U.S. patent application number 10/410611 was filed with the patent office on 2003-11-27 for hydrate-inhibiting well fluids.
Invention is credited to Darring, Michael T., Foxenberg, William E., Gobert, Kim J., Horton, Robert L., Kippie, David P..
Application Number | 20030220202 10/410611 |
Document ID | / |
Family ID | 29255351 |
Filed Date | 2003-11-27 |
United States Patent
Application |
20030220202 |
Kind Code |
A1 |
Foxenberg, William E. ; et
al. |
November 27, 2003 |
Hydrate-inhibiting well fluids
Abstract
A method of treating a well including injecting a well-treating
fluid into the well, where the well-treating fluid comprises a
glycol compound and an organic liquid, the glycol compound and
organic liquid being present in amounts selected to achieve a
desired density. In another embodiment, a well fluid including a
glycol compound an organic liquid, and a salt, wherein the glycol
compound, organic liquid, and salt are present in amounts selected
to achieve a predetermined density is disclosed.
Inventors: |
Foxenberg, William E.;
(Houston, TX) ; Darring, Michael T.; (Houston,
TX) ; Gobert, Kim J.; (Houston, TX) ; Kippie,
David P.; (Katy, TX) ; Horton, Robert L.;
(Sugarland, TX) |
Correspondence
Address: |
Jonathan P. Osha
ROSENTHAL & OSHA L.L.P.
Suite 2800
1221 McKinney
Houston
TX
77010
US
|
Family ID: |
29255351 |
Appl. No.: |
10/410611 |
Filed: |
April 10, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60374049 |
Apr 19, 2002 |
|
|
|
60412543 |
Sep 20, 2002 |
|
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Current U.S.
Class: |
507/200 |
Current CPC
Class: |
C09K 8/32 20130101; C09K
8/06 20130101; C09K 8/34 20130101; C09K 2208/22 20130101 |
Class at
Publication: |
507/200 |
International
Class: |
E21B 001/00 |
Claims
What is claimed is:
1. A well fluid comprising: a glycol compound; and an organic
liquid, wherein the glycol compound and the organic liquid are
present in amounts selected to achieve a predetermined density
suitable for annular pressure control.
2. The well fluid of claim 1, further comprising water.
3. The well fluid of claim 1, further comprising a salt
solution.
4. The well fluid of claim 1, wherein the well fluid is
substantially water-free.
5. The well fluid of claim 1, further comprising a polymer, wherein
the polymer, the glycol compound, and the organic liquid are
present in amounts selected to achieve a predetermined heat
capacity.
6. The well fluid of claim 1, further comprising a polymer, wherein
the polymer, the glycol compound, and the organic liquid are
present in amounts selected to achieve a predetermined thermal
conductivity.
7. The well fluid of claim 1, further comprising a polymer, wherein
the polymer, the glycol compound, and the organic liquid are
present in amounts selected to achieve a predetermined
viscosity.
8. The well fluid of claim 3, wherein the salt solution comprises
at least one selected from the group consisting of halide brines,
formate brines, and acetate brines.
9. The well fluid of claim 8, wherein the salt solution comprises
calcium bromide.
10. The well fluid of claim 1, wherein the glycol compound
comprises at least one selected from the group consisting of
ethylene glycol, propylene glycol, and monoethylene glycol.
11. The well fluid of claim 1, wherein the glycol compound
comprises 20% to 50% of a total weight percentage of the well
fluid.
12. The well fluid of claim 11, wherein the glycol compound
comprises monoethylene glycol.
13. The well fluid of claim 1, wherein the organic liquid comprises
20% to 50% of the total weight percentage of the well fluid.
14. The well fluid of claim 12, wherein the organic liquid
comprises methanol.
15. The well fluid of claim 1, wherein the predetermined density
comprises 5 ppg to 9 ppg.
16. A method of treating a well comprising: injecting a
well-treating fluid into the well, wherein the well-treating fluid
comprises a glycol compound, and an organic liquid, the glycol
compound and the organic liquid present in amounts selected to
achieve a predetermined density suitable for annular pressure
control.
17. A well fluid comprising: a glycol compound; and a quaternary
amine salt, wherein the glycol compound and the quaternary amine
salt are present in amounts selected to achieve a predetermined
density suitable for annular pressure control.
18. The well fluid of claim 17, further comprising an organic
liquid.
19. The well fluid of claim 17, wherein the glycol compound and the
quaternary amine salt are selected such that a density of the well
fluid decreases when the quaternary amine is added to the glycol
compound.
20. The well fluid of claim 17, wherein the glycol compound
comprises at least one selected from the group consisting of
ethylene glycol, propylene glycol, and monoethylene glycol.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority pursuant to 35 U.S.C.
.sctn.119 of U.S. Provisional Patent Application No. 60/374,049
filed on Apr. 19, 2002, entitled "Well Fluid," in the name of
William E. Foxenberg. This provisional application is incorporated
herein by reference. This application also claims priority pursuant
to 35 U.S.C. .sctn.119 of U.S. Provisional Patent Application No.
60/412,543 filed on Sep. 20, 2002, entitled "Hydrate-Inhibiting
Well Fluids," in the names of William E. Foxenberg, Michael T.
Darring, Kim J. Gobert, David P. Kippie, and Robert L. Horton. This
provisional application is incorporated herein by reference.
BACKGROUND OF INVENTION
[0002] 1. Field of the Invention
[0003] The invention relates generally to wellbore fluids. More
particularly, the present invention relates to non-aqueous,
non-corrosive packer fluids.
[0004] 2. Background Art
[0005] When drilling or completing wells in earth formations,
various fluids typically are used in the well for a variety of
reasons. For the purposes herein, such fluid will be referred to as
"well fluid." In particular, one type of commonly used well fluid
is known as a "packer fluid." The term packer fluid means a fluid
that is left in the annular region of a well between tubing and
outer casing above a packer. The main functions of a packer fluid
are: (1) to provide hydrostatic pressure in order to lower
differential pressure across a sealing element, (2) to lower
differential pressure on a wellbore and casing to prevent collapse
and (3) to protect metals and elastomers from corrosion or
deterioration. Generally, they should be of sufficient density to
control the producing formation, be solids-free and resistant to
viscosity changes over long periods of time, and be noncorrosive to
the wellbore and completion components.
[0006] When setting a packer, it is desirable to place a fluid in
the annulus that is solids-free, thermally stable and maintains a
selected hydrostatic pressure. In some situations, a modified
drilling mud is used as the packer fluid. However, the lack of
long-term chemical stability and of long-term solids suspension are
properties that limit the use of drilling mud. In many situations,
a solids-free brine is used as the packer fluid in order to
maintain long-term chemical stability and obviate the need for
long-term solids suspension. These fluids, in some cases, are prone
to form hydrates with high pressure hydrocarbon gas in the
formation. In other cases, the fluid must meet certain performance
specifications such as density, hydrate inhibition, viscosity and
annulus compatibility that cannot otherwise be met by standard
packer fluids, i.e., salt solutions and/or drilling muds of
well-established composition.
SUMMARY OF INVENTION
[0007] In one aspect, the present invention relates to a method of
treating a well including injecting a substantially water-free
well-treating fluid into the well, where the well-treating fluid
comprises a glycol compound and an organic liquid, the glycol
compound and the organic liquid being present in amounts selected
to achieve a predetermined density.
[0008] In another aspect, the present invention relates to a
substantially water-free well fluid including a glycol compound and
an organic liquid, where the glycol compound and the organic liquid
are present in amounts selected to achieve a predetermined
density.
[0009] In one aspect, the present invention relates to a method of
treating a well including injecting a well-treating fluid into the
well, where the well-treating fluid comprises water, a glycol
compound, and other organic liquids in which the combination of
fluids meets pre-set performance characteristics such as density,
viscosity, hydrate inhibition, and compatibility with other fluids
and elements in the annulus.
[0010] In one aspect, the present invention relates to a well fluid
that includes water, a glycol compound, and other organic liquids
in which the combination of fluids meets pre-set performance
characteristics such as density, viscosity, hydrate inhibition, and
compatibility with other fluids and elements in the annulus.
[0011] In another aspect, the present invention relates to a well
fluid that includes a glycol compound, and a quaternary amine salt,
where the glycol compound and the quaternary amine salt are present
in amounts selected to achieve a predetermined density.
[0012] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
DETAILED DESCRIPTION
[0013] When setting a packer, it is desirable to have a fluid in
the well annulus that is solids-free, thermally stable, and
maintains a selected hydrostatic pressure. This invention relates
to aqueous or non-aqueous fluids that can achieve a relatively
broad range of densities without requiring solids, and are true
solutions rather than emulsions or suspensions.
[0014] Glycols, such as ethylene glycol, propylene glycol, and
others can be mixed at a very broad range of ratios with water
and/or organic liquids such as alcohols, glycol ethers and others
to form fluid mixtures having densities ranging from low (.about.7
lbm/gal) to high (.about.11 lbm/gal), depending on desired
properties. Lbm/gal is a unit of density, which one of ordinary
skill in the art would interpret as pound per gallon, or more
specifically pound mass per gallon. Such mixtures inhibit hydrates
because the mixture is either substantially free of water or the
water is made inhibitive by virtue of the glycol and alcohol. Of
course, some water is absorbed from the atmosphere and, therefore,
some water is present in the glycol, but this amount is
insufficient to make the fluid corrosive. These mixtures can also
be viscosified with certain polymers, known within the oil and gas
industry, to achieve highly viscous fluids that show excellent
thermal insulation by virtue of their heat capacities, thermal
conductivities and viscosities.
[0015] In one embodiment, the present invention describes the
development of non-aqueous, non-solids laden, non-corrosive,
hydrate inhibitive well fluids (or packer fluids) for use in oil
field production annuli. The well fluids are prepared to desired
densities for annular pressure control by proportioning miscible,
non-aqueous fluids together. The non-aqueous fluids include
glycols, glycol-ethers, alcohols and other organic liquids. The
well fluids may contain soluble salts to achieve specific
densities. The well fluids may be viscosified with synthetic or
biopolymers to reduce convective currents, needed in some cases for
annular heat insulation.
[0016] In another embodiment, the present invention describes the
development of non-solids laden, non-corrosive, hydrate inhibitive
well fluids for use in oil field production annuli. The fluid is
prepared to desired densities for annular pressure control by
proportioning miscible fluids together with water. These fluids
include glycols, glycol-ethers, alcohols and other organic liquids.
The fluids may contain soluble salts to achieve specific densities.
The fluids may be viscosified with synthetic or biopolymers to
reduce convective currents, needed in some cases for annular heat
insulation.
[0017] One of ordinary skill in the art would appreciate that a
glycol compound and an organic liquid may be mixed in amounts
sufficient to yield a desired density. In addition, multiple glycol
compounds and multiple organic liquids may be mixed, with or
without water, so long as the mixture remains a solution.
EXAMPLE 1
[0018] In one embodiment, a well fluid in accordance with one
embodiment of the present invention comprises a mixture of 0.2
barrels of methanol, 0.35 barrels of monoethylene glycol (MEG),
0.42 barrels of water, and a sufficient amount of a CaBr.sub.2
solution, having a density of 14.5 ppg, to form a well fluid,
referred to as formulation 1 herein, having an overall density of
approximately 8.6 ppg.
EXAMPLE 2
[0019] In another embodiment, a well fluid in accordance with one
embodiment of the present invention comprises a mixture 0.2 barrels
of methanol, 0.35 barrels of monoethylene glycol (MEG), 0.42
barrels of water, and a sufficient amount of a CaBr.sub.2 solution,
having a density of 15.3 ppg, to form a well fluid, referred to as
formulation 2 herein, having an overall density of approximately
8.8 ppg. While particular salts, and particular densities are
referenced in the above embodiments, it should be understood that
the salt types and concentrations may also vary from zero to
saturation, according to density/compatibility requirements.
[0020] At temperatures of at least 30.degree. F., aqueous fluids
are susceptible to gas hydrate formation if high-pressure gas is
encountered. Typical oilfield pressures exceed 8,000 psi. An
additional consideration is that well fluids having a density of
8.6 ppg (achievable with 3.5-4.5 wt % salt) are often used. This
salt concentration is not adequate to prevent hydrate formation
under the combination of low salinity fluid, low temperature and
high gas pressure, should such a combination occur in the wellbore.
Therefore, other means of hydrate prevention, while maintaining
density control, are desired.
[0021] The present invention has discovered that advantageously,
mixtures of glycol and organic liquids are effective hydrate
inhibitors.
[0022] In testing formulations 1 and 2, it was discovered that the
well fluids provided hydrate suppression at pressures greater than
8,000 psi at 38.degree. F. Second, the well fluids maintained a
density of about 8.5-8.8 ppg at wellbore conditions. Third, a
viscosity of less than 30 centiPoise (cP) at mudline temperature
(38-40.degree. F.) and less than 30 cP at 8,200 psi was maintained.
Fourth, the tested formulations provided long-term stability
(>24 hours) at wellbore temperature (38-280.degree. F.) and
pressure (8,200 psi). In addition, well fluids of the present
invention were found to be compatible with a large number of
wellbore elastomers/wellbore fluids.
[0023] In the above formulations, it was discovered that the
presence of CaBr.sub.2 salt could cause precipitates to form.
Therefore, additional well fluids were formulated, whereby the
CaBr.sub.2 solution was replaced by volume ratios of methanol,
monoethylene glycol and water to a specified density.
[0024] Further formulations are shown in Table 1 below.
1TABLE 1 Hydrate Formation Parameters for Water - Methanol - MEG -
Salt Mixtures wt % Hydrate Hydrate Density wt % Wt % wt % KCI Temp
@ psi of Water Methanol MEG (10.8 ppg) 9,000 psi 37.degree. F.
Mixture.sup.(1) 100 87.degree. F. 188 psi .about.8.33 ppg 97 3
87.degree. F. 188 psi .about.8.4 ppg 52 45 3 44.degree. F. 6,600
psi .about.7.7 ppg 47 50 3 36.degree. F. 11,000 psi .about.7.6 ppg
52 45 3 39.degree. F. 8,670 psi .about.8.8 ppg 47 50 3 30.degree.
F. 11,000 psi .about.8.9 ppg 52 25 20 3 50.degree. F. 3.600 psi
.about.8.2 ppg 47 30 20 3 42.degree. F. 6,660 psi .about.8.2 ppg 47
20 30 3 44.degree. F. 6,660 psi .about.8.4 ppg 42 20 35 3
36.degree. F. 11,000 psi .about.8.5 ppg .sup.(1)Calulated values;
WHyP Hydrate Prediction Software
[0025] In yet other embodiments of the present invention,
formulations are produced involving (1) halide brines, formate
brines, and acetate brines, such as, for example, those based on
tetramethylammonium chloride, tetramethylammonium bromide,
tetramethylammonium formate, tetramethylammonium acetate,
tetraethylammonium chloride, tetraethylammonium bromide,
tetraethylammonium formate, tetraethylammonium acetate,
tetrapropylammonium chloride, tetrapropylammonium bromide,
tetrapropylammonium formate, tetrapropylammonium acetate,
tetrabutylammonium chloride, tetrabutylammonium bromide,
tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl.sub.2,
ZnBr.sub.2, CaBr.sub.2, ZnBr.sub.2/CaBr.sub.2 blends,
ZnBr.sub.2/CaBr.sub.2/CaCl.sub.2 blends, CsBr, CsI, CsHCO.sub.2,
and mixtures thereof, (2) ethylene glycol solutions of
tetramethylammonium chloride, tetramethylammonium bromide,
tetramethylammonium formate, tetramethylammonium acetate,
tetraethylammonium chloride, tetraethylammonium bromide,
tetraethylammonium formate, tetraethylammonium acetate,
tetrapropylammonium chloride, tetrapropylammonium bromide,
tetrapropylammonium formate, tetrapropylammonium acetate,
tetrabutylammonium chloride, tetrabutylammonium bromide,
tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl.sub.2,
ZnBr.sub.2, CaBr.sub.2, ZnBr.sub.2/CaBr.sub.2 blends,
ZnBr.sub.2/CaBr.sub.2/CaCl.sub.2 blends, CsBr, CsI, CsHCO.sub.2,
and mixtures thereof, and (3) methanol solutions of
tetramethylammonium chloride, tetramethylammonium bromide,
tetramethylammonium formate, tetramethylammonium acetate,
tetraethylammonium chloride, tetraethylammonium bromide,
tetraethylammonium formate, tetraethylammonium acetate,
tetrapropylammonium chloride, tetrapropylammonium bromide,
tetrapropylammonium formate, tetrapropylammonium acetate,
tetrabutylammonium chloride, tetrabutylammonium bromide,
tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl.sub.2,
ZnBr.sub.2, CaBr.sub.2, ZnBr.sub.2/CaBr.sub.2 blends,
ZnBr.sub.2/CaBr.sub.2/CaCl.sub.2 blends, CsBr, CsI, CsHCO.sub.2,
and mixtures thereof. Furthermore, (4) blends of the above
mentioned brines and methanol solutions, (5) blends of the above
mentioned brines and ethylene glycol solutions, (6) blends of the
above mentioned ethylene glycol solutions, and methanol solutions,
and (7) blends of the above mentioned brines, ethylene glycol
solutions, and methanol solutions are also within the scope of the
present invention.
[0026] Accordingly, in another aspect, the present invention
relates to well fluids comprising a glycol compound and a
quaternary amine salt. Furthermore, the glycol compound and
quaternary amine may be mixed with an organic liquid, as described
above, or with numerous other compounds. In addition, mixtures of
any or all of the above compounds may be used in connection with
the present invention. The above list is not intended to be a
comprehensive list of all suitable mixtures within the scope of the
present invention. One of ordinary skill in the art, having
reference to this specification, will recognize that other mixtures
are within the scope of the present invention.
EXAMPLE 3
[0027] As a third example of the formulations in accordance with
one embodiment of the present invention, a solution comprising 200
grams of ethylene glycol and 150 grams of tetrabutylammonium
bromide was prepared. The solution had a density of 9.0 ppg and a
TCT (Thermodynamic Crystallization Temperature) <25.degree. F.
This fluid is highly inhibitive of hydrates. In this third example,
the addition of salt to ethylene glycol caused the density to drop
from about 9.3 ppg to 9.0, a highly unusual and surprising result
having considerable utility. Typically, salts like CaBr.sub.2,
NaCl, and the like, cause the density of ethylene glycol to
increase upon the addition of the salt to the ethylene glycol. In
contrast, when the salt is, for example, tetrabutylammonium
bromide, the density decreases. Other salts that exhibit this
surprising behavior include tetramethylammonium chloride,
tetramethylammonium acetate, and the like.
EXAMPLE 4
[0028] As a fourth example of these formulations, a solution
comprising 200 grams of ethylene glycol and 400 grams of
tetrabutylammonium bromide was prepared. The solution had a density
of 9.0 ppg, substantially the same as that of the third example,
another highly surprising result--that a substantial amount of a
salt with density substantially greater than 9.0 ppg could be added
to a solution without any appreciable density increase in the
solution. This fluid is highly inhibitive of hydrates.
EXAMPLE 5
[0029] As a fifth example of these formulations, a solution
comprising 180 grams of ethylene glycol, 135 grams of
tetrabutylammonium bromide and 35 grams of methanol was prepared.
The solution had a density <9.0 ppg. This fluid is highly
inhibitive of hydrates.
EXAMPLE 6
[0030] As a sixth example of these formulations, a solution
comprising 180 grams of ethylene glycol, 360 grams of
tetrabutylammonium bromide and 60 grams of methanol was prepared.
The solution had a density <9.0 ppg. This fluid is highly
inhibitive of hydrates.
EXAMPLE 7
[0031] As a seventh example of these formulations, a solution
comprising 50 grams of ethylene glycol and 75 grams of
tetramethylammonium acetate. The solution had a density 8.7 ppg.
This example further illustrates the suprisingly the lower of these
solutions. This fluid is highly inhibitive of hydrates.
COMPARATIVE EXAMPLE
[0032] As a comparison, a solution comprising 200 grams of water
and 200 grams of tetrabutylammonium bromide was prepared; however,
the solution had a density of 8.7 ppg, a TCT of 50.degree. F., and
a water activity (a.sub.w) of 0.93. This fluid is not highly
inhibitive of hydrates, as evidenced by the relatively high
a.sub.w.
[0033] In addition, while specific amounts of chemicals used are
described in the above embodiments, it is specifically within the
scope of the invention that amounts different from those may be
used to provide the desired density.
[0034] For example, in one or more embodiments, a suitable well
fluid having a predetermined density may comprise 20% to 50% of
methanol and 20% to 50% of monethylene glycol of the total weight
percentage. More preferably, in one or more embodiments, a suitable
well fluid having a predetermined density may comprise 30% to 45%
of methanol and 30% to 45% of monoethylene glycol of the total
weight percentage. Still more preferably, in one or more
embodiments, a suitable well fluid may comprise 35% to 40% of
methanol and 35% to 40% of monoethylene glycol of the total weight
percentage.
[0035] Further, in one or more embodiments, a suitable well fluid
may comprise a density of 5 ppg to 9 ppg. More preferably, in one
or more embodiments, a suitable well fluid may comprise a density
of 8.2 ppg to 8.8 ppg. Still more preferably, in one or more
embodiments, a suitable well fluid may comprise 8.3 ppg to 8.5
ppg.
[0036] While the foregoing embodiments reference a limited number
of compounds, it should be recognized that chemical compounds
having the same general characteristics also would function in an
analogous fashion. For example, it is expressly within the scope of
the present invention that other compounds containing primary,
secondary, or tertiary alcohols may be used, such as, for example,
diethylene glycol, triethylene glycol, and other glycol derivatives
like diethylene glycol methylether, diethylene glycol ethylether,
triethylene gylcol methylether, and triethylene glycol ethylether,
glycerol and glycerol derivatives like glycerol formal, glycerol
1,3 diglycerolate, glyceroethoxylate, 1,6, hexandiol, and 1,2
cyclohexandiol.
[0037] In general, while the present invention has been described
with respect to packer fluids, it is expressly within the scope of
the present invention that the fluids disclosed herein may also be
used as fluids in or in connection with drilling, drill-in,
displacement, completion, hydraulic fracturing, work-over,
well-treating, testing, or abandonment.
[0038] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
* * * * *