U.S. patent application number 14/028039 was filed with the patent office on 2015-03-19 for well treatment.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Syed A. Ali, J. Ernest Brown, Stephen Nigel Davies, Neil F. Hurley, Richard Hutchins, Li Jiang, Timothy G.J. Jones, Bruno Lecerf, John W. Still, Dmitriy Usoltsev, Murtaza Ziauddin.
Application Number | 20150075797 14/028039 |
Document ID | / |
Family ID | 52666917 |
Filed Date | 2015-03-19 |
United States Patent
Application |
20150075797 |
Kind Code |
A1 |
Jiang; Li ; et al. |
March 19, 2015 |
WELL TREATMENT
Abstract
Rapidly pulsed injection fracture acidizing. A method comprises
rapidly pulsed injection of a high reactivity fracture treatment
fluid mode or substage alternated with one or more low reactivity
treatment fluid modes or substages.
Inventors: |
Jiang; Li; (Katy, TX)
; Hutchins; Richard; (Sugar Land, TX) ; Ziauddin;
Murtaza; (Katy, TX) ; Brown; J. Ernest; (Sugar
Land, TX) ; Ali; Syed A.; (Sugar Land, TX) ;
Hurley; Neil F.; (Boston, MA) ; Still; John W.;
(Katy, TX) ; Jones; Timothy G.J.; (Cambridge,
GB) ; Davies; Stephen Nigel; (Sugar Land, TX)
; Lecerf; Bruno; (Houston, TX) ; Usoltsev;
Dmitriy; (San Antonio, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar land
TX
|
Family ID: |
52666917 |
Appl. No.: |
14/028039 |
Filed: |
September 16, 2013 |
Current U.S.
Class: |
166/307 ;
166/177.5 |
Current CPC
Class: |
E21B 43/283
20130101 |
Class at
Publication: |
166/307 ;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method comprising injecting a treatment stage fluid into a
subterranean formation above a fracturing pressure to form a
fracture in the formation; successively alternating reactivity
modes in the treatment stage fluid, in either order, between at
least first and second reactivity modes to react with carbonate in
the formation at different rates or times to unevenly etch surfaces
of the fracture; sustaining injection of the treatment stage fluid
during each of the first and second reactivity modes for a period
of time from 5 seconds up to 2.5 minutes; repeating the successive
alternation of reactivity modes for a plurality of cycles; and
reducing pressure to facilitate fracture closure and form
interconnected, hydraulically conductive channels between opposing
fracture surfaces.
2. The method of claim 1, wherein one of the first and second
reactivity modes comprises a reactant reactive with the carbonate
in the formation and the other of the first and second reactivity
modes comprises the reactant at a lesser concentration, or in a
less reactive form, or is free of the reactant.
3. The method of claim 2, wherein the reactant is selected from the
group consisting of mineral acids, organic acids, chelants and
combinations thereof.
4. The method of claim 1, further comprising: successively
alternating viscosity modes in the treatment stage fluid, in either
order, between at least first and second viscosity modes, wherein
one of the first and second viscosity modes has a higher viscosity
than the other; sustaining injection of the treatment stage fluid
during each of the first and second modes for a period of time from
5 seconds up to 2.5 minutes; and repeating the successive
alternation of viscosity modes for a plurality of cycles.
5. The method of claim 4, wherein the first and second reactivity
modes coincide with the first and second viscosity modes,
respectively.
6. The method of claim 5, wherein the relatively low viscosity
modes form fingers penetrating into the high viscosity modes in the
fracture.
7. The method of claim 6, wherein the fingers break through the
penetrated high viscosity mode into a preceding low viscosity
mode.
8. The method of claim 5, wherein the first reactivity and
viscosity modes have a high viscosity and low reactivity relative
to the second reactivity and viscosity mode.
9. The method of claim 8, wherein the first reactivity and
viscosity modes comprises a viscoelastic diverting agent and has a
viscosity higher than that of the second reactivity and viscosity
modes.
10. The method of claim 1, wherein the treatment stage fluid
comprises a gel, a cross-linked gel, an emulsion, a foam, or a
combination thereof.
11. The method of claim 1, wherein the treatment stage fluid
comprises a solid material slurried in a carrier fluid.
12. The method of claim 1, wherein the treatment stage fluid
comprises a plurality of polyolefin beads having an average
particle size distribution of less than or equal to about 1000
microns (.about.20 mesh).
13. The method of claim 1, wherein one of the first and second
reactivity modes comprises asphaltene, polylactic acid, latex, or a
combination thereof, and the other one of the first and second
reactivity modes comprises a multivalent cation.
14. The method of claim 1, wherein one of the first and second
reactivity modes comprises an aqueous carrier fluid, and the other
one of the first and second reactivity modes comprises an
oleaginous carrier fluid.
15. The method of claim 1, wherein the treatment stage fluid
comprises a water-in-oil emulsion wherein a reactant with carbonate
in the formation is in a dispersed phase.
16. The method of claim 1, further comprising gelling the first
reactivity mode, the second reactivity mode or both in the
fracture.
17. The method of claim 1, wherein a volumetric ratio of the first
reactivity mode to the second reactivity mode is from about 1:99 to
about 99:1.
18. The method of claim 1, wherein the sustained periods of time
are from about 5 seconds to about 1 minute.
19. The method of claim 1, further comprising injecting a pad stage
in advance of the treatment fluid stage, injecting a terminal flush
stage, or a combination thereof.
20. A method comprising: injecting a treatment stage fluid above a
fracturing pressure to form a fracture in a subterranean formation
penetrated by a wellbore; successively alternating modes in the
treatment stage fluid, in either order, between at least first and
second modes; wherein the first modes have a high viscosity
relative to the second modes for viscous fingering of the second
mode into the first mode in the fracture; wherein the second modes
have high reactivity with carbonate in the formation relative to
the first mode to unevenly etch surfaces of the fracture;
sustaining injection of the treatment stage fluid during each of
the first and second modes for a period of time from 5 seconds up
to 2.5 minutes; repeating the successive alternation of modes for a
plurality of cycles; and reducing pressure to facilitate fracture
closure and form interconnected, hydraulically conductive channels
between opposing fracture surfaces.
21. The method of claim 20, wherein the viscous fingering from one
of the second modes breaks through one of the first modes into
another one of the second modes.
22. A system, comprising: a subterranean formation penetrated by a
wellbore; a treatment fluid stage disposed in the wellbore, the
treatment fluid stage comprising a plurality of first mode
substages disposed in the wellbore in an alternating sequence with
a plurality of second mode substages, wherein the first mode
substages have a high viscosity relative to the second mode
substages and wherein the second mode substages have a high
reactivity with carbonate in the formation relative to the first
mode substages; and a pump system to continuously deliver the
treatment fluid stage from the wellbore to the formation at a
pressure above fracturing pressure to inject the treatment fluid
stage into a fracture in the formation, and at a rate wherein each
substage is injected into the formation over a period of time from
1 second to 2.5 minutes.
23. A system, comprising: a subterranean formation penetrated by a
wellbore; means for injecting a treatment stage fluid above a
fracturing pressure to form a fracture in the formation; means for
successively alternating modes in the treatment stage fluid, in
either order, between at least first and second modes; wherein the
first modes have a high viscosity relative to the second modes for
viscous fingering of the second mode into the first mode in the
fracture; wherein the second modes have high reactivity with
carbonate in the formation relative to the first mode to unevenly
etch surfaces of the fracture; means for sustaining injection of
the treatment stage fluid during each of the first and second modes
for a period of time from 5 seconds up to 2.5 minutes; means for
repeating the successive alternation of modes for a plurality of
cycles; and means for reducing pressure to facilitate fracture
closure and form interconnected, hydraulically conductive channels
between opposing fracture surfaces.
Description
RELATED APPLICATIONS
[0001] None.
FIELD
[0002] The disclosure relates to methods for treating subterranean
formations. More particularly, the disclosure relates to methods
for fracturing, acidizing or otherwise stimulating a wellbore.
BACKGROUND
[0003] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0004] Carbonate reservoirs present tremendous challenges to
completion, stimulation and production processes. These completion
intervals are often vertically and laterally heterogeneous with
natural permeability barriers, natural fractures and a vast array
of porosity types. In some wells, acid reaction rate may be the
dominant factor controlling the effectiveness of an acid-fracturing
treatment. Temperature accelerates the reaction rate between acid
and carbonate formation and, in turn, significantly affects the
depth of penetration. Management of the rapid reaction rate of the
acid with the carbonate formation presents a challenge to create
long, conductive fractures.
[0005] In hydraulic fracturing, a first viscous fluid called the
pad has been injected into the formation to initiate and propagate
the fracture, and is followed by a second fluid that contains a
proppant to keep the fracture open after the pumping pressure is
released. In acid fracturing, the second fluid contains an acid or
other chemical such as a chelating agent that can dissolve part of
the rock, causing irregular etching of the fracture face and
removal of some of the mineral matter, resulting in spaces between
the opposing fracture surfaces upon closure.
[0006] The relatively high reactivity of mineral acids with
carbonate formations, however, may result in the rapid consumption
of the acid before the acid can penetrate as deeply as desired into
the fracture. Accordingly, it would be beneficial to improve
fracture conductivity.
SUMMARY
[0007] According to some embodiments of the disclosure herein, a
method comprises rapidly alternating or pulsing modalities of
reactivity of a treatment fluid stage introduced into a fracture in
a reactive formation, such as, for example: alternating pulses of a
low reactivity mode and a high reactivity mode, which may be
delivered downhole in a common flow conduit or in separate flow
paths.
[0008] According to some embodiments, a method according to the
instant disclosure may comprise: injecting a treatment stage fluid
into a subterranean formation above a fracturing pressure to form a
fracture in the formation; successively alternating reactivity
modes in the treatment stage fluid, in either order, between at
least first and second reactivity modes to react with carbonate in
the formation at different rates or times to unevenly etch surfaces
of the fracture; sustaining injection of the treatment stage fluid
during each of the first and second reactivity modes for a period
of time from 5 seconds up to 2.5 minutes; repeating the successive
alternation of reactivity modes for a plurality of cycles; and
reducing pressure to facilitate fracture closure and form
interconnected, hydraulically conductive channels between opposing
fracture surfaces.
[0009] In some embodiments, one of the first and second reactivity
modes comprises a reactant reactive with the carbonate in the
formation and the other of the first and second reactivity modes
comprises the reactant at a lesser concentration, or in a less
reactive form, or is free of the reactant. In some embodiments, the
reactant is selected from the group consisting of mineral acids,
organic acids, chelants and combinations thereof. In some
embodiments, the method may include injecting a pad stage in
advance of the treatment fluid stage, injecting a terminal flush
stage, or a combination thereof.
[0010] According to some embodiments, the method may further
comprise: successively alternating viscosity modes in the treatment
stage fluid, in either order, between at least first and second
viscosity modes, wherein one of the first and second viscosity
modes has a higher viscosity than the other; sustaining injection
of the treatment stage fluid during each of the first and second
modes for a period of time from 5 seconds up to 2.5 minutes; and
repeating the successive alternation of viscosity modes for a
plurality of cycles. In some embodiments, the first and second
reactivity modes coincide with the first and second viscosity
modes, respectively.
[0011] According to some embodiments, the relatively low viscosity
mode forms fingers penetrating into the high viscosity mode in the
fracture, and in some further embodiments, the fingers break
through the penetrated high viscosity mode into a preceding low
viscosity mode and/or form channels between islands of the high
viscosity mode. In some embodiments, the first reactivity and
viscosity mode has a high viscosity and low reactivity relative to
the second reactivity and viscosity mode.
[0012] According to some embodiments, a system may comprise: a
subterranean formation penetrated by a wellbore; a treatment fluid
stage disposed in the wellbore, the treatment fluid stage
comprising a plurality of first mode substages disposed in the
wellbore in an alternating sequence with a plurality of second mode
substages, wherein the first mode substages have a high viscosity
relative to the second mode substages and wherein the second mode
substages have a high reactivity with carbonate in the formation
relative to the first mode substages; and a pump system to
continuously deliver the treatment fluid stage from the wellbore to
the formation at a pressure above fracturing pressure to inject the
treatment fluid stage into a fracture in the formation, and at a
rate wherein each substage is injected into the formation over a
period of time from 1 second to 2.5 minutes. In some embodiments,
the viscous fingering from one of the second modes breaks through
one of the first modes into another one of the second modes and/or
forms channels between islands of the first mode(s).
[0013] According to some embodiments, a system may comprise: a
subterranean formation penetrated by a wellbore; means for
injecting a treatment stage fluid above a fracturing pressure to
form a fracture in the formation; means for successively
alternating modes in the treatment stage fluid, in either order,
between at least first and second modes; wherein the first modes
have a high viscosity relative to the second modes for viscous
fingering of the second mode into the first mode in the fracture;
wherein the second modes have high reactivity with carbonate in the
formation relative to the first mode to unevenly etch surfaces of
the fracture; means for sustaining injection of the treatment stage
fluid during each of the first and second modes for a period of
time from 5 seconds up to 2.5 minutes; means for repeating the
successive alternation of modes for a plurality of cycles; and
means for reducing pressure to facilitate fracture closure and form
interconnected, hydraulically conductive channels between opposing
fracture surfaces.
[0014] In some embodiments, the first reactivity and viscosity
modes, or mode substages, comprise a viscoelastic diverting agent
and has a viscosity higher than that of the second reactivity and
viscosity modes, or mode substages.
[0015] In some embodiments, the treatment stage fluid comprises a
gel, a cross-linked gel, an emulsion, a foam, or a combination
thereof.
[0016] In some embodiments, the treatment stage fluid comprises a
solid material slurried in a carrier fluid.
[0017] In some embodiments, the treatment stage fluid comprises a
plurality of polyolefin beads having an average particle size
distribution of less than or equal to about 1000 microns (.about.20
mesh).
[0018] In some embodiments, one of the first and second reactivity
modes, or mode substages, comprises asphaltene, polylactic acid,
latex, or a combination thereof, and the other one of the first and
second reactivity modes, or mode substages, comprises a multivalent
cation.
[0019] In some embodiments, one of the first and second reactivity
modes, or mode substages, comprises an aqueous carrier fluid, and
the other one of the first and second reactivity modes, or mode
substages, comprises an oleaginous carrier fluid.
[0020] In some embodiments, the treatment stage fluid comprises a
water-in-oil emulsion wherein a reactant with carbonate in the
formation is in a dispersed phase.
[0021] According to some embodiments, a method may comprise:
injecting a treatment stage fluid above a fracturing pressure to
form a fracture in a subterranean formation penetrated by a
wellbore; successively alternating modes in the treatment stage
fluid, in either order, between at least first and second modes;
wherein the first modes have a high viscosity relative to the
second modes for viscous fingering of the second mode into the
first mode in the fracture; wherein the second modes have high
reactivity with carbonate in the formation relative to the first
mode to unevenly etch surfaces of the fracture; sustaining
injection of the treatment stage fluid during each of the first and
second modes for a period of time from 5 seconds up to 2.5 minutes;
repeating the successive alternation of modes for a plurality of
cycles; and reducing pressure to facilitate fracture closure and
form interconnected, hydraulically conductive channels between
opposing fracture surfaces. In some embodiments, the viscous
fingering from one of the second modes may break through one of the
first modes into another one of the second modes and/or to form
channels separating islands of the first mode(s).
[0022] In some embodiments, the relative reactivities with the
formation, the viscosities, and the like, of the two fluid modes
may be controlled to further improve fracture conductivity.
According to some embodiments, the relative proportions of the
fluid modes, or mode substages, injected, and/or the composition of
the two fluid mode, or mode substages, may be varied over time to
further improve the conductivity of the fracture. For example, in
some embodiments, a volumetric ratio of the first reactivity mode
or mode substage to the second reactivity mode or mode substage may
be from about 1:99 to about 99:1, such as by changing the injection
or pumping times and/or rates between the modes and/or mode
substages. In some embodiments, the sustained periods of time are
from about 5 seconds to about 1 minute.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] FIG. 1 illustrates the compartmentalization provided by
embodiments of the instant disclosure, relative to a comparative
example.
[0024] FIG. 2 illustrates the interpenetration or fingering of
fluids according to embodiments of the instant disclosure, relative
to a comparative example.
[0025] FIG. 3 illustrates the concentration profiles of different
phases of the fluids over time according to embodiments of the
instant disclosure.
[0026] FIG. 4 illustrates the effect of formation stabilization by
degradable polymers loaded into one of the fluids according to
embodiments of the instant disclosure.
[0027] FIG. 5 illustrates formation of absorbent aggregates in
domains in the presence of PLA fibers according to embodiments of
the instant disclosure.
[0028] FIG. 6 illustrates embodiments of the instant disclosure
wherein the mineral acid fluid is injected periodically into a
continuous gel phase.
[0029] FIG. 7 schematically illustrates a formation fracturing
system to implement a pumping sequence according to some
embodiments of the instant disclosure.
DETAILED DESCRIPTION
[0030] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure.
[0031] The description and examples are presented solely for the
purpose of illustrating the preferred embodiments and should not be
construed as a limitation to the scope. While the compositions are
described herein as comprising certain materials, it should be
understood that the composition could optionally comprise two or
more chemically different materials. In addition, the composition
can also comprise some components other than the ones already
cited. In the summary and this detailed description, each numerical
value should be read once as modified by the term "about" (unless
already expressly so modified), and then read again as not so
modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a concentration range listed or described as being useful,
suitable, or the like, is intended that any and every concentration
within the range, including the end points, is to be considered as
having been stated. For example, "a range of from 1 to 10" is to be
read as indicating each and every possible number along the
continuum between about 1 and about 10. Thus, even if specific data
points within the range, or even no data points within the range,
are explicitly identified or refer to only a few specific, it is to
be understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possession of the entire range and
all points within the range.
[0032] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description.
[0033] The term "treatment," or "treating," refers to any
subterranean operation that uses a fluid in conjunction with a
desired function and/or for a desired purpose. The term
"treatment," or "treating," does not imply any particular action by
or use of the fluid.
[0034] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture in the
rock formation around a well bore, by pumping fluid at very high
pressures (pressure above the determined closure pressure of the
formation), to increase production rates from a hydrocarbon
reservoir. The "formation" of a fracture includes either or both of
creating or initiating a new fracture or fracture branch as well as
propagating or extending a fracture.
[0035] The terms "acidizing," "etching" or "acid etching" refer to
the process and methods of dissolving or degrading a surface of a
geological formation such as a fracture, by any reactant which may
be, for example, an acid, acid precursor, a chelant or another
reactant or combination of reactants.
[0036] The term "proppant" includes proppant or gravel used to hold
fractures open and also includes gravel or proppant used in a
gravel packing and/or a frac-pack operation.
[0037] As used herein, the terms "treatment fluid" or "wellbore
treatment fluid" are inclusive of "fracturing fluid" or "treatment
slurry" and should be understood broadly. These may be or include a
liquid, a solid, a gas, and combinations thereof, as will be
appreciated by those skilled in the art. A treatment fluid may take
the form of a solution, an emulsion, an energized fluid (including
foam), slurry, or any other form as will be appreciated by those
skilled in the art.
[0038] "Carrier," "fluid phase" or "liquid phase" refer to the
fluid or liquid that is present in the fluid, including emulsions,
foams and energized fluids. Reference to "aqueous phase" refers to
a carrier phase comprised predominantly of water, which may be a
continuous or dispersed phase. As used herein the terms "liquid" or
"liquid phase" encompasses both liquids per se and supercritical
fluids, including any solutes dissolved therein.
[0039] As used herein, a blend of particles and a fluid may be
generally referred to as a slurry, an emulsion, or the like. For
purposes herein "slurry" refers to a mixture of solid particles
dispersed in a fluid carrier. An "emulsion" refers to a form of
slurry in which the particles are of a size such that the particles
do not exhibit a static internal structure, but are assumed to be
statistically distributed. In some embodiments, an emulsion is a
mixture of two or more liquids that are normally immiscible
(nonmixable or unblendable). For purposes herein, an emulsion
comprises at least two phases of matter, which may be a first
liquid phase dispersed in a continuous (second) liquid phase,
and/or a first liquid phase and one or more solid phases dispersed
in a continuous (second) liquid phase. Emulsions may be
oil-in-water, water-in-oil, or any combination thereof, e.g., a
"water-in-oil-in-water" emulsion or an "oil-in-water-in-oil"
emulsion.
[0040] The terms "energized fluid" and "foam" refer to a fluid
which when subjected to a low pressure environment liberates or
releases gas from solution or dispersion, for example, a liquid
containing dissolved gases. Foams or energized fluids are stable
mixtures of gases and liquids that form a two-phase system. Foam
and energized fluids are generally described by their foam quality,
i.e. the ratio of gas volume to the foam volume (fluid phase of the
treatment fluid), i.e., the ratio of the gas volume to the sum of
the gas plus liquid volumes). If the foam quality is between 52%
and 95%, the energized fluid is usually called foam. Above 95%,
foam is generally changed to mist. In the present patent
application, the term "energized fluid" also encompasses foams and
refers to any stable mixture of gas and liquid, regardless of the
foam quality. Energized fluids comprise any of: [0041] (a) Liquids
that at bottom hole conditions of pressure and temperature are
close to saturation with a species of gas. For example the liquid
can be aqueous and the gas nitrogen or carbon dioxide. Associated
with the liquid and gas species and temperature is a pressure
called the bubble point, at which the liquid is fully saturated. At
pressures below the bubble point, gas emerges from solution; [0042]
(b) Foams, consisting generally of a gas phase, an aqueous phase
and a solid phase. At high pressures the foam quality is typically
low (i.e., the non-saturated gas volume is low), but quality (and
volume) rises as the pressure falls. Additionally, the aqueous
phase may have originated as a solid material and once the gas
phase is dissolved into the solid phase, the viscosity of solid
material is decreased such that the solid material becomes a
liquid; or [0043] (c) Liquefied gases.
[0044] As used herein, reactivity refers to the relative rate at
which a material or treatment fluid in contact with a surface of a
formation can solubilize the carbonate minerals present in the
formation at downhole conditions; and in embodiments, the
reactivity may be measured by the rate of production of either
CO.sub.2 gas or calcium cation. A treatment fluid is essentially
non-reactive with the carbonate in the formation if it is no more
reactive than deionized water at a pH of 7.
[0045] In embodiments herein, a method comprises successively
alternatingly injecting a plurality of modes of a treatment stage
fluid through and/or from a wellbore into a fracture in a formation
wherein the modes have different reactivity properties to unevenly
etch surfaces of the fracture. As representative examples of a
two-mode method or system wherein a first mode or first mode
substage may be relatively less reactive than a second mode or
second mode substage where the second mode or second mode substage
may contain a reactant or combination of reactants to react with
carbonate in the formation, the less reactive first mode may (1) be
free of the reactant, (2) contain a lesser amount of the same
reactant, (3) contain a different reactant that is less reactive,
(4) contain a delayed form of the same or different reactant (which
may, after activation be more or preferably less reactive than the
reactant in the second mode), (5) contain a reaction inhibitor,
which may be either temporary or long lasting, (6) may contain a
protective coating former(s) or a system to form a temporary or
long-lasting coating to protect a formation surface from reaction,
e.g., a temporary or long-lasting coating that is inert to or
reacts with one or more reactant(s) in the first or second modes or
mode substages, or (7)
[0046] In some embodiments, the first fluid comprises mineral acid,
e.g., hydrochloric, sulfuric, hydrofluoric, phosphoric, nitric or
the like, including combinations. In some embodiments, the first
mode/substage, the second mode/substage, or both comprise a gel, a
cross-linked gel, or a combination thereof. For example, the
treatment stage fluid may have a continuous gel concentration and a
crosslinker may be alternately pulsed to form the cross-linked gel
in one of the modes/substages. In some embodiments, the second
fluid comprises a viscoelastic diverting agent. In some
embodiments, the first mode/substage, the second mode/substage, or
both comprise a C.sub.1-C.sub.40 carboxylic acid, a
C.sub.8-C.sub.40 phosphonic acid, a C.sub.8-C.sub.40 sulfonic acid,
or a combination thereof. In some embodiments, the first
mode/substage, the second mode/substage, or both comprise a
C.sub.8-C.sub.36 saturated carboxylic acid. In some embodiments,
the first mode/substage, the second mode/substage, or both comprise
a C.sub.8-C.sub.40 amine.
[0047] In some embodiments, the first mode/substage, the second
mode/substage, or both comprise a solid material, e.g., proppant,
fiber, pillar reinforcement material, fluid loss control material,
etc. In some embodiments, the first mode/substage, the second
mode/substage, or both comprise a plurality of polyolefin beads
having an average particle size distribution of less than or equal
to about 1000 microns (.about.20 mesh). In some embodiments, at
least one of the first mode/substage, the second mode/substage, or
both comprise asphaltene, polylactic acid, latex, or a combination
thereof, and another one of the first mode/substage, the second
mode/substage, or both comprise a multivalent cation.
[0048] In some embodiments, one of the first mode/substage, the
second mode/substage, or both comprise an aqueous carrier fluid and
the other one of the first mode/substage, the second mode/substage,
or both comprise an oleaginous carrier fluid. In some embodiments,
the first mode/substage, the second mode/substage, or both comprise
an emulsion, e.g., a water-in-oil emulsion, an oil-in-water
emulsion, a water-in-oil-in-water emulsion, an oil-in-water-in-oil
emulsion, or the like, and in some embodiments, wherein mineral
acid is present in a dispersed phase.
[0049] In some embodiments, one of the first and second modes or
substages is reactive with the carbonate in the formation and the
other of the first and second modes or substages is essentially
non-reactive with the carbonate in the formation.
[0050] In some embodiments, a viscosity of one of the first and
second modes or substages is greater than the other of the first
and second modes or substages.
[0051] In some embodiments, a volumetric ratio of a first
low-reactivity, high-viscosity mode, low viscosity mode/substage
relative to the second high-reactivity, low viscosity mode/substage
is from about 1:99 to about 99:1, or from about 1:20 to 20:1, or
from about 1:1 to about 1:20, or from about 1:1 to about 1:10 or
from about 1:2 to about 1:10, or from about 1:3 to about 1:10. In
some embodiments, the volumetric ratio of the first mode/substage
relative to the second mode/substage is varied between successive
injections. In some embodiments, the reactivity of the first
mode/substage, the reactivity of the second mode/substage, or both,
are varied between successive injections.
[0052] In some embodiments, the sustained period of time of the
injections of the first and/or second modes/substages or both are
from about 5 or 10 seconds to about 150 or 120, or 90, or 60, or 30
or 20 seconds, e.g., from 10 to 30 seconds or 10 to 20 seconds.
[0053] As used herein, the switching time or sustained period of
time refers to the lag time between injections of the different
modes/substages, e.g., the time for injection of the particular
mode/substage. In embodiments, the switching time is sufficiently
long to avoid complete mixing between successive pulses and retain
distinct slugs of alternate fluids.
[0054] FIG. 1 shows the compartmentalizing feature of the alternate
phases of the fluids within the fracture extending radially from
wellbore 10, e.g., an initial viscosified pad stage, and a
treatment fluid stage having a reactive mode and a viscosified
mode. The upper panel represents conventional or comparative
methods where, after the initial pad stage 12, the switch between
the reactive modes 14 and the viscosified modes 16 is on the time
domain of 10 minutes or more. The lower panel shows embodiments of
the instant disclosure, where after the initial pad stage 22, the
switch between the reactive modes 24 and the viscosified modes 26
is less than 2.5 minutes, e.g., less than or equal to 1 minute,
less than or equal to 30 seconds, or less than or equal to about 20
seconds.
[0055] In embodiments, at least one pump is used to inject the
fluids. In embodiments, the portioning of the injected fluids
comprises gate switching of the input and/or output of the pumping
and blending apparatus.
[0056] A drawback of using a mineral acid such as HCl, in one form
or another, in fracture acidizing heretofore is its inability to
generate fracture with desired length, primarily due to the rapid
reaction rate of the acid with the carbonate rock surface in
particular at higher reservoir temperatures. Embodiments disclosed
herein take advantage of the rapid reaction rate of the acid,
within a confined elongated space to generate corresponding
elongated fractures.
[0057] In embodiments, the method utilizes at least two fluids
which differ with respect to reactivity with the carbonate
formation, viscosity, density, composition, and/or the like. For
purposes of simplicity and illustration, the following discussion
refers to first and second fluids in reference to both the
respective first and second modes of the treatment stage fluid in
the method, as well as respective first and second mode substages
of the treatment fluid stage in the system. The terms "modes" and
"substages" and "fluids" in this sense are used interchangeably.
While the discussion herein refers to the first fluid as having a
lower reactivity and/or higher viscosity and the second fluid as
having a higher reactivity and/or lower viscosity by way of example
and illustration, the designations "first" and "second" are for
reference only and do not imply any particular order of injection.
For example, if a relatively viscous, essentially inert pad stage
is employed in advance of the treatment fluid stage, the initial
mode or substage of the treatment stage fluid immediately following
the pad stage may be either the "second" fluid having a higher
reactivity and/or lower viscosity, or the "first" fluid having a
lower reactivity and/or higher viscosity. Further, combinations of
high-reactivity, high-viscosity first fluids and low-reactivity,
low-viscosity second fluids are also contemplated.
[0058] In embodiments, the more reactive fluid comprises a mineral
acid. Suitable mineral acids include hydrochloric acid, sulfuric
acid, nitric acid, phosphoric acid, boric acid, hydrofluoric acid,
hydrobromic acid, and/or perchloric acid. In embodiments, the
mineral acid is hydrochloric acid. For purposes herein, embodiments
which refer to HCl are to be interpreted as the same embodiment
comprising a mineral acid, and are not limited to HCl unless
expressly indicated as such. Accordingly, HCl and mineral acid are
used interchangeably herein.
[0059] In embodiments, the first fluid may be at least partially
soluble in the second fluid. In other embodiments, the first fluid
may be at least partially miscible with the second fluid. In other
embodiments, the first fluid may be immiscible with the second
fluid.
[0060] In embodiments, the first fluid comprises one or more
components which render the first fluid more reactive to the
composition of the formation as compared to the second fluid. In
embodiments, the first fluid reacts with the formation (e.g., a
carbonate formation) at a first reaction rate according to the
equation:
First reaction rate=k.sub.1*[first fluid mode]
where k.sub.1 is the rate constant; and
[0061] the second fluid reacts with the formation (e.g., a
carbonate formation) at a second reaction rate according to the
equation:
Second reaction rate=k.sub.2*[second fluid mode]
where k.sub.2 is the rate constant. In embodiments, the first
reaction rate is greater than the second reaction rate. In
embodiments, the second reaction rate is essentially zero. Stated
in other terms, in embodiments, the second fluid is essentially
non-reactive with respect to the formation under the conditions
present.
[0062] In embodiments, a fracturing fluid system comprises at least
two discrete phases. One of the phases comprises an inorganic acid,
e.g., HCl, which may be present as an aqueous solution, or which
may be a dispersed phase of a water-in-oil emulsion. The other
phase is less reactive, or essentially inert, with respect to the
carbonate surfaces of the formation.
[0063] Accordingly, in embodiments, the first fluid comprises an
aqueous carrier fluid and the second fluid comprises an aqueous
carrier fluid. In other embodiments, the first fluid comprises an
aqueous carrier fluid and the second fluid comprises an oleaginous
carrier fluid. In still other embodiments the first fluid comprises
an oleaginous carrier fluid and the second fluid comprises an
aqueous carrier fluid. In still other embodiments, the first fluid
comprises an oleaginous carrier fluid and the second fluid
comprises an oleaginous carrier fluid. In embodiments, the first
fluid, the second fluid, or both may comprise an emulsion,
particulates, proppant, anchorants, fibers, flakes, and/or the
like.
[0064] The method further comprises employing a sequential pumping
schedule with relatively short intervals i.e., less than 2.5
minutes or less than one minute, for example, 10-20 seconds, or a
rapid frequency of pulsing one fluid then the next fluid
sequentially to generate a fluid stream having relatively slim
"strips" or relatively small portions of the two phases in the
essentially continuous fluid stream being delivered to the
wellbore. In embodiments, a lower viscosity acid phase will
intermix in a non-uniform manner, e.g. via fingering, into the
preceding less reactive phase. In embodiments, the less reactive
phase or fluid comprises a gel phase. The intermixing or fingering
achieves an extensive penetration rendering the pad phase into
discrete "pockets" or "islands". Hence the rock surface of the
formation will not be contacted with all of the acid present in a
particular portion of the fluid stream and thus, will not be
consumed by the acid, serving as the pillar in the fracture.
[0065] FIG. 2 compares a conventional method with embodiments
according to the instant disclosure, showing the interpenetration
of low-viscosity and high-viscosity fluid modes 14, 16 in the form
of fingering 18 caused by the viscosity differential between the
first mode fluid 16 and the second mode fluid 18 in a comparative
method where the slugs are relatively large, versus the
interpenetration of low-viscosity and high-viscosity fluid modes
24, 26 in the form of fingering 28 caused by the viscosity
differential between the first mode fluid 26 and the second mode
fluid 28 according to embodiments of the instant disclosure, having
much shorter pumping intervals. The resultant isolated islands of
the second fluid modes 26 serve as masks to shield the rapid
etching reaction on formation surface, hence leading to pillars and
other heterogeneous formations.
[0066] In embodiments, the relative phase viscosities of the two
fluids may be determined according to: "The Unstable Displacement
Theory ("A Method for Predicting the Performance of Unstable
Miscible Displacement in Heterogeneous Media," E. J. Koval, SPE
450-PA, volume 3, #2, pp. 145-154, 1963), which may be adapted
according to the present disclosure by one having minimal skill in
the art.
[0067] In addition, the brief retention time of HCl at any given
location as a result of the rapidly moving discrete portions of the
fluids along the fracture also serves to minimize the spend rate of
HCl on a given carbonate surface within the fracture. Accordingly,
in embodiments, the method may include providing a rapidly pulsing
fracturing pump system to sequentially, and repetitively, inject
two or more phases of distinct viscosity and/or acidity at
desirable frequencies modulated by, for example, a programmable
logic control board, and/or using a programmable digital
attenuator, and/or the like, without switching on and then
switching off various pumps which inevitably delays pumping rate
changes, and which results in much broader intervals of fluids, and
thus lacks the level of intermixing achieved by embodiments
according to the present disclosure.
[0068] As shown in FIG. 3, the concentration profiles of different
fluid modes 24, 26 alternate over time. The overlapping portions of
the fluid modes 24, 26 indicate the intermixing of the two fluids
in the treatment fluid that may be produced, e.g., in the wellbore
in transit to the formation, according to some embodiments of the
instant disclosure.
[0069] Suitable gels include both aqueous gels and non-aqueous or
oleaginous gels, which may include one or more gellants dispersed
or at least partially dissolved in a carrier fluid. In embodiments,
the second fluid comprises hydratable gels, e.g., gels containing
polysaccharides such as guars, xanthan and diutan,
hydroxyethylcellulose, polyvinyl alcohol, other hydratable
polymers, colloids, and the like; or an oil-based gelled fluid or
otherwise viscosified oil. In embodiments, the second fluid may
comprise an at least partially cross-linked gel to further increase
the viscosity of the second fluid.
[0070] In embodiments, the first fluid may comprise a mineral acid
and the second fluid may comprise a gel and/or one or more organic
acids. In embodiments, the first fluid (the acid phase) contains an
appropriate level of HCl concentration from about 1 wt % to about
35 wt %, and pumped in between portions of the second fluid
comprising organic acids. Organic acids suitable for use herein
include those having from 1 to 40 carbon atoms, may be saturated
and/or unsaturated, and may comprise aliphatic and/or aromatic
moieties, and a carboxyl group, a sulfonic acid group, a phosphonic
acid group, and/or the like characterized in that the proton(s) of
the acid is only partially dissociable. Accordingly, the organic
acids are selected for being weakly acidic. These organic acids
form salts and thus attach to the carbonate formation. In addition,
the organic acids may be selected to function as masking agents to
HCl. In embodiments, the organic acids may contain an alkyl chain
having from about 8 to 30 carbon atoms, which repels HCl from
accessing the carbonate surface underneath. These materials,
including C.sub.8-C.sub.40 alkylcarboxylic acid such as
octadecanoic acid, C.sub.8-C.sub.40 alkylphosphonic acid such as
octadecylphosphonic acid, and/or C.sub.8-C.sub.40 alkylsulfonic
acid such as octadecylsulfonic acid, or their polymerized versions.
In embodiments, the organic acids are selected for an ability to
bind to the carbonate surface at the cationic sites through a
self-assembly mechanism, while their alkyl chains forming a
hydrophobic barrier inhibiting the access of HCl to the formation,
thus reducing the spend rate of the HCl or other mineral acid
present in the first fluid.
[0071] In embodiments, the first fluid comprises a mineral acid and
the second fluid comprises one or more degradable polymers or one
or more degradable polymers in addition to a gel.
[0072] Suitable degradable polymers may include, but are not
limited to, polyethylene, polyhydroxyalkanoates,
poly[R-3-hydroxybutyrate],
poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate],
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based
polymers, polylactic acid and copolyesters, aliphatic-aromatic
polyesters, poly(.epsilon.-caprolactone), polyethylene
terephthalate, polybutylene terephthalate; proteins such as
gelatin, wheat and maize gluten, cottonseed flour, whey proteins,
myofibrillar proteins, caseins, and combinations thereof. The
degradable polymers may degrade through thermal, optical and/or
biological routes and may take the form of fiber, bead, flake
and/or the like. In embodiments, the degradable polymer may
comprise acidic polymers, for example polylactic acid (PLA),
polyglycolic acid (PGA), copolymers thereof, and the like. In
embodiments, the degradable polymers are selected according to a
rate of hydrolysis such that they facilitate sustainable
conductivity into the fracture via reducing the spend rate of the
mineral acid through delayed hydrolysis.
[0073] In embodiments, the first fluid comprises a gellant in
combination with the mineral acid. Accordingly, the viscosity of
the first fluid may be increased to further mask the mineral acid
thus further delaying the contact of the mineral acid with the
formation. In embodiments, the gelled first fluid may be utilized
with a gelled second fluid, and/or a crosslinked gelled second
fluid.
[0074] In embodiments, the first fluid may comprise a gelled
mineral acid and the second phase may comprise an organic acid as
described herein. In some embodiments, the second fluid may
comprise a solid acid such as polylactic acid, polyglycolic acid,
citric acid, sulfamic acid or the like, including combinations. In
embodiments the second fluid may additionally or alternatively
comprise chelants. Likewise, in embodiments, the first fluid may
comprise a gelled mineral acid and the second fluid may comprise a
degradable polymer, a gel, and/or the like as described herein.
[0075] In embodiments, one of the first and second fluids may
comprise a mineral acid present as a dispersed phase of a
water-in-oil emulsion in an oleaginous first fluid. Examples of an
emulsified mineral acid include emulsions available under the trade
designation SUPER X* EMULSION.TM. (Schlumberger, Houston, Tex.),
which is a 70:30 HCl-in-oil dispersion. In embodiments, the second
emulsified mineral acid fluid may be utilized with another fluid
such as gelled fluid, a crosslinked fluid, a fluid comprising
organic acids, a second fluid comprising degradable polymers, or
any combination thereof.
[0076] In embodiments, the first fluid may comprise a mineral acid
and may further comprise one or more organic acids, one or more
degradable polymers, one or more water soluble polymers, and/or the
like. In embodiments, the organic acids and/or degradable polymers
may be selected to comprise a slower rate of hydrolysis, most
likely after the spending of HCl, creating lasting reactivity in
the acid fluid and hence, improved heterogeneity within the
formation surface initially occupied by the mineral acid fluid. The
presence of weaker acid species in the first fluid results in a
portion of the carbonate surface having reduced exposure to the
mineral acid, which further reduces the spend rate of the mineral
acid.
[0077] Degradable polymers and/or water soluble polymers of various
configurations and compositions (e.g., fibers, beads, flakes and
the like) may be selected to function analogously to organic acids
of comparable molecular weight, but which may have even slower
hydrolysis rates as compared to organic acids. Water soluble
polymers may further serve to modulate the viscosity of the first
mineral acid fluid to provide improved control over the extent of
fingering into the second fluid. In addition, such polymeric
species selected for their slow rates of hydration may also
contribute to control the rate of leak-off and other issues
prevalent during acid fracturing of carbonate formations.
[0078] In embodiments, the degradable polymers and/or water soluble
polymers may be selected for having slow rates of hydration to
provide support to formation strength, which may be particularly
beneficial for those regions weakened by mineral acid etching and
on a larger scale to so-called soft formations. In embodiments,
degradable polymers may be selected for having a percolation
threshold which does not weaken the rock subsequent to HCl leak
off, such that they also provide for additional conductivity
between the formation and the wellbore.
[0079] FIG. 4 illustrates the effect of formation stabilization by
the degradable polymers 28 loaded in the first mode fluid 24.
Subsequent to fluid leak off and closure between the fracture
surfaces 30, 32, these slowly hydrating species provide mechanical
support to the regions 34 weakened by mineral acid etching.
[0080] In embodiments, the first fluid may further include a
plurality of degradable polymers selected to provide extended
release of acidic species upon hydrolysis, and hence provide
continuous etching of the carbonate surface. Up to the point where
the hydrolysis takes place, these species act as a temporary mask
for the carbonate surfaces underneath, thereby reducing the spend
rate of the acid and providing improved heterogeneity to the
conductive channels.
[0081] In embodiments, the second fluid may comprise a viscoelastic
diverting agent (VDA) which leads to differential reactivities in
the fingering regions against the rest of the phase. Suitable VDA
include anionic surfactants which form a thin film of viscous fluid
on the formation surface, hence retarding the mineral acid
reactivity when present. By further shielding discrete portions of
formation, the presence of a viscoelastic diverting agent further
enhances the formation of discrete islands or columns resultant
from fingering of the first fluid into the second fluid.
[0082] In embodiments, suitable viscoelastic diverting agents may
include anionic surfactants, which include alkyl sulfates, alkyl
ether sulfates, alkyl ester sulfonates, alpha olefin sulfonates,
linear alkyl benzene sulfonates, branched alkyl benzene sulfonates,
linear dodecylbenzene sulfonates, branched dodecylbenzene
sulfonates, alkyl benzene sulfonic acids, dodecylbenzene sulfonic
acid, sulfosuccinates, sulfated alcohols, ethoxylated sulfated
alcohols, alcohol sulfonates, ethoxylated and propoxylated alcohol
sulfonates, alcohol ether sulfates, ethoxylated alcohol ether
sulfates, propoxylated alcohol sulfonates, sulfated nonyl phenols,
ethoxylated and propoxylated sulfated nonyl phenols, sulfated octyl
phenols, ethoxylated and propoxylated sulfated octyl phenols,
sulfated dodecyl phenols, ethoxylated and propoxylated sulfated
dodecyl phenols. In embodiments, the viscoelastic diverting agents
includes dodecylbenzene sulfonic acid.
[0083] In embodiments, suitable viscoelastic diverting agents may
include nonionic surfactants, which may include amine oxides,
ethoxylated or propoxylated alkyl phenols such as dodecyl phenols,
decyl phenols, nonyl phenols, and octyl phenols, etc., ethoxylated
or propoxylated primary linear C.sub.4 to C.sub.20 alcohols,
polyethylene glycols of all molecular weights and reactions, and
polypropylene glycols of all molecular weights and reactions.
[0084] In embodiments, suitable viscoelastic diverting agents may
include hydrotropic surfactants, which may include dicarboxylic
acids, phosphate esters, sodium xylene sulfonate, and/or sodium
dodecyl diphenyl ether disulfonate.
[0085] In embodiments, the second fluid may include one or more
weak organic bases, such as amine-containing species. The
accelerated reaction between the mineral acid present in the first
fluid and the organic base present in the second fluid directs the
spending of the mineral acid along the second fluid while retarding
its spending toward the carbonate surface of the formation. In
addition, the reaction between the mineral acid and the carbonate
formation raises the localized pH of the fluid. In embodiments, the
organic base may be selected such that this increase in pH is
sufficient to precipitate the organic base onto the carbonate
surface, thus further masking the surface and preventing further
consumption of the mineral acid.
[0086] In embodiments, the second fluid may comprise saturated
fatty acids, which produce a thin film of hydrophobic coatings on
the carbonate surface upon attachment to cationic sites present on
the formation, which thus serve to reduce the consumption rate of
mineral acid as subsequent portions of the first fluid contact the
formation.
[0087] In embodiments, the first fluid, the second fluid, or both
may comprise a solid particulate, which may include a proppant. In
embodiments, the first fluid, the second fluid, or both may
comprise an amount of plastic beads. In embodiments, the plastic
beads comprise an average particle size distribution of less than
or equal to about 1000 microns. In embodiments, the plastic beads
have a size domain of 20-40 mesh, or 40-70 mesh, such that the
beads function as near-permanent pillars in the formation after the
decomposition of the second fluid, to facilitate the formation of a
conductive network. In embodiments, the beads comprise polystyrene,
polyethylene, polypropylene, poly(methyl methacrylate), and/or the
like.
[0088] In embodiments, the first fluid, the second fluid, or both
may include amounts of one or more solid filler(s) having particle
size distributions, and present at concentrations suitable for the
modulation or control of a leak-off rate of one or more of the
fluids. In embodiments, the solid fillers may be selected to
control the viscosity differential between the two phases, and the
like.
[0089] FIG. 5 shows aggregation in the fracture 36 of the particles
into domains 38A, 38B, 38C, 38D of various morphologies in the
presence of PLA fibers, which produce a conductive channel
network.
[0090] In embodiments, the treatment fluid produced according to
the instant disclosure is formed by pumping of rapidly alternating
oil and mineral acid phases, in the absence of any surfactant or
solid species. Such embodiments induce sufficient differential
rates of etching on carbonate surface that lead to conductive
channel network and also produce a clean fracture ready for further
treatment and/or subsequent completion operations.
[0091] In embodiments, the treatment fluid produced according to
the instant disclosure is formed by pumping of rapidly alternating
non-aqueous second fluids and mineral acid containing first fluids,
where the second fluid comprises an appropriate concentration of a
bifunctional species having at least one terminal moiety having
affinity toward carbonate surfaces, while the other moiety
functions as a masking agent to the mineral acid fluid. Suitable
moieties which function as masking agents include polar
hetero-aromatic molecules comprising oxygen, nitrogen and/or sulfur
atoms. Suitable moieties which may function as masking agents may
comprise C.sub.8-C.sub.40 alkyl chains.
[0092] In embodiments, the bifunctional species may comprise
asphaltenes and/or structural analogues thereof. Asphaltenes may be
present as granules, flakes, and/or as fibers. In embodiments, the
phase change behavior of asphaltenes may be modulated using various
combinations of solvents, and the presence of multivalent (high
valent) cations (e.g. Al.sup.3+, Fe.sup.3+), and/or precipitation
inhibitors, which may be controlled by fluid placement as exerted
through pumping. Accordingly, in embodiments, the composition of
one or more of the fluids may be controlled to deliver components
which produce the onset of asphaltene precipitation at a desirable
timing, and hence the location in the fracture. In such
embodiments, the extent of aggregation may be controlled to produce
a patch size, as well as an interval between individual patches to
further maximize a sustained conductivity for the formation fluids.
In embodiments, the first fluid, the second fluid, or both may
further include PLA and/or latex in the form of fibers, flakes
and/or beads to further facilitate aggregation of the
aforementioned adsorbents into tightly packed domains that results
in a network of conductive channels with high and sustaining
performances. Accordingly, in embodiments, at least one of a
plurality of second portions comprise asphaltene, polylactic acid,
latex, or a combination thereof, and another of the plurality of
second portions comprise a multivalent cation.
[0093] In embodiments, especially wherein a formation may comprise
a mixture of carbonate and clay minerals, the treatment fluid
produced according to the instant disclosure is formed by pumping
rapidly alternating non-aqueous second fluids and HCl containing
first fluids, where the second fluids further comprise species
having preferential affinity toward a negatively charged clay
surface. Suitable species include quaternary amines, which may
include mono, di and/or tri aliphatic chains with carbon numbers
between 10 and 30, for example, between 12 and 24, which are
selected to anchor the component on the clay, such that the
expansive aliphatic chains produce a kinetic barrier (i.e., a mask)
to the mineral acid.
[0094] In embodiments, a volume to volume ratio of individual
portions of the first fluid injected relative to a subsequent or
preceding portion of the second fluid is from about 1:99 to about
99:1, for example, 1:9 to 9:1, or 1:5 to 5:1, or 1:3 to 3:1 or 2:1
to 1:2. In embodiments, the treatment fluid according to the
instant disclosure is produced by pumping portions of the fluids at
a constant ratio to one another. For example, in embodiments, the
volumetric ratio of the first fluid pumped relative to the second
fluid is held constant at 1:3, or 1:2, or 1:1, or 2:1, or 3:1,
etc.
[0095] In another embodiment, the treatment fluid according to the
instant disclosure is produced by pumping the various fluids such
that a volume ratio of the portion of the first fluid injected
relative to the portion of the second fluid injected into the
wellbore increases (or decreases), e.g., linearly and/or
exponentially over a period of time and/or between successive
stages or pulses.
[0096] In another embodiment, the treatment fluid according to the
instant disclosure is produced by pumping the various fluids such
that a volume ratio of the portion of the first fluid injected
relative to the portion of the second fluid injected into the
wellbore is varied in blocks or other intervals over a period of
time or between successive stages or pulses.
[0097] In embodiments, the concentration of a first component
present in the first fluid, a second component present in the
second fluid, or both, vary over a period of time. In embodiments,
the concentration of a particular component may increase (or
decrease), e.g., linearly or exponentially over a period of time or
between successive stages, and/or may be varied in blocks or other
discrete intervals over a period of time or between successive
stages.
[0098] In embodiments, the acid concentration in the first fluid is
incrementally increased (or decreased) along the pumping sequence,
such that the acid capacity at the early acid stages is partially
retarded, thus minimizing undue damage to the formation surface
while pumping.
[0099] In embodiments, the first fluid is pumped directly into the
continuously pumping second fluid. Accordingly, the rapid cycling
comprises forming discrete intervals of the acid phase in a
continuous gel or other second fluid phase. In such embodiments,
the mineral acid may be gelled upon mixing with the second fluid,
hence retarding acid reactivity.
[0100] FIG. 6 shows such another pumping scheme in which a
continuous viscosified mode 40 of a treatment stage fluid is pumped
while a reactivity mode 42, e.g., such as HCl, is injected
periodically. The rate of pulses between the two phases is in the
time domain, for example, of less than 2.5 minutes, or less than
about 1 minute, or less than or equal to about 30 seconds.
[0101] Likewise, in embodiments, the second fluid may be
intermittently pumped into a continuously pumped first fluid acid
phase. In such embodiments, the difference in the reactivities of
the two fluids results in heterogeneous etching rates on carbonate
surfaces and therefore improves conductivity in the formation. Such
embodiments may be suitable when acid species having slower
reaction rates, such as formic acid, acetic acid, and so on are
employed in the first fluid, and/or in acid fracturing formations
having relatively lower temperatures wherein acid spend rate are
not as prevalent.
[0102] With reference to FIG. 7, a system 50 used to implement a
pumping sequence according to embodiments of the instant disclosure
may include a pump system 52 comprising one or more pumps to supply
the alternating viscosity and/or reactivity slugs 54, 56 to the
wellbore 58 and fracture 60. In embodiments as illustrated, the
wellbore 58 may include a substantially horizontal portion 58A,
which may be cased or completed open hole, wherein the fracture 60
is transversely or longitudinally oriented and thus generally
vertical or sloped with respect to horizontal. A switching station
62 in some embodiments may be provided at the surface to supply
feed line 64 with various modes of treatment fluids and/or
components from sources 66, 68, 70, 72 which may for example be
premixed pad, treatment, transition and/or flush stage fluids,
and/or a carrier fluid and neat or concentrated masterbatches of
acid(s) or other reactant(s) and viscosifier(s) to allow reliable
alternation of reactivity and/or viscosity modes, and any other
additives which may be supplied with or in any of the sources 66,
68, 70, 72, in any order, such as, for example, proppants,
crosslinkers, loss control agents, friction reducers, clay
stabilizers, biocides, breakers, breaker aids, corrosion
inhibitors, and/or proppant flowback control additives, or the
like. In some embodiments, concentrations of one or more additives,
including other or additional reactants and/or viscosifiers, to the
fracturing fluid may be alternated, e.g., in addition to
alternating acid or chelant concentration. For example breaker for
the carrier fluid may be added only to high-viscosity mode fluid,
or a higher breaker concentration may be added to high-reactivity
mode fluid and a lower breaker concentration may be added to
high-viscosity mode fluid. Two or more additives (including
reactants and/or viscosifiers) may also be alternated
independently.
[0103] A programmable controller 74, which may be a programmable
logic control board, digital attenuator or the like, may be
provided in some embodiments to modulate the frequency of rapidly
pulsing for the sequential and repetitive injection of two or more
modes of distinct reactivity and/or viscosity. The well may if
desired also be provided with a shut in valve 76 to maintain
pressure in the wellbore 58 and fracture 60, flow-back/production
line 78 to flow back or produce fluids either during or
post-treatment, as well as any conventional wellhead equipment.
[0104] In some embodiments, the system 50 may be or include
blenders commercially available under the trade designations
PodSTREAK.TM. or SuperPOD.TM. or the like, with appropriate gate
switch pulsing.
Embodiments
[0105] As is evident from the disclosure herein, a variety of
embodiments are contemplated: [0106] E1. A method comprising:
injecting a treatment stage fluid into a subterranean formation
above a fracturing pressure to form a fracture in the formation;
successively alternating reactivity modes in the treatment stage
fluid, in either order, between at least first and second
reactivity modes to react with carbonate in the formation at
different rates or times to unevenly etch surfaces of the fracture;
sustaining injection of the treatment stage fluid during each of
the first and second reactivity modes for a period of time from 1
second up to 10 minutes; repeating the successive alternation of
reactivity modes for a plurality of cycles; and reducing pressure
to facilitate fracture closure and form interconnected,
hydraulically conductive channels between opposing fracture
surfaces. [0107] E2. The method of Embodiment E1, wherein one of
the first and second reactivity modes comprises a reactant reactive
with the carbonate in the formation and the other of the first and
second reactivity modes comprises the reactant at a lesser
concentration, or in a less reactive form, or is free of the
reactant. [0108] E3. The method of Embodiment E2, wherein the
reactant is selected from the group consisting of mineral acids,
organic acids, chelants and combinations thereof. [0109] E4. The
method of Embodiment E2 or Embodiment E3, wherein the reactant
comprises a solid acid. [0110] E5. The method of any one of
Embodiments E2 to E4, wherein the reactant comprises HCl. [0111]
E6. The method of any one of Embodiments E2 to E5, wherein the
reactant is encapsulated. [0112] E7. The method of any one of
Embodiments E2 to E6, wherein the reactant is selected from
C.sub.1-C.sub.40 organic acids to form a coating on the surfaces of
the fracture to inhibit further reaction on the coated surfaces.
[0113] E8. The method of Embodiment E7, wherein the organic acid is
selected from carboxylic acids, phosphonic acids, sulfonic acids
(including methane sulfonic acid), and combinations thereof. [0114]
E9. The method of Embodiment E8, wherein the organic acid comprises
a C.sub.8-C.sub.36 organic acid. [0115] E10. The method of any one
of Embodiments E7 to E9 wherein the first reactivity modes comprise
the organic acid and the second reactivity modes comprise a mineral
acid, wherein the second reactivity modes are more reactive with
the carbonate in the formation relative to the first reactivity
modes. [0116] E11. The method of any one of Embodiments E1 to E10
wherein the first reactivity modes comprise a weak organic base to
coat surfaces of the fracture to inhibit reaction on the coated
surfaces with a subsequent one of the second reactivity modes.
[0117] E12. The method of Embodiment E11, wherein the weak organic
base comprises a C.sub.8-C.sub.40 amine or ammonium, or a
combination thereof. [0118] E13. The method of any one of
Embodiments E1 to E12, further comprising: successively alternating
viscosity modes in the treatment stage fluid, in either order,
between at least first and second viscosity modes, wherein one of
the first and second viscosity modes has a higher viscosity than
the other; sustaining injection of the treatment stage fluid during
each of the first and second modes for a period of time from 1
second up to 10 minutes; and repeating the successive alternation
of viscosity modes for a plurality of cycles. [0119] E14. The
method of Embodiment E13, wherein the relatively low viscosity
modes form fingers penetrating into a respective one of any
preceding high viscosity mode in the fracture. [0120] E15. The
method of Embodiment E14, wherein the fingers break through the
penetrated high viscosity mode into a preceding low viscosity mode.
[0121] E16. The method of Embodiment E14 or Embodiment E15 wherein
the fingers form channels between islands of the high viscosity
modes. [0122] E17. The method of any one of Embodiments E13 to E16,
wherein the first and second reactivity modes coincide with the
first and second viscosity modes, respectively. [0123] E18. The
method of Embodiment E17, wherein the first modes comprise a high
viscosity and low reactivity relative to the second modes. [0124]
E19. The method of Embodiment 18, wherein the first mode comprises
a viscoelastic diverting agent. [0125] E20. The method of any one
of Embodiments E1 to E19, wherein the treatment stage fluid
comprises a gel, a cross-linked gel, an emulsion, a foam, or a
combination thereof. [0126] E21. The method of any one of
Embodiments E1 to E20, wherein the treatment stage fluid comprises
a solid material slurried in a carrier fluid. [0127] E22. The
method of Embodiment E21, wherein the treatment stage fluid
comprises a plurality of polyolefin beads having an average
particle size distribution of less than or equal to about 1000
microns (.about.20 mesh). [0128] E23. The method of any one of
Embodiments E1 to E22, wherein one of the first and second
reactivity modes comprises asphaltene, polylactic acid, latex, or a
combination thereof, and the other one of the first and second
reactivity modes comprises a multivalent cation. [0129] E24. The
method of any one of Embodiments E1 to E23, wherein one of the
first and second reactivity modes comprises an aqueous carrier
fluid, and the other one of the first and second reactivity modes
comprises an oleaginous carrier fluid. [0130] E25. The method of
any one of Embodiments E1 to E24, wherein the treatment stage fluid
comprises a water-in-oil emulsion wherein a reactant with carbonate
in the formation is in a dispersed phase. [0131] E26. The method of
any one of Embodiments E1 to E25, further comprising gelling the
first reactivity mode, the second reactivity mode or both in the
fracture. [0132] E27. The method of any one of Embodiments E1 to
E26, wherein a volumetric ratio of the first reactivity mode to the
second reactivity mode is from about 1:99 to about 99:1. [0133]
E28. The method of any one of Embodiments E1 to E27, wherein the
sustained periods of time are from about 5 seconds to about 1
minute. [0134] E29. The method of any one of Embodiments E1 to E28,
further comprising injecting a pad stage in advance of the
treatment fluid stage, injecting a terminal flush stage, or a
combination thereof. [0135] E30. A method comprising: injecting a
treatment stage fluid above a fracturing pressure to form a
fracture in a subterranean formation penetrated by a wellbore;
successively alternating modes in the treatment stage fluid, in
either order, between at least first and second modes; wherein the
first modes have a high viscosity relative to the second modes for
viscous fingering of the second mode into the first mode in the
fracture; wherein the second modes have high reactivity with
carbonate in the formation relative to the first mode to unevenly
etch surfaces of the fracture; sustaining injection of the
treatment stage fluid during each of the first and second modes for
a period of time from 5 seconds up to 150 seconds; repeating the
successive alternation of modes for a plurality of cycles; and
reducing pressure to facilitate fracture closure and form
interconnected, hydraulically conductive channels between opposing
fracture surfaces. [0136] E31. The method of Embodiment E30,
wherein the viscous fingering from one of the second modes breaks
through a respective preceding one of the first modes into a
preceding one of the second modes to form channels between islands
of the respective preceding first modes. [0137] E32. The method of
Embodiment E30 or Embodiment E31, wherein the first modes comprise
gel and the second modes comprise mineral acid. [0138] E33. The
method of Embodiment E32, wherein the gel is crosslinked. [0139]
E34. The method of Embodiment E32 or E33, wherein the second modes
comprise gel. [0140] E35. The method of Embodiment E34, wherein the
gel in the second modes is crosslinked. [0141] E36. The method of
any one of Embodiments E30 to E35, wherein the first modes comprise
an organic acid having from 1 to 40 carbon atoms. [0142] E37. The
method of Embodiment E36, wherein the organic acid in the first
mode forms a coating on the fracture surface to inhibit reaction
with the mineral acid. [0143] E38. The method of any one of
Embodiments E30 to E37, wherein the second modes comprise an
organic acid having from 1 to 40 carbon atoms. [0144] E39. The
method of Embodiment E38, wherein the organic acid in the second
mode initially inhibits reaction of the carbonate in the formation
with the mineral acid, or after reduction of a concentration of the
mineral acid in the second mode facilitates reaction with the
carbonate in the formation, or both. [0145] E40. The method of any
one of Embodiments E30 to E39, wherein the first modes comprise a
degradable polymer. [0146] E41. The method of Embodiment E40,
wherein the degradable polymer in the first mode forms a coating on
the fracture surface to inhibit reaction with the mineral acid.
[0147] E42. The method of any one of Embodiments E30 to E41,
wherein the second modes comprise a degradable polymer. [0148] E43
The method of Embodiment E42, wherein the degradable polymer in the
second mode initially inhibits reaction of the carbonate in the
formation with the mineral acid, or after reduction of a
concentration of the mineral acid in the second mode facilitates
reaction with the carbonate in the formation, or both. [0149] E44.
The method of any one of Embodiments E40 to E43, wherein the
degradable polymer(s) is (are independently) selected from the
group consisting of: polyethylene, polyhydroxyalkanoates such as
poly[R-3-hydroxybutyrate],
poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], and
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based
polymers, polylactic acid and copolyesters, polyglycolic acid and
copolyesters, aliphatic-aromatic polyesters,
poly(.epsilon.-caprolactone), polyethylene terephthalate,
polybutylene terephthalate; proteins such as gelatin, wheat and
maize gluten, cottonseed flour, whey proteins, myofibrillar
proteins, caseins, and combinations thereof. [0150] E45. The method
of any one of Embodiments E40 to E43, wherein the degradable
polymer(s) is (are independently) selected from polylactic acid,
polyglycolic acid and copolymers thereof. [0151] E46. The method of
any one of Embodiments E40 to E45, wherein the degradable polymer
comprises a mixture in the respective mode(s) of at least two
polymer species that degrade to form acid, wherein each of the at
least two polymer species have a different rate of hydrolysis.
[0152] E47. The method of any one of Embodiments E30 to E46,
wherein the second mode comprises an emulsion of the mineral acid
in an oleaginous carrier fluid. [0153] E48. The method of any one
of Embodiments E30 to E47, wherein adjacent ones of the first and
second modes have a viscosity difference in the fracture of at
least 50 mPa-s. [0154] E49. The method of any one of Embodiments
E30 to E48, wherein adjacent ones of the first and second modes
have a second mode:first mode volumetric ratio of 1:1 or more.
[0155] E50. The method of Embodiment E49, wherein the second
mode:first mode volumetric ratio is from 1:1 to 10:1. [0156] E51.
The method of Embodiment E49 or Embodiment E50, wherein the second
mode:first mode volumetric ratio in adjacent ones of later-injected
modes is greater than in adjacent ones of earlier-injected modes.
[0157] E52. The method of any one of Embodiments E30 to E51,
wherein a concentration of mineral acid in later-injected second
modes is greater than in earlier-injected second modes. [0158] E53.
The method of any one of Embodiments E30 to E52, wherein one or
more of the first modes comprises a viscoelastic diverting agent.
[0159] E54. The method of Embodiment E53, wherein the viscoelastic
diverting agent comprises anionic surfactant. [0160] E55. The
method of any one of Embodiments E30 to E54, wherein the first
modes comprise a non-aqueous phase. [0161] E56. The method of
Embodiment E55, wherein the non-aqueous phase comprises asphaltene.
[0162] E57. The method of Embodiment E56, further comprising
precipitating patches of the asphaltene on a surface of the
formation in the fracture. [0163] E58. The method of any one of
Embodiments E55 to E57, wherein the first modes comprise fibers,
flakes, beads or combinations thereof. [0164] E59. The method of
Embodiment E58 wherein the fibers, flakes, beads or combinations
thereof comprise polylactic acid, polyglycolic acid, latex or
combinations thereof. [0165] E60. The method of any one of
Embodiments E55 to E59, comprising modulation phase change behavior
of one or more components of the nonaqueous phase by adjusting
solvent composition, multivalent cation concentrations,
precipitation inhibitors or a combination thereof. [0166] E61. The
method of any one of Embodiments E1 to E60, wherein the treatment
stage fluid comprises proppant. [0167] E62. The method of any one
of Embodiments E1 to E61, wherein the formation comprises clay and
the treatment stage fluid comprises C.sub.8-C.sub.40 amine or
ammonium, or a combination thereof to form a hydrophobic coating on
the clay. [0168] E63. A system, comprising: a subterranean
formation penetrated by a wellbore; a treatment fluid stage
disposed in the wellbore, the treatment fluid stage comprising a
plurality of first mode substages disposed in the wellbore in an
alternating sequence with a plurality of second mode substages,
wherein the first mode substages have a high viscosity relative to
the second mode substages and wherein the second mode substages
have a high reactivity with carbonate in the formation relative to
the first mode substages; and a pump system to continuously deliver
the treatment fluid stage from the wellbore to the formation at a
pressure above fracturing pressure to inject the treatment fluid
stage into a fracture in the formation, and at a rate wherein each
substage is injected into the formation over a period of time from
5 seconds to 2.5 minutes. [0169] E64. The system of Embodiment E63,
wherein the first mode substages comprise a reactant reactive with
the carbonate in the formation and the second mode substages
comprise the reactant at a lesser concentration, or in a less
reactive form, or is free of the reactant. [0170] E65. The system
of Embodiment E64, wherein the reactant is selected from the group
consisting of mineral acids, organic acids, chelants and
combinations thereof. [0171] E66. The system of Embodiment E64 or
Embodiment E65, wherein the reactant comprises a solid acid. [0172]
E67. The system of any one of Embodiments E64 to E66, wherein the
reactant comprises HCl. [0173] E68. The system of any one of
Embodiments E64 to E67, wherein the reactant is encapsulated.
[0174] E69. The system of any one of Embodiments E64 to E68,
wherein the reactant is selected from C.sub.1-C.sub.40 organic
acids to form a coating on the surfaces of the fracture to inhibit
further reaction on the coated surfaces.
[0175] E70. The system of Embodiment E69, wherein the organic acid
is selected from carboxylic acids, phosphonic acids, sulfonic
acids, and combinations thereof. [0176] E71. The system of
Embodiment E70, wherein the organic acid comprises a
C.sub.8-C.sub.36 organic acid. [0177] E72. The system of any one of
Embodiments E69 to E71 wherein the first mode substages comprise
the organic acid and the second mode substages comprise a mineral
acid, wherein the second reactivity modes are more reactive with
the carbonate in the formation relative to the first reactivity
modes. [0178] E73. The system of any one of Embodiments E63 to E72
wherein the first mode substages comprise a weak organic base to
coat surfaces of the fracture to inhibit reaction on the coated
surfaces with a subsequent one of the second mode substages. [0179]
E74. The system of Embodiment E73, wherein the weak organic base
comprises a C.sub.8-C.sub.40 amine or ammonium, or a combination
thereof. [0180] E75. The system of any one of Embodiments E63 to
E74, further comprising: successively alternating ones of the first
and second mode substages in the fracture. [0181] E76. The system
of Embodiment E75, further comprising fingers of the relatively low
viscosity mode substages penetrating into a respective one of any
preceding high viscosity mode substage in the fracture. [0182] E77.
The system of Embodiment E76, wherein the fingers break through the
penetrated high viscosity mode substage into a preceding low
viscosity mode substage. [0183] E78. The system of Embodiment E76
or Embodiment E77 wherein the fingers form channels between islands
of the high viscosity modes. [0184] E79. The system of any one of
Embodiments E63 to E78, wherein the first mode comprises a
viscoelastic diverting agent. [0185] E80. The system of any one of
Embodiments E63 to E79, wherein the treatment fluid stage comprises
a gel, a cross-linked gel, an emulsion, a foam, or a combination
thereof. [0186] E81. The system of any one of Embodiments E63 to
E80, wherein the treatment fluid stage comprises a solid material
slurried in a carrier fluid. [0187] E82. The system of Embodiment
E81, wherein the treatment fluid stage comprises a plurality of
polyolefin beads having an average particle size distribution of
less than or equal to about 1000 microns (.about.20 mesh). [0188]
E83. The system of any one of Embodiments E63 to E82, wherein one
of the first and second mode substages comprises asphaltene,
polylactic acid, latex, or a combination thereof, and the other one
of the first and second reactivity mode substages comprises a
multivalent cation. [0189] E84. The system of any one of
Embodiments E63 to E83, wherein one of the first and second
reactivity mode substages comprises an aqueous carrier fluid, and
the other one of the first and second reactivity mode substages
comprises an oleaginous carrier fluid. [0190] E85. The system of
any one of Embodiments E63 to E84, wherein the treatment fluid
stage comprises a water-in-oil emulsion wherein a reactant with
carbonate in the formation is in a dispersed phase. [0191] E86. The
system of any one of Embodiments E63 to E85, further comprising
gelled first or second mode substages or both in the fracture.
[0192] E87. The system of any one of Embodiments E63 to E26,
wherein a volumetric ratio of the first mode substages to the
second mode substages is from about 1:99 to about 99:1. [0193] E88.
The system of any one of Embodiments E63 to E87, wherein the period
of time is from about 5 seconds to about 1 minute. [0194] E89. The
system of any one of Embodiments E63 to E88, further comprising a
pad stage ahead of the treatment stage fluid, a terminal flush
stage behind the treatment stage fluid, or a combination thereof.
[0195] E90. The system of any one of Embodiments E63 to E88,
comprising a pad stage ahead of the treatment stage fluid in the
fracture; successively alternating ones of the second and first
mode substages in the fracture behind the pad stage; viscous
fingering in the fracture of the second mode substages into the
first mode substages; wherein the fingers break through the
penetrated first mode substage into a preceding second mode
substage to form channels between islands of the first mode
substages. [0196] E91. The system of Embodiment E90, comprising
viscous fingering from a first one of the second mode substages
into a pad stage. [0197] E92. The system of Embodiment E90 or
Embodiment E91, wherein the first mode substages comprise gel and
the second mode substages comprise mineral acid. [0198] E93. The
system of Embodiment E92, wherein the gel is crosslinked. [0199]
E94. The system of Embodiment E92 or E93, wherein the second mode
substages comprise gel. [0200] E95. The system of Embodiment E94,
wherein the gel in the second mode substages is crosslinked. [0201]
E96. The system of any one of Embodiments E90 to E95, wherein the
first mode substages comprise an organic acid having from 1 to 40
carbon atoms. [0202] E97. The system of Embodiment E96, wherein the
organic acid in the first mode forms a coating on the fracture
surface to inhibit reaction with the mineral acid. [0203] E98. The
system of any one of Embodiments E90 to E97, wherein the second
mode substages comprise an organic acid having from 1 to 40 carbon
atoms. [0204] E99. The system of Embodiment E98, wherein the
organic acid in the second mode initially inhibits reaction of the
carbonate in the formation with the mineral acid, or after
reduction of a concentration of the mineral acid in the second mode
facilitates reaction with the carbonate in the formation, or both.
[0205] E100. The system of any one of Embodiments E90 to E99,
wherein the first mode substages comprise a degradable polymer.
[0206] E101. The system of Embodiment E100, wherein the degradable
polymer in the first mode forms a coating on the fracture surface
to inhibit reaction with the mineral acid. [0207] E102. The system
of any one of Embodiments E90 to E101, wherein the second mode
substages comprise a degradable polymer. [0208] E103 The system of
Embodiment E102, wherein the degradable polymer in the second mode
initially inhibits reaction of the carbonate in the formation with
the mineral acid, or after reduction of a concentration of the
mineral acid in the second mode facilitates reaction with the
carbonate in the formation, or both. [0209] E104. The system of any
one of Embodiments E100 to E103, wherein the degradable polymer(s)
is (are independently) selected from the group consisting of:
polyethylene, polyhydroxyalkanoates such as
poly[R-3-hydroxybutyrate],
poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], and
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based
polymers, polylactic acid and copolyesters, polyglycolic acid and
copolyesters, aliphatic-aromatic polyesters,
poly(.epsilon.-caprolactone), polyethylene terephthalate,
polybutylene terephthalate; proteins such as gelatin, wheat and
maize gluten, cottonseed flour, whey proteins, myofibrillar
proteins, caseins, and combinations thereof. [0210] E105. The
system of any one of Embodiments E100 to E103, wherein the
degradable polymer(s) is (are independently) selected from
polylactic acid, polyglycolic acid and copolymers thereof. [0211]
E106. The system of any one of Embodiments E100 to E105, wherein
the degradable polymer comprises a mixture in the respective
mode(s) of at least two polymer species that degrade to form acid,
wherein each of the at least two polymer species have a different
rate of hydrolysis. [0212] E107. The system of any one of
Embodiments E90 to E106, wherein the second mode comprises an
emulsion of the mineral acid in an oleaginous carrier fluid. [0213]
E108. The system of any one of Embodiments E90 to E107, wherein
adjacent ones of the first and second mode substages have a
viscosity difference in the fracture of at least 50 mPa-s. [0214]
E109. The system of any one of Embodiments E90 to E108, wherein
adjacent ones of the first and second mode substages have a second
mode:first mode volumetric ratio of 1:1 or more. [0215] E110. The
system of Embodiment E109, wherein the second mode:first mode
volumetric ratio is from 1:1 to 10:1. [0216] E111. The system of
Embodiment E109 or Embodiment E110, wherein the second mode:first
mode volumetric ratio in adjacent ones of later-injected mode
substages is greater than in adjacent ones of earlier-injected mode
substages. [0217] E112. The system of any one of Embodiments E90 to
E111, wherein a concentration of mineral acid in later-injected
second mode substages is greater than in earlier-injected second
mode substages. [0218] E113. The system of any one of Embodiments
E10 to E112, wherein one or more of the first mode substages
comprises a viscoelastic diverting agent. [0219] E114. The system
of Embodiment E113, wherein the viscoelastic diverting agent
comprises anionic surfactant. [0220] E115. The system of any one of
Embodiments E90 to E114, wherein the first mode substages comprise
a non-aqueous phase. [0221] E116. The system of Embodiment E115,
wherein the non-aqueous phase comprises asphaltene. [0222] E117.
The system of Embodiment E116, further comprising precipitating
patches of the asphaltene on a surface of the formation in the
fracture. [0223] E118. The system of any one of Embodiments E115 to
E117, wherein the first mode substages comprise fibers, flakes,
beads or combinations thereof. [0224] E119. The system of
Embodiment E118 wherein the fibers, flakes, beads or combinations
thereof comprise polylactic acid, polyglycolic acid, latex or
combinations thereof. [0225] E120. The system of any one of
Embodiments E115 to E119, wherein the nonaqueous phase comprises
solvent composition, multivalent cation concentrations,
precipitation inhibitors or a combination thereof to modulate phase
change behavior in the fracture. [0226] E121. The system of any one
of Embodiments E63 to E120, wherein the treatment stage fluid
comprises proppant. [0227] E122. The system of any one of
Embodiments E63 to E121, wherein the formation comprises clay and
the treatment stage fluid comprises C.sub.8-C.sub.40 amine or
ammonium, or a combination thereof to form a hydrophobic coating on
the clay. [0228] E123. A system, comprising: a subterranean
formation penetrated by a wellbore; means for injecting a treatment
stage fluid above a fracturing pressure to form a fracture in the
formation; means for successively alternating modes in the
treatment stage fluid, in either order, between at least first and
second modes; wherein the first modes have a high viscosity
relative to the second modes for viscous fingering of the second
mode into the first mode in the fracture; wherein the second modes
have high reactivity with carbonate in the formation relative to
the first mode to unevenly etch surfaces of the fracture; means for
sustaining injection of the treatment stage fluid during each of
the first and second modes for a period of time from 5 seconds up
to 2.5 minutes; means for repeating the successive alternation of
modes for a plurality of cycles; and means for reducing pressure to
facilitate fracture closure and form interconnected, hydraulically
conductive channels between opposing fracture surfaces.
[0229] The foregoing disclosure and description is illustrative and
explanatory thereof and it can be readily appreciated by those
skilled in the art that various changes in the size, shape and
materials, as well as in the details of the illustrated
construction or combinations of the elements described herein can
be made without departing from the spirit of the disclosure.
* * * * *