U.S. patent application number 11/540296 was filed with the patent office on 2008-04-03 for treatment fluids viscosifield with modified xanthan and associated methods for well completion and stimulation.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Richard W. Pauls, Thomas D. Welton.
Application Number | 20080078545 11/540296 |
Document ID | / |
Family ID | 38691929 |
Filed Date | 2008-04-03 |
United States Patent
Application |
20080078545 |
Kind Code |
A1 |
Welton; Thomas D. ; et
al. |
April 3, 2008 |
Treatment fluids viscosifield with modified xanthan and associated
methods for well completion and stimulation
Abstract
The present invention relates to viscosified treatment fluids
used in well completion and stimulation operations for oil and gas
production, and more particularly, to viscosified treatment fluids
comprising xanthan gelling agents. In one embodiment, the present
invention provides a method of treating a portion of a subterranean
formation comprising the steps of: providing a viscosified
treatment fluid that comprises water and a gelling agent that
comprises a modified xanthan; and treating the portion of the
subterranean formation. The present invention also provides methods
of fracturing, gravel packing, acidizing with the viscosified
treatments fluids. Also provided are viscosified treatment fluid
compositions and gelling agent compositions.
Inventors: |
Welton; Thomas D.; (Duncan,
OK) ; Pauls; Richard W.; (Duncan, OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
38691929 |
Appl. No.: |
11/540296 |
Filed: |
September 28, 2006 |
Current U.S.
Class: |
166/278 ;
166/295; 166/300; 166/305.1; 507/213; 507/219; 507/903;
507/921 |
Current CPC
Class: |
C09K 8/08 20130101 |
Class at
Publication: |
166/278 ;
166/300; 166/295; 166/305.1; 507/213; 507/219; 507/903;
507/921 |
International
Class: |
E21B 43/04 20060101
E21B043/04; E21B 43/22 20060101 E21B043/22 |
Claims
1. A method of treating a portion of a subterranean formation
comprising the steps of: providing a viscosified treatment fluid
that comprises water, a gelling agent that comprises a modified
xanthan and a crosslinker to crosslink the modified xanthan; and
treating the portion of the subterranean formation.
2. The method of claim 1, wherein at least a portion of the xanthan
is nonacetylated.
3. The method of claim 1, wherein at least a portion of the xanthan
is depyruvylated.
4. The method of claim 1, wherein at least a portion of the xanthan
is nonacetylated and depyruvylated.
5. The method of claim 1, wherein the liquid portion of the
viscosified treatment fluid has a density of about 8.3 pounds per
gallon to about 19.3 pounds per gallon.
6. The method of claim 1, wherein the portion of the subterranean
formation has a temperature of from about 30.degree. F. to about
400.degree. F.
7. The method of claim 1, wherein the gelling agent is included in
the viscosified treatment fluid is an amount from about 5 lbs to
about 200 lbs per 1000 gallons of the liquid viscosified treatment
fluid.
8. The method of claim 1, wherein the water contains calcium
bromide brine, zinc bromide brine, calcium chloride brine, sodium
chloride brine, sodium bromide brine, potassium bromide brine,
potassium chloride brine, sodium nitrate brine, potassium formate
brine, sodium formate, cesium formate, mixtures thereof or a
mixture thereof.
9. The method of claim 1, wherein the viscosified treatment fluid
further comprises a salt, a pH control additive, a surfactant, a
breaker, a bactericide, a crosslinker, a fluid loss control agent,
a stabilizer, a chelant, a scale inhibitor, gases, mutual solvents,
fibers, proppant, corrosion inhibitors, acids, bases, oxidizers,
reducers, or a combination thereof.
10. The method of claim 1, wherein the viscosified treatment fluid
further comprises tackifying agent or resin.
11. The method of claim 1, further comprising a salt selected from
the group consisting of: calcium bromide, zinc bromide, calcium
chloride, sodium chloride, sodium bromide, potassium bromide,
potassium chloride, sodium nitrate, potassium formate, or any
mixture thereof in any proportion.
12. The method of claim 1, further comprising a pH control additive
selected from the group consisting of: a base, a chelating agent,
an acid, a combination of a base and a chelating agent, or a
combination of an acid and a chelating agent.
13. The method of claim 1, wherein the crosslinker is selected from
the group consisting of: a peroxy compound, a ferric iron
derivative, or a magnesium derivative.
14. The method of claim 1, further comprising a breaker, wherein
the breaker is selected from the group consisting of: an acid, an
acid generating material, a peroxide, an oxidizing agent, or an
enzyme.
15. The method of claim 14, wherein the breaker is encapsulated and
comprises a coating.
16. The method of claim 15, wherein the coating comprises a
degradable material.
17. The method of claim 16, wherein the degradable material is
selected from the group consisting of: a polysaccharide, a chitin,
a chitosan, a protein, an aliphatic poly(ester), a poly(lactide), a
poly(glycolide), a poly(.epsilon.-caprolactone), a
poly(hydroxybutyrate), a poly(anhydride), an aliphatic
polycarbonate, an orthoester, a poly(orthoester), a poly(amino
acid), a poly(ethylene oxide), a poly(phosphazene), a derivative
thereof, or any combination thereof in any proportion.
18. The method of claim 6, further comprising a fluid loss control
agent included in an amount of from about 5 lbs to about 50 lbs per
1000 gals of the viscosified treatment fluid.
19. The method of claim 18, wherein the fluid loss control agent
comprises silica flour, a starch, diesel, or a degradable
material.
20. The method of claim 1, wherein the viscosified treatment fluid
further comprises a breaker and an activator or a retarder.
21. A method of placing a gravel pack in a portion of a
subterranean formation comprising: providing a viscosified gravel
pack fluid that comprises gravel, a brine, a gelling agent that
comprises a modified xanthan, and a crosslinker to crosslink the
modified xanthan; and contacting the portion of the subterranean
formation with the viscosified gravel pack fluid so as to place a
gravel pack in or near a portion of the subterranean formation.
22-24. (canceled)
25. A method of treating a portion of a subterranean formation
comprising the steps of: providing a viscosified treatment fluid
that comprises water, a gelling agent that comprises a modified
xanthan, and a fluid loss control agent included in an amount of
from about 5 lbs to about 50 lbs per 1000 gals of the viscosified
treatment fluid; and treating the portion of the subterranean
formation, wherein the portion of the subterranean formation has a
temperature of from about 30.degree. F. to about 400.degree. F.
26. The method of claim 25, wherein the fluid loss control agent
comprises silica flour, a starch, diesel, or a degradable material.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable
BACKGROUND OF THE INVENTION
[0004] The present invention relates to viscosified treatment
fluids used in oil field well completion and stimulation
operations, and more particularly, to viscosified treatment fluids
comprising xanthan gelling agents, and their use in such oil field
operations.
[0005] In well completion and stimulation operations, viscosified
treatment fluids are often used to carry particulates into
subterranean formations for various purposes, e.g., to deliver
particulates to a desired location within a well bore. Examples of
subterranean operations that use such viscosified treatment fluids
include servicing and completion operations such as fracturing,
gravel packing, frac-packing, acidizing, acid fracturing, and
fluid-loss pill formation.
[0006] In fracturing, for example, a viscosified fracturing fluid
is used to carry proppant to fractures within the formation, inter
alia, to maintain the integrity of those fractures to enhance the
flow of desirable fluids to a well bore. In sand control
operations, for example, gravel packing operations, a screen,
slotted liner, or other mechanical device is often placed into a
portion of a well bore. A viscosified gravel pack fluid is used to
deposit particulates, often referred to as gravel, into the annulus
between the mechanical device and the formation or casing to
inhibit the flow of particulates from a portion of the subterranean
formation to the well bore.
[0007] The viscosified treatment fluids used in subterranean
operations are oftentimes aqueous-based fluids comprising gelling
agents that increase the viscosities of the treatment fluids, inter
alia, to enhance the ability of the treatment fluids to suspend
sand or other particulate material. These gelling agents are
typically polysaccharides that when hydrated and at a sufficient
concentration are capable of forming a viscous solution. A commonly
used polysaccharide gelling agent is xanthan. Xanthan often is a
preferred gelling agent because it provides, inter alia,
advantageous sand transport properties, long-lasting viscosity,
desirable sheer thinning characteristics, and efficient breaking
properties to a viscosified treatment fluid in which it is
used.
SUMMARY OF THE INVENTION
[0008] The present invention relates to viscosified treatment
fluids used in well completion or stimulation operations, and more
particularly, to viscosified treatment fluids comprising xanthan
gelling agents, and their use in such oil field operations.
[0009] In one embodiment, the present invention provides a method
of treating a portion of a subterranean formation comprising the
steps of: providing a viscosified treatment fluid that comprises
water and a gelling agent that comprises a modified xanthan, such
as nonacetylated and/or nonpyruvylated xanthan; and treating the
portion of the subterranean formation. As used herein,
nonacetylated means having fewer acetyl groups than typical
xanthan, whether the difference is the result of genetic
engineering or plant selection or the result of chemical treatment
of a typical xanthan. Similarly, nonpyruvylated means having fewer
pyruvyl groups, whether the difference is the result of genetic
engineering or plant selection or the result of chemical treatment
of a typical xanthan. As used herein, nonpruvylated and
nonacetylated are intended to encompass depruvylated and
deacetylated, respectively.
[0010] In another embodiment, the present invention provides a
method of placing a gravel pack in a portion of a subterranean
formation comprising: providing a viscosified gravel pack fluid
that comprises gravel, water, and a gelling agent that comprises a
modified xanthan; and contacting the portion of the subterranean
formation with the viscosified gravel pack fluid so as to place a
gravel pack in or near a portion of the subterranean formation.
[0011] In one embodiment, the present invention provides a method
of fracturing a portion of a subterranean formation comprising:
providing a viscosified fracturing fluid that comprises water and a
gelling agent that comprises a modified xanthan; and contacting the
portion of the subterranean formation with the viscosified
fracturing fluid at a sufficient pressure to create or enhance at
least one fracture in the subterranean formation.
[0012] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
comprising using a viscosified treatment fluid that comprises water
and a gelling agent that comprises a modified xanthan in a well
completion or a servicing operation.
[0013] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
comprising using a viscosified treatment fluid that comprises water
and a gelling agent that comprises a modified xanthan in a well
completion or a servicing operation, and the subterranean formation
has a bottom hole temperature of from about 30.degree. F. to about
400.degree. F.
[0014] In another embodiment, the present invention provides a
viscosified treatment fluid comprising brine and a gelling agent
that comprises a modified xanthan.
[0015] The present invention provides a treatment fluid comprising
water and a gelling agent that comprises a modified xanthan for use
in a well completion or stimulation operation.
[0016] In one embodiment, the present invention provides a method
of making a viscosified treatment fluid comprising the steps of:
dispersing a gelling agent that comprises a modified xanthan into a
brine with adequate sheer to fully disperse the gelling agent
therein to form a brine and gelling agent mixture; mixing the brine
and gelling agent mixture with additional brine; allowing the
modified xanthan to fully hydrate in the brine and gelling agent
mixture to form a viscosified treatment fluid.
[0017] 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.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0018] In certain embodiments, the present invention provides
compositions and methods that are especially suitable for use in
well bores comprising bottom-hole temperatures ("BHTs") from about
30.degree. F. to about 400.degree. F. As known to one of ordinary
skill in the art, the bottom hole circulating temperature may be
below the BHT of the well bore, however, the BHT should be
indicative of the temperature of a treatment fluid circulated in
the bottom hole during the treatment. The temperatures to which the
fluids are subjected can affect their particulate transport
properties, depending on the concentration of the xanthan gelling
agent in the fluid as well as other components. One advantage of
the present invention is that the particulate transport properties
of the fluids of the present invention are exceptional in that, in
certain embodiments, the fluids can hold particulates in almost
perfect suspension under static conditions at elevated temperatures
for many hours, possibly several days.
[0019] Another advantage of the many advantages of the fluids of
the present invention is that they are sheer thinning fluids.
[0020] The viscosified treatment fluids of the present invention
generally comprise water and a gelling agent that comprises a
modified xanthan.
[0021] The term "modified xanthan" as used herein means a xanthan
that has been treated, either chemically, genetically, or
otherwise, to modify or alter the normal polymeric structure of
xanthan. Two preferable modifications are where a portion (or all)
of the acetyl and/or the pyruvate groups have been removed.
[0022] Suitable modified xanthans generally exhibit pseudoplastic
rheology (sheer reversible behavior). Suitable modified xanthans
also are generally soluble in hot or cold water, and are stable
over a range of pHs and temperatures. Additionally, they are
compatible with and stable in systems containing salts, e.g., they
will fully hydrate in systems comprising salts. Moreover, suitable
modified xanthans should provide good suspension for particulates
often used in subterranean applications, such as proppant or
gravel. Preferred xanthans should have good filterability. For
example, in gravel packing a desirable modified xanthan preferably
has a flow rate of at least about 200 ml in 2 minutes at ambient
temperature in a filtering laboratory test on a Baroid Filter Press
using 40 psi of differential pressure and a 11 cm Whatman filter
paper having a 2.7 .mu. pore size. An example of a suitable
deactylated xanthan for use in conjunction with the compositions
and methods of the present invention is commercially available from
Degussa.
[0023] In some embodiments, suitable modified xanthans can be
treated to help remove debris from the modified xanthan polymer.
For example, an enzyme as known in the art for treating normal
xanthan can be used to treat a modified xanthan to remove debris.
This can be particularly advantageous for use of the modified
xanthan in a brine. In certain preferred embodiments, the
viscosified treatment fluids of the present invention comprise a
brine and a gelling agent that comprises a modified xanthan.
[0024] Optionally, the gelling agent of the present invention can
comprise an additional biopolymer if the use of the modified
xanthan and the biopolymer produces a desirable result, e.g., a
synergistic effect. Suitable biopolymers may include
polysaccharides and/or derivatives thereof. Depending on the
application, one biopolymer may be more suitable than another. One
of ordinary skill in the art with the benefit of this disclosure
will be able to determine if a biopolymer should be included for a
particular application based on, for example, the desired viscosity
of the viscosified treatment fluid and the bottom hole temperature
("BHT") of the well bore.
[0025] The amount of gelling agent used in the viscosified
treatment fluids of the present invention can vary from about 20
lb/Mgal to about 100 lb/Mgal. In other embodiments, the amount of
gelling agent included in the treatment fluids of the present
invention can vary from about 30 lb/Mgal to about 80 lb/Mgal. In a
preferred embodiment, about 60 lb/Mgal of a gelling agent is
included in an embodiment of a treatment fluid of the present
invention. It should be noted that in well bores comprising BHTs of
200.degree. F. or more, 70 lbs/Mgal or more of the gelling agent
can be beneficially used in a treatment fluid of the present
invention.
[0026] The viscosified treatment fluids of the present invention
can vary widely in density. One of ordinary skill in the art with
the benefit of this disclosure will recognize the particular
density that is most appropriate for a particular application. In
certain preferred embodiments, the viscosified treatment fluids of
the present invention will have a density of about 8.3 pounds per
gallon ("ppg") to about 19.2 ppg. The desired density for a
particular viscosified treatment fluid may depend on
characteristics of the subterranean formation, including, inter
alia, the hydrostatic pressure required to control the fluids of
the subterranean formation during placement of the viscosified
treatment fluids. The types of salts or brines used to achieve the
desired density of the viscosified treatment fluid can be chosen
based on factors such as compatibility with the formation,
crystallization temperature, and compatibility with other treatment
and/or formation fluids. Availability and environmental impact also
may affect this choice. In certain embodiments, the viscosified
treatment fluid can be foamed with a gas, such as nitrogen or
carbon dioxide.
[0027] A brine suitable for use in the viscosified treatment fluids
of the present invention with a modified xanthan can include brines
of monovalent cations brines, which can be of any weight up to
saturation of the salt. Brines that comprise divalent or trivalent
cations, e.g., magnesium, calcium, iron, in some concentrations and
at some pH levels may cause undesirable crosslinking of a normal
xanthan polymer, and to a lesser extent a modified xanthan
polymer.
[0028] If a water source is used which contains such divalent or
trivalent cations in concentrations sufficiently high to be
problematic even for the modified xanthan, then the concentration
of such divalent or trivalent salts can be reduced or completely
removed. Such cations can be reduced or removed, for example, by a
process such as reverse osmosis or by raising the pH of the water
in order to precipitate out such divalent salts to lower the
concentration of such salts in the water before the water is used.
Another method for removing such ions is to include a chelating
agent to chemically bind the problematic ions to prevent their
undesirable interactions with the modified xanthan. Suitable
chelants include, but are not limited to, citric acid or sodium
citrate. Other chelating agents also are suitable.
[0029] Examples of suitable brines include monovalent brines such
as sodium chloride brines, sodium bromide brines, potassium bromide
brines, potassium chloride brines, sodium nitrate brines, potassium
formate brines, cesium formate brines, and the like, and any
mixture thereof in any proportion. In addition, however, the
modified xanthans can be more easily hydrated with other brines of
divalent and trivalent cations such as calcium bromide brines, zinc
bromide brines, calcium chloride brines, mixtures thereof, and the
like, and any mixture thereof in any proportion. The brine chosen
should be compatible with the formation and should have a
sufficient density to provide the appropriate degree of well
control. Additional salts can be added to a water source, e.g., to
provide a brine. The added salts can be used to help formulate a
resulting viscosified treatment fluid having a desired density.
[0030] A preferred suitable brine is seawater. The gelling agents
of the present invention can be used successfully with
seawater.
[0031] In certain embodiments, the viscosified treatment fluids of
the present invention also can comprise other salts, pH control
additives, surfactants, breakers, bactericides, crosslinkers, fluid
loss control additives, stabilizers, chelants, gases, mutual
solvents, fibers, proppant, corrosion inhibitors, acids, bases,
oxidizers, reducers, scale inhibitors, combinations thereof, or the
like.
[0032] A salt may be included in the viscosified treatment fluids
of the present invention for many purposes other than increasing
the density of the fluid. For example, a salt also can be included
for reasons related to compatibility of the viscosified treatment
fluid with the formation and formation fluids. To determine whether
a salt may be beneficially used for compatibility purposes, a
compatibility test may be performed to identify potential
compatibility problems. From such tests, one of ordinary skill in
the art with the benefit of this disclosure will be able to
determine whether and what salt should be included in a viscosified
treatment fluid of the present invention. Suitable salts include,
but are not limited to, calcium bromide, zinc bromide, calcium
chloride, sodium chloride, sodium bromide, potassium bromide,
potassium chloride, sodium nitrate, potassium formate, sodium
formate, cesium formate, mixtures thereof, and the like. Regardless
of the purpose for adding other salt, however, divalent and
trivalent cations may still be of concern.
[0033] Optionally, the treatment fluids can include a material for
retarding the movement of the proppant or fines. For example,
materials in the form of fibers, flakes, ribbons, beads, shavings,
platelets and the like that comprise glass, ceramics, carbon
composites, 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, which are incorporated herein by reference.
[0034] The treatment fluids can include a resin or resin coating on
proppant or gravel. An example of suitable resins include those
that are commercially available from Halliburton Energy Services,
Inc. under the trade name Expedite.RTM. Service.
[0035] Alternatively, or in addition to such other resins or resin
coatings, a material comprising a tackifying compound can 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 particulates adjacent thereto will adhere
together to form agglomerates that may bridge in the created
fracture to prevent particulate flowback. An example of suitable
tackifying compounds include those that are commercially available
from Halliburton Energy Services, Inc. under the trade name and
SandWedge.RTM. Conductivity Enhancement Service. The tackifying
compound also can be introduced into the formation with the
low-molecular-weight fluid before or after the introduction of the
proppant particulates into the formation. The coated material can
be 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, and 6,209,643 which
are incorporated herein by reference thereto. Further, aqueous
based tackifying compounds can be used as envisioned in U.S. patent
applications 20050277554, 20050274517, 20050092489, and
20050059558, which are incorporated herein by reference
thereto.
[0036] Suitable pH control additives, in certain embodiments, can
comprise bases, chelating agents, acids, or combinations of
chelating agents and acids or bases. A pH control additive can be
necessary to maintain the pH of the treatment fluid at a desired
level, e.g., to improve the effectiveness of certain breakers and
to reduce corrosion on any metal present in the well bore or
formation, etc. In some instances, it can be beneficial to maintain
the pH at neutral or above 7.
[0037] In some embodiments, the pH control additive can be a
chelating agent. When added to the treatment fluids of the present
invention, such a chelating agent can chelate any dissolved iron
(or other divalent or trivalent cation) that may be present in the
water. Such chelating may prevent such ions from crosslinking the
gelling agent molecules. Such crosslinking may be problematic
because, inter alia, it may cause severe filtration problems. Any
suitable chelating agent can be used with the present invention.
Examples of suitable chelating agents include, but are not limited
to, an anhydrous form of citric acid, commercially available under
the tradename Fe-2.TM. iron sequestering agent from Halliburton
Energy Services, Inc., of Duncan, Okla. Another example of a
suitable chelating agent is a solution of citric acid dissolved in
water, commercially available under the tradename Fe-2A.TM.
buffering agent from Halliburton Energy Services, Inc., of Duncan,
Okla. Another example of a suitable chelating agent is sodium
citrate, commercially available under the tradename FDP-S714-04
from Halliburton Energy Services, Inc. of Duncan, Okla. Other
chelating agents that are suitable for use with the present
invention include, inter alia, nitrilotriacetic acid and any form
of ethylene diamine tetracetic acid ("EDTA") or its salts.
Generally, the chelating agent is present in an amount sufficient
to prevent crosslinking of the gelling agent molecules by any free
iron (or any other divalent or trivalent cation) that may be
present. In one embodiment, the chelating agent can be present in
an amount of from about 0.02% to about 2.0% by weight of the
treatment fluid. In another embodiment, the chelating agent is
present in an amount in the range of from about 0.02% to about 0.5%
by weight of the treatment fluid. One of ordinary skill in the art
with the benefit of this disclosure will be able to determine the
proper concentration of chelating agents for a particular
application.
[0038] In another embodiment, the pH control additive can be an
acid. Any known acid can be suitable with the treatment fluids of
the present invention. Examples of suitable acids include, inter
alia, hydrochloric acid, acetic acid, formic acid, and citric
acid.
[0039] The pH control additive also can comprise a base to elevate
the pH of the viscosified treatment fluid. Generally, a base can be
used to elevate the pH of the mixture to greater than or equal to
about 7. Having the pH level at or above 7 may have a positive
effect on a chosen breaker being used. This type of pH may also
inhibit the corrosion of any metals present in the well bore or
formation, such as tubing, sand screens, etc. Any known base that
is compatible with the gelling agents of the present invention can
be used in the viscosified treatment fluids of the present
invention. Examples of suitable bases include, but are not limited
to, sodium hydroxide, potassium carbonate, potassium hydroxide and
sodium carbonate. An example of a suitable base is a solution of
25% sodium hydroxide commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the tradename MO-67.TM. pH
control agent. Another example of a suitable base solution is a
solution of potassium carbonate commercially available from
Halliburton Energy Services, Inc., of Duncan, Okla., under the
tradename BA-40L.TM. buffering agent. One of ordinary skill in the
art with the benefit of this disclosure will recognize the suitable
bases that can be used to achieve a desired pH elevation.
[0040] In still another embodiment, the pH control additive can
comprise a combination of an acid and a chelating agent or a base
and a chelating agent. Such combinations may be suitable when,
inter alia, the addition of a chelating agent (in an amount
sufficient to chelate the iron present) is insufficient by itself
to achieve the desired pH level.
[0041] In some embodiments, the viscosified treatment fluids of the
present invention can include surfactants, e.g., to improve the
compatibility of the viscosified treatment fluids of the present
invention with other fluids (like any formation fluids) that may be
present in the well bore. An artisan of ordinary skill with the
benefit of this disclosure will be able to identify the type of
surfactant as well as the appropriate concentration of surfactant
to be used. Suitable surfactants can be used in a liquid or powder
form. Where used, the surfactants are present in the viscosified
treatment fluid in an amount sufficient to prevent incompatibility
with formation fluids or well bore fluids. In an embodiment where
liquid surfactants are used, the surfactants are generally present
in an amount in the range of from about 0.01% to about 5.0% by
volume of the viscosified treatment fluid. In one embodiment, the
liquid surfactants are present in an amount in the range of from
about 0.1% to about 2.0% by volume of the viscosified treatment
fluid. In embodiments where powdered surfactants are used, the
surfactants can be present in an amount in the range of from about
0.001% to about 0.5% by weight of the viscosified treatment fluid.
Examples of suitable surfactants are non-emulsifiers commercially
available from Halliburton Energy Services, Inc., of Duncan, Okla.,
under the tradenames LOSURF-259.TM. nonionic nonemulsifier,
"LOSURF-300M.TM. nonionic surfactant, and LOSURF-400.TM.
surfactant. Another example of a suitable surfactant is a
non-emulsifier commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the tradename NEA-96M.TM.
Surfactant. It should be noted that it may be beneficial to add a
surfactant to a viscosified treatment fluid of the present
invention as that fluid is being pumped downhole to help eliminate
the possibility of foaming in the surface equipment.
[0042] In some embodiments, the viscosified treatment fluids of the
present invention can contain bactericides to protect both the
subterranean formation as well as the viscosified treatment fluid
from attack by bacteria. Such attacks may be problematic because
they may lower the viscosity of the viscosified treatment fluid,
resulting in poorer performance, such as poorer sand suspension
properties, for example. Any bactericides known in the art are
suitable. An artisan of ordinary skill with the benefit of this
disclosure will be able to identify a suitable bactericide and the
proper concentration of such bactericide for a given application.
Where used, such bactericides are present in an amount sufficient
to destroy all bacteria that may be present. Examples of suitable
bactericides include, but are not limited to, a
2,2-dibromo-3-nitrilopropionamide, commercially available under the
tradename BE-3S biocide from Halliburton Energy Services, Inc., of
Duncan, Okla., and a 2-bromo-2-nitro-1,3-propanediol commercially
available under the tradename BE-6 biocide from Halliburton Energy
Services, Inc., of Duncan, Okla. In one embodiment, the
bactericides are present in the viscosified treatment fluid in an
amount in the range of from about 0.001% to about 0.003% by weight
of the viscosified treatment fluid. Another example of a suitable
bactericide is a solution of sodium hypochlorite, commercially
available under the tradename "CAT-1" chemical from Halliburton
Energy Services, Inc., of Duncan, Okla. In certain embodiments,
such bactericides can be present in the viscosified treatment fluid
in an amount in the range of from about 0.01% to about 0.1% by
volume of the viscosified treatment fluid. In certain preferred
embodiments, when bactericides are used in the viscosified
treatment fluids of the present invention, they are added to the
viscosified treatment fluid before the gelling agent is added.
[0043] The viscosified treatment fluids of the present invention
also optionally can comprise a suitable crosslinker to crosslink
the modified xanthan of the gelling agent in the viscosified
treatment fluid. Crosslinking may be desirable at higher
temperatures and/or when the sand suspension properties of a
particular fluid of the present invention may need to be altered
for a particular purpose. Suitable crosslinkers include, but are
not limited to, combination crosslinker-breakers of the type
disclosed in U.S. Pat. No. 7,090,015 issued Aug. 15, 2006, which is
incorporated herein by reference; ferric iron derivatives;
magnesium derivatives; and the like. Any crosslinker that is
compatible with the modified xanthan in the gelling agent can be
used. One of ordinary skill in the art with the benefit of this
disclosure will recognize when such crosslinkers are appropriate
and what particular crosslinker will be most suitable.
[0044] The viscosified treatment fluids of the present invention
also can comprise breakers capable of reducing the viscosity of the
viscosified treatment fluid at a desired time. Examples of such
suitable breakers for viscosified treatment fluids of the present
invention include, but are not limited to, sodium chlorites,
hypochlorites, perborate, persulfates, peroxides, including organic
peroxides. Other suitable breakers include, but are not limited to,
suitable acids and peroxide breakers, as well as enzymes that may
be effective in breaking xanthan. Preferred examples of peroxide
breakers include tert-butyl hydroperoxide and tert-amyl
hydroperoxide. A breaker can be included in a viscosified treatment
fluid of the present invention in an amount and form sufficient to
achieve the desired viscosity reduction at a desired time. The
breaker can be formulated to provide a delayed break, if desired.
For example, a suitable breaker can be encapsulated if desired.
Suitable encapsulation methods are known to those skilled in the
art. One suitable encapsulation method that can be used involves
coating the chosen breakers with a material that will degrade when
downhole so as to release the breaker when desired. Resins that can
be suitable include, but are not limited to, polymeric materials
that will degrade when downhole. The terms "degrade,"
"degradation," or "degradable" refer to both the two relatively
extreme cases of hydrolytic degradation that the degradable
material may undergo, i.e., heterogeneous (or bulk erosion) and
homogeneous (or surface erosion), and any stage of degradation in
between these two. This degradation can be a result of, inter alia,
a chemical or thermal reaction or a reaction induced by radiation.
Suitable examples include, but are not limited to, polysaccharides
such as dextran or cellulose; chitins; chitosans; proteins;
aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic polycarbonates; orthoesters,
poly(orthoesters); poly(amino acids); poly(ethylene oxides); and
polyphosphazenes. If used, a breaker should be included in a
composition of the present invention in an amount sufficient to
facilitate the desired reduction in viscosity in a viscosified
treatment fluid. For instance, peroxide concentrations that can be
used vary from about 0.05 to about 30 gallons of peroxide per 1000
gallons of the viscosified treatment fluid.
[0045] Optionally, a viscosified treatment fluid of the present
invention can contain an activator or a retarder, inter alia, to
optimize the break rate provided by the breaker. Any known
activator or retarder that is compatible with the particular
breaker used is suitable for use in the present invention. Examples
of such suitable activators include, but are not limited to, acid
generating materials, chelated iron, copper, cobalt, and reducing
sugars. Examples of suitable retarders include sodium thiosulfate
and diethylene triamine. In some embodiments, the sodium
thiosulfate can be used in a range of from about 1 to about 100
lbs. per 1000 gallons of viscosified treatment fluid. A preferred
range can be from about 5 to about 20 lbs per 1000 gallons. An
artisan of ordinary skill with the benefit of this disclosure will
be able to identify a suitable activator or retarder and the proper
concentration of such activator or retarder for a given
application.
[0046] The viscosified treatment fluids of the present invention
also can comprise suitable fluid loss control agents. Such fluid
loss control agents may be particularly useful when a viscosified
treatment fluid of the present invention is being used in a
fracturing operation. This may be due in part to xanthan's
potential to leak off into formation. Any fluid loss agent that is
compatible with the viscosified treatment fluid is suitable for use
in the present invention. Examples include, but are not limited to,
starches, silica flour, and diesel dispersed in the treatment
fluid. Another example of a suitable fluid loss control additive is
one that comprises a degradable material. Suitable degradable
materials include degradable polymers. Specific examples of
suitable polymers include polysaccharides such as dextran or
cellulose; chitins; chitosans; proteins; aliphatic polyesters;
poly(lactides); poly(glycolides); poly(glycolide-co-lactides);
poly(p-caprolactones); poly(3-hydroxybutyrates);
poly(3-hydroxybutyrate-co-hydroxyvalerates); poly(anhydrides);
aliphatic poly(carbonates); poly(orthoesters); poly(amino acids);
poly(ethylene oxides); poly(phosphazenes); derivatives thereof; or
combinations thereof. If included, a fluid loss additive should be
added to a viscosified treatment fluid of the present invention in
an amount of about 5 to about 50 pounds per 1000 gallons of the
viscosified treatment fluid. In certain preferred embodiments, the
fluid loss additive can be included in an amount from about 15 to
about 30 pounds per 1000 gallons of the viscosified treatment
fluid. For some liquid additives like diesel, these can be included
in an amount from about 1% to about 20% by volume; in some
preferred embodiments, these can be included in an amount from
about 3% to about 10% by volume.
[0047] If in a particular application a chosen viscosified
treatment fluid is experiencing a viscosity degradation a
stabilizer might be useful and can be included in the fluid. One
example of a situation where a stabilizer might be beneficial is
where the BHT of the well bore is sufficient by itself to break the
viscosified treatment fluid with the use of a breaker. Suitable
stabilizers include, but are not limited to, sodium thiosulfate.
Such stabilizers may be useful when the viscosified treatment
fluids of the present invention are utilized in a subterranean
formation having a temperature above about 150.degree. F. If
included, a stabilizer can be added in an amount of from about 1 lb
to about 50 lb per 1000 gal of viscosified treatment fluid. In
other embodiments, a stabilizer can be included in an amount of
from about 5 to about 20 lb per 1000 gal of viscosified treatment
fluid.
[0048] Scale inhibitors can be added to the viscosified treatment
fluids of the present invention, for example, when a viscosified
treatment fluid of the present invention is not particularly
compatible with the formation waters in the formation in which it
is being used. Any scale inhibitor that is compatible with the
viscosified treatment fluid in which it will be used in suitable
for use in the present invention. An example of a preferred
compound is "LP55.TM." scale inhibitor from Halliburton Energy
Services in Duncan, Okla. Another example of a preferred compound
is "LP65.TM." scale inhibitor available from Halliburton Energy
Services in Duncan, Okla. If used, a scale inhibitor should be
included in an amount effective to inhibit scale formation.
Suitable amounts of scale inhibitors to include in the viscosified
treatment fluids of the present invention can range from about 0.05
to 10 gallons per about 1000 gallons of the viscosified treatment
fluid, more preferably from about 0.1 to 2 gallons per about 1000
gallons of the viscosified treatment fluid.
[0049] Any particulates such as proppant and/or gravel that are
commonly used in subterranean operations can be used successfully
in conjunction with the compositions and methods of the present
invention. For example, resin and/or tackifier coated particulates
can be suitable.
[0050] According to a preferred embodiment, the present invention
provides a method of making a viscosified treatment fluid
comprising the steps of: providing a brine; filtering the brine
through a filter; dispersing a gelling agent that comprises a
modified xanthan into the brine with adequate sheer to fully
disperse the gelling agent therein to form a brine and gelling
agent mixture; mixing the brine and gelling agent mixture; allowing
the modified xanthan to fully hydrate in the brine and gelling
agent mixture to form a viscosified treatment fluid; and filtering
the viscosified treatment fluid. In a preferred embodiment, a
viscosified treatment fluid of the present invention can be
prepared according to the following process: providing a brine
having a suitable density; adding optional chemical such as
biocides, chelating agents, pH control agents, and the like;
filtering the brine through a 2 micron. filter or a finer filter;
dispersing the gelling agent comprising a modified xanthan into the
brine with adequate sheer to fully disperse polymer therein; mixing
the fluid until the modified xanthan is fully hydrated; shearing
the viscosified treatment fluid to fully disperse any microglobs of
xanthan polymer (e.g., a relatively small agglomeration of
unhydrated xanthan polymer at least partially surrounded by a dense
layer of at least partially hydrated xanthan polymer) that have not
fully dispersed; filtering the fluid; and adding any additional
optional ingredients including surfactants, breakers, activators,
retarders, and the like.
[0051] In one embodiment, the present invention provides a method
of treating a portion of a subterranean formation comprising the
steps of: providing a viscosified treatment fluid that comprises a
brine and a gelling agent that comprises a modified xanthan; and
treating the portion of the subterranean formation.
[0052] In another embodiment, the present invention provides a
method of treating a portion of a subterranean formation
comprising: providing a viscosified treatment fluid that comprises
seawater and a gelling agent that comprises a modified xanthan; and
treating the portion of the subterranean formation.
[0053] The viscosified treatment fluids of the present invention
are useful in gravel packing operations. In an example of such an
embodiment, the present invention provides a method of placing a
gravel pack in a portion of a subterranean formation comprising:
providing a viscosified gravel pack fluid that comprises gravel, a
brine and a gelling agent that comprises a modified xanthan; and
contacting the portion of the subterranean formation with the
viscosified gravel pack fluid so as to place a gravel pack in or
near a portion of the subterranean formation.
[0054] The viscosified treatment fluids of the present invention
can be useful in subterranean fracturing operations. In one
embodiment, the present invention provides a method of fracturing a
portion of a subterranean formation comprising: providing a
viscosified fracturing fluid that comprises a brine and a gelling
agent that comprises a modified xanthan; and contacting the portion
of the subterranean formation with the viscosified fracturing fluid
at a sufficient pressure to create or enhance at least one fracture
in the subterranean formation.
[0055] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
comprising using a viscosified treatment fluid that comprises a
brine and a gelling agent that comprises a modified xanthan in a
completion or a servicing operation.
[0056] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
comprising using a viscosified treatment fluid that comprises a
brine and a gelling agent that comprises a modified xanthan in a
completion or a servicing operation, and the subterranean formation
has a bottom hole temperature of from about 30.degree. F. to about
400.degree. F.
[0057] In another embodiment, the present invention provides a
viscosified treatment fluid comprising seawater and a gelling agent
that comprises a modified xanthan.
[0058] In another embodiment, the present invention provides a
subterranean treatment fluid gelling agent that comprises a
modified xanthan.
[0059] To facilitate a better understanding of the present
invention, the following examples of some of the preferred
embodiments are given. In no way should such examples be read to
limit, or define, the scope of the invention.
EXAMPLE
[0060] It has been found that modified xanthan has suitable
filtration and rheological properties for gravel packing. According
to an example for the invention, 3.6 grams of modified
(deacetylated) xanthan gum was mixed with 500 mL of fresh water.
The mixture was filtered through dry filter paper. Starting with a
200 mL sample of the mixture, after 2 minutes 43 mL was through the
dry filter paper.
[0061] The viscosity of the mixture was measured at 300 revolutions
per minute ("rpm") as shown in the following table.
TABLE-US-00001 TABLE Viscosity of Modified Xanthan Gel Minutes
Viscosity at 300 rpm 1 38.5 2 39 3 39 4 38.5 5 39 6 38.5 7 38.5 8
39 9 39 10 39
[0062] 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 numerous changes may
be made by those skilled in the art, such changes are encompassed
within the spirit of this invention as defined by the appended
claims.
* * * * *