U.S. patent application number 11/857859 was filed with the patent office on 2008-08-21 for methods and apparatus for fiber-based diversion.
Invention is credited to Curtis L. Boney, Oscar Bustos.
Application Number | 20080196896 11/857859 |
Document ID | / |
Family ID | 39705662 |
Filed Date | 2008-08-21 |
United States Patent
Application |
20080196896 |
Kind Code |
A1 |
Bustos; Oscar ; et
al. |
August 21, 2008 |
Methods and apparatus for fiber-based diversion
Abstract
Methods and apparatus are described for fiber-based fluid
diversion in hydrocarbon-containing wells. One method embodiment of
the invention comprises treating a first zone in a well; conveying
a tool into the well, the tool carrying a composition comprising
fibers; and activating the tool to deploy enough of the composition
to form a fibrous plug and at least partially plug the first zone.
The tool may be a positive displacement bailer, and an apparatus of
the invention comprises a positive displacement bailer; the bailer
comprising a compartment for holding a composition comprising
fibers for forming fiber-based plugs in a well; the compartment
partially defined by and cooperating with a positive displacement
portion to expel and selectively deploy the composition in the well
to form one or more fiber-based plugs in the well.
Inventors: |
Bustos; Oscar; (Castle Rock,
CO) ; Boney; Curtis L.; (Houston, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION;David Cate
IP DEPT., WELL STIMULATION, 110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
39705662 |
Appl. No.: |
11/857859 |
Filed: |
September 19, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60890085 |
Feb 15, 2007 |
|
|
|
Current U.S.
Class: |
166/281 ;
166/285; 166/55.2 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/267 20130101 |
Class at
Publication: |
166/281 ;
166/285; 166/55.2 |
International
Class: |
E21B 43/116 20060101
E21B043/116 |
Claims
1. A method of fluid diversion in a well, comprising: (a) treating
a first zone in a well; (b) conveying a tool into the well, the
tool carrying a composition comprising fibers; and (c) activating
the tool to deploy enough of the composition to form a fibrous plug
and at least partially plug the first zone.
2. The method of claim 1, comprising (d) repeating steps (a)
through (c) for at least one more zone.
3. The method of claim 1, wherein the treating comprises flowing a
stimulation fluid through one or more previously formed
perforations into channels.
4. The method of claim 3 comprising injecting the stimulation fluid
under pressure sufficient to fracture a formation which the well
intersects.
5. The method of claim 1 wherein the conveying a tool into the well
comprises conveying a bailer.
6. The method of claim 5 wherein the bailer is a positive
displacement bailer.
7. The method of claim 5 comprising conveying the bailer on the
distal end of a perforating gun.
8. The method of claim 1 wherein the fibers of the composition are
selected from degradable fibers, non-degradable fibers, fibers
comprising a degradable portion and a non-degradable portion, and
mixtures and combinations thereof.
9. The method of claim 1 wherein the composition comprises
non-fiber particulates.
10. The method of claim 9 wherein the non-fiber particulates are
selected from organic materials, organometallic materials,
inorganic materials, and combinations and mixtures thereof.
11. The method of claim 10 wherein the inorganic materials are
selected from sand, ceramics, salts, and combinations and mixtures
thereof.
12. The method of claim 3 wherein the conveying comprises stopping
the tool adjacent the first zone, the composition comprises fibers
having bridging characteristics, and the method comprises forming a
fiber-based plug in the well adjacent the perforations.
13. A method for performing multi-zone well treatment operations,
comprising: (a) treating a first zone in a well by flowing a
completion or stimulation fluid through one or more previously
formed perforations into channels; (b) conveying a bailer on the
distal end of a perforating gun into the well using a conveying
device selected from slickline, wireline, coiled tubing, and
jointed tubing, the bailer carrying a composition comprising
water-dispersible fibers; (c) stopping the bailer adjacent the
first zone; (d) activating the bailer to deploy enough of the
composition to form a fiber-based plug and at least partially plug
the first zone; and (e) repeating steps (a) through (d) for at
least one more zone.
14. The method of claim 13 wherein the bailer is a positive
displacement bailer.
15. The method of claim 13 wherein the composition comprises fibers
having bridging characteristics and at least two particulates
having different particle sizes, and the method comprises forming a
fiber-based plug in the well adjacent the perforations of the first
zone and said at least one other zone.
16. An apparatus useful for performing multi-zone well treatment
operations, the apparatus comprising: a positive displacement
bailer; the bailer comprising a compartment for holding a
composition comprising fibers for forming fiber-based plugs in a
well; the compartment partially defined by and cooperating with a
positive displacement portion to expel and selectively deploy the
composition in the well to form one or more fiber-based plugs in
the well.
17. The apparatus of claim 16 wherein the positive displacement
bailer is connected to an end of a perforating gun.
18. The apparatus of claim 16 wherein the positive displacement
bailer is attached to and deployable by a wireline.
19. The apparatus of claim 16 wherein the positive displacement
bailer is attached to and deployable by coiled tubing.
20. The apparatus of claim 16 wherein the positive displacement
bailer is attached to a jetting device.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority under 35 U.S.C.
.sctn. 119(e) to U.S. Provisional Application Ser. No. 60/890,085,
filed Feb. 15, 2007, incorporated by reference herein in its
entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of Invention
[0003] The present invention provides efficient methods and
apparatus of fiber-based fluid diversion in hydrocarbon-containing
wells. More specifically, the present invention provides efficient
methods and apparatus to treat multiple zones in
hydrocarbon-containing wells by use of fiber-based diversion.
[0004] 2. Related Art
[0005] A common technique for achieving zonal isolation useful for
treating and/or completing wells having multiple pay zones is
through use of a wireline deployable bridge plug such as is
described in U.S. Pat. No. 6,708,768. The inherent disadvantage of
bridge plugs is that they require setting and drill-out when used
for more than one zone; hence increasing both time and cost of the
operation.
[0006] An example operation is described in the below sequence that
details the steps performed to treat and complete a multi-zone well
using bridge plugs. In the below example, the bridge plug is of the
"flow-thru" type that acts like a check valve providing positive
hydraulic isolation when fluids are injected in a downward
direction, but allows fluid passage therethrough in an upwards
direction when fluids are produced from the formation. The example
operational sequence is as follows: [0007] 1. Run in hole with
wireline guns and perforate the desired intervals; [0008] 2. Run
out of the hole with wire line and spent perforating guns; [0009]
3. Fracture stimulate the perforated intervals; [0010] 4. Flowback
for about 1 hr to ensure minimum amount of proppant is left in the
wellbore; [0011] 5. Run in hole with bridge plug and guns for the
second interval; [0012] 6. Set the bridge plug above the zones
fractured on step 3; [0013] 7. Perforate the layers for the second
fracture stage; [0014] 8. Run out of the hole with spent
perforating guns and wireline; [0015] 9. Fracture stimulate the
perforated intervals; [0016] 10. Repeat 4-9 steps as many times as
necessary.
[0017] Once the last fracture stage is pumped, operations cease for
a few days or even weeks to flowback as much fracturing fluid
injected as possible. After the flowback period, the next step is
to mill out the bridge plugs by using a workover rig or coiled
tubing. Finally production tubing is run in the wellbore and the
well is connected to the flow line to start producing oil and/or
gas.
[0018] There is thus a long-felt but as yet unmet need in the
hydrocarbon production industry for improved methods and apparatus
for treating and/or completing a well having multiple pay
zones.
SUMMARY OF THE INVENTION
[0019] In accordance with the present invention, methods and
apparatus for performing multi-zone well treatment operations are
presented.
[0020] One aspect of the invention are methods for carrying and
selectively deploying fiber-based plugs in wells, one embodiment
comprising: [0021] (a) treating a first zone in a well; [0022] (b)
conveying a tool into the well, the tool carrying a composition
comprising fibers; and [0023] (c) activating the tool to deploy
enough of the composition to form a fibrous plug and at least
partially plug the first zone.
[0024] Methods within the invention comprise (d) repeating steps
(a) through (c) for at least one more zone, and methods wherein the
treating comprises flowing a stimulation fluid through one or more
previously formed perforations into channels. Other methods within
the invention include those comprising injecting the stimulation
fluid under pressure sufficient to fracture a formation which the
well intersects, methods wherein the conveying a tool into the well
comprises conveying a bailer, and methods wherein the bailer is a
positive displacement bailer. In certain embodiments the bailer may
be connected to and deployed on the distal end of a perforating
gun.
[0025] Methods within the invention are particularly adept in
delivery of fiber-based plugs, wherein the fibers of the
composition are selected from degradable fibers, non-degradable
fibers, fibers comprising a degradable portion and a non-degradable
portion, and mixtures and combinations thereof. The fibers may be
organic, inorganic, or combination thereof. The cross-sectional
shape of the fibers may be any cross-section known or conceived.
The fibers may be core-sheath, side-by-side, crimped, uncrimped,
and the like. The fiber length may be staple fibers, longer than
staple fibers, or mixture thereof.
[0026] In certain methods the composition may comprise non-fiber
particulates. Suitable non-fiber particulates may be selected from
organic materials, organometallic materials, inorganic materials,
and combinations and mixtures thereof. Suitable inorganic materials
may be selected from sand, ceramics, salts, and combinations and
mixtures thereof. Suitable organic particulates include polymeric
particulates, such as thermoplastics, thermosets, thermoplastic
elastomers, adhesive particles, and the like. In certain
embodiments the composition may comprise two or more particulates
having different average particle sizes, or simply different sizes,
which tends to increase the bridging characteristic of the
compositions. In certain embodiments, a retainer/basket arrangement
may be used to deposit the fiber-based composition in the well. The
retainer/basket may be comprised of degradable materials as well.
As used herein the term "degradable" means that the material
referred to in the particular case may be dissolved, melted, or
otherwise rendered incapable of supporting pressure or holding
vacuum. "Dissolved" and "dissolvable" mean acid-, base-, and/or
water-soluble. Non-limiting examples of compositions that may be
dissolved by acid include materials selected from magnesium,
aluminum, and the like.
[0027] Other methods of the invention include those wherein the
conveying comprises stopping the tool adjacent the first zone, and
the method comprises forming a fiber-based plug in the well
adjacent the perforations using the composition, the comprising
fibers having bridging characteristics.
[0028] Another aspect of the invention are apparatus useful for
performing multi-zone well treatment operations, one apparatus
comprising: [0029] a positive displacement bailer; [0030] the
bailer comprising a compartment for holding a composition
comprising fibers for forming fiber-based plugs in a well; [0031]
the compartment partially defined by and cooperating with a
positive displacement portion to expel and selectively deploy the
composition in the well to form one or more fiber-based plugs in
the well.
[0032] Apparatus within the invention include those wherein the
positive displacement bailer is connected to an end of a
perforating gun. In other apparatus within the invention the
positive displacement bailer may be connected to a wireline, coiled
tubing, or a jetting device.
[0033] As used in herein, the phrase "composition comprising
fibers" means a Newtonian or non-Newtonian fluid that is able to
flow or be expelled from a compartment of a positive displacement
bailer. A non-limiting list of suitable compositions for use in the
invention may include slurries, gels, liquids, foams, and the like.
An acceptable composition may differ from well to well, depending
on such parameters as the time of the year; geographic location of
the well; depth, pressure, and/or temperature of the zone or zones
to be treated; compositions of the well fluids; customer
requirements; laws and regulations, and the like. In certain
embodiments the fibers are dispersible by water-based completion
fluids and water-based well-stimulation fluids. Additionally, it
should be understood that the term "fiber-based plug" encompasses
all fiber-based plugs and compositions comprising fibers having
bridging characteristics. As will be discussed below, the
fiber-based compositions may additionally comprise materials that
enhance the bridging such as different particle sizes of organic
and/or inorganic materials, for example calcium carbonate, benzoic
acid flakes, sand and ceramic proppants.
[0034] As used herein the terms "treat" and "treating" should be
understood to encompass all known fracture or stimulation
techniques and fluids. "Treating" may include exposing the
formation to organic or inorganic compositions, chemical, physical,
mechanical, and other conditions, or combination thereof, and
either simultaneously or sequentially.
[0035] As used herein the phrase "activating the tool" includes,
but is not limited to activation or actuation using hard-wired
connections, wireless telemetry, fiber-optic cables, explosive
shock, and the like.
[0036] Apparatus and methods of the invention allow the bailer to
be run in hole along with the perforation guns, the ability to
store enough fiber-based diverter composition for plugging multiple
zones, the ability to place multiple fiber-based slugs to cover
previously fracture stimulated layers, and the ability to be
recharged with the fiber-based diverter on location.
[0037] Apparatus and methods of the invention will become more
apparent upon review of the detailed description of the invention
and the claims that follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0038] The manner in which the objectives of the invention and
other desirable characteristics may be obtained is explained in the
following description and attached drawing in which:
[0039] FIG. 1A is a schematic side elevation view, with parts
broken away, illustrating an embodiment of the positive
displacement bailer of the present invention, which may deliver a
fiber-based plug on top of a retaining basket as illustrated in
FIG. 1B;
[0040] FIGS. 2 through 6 illustrate an example operational sequence
in accordance with methods of the present invention; and
[0041] FIG. 7 is a schematic logic diagram illustrating a method of
the invention.
[0042] It is to be noted, however, that the appended drawings are
not to scale and illustrate only typical embodiments of this
invention, and are therefore not to be considered limiting of its
scope, for the invention may admit to other equally effective
embodiments.
DETAILED DESCRIPTION
[0043] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those skilled in the art that the present
invention may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0044] In the specification and appended claims, the terms
"connect", "connection", "connected", "in connection with", and
"connecting" are used to mean "in direct connection with" or "in
connection with via another element"; and the term "set" is used to
mean "one element" or "more than one element". As used herein, the
terms "up" and "down", "upper" and "lower", "upwardly" and
downwardly", "upstream" and "downstream"; "above" and "below"; and
other like terms indicating relative positions above or below a
given point or element are used in this description to more clearly
describe some embodiments of the invention. However, when applied
to equipment and methods for use in wells that are deviated or
horizontal, such terms may refer to a left to right, right to left,
or other relationship as appropriate.
[0045] There are many applications in well drilling, servicing, and
completion in which it becomes necessary to isolate particular
zones within the well. In some applications, such as cased-hole
situations, conventional bridge plugs such as the Baker Hughes
model T, N1, NC1, P1, or S wireline-set bridge plugs are inserted
into the well to isolate zones. The bridge plugs may be temporary
or permanent; the purpose of the plugs is simply to isolate some
portion of the well from another portion of the well. In some
instances perforations in the well in one portion need to be
isolated from perforations in another portion of the well. In other
situations there may be a need to use a bridge plug to isolate the
bottom of the well from the wellhead. There are also situations
where these plugs are not used necessarily for isolation but
instead are used to create a cement plug in the wellbore which may
be used for permanent abandonment. In other applications a bridge
plug with cement on top of it may be used as a kickoff plug for
side-tracking the well. Bridge plugs may be drillable or
retrievable. Brillable bridge plugs must be drilled out, and
therefore are constructed of a brittle metal such as cast iron that
can be drilled out. However, as rig time is typically charged for
by the hour, it would be highly advantageous to avoid any drilling
of bridge plugs.
[0046] The methods and apparatus of the invention are useful to
efficiently treat multiple zones in oil or gas wells by using a
fiber-based plug that is precisely positioned using a positive
displacement bailer. In one embodiment, the positive displacement
bailer is attached to the end of a perforating gun. An advantage of
the inventive apparatus is the elimination of the need for hardware
plugs, such as bridge plugs, to achieve zonal isolation for
effective treatment. Removing the necessity of the hardware plugs
reduces both time and cost of completion by eliminating the setting
and drill out of bridge plugs.
[0047] The fiber-based plugs of the present invention comprise one
or more fiber-based materials that may be used by themselves or in
combination with particulates; in certain embodiments the
particulates may comprise two or more particulates having different
average particle sizes, or simply of different sizes. The
particulates need not be any particular shape, and may be random or
non-randomly shaped. The particulates may be round, ovoid, cubed,
pellet-shaped, coated, non-coated, porous, non-porous, and the
like. The plugs may be designed with one or more particulates and
the composition of those particulates may be selected from
inorganic materials, such as sand, ceramics, and salts, and organic
materials such as benzoic acid flakes, thermoplastic polymers,
thermoset polymers, elastomeric polymers, and the like, and
polymers having a combination of these properties, such as
thermoplastic elastomers. In certain embodiments, degradable
materials may be used to minimize formation damage. Degradable
materials include degradable fibers, thermoplastics and solid
acids. As used herein the terms "polymer" and "polymeric" include
thermoplastic, elastomeric, and, under certain conditions,
thermosetting resins. The term includes polymers, oligomers,
co-polymers, and the like, which may or may not be cross-linked.
Polymers may be carbon chain polymers, heterochain polymers,
combinations (co-polymers) thereof, and physical mixtures thereof.
If two or more polymers are present, they may be physically mixed,
and may be cross-linked via covalent bonds, ionic bonds, or both
covalent and ionic bonds. The polymers may exist as a matrix for a
curing agent or other active chemical specie, as a matrix for
relatively inert ingredients, such as fillers, or both.
[0048] Referring now to the figures, where the same numerals are
used throughout to indicate like components unless otherwise
indicated, FIG. 1A illustrates one embodiment of a positive
displacement bailer of the present invention, indicated generally
by numeral 10. Bailer 10 in this embodiment is a positive
displacement bailer, and has as its main components a bailer body
12 and a piston 14. Bailer body 12 defines two internal
compartments 16 and 18 in this embodiment. Compartment 16 may hold
a hydraulic fluid or some other working fluid, while compartment 18
is designed to hold composition which is deposited through one or
more ports 20, 22, to form a fiber-based plug in accordance with
the invention. Fiber-based plugs of the invention may be precisely
positioned near perforations in casing 8 (as illustrated in FIGS.
2-6). Bailer 10 may also include threaded connection 24 for
attaching a perforating tool (not illustrated in FIG. 1A), and a
wire-line 26. In certain embodiments it may be useful to employ a
retainer and basket arrangement as illustrated in FIG. 1B for
supporting the deployed fiber-based plug. Basket 6 may be run in
hole using the wireline 26. As illustrated, basket 6 seals against
the inside of casing 8 at points 7 and 9 (multiple seal points may
be present). Composition from bailer ports 20, 22 may be delivered
into the basket and allowed to build up to a height determined by
the particular situation. The use of a basket is optional and
depends on the setting ability of the composition used to form the
fiber-based plugs. If, for example, the composition is formulated
to have a specific gravity close to or slight less than fluid in
the well, it may be possible to "float" the composition in the well
fluid and build up a mass of fibers, optionally with particulates,
that bridges the well bore. Further discussion of this point may be
seen herein below.
[0049] The positive displacement bailer 10 may be run along with
the perforation guns, and chamber 18 may be sized so that it can
store enough of the fiber-based material to place multiple
fiber-based slugs to plug previously fractured zones. Piston 14 of
positive displacement bailer 10 can be displaced multiple times to
accommodate the multiple zone placement of the slugs. In addition,
the positive displacement bailer 10 may be pre-loaded with the
fiber-based material on location.
[0050] FIGS. 2 through 6 illustrate an example operational sequence
in accordance with methods of the present invention. As illustrated
in FIG. 2, during a first stage, multiple zones are perforated and
treated, with perforations illustrated at 32 previously having been
formed by a perforating gun 28 having a plurality of perforating
charges 29, which may be selectively fired by an operator. The
extent of the treatment fluid entry into the reservoir is
illustrated schematically as plumes 30a, 30b, 30c, and so on.
Fiber-based material plugs 31, 31a, 31b, 31c, 31d, and so on are
spotted using the positive displacement bailer 10 to temporarily
plug the treated zones. The length L of a first stage may range
from about 50 to 200 ft, or from 100 to 200 ft, or from 125 ft to
175 ft, or in some embodiments may range from 140 ft to 160 ft, or
from 148 ft to 152 ft. FIGS. 2, 3, 4, and 5 illustrate one, two,
three, and four fiber-based plugs, respectively, spotted in casing
28 adjacent perforations 32. Once all of the zones of the first
stage L have been plugged, the process is repeated for a second
treating stage. The perforating gun 28 may then be removed, as
illustrated in FIG. 6. It should be noted that in the embodiment
illustrated in FIGS. 2 through 6 it may not always be necessary for
the perforating gun string to be removed from the hole unless it is
necessary for the positive displacement bailer to be recharged with
more fiber-based material. For example, the perforating gun string
may comprise multiple guns adapted to selectively fire when located
in specific zones; thus removing the necessity to pull out of hole
between each zone or stage.
[0051] An operational sequence of one method of the present
invention is illustrated schematically as a logic diagram in FIG.
7. A first step is to run in hole with wireline the perforating
guns and perforate the desired intervals; then run out of the hole
with wireline; fracture stimulate the perforated intervals;
flowback for about 1 hr to ensure minimum amount of proppant is
left in the well bore; run in hole with the wire line deployable,
positive displacement bailer and guns for the second interval;
place a fiber-based plug in front of or above each previously
fracture stimulated interval; perforate the layers for the second
fracture stage; run out of the hole with wireline; and fracture
stimulate the perforated intervals. The fiber-based plug will
bridge in front of the perforations, preventing any re-fracture.
The steps may be repeated as many times as necessary, or until
there is no more composition in the bailer. Once last fracture
stage is pumped, the well may be connected for clean up for few
days or even weeks to flowback as much fracturing fluid injected as
possible. A wellbore cleanout may then be conducted by either
workover rig or coiled tubing using a jetting device. Finally
production tubing is run in the wellbore.
[0052] Regarding the perforation operation, shaped charge
perforating is commonly used, in which shaped charges are mounted
in perforating guns that are conveyed into the well on a slickline,
wireline, tubing, or another type of carrier. The perforating guns
are then fired to create openings in the casing and to extend
perforations as penetrations into the formation. In some cases
wells may include a pre-pack comprising an oxidizer composition,
and perforation may proceed through the pre-pack. These techniques
may be used separately or in conjunction with shaped charges that
include an oxidizer in the charge itself. Any type of perforating
gun may be used. A first type, as an example, is a strip gun that
includes a strip carrier on which capsule shaped charges may be
mounted. The capsule shaped charges are contained in sealed
capsules to protect the shaped charges from the well environment.
Another type of gun is a sealed hollow carrier gun, which includes
a hollow carrier in which non-capsule shaped charges may be
mounted. The shaped charges may be mounted on a loading tube or a
strip inside the hollow carrier. Thinned areas (referred to as
recesses) may be formed in the wall of the hollow carrier housing
to allow easier penetration by perforating jets from fired shaped
charges. Another type of gun is a sealed hollow carrier
shot-by-shot gun, which includes a plurality of hollow carrier gun
segments in each of which one non-capsule shaped charge may be
mounted.
[0053] Other downhole perforating mechanisms are described
generally in U.S. Pat. No. 6,543,538. Alternative perforating
devices include water and/or abrasive jet perforating, chemical
dissolution, and laser perforating for the purpose of creating a
flow path between the wellbore and the surrounding formation. Each
individual gun may be on the order of 2 to 8 feet in length, and
contain on the order of 8 to 20 perforating charges placed along
the gun tube; as many as 15 to 20 individual guns could be stacked
one on top of another such that the assembled gun system total
length may be approximately 80 to 100 feet. This total gun length
may be deployed in the wellbore using a surface crane and
lubricator systems. Longer gun lengths could also be used, but
would generally require additional or special equipment. The
perforating device may be conveyed downhole by various means, such
as electric line, wireline, slickline, conventional tubing, coiled
tubing, and casing conveyed systems. The perforating device can
remain in the hole after perforating the first zone and then be
positioned to the next zone before, during, or after treatment of
the first zone. There are numerous other patents describing
perforating requiring either a mechanical device (such as a sliding
sleeve), pumping fluid though a jetting device, perforating guns,
or other downhole devices.
[0054] Alternatively, the well or portions thereof may be cased
using pre-perforated casing and casing sections as described in
assignee's co-pending U.S. patent application Ser. No. 11/769,284,
filed Jun. 27, 2007, incorporated herein by reference, which
describes providing a plurality of casing sections and a plurality
of casing joints for joining the casing sections, the casing joints
having a plurality of flow-through passages therethrough
temporarily plugged with a composition, the composition
independently selected for each casing joint; (b) forming a casing
string comprising the casing sections and casing joints and running
the casing string in hole; (c) exposing a first casing joint of the
casing string to conditions sufficient to displace the composition
from the flow-through passages in the first casing joint; (d)
pumping a stimulation treatment fluid into a formation through the
flow-through passages in the first casing joint; (e) plugging the
flow-through passages in the first casing section; and (f) exposing
a second casing joint of the casing string to conditions sufficient
to displace the composition from the flow-through passages in the
second casing joint. The flow-through passages may be formed by any
known techniques, such as cutting, sawing, drilling, filing, and
the like. The process of forming the flow-through passages may be
manual, automated, or combination thereof. The dimensions and
shapes of the flow-through passages may be any number of sizes and
shapes, such as circular, oval, rectangular, rectangular with half
circles on each end, slots, including slots angled to the
longitudinal axis of the casing, and the like. The flow-through
passages may surround the casing or casing joint in 60 degree (or
other angle) phasing. The phasing may be 5, 10, 20, 30, 60, 75, 90,
120 degree phasing. In certain embodiments it may be desired to
maximize the Area Open to Flow (AOF), in which case rectangular
flow-through passages may be the best choice; however, these shapes
may be more difficult to manufacture, and may present problems with
mechanical strength of the pup joint. Circular flow-through
passages would be easiest to make, but these sacrifice AOF due to
the casing curvature. Slots and notches may be used in certain
embodiments and allow covering the "weep hole" formed by pulsation
of tubing while sand jetting. The slots in the casing, if used,
could also be at an angle to the casing (not longitudinal with it).
In certain embodiments, from 4 to 6 angled slots at the same depth
around the casing may be used. In this way we would be more likely
to get an opening in the casing that would align with the frac
plane. Regarding the composition to temporarily fill the
flow-through passages prior to treatment of the well, these may be
inorganic materials, organic materials, mixtures of organic and
inorganic, and the like. As used herein the term "filling" the
flow-through passages may include a soluble "patch" over the
flow-through passages (on inside or outside surface of the pipe).
Non-limiting examples of compositions that may be dissolved by acid
include materials selected from magnesium, aluminum, and the like.
Reactive metals, earth metals, composites, ceramics, and the like
may also be used. The composition should be able to hold pressure
up to an absolute pressure of about 6,000 psi [41 megapascals], in
certain embodiments up to about 7,000 psi [48 megapascals], in
other embodiments up to about 8,000 psi [55 megapascals], in
certain embodiments up to about 9,000 psi [62 megapascals], and in
certain embodiments up to about 10,000 psi [68 megapascals].
[0055] Suitable degradable materials may be organic, inorganic, or
combinations (mixtures) thereof. Examples of usable degradable
organic materials are those that comprise aqueous phase-soluble
polymers, for example polylactic acid, polyglycolic acid or
copolymers thereof that are soluble in the aqueous phases in the
subterranean environment. Other suitable degradable organic
materials are oil-phase soluble materials, such as polystyrene and
homologs thereof, derivatives of polystyrene and homologs thereof,
and some low molecular weight polyolefin fibers and co-polymers
thereof. Degradable organic materials useful in the invention may
comprise physical mixtures of two or more aqueous-phase soluble
polymers, two or more oil-phase soluble polymers, and mixtures of
one or more aqueous-phase soluble polymers and one or more
oil-phase soluble polymers.
[0056] Other suitable degradable organic materials include
materials such as degradable simple carbohydrates such as sugars,
also called saccharides, such as mono-, di-, and trisaccharides.
Oligosaccharides are saccharides comprising up to eight units.
Polysaccharides are polymeric saccharides having greater than eight
subunits; natural polysaccharides generally comprise 10-3000
subunits. Examples of suitable monosaccharides include sucrose,
fructose, ribulose, mannose, galactose, and glucose. Suitable
disaccharides include those wherein the saccharide units are the
same or different. An example of a disaccharide in which the
subunits are the same is maltose, while lactose is an example of a
disaccharide in which the two monosaccharide units are different.
The saccharides may be in the pyranose form, the furanose form, or
both.
[0057] If the additive comprises a saccharide, there are many
options for first and second states; indeed, there may be many
intermediate states. The easiest transition from a first state to a
second state to visualize is the transition from a solid to a
liquid. For example, the first state of the saccharide additive may
be a solid, and the second state of the additive may be a dissolved
version of the saccharide in water, as saccharides are extremely
water-soluble due to their polyhydroxy nature. They tend to form
viscous syrups that crystallize poorly. If the saccharide is a
polysaccharide, it may be possible to controllably, gradually
hydrolyze the molecules to oligo- and/or monosaccharides; for
example the first state may be a polysaccharide having 20 subunits,
and the second state may be an oligosaccharide having 8 or less
subunits. Another second state may be one of the many chemical
derivatives of saccharides, such as ethers, cyclic acetals, ketals,
esters, alditols, aldonic acids, saccharic acids, dialdehydes,
phyneylhydrazones, osazones, and the like, all of which may be
formed from saccharides using well-known published techniques. For
example, ethers may be formed from saccharides under mildly acidic
conditions. In these reactions the OH group at the anomeric carbon
is replaced by an alkoxy group. Cyclic acetals and ketals may be
formed by reacting the saccharide 1,2-diols with an aldehyde or
ketone under mildly acidic conditions. Esters (acetates) may be
formed by reacting one or more of the saccharide OH groups with
acetic anhydride and a mild basic catalyst such as sodium acetate
or pyridine. Alditols such as D-mannitol may be produced by the
sodium borohydride reduction of D-mannose. Aldonic and saccharic
acids may be produced by oxidizing the saccharide employing bromine
in a buffered solution at pH ranging from 5-6. Aqueous nitric acid
may be used as a more vigorous oxidizing agent to form polyhydroxy
dicarboxylic acids (called saccharic acids). Periodic acid
(HIO.sub.4) may be used to cleave saccharides to dialdehydes. These
and other reactions of saccharides are discussed in standard
textbooks, such as Streitwieser, Jr., et al., "Introduction to
Organic Chemistry", pp. 704-718 (1976), incorporated herein by
reference.
[0058] Yet other suitable organic degradable additive embodiments
are organic compounds, or mixtures thereof, that sublime at
temperatures ranging from about 0.degree. C. and higher in the
presence of hydrocarbon gas streams. Example of these include
camphor, naphthalene, benzaldehyde, mixtures thereof, and the
like.
[0059] Salts of any of the above organic degradable additives may
also be used.
[0060] Suitable inorganic degradable materials for use as additives
in the invention are inorganic salts, for example sodium chloride,
potassium chloride, ammonium carbonate, ammonium perchlorate,
mixtures thereof, and the like.
[0061] Suitable degradable materials (fibers, particulates, casing
flow-through passage filling, or any of these) include acid-,
basic-, and/or water-soluble polymers, with or without inclusion of
relatively insoluble materials, such as water-insoluble polymers,
ceramics, fillers, and combinations thereof. Aluminum and magnesium
bolts or plugs are one example of acid-soluble inorganic materials
that may be used for casing flow-though passage filler.
Compositions useful in the invention may comprise a water-soluble
inorganic material, a water-soluble organic material, and
combinations thereof. The water-soluble organic material may
comprise a water-soluble polymeric material, for example, but not
limited to poly(vinyl alcohol), poly(lactic acid), and the like.
The water-soluble polymeric material may either be a normally
water-insoluble polymer that is made soluble by hydrolysis of side
chains, or the main polymeric chain may be hydrolysable.
[0062] The fiber-based plugs and casing flow-through passage
fillers function to dissolve when exposed in a user controlled
fashion to one or more activators. In this way, zones in a
wellbore, or the wellbore itself or branches of the wellbore, may
be treated for periods of time uniquely defined by the user.
Suitable activators include chemicals, heat, light, pressure or
some other activator or combination of activators useful in a
variety of well treatment operations.
[0063] If the activator is a fluid composition, suitable fibers,
particulates, and casing fillers useful in the invention include
water-soluble materials selected from water-soluble inorganic
materials, water-soluble organic materials, and combinations
thereof. Suitable water-soluble organic materials may be
water-soluble natural or synthetic polymers or gels. The
water-soluble polymer may be derived from a water-insoluble polymer
made soluble by main chain hydrolysis, side chain hydrolysis, or
combination thereof, when exposed to a weakly acidic environment.
Furthermore, the term "water-soluble" may have a pH characteristic,
depending upon the particular polymer used.
[0064] Suitable water-insoluble polymers which may be made
water-soluble by acid hydrolysis of side chains include those
selected from polyacrylates, polyacetates, and the like and
combinations thereof.
[0065] Suitable water-soluble polymers or gels include those
selected from polyvinyls, polyacrylics, polyhydroxyacids, and the
like, and combinations thereof.
[0066] Suitable polyvinyls include polyvinyl alcohol, polyvinyl
butyral, polyvinyl formal, and the like, and combinations thereof.
Polyvinyl alcohol is available from Celanese Chemicals, Dallas,
Tex., under the trade designation Celvol. Individual Celvol
polyvinyl alcohol grades vary in molecular weight and degree of
hydrolysis. Molecular weight is generally expressed in terms of
solution viscosity. The viscosities are classified as ultra low,
low, medium and high, while degree of hydrolysis is commonly
denoted as super, fully, intermediate and partially hydrolyzed. A
wide range of standard grades is available, as well as several
specialty grades, including polyvinyl alcohol for emulsion
polymerization, fine particle size and tackified grades. Celvol
805, 823 and 840 polyvinyl alcohols are improved versions of
standard polymerization grades--Celvol 205, 523 and 540 polyvinyl
alcohols, respectively. These products offer a number of advantages
in emulsion polymerization applications including improved water
solubility and lower foaming. Polyvinyl butyral is available from
Solutia Inc., St. Louis, Mo., under the trade designation BUTVAR.
One form is Butvar Dispersion BR resin, which is a stable
dispersion of plasticized polyvinyl butyral in water. The
plasticizer level is at 40 parts per 100 parts of resin. The
dispersion is maintained by keeping pH above 8.0, and may be
coagulated by dropping the pH below this value. Exposing the
coagulated version to pH above 8.0 would allow the composition to
disperse, thus affording a control mechanism.
[0067] Suitable polyacrylics include polyacrylamides and the like
and combinations thereof, such as N,N-disubstituted
polyacrylamides, and N,N-disubstituted polymethacrylamides. A
detailed description of physico-chemical properties of some of
these polymers are given in, "Water-Soluble Synthetic Polymers:
Properties and Behavior", Philip Molyneux, Vol. I, CRC Press,
(1983) incorporated herein by reference.
[0068] Suitable polyhydroxyacids may be selected from polyacrylic
acid, polyalkylacrylic acids, interpolymers of acrylamide/acrylic
acid/methacrylic acid, combinations thereof, and the like.
[0069] So-called "multicomponent" fibers may also be used in
forming fiber-based plugs. By "multicomponent" fibers we mean
fibers that have two or more distinct phases, regions, or chemical
compositions; in other words, two or more regions that are distinct
either physically, chemically, or both physically and chemically.
Because multicomponent fibers have at least two distinct regions
they may be engineered to have multiple beneficial properties, and
these properties can be tuned to a greater extent than that of a
single component material fiber. As one of many examples, the
material in the inner core of a core-sheath fiber can be selected
for strength, flexibility and robustness, while the outer layer can
be selected for its adhesive qualities. As one of many examples, in
the case of multicomponent fibers, the material in the inner core
of a core-sheath fiber may be selected for strength, flexibility
and robustness, while the outer layer may be selected for its
adhesive qualities. As another example, a side-by-side bicomponent
fiber may have one component selected for strength, flexibility and
robustness, while the other component may be selected for its
adhesive qualities. Other suitable multicomponent articles include
those wherein the least robust material is enclosed in a more
robust sheath; those wherein polymers such as PLA and polyglycolic
acid is enclosed in a sheath comprised of polyester, polyamide,
and/or polyolefin thermoplastic; those wherein a sensitive
adhesive, for example a pressure-sensitive adhesive,
temperature-sensitive adhesive, or moisture-sensitive adhesive, or
curable adhesive is enclosed in a degradable sheath, such as a
polymer sheath; and those wherein one of the components is selected
to be tacky at a specific downhole temperature, such as the
bottomhole static temperature (BHST), and have a modulus of less
than 3.times.10.sup.6 dynes/cm.sup.2 at a frequency of about 1 Hz,
the tacky component and is embedded in a degradable polymer
sheath.
[0070] Certain fluid compositions useful in forming fiber-based
plugs of the invention may comprise proppant. Methods within this
aspect of the invention include those wherein proppant is combined
with the fluid composition prior to and/or during injecting the
fluid composition into the wellbore. Other methods within the
invention include those wherein the injecting comprises pumping the
fluid composition into the wellbore under pressure, either with or
without a proppant in the fluid composition.
[0071] When desired, proppant may be pumped into the formation,
either combined with the compositions of the invention, or combined
in situ. As has been indicated above, the function of a proppant is
to "prop" the walls adjacent a fracture in a subterranean formation
apart so that the fracture is not closed by the forces which are
extent in the formation. It is advantageous for the walls adjacent
the fracture to be "propped" apart so that the formation can be
worked, usually to remove oil or natural gas. In general the fluid
compositions, multicomponent articles therein, methods, and
networks of the invention perform well with any known proppant, but
may be particularly effective when using the least expensive
proppant, siliceous sand. At greater stresses, it is believed, the
sand particles are disintegrated, forming fines which then may plug
the formation, reducing its permeability and resulting in costly
well cleanouts, or even abandoning the well. This is discussed in
U.S. Pat. No. 3,929,191, the disclosure of which is incorporated
herein by reference. Sintered bauxite has also been used as a
proppant, and may be preferable to siliceous sand because of its
ability to withstand higher stresses without disintegration.
However, sintered bauxite can be less desirable than siliceous sand
as a proppant because it is substantially more expensive and is
less generally available. The use of sintered bauxite as a proppant
is disclosed in U.S. Pat. No. 4,068,718, the disclosure of which is
incorporated herein by reference.
[0072] Other suitable proppants are described in U.S. Pat. Nos.
6,406,789; 6,582,819; and 6,632,527, the disclosures of which are
incorporated herein by reference. As the '789 patent explains,
three different types of propping materials, i.e., proppants, are
currently employed. The first type of proppant is a sintered
ceramic granulation/particle, usually aluminum oxide, silica, or
bauxite, often with clay-like binders or with incorporated hard
substances such as silicon carbide (e.g., U.S. Pat. No. 4,977,116
to Rumpf et al, incorporated herein by reference, EP Patents 0 087
852, 0 102 761, or 0 207 668). The ceramic particles have the
disadvantage that the sintering must be done at high temperatures,
resulting in high energy costs. The second type of proppant is made
up of a large group of known propping materials from natural,
relatively coarse, sands, the particles of which are roughly
spherical, such that they can allow significant flow (English "frac
sand") (see U.S. Pat. No. 5,188,175 for the state of the
technology). The third type of proppant includes samples of type
one and two that may be coated with a layer of synthetic resin
(U.S. Pat. No. 5,420,174 to Deprawshad et al; U.S. Pat. No.
5,218,038 to Johnson et al and U.S. Pat. No. 5,639,806 to Johnson
et al (the disclosures of U.S. Pat. Nos. 5,420,174, 5,218,038 and
5,639,806, incorporated herein by reference); EP Patent No. 0 542
397). As discussed herein, in some hydraulic fracturing
circumstances, the precured proppants in the well would flow back
from the fracture, especially during clean up or production in oil
and gas wells. Some of the proppant can be transported out of the
fractured zones and into the well bore by fluids produced from the
well. This transportation is known as flow back. Flowing back of
proppant from the fracture is undesirable and has been controlled
to an extent in some instances by the use of a proppant coated with
a curable resin which will consolidate and cure underground.
Phenolic resin coated proppants have been commercially available
for some time and used for this purpose. Thus, resin-coated curable
proppants may be employed to "cap" the fractures to prevent such
flow back. The resin coating of the curable proppants is not
significantly crosslinked or cured before injection into the oil or
gas well. Rather, the coating is designed to crosslink under the
stress and temperature conditions existing in the well formation.
This causes the proppant particles to bond together forming a
3-dimensional matrix and preventing proppant flow back. These
curable phenolic resin coated proppants work best in environments
where temperatures are sufficiently high to consolidate and cure
the phenolic resins. However, conditions of geological formations
vary greatly. In some gas/oil wells, high temperature
(>180.degree. F. (82.degree. C.) and high pressure (>6,000
psi (41 MPa)) are present downhole. Under these conditions, most
curable proppants can be effectively cured. Moreover, proppants
used in these wells need to be thermally and physically stable,
i.e., do not crush appreciably at these temperatures and pressures.
Curable resins include (i) resins which are cured entirely in the
subterranean formation and (ii) resins which are partially cured
prior to injection into the subterranean formation with the
remainder of curing occurring in the subterranean formation. Many
shallow wells often have downhole temperatures less than
130.degree. F. (54.degree. C.), or even less than 100.degree. F.
(38.degree. C.).
[0073] Due to the diverse variations in geological characteristics
of different oil and gas wells, no single proppant possesses all
properties which can satisfy all operating requirements under
various conditions. The choice of whether to use a precured or
curable proppant or both is a matter of experience and knowledge as
would be known to one skilled in the art. In use, the proppant is
suspended in the fracturing fluid. Thus, interactions of the
proppant and the fluid will greatly affect the stability of the
fluid in which the proppant is suspended. The fluid needs to remain
viscous and capable of carrying the proppant to the fracture and
depositing the proppant at the proper locations for use. However,
if the fluid prematurely loses its capacity to carry, the proppant
may be deposited at inappropriate locations in the fracture or the
well bore. This may require extensive well bore cleanup and removal
of the mispositioned proppant. It is also important that the fluid
breaks (undergoes a reduction in viscosity) at the appropriate time
after the proper placement of the proppant. After the proppant is
placed in the fracture, the fluid shall become less viscous due to
the action of breakers (viscosity reducing agents) present in the
fluid. This permits the loose and curable proppant particles to
come together, allowing intimate contact of the particles to result
in a solid proppant pack after curing. Failure to have such contact
will give a much weaker proppant pack. Foam, rather than viscous
fluid, may be employed to carry the proppant to the fracture and
deposit the proppant at the proper locations for use. The foam is a
stable foam that can suspend the proppant until it is placed into
the fracture, at which time the foam breaks. Agents other than foam
or viscous fluid may be employed to carry proppant into a fracture
where appropriate. Also, resin coated particulate material, e.g.,
sands, may be used in a wellbore for "sand control." In this use, a
cylindrical structure is filled with the proppants, e.g., resin
coated particulate material, and inserted into the wellbore to act
as a filter or screen to control or eliminate backwards flow of
sand, other proppants, or subterranean formation particles.
Typically, the cylindrical structure is an annular structure having
inner and outer walls made of mesh. The screen opening size of the
mesh being sufficient to contain the resin coated particulate
material within the cylindrical structure and let fluids in the
formation pass therethrough.
[0074] In certain embodiments, the particulates employed may have a
unimodal size distribution; in other embodiments a multimodal size
distribution, such as bimodal, trimodal, and higher modalities. In
other embodiments, the particulates may be polymeric, and may be
designed to hold their shape up to a desired temperature, above
which the particles deform. For example, a plurality of
microspheres may deform to form a substantially continuous coating
over fibers. Other polymeric microspheres may comprise one or more
hydrocarbons, such as a relatively low molecular weight normal,
branched, or cyclic alkanes, alkenes, alkynes, and the like, as
well as aromatic compounds such as toluene, xylene, styrene,
divinylbenzene, and the like. Some of these, such as styrene and
divinylbenzene, may react to form an oligomer within the polymeric
microsphere. Microspheres may have more than one of these features
in a single microsphere; for example, a single microsphere may be
both acid functionalized, have a degree of elasticity, and be
bimodal in size distribution. Furthermore, in any single proppant
particle, the microspheres may be substantially identical, or they
vary widely in composition and properties.
[0075] Fluid compositions useful in methods of the invention may be
used with and/or employ any of a number of well treatments or well
completions. As used herein the terms "well completion" and
"completion" are used as nouns except when referring to a
completion operation. Well completions within the invention
include, but are nor limited to, casing completions, commingled
completions, hydraulic fracturing, coiled tubing completions, dual
completions, high temperature completions, high pressure
completions, high temperature/high pressure completions, multiple
completions, natural completions, artificial lift completions,
partial completions, primary completions, tubingless completions,
and the like.
[0076] When a fluid having, a specific, controlled pH and
temperature is pumped into the well, the fiber-based plugs will be
exposed to the fluid and begin to degrade, depending on the
composition and the fluid chosen. The degradation may be controlled
in time to degrade quickly, for example over a few seconds or
minutes, or over longer periods of time, such as hours or days. For
example, a composition useful in the invention comprising fibers
that dissolve at a temperature above reservoir temperature may be
used to form a fiber-based plug, and subsequently exposed to a
fluid pumped from the surface having a temperature above the
reservoir temperature. The reverse may be desirable in other well
treatment operations. The fiber-based plug may then be allowed to
warm up to the pumped fluid temperature at the layer where
treatment is taking place, allowing degradation of the fiber-based
plug.
[0077] As noted previously, ingredients may be added to the
composition dispensed from the positive displacement baler to
facilitate the fiber-based plugs in bridging, such as expandable
inorganic or organic materials. Examples of expandable materials
are intumescent materials, where "intumescent" refers to a material
which expands upon heating above about 100.degree. C., although the
temperature at which a particular intumescent material intumesces
is dependent on the composition of that material. One useful
intumescent material comprises a non-aqueous, indefinitely
conformable, halogen-free, intumescent putty comprising a blend of
intumescent material, rubber, and unvulcanized rubber, the rubber
and unvulcanized rubber together provide the putty with a softness
value of at least 4 mm (preferably, at least 4.5 mm; more
preferably at least 5 mm; and even more preferably, at least 6 mm).
Further, the putty is essentially free (i.e., contains less than
0.25 percent by weight) of a rubber curing agent. These putties are
described in U.S. Pat. No. 5,578,671, assigned to Minnesota Mining
and Manufacturing Company, St. Paul, Minn., incorporated herein by
reference. In these intumescent compositions the rubber may be
selected from natural rubber, butyl rubbers, polybutadiene rubbers,
synthetic isoprene rubbers, styrene butadiene rubbers, ethylene
acrylic rubbers, nitrile rubbers, urethane rubbers, ethylene vinyl
acetate rubbers, and combinations thereof, and the unvulcanized
rubber may be selected from unvulcanized natural rubber,
unvulcanized butyl rubbers, unvulcanized polybutadiene rubbers,
unvulcanized synthetic isoprene rubbers, unvulcanized styrene
butadiene rubbers, unvulcanized ethylene acrylic rubbers,
unvulcanized nitrile rubbers, unvulcanized urethane rubbers,
unvulcanized ethylene vinyl acetate rubbers, and combinations
thereof. Other intumescent compositions are described in U.S. Pat.
Nos. 4,273,879; 4,952,615; and 5,175,197.
[0078] The term "reservoir" may include hydrocarbon deposits
accessible by one or more wellbores. A "well" or "wellbore"
includes cased, cased and cemented, or open-hole wellbores, and may
be any type of well, including, but not limited to, a producing
well, an experimental well, an exploratory well, and the like.
Wellbores may be vertical, horizontal, any angle between vertical
and horizontal, diverted or non-diverted, and combinations thereof,
for example a vertical well with a non-vertical component.
[0079] As will be readily apparent to those skilled in the art, the
present invention may easily be produced in other specific forms
without departing from its spirit or essential characteristics. The
present embodiments are, therefore, to be considered as merely
illustrative and not restrictive, the scope of the invention being
indicated by the claims rather than the foregoing description, and
all changes which come within the meaning and range of equivalence
of the claims are therefore intended to be embraced therein.
Although only a few exemplary embodiments of this invention have
been described in detail above, those skilled in the art will
readily appreciate that many modifications are possible in the
exemplary embodiments without materially departing from the novel
teachings and advantages of this invention. Accordingly, all such
modifications are intended to be included within the scope of this
invention as defined in the following claims. Although the above
described examples of the present invention are directed toward
wire line methods and apparatus, one skilled in the art will
recognize that the present invention has equal applicability to
coiled tubing or slickline operations. For example, the positive
displacement bailer of the present invention could be attached to a
jetting head deployed on coiled tubing and used in a multi-zone
stimulation operation where either the zones have already been
perforated or the jetting head is used to perform jet perforating
operations.
* * * * *