U.S. patent application number 11/948930 was filed with the patent office on 2008-10-30 for surface mixing of encapsulated plug components for well remediationg.
Invention is credited to Boyce D. Burts, Boyce Donald Burts, Freddie L. Sabins, Larry Watters.
Application Number | 20080264637 11/948930 |
Document ID | / |
Family ID | 39678629 |
Filed Date | 2008-10-30 |
United States Patent
Application |
20080264637 |
Kind Code |
A1 |
Burts; Boyce D. ; et
al. |
October 30, 2008 |
Surface Mixing of Encapsulated Plug Components for Well
Remediationg
Abstract
A two part encapsulated cementing system is surface mixed and
then placed downhole in a method of remediating an active well.
This mixture is then placed downhole where it is allowed to degrade
in the well fluid allowing for the formation of a cement plug.
Inventors: |
Burts; Boyce D.; (Lafayette,
LA) ; Burts; Boyce Donald; (Lafayette, LA) ;
Sabins; Freddie L.; (Houston, TX) ; Watters;
Larry; (Spring, TX) |
Correspondence
Address: |
GILBRETH & ASSOCIATES, P.C.
PO BOX 2428
BELLAIRE
TX
77402-2428
US
|
Family ID: |
39678629 |
Appl. No.: |
11/948930 |
Filed: |
November 30, 2007 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
11162456 |
Sep 9, 2005 |
|
|
|
11948930 |
|
|
|
|
60608255 |
Sep 9, 2004 |
|
|
|
60608256 |
Sep 9, 2004 |
|
|
|
60608257 |
Sep 9, 2004 |
|
|
|
Current U.S.
Class: |
166/293 ;
166/192 |
Current CPC
Class: |
E21B 33/13 20130101;
C04B 40/0666 20130101; C04B 40/0666 20130101; C04B 40/0666
20130101; C04B 40/065 20130101; C04B 28/32 20130101; C04B 28/34
20130101; C04B 40/065 20130101; C04B 40/065 20130101; C09K 8/426
20130101; C04B 28/18 20130101; C04B 40/0666 20130101 |
Class at
Publication: |
166/293 ;
166/192 |
International
Class: |
C09K 8/46 20060101
C09K008/46 |
Claims
1. A method of remediating a well having a well fluid residing in
the well, the method comprising: (A) providing an encapsulated
component A and an encapsulated component B, wherein component A
and component B will upon contact form into a cementing plug, and
each having a density greater than the density of the well fluid,
(B) forming a mixture of encapsulated component A and encapsulated
component B; and (C) placing the mixture in the well to be
remediated.
2. The method of claim 1, wherein step (C) is carried out utilizing
one or more of a dump bailer; pumping through tubing, drillpipe,
work strings or tubulars; gravity flow; and bull heading.
3. The method of claim 1, wherein the well fluid density is in the
range of about 8.33 ppq up to about 20.0 ppg, the encapsulated
component A density is in the range of about 8.33 ppg up to about
22.0 ppg, and the encapsulated component B density is in the range
of about 8.33 up to about 22.0 ppg.
4. The method of claim 1, wherein component A is selected from the
group consisting of Na.sub.2SiO.sub.3, NaPO.sub.3, CaHPO.sub.4,
Silica, Al.sub.2(HPO.sub.4).sub.3, and, MgO, and wherein component
B is selected from the group consisting of Ca(OH).sub.2, AlOOH,
Ca(OH).sub.2+base, silica+acid, Alumina+base, NaAlO.sub.2,
MgCl.sub.2.
5. A method of plugging an abandoned well having a well fluid
residing therein, the method comprising: (A) providing an
encapsulated component A and an encapsulated component B, wherein
component A and component B will upon contact form into a cementing
plug, and each having a density greater than the density of the
well fluid; (B) forming a mixture of encapsulated component A and
encapsulated component B; and (C) placing the mixture in the
abandoned well; (E) degrading the encapsulated material to allow
the components A and B to contact and form a cementing plug.
6. The method of claim 5, wherein steps (C) are carried out
utilizing one or more of a dump bailer; pumping through tubing,
drillpipe, work strings or tubulars; gravity flow; and bull
heading.
7. The method of claim 5 wherein the well fluid density is in the
range of about 8.33 ppg up to about 20.0 ppg, the encapsulated
component A density is in the range of about 8.33 ppg up to about
22.0 ppg, and the encapsulated component B density is in the range
of about 8.33 up to about 22.0 ppg.
8. The method of claim 5, wherein component A is selected from the
group consisting of Na.sub.2SiO.sub.3, NaPO.sub.3, CaHPO.sub.4,
Silica, Al.sub.2(HPO.sub.4).sub.3, and, MgO, and wherein component
B is selected from the group consisting of Ca(OH).sub.2, AlOOH,
Ca(OH).sub.2+base, silica+acid, Alumina+base, NaAlO.sub.2,
MgCl.sub.2.
9. A remediated well comprising: a well bore of an active well; and
residing in the wellbore, an intermixed cementing system comprising
encapsulated component A and encapsulated component B, wherein
components A and B will form a cementing plug upon contact with
each other.
Description
RELATED APPLICATION DATA
[0001] This application is a continuation of U.S. patent
application Ser. No. 11/162,456, filed Sep. 9, 2005, herein
incorporated by reference, that claimed priority/benefit of U.S.
Provisional Patent Application Ser. Nos. 60/608,255, 60/608,256,
and 60/608,257, all filed Sep. 9, 2004, and all herein incorporated
by reference.
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 wells, remediated wells,
remediation of wells, to methods, apparatus and products for
remediating wells, including oil, gas, water, geothermal, or
analogous wells.
[0004] 2. Brief Description of the Related Art
[0005] The hard impermeable mass deposited in the annular space in
a well by primary cementing processes is subjected to a number of
stresses during the lifetime of the well. The pressure inside the
casing can increase or decrease as the fluid filling it changes or
as additional pressure is applied to the well, such as when the
drilling fluid is replaced by a completion fluid or by a fluid used
in a stimulation operation. A change of temperature also creates
stress in the cement, at least during the transition period before
the temperatures of the steel and the cement come into equilibrium.
It can become necessary to repair the primary cementing mass.
[0006] It is sometimes desirable in production of oil wells to
place cement through perforations in the casing of the well both
below and above the oil producing formation or zone. This cementing
is carried out to prevent water and/or gas from migrating to the
wellbore along with the oil. The intent is to leave the water and
gas in the formations adjacent to the oil producing zone so that
the water and gas will drive the oil to the wellbore, thereby
increasing recovery of oil.
[0007] Squeeze cementing is a process of forcing a cement
composition through perforations, holes or splits in a
casing/wellbore annular space of a well in order to repair a
primary cement job that failed due to the cement bypassing the mud
(channeling); to eliminate water intrusion from above, below or
within the hydrocarbon-producing zone; to reduce the producing gas
to oil ratio by isolating gas zones from adjacent oil intervals; to
repair casing leaks due to a corroded or split pipe; to plug all,
or part, of one or more zones in a multizone injection well so as
to direct the injection into the desired intervals; and to plug and
abandon a depleted or watered-out producing zone.
[0008] Due to high pressures involved, squeeze cementing can be
accompanied by problems such as propagating fractures. In addition,
the use of conventional Portland cement has several potential
problems of its own, particularly where high strength and good
adhesion to the borehole wall are needed in order to effect good
sealing. The presence of drilling mud pockets on channels under the
primary cement may not only lead to failure of the primary cement
job, but can adversely affect the strength of the squeeze cementing
job. In addition, the presence of brine in the well can adversely
affect both the primary and remedial cement jobs, increasing
setting time and causing loss of strength of the cement.
[0009] U.S. Pat. No. 5,178,519, issued Jan. 12, 1993, to Striech et
al., discloses a method and apparatus for performing a block
squeeze cementing job. The invention provides for perforating the
wellbore above and below the desired well formation on a single
wireline trip and setting a lower packer on a wireline above the
lower perforations. A stinger is positioned in the lower packer,
and secondary packer elements on an upper packer are set above the
upper perforations. Cementing of the lower perforations is carried
out through the lower packer. The secondary packer elements are
unset, and the stinger is repositioned adjacent to the upper
perforations. Primary packer elements on the upper packer are then
set, and the cementing of the upper perforations is carried out
through the upper packer and stinger. Setting of the secondary
packer elements requires only vertical movement of the tubing
string and no rotation. Both cementing steps are carried out on a
single tubing trip. The upper packer is retrievable, and the lower
packer is of a drillable type. Hydraulic slips may be provided on
the upper packer to prevent movement thereof during either
cementing operation.
[0010] U.S. Pat. No. 6,065,539, issued May 23, 2000 to Noik et al.,
discloses a method of cementing a casing in a well drilled in the
ground comprises injecting a liquid material comprising
phenol-formol resin from the surface, wherein the resin is modified
by means of a determined amount of furfuryl alcohol, and an amount
of mineral filler unreactive towards the resin is added. The
invention further relates to a thermosetting cementing material
comprising phenol-formol resin. The resin is modified by means of
an amount of furfuryl alcohol and comprises at least a proportion
of an unreactive granular filler.
[0011] U.S. Pat. No. 6,591,909, issued Jul. 15, 2003 to Dao et al.,
discloses a method and composition is provided using whey protein
as a retarder in a cementing composition for use in cementing
operations in a subterranean zone penetrated by a well bore.
[0012] U.S. Pat. No. 6,767,867, issued Jul. 27, 2004 to Chatterji
et al., discloses methods of treating subterranean zones penetrated
by well bores in primary well cementing operations, well completion
operations, production stimulation treatments and the like. The
methods are basically comprised of introducing into the
subterranean zone an aqueous well treating fluid comprised of water
and a water soluble polymer complex fluid loss control
additive.
[0013] U.S. Pat. No. 6,899,177, issued May 31, 2005 to Chatterji et
al., discloses methods of cementing subterranean zones penetrated
by well bores using cement compositions having enhanced compressive
strengths are provided. A method of the invention basically
comprises the steps of preparing or providing a cement composition
having enhanced compressive strength upon setting comprising a
hydraulic cement, sufficient water to form a slurry and a
hydroxyamine compressive strength enhancing additive. Thereafter,
the cement composition is placed in a subterranean zone to be
cemented and allowed to set into an impermeable solid mass
therein.
[0014] In spite of the advances in the prior art, conventional
cement systems suffer from a 6 hour safety margin to dump the
slurry; long set times; low shear bond values; long cement lengths,
and long wait on cement (WOC) times causing high expense.
[0015] Thus, there still exists a need in the art for improved
methods, apparatus and products for remediating wells.
SUMMARY OF THE INVENTION
[0016] According to one embodiment of the present invention, there
is provided an active well (i.e, it's not abandoned) comprising a
well bore; and residing in the wellbore, an intermixed cementing
system comprising encapsulated component A and encapsulated
component B, wherein components A and B will form a cementing plug
upon contact with each other.
[0017] According to even another embodiment of the present
invention, there is provided a method of remediating an active
well. The method includes providing a two component separately
encapsulated cementing system having encapsulated component A and
encapsulated component B, each component having a density greater
than the density of any well fluid residing in the well. The method
also includes forming a mixture of the encapsulated component A and
encapsulated component B prior to their introduction into the well.
The method even further includes placing the mixture in the
well.
[0018] According to still another embodiment of the present
invention, there is provided a method of remediating an active
well. The method includes providing a two component separately
encapsulated cementing system having encapsulated component A and
encapsulated component B, each component having a density greater
than the density of any well fluid residing in the well. The method
also includes forming a mixture of the encapsulated component A and
encapsulated component B prior to their introduction into the well.
The method even further includes placing the mixture in the well.
The method yet further includes allowing the well fluid to degrade
the encapsulant allow for direct contact of compents A and B, and
the formation of a cement plug.
DETAILED DESCRIPTION OF THE INVENTION
[0019] The method of the present invention for remediating an
active well involves the use of a two part plugging composition,
which is incorporated into known plugging methods. As used herein
"active well" refers to any well that is not an abandoned well or
one that is not undergoing abandonment. For example, a well during
the process of drilling, an operating producing well, and the
like.
[0020] The method of the present invention for remediation of an
active well involves the use of a two part plugging composition,
which is incorporated into known remediation methods.
[0021] The present invention will utilize any of the known
agglomeration and encapsulation technology to bind and coat powders
into pellets that will perform as described.
[0022] In the present invention, the two powders are pelletized
separately to withstand the trip down hole and then release to form
a settable mix with water. The encapsulated material is protected
from being wetted by well fluids and is of sufficient particle size
and density to allow falling through clear well fluids at a rate of
at least 1 foot/second. The encapsulation coating degrades with
time and/or temp to release components.
[0023] The table below outlines several pairs sets of two solid
components for use in the present invention. While the table is
shown with components A and B paired, it is also possible to create
pairs by picking one or more from A and one or more from B. Acidic
or basic conditions are required for some of the reactions. It is
possible to encapsulate NaOH adsorbed onto DE or a salt of an
organic acid as a means of providing required pH.
TABLE-US-00001 Component A Component B Na.sub.2SiO.sub.3
Ca(OH).sub.2 Na.sub.2SiO.sub.3 AlOOH NaPO.sub.3 Ca(OH).sub.2
CaHPO.sub.4 Ca(OH).sub.2 CaHPO.sub.4 Ca(OH).sub.2 + base
Na.sub.2SiO.sub.3 silica + acid Silica Ca(OH).sub.2 + base Silica
Alumina + base Al.sub.2(HPO.sub.4).sub.3 Ca(OH).sub.2 + base
Na.sub.2SiO.sub.3 NaAlO.sub.2 MgO MgCl.sub.2
[0024] Examples of suitable compositions include Component 1--50%
silica flour+-15% Ca(OH).sub.2+15% Na.sub.2SiO.sub.3+20% PVA
binder. Component 2--NaOH adsorbed onto DE 12% active.
[0025] In particular, the two part plugging composition of the
present invention comprises a component selected from an A list of
components and a component selected from a B list of components.
Each component is separately encapsulated. In absence of the
encapsulation the components will form a cementing plug.
[0026] The encapsulations on the encapsulated component are
designed to degrade upon contact with the well fluid. The timing of
the degradation can to tailored to fit the desired well operation.
A mixture of encapsulated component A and encapsulated component B,
mixed prior to placement in the well, will be placed in the well.
After sufficient time, the encapsulant will degrade allowing for
direct contact of components A and B, and the formation of a
cementing plug.
[0027] In the present invention, the cementing system not only
contains the components, 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.
[0028] While any cementing system may be utilized, it is desired
that the system exhibit one or more, preferably several if not all,
of the following characteristics: 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).
[0029] 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.
[0030] The resulting cementing system may bond to the casing and or
other formation surfaces in the well. The pipe may have coating of
oil or water based drilling mud.
[0031] The method of the present invention for remediation of
wells, includes any of the known remediation methods in which is
utilized the two component plugging composition as the cementing
material. While a generalized remediation method is described
below, it should be understood that any suitable remediation method
as is known in the art, including any described above in the
background or described in any cited reference (all of which are
herein incorporated by reference), may be utilized with the
remediation composition of the present invention.
[0032] The cementing compositions of the invention are useful in a
number of repair and remediation cementing operations including
those operations to plug lost circulation and other undesirable
fluid inflow and outflow zones in wells, to plug cracks and holes
in pipe strings cemented therein and to accomplish other required
remedial well operations. Generally, these repair and remediation
cementing processes used in a well during its productive life are
referred to as secondary cementing. In the practice of the present
invention the compositions of the present invention may be utilized
in any known secondary cementing method including any of the
remediation cementing methods disclosed in any of the references
cited herein, all of which are herein incorporated by
reference.
[0033] In general secondary cementing is carried out by placing
components of a cementing composition from a source at the ground
surface downhole to the point of repair and/or remediation. The
components of the cementing composition are then allowed to set
into a hard impermeable mass. Any method known in the art for
placing and/or positioning components of a cementing composition
downhole at the point of remediation may be used herein, all of
which are herein incorporated by reference.
[0034] Generally in the practice of the method of the present
invention, one of the components is selected as the first placed
component and placed in the well at the desired remediation
location, followed by placement of the other component as the
second placed component in the well at a position above the first
component, to allow the second component to gravity flow into the
first component.
[0035] 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. 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").
[0036] It is crucial that the first and second components have
greater densities than the well fluid density.
[0037] In some instances the selected first and second components
will not have suitable densities, specifically, the densities of
the first and second components may not be greater than that of the
well fluid, or the densities may not have a suitable enough
differential to achieve suitable displacement thru the well fluid.
Critically, encapsulated components A and B need to flow thru the
well fluid at about the same rate, otherwise they will become
stratified upon landing at the desire plugging location.
Adjustments can be made to densities and shape to provide about the
same flow property thru the well fluid.
[0038] The present invention provides for the utilization of
weighting agent additives to the first and second components to
change the density of those components. 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.
[0039] In the remediation method of the present invention first and
second components are provided which have densities greater than
the well fluid. Should the density of the first or second component
need adjustment, a weighting agent as discussed above, will be
added as necessary. The encapsulated components are mixed together
prior to introduction into the well. The mixture is then introduced
into the well fluid at a position on top of sand/petal basket.
[0040] It should also be appreciated that at some point, the
density differential between the well fluid and that of first and
second components is so low as to result in too slow of
displacement.
[0041] On the other hand, it should further be appreciated that at
some point, the density differential between the well fluid and the
first and second components is so great as to result in too rapid
displacement so as to cause problems.
[0042] Thus, the density differential should be selected so as to
provide fast enough displacement for the plugging operation, and to
facilitate sufficient in-situ mixing, and this differential can be
determined on a case by case basis, for example by observation in
clear container and trial and error.
[0043] 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
encapsulated components in the range of about 8.33 ppg up to about
22.0 ppg.
[0044] 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, polyvinyl
alcohols, resins, other adhesives), emulsifiers, ph control agents,
fluid loss additives, gas prevention additive, dispersants,
expanding agents, and wetting agents.
[0045] Although the present invention has been illustrated by
preferred reference to encapsulated components A and B, and
specific ones listed, it should be understood that any plugging
composition having two or more components can be encapsulated and
utilized in the present invention.
[0046] All materials cited herein, including but not limited to any
cited patents, publications, articles, books, journals, brochures,
are herein incorporated by reference.
[0047] 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 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.
* * * * *