CN110965994A - Shaft leakage detection method - Google Patents
Shaft leakage detection method Download PDFInfo
- Publication number
- CN110965994A CN110965994A CN201811130579.8A CN201811130579A CN110965994A CN 110965994 A CN110965994 A CN 110965994A CN 201811130579 A CN201811130579 A CN 201811130579A CN 110965994 A CN110965994 A CN 110965994A
- Authority
- CN
- China
- Prior art keywords
- wellbore
- location
- data
- temperature
- test
- 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.)
- Pending
Links
- 238000001514 detection method Methods 0.000 title claims abstract description 39
- 238000012360 testing method Methods 0.000 claims abstract description 52
- 230000003287 optical effect Effects 0.000 claims abstract description 43
- 238000000034 method Methods 0.000 claims abstract description 36
- 230000008569 process Effects 0.000 claims abstract description 17
- 239000013307 optical fiber Substances 0.000 claims description 18
- 239000000835 fiber Substances 0.000 claims description 15
- 238000004519 manufacturing process Methods 0.000 abstract description 6
- 230000000694 effects Effects 0.000 abstract description 4
- 239000007789 gas Substances 0.000 description 26
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 10
- 238000005516 engineering process Methods 0.000 description 6
- 150000003839 salts Chemical class 0.000 description 6
- 239000003345 natural gas Substances 0.000 description 5
- 238000010586 diagram Methods 0.000 description 2
- 239000000700 radioactive tracer Substances 0.000 description 2
- 230000002159 abnormal effect Effects 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000007664 blowing Methods 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 230000006837 decompression Effects 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
Landscapes
- Physics & Mathematics (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Geophysics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Examining Or Testing Airtightness (AREA)
Abstract
The invention discloses a shaft leakage detection method, and belongs to the field of oil and gas production. One end of a test optical cable is put into a shaft, and the other end of the test optical cable is connected with a distributed acoustic wave sensor and a distributed temperature sensor; acquiring background noise data and background temperature data of each depth position of the shaft through the sensor; relieving the pressure of the annulus between the casing and the shaft; acquiring noise data and temperature data of each depth position of the shaft in the pressure relief process through the sensor; determining a first suspected leakage position according to the background noise data and the noise data; determining a second suspected leakage position according to the background temperature data and the temperature data; determining that a leak exists in the wellbore at the first suspected leak location and the second suspected leak location when a distance between the first suspected leak location and the second suspected leak location is less than a specified value. The problem of can't confirm the degree of depth position of leakage point among the correlation technique is solved, the effect that can confirm the degree of depth position of leakage point has been reached.
Description
Technical Field
The invention relates to the field of oil and gas production, in particular to a shaft leakage detection method.
Background
In the natural gas production process, a leakage situation occurs in the well bore, and the well bore needs to be detected so as to confirm the position of the leakage point.
One wellbore leak detection method in the related art is to open a sealed wellbore, place a noise detector and a temperature detector at the bottom of the wellbore, lift the downhole noise detector and temperature detector, and perform full well detection during the lifting process of the noise detector and temperature detector.
In the process of implementing the invention, the inventor finds that the related art has at least the following problems: in the operation method, friction is caused in the process of lifting the noise detector, accurate noise data cannot be obtained, and the temperature of the shaft changes when the shaft is lowered to obtain the instrument, so that accurate temperature data cannot be obtained, and the depth position of the leakage point cannot be obtained.
Disclosure of Invention
The embodiment of the invention provides a shaft leakage detection method, which can solve the problem that the depth position of a leakage point cannot be obtained in the related technology. The technical scheme is as follows:
according to a first aspect of the invention, there is provided a wellbore leak detection method for a wellbore in a downhole casing of a gas well, the method comprising:
one end of a test optical cable is lowered into the shaft, and the distributed acoustic wave sensor and the distributed temperature sensor are connected with the other end of the test optical cable;
acquiring background noise data of each depth position of the shaft through the distributed acoustic wave sensor;
acquiring background temperature data of each depth position of the shaft through the distributed temperature sensor;
depressurizing an annulus between the casing and the wellbore;
acquiring noise data of each depth position of the shaft in the pressure relief process through the distributed acoustic wave sensor;
acquiring temperature data of each depth position of the shaft in the pressure relief process through the distributed temperature sensors;
determining a first suspected leak location from the background noise data and the noise data;
determining a second suspected leak location from the background temperature data and the temperature data;
determining that a leak exists in the wellbore at the first and second suspected leak locations when the distance between the first and second suspected leak locations is less than a specified value.
Optionally, the depressurizing an annulus between the casing and the wellbore includes:
and relieving the pressure of the annulus between the casing and the shaft until the pressure in the annulus is stable and stops.
Optionally, before the running the end of the test fiber optic cable into the wellbore, the method further comprises:
and installing a wellhead blowout preventer at the wellhead of the gas well.
Optionally, determining a first suspected leakage location according to the background noise data and the noise data includes:
determining the first location of the wellbore as the first suspected leak location when a similarity of noise in the noise data at the first location to noise in the background noise data at the first location is less than a noise threshold.
Optionally, determining a second suspected leakage location according to the background temperature data and the temperature data includes:
determining a second location of the wellbore as the second suspected leak location when a similarity of a temperature of the second location in the temperature data and a temperature of the second location in the background temperature data is less than a temperature threshold.
Optionally, the test optical cable includes at least one single-mode optical fiber, and the at least one single-mode optical fiber is connected to the distributed acoustic wave sensor.
Optionally, the test optical cable includes at least one multimode optical fiber, and the at least one multimode optical fiber is connected to the distributed temperature sensor.
Optionally, the running of one end of the test optical cable into the wellbore, the connection of the distributed acoustic sensor and the distributed temperature sensor with the other end of the test optical cable, includes:
connecting the test optical cable with an optical cable counterweight;
running one end of the test fiber optic cable into the wellbore;
and after the test optical cable and the optical cable counterweight are stable, connecting the other end of the test optical cable with the distributed acoustic wave sensor and the distributed temperature sensor.
Optionally, the running one end of the test fiber optic cable into the wellbore includes:
running an end of the test fiber optic cable into the wellbore with the end of the test fiber optic cable at a specified distance below a bottom of the wellbore.
Optionally, depressurizing an annulus between the casing and the wellbore, comprising:
and guiding the gas in the annular space to the wellhead of the gas well for releasing.
The technical scheme provided by the embodiment of the invention has the beneficial effects that at least:
one end of a test optical cable is firstly put into a shaft, a distributed acoustic wave sensor and a distributed temperature sensor are both connected with the other end of the test optical cable, acquiring background noise data and temperature data of various depth positions of a shaft through the distributed acoustic wave sensor and the distributed temperature sensor, the annulus between the casing and the shaft is decompressed, then the noise data and the temperature data of each depth position of the shaft in the decompression process are obtained through the distributed acoustic wave sensor and the distributed temperature sensor, determining a first suspected leak location based on the background noise data and the noise data, determining a second suspected leak location based on the background temperature data and the temperature data, determining that a leak exists in the wellbore at the first suspected leak location and the second suspected leak location when a distance between the first suspected leak location and the second suspected leak location is less than a specified value. The problem of can't confirm the degree of depth position of leakage point among the correlation technique is solved, the effect that can confirm the degree of depth position of leakage point has been reached.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the drawings needed to be used in the description of the embodiments will be briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present invention, and it is obvious for those skilled in the art to obtain other drawings based on these drawings without creative efforts.
FIG. 1 is a schematic diagram of an environment for implementing a method for detecting wellbore leaks, according to an embodiment of the present invention;
FIG. 2 is a flow chart of a method of wellbore leak detection according to an embodiment of the present invention;
FIG. 3 is a flow chart of another method of wellbore leak detection according to an embodiment of the present invention;
fig. 4 is a graph of distributed temperature sensor detection data according to an embodiment of the present invention.
With the above figures, certain embodiments of the invention have been illustrated and described in more detail below. The drawings and the description are not intended to limit the scope of the inventive concept in any way, but rather to illustrate it by those skilled in the art with reference to specific embodiments.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention more apparent, embodiments of the present invention will be described in detail with reference to the accompanying drawings.
At present, the salt cavern underground gas storage is a storage space for storing natural gas by utilizing a thicker salt layer or salt dome underground and manually dissolving a cavern formed in the salt layer or salt dome by water. During the operation of the salt cavern underground gas storage, if the shaft leaks, natural gas can enter an annular space between the sleeve and the shaft, and the phenomenon of annular space pressure occurs. Because the pressure-resistant grade of the sleeve is limited, if the annular pressure is overlarge, the serious potential safety hazard that the sleeve fails to cause a large amount of natural gas to leak exists. At the moment, the position of the leakage point needs to be positioned, and the leakage degree is analyzed, so that the safety production guarantee level of the gas storage is improved.
One wellbore leak detection method in the related art is to open a sealed wellbore, place a noise detector and a temperature detector at the bottom of the wellbore, and lift the downhole noise detector and temperature detector, so that the noise detector and temperature detector perform full-well detection in the lifting process.
However, in the process of implementing the present invention, the inventors found that the related art has at least the following problems: the operation method of the method firstly opens the sealed shaft when detection is carried out, so that temperature detection data is not accurate enough, friction is caused in the process of lifting the noise detector, accurate noise data cannot be obtained, and therefore the operation method cannot determine the depth position of a leakage point.
In addition, the gas tracer detection method is also not suitable for the gas storage, and natural gas can be emptied when the gas storage is used for injecting and producing gas through a pipeline, so that the leakage of a shaft of the gas storage cannot be explained by detecting the tracer, and the position of the leakage point cannot be judged.
FIG. 1 is a schematic illustration of an implementation environment of some embodiments of the invention that may include a gas well and a leak detection apparatus, wherein the gas well includes: wellhead blowout preventer 11, casing shoe 12, casing 13, annulus 14, wellbore 15. The leak detection system includes: the test optical cable 21, the optical cable counterweight 22, the single-mode optical fiber 221, the multi-mode optical fiber 222, the distributed temperature sensor 23 and the distributed acoustic wave sensor 24.
As shown, a wellhead blowout preventer 11 is installed at the wellhead of a gas well, and an end of a test cable 21 with a cable counterweight 22 is lowered into the wellbore 15 below a casing shoe 12, wherein the test cable 21 includes at least one single mode optical fiber 221 and at least one multimode optical fiber 222. At least one single mode fiber 221 in the test optical cable 21 can be connected with the distributed acoustic wave sensor 24 to form a distributed acoustic wave sensor system, and the distributed acoustic wave sensor system can acquire noise data at various depths in the well. The at least one multimode optical fiber 222 may be coupled to a distributed temperature sensor 23 to form a distributed temperature sensor system that may acquire temperature data at various depths downhole. And (3) decompressing the annular space 14 between the casing 13 and the well bore 15, and recording the detection data of the distributed acoustic wave sensor 24 and the distributed temperature sensor 23.
The embodiment of the invention provides a shaft leakage detection method, which can solve the problem that the depth position of a leakage point cannot be determined in the related technology.
FIG. 2 is a flow chart of a method of wellbore leak detection according to an embodiment of the present invention, which may include the following steps:
in step 201, one end of the test optical cable is lowered into the wellbore, and both the distributed acoustic wave sensor and the distributed temperature sensor are connected with the other end of the test optical cable.
In step 202, background noise data is acquired at various depth locations of the wellbore by distributed acoustic sensors.
In step 203, background temperature data for various depth locations of the wellbore is acquired via the distributed temperature sensors.
In step 204, the annulus between the casing and the wellbore is vented.
In step 205, noise data at various depth locations of the wellbore during pressure relief is acquired by a distributed acoustic sensor.
In step 206, temperature data of various depth positions of the shaft in the pressure relief process is obtained through the distributed temperature sensors.
In step 207, a first suspected leak location is determined based on the background noise data and the noise data.
In step 208, a second suspected leak location is determined based on the background temperature data and the temperature data.
In step 209, a determination is made that a leak exists in the wellbore at the first and second suspected leak locations when the distance between the first and second suspected leak locations is less than a specified value.
In summary, according to the wellbore leak detection method provided in the embodiments of the present invention, one end of a test optical cable is first inserted into a wellbore, a distributed acoustic sensor and a distributed temperature sensor are both connected to the other end of the test optical cable, background noise data and temperature data of each depth position of the wellbore are obtained by the distributed acoustic sensor and the distributed temperature sensor, pressure is released to an annulus between a casing and the wellbore, noise data and temperature data of each depth position of the wellbore during pressure release are obtained by the distributed acoustic sensor and the distributed temperature sensor, a first suspected leak position is determined according to the background noise data and the noise data, a second suspected leak position is determined according to the background temperature data and the temperature data, and when a distance between the first suspected leak position and the second suspected leak position is smaller than a specified value, a point of leak in the wellbore at the first suspected leak location and the second suspected leak location is determined. The problem of can't confirm the degree of depth position of leakage point among the correlation technique is solved, the effect that can confirm the degree of depth position of leakage point has been reached.
FIG. 3 is a flow chart illustrating another method of wellbore leak detection according to embodiments of the present invention, which may include:
in step 301, a wellhead blowout preventer is installed at the wellhead of a gas well.
The wellhead blowout preventer can be used for sealing a wellhead, a valve of a gas production tree of a suspected leakage well is closed before the wellhead blowout preventer is installed, and the wellhead blowout preventer is installed after the gas production tree is decompressed. Wherein the wellhead blowout preventer is also provided with a pressure gauge, and the pressure gauge can record the pressure value of the front shaft after pressure relief and the pressure value of the rear shaft after pressure relief is stable.
In step 302, a test cable is connected to the cable weight.
Because the optical cable is light in weight, one end of the optical cable which is put into the shaft can be connected with the optical cable counter weight, and the optical cable is ensured to be fast and stable after being put into the shaft.
In step 303, an end of the test fiber optic cable is lowered into the wellbore with the end of the test fiber optic cable at a specified distance below the bottom of the wellbore.
One end of the optical cable counterweight is placed in a position 6-10 meters below a casing shoe of a shaft, wherein the upper end of the casing shoe is connected with a casing, the lower end of the casing shoe is provided with a short section which is internally chamfered and is connected with a guide shoe in a thread or other modes, and the optical cable counterweight is placed below the casing shoe, so that the detection data of the detection instrument can be more comprehensive and accurate. The cable weight may also be lowered to other depths within the wellbore, and embodiments of the present invention are not limited thereto.
In step 304, after the optical cable to be tested and the optical cable counterweight are stabilized, the other end of the optical cable to be tested is connected with the distributed acoustic wave sensor and the distributed temperature sensor.
The test fiber optic cable may include at least one single mode optical fiber and at least one multimode optical fiber. The distributed acoustic wave sensor system can acquire noise data of various depths in a well. At least one multimode optical fiber can be connected with a distributed temperature sensor to form a distributed temperature sensor system, and the distributed temperature sensor system can acquire temperature data of various depths in the well. The connected distributed acoustic wave sensor and the connected distributed temperature sensor can be placed at fixed positions to obtain detection data through a test optical cable, and a test instrument in the prior art carries out data detection in the lifting process, so that the operation is complex.
In step 305, background noise data is acquired at various depth locations of the wellbore by distributed acoustic sensors.
And when the test optical cable is stable, testing the noise data of each current depth position in the shaft as background noise data.
Optionally, the distributed acoustic wave sensor may obtain noise data at different depth positions in the wellbore through an optical fiber according to a distributed sensing technology of brillouin scattering. The distributed acoustic wave sensor can be used for detecting the noise data of the position of the leakage point with small diameter and small leakage amount.
The sensing mechanism of the distributed sensing technology of brillouin scattering is to measure the frequency shift and power of brillouin scattering signals under the condition of known temperature and strain coefficient according to brillouin scattering, and the distributed sensing technology of brillouin scattering has many advantages, such as less loss, capability of avoiding electromagnetic interference, capability of transmitting among long distances and the like.
In step 306, background temperature data is obtained for each depth location of the wellbore via the distributed temperature sensors.
And when the test optical cable is stable, the temperature data of each current depth position in the test shaft is used as background temperature data.
Optionally, the distributed temperature sensor may measure temperature data of different depth positions in the wellbore on the multimode optical fiber through the optical fiber according to a distributed sensing technology of brillouin scattering. The distributed temperature sensor can be used for detecting the temperature data of the position of the leakage point with large diameter and large leakage amount.
In step 307, the annulus between the casing and the wellbore is vented.
After the background data is obtained, the pressure of the annulus between the casing and the shaft can be released, and the gas in the annulus can be released by guiding the gas to the wellhead of the gas well so as to release the pressure until the pressure in the annulus is stable and stops. The step of releasing the gas in the annular space to the wellhead of the gas well refers to the step of blowing the gas in the annular space to a platform torch at the wellhead of the gas well through a pressure relief pipeline, and the whole pressure relief process is also the detection process of the distributed sound wave sensor and the distributed temperature sensor. The pressure relief is stopped until the pressure in the annulus is stable, the time for the whole pressure relief can be recorded, the pressure relief time can also be set, for example, ten minutes for pressure relief, and the data change in the shaft in ten minutes is detected by the distributed acoustic wave sensor and the distributed temperature sensor. The embodiments of the present invention are not limited herein.
In step 308, a first suspected leak location is determined based on the background noise data and the noise data.
When the similarity of the noise in the noise data at the first location of the wellbore to the noise in the background noise data at the first location is less than a noise threshold (which may be a condition satisfied by a first suspected leak location), determining that the first location is the first suspected leak location. Wherein the first location may be any location within the wellbore. The noise threshold is a similarity or a similarity interval that can be set by a person skilled in the art according to actual situations.
In step 309, a second suspected leak location is determined based on the background temperature data and the temperature data.
When the similarity between the temperature of the second location of the wellbore in the temperature data and the temperature of the second location in the background temperature data is less than a temperature threshold (which may be a condition satisfied by the second suspected leak location), the second location is determined to be a second suspected leak location. The second location may be any location within the wellbore. The temperature threshold is a similarity or a similarity interval that can be set by a person skilled in the art according to actual situations. Fig. 4 is a detection data diagram of the distributed temperature sensor, as shown in the figure, the abscissa is temperature, the unit is celsius, the ordinate is depth, the unit is meter, the solid line is background temperature, the dotted line is temperature detected in the pressure relief process, and it can be seen that there is an abnormal protrusion t in the detected temperature data at the position of the dotted line frame k, so the depth at the position of the dotted line frame k is the second suspected leakage position.
In step 310, a determination is made that a leak exists in the wellbore at the first and second suspected leak locations when the distance between the first and second suspected leak locations is less than a specified value.
A depth location of the leak may be determined based on the first suspected leak location and the second suspected leak location.
Wherein the designated value can be a numerical value or a numerical value interval set by a person skilled in the art according to actual conditions.
The leak depth of one or more leaks in the wellbore may be determined by the manner of steps 301 through 310.
In summary, according to the wellbore leak detection method provided in the embodiments of the present invention, one end of a test optical cable is first inserted into a wellbore, a distributed acoustic sensor and a distributed temperature sensor are both connected to the other end of the test optical cable, background noise data and temperature data of each depth position of the wellbore are obtained by the distributed acoustic sensor and the distributed temperature sensor, pressure is released to an annulus between a casing and the wellbore, noise data and temperature data of each depth position of the wellbore during pressure release are obtained by the distributed acoustic sensor and the distributed temperature sensor, a first suspected leak position is determined according to the background noise data and the noise data, a second suspected leak position is determined according to the background temperature data and the temperature data, and when a distance between the first suspected leak position and the second suspected leak position is smaller than a specified value, a point of leak in the wellbore at the first suspected leak location and the second suspected leak location is determined. The problem of can't confirm the degree of depth position of leakage point among the correlation technique is solved, the effect that can confirm the degree of depth position of leakage point has been reached.
In the present invention, the terms "first" and "second" are used for descriptive purposes only and are not to be construed as indicating or implying relative importance. The term "plurality" means two or more unless expressly limited otherwise.
The above description is only exemplary of the present invention and should not be taken as limiting the invention, as any modification, equivalent replacement, or improvement made within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (10)
1. A method of wellbore leak detection for a wellbore in a downhole casing of a gas well, the method comprising:
one end of a test optical cable is lowered into the shaft, and the distributed acoustic wave sensor and the distributed temperature sensor are connected with the other end of the test optical cable;
acquiring background noise data of each depth position of the shaft through the distributed acoustic wave sensor;
acquiring background temperature data of each depth position of the shaft through the distributed temperature sensor;
depressurizing an annulus between the casing and the wellbore;
acquiring noise data of each depth position of the shaft in the pressure relief process through the distributed acoustic wave sensor;
acquiring temperature data of each depth position of the shaft in the pressure relief process through the distributed temperature sensors;
determining a first suspected leak location from the background noise data and the noise data;
determining a second suspected leak location from the background temperature data and the temperature data;
determining that a leak exists in the wellbore at the first and second suspected leak locations when the distance between the first and second suspected leak locations is less than a specified value.
2. The wellbore leak detection method of claim 1, wherein said depressurizing an annulus between the casing and the wellbore comprises:
and relieving the pressure of the annulus between the casing and the shaft until the pressure in the annulus is stable and stops.
3. The wellbore leak detection method of claim 1, wherein prior to running an end of a test cable into the wellbore, the method further comprises:
and installing a wellhead blowout preventer at the wellhead of the gas well.
4. The wellbore leak detection method of claim 1, wherein determining a first suspected leak location from the background noise data and the noise data comprises:
determining the first location of the wellbore as the first suspected leak location when a similarity of noise in the noise data at the first location to noise in the background noise data at the first location is less than a noise threshold.
5. The wellbore leak detection method of claim 1, wherein determining a second suspected leak location based on the background temperature data and the temperature data comprises:
determining a second location of the wellbore as the second suspected leak location when a similarity of a temperature of the second location in the temperature data and a temperature of the second location in the background temperature data is less than a temperature threshold.
6. The wellbore leak detection method of claim 1, wherein the test fiber optic cable comprises at least one single mode optical fiber connected to the distributed acoustic wave sensor.
7. The wellbore leak detection method of claim 1, wherein the test fiber optic cable comprises at least one multimode optical fiber, the at least one multimode optical fiber being connected to the distributed temperature sensor.
8. The wellbore leak detection method of claim 1, wherein lowering one end of a test cable into the wellbore, the distributed acoustic wave sensor and the distributed temperature sensor each being connected to the other end of the test cable comprises:
connecting the test optical cable with an optical cable counterweight;
running one end of the test fiber optic cable into the wellbore;
and after the test optical cable and the optical cable counterweight are stable, connecting the other end of the test optical cable with the distributed acoustic wave sensor and the distributed temperature sensor.
9. The wellbore leak detection method of claim 8, wherein said running an end of the test fiber optic cable into the wellbore comprises:
running an end of the test fiber optic cable into the wellbore with the end of the test fiber optic cable at a specified distance below a bottom of the wellbore.
10. The method of any of claims 1 to 9, wherein depressurizing an annulus between the casing and the wellbore comprises:
and guiding the gas in the annular space to the wellhead of the gas well for releasing.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201811130579.8A CN110965994A (en) | 2018-09-27 | 2018-09-27 | Shaft leakage detection method |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201811130579.8A CN110965994A (en) | 2018-09-27 | 2018-09-27 | Shaft leakage detection method |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CN110965994A true CN110965994A (en) | 2020-04-07 |
Family
ID=70026504
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN201811130579.8A Pending CN110965994A (en) | 2018-09-27 | 2018-09-27 | Shaft leakage detection method |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN110965994A (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN111963154A (en) * | 2020-09-01 | 2020-11-20 | 中国石油天然气股份有限公司 | Casing damage oil well leakage point identification method |
| CN114199479A (en) * | 2021-12-17 | 2022-03-18 | 山东鲁银盐穴储能工程技术有限公司 | Method for testing leakage rate of production casing |
Citations (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20090114386A1 (en) * | 2007-11-02 | 2009-05-07 | Hartog Arthur H | Systems and methods for distributed interferometric acoustic monitoring |
| CN101680295A (en) * | 2007-02-15 | 2010-03-24 | 高真工程公司 | Method and apparatus for fluid migration profiling |
| US20100219334A1 (en) * | 2009-02-27 | 2010-09-02 | Baker Hughes Incorporated | System and method for wellbore monitoring |
| CN103518123A (en) * | 2011-05-04 | 2014-01-15 | 光学感应器控股有限公司 | Integrity monitoring of conduits |
| CN105890637A (en) * | 2009-05-27 | 2016-08-24 | 希里克萨有限公司 | Method and apparatus for optical sensing |
| US20160312606A1 (en) * | 2015-04-25 | 2016-10-27 | James N. McCoy | Method for detecting leakage in an underground hydrocarbon storage cavern |
| WO2018022532A1 (en) * | 2016-07-27 | 2018-02-01 | Schlumberger Technology Corporation | Simultaneous distributed measurements on optical fiber |
| CN108222919A (en) * | 2016-12-12 | 2018-06-29 | 中国石油天然气股份有限公司 | Gas-water interface monitoring method applied to gas injection and brine discharge stage of salt cavern gas storage |
-
2018
- 2018-09-27 CN CN201811130579.8A patent/CN110965994A/en active Pending
Patent Citations (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN101680295A (en) * | 2007-02-15 | 2010-03-24 | 高真工程公司 | Method and apparatus for fluid migration profiling |
| US20090114386A1 (en) * | 2007-11-02 | 2009-05-07 | Hartog Arthur H | Systems and methods for distributed interferometric acoustic monitoring |
| US20100219334A1 (en) * | 2009-02-27 | 2010-09-02 | Baker Hughes Incorporated | System and method for wellbore monitoring |
| CN105890637A (en) * | 2009-05-27 | 2016-08-24 | 希里克萨有限公司 | Method and apparatus for optical sensing |
| CN103518123A (en) * | 2011-05-04 | 2014-01-15 | 光学感应器控股有限公司 | Integrity monitoring of conduits |
| US20160312606A1 (en) * | 2015-04-25 | 2016-10-27 | James N. McCoy | Method for detecting leakage in an underground hydrocarbon storage cavern |
| WO2018022532A1 (en) * | 2016-07-27 | 2018-02-01 | Schlumberger Technology Corporation | Simultaneous distributed measurements on optical fiber |
| CN108222919A (en) * | 2016-12-12 | 2018-06-29 | 中国石油天然气股份有限公司 | Gas-water interface monitoring method applied to gas injection and brine discharge stage of salt cavern gas storage |
Non-Patent Citations (1)
| Title |
|---|
| 刘迪等: "气井井下油管泄漏地面声波检测试验研究", 《中国安全科学学报》 * |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN111963154A (en) * | 2020-09-01 | 2020-11-20 | 中国石油天然气股份有限公司 | Casing damage oil well leakage point identification method |
| CN114199479A (en) * | 2021-12-17 | 2022-03-18 | 山东鲁银盐穴储能工程技术有限公司 | Method for testing leakage rate of production casing |
| CN114199479B (en) * | 2021-12-17 | 2024-04-16 | 山东鲁银盐穴储能工程技术有限公司 | Method for testing leakage rate of production sleeve |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US10753820B2 (en) | Integrity monitoring of conduits | |
| US20240003765A1 (en) | Method and system for detecting dynamic strain | |
| US8476583B2 (en) | System and method for wellbore monitoring | |
| US10591639B2 (en) | Methods and systems employing a flow prediction model based on acoustic activity and proppant compensation | |
| US20060115204A1 (en) | Distributed Temperature Sensing System with Remote Reference Coil | |
| US20130298665A1 (en) | System and method for monitoring strain & pressure | |
| US20120018149A1 (en) | Method of detecting fluid in-flows downhole | |
| US20130090867A1 (en) | Leakage Detection System | |
| US7753118B2 (en) | Method and tool for evaluating fluid dynamic properties of a cement annulus surrounding a casing | |
| Boone et al. | Detecting leaks in abandoned gas wells with fibre-optic distributed acoustic sensing | |
| CN110965994A (en) | Shaft leakage detection method | |
| US20160265905A1 (en) | Distributed strain monitoring for downhole tools | |
| Feherty et al. | Disposable Fibre Optic Intervention System: Case Study of Successful Leak Detection Offshore North Sea | |
| US20170284187A1 (en) | Monitoring Wireline Coupling and Distribution | |
| US20130105148A1 (en) | Hydrocarbon detection in annulus of well | |
| US20230184597A1 (en) | Coil of reference fiber for downhole fiber sensing measurement | |
| US11572752B2 (en) | Downhole cable deployment | |
| CA3141603C (en) | Distributed acoustic sensor with trackable plug | |
| WO2014058335A1 (en) | Method and apparatus for evaluating the cementing quality of a borehole | |
| CN111749684A (en) | Seal testing method | |
| WO2023060162A1 (en) | Distributed fiber optic sensing and detection systems and methods for improved drilling operations and well control | |
| CN113218591A (en) | Method, device, system and storage medium for locating leakage point of production string | |
| JP2021181965A (en) | Underground water observation device and underground water observation method |
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 | ||
| RJ01 | Rejection of invention patent application after publication | ||
| RJ01 | Rejection of invention patent application after publication |
Application publication date: 20200407 |