U.S. patent application number 12/454600 was filed with the patent office on 2010-11-25 for methods for treating a well using a treatment fluid containing a water-soluble polysaccharide, a water-soluble salt, and urea.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Ian D. Robb.
Application Number | 20100298177 12/454600 |
Document ID | / |
Family ID | 42262298 |
Filed Date | 2010-11-25 |
United States Patent
Application |
20100298177 |
Kind Code |
A1 |
Robb; Ian D. |
November 25, 2010 |
METHODS FOR TREATING A WELL USING A TREATMENT FLUID CONTAINING A
WATER-SOLUBLE POLYSACCHARIDE, A WATER-SOLUBLE SALT, AND UREA
Abstract
Methods are provided for treating a portion of a well and
include the steps of: (a) forming a treatment fluid comprising an
aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; and (b)
introducing the treatment fluid into the portion of the well.
According to the inventions, the concentration of the urea in the
water is in at least a sufficient concentration such that aqueous
solution: (1) has a G' of at least 2 Pa, or (2) is filterable.
According to the inventions, an identical aqueous solution except
with less than the sufficient concentration of the urea would not
satisfy the above conditions.
Inventors: |
Robb; Ian D.; (Lawton,
OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
42262298 |
Appl. No.: |
12/454600 |
Filed: |
May 20, 2009 |
Current U.S.
Class: |
507/213 ;
507/211 |
Current CPC
Class: |
C09K 8/90 20130101; C09K
2208/30 20130101; C09K 8/685 20130101; C09K 2208/26 20130101 |
Class at
Publication: |
507/213 ;
507/211 |
International
Class: |
C09K 8/68 20060101
C09K008/68 |
Claims
1. A method for treating at least a portion of a well, the method
comprising the steps of: (a) forming a treatment fluid comprising
an aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution has a G' of
at least 2 Pa whereas an identical aqueous solution except with
less than the sufficient concentration of the urea would not have a
G' of at least 2 Pa, and wherein G' is measured in the linear
viscoelastic region at at least one desired temperature in the
range of 10.degree. C.-50.degree. C. without any increase in
temperature of the aqueous solution above the desired temperature;
and (b) introducing the treatment fluid into the well.
2. The method according to claim 1, wherein the aqueous solution is
filterable.
3. The method according to claim 2, wherein the treatment fluid is
introduced into the well at a temperature below 40.degree. C.
4. The method according to claim 2, wherein the treatment fluid is
introduced into the well at a temperature at or below 30.degree.
C.
5. The method according to claim 1, wherein the aqueous solution
has a G' of at least 5 Pa and the desired temperature is 30.degree.
C.
6. The method according to claim 1, wherein the aqueous solution
has a G' of at least 10 Pa and the desired temperature is
40.degree. C.
7. The method according to claim 1, wherein the aqueous solution
has a G' of at least 10 Pa and the desired temperature is
30.degree. C.
8. The method according to claim 1, wherein the polysaccharide is
selected from the group consisting of diutan, xanthan, and any
combination thereof in any proportion.
9. The method according to claim 1, wherein the polysaccharide is
in a concentration at least 0.1% by weight of the water in the
aqueous solution.
10. The method according to claim 1, wherein the polysaccharide is
in a concentration in the range of 0.1% to 1.0% by weight of the
water in the aqueous solution.
11. The method according to claim 1, wherein the one or more salts
are selected from the group consisting of sodium bromide, sodium
chloride, calcium bromide, calcium chloride, zinc bromide, zinc
chloride, and any combination thereof in any proportion.
12. The method according to claim 1, wherein the water-salt
solution has a density in the range of 10.5 ppg-15.5 ppg.
13. The method according to claim 1, wherein the urea is in a
concentration of at least 5% by weight of the water in the aqueous
solution.
14. The method according to claim 1, wherein the urea is in a
concentration in the range of 12%-35% by weight of the water in the
aqueous solution.
15. The method according to claim 1, wherein the treatment fluid
further comprises a cross-linking agent for the polysaccharide.
16. The method according to claim 1, wherein the treatment fluid
further comprises a breaker.
17. The method according to claim 1, wherein the treatment fluid
further comprises an insoluble particulate.
18. The method according to claim 17, wherein the insoluble
particulate comprises gravel.
19. A method for treating at least a portion of a well, the method
comprising the steps of: (a) forming a treatment fluid comprising
an aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution is
filterable, whereas an identical aqueous solution except with less
than the sufficient concentration of the urea would not be
filterable; and (b) introducing the treatment fluid into the
well.
20. The method according to claim 19, wherein the aqueous solution
has a G' of at least 2 Pa at a temperature of 30.degree. C.
21. The method according to claim 19, wherein the polysaccharide is
selected from the group consisting of diutan, xanthan, and any
combination thereof in any proportion.
22. The method according to claim 19, wherein the polysaccharide is
in a concentration at least 0.1% by weight of the water in the
aqueous solution.
23. The method according to claim 19, wherein the polysaccharide is
in a concentration in the range of 0.1% to 1.0% by weight of the
water in the aqueous solution.
24. The method according to claim 19, wherein the one or more salts
are selected from the group consisting of sodium bromide, sodium
chloride, calcium bromide, calcium chloride, zinc bromide, zinc
chloride, and any combination thereof in any proportion.
25. The method according to claim 19, wherein the water-salt
solution has a density in the range of 10.5 ppg-15.5 ppg.
26. The method according to claim 19, wherein the urea is in a
concentration of at least 5% by weight of the water in the aqueous
solution.
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
SUMMARY
[0004] Methods according to the inventions are directed to treating
a subterranean formation for producing oil or gas.
[0005] According to a first aspect of the inventions, a method is
provided for treating at least a portion of a well, the method
includes the steps of: (a) forming a treatment fluid comprising an
aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution has a G' of
at least 2 Pa whereas an identical aqueous solution except with
less than the sufficient concentration of the urea would not have a
G' of at least 2 Pa, and wherein G' is measured in the linear
viscoelastic region at at least one desired temperature in the
range of 10.degree. C.-50.degree. C. without any increase in
temperature of the aqueous solution above the desired temperature;
and (b) introducing the treatment fluid into the well.
[0006] According to another aspect of the inventions, a method is
provided for treating at least a portion of a well, the method
includes the steps of: (a) forming a treatment fluid comprising an
aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution is
filterable, whereas an identical aqueous solution except with less
than the sufficient concentration of the urea would not be
filterable; and (b) introducing the treatment fluid into the well.
As used herein, "filterable" means that at least 100 g of the
aqueous solution is capable of being passed within 100 seconds
through an 11-micron filter paper (i.e., Whatman.RTM. filter paper
or equivalent) with a circular filtration area having a diameter of
5.4 cm, at a differential pressure of 50 psi, and at a temperature
of 30.degree. C.
[0007] The features and advantages of the present inventions will
be more readily appreciated when considered in conjunction with the
accompanying drawing.
BRIEF DESCRIPTION OF THE DRAWING
[0008] The accompanying drawing is incorporated into the
specification to illustrate examples according to the presently
most-preferred embodiment of the present inventions. The drawing is
not to be construed as limiting the inventions. The drawing
includes the following figures:
[0009] FIG. 1 is a graph of G' and G'' versus temperature for an
aqueous solution containing 0.5% diutan and a calcium bromide
(CaBr.sub.2) salt solution having a density of 11.3 pounds per
gallon (ppg).
[0010] FIG. 2 is a graph of G' and G'' in Pa versus temperature for
several aqueous solutions containing 0.5% diutan and varied
concentrations of urea in CaBr.sub.2 salt solutions having varied
densities.
DETAILED DESCRIPTION OF THE INVENTION
[0011] Oil and gas hydrocarbons are naturally occurring in some
subterranean formations. A subterranean formation containing oil or
gas is sometimes referred to as a reservoir. A reservoir may be
located under land or offshore. To produce oil or gas from a
reservoir, a well is drilled into the earth.
[0012] It is often desirable to treat at least a portion of a well
with a treatment fluid in the effort to produce oil or gas from a
reservoir. A treatment is designed to resolve a specific condition
in a well. For example, stimulation is a treatment performed on a
well to restore or enhance the productivity of a well.
[0013] As used herein, a "treatment fluid" is a fluid designed and
prepared to resolve a specific condition of a well or subterranean
formation, such as for stimulation, isolation, gravel packing, or
control of reservoir gas or water. The term "treatment fluid"
refers to the specific composition of the fluid as it is being
introduced into a wellbore. The term "treatment" in the term
"treatment fluid" does not necessarily imply any particular action
by the fluid.
[0014] Stimulation treatments fall into two main groups, hydraulic
fracturing and matrix treatments. In a fracturing treatment, a
treatment fluid is injected into a wellbore and into a subterranean
formation penetrated by the wellbore at a pressure that is above
the fracture pressure of the subterranean formation, which higher
fluid pressure fractures the formation to create a flow path
between the subterranean formation and the wellbore. Hydraulic
fracturing is described in more detail below. In a matrix
treatment, a treatment fluid is injected into a wellbore and into a
subterranean formation penetrated by the wellbore at a pressure
that is below the fracture pressure of the subterranean formation,
which lower fluid pressure is sufficient to force the treatment
fluid into the matrix of the formation but not sufficient to
fracture the subterranean formation.
[0015] As mentioned above, "hydraulic fracturing" is a common
stimulation treatment. A treatment fluid adapted for this purpose
sometimes is referred to as a "fracturing fluid." The fracturing
fluid is pumped at a sufficiently high flow rate and pressure into
the wellbore and into the subterranean formation to create or
enhance a fracture in the subterranean formation. Creating a
fracture means making a new fracture in the formation. Enhancing a
fracture means enlarging a pre-existing fracture in the
formation.
[0016] Fracturing a subterranean formation typically requires many
thousands of gallons of fracturing fluid. Further, it is often
desirable to fracture at more than one downhole location of a well.
Thus, a high volume of fracturing fluid usually is required to
treat a well, which means that a low-cost fracturing fluid is
desirable. Because of the ready availability and relative low cost
of water compared to other liquids, a fracturing fluid usually is
water based. As used herein, a "water-based" fluid means a
homogenous fluid of water or an aqueous solution or a heterogeneous
fluid comprising water or an aqueous solution as the continuous
phase.
[0017] After the pumping of the fracturing fluid is stopped, the
fracture will tend to close. To prevent the fracture from closing,
a material, called proppant, is placed in the fracture to keep the
fracture propped open. Proppant is usually in the form of an
insoluble particulate, which is suspended in the fracturing fluid,
carried downhole, and deposited in the fracture. The proppant holds
the fracture open while still allowing fluid flow through the
permeability of the proppant. When deposited in the fracture, the
proppant forms a "proppant pack," and, while holding the fracture
open, provides conductive channels through which fluids can flow to
the wellbore. These channels provide an additional flow path for
the oil or gas to reach the wellbore, which increases oil and gas
production from the well. For this purpose, an insoluble
particulate for use as proppant is selected based on two
characteristics: particulate size range and strength.
[0018] A particulate for use as a proppant must have an appropriate
size to be placed in the fracture, prop open the fracture as a
proppant pack, and allow fluid to flow through the proppant pack,
i.e., in between and around the proppant particulate making up the
pack. Appropriate sizes of particulate for use as a proppant are
typically in the range from about 8 to about 100 U.S. Standard
Mesh. A typical proppant is sand, which geologically is defined as
having a particle size ranging in diameter from about 0.0625
millimeters ( 1/16 mm) up to about 2 millimeters. The next smaller
size class in geology is silt, particles smaller than 0.0625 mm
down to 0.004 mm in diameter. The next larger size class in geology
is gravel, with particles ranging from greater than 2 mm up to 64
mm. As used herein, this geological definition of gravel size class
will not apply to a slurry to be pumped downhole, as such particles
are so large they would plug up pumps.
[0019] The particulate material of a proppant must have sufficient
strength to prop a fracture open and to allow fluid flow through a
pack of the particulate material in the fracture. For a proppant
material that crushes under closure stress, the proppant preferably
has an API crush strength of at least 2,000 psi closure stress
based on 10% crush fines. The proppant can be coated with a resin
to help improve the strength of the proppant.
[0020] As used herein, "proppant" means and refers to an insoluble
particulate material that is suitable for use as a proppant pack,
including without limitation sand, synthetic materials,
manufactured materials, and any combination thereof in any
proportion. For this purpose, "proppant" does not mean or refer to
suspended solids, silt, fines, or other types of insoluble
particulate smaller than 0.0625 mm. Further, it does not mean or
refer to insoluble particulate larger than 2 mm. "Proppant" also
does not mean or refer to dissolved solids.
[0021] Suitable proppant materials include, but are not limited to,
sand (silica), walnut shells, sintered bauxite, glass beads,
plastics, nylons, resins, other synthetic materials, and ceramic
materials. Mixtures of proppants can be used as well. If sand is
used, it typically will be from about 20 to about 100 U.S. Standard
Mesh in size. For a synthetic proppant, typically mesh sizes about
8-100 are used. The concentration of proppant in a fracturing fluid
can be in any concentration known in the art, and preferably will
be in the range of from about 0.01 kilogram to about 3 kilogram of
proppant added per liter of liquid phase (about 0.1 lb/gal-25
lb/gal).
[0022] An insoluble particulate also can be used for "gravel
packing" operations in a well. The insoluble particulate, when used
for this purpose, is referred to as "gravel." If the insoluble
particulate is for gravel packing, its compressive strength or
crush resistance is less critical. More particularly in the oil and
gas field and as used herein, the term "gravel" is sometimes used
to refer to relatively large particles in the sand size
classification, that is, particles ranging in diameter from about
0.5 mm up to about 2 mm.
[0023] In a gravel packing operation, a treatment fluid containing
"gravel" is introduced through the wellbore and into the
subterranean formation to be treated. The gravel, once located in
the subterranean formation, forms a "gravel pack." The aqueous
solution of the treatment fluid should be filterable so that it
would be capable of passing through the formed gravel pack. The
aqueous solution of the treatment fluid can be tested for this
capability by measuring the flow of the aqueous solution of the
treatment fluid (i.e., the treatment fluid without any gravel or
other insoluble material), through a standard filter paper under
applied pressure. Significant quantities of cross-linked polymers
or partially-soluble polymers can adversely affect the
filterability of the aqueous solution of a treatment fluid to be
used in a gravel packing operation. Therefore, it is common for a
treatment fluid used in gravel packing operations to contain only
small quantities, if any, of cross-linked or partially-soluble
polymers.
[0024] The insoluble material for use as proppant or gravel
typically has a much higher specific gravity than deionized water
measured at 25.degree. C. (77 F) and 1 atmosphere pressure. For
example, sand has a specific gravity of about 2.7. Such a proppant
suspended in water will tend to settle out from the water. To help
suspend the proppant (or other particulate with a substantially
different density than water) in a water-based fracturing fluid, it
is common to use a suspending agent to help suspend the proppant
and prevent the proppant from separating out of the treatment
fluid. As used herein, a "suspending agent" is a substance that is
capable of suspending insoluble particulates such as proppant or
gravel in a fluid. A common suspending agent used in treatment
fluids is a polysaccharide.
[0025] A suspending agent tends to gel a fluid, which can be useful
in suspending an insoluble particulate in the fluid. Historically,
the gel characteristics of a fluid have not been easy to measure
directly, however, a viscosity measurement can be used as an
indicator of the capacity of a fluid to suspend and transport a
particulate. Accordingly, a suspending agent sometimes has been
referred to as a viscosity-increasing agent. Viscosity is the
resistance of a fluid to flow, defined as the ratio of shear stress
to shear rate. The viscosity of a well treatment fluid usually is
expressed in the unit centipoise ("cP"). Viscosity must have a
stated or an understood shear rate and measurement temperature in
order to be meaningful.
[0026] While viscosity tends to correlate with the suspending
capability of a fluid, viscosity is not necessarily a measure of
the suspending ability of a fluid. Even if the viscosity of a
treatment fluid is high, that does not mean the treatment fluid
necessarily can suspend an insoluble particulate such as proppant
or gravel.
[0027] More accurately, a suspending agent increases the elastic
modulus and loss modulus of a fluid. The elastic modulus and loss
modulus of a fluid are measurements that can be related directly to
the suspending capability of a suspending agent in a treatment
fluid, e.g., how well the suspending agent will suspend proppant or
gravel in the treatment fluid. For example, a fluid with a high
suspending capability will have a higher elastic modulus value
compared to a fluid without such a high suspending capability.
[0028] Elastic modulus (G') is a measure of the tendency of a
substance to be deformed elastically when a force is applied to it.
Elastic modulus is expressed in units of pressure, for example, Pa
(Pascals) or dynes/cm.sup.2. Loss modulus (G'') is a measure of the
energy lost when a substance is deformed. G'' is also expressed in
units of pressure, for example, Pa (Pascals) or dynes/cm.sup.2.
When comparing G' to G'' of a fluid, the units of both G' and G''
should be the same. Temperature can have an effect on the elastic
modulus of a fluid and the loss modulus of a fluid. In general, the
elastic modulus and loss modulus of a fluid will be different for a
fluid tested at 30.degree. C. compared to a fluid tested at
100.degree. C. More particularly, the elastic modulus and loss
modulus of a fluid usually tend to decrease as the temperature of
the fluid increases. Thus, in stating the elastic modulus or loss
modulus of a fluid, it is important to state the temperature at
which the measurement is made.
[0029] Because of the high volume of fracturing fluid typically
used in a fracturing operation, it is desirable to increase the
elastic modulus of the fracturing fluid to the desired elastic
modulus using as little suspending agent as possible. Being able to
use only a small concentration of the suspending agent requires a
lesser amount of the suspending agent in order to achieve the
desired elastic modulus in a large volume of fracturing fluid.
[0030] Efficient and inexpensive suspending agents typically
comprise a water-soluble polymer. More preferably, the
water-soluble polymer is a polysaccharide such as guar, xanthan, or
diutan.
[0031] To further increase the gelling of a fluid, the suspending
agent can be cross linked. As used herein, a "cross link" or "cross
linking" is a connection between two or more polymer molecules.
[0032] Optionally, one or more other additives can be included to
form a treatment fluid to be delivered into a wellbore for various
purposes. For example, a treatment fluid commonly includes a
breaker. A breaker is a chemical used for the purpose of
diminishing or "breaking" the viscosity and elastic modulus of the
fluid so that this fluid can be recovered more easily from the
formation during cleanup. Types of breakers include, for example,
oxidizers, enzymes, or acids, including delayed release or
encapsulated breakers.
[0033] A treatment fluid can include a surfactant. For example, a
surfactant may be used for its ability to aid the dispersion and/or
stabilization of a gas component into the fluid.
[0034] Further, a treatment fluid can contain other materials,
additives, and chemicals that are used in oil field applications.
These include, but are not necessarily limited to, a breaker aid, a
co-surfactant, an oxygen scavenger, an alcohol, a scale inhibitor,
a corrosion inhibitor, a fluid-loss additive, an oxidizer, a
bactericide, a biocide, a microemulsion, and the like. The
treatment fluid can also include a gas for foaming the fluid.
[0035] One of the most common components of a treatment fluid is a
water-soluble salt. A salt may be naturally occurring in the water
source (as in seawater). A salt can be added to help make a
treatment fluid be more chemically compatible with the subterranean
formation. A salt can be included to increase the density of a
treatment fluid. A salt used to increase the density of the
treatment fluid can be selected based on a sufficient density and
sufficient solubility such that the water-salt solution of the
treatment fluid has a density of at least 10 pounds per gallon
(ppg). For example, a salt having a sufficient density is a salt
having a density of at least 1.5 g/cm.sup.3. For example, a salt
having a sufficient solubility is a salt that is capable of
dissolving at least 1.5 lbs of salt per gallon of deionized water
(268 g/L). For example, metal salts, such as calcium bromide
(CaBr.sub.2) or sodium bromide (NaBr), can be added to the
treatment fluid in a high concentration to give a water-salt
solution having a density in the range of 10.0 to 15.0 pounds per
gallon (ppg). Other examples of water-soluble metal salts that can
be in a treatment fluid include zinc bromide, calcium chloride, and
potassium formate, and any combination thereof in any
proportion.
[0036] The presence of salt, however, especially in a high
concentration, can make it difficult to dissolve certain types of
polysaccharides in an aqueous fluid. This is known to be a problem
for xanthan and diutan, for example. If the polysaccharide is
inhibited from dissolving, then a lower G' value will be observed
for the fluid compared to a fluid having a higher dissolved
concentration of the polysaccharide. It is important that a
treatment fluid have a desired G' value (or desired viscosity as a
proxy for the suspending capability) to be able to suspend a
desired concentration of proppant or gravel at the time the
treatment fluid is introduced into a wellbore of a well.
[0037] Various techniques can be used to help dissolve the
polysaccharide. For example, if xanthan or diutan does not dissolve
in an aqueous solution having a high concentration of salt at
30.degree. C., the fluid can be heated to above 70.degree. C. to
help dissolve the xanthan or diutan. Unfortunately, such an added
process of heating the fluid to help dissolve a polysaccharide is
very expensive.
[0038] For a fluid tested at 30.degree. C., the elastic modulus or
loss modulus of the fluid can be different if the fluid is not
heated beyond 30.degree. C. compared to a fluid that is heated
above 30.degree. C., for example to 80.degree. C., and then cooled
back down to 30.degree. C. As used herein, a G' value at a stated
temperature for a fluid is measured without any heating of the
fluid above that temperature.
[0039] According to a first aspect of the inventions, a method is
provided for treating a portion of a well, where the method
includes the steps of: (a) forming a treatment fluid comprising an
aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution has a G' of
at least 2 Pa whereas an identical aqueous solution except with
less than the sufficient concentration of the urea would not have a
G' of at least 2 Pa, and wherein G' is measured in the linear
viscoelastic region at at least one desired temperature in the
range of 10.degree. C.-50.degree. C. without any increase in
temperature of the aqueous solution above the desired temperature;
and (b) introducing the treatment fluid into the well.
[0040] According to another aspect of the inventions, a method is
provided for treating a portion of a well, where the method
includes the steps of: (a) forming a treatment fluid comprising an
aqueous solution, wherein the aqueous solution comprises: (i)
water; (ii) a water-soluble polysaccharide; (iii) one or more
water-soluble salts, wherein the one or more salts are selected and
are in at least a sufficient concentration such that the water-salt
solution has a density of at least 10 ppg; and (iv) urea; wherein
the concentration of the urea in the water is in at least a
sufficient concentration such that the aqueous solution is
filterable, whereas an identical aqueous solution except with less
than the sufficient concentration of the urea would not be
filterable; and (b) introducing the treatment fluid into the
well.
[0041] Preferably, the aqueous solution of the treatment fluid has
a G' of at least 2 Pa measured in the linear viscoelastic region at
a temperature of 30.degree. C. and is filterable. The aqueous
solution preferably has a G' of at least 5 Pa measured in the
linear viscoelastic region at a temperature of 30.degree. C.
Preferably, the aqueous solution has a G' of at least 10 Pa
measured in the linear viscoelastic region at a temperature of
40.degree. C. More preferably, the aqueous solution has a G' of at
least 10 Pa measured in the linear viscoelastic region at a
temperature of 30.degree. C.
[0042] Preferably, the treatment fluid is introduced into a
wellbore of the well at a temperature below 40.degree. C. More
preferably, the treatment fluid is introduced into a wellbore at a
temperature at or below 30.degree. C. Most preferably, the
treatment fluid is introduced into a wellbore of the well without
any prior heating of the water of the treatment fluid to help
dissolve the polysaccharide in the water of the treatment
fluid.
[0043] As used herein, the term "water-soluble polysaccharide"
means the polysaccharide is at least 10 g/L soluble in deionized
water at a temperature of 25.degree. C. (77.degree. F.) and a
pressure of 1 atmosphere. As used herein, the term "water-soluble
salt" means that the water-soluble salt has at least a sufficient
density and is at least sufficiently water soluble such that it is
possible to make a water-salt solution of water and the salt having
a density of at least 10 lb/gal. Preferably, at least 1.5 lbs of
the salt dissolves in 1 gal of deionized water (268 g/L) at a
temperature of 25.degree. C. (77.degree. F.) and a pressure of 1
atmosphere. Preferably, the water-soluble salt has a density of at
least 1.5 g/cm.sup.3.
[0044] Preferably, the polysaccharide is selected from the group
consisting of diutan, xanthan, and any combination thereof in any
proportion. Preferably, the polysaccharide is in a concentration at
least 0.1% by weight of the water in the aqueous solution. More
preferably, the polysaccharide is in a concentration in the range
of 0.1% to 1.0% by weight of the water in the aqueous solution.
[0045] Preferably, the treatment fluid contains a water-salt
solution having a density in the range of 10.5-15.5 ppg. The one or
more salts are selected from the group consisting of sodium
bromide, sodium chloride, calcium bromide, calcium chloride, zinc
bromide, zinc chloride, and any combination thereof in any
proportion.
[0046] Preferably, the urea is in a concentration of at least 5% by
weight of the water in the aqueous solution. More preferably, the
urea is in a concentration in the range of 12%-35% by weight of the
water in the aqueous solution.
[0047] The treatment fluid can include an insoluble particulate
selected from the group consisting of proppant and gravel.
Preferably, the insoluble particulate is gravel. Preferably, the
gravel has a size distribution such that 90% of the gravel is in
the range of 0.5 mm to 2 mm.
[0048] The treatment fluid can include a cross-linking agent for
the polysaccharide. The treatment fluid can optionally include a
breaker. The breaker can be in a delayed-release form. For example,
the breaker can be in the form of a delayed-release capsule.
[0049] The methods of the inventions can also include the step of
introducing a breaker into the portion of well after the step of
introducing the treatment fluid into the portion of the well. If
the breaker is in a delayed-release form, the methods of the
inventions can further include the step of simultaneously
introducing the breaker with the treatment fluid into the portion
of the well.
[0050] FIGS. 1 and 2 illustrate examples of aqueous solutions
according to the presently most-preferred embodiment of the present
inventions. FIG. 1 is a graph of the elastic modulus (G') and loss
modulus (G'') in Pascal (Pa) versus temperature of an aqueous
solution containing 0.5% diutan by volume and a calcium bromide
(CaBr.sub.2) salt solution having a density of 11.3 pounds per
gallon (ppg). The data show that the fluid has a low G' at lower
temperatures, but as the temperature of the fluid is increased, G'
increases. The low G' values at lower temperatures indicate that
the diutan is not as dissolved at these lower temperatures, and,
therefore, the fluid has less suspending capability at these lower
temperatures.
[0051] FIG. 2 is a graph of G' and G'' in Pascal (Pa) versus
temperature of aqueous solutions containing 0.5% diutan by volume
and varied concentrations of urea in CaBr.sub.2 salt solutions
having varied densities. As can be appreciated from the data, the
fluid containing 7.7% urea by volume exhibits a G' curve similar to
a fluid without urea. Conversely, the fluids containing 18% and
24.4% urea by volume have higher G' values in the temperature range
of approximately 30.degree. C. to approximately 70.degree. C.
compared to the fluids with either 0% or 7.7% urea by volume. The
high G' values indicate that the diutan is more dissolved at lower
temperatures in the fluids containing 18% or 24.4% urea. compared
to the fluids containing 0% or 7.7% urea. The 18% and 24.4% urea
fluids have an increased suspending capability at the lower
temperatures compared to the fluids containing 0% and 7.7%
urea.
* * * * *