CN113027426B

CN113027426B - Method, device and storage medium for determining leakage pressure

Info

Publication number: CN113027426B
Application number: CN201911251176.3A
Authority: CN
Inventors: 刘天恩; 周宝义; 张海军; 郝晨; 廖兴松; 付大其; 王立辉; 孙景涛; 阴启武; 赵腾; 卓绿燕; 郭秋霞
Original assignee: Petrochina Co Ltd
Current assignee: Petrochina Co Ltd
Priority date: 2019-12-09
Filing date: 2019-12-09
Publication date: 2023-11-28
Anticipated expiration: 2039-12-09
Also published as: CN113027426A

Abstract

The application discloses a method and a device for determining leakage pressure and a storage medium, and belongs to the technical field of drilling of oil and gas fields. The method comprises the steps of obtaining the safe annular pressure and the corresponding safe bearing depth of each drilling well section in a plurality of wellbores, determining the fracture pressure and the annular pressure consumption of each sampling point in the plurality of sampling points in the depth direction in each drilling well section in each wellbore, determining the leakage pressure of each sampling point in each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section, further generating a leakage pressure map of each wellbore, and determining the leakage pressure map of the wellbore to be drilled based on the leakage pressure map of each wellbore, so that the possibility of leakage of the wellbore to be drilled is avoided.

Description

Method, device and storage medium for determining leakage pressure

Technical Field

The application relates to the technical field of drilling of oil and gas fields, in particular to a leakage pressure determining method, a leakage pressure determining device and a storage medium.

Background

Lost circulation is a long-term pending major problem in the drilling process, and the occurrence of lost circulation can cause great harm to exploration and development of oil and gas fields. The lost circulation refers to the phenomenon that when the liquid column pressure of the drilling fluid in the well bore is larger than the pressure of stratum fluid, the drilling fluid leaks into the space such as stratum pores or cracks. Therefore, in order to avoid the occurrence of lost circulation, the lost circulation pressure when lost circulation occurs is determined first, and then the liquid column structure of the drilling fluid in the shaft is designed based on the lost circulation pressure, so that the liquid column pressure of the drilling fluid is controlled. Where lost pressure refers to the minimum pressure required for drilling fluid in a wellbore to enter a formation pore or fracture.

In the related art, when the leak pressure of lost circulation is determined, logging sound waves can be sent into a shaft through a sound wave generator included in the sound wave velocity logging instrument, and then the logging sound waves are received through two sound wave receivers included in the sound wave velocity logging instrument and positioned in the shaft, so that the sound wave time difference of the logging sound waves received by the two sound wave receivers can be determined, and in the process that the two sound wave receivers synchronously move along the depth direction of the shaft, the sound wave velocity logging instrument can obtain a plurality of sound wave time differences. And then the multiple acoustic time differences can be input into a parameter acquisition interface of the EQUIPOISE (pressure prediction software) to directly generate a fracture pressure curve of the shaft along the depth direction through the EQUIPOISE, so that the fracture pressure corresponding to any well depth in the shaft can be used as the leakage pressure corresponding to any well depth.

However, due to the diversity and complexity of the formation environment, i.e., the leak-off pressure corresponding to any well depth in the wellbore, may be affected not only by the fracture pressure, but also by other factors. Thus, if the burst pressure corresponding to any well depth is used as the leak pressure corresponding to any well depth, the leak pressure corresponding to any well depth is easy to have lower accuracy.

Disclosure of Invention

The application provides a method, a device and a storage medium for determining the leakage pressure, which can solve the problem of low accuracy of the leakage pressure corresponding to any well depth in a well bore. The technical scheme is as follows:

in a first aspect, a method of determining leak pressure is provided, the method comprising:

acquiring the safety annular pressure of each drilling well section and the corresponding safety bearing depth, wherein each drilling well section is included in a plurality of wellbores, the wellbores are wellbores which are drilled and put into use, the safety annular pressure is annular pressure which cannot be lost in the corresponding drilling well section, and the safety bearing depth is the depth for detecting the safety annular pressure in the corresponding wellbores;

determining the fracture pressure and annular pressure consumption of each sampling point in a plurality of sampling points in the depth direction in each drilling section in each shaft, wherein the fracture pressure refers to the pressure of fracture of a stratum of the corresponding sampling point, and the annular pressure consumption refers to the pressure drop value of drilling fluid at the corresponding sampling point;

generating a leakage pressure map of each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section;

Determining a leak-off pressure map for each of the plurality of wellbores based on the leak-off pressure map for each of the plurality of wellbores;

determining a leak-off pressure map of a wellbore of the plurality of wellbores that is closest to a location between the wellbore to be drilled as the leak-off pressure map of the wellbore to be drilled.

Optionally, the generating a leak-off pressure map of each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section, and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section includes:

for a first drilling well section, acquiring a leakage state of drilling fluid in the first drilling well section, wherein the first drilling well section refers to any drilling well section included in any well shaft in the plurality of well shafts;

and if the drilling fluid of the first drilling section is determined to be lost based on the lost circulation state, generating a lost circulation pressure map of the first drilling section based on the depth of each sampling point and the annular pressure consumption in the first drilling section.

Optionally, after the obtaining the leakage state of the drilling fluid in the first drilling section, the method further includes:

if the drilling fluid of the first drilling section is determined not to leak based on the leakage state, and sampling points with depth smaller than the safe bearing depth of the first drilling section exist in a plurality of sampling points in the first drilling section, generating a first leakage pressure curve of the first drilling section based on the safe bearing depth and the safe annular pressure;

Selecting at least one sampling point from a plurality of sampling points within the first drilling section having a depth greater than a safe bearing depth of the first drilling section;

for each sampling point in the at least one sampling point, selecting the maximum value of the fracture pressure and the annular pressure consumption of each sampling point as the leakage pressure of the corresponding sampling point;

generating a second leak-off pressure curve for the first drilling interval based on the depth and leak-off pressure of each of the at least one sampling point;

and generating a leakage pressure map of the first drilling well section according to the first leakage pressure curve and the second leakage pressure curve.

Optionally, determining the fracture pressure and annulus pressure loss at each of a plurality of sampling points in a depth direction within each respective drilling section in each wellbore comprises:

for a first drilling well section in a first well bore, acquiring the well bore diameter, the outer diameter of a drill rod and the outer diameter of a drill string of the first well bore, and the drill string length, the fluid parameter, the overburden formation pressure, the formation rock poisson ratio and the formation pore pressure of each of a plurality of sampling points in the depth direction in the first drilling well section, wherein the first well bore refers to any well bore in the plurality of well bores, the first drilling well section refers to any well section in the first well bore, and the overburden formation pressure refers to the pressure caused by the formation covered on the position of the corresponding sampling point;

Determining a fracture pressure and an annulus pressure loss for each sampling point in the first wellbore section based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length, the fluid parameters, the overburden formation pressure, the formation rock poisson ratio, and the formation pore pressure for each sampling point in the first wellbore section.

Optionally, the determining the fracture pressure and annulus pressure loss for each sampling point in the first wellbore section based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length, the fluid parameters, the overburden pressure, the formation rock poisson ratio, and the formation pore pressure for each sampling point in the first wellbore section comprises:

for a first sampling point, determining a fracture pressure of the first sampling point based on an overburden formation pressure, a formation rock poisson ratio, and a formation pore pressure of the first sampling point, the first sampling point being any sampling point within the first drilling interval;

and determining the annular pressure loss of the first sampling point based on the wellbore diameter of the first wellbore, the drill rod outer diameter and the drill string outer diameter, and the drill string length and the fluid parameters of the first sampling point.

In a second aspect, there is provided a leak pressure determination apparatus, the apparatus comprising:

the system comprises an acquisition module, a control module and a control module, wherein the acquisition module is used for acquiring the safety annular pressure of each drilling well section and the corresponding safety bearing depth of each drilling well section, wherein each drilling well section is included in a plurality of drilling shafts, the plurality of drilling shafts are drilling well completed and put into use, the safety annular pressure is the annular pressure of the corresponding drilling well section, no leakage occurs, and the safety bearing depth is the depth for detecting the safety annular pressure in the corresponding drilling well section;

the first determining module is used for determining the fracture pressure and annular pressure consumption of each sampling point in a plurality of sampling points in the depth direction in each drilling section in each shaft, wherein the fracture pressure refers to the pressure of fracture of a stratum of the corresponding sampling point, and the annular pressure consumption refers to the pressure drop value of drilling fluid at the corresponding sampling point;

the generation module is used for generating a leakage pressure map of each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section and the rupture pressure and the annular pressure consumption of each sampling point in each drilling well section;

a second determining module configured to determine a loss pressure map for each of the plurality of wellbores based on the loss pressure maps for each of the plurality of wellbores included in each of the plurality of wellbores;

And a third determining module, configured to determine a leak-off pressure map of a wellbore, which is closest to a position between the wellbores to be drilled, from the plurality of wellbores as the leak-off pressure map of the wellbore to be drilled.

Optionally, the generating module includes:

the first acquisition unit is used for acquiring the leakage state of the drilling fluid in a first drilling well section, wherein the first drilling well section refers to any drilling well section included in any one of the plurality of wellbores;

the first generation unit is used for generating a loss pressure map of the first drilling well section based on the depth of each sampling point and annular pressure loss in the first drilling well section if the loss of the drilling fluid of the first drilling well section is determined based on the loss state.

Optionally, the generating module further includes:

a second generating unit, configured to generate a first loss pressure curve of the first drilling section based on the safe bearing depth and the safe annulus pressure if it is determined that no loss of drilling fluid of the first drilling section occurs based on the loss state, and sampling points having a depth smaller than the safe bearing depth of the first drilling section exist in a plurality of sampling points in the first drilling section;

A first selection module for selecting at least one sampling point having a depth greater than a safe bearing depth of the first drilling section from a plurality of sampling points within the first drilling section;

the second selection module is used for selecting the maximum value of the fracture pressure and the annular pressure consumption of each sampling point as the leakage pressure of the corresponding sampling point for each sampling point in the at least one sampling point;

a third generation unit configured to generate a second leak-off pressure curve of the first drilling section based on a depth and a leak-off pressure of each of the at least one sampling point;

and the fourth generation unit is used for generating a leakage pressure map of the first drilling well section according to the first leakage pressure curve and the second leakage pressure curve.

Optionally, the first determining module includes:

a second obtaining unit, configured to obtain, for a first drilling section in a first wellbore, a wellbore diameter, a drill pipe outer diameter, and a drill string outer diameter of the first wellbore, and a drill string length, a fluid parameter, an overburden formation pressure, a formation rock poisson ratio, and a formation pore pressure of each of a plurality of sampling points in a depth direction in the first drilling section, where the first wellbore refers to any one of the plurality of wellbores, the first drilling section refers to any one of the wellbores, and the overburden formation pressure refers to a pressure caused by a formation that is overburden over a location where the corresponding sampling point is located;

And the first determining unit is used for determining the fracture pressure and the annular pressure consumption of each sampling point in the first drilling section based on the borehole diameter, the drill rod outer diameter and the drill string outer diameter of the first shaft, the drill string length, the fluid parameters, the overburden formation pressure, the stratum rock poisson ratio and the stratum pore pressure of each sampling point in the first drilling section.

Optionally, the first determining unit includes:

a first determining subunit, configured to determine, for a first sampling point, a fracture pressure of the first sampling point based on an overburden formation pressure, a formation rock poisson ratio, and a formation pore pressure of the first sampling point, where the first sampling point is any sampling point in the first drilling section;

a second determination subunit for determining an annulus pressure loss at the first sampling point based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length and fluid parameters of the first sampling point.

In a third aspect, there is provided a computer readable storage medium having stored therein a computer program which, when executed by a processor, implements the method of any of the first aspects provided above.

In a fourth aspect, there is provided a computer program product containing instructions which, when run on a computer, cause the computer to perform any of the methods provided in the first aspect.

The technical scheme provided by the application has the beneficial effects that at least the following steps are included:

the method comprises the steps of obtaining the safe annular pressure and the corresponding safe bearing depth of each drilling well section in each well section in a plurality of well shafts, determining the fracture pressure and the annular pressure consumption of each sampling point in the plurality of sampling points in the depth direction in each drilling well section in each well shaft, determining the leakage pressure of each sampling point in each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section, further generating the leakage pressure map of each well shaft, and determining the leakage pressure map of the well shaft to be drilled based on the leakage pressure map of each well shaft, so that the possibility of leakage of the well shaft to be drilled is avoided.

Drawings

In order to more clearly illustrate the technical solutions of the embodiments of the present application, the drawings required for the description of the embodiments will be briefly described below, and it is apparent that the drawings in the following description are only some embodiments of the present application, and other drawings may be obtained according to these drawings without inventive effort for a person skilled in the art.

FIG. 1 is a schematic flow chart of a method for determining leak pressure according to an embodiment of the present application;

FIG. 2 is a flow chart of a method for determining fracture pressure and annular pressure loss at a first sampling point according to an embodiment of the present application;

FIG. 3 is a schematic diagram of a leakage pressure determining device according to an embodiment of the present application;

fig. 4 is a block diagram of a terminal according to the present application.

Detailed Description

For the purpose of making the objects, technical solutions and advantages of the present application more apparent, the embodiments of the present application will be described in further detail with reference to the accompanying drawings.

Fig. 1 is a schematic flow chart of a leak pressure determining method according to an embodiment of the present application, where the method is applied to a leak pressure determining device, and the leak pressure determining device is built in a terminal, and the terminal may be a computer, a mobile phone, a palm computer, a tablet computer, etc. Referring to fig. 1, the method includes the following steps.

Step 101: and acquiring the safety annular pressure and the corresponding safety bearing depth of each drilling well section included in each well in the plurality of well bores.

The safety annular pressure refers to annular pressure which cannot be lost in a corresponding well drilling section, and the safety bearing depth refers to the depth of detection of the safety annular pressure in a corresponding well bore.

The drilling process of oil and gas wells is usually carried out in sections, i.e. one well bore can correspond to a plurality of well sections. And because the safety annular pressure of each drilling well section and the corresponding safety bearing depth are obtained in the same way, namely, the safety annular pressure of each drilling well section included in each well section in the plurality of well shafts and the corresponding safety bearing depth are obtained in the same way. Accordingly, a first section of the first wellbore will be described in detail below as an example.

The first well bore refers to any well bore of a plurality of well bores, and the first well drilling section refers to any well section in the first well bore. The plurality of wellbores refers to wellbores that are drilled and put into service. Because the geological conditions of the same block are similar, the possibility of lost circulation of the wellbores of the same block can be referred to each other, so that a plurality of wellbores can refer to wellbores located in the same block.

In some embodiments, the terminal may display a first parameter acquisition interface, and may then acquire the safety annular pressure and the corresponding safety bearing depth of the first drilling well section entered by the user at the first parameter acquisition interface. That is, the user may input the safety annular pressure and the corresponding safety bearing depth of the first drilling interval at the first parameter acquisition interface, such that the terminal may acquire these parameters from the first parameter acquisition interface. Of course, the terminal may also communicate with a storage device for such data to obtain the safe annular pressure and corresponding safe bearing depth of the first wellbore section from the storage device.

It should be noted that, after the first well Duan Wanzuan, a formation pressure test may be performed on the first well section to understand the pressure-bearing capacity of the first well section, that is, the safety annular pressure of the first well section, so as to avoid a phenomenon that the fluid column pressure of the fluid in the first well section is greater than the safety annular pressure and thus lost circulation occurs. The depth of the detection instrument when the stratum pressure test is carried out on the first drilling section is the safe pressure-bearing depth.

Step 102: the fracture pressure and annulus pressure loss are determined for each of a plurality of sampling points in the depth direction within each respective wellbore section.

The fracture pressure refers to the pressure of fracture of the stratum at the corresponding sampling point, and the annular pressure consumption refers to the pressure drop value of the drilling fluid at the corresponding sampling point.

Since the determination manners of the fracture pressure and the annular pressure loss of each of the plurality of sampling points in the depth direction of each drilling well section in each wellbore are the same, the determination manners of the fracture pressure and the annular pressure loss of the first sampling point are described in detail by taking the first sampling point in the first drilling well section of the first wellbore as an example through steps 1021-1023.

The first sampling point is any one of a plurality of sampling points in the depth direction along the inner edge of the first drilling section.

Step 1021: the method includes the steps of obtaining a wellbore diameter of a first wellbore, an outer diameter of a drill rod, and an outer diameter of a drill string, and a drill string length, a fluid parameter, overburden formation pressure, formation rock poisson ratio, and formation pore pressure for each of a plurality of sampling points in a depth direction within a first drilling section.

Wherein, the overburden formation pressure refers to the pressure caused by the formation that is overburden over the location of the corresponding sampling point.

In some embodiments, the terminal may display a second parameter acquisition interface to acquire the wellbore diameter of the first wellbore, the outside diameter of the drill pipe, the outside diameter of the drill string, and the length of the drill string, the fluid parameters of the first sampling point entered by the user at the second parameter acquisition interface. That is, the user may enter the wellbore diameter of the first wellbore, the outside diameter of the drill pipe, the outside diameter of the drill string, and the length of the drill string at the first sampling point, fluid parameters at the second parameter acquisition interface, such that the terminal may acquire these parameters from the second parameter acquisition interface. Of course, the terminal may also communicate with a memory device of such data to obtain from the memory device the borehole diameter of the first wellbore, the outside diameter of the drill pipe, the outside diameter of the drill string, and the length of the drill string, the fluid parameters at the first sampling point.

The fluid parameters may be determined by measurement with a six-speed rotational viscometer, and a specific method for measuring the fluid parameters with the six-speed rotational viscometer may refer to related technologies, which are not described in detail in the embodiment of the present application.

Wherein the fluid may be a drilling fluid and the fluid parameters may include annulus kick-up speed, density, displacement, plastic viscosity, yield value, popularity index, consistency coefficient and readings of a six-speed rotational viscometer of 3 r/min. The reading of the six-speed rotary viscometer of 3r/min refers to the reading on a rotating time scale when the outer cylinder of the six-speed rotary viscometer drives drilling fluid to rotate at the speed of 3 r/min.

In some embodiments, the sonic time difference detected by the sonic logging tool at the first sampling point may be input to a parameter acquisition interface of the equipiose, and the overburden formation pressure, the formation rock poisson ratio, and the formation pore pressure at the first sampling point may be determined by the equipiose. Thereafter, overburden formation pressure, formation rock poisson ratio, and formation pore pressure at the first sampling point may be obtained from the equipiose via communication between the equipiose and the terminal. Of course, the terminal may display the third parameter acquisition interface, so as to acquire the overburden formation pressure, the formation rock poisson ratio and the formation pore pressure of the first sampling point input by the user at the third parameter acquisition interface. That is, the user may enter the overburden formation pressure, the formation rock poisson's ratio, and the formation pore pressure at the first sampling point at the third parameter acquisition interface.

Step 1022: the fracture pressure of the first sampling point is determined based on the overburden pressure, the formation rock poisson ratio, and the formation pore pressure of the first sampling point.

In some embodiments, the fracture pressure of the first sampling point may be determined by equation (1) below based on the overburden pressure, the formation rock poisson ratio, and the formation pore pressure of the first sampling point:

wherein F is _g For fracture pressure, v is the Poisson's ratio of formation rock, σ _v To overburden formation pressure, P _p Is the formation pore pressure.

Of course, the burst pressure of the first sampling point may be determined by other methods, which are not limited in this embodiment of the present application.

Step 2023: the annulus pressure loss at the first sampling point is determined based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length and fluid parameters of the first sampling point.

Since the annular pressure loss at the first sampling point is related to the type and flow regime of the fluid corresponding to the first sampling point in the first wellbore section, in some embodiments, the annular pressure loss at the first sampling point may be determined by steps (1) - (3) below.

(1) And acquiring the type of the fluid corresponding to the first sampling point.

In some embodiments, the terminal may display a fourth parameter acquisition interface to acquire a type of fluid corresponding to the first sampling point input by the user at the fourth parameter acquisition interface. That is, the user may input the type of fluid corresponding to the first sampling point at the fourth parameter acquisition interface, and thus the terminal may acquire the parameters from the fourth parameter acquisition interface. Of course, the terminal may also communicate with the storage device of these data to obtain from the storage device the type of fluid corresponding to the first sampling point.

The types of fluids may include, among others, bingham fluids, power law fluids, and heba fluids.

(2) And determining the flow state of the fluid corresponding to the first sampling point based on the wellbore diameter and the drill rod outer diameter of the first wellbore, the type of the fluid corresponding to the first sampling point and the fluid parameter of the first sampling point.

When the type of fluid corresponding to the first sampling point is a bingham fluid, the fluid parameters of the first sampling point may include annulus kick-back speed, density, plastic viscosity, yield value.

In some embodiments, the reynolds number corresponding to the first sampling point may be determined based on the wellbore diameter and the drill pipe outer diameter of the first wellbore, and the annulus kick-up speed, density, plastic viscosity, yield value of the first sampling point by equation (2) below, after which the flow regime of the fluid corresponding to the first sampling point is determined to be turbulent when the reynolds number is greater than or equal to 2100, and the flow regime of the fluid corresponding to the first sampling point is determined to be laminar when the reynolds number is less than 2100.

Wherein R is _e For the Reynolds number corresponding to the first sampling point, d _h Is the diameter of the well bore, d _p Is the outer diameter of the drill rod, v _a An annulus return velocity ρ of the fluid for the first sample point _d For the density of the fluid at the first sampling point, τ _yp Yield force, μ of fluid at first sampling point _PV Is the plastic viscosity of the fluid at the first sampling point.

In other embodiments, the critical annular return rate corresponding to the first sampling point may be determined according to the following formula (3) based on the wellbore diameter of the first wellbore and the drill pipe outer diameter, as well as the density, plastic viscosity, and yield value of the first sampling point, after which the flow state of the fluid corresponding to the first sampling point is determined to be turbulent when the annular return rate of the first sampling point is greater than or equal to the critical annular return rate, and the flow state of the fluid corresponding to the first sampling point is determined to be laminar when the annular return rate of the first sampling point is less than the critical annular return rate.

Wherein v is _cr For the critical annular return speed corresponding to the first sampling point, mu _PV Is the plastic viscosity of the fluid at the first sampling point, τ _yp Yield force ρ of fluid being the first sampling point _d A density of the fluid at the first sampling point, d _h Is the diameter of the well bore, d _p Is the outer diameter of the drill rod.

When the type of fluid corresponding to the first sampling point is a power law fluid, the fluid parameters of the first sampling point may include annulus return velocity, density, popularity index, consistency coefficient.

In some embodiments, an annulus flow regime indicator corresponding to a first sampling point may be determined based on the wellbore diameter and the drill pipe outer diameter of the first wellbore, and the annulus return velocity, density, popularity index, and consistency factor of the first sampling point by the following equations (4) and (5), where the annulus flow regime indicator is greater than or equal to 808, the flow regime of the fluid corresponding to the first sampling point is determined to be turbulent, and where the annulus flow regime indicator is less than 808, the flow regime of the fluid corresponding to the first sampling point is determined to be laminar.

Wherein v is _cr For the annular critical return speed corresponding to the first sampling point, n is the popularity index of the fluid of the first sampling point, K is the consistency coefficient of the fluid of the first sampling point, ρ _d A density of the fluid at the first sampling point, d _h Is the diameter of the well bore, d _p Is the outer diameter of the drill rod, Z is an annular flow state indication value corresponding to a first sampling point, v _a The annulus upward velocity of the fluid at the first sampling point.

In other embodiments, the critical annular return rate corresponding to the first sampling point may be determined according to the above formula (4) based on the wellbore diameter of the first wellbore and the drill pipe outer diameter, as well as the density, popularity index, and consistency coefficient of the first sampling point, where the flow state of the fluid corresponding to the first sampling point is turbulent when the annular return rate of the first sampling point is greater than or equal to the critical annular return rate, and where the flow state of the fluid corresponding to the first sampling point is laminar when the annular return rate of the first sampling point is less than the critical annular return rate.

When the type of fluid corresponding to the first sampling point is a herba fluid, the fluid parameters of the first sampling point may include annulus return velocity, density, popularity index, consistency coefficient, and readings of a six-speed, six-speed rotational viscometer of 3 r/min.

In some embodiments, the reynolds number corresponding to the first sampling point may be determined by equation (6) below based on the wellbore diameter and the drill pipe outer diameter of the first wellbore, as well as the annulus return velocity, density, popularity index, consistency coefficient, and readings of the six-speed rotational viscometer 3r/min for the first sampling point, where the reynolds number is greater than or equal to 2100, the flow regime of the fluid corresponding to the first sampling point is determined to be turbulent, and where the reynolds number is less than 2100, the flow regime of the fluid corresponding to the first sampling point is determined to be laminar.

Wherein R is _e For the reynolds number corresponding to the first sampling point,n is the popularity index of the fluid at the first sampling point, d _h Is the diameter of the well bore, d _p Is the outer diameter of the drill rod, v _a An annulus return velocity ρ of the fluid for the first sample point _d For the density of the fluid at the first sampling point, K is the consistency coefficient of the fluid at the first sampling point, θ ₃ Is a reading of a six-speed rotational viscometer of 3 r/min.

(3) And determining the annular pressure loss of the first sampling point based on the wellbore diameter and the drill string outer diameter of the first wellbore, the type and flow state of the fluid corresponding to the first sampling point, the drill string length and the fluid parameters of the first sampling point.

When the type of fluid corresponding to the first sampling point is a bingham fluid and the flow state of the corresponding fluid is turbulent, the fluid parameters of the first sampling point may include density, displacement, and plastic viscosity.

In some embodiments, the annular pressure loss at the first sampling point may be determined based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, density, displacement, plastic viscosity at the first sampling point by equations (7) and (8) below:

ΔP _a ＝K _a LQ ^1.8 (8)

wherein K is _a The annular pressure consumption coefficient of the first sampling point is ρ _d Mu, the density of the fluid at the first sampling point _PV The plastic viscosity of the fluid at the first sampling point, d _h Is the diameter of the well bore, d _a Is the outer diameter of the drill string, deltaP _a The annular pressure loss of the first sampling point is L, the length of the drill string of the first sampling point is L, and Q is the displacement of the fluid of the first sampling point.

When the type of fluid corresponding to the first sampling point is a bingham fluid and the flow state of the corresponding fluid is a laminar flow, the fluid parameters of the first sampling point may include a yield value, a displacement, and a plastic viscosity.

In some embodiments, the annular pressure loss at the first sampling point may be determined based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, yield value, displacement, plastic viscosity at the first sampling point by the following equation (9):

wherein DeltaP _a Annular pressure loss, mu, for the first sampling point _PV For the plastic viscosity of the fluid at the first sampling point, Q is the displacement of the fluid at the first sampling point, L is the drill string length at the first sampling point, d _h Is the diameter of the well bore, d _a Is the outer diameter of the drill string, τ _yp Is the yield force of the fluid at the first sampling point.

When the type of fluid corresponding to the first sampling point is a power law fluid and the flow state of the corresponding fluid is turbulent, the fluid parameters of the first sampling point may include density, popularity index, and consistency coefficient.

In some embodiments, the annular pressure loss at the first sampling point may be determined based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, density, popularity index, consistency factor at the first sampling point by equations (10) and (11) as follows:

ΔP _a ＝K _a LQ ^{[14+(n-2)(1.4-lgn)]/7} (11)

wherein DeltaP _a For annular pressure loss at the first sampling point, Q is the displacement of fluid at the first sampling point, L is the drill string length at the first sampling point, d _h Is the diameter of the well bore, d _a For the drill string outer diameter, n is the popularity index of the fluid at the first sampling point, and K is the consistency coefficient of the fluid at the first sampling point.

When the type of fluid corresponding to the first sampling point is a power law fluid and the flow state of the corresponding fluid is a laminar flow, the fluid parameters of the first sampling point may include displacement, popularity index, and consistency coefficient.

In some embodiments, the annular pressure loss at the first sampling point may be determined based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, displacement, popularity index, consistency factor at the first sampling point by the following equation (12):

When the type of fluid corresponding to the first sampling point is a herbar fluid and the flow state of the corresponding fluid is turbulent, the fluid parameters of the first sampling point may include density, displacement, and reynolds number corresponding to the herbar fluid in turbulent flow.

In some embodiments, the annular pressure loss at the first sampling point may be determined by the following equations (13) and (14) based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, density, displacement, and corresponding reynolds number of the heba fluid at turbulence at the first sampling point:

wherein DeltaP _a For annular pressure loss at the first sampling point, Q is the displacement of fluid at the first sampling point, L is the drill string length at the first sampling point, d _h Is the diameter of the well bore, d _a For the outer diameter of the drill string, R _e The first sampling point is the Reynolds number of the Bach fluid corresponding to the turbulent flow.

When the type of fluid corresponding to the first sampling point is a herba fluid and the flow regime of the corresponding fluid is a laminar flow, the fluid parameters of the first sampling point may include the displacement, the popularity index, the consistency coefficient, and the readings of the six-speed rotational viscometer 3 r/min.

In some embodiments, the annular pressure loss at the first sampling point may be determined by equation (15) below based on the wellbore diameter and the drill string outer diameter of the first wellbore, and the drill string length, displacement, popularity index, consistency factor, and readings of the six-speed rotational viscometer 3r/min at the first sampling point:

wherein DeltaP _a The annular pressure loss of the first sampling point is L, the length of the drill string of the first sampling point is d _h Is the diameter of the well bore, d _a For the outer diameter of the drill string, K is the consistency coefficient of the fluid at the first sampling point, n is the popularity index of the fluid at the first sampling point, Q is the displacement of the fluid at the first sampling point, theta ₃ Is a reading of a six-speed rotational viscometer of 3 r/min.

It should be noted that, when the liquid column structure of the drilling fluid in the well bore is designed, the design of the liquid column density structure of the drilling fluid is mainly included, and in order to be convenient and intuitive, the liquid column density structure of the drilling fluid can be determined based on the leakage pressure, and the equivalent density of the leakage pressure can be directly determined. Therefore, after the annulus pressure loss at the first sampling point is determined, the annulus pressure loss may be equivalent to an annulus pressure loss equivalent density, specifically:

the well depth of the first sampling point can be obtained, and then the annular pressure loss equivalent density of the first sampling point is determined based on the well depth, the density and the annular pressure loss of the first sampling point through the following formula (16):

Wherein ECD is annular pressure consumption equivalent density of a first sampling point, ρ _d Is the firstDensity, Δp, of fluid at a sampling point _a And D is the well depth of the first sampling point.

It should be further noted that, except that the annular pressure consumption may be equivalent to the annular pressure consumption equivalent density, the safety annular pressure may also be equivalent to the safety pressure equivalent density, the fracture pressure may also be equivalent to the fracture pressure equivalent density, and the specific equivalent manner may refer to the related art, which is not described in detail in the embodiment of the present application.

Step 103: and generating a leakage pressure map of each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section.

Since the leak-off pressure maps for the individual wellbore sections in each wellbore are determined in the same manner, a leak-off pressure map for the first wellbore section is then generated, for example, by the following steps (1) -step (3).

(1) And acquiring the leakage state of the drilling fluid in the first drilling section.

In some embodiments, the terminal may obtain a loss state of drilling fluid in the first drilling interval, and determine whether the first drilling interval is lost according to the obtained loss state.

The terminal may display a fifth parameter obtaining interface, and may obtain a leakage state of drilling fluid in the first drilling section input by the user at the fifth parameter obtaining interface. That is, the user may enter the lost state of the drilling fluid within the first drilling interval at a fifth parameter acquisition interface so that the terminal may acquire these parameters from the fifth parameter acquisition interface. Of course, the terminal may also communicate with a storage device for such data to obtain from the storage device the lost state of the drilling fluid in the first drilling interval.

(2) If it is determined that the drilling fluid of the first drilling section is lost based on the lost circulation condition, a loss pressure map of the first drilling section is generated based on the depth of each sampling point and the annulus pressure loss within the first drilling section.

In some embodiments, the depth of each sampling point in the plurality of sampling points along the depth direction in the first drilling section can be obtained, then, a first right-angle coordinate system with the depth as an ordinate and the pressure value as an abscissa is established, then, corresponding coordinate points are determined in the first right-angle coordinate system according to the depth of each sampling point and the annular pressure consumption, a plurality of coordinate points are obtained, and then, the plurality of coordinate points are fitted in a curve fitting mode to obtain a curve on the first right-angle coordinate system so as to generate a leakage pressure map of the first drilling section.

It should be noted that, besides the first rectangular coordinate system with depth as ordinate and annular pressure consumption as abscissa, a first rectangular coordinate system with depth as ordinate and density value as abscissa may be also established, then corresponding coordinate points are determined in the first rectangular coordinate system according to the depth of each sampling point and annular pressure consumption equivalent density to obtain a plurality of coordinate points, and then the plurality of coordinate points are fitted in a curve fitting manner to obtain a curve on the first rectangular coordinate system so as to generate a leakage pressure map of the first drilling well section.

(3) If it is determined that no fluid loss has occurred in the first section based on the loss state, a loss pressure map of the first section is generated by steps (3 a) - (3 e) below.

(3a) A first leak-off pressure curve for the first drilling interval is generated based on the safe bearing depth and the safe annulus pressure.

Because the annular pressure of the well bore gradually increases along with the depth of the well bore, the safety annular pressure of the first drilling well section can be used as the safety annular pressure of the sampling point corresponding to any depth smaller than the safety bearing depth in the first drilling well section, that is, the safety annular pressure can be used as the leakage pressure of the sampling point corresponding to any depth smaller than or equal to the safety bearing depth.

In some embodiments, the depth of each sampling point corresponding to the safe bearing depth in the first drilling section can be obtained, then a second rectangular coordinate system taking the depth as an ordinate and taking the pressure value as an abscissa is established, corresponding coordinate points are determined in the second rectangular coordinate system according to the depth of each sampling point and the leakage pressure to obtain a plurality of coordinate points, and then the plurality of coordinate points are fitted in a curve fitting mode to obtain a curve on the second rectangular coordinate system so as to generate a first leakage pressure curve of the first drilling section.

It should be noted that the generated first leakage pressure curve may be a straight line segment along the depth direction. In addition, a second rectangular coordinate system with depth as an ordinate and density as an abscissa may be established with reference to the first rectangular coordinate system.

(3b) At least one sampling point having a depth greater than the safe bearing depth of the first wellbore section is selected from a plurality of sampling points within the first wellbore section.

The depth of any one of the plurality of sampling points of the first drilling interval may be compared to the safe bearing depth, and when the depth of any one of the sampling points is greater than the safe bearing depth, the any one of the sampling points may be determined to be one of the at least one sampling point.

(3c) For each of the at least one sampling points, a maximum of the fracture pressure and the annulus pressure loss for each sampling point is selected as the leak pressure for the corresponding sampling point.

And comparing the fracture pressure of each sampling point with the annular pressure consumption, when the fracture pressure of the corresponding sampling point is larger than the annular pressure, taking the fracture pressure as the leakage pressure of the corresponding sampling point, and when the fracture pressure of the corresponding sampling point is smaller than the annular pressure, taking the annular pressure consumption as the leakage pressure of the corresponding sampling point.

(3d) A second loss pressure curve for the first drilling section is generated based on the depth and loss pressure of each of the at least one sampling point.

In some embodiments, the depth and the leakage pressure of each sampling point in at least one sampling point may be set up, then a third rectangular coordinate system with the depth as an ordinate and the pressure value as an abscissa is established, then corresponding coordinate points are determined in the third rectangular coordinate system according to the depth and the leakage pressure of each sampling point to obtain a plurality of coordinate points, and then the plurality of coordinate points are fitted in a curve fitting manner to obtain a curve on the third rectangular coordinate system so as to generate a second leakage pressure curve of the first drilling section.

It should be noted that, referring to the first rectangular coordinate system, a third rectangular coordinate system may be established, in which the depth is the ordinate and the density value is the abscissa.

(3e) And generating a leak-off pressure map of the first wellbore section based on the first leak-off pressure curve and the second leak-off pressure curve.

In some embodiments, the second rectangular coordinate system where the first leakage pressure curve is located may be overlapped with the third rectangular coordinate system where the second leakage pressure curve is located, where the first leakage pressure curve and the second leakage pressure curve may be displayed in the same rectangular coordinate system, so as to obtain a leakage pressure map of the first drilling section.

Step 104: a leak-off pressure map for each of the plurality of wellbores is determined based on the leak-off pressure maps for each of the plurality of wellbores including the respective drilling section.

After the leak-off pressure map for each wellbore included in each wellbore has been determined by steps 101-103 described above, the leak-off pressure map for each wellbore may be determined based on the leak-off pressure maps for the respective wellbore included in each wellbore. Since the method for determining the leak-off pressure map is the same for each of the plurality of wellbores, a first wellbore will be described as an example.

In some embodiments, for a plurality of drilling well sections included in the first wellbore, the rectangular coordinate systems corresponding to the leak-off pressure maps of the plurality of drilling well sections may be overlapped, so that the leak-off pressure curve included in each drilling well section is displayed in the same rectangular coordinate system, and thus the leak-off pressure map of the first wellbore may be obtained.

Step 105: a leak-off pressure map of a wellbore of the plurality of wellbores that is closest to a location between the wellbore to be drilled is determined as the leak-off pressure map of the wellbore to be drilled.

Because the stratum environment of the same block is similar, the leakage pressure of each well bore in the same block at the same depth is similar, the leakage pressure map of the well bore closest to the position between the well bores to be drilled in the plurality of well bores can be determined as the leakage pressure map of the well bore to be drilled, the leakage pressure corresponding to any depth of the well bore to be drilled can be obtained, and the liquid column structure of the well bore to be drilled can be designed based on the leakage pressure map of the well bore to be drilled.

According to the embodiment of the application, the safety annular pressure and the corresponding safety bearing depth of each well drilling section in each well drilling section are obtained, the rupture pressure and the annular pressure consumption of each sampling point in the plurality of sampling points in the depth direction in each well drilling section are determined, then the leak-off pressure of each sampling point in each well drilling section is determined based on the safety bearing depth and the safety annular pressure of each well drilling section and the rupture pressure and the annular pressure consumption of each sampling point in each well drilling section, and then the leak-off pressure map of each well drilling section is generated, and then the leak-off pressure map of the well drilling section to be drilled is determined based on the leak-off pressure map of each well drilling section, so that the possibility of leak-off of the well drilling section to be drilled is avoided.

Fig. 3 is a schematic structural diagram of a leakage pressure determining device according to an embodiment of the present application. Referring to fig. 3, the apparatus includes:

the obtaining module 301 is configured to obtain a safety annular pressure of each drilling well section included in each of a plurality of wellbores and a corresponding safety bearing depth, where the plurality of wellbores are wellbores that are drilled and put into use, the safety annular pressure is an annular pressure that the corresponding drilling well section cannot leak, and the safety bearing depth is a depth for detecting the safety annular pressure in the corresponding wellbore;

a first determining module 302, configured to determine a fracture pressure and an annulus pressure consumption of each of a plurality of sampling points along a depth direction in each drilling section in each wellbore, where the fracture pressure refers to a pressure at which a stratum of the corresponding sampling point is fractured, and the annulus pressure consumption refers to a pressure drop value of drilling fluid at the corresponding sampling point;

a generating module 303, configured to generate a leakage pressure map of each drilling well section based on the safe bearing depth and the safe annular pressure of each drilling well section, and the fracture pressure and the annular pressure consumption of each sampling point in each drilling well section;

a second determining module 304 configured to determine a loss pressure map for each of the plurality of wellbores based on the loss pressure maps for each of the plurality of wellbores;

A third determination module 305 is configured to determine a loss pressure map of a wellbore of the plurality of wellbores that is closest to a location between the wellbores to be drilled as a loss pressure map of the wellbore to be drilled.

Optionally, the generating module includes:

the first acquisition unit is used for acquiring the leakage state of the drilling fluid in a first drilling section for a first drilling section, wherein the first drilling section refers to any drilling section included in any one of a plurality of wellbores;

Optionally, the generating module further includes:

the second generation unit is used for generating a first leakage pressure curve of the first drilling well section based on the safe pressure-bearing depth and the safe annular pressure if the drilling fluid of the first drilling well section is determined not to leak based on the leakage state, and sampling points with the depth smaller than the safe pressure-bearing depth of the first drilling well section exist in a plurality of sampling points in the first drilling well section;

a third generation unit for generating a second loss pressure curve of the first drilling section based on the depth and loss pressure of each of the at least one sampling point;

and the fourth generation unit is used for generating a leakage pressure map of the first drilling section according to the first leakage pressure curve and the second leakage pressure curve.

Optionally, the first determining module includes:

the second obtaining unit is used for obtaining the borehole diameter, the drill rod outer diameter and the drill string outer diameter of the first well bore for a first well drilling section in the first well bore, and the drill string length, the fluid parameter, the overburden formation pressure, the formation rock poisson ratio and the formation pore pressure of each of a plurality of sampling points in the depth direction in the first well drilling section, wherein the first well bore refers to any well bore in the plurality of well bores, the first well drilling section refers to any well section in the first well bore, and the overburden formation pressure refers to the pressure caused by the formation covered on the position of the corresponding sampling point;

And the first determining unit is used for determining the fracture pressure and the annular pressure consumption of each sampling point in the first drilling section based on the borehole diameter, the drill rod outer diameter and the drill string outer diameter of the first shaft and the drill string length, the fluid parameters, the overburden formation pressure, the formation rock poisson ratio and the formation pore pressure of each sampling point in the first drilling section.

Optionally, the first determining unit includes:

the first determining subunit is used for determining fracture pressure of a first sampling point based on overburden formation pressure, formation rock poisson ratio and formation pore pressure of the first sampling point, wherein the first sampling point is any sampling point in the first drilling well section;

a second determination subunit for determining an annulus pressure loss at the first sampling point based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length and fluid parameters at the first sampling point.

It should be noted that: the leak pressure determining apparatus provided in the above embodiment only illustrates the division of the above functional modules when determining the leak pressure, and in practical application, the above functional allocation may be performed by different functional modules according to needs, that is, the internal structure of the device is divided into different functional modules, so as to perform all or part of the functions described above. In addition, the leakage pressure determining device and the leakage pressure determining method provided in the foregoing embodiments belong to the same concept, and specific implementation processes thereof are detailed in the method embodiments and are not described herein again.

Fig. 4 illustrates a block diagram of a terminal 400 according to an exemplary embodiment of the present application. Referring to fig. 4, the terminal 400 may be: smart phones, tablet computers, notebook computers or desktop computers. The terminal 400 may also be referred to by other names as user equipment, portable terminal, laptop terminal, desktop terminal, etc. Referring to fig. 4, the terminal 400 may include a processor 401 and a memory 402.

Processor 401 may include one or more processing cores such as a 4-core processor, an 8-core processor, etc. The processor 401 may be implemented in at least one hardware form of DSP (Digital Signal Processing ), FPGA (Field-Programmable Gate Array, field programmable gate array), PLA (Programmable Logic Array ). The processor 401 may also include a main processor, which is a processor for processing data in an awake state, also called a CPU (Central Processing Unit ), and a coprocessor; a coprocessor is a low-power processor for processing data in a standby state. In some embodiments, the processor 401 may integrate a GPU (Graphics Processing Unit, image processor) for rendering and drawing of content required to be displayed by the display screen. In some embodiments, the processor 401 may also include an AI (Artificial Intelligence ) processor for processing computing operations related to machine learning.

Memory 402 may include one or more computer-readable storage media, which may be non-transitory. Memory 402 may also include high-speed random access memory, as well as non-volatile memory, such as one or more magnetic disk storage devices, flash memory storage devices. In some embodiments, a non-transitory computer readable storage medium in memory 402 is used to store at least one instruction for execution by processor 401 to implement a leak pressure determination method provided by a method embodiment of the present application.

In some embodiments, the terminal 400 may further optionally include: a peripheral interface 403 and at least one peripheral. The processor 401, memory 402, and peripheral interface 403 may be connected by a bus or signal line. The individual peripheral devices may be connected to the peripheral device interface 403 via buses, signal lines or a circuit board. Specifically, the peripheral device includes: at least one of radio frequency circuitry 404, a display screen 405, a positioning component 406, and a power supply 407.

Peripheral interface 403 may be used to connect at least one Input/Output (I/O) related peripheral to processor 401 and memory 402. In some embodiments, processor 401, memory 402, and peripheral interface 403 are integrated on the same chip or circuit board; in some other embodiments, either or both of the processor 401, memory 402, and peripheral interface 403 may be implemented on separate chips or circuit boards, which is not limited in this embodiment.

The Radio Frequency circuit 404 is configured to receive and transmit RF (Radio Frequency) signals, also known as electromagnetic signals. The radio frequency circuitry 404 communicates with a communication network and other communication devices via electromagnetic signals. The radio frequency circuit 404 converts an electrical signal into an electromagnetic signal for transmission, or converts a received electromagnetic signal into an electrical signal. Optionally, the radio frequency circuit 404 includes: antenna systems, RF transceivers, one or more amplifiers, tuners, oscillators, digital signal processors, codec chipsets, subscriber identity module cards, and so forth. The radio frequency circuitry 404 may communicate with other terminals via at least one wireless communication protocol. The wireless communication protocol includes, but is not limited to: the world wide web, metropolitan area networks, intranets, generation mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks, and/or WiFi (Wireless Fidelity ) networks. In some embodiments, the radio frequency circuitry 404 may also include NFC (Near Field Communication ) related circuitry, which is not limiting of the application.

The display screen 405 is used to display a UI (User Interface). The UI may include graphics, text, icons, video, and any combination thereof. When the display screen 405 is a display screen, the display screen 405 also has the ability to collect touch signals at or above the surface of the display screen 405. The touch signal may be input as a control signal to the processor 401 for processing. At this time, the display screen 405 may also be used to provide virtual buttons and/or a virtual keyboard, also referred to as soft buttons and/or a soft keyboard. In some embodiments, the display 405 may be one, providing a front panel of the terminal 400; in other embodiments, the display 405 may be at least two, and disposed on different surfaces of the terminal 400 or in a folded design; in still other embodiments, the display 405 may be a flexible display disposed on a curved surface or a folded surface of the terminal 400. Even more, the display screen 405 may be arranged in an irregular pattern that is not rectangular, i.e. a shaped screen. The display 405 may be made of LCD (Liquid Crystal Display ), OLED (Organic Light-Emitting Diode) or other materials.

The locating component 406 is used to locate the current geographic location of the terminal 400 to enable navigation or LBS (Location Based Service, location-based services). The positioning component 406 may be a positioning component based on the United states GPS (Global Positioning System ), the Beidou system of China, or the Galileo system of Russia.

The power supply 407 is used to power the various components in the terminal 400. The power supply 407 may be an alternating current, a direct current, a disposable battery, or a rechargeable battery. When the power supply 407 includes a rechargeable battery, the rechargeable battery may be a wired rechargeable battery or a wireless rechargeable battery. The wired rechargeable battery is a battery charged through a wired line, and the wireless rechargeable battery is a battery charged through a wireless coil. The rechargeable battery may also be used to support fast charge technology.

Those skilled in the art will appreciate that the structure shown in fig. 4 is not limiting of the terminal 400 and may include more or fewer components than shown, or may combine certain components, or may employ a different arrangement of components.

In the above embodiments, there is also provided a non-transitory computer readable storage medium comprising instructions for storing at least one instruction for execution by a processor to implement the method provided by the above embodiments shown in fig. 1 or fig. 2.

Embodiments of the present application also provide a computer program product comprising instructions which, when run on a computer, cause the computer to perform the method provided by the embodiments shown in fig. 1 or fig. 2 described above.

It will be understood by those skilled in the art that all or part of the steps for implementing the above embodiments may be implemented by hardware, or may be implemented by a program for instructing relevant hardware, where the program may be stored in a computer readable storage medium, and the storage medium may be a read-only memory, a magnetic disk or an optical disk, etc.

The foregoing description of the preferred embodiments of the application is not intended to limit the application to the precise form disclosed, and any such modifications, equivalents, and alternatives falling within the spirit and scope of the application are intended to be included within the scope of the application.

Claims

1. A method of determining a leak pressure, the method comprising:

generating a leak-off pressure map for each drilling interval based on the safe bearing depth and the safe annulus pressure for each drilling interval and the fracture pressure and the annulus pressure consumption for each sampling point within each drilling interval, wherein generating the leak-off pressure map for each drilling interval based on the safe bearing depth and the safe annulus pressure for each drilling interval and the fracture pressure and the annulus pressure consumption for each sampling point within each drilling interval comprises: for a first drilling well section, acquiring a leakage state of drilling fluid in the first drilling well section, wherein the first drilling well section refers to any drilling well section included in any well shaft in the plurality of well shafts; if the drilling fluid of the first drilling section is determined not to leak based on the leakage state, and sampling points with depth smaller than the safe bearing depth of the first drilling section exist in a plurality of sampling points in the first drilling section, generating a first leakage pressure curve of the first drilling section based on the safe bearing depth and the safe annular pressure; selecting at least one sampling point from a plurality of sampling points within the first drilling section having a depth greater than a safe bearing depth of the first drilling section; for each sampling point in the at least one sampling point, selecting the maximum value of the fracture pressure and the annular pressure consumption of each sampling point as the leakage pressure of the corresponding sampling point; generating a second leak-off pressure curve for the first drilling interval based on the depth and leak-off pressure of each of the at least one sampling point; generating a leak-off pressure map of the first wellbore section according to the first leak-off pressure curve and the second leak-off pressure curve;

2. The method of claim 1, wherein generating the leak-off pressure map for the respective wellbore section based on the safe bearing depth and the safe annulus pressure for the respective wellbore section and the fracture pressure and the annulus pressure consumption for each sampling point within the respective wellbore section, further comprises:

3. The method of claim 1, wherein determining the fracture pressure and annulus pressure loss for each of a plurality of sampling points in the depth direction within each respective wellbore section comprises:

4. The method of claim 3, wherein the determining the fracture pressure and annulus pressure at each sampling point within the first wellbore section based on the wellbore diameter, the drill pipe outer diameter, and the drill string outer diameter of the first wellbore, and the drill string length, the fluid parameters, the overburden pressure, the formation poisson's ratio, and the formation pore pressure at each sampling point within the first wellbore section comprises:

5. A drop-out pressure determining apparatus, the apparatus comprising:

A third determining module configured to determine a leak-off pressure map of a wellbore of the plurality of wellbores that is closest to a location between the wellbores to be drilled as the leak-off pressure map of the wellbore to be drilled;

wherein, the generating module includes:

6. The apparatus of claim 5, wherein the generating module further comprises:

7. The apparatus of claim 5, wherein the first determination module comprises:

8. A computer readable storage medium, characterized in that the storage medium has stored therein a computer program which, when executed by a processor, implements the method of any of claims 1-4.