U.S. patent application number 13/330040 was filed with the patent office on 2013-04-11 for chemomechanical treatment fluids and methods of use.
This patent application is currently assigned to CONOCOPHILLIPS COMPANY. The applicant listed for this patent is Robert Charles Choens, II, Jeremy Johnson, Carl T. Montgomery, Gangerico G. Ramos. Invention is credited to Robert Charles Choens, II, Jeremy Johnson, Carl T. Montgomery, Gangerico G. Ramos.
Application Number | 20130087340 13/330040 |
Document ID | / |
Family ID | 45497828 |
Filed Date | 2013-04-11 |
United States Patent
Application |
20130087340 |
Kind Code |
A1 |
Choens, II; Robert Charles ;
et al. |
April 11, 2013 |
CHEMOMECHANICAL TREATMENT FLUIDS AND METHODS OF USE
Abstract
Methods and systems are provided for favorably altering the
chemomechanical properties of subterranean formations using
treatment fluids comprising surfactants and halide salts. Methods
for treating formations comprise the steps of introducing a
chemomechanical treatment fluid into the formation and allowing the
treatment fluid to interact with the formation to alter its
petrochemical properties in various ways. Depending on the
application, the chemomechanical treatment fluid may comprise a
base fluid, a halide salt and an amphoteric or nonamphoteric
surfactant where the surfactant is dissolved in the base fluid at a
concentration below its critical micelle concentration.
Applications of use involving the chemomechanical treatment fluids
include treatment operations, secondary recovery operations,
drilling operations, and any other operation that would benefit
from the formation property modifications described herein.
Subterranean formation properties that may to be varied by the
chemomechanical treatment fluid include fracture toughness,
compressive strength, and tensile strength.
Inventors: |
Choens, II; Robert Charles;
(Houston, TX) ; Ramos; Gangerico G.;
(Bartlesville, OK) ; Montgomery; Carl T.; (Grove,
OK) ; Johnson; Jeremy; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Choens, II; Robert Charles
Ramos; Gangerico G.
Montgomery; Carl T.
Johnson; Jeremy |
Houston
Bartlesville
Grove
Houston |
TX
OK
OK
TX |
US
US
US
US |
|
|
Assignee: |
CONOCOPHILLIPS COMPANY
Houston
TX
|
Family ID: |
45497828 |
Appl. No.: |
13/330040 |
Filed: |
December 19, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61432495 |
Jan 13, 2011 |
|
|
|
Current U.S.
Class: |
166/307 ;
166/305.1; 166/308.2; 507/205 |
Current CPC
Class: |
C09K 8/68 20130101; E21B
43/26 20130101; E21B 43/16 20130101; C09K 8/584 20130101 |
Class at
Publication: |
166/307 ;
166/308.2; 166/305.1; 507/205 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/16 20060101 E21B043/16 |
Claims
1. A method for treating a subterranean formation comprising: (a)
providing a chemomechanical treatment fluid comprising a base
fluid, a nonamphoteric surfactant, and a halide salt, wherein the
nonamphoteric surfactant is dissolved in the base fluid at a
concentration below its critical micelle concentration; (b)
introducing the chemomechanical treatment fluid under pressure into
the subterranean formation, the subterranean formation having a
plurality of fractures, tensile strengths, compressive strengths,
and a fracture toughness, wherein each fracture has one or more
fracture tips; (c) substantially ceasing the introduction of the
chemomechanical treatment fluid; (d) allowing the chemomechanical
treatment fluid to saturate the fracture tips; (e) allowing the
chemomechanical treatment fluid to interact with the subterranean
formation to decrease the tensile strengths, compressive strengths,
and fracture toughness of the subterranean formation; and (f)
introducing additional chemomechanical treatment fluid after step
(d) under pressure to bifurcate the fracture tips so as to from
multiple fractures from each fracture.
2. The method of claim 1 wherein the base fluid comprises an
aqueous fluid and wherein the nonamphoteric surfactant comprises
quaternary ammonium cation surfactant.
3. The method of claim 1 wherein the base fluid comprises an
aqueous fluid and wherein the nonamphoteric surfactant is ammonium
laurel sulfate, sodium lauryl sulfate, or sodium dodecyl
sulfate.
4. The method of claim 1 wherein the base fluid comprises water and
an alcohol and wherein the nonamphoteric surfactant comprises a
cationic fluorinated surfactant.
5. The method of claim 2 wherein the concentration of the
quaternary ammonium cation surfactant in base fluid is from about
100 ppm to about 250 ppm.
6. The method of claim 5 wherein the subterranean formation
comprises a limestone or a sandstone formation.
7. The method of claim 6 wherein the subterranean formation is a
low permeability formation, having a permeability of less than
about 100 mD before step (b).
8. The method of claim 7 wherein the halide salt is a chloride salt
or a bromide salt.
9. The method of claim 8 wherein step (f) follows step (d) with a
minimum time delay of at least about 1 hour between steps (f) and
(d).
10. The method of claim 1 wherein the base fluid comprises an
aqueous fluid, wherein the nonamphoteric surfactant comprises a
fluorinated surfactant.
11. The method of claim 1 wherein the halide salt is a chloride
salt or a bromide salt.
12. The method of claim 1 further comprising repeating steps (b)
through (f) a plurality of times.
13. A method for treating a subterranean formation comprising: (a)
providing a chemomechanical treatment fluid comprising a base
fluid, an amphoteric surfactant, and a halide salt, wherein the
amphoteric surfactant is dissolved in the base fluid at a
concentration below its critical micelle concentration; (b)
introducing the chemomechanical treatment fluid into the
subterranean formation; (c) allowing the chemomechanical treatment
fluid to interact with the subterranean formation to increase the
tensile strengths, compressive strengths, and fracture toughness of
the subterranean formation to form a treated portion of the
subterranean formation; and (d) drilling a portion of a well bore
in the treated portion of the subterranean formation.
14. The method of claim 13 wherein the base fluid comprises an
aqueous fluid and wherein the amphoteric surfactant comprises an
amphoteric flourinated surfactant.
15. The method of claim 14 wherein the concentration of the
amphoteric flourinated surfactant in the base fluid comprises is
from about 100 ppm to about 250 ppm.
16. The method of claim 13 wherein the step (b) further comprises
introducing the chemomechanical treatment fluid into the well
bore.
17. The method of claim 15 wherein the subterranean formation
comprises a limestone or a sandstone formation.
18. The method of claim 13 wherein the subterranean formation is a
low permeability formation, having a permeability of less than
about 100 mD before step (b).
19. The method of claim 17 wherein the halide salt is a chloride
salt or a bromide salt.
20. The method of claim 19 wherein step (f) follows step (d) with a
minimum time delay of at least about 1 hour between steps (f) and
(d).
21. The method of claim 19 wherein step (f) follows step (d) with a
minimum time delay of from about 15 minutes to about 1 hour between
steps (f) and (d).
22. The method of claim 13 wherein the base fluid comprises an
aqueous fluid and wherein the amphoteric surfactant comprises a
fluorinated surfactant.
23. The method of claim 13 wherein the halide salt is a chloride
salt or a bromide salt.
24. An enhanced hydrocarbon recovery method comprising: providing a
chemomechanical treatment fluid comprising an aqueous base fluid, a
surfactant, and a halide salt, wherein the surfactant is dissolved
in the aqueous base fluid at a concentration below its critical
micelle concentration; introducing the chemomechanical treatment
fluid into the subterranean formation by way of an injection well;
allowing the chemomechanical treatment fluid to interact with the
subterranean formation to decrease the tensile strengths,
compressive strengths, and fracture toughness of the subterranean
formation; and sweeping hydrocarbons towards a production well
using the chemomechanical treatment fluid as a driving fluid for
motivating the hydrocarbons towards the production well.
25. The method of claim 24 wherein the surfactant is an amphoteric
surfactant and wherein the halide salt comprises an iodide
salt.
26. The method of claim 24 wherein the subterranean formation is a
limestone or a sandstone formation.
27. A chemomechanical treating fluid for treating subterranean
formations comprising: an aqueous base fluid wherein the aqueous
base fluid comprises water and an alcohol; a nonamphoteric
surfactant wherein the nonamphoteric surfactant is dissolved in the
aqueous base fluid at a concentration below its critical micelle
concentration; and a halide salt.
28. The method of claim 27 wherein the nonamphoteric surfactant
comprises a nonionic fluorinated surfactant.
29. The method of claim 28 wherein the nonamphoteric surfactant
comprises an amine oxide based fluorinated surfactant.
30. The method of claim 29 wherein the concentration of ammonium
laurel sulfate in the base fluid is from about 100 ppm to about 250
ppm.
31. The method of claim 30 wherein the halide salt is a chloride
salt or a bromide salt.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which
claims the benefit of and priority to U.S. Provisional Application
Ser. No. 61/432,495 filed Jan. 13, 2011, entitled "Chemomechanical
Treatment Fluids and Methods of Use," which is hereby incorporated
by reference in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates generally to methods and
systems for treating subterranean formations. More particularly,
but not by way of limitation, embodiments of the present invention
include methods and systems for favorably altering the
chemomechanical properties of subterranean formations with
treatment fluids comprising surfactants and halide salts.
BACKGROUND
[0003] Hydrocarbons occupy pore spaces in subterranean formations
such as, in sandstone and limestone formations. The pore spaces are
often interconnected and have a certain permeability, which is a
measure of the ability of the rock to transmit fluid flow.
Maximizing production from low permeability reservoirs remains a
continuing challenge in the hydrocarbon producing industry.
[0004] A variety of conventional methods have been used to improve
the permeability of formations to enhance hydrocarbon recovery.
Examples of such treatment methods include stimulation operations
such as fracturing and acid stimulation operations.
[0005] Hydraulic fracturing is a process by which a fluid under
high pressure is injected into the formation to create and/or
extend fractures that penetrate into the formation. These fractures
can create flow channels to improve well productivity. Propping
agents of various kinds, chemical or physical, may be used to hold
the fractures open and to prevent the healing of the fractures
after the fracturing pressure is released. Acid stimulation, on the
other hand, is a chemical stimulation method that involves the
injection of acid solutions that create porous channels throughout
the formation to improve the permeability and porosity of the
formation.
[0006] While conventional methods are typically effective at
improving the hydrocarbon producing characteristics of a formation,
at least in the short term, operators continually seek to enhance
reservoir productivity.
[0007] Other applications that may benefit from altering the
petrochemical properties of hydrocarbon reservoirs include enhanced
treatment fluids or completion fluids used prior to or
simultaneously with drilling operations. For example, any treatment
operation that increases a drilling operations rate-of-penetration
(ROP) is usually desirable. At the same time, preventing a
phenomenon referred to as washouts or loss of drilling mud or
completion fluids is also desirable during some operations such as
completion operations. Therefore, treating a subterranean formation
so as to alter its petrochemical properties to achieve improved
production characteristics continues to evoke high interest in the
industry.
SUMMARY
[0008] The present invention relates generally to methods and
systems for treating subterranean formations. More particularly,
but not by way of limitation, embodiments of the present invention
include methods and systems for favorably altering the
chemomechanical properties of subterranean formations with
treatment fluids comprising surfactants and halide salts.
[0009] One example of a method for treating a subterranean
formation comprises: (a) providing a chemomechanical treatment
fluid comprising a base fluid, a nonamphoteric surfactant, and a
halide salt, wherein the nonamphoteric surfactant is dissolved in
the base fluid at a concentration below its critical micelle
concentration; (b) introducing the chemomechanical treatment fluid
under pressure into the subterranean formation, the subterranean
formation having a plurality of fractures, tensile strengths,
compressive strengths, and a fracture toughness, wherein each
fracture has one or more fracture tips; (c) substantially ceasing
the introduction of the chemomechanical treatment fluid; (d)
allowing the chemomechanical treatment fluid to saturate the
fracture tips; (e) allowing the chemomechanical treatment fluid to
interact with the subterranean formation to decrease the tensile
strengths, compressive strengths, and fracture toughness of the
subterranean formation; and (f) introducing additional
chemomechanical treatment fluid after step (d) under pressure to
bifurcate the fracture tips so as to from multiple fractures from
each fracture.
[0010] One example of a method for treating a subterranean
formation comprises: (a) providing a chemomechanical treatment
fluid comprising a base fluid, an amphoteric surfactant, and a
halide salt, wherein the amphoteric surfactant is dissolved in the
base fluid at a concentration below its critical micelle
concentration; (b) introducing the chemomechanical treatment fluid
into the subterranean formation; (c) allowing the chemomechanical
treatment fluid to interact with the subterranean formation to
increase the tensile strengths, compressive strengths, and fracture
toughness of the subterranean formation to form a treated portion
of the subterranean formation; and (d) drilling a portion of a well
bore in the treated portion of the subterranean formation.
[0011] One example of an enhanced hydrocarbon recovery method
comprises: providing a chemomechanical treatment fluid comprising
an aqueous base fluid, a surfactant, and a halide salt, wherein the
surfactant is dissolved in the aqueous base fluid at a
concentration below its critical micelle concentration; introducing
the chemomechanical treatment fluid into the subterranean formation
by way of an injection well; allowing the chemomechanical treatment
fluid to interact with the subterranean formation to decrease the
tensile strengths, compressive strengths, and fracture toughness of
the subterranean formation; and sweeping hydrocarbons towards a
production well using the chemomechanical treatment fluid as a
driving fluid for motivating the hydrocarbons towards the
production well.
[0012] One example of a chemomechanical treating fluid for treating
subterranean formations comprises: an aqueous base fluid wherein
the aqueous base fluid comprises water and an alcohol; a
nonamphoteric surfactant wherein the nonamphoteric surfactant is
dissolved in the aqueous base fluid at a concentration below its
critical micelle concentration; and a halide salt.
[0013] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying figures,
wherein:
[0015] FIG. 1 compares tensile strengths of carbonate-rich rock
samples soaked in various surfactants.
[0016] FIG. 2 shows average tensile strengths results of the rock
samples of FIG. 1 for each of the surfactants.
[0017] FIG. 3 compares tensile strengths of quartz-rich sandstone
rock samples both dry and soaked in various surfactants.
[0018] FIG. 4 shows average tensile strengths results of the rock
samples of FIG. 3 for each of the surfactants.
[0019] FIG. 5 compares fracture toughness of carbonate-rich rock
samples both dry and soaked in various surfactants.
[0020] FIG. 6 compares the rock sample fracture toughness results
of FIG. 5 for each of the surfactants to that of dry rock.
[0021] FIG. 7 compares the rock sample fracture toughness of the
Eagle Ford Shales under dry and wet conditions.
[0022] FIG. 8 shows each of the Eagle Ford tests of FIG. 7 compared
to the dry sample.
[0023] While the present invention is susceptible to various
modifications and alternative forms, specific exemplary embodiments
thereof have been shown by way of example in the drawings and are
herein described in detail. It should be understood, however, that
the description herein of specific embodiments is not intended to
limit the invention to the particular forms disclosed, but on the
contrary, the intention is to cover all modifications, equivalents,
and alternatives falling within the spirit and scope of the
invention as defined by the appended claims.
DETAILED DESCRIPTION
[0024] The present invention relates generally to methods and
systems for treating subterranean formations. More particularly,
but not by way of limitation, embodiments of the present invention
include methods and systems for favorably altering the
chemomechanical properties of subterranean formations with
treatment fluids comprising surfactants and halide salts.
[0025] In certain embodiments, methods for treating subterranean
formations comprise the steps of introducing a chemomechanical
treatment fluid into the subterranean formation and allowing the
chemomechanical treatment fluid to interact with the subterranean
formation to alter its petrochemical properties in various ways.
Depending on the desired application, the chemomechanical treatment
fluid may comprise a base fluid, a halide salt and an amphoteric or
nonamphoteric surfactant where the surfactant is dissolved in the
base fluid at a concentration below its critical micelle
concentration. Applications of use involving the chemomechanical
treatment fluids include treatment operations, secondary recovery
operations, drilling operations, and any other operation that would
benefit from the formation property modifications described herein.
Subterranean formation properties that may to be varied by the
chemomechanical treatment fluid include, but are not limited to,
fracture toughness, tensile strength, or a combination thereof.
Other enhancements of the methods are described further below.
[0026] Reference will now be made in detail to embodiments of the
invention, one or more examples of which are illustrated in the
accompanying drawings. Each example is provided by way of
explanation of the invention, not as a limitation of the invention.
It will be apparent to those skilled in the art that various
modifications and variations can be made in the present invention
without departing from the scope or spirit of the invention. For
instance, features illustrated or described as part of one
embodiment can be used on another embodiment to yield a still
further embodiment. Thus, it is intended that the present invention
cover such modifications and variations that come within the scope
of the invention.
[0027] In certain embodiments, chemomechanical treatment fluids may
comprise a base fluid, a halide salt, and a surfactant. The
chemomechanical treatment fluid may advantageously modify certain
properties of the formation, such as the fracture toughness. The
concentrations of and the types of halide salts and surfactants
employed in the chemomechanical treatment fluid influence the
interaction of the chemomechanical treatment fluid and the
formation. In certain embodiments, a plurality of halide salts
and/or surfactants may be employed as desired or as particular
applications warrant. The specific concentrations and types of
chemomechanical treatment fluids employed depend on a number of
factors, including, but not limited to, desired application,
formation lithology, cementation, mineralogy, virgin pore pressure,
formation temperature, acidity, or pH, secondary porosity, and the
presence of discontinuities (e.g. fractures, bugs, and
bedding).
[0028] The surfactant may comprise an amphoteric surfactant or a
nonamphoteric surfactant depending on the desired application. In
certain embodiments, a plurality of surfactants may be used.
[0029] Generally, nonamphoteric surfactants may be employed where a
weakening of the formation is desired, whereas amphoteric
surfactants may be employed where a strengthening of the formation
is desired. Examples of suitable nonamphoteric and amphoteric
surfactants for use with the present invention include, but are not
limited to, ammonium laurel sulfate, sodium lauryl sulfate, sodium
dodecyl sulfate, fluorinated surfactants, cationic fluorinated
surfactants, or any combination thereof. Under some conditions,
various surfactants will act as a nonamphoteric surfactant or an
amphoteric surfactant.
[0030] In certain embodiments, suitable concentrations of
surfactants include concentrations from about 100 ppm to about 250
ppm. In certain embodiments, the concentration of surfactant is
below its critical micelle concentration (CMC). The critical
micelle concentration (CMC) is the concentration of surfactants
above which micelles are spontaneously formed. Above the CMC,
surfactants start aggregating into micelles, thus again decreasing
the system's free energy by decreasing the contact area of
hydrophobic parts of the surfactant with water. Upon reaching CMC,
any further addition of surfactants will just increase the number
of micelles (in the ideal case). CMC is an important characteristic
of a surfactant. Before reaching the CMC, the surface tension
changes strongly with the concentration of the surfactant. After
reaching the CMC, the surface tension remains more constant.
[0031] The halide salt may comprise any halide salt capable of
assisting the modification of formation properties, including
weakening or strengthening the formation as desired. Examples of
suitable halide salts for use with the present invention include,
but are limited to, chloride salts, iodide, salts, bromide salts,
fluoride salts, halide salts of potassium, or any combination
thereof. In certain embodiments, the addition of halide salts
provides beneficial petrophysical and petrochemical interactions
with the formation and may enhance the effects of the surfactants
in the chemomechanical treatment fluid.
[0032] The base fluid of the chemomechanical treatment fluid may
comprise any aqueous fluid. In certain embodiments, the base fluid
comprises water. The water may be from any source including, but
not limited to fresh water, sea water, naturally-occurring
formation water, artificially-injected formation water, or any
combination thereof. In certain embodiments, the base fluid may
comprise an alcohol as desired.
Various Methods of Use and Application
[0033] Useful applications of chemomechanical treatment fluids of
the present invention include, but are not limited to, stimulation
enhancement, fluid loss prevention during drilling applications,
prevention of disintegration or prevention of weakening of the
formation being drilled or stimulated, strengthening of the
formation being drilled or stimulated, enhancement of secondary
operations, and enhancement of hydrocarbon recovery operations.
[0034] One example of a method for stimulation enhancement
comprises treating a subterranean formation with a chemomechanical
treatment fluid to enhance a stimulation operation such as a
fracturing operation. In this example, the chemomechanical
treatment fluid may be introduced into a subterranean formation to
create a plurality of first fractures. Alternatively or
additionally, the chemomechanical treatment fluid may be introduced
into a subterranean formation that already possesses a plurality of
first fractures.
[0035] After introduction of the chemomechanical treatment fluid
into the subterranean formation, the operator may cease introducing
chemomechanical treatment fluid into the subterranean formation and
allow the chemomechanical treatment fluid to saturate the fracture
tips of the existing fractures in the subterranean formation. As
mentioned previously, interaction of the chemomechanical treatment
fluid with the formation may cause a weakening of the formation or
a reduction in the fracture toughness of the formation. During the
saturation period, the surfactants of chemomechanical treatment
fluids may alter the free surface energy of the crack face and
reduce the work required to propagate a fracture. That is,
chemomechanical treatment fluids of the present invention may
change the tensile strength and fracture toughness of the rocks by
altering the work needed to propagate microscopic cracks. Molecules
at the surface of a grain have higher bond energy than internal
molecules, so, to propagate a crack in a grain and create new
surface area, work must be done to break the bonds of an internal
molecule and crate higher energy bonds of surface grains. Surface
acting agents such as surfactants and inorganic salts adsorb and
weakly bond with the surface molecules, lowering the bond energy
and reducing the work needed to propagate a crack. Because some
surface acting agents work better than others, these principles can
be used to either increase or reduce the tensile strength and
fracture toughness in the rock of interest.
[0036] During the period of saturation, pressure may be maintained
in the formation or allowed to reduce, depending on the conditions
of the system. In certain embodiments, the time period of
saturation may vary from about 15 minutes to about half an hour to
about two hours. In certain embodiments, this delay (between
saturation of the fracture tips and subsequent introduction of
additional chemomechanical treatment fluid) allows lagging fluids
sufficient time to catch up with the tip of the propagating
fractions. This process may be repeated two or more times if
desired. This process may be referred to as the "hesitation"
method, because some fluids are left behind the tip of the fracture
and require some time for them to travel towards the moving
end.
[0037] Upon sufficient saturation of the fracture tips, additional
chemomechanical treatment fluid may be introduced under pressure to
bifurcate the fracture tips so as to form multiple fractures from
each first fracture. In certain embodiments, the saturation of the
fracture tips allows the fluid to act as a "wedge" when additional
chemomechanical treatment fluid is reintroduced into the formation.
Thus, the cyclical introduction of the chemomechanical treatment
fluid allows a wedge-splitting effect to occur so as to enhance the
fracture tip birfurcations. These cyclical introductions of the
chemomechanical treatment fluid may be repeated a plurality of
times as desired. The subsequent reintroductions of chemomechanical
treatment fluid should be sufficient to increase the pressure above
the fracturing pressure. For most reservoirs, any rate of injection
will be suitable if the injection rate imparts a downhole pressure
that is near or above the parting pressure of the formation being
treated (e.g. between about 500 psi and about 5,000 psi). In
general, the fractures may extend radially at least about 10 feet
from the well bore into the formation.
[0038] The stimulation enhancement methods described herein may
have particular suitability in limestone formations, sandstone
formations, low permeability formations, or any combination
thereof. In certain embodiments, the applications described herein
may have particular advantage in formations having low
permeabilities of less than about 100 mD.
[0039] Another useful application of the chemomechanical treatment
fluids described herein include treatment of subterranean
formations in anticipation of drilling. Alternatively or
additionally, treatment operations may also be performed
simultaneously while drilling.
[0040] In such drilling applications, the chemomechanical treatment
fluids may interact with the subterranean formation around the
wellbore to increase the fracture toughness of the formation.
Increasing the fracture toughness of the formation may be
advantageous in certain embodiments by preventing washouts or fluid
loss during certain drilling or treatment operations. Increasing
fracture toughness may also aid in preventing well collapse.
[0041] In certain situations, decreasing the fracture toughness may
be desired to increase the rate of penetration of drilling. Thus,
if desired, the composition of the chemomechanical treatment fluids
will be chosen to decrease rather than increase the fracture
toughness of the subterranean formation. In some cases,
chemomechanical treatment fluids may be included as one component
of a drilling mud or other completion fluid.
[0042] Other beneficial applications of chemomechanical treatment
fluids of the present invention include using chemomechanical
treatment fluids to enhance secondary operations such as water
flood sweeps. In this way, chemomechanical treatment fluids may be
used as a water flood to enhance recovery of hydrocarbons by
"sweeping" any hydrocarbons remaining in place towards a production
well. In addition to the chemomechanical treatment fluid
functioning as a water flood, the chemomechanical treatment fluid
may also act to beneficially modify the properties of the
subterranean formation so as to increase the permeability of the
formation. Additionally or alternatively, the chemomechanical
treatment fluid may also act to change the fracture toughness of
the formation in anticipation of a treatment operation, a
stimulation operation, or a drilling operation.
[0043] All or a portion of the surfactants and the halide salts may
be encapsulated in a time-delay encapsulation material. Any
encapsulation method known in the art may be used including, but
not limited to, those encapsulating materials which degrade based
on chemical or thermal conditions. In this way, chemomechanical
treatment fluids may be designed to more efficiently target one or
more zones of a subterranean formation. Some embodiments of
chemomechanical treatment fluids may include multiple types of
surfactants and/or halide salts as desired. Where multiple
surfactants and/or halide salts are used, one or more of each may
be coated in a time-delay release encapsulation for delayed
activation or delivery of the chemical agent.
[0044] Where multiple geological subterranean zones are present
next to one another, operators may wish to target each subterranean
zone with an eye towards modifying the properties of each
subterranean zone in a different way. For example, a reservoir
layer may be bounded above and below by adjacent barrier layers. In
certain embodiments, one may wish to increase the fracture
toughness of the barrier layers while simultaneously decreasing the
fracture toughness of the reservoir layer. Because one
chemomechanical treatment fluid may have differing effects on
differing geological adjacent layers, under some circumstances, an
operator may be able to advantageously increase the fracture
toughness of one geological layer while simultaneously decreasing
the fracture toughness of another geological layer.
[0045] It is explicitly recognized that any of the elements and
features of each of the methods described herein are capable of use
with any of the other methods described herein with no limitation.
Furthermore, it is explicitly recognized that the steps of the
methods herein may be performed in any order except unless
explicitly stated otherwise or inherently required otherwise by the
particular method.
[0046] To facilitate a better understanding of the present
invention, the following examples of certain embodiments are given.
In no way should the following examples be read to limit, or
define, the scope of the invention.
EXAMPLES
[0047] In one test, we measured the tensile strength of
carbonate-rich rock samples from the Eagle Ford Reservoir, that
were soaked in various chemical additives. FIG. 1 compares tensile
strengths of carbonate-rich rock samples soaked in various
surfactants. As shown in FIG. 1, the chloride-rich fluid (KCl) was
not as effective as the other fluids (or surfactants).
[0048] FIG. 2 shows average tensile strengths results of the rock
samples of FIG. 1 for each of the surfactants.
[0049] FIG. 3 compares tensile strengths of quartz-rich sandstone
rock samples both dry and soaked in various surfactants. Here, the
same type of tensile strength was employed to test rock specimens
from a quartz-rich sandstone formation called the "Tensleep"
formation. FIG. 3 shows the results of each specimen with no fluid
(dry), and saturated with fluid such as a chloride (KCl) or
surfactant (FS 50 and TLF 10652). FIG. 4 shows average tensile
strengths results of the rock samples of FIG. 3 for each of the
surfactants. The average for each fluid-group for the Tensleep
tests (in FIG. 3) are given in FIG. 4 where the average tensile
strength with the chloride fluid (KCl) is only slightly lower than
the average dry strength but those with the surfactants are lower
by as much as 18%.
[0050] We also measured a strength called "Fracture Toughness", the
resistance of a material to propagate a tensile fracture. FIG. 5
shows the results for the Tensleep sandstone's fracture toughness,
comparing the effects of 3 fluids and the dry rock. In this Figure,
the fracture toughness of carbonate-rich rock samples is compared
for both dry and soaked in various surfactants.
[0051] FIG. 6 compares the rock sample fracture toughness results
of FIG. 5 in terms of percent-reduction of toughness relative to
the average dry fracture toughness. The chloride-rich fluid and the
surfactant TLF 10652 have the most weakening effect relative to dry
rock.
[0052] For the Eagle Ford carbonate-rich shales, the same fracture
toughness experiments shown in FIG. 7 for wet samples and one dry
sample with dry toughness of 1,240 psi-square-root of (inch). FIG.
8 shows each of the Eagle Ford tests compared to the dry sample,
where fluids lower the strength, relative to the dry condition, by
27% to 41%.
[0053] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The 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 therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations and equivalents are considered within the
scope and spirit of the present invention.
* * * * *