U.S. patent application number 12/971927 was filed with the patent office on 2011-08-04 for use of reactive solids and fibers in wellbore clean-out and stimulation applications.
Invention is credited to J.Ernest Brown, Oscar Bustos, Michael J. Fuller, M. Nihat Gurmen, Ryan Hellman, Daniel Kalinin, Ling Kong Teng.
Application Number | 20110186293 12/971927 |
Document ID | / |
Family ID | 44319920 |
Filed Date | 2011-08-04 |
United States Patent
Application |
20110186293 |
Kind Code |
A1 |
Gurmen; M. Nihat ; et
al. |
August 4, 2011 |
USE OF REACTIVE SOLIDS AND FIBERS IN WELLBORE CLEAN-OUT AND
STIMULATION APPLICATIONS
Abstract
A method and apparatus to treat a subterranean formation
including introducing a fluid comprising degradable material into a
wellbore, contacting a surface of the wellbore with the fluid, and
stimulating a surface of a subterranean formation, wherein the
contacting the wellbore surface and stimulating the formation occur
over a time period that is tailored by the properties of the
degradable material. In some embodiments, the properties of the
degradable material include a chemical composition, a surface area,
a geometric shape of a particle of the material, a concentration of
the material in the fluid, a density of the material, a dimension
of a particle of the material, or a combination thereof.
Inventors: |
Gurmen; M. Nihat; (Grand
Junction, CO) ; Kalinin; Daniel; (Al-Khobar, SA)
; Hellman; Ryan; (Bakersfield, CA) ; Bustos;
Oscar; (Trophy Club, TX) ; Brown; J.Ernest;
(Fort Collins, CO) ; Fuller; Michael J.; (Houston,
TX) ; Teng; Ling Kong; (Batu Anam, MY) |
Family ID: |
44319920 |
Appl. No.: |
12/971927 |
Filed: |
December 17, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61300203 |
Feb 1, 2010 |
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Current U.S.
Class: |
166/276 ;
166/305.1 |
Current CPC
Class: |
C09K 2208/30 20130101;
C09K 8/536 20130101 |
Class at
Publication: |
166/276 ;
166/305.1 |
International
Class: |
E21B 43/02 20060101
E21B043/02; E21B 43/16 20060101 E21B043/16 |
Claims
1. A method for treating a subterranean formation, comprising:
introducing a fluid comprising degradable material into a wellbore;
contacting a surface of the wellbore with the fluid; and
stimulating a surface of a subterranean formation, wherein the
contacting the wellbore surface and stimulating the formation occur
over a time period that is tailored by the properties of the
degradable material.
2. The method of claim 1, wherein the properties of the degradable
material comprise a chemical composition, a surface area, a
geometric shape of a particle of the material, a concentration of
the material in the fluid, a density of the material, a dimension
of a particle of the material, or a combination thereof.
3. The method of claim 1, further comprising allowing the
degradable material to degrade.
4. The method of claim 3, wherein the degradable material releases
acid as it degrades.
5. The method of claim 1, wherein the surface of the subterranean
formation comprises carbonate.
6. The method of claim 1, wherein the surface of the wellbore
comprises carbonate.
7. The method of claim 1, wherein the time period is 48 hours or
less.
8. The method of claim 1, wherein the time period is 48 hours or
more.
9. The method of claim 1, wherein the time period is 72 hours or
more.
10. The method of claim 1, wherein the time period is 12 days or
more.
11. The method of claim 1, wherein the fluid comprises water.
12. The method of claim 1, wherein the fluid comprises oil.
13. The method of claim 1, wherein the fluid further comprises
surfactant.
14. The method of claim 13, wherein the surfactant comprises
viscoelastic surfactant.
15. The method of claim 14, wherein the viscoelastic surfactant
comprises betaine.
16. The method of claim 1, wherein the fluid comprises corrosion
inhibitor.
17. The method of claim 1, wherein the fluid comprises mutual
solvent.
18. The method of claim 1, wherein the degradable material is a
chelating agent.
19. The method of claim 1, wherein the degradable material has an
amount of particulates with average particle size and a second
amount of particulates with a second average particle size, wherein
the second average particle size is between three to twenty times
smaller than the first average particle size.
20. The method of claim 19, wherein the second average particle
size is between five to ten times smaller than the first average
particle size.
21. The method of claim 19, wherein the degradable material has a
further amount of particulates having a third average particle
size, wherein the third average particle size is between three to
twenty times smaller than the second average particle size.
22. The method of claim 21, wherein the third average particle size
is between five to ten times smaller than the second average
particle size.
23. The method of claim 19, wherein the wellbore further comprises
a screen.
24. The method of claim 1, wherein the fluid further comprises
calcium carbonate particles.
25. The method of claim 1, wherein the fluid comprises corrosion
inhibitor, mutual solvent, surfactant.
26. The method of claim 1, wherein the temperature of the formation
is 150 degF or higher.
27. The method of claim 1, wherein the pH of the fluid while
introducing a fluid comprising degradable material into a wellbore
is 5 to 8.
28. A method for treating a subterranean formation, comprising:
introducing a fluid comprising degradable material and oleaginous
fluid into a wellbore; contacting a surface of the wellbore with
the fluid; and stimulating a surface of a subterranean formation,
wherein the contacting the wellbore surface and stimulating the
formation occur over a time period that is tailored by the
properties of the degradable material.
29. A method for forming a filtercake in a subterranean formation,
comprising: introducing a fluid comprising degradable material and
oleaginous phase into a wellbore; contacting a surface of the
wellbore with the fluid; and stimulating a surface of a
subterranean formation, wherein the contacting the wellbore surface
and stimulating the formation occur over a time period that is
tailored by the properties of the degradable material.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and the benefit of as a
non-provisional application of U.S. Provisional Application Ser.
No. 61/300,203, filed Feb. 1, 2010, and entitled, "Use of Reactive
Solids and Fibers in Wellbore Clean-Out and Stimulation
Applications," which is incorporated by reference herein in its
entirety.
BACKGROUND
[0002] 1. Field
[0003] This invention relates to methods and fluids used in
treating a subterranean formation. In particular, the invention
relates to the preparation and use of reactive solids and fibers in
wellbore clean-out and stimulation applications.
[0004] 2. Description of the Related References
[0005] This invention relates to a composition and method for
stimulation and for removing impermeable layers created for fluid
loss control in a subterranean formation. More particularly it
relates to the use of a fluid containing a delayed solid acid
material that can either remove drilling mud filtercakes or create
a self-destructing filtercake in subterranean formations that
require fluid loss control.
[0006] During drilling of a well, a thin layer of impermeable
material is deposited on the reservoir rock by the drilling fluid
(or mud). This thin layer of material is called a filtercake and
aids in controlling drilling fluid leak-off into the formation and
restricts the inflow of reservoir fluids into the well during
completion. If the filtercake that is created during the drilling
process is not removed prior to or during completion of the well,
problems may occur when the well is put on production. These may
include completion equipment failures, such as erosion and plugging
of the equipment, and impaired reservoir productivity, which may be
in the form of early water production or water coning.
[0007] The major components typically found in conventional
drilling mud filtercake include such materials as polymers,
carbonates and other inorganic salts, and clays. Removal of the mud
filtercake can be accomplished through mechanical means (scrapping,
jetting, underreaming, etc). Conventional chemical treatments for
removing filtercake include pumping aqueous solutions with an
oxidizer (such as persulfate), inorganic acids (such as HCl),
organic acids (such as acetic or formic acids), chelating agents
(such as EDTA), enzymes or combinations of these. Generally, the
oxidizer or enzyme digests the polymer layer in the filtercake and
the acids dissolve the carbonate portion in the filtercake.
[0008] There are several problems that exist in conventional
filtercake removal. The acids used tend to react very quickly with
carbonate and "wormholes" are readily formed where most of the acid
will funnel off through these small openings into the reservoir and
leave most of the zone untreated. Oxidizers are very corrosive and
reactive. They also must be pumped as a separate stage, which
causes operational complexity and extra cost. Additionally, the
lifetime of an oxidizer at higher temperatures may be only a few
seconds. Enzyme breakers are extremely sensitive to pH,
temperature, and ionic strength. They are not effective in breaking
polymers in acidic solutions and will lose their activity at higher
temperatures. Chelants are weak acids and poor dissolvers of
carbonate compared to other organic acids, such as acetic and
formic acid. Catalysts and activators require a second step in the
completion process that causes additional operational costs.
[0009] There are many oilfield applications that require the use of
fluid loss control agents in the near well-bore region, within the
formation itself or against sand control screens and gravel packs.
Some of these applications are in cased and perforated wellbores,
while others are in open holes.
[0010] In some applications, enzyme or oxidizer soaks (to hydrolyze
polymeric components of the filtercake) are performed, followed by
an acid treatment. This process is also ineffective, since the
reaction of the acid with carbonate bridging agents in the absence
of coating with polymeric components (as it would be after the
enzyme or oxidizer soak) is much faster than the reaction of acid
with all components of the filtercake intact, causing the same
problems.
[0011] Other alternatives include combining chelating agent
solutions, which provides much slower reaction rates with much
lower corrosion rates. Although enzyme and chelating agent
solutions or chelating agent solutions alone have been effectively
used in open hole completions, in longer wells, and particularly at
higher temperatures, even they may react relatively quickly in long
open hole completions. Thus, it is desirable to have a filtercake
cleanup solution which is not reactive until after some time (e.g.,
until after the wash-pipe is pulled and the formation is isolated).
There is therefore a need to provide improvements in compositions
and methods for filtercake removal and for providing effective and
readily reversible fluid loss pills or treatments.
SUMMARY
[0012] Embodiments of this invention relate to a method to treat a
subterranean formation including introducing a fluid comprising
degradable material into a wellbore, contacting a surface of the
wellbore with the fluid, and stimulating a surface of a
subterranean formation, wherein the contacting the wellbore surface
and stimulating the formation occur over a time period that is
tailored by the properties of the degradable material. In some
embodiments, the properties of the degradable material include a
chemical composition, a surface area, a geometric shape of a
particle of the material, a concentration of the material in the
fluid, a density of the material, a dimension of a particle of the
material, or a combination thereof. Some embodiments may benefit
from the use of an oil-based system or a water-based system.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 shows the rheology of 5% NaCl brine and 6% erucic
amidopropyl dimethyl betaine at 207 degress F.
[0014] FIG. 2 is a plot of pH as a function of time for Tests 1-3
of Table 2 at 158 degrees F.
[0015] FIG. 3 is a plot of pH as a function of time for Tests 4-6
of Table 2 at 158 degrees F.
[0016] FIG. 4 is a plot of pH as a function of time for Tests 7-9
of Table 3 at 158 degrees F.
[0017] FIG. 5 is a plot of pH as a function of time for Tests 10-12
of Table 3 at 158 degrees F.
[0018] FIG. 6 is a plot of pH as a function of time for Tests 1 and
3 of Table 2 at 200 degrees F.
[0019] FIG. 7 is a plot of pH as a function of time for Tests 4 and
6 of Table 2 at 200 degrees F.
[0020] FIG. 8 is a plot of pH as a function of time for Tests 7 and
9 of Table 3 at 200 degrees F.
[0021] FIG. 9 is a plot of pH as a function of time for Tests 10
and 12 of Table 3 at 200 degrees F.
DESCRIPTION
[0022] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary of the invention and this detailed
description, each numerical value should be read once as modified
by the term "about" (unless already expressly so modified), and
then read again as not so modified unless otherwise indicated in
context. Also, in the summary of the invention and this detailed
description, it should be understood that a concentration range
listed or described as being useful, suitable, or the like, is
intended that any and every concentration within the range,
including the end points, is to be considered as having been
stated. For example, "a range of from 1 to 10" is to be read as
indicating each and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possessed knowledge of the entire
range and all points within the range.
[0023] The statements made herein merely provide information
related to the present disclosure and may not constitute prior art,
and may describe some embodiments illustrating the invention.
[0024] There are many wellbore clean-out and stimulation systems
currently in use in the upstream oil & gas industry. In
general, the two processes are isolated from each other. The
chemistry for both instances can vary substantially from one
product to the other. Generally, the mud properties used in the
productive section of a reservoir would dictate the chemistry of
wellbore cleanout system. One of the common components used as
bridging agent in both water-based and oil-based mud systems is
calcium carbonate particles with specific sizes and shapes. Various
functional additives like mutual solvents and surfactants enable
efficient contact with a reactive component in the system. This
reactive component in the system can be an acid or chelant, and the
component attacks the bridging agent to destabilize and dissolve
the mud filtercake on the wellbore wall. The technical challenge
resolved by embodiments of this invention is to make this reaction
uniform and minimize losses during the process. Solid acid beads
and fibers give a unique opportunity to delay or tailor reactions
substantially and combine it with the stimulation step afterwards
in carbonate formations.
[0025] The process of cleanout and stimulation happens
simultaneously or one after the other. For example, once the solid
acid hydrolyzes, acid is generated, then acid reacts with the
filtercake, and any remaining hydrolyzed acid will react with the
carbonate formation. In the wellbore, there is enough solid acid to
react with carbonate material in the filter cake and additionally
to react with the formation. The hydrolyzed acid performs a
wellbore enlargement and/or fissure cleanout, which could be
considered one stimulation technique. In some embodiments,
hydrolysis of the solid or chelant, such as solid acid, will not be
intermediate. Therefore, the non-hydrolyzed solid acid will form
temporarily filtercake and will block any pinholes which would lead
to more even mud cake dissolution; eventually all solid acid will
hydrolyze and be consumed.
[0026] This technology utilizes solid acid, such as polylactic
acid, to dissolve calcium carbonate-based filter cake from water
based fluids. Also, the acid stimulates the near-wellbore region in
openhole wells completed in carbonate formations. The solid acid is
an inert substance under surface conditions but hydrolyzes into an
acid under downhole conditions after a certain time influenced by
bottomhole temperature. This mechanism will allow for a delayed
reaction time which will be useful when it is placed with a rig
after drilling the openhole section. It will give the rig time to
pull out of hole and skid off the well before the acid reacts,
preventing losses and well control issues. The solid acid will also
simplify pumping operations since the fluid is non-corrosive and
simple to place.
[0027] The solid acid will be mixed with a carrier fluid and pumped
from the surface and placed in the openhole section. The solid acid
will then hydrolyze and react with the near-wellbore region,
allowing for wellbore cleanout and matrix stimulation. This could
be applied in hydrocarbon producing wells or water injection
wells.
[0028] Degradable material like PLA, PGA, etc. could be used to
enhance productivity or injectivity of wells as described here.
Generally, as the material degrades, it releases acid that may
stimulate the surfaces it encounters. Time and temperature of
exposure will influence the solubility of the material and how the
material degrades. Some embodiments may benefit from the use of a
prepad treatment to cool the formation, which is especially
important for high temperature wells when delay of the reaction is
needed. The concentration of the material may be varied depending
on various parameters of the system. Some embodiments may benefit
from the material in concentrations of about 0.5 ppa of degradable
material.
[0029] The pH of the fluid is important to how the system works.
Specifically, the fluid should be tailored to have a neutral pH in
a range of 5-8 pH. The pH will be reduced as the degradable solid
hydrolyzes under downhole temperature and pressure. Also, having an
initially neutral pH is critical to delaying filtercake
dissolution. More reactive (higher or lower pH) systems may have
premature breakthrough.
[0030] The density of the fluid may also be tailored to a specific
optimized level. This optimized density may help maintain a
specific hydrostatic level to deliver pressure downhole and to
suspend degradable solid particles.
[0031] A. Spotting slurried degradable material after finishing
drilling wellbore using circulation (direct or reverse) via
drillstring, coiled tubing or jointed pipe or bullheading the
slurried material into wellbore to create concentration of the
degradable material. This material could not leak-off into
formation and may act as fluid loss agent, although this is not the
primary intention of the use. Degradation of the material is
controlled by temperature of the subterranean formation so an
appropriate material would be selected to provide sufficient time
for retracting the pipe (if used for the placement) and run in the
wellbore completion or otherwise prepare the well for production or
injection. Degradation of the material via hydrolysis would result
in forming a certain amount of organic acid. This acid would react
with the bridging material of mud filtercake (typically calcium
carbonate) and subterraneous rock, thus enhancing its permeability
to reservoir or injected fluids or gases. Low reaction rate of the
acid also permits squeezing it into formation either under pressure
of hydrostatic column or intended injection. Degradable material
could be in form of beads, fiber, chips, flakes, powder, or others.
A combination of sized round particles could be used to enhance
slurried degradable material ability to flow and reduce risk of
leaving placement tubulars downhole if stuck due to local
concentration of the material (degradable nature of material would
make it possible to free pipe after a certain time, however, delay
may not be desired). Use of degradable material as stand-alone
stimulation system is desirable and differs from use of degradable
solid beads in fracturing or fiber in matrix stimulation. Use of
this material for mud filtercake removal also has a potential for
long reaction retardation.
[0032] B. Adding degradable material to acid or non-acidic reactive
solutions intended to dissolve mud filtercake to enhance its
performance by forming temporarily barrier across zones of uneven
dissolution (pinholes) to effectively prevent loss of fluid into
subterranean formation and to keep it in the wellbore for uniform
dissolution of the mentioned mud filtercake. Degradable particles
would later hydrolyze and in turn react with remaining bridging
material of the filtercake or reactive material of formation
similarly to above example. This is different from use of
fiber-like degradable material for fluid diversion because
diversion would occur after placement of the reactive solution.
[0033] C. Degradable material to be introduced into a stream of
fluid injected into subterraneous formations for pressure support
or other reasons whenever increase of injectivity or alteration of
its distribution along length of wellbore is desired. Once enough
material is placed into the wellbore, injection could be
temporarily suspended or slowed to allow temperature increase to
promote hydrolysis of the degradable material into stimulation
fluid which would react with the subterraneous formation on
wellbore face or by leaking into later, thus increasing its ability
to receive more fluids or altering injectivity profile in a
favorable manner. Slowing or suspending injectivity may not be
required for certain degradable materials upon exposure to downhole
temperatures. Such use of degradable particles as a sole
stimulation system is desirable.
[0034] D. Continuous injection of degradable particles into fluid
injected into subterraneous formations for pressure support or
other reasons whenever temporary alteration of injectivity profile
is desired. Solids will divert flow away from fissures or thief
zones allowing better sweep efficiency. Effect of the resulting
cool-down could be used to prolong diversion. The suspension of
solids fed into the stream of injected fluid or temporarily
suspension of the fluid injection would revert the injection
profile.
[0035] Degradable materials, such as solid acids including solid
polymeric acid, that may be used in this process include polylactic
acid, polyglycolic acid, and benzoic acid. The solid polymeric acid
precursor may be made from at least one of homopolymers of lactic
acid, glycolic acid, hydroxybutyrate, hydroxyvalerate and epsilon
caprolactone; random copolymers of at least two of lactic acid,
glycolic acid, hydroxybutyrate, hydroxyvalerate, epsilon
caprolactone, L-serine, L-threonine, and L-tyrosine; block
copolymers of at least two of polyglycolic acid, polylactic acid,
hydroxybutyrate, hydroxyvalerate, epsilon caprolactone, L-serine,
L-threonine, and L-tyrosine; homopolymers of ethylenetherephthalate
(PET), butylenetherephthalate (PBT) and ethylenenaphthalate (PEN);
random copolymers of at least two of ethylenetherephthalate,
butylenetherephthalate and ethylenenaphthalate; block copolymers of
at least two of ethylenetherephthalate, butylenetherephthalate and
ethylenenaphthalate; and combinations of these. The identity of the
degradable material may be selected to optimize degradation delay
based on the temperature of the formation. Polyglycolic acid may be
more desirable when the formation temperature is low, polylactic
may be more desirable when the formation temperature is above 150
degF.
[0036] In one embodiment, the particulate material has a first
average particle size and the degradable particulate material has a
second average particle size, wherein the second average particle
size is between three to twenty times smaller than the first
average particle size. The second average particle size may be
between five to ten times smaller than the first average particle
size. In a second embodiment, the degradable particulate material
has further an amount of particulates having a third average
particle size, wherein the third average particle size is between
three to twenty times smaller than the second average particle
size. The third average particle size may be between five to ten
times smaller than the second average particle size.
[0037] The particulate material may be of any geometry that is
appropriate for the task. Fibers, flakes, cylinders, round, oblong,
rod-like, beads, or other shapes that are selected for their
dimensions, high-aspect-ratio size, surface area to volume ratio,
surface area, volume, or any other geometry parameter that may be
tailored to help the material degrade with a desired profile. Some
embodiments may benefit from a mixture of particle shapes or sizes.
Some embodiments may benefit from a mixture of degradable and
non-degradable materials.
[0038] The carrier fluid for the solid acid may be any variety of
fluids including drilling muds, drilling fluids, fracturing fluids,
and other fluids employed by the oil field services industry.
Water-based fluids may benefit from the optional inclusion of
additional additives including enzymes, surfactant, microemulstion,
demulsifier, acid, buffers, (mutual) solvent, and carrion
inhibitor. Oil-based fluids may also benefit from the optional
inclusion of additional additives including surfactants,
microemulsions, solvents, demulsifier, and corrosion inhibitor. The
concentration of additives in oil-based muds may be higher than the
concentration in water-based muds. Further, the oil-based fluid
systems may benefit from a solvent based preflush step.
[0039] Generally, oil based mud may contain oil (linear paraffin,
diesel, etc., water, calcium chloride, primary and secondary
emulsifiers, viscosifiers such as modified clay, lime, fluid loss
agent, and weighing agent such as barite or calcium carbonate. Some
oil-based fluids may be an invert emulsion, i.e., emulsions in
which the non-oleaginous fluid is the discontinuous phase and the
oleaginous fluid is the continuous phase.
[0040] The oleaginous fluid may be a liquid and more preferably is
a natural or synthetic oil and more preferably the oleaginous fluid
is selected from the group including diesel oil; mineral oil; a
synthetic oil, such as hydrogenated and unhydrogenated olefins
including polyalpha olefins, linear and branch olefins and the
like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters
of fatty acids, specifically straight chain, branched and cyclical
alkyl ethers of fatty acids, mixtures thereof and similar compounds
known to one of skill in the art; and mixtures thereof. The
concentration of the oleaginous fluid should be sufficient so that
an invert emulsion forms, and the concentration of the oleaginous
fluid may be less than about 99% by volume of the invert emulsion.
In one embodiment the amount of oleaginous fluid is from about 30%
to about 95% by volume of the invert emulsion fluid and more
preferably about 40% to about 90% by volume of the invert emulsion
fluid. The oleaginous fluid in one embodiment may include at least
5% by volume of a material selected from the group including
esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and
combinations thereof.
[0041] The non-oleaginous fluid used in the formulation of the
invert emulsion fluid disclosed herein may be a liquid and
preferably may be an aqueous liquid. More preferably, the
non-oleaginous liquid may be selected from the group including sea
water, a brine containing organic and/or inorganic dissolved salts,
liquids containing water-miscible organic compounds and
combinations thereof. The amount of the non-oleaginous fluid is
typically less than the theoretical limit needed for forming an
invert emulsion. Thus in one embodiment the amount of
non-oleaginous fluid is less that about 70% by volume of the invert
emulsion fluid and preferably from about 1% to about 70% by volume
of the invert emulsion fluid. In another embodiment, the
non-oleaginous fluid is preferably from about 5% to about 60% by
volume of the invert emulsion fluid.
[0042] Also typically included are emulsifiers and emulsifier
systems for stabilizing the emulsion. As used herein, emulsifier,
emulsifying agent, and surfactant are used interchangeably. The
emulsifying agent serves to lower the interfacial tension of the
liquids so that the non-oleaginous liquid may form a stable
dispersion of fine droplets in the oleaginous liquid. A full
description of such invert emulsions may be found in Composition
and Properties of Drilling and Completion Fluids, 5th Edition, H.
C. H. Darley, George R. Gray, Gulf Publishing Company, 1988, pp.
328-332, the contents of which are hereby incorporated by
reference.
[0043] Emulsifiers that may be used in the fluids disclosed herein
include, for example, fatty acids, soaps of fatty acids,
amidoamines, polyamides, polyamines, oleate esters, such as
sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or
alcohol derivatives and combinations or derivatives of the above.
Additionally, the fluid may also contain surfactants that may be
characterized as wetting agents. Wetting agents that may be
suitable for use in the fluids disclosed herein include crude tall
oil, oxidized crude tall oil, organic phosphate esters, modified
imidazolines and amidoamines, alkyl aromatic sulfates and
sulfonates, and the like, and combinations or derivatives of these.
However, when used with the invert emulsion fluid, the use of fatty
acid wetting agents should be minimized so as to not adversely
affect the reversibility of the invert emulsion disclosed herein.
FAZE-WET.RTM., VERSACOAT.RTM., SUREWET.RTM., VERSAWET.RTM., and
VERSAWET.RTM. NS are examples of commercially available wetting
agents manufactured and distributed by M-I L.L.C. of Houston, Tex.
that may be used in the fluids disclosed herein.
[0044] In a particular embodiment, the invert emulsion may be of
the reversible type, whereby the invert emulsion may be converted
from a water-in-oil type emulsion to an oil-in-water type emulsion
upon exposure to acid, for example. Such reversible oil-based
fluids include those described in U.S. Pat. Nos. 6,218,342,
6,806,233 6,790,811, 7,527,097, 7,238,646, 6,989,354, 7,178,550,
6,608,006, 7,152,697, 7,178,594, 7,222,672, 7,238,646 and
7,377,721, for example, which are herein incorporated by reference
in their entirety.
[0045] The viscosity of the fluid may be tailored to maintain
suspension of degradable solid particles uniformly along the length
of openholse sections to minimize settling. To control the fluid
viscosity, a variety of additives may be used including
viscoelastic surfactants and polymers such as guar, HEC, xantham,
guar derivative, cellulose, cellulose derivative,
heteropolysaccharide, heteropolysaccharide derivative,
polyacrylamide, CMHPG, cationic guar, diutan, partially hydrolyzed
polyacrylamide, copolymers of partially hydrolyzed polyacrylamide
alginate, chitosan, or a combination thereof.
[0046] In embodiments of the invention, systems of the invention
made of degradable solid acids are especially useful in conjunction
with viscoelastic surfactant (VES) fluid system. VES fluid system
is a fluid viscosified with a viscoelastic surfactant and any
additional materials, such as but not limited to salts,
co-surfactants, rheology enhancers, stabilizers and shear recovery
enhancers that improve or modify the performance of the
viscoelastic surfactant.
[0047] The useful VES's include cationic, anionic, nonionic, mixed,
zwitterionic and amphoteric surfactants, especially betaine
zwitterionic viscoelastic surfactant fluid systems or amidoamine
oxide viscoelastic surfactant fluid systems. Examples of suitable
VES systems include those described in U.S. Pat. Nos. 5,551,516;
5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,258,859 and
6,509,301, which are all hereby incorporated by reference. The
system of the invention is also useful when used with several types
of zwitterionic surfactants. In general, suitable zwitterionic
surfactants have the formula:
RCONH--(CH.sub.2).sub.a(CH.sub.2CH.sub.2O).sub.m(CH.sub.2).sub.b--N.sup.-
+(CH.sub.3).sub.2--(CH.sub.2).sub.a'(CH.sub.2CH.sub.2O).sub.m'(CH.sub.2).s-
ub.b'COO.sup.-
[0048] in which R is an alkyl group that contains from about 14 to
about 23 carbon atoms which may be branched or straight chained and
which may be saturated or unsaturated; a, b, a', and b' are each
from 0 to 10 and m and m' are each from 0 to 13; a and b are each 1
or 2 if m is not 0 and (a+b) is from 2 to about 10 if m is 0; a'
and b' are each 1 or 2 when m' is not 0 and (a'+b') is from 1 to
about 5 if m is 0; (m+m') is from 0 to about 14; and the 0 in
either or both CH.sub.2CH.sub.2O groups or chains, if present, may
be located on the end towards or away from the quaternary
nitrogen.
[0049] Preferred zwitterionic surfactants include betaines. Two
suitable examples of betaines are BET-O and BET-E. The surfactant
in BET-O-30 is shown below; one chemical name is oleylamidopropyl
betaine. It is designated BET-O-30 because as obtained from the
supplier (Rhodia, Inc. Cranbury, N.J., U.S.A.) it is called
Mirataine BET-O-30 because 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 propylene glycol. An analogous material, BET-E-40, is
also available from Rhodia and contains an erucic acid amide group
(including a C.sub.21H.sub.41 alkene tail group) and is
approximately 40% active ingredient, with the remainder being
substantially water, sodium chloride, and isopropanol. VES systems,
in particular BET-E-40, optionally contain about 1% of a
condensation product of a naphthalene sulfonic acid, for example
sodium polynaphthalene sulfonate, as a rheology modifier, as
described in U.S. Pat. No. 7,084,095. The surfactant in BET-E-40 is
also shown below; one chemical name is erucylamidopropyl betaine.
BET surfactants, and other VES's are described in U.S. Pat. No.
6,258,859. BET surfactants make viscoelastic gels when in the
presence of certain organic acids, organic acid salts, or inorganic
salts; in that patent, the inorganic salts were present at a weight
concentration up to about 30%. Co-surfactants may be useful in
extending the brine tolerance, and to increase the gel strength and
to reduce the shear sensitivity of the VES-fluid, in particular for
BET-O-type surfactants. An example given in U.S. Pat. No. 6,258,859
is sodium dodecylbenzene sulfonate (SDBS), also shown below. Other
suitable co-surfactants include, for example those having the
SDBS-like structure in which x=5-15; preferred co-surfactants are
those in which x=7-15. Still other suitable co-surfactants for
BET-O-30 are certain chelating agents such as trisodium
hydroxyethylethylenediamine triacetate. The rheology enhancers may
be used with viscoelastic surfactant fluid systems that contain
such additives as co-surfactants, organic acids, organic acid
salts, and/or inorganic salts.
##STR00001##
[0050] Some embodiments use betaines; for example BET-E-40.
Although experiments have not been performed, it is believed that
mixtures of betaines, especially BET-E-40, with other surfactants
are also suitable.
[0051] Other betaines that are suitable include those in which the
alkene side chain (tail group) contains 11-23 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=2-10,
and p=1-5, and mixtures of these compounds. Betaines are those in
which the alkene side chain contains 11-21 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=3-5,
and p=1-3, and mixtures of these compounds. These surfactants are
used at a concentration of about 0.5 to about 10%, or from about 1
to about 6%, and or from about 1.5 to about 6%. In some
embodiments, erucic amidopropyl dimethyl betaine may be selected,
which is commercially available from Rhodia of Cranbury, N.J.
[0052] Although the invention has been described using the term
"VES", or "viscoelastic surfactant" to describe the non-polymeric
viscosified well treatment fluids, other non-polymeric materials
may also be used to viscosify the fluid provided that the
requirements described herein for such a fluid are met, for example
the required viscosity, stability, compatibility, and lack of
damage to the wellbore, formation or fracture face.
EXAMPLES
[0053] The following examples are presented to illustrate the
preparation and properties of fluid systems, and should not be
construed to limit the scope of the invention, unless otherwise
expressly indicated in the appended claims. All percentages,
concentrations, ratios, parts, etc. are by weight unless otherwise
noted or apparent from the context of their use.
[0054] Testing was performed to examine a wellbore cleanout fluid
utilizing solid polylactic acid intended for water-based mud (WBM)
applications. The base cleanout fluid was 5% NaCl brine; in order
to obtain good suspension of solid polylactic acid, 6% was utilized
as viscosifier. Rheology of the viscous carrier 5% NaCl brine+6%
erucic amidopropyl dimethyl betaine was also tested at 207 degF.
The testing shows that the optimized fluid maintains viscosity
above 100 cP at 100 sec-1 for more than 3 hours.
[0055] WBM mud cake dispersion and dissolution tests were conducted
on mud cakes prepared on both filter paper and on a core plug; the
dissolution fluid in this testing included 1 PPA solid polylactic
acid in the carrier fluid 5% NaCl brine+6% erucic amidopropyl
dimethyl betaine. The conclusions are listed below: [0056] Testing
on filter paper shows 2.2%, 7.6%, 54% and 100%
dispersion/dissolution of the filtercake after 4, 8, 24 and 48
hours, respectively, at 207 degF. [0057] Roughly 32% of solid
polylactic acid solids remained unhydrolysed after the testing.
[0058] Dissolution of a mud cake prepared on a core plug at 207
degF and 300 psi differential pressure shows 68% dispersion and
dissolution after 3 days soaking [0059] In the core plug
experiment, again 35% of solid polylactic acid remaining
unhydrolyzed after the testing. [0060] It is recommended from these
preliminary results to reduce the overall concentration of solid
polylactic acid below 1 PPA in field execution.
Rheology 5% NaCl Brine+6% Erucic Amidopropyl Dimethyl Betaine
[0060] [0061] Measure the required amount of water and pour into a
Waring blender. [0062] Add in the required amount of NaCl [0063]
Add in the required amount of erucic amidopropyl dimethyl betaine
into the brine [0064] Shear the fluid at high RPM .about.12000 rpm
[0065] Remove the air bubbles by centrifuging the fluid [0066] Once
the air bubbles are remove, measure 50 mL of the fluid and pour it
into HPHT rheometer cup. Apply 400 psi and run shear ramps as per
API RP 39 starting at room temperature up to 207 degF [97 degC]
[0067] A B5 bob is used for the test and shear ramping: 118 rpm
(100 s.sup.-1), 88.5 rpm (75 s.sup.-1), 59 rpm (50 s.sup.-1), 29.5
rpm (25 s.sup.-1), 59 rpm (50 s.sup.-1), 88.5 rpm (75 s.sup.-1),
118 rpm (100 s.sup.-1). [0068] Interval stir rate is set at 118 rpm
(100 s.sup.-1) between each temperature interval. [0069] M5600 HPHT
rheometers manufactured by Grace Instruments were used. Test shear
rates and viscosity calculations follow API Recommended Procedure
39.
Water Based Mud Cake Dispersion and Dissolution
[0069] [0070] Water-based mud cake (with CaCO.sub.3 bridging
particles) was prepared on a filter paper. [0071] The mud cake was
divided into four parts (each for 4, 8, 24, 48 and 72 hours
testing) [0072] The initial weight of each mudcake was recorded.
[0073] The wellbore cleanout fluid as per method 2.1 above with 1
PPA solid polylactic acid was performed. [0074] The mudcake was
placed into a beaker [0075] 200 mL of wellbore cleanout fluid was
poured into the beaker with mudcake. [0076] The beaker was placed
into water bath at 200 degF. [0077] The pH of the solution by time
was checked. [0078] After 24, 48 and 72 hours take out the
respective beaker, the final weight of the mud cake was
measured.
Water Based Mud Cake Dispersion and Dissolution on Core Plug
[0078] [0079] Saturate the core plug with 5% NaCl brine [0080]
Measure the weight of the core plug setup without mudcake [0081]
CaCO.sub.3 based mud cake is prepared on a Berea Core Plug (150 mD)
by applying 500 psi differential pressure. [0082] After 6 hours,
remove and take pictures of the mud cake obtained [0083] Measure
the initial weight of the core plug setup with mudcake [0084] Mix
the wellbore cleanup fluid as per method 2.1 above with 1 PPA solid
polylactic acid [0085] Pour 100 mL of wellbore cleanout fluid into
the cell with mudcake. [0086] Place the cell into heater jacket at
200 degF [0087] Apply 500 psi pressure at the top of the cell and
200 psi back-pressure at the bottom of the cell [0088] Let the
treatment fluid soak for 3 days [0089] Collect the filtrate from
the bottom of the cell versus time and check the pH and measure
[Ca] concentration using ICP [0090] Weigh the core with residual
mud cake to calculate mass of final mud cake.
[0091] Rheology of 5% NaCl Brine+6% Erucic Amidopropyl Dimethyl
Betaine
[0092] FIG. 1 illustrates the rheology of 5% NaCl brine and 6%
erucic amidopropyl dimethyl betaine at 207 degF. It provides a
baseline viscosity and shear rate that are relatively stable over
120 minutes.
Mud Cake Dispersion and Dissolution
[0093] Visual inspection, as recorded by photographs, compared
initial mud cake to the mud cake over time on filter paper. After 4
hours, 2.2% of the mud cake was dissolved and dispersed and after 8
hours, 7.6% dissolved and dispersed. After 24 hours 54% dissolved
and dispersed and after 48 and 72 hours, the mud cake was
completely dissolved and dispersed.
[0094] Visual inspection tests, as recorded by photographs, also
compared solids in a beaker over time. The test showed unhydrolyzed
polylactic acid remained as a solid in the beaker after 72 hours.
Approximately 32% solid remained.
Mud Cake Dispersion and Dissolution in Core Plug
[0095] Core plug tests were also visually inspected and recorded by
photographs. The tests of the core plug after 3 days soaking at 207
degF showed that roughly 68% (w/w) of the mud cake is
dispersed/dissolved. About 35% of the polylactic acid solids remain
un-dissolved.
[0096] Next, the volume, pH and calcium content of the filtrate
collected over time were recorded and are summarized below in Table
1.
TABLE-US-00001 TABLE 1 Filtrate Analysis Time Accumulative Volume
of pH (pH Calcium (hours) Filtrate Collected (mL) paper) Content
(mg/L) 6 3 8 272.5 8 4 7 1843.6 24 10 4 25651.2 48 20 (flowing
continuously) 3 >40000 *Note: At 48 hours filtrate is flowing
continuously, with total volume collected 10 mL. The remaining
fluid is left in the cell to soak for 3 days.
[0097] As described above, WBM mud cake dispersion and dissolution
tests were conducted on mud cakes prepared on both filter paper and
on a core plug; the dissolution fluid in this testing included 1
PPA solid polylactic acid in the carrier fluid 5% NaCl brine+6%
erucic amidopropyl dimethyl betaine. From these tests, one can
conclude the following. [0098] Testing on filter paper shows 2.2%,
7.6%, 54% and 100% dispersion/dissolution of the filtercake after
4, 8, 24 and 48 hours, respectively, at 207 degF. [0099] Roughly
32% of polylactic acid solids remained unhydrolysed after the
testing. [0100] Dissolution of a mud cake prepared on a core plug
at 207 degF and 300 psi differential pressure shows 68% dispersion
and dissolution after 3 days soaking [0101] In the core plug
experiment, again 35% of solid polylactic acid remaining
unhydrolyzed after the testing. [0102] In field execution, it is
recommended to reduce the overall concentration of solid polylactic
acid below 1 PPA.
[0103] Testing was performed to examine a wellbore cleanout fluid
utilizing solid polylactic acid intended for oil based mud (OBM)
applications in general. The treatment fluid consists of based
fluid which is 11 ppg NaBr brine, 50 gallon/1000 gallon of
proprietary amine oxide surfactant, 25 gallon/1000 gallon of
ethyleneglycol monobutyl ether (EGMBE), 2 gallon/1000 gallon of
acid corrosion inhibitor and 0.5 PPA of PLA-2040.
[0104] The efficiency of the oil based mud (OBM) filter cake
removal tests were conducted on mud cake formed by both filter
paper (2.5 in specially hardened filter paper) and ceramic filter
disc (0.4 darcy/3 micron). The conclusions of the tests
follows.
[0105] Testing on filter paper indicated that 100%
dispersion/dissolution of the filtercake after 3 days (72 hours) at
207 degF.
[0106] 100% of the solid polylactic acid hydrolyzed after 12 days
at 207 degF. No solid acid was observed but only some oil residue
remained.
[0107] The test was conducted with the same treatment fluid at
different temperature. 100% of solid polylactic acid was hydrolyzed
after 3 days at 250 degF. No significant hydrolyzed of solid
polylactic acid after 13 days at 150 degF. The solid polylactic
acid hydrolyzed faster at higher temperature.
[0108] The retain permeability test was conducted by utilized the
ceramic filter disc, 100% hydrolyzed of solid polylactic acid was
observed after 12 days of soaking at 207 degF. The retained
permeability of the ceramic filter disc was 89.57%.
Oil Based Mud Cake Dispersion and Dissolution on Filter Paper
[0109] Weigh the empty filter paper. (w1) [0110] Using the High
temperature and high pressure fluid loss cell and heating jacket,
create mud-cake on the filter paper by applying 300 psi
differential pressure at 207 degF. Stop the mud cake formation
after collect the filtrate approximates 4-6 ml. [0111] Remove the
mud-cake from the cell. [0112] Mud-cake was divided into 4 equal
parts, take each part for the different tests. [0113] Weigh the
mud-cake with the filter paper as w2. [0114] Immersed the mud-cake
and filter paper into 250 ml of bottle with 200 ml of testing fluid
solution. [0115] The test bottle was placed into the pre-heated
oven at 207 degF for 12 days. [0116] Check the physical appearance
of the mud-cake in the test bottle from time to time. [0117] Remove
the remained mud-cake with filter paper after 12 days of soaking
and weigh the mud-cake remained on filter paper as w3. [0118]
Calculate the solubility and dispersing with the following
formulation.
[0118] Solubility and dispersing percentage = ( w 2 - w 3 ) ( w 2 -
w 1 ) .times. 100 ##EQU00001##
Retained Permeability Determination by Ceramic Disc
[0119] Vacuum to saturate the ceramic disc in 3% KCl brine. [0120]
Weigh the initial weight of the saturated ceramic disc. [0121] The
disc was loaded into the 500 ml HPHT fluid loss cell. Determine the
initial permeability in the production direction using 3% KCl by
recording the differential pressure at various flowrates. [0122]
Pour the oil based mud into the HTHP fluid loss cell and apply 300
psi differential pressure to make the mud-cake. Heat up the cell to
207 degF. Cool down the cell after obtained the filtrate
approximates 4-6 ml. [0123] Pour in the treatment fluid into the
HTHP cell. Heat the cell up to 207 degF and apply 300 psi
differential pressure. Soak the treatment fluid at the designated
testing pressure and temperature for 12 days. [0124] Bled off the
pressure and removed the treatment fluid from the cell. [0125] Fill
the cell with 3% KCl to measure the final permeability. The final
permeability is measure by injecting the brine in production
direction with differential pressure at various rates. The retained
permeability is calculate by
[0125] Retained permeability = Final Permeability Initial
Permeability .times. 100 ##EQU00002##
Oil Based Mud Cake Dispersion and Dissolution (on Filter Paper)
[0126] Visual inspection on physical appearance of the initial mud
cake to the mud cake change over time on filter paper. The mud cake
and filter paper was soaked in the treatment fluid consists of
based fluid which is 11 ppg NaBr brine, 50 gallon/1000 gallon of
proprietary amine oxide surfactant, 25 gallon/1000 gallon of
ethyleneglycol monobutyl ether (EGMBE), 2 gallon/1000 gallon of
acid corrosion inhibitor and 0.5 PPA of PLA-2040. After 4 days of
soaking, only 47.90% of mud cake dissolved and dispersed. 98% of
mud cake dissolved and dispersed after 12 days of soaking at 207
degF. Solid polylactic acid dissolved 100% after 12 days of soaking
at 207 degF.
[0127] The same treatment fluid were tested at difference
temperature; 150 degF, 207 degF and 250 degF. Solid polylactic acid
dissolved 100% after 12 days soaking at 207 degF and after 3 days
soaking at 250 degF. Significant of un-dissolved solid polylactic
acid was observed after 13 days soaking at 150 degF. On the other
hand, more than 97% of the mud cake dissolved after 12 days soaking
at 207 degF and 3 days soaking at 250 degF.
[0128] Solid polylactic acid was replaced with acetic acid in the
treatment fluid to measure the difference in reactivity between the
solid polylactic acid and the acetic acid. 47.9% of mud cake
dissolved and dispersed after 4 days of soaking at 207 degF with
the treatment fluid contains solid polylactic acid. 86% of the mud
cake dissolved and dispersed after 2 days of soaking at 207 degF
with the treatment fluid contains acetic acid. This indicate the
solid polylactic acid have some delay in reaction.
Retained Permeability for the Oil Based Mud
[0129] The initial permeability of the clean ceramic disc was
determined, oil based mud cake was formed with the ceramic disc.
The treatment fluid consists of based fluid which is 11 ppg NaBr
brine, 50 gallon/1000 gallon of proprietary amine oxide surfactant,
25 gallon/1000 gallon of ethyleneglycol monobutyl ether (EGMBE), 2
gallon/1000 gallon of acid corrosion inhibitor and 0.5 PPA of
PLA-2040 was poured into the HTHP cell and soaked for 12 days at
207 degF. Final permeability of the ceramic disc was obtained. The
89.57% of retained permeability show good oil based mud-cake
removal property.
[0130] The next set of experiments compares solid acid size,
calcium carbonate presence, temperature, and brine medium for the
treatment fluid apply to oil based mud (OBM)
[0131] Tables 2 and 3--Brine, acid mesh size, and calcium carbonate
mass.
TABLE-US-00002 Test1 Test 2 Test 3 Test4 Test 5 Test 6 Brine used
2% KCl 2% KCl 2% KCl 2% KCl 2% KCl 2% KCl vol of brine, ml 42 42 42
42 42 42 wt of PLA- 2.5158 2.5 2.5 2040, g wt of PLA- 2.5 2.5 2.5
100, g wt of CaCO3 25.2 12.6 25.2 12.6
TABLE-US-00003 Test 7 Test 8 Test 9 Test10 Test 11 Test 12 Brine
used 12.5 12.5 12.5 12.5 12.5 12.5 ppg ppg ppg ppg ppg ppg NaBr
NaBr NaBr NaBr NaBr NaBr vol of brine, ml 42 42 42 42 42 42 wt of
PLA- 2.5 2.5 2.5 2040, g wt of PLA- 2.5 2.5 2.5 100, g wt of CaCO3
25.2 12.6 25.2 12.6
[0132] The results of these tests are illustrated by FIGS. 5 to 9.
Specifically, 100 mesh PLA is more reactive than 2040 mesh PLA.
Also, calcium carbonate does not accelerate the hydrolysis process,
it neutralizes the fluid pH. Higher temperature accelerates the
hydrolysis process. A concentration of 60 or 30 weight percent
calcium carbonate did not yield significantly different results.
The brine identity (NaBr or KCl) did not yield significantly
different results.
TABLE-US-00004 TABLE 4 Summary of results from tests described by
Tables 2 and 3 Test 1 Test 2 Test 3 Test 4 Test 5 Brine used 11.34
ppg 11.34 ppg 11.34 ppg 11.34 ppg Distilled NaBr NaBr NaBr NaBr
water PLA-2040 0.1 ppa 0.2 ppa 0.3 ppa 0.4 ppa 0.1 ppa Curing
Period 6 days 6 days 6 days 6 days 6 days Curing Temperature 203
deg F. 203 deg F. 203 deg F. 203 deg F. 203 deg F. Final Fluid pH
1.19 1.18 1.23 0.56 2.13 % of solid 53.00 47.00 47.00 47.00 45.00
acid soluble
[0133] This shows that the solubility of the solid acid is
approximate 50% for 6 days curing regardless of the initial
concentration. This table also generally shows that the solubility
of the solid acid is dependent to time and not depend on the
concentration. Some testing indicated that it may take more than 11
days to hydrolyze all PLA for some of the material tested.
Additional testing that was visually observed and photographed
showed that 4 days was insufficient to hydrolyze all PLA, but that
after 12 days, no solid acid was residual and some oil residue
remained.
[0134] The particular embodiments disclosed above are illustrative
only, as the invention may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Furthermore, no limitations
are intended to the details herein shown, other than as described
in the claims below. It is therefore evident that the particular
embodiments disclosed above may be altered or modified and all such
variations are considered within the scope and spirit of the
invention. Accordingly, the protection sought herein is as set
forth in the claims below.
* * * * *