U.S. patent application number 14/283194 was filed with the patent office on 2014-09-11 for drilling fluid that when mixed with a cement composition enhances physical properties of the cement composition.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is Abhimanyu DESHPANDE, Rahul PATIL, Krishna RAVI, Donald WHITFILL. Invention is credited to Abhimanyu DESHPANDE, Rahul PATIL, Krishna RAVI, Donald WHITFILL.
Application Number | 20140256602 14/283194 |
Document ID | / |
Family ID | 46178799 |
Filed Date | 2014-09-11 |
United States Patent
Application |
20140256602 |
Kind Code |
A1 |
RAVI; Krishna ; et
al. |
September 11, 2014 |
DRILLING FLUID THAT WHEN MIXED WITH A CEMENT COMPOSITION ENHANCES
PHYSICAL PROPERTIES OF THE CEMENT COMPOSITION
Abstract
According to an embodiment, a drilling fluid comprises: water
and a set accelerator, wherein the drilling fluid has a 10 minute
gel strength of less than 20 lb*ft/100 sq ft, wherein the drilling
fluid has a density in the range of about 9 to about 14 pounds per
gallon, wherein the drilling fluid remains pourable for at least 5
days, and wherein when at least one part of the drilling fluid
mixes with three parts of a cement composition consisting of water
and cement, the drilling fluid cement composition mixture develops
a compressive strength of at least 1,200 psi. According to another
embodiment, a method of using the drilling fluid comprises the
steps of: introducing the drilling fluid into at least a portion of
a subterranean formation, wherein at least a portion of the
drilling fluid is capable of mixing with a cement composition.
Inventors: |
RAVI; Krishna; (Houston,
TX) ; WHITFILL; Donald; (Houston, TX) ; PATIL;
Rahul; (Maharashtra, IN) ; DESHPANDE; Abhimanyu;
(Maharashtra, IN) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
RAVI; Krishna
WHITFILL; Donald
PATIL; Rahul
DESHPANDE; Abhimanyu |
Houston
Houston
Maharashtra
Maharashtra |
TX
TX |
US
US
IN
IN |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
46178799 |
Appl. No.: |
14/283194 |
Filed: |
May 20, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13150438 |
Jun 1, 2011 |
|
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14283194 |
|
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Current U.S.
Class: |
507/108 ;
507/110; 507/140 |
Current CPC
Class: |
C09K 8/467 20130101;
C09K 8/032 20130101; C09K 8/08 20130101; C09K 2208/00 20130101;
C04B 28/02 20130101; C09K 8/06 20130101; C04B 28/02 20130101; C09K
8/467 20130101; C04B 2103/0068 20130101; C04B 2103/12 20130101;
C04B 2103/22 20130101; C04B 2103/408 20130101; C04B 2103/44
20130101; C04B 28/02 20130101; C04B 12/04 20130101; C04B 14/28
20130101; C04B 14/30 20130101; C04B 14/308 20130101; C04B 14/368
20130101; C04B 24/02 20130101; C04B 24/18 20130101; C04B 24/18
20130101; C04B 24/24 20130101; C04B 24/38 20130101; C04B 24/383
20130101; C09K 8/467 20130101 |
Class at
Publication: |
507/108 ;
507/140; 507/110 |
International
Class: |
C09K 8/08 20060101
C09K008/08; C09K 8/06 20060101 C09K008/06 |
Foreign Application Data
Date |
Code |
Application Number |
May 15, 2012 |
US |
PCT/US12/37950 |
Claims
1. A drilling fluid comprising: water and a set accelerator,
wherein at least a portion of the drilling fluid is capable of
mixing with a cement composition, and wherein a test mixture of the
drilling fluid and a cement composition consisting of water and
cement, having a drilling fluid to cement composition ratio of 1:3,
develops a compressive strength of at least 1,200 psi; whereas, a
substantially identical test mixture, except that the drilling
fluid does not contain the set accelerator, develops a compressive
strength of less than 1,200 psi.
2. The drilling fluid according to claim 1, wherein the water is
selected from the group consisting of freshwater, brackish water,
saltwater, and any combination thereof.
3. The drilling fluid according to claim 1, wherein the set
accelerator is in at least a sufficient concentration such that the
test mixture develops a compressive strength of at least 1,200
psi.
4. The drilling fluid according to claim 1, wherein a test mixture
of the drilling fluid and a cement composition consisting of water
and cement, having a drilling fluid to cement composition ratio of
10:90, develops a compressive strength of at least 2,000 psi;
whereas, a substantially identical test mixture, except that the
drilling fluid does not contain the set accelerator, develops a
compressive strength of less than 2,000 psi.
5. The drilling fluid according to claim 1, wherein when at least
one part of the drilling fluid mixes with three parts of a cement
composition consisting of water and cement, the drilling fluid
cement composition mixture develops a compressive strength of at
least 1,200 psi.
6. The drilling fluid according to claim 1, wherein the set
accelerator is selected from the group consisting of sodium
metasilicate, potassium orthosilicate, sodium orthosilicate, and
combinations thereof.
7. The drilling fluid according to claim 1, wherein the drilling
fluid further comprises a viscosifier.
8. The drilling fluid according to claim 7, wherein the viscosifier
is selected from the group consisting of a xanthan gum polymer,
cellulose, derivatives thereof, and any combinations thereof.
9. The drilling fluid according to claim 7, wherein the viscosifier
is in at least a sufficient concentration such that the drilling
fluid has a 10 min gel strength of less than 20 lb*ft/100 sq
ft.
10. The drilling fluid according to claim 1, wherein the drilling
fluid further comprises a weighting agent.
11. The drilling fluid according to claim 10, wherein the weighting
agent is selected from the group consisting of barite, hematite,
manganese tetroxide, calcium carbonate, and combinations
thereof.
12. The drilling fluid according to claim 10, wherein the weighting
agent is selected such that the drilling fluid has a 10 min gel
strength of less than 20 lb*ft/100 sq ft.
13. The drilling fluid according to claim 10, wherein the weighting
agent is selected such that the drilling fluid remains in a fluid
state for a specified period of time.
14. The drilling fluid according to claim 1, wherein the drilling
fluid further comprises a set retarder.
15. The drilling fluid according to claim 14, wherein the set
retarder is selected from the group consisting of a lignosulfonate,
a lignite, a synthetic polymer, and combinations thereof.
16. The drilling fluid according to claim 14, wherein the set
retarder is in at least a sufficient concentration such that the
drilling fluid has a 10 min gel strength of less than 20 lb*ft/100
sq ft.
17. The drilling fluid according to claim 1, wherein the drilling
fluid further comprises a dispersant.
18. The drilling fluid according to claim 17, wherein the
dispersant is selected from the group consisting of
lignosulfonates, lignite, alcohol derivatives, and combinations
thereof.
19. The drilling fluid according to claim 1, wherein the drilling
fluid does not contain a clay.
20. The drilling fluid according to claim 1, wherein a mixture of
the drilling fluid and the cement composition sets.
Description
TECHNICAL FIELD
[0001] A drilling fluid that is compatible with a cement
composition is provided. A method of using the cement compatible
drilling fluid is also provided. In certain embodiments, the
drilling fluid maintains a fluid state, and when mixed with the
cement composition, enhances at least some of the physical
properties of the cement composition. According to some
embodiments, the drilling fluid does not contain a clay.
SUMMARY
[0002] According to an embodiment, a method of using a drilling
fluid comprises: introducing the drilling fluid into at least a
portion of a subterranean formation, wherein the drilling fluid
comprises: water and a set accelerator, wherein at least a portion
of the drilling fluid is capable of mixing with a cement
composition.
[0003] According to another embodiment, a method of using a
drilling fluid comprises: introducing the drilling fluid into at
least a portion of a subterranean formation, wherein the drilling
fluid comprises: water and a set accelerator, wherein the drilling
fluid has a 10 minute gel strength of less than 20 lb*ft/100 sq ft,
wherein the drilling fluid has a density in the range of about 9 to
about 14 pounds per gallon, wherein the drilling fluid remains
pourable for at least 5 days, and wherein when at least one part of
the drilling fluid mixes with three parts of a cement composition
consisting of water and cement, the drilling fluid cement
composition mixture develops a compressive strength of at least
1,200 psi.
[0004] According to another embodiment, a drilling fluid comprises:
water and a set accelerator, wherein at least a portion of the
drilling fluid is capable of mixing with a cement composition, and
wherein a test mixture of the drilling fluid and a cement
composition consisting of water and cement, having a drilling fluid
to cement composition ratio of 1:3, develops a compressive strength
of at least 1,200 psi; whereas, a substantially identical test
mixture, except that the drilling fluid does not contain the set
accelerator, develops a compressive strength of less than 1,200
psi.
BRIEF DESCRIPTION OF THE FIGURES
[0005] The features and advantages of certain embodiments will be
more readily appreciated when considered in conjunction with the
accompanying figures. The figures are not to be construed as
limiting any of the preferred embodiments.
[0006] FIG. 1 is a graph of consistency (Bc) versus time (hr:min),
showing the thickening time for a test mixture containing 1 part of
a drilling fluid to 9 parts of a cement composition.
DETAILED DESCRIPTION
[0007] As used herein, the words "comprise," "have," "include," and
all grammatical variations thereof are each intended to have an
open, non-limiting meaning that does not exclude additional
elements or steps.
[0008] As used herein, a "fluid" is a substance having a continuous
phase that can flow and conform to the outline of its container
when the substance is tested at a temperature of 71.degree. F.
(22.degree. C.) and a pressure of one atmosphere "atm" (0.1
megapascals "MPa"). A fluid can be a liquid or gas. A homogenous
fluid has only one phase; whereas a heterogeneous fluid has more
than one distinct phase. A colloid is an example of a heterogeneous
fluid. A colloid can be: a slurry, which includes a continuous
liquid phase and undissolved solid particles as the dispersed
phase; an emulsion, which includes a continuous liquid phase and at
least one dispersed phase of immiscible liquid droplets; or a foam,
which includes a continuous liquid phase and a gas as the dispersed
phase. As used herein, a "fluid state" means a substance that is a
fluid and is not a gel or a solid. As used herein, the term
"water-based" means a heterogeneous fluid in which the continuous
liquid phase is an aqueous liquid. As used herein, the term
"oil-based" means a heterogeneous fluid in which the continuous
phase is a liquid hydrocarbon.
[0009] A "gel" refers to a substance that does not easily flow and
in which shearing stresses below a certain finite value fail to
produce permanent deformation. A substance can develop gel
strength. The higher the gel strength, the more likely the
substance will become a gel. Conversely, the lower the gel
strength, the more likely the substance will remain in a fluid
state. Although there is not a specific dividing line for
determining whether a substance is a gel, generally, a substance
with a 10 minute gel strength greater than 100 lb*ft/100 sq ft
(47.88 Pa) will become a gel. Alternatively, generally, a substance
with a 10 minute gel strength less than 100 lb*ft/100 sq ft (47.88
Pa) will remain in a fluid state.
[0010] As used herein, a "cement composition" is a mixture of at
least cement and water, and possibly additives. As used herein, the
term "cement" means an initially dry substance that, in the
presence of water, acts as a binder to bind other materials
together. An example of cement is Portland cement. A cement
composition is generally a slurry in which the water is the
continuous phase of the slurry and the cement (and any other
insoluble particles) is the dispersed phase. The continuous phase
can include dissolved solids.
[0011] Oil and gas hydrocarbons are naturally occurring in some
subterranean formations. A subterranean formation containing oil or
gas is sometimes referred to as a reservoir. A reservoir may be
located under land or off shore. In order to produce oil or gas, a
wellbore is drilled into a reservoir or adjacent to a
reservoir.
[0012] A well can include, without limitation, an oil, gas, water,
or injection well. As used herein, a "well" includes at least one
wellbore. A wellbore can include vertical, inclined, and horizontal
portions, and it can be straight, curved, or branched. As used
herein, the term "wellbore" includes any cased, and any uncased,
open-hole portion of the wellbore. A near-wellbore region is the
subterranean material and rock of the subterranean formation
surrounding the wellbore. As used herein, a "well" also includes
the near-wellbore region. The near-wellbore region is generally
considered to be the region within about 100 feet of the wellbore.
As used herein, "into a well" means and includes into any portion
of the well, including into the wellbore or into the near-wellbore
region via the wellbore.
[0013] A portion of a wellbore may be an open hole or cased hole.
In an open-hole wellbore portion, a tubing string may be placed
into the wellbore. The tubing string allows fluids to be introduced
into or flowed from a remote portion of the wellbore. In a
cased-hole wellbore portion, a casing is placed into the wellbore
which can also contain a tubing string. A wellbore can contain an
annulus. Examples of an annulus include, but are not limited to:
the space between the wellbore and the outside of a tubing string
in an open-hole wellbore; the space between the wellbore and the
outside of a casing in a cased-hole wellbore; and the space between
the inside of a casing and the outside of a tubing string in a
cased-hole wellbore.
[0014] A wellbore is formed using a drill bit. A drill string can
be used to aid the drill bit in drilling through the subterranean
formation to form the wellbore. The drill string can include a
drilling pipe. During drilling operations, a drilling fluid,
sometimes referred to as a drilling mud, may be circulated
downwardly through the drilling pipe, and back up the annulus
between the wellbore and the outside of the drilling pipe. The
drilling fluid performs various functions, such as cooling the
drill bit, maintaining the desired pressure in the well, and
carrying drill cuttings upwardly through the annulus between the
wellbore and the drilling pipe.
[0015] During well completion, it is common to introduce a cement
composition into a portion of an annulus in a wellbore. For
example, in a cased-hole wellbore, a cement composition can be
placed into and allowed to set in the annulus between the wellbore
and the casing in order to stabilize and secure the casing in the
wellbore. By cementing the casing in the wellbore, fluids are
prevented from flowing into the annulus. Consequently, oil or gas
can be produced in a controlled manner by directing the flow of oil
or gas through the casing and into the wellhead. Cement
compositions can also be used in primary or secondary cementing
operations, well-plugging, or gravel packing operations.
[0016] A spacer fluid can be introduced into the wellbore after the
drilling fluid and before the cement composition. The spacer fluid
can be circulated down through a drill string or tubing string and
up through the annulus. The spacer fluid functions to remove the
drilling fluid from the wellbore.
[0017] It is desirable to remove a drilling fluid completely from a
wellbore before or during the introduction of a cement composition
into the wellbore. Some drilling fluids are more difficult to
remove from the wellbore compared to other drilling fluids. For
example, depending on the ingredients in a water-based drilling
fluid, a water-based drilling fluid can be difficult to remove from
the wellbore. A common ingredient in a drilling fluid is a clay.
Clays can include bentonite, hectorite, kaolinite, attapulgite, and
sepiolite. Some clays are hygroscopic. Hygroscopicity is the
ability of a substance to attract and hold water molecules from the
surrounding environment through either absorption or adsorption,
with the substance becoming physically changed, for example by
swelling, as water molecules become suspended between the
substance's molecules in the process. Because of the hygroscopic
nature of some clays, the clay in a drilling fluid can swell in the
presence of water and become a gel. For example, if a water-based
drilling fluid contains a hygroscopic clay, such as bentonite, then
the clay can swell in the presence of the aqueous continuous phase
and become a gel. A drilling fluid that becomes a gel is more
difficult to remove from a wellbore compared to a drilling fluid
that remains in a fluid state.
[0018] Even though a spacer fluid may be used, and regardless of
the type of drilling fluid used or the ingredients in the drilling
fluid, it is extremely difficult to remove all of the drilling
fluid from a wellbore. The remaining drilling fluid in the wellbore
is commonly referred to as a "mud-pocket". When a cement
composition is then introduced into the wellbore, the cement
composition can mix with the mud pockets and become "contaminated."
Some of the ingredients in the drilling fluid can cause adverse
effects on some of the physical properties of the contaminated
cement composition. For example, the rheology and compressive
strength of the contaminated cement composition can be adversely
affected. Moreover, it is harder for a cement composition to mix
with a gelled drilling fluid compared to a drilling fluid in a
fluid state. The cement composition may not be able to form a bond
with the gelled drilling fluid. As a result, the cement composition
may not properly set and form a bond with the substrates (e.g., a
casing or a face of a formation) that it was designed to bond to.
Consequently, there may be areas within the annulus that are not
sealed by the cement, thus allowing for the flow of fluids into or
out of those areas.
[0019] Some of the physical properties of a cement composition can
be adversely affected by, inter alia: dilution of the cement
composition with the drilling fluid; and ingredients (e.g., organic
materials) in the drilling fluid that can act as a set retarder for
the cement composition. Some of the ingredients in the drilling
fluid, such as clays, can get bound in the matrix of the cement
composition, thus decreasing the compressive strength of the
composition. There is a need for a drilling fluid that: (1) remains
in a fluid state after being introduced into the well such that, if
not completely removed, it can mix with a subsequently-introduced
cement composition; (2) includes ingredients that do not adversely
affect the physical characteristics of the cement composition, but
rather enhance the physical characteristics of the cement
composition; and (3) after mixing with a subsequently-introduced
cement composition, the mixture sets, thus allowing for a more
complete zonal isolation.
[0020] It has been discovered that a water-based drilling fluid
containing a set accelerator can: remain in a fluid state, allowing
for improved mixing with a cement composition compared to a gelled
drilling fluid; and when mixed with a cement composition can be
used to enhance at least some of the physical properties of the
cement composition. The drilling fluid/cement composition mixture
may exhibit better rheology and develop a higher compressive
strength compared to a mixture wherein the drilling fluid does not
contain a set accelerator.
[0021] During drilling operations, it is desirable for the drilling
fluid to remain pumpable during introduction into and removal from
the subterranean formation. During cementing operations, it is
desirable for the cement composition to remain pumpable during
introduction into the well and until the cement composition is
situated in the portion of the well to be cemented. After the
cement composition has reached the portion of the well to be
cemented, the cement composition can ultimately set. A drilling
fluid or cement composition that thickens too quickly while being
pumped can damage pumping equipment or block tubing or pipes. A
cement composition that sets too slowly can cost time and money
while waiting for the composition to set.
[0022] If any test (e.g., thickening time or compressive strength)
requires the step of mixing, then the substance is mixed according
to the following procedures. For the drilling fluid, the water is
added to a mixing container and the viscosifier is added to the
water and allowed to hydrate. The remaining drilling fluid
ingredients, except for the weighting agent and pH adjuster are
added to the container at a uniform rate in not more than 15
seconds (s). The motor of the base is then turned on and maintained
at 4,000 revolutions per minute (rpm) for up to several minutes to
ensure proper dispersion. The weighting agent is then added to the
container and the drilling fluid is mixed again. Finally, the pH of
the drilling fluid is determined and, if needed, a pH adjuster is
added to the drilling fluid to obtain the desired pH. It is to be
understood that any mixing is performed at ambient temperature and
pressure (about 71.degree. F. (22.degree. C.) and about 1 atm (0.1
MPa)). For the cement composition, the water is added to a mixing
container and the container is then placed on a mixer base. The
motor of the base is then turned on and maintained at 4,000
revolutions per minute (rpm). The cement and any other ingredients
are added to the container at a uniform rate in not more than 15
seconds (s). After all the cement and any other ingredients have
been added to the water in the container, a cover is then placed on
the container, and the cement composition is mixed at 12,000 rpm
(+/-500 rpm) for 35 s (+/-1 s). If the drilling fluid and the
cement composition are to be mixed together to form a "test
mixture," then a stated amount by volume of the drilling fluid is
added to a mixing container and a stated amount by volume of the
cement composition is then added to the container. The test mixture
is mixed by hand and, if needed, may be mixed at a rpm of not
greater than 4,000 rpm to ensure proper mixing. The stated amount
of drilling fluid to cement composition may be stated as a ratio.
For example, 25:75 or 10:90.
[0023] It is also to be understood that if any test (e.g.,
thickening time or compressive strength) requires the test be
performed at a specified temperature and possibly a specified
pressure, then the temperature and pressure of the substance (e.g.,
drilling fluid, cement composition, or test mixture) is ramped up
to the specified temperature and pressure after being mixed at
ambient temperature and pressure. For example, the substance can be
mixed at 71.degree. F. (22.degree. C.) and 1 atm (0.1 MPa) and then
placed into the testing apparatus and the temperature of the
substance can be ramped up to the specified temperature. As used
herein, the rate of ramping up the temperature is generally in the
range of not more than about 3.degree. F./min to about 5.degree.
F./min (about 1.67.degree. C./min to about 2.78.degree. C./min).
After the substance is ramped up to the specified temperature and
possibly pressure, the substance is maintained at that temperature
and pressure for the duration of the testing.
[0024] As used herein, the "thickening time" is how long it takes
for a substance to become unpumpable at a specified temperature and
pressure. The pumpability of a substance is related to the
consistency of the substance. The consistency of a substance is
measured in Bearden units of consistency (Bc), a dimensionless unit
with no direct conversion factor to the more common units of
viscosity. As used herein, a substance becomes "unpumpable" when
the consistency of the substance reaches 70 Bc. As used herein, the
consistency of a substance is measured as follows. The substance is
mixed. The substance is then placed in the test cell of a
High-Temperature, High-Pressure (HTHP) consistometer, such as a
FANN.RTM. Model 275 or a Chandler Model 8240. Consistency
measurements are taken continuously until the cement composition
exceeds 70 Bc.
[0025] Rheology is a unit-less measure of how a material deforms
and flows. Rheology includes the material's elasticity, plasticity,
and viscosity. As used herein, the "rheology" of a substance is
measured as follows. The substance is mixed. The substance is
placed into the test cell of a rotational viscometer, such as a
FANN.RTM. Model 35 viscometer, fitted with a Bob and Sleeve
attachment and a spring number 1. The substance is tested at the
specified temperature and ambient pressure, about 1 atm (0.1 MPa).
Rheology readings are taken at multiple rpm's, for example, at 3,
6, 30, 60, 100, 200, 300, and 600.
[0026] A substance can develop gel strength. As used herein, the
"initial gel strength" of a substance is measured as follows. After
the rheology testing of the substance is performed, the substance
is allowed to sit in the test cell for 10 seconds (s). The motor of
the viscometer is then started at 3 rpm. The maximum deflection on
the dial reading is multiplied by the spring constant and also
multiplied by a conversion constant of 0.5099 to obtain a gel
strength in units of Pascals (Pa). The gel strength in Pa can then
be multiplied by a conversion constant of 2.0885 to obtain a gel
strength in units of lb*ft/100 sq ft. As used herein, the "10 min
gel strength" is measured as follows. After the initial gel
strength test has been performed, the substance is allowed to sit
in the test cell for 10 minutes (min). The motor of the viscometer
is then started at 3 rpm. The maximum deflection on the dial
reading is then multiplied as described above to obtain a gel
strength in units of either Pa or lb*ft/100 sq ft. The lower the
value for the initial and 10 min gel strengths, the more likely the
substance will remain in a fluid state. Moreover, if the difference
between the initial and 10 min gel strengths is very low (generally
a difference of about less than 10 units), then the substance can
be called a flat gel; whereas a substance with a difference of more
than 10 units can be called a progressive gel. A flat gel indicates
that the gelation of the substance is not gaining much strength
with time; whereas, a progressive gel indicates that the gelation
of the substance is rapidly gaining strength with time.
[0027] A cement composition can develop compressive strength.
Cement composition compressive strengths can vary and can exceed
10,000 psi (69 MPa). As used herein, the "compressive strength" of
a cement composition or a test mixture is measured at ambient
temperature (about 71.degree. F., about 22.degree. C.) using the
destructive method as follows. The substance is mixed. The
substance is then cured until the substance has set. As used
herein, the term "set," and all grammatical variations thereof, is
intended to mean the process of becoming hard or solid by curing.
The set substance is then placed into a compression-testing device,
such as a Super L Universal testing machine model 602, available
from Tinius Olsen, Horsham in Pennsylvania, USA. The pressure is
gradually increased until the substance breaks. The compressive
strength is calculated as the force required to break the substance
divided by the smallest cross-sectional area in contact with the
load-bearing plates of the compression-testing device. The
compressive strength is reported in units of pressure, such as
pound-force per square inch (psi) or megapascals (MPa).
[0028] According to an embodiment, a method of using a cement
compatible drilling fluid comprises the steps of: introducing the
drilling fluid into at least a portion of a subterranean formation,
wherein the drilling fluid comprises: water and a set accelerator,
wherein at least a portion of the drilling fluid is capable of
mixing with a cement composition.
[0029] According to another embodiment, a method of using a cement
compatible drilling fluid comprises the steps of: introducing the
drilling fluid into at least a portion of a subterranean formation,
wherein the drilling fluid comprises: water and a set accelerator,
wherein the drilling fluid has a 10 minute gel strength of less
than 20 lb*ft/100 sq ft, wherein the drilling fluid has a density
in the range of about 9 to about 14 pounds per gallon, wherein the
drilling fluid remains pourable for at least 5 days, and wherein
when at least one part of the drilling fluid mixes with three parts
of a cement composition consisting of water and cement, the
drilling fluid cement composition mixture develops a compressive
strength of at least 1,200 psi.
[0030] According to another embodiment, a drilling fluid comprises:
water and a set accelerator, wherein at least a portion of the
drilling fluid is capable of mixing with a cement composition, and
wherein a test mixture of the drilling fluid and a cement
composition consisting of water and cement, having a drilling fluid
to cement composition ratio of 1:3, develops a compressive strength
of at least 1,200 psi; whereas, a substantially identical test
mixture, except that the drilling fluid does not contain the set
accelerator, develops a compressive strength of less than 1,200
psi.
[0031] The discussion of preferred embodiments regarding the
drilling fluid, the cement composition, the test mixture, or any
ingredient in the afore-mentioned, is intended to apply to the
composition embodiments and the method embodiments. Any reference
to the unit "gallons" means U.S. gallons.
[0032] According to certain embodiments, a test mixture of the
drilling fluid and a cement composition consisting of water and
cement, having a drilling fluid to cement composition ratio of 1:3,
develops a compressive strength of at least 1,200 psi (8.3 MPa),
alternatively at least 800 psi (5.5 MPa); whereas, a substantially
identical test mixture, except that the drilling fluid does not
contain the set accelerator, develops a compressive strength of
less than 1,200 psi (8.3 MPa), alternatively less than 800 psi (5.5
MPa). According to another embodiment, a test mixture of the
drilling fluid and a cement composition consisting of water and
cement, having a drilling fluid to cement composition ratio of
10:90, develops a compressive strength of at least 2,000 psi (13.8
MPa), alternatively at least 1,500 psi (10.3 MPa); whereas, a
substantially identical test mixture, except that the drilling
fluid does not contain the set accelerator, develops a compressive
strength of less than 2,000 psi (13.8 MPa), alternatively less than
1,500 psi (10.3 MPa). According to other embodiments, when at least
one part of the drilling fluid mixes with three parts of a cement
composition consisting of water and cement, the drilling fluid
cement composition mixture develops a compressive strength of at
least 1,200 psi (8.3 MPa), alternatively at least 800 psi (5.5
MPa). In another embodiment, a test mixture of the drilling fluid
and a cement composition consisting of water and cement, having a
drilling fluid to cement composition ratio of 3:1, sets; whereas, a
substantially identical test mixture, except that the drilling
fluid does not contain the set accelerator, does not set. In yet
another embodiment, a test mixture of the drilling fluid and a
cement composition consisting of water and cement, having a
drilling fluid to cement composition ratio of 3:1, develops a
compressive strength of at least 60 psi (0.4 MPa); whereas, a
substantially identical test mixture, except that the drilling
fluid does not contain the set accelerator, develops a compressive
strength of less than 60 psi (0.4 MPa).
[0033] It is to be understood that if any of the embodiments
specify a "test mixture," then the composition of the drilling
fluid comprises those ingredients listed and does not exclude
additional ingredients; however, the composition of the cement
composition consists of water and cement only and does exclude
additional ingredients.
[0034] The drilling fluid includes water. The water can be selected
from the group consisting of freshwater, brackish water, saltwater,
and any combination thereof. The drilling fluid can further include
a water-soluble salt. Preferably, the salt is selected from sodium
chloride, calcium chloride, calcium bromide, potassium chloride,
potassium bromide, magnesium chloride, and any combination
thereof.
[0035] The drilling fluid includes a set accelerator. The set
accelerator can be selected from the group consisting of sodium
metasilicate, potassium orthosilicate, sodium orthosilicate, and
combinations thereof. Commercially-available examples of a suitable
set accelerator include, but are not limited to, CALSEAL.RTM. 60,
FLO-CHECK.RTM., ECONOLITE.RTM., and combinations thereof, marketed
by Halliburton Energy Services, Inc. According to an embodiment,
the set accelerator is in a concentration of at least 3% by weight
of the water (bww). The set accelerator can also be in a
concentration in the range of about 3% to about 10% bww. According
to another embodiment, the set accelerator is in at least a
sufficient concentration such that the 1:3 test mixture develops a
compressive strength of at least 1,200 psi (8.3 MPa), while the
test mixture without the set accelerator develops a compressive
strength of less than 1,200 psi (8.3 MPa). According to yet another
embodiment, the set accelerator is in at least a sufficient
concentration such that the 10:90 test mixture develops a
compressive strength of at least 2,000 psi (13.8 MPa), while the
test mixture without the set accelerator develops a compressive
strength of less than 2,000 psi (13.8 MPa).
[0036] The drilling fluid can further include a viscosifier. The
viscosifier can be selected from the group consisting of a xanthan
gum polymer, cellulose, derivatives thereof, and any combinations
thereof. Commercially-available examples of a suitable viscosifier
include, but are not limited to, BARAZAN.RTM. D PLUS, BARAZAN.RTM.,
BARAZAN.RTM. D, WG-17.RTM., and combinations thereof, marketed by
Halliburton Energy Services, Inc. According to an embodiment, the
viscosifier is in a concentration of at least 0.2% bww. The
viscosifier can also be in a concentration in the range of about
0.2% to about 1% bww. According to another embodiment, the
viscosifier is in at least a sufficient concentration such that the
drilling fluid has a 10 min gel strength of less than 20 lb*ft/100
sq ft (9.57 Pa).
[0037] The drilling fluid can have a pH in the range of about 7.5
to about 12.5. The drilling fluid can further comprise a pH
adjuster. The pH adjuster can be an acid or a base. According to an
embodiment, the pH adjuster is selected and the pH adjuster is in a
concentration such that the drilling fluid has a pH in the range of
about 7.5 to about 12.5.
[0038] The drilling fluid can also include a weighting agent. The
weighting agent can be selected from the group consisting of
barite, hematite, manganese tetroxide, calcium carbonate, and
combinations thereof. According to an embodiment, the weighting
agent is selected such that the drilling fluid has a 10 min gel
strength of less than 20 lb*ft/100 sq ft (9.57 Pa). According to
another embodiment, the weighting agent is selected such that the
drilling fluid remains in a fluid state for a specified period of
time. The specified period of time can be in the range of about 3
days to about 14 days. The specified period of time can also be in
the range of about 7 days to about 10 days. The specified period of
time can also be the time it takes for a cement composition to be
introduced into the portion of the subterranean formation after the
step of introducing the drilling fluid. According to another
embodiment, the weighting agent is not a clay. According to yet
another embodiment, the drilling fluid does not form a filtercake
on a face of the portion of the subterranean formation.
Commercially-available examples of a suitable weighting agent
include, but are not limited to, BAROID.RTM., MICROMAX.TM.,
BARACARB.RTM., and combinations thereof, marketed by Halliburton
Energy Services, Inc. According to an embodiment, the weighting
agent is in a concentration of at least 60% bww. The weighting
agent can also be in a concentration in the range of about 60% to
about 80% bww. According to another embodiment, the weighting agent
is in at least a sufficient concentration such that the drilling
fluid has a density in the range of about 9 to about 14 pounds per
gallon "ppg" (about 1.1 to about 1.7 kilograms per liter
"kg/L").
[0039] The drilling fluid can include a set retarder. The set
retarder can be selected from the group consisting of a
lignosulfonate, a lignite, a synthetic polymer, and combinations
thereof. Commercially-available examples of a suitable set retarder
include, but are not limited to, HR.RTM.-4, HR.RTM.-5, HR.RTM.-6,
HR.RTM.-12, HR.RTM.-20, HR.RTM.-25, SCR-100.TM., SCR-500.TM., and
combinations thereof, marketed by Halliburton Energy Services, Inc.
According to an embodiment, the set retarder is in a concentration
of at least 0.05% bww. The set retarder can also be in a
concentration in the range of about 0.05% to about 0.3% bww.
According to an embodiment, the set retarder is in at least a
sufficient concentration such that the drilling fluid has a 10 min
gel strength of less than 20 lb*ft/100 sq ft (9.57 Pa). According
to another embodiment, the set retarder is in at least a sufficient
concentration such that the drilling fluid remains in a fluid state
for a specified period of time. The specified period of time can be
in the range of about 3 days to about 14 days. The specified period
of time can also be in the range of about 7 days to about 10 days.
The specified period of time can also be the time it takes for a
cement composition to be introduced into the portion of the
subterranean formation after the step of introducing the drilling
fluid.
[0040] According to an embodiment, at least a portion of the
drilling fluid is capable of mixing with a cement composition. The
methods can further include at least a portion of the drilling
fluid is capable of mixing with the cement composition for a
specified period of time. The specified period of time can be at
least 3 days. The specified period of time can also be in the range
of about 3 days to about 14 days. The specified period of time can
also be in the range of about 7 days to about 10 days. According to
another embodiment, the specified period of time is the time it
takes for a cement composition to be introduced into the portion of
the subterranean formation. According to this embodiment, the step
of introducing the cement composition into the portion of the
subterranean formation is preferably performed after the step of
introducing the drilling fluid into the portion of the subterranean
formation. According to yet another embodiment, the set retarder is
in at least a sufficient concentration such that the at least a
portion of the drilling fluid is capable of mixing with the cement
composition for the specified period of time.
[0041] The drilling fluid can also include a dispersant. The
dispersant can be selected from the group consisting of
lignosulfonates, lignite, alcohol derivatives, and combinations
thereof. Commercially-available examples of a suitable dispersant
include, but are not limited to, QUIK-THIN.RTM., THERMA-THIN.RTM.,
ENVIRO-THIN.TM., DEEP-TREAT.TM., COLDTROL.TM., and combinations
thereof, marketed by Halliburton Energy Services, Inc. According to
an embodiment, the dispersant is in a concentration of at least
0.25% bww. The dispersant can also be in a concentration in the
range of about 0.25% to about 3% bww.
[0042] The drilling fluid can also include a friction reducer.
Commercially-available examples of a suitable friction reducer
include, but are not limited to, CFR-2.TM., CFR-3.TM., CFR-5LE.TM.,
CFR-6.TM., CFR-8.TM., and combinations thereof, marketed by
Halliburton Energy Services, Inc. The friction reducer can be in a
concentration of at least 0.5% bww. The friction reducer can also
be in a concentration in the range of about 0.5% to about 5%
bww.
[0043] In an embodiment, a test mixture of the drilling fluid and a
cement composition consisting of water and cement, having a
drilling fluid to cement composition ratio of 10:90, has a
thickening time of less than 16 hours; whereas, a substantially
identical test mixture, except that the drilling fluid does not
contain the set accelerator, has a thickening time of greater than
16 hours, when tested at a temperature of 80.degree. F.
(26.7.degree. C.) and a pressure of 1 atm.
[0044] If any embodiment discloses a cement composition, then the
cement composition includes at least water and cement. The water
can be selected from the group consisting of freshwater, brackish
water, saltwater, and any combination thereof. The cement can be
Class A cement, Class C cement, Class G cement, Class H cement, fly
ash, slag, volcanic ash, and any combination thereof. Preferably,
the cement is Class G cement or Class H cement.
[0045] According to the method embodiments, the methods include the
step of introducing the drilling fluid into at least a portion of a
subterranean formation. The step of introducing can be for the
purpose of drilling a wellbore to form a well. In an embodiment, at
least a portion of a wellbore is formed by drilling the wellbore
with the drilling fluid. The drilling fluid can be in a pumpable
state before and during introduction into the subterranean
formation. The well can be an oil, gas, water, or injection well.
The well into a subterranean formation can include an annulus. The
step of introducing the drilling fluid can include introducing the
drilling fluid into a portion of the annulus.
[0046] The methods can further include the step of introducing a
spacer fluid into the at least a portion of the subterranean
formation after the step of introducing the drilling fluid. The
methods can also further include the step of introducing a cement
composition into the at least a portion of the subterranean
formation. Preferably, the step of introducing the cement
composition is performed after the step of introducing the drilling
fluid. If the methods also include the step of introducing a spacer
fluid, then preferably, the step of introducing the cement
composition is performed after the step of introducing the spacer
fluid. The step of introducing the cement composition can be for
the purpose of at least one of the following: well completion; foam
cementing; primary or secondary cementing operations;
well-plugging; gravel packing, and zonal isolation. The cement
composition can be in a pumpable state before and during
introduction into the subterranean formation. The step of
introducing can include introducing the cement composition into the
well. According to another embodiment, the subterranean formation
is penetrated by a well and the well includes an annulus. According
to this other embodiment, the step of introducing can include
introducing the cement composition into a portion of the
annulus.
[0047] If the method embodiments further include the step of
introducing a cement composition into the subterranean formation,
then the cement composition comprises water and cement. According
to these embodiments, the cement composition can further include
additives. Examples of an additive include, but are not limited to,
a filler, a fluid loss additive, a set retarder, a friction
reducer, a strength-retrogression additive, a defoaming agent, a
high-density additive, a set accelerator, a mechanical property
enhancing additive, a lost-circulation material, a
filtration-control additive, a thixotropic additive, a
nano-particle, and combinations thereof.
[0048] The cement composition can include a filler. Suitable
examples of fillers include, but are not limited to, fly ash, sand,
clays, and vitrified shale. The filler can be in a concentration in
the range of about 5% to about 50% by weight of the cement
(bwc).
[0049] The cement composition can include a fluid loss additive.
Suitable examples of commercially-available fluid loss additives
include, but are not limited to, HALAD.RTM.-344, HALAD.RTM.-413,
and HALAD.RTM.-300, marketed by Halliburton Energy Services, Inc.
The fluid loss additive can be in a concentration in the range of
about 0.05% to about 10% bwc.
[0050] The cement composition can include a set retarder. Suitable
examples of commercially-available set retarders include, but are
not limited to, HR.RTM.-4, HR.RTM.-5, HR.RTM.-6, HR.RTM.-12,
HR.RTM.-20, HR.RTM.-25, SCR-100.TM., and SCR-500.TM., marketed by
Halliburton Energy Services, Inc. The set retarder can be in a
concentration in the range of about 0.05% to about 10% bwc.
[0051] The cement composition can include a friction reducer.
Suitable examples of commercially-available friction reducers
include, but are not limited to, CFR-2.TM., CFR-3.TM., CFR-5LE.TM.,
CFR-6.TM., and CFR-8.TM., marketed by Halliburton Energy Services,
Inc. The friction reducer can be in a concentration in the range of
about 0.1% to about 10% bwc.
[0052] The cement composition can include a strength-retrogression
additive. Suitable examples of commercially-available
strength-retrogression additives include, but are not limited to,
SSA-1.TM. and SSA-2.TM., marketed by Halliburton Energy Services,
Inc. The strength-retrogression additive can be in a concentration
in the range of about 5% to about 50% bwc.
[0053] The cement composition can include a set accelerator. The
set accelerator can be selected from the group consisting of sodium
metasilicate, potassium orthosilicate, sodium orthosilicate, and
combinations thereof. Commercially-available examples of a suitable
set accelerator include, but are not limited to, CALSEAL.RTM. 60,
FLO-CHECK.RTM., ECONOLITE.RTM., and combinations thereof, marketed
by Halliburton Energy Services, Inc.
[0054] Commercially-available examples of other additives include,
but are not limited to, HIGH DENSE.RTM. No. 3 weight additive, HIGH
DENSE.RTM. No. 4 weight additive, BARITE.TM. heavyweight additive,
MICROMAX.TM. weight additive, SILICALITE.TM. additive for
light-weight cement compositions, WELLLIFE.RTM. 665 strength
additive, WELLLIFE.RTM. 809 strength additive, WELLLIFE.RTM. 810
strength additive, and CHANNEL SEAL.TM. settable spotting fluid,
marketed by Halliburton Energy Services, Inc.
[0055] According to the method embodiments, preferably, at least a
portion of any drilling fluid remaining in the subterranean
formation after the step of introducing the drilling fluid is
capable of mixing with the cement composition. According to these
embodiments, the drilling fluid and the cement composition are
capable of forming a "mixture." According to this embodiment, the
mixture can contain about 2% to about 30% by volume of the drilling
fluid.
[0056] The mixture can have a thickening time of at least 3 hours
at the bottomhole temperature and pressure. As used herein, the
term "bottomhole" refers to the portion of the subterranean
formation that the drilling fluid is introduced into. The mixture
can also have a thickening time in the range of about 3 hours to
about 20 hours at the bottomhole temperature and pressure.
According to another embodiment, the mixture has a setting time of
less than 48 hours at the bottomhole temperature and pressure. The
mixture, can have a setting time of less than 24 hours at the
bottomhole temperature and pressure. According to yet another
embodiment, the mixture has a compressive strength of at least
1,000 psi (6.9 MPa) at the bottomhole temperature and pressure. The
mixture can also have a compressive strength of at least 2,000 psi
(13.8 MPa) at the bottomhole temperature and pressure.
[0057] The method embodiments can also include the step of allowing
the mixture to set. The step of allowing the mixture to set can be
after the step of introducing the cement composition into the
subterranean formation. The method can include the additional steps
of perforating, fracturing, or performing an acidizing treatment,
after the step of allowing the mixture to set.
EXAMPLES
[0058] To facilitate a better understanding of the preferred
embodiments, the following examples of certain aspects of the
preferred embodiments are given. The following examples are not the
only examples that could be given according to the preferred
embodiments and are not intended to limit the scope of the
invention.
[0059] For the data contained in the following tables and figures,
the concentration of any ingredient in a cement composition or a
drilling fluid can be expressed as a percent by weight of the water
(abbreviated as "% bww"); pounds per barrel (abbreviated as
"lb/bbl"); or gallons per sack of cement (abbreviated as
"gal/sk").
[0060] The drilling fluid had a density of 12 pounds per gallon
(lb/gal). The cement compositions included deionized water, Class H
cement, and CFR.RTM.-3L, friction reducer at a concentration of
0.05 gal/sk and had a density of 15.6 lb/gal.
[0061] Each of the drilling fluid, the cement composition, and the
drilling fluid/cement composition mixture ("test mixture") were
mixed and tested according to the procedure for the specific test
as described in The Detailed Description section above. The ratio
of drilling fluid to cement composition for each test mixture is
listed as either 75:25, 25:75, or 10:90. Rheology testing, and
initial and 10 minute gel strength tests were conducted at a
temperature of 80.degree. F. (26.7.degree. C.). The compressive
strength tests were conducted by curing the sample for 72 hours
until set at a temperature of 80.degree. F. (26.7.degree. C.). The
thickening time test was conducted at a temperature of 80.degree.
F. (26.7.degree. C.) and a pressure of 750 psi (5.2 MPa).
[0062] Table 1 contains a list of the ingredients and their
respective concentrations for the drilling fluid. The drilling
fluid contained deionized water. BARAZAN.RTM. D PLUS is a powdered
xanthan gum polymer viscosifier that has been treated with a
dispersant. Sodium hydroxide is a pH adjuster. BAROID.RTM. is a
weighting agent comprising barite. CAL SEAL.RTM. 60 is a
hemihydrate form of calcium sulfate set accelerator and
FLO-CHECK.RTM. is a silicate system set accelerator. HR.RTM.-5 is a
chemically-modified lignosulfonate set retarder and CFR.RTM.-3L
friction reducer is a condensation reaction product of
formaldehyde, acetone and sodium bisulfite.
TABLE-US-00001 TABLE 1 Concentration Ingredient lb/bbl % bww
BARAZAN .RTM. D PLUS 1.00 0.37 NaOH 1.00 0.37 BAROID .RTM. 211.00
78.44 CAL SEAL .RTM. 60 15.00 5.58 FLO-CHECK .RTM. 5.00 1.86 Water
269.00 -- HR .RTM.-5 0.30 0.11 CFR .RTM.-3L 2.00 0.74
[0063] Table 2 contains rheology data for the drilling fluid,
several test mixtures, and the cement composition. As can be seen
in Table 2, the drilling fluid exhibited good rheologies. As can
also be seen in Table 2, the test mixtures exhibited improved
rheologies as the amount of cement composition increased. Moreover,
each of the test mixtures exhibited comparable rheologies compared
to the cement composition.
TABLE-US-00002 TABLE 2 Rheology rpm Type of Fluid 600 300 200 100
60 30 6 3 Drilling Fluid 50 32 25 18 15 11 8 7 75:25 test mixture
72 45 35 30 26 23 16 14 25:75 test mixture 77 50 37 31 27 18 17 16
10:90 test mixture 83 54 43 35 29 24 13 8 Cement Composition 56 40
31 24 21 18 12 10
[0064] Table 3 contains initial and 10 minute gel strength data for
the drilling fluid, several test mixtures, and the cement
composition; and compressive strength data for the test mixtures
and the cement composition. Table 3 also contains compressive
strength data for several "control test mixtures." The control test
mixtures did not contain a set accelerator and contained the stated
drilling fluid to cement composition ratio. As can be seen in Table
3, the drilling fluid has low gel strengths, which indicates that
it will remain in a fluid state. Moreover, because there is only a
difference of 1 unit between the initial and 10 min gel strengths,
the drilling fluid is not a progressive gel. As can also be seen in
Table 3, each of the test mixtures exhibited better gel strengths
compared to the drilling fluid and compared to the cement
composition. This indicates that if a cement composition becomes
contaminated with the drilling fluid, then the drilling fluid will
not have adverse effects on the gel strength of the mixture.
Additionally, the test mixtures having a ratio of 25:75 and 10:90
exhibited very good compressive strengths. Again, this indicates
that if a cement composition becomes contaminated with up to 33% of
the drilling fluid, then the drilling fluid will not have adverse
effects on the compressive strength of the mixture. Moreover, each
of the test mixtures exhibited a much higher compressive strength
compared to the respective control test mixture. As can also be
seen, the control test mixture having a drilling fluid to cement
composition ratio of 75:25 did not set and remained as a gelled
material. This indicates that a drilling fluid without a set
retarder, when contaminated with 3 parts of a cement composition
will not provide any zonal isolation in a formation; whereas by
adding a set accelerator to the drilling fluid, the mixture set and
developed a compressive strength of 80 psi (0.6 MPa). The addition
of a set accelerator in the drilling fluid should help in providing
zonal isolation in a formation.
TABLE-US-00003 TABLE 3 10 s Gel 10 min Gel Strength Strength
Compressive (lb * ft/100 sq (lb * ft/100 sq Strength Type of Fluid
ft) ft) (psi) Drilling Fluid 8.52 9.58 -- 75:25 test 13.84 14.91 80
mixture 75:25 control -- -- Did not set test mixture 25:75 test
14.91 21.30 1,843 mixture 25:75 control -- -- 504 test mixture
10:90 test 7.45 15.97 2,280 mixture 10:90 control 1,300 test
mixture Cement 9.58 13.84 2,350 Composition
[0065] FIG. 1 is a graph of consistency (Bc) versus time (hr:min)
showing the thickening time for a test mixture having a drilling
fluid to cement composition ratio of 10:90. The test mixture had a
thickening time of 14:02. This indicates that if a cement
composition becomes contaminated with up to approximately 10% of
the drilling fluid, then the drilling fluid will not have adverse
effects on the thickening time of the mixture.
[0066] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is, therefore, evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. While compositions and methods are
described in terms of "comprising," "containing," or "including"
various components or steps, the compositions and methods also can
"consist essentially of" or "consist of" the various components and
steps. Whenever a numerical range with a lower limit and an upper
limit is disclosed, any number and any included range falling
within the range is specifically disclosed. In particular, every
range of values (of the form, "from about a to about b," or,
equivalently, "from approximately a to b," or, equivalently, "from
approximately a to b") disclosed herein is to be understood to set
forth every number and range encompassed within the broader range
of values. Also, the terms in the claims have their plain, ordinary
meaning unless otherwise explicitly and clearly defined by the
patentee. Moreover, the indefinite articles "a" or "an", as used in
the claims, are defined herein to mean one or more than one of the
element that it introduces. If there is any conflict in the usages
of a word or term in this specification and one or more patent(s)
or other documents that may be incorporated herein by reference,
the definitions that are consistent with this specification should
be adopted.
* * * * *