U.S. patent application number 11/581539 was filed with the patent office on 2007-04-19 for method of using viscoelastic vesicular fluids to enhance productivity of formations.
This patent application is currently assigned to BJ Services Company. Invention is credited to David Alleman, Qi Qu.
Application Number | 20070087940 11/581539 |
Document ID | / |
Family ID | 32655600 |
Filed Date | 2007-04-19 |
United States Patent
Application |
20070087940 |
Kind Code |
A1 |
Qu; Qi ; et al. |
April 19, 2007 |
Method of using viscoelastic vesicular fluids to enhance
productivity of formations
Abstract
A process for enhancing the productivity of a formation consists
of introducing into the formation a viscoelastic fluid which
contains at least one surfactant, at least one quaternary amine
polyelectrolyte, water, and a non-aqueous solvent. The surfactant
forms aggregation structures or vesicles. The fluid, which
significantly enhances fluid viscosity and thermal stability, is
particularly effective as a diverting fluid to divert an acid
treatment package from a high permeability or undamaged portion of
a formation to a low permeability or damaged portion of a formation
as well as a fracturing fluid. In addition, the fluid is useful for
sand control completion.
Inventors: |
Qu; Qi; (Spring, TX)
; Alleman; David; (Houston, TX) |
Correspondence
Address: |
JONES & SMITH, LLP
THE RIVIANA BUILDING
2777 ALLEN PARKWAY, SUITE 800
HOUSTON
TX
77019-2141
US
|
Assignee: |
BJ Services Company
|
Family ID: |
32655600 |
Appl. No.: |
11/581539 |
Filed: |
October 16, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10846994 |
May 14, 2004 |
7144844 |
|
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11581539 |
Oct 16, 2006 |
|
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10356210 |
Jan 31, 2003 |
7115546 |
|
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10846994 |
May 14, 2004 |
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Current U.S.
Class: |
507/112 ;
507/214 |
Current CPC
Class: |
Y10S 507/922 20130101;
C09K 2208/30 20130101; C09K 8/601 20130101; C09K 8/76 20130101;
C09K 2208/26 20130101; C09K 8/74 20130101; C09K 8/602 20130101 |
Class at
Publication: |
507/112 ;
507/214 |
International
Class: |
C09K 8/00 20060101
C09K008/00 |
Claims
1. A method of fracturing a hydrocarbon-bearing formation which
comprises introducing to the formation a viscoelastic vesicular
fracturing fluid comprising (a) at least one surfactant; (b) at
least one quaternary amine polyelectrolyte; (c) water; and (d) a
non-aqueous solvent.
2. The method of claim 1, wherein the polyelectrolyte is a
quaternary amine of a cellulose ether, aminoalkyl cellulose,
aminocarbamoyl cellulose, hydroxyalkylcellulose or betainized
cellulose aminoamides.
3. The method of claim 1, wherein the polyelectrolyte is a
cellulose ether represented by the overall structural formula:
##STR5## wherein: R.sub.cell is the residue of an anhydroglucose
repeat unit; t is 0 or 1; X is oxygen; z is from 50 to about
20,000; and each R.sub.1, R.sub.2 and R.sub.3 is individually
represented by the substituent structural formula: ##STR6##
wherein: A.sup.- is an anion; a is an integer of from 1 to about 3;
m is an integer of from 0 to about 6; n is an integer greater than
or equal to 0, provided that the level of cationic substitution,
CS, defined by the average moles of quaternary nitrogen atoms per
mole anhydroglucose repeat unit is greater than 0; p is an integer
of from 0 to about 6; q is 0 or 1; each R.sub.5 and R.sub.7 is
individually ethylene, a propylene or a hydroxypropylene; R.sub.6
is a di- or trivalent, cyclic, branched or straight chain,
saturated or unsaturated hydrocarbon having from 2 to about 6
carbon atoms, provided there are at least 2 carbon atoms between
the nitrogen atom and any oxygen atom; R.sub.8 is hydrogen,
hydroxyl, R.sub.h, alkyl, carboxyl or alkali metal or amine
carboxylate, or other terminal group provided that when q is 0 then
R.sub.8 is hydrogen or alkyl; each R.sub.9, R.sub.10 and R.sub.11
is individually R.sub.h, alkyl, aryl, aralkyl, alkaryl, cycloalkyl,
alkoxyaryl or alkoxyalkyl, having at least two carbon atoms
separating the oxygen atom in the alkoxyaryl or alkoxyalkyl group
from the nitrogen atom or together with R.sub.6 forms a
heterocyclic ring; R.sub.h is a hydrophobic group containing an
alkyl group having at least 8 carbon atoms; v is equal to the
valence of A; y is 0 or 1, provided that when y is 0 then p and q
are 0 and R.sub.8 is hydrogen or other terminal group.
4. The method of claim 3, wherein the cellulose ether is
polyquaternium-4.
5. The method of claim 1, wherein the water is fresh water or
seawater.
6. The method of claim 1, wherein the pH of the viscoelastic fluid
is between from about 9.0 to about 11.0.
7. The method of claim 1, wherein the at least one surfactant is an
anionic surfactant or a mixture of a cationic and an ionic
surfactant.
8. (canceled.)
9. (canceled.)
10. (canceled.)
11. (canceled.)
12. The method of claim 1, wherein the fluid further comprises an
internal breaker.
13. The method of claim 12, wherein the internal breaker comprises
at least one oxidative breaker and/or at least one acid forming
agent.
14. The method of claim 13, wherein the oxidative breaker is at
least one member selected from a persulfate, peroxidizer, sodium
perborate, sodium bromate, sodium perforate, potassium iodate,
potassium periodate, sodium chlorite, sodium hypochlorite, lithium
hypochlorite or calcium hypochlorite.
15. The method of claim 13, wherein the at least one acid forming
agent is initially inert but slowly hydrolyzes in the fracturing
fluid to produce a Bronsted acid, thereby gradually lowering the pH
of the fluid to activate the oxidative breaker.
16. The method of claim 15, wherein the acid forming agent is an
organic anhydride, acyl halide, sulfonyl halide, benzylic halide or
a low molecular weight ester.
17. The method of claim 16, wherein the low molecular weight ester
is ethyl acetate, 2-ethoxyethylacetate, ethylacetoacetate,
triethylcitrate, methylbenzoate or dimethylphthalate.
18. The method of claim 17, wherein the low molecular weight ester
is trimethyl citrate.
19. The method of claim 14, wherein the oxidative breaker is
ammonium persulfate.
20. The method of claim 18, wherein the oxidative breaker is
ammonium persulfate.
21. The method of claim 1, wherein the non-aqueous solvent
comprises a linear, branched, or cyclic alcohol.
22. A method of fracturing a subterranean formation comprising: (a)
providing an aqueous-based hydraulic fracturing fluid comprising
vesicles; and (b) pumping the fluid through a wellbore and into a
formation at a pressure sufficient to fracture the formation; and
further wherein the fracturing fluid comprises: (1) at least one
surfactant; (2) at least one quaternary amine polyelectrolyte; (3)
water; and (4) a non-aqueous solvent.
23. The method of claim 22, wherein the polyelectrolyte is a
derivative of carboxymethyl cellulose wherein at least one of the
carboxymethyl groups are replaced by polyquaternary ammonium
groups.
24. The method of claim 22, wherein the vesicles have a diameter of
between about 100 .ANG. and about 50 microns.
25. The method of claim 22, wherein the vesicles are unilamellar,
multilamellar, or both.
26. The method of claim 22, wherein the polyelectrolyte is a
cellulose ether represented by the overall structural formula:
##STR7## wherein: R.sub.cell is the residue of an anhydroglucose
repeat unit; t is 0 or 1; X is oxygen; z is from 50 to about
20,000; and each R.sub.1, R.sub.2 and R.sub.3 is individually
represented by the substituent structural formula: ##STR8##
wherein: A.sup.- is an anion; a is an integer of from 1 to about 3;
m is an integer of from 0 to about 6; n is an integer greater than
or equal to 0, provided that the level of cationic substitution,
CS, defined by the average moles of quaternary nitrogen atoms per
mole anhydroglucose repeat unit is greater than 0; p is an integer
of from 0 to about 6; q is 0 or 1; each R.sub.5 and R.sub.7 is
individually ethylene, a propylene or a hydroxypropylene; R.sub.6
is a di- or trivalent, cyclic, branched or straight chain,
saturated or unsaturated hydrocarbon having from 2 to about 6
carbon atoms, provided there are at least 2 carbon atoms between
the nitrogen atom and any oxygen atom; R.sub.8 is hydrogen,
hydroxyl, R.sub.h, alkyl, carboxyl or alkali metal or amine
carboxylate, or other terminal group provided that when q is 0 then
R.sub.8 is hydrogen or alkyl; each R.sub.9, R.sub.10 and R.sub.11
is individually R.sub.h, alkyl, aryl, aralkyl, alkaryl, cycloalkyl,
alkoxyaryl or alkoxyalkyl, having at least two carbon atoms
separating the oxygen atom in the alkoxyaryl or alkoxyalkyl group
from the nitrogen atom or together with R.sub.6 forms a
heterocyclic ring; R.sub.h is a hydrophobic group containing an
alkyl group having at least 8 carbon atoms; v is equal to the
valence of A; y is 0 or 1, provided that when y is 0 then p and q
are 0 and R.sub.8 is hydrogen or other terminal group.
27. The method of claim 26, wherein the cellulose ether is
polyquatemium-4.
Description
[0001] This application is a continuation of U.S. application Ser.
No. 10/846,994 filed May 14, 2004, which is a continuation-in-part
application of U.S. application Ser. No. 10/356,210 filed on Jan.
31, 2003.
FIELD OF THE INVENTION
[0002] This invention relates to viscoelastic surfactant based
fluids which contain a quaternary amine polyelectrolyte and a
method of using such fluids to enhance the Productivity of a
hydrocarbon-bearing formation. In a preferred embodiment, the
invention relates to the use of well treatment viscoelastic fluids,
such as diverter fluids in matrix acidizing, fracturing fluids and
fluids for sand control completion.
BACKGROUND OF THE INVENTION
[0003] Matrix acidizing, the process of injecting a formation
stimulation fluid such as acid or other acid-forming materials that
may react with minerals in the formation to increase the formation
permeability, is a common method used to stimulate and enhance the
Production of hydrocarbons from a hydrocarbon producing formation
and remove formation damage caused by drilling mud invasion and
clay migration.
[0004] For most matrix acid treatments, acid is injected into the
reservoir below or above fracturing rates and pressures. To obtain
the maximum benefits of matrix acidizing, it is often desirable to
treat the entire productive interval of the formation with the
stimulation fluid. As the stimulation fluid is pumped, it will
preferentially enter the interval of least resistance (lowest
stress) or highest permeability and will react with the formation
material and open additional flow paths. As a result, the high
permeability interval or non-damaged zone receives most or all of
the stimulation while the desired low permeability or damaged zones
do not receive the desired stimulation. In most cases, the low
permeability or damaged zone is the portion of the reservoir that
will benefit the least from stimulation. Without proper diversion,
the acid, by flowing to the higher permeability zone, leaves the
low permeability zone untreated.
[0005] Acid treatment is further used to remove formation damage.
Standard sand control treatments often use high rate water packs.
Before or after placement of gravel with a completion fluid,
low-density brine or a linear gel, a large acid treatment is
typically pumped to remove the near wellbore formation damage or
skins encountered in perforation wells. Thus, a clay acid package
is often pumped into the formation before the gravel pack to
stabilize the residual clay. The results of these treatments are
often directly related to the ability of the acid to remove the
near-wellbore damage and connect the wellbore to the formation. In
addition to determining the most effective combination of acid
blends and volumes for each particular reservoir, treatment design
and planning is often performed in order to ensure that the acid is
placed across the entire interval. Such staging of acid treatment
across the entire interval further serves to treat the damaged
portion of the sands.
[0006] The successful acid placement in matrix treatments of open
hole horizontal wells is even more difficult due to the length of
the zone treated and potential variation of the formation
properties. A successful diversion technique is critical to place
the acid to the location where damage exists. For an ideal acid
treatment on a long heterogeneous reservoir, one would prefer the
majority of the acid to be injected into damaged or low
permeability intervals; the minimum amount of acid being spent in
the clean or undamaged reservoir. However acid, a nonviscous fluid,
enters into the region with the lowest stress contrast which
unfortunately is typical of the cleanest interval or the partially
depleted sand. In order to re-direct the stimulation fluids from
the non-damaged intervals into the damaged intervals, a pressure
differential across the high permeability or non-damaged intervals
is preferably created. This pressure differential typically forces
the stimulation fluid into new portions of the reservoir that
otherwise would not receive the stimulation fluid. Until a
sufficient pressure differential is built up in this region, the
fluid continues to be injected into the high permeability zones of
the interval.
[0007] In light of such difficulties, operators and service
companies typically attempt to stagger the introduction of acid
fluid into damaged intervals. Such methodology more effectively
treats all of the requisite intervals. In conjunction with the acid
staging of the acid volumes, diverter stages are often pumped to
temporarily plug the zones that are taking the acid. Rate increases
during the treatment to increase injection pressure and cause
diversions also are often attempted. Depending on the formation
condition, various diverting techniques, such as particulate
diverting agents, or viscous acids, have been used both
successfully and unsuccessfully in gravel pack and stimulation
treatments for numerous years. With many options of chemical
diverting or bridging agents available, the type of product used
varies from application to application and in some cases may even
cause formation damage by the chemical residues. Previous works
also established the model and practice to control the pumping rate
to achieve the desired diversion.
[0008] The overall success or failure of many acid treatments is
often judged by the ability to inject or direct the acid into the
damaged or lower permeability zone. Without good diversion, the
results of the acid treatment often lead to either incomplete
damage removal and/or requirements for uneconomical volumes of
treatment fluids. A well developed diverting agent, without
formation damage after the treatment, is critical to the success of
any matrix acid stimulation treatment and successful sand control
completion.
[0009] Chemical diverting agents attempt to temporarily block the
high permeability interval and divert the stimulation fluids into
the desired low permeability or damaged intervals. It is desirable
for these viscous gels to be stable at the bottomhole temperature
and also to be removable from the formation rapidly after the
treatment in order to eliminate any potential damage to the high
permeability intervals. One chemical diverting fluid is a gelled
hydroxyethylcellulose (HEC) pill wherein the viscosity of the pill
influences the injection pressure of the interval it enters. As the
pill enters the formation, the viscosity of the pill restricts the
injection of other fluids into this area. As the injection pressure
increases within this portion of the interval, other sections of
the interval break down and begin accepting fluid. This technique
is severely limited if the temperature of the gelled HEC exceeds
200.degree. F. Above this temperature, the base viscosity and life
of the pill is greatly decreased. Another problem seen with gelled
HEC is that the blocked zone may be damaged from the polymeric
residue left inside the porous media once the acid treatment is
completed.
[0010] Foams may also be used as a diverting method for acid
stimulation. Foams typically are generated through a blend of
surfactants and/or a polymer. One of the popular diverting
techniques in gravel packing and stimulation is the use of a foamed
KCl or NH.sub.4Cl or a gelled HEC pill. When a fluid with high
viscosity enters into the high perm zone which restricts the
injection of other fluids into the same zone, the injection
pressure begins to increase. As the overall injection pressure
increases and overcomes the pressure threshold, the relatively low
perm sections of the interval begin accepting the injected fluid.
This technique is severely limited by temperature due to the
instability of most foamed or gelled pills above 200.degree. F.
Above this temperature the base viscosity of the pill is greatly
decreased and the life of the pill affected.
[0011] Another problem associated with foamed or gelled diverters
is the lack of effectiveness in extremely high permeability
reservoirs (>500 mD). Foamed or gelled HEC pills have little
effect in high permeability reservoirs due to the ability of the
formation to allow for "leak-off" of such fluids. Properly sized
particles such as silica flour, calcium carbonate, or organic
resins, with the ability to effectively pass through the gravel or
perforations but plate or "bridge off" on the formation face, have
been introduced in these environments. Even combinations of HEC
diversion agents, nitrogen, and oil-soluble resins have been field
tested. The main problems associated with the solid particles may
be the improper sizing causing deep invasion problems that may not
readily "clean-up" and cause further damage.
[0012] The addition of the polymer may also cause formation damage,
as described above, while the use of nitrogen gas tanks and other
associated pumping equipment are typically required for foam used
as acid stimulation diverting agent. This may not be practical in
many cases, especially for offshore acid treatments, as the
operation is often limited by available deck space on the rig or
vessel. In addition, foams typically become unstable above
250.degree. F.
[0013] Another type of viscous fluid diverting agent used to assist
in formation stimulation is a surfactant or surfactant mixture. One
such viscoelastic fluid forms micelles. These wormlike micelles are
sensitive to hydrocarbons. By utilizing this sensitivity, the fluid
may selectively block water-bearing zones while the
hydrocarbon-bearing zone is unaffected. However, this viscoelastic
surfactant fluid typically cannot discriminate between zones with
various permeabilities as long as the zones are
hydrocarbon-bearing. Further, unlike polymer based fluids which
rely upon filter cake deposition to control leak-off to the
formation, viscoelastic surfactant agents control fluid leak-off
into the formation through the structure size of the micelles.
Micellar based VES fluids usually have high leak-off rates to the
formation due to the small size of the wormlike micelles. Rapid
weaving and breaking of these structures also limits the ability of
the micellar based viscoelastic system to control fluid leak-off.
The temperature limitations for such a system are generally around
200.degree. F. due to the low stability of micellar structure.
[0014] With every type of diverting system available currently,
clean-up only occurs with the inclusion of some type of outside
source. Time, temperature, and interaction with either reservoir
fluids or hydrocarbons are required to remove the diverting agent
in place. For example, viscoelastic surfactant acid diverters
typically require contact with the liquid hydrocarbon during
flowback. Without this interaction the same factors that prevent
fluids from entering a portion of the reservoir may also inhibit
the ability of the reservoir to produce hydrocarbons.
[0015] In summary, the success of a stimulation treatment or gravel
packed completion is often dependent on the ability of the
diverting agent to force the acid treatment into different portions
of the reservoir.
[0016] A need therefore exists for a method for diverting the
stimulation fluid from high permeability zones to desired low
permeability zones by a method which avoids the shortcomings of the
prior art. This method should preferably use a composition that
does not damage the formation, and is easily removed from the
formation.
[0017] Another common stimulation technique used to enhance
production of hydrocarbon from subterranean formations is hydraulic
fracturing which is typically employed to stimulate wells wherein
recovery efficiency is typically limited by the flow mechanisms
associated with a low permeability formation. During hydraulic
fracturing, a fracturing fluid, typically a gelled or thickened
aqueous solution containing chemical agents as "breakers" and a
suspended proppant, is injected into a wellbore under high pressure
and is pumped at high rates. Once natural reservoir pressures are
exceeded, the fluid induces a fracture in the formation and
transports the proppant into the fracture.
[0018] The fracture generally continues to grow during pumping and
the proppant remains in the fracture in the form of a permeable
"pack" that serves to "prop" the fracture open. In this way, the
proppant pack forms a highly conductive pathway for hydrocarbons
and/or other formation fluids to flow into the wellbore. The
fracturing fluid ultimately leaks off into the surrounding
formation. The treatment design generally requires the fracturing
fluid to reach maximum viscosity as it enters the fracture which
affects the fracture length and width.
[0019] An important attribute of fracturing fluids is their ability
to be recovered from the formation. Typically, the recovery of the
fracturing fluid is accomplished by reducing the viscosity of the
fluid to a low value such that it flows naturally from the
formation under the influence of formation fluids and pressure.
This viscosity reduction or conversion is referred to as breaking.
Historically, the application of breaking fluids as fracturing
fluids at elevated temperatures, i.e., above about 120-130.degree.
F., has been a compromise between maintaining proppant transport
and achieving the desired fracture conductivity, measured in terms
of effective propped fracture length. Conventional oxidative
breakers may react rapidly at elevated temperatures, potentially
leading to catastrophic loss of proppant transport. Further,
encapsulated oxidative breakers often have limited utility at
elevated temperatures due to a tendency to release prematurely or
have been rendered ineffective through payload self-degradation
prior to release.
[0020] Fracturing fluids composed of viscoelastic surfactant
forming micelles have been reported in U.S. Pat. No. 6,435,277.
Such micellar-type viscoelastic fluids have not been utilized
widely in fracturing treatments of relatively low permeability
formations because, amongst other reasons, materials have not been
available that would enable the maintenance of needed viscosity at
the elevated temperatures required for hydraulic fracturing
operations. Further, such fluids are often subject to temperature
and stability limitations and form emulsions which make the fluid
recovery and fracture clean-up difficult. This patent further
reports the previous limitation of viscoelastic surfactant
fracturing fluids to formations containing clays as well as
formations which require soluble salts for inhibiting hydration of
clay materials.
[0021] A need therefore exists for surfactant based fluids having
the ability to suspend proppants which are economical and which
exhibit superior properties compared to existing products available
on the market. In addition, such products need to maintain
requisite viscosity at higher temperatures while being thermally
stable without causing damage to the formation.
SUMMARY OF THE INVENTION
[0022] The viscoelastic vesicular fluid of the invention contains a
surfactant, such as an amphoteric surfactant, water, a non-aqueous
solvent, a quaternary amine polyelectrolyte and, optionally, an
internal breaker package to break the surfactant gel and reduce the
fluid viscosity to water. This system does not require contact with
formation fluids, brines, or acids for clean up to provide optimum
production.
[0023] The viscoelastic fluid of the invention does not cause
formation damage and preferably comprises densely packed surfactant
aggregations, called vesicles. The inclusion of the polyelectrolyte
facilitates the formation of the vesicles and reduces the need for
high levels of surfactant. Further, the addition of the
polyelectrolyte enhances thermal stability of the fluid.
[0024] The Theological properties of the fluid of the invention may
be adjusted by varying the pH of the fluid, concentration of
surfactant, temperature during usage of the fluid and selection of
the polyelectrolyte.
[0025] The fluid of the present invention is particularly effective
as a diverter fluid since it overcomes the disadvantages of the
prior art by providing non-damaging methods for diverting acid
stimulating fluids to the low permeability or damaged intervals
adjacent to the high permeability or non-damaged intervals.
[0026] The viscoelastic surfactant fluid of the present invention
is further highly effective in the fracturing of subterranean
formations, such as formations surrounding oil or gas wells. The
fracturing fluid further typically contains an internal breaker
package to break the surfactant gel and reduce the fluid viscosity
to water. The preferred internal breaker package consists of at
least one oxidative breaker and at least one acid forming
agent.
[0027] In another embodiment of the present invention, a process
for stimulating a formation is described. In one embodiment, a
process for injecting a diverting fluid into a formation is
described. The injection is carried out at a pressure lower than
the fracture pressure of the formation.
[0028] In yet another embodiment of the invention, an acid
stimulation package is injected into the formation, followed by the
optional pumping of a spacer fluid. The diverter fluid is then
injected into the formation. The pH of the diverting fluid is then
reduced. A second acid stimulation package is then injected into
the formation. The diverter fluid is injected into the large pore
throat portion of the formation as well as the small pore throat
portion of the formation. The small pore throat invasion depth of
the diverting fluid is less than the large pore throat invasion
depth.
[0029] In another embodiment of the present invention, the fluid is
pumped, for example, into a relatively low permeability formation
at a pressure sufficient to fracture the formation, the relatively
low permeability formation having a fracture face engaged by the
fluid during pumping. Typically, the formation comprises at least
one largely hydrocarbon-bearing zone and at least one largely
aqueous zone.
[0030] The average viscosity maintained by the fluid is more than
100 cp@ 100 s.sup.-1 from ambient temperature to about 300.degree.
F., when the fluid is used as diverter fluid, and, when the fluid
is used as a fracturing fluid, about 350.degree. F., compared to an
upper temperature limit of 275.degree. F. of the prior art wormlike
micelle surfactant based fracturing fluids.
[0031] Another significant advantage of the viscoelastic fluid of
the invention is its response to low pH fluid, such as acid. The
prior art micellar systems relied upon interaction with
hydrocarbons or formation fluids to reduce viscosity. In contrast,
the viscosity of the viscoelastic fluids of the invention may be
decreased at low pH. By controlling the time that the acid-forming
agent reduces the pH, the time required for the fluid to lose
viscosity can be controlled. The resulting product is a fluid that
can be broken at a desired time.
BRIEF DESCRIPTION OF THE DRAWINGS
[0032] In order to more fully understand the drawings referred to
in the detailed description of the present invention, a brief
description of each drawing is presented, in which:
[0033] FIG. 1A is a Transmission Electron Microscopy (TEM) image
which illustrates the vesicle structure of the inventive
viscoelastic surfactant fluids.
[0034] FIG. 1B is an illustration of the vesicular structure of a
diverting fluid within the invention.
[0035] FIG. 2 demonstrates the leak-off or invasion permeabilities
of the inventive viscoelastic surfactant fluids over time.
[0036] FIG. 3 shows the pH dependence of the fluid viscosity of the
inventive viscoelastic surfactant fluids on temperature and pH.
[0037] FIG. 4 shows the effect of temperature on the viscosity of
the viscoelastic surfactant fluids of the invention.
[0038] FIG. 5 compares the rheological data of the inventive
viscoelastic surfactant fluids with varying amount of quaternary
amine polyelectrolyte.
[0039] FIGS. 6 and 7 show the relationship of pressure and rate of
introduction versus time of injection of acid and two diverting
fluids for Examples 2 and 3, respectively.
[0040] FIG. 8 demonstrates the rheological profile of the
viscoelastic surfactant diverter pill made in Example 1.
[0041] FIG. 9 shows the dependence of concentration of the
nonaqueous solvent on the fluid viscosity of the viscoelastic
surfactant fracturing fluids, as discussed in Example 6.
[0042] FIG. 10 demonstrates the effect of the gel breaker on the
fluid viscosity of the viscoelastic surfactant fracturing fluids of
the invention, as illustrated in Example 7.
[0043] FIG. 11 demonstrates the effect of a clay stabilizer on the
fluid viscosity of the viscoelastic surfactant fracturing fluids of
the invention, as taught in Example 8.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0044] The viscoelastic fluid of the invention comprises: [0045]
(1) at least one surfactant; [0046] (2) at least one quaternary
amine polyelectrolyte; [0047] (3) water, including, but not limited
to, sea water or fresh water, and [0048] (4) a non-aqueous solvent.
These components are preferably combined in percentages that are
appropriate for the formation to be stimulated.
[0049] Generally, the fluid contains surfactant(s) of about 1 to
about 50 weight percent, preferably about 1 to about 40 weight
percent, and even more preferably about 2 to about 20 weight
percent, based upon the weight of the fluid. The polyelectrolyte is
generally present in ranges from about 0.05% to about 3.0% weight
percent, preferably about 0. 1% to about 1% weight percent, and
more preferably at about 0.1% to about 0.5% weight percent, based
upon the weight of the fluid. The non-aqueous solvents are
generally present in ranges from about 0.1 to about 25 weight
percent, preferably about 0.5 to about 20 weight percent, and more
preferably at about 1 to about 15 weight percent, based upon the
weight of the fluid. The remainder weight percent is water.
[0050] The quaternary amine polyelectrolyte ("polyquats") is
generally soluble in both aqueous and aqueous-alcoholic media. The
quaternary amine polyelectrolyte ("polyquats") is generally soluble
in both aqueous and aqueous-alcoholic media and interacts with the
surfactant, thereby enlarging the vesicle size and enhancing the
thermal stability of the vesicular structure. For conventional
vesicle based viscoelastic fluids, a high concentration of
surfactant is required in order to create a dense pack vesicle
fluid and generate adequate viscosity for practical applications.
With the addition of polyquats, a significant reduction of
surfactant concentration is achieved, from originally more than 20
percent to current of about 7%.
[0051] Polyquats include derivatives of cellulose ethers, such as
carboxymethyl cellulose. Further, suitable polyquats include
aminoalkyl celluloses, aminocarbamoyl celluloses,
hydroxyethylcellulose as well as betainized cellulose
aminoamides.
[0052] Exemplary of such polyquats include those cellulose ether
derivatives represented by the overall structural formula: ##STR1##
wherein:
[0053] R.sub.cell is the residue of an anhydroglucose repeat unit,
particularly from cellulose;
[0054] t is 0 or 1;
[0055] X is oxygen;
[0056] z is from 50 to about 20,000; and
[0057] each R.sub.1, R.sub.2 and R.sub.3 is individually
represented by the substituent structural formula: ##STR2##
wherein:
[0058] A.sup.- is an anion;
[0059] a is an integer of from 1 to about 3;
[0060] m is an integer of from 0 to about 6;
[0061] n is an integer greater than or equal to 0, provided that
the level of cationic substitution, CS, defined by the average
moles of quaternary nitrogen atoms per mole anhydroglucose repeat
unit is greater than 0; preferably n is from 1 to about 25, most 3
to 10, more preferably 3;
[0062] p is an integer of from 0 to about 6;
[0063] q is 0 or 1;
[0064] each R.sub.5 and R.sub.7 is individually ethylene, a
propylene or a hydroxypropylene;
[0065] R.sub.6 is a di- or trivalent, cyclic, branched or straight
chain, saturated or unsaturated hydrocarbon having from 2 to about
6 carbon atoms, provided there are at least 2 carbon atoms between
the nitrogen atom and any oxygen atom, such as in the ether
substituent or polysaccharide residue;
[0066] R.sub.8 is hydrogen, hydroxyl, R.sub.h, alkyl, carboxyl or
alkali metal or amine carboxylate, or other terminal group provided
that when q is 0 then R.sub.8 is hydrogen or alkyl; R.sub.8 is
preferably hydrogen or alkyl;
[0067] each R.sub.9, R.sub.10 and R.sub.11 is individually R.sub.h,
alkyl, aryl, aralkyl, alkaryl, cycloalkyl, alkoxyaryl or
alkoxyalkyl, having at least two carbon atoms separating the oxygen
atom in the alkoxyaryl or alkoxyalkyl group from the nitrogen atom,
or together with R.sub.6 forms a heterocyclic ring. Such nitrogen
substituents include lower alkyls having from 1 to about 3 carbon
atoms, such as methyl, or ethyl; aryls such as phenyl; aralkyls
such as benzyl; or, together with R.sub.6, dialkyl substituted
cycloalkyl such as N,N-dimethyl pyrrolidyl; and the like. Preferred
nitrogen substituents of each repeat unit are methyl, a hydrophobic
group, or together with R.sub.6 provides a pyrrolidyl, or are a
mixture of such groups;
[0068] R.sub.h is a hydrophobic group containing an alkyl group
having at least 8 carbon atoms, preferably from about 10 to about
24 carbon atoms, and most preferably from about 10 to about 18
carbon atoms;
[0069] v is equal to the valence of A, preferably 1; and
[0070] y is 0 or 1, provided that when y is 0 then p and q are 0
and R.sub.8 is hydrogen or other terminal group.
[0071] In a preferred embodiment, z is from about 100 to about
6,000; and most preferably from about 250 to about 4,000. The
corresponding molecular weights of the cationic cellulose ether
ranges typically from several thousand up to several million.
[0072] Exemplary anions for A.sup.- include inorganic anions such
as chloride, bromide, iodide, sulfate, methylsulfate, sulfonate,
nitrate, phosphate and the like; and organic anions such as acetate
and the like. Monovalent anions are preferred, particularly halides
and especially chloride. The anions are typically provided as the
residue of the quaternary ammonium salts used as quatemizing
agents, or by other known techniques.
[0073] The number of quaternary nitrogen atoms per substituent,
defined by n in Formula III, is greater than or equal to 0. The
extent of quaternization throughout the polysaccharide,
characterized as the degree of cationic substitution, i.e., CS,
provides an average value per repeat unit which is greater than 0,
and in some embodiments is generally less than 1 and preferably
from about 0.01 to about 0.6.
[0074] Such cellulose ether derivatives of formula (I) are
disclosed in U.S. Pat. No. 4,767,463, herein incorporated by
reference. In a particularly preferred embodiment, the cellulose
ether is polyquatemium-4 represented by the structural formula:
##STR3## Polyquaternium-4 or quaternized hydroxyethyl cellulose is
manufactured by National Starch and Chemical Corporation under the
trademark Celquat. The viscous grade H-100 is especially effective.
It is supplied as a granular powder which is soluble in water.
[0075] Further preferred polyquats include those of the general
formula: ##STR4## wherein
[0076] b is between 2 and 8, preferably 4 or 5; and wherein:
[0077] R.sup.1 is hydrogen or methyl, preferably hydrogen;
[0078] R.sup.2 is a divalent aliphatic hydrocarbon group with 2 to
20 carbon atoms, preferably --CH.sub.2--CH.sub.2-- or
--CH.sub.2--CH.sub.2--CH.sub.2--;
[0079] R.sup.3, R.sup.4, R.sup.6, R.sup.7 and R.sup.8 are alkyl
groups with 1 to 4 carbon atoms that may be the same as one another
or different from one another, and are preferably each methyl
groups;
[0080] R.sup.5 is a substituted or unsubstituted divalent aliphatic
group with 2 to 5 carbon atoms, preferably --CH.sub.2--CH(OH)
--CH.sub.2--; and
[0081] X.sup.1 and X.sup.2 are anions that may be the same as one
another or different from one another; preferably a halide, a
sulfate ester group, or a sulfonic acid group, most preferably
chloride.
[0082] Such polyquats are disclosed in U.S. Pat. No. 6,071,505,
herein incorporated by reference, and typically may have at least
about 0.2 polyquaternary ammonium groups present for each
anhydroglucose unit of the polymeric molecule, preferably between
about 0.3 and about 0.7 diquaternary groups per anhydroglucose
unit, most preferably about 0.5.
[0083] Further exemplary polyquats include ammonium derivatives of
cellulose ethers, aminoalkyl cellulosics, aminocarbamoyl cellulosic
material, hydroxyalkylcellulose as well as betainized cellulose
aminoamides.
[0084] Viscoelastic fluids not containing polyquats typically lose
viscosity upon dilution with water or mixing with hydrocarbons. The
effect of temperature on viscosity in the viscoelastic surfactant
fluids of the invention versus those fluids containing no polyquat
is illustrated in FIG. 4.
[0085] The water may be fresh water or salt water. The water may
also contain a salt. Useful salts include, but are not limited to,
potassium chloride, sodium chloride, cesium chloride, ammonium
chloride, calcium chloride, magnesium chloride, sodium bromide,
potassium bromide, cesium bromide, calcium bromide, zinc bromide,
sodium formate, potassium formate, cesium formate, sodium acetate,
and mixtures thereof. The percentage of salt in the water
preferably ranges from about 0% to about 60% by weight, based upon
the weight of the water.
[0086] The viscoelastic fluid of the invention is characterized by
its vesicle structure. FIG. 1A is a Transmission Electron
Microscopy (TEM) image which illustrates the vesicle structure.
Such vesicles are best described as a "water-in-water" emulsion. A
schematic drawing of the vesicle 15 is illustrated in FIG. 1B.
Vesicle core water 10 lies at the approximate center of the vesicle
structure. The surfactant chains 20 have a hydrophilic end 23 and
hydrophobic end 24. The surfactant chains 20, composed from at
least two surfactant molecules, 21 and 22, are formed from the
attraction of hydrophobic ends 24 of the surfactant molecules. At
least one hydrophilic end 23 of surfactant chain joins vesicle core
water 10. Water 30 surrounds vesicle 15. Among the surfactant chain
20 is non-aqueous solvent 40 that facilitates the structure of the
vesicle. The representative vesicle shown in FIG. 1B is
unilamellar. A multilamellar vesicle structure is similar in
structure, with surrounding water 30 becoming a new core water
layer for the next layer of surfactant chains.
[0087] The vesicles are classified by the structure of surfactant
aggregations in water. Such vesicles provide adequate viscosity for
acid diverting purpose and may be characterized as bi-layered
aggregates. The diameter of the vesicle generally varies from
between about 100 .ANG. to about 50 microns. The size of the
aggregation structure of the vesicles is typically much larger than
the wormlike micelles. This increase in aggregate structure size
creates a much larger surface area. Typically, the vesicle is
circular like a ball, in contrast to the wormlike rod-shaped
micelles of the prior art. The diameter of the vesicle ball of the
invention generally is about the same as the length of the
rod-shaped micelles of the prior art. The vesicle structure is also
a more stable system than the micellar system and does not
continually lose shape and reform over time like the wormlike
micelles. Vesicles in a particular system are not necessarily of a
uniform size and may have a wide distribution. When the term
"vesicle" is used herein it is meant to mean both unilamellar and
multilamellar vesicles.
[0088] The fluid viscosity for the diverting fluids of the
invention may principally be attributed to the vesicular structures
aggregated through interaction of surfactant molecules. The
surfactant molecules form vesicles through physical interactions
and once the physical condition changes, the vesicle structure
changes and fluid loses its viscosity.
[0089] Many different types of surfactants may be used to form the
viscoelastic surfactant fluids. For instance, the mixture of a
cationic and an ionic surfactant with water and a non-aqueous
solvent will form such a vesicle. Double-tailed surfactants,
amphoteric surfactants, and anionic surfactants may also be used.
The typical surfactant molecules for this type of fluid are
molecules with molecular weight around several hundreds. The
surfactant may be chemically or enzymatically modified.
[0090] Examples of suitable surfactants forming the aggregated
vesicles include, but are not limited to, imadazoline, alkyl
betaine, alkyl amine oxide, phospholipids and lecithin. In a
preferred embodiment, the lecithin may be obtained from soybeans.
The lecithin may be natural or synthetic lecithin. Preferred
phospholipids and lecithin include phosphatidylcholine,
phosphatidylethanolamine, and phosphatidylinositol. Additional
information on lecithin and its many variants, may be found in
Kirk-Othmer Encyclopedia of Chemical Technology, 4.sup.th ed.
Volume 15, pages 192-210, John Wiley & Sons, 1995, Lecithins
Sources, Manufacture & Uses, by Bernard F. Szuhaj, American Oil
Chemists' Society, 1985 and Lecithins, by Bernard F. Szuhaj and
Gary R. List, American Oil Chemists' Society, 1985.
[0091] The introduction of polyquat as electrolyte further reduces
the minimum amount of surfactant required for vesicle formation.
Before the addition of the electrolyte, almost 27% by volume
surfactant loading is minimally required in order to generate
adequate viscosity for oilfield applications. Upon the addition of
electrolyte to 10 weight percent surfactant, gelation commences and
the final viscosity of the vesicular fluid is dependent upon the
loading of the quaternary amine electrolyte. This phenomena is
further evident by observation of the vesicular fluid in FIG. 1. To
generate the fluid viscosity seen in a vesicular fluid containing
no polyquat, more surfactant is required as the number and size of
vesicles in the fluid increase. The reduction in surfactant
concentration further makes it possible to minimize the potential
of emulsion formation. In fact, no emulsion has been observed in
either laboratory or field usages of the inventive vesicular
fluids.
[0092] When used as a fracturing fluid, the polyquat further is
useful to reduce clay swelling attributable to clay
stabilizers.
[0093] The viscoelastic surfactant fluids of the invention are
further sensitive to pH. As illustrated in FIG. 3, the inventive
diverting fluids may lose structure and viscosity at low pH. This
is particularly beneficial in applications of acid diverting since
it ensures complete gel breaking during the acid pumping stage,
leaving no damage to the high permeability zone. The pH of the
fluid should preferably be above 9.0, preferably between about 9.0
and about 11.0.
[0094] The non-aqueous solvent is typically one or more
hydrocarbons and/or halogenated hydrocarbons, although other
non-aqueous solvents also function appropriately. Examples of the
non-aqueous solvents include, but are not limited to, aliphatic
hydrocarbons, aromatic hydrocarbon, alcohols, mineral oils, organic
oils such as a soybean oil or a corn oil, fatty acids, glycol
ethers, ethers, or mixtures thereof. An example of an alcohol
useful in the composition is a linear, branched, or cyclic C.sub.1
to C.sub.20 alcohol, such as a linear or branched C.sub.4 to
C.sub.20 alcohol. Examples of these solvents are 2-ethyl hexanol,
ethylene glycol monobutyl ether, ethylene glycol monobutyl, or
mixtures thereof.
[0095] When employed as a diverter fluid, the inventive
viscoelastic fluids of the invention may optionally include an
internal breaker to ensure complete breaking at desired time
intervals. When used as a hydraulic fracturing fluid, the inventive
viscoelastic composition of the invention typically include an
internal breaker. Use of the internal breaker ensures that the
viscous gel will be broken without leaving residual damage to the
higher permeability formation. Without the internal breaker, the
time required for the fluid to lose viscosity is most easily
controlled by monitoring the effect of the acid-forming agent on
the pH of the fluid. Generally, after the diverting fluid is
broken, the formation will return to the same permeability as
before the diverting fluid was applied.
[0096] Suitable internal breakers for use in the invention may be
an ester, an organic or inorganic acid, an anhydride, an acid
halide, a polyglycolic acid or mixtures thereof. Examples of these
include, but are not limited to, methyl formate, ethyl formate,
propyl formate, butyl formate, methyl acetate, ethyl acetate,
propyl acetate, butyl acetate, ethylene glycol monobutyl acetate,
ethylene glycol diacetate, acetic anhydride, acetic formic
anhydride, succinic anhydride, tetrachlorophthalic anhydride,
chloro ethyl formate, chloro ethyl acetate, polyglycolic acid,
ethylene glycol diacetate, ethylene glycol triacetate, and the like
and mixtures thereof. The internal breaker may also be an oxidizer
such as, but not limited to, persulfates, such as ammonia
persulfate and sodium persulfate, and peroxidizers such as hydrogen
peroxide. These compounds may also be used in combination when
desired.
[0097] When used as a fracturing fluid, the inventive viscoelastic
composition of the invention typically include an internal breaker
to ensure complete breaking at the desired time intervals.
Typically, the internal breaker used with the fracturing fluid is a
combination of at least one oxidative breaker and at least one acid
forming agent. The percentage of internal breaker in the fluid is
typically dependent upon the type of internal breaker and the
desired time for reducing the fluid pH. By controlling the time in
which the acid-forming agent reduces the pH, the time required for
the fluid to lose viscosity may be controlled, creating a fluid
that can be broken at a desired time.
[0098] The percentage of internal breaker in the fluid will
typically depend upon the type of internal breaker and the desired
time for reducing the fluid pH. The internal breaker may range from
about 0.001 to about 10% of the total fluid, preferably 0.001-5%,
most preferably 0.003-2%, all by weight, but may be higher or lower
if desired. When used in fracturing fluids, the weight percentage
of the two breakers in the internal breaker system is typically
between from about 0.001% to about 1% oxidative internal breaker
and the remainder being the acid forming agent. The combination of
acid, temperature and internal breaker ensures that the fluids of
the invention will be broken during or after treatment. Such
properties have particular applicability in both dry gas and oil
bearing reservoirs.
[0099] The oxidative internal breaker is preferably, but not
limited to, persulfates, such as ammonium persulfate, sodium
persulfate, encapsulated ammonium persulfate, potassium persulfate,
encapsulated potassium persulfate, and peroxidizers such as
inorganic peroxides (including encapsulated inorganic peroxides)
like hydrogen peroxide, organic peroxides (including encapsulated
organic peroxides) as well as sodium perborate (including
encapsulated sodium perborate), as well as sodium bromate, sodium
perforate, potassium iodate, potassium periodate, sodium chlorite,
sodium hypochlorite, lithium hypochlorite and calcium hypochlorite
or a mixture thereof.
[0100] The acid forming agent, preferably acting as a companion to
the oxidative breaker, is any substance which is initially inert
but slowly hydrolyzes in the fracturing fluid to produce a Bronsted
acid, thereby gradually lowering the pH of the fluid and activating
the oxidative breaker. The preferred acid forming agent includes
organic anhydrides, acyl halides, sulfonyl halides, benzylic
halides and low molecular weight esters which slowly hydrolyze to
produce Bronsted acids. By "low molecular weight" ester is meant
that the ester should be soluble in the fracturing fluid in order
to accomplish its intended purpose of hydrolyzing with time to
produce an acid. Generally, the higher the molecular weight, the
less soluble the ester. As a result, lower molecular weight esters
are preferred for ease of use. Preferably, the acid forming agent
is a low molecular weight ester selected from the group consisting
of ethyl acetate, 2-ethoxyethylacetate, ethylacetoacetate,
triethylcitrate, methylbenzoate and dimethylphthalate.
[0101] The stimulation fluid of the invention may further other
components conventionally used in the art. For instance, the fluid
may include a demulsifier or non-emulsifier, fluid loss additive,
mutual solvent, etc. Where the stimulation fluid is a diverter
fluid, an acid or corrosion inhibitor may further be employed.
Acids may include inorganic acids such as hydrofluoric,
hydrobromic, hydrochloric, and H.sub.2CO.sub.3, and organic acids
such as acetic acid, formic acid, and citric acid. Mutual solvents
include such compounds as ethylene glycol monobutyl ether, and
dipropylene glycol methyl ether. The diverter fluid may be used
with a spacer fluid such as a salt solution of NaCl, KCl and/or
NH.sub.4Cl. Such components are present in an amount between from
about 0.05% to about 10%, preferably from about 0.05% to about 5%,
weight percent of the total weight of the fluid.
[0102] In addition, the fluid of the invention may contain a gas
such as carbon dioxide or nitrogen, and the like. This fluid
preferably contains less than 30% gas by volume, preferably less
than 10%, and most preferably less than 5% gas.
[0103] Invasion or the leak-off profile of the viscoelastic fluid
of the invention may be controlled by the size of the surfactant
aggregated structure. With the viscoelastic fluids of the
invention, the size of the aggregation structure of the system is
large. The physical size of the vesicles of the invention are much
larger than the prior art wormlike micelles. In particular, the
generally ball-shaped vesicles are three-dimensional in contrast to
the one-dimensional rod-like micelles of the prior art. The
ball-shaped vesicles of the invention are stable and do not
continually lose shape and reform over time. Thus, the vesicles
formed by the surfactant aggregates render a viscoelastic system
having greater ability to control fluid leak-off and invasion. In
particular, an operator may control leak-off of the stimulating
fluid to the formation by controlling the size differential between
the vesicles and the pore throats. As the size differential
increases, for example, because of a permeability decrease or
damage, the invasion of the vesicles into the formation is reduced.
Conversely as the size differential decreases, for example, because
of a permeability increase, the invasion into the formation
increases.
[0104] As such, the VES fluids of the invention do not generally
form filter cake and behave similarly in leak-off tests as other
VES fluids. Further, in most cases, they exhibit less leak-off than
the wormlike VES micellar type fluids of the prior art in middle
permeability formations.
[0105] Further, the thermal stability of the vesicular structure of
the fluid is greatly improved over the conventional surfactant
vesicle structures or the wormlike micelles of the prior art.
[0106] Without its use as a diverting fluid, the stimulating fluid
would normally be injected into the portion of formation at the
point of least resistance during matrix injection. This portion of
the formation is typically associated with the highest permeability
or least amount of formation damage. An injection pressure increase
in the high permeability or undamaged portion of the formation or
diverting agent would be required to change the injection profile.
When used as a diverter fluid, once the viscous fluid is in place
in the formation, it will have a finite depth of invasion related
to the pore throat diameter. Typically, for a given formation type,
the invasion depth is directly proportional to the nominal pore
throat diameter of the formation. As the fluid stops moving in the
formation, the amount of injection pressure into this interval will
also increase. At some point during injection, the pressure
required to inject the stimulation fluid into this interval will
exceed the pressure required to inject the stimulation fluid into
other portions of the interval and diversion will be achieved.
[0107] The viscous pill may be placed across the entire formation.
Varying depths of invasion will then occur throughout the formation
based upon the varying permeability or damage throughout the
interval. The ability of the viscoelastic fluid to invade into
these pore throats will vary depending on the difference between
pore throat sizing of the damaged and non-damaged formation
materials. Invasion depths will normally be greater in the cleaner
or non-damaged portion of the formation (larger pore throats) than
in the lower permeability or damaged zones (smaller or partially
filled pore throats). With a greater depth of invasion in the
cleaner sections of the formation, more of the diverting pill may
be placed in these intervals.
[0108] FIG. 2 demonstrates the leak-off rate of a viscoelastic
fluid of the invention in a formation with differing
permeabilities, specifically in a 2 inch core at 180.degree. F.
with permeabilities of 50 mD and 500 mD wherein the leak-off volume
is represented by the y-axis and where mD is the unit for
permeability. The fluid has a much higher leak-off in the high perm
core (500 mD) (deeper invasion into the formation) than that in a
low perm core (50 mD). The returned penn on the core flow tests
were accessed by flowing the core with 3% KCl to obtain the
permeability of the core, pushing the diverting fluid (as a pill)
through the core to create the plug, flowing the core again with 3%
KCl to obtain the returned permeability of the core, the "returned
perm." If the second reading on the permeability is the same as the
original value, the returned permeability is 100%. The results
indicated 90% returned perm without breaker and 100% returned perm
with the addition of internal breakers.
[0109] Thus, when the fluid of the invention is pushed into a
production zone, as diverting fluid, with various permeabilities,
the majority of the diverting fluid will enter into the high
permeability or non-damaged zone and form a temporary plug or
viscous pill while the lower permeability zone has little invasion.
This temporary viscous pill causes a pressure increase and diverts
the fluid to a lower permeability portion of the formation.
[0110] Conventionally, the pill is pumped behind the stimulation
fluid and enters the same portion of the formation as the
stimulation fluid. A temporary "bridge" is formed. The viscoelastic
pill has varying depths of invasion based upon permeability or
damage to the interval since the plug and the pill enter across the
entire formation. The annulus pressure increases and the acid
stage, following introduction of the diverter, directs the acid to
other portions of the interval. The diverting fluid of invention
may also have an internal breaker built into the system to insure
that the fluid viscosity can be reduced after a period of time.
[0111] Throughout the treatment, as injection is continued and
pressure decreases, due to the removal of damage in other portions
of the interval or the loss of viscosity of the diverting pill,
additional diverter stages may be pumped. By alternating the
pumping of acid stimulation fluids and diverting fluids, the
heterogeneous formation may be appropriately treated. A typical
pumping schedule may be as follows: [0112] (1) Injecting an acid
stimulation fluid package; [0113] (2) Optionally pumping a spacer
fluid; [0114] (3) Injecting a viscoelastic surfactant diverting
fluid; [0115] (4) Optionally, followed by pumping a spacer fluid;
and [0116] (5) Repeat step 1 to 4 as necessary. Preferably, the
injection pressure of the diverting fluid is less than the fracture
pressure of the formation. This fracture pressure will depend upon
the type of formation.
[0117] The final injection pressure of the spacer fluid or acid
stimulation fluid will generally be lower than original injection
pressure, demonstrating damage removal or stimulation of portions
of the zone that were not included in the initial injection. If
necessary, steps 1 to 4 may be repeated to improve the placement of
stimulation fluids by monitoring the treating pressure, bottom hole
pressure, or surface pressure reading.
[0118] A reduction in pH of the vesicle structured viscoelastic
fluid will cause a reduction in the fluid viscosity. In most
stimulations, a stage of acid is injected following the diverting
stage. As the stimulation fluid enters the formation and comes in
contact with the viscous pill, the acid or low pH fluid will reduce
the pill's viscosity. As the viscosity of the pill is reduced,
fluid enters that portion of the reservoir. Because the diverting
fluid will most often have less penetration into the damaged or
less permeable section of the formation, there is less diverting
fluid in the damaged or less permeable section of the formation in
a bulk sense. As a result, acid from a later acid treatment or
resulting from the acid-forming compounds of an internal breaker
will remove all or nearly all of the diverting agent from the
damaged or less permeable section of the formation before that of
the undamaged or more permeable section. This action allows
penetration of the acid treatment in the damaged or less permeable
section of the formation before that of the undamaged or more
permeable section. The oxidizing agent type of internal breaker is
believed to result in the same effect, but by a different mechanism
of actually breaking up the surfactant chains of the vesicles. With
less of the pill volume in the lower permeability zones, viscosity
loss normally occurs more rapidly. As the viscosity of the pill is
reduced, and with less volume in the damaged interval, the pressure
restriction causing diversion is normally reduced and the
stimulation fluid enters that area of the formation. This formation
invasion profile is a reason for the successful diversion of the
acid treatment.
[0119] The viscoelastic fluid of the invention more readily loses
its viscosity (and thus structure) at lower pH, as shown in FIG. 3.
FIG. 3 is a graphical depiction illustrating the dependence of the
viscosity of the fluid of the invention on temperature and pH.
Diverting fluid line 400 depicts the viscosity of the diverting
fluid of one embodiment of the invention at a pH of 12.0, fluid
line 500 at a pH of 1 1.0, fluid line 600 at a pH of 10.0 and fluid
line 700 at a pH of 9.0. The pH of the fluid may be adjusted when
desired. Typically, the pH is maintained at a value of between
about 9.0 to about 11.0. The pH may be adjusted by any means known
in the art, including the addition of acid or base to the fluid, or
bubbling CO.sub.2 through the fluid and the like.
[0120] The fluids of the invention are easy to use and can be
prepared on site or off-site. When used as a fracturing fluid, the
inventive fluids exhibit excellent proppant carrying capacity
including any proppant used with the viscoelastic fluids of the
prior art.
EXAMPLES
[0121] The following examples will illustrate the practice of the
present invention in preferred embodiments. Other embodiments
within the scope of the claims herein will be apparent to one
skilled in the art from consideration of the specification and
practice of the invention as disclosed herein. It is intended that
the specification, together with the example, be considered
exemplary only, with the scope and spirit of the invention being
indicated by the claims which follow.
[0122] Viscosity measurements were conducted on a Fann 50C
viscometer while the respective sample was sheared at 100 s.sup.-1
constantly while the temperature was raised to the stated test
temperature. The pressure readings were recorded through field
applications of the fluid. Examples 2 and 3 are studies resulting
from the injection into an oil well in the Gulf of Mexico having a
bottomhole temperature ranging between 150 and 200.degree. F.
Example 1
[0123] About 0.3 g of a carboxymethyl cellulose containing a
quaternary amine group, commercially available as CELQUAT.RTM.
H-100 polyelectrolyte (from National Starch & Chemical) was
added to 90 ml of water, as an aqueous solvent, in a Waring
blender. The mixture was agitated for approximately 30 minutes.
About 2.4 ml of ethylene glycol monobutyl ether was added under
agitation, followed by 7.6 ml of lecithin (Riceland Chemical).
Agitation was continued for another 10 minutes. The pH of the
solution was then adjusted to 10.0 using a 30% NaOH solution and
the solution was agitated for another 10 minutes. The fluid was
poured out and a viscosity test was then run on a Fann 50. The
results of the rheological measurements are set forth in FIG. 8.
FIG. 8 further illustrates the effect of temperature on viscosity
of the viscoelastic surfactant fluid of the invention.
Example 2
[0124] A viscoelastic surfactant diverter pill, made from the
preparation in Example 1, was used in a 53-foot oil-bearing
reservoir at a measured depth of 14,500 feet. Bottomhole
temperature in this interval was recorded at 198.degree. F. and the
interval was completed as a high rate water pack (HRWP). A 10% HCl
-5% acetic acid treatment was injected in stages in front of the
gravel to remove the damage and improve connection to the
near-wellbore region. The acid treatment was separated into three
stages to best treat the entire interval with two diverter
pills.
[0125] After injecting the first HCl/acetic acid into the
formation, the treating pressure on the annulus decreased from
1,300 psi to less than 250 psi at a rate of 1.5 bpm (See FIG. 6).
The annulus pressure stabilized during treatment of the well with a
5% NH.sub.4Cl spacer fluid. The viscoelastic diverter pill was
injected into the well. Once the viscoelastic diverter pill reached
the perforations, an increase of 1200 psi in annulus pressure was
observed as the rate was held constant at 3 bpm. Most of this
pressure increase can be associated with the diverter pill since
the pumping rate was kept fairly stable.
[0126] Following the placement of the first diverter pill, a second
stage of HCl/acetic acid treatment was injected into the formation
at 3 bpm. Once the acetic acid/HCl entered the formation, the
pressure decreased from 1300 psi to 400 psi on the annulus. The
pressure response is indicative that the fluid entered the portion
of the damaged or lower perm interval and clean-up of this portion
of the perforated interval occurred.
[0127] As the second diverter pill was introduced into the
formation, the annulus pressure increased from previous 400 psi up
to 1400 psi over several minutes while the pumping rate was kept at
3.5 bpm. This pressure increase can be attributed to the viscosity
effect of the viscoelastic diverter pill inside the porous
formation. Following the introduction of the second diverter, the
last stage of HCl/acetic acid was injected. Once this portion of
the acid was on the formation, the annulus pressure dropped in
several minutes. Although part of the acid enters the temporarily
bridged zone, a good portion of the acid would be diverted into
some portion of the reservoir unstimulated by the previous two
stages of acid. This could be indicative of acid diversion and
clean-up in a new portion of the perforated interval or indicative
that the diverter pill had lost viscosity and the effective
"bridging" or diversion.
[0128] The HRWP was pumped as designed with an annular screen-out
occurring and the well was producing above expected production
rates.
[0129] The pressure responses demonstrate that there is no
injection restriction after the introduction of the diverter fluid
followed by acid stimulation. Further, it indicates that no damage
is caused by the diverter fluid. Additional pills can be added to
the treatment to promote additional diversion, if necessary. No
emulsion was formed in this Example.
Example 3
[0130] In this Example, the viscoelastic diverter pill of Example 1
was used in a 120 ft gross and 91 ft net oil reservoir at a
measured depth of 9,600 feet. The well was not perfectly deviated
by 41 degrees. The primary in a single selective, this zone was
completed as a HRWP. The bottomhole temperature in this interval
was recorded at 150.degree. F. A 10% HCl acid solution was injected
in front of the gravel to improve connection to the near-wellbore
region. The acid treatment was separated into four stages with
three viscoelastic diverter pills.
[0131] Once the first acetic-HCl acid stage reached formation, the
treating pressure on the annulus decreased from 450 psi to 200 psi
(See FIG. 7). As injection was continued with the HCl acid and the
acid rate was increased from about 2 bpm to about 3.0 bpm, the
annulus pressure continued to decrease. The (first) viscoelastic
diverter pill was injected at the rate of 3.0 bpm and once the
diverter pill reached the perforations, a 300 psi increase in
annulus pressure was observed at a rate of about 3.0 bpm. Following
the placement of the first diverter pill, the second stage of
treatment acid was injected into the formation at 3.0 bpm. A
stabilized pressure injection profile was observed over the next 5
minutes as the second stage of 5% NH.sub.4Cl spacer and HCl acids
were injected into the formation. As the second stage of HCl
entered the formation, the pressure decreased from 500 psi to about
300 psi on the annulus. The injection rate of the acid was
increased to 3.75 bpm and the (second) diverter pill was
injected.
[0132] Once the diverter reached formation, a 300 psi pressure
increase was observed in the annulus. Following the second
diverter, the third stage of HCl was injected at the rate of 6 bpm.
There was a 5 minute period in which the annulus pressure
stabilized at about 650 psi and then rapidly decreased to about 500
psi once the acid entered into the non-treated zone and breakdown
of the formation occurred. (This could be indicative of acid
diversion and clean-up in a new portion of the perforated interval
or that the diverter pill had lost viscosity and the effective
"bridging" or diversion.)
[0133] A third diverter pill was pumped and followed by the last
stage of the acid treatment. A 200 psi pressure increase was
observed in this stage of the diverter. Once the last stage of the
acid entered the formation, 5% KCl was pumped to flush the
formation and the step rate test was started. The HRWP was pumped
as designed with an annular screen-out occurring and the well was
producing above operator expectations.
[0134] The pressure responses demonstrate that there is no
injection restriction after the introduction of the diverter fluid
followed by acid stimulation. Further, it indicates that no damage
is caused by the diverter fluid. Additional pills can be added to
the treatment to promote additional diversion, if desired. No
emulsion was formed in this Example.
Example 4
[0135] This Example illustrates that the viscoelastic surfactant
fluids of the invention are sensitive to pH and demonstrates the
effect of pH on viscosity of the viscoelastic surfactant fracturing
fluid of the invention.
[0136] Four base fluids were made as following: 0.3 g of
CELQUAT.RTM. H-100 polyelectrolyte was added to 90 ml of water, as
an aqueous solvent, under continuous agitation for 30 minutes,
followed by 1.2 ml of ethylene glycol monobutyl ether and then 8.8
ml of lecithin while under agitation.
[0137] Fluid #1: the pH was adjusted to 9.0 using a 30% NaOH
solution and agitation was continued for another 10 minutes.
[0138] Fluid #2: the pH was adjusted to 10.0 using a 30% NaOH
solution and agitation was continued for another 10 minutes.
[0139] Fluid #3: the pH was adjusted to 11.0 using a 30% NaOH
solution and agitation was continued for another 10 minutes.
[0140] Fluid #4: the pH was adjusted to 12.0 using a 30% NaOH
solution and agitation was continued for another 10 minutes.
[0141] The viscoelastic surfactant fracturing fluid used the
invention more readily loses its viscosity (and thus structure) at
lower pH, as shown in FIG. 3. This is particularly beneficial since
it ensures complete gel breaking during the pumping stage, leaving
no damage to the high permeability zone. The pH of the fluid may be
adjusted when desired. Typically, the pH is maintained at a value
preferably above 9.0, typically between about 9.0 to about 11.0.
The pH may be adjusted by any means known in the art, including the
addition of acid or base to the fluid, or bubbling CO.sub.2 through
the fluid and the like. FIG. 3 is a graphical depiction
illustrating the dependence of the viscosity of the viscoelastic
surfactant fracturing fluid on temperature and pH.
Example 5
[0142] This Example illustrates the effect of polyquat
polyelectrolyte loading on viscosity of the viscoelastic surfactant
fracturing fluid of the invention.
[0143] Three base fluids were made by adding:
[0144] Fluid #1:0.2 g of CELQUAT.RTM. H-100;
[0145] Fluid #2:0.3 g of CELQUAT.RTM. H-100; and
[0146] Fluid #3:0.4 g of CELQUAT.RTM. H-100 to 90 ml of water, as
an aqueous solvent, under continuous agitation for 30 minutes,
followed by 1.2 ml of ethylene glycol monobutyl ether and then 8.8
ml of lecithin while under agitation. The pH of each fluid was
adjusted to 10.0 using a 30% NaOH solution and agitation was
continued for another 10 minutes.
[0147] The viscosity of each fluid was then measured while the
temperature was raised to each test temperature. FIGS. 4 and 5
compare the rheological data between viscoelastic fluids with
varying amounts of polyquat. Specifically it demonstrates the
change in viscosity at elevated temperatures of fluids containing
0.2 weight percent polyquat, 0.3 weight percent polyquat and no
polyquat but an increased level of surfactant. A vesicle fluid
having no polyquat exhibits the thermal stability at about
250.degree. F. With the introduction of polyquat, it is possible to
stabilize the viscoelastic fluid up to about 350.degree. F. The
positively charged polyquat has strong interaction with the
surfactant molecules which thereby result in more stable vesicles.
Compared to the vesicular fluid containing no polyquat, the
vesicular structure of the invention containing a polyquat is
larger and more diverse in size. This character is likely
attributed to the interaction of the polyquat with surfactant
molecules. This strong interaction makes it possible to have more
and larger vesicles than the vesicle fluids containing surfactant
only. As shown in FIG. 1, the vesicle structures of the invention
have concentric rings and are typical of multilayered surfactant
vesicles.
[0148] Thus, the rheology of inventive vesicle fluid further
depends on the loading of polyquat. As shown in FIG. 4, the
vesicular fluid with polyquat as electrolyte has lower viscosity at
lower temperatures than the vesicular fluid void of polyquat and
having higher surfactant loading. When the loading of the polyquat
reaches 0.3%, the fluid has similar viscosity at lower temperatures
to that of the fluid without polyquat. At higher temperatures, the
vesicular fluid with polyquat has significantly higher viscosity
than the vesicular fluid void of polyquat. Thus, the vesicular
fluid increases its viscosity as the loading of polyquat increases;
however, the increment in loading of polyquat does not further
enhance vesicular structure and viscosity. Because of the reduced
surfactant loading, the potential of emulsion formation between the
fracturing fluid and the produced hydrocarbon is reduced.
Example 6
[0149] This Example illustrates the effect of nonaqueous solvent
loading on viscosity of the viscoelastic surfactant fracturing
fluid of the invention.
[0150] Four base fluids were made as following: 0.3 g of
CELQUAT.RTM. H-100 was added to 90 ml of water, as an aqueous
solvent, under continuous agitation for 30 minutes, followed
by:
[0151] Fluid #1:1.2 ml of ethylene glycol monobutyl ether and then
8.8 ml of lecithin while under agitation;
[0152] Fluid #2:1.9 ml of ethylene glycol monobutyl ether and then
8.1 ml of lecithin while under agitation;.
[0153] Fluid #3:2.4 ml of ethylene glycol monobutyl ether and then
7.6 ml of lecithin while under agitation; and
[0154] Fluid #4:2.9 ml of ethylene glycol monobutyl ether and then
7.1 ml of lecithin while under agitation.
[0155] The pH of each fluid was then adjusted to 10.0 using a 30%
NaOH solution and agitation was continued for another 10
minutes.
[0156] The viscosity of each fluid was measured while the
temperature was raised to the test temperature. The viscosity was
measured and the results of the rheological measurements are set
forth in FIG. 9. FIG. 9 demonstrates that a window of solvent
concentrations is suitable. For instance, as shown by Fluid #1 and
Fluid #2, a peak at higher concentrations at certain temperatures
is evidenced.
Example 7
[0157] This Example illustrates the effect of a gel breaker on
viscosity of the viscoelastic surfactant fracturing fluid of the
invention.
[0158] 0.3 g of CELQUAT.RTM. H-100 was added to 90 ml of water, as
an aqueous solvent, under continuous agitation for 30 minutes,
followed by 1.9 ml of ethylene glycol monobutyl ether and then 8.1
ml of lecithin. The pH of the solution was adjusted to 10.0 using a
30% NaOH solution and agitation was continued for another 10
minutes.
[0159] A breaker package, containing 1 ml of triethylcitrate and
0.042 g ammonium persulfate was added to the fluid immediately
before the fluid was placed on the Fann 50C viscometer and sheared
at 100 s.sup.-1 constantly while the temperature was raised to the
test temperature, 140.degree. F. Viscosity of the fluid was
measured under 100 s-1 constant shear during the course of the test
while the temperature was maintained at 140.degree. F. The fluid
viscosity started dropping to below 100 cp after about 210 minutes.
The results of the rheological measurements of the fluid are shown
in FIG. 10.
[0160] The combination of temperature and internal breaker ensures
that the fracturing fluids of the invention will be broken during
or after treatment. The optional internal breaker therefore assists
to ensure that, even without acid interaction, the viscous gel will
be broken and will not leave residual damage to the higher
permeability formation. Generally, after the fracturing fluid is
broken, the formation will return to the same viscosity as before
the fracturing fluid was applied.
Example 8
[0161] This Example illustrates the effect of a clay stabilizer on
viscosity of the viscoelastic surfactant fracturing fluid of the
invention. 0.3 of CELQUAT.RTM. H-100 was added to 90 ml of water,
as an aqueous solvent, under continuous agitation for 30 minutes,
and then 0.1 ml of Product 239, a clay stabilizer from Specialty
Product, was added, followed by 2.4 ml of ethylene glycol monobutyl
ether and then 7.6 ml of lecithin while under agitation. The pH of
the solution was adjusted to 10.0 using a 30% NaOH solution and
agitation was continued for another 10 minutes. The fluid was
placed on the Fann 50C viscometer and sheared at 100 s.sup.-1
constantly while the temperature was raised to the test
temperature. FIG. 11 illustrates the Theological measurements of
the fluid and demonstrates that the inventive fluid of the
invention is compatible with additional typical clay stabilizers
used by the industry
Example 9
[0162] A sample of VES fluid was prepared by adding 0.3 g of
CELQUAT.RTM. H-100 quaternary amine to 90 ml of water under
continuous agitation for 30 minutes, followed by 2.4 ml of EGMBE
(ethylene glycol monobutyl ether) and then 7.6 ml of lecithin while
under agitation. The pH of the solution was adjusted to
approximately 10.0 using a 30% NaOH solution and the solution was
agitated for another 10 minutes. A breaker package (0.6 ml of
triethylcitrate and 0.06 g of ammonium persulfate) was added into
the fluid immediately prior to pumping the fluid into a permeameter
as described in the paragraph below.
[0163] Core flow test was done on a homemade permeameter. A 2''
long and 1'' diameter Berea sandstone core was cut and degassed and
then placed in a 3% KCl solution for at least 24 hrs under vacuum.
The initial permeability of the core was obtained with 3% KCl at
180 F by pumping 3% KCl at constant flow rate from production
direction. After the initial perm was obtained, the VES fluid from
the above paragraph (with breaker) was pumped through the core from
injection direction (reverse direction) and at least 30-minute
fluid leak-off was collected. The core was then shut-in for at
least 12 hrs at 180 F. A 3% KCl solution was then pumped through
the core from the production direction at constant flow rate to
regain the perm of the core. The regained permeability of the core
was 98% of the original permeability of the core.
[0164] From the foregoing, it will be observed that numerous
variations and modifications may be effected without departing from
the true spirit and scope of the novel concepts of the
invention.
* * * * *