U.S. patent application number 10/860951 was filed with the patent office on 2005-12-29 for methods of treating subterranean formations using low-molecular-weight fluids.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES. Invention is credited to Adams, David M., Farabee, Leldon M., Stegent, Neil A..
Application Number | 20050284637 10/860951 |
Document ID | / |
Family ID | 35504362 |
Filed Date | 2005-12-29 |
United States Patent
Application |
20050284637 |
Kind Code |
A1 |
Stegent, Neil A. ; et
al. |
December 29, 2005 |
Methods of treating subterranean formations using
low-molecular-weight fluids
Abstract
The present invention relates to systems and methods useful in
subterranean treatment operations. More particularly, the present
invention relates to systems and methods for treating subterranean
formations using low-molecular-weight fluids. Examples of methods
of the present invention include methods of treating a subterranean
formation intersected by a wellbore; methods of enhancing
production from multiple subterranean formations penetrated by a
well bore during a single trip through the well bore; methods of
enhancing production, in real time, from multiple subterranean
formations penetrated by a well bore during a single trip through
the well bore; and methods of reducing the cost of enhancing
production from multiple formations penetrated by a well bore by
stimulating multiple formations, on a single trip through the well
bore, with a fluid that minimizes damage to the formation.
Inventors: |
Stegent, Neil A.; (Kilgore,
TX) ; Adams, David M.; (Katy, TX) ; Farabee,
Leldon M.; (Houston, TX) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 South Second Street
P.O. Drawer 1431
Duncan
OK
73536-0440
US
|
Assignee: |
HALLIBURTON ENERGY SERVICES
|
Family ID: |
35504362 |
Appl. No.: |
10/860951 |
Filed: |
June 4, 2004 |
Current U.S.
Class: |
166/308.1 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 33/12 20130101; C09K 8/68 20130101; C09K 8/5758 20130101; E21B
23/006 20130101 |
Class at
Publication: |
166/308.1 |
International
Class: |
E21B 043/26 |
Claims
What is claimed is:
1. A method of treating a subterranean formation intersected by a
wellbore comprising: lowering a work string having a first packer
apparatus connected to a lower end of the work string to a desired
location in the wellbore, the work string being communicated with
the wellbore through a longitudinal opening defined by the first
packer apparatus, the first packer apparatus comprising: a packer
mandrel; and an expandable packer element disposed about the packer
mandrel; compressing the expandable packer element by lowering the
packer mandrel relative to the expandable packer element thereby
expanding the packer element outward to engage and seal a casing in
the wellbore below the formation, wherein the compressing step
seals the longitudinal opening to prevent communication
therethrough; displacing a low-molecular-weight fluid down the work
string and into the wellbore through a flow port defined in the
work string above the first packer apparatus, so as to create or
enhance at least one fracture in the subterranean formation;
unsealing the longitudinal opening after the displacing step to
communicate a portion of the wellbore above the expandable packer
element with a portion of the wellbore below the expandable packer
element through the longitudinal opening to equalize a pressure in
the wellbore above and below the expandable packer element; and
disengaging the expandable packer element from the casing.
2. The method of claim 1 wherein the work string has a second
packer apparatus connected therein, the second packer apparatus
being located above the formation, the method further comprising:
actuating the second packer apparatus to seal the wellbore above
the formation.
3. The method of claim 1 further comprising: moving the work string
to a second desired location in the wellbore; compressing the
expandable packer element by lowering the packer mandrel relative
to the expandable packer element to seal the casing and seal the
longitudinal opening in the first packer apparatus after the moving
step; displacing a second fluid down the work string into the
wellbore above the first packer apparatus; and reopening the
longitudinal opening to equalize the pressure above and below the
expandable packer element of the first packer apparatus after the
step of displacing a second fluid down the work string.
4. The method of claim 1 wherein the first packer apparatus further
comprises: a drag sleeve disposed about the packer mandrel, the
drag sleeve being slidable relative to the packer mandrel; and an
equalizing valve connected to a lower end of the drag sleeve and
extending upwardly therefrom into the packer mandrel.
5. The method of claim 1 further comprising the step of moving the
packer apparatus to another formation adjacent the well and
repeating the step of displacing a low-molecular-weight fluid down
the work string and into the wellbore to create or extend at least
one fracture in the formation.
6. The method of claim 1 wherein the equalizing valve may be moved
between the open and closed positions by reciprocation of the work
string.
7. The method of claim 1 wherein the equalizing valve defines a
generally cylindrical outer surface, and wherein in the closed
position the generally cylindrical outer surface sealingly engages
an inner surface of the packer mandrel.
8. The method of claim 1 wherein an interior of the work string is
in communication with the wellbore through flow ports defined in
the work string above the packer element so that a fluid may be
communicated into the formation through the flow ports when the
equalizing valve is in the closed position, and wherein the portion
of the wellbore above the packer element is in communication with
the portion of the wellbore below the packer element through the
flow ports, the packer mandrel, and the drag sleeve into the
wellbore when the equalizing valve is in the open position in order
to equalize the pressure in the wellbore above and below the packer
element.
9. The method of claim 1 wherein the equalizing valve moves from
the open position to the closed position when the packer apparatus
is actuated to expand the packer element to sealingly engage the
wellbore.
10. The method of claim 1 wherein the longitudinal opening has a
reduced diameter portion, wherein the equalizing valve comprises a
generally tubular element disposed in the longitudinal opening, and
wherein the equalizing valve is moved between the open and closed
positions by moving the equalizing valve in and out of the reduced
diameter portion to seal and open the longitudinal opening.
11. The method of claim 1 wherein the equalizing valve moves
between the open and the closed positions as the packer apparatus
is moved between the set and unset positions.
12. The method of claim 1 wherein the equalizing valve may be moved
from the closed position to the open position by pulling upward on
the work string.
13. The method of claim 1 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
14. The method of claim 1 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
15. The method of claim 1 wherein the low-molecular-weight fluid
comprises an acid system.
16. The method of claim 15 wherein the acid system comprises a
viscosifier.
17. The method of claim 16 wherein the viscosifier is present in
the acid system in an amount in the range of from about 0.002% to
about 0.035% by volume.
18. The method of claim 16 wherein the viscosifier comprises an
emulsifier or a surfactant.
19. The method of claim 15 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system.
20. The method of claim 15 wherein the acid system comprises a
hydrofluoric acid based delayed carbonate acid system.
21. The method of claim 1 wherein the low-molecular-weight fluid
comprises water.
22. The method of claim 1 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
23. The method of claim 22 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
24. The method of claim 22 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
25. The method of claim 22 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
26. The method of claim 22 wherein the crosslinking agent is a
boron-based compound, ulexite, colemanite, a compound that
comprises zirconium IV ions, a compound that comprises titanium IV
ions, an aluminum compound, or a compound that comprises antimony
ions.
27. The method of claim 22 wherein the crosslinking agent is
present in the low-molecular-weight fluid in an amount in the range
of from about 50 ppm to about 5000 ppm active crosslinker.
28. The method of claim 1 wherein the low-molecular-weight fluid
further comprises a pH-adjusting compound, a delayed delinker, a
buffer, a surfactant, a clay stabilizer, a fluid loss control
agent, a scale inhibitor, a demulsifier, a bactericide, a breaker,
an activator, or a mixture thereof.
29. A method of reducing the cost of enhancing production from
multiple formations penetrated by a well bore by stimulating
multiple formations, on a single trip through the well bore, with a
fluid that minimizes damage to the formation comprising: lowering a
work string having a first packer apparatus connected to a lower
end of the work string to a desired location in the wellbore, the
work string being communicated with the wellbore through a
longitudinal opening defined by the first packer apparatus, the
first packer apparatus comprising: a packer mandrel; and an
expandable packer element disposed about the packer mandrel;
compressing the expandable packer element by lowering the packer
mandrel relative to the expandable packer element thereby expanding
the packer element outward to engage and seal a casing in the
wellbore below the formation, wherein the compressing step seals
the longitudinal opening to prevent communication therethrough;
displacing a low-molecular-weight fluid down the work string and
into the wellbore through a flow port defined in the work string
above the first packer apparatus, so as to create or enhance at
least one fracture in the subterranean formation, the
low-molecular-weight fluid having the capability of enhancing the
regain permeability of the formation; unsealing the longitudinal
opening after the displacing step to communicate a portion of the
wellbore above the expandable packer element with a portion of the
wellbore below the expandable packer element through the
longitudinal opening to equalize a pressure in the wellbore above
and below the expandable packer element; disengaging the expandable
packer element from the casing; and moving the packer apparatus to
another formation in the well bore and repeating the step of
displacing a low-molecular-weight fluid down the work string and
into the wellbore to create or extend at least one fracture in the
formation.
30. The method of claim 29 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
31. The method of claim 29 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
32. The method of claim 29 wherein the low-molecular-weight fluid
comprises an acid system.
33. The method of claim 32 wherein the acid system comprises a
viscosifier.
34. The method of claim 33 wherein the viscosifier is present in
the acid system in an amount in the range of from about 0.002% to
about 0.035% by volume.
35. The method of claim 33 wherein the viscosifier comprises an
emulsifier or a surfactant.
36. The method of claim 32 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system.
37. The method of claim 32 wherein the acid system comprises a
hydrofluoric acid based delayed carbonate acid system.
38. The method of claim 29 wherein the low-molecular-weight fluid
comprises water.
39. The method of claim 29 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
40. The method of claim 39 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
41. The method of claim 39 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
42. The method of claim 39 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
43. The method of claim 39 wherein the crosslinking agent is a
boron-based compound, ulexite, colemanite, a compound that
comprises zirconium IV ions, a compound that comprises titanium IV
ions, an aluminum compound, or a compound that comprises antimony
ions.
44. The method of claim 39 wherein the crosslinking agent is
present in the low-molecular-weight fluid in an amount in the range
of from about 50 ppm to about 5000 ppm active crosslinker.
45. The method of claim 29 wherein the low-molecular-weight fluid
further comprises a pH-adjusting compound, a delayed delinker, a
buffer, a surfactant, a clay stabilizer, a fluid loss control
agent, a scale inhibitor, a demulsifier, a bactericide, a breaker,
an activator, or a mixture thereof.
46. A method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising lowering a work string
having a first packer apparatus connected to a lower end of the
work string to a desired location in the wellbore, the work string
being communicated with the wellbore through a longitudinal opening
defined by the first packer apparatus, the first packer apparatus
comprising: a packer mandrel; and an expandable packer element
disposed about the packer mandrel; compressing the expandable
packer element by lowering the packer mandrel relative to the
expandable packer element thereby expanding the packer element
outward to engage and seal a casing in the wellbore below the
formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or extend at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; determining, in real time, at least one parameter
related to the creation or enhancement of the at least one
fracture; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation
adjacent the well and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
47. The method of claim 46 wherein the step of determining, in real
time, at least one parameter related to the creation or enhancement
of the at least one fracture comprises determining, in real time,
that at least one fracture therein has been created or enhanced to
a desired extent.
48. The method of claim 47 wherein the step of relocating the tool
assembly within the well bore to another desired location in the
same, or different, formation is performed after the step of
determining, in real time, that at least one fracture therein has
been created or enhanced to a desired extent.
49. The method of claim 46 further comprising performing a
remediative step after the step of determining, in real time, at
least one parameter related to the creation or enhancement of the
at least one fracture.
50. The method of claim 49 wherein the remediative step comprises
reducing the concentration of a proppant present in the
low-molecular-weight fluid.
51. The method of claim 49 wherein the remediative step comprises
reducing the viscosity of the low-molecular-weight fluid.
52. The method of claim 46 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
53. The method of claim 46 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
54. The method of claim 46 wherein the low-molecular-weight fluid
comprises an acid system.
55. The method of claim 54 wherein the acid system comprises a
viscosifier.
56. The method of claim 55 wherein the viscosifier is present in
the acid system in an amount in the range of from about 0.002% to
about 0.035% by volume.
57. The method of claim 55 wherein the viscosifier comprises an
emulsifier or a surfactant.
58. The method of claim 54 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
59. The method of claim 46 wherein the low-molecular-weight fluid
comprises water.
60. The method of claim 46 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
61. The method of claim 60 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
62. The method of claim 60 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
63. The method of claim 60 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
64. The method of claim 60 wherein the crosslinking agent is a
boron-based compound, ulexite, colemanite, a compound that
comprises zirconium IV ions, a compound that comprises titanium IV
ions, an aluminum compound, or a compound that comprises antimony
ions.
65. The method of claim 60 wherein the crosslinking agent is
present in the low-molecular-weight fluid in an amount in the range
of from about 50 ppm to about 5000 ppm active crosslinker.
66. The method of claim 46 wherein the low-molecular-weight fluid
further comprises a pH-adjusting compound, a delayed delinker, a
buffer, a surfactant, a clay stabilizer, a fluid loss control
agent, a scale inhibitor, a demulsifier, a bactericide, a breaker,
an activator, or a mixture thereof.
67. A method of enhancing production from multiple subterranean
formations penetrated by a well bore during a single trip through
the well bore, comprising lowering a work string having a first
packer apparatus connected to a lower end of the work string to a
desired location in the wellbore, the work string being
communicated with the wellbore through a longitudinal opening
defined by the first packer apparatus, the first packer apparatus
comprising: a packer mandrel; and an expandable packer element
disposed about the packer mandrel; compressing the expandable
packer element by lowering the packer mandrel relative to the
expandable packer element thereby expanding the packer element
outward to engage and seal a casing in the wellbore below the
formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or extend at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation
adjacent the well and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
68. The method of claim 67 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
69. The method of claim 67 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
70. The method of claim 67 wherein the low-molecular-weight fluid
comprises an acid system.
71. The method of claim 70 wherein the acid system comprises a
viscosifier.
72. The method of claim 71 wherein the viscosifier is present in
the acid system in an amount in the range of from about 0.002% to
about 0.035% by volume.
73. The method of claim 71 wherein the viscosifier comprises an
emulsifier or a surfactant.
74. The method of claim 70 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
75. The method of claim 67 wherein the treatment fluid comprises
water.
76. The method of claim 67 wherein the treatment fluid comprises
water, a substantially fully hydrated depolymerized polymer, and a
crosslinking agent.
77. The method of claim 76 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
78. The method of claim 76 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
79. The method of claim 76 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
80. The method of claim 76 wherein the crosslinking agent is a
boron-based compound, ulexite, colemanite, a compound that
comprises zirconium IV ions, a compound that comprises titanium IV
ions, an aluminum compound, or a compound that comprises antimony
ions.
81. The method of claim 76 wherein the crosslinking agent is
present in the low-molecular-weight fluid in an amount in the range
of from about 50 ppm to about 5000 ppm active crosslinker.
82. The method of claim 67 wherein the low-molecular-weight fluid
further comprises a pH-adjusting compound, a delayed delinker, a
buffer, a surfactant, a clay stabilizer, a fluid loss control
agent, a scale inhibitor, a demulsifier, a bactericide, a breaker,
an activator, or a mixture thereof.
Description
BACKGROUND OF THE INVENTION TECHNOLOGY
[0001] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular weight treatment
fluids.
[0002] Hydrocarbon-bearing subterranean formations penetrated by
well bores often may be treated to increase their permeability or
conductivity, and thereby facilitate greater hydrocarbon production
therefrom. One such production stimulation treatment, known as
"fracturing," involves injecting a treatment fluid (e.g., a
"fracturing fluid") into a subterranean formation or zone at a rate
and pressure sufficient to create or enhance at least one fracture
therein. Fracturing fluids commonly comprise a proppant material
(e.g., sand, or other particulate material) suspended within the
fracturing fluid, which may be deposited into the created
fractures. The proppant material functions, inter alia, to prevent
the formed fractures from re-closing upon termination of the
fracturing operation. Upon placement of the proppant in the formed
fractures, conductive channels may remain within the zone or
formation, through which channels produced fluids readily may flow
to the well bore upon completion of the fracturing operation.
[0003] Because most fracturing fluids should suspend proppant
material, the viscosity of fracturing fluids often has been
increased through inclusion of a viscosifier. After a viscosified
fracturing fluid has been pumped into the formation to create or
enhance at least one fracture therein, the fracturing fluid
generally may be "broken" (e.g., caused to revert into a low
viscosity fluid), to facilitate its removal from the formation. The
breaking of viscosified fracturing fluids commonly has been
accomplished by including a breaker within the fracturing
fluid.
[0004] Conventional fracturing fluids usually are water-based
liquids containing a viscosifier that comprises a polysaccharide
(e.g., guar gum). Guar, and derivatized guar polymers such as
hydroxypropylguar, are water-soluble polymers that may be used to
create high viscosity in an aqueous fracturing fluid, and that
readily may be crosslinked to further increase the viscosity of the
fracturing fluid. While the use of gelled and crosslinked
polysaccharide-containing fracturing fluids has been successful,
such fracturing fluids often have not been thermally stable at
temperatures above about 200.degree. F. That is, the viscosity of
the highly viscous gelled and crosslinked fluids may decrease over
time at high temperatures. To offset the decreased viscosity, the
concentration of the viscosifier often may be increased, which may
result in, inter alia, increased costs and increased friction
pressure in the tubing through which the fracturing fluid is
injected into a subterranean formation. This may increase the
difficulty of pumping the fracturing fluids. Thermal stabilizers,
such as sodium thiosulfate, often have been included in fracturing
fluids, inter alia, to scavenge oxygen and thereby increase the
stabilities of fracturing fluids at high temperatures. However, the
use of thermal stabilizers also may increase the cost of the
fracturing fluids.
[0005] Certain types of subterranean formations, such as certain
types of shales and coals, may respond unfavorably to fracturing
with conventional fracturing fluids. For example, in addition to
opening a main, dominant fracture, the fracturing fluid may further
invade numerous natural fractures (or "butts" and "cleats," where
the formation comprises coal) that may intersect the main fracture,
which may cause conventional viscosifiers within the fracturing
fluid to invade intersecting natural fractures. When the natural
fractures re-close at the conclusion of the fracturing operation,
the conventional viscosifiers may become trapped therein, and may
obstruct the flow of hydrocarbons from the natural fractures to the
main fracture. Further, even in circumstances where the viscosifier
does not become trapped within the natural fractures, a thin
coating of gel nevertheless may remain on the surface of the
natural fractures after the conclusion of the fracturing operation.
This may be problematic, inter alia, where the production of
hydrocarbons from the subterranean formation involves processes
such as desorption of the hydrocarbon from the surface of the
formation. Previous attempts to solve these problems have involved
the use of less viscous fracturing fluids, such as non-gelled
water. However, this may be problematic, inter alia, because such
fluids may prematurely dilate natural fractures perpendicular to
the main fracture a problem often referred to as "near well bore
fracture complexity," or "near well bore tortuosity." This may be
problematic because the creation of multiple fractures, as opposed
to one or a few dominant fractures, may result in reduced
penetration into the formation, e.g., for a given injection rate,
many short fractures may be created rather than one, or a few,
lengthy fracture(s). This may be problematic because in low
permeability formations, the driving factor to increase
productivity often is the fracture length. Furthermore, the use of
less viscous fracturing fluids also may require excessive fluid
volumes, and/or excessive injection pressure. Excessive injection
pressure may frustrate attempts to place proppant into the
fracture, thereby reducing the likelihood that the fracturing
operation will increase hydrocarbon production.
[0006] It often is desirable to selectively treat hydrocarbon
zones, or formations, to extract hydrocarbons therefrom while
isolating the formation from other intervals in a well bore. A
packer may be used to isolate a section of the well bore that may
be either above, or below the packer. Once a particular operation,
for example a fracturing operation, has been performed, it may be
desirable to unset or release the packer and move it to another
location in the wellbore and set the packer again to isolate
another section of the wellbore. Generally, a pressure differential
across the packer element will exist after an operation in the
wellbore is performed. For example, when fracturing fluid pumped
through a work string is communicated with the wellbore adjacent a
formation, the pressure above the packer element, which will be
located below the formation, will be higher than the pressure below
the packer element after the operation is performed. In order to
unset the packer, the pressure above and below the packer element
which engages the casing must be equalized. Normally, in order to
equalize the pressure, the formation must be allowed to flow. If,
because of the nature of the operation performed or due to the
position of the packer, the pressure below a packer is greater than
the pressure above the packer, pressure in the wellbore above the
packer may be increased by displacing a higher or lower density
fluid into the wellbore above the packer or by pressurizing the
area above the packer. Once the pressure is equalized, the work
string can then be manipulated to unset the packer.
[0007] There are a number of difficulties associated with the
present methods of isolating formations utilizing packers lowered
into a wellbore on coiled tubing. One manner of isolating sections
is to utilize opposing cup packers which are well known in the art.
To isolate a particular section of a wellbore, such a system
utilizes upper and lower cup packers that are energized simply by
flowing through a port between the packers which causes expansion
of the packers by creating a differential pressure at the cups.
Pressure may be equalized before attempting to move the packer by
flowing the well back up the tubing. There are some difficulties
associated with such a method, including leak-off and compression,
and safety concerns because of the gasified fluids communicated to
the surface. It is also sometimes necessary to reverse-circulate
fluids to reduce the differential pressure used to set the cup
packers. There are environments, however, where it is difficult to
reverse-circulate. Although some opposing cup tools have a bypass
which will allow the pressure above and below the tools to
equalize, the bypasses cannot handle environments wherein fluids
have a high solids content.
[0008] Although such a system may work adequately, compression
packers are more reliable and create less wear on the coiled
tubing. Compression packers utilized on coiled tubing to isolate a
section of a wellbore typically have a solid bottom such that
communication with the wellbore through the lower end of the packer
is not possible and the only way to equalize pressure and unset the
packer is by flowing the well or by pressurizing the wellbore. This
presents many of the same problems associated with a dual cup
packer system. If the tools are moved when differential pressure
exists, damage may occur and such operations can be time-consuming
and costly.
SUMMARY OF THE INVENTION
[0009] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular weight treatment
fluids.
[0010] An example of a method of the present invention is a method
of treating a subterranean formation intersected by a wellbore
comprising: lowering a work string having a first packer apparatus
connected to a lower end of the work string to a desired location
in the wellbore, the work string being communicated with the
wellbore through a longitudinal opening defined by the first packer
apparatus, the first packer apparatus comprising: a packer mandrel;
and an expandable packer element disposed about the packer mandrel;
compressing the expandable packer element by lowering the packer
mandrel relative to the expandable packer element thereby expanding
the packer element outward to engage and seal a casing in the
wellbore below the formation, wherein the compressing step seals
the longitudinal opening to prevent communication therethrough;
displacing a low-molecular-weight fluid down the work string and
into the wellbore through a flow port defined in the work string
above the first packer apparatus, so as to create or enhance at
least one fracture in the subterranean formation; unsealing the
longitudinal opening after the displacing step to communicate a
portion of the wellbore above the expandable packer element with a
portion of the wellbore below the expandable packer element through
the longitudinal opening to equalize a pressure in the wellbore
above and below the expandable packer element; and disengaging the
expandable packer element from the casing.
[0011] Another example of a method of the present invention is a
method of reducing the cost of enhancing production from multiple
formations penetrated by a well bore by stimulating multiple
formations, on a single trip through the well bore, with a fluid
that minimizes damage to the formation comprising: lowering a work
string having a first packer apparatus connected to a lower end of
the work string to a desired location in the wellbore, the work
string being communicated with the wellbore through a longitudinal
opening defined by the first packer apparatus, the first packer
apparatus comprising: a packer mandrel; and an expandable packer
element disposed about the packer mandrel; compressing the
expandable packer element by lowering the packer mandrel relative
to the expandable packer element thereby expanding the packer
element outward to engage and seal a casing in the wellbore below
the formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or enhance at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation in the
well bore and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
[0012] Another example of a method of the present invention is a
method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising: lowering a work string
having a first packer apparatus connected to a lower end of the
work string to a desired location in the wellbore, the work string
being communicated with the wellbore through a longitudinal opening
defined by the first packer apparatus, the first packer apparatus
comprising: a packer mandrel; and an expandable packer element
disposed about the packer mandrel; compressing the expandable
packer element by lowering the packer mandrel relative to the
expandable packer element thereby expanding the packer element
outward to engage and seal a casing in the wellbore below the
formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or extend at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; determining, in real time, at least one parameter
related to the creation or enhancement of the at least one
fracture; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation
adjacent the well and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
[0013] Yet another method of the present invention is a method of
enhancing production from multiple subterranean formations
penetrated by a well bore during a single trip through the well
bore, comprising: lowering a work string having a first packer
apparatus connected to a lower end of the work string to a desired
location in the wellbore, the work string being communicated with
the wellbore through a longitudinal opening defined by the first
packer apparatus, the first packer apparatus comprising: a packer
mandrel; and an expandable packer element disposed about the packer
mandrel; compressing the expandable packer element by lowering the
packer mandrel relative to the expandable packer element thereby
expanding the packer element outward to engage and seal a casing in
the wellbore below the formation, wherein the compressing step
seals the longitudinal opening to prevent communication
therethrough; displacing a low-molecular-weight fluid down the work
string and into the wellbore through a flow port defined in the
work string above the first packer apparatus, so as to create or
extend at least one fracture in the subterranean formation, the
low-molecular-weight fluid having the capability of enhancing the
regain permeability of the formation; unsealing the longitudinal
opening after the displacing step to communicate a portion of the
wellbore above the expandable packer element with a portion of the
wellbore below the expandable packer element through the
longitudinal opening to equalize a pressure in the wellbore above
and below the expandable packer element; disengaging the expandable
packer element from the casing; and moving the packer apparatus to
another formation adjacent the well and repeating the step of
displacing a low-molecular-weight fluid down the work string and
into the wellbore to create or extend at least one fracture in the
formation.
[0014] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying drawings,
wherein:
[0016] FIG. 1 illustrates a packer apparatus of the present
invention disposed in a wellbore;
[0017] FIG. 2 schematically shows the packer apparatus set in a
wellbore.
[0018] FIGS. 3A-3D are partial section views of the packer
apparatus of the present invention in the running position.
[0019] FIGS. 4A-4D are partial section views of the packer
apparatus in the set position.
[0020] FIGS. 5A-5D are partial section views of the packer
apparatus of the present invention in the retrieving position.
[0021] FIG. 6 shows a flat pattern of the J-slot defined in the
packer mandrel of the present invention.
[0022] FIG. 7 shows an alternative embodiment of a drag sleeve of
the present invention.
[0023] While the present invention is susceptible to various
modifications and alternative forms, specific exemplary embodiments
thereof have been shown in the drawings and are herein described.
It should be understood, however, that the description herein of
specific embodiments is not intended to limit the invention to the
particular forms disclosed, but on the contrary, the intention is
to cover all modifications, equivalents, and alternatives falling
within the spirit and scope of the invention as defined by the
appended claims.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0024] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular-weight fluids. As
referred to herein, the term "low-molecular-weight fluid" is
defined to mean a fluid that has an average molecular weight of
less than about 1,000,000. Certain embodiments of the
low-molecular-weight fluids useful in accordance with the present
invention may have a viscosity, measured at a reference temperature
of about 25.degree. C., of at least about 2 cP; such viscosity may
be measured on, for example, a Fann Model 35 viscometer, or the
like. Certain other embodiments of low-molecular-weight fluids
useful with the present invention may have a lower viscosity, such
as, for example, when the low-molecular-weight fluid is water.
[0025] In certain embodiments of the present invention, the use of
a low-molecular-weight fluid in the methods and systems of the
present invention may result in, among other things, improved
cleanup of the low-molecular-weight fluid at the conclusion of the
treatment operation, and reduced loss of the low-molecular-weight
fluid into the subterranean formation during the treatment
operation. The subterranean formation also may exhibit improved
"regain permeability" upon the conclusion of the treatment
operation. As referred to herein, the term "regain permeability"
will be understood to mean the degree to which the permeability of
a formation that has been exposed to a treatment fluid approaches
the original permeability of the formation. For example, a
determination that a subterranean formation evidences "100% regain
permeability" at the conclusion of a treatment operation indicates
that the permeability of the formation, post-operation, is equal to
its permeability before the treatment operation. In certain
embodiments of the present invention, the methods and systems of
the present invention may permit, inter alia, highly accurate,
"pinpoint" placement of a fracture that has been created or
enhanced through the injection of a low-molecular-weight fluid at a
desired location in a reservoir.
[0026] In certain embodiments of the present invention, the
low-molecular-weight fluid may comprise an acid system. The acid
system may be polymer-based or nonpolymer-based. In certain
embodiments, the acid system may comprise a viscosifier (sometimes
referred to as a "gelling agent."). Where the acid system comprises
a viscosifier, a broad variety of viscosifiers may be used,
including, but not limited to, emulsifiers and surfactants.
Examples of suitable viscosifiers include, but are not limited to,
those that are commercially available from Halliburton Energy
Services, Inc., under the trade names SGA-HT, SGA-I, and SGA-II. In
certain embodiments wherein the low-molecular-weight fluid used in
the methods and systems of the present invention is an acid system
that comprises a viscosifier, the viscosifier may be present in the
acid system in an amount in the range of from about 0.001% to about
0.035% by volume. Examples of other acid systems that may be
suitable include, but are not limited to, a hydrochloric acid based
delayed carbonate acid system that is commercially available from
Halliburton Energy Services, Inc., under the trade name CARBONATE
20/20, and a hydrofluoric acid based delayed carbonate acid system
that is commercially available from Halliburton Energy Services,
Inc., under the trade name SANDSTONE 2000.
[0027] Another example of a suitable low-molecular-weight fluid
that may be used with the methods and systems of the present
invention is water. Generally, the water may be from any
source.
[0028] Another example of a suitable low-molecular-weight fluid is
described in U.S. Pat. No. 6,488,091, the relevant disclosure of
which is hereby incorporated by reference. Such
low-molecular-weight fluid has an average molecular weight in the
range of from about 100,000 to about 250,000, generally has a
viscosity (measured at a reference temperature of about 25.degree.
C. on, for example, a Fann Model 35 viscometer, or the like) of at
least about 8 cP, and generally comprises water, a substantially
fully hydrated depolymerized polymer, and a crosslinking agent for
crosslinking the substantially fully hydrated depolymerized
polymer. The water can be selected from fresh water, unsaturated
salt water (e.g., brines and seawater), and saturated salt water.
The substantially fully hydrated depolymerized polymer in the
low-molecular-weight fluid may be, inter alia, a depolymerized
polysaccharide. In certain embodiments, the substantially fully
hydrated depolymerized polymer is a substantially fully hydrated
depolymerized guar derivative polymer selected from the group
consisting of hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar and
carboxymethylhydroxyethylguar. In certain embodiments, the
substantially fully hydrated depolymerized polymer is substantially
fully hydrated depolymerized hydroxypropylguar. Generally, where
the low-molecular-weight fluid comprises water, a substantially
fully hydrated depolymerized polymer, and a crosslinking agent, the
substantially fully hydrated depolymerized polymer is present in
the low-molecular-weight fluid in an amount in the range of from
about 0.2% to about 5% by weight of the water therein.
[0029] Optionally, the low-molecular-weight fluids suitable for use
with the present invention may further comprise a crosslinking
agent. A broad variety of crosslinking agents may be suitable for
use in accordance with the methods and systems of the present
invention. For example, where the low-molecular-weight fluids
useful in the present invention comprise water, and a substantially
fully hydrated depolymerized polymer, suitable crosslinking agents
include, but are not limited to, boron-based compounds (e.g., boric
acid, ulexite, colemanite, disodium octaborate tetrahydrate, sodium
diborate and pentaborates). The crosslinking of the substantially
fully hydrated depolymerized polymer that may be achieved by these
crosslinking agents generally is fully reversible (e.g., the
crosslinked, substantially fully hydrated polymer easily may be
delinked if and when desired). Metal-based crosslinking agents also
may be suitable, bearing in mind that crosslinking of the
substantially fully hydrated depolymerized polymer that may be
achieved by these crosslinking agents generally is less reversible.
Examples of suitable metal-based crosslinking agents include, but
are not limited to, compounds that can supply zirconium IV ions
(e.g., zirconium lactate, zirconium lactate triethanolamine,
zirconium carbonate, zirconium acetylacetonate and zirconium
diisopropylamine lactate), compounds that can supply titanium IV
ions (e.g., titanium ammonium lactate, titanium triethanolamine,
and titanium acetylacetonate), aluminum compounds (e.g., aluminum
lactate or aluminum citrate), or compounds that can supply antimony
ions. In certain embodiments, the crosslinking agent is a borate
compound. The exact type and amount of crosslinking agent, or
agents, used depends upon, inter alia, the specific substantially
fully hydrated depolymerized polymer to be crosslinked, formation
temperature conditions and other factors known to those individuals
skilled in the art. Where included, the optional crosslinking agent
may be present in the low-molecular-weight fluid in an amount in
the range of from about 50 ppm to about 5000 ppm active
crosslinker.
[0030] Optionally, when the low-molecular-weight fluids useful with
this invention are used to carry out a fracture stimulation
procedure, proppant material may be included in at least a portion
of the low-molecular-weight fluid as it is pumped into the
subterranean formation to be fractured and into fractures created
therein. For example, the proppant material may be metered into the
low-molecular-weight fluid as the low-molecular-weight fluid is
formed. The quantity of proppant material per volume of
low-molecular-weight fluid can be changed, as desired, in real
time. Examples of proppant material that may be utilized include,
but are not limited to, resin-coated or uncoated sand, sintered
bauxite, ceramic materials or glass beads. Suitable materials are
commercially available from Carboceramics, Inc., of Irving, Tex.;
Sintex Minerals & Services, Inc., of Houston, Tex.; and
Norton-Alcoa Proppants, of Fort Smith, Ark. Examples of
intermediate strength ceramic proppants that may be suitable
include, but are not limited to, EconoProp.RTM., Carbo Lite.RTM.,
Carbo Prop.RTM., Interprop.RTM., Naplite.RTM., and Valuprop.RTM..
Examples of high strength ceramic proppants include, but are not
limited to, Carbo HSP.RTM., Sintered Bauxite and SinterBall.RTM..
Where included, the proppant material utilized may be present in
the low-molecular-weight fluid in an amount in the range of from
about 0.25 to about 24 pounds of proppant material per gallon of
the low-molecular-weight fluid.
[0031] Optionally, in certain embodiments wherein the
low-molecular-weight fluid comprises water, a crosslinking agent,
and a substantially fully hydrated depolymerized polymer, a
pH-adjusting compound for adjusting the pH of the
low-molecular-weight fluid to the optimum pH for crosslinking may
be included in the low-molecular-weight treating fluid. The
pH-adjusting compound can be selected from sodium hydroxide,
potassium hydroxide, lithium hydroxide, fumaric acid, formic acid,
acetic acid, hydrochloric acid, acetic anhydride and the like. In
certain embodiments, the pH-adjusting compound is sodium hydroxide.
Where included, the pH-adjusting compound may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 0.3% by weight of the water in the
low-molecular-weight fluid. In certain embodiments wherein the
pH-adjusting compound comprises a borate compound, the pH-adjusting
compound is utilized to elevate the pH of the low-molecular-weight
fluid to above about 9. At that pH, the borate compound
crosslinking agent crosslinks the short chain hydrated polymer
segments. When the pH of the crosslinked low-molecular-weight fluid
falls below about 9, the crosslinked sites are no longer
crosslinked. Thus, when the crosslinked low-molecular-weight fluid
contacts the subterranean formation being treated, the pH may be
lowered to some degree, which may begin the breaking process.
[0032] Optionally, in certain embodiments wherein the
low-molecular-weight fluid comprises water, a crosslinking agent,
and a substantially fully hydrated depolymerized polymer, the
low-molecular-weight fluid may comprise a delayed delinker capable
of lowering the pH of the low-molecular-weight fluid. In certain
embodiments, the presence of the delayed delinker in the
low-molecular-weight fluid may cause the low-molecular-weight fluid
to completely revert to a thin fluid in a short period of time.
Examples of delayed delinkers that may be utilized include, but are
not limited to, various lactones, esters, encapsulated acids and
slowly-soluble acid-generating compounds, oxidizers which produce
acids upon reaction with water, water-reactive metals such as
aluminum, lithium and magnesium and the like. In certain
embodiments, the delayed delinker comprises an ester. Where
included, the delayed delinker may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 1% by weight of the water therein. Alternatively,
any of the conventionally used delayed breakers employed with metal
ion crosslinkers can be utilized, for example, oxidizers such as
sodium chlorite, sodium bromate, sodium persulfate, ammonium
persulfate, encapsulated sodium persulfate, potassium persulfate,
or ammonium persulfate, and the like, as well as magnesium
peroxide, and encapsulated acids. Enzyme breakers that may be
employed include alpha and beta amylases, amyloglucosidase,
invertase, maltase, cellulase and hemicellulase. The specific
breaker or delinker utilized, whether or not it is encapsulated, as
well as the amount thereof employed will depend upon factors
including, inter alia, the breaking time desired, the nature of the
polymer and crosslinking agent, and formation characteristics and
conditions.
[0033] Optionally, the low-molecular-weight fluid also may include
a surfactant. The inclusion of a surfactant in the
low-molecular-weight fluid may, inter alia, prevent the formation
of emulsions between the low-molecular-weight fluid and
subterranean formation fluids contacted by the low-molecular-weight
fluid. Examples of such surfactants include, but are not limited
to, alkyl sulfonates, alkyl aryl sulfonates (e.g., alkyl benzyl
sulfonates such as salts of dodecylbenzene sulfonic acid), alkyl
trimethylammonium chloride, branched alkyl ethoxylated alcohols,
phenol-formaldehyde anionic resin blends, cocobetaines, dioctyl
sodium sulfosuccinate, imidazolines, alpha olefin sulfonates,
linear alkyl ethoxylated alcohols, trialkyl benzylammonium chloride
and the like. In certain embodiments, the surfactant may comprise
methanol. An example of a suitable surfactant is commercially
available from Halliburton Energy Services, Inc., under the trade
name "LO-SURF 300." In certain embodiments, the surfactant
comprises dodecylbenzene sulfonic acid salts. Where included, the
surfactant generally is present in the low-molecular-weight fluid
in an amount in the range of from about 0.001% to about 0.5% by
weight of the water therein.
[0034] Optionally, the low-molecular-weight fluid also may include
a clay stabilizer selected, for example, from the group consisting
of potassium chloride, sodium chloride, ammonium chloride,
tetramethyl ammonium chloride, and the like. An example of a
suitable clay stabilizer is commercially available from Halliburton
Energy Services, Inc., under the trade name "CLA-STA XP." In
certain embodiments, the clay stabilizer is potassium chloride or
tetramethyl ammonium chloride. Where included, the clay stabilizer
is generally present in the low-molecular-weight fluid in an amount
in the range of from about 0.001% to about 1% by weight of the
water therein.
[0035] Optionally, the low-molecular-weight fluid may comprise a
fluid loss control agent. Examples of fluid loss control agents
that may be used include, but are not limited to, silica flour,
starches, waxes, diesels, and resins. An example of a suitable
silica flour is commercially available from Halliburton Energy
Services, Inc., under the trade name "WAC-9." An example of a
suitable starch is commercially available from Halliburton Energy
Services, Inc., under the trade name "ADOMITE AQUA." Where
included, the fluid loss control agent may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 1% by weight of water therein.
[0036] Optionally, the low-molecular-weight fluid also may include
compounds for retarding the movement of the proppant within the
created or enhanced fracture. For example, materials in the form of
fibers, flakes, ribbons, beads, shavings, platelets and the like
that comprise glass, ceramics, carbon composite, natural or
synthetic polymers, resins, or metals and the like can be admixed
with the low-molecular-weight fluid and proppant. A more detailed
description of such materials is disclosed in, for example, U.S.
Pat. Nos. 5,330,005; 5,439,055; and 5,501,275, the relevant
disclosures of which are incorporated herein by reference. Examples
of suitable epoxy resins include those that are commercially
available from Halliburton Energy Services, Inc., under the trade
names "EXPEDITE" and "SAND WEDGE." Alternatively, or in addition to
the prior materials, a material comprising a tackifying compound
may be admixed with the low-molecular-weight fluid or the proppant
particulates to coat at least a portion of the proppant
particulates, or other solid materials identified above, such that
the coated material and particulate adjacent thereto will adhere
together to form agglomerates that may bridge in the created
fracture to prevent particulate flowback. The tackifying compound
also may be introduced into the formation with the
low-molecular-weight fluid before or after the introduction of the
proppant into the formation. The coated material is effective in
inhibiting the flowback of fine particulate in the proppant pack
having a size ranging from about that of the proppant to less than
about 600 mesh. The coated proppant or other material is effective
in consolidating fine particulates in the formation in the form of
agglomerates to prevent the movement of the fines during production
of the formation fluids from the well bore subsequent to the
treatment. A more detailed description of the use of such
tackifying compounds and methods of use thereof are disclosed in
U.S. Pat. Nos. 5,775,415; 5,787,986; 5,833,000; 5,839,510;
5,871,049; 5,853,048; and 6,047,772, the relevant disclosures of
which are incorporated herein by reference thereto.
[0037] Optionally, additional additives may be included in the
low-molecular-weight fluids including, but not limited to, scale
inhibitors, demulsifiers, bactericides, breakers, activators and
the like. An example of a suitable scale inhibitor is commercially
available from Halliburton Energy Services, Inc., under the trade
name "SCA 110." An example of a suitable breaker is commercially
available from Halliburton Energy Services, Inc., under the trade
name "VICON." Another example of a suitable breaker is commercially
available from Halliburton Energy Services, Inc., under the trade
name "HMP DE-LINK." Examples of suitable bactericides are
commercially available from Halliburton Energy Services, Inc.,
under the trade names "BE-3" and "BE-6."
[0038] In one embodiment, the present invention provides a system
that advantageously may be used with a low-molecular-weight fluid
to perform a variety of functions in a subterranean formation.
Referring now to FIGS. 1 and 2, a packer designated by the numeral
10 is shown connected in a work string 15 disposed in a well bore
20. A casing 25 may be cemented in well bore 20. Work string 15 and
casing 25 define an annulus 30. As illustrated in FIGS. 1 and 2,
well bore 20 intersects a formation 35. Formation 35 typically
comprises hydrocarbons. Casing 25 has perforations 40 adjacent
formation 35, such that formation 35 is in fluid communication with
annulus 30.
[0039] In addition to packer 10, work string 15 also may include: a
ported sub 42 connected to an upper end of packer 10; blast joints
44 connected to ported sub 42; a centralizer 46; and an upper
packer 48 connected to centralizer 46. Upper packer 48 may have a
shear release joint 50 connected to the upper end thereof. Upper
packer 48 may have a second centralizer 52 connected thereto.
Centralizer 52 has a coiled tubing connector 54 connected thereto,
which is adapted to be connected to coiled tubing 56. FIGS. 1 and 2
illustrate packer 10 during its placement within well bore 30 as
part of work string 15. Work string 15 is positioned so that packer
10 is positioned below formation 35. Packer 48, which may be a cup
packer of the type known in the art, is positioned above formation
35. FIG. 1 schematically illustrates packer 10 in a running or
unset position 58, while FIG. 2 schematically illustrates packer 10
in its set position 60. Packer 10 also is shown in the running
position 58 in FIGS. 3A through 3D, and in the set position 60 in
FIGS. 4A through 4D. In FIGS. 5A through 5D, packer 10 is shown in
a retrieving position 62. In each of FIGS. 3, 4, and 5, casing 25
is depicted by a dashed line.
[0040] Packer 10 comprises a housing 70 having an upper end 72 and
a lower end 74. Housing 70 defines a longitudinal opening 76
extending from upper end 72 to lower end 74 thereof. Housing 70 is
connected at threaded connection 78 to a lower end 80 of ported sub
42. Ported sub 42 has an upper end 82 having threads 84 defined
therein, and thus is adapted to be connected in work string 15
between lower or first packer 10 and upper or second packer 48.
Ported sub 42 defines an interior or longitudinal flow passage 86.
Ported sub 42 also defines at least one port 88 (and, in certain
embodiments, a plurality of ports 88) defined therethrough
intersecting flow passage 86 and thus communicating flow passage 86
with well bore 20, and particularly with annulus 30.
[0041] Packer 10 further includes a packer element 90, which in
certain embodiments is an elastomeric packer element disposed about
housing 70. Housing 70 comprises a packer mandrel 92 having a drag
sleeve 94 disposed thereabout. Packer element 90 is disposed about
packer mandrel 92 above drag sleeve 94. Packer mandrel 92 has an
upper end 96, a lower end 98 and defines a longitudinal opening 100
extending therebetween. Longitudinal opening 100 defines a portion
of longitudinal opening 76. Threads 102 are defined in packer
mandrel 92 at upper end 96 on an inner surface 104 thereof. Packer
mandrel 92 further defines an outer surface 105.
[0042] Inner surface 104 of packer mandrel 92 defines a first inner
diameter 106, a second inner diameter 108 therebelow and extending
radially inwardly therefrom, and a third inner diameter 110
extending radially inwardly from second diameter 108. An upward
facing shoulder 112 is defined by, and extends between, second and
third inner diameters 108 and 110, respectively. Inner surface 104
further defines a tapered surface 114 extending downwardly and
radially outwardly from third inner diameter 110 to a fourth inner
diameter 116. A fifth inner diameter 118 has a magnitude greater
than that of fourth inner diameter 116 and extends downwardly from
a lower end 120 of fourth inner diameter 116 to lower end 98 of
packer mandrel 92.
[0043] A seal 122 having an upper end 124 and a lower end 126 is
disposed in packer mandrel 92 and, in certain embodiments, is
received in second inner diameter 108. In certain embodiments, seal
122 includes an elastomeric seal element 128, and may have seal
spacers 129 disposed in packer mandrel 92 to engage the upper and
lower ends of seal element 128. Seal 122 has an inner surface 130
defining an inner diameter 132 that, in certain embodiments, is
substantially identical to, or slightly smaller than, third inner
diameter 110. Third inner diameter 110 and diameter 132 defined by
seal 122 may be referred to as a reduced diameter portion 133 of
packer mandrel 92 which, as explained in greater detail below, will
be sealingly engaged by the equalizing valve disposed in housing
70. A seal retainer 134 having an upper end 136 and a lower end 138
is threadedly connected to packer mandrel 92 at threads 102. Seal
122 is held in place by lower end 138 of seal retainer 134 and
shoulder 112.
[0044] Outer surface 105 defines a first outer diameter 140 and a
second outer diameter 142. A tapered shoulder 141 is defined on,
and extends radially outwardly from, first outer diameter 140 above
second outer diameter 142. Second outer diameter 142 extends
radially outwardly from, and has a greater diameter than, first
outer diameter 140.
[0045] Packer element 90 is disposed about outer surface 105. In
certain embodiments, packer element 90 is disposed about first
outer diameter 140 of outer surface 105. Packer element 90 has an
upper end 144, a lower end 146, an inner surface 148, and an outer
surface 150. A packer shoe 152 having an upper end 154 and a lower
end 156 is disposed about packer mandrel 92. Packer shoe 152 is
connected to packer mandrel 92 with a screw 153 (not shown in FIGS.
4A-4D and 5A-5D) and shear pin 155 (not shown in FIGS. 4A-4D and
5A-5D), or by other means known in the art. Lower end 156 of packer
shoe 152 engages upper end 146 of packer element 90.
[0046] A wedge 158 having an upper end 160 and a lower end 162 is
disposed about outer surface 150 of packer mandrel 92. Upper end
160 of wedge 158 engages lower end 146 of packer element 90. Wedge
158 has an outer surface 163 that defines an outer diameter 164
that extends from the upper end 160 thereof a portion of the
distance to lower end 162, and has a lower end 166. Outer surface
163 of wedge 158 tapers radially inwardly from lower end 166 of
outer diameter 164 to lower end 162 of wedge 158 and comprises a
tapered surface 165. When packer 10 is in running position 58,
lower end 162 of wedge 158 engages radially outwardly extending
shoulder 141 on outer diameter 140 of packer mandrel 92.
[0047] Packer mandrel 92 defines a continuous J-slot 170 in the
second outer diameter 142 thereof. J-slot 170 is illustrated in a
flat pattern in FIG. 6, and will be described in greater detail
hereinbelow. Drag sleeve 94 is disposed about packer mandrel 92,
and along with packer mandrel 92 comprises housing 70. Drag sleeve
94 has an outer surface 173, an inner surface 175, an upper end 174
and a lower end 176 that extends downwardly beyond lower end 98 of
packer mandrel 92, and comprises lower end 72 of housing 70. A slip
178 is disposed about packer mandrel 92 above drag sleeve 94. Slip
178 has an upper end 180 and a lower end 182. Lower end 182 engages
upper end 174 of drag sleeve 172. An inner surface 184 of slip 178
has an upper portion 186 and a lower portion 188. Upper portion 186
of inner surface 184 is a tapered surface 190 that extends radially
outwardly from packer mandrel 92 and is adapted to engage tapered
surface 165 on wedge 158. Slip 178 is of a type well known in the
art, and has teeth 192 adapted to engage casing 25. Leaf springs
194 extend upwardly from upper end 174 of drag sleeve 94, and are
adapted to engage slip 178 and to prevent slip 178 from prematurely
engaging the casing. A plurality of drag springs 196 are attached
to drag sleeve 172. Drag springs 196 extend radially outwardly from
outer surface 173, and will engage casing 25 when packer 10 is in
its running and retrieving positions 58 and 62, respectively. At
least one (and, in certain embodiments, two) lugs 198 are
threadedly connected to drag sleeve 94, and extend radially
inwardly from inner surface 175. Lug 198 extends into, and is
retained in, J-slot 170 defined in packer mandrel 92.
[0048] Inner surface 175 of drag sleeve 94 has threads 200 defined
thereon at the lower end 176 thereof. An equalizing valve 210 is
threadedly connected to drag sleeve 172 at threads 200, and extends
upwardly therefrom into packer mandrel 92. Equalizing valve 210 has
a lower end 212 and extends upwardly in housing 70 to an upper end
214. Equalizing valve 210 is generally tubular, and has a tapered
upper end 214. Upper end 214 is a ported upper end, and thus
includes a generally vertical opening 216 extending downwardly from
tip 215 thereof. At least one radial port 219 (and, in certain
embodiments, a plurality of radial ports 219) extend radially
outwardly from the lower end 218 of vertical opening 216 through
the side of equalizing valve 210.
[0049] Equalizing valve 210 may be assembled in sections that
include ported valve tip 220, which is threadedly connected to a
valve extension 222 having upper and lower ends 224 and 226,
respectively. A valve bypass insert 228 is threadedly connected to
valve extension 222. Valve bypass insert 228 is threadedly
connected to threads 200 on drag sleeve 94. Valve bypass insert 228
has a plurality of passageways 229 therethrough, to provide for the
communication of fluid therethrough.
[0050] Optionally, an operator may elect to employ a pressure
sensor (not shown) as part of work string 15. A wide variety of
pressure sensors may be used in accordance with the present
invention. In certain embodiments, the pressure sensor may be
capable of storing data that may be generated during a subterranean
operation until a desired time, e.g., until the completion of the
operation when the pressure sensor is removed from the subterranean
function. In certain embodiments of the present invention, the
incorporation of a pressure sensor may permit an operator to
evaluate conditions in the subterranean formation (which conditions
may include, but are not limited to, parameters related to the
creation or enhancement of the fracture) in real time or
near-real-time, and, inter alia, to undertake a remediative step in
real time or near-real-time. Example of remediative steps include,
inter alia, swapping from a proppant-laden fluid to a linear fluid,
reducing the concentration of a proppant present in the fluid, and
reducing the viscosity of the fluid. In certain embodiments of the
present invention, the operator may be able to determine, in
real-time, that the fracture in the subterranean formation has been
created or enhanced to a desired extent. In certain embodiments,
the operator may move packer 10 to a different zone in the same, or
different, formation after determining, in real time, that the
fracture has been created or enhanced to a desired extent. As
referred to herein, the term "real time" will be understood to mean
a time frame in which the occurrence of an event and the reporting
or analysis of it are almost simultaneous; e.g., within a maximum
duration of not more than two periods of a particular signal (e.g.,
a pressure signal, electrical signal, or the like) being evaluated.
For example, an operator may view, in real time, a plot of the
pressure in the formation that has been transmitted by the optional
pressure sensor (not shown), and determine, at a particular time
during the fracturing operation, that an increase, or increases, in
the slope of the pressure indicate the need to perform a
remediative step such as those described above. One of ordinary
skill in the art, with the benefit of this disclosure, will be able
to evaluate a real time plot of the pressure in the formation, and
evaluate conditions in the formation, and determine the appropriate
remediative step to perform in response.
[0051] Optionally, an operator may elect to employ a tension
indicator (not shown) as part of work string 15. The inclusion of a
tension indicator may provide an operator with a broad-variety of
information. In certain embodiments of the present invention, the
inclusion of a tension indicator may enable an operator to
identify, inter alia, whether packer 10 has been completely set, or
completely unset. In certain embodiments of the present invention,
the inclusion of a tension indicator may enable an operator to
identify, inter alia, the location within a well where an
obstruction may be hindering the ability to move packer 10; in
certain embodiments of the present invention, these
identifications, and the determination of other similar parameters,
may be made in real time. For example, an operator may view a real
time plot of the tension sensed by the tension indicator, and
determine, upon detection of an increase or decrease in the
tension, that the packer has become unset, or, as another example,
that the tension sensed by the tension indicator has increased
sufficiently to suggest that the mechanical integrity of packer 10,
or another element of work string 15, may be imperiled. In certain
embodiments, the operator may undertake a remediative step after
making such real time determination or identification. An example
of a remediative step includes, but is not limited to, raising or
lowering work string 15 without unsetting packer 10. Another
example of a remediative step includes, but is not limited to,
increasing or decreasing the flow rate of the low-molecular-weight
fluid. One of ordinary skill in the art, with the benefit of this
disclosure, will be able to evaluate a real time plot of the
tension and determine the appropriate remediative step to perform
in response.
[0052] In certain embodiments of the present invention, packer 10
operates in the following manner. Packer 10 is lowered into well
bore 20 (as schematically depicted in FIG. 1) on work string 15.
Drilling fluid or other fluid in the well bore 20 may be
communicated through valve bypass insert 228 into the housing and
upward into ported sub 42. Fluid in the well bore 20 also is
communicated through ports 88 in ported sub 42.
[0053] Running position 58 also may be referred to as an "open"
position of packer 10, as it permits communication of fluid through
housing 70. Thus, when packer 10 is in running position 58,
equalizing valve 210 also may be said to be in an "open" position,
which may be referred to as a first open position 230. Packer 10 is
lowered into the well bore 20 until it reaches a desired location
in the well bore 20, such as that schematically depicted in FIG. 1.
As illustrated therein, packer 10 is located below formation 35, in
which an operation is to be performed, and upper packer 48 is
located above formation 35. The operation to be performed may be a
production operation, treatment operation (e.g., fracturing), or
another desired operation.
[0054] As packer 10 is lowered into the well bore 20, J-slot 170
will engage lug 198 such that drag sleeve 94 moves downward with
packer mandrel 92. As illustrated in FIG. 6, J-slot 170 has two
packer set legs 232A and 232B, respectively, two packer run legs
234A and 234B, respectively, and four packer retrieve legs 236A,
236B, 236C, and 236D, respectively.
[0055] J-slot 170 also includes upper ramps 233 extending between
the packer set legs 232A-232B and the packer run legs 234A-234B,
and has lower ramps 235 extending between adjacent packer retrieve
legs 236A-236D. When packer 10 is being lowered into the well bore
20, lug 198 will engage one of packer run legs 234A-234B. In FIG.
6, lug 198 is shown engaging an upper end of packer set leg 234A.
When packer 10 has reached its desired location in the well bore,
the work string may be lifted upwardly, to move packer 10 from its
running position 58 to its set position 60. Upward pull on coiled
tubing 56 will cause packer mandrel 92 to move upward relative to
drag sleeve 94, which will be held in place by the engagement of
drag springs 196 with casing 25. Lug 198 will engage a lower ramp
235, which will cause rotation of drag sleeve 94 relative to packer
mandrel 92. The upward pull is continued, until lug 198 is
positioned over a retrieving leg 236A-236D, and in FIG. 6, over leg
236B. Coiled tubing 56 then may be released and allowed to move
downwardly, so that packer mandrel 92 moves downwardly relative to
drag sleeve 94 and thus downward relative to equalizing valve 210.
Slip 178 is urged radially outwardly by wedge 158 to engage casing
25. When slip 178 engages casing 25, downward movement of wedge 158
stops. Packer shoe 152 will continue to move with packer mandrel 92
and will compress packer element 90 so that it sealingly engages
casing 25. Lug 198 will engage an upper ramp 233, and as packer
mandrel 92 continues to be lowered, drag sleeve 94 will rotate and
lug 198 will be received in a packer set leg 232A-232B, in this
case leg 232A until it reaches the set position 60. When packer 10
is moved to its set position 60, which may also be referred to as a
"closed" position of the packer 10, equalizing valve 210 moves
upward relative to packer mandrel 92 to a closed position 240, such
that it engages reduced diameter portion 133 and is sealingly
engaged by seal 122. Equalizing valve 210 thus moves to closed
position 240 when the packer 10 is actuated to its set position 60,
wherein packer element 90 sealingly engages casing 25 below
formation 35.
[0056] When the equalizing valve 210 is in closed position 240, it
seals longitudinal opening 76 such that communication through
housing 70 is blocked. Thus, fluid may be displaced down coiled
tubing 56 and through ports 88 to treat formation 35, or the
formation 35 may be produced through ports 88. For example, if the
formation 35 is to be fractured, a low-molecular-weight fluid may
be displaced down coiled tubing 56 and out ports 88 into annulus 30
and formation 35. Displacement of fluid into annulus 30 through
ports 88 will energize upper packer 48 so that it seals against
casing 25 above formation 35. Pressure above packer element 90 will
increase as the low-molecular-weight fluid is continually displaced
through ports 88 into the annulus 30 between packer element 90 and
upper packer 48.
[0057] Once the desired operation, in this case fracturing, is
complete, it may be desirable to either remove work string 15 from
wellbore 20, or to move the work string 15 within the wellbore 20
to perform another operation at a different location within the
wellbore 20. In order to do so, the pressure above and below the
packer element 90 is equalized.
[0058] To equalize the pressure, upward pull is once again applied
to packer mandrel 92 by pulling upwardly on coiled tubing 56.
Packer mandrel 92 will move relative to equalizing valve 210 until
radial ports 219 are below seal 122. This will allow fluid in
wellbore 20 between packers 10 and 48 to pass through ports 88 into
longitudinal opening 76 defined by housing 70, and out through
valve bypass insert 228 into the wellbore 20 below packer element
90. As pressure begins to equalize, upward pull on coiled tubing 56
will become easier, and a greater flow area will be established
when equalizing valve 210 is completely removed from reduced
diameter portion 133, such that free communication is allowed from
wellbore 20 into ports 88 and downward through housing 70. Because
free communication is allowed, pressure will equalize and the
packer 10 can be easily unset simply by continuing to pull upwardly
on packer mandrel 92 with coiled tubing 56. Because there will be
little or no differential pressure across packer element 90, upward
pull will allow the packer 10 to unset. The packer 10 can be pulled
upwardly and retrieved, as depicted in FIGS. 5A-5D or if desired
can be moved to another location in the wellbore 20 and can be
reset so that treatment and/or production from another formation
can occur. This process can be repeated as often as possible in
individual formations in the wellbore 20.
[0059] In the embodiment shown, lugs 198 are fixed to drag sleeve
94. Thus, drag sleeve 94 will rotate when packer mandrel 92 is
moved vertically such that ramp 233 or 235, respectively, is
engaged by lugs 198. An alternate lug arrangement is shown in FIG.
7.
[0060] FIG. 7 shows a drag sleeve 250. Drag sleeve 250 is identical
in all aspects to drag sleeve 94 except that drag sleeve 250 is
comprised of two pieces and includes a rotatable ring with lugs
attached thereto as will be described. Drag sleeve 250, like drag
sleeve 94, has drag springs 196 and has ports 231, along with the
other features of drag sleeve 94. Drag sleeve 250 comprises an
upper portion 252 having a lower end 254, and a lower portion 256
having an upper end 258. Drag sleeve 250 has an inner surface 260
which defines an inner diameter 262 on upper portion 252 and an
inner diameter 264 on lower portion 256. Drag sleeve 250 has a
recess 266 defined therein defining a recessed diameter 268, which
is recessed outwardly from inner diameter 262. Recess 266 defines a
downward facing shoulder 270 in upper portion 252.
[0061] A lug rotator assembly 272 is disposed in drag sleeve 250 in
recess 266 and is rotatable therein. The lug rotator assembly 272
comprises a rotator ring 274 having an outer diameter 276 and an
inner diameter 278. In certain embodiments, outer diameter 276 may
be slightly smaller than recessed diameter 268, so that rotator
ring 274 will rotate in recess 266. In certain embodiments, inner
diameter 278 may be substantially the same as inner diameter 262.
Lug rotator assembly 272 includes a pair of lugs 280 extending
radially inwardly from inner diameter 278. Lugs 280 are adapted to
be received in J-slot 170. Lugs 280 may have a generally
cylindrical shaft portion 282 and a head 284. Head 284 defines a
shoulder 286 and will engage an opposite facing shoulder 288
defined in rotator ring 274 in openings 290 in which lugs 280 are
received. Lug rotator assembly 272 is held in place by downward
facing shoulder 270 and upper end 258 of lower portion 256 of drag
sleeve 250. Lug rotator assembly 272 will rotate relative to drag
sleeve 250 when packer mandrel 92 is moved therein such that lugs
280 engage either the upper ramp 233 or the lower ramp 235 defined
by the J-slot 170. Vertical movement of the packer mandrel 92,
after lugs 280 have engaged a ramp, will cause lug rotator assembly
272 to rotate until the lugs 280 are positioned in a packer run
leg, a packer set leg, or a packer retrieve leg depending on the
operation to be performed. This ensures an apparatus that can be
moved between its set and unset positions, even in wellbores where
drag sleeves tightly engage the casing such that the drag sleeve
will not readily rotate to allow lugs fixed thereto to be moved
within the J-slot to a desired position.
[0062] Accordingly, an example of a method of the present invention
is a method of treating a subterranean formation intersected by a
wellbore comprising: lowering a work string having a first packer
apparatus connected to a lower end of the work string to a desired
location in the wellbore, the work string being communicated with
the wellbore through a longitudinal opening defined by the first
packer apparatus, the first packer apparatus comprising: a packer
mandrel; and an expandable packer element disposed about the packer
mandrel; compressing the expandable packer element by lowering the
packer mandrel relative to the expandable packer element thereby
expanding the packer element outward to engage and seal a casing in
the wellbore below the formation, wherein the compressing step
seals the longitudinal opening to prevent communication
therethrough; displacing a low-molecular-weight fluid down the work
string and into the wellbore through a flow port defined in the
work string above the first packer apparatus, so as to create or
enhance at least one fracture in the subterranean formation;
unsealing the longitudinal opening after the displacing step to
communicate a portion of the wellbore above the expandable packer
element with a portion of the wellbore below the expandable packer
element through the longitudinal opening to equalize a pressure in
the wellbore above and below the expandable packer element; and
disengaging the expandable packer element from the casing.
[0063] Another example of a method of the present invention is a
method of reducing the cost of enhancing production from multiple
formations penetrated by a well bore by stimulating multiple
formations, on a single trip through the well bore, with a fluid
that minimizes damage to the formation comprising: lowering a work
string having a first packer apparatus connected to a lower end of
the work string to a desired location in the wellbore, the work
string being communicated with the wellbore through a longitudinal
opening defined by the first packer apparatus, the first packer
apparatus comprising: a packer mandrel; and an expandable packer
element disposed about the packer mandrel; compressing the
expandable packer element by lowering the packer mandrel relative
to the expandable packer element thereby expanding the packer
element outward to engage and seal a casing in the wellbore below
the formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or enhance at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation in the
well bore and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
[0064] Another example of a method of the present invention is a
method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising: lowering a work string
having a first packer apparatus connected to a lower end of the
work string to a desired location in the wellbore, the work string
being communicated with the wellbore through a longitudinal opening
defined by the first packer apparatus, the first packer apparatus
comprising: a packer mandrel; and an expandable packer element
disposed about the packer mandrel; compressing the expandable
packer element by lowering the packer mandrel relative to the
expandable packer element thereby expanding the packer element
outward to engage and seal a casing in the wellbore below the
formation, wherein the compressing step seals the longitudinal
opening to prevent communication therethrough; displacing a
low-molecular-weight fluid down the work string and into the
wellbore through a flow port defined in the work string above the
first packer apparatus, so as to create or extend at least one
fracture in the subterranean formation, the low-molecular-weight
fluid having the capability of enhancing the regain permeability of
the formation; unsealing the longitudinal opening after the
displacing step to communicate a portion of the wellbore above the
expandable packer element with a portion of the wellbore below the
expandable packer element through the longitudinal opening to
equalize a pressure in the wellbore above and below the expandable
packer element; determining, in real time, at least one parameter
related to the creation or enhancement of the at least one
fracture; disengaging the expandable packer element from the
casing; and moving the packer apparatus to another formation
adjacent the well and repeating the step of displacing a
low-molecular-weight fluid down the work string and into the
wellbore to create or extend at least one fracture in the
formation.
[0065] Yet another method of the present invention is a method of
enhancing production from multiple subterranean formations
penetrated by a well bore during a single trip through the well
bore, comprising: lowering a work string having a first packer
apparatus connected to a lower end of the work string to a desired
location in the wellbore, the work string being communicated with
the wellbore through a longitudinal opening defined by the first
packer apparatus, the first packer apparatus comprising: a packer
mandrel; and an expandable packer element disposed about the packer
mandrel; compressing the expandable packer element by lowering the
packer mandrel relative to the expandable packer element thereby
expanding the packer element outward to engage and seal a casing in
the wellbore below the formation, wherein the compressing step
seals the longitudinal opening to prevent communication
therethrough; displacing a low-molecular-weight fluid down the work
string and into the wellbore through a flow port defined in the
work string above the first packer apparatus, so as to create or
extend at least one fracture in the subterranean formation, the
low-molecular-weight fluid having the capability of enhancing the
regain permeability of the formation; unsealing the longitudinal
opening after the displacing step to communicate a portion of the
wellbore above the expandable packer element with a portion of the
wellbore below the expandable packer element through the
longitudinal opening to equalize a pressure in the wellbore above
and below the expandable packer element; disengaging the expandable
packer element from the casing; and moving the packer apparatus to
another formation adjacent the well and repeating the step of
displacing a low-molecular-weight fluid down the work string and
into the wellbore to create or extend at least one fracture in the
formation.
[0066] Therefore, the present invention is well adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those that are inherent therein. While the invention has
been depicted and described by reference to particular embodiments
of the invention, such a reference does not imply a limitation on
the invention, and no such limitation is to be inferred. The
invention is capable of considerable modification, alternation, and
equivalents in form and function, as will occur to those ordinarily
skilled in the pertinent arts and having the benefit of this
disclosure. The depicted and described embodiments of the invention
are exemplary only, and are not exhaustive of the scope of the
invention. Consequently, the invention is intended to be limited
only by the spirit and scope of the appended claims, giving full
cognizance to equivalents in all respects.
* * * * *