U.S. patent application number 13/973579 was filed with the patent office on 2014-03-06 for controlled electrolytic metallic materials for wellbore sealing and strengthening.
This patent application is currently assigned to Baker Hughes Incorporated. The applicant listed for this patent is Baker Hughes Incorporated. Invention is credited to Marcus Davidson, Lirio Quintero, Stephen R. Vickers, Zhiyue Xu.
Application Number | 20140060834 13/973579 |
Document ID | / |
Family ID | 50184195 |
Filed Date | 2014-03-06 |
United States Patent
Application |
20140060834 |
Kind Code |
A1 |
Quintero; Lirio ; et
al. |
March 6, 2014 |
Controlled Electrolytic Metallic Materials for Wellbore Sealing and
Strengthening
Abstract
Contacting the wellbore with a fluid composition and forming a
metallic powder barrier at or near the tip of a fracture extending
from the wellbore into a subterranean formation may strengthen a
wellbore. The fluid composition may include a base fluid and a
metallic powder having a plurality of metallic powder particles.
The base fluid may include a drilling fluid, a completion fluid, a
servicing fluid, a fracturing fluid, and mixtures thereof. The
metallic powder particles may have a particle core and a metallic
coating layer. The particle core may include a core material
selected, such as magnesium, zinc, aluminum, manganese, vanadium,
chromium, molybdenum, iron, cobalt, silicon, nitride, tungsten, and
a combination thereof. The metallic coating layer may be disposed
on the particle core thereby forming a metallic powder particle.
The metallic powder particles may be configured for solid-state
sintering to one another to form the metallic particle
compacts.
Inventors: |
Quintero; Lirio; (Houston,
TX) ; Vickers; Stephen R.; (Alford Aberdeenshire,
GB) ; Davidson; Marcus; (Inverurie, GB) ; Xu;
Zhiyue; (Cypress, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes Incorporated |
Houston |
TX |
US |
|
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
50184195 |
Appl. No.: |
13/973579 |
Filed: |
August 22, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61695474 |
Aug 31, 2012 |
|
|
|
Current U.S.
Class: |
166/292 |
Current CPC
Class: |
C09K 8/50 20130101; E21B
33/138 20130101; E21B 21/003 20130101; E21B 33/13 20130101 |
Class at
Publication: |
166/292 |
International
Class: |
E21B 33/13 20060101
E21B033/13 |
Claims
1. A method for strengthening a wellbore comprising: contacting the
wellbore with a fluid composition, wherein the fluid composition
comprises: a base fluid selected from the group consisting of a
drilling fluid, a completion fluid, a servicing fluid, a fracturing
fluid, and mixtures thereof; and metallic powder comprising a
plurality of metallic powder particles, each powder particle
comprising: a particle core comprising a core material having a
melting temperature (T.sub.p), and wherein the core material is
selected from the group consisting of magnesium, zinc, aluminum,
manganese, vanadium, chromium, molybdenum, iron, cobalt, silicon,
nitride, tungsten, and a combination thereof; and a metallic
coating layer disposed on the particle core, wherein the metallic
coating layer comprises a metallic coating material having a
melting temperature (T.sub.c); and forming a first metallic powder
barrier at or near the tip of a fracture extending from the
wellbore into a subterranean formation with the metallic
powder.
2. The method of claim 1, wherein the metallic powder particles are
configured for solid-state sintering to one another at a
predetermined sintering temperature (T.sub.s) to form a metallic
particle compact, and wherein T.sub.s is less than T.sub.p and
T.sub.c.
3. The method of claim 2, wherein the size of the metallic particle
compact ranges from about 500 .mu.m to about 20 cm.
4. The method of claim 1, wherein the fluid composition comprises a
concentration of the metallic powder in an amount ranging from
about 0.05 wt % to about 10 wt % of the total fluid
composition.
5. The method of claim 1 further comprising reducing additional
growth of the fracture as compared to the wellbore absent the
metallic powder barrier.
6. The method of claim 1, further comprising reducing an amount of
the base fluid lost to the formation as compared to the amount of
fluid lost to the formation in the absence of the metallic powder
barrier.
7. The method of claim 1, further comprising forming a second
metallic powder barrier on the wellbore to prevent solid and fluid
going from or into the formation.
8. The method of claim 1, further comprising contacting the
metallic powder barrier with a surfactant to reverse the
wettability of at least a portion of the metallic powder particles
therein.
9. The method of claim 6, wherein the surfactant is part of a
mesophase fluid selected from the group consisting of a
miniemulsion, a nanoemulsion, a macroemulsion, and combinations
thereof.
10. The method of claim 1 further comprising degrading at least a
portion of the metallic powder barrier after a predetermined
condition selected from the group consisting of a temperature
change, the presence of an acid, an amount of time, and
combinations thereof.
11. The method of claim 8, wherein the degrading the metallic
powder particles occurs by a method selected from the group
consisting of dissolving the metallic powder particles,
disintegrating the metallic powder particles, corroding the
metallic powder particles, melting the metallic powder particles,
and combinations thereof.
12. The method of claim 1, wherein the core material is selected
from the group consisting of an Mg--Zn alloy, an Mg--Al alloy, an
Mg--Mn alloy, an Mg--Zn--Y alloy, and combinations thereof.
13. The method of claim 1, wherein the size of the powder particle
ranges from about 25 nm to about 5000 .mu.m.
14. The method of claim 1, wherein the particle core has a diameter
ranging from about 1 .mu.m to about 300 .mu.m.
15. The method of claim 1, wherein the core material comprises an
Mg--Al--X alloy; and wherein X is selected from the group
consisting of Zn, Mn, Si, Ca, Y, and combinations thereof.
16. The method of claim 13, wherein the Mg--Al--X alloy comprises
up to about 85 wt % of Mg, up to about 15 wt % Al, and up to about
5 wt % X.
17. The method of claim 1, wherein the metallic coating material is
selected from the group consisting of Al, Zn, Mn, Mg, Mo, W, Cu,
Fe, Si, Ca, Co, Ta, Re, Ni, an oxide thereof, a carbide thereof, a
nitride thereof, and a combination of any of the aforementioned
materials; and wherein the metallic coating material has a
different chemical composition than the chemical composition of the
particle core.
18. A method for strengthening a wellbore comprising: contacting
the wellbore with a fluid composition, wherein the fluid
composition comprises: a base fluid selected from the group
consisting of a drilling fluid, a completion fluid, a servicing
fluid, a fracturing fluid, and mixtures thereof; and a metallic
powder comprising a plurality of metallic powder particles, each
powder particle comprising: a particle core comprising a core
material having a melting temperature (T.sub.p), and wherein the
core material is selected from the group consisting of magnesium,
zinc, aluminum, manganese, vanadium, chromium, molybdenum, iron,
cobalt, silicon, nitride, tungsten, and a combination thereof; and
a metallic coating layer disposed on the particle core, wherein the
metallic coating layer comprises a metallic coating material having
a melting temperature (T.sub.c); and wherein the metallic powder
particles are configured for solid-state sintering to one another
at a predetermined sintering temperature (T.sub.S), and T.sub.S is
less than T.sub.P and T.sub.C to form a metallic particle compact;
and forming a metallic powder barrier with the metallic powder at
or near the tip of a fracture extending from the wellbore into a
subterranean formation to reduce additional growth additional
growth of the fracture as compared to the fracture in the absence
of the metallic powder barrier; and degrading at least a portion of
the metallic powder barrier after a predetermined condition
selected from the group consisting of a temperature change, the
presence of an acid, an amount of time, and combinations
thereof.
19. A method for strengthening a wellbore comprising: contacting
the wellbore with a fluid composition, wherein the fluid
composition comprises: a base fluid selected from the group
consisting of a drilling fluid, a completion fluid, a servicing
fluid, a fracturing fluid, and mixtures thereof; and a metallic
powder comprising a plurality of metallic powder particles ranging
in size from about 25 nm to about 5000 nm, each powder particle
comprising: a particle core comprising a core material having a
melting temperature (T.sub.p), and wherein the core material is
selected from the group consisting of magnesium, zinc, aluminum,
manganese, vanadium, chromium, molybdenum, iron, cobalt, silicon,
nitride, tungsten, and a combination thereof; and a metallic
coating layer disposed on the particle core, wherein the metallic
coating layer comprises a metallic coating material having a
melting temperature (T.sub.c); and forming a metallic powder
barrier at or near the tip of a fracture extending from the
wellbore into a subterranean formation with the metallic powder;
contacting the metallic powder barrier with a surfactant to reverse
the wettability of at least a portion of the metallic powder
particles therein.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of Provisional Patent
Application No. 61/695,474 filed Aug. 31, 2012, which is
incorporated by reference herein in its entirety.
TECHNICAL FIELD
[0002] The present invention relates to sealing and strengthening a
wellbore by contacting the wellbore with a fluid composition and
forming a metallic powder barrier at or near the tip of a fracture
extending from the wellbore into a subterranean formation.
BACKGROUND
[0003] Drilling fluids used in the drilling of subterranean oil and
gas wells along with other drilling fluid applications and drilling
procedures are known. In rotary drilling there are a variety of
functions and characteristics that are expected of drilling fluids,
also known as drilling muds, or simply "muds". The functions of a
drilling fluid include, but are not necessarily limited to, cooling
and lubricating the bit, lubricating the drill pipe, carrying the
cuttings and other materials from the hole to the surface, and
exerting a hydrostatic pressure against the borehole wall to
prevent the flow of fluids from the surrounding formation into the
borehole.
[0004] Drilling fluids are typically classified according to their
base fluid. In water-based muds, solid particles are suspended in
water or brine. Oil can be emulsified in the water, which is the
continuous phase. Brine-based drilling fluids, of course are a
water-based mud (WBM) in which the aqueous component is brine.
Oil-based muds (OBM) are the opposite or inverse. Solid particles
are suspended in oil, and water or brine is emulsified in the oil
and therefore the oil is the continuous phase. Oil-based muds can
be either all-oil based or water-in-oil macroemulsions, which are
also called invert emulsions. In oil-based mud, the oil may consist
of any oil that may include, but is not limited to, diesel, mineral
oil, esters, or alpha-olefins. OBMs as defined herein also include
synthetic-based fluids or muds (SBMs). SBMs often include, but are
not necessarily limited to, olefin oligomers of ethylene, esters
made from vegetable fatty acids and alcohols, ethers and polyethers
made from alcohols and polyalcohols, paraffinic, or aromatic,
hydrocarbons alkyl benzenes, terpenes and other natural products
and mixtures of these types. OBMs and SBMs are also sometimes
collectively referred to as "non-aqueous fluids" (NAFs).
[0005] Damage to a reservoir is particularly harmful if it occurs
while drilling through the pay zone or the zone believed to hold
recoverable oil or gas. In order to minimize such damage, a
drill-in fluid may be pumped through the drill pipe while drilling
through the pay zone.
[0006] Another type of fluid used in oil and gas wells is a
completion fluid. A completion fluid is pumped down a well after
drilling operations are completed and during the completion phase.
Drilling mud typically is removed or displaced from the well using
a completion fluid, which may be a clear brine. Then, the equipment
required to produce fluids to the surface is installed in the well.
A completion fluid must have sufficient density to maintain a
differential pressure with the wellbore, which controls the
well.
[0007] When drilling through a rock formation, mud may be lost into
the formation through fractures (small or large fissures) of the
formation. In other instances, fractures may be induced while
drilling, such as in the case of drilling with a high overbalanced
pressure through depleted sands. With both types of fractures, i.e.
naturally-occurring or induced, severe fluid loss may occur,
especially when drilling with an oil-based drilling mud. Examples
of fluids that may be lost include, but are not limited to water or
oil from drilling and completion fluids, typically used for
downhole purposes, and the like. Another example is water invasion
into shale formations, which may weaken the wellbore causing
stability problems, such as a hole collapse.
[0008] Solid particles from the aforementioned types of fluids may
physically plug or bridge across flowpaths at or near the fracture
tip of the porous formation. Chemical reactions between the
drilling fluid and the formation rock and fluids may precipitate
solids or semisolids to plug pore spaces. It will also be
understood that the drilling fluid, e.g. oil-based mud, is
deposited and concentrated at the borehole face and partially
inside the formation. However, the solid particles plugging or
bridging across the formation may only be desirable for a temporary
amount of time because the plugging can also cause a reduction of
hydrocarbon production. Many operators are interested in improving
formation clean up and removing the formed plugging material after
drilling into reservoirs.
[0009] It would be advantageous to design a fluid composition
having potentially degradable particles where the degradable
particles may seal the wellbore or form a plug at or near the
fracture tip for purposes of strengthening the wellbore and allow
for the degradation of the plug if so desired.
SUMMARY
[0010] There is provided, in one form, a method for sealing and/or
strengthening a wellbore. A fluid composition may contact the
wellbore where the fluid composition includes a fluid and a
metallic powder having a plurality of metallic powder particles.
The metallic powder may form a metallic powder barrier at or near
the tip of a fracture extending from the wellbore into a
subterranean formation. The fluid may be a drilling fluid, a
completion fluid, a servicing fluid, a fracturing fluid, and
mixtures thereof. Each metallic powder particle may include a
particle core, and a metallic coating layer disposed on the
particle core. The particle core may have or include a core
material with a melting temperature (T.sub.p), and the core
material may be or include magnesium, zinc, aluminum, manganese,
vanadium, chromium, molybdenum, iron, cobalt, silicon, nitride,
tungsten, and a combination thereof. The metallic coating layer
disposed on the particle core may include a metallic coating
material having a melting temperature (T.sub.c).
[0011] In an alternative non-limiting embodiment, the metallic
powder particles described above may be configured for solid-state
sintering to one another at a predetermined sintering temperature
(T.sub.S) where T.sub.S is less than T.sub.P and T.sub.C to form a
metallic particle compact. The metallic powder particles and/or the
metallic particle compacts may degrade after a predetermined
condition including, but not necessarily limited to, a temperature
change, the presence of an acid, an amount of time, or a
combination thereof. A metallic powder barrier that includes the
metallic powder particles may form at or near the tip of the
fracture that may reduce additional growth of the fracture as
compared to a wellbore contacted with a fluid composition absent
the metallic powder.
[0012] The metallic powder barrier formed from the metallic powder
appears to control the fracture size and strengthen the
wellbore.
BRIEF DESCRIPTION OF THE DRAWING
[0013] FIG. 1 is a non-limiting, schematic illustration of three
types of metallic powder particles with degradable portions
thereof.
[0014] It will be appreciated that the various structures and parts
thereof schematically shown in FIG. 1 are not necessarily to scale
or proportion since many proportions and features have been
exaggerated for clarity and illustration.
DETAILED DESCRIPTION
[0015] A method has been discovered for strengthening and sealing a
wellbore that involves the use of at least partially degradable
metallic powder particles blended with a base fluid, such as but
not necessarily limited to a drilling fluid, a completion fluid, a
servicing fluid, a fracturing fluid, and mixtures thereof to form a
fluid composition. Once a fracture is induced within a subterranean
reservoir, various fluids may be lost into the formation, also
termed `lost circulation` of fluid.
[0016] To prevent loss of water or other fluids into the formation,
the metallic powder particles may be carried into these fractures
and act as proppants and thereby strengthen the wellbore by forming
a stress cage around the wellbore. The concentration of the
metallic powder within the fluid composition may range from about
0.05 wt % independently to about 10 wt %, alternatively from about
0.05 wt % independently to about 3 wt %. When the term
"independently" is used herein with respect to a parameter range,
it is to be understood that all lower thresholds may be used
together with all upper thresholds to form suitable and acceptable
alternative ranges. The fluid composition may be pumped into the
wellbore to form a metallic powder barrier at or near the tip of a
fracture extending from the wellbore into a subterranean
formation.
[0017] `Metallic powder barrier` is defined herein to be a material
intended to form a blockage or block passage of a fluid into or out
of the wellbore and/or formation, such as but not limited to, a
plug, a sealant, a bridging material, and combinations thereof.
Such a barrier may be useful on small scale to block pore space of
a formation, or on a larger scale to form a plug and create
multiple zones within a wellbore. The metallic powder barrier
formed may reduce additional growth of the fracture as compared to
contacting the wellbore with a fluid composition absent the
metallic powder. The metallic powder barrier may also reduce the
amount of fluid lost in the formation. In one non-limiting
embodiment, the metallic powder barrier may form a seal on the
wellbore to prevent solid and fluid going from or into the
formation and/or prevent pressure transmission.
[0018] The degradable metallic powder particles and/or metallic
particle compacts may be designed to be pumpable along with the
base fluid. With time, these metallic powder particles and/or
metallic particle compacts will either degrade partially or
completely in downhole formation water, fracturing fluid (i.e.
mixture of water and/or brine), other fluids, or other conditions.
Some of these metallic powder particles and/or metallic particle
compacts may degrade in hydrocarbons if the hydrocarbons contain
H.sub.2S, CO.sub.2, and other acid gases that cause degradation of
the materials. Oxides, nitrides, carbides, intermetallics or
ceramic coatings that are partially or fully resistant of these
dissolvable metallic powder particles and/or metallic particle
compacts may be dissolved with a second fluid, such as an acid or
brine-based fluids. This allows for a metallic powder barrier to
form at or near the fracture tip for a period of time that the
metallic powder barrier is needed, and then the degradable metallic
powder particles and/or metallic particle compacts within the
metallic powder barrier may be degraded according to pre-determined
conditions or once the metallic powder barrier is no longer needed.
By "at or near" is meant within a few inches, e.g. about 2 inches
independently to about 4 inches from the tip of the fracture, or
alternatively, less than 1 inch from the tip of the fracture.
[0019] In a non-limiting embodiment, the metallic powder particles
may be oil-wet from the oil-based muds. A surfactant may contact
the metallic powder particles and/or formed metallic powder barrier
to change at least a portion of the metallic powder particles from
oil-wet to water-wet; alternatively, a mesophase fluid may be
injected into the wellbore to change the metallic powder particles
from oil-wet to water-wet. More specifically, the surfactant (in
the absence of a mesophase fluid) or the mesophase fluid may
reverse the wettability, remove and/or minimize the metallic powder
barrier formed from the metallic powder particles at or near the
fracture tip. Mesophase fluids are defined herein as selected from
the group of a miniemulsion, a nanoemulsion, macroemulsion or a
microemulsion in equilibrium with excess oil or water or both
(Winsor III), a single-phase microemulsion (Winsor IV) as defined
by U.S. Pat. No. 8,235,120, which is incorporated herein by
reference.
[0020] In an alternative non-limiting embodiment, the metallic
powder particles may be water-wet from the water-based muds. A
surfactant may contact the metallic powder particles and/or formed
metallic powder barrier to change at least a portion of the
metallic powder particles from water-wet to oil-wet; alternatively,
a mesophase fluid may be injected into the wellbore to change the
metallic powder particles from water-wet to oil-wet. More
specifically, the surfactant (in the absence of a mesophase fluid)
or the mesophase fluid may reverse the wettability, remove and/or
minimize the metallic powder barrier formed from the metallic
powder particles at or near the fracture tip.
[0021] In this instance, the metallic powder particles may be
oil-wet (or non-polar), so the mesophase fluid may be
water-continuous. Mesophase fluids also include collections of
components that make these emulsions. These mesophase fluids may be
formed either prior to introduction into a wellbore or formed in
situ. That is, it is not necessary to completely form the mesophase
fluid (e.g. microemulsion) on the surface and pump it downhole. The
in situ mesophase fluid (e.g. microemulsion, nanoemulsion, etc.)
may be formed when at least one surfactant and a polar phase
(usually, but not limited to water or brine) contacts the non-polar
metallic powder particles and solubilizes the non-polar material
thereon. Such mesophase fluids may also be introduced as pills to
carry out the same function.
[0022] The mesophase fluid may include at least one surfactant, an
oil-based fluid, an aqueous-based fluid, and an optional
co-surfactant. The surfactant may be or include, but is not limited
to an extended chain surfactant, a non-extended chain surfactant, a
co-surfactant, and combinations thereof. The surfactant may be or
include, but is not limited to non-ionic, anionic, cationic,
amphoteric surfactants, extended chain surfactants, and
combinations thereof. Suitable nonionic surfactants include, but
are not necessarily limited to, alkyl polyglycosides, sorbitan
esters, polyglycol esters, methyl glucoside esters, alcohol
ethoxylates or alkylphenol ethoxylates. Suitable anionic
surfactants include, but are not necessarily limited to, alkali
metal alkyl sulfates, alkyl or alkylaryl sulfonates, linear or
branched alkyl ether sulfates and sulfonates, alcohol
polypropoxylated and/or polyethoxylated sulfates, alkyl or
alkylaryl disulfonates, alkyl disulfates, alkyl sulphosuccinates,
alkyl ether sulfates, linear and branched ether sulfates, and
mixtures thereof. Suitable cationic surfactants include, but are
not necessarily limited to, arginine methyl esters, alkanolamines
and alkylenediamides.
[0023] The optional co-surfactant may be a surface-active
substance, such as but not limited to, mono or poly-alcohols, low
molecular weight organic acids or amines, polyethylene glycol, low
ethoxylation solvents and mixtures thereof.
[0024] Once the metallic powder particles are water-wet, the second
fluid may be an almost neutral fluid (`almost neutral` is defined
herein to mean a pH ranging from about 6.5 to about 7.5, e.g.
water) and injected into the wellbore to dissolve the metallic
powder particles. Although an acidic solution (e.g. a fluid having
a pH less than about 6.5) may dissolve the metallic powder
particles quicker than an almost neutral fluid, the acidic solution
may corrode the well equipment downhole. For example, the metallic
powder barrier formed from the powder particles may be used to aid
in completion of a well; use of an acidic solution would corrode
and/or dissolve the completion equipment for the finished well.
Thus, depending on the use of the metallic powder particles and the
metallic powder barrier formed therefrom, one skilled in the art
must assess whether to use a second fluid that is acidic or almost
neutral.
[0025] The degradable portions of the metallic powder particles
and/or metallic particle compacts may be lightweight, high-strength
and have selectably and controllably degradable materials.
Fully-dense, sintered metallic particle compacts may be formed from
coated metallic powder particles having lightweight particle cores.
A coating may be formed on the particle core having at least one
layer, alternatively from about 1 layer independently to about 10
layers depending on the thickness of each layer. The powder
particle core may be or include an electrochemically-active (e.g.
having relatively higher standard oxidation potentials),
lightweight, and/or high-strength material.
[0026] The powder particles may degrade over a period of time
ranging from about 0.5 hours independently to about 4 weeks,
alternatively from about 10 minutes independently to about 2 weeks,
or from about 5 minutes independently to about 24 hours.
[0027] These metallic powder particles and/or metallic particle
compacts provide a unique and advantageous combination of
mechanical strength properties, such as compression and shear
strength, low density and selectable and controllable corrosion
properties, particularly rapid and controlled dissolution in
various wellbore fluids, and combinations thereof. For example, the
particle core and coating layers of these metallic powder particles
may be selected to provide sintered metallic particle compacts
suitable for use as high strength engineered materials having a
compressive strength and shear strength comparable to various other
engineered materials, including carbon, stainless and alloy steels,
but which also have a low density comparable to various polymers,
elastomers, low-density porous ceramics and composite
materials.
[0028] The selectable and controllable degradation or disposal
characteristics described may also allow the dimensional stability
and strength of materials to be maintained until the metallic
powder particles and/or metallic particle compacts are no longer
needed. In one non-limiting example, it may be beneficial to
degrade the metallic powder particles at or near the fracture tip
prior to producing the well to allow for the well to be produced at
full capacity. Once the metallic powder barrier having the metallic
particles is no longer needed, a condition may be changed to
promote the degrading of the metallic particles, such as but not
limited to a predetermined environmental condition, such as a
wellbore condition, including but not necessarily limited to
wellbore fluid temperature, pressure or pH value, salt or brine
composition, etc. The degrading of the metallic powder particles
may occur by a method, such as but not limited to dissolving the
metallic powder particles, degrading the metallic powder particles,
corroding the metallic powder particles, melting the metallic
powder particles, and combinations thereof.
[0029] As yet another example, these metallic powder particles
and/or metallic particle compacts may be configured to provide a
selectable and controllable degradation, disintegration or disposal
in response to a change in an environmental condition. An example
of an environmental condition may include, but is not necessarily
limited to, a transition from a very low dissolution rate to a very
rapid dissolution rate in response to a change in a property or
condition of a wellbore proximate an article formed from the
metallic particle compact, including a property change in a
wellbore fluid that is in contact with the metallic powder
particles and/or metallic particle compacts. Such property changes
may be or include, but are not necessarily limited to a temperature
change, the presence of an acid, an amount of time, and
combinations thereof.
[0030] In one non-limiting embodiment, these degradable powder
particles may be called controlled electrolytic metallics (CEM)
particles. Methods for using these metallic powder particles and/or
metallic particle compacts are described further below, as well as
in U.S. patent application Ser. No. 12/633,686 entitled COATED
METALLIC POWDER AND METHOD OF MAKING THE SAME, filed Dec. 8, 2009,
which is herein incorporated by reference in its entirety.
[0031] Magnesium or other reactive materials could be used in the
powders to make the degradable metal portions, for instance,
aluminum, zinc, manganese, molybdenum, tungsten, copper, iron,
calcium, cobalt, tantalum, rhenium, nickel, silicon, rare earth
elements, and alloys thereof and combinations thereof. As used
herein, rare earth elements include Sc, Y; lanthanide series
elements, including La, Ce, Pr, Nd, Pm, Sm, Eu, Gd, Te, Dy, Ho, Er,
Tm, or Lu; or actinide series elements, including Ac, Th, Pa, U,
Np, Pu, Am, Cm, Bk, Cf, Bk, Cf, Es, Fm, Md, or No; or a combination
of rare earth elements.
[0032] These metals may be used as pure metals or in any
combination with one another, including various alloy combinations,
such as amalgams and/or other physical combinations of these
materials, including binary, tertiary, or quaternary alloys of
these materials. Nanoscale metallic and/or non-metallic coatings
could be applied to these electrochemically active metallic powder
particles and/or metallic particle compacts to further strengthen
the material and to provide a means to accelerate or decelerate the
degrading rate.
[0033] Degradable enhancement additives include, but are not
necessarily limited to, magnesium, aluminum, nickel, iron, cobalt,
copper, tungsten, rare earth elements, and alloys thereof and
combinations thereof. It will be observed that some elements are
common to both lists, that is, those metals which can form
degradable metals and degradable metal compacts and those which can
enhance such metals and/or compacts. The function of the metals,
alloys or combinations depends upon what metal or alloy is selected
as the major particle core first.
[0034] The relative degradable rate depends on the value of the
standard potential of the additive or coating relative to that of
the particle core. For instance, to make a relatively more slowly
degrading particle core, the coating composition needs to have a
lower standard potential than that of the particle core. An
aluminum particle core with a magnesium coating is a suitable
example. Or, to make this particle core dissolve faster, the
standard potential of the particle core needs to be lower than that
of the coating. A non-limiting example of the latter situation
would be a magnesium particle core with a nickel coating.
[0035] These electrochemically active metals or metals with
nanoscale coatings may be degraded by a number of common wellbore
fluids, including any number of ionic fluids or highly polar
fluids. Non-limiting examples of such fluids include, but are not
limited to, sodium chloride (NaCl), potassium chloride (KCl),
hydrochloric acid (HCl), calcium chloride (CaCl.sub.2), sodium
bromide (NaBr), calcium bromide (CaBr.sub.2), zinc bromide
(ZnBr.sub.2), sodium formate, potassium formate, or cesium
formate.
[0036] Alternatively, relatively non-degradable metallic powder
particles (e.g. a ceramic portion) may be designed to where only
the coating of each particle degrades in a downhole environment,
while the rest of the metallic powder particle remains in place as
part of the barrier at or near the tip of the fracture. For
instance, these non-degradable metallic powder particles include
high strength intermetallic particles or ceramic particles of
oxides, nitrides, carbides, or specifically MgO in a non-limiting
example. The metallic powder particles could be solid or hollow.
The degradable coatings include, but are not limited to, the
reactive metals with corrosion enhancement coatings mentioned
above.
[0037] It will be appreciated that in the embodiment where there is
a degradable coating over all or a majority of a degradable
particle core, there may be applications where the coating should
be relatively more easily degraded than the particle core, and
other applications where the particle core is relatively more
easily degraded than the coating. Indeed, multiple coatings over a
particle core may be used to provide further control over the
degradation of the metallic powder particles and/or metallic
particle compacts. Combinations of different fluids and metallic
powder particles and/or metallic particle compacts with different
layers or portions that degrade at different rates will provide
many ways to design and control the formed metallic powder barrier
at or near the fracture tip depending on the desired wellbore
strengthening properties, the length of time desired for a formed
barrier, etc.
[0038] The dissolvable metallic powder particles and/or metallic
particle compacts may be spherical, elongated, rod-like or another
geometric shape. In another non-limiting embodiment, they may be
flake or granular in shape to reduce fluid losses to the formation.
One non-limiting example of the flake shape is SOLUFLAKE.TM. from
Baker Hughes.
[0039] The dissolvable metallic powder cores and/or metallic
particle compacts formed from the metallic powder particles may be
either uncoated or coated. Uncoated particle cores may be reactive
metals such as magnesium, aluminum, zinc, manganese or their
alloys, or metals with degradable enhancement additives included in
the particle core. Coated particles may have a particle core and at
least one metallic coating layer. The particle core of a coated
powder particle may be of metals such as magnesium, zinc, aluminum,
manganese, vanadium, chromium, molybdenum, iron, cobalt, silicon,
nitride, tungsten, and combinations thereof.
[0040] The metallic coating material may be or include, but is not
limited to, Al, Zn, Mn, Mg, Mo, W, Cu, Fe, Si, Ca, Co, Ta, Re, Ni,
an oxide thereof, a carbide thereof, a nitride thereof, and a
combination of any of the aforementioned materials. The metallic
coating material may be a different chemical composition than the
chemical composition of the particle core. The metallic coating
layer could be such that it accelerates or decelerates the
degradation of the metallic powder particle. These metallic powder
particles could be such that they degrade either partially or
completely over a period of time. The degradation rate may be
controlled by the composition of the base fluid, such as but not
limited to a drilling fluid, a completion fluid, a servicing fluid,
a fracturing fluid, and mixtures thereof.
[0041] In a non-limiting embodiment, the core material may be
Mg--Zn, Mg--Al, Mg--Mn, Mg--Zn--Y and combinations thereof. When
the core material is an Mg--Al--X alloy, the X may be or include
Zn, Mn, Si, Ca, Y, and combinations thereof. Additionally, the
Mg--Al--X alloy may be up to about 85 wt % of Mg, up to about 15 wt
% Al, and up to about 5 wt % X.
[0042] In an alternative procedure, it is conceived that these
degradable metallic powder particles and/or metallic particle
compacts may be designed so that a stimulation or second fluid
triggers the degradation of the powder particle compacts and/or
powder particles. After the metallic powder barrier has formed at
or near the fracture, a subsequent dosing of a second fluid,
different from the base fluid initially used to deliver the
degradable metallic powder particles and/or metallic particle
compacts into the wellbore, will trigger the dissolution of the
degradable particle phase or degradable particle compact phase. The
additional stimulation fluid treatments may include an acid or
brine or seawater, heated water or steam, or even fresh
water--something that provides chemical and/or physical stimuli for
triggering the dissolvable material to actually dissolve or
degrade. The acid may be a mineral acid (where examples include,
but are not necessarily limited to HCl, H.sub.2SO.sub.4,
H.sub.2PO.sub.4, HF, and the like), and/or an organic acid (where
examples include, but are not necessarily limited to acetic acid,
formic acid, fumaric acid, succinic acid, glutaric acid, adipic
acid, citric acid, and the like). In another embodiment, the acid
or brine may be the internal phase of an emulsion stimulation of a
cleanup fluid.
[0043] The size of the metallic powder particle may range from
about 25 nm independently to about 5000 .mu.m, alternatively from
about 100 nm independently to about 750 .mu.m. For a coated powder
particle, i.e. one having a powder particle core and a powder
particle coating, the particle core may have a diameter ranging
from about 1 nm independently to about 300 .mu.m, alternatively
from about 50 nm to about 500 .mu.m. The metallic coating layer
disposed on the particle core may have a melting temperature (Tc).
The thickness of the metallic coating layer may range from about 25
nm independently to about 2500 nm, or from about 100 nm
independently to about 500 nm. The metallic powder particles may be
configured for solid-state sintering to one another at a
predetermined sintering temperature (Ts) where Ts is less than Tp
and Tc to form a metallic particle compact. The size of the
metallic particle compact ranges from about 500 .mu.m independently
to about 20 cm.
[0044] The invention will now be illustrated with respect to
certain examples, which are not intended to limit the invention in
any way but simply to further illustrate it in certain specific
embodiments.
[0045] Shown in FIG. 1 is one version of a metallic powder particle
12 that is completely degradable, and an alternate embodiment of a
metallic powder particle 14 that has a portion 16 that is
degradable at a first rate, and a portion 18 that is degradable at
a second rate. In the particular, alternative embodiment of
metallic powder particle 14 shown in FIG. 1, metallic powder
particle 14 may have a generally central particle core 18 that is
relatively more slowly degradable compared to portion 16, which is
relatively more rapidly degradable and is a relatively uniform
coating over the generally central particle core 18. It should be
understood that the rates of degradation between portion 16 and
portion 18 may be reversed. In another non-limiting embodiment,
portion 18 is essentially not degradable in the process. However,
it will be appreciated that metallic powder particle 14 may have
other configurations, for example degradable portion 16 may not be
uniformly applied over generally central particle core 18.
[0046] These coatings may be formed by any acceptable method known
in the art and suitable methods include, but are not necessarily
limited to, chemical vapor deposition (CVD) including fluidized bed
chemical vapor deposition (FBCVD), as well as physical vapor
deposition, laser-induced deposition and the like, as well as
sintering and/or compaction. In another non-limiting version, the
particle may be formed of two approximately equal, or even unequal,
hemispheres, one of which is a relatively insoluble portion 18 and
the other of which is a relative dissolvable portion.
[0047] Also shown in FIG. 1 is a different embodiment of a metallic
particle compact 40, which may have powder particle cores 36 and a
thin metallic coating layer 38 thereon. Such metallic particle
compacts 40 do not necessarily have a metallic coating layer 38
over the entire metallic particle compact 40. In a non-limiting
instance, note that powder particle core 36 on the right side of
metallic particle compact 40 is not covered by coating 38. Metallic
particle compacts 40 may be reduced in size or degraded uniformly.
In an alternative non-limiting embodiment of a metallic particle
compact, at least two of the metallic powder particles 12, 14, 40,
and combinations thereof, may be sintered together to form a
metallic particle compact.
[0048] In a different non-limiting embodiment, the particles of
FIG. 1 may be engineered to have increased strength, at least up
until the powder particles begin to degrade. In a non-limiting
example, the portion 16 may be ceramic (e.g. an inorganic,
nonmetallic material) and the portion 18 may be metal.
[0049] It will be further understood that although metallic powder
particles 12 and 14 are shown as spheres, they may be other shapes
including, but not necessarily limited to, irregular rod-like,
acicular, dendritic, flake, nodular, irregular, and/or porous. In
another non-limiting version, the metallic powder particle may be
hollow or porous. For example, the metallic powder particle may
only have a coating but not a powder particle core.
[0050] In another non-restrictive embodiment, the degradable
portions of metallic powder particles 12 and 14 are made from a
degradable metal sintered and/or compacted from a metallic
composite powder comprising a plurality of metallic powder
particles. These smaller powder particles are not to be confused
with metallic powder particles 12 and 14. Each metallic powder
particle may comprise a particle core, where the particle core
comprises a core material comprising Mg, Al, Zn or Mn, or a
combination thereof, having a melting temperature (T.sub.P). The
powder particle may additionally comprise a metallic coating layer
disposed on the powder particle core and comprising a metallic
coating material having a melting temperature (T.sub.C), wherein
the powder particles are configured for solid-state sintering to
one another at a predetermined sintering temperature (T.sub.S), and
T.sub.S is less than T.sub.P and T.sub.C. Alternatively, T.sub.S is
slightly higher that T.sub.P and T.sub.C for localized micro-liquid
state sintering, By "slightly higher" is meant about 10 to about
50.degree. C. higher than the lowest melting point of all the
phases involved in the material for localized micro-liquid
sintering.
[0051] There are at least three different temperatures involved:
T.sub.P for the particle core, T.sub.C for the coating, and a third
one T.sub.PC for the binary phase of P and C. T.sub.PC is normally
the lowest temperature among the three. In a non-limiting example,
for a Mg particle with an Aluminum coating, according to a Mg--Al
phase diagram, T.sub.P=650.degree. C., T.sub.C=660.degree. C. and
T.sub.PC=437 to <650.degree. C. depending on wt % ratio of the
Mg--Al system. Therefore, for completed solid-state sintering, the
predetermined process temperature needs to be less than T.sub.PC.
For micro-liquid phase sintering at the core-coating interface, the
temperature may be 10-50 degree C. higher than T.sub.PC but less
than T.sub.P and T.sub.C. A temperature higher than T.sub.P or
T.sub.C may be too much, causing macro melting and destroying the
coating structure.
[0052] The proportion of base fluid may be greater than that of
completely degradable metallic powder particle 12. In one
non-limiting embodiment, the proportion of degradable particles
within the total fluid composition may range from about 0.05 wt %
independently to about 10 wt %, alternatively from about 0.05 wt %
independently to about 3 wt %.
[0053] The completely dissolvable metallic powder particle 12 need
not be the same or approximately the same size as the metallic
powder particle 14. In one non-limiting embodiment, average
particle size of the metallic powder particle 12 may range from
about 100 nm independently to about 100 microns, alternatively from
about 100 nm independently to about 1 micron.
[0054] After placement of the metallic powder barrier, at least a
portion of the degradable metallic powder particle 12 may be
degraded and removed therefrom, which thereby reduces the size of
the barrier. This may be beneficial when it is desirable to have a
barrier of varying sizes over a period of time, or alternatively it
may be beneficial to degrade the metallic powder particles once the
barrier is no longer needed. The second fluid may degrade the
metallic powder particles of the barrier. "Second fluid" is defined
herein to mean any fluid added into the wellbore after the fluid
formulation has been pumped into the wellbore, which may include
but is not necessarily limited to a fluid that is the same base
fluid as the first fluid but has been altered for purposes of
degrading the particles.
[0055] The second fluid may contain corrosive material, such as
select types and amounts of acids and salts, to control the rate of
degradation of the particles. In another embodiment, the fluid
formulation that introduced the metallic powder particles into the
fracture may be removed or displaced, and subsequently a second
fluid may be introduced to degrade the metallic powder particles
12. This second fluid may suitably be, but is not necessarily
limited to, fresh water, brines, acids, hydrocarbons, emulsions,
and combinations thereof so long as it is designed to dissolve all
or at least a portion of the dissolvable metallic powder particles
12. While all of the metallic powder particles 12 may be removed,
as a practical matter, in an alternate embodiment, it may not be
possible to contact and degrade all of the dissolvable metallic
powder particles 12 with the subsequent fluid and thus remove or
degrade all of them. In one non-limiting embodiment, at least 90%
to about 100% of the barrier may be removed, alternatively at least
50%, and in another non-limiting embodiment at least 10%.
[0056] A third fluid may also be used for further degrading of the
metallic powder particles. "Third fluid" is defined herein as any
fluid used after the second fluid that may degrade the metallic
powder particles in a different manner than that of the second
fluid.
[0057] In the foregoing specification, the invention has been
described with reference to specific embodiments thereof, and has
been demonstrated as effective in providing methods and
compositions for strengthening a wellbore. However, it will be
evident that various modifications and changes can be made thereto
without departing from the broader spirit or scope of the invention
as set forth in the appended claims. Accordingly, the specification
is to be regarded in an illustrative rather than a restrictive
sense. For example, specific combinations of or types of base
fluids, metallic particle compacts, metallic particles, particle
cores, metallic coating layers, second fluids, third fluids, and
other components falling within the claimed parameters, but not
specifically identified or tried in a particular composition or
method, are expected to be within the scope of this invention.
Further, it is expected that the components and proportions of the
base fluid and metallic powder particles and procedures for
strengthening the wellbore or forming a metallic powder barrier at
or near the fracture tip may change somewhat from one application
to another and still accomplish the stated purposes and goals of
the methods described herein. For example, the methods may use
different pressures, pump rates, additional fluids, and/or
different steps than those exemplified herein.
[0058] The words "comprising" and "comprises" as used throughout
the claims is interpreted "including but not limited to".
[0059] The present invention may suitably comprise, consist or
consist essentially of the elements disclosed and may be practiced
in the absence of an element not disclosed. For instance, a method
for strengthening a wellbore may consist of or consist essentially
of contacting the wellbore with a fluid composition having a base
fluid and a metallic powder having a plurality of metallic
particles, and forming a metallic powder barrier at or near the tip
of a fracture extending from the wellbore into a subterranean
formation, where the method further consists of or consists
essentially of degrading the metallic powder particles after a
predetermined condition, and reducing additional growth of the
fracture as compared to contacting the wellbore with a fluid
composition absent the metallic powder.
* * * * *