US3392783A - Method of producing fluids from a well bore producing formation - Google Patents

Method of producing fluids from a well bore producing formation Download PDF

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US3392783A
US3392783A US593502A US59350266A US3392783A US 3392783 A US3392783 A US 3392783A US 593502 A US593502 A US 593502A US 59350266 A US59350266 A US 59350266A US 3392783 A US3392783 A US 3392783A
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well
tubing string
pass
packer
producing
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US593502A
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Milner L Reed
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Hughes Tool Co
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Brown Oil Tools Inc
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Assigned to HUGHES TOOL COMPANY A CORP. OF DE reassignment HUGHES TOOL COMPANY A CORP. OF DE MERGER (SEE DOCUMENT FOR DETAILS). EFFECTIVE DEC. 22, 1981 (DELAWARE) Assignors: BROWN OIL TOOLS, INC. A TX CORP.
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    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • 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
    • E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones

Definitions

  • Another object is to provide an improved method of steam injection into a well bore in which the packer bypass is controlled without manipulation of the well string on which the packer is mounted.
  • a further object is to provide an improved method of injecting steam into a well bore producing formation through a well string having a well packer mounted thereon and set against the well bore in which the packer bypass is normally open and is closed, responsive to the heat of the injected steam.
  • Still another object is to provide an improved method of producing well fluids from a well bore formation by steam injection under pressure in which the normally open well packer by-pass closes during steam injection and opens thereafter to provide more efiicient pumping of the fluids from the well bore.
  • FIGURE 1 is a partial longitudinal sectional view of a well packer in set position which has a by-pass that may be controlled in accordance with the present invention.
  • FIGURE 2 is a schematic sectional view of a well bore and illustrating the position of the well packer by-pass before steam injection and showing the cleaning of the well.
  • FIGURE 3 is a similar view illustrating steam injection.
  • FIGURE 4 is another view similar to FIGURES 2 and 3 which illustrates the pumping of well fluids after steam injection has been completed.
  • FIGURE 1 illustrates a well packer suitable for use with the improved method of the present invention.
  • This well packer is disclosed in the application of John B. Davis, Ser. No. 553,455, filed May 27, 1966 and entitled Well Packer.
  • This well packer is adapted to be lowered into a well bore on a well string, such as tubing string T, and set to seal against the interior of the casing C.
  • This well packer includes inner and outer tubular supports and 12, packing assembly P, anchor- 3,392,783 Patented July 16, 1968 ing assembly A, setting means S and a release means R. Both tubular supports 10 and 12 are connected to the collar 14 on tubing string T and are spaced apart to define the passageway 16.
  • the lower end of inner tubular support 10 connects to the lower extension of tubing string T.
  • the lower end of outer tubular support 12 connects to the grooved collar 18 which cooperates with the pins 20 in the sleeve 22 depending from the anchoring assembly A to prevent inadvertent release of the releasing means R except when the packer is to be unset.
  • the by-pass includes the passageway 16 and the ports 24 defined in outer tubular support 12.
  • the interior of the packing assembly P includes the seal 26 which is adapted to seal against the exterior of tubular support 12.
  • This packer is set by lowering the tubing string T to position the pins 28 on collar 14 in the grooves 30 at the upper end of the setting means S and rotating the tubing string T to cause the setting means S to compress the packing and anchoring assemblies into set position. Thereafter, the tubing string T may be moved to position the ports 24 either above or below the seal 26.
  • the well bore B extends through the producing formation F.
  • the casing C has been set in the well bore B and extends from the surface down to a level above the producing formation F.
  • the well packer has been lowered on the tubing string T and its packing assembly P and anchoring assembly A have been set against the interior of the casing C. With the packer set, the tubing string T is supported by the slips 32 in the tubing head assembly 34 and the usual packing 36 seals around the tubing string T.
  • a valve 38 is installed in the tubing string T above the packing P and suitable connection (not shown) is provided to the upper end of tubing string T for the circulation of fluids thereto.
  • the line 40 controlled by the valve 42 connects into the upper end of the casing C to control the discharge of fluids in the annulus defined by the casing C and the tubing string T.
  • the positioning of the tubing string T positions the ports 24 a preselected distance above the well packer seal 26 so that the well packer by-pass is open.
  • the position of ports 24 is selected to assure closing of the by-pass by thermal expansion of the tubing string T during the initial phases of steam injection.
  • Another factor to consider in positioning the tubing string is to be sure that sufiicient length of the tubular supports 10 and 12 is provided above the well packer to assure that the thermal expansion of the tubing string T does not move the collar 14 into direct contact with the well packer.
  • the collar 14 should be a sufiicient distance above the well packer so that no thermal expansion forces are exerted on the well packer but rather the tubular supports 10 and 12 slide through the well packer to accommodate thermal expansion of the tubing string T.
  • fresh water is circulated, as shown by the arrows in FIGURE 2, down through the tubing string T and upwardly through the by-pass and the annulus to discharge mud and oil from the well bore through line 40 and to fill both the tubing string and the annulus with fresh water.
  • the steam pressure forces some of the water into the producing formation F.
  • the temperature of the steam injected heats the tubing string T causing it to expand downwardly to close the by-pass by moving the ports 24 downwardly through the seal 26.
  • the pressures above and below the well packer are equalized and substantially no fluids flow through the ports 24.
  • the by-pass closes, the annulus pressure at the surface starts to build as a result of the heating of the water in the annulus.
  • the valve 42 is preferably opened to allow the water in the annulus to be vaporized. It is generally preferred to vaporize the water from the by-pass as a means of limiting the temperature to which the casing C is heated and to avoid having to pump the water from the well bore during the production of the well fluids from the producing formation F.
  • FIG. 1 illustrates the steam injection step of the method and shows the by-pass closed and the water vaporized from the annulus above the well packer.
  • steam injection is continued for several days until the desired degree of heating of the producing formation has been achieved.
  • suitable producing equipment such as the pump shown in FIG- URE 4
  • the tubing string T is cooling and when cooled sufficiently, contracts to open the by-pass. With the bypass open, vapors in the well bore flow up through the by-pass through the annulus and are discharged through line 40 under control of valve 42.
  • the well fluids in the well bore are produced upward through the tubing string T and are directed to suitable surface recovery equipment (not shown) wherein the well fluids and water produced from the well bore may be readily separated. Production of well fluids is continued so long as the amount of well fluids recovered justifies.
  • the well is again subjected to steam injection.
  • the pumping equipment is removed from the tubing string T.
  • Steam injection may then be immediately commenced but it is preferred that the tubing string and the annulus be filled with fresh water before starting the steam injection to assure that there is substantially no fluid flow through the 'by-pass as it is closed. In this manner, the by-pass seal 26 is protected from the cutting action of fluids which might exist during closing.
  • the commencement of steam injection heats the tubing string T causing it to elongate and close the by-pass.
  • the steam injection and production of well fluids proceeds as described.
  • the steps of steam injection and production of well fluids are continued as long as the well fluids recovered justify the expense of the operation.
  • the present invention provides a method of producing well fluids by steam injection which does not require manipulation of the tubing string to control the opening and closing of the well packer by-pass once the tubing string has been hung in its preselected position.
  • This method therefore, eliminates the need for hoisting equipment for manipulating the tubing string at the surface.
  • the by-pass is closed by the thermal expansion of the tubing which is heated by the steam.
  • the method of producing well fluids from a producing formation in a well bore comprising running and setting a well packer having a by-pass on a tubing string above the producing formation in the well bore,

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Piles And Underground Anchors (AREA)

Description

July 16, 1968 M. L. REED 3,392,783
METHOD OF PRODUCING FLUIDS FROM A WELL BORE PRODUCING FORMATION Filed NOV. 10, 1966 2 Sheets-Sheet 1 5G z wemfi j {AM W40 BY 6,. W
M. L.. REED July 16, 1968 METHOD OF PRODUCING FLUIDS FROM A WELL BORE PRODUCING FORMATION 2 Sheets-Sheet 2 Filed Nov. 10, 1966 STEAM ATTO NE) United States Patent 3,392,783 METHOD OF PRODUCING FLUIDS FROM A WELL BORE PRODUCING FORMATION Milner L. Reed, Houston, Tex., assignor to Brown Oil Tools, Inc., Houston, Tex., a corporation of Texas Filed Nov. 10, 1966, Ser. No. 593,502 8 Claims. (Cl. 166-40) The present invention relates to an improved method of producing well fluids in which the well fluids are heated in the producing formation by injection of a heated fluid from the surface of the well bore.
In the production of low gravity non viscous hydrocarbons from a producing formation, steam has been injected through a well pipe string on which a packer is mounted to allow the steam pressure to be maintained at the face of the particular producing formation being treated. It has been a common practice to provide a bypass of the well packer which may be opened or closed by manipulation of the well pipe. This control of the bypass requires that some additional equipment, such as, hoisting equipment be available at the wellhead.
It is therefore an object of the present invention to provide an improved method for producing well fluid with injection of heated fluid in the well which eliminates the need of such well string handling equipment at the surface of the well bore.
Another object is to provide an improved method of steam injection into a well bore in which the packer bypass is controlled without manipulation of the well string on which the packer is mounted.
A further object is to provide an improved method of injecting steam into a well bore producing formation through a well string having a well packer mounted thereon and set against the well bore in which the packer bypass is normally open and is closed, responsive to the heat of the injected steam.
Still another object is to provide an improved method of producing well fluids from a well bore formation by steam injection under pressure in which the normally open well packer by-pass closes during steam injection and opens thereafter to provide more efiicient pumping of the fluids from the well bore.
These and other objects and advantages of the present invention are hereinafter set forth and explained in relation to the drawings showing a preferred form of the present invention and wherein:
FIGURE 1 is a partial longitudinal sectional view of a well packer in set position which has a by-pass that may be controlled in accordance with the present invention.
FIGURE 2 is a schematic sectional view of a well bore and illustrating the position of the well packer by-pass before steam injection and showing the cleaning of the well.
FIGURE 3 is a similar view illustrating steam injection.
FIGURE 4 is another view similar to FIGURES 2 and 3 which illustrates the pumping of well fluids after steam injection has been completed.
Referring to the drawings, FIGURE 1 illustrates a well packer suitable for use with the improved method of the present invention. This well packer is disclosed in the application of John B. Davis, Ser. No. 553,455, filed May 27, 1966 and entitled Well Packer. This well packer is adapted to be lowered into a well bore on a well string, such as tubing string T, and set to seal against the interior of the casing C. This well packer includes inner and outer tubular supports and 12, packing assembly P, anchor- 3,392,783 Patented July 16, 1968 ing assembly A, setting means S and a release means R. Both tubular supports 10 and 12 are connected to the collar 14 on tubing string T and are spaced apart to define the passageway 16. The lower end of inner tubular support 10 connects to the lower extension of tubing string T. The lower end of outer tubular support 12 connects to the grooved collar 18 which cooperates with the pins 20 in the sleeve 22 depending from the anchoring assembly A to prevent inadvertent release of the releasing means R except when the packer is to be unset.
The by-pass includes the passageway 16 and the ports 24 defined in outer tubular support 12. The interior of the packing assembly P includes the seal 26 which is adapted to seal against the exterior of tubular support 12. Thus, when the ports 24 are positioned below the seal 26, the by-pass is closed and when they are positioned above the seal 26, the by-pass is open.
This packer is set by lowering the tubing string T to position the pins 28 on collar 14 in the grooves 30 at the upper end of the setting means S and rotating the tubing string T to cause the setting means S to compress the packing and anchoring assemblies into set position. Thereafter, the tubing string T may be moved to position the ports 24 either above or below the seal 26.
Referring to the schematic illustrations of FIGURES 2, 3 and 4, the well bore B extends through the producing formation F. The casing C has been set in the well bore B and extends from the surface down to a level above the producing formation F. The well packer has been lowered on the tubing string T and its packing assembly P and anchoring assembly A have been set against the interior of the casing C. With the packer set, the tubing string T is supported by the slips 32 in the tubing head assembly 34 and the usual packing 36 seals around the tubing string T. A valve 38 is installed in the tubing string T above the packing P and suitable connection (not shown) is provided to the upper end of tubing string T for the circulation of fluids thereto. The line 40 controlled by the valve 42 connects into the upper end of the casing C to control the discharge of fluids in the annulus defined by the casing C and the tubing string T.
In accordance with the present invention, the positioning of the tubing string T, when it is supported at the surface, positions the ports 24 a preselected distance above the well packer seal 26 so that the well packer by-pass is open. The position of ports 24 is selected to assure closing of the by-pass by thermal expansion of the tubing string T during the initial phases of steam injection. Another factor to consider in positioning the tubing string, is to be sure that sufiicient length of the tubular supports 10 and 12 is provided above the well packer to assure that the thermal expansion of the tubing string T does not move the collar 14 into direct contact with the well packer. Thus, the collar 14 should be a sufiicient distance above the well packer so that no thermal expansion forces are exerted on the well packer but rather the tubular supports 10 and 12 slide through the well packer to accommodate thermal expansion of the tubing string T.
With the well packer set and the tubing string T properly positioned as described, fresh water is circulated, as shown by the arrows in FIGURE 2, down through the tubing string T and upwardly through the by-pass and the annulus to discharge mud and oil from the well bore through line 40 and to fill both the tubing string and the annulus with fresh water.
Upon completion of Water circulation, steam is injected through the tubing string T with the valve 42 closed.
The steam pressure forces some of the water into the producing formation F. The temperature of the steam injected heats the tubing string T causing it to expand downwardly to close the by-pass by moving the ports 24 downwardly through the seal 26. As long as the ports 24 are open and the annulus is full of water, the pressures above and below the well packer are equalized and substantially no fluids flow through the ports 24. When the by-pass closes, the annulus pressure at the surface starts to build as a result of the heating of the water in the annulus. As soon as this pressure increase is detected, as by a pressure gauge (not shown) in line 40 between valve 42 and the annulus, the valve 42 is preferably opened to allow the water in the annulus to be vaporized. It is generally preferred to vaporize the water from the by-pass as a means of limiting the temperature to which the casing C is heated and to avoid having to pump the water from the well bore during the production of the well fluids from the producing formation F.
With the by-pass closed, the continued injection of steam forces the steam into the producing formation F and thereby provides the desired heat in the formation to assist in the recovery of the well fluids from the formation/FIGURE 2 illustrates the steam injection step of the method and shows the by-pass closed and the water vaporized from the annulus above the well packer. Generally, steam injection is continued for several days until the desired degree of heating of the producing formation has been achieved.
When the steam injection step is completed, suitable producing equipment, such as the pump shown in FIG- URE 4, is installed in the tubing string T and the Well fluids are allowed to flow into the well bore B to a level above the lower end of the tubing string T. During this period, the tubing string T is cooling and when cooled sufficiently, contracts to open the by-pass. With the bypass open, vapors in the well bore flow up through the by-pass through the annulus and are discharged through line 40 under control of valve 42.
The well fluids in the well bore are produced upward through the tubing string T and are directed to suitable surface recovery equipment (not shown) wherein the well fluids and water produced from the well bore may be readily separated. Production of well fluids is continued so long as the amount of well fluids recovered justifies.
Generally when the production is stopped, the well is again subjected to steam injection. To start steam injection, the pumping equipment is removed from the tubing string T. Steam injection may then be immediately commenced but it is preferred that the tubing string and the annulus be filled with fresh water before starting the steam injection to assure that there is substantially no fluid flow through the 'by-pass as it is closed. In this manner, the by-pass seal 26 is protected from the cutting action of fluids which might exist during closing.
The commencement of steam injection heats the tubing string T causing it to elongate and close the by-pass. The steam injection and production of well fluids proceeds as described. The steps of steam injection and production of well fluids are continued as long as the well fluids recovered justify the expense of the operation.
From the foregoing, it can be seen that the present invention provides a method of producing well fluids by steam injection which does not require manipulation of the tubing string to control the opening and closing of the well packer by-pass once the tubing string has been hung in its preselected position. This method, therefore, eliminates the need for hoisting equipment for manipulating the tubing string at the surface. The by-pass is closed by the thermal expansion of the tubing which is heated by the steam.
The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the size, shape and materials, as well as in the details of the illustrated construction, may be made within the scope of the appended claims Withoutdeparting from the spirit of the invention.
What is claimed is:
1. The method of heating a producing formation in a well =bore, comprising running into a well bore, a well packer having a packing assembly, a tubular support with a by-pass therethrough and a seal between said packing assembly and said tubular support with said well packer supported on atubing string, 1 setting said well packer in said well bore, e
positioning said tubular support with said by-pass a preselected distance above said seal, and" injecting steam through said tubing string,
said injected steam heating said tubing string and said tubular support whereby thermal elongation of said tubing string and said tubular support moves said by-pass through said seal and closes thegby-pass around said well packer.
2. The method according to claim .1, includingthe steps of circulating fresh water through said tubing string into said well bore after said packer is set and said tubular support is positioned with respect to said seal and prior to said steam injection.
3. The method according to claim 2,v including the steps of j opening the annulus at the surface surrounding the tubing string during the circulation of fresh water, and closing said annulus for the injection of steam. 4. The method according to claim 3, including the steps of detecting an increase of pressure in said annulus at the surface during steam injection, and
thereafter opening said annulus at the surface to .dis-
charge water vapors which are formed in said annulus by the heating of the water therein by the injected steam.
5. The method of producing well fluids from a producing formation in a well bore, comprising running and setting a well packer having a by-pass on a tubing string above the producing formation in the well bore,
supporting said tubing string at the wellhead so that the by-pass of said well packer is open,
injecting fresh water to wash the well bore,
injecting steam through said tubing string whereby the tubing string elongates responsive to a temperature increase and closes said by-pass,
discontinuing steam injection to allow the tubing string to cool whereby it contracts responsive to the cooling to open said by-pass, and
producing fluids from the producing formation upwardly through the tubing string.
6. The method according to claim 5, wherein the annulus around the tubing string is open at the surface during the injection of fresh water and including the steps of,
closing said annulus during initial steam injection to minimize flow through said by-pass'while' said bypass is closing.
7. The method according to claim 6, including the steps of detecting a pressure increase in said annulus during initial steam injection to detect the closing of said by-pass, and
thereafter opening said annulus to discharge vapors therein caused by the heat of said stream.
8. The method according to claim 5, including the steps of injecting fresh water through said tubing string after said producing step is terminated, and
thereafter repeating the steps of injecting steam, discontinuing steam injection and producing fluids through the tubing string.
(References on following page) References Cited UNITED STATES PATENTS Crites et a1 16653 X Harlan et a1. 166-39 5 Sutliff et a1. 16640 X Brown 16648 6 OTHER REFERENCES Owens, W. D., et aL: Steam Stimulation for Secondary Recovery, in Producers Monthly 29 (4), April 1965, pp. 8 and 10-13.
CHARLES E. OCONNELL, Primaly Examiner.
I. A. CALVERT, Assistant Examiner.

Claims (1)

1. THE METHOD OF HEATING A PRODUCING FORMATION IN A WELL BORE, COMPRISING RUNNING INTO A WELL BORE, A WELL PACKER HAVING A PACKING ASSEMBLY, A TUBULAR SUPPORT WITH A BY-PASS THERETHROUGH AND A SEAL BETWEEN SAID PACKING ASSEMBLY AND SAID TUBULAR SUPPORT WITH SAID WELL PACKER SUPPORTED ON A TUBING STRING, SETTING SAID WELL PACKER IN SAID WELL BORE, POSITIONING SAID TUBULAR SUPPORT WITH SAID BY-PASS A PRESELECTED DISTANCE ABOVE SAID SEAL, AND INJECTING STEAM THROUGH SAID TUBING STRING, SAID INJECTED STEAM HEATING SAID TUBING STRING AND SAID TUBULAR SUPPORT WHEREBY THERMAL ELONGATION OF SAID TUBING STRING AND SAID TUBULAR SUPPORT MOVES SAID BY-PASS THROUGH SAID SEAL AND CLOSES THE BY-PASS AROUND SAID WELL PACKER.
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Cited By (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3552489A (en) * 1968-12-04 1971-01-05 Schlumberger Technology Corp Well packer apparatus
US3583488A (en) * 1969-05-14 1971-06-08 Chevron Res Method of improving steam-assisted oil recovery
US3791449A (en) * 1971-10-13 1974-02-12 Brown Oil Tools Telescoping displacement joint
US4375240A (en) * 1980-12-08 1983-03-01 Hughes Tool Company Well packer
US4399865A (en) * 1981-07-20 1983-08-23 Chevron Research Company Concentric steaming string downhole apparatus
US4548265A (en) * 1983-07-15 1985-10-22 Baker Oil Tools, Inc. Downhole steam packing
WO2006109031A1 (en) * 2005-04-09 2006-10-19 Petrowell Limited Improved packer
US20110127768A1 (en) * 2008-03-29 2011-06-02 Petrowell Limited Improved tubing section coupling
US20130160996A1 (en) * 2011-10-28 2013-06-27 Halliburton Energy Services, Inc. Downhole Packer Assembly Having a Selective Fluid Bypass and Method for Use Thereof

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1961280A (en) * 1933-07-11 1934-06-05 Phillips Petroleum Co Method and apparatus for controlling oil wells
US3019838A (en) * 1959-12-30 1962-02-06 Texaco Inc Well bore completion method
US3352359A (en) * 1965-06-10 1967-11-14 St Louis Janitor Supply Co Apparatus for steam treating a deep well
US3357489A (en) * 1965-02-19 1967-12-12 Cicero C Brown Multiple well production packer apparatus and methods of positioning the same

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1961280A (en) * 1933-07-11 1934-06-05 Phillips Petroleum Co Method and apparatus for controlling oil wells
US3019838A (en) * 1959-12-30 1962-02-06 Texaco Inc Well bore completion method
US3357489A (en) * 1965-02-19 1967-12-12 Cicero C Brown Multiple well production packer apparatus and methods of positioning the same
US3352359A (en) * 1965-06-10 1967-11-14 St Louis Janitor Supply Co Apparatus for steam treating a deep well

Cited By (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3552489A (en) * 1968-12-04 1971-01-05 Schlumberger Technology Corp Well packer apparatus
US3583488A (en) * 1969-05-14 1971-06-08 Chevron Res Method of improving steam-assisted oil recovery
US3791449A (en) * 1971-10-13 1974-02-12 Brown Oil Tools Telescoping displacement joint
US4375240A (en) * 1980-12-08 1983-03-01 Hughes Tool Company Well packer
US4399865A (en) * 1981-07-20 1983-08-23 Chevron Research Company Concentric steaming string downhole apparatus
US4548265A (en) * 1983-07-15 1985-10-22 Baker Oil Tools, Inc. Downhole steam packing
WO2006109031A1 (en) * 2005-04-09 2006-10-19 Petrowell Limited Improved packer
GB2439006A (en) * 2005-04-09 2007-12-12 Petrowell Ltd Improved packer
GB2439006B (en) * 2005-04-09 2010-04-28 Petrowell Ltd Improved packer
US20110127768A1 (en) * 2008-03-29 2011-06-02 Petrowell Limited Improved tubing section coupling
US9133968B2 (en) 2008-03-29 2015-09-15 Petrowell Limited Tubing section coupling
US20130160996A1 (en) * 2011-10-28 2013-06-27 Halliburton Energy Services, Inc. Downhole Packer Assembly Having a Selective Fluid Bypass and Method for Use Thereof
US9127539B2 (en) * 2011-10-28 2015-09-08 Halliburton Energy Services, Inc. Downhole packer assembly having a selective fluid bypass and method for use thereof

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Owner name: HUGHES TOOL COMPANY A CORP. OF DE

Free format text: MERGER;ASSIGNOR:BROWN OIL TOOLS, INC. A TX CORP.;REEL/FRAME:003967/0348

Effective date: 19811214