U.S. patent application number 13/664259 was filed with the patent office on 2014-05-01 for wellbore servicing compositions and methods of making and using same.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Jay Paul DEVILLE, Pubudu Hasanka GAMAGE.
Application Number | 20140121135 13/664259 |
Document ID | / |
Family ID | 49304402 |
Filed Date | 2014-05-01 |
United States Patent
Application |
20140121135 |
Kind Code |
A1 |
GAMAGE; Pubudu Hasanka ; et
al. |
May 1, 2014 |
Wellbore Servicing Compositions and Methods of Making and Using
Same
Abstract
A method of servicing a wellbore in a subterranean formation
comprising preparing an invert emulsion comprising an aqueous
fluid, an oleaginous fluid, and an emulsifier composition (EC),
wherein the emulsifier composition comprises an emulsifier, a
diluent, and a thinner, wherein the thinner comprises an alcohol, a
fatty acid amide, or combinations thereof; and placing the invert
emulsion in the wellbore. A method of servicing a wellbore in a
subterranean formation comprising flowing a wellbore serving fluid
comprising an emulsifier composition (EC) through a portion of a
subterranean formation, wherein the EC comprises an emulsifier, a
diluent and a thinner and wherein the thinner comprises
2-methyl-1-propanol, 2-methyl-2-butanol, a fatty acid amide, or
combinations thereof; contacting the EC with oil in situ within the
formation to form an emulsion; and reducing the water-oil
interfacial tension and altering the wettability to provide
enhanced oil recovery from the formation.
Inventors: |
GAMAGE; Pubudu Hasanka;
(Katy, TX) ; DEVILLE; Jay Paul; (Spring,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
49304402 |
Appl. No.: |
13/664259 |
Filed: |
October 30, 2012 |
Current U.S.
Class: |
507/131 ;
507/241 |
Current CPC
Class: |
C09K 8/36 20130101 |
Class at
Publication: |
507/131 ;
507/241 |
International
Class: |
C09K 8/58 20060101
C09K008/58 |
Claims
1. A method of servicing a wellbore in a subterranean formation
comprising: preparing an invert emulsion comprising an aqueous
fluid, an oleaginous fluid, and an emulsifier composition (EC),
wherein the emulsifier composition comprises (a) an emulsifier in
an amount of from about 25 wt. % to about 100 wt. %, based on the
total weight of the EC, (b) a diluent wherein the diluent is
present in the EC in an amount of from about 15 wt. % to about 90
wt. %, based on the total weight of the EC, and (c) a thinner,
wherein the thinner comprises an alcohol, a fatty acid amide, or
combinations thereof, and wherein the fatty acid amide comprises
the product of a reaction between (i) an amine comprising diethanol
amine, dimethylamine, diethylamine, methylamine, ethylamine,
piperidine, aniline, or combinations thereof and (ii) a fatty acid
or a fatty acid ester or combinations thereof; and placing the
invert emulsion in the wellbore.
2. The method of claim 1 wherein the emulsifier comprises a
carboxylic acid-terminated polyamide, a mixture produced by a
Diels-Alder reaction of dienophiles with a mixture of fatty acids
and/or resin acids, or combinations thereof.
3. The method of claim 2 wherein the carboxylic acid-terminated
polyamide comprises one or more products of a condensation reaction
between fatty acids and polyamines.
4. The method of claim 2 wherein the dienophile comprises
carboxylic acids, polycarboxylic acids, anhydrides, or combinations
thereof.
5. The method of claim 2 wherein the fatty acids and/or resin acids
are derived from the distillation of crude tall oil.
6. (canceled)
7. The method of claim 1 wherein the diluent comprises petroleum
oils, natural oils, synthetically-derived oils, diesel oil,
kerosene oil, mineral oil, olefins and polyolefins,
polydiorganosiloxanes, esters, biodiesel, diesters of carbonic
acid, paraffins, ethers, or combinations thereof.
8. (canceled)
9. The method of claim 1 wherein the alcohol comprises
2-methyl-1-propanol, 2-methyl-2-butanol or combinations
thereof.
10-11. (canceled)
12. The method of claim 1 wherein the fatty acid comprises oleic
acid, linoleic acid, abietic acid, abietic acid derivatives,
pimaric acid, plamitic, myristic, linolenic, stearic, or
combinations thereof.
13. The method of claim 1 wherein the fatty acid ester comprises a
methyl fatty acid ester, an ethyl fatty acid ester, a naturally
occurring ester, a triglyceride, soya oil, sunflower oil, corn oil,
safflower oil, or combinations thereof.
14. The method of claim 1 wherein the fatty acid amide comprises a
fatty dimethyl amide.
15. The method of claim 1 wherein the thinner is present in the EC
in an amount of from about 0.1 wt. % to about 40 wt. %, based on
the total weight of the EC.
16. The method of claim 1 wherein the wellbore servicing fluid
comprises an oil-based drilling mud.
17. The method of claim 1 wherein the EC has a pour point of from
about -20.degree. F. to about 100.degree. F.
18. The method of claim 1 wherein the EC has an electrical
stability of from about 0 to about 2000 V.
19. The method of claim 1 wherein the EC has a viscosity of from
about 100 cp to about 100000 cp.
20. A method of servicing a wellbore in a subterranean formation
comprising: flowing a wellbore serving fluid comprising an
emulsifier composition (EC) through a portion of a subterranean
formation, wherein the EC comprises an emulsifier, a diluent
wherein the diluent is present in the EC in an amount of from about
15 wt. % to about 90 wt. %, based on the total weight of the EC and
a thinner, wherein the thinner comprises 2-methyl-1-propanol,
2-methyl-2-butanol, a fatty acid amide, or combinations thereof;
and wherein the fatty acid amide comprises the product of a
reaction between (i) an amine comprising diethanol amine,
dimethylamine, diethylamine, methylamine, ethylamine, piperidine,
aniline, or combinations thereof and (ii) a fatty acid or a fatty
acid ester or combinations thereof; contacting the EC with oil in
situ within the formation to form an emulsion; and reducing the
water-oil interfacial tension and altering the wettability to
provide enhanced oil recovery from the formation.
21. The method of claim 20 wherein the emulsifier comprises a
partial amide.
22. An invert emulsion wellbore servicing fluid comprising an
aqueous fluid, an oleaginous fluid, and an emulsifier composition
(EC), wherein the emulsifier composition comprises an emulsifier, a
diluent, and a thinner, wherein the thinner comprises an alcohol, a
fatty acid amide, or combinations thereof.
23. The invert emulsion of claim 22 formulated as a drilling
fluid.
24. The method of claim 20 wherein the EC has a pour point of from
about -20.degree. F. to about 100.degree. F.
25. The method of claim 20 wherein the EC has an electrical
stability of from about 0 to about 2000 V.
26. The method of claim 20 wherein the EC has a viscosity of from
about 100 cp to about 100000 cp.
27. The method of claim 20 wherein the servicing of the wellbore is
an enhanced oil recovery operation.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 1. Field
[0004] This disclosure relates to methods of servicing a wellbore.
More specifically, it relates to wellbores servicing compositions
and methods of making and using same.
[0005] 2. Background
[0006] Natural resources such as gas, oil, and water residing in a
subterranean formation or zone are usually recovered by drilling a
wellbore down to the subterranean formation while circulating a
drilling fluid in the wellbore. After terminating the circulation
of the drilling fluid, a string of pipe, e.g., casing, is run in
the wellbore. The drilling fluid is then usually circulated
downward through the interior of the pipe and upward through the
annulus, which is located between the exterior of the pipe and the
walls of the wellbore. Next, primary cementing is typically
performed whereby a cement slurry is placed in the annulus and
permitted to set into a hard mass (i.e., sheath) to thereby attach
the string of pipe to the walls of the wellbore and seal the
annulus. Subsequent secondary cementing operations may also be
performed.
[0007] Emulsifier compositions (EC) are routinely employed in
wellbore servicing fluids (WSFs) to lower the interfacial tension
between oil and water which allows stable emulsions with small
drops to be formed. ECs typically comprise an emulsifier and one or
more additives which function to modify one or more properties of
the compositions. The components of the ECs are subject to
evaluation for compliance with various health, safety, and
environmental (HSE) guidelines. Thus an ongoing need exists for
improved ECs that meet current HSE guidelines.
SUMMARY
[0008] Disclosed herein is a method of servicing a wellbore in a
subterranean formation comprising preparing an invert emulsion
comprising an aqueous fluid, an oleaginous fluid, and an emulsifier
composition (EC), wherein the emulsifier composition comprises an
emulsifier, a diluent, and a thinner, wherein the thinner comprises
an alcohol, a fatty acid amide, or combinations thereof; and
placing the invert emulsion in the wellbore.
[0009] Also disclosed herein is a method of servicing a wellbore in
a subterranean formation comprising flowing a wellbore serving
fluid comprising an emulsifier composition (EC) through a portion
of a subterranean formation, wherein the EC comprises an
emulsifier, a diluent and a thinner and wherein the thinner
comprises 2-methyl-1-propanol, 2-methyl-2-butanol, a fatty acid
amide, or combinations thereof; contacting the EC with oil in situ
within the formation to form an emulsion; and reducing the
water-oil interfacial tension and altering the wettability to
provide enhanced oil recovery from the formation.
[0010] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description, wherein like reference numerals
represent like parts.
[0012] FIGS. 1 and 2 are plots of the electrical stability over
time for the samples from Example 2.
DETAILED DESCRIPTION
[0013] It should be understood at the outset that although an
illustrative implementation of one or more embodiments are provided
below, the disclosed systems and/or methods may be implemented
using any number of techniques, whether currently known or in
existence. The disclosure should in no way be limited to the
illustrative implementations, drawings, and techniques below,
including the exemplary designs and implementations illustrated and
described herein, but may be modified within the scope of the
appended claims along with their full scope of equivalents.
[0014] Disclosed herein are emulsifier compositions (ECs)
comprising an emulsifier, a diluent, and a thinner, and wellbore
servicing fluids (WSFs) comprising such ECs. In an embodiment, the
EC may be used for stabilizing emulsified fluids. In some
embodiments, the composition may be used during enhanced oil
recovery (EOR) operations. In an embodiment, an EC of the type
disclosed herein displays a toxicity level that is sufficiently low
to meet one or more HSE guidelines. Each of the components of the
EC as well as methods of using same will be described in more
detail herein.
[0015] In an embodiment, the EC comprises an emulsifier. Without
wishing to be limited by theory, an emulsifier is a compound that
aids in the forming of an emulsion (i.e., a mixture of two or more
liquids that are normally immiscible) by decreasing the interfacial
tension between immiscible liquids (e.g., oil and water); or a
compound that stabilizes an already existing emulsion by decreasing
the separation tendency of the liquids; or both. In an embodiment,
the emulsifier comprises a carboxylic acid-terminated polyamide, a
mixture produced by a Diels-Alder reaction of dienophiles with a
mixture of fatty acids and/or resin acids, or combinations
thereof.
[0016] In an embodiment, the emulsifier comprises a carboxylic
acid-terminated polyamide (CATP). The CATP may be a product of a
condensation reaction between a fatty acid and a polyamine. In an
embodiment, a condensation reaction between a fatty acid and a
polyamine results in a mixture of reaction products that include
CATPs. In some embodiments, the mixture of reaction products may be
further processed using any suitable methodology to increase the
amount of CATPs present. For example, the mixture of reaction
products may be subjected to purification and/or separation
techniques. Alternatively, the mixture of reaction products may be
utilized in the EC without further processing. In an embodiment the
amount of CATPs present in the mixture of reaction products is
about 90 wt. % based on the total weight of the mixture,
alternatively from about 30 wt. % to about 100 wt. %, or
alternatively from about 85 wt. % to about 98 wt. %.
[0017] In some embodiments, the stoichiometry of the reactants in
the condensation reaction for formation of the CATPs is adjusted so
as to create a "partial amide" intermediate product. The partial
amide may be characterized by a mole ratio of the reactive acid
sites to amine sites of about 0.6:1, alternatively from about 0.5:1
to about 0.75:1, or alternatively from about 0.55:1 to about
0.65:1. The CATPs may be formed from the partial amide intermediate
using any suitable methodology. For example, the remaining amine
sites of the partial amide may be further reacted with an acid
anhydride or polycarboxylic acid to produce the CATP. These
reactions are depicted in Schemes I and II.
[0018] Referring to Scheme I, a tall oil fatty acid (TOFA) is
reacted with diethylenetriamine (DETA) in a molar ratio of DETA to
TOFA of 1:2, and the reaction product is further reacted with
maleic anhydride, to form a two thirds amide (2/3 amide) mixture.
Tall oil is a product made from acid treatment of alkaline liquors
obtained from the manufacturing of wood pulp.
##STR00001##
[0019] Referring to Scheme II, a tall oil fatty acid (TOFA) is
reacted with diethylenetriamine (DETA) in a molar ratio of DETA to
TOFA of 1:1.5, and the reaction products are further reacted with
maleic anhydride, to form a half-amide (1/2 amide) mixture.
##STR00002##
[0020] In an embodiment, the emulsifier comprises the reaction
product of a Diels-Alder reaction of dienophiles with an acid
mixture. The reaction product of the Diels-Alder reaction of
dienophiles with an acid mixture is hereinafter designated a DARM.
In an embodiment, the acid mixture comprises fatty acids and resin
acids derived from the distillation of crude tall oil. The fatty
acids found in tall oil are typically long chain monocarboxylic
acids such as oleic, linoleic, myristic, linolenic, stearic and
palmatic acid. Resin acids refer to a mixture of organic acids
derived from the oxidation and polymerization reactions of terpenes
and include compounds such as abietic acid, abietic acid
derivatives and pimaric acid. The ratio of fatty acids to resin
acids in the acid mixture may range from about 4:1 to about 1:1,
alternatively from about 3:1 to about 1:1, or alternatively from
about 2.5:1 to about 1.5:1. In an embodiment, the dienophile
comprises carboxylic acids, polycarboxylic acids, anhydrides, or
combinations thereof. The reaction of the dienophiles with the acid
mixture (i.e., fatty acids and resin acids) results in a mixture of
reaction products containing the DARM. In an embodiment, the amount
of the DARM present in the mixture of reaction products is from
about 50 wt. % to about 100 wt. %, alternatively from about 70 wt.
% to about 98 wt. %, or alternatively from about 85 wt. % to about
97 wt. % based on the total weight of the reaction products.
[0021] In an embodiment, the emulsifier is a blend of a CATP and a
DARM. The CATP and DARM may be combined using any suitable
methodology, e.g., blending, mixing to form an emulsifier. In such
embodiments, the ratio of the CATP to the DARM may range from about
1:5 to about 1:1, alternatively from about 1:4 to about 1:1, or
alternatively from about 1:3 to about 1:2. In an embodiment, the
quantity of the DARM will exceed the quantity of the CATP.
[0022] In an embodiment, the emulsifier (comprising a CATP, a DARM
or both) may be further reacted with one or more cations to form
soaps. Non-limiting examples of cations suitable for use in the
saponification reaction include calcium cations, sodium cations,
magnesium cations In an embodiment, the emulsifiers (i.e., CATP,
DARM, or both) are reacted with calcium cations which are provided
by any suitable source such as by contacting the emulsifier with
lime, quicklime, calcium chloride, or combinations thereof.
[0023] In an embodiment, the emulsifier comprises one or more
components of EZ MUL NT emulsifier; LE SUPERMUL emulsifier; or
combinations thereof. EZ MUL NT emulsifier is an invert emulsifier
and oil-wetting agent for mineral oil and paraffin based drilling
fluid systems, and LE SUPERMUL emulsifier is an invert emulsifier
and oil-wetting agent for synthetic based drilling fluid systems
both of which are commercially available from Halliburton Energy
Services, Inc. Additional examples of emulsifiers suitable for use
in the present disclosure are described in U.S. Pat. Nos.
6,620,770; 7,008,907; 7,271,132; 7,432,230; and 7,534,746; each of
which is incorporated by reference herein in its entirety.
[0024] In an embodiment an emulsifier of the type disclosed herein
(e.g., CATP, DARM, or both) may be present within the EC in an
amount of from about 25 wt. % to about 100 wt. %, alternatively
from about 40 wt. % to about 80 wt. %, alternatively from about 30
wt. % to about 65 wt. %, or alternatively from about 45 wt. % to
about 65 wt. % based on the total weight of the EC.
[0025] In an embodiment, the EC comprises a diluent. A diluent may
be included in an EC of the type described herein with the purpose
of diluting and/or modifying one or more physical properties of the
composition (e.g., modifying the pour point of the
composition).
[0026] In an embodiment, the diluent generally comprises any
suitable oil. Nonlimiting examples of a diluent suitable for use in
the present disclosure include petroleum oils, natural oils,
synthetically-derived oils, diesel oil, kerosene oil, mineral oil,
olefins and polyolefins (e.g., alpha-olefins and/or internal
olefins), polydiorganosiloxanes, esters, biodiesel, diesters of
carbonic acid, paraffins, ethers, or combinations thereof.
[0027] In an embodiment a diluent of the type disclosed herein may
be present within the EC in an amount of from about 15 wt. % to
about 90 wt. %, alternatively from about 20 wt. % to about 75 wt.
%, or alternatively from about 25 wt. % to about 70 wt. % based on
the total weight of the EC.
[0028] In an embodiment, the EC comprises a thinner (i.e., thinning
agent). A thinner may be added to an EC of the type described
herein with the purpose of modifying one or more physical
properties of the EC (e.g., modifying the pour point of the
composition). Without wishing to be limited by theory, the thinner
may function to alter the physical properties of the mixture by
contributing to breaking up intermolecular forces between the
compounds of the mixture. In an embodiment, the thinner functions
to adjust the viscosity of the EC to some user and/or process
desired range. In an embodiment, the thinner comprises an alcohol,
a fatty acid amide, or combinations thereof.
[0029] In an embodiment, the thinner comprises 2-methyl-1-propanol
(i.e., isobutyl alcohol), 2-methyl-2-butanol (i.e., tert-amyl
alcohol) or combinations thereof. In an embodiment, the thinner
comprises 2-methyl-1-propanol (i.e., isobutyl alcohol) which is
depicted in Structure 1.
##STR00003##
2-methyl-1-propanol is an organic compound with the formula
(CH.sub.3).sub.2CHCH.sub.2OH. Isomers of 2-methyl-1-propanol
include n-butanol, 2-butanol, and tert-butanol. 2-methyl-1-propanol
can be produced by the carbonylation of propylene or naturally
during the fermentation of carbohydrates.
[0030] In an embodiment the thinner comprises 2-methyl-2-butanol
(i.e., tert-amyl alcohol) which is depicted in Structure 2.
##STR00004##
2-Methyl-2-butanol, tert-amyl alcohol, 2M2B or amylene hydrate, is
one of the isomers of amyl alcohol. It is a clear, colorless liquid
with a strong odor of peppermint or camphor.
[0031] In an embodiment, the thinner comprises a fatty acid amide.
The fatty acid amide may be the product of a reaction between a
fatty acid such as oleic acid or linoleic acid, and a primary or
secondary amine such as diethanol amine, dimethylamine,
diethylamine, methylamine, ethylamine, piperidine, aniline, or
combinations thereof.
[0032] In another embodiment, the fatty acid amide comprises the
product of a transamidification reaction between an amine and a
fatty acid ester. The fatty acid ester may be a simple ester, such
as the methyl or ethyl ester of the fatty acid or it may be a
naturally occurring ester, such as a triglyceride. For example, the
fatty acid ester in the transamidification reaction may comprise
soya oil, sunflower oil, corn oil, safflower oil, or combinations
thereof. In such an embodiment, the fatty acid amide may be the
product of about 1:1 molar ratio of the fatty acid ester and the
amine, alternatively about 1:1.5 molar ratio, or alternatively
about 1:3 molar ratio. In an embodiment, the thinner comprises a
fatty dimethyl amide.
[0033] As may be appreciated by one of skill in the art viewing
this disclosure, the product resulting from the above-noted
transamidification reaction between fatty acid esters (e.g., mixed
fatty acid esters) and amines may be a complex mixture. For
example, the resulting product may comprise a mixture of compounds
including amides, amines, alkyl acids, and other side products. It
is contemplated that the resulting product may be used in an EC of
the type disclosed herein without further purification.
Alternatively, the resulting product may be subjected to one or
more suitable methodologies for purifying or increasing the utility
of the product in an EC of the type disclosed herein.
[0034] In an embodiment, the thinner comprises STEPOSOL M-8-10 and
STEPOSOL M-10, which are both formulations of N,N-dimethylcapramide
commercially available from Stepan.
[0035] In an embodiment a thinner of the type disclosed herein may
be present within the EC in an amount of from about 0.1 wt. % to
about 40 wt. %, alternatively from about 1.0 wt. % to about 20 wt.
%, or alternatively from about 1.5 wt. % to about 10 wt. %, based
on the total weight of the EC.
[0036] In an embodiment, an EC of the type disclosed herein is
characterized by a pour point of from about 100.degree. F. to about
-20.degree. F., alternatively from about 40.degree. F. to about
-10.degree. F., or alternatively from about 32.degree. F. to about
0.degree. F. The pour point herein refers to the lowest temperature
at which a liquid retains its flow characteristics. The pour point
of the EC is a qualitative test and may be determined by allowing
the EC to equilibrate at a certain temperature, and then observing
whether it is possible to pour the EC out of its container.
[0037] In an embodiment, the EC has a viscosity of from about 100
centipoise (cp) to about 1000000 cp, alternatively from about 200
cp to about 50000 cp, alternatively from about 250 cp to about
10000 cp, or alternatively from about 500 cp to about 10000 cp as
determined by Anton Paar rheometer (Physica MCR 501).
[0038] In an embodiment, the EC may be used in a WSF at
temperatures of from about 40.degree. F. to about 550.degree. F.,
alternatively from about 80.degree. F. to about 350.degree. F., or
alternatively from about 100.degree. F. to about 300.degree. F.
[0039] The wellbore servicing fluid (WSF) may contain any amount of
the EC effective for the intended wellbore service. In an
embodiment, the EC is present in a WSF in an amount of from about
0.1 lb/bbl to about 40 lb/bbl, alternatively from about 2 lb/bbl to
about 30 lb/bbl, or alternatively from about 6 lb/bbl to about 20
lb/bbl based on the total weight of the WSF.
[0040] In an embodiment, the EC comprises an emulsifier, a diluent,
and a thinner. For example, the EC may comprise 65 wt. %
emulsifier, 25 wt. % mineral oil, and 10 wt. % isobutyl alcohol
based on the total weight of the EC. In such embodiments, the
emulsifier is a CATP prepared according to the two third amide
synthesis depicted in Scheme I. Such an EC may be used in a WSF
comprising an oil-in-water emulsion or a water-in-oil emulsion to
aid in stabilization of the WSF.
[0041] In an embodiment, the EC comprises 50 wt. % emulsifier, 41
wt. % diesel oil, and 9 wt. % tert-amyl alcohol based on the total
weight of the EC. In such embodiments, the emulsifier is a CATP
according to the half-amide synthesis depicted in Scheme II. Such
an EC may be used in a WSF comprising an oil-in-water emulsion or a
water-in-oil emulsion to aid in stabilization of the WSF.
[0042] In an embodiment, a method of servicing a wellbore comprises
drilling a wellbore in a subterranean formation and introducing to
the formation a wellbore servicing fluid (WSF), and specifically a
WSF comprising an EC as disclosed herein. As used herein, a
"servicing fluid" refers to a fluid used to drill, complete, work
over, fracture, repair, prepare in any way a wellbore for the
recovery of materials residing in a subterranean formation
penetrated by the wellbore, or recovering of such materials. 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.
[0043] In an embodiment, the WSF comprises an EC. In an embodiment,
the components of the EC are combined at the well site along with
the remaining components of the WSF (e.g., an aqueous fluid, an
oleaginous fluid, etc.); alternatively, the components of the EC
are combined off-site (that is, the EC is formed as an additive
package prior to arriving at the well site) and the EC is
transported to and used at the well site (combined with the
remaining components of the WSF such as an aqueous fluid, an
oleaginous fluid, etc.).
[0044] Examples of wellbore servicing fluids include, but are not
limited to, cement slurries, drilling fluids or muds, spacer
fluids, lost circulation fluids, fracturing fluids, wettability
alteration fluids or completion fluids. In an embodiment, the WSF
comprises an oil-based servicing and/or drilling fluid or an
aqueous based servicing and/or drilling fluid that comprises at
least one oleaginous component. Nonlimiting examples of oil-based
fluids suitable for use in the present disclosure include oil-based
drilling or servicing fluids, invert emulsions and servicing fluids
comprising substantially no aqueous component.
[0045] In an embodiment, an EC of the type disclosed herein can be
introduced to a wellbore servicing fluid and function as an
emulsifier. In an embodiment, the wellbore servicing fluid is an
oil-based wellbore servicing fluid. As used herein, an oil-based
wellbore servicing fluid includes fluids that are comprised
entirely or substantially of non-aqueous fluids and/or invert
emulsions wherein the continuous phase is a non-aqueous fluid. In
an embodiment, the oil-based wellbore servicing fluid comprises
less than about 35%, 25%, 20%, 15%, 10% or 1% water by weight of
the wellbore servicing fluid. Alternatively, the wellbore servicing
fluid may contain a balance of the non-aqueous fluid after taking
other components of the fluid composition into account.
[0046] In an embodiment the wellbore servicing fluid comprises an
oleaginous fluid. Examples of oleaginous fluids suitable for use in
the present disclosure include, but are not limited to petroleum
oils, natural oils, synthetically-derived oils, or combinations
thereof. Nonlimiting examples of oleaginous fluids suitable for use
in the present disclosure include diesel oil, fuel oil, kerosene
oil, mixtures of crude oil, mineral oil, synthetic oil, vegetable
oils, olefins, polyolefins, alpha-olefins, internal olefins,
polydiorganosiloxanes, acetals, esters, diesters of carbonic acid,
linear or branched paraffins, or combinations thereof.
[0047] Commercial examples of oleaginous fluids suitable for use in
this disclosure include without limitation PETROFREE base fluid,
which is a synthetic 100% ester base fluid and, XP-07 synthetic
paraffin base fluid, which is a pure normal alkane mixture, both of
which are available from Halliburton Energy Services, Inc; SHELL
SARALINE 185V which is a synthetic drilling base fluid commercially
available from Shell; EDC 99-DW which is a hydrocarbon commercially
available from TOTAL Petrochemicals; ESCAID 110 hydrocarbon fluid
is a petroleum distillate commercially available from EXXON-MOBIL
Corp; and BAROID ALKANE paraffin-based synthetic fluid which is a
base oil commercially available from Halliburton Energy Services,
Inc.
[0048] In an embodiment, the wellbore servicing fluid comprises a
water-in-oil emulsion fluid, termed an invert emulsion, comprising
an oleaginous fluid and a non-oleaginous fluid (e.g., water), and
further comprises an EC of the type disclosed herein.
[0049] In an embodiment, the oleaginous fluid of the invert
emulsion may be of the type previously disclosed herein. The
concentration of the oleaginous fluid in the emulsion should be
sufficient so that an invert emulsion forms and may be less than
about 99 volume percent (vol. %) based on the total volume of fluid
the invert emulsion. In an embodiment, the amount of oleaginous
fluid is from about 30 vol. % to about 95 vol. %, alternatively
from about 40 vol. % to about 90 vol. %, or alternatively from
about 50 vol. % to about 85 vol. % based on the total volume of
fluid the invert emulsion.
[0050] In an embodiment, the non-oleaginous fluid component of the
invert emulsion may generally comprise any suitable aqueous liquid.
Examples of suitable non-oleaginous fluids include, but are not
limited to, sea water, freshwater, naturally-occurring and
artificially-created brines containing organic and/or inorganic
dissolved salts, liquids comprising water-miscible organic
compounds, and combinations thereof. Examples of suitable brines
include, but are not limited to, chloride-based, bromide-based, or
formate-based brines containing monovalent and/or polyvalent
cations and combinations thereof. Examples of suitable
chloride-based brines include, but are not limited to, sodium
chloride, potassium chloride and calcium chloride. Examples of
suitable bromide-based brines include, but are not limited to,
sodium bromide, calcium bromide, and zinc bromide. Examples of
suitable formate-based brines include, but are not limited to,
sodium formate, potassium formate, and cesium formate.
[0051] In an embodiment, the non-oleaginous fluid may be present in
an amount that is less than the theoretical limit needed for
forming an invert emulsion. In an embodiment, the non-oleaginous
fluid may be present in an amount of less than about 70 volume
percent (vol. %) based on the total volume of the invert emulsion,
alternatively from about 1 vol. % to about 70 vol. %, or
alternatively from about 5 vol. % to about 60 vol. %.
[0052] For example, in an embodiment, the invert emulsion may
comprise from about 20 vol. % to about 60 vol. % non-oleaginous
fluid based on the total volume of the invert emulsion and about 40
vol. % to 80 vol. % oleaginous fluid by volume, alternatively, from
about 30 vol. % to about 50 vol. % or from about 50 vol. % to 70
vol. %.
[0053] In an embodiment, the EC may be utilized in a WSF suitable
for use in a drilling operation. In such embodiments, the wellbore
servicing fluid may be an invert emulsion, oil-based drilling mud
comprising the EC.
[0054] In an embodiment, a WSF comprising an EC of the type
described herein may be used during an enhanced oil recovery
operation (EOR). EOR is a generic term for techniques for
increasing the amount of crude oil that can be extracted from a
hydrocarbon-producing formation (e.g., hydrocarbon reservoirs). EOR
is achieved by gas injection, foam injection, chemical injection,
microbial injection, or thermal recovery (which includes cyclic or
continuous steam, steam flooding, and fire flooding).
[0055] In an embodiment, the EOR operation comprises chemical
injection. ECs of the type disclosed herein can be used as a
surfactant in an alkali surfactant polymer (ASP) flood. Chemicals
used in EOR applications are dissolved in the formation brine or
water from an available aquifer. Precipitation of surfactant in
high saline water has been considered as one of the major problems
associated with the ASP flooding. The ECs of this disclosure may
display high solubility with high salinity brines (e.g., greater
than about 300,000 ppm salt). ECs of the type disclosed herein when
introduced into the injection water may reduce the oil water
interfacial tension (IFT). Also the EC can alter the wettability of
the reservoir rock. Reduction of IFT and wettability alteration can
increase the oil recovery by mobilizing residual oil.
[0056] In an embodiment, the EOR occurs in a two well
configuration, i.e., an injector well and a producer well. For
example, a WSF comprising an EC may be pumped into the formation
via the injector well. The WSF comprising the EC may be allowed to
sweep across the formation, by flowing through oil-containing zones
that connect the injector well to the producer well.
[0057] In an embodiment, the EC, a WSF comprising the EC, and
methods of using same disclosed herein may be advantageously
employed in the performance of one or more wellbore servicing
operations. In an embodiment, the EC may be advantageously employed
in high salinity environments, for example high salinity WSFs
and/or downhole environments having high salinity (that may in turn
yield increased salinity is WSFs employed therein). In an
embodiment, an EC is employed in a WSF comprising saturated brines.
For example, the EC may be employed in WSF having salt
concentrations ranging from about 0 ppm to about 500,000 ppm,
alternatively from about 1000 ppm to about 300,000 ppm, or
alternatively from about 50,000 ppm to about 150,000 ppm.
[0058] An EC of the type disclosed herein may facilitate the
formation of stable WSF emulsions having an electrical stability
ranging from about 0 to about 2000 Volts (V), alternatively from
about 100 V to about 1500 V, or alternatively from about 100 V to
about 1000 V as described in API Recommended Practice 13B-2.
Additionally, in an embodiment, the EC may be environmentally
acceptable, and display a low toxicity level.
[0059] The following are additional enumerated embodiments of the
concepts disclosed herein.
[0060] A first embodiment which is a method of servicing a wellbore
in a subterranean formation comprising preparing an invert emulsion
comprising an aqueous fluid, an oleaginous fluid, and an emulsifier
composition (EC), wherein the emulsifier composition comprises an
emulsifier, a diluent, and a thinner, wherein the thinner comprises
an alcohol, a fatty acid amide, or combinations thereof; and
placing the invert emulsion in the wellbore.
[0061] A second embodiment which is the method of the first
embodiment wherein the emulsifier comprises a carboxylic
acid-terminated polyamide, a mixture produced by a Diels-Alder
reaction of dienophiles with a mixture of fatty acids and/or resin
acids, or combinations thereof.
[0062] A third embodiment which is the method of the second
embodiment wherein the carboxylic acid-terminated polyamide
comprises one or more products of a condensation reaction between
fatty acids and polyamines.
[0063] A fourth embodiment which is the method of any of the second
and third embodiments wherein the dienophile comprises carboxylic
acids, polycarboxylic acids, anhydrides, or combinations
thereof.
[0064] A fifth embodiment which is the method of any of the second
through fourth embodiments wherein the fatty acids and/or resin
acids are derived from the distillation of crude tall oil.
[0065] A sixth embodiment which is the method of any of the first
through fifth embodiments wherein the emulsifier is present in the
EC in an amount of from about 25 wt. % to about 100 wt. %, based on
the total weight of the EC.
[0066] A seventh embodiment which is the method of any of the first
through sixth embodiments wherein the diluent comprises petroleum
oils, natural oils, synthetically-derived oils, diesel oil,
kerosene oil, mineral oil, olefins and polyolefins (e.g.,
alpha-olefins and/or internal olefins), polydiorganosiloxanes,
esters, biodiesel, diesters of carbonic acid, paraffins, ethers, or
combinations thereof.
[0067] An eighth embodiment which is the method of any of the first
through seventh embodiments wherein the diluent is present in the
EC in an amount of from about 15 wt. % to about 90 wt. %, based on
the total weight of the EC.
[0068] A ninth embodiment which is the method of any of the first
through eighth embodiments wherein the alcohol comprises
2-methyl-1-propanol, 2-methyl-2-butanol or combinations
thereof.
[0069] A tenth embodiment which is the method of any of the first
through ninth embodiments wherein the fatty acid amide comprises
the product of a reaction between a polyamine and a fatty acid or a
fatty acid ester or combinations thereof.
[0070] An eleventh embodiment which is the method of the tenth
embodiment wherein the amine comprises diethanol amine,
dimethylamine, diethylamine, methylamine, ethylamine, piperidine,
aniline, or combinations thereof.
[0071] A twelfth embodiment which is the method of any of the tenth
and eleventh embodiments wherein the fatty acid comprises oleic
acid, linoleic acid, abietic acid, abietic acid derivatives,
pimaric acid, plamitic, myristic, linolenic, stearic, or
combinations thereof.
[0072] A thirteenth embodiment which is the method of any of the
tenth through twelfth embodiments wherein the fatty acid ester
comprises a methyl fatty acid ester, an ethyl fatty acid ester, a
naturally occurring ester, a triglyceride, soya oil, sunflower oil,
corn oil, safflower oil, or combinations thereof.
[0073] A fourteenth embodiment which is the method of any of the
tenth through thirteenth embodiments wherein the fatty acid ester
comprises a fatty dimethyl amide.
[0074] A fifteenth embodiment which is the method of any of the
first through fourteenth embodiments wherein the thinner is present
in the EC in an amount of from about 0.1 wt. % to about 40 wt. %,
based on the total weight of the EC.
[0075] A sixteenth embodiment which is the method of any of the
first through fifteenth embodiments wherein the wellbore servicing
fluid comprises an oil-based drilling mud.
[0076] A seventeenth embodiment which is the method of any of the
first through sixteenth embodiments wherein the EC has a pour point
of from about -20.degree. F. to about 100.degree. F.
[0077] An eighteenth embodiment which is the method of any of the
first through seventeenth embodiments wherein the EC has an
electrical stability of from about 0 to about 2000 V.
[0078] A nineteenth embodiment which is the method of any of the
first through eighteenth embodiments wherein the EC has a viscosity
of from about 100 cp to about 100000 cp.
[0079] A twentieth embodiment which is a A method of servicing a
wellbore in a subterranean formation comprising flowing a wellbore
serving fluid comprising an emulsifier composition (EC) through a
portion of a subterranean formation, wherein the EC comprises an
emulsifier, a diluent and a thinner and wherein the thinner
comprises 2-methyl-1-propanol, 2-methyl-2-butanol, a fatty acid
amide, or combinations thereof; contacting the EC with oil in situ
within the formation to form an emulsion; an reducing the water-oil
interfacial tension and altering the wettability to provide
enhanced oil recovery from the formation.
[0080] A twenty-first embodiment which is the method of the
twentieth embodiment wherein the emulsifier comprises a partial
amide.
[0081] A twenty-second embodiment which is the invert emulsion
wellbore servicing fluid comprising an aqueous fluid, an oleaginous
fluid, and an emulsifier composition (EC), wherein the emulsifier
composition comprises an emulsifier, a diluent, and a thinner,
wherein the thinner comprises an alcohol, a fatty acid amide, or
combinations thereof.
[0082] A twenty-third embodiment which is the invert emulsion of
the twenty-second embodiment formulated as a drilling fluid.
EXAMPLES
[0083] The embodiments having been generally described, the
following examples are given as particular embodiments of the
disclosure 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 or the claims in
any manner.
Example 1
[0084] Six samples, designated samples 1-6, were prepared
containing an emulsifier, a diluent, and a thinner. Three thinning
agents were used: isobutyl alcohol (IBA), tertiary amyl alcohol
(t-AA) and butyl blend (BB, 1:1 mixture of ethylene
glycol-monobutyl ether and diethylene glycol butyl ether). In all
cases the diluent was mineral oil and the emulsifier was a
two-thirds amide. The composition of each sample and the amounts of
each component present in the sample are presented in Table 1 as
the weight percent of material based on the total weight of the
sample. The samples were formulated to provide a composition having
a pour point of 0.degree. F.
TABLE-US-00001 TABLE 1 Sample Emulsifier Number Thinner (wt. %)
Thinner (wt. %) Diluent (wt. %) 1 IBA 65 9 26 2 t-AA 65 9 26 3 BB
65 9 26 4 IBA 40 1 59 5 t-AA 40 1 59 6 BB 40 3 57
[0085] The data displayed in Table 1 indicates that when the
compositions were formulated by having a 65 wt. % emulsifier (i.e.,
two-thirds amide), all compositions required the same amount of
diluent, i.e., 26 wt. %, and also the same amount of thinner, i.e.,
9 wt. %. However, the composition that utilized BB as the thinner
was notably much thicker. This results also demonstrate that when
the samples were formulated to have 40 wt. % of the two-thirds
amide emulsifier, to achieve a pour point of 0.degree. F., the
compositions required 59 wt. % of diluent however only 1 wt. % of
thinners of the type disclosed herein (i.e., IBA and t-AA) were
needed. In contrast, when BB was used as a thinner, the amount of
thinner required to achieve a 0.degree. F. pour point was 3 wt. %,
more than twice the amount required for either IBA or t-AA.
[0086] Similar results were obtained when the emulsifier was a
half-amide, Table 2. Referring to Table 2, six samples designated
samples 7 to 12 were prepared containing the half-amide emulsifier,
mineral oil as the diluent and the indicated thinner present in the
weight percentages indicated which are based on the total weight of
the sample.
TABLE-US-00002 TABLE 2 Emulsifier Sample Thinner (wt. %) Thinner
(wt. %) Diluent (wt. %) 7 IBA 50 10 40 8 t-AA 50 10 40 9 BB 50 10
40 10 IBA 30 1.5 68.5 11 t-AA 30 1.5 68.5 12 BB 30 2.5 67.5
[0087] The data displayed in Table 2 indicates that when the
samples contained 50 wt. % of the half-amide emulsifier, each
sample required 40 wt. % diluent and 10 wt. % thinner to achieve a
pour point of 0.degree. F. However, the composition that utilized
BB as the thinner was notably thicker. The results also demonstrate
that when the samples contained 30 wt. % half-amide emulsifier each
sample required 68.5 wt. % diluent. However samples 10 and 11 which
contained IBA and t-AA respectively only required 1.5 wt. % to
provide a pour point of 0.degree. F. In contrast, when BB was used
as a thinner, Sample 12, the amount of thinner required to achieve
a 0.degree. F. pour point was considerably higher, 2.5 wt. %.
[0088] For a two-third amide emulsifier, the effect of the type of
fatty acid amide thinner on the pour point was investigated and the
data is presented in Table 3. Referring to Table 3, each of samples
13-16 contained a two-third amide emulsifier, mineral oil as the
diluent and the indicated thinner in the amounts indicated in the
Table 3.
TABLE-US-00003 TABLE 3 Sample Emulsifier Thinner Diluent No.
Thinner (wt. %) (wt. %) (wt. %) 13 STEPOSOL M-8-10 65 20 5 14
STEPOSOL M-10 65 20 5 15 STEPOSOL M-8-10 40 10 50 16 STEPOSOL M-10
40 10 50
[0089] Referring to the data in Table 3, for the samples containing
65 wt. % of the two-thirds amide emulsifier, 5 wt. % diluent and 20
wt. % thinner was required to observe a pour point of .degree. F.
For the samples containing 40 wt. % of the two-thirds amide
emulsifier, 50 wt. % of the mineral oil diluent and 10 wt. % of the
thinner was required to observe a pour point of .degree. F.
Example 2
[0090] The stability of emulsions comprising ECs of the type
disclosed herein were investigated by stress-testing emulsions
under shear. More specifically, six samples, designated samples
A-E, were prepared. Samples A, B, and C contained diesel oil as the
base oil, a two-thirds emulsifier and IBA, t-AA, and BB
respectively. Sampled D, E, and F contained mineral oil as the base
oil, a two-thirds emulsifier and IBA, t-AA, and BB respectively.
Each sample also contained a calcium chloride brine and
viscosifier. The amounts of each component utilized are presented
in Table 4. GELTONE II viscosifier is an organophilic clay
commercially available from Halliburton Energy Services.
TABLE-US-00004 TABLE 4 Component Units Amount Base Oil Bbl 0.6097
Active Emulsifier (65%) Lb 1.3 CaCl.sub.2 Brine Bbl 0.1197 GELTONE
II viscosifier Lb 3 Salinity of Brine ppm 300,000 Oil to Water
Ratio 85/15 (volumetric) Density lb/gal 15
[0091] The samples were run on a Multi-mixer with periodic
measurement of electrical stability. The electrical stability of
each sample as a function of time with shear was determined by ES
(electric stability) meter in accordance with the procedures
described in API Recommended Practice 13B-2, and the results are
plotted in FIGS. 1 and 2 for diesel and mineral oil as the base
oil, respectively. In an electrical stability test, an emulsion is
present if the electrical stability is greater than zero. A stable
emulsion is indicated by a high value of electrical stability that
can be sustained over time. For both Diesel oil (FIG. 1) and
mineral oil (FIG. 2), samples containing IBA, i.e., Samples A and
D, had a higher stability than samples containing t-AA, i.e.,
Samples B and E which in turn was higher than samples containing
BB, i.e., Samples C and F. Further, the samples containing mineral
oil, i.e., Samples D-F, had higher electrical stability values over
longer time periods when compared to the samples containing diesel,
i.e., Samples A-C.
[0092] The exemplary EC disclosed herein may directly or indirectly
affect one or more components or pieces of equipment associated
with the preparation, delivery, recapture, recycling, reuse, and/or
disposal of the disclosed EC. For example, the disclosed EC may
directly or indirectly affect one or more mixers, related mixing
equipment, mud pits, storage facilities or units, fluid separators,
heat exchangers, sensors, gauges, pumps, compressors, and the like
used generate, store, monitor, regulate, and/or recondition the
exemplary EC. The disclosed EC may also directly or indirectly
affect any transport or delivery equipment used to convey the EC to
a well site or downhole such as, for example, any transport
vessels, conduits, pipelines, trucks, tubulars, and/or pipes used
to fluidically move the EC from one location to another, any pumps,
compressors, or motors (e.g., topside or downhole) used to drive
the EC into motion, any valves or related joints used to regulate
the pressure or flow rate of the EC, and any sensors (i.e.,
pressure and temperature), gauges, and/or combinations thereof, and
the like. The disclosed EC may also directly or indirectly affect
the various downhole equipment and tools that may come into contact
with the chemicals/fluids such as, but not limited to, drill
string, coiled tubing, drill pipe, drill collars, mud motors,
downhole motors and/or pumps, floats, MWD/LWD tools and related
telemetry equipment, drill bits (including roller cone, PDC,
natural diamond, hole openers, reamers, and coring bits), sensors
or distributed sensors, downhole heat exchangers, valves and
corresponding actuation devices, tool seals, packers and other
wellbore isolation devices or components, and the like.
[0093] While 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.). For example, whenever a
numerical range with a lower limit, R.sub.L, and an upper limit,
R.sub.U, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.L+k*(R.sub.U-R.sub.L), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, i.e., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. 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.
[0094] 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
embodiments of the present invention. The discussion of a reference
in the Description of Related Art 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.
* * * * *