U.S. patent application number 13/623109 was filed with the patent office on 2014-03-20 for methods for plug cementing.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Bruno Drochon, Dominique Guillot, Lijun Lin, Philip F. Sullivan.
Application Number | 20140076563 13/623109 |
Document ID | / |
Family ID | 50273268 |
Filed Date | 2014-03-20 |
United States Patent
Application |
20140076563 |
Kind Code |
A1 |
Lin; Lijun ; et al. |
March 20, 2014 |
Methods for Plug Cementing
Abstract
Compositions comprise polyacrylamide, a non-metallic crosslinker
and a pH-adjustment material. Such compositions have utility in the
context of remedial cementing, plug cementing in particular. The
compositions may be pumped into a subterranean well, where they
polymerize and form a support on which a cement plug may sit. The
support may maintain the position of the cement plug in the
wellbore and minimize cement-plug contamination.
Inventors: |
Lin; Lijun; (Sugar Land,
TX) ; Sullivan; Philip F.; (Bellaire, TX) ;
Guillot; Dominique; (Fontenay Aux Roses, FR) ;
Drochon; Bruno; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
50273268 |
Appl. No.: |
13/623109 |
Filed: |
September 20, 2012 |
Current U.S.
Class: |
166/295 |
Current CPC
Class: |
C04B 26/04 20130101;
C09K 8/426 20130101; C04B 28/04 20130101; C04B 26/02 20130101; C09K
8/46 20130101; E21B 33/13 20130101; C04B 26/02 20130101; C04B
22/126 20130101; C04B 14/368 20130101; C04B 24/2652 20130101 |
Class at
Publication: |
166/295 |
International
Class: |
E21B 33/16 20060101
E21B033/16 |
Claims
1. A method for setting a cement plug in a subterranean wellbore,
comprising: i. preparing an aqueous process fluid composition
comprising more than 1 wt % polyacrylamide and a non-metallic
crosslinker; ii. placing the composition into the wellbore; iii.
allowing the composition to crosslink and form a gel; iv. preparing
a cement slurry; and v. placing the slurry in the wellbore.
2. The method of claim 1, wherein the non-metallic crosslinker
comprises a polylactam.
3. The method of claim 1, wherein the non-metallic crosslinker
comprises polyvinylpyrrolidone, polyvinylcaprolactam or a
combination thereof.
4. The method of claim 3, wherein the polyvinylpyrrolidone has a
weight average molecular weight of greater than or equal to about
50,000 g/mol and less than or equal to about 2 million g/mol.
5. The method of claim 1, wherein the non-metallic crosslinker has
a weight average molecular weight greater than or equal to about
10,000 g/mol and less than or equal to about 2 million g/mol.
6. The method of claim 1, wherein the polyacrylamide has a degree
of hydrolysis higher than or equal to about 0% and lower than or
equal to about 40%.
7. The method of claim 1, wherein the molecular weight of the
polyacrylamide is between about 10,000 g/mol and 20 million
g/mol.
8. The method of claim 1, wherein the pH of the composition is
adjusted such that the pH is higher than or equal to 11 or lower
than or equal to 1.
9. The method of claim 1, wherein the composition further comprises
sodium chloride, potassium chloride, calcium chloride, calcium
bromide, zinc bromide, sodium formate, potassium formate, cesium
formate or combinations thereof.
10. The method of claim 1, wherein the cement slurry comprises
Portland cement, a lime/silica blend, a lime/pozzolan blend,
calcium aluminate cement, zeolites, a chemically bonded phosphate
ceramic, geopolymers or combinations thereof.
11. The method of claim 1, wherein the composition further
comprises silica, barite, hematite, ilmenite, manganese tetraoxide,
glass fibers, carbon fibers, nylon fibers, polyvinylalcohol fibers,
polylactic acid fibers, polyvinylchloride fibers, polyethylene
fibers or polyurethane fibers or combinations thereof.
12. A method for treating a subterranean wellbore, comprising: i.
preparing an aqueous process fluid composition comprising more than
1 wt % polyacrylamide and a non-metallic crosslinker; ii. placing
the composition into the wellbore; iii. allowing the composition to
crosslink and form a gel; iv. preparing a cement slurry; and v.
placing the slurry in the wellbore; wherein, the molecular weight
of the polyacrylamide is between about 10,000 g/mol and 20 million
g/mol.
13. The method of claim 12, wherein the non-metallic crosslinker
comprises a polylactam.
14. The method of claim 12, wherein the non-metallic crosslinker
comprises polyvinylpyrrolidone, polyvinylcaprolactam or a
combination thereof.
15. The method of claim 14, wherein the polyvinylpyrrolidone has a
weight average molecular weight of greater than or equal to about
50,000 g/mol and less than or equal to about 2 million g/mol.
16. The method of claim 12, wherein the non-metallic crosslinker
has a weight average molecular weight greater than or equal to
about 10,000 g/mol and less than or equal to about 2 million
g/mol.
17. The method of claim 12, wherein the polyacrylamide has a degree
of hydrolysis higher than or equal to about 0% and lower than or
equal to about 40%.
18. The method of claim 1, wherein the pH of the composition is
adjusted such that the pH is higher than or equal to 11 or lower
than or equal to 1.
19. The method of claim 1, wherein the composition further
comprises sodium chloride, potassium chloride, calcium chloride,
calcium bromide, zinc bromide, sodium formate, potassium formate,
cesium formate or combinations thereof.
20. The method of claim 1, wherein the composition further
comprises silica, barite, hematite, ilmenite, manganese tetraoxide,
glass fibers, carbon fibers, nylon fibers, polyvinylalcohol fibers,
polylactic acid fibers, polyvinylchloride fibers, polyethylene
fibers or polyurethane fibers or combinations thereof.
Description
BACKGROUND
[0001] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0002] This disclosure relates to methods for servicing
subterranean wells, in particular, fluid compositions and methods
for remedial cementing operations.
[0003] Remedial cementing is a general term to describe operations
that employ cementitious fluids to cure a variety of well problems.
Such problems may occur at any time during the life of the well,
from well construction to well stimulation, production and
abandonment. Remedial cementing is commonly divided into two broad
categories--plug cementing and squeeze cementing. Plug cementing
consists of placing cement slurry in a wellbore and allowing it to
set. Squeeze cementing consists of forcing cement slurry through
holes, splits or fissures in the casing/wellbore annular space.
[0004] During construction of a subterranean well, remedial
operations may be required to maintain wellbore integrity during
drilling, to cure drilling problems, or to repair defective primary
cement jobs. Wellbore integrity may be compromised when drilling
through mechanically weak formations, leading to hole enlargement.
Cement slurries may be used to seal and consolidate the borehole
walls. Remedial cementing is a common way to repair defective
primary cement jobs, to either allow further drilling to proceed or
to provide adequate zonal isolation for efficient well
production.
[0005] During well production, remedial cementing operations may be
performed to restore production, change production characteristics
(e.g., to alter the gas/oil ratio or control water production), or
repair corroded tubulars. During a stimulation treatment, the
treatment fluids must enter the target zones and not leak behind
the casing. If poor zonal isolation behind the production casing is
suspected, a remedial cementing treatment may be necessary.
[0006] Well abandonment frequently involves placing cement plugs to
ensure long-term zonal isolation between geological formations,
replicating the previous natural barriers between zones. However,
before a well can be abandoned, annular leaks must be sealed.
Squeeze cementing techniques may be applied for this purpose.
[0007] Cementitious fluid systems employed during
remedial-cementing operations may comprise Portland cement
slurries, lime/silica blends, lime/pozzolan blends,
calcium-aluminate cement slurries, Sorel cements, zeolites,
chemically bonded phosphate ceramics, geopolymers and organic
resins based on epoxies or furans.
[0008] The most common method for placing a cement plug is the
balanced-plug technique (FIG. 1). Tubing or drillpipe 101 is run
into the wellbore 102 to the desired depth of the plug base 103. To
avoid contamination by other wellbore fluids, appropriate volumes
of spacer fluid 104 or chemical wash may be pumped ahead of and
behind the cement slurry 105. A displacement fluid or drilling
fluid 106 may reside above the spacer fluid. The volumes are such
that they correspond to the same heights in the annulus and in the
pipe, thus achieving a hydrostatic balance. Once the plug is
balanced, the pipe is slowly pulled out of the cement to a depth
above the plug, and excess cement slurry is reversed out.
[0009] A problem that may arise during placement of a balanced plug
is contamination by fluids that reside below the plug. To minimize
downward migration of the cement plug, fluids with high gel
strengths may be placed as a base 107. Examples of such fluids
include thixotropic bentonite suspensions, silicate gels or
crosslinked polymer pills. The pills may be weighted to a density
higher than that of the cement plug to ensure better stability of
the interface. Mechanical devices such as inflatable packers,
diaphragms and umbrella-shaped membranes may also be used as bases
for cement plugs.
[0010] A thorough overview of remedial cementing compositions and
practices may be found in the following publication. Daccord G et
al.: "Remedial Cementing," in Nelson E B and Guillot D (eds.): Well
Cementing, 2.sup.nd Edition, Houston: Schlumberger (2006)
503-547.
SUMMARY
[0011] In an aspect, embodiments relate to methods for setting a
cement plug in a subterranean wellbore. A process fluid composition
is prepared that comprises at least 1 wt % polyacrylamide and a
non-metallic crosslinker. The composition is placed in the wellbore
and allowed to crosslink and form a gel. A cement slurry is
prepared and placed in the wellbore such that is rests on top of
the gel, thereby forming the plug.
[0012] In a further aspect, embodiments relate to methods for
treating a subterranean wellbore. A process fluid composition is
prepared that comprises at least 1 wt % polyacrylamide and a
non-metallic crosslinker. The composition is placed in the wellbore
and allowed to crosslink and form a gel. A cement slurry is
prepared and placed in the wellbore such that is rests on top of
the gel, thereby forming the plug. The molecular weight of the
polyacrylamide may be between about 10,000 g/mol and 20 million
g/mol.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 presents an illustration of a balanced cement
plug.
[0014] FIG. 2 presents the complex viscosities of aqueous
polyacrylamide (PAM)--polyvinylpyrrolidone (PVP) gels containing
various amounts of oil-base drilling fluid (OBM).
[0015] FIG. 3 presents the complex viscosities of aqueous
polyacrylamide-polyvinylpyrrolidone gels containing various amounts
of water-base drilling fluid (WBM).
DETAILED DESCRIPTION
[0016] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and the detailed description, it should be understood that
a concentration range listed or described as being useful,
suitable, or the like, is intended that any and every concentration
within the range, including the end points, is to be considered as
having been stated. For example, "a range of from 1 to 10" is to be
read as indicating each and every possible number along the
continuum between about 1 and about 10. Thus, even if specific data
points within the range, or even no data points within the range,
are explicitly identified or refer to only a few specific, it is to
be understood the Applicant appreciates and understands that any
and all data points within the range are to be considered to have
been specified, and that the Applicant possessed knowledge of the
entire range and all points within the range.
[0017] The following definitions are provided in order to aid those
skilled in the art to understand the detailed description.
[0018] The term "treatment," or "treating," refers to any
subterranean operation that uses a fluid in conjunction with a
desired function and/or for a desired purpose. The term
"treatment," or "treating," does not imply any particular action by
the fluid.
[0019] As used herein, the term "polymer" or "oligomer" is used
interchangeably unless otherwise specified, and both refer to
homopolymers, copolymers, interpolymers, terpolymers, and the like.
Likewise, a copolymer may refer to a polymer comprising at least
two monomers, optionally with other monomers. When a polymer is
referred to as comprising a monomer, the monomer is present in the
polymer in the polymerized form of the monomer or in the derivative
form of the monomer. However, for ease of reference the phrase
comprising the (respective) monomer or the like is used as
shorthand.
[0020] As used herein, the term "process fluid" refers to a
pumpable fluid that may be circulated in a subterranean well. Such
fluids may include drilling fluids, cement slurries, spacer fluids,
pills, chemical washes, completion fluids, fracturing fluids,
gravel-pack fluids and acidizing fluids. Those skilled in the art
will recognize that pumpable fluids may have viscosities lower than
about 1000 cP at a shear rate of 100 s.sup.-1.
[0021] As used herein, the term "gel" refers to a solid or
semi-solid, jelly-like composition that can have properties ranging
from soft and weak to hard and tough. The term "gel" refers to a
substantially dilute crosslinked system, which exhibits no flow
when in the steady-state, which by weight is mostly liquid, yet
behaves like a solid due to a three-dimensional crosslinked network
within the liquid. It is the crosslinks within the fluid that give
a gel its structure (hardness) and contribute to stickiness.
Accordingly, gels are a dispersion of molecules of a liquid within
a solid in which the solid is the continuous phase and the liquid
is the discontinuous phase. A gel is considered to be present when
the Elastic Modulus G' is larger than the Viscous Modulus G," when
measured using an oscillatory shear rheometer (such as a Bohlin CVO
50) at a frequency of 1 Hz and at 20.degree. C. The measurement of
these moduli is well known to one of minimal skill in the art, and
is described in An Introduction to Rheology, by H. A. Barnes, J. F.
Hutton, and K. Walters, Elsevier, Amsterdam (1997).
[0022] The term polyacrylamide refers to pure polyacrylamide
homopolymer or copolymer with near zero amount of acrylate groups,
a polyacrylamide polymer or copolymer with a mixture of acrylate
groups and acrylamide groups formed by hydrolysis and copolymers
comprising acrylamide, acrylic acid, and/or other monomers.
[0023] This disclosure incorporates process fluids that may
comprise polyacylamide crosslinked with a non-metallic crosslinker.
The non-metallic crosslinkers do not include metals, but are
instead organic molecules, oligomers, polymers, and/or the like.
The polyacrylamide may have a weight average molecular weight
higher than or equal to about 10,000 g/mol and lower than or equal
to about 20 million g/mol, or between about 500,000 g/mol and about
5 million g/mol. The polyacrylamide may have a degree of hydrolysis
of from 0% up to less than or equal to about 40%, or from 0.05% up
to less than or equal to about 20%, or from 0.1% up to less than or
equal to about 15%.
[0024] The non-metallic crosslinker may comprise a polylactam.
Polylactams include any oligomer or polymer having pendent lactam
(cyclic amide) functionality. Polylactams may be homopolymers,
copolymers, block-copolymers, grafted polymers, or any combination
thereof comprising from 3 to 20 carbon atoms in the lactam
functional group pendent to the polymer backbone. Examples include
polyalkyl-beta lactams, polyalkyl-gamma lactams, polyalkyl-delta
lactams, polyalkyl-epsilon lactams, polyalkylene-beta lactams,
polyalkylene-gamma lactams, polyalkylene-delta lactams,
polyalkylene-epsilon lactams, and the like. Other examples of
polylactams include polyalkylenepyrrolidones,
polyalkylenecaprolactams, polymers comprising Vince lactam
(2-azabicyclo[2.2.1]hept-5-en-3-one), decyl lactam, undecyl lactam,
lauryl lactam, and the like. The alkyl or alkylene substituents in
these polymers may include any polymerizable substituent having
from 2 to about 20 carbon atoms, e.g., vinyl, allyl, piperylenyl,
cyclopentadienyl, or the like. The non-metallic crosslinker may be
polyvinylpyrrolidone, polyvinylcaprolactam, or a combination
thereof. In the present disclosure, polyvinylpyrrolidone may have a
weight average molecular weight higher than or equal to about
10,000 g/mol and less than or equal to about 2 million g/mol, or
higher than or equal to 50,000 g/mol and less than or equal to
about 2 million g/mol.
[0025] Once crosslinking occurs, the process fluid may become a
gel.
[0026] The process fluid may have an initial pH between about 3 and
about 9. Accordingly, the process fluid may further comprise a
pH-adjusting agent that causes the fluid pH to fall below 3 or rise
above 9. Such agents may comprise a base, an acid, a pH buffer, or
any combination thereof. Such agents may comprise an alkali metal
hydroxide, magnesium oxide, sodium carbonate, sulfuric acid, an
organic acid, carbon dioxide or a combination thereof.
[0027] The Applicant has determined that the disclosed
polyacrylamide process fluids have utility in the context of plug
cementing. The process fluids may form gels with sufficient
strength to support a cement plug and prevent contamination of the
plug by other wellbore fluids.
[0028] An aqueous process fluid may be prepared that comprises at
least 1 wt % polyacrylamide and a non-metallic crosslinker. The
fluid may then be pumped downhole, whereupon the polyacrylamide
crosslinks and forms a support for a cement plug. To facilitate gel
development, the process fluid may further comprise a pH adjustment
material in an amount such that the pH of the
polyacrylamide-crossliker formulation is higher than or equal to 11
or lower than or equal to 1. Suitable pH adjustment materials may
comprise alkali metal hydroxides, magnesium oxide, sodium
carbonate, sulfuric acid, an organic acid, carbon dioxide and other
such materials well known in the art. The process fluid may be
water-base, oil-base, a water-in-oil emulsion or an oil-in-water
emulsion.
[0029] The rate at which the crosslinking reaction proceeds may be
controlled. For example, the polyacrylamide and non-metallic
crosslinker may be placed downhole in separate streams. The streams
may commingle in the wellbore and crosslinking commences, forming
the support. Another technique may be to prepare the crosslinked
polyacrylamide gel in advance and freeze dry the gel. The
freeze-dried gel may then be incorporated into the process fluid
and placed into the well. At this point, formation water may
hydrate the freeze-dried gel particles, thereby forming the
support. One may control the rate at which the freeze-dried gel
dissolves and hydrates by varying the particle size of the gel
particles. In yet another technique, the freeze-dried particles may
be added to an oil-base drilling fluid. When pumped into the well,
the particles may encounter formation water and may commence
hydrating and forming a support. In yet another technique, solid
polyacrylamide, non-metallic crosslinker and pH adjustment material
may be added to an oil-base process fluid. When the suspended
polyacrylamide, non-metallic crosslinker and pH adjustment material
encounter formation water, hydration and crosslinking may commence
and thereby form a support.
[0030] Yet another technique for controlling gel formation may be
to partition the polyacrylamide, non-metallic crosslinker and pH
adjustment material in different phases of an emulsion process
fluid. The process fluid may be an oil-in-water emulsion or a
water-in-oil emulsion. For example, the pH adjustment material may
dissolved in the aqueous phase and the other ingredients dispersed
in the oil phase. Those skilled in the art will appreciate that any
arrangement of the ingredients may be effective, as long as one of
them is in a phase that is different than the other two. The
Applicant envisions several techniques by which the emulsions may
be destabilized, thereby triggering the crosslinking reaction. One
technique may be to design the emulsion such that it becomes
unstable upon contact with formation water in the well. Another
technique may be to design the emulsion such that it becomes
unstable upon exposure to shear--for example the shear provided by
pumping the emulsion through a drill bit. Destabilization of the
emulsion may cause the ingredients to commingle, thereby initiating
the crosslinking reaction. Yet another technique may be to
encapsulate one or more of the ingredients, and incorporate the
capsules in the process fluid. The capsule coating may be degraded
inside the wellbore by, for example, exposure to heat, pressure,
formation water or other changes in chemical environment known in
the art. The coating may also be degraded by, for example, exposure
to shear, ultrasonic vibration, x-ray or gamma-ray irradiation,
microwave irradiation or other electromechanical stimuli known in
the art.
[0031] For all of the techniques described above, the efficiency of
plug-support formation may be enhanced by including solid additives
in the process fluid. The solids may comprise granular, lamellar
and fibrous substances. Granular materials may comprise nutshells,
plastic beads, limestone particles, sulfur particles, expanded
perlite or cottonseed hulls and combinations thereof. The particle
size of the granular materials may be between about 10 .mu.m and
10,000 .mu.m, or may be between about 100 .mu.m and 1000 .mu.m The
concentration of the granular materials may vary between about 2.85
kg/m.sup.3 and 428 kg/m.sup.3 (1 lbm/bbl and 150 lbm/bbl), or may
vary between about 28.5 kg/m.sup.3 and 342 kg/m.sup.3 (10 lbm/bbl
and 120 lbm/bbl). Lamellar materials may comprise cellophane
flakes, polyester flakes or mica or combinations thereof. The flake
size may vary between about 6 mm.times.6 mm and about 25
mm.times.25 mm, or may vary between about 13 mm.times.13 mm and
about 19 mm.times.19 mm. The concentration of the lamellar
materials may vary from about 2.85 kg/m.sup.3 and 28.5 kg/m.sup.3
(1 lbm/bbl and 10 lbm/bbl), or may vary between about 14.3
kg/m.sup.3 and 22.8 kg/m.sup.3 (5 lbm/bbl and 8 lbm/bbl). The
flakes need not necessarily have a square profile. Fibrous
materials may comprise sawdust, prairie hay, tree bark, shredded
wood, glass fibers, carbon fibers, nylon fibers, polyvinylalcohol
fibers, polylactic acid fibers, polyvinylchloride fibers,
polyethylene fibers, or polyurethane fibers or combinations
thereof. The fiber length may vary between about 1 mm and about 15
mm, or between about 5 mm and 10 mm. The fiber concentration may
vary between about 28.5 kg/m.sup.3 and about 171 kg/m.sup.3 (10
lbm/bbl and 60 lbm/bbl), or may vary from about 57 kg/m.sup.3 and
about 128 kg/m.sup.3 (20 lbm/bbl and 45 lbm/bbl). The fibers may be
linear or curved.
[0032] For all of the techniques discussed above, the viscosities
of the process fluids before crosslinking may be within the
pumpable range; i.e., lower than 1000 cP at a shear rate of 1000
s.sup.-1.
[0033] Those skilled in the art will recognize that the formation
of cement-plug supports envisioned by the Applicant is not
necessarily limited to the techniques described above.
[0034] In an aspect, embodiments relate to methods for setting a
cement plug in a subterranean wellbore. A process fluid composition
is prepared that comprises at least 1 wt % polyacrylamide and a
non-metallic crosslinker. The composition is placed in the wellbore
and allowed to crosslink and form a gel. A cement slurry is
prepared and placed in the wellbore such that is rests on top of
the gel, thereby forming the plug.
[0035] In a further aspect, embodiments relate to methods for
treating a subterranean wellbore. A process fluid composition is
prepared that comprises at least 1 wt % polyacrylamide and a
non-metallic crosslinker. The composition is placed in the wellbore
and allowed to crosslink and form a gel. A cement slurry is
prepared and placed in the wellbore such that is rests on top of
the gel, thereby forming the plug. The molecular weight of the
polyacrylamide may be between about 10,000 g/mol and 20 million
g/mol.
[0036] Those skilled in the art will also recognize that the
process fluid may further comprise one or more viscosifiers. Some
non-limiting examples of viscosifiers include (but are not limited
to) hydratable gels (e.g. guars, poly-saccharides, xanthan,
hydroxy-ethyl-cellulose, etc.), a crosslinked hydratable gel, a
viscosified acid (e.g. gel-based), an emulsified acid (e.g. oil
outer phase), an energized fluid (e.g. an N.sub.2 or CO.sub.2 based
foam) and viscoelastic surfactants (VES). Additionally, the carrier
fluid may be a brine, and/or may include a brine.
[0037] The VES may be selected from the group consisting of
cationic, anionic, zwitterionic, amphoteric, nonionic and
combinations thereof. The viscoelastic surfactants, when used alone
or in combination, are capable of forming micelles that form a
structure in an aqueous environment that contribute to the
increased viscosity of the fluid (also referred to as "viscosifying
micelles"). These fluids are normally prepared by mixing in
appropriate amounts of VES suitable to achieve the desired
viscosity. The viscosity of VES fluids may be attributed to the
three dimensional structure formed by the components in the fluids.
When the concentration of surfactants in a viscoelastic fluid
significantly exceeds a critical concentration, and in most cases
in the presence of an electrolyte, surfactant molecules aggregate
into species such as micelles, which can interact to form a network
exhibiting viscous and elastic behavior.
[0038] A zwitterionic surfactant of the family of betaines may be
used. Exemplary cationic viscoelastic surfactants include amine
salts and quaternary ammonium salts. Exemplary amphoteric
viscoelastic surfactant systems include for example amine oxides
and amidoamine oxides. Mixtures of zwitterionic surfactants and
amphoteric surfactants are suitable. An example is a mixture of
about 13% isopropanol, about 5% 1-butanol, about 15% ethylene
glycol monobutyl ether, about 4% sodium chloride, about 30% water,
about 30% cocoamidopropyl betaine, and about 2%
cocoamidopropylamine oxide. Suitable anionic surfactants include
alkyl sarcosinates.
[0039] The process fluid may optionally further comprise additional
additives, including weighting agents, fluid loss control
additives, gas migration control additives, colloidal-size
minerals, corrosion inhibitors, scale inhibitors, catalysts, clay
control agents, biocides, friction reducers and combinations
thereof and the like. Suitable weighting agents may include silica,
barite, hematite, ilmenite or manganese tetraoxide or combinations
thereof.
[0040] The process fluid may further comprise sodium chloride,
potassium chloride, calcium chloride, calcium bromide, zinc
bromide, sodium formate, potassium formate or cesium formate or
combinations thereof.
[0041] The placement method may incorporate a variety of techniques
known to those skilled in the art. For example, coiled tubing,
casing or drillpipe may be used to convey the process fluid into
the well. Or, the process fluid may be conveyed to the lost
circulation zone by a dump bailer.
[0042] The placement method may also incorporate the use of pre-
and post-flushes. For example, a high-pH (e.g., >9) or
neutral-pH fluid may be pumped ahead of or behind the disclosed
process fluids, or both. Such a technique may help prevent the
process fluid from flowing into permeable formations, and confine
the process fluid to wellbore region.
EXAMPLES
[0043] The following examples serve to better illustrate the
present disclosure. All examples employ process fluids comprising
the following ingredients: (1) partially hydrolyzed (10%)
polyacrylamide with a molecular weight of about 5 million,
MAGNAFLOC 24 available from Ciba Specialty Chemicals; (2)
polyvinylpyrrolidone with a molecular weight of 55,000, available
from Aldrich Chemicals; and sodium hydroxide. The following aqueous
fluid formulation was used in all of the examples: 3 wt %
polyacrylamide, 6 wt % polyvinylpyrrolidone and sufficient NaOH to
achieve a fluid pH between 11 and 12. The polyacrylamide and
polyvinylpyrrolidone were prehydrated in water before adjusting the
pH.
Example 1
[0044] The aforementioned polyacrylamide/polyvinylpyrrolidone
(PAM/PVP) composition at pH 12 was prepared and placed in a series
of glass jars. Various volumes of cement slurry were then poured on
top of the gels, thereby varying the hydrostatic pressure or stress
on the gels. The slurry was neat Class G cement+44% water by weight
of cement. Visual observations of the effects are summarized in
Table 1.
TABLE-US-00001 TABLE 1 Ability of PAM/PVP Composition to Support
Cement Slurry Column. Cement Slurry Jar Diameter Induced Stress (g)
(mm) (kPa) Remarks 40 44 0.26 Gel sufficiently strong. 80 44 0.52
Gel sufficiently strong. 120 44 0.77 Gel sufficiently strong. 160
44 1.03 Gel sufficiently strong. 300 56 1.19 Gel sufficiently
strong. 60 23.5 1.36 Gel sufficiently strong. 20 26 4.06 Gel
sufficiently strong.
[0045] In all cases, the gel was able to support the cement column
No commingling was observed. The cement slurry also set in all
cases, indicating the presence of the gel did not disrupt the
cement-setting process.
Example 2
[0046] This example was similar to Example 1, except that the
fluids were placed in 2.54-cm (1-in) diameter clear plastic tubing
instead of jars. In addition, the effects of a water-base and an
oil-base drilling fluid were investigated. The water-base drilling
fluid, prepared by MI-Swaco, comprised water, barite, polymers and
REV DUST (available from MI-Swaco). The fluid density was 1170
kg/m.sup.3. The oil-base mud, prepared by MI-Swaco, was a
water-in-oil emulsion comprising water, oil, barite, calcium
chloride and polymers. The fluid density was 1900 kg/m.sup.3. The
previously described PAM/PVP gels were prepared at pH 12 and
transferred to the tubing. Cement slurry was placed above them.
When present, the drilling fluid was placed below the gel. Three
tests were performed:
[0047] 1. 50 g gel; 500 g cement slurry
[0048] 2. 50 g gel; 400 g cement slurry; 50 g water-base drilling
fluid
[0049] 3. 50 g gel; 400 g cement slurry; 50 g oil-base drilling
fluid
[0050] In all three cases, the gel supported the cement slurry. In
cases when drilling fluid was present, the gel did not commingle
with the drilling fluid. After aging overnight, the cement slurry
set normally.
Example 3
[0051] Experiments were performed to investigate the compatibility
of the PAM/PVP gel with a water-base drilling fluid and an oil-base
drilling fluid. The gel was mixed with the drilling fluids in the
following ratios: 10 wt % drilling fluid; 30 wt % drilling fluid;
50 wt % drilling fluid; 100 wt % drilling fluid; and 200 wt %
drilling fluid. Complex viscosities were measured by placing the
mixtures in a Bohlin rheometer.
[0052] As shown in FIGS. 2 and 3, the complex viscosity steadily
decreased with the drilling fluid concentration. No precipitous
loss of viscosity was observed.
[0053] In addition to the rheology measurements, tubing experiments
similar to those described in Example 2 were performed. This time
the PAM/PVP gel was pre-mixed with either 20 wt % water-base
drilling fluid or 20% oil-base drilling fluid. In both cases, the
gel was still able to support the cement-slurry column.
Example 4
[0054] Experiments were performed that are similar to those
described in
[0055] Example 2. However, this time the PAM/PVP gel was prepared
in a saturated potassium formate brine instead of fresh water. The
brine density was 2180 kg/m.sup.3 (18.2 lbm/gal). In addition, the
PAM and PVP were not prehydrated in the brine; instead, they were
added as solids to form a suspension.
[0056] Three tests were performed:
[0057] 1. 110 g gel; 400 g cement slurry
[0058] 2. 110 g gel; 400 g cement slurry; 50 g water-base drilling
fluid
[0059] 3. 110 g gel; 400 g cement slurry; 50 g oil-base drilling
fluid
[0060] In all three cases, the gel supported the cement slurry. In
cases when drilling fluid was present, the gel did not commingle
with the drilling fluid. After aging overnight, the cement slurry
set normally.
[0061] Additional tests were performed with gels that were
contaminated with 20 wt % of water-base or oil-base drilling fluid.
In both cases, the gel was still able to support the cement-slurry
column
[0062] Although various embodiments have been described with
respect to enabling disclosures, it is to be understood that the
preceding information is not limited to the disclosed embodiments.
Variations and modifications that would occur to one of skill in
the art upon reading the specification are also within the scope of
the disclosure, which is defined in the appended claims.
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