U.S. patent number RE32,302 [Application Number 06/763,121] was granted by the patent office on 1986-12-09 for fracturing method for stimulation of wells utilizing carbon dioxide based fluids.
This patent grant is currently assigned to Halliburton Company. Invention is credited to Stephen W. Almond, Phillip C. Harris.
United States Patent |
RE32,302 |
Almond , et al. |
December 9, 1986 |
Fracturing method for stimulation of wells utilizing carbon dioxide
based fluids
Abstract
A method of fracturing a subterranean formation with a
stabilized foamed fracturing fluid comprising from about 50 percent
to in excess of about 96 percent by volume of carbon dioxide with
the remainder comprising an aqueous liquid and a selected
surfactant. The foam is formed in situ by injection of a stabilized
liquid-liquid emulsion containing liquid carbon dioxide into a well
bore penetrating the formation. The temperature and pressure of the
emulsion is controlled to maintain the carbon dioxide in the liquid
phase during injection into the well bore. Thereafter, the carbon
dioxide is heated by the subterranean formation to a temperature
above about 88.degree. F. at which time the stabilized emulsion
spontaneously forms a high quality stabilized foam.
Inventors: |
Almond; Stephen W. (Ventura,
CA), Harris; Phillip C. (Duncan, OK) |
Assignee: |
Halliburton Company (Duncan,
OK)
|
Family
ID: |
27031095 |
Appl.
No.: |
06/763,121 |
Filed: |
August 6, 1985 |
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
Reissue of: |
436763 |
Oct 25, 1982 |
04480696 |
Nov 6, 1984 |
|
|
Current U.S.
Class: |
166/308.6;
507/240; 507/254; 507/261; 507/922 |
Current CPC
Class: |
C09K
8/703 (20130101); E21B 43/267 (20130101); E21B
43/26 (20130101) |
Current International
Class: |
E21B
43/26 (20060101); C09K 8/60 (20060101); C09K
8/70 (20060101); E21B 43/267 (20060101); E21B
43/25 (20060101); E21B 043/267 () |
Field of
Search: |
;166/308,283,281,271,280,307 ;252/8.55R |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Halliburton Company Invoice Nos.
033340;033344;116114;186539;613751;618150;714098;715976;715986;716410;8200
54;820068;820397;820672;959937;900908;048069;069981;070030;194307;490871;73
1653;820065;822186;860145;909865;586274;956229;961361;994305;068480;085629;
183219;715983;924621. .
Declaration of Lacy Clark Lance. .
Complaint, Defendant's Answer and Counterclaim and Plaintiff's
reply to the counterclaim filed in Civil Action No. CIV-85-430R,
United States District Court for the Western District of Oklahoma.
.
Motion to Stay Proceedings Pending a Determination Upon Plaintiff's
Application for Reissue of the Patent in Suit and Memorandum in
Support of Plaintiff's Motion to Stay Proceedings Pending a
Determination Upon Plaintiff's Application for Reissue of the
Patent in Suit, both filed in Civil Action No. CIV-85-430R, United
States District Court for the Western District of Oklahoma. .
Treatment Reports (Bates Nos. 0984-0987). .
Treatment Report (Bates No. 1046). .
Treatment Reports (Bates Nos. 1047-1050). .
Treatment Report (Bates Nos. 1058-1062). .
Treatment Report (Bates Nos. 1191-1194). .
Treatment Report (Bates Nos. 1195-1196). .
Plaintiff's Answers to Defendant's First Interrogatories and
Request for Production of Documents. .
SPE Paper No. 9705, Energized Fracturing with Fifty Percent Carbon
Dioxide for Improved Hydrocarbon, Black & Langsford. .
Article entitled "Energized Fracturing with 50% CO.sub.2 for
Improved Hydrocarbon Recovery," Black & Langsford. .
Carbon Dioxide Engineering-Bates No. 0420-0446. .
Carbon Dioxide-A Multipurpose Additive for Effective Well
Stimulation-Bates No. 0447-0453. .
Increase Treatment Benefits with Western's CO.sub.2 Service Bates
No. 0454-0457. .
The Use of Carbon Dioxide in Well Stimulation Work Bates No.
0656-0686. .
Sand Fracturing with Liquid Carbon Dioxide-Bates No. 0798-0805.
.
Treatment Recommendation for Kansas-Nebraska Natural Gas in the
Council Grove of the Hugoton Field, Bates No. 0840-0858. .
Treatment Report, Bates No. 859-861. .
Stimulation Proposal-ARCO Oil and Gas, State "F" Lea County, NM,
Bates No. 0976-0982. .
Treatment Report, Bates No. 0983. .
Treatment Report, Bates No. 0988-0992. .
Stimulation Proposal ARCO Oil & Gas Co. McDonald State #30 Lea
County, NM, Bates No. 1101-1112. .
Stimulation Proposal-ARCO Oil & Gas Co. McDonald State #30 Lea
County, NM (Bates Nos. 1113-1124). .
Stimulation Proposal-ARCO Gas & Oil Co. H.S. Record WN #2 South
Eunice Field Sec. 10-T22S-R36E Lea Co. NM Bates No. 1133-1157.
.
Treatment Report, Bates No. 1169. .
Treatment Report, Bates No. 1170. .
Stimulation Proposal-ARCO Oil & Gas State "F" DE #1 Lea County,
NM, Bates No. 1184-1190. .
Treatment Report, Bates No. 1063. .
Transcript of Deposition of Charles L. Smith, Agent for B.
J.-Titan, taken on May 8, 1985. .
Transcript of Lance taken on Mar. 25, 1985. .
Transcript of Deposition of Phillip C. Harris. .
Transcript of Lawrence John Harrington taken on Jul. 1,
1985..
|
Primary Examiner: Novosad; Stephen J.
Attorney, Agent or Firm: Kent; Robert A. Weaver; Thomas
R.
Claims
What is claimed is:
1. A method of fracturing a subterranean formation penetrated by a
well bore comprising:
admixing an aqueous liquid with liquid carbon dioxide and a
selected surfactant comprising at least one member selected from
the group consisting of alkyl quaternary amines, betaines, sulfated
alkoxylates and ethoxylated linear alcohols to form a stabilized
emulsion, said emulsion comprising .Iadd.an amount of liquid carbon
dioxide whereby upon conversion of said liquid carbon dioxide to a
gas and said emulsion to a foam, said foam contains .Iaddend.from
about .[.50.]. .Iadd.53 .Iaddend.to in excess of about 96 percent
by per volume carbon dioxide and said surfactant being present in
said emulsion in an amount sufficient to stabilize said
emulsion;
introducing said emulsion into said well bore penetrating said
subterranean formation at a temperature below the critical
temperature of carbon dioxide and under sufficient pressure to
maintain the carbon dioxide as a liquid;
maintaining said emulsion within said formation for a sufficient
time to permit said emulsion to be heated to a temperature above
the critical temperature of carbon dioxide to form a stabilized
foam from said emulsion, said foam having a viscosity immediately
after formation which is substantially the same as the viscosity of
the emulsion; and
fracturing said subterranean formation with said foam.
2. The method of claim 1 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of the emulsion.
3. The method of claim 1 wherein said emulsion contains a gelling
agent comprising a hydratable polymer.
4. A method of claim 1 wherein said emulsion contains a proppant
material.
5. The method of claim 4 wherein said proppant is present in an
amount of from about 0.5 pound to about 15 pounds per gallon of
emulsion.
6. The method of claim 1 wherein said emulsion contains a gelling
agent comprising a hydratable polymer in an amount of from about 10
pounds to about 80 pounds per 1,000 gallons of aqueous liquid.
7. A method of fracturing a subterranean formation penetrated by a
well bore comprising:
admixing an aqueous liquid with a proppant material, liquid carbon
dioxide and a selected surfactant comprising at least one member
selected from the group consisting of alkyl quaternary amines,
betaines, sulfated alkoxylates and ethoxylated linear alcohols to
form a stabilized emulsion, said emulsion comprising .Iadd.an
amount of liquid carbon dioxide whereby upon conversion of said
liquid carbon dioxide to a gas and said emulsion to a foam, said
foam contains .Iaddend.from about .[.50.]. .Iadd.53 .Iaddend.to in
excess of about 96 percent by volume carbon dioxide and said
surfactant being present in said emulsion in an amount sufficient
to stabilize said emulsion;
introducing said stabilized emulsion into said well bore
penetrating said subterranean formation at a temperature below the
critical temperature of carbon dioxide and under sufficient
pressure to maintain the carbon dioxide as a liquid;
maintaining said stabilized emulsion within said formation for a
sufficient time to permit said emulsion to be heated to a
temperature above the critical temperature of carbon dioxide to
form a stabilized foam from said emulsion, said foam having a
viscosity immediately after formation which is substantially the
same as the viscosity of the emulsion;
contacting said formation with said foam at a pressure sufficient
to create at least one fracture in said subterranean formation;
and
depositing said proppant material in said fracture in said
subterranean formation.
8. The method of claim 7 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of the emulsion.
9. The method of claim 7 wherein said emulsion contains a gelling
agent comprising a hydratable polymer.
10. The method of claim 7 wherein said proppant is present in an
amount of from about 0.5 pound to about 15 pounds per gallon of
emulsion.
11. The method of claim 7 wherein said emulsion contains a gelling
agent comprising a hydratable polymer in an amount of from about 10
pounds to about 80 pounds per 1,000 gallons of aqueous liquid.
12. A method of fracturing a subterranean formation penetrated by a
well bore comprising:
admixing an aqueous liquid and a gelling agent with liquid carbon
dioxide and a selected surfactant to form a stabilized emulsion,
said emulsion comprising .Iadd.an amount of liquid carbon dioxide
whereby upon conversion of said liquid carbon dioxide to a gas and
said emulsion to a foam, said foam contains .Iaddend.from about
.[.50.]. .Iadd.53 .Iaddend.to in excess of about 96 percent by
volume carbon dioxide and said surfactant being present in said
emulsion in an amount sufficient to stabilize said emulsion and
said gelling agent comprising a hydratable polymer present in an
amount of from about 10 pounds to about 80 pounds per 1000 gallons
of aqueous liquid and an inhibitor to retard the hydration rate of
the hydratable polymer;
introducing said emulsion into said well bore penetrating said
subterranean formation at a temperature below the critical
temperature of carbon dioxide and under sufficient pressure to
maintain the carbon dioxide as a liquid;
maintaining said emulsion within said formation for a sufficient
time to permit said emulsion to be heated to a temperature above
the critical temperature of carbon dioxide to form a stabilized
foam from said emulsion, said foam having a viscosity immediately
after formation which is substantially the same as the viscosity of
the emulsion; and
fracturing said subterranean formation with said foam.
13. The method of claim 12 wherein said surfactant comprises at
least one member selected from the group consisting of alkyl
quaternary amines, betaines, sulfated alkoxylates and ethyoxylated
linear alcohols.
14. The method of claim 12 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of the emulsion.
15. A method of fracturing a subterranean formation penetrated by a
well bore comprising:
admixing an aqueous liquid and a gelling agent comprising a
hydratable polymer and an inhibitor to retard the hydration rate of
said hydratable polymer with a proppant material, liquid carbon
dioxide and a selected surfactant to form a stabilized emulsion,
said emulsion comprising .Iadd.an amount of liquid carbon dioxide
whereby upon conversion of said liquid carbon dioxide to a gas and
said emulsion to a foam, said foam contains .Iaddend.from about
.[.50.]. .Iadd.53 .Iaddend.to in excess of about 96 percent by
volume carbon dioxide, said surfactant being present in said
emulsion in an amount sufficient to stabilize said emulsion and
said gelling agent being present in an amount of from about 10
pounds to about 80 pounds per 1000 gallons of aqueous liquid;
introducing said stabilized emulsion into said well bore
penetrating said subterranean formation at a temperature below the
critical temperature of carbon dioxide and under sufficient
pressure to maintain the carbon dioxide as a liquid;
maintaining said stabilized emulsion within said formation for a
sufficient time to permit said emulsion to be heated to a
temperature above the critical temperature of carbon dioxide to
form a stabilized foam from said emulsion, said foam having a
viscosity immediately after formation which is substantially the
same as the viscosity of the emulsion;
contacting said formation with said foam at a pressure sufficient
to create at least one fracture in said subterranean formation;
and
depositing said proppant material in said fracture in said
subterranean formation.
16. The method of claim 15 wherein said surfactant comprises at
least one member selected from the group consisting of alkyl
quaternary amines, betaines, sulfated alkoxylates and ethyoxylated
linear alcohols.
17. The method of claim 15 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of the emulsion.
18. The method of claim 15 wherein said proppant is present in an
amount of from about 0.5 pound to about 15 pounds per gallon of
emulsion. .Iadd.
19. A method of fracturing a subterranean formation penetrated by a
well bore comprising:
admixing an aqueous liquid with liquid carbon dioxide and a
selected surfactant comprising at least one member selected from
the group consisting of alkyl quaternary amines, betaines, sulfated
alkoxylates and ethoxylated linear alcohols to form a stabilized
emulsion, said emulsion comprising from about 67 to about 95
percent by volume carbon dioxide and said surfactant being present
in said emulsion in an amount sufficient to stabilize said
emulsion;
introducing said emulsion into said well bore penetrating said
subterranean formation at a temperature below the critical
temperature of carbon dioxide and under sufficient pressure to
maintain the carbon dioxide as a liquid;
maintaining said emulsion within said formation for a sufficient
time to permit said emulsion to be heated to a temperature above
the critical temperature of carbon dioxide to form a stabilized
foam from said emulsion, said foam having a viscosity immediately
after formation which is substantially the same as the viscosity of
the emulsion; and
fracturing said subterranean formation with said foam..Iaddend.
.Iadd.
20. The method of claim 19 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of the emulsion..Iaddend. .Iadd.21. The method of
claim 19 wherein said emulsion contains a gelling agent comprising
a hydratable polymer..Iaddend. .Iadd.22. The method of claim 21
wherein said emulsion contains a proppant material..Iaddend.
.Iadd.23. The method of claim 22 wherein said proppant is present
in an amount of from about 0.5 pound to about 15 pounds per gallon
of emulsion..Iaddend. .Iadd.24. The method of claim 21 wherein said
emulsion contains a gelling agent comprising a hydratable polymer
in an amount of from about 10 pounds to about 80 pounds
per 1,000 gallons of aqueous liquid..Iaddend. .Iadd.25. A method of
fracturing a subterranean formation penetrated by a well bore
comprising:
admixing an aqueous liquid with a proppant material, liquid carbon
dioxide and a selected surfactant comprising at least one member
selected from the group consisting of alkyl quaternary amines,
betaines, sulfated alkoxylates and ethoxylated linear alcohols to
form a stabilized emulsion, said emulsion comprising from about 67
to about 95 percent by volume carbon dioxide and said surfactant
being present in said emulsion in an amount sufficient to stabilize
said emulsion;
introducing said stabilized emulsion into said well bore
penetrating said subterranean formation at a temperature below the
critical temperature of carbon dioxide and under sufficient
pressure to maintain the carbon dioxide as a liquid;
maintaining said stabilized emulsion within said formation for a
sufficient time to permit said emulsion to be heated to a
temperature above the critical temperature of carbon dioxide to
form a stabilized foam from said emulsion, said foam having a
viscosity immediately after formation which is substantially the
same as the viscosity of the emulsion;
contacting said formation with said foam at a pressure sufficient
to create at least one fracture in said subterranean formation;
and
depositing said proppant material in said fracture in said
subterranean formation..Iaddend. .Iadd.26. The method of claim 25
wherein said surfactant is present in a concentration in the range
of from about 0.05 percent to about 2.0 percent by weight of the
emulsion..Iaddend. .Iadd.27. The method of claim 25 wherein said
emulsion contains a gelling agent comprising a hydratable
polymer..Iaddend. .Iadd.28. The method of claim 27 wherein said
hydratable polymer is present in said emulsion in an amount of from
about 10 pounds to about 80 pounds per 1,000 gallons of aqueous
liquid..Iaddend. .Iadd.29. The method of claim 28 wherein said
proppant is present in an amount of from about 0.5 pound to about
15 pounds per gallon
of emulsion..Iaddend. .Iadd.30. A method of fracturing a
subterranean formation having a temperature above the critical
temperature of carbon dioxide and penetrated by a well bore
comprising:
admixing an aqueous liquid containing a gelling agent with liquid
carbon dioxide and a selected surfactant comprising at least one
member selected from the group consisting of alkyl quaternary
amines, betaines, sulfated alkoxylates and ethoxylated linear
alcohols to form a stabilized emulsion, said emulsion comprising an
amount of liquid carbon dioxide whereby upon conversion of said
liquid carbon dioxide to a gas and said emulsion to a foam, said
foam contains from about 53 to in excess of about 96 percent by
volume carbon dioxide and said surfactant being present in said
emulsion in an amount sufficient to stabilize said emulsion;
introducing said emulsion into said well bore penetrating said
subterranean formation at a temperature below the critical
temperature of carbon dioxide and under sufficient pressure to
maintain the carbon dioxide as a liquid; and
continuing the introduction of said emulsion into said well bore
and into said formation so that said emulsion is heated to a
temperature above the critical temperature of carbon dioxide to
form a stabilized foam from said emulsion and so that fractures are
formed in said subterranean
formation..Iaddend. .Iadd.31. The method of claim 30 wherein a
proppant material is admixed with said aqueous liquid, gelling
agent, liquid carbon dioxide and surfactant..Iaddend. .Iadd.32. The
method of claim 31 wherein said gelling agent is a hydratable
polymer and is present in said emulsion in an amount of from about
10 pounds to about 80 pounds per 1,000 gallons of aqueous liquid in
said emulsion..Iaddend. .Iadd.33. The method of claim 32 wherein
said surfactant is present in said emulsion in an amount in the
range of from about 0.05 percent to about 2.0 percent by weight of
said emulsion..Iaddend. .Iadd.34. The method of claim 33 wherein
said proppant material is present in said emulsion in an amount of
from about 0.5 pound
to about 15 pounds per gallon of emulsion..Iaddend. .Iadd.35. A
method of fracturing a subterranean formation having a temperature
above the critical temperature of carbon dioxide and penetrated by
a well bore comprising:
admixing an aqueous liquid containing a gelling agent with liquid
carbon dioxide and a selected surfactant comprising at least one
member selected from the group consisting of alkyl quaternary
amines, betaines, sulfated alkoxylates and ethoxylated linear
alcohols to form a stabilized emulsion, said emulsion comprising
from about 67 to about 95 percent by volume carbon dioxide and said
surfactant being present in said emulsion in an amount sufficient
to stabilize said emulsion;
introducing said emulsion into said well bore penetrating said
subterranean formation at a temperature below the critical
temperature of carbon dioxide and under sufficient pressure to
maintain the carbon dioxide as a liquid; and
continuing the introduction of said emulsion into said well bore
and into said formation so that said emulsion is heated to a
temperature above the critical temperature of carbon dioxide to
form a stabilized foam from said emulsion and so that fractures are
formed in said subterranean
formation..Iaddend. .Iadd.36. The method of claim 35 wherein a
proppant material is admixed with said aqueous liquid, gelling
agent, liquid carbon dioxide and surfactant..Iaddend. .Iadd.37. The
method of claim 36 wherein said gelling agent is a hydratable
polymer and is present in said emulsion in an amount of from about
10 pounds to about 80 pounds per 1,000 gallons of aqueous liquid in
said emulsion..Iaddend. .Iadd.38. The method of claim 37 wherein
said surfactant is present in said emulsion in an amount in the
range of from about 0.05 percent to about 2.0 percent by weight of
said emulsion..Iaddend. .Iadd.39. The method of claim 38 wherein
said proppant is present in said emulsion in an amount of from
about 0.5 pound to about
15 pounds per gallon of emulsion..Iaddend. .Iadd.40. A method of
fracturing a subterranean formation having a temperature above the
critical temperature of carbon dioxide and penetrated by a well
bore comprising:
admixing an aqueous liquid, a hydratable polymer gelling agent and
a proppant material with liquid carbon dioxide and a selected
surfactant to form a stabilized emulsion, said emulsion comprising
an amount of liquid carbon dioxide whereby upon conversion of said
liquid carbon dioxide to a gas and said emulsion to a foam, said
foam contains from about 53 to in excess of about 96 percent by
volume carbon dioxide and said surfactant being present in said
emulsion in an amount sufficient to stabilize said emulsion;
introducing said stabilized emulsion into said well bore
penetrating said subterranean formation at a temperature below the
critical temperature of carbon dioxide and under sufficient
pressure to maintain the carbon dioxide as a liquid;
continuing the introduction of said emulsion into said well bore
and into said formation so that said emulsion is heated to a
temperature above the critical temperature of carbon dioxide to
form a foam from said emulsion which is stabilized by said
surfactant and supports proppant material in a concentration
substantially the same as the concentration of the proppant
material in said emulsion and so that fractures are formed in said
subterranean formation and proppant material is carried into and
deposited
in said fractures..Iaddend. .Iadd.41. The method of claim 40
wherein said surfactant comprises at least one member selected from
the group consisting of alkyl quaternary amines, betaines, sulfated
alkoxylates and ethoxylated linear alcohols..Iaddend. .Iadd.42. The
method of claim 40 wherein said surfactant is present in a
concentration in the range of from about 0.05 percent to about 2.0
percent by weight of said emulsion..Iaddend. .Iadd.43. The method
of claim 42 wherein said hydratable polymer gelling agent is
present in said emulsion in an amount of from about 10 to about 80
pounds per 1,000 gallons of aqueous liquid..Iaddend. .Iadd.44. The
method of claim 43 wherein said proppant is present in said
emulsion in an amount of from about 0.5 pound to about 15
pounds per gallon of emulsion..Iaddend. .Iadd.45. A method of
fracturing a subterranean formation having a temperature above the
critical temperature of carbon dioxide penetrated by a well bore
comprising:
admixing an aqueous liquid, a hydratable polymer gelling agent and
a proppant material with liquid carbon dioxide and a selected
surfactant to form a stabilized emulsion, said emulsion comprising
from about 67 to about 95 percent by volume carbon dioxide and said
surfactant being present in said emulsion in an amount sufficient
to stabilize said emulsion;
introducing said stabilized emulsion into said well bore
penetrating said subterranean formation at a temperature below the
critical temperature of carbon dioxide and under sufficient
pressure to maintain the carbon dioxide as a liquid;
continuing the introduction of said emulsion into said well bore
and into said formation so that said emulsion is heated to a
temperature above the critical temperature of carbon dioxide to
form a foam from said emulsion which is stabilized by said
surfactant and supports proppant material in a concentration
substantially the same as the concentration of the proppant
material in said emulsion and so that fractures are formed in said
subterranean formation and proppant material is carried into and
deposited in said fractures..Iaddend. .Iadd.46. The method of claim
45 wherein said surfactant comprises at least one member selected
from the group consisting of alkyl quaternary amines, betaines,
sulfated alkoxylates and ethoxylated linear alcohols..Iaddend.
.Iadd.47. The method of claim 45 wherein said surfactant is present
in a concentration in the range of from about 0.05 percent to about
2.0 percent by weight of said emulsion..Iaddend. .Iadd.48. The
method of claim 47 wherein said hydratable polymer gelling agent is
present in said emulsion in an amount of from about 10 to about 80
pounds per 1,000 gallons of aqueous liquid..Iaddend. .Iadd.49. The
method of claim 48 wherein said proppant is present in said
emulsion in an amount of from about 0.5 pound to about 15 pounds
per gallon of emulsion..Iaddend.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to a method of fracturing subterranean
formations penetrated by a well bore utilizing carbon dioxide based
fluids. More particularly, this invention relates to a method of
fracturing a subterranean formation with a two-phase fluid.
2. Description of the Prior Art
The treatment of subterranean formations penetrated by a well bore
to stimulate the production of hydrocarbons therefrom or the
ability of the formation to accept injected fluids has long been
known in the art. One of the most common methods of increasing
productivity of a hydrocarbon-bearing formation is to subject the
formation to a fracturing treatment. This treatment is effected by
injecting a liquid, gas or two-phase fluid which generally is
referred to as a fracturing fluid down the well bore at sufficient
pressure and flow rate to fracture the subterranean formation. A
proppant material such as sand, fine gravel, sintered bauxite,
glass beads or the like can be introduced into the fractures to
keep them open. The propped fracture provides larger flow channels
through which an increased quantity of a hydrocarbon can flow,
thereby increasing the productive capability of a well.
A traditional fracturing technique utilizes a water or oil-based
fluid to fracture a hydrocarbon-bearing formation.
Another successful fracturing technique has been that known as
"foam fracturing". This process is described in, for example, U.S.
Pat. No. 3,980,136. Briefly, that process involves generation of a
foam of a desired "Mitchell quality" which then is introduced
through a well bore into a formation which is to be fractured. The
composition of the foam is such that the Mitchell foam quality at
the bottom of the well is in the range of from about 0.53 to 0.99.
Various gases and liquids can be used to create the foam, but foams
generally used in the art are made from nitrogen and water, in the
presence of a suitable surfactant, the pressure at which the foam
is pumped into the well is such that it will cause a fracture of
the hydrocarbon-bearing formation. Additionally, the foam comes out
of the well easily when the pressure is released from the well
head, because the foam expands when the pressure is reduced.
Yet another fracturing technique has been that utilizing a
liquified, normally gaseous fluid. U.S. Pat. No. 3,195,634, for
example, discloses a method for treating a subterranean formation
penetrated by a well bore with a composition comprising a
liquid-liquid mixture of carbon dioxide and water. The carbon
dioxide is present in an amount equivalent to from about 300 to
about 1500 SCF at 80.degree. F. and 14.7 psia per 42 gallons of
water. The composition is injected into the formation under
sufficient pressure to fracture the formation. The composition can
include gelling agents and proppant materials. Upon pressure
release at the well head, the liquid carbon dioxide vaporizes and
flows from the formation.
U.S. Pat. No. 3,310,112 discloses a method of fracturing a
subterranean formation penetrated by a well bore comprising
introduction of a mixture of liquid carbon dioxide and a propping
agent slurried in a suitable vehicle into the well bore at a
pressure sufficient to fracture the formation. The liquid carbon
dioxide is present in an amount sufficient to provide at least five
volumes of carbon dioxide per volume of slurried propping agent.
After injection of the liquid carbon dioxide containing the
propping agent, the pressure on the well bore is released. The
liquid carbon dioxide normally is heated sufficiently by the
formation that upon pressure release, the liquid changes to a gas.
A substantial portion of the carbon dioxide then leaves the well
and forces or carries out with it an appreciable amount of the oil
or aqueous vehicle utilized to transport the proppant.
U.S. Pat. No. 3,368,627 discloses a method of treating a formation
penetrated by a well bore which consists essentially of injecting
down the well bore a fluid azeotropic mixture which has a critical
temperature sufficiently high or a critical pressure sufficiently
low to remain a liquid at the temperature and pressure existing
during injection and treatment of the formation. The fluid mixture
has critical properties such that a substantial portion of the
injected fluid is converted to a gas upon a release of the pressure
applied to the liquid during injection into the formation. The
fluid mixture consists essentially of carbon dioxide and at least
one C.sub.2 to C.sub.6 hydrocarbon.
U.S. Pat. No. 3,664,422 discloses a method of treating a subsurface
earth formation penetrated by a well bore comprising injection of a
liquified gas together with a gelled alcohol into the formation at
a pressure sufficient to fracture the formation. The liquified gas
is returned from the formation by vaporization following pressure
reduction on the well bore. The gelled alcohol is removed by
vaporization during subsequent production from the well leaving
only the broken gelling agent in the formation.
It would be desirable to provide a method by which a viscous fluid
can be created from carbon dioxide and an aqueous fluid which is
stable over a broad temperature range and is capable of carrying
high concentrations of proppant into a subterranean formation.
SUMMARY OF THE INVENTION
The present invention relates to a method and fluids for forming
fractures in subterranean formations penetrated by a well bore and
transporting increased concentrations of proppant material into the
formation penetrated by the well bore. The method and fluids permit
increased penetration of the formation by the fluids together with
low fluid leak-off to the formation and the ability to carry high
concentrations of proppant material without proppant settling in
the fracturing fluids. The fracturing fluids of the invention are
stabilized liquid-liquid emulsions of liquified carbon dioxide and
an aqueous fluid at surface conditions, and the emulsion is
converted into a gas-in-liquid foam upon heating in the formation
to a temperature above the critical temperature of the carbon
dioxide. The fracturing fluids comprise from about 50 to in excess
of 96 percent by volume carbon dioxide. The fracturing fluid
contains a surfactant which stabilizes the emulsion and foam which
is produced against breakdown and can include gelling agents for
additional stability, proppant material and the like.
The emulsions and foams produced by the method of the present
invention are characterized by a high quality, that is, the ratio
of the carbon dioxide volume to the volume of the carbon dioxide
and aqueous liquids in the fluid is very high and the emulsions and
foams have a viscosity sufficient to transport significant
concentrations of proppant material. The emulsion which is formed
by practice of the present method has a very fine cell size
distribution or texture which is sufficiently stable to support
proppant material in concentrations up to a level in excess of
about 15 pounds per gallon of emulsion.
DESCRIPTION OF THE PREFERRED EMBODIMENT
In the practice of the present invention, a fracturing fluid is
prepared by admixing, under suitable conditions of temperature and
pressure, a quantity of liquified carbon dioxide with an aqueous
liquid and a surfactant to form a stabilized liquid-liquid
emulsion.
The liquified carbon dioxide is provided from a surface vessel at a
temperature and pressure sufficient to maintain the liquid
conditions of the normally gaseous carbon dioxide, such as for
example, a temperature of about 0.degree. F. and a pressure of
about 300 psia. The liquid carbon dioxide is admixed with the
aqueous fluid in an amount sufficient to provide a volumetric ratio
of liquid carbon dioxide to aqueous fluid in the range of from
about 1:1 to about 20:1. Preferably, the ratio is in the range of
from about 2:1 to about 18:1. The foam formed from the emulsion
will have a quality of from about 50 percent to in excess of about
96 percent. The term "quality" as used herein is intended to mean
the percentage of the volume of carbon dioxide at the existing
temperature and pressure within the formation to the volume of the
carbon dioxide plus the volume of the aqueous fluid and any other
liquid components present in the fracturing fluid.
The aqueous liquid can comprise any aqueous solution which does not
adversely react with the constituents of the fracturing fluid, the
subterranean formation or the hydrocarbons present therein. The
aqueous liquid can comprise, for example, water, a potassium
chloride solution, water-alcohol mixtures or the like.
The liquid carbon dioxide and aqueous liquid can be admixed in a
pressurized mixer or other suitable apparatus. In one preferred
embodiment, the carbon dioxide and aqueous liquid are admixed by
turbulent contact at a simple "T" connection in the fracturing
fluid injection pipeline to form the emulsion. The emulsion will
have a temperature below about the critical temperature of the
carbon dioxide. The liquid-liquid emulsion is stabilized by the
addition of a quantity of a selected surfactant. The surfactant
comprises cationic, anionic or nonionic compounds, such as for
example, betaines, sulfated alkoxylates, alkyl quaternary amines or
ethoxylated linear alcohols. The particular surfactant employed
will depend upon the type of formation which is to be fractured.
The surfactant is admixed with the emulsion in an amount of from
about one-half to about 20 gallons per 1000 gallons of emulsion to
provide a surfactant concentration of from about 0.05 percent to
about 2.0 percent by weight. It is to be understood that larger
quantities of the designated surfactants can be employed, however,
such use is uneconomical. The surfactant, preferably, is admixed
with the aqueous liquid prior to formation of the emulsion to
facilitate uniform admixing.
The stabilized emulsion which is formed is characterized by a very
fine cell size distribution or texture. The term "cell size" as
used herein means the size of the gaseous or liquid carbon dioxide
droplet which is surrounded by the aqueous fluid in the emulsion.
The term "texture" as used herein means the general appearance of
the distributed cells of gaseous or liquid carbon dioxide in the
emulsion. The fine texture of the emulsion of the present invention
permits the transport of high concentrations of proppant material.
The fine texture of the emulsion also results in the formation of a
foam having a smaller cell size than otherwise would be possible
such as by conventional foam generation methods in which the foam
is generated on the surface and pumped into the subterranean
formation.
In one preferred embodiment, a gelling agent is admixed with the
aqueous liquid prior to formation of the emulsion. The gelling
agent can comprise, for example hydratable polymers which contain,
in sufficient concentration and reactive position, one or more of
the functional groups, such as, hydroxyl, cis-hydroxyl, carboxyl,
sulfate, sulfonate, amino or amide. Particularly sutiable such
polymers are polysaccharides and derivatives thereof which contain
one or more of the following monosaccharide units: galactose,
mannose, glucoside, glucose, xylose, arabinose, fructose,
glucuronic acid or pyranosyl sulfate. Natural hydratable polymers
containing the foregoing functional groups and units include guar
gum and derivatives thereof, locust bean gum, tara, konjak,
tamarind, starch, cellulose and derivatives thereof, karaya,
xanthan, tragacanth and carrageenan.
Hydratable synthetic polymers and copolymers which contain the
above-mentioned functional groups and which can be utilized in
accordance with the present invention include, but are not limited
to, polyacrylate, polymethacrylate, polyacrylamide, maleic
anhydride methylvinyl ether copolymers, polyvinyl alcohol, and
polyvinylpyrrolidone.
Various compounds can be utilized with the above-mentioned
hydratable polymers in an aqueous solution to inhibit or retard the
hydration rate of the polymers, and therefore, delay a viscosity
increase in the solution for a required period of time. Depending
upon the particular functional groups contained in the polymer,
different inhibitors react with the functional groups to inhibit
hydration. For example, inhibitors for cis-hydroxyl functional
groups include compounds containing multivalent metals which are
capable of releasing the metal ions in an aqueous solution,
borates, silicates, and aldehydes. Examples of the multivalent
metal ions are chrominum, zirconium, antimony, titanium, iron
(ferrous or ferric), tin, zinc and aluminum. Inhibitors for
hydroxyl functional groups include mono- and di-functional
aldehydes containing from about 1 to about 5 carbon atoms and
multivalent metal salts that form hydroxide. Multivalent metal
salts or compounds can be utilized as inhibitors for the hydroxyl
functional groups. Inhibitors for amides include aldehydes and
multivalent metal salts or compounds. Generally, any compound can
be used as an inhibitor for a hydratable polymer if the compound
reacts or otherwise combines with the polymer to cross-link, form a
complex or otherwise tie-up the functional groups of the polymer
whereby the rate of hydration of the polymer is retarded.
As stated above, the functional groups contained in the polymer or
polymers utilized must be in sufficient concentration and in a
reactive position in interact with the inhibitors. Preferred
hydratable polymers which yield high viscosities upon hydration,
that is, apparent viscosities in the range of from about 10
centipoise to about 90 centipoise at a concentration in the range
of from about 10 lbs/1000 gals. to about 80 lbs/1000 gals. in
water, are guar gum and guar derivatives such as hydroxypropyl guar
and carboxymethylguar, cellulose derivatives such as
hydroxyethylcellulose, carboxymethylcellulose, and
carboxymethyl-hydroxyethylcellulose, locust bean gum, carrageenan
gum and xanthan gum. Xanthan gum is a biopolysaccharide produced by
the action of bacteria of the genus Xanthonomas. The hydration of
the polymers can be inhibited or retarded by various inhibitors
present in the aqueous liquid. The reversal of the inhibition of
such polymers by the inhibitors can be accomplished by a change in
the pH of the solution or by heating the solution to an appropriate
temperature, generally above about 140.degree. F.
Examples of some of the inhibitors which can be utilized depending
upon the particular polymer or polymers used in the aqueous liquid
are sodium sulfite-sodium dichromate, aluminum sulfate, titanium
triethanolamine chelate, basic potassium pyroantimonate, zinc
chloride, iron chloride, tin chloride, zirconium oxychloride in
hydrochloric acid solution, sodium tetraborate and glyoxal. The
gelled aqueous liquid thus formed can be used to transport
significant quantities of proppant material to the point of mixing
with the carbon dioxide. The proppant material can comprise, for
example, sand, graded gravel, glass beads, sintered bauxite,
resin-coated sand or the like.
The proppant material is admixed with the gelled aqueous liquid
prior to admixing with the liquid carbon dioxide. The admixing of
the proppant material with the gelled liquid can be effected in any
suitable mixing apparatus, such as for example, a batch mixer or
the like.
The amount of proppant material admixed with the gelled aqueous
liquid may be varied to provide the desired amount of proppant in
the two-phase fluid introduced into the formation. The proppant
material can be admixed with the aqueous liquid in an amount of
from about zero pounds of proppant per gallon of aqueous liquid up
to as many pounds of proppant material per gallon as may be pumped.
Depending upon formation reservoir conditions, the amount of
proppant material transported by the two-phase fluid within the
subterranean formation generally can be in the range of from about
1/2 pound to about 15 pounds per gallon of two-phase fracturing
fluid without a screen out occurring.
The fracturing fluid of the present invention is introduced into
the well bore which penetrates the subterranean formation to be
treated at a temperature below the critical temperature of the
carbon dioxide and at a pressure above the critical pressure of the
carbon dioxide. The initial viscosity of the liquid-liquid emulsion
comprising the fracturing fluid is such that the fluid is easily
pumped through the well bore, however, the viscosity of the fluid
still is sufficient to support a significant quantity of proppant
material.
As the fracturing fluid is introduced into the subterranean
formation, the fluid slowly is heated to a temperature above the
critical temperature of the carbon dioxide. Surprisingly, it has
been found that when the stabilized liquid-liquid emulsion is
heated to a temperature above the critical temperature of the
carbon dioxide, the fluid maintains its viscosity and undergoes
conversion into a foam. The foam as well as the emulsion is
stabilized by the presence of the surfactant and the gelling agent
present in the fracturing fluid. As the liquid carbon dioxide
undergoes conversion to a gas, a slight increase in the volume of
the carbon dioxide is found to occur. The term "gas" as used herein
means a fluid at a temperature equal to or above the critical
temperature of the fluid while maintained at any given pressure.
Upon conversion of the stabilized liquid-liquid emulsion of the
present invention to a foam, the foam is found to be substantially
stabilized and it continues to transport the proppant material into
the fracture formed in the subterranean formation by the foamed
fracturing fluid with at least substantially the same effectiveness
as a gelled liquid. The foam has been found to have a viscosity
immediately after formation which is substantially the same as the
viscosity of the liquid-liquid emulsion. Further, the foam
substantially reduces any fluid leak-off to the formation that
otherwise would occur is only a liquid fracturing fluid was
utilized to treat the formation. The low fluid-loss characteristics
of the fracturing fluid of the present invention results in a
greater volumetric efficiency for a given volume and injection rate
of the fracturing fluid in comparison to liquid fracturing
fluids.
After the introduction of the full amount of the calculated or
estimated volume of fracturing fluid necessary to fracture the
formation and transport the proppant material, the well bore is
shut-in for a period of time sufficient to permit stabilization of
the subterranean formation. In one embodiment, the well is shut-in
for a period of time to permit the formation to at least partially
close upon the proppant material and stabilize the fracture volume.
The shut-in period can be from several minutes to in excess of
about 12 hours and, preferably, is in the range of from about 1 to
2 hours. After the subterranean formation has stabilized, the well
is opened under controlled conditions and the pressure drop in the
well bore causes the foam to break. The carbon dioxide gas then
moves from the formation into the well bore and exits the well bore
at the surface. The gas carries from the formation substantially
all of the liquids present in the fracturing area which leaves the
formation and well clean and ready for the commencement of
production.
To further illustrate the method of the present invention, and not
by way of limitation, the following examples are provided.
EXAMPLE I
To illustrate the stability of the liquid-liquid emulsion, the
following tests were performed. To 15 milliliters of aqueous fluid
in a pressure vessel, 45 milliliters of liquid carbon dioxide is
added to form a mixture. The mixture is maintained at a temperature
of about 75.degree. F. and a pressure of about 900 psig by nitrogen
gas. This mixture is stirred for approximately one minute at 1,000
rpm. The time required for the liquid-liquid emulsion to separate
into two layers then is determined. The time required for the
separation to occur provides a relative indication of the stability
of emulsion.
In the first test, the aqueous fluid in the emulsion comprised
water. The emulsion separated into two clear layers in about six
seconds.
In the second test, the aqueous fluid comprised a hydrated gelling
agent in a ratio of 20 lb. of guar gum per 1,000 gallons of water.
The liquid-liquid mixture formed an emulsion which rapidly
dissipated to form a cloudy liquid which did not separate further
after fifteen minutes.
In the third test, in accordance with the present invention, the
aqueous fluid comprised water and a surfactant comprising an
ammonium salt of a sulfated linear C.sub.12 to C.sub.14 alcohol
ethoxylated with 3 moles of ethylene oxide in a ratio of 5 gallons
surfactant per 1,000 gallons of water. The liquid-liquid mixture
formed a fine textured emulsion together with some foam from the
apparent entrainment of nitrogen gas utilized to provide the
overpressure to maintain the 900 psig pressure. The emulsion and
foam had a volume of about 90 milliliters and after 15 minutes has
a volume of over about 80 milliliters.
In the fourth test a gelling agent comprising guar gum was added to
a mixture comprising the same composition as the third test in a
ratio of 20 lb. per 1,000 gallons of water. The liquid-liquid
mixture formed a fine textured emulsion together with some foam.
The emulsion and foam had a volume of over about 90 milliliters
and, after 15 minutes, no apparent separation or reduction in
volume occurred.
These tests clearly illustrate the substantial stability of the
emulsion formed in accordance with the practice of the present
invention. The stability of the foam formed in the tests also is an
indication that the foam formed upon heating the carbon dioxide to
a temperature above its critical temperature in the subterranean
formation will have substantial stability.
EXAMPLE II
A fracturing treatment is performed on a well in the Cotton Valley
Sand Formation in Louisiana. The well is perforated at a level of
about 6,900 feet. The formation has a permeability of about 1.0
millidarcy and a porosity of about 16 percent. The bottom hole
temperature is about 200.degree. F. The treatment was effected by
pumping the fracturing fluid through a 27/8 inch tubing string
positioned in the well bore.
A prepad of 4,000 gallons of two percent potassium chloride water
gelled with 40 pounds of hydroxypropylguar per 1,000 gallons of
water is introduced into the formation. The potassium chloride is
used as a water treating agent to prevent clay swelling in the
formation. A pad of 10,000 gallons of a liquid-liquid emulsion then
is introduced into the tubing. The emulsion comprises 70 percent by
volume liquid carbon dioxide with the remainder being two percent
potassium chloride water together with 40 pounds of
hydroxypropylguar and six gallons of an anionic surfactant per
1,000 gallons of water. The surfactant comprises an ammonium salt
of a sulfated linear C.sub.12 to C.sub.14 alcohol ethoxylated with
3 moles of ethylene oxide. Fracturing fluid having the same
composition as the pad fluid then is introduced into the tubing
together with increasing quantities of a proppant comprising 20/40
mesh sand. A total of 20,000 gallons of emulsion is introduced into
the tubing with a sand concentration increasing in four generally
equal stages from 1 pound per gallon of emulsion to 4 pounds per
gallon. This concentration is achieved by admixing the sand with
the gelled 2 percent potassium chloride water in a blender and
subsequently admixing the gelled fluid with the liquid carbon
dioxide by passage through a "T" connector in the injection
pipeline connected to the 27/8-inch tubing string. Thereafter, the
tubing is flushed with sufficient gelled 2 percent potassium
chloride water similar to the prepad to force the fracturing fluid
into the formation.
The emulsion was introduced into the tubing at a rate of about 15
barrels per minute.
The well is shut-in for about 1 to 2 hours, after which it was
vented to atmospheric pressure under controlled conditions. The
gaseous carbon dioxide is allowed to flow out of the well and in
excess of about 80 percent of the water introduced into the
formation is returned with the carbon dioxide.
The well prior to the treatment in accordance with the present
invention, was producing approximately two barrels of oil per day.
After treatment, the well produced in excess of forty barrels of
oil per day and after five months is still producing in excess of
30 barrels of oil per day.
EXAMPLE III
A fracturing treatment is performed on a well in the Mancos
Formation in Colorado. The well is perforated at a level of about
10,800 feet. The formation has a permeability of about 0.0005
millidarcy. The bottom hole temperature is about 250.degree. F. The
treating is effected by pumping the fluids down the annulus between
27/8-inch and 7-inch tubing positioned in the well bore.
A pad comprising a liquid-liquid emulsion comprising 70 percent by
volume liquid carbon dioxide with the remainder comprising 2
percent potassium chloride water gelled with 40 pounds of
hydroxypropylguar and stabilized with 8 gallons of the surfactant
of Example I per 1,000 gallons of water. The fracturing fluid has
the same composition as the pad fluid except that a proppant is
admixed with the gelled water prior to formation of the
liquid-liquid emulsion. The fracturing fluid is cleaned from the
well bore with a flush fluid. The flush has the same composition as
the pad fluid. The sequence of the fluids and the proppant
concentrations are as indicated in the following Table. The
proppant comprises sand of either 70/100 mesh or 20/40 mesh on the
U.S. Sieve Series.
TABLE ______________________________________ Typical Proppant
Volume, Rate of Annulus Concen- Prop- (M Pumping, Pressure, tration
pant Fluid Gallon) (BPM) (PSI) (Lb/Gal) Size
______________________________________ PAD 30 48 4070 -- -- Frac
Fluid 10 47 5110 1.5 70/170 PAD 20 48 4900 -- -- Frac Fluid 20 48
5140 1 20/40 Frac Fluid 20 48 5210 2 20/40 Frac Fluid 30 47 5360 3
20/40 Frac Fluid 30 42 5150 4 20/40 Frac Fluid 40 42 5320 5 20/40
Frac Fluid 13.sup.1 38 4950 6 20/40 Frac Fluid 13.sup.1 38 5040 7
20/40 Flush 13.sup.1 38 4310 -- --
______________________________________ .sup.1 The liquid carbon
dioxide is reduced from 70 percent to 67 percent by volume of the
fluid.
The method of the present invention is capable of placing proppant
into a formation at a concentration of in excess of 7 pounds per
gallon of foam formed in the formation upon conversion of the
liquid-liquid emulsion. Following the treatment, the well is
shut-in for about 3 hours after which it is vented to the
atmosphere. The gaseous carbon dioxide is allowed to flow from the
formation and approximately 85 percent of the water introduced into
the formation is returned within three days with the carbon
dioxide.
Prior to the described treatment, the well was producing less than
about 50 MCF of gas per day; and about a month after the treatment,
the well stabilized at about 450 MCF of gas per day.
The terms "stable" or "stabilized" as used herein with regard to
the emulsions and foams of the present invention means the physical
and functional properties of the fluid remain substantially
unchanged for a period of time sufficient to permit the described
formation treatment to be effected.
While preferred embodiments of the invention have been described
herein, changes or modifications in the method may be made by an
individual skilled in the art, without departing from the spirit or
scope of the invention as set forth in the appended claims.
* * * * *