U.S. patent application number 10/990213 was filed with the patent office on 2005-06-16 for method and composition for the triggered release of polymer-degrading agents for oil field use.
Invention is credited to Ballard, David A., Freeman, Michael A., Jiang, Ping, Mistry, Kishor Kumar, Norman, Monica, Symes, Kenneth C..
Application Number | 20050130845 10/990213 |
Document ID | / |
Family ID | 33422513 |
Filed Date | 2005-06-16 |
United States Patent
Application |
20050130845 |
Kind Code |
A1 |
Freeman, Michael A. ; et
al. |
June 16, 2005 |
Method and composition for the triggered release of
polymer-degrading agents for oil field use
Abstract
Disclosed are methods and related compositions for altering the
physical and chemical properties of a substrate used in hydrocarbon
exploitation, such as in downhole drilling operations. In a
preferred embodiment a method involves formulating a fluid,
tailored to the specific drilling conditions, that contains one or
more inactivated enzymes. Preferably the enzyme is inactivated by
encapsulation in a pH responsive material. After the fluid has been
introduced into the well bore, one or more triggering signals, such
as a change in pH, is applied to the fluid that will activate or
reactivate the inactivated enzyme, preferably by causing it to be
released by the encapsulation material. The reactivated enzyme is
capable of selectively acting upon a substrate located downhole to
bring about the desired change in the chemical or physical
properties of the substrate.
Inventors: |
Freeman, Michael A.;
(Kingwood, TX) ; Norman, Monica; (Houston, TX)
; Ballard, David A.; (Stonehaven, GB) ; Jiang,
Ping; (Sandnes, NO) ; Symes, Kenneth C.; (East
Morton, GB) ; Mistry, Kishor Kumar; (Bradford,
GB) |
Correspondence
Address: |
CARTER J. WHITE LEGAL DEPARTMENT
M-I L.L.C.
5950 NORTH COURSE DRIVE
HOUSTON
TX
77072
US
|
Family ID: |
33422513 |
Appl. No.: |
10/990213 |
Filed: |
November 16, 2004 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10990213 |
Nov 16, 2004 |
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09711655 |
Nov 13, 2000 |
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6818594 |
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60165393 |
Nov 12, 1999 |
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Current U.S.
Class: |
507/100 ;
507/200 |
Current CPC
Class: |
Y10S 507/902 20130101;
C09K 8/665 20130101; C09K 8/536 20130101; C09K 8/68 20130101; Y10S
507/922 20130101; C09K 8/92 20130101; Y10S 507/921 20130101 |
Class at
Publication: |
507/100 ;
507/200 |
International
Class: |
E21B 043/00 |
Claims
1-49. (canceled)
50. A composition for use in hydrocarbon exploitation operations,
the composition comprising a fluid or solid device containing: at
least one degradable substrate; and an encapsulated
substrate-degrading agent, said encapsulated agent being capable of
responding to a triggering signal such that said agent becomes
sufficiently unecapsulated to allow said agent to degrade said
substrate under degradation promoting conditions such that a
physical or chemical property of the substrate is altered.
51-52. (canceled)
53. The composition of claim 50 wherein said triggering signal
comprises a change in pH of a medium contacting said encapsulated
agent.
54-85. (canceled)
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 60/165,393 filed Nov. 12, 1999.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention generally relates to compositions and
methods used for hydrocarbon exploitation such as in the drilling
of and production from wells, especially oil and gas wells. More
particularly, the invention relates to such compositions and
methods which alter the physical or chemical properties of a
polymeric component of an oil field fluid or residue, such as
decomposing a polymeric viscosifier or fluid loss control agent
contained in such fluid or residue in response to a defined
chemical or physical signal.
[0004] 2. Description of Related Art
[0005] The selection of materials for well construction is
essential to the successful completion of an oil or gas well. Among
the most important is the selection of a drilling fluid. A drilling
fluid having the desired properties is passed down through the
drill pipe, out a nozzle at the drill bit, and returned to the
surface through an annular portion of the well bore. The drilling
fluid primarily fimctions to remove cuttings from the bore hole;
lubricate, cool and clean the drill bit; reduce friction between
the drilling string and the sides of the bore hole; maintain
stability of the bore hole; prevent the inflow of fluids from
permeable rock formations; and provide information on downhole
conditions. The composition of a drilling fluid is carefully
selected to optimize production within the vast diversity of
geological formations and environmental conditions encountered in
oil and gas recovery. At the same time, the fluid should not
present a risk to personnel, drilling equipment, or the
environment.
[0006] Drilling fluids may be water, oil, synthetic, or gas based.
The composition is typically tailor-made to specific drilling
conditions, varying in size and distribution of suspended
particles, density, temperature, pH, pressure, salt concentration,
alkalinity, electrical conductivity, lubricity, and corrosivity,
all of which may be influenced by the surrounding geological
formations. Further explanation of the properties of fluids useful
in the recovery of oil and gas may be obtained from a review of the
publication, H. C. H. DARLEY & GEORGE R. GRAY, COMPOSITION AND
PROPERTIES OF DRILLING AND COMPLETION FLUIDS 1-37 (5.sup.th ed.
1988); and CHILINGARIAN, ET AL., DRILLING AND DRILLING FLUIDS,
DEVELOPMENTS IN PETROLEUM SCIENCE 11 (1981).
[0007] Water-based drilling fluids, or muds, may consist of
polymers, biopolymers, clays and organic colloids added to an
aqueous based fluid to obtain the required viscous and filtration
properties. Heavy minerals, such as barite or calcium carbonate,
may be added to increase density. Solids from the formation are
incorporated into the mud and often become dispersed in the mud as
a consequence of drilling. Further, drilling muds may contain one
or more natural and/or synthetic polymeric additives, including
polymeric additives that increase the Theological properties (e.g.,
plastic viscosity, yield point value, gel strength) of the drilling
mud, and polymeric thinners and flocculents.
[0008] Polymeric additives included in the drilling fluid may act
as fluid loss control agents. Fluid loss control agents, such as
starch, prevent the loss of fluid to the surrounding formation by
reducing the permeability of filter cakes formed on the newly
exposed rock surface. In addition, polymeric additives are employed
to impart sufficient carrying capacity and thixotropy to the mud to
enable the mud to transport the cuttings up to the surface and to
prevent the cuttings from settling out of the mud when circulation
is interrupted.
[0009] Most of the polymeric additives employed in drilling mud are
resistant to biodegration, extending the utility of the additives
for the useful life of the mud. Specific examples of biodegradation
resistant polymeric additives employed include biopolymers- such as
xanthans (xanthan gum) and scleroglucan; various acrylic based
polymers, such as polyacrylamides and other acrylamide based
polymers; and cellulose derivatives, such as
dialkylcarboxymethylcellulose, hydroxyethylcellulose and the sodium
salt of carboxy-methylcellulose, chemically modified starches, guar
gum, phosphomannans, scleroglucans, glucans, and dextrane. See U.S.
Pat. No. 5,165,477, which is incorporated herein by reference.
[0010] Most drilling fluids are designed to form a thin,
low-permeability filter cake to seal permeable formations
penetrated by the bit. This is essential to prevent both the loss
of fluids to the formation and the influx of fluids that may be
present in the formation. Filter cakes often comprise bridging
particles, cuttings created by the drilling process, polymeric
additives, and precipitates.
[0011] For a filter cake to form, it is important that the mud
contain bridging particles, particles of a size selected to seal
the pore openings in the formation. While finer particles may be
carried deeper into a formation, bridging particles are trapped in
the surface pores, and form the foundation for the filter cake. The
bridged zone in the surface pores begins to trap successively
smaller particles, and fluids interchange until an essentially
impenetrable barrier is formed.
[0012] The formation of a filter cake seal is fostered by an
imbalance of pressure of the mud column over the pressure exerted
by fluids within the formation. It is recommended that drilling
fluid pressure exceed the pressure exerted by fluids in the pores
of the formation by about 200 psi. Pore pressure depends on the
depth of the formation, the density of the pore fluids, and
geological conditions. Similarly, the outward pressure exerted by
the drilling fluid is a function of the density of the drilling
fluid and the depth of the formation in question.
[0013] Since the outward pressure of the mud column is usually
greater than the pressure exerted by the pore formation, it is also
a primary function of the filter cake to prevent drilling fluid
from continuously permeating into formations surrounding the well
bore. The permeability of the filter cake is dependent upon
particle distribution and size, in addition to electrochemical
conditions of the mud. The composition of the drilling fluid can be
adjusted to increase or decrease permeability, for example, by
adding soluble salts, or increasing the number of particles in the
colloidal size range. Fluid from the mud which permeates the
barrier is known as filtrate. The probability of successful
completion of a well may depend, in large part, upon the filtration
properties of the mud being matched to the geological formations,
and the composition of the filtrate. For further explanation of the
properties and formation of filter cakes, see H. C. H. Darley and
George R. Gray, COMPOSITION AND PROPERTIES OF DRILLING AND
COMPLETION FLUIDS, (5.sup.th ed., 1988).
[0014] Although filter cake formation is essential to drilling
operations, the filter cake can be a significant impediment to the
production of hydrocarbon or other fluids from the well. Damage to
producing formations can occur by directly plugging the surface of
the rock, M. J. Economides, et al., PETROLEUM WELL CONSTRUCTION,
John Wiley and Sons, N.Y., 1988, p.121, or indirectly by plugging
the hardware placed in the well. Ladva, H. K. J., et al.,
"Mechanisms of Sand Control Screen Plugging From Drill-In Fluids
and its Cleanup Using Acid, Oxidizers and Enzyme Breakers," SPE
39439 (Feb. 18, 1998). Removal of the blockage presented by the
filter cake may be essential to the commercial viability of the
well. Many methods are used to remove filter cake damage, including
concentrated acids, strong oxidizers, chelating agents and enzymes.
Because enzymes are highly specific, they do not react or degrade
the materials commonly found within a subterranean formation or
used in well bore operations, such as limestone, iron, resin coated
proppants, tubings and the like. This makes enzymes an excellent
candidate to destroy the filter cake without harming the completion
hardware or personnel.
[0015] As disclosed by U.S. Pat. No. 5,247,995 ("the '995 patent"),
incorporated herein by reference, the permeability of a formation
may be assessed in a laboratory. One procedure of assessing the
permeability measures the flow of a fluid through a damaged
formation sample at a given rate and pressure. As reported, a
completely broken filter cake regains greater than about 95% of the
initial permeability of a formation sample using a damage
permeability test, while a plugged formation has about 30% of the
initial permeability, depending on the fluid, core and conditions.
A second procedure assesses the retained conductivity of the
formation. As reported, a plugged formation has retained
conductivity of less than 10%, depending on the conditions.
[0016] Therefore, removal of the filter cake is necessary to
increase flow of production fluids from the formation. Since filter
cake is compacted and often adheres strongly to the formation, it
may not be readily or completely flushed out of the formation by
fluid action alone. Removal of the filter cake often requires some
additional treatment. Common oxidants, for example, persulfates,
may be used to remove filter cake. As the '995 patent disclosed,
however, oxidants are ineffective at low temperature ranges, from
ambient temperature to 130.degree. F, As reported, in this
temperature range the oxidants are stable and do not readily
undergo homolytic cleavage to initiate the degradation of the
filter cake. Cleavage is typically achieved at lower temperatures
only by using high concentrations of oxidizers. High oxidizer
concentrations are frequently poorly soluble under the treatment
conditions.
[0017] Reactions involving common oxidants are also often difficult
to control. Oxidants tend to react with many things other than
their intended target. For example, oxidants can react with iron
found in the formation, producing iron oxides that precipitate and
damage the formation, decreasing permeability. Oxidants can also
react non-specifically with other materials used in the oil
industry, for example, tubings, linings and resin coated
proppants.
[0018] Further, to completely remove the filter cake after treating
with oxidants, additional treatment may be required. An extra acid
hydrolysis step may be necessary to remove any residue. Treatment
with an acid, for example, hydrochloric acid, augments the removal
of excess residue. Acid treatments, however, corrode steel and
equipment used in the operation. Acid treatments may also be
incompatible with the formation and/or its fluids.
[0019] Residues, such as filter cakes, can also present
difficulties during drilling operations. For example, in permeable
formations, filtration properties must be controlled to prevent
thick filter cakes from excessively reducing the gauge of the
borehole. Further, poor filter cakes may cause the drill pipe to
become stuck, known as "differential sticking." Helmick and
Longley, "Pressure-Differential Sticking of Drill Pipe and How it
Can Be Avoided or Relieved," API Drill. Prod. Prac. (1957).
pp.55-60; Outmans, H. D., "Mechanics of Differential-Pressure
Sticking of Drill Collars," Trans. AIME, Vol. 213 (1958).
pp.265-274. This occurs when part of the drill string bears against
the side of the hole while drilling, and erodes away part of the
filter cake. When rotation of the pipe is stopped, the part of the
pipe in contact with the cake is isolated from the pressure of the
mud column, and is subject only to the pore pressure of the filter
cake. The differential pressure thus created causes drag which can
be sufficient to prevent the pipe from being moved. Sometimes, the
pipe can be freed by spotting oil around the stuck section, but if
this procedure fails, more expensive and time consuming methods are
entailed (H. C. H. DARLEY & GEORGE R. GRAY, COMPOSITION AND
PROPERTIES OF DRILLING AND COMPLETION FLUIDS 405-11 (5.sup.th ed.
1988)).
[0020] In addition, drilling fluid residues remaining in the well
tend to interfere with other phases of drilling and completion
operations such as cementing the casing to the wall of the bore.
Filter cake and residual mud can prevent casing cement from
properly bonding to the wall of the bore. The trajectory of a well
bore may be tortuous, and the wall of the bore often has various
ledges and cavities therein which contain thixotropic drilling mud.
The drilling mud in contact with the bore wall is quiescent while
the casing is lowered into the bore and tends to gel. When
circulation is resumed, the fluid pumped through the casing and up
through the annulus between the casing and the bore wall makes
paths or channels or even bypasses the "gelled" mud contained by
the ledges and cavities.
[0021] Thus, cement pumped through the casing and up through the
annulus to cement the casing to the bore wall flows through the
paths or channels in the mud leaving large pockets of mud between
the casing and the bore wall. These pockets can ultimately result
in fluid communication with formation zones that the cement is
supposed to isolate.
[0022] In an attempt to solve the above-noted problem, special
fluids are often circulated through the annulus between the casing
and the wall of the bore before the casing is cemented to remove
mud remaining therein. Unfortunately, this procedure, often
referred to as a "spacer" flush, is inadequate in many
applications. Conventional flushing fluids are not always capable
of sufficiently decreasing the gel strength, viscosity and other
rheological properties of the mud caused by polymeric additives
therein. As a result, the mud cannot be flushed out of the well.
Instead, expensive squeeze cementing operations are carried out to
fill in the gaps in the cement caused by the mud. For example, see
U.S. Pat. No. 5,165,477, incorporated herein by reference.
[0023] Enzymes are a class of proteins that are responsible for
catalyzing almost every chemical reaction that occurs in living
organisms. They are characterized by two remarkable qualities: (1)
to act as catalysts, often increasing the rate of a chemical
reaction by as much as 10.sup.6-10.sup.12 times that of an
uncatalyzed reaction; and (2) their high degree of specificity, the
ability to act selectively on one substance or a small number of
chemically similar substances. As a catalyst, enzyme structure
remains unaltered as a result of reaction with the substrate, thus,
the enzyme may initiate another reaction, and so on. However, as
nature's catalysts, enzymes are usually only active within the
range of conditions, particularly pH, temperature, and aqueous
solvents, found within the cells from which they are isolated.
While the range of environmental conditions in which living
organisms exist is quite broad, this presents a major distinction
between enzymes and other chemical catalysts, such as charcoal and
platinum, which often require much higher temperatures and more
extreme pH conditions than most enzymes. For a more detailed
discussion of the properties of enzymes, see LODISH, ET AL.,
MOLECULAR CELL BIOLOGY, 75-86 (3d ed. 1995).
[0024] It has been reported in the literature that enzymes can be
used to degrade drilling fluid residues. For example, Hanssen, et
al., "New Enzyme Process for Downhole Cleanup of Reservoir Drilling
Filter cake" SPE 50709 (1999) describes experimental work towards
the use of enzymes for downhole cleanup of filter cakes produced by
water-based drilling fluids. These experiments focused on filter
cakes containing modified starch and xanthan, applying thermostable
.alpha.-amylases, and polyanionic cellulose (PAC)-based fluids
using cellulase enzymes. As reported, these enzymes are shown to be
highly effective in degrading starch/xanthan and PAC/xanthan
water-based drilling fluids and their filter cakes in the
laboratory.
[0025] Hanssen, et al., disclosed the properties of several enzymes
and filter cake components as follows:
[0026] All starches are mixtures of amylose, a linear
polysaccharide, and the related but branched amylopectin, in a
ratio dependent on its natural source (corn, potatoes, and other
crops). Molecular weight also varies with the source, but is
typically very high: 10.sup.5-10.sup.9 corresponding to approx.
500-5000 monomer units. Chemically modified starches may have
hydroxyethyl or hydroxypropyl side-chain substituents on an
unchanged backbone. Modified and crosslinked starches may be as
large as 30.mu. in size.
[0027] An .alpha.-amylase enzyme is reported to hydrolyze the
.alpha.-1,4 glycosidic bonds characteristic of the starch backbone
to water-soluble oligosaccharides of 2 to 10 sugar units. It is
indicated that the reaction occurs by attachment of the active site
in the enzyme to an .alpha.-1,4 bond in the polymer molecule where
hydrolysis can occur, forming an enzyme-substrate complex, followed
by "clipping" of the bond. This reaction continues on and on again,
causing the degradation of the polymer chain. These enzymes
typically have molecular weights on the order of 25-75,000 and
diameters of 5-10 nm. Hence, amylases are smaller than the
polysaccharides they destroy, but have a very different shape.
[0028] Cellulase enzymes are similarly reported as specific for the
bonds in cellulose polymers. Here the .beta.-(1,4) bonds
characteristic of this polysaccharide are broken down.
Carboxymethyl celluloses (CMC's) and polyanionic celluloses (PAC's)
in general, with hydrophilic side chains, were also degraded by the
cellulases reported in the Hanssen, et al., study.
[0029] In addition to their conclusions as to the potential of
enzymes in oil production, Hanssen, et al., disclosed two
experimental methods which allow for rapid, repeatable and
consistent selection and development of enzyme products for
application in the field, including (1) a visual filter cake
degradation test for screening of treatment fluid, and (2)
filtration tests for quantitative evaluation of enzyme
activity.
[0030] Others have also described the useful properties of enzymes.
U.S. Pat. No. 5,126,051, and U.S. Pat. No. 5,165,477, both of which
are incorporated herein by reference, disclose the use of enzymes
for (1) cleaning up a well site drilling mud pit containing
drilling mud comprising polymeric organic viscosifiers; and (2)
removing used drilling mud comprising a polymeric organic
viscosifier from a wellbore. In the downhole application of this
invention, a fluid comprising one or more enzymes capable of
rapidly degrading the polymeric organic component of the drilling
fluid is injected into the well. The enzymes degrade the organic
polymeric viscosifier, allowing the drilling fluid residues to
disperse within a wash fluid, which can then be recovered from the
well. As disclosed, the enzymes contained within the fluid wash
must rapidly decompose the drilling mud in contact with the
wellbore before they are rendered inactive by harsh downhole
conditions. As reported, laboratory tests conducted using five
different enzymes illustrated that enzymes can be effectively used
at low concentrations to rapidly degrade polymeric organic
viscosifiers of the type used in drilling muds.
[0031] Further, U.S. Pat. No. 5,247,995 ("the '995 patent"),
incorporated herein by reference, discloses a method of degrading
damaging polysaccharide-containing filter cakes, produced from
fracturing fluids, and other damaging fluids using enzymes specific
to those polysaccharides. The method consists of pumping an enzyme
treatment to a desired location within the well bore to coat the
filter cake, degrading the polysaccharide containing filter cake,
and removing the degraded filter cake, thus increasing the
permeability of the formation.
[0032] Specifically, the '995 patent describes suitable hydratable
polysaccharides such as the galactomannan gums, guars, derivatized
guars, cellulose and cellulose derivatives. Specific examples
disclosed are guar gum, guar gum derivatives, locust bean gum,
caraya gum, xanthan gum, cellulose, and cellulose derivatives.
Further, the invention of the '995 patent describes various other
suitable polysaccharides used in the oil industry, such as starch
and starch derivatives, which thicken fluids and control fluid
loss.
[0033] The method of the '995 patent for treating guar-containing
filter cakes comprises using enzymes that are hydrolases. As
reported, the enzyme hydrolases are stable in the pH range of about
2.0 to 11.0 and remain active at both acid and alkaline pH ranges
of about 2.0 to 10.0. These same enzymes were reported as active at
low to moderate temperatures of about 50.degree. F. to about
195.degree. F. As disclosed, for the preferred method of the '995
patent, the pH range is 3 to 7 at a temperature range of about
80.degree. F. to 195.degree. F. At temperatures of above about
125.degree. F., the preferable pH ranges from about 3 to 5.
[0034] As disclosed, the enzymes are specific to attack the
mannosidic and galactomannosidic linkages in the guar residue,
breaking the molecules into monosaccharide and disaccharide
fragments. Under some conditions, these enzymes hydrolyze the
residue completely into monosaccharide fragments. The preferred
enzymes for the guar-containing filter cake are galactomannan
hydrolases collectively called galactomannanase and they
specifically hydrolyze the (1,6)-.alpha.-D-galactomannosidic and
the (1,4)-.beta.-D-mannosidic linkages between the monosaccharide
units in the guar-containing filter cake respectively.
[0035] The method of the '995 patent also consists of removing
cellulose-containing filter cakes using hydrolase enzymes which
differ from the enzymes for the guar-containing filter cake. As
reported, these enzymes are active in the pH range of about 1.0 to
8.0. The preferred pH range is about 3.0 to 5.0. These same enzymes
are active at low to moderate temperatures of about 50.degree. F.
to 140.degree. F. Most preferably for the method of the invention,
the pH is about 3.5 to 4.0.
[0036] As disclosed by the '995 patent, with a cellulose or
derivatized cellulose containing filter cake, the specific enzymes
attack the glucosidic linkages of the cellulose backbone, breaking
the backbone into fragments. Insoluble cellulose is composed of
repeating units of D-glucose joined by (1,4)-.beta.-glucosidic
linkages. The fragments are broken down into soluble D-glucose
monosaccharides. The preferred enzymes are any enzymes or
combination of enzymes that attack the glucosidic linkages of the
cellulose polymer backbone and degrade the polymer into mostly
monosaccharide units, such as cellulase, nonspecific hemicelluases,
glucosidase, endoxylanase, exo-xylanase and the like. The two
preferred enzymes are commonly called exo and endo xylanases. The
preferred enzymes for this cellulose based system specifically
hydrolyze the exo(1,4)-.beta.-D-glucosidic and the
endo(1,4)-.beta.-D-glucosidic linkages between the monosaccharide
units in the cellulose backbone and the (1,4)-.beta.-D-glucosidic
linkage of any cellobiose fragments.
[0037] Further, the method of the '995 patent for removing starch
derived filter cake consists of using enzymes that are specific for
the linkages found within the starch molecule. These enzymes are
active at the pH range of between about 2.0 to 10.0 for the
temperature range of about 50.degree. F. to 230.degree. F.
[0038] As described, starch, like cellulose, is a polysaccharide
formed of repeating units of D-glucose. However, the glucose
molecules are joined in an (1,4)-.alpha.-glucosidic linkage rather
than the (1,4)-.beta.-glucosidic linkage found in cellulose. Starch
contains a mixture of two polymers, amylose and amylopectin.
Amylose consists of a linear chain of D-glucose molecules bound in
.alpha.-D-(1-4) linkages. Amylopectin, the major component of the
starch polysaccharide, is a highly branched D-glucan with a
backbone of D-glucose .alpha.-D-(1-4) linkages and D-glucose side
chains connected by .alpha.-D-(1-6) linkages. To reduce the
viscosity of starch residue, such as filter cake, the preferred
enzymes digest the starch molecules until no starch is present as
determined by iodine testing. The enzymes reduce the starch into
smaller units, most likely oligosaccharide units and dextrin. This
degradation sufficiently decreases the size of the starch polymer
so as to make it soluble, removing it as component in the filter
cake. The smaller polysaccharides do not damage the formation and
often terminally degrade at higher temperatures. These enzymes or
combination of enzymes are selected from the endo-amnylases,
exo-amylases, isoamylases, glucosidases, .alpha.-glucosidases,
glucan (1,4)-.alpha.-glucosidase, glucan (1,6)-.alpha.-glucosidase,
oligo-(1,6)-glucosidase, .alpha.-glucosidase, .alpha.-dextrin
endo-(1,6)-.alpha.-glucosidase, amylo-(1,6)-glucosidase, glucan
(1,4)-.alpha.-maltotetrahydralase, glucan
(1,6)-.alpha.-isomaltosidase, glucan
(1,4)-.alpha.-maltohexaosidase, and the like.
[0039] As disclosed, the preferred enzymes are endo-amylases. The
endo-amylases randomly attack the internal .alpha.-glucosidic
linkages. There is no preferable type of endo-amylase, as the
specific endo-amylase selected varies on the conditions present in
the formation, such as pH and temperature.
[0040] Further, as disclosed, the enzyme treatment for
cellulose-containing polysaccharides can be adapted for other
polysaccharides with the cellulose backbone and side chains. The
treatment may require additional enzymes to break the side chain
linkages before effective degradation of the backbone occurs. These
enzymes are hydrolases specific to the linkages of the side
chains.
[0041] One example disclosed in the '995 patent of this type of
polysaccharide is xanthan. Enzyme treatment specific for the
xanthan polysaccharide reduces the static viscosity of the xanthan.
As described, the enzyme treatment works at a pH range between
about 2.0 and 10.0 at temperatures ranging from about 50.degree. F.
to 150.degree. F.
[0042] As described in the '995 patent, xanthan gums are
cellulose-containing, heteropolysaccharides. Xanthans contain a
cellulose backbone of (1,4)-.beta.-D-glucosidic linkages and
trisaccharide side chains on alternate residues. The trisaccharide
side chains may consist of glucuronic acid, pyruvated mannose,
mannose, and/or acetylated mannose. The method of the '995 patent
uses hydrolases which can break down the (1,4)-.beta.-D-glucosidic
linkages within the cellulose backbone. The cellulose backbone,
however, can only be broken after treating the xanthan to degrade
the trisaccharide side chains with another enzyme such as a
mannosidase. The treatment therefore requires at least two enzymes.
The enzyme treatment uses the same enzymes described above for
cellulose-containing filter cakes and mannosidase or mannan
(1,2)-.beta.-D-mannosidase, although no particular enzymes or
concentration of enzymes are currently preferred. The xanthan gum
reduces to smaller polysaccharide molecules, probably the smallest
is a tetrasaccharide. The degradation decreases the static
viscosity of the xanthan polysaccharide for easy removal. The pH
depends on the activity range of the selected enzymes and the
conditions found within the formation.
[0043] Further, U.S. Pat. No. 5,566,759, incorporated herein by
reference, discloses a mechanism for degrading cellulose-containing
fluids used during fracturing, workover and completion operations
to produce an efficacious degradation of a cellulose-containing
fluid at an alkaline pH range and higher temperatures than were
disclosed in the '995 patent, illustrating that systems can be
designed for the use of enzymes which operate outside previously
determined ranges of enzyme activity.
[0044] Methods of enzyme inactivation and encapsulation have been
reported in the context of well stimulation and fracturing
fluids.
[0045] Hydraulic fracturing is a conventional practice for
producing one or more cracks or "fractures" in a formation by
applying sufficient pressure via a fracturing fluid to cause the
mechanical breakdown of a formation. The fracturing process is
meant to increase the permeability or conductivity of the
formation, and ultimately, well productivity. Fracturing fluids are
usually a highly viscous gel emulsion or foam, suspended in which
is a proppant, such as sand or other particulate matter. The
high-viscosity of the fluid is important, generating larger
fracture volume and fracture width, and more efficiently
transporting proppant material. The purpose of the proppant is to
prevent the fracture from closing upon removal of pressure. Once
the fracture has been established, it is desirable to remove the
highly viscous fluid, allowing hydrocarbon production through the
pores between the proppant in the newly formed fracture. To
facilitate removal of the fluid, a "breaker," or viscosity-reducing
agent, is employed. The typical breakers that are used in
fracturing fluids are enzymes and oxidizers. Simply adding a
breaker to the fluid, however, is problematic; results are often
unreliable, and can lead to premature breaking of the fluid before
the fracturing process is complete, resulting in a decrease in the
number or length of fractures, and well productivity.
[0046] There have been a number of proposed methods for controlling
the activity of breakers to alleviate the above problems. For
example, U.S. Pat. No. 4,202,795, incorporated herein by reference,
discloses a method in which a breaker is combined with a hydratable
gelling agent, and a gel-degrading substance. The mixture is formed
into pills or pellets, preferably having size and range of about 20
to about 40 mesh. (U.S. Sieve Series) After combining the pellets
with an aqueous fluid into which the chemical is to be released,
the gelling agent in the pellets hydrates and forms a protective
gel around each of the pellets which prevents the release of the
chemical into the aqueous fluid for the predetermined time period
required for the protective gel to be removed by the gel-degrading
substance in the pellets. The most serious problem associated with
this system is that the breaker tends to be released over a
significant period of time due to differences in the thickness of
the protective coating and in variations of length of time and
temperature exposure of the individual pellets. A large amount of
hydratable gelling agent is typically required and the amount of
hydratable gelling agent must be monitored closely.
[0047] U.S. Pat. No. 4,506,734, incorporated herein by reference,
also provides a method for reducing the viscosity and the resulting
residue of an aqueous or oil based fluid introduced into
subterranean formation by introducing a viscosity-reducing chemical
contained within hollow or porous, crushable and fragile beads
along with a fluid, such as a hydraulic fracturing fluid, under
pressure into the subterranean formation. When the fracturing fluid
passes or leaks off into the formation, or the fluid is removed by
back flowing, the resulting fractures in the subterranean formation
close and crush the beads. The crushing of the beads then releases
the viscosity-reducing chemical into the fluid. This process is
dependent upon the closure pressure of the formation to obtain
release of the breaker and is, thus, subject to varying results
dependent upon the formation and its closure rate.
[0048] U.S. Pat. No. 4,741,401, incorporated herein by reference,
discloses a method for breaking a fracturing fluid comprised of
injecting into the subterranean formation a capsule comprising an
enclosure member containing the breaker. The enclosure member i$
sufficiently permeable to at least one fluid existing in the
subterranean environment or injected with the capsule such that the
enclosure member is capable of rupturing upon sufficient exposure
to the fluid, thereby releasing the breaker. The patent teaches
that the breaker is released from the capsule by pressure generated
within the enclosure member due solely to the fluid penetrating
into the capsule whereby the increased pressure caused the capsule
to rupture, i.e., destroys the integrity of the enclosure member,
thus releasing the breaker. This method for release of the breaker
would result in the release of substantially the total amount of
breaker contained in the capsule at one particular point in
time.
[0049] In another method to release a breaker, U.S. Pat. No.
4,770,796, incorporated herein by reference, teaches or suggests an
acid fracturing fluid composition comprising a polymer, a
crosslinking agent for said polymer, an aqueous acid and a breaker
compound capable of coordinating with titanium or zirconium
crosslinking agent. The breaker compound is encapsulated in a
composition comprising a cellulosic material, a fatty acid, and,
optionally, a wax.
[0050] Further, U.S. Pat. No. 4,919,209, incorporated herein by
reference, discloses a proposed method for breaking a fracturing
fluid. Specifically, the patent discloses a method for breaking a
gelled oil fracturing fluid for treating a subterranean formation
which comprises injecting into the formation a breaker capsule
comprising an enclosure member enveloping a breaker. The enclosure
member is sufficiently permeable to at least one fluid existing in
the formation or in the gelled oil fracturing fluid injected with
the breaker capsule, such that the enclosure member is capable of
dissolving or eroding off upon sufficient exposure to the fluid,
thereby releasing the breaker.
[0051] U.S. Pat. No. 5,102,558, incorporated herein by reference,
discloses an encapsulated breaker chemical composition for use in a
fracturing process. The capsule is described as a pinhole free
coating of a neutralized sulfonated elastomeric polymer having a
preferred thickness of about 2 to 80 microns deposited on the
surface of a breaker chemical. The neutralized sulfonated polymer
is not degraded by the breaker chemical, and is permeable to the
breaker chemical at conditions of use.
[0052] U.S. Pat. No. 5,102,559, incorporated herein by reference,
improves upon the neutralized sulfonated polymer capsule of U.S.
Pat. No. 5,102,558 by first coating the breaker with a water
soluble sealing layer, such as urea, such that the breaker is
protected from aging and is prevented from degrading the polymer
coating. Further, the seal shields the chemical from premature
release by creating a barrier to water soluble fluid
components.
[0053] Similarly, U.S. Pat. No. 5,110,486, incorporated herein by
reference, describes an encapsulated breaker composition comprising
a breaker chemical encapsulated by a pinhole free coating of an
ionically and covalently crosslinked neutralized sulfonated
elastomeric polymer. Again, the polymer is permeable to the
breaker, which is non-reactive to the polymer.
[0054] U.S. Pat. No. 5,164,099, incorporated herein by reference,
discloses a proposed method for breaking a fluid utilizing a
percarbonate, perchlorate or persulfate breaker encapsulated with a
polyamide. The polyamide membrane is permeable to at least one
fluid in the formation which dissolves the breaker and the breaker
then diffuses through the membrane to break the fracturing fluid
with the membrane staying intact during the breaker release. Thus
providing a means of slowly releasing amounts of breaker over time
instead of a single release of the total volume of the breaker from
all capsules at a given time.
[0055] U.S. Pat. No. 5,373,901, incorporated herein by reference,
discloses a method of encapsulating a breaker within a membrane
comprising a partially hydrolyzed acrylic crosslinked with either
an aziridine prepolymer or a carbodiimide. The membrane has
imperfections through which the breaker can diffuse upon contact
with an aqueous fluid. The imperfections may be created by the
incorporation of selected micron-sized particles in the membrane
coating.
[0056] U.S. Pat. No. 5,437,331, incorporated herein by reference,
discloses a polymeric particle or bead having a network of pores
with an enzyme breaker held protectively within the network to
provide a controlled time release of the enzyme. The invention is
described as having increased mechanical stability over previous
micro-encapsulated or gel delivery vehicles, which renders this
delivery system capable of being manufactured, processed, handled,
and applied under more severe conditions, such as mechanical
pumping.
[0057] U.S. Pat. No. 5,580,844, incorporated herein by reference,
provides a coated breaker chemical, in which the coating comprises
a blend of neutralized sulfonated ionomer and asphalt. Such
coatings were shown to be useful because of their water barrier
properties, their elasticity, and ability to be applied as thin
continuous coatings substantially free of pinholes. The patent
describes the capability of this encapsulation to include enzyme
breakers, and to provide controlled release of the breaker over a
period of time under conditions of use.
[0058] U.S. Pat. No. 5,591,700, incorporated herein by reference,
discloses a breaker encapsulated by a water soluble surfactant. The
surfactants proposed are waxy materials that melt and/or dissolve
into the fracturing fluids at temperatures in the subterranean
formation to be fractured. The distinguishing feature of these
surfactants is that they are solid at ambient surface conditions,
while dissolving at temperatures within the formation.
[0059] Further, U.S. Pat. No. 5,604,186, incorporated herein by
reference, describes an enzyme solution coated substrate covered
with a membrane comprising a partially hydrolyzed acrylic
crosslinked with either an azidirine prepolymer or carbodiimide.
The membrane contains imperfections through which an aqueous fluid
may pass into the breaker to contact the enzyme and diffuse the
enzyme outward from the breaker particle.
[0060] U.S. Pat. No. 5,948,735, incorporated herein by reference,
discloses an encapsulated breaker for use in oil-based fracturing
fluids. The invention describes a solid particle breaker chemical
coated with an oil degradable rubber coating, which is introduced
into an oil-based fracturing fluid, which exhibits a delayed
release of the active chemical.
[0061] As described in the previously-mentioned patents, certain
types of encapsulation can be useful to inactivate a breaker until
such time, or under such conditions, as the chemical activity is
needed to decrease viscosity of the fracturing fluid. As described
in U.S. Pat. No. 5,806,597, encapsulation has its limitations. For
instance, premature release of the enzyme payload sometimes occurs
due to product manufacturing defects, imperfections, or coating
damage experienced in pumping the particles through surface
equipment tubular and perforations.
[0062] U.S. Pat. No. 5,806,597 ("the '597 patent"), incorporated
herein by reference, proposes that rather than encapsulate the
breaker, a complex containing the breaker is maintained in a
substantially unreactive state by maintaining conditions of pH and
temperature. The complex comprises a matrix of compounds,
substantially all of which include a breaker component, a
crosslinker component, and a polymer component. Once the fracture
is completed, conditions are changed, the complex becomes active,
and the breaker begins to catalyze polymer degradation.
[0063] Further, the '597 patent discloses that the preferred
breaker components are polymer specific enzymes. These enzymes are
particularly advantageous in that they will attach to a strand of
the polymer, although inactive, and bind or stay attached to that
polymer until such time as conditions are appropriate for the
reaction to occur. The enzyme will migrate with the substrate, such
that it will be dispersed within the fluid where it is needed.
[0064] The underlying basis of this method of control is better
explained by considering conventional enzyme pathways which may be
described by the following reaction: E+S.thrfore.[ES].thrfore.E+P,
in which E is an enzyme, S is a substrate, [ES] is an intermediate
enzyme-substrate complex and P is the product of the substrate
degradation catalyzed by the enzyme. The reaction rate of the
intermediate enzyme-substrate complex is pH dependent and may be
slowed or even virtually halted by controlling the pH and
temperature of the enzyme substrate complex. Further explanation of
this process may be found in MALCOM DIXON & EDWIN C. WEBB,
ENZYMES 162 (1979).
[0065] Although the literature reflects a great deal of effort
directed at controlling the activity of fracturing fluid breakers,
most of those methods are limited in their usefulness by
unfavorable downhole conditions or by economic factors.
Particularly lacking in the field are adequate ways of avoiding the
problems associated with drilling fluids, which must undergo high
shear while drilling, cycling of temperature between bottom-hole
and surface, and remain useable for weeks. Once drilling stops, the
residues, or filter cakes remaining in the well, that inhibit
drilling operations or damage producing formations, must be
destroyed, sometimes at an indeterminate time after drilling. Still
needed are better ways of providing a functional agent, such as an
enzyme or a chemical, that can withstand the rigors of drilling, be
deliverable to a specified downhole location and of obtaining a
desired or selective activity to accomplish the decomposition of a
polymeric viscosifier, or other substrate. Also needed are better
ways of controlling the release or activity of an enzyme, chemical
or other functional agent in order to alter the physical or
chemical properties of a polymeric component of an oil field fluid
or residue. Moreover, suitable physically robust particles that
respond to a trigger to release an enzyme or otherwise reactive
substance that has been held inactive would have a number of
applications. Such particles could also lend themselves to solving
the more general problems of building in countermeasures to fluid
contamination, selectable degradation of solid materials within and
without the well bore, and facilitation of waste management of
materials containing degradable polymers.
SUMMARY OF THE INVENTION
[0066] The present invention solves many of the problems
encountered in the hydrocarbon exploitation industry. The inventors
have developed active, and particularly catalytic, agents that can
be made inert and remain inert under shear, temperature and
prolonged exposure and that can be safely added to materials which
would otherwise quickly change physical or chemical properties in
their presence. Yet those inert agents become active to make those
changes in response to a stimulus or trigger delivered either by
direct action or the action of environmental agents made accessible
over time or as a result of some indirect change such as reversal
of pressure differentials or discharge into the environment. The
agent, such as an enzyme or radical initiator, once activated is
able to reverse physical or chemical properties (e.g., breaking the
seal of an impermeable filter cake to release gas and oil or
converting a mechanically strong material into innocuous fragments)
has wide applications to the problems of building in
countermeasures to fluid contamination, selectable degradation of
solid materials within and without the well bore, and facilitation
of waste management of materials containing degradable
materials.
[0067] Accordingly, certain embodiments of the invention are
directed to methods and related compositions for altering the
physical and/or chemical properties of substrates used in
hydrocarbon exploitation, in both downhole and in surface
applications. These compositions and methods will find use in a
variety of drilling, completion, workover, production, reclamation
and disposal operations. The more preferred embodiments include the
triggered release of agents, such as enzymes and chemicals that
specifically act on defined substrates, such as polymeric
viscosifiers, fluid loss control agents and.chemical contaminants
like H.sub.2S. Creating a new drilling fluid formulation, including
an enzyme within the circulating fluid system could provide for
easy decomposition of the drilling fluid at the end of drilling
operations, both in the fluid returned to tanks on the surface and
the fluid lost to the formation or discharged whole or on cuttings
into the environment. In certain of the new reservoir drilling
fluid compositions, the encapsulated enzyme retains the enzyme
during drilling operations and releases the enzyme or enzymes upon
receipt of a chemical trigger such as pH or salinity change, or the
enzyme is released over a defined period of time. An important
trigger has been found to be CO.sub.2, which is present in many
reservoirs.
[0068] In accordance with certain embodiments of the present
invention, a method of degrading a predetermined substrate is
provided. The method includes formulating a fluid or a solid
material containing a degradable substrate and an inactivated
substrate-degrading agent, the inactivated agent being responsive
to a predetermined triggering signal such that the agent becomes
activated upon exposure to the triggering signal. The activated
agent is capable of degrading the substrate under degradation
promoting conditions to change its physical or chemical properties.
In some embodiments the step of applying a triggering signal
comprises exposing the inactivated degrading agent to a stimulus
selected from the group consisting of exposure to a reducing
agents, oxidizers, chelating agents, radical initiators, carbonic
acid, ozone, chlorine, bromine, peroxide, electric current,
ultrasound, change in pH, change in salinity, change in ion
concentration, change in temperature and change in pressure, the
inactivated degrading agent being capable of physically and/or
chemically responding to said stimulus.
[0069] In some embodiments the degrading agent comprises at least
one enzyme having activity for degrading the substrate under
degradation promoting conditions, and in some embodiments the
substrate-degrading agent is encapsulated by an encapsulating
material that is responsive to said triggering signal such that at
least a portion of said enzyme is released by said encapsulating
material upon exposure to a triggering signal. Certain embodiments
include an encapsulating material formed of a co-polymer of (a) an
ethylenically unsaturated hydrophobic monomer with (b) a free base
monomer of the formula
CH.sub.2.dbd.CR.sup.1COXR.sup.2NR.sup.3R.sup.4
[0070] where R is hydrogen or methyl, R.sup.2 is alkylene
containing at least two carbon atoms, X is O or NH, R.sup.3 is a
hydrocarbon group containing at least 4 carbon atoms and R.sup.4 is
hydrogen or a hydrocarbon group. In certain embodiments R.sup.3 is
t-butyl and R.sup.4 is hydrogen, and in certain embodiments R.sup.1
is methyl, R.sup.2 is ethylene and X is O. In some embodiments the
hydrophobic monomer is a styrene or methylmethacrylate, and the
encapsulating material is a co-polymer of styrene or methyl
methacrylate with t-butyl amino ethyl methacrylate. In some
embodiments the co-polymer comprises 55 to 80 weight % styrene,
methyl styrene or methyl methacrylate with 20 to 45 weight %
t-butylamino-ethyl methacrylate.
[0071] According to certain embodiments, the method also includes
maintaining enzyme activity promoting conditions in a downhole
environment, and, optionally, establishing enzymatic activity
inhibiting conditions. In some embodiments the fluid or solid
device comprises at least two inactivated enzymes, wherein the
inactivated enzymes are capable of being reactivated by the same or
different triggering signals, such that upon reactivation the
reactivated enzymes are capable of acting upon the same or
different substrates independently or in concert. In some
embodiments the enzyme is selected from the group consisting of
endo-amylases, exo-amylases, isomylases, glucosidases,
amylo-glucosidases, malto-hydrolases, maltosidases,
isomalto-hydro-lases and malto-hexaosidases. In some embodiments
the reactivated enzyme is capable of being inactivated by
application of a second triggering signal, wherein the second
triggering signal may be the same or a different triggering signal,
such that the inactivated enzyme no longer acts on the
substrate.
[0072] Certain embodiments of the methods of the invention employ a
degradable substrate selected from the group consisting of
celluloses, derivatized celluloses, starches, derivatized starches,
xanthans and derivatized xanthans. In certain embodiments the fluid
is a circulating drilling fluid, completion fluid or workover
fluid. In some embodiments the fluid is a stimulation fluid such as
a fracturing fluid. In other embodiments the may include
formulating a solid device comprises a self-destructing bridging
particle containing a degradable substrate and a reactivatable
inactivated enzyme for reversible fluid loss control. In some
embodiments the method employs a solid device comprises degradable
polymers and a reactivatable inactivated enzyme fashioned into
hardware for use downhole or on the surface.
[0073] According to another embodiment, a method of increasing the
flow of production fluid from a well is provided that comprises
formulating a fluid comprising a degradable polymeric substrate and
an inactivated enzyme. This method also includes introducing the
fluid into a downhole environment and applying a triggering signal
to the fluid. The triggering signal is sufficient to reactivate the
inactivated enzyme to give a reactivated enzyme, and the
reactivated enzyme is capable of selectively degrading the
substrate sufficient to alter a physical property of the fluid such
that the flow of production fluid is increased. In some embodiments
the step of introducing the fluid into a downhole environment
comprises forming a filter cake containing said degradable
substrate and said inactivated enzyme. In some embodiments the
fluid comprises more than one inactivated enzyme, wherein the
inactivated enzymes are capable of being reactivated by the same or
different triggering signals, wherein upon reactivation the
reactivated enzymes are capable of acting upon the same or
different substrates. In some embodiments the fluid is a
circulating drilling fluid, a completion fluid, a workover fluid or
a stimulation fluid. According to another embodiment, a method of
increasing the flow of production fluid from a well is provided
that comprises formulating a fluid comprising a degradable
polymeric substrate and an inactivated enzyme. This method also
includes introducing the fluid into a downhole environment, where
the fluid is present as whole fluid, such as drilling fluid lost to
natural fractures and other open features. The direct application
of a physical, triggering signal, such as a change in pH with weak
acids, is sufficient to reactivate the inactivated agent, such as
an enzyme, to give a reactivated enzyme, and the reactivated enzyme
is capable of selectively degrading the substrate sufficient to
alter a physical property of the fluid as viscosity or particle
suspending ability or pore-plugging ability such that the flow of
production fluid is increased. Cementing and other activities that
indirectly increase fluid production can also benefit by, for
example, liquefaction and sloughing of drilling fluids left behind
by imperfect cleaning of the well bore.
[0074] Carbon dioxide, present in many producing formations, has
been shown to be an effective trigger for certain formulations.
This provides for indirect delivery of the trigger by the reversal
of pressure at the time of production. During drilling, completion,
stimulation, and workover operations, the pressure is usually in
the radially out direction, forcing fluids out from the wellbore
and pushing fomration fluids away form the borehole. Production
begins with a reversal of the pressure differential, inducing
formation fluids to flow into the well bore. Fluids inadvertantly
or purposefully left into the well bore become more exposed to the
formation fluids, very often including CO.sub.2. In contact with an
aqueous phase, CO.sub.2 reacts with water to form carbonic acid
H.sub.2CO.sub.3, a mild acid, but sufficient to lower the pH of
fluids to the bicarbonate buffer point determined by the
environment.
[0075] Also provided by the present invention is a method of
degrading filter cake. The method comprises formulating a fluid
capable of making filter cakes and comprising a polymeric
viscosifier or fluid loss control agent and an inactivated enzyme.
An imporatnt example is a drilling fluid, where filter cake
formation is an essential feature. The fluid is introduced into a
downhole environment such that a filter cake containing the
polymeric viscosifier or fluid loss control agent and the
inactivated enzyme is formed. The fluid may be displaced from the
well at the point, leaving the solid filter cake pressed into the
surface of the well bore. A triggering signal is applied to the
filter cake, the triggering signal being sufficient to reactivate
the inactivated enzyme to give a reactivated enzyme. The
reactivated enzyme is capable of selectively degrading the
polymeric viscosifier or fluid loss control agent such that the
filter cake at least partially disintegrates, allowing fluid to
pass through the previously impermeable cake. CO.sub.2 from the
formation provides an especially useful route for decomposition of
filter cakes where externally applied breakers such as concentrated
mineral acids or oxidizers cannot be used, or where no external
wash can be applied due to, for example, mechanical failure,
preventing even application of the intended trigger signal. Further
provided by the present invention is a method of eliminating a
contaminant from a drilling fluid or subterranean formation.
According to certain embodiments, a fluid is formulated that
comprises an inactivated contaminant-destroying agent. The method
includes introducing the fluid into a downhole environment
containing a predetermined contaminant that is a substrate capable
of being degraded or destroyed by the agent under degradation
promoting conditions, and then applying a triggering signal to the
fluid. The optimal signal is the appearance of the contaminant,
such as the lowering of pH by the introduction of hydrogen sulfide.
The triggering signal then reactivates the inactivated agent to
allow it to degrade the contaminant. As it often takes more than an
hour for fluids to circulate from the bottom of a well to the top,
and fluids are often left standing statically in the well, such a
contaminant-triggered response provides for an automatic response,
using materials that would otherwise be consumed by side reactions
or destroy other fluid components if active in the fluid. The
method may also include dislodging a piece of drilling equipment
from an at least partially disintegrated filter cake.
[0076] Further provided by the present invention is a method of
eliminating a contaminant from a drilling fluid or subterranean
formation. According to certain embodiments, a fluid is formulated
that comprises an inactivated substrate-degrading agent. The method
includes introducing the fluid into a downhole environment
containing a predetermined contaminant that is a substrate capable
of being degraded by the agent under degradation promoting
conditions, and then applying a triggering signal to the fluid. The
triggering signal is sufficient to reactivate the inactivated agent
to provide a reactivated agent. allowing the reactivated
substrate-degrading agent to degrade the contaminant. The fluid may
be, for example, a circulating drilling fluid, completion fluid or
a workover fluid and, in certain embodiments the contaminant is
H.sub.2S.
[0077] Also provided in accordance with the present invention is a
wellbore servicing composition comprising a fluid or a solid device
containing at least one degradable substrate, said substrate
contributing to the structural integrity of said device or to the
structural integrity of a residue of said fluid, and an inactivated
substrate-degrading agent. The substrate-degrading agent is capable
of responding to a triggering signal such that the agent becomes at
least partially reactivated sufficient to degrade said substrate
under degradation promoting conditions in a downhole environment
such that a physical or chemical property of the composition is
altered. The utility of the invention in destroying solid filter
cake formed in the wellbore and containing the inactivated agent
can be extended to pre-formed solid materials. An example would be
to make solid particles from starch and starch-containing synthetic
polymers to serve a rigid bridging particles, for example, for use
in low density fluids where the density of calcium carbonate cannot
be tolerated, and strong chemicals cannot be used to clean up the
filter cake, or where cleanup chemicals may not be able to be
applied. Another application could be to cash sheets of degradable
polymer containing the inactivated agent for use as cover for
premium screens such as prepacked sand screens. The covers could
prevent damage of the screens whilst being placed into the
wellbore, and then destroyed by application of the trigger or
exposure to CO.sub.2 from the well.
[0078] Still flurther provided in accordance with the invention is
a wellbore treatment method comprising formulating a fluid
comprising an encapsulated substrate-degrading agent; introducing
the fluid into a downhole environment containing a predetermined
substrate capable of being degraded by the agent under degradation
promoting conditions; and providing for generation of the trigger
upon reaching the desire point. One example would be the use of
encapsulation to preserve the activity of the agent that would
normally be lost during the trip to the site of use, say by thermal
degradation of enzymes in a brine pumped to the producing zone at
the bottom of a deep, hot well. Including materials that generate a
trigger as they thermally degrade would provide for the preserved
agent to be released where it could immediately act.
[0079] Also provided by the present invention is a composition for
use in hydrocarbon exploitation operations. The composition can be,
for example, a circulating drilling fluid, a completion fluid, a
workover fluid, a bridging particle and a solid hardware device. In
certain embodiments the composition comprises a fluid or a solid
device containing at least one degradable substrate and an
encapsulated substrate-degrading agent. The encapsulated agent is
capable of responding to a triggering signal such that the agent
becomes sufficiently unencapsulated to allow the agent to degrade
the substrate under degradation promoting conditions such that a
physical or chemical property of the substrate is altered. In some
embodiments the encapsulated substrate-degrading agent is
inactivated by encapsulation in a material that is capable of
responding to the triggering signal by making the degrading agent
available to the degradable substrate. In certain embodiments the
triggering signal includes a change in pH of a medium contacting
the encapsulated agent. The substrate degrading agent may comprise
at least one inactivated enzyme, wherein the inactivated enzymes
are capable of being reactivated by the same or different
triggering signals, wherein upon reactivation the reactivated
enzymes are capable of acting independently or in concert upon the
same or different substrates. In some embodiments the substrate is
selected from the group consisting of celluloses, derivatized
celluloses, starches, derivatized starches, xanthans, and
derivatized xanthans. In some embodiments the substrate contributes
to the structural integrity of the device or to the structural
integrity of a residue of the fluid such that degradation of a
substrate causes a physical change in the composition. For
instance, the disintegration of a filter cake. In some embodiments
the enzyme is an endo-amylase, exo-amylase, isomylase, glucosidase,
amylo-glucosidase, malto-hydrolase, maltosidase,
isomalto-hydro-lase or malto-hexaosidase.
[0080] In certain embodiments, the triggering signal comprises
exposure to a reducing agent, oxidizer, chelating agent, radical
initiator, carbonic acid, ozone, chlorine, bromine, peroxide,
electric current, ultrasound, change in pH, change in salinity,
change in ion concentration, change in temperature and change in
pressure, or a combination of such stimuli.
[0081] In some composition embodiments the encapsulated agent
comprises an encapsulation material formed of a co-polymer of (a)
an ethylenically unsaturated hydrophobic monomer with (b) a free
base monomer of the formula
CH.sub.2.dbd.CR.sup.1COXR.sup.2NR.sup.3R.sup.4
[0082] where R is hydrogen or methyl, R.sup.2 is alkylene
containing at least two carbon atoms, X is O or NH, R.sup.3 is a
hydrocarbon group containing at least 4 carbon atoms and R.sup.4 is
hydrogen or a hydrocarbon group. For example, the encapsulating
material may be a co-polymer of styrene or methyl methacrylate with
t-butyl amino ethyl methacrylate.
[0083] These and other features of the present invention are more
fully set forth in the description of illustrative embodiments of
the invention with reference to the following drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0084] The description is presented with reference to the
accompanying drawings in which:
[0085] FIG. 1 is a graph of representative data comparing the
Starch (Flo-Trol) Suspension Viscosity with mixing time.
[0086] FIG. 2 is a graph illustrating the deviscosifying action of
an unencapsulated enzyme.
[0087] FIG. 3 is a graph showing enzyme release and control by pH
of one embodiment of an encapsulated enzyme/starch composition.
[0088] FIG. 4 is a graph showing stability of an encapsulated
enzyme/starch system at pH 10 and release upon adjustment to pH
5.
[0089] FIG. 5 is a graph illustrating month-long stability of
enzyme capsules at pH 10 and release upon lowering the pH to 5.
[0090] FIG. 6 is a graph illustrating the effect of shear on starch
slurry viscosity in the presence of one embodiment of an
encapsulated enzyme composition, at pH 5 and 10.
[0091] FIG. 7 is a graph showing the effect of shear on
encapsulated enzyme release in starch slurry at pH 10 and after
lowering to pH 5, for one embodiment of an encapsulated
enzyme/starch system.
[0092] FIG. 8 is a graph illustrating an example of fluid loss
control for control and encapsulated enzyme containing fluids under
100 psi N.sub.2 pressure.
[0093] FIG. 9 is a graph showing that in one embodiment a mud
filter cake containing an encapsulated enzyme broke with CO.sub.2
pressure but not with N.sub.2.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0094] New methods, compositions and devices have been developed
that are suitable for use with oil field fluids, circulating fluids
and solid articles employed in the drilling, completion, workover,
stimulation, production, reclamation or disposal operations in oil
and gas wells.
[0095] Drilling Fluids Containing an Inactivated or Encapsulated
Enzyme
[0096] Some of the more preferred compositions are useful for
inclusion in a circulating drilling fluid or mud system. These
compositions contain inactivated enzymes that are capable of being
activated or reactivated by a chemical or physical signal or by a
change in drilling fluid conditions. The enzymes remain inactive
until such time as a change in the properties of the drilling fluid
is desired. The enzyme is then activated upon exposure to a
chemical or physical signal, or a change in the drilling fluid
environment, such as a decrease in pH or temperature. Upon
activation, such enzymes are capable of selectively degrading fluid
components remaining within the well bore, such as filter cakes or
other damaging material that may form during drilling operations.
Additional changes in the drilling fluid environment may serve to
regulate enzyme activity. By controlling the activity of enzymes
contained within the circulating drilling fluid system, several
drilling problems associated with drilling fluid formations may be
avoided, thus increasing well productivity.
[0097] As used herein and in the appended claims, "circulating
drilling fluid system" means a system in which the drilling fluid
is circulated through the well for the purposes of drilling. The
composition of the drilling fluid, therefore, should be tailored to
fulfill the traditional roles of drilling fluids as described in H.
C. H. DARLEY & GEORGE R. GRAY, COMPOSITION AND PROPERTIES OF
DRILLING AND COMPLETION FLUIDS (5.sup.th ed. 1988), in addition to
functioning in accordance with present invention. It should be
understood by those skilled in the art, however, that the method of
using deactivated enzymes in the present invention is not limited
to circulating drilling fluid systems, but can be used in downhole
applications, other than those involving active drilling, whenever
it is desirable to control fluid loss to the surrounding formation,
such as during the placement of well completion equipment or
reintroduction of fluid into porous formations.
[0098] Just as the composition of the drilling fluid must be
carefully composed to meet the individual requirements of a
specific drilling operation, the type of enzymes selected, and
method of inactivation, is dependent upon the nature of polymeric
additives, and the whole of conditions expected within the well
bore. A wide variety of enzymes have been identified and separately
classified according to their characteristics. A detailed
description and classification of known enzymes is provided in the
reference entitled ENZYME NOMENCLATURE (1984): RECOMMENDATIONS OF
THE NOMENCLATURE COMMITTEE OF HE INTERNATIONAL UNION OF
BIOCHEMISTRY ON THE NOMENCLATURE AND CLASSIFICATION OF
ENZYME-CATALYSED REACTIONS (Academic Press 1984) [hereinafter
referred to as "Enzyme Nomenclature (1984)"], the disclosure of
which is fully incorporated by reference herein. According to
Enzyme Nomenclature (1984), enzymes can be divided into six
classes, namely (1) Oxidoreductases, (2) Transferases, (3)
Hydrolases, (4) Lyases, (5) Isomerases, and (6) Ligases. Each class
is further divided into subclasses by action, etc. Although each
class may include one or more enzymes that will degrade one or more
polymeric additives present in drilling mud, the classes of enzymes
in accordance with Enzyme Nomenclature (1984) most useful in the
methods of the present invention are (3) Hydrolases, (4) Lyases,
(2) Transferases, and (1) Oxidoreductases. Of the above, classes
(3) and (4) are the most applicable to the present invention.
[0099] Examples of enzymes within classes (1)-(4) according to
Enzyme Nomenclature (1984) for use in accordance with the methods
of the present invention are described in Table I below:
1TABLE I Class (3) Hydrolases (enzymes functioning to catalyze the
hydrolytic cleavage of various bonds including the bonds C--O,
C--N, and C--C) 3.1 - Enzymes Acting on Ester Bonds 3.1.3 -
Phosphoric monoester hydrolases 3.2 - Glycosidases 3.2.1.1 -
alpha-Amylase 3.2.1.2 - beta-Amylase 3.2.1.3 - Glucan
1,4-alpha-glucosidase 3.2.1.4 - Cellulase 3.2.1.11 - Dextranase
3.2.1.20 - alpha-Glucosidase 3.2.1.22 - alpha-Galactosidase
3.2.1.25 - beta-Mannosidase 3.2.1.48 - Sucrase 3.2.1.60 - Glucan
1,4-alpha-maltotetraohyd- rolase 3.2.1.70 - Glucan
1,6-alpha-glucosidase 3.4 - Enzymes Acting on Peptide Bonds
(peptide hydrolases) 3.4.22 - Cysteine proteinases 3.4.22.2 -
Papain 3.4.22.3 - Fecin 3.4.22.4 - Bromelin Class (4) Lyases
(enzymes cleaving C--C, C--O, C--N and other bonds by means other
than hydrolysis or oxidation) 4.1 - Carbon-carbon lyases 4.2 -
Carbon-oxygen lyases 4.3 - Carbon-nitrogen lyases Class (2)
Transferases (enzymes transferring a group, for example, a methyl
group or a glyccosyl group, from one compound (donor) to another
compound (acceptor) 2.1 - Transferring one-carbon groups 2.1.1 -
Methyltransferases 2.4 - Glycosyltransferases 2.4.1.1 -
Phosphorylase Class (1) Oxidoreductases (enzymes catalyzing
oxidoreductions) 1.1 - Acting on the CH--OH group of donors
1.1.1.47 - glucose dehyogenase
[0100] The polymeric additive can be any of the polymeric additives
familiar to those in the well service industry. For example,
carboxymethylcellulose, hydroxyethylcellulose, guar, xanthan,
glucans and starch. Table II below lists exemplary polymeric
additives that may be present in drilling fluid residues and
examples of corresponding enzymes capable of rapidly degrading such
additives under reaction-promoting conditions.
2TABLE II Examples of Polymeric Organic Additives and Effective
Enzymes for Rapidly Degrading the Same Common Oil-field Biological
Polymers Effective Enzymes(s) Carboxymethylcellulose hemicellulase,
cellulase, amyloglucosidase, .alpha.- amylase, .beta.- and
derivatives thereof (CMC) amylase,
glucan-(1,4)-.alpha.-glucosidase, glucan-(1,6)-.alpha.-
glucosidase, cellulose-(1,4)-.beta.-cellobiosidase
Hydroxyethylcellulose (HEC) hemicellulase, cellulase,
amyloglucosidase, cellulose-(1,4)-.beta.- cellobiosidase Guar
hemicellulase, cellulase, amyloglucosidasecellulose-(1,4)-.beta.-
cellobiosidase Xanthan glucosidase,
glucan-(1,4)-.alpha.-glucosidase, glucan-(1,6)-.alpha.-
glucosidase, .alpha.-glucosidase Glucans (including
glucan-(1,4)-.alpha.-maltotetraohydrolase, glucan-(1,4)-.alpha.-
scleroglucan) glucosidase, cellulase, .beta.-glucanase (such as
ULTRA L from Novo Nordisk) Starch and chemically endoamylases,
exo-amylases, isoamylases, glucosidases, .alpha.- modified starch
glucosidases, glucan-(1,4)-.alpha.-glucosidase,
glucan-(1,6)-.alpha.- glucosidase, oligo-(1,6)-glucosidase,
.alpha.-glucosidase, .alpha.-dextrin
endo-(1,6)-.alpha.-glucosidase, amylo-(1,6)-glucosidase, glucan-
(1,4)-.alpha.-glucosidase, amylo-(1,6)-glucosidase, glucan
(1,4)-.alpha.- maltotetrahydralase,
glucan-(1,6)-.alpha.-isomaltosidase, glucan-
(1,4)-.alpha.-maltohexaosidase
[0101] Enzyme Inactivation
[0102] Inactivation of the enzyme is preferably accomplished
through a physical sequestration of the enzyme molecules, for
example within a polymeric capsule impermeable to the enzyme. For
example, the enzyme may be trapped in a functional polymer matrix
that is pH sensitive, with the enzyme being released in response to
high pH. Another example is the precipitation of an enzyme trapped
within a semi-permeable nylon shell, and then disruption of the
shell by high pH. Another example is directly coating a dry enzyme
granule with a functional polymer directly. Yet another means of
inactivating the enzyme is to utilize an enzyme that requires the
addition of an activator molecule to initiate enzyme activity, or
by the addition of an enzyme inhibitor. All such techniques may be
utilized in preparing suitable inactivated enzymes. Preferably the
enzyme is encapsulated by an acid- or alkaline-responsive material
that is caused to release the enzyme in response to the appropriate
pH change in the capsule surroundings. Various materials and
techniques for encapsulating compounds and enzymes under conditions
compatible with maintaining the activity of enzymes are disclosed
in one or more of the following U.S. Patents assigned at issue to
Ciba-Geigy Corporation; U.S. Pat. Nos. 5,837,290; 5,805,264;
5,310,721; 4,978,481; 4,968,532; 4,619,764; 4,003,846; 5,094,785 or
in PCT publication WO 97/24178. The disclosures of these patents
are incorporated herein by reference. Additional guidance for
encapsulating compounds and enzymes under acceptable conditions is
provided in one or more of the following U.S. Pat. Nos.: 5,492,646;
5,460,817; 5,194,263; 5,035,900; 5,324,445; 5,972,363; 5,972,387;
5,968,794; 5,965,121; 5,962,015; 5,955,503; 5,932,385; 5,916,790;
5,914,182; 5,908,623; and 5,895,757. The disclosures of these
patents are incorporated herein by reference.
[0103] Inactivation of the enzyme is reversed upon exposure to a
chemical or physical signal such as a change in the pH or by
altering the salinity of the drilling environment. Alternatively
the triggering agent may be a reducing agent, oxidizer, chelating
agent, radical initiator, carbonic acid, ozone, chlorine, bromine,
peroxide, electric current, or ultrasound; or alteration in the
drilling fluid environment, such as a change ion concentration,
temperature, or pressure. Preferably activation of the enzyme is
accomplished, at least in part, by action of the triggering agent
on the encapsulating material resulting in the release of the
enzyme. In some cases it may be desirable to additionally regulate
the enzymatic activity of the released enzyme by adjusting the pH,
salinity or other environmental condition to provide
activity-promoting conditions. It may be desirable in some
situations to utilize a combination of signals and/or environmental
changes; for example, to insure against premature activation. Once
an enzyme is activated, the enzyme will catalyze reactions which
alter the physical or chemical properties of the components of the
fluid or solids as required to facilitate the drilling and/or oil
recovery process. In some embodiments the enzyme can be deactivated
upon exposure to an additional chemical or physical signal, or
change in drilling fluid environment. For example, a required
co-factor could be omitted from the circulating fluid or an enzyme
inhibitor could be introduced via the circulating fluid to again
inactivate the enzyme, or the pH could be raised or lowered beyond
the working range of the enzyme. Such an option could be beneficial
for controlling accidental enzyme release, or runaway enzyme
activity at a downhole site.
[0104] In some situations, it may be advantageous to use a mixture
of enzymes in connection with well drilling activities. Such
enzymes may act in concert, accelerating the breakdown of drilling
fluids by either facilitating enzyme activity, or operating on
distinct substrates. For some applications it could be advantageous
to allow enzymes which may counteract one another, be competitive,
or otherwise negatively impact enzyme activity, to be included in
the system, so long as they can be independently activated by
distinct signals or changes in the drilling environment. For
example, one enzyme might be activated at a high pH, while the
other enzyme at a lower pH, at a higher temperature, or upon the
addition of a cofactor.
[0105] Degradation of Filter Cake
[0106] A preferred use for the inactivated enzyme compositions is
for the controlled degradation of a filter cake formed during well
bore operations thus allowing increased permeability of drilling
fluid residues and enhanced recovery of formation fluids. U.S. Pat.
No. 5,165,477 ("the '477 patent") and U.S. Pat. No. 5,126,051 ("the
'051 patent"), disclose the use of enzymes to degrade filter cakes
by applying an external wash to the well bore. The enzymes within
the fluid wash, selected to be effective against one or more
drilling fluid components, catalyze the degradation of one or more
biopolymers within the fluid. Both the '477 patent and the '051
patent disclose, however, that to practice the invention, it is
important to select only enzymes capable of rapidly degrading the
polymeric additives in downhole applications because the harsh
chemicals and conditions associated with drilling muds can
permanently render the enzymes inactive by denaturing the protein.
Use of muds containing inactivated enzymes constitutes a marked
improvement over the use of a conventional enzyme wash to degrade
filter cake and other downhole drilling fluid residues because the
inactivated enzymes are incorporated into the filter cake and other
fluid residues as they develop. This has the benefit of (1) placing
the enzymes in contact with the substrate, (2) dispersing the
enzyme in a more effective manner; and (3) protecting the enzymes
from harsh downhole conditions and (4) providing for enzymatic
degradation in areas that are not reached by external wash. The
result is believed to lead to a more effective and efficient
removal of the filter cake.
[0107] A further difficulty with some enzyme washes of the prior
art is that, for some enzymes to be effective in dissolving the
filter cake, contact needs to be established by either the enzyme
flowing into the filter cake by the help of liquid flow, or by
self-diffusion of enzyme into the filter cake. Hanssen, et al.,
"New Enzyme Process for Downhole Cleanup of Reservoir Drilling
Fluid Filtercake," SPE 50709 (1999). This raises some difficulties
in that (1) the relatively large enzyme molecules may be slow to
enter the tiny pores of a tight filter cake and diffuse through it;
or (2) the enzymes may immobilize on the outside of the filter
cake. In contrast, in the presently-described method it is the
penetration of the cake by the trigger that initiates degradation
by releasing the incorporated, inactivated enzymes. Thus, the
enzymes do not have to work into the cake from the surface but
rather are free to react with substrates throughout the filter cake
or fluid.
[0108] Particle sizes of an inactivated enzyme are preferably
formulated for the most effective distribution within the filter
cake during its deposition. It can be expected the inactivated
enzyme will be incorporated into both the external filter cake laid
on the surface of the rock and the internal filter cake pushed into
the pores of the rock, where at least some of the enzymes
conventionally applied as an external wash will not reach. In many
cases this will lead to faster, more effective removal of filter
cake, and greater permeability of the formation.
[0109] Further, by being incorporated into the filter cake, the
enzymes are provided protection from the harsh environment of the
circulating mud system. The '477 patent indicates that there may be
additional costs in the use of an external wash in that "it may be
necessary to use a higher concentration of enzyme(s) to compensate
for high temperature conditions" due to the thermal degradation of
the enzyme activity during the high temperature transit to the
target site. At some point, as the well is drilled deeper,
conditions may become so severe that applying an enzyme wash
through the drill string may require such high loadings so as to be
impractical. In the present invention, however, the inactivated
enzyme incorporated in the fluid is protected from degradation will
have already been incorporated in the as well depth is increasing,
thus obviating the need to later pass enzymes through deeper, more
severe well environments. In addition, the encapsulated enzyme
could be used to deliver an external wash under extreme conditions
by putting it into a fluid with components that would generate the
trigger under downhole conditions, thereby eliminating
decomposition during the trip. In addition, certain enzyme
inactivation methods, such as encapsulation, provide protection
from the harsh conditions of the well bore and mechanical stress
the enzymes will encounter in the drill bit and nozzles when
circulated during drilling.
[0110] In most applications, the cost of the enzymes is an
important consideration. Because of the protection provided by
encapsulation and/or incorporation into the fluid residues, it is
not necessary that enzyme selection be limited to those that act
rapidly. In fact, some of the new compositions are expected to
provide for greater enzyme survivability, and for a greater
selection of potential enzyme candidates, some of which are likely
to be more effective or less costly than those typically employed
in enzyme washes.
[0111] Another cost-saving benefit of at least some of the new
compositions is that, as a result of including the enzyme within
the circulating drilling fluid system, the additional step of
preparing and applying an enzymatic wash is obviated. While the
same preliminary testing may be required in some cases to determine
the most suitable enzyme and method of inactivation, applying an
enzyme wash requires a greater expenditure of time and effort
overall. By extending the range of enzymatic action, new drilling
mud compositions are possible using materials heretofore difficult
to break with enzymatic action.
[0112] The following examples are included to demonstrate preferred
embodiments of the invention. It should be appreciated by those of
skill in the art that the techniques disclosed in the examples
which follow represent techniques discovered by the inventors to
function well in the practice of the invention, and thus can be
considered to constitute preferred modes for its practice. However,
those of skill in the art should, in light of the present
disclosure, appreciate that many changes can be made in the
specific embodiments which are disclosed and still obtain a like or
similar result without departing from the scope of the
invention.
[0113] Unless otherwise stated, all starting materials are
commercially available and standard laboratory techniques and
equipment are utilized.
[0114] General Materials and Methods
[0115] Equipment:
[0116] Hamilton Beach "Malt mixer"
[0117] Brookfield DV-II or DV-III Fann 35 viscometer
[0118] Standard calibrated Thermometer
[0119] 1L tall form beaker or beaker flask
[0120] Balance of technical quality or better
[0121] Stopwatch or similar timer
[0122] pH meter or similar means for determining pH
[0123] Silverson Mixer L4RT with general purpose disintegrating
head
[0124] Materials:
3 Tradename Common Name Supplier Flo-Trol Chemically M-I Drilling
Fluids, Houston, TX modified starch Dual-Trol Chemically M-I
Drilling Fluids, Houston, TX modified starch PROCARB sized calcium
M-I Drilling Fluids, Houston, TX carbonate BIOVIS scleroglucan SKW
Chemicals, Inc., Marietta, GA biopolymer SAFECIDE biocide M-I
Drilling Fluids, Houston, TX SAFE defoamer M-I Drilling Fluids,
Houston, TX DFOAM FLOVIS PLUS xanthan M-I Drilling Fluids, Houston,
TX biopolymer FAO-5 disk ceramic disc Fann Instrument Corporation,
Houston, TX NORPAR 13 paraffin oil Exxon Company, USA, Houston, TX
SAFE CARB F finely ground M-I Drilling Fluids, Houston, TX calcium
carbonate
[0125] Distilled or deionized water
[0126] HCl or NaOH or similar strong acid and base agents to adjust
pH as needed
[0127] Stock Starch Suspension
[0128] The stock starch suspension is prepared fresh daily, to
reduce the effects of adding biocide. Solids will settle. Mix
thoroughly before each use. The recipe may be scaled up to produce
larger quantities of starch slurry. Add 42 grams of Flo-Trol to 1 L
of di-water in tall form beaker, or preferably 1 L beaker. (Note
that iron affects enzyme action, so glass is preferred to stainless
steel mixer cup). Stir at high speed with Hamilton Beach malt mixer
or similar, for 15 minutes. Check pH, adjust to between 6 and 8 as
required. Check rheology at about 70.degree. F. If using the
Brookfield apparatus, look for about 30% torque at 250 rpm using
LV-2 spindle. If using a Fann 35 apparatus, look for a dial reading
above 15 at 600 rpm with R1B1 set. Establish Baseline. Record
viscosity at 5 minute intervals for one hour. Recheck viscosity
after 24 hours, stirring sample to re-suspend starch.
[0129] Enzyme Solution
[0130] An enzyme such as one of those listed in Table I, above, is
obtained as a solid or liquid solution and dissolved in an aqueous
solution, optionally containing a preservative.
[0131] Encapsulated Enzymes
[0132] An enzyme solution is lyophilized and the resulting
particles are encapsulated in a polymeric material as generally
described in U.S. Pat. No. 5,492,646; 5,460,817 or 5,324,445, or in
PCT publication WO 97/24178. In the present examples an ionophoric
polymer that is more permeable to a selected enzyme at a defined
acid pH than at a defined alkaline pH was preferred. Encapsulation
polymers were obtained from Ciba Specialty Chemicals, United
Kingdom. Preferably the encapsulating material is formed of a free
base form of a cationic polymer which is a co-polymer of (a) an
ethylenically unsaturated hydrophobic monomer with (b) a monomer of
the formula
CH.sub.2.dbd.CR.sup.1COXR.sup.2NR.sup.3R.sup.4
[0133] where R.sup.1 is hydrogen or methyl, X is O or NH, R.sup.2
is
[0134] alkylene containing at least two carbon atoms, R.sup.3
is
[0135] a hydrocarbon group containing at least 4 carbon
[0136] atoms and R.sup.4 is hydrogen or a hydrocarbon group.
[0137] The preferred monomers are those in which R.sup.3 is
tertiary butyl since the presence of the tertiary butyl group
imposes particularly useful swelling properties on the polymer
formed from that monomer. However R.sup.3 may be other butyl or
higher alkyl groups or it may be other hydra-carbon groups
containing at least 4 carbon atoms (but usually not more than 8
carbon atoms). The t-butyl group is also advantageous because it
seems to render the monomer units containing it more resistant to
alkaline hydrolysis.
[0138] R.sup.4 is frequently hydrogen but it can be alkyl such as
methyl, ethyl or higher alkyl or it can be other hydro carbon
group. The total number of carbon atoms in R.sup.3 and R.sup.4
together is usually below 12, often below 8.
[0139] R.sup.2 is usually ethylene but it can be other linear or
branched alkylene group containing two or more (for instance 2-4)
carbon atoms.
[0140] R.sup.1 is usually methyl.
[0141] X can be NH, with the result that the cationic monomer is
preferably a monoalkyl or dialkyl aminoalkyl (meth) acrylamide
monomer, but preferably X is O, with the result that the cationic
monomer is preferably a monoalkyl or dialkyl aminoalkyl (meth)
acrylate.
[0142] The hydrophobic monomer can be any ethylenically unsaturated
monomer that is insoluble in water, for instance generally having a
partition coefficient K between hexane and deionised water at
20.degree. C. of at least 5 and preferably at least 10. The
hydrophobic monomer can be a water-insoluble alkyl ester of
methacrylic acid or other aliphatic, water-insoluble monomer such
as methyl, ethyl or butyl acrylate or methacrylate. However the
preferred hydrophobic monomers are ethylenically unsaturated
aromatic hydrocarbon monomers, such as styrenes, preferably styrene
or a methyl styrene or methyl methacrylate.
[0143] Generally the amount of cationic monomer will be within the
range 5-30 mole % or 10-50 weight %. Best results are generally
achieved with amounts of from around 12-25 mole % of the cationic
free base monomer. When, as is preferred, the free base monomer is
t-butylamino-ethyl methacrylate and the hydrophobic monomer is a
styrene or methyl methacrylate, the amount of cationic monomer is
preferably from 5%-50% by weight, most preferably around 5%-35% by
weight.
[0144] The matrix can be formed of recurring units of monomers
consisting solely of the hydrophobic monomer and the free base
cationic monomer but if desired minor amounts of other monomers may
be included.
[0145] The matrix is preferably formed by a method analogous to
that which is described in EP 361677 or EP 356239, the disclosures
of which are incorporated herein by reference, for the formation of
a matrix of anionic polymer. Thus it may be made by dehydrating
particles each of which is an oil-in-water emulsion of the free
base polymer or it may be made by forming particles of a salt of
the polymer with a volatile acid and evaporating the volatile acid
during the drying so as to form the free base of the polymer.
[0146] The amount of cationic monomer groups in the form of salt,
in the polymer, should be as small as possible and should be below
20 mole %, preferably below 10 mole % and most preferably below 5
mole % based on the amount of free base cationic monomer groups in
the polymer. Preferably it is substantially zero. The preferred way
of making the particles of polymeric matrix is by forming a reverse
phase dispersion in a water immiscible non-aqueous liquid of
droplets containing the chosen active ingredient and either an
oil-in-water emulsion of the polymer or an aqueous solution of a
salt of the polymer with a volatile acid and then distilling the
dispersion so as to eliminate the water and, if necessary, to drive
off the volatile acid. The formation of the reverse phase
dispersion is preferably conducted in the presence of a polymeric
(generally amphipathic) stabiliser and/or an emulsifier, for
instance as described in EP 356239 and EP 361677 and WO 92/20771,
the disclosures of which are incorporated herein by reference.
[0147] When, as is preferred, the matrix particles are made by
providing a solution of a water soluble salt form of the polymer,
this solution can be made by acidifying, using a volatile acid, an
oil-in-water emulsion formed by oil-inwater emulsion polymerization
of the monomers. Preferably, however, the solution is made by
polymerizing the free base monomer and the hydrophobic monomer
while dissolved in an organic solvent so as to form a solution of
the free base polymer inorganic solvent. This is followed by
addition of an aqueous solution of a volatile acid wherein the
solvent has higher volatility than the acid. The solvent is then
distilled off so as to leave a solution in water of the salt form
of the polymer. A suitable volatile acid is acetic acid, in which
event a suitable solvent is n-butylacetate.
[0148] In order to maximize the conversion of the salt form of the
cationic polymer to the free base form, it is desirable to bake the
product, after distilling off the water, at a temperature of at
least 95.degree. C. and usually 100.degree. C. for at least 15
minutes and usually at least 20 or 30 minutes. Preferably this is
conducted under sufficient vacuum (if necessary) to maximize the
removal of volatile acid.
[0149] Enzyme Deviscosification Test
[0150] Check viscosity of stock solution is within 20% of original
value. Spike 150 mL of sample with 0.10 mL of unencapsulated enzyme
solution (scale the treatment level to sample size by ratio). Stir
to completely mix sample. Measure rheology at 5 minute intervals
for one hour. Observe initial viscosity increase followed by
decrease to less than one half of starting viscosity at one hour.
This demonstrates the susceptibility of the substrate to
degradation by the selected enzyme at the treatment level
applied.
[0151] Encapsulated Enzyme Test--Demonstration of Resistance Mild
Shear
[0152] Pour out two samples of starch slurry, and blend in
encapsulated enzymes to deliver the same enzyme activity as tested
with unencapsulated enzyme into starch system as above, using
Hamilton Beach mixer. Run Enzyme Deviscosification test. Recheck
viscosity after 24 hours.
[0153] Encapsulated Enzyme Test--Demonstration of Release by pH
[0154] Blend in encapsulated enzymes into starch system as above,
using Hamilton Beach mixer. Measure initial viscosity, adjust pH to
release enzyme, and measure viscosity as per Enzyme
Deviscosification test.
[0155] Encapsulated Enzyme Test--Demonstration of Resistance to
High Shear
[0156] Blend in encapsulated enzyme into starch system as above,
using a Hamilton Beach mixer. Apply shear of 8000 rpm using
Silverson L4RT with general purpose disintegrating head and
standard square hole screen for 90s/L of fluid. Run Enzyme
Deviscosification test and recheck viscosity after 24 hours, yield
enzyme. Run Enzyme Deviscosification test.
[0157] High Shear/Hot Roll/High Shear Simulation of Fluid
Circulation
[0158] Apply high shear to a encapsulated enzyme-containing fluid.
Run the Enzyme Deviscosification test. "Hot Roll" at 150.degree. F.
for 16 hours (This can be done by placing the sample in a bottle
and putting it into an oven equipped with rollers that continuously
turn the bottle.) A shaker bath would serve as an approximation. RB
flask/heating mantle would NOT work.) Run the Enzyme
Deviscosification test, re-apply high shear, run the Enzyme
Deviscosification test, yield enzyme, and run the Enzyme
Deviscosification test.
[0159] By following the foregoing protocols, one can determine the
appropriate polymeric additive (enzyme substrate), enzyme, enzyme
activity, encapsulating material and conditions for enzyme
activation necessary for use of the enzyme in the methods of
present invention. The systematic variation of conditions will also
readily permit one of ordinary skill in the art to find an enzyme
and polymeric additive that will function in the formation of
downhole filter cake and also allow the controlled degradation or
removal of the filter cake under preselected conditions. Preferably
the encapsulated enzyme particles are no larger than about 74.mu.
in diameter, remain unaggregated when combined with the other
drilling fluid components and are capable of withstanding the shear
forces generated during drilling, particularly the shear forces
generated by the mud pump and transiting the bit jets. It is also
preferred that the inactivated or encapsulated enzyme control
enzyme release or activity during dynamic exposure to drilling
temperatures up to at least about 130.degree. F., and preferably up
to about 200.degree. F., yet releases the enzyme or enzymes when
triggered. For use as a reservoir drilling fluid, it is preferred
that the encapsulated enzyme retain the enzyme during drilling
operations and release the enzyme or enzymes upon receipt of a
chemical trigger such as pH or salinity change, or over a defined
period of time.
EXAMPLE 1
[0160] Employing the above-described procedures, the inventors have
developed an encapsulated starch-degrading enzyme that is inactive
at pH 10 and higher but releases active enzyme at pH 8 and lower. A
choice was made among several alpha-amylases offered by
Novo-Nordisk Pharmaceutical Company, selecting one that has the
highest activity at the temperature and pH expected to be
encountered for the present examples. The enzyme solution was then
lyophylized to remove water and made suitable for the application
of an encapsulation technology described by Ciba in U.S. Pat. Nos.
5,492,646; 5,460,817 and 5,324,445 and in PCT publication WO
97/24178, the disclosures of which are incorporated herein by
reference.
[0161] Encapsulation was accomplished. using a suitable co-polymer
of styrene (when preparing sample lots #57 and #63) or methyl
methacrylate (when preparing sample #37) and t-butyl amino ethyl
methacrylate was synthesized by isothermal solution polymerization
in an organic solvent using an azo initiator. Aqueous acetic acid
solution was then added to the organic solution and the organic
solvent was distilled off, leaving a 20-30% weight solution of the
co-polymer, as the acetate salt, in water at pH 4-5.5. The solution
was mixed with a liquid amylase preparation and dispersed in
hydrocarbon oil, with adjustment of the pH to 4.5, followed by
distillation to produce a dried dispersion. The dispersion was then
held at 100.degree. C. for 60 minutes under vacuum to drive off
acetic acid. A surfactant wetting agent was added to the liquid
formulation to allow wetting in aqueous solutions. Preferably
aggregation of the enzyme capsules is avoided when they are mixed
with the other components of the drilling fluid formulations. In
this regard, it is important that the pH of the fluid be above the
yield pH before the addition of the capsules.
[0162] The encapsulated enzyme was tested in five reservoir
drilling fluid formulations and was found to have little or no
effect on fluid properties at pH 10 and above, although some lots
of encapsulated enzyme produced small changes due to trace amounts
of unencapsulated enzyme. Operating at pH 11.6 can control the
unencapsulated enzyme. The fluids are stable to hot-rolling and
shear at 60.degree. C. (158.degree. F.). Reducing the pH of the
fluid to 5 produces or "triggers" the destruction of the starch
components of the fluid by first causing a change in the polymer
that results in the release of the enzyme. Without wishing to be
bound by a particular theory of the mechanism of action, the
encapsulating material is believed to become more permeable to the
enzyme or to be disrupted. As a result of the action of the enzyme
on the starch substrate--the fluid settles and allows easy recovery
of the brine. Filter cakes made with these fluids are impermeable
when pressured with nitrogen gas and neutral to basic brines. Mild
acids, such as that produced by CO.sub.2 gas, make the filter cakes
highly permeable. As CO.sub.2 permeates the neutral pH NaCl brine,
it forms carbonic acid, H.sub.2CO.sub.3, which ionizes and lowers
the pH to 5 or less. As the filter cakes see this lower pH, the
encapsulated enzymes are released to degrade the starches and open
pathways for brine to permeate through the cake whereby the
integrity of the cake is destroyed.
[0163] It is preferable that the enzyme chosen demonstrate the
greatest retention of activity after exposure to well bore
temperatures over time. Based on the data in Table III, Amylase A,
obtained from Novo-Nordisk A/S, Denmark was selected for use with
the current example.
4TABLE III Stability of starch enzymes at temperature, expressed as
% residual activity Product/Temperature 1 week 2 weeks 3 weeks
Amylase A/70.degree. C. (158.degree. F.) 70 63 67 Amylase
A/90.degree. C. (194.degree. F.) 38 18 16 Amylase B/70.degree. C.
(158.degree. F.) 60 47 43 Amylase B/90.degree. C. (194.degree. F.)
20 9 9
[0164] The method involves suspending 42 grams of starch in 1L of
water, mixing for 15 minutes. Baseline viscosity was established by
monitoring viscosity at five-minute intervals for 60 minutes.
Enzyme treatments were mixed into the starch, observing the course
of degradation 20 as reduction in viscosity. The procedure used an
API style, three-blade propeller on a Hamilton Beach mixer
controlled by a rheostat. Mixing time was increased to 60 minutes
mixing time.
[0165] FIG. 1 provides a graphical representation of representative
data comparing the Starch (Flo-Trol) Suspension Viscosity with
mixing time. These data demonstrates that the viscosity of the
Flo-Trol test suspension stabilized for at least one hour after 40
min. mixing time.
[0166] Using the procedures outlined above, a 47.5 g/L Flo-Trol
suspension in 21 wt % NaCl brine was prepared. Four aliquots were
taken. The pH of two was adjusted to 5 with dilute hydrochloric
acid. The pH of the remaining two aliquots were adjusted to 9 with
dilute caustic. Samples were heated to 80.degree. C. (176.degree.
F.). One set of pH 9 and 5 aliquots was treated with 30.4 mg/L of
starch enzyme in solution. An equivalent 30.4 mg/L of enzyme was
added as micron-sized polymer capsules suspended in hydrocarbon.
FIG. 2 is a graph showing the action of raw enzyme and encapsulated
enzyme lot, referred to as Sample #57, on starch at pH 5 and 9, at
80.degree. C. (176.degree. F.). Viscosity measured at 600 rpm on
Fann 35, normalized to value after pH adjustment and before enzyme
treatment. As shown in FIG. 2, the deviscosifying action of
unencapsulated enzyme is immediate, reducing measured viscosity 90%
in minutes at both pH 9 and pH 5. The pH 9 suspension treated with
encapsulated enzyme sample #57 showed no degradation in 60 minutes.
However, the pH 5 suspension treated with encapsulated enzyme
sample #57 showed reduced viscosity starting at 30 minutes, with
90+% reduction obtained in 60 minutes.
[0167] The deviscosification by raw enzyme at pH 9 demonstrates
control by the encapsulated enzyme. The similar, although delayed,
deviscosification of the pH 5 encapsulated enzyme/starch systems
demonstrates the release of enzyme in response to a different
pH.
[0168] One of skill in the art should appreciate that drilling
requires stability over the span of several days to two weeks, so
longer-term exposures were tested. Stability at pH 9 for 20 hours
is shown in FIG. 3. FIG. 3 is a graph showing enzyme release and
control by pH at 60.degree. C. (158.degree. F.). Aliquots of 47.5
g/L slurry of starch adjusted to pH 10 or 5 and treated with
encapsulated enzyme. Viscosity was estimated from visual
observation. Portions of a standard starch slurry were separately
adjusted to pH 9 and 5, heated to 60.degree. C. (158.degree. F.),
and inoculated with 7.6 ppm of encapsulated enzyme. The pH 9 sample
retained viscosity for 20 hours. The pH 5 material lost viscosity
somewhere between the observations at 7 and 16 hours. An important
finding was that pH of these systems drifts from the initial value,
and must be either buffered or maintained by adjustment with acid
or base.
[0169] While weeklong stability is essential, release upon pH
change after the week is equally important. Representative data
resulting from extending test periods to 185 hours is shown in FIG.
4. FIG. 4 is a graph demonstrating weeklong stability of
encapsulated enzymes at pH 9 with release upon adjustment to pH 5.
The points on the graph are visual assessments. One aliquot of a
47.5-g/L slurry of Dual-Flo starch in 21 wt % NaCl brine was
adjusted to pH 10. Another aliquot was adjusted to pH 5. Each was
treated with 7.6 mg/L of encapsulated enzyme, and held at
60.degree. C. (158.degree. F.). Viscosity was monitored by visual
observation of the sample when lightly shaken. As shown in the
graph, the pH 10 aliquot retained viscosity for 185 hours. The pH 5
sample lost viscosity between observation at 20 and 25 hours. FIG.
4 shows that the pH 10 sample was split at 150 hours and one
portion was adjusted to pH 5 with acid. Between observation at 175
and 185 hours, the pH 5 portion lost viscosity, demonstrating
release of the enzyme.
[0170] On occasion, drilling operations are interrupted by
hurricanes, lack of supplies, armed insurrection, etc. It would be
desirable for the encapsulated enzyme to be stable considerably
longer than the expected drilling time. The results of a month-long
exposure experiment are shown in FIG. 5. FIG. 5 is a graph
demonstrating month-long stability of enzyme capsules at pH 10 with
release upon pH lowered to 5. 47.5 g/L Dual-Flo starch slurry
adjusted to pH 10 and 5, treated with 7.6 mg/L encapsulated enzyme.
After 150 hours, a portion of the pH 10 sample was adjusted to pH
5, which deviscosified between observations at 600 and 680 hr.
Slurry samples were pH adjusted, treated with encapsulated enzyme
and dynamically aged by hot rolling at 60.degree. C. (158.degree.
F.). A pH 10 suspension retained viscosity for 780 hours. A sample
adjusted to pH 5 before application of the encapsulated enzyme lost
viscosity overnight.
[0171] Release of the enzyme was observed in a portion of the pH 10
sample that was adjusted to pH 5 at 150 hours. While delayed, the
sample deviscosified between observations at 600 and 680 hours.
[0172] An important feature of any drilling fluid additive is its
ability to resist the effects of shear forces generated in
transiting the bit jet and impacting on the rock surface being
drilled. This was simulated by using a Silverson LR4T mixer with a
general dispersing head to shear a Dual-Flo starch slurry for 10
min at 6000 rpm. FIG. 6 is a graph showing the effect of shear on
starch slurry viscosity in the presence of encapsulated enzymes at
pH 5 and 10. The viscosity of starch slurries at each step of
challenging the samples with the Silverson mixer is shown. Step 1
adjusted the slurries to pH 10 and pH 5. Second, shear was applied
and hot rolled for 16 hours at 60.degree. C. (158.degree. F.).
Third came another shear treatment and hot rolling. Step 4
monitored viscosity for an additional day. Untreated starch at pH
10 and 5 showed very little change in viscosity. The pH 5
encapsulated enzyme sample lost viscosity at step 2. The pH 10
sample shows a bit higher viscosity at step 2, but the later
readings fall into the range seen for the starch-only samples. This
small effect may be due to a trace amount of unencapsulated enzyme
present in this lot of encapsulated enzyme.
[0173] A further test of shear is shown in FIG. 7 illustrating the
effect of shear on encapsulated enzyme release in starch slurry at
pH 10 lowered to pH 5. Here aliquots of starch were adjusted to pH
10 with 0.5 g/L MgO and heated to 60.degree. C. (158.degree. F.).
One was treated with enyyme, the other with encapsulated enzyme.
Both samples were sheared for 10 minutes at 6000 rpm, and hot
rolled. The enzyme-treated sample lost viscosity between
observations at four and fifty hours. The encapsulated enzyme
gained some viscosity over fifty hours, possibly due to trace free
enzyme. At 67 hours, the viscosity stabilized, remaining at that
value when rechecked at 167 hours, demonstrating the encapsulated
enzyme was controlled.
[0174] The pH of this sample was then lowered to 8 with citric
acid. Some loss of viscosity was found when rechecked 18 hours
later. Because MgO buffers pH as a solid, acid additions can
produce short term reductions in pH that are slowly counteracted by
dissolution of MgO. When checked, the pH of the sample had risen
well above 8. More acid was used readjust pH to 5.5, and sample hot
rolled 16 hours. The pH was further lowered to 5. At this point
viscosity was reduced by more than 80%.
EXAMPLE 2
[0175] Four exemplary reservoir drilling fluids containing the
encapsulated .alpha.-Amylase enzyme, encapsulated as described
above, were prepared and it was demonstrated that the incorporation
into finished reservoir drilling fluid without release of enzymes
under operating conditions is feasible. The composition of the four
reservoir drilling fluid formulations numbered 1 to 4 are reported
in Table IV. Fluids were prepared using standard oilfield products
and procedures. References to numbered fluids in the following
tables refer to this chart.
[0176] Fluid 1 shows good rheology and fluid loss control as shown
in Table V. When treated with encapsulated enzyme and maintained at
pH 10, rheology and fluid loss properties are essentially
unchanged. Treatment with neat enzyme results in loss of viscosity
and an increase in API fluid loss. When the stable pH 10 fluid was
adjusted to pH 5 with phosphoric acid, rheology and fluid loss go
to nearly the levels of the fluid treated with neat enzyme.
5TABLE IV Reservoir Drilling Fluid Formulations Material Unit 1 2 3
4 Product Function Water g 256.8 311.2 317.7 317.7 Liquid phase KCl
g 17.1 Density NaCl g 68.3 34.2 17.1 -- Density PROCARB g 50 50 50
50 Bridging solid/ density DUAL-FLO g 5 5 5 5 Starch fluid loss
additive BIOVIS g 1.5 1.5 1.5 1.5 Scleroglucan based viscosifier
SAFECIDE g 0.2 0.2 0.2 0.2 Biocide SAFE DFOAM g 0.2 0.2 0.2 0.2
Foam suppressant MgO g 1.5 1.5 1.5 1.5 Alkaline pH buffer
[0177]
6TABLE V Properties of Fluid 1 treated with enzyme and encapsulated
enzyme Hours of API Dynamic Fluid Aging Fann 35 Dial readings at:
Loss (60.degree. C.) 600 rpm 300 rpm 200 rpm 100 rpm 6 rpm 3 rpm 10
sec Gel pH (mL) Formulated fluid 1 18 68 48 40 31 15 13 17 9.6 6.3
288 58 43 40 31 14 12 17 9.4 5.5 Formulated fluid 1 + 0.7 ml
encapsulated enzyme #63 (10%) suspension 18 67 47 41 33 16 14 18
9.7 4.4 42 70 50 43 33 15 13 17 9.5 4.6 120 85 59 49 37 16 13 16
9.5 5.6 Formulated fluid 1 + 7.6 ppm neat enzyme 18 37 26 22 18 10
9 12 9.4 23 288 32 25 22 18 9 8 10 8.6 23 Formulated fluid 1 + 3 ml
#63 after 18 hours aging pH reduced to 5 with H.sub.3PO.sub.4 18,
treat, 18 44 31 29 24 11 9 13 6.4 18.2 18, treat, 41 31 26 21 11 10
14 7.7 21.5 114
[0178] Fluids 2, 3 and 4 show that a range of brine salinities can
be used to make stable fluids at pH 10 incorporating encapsulated
enzyme. Table VI shows the rheologies and fluid losses of the
treated and untreated fluids are essentially unchanged.
7TABLE VI Fluids 2, 3 and 4 Before and After Treatment with
Encapsulated Enzyme 10" API Time (hrs.) 600 rpm 300 rpm 200 rpm 100
rpm 6 rpm 3 rpm Gel pH (ml) Formulated fluid 2 dynamic aged at
60.degree. C. 68 41 31 27 21 12 10 13 9.8 6 Formulated fluid 2 + 2
ml #37 (50% suspension) dynamic aged at 60.degree. C. 68 40 28 24
19 10 8 11 9.7 5.6 Formulated fluid 3 aged at 60.degree. C. 68 37
28 25 20 11 10 13 9.9 5.7 Formulated fluid 3 + 2 ml #37 (50%
suspension) dynamic aged at 60.degree. C. 68 38 28 24 20 11 9 12
9.7 5 Formulated fluid 4 dynamic aged at 60.degree. C. 68 39 29 25
21 11 10 14 10.2 5.5 Formulated fluid 4 + 2 ml #37 (50% suspension)
dynamic aged at 60.degree. C. 68 34 25 21 18 9 8 11 9.9 5.9
[0179] Because lowering filter cake permeability was a desired
objective in this project, High Pressure High Temperature (HTHP)
filter cakes were made using fluids 2, 3,and 4 by placing the
fluids into a standard HTHP cell with an aloxite disc for the
filtration medium. The fluid is loaded into the cell and pressured
to 500 psi with nitrogen gas, a typical over pressure between the
hydrostatic pressure of typical drilling fluid and the pressure of
the formation. The cell is heated to test temperature, and a valve
behind the disc opened to allow filtrate to be collected in a
reciever flask. The burst of liquid caught in the first minute was
recorded as spurt loss. At 180 minutes the cumulative filtrate
volume was recorded and the valve closed. The cell was
depressurized and the loose mud was poured out of the cell, leaving
the filter cake adhered to the aloxite disc. Brine was poured into
the cell. The cell was pressured to 65 psi with carbon dioxide,
simulating typical completion fluid overpressure. As shown in Table
VII, filter cakes from fluids containing encapsulated enzyme passed
slightly greater amounts of the NaCl brine than filter cakes from
untreated fluids, but both were within acceptable limits.
[0180] As CO.sub.2 permeates the neutral pH NaCl brine, it forms
carbonic acid, H.sub.2CO.sub.3, which ionizes and lowers the pH to
5 or less. As the filter cakes see this lower pH, the encapsulated
enzymes are released to degrade the starches and open pathways for
brine to permeate through the cake.
8TABLE VII HTHP Fluid Loss of Filter cake with CO.sub.2 Fluid Loss
(mL) with 500 psi N.sub.2 NaCl Brine loss (mL) through filter cake
after being at 60.degree. C. shut in overnight under 65 psi
CO.sub.2 at 60.degree. C. Spurt 180 m 90 m 3.25 h 5 h 8 h 25 h 29 h
Formulated fluid 2 aged at 60.degree. C. 2.5 19 2.8 3.8 4.5 6 11 13
Formulated fluid 2 aged at 60.degree. C. + 2 ml #37 (50%
suspension) 3 15 2.3 4.3 5.5 8.3 21.5 24 Formulated fluid 2 aged at
60.degree. C. 2 15 2 3 4 5.5 11 12.5 Formulated fluid 2 aged at
60.degree. C. + 2 ml #37 (50% suspension) 2 16.8 1.8 37 39 -- -- --
Formulated fluid 3 aged at 60.degree. C. 1 17.5 1 26.5 27.5 -- --
-- Formulated fluid 3 aged at 60.degree. C. + 2 ml #37 (50%
suspension) 2 21 3 38 41.5 -- -- -- 10 micron ceramic disc used for
all tests Test interrupted after HTHP fluid loss. Tests restarted
after 2 weeks, HTHP cells rolled for 1 hour at 60.degree. C. before
being emptied refilled with brine and CO.sub.2 pressure applied
[0181] The fluid in use must withstand the shear forces of
drilling, creating low permeability filter cakes that are stable to
clear brine displacements. When the chemical trigger is received,
filter cake permeability must then be increased to allow production
of the fluids held within the rock. To demonstrate these features,
a fluid was prepared using the formulation shown in Table VIII.
[0182] The fluid was prepared and hot rolled at 150.degree. F. for
16 hours. The fluid was split into two, 350 mL "lab barrels" (bb1).
One 1ab bb1 was labeled CZ, and treated with 0.5 mL of a 1:1
mixture of an encapsulated enzyme suspension and a normal-paraffin
oil (Norpar 13). The other 1ab bb1 was labeled Control, and was
treated with 0.5 ml of the paraffin oil containing no encapsulated
enzyme.
9TABLE VIII Shear/cake test fluid Ingredient Loading per 350 mL Tap
Water 299 mL NaCl 95 g KCl 10.5 g Biopolymer viscosifier (FLOVIS
0.75 g PLUS) MgO 3 g Calcium carbonate (SAFE 15 g CARB F) Starch
(DUAL-TROL) 5 g THPS biocide 0.02 mL 0.1 N NaOH solution adjust to
pH 10.5 Final Density 10.2 lb/gal
[0183] Each fluid was sheared three times for 5 minutes each time
using a Silverson L4RT at 8000 rpm. Both fluids were hot rolled at
54.degree. C. (130.degree. F.) for 16 hours. After the hot roll,
each fluid was again sheared three times for 5 minutes each time.
Fann 35 rheology and pH were taken on the fluids throughout the
shear/hot roll regimen, and remained consistent. See Table IX.
10TABLE IX Effect of Shear on Control and CZ fluids Plus 16 hr hot
roll at 16 hr After 3 .times. 5 130.degree. F. and hot rolled
minute shear 3 .times. 5 min shear Rpm 150.degree. F. Control CZ
Control CZ 600 33 29 28 31 31 300 22 20 20 21 21 200 18 17 16 17 18
100 14 12 12 13 13 6 5 4 5 4 4 3 4 3 3 3 3 pH 10.2 10.6 10.7 10.6
10.5
[0184] Each fluid was split into two parts and loaded into HPHT
cells. Filter cakes were built for 19 hours at 130.degree. F. under
1000-psi nitrogen on FAO-5 ceramic disks. FIG. 8 is a graph
illustrating fluid loss for Control and CZ fluids under 100 psi
N.sub.2. Fluid loss of the base fluids was slightly higher than the
CZ samples, but all were within acceptable range.
[0185] After 19 hours, the cells were depressurized and the
drilling fluid poured off. One filter cake of each mud was treated
with a 3% KCl brine previously adjusted to pH 9 with caustic, and
the cells pressured to 100 psi with nitrogen from a common gas
manifold. The other filter cake was covered with 3% KCl brine with
no pH adjustment, and both cells pressured to 100 psi with CO.sub.2
from a common gas manifold.
[0186] FIG. 9 is a graph illustrating brine passage through filter
cakes under 100 psi gas pressures. As shown, both the filter cake
from the Control fluid and the filter cake froim the CZ fluid
containing encapsulated enzyme had low levels of permeability to pH
9 KCl brine under 100 psi of nitrogen for 160 hours.
[0187] Both CO.sub.2 traces show an unusual slow down in collection
rate in the first 24 hours, followed by a sudden increase in rate.
This feature was produced by a partially closed valve in the
CO.sub.2 manifold that shut off pressure to cells after the initial
adjustment, allowing the pressure to drop to low levels, reducing
permeation of the fluid through the filter cake. Re-setting the
valve after 24 hours brought the pressure back, and fluid flow
resumed at that point.
[0188] The Control mud filter cake exposed to neutral pH KCl brine
and 100 psi of CO.sub.2 allowed fluid to pass at about the same
rate as the two nitrogen-pressured cakes. The filter cake built
from the enzyme-containing CZ fluid began leaking fluid at a fast
rate after about 60 hours of exposure, culminating in catastrophic
loss of the entire brine fill at about 105 hours. Only the
experiment comprising the three items of the invention, i.e. a
degradable substrate, an inactivated enzyme agent and triggering
low pH produced significant change in permeability.
[0189] For the purposes of this disclosure, the word "enzyme" is
meant to include enzymes obtained from living organisms, created
from the genetic material of living organisms, organisms containing
enzymes or organisms containing the genetic material which creates
enzymes, spores, seeds and other catalytic materials.
Additional Embodiments
[0190] A variety of alternative embodiments that utilize a
triggered release material and specific pH triggering of an,;
encapsulated substatce.are also encompassed by the present
invention. Some of these include:
[0191] CO.sub.2 or pH change-released breakers of all sorts,
including enzymes, oxidizers, acids (derived from, e.g., a neutral
polymer like polyhdroxyacetic acid), for breaking fracturing
fluids, workover, gravel pack and completion fluids.
[0192] Perf-tunnel fluid loss control pills formulated with an
enzymatically degradable material, and may in addition have any of
several viscosifiers and/or solid bridging agents and the
appropriate encapsulated enzymes. Perf pills are placed into a well
bore to control loss of fluid through perforation tunnels shot in
to the rock. As the tunnels may be many inches deep, breaker
chemicals applied at the well bore have difficulty reaching the far
end of the fluid and filter cake packed into the tunnel. Permeation
of CO.sub.2 into the tunnel from the formation can trigger
breakdown of the material across the entire length of the
tunnel.
[0193] Molded starch-polymer components containing encapsulated
enzyme for use in down-hole and surface oil field applications
could provide means of their decomposition in response to changes
in well bore conditions or application of a chemical signal. For
example, a starch-polymer containing encapsulated enzyme could be
molded into a Perf gun holder for use in constricted well bores
where recovery after perforation may be impossible. Unretrieved
guns physically interfere with many production operations, and a
polymer that degrades upon prolonged exposure to CO.sub.2 may
remove such impediment.
[0194] Molded starch-polymer components containing encapsulated
enzyme molded into a film might be used to sheathe "pre-packed"
sand screen assemblies. The units could be placed into the well
bore without plugging the epoxied sand bed with particles from the
well bore, and the film degraded by CO.sub.2 exposure when the well
is brought on line to expose the screen.
[0195] Molded starch-polymer components containing encapsulated
enzyme molded into a stop or stay restraining a valve controlling
flow along the wellbore to the surface. As the formation is drained
of oil, water enters the well bore, reducing the net flow of oil
from the well, and causing disposal problems on the surface. The
water passing over the stay or stop could trigger release of the
encapsulated enzyme, releasing enzymes to degrade the polymer and
allowing the valve to close, sealing off the water producing zone
from the still productive portions of the well.
[0196] Molded starch-polymer components containing encapsulated
enzyme molded into surface fixtures such as base pads, oil storage
tanks, oil-carrying pipes, could be washed free of oil with a
vinegar wash and left to decompose at an enhanced rate at the well
site or in land farm disposal. Examples of such molded, degradable
polymers are given in BIODEGRADABLE POLYMERS IN NORTH AMERICA &
EUROPE, available from MarTek, New York, N.Y.
[0197] Molded starch-polymer components containing encapsulated
enzyme molded into flakes or granules for use as a bridging agent
in high pH drilling fluids or Ifud loss control pills. These
particles would be stable at high pH, but destroyed by weak acid at
low temperature or self-destructing by CO.sub.2 exposure, opening
up producing rock in zones not reached by an applied external
breaker.
[0198] Starch-viscosified fracturing fluids containing the
encapsulated enzyme for use in fracturing wells, such that fluid
that is not produced back, loses viscosity with prolonged exposure
to CO.sub.2.
[0199] Starch-based adhesives containing encapsulated enzymes for
binding plywood, pressboard and other well site building materials.
At end of well operations, a mild acid, such as a vinegar wash,
could be used to activate for improved degradation of said
materials.
[0200] Starch-based adhesives containing encapsulated enzymes for
reversibly sealing downhole fractures.
[0201] Cellulose fiber materials containing encapsulated
hemicelluases for the above uses.
[0202] Encapsulated enzymes, organisms or spores that are released
when the mud is discharged into the environment, facilitating
bio-degradation of the fluid.
[0203] Encapsulated protease and esterase enzymes that are
contained within the fluid or filter cakes, becoming activated with
CO.sub.2 exposure. These enzymes are free to react with esters
either contained within the fluid or added to the fluid, generating
free acid by breaking the ester bonds. Encapsulated iron, zinc or
other metal compounds or complexes such as EDTA chelates, released
upon exposure to H.sub.2S and the resulting drop in pH, to control
H.sub.2S incursion. Encapsulation keeps the metal species from
interfering with the performance of fluid materials such as xanthan
gums or starches, and yet makes the material available to react
with and render harmless the toxic H.sub.2S.
[0204] Encapsulated oxidants that are kept from reacting with the
circulating fluid but are released upon application of mild acid or
reservoir CO.sub.2. An existing product, magnesium peroxide, is
used in this way, added as a solid to the system kept at a high pH.
The magnesium peroxide is kept from dissolving and attacking the
fluid by a surface reaction of Mg(OH).sub.2Mg.sup.2++2 OH.sup.-.
However, because it is in direct contact with the fluid, eventually
the particles releases all the Mg peroxide by the dynamic
equilibrium of the surface reaction. Anti-oxidants or sacrificial
organic materials must be added to consume the prematurely released
peroxide. This limits the application to lower temperatures and
short times. A capsule that prevents or slows the rates of the
dissolution reaction would preserve the oxidizer, delivering more
to breaking the cakes, and reducing or eliminating the need for
anti-oxidants.
[0205] Encapsulated peroxidase enzymes or other catalysts or
antioxidants for destruction of peroxide created by or in excess
from application of oxidative breakers. Kept from interfering with
the action of the oxidizers at high pH but released upon prolonged
exposure to CO.sub.2 or other lowering of pH to consume the
peroxides and reduce corrosivity and potential formation damage by
iron oxidation.
[0206] Encapsulated polyhydroxyacetic acid. This has been used
several times as a fluid component that is neutral and unreactive
under initial conditions, but over time and temperature hydrolyzes
to release hydroxyacetic acid. This rate of release is uncontrolled
because the released acid catalyses the further breakdown of the
polymer, resulting in a cascade of release. A capsule able to
retard yield until a critical pH was reached could provide a much
greater level of control.
[0207] Drilling fluid for locations known to have problems with
stuck pipe, comprising an encapsulated enzyme or other breaker, and
a corresponding substrate as a filter cake component.
Differentially stuck pipe occurs when a modest loss of fluid
thorough the sidewall of the bore pulls the drilling pipe against
the side. The differential pressure between the wellbore and the
rack sticks the pipe firmly in place. A common remedy is to replace
the drilling fluid in the stuck region with materials such a
organic solvents, surfactants, etc. that cause the established
filter cakes to crack or break, dramatically increasing fluid loss.
The invading front causes the pressure drop to move from the well
bore to the radially expanding zone of fluid invasion. However,
these specialty chemicals need to be immediately available in order
to work. Success of freeing the pipe diminishes rapidly within the
first three hours. Using an encapsulated material such as an enzyme
as part of the drilling fluid would allow even a dilute acid wash
to activate and break the cake, loosing the pipe.
[0208] In one preferred illustrative embodiment, the fluid includes
more than one inactivated enzyme that are capable of being
reactivated by the same or different triggering signals. Further,
upon reactivation the reactivated enzymes are capable of acting
upon the same or different substrates. Such substrate may be
celluloses, derivatized celluloases, starches, derivatized
starches, xanthans, and derivatized xanthans. therefore logically
the preferred inactivated enzyme can be selected from the group
consisting of endo-amylases, exo-amylases, isomylases,
glucosidases, amylo-glucosidases, malto-hydrolases, maltosidases,
isomalto-hydrolases, malto-hexaosidases. In one illustrative
embodiment, the reactivated enzyme is capable of being inactivated
by application of a second triggering signal, so that the enzyme
may go through one or more cycles of inactivation and reactivation.
The second triggering signal may be the same or a different
triggering signal. For example, in one illustrative embodiment, a
change in pH conditions may be used to activate and inactivate an
enzyme while in another illustrative embodiment a change in pH may
activate the enzyme, but a change in temperature, or the
concentration of the product of the enzymatic reaction may cause
inactivation. Thus depending upon the method of encapsulation and
the enzyme and substrate a wide range of potential triggering
signals exist, but preferably the triggering signal is selected
from exposure to a reducing agent, oxidizer, chelating agent,
radical initiator, carbonic acid, ozone, chlorine, bromine,
peroxide, electric current, ultrasound, or activator, or a change
in pH, salinity, ion concentration, temperature, or pressure.
[0209] The present illustrative embodiment includes fluids used in
the drilling of oil and gas wells and preferably the fluid is a
circulating drilling fluid, completion fluid or workover fluid.
Preferably the continuous fluid phase is water based.
[0210] As described above, the reactivated enzyme is capable of
selectively acting upon a downhole substrate and thereby increasing
the flow of production fluid. Preferably the substrate is a
component of the filter cake that is formed during the drilling
process. It is also preferred that the fluid be a fluid that is
useful in the drilling of oil and gas wells and preferably the
fluids are formulated and utilized as a circulating drilling fluid,
completion fluid or workover fluid. The fluid of the present
illustrative embodiment may include more than one inactivated
enzyme that is capable of being reactivated by the same or
different triggering signals. Upon reactivation the reactivated
enzymes are capable of acting upon the same or different
substrates.
[0211] The fluid of the present illustrative embodiment may include
more than one inactivated enzyme, in which the inactivated enzymes
are capable of being reactivated by the same or different
triggering signals. Upon reactivation the reactivated enzymes are
capable of acting upon the same or different substrates. As
previously noted, in some embodiments the reactivated enzyme may be
capable of being inactivated by application of a second triggering
signal, and that second triggering signal may be the same or a
different triggering signal. Thus, in some applications it may be
advantageous for the inactivated enzyme to be able to go through
one or more cycles of inactivation and reactivation.
[0212] The present invention also encompasses an illustrative
composition including a continuous fluid phase and an inactivated
enzyme, wherein upon application of a triggering signal the
inactivated enzyme is reactivated to give a reactivated enzyme, and
wherein the reactivated enzyme is capable of selectively acting
upon a downhole substrate. Such an illustrative composition may
include more than one inactivated enzyme, wherein the inactivated
enzymes are capable of being reactivated by the same or different
triggering signals, wherein upon reactivation the reactivated
enzymes are capable of acting upon the same or different
substrates. In one preferred embodiment of the illustrative
composition the inactivated enzyme is inactivated by
encapsulation.
[0213] The illustrative composition may be a circulating drilling
fluid, completion fluid or workover fluid utilized in the oil and
gas industry and it is preferred that the continuous fluid phase is
water based.
[0214] The substrates for the enzyme may be selected from
celluloses, derivatized celluloases, starches, derivatized
starches, xanthans, and derivatized xanthans. Thus the inactive
enzyme may be preferably selected from endo-amylases, exo-amylases,
isomylases, glucosidases, amylo-glucosidases, malto-hydrolases,
maltosidases, isomalto-hydro-lases, malto-hexaosidases. Regardless
of the enzyme selected, the reactivated enzyme should be capable of
being inactivated by application of a second triggering signal,
that may be the same or a different triggering signal used to
activate the enzyme. Therefore an enzyme may go through one or more
cycles in inactivation and reactivation.
[0215] The triggering signal of the present illustrative embodiment
may be exposure to a reducing agent, oxidizer, chelating agent,
radical initiator, carbonic acid, ozone, chlorine, bromine,
peroxide, electric current, ultrasound, or activator, or a change
in pH, salinity, ion concentration, temperature, or pressure. The
selection of the triggering signal will depend upon the conditions
and formulations of the drilling fluid, the formation and the
enzyme or enzymes involved.
[0216] While the compositions and methods of this invention have
been described in terms of preferred embodiments, it will be
apparent to those of skill in the art that variations may be
applied to the process described herein without departing from the
concept and scope of the invention. For example, although reservoir
drilling fluids containing inactivated substrate-degrading agents,
or enzymes, are emphasized in the foregoing examples and
discussion, one can appreciate that with little or no modification
similar compositions and methods may be readily employed with a
variety of fluid or solid devices in surface as well as downhole
operations. Similarly, the foregoing examples emphasize enzymes as
preferred activatable substrate-degrading agents, however it should
be understood that other chemicals or agents may be employed
instead. For instance a microorganism, a co-factor, a spore, an
inorganic chemical, and precursors thereof, could be substituted
for an enzyme in some cases. All such similar substitutes and
modifications apparent to those skilled in the art are deemed to be
within the scope and concept of the invention as it is set out in
the following claims. The disclosure of U.S. Provisional Patent
Application No. 60/165,393 is incorporated herein by reference.
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