U.S. patent application number 13/527367 was filed with the patent office on 2013-12-19 for breaking diutan with metal activitor down to 140 .degree.f or lower.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is SHOY C. GEORGE, PRAJAKTA RATNAKAR PATIL, LALIT P. SALGAONKAR. Invention is credited to SHOY C. GEORGE, PRAJAKTA RATNAKAR PATIL, LALIT P. SALGAONKAR.
Application Number | 20130333886 13/527367 |
Document ID | / |
Family ID | 48468847 |
Filed Date | 2013-12-19 |
United States Patent
Application |
20130333886 |
Kind Code |
A1 |
GEORGE; SHOY C. ; et
al. |
December 19, 2013 |
BREAKING DIUTAN WITH METAL ACTIVITOR DOWN TO 140 .degree.F OR
LOWER
Abstract
A method of gravel packing a treatment zone of a well includes
the steps of: (A) forming a treatment fluid including a continuous
aqueous phase and gravel, wherein the aqueous phase includes: (i)
water; (ii) diutan; (iii) oxidizer in the range of 0.1% to 2% by
weight of the water; (iv) organic acid in the range of 0.5% to 5%
by weight of the water; and (v) transition metal compound in the
range of 0.001% to 0.25% by weight of the water; and (B)
introducing the treatment fluid into the treatment zone; wherein
the design temperature is less than 180.degree. F.; wherein the
continuous phase of the treatment fluid has a viscosity in the
range of 10 cP to 75 cP at the design temperature; and wherein the
concentration of the organic acid is less than would cause the
diutan to salt out at the design temperature.
Inventors: |
GEORGE; SHOY C.; (THRISSUR,
IN) ; SALGAONKAR; LALIT P.; (PUNE, IN) ;
PATIL; PRAJAKTA RATNAKAR; (PUNE, IN) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GEORGE; SHOY C.
SALGAONKAR; LALIT P.
PATIL; PRAJAKTA RATNAKAR |
THRISSUR
PUNE
PUNE |
|
IN
IN
IN |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
48468847 |
Appl. No.: |
13/527367 |
Filed: |
June 19, 2012 |
Current U.S.
Class: |
166/278 |
Current CPC
Class: |
C09K 8/514 20130101 |
Class at
Publication: |
166/278 |
International
Class: |
E21B 43/04 20060101
E21B043/04 |
Claims
1. A method of gravel packing a treatment zone of a well, the
method comprising the steps of: (A) forming a treatment fluid
comprising a continuous aqueous phase and gravel, wherein the
continuous aqueous phase comprises: (i) water; (ii) a
viscosity-increasing agent selected from the group consisting of
diutan, clarified diutan, a water-soluble derivative of diutan, and
any combination thereof; (iii) a water-soluble oxidizer or source
of a water-soluble oxidizer, wherein the concentration of the
water-soluble oxidizer is in the range of 0.1% to 2% by weight of
the water of the continuous phase; (iv) a water-soluble organic
acid or source of a water-soluble organic acid, wherein the
water-soluble organic acid has a pKa(1) in the range of 1 to 5 and
the concentration of the water-soluble organic acid is in the range
of 0.5% to 5% by weight of the water of the continuous phase; and
(v) a water-soluble transition metal compound or source of a
water-soluble transition metal compound, wherein the concentration
of the water-soluble transition metal compound is in the range of
0.001% to 0.25% by weight of the water of the continuous phase; and
(B) introducing the treatment fluid into the treatment zone of the
well; wherein the design temperature of the treatment zone of the
well is less than 180.degree. F. (82.2.degree. C.); wherein the
continuous phase of the treatment fluid has or develops a viscosity
in the range of 10 cP to 75 cP at the design temperature; and
wherein the concentration of the water-soluble organic acid is less
than the concentration that would cause the viscosity-increasing
agent to salt out from the continuous aqueous phase at the design
temperature.
2. The method according to claim 1, wherein the aqueous phase
comprises inorganic salt dissolved in the continuous aqueous phase
to the extent of at least 2% by weight of the water.
3. The method according to claim 1, wherein the aqueous phase
comprises inorganic salt dissolved in the continuous aqueous phase
to the extent of at least 5% by weight of the water.
4. The method according to claim 1, wherein the
viscosity-increasing agent is selected from the group consisting of
diutan, clarified diutan, and any combination thereof.
5. The method according to claim 1, wherein the viscosity of the
treatment fluid is at least 20 cP.
6. The method according to claim 1, wherein the oxidizer comprises
a peroxide.
7. The method according to claim 6, wherein the oxidizer comprises
t-butyl hydro peroxide.
8. The method according to claim 1, wherein the organic acid is
formic acid.
9. The method according to claim 1, wherein the transition metal of
the transition metal compound is selected from the group consisting
of manganese, vanadium, cobalt, and iron has a valence state of at
least 2.
10. The method according to claim 1, wherein the transition metal
compound is a ferric compound.
11. The method according to claim 1, wherein the transition metal
compound is a ferric chloride.
12. The method according to claim 1, wherein the pH of the
continuous aqueous phase of the treatment fluid is in the range of
about 3 to about 5.
13. The method of claim 1, wherein the continuous aqueous phase of
the treatment fluid further comprises a pH-adjuster other than the
viscosity-increasing agent, the oxidizer, the organic acid, and the
transition metal compound.
14. The method according to claim 13, wherein the continuous
aqueous phase of the treatment fluid excludes a strong acid.
15. The method according to claim 1, wherein the step of
introducing comprises introducing under conditions for gravel
packing the treatment zone of the wellbore.
16. The method according to claim 1, wherein the step of
introducing is below the fracture pressure of the treatment zone of
the well.
17. The method according to claim 1, wherein the step of flowing
back is in the range of 1 to 5 days of the step of introducing.
18. The method according to claim 1, wherein the design temperature
of the treatment zone of the well is between 140.degree. F.
(60.degree. C.) and 180.degree. F. (82.2.degree. C.).
19. A method of gravel packing a treatment zone of a well, the
method comprising the steps of: (A) forming a treatment fluid
including a continuous aqueous phase and gravel, wherein the
aqueous phase comprises: (i) water; (ii) diutan; (iii) oxidizer in
the range of 0.1% to 2% by weight of the water; (iv) organic acid
in the range of 0.5% to 5% by weight of the water; and (v)
transition metal compound in the range of 0.001% to 0.25% by weight
of the water; and (B) introducing the treatment fluid into the
treatment zone; wherein the design temperature is less than
180.degree. F.; wherein the continuous phase of the treatment fluid
has a viscosity in the range of 10 cP to 75 cP at the design
temperature; and wherein the concentration of the organic acid is
less than would cause the diutan to salt out at the design
temperature.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
TECHNICAL FIELD
[0002] The inventions are in the field of producing crude oil or
natural gas from subterranean formations. More particularly, the
present invention relates to methods of reducing the viscosity of
well treatment fluids that include diutan or a diutan derivative.
The present invention has particular application to gravel
packing.
BACKGROUND
Producing Oil and Gas
[0003] In the context of production from a well, oil and gas are
understood to refer to crude oil and natural gas. Oil and gas are
naturally occurring hydrocarbons in certain subterranean
formations.
[0004] To produce oil or gas from a reservoir, a well is drilled
into a subterranean formation, which may be the reservoir or
adjacent to the reservoir. A well includes a wellhead and at least
one wellbore from the wellhead penetrating the earth. Typically, a
wellbore must be drilled thousands of feet into the earth to reach
a hydrocarbon-bearing formation. Generally, the greater the depth
of the formation, the higher the static pressure and temperature of
the formation.
[0005] Generally, well services include a wide variety of
operations that may be performed in wells, such as drilling,
cementing, completion, and intervention. Well services are designed
to facilitate or enhance the production of desirable fluids from or
through a subterranean formation. A well service usually involves
introducing a well fluid into a well.
[0006] Drilling, completion, and intervention operations can
include various types of treatments that are commonly performed in
a wellbore or subterranean formation. For example, a treatment for
fluid-loss control can be used during any of drilling, completion,
and intervention operations. During completion or intervention,
stimulation is a type of treatment performed to enhance or restore
the productivity of oil and gas from a well. Stimulation treatments
fall into two main groups: hydraulic fracturing and matrix
treatments. Fracturing treatments are performed above the fracture
pressure of the subterranean formation to create or extend a highly
permeable flow path between the formation and the wellbore. Matrix
treatments are performed below the fracture pressure of the
formation. Other types of completion or intervention treatments can
include, for example, gravel packing, consolidation, and
controlling excessive water production. Still other types of
completion or intervention treatments include, but are not limited
to, damage removal, formation isolation, wellbore cleanout, scale
removal, and scale control. Of course, other well treatments and
treatment fluids are known in the art.
Acidizing
[0007] Acidizing is a type of stimulation treatment, which is
performed below the reservoir fracture pressure in an effort to
restore or enhance the natural permeability of the reservoir rock.
Well acidizing is achieved by pumping acid into the well to
dissolve limestone, dolomite and calcite cement between the
sediment grains of the reservoir rocks. There are two types of acid
treatment: matrix acidizing and fracture acidizing
[0008] In matrix acid job, acid is pumped into the well and into
the pores of the reservoir rocks. In this form of acidization, the
acids dissolve the sediments and mud solids that are inhibiting the
permeability of the rock, enlarging the natural pores of the
reservoir and stimulating flow of hydrocarbons.
[0009] While matrix acidizing is carried out at a pressure less
than the fracture pressure of the reservoir rock, fracture
acidizing involves pumping highly pressurized acid into the well,
physically fracturing the reservoir rock and dissolving the
permeability inhibitive sediments. This type of acid job forms
channels through which the hydrocarbons can flow.
Hydraulic Fracturing
[0010] Hydraulic fracturing is a common stimulation treatment. The
purpose of a fracturing treatment is to provide an improved flow
path for oil or gas to flow from the hydrocarbon-bearing formation
to the wellbore. A treatment fluid adapted for this purpose is
sometimes 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
one or more fractures 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.
[0011] The formation or extension of a fracture in hydraulic
fracturing may initially occur suddenly. When this happens, the
fracturing fluid suddenly has a fluid flow path through the
fracture to flow more rapidly away from the wellbore. As soon as
the fracture is created or enhanced, the sudden increase in the
flow of fluid away from the well reduces the pressure in the well.
Thus, the creation or enhancement of a fracture in the formation
may be indicated by a sudden drop in fluid pressure, which can be
observed at the wellhead. After initially breaking down the
formation, the fracture may then propagate more slowly, at the same
pressure or with little pressure increase. It can also be detected
with seismic techniques.
[0012] Proppant for Hydraulic Fracturing
[0013] A newly-created or newly-extended fracture will tend to
close together after the pumping of the fracturing fluid is
stopped. To prevent the fracture from closing, a material is
usually placed in the fracture to keep the fracture propped open
and to provide higher fluid conductivity than the matrix of the
formation. A material used for this purpose is referred to as a
proppant.
[0014] A proppant is in the form of a solid particulate, which can
be suspended in the fracturing fluid, carried downhole, and
deposited in the fracture to form a proppant pack. The proppant
pack props the fracture in an open condition while allowing fluid
flow through the permeability of the pack. The proppant pack in the
fracture provides a higher-permeability flow path for the oil or
gas to reach the wellbore compared to the permeability of the
matrix of the surrounding subterranean formation. This
higher-permeability flow path increases oil and gas production from
the subterranean formation.
[0015] A particulate for use as a proppant is usually selected
based on the characteristics of size range, crush strength, and
solid stability in the types of fluids that are encountered or used
in wells. Preferably, a proppant should not melt, dissolve, or
otherwise degrade from the solid state under the downhole
conditions.
[0016] The proppant is selected to be an appropriate size to prop
open the fracture and bridge the fracture width expected to be
created by the fracturing conditions and the fracturing fluid. If
the proppant is too large, it will not easily pass into a fracture
and will screenout too early. If the proppant is too small, it will
not provide the fluid conductivity to enhance production. See, for
example, McGuire and Sikora, 1960. In the case of fracturing
relatively permeable or even tight-gas reservoirs, a proppant pack
should provide higher permeability than the matrix of the
formation. In the case of fracturing ultra-low permeable
formations, such as shale formations, a proppant pack should
provide for higher permeability than the naturally occurring
fractures or other micro-fractures of the fracture complexity.
[0017] 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-sized, which geologically is
defined as having a largest dimension ranging from about 0.06
millimeters up to about 2 millimeters (mm). (The next smaller
particle size class below sand sized is silt, which is defined as
having a largest dimension ranging from less than about 0.06 mm
down to about 0.004 mm.) As used herein, proppant does not mean or
refer to suspended solids, silt, fines, or other types of insoluble
solid particulate smaller than about 0.06 mm (about 230 U.S.
Standard Mesh). Further, it does not mean or refer to particulates
larger than about 3 mm (about 7 U.S. Standard Mesh).
[0018] The proppant is sufficiently strong, that is, has a
sufficient compressive or crush resistance, to prop the fracture
open without being deformed or crushed by the closure stress of the
fracture in the subterranean formation. For example, for a proppant
material that crushes under closure stress, a 20/40 mesh proppant
preferably has an API crush strength of at least 4,000 psi closure
stress based on 10% crush fines according to procedure API RP-56. A
12/20 mesh proppant material preferably has an API crush strength
of at least 4,000 psi closure stress based on 16% crush fines
according to procedure API RP-56. This performance is that of a
medium crush-strength proppant, whereas a very high crush-strength
proppant would have a crush-strength of about 10,000 psi. In
comparison, for example, a 100-mesh proppant material for use in an
ultra-low permeable formation such as shale preferably has an API
crush strength of at least 5,000 psi closure stress based on 6%
crush fines. The higher the closing pressure of the formation of
the fracturing application, the higher the strength of proppant is
needed. The closure stress depends on a number of factors known in
the art, including the depth of the formation.
[0019] Further, a suitable proppant should be stable over time and
not dissolve in fluids commonly encountered in a well environment.
Preferably, a proppant material is selected that will not dissolve
in water or crude oil.
[0020] Suitable proppant materials include, but are not limited to,
sand (silica), ground nut shells or fruit pits, sintered bauxite,
glass, plastics, ceramic materials, processed wood, resin coated
sand or ground nut shells or fruit pits or other composites, and
any combination of the foregoing. Mixtures of different kinds or
sizes of proppant can be used as well. In conventional reservoirs,
if sand is used, it commonly has a median size anywhere within the
range of about 20 to about 100 U.S. Standard Mesh. For a synthetic
proppant, it commonly has a median size anywhere within the range
of about 8 to about 100 U.S. Standard Mesh.
[0021] The concentration of proppant in the treatment fluid depends
on the nature of the subterranean formation. As the nature of
subterranean formations differs widely, the concentration of
proppant in the treatment fluid may be in the range of from about
0.03 kilograms to about 12 kilograms of proppant per liter of
liquid phase (from about 0.1 lb/gal to about 25 lb/gal).
Sand Control & Gravel Packing
[0022] It is well known in the subterranean drilling and completion
art that particulate materials such as sand may be produced during
the production of hydrocarbons from a well traversing an
unconsolidated or loosely consolidated subterranean formation.
Numerous problems may occur as a result of the production of such
particulate. For example, the particulate causes abrasive wear to
components within the well, such as tubing, pumps and valves. In
addition, the particulate may partially or fully clog the well
creating the need for an expensive workover. Also, if the
particulate matter is produced to the surface, it must be removed
from the hydrocarbon fluids by processing equipment at the
surface.
[0023] Gravel packing is commonly used as a sand-control method to
prevent production of formation sand or other fines from a poorly
consolidated subterranean formation. In this context, "fines" are
tiny particles, typically having a diameter of 43 microns or
smaller, that have a tendency to flow through the formation with
the production of hydrocarbon. The fines have a tendency to plug
small pore spaces in the formation and block the flow of oil. As
all the hydrocarbon is flowing from a relatively large region
around the wellbore toward a relatively small area around the
wellbore, the fines have a tendency to become densely packed and
screen out or plug the area immediately around the wellbore.
Moreover, the fines are highly abrasive and can be damaging to
pumping and oilfield other equipment and operations.
[0024] Placing a relatively larger particulate near the wellbore
helps filter out the sand or fine particles and prevents them from
flowing into the well with the produced fluids. The primary
objective is to stabilize the formation while causing minimal
impairment to well productivity.
[0025] The particulate used for this purpose is referred to as
"gravel." In the oil and gas field, and as used herein, the term
"gravel" is refers to relatively large particles in the sand size
classification, that is, particles ranging in diameter from about
0.1 mm up to about 2 mm. Generally, a particulate having the
properties, including chemical stability, of a low-strength
proppant is used in gravel packing. An example of a commonly used
gravel packing material is sand having an appropriate particulate
size range. For various purposes, the gravel particulates also may
be coated with certain types of materials, including resins,
tackifying agents, and the like. For example, a tackifying agent
can help with fines and resins can help to enhance conductivity
(e.g., fluid flow) through the gravel pack.
[0026] In one common type of gravel packing, a mechanical screen is
placed in the wellbore and the surrounding annulus is packed with a
particulate of a larger specific size designed to prevent the
passage of formation sand or other fines. Typically, the liquid
carrier fluid is returned to the surface by flowing through the
screen and up a wash pipe. The gravel is deposited around the
screen to form a gravel pack, which is a highly permeable allowing
hydrocarbon fluid to flow easily while blocking the flow of the
particulate carried in the hydrocarbon fluids. As such, gravel
packs can successfully prevent the problems associated with the
production of particulate materials from the formation.
[0027] It is also common, for example, to gravel pack after a
fracturing procedure, and such a combined procedure is sometimes
referred to as a "frac-packing."
[0028] Like with placing a proppant in a subterranean formation
during hydraulic fracturing, in gravel packing a viscosified fluid
can be used to help transport and place the gravel in the well.
Carrier Fluid for Particulate
[0029] A well fluid can be adapted to be a carrier fluid for
particulates.
[0030] For example, a proppant used in fracturing or a gravel used
in gravel packing may have a much different density than the
carrier fluid. For example, sand has a specific gravity of about
2.7, whereas water has a specific gravity of 1.0 at Standard
Laboratory Conditions of temperature and pressure. A proppant or
gravel having a different density than water will tend to separate
from water very rapidly.
[0031] As many well fluids are water-based, partly for the purpose
of helping to suspend particulate of higher density, and for other
reasons known in the art, the density of the fluid used in a well
can be increased by including highly water-soluble salts in the
water, such as potassium chloride. However, increasing the density
of a well fluid will rarely be sufficient to match the density of
the particulate.
[0032] Increasing Viscosity of Fluid for Suspending Particulate
[0033] Increasing the viscosity of a well fluid can help prevent a
particulate having a different specific gravity than an external
phase of the fluid from quickly separating out of the external
phase.
[0034] A viscosity-increasing agent can be used to increase the
ability of a fluid to suspend and carry a particulate material in a
well fluid. A viscosity-increasing agent can be used for other
purposes, such as matrix diversion, conformance control, or
friction reduction.
[0035] A viscosity-increasing agent is sometimes referred to in the
art as a viscosifying agent, viscosifier, thickener, gelling agent,
or suspending agent. In general, any of these refers to an agent
that includes at least the characteristic of increasing the
viscosity of a fluid in which it is dispersed or dissolved. There
are several kinds of viscosity-increasing agents and related
techniques for increasing the viscosity of a fluid.
[0036] In general, because of the high volume of fracturing fluid
typically used in a fracturing operation, it is desirable to
efficiently increase the viscosity of fracturing fluids to the
desired viscosity using as little viscosity-increasing agent as
possible. In addition, relatively inexpensive materials are
preferred. Being able to use only a small concentration of the
viscosity-increasing agent requires a lesser amount of the
viscosity-increasing agent in order to achieve the desired fluid
viscosity in a large volume of fracturing fluid.
[0037] Polymers for Increasing Viscosity
[0038] Certain kinds of polymers can be used to increase the
viscosity of a fluid. In general, the purpose of using a polymer is
to increase the ability of the fluid to suspend and carry a
particulate material. Polymers for increasing the viscosity of a
fluid are preferably soluble in the external phase of a fluid.
Polymers for increasing the viscosity of a fluid can be naturally
occurring polymers such as polysaccharides, derivatives of
naturally occurring polymers, or synthetic polymers.
[0039] Treatment fluids used in high volumes, such as fracturing
fluids, are usually water-based. Efficient and inexpensive
viscosity-increasing agents for water include certain classes of
water-soluble polymers.
[0040] As will be appreciated by a person of skill in the art, the
dispersibility or solubility in water of a certain kind of
polymeric material may be dependent on the salinity or pH of the
water. Accordingly, the salinity or pH of the water can be modified
to facilitate the dispersibility or solubility of the water-soluble
polymer. In some cases, the water-soluble polymer can be mixed with
a surfactant to facilitate its dispersibility or solubility in the
water or salt solution utilized.
[0041] The water-soluble polymer can have an average molecular
weight in the range of from about 50,000 to 20,000,000, most
preferably from about 100,000 to about 4,000,000. For example, guar
polymer is believed to have a molecular weight in the range of
about 2 to about 4 million.
[0042] Typical water-soluble polymers used in well treatments
include water-soluble polysaccharides and water-soluble synthetic
polymers (e.g., polyacrylamide). The most common water-soluble
polysaccharides employed in well treatments are guar and its
derivatives.
[0043] As used herein, a "polysaccharide" can broadly include a
modified or derivative polysaccharide. As used herein, "modified"
or "derivative" means a compound or substance formed by a chemical
process from a parent compound or substance, wherein the chemical
skeleton of the parent is retained in the derivative. The chemical
process preferably includes at most a few chemical reaction steps,
and more preferably only one or two chemical reaction steps. As
used herein, a "chemical reaction step" is a chemical reaction
between two chemical reactant species to produce at least one
chemically different species from the reactants (regardless of the
number of transient chemical species that may be formed during the
reaction). An example of a chemical step is a substitution
reaction. Substitution on a polymeric material may be partial or
complete.
[0044] Single- or Multi-Chain Polymers
[0045] A polymer can be classified as being single chain or multi
chain, based on its solution structure in aqueous liquid media.
Examples of single-chain polysaccharides that are commonly used in
the oilfield industry include guar, guar derivatives, and cellulose
derivatives. Guar polymer, which is derived from the beans of a
guar plant, is referred to chemically as a galactomannan gum.
Examples of multi-chain polysaccharides include xanthan, diutan,
and scleroglucan, and derivatives of any of these. Without being
limited by any theory, it is currently believed that the
multi-chain polysaccharides have a solution structure similar to a
helix or are otherwise intertwined.
[0046] Fluid Damage to Proppant Pack or Matrix Permeability
[0047] In well treatments using viscous well fluids, the material
for increasing the viscosity of the fluid can damage the
permeability of the proppant pack or the matrix of the subterranean
formation. For example, a treatment fluid can include a polymeric
material that is deposited in the fracture or within the matrix. By
way of another example, the treatment fluid may include surfactants
that leave unbroken micelles in the fracture or change the
wettability of the formation in the region of the fracture.
[0048] Breakers are utilized in many treatments to mitigate fluid
damage in the formation. However, breakers and other treatments are
subject to variability of results, they add expense and
complication to a fracture treatment, and in can still leave at
least some fluid damage in the formation.
Breaker for Viscosity of Fluid with Polysaccharide
[0049] After a treatment fluid is placed where desired in the well
and for the desired time, the fluid usually must be removed from
the wellbore or the formation. For example, in the case of
hydraulic fracturing, the fluid should be removed leaving the
proppant in the fracture and without damaging the conductivity of
the proppant bed. To accomplish this removal, the viscosity of the
treatment fluid must be reduced to a very low viscosity, preferably
near the viscosity of water, for optimal removal from the propped
fracture. Similarly, when a viscosified fluid is used for gravel
packing, the viscosified fluid must be removed from the gravel
pack.
[0050] Reducing the viscosity of a viscosified treatment fluid is
referred to as "breaking" the fluid. Chemicals used to reduce the
viscosity of treatment fluids are called breakers. Other types of
viscosified well fluids also need to be broken for removal from the
wellbore or subterranean formation.
[0051] No particular mechanism is necessarily implied by the term.
For example, a breaker can reduce the molecular weight of a
water-soluble polymer by cutting the long polymer chain. As the
length of the polymer chain is cut, the viscosity of the fluid is
reduced. For instance, reducing the guar polymer molecular weight
to shorter chains having a molecular weight of about 10,000
converts the fluid to near water-thin viscosity. This process can
occur independently of any crosslinking bonds existing between
polymer chains. In the case of a crosslinked viscosity-increasing
agent, for example, one way to diminish the viscosity is by
breaking the crosslinks.
[0052] Thus, removal of the treatment fluid is facilitated by using
one or more breakers to reduce fluid viscosity.
[0053] Breakers must be selected to meet the needs of each
situation. First, it is important to understand the general
performance criteria of breakers. In reducing the viscosity of the
treatment fluid to a near water-thin state, the breaker must
maintain a critical balance. Premature reduction of viscosity
during the pumping of a treatment fluid can jeopardize the
treatment. Inadequate reduction of fluid viscosity after pumping
can also reduce production if the required conductivity is not
obtained.
[0054] A breaker should be selected based on its performance in the
temperature, pH, time, and desired viscosity profile for each
specific treatment.
[0055] In fracturing, for example, the ideal viscosity versus time
profile would be if a fluid maintained 100% viscosity until the
fracture closed on proppant and then immediately broke to a thin
fluid. Some breaking inherently occurs during the 0.5 to 4 hours
required to pump most fracturing treatments. One guideline for
selecting an acceptable breaker design is that at least 50% of the
fluid viscosity should be maintained at the end of the pumping
time. This guideline may be adjusted according to job time, desired
fracture length, and required fluid viscosity at reservoir
temperature. A typical gravel pack break criteria is a minimum
4-hour break time.
[0056] Chemical breakers used to reduce viscosity of a fluid
viscosified with a viscosifying polymer used in fracturing or other
subterranean applications are generally grouped into three classes:
oxidizers, enzymes, and acids. The breakers operate by cleaving the
backbone of polymer either by hydrolysis of acetyl group, cleavage
of glycosidic bonds, oxidative/reductive cleavage, free radical
breakage or combination of these processes. A breaker should be
selected based on its performance in the temperature, pH, time, and
desired viscosity profile for each specific treatment.
[0057] Breaking of Multi-Chain Polysaccharides More Difficult
[0058] Fluids viscosified with a multi-chain polysaccharide can be
more difficult to break than fluids viscosified with a single-chain
polysaccharide. In particular, there are few methods available to
break the fluid viscosity of a fluid viscosified with a multi-chain
polysaccharide at low temperatures (below 180.degree. F. or
82.2.degree. C.), and they suffer from various problems. In
particular, it is desirable to have a breaker system operative for
diutan at least in this temperature range, which would be
particularly useful in low-temperature gravel packing
applications.
SUMMARY OF THE INVENTIONS
[0059] The inventions are in the field of producing crude oil or
natural gas from subterranean formations. More specifically, the
inventions generally relate to methods and compositions for
treating a subterranean formation. More particularly, the present
invention relates to methods of reducing the viscosity of treatment
fluids that include diutan or a diutan derivative, which is
particularly useful in low-temperature gravel packing
applications.
[0060] In an embodiment, a method of gravel packing a treatment
zone of a well is provided. The method includes the steps of:
[0061] (A) forming a treatment fluid comprising a continuous
aqueous phase and gravel, wherein the continuous aqueous phase
comprises: [0062] (i) water; [0063] (ii) a viscosity-increasing
agent selected from the group consisting of diutan, clarified
diutan, a water-soluble derivative of diutan, and any combination
thereof; [0064] (iii) a water-soluble oxidizer or source of a
water-soluble oxidizer, wherein the concentration of the
water-soluble oxidizer is in the range of 0.1% to 2% by weight of
the water of the continuous phase; [0065] (iv) a water-soluble
organic acid or source of a water-soluble organic acid, wherein the
water-soluble organic acid has a pKa(1) in the range of 1 to 5 and
the concentration of the water-soluble organic acid is in the range
of 0.5% to 5% by weight of the water of the continuous phase; and
[0066] (v) a water-soluble transition metal compound or source of a
water-soluble transition metal compound, wherein the concentration
of the water-soluble transition metal compound is in the range of
0.001% to 0.25% by weight of the water of the continuous phase; and
[0067] (B) introducing the treatment fluid into the treatment zone
of the well; [0068] wherein the design temperature of the treatment
zone of the well is less than 180.degree. F. (82.2.degree. C.);
[0069] wherein the continuous phase of the treatment fluid has or
develops a viscosity in the range of 10 cP to 75 cP at the design
temperature; and [0070] wherein the concentration of the
water-soluble organic acid is less than the concentration that
would cause the viscosity-increasing agent to salt out from the
continuous aqueous phase at the design temperature.
[0071] These and other aspects of the invention will be apparent to
one skilled in the art upon reading the following detailed
description. While the invention is susceptible to various
modifications and alternative forms, specific embodiments thereof
will be described in detail and shown by way of example. It should
be understood, however, that it is not intended to limit the
invention to the particular forms disclosed, but, on the contrary,
the invention is to cover all modifications and alternatives
falling within the spirit and scope of the invention as expressed
in the appended claims.
BRIEF DESCRIPTION OF THE DRAWING
[0072] The accompanying drawing is incorporated into the
specification to help illustrate examples according to the
presently most-preferred embodiment of the invention.
[0073] FIG. 1 is a graph of the reduction in viscosities (cP) over
time (Hrs) of six different test fluids of 30 lb/Mgal clarified
diutan, wherein the breaker system has varied concentrations of
t-butyl hydro peroxide ("TBHP") as oxidizer, formic acid as organic
acid, and FeCl.sub.3 as transition metal activator.
[0074] FIG. 2 is a graph of a test fluid according to the
invention, showing that the regained permeability value of 82.5%
was achieved.
DESCRIPTION OF PREFERRED EMBODIMENTS AND BEST MODE
Definitions and Usages
[0075] Interpretation
[0076] The words or terms used herein have their plain, ordinary
meaning in the field of this disclosure, except to the extent
explicitly and clearly defined in this disclosure.
[0077] If there is any conflict in the usages of a word or term in
this disclosure and one or more patent(s) or other documents that
may be incorporated by reference, the definitions that are
consistent with this specification should be adopted.
[0078] Patent Terms
[0079] The words "comprising," "containing," "including," "having,"
and all grammatical variations thereof are intended to have an
open, non-limiting meaning. For example, a composition comprising a
component does not exclude it from having additional components, an
apparatus comprising a part does not exclude it from having
additional parts, and a method having a step does not exclude it
having additional steps. When such terms are used, the
compositions, apparatuses, and methods that "consist essentially
of" or "consist of" the specified components, parts, and steps are
specifically included and disclosed.
[0080] The indefinite articles "a" or "an" mean one or more than
one of the component, part, or step that the article
introduces.
[0081] Whenever a numerical range of degree or measurement with a
lower limit and an upper limit is disclosed, any number and any
range falling within the range is also intended to be specifically
disclosed. For example, every range of values (in the form "from a
to b," or "from about a to about b," or "from about a to b," "from
approximately a to b," and any similar expressions, where "a" and
"b" represent numerical values of degree or measurement) is to be
understood to set forth every number and range encompassed within
the broader range of values.
[0082] Well Terms
[0083] In the context of production from a well, oil and gas are
understood to refer to crude oil and natural gas. Oil and gas are
naturally occurring hydrocarbons in certain subterranean
formations.
[0084] A "subterranean formation" is a body of rock that has
sufficiently distinctive characteristics and is sufficiently
continuous for geologists to describe, map, and name it.
[0085] A subterranean formation having a sufficient porosity and
permeability to store and transmit fluids is sometimes referred to
as a "reservoir."
[0086] A subterranean formation containing oil or gas may be
located under land or under the seabed off shore. Oil and gas
reservoirs are typically located in the range of a few hundred feet
(shallow reservoirs) to a few tens of thousands of feet (ultra-deep
reservoirs) below the surface of the land or seabed.
[0087] A "well" includes a wellhead and at least one wellbore from
the wellhead penetrating the earth. The "wellhead" is the surface
termination of a wellbore, which surface may be on land or on a
seabed. A "well site" is the geographical location of a wellhead of
a well. It may include related facilities, such as a tank battery,
separators, compressor stations, heating or other equipment, and
fluid pits. If offshore, a well site can include a platform.
[0088] The "wellbore" refers to the drilled hole, including any
cased or uncased portions of the well. The "borehole" usually
refers to the inside wellbore wall, that is, the rock face or wall
that bounds the drilled hole. A wellbore can have portions that are
vertical, horizontal, or anything in between, and it can have
portions that are straight, curved, or branched. As used herein,
"uphole," "downhole," and similar terms are relative to the
direction of the wellhead, regardless of whether a wellbore portion
is vertical or horizontal.
[0089] As used herein, introducing "into a well" means introduced
at least into and through the wellhead. According to various
techniques known in the art, tubulars, equipment, tools, or well
fluids can be directed from the wellhead into any desired portion
of the wellbore.
[0090] As used herein, a "well fluid" broadly refers to any fluid
adapted to be introduced into a well for any purpose. A well fluid
can be, for example, a drilling fluid, a cementing composition, a
treatment fluid, or a spacer fluid. If a well fluid is to be used
in a relatively small volume, for example less than about 200
barrels (about 32 m.sup.3), it is sometimes referred to in the art
as a wash, dump, slug, or pill.
[0091] As used herein, the word "treatment" refers to any treatment
for changing a condition of a portion of a wellbore or an adjacent
subterranean formation; however, the word "treatment" does not
necessarily imply any particular treatment purpose. A treatment
usually involves introducing a well fluid for the treatment, in
which case it may be referred to as a treatment fluid, into a well.
As used herein, a "treatment fluid" is a fluid used in a treatment.
Unless the context otherwise requires, the word "treatment" in the
term "treatment fluid" does not necessarily imply any particular
treatment or action by the fluid.
[0092] Broadly, a zone refers to an interval of rock along a
wellbore that is differentiated from uphole and downhole zones
based on hydrocarbon content or other features, such as
permeability, composition, perforations or other fluid
communication with the wellbore, faults, or fractures. A zone of a
wellbore that penetrates a hydrocarbon-bearing zone that is capable
of producing hydrocarbon is referred to as a "production zone." As
used herein, a "treatment zone" refers to an interval of rock along
a wellbore into which a well fluid is directed to flow from the
wellbore. As used herein, "into a treatment zone" means into and
through the wellhead and, additionally, through the wellbore and
into the treatment zone.
[0093] The term "design temperature" refers to an estimate or
measurement of the actual temperature at the downhole environment
at the time of a well treatment. That is, design temperature takes
into account not only the bottom hole static temperature ("BHST"),
but also the effect of the temperature of the well fluid on the
BHST during treatment and other factors known in the field. Because
treatment fluids may be considerably cooler than BHST, the
difference between the two temperatures can be quite large.
Ultimately, if left undisturbed, a subterranean formation will
return to the BHST.
[0094] Variations in Well Fluids
[0095] Unless the specific context otherwise requires, a well fluid
or treatment fluid refers to the specific properties and
composition of a fluid at the time the fluid is being introduced
into a well. In addition, it should be understood that, during the
course of a well operation such as drilling, cementing, completion,
or intervention, or during a specific treatment, the specific
properties and composition of a type of well fluid can be varied or
several different types of well fluids can be used. For example,
the compositions can be varied to adjust viscosity or elasticity of
the well fluids to accommodate changes in the concentrations of
particulate to be carried downhole. It can also be desirable to
accommodate expected changes in temperatures encountered by the
well fluids during the course of the treatment. By way of another
example, it can be desirable to accommodate the longer duration
that an earlier-introduced treatment fluid may need to maintain
viscosity before breaking compared to the shorter duration that a
later-introduced treatment fluid may need to maintain viscosity
before breaking. Changes in concentration of a particulate,
viscosity-increasing agent, breaker, or other additives in the
various treatment fluids of a treatment operation can be made in
stepped changes of concentrations or ramped changes of
concentrations.
[0096] Physical States and Phases
[0097] A substance can be a pure chemical or a mixture of two or
more different pure chemicals.
[0098] As used herein, "phase" is used to refer to a substance
having a chemical composition and physical state that is
distinguishable from an adjacent phase of a substance having a
different chemical composition or different physical state.
[0099] As used herein, if not other otherwise specifically stated,
the physical state or phase of a substance (or mixture of
substances) and other physical properties are determined at a
temperature of 77.degree. F. (25.degree. C.) and a pressure of 1
atmosphere (Standard Laboratory Conditions) without applied
shear.
[0100] Solubility Terms
[0101] A substance is considered to be "soluble" in a liquid if at
least 10 grams of the substance can be dissolved in one liter of
the liquid when tested at 77.degree. F. and 1 atmosphere pressure
for 2 hours and considered to be "insoluble" if less soluble than
this.
[0102] As will be appreciated by a person of skill in the art, the
hydratability, dispersibility, or solubility of a substance in
water can be dependent on the salinity, pH, or other substances in
the water. Accordingly, the salinity, pH, and additive selection of
the water can be modified to facilitate the hydratability,
dispersibility, or solubility of a substance in aqueous solution.
To the extent not specified, the hydratability, dispersibility, or
solubility of a substance in water is determined in deionized
water, at neutral pH, and without any other additives.
[0103] The "source" of a chemical species in a solution or fluid
composition, can be a substance that makes the chemical species
chemically available immediately or it can be a substance that
gradually or later releases the chemical species to become
chemically available.
[0104] Fluids
[0105] Every fluid inherently has at least a continuous phase. A
fluid can have more than one phase. The continuous phase of a well
fluid is a liquid under Standard Laboratory Conditions. For
example, a well fluid can in the form of be a suspension (solid
particles dispersed in a liquid phase), an emulsion (liquid
particles dispersed in another liquid phase), or a foam (a gas
phase dispersed in liquid phase).
[0106] As used herein, a water-based fluid means that water or an
aqueous solution is the dominant material, that is, greater than
50% by weight, of the continuous phase of the substance, excluding
the weight of any dissolved salts.
[0107] In contrast, "oil-based" means that oil is the dominant
material by weight of the continuous phase of the substance. In
this context, the oil of an oil-based fluid can be any oil. In
general, an oil is any substance that is liquid Standard Laboratory
Conditions, is hydrophobic, and soluble in organic solvents. Oils
have a high carbon and hydrogen content and are relatively
non-polar substances, for example, having a polarity of 3 or less
on the Synder polarity index. This general definition includes
classes such as petrochemical oils, vegetable oils, and many
organic solvents. All oils can be traced back to organic
sources.
[0108] Apparent Viscosity of a Fluid
[0109] Viscosity is a measure of the resistance of a fluid to flow.
In everyday terms, viscosity is "thickness" or "internal friction."
Thus, pure water is "thin," having a relatively low viscosity
whereas honey is "thick," having a relatively higher viscosity. Put
simply, the less viscous the fluid is, the greater its ease of
movement (fluidity). More precisely, viscosity is defined as the
ratio of shear stress to shear rate.
[0110] A Newtonian fluid (named after Isaac Newton) is a fluid for
which stress versus strain rate curve is linear and passes through
the origin. The constant of proportionality is known as the
viscosity. Examples of Newtonian fluids include water and most
gases. Newton's law of viscosity is an approximation that holds for
some substances but not others.
[0111] Non-Newtonian fluids exhibit a more complicated relationship
between shear stress and velocity gradient (i.e., shear rate) than
simple linearity. Thus, there exist a number of forms of
non-Newtonian fluids. Shear thickening fluids have an apparent
viscosity that increases with increasing the rate of shear. Shear
thinning fluids have a viscosity that decreases with increasing
rate of shear. Thixotropic fluids become less viscous over time at
a constant shear rate. Rheopectic fluids become more viscous over
time at a constant sear rate. A Bingham plastic is a material that
behaves as a solid at low stresses but flows as a viscous fluid at
high stresses.
[0112] Most well fluids are non-Newtonian fluids. Accordingly, the
apparent viscosity of a fluid applies only under a particular set
of conditions including shear stress versus shear rate, which must
be specified or understood from the context. In the oilfield and as
used herein, unless the context otherwise requires it is understood
that a reference to viscosity is actually a reference to an
apparent viscosity. Apparent viscosity is commonly expressed in
units of centipoise ("cP").
[0113] Like other physical properties, the viscosity of a Newtonian
fluid or the apparent viscosity of a non-Newtonian fluid may be
highly dependent on the physical conditions, primarily temperature
and pressure.
[0114] Gels and Deformation
[0115] The physical state of a gel is formed by a network of
interconnected molecules, such as a crosslinked polymer or a
network of micelles. The network gives a gel phase its structure
and an apparent yield point. At the molecular level, a gel is a
dispersion in which both the network of molecules is continuous and
the liquid is continuous. A gel is sometimes considered as a single
phase.
[0116] Technically, a "gel" is a semi-solid, jelly-like physical
state or phase that can have properties ranging from soft and weak
to hard and tough. Shearing stresses below a certain finite value
fail to produce permanent deformation. The minimum shear stress
that will produce permanent deformation is referred to as the shear
strength or gel strength of the gel.
[0117] As used herein, unless otherwise specified or the context
otherwise requires, a substance referred to as a "gel" is subsumed
by the concept of "fluid" if it is a pumpable fluid.
[0118] In the oil and gas industry, however, the term "gel" may be
used to refer to any fluid having a viscosity-increasing agent,
regardless of whether it is a viscous fluid or meets the technical
definition for the physical state of a gel. A "base gel" is a term
used in the field for a fluid that includes a viscosity-increasing
agent, such as guar, but that excludes crosslinking agents.
Typically, a base gel is mixed with another fluid containing a
crosslinker, wherein the mixture is adapted to form a crosslinked
gel. Similarly, a "crosslinked gel" may refer to a substance having
a viscosity-increasing agent that is crosslinked, regardless of
whether it is a viscous fluid or meets the technical definition for
the physical state of a gel.
[0119] Viscosity and Gel Measurements
[0120] There are numerous ways of measuring and modeling viscous
properties, and new developments continue to be made. The methods
depend on the type of fluid for which viscosity is being measured.
A typical method for quality assurance or quality control (QA/QC)
purposes uses a couette device, such as a Fann Model 35 or 50
viscometer or a Chandler 5550 HPHT viscometer, that measures
viscosity as a function of time, temperature, and shear rate. The
viscosity-measuring instrument can be calibrated using standard
viscosity silicone oils or other standard viscosity fluids.
[0121] Due to the geometry of most common viscosity-measuring
devices, however, solid particulate, especially if larger than silt
(larger than 74 micron), would interfere with the measurement on
some types of measuring devices. Therefore, the viscosity of a
fluid containing such solid particulate is usually inferred and
estimated by measuring the viscosity of a test fluid that is
similar to the fracturing fluid without any proppant or gravel that
would otherwise be included. However, as suspended particles (which
can be solid, gel, liquid, or gaseous bubbles) usually affect the
viscosity of a fluid, the actual viscosity of a suspension is
usually somewhat different from that of the continuous phase.
[0122] As used herein, unless otherwise specified or unless the
context otherwise requires, the apparent viscosity of a fluid
(excluding any suspended solid particulate larger than silt) is
measured with a Fann Model 35 type viscometer with an F1 spring, B1
bob, and R1 rotor at a shear rate of 511 l/s and at 77.degree. F.
(25.degree. C.) and a pressure of 1 atmosphere. For reference, the
viscosity of pure water is about 1 cP.
[0123] A substance is considered to be a fluid if it has an
apparent viscosity less than 5,000 cP (independent of any gel
characteristic).
[0124] As used herein, a fluid is considered to be "viscous" if it
has an apparent viscosity of 10 cP or higher. The viscosity of a
viscous fluid is considered to break or be broken if the viscosity
is reduced to 5 cP or lower. In many applications, however, it is
desirable to achieve a complete break of less than 3 cP.
[0125] General Measurement Terms
[0126] Unless otherwise specified or unless the context otherwise
clearly requires, any ratio or percentage means by weight.
[0127] Unless otherwise specified or unless the context otherwise
clearly requires, the phrase "by weight of the water" means the
weight of the water of the continuous phase of the fluid without
the weight of any viscosity-increasing agent, dissolved salt,
suspended particulate, or other materials or additives that may be
present in the water.
[0128] Any doubt regarding whether units are in U.S. or Imperial
units, where there is any difference, U.S. units are intended. For
example, "gal/Mgal" means U.S. gallons per thousand U.S.
gallons.
[0129] Unless otherwise stated, mesh sizes are in U.S. Standard
Mesh.
[0130] The micrometer (.mu.m) may sometimes be referred to herein
as a micron.
General Purposes
[0131] Diutan gels are commonly used in gravel packing operations
at temperatures from 180.degree. F. to 270.degree. F. The purpose
of this invention is to disclose a breaker system that can
successfully reduce the viscosity of a diutan gel at temperatures
below 180.degree. F., and preferably down to a temperature at least
as low as 140.degree. F.
[0132] Diutan provides superior sand settling properties compared
to other water-soluble polymers as viscosity-increasing agents,
which can allow for reduced polymer loadings with potentially lower
frictions to allow for longer completions.
[0133] Diutan is commonly used in a concentration of about 5
lb/Mgal to about 100 lb/Mgal, depending on the desired viscosity
and other properties of a fluid at the design temperature. For
example, about 25 lb/Mgal of diutan in water may be used for a
design temperature of about 140.degree. F. to provide a fluid
viscosity of about 25 cP.
[0134] Depending on the application, field requirements often
demand breaking of a fluid viscosified with diutan in less than 4
days at temperatures from 140.degree. F. to 180.degree. F. The
breaking must not be too soon, however, which would adversely
affect the sand suspension properties of the fluid during the time
required for placing a particulate, such as a gravel for gravel
packing. For such applications, a new and different breaker system
is required. A breaker system for diutan capable of meeting such
field requirements would allow for making a valuable treatment
fluid, which could be used, for example, for gravel carrying fluid
systems. A particularly useful application, for example, would be
open hole gravel packing, where the treatment fluid would be
increase the current maximum length of open hole gravel packing at
such low temperatures. For such an application, the breaking time
should not be less than 2 hours.
Oxidizers Offer Insufficient Breaking of Diutan at Low
Temperature
[0135] While oxidizing agents may be effective to at least
partially break treatment fluids comprising a diutan composition,
the use of oxidizing breakers in combination with diutan may
interfere with a subterranean formation's ability to regain a
desired level of permeability. This may be due in part to residual
treatment fluids or reaction products that remain in the formation
after the treatment fluid is broken. In particular, it is believed
that oxidizing agents may not substantially degrade or otherwise
reduce the presence of diutan-producing bacterial bodies in the
subterranean formation. These bacterial bodies are thought to be at
least partially responsible for creating a physical barrier in the
formation which reduces permeability.
[0136] In addition, oxidizing breakers have not been able to
provide a complete break of a diutan polymer backbone at
temperatures below 200.degree. F. (93.degree. C.). For example,
reduced regained-permeability values have been seen when oxidizing
breakers were used at lower temperatures. A permeability regain of
less than 80% after a treatment with a treatment fluid containing
diutan is considered poor or less than acceptable.
Organic Acids Offer Insufficient Breaking of Diutan at Low
Temperature
[0137] Organic acids are typically used to break diutan polymer
gels.
[0138] For example, U.S. Pat. No. 7,584,791 issued Sep. 8, 2009
discloses a method of using organic acids such as formic and acetic
acids to break diutan fluids at temperatures within the range of
180.degree. F. to 270.degree. F. Breaking the diutan polymer has
been achieved by adjusting the pH of the gravel-pack fluid with
internal organic acid breakers such as formic acid and acetic acid.
Regained permeability values were excellent when fluid comprising
of diutan polymer was broken by adjusting the fluid pH with these
acids to the proper level.
[0139] Acid breakers applicable to diutan from 180.degree. F. to
220.degree. F. typically use formic acid, which causes breaking by
reducing the pH of the system to a level sufficient to degrade the
polymer backbone. At effective concentrations, formic acid provides
a break time of 2 to 3 days in the temperature range of 180.degree.
F. to 220.degree. F. Breaker times shorter than 2 to 3 days at
temperatures above 180.degree. F. can be achieved at using higher
formic acid loadings.
[0140] To provide a break time of less than 4 days at temperatures
below 180.degree. F. would require higher loadings of formic acid.
For example, preliminary break tests at 160.degree. F. with 40
lb/Mgal diutan gels have indicated the requirement of nearly 35 to
40 gal/Mgal formic acid to reduce the viscosity below 5 cP at 511
sec.sup.-1 in 3 to 4 days. Using diutan gels at 140.degree. F.
would require much higher concentrations of formic acid to break
the viscosity of the fluid in a reasonable time.
[0141] Unfortunately, using higher concentrations of formic acid or
other such organic acid would adversely affect the properties of
the well fluid. For example, higher formic acid loadings severely
affect the particulate suspension properties of fluids viscosified
with diutan. In addition, one of the things that can cause the
polymer to salt-out is the low pH of the fluid. Since the breakers
for this system are organic acids, using high amount of these acids
can cause the salting-out issue. At high loadings of formic acid,
the cloud point of the gel system is reduced, which can cause
serious lumping when the breaker is added. As used herein, the
"cloud" point or "salt out" point is the concentration of the
polymer that is insoluble in a specific solution (for example, an
aqueous 7% KCl solution with a specific concentration of acid and
pH) at a specific temperature (for example, the design
temperature), which is indicated by the change of the solution from
clear to cloudy. For these reasons, diutan viscosified fluids with
higher acid loadings are unsuitable for applications that include
suspending particulate, such as gravel packing.
Combination of Oxidizer and Acid Insufficient to Break Diutan at
Low Temperature
[0142] In addition, a combination of oxidizing and acid breakers at
reasonable concentrations is insufficient to break the viscosity of
a fluid viscosified with diutan at low temperatures of less than
180.degree. F. For example, either or both the concentration of the
oxidizer or the acid would be required in high concentrations that
would interfere with the function of the treatment fluid. High
concentrations of oxidizer provide poor formation permeability
regain. High concentrations of acid lower the cloud point of diutan
or clarified diutan.
Low-Temperature Breaker System for Diutan
[0143] Due to the above challenges, there is a need to identify an
alternate breaker system that can successfully reduce or break the
viscosity of diutan fluids at a design temperature below
180.degree. F., and preferably at least as low as 140.degree.
F.
[0144] According to the invention, a breaker system including an
oxidizer, organic acid, and a transition metal activator is useful
for diutan at low temperatures of less than 180.degree. F., and at
temperatures down to at least at low as 140.degree. F. Breaking at
even lower temperatures is believed to be feasible with such a
breaker system. The breaker system is effective down to at least as
low at 140.degree. F. without requiring high loadings of organic
acid that is, without requiring the use of concentrations of the
acid that would cause the salting out of the diutan in the
treatment fluid at the design temperature.
[0145] According to a preferred embodiment, the breaker system
includes t-butyl hydro peroxide ("TBHP"), formic acid, and ferric
chloride.
Methods for Treating a Treatment Zone of a Well
[0146] The present invention relates to methods of treating a
treatment zone of a well with a treatment fluid viscosified with a
diutan or derivative and having a breaker system according to the
invention.
[0147] Accordingly, a method of treating a treatment zone of a well
is provided. The method includes the steps of: [0148] (A) forming a
treatment fluid comprising a continuous aqueous phase and gravel,
wherein the continuous aqueous phase comprises: [0149] (i) water;
[0150] (ii) a viscosity-increasing agent selected from the group
consisting of diutan, clarified diutan, a water-soluble derivative
of diutan, and any combination thereof; [0151] (iii) a
water-soluble oxidizer or source of a water-soluble oxidizer,
wherein the concentration of the water-soluble oxidizer is in the
range of 0.1% to 2% by weight of the water of the continuous phase;
[0152] (iv) a water-soluble organic acid or source of a
water-soluble organic acid, wherein the water-soluble organic acid
has a pKa(1) in the range of 1 to 5 and the concentration of the
water-soluble organic acid is in the range of 0.5% to 5% by weight
of the water of the continuous phase; and [0153] (v) a
water-soluble transition metal compound or source of a
water-soluble transition metal compound, wherein the concentration
of the water-soluble transition metal compound is in the range of
0.001% to 0.25% by weight of the water of the continuous phase; and
[0154] (B) introducing the treatment fluid into the treatment zone
of the well; [0155] wherein the design temperature of the treatment
zone of the well is less than 180.degree. F. (82.2.degree. C.);
[0156] wherein the continuous phase of the treatment fluid has or
develops a viscosity in the range of 10 cP to 75 cP at the design
temperature; and [0157] wherein the concentration of the
water-soluble organic acid is less than the concentration that
would cause the viscosity-increasing agent to salt out from the
continuous aqueous phase at the design temperature.
[0158] More particularly, the present invention provides a very
simple, effective, and relatively safe means of breaking treatment
fluids viscosified with a diutan or derivative at design
temperatures down to at least as low as 140.degree. F.
[0159] A treatment fluid according to the invention is preferably
adapted to have break times in the range of 1 to 5 days at
temperatures in the range of 140.degree. F. to 180.degree. F. More
preferably, the breaker is effective to provide a break time in the
range of 2 to 4 days down to a temperature of 140.degree. F. at
temperatures in the range of 140.degree. F. to 180.degree. F.
[0160] A particularly useful application for this invention is
gravel packing.
[0161] As used herein, a short break time means less than 5 days,
preferably less than 3 days, and more preferably less than 2 days
at a temperature within the temperature range of 140.degree. F. to
180.degree. F. Nevertheless, it is also desirable that the break
time not be too short, that is, preferably at least 1 day, more
preferably at least 2 days. Accordingly, a break time includes
break times in the range of 1 day to 5 days at a temperature within
the temperature range of 140.degree. F. to 180.degree. F.
[0162] While the methods of the present invention may be suitable
for use in a variety of subterranean treatments, they may be
particularly useful in treatments for subterranean formations or
treatment zones having low design temperatures, such as those
between 140.degree. F. and 180.degree. F. One of the many
advantages of the present invention is that it may allow for a
controlled decrease in the viscosity of a viscosified treatment
fluid. In some embodiments, a breaker system of the present
invention may be able to break a treatment fluid comprising a
diutan or derivative at temperatures down to 140.degree. F., while
providing satisfactory particulate suspension for a desired minimum
time, e.g. 4 hours.
[0163] The methods of the present invention may be used in any
subterranean operation involving the introduction of a treatment
fluid into a subterranean formation wherein the viscosity of the
treatment fluid is decreased, including, gravel-packing operations,
frac-packing operations, well bore cleanout operations, and the
like. In certain embodiments of the present invention, the
treatment fluid may be introduced into a portion of a subterranean
formation so as to create a "plug" capable of diverting the flow of
fluids that are introduced to the well bore at some point after the
plug has formed (e.g., other treatment fluids) to other portions of
the formation. In those embodiments, the breaker then may be
allowed to reduce the viscosity of the fluid within the formation's
pores, which may at least partially restore the flow of fluids
through that portion of the subterranean formation.
Continuous Aqueous Phase
[0164] The continuous aqueous phase of the treatment fluid is a
liquid. However, it is contemplated that the treatment fluid can be
foamed or an emulsion. The continuous aqueous phase of the
treatment fluid is preferably adapted to carry a particulate, such
as gravel for gravel packing. In an embodiment, however, the
treatment fluid is not foamed or an emulsion. As used herein, a
foamed fluid has at least 5% by volume of a gas.
[0165] According to the invention, the treatment fluid is a
water-based fluid wherein the continuous aqueous phase of the fluid
is greater than 50% by weight water (excluding the weight of
dissolved any salts).
[0166] The water preferably is present in the treatment fluids
suitable for use in the present invention in an amount at least
sufficient to substantially hydrate the viscosity-increasing agent.
In some embodiments, the aqueous phase, including the dissolved
materials therein, may be present in the treatment fluids in an
amount in the range from about 5% to 100% by volume of the
treatment fluid.
[0167] Preferably, the water for use in the treatment fluid does
not contain anything that would adversely interact with the other
components used in accordance with this invention or with the
subterranean formation.
[0168] The aqueous phase can include freshwater or non-freshwater.
Non-freshwater sources of water can include surface water ranging
from brackish water to seawater, brine, returned water (sometimes
referred to as flowback water) from the delivery of a well fluid
into a well, unused well fluid, and produced water. As used herein,
brine refers to water having at least 40,000 mg/L total dissolved
solids.
[0169] In some embodiments, the aqueous phase of the treatment
fluid may comprise a brine. Examples of suitable brines include
calcium bromide brines, zinc bromide brines, calcium chloride
brines, sodium chloride brines, sodium bromide brines, potassium
bromide brines, potassium chloride brines, sodium nitrate brines,
sodium formate brines, potassium formate brines, cesium formate
brines, magnesium chloride brines, mixtures thereof, and the like.
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 may be added to a water source, e.g., to
provide a brine, and a resulting treatment fluid, having a desired
density. Brines, where used, may be of any weight.
[0170] Salts may optionally be included in the treatment fluids of
the present invention for many purposes, including, for reasons
related to compatibility of the 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 a salt should be
included in a treatment fluid suitable for use in the present
invention. Suitable salts include, but are not limited to, calcium
chloride, sodium chloride, magnesium chloride, potassium chloride,
sodium bromide, potassium bromide, ammonium chloride, sodium
formate, potassium formate, cesium formate, mixtures thereof, and
the like. The amount of salt that should be added should be the
amount necessary for formation compatibility, such as stability of
clay minerals, taking into consideration the crystallization
temperature of the brine, e.g., the temperature at which the salt
precipitates from the brine as the temperature drops.
Viscosity-Increasing Agent Including Water-Soluble Polymer having
Diutan Backbone
[0171] A viscosity-increasing agent suitable for use in the methods
of the present invention is selected from the group consisting of
diutan, one or more clarified diutans, one or more water-soluble
derivatives of diutan, and any combination thereof.
[0172] Despite certain suggestions in the field to the contrary,
diutan and clarified diutan are well known to be not readily
crosslinkable with a transition metal. For example, U.S. Pat. No.
7,621,334 issued Nov. 24, 2009 discloses that suitable viscosities
could be obtained for acidic treatment fluids that comprise gelling
agents that comprise diutant without using crosslinkers.
[0173] Accordingly, transition metals are not expected to be
included in treatment fluids viscosified with diutan or a clarified
diutan. Unless a derivative of diutan has functional groups that
can be crosslinked with a transition metal, diutan derivatives are
not expected to be readily crosslinkable with a transition metal.
In addition, the viscosity should be sufficient for the purpose of
the treatment fluid, but not higher than necessary as this would
make the fluid more difficult to break and more difficult to clean
up from the treatment zone. Using diutan or clarified diutan in
gravel-packing applications, for example, it is not necessary and
not desirable to crosslink the viscosity-increasing agent, where,
for example, a viscosity in the range of 10 cP of up to about 75 cP
is desired. A fluid viscosified with diutan or derivative thereof
is considered not crosslinked unless the viscosity is well above 75
cP.
[0174] Diutan
[0175] Diutan gum (commonly referred to simply as diutan) is a
multi-chain polysaccharide that is sometimes used to increase
viscosity in well fluids. Diutan's thickening, suspending, and
stabilizing properties in aqueous fluids makes it especially useful
as suspension systems in gravel packing.
[0176] In general, diutan is a polysaccharide which may be prepared
by fermentation of a strain of sphingomonas, for example
Sphingomonas sp. ATCC 53159. Diutan may also be referred to as a
polysaccharide designated S-657 or S-8 in some literature. Its
structure has been elucidated as having a repeat unit of a
hexasaccharide with a tetrasaccharide repeat unit in the backbone
that comprises glucose and rhamnose units and a di-rhamnose side
chain. Details of the diutan gum structure may be found in an
article by Diltz et al., "Location of O-acetyl Groups in S-657
Using the Reductive-Cleavage Method," Carbohydrate Research, Vol.
331, pp. 265-270 (2001). Details of preparing diutan gum may be
found in U.S. Pat. No. 5,175,278, filed Sep. 4, 1990 by Jerry A.
Peik, Suzanna M. Steenbergen, and George T. Veeder, which is
incorporated by reference. Diutan is composed principally of
carbohydrate, about 12% protein and about 7% (calculated as
O-acetyl) acyl groups, the carbohydrate portion containing about
19% glucuronic acid, and the neutral sugars rhamnose and glucose in
the approximate molar ratio of 3:2. Other details on diutan can be
found in U.S. Pat. No. 6,620,775, filed Nov. 26, 2001 by Philip E.
Winston and John M. Swazey, hereby incorporated by reference in its
entirety. It is believed to have thickening, suspending, and
stabilizing properties in aqueous or non-aqueous solutions.
[0177] Clarified Diutan
[0178] The term "clarified diutan" as used herein refers to a
diutan that has improved turbidity or filtration properties as
compared to non-clarified diutan. In some embodiments, suitable
clarified diutans may have been treated with enzymes or the like to
remove residual cellular structures, such as cell walls. In some
embodiments, suitable clarified diutans may be produced from
genetically modified or bioengineered strains of bacteria or other
strains of bacteria that allow the clarified diutan to have
improved functional properties such as filterability, turbidity,
etc.
[0179] In some embodiments, the viscosity-increasing agents
suitable for use in the methods of the present invention may
comprise a clarified diutan, wherein the clarified diutan at a 0.1%
concentration in deionized water, in a 1 cm optical cell, has a
transmittance at 350 nanometers ("nm") wavelength of at least about
20%. In some embodiments, the clarified diutan has a transmittance
in the range of about 20% to about 90%. One of ordinary skill in
the art with the benefit of this disclosure will recognize that the
transmittance of any particular treatment fluid may also vary
depending on the addition of certain additives, the composition of
the treatment fluid, the degree of hydration of the diutan, the
temperature, and the pH of the treatment fluid.
[0180] Additional information regarding clarified diutan may be
found in U.S. Patent Publication Nos. 2008/0194427, 2008/0194428,
2008/0194430, each published Aug. 14, 2008, each having for named
inventors Thomas D. Welton, Richard W. Pauls, Lulu Song, Jason E.
Bryant, Sean R. Beach; and Ian D. Robb, and each entitled
"Treatment Fluids Comprising Diutan and Associated Methods," the
entire disclosure of which is incorporated herein by reference.
[0181] Diutan Derivative
[0182] In one embodiment, the diutan or clarified diutan may be
modified by genetic engineering or bacteria selection or the result
of chemical treatment or derivatization of a diutan. An example of
such a modification would be where a portion of the diutan is
oxidized or hydrolyzed. Suitable clarified diutan may also be
present in a form that will only partially hydrate or will not
hydrate at ambient temperature. This form of clarified diutan may
be chemically modified, chemically coated, genetically modified, or
produced from a new strain of bacteria.
[0183] Sources of Diutan
[0184] Examples of suitable sources of a diutan may include those
disclosed in U.S. Pat. No. 5,175,278 and U.S. Patent Publication
Nos. 2006/0121578, 2006/0199201, 2006/0166836, 2006/0166837, and
2006/0178276, which are herein incorporated by reference. Diutan
can be obtained from CP Kelco US Inc. (Houston), the commercial
name being Geovis.
[0185] Advantages of Diutan, Clarified Diutan, or Derivatized
Diutan
[0186] A fluid viscosified with a diutan or derivatized diutan can
enable a substantial amount of design flexibility for a number of
applications that would benefit using a shear-thinning, low-damage
fluid system including, for example, gravel packing, fluid loss
control, and friction pressure reduction.
[0187] A fluid viscosified with a diutan or derivatized diutan can
enable a simple mixing procedure and rapid viscosity development in
a number of water-based fluids including for example, fresh water,
potassium or sodium chloride brines, and sodium bromide brines. The
polymer can be rapidly dispersed in an aqueous phase without going
through a complex mixing protocol or an extended hydration period.
Its ease of mixing and rapid hydration apply to seawater and
mono-valent brines used in completion operations.
[0188] Diutan viscosified fluid can provide excellent particulate
suspension under static conditions at temperatures up to
270.degree. F. (132.2.degree. C.). It is a shear thinning fluid
that has relatively low viscosity at high shear rates and high
viscosity at low shear rates, which is useful in many types of
treatment applications.
[0189] Because such fluids have high viscosity under low shear
conditions, it can be useful to suspend particulates similar to a
fluid viscosified with a cross-linked polymer. In addition, the
high viscosities under low shear attained with these polymer
loadings can be used to help control fluid losses during workover
and completion operations with reduced damage to the formation.
[0190] At lower polymer concentrations, a fluid with diutan or a
derivative can produce a "slick water" or "slick brine" consistency
to help reduce pumping friction pressures.
[0191] Form and Concentration
[0192] The viscosity-increasing agent can be provided in any form
that is suitable for the particular treatment fluid or application
of the present invention. In certain embodiments, the
viscosity-increasing agent may be provided as a liquid, gel,
suspension, or solid additive that is admixed or incorporated into
a treatment fluid used in conjunction with the present
invention.
[0193] The viscosity-increasing agent should be present in a
treatment fluid in a form and in an amount at least sufficient to
impart the desired viscosity to a treatment fluid. If used in a
gravel packing fluid, the treatment fluid contains the
viscosity-increasing agent in an amount sufficient to provide
suspension of particulates such as sand. Preferably, the
concentration of the viscosity-increasing agent is at least
sufficient such that the continuous phase of the treatment fluid is
greater than 10 cP at the design temperature. For example, the
amount of diutan in the gravel packing fluid can range from about
0.01% to about 2.0% by weight and preferably between 0.1% to about
1.0%. Other diutan concentrations are also contemplated for various
subterranean formation applications. For example, in some
embodiments, the amount of viscosity-increasing agent used in the
treatment fluids suitable for use in the present invention may vary
from about 5 pounds per 1,000 gallons of treatment fluid
("lbs/Mgal") to about 100 lbs/Mgal. In gravel packing embodiments,
the amount of viscosity-increasing agent included in the treatment
fluids suitable for use in the present invention may vary from
about 20 lbs/Mgal to about 80 lbs/Mgal. In embodiments in which the
amount of diutan approaches 100 lbs/Mgal, the diutan may act to
increase the viscosity of the treatment fluid so that the treatment
fluid may be used as a diverting fluid or fluid loss pill to seal a
formation.
[0194] Optional Additional Viscosity-Increasing Agent
[0195] Other, additional viscosity-increasing agents may or may not
be included in the treatment fluid, provided they do not adversely
interact with the breaker system. In some embodiments, diutan may
be used in combination with other viscosity-increasing agents so
that the diutan only imparts its viscosity once the treatment fluid
has entered the formation to provide viscosity at elevated
temperatures where other viscosity-increasing agents may no longer
provide adequate viscosity. Suitable additional
viscosity-increasing agents may include polysaccharides and
galactomannan gums. Depending on the application, one
viscosity-increasing agent 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 an additional viscosity-increasing
agent should be included for a particular application based on, for
example, the desired viscosity of the treatment fluid and the
design temperature.
[0196] In an embodiment, the continuous aqueous phase of the
treatment fluid excludes a viscosity-increasing agent that is not
selected from the group consisting of diutan, a clarified diutan,
or a water-soluble derivative of diutan. In other words, the
aqueous phase excludes a viscosity-increasing agent that does not
have a diutan polymer backbone.
[0197] Viscosity-Increasing Agents not Crosslinkable with
Transition Metal
[0198] In another embodiment, the continuous aqueous phase of the
treatment fluid excludes any viscosity-increasing agent that can be
readily crosslinked with a transition metal in the treatment fluid
and at the design temperature.
Breaker System Including Metal Activator
[0199] The breakers suitable for use in the present invention
generally include: (a) a water-soluble oxidizer, (b) a
water-soluble organic acid having a pKa(1) in the range of 1 to 5;
and (c) a water-soluble transition metal compound.
[0200] Preferably, the water-soluble oxidizer is in the range of
about 0.1% to about 2% by weight of the water of the continuous
phase. More preferably, the water-soluble oxidizer is in the range
of about 0.5% to about 1% by weight of the water of the continuous
phase.
[0201] Preferably, the water-soluble organic acid is in the range
of about 0.5% to about 5% by weight of the water of the continuous
phase. More preferably, the water-soluble oxidizer is in the range
of about 1% to about 4% by weight of the water of the continuous
phase. These are less the concentrations that would be useful for
acidizing treatments.
[0202] Preferably, the transition metal compound or source of a
water-soluble transition metal compound is in the range of about
0.001% to about 0.25% by weight of the water of the continuous
phase. More preferably, the transition metal compound or source of
a water-soluble transition metal compound is in the range of about
0.002% to about 0.1% by weight of the water of the continuous
phase. These concentrations are less than the concentrations that
would be useful for crosslinking a polymeric viscosity-increasing
agent such as diutan.
[0203] Examples of oxidizers include chlorites, hypochlorites,
chlorates, perchlorates, and other analogous halogen compounds,
perborates, and peroxides. The oxidizer is preferably an peroxide.
According to a most preferred embodiment, the oxidizer is t-butyl
hydroperoxide ("TBHP", also known as 2-methylpropane-2-peroxol),
which is commercially available in aqueous solution.
[0204] Preferably, the organic acid is non-halogenated based on
environmental concerns. Examples of suitable organic acids include
formic acid (pKa 3.77), and acetic acid (pKa 4.79). Most
preferably, the organic acid is formic acid, which is commercially
available as a concentrated liquid.
[0205] The transition metal activator is preferably selected from
the group consisting of manganese, vanadium, cobalt, and iron
having an oxidation state in the range of at least 2, and
preferably in the range of 2 to 4. More preferably, the transition
metal activator is selected from the group consisting of manganese
+2 or +3; vanadium +3 or +4; cobalt +2; and iron +3. Most
preferably, the transition metal compound is a ferric compound.
Preferably, the transition metal is not chelated. For example,
according to the presently most preferred embodiment, the
transition metal compound is a ferric chloride.
pH and pH Adjuster
[0206] The pH of the continuous aqueous phase of the treatment
fluid is less than 7.
[0207] In certain embodiments, the treatment fluids of the present
invention can comprise a pH-adjuster other than the
viscosity-increasing agent, the oxidizer, the organic acid, and the
transition metal compound. Preferably, the pH adjuster does not
have undesirable properties, as discussed above. In addition, it is
preferred that the pH adjuster avoid strong acids such as
hydrochloric acid. Strong acids are highly corrosive to metals
downhole.
[0208] Preferably, the organic acid and any other pH-adjuster are
present in an amount sufficient to maintain or adjust the pH of the
fluid to a pH of less than 5 at the time of introducing. More
preferably, the organic acid and any other pH-adjuster are present
in an amount sufficient to maintain or adjust the pH of the fluid
to a pH in the range of about 3 to about 5.
Particulate in Treatment Fluid
[0209] In an embodiment, the treatment fluid can include a
particulate. A particulate, such as gravel, can be used in the
present invention. Examples include sand, gravel, bauxite, ceramic
materials, glass materials, polymer materials, wood, plant and
vegetable matter, nut hulls, walnut hulls, cottonseed hulls, cured
cement, fly ash, fibrous materials, composite particulates, hollow
spheres or porous particulate. It should be understood that the
term "particulate," as used in this disclosure, includes all known
shapes of materials including substantially spherical materials,
oblong, ellipsoid, rod-like, polygonal materials (such as cubic
materials), mixtures thereof, and the like.
[0210] In some embodiments in which the treatment fluid comprises
particulates, the treatment fluid may be capable of suspending at
least a portion of the particulates contained therein. Treatment
fluids comprising particulates may be used in any method known in
the art that requires the placement of particulates in a
subterranean formation. For example, treatment fluids of the
present invention that comprise particulates may be used, inter
alia, to form a gravel pack in or adjacent to a portion of the
subterranean formation.
Other Well Fluid Additives
[0211] In certain embodiments, the treatment fluids suitable for
use in the methods of the present invention also can optionally
comprise other commonly used well fluid additives, such as those
selected from the group consisting of surfactants, bactericides,
fluid loss control additives, stabilizers, chelants, scale
inhibitors, corrosion inhibitors, hydrate inhibitors, clay
stabilizers, salt substitutes (such as trimethyl ammonium
chloride), relative permeability modifiers (such as HPT-1.TM.
commercially available from Halliburton Energy Services, Duncan,
Okla.), sulfide scavengers, fibers, nanoparticles, and any
combinations thereof.
[0212] It should be understood, however, that in an embodiment the
treatment fluid does not include hydraulic cement and the treatment
fluid is not a hydraulic cement composition.
Forming a Treatment Fluid
[0213] The method includes a step of forming a treatment fluid,
wherein the treatment fluid includes: a continuous aqueous phase
and gravel. The continuous aqueous phase includes: [0214] (i)
water; [0215] (ii) a viscosity-increasing agent selected from the
group consisting of diutan, clarified diutan, a water-soluble
derivative of diutan, and any combination thereof; [0216] (iii) a
water-soluble oxidizer or source of a water-soluble oxidizer,
wherein the concentration of the water-soluble oxidizer is in the
range of 0.1% to 2% by weight of the water of the continuous phase;
[0217] (iv) a water-soluble organic acid or source of a
water-soluble organic acid, wherein the water-soluble organic acid
has a pKa(1) in the range of 1 to 5 and the concentration of the
water-soluble organic acid is in the range of 0.5% to 5% by weight
of the water of the continuous phase; and [0218] (v) a
water-soluble transition metal compound or source of a
water-soluble transition metal compound, wherein the concentration
of the water-soluble transition metal compound is in the range of
0.001% to 0.25% by weight of the water of the continuous phase.
[0219] The treatment fluid may be prepared at the job site,
prepared at a plant or facility prior to use, or certain components
of the treatment fluid (e.g., the aqueous phase and the
viscosity-increasing agent) may be pre-mixed prior to use and then
transported to the job site. Certain components of the treatment
fluid may be provided as a "dry mix" to be combined with liquid or
other components prior to or during introducing the treatment fluid
into the subterranean formation.
[0220] In certain embodiments, the preparation of these treatment
fluids of the present invention may be done at the job site in a
method characterized as being performed "on the fly." The term
"on-the-fly" is used herein to include methods of combining two or
more components wherein a flowing stream of one element is
continuously introduced into flowing stream of another component so
that the streams are combined and mixed while continuing to flow as
a single stream as part of the on-going treatment. Such mixing can
also be described as "real-time" mixing. In some embodiments of the
present invention, the diutan viscosity-increasing agent may be
mixed into the base fluid on the fly.
Introducing the Treatment Fluid into the Well
[0221] Often the step of delivering a well fluid into a well is
within a relatively short period after forming the well fluid,
e.g., less within 30 minutes to one hour. More preferably, the step
of delivering the well fluid is immediately after the step of
forming the well fluid, which is "on the fly." It should be
understood that the step of delivering the treatment fluid into the
wellbore can advantageously include the use of one or more fluid
pumps.
[0222] The treatment fluid may be provided and introduced into the
subterranean formation in certain embodiments of the present
invention by any means known in the art. In certain embodiments,
the treatment fluid may be introduced into the subterranean
formation by pumping the treatment fluid into a well bore that
penetrates a portion of the subterranean formation.
[0223] In an embodiment, the step of introducing comprises
introducing under conditions for gravel packing the portion of the
wellbore.
[0224] In an embodiment, the step of introducing is below the
fracture pressure of the portion of the well.
Flow Back Conditions
[0225] In an embodiment, the method includes the step of flowing
back from the treatment zone. Preferably, the step of flowing back
is within 5 days of the step of introducing. In another embodiment,
the step of flowing back is in the range of 2 to 4 days of the step
of introducing.
After Well Treatment, Producing Hydrocarbon from Subterranean
Formation
[0226] Preferably, the method further includes, after the step of
introducing, and preferably after a step of flowing back from the
treatment zone, a step of producing hydrocarbon from the
subterranean formation. This is a desirable objective.
EXAMPLES
[0227] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the entire scope of the invention.
[0228] Break Tests
[0229] The following break tests illustrate the breaking of a
diutan using a breaker system according to the invention at
temperatures down to 140.degree. F. Preliminary testing has been
conducted to confirm the breaking of diutan to very low viscosities
5 cP (at 511 sec.sup.-1 shear on a Fann 35 viscometer) in 3 days at
140.degree. F.
[0230] A typical treatment fluid can be prepared by taking 980 ml
of the appropriate brine in a 1 liter Waring.RTM. blender jar. In
this example, the brine contained KCl at a concentration of 7% w/v.
BE-3S.TM. and BE-6.TM. as bactericides were added to the above
brine under continuous stirring at a concentration of 0.15 lb/Mgal
respectively. 12.0 lb/Mgal of iron chelating agent was then added
and allowed to dissolve completely. This was followed by addition
of 30 lb/Mgal of diutan powder. Contents were allowed to mix for 10
minutes maintaining about a 1 inch vortex without entrapping any
air during the mixing interval. The contents were allowed to remain
static for about an hour to allow complete hydration of the gelling
agent. Once the gel was hydrated, 20 gal/Mgal of NEA-96M.TM. as
non-emulsifier surfactant was added to complete the gel preparation
procedure.
[0231] A typical break test at 140.degree. F. was carried out using
200 ml of the above hydrated diutan gel. The gel was placed under
stifling in a 300 ml Waring.RTM. blender jar. In the present
example, 5.0 gal/Mgal of TBHP solution (68 to 72%) as oxidizer was
added to the gel under stifling followed by addition of 20 gal/Mgal
of 94-96% formic acid. This was followed by addition of 0.75
gal/Mgal ferric chloride solution (38-40%). Once all these were
properly mixed, the break test gel mixture was taken in a glass
bottle and placed in a pre-heated constant-temperature water bath
maintained at a test temperature of 140.degree. F. At the desired
time interval, the test bottle was taken out of the water bath and
the apparent viscosity of the break test gel mixture was measured
on a Fann 35 viscometer at 300 RPM (corresponds to 511 sec.sup.-1
shear rate). In the present example, after 3 days (72 hours), an
apparent viscosity of 2.0 cP was observed. The result of varying
the amounts of individual breaker components of the breaker system
(TBHP solution, formic acid and ferric chloride solution) at
140.degree. F. on the apparent viscosity of 30 lb/Mgal diutan gel
at various time intervals is depicted in FIG. 1.
[0232] Breaking tests are shown in Table 1 for a 30 lb/Mgal diutan
hydrated in water with 7% KCl, which provides a fluid having an
initial viscosity of about 25 cP.
TABLE-US-00001 TABLE 1 Breaker Composition used at 140.degree. F.
Ferric Diutan TBHP Formic Chloride Apparent Viscosity (cP) Test
Loading Solution Acid Solution on Fann 35 @ 511 sec.sup.-1
Composition (lb/Mgal) (68-72%) (94-96%) (38-40%) Day 1 Day 2 Day 3
1 30 5.0 gpt 20 gpt 0.75 gpt 18 7 2 2 30 5.0 gpt -- 0.75 gpt 26 26
26 3 30 -- 20 gpt 0.75 gpt 26 26 26 4 30 5.0 gpt 20 gpt -- 26 26 26
5 30 -- 50 gpt -- 25 25 25 6 30 5.0 gpt -- -- 25 25 25
[0233] From Table 1, it can be observed that only composition 1 can
give reduced viscosity at 140.degree. F. that is in presence of
oxidizer (TBHP), organic acid (formic acid) and an activator
(Ferric Chloride). Absence of any one of the component from
composition 1 will not achieve desire breaking.
[0234] The chart of FIG. 1 shows the effect of varying the amounts
of individual breaker components of the breaker system at
140.degree. F. on the apparent viscosity of 30 lb/Mgal diutan
loading at various time intervals. All these test fluids included:
(a) 1,2,3-propanetricarboxylic acid, 2-hydroxy-, trisodium salt,
dihydrate 100%, in solid form, as an iron chelating agent; (b)
2,2-dibromo-3-nitrilopropionamide 97.5%, in solid form, as a
bactericide; (c) 2-bromo-2-nitro-1,3-propanediol, 95-100%, in solid
form, as bactericide; and (d) a surfactant "NEA-96M", a general
surfactant, which is commercially available from Halliburton Energy
Services, Inc. in Duncan, Okla. The chart of FIG. 1 shows that
desired break times can be achieved by optimizing the
concentrations of the components of the breaker system, which
included TBHP, formic acid, and ferric chloride solution.
[0235] In addition, the breaker system for such a diutan loading
can achieve a very low viscosity of less than 5 cP within a short
time of less than 3 days at 140.degree. F. The added advantage of
this breaker system is the use of concentrations of the breaker
system (and any one of its components) at less than the
concentration that would contribute to salting out of the of the
diutan to achieve short break times at temperatures between
140.degree. F. and 180.degree. F., making it practical for field
applications. At temperatures higher than 140.degree. F., break
times shorter than 3 days are likely to be achieved, if
desired.
[0236] Both the polymer loading and the breaker component
concentrations can affect break time, of course.
[0237] Regained Permeability Test
[0238] Regained permeability measurement was carried out using a
cylindrical Aloxite core (400 mD permeability to air) with
dimension of 1 inch in diameter and 2 inch in length. The core with
one end considered as the injection end and the other end as the
production end was placed inside Hassler sleeve assembly. The
entire Hassler sleeve assembly was placed inside an air oven
maintained at the test temperature of 140.degree. F. An overburden
pressure of 1,100 psi was applied over the Hassler sleeve assembly
to ensure the flow of test fluids through the core and avoid the
test fluids from bypassing the core and flowing through the
core-sleeve annulus. The initial and final permeability measurement
was carried out at the test temperature of 140.degree. F. by
flowing API brine in the production direction before and after the
treatment stage. The treatment stage was run by flowing the test
fluid recipe through the core in the injection direction. The
treatment stage comprised of flowing a total of 10 pore volumes of
the test fluid through the aloxite core. The test fluid recipe
comprised of 30 lb/Mgal diutan gel mixed with a breaker system made
up of 5.0 gal/Mgal of TBHP solution (68 to 72%) as oxidizer, 20
gal/Mgal of 94 to 96% Formic acid and 3.0 gal/Mgal Ferric chloride
solution (38 to 40%). As depicted in FIG. 2, a regained
permeability value of 82.5% was achieved.
CONCLUSION
[0239] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein.
[0240] The particular embodiments disclosed are illustrative only,
as the present invention may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. The various steps according to
the disclosed elements or steps can be combined advantageously or
practiced together in various combinations to increase the
efficiency and benefits that can be obtained from the invention.
Such variations and combinations are considered within the scope
and spirit of the present invention.
[0241] The invention illustratively disclosed herein suitably may
be practiced in the absence of any element or step that is not
specifically disclosed or claimed.
[0242] Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims.
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