403957 B CN 109403957B
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
Abstract
A method of high pressure formation pressure buildup, comprising: step one, after overflow of a drilling well is determined, well logging data at the initial moment of overflow are obtained; step two, respectively determining a hook load change value and an annular circulation equivalent density according to logging data; and step three, determining the formation pressure of the stratum which is drilled under high pressure according to the sectional area of the drill rod body at the wellhead, the hook load change value and the annular circulation equivalent density. The method can accurately and quickly determine the formation pressure of the stratum to be met after the well is overflowed, and is not only suitable for solving the formation pressure after the fractured high-pressure oil-gas layer overflows, but also suitable for solving the formation pressure after the high-permeability high-pressure oil-gas layer overflows.
Description
Technical Field
The invention relates to the technical field of drilling, in particular to a formation pressure acquisition method, and particularly relates to a method for acquiring formation pressure after a high-pressure gas layer overflows in the drilling process of petroleum, natural gas and unconventional energy.
Background
At present, a carbonate rock stratum (or called as a fractured carbonate rock stratum) with cracks and karst caves developing and a shale stratum with cracks and bedding developing are main objects of natural gas exploration and development in China. The safe density window of the fractured gas formation drilling is narrow, and the problems of overflow and leakage existing at the same time generally exist, so that the consequences of long drilling period, low pure drilling timeliness, high well control safety difficulty, high drilling cost and the like are caused, and the process of natural gas exploration and development is restricted. The core of safe drilling and well control is to ensure that wellbore pressure can balance formation pressure.
The probability of natural gas overflow and drilling fluid loss of a fractured gas layer is high, and the formation pressure needs to be accurately obtained firstly after the natural gas overflow and the drilling fluid loss occur. The existing stratum pressure calculation method after loss mainly comprises a static liquid level depth calculation method, a drilling tool hanging weight change calculation method and a different-displacement circulating differential pressure calculation method, and the methods are simple and practical, and the precision can meet the requirements of site construction. Conventional methods for obtaining formation pressure after flooding mainly include riser pressure gauge algorithms and casing pressure gauge algorithms. The riser pressure and the casing pressure change constantly with time after the overflow shut-in, and the conventional calculation method of the formation pressure needs to judge whether the pressure is balanced, namely the pressure reading time. The pressure reading time is determined by the intersection point of the straight line segment and the exponential segment in the riser pressure (casing pressure can be used in partial situations) and time curve after the well of the permeable reservoir is shut in. At present, the research on the pressure reading time of a fractured reservoir is not complete, and no clear pressure reading time exists, but an empirical value of 3-5min is generally adopted in field application.
Due to the influence of annular gas invasion, the method for calculating the formation pressure through the casing pipe pressure is low in precision, the calculation precision can be improved by calculating the height of the annular gas column through the shut-in overflow amount, but the gas overflow increment after shut-in is still difficult to calculate accurately. The method of calculating formation pressure by riser pressure usually assumes that gas invasion does not occur in the tool and experimental studies have shown that after flooding occurs, gas phase can enter both the annulus and the drill string, accumulating in the lower part of the drill string as it does not easily slip up the drill string. Therefore, when a back-pressure valve is not installed or fails, the degree of accumulation of the gas phase in the drill string after the occurrence of flooding is difficult to judge, which brings an uncertain factor to the method of calculating the formation pressure at the riser pressure.
Disclosure of Invention
In order to solve the above problems, the present invention provides a method for acquiring a high-pressure formation pressure, the method comprising:
step one, after overflow of a drilling well is determined, well logging data at the initial moment of overflow are obtained;
step two, respectively determining a hook load change value and annular circulation equivalent density according to the logging data;
and step three, determining the formation pressure of the drilling well in the high-pressure stratum according to the sectional area of the drill rod body at the wellhead, the hook load change value and the annular circulation equivalent density.
According to an embodiment of the invention, in the first step, hook load data, outlet flow data and/or riser pressure data of a drilled well are obtained, whether the data variation of the hook load data, the outlet flow data and/or the riser pressure data is larger than a corresponding data variation threshold value is judged, if yes, it is judged that the drilled well is suspected to overflow and is shut down, then wellhead pressure data is obtained, and whether the drilled well overflows is judged according to the wellhead pressure data.
According to an embodiment of the invention, in the second step, the annular circulation equivalent density is determined according to the drilling fluid outlet flow and the drilling fluid densities at the inlet and the outlet in the logging data.
According to an embodiment of the present invention, the third step includes:
calculating the bottom hole pressure difference during overflow according to the hook load change value and the sectional area of the drill rod body at the wellhead;
and calculating the formation pressure according to the bottom hole pressure difference and the annular circulation equivalent density.
According to an embodiment of the invention, in step three, the formation pressure is calculated according to the following expression:
Pp＝ρecdgH+ΔP＝ρecdgH+ΔHL/S
wherein the content of the first and second substances,Pprepresenting the formation pressure, pecdRepresenting annular circulation equivalent density, g representing gravity acceleration, H representing bottom hole vertical depth during overflow, deltaP representing bottom hole pressure difference, S representing cross section area of drill rod body at wellhead, deltaHLIndicating the hook load variation value.
According to an embodiment of the invention, in the third step, the method further calculates the formation pressure equivalent density according to the cross-sectional area of the drill rod body at the wellhead, the hook load change value and the annulus circulation equivalent density.
According to an embodiment of the invention, in the third step, the formation pressure equivalent density is corrected according to the additional equivalent density, so as to obtain a corrected formation pressure equivalent density.
According to an embodiment of the invention, in the third step, the corrected formation pressure equivalent density is calculated according to the following expression:
ρ′p＝ρp+Δρ＝ρecd+ΔHL/(SgH)+Δρ
where ρ isp' denotes the corrected formation pressure equivalent density, ρpRepresenting formation pressure equivalent density, ρ, without taking into account pressure decayecdRepresents annular circulation equivalent density, g represents gravity acceleration, H represents bottom hole vertical depth during overflow, S represents cross section area of drill rod body at well head, and deltaHLDenotes the hook load change value, and Δ ρ denotes the additive equivalent density.
According to one embodiment of the invention, in step three, the additional equivalent density is calculated from the in-flight pressure loss and the bottom hole sag at flooding.
According to one embodiment of the invention, the additional equivalent density is calculated according to the following expression:
Δρ＝Pv/(gH)
wherein Δ ρ represents the additive equivalent density, PvWhich represents the pressure loss on the way along the formation fluid flow to the wellbore, g represents the gravitational acceleration, and H represents the bottom hole vertical depth at flooding.
The stratum pressure obtaining method provided by the invention sets the obtaining time of the stratum pressure as the initial overflow time, and can accurately and quickly determine the stratum pressure of a drilling well meeting the stratum after the well drilling overflows.
Additional features and advantages of the invention will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by practice of the invention. The objectives and other advantages of the invention will be realized and attained by the structure particularly pointed out in the written description and claims hereof as well as the appended drawings.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required in the description of the embodiments or the prior art:
FIG. 1 is a schematic flow diagram of an implementation of a formation pressure acquisition method according to an embodiment of the invention;
FIG. 2 is a detailed flow chart of calculating formation pressure according to one embodiment of the invention;
FIG. 3 is a graphical representation of a log of a well according to one embodiment of the present invention;
FIG. 4 is a graphical representation of a log of another well according to one embodiment of the present invention.
Detailed Description
Embodiments of the present invention will be described in detail with reference to the accompanying drawings and examples, so that how to apply the technical means to solve the technical problems and achieve the technical effects can be fully understood and implemented. It should be noted that, unless otherwise specified, the embodiments and the features of the embodiments of the present invention may be combined with each other, and the technical solutions formed are within the scope of the present invention.
In the following description, for purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the embodiments of the invention. It will be apparent, however, to one skilled in the art that the present invention may be practiced without these specific details or with a specific implementation described herein.
Additionally, the steps illustrated in the flowcharts of the figures may be performed in a computer system such as a set of computer-executable instructions and, although a logical order is illustrated in the flowcharts, in some cases, the steps illustrated or described may be performed in an order different than here.
Aiming at the problems in the prior art, the invention provides a novel method for acquiring the formation pressure after high-pressure formation overflow, which can accurately and quickly acquire the formation pressure after well drilling overflow so as to guide killing operation.
Fig. 1 shows a schematic flow chart of an implementation of the formation pressure obtaining method provided by the embodiment.
In this embodiment, the method first determines whether the well is overflowing. Specifically, as shown in fig. 1, in the present embodiment, the method preferably obtains the hook load data, the outlet flow data, and the riser pressure data of the drilling well in step S101, and determines whether the data variation of the hook load data, the outlet flow data, and the riser pressure data is greater than the corresponding data variation threshold in step S102. If there is at least one data with a variation exceeding the threshold value of the variation, the method may determine in step S103 that the well is suspected to overflow, and therefore close the well immediately.
It should be noted that, in different embodiments of the present invention, the data variation threshold of each data for determining whether the well is suspected to overflow may be configured to be different reasonable values according to actual needs, and the present invention does not limit the specific value of the data variation threshold of each data.
Of course, in other embodiments of the present invention, the method may determine whether the well is suspected to have overflow in step S101 according to only one or two of the above listed items, or may determine whether the well is suspected to have overflow by combining other reasonable items, which is not limited in this disclosure.
After shut-in, the method obtains wellhead pressure (riser pressure and/or casing pressure) data as a function of shut-in time at step S104, and further determines whether the well is overflowing according to the wellhead pressure data. Specifically, the method determines whether the wellhead pressure is greater than 0 and/or still rising after shut-in step S104, wherein if the wellhead pressure is greater than 0 or still rising after shut-in, the method may determine that the well is overflowing in step S105.
It should be noted that in other embodiments of the present invention, the method may also be used in other reasonable ways to determine whether a well is overflowing, and the present invention is not limited thereto.
When the overflow of the drilling well is determined, the method immediately obtains logging data of the actual overflow initial time in step S106, and calculates and obtains the formation pressure of the drilling well in the high-pressure stratum according to the sectional area of the drill rod body at the wellhead and the logging data of the overflow initial time in the subsequent steps.
Through analysis, the bottom hole pressure of the well bore is suddenly increased at the moment of drilling a high-pressure gas layer, which causes the stress and the hydraulics of the pipe column to change. According to the stress balance of the pipe column, before and after the overflow occurs, the reduction value of the hook load is as follows:
ΔHL′＝ΔWp+ΔWmi-ΔFmo-ΔFd-ΔFv (1)
wherein, Δ HL' represents a hook load reduction value, Δ WpRepresenting the change in empty weight, Δ W, of the drill stringmiRepresenting the value of change in weight of fluid inside the drill string, Δ FmoIndicating the value of the change in buoyancy of the drill string due to the annular fluid. Δ FdAnd representing the change value of the frictional resistance of the drill string, wherein the direction of the frictional resistance is positive upwards and negative downwards. Δ FvRepresenting fluid production inside and outside the drill stringGenerating a viscosity force change value, wherein the viscosity force direction is positive upwards and negative downwards.
Since weight-on-bit is a boundary condition and is part of the drill string float weight, it is not necessary to include weight-on-bit in expression (1). When the sudden drilling meets a high-pressure stratum, the weight of a drill column, the weight of fluid in the drill column and the friction resistance of the drill column are unchanged, the viscous resistance value is very small and can be ignored, and therefore the change value of the load of the hook is as follows:
ΔHL＝-ΔHL′＝ΔFmo (2)
in the present embodiment, the hook load variation value may be regarded as an absolute value of the hook load reduction value in expression (1).
Buoyancy increase value Delta F of composite drill string composed of different sizes constructed according to the area-under-pressure methodmoIt can be calculated according to the following expression:
ΔFmo＝ΔPS (3)
wherein S represents the sectional area of the drill rod body at the wellhead, and deltaP represents the bottom hole pressure difference during overflow.
The bottom hole pressure differential Δ P may be calculated according to the following expression:
when drilling a high-pressure stratum, the flow velocity of the annulus can be suddenly increased, the annular circulation pressure loss or the annular circulation equivalent density can also be instantly increased, but the degree of gas pollution of the drilling fluid in the annulus is low, so that the stratum pressure can be calculated according to the following expression:
Pp＝ρecdgH+ΔP＝ρecdgH+ΔHL/S (5)
wherein, PpRepresenting the formation pressure, pecdThe annular circulation equivalent density is shown, g is the gravity acceleration, and H is the bottom hole vertical depth when overflowing.
Based on the above analysis, as shown in fig. 1, in this embodiment, after acquiring the logging data at the initial overflow time, the method determines the logging data according to the logging data in step S107Hook load variation Δ HLAnd annulus circulation equivalent density ρecd. In this embodiment, the method preferably determines the annular circulation equivalent density ρ from the drilling fluid outlet flow and the drilling fluid densities at the inlet and outlet included in the logging data at the initial flooding timeecd. Of course, in other embodiments of the invention, the method may also be used in other reasonable ways to determine the annular circulation equivalent density ρecdThe present invention is not limited thereto.
Subsequently, the method will change the value Δ H according to the section area S of the drill rod body at the wellhead, the hook load, based on expression (5) in step S108LAnd annulus circulation equivalent density ρecdTo determine the formation pressure of the formation being encountered. Of course, in other embodiments of the present invention, the method may also first vary the value Δ H according to the cross-sectional area S of the drill rod body at the wellhead and the hook load based on expression (4) in step S108LCalculating the bottom hole pressure difference delta P when overflowing, and then based on the expression (5), calculating the annular circulation equivalent density rho according to the bottom hole pressure difference delta PecdAnd calculating the bottom hole vertical depth H during overflow to obtain the formation pressure P of the stratum encountered by the drilling wellp。
In the present embodiment, as shown in fig. 1, the method changes the value Δ H according to the section area S of the drill rod body at the wellhead and the hook load in step S108LAnd annulus circulation equivalent density ρecdNot only can determine the formation pressure P of the drilling well encountering the formationpThe formation pressure equivalent density ρ of the formation may also be determinedp。
In particular, in the present embodiment, the method preferably calculates the formation pressure equivalent density ρ according to the following expressionp：
ρp＝ρecd+ΔHL/(SgH) (6)
When a drilling well encounters a large fracture and gas cut or flooding occurs, the formation pressure in the near wellbore zone differs from the original formation pressure by a substantially negligible amount due to the on-way pressure loss created by the fracture. If the overflow is caused by a micro fracture, the micro fracture will generate a large on-way pressure loss, and the formation pressure in the near wellbore zone will be lower than the original formation pressure, so the formation pressure calculation result needs to be corrected appropriately.
Specifically, as shown in fig. 1, in the present embodiment, the method preferably corrects the formation pressure equivalent density obtained in step S108 according to the additional equivalent density in step S109, so as to obtain a corrected formation pressure equivalent density. In this embodiment, the additional equivalent density may be a fracture formation additional equivalent density or a hypertonic formation additional equivalent density according to the difference of formation properties and the difference of in-situ pressure equivalent density generated by the formation fluid flowing to the well bore, and the invention is not limited thereto.
Wherein the method calculates the corrected formation pressure equivalent density in step S109, preferably according to the following expression:
ρ′p＝ρp+Δρ＝ρecd+ΔHL/(SgH)+Δρ (7)
wherein, ρ'pRepresenting corrected formation pressure equivalent density, ppRepresenting formation pressure equivalent density, ρ, without taking into account pressure decayecdRepresents annular circulation equivalent density, g represents gravity acceleration, H represents bottom hole vertical depth during overflow, S represents cross section area of drill rod body at well head, and deltaHLDenotes the hook load change value, and Δ ρ denotes the additive equivalent density.
In this embodiment, the method relies on the on-way pressure loss P created by formation fluid flowing to the wellbore during floodingvAnd the bottom hole vertical depth H at flooding. The method preferably calculates the on-way pressure loss P generated by formation fluid flowing under the laminar condition according to the dynamic viscosity coefficient mu of the formation fluid, the flow rate q of the formation fluid during overflow, the length l of the flowing fluid, the width b of the fracture and the height h of the fracturev。
Specifically, in this embodiment, the method preferably calculates the fracture formation additional equivalent density Δ ρ according to the following expression:
Δρ＝Pv/(gH) (8)
wherein l is greater than h, and b is greater than h.
Of course, in other embodiments of the invention, the method may be used in other reasonable ways to determine the on-way pressure loss P created during the flow of formation fluid into the wellborevAnd/or additional equivalent density Δ ρ, although the invention is not limited in this respect. For example, in one embodiment of the present invention, the value of the additional equivalent density Δ ρ may also be determined according to empirical drilling experience.
The formation pressure obtaining method provided by the embodiment is not only suitable for obtaining the formation pressure after the fractured high-pressure gas layer overflows, but also suitable for obtaining the formation pressure after the permeable high-pressure gas layer (especially the high-permeability high-pressure gas layer) overflows. It should be noted that for permeable formations, the method provided by the present embodiment requires the use of darcy's law of seepage to calculate the on-way pressure loss P of fluid flow consumptionvAnd the permeable formation add-on equivalent density Δ ρ.
It should be noted that in the present embodiment, the method preferably takes whether or not the hook load changes abruptly as a condition whether or not the lamination pressure is calculated by the method. When the drill overflows in a high-pressure air layer and the load of a big hook is suddenly reduced, the method calculates the formation pressure and the formation pressure equivalent density through the steps S106 to S109; when the hook load is not suddenly reduced, the method will determine the formation pressure and formation pressure equivalent density based on conventional methods of riser pressure and/or casing pressure.
In order to more clearly show the advantages of the formation pressure obtaining method provided by the embodiment, the formation pressure when a well overflows is obtained by using the formation pressure obtaining method provided by the embodiment. The well layer is an Ordovician eagle mountain group fractured carbonate rock oil-gas layer, and overflow is generated in the process of drilling in the eagle mountain group stratum.
Specifically, as shown in FIG. 4, forIn the well, when core drilling is carried out to the well depth of 7861.68m, overflow occurs, and the drilling fluid density at the inlet and the outlet is 1.50g/cm3The plastic viscosity was 27mPa-s, the dynamic shear force was 10Pa, and the inlet flow rate was 11.94L/s. At the initial moment of overflow, the hook load is reduced from 2298.8kN to 1815.3kN, the outlet flow is increased from 27% to 100% (44L/s), then the hook load rapidly falls back, and then the hook load is increased to 100% again. And (3) hard shut-in, casing pressure is 22MPa, the float valve works, and the pressure of the vertical pipe is 0. Because the pressure of the stratum is large and the float valve works normally, the riser cannot be used for solving the pressure, the pressure of the stratum is forced to be solved by adopting the pressure of the casing, and the calculated pressure coefficient of the stratum is about 1.80.
The bottom hole circulation equivalent density (ECD) is 1.56 g/cm calculated according to the wellhead flow rate of 11.94L/s-44L/s3-1.65g/cm3And converting the formation pressure coefficient into a formation pressure coefficient larger than 1.97 and smaller than 2.06 according to the hook load change value. After the overflow occurs, the well is firstly pressured by adopting a push-down method, and the stratum is not broken when the sleeve is pressed to 60 MPa. The density of use is 1.80g/cm3The discharge capacity of the well killing fluid is 10L/s, and the casing pressure is reduced from 42MPa to 5MPa after one-week throttling circulation. The sleeve pressure is controlled to be 3-4MPa, the use discharge capacity is 10L/s, and the density is 1.89g/cm3The well killing fluid is throttled and circulated for one week, and well killing is successful, wherein the ECD of casing pressure is considered to be 1.99g/cm3-2.01g/cm3. Adjusting the density of the drilling fluid to 1.92g/cm3The upward oil-gas velocity after 10h of rest time is 290.23m/h, the gas is discharged circularly, and the ECD is 2.00g/cm3The formation is stabilized by pressure. According to comprehensive judgment of overflow and well killing data, the well bottom pressure coefficient when 7861.68m overflows is 2.00.
As shown in fig. 4, when the well is drilled to a well depth of 7874.01m, the well is flooded again. The density of the drilling fluid outlet is greatly changed (1.87 g/cm) before overflowing3-1.90g/cm3) The inlet density is 1.92g/cm3The plastic viscosity was 34mPa-s, the dynamic shear force was 12Pa, and the displacement was 16.11L/s. The hook load is reduced from 2196.30 kN to 2024.20kN at the initial overflow moment, the outlet flow is increased from 38 percent to 100 percent, and the drilling fluid density is 1.87g/cm3-1.92g/cm3The ECD was calculated to be 2.055g/cm3-2.105g/cm3. The well shut-in is successful after 3min of overflow, the formation pressure coefficient is about 2.20 according to the conversion of the pressure of the stand pipe to 21.3MPa, and the method provided by the inventionThe lamination coefficients were calculated to be about 2.195-2.245 with an average value of 2.22. The daily gas production is large (about 358.1X 104 m) according to the initial blowout period of the well3The fact of/d) shows that 7874.01m drill encounters large-size cracks or karst caves and the connectivity of the cracks and the caves is good, and the gas pressure loss along the way is basically negligible under small gas quantity when overflow occurs.
The stratum pressure obtaining method provided by the embodiment sets the obtaining time of the stratum pressure as the initial overflow time, and can accurately and quickly determine the stratum pressure of the stratum to be met after the well drilling overflows, and the method is not only suitable for obtaining the stratum pressure of a fractured high-pressure oil-gas layer after overflowing, but also suitable for obtaining the stratum pressure of a high-permeability high-pressure oil-gas layer after overflowing.
It is to be understood that the disclosed embodiments of the invention are not limited to the particular structures or process steps disclosed herein, but extend to equivalents thereof as would be understood by those skilled in the relevant art. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting.
Reference in the specification to "one embodiment" or "an embodiment" means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Thus, the appearances of the phrase "one embodiment" or "an embodiment" in various places throughout this specification are not necessarily all referring to the same embodiment.
While the above examples are illustrative of the principles of the present invention in one or more applications, it will be apparent to those of ordinary skill in the art that various changes in form, usage and details of implementation can be made without departing from the principles and concepts of the invention. Accordingly, the invention is defined by the appended claims.
Claims (8)
1. A method of high pressure formation pressure buildup, the method comprising:
step one, after overflow of a drilling well is determined, well logging data at the initial moment of overflow are obtained;
step two, respectively determining a hook load change value and an annular circulation equivalent density according to the logging data;
thirdly, determining the formation pressure of the drilling well in the high-pressure formation according to the sectional area of the drill rod body at the wellhead, the hook load change value and the annular circulation equivalent density, wherein the third step comprises the following steps:
calculating bottom hole pressure difference during overflow according to the hook load change value and the sectional area of the drill rod body at the wellhead;
calculating the formation pressure from the bottom hole pressure differential and annular circulation equivalent density, wherein the formation pressure is calculated according to the following expression:
Pp＝ρecdgH+△P＝ρecdgH+△HL/S
wherein, PpRepresenting the formation pressure, pecdShowing annular circulation equivalent density, g showing gravity acceleration, H showing bottom hole vertical depth during overflow, DeltaP showing bottom hole pressure difference, S showing cross section area of drill rod body at well head, DeltaHLIndicating the hook load variation value.
2. The method of claim 1, wherein in the first step, hook load data, outlet flow data and/or riser pressure data of the well is obtained, whether the data variation of the hook load data, the outlet flow data and/or the riser pressure data is larger than a corresponding data variation threshold value is judged, if yes, the well is determined to be overflowed and shut down, then wellhead pressure data is obtained, and whether the well is overflowed is judged according to the wellhead pressure data.
3. The method of claim 2 wherein in step two, the annular circulation equivalent density is determined from the drilling fluid outlet flow and the drilling fluid densities at the inlet and outlet in the logging data.
4. The method according to any one of claims 1 to 3, wherein in the third step, the method further calculates the formation pressure equivalent density according to the cross-sectional area of the drill rod body at the wellhead, the hook load variation value and the annulus circulation equivalent density.
5. The method of claim 4, wherein in step three, the formation pressure equivalent density is further modified based on the additional equivalent density to obtain a modified formation pressure equivalent density.
6. The method of claim 5, wherein in step three, the modified formation pressure equivalent density is calculated according to the expression:
ρ′p＝ρp+△ρ＝ρecd+△HL/(SgH)+△ρ
wherein, ρ'pRepresenting corrected formation pressure equivalent density, ppRepresenting formation pressure equivalent density, ρ, without taking into account pressure decayecdShowing annular circulation equivalent density, g showing gravity acceleration, H showing bottom hole vertical depth during overflow, S showing cross section area of drill rod body at well head, and Delta HLThe hook load variation value is shown, and Δ ρ is the additive equivalent density.
7. The method of claim 5, wherein in step three, the additional equivalent density is calculated from the in-flight pressure loss and the bottom hole sag at flooding.
8. The method of claim 7, wherein the additional equivalent density is calculated according to the expression:
△ρ＝Pv/(gH)
wherein Δ ρ represents the additive equivalent density, PvRepresenting the earth formationThe loss of on-way pressure as the fluid flows into the wellbore, g represents the gravitational acceleration, and H represents the bottom hole sag at flooding.
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