U.S. patent application number 12/018050 was filed with the patent office on 2008-07-31 for well treating agents of metallic spheres and methods of using the same.
This patent application is currently assigned to BJ Services Company. Invention is credited to Jeffrey C. Dawson.
Application Number | 20080179057 12/018050 |
Document ID | / |
Family ID | 39428054 |
Filed Date | 2008-07-31 |
United States Patent
Application |
20080179057 |
Kind Code |
A1 |
Dawson; Jeffrey C. |
July 31, 2008 |
Well Treating Agents of Metallic Spheres and Methods of Using the
Same
Abstract
Hollow non-porous metallic spheres may be used in treatment of
subterranean formations, including hydraulic fracturing and sand
control methods, such as gravel packing. The spheres typically
having a diameter ranging from about 4 mesh to about 100 mesh. When
employed in deep water environments having high closure stresses,
the spheres have a thicker wall and are characterized by the higher
ASG, typically between 2.5 to about 4.0. The ASG of the spheres,
when less harsh environments are encountered, is generally ultra
lightweight (ULW) with an ASG less than or equal to 2.0. Fracture
conductivity may be increased by the placement of the hollow
non-porous metallic spheres as a partial monolayer.
Inventors: |
Dawson; Jeffrey C.; (Spring,
TX) |
Correspondence
Address: |
JONES & SMITH , LLP
2777 ALLEN PARKWAY, SUITE 800
HOUSTON
TX
77019
US
|
Assignee: |
BJ Services Company
|
Family ID: |
39428054 |
Appl. No.: |
12/018050 |
Filed: |
January 22, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60897679 |
Jan 26, 2007 |
|
|
|
Current U.S.
Class: |
166/280.2 ;
507/204; 507/220 |
Current CPC
Class: |
C09K 8/805 20130101 |
Class at
Publication: |
166/280.2 ;
507/220; 507/204 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A well treating agent comprising particulates consisting of
hollow non-porous metallic spheres.
2. The well treating agent of claim 1, wherein the metal is
stainless steel alloy, carbon steel or a metal selected from the
group consisting of iron, chromium, titanium, nickel, cobalt or
molybdenum or an alloy mixture thereof.
3. The well treating agent of claim 2, wherein the metal is
stainless steel or titanium.
4. The well treating agent of claim 1, further comprising a coating
on at least a portion of the hollow non-porous metallic
spheres.
5. The well treating agent of claim 4, wherein the coating is
selected from the group consisting of a phenolic resin,
phenol-formaldehyde resin, melamine-formaldehyde resin,
polyurethane, carbamate resin, epoxy resin, polyamide,
polyethylene, polystyrene and a combination thereof.
6. The well treating agent of claim 5, wherein the coating is
selected from the group consisting of an epoxy resin, phenol
formaldehyde resin and a urethane resin.
7. The well treating agent of claim 1, wherein the apparent
specific gravity of the core of the well treating agent is less
than or equal to 4.0.
8. The well treating agent of claim 7, wherein the apparent
specific gravity of the core of the well treating agent is less
than or equal to 3.0.
9. The well treating agent of claim 8, wherein the apparent
specific gravity of the core of the well treating agent is less
than or equal to 2.0.
10. The well treating agent of claim 9, wherein the apparent
specific gravity of the core of the well treating agent is less
than or equal to 1.5.
11. The well treating agent of claim 1, wherein the apparent
specific gravity of the core of the well treating agent is between
from about 1.05 to about 2.0.
12. A proppant or sand control particulate composed of the well
treating agent of claim 1.
13. A method of treating a well which comprises introducing into
the well a composition comprising the well treating agent of claim
1.
14. The method of claim 13, wherein the well treating agent is
introduced into the well as part of a sand control and/or hydraulic
fracturing operation.
15. The method of claim 13, wherein the well treating agent is
introduced into the well at concentrations sufficient to achieve a
partial monolayer fracture.
16. The method of claim 14, wherein the fracturing is conducted at
a closure stress greater than about 1500 psi at a temperature
greater than 150.degree. F.
17. The method of claim 13, wherein the apparent specific gravity
of the well treating agent is less than or equal to 4.0.
18. The method of claim 17, wherein the apparent specific gravity
of the well treating agent is less than or equal to 3.0.
19. A well treating agent comprising a core and a coating on at
least a portion of the core, wherein the core comprises hollow
non-porous metallic spheres.
20. The well treating agent of claim 19, wherein the coating is
selected from the group consisting of a phenolic resin,
phenol-formaldehyde resin, melamine-formaldehyde resin,
polyurethane, carbamate resin, epoxy resin, polyamide,
polyethylene, polystyrene and a combination thereof.
21. The well treating agent of claim 19, wherein the coating is
selected from the group consisting of an epoxy resin, phenol
formaldehyde resin and a urethane resin.
22. The well treating agent of claim 19, wherein the metal is
stainless steel alloy, carbon steel or a metal selected from the
group consisting of iron, chromium, titanium, nickel, cobalt or
molybdenum or an alloy mixture thereof.
23. The well treating agent of claim 19, wherein the apparent
specific gravity of the well treating agent is less than or equal
to 2.0.
24. The well treating agent of claim 23, wherein the apparent
specific gravity of the well treating agent is less than or equal
to 1.5.
25. A proppant or sand control particulate composed of the well
treating agent of claim 19.
26. A method of treating a well which comprises introducing into
the well a composition comprising the well treating agent of claim
19.
27. The method of claim 26, wherein the well treating agent is
introduced into the well as part of a sand control and/or hydraulic
fracturing operation.
28. The method of claim 27, wherein the well treating agent is
introduced into the well at concentrations sufficient to achieve a
partial monolayer fracture.
29. The method of claim 27, wherein the fracturing is conducted at
a closure stress greater than about 1500 psi at a temperature
greater than 150.degree. F.
30. The method of claim 26, wherein the apparent specific gravity
of the well treating agent is less than or equal to 4.0.
31. The method of claim 30, wherein the apparent specific gravity
of the well treating agent is less than or equal to 3.0.
32. A well treating agent comprising a core of hollow non-porous
metallic spheres, the core being free of a fibrous reinforcing
agent, wherein the compressive strength of the well treating agent
is greater than the compressive strength of a similar well treating
agent containing a core of hollow non-porous metallic spheres and a
fibrous reinforcing agent.
33. A sand control method for a wellbore penetrating a subterranean
formation, comprising: introducing into the wellbore a slurry
comprising particulates and a carrier fluid, wherein the
particulates are hollow non-porous metallic spheres; placing at
least a portion of the particulates adjacent the subterranean
formation to form a fluid-permeable pack capable of reducing or
substantially preventing the passage of formation particles from
the subterranean formation into the wellbore while allowing passage
of formation fluids from the subterranean formation into the
wellbore.
34. The method of claim 33, wherein the particulates have an
apparent specific gravity less than or equal to 2.0.
35. The method of claim 33, wherein the particulates have an
apparent specific gravity between from about 1.05 to about 2.0.
Description
[0001] This application claims the benefit of U.S. patent
application Ser. No. 60/897,679, filed on Jan. 26, 2007, wherein is
herein incorporated by reference.
FIELD OF THE INVENTION
[0002] This invention relates to methods and compositions useful
for subterranean formation treatments, such as hydraulic fracturing
and sand control. In particular, this invention relates to the use
of hollow substantially non-porous metallic spheres in sand control
methods such as gravel packing, frac pack treatments, etc., as well
as proppant material in hydraulic fracturing.
BACKGROUND OF THE INVENTION
[0003] Stimulation procedures often require the use of well
treating materials having high compressive strength. In hydraulic
fracturing, such materials must further be capable of enhancing the
production of fluids and natural gas from low permeability
formations.
[0004] In a typical hydraulic fracturing treatment, fracturing
treatment fluid containing a solid proppant material is injected
into the wellbore at high pressures. Once natural reservoir
pressures are exceeded, the fluid induces fractures in the
formation and proppant is deposited in the fracture, where it
remains after the treatment is completed. The proppant material
serves to hold the fracture open, thereby enhancing the ability of
fluids to migrate from the formation to the wellbore through the
fracture. Fractured well productivity depends on the ability of a
fracture to conduct fluids from a formation to a wellbore. Fracture
conductivity is an important parameter in determining the degree of
success of a hydraulic fracturing treatment. Choosing a proppant is
critical to the success of well stimulation.
[0005] Conventional proppants, such as sand and glass beads and
bauxite, as well as resin-coated sands, intermediate strength
ceramics and sintered bauxite, are characterized by a fairly high
apparent specific gravity (ASG). For instance, the ASG for sand is
about 2.65 and the ASG for sintered bauxite is 3.4. Proppant
transport is often difficult with such proppants. Further, higher
ASG proppants (greater than 2.65) often cause a reduction in
propped fracture volume, based on equivalent mass of proppant,
which, in turn, causes a reduction in fracture conductivity. The
high ASG of such conventional proppants is known to be the
controlling factor in the difficulties in proppant transport and
reduced propped fracture volume.
[0006] More recently, ultra lightweight (ULW) materials have been
used as proppants. ULW proppants are typically characterized by an
ASG less than or equal to 2.45 and exhibit better deformability
than conventional heavy proppants. ULW proppants, in addition to
having lower ASG than conventional heavy proppants, typically
exhibit sufficient strength to withstand the rigors of high
temperatures and high stresses downhole. While offering excellent
compressive strength, ULW proppants often soften and loose their
compressive strength especially at high temperature and high
pressure downhole conditions. Alternatives have therefore been
sought.
[0007] Further, alternative materials have been sought for use with
hydraulic fracturing fluids (such as water, salt brine and
slickwater) at relatively low concentrations in order that a
partial monolayer of proppant in the fracture may be obtained. In
conventional sand packs, tightly held packs often are characterized
by insufficient interconnected interstitial spaces between abutting
particulates. Increased interstitial spaces between the
particulates are typically desired in order to increase
conductivity. This may be achieved by use of a partial monolayer
fracture wherein reduced volume of proppant particulates in a
fracture is created by the use of widely spaced proppant
particulates. Increased fracture conductivity results since the
produced fluids typically flow around the widely-spaced proppant
particulates rather than through the interstitial spaces in a
packed bed. The phenomena of partial monolayer fracturing has been
discussed in the literature. See, for instance, Brannon et al,
"Maximizing Fracture Conductivity with Partial Monolayers:
Theoretical Curiosity or Highly Productive Reality" SPE 90698,
presented at the SPE Annual Technical Conference and Exhibition,
Houston, Sep. 26-29, 2004. Unfortunately, partial monolayer
fracturing has been difficult to achieve with state-of-the-art
proppants.
[0008] Improved well treating agents have also been sought for use
in the prevention of sand grains and/or other formation fines from
migrating into the wellbore. When such migration occurs, such
grains and fines typically reduce the rate of hydrocarbon
production from the well. In addition, such grains and fines can
cause serious damage to well tubulars and to well surface
equipment.
[0009] Gravel packs are often used to control migration of
particulates in such producing formations. A gravel pack typically
consists of a uniformly sized mass of spherical particulates which
are packed around the exterior of a screening device. Such
screening devices, typically positioned in an open hole or inside
the well casing, have very narrow openings which are large enough
to permit the flow of formation fluid but small enough to allow the
particulates to pass through. The particulates operate to trap, and
thus prevent the further migration of, formation sand and fines
which would otherwise be produced along with the formation
fluid.
[0010] In order to be useful in gravel packing applications, such
particulates must exhibit high strength and be capable of
functioning in low permeability formations. ULW well treating
agents have been proposed for use in gravel packing applications to
improve transport, placement, and packing efficiency. Concerns
exist however that ULW particulates do not demonstrate the chemical
resistance properties required of particulates for use in gravel
packing.
[0011] Alternative well treating agents have therefore been sought
which exhibit high compressive strength and which may be used to
improve packing efficiency, transport and placement of proppant in
fracturing. It is further desired that such materials be useful in
other oilfield treatment processes, such as sand control.
SUMMARY OF THE INVENTION
[0012] The invention relates to a well treating agent composed of
hollow non-porous metallic spheres. The invention further relates
to a well treating composite which contains the hollow non-porous
metallic spheres. In a preferred embodiment, the composite consists
of a core comprising the metallic spheres and a coating applied
onto at least a portion of the hollow non-porous metallic
spheres.
[0013] The metallic spheres are preferably composed of stainless
steel alloy or carbon steel as well as metals, such as iron,
chromium, titanium, nickel, cobalt, aluminum or molybdenum or an
alloy mixture of such metals. In a preferred embodiment, the metal
is stainless steel or titanium. Typically, the diameter of the
spheres ranges from about 4 mesh to about 100 mesh.
[0014] The hollow non-porous metallic spheres are generally
introduced into the well with a carrier fluid.
[0015] The coating may be applied to a portion of the metallic
spheres or to the entire circumference of the spheres. The coating
may function as a sealant to prevent invasion of the carrier fluid
(as well other fluids in the wellbore) into the core. The coating
may further provide greater anti-corrosive characteristics to the
well treating composite.
[0016] Suitable coatings include phenolic resins,
phenol-formaldehyde resins, melamine-formaldehyde resins,
polyurethanes, carbamate resins, epoxy resins, polyamides,
polyolefins, such as polyethylene, polystyrene and a combination
thereof. In a preferred embodiment, the coating is an epoxy resin,
phenol formaldehyde resin or a urethane resin.
[0017] The apparent specific gravity (ASG) of the hollow non-porous
metallic spheres is generally less than or equal to 4.0, preferably
less than or equal to 3.0. When employed in deep water environments
having high closure stresses, such as when used as proppants, the
spheres have a thicker wall and are characterized by an ASG which
is preferably in the vicinity of from about 2.5 to about 4.0. The
ASG of the spheres, when less harsh environments are encountered,
is generally less than or equal to 2.0, generally between from
about 1.05 to about 2.0.
[0018] The well treating agent and composite defined herein exhibit
high compressive strength. Fracturing may therefore be conducted at
closure stresses greater than about 500 psi and at temperatures
ranging from ambient to 500.degree. F. For example, spheres of a 1
mm diameter and an ASG of about 1.3 are capable of withstanding up
to 20,000 psi. The high compressive strength exhibited by the
spheres may be attributable to the stiffness of the metal. The high
compressive strength may further be attributable to the cylindrical
shape of the spheres upon them being subjected to high pressures.
As high pressure is applied, such as by a mechanical press, the
metallic spheres start to deform between the two platens and the
two points of contact begin to cave. As the area exposed to the
load increases, the deformed particulates resemble oriented
cylinders. Such cylinders, along with their short length, offer
tremendous strength to the particulates.
[0019] While the well treating agent and composite may be combined
with fibrous reinforcing agents, typically the addition of fibrous
reinforcing agents is unnecessary. The compressive strength of the
well treating agent free of fibrous reinforcing agents is typically
greater than the compressive strength of an aggregate composed of
the same hollow non-porous metallic spheres and fibrous reinforcing
agent.
[0020] A further benefit of the well treating agents of the
invention is their ability to capture and trap spalding fines
formed during closure. Such fines may be trapped within the
deforming region of the spheres.
[0021] The well treating agent and composite of the invention finds
particular applicability as proppants in the fracturing of
hydrocarbon-bearing formations. In particular, the well treating
agent or composite may be introduced into the well at
concentrations sufficient to achieve a partial monolayer of
proppant in the fracture.
[0022] The well treating agents of the invention, as well as
composites comprising such well treating agents, may further be
used in sand control. In such applications, the hollow non-porous
metallic spheres (or composites) are typically introduced into the
wellbore in a slurry of the carrier fluid. At least a portion of
the well treating agent (or composite) is placed adjacent the
subterranean formation to form a fluid-permeable pack. The pack is
capable of reducing or substantially preventing the passage of
formation particles from the subterranean formation into the
wellbore. At the same time, formation fluids from the subterranean
formation are permitted to pass into the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] In order to more fully understand the drawings referred to
in the detailed description of the present invention, a brief
description of each drawing is presented, in which:
[0024] FIG. 1 is a schematic diagram of a particle compression cell
used to test deformation of a metallic sphere of the invention.
[0025] FIG. 2 is a displacement-load curve for different metallic
spheres defined by the invention.
[0026] FIG. 3 is a photograph of metallic spheres within the
invention at the point of collapse at varying loads.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0027] The well treating agent of the invention contains
particulates of hollow metallic spheres. The metallic spheres may
exhibit a minimal level of porosity, i.e., that level of porosity
which is necessary for the release of internal gases from the
spheres upon exposure of the spheres to elevated temperatures
and/or pressures. Well treating agents exhibiting such minimal
levels of porosity are hereinafter referred to as being
"substantially non-porous". Typically, the amount of porosity in
such substantially non-porous metallic spheres is less than or
equal to 1 volume percent based on the total volume of the metal
which constitutes the metallic sphere. Alternatively, the hollow
metallic spheres may be completely non-porous. (The reference
herein to "hollow non-porous metallic spheres" shall refer to both
those hollow metallic spheres which are completely non-porous as
well as those metallic spheres which are substantially
non-porous.)
[0028] The well treating agent may consist entirely of the hollow
non-porous metallic spheres.
[0029] The hollow non-porous metallic spheres are typically
lightweight and exhibit high strength. As such, they find
particular applicability as proppant and sand control particulates
in gravel packing and hydraulic fracturing. Preferably, such
particulates have a sphericity of about 0.9, API RP 58, an
important parameter for gravel packing as higher sphericity equates
to relatively high permeability.
[0030] The particle size of the metallic spheres may be selected
based on anticipated downhole conditions including the width of the
anticipated fracture. Typically, the diameter of the spheres is in
a range from about 4 mesh to about 100 mesh, alternatively from
about 10 mesh to about 40 mesh. The spheres deform with stress and
yet are sufficiently strong to be used on their own at high
pressures, such as a closure stress in excess of 4,000 psi, when
the spheres are used in a partial monolayer hydraulic fracturing
application. The spheres are further capable of preventing sand
grains and/or other formation fines from migrating into the
wellbore in sand control applications.
[0031] The metallic spheres are made from conductive metal or alloy
powders which, preferably, exhibit at least some resistance to
corrosion at downhole fluids and downhole conditions. Such
conductive metals may be stainless steel, iron, copper, nickel,
cobalt, chromium, aluminum, molybdneum, titanium, silver, gold,
tin, lead, steel, cast iron, brass, bronze, nickel alloys or a
mixture or alloys thereof. Stainless steel alloy or carbon steel
are preferred, as well as metals, such as iron, chromium, titanium,
nickel, aluminum, cobalt or molybdenum or an alloy mixture of such
metals. Stainless steel and titanium are most preferred.
[0032] The hollow metallic spheres may be produced by procedures
known in the art. One such method is an electromagnetic levitation
melting technique, disclosed in U.S. Pat. No. 4,565,571. In this
process, a particulate material containing a conductive metal or
alloy powder is formed which exhibits sufficient green strength to
be substantially self-supporting. The green porous article is then
subjected to an electromagnetic field which (i) has a field
strength and frequency sufficient to exert a force in a direction
such that the force of gravity acting on the green article is
counterbalanced thereby levitating it in space, and (ii) has a
frequency sufficient to induce an eddy current in the article of
such intensity that the dissipation thereof produces sufficient
heat to melt the electrically conductive metal. Pores are therefore
entrapped in the pores of the green particle as well as any gases
contained therein. The molten particle containing the entrapped
pores may be heated for a longer period of time to expand the gases
contained in the pores to a volume such that substantially all of
the entrapped pores combine to produce a hollow molten metal
sphere. The spheres are then cooled at a rate sufficient to
solidify the molten metal.
[0033] Another method of manufacturing the hollow non-porous
metallic spheres is by the continuous extrusion of a dispersion
containing the particulate metal from a coaxial blowing nozzle, as
disclosed in U.S. Pat. No. 4,867,931. This process uses an aqueous
or volatile solvent containing dispersed metal oxide(s) which is
capable of forming a film. The particle film may consist of a
selection of metal oxides, such as iron oxide, nickel oxide,
molybdeum oxide, chromium oxide, cobalt oxide and titanium hydride,
mixed at the requisites percentages to yield the final desired
alloy. The dispersion may also contain a binder, such as cellulose
acetate or polyvinyl alcohol; a film stabilizing agent which may
include an anionic surfactant, such as a salt of lauryl sulfate;
and a dispersing agent which may include a sodium alkyl or sodium
aryl sulfate. The dispersed phase is fed to a concentric, coaxial
blowing nozzle, such that the inner nozzle supplies a blowing gas
contacting the dispersing phase residing in the annulus near the
orifice of the blowing nozzle. The blowing gas (typically nitrogen,
argon or hydrogen) pushes through a thin layer of dispersing phase
at the orifice creating a droplet or hollow sphere of dispersed
phase. While falling, the droplet is heated to form a workable
"green" hollow sphere of the oxide. The spheres are then gathered
and heated in a kiln to a temperature between from about
400.degree. C. to about and 800.degree. C. in a reducing atmosphere
of hydrogen. Heating in hydrogen reduces the oxides to the metal
and water. The metallic spheres are then heated to a temperature
between from about 1000.degree. C. to about 1500.degree. C. to
strengthen the spheres in a sintering process. This process
produces uniformly sized, hollow non-porous metallic spheres having
a uniform wall thickness.
[0034] A coating is preferably applied to the circumference of the
spheres to form a coated composite. While the coating may function
as a sealant to prevent entry of the carrier fluid or other
wellbore fluids into the core of the spheres, the non-porous nature
of the metallic spheres typically often renders such a sealant
unnecessary. The amount of coating, when present, is typically from
about 0.5 to about 10% by weight of the composite.
[0035] The coating may be applied to the non-porous metallic
spheres using any suitable method known in the art. For example,
the process, as disclosed in U.S. Pat. No. 7,135,231, may consist
of heating the metallic spheres to a temperature between from about
93.degree. C. to about 425.degree. C., adding the heated spheres to
a mixing apparatus, if necessary, and then applying a coupling
agent, such as a polyamine, onto the surface of the spheres. A
resin coating may then be sputtered onto at least a portion of the
surface of the spheres. If additional protection is necessary, the
process can include sputtering additional resin coats onto the
spheres in an incremental manner, such that the resultant coated
sphere has a plurality of interleaved resin coats fully coating the
spheres.
[0036] The coating of the composite may further function to
counteract caustic downhole conditions on the metal of the spheres
and thus may provide greater anti-corrosive characteristics to the
well treating agent.
[0037] In another embodiment, the metallic spheres may be heated to
a temperature between from about 93.degree. C. to about 425.degree.
C. and a resinous coating then applied while the metallic spheres
are being cooled.
[0038] Representative coatings for the composite include phenolic
resins, phenol-formaldehyde resins, melamine-formaldehyde resins,
polyurethanes, carbamate resins, epoxy resins, polyamides,
polyolefins, such as polyethylene, polystyrene and a combination
thereof. In a preferred embodiment, the coating is an epoxy resin,
phenol formaldehyde resin or a urethane resin.
[0039] The apparent specific gravity (ASG) of the hollow non-porous
metallic spheres is generally less than or equal to 4.0, preferably
less than or equal to 3.0. The non-porous nature of the metallic
spheres assists in keeping the ASG of the spheres to remain
constant during transport.
[0040] When the well treating agents (or composites) are employed
in deep water environments having high closure stresses, the ASG of
the hollow non-porous metallic spheres is preferably between from
about 2.5 to about 4.0. In such applications, fracturing may be
conducted at closure stresses greater than about 1500 psi and at
temperatures ranges between ambient and 260.degree. C. As a result,
the well treating agents defined herein, as well as composites
containing the same, function well in ultra deep, hot, high closure
stress applications.
[0041] For use in less harsh environments, the ASG of the hollow
non-porous metallic spheres is generally less than or equal to 2.0,
generally less than 1.5, more generally between from about 1.05 to
about 2.0.
[0042] The spheres, either by themselves as well treating gent or
as a composite, are generally introduced into the well with a
carrier fluid. Any carrier fluid suitable for transporting the
spheres into the well and/or subterranean formation fracture in
communication therewith may be employed including, but not limited
to, carrier fluids including a brine, salt water, unviscosified
water, fresh water, potassium chloride solution, a saturated sodium
chloride solution, liquid hydrocarbons, and/or a gas such as
nitrogen or carbon dioxide. In a preferred embodiment, the carrier
fluid is unviscosified water or brine.
[0043] The carrier fluid may be gelled, non-gelled or have a
reduced or lighter gelling requirement. The latter may be referred
to as "weakly gelled", i.e., having minimum sufficient polymer,
thickening agent, such as a viscosifier, or friction reducer to
achieve friction reduction when pumped downhole (e.g., when pumped
down tubing, work string, casing, coiled tubing, drill pipe, etc.),
and/or may be characterized as having a polymer or viscosifier
concentration of from greater than 0 pounds of polymer per thousand
gallons of base fluid to about 10 pounds of polymer per thousand
gallons of base fluid, and/or as having a viscosity of from about 1
to about 10 centipoises. The non-gelled carrier fluid typically
contains no polymer or viscosifer.
[0044] The use of a non-gelled carrier fluid eliminates a source of
potential packing and/or formation damage and enhancement in the
productivity of the well. Elimination of the need to formulate a
complex suspension gel may further mean a reduction in tubing
friction pressures, particularly in coiled tubing and in the amount
of on-location mixing equipment and/or mixing time requirements, as
well as reduced costs. In one embodiment employing a substantially
neutrally buoyant particulate and a brine carrier fluid, mixing
equipment need only include such equipment that is capable of (a)
mixing the brine (dissolving soluble salts), and (b) homogeneously
dispersing in the substantially neutrally buoyant particulate.
[0045] The carrier fluid may further contain one or more
conventional additives to the well service industry such as a
gelling agent, crosslinking agent, gel breaker, surfactant,
biocide, surface tension reducing agent, foaming agent, defoaming
agent, demulsifier, non-emulsifier, scale inhibitor, gas hydrate
inhibitor, polymer specific enzyme breaker, oxidative breaker,
buffer, clay stabilizer, paraffin inhibitor, anti-corrosion agent,
acid, buffer, solvent or a mixture thereof and other well treatment
additives known in the art. The addition of such additives to the
carrier fluids minimizes the need for additional pumps required to
add such materials on the fly.
[0046] The hollow non-porous metallic spheres (or composites
containing the spheres) may be advantageously pre-suspended as a
substantially neutrally buoyant particulate and stored in the
carrier fluid (e.g., brine of near or substantially equal density),
and then pumped or placed downhole as is, or diluted on the fly.
The term "substantially neutrally buoyant" refers to hollow
non-porous metallic spheres (or composites) that have an ASG
sufficiently close to the ASG of the selected ungelled or weakly
gelled carrier fluid (e.g., ungelled or weakly gelled completion
brine, other aqueous-based fluid, slick water, or other suitable
fluid) which allows pumping and satisfactory placement of the
proppant/particulate using the selected ungelled or weakly gelled
carrier fluid.
[0047] The well treating agents of the invention find particular
applicability in the fracturing of hydrocarbon-bearing formations
or water injection wells. While the hollow non-porous metallic
spheres are ideally suited for use as proppants in partial
monolayers, they are further useful in normal fracture packs and
sand control packs. In a preferred embodiment of the invention,
however, the well treating agents are used, in light of the
lightweight and high strength of the hollow non-porous metallic
spheres, in a fracturing fluid at concentrations sufficient to
achieve a partial monolayer fracture. Since the hollow non-porous
metallic spheres may be made in a variety of ASGs, when used in a
dense, non-viscous brine, some particles may float; some settle and
some remain buoyant for good distribution across the entire
fracture height for uniform coverage of the fracture area. Thus,
the hollow non-porous metallic spheres offer all the advantages of
lightweight proppants without sacrificing strength. In addition,
when the spheres fail to crush, they do not produce fines like
ceramic and quartz based proppants.
[0048] The wall of the hollow non-porous metallic spheres of the
well treating fluid are typically 100% metal and do not contain
reinforcing agents. The compressive strength of the well treating
agent free of fibrous reinforcing agents is typically greater than
the compressive strength of a well treating agent composed of the
same hollow non-porous metallic spheres and a fibrous reinforcing
agent. Fibrous reinforcing agents, when used with metallic spheres,
typically promote interconnecting voids in the spheres. See, for
instance, U.S. Pat. No. 4,867,931. This, in turn, causes the metal
spheres to fill with fluid. When used as well treating agents, the
entry of fluids into the metal spheres would increase the ASG of
the well treating agent when it is exposed to hydrostatic pressure.
This, in turn, jeopardizes the placement of the spheres in a
partial monolayer since heavier proppant falls faster upon entering
the fracture due to gravitational affects. The non-porous metallic
spheres (as well as composites containing the spheres) of the
invention are capable of achieving a partial monolayer fracture
since the proppant may be uniformly dispersed in the fracture at
the time of closure.
[0049] In another preferred embodiment, the hollow non-porous
metallic spheres and/or substantially neutrally buoyant metallic
spheres (as well as composites containing such spheres) are used in
a sand control method. The spheres (or composites) may be
introduced into the wellbore in a slurry with the carrier fluid.
The spheres (or composites) are placed adjacent the subterranean
formation to form a fluid-permeable pack. The fluid permeable pack
is capable of reducing or substantially preventing the passage of
formation particles from the subterranean formation into the
wellbore while at the same time allowing passage of formation
fluids from the subterranean formation into the wellbore.
[0050] In a preferred gravel pack operation, a screen assembly may
be placed or otherwise disposed within the wellbore so that at
least a portion of the screen assembly is disposed adjacent the
subterranean formation. (The gravel pack operation may further
proceed using a screenless pack.) A slurry containing the hollow
non-porous metallic spheres (or composites) may then be introduced
into the wellbore and placed adjacent the subterranean formation by
circulation or other suitable method. A fluid-permeable pack is
formed in the annular area between the exterior of the screen and
the interior of the wellbore which is capable of reducing or
substantially preventing the passage of formation particles from
the subterranean formation into the wellbore during production of
fluids from the formation. At the same time, the permeable pack
allows the passage of formation fluids from the subterranean
formation through the screen into the wellbore. When the flow is
reversed, the consolidated hollow metallic spheres will flow back
(or composites) with minimal formation sands. Particularly
advantageous results are obtained in horizontal gravel packing
which are large, such as those 6,000 ft long.
[0051] The hollow non-porous metallic spheres (or composites
containing the spheres) may be mixed with the carrier fluid in any
manner suitable for delivering the mixture to a wellbore and/or
subterranean formation. In one embodiment, the spheres (or
composites) may be injected into a subterranean formation in
conjunction with a hydraulic fracturing treatment or other
treatment at pressures sufficiently high enough to cause the
formation or enlargement of fractures, or to otherwise expose the
particles to formation closure stress. Such other treatments may be
near wellbore in nature (affecting near wellbore regions) and may
be directed toward improving wellbore productivity and/or
controlling the production of fracture proppant or formation
sand.
[0052] The hollow non-porous metallic spheres (or composites
containing the spheres) are further employed in frac-pack
operations, especially in unconsolidated and semi-consolidated
formations in order to facilitate fluid recovery while preventing
particulate migration. The frac-pack operation typically embodies
the features of both a fracturing operation and a gravel packing
operation. The unconsolidated formation may initially be fractured
using the particulate materials. Additional proppant may then be
held in place in the wellbore by (a) packing the material around a
gravel packing screen and/or (b) consolidating the proppant
material by means of a resin coating.
[0053] The well treating agents of the invention are further highly
effective in capturing and trapping fines formed from "spalling"
which is caused by embedment of the hydraulic fracture proppant
into the exposed faces of the rock during closure. Such fines may
severely reduce fracture conductivity. Such fines may be trapped
within the deforming region of the spheres and, as such, are
prevented from entering into the proppant pack.
[0054] In other fracturing application that employ multi-layer
proppant packs, the hollow non-porous metallic spheres (as well as
composites containing such spheres) may also be added to
conventional proppants in concentrations from 0.5% to 20%, based on
the total weight of proppant, to minimize or prevent proppant from
being dislodged from the sand pack. Proppant flowback occurs from
high velocity fluids, such as treatment fluids, as formation
fluids, such as oil or gas, pass through a multi-layer proppant
pack. The ability of the hollow non-porous metal spheres to deform
allows conventional proppants, under closure stresses in excess of
500 psi, to indent the surface of the hollow non-porous metallic
spheres or composites. Because the concentration of hollow
non-porous metallic spheres (or composites) are considerably less
than the conventional proppant, the probability is high that
multiple proppant grains will indent the surface of the hollow
non-porous metallic spheres simultaneously. This indentation
feature has shown considerable improvement in minimizing proppant
flowback as discussed in U.S. Pat. No. 6,059,034.
EXAMPLES
[0055] The following examples will illustrate the practice of the
present invention in preferred embodiments. Other embodiments
within the scope of the claims herein will be apparent to one
skilled in the art from consideration of the specification and
practice of the invention as disclosed herein. It is intended that
the specification, together with the example, be considered
exemplary only, with the scope and spirit of the invention being
indicated by the claims which follow.
[0056] Strength and stiffness are the basic physical properties
that are measured to evaluate the effectiveness and deformation
characteristics of hollow non-porous metallic spheres. The
following test procedures were used to measure the deformation
versus applied load for single metallic spheres. All the tests were
conducted at 22.degree. C.
[0057] The test cell, as shown in FIG. 1, consisted of a
cylindrical stainless steel base-pedestal and a movable steel
piston. A single particulate of a hollow non-porous metallic sphere
of maraging 200 steel was placed at the center of the pedestal
surface. (Ten different spheres of maraging 200 steel were tested
varying slightly in size and wall thickness.) The piston was placed
over and in contact with the sphere. The hollow cylinder kept the
piston in vertical alignment. The diameter of the pedestal and
piston was one-inch.
[0058] The initial width of the sphere was determined by measuring
the change in height of the movable piston after insertion of the
proppant grain into the cell.
[0059] The test cell was placed in a United Calibration Corporation
SSTM-5 mechanical press. Two linear variable differential
transformers (LVDTs) were placed in parallel with the test cell and
the change in position of the piston was measured as load was
applied. The test was conducted at a constant load rate of 5
lbs/minute and the load (force) and particle displacement was
recorded simultaneously as a function of time. The test was
terminated at predetermined degrees of sphere deformation. The net
displacement of the collapsing sphere was calculated by subtracting
the test apparatus compliance from the gross displacement. (Test
apparatus compliance was measured independently without a sphere in
the cell). The strain in the direction of load was then calculated
by dividing the initial width of the sphere into the net
displacement.
[0060] FIG. 2 is a plot of force versus displacement of the data
obtained and shows where the metallic spheres first began to
deform. The average slope of the load-displacement curve provides a
measure of stiffness of the metallic sphere. In all cases, the
load-displacement curve displayed a positive slope due to the
deformation of the metallic sphere that was in direct contact with
the piston and pedestal. The differences in results are
attributable to the slight variation in size and wall thickness of
the spheres.
[0061] FIG. 3 pictures a collection of metallic spheres at varying
stages of their collapse. The load at the point of deformation is
also shown.
[0062] From the foregoing, it will be observed that numerous
variations and modifications may be effected without departing from
the true spirit and scope of the novel concepts of the
invention.
* * * * *