CN107642356B - Stratum pore pressure prediction method and device based on fracture leakage information - Google Patents
Stratum pore pressure prediction method and device based on fracture leakage information Download PDFInfo
- Publication number
- CN107642356B CN107642356B CN201610576900.XA CN201610576900A CN107642356B CN 107642356 B CN107642356 B CN 107642356B CN 201610576900 A CN201610576900 A CN 201610576900A CN 107642356 B CN107642356 B CN 107642356B
- Authority
- CN
- China
- Prior art keywords
- pore pressure
- fracture
- formation pore
- determining
- pressure
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active
Links
Images
Landscapes
- Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
Abstract
The invention provides a method and a device for predicting formation pore pressure based on fracture leakage information, wherein the method for predicting the formation pore pressure based on the fracture leakage information comprises the following steps: acquiring first logging data, first fracture occurrence information, first drilling fluid loss equivalent density and first formation pore pressure of a known well in an original state of a target work area; determining a corresponding relation between the first formation pore pressure and the first fracture occurrence information; acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of a new well after the target work area is mined; and determining the second formation pore pressure of the new well according to the second logging data, the second fracture attitude information, the second drilling fluid loss equivalent density and the corresponding relation between the first formation pore pressure and the first fracture attitude information. The prediction method provided by the invention can improve the prediction accuracy of the formation pore pressure.
Description
Technical Field
The invention relates to the field of geomechanics, in particular to a method and a device for predicting formation pore pressure based on fracture leakage information.
Background
Formation pore pressure, also referred to as formation pressure or pore pressure, is the pressure that fluids (oil, gas, water) have in the pores or fractures of the formation. The accurate acquisition of the formation pore pressure plays an important role in formulating perfect drilling, well completion and oil and gas development schemes and technical measures and reducing operation risks.
At present, two methods are generally adopted for acquiring formation pore pressure, one method is to actually test the formation and directly read out the formation pore pressure in test data, and because special test equipment is needed in the actual measurement process and the test difficulty is high, the operability of the method for acquiring the formation pore pressure through actual measurement is poor. Another method is to calculate from the log data according to an empirical formula, such as: an equivalent depth method or an effective stress method, etc. are used.
However, the method for obtaining the formation pore pressure by calculation according to the empirical formula only considers the logging data, so that the accuracy of the formation pore pressure is low.
Disclosure of Invention
The invention provides a method and a device for predicting formation pore pressure based on fracture leakage information, which take formation fracture information into consideration in the acquired formation pore pressure and improve the prediction accuracy of the formation pore pressure.
The invention provides a stratum pore pressure prediction method based on fracture loss information, which comprises the following steps:
acquiring first logging data, first fracture occurrence information, first drilling fluid loss equivalent density and first formation pore pressure of a known well in an original state of a target work area;
determining a corresponding relation between the first formation pore pressure and the first fracture attitude information according to the first logging data, the first fracture attitude information, the first drilling fluid loss equivalent density and the first formation pore pressure;
acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of the new well after the target work area is mined;
and determining the second stratum pore pressure of the new well according to the second logging data, the second fracture attitude information, the second drilling fluid loss equivalent density and the corresponding relation between the first stratum pore pressure and the first fracture attitude information.
The invention provides a stratum pore pressure prediction device based on fracture leakage information, which comprises:
the system comprises a first acquisition module, a second acquisition module and a third acquisition module, wherein the first acquisition module is used for acquiring first logging data, first fracture occurrence information, first drilling fluid leakage equivalent density and first formation pore pressure of a known well in an original state of a target work area;
a first determination module, configured to determine a correspondence between the first formation pore pressure and the first fracture occurrence information according to the first logging data, the first fracture occurrence information, the first drilling fluid loss equivalent density, and the first formation pore pressure;
the second acquisition module is used for acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of the new well after the target work area is mined;
and the prediction module is used for determining the second stratum pore pressure of the new well according to the second logging data, the second fracture occurrence information, the second drilling fluid loss equivalent density and the corresponding relation between the first stratum pore pressure and the first fracture occurrence information.
The invention provides a stratum pore pressure prediction method and a stratum pore pressure prediction device based on fracture leakage information.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, and it is obvious that the drawings in the following description are some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to these drawings without creative efforts.
FIG. 1 is a flow chart of a method for predicting formation pore pressure based on fracture loss information according to an embodiment of the present invention;
FIG. 2 is a flowchart of a method for predicting formation pore pressure based on fracture loss information according to a second embodiment of the present invention;
FIG. 3 is a flowchart of a method for predicting formation pore pressure based on fracture loss information according to a third embodiment of the present invention;
fig. 4 is a schematic structural diagram of a formation pore pressure prediction apparatus based on fracture loss information according to an embodiment of the present invention;
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are some, but not all, embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
Fig. 1 is a flowchart of a method for predicting formation pore pressure based on fracture loss information according to an embodiment of the present invention. As shown in fig. 1, the method for predicting formation pore pressure based on fracture loss information according to this embodiment may include:
The known well refers to a trial production well at the initial stage of the mining of the target work area, and the related data of the known well can reflect the original state information of the target work area. First logging data of the known well, first fracture occurrence information, first drilling fluid loss equivalent density and first formation pore pressure are obtained through actual measurement.
Optionally, the first fracture occurrence information may include: crack occurrence number, crack depth, crack inclination angle and crack trend.
Alternatively, the location of a known well leak may also be obtained.
In particular, the formation pore pressure may be different for different fracture occurrence information, and thus, the formation pore pressure is correlated with the fracture occurrence information. According to the first logging data, the first fracture occurrence information, the first drilling fluid loss equivalent density and the first formation pore pressure, the corresponding relation between the first formation pore pressure and the first fracture occurrence information is determined in a forward mode, and the dependency relation between the first formation pore pressure and the first fracture occurrence information can be accurately reflected according to the corresponding relation between the first formation pore pressure and the first fracture occurrence information.
It should be noted that, the expression form of the correspondence relationship between the first formation pore pressure and the first fracture occurrence information is not limited in this embodiment, for example: may be one formula, an algorithm comprising a plurality of formulas, and the like.
And 103, acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of a new well after the mining of the target work area.
The new well refers to a well newly developed after the mining of the target work area, and the related data of the new well can reflect the state information of the target work area after the mining. And obtaining second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of the new well through actual measurement.
Optionally, the lost circulation location of the new well may also be obtained.
It should be noted that "first" and "second" in all embodiments of the present invention are only for distinguishing data corresponding to a known well from data corresponding to a new well, and the same concept has the same meaning, for example: the first logging data and the second logging data are logging data.
And step 104, determining the second stratum pore pressure of the new well according to the second logging data, the second fracture occurrence information, the second drilling fluid loss equivalent density and the corresponding relation between the first stratum pore pressure and the first fracture occurrence information.
Because it is difficult to obtain the second formation pore pressure of the new well through actual measurement, the second formation pore pressure of the new well needs to be predicted according to the existing data. Specifically, because the corresponding relationship between the first formation pore pressure and the first fracture occurrence information can accurately reflect the dependency relationship between the formation pore pressure and the fracture occurrence information, the second formation pore pressure of the new well can be determined in an 'inversion' mode according to the second logging data, the second fracture occurrence information and the second drilling fluid leakage equivalent density of the new well based on the corresponding relationship between the first formation pore pressure and the first fracture occurrence information.
In the process of predicting the second formation pore pressure of the new well, the corresponding relation between the first formation pore pressure and the first fracture occurrence information is adopted, so that the fracture leakage information is considered in the acquired second formation pore pressure of the new well, and compared with the prior art that the formation pore pressure is calculated according to an empirical formula by only considering logging data, the prediction accuracy of the formation pore pressure is improved.
The embodiment provides a stratum pore pressure prediction method based on fracture leakage information, which is characterized in that the corresponding relation between the stratum pore pressure and the fracture occurrence information is determined through the related data of a known well in the original state of a target work area, and the stratum pore pressure after the mining of the target work area can be predicted through the related data of a new well after the mining of the target work area based on the corresponding relation. According to the stratum pore pressure prediction method based on the fracture leakage information, the influence of fracture mechanical activity on the stratum pore pressure is considered in the stratum pore pressure prediction process, so that the prediction accuracy of the stratum pore pressure is improved.
Fig. 2 is a flowchart of a formation pore pressure prediction method based on fracture loss information according to a second embodiment of the present invention, which provides another implementation manner of the formation pore pressure prediction method based on fracture loss information on the basis of the first embodiment, and in particular provides a specific implementation manner of step 102 in the first embodiment. As shown in fig. 2, in the method for predicting formation pore pressure based on fracture loss information provided in this embodiment, step 102, determining a corresponding relationship between the first formation pore pressure and the first fracture occurrence information according to the first logging data, the first fracture occurrence information, the first drilling fluid loss equivalent density, and the first formation pore pressure may include:
Wherein, the first critical injection pressure refers to the formation pore pressure when the fracture slides.
Specifically, the first critical injection pressure is determined under the condition of the first formation pore pressure through first well logging data and first fracture occurrence information of a known well, namely, the first critical injection pressure is obtained through theoretical calculation according to measured data, the first drilling fluid leakage equivalent density is obtained through actual measurement, and if the difference value between the first critical injection pressure and the first drilling fluid leakage equivalent density is within a preset error range, the theoretical calculation corresponds to the measured data, so that the corresponding relation between the first formation pore pressure and the first fracture occurrence information obtained at the moment is accurate.
Wherein the preset error range is set as required.
The method for predicting the formation pore pressure based on the fracture loss information provided by the embodiment is described below by taking specific numerical values as examples.
For example: the first drilling fluid leakage equivalent density of a well X in the original state of a target work area is known to be 1.85, the first formation pore pressure is 1.79, the first critical injection pressure when the fracture is opened is determined to be 1.85 under the condition that the first formation pore pressure is 1.79 according to the first logging data and the first fracture occurrence information, and the first critical injection pressure and the first drilling fluid leakage equivalent density are both 1.85, so that the calculation process of the first critical injection pressure when the fracture is opened, which is determined according to the first logging data, the first fracture occurrence information and the first formation pore pressure, is considered to be correct, and the calculation process is the correct corresponding relation between the determined first formation pore pressure and the first fracture occurrence information.
Optionally, as a specific implementation manner, the step 201, determining a first critical injection pressure when the fracture opens under the condition of the first formation pore pressure according to the first logging data and the first fracture occurrence information, may include:
a first mechanical parameter of the known well is determined based on the first log data and the first formation pore pressure.
And determining the shear stress of the fracture surface and the positive stress of the fracture surface through tensor transformation according to the first mechanical parameter and the first fracture occurrence information.
According to the formula
A first critical implant pressure is determined.
Wherein S isnIs the positive stress of the crack surface,. tau.is the shear stress of the crack surface,. mu.is the sliding friction coefficient of the crack surface,
is the first critical implant pressure.
Optionally, the first mechanical parameter may include: poisson's ratio, young's modulus, internal friction coefficient, rock compressive strength, horizontal minimum principal stress, horizontal maximum principal stress, vertical stress, and direction of maximum principal stress.
The embodiment provides a stratum pore pressure prediction method based on fracture leakage information, and the prediction accuracy of stratum pore pressure can be improved.
Fig. 3 is a flowchart of a method for predicting formation pore pressure based on fracture loss information according to a third embodiment of the present invention, and this embodiment provides another implementation manner of the method for predicting formation pore pressure based on fracture loss information based on the first embodiment and the second embodiment, and particularly provides a specific implementation manner of step 104 in the first embodiment. As shown in fig. 3, in the method for predicting formation pore pressure based on fracture leakage information according to this embodiment, in step 104, determining a second formation pore pressure of a new well according to the second logging data, the second fracture occurrence information, the second drilling fluid leakage equivalent density, and the corresponding relationship between the first formation pore pressure and the first fracture occurrence information, which may include:
and 301, determining a second critical injection pressure when the fracture is opened under the condition of the first formation pore pressure according to the second logging data and the second fracture occurrence information.
This step is similar to the principle of step 201 in the second embodiment, and is not described herein again.
Wherein the second critical injection pressure refers to the formation pore pressure when the fracture slips.
The preset error range is similar to the principle in the second embodiment, and is not described herein again.
And 303, if the difference between the second critical injection pressure and the second drilling fluid loss equivalent density exceeds a preset error range, reducing the first formation pore pressure, and repeatedly executing the steps of determining the second critical injection pressure and judging whether the second critical injection pressure exceeds the preset error range according to the reduced first formation pore pressure until the difference between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, and determining the first formation pore pressure at the moment as the second formation pore pressure of the new well.
Specifically, the second critical injection pressure is determined under the condition of the first formation pore pressure of the known well through second logging data and second fracture occurrence information of the new well, that is, the second critical injection pressure is obtained through theoretical calculation according to measured data of the new well when the formation pore pressure is assumed to be unchanged, and if a difference between the second critical injection pressure and the second drilling fluid loss equivalent density exceeds a preset error range, the theoretical calculation does not correspond to the measured data, so that the premise that the formation pore pressure is assumed to be unchanged is not true.
Generally, after the target work area is mined, the formation pore pressure gradually decreases, so that if the difference between the second critical injection pressure and the second drilling fluid loss equivalent density exceeds a preset error range, the first formation pore pressure is reduced, the second critical injection pressure when the fracture is opened is determined again under the condition of the reduced first formation pore pressure according to the second logging data and the second fracture occurrence information, and whether the difference between the newly obtained second critical injection pressure and the second drilling fluid loss equivalent density exceeds the preset error range is determined again.
If the difference between the newly obtained second critical injection pressure and the second drilling fluid loss equivalent density exceeds the preset error range, the reduced first formation pore pressure is judged to be larger, the first formation pore pressure is continuously reduced, the steps of determining the second critical injection pressure and judging whether the difference exceeds the preset error range are repeated until the difference between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, at the moment, the theoretical calculation is corresponding to the actually measured data, and therefore the first formation pore pressure at the moment is determined as the second formation pore pressure of the new well.
Therefore, when the difference between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds the preset error range, the iterative process is carried out, based on the corresponding relation between the formation pore pressure and the fracture attitude information, the first formation pore pressure which is gradually reduced is obtained through the second logging data of the new well, the second fracture attitude information and continuous iteration, and when the difference between the second critical injection pressure and the second drilling fluid leakage equivalent density is within the preset error range, the accurate second formation pore pressure of the new well can be obtained.
Optionally, as a specific implementation, reducing the pore pressure of the first formation may include:
and reducing the first formation pore pressure according to a preset step length.
Wherein the preset step length is set according to the requirement.
The method for predicting the formation pore pressure based on the fracture loss information provided by the embodiment is described by taking specific data as an example.
For example: the pore pressure of the first stratum of the well X in the original state of the target work area is known to be 1.79, and after the target work area is mined for several years, the second drilling fluid loss equivalent density of the new well Y is 1.86, according to the second logging data and the second fracture occurrence information of the new well Y, determining a second critical injection pressure when the fracture is opened under the condition that the first formation pore pressure is 1.79, if the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density is 1.86 and exceeds a preset error range, reducing the first formation pore pressure according to a preset step length of 0.02, namely, the iterative operation is carried out according to the pore pressure of the first stratum being 1.77, 1.75 and 1.73 … in sequence, when the pore pressure of the first formation is 1.71, the second critical injection pressure is 1.86, the second critical injection pressure and the second drilling fluid leakage equivalent density are both 1.86, the difference is within a preset error range, the first formation pore pressure at this time, 1.71, is determined as the second formation pore pressure for the new well.
Optionally, after step 302, the method may further include:
and if the difference value between the second critical injection pressure and the second drilling fluid loss equivalent density is within a preset error range, determining the first formation pore pressure as the second formation pore pressure of the new well.
Specifically, if the difference between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, it indicates that the theoretical calculation corresponds to the measured data, and the formation pore pressure is unchanged, so the first formation pore pressure is determined as the second formation pore pressure of the new well.
The embodiment provides a stratum pore pressure prediction method based on fracture leakage information, and the prediction accuracy of stratum pore pressure can be improved.
Fig. 4 is a schematic structural diagram of a formation pore pressure prediction apparatus based on fracture leakage information according to an embodiment of the present invention, which is used to execute the formation pore pressure prediction method based on fracture leakage information according to any one of fig. 1 to 3. As shown in fig. 4, the apparatus for predicting formation pore pressure based on fracture loss information according to this embodiment may include:
the first obtaining module 11 is configured to obtain first logging data, first fracture occurrence information, first drilling fluid loss equivalent density, and first formation pore pressure of a known well in an original state of a target work area.
The first determining module 12 is configured to determine a corresponding relationship between the first formation pore pressure and the first fracture occurrence information according to the first logging data, the first fracture occurrence information, the first drilling fluid loss equivalent density, and the first formation pore pressure.
And the second obtaining module 13 is configured to obtain second logging data of a new well after the target work area is mined, second fracture occurrence information, and a second drilling fluid loss equivalent density.
And the prediction module 14 is configured to determine a second formation pore pressure of the new well according to the second logging data, the second fracture occurrence information, the second drilling fluid loss equivalent density, and a corresponding relationship between the first formation pore pressure and the first fracture occurrence information.
Optionally, the first determining module 12 may include: a first calculation unit and a first determination unit.
And the first calculation unit is used for determining a first critical injection pressure when the fracture is opened under the condition of the first formation pore pressure according to the first logging data and the first fracture occurrence information.
The first determining unit is used for determining that the first formation pore pressure and the first fracture occurrence information have a correct corresponding relation if the difference value between the first critical injection pressure and the first drilling fluid loss equivalent density is within a preset error range.
Optionally, the first computing unit is specifically configured to:
a first mechanical parameter of the known well is determined based on the first log data and the first formation pore pressure.
And determining the shear stress of the fracture surface and the positive stress of the fracture surface through tensor transformation according to the first mechanical parameter and the first fracture occurrence information.
According to the formula
A first critical implant pressure is determined. Wherein S isnIs the positive stress of the crack surface,. tau.is the shear stress of the crack surface,. mu.is the sliding friction coefficient of the crack surface,
is the first critical implant pressure.
Optionally, the prediction module 14 may include: a second calculation unit, a judgment unit and a prediction unit.
And the second calculation unit is used for determining a second critical injection pressure when the fracture is opened under the condition of the first formation pore pressure according to the second logging data and the second fracture occurrence information.
And the judging unit is used for judging whether the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds a preset error range.
And the prediction unit is used for reducing the pore pressure of the first stratum when the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds a preset error range, and repeatedly executing the steps of determining the second critical injection pressure and judging whether the second critical injection pressure exceeds the preset error range according to the reduced pore pressure of the first stratum until the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density is within the preset error range, and determining the first stratum pore pressure at the moment as the second stratum pore pressure of the new well.
Optionally, the prediction unit is further configured to:
and when the difference value between the second critical injection pressure and the second drilling fluid loss equivalent density is within a preset error range, determining the first formation pore pressure as the second formation pore pressure of the new well.
The formation pore pressure prediction apparatus based on fracture loss information provided in this embodiment is used to execute the method provided in the method embodiment shown in fig. 1 to 3, and the technical principle and the technical effect are similar, which are not described herein again.
Finally, it should be noted that: the above embodiments are only used to illustrate the technical solution of the present invention, and not to limit the same; while the invention has been described in detail and with reference to the foregoing embodiments, it will be understood by those skilled in the art that: the technical solutions described in the foregoing embodiments may still be modified, or some or all of the technical features may be equivalently replaced; and the modifications or the substitutions do not make the essence of the corresponding technical solutions depart from the scope of the technical solutions of the embodiments of the present invention.
Claims (10)
1. A stratum pore pressure prediction method based on fracture loss information is characterized by comprising the following steps:
acquiring first logging data, first fracture occurrence information, first drilling fluid loss equivalent density and first formation pore pressure of a known well in an original state of a target work area;
determining a corresponding relation between the first formation pore pressure and the first fracture attitude information according to the first logging data, the first fracture attitude information, the first drilling fluid loss equivalent density and the first formation pore pressure;
acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of the new well after the target work area is mined;
and determining the second stratum pore pressure of the new well according to the second logging data, the second fracture attitude information, the second drilling fluid loss equivalent density and the corresponding relation between the first stratum pore pressure and the first fracture attitude information.
2. The method of claim 1, wherein the determining a correspondence between the first formation pore pressure and the first fracture pay status information from the first log data, the first fracture pay status information, the first drilling fluid loss equivalent density, and the first formation pore pressure comprises:
determining a first critical injection pressure when a fracture is opened under the condition of the first formation pore pressure according to the first logging data and the first fracture occurrence information;
and if the difference value between the first critical injection pressure and the first drilling fluid loss equivalent density is within a preset error range, determining that the first formation pore pressure and the first fracture occurrence information have a correct corresponding relation.
3. The method of claim 2, wherein determining a first critical injection pressure at which a fracture opens at the first formation pore pressure condition based on the first log data, the first fracture parturition information, comprises:
determining a first mechanical parameter of the known well from the first log data and the first formation pore pressure;
determining the shear stress of a crack surface and the normal stress of the crack surface through tensor transformation according to the first mechanical parameter and the first crack occurrence information;
according to the formula
Determining the first critical injection pressure; wherein S isnIs the positive stress of the crack surface, tau is the shear stress of the crack surface, mu is the sliding friction coefficient of the crack surface,
is the first critical implant pressure.
4. The method of claim 1, wherein the determining a second formation pore pressure for the new well from the second log data, the second fracture occurrence information, the second drilling fluid loss equivalent density, and the correspondence between the first formation pore pressure and the first fracture occurrence information comprises:
determining a second critical injection pressure when the fracture is opened under the condition of the first formation pore pressure according to the second logging data and the second fracture occurrence information;
judging whether the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds a preset error range or not;
if the difference between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds the preset error range, reducing the first formation pore pressure, and repeatedly executing the steps of determining the second critical injection pressure and judging whether the second critical injection pressure exceeds the preset error range according to the reduced first formation pore pressure until the difference between the second critical injection pressure and the second drilling fluid leakage equivalent density is within the preset error range, and determining the first formation pore pressure at the moment as the second formation pore pressure of the new well.
5. The method of claim 4, further comprising:
and if the difference value between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, determining the first formation pore pressure as the second formation pore pressure of the new well.
6. A formation pore pressure prediction device based on fracture loss information is characterized by comprising:
the system comprises a first acquisition module, a second acquisition module and a third acquisition module, wherein the first acquisition module is used for acquiring first logging data, first fracture occurrence information, first drilling fluid leakage equivalent density and first formation pore pressure of a known well in an original state of a target work area;
a first determination module, configured to determine a correspondence between the first formation pore pressure and the first fracture occurrence information according to the first logging data, the first fracture occurrence information, the first drilling fluid loss equivalent density, and the first formation pore pressure;
the second acquisition module is used for acquiring second logging data, second fracture occurrence information and second drilling fluid leakage equivalent density of the new well after the target work area is mined;
and the prediction module is used for determining the second stratum pore pressure of the new well according to the second logging data, the second fracture occurrence information, the second drilling fluid loss equivalent density and the corresponding relation between the first stratum pore pressure and the first fracture occurrence information.
7. The apparatus of claim 6, wherein the first determining module comprises: a first calculation unit and a first determination unit;
the first calculation unit is used for determining a first critical injection pressure when a fracture is opened under the condition of the first formation pore pressure according to the first logging data and the first fracture occurrence information;
the first determining unit is configured to determine that a correct corresponding relationship exists between the first formation pore pressure and the first fracture occurrence information if a difference between the first critical injection pressure and the first drilling fluid loss equivalent density is within a preset error range.
8. The apparatus according to claim 7, wherein the first computing unit is specifically configured to:
determining a first mechanical parameter of the known well from the first log data and the first formation pore pressure;
determining the shear stress of a crack surface and the normal stress of the crack surface through tensor transformation according to the first mechanical parameter and the first crack occurrence information;
according to the formula
Determining the first critical injection pressure; wherein S isnIs the positive stress of the crack surface, tau is the shear stress of the crack surface, mu is the sliding friction coefficient of the crack surface,
is the first critical implant pressure.
9. The apparatus of claim 6, wherein the prediction module comprises: a second calculation unit, a judgment unit and a prediction unit;
the second calculation unit is used for determining a second critical injection pressure when the fracture is opened under the condition of the first formation pore pressure according to the second logging data and the second fracture occurrence information;
the judging unit is used for judging whether the difference value between the second critical injection pressure and the second drilling fluid leakage equivalent density exceeds a preset error range or not;
the prediction unit is configured to reduce the first formation pore pressure when the difference between the second critical injection pressure and the second drilling fluid loss equivalent density exceeds the preset error range, and repeatedly execute the steps of determining the second critical injection pressure and determining whether the second critical injection pressure exceeds the preset error range according to the reduced first formation pore pressure until the difference between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, and determine the first formation pore pressure at this time as the second formation pore pressure of the new well.
10. The apparatus of claim 9, wherein the prediction unit is further configured to:
and when the difference value between the second critical injection pressure and the second drilling fluid loss equivalent density is within the preset error range, determining the first formation pore pressure as the second formation pore pressure of the new well.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201610576900.XA CN107642356B (en) | 2016-07-20 | 2016-07-20 | Stratum pore pressure prediction method and device based on fracture leakage information |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201610576900.XA CN107642356B (en) | 2016-07-20 | 2016-07-20 | Stratum pore pressure prediction method and device based on fracture leakage information |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN107642356A CN107642356A (en) | 2018-01-30 |
| CN107642356B true CN107642356B (en) | 2021-01-29 |
Family
ID=61108957
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN201610576900.XA Active CN107642356B (en) | 2016-07-20 | 2016-07-20 | Stratum pore pressure prediction method and device based on fracture leakage information |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN107642356B (en) |
Citations (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103089253A (en) * | 2013-01-22 | 2013-05-08 | 中国石油大学(北京) | Method using wavelet transformation to calculate formation pore pressure |
| CN104100259A (en) * | 2013-04-03 | 2014-10-15 | 中国石油天然气集团公司 | Method and device for stabilizing well wall in fine managed pressure drilling |
| CN104500054A (en) * | 2014-12-15 | 2015-04-08 | 中国石油天然气集团公司 | Method and device for determining formation pore pressure |
| CN105243210A (en) * | 2015-10-08 | 2016-01-13 | 中国石油集团川庆钻探工程有限公司 | Method for predicting formation fracturing pressure by utilizing imaging logging information |
| CN105468886A (en) * | 2014-09-04 | 2016-04-06 | 中国石油化工股份有限公司 | Method for calculating formation pressure based on petrophysical parameters |
| WO2016108813A1 (en) * | 2014-12-29 | 2016-07-07 | Halliburton Energy Services, Inc. | Fluid loss determination apparatus, methods, and systems |
Family Cites Families (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20150134258A1 (en) * | 2013-11-13 | 2015-05-14 | Schlumberger Technology Corporation | Well Pressure Control Event Detection and Prediction Method |
-
2016
- 2016-07-20 CN CN201610576900.XA patent/CN107642356B/en active Active
Patent Citations (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103089253A (en) * | 2013-01-22 | 2013-05-08 | 中国石油大学(北京) | Method using wavelet transformation to calculate formation pore pressure |
| CN104100259A (en) * | 2013-04-03 | 2014-10-15 | 中国石油天然气集团公司 | Method and device for stabilizing well wall in fine managed pressure drilling |
| CN105468886A (en) * | 2014-09-04 | 2016-04-06 | 中国石油化工股份有限公司 | Method for calculating formation pressure based on petrophysical parameters |
| CN104500054A (en) * | 2014-12-15 | 2015-04-08 | 中国石油天然气集团公司 | Method and device for determining formation pore pressure |
| WO2016108813A1 (en) * | 2014-12-29 | 2016-07-07 | Halliburton Energy Services, Inc. | Fluid loss determination apparatus, methods, and systems |
| CN105243210A (en) * | 2015-10-08 | 2016-01-13 | 中国石油集团川庆钻探工程有限公司 | Method for predicting formation fracturing pressure by utilizing imaging logging information |
Non-Patent Citations (2)
| Title |
|---|
| 压力衰竭地层井漏预测技术研究;胡莎莎;《中国优秀硕士论文全文期刊库（工程科技I辑）》;20150615;第9-31页 * |
| 基于历史数据和随钻信息预测地层压力的理论及应用研究;何雷;《中国优秀硕士论文全文期刊库（工程科技I辑）》;20140815(第8期);第18-52页 * |
Also Published As
| Publication number | Publication date |
|---|---|
| CN107642356A (en) | 2018-01-30 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US10605074B2 (en) | Mapping of fracture geometries in a multi-well stimulation process | |
| US9741106B2 (en) | Computed tomography (CT) systems and methods analyzing rock property changes resulting from a treatment | |
| US10253613B2 (en) | Guided drill system for oil reservoir drilling | |
| CN109655903B (en) | Shale layer transverse wave velocity prediction method and system | |
| EA014144B1 (en) | Method and apparatus for predicting the hydrocarbon production of a well location | |
| CN106917623B (en) | Method and device for predicting stability of well wall of well | |
| US20160069181A1 (en) | Systems and Methods for Cement Evaluation | |
| US10385659B2 (en) | Evaluation of production performance from a hydraulically fractured well | |
| US20180320493A1 (en) | Automated upscaling of relative permeability using fractional flow in systems comprising disparate rock types | |
| CN110470581A (en) | Determine the method, apparatus and storage medium of reservoir stress sensitive degree | |
| CN111963149B (en) | Post-fracturing stratum pressure solving method taking earth stagnation amount pressurization into consideration | |
| CN107642356B (en) | Stratum pore pressure prediction method and device based on fracture leakage information | |
| US11333013B2 (en) | Segmentation of time-frequency signatures for automated pipe defect discrimination | |
| CN116106139A (en) | Method for measuring shear strength of natural cracks under temperature difference condition | |
| AU2012382975B2 (en) | Method and apparatus for formation tester data interpretation with diverse flow models | |
| CN111241652A (en) | Method and device for determining viscosity of crude oil in stratum | |
| WO2015065453A1 (en) | Determining pressure within a sealed annulus | |
| CN111624662B (en) | Speed field correction method, device and equipment | |
| CA2929912C (en) | System and method for stress inversion via image logs and fracturing data | |
| CN113495295B (en) | Weak-connectivity fracture-cavity reservoir identification method, device, equipment and storage medium | |
| RU2731013C2 (en) | Method of short-term hydrodynamic analysis of horizontal wells and wells with formation hydraulic fracturing at unsteady filtration mode | |
| CN115749763A (en) | Method and device for determining underground leakage rate | |
| CN116223338A (en) | Crack permeability evaluation method and system based on flat model experiment | |
| CN118091786A (en) | Method and device for correcting linear density of cracks based on underground logging data | |
| CN114065097A (en) | Reservoir permeability determination method, system, equipment and readable storage medium |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| GR01 | Patent grant | ||
| GR01 | Patent grant |