U.S. patent application number 10/427030 was filed with the patent office on 2003-11-20 for fluids and techniques for hydrocarbon well completion.
Invention is credited to Chang, Frank F., Davison, Jonathan Mark, Fu, Diankui, Morris, Elizabeth W.A., Parlar, Mehmet, Tibbles, Raymond J., Vinod, Palathinkara S., Wierenga, Antje M..
Application Number | 20030216263 10/427030 |
Document ID | / |
Family ID | 29420807 |
Filed Date | 2003-11-20 |
United States Patent
Application |
20030216263 |
Kind Code |
A1 |
Tibbles, Raymond J. ; et
al. |
November 20, 2003 |
Fluids and techniques for hydrocarbon well completion
Abstract
The Invention relates to novel fluids and techniques to
optimize/enhance the production of hydrocarbon from subterranean
formations (e.g., "completion fluids"), in particular, fluids and
techniques are disclosed and claimed which remove wellbore damage
and near-wellbore damage in the form of coating formed from
drilling and production-related operations ("filtercake"); the
techniques can be applied either by themselves or in conjunction
with other completion operations, such as gravel packing; preferred
embodiments are chelating agent and enzyme systems in a
viscoelastic surfactant (VES) matrix.
Inventors: |
Tibbles, Raymond J.;
(Youngsville, LA) ; Parlar, Mehmet; (Broussard,
LA) ; Chang, Frank F.; (Sugar Land, TX) ; Fu,
Diankui; (Missouri City, TX) ; Davison, Jonathan
Mark; (Torphins, GB) ; Morris, Elizabeth W.A.;
(Aberdeen, GB) ; Wierenga, Antje M.; (Houston,
TX) ; Vinod, Palathinkara S.; (Stafford, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION
IP DEPT., WELL STIMULATION
110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
29420807 |
Appl. No.: |
10/427030 |
Filed: |
April 30, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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10427030 |
Apr 30, 2003 |
|
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09651059 |
Aug 30, 2000 |
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Current U.S.
Class: |
507/200 |
Current CPC
Class: |
C09K 8/52 20130101; C09K
2208/24 20130101 |
Class at
Publication: |
507/200 |
International
Class: |
E21B 001/00 |
Claims
We claim:
1. A well completion fluid for breaking filtercake having
substantial calcite and starch content, said fluid comprising a
chelating agent and an enzyme, wherein said chelating agent is
present in a quantity effective to promote the dissolution of
calcium carbonate and said enzyme is suitable for dissolving
starch.
2. The well completion fluid of claim 1 wherein said enzyme is
selected from the group consisting of .alpha.-amylase and
.beta.-amylase.
3. The well completion fluid of claim 2, wherein said enzyme is
.alpha.-amylase and is present in said fluid at a concentration of
between 0.05 and 1.5%.
4. The well completion fluid of claim 1 further comprising a
salt.
5. The well completion fluid of claim 1, wherein said salt is
selected from the group consisting of KC.sub.1 and NH.sub.4Cl
6. The well completion fluid of claim 4, wherein said salt is
present in said fluid at a concentration of between 3 and 5%.
7. The well completion fluid of claim 1, wherein said chelating
agent is selected from the selected from the group consisting of
1-hydroxyethylidene-1,1-diphosphonic acid-1 (HEDP),
aminotri(methylene phosphonic acid (ATMP),
diethylenetriaminepentamethylenephosphonic acid (DTPMP),
ethylenedieminetetraacetic acid (EDTA), cyclohexanediaminetetraa-
cetic acid (CDTA), diethylenediaminepentaacetic acid (DTPA), and
nitrilotriacetic acid (NTA).
8. The well completion fluid of claim 7 wherein said chelating
agent is EDTA and is present in said fluid at a concentration
between 5 and 28%.
9. The well completion fluid of claim 3 wherein said enzyme is
.alpha.-amylase and is present in said fluid at a concentration of
about 0.5%.
Description
TECHNICAL FIELD OF THE INVENTION
[0001] The Invention relates to novel fluids and techniques to
optimize/enhance the production of hydrocarbon from subterranean
formations, in particular, fluids and techniques are disclosed and
claimed which remove wellbore and near-wellbore formation damage in
the form of coating formed from drilling and production-related
operations; the techniques can be applied either by themselves or
in conjunction with other completion operations, such as gravel
packing.
BACKGROUND OF THE INVENTION
[0002] The present Invention relates to novel fluids and techniques
to optimize/enhance the production of hydrocarbons from
subterranean formations. To recover hydrocarbons (e.g., oil,
natural gas) it is of course, necessary to drill a hole in the
subsurface to contact the hydrocarbon-bearing formation. This way,
hydrocarbons can flow from the formation, into the wellbore and to
the surface. Recovery of hydrocarbons from a subterranean formation
is known as "production." One key parameter that influences the
rate of production is the permeability of the formation along the
flowpath that the hydrocarbon must travel to reach the wellbore.
Sometimes, the formation rock has a naturally low permeability,
other times, the permeability is reduced during, for instance,
drilling the well. When a well is drilled, a fluid is circulated
into the hole to contact the region of the drill bit, for a number
of reasons--including, to cool the drill bit, to carry the rock
cuttings away from the point of drilling, and to maintain a
hydrostatic pressure on the formation wall to prevent production
during drilling.
[0003] Drilling fluid is expensive particularly in light of the
enormous quantities that must be used during drilling.
Additionally, drilling fluid can be lost by leaking off into the
formation. To prevent this, the drilling fluid is often
intentionally modified so that a small amount leaks off and forms a
coating on the wellbore, or a "filtercake."
[0004] Yet once drilling is complete, and production is desired,
then this coating or filtercake must be removed. The present fluids
and techniques are directed to removing this filtercake or other
such damage in the wellbore and near-wellbore region, that results
either intentionally (in the case of drilling fluid) or
unintentionally (in the case of scale deposits from produced water
or dewatered fluids from workover/stimulation operations performed
on the well).
[0005] Conventional treatments for removing filtercake include:
aqueous solution with an oxidizer (such as persulfate),
hydrochloric acid solution, organic (acetic, formic) acid,
combination of acid and oxidizer, and aqueous solutions containing
enzymes. For instance, the use of enzymes to remove filtercake is
disclosed in U.S. Pat. No. 4,169,818, Mixture of
Hydroxyropylcellulose and Poly(Maleic Anhydride/Alkyl Vinyl Ether)
as a Hydrocolloid Gelling Agent (1979) (col. 1, ln. 42); U.S. Pat.
No. 3,515,667, Drilling Fluid Additive (1970); U.S. Pat. No.
3,509,950, Well Drilling Mud and Screen Composition of Use Thereof
U.S. Pat. No. 2,259,419, Well Drilling (1941). Chelating agents
(e.g., EDTA) are also used to promote the dissolution of calcium
carbonate. See, C. N. Fredd and H. S. Fogler, Chelating Agents as
Effective Watrix Stimulation Fluids for Carbonate Formations, SPE
372212 (1997); C. N. Fredd and H. S. Fogler, Alternative
Stimulation Fluids and Their Impact on Carbonate Acidizing, SPE
31074 (1996), both articles are hereby incorporated by reference in
their entirety. According to conventional teaching, the oxidizer
and enzyme attack the polymer fraction of the filtercake; the acids
mainly attack the carbonate fraction (and other minerals).
Generally speaking, oxidizers and enzymes are ineffective in
degrading the carbonate fraction; likewise, acids have very little
effect on polymer.
[0006] In addition, numerous problems plague conventional
techniques of filtercake removal. Perhaps the most troublesome is
the issue of "placement." For instance, one common component in
filtercake is calcium carbonate. The substance of choice to remove
calcium carbonate is hydrochloric acid Hydrochloric acid reacts
very quickly with calcium carbonate. What happens then, is that the
filtercake begins to dissolve, therefore dramatically increasing
the permeability of the wellbore face, so that the wellbore region
is no longer "sealed off" from the formation. Once this happens,
the entire clean-up fluid may then leak off into the formation
through this zone of increased permeability ("thief zones," or
discrete zones within the interval of very high permeability where
more filtercake dissolution has occurred than at other places along
the interval).
[0007] A second problem with removal of filtercake is that it is
comprised of several substances, and which are, as mentioned
earlier, not generally removable with a single substance. Calcium
carbonate and organic polymers (e.g., starch and other
polysaccharide) are two primary constituents of conventional
drilling fluids that form a filtercake on the wellbore. Treating
these successively--i.e., with two different fluids, one after the
other--is problematic since, it requires at least two separate
treatments. Combining two different breakers (one for the polymer
fraction, one for calcite) is problematic since each has a distinct
activity profile (or optimal window of activity, based on
temperature, pH, etc.) and the activity profiles of two different
breakers may not coincide. This is particularly likely if one of
the breakers is an enzyme, which are notoriously temperature and pH
sensitive.
[0008] Moreover, if the calcium carbonate is removed first--as it
often is--then, once the hydrochloric acid contacts the filtercake,
regions of higher permeability are created in the wellbore (where
the filtercake has dissolved). Hence, fluid will leak-off into the
formation during subsequent phases of the filter-cake removal
treatment.
[0009] Hence, the ideal fluid must be easy to "spot" or place in
wellbore over the entire length of the desired zone, contiguous
with the producing zone (e.g., a two thousand foot horizontal
zone)--before any filtercake dissolution occurs. If the fluid
begins to dissolve the filtercake too quickly, then the fluid will
be lost through the thief zones and the entire fluid treatment will
be destroyed. In other words, a hypothetical ideal fluid would be
completely unreactive for a period of time to enable it to be
spotted along the entire length of the producing interval, then,
once in place, react sufficiently slowly and uniformly, so that no
thief zones are. Again, if thief zones form, then the entire mass
of fluid can leak off through that zone. Hence, reasonably
uniform/controlled dissolution is necessary to ensure that the
fluid remains in contact with the filtercake along the entire
interval until near-complete dissolution of the filtercake has
occured along the entire interval.
[0010] Moreover, removing filtercake is an expensive and
time-consuming procedure. Therefore, it is desirable to do this at
the same time that another treatment is being performed, if
possible. For instance, if a material must be delivered to one
portion of the formation into the wellbore (e.g., in conjunction
with a remedial treatment), then the fluid used to carry that
material can be an acid solution which will also dissolve portions
of the filtercake. Again, if the carrier fluid leaks off into the
formation through a thief zone, then the remedial operation is
completely destroyed.
[0011] One common treatment performed on wells, particularly wells
in the Gulf Coast region of the United States, is known as a
"gravel pack." Gravel pack operations are performed to prevent the
production of sand along with hydrocarbon, which often occurs in
formations of weakly consolidated sands. To prevent sand
production, a filter (or screen) can be placed around the portion
of the wellbore in which production occurs. A more long-term
solution for sand control is achieved if the region between the
screen and the formation is filled with gravel, which is properly
sized to prevent the sand from moving through the gravel and into
the wellbore-to function as a filter-so that when the sand tries to
move through the gravel, it is filtered and held by the gravel or
screen, but hydrocarbon continues to flow unhindered (by either the
gravel or screen) into the wellbore.
[0012] Again, it would be highly advantageous if the fluid used to
deliver the gravel could also be used to dissolve the filtercake,
which would eliminate the need for a separate treatment just to
dissolve the filtercake. This would result in substantial cost
savings--both because a separate treatment is costly, and because
it take additional time to perform such a treatment.
[0013] Thus, what is desired is a fluid that can be used as a
carrier fluid (though it need not be used for that purpose) and
that can also degrade the filtercake. An ideal carrier fluid is
inert--i.e., it should not degrade the filtercake instantaneously
(otherwise the fluid can be lost into the formation)--but an ideal
filtercake dissolution fluid must dissolve the cake, eventually.
Therefore, an ideal fluid must somehow combine these two
contradictory attributes.
[0014] Indeed, the need for filtercake clean-up is particularly
acute in gravel to pack completions--i.e., wells in which the
movement of sand along with the hydrocarbon is prevented by a
gravel pack/screen combination--because, the entrapment of the
filter-cake between the formation and screens or gravel can result
in substantial reduction in production. The need for a reliable
filtercake clean-up treatment with a good diversion mechanism (to
ensure proper placement) is also particularly acute in horizontal,
or highly deviated wells. In these cases, the producing interval
may be several thousand feet, compared with a vertical well, which
may have a producing zone of about 30 feet. Because the difficulty
of placing a mass or fluid to achieve near-uniform dissolution over
1000 feet interval is far greater than for a 30 feet
interval--placement takes longer, and the potential for the
creation of thief zones is far greater.
[0015] Therefore, an urgent need exists in the drilling and
completions sector for a reliable fluid for degrading
filtercake--quickly, efficiently, and completely, and which can be
used as a carrier fluid in conjunction with other
completion/workover/stimulation operations. This is the primary
objective of the present Invention.
SUMMARY OF THE INVENTION
[0016] The present Invention relates to fluids intend to break
filtercake (whether produced from drilling, production, completion,
workover, or stimulation activity, either produced intentionally or
unintentionally. In particularly preferred embodiments, the fluids
and techniques are directed to degrading (or "breaking") filtercake
formed from starch/carbonate-containing drilling fluid such as the
STARDRILL.TM. (a drill-in fluid manufactured and sold by
Schlumberger). In other particularly preferred embodiments, the
fluids of the present Invention are operable in conjunction with a
gravel pack operation, and in particular, though not exclusively,
to break filtercake, in conjunction with a gravel pack
operation.
[0017] Therefore, one object of the present Invention is to provide
novel completion fluids to break filtercake, either alone or in
conjunction with other workover/completion/stimulation treatments,
but in particular, gravel pack operations. Preferred embodiments
relate to fluids to break filtercake having substantial calcite and
starch content. Particularly preferred embodiments related to
treatment fluids having two essential components: a chelating agent
and an enzyme. These components were selected based on their
ability to dissolve different components of the filtercake, and
based on their ability to dissolve these components at particular
rates relative to one another. Other particularly preferred
embodiments are fluids having these two components in a VES
(viscoelastic surfactant) system. VES systems have numerous
advantages--discussed at length in U.S. Patents incorporated by
reference below--including that they are readily gelled, they can
be disposed of more easily than guar and modified guar systems,
they are more readily removed from subsurface formations. In
addition, and of particular importance of the present Invention,
VES systems create very low friction pressures compared with
conventional carrier fluids, and therefore they are particularly
preferred, for instance, in gravel pack operations of the present
Invention.
[0018] The fluids of the present Invention can be successfully
spotted or placed over, for instance, a 2000 ft. horizontal
producing zone-without substantial leakoff. Particularly preferred
embodiments to achieve this incorporate Mobil's AllPAC.TM.
(licensed exclusively to Schlumberger). This way, the gravel pack
operation, for instance, can take place without fluid loss.
[0019] At the same time, the fluid of the present Invention acts
slowly upon the filtercake, to slowly but steadily dissolve it, but
not before the particular workover operation has been
completed.
[0020] Moreover, the break time (or time to substantial dissolution
of the filtercake) of the fluids of the present Invention are
optimized so that the overall or blended dissolution rate is very
slow at low temperatures but much higher at high temperatures. The
primary advantage of this unique temperature-dependence is that
fluid can be introduced into the entire zone of interest before
filtercake dissolution occurs, then as the fluid temperature rises
due to contact with the wellbore, only then does dissolution
occur.
[0021] The fluids and techniques of the present Invention are quite
general and are operable in a variety of settings. These include,
but are not limited to, screen-only completions and gravel pack
completions; open hole and cased hole; vertical and highly deviated
wells; single-application soak or circulating fluid in which the
treatment fluid (of the present Invention) also serves as a carrier
fluid for, e.g., a gravel pack operation; in conjunction with a
gelling agent or viscoelastic surfactant (e.g., ClearFRAC.TM.) or
alone, and with a variety of clean-up tools. In summary, since the
problem of placement and uniform dissolution are present in
virtually every instance, the fluids and techniques of the present
Invention are readily applicable to any scenario in which it is
desirable to remove flitercake from the wellbore or near-wellbore
region in the formation, regardless of whether the filtercake was
produced during drilling or during other post-drilling operations
(e.g., fluid-loss control pill, gravel pack operation, fracturing,
matrix acidizing, and so forth).
[0022] Finally, the fluids of the present Invention are a viable,
cost-effective replacement for HCl-based fluids, conventional
fluids of choice to remove filtercake. Perhaps the major problem
with HCl systems (aside from their ineffectiveness in removing the
carbonate fraction of filtercake) is corrosion--corrosion of the
above-ground storage tanks, pumps, down-hole tubulars used to place
the fluid, and wellbore casings. Moreover, a cost-effective
solution to corrosion is not readily available, as evidenced by the
fact that corrosion inhibitors is a significant portion of the
total expense of a filtercake remove (or matrix-acidizing)
treatment. With many of the fluids of the present Invention (those
that do not contain acid) the problem of corrosion is drastically
minimized. Additionally, personnel safety and environmental
concerns are significantly reduced with the fluids of the present
Invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] FIG. 1 shows change in viscosity of various VES solutions at
100 sec.sup.-1 after 101 minutes at 180.degree. F., upon addition
of K.sub.2-EDTA, .alpha.-amylase, ammonium persulfate--either
separately or in combination. These data show for instance, that
the viscosity of VES is not significantly affected by the addition
of 0.5% .alpha.-amylase, nor is it affected by the addition of 0.5%
.alpha.-amylase and 28% K.sub.2-EDTA.
[0024] FIG. 2 shows the effect of various combinations of
.alpha.-amylase and K.sub.2-EDTA on VES (5% by volume) theology: 3%
NH.sub.4Cl and 28% K.sub.2-EDTA (diamonds); 4% KCl (open boxes); 4%
KCl in 28% K.sub.2-EDTA (triangles); 3% NH.sub.4Cl and 0.5%
C-amylase and 28% K.sub.2-EDTA (diagonal crosses with vertical
lines); 3% HN.sub.4Cl in tap water (diagonal crosses); 3%
NH.sub.4Cl and 0.5% .alpha.-amylase (open circles); 4% KCl and 0.5%
.alpha.-amylase in tap water (vertical lines); 4% KCl and 0.5%
C-amylase in 28% K.sub.2-EDTA Light open boxes). These data show,
for instance that the addition of .alpha.-amylase in a VES solution
does not significantly affect VES-solution viscosity at 100
sec.sup.-1, yet if .alpha.-amylase is added to a VES solution to
which 28% K.sub.2-EDTA and KCl are also added, then viscosity is
significantly reduced--though not if NH.sub.4Cl is used instead of
KCl.
[0025] FIG. 3 shows the effect of VES (5%) on the cake-breaking
activity of both enzyme and conventional oxidizer breakers. The
white bars represent (from left to right): (1) no VES, 0.5%
.alpha.-amylase, 4% KCl; (2) no VES, 1% ammonium persulfate, 4%
KCl. The black bars represent: (1) no VES, 0.5% .alpha.-amylase, 4%
KCl, (2) VES, 4% KCl; (3) VES 1% ammonium persulfate; (4) VES, 1%
ammonium persulfate, 0.1% triethanolamine, 4% KCl. The gray bars
represent: (1) VES, 0.5% .alpha.-amylase, 28% K2-EDTA, 4% KCl; (2)
VES, 28% K.sub.2-EDTA, 4% KCl; (3) VES, 1% ammonium persulfate, 28%
K2-EDTA 4% KCl; (4) VES, 5% (low temperature-optimized) ammonium
persulfate, 28% K.sub.2-EDTA, 4%; (5) VES, 5% encapsulated ammonium
persulfate, 28% K.sub.2-EDTA, 4% KCl. All assays were conducted at
150.degree. F. These data show that VES impairs but does not
entirely destroy cake-breaking activity.
[0026] FIG. 4 shows the effect of VES (5%) on two breaker types
(.alpha.-amylase and ammonium persulfate), (1) 1% ammonium
persulfate, no VES (thin gray line); 1% ammonium persulfate, VES
(think black line); (2) 0.5% .alpha.-amylase, no VES (thick gray
line), 0.5% .alpha.-amylase, VES (thick black line). These data
show that VES is compatible with these two breaker systems.
[0027] FIG. 5 shows the effect of VES on K.sub.2-EDTA cake-breaking
activity, 5% VES, 28% K2-EDTA flight gray line), 5% VES, no
K.sub.2-EDTA (dark gray line), no VES, 28% K.sub.2-EDTA (black
line). These data show that the presence of VES substantially
affects K.sub.2-EDTA activity.
[0028] FIG. 6 shows the rheology (shear rate versus viscosity) of
two different types of VES systems (VES and VES.sub.1), a 28%
K.sub.2-EDTA/0.5% .alpha.-amylase system in 5% VES at 125.degree.
F. Sight triangles) compared with similar systems, no
.alpha.-amylase (crosses), 1.5% VES at 75.degree. F. (plus
K.sub.2-EDTA/.alpha.-amylase) (dark triangles), 5% VES.sub.1 at
140.degree. F. (diamonds). These data show that the rheology of a
different VES system is not significantly affected by the addition
of K.sub.2-EDTA/.alpha.-amylase.
[0029] FIG. 7 is identical to FIG. 6 expect that the system was
tested at 200.degree. F. instead of 125.degree. F. These data show
no significant difference in activity of the systems under study at
125 versus 200.degree. F.
[0030] FIG. 8 shows the viscosity (at 170 s.sup.-1) of a 3% VES
solution at 80.degree. F. as a function of HCl concentration. These
data show that, above 15% HCl (between 15 and 25%) solution
viscosity decreases, but below that, the VES-stability is not
affected by the acid.
[0031] FIG. 9 compares the effect of C-amylase and ammonium
persulfate in 5% VES/28% K.sub.2-EDTA solutions, 0.5%
.alpha.-amylase (black line with crosses), no polymer break (gray
line), 1% ammonium persulfate (black line). These data show the
superior activity of .alpha.-amylase over ammonium persulfate in a
VES/K.sub.2-EDTA system.
[0032] FIG. 10 compares the effect of different salts on the
rheology of a 5% VES+27.3% K.sub.2-EDTA system: 4% potassium
chloride (no K.sub.2-EDTA) (crosses); 3% ammonium chloride
(circles) (no K.sub.2-EDTA); 4% potassium chloride (vertical
lines); 3% ammonium chloride (flat boxes). These data show that
K.sub.2-EDTA does not substantially affect the viscosity of the 5%
VES system.
[0033] FIG. 11 shows a comparison of break times (filtercake
degradation) for three different systems: 15% HCl (diamonds), 9%
formic acid (squares), and 28% K.sub.2-EDTA. These data show that
the HCl system breaks the filtercake more rapidly that the other
two systems.
[0034] FIG. 12 shows the effect of .alpha.-amylase on a
K.sub.2-EDTA/VES system on the system's cake-breaking activity. The
systems shown are control/blank (diamonds), K.sub.2-EDTA/VES only
(squares), and K.sub.2-EDTA/VES with .alpha.-amylase. These data
show that the addition of the enzyme substantially enhances
leak-off (a proxy for filtercake degradation), and that this effect
occurs very quickly (<1 minute).
[0035] FIG. 13 shows a comparison of two systems with respect to
their capacity to break filtercake. The two systems are
K.sub.2-EDTA only (diamonds) and K.sub.2-EDTA, and .alpha.-amylase
(squares). These data show that more complete break occurs with the
K.sub.2-EDTA/.alpha.-amylas- e system (after approximately 500
minutes).
[0036] FIG. 14 compares retained permeability for a 5% VES system
in 3% NH.sub.4Cl (2 hrs., 300 psi, 150.degree. F.) upon addition of
various breakers, from left to right: nothing, VES only, 28%
K.sub.2-EDTA only; 14% K.sub.2-EDTA; 28%; 28% K.sub.2-EDTA at pH
5.5; 28% K.sub.2-EDTA+0.5 .alpha.-amylase; and 0.5%
.alpha.-amylase. These data show that the
K.sub.2-EDTA+.alpha.-amylase system gives superior retained
permeability.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0037] Again, the center of gravity, though not the exclusive
scope, of the present Invention, is a set of fluid compositions and
techniques for removing de-watered drilling fluid (i.e.,
"filtercake"). In general, fluids which perform this function are
referred to as "completion fluids." The common denominator of
preferred embodiments (completion fluids) of the present Invention
is they are specifically, though not exclusively, optimized to
degrade/remove drilling filtercake produced from a certain kind of
drilling fluid-a drill-in fluid system, known by the trademark,
STARDRILL.TM.. Primary components of STARDRILL are calcite, starch,
and lesser concentrations of either xanthan or scleroglucan.
[0038] The fluids of the present Invention were designed based on
numerous criteria, two primary criteria are: (1) rheology, i.e.,
ensuring that the fluid rheology at bottom hole circulating
temperature fell with acceptable limits (e.g., sufficient viscosity
to deliver gravel) over a wide shear rate range; and (2) cleanup,
i.e., ensuring that the formulations were effective at removing
filtercake while minimizing damage to the formation and not unduly
interfering with a contemporaneous completion (e.g., gravel
pack).
[0039] In addition, any system design that combines an enzyme and
other breakers must account for the variable activity windows of
the different breakers, particularly since some enzymes are highly
pH and temperature sensitive.
EXAMPLE 1
Stability of VES Systems in the Presence of Breakers
[0040] Again, one object of the present Inveniton is to provide
novel fluids that will degrade, filtercake and which can also serve
as carrier fluids in conjunction with other well treatments,
particularly, gravel pack operations. In the case of gravel pack
operations, the carrier fluid must be viscous in order to transport
the gravel. Thus, VES systems are preferred. Again, VES stands for
"viscoelastic surfactant." The use of VES for well treatment fluids
has validated in numerous actual well treatments. Well treatment
fluids based on VES are the subject of numerous patents and patent
applications, each assigned to Schlumberger, and incorporated by
reference in its entirety. U.S. Pat. No. 5,258,137, Viscoelastic
Surfactant Based Foam Fluids, assigned to Schlumberger Technology
Corporation, 1993; U.S. Pat. No. 5,551,516, Hydraulic Fracturing
Process and Compositions, Schlumberger Technology Corporation,
1996; U.S. patent application Ser. No. 08/727,877, Methods of
Fracturing Subterranean Formations, assigned to Schlumberger
Technology Corporation, filed Oct. 9, 1996; U.S. patent application
Ser. No. 08/865,137, Methods for Limiting the Inflow of Formation
Water and for Stimulating Subterranean Formations, assigned to
Schlumberger Technology Corporation, filed May 29, 1997; U.S.
patent application Ser. No. 09/166,658, Methods of Fracturing
Subterranean Formations, assigned to Schlumberger Technology
Corporation, filed Oct. 5, 1998.
[0041] In the Examples that follow the VES system most often used
is N-cis-13-docosenoic-N,N,-bis(2-hydroxymethyl)-N-methyl ammonium
chloride (a.k.a. N-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium
chloride). In addition, the actual VES system used in the Examples
contains 25% isopropanol to enhance VES stability at low
temperatures. In some instances, a second VES system is used,
referred to as VES.sub.1, and which consists of glyceryl esters of
three different fatty acids, 23.5% erucyl (C.sub.22 with one double
bond), 32% oleic (C.sub.18 with one double bond) and 44.5% linoleic
(C.sub.18 with three double bonds separated by methylene groups)
acids.
[0042] In addition, the VES systems referenced above are fully
compatible with seawater in addition to ordinary tap water. Thus,
the term "VES" subsumes VES systems prepared from seawater in
addition to freshwater. VES systems prepared from seawater are
disclosed and claimed in U.S. patent application Ser. No.
09/166,658, Methods of Fracturing Subterranean Formations, filed
Oct. 10, 1998, and assigned to Schlumberger. This application is
hereby incorporated by reference in its entirety, and particularly
with respect to that portion disclosing the operability of VES
systems prepared from seawater.
[0043] The experimental results that follow illustrate that VES
systems retain their stability (viscosity) upon addition of the
breakers (either alone or in combination) of the present
Invention.
[0044] The following experimental protocol was observed for the
data collected and presented in the Examples that follow. First a
dry sandstone core was weighed, then saturated with brine (to water
wet the core) and then weighed again. Based on comparison of these
two measurements, a pore volume was determined. Next, the core was
heated to test temperature (150.degree. F.). Then, 100 pore volumes
of kerosene was flowed through the filtercake core, at about 10
psi. The purpose of this step is to fill the pores with
hydrocarbon. The sandstone core's permeability to kerosene was then
observed. Next, the kerosene is poured off, then 125 ml of
STARDRILL drilling fluid was applied to the core under a pressure
of 300 psi for about one hour. The goal is simulate overbalanced
conditions within a typical wellbore; hence, the STARDRILL fluid
was "forced" into the core to mimic leakoff. After one hour, the
excess STARDRILL was poured off, and the core was rinsed with
brine.
[0045] Next, the STARDRILL filtercake-coated core was contacted
with a series of "clean-up" solutions--100 ml, at 300 psi for 2
hours (to simulate, e.g., a typical gravel pack operation). In the
case of the data presented in FIG. 14, for instance, each clean-up
solution consisted of a matrix of 5% VES in 3% NH.sub.4Cl. These
solutions are (from left to right in FIG. 14: "backflow" (to
simulate allowing the well to produce without any clean-up. "blank"
(VES only), 28% K.sub.2-EDTA; 14% K.sub.2-EDTA; 28% K.sub.2-EDTA at
pH 5.5; 28% K.sub.2-EDTA+0.5% .alpha.-amylase; and 0.5%
.alpha.-amylase. In each instance, the amount of clean-up solution
contacted with the sandstone core was 100 ml. After two hours, the
leak-off volumes were observed; the retained permeability to
kerosene was measured at the test temperature.
[0046] Upon preparing the breaker systems in the VES matrix, none
of the fluids showed sedimentation or phase separation; however,
when the pH of the VES in 28% K.sub.2-EDTA) was increased to values
higher than 11, a white waxy substance was observed. Apparently at
this high pH, the EDTA-complex interferes with the surfactants and
worm-like micellar structure in the VES system. The viscosity of
the systems under study was measured using API Standard ramps at
180F (100 sec.sup.-1 viscosity). The source of the viscoelastic
behavior and the high low-shear viscosity of VES-based solutions is
the wormlike micellar structure formed by the surfactants (either
4% KCl or 3% NH.sub.4Cl). Addition of filtercake-breakers may
affect this micellar structure, and hence also the the rheological
behavior of the VES solutions. This can occur either through
reaction of the additive with the VES-surfactant molecule or by
interaction of the additive VES with the CF micellar structure.
[0047] The results shall now be discussed. FIG. 1 is an overview of
the viscosities measured for 5% VES-solutions with various
additives. The values correspond to 100 s.sup.-1 after shearing the
sample at 100 s.sup.-1 for 101 minutes. This viscosity is
calculated from the API-ramps that were taken at that point. These
data show for instance that VES viscosity (and probably the
microscopic micellar structure) are not significantly affected by
the addition of either EDTA or .alpha.-amylase, or by the addition
of the two breakers together.
[0048] FIG. 2 reports related data. There, the effect of the
addition of starch-breaking enzyme .alpha.-amylase on VES rheology
is shown. According to FIG. 2, addition of .alpha.-amylase to a
VES-in-brine solution does not significantly affect the viscosity
of VES at 100 sec.sup.-1. Yet, when .alpha.-amylase is added to VES
in EDTA/KCl brine, the viscosity is reduced considerably. It is
striking that this effect does not occur if EDTA/NH.sub.4Cl brine
is used. Repetition of both tests gave similar results.
[0049] FIG. 6 shows the effect on the rheology of VES systems to
which 28% K.sub.2-EDTA and 4% KCl are added (at 125.degree. F. if
not specified). These data show that the rheology of VES is not
significantly affected by the addition of either K.sub.2-EDTA or
.alpha.-amylase, or both. FIG. 7 presents similar data though at
higher temperature. In addition what these two Figures also show is
that both 5% VES (short-chain) VES at 140.degree. F. and 1.5%
(long-chain) VES at 75.degree. F. are competent gravel pack carrier
fluids. Hence, in accordance with the present Invention, it is now
possible to formulate gravel pack carrier fluids containing filter
cake breakers for 125 and 150.degree. F., that have similar
rheology.
[0050] FIG. 8 shows the effect of varying HCl concentration on the
viscosity of a 3% VES system at 80.degree. F. As evidenced by these
data, viscosity is barely affected from about 5% HCl to about 15%
HCl, after which viscosity falls off significantly.
[0051] Finally, FIG. 10 compares the effect of different salts
(sodium salicylate, KCl, and NH.sub.4Cl) on the rheology of a 5%
VES system. These data convincingly demonstrate that K.sub.2-EDTA
(at up to 28%, which is roughly the solubility limit of EDTA in
water) does not substantially affect the viscosity of a 5% VES
system. Additionally, these data show that neither KCl nor
NH.sub.4Cl affects the rheology of the 5% VES system; however,
sodium salicylate, even at very low concentrations (0.5%) has a
dramatic effect on VES viscosity when EDTA is present (an
approximately 40% decrease in viscosity).
[0052] From these data, two sets of particularly preferred
embodiments emerge. These are completion fluids having both
.alpha.-amylase and EDTA with or without VES. Yet if VES is used as
the matrix, then the preferred salt is NH.sub.4Cl at about 3%.
Thus, one particular preferred completion fluid of the present
Invention contains: 5% VES, 0.5% .alpha.-amylase, and 28%
K.sub.2-EDTA, in a 4% NH.sub.4Cl solution. Another particular
preferred fluid is: , 0.5% .alpha.-amylase, and 28% K.sub.2-EDTA,
in a 4% salt solution (the salt type is less critical if VES is not
used).
[0053] Without intending to be bound by this suggested mechanism,
we posit that the combination of chelating agent and enzyme (e.g.,
K.sub.2-EDTA and .alpha.-amylase) operate in synergy to break filer
cake comprised of starch and calcite. More particularly, the starch
polymer and the calcite are arranged in a complex configuration,
e.g., the polymer coating the calcite particles. Thus, a breaker
that acts primarily upon the polymer (e.g., an enzyme) will simply
degrade the particle coating, but leave the particles untouched.
Similarly, a breaker that acts primarily upon the calcite particles
will have difficulty reaching them due to the polymer coating-hence
the observed synergistic activity of the enzyme+chelating agent
combination fluid.
[0054] The goal of an ideal completion fluid is that it degrade the
filtercake to the greatest extent possible while at the same time
ensuring a high retained permeability. Thus, a completion fluid
that resulted in maximum filtercake degradation but that left
filtercake particles embedded in the wellbore, is ineffective,
since retained permeability will be low. Therefore, the degradation
must be even and complete-i.e., result in small particles that
cannot plug the wellbore, but that can be removed in a circulating
wash or can be produced with the hydrocarbon.
EXAMPLE 2
Breaker Activity in VES Systems
[0055] The previous Example adequately demonstrated that VES
systems are stable--i.e., their viscosity is not substantially
affected in the presence of the breakers of the present Invention
(e.g., HCl, formic and acetic acid, enzymes, and chelating agents).
This Example demonstrates that the VES matrix does not
substantially affect the activity of the breakers-i.e., with
respect to breaking filtercake.
[0056] FIG. 3 shows the effect of VES (5%) on the activity of both
enzyme (.alpha.-amylase) and conventional oxidizer breakers
(ammonium persulfate, dissolved and encapsulated). These data show
that VES inhibits the activity of breakers of proven efficacy.
[0057] As evidenced by FIG. 4, the data presented in FIG. 3 must be
qualified by an evaluation of the time-dependence of these systems.
FIG. 4 shows that VES actually increases the activity of (X-amylase
over approximately the first 65 minutes of the test.
[0058] FIG. 5 shows the results of an K.sub.2-EDTA system (in the
presence of 5% VES and without). These results show that VES does
have a substantial effect on EDTA activity.
EXAMPLE 3
Performance of the Completion Fluids of the Present Invention
[0059] Having shown that the various breaking agents (e.g., acid,
enzymes, and chelating agents) separately or in combination, are
effective in VES solutions (as well in non-VES solutions) and
having shown to what extent these agents are affected by the VES,
we shall now demonstrate in more detail the superior performance of
the completion fluids of the present Invention.
[0060] The purpose of this Example is to demonstrate that certain
formulations of the present Invention exhibit superior filtercake
removal--compared with conventional systems. The experimental
protocol in this Example was carefully designed to simulate, as
closely as possible, actual conditions in an exemplary water-wet,
oil-saturated, sandstone reservoir.
[0061] The data presented in FIG. 9 compares the effect of
.alpha.-amylase versus an oxidizer breaker (ammonium persulfate) in
a VES/K.sub.2-EDTA system (5% VES, 28% K.sub.2-EDTA, 4% KCl). These
data show that an enzyme+EDTA system is unquestionably superior to
an oxidizer+EDTA system. These data are surprising since, while the
EDTA is directed to the calcite fraction of the filtercake, the
oxidizer and .alpha.-amylase are directed to the polymer fraction.
Therefore, both binary systems are "complete" in that they contain
a breaker for each of the two fractions comprising the filtercake,
hence one might expect comparable filtercake removal rates (or
extent).
[0062] FIG. 11 presents data that compares the activity (break
times) of 15% HCl, formic acid, and 28% K.sub.2-EDTA in 5% VES, as
a function of temperature. As evidenced by FIG. 11, the EDTA system
outperforms the acid systems by a substantial margin, particularly
at lower temperatures.
[0063] FIGS. 12 and 13 compare the activity of an EDTA system
versus an EDTA/.alpha.-amylase system, in VES (FIG. 12) and without
VES (FIG. 13). A comparison of the two Figures shows that the
EDTA-only system is actually enhanced in the presence of VES,
though this effect is unobservable prior to about 90 minutes. FIG.
12 corroborates earlier data showing the superior performance of
the chelating agent/enzyme system compared with chelating agent by
itself. FIG. 12 also shows that this effect is very rapid--less
than one minute).
[0064] The leak-off data of FIG. 14 is consonant with that
presented in FIG. 12. Most significantly though, FIG. 14 shows that
the EDTA/.alpha.-amylase system gives the highest retained
permeability--over 90%, compared with the EDTA-only system which
resulted in a retained permeability of just over 80%. Therefore,
the VES/EDTA/.alpha.-amylase system of the present Invention is
demonstrably superior to conventional clean-up formulations on both
relevant axes of comparison: leak-off and retained permeability.
Moreover, results presented earlier (e.g., FIG. 4 for
.alpha.-amylase; FIG. 5 for EDTA) show that VES is a viable carrier
fluid for the EDTA/.alpha.-amylase system. Similarly, as evidenced
by the results presented in FIGS. 1 and 2, the EDTA/.alpha.-amylase
system activity does not significantly affect the characteristics
of the VES matrix (e.g., viscosity).
[0065] Finally, the skilled treatment designer will recognize that
chelating agents other than EDTA are operable in fluid compositions
of the present Invention. The relevant parameters for selection of
the fluid are the calcite (or other mineral) dissolution constant
(a thermodynamic parameter), the proton dissociation constants
(also thermodynamic parameters), and kinetic parameters. The
skilled treatment designer can infer the behavior of other
chelating agents by comparing those parameters for EDTA with those
for the chelating agent under consideration. A systematic study of
the kinetics of calcite dissolution by various chelating agents
(including EDTA, DTPA, and CDTA) is presented in C. N. Fredd and H.
S. Fogler, The Influence of Chelating Agents on the Kinetics of
Calcite Dissolution 204 J. Colliod Interface Sci. 187 (1998). This
article is incorporated by reference in its entirety.
EXAMPLE 4
Specialized Applications
[0066] The fluids and techniques of the present Invention are quite
general and are operable in a variety of settings. Since the
problem of placement and uniform dissolution are present in
virtually every instance, the fluids and techniques of the present
Invention are readily applicable to any scenario in which it is
desirable to remove filtercake from the wellbore or near-wellbore
region in the formation, regardless of whether the filtercake was
produced during drilling or during other post-drilling operations
(e.g., fluid-loss control pill, gravel pack operation, fracturing,
matrix acidizing, and so forth). The fluids and techniques of the
present Invention are applicable in numerous different
environments, including:
[0067] screen-only completions and gravel pack completions;
[0068] open hole and case hole;
[0069] vertical and highly deviated wells;
[0070] single-stage soak fluid or circulating fluid in which the
treatment fluid (of the present Invention) also serves as a carrier
fluid for, e.g., a gravel pack operation;
[0071] in conjunction with a gelling agent such as a viscoelastic
surfactant (e.g., ClearFRAC.TM.) or alone;
[0072] with a variety of clean-up tools and unconventional
technologies (e.g., Mobil's Alternate Path Technology, see, e.g.,
L. G. Jones, et al., Gravel Packing Horizontal Wellbores With
Leak-Off Using Shunts, SPE 38640, hereby incorporated by reference
in its entirety); or
[0073] in conjunction with other fluid additives (e.g.,
anti-corrosive agents) or dissolution components (e.g., an
oxidizer).
[0074] One such specialized setting in which the fluids of the
present Invention can be applied is a particular type of gravel
pack operation known as "AllPAC" or Alternate Path technology. (As
used herein, the term "gravel pack" includes treatments
incorporating the AllPAC technology. This technology is described
in a number of patents, each is assigned to Mobile, and licensed
exclusively to Schlumberger. U.S. Pat. No. 5,560,427, Fracturing
and Propping a Formation Using a Downhole Slurry Splitter (1996);
U.S. Pat. No. 5,515,915, Well Screen Having Internal Shunt Tubes
(1996); U.S. Pat. No. 5,419,394, Tools for Delivering Fluid to
Spaced Levels in a Wellbore (1995); U.S. Pat. No. 5,417,284, Method
for Fracturing and Propping a Formation (1995); U.S. Pat. No.
5,390,966, Single Connector for Shunt Conduits on Well Tool (1995);
U.S. Pat. No. 5,333,688, Method and Apparatus for Gravel Packing of
Wells (1994); U.S. Pat. No. 5,161,613, Apparatus for Treating
Formations Using Alternate Flopaths (1992); U.S. Pat. No.
5,113,935, Gravel Packing of Wells (1992); U.S. Pat. No. 5,082,052,
Apparatus for Gravel Packing Wells (1992); U.S. Pat. No. 4,945,991,
Method for Gravel Packing Wells (1990). Each of these patents is
incorporated by reference in its entirety.
[0075] The significance of the AllPAC technology to the fluids and
techniques of the present Invention cannot be over-emphasized.
Without AllPAC, gravel packing with a viscous carrier fluid is very
difficult, in some instances, virtually impossible. AllPAC screen
is comprised of shunt tubes which permit the easy flow of viscous
fluid through the screen annulus to its intended situs.
[0076] In addition, a thorough discussion of filtercake removal in
conjunction with sand control operations, in open-hole horizontal
wells is provided in C. Price-Smith, et. al., Open Hole Horizontal
Well Cleanup in Sand Control Completions: State of the Art in Field
Practice and Laboratory Development, SPE 50673 (1998). This article
is incorporated by reference in its entirety.
[0077] The ALLPAC technology incorporates a novel gravel pack
screen device which contains "shunt-tubes" or alternate flow paths,
attached to the sides of the screen. These shunt tubes permit
effective gravel packing by elimtinating bridging (or more
precisely, by letting the fluid flow around a bridged zone), thus
even long horizontal sections can be gravel packed even with high
fluid loss. Therefore, when the fluids of the present Invention are
used in conjunction with the ALLPAC technology, a novel method is
enabled. In this method, the filtercake is readily cleaned up
during the gravel pack operation since fluid loss (leak-off) will
not substantially interfere with the quality of the gravel pack.
Thus rig time is substantially reduced by combining filtercake
removal with gravel pack treatment.
[0078] Indeed, combined gravel pack/filtercake removal treatments
the fluids of the present Invention incorporating the AllPAC
technology provide a cost-effective means to complete a well. A
yard test with a single shunt tube placed in side a slotted liner
packed an entire length of 2,000 ft using the VES. During this
test, it was found that 40/60 gravel (approx. 50 darcies)) was
sufficient to divert flow down the shunt tube. Again, leak off is
not a concern, which is another substantial advantage of the AllPAC
technology as it is exploited using the fluids and methods of the
present Invention.
* * * * *