U.S. patent application number 14/697862 was filed with the patent office on 2015-08-13 for methods and compositions for delayed release of chemicals and particles.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is BAKER HUGHES INCORPORATED. Invention is credited to JAMES B. CREWS, TIANPING HUANG.
Application Number | 20150225640 14/697862 |
Document ID | / |
Family ID | 40899850 |
Filed Date | 2015-08-13 |
United States Patent
Application |
20150225640 |
Kind Code |
A1 |
CREWS; JAMES B. ; et
al. |
August 13, 2015 |
METHODS AND COMPOSITIONS FOR DELAYED RELEASE OF CHEMICALS AND
PARTICLES
Abstract
Agents, chemicals and particles may be controllably released at
remote locations, such as pre-selected or predetermined portions of
subterranean formations, by binding or associating or trapping them
with an association of micelles formed by a viscoelastic surfactant
(VES) in an aqueous base fluid to increase the viscosity of the
fluid. An internal breaker within the association of micelles
disturbs the association of micelles at some later, predictable or
predetermined time thereby reducing the viscosity of the aqueous
viscoelastic treating fluid and releasing the agent, chemical or
particle at a predetermined or selected location.
Inventors: |
CREWS; JAMES B.; (Willis,
TX) ; HUANG; TIANPING; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BAKER HUGHES INCORPORATED |
Houston |
TX |
US |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
40899850 |
Appl. No.: |
14/697862 |
Filed: |
April 28, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12404723 |
Mar 16, 2009 |
9029299 |
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14697862 |
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11679018 |
Feb 26, 2007 |
7723272 |
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12404723 |
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11755581 |
May 30, 2007 |
7550413 |
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11679018 |
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11125465 |
May 10, 2005 |
7343972 |
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11755581 |
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61037179 |
Mar 17, 2008 |
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60815693 |
Jun 22, 2006 |
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60570601 |
May 13, 2004 |
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Current U.S.
Class: |
507/200 |
Current CPC
Class: |
C09K 8/602 20130101;
C09K 8/584 20130101; C09K 2208/30 20130101; C09K 8/536 20130101;
C09K 8/516 20130101; C09K 8/68 20130101; C09K 8/84 20130101 |
International
Class: |
C09K 8/84 20060101
C09K008/84 |
Claims
1. An aqueous viscoelastic treating fluid comprising: an aqueous
base fluid; a viscoelastic surfactant (VES) gelling agent in an
amount effective to form a VES gel that increases the viscosity of
the aqueous viscoelastic surfactant treating fluid; at least one
internal breaker within the VES gel, where the internal breaker is
selected from the group consisting of mineral oils, fish oils,
hydrogenated polyalphaolefin oils, transition metal ion sources,
reducing agent sources, chelating agent sources, alkali metal
sources, alkaline earth metal sources, saponified fatty acids,
unsaturated or saturated fatty acids, and combinations thereof; an
agent within the VES gel, where the agent is selected from the
group consisting of fluid loss control agents, bacteria, enzyme
polymer breakers, oxidative polymer breakers, polymer breaker
enhancers, microencapsulated chemicals, macroencapsulated
chemicals, nanoencapsulated chemicals, scale inhibitors, gas
hydrate inhibitors, stimulation chemicals, remedial cleanup agents,
water-block removal agents, crosslinkers, polymers, biocides,
corrosion inhibitors, corrosion dissolvers, pH modifiers, metal
chelators, metal complexors, antioxidants, wetting agents, polymer
stabilizers, clay stabilizers, scale dissolvers, wax inhibitors,
wax dissolvers, asphaltene precipitation inhibitors, waterflow
inhibitors, sand consolidation chemicals, permeability modifiers,
foaming agents, microorganisms, nutrients for microorganisms, fine
migration control agents, zeolites, clays, inorganic flakes,
ceramics, cement, activated carbon, surfactants, paraffin
inhibitors, oxygen scavengers, amines, pH buffers, friction
reducers, clay inhibitors, production chemicals, diverting agents,
diverting agents and salts thereof and combinations thereof; and a
component selected from the group consisting of a temperature
stabilizer, a viscosity stabilizer, a viscosity enhancer, and
combinations thereof.
2. The aqueous viscoelastic treating fluid of claim 1 where the
aqueous base fluid is brine.
3. The aqueous viscoelastic treating fluid of claim 1 where a fluid
loss control agent is present at a concentration effective to
improve the fluid loss of the aqueous viscoelastic treating fluid
as compared with an identical fluid absent the fluid loss control
agent, where the fluid loss control agent is selected from the
group consisting of alkaline earth metal oxides, alkaline earth
metal hydroxides, transition metal oxides, transition metal
hydroxides, and mixtures thereof.
4. The aqueous viscoelastic treating fluid of claim 3 where in the
fluid loss control agent, the alkaline earth metal oxide or
hydroxide is selected from the group consisting of oxides or
hydroxides of magnesium, calcium, strontium, barium and mixtures
thereof, and the transition metal oxide or hydroxide is selected
from the group consisting of oxides or hydroxides of aluminum,
zirconium, vanadium, molybdenum, manganese, iron, cobalt, nickel,
palladium, copper, zinc, tin, antimony, titanium and combinations
thereof.
5. The aqueous viscoelastic treating fluid of claim 3 where the
effective concentration of the fluid loss control agent ranges from
about 2 to about 200 pptg (about 0.2 to about 24 kg/m.sup.3) based
on the aqueous viscoelastic treating fluid.
6. The aqueous viscoelastic treating fluid of claim 1 where the
agent is a solid and has a size ranging from about 1 nanometer to
about 10 millimeters.
7. The aqueous viscoelastic treating fluid of claim 1 where the
agent is a liquid.
8. An aqueous viscoelastic treating fluid comprising: a brine base
fluid; a viscoelastic surfactant (VES) gelling agent in an amount
effective to form a VES gel that increases the viscosity of the
aqueous viscoelastic surfactant treating fluid; at least one
internal breaker within the VES gel, where the internal breaker is
selected from the group consisting of mineral oils, fish oils,
hydrogenated polyalphaolefin oils, transition metal ion sources,
reducing agent sources, chelating agent sources, alkali metal
sources, alkaline earth metal sources, saponified fatty acids,
unsaturated or saturated fatty acids, and combinations thereof; an
agent within the VES gel, where the agent is a solid and has a size
ranging from about 1 nanometer to about 10 millimeters, and is
selected from the group consisting of fluid loss control agents,
enzyme polymer breakers, oxidative polymer breakers, polymer
breaker enhancers, microencapsulated chemicals, macroencapsulated
chemicals, nanoencapsulated chemicals, scale inhibitors, gas
hydrate inhibitors, stimulation chemicals, remedial cleanup agents,
water-block removal agents, crosslinkers, polymers, biocides,
corrosion inhibitors, corrosion dissolvers, pH modifiers, metal
chelators, metal complexors, antioxidants, wetting agents, polymer
stabilizers, clay stabilizers, scale dissolvers, wax inhibitors,
wax dissolvers, asphaltene precipitation inhibitors, waterflow
inhibitors, sand consolidation chemicals, permeability modifiers,
foaming agents, nutrients for microorganisms, fine migration
control agents, zeolites, clays, inorganic flakes, ceramics,
cement, activated carbon, surfactants, paraffin inhibitors, oxygen
scavengers, amines, pH buffers, friction reducers, clay inhibitors,
production chemicals, diverting agents, diverting agents and salts
thereof and combinations thereof; and a component selected from the
group consisting of a temperature stabilizer, a viscosity
stabilizer, a viscosity enhancer, and combinations thereof.
9. The aqueous viscoelastic treating fluid of claim 8 where the
agent comprises a fluid loss control agent is present at a
concentration effective to improve the fluid loss of the aqueous
viscoelastic treating fluid as compared with an identical fluid
absent the fluid loss control agent, where the fluid loss control
agent is selected from the group consisting of alkaline earth metal
oxides, alkaline earth metal hydroxides, transition metal oxides,
transition metal hydroxides, and mixtures thereof.
10. The aqueous viscoelastic treating fluid of claim 8 where a
fluid loss control agent is present at a concentration effective to
improve the fluid loss of the aqueous viscoelastic treating fluid
as compared with an identical fluid absent the fluid loss control
agent, where the fluid loss control agent is selected from the
group consisting of alkaline earth metal oxides, alkaline earth
metal hydroxides, transition metal oxides, transition metal
hydroxides, and mixtures thereof.
11. The aqueous viscoelastic treating fluid of claim 10 where in
the fluid loss control agent, the alkaline earth metal oxide or
hydroxide is selected from the group consisting of oxides or
hydroxides of magnesium, calcium, strontium, barium and mixtures
thereof, and the transition metal oxide or hydroxide is selected
from the group consisting of oxides or hydroxides of aluminum,
zirconium, vanadium, molybdenum, manganese, iron, cobalt, nickel,
palladium, copper, zinc, tin, antimony, titanium and combinations
thereof.
12. The aqueous viscoelastic treating fluid of claim 10 where the
effective concentration of the fluid loss control agent ranges from
about 2 to about 200 pptg (about 0.2 to about 24 kg/m.sup.3) based
on the aqueous viscoelastic treating fluid.
13. An aqueous viscoelastic treating fluid comprising: a brine
aqueous base fluid; a viscoelastic surfactant (VES) gelling agent
in an amount effective to form a VES gel that increases the
viscosity of the aqueous viscoelastic surfactant treating fluid; at
least one internal breaker within the VES gel, where the internal
breaker is selected from the group consisting of mineral oils, fish
oils, hydrogenated polyalphaolefin oils, transition metal ion
sources, reducing agent sources, chelating agent sources, alkali
metal sources, alkaline earth metal sources, saponified fatty
acids, unsaturated or saturated fatty acids, and combinations
thereof; an agent within the VES gel, where the agent is selected
from the group consisting of fluid loss control agents, bacteria,
enzyme polymer breakers, oxidative polymer breakers, polymer
breaker enhancers, microencapsulated chemicals, macroencapsulated
chemicals, nanoencapsulated chemicals, scale inhibitors, gas
hydrate inhibitors, stimulation chemicals, remedial cleanup agents,
water-block removal agents, crosslinkers, polymers, biocides,
corrosion inhibitors, corrosion dissolvers, pH modifiers, metal
chelators, metal complexors, antioxidants, wetting agents, polymer
stabilizers, clay stabilizers, scale dissolvers, wax inhibitors,
wax dissolvers, asphaltene precipitation inhibitors, waterflow
inhibitors, sand consolidation chemicals, permeability modifiers,
foaming agents, microorganisms, nutrients for microorganisms, fine
migration control agents, zeolites, clays, inorganic flakes,
ceramics, cement, activated carbon, surfactants, paraffin
inhibitors, oxygen scavengers, amines, pH buffers, friction
reducers, clay inhibitors, production chemicals, diverting agents,
diverting agents and salts thereof and combinations thereof; a
component selected from the group consisting of a temperature
stabilizer, a viscosity stabilizer, a viscosity enhancer, and
combinations thereof; and a fluid loss control agent is present at
a concentration effective to improve the fluid loss of the aqueous
viscoelastic treating fluid as compared with an identical fluid
absent the fluid loss control agent, where the fluid loss control
agent is selected from the group consisting of alkaline earth metal
oxides, alkaline earth metal hydroxides, transition metal oxides,
transition metal hydroxides, and mixtures thereof.
14. The aqueous viscoelastic treating fluid of claim 13 where in
the fluid loss control agent, the alkaline earth metal oxide or
hydroxide is selected from the group consisting of oxides or
hydroxides of magnesium, calcium, strontium, barium and mixtures
thereof, and the transition metal oxide or hydroxide is selected
from the group consisting of oxides or hydroxides of aluminum,
zirconium, vanadium, molybdenum, manganese, iron, cobalt, nickel,
palladium, copper, zinc, tin, antimony, titanium and combinations
thereof.
15. The aqueous viscoelastic treating fluid of claim 13 where the
effective concentration of the fluid loss control agent ranges from
about 2 to about 200 pptg (about 0.2 to about 24 kg/m.sup.3) based
on the aqueous viscoelastic treating fluid.
16. The aqueous viscoelastic treating fluid of claim 13 where the
agent is a solid and has a size ranging from about 1 nanometer to
about 10 millimeters.
17. The aqueous viscoelastic treating fluid of claim 13 where the
agent is a liquid.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS
[0001] This application is a divisional patent application of U.S.
patent application Ser. No. 12/404,723 filed Mar. 16, 2009, which
issued on May 12, 2015 as U.S. Pat. No. 9,029,299, which in turn
claimed the benefit of U.S. Provisional Patent Application No.
61/037,179 filed on Mar. 17, 2008, and is a continuation-in part of
U.S. patent application Ser. No. 11/679,018 filed on Feb. 26, 2007,
issued May 25, 2010 as U.S. Pat. No. 7,723,272 and is a
continuation-in part of U.S. patent application Ser. No. 11/755,581
filed on May 30, 2007, issued Jun. 23, 2009 as U.S. Pat. No.
7,550,413, which in turn claims the benefit of U.S. Provisional
Patent Application No. 60/815,693 filed on Jun. 22, 2006, and is a
continuation-in part of U.S. patent application Ser. No.
11/125,465, filed on May 10, 2005, issued Mar. 18, 2008 as U.S.
Pat. No. 7,343,972, which in turn claims the benefit of U.S.
Provisional Patent Application No. 60/570,601 filed May 13, 2004;
all of which are incorporated herein by reference in their
entireties.
TECHNICAL FIELD
[0002] The present invention relates to aqueous, viscoelastic
fluids used during hydrocarbon treatment operations, and more
particularly relates, in one non-limiting embodiment, to methods
and compositions for delayed delivery of particles, chemicals and
other agents at remote locations such as downhole to a subterranean
reservoir.
BACKGROUND
[0003] Hydrocarbons such as oil, natural gas, etc., may be obtained
from a subterranean geologic formation, e.g., a reservoir, by
drilling a well that penetrates the hydrocarbon-bearing formation.
This provides a partial flowpath for the hydrocarbons to reach the
surface. In order for oil to be produced, that is travel from the
formation to the well bore (and ultimately to the surface), there
must be a sufficiently unimpeded flowpath from the formation to the
well bore. Unobstructed flow through the formation rock (e.g.,
sandstone, carbonates) is possible when rock pores of sufficient
size and number are present for the oil to move through the
formation.
[0004] However, as is becoming more generally known, greater effort
and varied approaches must be undertaken to produce hydrocarbons
since the relatively easier to produce subterranean formations have
generally been found. Thus, the oil and gas industry is looking at
producing hydrocarbons from subterranean formations where
recovering the hydrocarbons is more difficult and requires many
steps, including the introduction and placement of various
components, additives and agents at relatively precise locations
downhole.
[0005] One such more complicated process involves hydraulically
fracturing the subterranean formation--literally breaking or
fracturing a portion of the strata surrounding the wellbore. The
development of suitable fracturing fluids to provide the necessary
hydraulic force is a complex art because the fluids must
simultaneously meet a number of conditions. For example, they must
be stable at high temperatures and/or high pump rates and high
shear rates which can cause the fluids to degrade and prematurely
settle out the proppant before the fracturing operation is
complete. Various fluids have been developed, but most commercially
used fracturing fluids are aqueous based liquids which have either
been gelled or foamed. When the fluids are gelled, typically a
polymeric gelling agent, such as a solvatable polysaccharide is
used, which may or may not be crosslinked. The thickened or gelled
fluid helps keep the proppants within the fluid during the
fracturing operation.
[0006] While polymers have been used in the past as gelling agents
in fracturing fluids to carry or suspend solid particles in the
brine, such polymers require separate breaker compositions to be
injected to reduce the viscosity. Further, the polymers tend to
leave a coating on the proppant even after the gelled fluid is
broken, which coating may interfere with the functioning of the
proppant. Studies have also shown that "fish-eyes" and/or
"microgels" present in some polymer gelled carrier fluids will plug
pore throats, leading to impaired leakoff and causing formation
damage. Conventional polymers are also either cationic or anionic
which present the disadvantage of likely damage to the producing
formations.
[0007] Aqueous fluids gelled with viscoelastic surfactants (VESs)
are also known in the art. VES-gelled fluids have been widely used
as gravel-packing, frac-packing and fracturing fluids because they
exhibit excellent rheological properties and are less damaging to
producing formations than crosslinked polymer fluids. VES fluids
are non-cake-building fluids, and thus leave no potentially
damaging polymer cake residue. However, the same property that
makes VES fluids less damaging tends to result in significantly
higher fluid leakage into the reservoir matrix, which reduces the
efficiency of the fluid especially during VES fracturing
treatments. It would thus be very desirable and important to
discover and use fluid loss agents for VES fracturing treatments in
high permeability formations.
[0008] Many techniques and compositions are known to introduce
chemicals, particles and other agents on a delayed release
downhole, not only for purposes of fracturing, but for other
reasons, including, but not limited to reducing fluid loss (as
mentioned), breaking the gelled fluid, inhibiting scale, inhibiting
corrosion, inhibiting hydrate formation, stimulation treatments
(e.g. with acids), for cementing, for remedial purposes, etc.
Various methods of keeping the chemical, particle or other agent in
a form that is ineffective or preserved until delivery or release
at the proper locations downhole include microencapsulation,
macroencapsulation, incorporation within an emulsion or multiple
emulsion, and the like. It would be desirable if other techniques
besides these could be devised to provide an alternative or
improved downhole delayed agent delivery system.
SUMMARY
[0009] There is provided, in one form, a method for delayed
treating of a subterranean formation with an agent that involves
injecting an aqueous viscoelastic surfactant treating fluid through
a wellbore to the subterranean formation, particularly at a
predetermined location, in non-limiting examples, in a fracture or
at a particular zone. The aqueous viscoelastic treating fluid may
include, but is not necessarily limited to, an aqueous base fluid,
a viscoelastic surfactant (VES) gelling agent present in an amount
effective to form an association of micelles that increases the
viscosity of the aqueous viscoelastic surfactant treating fluid,
one or more internal breakers within the association of micelles,
and the agent within the association of micelles. The method
further involves breaking the association of micelles with the
internal breakers to reduce the viscosity of the aqueous
viscoelastic surfactant treating fluid and to deliver the agent at
the predetermined location, and thus contact and/or treat the
subterranean formation.
[0010] There is further provided in another non-limiting embodiment
an aqueous viscoelastic treating fluid that includes an aqueous
base fluid, a VES gelling agent in an amount effective to form an
association of micelles that increases the viscosity of the aqueous
viscoelastic surfactant treating fluid, at least one internal
breaker within the association of micelles, and an agent within the
association of micelles. The agent may include, but is not
necessarily limited to, fluid loss control agents, bacteria,
bacteria nutrients, biocides, enzyme polymer breakers, oxidative
polymer breakers, microencapsulated chemicals, macroencapsulated
chemicals, nanoencapsulated chemicals, scale inhibitors, gas
hydrate inhibitors, corrosion inhibitors, stimulation chemicals,
remedial cleanup agents, water-block removal agents, scale removal
agents, fine migration control agents, and combinations thereof.
The aqueous viscoelastic surfactant treating fluid may also include
a temperature stabilizer and/or a viscosity stabilizer.
[0011] In particular, in the case of the fluid loss control agents
(e.g. MgO and/or Mg(OH).sub.2, and the like), these appear to help
develop a pseudo-filter cake of VES micelles by associating with
them as well as ions and particles (in one non-restrictive
explanation) to produce a novel and unusual viscous fluid layer of
pseudo-crosslinked elongated micelles on the wellbore and/or
reservoir face that limits further VES fluid leak-off for
controlling the depth of treatment fluid penetration and/or as a
means to better direct and target the placement location of the
treating fluid with the select agent or agents to be released.
Additionally, the art may be further advanced by use of
nanometer-sized fluid loss control agents that also form a similar
viscous fluid layer of pseudo-crosslinked micelles on the wellbore
and/or formation face that are equivalent to micron-sized fluid
loss control agents herein in controlling rate of VES fluid loss
and placement location of the treatment fluid, yet can be non-pore
plugging and physically easier to produce back with the VES fluid
after a VES treatment. That is, the effectiveness of the method is
largely independent of the size of the fluid loss control agents.
The use of MgO for fluid loss control also has utility over a broad
range of temperature of about 70.degree. F. to about 400.degree. F.
(about 21.degree. C. to about 204.degree. C.).
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a schematic illustration of a top view of a
wellbore and a hydraulic fracture;
[0013] FIG. 2 is a schematic illustration of the top view of the
wellbore and hydraulic fracture of FIG. 1 where the gray area
indicates the placement of a delayed release treatment fluid with
pseudo-crosslink fluid control;
[0014] FIG. 3 is a schematic illustration of a cross-sectional,
elevation view of a hydraulic fracture around a wellbore; and
[0015] FIG. 4 is a schematic illustration of the cross-sectional,
elevation view of the hydraulic fracture around a wellbore of FIG.
3 where the delayed release treatment fluid is shown as a gray
area;
[0016] FIG. 5 is a schematic, cross-sectional, perspective view of
wellbore and a hydraulic fracture; and
[0017] FIG. 6 is a schematic, cross-sectional, perspective view of
the wellbore and hydraulic fracture of FIG. 5 where the gray area
indicates placement of a delayed release treatment fluid
illustrating near complete coverage of the fracture section.
[0018] It will be appreciated that the Figures are schematic
illustrations which are not to scale, and that not all features are
in proper proportion to more clearly illustrate certain
features.
DETAILED DESCRIPTION
[0019] Methods and chemical compositions have been discovered for
altering the properties of viscoelastic surfactants (VESs) in
aqueous fluids. It has been further surprisingly found that this
technology may be applied toward controlled, targeted release of
particles, chemicals and other agents over time, either relatively
spontaneously or over a relatively long term, when placed in the
wellbore or downhole in a subterranean reservoir.
[0020] A specific method is primarily the temporary trapping or
holding of particular agents (e.g. liquid chemicals or solid
chemicals and other particles) within a VES fluid matrix and the
delayed release of the particular agents once or after a certain
duration of time downhole by activation of internal breaking agents
that degrade the VES micelles structure and fluid viscosity. The
specific chemical properties to be considered in designing the
delayed and controlled release of a particular agent at a
particular time and location include, but are not necessarily
limited to: [0021] 1. Appropriate viscosity to incorporate and
temporarily trap the agent to be released. [0022] 2. Appropriate
type and amount of an internal breaker or internal breakers. [0023]
3. The presence and proportion of a temperature stabilizer. [0024]
4. The presence and proportion of a viscosity stabilizer. [0025] 5.
The presence and proportion of a VES micelle associating fluid loss
control agent or agents.
[0026] By "delayed release" is meant the release of the agent (e.g.
chemical, particle, etc.) in a form and amount that is effective
for their stated purpose. That is, the agent is no longer prevented
from being effective or active by being present in an association
of micelles that impart increased viscosity to the aqueous base
fluid. These agents are temporarily prevented or inhibited from
being effective, or at least substantially effective, by the
presence and unique properties of the association of elongated
micelles in which they are present.
[0027] Liquids gelled with polymers form polymeric filter cakes on
and within the formation which can result in damage to the
formation when the polymeric filter cakes are incompletely or only
partially removed prior to hydrocarbon production. This damage may
result in reduced production of hydrocarbons. In contrast,
viscoelastic type surfactants generate viscosity in aqueous fluids
by forming unique elongated micelle arrangements. These unique
arrangements have often been referred to as worm-like or rod-like
micelles structures. The increase in viscosity is believed due to
the entanglement of the worm-like or elongated micelles. Further,
it is this interaction, entanglement or association of micelles
that carries the agent and keeps the agent from becoming active
prematurely, in one non-limiting explanation herein. Additionally,
VES gelled aqueous fluids may exhibit very high viscosity at very
low shear rates and under static conditions, and this fluid
property can be further enhanced by the addition of select
particles that associate the micelles together into a stronger
network or a more connected network, which further limits the rate
of agent release until the internal breaker degrades the viscous
elongated micelle structures into non-viscous spherical micelle
structures. It has been found that generally VES fluids do not
damage formations to the extent that polymer gelled fluids do.
[0028] In the non-restrictive embodiment of placing a fluid loss
control agent, the aqueous fluid is viscosified with a VES having
an internal breaker so that the agent to be released is
concentrated on the wellbore or on a fracture face as the desired
location of release. A unique character of this method is that the
VES micelles associate with one another in the aqueous fluid, and
the associated micelles incorporate the agent and internal breakers
therein (and other components). The VES viscosity is an important
property used to place the agent to a desired location, and one or
more internal breakers are used for quicker, delayed, or otherwise
controlled release of the agent, where little to no formation
damage occurs with this delay composition; that is, the
viscoelastic surfactant viscosified fluid, when broken by the
internal breaking agents, will have brine-like fluid viscosity and
is easily and readily producible from the subterranean formation
and will leave little to no formation permeability damage.
[0029] Agents that may be released include, but are not necessarily
limited to, fluid loss control agents, bacteria, bacteria
nutrients, biocides, preservatives, enzyme polymer breakers,
oxidative polymer breakers, polymer breaker enhancers, chelating
agents, microencapsulated chemicals, macroencapsulated chemicals,
nanoencapsulated chemicals, fertilizers, zeolites, clays, pigments,
inorganic minerals, inorganic flakes, ceramics, cement, shells,
waxes, activated carbon, fullerenes, graphite, metals, metallic
ions and complexes, resins, natural oils, refined oils, synthetic
oils, fatty acids, proteins, amino acids, siloxanes, organic acids,
polymerized organic acids, natural polymers, derivatized polymers,
synthetic polymers, salts, sugars, water wetting surfactants, oil
wetting surfactants, emulsifying agents, demulsifying agents,
anti-oxidants, oxygen scavengers, meta-silicates, amines, pH
buffers, friction reducers, clay inhibitors, scale inhibitors, gas
hydrate inhibitors, corrosion inhibitors, paraffin inhibitors,
stimulation chemicals, production chemicals, remedial cleanup
agents, water-block removal agents, scale removal agents, diverting
agents, fine migration control agents, and the like and
combinations thereof. As described herein, microencapsulation and
microcapsules are defined herein as concerning encapsulated
materials where the diameter of the microcapsule is 100 microns
down to 1000 nanometers. Macroencapsulation involves the
encapsulation of materials where the diameter of the macrocapsule
is greater than 100 microns. Nanoencapsulation and nanocapsules
refer to encapsulated materials where the diameter of the capsule
is 1000 nanometers or less. The maximum size of the particulates,
solids and other agents within the association of micelles is about
10 millimeters.
[0030] The delayed release chemicals may also be and involve other
more common agents in cementing, stimulation and production of
subterranean formation, including long horizontal reservoir
drilling and completion, as well as for transporting and delayed
release of agents along a pipeline or other transmission conduit.
In such applications, in the "parent" product (i.e. VES product
gelled in an aqueous fluid), the agent may be complexed rather than
suspended or solubilized, where agent release may be triggered upon
the parent product use, and the like. It is expected that this
technology may have significant usage in other industries,
including, but not necessarily limited to, agricultural
applications, environmental remediation, waste disposal processes,
cleaning processes, cosmetic uses, building and construction
industry, mining industry, textile arts, and the like.
Aqueous Base Fluids and Viscoelastic Surfactants
[0031] In the methods and compositions described herein, for
instance an aqueous fracturing fluid, as a non-limiting example, is
first prepared by blending a VES into an aqueous base fluid. The
aqueous base fluid could be, for example, water, brine,
aqueous-based foams or water-alcohol mixtures. The brine base fluid
may be any brine, conventional or to be developed which serves as a
suitable media for the various components. As a matter of
convenience, in many cases the brine base fluid may be the brine
available at the site used in the completion fluid, for a
non-limiting example.
[0032] As noted, the aqueous fluids gelled by the VESs herein may
optionally be brines. In one non-limiting embodiment, the brines
may be prepared using salts including, but not necessarily limited
to, NaCl, KCl, CaCl.sub.2, MgCl.sub.2, NH.sub.4Cl, CaBr.sub.2,
NaBr, sodium formate, potassium formate, and other commonly used
stimulation and completion brine salts. The concentration of the
salts to prepare the brines can be from about 0.5% by weight of
water up to near saturation for a given salt in fresh water, such
as 10%, 20%, 30%, 40% and higher percent salt by weight of water.
The brine can be a combination of one or more of the mentioned
salts, such as a brine prepared using NaCl and CaCl.sub.2 or NaCl,
CaCl.sub.2, and CaBr.sub.2 as non-limiting examples.
[0033] The viscoelastic surfactants suitable for use herein may
include, but are not necessarily limited to, non-ionic, cationic,
amphoteric, and zwitterionic surfactants. Specific examples of
zwitterionic/amphoteric surfactants include, but are not
necessarily limited to, dihydroxyl alkyl glycinate, alkyl ampho
acetate or propionate, alkyl betaine, alkyl amidopropyl betaine and
alkylimino mono- or di-propionates derived from certain waxes, fats
and oils. Quaternary amine surfactants are typically cationic, and
the betaines are typically zwitterionic. The thickening agent may
be used in conjunction with an inorganic water-soluble salt or
organic additive such as phthalic acid, salicylic acid or their
salts.
[0034] Some non-ionic fluids are inherently less damaging to the
producing formations than cationic fluid types, and are more
efficacious per pound than anionic gelling agents. Amine oxide
viscoelastic surfactants have the potential to offer more gelling
power per pound, making it less expensive than other fluids of this
type.
[0035] The amine oxide gelling agents RN.sup.+(R').sub.2O.sup.- may
have the following structure (I):
##STR00001##
where R is an alkyl or alkylamido group averaging from about 8 to
24 carbon atoms and R' are independently alkyl groups averaging
from about 1 to 6 carbon atoms. In one non-limiting embodiment, R
is an alkyl or alkylamido group averaging from about 8 to 16 carbon
atoms and R' are independently alkyl groups averaging from about 2
to 3 carbon atoms. In an alternate, non-restrictive embodiment, the
amine oxide gelling agent is tallow amido propylamine oxide
(TAPAO), which should be understood as a dipropylamine oxide since
both R' groups are propyl.
[0036] Materials sold under U.S. Pat. No. 5,964,295 include
CLEARFRAC.TM., which may also comprise greater than 10% of a
glycol. This patent is incorporated herein in its entirety by
reference. One preferred VES is an amine oxide. As noted, a
particularly preferred amine oxide is tallow amido propylamine
oxide (TAPAO), sold by Baker Oil Tools as SURFRAQ.TM. VES. SURFRAQ
is a VES liquid product that is 50% TAPAO and 50% propylene glycol.
These viscoelastic surfactants are capable of gelling aqueous
solutions to form a gelled base fluid. The additives herein may
also be used in DIAMOND FRAQ.TM. which is a VES system, similar to
SURFRAQ, which contains VES breakers sold by Baker Oil Tools.
[0037] The amount of VES included in the treating fluid depends on
the type of application. For hydraulic fracturing treatments, the
concentration of VES product to use is related to generating,
creating or producing enough fluid viscosity to control the rate of
fluid leak off into the pores of the fracture, which is also
dependent on the type and amount of fluid loss control agent used,
and both work together to improve fluid efficiency to develop the
optimum size and geometry of the fracture within the reservoir for
enhanced reservoir production of hydrocarbons and to also keep the
chemicals, particles (e.g. proppant or other particles) and/or
other agent complexed, suspended or viscosity trapped therein
during the fluid injecting step. For remedial treatments, such as
removal of residual crosslinked polymer filtercake typically left
within a hydraulic fracture after a crosslinked polymer fluid
fracturing treatment, the distribution of an enzyme or oxidative
polymer breaker agent within the damaged hydraulic fracture can be
significantly improved by using a VES-based treating fluid
containing a moderate to high amount of VES product in combination
with a VES micelle associating fluid loss agent. The micelle
associating agent allows the development of pseudo-filtercake to:
1) reduce the amount of treating fluid leak-off away from the
fracture; and 2) keep more treatment fluid within the hydraulic
fracture and thereby significantly improve the distribution of the
treating fluid containing polymer breaker. For a treatment to place
clay stabilizer within a producing formation to reduce the rate of
fines migration to the wellbore region, a low to moderate
concentration of VES product in KCl brine will enhance the
distribution of the clay stabilizer within the treated reservoir.
Stages of lower viscosity followed by higher viscosity VES-based
treating fluid can also be used to aid uniform distribution of the
treating fluid with clay stabilizer in the reservoir. A similar
treatment can be devised for placement of formation fines control
agent or agents within the reservoir or more specifically on
proppant particles within a hydraulic fracture. Thus, depending on
the application, the VES is added to the aqueous fluid in
concentrations ranging from about 0.5 to about 12.0% by volume of
the total aqueous fluid (5 to 120 gallons per thousand gallons
(gptg)). In another non-limiting embodiment, the range is from
about 1.0 to about 6.0% by volume VES product. In an alternate,
non-restrictive form, the amount of VES ranges from about 2 to
about 10 volume %.
Internal Breakers
[0038] In one particularly useful embodiment, the aqueous
viscoelastic treating fluid contains internal breakers. By the term
"internal breakers" is meant that the breaker is present in the
fluid along with the composition causing the increase in viscosity,
e.g. polymers or VESs, as contrasted with adding the breaker to the
gelled fluid separately, for instance, injecting the breaker
downhole after the gelled treating fluid. Although in some
non-limiting embodiments, polymers are not used to increase the
viscosity of the aqueous fluid, they may in some embodiments be
used together with VESs. Conventional polymer breakers include, but
are not limited to, enzymes, oxidizers, bacteria, acids, and
combinations thereof.
[0039] The compositions of the treatment fluids herein may be a
synergistic combination of internal breakers with one or more high
temperature optional stabilizers, optional viscosity enhancers,
fluid loss control agents, and mix water brines up to 14.4 ppg
salinity (1.7 kg/liter), e.g. CaBr.sub.2. The internal breakers
described herein surprisingly work in the presence of several types
of VES micelle stabilizers, micelle viscosity enhancers, micelle
fluid loss control agents, a wide range of mix water salinity
(including divalent ions like calcium and magnesium) for fluid
temperature applications ranging from about 80.degree. F. to about
300.degree. F. (about 27 to about 149.degree. C.). The ability of
these agents to work together by compatible mechanisms is
remarkably unique and allows the many enhanced VES fluid
performance properties to be combined.
[0040] In polymer filter cake, most of breaker in the polymer fluid
system is leaked-off into the formation matrix and leaves a high
concentration of polymer in the cake (fracture). The breaker is not
attached to or connected with the polymer. In VES pseudo-filter
cake, the internal breaker appears to be contained or resident
inside of VES micelles and thus goes wherever VES micelles go, in
one non-limiting explanation. The fluid loss control agents may
work from about 80.degree. F. to about 300.degree. F. (about 27 to
about 149.degree. C.). A wide range of particle types and
properties have been found of utility to improve the performance of
the VES treating fluid, which includes, but is not necessarily
limited to, surface adsorption, crystal surface charges,
piezoelectric and pyroelectric particles, and nano-sized particle
properties and technology. Additionally, the synergistic use of
internal breakers with the pseudo-filter cake has been discovered
to allow the pseudo-filter cake to be readily degraded into an
easily producible broken VES fluid. Another improved performance
feature is how the fluids herein, a portion of which may inevitably
leak-off into the pores of the reservoir during a treatment, can
carry with it internal breaker that converts the VES fluid into an
easily producible or flowable fluid without the need for contacting
reservoir hydrocarbons and which also delivers the agent downhole
at a particular time and thus a particular place. Contact of a
VES-gelled aqueous fluid with reservoir hydrocarbons is one method
of breaking the viscosity of these fluids. The methods and fluids
herein are significant improvements over conventional methods and
compositions, which, without contacting hydrocarbons, exhibit very
high viscosity at very low shear rates, such as 2000 cps or more at
1 sec shear rate. The very high viscosity of VES fluids at very low
shear rates makes the leaked-off VES fluid within the pores of the
formation require higher reservoir pressure in order to move and
remove (clean up) the fluid within the reservoir matrix. Laboratory
core clean-up tests have shown that very little pressure and time
is required to remove internally broken VES from the pore matrix of
Berea cores as compared to VES fluids without an internal
breaker.
[0041] A viscoelastic surfactant-internal breaker aqueous fluid
system containing viscosity enhancers, VES stabilizers for high
temperature, and fluid loss control agents and methods for using
the systems for delivering agents relatively precisely to
subterranean formations penetrated by a well bore have been
discovered. A viscous gel starts to develop when the viscoelastic
surfactant (VES) is mixed with an aqueous base fluid. A salt or
other counterion may be used in the aqueous fluid containing VES to
help promote viscous micelle formation. The VES-based fracturing
fluid is pumped in one or more sequential stages. The stages of
viscoelastic surfactant gelled fluid (that contains the mineral oil
and/or fish oil, transition metal ion source, saponified fatty
acid, unsaturated or saturated fatty acid or other internal
breaker, e.g.) maintains a high viscosity prior to fracturing and
other treating fluid applications and eventual breaking (viscosity
reduction) of the fluid through action of the breaker and thus
delivery of the agent. The viscosity of the VES gelled fluid is
particularly improved, increased or enhanced, particularly at low
shear rates, by the presence of particulate viscosity enhancers.
One non-limiting example of a particulate viscosity enhancer is
nano-size ZnO particles used at 0.05 to 0.1% by weight of VES
treating fluid. In another non-limiting example, the fluid
viscosity can be improved up to ten-fold compared to VES fluid
without particulate viscosity enhancer.
[0042] The rate of fluid leak-off during a treatment is also
significantly reduced by the presence of particulate fluid loss
control agents. Further, the viscosity stability of the VES-gelled
fluid may be improved or enhanced by the presence of particulate
high temperature viscosity stabilizing agents. The viscosity
enhancers, viscosity stabilizers, and fluid loss control agents,
further improve the ability of the VES-based aqueous fluid to place
agents in select or predetermined locations within the reservoir,
and each work by a mechanism that does not inhibit the activity or
mechanism of the other. In one non-limiting example, the presence
of a high temperature viscosity stabilizer does not inhibit the
activity of the internal breakers. In another non-limiting example,
the presence and activity of a fluid loss control agent does not
inhibit the breaking activity of an internal breaker. After
completion of the pumping treatment and shut-in of the well, the
internal breaker (e.g. mineral oil and/or fish oil) breaks the
viscous gel, i.e. lowers the viscosity of the fracturing fluid
readily and easily in the presence of the viscosity stabilizers,
viscosity enhancers, and the like. The internally broken VES fluid
is very easy to flow back with the producing fluid, leaving little
or no damage to the formation. Very little reservoir pressure and
time is required to produce and clean up the broken VES fluid. No
reliance on reservoir hydrocarbons is required to contact the VES
fracturing fluid and reduce its viscosity, and thus release the
agent at a time later than injection through the wellbore. Because
of their nanometer size and the minute amount used, the particulate
viscosity enhancers and stabilizers are also readily producible and
will readily clean-up and flowback with the broken VES fluid,
leaving little to no particulate damage to the formation.
[0043] As noted, aqueous fluids gelled with viscoelastic
surfactants have been previously used in wellbore completions, such
as hydraulic fracturing, without the use of an internal breaker
system, and typically rely on external downhole conditions for the
VES-gelled fluid to break, such as dilution with reservoir brine
and more importantly gel breaking through interaction with
reservoir hydrocarbons during production of such reservoir fluids
to the surface. However, reliance on external downhole conditions
has showed instances where unbroken or poorly broken VES fluid
remains within the reservoir after a VES fluid treatment and has
impaired hydrocarbon production. There are aqueous fluids gelled
with viscoelastic surfactants that are known to be "broken" or have
their viscosities reduced, although some of the known breaking
methods utilize external clean-up fluids as part of the treatment
design (such as pre- and post-flush fluids placed within the
reservoir before and after well completion treatments, such as
conventional gravel packing and also "frac-packing"--hydraulic
fracturing followed by gravel packing treatment). There are other
known methods, but they are relatively slow--for instance the use
of VES-gel breaking bacteria with fluid viscosity break times
ranging from half a day up to 7 days. There has evolved in the
stimulation fluid art an industry standard need for "quick gel
break", but for VES-gelled fluids this has been a substantially
challenging problem. There needs to be a method for breaking
VES-gelled fluids that can be as easy, as quick, and as economic as
breaking conventional polymeric fluids, in one non-limiting
embodiment, using an internal breaker. At the same time, it is not
desirable to reduce the viscosity of the fluid, i.e. break the gel,
immediately or essentially instantaneously. Of concern is the fact
than an unbroken VES fluid has exceptionally high viscosity at very
low shear rate and static conditions which makes it difficult for
reservoir hydrocarbons to contact all of the VES fluid and to
displace it from the pores of a treated reservoir. This is
particularly true for gas reservoirs and crude oil reservoirs that
have heterogeneous permeability with high relative permeability
sections present.
[0044] New methods have been discovered to reduce the viscosity of
aqueous fluids gelled with viscoelastic surfactants (i.e.
surfactants that develop viscosity in aqueous brines, including
chloride brines, by formation of rod- or worm-shaped micelle
structures). The new methods remove the need or reliance on
reservoir hydrocarbons to contact, break, and cleanup the
viscoelastic fluid. The improvements will allow relatively very
quick breaks, such as within about 1 to about 16 hours, compared to
using bacteria to break VES which takes at least 48 or more hours,
and more typically 4 to 7 days. In another non-limiting embodiment
the break occurs within about 1 to about 8 hours; alternatively
from about 1 to about 4 hours, and in another non-restrictive
version about 1 to about 2 hours. The breaker components herein can
be used as an internal breaker, e.g. added to the gel after batch
mixing of a VES-gel treatment, or added on-the-fly after continuous
mixing of a VES-gel treatment using a liquid additive metering
system in one non-limiting embodiment, or the components may be
used separately, if needed, as an external breaker solution to
remove VES gelled fluids already placed downhole. Internal breakers
suitable for the methods and compositions herein include, but are
not necessarily limited to, transition metal ion sources, reducing
agent sources, chelating agent sources, alkali metal sources,
alkaline earth metal sources, saponified fatty acids, mineral oils,
hydrogenated polyalphaolefin oils, saturated fatty acids,
unsaturated fatty acids and combinations thereof. Bacteria may also
be used alone or conjunction with these other internal breakers,
although as noted, reducing the viscosity of VES gelled fluids with
bacteria is relatively slow. The use of bacteria as a viscosity
breaker for VES gelled fluids is described in U.S. Pat. No.
7,052,901 to Baker Hughes, incorporated herein in its entirety by
reference.
[0045] The internal breakers (e.g. mineral oils, hydrogenated
polyalphaolefin oils, saturated fatty acids, polyunsaturated fatty
acids, and the like) are not solubilized in the brine, since they
are inherently hydrophobic, but rather interact with the VES
surfactant worm-like micelle structures initially as dispersed
microscopic oil droplets and thus form an oil-in-water type
emulsion where the oil droplets are dispersed in the "internal
phase" as a "discontinuous phase" of the brine medium/VES fluid
which is the "outer phase" or "continuous phase". Laboratory tests
have shown that small amounts of unsaturated fatty acids, enough to
eventually completely the break VES viscosity, will not
spontaneously degrade VES viscosity upon individual association and
dispersion within the VES micelles, but will become active to
degrade VES viscosity upon activation, such as auto-oxidation of
the fatty acids to products that disrupt the elongated, "rod-like"
or "worm-like" micelles.
[0046] Surprisingly and unexpectedly the method may employ one or
more mineral oil (as a non-limiting example of a suitable breaker)
as the breaking component. This is surprising because, as
previously discussed, the literature teaches that contact of a
VES-gelled fluid with hydrocarbons, such as those of the formation
in a non-limiting example, essentially instantaneously reduces the
viscosity of the gel or "breaks" the fluid. By "essentially
instantaneously" is meant less than one-half hour. The rate of
viscosity break for a given reservoir temperature by the methods
described herein is influenced by type and amount of salts within
the mix water (i.e. seawater, KCl, NaBr, CaCl.sub.2, CaBr.sub.2,
NH.sub.4CI and the like), presence of a co-surfactant (i.e. sodium
dodecyl sulfate, sodium dodecyl benzene sulfonate, potassium
laurate, potassium oleate, sodium lauryl phosphate, and the like),
VES type (i.e. amine oxide, quaternary ammonium salt, and the
like), VES loading, the amount of breaker (e.g. mineral oil) used,
the distillation range of the mineral oil, its kinematic viscosity,
the presence of components such as aromatic hydrocarbons, and the
like.
[0047] It is important to add the lower molecular weight mineral
oils after the VES product is added to the aqueous fluid. However,
for higher molecular weight mineral oils, types like GLORIA.RTM.
and HYDROBRITE.RTM. 200 from Crompton Corporation, they may be
added before, during or after the VES product addition. Mineral oil
(also known as liquid petrolatum) is a by-product in the
distillation of petroleum to produce gasoline. It is a chemically
inert transparent colorless oil composed mainly of linear,
branched, and cyclic alkanes (paraffins) of various molecular
weights, related to white petrolatum. Mineral oil is produced in
very large quantities, and is thus relatively inexpensive. Mineral
oil products are typically highly refined, through distillation,
hydrogenation, hydrotreating, and other refining processes, to have
improved properties, and the type and amount of refining varies
from product to product. Highly refined mineral oil is commonly
used as a lubricant and a laxative, and with added fragrance is
marketed as "baby oil" in the U.S. Most mineral oil products are
very inert and non-toxic, and are commonly used as baby oils and
within face, body and hand lotions in the cosmetics industry. Other
names for mineral oil include, but are not necessarily limited to,
paraffin oil, paraffinic oil, lubricating oil, base oil, white
mineral oil, and white oil.
[0048] In one non-limiting embodiment the mineral oil is at least
99 wt % paraffinic. Because of the relatively low content of
aromatic compounds, mineral oil has a better environmental profile
than other oils. In general, the more refined and less aromatic the
mineral oil, the better. In another non-restrictive version, the
mineral oil may have a distillation temperature range from about
160 to about 550.degree. C., alternatively have a lower limit of
about 200.degree. C. and independently an upper limit of about
480.degree. C.; and a kinematic viscosity at 40.degree. C. from
about 1 to about 250 cSt, alternatively a lower limit of about 1.2
independently to an upper limit of about 125 cSt. Specific examples
of suitable mineral oils include, but are not necessarily limited
to, BENOL.RTM., CARNATION.RTM., KAYDOL.RTM., SEMTOL.RTM.,
HYDROBRITE.RTM. and the like mineral oils available from Crompton
Corporation, ESCAID.RTM., EXXSOL.RTM. ISOPAR.RTM. and the like
mineral oils available from ExxonMobil Chemical, and similar
products from other mineral oil manufacturers. The ESCAID 110.RTM.
and Conoco LVT-200.RTM. mineral oils have been well known
components of oil-based drilling muds and the oil industry has
considerable experience with these products, thus making them
attractive choices. The mineral oils from ConocoPhillips Company
with their high purity and high volume use within other industries
are also an attractive choice.
[0049] It has been discovered in breaking VES-gelled fluids
prepared in monovalent brines (such as 3% KCl brine) that at
temperatures below about 180.degree. F. (82.degree. C.) ESCAID.RTM.
110 works well in breaking VES-gelled fluids, and that at or above
about 140.degree. F. (60.degree. C.) HYDROBRITE.RTM. 200 works
well. The use of mineral oils herein is safe, simple and
economical. In some cases for reservoir temperatures between about
120.degree. to about 240.degree. F. (about 49.degree. to about
116.degree. C.) a select ratio of two or more mineral oil products,
such as 50 wt % ESCAID.RTM. 110 to 50 wt % HYDROBRITE.RTM. 200 may
be used to achieve controlled, fast and complete break of a
VES-gelled fluid.
[0050] It has also been discovered that type and amount of salt
within the mix water used to prepare the VES fluid (such as 3 wt %
KCl, 21 wt % CaCl.sub.2, use of natural seawater, and so on) and/or
the presence of a VES gel stabilizer (such as VES-STA 1 available
from Baker Oil Tools) may affect the activity of a mineral oil in
breaking a VES fluid at a given temperature. For example,
ESCAID.RTM. 110 at 5.0 gptg will readily break the 3 wt % KCL based
VES fluid at 100.degree. F. (38.degree. C.) over a 5 hour period.
ESCAID.RTM. 110 also has utility as a breaker for a 10.0 ppg
CaCl.sub.2 (21 wt % CaCl.sub.2) based VES fluid at 250.degree. F.
(121.degree. C.) when a VES stabilizer (2.0 pptg VES-STA 1) is
included. More information about using mineral oils, hydrogenated
polyalphaolefin oils and saturated fatty acids as internal breakers
may be found in U.S. Pat. No. 7,347,266, incorporated by reference
herein in its entirety.
[0051] In one non-limiting embodiment these gel-breaking products
or breakers work by rearrangement of the VES micelles from
rod-shaped or worms-haped elongated structures to spherical
structures. The breaking components described herein may also
include the unsaturated fatty acid or polyenoic and monoenoic
components of U.S. Patent Application Publication 2006/0211776,
Ser. No. 11/373,044 filed Mar. 10, 2006, incorporated herein in its
entirety by reference. In one non-limiting embodiment these
unsaturated fatty acids (e.g. oleic, linoleic, linolenic,
eicosapentaenoic, etc.) may possibly be used alone--in oils they
are commonly found in (e.g. flax oil, soybean oil, etc.), and can
be provided as custom fatty acid blends (such as Fish Oil 18:12TG
by Bioriginal Food & Science Corp.)--or used together with the
mineral oils herein. In another non-limiting embodiment, natural
saturated hydrocarbons such as terpenes (e.g. pinene, d-limonene,
etc.), saturated fatty acids (e.g. lauric acid, palmitic acid,
stearic acid, etc. from plant, fish and/or animal origins) and the
like may possibly be used together with or alternatively to the
mineral oils herein. In some cases it is preferred that the plant
or fish oil be high in polyunsaturated fatty acids, such as flax
oil, salmon oil, and the like. The plant and fish oils may be
refined, blended and the like to have the desired polyunsaturated
fatty acid composition modified for the compositions and methods
herein. Other refinery distillates may potentially be used in
addition to or alternatively to the mineral oils described herein,
as may be hydrocarbon condensation products. Additionally,
synthetic mineral oils, such as hydrogenated polyalphaolefins, and
other synthetically derived saturated hydrocarbons may be of
utility to practice the methods herein.
[0052] In one non-limiting embodiment, the breaking or viscosity
reduction is triggered or initiated or facilitated by heat. These
mineral, plant, and animal oils will slowly, upon heating, break or
reduce the viscosity of the VES gel with the addition of or in the
absence of any other viscosity reducing agent. The amount of
internal breaker (mineral oil, e.g.), needed to break a VES-gelled
fluid may in some cases be temperature dependent, with less needed
as the fluid temperature increases. For mineral oil, the kinematic
viscosity, molecular weight distribution, and amount of impurities
(such as aromatics, olefins, and the like) also appear to influence
the rate in which a mineral oil will break a VES-gelled fluid at a
given temperature. For unsaturated fatty acid oils the type and
amount of unsaturation (i.e. double carbon bonds) appears to be the
major influence on the rate at which the fatty acid oil will break
the VES-gelled fluid at a given temperature. Once a fluid is
completely broken at an elevated temperature and cooled to room
temperature a degree of viscosity reheal may occur but in most
cases no rehealing is expected. The effective amount of mineral
oil, plant oil and/or fish oil ranges from about 0.1 to about 20
gptg based on the total fluid, in another non-limiting embodiment
from a lower limit of about 0.5 gptg, where "total fluid" means
overall VES gelled fluid with all components of the particular
embodiment. Independently the upper limit of the range may be about
12 gptg based on the total fluid. (It will be appreciated that
units of gallon per thousand gallons (gptg) are readily converted
to SI units of the same value as, e.g. liters per thousand liters,
m.sup.3/1000 m.sup.3, etc.).
[0053] Controlled viscosity reduction rates can be achieved at a
temperature of from about 70.degree. F. to about 400.degree. F.
(about 21 to about 204.degree. C.), and alternatively at a
temperature of from about 100.degree. F. independently to an upper
end of the range of about 280.degree. F. (about 38 to about
138.degree. C.), and in another non-limiting embodiment
independently up to about 300.degree. F. (149.degree. C.). In one
non-limiting embodiment, the fluid designer would craft the fluid
system in such a way that the VES gel would break at or near the
formation temperature to deliver the agent downhole at a
predetermined or designed location.
[0054] In one non-limiting embodiment, fluid internal breaker
design would be based primarily on formation temperature, i.e. the
temperature the fluid will be heated to naturally in the formation
once the acidizing, fracturing or other treatment is over. Fluid
design may take into account the expected duration or exposure of
the fluid at formation temperature during a treatment. There would
generally be no additional temperature or heating the VES fluid
would see or experience other than original reservoir
temperature.
[0055] In another non-limiting example, a combination of internal
breakers may have synergistic results, that is, the breaking
profile of the fluid over time may be improved when two types of
internal breakers are used rather only one or the other. The use of
mineral oil alone, like the use of polyenoic breaker alone, does
not give the rate and degree of viscosity reduction over time as
does the combination of mineral oil with polyenoic breaker. By
using combinations of internal breakers, both the initial and final
break of the VES fluid may be customized, that is, have improved
overall breaking performance. One breaker mechanism may help speed
up another breaker mechanism. Surprisingly, even with two internal
breaker mechanisms present in the VES fluid, the novel
pseudo-filter cake with fluid loss control agent may show excellent
fluid loss control.
[0056] It is sometimes difficult to specify with accuracy in
advance the amount of the various breaking components that should
be added to a particular aqueous fluid gelled with viscoelastic
surfactants to sufficiently or fully break the gel, in general. For
instance, a number of factors affect this proportion, including but
not necessarily limited to, the particular VES used to gel the
fluid; the particular breaker used (e.g. mineral, plant, and/or
fish oil, unsaturated fatty acid, etc.); the temperature of the
fluid; the downhole pressure of the fluid, the starting pH of the
fluid; and the complex interaction of these various factors.
Nevertheless, in order to give an approximate idea of the
proportions of the various breaking components to be used in the
methods herein, approximate ranges will be provided. In an
alternative, non-limiting embodiment the amount of mineral oil that
may be effective herein may range from about 5 to about 25,000 ppm,
based on the total amount of the fluid. In another non-restrictive
version, the amount of mineral oil may range from a lower end of
about 50 independently to an upper end of about 12,000 ppm.
[0057] The use of transition metal ion sources as breakers for
VES-gelled fluids is more fully described in U.S. Ser. No.
11/145,630 filed Jun. 6, 2005, published as U.S. Patent Application
Publication 2006/0041028, incorporated by reference herein in its
entirety. Briefly, the transition metal ion source used as an
internal breaker may include a transition metal salt or transition
metal complex, where the transition metal may be from Groups VA,
VIA, VIIA, VIIIA, IB, IIB, IIIB, and IVB of the Periodic Table
(previous IUPAC American Group notation). One or more chelating
agents and/or one or more reducing agent sources may also be used
in conjunction with the transition metal ion sources as breaking
agents. In one non-limiting embodiment, the amount of transition
metal ion from the transition metal ion source ranges from about
0.01 to about 300 ppm, based on the total fluid.
[0058] The use of saponified fatty acids as breakers for VES gelled
aqueous fluids is more fully described in U.S. Ser. No. 11/372,624
filed Mar. 10, 2006, published as U.S. Patent Application
Publication 2006/0211775, incorporated by reference herein in its
entirety. Briefly, the saponified fatty acids are soap reaction
products of a fatty acid with an alkaline compound selected from
the group consisting of organic bases, alkali metal bases, alkaline
earth metal bases, ammonium bases, and combinations thereof. The
soap reaction products may be pre-formed prior to addition as an
internal breaker, or may be formed in situ. Suitable fatty acids
include, but are not limited to those found in plant oils and
animal oils. Suitable alkali metal bases, alkaline earth metal
bases and ammonium bases include, but are not necessarily limited
to oxides and hydroxides of cations of the group including Na, K,
Cs, Ca, Mg, Ba, Fe, Mn, Cu, Zn, Zr, Mo, V, Co, Al, Sn, NH.sub.4,
(CH.sub.3).sub.4N, and mixtures thereof. Suitable organic bases
include, but are not necessarily limited to, diethanolamine,
triethanolamine, choline bases and mixtures thereof. In one
non-restrictive embodiment herein, the amount of saponified fatty
acid that is effective as a viscosity breaker ranges from about 50
to about 20,000 ppm based on the total viscoelastic surfactant
gelled fluid.
[0059] The use of the disclosed breaker systems is ideal for
controlling viscosity reduction of VES based fracturing treating
fluids. The breaking system may also be used for breaking gravel
pack fluids, acidizing or near-wellbore clean-up fluids, loss
circulation pill fluids composed of VES, drilling fluids composed
of VES, targeted placement of delayed release agents, and for many
other applications. The breaker system may additionally work for
foamed fluid applications (hydraulic fracturing, acidizing, and the
like), where N.sub.2 or CO.sub.2 gas is used for the gas phase. The
VES breaking methods herein are a significant improvement in that
it gives breaking rates for VES based fluids that the industry is
accustomed to with conventional polymer based fluids, such as
borate crosslinked guar and linear HEC (hydroxyethylcellulose).
Potentially more importantly, the use of these internal breaker
systems in combination with external downhole breaking conditions
should help assure that the agents (chemicals, particles, etc.) are
delivered relatively precisely on a time-delayed basis at the
downhole location desired.
[0060] In one non-limiting embodiment, the compositions herein will
degrade the gel created by a VES in an aqueous fluid, by
disaggregation or rearrangement of the VES micellar structure.
However, the inventors do necessarily not want to be limited to any
particular mechanism. Also, in another non-restrictive version, the
only component present in the VES gelled aqueous fluid that reduces
viscosity is one of the internal breakers described herein, or
mixtures thereof. That is, a separately introduced external breaker
component introduced after the VES-gelled fracturing fluid is not
used (e.g. various clean-up fluids). However, conditions (such as
elevated temperature) and already existing chemicals (reservoir
hydrocarbons) may be present when and where the internal breakers
are included, either intentionally or incidentally.
Fluid Loss Agents
[0061] It has been discovered that the addition of alkaline earth
metal oxides, such as magnesium oxide, and alkaline earth metal
hydroxides, such as calcium hydroxide, to an aqueous fluid gelled
with a VES improved the fluid loss of these brines. The fluid loss
control agents herein are believed to be particularly useful in
directing placement of VES-gelled fluids containing select agents
to be used for well completion, remedial and/or stimulation. In
another particularly useful application of directing placement of
VES-gelled fluid containing select agents is for long horizontal
completions, such as 4000 feet (1220 meters) or longer horizontal
wellbores where uniform coverage is often problematic using
conventional methods. The VES-gelled fluids may further comprise
proppants or gravel, if they are intended for use as fracturing
fluids or gravel packing fluids, although such uses do not require
that the fluids include proppants or gravel. In particular, the
VES-gelled aqueous fluids have improved (reduced, diminished or
prevented) fluid loss over a broad range of temperatures, such as
from about 70 (about 21.degree. C.) to about 400.degree. F. (about
204.degree. C.); alternatively up to about 350.degree. F. (about
177.degree. C.), and in another non-limiting embodiment up to about
300.degree. F. (about 149.degree. C.). Use of MgO and the like
particles, as disclosed within U.S. Pat. No. 7,343,972
(incorporated herein by reference in its entirety) is for high
temperature stability of VES viscosity, and applies for temperature
applications above about 190.degree. F. (about 88.degree. C.). The
use of MgO and the like particles for the fluid loss control herein
has application and functionality to much broader temperature
range, such as from about 70.degree. F. to about 400.degree. F.
(about 21.degree. C. to about 204.degree. C.), and may be used in
low salinity monovalent brines, such as 3% KCl.
[0062] The fluid loss control agents (e.g. MgO and/or Mg(OH).sub.2,
and the like) appear to help develop a pseudo-filter cake of VES
micelles by associating with them as well as ions and particles (in
one non-restrictive explanation) to produce a novel and unusual
viscous fluid layer of pseudo-crosslinked elongated micelles on the
reservoir face that limits further VES fluid leak-off.
Additionally, the art may be further advanced by use of
nanometer-sized fluid loss control agents that also form a similar
viscous fluid layer of pseudo-crosslinked micelles on the formation
face that are equivalent to micron-sized fluid loss control agents
herein in controlling rate of VES fluid loss, yet can be non-pore
plugging and physically easier to produce back with the VES fluid
after a VES treatment. That is, the effectiveness of the method is
largely independent of the size of the fluid loss control
agents.
[0063] Additionally, it has been discovered that the range in
reservoir permeability does not significantly control the rate of
fluid leaked-off when the additives described herein are within a
VES fluid. Thus, the rate of leak-off in 2000 md reservoirs will be
comparable to rate of leak-off in 100 and 400 md reservoirs. This
enhanced control in the amount of fluid leaked-off for higher
permeability reservoirs also expands the range in reservoir
permeability to which the VES fluid may be applied. The expanded
permeability range may allow VES fluids to be used successfully
within reservoirs with permeabilities as high as 2000 to 3000 or
more millidarcies (md). Prior VES-gelled aqueous fluids have
reservoir permeability limitations of about 800 md, and even then
they result in 2- to 4-fold volume of VES fluid leak-off rate as
compared with the fluid loss control achievable with the methods
and compositions herein.
[0064] Prior art VES-gelled aqueous fluids, being non-wall-building
fluids (i.e. there is no polymer or similar material build-up on
the formation face to form a filter cake) that do not build a
filter cake on the formation face, have viscosity-controlled fluid
leak-off into the reservoir. By contrast, the methods and
compositions herein use a fluid loss agent that associates with the
VES micelle structures through chemisorption or/and particle
surface charge attraction, allowing pseudo-crosslinking of the
elongated micelles to occur, in one non-limiting explanation of the
mechanisms at work herein. This unique association has been found
to form a highly viscous layer of crosslinked-like VES fluid on the
formation face, thus acting as a pseudo-filter cake layer that
limits and controls additional VES fluid from leaking-off into the
reservoir pores. The pseudo-filter cake is composed of VES micelles
that have VES surfactants with very low molecular weights of less
than 1000. This is in contrast to and different from polymeric
fluids that form true polymer mass accumulation-type filter cakes
by having very high molecular weight polymers (1 to 3 million
molecular weight) that due to their size are not able to penetrate
the reservoir pores, but bridge-off and restrict fluid flow in the
pores.
[0065] The fluid loss agents herein associate with the VES micelles
and as VES fluid is leaked-off into the reservoir a viscous layer
of micelles and fluid loss control particles and/or ions accumulate
on the formation face, thus reducing the rate of VES fluid
leak-off. It has been discovered that particulate plugging of the
reservoir pores is not the mechanism of leak-off control or the
mechanism that allows development of the viscous micelle layer.
Tests using nanometer-sized fluid loss agents (where
"nanometer-sized" is defined herein as on the order of 10.sup.-9 to
10.sup.-8 meters), that have no potential to bridge or plug
reservoir pores of 1 and or higher reservoir permeability, still
develop the viscous micelle layer. These materials still have the
same or similar leak-off control-rate profiles (i.e. rate of fluid
leak-off over time) as the 1 to 5 micron size fluid loss control
particles useful for the compositions and methods herein that are
larger. Thus, the size of the fluid loss agent is not a controlling
and/or primary factor of methods and compositions herein, that is,
to control VES fluid leak-off rate.
[0066] The fluid loss control agents useful herein include, but are
not necessarily limited to, slowly soluble alkaline earth metal
oxides or alkaline earth metal hydroxides, transition metal oxides,
transition metal hydroxides, or mixtures thereof. In one
non-limiting embodiment, the alkaline earth metal and transition
metals in these additives may include, but are not necessarily
limited to, magnesium, calcium, barium, strontium, aluminum,
zirconium, vanadium, molybdenum, manganese, iron, cobalt, nickel,
palladium, copper, zinc, tin, antimony, titanium, combinations
thereof and the like. In one non-restrictive version, the
transition metals such as copper, tin, nickel, and the like may be
used in relatively low concentration compared to or in combination
with the alkaline earth metals. In one non-restrictive embodiment,
the amount of additive ranges from about 2 to about 200 pounds per
thousand gallons (pptg) (about 0.2 to about 24 kg/m.sup.3) based on
the aqueous viscoelastic treating fluid. In another non-restrictive
embodiment, the amount of additive may have a lower limit of about
6 pptg (about 0.7 kg/m.sup.3) and independently an upper limit of
about 80 pptg (about 9.6 kg/m.sup.3), and in another
non-restrictive version a lower limit of about 8 pptg (about 1
kg/m.sup.3) and independently an upper limit of about 40 pptg
(about 4.8 kg/m.sup.3), and in still another non-limiting
embodiment, a lower limit of about 10 pptg (about 1.2 kg/m.sup.3)
and independently an upper limit of about 25 pptg (about 3
kg/m.sup.3).
[0067] The amount of transition metal oxides or transition metal
hydroxides may range from about 0.0001 pptg (about 0.01 g/m.sup.3)
independently to an upper limit of about 4 pptg (about 0.45
kg/m.sup.3), and in another non-restrictive version from about 0.1
pptg (about 12 g/m.sup.3) independently up to about 0.5 pptg (about
60 g/m.sup.3). In another non-limiting embodiment, the particle
size of the fluid loss control agents ranges between about 1
nanometer independently up to about 0.2 millimeter. In another
non-limiting embodiment, the particle size of the fluid loss
control agents ranges between about 4 nanometers independently up
to about 74 microns. The fluid loss control agents may be added
along with the VES fluids. In another non-restrictive version the
fluid loss control agents may have a surface area of between about
10 to about 700 square meters per gram (m.sup.2/g).
Delayed Release Agents
[0068] A chemical or biological agent (e.g. crosslinked polymer,
acid, or biocide, among others) that is a useful component of a
completion, stimulation, remedial or workover fluid can, in certain
cases, be undesirably neutralized or degraded before reaching the
site at which it is to have its effect. Therefore, in certain
instances, more of the agent is used in order to be effective and
to compensate for agent that is lost in delivering the agent to the
site. Thus, there is a need for a more efficient way to deliver
useful chemical and biological agents to a desired location in a
well. In the methods and compositions herein, these and other
agents may be present within the association of micelles and would
not be spent, that is, would be kept from reacting or being
effective until the fluid containing the association of micelles is
delivered downhole, or to some other remote location, where the gel
is broken with an internal breaker, the micelles dissociate, and
the agent is delivered to a particular location at a point in time
later or delayed from its initial injecting into a well bore.
[0069] Such chemical or biological agents may include, but not
necessarily be limited to, fluid loss control agents, oxidative
polymer breakers, enzyme polymer breakers, polymer breaker
enhancers, microencapsulated chemicals, macroencapsulated
chemicals, nanoencapsulated chemicals, fertilizers, zeolites,
clays, pigments, inorganic minerals, inorganic flakes, ceramics,
cement, shells, waxes, activated carbon, fullerenes, graphite,
metals, metallic ions and complexes, resins, natural oils, refined
oils, synthetic oils, fatty acids, proteins, amino acids,
siloxanes, organic acids, polymerized organic acids, scale
inhibitors, gas hydrate inhibitors, stimulation chemicals,
production chemicals, pipeline chemicals, water treatment
chemicals, mining chemicals, detergent chemicals, environmental
remediation chemicals, remedial cleanup agents, water-block removal
agents, crosslinkers, polymers, biocides, preservatives, corrosion
inhibitors, corrosion dissolvers, pH modifiers, metal chelators,
metal complexors, antioxidants, wetting agents, polymer
stabilizers, clay stabilizers, scale dissolvers, wax inhibitors,
wax dissolvers, asphaltene precipitation inhibitors, waterflow
inhibitors, sand consolidation chemicals, permeability modifiers,
foaming agents, diverting agents, microorganisms, nutrients for
microorganisms, salts, sugars, water wetting surfactants, oil
wetting surfactants, emulsifying agents, demulsifying agents,
anti-oxidants, oxygen scavengers, meta-silicates, amines, friction
reducers, fines migration control agents, and the like. As
previously noted, the delayed release agents may be solids or
liquids. The delayed release agents may be oil-soluble,
water-soluble and/or water dispersible.
[0070] The aqueous treatment fluid can also contain other additives
common to the well service industry such as water wetting
surfactants, non-emulsifiers and the like. In the methods and
compositions herein, the base fluid may also contain additives
which can contribute to breaking the gel (reducing the viscosity)
of the VES fluid.
[0071] In another non-limiting embodiment, the treatment fluid may
contain other viscosifying agents, other different surfactants,
clay stabilization additives, scale dissolvers, biopolymer
degradation additives, and other common and/or optional
components.
Stabilizers
[0072] Additionally, select particulate fluid loss control agents
herein may optionally be used at lower concentrations in the VES
treating fluid as high temperature viscosity stabilizers; that is
for stabilizing or sustaining the VES fluid viscosity at elevated
fluid temperatures, such as above 180.degree. F. (82.degree. C.).
Suitable viscosity stabilizers include, but are not limited to,
magnesium oxide, magnesium hydroxide, calcium oxide, calcium
hydroxide, sodium hydroxide, and the like. The select viscosity
stabilizers may, in one non-limiting embodiment, have an average
particle size of 500 nanometers or less, that is, to be preferably
small enough to be non-pore plugging and thereby will remain with
the VES fracturing fluid wherever it goes during the treatment and
during flowback. More information about using these oxides and
hydroxides as high temperature viscosity stabilizers may be found
in U.S. Pat. No. 7,343,972 and U.S. Patent Application Publication
No. 2008/0051302 A1, both of which are incorporated by reference
herein in their entirety.
[0073] The increased viscosity of aqueous fluids gelled with
viscoelastic surfactants (VESs) may also be maintained or
stabilized by one or more stabilizers that are glycols and/or
polyols. These glycols and polyols may stabilize the increased
viscosity of VES-gelled fluids effectively over an increased
temperature range, such as from about ambient to about 300.degree.
F. (about 149.degree. C.). Even though some VESs used to increase
the viscosity of aqueous fluids contain a glycol solvent, the use,
addition or introduction of the same or different glycol or a
polyol, possibly of increased purity, may improve the viscosity
stability of the fluid as a whole. Suitable glycols for use with
the stabilizing method herein include, but are not necessarily
limited to, monoethylene glycol (MEG), diethylene glycol (DEG),
triethylene glycol (TEG), tetraethylene glycol (TetraEG),
monopropylene glycol (MPG), dipropylene glycol (DPG), and
tripropylene glycol (TPG), and where the polyols include, but are
not necessarily limited to, polyethylene glycol (PEG),
polypropylene glycol (PPG), and glycerol and other sugar alcohols,
and mixtures thereof. In the case where the stabilizer is a polyol,
the molecular weight of the polyol may range from about 54 to about
370 weight average molecular weight, alternatively where the lower
threshold is about 92 weight average molecular weight, and/or where
the upper threshold is about 235 weight average molecular weight.
Suitable proportions of glycols or polyol stabilizers that may be
used, introduced or added, in one non-limiting embodiment, range
from about 0.1 to 10.0% by volume based on the total of the aqueous
fluid. In an alternate, non-restrictive embodiment, the lower end
of this proportion range may be about 0.2% by, and additionally or
alternatively the upper end of this proportion range may be about
5.0% by. Further details about polyol and/or glycol stabilizers may
be found in U.S. Patent Application Publication No. 2007/0244015
A1, incorporated herein in its entirety by reference.
[0074] In a useful, non-restrictive embodiment herein, use with
internal VES breakers can have synergistic clean-up effects for the
fluid loss control agent and the VES fluid. Use of these
compositions with an internal breaker may allow less VES fluid to
leak-off into the reservoir, thus resulting in less fluid needed to
be broken and removed once the treatment is over. Additionally, use
of an internal breaker within the VES micelles may further enhance
the breaking and removal of the pseudo-filter cake viscous VES
layer that develops on the formation face with the fluid loss
agents herein. Lab tests to date appear to show that the viscous
VES pseudo-filter cake has the micelles readily broken down to the
relatively non-viscous, more spherically-shaped micelles by use of
an internal breaker, and also with use of encapsulated breaker, if
used.
[0075] The invention will now be further illustrated with respect
to particular Examples which are not intended to limit the
invention in any regard, but instead are intended to further
describe and illuminate certain non-restrictive embodiments of the
invention.
Example 1
[0076] Shown in FIG. 1 is a top view schematic illustration of a
wellbore 10 with a schematic portrayal of a hydraulic fracture 11
extending in opposite directions (to the left and right of FIG. 1),
where portions 12A are the near-wellbore sections of hydraulic
fracture 11 and portions 12B are the near tip sections of hydraulic
fracture 11. The area within oval-shaped region 14A represents the
area of wellbore 10 and hydraulic fracture 11 commonly treated when
placing a non-diverting treatment fluid is used to clean up the
well, or when chemicals are placed within the hydraulic fracture
11; the edge of the area treated by the non-diverting treatment
fluid is seen at 14B. It may be seen that some of the treatment
fluid extends transverse to the fracture 11 (up and down, as seen
in FIG. 1), and more significantly that large portions of hydraulic
fracture 11, particularly the near tip sections 12B, are not
treated.
[0077] Shown in FIG. 2 is the top view schematic illustration of a
wellbore 10 and hydraulic fracture 11, where a delayed release
treatment fluid having pseudo-crosslinked fluid loss control as
described herein has been injected into the wellbore 10 and
fracture 11. The gray portion 15A is a schematic diagram of the
area of the hydraulic fracture 11 that is treated with this
treatment fluid, where the edge of the gray area 15A treated with
the delayed release treatment fluid is designated at 15B. It may be
seen that due to the diverting nature of the treatment fluid
described herein having pseudo-crosslinked micelles, the fluid
extends the entire length of the hydraulic fracture to the near tip
sections 12B and is not spent into the reservoir in the transverse
direction indicted by area 14A and edge 14A.
Example 2
[0078] Shown in FIG. 3 is a cross-sectional, elevation view of
hydraulic fracture and treatment fluid placements around a
wellbore, where 50 is the top section of the wellbore, 51 is the
bottom section of the wellbore, 52' and 52'' represent the upper
and lower boundaries, respectively, of the hydrocarbon-bearing
reservoir 52 and the near wellbore section of the hydraulic
fracture is shown at 53. Present within hydrocarbon-bearing
reservoir 52 is an upper high permeability streak 54 and a lower
high permeability streak 55 (which happens to be shown as deeper
than upper streak 54, in this non-limiting Example). Reservoir 52
has been fractured along upper high permeability streak 54 as shown
by upper section 56 of the hydraulic fracture and fractured along
lower high permeability streak 55 as shown by lower section 57 of
the hydraulic fracture. The white area 58 schematically illustrates
the upper area where a conventional treatment fluid is placed and
relatively larger white area 59 schematically illustrates the lower
area where a conventional treatment fluid is placed.
[0079] Shown in FIG. 4 is the cross-sectional, elevation view of
hydraulic fracture of FIG. 3 where gray area 60 schematically
illustrates the upper section of the placement of the delayed
release treatment fluid as described herein. Similarly, gray area
61 schematically illustrates the lower section of the placement of
the delayed release treatment fluid as described herein. These gray
areas 60 and 61 show near complete coverage of the upper section 56
and lower section 57 of the hydraulic fracture, respectively, for
the upper high permeability streak 54 and lower high permeability
streak 55. It may be seen that coverage using the delayed release
treatment fluids described herein is expected to be much greater
than for conventional treatment fluids. FIGS. 3 and 4 herein are
roughly comparable to FIGS. 1 and 2 previously described, but from
an elevation point of view, rather than from above.
Example 3
[0080] Shown in FIG. 5 is a cross-sectional, perspective view of a
hydraulic fracture and treatment fluid placement around a wellbore,
where 20 is the top section of the wellbore, 21 is the bottom
section of the wellbore, 22' and 22'' represent the upper and lower
boundaries, respectively, of the hydrocarbon-bearing reservoir 22
and the near wellbore section of the hydraulic fracture is shown at
23. The larger fracture 24 has an edge periphery 25. The first
potential area around the immediate wellbore area and hydraulic
fracture 24 where typical non-diverting treatment fluids are placed
is shown at 26, where the edge of this area is shown at 27. A
second potential area of wellbore and hydraulic fracture 24 where a
typical non-diverting treatment fluid is placed is shown at 28,
where the edge of this area is shown at 29. These areas are
generally understood to be considerably less in volume than the
entire area of fracture 24 and its boundary 25.
[0081] Shown in FIG. 6 is the cross-sectional, perspective view of
hydraulic fracture of FIG. 5 where gray area 30 schematically
illustrates the potential area along fracture 24 where the delayed
release treatment fluid as described herein may occur, where the
edge 31 of this region 30 demonstrates nearly complete coverage of
the fracture section 24 nearly to edge 25. FIG. 6 illustrates that
the potential area 30 extends wider than first potential area 26
and deeper than second potential area 28. Thus, the delayed release
treatment fluids described herein are expected to be more effective
than conventional treatment fluids since they will more fully
extend through and treat more of the hydraulic fracture in which
they are placed.
[0082] In the foregoing specification, the invention has been
described with reference to specific embodiments thereof as
effective in delivering chemicals, particles, and other agents
downhole using viscoelastic surfactant gelled fluids. However, it
will be evident that various modifications and changes can be made
thereto without departing from the broader spirit or scope of the
invention as set forth in the appended claims. Accordingly, the
specification is to be regarded in an illustrative rather than a
restrictive sense. For example, specific combinations of brines,
viscoelastic surfactants, internal breakers and chemicals,
particles and other agents, and other components falling within the
claimed parameters, but not specifically identified or tried in a
particular composition, are anticipated to be within the scope of
this invention.
[0083] The present invention may suitably comprise, consist or
consist essentially of the elements disclosed and may be practiced
in the absence of an element not disclosed.
[0084] The words "comprising" and "comprises" as used throughout
the claims, are to be interpreted to mean "including but not
limited to" and "includes but not limited to", respectively.
* * * * *