Field of Invedtion'
The present invention relates to a method of acidizing subterranean
formations in well operations and, more particularly, to the use of a
exothermic reaction to heat a subterranean formation in order to improve the
acidization of the subterranean formation.
Background Technical Information
Acidic fluids may be present in a multitude of operations in the oil
and chemical industries. Acidic fluids are often used as a treatment fluid in
well operations. These acidic treatment fluids may be used in clean-up
operations, stimulation operations, or other operations for oil and gas wells.
Acidic stimulation operations may be used in hydraulic fracturing and
matrix acidizing treatments. As used herein, the term "treatment fluid"
refers to any fluid that may be used in an application in conjunction with a
desired function and/or for a desired purpose. The term "treatment" does not
imply any particular action by the fluid or any component thereof.
A common problem associated with using acidic treatment fluids in
subterranean formations is that certain formation types, for example
dolomite formations, may be difficult. to acidize. For example, dolomite
formations with low temperatures (e.g., temperatures of 200" F or lower)
may, in some instances, not be effectively acidized by application of an
acidizing treatment'fluid alone. These low temperature dolomite formations
may require additional expenditures and time in order to be effectively
acidized.
Assortments of alternatives have been developed to acidize dolomite
formations at low temperatures. Some of these alternatives may include
viscoelastic surfactants that, in certain circumstances, may gel and push the
acidizing treatment fluid further into the formation which may increase the
range in which the acidizing treatment fluid penetrates the formation.
However, these viscoelastic surfactants may still require larger volumes to
be pumped for effective acidization due to the retarded reaction rates.
Brief Description of the Drawings
These drawings illustrate certain aspects of some of the
embodiments of the present invention, and should not be used to limit or
define the invention.
5 Figure 1 illustrates an example system for delivery of treatments
fluids into a wellbore.
Figure 2 illustrates another example system for delivery of
treatments fluids into a wellbore.
10 Description of Invention w.r.t. Drawings
The present invention relates to acidizing subterranean formations
and, more particularly, to the use of a exothermic reaction to heat a
subterranean formation in order to improve the acidization of the
subterranean formation.
15 There may be several potential advantages to the methods and
compositions of the treatment fluids disclosed herein, only some of which
may be alluded to herein. One of the many potential advantages is that
formations having low temperatures (e.g., less than 200 OF) may be acidized
efficiently where conventional acids fail. An additional advantage may be
20 that formations with low reactivity (e.g., dolomite formations) may be
acidized efficiently where conventional acid treatments fail. Further
advantage may be that the efficient acidizing of a formation may result in
higher production due to a faster acid reaction rate and therefor dissolution
rate. Another potential advantage may be that the disclosed methods and
25 systems are cost effective and may be implemented easily.
To increase the rate of an acidizing reaction, heat may be applied to
the formation. The heat may be provided by an exothermic chemical
reaction placed in the area where acidization is occurring, or is to occur.
Distinct treatment fluids may be used to convey the acidizing component
30 and the exothermic reaction components to the formation. The schedule of
the treatment fluids may be altered as desired. For example, some examples
may comprise a treatment fluid comprising an acid being placed in the target
formation followed by a subsequent treatment fluid comprising the
? -
exothermic reaction components. In this example, the exothermic reaction
components should not react until a threshold pH value is achieved.
Therefore, the exothermic reaction components may not react until reaching
the target formation, which comprises a pH below the threshold due to the
5 presence of the acidizing component which was pumped to the target
formation previously in a separate treatment fluid.
Without being limited by theory, dolomite formations at
temperatures less than 200 OF (-93 "C) may have lower reactivity with
conventional acid systems as compared to other formations, for example,
10 limestone. Dolomite formations at low temperatures may require higher
pore volumes (e.g., 40+ pore volumes at 25OC) as compared to a limestone
formation in order to wormhole breakthrough, this may be improved at
higher temperatures, for example, at greater than 75 OC. In some examples,
the dolomite dissolution rate may be lower than that of limestone at low
15 temperatures, however, the dissolution rate may increase to surpass that of
limestone when the formation temperature is increased beyond 200 OF.
The treatment fluids may comprise an acid. The acid may comprise
organic acids, inorganic acids, derivatives .thereof, or combinations thereof.
Examples of suitable acids generally include any acid or fluid capable of
20 dissolving carbonate. Specific examples may include, but are not limited to,
hydrochloric acid, hydrofluoric acid, formic acid, lactic acid, phosphoric
acid, sulfamic acid, acetic acid, esters of acids, acid sources, derivatives
thereof, and mixtures thereof. Acid sources may be my precursor of an acid,
for example, an aldehyde capable of being oxidized to form an acid. As will
25 be appreciated by those of ordinary skill, with the benefit of this disclosure,
acid-generating materials may also be used. The acid may be present in the
treatment fluids in any suitable amount, including in an amount of from
about 0.5% to about 40% by weight of the fluid. Alternatively, the acid may
be present in the treatment fluids in an amount of from about 2.5% to about
30 28% by weight of the fluid. Alternatively, the acid may be present in the
treatment fluids in an amount of from about 2.5% to about 15% by weight
of the fluid. Individuals skilled in the art, with the benefit of this disclosure,
should be able to select a suitable acid and a suitable concentration thereof
for a chosen application. In some instances, the particular concentration
used in any particular embodiment depends on what acid is being used, and
what percentage of acid .is present. Other complex, interrelated factors that
may be considered in deciding how much of the acid compound to use
5 include, but are not limited to, the composition of the formation, the
temperature of the formation, permeability of the formation, the pressure of
the formation, the particular fines in the formation, the particular acid used,
metals the acid may contact, corrosion concerns, the expected contact time
of the acid with the formation, etc.
10 As will be appreciated, the treatment fluids may be used in a variety
of acidizing operations. The purpose of acidizing is to dissolve acid-soluble
materials. A treatment fluid comprising an acid may be introduced into a
subterranean formatioh by way of a wellbore to dissolve the acid-soluble
materials. In this way, oil or gas can more easily flow from the formation
15 into the wellbore. In addition, acidizing can facilitate the flow of injected
treatment fluids from the well into the formation.
Acidizing operations may be carried out as acid fracturing
procedures or matrix acidizing procedures. In acid fracturing, an acidic
treatment fluid may be pumped into a formation at a sufficient pressure to
20 cause fracturing of the formation and to create differential (non-uniform)
etching of fracture conductivity. For example, an acidic treatment fluid
comprising an aqueous component and an acid may be introduced into the
formation to cause fracturing of the formation. Depending on the rock of the
formation, the acidizing treatment fluid can etch the fractures faces,
25 whereby flow channels may formed when the fractures close. The acidic
treatment fluid may also enlarge the pore spaces in the fracture faces and in
the formation. In matrix acidizing, the acidizing treatment fluid may be
injected from the wellbore into the formation at a rate and pressure below
the pressure sufficient to create a fracture in the formation.
3 0 The type of subterranean formation being treated with the acidic
treatment fluids described herein is not believed to be particularly limited.
The subterranean formation may comprise a carbonate formation, such as a
limestone or dolomite formation, for example. The subterranean formation
1Q.Q DELHL Q S - Q L - L Q B 5 QS: 41 - 5 -
may comprise a siliceous formation or have had a siliceous material
introduced thereto. Alternatively, the subterranean formation may comprise
a sandstone formation or a clay-containing formation. Even further, the
subterranean formation may comprise a subterranean formation having a
5 low permeability, such as a shale formation, for example. Moreover, the
subterranean formation may comprise native minerals such as, for example,
authigenic or detrital minerals, particularly layered aluminosilicates,
feldspathic minerals, or purely siliceous minerals.
As discussed above, the formation may be any type of formation
10 comprising any type of formation properties. The examples described herein
may be particularly suited for dolomite formations with low temperatures,
for example, formations with bottom hole static temperatures below 200 O F .
As discussed above, a separate exothermic reaction may be used to
heat the formation before andor during the acidization process in order to
15 improve the reaction rate of the acidization reaction. The exothermic
reaction may comprise sodium nitrite (NaN02) and ammonium chloride
(NH4Cl) which, when exposed to a pH of 4 or less, may react in an .
exothermic reaction to generate a large amount of heat (e.g., AH = -334.2
kJ/mol at 25" C). The large exotherm produced by the reaction may be used
20 to heat the subterranean formation to temperatures which may exceed 200"
F. The increased heat within the formation may also increase the rate of any
concurrent acidization reaction occurring within the formation. The reaction
of NaN02 and NH4C1 is illustrated by equation 1 below:
2 5 NaNOz +NH4Cl + NaCl + 2H20 + NZ (AH = -334.2 kJ/mol at
25°C) Eq. 1
Although, the exothermic reaction described in the disclosed examples
comprises the reaction of sodium nitrite and ammonium chloride, the
30 invention contemplates the use of any other exothermic reaction that
produces a large amount of heat and is compatible with wellbore conditions
, and the subterranean formation.
The components of the exothermic reaction (e.g., NaN02 andNH4Cl)
may be included in a treatment fluid The components may be individually
included in a treatment fluid in a concentration between about 0.01 molar to
about 7 molar. For example, the components may comprise a concentration
5 between about 0.1 molar to about 4.5 molar. The components may be
included in the same treatment fluid or may be included in distinct treatment
fluids. In some examples one of the components may be included in a
treatment fluid with an acid. For example, the treatment fluid may be
pumped to a target location where the acid decreases the pH of the
10 formation to less than 4. The second component may then be pumped in a
subsequent treatment fluid to the target location where it reacts with the first
component in the presence of the acid to generate an exotherm capable of
increasing the formation temperature. The increased formation temperature
increases the rate of acidization of the formation.
15 As discussed, the exothermic reaction may necessitate adding an
acid to a subterranean formation to decrease the pH of the exothermic
reaction components to 'a pH sufficiently low to initiate the subsequent
exothermic reaction (e.g., a pH of 4 or less for the reaction of NaN02 and
NH4C1). For some exothermic reaction components, a specific pH threshold
20 must be met to induce the reaction. The threshold may be met through
contact with an agent that adjusts the pH of the exothermic reaction
components, for example, an acid; or by placing the exothermic reaction
components in an environment with a pH surpassing the requisite reaction
threshold. Any volume andlor molarity of acid may be used provided the
25 amount is sufficient to lower the pH of the fluid in the formation to the
requisite degree.
In an example method, the acid may be pumped to the target
formation in a first treatment fluid. An optional spacer fluid comprising
water, or any other type of fluid sufficient for displacement, may be pumped
30 into the formation to separate at least a portion of the acid from at least a
portion of the exothermic reaction components which may be pumped in a
subsequent treatment fluid. This separation may be done so as to prevent
prematurely reacting the exothermic reaction components. If no separation
is performed, the exothermic reaction components may contact at least a
portion of the acid in the conduits andor equipment use to convey the
exothermic reaction components to the target area. This contact could
induce the exothermic reaction components to react and thus induce the
5 aforementioned portion of the acid present in the conduit and/or equipment
to corrode the conduit and/or equipment. Further, the heat will dissipate
prematurely and thus reduce acidizing efficiency. In examples in which
corrosion is not an issue, there may be no need to separate the acid from the
exothermic reaction components and the two may be pumped sequentially in
10 treatment fluids or may be pumped to the target location in the same
treatment fluid.
Continuing with the previous example, after the spacer fluid has
1
!
been pumped, the exothermic reaction components may then be pumped in a
second treatment fluid into the formation until they are placed into the target
15 area. The exothermic reaction components may then react to heat the
formation. A second spacer fluid (which may be the same or different from
the first spacer fluid) may be pumped behind the exothermic reaction
components. Then a third treatment fluid comprising the same acid or a
different acid may be pumped to the target area of the formation. The acids
20 present in the target area may have a relatively higher rate of acidization
because the target formation will have a higher temperature due to the
exotherm from the exothermic reaction.
Examples of suitable spacer fluids andor materials may include, but
should not be limited to poly saccharides such as dextran, cellulose, guar,
25 chitin, chitosan, aliphatic poly esters, poly lactide, poly glycolide, poly
caprolactone, poly hydroxyl butyrate, poly anhydrides, aliphatic poly
carbonates, poly ortho esters, poly amino acids, poly ethylene oxide etc.
Fatty alcohols selected from cholesterol, cholesteryl nonanoate,
glyceraldehyde triphenyl methanol, dimethyl terephthalate, and the like. .
30 With the benefit of this disclosure, one of ordinary skill in the art will be
able to separate the exothermic reaction components from the acid.
In alternative examples, one of the exothermic reaction components
(e.g., the sodium nitrite or the ammonium chloride) may be pumped to the
target area of the formation in a first treatment fluid. Then an optional
spacer fluid may be pumped to separate the prior pumped exothermic
reaction component from any subsequently pumped fluids. Finally, a second
treatment fluid comprising a volume of acid and the remaining exothermic
5 reaction component(s) may be pumped to the target formation. The
exothermic reaction may be induced by. the acid lowering the pH of the
target formation, and the exotherm generated by.the exothermic reaction
may increase the rate of acidization of the formation.
In further alternative embodiments, the second exothermic reaction
10 reactant which, as noted above, is pumped in a second treatment fluid with a
volume of acid, may be encapsulated with an encapsulation material. The
encapsulation material may slowly release the subsequent exothermic
reaction component into the formation to react with the prior pumped
exothermic reaction component in order to heat the formation and increase
15 the rate of acidization.
Various types of encapsulation techniques may be used to
encapsulate any of the exothermic reaction components including, but not
limited to, matrix encapsulation, spray-drying, pan coating, centrifugal
extrusion, air-suspension coating, vibrational nozzle encapsulation, and the
20 like. A specific example may comprise adding molten encapsulation
materials (e.g., wax) to the exothermic reaction component in a blender and
then blending the mixture while maintaining a temperature above the
melting point of the encapsulation material. The mixture should be blended
until a homogenous mixture is formed. The encapsulation material may be
25 at least partially coated on the exothermic reaction component. Further, the
encapsulation material may completely coat the exothermic reaction
component. Even fhher, the encapsulation material may both partially and
completely coat the exothermic reaction component.
Suitable encapsulation materials may comprise relatively inert
30 materials that do not react or otherwise negatively interfere with other
components of the treatment fluids or the formation. In some examples, the
encapsulation materials may be inert to the chemical and physical properties
of the treatment fluids and the formation.
The encapsulation materials may comprise any material capable of
encapsulating a exothermic reaction component. Example encapsulation
materials may generally comprise clay, silica, polymers, etc. Specific
examples may comprise water-insoluble. polymers such as acrylic acid
5 cross-linked with polyalkenyl ethers or divinyl glycol and waxes such as
polyethylene wax, stearamide wax, paraffin wax, and the like. A
commercial example of a suitable encapsulation material is the
CARBOPOL~ family of polymers, a registered trademark of Noveon, Inc.
Another commercial example of an encapsulation material is BW-436
10 paraffin wax, available from Blended Waxes, Inc. of Oshkosh, Wisconsin.
Further materials may include, but should not be limited to: micro-particles
or nano-particles such as poly(1actide-co-glycolide), poly(L-lactic acid),
poly(D,L-lactic acid), polyglycolic acid, polyanhydrides, poly(ortho ethers),
poly(~-caprolactone), poly(hydroxy butyrate), poly(propy1ene fumarate),
15 polyphosphoesters, polyphosphazenes, collagen, gelatin, carbohydrates, and
the like. In some examples, a first encapsulating material may release a set
of exothermic reaction components (e.g., sodium nitrite and ammonium
chloride) which may react and then raise the temperature of the formation.
When the temperature is raised, a second encapsulation material may release
20 an additional set of exothermic reaction components to release additional
heat in a later stage. The first and second encapsulation materials may
comprise different materials or different chemical compositions; or they
may comprise the same chemical composition but with a different pore
sizes, for example, the first encapsulation material may have comparatively
25 bigger pores to release the exothermic reaction components faster than the
second encapsulation material. Further .a combination of materials may be
used to control the release of the exothermic reaction components in stages.
Additionally, the melting point of the encapsulation material may be a factor
for consideration in choosing an encapsulation material. As described
30 above, melting or dissolving an encapsulation material, for example a first
encapsulation material, may be important for reaching a temperature
necessary to surpass the melting point of any additional encapsulation
materials, for example, a second encapsulation material. The melting point
may, in some instances, determine the rate of release of the exothermic
reaction component from the encapsulation material. Additional melting
point considerations may include storage of the exothermic reaction
reactants in high-heat environments, wherein. it may be advantageous to
- 5 select encapsulation materials that can be stored on site without melting
and/or compaction.
The amount of the encapsulation material. used may generally
depend on a number of factors. The factors may include the particular
exothermic reaction component, the specific encapsulation material, the
10 .encapsulation technique desired, the melting point of the encapsulation
material, and the total cost, amongst others factors. The encapsulation
material may be present in an amount of about 0.1% to about 50% by
weight of the encapsulated exothermic reaction component. For example,
the encapsulation material may be present in an amount of about 0.1%,
15 about 2.5%, about 5%, about lo%, about 20%, about 30%, about 40%, or
about 50% by weight of the encapsulated exothermic reaction component.
The treatments fluids and optional spacer fluids may comprise an
aqueous component. The aqueous component may be from any source
provided that it does not contain an excess of compounds that may
20 undesirably affect other components in the treatment fluid. The aqueous
component may comprise fresh water or salt water. Salt water generally may
include one or more dissolved salts therein and may be saturated or
unsaturated as desired for a particular application. Seawater or brines may
be suitable for use in some applications. The amount of the aqueous
25 component may typically be dictated by the final concentration of acid
desired. With the benefit of this disclosure one of ordinary skill in the art
should recognize the appropriate type and amount of the aqueous
component for a chosen application.
Lost-circulation materials may be included in the treatment fluids to,
30 for example, help prevent the loss of fluid. circulation into the subterranean
formation. Examples of lost-circulation materials include, but are not
limited to, graphite, nut shells, calcium carbonate, and the like. Further
examples of lost-circulation materials may include various types of fibers
including natural or synthetic fibers. For example, the lost-circulation fiber
types may include natural, biopolymers, synthetic, biodegradable, and/or
biocompatible fibers. Examples of synthetic fibers may include, but are not
limited to, polymers composed of polypropylene, polyaramide, polyester,
5 polyacrylonitrile, and polyvinyl alcohol. Examples of biodegradable fibers
may include, but are not limited to, fibers composed of modified cellulose,
chitosan, soya, modified chitosan, polycaprolactone, poly(3-
hydroxybutyrate), polyhydroxy-alkanoates, polyglycolic acid "PGA",
polylactic acid "PLA", polyorthoesters, polycarbonates, polyaspartic acid,
10 polyphosphoesters, or copolymers thereof. Examples of other suitable fibers
may include, but are not limited to fibers of cellulose including viscose
cellulosic fibers, oil coated cellulosic fibers, and fibers derived from a plant
product like paper fibers; carbon including carbon fibers; melt-processed
inorganic fibers including basalt fibers, wollastonite fibers, non-amorphous
15 metallic fibers, ceramic fibers, and glass fibers. The lost-circulation
materials may be present in the treatment fluids in an amount in the range of
from about 0 % to about 20% by weight of the treatment fluid. More
particularly, the lost-circulation materials may be present in an amount
ranging between any .of and/or including any of. about 0%, about 0.1%,
20 about I%, about 2%, about 4%, about 6%, about 8%, about lo%, or about
20% by weight of the treatment fluid. One of ordinary skill in the art, with
the benefit of this disclosure, should recognize the appropriate type and
amount of lost circulation material to include for a chosen application.
A method for acidizing a subterranean formation may be provided.
25 The method may include one or all of the components illustrated on FIGS. 1-
2. The method may comprise using an acid to lower the pH of a fluid within
a subterranean formation; reacting exothermic reaction components in the
fluid within the subterranean formation to heat the subterranean formation;
and acidizing the subterranean formation. The acid may be selected from the
30 group consisting of hydrochloric acid, hydrofluoric acid, formic acid, lactic
acid, phosphoric acid, sulfamic acid, acetic acid, esters of acids, acid
sources, derivatives thereof, and mixtures thereof. The exothermic reaction
components may comprise sodium nitrite .and ammonium chloride. One of
the exothermic reaction components may. be encapsulated with an
encapsulation material. The encapsulation material may be selected from the
group consisting of a clay, a silica, a polymer, a wax, a gelatin, a collagen, a
carbohydrate, and a combination thereof.. The subterranean formation has a
5 temperature less than 200 OF prior to the step of reacting.
A method for acidizing a subterranean formation may be provided.
The method may include one or all of the components illustrated on FIGs. 1 -
2, The method may comprise introducing a first acidic treatment fluid into
the subterranean formation; introducing a treatment fluid comprising
10 exothermic reaction components into the subterranean formation, wherein
the exothermic reaction components react in an exothermic reaction at a
specific pH; and introducing a second acidic treatment fluid into the
subterranean formation. The first acidic treatment fluid and the second
acidic treatment may each individually comprise an acid selected from the
15 group consisting of hydrochloric acid, hydrofluoric acid, formic acid, lactic
acid, phosphoric acid, sulfamic acid, acetic acid, esters of acids, acid
sources, derivatives thereof, and mixtures thereof. The exothermic reaction
components comprise sodium nitrite and ammonium chloride. A spacer
fluid may be introduced into the subterranean formation prior to the
20 introduction of the treatment fluid. A portion of the exothermic reaction
components may be encapsulated in a first encapsulation material, and
wherein another portion of the exothermic reaction components are
encapsulated in a second encapsulate material. The first acidic treatment
fluid may comprise a first acid in an amount of from about 10% to about
25 20% by volume of the first treatment fluid, and wherein the second
treatment fluid comprises a second acid in an amount of from about 1% to
about 35% by volume of the second treatment fluid, wherein the first acid
and the second acid may the same or different acids. The subterranean
formation has a temperature less than 200 OF prior to the step of reacting.
30 A method for acidizing a subterranean formation may be provided.
The method may include one or all of the components illustrated on FIGs. 1 -
2. The method may comprise introducing a first treatment fluid comprising
a first exothermic reaction component into the subterranean formation; and
introducing a second treatment fluid comprising an acid and a
second exothermic reaction component ' into the subterranean formation,
wherein the first exothermic reaction component and the second exothermic
reaction component react in an exothermic reaction at a specific pH. The
5 first exothermic reaction component may comprise sodium nitrite and the
second exothermic reaction component may comprise ammonium chloride.
The first exothermic reaction component may comprise ammonium chloride
and the second exothermic reaction component may comprise sodium
nitrite. The acid may be selected from the group consisting of hydrochloric
10 acid, hydrofluoric acid, formic acid, lactic acid, phosphoric acid, sulfamic
acid, acetic acid, esters of acids, acid sources, derivatives thereof, and
mixtures thereof. The subterranean formation has a temperature less than
200 OF. The acid may be present in the second treatment fluid in an amount
of from about 1% to about 35% by volume of the second treatment fluid.
15 The second exothermic reaction component .may be encapsulated with an
encapsulation material. The encapsulation material may be selected from the
group consisting of a clay, a silica, a polymer, a wax, a gelatin, a collagen, a
carbohydrate, and a combination thereof.
Turning now to Figure 1, an example well system 100 for
20 introduction of treatment fluids described herein into a wellbore 105 is
shown. As depicted in Figure 1, system 100 may include a fluid handling
system 110 for introducing an acidic treatment fluid 115 into the wellbore
by way of tubular 120. Acidic treatment fluid 11 5 comprises any acid of the
acids disclosed herein in any desirable volume and molarity. In the
25 illustrated embodiment, the fluid handling system 110 is above the surface
125 while wellbore 105 and tubular 120 are below the surface 125. The fluid
handling system 110 can be configured as shown in Figure 1 or in a
different manner, and may include additional or different features as
appropriate. The fluid. handling system 110 may be deployed via skid
30 - equipment, marine vessel deployed or may be comprised of sub-sea
deployed equipment.
As illustrated in Figure 1, wellbore 105 may include vertical and
horizontal sections, and an acidic treatment fluid 11 5 may be introduced into
subterranean formation 130 surrounding the horizontal portion of the
wellbore 105. Generally, a wellbore 105 may include horizontal, vertical,
slant, curved, and other types of wellbore geometries and orientations, and
the acidic treatment fluid 115 may generally be applied to subterranean
5 formation 130 surrounding any portion of wellbore 105. Wellbore 105 may
include a casing that is cemented or otherwise secured to the wellbore wall.
Wellbore 105 can be uncased or include uncased sections. Perforations can
be formed in the casing to allow treatment fluids and/or other materials to
flow into subterranean formation 130. Perforations can be formed using
10 shape charges, a perforating gun, and/or other tools.
Fluid handling system 110 may include mobile vehicles, immobile
installations, skids, hoses, tubes, fluid tanks or reservoirs, pumps, valves,
and/or other suitable structures and equipment. For example, the fluid
handling system 1 10 may include pumping equipment 135 and a fluid
15 supply 140, which both may be in fluid communication with the tubular
120. The fluid supply 140 may contain the acidic treatment fluid 1 15. The
pumping equipment 135 may be used to supply treatment fluid 1 15 from the
fluid supply 140, which may include tank, reservoir, connections to external
fluid supplies, and/or other suitable structures and equipment. Pumping
20 equipment 135 may be coupled to tubular 120 to communicate treatment
fluid 1 15 into wellbore 105. Fluid handling system 1 10 may also include
surface and down-hole sensors (not shown) to measure pressure, rate,
temperature and/or other parameters of treatment. Fluid handling system
110 may include pump controls and/or other types of controls for starting,
25 stopping and/or otherwise controlling pumping as well as controls for.
selecting and/or otherwise controlling fluids pumped during the injection
treatment. An injection control system may communicate with such
equipment to monitor and control the injection treatment.
The tubular 120 may include coiled tubing, sectioned pipe, and/or
30 other structures that communicate fluid through wellbore 105. Alternatively,
tubular may include casing, liners; or other tubular structures disposed in
wellbore 105. Tubular 120 may include flow control devices, bypass valves,
ports, and or other tools or well devices that control a flow of fluid from the
interior of tubular 120 into subterranean formation 130. For example,
tubular 120 may include ports to communicate acidic treatment fluid 115
directly into the rock matrix of the subterranean formation 130. Although
Figure 1 shows the horizontal section of the tubular 120 representing an
5 inner tubular structure of well system 100, in some embodiments, such inner
tubular structure may be absent.
With continued reference to Figure 1, well system 100 may be used
for delivery of the acidic treatment fluid '1'1 5 into wellbore 105. The acidic
treatment fluid 1 15 may be pumped from fluid supply 140 down the interior
10 of tubular 120 in wellbore 105. The acidic treatment fluid 1 15 may be
allowed to flow down the interior of tubular 120, exit the tubular 120, and
finally enter subterranean formation 130 surrounding wellbore 105. The
acidic treatment fluid 130 may dissolve acid soluble portions of
subterranean formation 130 and lower the pH of the subterranean formation
15 130 in the targeted area. The acidic treatment fluid 115 may also enter
subterranean formation 130 at a sufficient pressure to cause fracturing of
subterranean formation 130 in applications utilizing acidic fracturing.
In the example of Figure 1, subsequent to the delivery of acidic
treatment fluid 1 15 into the wellbore by well system 100, spacer fluid 145
20 may be introduced by well system 100 into tubular 120 to separate the
exothermic reaction treatment fluid 150 from acidic treatment fluid 1 15 and
thus minimize the potential for corrosion in tubular 120. As discussed, after
pumping of the spacer fluid 145 through tubular 120, a exothermic reaction
treatment fluid 150 comprising exothermic reaction components may be
25 delivered into wellbore 105 by well system 100 and pumped to the targeted
area of the subterranean formation 130. When the exothermic reaction
treatment fluid 150 reaches the target area of subterranean formation 130,
the lowered pH in the target area of subterranean formation 130 induces the
exothermic reaction components within exothermic reaction treatment fluid
30 150 to react. The exothermic reaction of the exothermic reaction
components may increase the temperature of the subterranean formation 130
. and thus, may also increase the reaction rate of any acidization reaction and
thus enhance stimulation of the-targeted area of subterranean formation 130.
I
With continued reference to Figure 1, a second spacer fluid 145 may
be introduced by well system 100 into tubular 120 to separate the
exothermic reaction treatment fluid 150 from a subsequent acidic treatment
fluid 115 and thus minimize .the potential for corrosion in tubular 120.
5 Finally, another acidic treatment fluid 11 5 may be introduced into wellbore
105 via delivery by well system 100. The acidic treatment fluid 1 15 may be
pumped from fluid supply 140 down the interior of tubular 120 in wellbore
105. The acidic treatment fluid 115 may be allowed to flow down the
interior of tubular 120, exit the tubular 120, and finally enter subterranean
10 formation 130 surrounding wellbore 105. The acidic treatment fluid 130
may dissolve acid soluble portions of subterranean formation 130 at an
increased rate due to the temperature increase induced by the exotherm from
the prior pumped exothermic reaction treatment fluid 150.
Figure 2 illustrates the same well system 100 as Figure 1, however,
15 the schedule of treatment fluids and/or ,the composition of the treatment
fluids has been altered. In Figure 2, a first treatment fluid 155 comprising
one exothermic reaction component may be delivered into wellbore 105 via
well system 100. The first treatment fluid 155 may be pumped from fluid
supply 140 down the interior of tubular 120 in wellbore 105. The first
20 treatment fluid 155 may be allowed to flow down the interior of tubular 120,
exit the tubular 120, and finally enter subterranean formation 130
surrounding wellbore 105. Spacer fluid 145 may be introduced by well
system 100 into tubular 120 to separate the first treatment fluid 155 from a
second treatment fluid 160 and thus minimize the potential for corrosion in
25 tubular 120.
As discussed, after pumping of the spacer fluid 145 through tubular
120, a second treatment fluid 160 comprising the remaining exothermic
reaction component(s) and at least one acid may be delivered into wellbore
105 by well system 100 and pumped to the targeted area of the subterranean
30 formation 130 via tubular 120. When the second treatment fluid 160 reaches
the target area of the subterranean formation 130, the acid within the second
treatment fluid 150 may raise the pH of the target area of the.subterranean
formation 130 which now contains the exothermic reaction components
introduced via the first treatment fluid 155 and the second treatment fluid
160. When the pH of the targeted area of the subterranean formation 130
reaches a threshold for reaction of the exothermic reaction components, the
exothermic reaction components react in an exothermic reaction to generate
a large exotherm which may increase the temperature of the targeted area of
the subterranean formation 130. This induced temperature increase may
increase the reaction rate of the acidization reaction within the targeted area
of the subterranean formation 130 and thus enhance stimulation of the
targeted area of subterranean formation 130.
In an alternative example, the second treatment fluid 160 of Figure 2
may comprise an encapsulated exothermic reaction component(s) that may
slowly release over time or as the'acid dissolves the encapsulation, such that
the exothermic reaction is delayed until the exothermic reaction component
of the second treatment fluid 160 is released to react with the exothermic
reaction component of the first treatment fluid 155.
It is to be recognized that the disclosed treatment fluids may also
directly or indirectly affect the various downhole equipment and tools that
may come into contact with the treatment fluids during operation. Such
equipment and tools may include, but are not limited to, wellbore casing,
20 wellbore liner, completion string, insert strings, drill string, coiled tubing,
slickline, wireline, drill pipe, drill collars, mud motors, downhole motors
and/or pumps, surface-mounted motors and/or pumps, centralizers,
turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools
and related telemetry equipment, actuators (e.g., electromechanical devices,
25 hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs,
screens, filters, flow control devices (e.g., inflow control devices,
autonomous inflow control devices, outflow control devices, etc.), couplings
(e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.),
control lines (e.g., electrical, fiber optic, hydraulic, etc.), surveillance lines,
30 drill bits and reamers, sensors or distributed sensors, downhole heat
I exchangers, valves and corresponding actuation devices, tool seals, packers,
I cement plugs, bridge plugs, and other wellbore isolation devices, or
I
components, and the like. Any of these components may be included in the
systems generally described above and depicted in the preceding figures.
Therefore, the present invention is well adapted to attain the ends
and advantages mentioned as well as those that are inherent therein. The
5 particular embodiments disclosed above are illustrative only, as the present
invention may be modified and practiced in different but equivalent manners
apparent to those skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of construction or
design herein shown, other than as described in the claims below. It is
10 therefore evident that the particular illustrative embodiments disclosed
above may be altered or modified and all such variations are considered
within the scope and spirit of the present invention. While compositions
and methods are described in terms of "comprising," "containing,"
"having," or "including" various components or steps, the compositions and
15 methods can also "consist essentially of' or "consist of' the various
components and steps. Whenever a numerical range with a lower limit and
an upper limit is disclosed, any number and any included range falling
within the range is specifically disclosed. In particular, every range of
values (of the form, "from about a to about b," or, equivalently, "from
20 approximately a to b," or, equivalently, "from approximately a-b") disclosed
herein is to be understood to set forth every number and range encompassed
within the broader range of values. Also, the terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly defined by
the patentee.
We claim:
1. A method of acidizing of subterranean formations in well
operations comprising:
using an acid to lower the pH of a fluid within a subterranean
5 formation; reacting exothermic reaction components in the fluid within
the subterranean formation to heat the subterranean formation; and
acidizing the subterranean formation.
2. A method as claimed in claim 1, wherein the acid is selected
from the group consisting of hydrochloric acid, hydrofluoric acid, formic
10 acid, lactic acid, phosphoric acid, sulfamic acid, acetic acid, esters of acids,
acid sources, derivatives thereof, and mixtures thereof.
3. A method ,as claimed in claim 1 or claim 2, wherein the
exothermic reaction components comprise sodium nitrite and ammonium
chloride.
15 4. A method as claimed in any preceding claim, wherein one of
the exothermic reaction components is encapsulated with an encapsulation
material.
5. A method as claimed in claim 4, wherein the encapsulation
material is selected from the group consisting of a clay, a silica, a polymer, a
20 wax, a gelatin, a collagen, a carbohydrate, and a combination thereof.
6. A method as claimed in any preceding claim, wherein the
subterranean formation has a temperature less than 200 O F prior to the step
of reacting.
7. A method of acidizing of subterranean formations
25 comprising:
introducing a first acidic treatment fluid into the subterranean
formation; introducing a treatment fluid comprising exothermic reaction
components into the subterranean formation, wherein the exothermic
reaction components react in an exothermic reaction at a specific pH; and
30 introducing a second acidic treatment fluid into the
subterranean formation.
8. A method as claimed in claim 7, wherein the first acidic
treatment fluid and the second acidic treatment each individually comprise
an acid selected from the group consisting of hydrochloric acid,
hydrofluoric acid, formic acid, lactic acid, phosphoric acid, sulfamic acid,
5 acetic acid, esters of acids, acid sources, derivatives thereof, and mixtures
thereof.
9. A method as claimed in claim 8 or claim 9, wherein the
exothermic reaction components comprise sodium nitrite and ammonium
chloride.
10 10. A method as claimed in any of claims 7 to 9, wherein a
spacer fluid is introduced into the subterranean formation prior to the
introduction of the treatment fluid.
11. A method as claimed in any of claims 7 to 10, wherein a
portion of the exothermic reaction components are encapsulated in a first
15 encapsulation material, and wherein another portion of the exothermic
reaction components are encapsulated in a second encapsulate material.
12. A method as claimed in any of claims 7 to 1 1, wherein the
first acidic treatment fluid comprises a first acid in an'amount of from about
10% to about 20% by volume of the first treatment fluid, and wherein the
20 second treatment fluid comprises a second acid in an amount of from about
1% to about 35% by volume of the second treatment fluid, wherein the first
acid and the second acid may the same or different acids.
13. A method of acidizing of subterranean formations
comprising:
2 5 introducing a first treatment fluid comprising a first
exothermic reaction component into the subterranean formation; and
introducing a second treatment fluid comprising an acid and
a second exothermic reaction component into the subterranean formation,
wherein the first exothermic reaction component and the second exothermic
30 reaction component react in an exothermic reaction at a specific pH.
14. A method as claimed in claim 13, wherein the first
exothermic reaction component comprises sodium nitrite and the second
exothermic reaction component comprises ammonium chloride.
HPO E L 3 - 2 2 . El3 14.1 - 2 1 -
15. A method as claimed in claim 13, wherein the first
exothermic reaction component comprises ammonium chloride and the
second exothermic reaction component comprises sodium nitrite.
16. A method as claimed in any of claims 13 to 15, wherein the
5 acid is selected from the group consisting of hydrochloric acid, hydrofluoric
acid, formic acid, lactic acid, phosphoric acid, sulfarnic acid, acetic acid,
esters of acids, acid sources, derivatives thereof, and mixtures thereof.
17. A method as claimed in any of claims 13 to 16, wherein
subterranean formation has a temperature less than 200 O F .
10 18. A method as claimed in any of claims 13 to 17, wherein the
acid is present in the second treatment fluid in an amount of from about 1%
to about 35% by volume of the second treatment fluid.
19. A method as claimed in any of claims 13 to 1 8, wherein the
second exothermic reaction component is encapsulated with an
15 encapsulation material.
20. A method as claimed in claim 19, wherein the encapsulation
material is selected from the group consisting of a clay, a silica, a polymer, a
wax, a gelatin, a collagen, a carbohydrate, and a combination thereof.