U.S. patent application number 11/531579 was filed with the patent office on 2008-03-13 for method to control the physical interface between two or more fluids.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Melissa G. Allin, Robert Bates, Daniel Bour, Christopher L. Gordon, Renee Manuel, Ronnie G. Morgan, Mark R. Savery.
Application Number | 20080060811 11/531579 |
Document ID | / |
Family ID | 38740217 |
Filed Date | 2008-03-13 |
United States Patent
Application |
20080060811 |
Kind Code |
A1 |
Bour; Daniel ; et
al. |
March 13, 2008 |
METHOD TO CONTROL THE PHYSICAL INTERFACE BETWEEN TWO OR MORE
FLUIDS
Abstract
A method of controlling the physical interface between two
wellbore servicing fluids during the displacement of one wellbore
servicing fluid by another, the method comprising selecting a
liquid plug having a viscosity greater than the viscosity of the
two wellbore servicing fluids, introducing a first wellbore
servicing fluid into the wellbore, introducing a volume of the
liquid plug into the wellbore, and introducing a second wellbore
servicing fluid into the wellbore, wherein the liquid plug is
selected such that the mixing between the two wellbore servicing
fluids is minimized.
Inventors: |
Bour; Daniel; (Mandeville,
LA) ; Morgan; Ronnie G.; (Waurika, OK) ;
Gordon; Christopher L.; (Duncan, OK) ; Allin; Melissa
G.; (Comanche, OK) ; Savery; Mark R.; (Duncan,
OK) ; Manuel; Renee; (Lafayette, LA) ; Bates;
Robert; (Houma, LA) |
Correspondence
Address: |
CRAIG W. RODDY;HALLIBURTON ENERGY SERVICES
P.O. BOX 1431
DUNCAN
OK
73536-0440
US
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
38740217 |
Appl. No.: |
11/531579 |
Filed: |
September 13, 2006 |
Current U.S.
Class: |
166/291 ;
166/294; 166/295 |
Current CPC
Class: |
C04B 26/04 20130101;
E21B 33/16 20130101; C04B 28/105 20130101; C09K 8/424 20130101;
C09K 8/426 20130101; C09K 8/40 20130101; Y02W 30/91 20150501; C04B
2201/10 20130101; Y02W 30/92 20150501; C04B 28/105 20130101; C04B
14/10 20130101; C04B 20/04 20130101; C04B 26/04 20130101; C04B
14/047 20130101; C04B 14/10 20130101; C04B 14/365 20130101; C04B
14/368 20130101; C04B 18/08 20130101 |
Class at
Publication: |
166/291 ;
166/294; 166/295 |
International
Class: |
E21B 33/16 20060101
E21B033/16 |
Claims
1. A method of controlling the physical interface between two
wellbore servicing fluids during the displacement of one wellbore
servicing fluid by another, the method comprising: (a) selecting a
liquid plug having a viscosity greater than the viscosity of the
two wellbore servicing fluids; (b) introducing a first wellbore
servicing fluid into the wellbore; (c) introducing a volume of the
liquid plug into the wellbore; and (d) introducing a second
wellbore servicing fluid into the wellbore; wherein the liquid plug
is selected such that the mixing between the two wellbore servicing
fluids is minimized.
2. The method of claim 1 wherein the liquid plug is capable of
being pumped as a plug of viscous material throughout the
displacement.
3. The method of claim 1 wherein the liquid plug is a thermally
activated gellable material that is capable of being pumped in a
plug flow condition in a deviated well.
4. The method of claim 1 wherein the liquid plug has a diffusion
coefficient of from about 1.times.10.sup.-8 cm.sup.2/sec to about
1.times.10.sup.-9 cm.sup.2/sec as determined by Fick's law of
diffusion.
5. The method of claim 1 wherein the liquid plug comprises a
thermally activated cement and an organophilic product.
6. The method of claim 5 wherein the thermally activated cement
comprises magnesium oxide and the organophilic product comprises
alkyl quaternary ammonium montmorillonite.
7. The method of claim 1 wherein the liquid plug is selected from
the group consisting of non-linear elastic solids, viscoelastics,
non-linear viscous fluids or combinations thereof.
8. The method of claim 1 wherein the liquid plug has a shear
viscosity of from about 100 cp to about 2,000,000 cp.
9. The method of claim 1 wherein the liquid plug has a yield stress
of from about 40 Pascals to about 40,000 Pascals.
10. The method of claim 1 wherein the liquid plug has an elasticity
of from about 0.005 psi to about 10,000 psi.
11. The method of claim 1 wherein the liquid plug has a plasticity
of from about 0.005 psi to about 10,000 psi.
12. The method of claim 1 wherein the liquid plug has a shear
stress history response of from about 1000 to about 10 million.
13. The method of claim 1 wherein the liquid plug is used as a
surface pressure indicator.
14. The method of claim 1 wherein the liquid plug comprises a
crosslinkable polymer system and a filler, wherein the
crosslinkable polymer system comprises a water soluble copolymer of
a non-acidic ethylenically unsaturated polar monomer and a
copolymerizable ethylenically unsaturated ester; a water soluble
terpolymer or tetrapolymer of an ethylenically unsaturated polar
monomer, an ethylenically unsaturated ester, and a monomer selected
from acrylamide-2-methylpropane sulfonic acid, N-vinylpyrrolidone,
or both; or combinations thereof; and a crosslinking agent
comprising a polyalkyleneimine, a polyfunctional aliphatic amine,
an aralkylamine, a heteroaralkylamine, or combinations thereof.
15. The method of claim 1 wherein selecting the liquid plug
comprises trial and error, computational modeling, or a combination
thereof.
16. The method of claim 15, wherein the computational modeling
comprises inputting the fluid properties of the two well servicing
fluids, including density, rheology, chemical composition, and
diffusion coefficients; wellbore geometry, including deviation,
casing geometry and placement, pumping schedule including rates and
volumes; and pressure, temperature, fluid compressibility,
formation properties; and calculating the degree of intermixing of
the two well servicing fluids.
17. The method of claim 14 wherein the crosslinkable polymer system
comprises a copolymer of acrylamide and t-butyl acrylate and the
crosslinking agent comprises polyethylene imine.
18. The method of claim 1 wherein the liquid plug comprises a
crosslinkable polymer system that is thermally activated.
19. The method of claim 18 wherein the thermal activation occurs
from about 180.degree. F. to about 320.degree. F.
20. The method of claim 14 wherein the filler comprises alkyl
quaternary ammonium montmorillonite, bentonite, zeolites, barite,
fly ash, calcium sulfate, or combinations thereof.
21. The method of claim 14 wherein the filler comprises a
hydratable polymer, an organophilic clay, a water-swellable clay,
or combinations thereof.
22. The method of claim 14 wherein the filler comprises alkyl
quaternary ammonium montmorillonite.
23. The method of claim 1 wherein the liquid plug comprises a
packing agent.
24. The method of claim 23 wherein the packing agent is a resin
coated particulate.
25. A method of placing a settable spacer in a wellbore in a
subterranean formation comprising: (a) selecting a liquid plug
composition comprising a thermally activated cement and an
organophilic product and having a viscosity, wherein the viscosity
of the liquid plug is chosen such that intermixing of the liquid
plug with the wellbore servicing fluids ahead of and behind it is
minimized; (b) pumping a volume of the liquid plug into the
wellbore; (c) stopping circulation of the wellbore fluids when a
surface pressure spike is indicated; and (d) allowing the cement to
set.
26. A method of separating servicing fluids during a wellbore
service operation comprising: placing a liquid plug between the
interface of two dissimilar wellbore servicing fluids, wherein the
liquid plug is rheologically designed to minimize the mixing
between the interfaces of the liquid plug and the wellbore
servicing fluids.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] This disclosure relates to a method for preventing the
intermixing of wellbore servicing fluids in a wellbore through the
use of a liquid plug.
[0005] 2. Background of the Invention
[0006] A natural resource such as oil or gas residing in a
subterranean formation can be recovered by drilling a well into the
formation. The subterranean formation is usually isolated from
other formations using a technique known as well cementing. In
particular, a wellbore is typically drilled down to the
subterranean formation while circulating a drilling fluid through
the wellbore. After the drilling is terminated, a string of pipe,
e.g., casing, is run in the wellbore. Primary cementing is then
usually performed whereby a cement slurry is pumped down through
the string of pipe and into the annulus between the string of pipe
and the walls of the wellbore to allow the cement slurry to set
into an impermeable cement column and thereby seal the annulus.
Subsequent secondary cementing operations, i.e., any cementing
operation after the primary cementing operation, may also be
performed. Examples of secondary cementing operations include
squeeze cementing whereby a cement slurry is forced under pressure
to areas of lost integrity in the annulus to seal off those areas,
and the setting of temporary or permanent cement plugs in order to
seal off a desired region of the wellbore.
[0007] A challenge encountered during drilling, completion, and
other servicing operations is the separation of the various
wellbore servicing fluids as they are pumped into the wellbore. In
many instances, it is highly desirable to minimize the intermixing
of these fluids at the interface. Intermingling of the fluids at
the interface may inhibit the ability of a fluid to perform its
intended purpose, for example, intermixing of displacement fluid
with a cement slurry may lead to contamination of the cement. This
contamination may cause an undesirable delay in or a failure of the
setting of the cement, which can mean a significant increase in
cost due to increased wait time or remedial repair of unset cement.
Furthermore, the contamination may negatively affect the strength
of the set cement, particularly around the shoe, where it may be
desirable to have the greatest strength. In some cases, this
weakening of the cement may cause a failure of the shoe test, again
mandating repair. Contamination of cement may also cause
undesirable acceleration of the setting of the cement. For example,
a salt brine may be used as a displacement fluid which may
accelerate the setting of the cement.
[0008] Separation of fluids at the interface is conventionally
performed by introducing mechanical separators or volumes of liquid
spacers between the fluids to be separated. In cementing
operations, for example, flexible and rigid mechanical plugs, e.g.
wiper plugs, are used to act as a barrier between the cement and
the displacement fluid to prevent fluid intermixing at the
interface as well as to wipe fluid such as drilling mud or cement
off the interior wall of the casing to prevent leftover cement
strings and to provide a means for detecting when the cement has
been completely displaced from within the casing. Usually this
detection occurs via a surge in surface pressure when the
mechanical plug lands at the bottom of the casing.
[0009] Despite the prevalent use of mechanical plugs, these plugs
can fail, or are incompatible with a given application. Plugs with
flexible wipers can deteriorate and disintegrate under normal
operating conditions and damaged plugs may not adequately prevent
the intermingling of wellbore fluids and cements. There are other
drawbacks associated with the use of these mechanical plugs. For
example, in liner applications a drill pipe wiper dart that latches
into a mechanical plug at the top of the liner is required to
insure fluid separation through multiple pipe sizes. In addition
these plugs may take time to drill out to continue operations and,
many sizes of plugs of various types may be needed over the course
of a drilling operation.
[0010] As mentioned previously, a liquid spacer may be used to
separate wellbore servicing fluids. Conventionally, while these
spacers/liquid flushes may separate incompatible fluids from the
cement, an undesirable amount of contamination still occurs.
Accordingly, an ongoing need exists for a method of minimizing the
intermixing of wellbore servicing fluids during normal operations,
particularly a method of minimizing the intermingling at the
interface of cement with a displacement fluid.
BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS
[0011] Disclosed herein is a method of controlling the physical
interface between two wellbore servicing fluids during the
displacement of one wellbore servicing fluid by another, the method
comprising selecting a liquid plug having a viscosity greater than
the viscosity of the two wellbore servicing fluids, introducing a
first wellbore servicing fluid into the wellbore, introducing a
volume of the liquid plug into the wellbore, and introducing a
second wellbore servicing fluid into the wellbore, wherein the
liquid plug is selected such that the mixing between the two
wellbore servicing fluids is minimized, for example less than about
50%.
[0012] Also disclosed herein is a method of placing a settable
spacer in a wellbore in a subterranean formation comprising
selecting a liquid plug composition comprising a thermally
activated cement and an organophilic product and having a
viscosity, wherein the viscosity of the liquid plug is chosen such
that intermixing of the liquid plug with the wellbore servicing
fluids ahead of and behind it is minimized, pumping a volume of the
liquid plug into the wellbore, stopping circulation of the wellbore
fluids when a surface pressure spike is indicated, and allowing the
cement to set.
[0013] Further disclosed herein is a method of separating servicing
fluids during a wellbore service operation comprising placing a
liquid plug between the interface of two dissimilar wellbore
servicing fluids, wherein the liquid plug is rheologically designed
to minimize the mixing between the interfaces of the liquid plug
and the wellbore servicing fluids.
[0014] The foregoing has outlined rather broadly the features and
technical advantages of the present invention in order that the
detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention
will be described hereinafter that form the subject of the claims
of the invention. It should be appreciated by those skilled in the
art that the conception and the specific embodiments disclosed may
be readily utilized as a basis for modifying or designing other
structures for carrying out the same purposes of the present
invention. It should also be realized by those skilled in the art
that such equivalent constructions do not depart from the spirit
and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For a detailed description of the preferred embodiments of
the invention, reference will now be made to the accompanying
drawings in which:
[0016] FIG. 1 is a flowchart of a fluid displacement simulation,
including an example of a graphical output from same.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0017] Disclosed herein are compositions and methods to control the
physical interface between two or more fluids, more specifically
between two or more servicing fluids in a wellbore. In an
embodiment, the method comprises placing a Liquid Plug (LP) between
the two or more fluids. The use of a liquid plug, hereinafter LP,
may minimize the intermixing of the LP and the fluids being
separated by the LP, resulting in the separation of the two fluids
while also minimizing the contamination of the separated fluids. In
various embodiments, the LP may be a highly viscous material and
may have various fluid properties as described herein. In some
embodiments, the LP is more viscous that the two fluids that are
separated by the LP. LPs such as those disclosed herein may be used
to separate any two fluids, and in particular any two wellbore
servicing fluids. LPs may serve additional functions as described
in more detail herein. Accordingly, LPs as described herein may be
used to separate non-cementitious fluids during wellbore servicing,
separate cement from displacement fluid during displacement of a
cement job, enhance mud displacement during cementing, provide a
plug for reverse circulation cementing operations, be used as a
lost circulation material and/or carrier of lost circulation
material during drilling operations (i.e. pump slugs of various
volumes of LP while drilling thorough lost circulation
zones),provide a base for plug cementing, act as a fluid caliper,
enhance formation integrity following squeeze cementing operations,
and perform settable functions, such as those required during
leak-off tests, the formation/placement of kick-off plugs, and plug
and abandonment operations. In an embodiment, the LP is used to
service a wellbore experiencing lost circulation. The viscosified
LP would naturally tend to flow into the lost circulation zone. In
such an embodiment, particulate bridging lost circulation material
may be included in the LP and delivered directly to the lost
circulation zone. Additionally, a LP may deform during use to
provide separation for any number of pipe geometries thereby
reducing the risk and mechanical problems associated with the
multiple plug systems described previously.
[0018] In various embodiments, the LP is a composition capable of
separating the interface of two fluids with minimal intermixing, as
described herein, while in their intended service. For example, the
LP may be a composition that is capable of separating the interface
of two wellbore servicing fluids with minimal intermixing while
being pumped into a wellbore. Such LP compositions may be
characterized, identified, and selected based upon various fluid
parameters such as density, rheology, chemical composition, and
diffusion/mixing coefficients. Rheological dimensions include shear
viscosity, shear rate index, yield stress, elasticity, plasticity,
and shear stress history as discussed in more detail below.
[0019] A LP may be characterized by its density. The density may be
measured by a pressurized fluid density balance according to the
American Petroleum Institute (API) method found in API Recommended
Practice 10B, Section 6. The density of a material suitable for use
as an LP may be in the range of from about 0.5 g/cc to about 4.0
g/cc, alternatively from about 0.8 g/cc to about 3 g/cc,
alternatively from about 1.0 g/cc to about 2.5 g/cc.
[0020] Viscosity is a measure of the resistance of a fluid to
deform under shear stress. It is a measure of the resistance of a
material to flow. A material with a high flow resistance displays a
high viscosity. For Newtonian fluids, the shear viscosity, usually
represented by .mu., is independent of the shear rate. For
non-Newtonian fluids, the non-Newtonian viscosity, .eta., is
dependent on the shear rate. In an embodiment, a LP has a viscosity
of from about 100 cp to about 2,000,000 cp, alternatively from
about 500 to about 1,000,000 cp, alternatively from about 1200 cp
to about 500,000 cp.
[0021] The shear rate is the rate of shear deformation (i.e. the
rate at which adjacent layers of fluid move with respect to each
other). In an embodiment, a LP has a shear rate index of from about
0.1 s.sup.-1 to about 1000 s.sup.-1, alternatively from about 0.5
s.sup.-1 to about 200 s.sup.-1, alternatively from about 1 s.sup.-1
to about 100 s.sup.-1.
[0022] Shear stress is the force that is required on a specific
area to make a material flow at a specific shear rate. It is a
stress above which the shape of a material changes without a
particular volume change. A greater shear stress indicates that a
larger force is required to make a material flow. The yield stress
is the minimum shear stress required to make a material to
plastically deform. High yield stress indicates that larger forces
must be applied to the same sample area to deform the sample. The
yield stress may be measured by a Brookfield YR-1 Yield Stress
Rheometer. In an embodiment, a LP has a yield stress of from 40
Pascals to 40,000 Pascals, alternatively from 70 Pascals to 15,000
Pascals, alternatively from 100 Pascals to 12,000 Pascals.
[0023] A material is termed elastic if it deforms under stress, but
returns to its original shape upon removal of the stress. The
amount of deformation is termed the strain. For small stresses, the
strain for many solids is proportional to the stress, having a
constant of proportionality, termed the elasticity. The elasticity
is a measure of the stiffness of the material, and is stated as the
inverse of Young's modulus of elasticity. Linear elasticity, as
described by Hooke's law, is an approximation, with real materials
displaying some degree of non-linear behavior. Beyond the elastic
limit or yield strength of an elastic material, the relationship
between stress and strain breaks down and the material may
irreversibly deform, exhibiting plasticity. This can be observed
using stress/strain curves. In an embodiment, a LP has an
elasticity of from about 0.005 psi to about 10,000 psi,
alternatively from about 50 psi to about 10,000 psi, alternatively
from about 500 psi to about 10,000 psi. In an embodiment, a LP has
an elasticity of from about 0.005 psi to about 500 psi,
alternatively from about 50 psi to about 500 psi alternatively from
about 0.005 psi to about 50 psi.
[0024] As mentioned above, plasticity is a measure of a material's
ability to undergo an irreversible deformation (to yield) in
response to an applied shear stress. In an embodiment, a LP has a
plasticity of from about 0.005 psi to about 10,000 psi,
alternatively from about 50 psi to about 10,000 psi, alternatively
from about 100 psi to about 10,000 psi, alternatively from about 50
psi to 100 psi, alternatively from about 0.005 psi to 50 psi.
[0025] The properties of a material may be dependent on its shear
stress history, including the magnitudes and duration of the
exposure of the material to shear stresses. The shear stress
history may be measured by integrating the volume average shear
rate (VASR) versus time history, in which the VASR is measured in
units of /1 sec, while the time is in seconds. This method is
described in an article by Walters et. al. entitled "Kinetic
Rheology of Hydraulic Fracturing Fluids" presented at the 2001
Society of Petroleum Engineers Annual Technical Conference,
presentation SPE 71660, and incorporated by reference in its
entirety. In an embodiment, a LP may have a shear stress history
response ranging from about 1000 to about 10 million, alternatively
from about 5,000 to about 500,000.
[0026] The chemical composition of the LP may vary provided that
the composition has an operable combination of the various fluid
properties described herein. In various embodiments, the LP may
have a chemical composition characterized by a cross-linked polymer
system, a latex based solution, any mineral-based solid suspension
such as bentonite clay in water, an emulsion, a naturally produced
material such as tree sap, or any fluid containing a material or a
combination of materials that provides the beneficial rheological
properties described herein. In an embodiment, the LP may comprise
a crosslinkable polymer system as described in more detail
herein.
[0027] In an embodiment, a LP has structural integrity that
prevents degradation of the rheological properties of the LP as it
is pumped downhole.
[0028] Suitable LPs include compositions or materials having the
fluid properties set forth above, which may include compositions or
materials chosen from three rheological families that will be
described in more detail herein below. In an embodiment, the LP is
a non-linear elastic solid, a viscoelastic, a non-linear viscous
fluid, or combinations thereof. Materials in these families exhibit
a shear dependence of the viscosity. More specifically, rheology is
the science of deformation and flow of matter. The specific
relationship between a stress applied to a material and the
resultant deformation of the material is a unique function of the
material that defines the rheological properties of the material.
These can be expressed with a rheological equation of state, which
is an analytical relationship between the complete stress and the
strain or strain rate tensors.
[0029] Non-Linear elastic solids are defined by the equation:
.tau.=G(.gamma.).gamma.
where .tau. is the shear stress, G is the shear modulus of the
material, and .gamma. is the shear strain, or shear deformation.
Unlike linear elastic (Hookean) solids, the shear modulus for
non-linear elastic solids is not a constant, but rather a function
of the shear deformation, .gamma.. A LP may be a material having
the simple shear deformation of a non-linear elastic solid. An
example of a suitable non-linear elastic solids include for example
and without limitation silicon.
[0030] Viscoelastic materials are, as the name indicates, materials
having both viscous and elastic properties. Viscoelastic materials
are non-Newtonian materials that may exhibit elasticity in certain
conditions. A material is said to be elastic if it deforms under
stress (for example, external forces), yet returns to its original
shape when the stress is removed. The amount of deformation is
called the strain. In response to small, rapidly-applied and then
removed strain, viscoelastic fluids may deform and then return to
their original shape, exhibiting elasticity. However, under larger
strains, or when the strains are applied for longer times, these
fluids may begin to flow, exhibiting viscous behavior. A
viscoelastic material has infinite material responses depending on
the strain-rate. Most polymers exhibit viscoelastic behavior,
behaving more like solids at low temperatures and rapid deformation
speeds. At high temperatures and slow deformation speeds, polymers
are more liquid in behavior. Examples of suitable viscoelastic
materials include some polymers and muddy soil.
[0031] The rheological equation of state for viscoelastic materials
can be expressed as:
.tau.=f(.gamma.,.gamma.',t . . . )
where .gamma. is the shear strain (shear deformation), .gamma.' is
the rate of strain (the shear rate), t is the time of subjection to
strain. A LP may be a material having the simple shear deformation
of a viscoelastic material.
[0032] Non-Linear viscous fluids are Non-Newtonian fluids having
the rheological equation of state:
.tau.=.eta.(.gamma.').gamma.'
where .eta. is the non-Newtonian viscosity, and .gamma.' is the
rate of strain (the shear rate). For non-linear viscous fluids, the
viscosity depends on the shear rate. Pseudo-plastic fluids or
"shear-thinning" fluids display an apparent viscosity decrease with
the rate of shear, while shear-thickening fluids display an
increase in apparent viscosity with rate of shear. A LP may be a
material having the simple shear deformation of a non-linear
viscous fluid. Examples of suitable non-linear viscous fluids
include guar gum polymer solutions (about 0.5% w/v) crosslinked
with borate, also common jello.
[0033] The fluid properties of a suitable LP may be optimized in
various ways, including, but not limited to, trial and error and
computational simulation. A LP can be chosen and tested for use as
a liquid plug in a laboratory or in the field, and its ability to
prevent intermixing at the fluid interfaces can be determined
experimentally. Using trial and error, a suitable LP may be chosen
for the specific fluids the LP is being used to separate and the
specific wellbore conditions.
[0034] Alternatively, a LP having suitable rheological properties
may be chosen through computer modeling and simulation of the well
behavior during use of a LP. Referring to FIG. 1, a fluid
displacement simulator 20 is shown having an input 10 and an output
30. The input 10 may include a variety of pre, post, or real-time
job parameters such wellbore geometry, including the deviation,
based upon experience and wellbore data such as caliper or other
logging data; the casing geometry and placement schedule; the
pumping schedule, including rates and volumes; the formation
properties such as pressure, temperature, compressibility of the
fluid to be recovered, and rock properties; and properties of the
fluids to be separated and the properties of the proposed LP. Fluid
properties include density, rheological dimensions, chemical
composition, and diffusion/mixing coefficients as described
herein.
[0035] Such input 10 may be used by fluid displacement simulator 20
to simulate the amount of mixing at an interface of the LP and
another fluid, e.g., a wellbore servicing fluid such as cement. The
fluid displacement simulator 20 may use analytical and/or empirical
algorithms to mathematically describe multiple aspects of fluid
displacement phenomena and fluid interaction, and thereby calculate
the degree of intermixing of the fluids at the interfaces. The
fluid displacement simulator may take into account fluid-fluid
intermixing interfaces including density variations across the
interface, viscosity variations across the interface, geometry
(e.g. length, width, height) of the interface, and time-dependent
changes occurring across the interface; casing rotating velocity
and axial velocity; mimicking true Newtonian and non-Newtonian
rheology; wellbore geometry and deviation; casing geometry and
placement; buoyancy effects, pressure effects, temperature effects,
fluid compressibility effects, rock effects; and combinations
thereof.
[0036] The output 30 from the fluid displacement simulator 20
described the degree of intermixing and the extent of fluid
displacement in text, graphical, or movie form. An example of a
graphical output is shown by output 40 showing the interface
variations 55 for density 45 and viscosity 50 of an axial slice of
an annular region of two fluids (e.g., a displaced fluid and a
displacing fluid) in a wellbore. Solid patterns at the top and
bottom of the display represent 100% displaced fluid 60 and 100%
displacing fluid 65, respectively, while non-uniformity in pattern
represents intermixing at the interface. Such graphical
representations, as well as other output such as numeric or percent
calculations, may be used to distinguish acceptable and
unacceptable amounts of intermixing. Thus, by using such software
as fluid displacement simulator 20, a suitable LP for a specific
wellbore servicing operation may be determined.
[0037] In various embodiments, the LP may provide for minimal
intermixing at one or both interfaces between the LP and two fluids
separated by the LP. For example, the LP may provide for
intermixing of less than about 50% by volume of the displaced fluid
anywhere mixing occurs (i.e. 50% by volume is the displacing fluid
and 50% by volume is the displaced fluid). In an embodiment, the
interface between an LP and a cement has intermixing of less than
about 10% by volume of the displaced fluid anywhere mixing occurs
(i.e. 90% by volume is the displacing fluid and 10% by volume is
the displaced fluid). In another embodiment, the interface between
an LP and a drilling fluid has intermixing of less than about 2% by
volume of the displaced fluid anywhere mixing occurs (i.e. 98% by
volume is the displacing fluid and 2% by volume is the displaced
fluid).
[0038] The LP may be characterized by one or more diffusion and/or
mixing coefficients. Diffusion and mixing coefficients refer to a
factor of proportionality representing the amount of a material
migrating across a unit area per unit time when intermingled with
another material, often as a result of random or forced agitation.
In an embodiment, the LP may have a diffusion coefficient of from
about 1.times.10.sup.-8 cm.sup.2/sec to about 1.times.10.sup.-9
cm.sup.2/sec as determined by Fick's law of diffusion with
parameters of diffusion flux (mol/cm.sup.2s), diffusion coefficient
(cm.sup.2/s), concentration (mol/cm.sup.3), and position (cm). In
another embodiment, the LP may have a mixing coefficient of from
about 1.times.10.sup.-7 cm.sup.2/sec to about 1.times.10.sup.-8
cm.sup.2/sec as determined by Fick's law of diffusion with
parameters of diffusion flux (mol/cm.sup.2s), diffusion coefficient
(cm.sup.2/s), concentration (mol/cm.sup.3), and position (cm).
[0039] In an embodiment, a LP having the desirable rheological
dimensions may comprise a crosslinkable polymer system and a
filler. Alternatively, the LP may comprise a crosslinkable polymer
system, a filler and a packing agent.
[0040] In an embodiment, the LP comprises a crosslinkable polymer
system. Examples of suitable crosslinkable polymer systems include,
but are not limited to, the following: a water soluble copolymer of
a non-acidic ethylenically unsaturated polar monomer and a
copolymerizable ethylenically unsaturated ester; a terpolymer or
tetrapolymer of an ethylenically unsaturated polar monomer, an
ethylenically unsaturated ester, and a monomer selected from
acrylamide-2-methylpropane sulfonic acid, N-vinylpyrrolidone, or
both; or combinations thereof. The copolymer may contain from one
to three polar monomers and from one to three unsaturated esters.
The crosslinkable polymer system may also include at least one
crosslinking agent, which is herein defined as a material that is
capable of crosslinking such copolymers to form a gel. As used
herein, a gel is defined as a crosslinked polymer network swollen
in a liquid medium. The crosslinking agent may be, for example and
without limitation, an organic crosslinking agent such as a
polyalkyleneimine, a polyfunctional aliphatic amine such as
polyalkylenepolyamine, an aralkylamine, a heteroaralkylamine, or
combinations thereof. Examples of suitable polyalkyleneimines
include without limitation polymerized ethyleneimine and
propyleneimine. Examples of suitable polyalkylenepolyamines include
without limitation polyethylene- and polypropylene-polyamines. A
description of such copolymers and crosslinking agents can be found
in U.S. Pat. Nos. 5,836,392; 6,192,986, and 6,196,317, each of
which is incorporated by reference herein in its entirety.
[0041] The ethylenically unsaturated esters used in the
crosslinkable polymer system may be formed from a hydroxyl compound
and an ethylenically unsaturated carboxylic acid selected from the
group consisting of acrylic, methacrylic, crotonic, and cinnamic
acids. The ethylenically unsaturated group may be in the alpha-beta
or beta-gamma position relative to the carboxyl group, but it may
be at a further distance. In an embodiment, the hydroxyl compound
is an alcohol generally represented by the formula ROH, wherein R
is an alkyl, alkenyl, cycloalkyl, aryl, arylalkyl, aromatic, or
heterocyclic group that may be substituted with one or more of a
hydroxyl, ether, and thioether group. The substituent can be on the
same carbon atom of the R group that is bonded to the hydroxyl
group in the hydroxyl compound. The hydroxyl compound may be a
primary, secondary, iso, or tertiary compound. In an embodiment, a
tertiary carbon atom is bonded to the hydroxyl group, e.g., t-butyl
and trityl. In an embodiment, the ethylenically unsaturated ester
is t-butyl acrylate.
[0042] The non-acidic ethylenically unsaturated polar monomers used
in the crosslinkable polymer system can be amides, e.g., primary,
secondary, and/or tertiary amides, of an unsaturated carboxylic
acid. Such amides may be derived from ammonia, or a primary or
secondary alkylamine, which may be optionally substituted by at
least one hydroxyl group as in alkylol amides such as
ethanolamides. Examples of such carboxylic derived ethylenically
unsaturated polar monomers include without limitation acrylamide,
methacrylamide, and acrylic ethanol amide.
[0043] In an embodiment, the crosslinkable polymer system is a
copolymer of acrylamide and t-butyl acrylate, and the crosslinking
agent is polyethylene imine. These materials are commercially
available as the H.sub.2ZERO service providing conformance control
system from Halliburton Energy Services. The H.sub.2ZERO service
providing conformance control system is a combination of HZ-10
polymer and HZ-20 crosslinker. HZ-10 is a low molecular weight
polymer consisting of polyacrylamide and an acrylate ester. The
gelation rate of the H.sub.2ZERO service providing conformance
control system is controlled by the unmasking of crosslinking sites
on the HZ-20 polymer which is a polyethylene imine crosslinker.
[0044] The concentrations of both HZ-10 polymer and HZ-20
crosslinker contribute to the LP reaction time, its final
mechanical properties and stability. In an embodiment, the
crosslinkable polymer system forms a viscous gel in from about 60
mins to about 300 mins, alternatively in from about 60 mins to
about 300 mins at a temperature of from about 180.degree. F. to
about 320.degree. F., alternatively from about 180.degree. F. to
about 225.degree. F. and, alternatively from about 250.degree. F.
to about 320.degree. F. The relative amounts of HZ-10 polymer and
HZ-20 crosslinker suitable for use in the preparation of LPs of
this disclosure will be described in detail later herein.
[0045] In an embodiment, the LP comprises a filler. Herein a filler
refers to particulates, also termed finer filler material, designed
to bridge off across the packing agent of the LP. Such fillers may
be smaller in size than the packing agent. Details of the filler
and packing agent size will be disclosed later herein. Such fillers
may have a pH of from about 3 to about 10. In an embodiment, the
filler has a specific gravity of less than about 1 to about 5,
alternatively from about 1.5 to about 5, alternatively from about
1.75 to about 4. Without wishing to be limited by theory, fillers
having a specific gravity in the disclosed range may produce a LP
with greater flexibility and ductility.
[0046] Examples of suitable fillers include without limitation
alkyl quaternary ammonium montmorillonite, bentonite, zeolites,
barite, fly ash, calcium sulfate, and combinations thereof. In an
embodiment the filler is an alkyl quarternary ammonium
montmorillonite. In an embodiment, the filler is a water swellable
or hydratable clay. In an alternative embodiment, the filler is an
oil-based sealing composition that may comprise a hydratable
polymer, an organophilic clay and a water swellable clay. Such
oil-based sealing compositions are disclosed in U.S. Pat. Nos.
5,913,364; 6,167,967; 6,258,757, and 6,762,156, each of which is
incorporated by reference herein in its entirety. In an embodiment,
the filler material is FLEXPLUG sealant, which is a deformable,
viscous, cohesive oil-based composition comprising alkyl quaternary
ammonium montmorillonite commercially available from Halliburton
Energy Services.
[0047] In an embodiment, the LP comprises a packing agent. Examples
of packing agents include without limitation resilient materials
such as graphite; fibrous materials such as cedar bark, shredded
cane stalks and mineral fiber; flaky materials such as mica flakes
and pieces of plastic or cellophane sheeting; and granular
materials such as ground and sized limestone or marble, wood, nut
hulls, formica, corncobs, gravel and cotton hulls. In an
embodiment, the packing agent is a resilient graphite such as
STEELSEAL or STEELSEAL FINE lost circulation additives which are
dual composition graphite derivatives commercially available from
Baroid Industrial Drilling Products, a Halliburton Energy Services
company.
[0048] In another embodiment, the packing agent is a resin-coated
particulate. Examples of suitable resin-coated particulates include
without limitation resin-coated ground marble, resin-coated
limestone, and resin-coated sand. In an embodiment, the packing
agent is a resin-coated sand. The sand may be graded sand that is
sized based on a knowledge of the size of the lost circulation
zone. The graded sand may have a particle size in the range of from
about 10 to about 70 mesh, U.S. Sieve Series. The graded sand can
be coated with a curable resin, a tackifying agent or mixtures
thereof. The hardenable resin compositions useful for coating sand
and consolidating it into a hard fluid permeable mass generally
comprise a hardenable organic resin and a resin-to-sand coupling
agent. Such resin compositions are well known to those skilled in
the art, as is their use for consolidating sand into hard fluid
permeable masses. A number of such compositions are described in
detail in U.S. Pat. Nos. 4,042,032, 4,070,865, 4,829,100, 5,058,676
and 5,128,390 each of which is incorporated herein by reference in
its entirety. Methods and conditions for the production and use of
such resin coated particulates are disclosed in U.S. Pat. Nos.
6,755,245; 6,866,099; 6,776,236; 6,742,590; 6,446,722, and
6,427,775, each of which is incorporated herein by reference in its
entirety. An example of a resin suitable for coating the
particulate includes without limitation SANDWEDGE NT conductivity
enhancement system that is a resin coating commercially available
from Halliburton Energy Services.
[0049] In some embodiments, additives may be included in the LP for
improving or changing the properties thereof. Examples of such
additives include but are not limited to salts, accelerants,
surfactants, set retarders, defoamers, settling prevention agents,
weighting materials, dispersants, vitrified shale, formation
conditioning agents, particulate bridging agents, or combinations
thereof. Other mechanical property modifying additives, for
example, are carbon fibers, glass fibers, metal fibers, minerals
fibers, and the like which can be added to further modify the
mechanical properties. These additives may be included singularly
or in combination. Methods for introducing these additives and
their effective amounts are known to one of ordinary skill in the
art.
[0050] In an embodiment, the LP includes a sufficient amount of
water to form a pumpable slurry. The water may be fresh water or
salt water, e.g., an unsaturated aqueous salt solution or a
saturated aqueous salt solution such as brine or seawater.
[0051] In an embodiment, the LP comprises a crosslinkable polymer
system and a filler. In such an embodiment, the crosslinkable
polymer system may be present in an amount of from about 35% to
about 90% by volume, and the filler may be present in an amount of
from about 8% to about 40% by volume.
[0052] Alternatively, the LP comprises a crosslinkable polymer
system, a filler and a packing agent. In such an embodiment, the
crosslinkable polymer system may be present in an amount of from
about 30% to about 90% by volume, the filler may be present in an
amount of from about 8% to about 40% by volume, and the packing
agent may be present in an amount of from about 1% to about 10% by
volume.
[0053] In an embodiment a LP is prepared by combining the
crosslinkable polymer system H.sub.2ZERO service providing
conformance control system with a filler, FLEXPLUG OBM sealant. In
such an embodiment, the LP is prepared by combining from about 35%
to about 90% by volume H.sub.2ZERO service providing conformance
control system with from about 8% to about 40% by volume FLEXPLUG
OBM sealant.
[0054] The H.sub.2ZERO service providing conformance control system
is prepared by mixing the HZ-10 low molecular weight polymer
consisting of polyacrylamide and an acrylate ester with the HZ-20
polyethylene imine crosslinker. The relative amounts of HZ-10 and
HZ-20 to be used in the preparation of H.sub.2ZERO can be adjusted
to provide gelling within a specified time frame based on reaction
conditions such as temperature and pH. For example, the amount of
HZ-20 crosslinker necessary for gelling is inversely proportional
to temperature wherein higher amounts of HZ-20 are required at
lower temperatures to effect formation of a viscous gel.
Additionally, gel time can be adjusted to compensate for the pH of
the filler material. Adjustment of the H.sub.2ZERO service
providing conformance control system to provide optimum gelling as
a function of temperature and/or pH is known to one of ordinary
skill in the art. The filler, FLEXPLUG OBM sealant is an oil-based
sealing composition comprising alkyl quaternary ammonium
montmorillonite. Without wishing to be limited by theory, such
oil-based sealing compositions may function by the hydratable
polymer reacting with water in the well bore to immediately hydrate
and form a highly viscous gel. The water swellable clay then
immediately swells in the presence of water and together with the
viscous gel forms a highly viscous sealing mass. The organophilic
clay may then react with an oil carrier fluid to add viscosity to
the composition so that the polymer and clay do not settle out of
the oil prior to reacting with water in the well bore.
[0055] In another embodiment, the LP comprises a thermally
activated cement and an organophilic product. In an embodiment, the
LP comprises a hydraulic cement. Herein hydraulic cement refers to
a powdered material that develops adhesive qualities and
compressive strength when cured with water. In an embodiment, an LP
comprises a metal oxide, alternatively an alkaline earth metal
oxide, alternatively magnesium oxide, MgO. In an embodiment, the
MgO comprises without limitation THERMATEK.TM. rigid setting fluid
which is commercially available from Halliburton Energy
Services.
[0056] In an embodiment, the LP comprises an organophilic
component. In an embodiment, the organophilic component comprises
an organophilic clay. Examples of suitable clays include without
limitation montmorillonite, bentonite, hectorite, attapulgite,
sepiolite and combinations thereof. In an embodiment, the LP
comprises FLEXPLUG OBM sealant, which is a deformable, viscous,
cohesive oil-based composition comprising alkyl quaternary ammonium
montmorillonite commercially available from Halliburton Energy
Services.
[0057] In an embodiment, the LP includes a sufficient amount of
aqueous fluid to form a pumpable slurry. The aqueous fluid may be a
water-based drilling mud, which may comprise fresh water or salt
water, e.g., an unsaturated aqueous salt solution or a saturated
aqueous salt solution such as brine or seawater.
[0058] In an embodiment, the LP comprises a thermally settable
cement and an organophilic component. In such an embodiment, the
thermally settable cement may be present in an amount of from about
35% to about 90% by volume, and the organophilic component may be
present in an amount of from about 8% to about 40% by volume.
[0059] In an embodiment a LP is prepared by combining the rigid
setting fluid THERMATEK with an organophilic component, FLEXPLUG
OBM sealant. In such an embodiment, the LP is prepared by combining
from about 35% to about 90% by volume THERMATEK rigid setting fluid
with from about 8% to about 40% by volume FLEXPLUG OBM sealant.
[0060] The components of the LP may be combined in any order
desired by the user to form a slurry that may then be placed into a
wellbore for use as a liquid plug. The components of the LP may be
combined using any mixing device compatible with the composition,
for example a bulk mixer. In an embodiment, the components of the
LP are combined at the site of the wellbore. Alternatively, the
components of the LP are combined off-site and then later used at
the site of the well. Methods for the preparation of a LP slurry
are known to one of ordinary skill in the art.
[0061] In an embodiment, the LPs of this disclosure when placed in
a wellbore act as a gellable liquid plug that is flexible, adhesive
and of appreciable compressive strength. In an embodiment, the LPs
of this disclosure have an appreciable static gel strength (SGS).
In an embodiment, the LPs of this disclosure act as a thermally
settable liquid plug.
[0062] The LPs disclosed herein may be used as a wellbore servicing
fluid in a variety of wellbore servicing applications as known to
one of skill in the art. As used herein, a "servicing fluid" refers
to a fluid used to drill, complete, work over, fracture, repair, or
in any way prepare a wellbore for the recovery of materials
residing in a subterranean formation penetrated by the wellbore.
Examples of servicing fluids include, but are not limited to,
cement slurries, drilling fluids or muds, spacer fluids, fracturing
fluids or completion fluids, all of which are well known in the
art. The servicing fluid is for use in a wellbore that penetrates a
subterranean formation. It is to be understood that "subterranean
formation" encompasses both areas below exposed earth and areas
below earth covered by water such as ocean or fresh water.
[0063] The cementing process is one of the most important processes
in the drilling and completion of a well. Cementing is done at
various points within a well, at various times while drilling, and
may be done within or outside the casing. Primary cementing is
carried out in order to form a protective sheath around the casing
and attach the casing to the wall of the well bore. This cement
sheath supports the casing, prevents migration of fluids in the
annulus, and protects the casing from corrosive formation
fluids.
[0064] During conventional cementing operations, the sheath is
formed by introducing a cement slurry into the upper end of the
casing at the ground surface and allowing the cement to flow
through the casing to the bottom of the well and reverse direction
as it enters the annulus. The cement then flows into and through
the annulus between the casing and the wall of the well bore, and
circulates back to the ground surface. Circulation is then
terminated and the cement is allowed to set.
[0065] Typically, a mechanical plug or plugs is used in an effort
to minimize contamination of the cement slurry during placement and
to indicate completion of the cementing operation. Mechanical plugs
are described in U.S. Pat. Nos. 4,190,112; 4,175,619; 4,706,747;
4,756,365; 5,437,330; and 6,196,311, each of which is incorporated
by reference herein in its entirety. As these mechanical plugs are
subject to failure and may be incompatible with a given operation
(e.g., mechanical plugs of the required size may not be available),
a LP may be used in addition to or in place of mechanical plugs to
enhance the physical separation of the fluids at the interface. In
an embodiment, a LP is introduced into a wellbore before the
addition of a cement slurry to the wellbore. In an embodiment, a LP
is added to the wellbore following the pumping of cement slurry. In
an embodiment, at least one LP is used in combination with at least
one mechanical plug. In an embodiment, the LP contains particulate
bridging materials, including, but not limited to, inert solids,
hydrophobic swellable agents, and elastomers, to seal off leaks in
a mechanical plug during displacement. In an embodiment, a LP
introduced into the wellbore behind a cement slurry assists in the
cleaning of the casing during displacement of the cement slurry,
reducing or eliminating the presence of leftover strings in the
casing following displacement.
[0066] During cementing, use is commonly made of collars and shoes.
These are typically restrictions that are attached to the pipe
string. The collar, e.g. float collar, and the shoe, e.g. float
shoe, help prevent the backflow of cement during the cementing
process, and often comprise a check valve to achieve this
prevention of backflow. In an embodiment, a LP may provide an
indication of when the cement has been displaced from the casing
string at a desired depth. As the LP flows from the relatively
large cross sectional area of the casing to the relatively small
cross sectional area of the float shoe or collar, the pressure
drop, which is a function of the viscosity of the material flowing
through the restriction, would increase due to the high viscosity
of the LP, yielding a surface pressure spike that may be
interpreted as an end of job indicator. In an embodiment,
particulates are added to the LP to increase the surface pressure
indication when passing through a restriction.
[0067] In an embodiment, the LP comprises a thermally settable
cement and an organophilic component. Once the LP is pumped down
the string and encounters the float collar, the increased shear to
get through the restriction would cause a temperature increase
which would lead to cement setting. A LP of this disclosure may
thus be utilized as a settable spacer. In this embodiment,
over-displacement of the cement slurry would not lead to an
insufficient cement job at the shoe, as the settable spacer would
set as a cement upon thermal activation initiated by the increase
in temperature experienced by the LP due to the increased shear
during flow through a restriction.
[0068] A LP of the present disclosure may be utilized to control
the physical interface between fluids during non-cementing well
operations. For example, in an embodiment, a LP is used to minimize
contamination of both fluids during the displacement of a drilling
fluid by a completions fluid. Minimization of contamination may
minimize expense incurred due to loss of valuable drilling fluids
and completion brines.
[0069] Drilling fluids, cuttings and gelled fluids are often found
near the formation wall of an annulus that is to be cemented. In an
embodiment, a LP is run prior to the introduction of the cement
slurry during primary cementing. The increased shear force of the
LP as compared to the cement slurry may aid in the removal of
unwanted materials from the annular wall, enhancing the success of
the primary cementing operation in isolating the formation. In an
embodiment, particulates are added to the LP to act as "gritty"
material and aid in the drilling fluid removal.
[0070] During conventional primary cementing (i.e. flow of the
slurry down the casing and back to the surface through the
annulus), it is often difficult to obtain the proper circulation of
cement inside the annulus due to a weak formation around the well.
In addition, the hydrostatic weight of the cement exerts additional
pressure on the formation, especially when increased pressure is
applied to the formation to overcome the friction of the cement
slurry. One technique used to overcome these difficulties, is
reverse circulation cementing. Reverse circulation cementing is
described in U.S. Pat. No. 6,920,929 which is incorporated by
reference herein in its entirety. In reverse circulation cementing,
the cement slurry is pumped down through the annulus and back up
the casing. While this greatly reduces the total pressure applied
to the formation, it has its own challenges. One challenge is that
because no mechanical plugs can be used as are used in conventional
cementing operations, the operator has no way to determine exactly
when the cement completely fills the annulus, without the use of
some type of expensive and time-consuming tool. The operator runs
the risk of either not filling the annulus completely with the
cement slurry or of running cement back up inside the casing
string, covering potential productive areas and/or incurring
additional time and expense to drill out this overrun cement. When
reverse circulation is performed, the leading edge of the cement is
in the shoe track area, necessitating additional volumes of cement
be pumped back up inside the casing during reverse circulation to
insure that competent cement is at the bottom of the casing. In an
embodiment, a LP of the present disclosure is run ahead of the
cement slurry in a reverse circulation cementing operation in order
to minimize contamination of the cement at the cement/drilling
fluid interface. In an embodiment, a LP of the present disclosure
is introduced into the annulus ahead of the cement slurry in a
reverse circulation cementing operation and gives a surface
pressure indication of when the cement reaches the bottom of the
casing and begins to circulate into the well by a narrowed orifice
present at the bottom of the chosen casing string. In an
embodiment, a LP of the present disclosure is introduced into the
annulus ahead of a cement slurry in a reverse circulation cementing
operation and sets up as a cement upon thermal activation.
[0071] Secondary cementing operations include cement plugging
applications. It is often desired to plug portions of the wellbore
for various purposes including forming a foundation for
sidetracking or drilling a deviated wellbore from the original
wellbore. Typically, an excess volume of cement slurry is pumped
into the well to compensate for the adverse effects of
contamination of the cement slurry by the drilling fluids present
in the wellbore. The excess volume of slurry is to provide enough
settable cement to insure a competent plug in view of the fact that
a portion of the slurry that gets contaminated will be unsettable.
In addition, it is often necessary to place a cement plug a
considerable distance from the bottom of the well. These plugs are
quite prone to failure due to drilling mud contamination when the
density of the slurry exceeds that of the drilling fluid in the
wellbore, since gravity increases the intermixing of the fluids,
leading to a cement with inadequate compressive strength or
improper positioning of the set plug. This can be the case in both
vertical and deviated well applications. In an embodiment, a LP of
the present disclosure, designed to prevent migration of a cement
slurry, is introduced into the wellbore prior to the addition of
cement slurry during formation and placement of a cement plug. In
an embodiment, a LP is introduced into the wellbore ahead of and
behind the cement slurry during formation of a cement plug.
[0072] Often, the exact dimensions of a drilled or cased hole are
not known. For example, when a hole section has been drilled,
washed out formations lead to an increased hole volume. An
engineered LP of the present disclosure may be used as a fluid
caliper to calculate the volume of an open hole section. In an
embodiment, a LP for use as a fluid caliper may be designed to
prevent intermixing of the displacing fluid and the fluid already
present in the wellbore. Knowing the casing sizes and volumes, a
measurement of the total fluids pumped during a circulation trip of
a LP may be used to calculate the volume of an open hole section.
In an embodiment, a LP is detectable upon return to the top of the
well (or seabed in riserless circulation operations) by its high
viscosity. In an embodiment, a LP is detectable upon returning to
the surface of a well by the addition of at least one dye or marker
incorporated therein.
[0073] If the primary cementing of the casing does not effectively
isolate the formations, it may be necessary to perform squeeze
cementing, which is the most common type of secondary (remedial)
cementing. Methods of squeeze cementing are described in U.S. Pat.
Nos. 5,322,124; 4,158,388; and 4,627,496, which are incorporated by
reference herein in their entirety. Squeeze cementing is the
process of forcing a cement slurry through holes in the casing or
liner and into the annulus to plug any channels that may exist in
the cement sheath. When the slurry being pumped into the wellbore
encounters a permeable formation, cement solids are filtered out of
the slurry as the liquid phase is forced into the formation in the
form of a cement filtrate. A successful cement squeeze operation
will plug the holes and cracks in the cement sheath with cement
filter cake that will cure to form an impenetrable barrier. The
cement is allowed to set and then a drill bit is lowered on a drill
string through the casing to drill out the cement plug normally
remaining in the casing. The casing may then be reperforated to
continue production. A difficulty associated with squeeze cementing
operations is determining when to stop pumping cement. In an
embodiment, a LP is introduced into a wellbore following the cement
slurry during a squeeze cement operation, and yields a surface
pressure indication of when to stop. In an embodiment, a LP
introduced into a wellbore behind squeeze cement seals off the
permeability of the formation, enhancing the formation integrity by
preventing lost circulation.
[0074] The LPs of this disclosure may provide lost circulation
control in a sufficiently short time period to prevent the operator
from pulling out of the hole and thus reducing nonproductive rig
time. Without wishing to be limited by theory, a packing agent of
the LP may immediately pack off into the lost circulation zones in
the subterranean formation. The filler may then squeeze into the
lost circulation zones forming a bridge between the larger sized
packing agent. Finally, the thermally activated crosslinkable
polymer system may gel into place to produce a permanent plug that
is flexible, adhesive and of appreciable compressive strength. In
addition, due to the filler within the slurry the amount of
crosslinkable polymer system squeezed into the matrix of the
surrounding rock may be minimized thus providing a finite layer of
rock adjacent to the plug that has negligible permeability and
avoids formation damage.
[0075] In many applications, it is desirable to leave a hard
material in or around the casing shoe upon completion of a
cementing operation. One case where this is desirable is when the
driller needs to determine the pore pressure of fluid bearing
formations in order to determine the maximum pressure or mud weight
that may be applied to the formation during drilling operations. A
leak-off test (LOT) is performed to test cement placed behind the
casing and a formation integrity test (FIT) is performed to
determine the pressure at which the formation will fracture or mud
will be lost to the formation. Methods for performing LOT/FIT tests
are given in U.S. Pat. No. 6,378,363, which is incorporated by
reference herein in its entirety. During a LOT/FIT, the well is
isolated from the atmosphere, and drilling mud is then pumped into
the wellbore from the surface at a slow, constant volumetric
flowrate, increasing the pressure in the well. The pumping
continues until a predetermined test pressure is reached, or until
drilling fluid loss from the well is detected. At some pressure
(unless the predetermined test pressure is below the leak off
pressure), fluid will enter the formation, or leak off, either
moving through existing permeable paths in the formation or by
fracturing the formation, thus creating space into which to flow.
The formation fracture pressure is determined from the LOT/FIT
results. In an embodiment, a LP comprising a thermally settable
cement and an organophilic component is introduced into a well
prior to drilling mud to be used for a LOT/FIT. In an embodiment, a
LP sets up as a hard cement upon undergoing a temperature increase
due to the restrictive nature of the float shoe, float collar, or
similar restriction prior to a LOT/FIT.
[0076] In many instances, a kick-off plug is used to prepare a site
for the drilling of a new well from the upper section of an
existing well. In this case, often a hard cementitious material is
placed in the well at the point of deviation of the new well and
used to "kick off" further drilling in the desired direction. In an
embodiment, in lieu of a conventional cement kick-off plug, a LP
comprising a thermally settable cement and an organophilic
component is introduced into a wellbore and allowed to set up as a
hard kick-off plug around the shoe track.
[0077] In an embodiment, a LP may be used for plug and abandonment
of a well, i.e. to prepare a well to be shut in and permanently
isolated. Methods for plug and abandonment are described in U.S.
Pat. Nos. 6,595,289, and 6,880,642, which are incorporated by
reference herein in their entirety. Regulatory requirements mandate
that strata, particularly freshwater aquifers, are adequately
isolated following plug and abandonment. A series of cement plugs
is set in the wellbore and tested at each stage for hydraulic
isolation. In an embodiment, a highly viscous LP may be used in the
placement of cement plugs. In an embodiment, a LP comprising a
thermally settable cement is introduced into the wellbore and
allowed to set to form strategically located plugs during plug and
abandon operations.
[0078] In an embodiment, one or multiple "slugs" of LP are
introduced into the drill string and pumped down to the lost
circulation to seal off the lost circulation zone with little or no
interruption of drilling operations and reduction in loss of
drilling fluid to the lost zone. In the process of drilling a well
low fracture gradients zones, fractured zones, etc. are often
encountered and loss of whole drilling fluid to the formation
becomes a problem. Significant losses of drilling fluid can impede
the progress of drilling the well, add significant cost to the
drilling of the well, prevent the drilling of the well to target
depth, and/or cause the total loss of the drilled open hole
section. Many lost circulation materials and systems are currently
commercially available. These systems either require cessation of
drilling operations to try to pump some type of treatment to seal
off the lost zone or materials are incorporated into drilling fluid
to try to "bridge" off the lost circulation zone. The viscous LP as
disclosed herein would tend to migrate to the place where losses
are occurring and may help seal off the zone due to flow resistance
in small openings where losses are occurring. In an embodiment, a
LP as disclosed herein when used to prevent lost circulation may
comprise particulate material such as sized calcium carbonate or
other particulate material. Such particulate materials have been
previously described herein. The incorporation of particulate
material in a LP would help deliver the needed lost circulation
material directly to the lost zone without having to add it to the
entire drilling fluid system.
[0079] The LPs may be introduced to the wellbore to control the
intermixing of fluids. In an embodiment, the LP is placed into a
wellbore as a single stream. In an embodiment, the LP is introduced
into the wellbore in two streams. In an embodiment, the LP is
activated by downhole conditions to form a barrier that
substantially seals the wellbore. For example the LP may form a
mass that plugs the zone at elevated temperatures, such as those
found at higher depths within a wellbore or those occurring due to
the shear required for a highly viscous fluid to pass through a
restriction such as a float shoe or collar.
[0080] In other embodiments, additives are also pumped into the
wellbore with LP. For example and without limitation, fluid
absorbing materials, resins, aqueous superabsorbers, viscosifying
agents, suspending agents, dispersing agents, or combinations
thereof can be pumped in the stream with the LPs disclosed.
[0081] In an embodiment, the wellbore in which the LP is positioned
belongs to a multilateral wellbore configuration. It is to be
understood that a multilateral wellbore configuration includes at
least two principal wellbores connected by one or more ancillary
wellbores.
[0082] While preferred embodiments of the invention have been shown
and described, modifications thereof can be made by one skilled in
the art without departing from the spirit and teachings of the
invention. The embodiments described herein are exemplary only, and
are not intended to be limiting. Many variations and modifications
of the invention disclosed herein are possible and are within the
scope of the invention. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term
"optionally" with respect to any element of a claim is intended to
mean that the subject element is required, or alternatively, is not
required. Both alternatives are intended to be within the scope of
the claim. Use of broader terms such as comprises, includes,
having, etc. should be understood to provide support for narrower
terms such as consisting of, consisting essentially of, comprised
substantially of, etc.
[0083] Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
preferred embodiments of the present invention. The discussion of a
reference herein is not an admission that it is prior art to the
present invention, especially any reference that may have a
publication date after the priority date of this application. The
disclosures of all patents, patent applications, and publications
cited herein are hereby incorporated by reference, to the extent
that they provide exemplary, procedural or other details
supplementary to those set forth herein.
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