US3566970A - Method of injecting treating liquids into well tubing - Google Patents
Method of injecting treating liquids into well tubing Download PDFInfo
- Publication number
- US3566970A US3566970A US798998A US3566970DA US3566970A US 3566970 A US3566970 A US 3566970A US 798998 A US798998 A US 798998A US 3566970D A US3566970D A US 3566970DA US 3566970 A US3566970 A US 3566970A
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- United States
- Prior art keywords
- tubing
- pressure
- liquid
- valve
- gas
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/02—Equipment or details not covered by groups E21B15/00 - E21B40/00 in situ inhibition of corrosion in boreholes or wells
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10S166/00—Wells
- Y10S166/902—Wells for inhibiting corrosion or coating
Definitions
- This invention relates to the production of oils and gases. More particularly .thiS invention is :1 method of injecting liquids into a tubing bore from the casing under controlled conditions.
- this invention is a new method for introducing liquids, for any desired purpose, into a tubing from the casing under controlled conditions.
- this inven tion can be used to inject corrosion inhibitors, to inject liquids to prevent the deposition of elemental sulfur on tubing walls, and to inject alcohol to prevent the formation of hydrocarbon hydrates.
- the invention will be described below with regard to its use in injecting corrosion inhibitors into the tubing.
- Oct. 6, 1953 discloses a method and apparatus for preventing corrosion in a well containing a well tubing and a well casing.
- an excessive volume of liquid corrosion inhibiting chemidal is required in the practice of the method disclosed by Carlisle and it necessary to remove the differential pressure injection valve for resetting if the pressure in thetubing varies.
- This invention may be used in a casedwell containing a tub ing having an injection valve and a packer below the injection valve which is expanded into contact with the casing; If
- gas is introduced into said annulus.
- the gas may be introduced before the corrosion inhibiting chemicalQThen pump pressure is applied sufficiently high to force corrosion inhibiting chemical into the tubing through the injection valve against the pressure in the tubing.
- FIG. 1 is a schematic view partly in section usein] in explaining ournew method for introducing. liquids into well tubing.
- a well bore indicated generally by the numeral 10 is shown drilled from the earths surface 12 and extending downwardly to somepoint below the earth's surface.
- a casing 14 has been formed within the well bore 10.
- a tubing 20 is connected to the wellhead 22.
- Tubing 20 extends from the wellhead 22 downwardly to a point adjacent the subsurface producing formation 18.
- An injection valve 24 is connected to the tubing 20 by means of a valve mounting means 26.
- the injection valve 24 may be a conventional injection valve readily available on the market.
- the injection valve24 may be a differential pressure valve similar tothat disclosed in the Carlisle et al. U.S.Pat. No. 2,654,436, issued Oct. 6, 1953.
- the packer 28 is mounted on the tubing 20at a point on the tubing 20 below the injection valve 241m: oils and/or gases produced from subsurface formation 18 flow through perforations 16, upwardly through the tubing 20 to the casing head 22 and then through theproduction line 30 controlled by valve 32.
- the produced fluids usually contain highly corrosive materials such as hydrogen sulfide and carbon dioxide which badly damage the subsurface equipment such as the tubing 20 in a very short time unless checked by proper treatment.
- the corrosion inhibiting chemical is introduced into the tubing-casing annulus 34by means of liquid line 36 and line introducedinto the tubing-casing annulus 34 by way of gasline 48'and line 38controlled by gas valve 50. It is not necessary that the gas be introduced after the corrosion inhibiting chemical. If desired the gas may be introduced before the corrosion inhibiting chemical or simultaneously.
- the gas pressure plus the weightof the fluid column must be greater than the. pressure setting of the differential pressure valve 24plus the average flowing tubing pressure.
- the differential pressure valve setting can be initially established in accordance with the expected average flowing tubing pressure. The pressure settingcan only;be changed by removing the valve, resetting it, and replacingthe valve on the tubing 20. This is costly and time consuming.
- tubing-casing annulus 34 is substantially full of liquid
- inject the corrosion inhibitingchernical into the tubing may be such that it is outside of the range of operation of the pump.
- the differentialpressure valve 24 must be. removed
- the average flowing tubing'pressure of the well may be such that if the tubing-casing annulus 34 is substantially full of liquid, a valve setting sufficiently great to hold up the liquid column may not be physically possible to build into the valve. Under these conditions,
- partial gaseous fillof the annular space is absolutely .necessa ry.
- casing annulus 34 can be varied by compressing or rarefying the gas column.
- the pressureof the gas column is increased by opening valve 50 and feeding more gas into the annulus 345
- the pressure of the :gas column may be decreased byopening;
- valve 50 and bleeding some of the gas from the annulus 34. It is not necessary to remove the differential pressure valve 24 to adjust the setting of the valve.
- Another advantage'of this invention results from the fact that the gaseous cushion is a poor heat conductor compared to liquids and solids. Therefore, the production flowing up tubing loses much less heat to the surrounding areas than it would if the tubing-casing annulus were completely full of liquid.
- the insulating effect of the gas enveloping the tubing prevents loss of heat from the uppermost end of the tubing 20. Temperature and pressure conditions within the tubing are maintained such that hydrocarbon hydrate compounds are prevented from forming and sulfur in elemental or compound form is not deposited on the inside of the tubing.
- a method of injecting treating liquids into a cased well with tubing placed therein having a normally closed injection valve which opens when the pressure in the tubing-casing annulus exceeds the pressure in the tubing by a predetermined amount and a packer below the injection valve expanded into contact with the casing comprising the steps of:
- a method in accordance with claim 1 wherein the amount of liquid and gas introduced provides a liquid column extending to a level above the injection valve and substantially below the top of the tubing-casing annulus and a gas column extending from the top of said liquid column to the top of said annulus, whereby said gas column insulates said tubing and prevents heat loss in the upper portion of said tubing.
- a method of injecting treating liquids into a case well with tubing placed therein having a normally closed differential pressure valve which opens when the pressure in the tubing-casing annulus exceeds the pressure in the tubing by a predetermined amount and a packer below the differential pressure valve expanded into contact with the casing comprising the steps of:
Abstract
This disclosure is of a method of introducing liquids into well tubing. The tubing has an injection valve and a packer located below the injection valve and expanded into contact with the casing. The liquid to be introduced into the tubing and a gas are introduced into the tubing-casing annulus. The gas pressure forces the liquid into the tubing through the injection valve against the pressure of the production within the tubing. The gas pressure may be varied to compensate for variations in tubing pressure.
Description
I United States Patent 72 Inventors MorganL-Crow; 2,889,276 6/1959 Barrettetal 252/8.55(E) RobertW.McQueen,Dallas,Tex. 3,190,357 6/1965 Kirk 166/312 21 Appl.N0. 798,998 3,193,016 7/1965 Knox 166/224x [22] Filed 11991311969 3,348,614 10/1967 Sinc1airetal.... 166/310 45] Patented Manz, 1971 3,424,249 l/1969 Hambyetal 166/304 [73] Assignee Dresser lndustries,lnc. OTHER REFERENCES Dallas,Tex;
[54] METHOD OF INJECTING TREATING LIQUIDS Muir, PD. Organic Inhibitors in Oil & Gas 1., Feb. 15, 1954,pp. 143 and 145-147. (Copy in 166-244C) Primary Examiner-Ian A. Calvert Attorneys- Robert W. Mayer, Daniel Rubin, Peter J. Murphy, Frank S. Troidl, Roy L. Van Winkle, William E. Johnson, Jr. and Roderick W. Mac Donald PATENIED m 2 I971 INVENTORS MORGAN IL. CROW ROBERT WfMcQUEEN ATTORNEY METHOD OF INJECTIN G TREATING LIQUIDSINTO WELL TUBING BACKGROUND OF THE INVENTION This invention relates to the production of oils and gases. More particularly .thiS invention is :1 method of injecting liquids into a tubing bore from the casing under controlled conditions.
Briefly, this invention is a new method for introducing liquids, for any desired purpose, into a tubing from the casing under controlled conditions. As specific examples, this inven tion can be used to inject corrosion inhibitors, to inject liquids to prevent the deposition of elemental sulfur on tubing walls, and to inject alcohol to prevent the formation of hydrocarbon hydrates. The invention will be described below with regard to its use in injecting corrosion inhibitors into the tubing.
It is highly important in the production of oils and gases to minimize corrosion caused by corrosive material produced along with the oils and gases. For example, hydrogen sulfide and carbon dioxide are often constituents of produced oil and.
gas. Unless protected against, hydrogen sulfide and carbon dioxide would soondamage equipment in .well bores to such an extent the equipment would be unusable.
It is common in the oil and gas industry to use a corrosion inhibiting chemical for minimizing the corrosive effects of materials such as hydrogen sulfide and carbon dioxide. Various corrosion inhibiting chemical tools have beendevised and various methods for injecting the corrosion inhibitingchemi cal into or on the subsurface equipmenthave beenfdevised.
For example, the Carlisle et al. US. Pat. No. 2,654,436, issued.
Oct. 6, 1953, discloses a method and apparatus for preventing corrosion in a well containing a well tubing and a well casing. However, an excessive volume of liquid corrosion inhibiting chemidal is required in the practice of the method disclosed by Carlisle and it necessary to remove the differential pressure injection valve for resetting if the pressure in thetubing varies.
SUMMARY-OF THE INVENTION This invention may be used in a casedwell containing a tub ing having an injection valve and a packer below the injection valve which is expanded into contact with the casing; If
of gas is introduced into said annulus. If desired, the gas may be introduced before the corrosion inhibiting chemicalQThen pump pressure is applied sufficiently high to force corrosion inhibiting chemical into the tubing through the injection valve against the pressure in the tubing.
It is common for the pressure due to production of oils and gases to vary within the tubing. With previous methods it is often necessary to remove thedifferential pressure injection valve and adjust saidvalve when the inside tubing pressure varies beyond a predetermined limit. An important feature of this invention is that the gas pressure exerted against the corrosion inhibiting chemical column is varied to compensate for variations in tubingpressure. Therefore, the differential pressure valve need not, be removed even. though variations in pressure should occur within the tubing;
The invention as well as its many advantages will be further understood by reference to the following detailed description and single FIG. which is a schematic view partly in section usein] in explaining ournew method for introducing. liquids into well tubing. 1
Referring to the drawing, a well bore indicated generally by the numeral 10 is shown drilled from the earths surface 12 and extending downwardly to somepoint below the earth's surface. A casing 14 has been formed within the well bore 10.
' Perforations lfihave been provided through the casing 14 to permit the passage of oils and/or, gases from the producing subsurface formation l8.
A tubing 20 is connected to the wellhead 22.. Tubing 20 extends from the wellhead 22 downwardly to a point adjacent the subsurface producing formation 18.
An injection valve 24 is connected to the tubing 20 by means of a valve mounting means 26. The injection valve 24 may be a conventional injection valve readily available on the market. For example, the injection valve24 may be a differential pressure valve similar tothat disclosed in the Carlisle et al. U.S.Pat. No. 2,654,436, issued Oct. 6, 1953.
The packer 28 is mounted on the tubing 20at a point on the tubing 20 below the injection valve 241m: oils and/or gases produced from subsurface formation 18 flow through perforations 16, upwardly through the tubing 20 to the casing head 22 and then through theproduction line 30 controlled by valve 32. The produced fluids usually contain highly corrosive materials such as hydrogen sulfide and carbon dioxide which badly damage the subsurface equipment such as the tubing 20 in a very short time unless checked by proper treatment.
The corrosion inhibiting chemical is introduced into the tubing-casing annulus 34by means of liquid line 36 and line introducedinto the tubing-casing annulus 34 by way of gasline 48'and line 38controlled by gas valve 50. It is not necessary that the gas be introduced after the corrosion inhibiting chemical. If desired the gas may be introduced before the corrosion inhibiting chemical or simultaneously.
In order to inject the liquid inhibitor 42 through the differential pressure valve 24, the gas pressure plus the weightof the fluid column (liquid and gas) must be greater than the. pressure setting of the differential pressure valve 24plus the average flowing tubing pressure. The differential pressure valve setting can be initially established in accordance with the expected average flowing tubing pressure. The pressure settingcan only;be changed by removing the valve, resetting it, and replacingthe valve on the tubing 20. This is costly and time consuming.
If the tubing-casing annulus 34 is substantially full of liquid,
the weight of the fluid column cannot be varied because liquid is incompressible. Conventional injection pumps are designed to operate within a predetermined pressure range. If the average flowing tubing pressure should vary above or below a .predetermined pressure range, the required pump pressure to.
inject the corrosion inhibitingchernical into the tubing may be such that it is outside of the range of operation of the pump. Thus, the differentialpressure valve 24 must be. removed,
reset, and replacedJEven more important, the average flowing tubing'pressure of the well. may be such that if the tubing-casing annulus 34 is substantially full of liquid, a valve setting sufficiently great to hold up the liquid column may not be physically possible to build into the valve. Under these conditions,
partial gaseous fillof the annular space is absolutely .necessa ry.
Gas is compressible. Therefore, in practicing our new.
method if the average flowing tubing pressure varies above or below a predetermined pressure range, the pressure exerted by the column of liquids and gases at valve 24in the tubing.-
casing annulus 34 can be varied by compressing or rarefying the gas column. The pressureof the gas column is increased by opening valve 50 and feeding more gas into the annulus 345 The pressure of the :gas column may be decreased byopening;
Another advantage'of this invention results from the fact that the gaseous cushion is a poor heat conductor compared to liquids and solids. Therefore, the production flowing up tubing loses much less heat to the surrounding areas than it would if the tubing-casing annulus were completely full of liquid. The insulating effect of the gas enveloping the tubing prevents loss of heat from the uppermost end of the tubing 20. Temperature and pressure conditions within the tubing are maintained such that hydrocarbon hydrate compounds are prevented from forming and sulfur in elemental or compound form is not deposited on the inside of the tubing.
It is to be understood that various modifications may be made to the described method without departing from the scope of the appended claims.
The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:
We claim:
1. A method of injecting treating liquids into a cased well with tubing placed therein having a normally closed injection valve which opens when the pressure in the tubing-casing annulus exceeds the pressure in the tubing by a predetermined amount and a packer below the injection valve expanded into contact with the casing comprising the steps of:
Introducing a treating liquid into the tubing-casing annulus whereby said liquid fills said annulus to a level above said injection valve and substantially below the top of said annulus; and
introducing a gas into said annulus whereby a portion of the liquid is forced through said valve into the tubing against the pressure in the tubing.
2. A method in accordance with claim 1 wherein the liquid includes a corrosion inhibiting chemical.
3. A method in accordance with claim 1 wherein the liquid includes an alcohol.
4. A method in accordance with claim 1 wherein the amount of liquid and gas introduced provides a liquid column extending to a level above the injection valve and substantially below the top of the tubing-casing annulus and a gas column extending from the top of said liquid column to the top of said annulus, whereby said gas column insulates said tubing and prevents heat loss in the upper portion of said tubing.
5. A method in accordance with claim 4 with the additional step of:
varying the pressure of the gas column in response to variations in tubing pressure whereby the pressure exerted at the valve by the combined liquid and gas columns compensates for variations in tubing pressure.
6. A method in accordance with claim 1 wherein the liquid includes a solvent.
7. A method of injecting treating liquids into a case well with tubing placed therein having a normally closed differential pressure valve which opens when the pressure in the tubing-casing annulus exceeds the pressure in the tubing by a predetermined amount and a packer below the differential pressure valve expanded into contact with the casing comprising the steps of:
introducing sufficient liquid into the tubing-casing annulus to fill said annulus up to the level above the inlet of the differential pressure valve and substantially below the top of the tubing-casing annulus;
thereafter introducing gas into said annulus at a pressure sufficient to force a portion of said liquid through said valve into the tubing against the pressure in the tubing; and
varying the gas pressure in response to variations in tubing pressure to maintain the liquid pressure at the valve sufficient to force the liquid through the valve into the tubing.
Claims (6)
- 2. A method in accordance with claim 1 wherein the liquid includes a corrosion inhibiting chemical.
- 3. A method in accordance with claim 1 wherein the liquid includes an alcohol.
- 4. A method in accordance with claim 1 wherein the amount of liquid and gas introduced provides a liquid column extending to a level above the injection valve and substantially below the top of the tubing-casing annulus and a gas column extending from the top of said liquid column to the top of said annulus, whereby said gas Column insulates said tubing and prevents heat loss in the upper portion of said tubing.
- 5. A method in accordance with claim 4 with the additional step of: varying the pressure of the gas column in response to variations in tubing pressure whereby the pressure exerted at the valve by the combined liquid and gas columns compensates for variations in tubing pressure.
- 6. A method in accordance with claim 1 wherein the liquid includes a solvent.
- 7. A method of injecting treating liquids into a case well with tubing placed therein having a normally closed differential pressure valve which opens when the pressure in the tubing-casing annulus exceeds the pressure in the tubing by a predetermined amount and a packer below the differential pressure valve expanded into contact with the casing comprising the steps of: introducing sufficient liquid into the tubing-casing annulus to fill said annulus up to the level above the inlet of the differential pressure valve and substantially below the top of the tubing-casing annulus; thereafter introducing gas into said annulus at a pressure sufficient to force a portion of said liquid through said valve into the tubing against the pressure in the tubing; and varying the gas pressure in response to variations in tubing pressure to maintain the liquid pressure at the valve sufficient to force the liquid through the valve into the tubing.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US79899869A | 1969-02-13 | 1969-02-13 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| US3566970A true US3566970A (en) | 1971-03-02 |
Family
ID=25174795
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| US798998A Expired - Lifetime US3566970A (en) | 1969-02-13 | 1969-02-13 | Method of injecting treating liquids into well tubing |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US3566970A (en) |
| FR (1) | FR2031394A1 (en) |
Cited By (11)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3675720A (en) * | 1970-07-08 | 1972-07-11 | Otis Eng Corp | Well flow control system and method |
| US4031955A (en) * | 1976-01-20 | 1977-06-28 | Baker Oil Tools, Inc. | Down hole inhibitor injector |
| US4103743A (en) * | 1976-10-29 | 1978-08-01 | Thomas L. Moran | Method and means of treating water wells |
| US4326585A (en) * | 1980-02-19 | 1982-04-27 | Baker International Corporation | Method and apparatus for treating well components with a corrosion inhibiting fluid |
| US4347899A (en) * | 1980-12-19 | 1982-09-07 | Mobil Oil Corporation | Downhold injection of well-treating chemical during production by gas lift |
| US4625803A (en) * | 1985-05-20 | 1986-12-02 | Shell Western E&P Inc. | Method and apparatus for injecting well treating liquid into the bottom of a reservoir interval |
| US4694908A (en) * | 1986-10-27 | 1987-09-22 | Camco, Incorporated | Method and apparatus of injecting fluid into a well conduit by coil tubing |
| US5188179A (en) * | 1991-12-23 | 1993-02-23 | Gay Richard J | Dynamic polysulfide corrosion inhibitor method and system for oil field piping |
| US6810957B2 (en) * | 2001-11-14 | 2004-11-02 | Bechtel Bwxt Idaho, Llc | Well constructions with inhibited microbial growth and methods of antimicrobial treatment in wells |
| US20110287985A1 (en) * | 2010-05-24 | 2011-11-24 | Chevron U.S.A. Inc. | Methods and systems for treating subterranean wells |
| US20240084675A1 (en) * | 2022-09-14 | 2024-03-14 | China University Of Petroleum (East China) | Apparatus for preventing and controlling secondary generation of hydrates in wellbore during depressurization exploitation of offshore natural gas hydrates and prevention and control method |
Citations (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US1602190A (en) * | 1926-01-04 | 1926-10-05 | Petroleum Rectifying Co | Method of dehydrating petroleum emulsions |
| US2139595A (en) * | 1935-11-11 | 1938-12-06 | Phillips Petroleum Co | Method for dissolving paraffing and wax |
| US2654436A (en) * | 1951-07-16 | 1953-10-06 | Macco Oil Tool Company Inc | Method of treating well fluids |
| US2889276A (en) * | 1955-03-30 | 1959-06-02 | Pan American Petroleum Corp | Vapor space corrosion inhibitor |
| US3190357A (en) * | 1962-05-03 | 1965-06-22 | Rufus P Kirk | Well tool and method of using same |
| US3193016A (en) * | 1962-04-30 | 1965-07-06 | Hydril Co | Reverse flow tubing valve |
| US3348614A (en) * | 1965-06-23 | 1967-10-24 | Mobil Oil Corp | Hydrate prevention in gas production |
| US3424249A (en) * | 1966-10-19 | 1969-01-28 | Shell Oil Co | Cleaning steam injection well tubing string in situ |
-
1969
- 1969-02-13 US US798998A patent/US3566970A/en not_active Expired - Lifetime
-
1970
- 1970-02-02 FR FR7003528A patent/FR2031394A1/fr not_active Withdrawn
Patent Citations (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US1602190A (en) * | 1926-01-04 | 1926-10-05 | Petroleum Rectifying Co | Method of dehydrating petroleum emulsions |
| US2139595A (en) * | 1935-11-11 | 1938-12-06 | Phillips Petroleum Co | Method for dissolving paraffing and wax |
| US2654436A (en) * | 1951-07-16 | 1953-10-06 | Macco Oil Tool Company Inc | Method of treating well fluids |
| US2889276A (en) * | 1955-03-30 | 1959-06-02 | Pan American Petroleum Corp | Vapor space corrosion inhibitor |
| US3193016A (en) * | 1962-04-30 | 1965-07-06 | Hydril Co | Reverse flow tubing valve |
| US3190357A (en) * | 1962-05-03 | 1965-06-22 | Rufus P Kirk | Well tool and method of using same |
| US3348614A (en) * | 1965-06-23 | 1967-10-24 | Mobil Oil Corp | Hydrate prevention in gas production |
| US3424249A (en) * | 1966-10-19 | 1969-01-28 | Shell Oil Co | Cleaning steam injection well tubing string in situ |
Non-Patent Citations (1)
| Title |
|---|
| Muir, P.D. Organic Inhibitors In Oil & Gas J., Feb. 15, 1954, pp. 143 and 145 147. (Copy in 166-244C) * |
Cited By (15)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3675720A (en) * | 1970-07-08 | 1972-07-11 | Otis Eng Corp | Well flow control system and method |
| US4031955A (en) * | 1976-01-20 | 1977-06-28 | Baker Oil Tools, Inc. | Down hole inhibitor injector |
| US4103743A (en) * | 1976-10-29 | 1978-08-01 | Thomas L. Moran | Method and means of treating water wells |
| US4326585A (en) * | 1980-02-19 | 1982-04-27 | Baker International Corporation | Method and apparatus for treating well components with a corrosion inhibiting fluid |
| US4347899A (en) * | 1980-12-19 | 1982-09-07 | Mobil Oil Corporation | Downhold injection of well-treating chemical during production by gas lift |
| US4625803A (en) * | 1985-05-20 | 1986-12-02 | Shell Western E&P Inc. | Method and apparatus for injecting well treating liquid into the bottom of a reservoir interval |
| US4694908A (en) * | 1986-10-27 | 1987-09-22 | Camco, Incorporated | Method and apparatus of injecting fluid into a well conduit by coil tubing |
| US5188179A (en) * | 1991-12-23 | 1993-02-23 | Gay Richard J | Dynamic polysulfide corrosion inhibitor method and system for oil field piping |
| US6810957B2 (en) * | 2001-11-14 | 2004-11-02 | Bechtel Bwxt Idaho, Llc | Well constructions with inhibited microbial growth and methods of antimicrobial treatment in wells |
| US20050034855A1 (en) * | 2001-11-14 | 2005-02-17 | Lee Brady D. | Well having inhibited microbial growth |
| US20050034856A1 (en) * | 2001-11-14 | 2005-02-17 | Lee Brady D. | Microbial growth inhibiting material and method of forming |
| US7090016B2 (en) | 2001-11-14 | 2006-08-15 | Battelle Energy Alliance, Llc | Well having inhibited microbial growth |
| US20110287985A1 (en) * | 2010-05-24 | 2011-11-24 | Chevron U.S.A. Inc. | Methods and systems for treating subterranean wells |
| US8424600B2 (en) * | 2010-05-24 | 2013-04-23 | Chevron U.S.A. Inc. | Methods and systems for treating subterranean wells |
| US20240084675A1 (en) * | 2022-09-14 | 2024-03-14 | China University Of Petroleum (East China) | Apparatus for preventing and controlling secondary generation of hydrates in wellbore during depressurization exploitation of offshore natural gas hydrates and prevention and control method |
Also Published As
| Publication number | Publication date |
|---|---|
| FR2031394A1 (en) | 1970-11-20 |
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