U.S. patent application number 10/308619 was filed with the patent office on 2003-09-04 for non-damaging fluid-loss pill and method of using the same.
Invention is credited to Marcinew, Richard, Samuel, Mathew, Xiao, Zhijun.
Application Number | 20030166471 10/308619 |
Document ID | / |
Family ID | 23316164 |
Filed Date | 2003-09-04 |
United States Patent
Application |
20030166471 |
Kind Code |
A1 |
Samuel, Mathew ; et
al. |
September 4, 2003 |
Non-damaging fluid-loss pill and method of using the same
Abstract
A fluid-loss pill that includes a brine solution and an
effective amount of a viscoelastic surfactant is disclosed. The
viscoelastic surfactant preferably includes at least one compound
selected from the family of compounds described by 1 where R.sub.1,
R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are carbon atom or carbon
chains, saturated or unsaturated, single or multiple unsaturation,
straight chain, branched chain or cyclic including aromatic or
alicyclic groups, and R.sub.1 contains 16-26 carbon atoms, R.sub.2
contains 2-10 carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains
1-6 carbon atoms. Methods of treating a well that include injecting
fluid-loss pill into a well to control lost-circulation or to kill
a well.
Inventors: |
Samuel, Mathew; (Al-Khobar,
SA) ; Marcinew, Richard; (Al-Khobar, SA) ;
Xiao, Zhijun; (Kuala Lumpur, MY) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION
IP DEPT., WELL STIMULATION
110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
23316164 |
Appl. No.: |
10/308619 |
Filed: |
December 3, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60336455 |
Dec 3, 2001 |
|
|
|
Current U.S.
Class: |
507/200 |
Current CPC
Class: |
C09K 2208/30 20130101;
C09K 8/52 20130101; C09K 8/06 20130101; C09K 8/508 20130101; C09K
8/62 20130101; C09K 8/506 20130101; C09K 2208/18 20130101; C09K
8/68 20130101 |
Class at
Publication: |
507/200 |
International
Class: |
E21B 001/00 |
Claims
What is claimed is:
1. A fluid loss control, lost-circulation pill comprising: An
aqueous solution; and A viscoelastic surfactant added in an
effective amount to provide an increase of viscosity at near-static
reservoir conditions.
2. The fluid loss pill of claim 1 wherein the viscoelastic
surfactant comprises at least one compound selected from the family
of compounds described by 6where R.sub.1, R.sub.2, R.sub.3, R.sub.4
and R.sub.5 are carbon atom or carbon chains, saturated or
unsaturated, single or multiple unsaturation, straight chain,
branched chain or cyclic including aromatic or alicyclic groups,
and R.sub.1 contains 16-26 carbon atoms, R.sub.2 contains 2-10
carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains 1-6 carbon
atoms.
3. The fluid loss pill of claim 1 wherein the aqueous solution is a
brine having a density of at least 11.5 pgg.
4. The fluid loss pill of claim 1, wherein the viscoelastic
surfactant comprises an erucylamidopropyl betaine.
5. The fluid loss pill of claim 1, wherein the viscoelastic
surfactant an oleylamidopropyl betaine
6. The fluid loss pill of claim 1, wherein the viscoelastic
surfactant blend comprises about 2% to about 30% by volume of the
fluid loss pill.
7. The fluid loss pill of claim 6, wherein the viscoelastic
surfactant comprises about 5% to about 20% by volume of the fluid
loss pill.
8. The fluid loss pill of claim 7, wherein the viscoelastic
surfactant comprises about 10% to 15% of the fluid loss pill.
9. The fluid loss pill of claim 1, further comprising a
cosurfactant selected among the class of benzene sulfonate
described by 7
10. The fluid loss pill of claim 1, further comprising particulates
selected among acid or chelant soluble particulates, resins, graded
starches and polymers.
11. The fluid loss pill of claim 10, wherein the fluid loss pill
comprises calcium carbonate as acid soluble bridging
particulates.
12. A method of controlling loss circulation in a well comprising
injecting a fluid loss pill comprising: An aqueous solution; and A
viscoelastic surfactant added in an effective amount to provide an
increase of viscosity at near-static reservoir conditions.
13. The method of claim 12 wherein the viscoelastic surfactant
comprises at least one compound selected from the family of
compounds described by 8where R.sub.1, R.sub.2, R.sub.3, R.sub.4
and R.sub.5 are carbon atom or carbon chains, saturated or
unsaturated, single or multiple unsaturation, straight chain,
branched chain or cyclic including aromatic or alicyclic groups,
and R.sub.1 contains 16-26 carbon atoms, R.sub.2 contains 2-10
carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains 1-6 carbon
atoms.
14. The method of claim 12 wherein the aqueous solution is a brine
having a density of at least 11.5 pgg.
15. The method of claim 12, wherein the viscoelastic surfactant
comprises an erucylamidopropyl betaine.
16. The method of claim 12, wherein the viscoelastic surfactant an
oleylamidopropyl betaine
17. The method of claim 12, wherein the viscoelastic surfactant is
used in conjunction with a polymer, linear or crosslinked to build
viscosity and also to develop a filtercake.
18. The method of claim 12, wherein the viscoelastic surfactant
blend comprises about 2% to about 30% by volume of the fluid loss
pill.
19. The method of claim 12, wherein the pill further comprises a
cosurfactant selected among the class of benzene sulfonate
described by 9
20. The method of claim 12, wherein the pill further comprises
particulates selected among acid or chelant soluble particulates,
resins, graded starches and polymers.
21. A method of killing a well comprising injecting a fluid loss
pill comprising: An aqueous solution; and A viscoelastic surfactant
added in an effective amount to provide an increase of viscosity at
near-static reservoir conditions.
22. The method of claim 21 wherein the viscoelastic surfactant
comprises at least one compound selected from the family of
compounds described by 10where R.sub.1, R.sub.2, R.sub.3, R.sub.4
and R.sub.5 are carbon atom or carbon chains, saturated or
unsaturated, single or multiple unsaturation, straight chain,
branched chain or cyclic including aromatic or alicyclic groups,
and R.sub.1 contains 16-26 carbon atoms, R.sub.2 contains 2-10
carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains 1-6 carbon
atoms.
23. The method of claim 21 wherein the aqueous solution is a brine
having a density of at least 11.5 pgg.
24. The method of claim 21, wherein the viscoelastic surfactant
comprises an erucylamidopropyl betaine.
25. The method of claim 21, wherein the viscoelastic surfactant an
oleylamidopropyl betaine
26. The method of claim 21, wherein the viscoelastic surfactant is
used in conjunction with a polymer, linear or crosslinked to build
viscosity and also to develop a filtercake.
27. The method of claim 21, wherein the viscoelastic surfactant
blend comprises about 2% to about 30% by volume of the fluid loss
pill.
28. The method of claim 21, wherein the pill further comprises a
cosurfactant selected among the class of benzene sulfonate
described by 11
29. The method of claim 21, wherein the pill further comprises
particulates selected among acid or chelant soluble particulates,
resins, graded starches and polymers.
30. A method of pre-conditioning a well in a high-permeable
reservoir prior to performing the injection of a polymer-base fluid
comprising injecting a fluid loss pill An aqueous solution; and A
viscoelastic surfactant added in an effective amount to provide an
increase of viscosity at near-static reservoir conditions. to
minimize to the volume of polymer invasion into the formation
before the formation of the polymer-containing filter cake.
31. The method of claim 30 wherein the viscoelastic surfactant
comprises at least one compound selected from the family of
compounds described by 12where R.sub.1, R.sub.2, R.sub.3, R.sub.4
and R.sub.5 are carbon atom or carbon chains, saturated or
unsaturated, single or multiple unsaturation, straight chain,
branched chain or cyclic including aromatic or alicyclic groups,
and R.sub.1 contains 16-26 carbon atoms, R.sub.2 contains 2-10
carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains 1-6 carbon
atoms.
32. The method of claim 30 wherein the aqueous solution is a brine
having a density of at least 11.5 pgg.
33. The method of claim 30, wherein the viscoelastic surfactant
blend comprises about 2% to about 30% by volume of the fluid loss
pill.
34. The method of claim 30, wherein the pill further comprises a
cosurfactant selected among the class of benzene sulfonate
described by 13
35. The method of claim 30, wherein the pill further comprises
particulates selected among acid or chelant soluble particulates,
resins, graded starches and polymers.
36. A method of packing a well comprising the placement of solids
comprising the use of a fluid comprising An aqueous solution; and A
viscoelastic surfactant added in an effective amount to provide an
increase of viscosity at near-static reservoir conditions.
37. The method of claim 36 wherein the viscoelastic surfactant
comprises at least one compound selected from the family of
compounds described by 14where R.sub.1, R.sub.2, R.sub.3, R.sub.4
and R.sub.5 are carbon atom or carbon chains, saturated or
unsaturated, single or multiple unsaturation, straight chain,
branched chain or cyclic including aromatic or alicyclic groups,
and R.sub.1 contains 16-26 carbon atoms, R.sub.2 contains 2-10
carbon atoms, R.sub.3, R.sub.4 and R.sub.5 contains 1-6 carbon
atoms.
38. The method of claim 36 wherein the aqueous solution is a brine
having a density of at least 11.5 pgg.
39. The method of claim 36 wherein the step of placing solids
comprises the step of proppants placement.
40. The method of claim 39 wherein the step of packing is performed
on a sand control screen.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This Application claims the benefit of U.S. Provisional
Patent Application No. 60/336,455, filed on Dec. 3, 2001.
FIELD OF THE INVENTION
[0002] The invention relates generally to the exploitation of
hydrocarbon-containing formations or injection wells. More
specifically, the invention relates to fluid-loss control of well
treatment fluids.
BACKGROUND ART
[0003] When drilling or completing wells in earth formations,
various fluids typically are used in the well for a variety of
reasons. The fluid often is aqueous. For the purposes herein, such
fluid will be referred to as "well fluid." Common uses for well
fluids include: lubrication and cooling of drill bit cutting
surfaces while drilling generally or drilling-in (i.e., drilling in
a targeted petroliferous formation), transportation of "cuttings"
(pieces of formation dislodged by the cutting action of the teeth
on a drill bit) to the surface, controlling formation pressure to
prevent blowouts, maintaining well stability, suspending solids in
the well, minimizing fluid loss into and stabilizing the formation
through which the well is being drilled, fracturing the formation
in the vicinity of the well, displacing the fluid within the well
with another fluid, cleaning the well, testing the well, implacing
a packer fluid, abandoning the well or preparing the well for
abandonment, and otherwise treating the well or the formation.
[0004] During the drilling of an hydrocarbon or injection well, the
well fluid is injected into the well through a drill pipe and
re-circulated to the surface in the annular area between a wellbore
wall and a drill string. The well fluid properties are constantly
monitored during the drilling operations and tailored to
accommodate the nature of the formation stratum being encountered
at the time. When drilling reaches the producing formation, special
concern is exercised. Preferentially, low solids content fluids are
used to minimize possible productivity loss by solids plugging
pores in the formation. Proper fluid density for overbalancing
formation pressure may be obtained by using high salt concentration
aqueous brines, while viscosity and fluid loss control generally
are attempted by polymer addition, and/or acid soluble particulates
such as calcium carbonate or size salt in saturated brine
solution.
[0005] Brines (such as calcium bromide, calcium chloride, zinc
chloride and zinc bromide or mixtures of these) commonly are used
as well fluids because of their wide density range and the fact
that brines are typically substantially free of suspended solids.
Additionally, brines typically do not damage certain types of
downhole formations. High density brines (for instance having a
density greater than 11 or even greater than 12.5 ppg) are
typically used for instance when over-pressured and/or highly
permeable and/or poorly consolidated formations are penetrated. The
high permeability of many hydrocarbon zones allows large quantities
of fluid to be lost to the formation. Dense brines are often
viscosified with crosslinked polymer, but the crosslinking is not
easy and predictable. When this crosslinked fluids are lost into
the formation by leakoff, it is often very difficult to unload them
from formations. Dense brines, e.g., calcium and zinc salts, can
form highly stable, acid-insoluble compounds when reacted with some
formation brines. Because of the high density of these brines,
stratification tends to further inhibit the removal. Once the
drilling fluid is lost into the formation, it becomes difficult to
remove. Therefore, the most effective means of preventing this type
of formation damage is to limit brine losses to the formation.
Likewise, losses of wellbore fluids occur when heavy brines are
used in other operations such as stimulation, perforation and
post-fracturing treatments.
[0006] Providing effective fluid loss control is highly desirable
to prevent damaging the formation in, for example, completion,
drilling, drill-in, displacement, perforations, hydraulic
fracturing, work-over, packer fluid placement or maintenance, well
treating, or testing operations. Techniques that have been
developed to control fluid loss include the use of "fluid loss
pills" or "lost circulation pills." Significant research has been
directed to determining suitable materials for the fluid loss
pills, as well as controlling and improving the properties of the
fluid loss pills. Excessive loses of high density brine into the
formation have always been a major concern during completion
operations, that lead to well control issues, as well as well bore
damage. The problem becomes more complex when the static bottomhole
temperature (BHT) exceeds 250.degree. F., and the job involves
running gravel pack assemblies and downhole sand screens.
[0007] Typically, lost-circulation pills are composed of very high
concentrations of crosslinked polymers, with or without bridging
particulates. Conventional fluid loss pills consist typically of a
crosslinked polymer, for instance a derivative cellulose such as
hydroxyethylcellulose, shredded into semi-rigid particulates. The
pills may further comprise bridging particulates, usually graded
sodium or potassium salts, or sized calcium carbonate particulates.
The sealing mechanism in these pills is a combination of viscosity,
solids bridging, and cake buildup on the porous rock. Due to the
instability of polymers at high BHT, incompatibility with some
divalent heavy brines, and the necessity to do remedial treatments
with acid or similar, a new solids-free lost circulation pill, that
is stable for prolonged periods at high BHT was developed.
[0008] Typically, fluid loss pills are used to inhibit the flow
from the formation to the well bore and work by enhancing
filter-cake buildup on the face of the formation to inhibit fluid
flow into the formation from the well bore. However, these fluid
loss pills can cause severe damage to near-wellbore areas due to
polymer filtration or filter-cake formation after their
application. At some point in the completion operation, the filter
cake must be removed to restore the formation's permeability,
preferably to its original level. If the formation permeability is
not restored to its original level, production levels can be
significantly reduced. Polymer-based fluid-loss control pills often
require long period of clean-up. Moreover, an effective clean-up
usually requires fluid circulation to provide high driving force
which allows diffusion to take place to help dissolve the
concentrated build up of materials and such fluid circulation may
not be feasible.
[0009] Graded salt particulates can be dissolved and removed by
circulating water or unsaturated salt brine. In the case of a
gravel pack operation, if this occurs before gravel packing, the
circulating fluid often causes sloughing of the formation into the
wellbore and yet further loss of fluids to the formation. If
removal is attempted after the gravel pack, the gravel packing
material often traps the particles against the formation and makes
removal much more difficult. Particulates such as carbonates, can
be removed with circulation of acid. Acids used for this treatment
is corrosive and the treatment can affect expensive screens, pumps
and other down hole tools. If the filter cake with starch and
Calcium carbonate is not removed, it can partially peak off (when
the well is producing) and float and move randomly in the fluid and
come out and get trapped in the surface equipments. On the other
hand, not removing the filter cake may seriously affect the
productivity (or injectivity) of the well.
[0010] Oil-soluble resins, sized calcium carbonates and graded salt
particulate will remain isolated in the pores of the formation
unless they are in contact with solvent. In the cases where the
solid materials cover a long section of wellbore, the rapid
dissolution by solvent causes localized removal. Consequently, a
thief zone forms and the majority of the solvent leaks through the
thief zone instead of spreading over the entire wellbore length.
This will dramatically lower the effectiveness of the Cleanup.
[0011] The use of conventional gel pills made from crosslinked
polymers in controlling fluid loss requires pumping the material
through large-diameter tubing because of high friction pressures.
These materials are typically prepared at the well site. The most
commonly used fluid-loss control pills contain high concentrations
(100 to 150 lbs/1000 gal) of hydroxyethylcellulose (HEC). HEC is
generally accepted as a polymer affording minimal permeability
damage during completion operations. Normally, HEC polymer
solutions do not form rigid gels, but control fluid loss by a
viscosity-regulated or filtration mechanism. Such polymer fluids
may penetrate deeper into the formation than other crosslinked
polymers. Permeability damage may increase with increasing
penetration of such polymeric fluids.
[0012] U.S. Pat. No. 5,981,447 provides fluid loss pill comprised
of a crosslinked gel of HEC by zirconium. This product requires a
pH greater than 12.5. The pH increase is achieved by adding
magnesium oxide, which solubility is improved by adding a chelant.
By a chelating mechanism, the high-temperature stability of the
crosslinked gel is improved up to 290.degree. F. The use of high pH
in a calcium, magnesium and iron environment could precipitate the
corresponding hydroxides that will further reduce leakoff, but
these insoluble are damaging and are difficult to remove. In a
typical fluidloss pill, there may be a need to more than ten
additives such as a temperature stabilizer, a delaying agent, a
gelling agent, a pH adjusting agent, a crosslinker, a crosslinker
activator, a chelating agent, a breaker, a breaker aid, a biocide,
and fluid loss additives.
[0013] Because of the high temperature, high shear (caused by the
pumping and placement), high pressures, and low pH to which well
fluids are exposed ("stress conditions"), the polymeric materials
used to form fluid loss pills and to viscosify the well fluids tend
to degrade rather quickly. In particular, for many of the cellulose
and cellulose derivatives (such as HEC) used as viscosifiers and
fluid control loss agents, significant degradation occurs at
temperatures above 200.degree. F. and higher. HEC, for example, is
considered sufficiently stable to be used in an environment of no
more than about 225.degree. F. Likewise, because of the high
temperature, high shear, high pressures, and low pH to which well
fluids are exposed, xanthan gum is considered stable to be used in
an environment of no more than about 290 to 300.degree. F., or
about 320 to 330.degree. F. in the presence of salts of
formate/acetate anions. Since these formulations are short lived
above 280.degree. F., it will not provide sufficient time to do
well operations after killing the well.
[0014] What is needed, therefore, are simple non-damaging
polymer-free fluid loss pills that can withstand high temperature
conditions.
SUMMARY OF INVENTION
[0015] In one aspect, the present invention relates to a fluid loss
or lost-circulation-control pill, that includes an aqueous
solution, and an effective amount of a viscoelastic surfactant,
wherein the viscoelastic surfactant added in an effective amount to
provide an increase of viscosity at near-static reservoir
conditions. By near-static reservoir conditions it is hereby meant
substantially no-shear such as for instance of about 1
sec.sup.-1.
[0016] The aqueous solution may be fresh water or preferably a
brine, in particular a heavy divalent metal brine from low to
saturated solutions, preferably having a density of 11 ppg and most
preferably higher than 12.5 ppg or higher.
[0017] In a preferred aspect of the invention, the viscoelastic
surfactant comprises at least one compound selected from the family
of compounds described by 2
[0018] where R.sub.1, R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are
carbon chains, saturated or unsaturated, straight, branched or
cyclic including aromatic groups, and R.sub.1 contains 16-26 carbon
atoms, R.sub.2 contains 2-10 carbon atoms, R.sub.3, R.sub.4 and
R.sub.5 contains 1-6 carbon atoms and wherein said viscoelastic
surfactant is added in an effective amount to provide an increase
of viscosity at near-static reservoir conditions.
[0019] In another aspect, the present invention relates to a method
of treating a well that includes injecting a fluid-loss pill or
lost-circulation-control pill into a well, wherein the fluid-loss
pill includes a viscoelastic surfactant and a brine solution are
also disclosed.
[0020] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
DETAILED DESCRIPTION
[0021] In one aspect, the present invention discloses an additive
for a "fluid-loss pill" that is based on a viscoelastic surfactant,
which is capable of being used in a vast range of temperatures. In
one embodiment, the well fluid may be used as a fluid loss pill.
Furthermore, the well fluid of the present invention is stable at
high temperatures (in excess of 350.degree. F.). In some
embodiments of the invention for instance, the fluid is stable at
300.degree. F. for extended periods >72 hours and for >36 hrs
at 320.degree. F. When used as a fluid loss pill, the well fluid is
compatible with oilfield heavy brines and does not require the
addition of further fluid loss materials such as starch, sized
salts, carbonate chips, mica or other particulates, though this
well fluid is compatible and can be used with these materials.
[0022] The base fluid may be fresh water or an aqueous solution
comprising mono, di or trivalent metal salts, ammonium or mixtures
of these. For some applications, in particular where freezing might
be expected, the base fluid may further comprises an alcohol such
as methanol, ethanol, propanol or a polyalcohol such a glycol or
polyglycols or mixture thereof.
[0023] In particular embodiments, the present invention is based on
adding an effective amount of a surfactant from a particular family
of zwitterionic viscoelastic surfactants to a well fluid. In a
preferred aspect of the invention, the viscoelastic surfactant
comprises at least one compound selected from the family of
compounds described by the general structure shown below: 3
[0024] Surfactants that are suitable for embodiments of the present
invention includes those in which the carbon chains R.sub.1,
R.sub.2, R.sub.3, R.sub.4 and R.sub.5 are carbon chains, saturated
or unsaturated, straight, branched or cyclic including aromatic
groups, and R.sub.1 contains 16-26 carbon atoms (not counting the
carbonyl carbon atom), R.sub.2 contains 2-10 carbon atoms, R.sub.3,
R.sub.4 and R.sub.5 contains 1-6 carbon atoms.
[0025] In a preferred aspect of the invention, R2 and R5 are
straight saturated chains and most preferably, the compounds are
from the family of betaines. Two preferred examples of viscoelastic
surfactants from the family of betaines are BET-O and BET-E. The
surfactant in BET-O-30 is shown below. It is manufactured by
Rhodia, Inc. Cranbury, N.J., U.S.A. It contains an oleyl acid amide
group (including a C.sub.17H.sub.33 alkene tail group) and contains
about 30% active surfactant; the remainder is substantially water,
sodium chloride, and a winterizing agent. 4
[0026] An analogous material, BET-E-40, is also available from
Rhodia and contains a erucic acid amide group (including a
C.sub.21H.sub.41 alkene tail group) and is about 40% active
ingredient, with the remainder substantially water, sodium
chloride, and isopropanol. The surfactant in BET-E-40 is also shown
below. BET surfactants, and others, are described in U.S. Pat. No.
6,258,859, which is assigned to the assignee of the present
invention, and is incorporated herein by reference. 5
[0027] The viscoelastic surfactant is typically added in a quantity
such that the above viscoelastic surfactant blend comprises about
3% to about 30% by volume of the "fluid-loss pill" (bearing in mind
that the surfactant itself is added as a solution. Therefore, to
obtain a fluid comprising 10% by volume of viscoelastic surfactant
blend, 10 ml of a solution of surfactant blend must be added to 100
ml of base fluid (water/brine). Preferred ratio ranges between
about 5% and about 20% by volume and most preferred ratio is
between 8 to 15% by volume.
[0028] According to U.S. Pat. No. 6,258,859, cosurfactants may be
useful in extending the brine tolerance, and to increase the gel
strength and to reduce the shear sensitivity of the VES-fluid,
especially for BET-O. An example given in the above patent is
sodium dodecylbenzenesulfonate (SDBS) as shown below. The ability
of cosurfactants to increase the gel stability of other main
surfactants depends upon the cosurfactant having the appropriate
geometry (including the appropriate tail group length) and
appropriate affinity for the main surfactant head group. The
appropriate geometry is essentially independent of the presence of
other electrolytes. Affinity for the main head group can be
affected by electrolytes, their concentration and pH.
[0029] Benzene sulfonate. Preferred compounds are when R is
(CH.sub.2).sub.xCH.sub.3 and x is from 5 to 15. SDBS is when
R=C12H25 and the counter-ion X is sodium
[0030] Other suitable cosurfactants for BET-O-30 are certain
chelating agents such as trisodium
hydroxyethylethylenedianiine-triacetate.
[0031] In certain embodiments, a surfactant may also be blended
with the cosurfactant. Suitable cosurfactants include the class of
benzene sulfonates that shown above in which x=5-15; preferred
cosurfactants are those having x=8-12. Cosurfactants are more
commonly used with BET-O-30 and are generally not needed with
BET-E-40, but any of the suitable betaines can be used with or
without cosurfactants.
[0032] In one embodiment, erucylamidopropyl betaine is used as the
surfactant. An "effective" amount as used herein means an amount of
viscoelastic surfactant that is able to raise the viscosity and/or
temperature stability of a well fluid to a level required by the
specific application. It is believed that the combination of
viscoelastic surfactant in the presence of brine can result in
micelle formation and the entanglement of micelles can lead to
increased viscosity for the fluid. Other applications have noted
the presence of micelles in well fluids, such as those disclosed by
U.S. Pat. No. 5,964,295, assigned to the assignee of the present
invention.
Experimental Data
[0033] A comprehensive laboratory investigation of BET-E
rheological behavior under different chemical environment has been
conducted to evaluate the effects of brine density, brine types,
gelling agent concentration, pH, presence of alcohols, and
temperature on the system rheological behavior. Additional tests
were done on the retained permeability and fluid loss evaluation of
solid-laden pill at the high permeability conditions.
[0034] Fluid Preparation: In a typical experiment, a solution of
erucylamidopropyl betaine blend (10 v/v % solution of a 30 v/v %
active erucylamidopropyl betaine) was mixed to 13 ppg CaBr.sub.2
brine solution in a Warring blender. The fluid was agitated at high
shear to result in the development of viscosity. The pH of the
solution was measured using a standard hydrogen electrode. The
rheology, fluid loss and retained permeability of the
erucylamidopropyl betaine/brine solution were then
investigated.
[0035] Rheological Measurement: For testing the Theological
behavior, a Fann 50 or NI HTHP rheometer was used. n'and K', the
Power Law parameters of the fluid were measured at several RPM and
from this data, the apparent viscosity of the fluid is calculated
at various shear rates. The calculated high and low shear
viscosities are given. Viscosity was calculated for a low shear
rate of 1 sec.sup.-1 to mimic the shear that the fluid will
experience while leaking off.
[0036] Core Flow Study: The effectiveness of the fluid to prevent
leakoff was investigated by measuring the pressure gradient
observed while pumping the fluid through a core. A carbonate core
with known porosity and permeability is used to test the fluidloss
effectiveness. Initially, the differential pressures were measured
by pumping a 36% CaCl2 solution at various rates ranging from 2 to
6 cc/minute. CaCl2 solution was injected both forward and in the
reverse direction. The delta P when pumping the fluidloss pill is
monitored.
[0037] The same set of core flow experiment was used to investigate
the non-damaging nature of the fluid. Permeability to 36% CaCl2
were measured in forward and reverse directions at several flow
rates. Once the base line is established, the fluidloss control
pill is pumped followed by water, hydrocarbon or mutual solvent to
determine the retained permeability.
[0038] Fluidloss Study: For testing the static fluid loss and
retain permeability, a cementing dynamic fluid loss cell was used.
Initial permeability of a ceramic disc of 2.54 cm diameter and 1 cm
thickness was evaluated prior to placement on the bottom of the
cell. 100 ml fluid (or slurry) is placed on the top of the ceramic
disc and the cell is assembled. The assembly is heated up to
bottomhole static temperature (BHST) and a top pressure of 100 psi
is applied. The top valve on the top is opened and the bottom
closed. The operator applies 100 psi on bottom and slowly increases
the top pressure to 105 psi to run the leak-off test. More pressure
is applied on the top if 5 psi is not enough to initiate the flow.
The volume of filtrate is recorded against time. The final
permeability is tested after flushing the ceramic disc with
ethylene glycol monobutyl ether, a mutual solvent.
[0039] The apparent viscosity of a solution containing 10% v/v of
erucylamidopropyl n 90% v/v 13 ppg CaBr.sub.2 brine at different
temperatures are summarized below. The is calculated from the Power
Law parameters, n' and K'.
1 TABLE I VISCOSITY (cP) TEMP (.degree. F.) 1 s.sup.-1 10 s.sup.-1
40 s.sup.-1 100 s.sup.-1 170 s.sup.-1 87 3433 919 366 246 182 104
3571 920 356 237 173 146 12825 2302 693 413 278 204 28947 4655 1298
749 491 249 15048 2373 652 374 244 277 18065 2611 676 377 242 302
1713 781 451 356 297 311 781 480 341 295 264 323 266 238 220 213
207 325 251 225 207 201 195 333 147 149 152 152 153 353 42 58 73 81
87 362 18 31 46 54 61 375 4 11 24 33 42
[0040] Table I shows that the apparent viscosity of the VES/brine
mixture remained relatively stable as shear force was increased,
even at temperatures approaching 375.degree. F. Moreover, Table 1
shows that the above fluid loss pill provides significant viscosity
enhancement without any additional additives and that such
enhancement is not lost with increasing temperature. In addition,
the fluid has very high low shear viscosity (1 s-1 for instance)
and is thus very effective as a fluid loss control pill (viscosity
based fluid loss control rather than the conventional filter cake
dependent leakoff control).
[0041] In another embodiment of the present invention, a solution
of erucylamidopropyl betaine (30% erucylamidopropyl betaine in a
winterizing formulation containing water, salt and an antifreezing
solvent) was added to a 12.5 ppg CaBr.sub.2 brine solution, in an
amount sufficient to constitute 15% by volume of erucylamidopropyl
betaine in the resultant solution. Methanol was then added, with
mixing, to the erucylamidopropyl betaine/brine solution in an
amount sufficient to constitute 5% by volume of methanol in the
resultant solution. The rheology of the methanol/erucylamidopropyl
betaine/brine solution was investigated using the same Fann 50
viscometer as described above. In this case, the temperature of the
solution was raised from 75.degree. F. to 350.degree. F. over a
period of two and a half hours. The solution was then held at
350.degree. F. for five hours to determine the fluid stability at
350.degree. F. for extended periods. Viscosity measurements were
made during this time. The results are summarized below in Table
II.
2TABLE II Time Temperature Viscosity (cp) at s.sup.-1 (Hr:min)
(.degree. F.) 1 10 40 100 170 0:00 75 12612 2021 671 324 212 0:05
100 19353 2688 819 373 237 1:00 200 359 281 242 219 207 1:30 300
225 71 35 22 17 2:00 325 546 104 38 20 14 2:30 350 263 71 32 19 14
3:30 350 508 98 36 19 13 4:30 350 498 94 34 18 12 5:30 350 522 101
37 19 13 6:30 350 383 96 41 24 17 7:30 350 661 127 47 24 17
[0042] Table II shows that this particular composition maintains
sufficient viscosity at low shear rates (1 and 10 s.sup.-1) for
several hours at 350.degree. F. (gel is not broken at 350 F even
after 7 hrs. Experiment was stopped because of the safety issues of
heating the fluid at 350 F for overnight. The viscosity is not lost
even after heating the fluid in closed high pressure bottle at 350
F for more than 24 h.
[0043] Table III shows the effect of brine density on gel rheology.
All fluids were composed of 10% BET-E-40 based on the weight of the
calcium bromide brine (no methanol added.) Increasing brine density
improves viscosity of the fluid and gel stability at higher
temperatures.
3 TABLE III Temperature Viscosity at 1 sec-1 (cp) (F.) 11.6 ppg
12.7 ppg 13.6 ppg 75 3627 4241 1628 100 10366 6262 4627 125 16474
11864 8150 150 26864 20577 19581 175 6801 36421 30563 200 21974
6353 10002 225 21171 27505 17878 250 1430 12547 30083 275 164 910
10253 300 42 87 740 325 6 17 171 350 2 2 74
[0044] Though the fluid loss control pill work at all brine
concentrations, optimization of brine type (for instance CaBr2 gave
better viscosity compared to the same concentration of CaCl2), and
an optimum concentration of brine is necessary for the best high
temperature performance of the fluid. Similarly, higher
concentration of surfactant is also needed for better performance
at high temperatures.
[0045] Experiments were also conducted to compare the effectiveness
of the fluid made from different divalent and monovalent salts. The
result is summarized in Table IV.
4TABLE IV Temperature Viscosity at 40 sec-1 (cp) (F.) 12.7 ppg
CaBr2 12.7 ppg NaBr 75 366 408 100 356 791 150 693 1509 200 1298
649 250 652 403 275 676 138 300 451 27 325 207 9 335 152 -- 350 73
--
[0046] Above table compares the apparent viscosity of the 10%
fluidloss control pill in the presence of 12.7 ppg CaBr2 and 12.7
ppg NaBr. Brines made from divalent metal salts are found to give
better high temperature performance.
[0047] The pH of the fluid is normally around 4.5. Depending on the
source of the brine, the pH can fluctuate to some extend. Table V
shows that the pH of the final system has no dramatic effect on the
rheology of the pill at any temperature. The effect of pH on the
apparent viscosity of 7% BET-E-40, within a pH range of 3 to 10 is
shown below in Table V.
5 TABLE V Temperature Viscosity of 7% Pill at 40 sec-1 (cP) (F.) pH
3.9 pH 7.6 pH 9.8 75 187 196 204 100 283 346 324 125 312 344 437
150 271 211 324 175 264 229 268 200 313 304 284 225 326 338 312 250
115 182 166 275 72 73 69 300 50 44 51
[0048] The recovery of the fluidloss pill viscosity was measured
under conditions in which the temperature was dramatically changed
under high shear conditions. 10% BET-E blend in 106 pcf CaBr2 was
subjected to drastic cooling and heating cycles. The pill viscosity
was measured during three heating and cooling cycles. During each
cycle the pill was continuously heated to 280.degree. F. for 30
minutes, the degradation rate of the surfactant is very low, which
will allow the pill to last more than 72 hours.
[0049] In some applications, the stability of the pill at BHT for
extended periods is very important for well control. Hence apparent
viscosity of the fluid is measured at the BHT for 72 hours. The
apparent viscosity (measured with a Fann 50) of a solution
comprising 15% BET-E-40 in 5% methanol in 87 pcf CaCl2 brine at 280
F was found to be about 260 cp @ 170 s-1 for the entire 72 hours
tested and the fluid is not degraded in this period. The fluid may
last for several weeks at 280 F, and the experiment is discontinued
because of the experimental limitations.
[0050] Core flow tests were also performed with carbonate cores
having approximately 16% porosity and 450 md permeability with air.
Delta Pressure was monitored by pumping a 36% CaCl2 solution at
various rates ranging from 2 to 6 cc/minute. CaCl2 solution was
injected both forward and in the reverse direction. When pumping
the Pill, on the 2 inch core a delta P of 475 psi was observed
indicating good control of the fluidloss. The core when flushed
with a mutual solvent, the delta P went down to zero indicating the
complete cleanup. This cleanup is observed when using even with 1%
mutual solvent or with excess of water. The new fluid loss control
pill is non-damaging (100% retained permeability).
[0051] Fluid loss testing was performed on the 1 cm disk with a 10%
BET-E fluid in 13.5 ppg calcium bromide brine (with or without a
bridging agent). The bridging agent was added at a ratio of 20 g of
calcium carbonate particulates per 100 ml of gel and consisted of
80% of coarse and 20% of medium particulates designed for bridging
highly permeable gravel-pack or screens. The tests were performed
at 350 F, using a 5 psi pressure differential to initiate the flow
(25 psi for the data marked with an asterisk). Table VI is the
summary of the fluid loss testing on the different loss control
systems.
6 TABLE VI Filtrate Collected (ml) 13.5 ppg 13.5 ppg CaBr2 brine +
Time CaBr2 brine 13.5 ppg CaBr2 brine + 10% BET-E-40 + (min)
(blank) 10% BET-E-40 bridging particulates 1 95 14 8 2 -- 29 12 3
-- 45 15 4 -- 60 18 5 -- 71 21 6 -- 80 25 7 -- 94 28 8 -- -- 31 9
-- -- 33 10 -- -- 36 11 -- -- 38 12 -- -- 41 13 -- -- 43 14 -- --
46 15 -- -- 48 16 -- -- 50 17 -- -- 56 (*) 18 -- -- 62 (*) 19 -- --
68 (*) 20 -- -- 72 (*) 21 -- -- 77 (*) 22 -- -- 81 (*) 23 -- -- 86
(*) 24 -- -- 91 (*) 25 -- -- 95 (*)
[0052] The fluid loss results listed in table VI above show that
the blank gel (without bridging particulates) can reduce the brine
fluid loss from >95 ml/min to 14 ml/min. A gel pill further
comprising bridging particulates lead to a reduction to 3-4 ml/min.
To be noted that the results discussed in this section are not
representing the real fluid loss behavior inside the reservoir
since the effective length of porous medium to be traveled through
is considerably greater than the ceramic disc used in these tests.
This fluid is found very effective in fluidloss control in the
field application. The test results conclusively indicates that the
addition of sized particles provides better fluid loss control
performance.
[0053] The initial permeability of a ceramic disc was 1824 mD.
After leak-off of the gel pill consisting of a 13.5 ppg CaBr2
brine+10% BET-E-40, the permeability was 1647 mD. After flushing
with a mutual solvent, the permeability was 1854 mD, resulting in
retained permeability of 102%, essentially showing again that no
damage on the permeable media when this pill is used.
[0054] It was further found that the addition of methanol lowers
the apparent viscosity but increases the gel stability.
[0055] Several "frac and pack" completions were performed in
highly-permeable sweet-gas and acid stimulations in the oil and
water injection wells. Limited volume gel pills were used to
prevent losses both after perforating and after hydraulic
fracturing and gravel-pack operations. The pills were found
effective on zones with bottomhole temperature ranging from
200.degree. F. to 320.degree. F. Brine loses were effectively
stopped or controlled for more than 3 days. The effectiveness of
the pill was demonstrated by a five-fold increase in pumping
pressure during placement. The wells were flowed back at rates
exceeding expectations without further remediation or
stimulation.
[0056] The pills according to the invention minimize brine losses
especially in high-temperature well-control applications where
conventional polymer fluids are not stable. The polymer-free pill
controlled losses and allowed pipe tripping in a clear, filtered
brine without well control issues.
[0057] Furthermore, it should be noted that while the above
examples mostly discuss the utility of viscoelastic surfactant in
CaBr.sub.2 containing brine solutions, it will be clear to one of
ordinary skill in the art that other brine solutions, such as
ZnCl.sub.2, CaCl.sub.2, and ZnBr.sub.2, NaCl, KCl, NH.sub.4C.sub.1,
NH.sub.4NO.sub.3, MgCl.sub.2, seawater, NaBr,
Na.sub.2S.sub.2O.sub.3, sodium acetate, sodium formate, potassium
acetate, potassium formate, and combinations thereof, may be used
to form brines having a density of at least 12.5 ppg. Additionally
for low pressure wells requiring fluid loss or well control,
lighter weight brines, down to and including fresh water, may be
utilized.
[0058] In addition, while specific amounts of the chemicals used
are described in the above embodiments, it is specifically within
the contemplation of the invention that amounts different from
those described above may be used to provide the desired thermal
stability, depending on the particular application. For example, in
one embodiment, a suitable fluid loss pill may comprise 2% by
volume to 30% by volume VES blend in a brine solution. More
preferably, in one embodiment the fluid loss pill may comprise 5%
by volume to 20% by volume viscoelastic surfactant. Still more
preferably, in one embodiment the fluid loss pill may comprise 10%
to 15% by volume of viscoelastic surfactant blend.
[0059] Furthermore, while the above embodiments describe
viscoelastic/brine solutions for use as a fluid loss pill, the
viscoelastic/brine solutions may be used for other applications
such as killing a well. Another application is to use the fluid
loss pill of the invention in a method of pre-conditioning a well
in a high-permeable reservoir prior to performing the injection of
a polymer-base fluid. The injection of a fluid loss pill according
to the invention minimizes the volume of polymer invasion into the
formation before the formation of the polymer-containing filter
cake and consequently, the formation damage associated with the
stimulation of highly permeable rock is reduced. Another
possibility is to use the fluid loss pill actually as a carrier
fluid for placing a gravel pack comprising specifically graded
solids [calcium carbonate, mica, silica, Kolite, cellophane flake,
fibers, etc] to control lost circulation in fractured/vugular
formations as well. Resins and/or polymer systems (linear or
crosslinked) can be mixed to provide a filter cake if needed too.
One of ordinary skill in the art, having reference to this
disclosure would recognize these applications without having to
perform undue experimentation.
[0060] According to a further embodiment, the fluid-loss pill of
the invention is used for non-damaging well control/kill
operations, using the viscoelastic gel to carry graded particulate
sizes (large particles such as proppant/sand solids for bridging
intially across perforations or open-hole, and "capped" with
smaller particulates such as calcium carbonate or silica fines).
The process involves providing a graded size and specific gravity
differential to ensure the finer particles settle on top of the
larger particles to provide a relatively impermeable filter-cake.
The viscoelastic surfactant provides the necessary carrying
capacity for the solids bridge, and a non-damaging fluid-loss
control. This specific mixing and placement technique is rather
unique, since the gel stability can be altered to suit the
temperature regime by either remaining stable, or break down to
allow solids to rapidly settle and cause the particulate
bridging/stratification process to occur. In other words, this
technique provides a way of controlling segregation rate of graded
particle sizing/specific gravities.
[0061] Embodiments of the present invention provide advantages over
prior art well fluids and in particular, prior art fluid loss pills
and kill fluids. Embodiments of the present invention disclose a
simple system composed of only two additives; a surfactant and a
brine (more additives can be added to alter or stabilize fluid
properties if necessary). The fluid is compatible with all oilfield
brines and do not require any adverse pH conditions to function.
Furthermore, embodiments of the present invention advantageously
provide a fluid that contains no polymer, solid additives or
particulates, which may cause formation damage. In addition, the
present invention advantageously provides viscosity controlled
fluid loss rather than particulate (filter cake) controlled fluid
loss, making the present invention easier to remove and
non-damaging.
[0062] Furthermore, embodiments of the present invention do not
show a time dependent breakdown with temperature. In addition,
embodiments of the present invention operate at "mild" pH ranges
(4.5 in one embodiment), increasing the number of additives that
can be used, should additives be required. In addition, because of
high particle suspension carrying capability of the fluid, this
fluid can carry debris produced while perforating the formation, to
the surface. The fluid can also be used to effectively sweep the
debris, particulates, proppants, scales, beads used to remove
scales, fibers, and fines. Further, because of the ability to
suspend particulates, materials may be added to the fluid if
additional fluid loss control is required. In particular, soluble
bridging particulates, e.g., calcium carbonate or resins, may be
useful. These soluble bridging particulates can be easily removed
by acid or hydrocarbon solvent wash. Other non-damaging bridging
agents that do not penetrate nor damage the formation matrix may be
also used and easily removed either by physical circulation from
the well bore (such as circulating out proppant slugs) or
solvent/acid dissolution.
[0063] In addition to the above, embodiments of the present
invention provide a well fluid that has long term stability (i.e.,
does not break/decompose within 72 hours). Advantageously, this
allows a well fluid to be mixed in accordance with the above
embodiments and stored for later use. Because of the constantly
changing conditions in the wellbore, it is often desirable to have
the flexibility to store a well fluid for a period of time, prior
to the use. Furthermore, because certain embodiments of the present
invention rely on a two component mixture, the formulation time for
the well fluid is greatly reduced over prior art well fluids, which
may incorporate as many as ten different additives. Moreover, the
same formulation is applicable for applications ranging from about
50.degree. F. to about 350.degree. F.
[0064] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
* * * * *