U.S. patent application number 15/300803 was filed with the patent office on 2017-01-19 for smart lcm for strengthening earthen formations.
The applicant listed for this patent is M-I L.L.C.. Invention is credited to Guido De Stefano, James Friedheim, Steven Young.
Application Number | 20170015887 15/300803 |
Document ID | / |
Family ID | 54241151 |
Filed Date | 2017-01-19 |
United States Patent
Application |
20170015887 |
Kind Code |
A1 |
De Stefano; Guido ; et
al. |
January 19, 2017 |
SMART LCM FOR STRENGTHENING EARTHEN FORMATIONS
Abstract
Methods for treating an earthen formation may include: drilling
at least a section of a wellbore using a first wellbore fluid
containing a first base fluid, and a first LCM-forming component;
injecting, upon experience of a fluid loss, a second wellbore fluid
containing a second base fluid, and a second LCM-forming component;
and reacting the first LCM-forming component with the second
LCM-forming component to form an LCM that reduces the fluid loss. A
fluid system may include a first component containing a first base
fluid and a first LCM-forming component; and a second component
containing a second base fluid and a second LCM-forming component,
wherein the second LCM-forming component is capable of reacting
with the first LCM-forming component to form a LCM.
Inventors: |
De Stefano; Guido; (Houston,
TX) ; Friedheim; James; (Spring, TX) ; Young;
Steven; (Cypress, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
M-I L.L.C. |
Houston |
TX |
US |
|
|
Family ID: |
54241151 |
Appl. No.: |
15/300803 |
Filed: |
March 30, 2015 |
PCT Filed: |
March 30, 2015 |
PCT NO: |
PCT/US2015/023253 |
371 Date: |
September 30, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61972871 |
Mar 31, 2014 |
|
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|
61972755 |
Mar 31, 2014 |
|
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61972805 |
Mar 31, 2014 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 8/508 20130101;
E21B 21/003 20130101; C09K 8/512 20130101; C09K 8/502 20130101;
C09K 8/32 20130101; C09K 8/035 20130101; C09K 8/506 20130101; E21B
33/138 20130101; C09K 8/516 20130101; C09K 8/36 20130101; C09K
8/032 20130101 |
International
Class: |
C09K 8/035 20060101
C09K008/035; E21B 21/00 20060101 E21B021/00; C09K 8/03 20060101
C09K008/03 |
Claims
1. A method comprising: drilling at least a section of a wellbore
using a first wellbore fluid comprising: a first base fluid, and a
first LCM-forming component; injecting, upon experience of a fluid
loss, a second wellbore fluid comprising: a second base fluid, and
a second LCM-forming component; and reacting the first LCM-forming
component with the second LCM-forming component to form an LCM that
reduces the fluid loss.
2. The method of claim 1, wherein the first base fluid is an invert
emulsion.
3. The method of claim 1, further comprising resuming drilling
operations after the formed LCM reduces fluid loss.
4. The method of claim 1, wherein injecting the second wellbore
fluid comprises injecting the second wellbore fluid through an
opening present on a drill bit and/or drill string.
5. The method of claim 1, wherein forming an LCM is triggered by
temperature, electromagnetic radiation, pH, or shear.
6. The method of claim 1, wherein the second LCM-forming component
is encapsulated.
7. The method of claim 5, wherein the encapsulated second
LCM-forming component remains encapsulated when exposed to shear
forces below about 15,000 s.sup.-1.
8. The method of claim 6, wherein the encapsulated second
LCM-forming component is activated by subjecting the encapsulated
second LCM-forming component to shear forces of at least 15,000
s.sup.-1.
9. The method of claim 7, wherein the shear forces are generated by
pumping the second wellbore fluid through an opening present on a
drill bit and/or drill string.
10. The method of claim 5, wherein the encapsulated second
LCM-forming component is activated by temperature, electromagnetic
radiation, pH, or shear.
11. The method of claim 1, wherein the first LCM-forming component
is one or more silicates, and the second LCM-forming component is
at least one of an alcohol, polyol, amine, or polyamine.
12. The method of claim 1, wherein the first LCM-forming component
is at least one of an alcohol, polyol, amine, or polyamine; and the
second LCM-forming component is one or more silicates.
13. The method of claim 1, wherein the second wellbore fluid is
pumped as a fluid loss pill.
14. The method of claim 1, wherein the formed LCM is an alcohol
crosslinked silicate.
15. A fluid system comprising: a first component comprising a first
base fluid and a first LCM-forming component; and a second
component comprising a second base fluid and a second LCM-forming
component, wherein the second LCM-forming component is capable of
reacting with the first LCM-forming component to form a LCM.
16. The system of claim 15, wherein the second LCM-forming
component is encapsulated.
17. The system of claim 16, wherein the encapsulated second
LCM-forming component remains encapsulated when exposed to shear
forces below about 15,000 s.sup.-1.
18. The system of claim 15, wherein the first base fluid is an
invert emulsion.
19. The system of claim 15, wherein the first LCM-forming component
is at least one of alcohol, polyol, amine, or polyamine; and the
second LCM-forming component is one or more silicates.
20. The system of claim 15, wherein the first LCM-forming component
is one or more silicates; and the second LCM-forming component is
at least one of an alcohol, polyol, amine, or polyamine.
21. A method comprising drilling at least a section of a wellbore
with a wellbore fluid comprising: a base fluid; and an encapsulated
LCM component, wherein the encapsulated LCM component is inactive
when exposed to shear forces below about 10,000 s.sup.-1.
22. The method of claim 21, wherein the encapsulated LCM component
become at least partially active when exposed to shear forces
greater than about 12,000 s.sup.-1.
23. The method of claim 21, wherein the encapsulated LCM component
becomes at least partially active when exposed to shear forces
greater than about 15,000 s.sup.-1.
Description
RELATED APPLICATION
[0001] This application claims priority to and the benefit of U.S.
Provisional Patent Application having Ser. No. 61/972,871, filed 31
Mar. 2014; U.S. Provisional Patent Application having Ser. No.
61/972,755, filed 31 Mar. 2014; and U.S. Provisional Patent
Application having Ser. No. 61/972,805, filed 31 Mar. 2014, which
are all incorporated by reference in their entirety.
BACKGROUND
[0002] During the drilling of a wellbore, various fluids may be
used in the well for a variety of functions. The fluids may be
circulated through a drill pipe and drill bit into the wellbore,
and then may subsequently flow upward through the wellbore to the
surface. During this circulation, the drilling fluid may act to
remove drill cuttings from the bottom of the hole to the surface,
to suspend cuttings and weighting material when circulation is
interrupted, to control subsurface pressures, to maintain the
integrity of the wellbore until the well section is cased and
cemented, to isolate the fluids from the formation by providing
sufficient hydrostatic pressure to prevent the ingress of formation
fluids into the wellbore, to cool and lubricate the drill string
and bit, and/or to maximize penetration rate.
[0003] Wellbore fluids may also be used to provide sufficient
hydrostatic pressure in the well to prevent the influx and efflux
of formation fluids and wellbore fluids, respectively. When the
pore pressure (the pressure in the formation pore space provided by
the formation fluids) exceeds the pressure in the open wellbore,
the formation fluids tend to flow from the formation into the open
wellbore. Therefore, the pressure in the open wellbore is often
maintained at a higher pressure than the pore pressure. However,
when wellbore pressures are maintained above the pore pressure, the
pressure exerted by the wellbore fluids may exceed the fracture
resistance of the formation and fractures and induced mud losses
may occur. Further, formation fractures may result in the loss of
wellbore fluid that decreases the hydrostatic pressure in the
wellbore to decrease, which may in turn also allow formation fluids
to enter the wellbore. As a result, the formation fracture pressure
may define an upper limit for allowable wellbore pressure in an
open wellbore while the pore pressure defines a lower limit.
Therefore, one constraint on well design and selection of drilling
fluids is the balance between varying pore pressures and formation
fracture pressures or fracture gradients though the depth of the
well.
[0004] As stated above, wellbore fluids are circulated downhole to
remove rock, as well as deliver agents to combat the variety of
issues described above. Fluid compositions may be water- or
oil-based and may contain weighting agents, surfactants, proppants,
viscosifiers, and fluid loss additives. However, fluid loss may
impede wellbore operations, as fluids escape into the surrounding
formation. During drilling operations, variations in formation
composition may lead to undesirable fluid loss events in which
substantial amounts of wellbore fluid are lost to the formation
through large or small fissures or fractures in the formation or
through a highly porous rock matrix surrounding the borehole. While
fluid loss is often associated with drilling applications, other
fluids may experience fluid loss into the formation including
wellbore fluids used in completions, drill-in operations,
productions, etc. Lost circulation may occur naturally in
formations that are fractured, highly permeable, porous, cavernous,
or vugular.
[0005] Lost circulation may also result from induced pressure
during drilling. Specifically, induced mud losses may occur when
the mud weight, which is often tuned for well control to maintain a
stable wellbore, exceeds the fracture resistance of the formations.
A particularly challenging situation arises in depleted reservoirs,
in which the drop in pore pressure effectively weakens a wellbore
through permeable, potentially hydrocarbon-bearing rock formation,
but neighboring or inter-bedded low permeability rocks maintain
their pore pressure. This can make the drilling of certain depleted
zones impossible because the mud weight employed to support lower
permeability rocks such as shale may exceed the fracture resistance
of high permeability sands and silts. Another unintentional method
by which lost circulation can result is through the inability to
remove low and high gravity solids from fluids. Without being able
to remove such solids, the fluid density can increase, thereby
increasing the hole pressure, and if such hole pressure exceeds the
formation fracture pressure, fractures and fluid loss can
result.
[0006] Various methods have been used to restore circulation of a
drilling fluid when a lost circulation event has occurred,
particularly the use of "lost circulation materials" (LCM) that
seal or block further loss of circulation. These materials may
generally be classified into several categories: surface plugging,
interstitial bridging, and/or combinations thereof. In addition to
traditional LCM pills, crosslinkable or absorbing polymers, and
cement or gunk squeezes have also been employed to combat fluid
loss downhole.
SUMMARY
[0007] In one aspect, embodiments disclosed herein relate to
methods for treating an earthen formation that include: drilling at
least a section of a wellbore using a first wellbore fluid
containing a first base fluid, and a first LCM-forming component;
injecting, upon experience of a fluid loss, a second wellbore fluid
containing a second base fluid, and a second LCM-forming component;
and reacting the first LCM-forming component with the second
LCM-forming component to form an LCM that reduces the fluid
loss.
[0008] In another aspect, embodiments disclosed herein relate a
fluid system that includes: a first component containing a first
base fluid and a first LCM-forming component; and a second
component containing a second base fluid and a second LCM-forming
component, wherein the second LCM-forming component is capable of
reacting with the first LCM-forming component to form a LCM.
[0009] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter. Other aspects and advantages of the disclosure will
be apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0010] FIG. 1 is a flowchart illustrating an embodiment of a method
of drilling incorporating a smart LCM of the instant
disclosure.
DETAILED DESCRIPTION
[0011] Embodiments disclosed herein relate to methods of treating
fluid loss in downhole formations. Methods and chemical systems in
accordance with the present disclosure are directed to treating
lost circulation, wherein a multi-component system capable of
reacting to form a lost circulation material (LCM) is employed. In
one or more embodiments described herein, LCM-forming components
that react to form an LCM material may be combined to form an LCM
on demand when treatment of fluid loss is experienced during a
wellbore operation. LCM-forming components may be isolated in
separate fluids, in separate phases of a single fluid, or
individual components may be isolated within a wellbore fluid in
which one or both components is encapsulated.
[0012] Embodiments of the present disclosure may be particularly
suitable for drilling through depleted sandstone formations, as
well as other depleted formation types. Depleted formations pose
numerous technical challenges, including wellbore instability,
severe lost circulation, etc., which generally make further
development uneconomical. Uncontrollable drilling fluid losses
frequently are unavoidable in the often large fracture
characteristics of these formations. While conventional wellbore
strengthening techniques often involve the use of particulates to
create a hoop stress and thus increase the strength of the
formation through formation of a stress cage, such techniques
involve the formation of new fractures, which may be undesirable
for a depleted formation. Thus, embodiments of the present
disclosure seek to strengthen the formation through the
multi-component system capable of reacting to form LCMs in situ.
The chemical reaction of the fluid components may be selectively
activated to prevent or at least reduce premature reaction within
the drill string and also achieve reaction in the near-bit area,
when desired. Thus, to achieve such selective activation, multiple
components may be incorporated into the wellbore fluid(s). To avoid
or reduce premature reaction, one of the components may be
encapsulated or otherwise rendered chemically non-reactive. Upon
activation and exposure to a second component, with which the first
component is reactive, the two (or more) components may react to
form the LCM.
[0013] In one or more embodiments, a first LCM-forming component
may be provided with a first wellbore fluid during normal wellbore
operations and, upon experiencing fluid loss into the formation, a
second LCM-forming component is introduced into the wellbore as
needed. Once injected, the second LCM-forming component may contact
the first LCM-forming component in the wellbore, which in turn
results in the formation of a LCM that seals or otherwise impedes
the flow of wellbore fluids into intervals of the wellbore
experiencing fluid loss. For example, in particular embodiments,
drilling operations may be commenced with a first LCM-forming
component dormant in a drilling fluid, while a second LCM-forming
component is added at the pit when losses are registered downhole.
The second LCM-forming component may be activated at the bit by
shear or pressure drop and react with the first LCM-forming
component in the wellbore fluid, forming a LCM material in situ
that serves to reduce fluid loss.
[0014] With particular respect to FIG. 1, a method of drilling in
accordance with the present disclosure is shown in which a
multi-component system is used to treat fluid loss. In the initial
stage, drilling mud components are mixed together with a first
LCM-forming component that remains inactive or substantially
inactive during drilling. When fluid loss is detected, such as by a
reduction in fluid pressure, a second wellbore fluid is prepared
containing a second LCM-forming component and introduced into the
wellbore near the source of fluid loss. During the injection of the
second component, the first and second LCM-forming components react
to form a LCM that enters into sites of fluid loss including, for
example, fractures, vugs, and highly permeable zones, and reduces
fluid loss. Further, because the LCM material is formed at the site
of injection when delivered from a drill bit and/or drill string,
use of wellbore fluid components and damage to the formation from
excess LCM is minimal During drilling operations using methods in
accordance with the present disclosure, any excess LCM formed may
be recovered from returned wellbore fluids and drill cuttings and
removed by techniques known in the art, such as mechanical shakers
and other separation methods. As fluid loss is reduced and fluid
pressures return to suitable levels for drilling, the injection of
the second wellbore fluid containing the second LCM-forming
component may be stopped and drilling operations may resume.
[0015] In one or more embodiments, the first LCM-forming component
may be within a wellbore fluid in a well and the second LCM-forming
component may be injected as needed in a fluid loss pill. As used
herein, the term "pill" is used to refer to a relatively small
quantity (often around 200 bbl or less) of a special blend of
wellbore fluid to accomplish a specific task that the regular
wellbore fluid cannot perform. In some embodiments, the lost
circulation pill may be used to plug a "thief zone," which simply
refers to a formation into which circulating fluids can be lost.
For example, operators on a rig may notice a decrease or cessation
in the flow of fluid returning and a volume of a wellbore fluid
containing a second LCM-forming component may be prepared and
pumped downhole to produce a LCM material that plugs the zone where
fluid is being lost. In some embodiments, the volume of the second
wellbore fluid applied as a pill may range from 1 to 30 m.sup.3,
from 3 to 20 m.sup.3, or from 5 to 16 m.sup.3.
[0016] In one or more embodiments, one or more of the components of
the LCM system may be encapsulated. In particular embodiments,
components may be released from an encapsulating coating in
response to an external stimulus or triggering event, which may
include changes in temperature or pH; degradation of the
encapsulant by enzymes, oxidants, or solvents; or physical
disruption of the encapsulant, such as by shearing, grinding, or
crushing.
[0017] In particular embodiments, the encapsulant may be designed
such that the encapsulant releases a LCM-forming component when
exposed to shear forces such as those that occur during injection
of a wellbore fluid downhole. For example, an encapsulated
component may be injected into a wellbore and as the wellbore fluid
containing the encapsulated reagent is exposed to shear forces that
occur as the fluid exits an opening in a tubular, drill string, or
drill bit, the shear forces may disrupt the encapsulating material
and release a reagent such as an LCM-forming component into the
surrounding fluid. Thus, the release and delivery of an
encapsulated component may be obtained by tuning the shear pressure
of the fluid injection in the wellbore.
[0018] Shear forces are closely related to the pressure drop
experienced by a wellbore fluid passing through constrictions in
various pumps, pipes, and drill-bits that may be present during a
particular wellbore operation. This phenomenon is also known as the
Venturi effect, which describes the physical process in which a
fluid's velocity increases as it passes through a constriction to
satisfy the principle of continuity, while its pressure decreases
to satisfy the principle of conservation of mechanical energy. The
greater the pressure differential between two particular stages
that a wellbore fluid passes through (e.g., a change in diameter of
a length of pipe or tubing), the greater the proportional pressure
drop and shear force the fluid experiences. For example, shear
forces may be highest when a fluid passes through narrow openings
or nozzles on a drill bit or a port of completion string
downhole.
[0019] In one or more embodiments, an encapsulant coating may be
designed such that the coating ruptures, thereby at least partially
activating the LCM-forming component, when exposed to shear forces
that may range from 10,000 to 30,000 s.sup.-1 in some embodiments,
or from 12,000 to 25,000 s.sup.-1. In other embodiments, activation
of the encapsulated component may occur at shear forces of at least
15,000 s.sup.-1 or at shear forces of least 20,000 s.sup.-1 in yet
other embodiments.
[0020] In some embodiments, the multi-component system may react to
form a LCM by simply contacting the individual components of the
LCM-forming system together. In other embodiments, the components
may be selected such that the reaction is optimized to
preferentially react at downhole temperatures or when exposed to
heat using one of the various downhole heating tools known in the
art. In yet other embodiments, reaction of the multi-component
system to form an LCM may be activated or accelerated by exposing
the components to electromagnetic radiation generated from a
downhole tool, including gamma, ultraviolet, microwave, and radio
wave radiation, for example.
[0021] LCM-Forming Components
[0022] In one or more embodiments, the multi-component LCM system
may form silicate polymers from the reaction of a silicate with an
alcohol, polyol, amine, or polyamine. As described above, in some
embodiments, a wellbore fluid may be formulated with either
component and the second component may be added as fluid loss is
experienced, creating LCM on demand and as needed to combat fluid
loss. Other possible embodiments include providing a single
wellbore fluid in which one or both components is encapsulated and
then forming the LCM by exposing the fluid to the proper stimulus,
e.g., a change in temperature or pH, or in response to mechanical
stress such as shear.
[0023] While not bound by a particular theory, it is believed that
the combination of the silicate species and the alcohol or amine
initiates a series of hydrolysis and condensation reactions that
serve to generally increase the molecular weight of the silicate
species and in some instances crosslink the silicate monomeric
units. The increase in molecular weight and crosslinking of the
silicate species serves to generate a viscous gel which may form a
more robust chemical seal in the filter cake where the encapsulated
particles were first embedded.
[0024] An LCM-forming silicate component in accordance with the
present disclosure may be present within a wellbore fluid as a
liquid or solid, or an encapsulated fluid or solid in some
embodiments. For example, silicates may be selected from one or
more of sodium silicate, potassium silicate, lithium silicate,
quaternary ammonium silicates, and the like.
[0025] In one or more embodiments, a silicate may be combined with
a small molecule or polymer having one or more hydroxyl groups in
order to produce a LCM. Fore example, a LCM may be prepared from
the reaction of a silicate and a hydroxyl-containing compound such
as a polyol containing 2 to 8 carbon atoms, including ethylene
glycol, 1,2-propylene glycol, 1,3-propylene glycol, 1,4-butylene
glycol, 1,5-pentanediol, 1,7-heptanediol, and the like. Other
potential alcohols included are polyoxyalkylene glycols and
water-soluble mono-alkyl ethers of glycols and polyoxyalkylene
glycols, polyoxyalkylene glycols such as polyoxyethylene glycols
and polyoxypropylene glycols, monoalkyl ethers of glycols include
monomethyl ether of ethylene glycol, monoethyl ether of ethylene
glycol, monobutyl ether of ethylene glycol, mono-methyl ether of
propyleneglycol, monobutyl ether of propylene glycol, monomethyl
ether of diethylene glycol, mono-ethyl ether of diethylene glycol,
monobutyl ether of diethylene glycol and the like.
[0026] Suitable hydroxyl-containing polymers also include
saccharides such as xanthan gum, guar gum, carboxymethylated
polysaccharides, hydroxypropyl polysaccharides, carboxymethyl,
hydroxyproply polysaccharides, and similarly derivatized starches.
Other examples include guar gum, cellulose, arabic gum, guar gum,
locust bean gum, tara gum, cassia gum, agar, alginates,
carrageenans, chitosan, scleroglucan, diutan, or modified starches
such as n-octenyl succinated starch, porous starch, and
hydroxypropyl- and/or carboxymethyl-derivatives of any of the
above. Other suitable hydroxyl-containing polymers may be selected
from synthetic polymers such as polyvinyl alcohol, partially
hydrolyzed polyvinyl acetate, and copolymers containing vinyl
alcohol or other monomers containing hydroxyl-substituted side
chains. Further, suitable crosslinkable polymers may be branched or
linear polyols with available hydroxy and/or amino groups.
[0027] Suitable amines may include small molecules and polymers
capable of reacting with a silicate to form a LCM such as, for
example: methylamine, ethylamine, propylamine, isopropylamine,
butylamine, amylamine, hexylamine aniline, toluidine amine,
xylidine amine, naphthylamine, benzylamine, di- and polyamines such
as C.sub.6-C.sub.12 diamines, phenylenediamine, ethylenediamine,
tetramethylenediamine, pentamethylenediamine, hexamethylenediamine,
octamethylenediamine, decamethylenediamine, xylylenediamine,
diphenylamine, piperazine and other compounds such as aminocaproic
acid, polyamines, alkylene polyamines, vinyl amines,
diethylenetriamine, triethylenetetramine, tetraethylenepentamine,
and the like. Other possible components include species that
contain heterogeneous functional groups such as aminoacetaldehyde
diethyl acetal, aminoacetic acid, aminobenzoic acid,
2-amino-1-butanol, 2-aminoethanol, 1-amino-2-propanol,
O-aminophenol, p-aminophenol, 1-amine-2-propanol,
6-amino-2-picoline, 2-amino-4-nitrophenol, aminosuccinic acid (DL
Aspartic acid), 2-aminopyridine, and mixtures thereof. In one or
more embodiments, suitable amino-containing components may include
polyetheramines such as the series of Jeffamines.RTM. available
from Huntsman Corporation (Dayton, Tex.).
[0028] In some embodiments, one or more of the LCM-forming
components may be encapsulated. In one or more embodiments, the
encapsulated component may include a sodium or potassium silicate
either in solid or solution form. In order to create an effective
chemical seal, the encapsulated silicate may be combined with a
second component, such as an amine, alcohol, or an alcohol or amine
produced from the corresponding hydrolyzed ester or amide.
[0029] In other embodiments, silicates may also be reacted with
multivalent cations (e.g., Ca.sup.+2, Mg.sup.+2, Al.sup.+3,
Fe.sup.+3, etc.) to produce insoluble metal silicates or metal
silicate gels. For example, upon addition of divalent calcium ions,
a monovalent silicate may react with the calcium to form a hydrated
calcium silicate. Multivalent cations may be derived from the
corresponding salts such as bicarbonates, phosphates,
polyphosphates, sulfates, etc. Such inorganic setting agents may be
included in the external phase of the fluid (or in a second
emulsion) so that, during emplacement of a fluid in a wellbore, the
setting agent is kept separate from silicate internal phase to
avoid premature crosslinking of the silicates and setting of the
fluid.
[0030] In other embodiments, the corresponding component that
initiates LCM-formation with a silicate may be an inorganic salt
such as calcium chloride (CaCl.sub.2), aluminum sulfate
(Al.sub.2(SO.sub.4).sub.3), or strontium chloride (SrCl.sub.2).
When the LCM-forming component is an inorganic salt, the reaction
with the sodium or potassium silicate first component will result
in precipitation of a calcium, aluminum, or strontium silicate LCM,
respectively, which may then treat formation defects that are the
source of fluid loss.
[0031] Water solubility of such silicates is due to the presence of
alkali metal oxides (M.sub.2O) which maintain the pH at a level
where silica (SiO.sub.2) can be dissolved. However, if the pH is
neutralized or lowered, the solubility of the silica is reduced and
it gels or polymerizes. Silicate gelation refers to the
self-polymerization or condensation of soluble silicate structures
to form a hydrous, amorphous gel structure of silicate, which
rapidly occurs at a pH below 10.5. Thus, in one or more
embodiments, pH may be used to control the deposition of silica as
a LCM. For example, a decrease in pH may be used to trigger the
precipitation of a silica LCM at the site of fluid loss when a drop
in fluid pressure is detected. In order to effect a pH change in
some embodiments, a mineral acid such as HCl or formic acid may be
encapsulated and deployed downhole. When production of the LCM is
desired, the encapsulated acid may then be activated by rupturing
the surrounding encapsulant by applying the appropriate triggering
mechanism, e.g., shearing, grinding, or temperature.
[0032] Other potential mechanisms for decreasing the pH of the
surrounding fluid and precipitating a silica LCM include injection
of an ester that hydrolyzes to produce the corresponding carboxylic
acid. Suitable esters may include formic or acetic acid ester of a
C.sub.4-C.sub.30 alcohol, which may be mono- or polyhydric. Other
esters that may find use in triggering gelation of the silicates of
the present disclosure include those releasing C.sub.1-C.sub.6
carboxylic acids, including hydroxycarboxylic acids formed by the
hydrolysis of lactones, such as .delta.-lactone and
.gamma.-lactone). In another embodiment, a hydrolyzable ester of
C.sub.1 to C.sub.6 carboxylic acid and a C.sub.2 to C.sub.30 poly
alcohol, including alkyl orthoesters, may be used.
[0033] It is also within the scope of the present disclosure to use
any one of the aforementioned inorganic salts, amines, alcohols,
esters, or amides as an encapsulated component. In these instances,
the sodium or potassium silicate component may be added and/or
emulsified into the non-aqueous wellbore fluid, and the respective
encapsulated component may be added when fluid loss is registered
in an on-demand fashion. In one or more other embodiments, as a
preventative measure against fluid loss the LCM-forming components
may be directly combined together in a single wellbore fluid
formulation and used during wellbore operations before a fluid loss
event is registered.
[0034] Encapsulation Materials
[0035] In one or more embodiments, LCM-forming components may be
released from an encapsulating coating in response to an external
stimulus or triggering event, which may include changes in
temperature or pH; degradation of the encapsulant by enzymes,
oxidants, or solvents; or physical disruption of the encapsulant,
such as by grinding or crushing. It is also envisioned that
encapsulants susceptible to triggered release may also be used in
conjunction with passive diffusion encapsulants, and combined with
any of the strategies disclosed above.
[0036] In particular embodiments, the encapsulant may be designed
such that the encapsulant releases a reagent when exposed to shear
forces such as those that occur during injection of a wellbore
fluid downhole. For example, an encapsulated reagent may be
injected into a wellbore and as the wellbore fluid containing the
encapsulated reagent is exposed to shear forces that occur as the
fluid exits an opening in a tubular, drill string, or drill bit,
the shear forces may disrupt the encapsulating material and release
the reagent into the surrounding fluid. Thus, the release and
delivery of an encapsulated reagent may be obtained by tuning the
shear pressure of the fluid injection in the wellbore.
[0037] The encapsulant coating may be designed such that the
encapsulated reagent is initially inactive, meaning that the
encapsulating reagent is not able to chemically interact with any
components external to the coating. Once exposed to shear forces,
the coating ruptures and at least partially activates the
encapsulated reagent, such that the reagent may chemically interact
with a secondary component. The coating may rupture when exposed to
shear forces that may range from 10,000 to 30,000 s.sup.-1 in some
embodiments, or from 12,000 to 25,000 s.sup.-1. In other
embodiments, activation of the encapsulated reagent may occur at
shear forces of at least 15,000 s.sup.-1 or at shear forces of
least 20,000 s.sup.-1 in yet other embodiments.
[0038] In one or more embodiments, a component may be encapsulated
in an organic coating prepared from cellulose acetate, cellulose
acetate butyrate, ethyl cellulose, hydroxymethyl cellulose,
hydroxyethyl cellulose, and the like. Other encapsulants include
polystyrene, copolymers of polystyrene with other vinylic monomers,
polymethylmethacrylate, copolymers of methylmethacrylate with other
ethylenically-unsaturated monomers, acrylic resins, polyolefins,
polyamides, polycarbonates, polystyrene, vinyl polymers such as
vinyl acetate, vinyl alcohol, vinyl chloride, vinyl butyral, and
copolymers, terpolymers, and quaternary polymers thereof. Examples
of pH-sensitive polymers include
poly(hydroxethyl)methacrylate-co-methacrylic acid) and a copolymer
of N,N,dimethylaminoethyl methacrylate and divinyl benzene.
[0039] In yet another embodiment, LCM-forming components may be
encapsulated in a coating that releases the component or components
in response to an external stimulus or triggering event, which may
include temperature, pH, enzymatic degradation, oxidants, solvents,
or physically disrupted, such as by grinding the encapsulated
components. It is also envisioned that encapsulants susceptible to
triggered release may also be used in conjunction with passive
diffusion encapsulants, and combined with any of the strategies
disclosed above.
[0040] The encapsulation material may be a heat-activated material
that remains intact prior to exposure to elevated temperatures,
such as those present in a downhole environment, and upon heating,
slowly melt and release the molecules or ions contained within. In
some embodiments, the coating may melt at a temperature greater
than 125.degree. F. (52.degree. C.). Examples of such materials are
vegetable fat, gelatin, and vegetable gums, and hydrogenated
vegetable oil. Other coatings may include materials selected from
lipid materials such as, but not limited to, mono-, di-, and
tri-glycerides, waxes, and organic and esters derived from animals,
vegetables, minerals, and modifications. Examples include glyceryl
triestearates such as soybean oil, cottonseed oil, canola oil,
carnuba wax, beeswax, bran wax, tallow, and palm kernel oil.
Heat-activated materials may also include those disclosed in U.S.
Pat. No. 6,312,741, which is incorporated herein by reference in
its entirety.
[0041] In a particular embodiment, the encapsulating material may
include enteric polymers, which are defined for the purposes of the
present disclosure, as polymers whose solubility characteristics
are pH dependent. Here, this means that component release is
promoted by a change from conditions of a first predetermined pH
value to a second predetermined pH condition.
[0042] Enteric polymers are commonly used in the pharmaceutical
industry for the controlled release of drugs and other
pharmaceutical agents over time. The use of enteric polymers allows
for the controlled release of a component under predetermined
conditions of pH, or a combination of pH and temperature. For
example, the Glascol.RTM. family of polymers are acrylic based
polymers (available form Ciba Specialty Chemicals) are considered
suitable enteric polymers for the present disclosure because the
solubility depends upon the pH of the solution. In an illustrative
embodiment of the present disclosure, an enteric polymer may be
selected as an encapsulating material that is substantially
insoluble at pH values greater than about 7.5 and that is more
soluble under conditions of decreasing pH.
[0043] Encapsulating materials may also include enzymatically
degradable polymers and polysaccharides such as galactomannan gums,
glucans, guars, derivatized guars, starch, derivatized starch,
hydroxyethyl cellulose, carboxymethyl cellulose, xanthan,
cellulose, and cellulose derivatives. Enzymatically degradable
polymers may include glycosidic linkages that are susceptible to
degradation by natural polymer degrading enzymes, which may be
selected from, for example, carbohydrases, amylases, pullulanases,
and cellulases. In other embodiments, the enzyme may be selected
from endo-amylase, exo-amylase, isoamylase, glucosidase,
amylo-glucosidase, malto-hydrolase, maltosidase, isomalto-hydrolase
or malto-hexaosidase. One skilled in the art would appreciate that
selection of an enzyme may depend on various factors such as the
type of polymeric additive used in the wellbore fluid being
degraded, the temperature of the wellbore, and the pH of wellbore
fluid
[0044] While a number of encapsulating compositions and release
mechanisms have been discussed, many methods of encapsulating and
releasing components described herein may alternatively be used
without departing from the scope of the present disclosure.
[0045] Lost circulation treatments in accordance with the present
disclosure may employ a base fluid and LCM-forming components,
weighting agents, natural or synthetic fibers, and/or bridging
agents. In yet other embodiments, the pills may include a number of
other additives known to those of ordinary skill in the art, such
as wetting agents, viscosifiers, surfactants, dispersants,
interfacial tension reducers, pH buffers, mutual solvents,
thinners, thinning agents, rheological additives and cleaning
agents.
[0046] LCM-forming components may be added to a wellbore fluid in
an amount ranging from 0.5 ppb to 80 ppb in some embodiments;
however, more or less may be desired depending on the particular
application. The amount of LCM-forming components employed may
depend on the fluid loss levels, the anticipated fractures, the
density limits for the pill in a given wellbore and/or pumping
limitations, etc.
[0047] Base Fluids
[0048] Base fluids described herein may be oil-based wellbore
fluids or invert emulsions in one or more embodiments. Suitable
oil-based or oleaginous fluids may be a natural or synthetic oil
and in some embodiments, in some embodiments the oleaginous fluid
may be selected from the group including diesel oil; mineral oil; a
synthetic oil, such as hydrogenated and unhydrogenated olefins
including polyalpha olefins, linear and branch olefins and the
like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters
of fatty acids, specifically straight chain, branched and cyclical
alkyl ethers of fatty acids, mixtures thereof and similar compounds
known to one of skill in the art; and mixtures thereof.
[0049] In other embodiments, the wellbore fluid may be an invert
emulsion having a continuous oleaginous phase and a discontinuous
aqueous (or non-oleaginous liquid) phase, among other substances
and additives. Non-oleaginous liquids may, in some embodiments,
include at least one of fresh water, sea water, brine, mixtures of
water and water-soluble organic compounds, and mixtures thereof. In
various embodiments, the non-oleaginous fluid may be a brine, which
may include seawater, aqueous solutions wherein the salt
concentration is less than that of sea water, or aqueous solutions
wherein the salt concentration is greater than that of sea water.
Salts that may be found in seawater include, but are not limited
to, sodium, calcium, aluminum, magnesium, potassium, strontium, and
lithium salts of chlorides, bromides, carbonates, iodides,
chlorates, bromates, formates, nitrates, oxides, sulfates,
silicates, phosphates and fluorides. Salts that may be incorporated
in a brine include any one or more of those present in natural
seawater or any other organic or inorganic dissolved salts.
Additionally, brines that may be used in the drilling fluids
disclosed herein may be natural or synthetic, with synthetic brines
tending to be much simpler in constitution. In one embodiment, the
density of the drilling fluid may be controlled by increasing the
salt concentration in the brine (up to saturation). In a particular
embodiment, a brine may include halide or carboxylate salts of
mono- or divalent cations of metals, such as cesium, potassium,
calcium, zinc, and/or sodium.
[0050] The amount of oleaginous liquid in the invert emulsion fluid
may vary depending upon the particular oleaginous fluid used, the
particular non-oleaginous fluid used, and the particular
application in which the invert emulsion fluid is to be employed.
However, in some embodiments, the amount of oleaginous liquid may
be sufficient to form a stable emulsion when used as the continuous
phase. In some embodiments, the amount of oleaginous liquid may be
at least about 30, or at least about 40, or at least about 50
percent by volume of the total fluid. The amount of non-oleaginous
liquid in the invert emulsion fluid may vary depending upon the
particular non-oleaginous fluid used and the particular application
in which the invert emulsion fluid is to be employed. In some
embodiments, the amount of non-oleaginous liquid may be at least
about 1 percent by volume of the total fluid, or at least about 3
percent, or at least about 5 percent. In some embodiments, the
amount may not be so great that it cannot be dispersed in the
oleaginous phase. Therefore, in certain embodiments, the amount of
non-oleaginous liquid may be less than about 90, or less than about
80, or less than about 70 percent by volume of the total fluid.
[0051] Conventional methods can be used to prepare the drilling
fluids disclosed herein, in a manner analogous to those normally
used to prepare conventional oil-based drilling fluids. In one
embodiment, a desired quantity of oleaginous fluid such as a base
oil and a suitable amount of a surfactant are mixed together and
the remaining components are added sequentially with continuous
mixing. An invert emulsion may also be formed by vigorously
agitating, mixing or shearing the oleaginous fluid and the
non-oleaginous fluid.
[0052] Wellbore Fluid Additives
[0053] Other additives that may be included in the wellbore fluids
disclosed herein include for example, wetting agents, organophilic
clays, viscosifiers, surfactants, dispersants, interfacial tension
reducers, pH buffers, mutual solvents, thinners, thinning agents
and cleaning agents. The addition of such agents should be well
known to one of ordinary skill in the art of formulating drilling
fluids and muds.
[0054] Emulsifiers that may be used in the fluids disclosed herein
include, for example, fatty acids, soaps of fatty acids,
amidoamines, polyamides, polyamines, oleate esters, such as
sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or
alcohol derivatives and combinations or derivatives of the above.
Additionally, lime or other alkaline materials may be added to
conventional invert emulsion drilling fluids and muds to maintain a
reserve alkalinity.
[0055] In some embodiments, the invert emulsion may be a high
internal phase ratio (HIPR) emulsion, wherein the aqueous or
non-oleaginous fluid within the oleaginous fluid is present in a
volume amount that is more than the non-oleaginous fluid. While a
number of possible emulsifiers may be used, one exemplary class of
emulsifiers is alkoxylated ether acids. In one or more embodiments,
an alkoxylated ether acid is an alkoxylated fatty alcohol
terminated with an carboxylic acid, represented by the following
formula:
##STR00001##
where R is C.sub.6-C.sub.24 or --C(O)R.sup.3 (where R.sup.3 is
C.sub.10-C.sub.22), R.sup.1 is H or C.sub.1-C.sub.4, R.sup.2 is
C.sub.1-C.sub.5 and n may range from 1 to 20. Such compound may be
formed by the reaction of an alcohol with a polyether (such as
poly(ethylene oxide), poly(propylene oxide), poly(butylene oxide),
or copolymers of ethylene oxide, propylene oxide, and/or butylene
oxide) to form an alkoxylated alcohol. The alkoxylated alcohol may
then be reacted with an .alpha.-halocarboxylic acid (such as
chloroacetic acid, chloropropionic acid, etc.) to form the
alkoxylated ether acid. In a particular embodiment, the selection
of n may be based on the lipophilicity of the compound and the type
of polyether used in the alkoxylation. In some particular
embodiments, where R.sup.1 is H (formed from reaction with
poly(ethylene oxide)), n may be 2 to 10 (between 2 and 5 in some
embodiments and between 2 and 4 in more particular embodiments). In
other particular embodiments, where R.sup.1 is --CH.sub.3, n may
range up to 20 (and up to 15 in other embodiments). Further,
selection of R (or R.sup.3) and R.sup.2 may also depend on based on
the hydrophilicity of the compound due to the extent of
polyetherification (i.e., number of n). In selecting each R (or
R.sup.3), R.sup.1, R.sup.2, and n, the relative hydrophilicity and
lipophilicity contributed by each selection may be considered so
that the desired HLB value may be achieved. Further, while this
emulsifier may be particularly suitable for use in creating a fluid
having a greater than 50% non-oleaginous internal phase,
embodiments of the present disclosure may also include invert
emulsion fluids formed with such emulsifier at lower internal phase
amounts.
[0056] Wetting agents that may be suitable for use in the fluids
disclosed herein include crude tall oil, oxidized crude tall oil,
surfactants, organic phosphate esters, modified imidazolines and
amidoamines, alkyl aromatic sulfates and sulfonates, and the like,
and combinations or derivatives of these. However, when used with
the invert emulsion fluid, the use of fatty acid wetting agents
should be minimized so as to not adversely affect the reversibility
of the invert emulsion disclosed herein. FAZE-WET.TM.,
VERSACOAT.TM., SUREWET.TM., VERSAWET.TM., and VERSAWET.TM. NS are
examples of commercially available wetting agents manufactured and
distributed by M-I L.L.C. that may be used in the fluids disclosed
herein. Silwet L-77, L-7001, L7605, and L-7622 are examples of
commercially available surfactants and wetting agents manufactured
and distributed by General Electric Company (Wilton, Conn.).
[0057] Organophilic clays, normally amine treated clays, may be
useful as viscosifiers and/or emulsion stabilizers in the fluid
composition disclosed herein. Other viscosifiers, such as oil
soluble polymers, polyamide resins, polycarboxylic acids and soaps
can also be used. The amount of viscosifier used in the composition
can vary upon the end use of the composition. However, normally
about 0.1% to 6% by weight range is sufficient for most
applications. VG-69.TM. and VG-PLUS.TM. are organoclay materials
distributed by M-I, L.L.C., Houston, Tex., and VERSA-HRP.TM. is a
polyamide resin material manufactured and distributed by M-I,
L.L.C., that may be used in the fluids disclosed herein. In some
embodiments, the viscosity of the displacement fluids is
sufficiently high such that the displacement fluid may act as its
own displacement pill in a well.
[0058] Conventional suspending agents that may be used in the
fluids disclosed herein include organophilic clays, amine treated
clays, oil soluble polymers, polyamide resins, polycarboxylic
acids, and soaps. The amount of conventional suspending agent used
in the composition, if any, may vary depending upon the end use of
the composition. However, normally about 0.1% to about 6% by weight
is sufficient for most applications. VG-69.TM. and VG-PLUS.TM. are
organoclay materials distributed by M-I L.L.C., and VERSA-HRP.TM.
is a polyamide resin material manufactured and distributed by M-I
L.L.C., that may be used in the fluids disclosed herein.
[0059] One skilled in the art would appreciate that depending on
components present in the fluid, the pH of the fluid may change. In
particular embodiments of the present disclosure, the pH of the LCM
treatment fluid may be less than about 10, and between about 7.5
and 8.5 in other embodiments. However, in other embodiments, a
greater pH may be desired, and may be achieved by including an
alkaline material such as lime to the pill.
[0060] In one or more embodiments, wellbore fluids in accordance
with the present disclosure may include at least one fiber additive
to aid in suspension and to provide additional compressive strength
to the resulting plug or seal. However, other embodiments may use
other LCM materials, where the addition of the fiber may restore at
least a portion of the strength loss due to the incorporation of a
weighting agent. As used herein, the term "fiber" refers to an
additive that has an elongated structure. The fiber may be inert
with respect to the base fluid and the LCM-forming components.
[0061] Various embodiments of the present disclosure may use a
fiber that has an elongated structure, which may be spun into
filaments or used as a component of a composite material such as
paper. In a particular embodiment, the fibers may range in length
from greater than 3 mm to less than 20 mm. While some embodiments
may use a synthetic fiber, other embodiments may include either a
naturally occurring fibrous (such as cellulose) material, and/or a
synthetic (such as polyethylene, or polypropylene) fibrous
material.
[0062] Synthetic fibers may include, for example, polyester,
acrylic, polyamide, polyolefins, polyaramid, polyurethane, vinyl
polymers, glass fibers, carbon fibers, regenerated cellulose
(rayon), and blends thereof. Vinyl polymers may include, for
example, polyvinyl alcohol. Polyesters may include, for example,
polyethylene terephthalate, polytriphenylene terephthalate,
polybutylene terephthalate, polylatic acid, and combinations
thereof. Polyamides may include, for example, nylon 6, nylon 6,6,
and combinations thereof. Polyolefins may include, for example,
propylene based homopolymers, copolymers, and multi-block
interpolymers, and ethylene based homopolymers, copolymers, and
multi-block interpolymers, and combinations thereof. The fiber may
be added to the pill in an amount ranging from 0.5 ppb to 10 ppb in
some embodiments; however, more or less may be desired depending on
the particular application.
[0063] A natural fiber may optionally be used with the LCM
materials (including silicate particles or other LCM materials) to
aid in suspension and viscosification of the slurry, as well as
provide additional compressive strength to the resulting plug or
seal. As used herein, the term "natural fiber" refers to an
additive formed from a naturally occurring material that has an
elongated structure, which may be spun into filaments or used as a
component of a composite material such as paper. Similar to the
synthetic fiber described above, the natural fiber may be inert
(does not react with) with respect to the base fluid and to the LCM
materials. When included, natural fibers may be present in an
amount up to 50 percent by weight of the pill.
[0064] Natural fibers generally include vegetable fibers, wood
fibers, animal fibers, and mineral fibers. In particular, the
natural fibers include cellulose, a polysaccharide containing up to
thousands of glucose units. Cellulose from wood pulp has typical
chain lengths between 300 and 1700 units, whereas cotton and other
plant fibers as well as bacterial celluloses have chain lengths
ranging from 800 to 10,000 units. In other embodiments, cellulose
fibers may be either virgin or recycled, extracted from a wide
range of plant species such as cotton, straw, flax, wood, etc.
[0065] Further, as mentioned above, the pills of the present
disclosure may optionally include at least one weighting agent to
provide the desired weight to the pills. As is known in the art,
control of density may be desired to balance pressures in the well
and prevent a blowout. To prevent a blowout, the fluid in the well
may have a density effective to provide a greater pressure than
that exerted from the formation into the well. However, fluids
having a density that place pressures on the formation that exceed
the fracture strength of the formation may cause further lost
circulation. Thus, it is often desirable to modify the density of a
wellbore fluid with weighting agents to balance the pressure
requirements of the well. Weighting agents may be selected from one
or more of the materials including, for example, barium sulfate,
calcium carbonate, dolomite, ilmenite, hematite or other iron ores,
olivine, siderite, manganese oxide, and strontium sulfate.
Additionally, it is also within the scope of the present disclosure
that the fluid may also be weighted up using salts (either in a
water- or oil-based pill) such as those described above with
respect to brine types. Selection of a particular material may
depend largely on the density of the material. The lowest wellbore
fluid viscosity at any particular density is obtained by using the
highest density particles. Weighting agents may be added to the
pill in an amount such that the final density may range from 6.5
pounds per gallon (ppg) to 20 ppg in some embodiments.
[0066] In addition to the above materials within the scope of the
present disclosure tja that bridging agents may also be
incorporated into a wellbore fluid. Particulate-based treatments
may include use of particles frequently referred to in the art as
bridging materials. For example, such bridging materials may
include at least one substantially crush resistant particulate
solid such that the bridging material props open and bridges or
plugs the fractures (cracks and fissures) that are induced in the
wall of the wellbore. As used herein, "crush resistant" refers to a
bridging material is physically strong enough to resist the closure
stresses exerted on the fracture bridge. Examples of bridging
materials suitable for use in the present disclosure include
graphite, calcium carbonate (such as marble), dolomite
(MgCO.sub.3.CaCO.sub.3), celluloses, micas, proppant materials such
as sands or ceramic particles and combinations thereof. Such
particles may range in size from 25 microns to 1500 microns.
Selection of size may depend on the level of fluid loss, the
fracture width, the formation type, etc.
[0067] Application of LCM-forming components adjacent a permeable
formation may be accomplished by methods known in the art. For
example, "thief zones" or permeable intervals will often be at or
near the bottom of the wellbore and will begin to absorb drilling
fluids when exposed during drilling operations. In such situations,
a LCM treatment may be spotted adjacent the permeable formation by
pumping a slug or pill of the treatment down and out of the drill
pipe or drill bit as is known in the art. It may be, however, that
the permeable formation is at a point farther up in the wellbore,
which may result, for example, from failure of a previous seal. In
such cases, the drill pipe may be raised as is known in the art so
that the pill or slug of the LCM treatment may be deposited
adjacent the permeable formation. The volume of the slug of LCM
treatment that is spotted adjacent the permeable formation may
range from less than that of the open hole to more than double that
of the open hole.
[0068] In some instances, more than one sequence of the described
fluid system treatments may be applied to produce sufficient LCM
material to treat a given interval experiencing fluid loss. Such
need may arise when a first treatment is insufficient to plug the
fissures and thief zone or was placed incorrectly. Further, in some
instances, the first round of treatment may have sufficiently
plugged the first lost circulation zone, but a second (or more)
lost circulation zone may also exist that warrants further
treatment.
[0069] It is also within the scope of the present disclosure that
one or more spacer pills may be used in conjunction with the pills
of the present disclosure. A spacer is generally characterized as a
thickened composition that functions primarily as a fluid piston in
displacing fluids present in the wellbore and/or separating two
fluids from each other.
[0070] Embodiments of the present disclosure may provide for a lost
circulation fluid that may be useful in high and low fluid loss
zones. Use of the fluid systems of the present disclosure may allow
for the formation of a plug or seal of a permeable formation that
has a high compressive strength, which allows for greater pressures
to be used without risk of experiencing further losses to the
sealed lost circulation zone.
[0071] While the disclosure has presented a limited number of
embodiments, those skilled in the art, having benefit of this
disclosure, will appreciate that other embodiments can be devised
which do not depart from the scope of the disclosure as presented
herein. Moreover, embodiments described herein may be practiced in
the absence of any element that is not specifically disclosed
herein. Accordingly, the scope of the disclosure should be limited
only by the attached claims.
* * * * *