Note: Descriptions are shown in the official language in which they were submitted.
CA 02871058 2014-11-14
COLD WEATHER HYDROCARBON WELL CEMENTING USING SURFACED
MIXED EPDXY
[0001]BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to wells, well operations, to
methods, apparatus and
products for operating wells. In another aspect, the present invention relates
to well cementing
operations, and to compositions, methods, apparatus and products for cementing
wells. In even
another aspect, the present invention relates to primary and secondary well
cementing operations,
and to compositions, methods, apparatus and products for cementing wells. In
still another
aspect, the present invention relates to cold weather well operations, and to
compositions,
methods, apparatus and products therefore. In yet another aspect, the present
invention relates to
cold weather compositions for well cementing operations, such as, but not
limited to sealing
casing leaks, micro-annular gas migration, water shut off, gas shut off and
zonal isolation for
wells, including oil, gas, water, geothermal, or analogous wells..
[0004] 2. Description of the Related Art
[0005] Some embodiments of the present invention relate to wells residing
in cold
weather environments. Cold weather brings it own challenges for operating
wells. In addition to
the obvious harshness of the cold on human operators around a well site and
cold on the physical
equipment, the cold also affects all of the well chemicals around the well
site. The obvious
physical effects on the chemicals would include hardening of solid chemicals,
viscosity changes
of various liquids and gels, perhaps even a state change from liquid to a gel
or a solid, perhaps
less vaporization from liquids, and perhaps less pressure on gases. However,
how this effects the
well operation is not always so clear, what needs to be done (if anything) to
correct for the
effects of cold weather are also not always so clear, and finally, if
weather/temperature corrective
CA 02871058 2014-11-14
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actions are taking, it is not clear that those corrective actions will
help/hurt the operation. In
some instances, the "cure" for the cold weather might be worse than the affect
of the cold
weather on the well operation.
[0006] In the present application, cold weather will generally mean
ambient temperatures
around the well site of less than 70 F, 60 F, 50 F, 45 F, 40 F, 35 F, 32 F, 30
F, 25 F, 20 F,
15 F, 10 F, 5 F, 0 F, -5 F, -10 F, -15 F, -20 F, or -30 F.
[0007] Cementing compositions are utilized in wells for both primary and
secondary
cementing operations.
[0008] U.S. Patent No. 7,748,455 to Burts, Jr., et al. issued July 6,2010
for surfaced
mixed epoxy method for primary cementing of a well discloses a two part epoxy
resin system is
surface mixed in a method of primary cementing a well. This surface mixed
epoxy resin is then
placed in the annulus of the well. Finally, the mixture in situ forms a hard
impermeable mass.
[0009] U.S. Patent No. 8,235,116 to Burts, Jr., et al. issued August 7,
2012 for a well
remediation using surfaced mixed epoxy discloses a two part epoxy resin system
is surface
mixed in a method of remediating an active well. This surface mixed epoxy
resin is then placed
in the well at the desired remediation depth. Finally, the mixture in situ
forms a cement plug.
[00010] In spite of the advances in the prior art, there is still a need
in the art for cold
weather well cementing compositions, methods, apparatus and products.
[00011] These and other needs in the art will become apparent to those of
skill in the art
upon review of this specification, including its drawings and claims.
[00012] SUMMARY OF THE INVENTION
[00013] It is an object of the present invention to provide for
compositions, methods,
apparatus and products relating to well cementing operations.
CA 02871058 2014-11-14
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[00014] These and other objects of the present invention will become
apparent to those of
skill in the art upon review of this specification, including its drawings and
claims.
[00015] According to one embodiment of the present invention, there is
provided a
method of cementing a well. The method may include providing an epoxy resin
component, an
activator component, wherein the activator component comprises a mercaptan.
The method may
also include surface mixing the components to form a cementing system. And,
the method may
include placing the system in the well to be cemented.
[00016] According to even another embodiment of the present invention,
there is provided
a method of cementing a well. The method may include providing an epoxy resin
component, an
activator component, and a diluent component, wherein the activatory component
comprises a
mercaptan. The method may also include surface mixing the components to form a
cementing
system, wherein the diluent is selected to allow the cementing system to have
working
flowability at the surface. And, the method may include placing the system in
the well to be
cemented.
[00017] According to still another embodiment of the present invention,
there is provided
a well fluid composition comprising a well fluid, an epoxy resin component,
and an activator
component, wherein the activator component comprises a mercaptan.
[00018] These and other embodiments of the present invention will become
apparent to
those of skill in the art upon review of this specification, including its
drawings and claims.
DETAILED DESCRIPTION OF THE INVENTION
[00019] T The methods of the present invention relate to the operation of
a well, more
specifically to various cementing operations. While the present invention may
be discussed in
terms of well cementing operations, such as, but not limited to sealing casing
leaks, micro-
annular gas migration, water shut off, gas shut off and zonal isolation, the
present invention is
not to be so limited and in fact is believed to be applicable to any primary,
secondary and/or
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other cementing operation. The present invention is also believed to have
applicability to any
type of well, including but not limited to, oil, gas, water, geothermal, or
analogous wells.
[00020] The method of the present invention for cementing a well involves
the use of a
two part cementing composition, which is incorporated into known cementing
methods. While
the present invention is illustrated mainly with respect to "active wells",
the present invention is
believed to have applicability to non-active wells also. As used herein
"active well" refers to any
well that is not an abandoned well or one that is not undergoing abandonment.
As examples, a
well during the process of drilling, a producing well, and the like.
[00021] In particular, the two part cementing composition of the present
invention
comprises a two part polymeric cementing system comprising a polymeric
component and an
activator component. The polymeric component will in the presence of an
activator component
be set up, reacted, hardened, cured, catalyzed or crosslinked into a cementing
plug. Some
embodiments of the present invention further include a diluent component as a
third component.
[00022] The polymeric component utilized in the present invention may be
any material
suitable polymeric material for forming a cementing plug that will adequately
plug the well in
the manner as desired, for the specific cementing operation as desired.
Examples of suitable
polymeric systems include those described in U.S. Patent Nos. 7,748,455 and
8,235,116 and
patents recited therein. This polymeric component may comprise a thermoplastic
or thermoset,
that is water soluble or insoluable. Preferably, this polymeric component is
an epoxy resin.
Commercially available examples of suitable epoxy resins include Epon 862 or
863-resin,
available from Momentive.
[00023] In the present invention, the polymeric system not only contains
the polymeric
material and activator, but may optionally include additives to improve
thermal stability, control
set time, generate expansion, and control fluid loss. The additives may be
incorporated into the
system directly, or into one or both of the components.
[00024] Any suitable polymeric system may be utilized, with epoxy systems
being
preferred. In selecting a suitable polymeric system, it is desired that the
system exhibit one or
more, preferably several if not all, of the following characteristics: liquid
system that is solid
CA 02871058 2014-11-14
free, no shrinkage upon set up, maintains (or causes an increase in) the
wellhole pressure;
hydrophobic; density allows it to fall thru the well fluid at a suitable rate;
and non-gas generating
(so as not to cause micro channels).
[00025] As utilized in the present invention, the activator component may
serves not only
to activate, set up, crosslink and/or cure the polymeric compound, but may
also serve to
accelerate such, so as to reduce the wait on cement (WOC) time. The activator
causes the
sealant to set under downhole temperature and pressure conditions at an
accelerated rate. Of
course, this activator component will have to be carefully selected depending
upon the material
utilized as the first component. Commercially available activators include
Epicure 3046 and
Epicure W, available from Momentive.
[00026] Some non-limiting embodiments of the present invention employ a
mercaptan
terminated polymer as part/all of the activator component. Some non-limiting
embodiments of
the present invention utilize an activator component comprising a mercaptan
terminated polymer
and a non-mercaptan activator, with the mercaptan terminated polymer
comprising in the range
of from/to or between any two of the following numbers 0.25, 0.5, 1, 2, 3, 4,
5, 6, 7, 8, 9, 10, 15,
20, 25, 30, 35, 40, 45, 50 parts by weight based on 100 parts of the polymer.
As non-limiting
examples, a range from 1 to 50 or a range between 2 and 30. It should be noted
that any desired
range can be constructed with any two listed numbers depending upon the
application desired.
[00027] Non-limiting examples of commercially available mercaptan
activators include,
Capcuret 40 SECHV Polyamine-Polymercaptan Epoxy curing agent from BASF, and
GPM-800
and GPM-800L0, both mercaptan terminated polymers, both from Gabriel
Perfomance Products.
[00028] In the present invention, accelerated set times are generally less
than 12 hours,
preferably less than 10 hours, more preferably less than 8 hours, even more
preferably less than 6
hours, still more preferably less than 4 hours, and yet more preferably less
than 2 hours.
[00029] The activator will cause the polymeric sealant to set under
downhole conditions to
cause the sealant to bond to the casing and or other formation surfaces in the
well. The pipe may
have coating of oil or water based drilling mud.
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[00030] The activator component may be selected to not only accelerate
cement set, but
may optionally be selected to also alter slurry density, clean downhole
surfaces, and/or improve
bond.
[00031] The activator will be selected for its known property for
accelerating the setup,
activation, cure, crosslinking, of the polymeric material. For the preferred
epoxy resin system,
activators for epoxies are well known, and any suitable one may be utilized.
In many instances
paired resin-activator systems are commercially available.
[00032] For some non-limiting embodiments, based on 100 parts by weight of
polymer,
the present invention anticipates utilizing 1, 5, 10, 15, 20, 25, 30, 35, 40,
45, 50, 55, 60, 65, 70,
75, 80, 85, 90, 95, 100 parts by weight of total activator component(s), or
any amount in the
range between or from/to any two of the foregoing listed numbers.
[00033] However, for some other non-limiting embodiments, based on 100
parts by
weight of polymer, the present invention anticipates utilizing greater than
40, 41, 42, 43, 44, 45,
46, 47, 48, 49, 50, 51, 52, 53, 54, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100
parts by weight of
total activator component(s). For even other non-limiting embodiments, based
on 100 parts by
weight of polymer, the present invention anticipates using greater than 40,
41, 42, 43, 44, 45, 46,
47, 48, 49, 50, 51, 52, 53, 54, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100
parts by weight of total
activator component(s). Preferably, based on 100 parts by weight of polymer,
the present
invention anticipates using greater than 45, 46, 47, 48, 49, 50, 60, 70, 80,
90 or 100 parts by
weight of activator components. More preferably, based on 100 parts by weight
of polymer, the
present invention anticipates using greater than 50, 51, 52, 53, 54, 55, 60,
70, 80, 90 or 100 parts
by weight of activator components. It should be understood that this "greater
than" refers to the
total weight of all of the activator components.
[00034] The cementing composition of the present invention may include a
third
component, a diluent. In some non-limiting embodiments, the cementing
composition will arrive
at the well site already comprising a polymeric component, an activator
component, and
optionally a diluent. The present invention contemplates adding (at the
surface) diluent to this
cementing composition (whether is already has diluent or not). In other non-
limiting
embodiment, the various polymeric component, activator component and diluent
component are
CA 02871058 2014-11-14
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all surface mixed at the well site. Non-limiting examples of suitable diluents
include functional
glycidyl esters and ethers. Non-limiting examples of suitable commercially
available diluents
include any of the "Heloxy" family of diluents (a non-limiting example of
which is Heloxy 7) or
CarDura E 1 OP high-temp diluent a glycidyl ester.
[00035] If present, the diluent will comprise in the range of from/to or
between any two of
the following numbers 0.25, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25,
30, 35, 40, 45, 50, 55, 60,
65, 70, 75, 80, 85, 90, 95 parts by weight based on 100 parts of the polymer.
An amount of
diluent may also be selected to provide for the cementing system to have
workable flowability at
the surface, meaning that at the ambient temperature at the well site surface,
the flowability of
the system allows it to be pumped in the desired well operation.
[00036] Examples of commercially available materials follows and possible
formulations
follow. Concentrations are parts by weight.
[00037] Materials: Epon 862 or 863-resin, Epicure 3046 low-temp hardener,
Epicure W
high temp hardener, Heloxy 7-primary reactive diluent, CarDura El OP-
secondary, high-temp
diluent. Formulations: (1) 100 Epon 862 or 863+ greater than 40 Epicure 3046
good 50 F to
100 F (downhole temperature); (2) 100 Epon 862 or 863+20 to 50 parts Heloxy 7+
greater than
40 parts Epicure 3046 good 70 F to 125 F (downhole temperature; (3) 100 Epon
862 or 863+20
to 50 parts Heloxy 7+ greater than 40 parts combined of Epicure 3046 and
Epicure W good 125
to 175 F (downhole temperature); (4) 100 parts Epon 862 or 863+0 to 50 parts
Heloxy 7+greater
than 40 parts Epicure W good from 175 to 250 F (downhole temperature); (5) 100
parts Epon
862 04 863+30 to 50 parts Heloxy 7+ greater than 40 parts Epicure W+0 to 20
parts CarDura
El OP good from 250 to 350 F.
[00038] The present invention also contemplates the optional use of two or
more activator
systems, generally selected to operate at various temperatures to assist in
controlling any set,
activation, curing, or crosslinking. A blend of polymeric material may also be
utilized.
[00039] The method of the present invention for cementing of wells,
includes any of the
known cementing methods in which is utilized the multi-component plugging
composition of the
present invention as the cementing material.
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[00040] The cementing compositions of the invention are useful in any type
of cementing
operation, including primary, secondary and other cementing operations.,
including, but not
limited to sealing casing leaks, micro-annular gas migration, water shut off,
gas shut off and
zonal isolation
[00041] Generally in the practice of the method of the present invention,
the various
components of the composition are mixed at the surface ("surface mixed") and
then placed
downhole at a desired location allowed to form into a plug.
[00042] Sealing casing leaks is a non-limiting example of the cementing
operation
possible with the present invention. Such an operation may include identifying
the casing leak
through diagnostic work. Once the casing leak is identified, the operation may
also include
positioning a packer below the casing. The operation may also include testing
the pump and
mixing equipment. The operation may also include surface batch mixing the
polymeric
component, activator component and any diluent component (if not pre mixed in
either/both
components). The operation may also include the addition of weighting agent:
light weight
beads, silica flour, barite, hematite, micro max, etc). The operation may also
include adding a
determined amount of low temperature additive designed through lab testing for
fluid time, and
pumping it through drill pipe, tubing, or coil tubing as a balanced plug. The
operation may also
include pulling the end of the work string above top of the plug and squeezing
the plug through
the casing leak leaving an amount of plug in the casing while allowing the
plug to solidify or
cure. Finally, the operation may include drilling the plug left in the casing
and applying a
positive or negative pressure test as desired.
[00043] Sealing micro annular gas migration in casing is another non-
limiting example of
the cementing operation possible with the present invention. For failed cement
gas migration in
casing such an operation may include identifying the gas migration through
diagnostic work, and
once leak is identified it is recommended to run in hole, and test pump and
mixing equipment.
The operation may also include surface batch mixing the polymeric component,
activator
component and any diluent component (if not pre mixed in either/both
components). The
operation may also include the addition of weighting agent: light weight
beads. silica flour,
barite, hematite, micro max, etc). The operation may also include adding a
determined amount
CA 02871058 2014-11-14
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of low temperature additive as determined through lab testing for fluid time,
and pumping it
through drill pipe, tubing, or coil tubing as a balanced plug. The operation
may also include
pulling the end of the work string above top of the plug and squeeze/ apply
positive pressure
(generally 250 psi > shut in casing pressure) to the plug while allowing the
plug to solidify or
cure. Finally, the operation may include applying a positive or negative
pressure test or bubble
test as desired.
[00044] Sealing micro annular gas migration in the casing annulus is
another non-limiting
example of the cementing operation possible with the present invention. For
failed cement in
casing annulus, this operation may include identifying the gas migration
through diagnostic
work, and once leak is identified, to run in hole with perforating assembly
and perforate the
casing above top of cement in annulus, and test pump and mixing equipment. The
operation may
also include surface batch mixing of the polymeric component(s), the activator
component(s),
and any desired diluent if not pre mixed in either of the components. The
operation may include
the addition of weighting agent: light weight beads, silica flour, barite,
hematite, micro max, etc.
The operation may also include adding an amount of low temperature additive as
determined
through lab testing for fluid time and pumping through casing annulus valve
taking returns on
casing, and once the plug is in place above failed cement in annulus, close
casing valve and
apply positive psi (generally 250 psi > shut in casing pressure) to the plug
while allowing the
plug to solidify or cure. The operation may also include applying positive or
negative pressure
test or bubble test as desired.
[00045] Zonal isolation (water, gas, etc.) is another non-limiting example
of the cementing
operation possible with the present invention. Such an operation may include
identifying the
casing leak through diagnostic work. Once the casing leak is identified, the
operation may also
include positioning a packer below the casing. The operation may also include
testing the pump
and mixing equipment. The operation may also include surface batch mixing the
polymeric
component, activator component and any diluent component (if not pre mixed in
either/both
components). The operation may also include the addition of weighting agent:
light weight
beads, silica flour, barite, hematite, micro max, etc). The operation may also
include adding a
determined amount of low temperature additive designed through lab testing for
fluid time, and
pumping it through drill pipe, tubing, or coil tubing as a balanced plug. The
operation may also
CA 02871058 2014-11-14
include pulling the end of the work string above top of the plug and squeezing
the plug through
the casing leak leaving an amount of plug in the casing while allowing the
plug to solidify or
cure. Finally, the operation may include drilling the plug left in the casing
and applying a
positive or negative pressure test as desired.
[00046] Preferably, in the practice of the present invention, the epoxy
system is heavier
than the well fluid to allow gravity flow thru the well fluid to the plug
location.
[00047] Any suitable apparatus and method for the delivery of the
components may be
utilized. As non-limiting examples, suitable delivery systems may utilize a
dump bailer, coiled
tubing and jointed tubing. They require a base to stack up against such as a
packer, petal basket
or sand plug. The compositions of the present invention may be directly
stacked up against the
packer or petal basket. While any suitable delivery mechanism can be utilized,
more specific
non-limiting examples of suitable delivery mechanisms include: dump bailer run
on electric line
or slick line; pumping through tubing, drillpipe, work strings or any
tubulars; allowing fall
through fluids via gravity; and pumping into an annullas or pipe without
displacing (i.e., "bull
heading").
[00048] In some instances epoxy system will not have suitable density,
specifically, the
density may not be greater than that of the well fluid.
[00049] Some non-limiting embodiments of the present invention provide for
the
utilization of weighting agent additives to the first component or the second
component, or to the
resultant combined system, to change the density of the mixed system. Suitable
additives to
change the density include metal salts, preferably calcium chloride. Other
examples of
weighting agents include sand, barite, hemitite, calcium carbonate, FeO. MgO,
and manganese
ore. Sufficient amounts of the additive are utilized to achieve the desired
density. Other non-
limiting embodiments of the present invention provide for no weighting agents
in the cementing
composition, that is, they are "neat" (without weighting agents).
[00050] In some well operations of the present invention, the desired
cement components
are surface mixed. The mixed components are then introduced into the well
fluid at a position
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above, or directly on top of (i.e. touching) the sand/petal basket to allow
for in-situ formation of
the cement plug to plug the well.
[00051] It should be appreciated that at some point, the density
differential between the
polymeric system and the well fluid is so low as to result in too slow of
displacement.
[00052] On the other hand, it should further be appreciated that at some
point, the density
differential between the system and the well fluid is so great as to result in
problems.
[00053] Thus, the density differential should be selected so as to provide
suitable gravity
feed of the system thru the well fluid to the desired location.
[00054] Typical densities for the well fluid will be in the range of about
8.33 ppg up to
about 20.0 ppg, with typical densities for the activator in the range of about
8.33 ppg up to about
21.0 ppg, and with typical densities for the sealant system in the range of
about 8.54 up to about
22.0 ppg.
[00055] It should be understood that other well fluid additives as are
well known in the art
may be incorporated into the first and/or second component, or added before,
along with, or after
the introduction of the first and/or second component, non-limiting examples
of which include
surfactants, surface bond enhancers (non-limiting examples include styrene
butadiene latex,
polyvinal alcohols, resins, other adhesives), emulsifiers, ph control agents,
fluid loss additives,
gas prevention additive, dispersants, expanding agents, and wetting agents.
[00056] Although the present invention has been illustrated by preferred
reference to
epoxy systems, it should be understood that any remediation composition having
two or more
components can be utilized in the present invention.
[00057] U.S. Patent Nos. 7,748,455 and 8,235,116, and any patents,
publications, articles,
books, journals, brochures, cited therein, are herein incorporated by
reference.
[00058] While the illustrative embodiments of the invention have been
described with
particularity, it will be understood that various other modifications will be
apparent to and can be
readily made by those skilled in the art without departing from the spirit and
scope of the
CA 02871058 2014-11-14
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invention. Accordingly, it is not intended that the scope of the claims
appended hereto be limited
to the examples and descriptions set forth herein but rather that the claims
be construed as
encompassing all the features of patentable novelty which reside in the
present invention,
including all features which would be treated as equivalents thereof by those
skilled in the art to
which this invention pertains.
