U.S. patent application number 13/488178 was filed with the patent office on 2013-12-05 for methods of using wellbore servicing compositions.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Larry S. EOFF, Natalie PASCARELLA, B. Raghava REDDY. Invention is credited to Larry S. EOFF, Natalie PASCARELLA, B. Raghava REDDY.
Application Number | 20130319672 13/488178 |
Document ID | / |
Family ID | 49668834 |
Filed Date | 2013-12-05 |
United States Patent
Application |
20130319672 |
Kind Code |
A1 |
REDDY; B. Raghava ; et
al. |
December 5, 2013 |
Methods of Using Wellbore Servicing Compositions
Abstract
A method of servicing a wellbore comprising preparing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material; placing the composition within a
detrimentally permeable zone; and contacting the composition with
water. A method of servicing a wellbore comprising placing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material into the wellbore wherein the wellbore
comprises hydrocarbon-producing zones and water-producing zones and
wherein the composition enters the water-producing zone and forms a
solid mass that obstructs the flow of water in the water-producing
zone. A method of servicing wellbore comprising placing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material into a lost circulation zone within the
wellbore; and contacting the composition in situ with a water
source.
Inventors: |
REDDY; B. Raghava; (The
Woodlands, TX) ; EOFF; Larry S.; (Duncan, OK)
; PASCARELLA; Natalie; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
REDDY; B. Raghava
EOFF; Larry S.
PASCARELLA; Natalie |
The Woodlands
Duncan
Houston |
TX
OK
TX |
US
US
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
49668834 |
Appl. No.: |
13/488178 |
Filed: |
June 4, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61655190 |
Jun 4, 2012 |
|
|
|
Current U.S.
Class: |
166/293 ;
166/285; 166/292 |
Current CPC
Class: |
C09K 8/34 20130101; C09K
8/502 20130101; C09K 8/426 20130101; C09K 8/428 20130101; C04B
28/02 20130101; Y02W 30/92 20150501; Y02W 30/91 20150501; C09K 8/46
20130101; C09K 8/424 20130101; Y02W 30/94 20150501; C04B 28/02
20130101; C04B 14/06 20130101; C04B 14/106 20130101; C04B 14/14
20130101; C04B 18/08 20130101; C04B 18/141 20130101; C04B 40/06
20130101; C04B 2103/40 20130101; C04B 2103/40 20130101 |
Class at
Publication: |
166/293 ;
166/285; 166/292 |
International
Class: |
E21B 33/13 20060101
E21B033/13 |
Claims
1. A method of servicing a wellbore comprising: (a) preparing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material; (b) placing the composition within a
detrimentally permeable zone; and (c) contacting the composition
with water.
2. The method of claim 1 wherein the cementitious material
comprises a hydraulic cement.
3. The method of claim 2 wherein the cementitious material
comprises Portland cements, pozzolana cements, gypsum cements,
phosphate cements, high alumina content cements, silica cements,
high alkalinity cements, shale cements, acid/base cements, magnesia
cements, fly ash cement, zeolite cement systems, cement kiln dust
cement systems, slag cements, micro-fine cement, or combinations
thereof.
4. The method of claim 1 wherein the composition further comprises
a filler.
5. The method of claim 4 wherein the filler comprises pumice, ASTM
Class F fly ash, sand, silica, metakaolin, slag, or combinations
thereof.
6. The method of claim 1 wherein the cementitious material has an
average particle size of equal to or less than about 50
microns.
7. The method of claim 4 wherein the cementitious material has an
average particle size of equal to or less than about 50
microns.
8. The method of claim 1 wherein the cementitious material is
present in the composition in an amount of from about 15 wt. % to
about 90 wt. % based on the total weight of the composition.
9. The method of claim 1 wherein the non-aqueous carrier fluid
comprises internal olefins, linear alpha olefins, poly alpha
olefins, diesel, mineral oil, kerosene, silicone fluids, oxygenated
solvents, or combinations thereof.
10. The method of claim 1 wherein the non-aqueous carrier fluid
comprises less than about 5% water by total weight of the
fluid.
11. The method of claim 1 wherein the composition further comprises
a dehydrating agent.
12. The method of claim 1 wherein the oil-wetting surfactant has a
hydrophilic-lipophilic balance of equal to greater than about
7.
13. The method of claim 1 wherein the water-imbibition enhancing
surfactant has a hydrophilic-lipophilic balance of greater than or
equal to about 10.
14. The method of claim 13, wherein the water-imbibition enhancing
surfactant is a quaternary ammonium compound comprising a benzyl
group and an alkyl group selected from the group consisting of a
coco alkyl group and a hydrogenated tallow alkyl group.
15. The method of claim 1 wherein the water contacting the
cementitious composition is endogenous to the detrimentally
permeable zone.
16. The method of claim 1 wherein the water contacting the
cementitious composition is exogenous to the detrimentally
permeable zone.
17. The method of claim 1 wherein a portion of the cementitious
material forms a solid mass when contacted with water.
18. The method of claim 17 wherein the portion of cementitious
material that forms a solid mass when contacted with water is equal
to or greater than about 75% of the cementitious material by
weight.
19. The method of claim 1 wherein the detrimentally permeable zone
comprises an area of lost circulation.
20. The method of claim 1 wherein the detrimentally permeable zone
comprises a water-producing area in a hydrocarbon producing
wellbore.
21. The method of claim 1 wherein the detrimentally permeable zone
comprises an area of lost structural integrity in a set cement
sheath.
22. A method of servicing a wellbore comprising placing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material into the wellbore, wherein the wellbore
comprises hydrocarbon-producing zones and water-producing zones and
wherein the composition enters the water-producing zone and forms a
solid mass that obstructs the flow of water in the water-producing
zone.
23. A method of servicing wellbore comprising: placing a
composition comprising a non-aqueous carrier fluid, an oil-wetting
surfactant, a water-imbibition enhancing surfactant, and a
cementitious material into a lost circulation zone within the
wellbore; and contacting the composition in situ with a water
source.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a regular utility application which
claims priority to U.S. Provisional Patent Application Ser. No.
61/655,190, filed Jun. 4, 2012 and entitled "Design Considerations
of Oil-Based, Squeeze Cement Slurries to Prevent Unwanted Fluid
Production: Methods of Slurry Performance Evaluation and Potential
Formulation Improvements;" which is incorporated by reference
herein in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 1. Technical Field
[0004] This disclosure relates to compositions for servicing a
wellbore. More specifically, this disclosure relates to methods of
treating water producing zones and zones of detrimental
permeability.
[0005] 2. Background
[0006] A natural resource such as oil or gas residing in a
subterranean formation can be recovered by drilling a well into the
formation. The subterranean formation is usually isolated from
other formations using a technique known as well cementing. In
particular, a wellbore is typically drilled down to the
subterranean formation while circulating a drilling fluid through
the wellbore. After the drilling is terminated, a string of pipe,
e.g., casing, is run in the wellbore. Primary cementing is then
usually performed whereby a cement slurry is pumped down through
the string of pipe and into the annulus between the string of pipe
and the walls of the wellbore to allow the cement slurry to set
into an impermeable cement column and thereby seal the annulus.
[0007] Subsequently, oil or gas residing in the subterranean
formation may be recovered by driving fluid into the well using,
for example, a pressure gradient that exists between the formation
and the wellbore, the force of gravity, displacement of the fluid
using a pump or the force of another fluid injected into the well
or an adjacent well. The production of the fluid in the formation
may be increased by hydraulically fracturing the formation. That
is, a viscous fracturing fluid may pumped down the wellbore to the
formation at a rate and a pressure sufficient to form fractures
that extend into the formation, providing additional pathways
through which the oil or gas can flow to the well. Unfortunately,
water rather than oil or gas may eventually be produced by the
formation through the fractures therein. To provide for the
production of more oil or gas, a fracturing fluid may again be
pumped into the formation to form additional fractures therein.
However, the previously used fractures first must be plugged to
prevent the loss of the fracturing fluid into the formation via
those fractures.
[0008] In addition to the fracturing fluid, other fluids used in
servicing a wellbore may also be lost to the subterranean formation
while circulating the fluids in the wellbore or otherwise placing
fluids in the wellbore. In particular, the fluids may enter and be
"lost" to the subterranean formation via depleted zones, zones of
relatively low pressure, lost circulation zones having naturally
occurring fractures, weak zones having fracture gradients exceeded
by the hydrostatic pressure of the fluid, and so forth. As a
result, the service provided by such fluid is more difficult to
achieve. For example, a drilling fluid may be lost to the
formation, resulting in the circulation of the fluid in the
wellbore being terminated and/or too low to allow for further
drilling of the wellbore. Such conditions may be referred to as
partial or complete loss of circulation or lost circulation.
[0009] In addition to the loss of fluids to the formation, wellbore
servicing operations may be detrimentally impacted by the
production of water from subterranean formations designed to
produce hydrocarbons, especially in mature wells. A method commonly
used to address either the undesired loss of fluids to a formation
(i.e., lost circulation) or to inhibit the introduction of water to
a hydrocarbon-bearing formation (i.e., conformance control) is to
reduce the permeability of zones that either serve as conduits for
the influx of water or zones that serve as conduits for the efflux
of wellbore servicing fluids which are collectively included herein
as detrimentally permeable zones (DPZ). An ongoing need exists for
compositions and methods that treat DPZs.
BRIEF SUMMARY
[0010] Disclosed herein is a method of servicing a wellbore
comprising preparing a composition comprising a non-aqueous carrier
fluid, an oil-wetting surfactant, a water-imbibition enhancing
surfactant, and a cementitious material; placing the composition
within a detrimentally permeable zone; and contacting the
composition with water.
[0011] Also disclosed herein is a method of servicing a wellbore
comprising placing a composition comprising a non-aqueous carrier
fluid, an oil-wetting surfactant, a water-imbibition enhancing
surfactant, and a cementitious material into the wellbore wherein
the wellbore comprises hydrocarbon-producing zones and
water-producing zones and wherein the composition enters the
water-producing zone and forms a solid mass that obstructs the flow
of water in the water-producing zone.
[0012] Also disclosed herein is a method of servicing wellbore
comprising placing a composition comprising a non-aqueous carrier
fluid, an oil-wetting surfactant, a water-imbibition enhancing
surfactant, and a cementitious material into a lost circulation
zone within the wellbore; and contacting the composition in situ
with a water source.
[0013] The foregoing has outlined rather broadly the features and
technical advantages of the present invention in order that the
detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention
will be described hereinafter that form the subject of the claims
of the invention. It should be appreciated by those skilled in the
art that the conception and the specific embodiments disclosed may
be readily utilized as a basis for modifying or designing other
structures for carrying out the same purposes of the present
invention. It should also be realized by those skilled in the art
that such equivalent constructions do not depart from the spirit
and scope of the invention as set forth in the appended claims.
DETAILED DESCRIPTION
[0014] Disclosed herein are compositions and methods for the
treatment of DPZs. Herein, DPZs collectively refer to zones or
areas within a subterranean formation whose presence or
permeability detrimentally impacts one or more wellbore servicing
operations. For example the DPZ may comprise a lost circulation
zone such as voids, vugular zones, and natural or induced
fractures. Alternatively, a DPZ may comprise water-producing areas
in an intended hydrocarbon-producing wellbore. In an embodiment,
compositions suitable for use in the treatment of DPZs comprise a
non-aqueous carrier fluid, optionally a dehydrating agent, an
oil-wetting surfactant, a water-imbibition enhancing surfactant, a
cementitious material, and optionally a filler. Herein, these
compositions are termed treatment compositions for detrimentally
permeable zones and designated TREATs. In an embodiment, a method
of servicing a wellbore comprises preparing a TREAT, placing the
TREAT downhole, and contacting the DPZ with the TREAT.
[0015] In an embodiment, the TREAT comprises a hydraulic cement
that sets and hardens by reaction with water. Examples of hydraulic
cements include but are not limited to Portland cements (e.g.,
classes A, B, C, G, and H Portland cements), pozzolana cements,
gypsum cements, phosphate cements, high alumina content cements,
silica cements, high alkalinity cements, shale cements, acid/base
cements, cement kiln dust cements, magnesia cements, fly ash
cement, zeolite cement systems, cement kiln dust cement systems,
slag cements, micro-fine cement, and combinations thereof.
[0016] In an embodiment, the cement may be present in the TREAT in
an amount of from about 15 weight percent (wt. %) to about 90 wt.
%, alternatively from about 30 wt. % to about 70 wt. % or
alternatively from about 50 wt. % to about 60 wt. % based on the
total weight of the composition.
[0017] In an embodiment, the TREAT comprises a filler. Herein,
fillers refer to any inorganic material that is introduced to the
composition in order to lower the consumption of the hydraulic
cement. In some embodiments, such fillers may improve one or more
properties of the composition in which it is included. In some
embodiments said improvements may be due to conversion of the
filler into cementitious material by reaction with one or more
hydration products of the cement in the presence of water in
reactions known as pozzolanic reactions. Examples of fillers
suitable for use in this disclosure include without limitation
pumice, ASTM Class F fly ash, sand, silica, metakaolin, slag, or
combinations thereof.
[0018] In an embodiment, the filler may be present in the TREAT in
an amount of from about 10 percent by weight of cement (bwoc) to
about 200% bwoc, alternatively from about 25% bwoc to about 150%
bwoc, or alternatively from about 50% bwoc to about 100% bwoc.
[0019] In an embodiment, the filler and/or hydraulic cement may be
sized so as provide materials having an average particle size of
equal to or less than about 50 microns, alternatively less than
about 25 microns or alternatively less than about 5 microns. The
average particle size refers to a median value of d50 obtained by
using standard particle size measurement equipment and represents
the particle sizes of half of the particles in the solid
composition. In an embodiment, the cement and filler may be ground
together to obtain a cementitious blend of desired particle sizes.
For example, cement clinker may be ground together with pumice,
perlite, slag, flyash, metakaolin or a combination of such
materials. A nonlimiting example of a material suitable for use in
this disclosure is FINECEM cement which is a fine particle, high
surface area cement blend commercially available from Halliburton
Energy Services, Inc.
[0020] In an embodiment, the TREAT comprises a non-aqueous carrier
fluid. The non-aqueous carrier fluid may be a single fluid or a
combination of fluids. In an embodiment, the non-aqueous carrier
fluid may be any non-aqueous fluid that is chemically compatible
with the other components of the TREAT and suitable for providing a
pumpable slurry. In an alternative embodiment, the non-aqueous
carrier fluid is any non-aqueous fluid that is chemically
compatible with the other components of the TREAT with a flash
point of equal to or greater than about 140.degree. F. and suitable
for providing a pumpable slurry. In an embodiment, the non-aqueous
carrier fluid is an oleaginous fluid. Examples of oleaginous fluids
suitable for use in a TREAT include, but are not limited to,
petroleum oils, natural oils, synthetically-derived oils,
oxygenated fluids, or combinations thereof. More particularly,
examples of oleaginous fluids suitable for use in the present
disclosure include, but are not limited to, diesel oil, kerosene
oil, mineral oil, synthetic oil such as polyolefins (e.g.,
alpha-olefins and/or internal olefins), polydiorganosiloxanes,
esters, diesters of carbonic acid, alcohols, alcohol esters,
ethers, paraffins, or combinations thereof. Other examples of
suitable non-aqueous carrier fluids include but are not limited to
aliphatic hydrocarbons such as, internal olefins, linear alpha
olefins, poly alpha olefins, diesel, mineral oil, kerosene,
silicone fluids or combinations thereof. Alternatively, the
non-aqueous carrier fluid is an oxygenated solvent such as ethylene
glycol, ethylene glycol monoalkyl ether, ethylene glycol dialkyl
ether or combinations thereof wherein the alkyl groups are methyl,
ethyl, propyl, butyl and the like. In an embodiment, the density of
non-aqueous carrier fluids suitable for use in this disclosure may
be in the range of from about 0.7 g/cc to about 1.5 g/cc. The
non-aqueous carrier fluid may be present in an amount of equal to
or greater than about 10 wt. % by total weight of the TREAT,
alternatively equal to or greater than about 15 wt. %, or
alternatively equal to or greater than about 20 wt. %.
[0021] In an embodiment, the non-aqueous carrier fluid excludes
water. Alternatively, the non-aqueous carrier fluid comprises less
than about 5%, 4%, 3%, 2% or 1% water by total weight of the
non-aqueous carrier fluid.
[0022] In an embodiment, the TREAT comprises a dehydrating agent.
The dehydrating agent may function to reduce the water content of
the non-aqueous carrier fluid upon contacting same. In an
embodiment, the dehydrating agent is any material chemically
compatible with the other components of the TREAT and able to
reduce the water content of the non-aqueous carrier fluid.
Alternatively, the dehydrating agent is any non-cementitious
material with an affinity for water that is capable of reducing the
water content of the non-aqueous carrier fluid to less than about
5%, 4%, 3%, 2% or 1% by weight when used in amounts of equal to or
less than about 25% by weight of the non-aqueous carrier fluid.
[0023] In an embodiment, the dehydrating agent may comprise high
surface area or highly porous materials containing hydrophilic
surfaces. Examples of such dehydrating agents include without
limitation high surface area silica, alumina, zeolitic materials,
molecular sieve materials or combinations thereof. In an
embodiment, the dehydrating agent comprises a zeolitic material.
Zeolites are a group of natural or synthetic hydrated
aluminosilicate minerals that contain alkali and alkaline metals.
They are characterized by a framework structure that encloses
interconnected cavities occupied by ion-exchangeable large metal
cations and water molecules permitting reversible dehydration. An
example of a suitable zeolitic material includes without limitation
SILIPORITE molecular sieve which is a synthetic zeolite
commercially available from Ceca Arkema Group.
[0024] In an embodiment, the dehydrating agent is an inorganic
material for example an inorganic salt or combination of inorganic
salts. Such salts may be hydroscopic salts, for example anhydrous
calcium chloride, or salts from which waters of crystallization has
been removed, for example anhydrous sodium sulfate, anhydrous
calcium sulfate, or calcium oxide. In some embodiments the
inorganic material may be a clay, for example bentonite, or an
anhydrous cementiceous material such as Portland cement.
[0025] In an embodiment, the TREAT comprises at least two
functional surfactants. In an embodiment, a first surfactant
functions as an oil-wetting surfactant (OWS) and facilitates
suspension of the cementitious material in the non-aqueous carrier
fluid. In such an embodiment, the OWS is soluble in the non-aqueous
carrier fluid. The OWS may be any material chemically compatible
with the other components of the TREAT and having a
hydrophilic-lipophilic balance (HLB) ratio of less than or equal to
7. The HLB is a system used to categorize surfactants according to
the balance between the hydrophilic and lipophilic portions of
their molecules. The HLB value indicates the polarity of the
molecules in an arbitrary range of 1 to 40 with the most commonly
used surfactants having a value of between 1 to 20. The HLB value
increases with increasing hydrophilicity of the surfactant.
Consequently, an OWS or one designed to promote compatibilization
of the particulate cementitious material surface with the
non-aqueous carrier fluid by rendering the surface of the
cementitious material hydrophobic by adsorption via the hydrophilic
head portion of the surfactant would have a low HLB value. The OWS
may be a nonionic, anionic, or cationic. In an embodiment, the
TREAT comprises at least one OWS with an HLB of less than or equal
to 7. Alternatively, the TREAT may comprise more than one OWS which
when combined have a calculated average HLB ratio of less than or
equal to 7. Examples of a suitable OWS include without limitation
nonylphenolethoxylates with less than 5 moles of ethylene oxide,
fatty acids and their salts, alkali and alkaline earth metal salts
of dodecybenzene sulfonic acid, sorbitan trioleate, sorbitan
monopalmitate, sorbitan monostearate, propylene glycol monolaurate,
propylene glycol monostearate, sorbitan distearate and any
combination of such surfactants. Other examples of commercially
available OWS include without limitation MOC A surfactant, OMC 2
thinner, OMC 3 thinner and OMC 42 thinner which are all
commercially available from Halliburton Energy Services, Inc. In an
embodiment, the OWS is utilized as a solution of the surfactant in
a non-aqueous solvent that contains less than about 10 wt. % water.
Non-aqueous solvents suitable for use in this disclosure are
materials similar to those as described for the non-aqueous carrier
fluid. The amount of the active surfactant in the solution may be
in range of from about 10 wt. % to about 80 wt. % by weight of the
surfactant solution.
[0026] In an embodiment, a TREAT comprises an OWS present in
amounts of from about 0.1 wt. % to about 10 wt. %, alternatively
from about 0.3 wt. % to about 6 wt. %, alternatively from about 0.5
wt. % to about 4 wt. % by weight of the non-aqueous carrier
fluid.
[0027] In an embodiment, a second surfactant functions as a
water-imbibition enhancing surfactant (WIES) and may aid in the
hydration of the cementitious material that has been treated with
an OWS surfactant and may contain hydrophobicized surfaces. More
particularly, the WIES may aid in enhancing the water uptake or
imbibition by cement in a non-aqueous carrier fluid that has been
treated with an oil wetting surfactant and then exposed to water.
Without wishing to be limited by theory, the presence of the WIES
may enhance imbibition of water by cement the surface of which has
been rendered hydrophobic both by treatment with a OWS and being
slurried in a non-aqueous carrier fluid. The WIES may facilitate
hydration reactions to take place ultimately to an extent that is
similar to a cement that has been directly exposed to water only.
Further, the WIES may aid in hydration of cement in such slurries
even when the agitation or mixing with water is less than ideal for
efficient mixing and hydration, for example under quiescent
conditions. Imbibition of water by non-aqueous cement slurries in
the presence of WIES may be accompanied by displacement of the
non-aqueous fluid by water penetration or by emulsification of the
non-aqueous fluid in water to form an oil-in-water emulsion or
both. The function of the WIES is to convert the TREAT to a
water-external phase with the non-aqueous fluid as the dispersed
phase as well as to render the cement particle surfaces hydratable
when contacted with water in the formation.
[0028] The WIES may be any surfactant material chemically
compatible with the other components of the TREAT and having a HLB
of greater than or equal to 10. Such a WIES may be nonionic,
anionic or cationic. In an embodiment, the TREAT comprises at least
one WIES with an HLB of greater than or equal to 10. Alternatively,
the TREAT may comprise more than one WIES which when combined have
a calculated average HLB ratio of greater than or equal to 10. An
example of a suitable WIES includes without limitation DUAL SPACER
B surfactant, which is an ethoxylated nonylphenol surfactant
commercially available from Halliburton Energy Services, Inc. Other
examples of suitable WIES are cationic quaternary ammonium salts,
for example ARQUAD DMCB and ARQUAD DMHTB which are benzyl coco
dimethyl ammonium chloride and dimethyl (hydrogenated tallow)
benzyl ammonium chloride commercially available from AkzoNobel
Corporation. Other suitable quaternary ammonium compounds include
propoxylated diethanolamine methyl ammonium chloride, commercially
available as EMCOL CC brand products from Akzo Nobel Corporation.
Examples of other suitable WIES include without limitation
polyoxyethylene sorbitan based surfactants, commonly referred to as
TWEEN surfactants, for example, TWEEN.RTM. 20, TWEEN.RTM. 40,
TWEEN.RTM. 60, TWEEN.RTM. 80, TWEEN.RTM. 81 or any combination such
surfactants. Such materials are available from many surfactant
vendors or from chemical companies such as Aldrich Chemical
Company.
[0029] In an embodiment, the WIES may be predissolved in a
non-aqueous solvent prior to its addition to TREAT. Suitable
solvents to dissolve the WIES include alcohols, alcohol ethers,
such as ethanol, isopropanol, methanol, 2-ethylhexanol ethylene
glycol monomethyl ether or combination of such solvents. The
concentrations active surfactant in such a solution may range from
about 25 wt. % to about 85 wt. %. In an embodiment, the TREAT
contains the WIES in amounts of from about 0.1 wt. % to about 10
wt. %, alternatively from about 0.3 wt. % to about 6 wt. %,
alternatively from about 0.5 wt. % to about 4 wt. % by weight of
total composition. In an embodiment, the OWS and WIES are used
without predissolution in solvents of the type disclosed herein. In
an embodiment, both the OWS and the WIES may be dissolved in a
solvent to obtain a single solution for use with TREAT.
[0030] In an embodiment, a TREAT may be prepared by the addition of
the components in any order desired by the user. Alternatively, the
TREAT may be prepared by the addition of the components in the
order to be described. In an embodiment, a TREAT is prepared by the
addition of a dehydrating agent to the non-aqueous carrier fluid.
In an embodiment, the dehydrating agent may be contacted with the
non-aqueous carrier fluid prior to the addition of any other
components of the TREAT and allowed to reduce the water content in
the non-aqueous carrier fluid. The dehydrating agent and
non-aqueous carrier fluid may be contacted for a time period
sufficient to substantially dehydrate the non-aqueous carrier
fluid. Herein, dehydration of the non-aqueous carrier fluid refers
to reducing the amount of aqueous material in the non-aqueous
carrier fluid to less than about 5%, 4%, 3%, 2% or alternatively
less than 1% by weight of the non-aqueous carrier fluid. As will be
understood by one of ordinary skill in the art, the time necessary
to substantially dehydrate the non-aqueous carrier fluid will
depend on numerous factors such as the amount of non-aqueous
carrier fluid, the water content thereof, and the amount and nature
of the dehydrating agent. As such, the time necessary for
dehydration of the non-aqueous carrier fluid may be designed by one
skilled in the art to meet the needs of the user. After the
dehydration period, the non-aqueous carrier fluid may be separated
from the dehydrating agent prior to mixing with the cement
composition. The non-aqueous carrier fluid after contact with the
dehydrating agent is termed the dehydrated non-aqueous carrier
fluid.
[0031] In some embodiments, the non-aqueous carrier fluid is
anhydrous. In such embodiments, the TREAT may exclude a dehydrating
agent and a method of forming a TREAT may exclude contacting the
non-aqueous carrier fluid with the dehydrating agent as described
previously herein.
[0032] In an embodiment, the dehydrated non-aqueous carrier fluid
(or anhydrous non-aqueous carrier fluid) is then contacted with the
cementitious material and surfactants in any user and/or process
desired order. In an embodiment, the OWS and WIES are combined and
used simultaneously in the formation of the TREAT wherein the OWS
and WIES are employed as a single solution in which the ratio OWS
to WIES may vary from 1:9 to 9:1. Alternatively, the TREAT is
prepared by sequential addition of the OWS and WIES. For example,
the TREAT may be prepared by addition of the OWS to the non-aqueous
carrier fluid, followed by addition of the cementitious material
and subsequently addition of the WIES. In another embodiment, the
WIES surfactant is added first to the non-aqueous carrier fluid,
followed by addition of the cementitious material and subsequent
addition of the OWS. In an embodiment, the OWS is added to
non-aqueous carrier fluid followed by WIES with subsequent addition
of the cementitious material. In an embodiment, cementitious
material is added to the non-aqueous carrier fluid followed by the
OWS and subsequent addition of the WIES. In all cases, the TREAT
composition contains at least two functional surfactants and a
cementitious material prior to entering the subterranean formation,
or contacting water in the wellbore.
[0033] In some embodiments, additives may be included in the TREAT
for improving or changing the properties thereof. Examples of such
additives include but are not limited to salts, accelerants, set
retarders, defoamers, fluid loss agents, weighting materials,
dispersants, vitrified shale, formation conditioning agents,
viscosifying agents, or combinations thereof. Other mechanical
property modifying additives, for example, carbon fibers, glass
fibers, metal fibers, minerals fibers, and the like can be added to
further modify the mechanical properties. These additives may be
included singularly or in combination. Methods for introducing
these additives and their effective amounts are known to one of
ordinary skill in the art. In an embodiment, the TREAT optionally
comprises a suspension aid. The suspension aid may function to
reduce or prevent the settling of cement particles and allow such
particles to remain suspended in the TREAT. In an embodiment, the
suspension aid comprises any material chemically compatible with
the other components of the TREAT and able to reduce or prevent the
settling of the cement particles. Alternatively, the suspension aid
comprises a partially or completely soluble polymer, organically
surface modified inorganic solids, for example organophilic clay,
organophilic glass or mineral fibers and the like.
[0034] The TREATs prepared as disclosed herein may be used as
wellbore servicing fluids. As used herein, a "servicing fluid"
refers to a fluid used to drill, complete, work over, fracture,
repair, or in any way prepare a wellbore for the recovery of
materials residing in a subterranean formation penetrated by the
wellbore. Examples of wellbore servicing fluids include, but are
not limited to, cement slurries, drilling fluids or muds, spacer
fluids, fracturing fluids or completion fluids. The servicing fluid
is for use in a wellbore that penetrates a subterranean formation.
It is to be understood that "subterranean formation" encompasses
both areas below exposed earth and areas below earth covered by
water such as ocean or fresh water.
[0035] In an embodiment, the TREAT functions to obstruct DPZs of
the type described herein. For example, the TREAT may be introduced
to the wellbore to prevent the loss of aqueous or non-aqueous
drilling fluids into loss-circulation zones such as voids, vugular
zones, and natural or induced fractures while drilling. In an
embodiment, the TREAT is placed into a wellbore as a single stream
where it may enter loss circulation zones. In one embodiment, a
TREAT entering the loss-circulation zone remains as a suspension
comprising unhydrated cementitious material until the suspension
encounters water present in the wellbore and/or formation and the
cementitious material is hydrated. The resultant hydrated TREAT may
have features ranging from that associated with a gelatinous mass
to those associated with a paste. In an embodiment, the hydrated
TREAT forms a solid mass sufficient to obstruct the detrimentally
permeable zone in which it is located and reduce loss circulation.
In an embodiment, the hydrated TREAT forms a solid mass in less
than about 5 minutes, alternatively in less than about 3 minutes,
and alternatively in less than about 1 minute when mixed with water
and agitation under laboratory conditions.
[0036] In another embodiment, the TREAT is placed into a wellbore
in a stream alone or in combination with another stream of
materials. For example, a second stream of aqueous fluid (e.g.,
water) may be placed in the wellbore before,
concurrently/simultaneously, or after/sequentially with the first
stream comprising the TREAT. For example, a first stream comprising
the TREAT may be pumped through a flowbore of a tubular disposed in
the wellbore (e.g., a work string, coiled tubing string, jointed
pipe string, etc.) and a second stream comprising an aqueous fluid
(e.g., water) may be pumped down an annular space formed between
the tubular and the wellbore wall (e.g., casing wall), whereby the
TREAT and the aqueous fluid mix downhole to form the hydrated TREAT
that obstructs the DPZs. The TREAT present in or proximate to the
loss circulation zones may contact the water introduced to the
formation via the second stream and form a mass sufficient to
obstruct the detrimentally permeable zone in which the TREAT is
located and reduce loss circulation. It is to be understood the
TREAT as placed into the wellbore comprises unhydrated cementitious
material and is a suspension of the unhydrated cementitious
material in non-aqueous carrier fluid, and the cement is
subsequently hydrated via contact with an aqueous fluid downhole
(e.g., a naturally occurring or in situ aqueous fluid such water
produced from the formation and/or water placed downhole prior,
concurrent/simultaneously, and/or after placement of the TREAT). It
is also to be understood that when the TREAT penetrates oil
producing zones, the cement in the TREAT remains unhydrated and
TREAT will flow out of the oil producing zone without forming a
solid mass or without lowering the permeability to oil either as
the original or diluted slurry.
[0037] In an embodiment, the TREAT when placed into a wellbore
enters one or more DPZs containing water produced by the
subterranean formation. In such embodiments, the TREAT may form a
viscous mass sufficient to obstruct the water-producing zone in
which it is located. Thus, it is contemplated that TREATs of the
type disclosed herein when placed in a DPZ are contacted with water
that is endogenous to the DPZ (e.g., connate water, formation
water, interstitial water, etc.) and/or may be contacted with water
that is exogenous to the DPZ such as water placed in the
subterranean formation during a wellbore servicing operation.
[0038] In an embodiment, the TREAT may be preceded by a pre-stream
(referred to as preflush) of a non-aqueous fluid that may be the
same, similar or different from the non-aqueous carrier fluid used
to prepare the TREAT. The preflush may function to displace any
water or an aqueous fluid present in the wellbore so as to prevent
premature contact of an aqueous fluid with TREAT.
[0039] In an embodiment, a TREAT of the type disclosed herein when
contacted with water develops a compressive strength of from about
50 psi to about 2000 psi, alternatively from about 100 psi to about
1000 psi, or alternatively from about 250 psi to about 750 psi.
Herein, the compressive strength is defined as the capacity of a
material to withstand axially directed pushing forces. The maximum
resistance of a material to an axial force is determined in
accordance with API Recommended Practices 10B-2, First Edition,
July 2005.
[0040] It is contemplated in some embodiments the TREAT when
contacted with water rapidly forms a solid mass sufficient to
obstruct the flow of fluids into or from the DPZ in which the TREAT
is located. Further, the cementitious material of the TREAT may
hydrate so rapidly as to form a mass that prevents at least a
portion of the TREAT from contacting water. For example, the water
may contact the TREAT and a mass form at the point of contact of
the water and TREAT such that the mass serves as an interface
between the water and an unreacted portion of the TREAT. The depth
of the interface may vary and will depend on a variety of factors
such as the shape and dimensions of the DPZ in which the TREAT and
water are contacted. In an embodiment, equal to or greater than
about 25% of the TREAT forms a solid mass after contact with water
in a DPZ, alternatively equal to or greater than about 30%, 35%,
40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90% or 95% of the
TREAT forms a solid mass when contacted with water in a DPZ without
agitation under laboratory conditions.
[0041] In an embodiment, the TREAT may be employed in well
completion operations such as secondary cementing operations. In
secondary cementing, often referred to as squeeze cementing, the
TREAT may be strategically positioned in the wellbore to repair an
area of lost structural integrity in a set cement sheath. For
example, the TREAT when utilized in secondary cementing may plug a
void or crack in the conduit, plug a void or crack in the hardened
sealant (e.g., cement sheath) residing in the annulus, plug
previously placed perforations (e.g., zones or areas previously
subjected to a perforating operation), plug a relatively small
opening known as a microannulus between the hardened sealant and
the conduit, and so forth.
[0042] It is to be understood TREATs of the type disclosed herein
are not intended for primary cementing and do not form sufficient
compressive strength to support structures or articles such as for
example a casing. It is to be understood TREATs of the type
disclosed have cementitious material suspended in a non-aqueous
carrier fluid until such time as the composition contacts water
within the wellbore. Consequently, TREATS within the wellbore that
do not contact water may remain as a non-aqueous fluid suspension
of cementitious material for an indefinite time period. TREATs of
this disclosure may obstruct DPZs in a sufficiently short time
period making it unnecessary for the operator to pull out of the
hole to address the problem and thus reducing nonproductive rig
time. In some embodiments, a method of servicing a wellbore
comprises introducing a TREAT of the type disclosed herein to the
wellbore and shutting in the wellbore for some period of time.
EXAMPLES
[0043] The invention having been generally described, the following
examples are given as particular embodiments of the invention and
to demonstrate the practice and advantages thereof. It is
understood that the examples are given by way of illustration and
are not intended to limit the specification of the claims in any
manner.
Example 1
[0044] The compressive strength of a TREAT of the type disclosed
herein was compared to the compressive strength of cement slurries
containing microfine particles. Three cement slurries were
prepared: Sample A (Control) contained MICROMATRIX cement and MOC A
surfactant in diesel; Sample B contained the same components as
Sample A with the exception that MOC A surfactant was replaced with
OMC 2 which is an non-aqueous drilling fluid conditioner and Sample
C contained OMC 2, LOSURF 20N which is a cationic non-emulsifying
surfactant and MICROMATRIX cement in diesel. MICROMATRIX cement,
MOC A surfactant, OMC 2 fluid conditioner and LOSURF 20N which is a
cationic non-emulsifying surfactant based on quaternized ammonium
salt are all commercially available from Halliburton Energy
Services, Inc. The general procedure for the preparation of the
slurries was as follows: to 25 ml diesel containing 0.5 ml ((2% by
volume of diesel) of MOC-A surfactant as OWS in a blender, 50 grams
MICROMATRIX cement was added with vigorous stirring for 30 seconds.
The slurries displayed excellent pourability and consistency at
surfactant levels of 0.3-2% by volume of diesel when other OWS were
tested. In order to test the ability of the slurry to form viscous
mass upon mixing with water, five milliliters of water was added
and stirred with a spatula vigorously. The time for the whole
slurry to form a viscous, stiff non-flowing mass was measured. For
the control slurry it was about 1 minute. For measurement of
compressive strengths, the slurry was mixed with water (20 grams,
40% by weight of cement) and hand-mixed with a spatula until a
uniform paste was formed. The paste was packed into
2.times.2.times.2 inch brass molds and cured in a water bath at
180.degree. F. for 72 hours. Compressive strengths of the paste
measured for three samples are presented in Table 1. Sample A was
prepared as described above with MOC-A, an OWS based on
dodecylbenzene sulfonic acid salt dissolved in non-aqueous
solvents. Sample B was prepared according to the general procedure
using OMC 2, an OWS based on oligomeric fatty acid solution in
non-aqueous solvents. Sample C is a mixture of OMC 2 as OWS and
LOSURF 20N as WIES and was prepared by adding WIES to a control
slurry prepared as described above. LOSURF 20N is a mixture of
benzyl group containing quaternized ammonium salts dissolved in
non-aqueous solvents.
TABLE-US-00001 TABLE 1 Sample Set Cement Density (ppg) Crush
Compressive Strength (psi) A 12.8 270 B 12.5 280 C 12.7 640
[0045] The results demonstrate that the inherent compressive
strengths of the inventive compositions (i.e., Sample C) are more
than double that of conventional cementitious compositions.
Example 2
[0046] Various TREATs of the type disclosed herein were prepared
and their ability to imbibe water under static conditions was
evaluated. Specifically, samples containing OWS/WIES surfactant
combination as indicated in Table 2 were prepared according to the
procedure and amounts described in the general procedure in Example
1. The amount of WIES solution was 0.5 ml. The amount of solid
WIES, for example LOSURF 2000S, was 0.3 grams. LOWSURF 396 is a
non-ionic surfactant, LOWSURF 2000S is a solid anionic surfactant
mixed with a solid hydrotrope, and LOSURF 19N is a quaternary
ammonium salt based on benzyl dimethyl coco ammonium chloride that
is dissolved in a non-aqueous solvent system comprising oxygenated
solvent. All tested surfactants are available from Halliburton
Energy Services, Inc. The slurries were placed in an Erlenmeyer
flask and water was poured gently down the walls of the flask to
simulate contact of the samples with water within a DPZ and to
ensure the slurry was not significantly disturbed or to minimize
agitational mixing. The flask once filled with water was sealed off
with a rubber-stopper fitted with a water-filled pipette such that
the pipette tip was under water level in the flask. The changes to
the level of water in the pipette were measured over 3-5 days at
room temperature. At the end of the experiment the water in the
flask was poured out. The cement crust was chipped carefully with a
chisel and the thickness of the set crust and the thickness of the
unset cement slurry were measured. The crust and unset slurry
thickness provided a measure of the water imbibition or penetration
into the cement. The results are shown in Table 2. The results
demonstrate that the best results are observed when cationic WIES
surfactants are used in combination with oil-wetting surfactants
(OWS). The results also demonstrate that non-aqueous slurries for
introduction into DPZs such as in squeeze cementing applications
(e.g., TREATs) can be designed with performance superior to
conventional materials for these applications.
TABLE-US-00002 TABLE 2 Surfactant OMC-2 + OMC-2 + OMC-2 + OMC-2 +
LOSURF LOSURF LOSURF LOSURF MOC-A OMC-2 396 20N 2000S 19N Set
cement 0.2 1 2 13-15 0.2 3-4 thickness (mm) Unset cement 14-15
15-17 15-17 1-3 16-18 12-14 thickness (mm)
Example 3
[0047] A mixture was prepared by adding to 25 ml diesel, 0.5 ml
MOC-A surfactant and 0.5 gram solid dimethyl (hydrogenated tallow)
benzyl ammonium chloride available as ARQUAD DMHTB from AKZO Nobel
Corporation. 50 grams MICROMATRIX cement was then added to the
mixture with stirring. The resulting slurry was transferred to a
beaker and beaker was filled with water in a gentle stream to
ensure minimum mixing. The mixture was stored at room temperature
for 3 days. The water was poured out and the set cement thickness
was measured. The set cement crust was about 85% of the cement
slurry volume with a small amount of unset cement slurry underneath
the set cement crust. The results demonstrate that quaternized
ammonium compounds containing a long chain alkyl group and a benzyl
group can function as effective WIES compounds.
Example 4
[0048] The general procedure described in Example 1 was repeated by
replacing MICROMATRIX cement with a microfine Portland cement and
pumice 1:1 blend that has been ground together to obtain an average
particle size (d50) of 5 microns. Upon addition of water (5-40% by
weight of Portland cement) and stirring with a spatula, the mixture
formed a non-flowing viscous paste within two minutes at room
temperature. This result demonstrates that cementitious blends that
have ground together to obtain a solid blend of desired particle
sizes will form solidified mass capable of blocking fluid flow in a
DPZ and can be utilized in the inventive methods and compositions
disclosed herein.
[0049] While preferred embodiments of the invention have been shown
and described, modifications thereof can be made by one skilled in
the art without departing from the spirit and teachings of the
invention. The embodiments described herein are exemplary only, and
are not intended to be limiting. Many variations and modifications
of the invention disclosed herein are possible and are within the
scope of the invention. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term
"optionally" with respect to any element of a claim is intended to
mean that the subject element is required, or alternatively, is not
required. Both alternatives are intended to be within the scope of
the claim. Use of broader terms such as comprises, includes,
having, etc. should be understood to provide support for narrower
terms such as consisting of, consisting essentially of, comprised
substantially of, etc.
[0050] Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
preferred embodiments of the present invention. The discussion of a
reference herein is not an admission that it is prior art to the
present invention, especially any reference that may have a
publication date after the priority date of this application. The
disclosures of all patents, patent applications, and publications
cited herein are hereby incorporated by reference, to the extent
that they provide exemplary, procedural or other details
supplementary to those set forth herein.
* * * * *