Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR STIMULATION OF MULTIPLE
FORMATION INTERVALS
FIELD OF THE INVENTION
This invention relates generally to the field of perforating and treating
subterranean formations to increase the production of oil and gas therefrom.
More
specifically, the invention provides an apparatus and a method for perforating
and
treating multiple intervals without the necessity of removing equipment from
the
wellbore between steps or stages.
BACKGROUND OF THE INVENTION
When a hydrocarbon-bearing, subterranean reservoir formation does not have
enough permeability or flow capacity for the hydrocarbons to flow to the
surface in
economic quantities or at optimum rates, hydraulic fracturing or chemical
(usually acid) stimulation is often used to increase the flow capacity. A
wellbore
penetrating a subterranean formation typically consists of a metal pipe
(casing)
cemented into the original drill hole. Holes (perforations) are placed to
penetrate
through the casing and the cement sheath surrounding the casing to allow
hydrocarbon
flow into the wellbore and, if necessary, to allow treatment fluids to flow
from the
wellbore into the formation.
Hydraulic fracturing consists of injecting fluids (usually viscous shear
thinning, non-Newtonian gels or emulsions) into a fomiation at such high
pressures
and rates that the reservoir rock fails and forms a plane, typically vertical,
fracture
(or fracture network) much like the fracture that extends through a wooden log
as a
wedge is driven into it. Granular proppant material, such as sand, cerainic
beads, or
other materials, is generally injected with the later portion of the
fracturing fluid to
hold the fracture(s) open after the pressure is released. Increased flow
capacity from
the reservoir results from the easier flow path left between grains of the
proppant
material within the fracture(s). In cheinical stimulation treatments, flow
capacity is
improved by dissolving materials in the formation or otherwise changing
formation
properties.
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Application of hydraulic fracturing as described above is a routine part of
petroleum industry operations as applied to individual target zones of up to
about 60
meters (200 feet) of gross, vertical thickness of subterranean formation. When
there
are multiple or layered reservoirs to be hydraulically fractured, or a very
thick
hydrocarbon-bearing formation (over about 60 meters), then alternate treatment
techniques are required to obtain treatment of the entire target zone. The
methods for
improving treatment coverage are commonly known as "diversion" methods in
petroleum industry terminology.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic
fracturing or chemical stimulation treatments, economic and technical gains
are
realized by injecting multiple treatment stages that can be diverted (or
separated) by
various means, including mechanical devices such as bridge plugs, packers,
downhole
valves, sliding sleeves, and baffle/plug combinations; ball sealers;
particulates such as
sand, ceramic material, proppant, salt, waxes, resins, or otller compounds; or
by
alternative fluid systems such as viscosified fluids, gelled fluids, foams, or
other
chemically formulated fluids; or using limited entry methods. These and all
other
methods and devices for temporarily blocking the flow of fluids into or out of
a given
set of perforations will be referred to herein as "diversion agents."
In mechanical bridge plug diversion, for example, the deepest interval is
first
perforated and fracture stimulated, then the interval is typically isolated by
a
wireline-set bridge plug, and the process is repeated in the next interval up.
Assuming
ten target perforation intervals, treating 300 meters (1,000 feet) of
formation in this
manner would typically require ten jobs over a time interval of ten days to
two weeks
with not only multiple fracture treatments, but also multiple perforating and
bridge
plug running operations. At the end of the treatment process, a wellbore clean-
out
operation would be required to remove the bridge plugs and put the well on
production. The major advantage of using bridge plugs or other mechanical
diversion
agents is high confidence that the entire target zone is treated. The major
disadvantages are the higll cost of treatment resulting from multiple trips
into and out
of the wellbore and the risk of complications resulting from so many
operations in the
well. For example, a bridge plug can become stuck in the casing and need to be
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drilled out at great expense. A fiutller disadvantage is that the required
wellbore
clean-out operation may damage some of the successfully fractured intervals.
One alternative to using bridge plugs is filling the portion of wellbore
associated with the just fractured interval with fracturing sand, commonly
referred to
as the Pine Island technique. The sand column in the wellbore essentially
plugs off
the already fractured interval and allows the next interval to be perforated
and
fractured independently. The primary advantage is elimination of the problems
and
risks associated with bridge plugs. The disadvantages are that the sand plug
does not
give a perfect hydraulic seal and it can be difficult to remove from the
wellbore at the
end of all the fracture stimulations. Unless the well's fluid production is
strong
enough to carry the sand from the wellbore, the well may still need to be
cleaned out
with a work-over rig or coiled tubing unit. As before, additional wellbore
operations
increase costs, mechanical risks, and risks of damage to the fractured
intervals.
Another method of diversion involves the use of particulate materials,
granular
solids that are placed in the treating fluid to aid diversion. As the fluid is
pumped, and
the particulates enter the perforations, a temporary block forms in the zone
accepting
the fluid if a sufficiently high concentration of particulates is deployed in
the flow
stream. The flow restriction then diverts fluid to the otller zones. After the
treatment,
the particulate is removed by produced formation fluids or by injected wash
fluid,
either by fluid transport or by dissolution. Commonly available particulate
diverter
materials include benzoic acid, napthalene, rock salt (sodium chloride), resin
materials, waxes, and polymers. Alternatively, sand, proppant, and ceramic
materials,
could be used as particulate diverters. Other specialty particulates can be
designed to
precipitate and form during the treatment.
Another method for diverting involves using viscosified fluids, viscous gels,
or foams as diverting agents. This method involves pumping the diverting fluid
across and/or into the perforated interval. These fluid systems are formulated
to
temporarily obstruct flow to the perforations due to viscosity or formation
relative
permeability decreases; and are also designed so that at the desired time, the
fluid
system breaks down, degrades, or dissolves (with or without adding chemicals
or
other additives to trigger such breakdown or dissolution) such that flow can
be
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restored to or from the perforations. These fluid systeins can be used for
diversion of
matrix chemical stimulation treatments and fracture treatments. Particulate
diverters
and/or ball sealers are sometimes incorporated into these fluid systems in
efforts to
enhance diversion.
Another possible process is limited entry diversion in which the entire target
zone of the formation to be treated is perforated with a very small number of
perforations, generally of small diameter, so that the pressure loss across
those
perforations during pumping promotes a high, internal wellbore pressure. The
internal wellbore pressure is designed to be high enough to cause all of the
perforated
intervals to fracture simultaneously. If the pressure were too low, only the
weakest
portions of the formation would fracture. The primary advantage of limited
entry
diversion is that there are no inside-the-casing obstructions like bridge
plugs or sand
to cause problems later. The disadvantage is that limited entry fracturing
often does
not work well for thick intervals because the resulting fracture is frequently
too
narrow (the proppant cannot all be pumped away into the narrow fracture and
remains
in the wellbore), and the initial, high wellbore pressure may not last. As the
sand
material is pumped, the perforation diameters are often quickly eroded to
larger sizes
that reduce the internal wellbore pressure. The net result can be that not all
of the
target zone is stimulated. An additional concern is the potential for flow
capacity into
the wellbore to be limited by the small number of perforations.
Some of the problems resulting from failure to stimulate the entire target
zone
or using mechanical methods that require multiple wellbore operations and
wellbore
entries that pose greater risk and cost as described above may be alleviated
by using
limited, concentrated perforated intervals diverted by ball sealers. The zone
to be
treated could be divided into sub-zones witli perforations at approximately
the center
of each of those sub-zones, or sub-zones could be selected based on analysis
of the
formation to target desired fracture locations. The fracture stages would then
be
pumped with diversion by ball sealers at the end of each stage. Specifically,
300
meters (1,000 feet) of gross formation might be divided into ten sub-zones of
about 30
meters (about 100 feet) each. At the center of each 30 meter (100 foot) sub-
zone, ten
perforations might be shot at a density of three shots per meter (one shot per
foot) of
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casing. A fracture stage would then be pumped with proppant-laden fluid
followed by
ten or more ball sealers, at least one for each open perforation in a single
perforation
set or interval. The process would be repeated until all of the perforation
sets were
fractured. Such a systein is described in more detail in U.S. Patent No.
5,890,536,
issued April 6, 1999.
Historically, all zones to be treated in a particular job that uses ball
sealers as
the diversion agent have been perforated prior to pumping treatment fluids,
and ball
sealers have been employed to divert treatment fluids from zones already
broken
down or otherwise taking the greatest flow of fluid to other zones taking
less, or no,
fluid prior to the release of ball sealers. Treatment and sealing
theoretically proceeded
zone by zone depending on relative breakdown pressures or permeabilities, but
problems were frequently encountered with balls prematurely seating on one or
more
of the open perforations outside the targeted interval and with two or more
zones
being treated simultaneously. Furthermore, this technique presumes that each
perforation interval or sub-zone would break down and fracture at sufficiently
different pressure so that each stage of treatment would enter only one set of
perforations.
The primary advantages of ball sealer diversion are low cost and low risk of
mechanical problems. Costs are low because the process can typically be
coinpleted
in one continuous operation, usually during just a few hours of a single day.
Only the
ball sealers are left in the wellbore to either flow out with produced
hydrocarbons or
drop to the bottom of the well in an area known as the rat (or junk) hole. The
primary
disadvantage is the inability to be certain that only one set of perforations
will fracture
at a time so that the correct number of ball sealers are dropped at the end of
each
treatment stage. In fact, optimal benefit of the process depends on one
fracture stage
entering the formation through only one perforation set and all other open
perforations
remaining substantially unaffected during that stage of treatment. Further
disadvantages are lack of certainty that all of the perforated intervals will
be treated
and of the order in which these intervals are treated while the job is in
progress.
When the order of zone treatment is not known or controlled, it is not
possible to
ensure that each individual zone is treated or that an individual stimulation
treatment
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stage has been optimally designed for the targeted zone. In some instances, it
may not
be possible to control the treatment such that individual zones are treated
with single
treatment stages.
To overcome some of the disadvantages that may occur during stimulation
treatments when multiple zones are perforated prior to pumping treatment
fluids, an
alternative mechanical diversion method has been developed that involves the
use of a
coiled tubing stimulation system to sequentially stimulate inultiple intervals
with
separate treatment. As with conventional ball sealer diversion, all intervals
to be
treated are perforated prior to pumping the stimulation treatment. Then coiled
tubing
is run into the wellbore with a mechanical "straddle-packer-like" diversion
tool
attached to the end. This diversion tool, when properly placed and actuated
across the
perforations, allows hydraulic isolation to be achieved above and below the
diversion
tool. After the diversion tool is placed and actuated to isolate the deepest
set of
perforations, stimulation fluid is pumped down the interior of the coiled
tubing and
exits flow ports placed in the diversion tool between the upper and lower
sealing
elements. Upon completion of the first stage of treatment, the sealing
elements
contained on the diversion tool are deactivated or disengaged, and the coiled
tubing is
pulled upward to place the diversion tool across the second deepest set of
perforations
and the process is continued until all of the targeted intervals have been
stimulated or
the process is aborted due to operational upsets.
This type of coiled tubing stimulation apparatus and method have been used to
h.ydraulically fracture multiple zones in wells with depths up to about 8,000
feet.
However, various technical obstacles, including friction pressure losses,
damage to
sealing elements, depth control, running speed, and potential erosion of
coiled tubing,
currently limit deployment in deeper wells.
Excess friction pressure is generated when pumping stimulation fluids,
particularly proppant-laden and/or high viscosity fluids, at high rates
through longer
lengths of coiled tubing. Depending on the length and diameter of the coiled
tubing,
the fluid viscosity, and the maximum allowable surface hardware working
pressures,
pump rates could be limited to just a few barrels per minute; which, depending
on the
characteristics of a specific subterranean formation, may not allow effective
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placement of proppant during lzydraulic fracture treatments or effective
dissolution of
formation materials during acid stimulation treatments
Erosion of the coiled tubing could also be a problem as proppant-laden fluid
is
pumped down the interior of the coiled tubing at high velocity, including the
portion
of the coiled tubing that remains wound on the surface reel. The erosion
concerns are
exacerbated as the proppant-laden fluid impinges on the "continuous bend"
associated
with the portion of the coiled tubing placed on the surface reel.
Most seal elements (e.g., "cup" seal technology) currently used in the coiled
tubing stimulation operations described above could experience sealing
problems or
seal failure in deeper wells as the seals are run past a large number of
perforations at
the higher well temperatures associated with deeper wells. Since the seals run
in
contact with or at a minimal clearance from the pipe wall, rough interior pipe
surfaces
andlor perforation burrs can damage the sealing elements. Seals currently
available in
straddle-packer-like diversion tools are also constr-ucted from elastomers
which may
be unable to withstand the higher temperatures often associated with deeper
wells.
Running speed of the existing systems with cup seals is generally on the order
of 15 to 30 feet-per-minute running downhole to 30 to 60 feet-per-minute
coming
uphole. For example, at the lower running speed, approximately. .13 hours
would be
required to reach a depth of 12,000 feet before beginning the stimulation.
Given
safety issues surrounding nighttime operations, this slow running speed could
result in
multiple days being required to complete a stimulation job. If any problems
are
encountered during the job, tripping in and out of the hole could be very
costly
because of the total operation times associated with the slow running speeds.
Depth control of the coiled tubing system and straddle-packer-like diversion
tool also becomes more difficult as depth increases, such that placing the
tool at the
correct depth to successfully execute the stimulation operation may be
difficult. This
problem is compounded by shooting the perforations before rumiing the coiled
tubing
system in the hole. The perforating operation uses a different depth
measurement
device (usually a casing collar locator system) than is generally used in the
coiled
tubing system.
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In addition, the coiled tubing method described above requires that all of the
perforations be placed in the wellbore in a separate perforating operation
prior to
pumping the stimulation job. The presence of multiple perforation sets open
above
the diversion tool can cause operational difficulties. For example, if the
proppant
fracture from the current zone were to grow vertically and/or poor quality
cement is
present behind pipe, the fracture could intersect the perforation sets above
the
diversion tool such that proppant could "dump" back into the wellbore on top
of the
diversion tool and prevent further tool movement. Also, it could be difficult
to
execute circulation operations if multiple perforation sets are open above the
diversion
tool. For example, if the circulation pressures exceed the breakdown pressures
associated with the perforations open above the diversion tool, the
circulation may not
be maintained with circulation fluid unintentionally lost to the formation.
A similar type of stimulation operation may also be performed using jointed
tubing and a workover rig rather than a coiled tubing system. Using a
diversion tool
deployed on jointed tubing may allow for larger diameter tubing to reduce
friction
pressure losses and allow for increased pump rates. Also, concerns over
erosion and
tubing integrity may be reduced when compared to coiled tubing since heavier
wall
thickness jointed tubing pipe may be used and jointed tubing would not be
exposed to
plastic deformation when run in the wellbore. However, using this approach
would
likely increase the time and cost associated with the operations because of
slower pipe
running speeds than those possible with coiled tubing.
To overcome some of the limitations associated with completion operations
that require multiple trips of hardware into and out of the wellbore to
perforate and
stimulate subterranean formations, methods have been proposed for "single-
trip"
deployment of a downhole tool string to allow for fracture stimulation of
zones in
conjunction with perforating. Specifically, these methods propose operations
that
may minimize the number of required wellbore operations and time required to
complete these operations, thereby reducing the stinlulation treatment cost.
These
proposals include 1) having a sand slurry in the wellbore while perforating
with
overbalanced pressure, 2) dumping sand from a bailer simultaneously with
firing the
perforating charges, and 3) including sand in a separate explosively released
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container. These proposals all allow for oniy ininimal fracture penetration
surrounding the wellbore and are not adaptable to the needs of multi-stage
hydraulic
fracturing as described herein.
Accordingly, there is a need for an improved method and apparatus for
individually treating each of multiple intervals of a subterranean formation
penetrated
by a wellbore while maintaining the economic benefits of multi-stage
treatment.
There is also a need for a method and apparatus that can economically reduce
the risks
inherent in the currently available stimulation treatment options for
hydrocarbon-
bearing formations with multiple or layered reservoirs or with thickness
exceeding
about 60 meters (200 feet) while ensuring that optimal treatment placement is
performed with a mechanical diversion agent that positively directs treatment
stages
to the desired location.
SUMMARY OF THE INVENTION
This invention provides an apparatus and method for perforating and treating
multiple intervals of one or more subterranean forinations intersected by a
wellbore.
The apparatus consists of a deployment means (e.g., coiled tubing, jointed
tubing, electric line, wireline, downhole tractor, etc.) with a bottomhole
assembly
("BHA") comprised of at least a perforating device and a re-settable
mechanical
sealing mechanism that may be independently actuated via one or more signaling
means (e.g., electronic signals transmitted via wireline; hydraulic signals
transmitted
via tubing, annulus, umbilicals; tension or compression loads; radio
transmission;
fiber-optic transmission; on-board BHA computer systems, etc.).
The method includes the steps of deploying the BHA within the wellbore
using a deployment means where the deployinent means may be a tubing-string,
cable, or downhole tractor. The perforating device is positioned adjacent to
the
interval to be perforated and is used to perforate the interval. The BHA is
positioned
within the wellbore using the deployment means, and the sealing mechanism is
actuated so as to establish a hydraulic seal that positively directs fluid
pumped down
the wellbore to enter the perforated interval. The sealing mechanism is
released. The
process can then be repeated, without removing the BHA from the wellbore, for
at
least one additional interval of the one or more subterranean formations.
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The deployment means can be a tubing string, including a coiled tubing or
standard jointed tubing, a wireline, a slickline, or a cable. Rather than
tubing or cable
deployment, the deployment means could also be a tractor system attached to
the
BHA. The tractor system may be a self-propelled, computer-controlled, and
carry
on-board signaling systems such that it is not necessary to attach cable or
tubing to
control and actuate the BHA and/or tractor system. Alteniatively, the tractor
system
could be controlled and energized by cable or tubing umbilicals such the
tractor
system and BHA are controlled and actuated via signals transmitted downhole
using
the umbilicals. Many different embodiments to the invention can exist
depending on
the suspension means and specific components of the BHA.
In the first embodiment of the invention, when the deployment means is a
tubing string, once an interval has been perforated the BHA can be moved and
the
sealing mechanism actuated to establish a hydraulic seal below the perforated
interval.
Then treating fluid can be pumped down the annulus between the tubing string
and the
wellbore and into the perforated interval. And a second treating fluid, such
as
nitrogen, could also be pumped down the tubing string at the same time that
the first
treating fluid is pumped down the annulus between the tubing string and the
wellbore.
In the second embodiment, when the suspension means is a tubing string, once
an interval has been perforated the BHA can be moved and the sealing mechanism
actuated to establish a hydraulic seal above the perforated interval. Then
treating fluid
can be pumped down the tubing string and into the perforated interval.
In the third embodiment, when the deployment means is a tubing string, the
BHA can be moved and the sealing mechanism actuated to establish a hydraulic
seal
above and below the perforated interval (where the sealing mechanism consists
of two
seal elements spaced sufficient distance apart to straddle the perforated
interval). In
this third embodiment, treating fluid can be pumped down the tubing string
itself,
through a flow port placed in-between the two seal elements of the sealing
mechanism
and into the perforated interval.
In a fourth embodiment of the invention, when the BHA is deployed in the
wellbore using a wireline, slickline or cable, the BHA would be moved and the
sealing mechanism actuated to establish a hydraulic seal below the perforated
interval
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to be treated, and the treating fluid would be pumped down the annulus between
the
wireline, slickline, or cable, and the wellbore.
In a fifth embodiment of the invention, an "umbilical" is deployed as an
additional means to actuate a BHA component. In the most general sense, the
umbilical could take the form of a small diameter tubing or multiple tubing to
provide
hydraulic communication with BHA components; and/or the umbilical could take
the
form of a cable or multiple cables to provide electrical or electro-optical
communication with BHA components.
In a sixth embodiment of the invention, when the deployment means is a
tractor system attached to the BHA, the BHA can be moved and the sealing
mechanism actuated to establish a hydraulic seal below the perforated
interval. The
treating fluid can be pumped down the wellbore and into the perforated
interval.
In a seventh einbodiment of the invention, abrasive fluid-jet cutting
technology is used for perforating and the BHA is suspended by tubing such
that the
BHA can be moved and the sealing mechanism actuated to establish a hydraulic
seal
below the perforated interval. The treating fluid would then be pumped down
the
annulus between the tubing and wellbore.
One of the primary advantages of this apparatus and method is that the BHA,
including the sealing mechanism and the perforating device, does not need to
be
removed from the wellbore prior to treatment with the treating fluid and
between
treatinent of multiple formation zones or intervals. Another primary advantage
of this
apparatus and method is that each treatment stage is diverted using a
mechanical
diversion agent such that precise control of the treatment diversion process
is achieved
and each zone can be optimally stimulated. As a result, there are significant
costs
savings associated with reduction in the time required to perforate and treat
multiple
intervals within a wellbore. In addition, there are production improvements
associated with using a mechanical diversion agent to provide precisely-
controlled
treatment diversion when stimulating multiple formation interval within a
wellbore.
As such, the inventive method and apparatus provide significant economic
advantages
over existing methods and equipment since the inventive method and apparatus
allow
for perforating and stimulating multiple zones with a single wellbore entry,
and
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subsequent withdrawal, of a bottomhole assembly that provides dual
functionality as
both a mechanical diversion agent and perforating device.
In a further embodiment of the invention, there is provided a method of
perforating and treating multiple intervals of one or more subterranean
formations
intersected by a wellbore, said method comprising (a) deploying a bottom-hole
assembly ("BHA") within said wellbore, said BHA having a perforating device, a
sealing mechanism and at least one pressure equalization means; (b) using said
perforating device to perforate an interval of said one or more subterranean
formations;
(c) actuating said sealing mechanism so as to establish a hydraulic seal in
said wellbore;
(d) pumping a treating fluid in said wellbore and into the perforations
created by said
perforating device, without removing said perforating device from said
wellbore; (e)
establishing pressure communication between the portions of the wellbore above
and
below said sealing mechanism through said at least one pressure equalization
means; (f)
releasing said sealing mechanism; and repeating steps (b) through (f) for at
least one
additional interval of said one or more subterranean formations.
In a further embodiment of the invention, there is provided a method of
perforating and treating multiple intervals of one or more subterranean
formations
intersected by a wellbore, said method comprising: deploying a bottom-hole
assembly
("BHA") within said wellbore, said BHA having at least one perforating device
and at
least one sealing mechanism, said perforating device being positioned below
said
sealing mechanism; using said at least one perforating device to perforate an
interval of
said one or more subterranean formations; actuating said at least one sealing
mechanism so as to establish a hydraulic seal in said wellbore; pumping a
treating fluid
in said wellbore and into the perforations created by said perforating device,
without
removing said perforating device from said wellbore; releasing said sealing
mechanism;
and (1) repeating steps (b) through (e) for at least one additional interval
of said one or
more subterranean formations.
In a further embodiment of the invention, there is provided a method of
perforating and treating multiple intervals of one or more subterranean
formations
intersected by a wellbore, said multiple intervals including a deepest target
interval and
sequentially shallower target intervals, said method comprising: deploying a
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bottom-hole assembly ("BHA") within said wellbore, said BHA having a
perforating
device and a sealing mechanism, said perforating device positioned below said
sealing
mechanism; using said perforating device to perforate said deepest target
interval of
said one or more subterranean formations; pumping a treating fluid in said
wellbore and
into the perforations created in said deepest target interval by said
perforating device
without removing said perforating device from said wellbore; positioning said
BHA in
said wellbore and using said perforating device to perforate the next
sequentially
shallower target interval of said one or more subterranean formations;
repositioning
said BHA in said wellbore and actuating said sealing mechanism to
hydraulically
isolate the perforations created in said next sequentially shallower target
interval from
the perforated deepest target interval; pumping a treating fluid in said
wellbore and into
the perforations created in said next sequentially shallower target interval
by said
perforating device without removing said perforating device from said
wellbore;
releasing said sealing mechanism; and repeating steps (d) through (g) for at
least one
additional sequentially shallower target interval of said one or more
subterranean
formations wherein the perforations created in said at least one additional
sequentially
shallower target intervals are hydraulically isolated from the perforated
intervals below.
In a further embodiment of the invention, there is provided an apparatus for
use
in perforating and treating multiple intervals of one or more subterranean
formations
intersected by a wellbore, said apparatus comprising: a bottom-hole assembly
(BHA),
adapted to be deployed in said wellbore by a deployment means, said BHA having
at
least one perforating device for sequentially perforating said multiple
intervals, at least
one sealing mechanism and at least one pressure equalization means; and said
sealing
mechanism capable of establishing a hydraulic seal in said wellbore, said
pressure
equalization means capable of establishing pressure communication between
portions
of said wellbore above and below said sealing mechanism, and said sealing
mechanism
further capable of releasing said hydraulic seal to allow said BHA to move to
a
different position within said wellbore, thereby allowing each of said
multiple treatment
intervals to be treated separately from said other treatment intervals.
In a further embodiment of the invention, there is provided an apparatus for
use
in perforating and treating multiple intervals of one or more subterranean
formations
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intersected by a wellbore, said apparatus comprising: a bottom-hole assembly
(BHA),
adapted to be deployed in said wellbore by a deployment means, said BHA having
at
least one perforating device for sequentially perforating said multiple
intervals and at
least one sealing mechanism, said perforating device being positioned below
said
sealing mechanism; and said sealing mechanism capable of establishing a
hydraulic
seal in said wellbore, and further capable of releasing said hydraulic seal to
allow said
BHA to move to a different position within said wellbore, thereby allowing
each of said
multiple treatment intervals to be treated separately from said other
treatment intervals.
BRIEF DESCRIPTION OF THE DRAWINGS
The present invention and its advantages will be better understood by
referring
to the following detailed description and the attached drawings in which:
Figure 1 illustrates one possible representative wellbore configuration with
peripheral equipment that could be used to support the bottomhole assembly
used in the
present invention. Figure 1 also illustrates representative bottomhole
assembly storage
welibores with surface slips that may be used for storage of spare or
contingency
bottomhole assemblies.
Figure 2A illustrates the first embodiment of the bottomhole assembly
deployed using coiled tubing in an unperforated wellbore and positioned at the
depth
location to be perforated by the first set of selectively-fired perforating
charges. Figure
2A further illustrates that the bottomhole assembly consists of a perforating
device, an
inflatable, re-settable packer, a re-settable axial slip device, and ancillary
components.
Figure 2B represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 2A after the first set of selectively-fired perforating charges are
fired resulting
in perforation holes through the production casing and cement sheath and into
the first
forrnation zone such that hydraulic communication is established between the
wellbore
and the first formation zone.
Figure 2C represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 2B after the bottomhole assembly has been re-positioned and the first
formation
zone stimulated with the first stage of the multiple-stage, hydraulic,
proppant fracture
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treatment where the first stage of the fracture treatment was pumped downhole
in the
wellbore annulus existing between the coiled tubing and production casing. In
Figure
2C, the sealing mechanism is shown in a de-activated position since, for
illustration
purposes only, it is assumed that no other perforations besides those
associated with the
first zone are present, and as such, isolation is not necessary for treatment
of the first
zone.
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Figure 3A represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 2C after the bottomhole assembly has been re-positioned and the second
set of
selectively-fired perforating charges have been fired resulting in perforation
holes
through the production casing and cement sheath and into the second formation
zone
such that hydraulic communication is established between the wellbore and the
second formation zone.
Figure 3B represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 3A after the bottomhole assembly has been re-positioned a sufficient
distance
below the deepest perforation of the second perforation set to allow slight
movement
upward of the BHA to set the re-settable axial slip device while keeping the
location
of the circulation port below the bottom-most perforation of the second
perforation
set.
Figure 3C represents the bottomhole assembly, coiled tubing and wellbore of
Figure 3B after the re-settable mechanical slip device has been actuated to
provide
resistance to downward axial movement ensuring that the inflatable, re-
settable paclcer
and re-settable mechanical slip device are located between the first zone and
second
zone perforations.
Figure 3D represents the bottomhole asseinbly, coiled tubing and wellbore of
Figure 3C after the inflatable, re-settable packer has been actuated to
provide a barrier
to flow between the portion of the wellbore directly above the inflatable, re-
settable
packer and the portion of the wellbore directly below the inflatable, re-
settable packer.
Figure 3E represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 3D after the second formation zone has been stiinulated with the second
stage
of the multiple stage hydraulic proppant fracture treatinent where the second
stage of
the fracture treatment was pumped downhole in the wellbore annulus existing
between the coiled tubing and production casing.
Figure 3F represents the bottomhole assembly, coiled tubing, and wellbore of
Figure 3E after the inflatable, re-settable packer has been de-activated
thereby
re-establishing pressure communication between the portion of the wellbore
directly
above the inflatable, re-settable packer and the portion of the wellbore
directly below
the inflatable, re-settable packer. The re-settable mechanical slip device is
still
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energized and continues to prevent movement of the coiled tubing and
bottomhole
assembly down the wellbore.
Figure 4A represents a modified bottomhole assembly, similar to the
bottomhole assembly described in Figures 2A through 2C and Figures 3A
through 3F, but with the addition of a mechanical-plug, settable with a select-
fire
charge setting systein, located below the string of perforating guns. Figure
4A also
represents the coiled tubing, and wellbore of Figure 3F after an additional,
third
perforating and fracture stimulation operation has been performed. In Figure
4A, it is
noted that only the second and third fractures and perforation sets are shown.
In
Figure 4A, the modified bottomhole assembly is shown suspended by coiled
tubing
such that the location of the bridge-plug is located above the last perforated
interval
and below the next interval to be perforated.
Figure 4B represents the bottoinhole assembly, coiled tubing, and wellbore of
Figure 4A after the mechanical-plug has been select-fire-charge-set in the
well and
after the bottomhole assembly has been re-positioned and the first set of
selectively-fired perforating charges have been fired and result in
perforation holes
through the production casing and cement sheath and into the fourth formation
zone
such that hydraulic communication is established between the wellbore and the
fourth
formation zone.
Figure 5 represents a second embodiment of the invention. In this
embodiment, the suspension means is a tubing string, and once an interval has
been
perforated, the BHA can be moved and the sealing mechanisin actuated to
establish a
hydraulic seal above the perforated interval. Then treating fluid can be
pumped down
the tubing string and into the perforated interval.
Figure 6 represents a third embodiment of the invention. The suspension
means is a tubing string, and the BHA can be moved and the sealing mechanism
actuated to establish a hydraulic seal above and below the perforated interval
(where
the sealing mechanism consists of two seal elements spaced sufficient distance
apart
to straddle the perforated interval). In this third embodiment, treating fluid
can be
pumped down the tubing string itself, through a flow port placed in-between
the two
seal elements of the sealing mechanism and into the perforated interval.
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Figure 7 represents a fourth embodiment of the invention. The BHA is
suspended in the wellbore using a wireline (or slickline or cable). The BHA
would be
moved and the sealing mechanism actuated to establish a hydraulic seal below
the
perforated interval to be treated, and the treating fluid would be pumped down
the
annulus between the wireline, slickline, or cable, and the wellbore.
Figures 8A and 8B represent a fifth embodiment of the invention that utilizes
an umbilical tubing, deployed interior to the tubing used as the deployment
means, for
actuation of the re-settable sealing mechanism.
Figure 9 represents a sixth embodiment of the invention that utilizes a
tractor
system attached to the BHA such that BHA can be moved and the sealing
mechanism
actuated to establish a hydraulic seal below the perforated interval. The
treating fluid
can be pumped down the wellbore and into the perforated interval.
Figure 10 represents a seventh embodiment of the invention that utilizes
abrasive or erosive fluid-jet cutting technology for the perforating device.
The BHA
is suspended in the wellbore using jointed tubing and consists of a mechanical
compression-set, re-settable packer, an abrasive or erosive fluid jet
perforating device,
a mechanical casing-collar locator, and ancillary components. In this
embodiment,
perforations are created by pumping an abrasive fluid down the jointed tubing
and out
of a jetting tool located on the BHA such that a high-pressure high-speed
abrasive or
erosive fluid jet is created and used to penetrate the production casing and
surrounding cement sheath to establish hydraulic communication with the
desired
formation interval. After setting the re-settable packer below the zone to be
stimulated, the stimulation treatment can then pumped down the annulus located
between the tubing string and the production casing string.
DETAILED DESCRIPTION OF THE INVENTION
The present invention will be described in connection with its preferred
embodiments. However, to the extent that the following description is specific
to a
particular embodiment or a particular use of the invention, this is intended
to be
illustrative only, and is not to be construed as limiting the scope of the
invention. On
the contrary, the description is intended to cover all alternatives,
modifications, and
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equivalents that are included within the spirit and scope of the invention, as
defined
by the appended claims.
The present invention provides a new method, new system, and a new
apparatus for perforating and stimulating multiple formation intervals, which
allows
each single zone to be treated with an individual treatment stage while
eliminating or
minimizing the problems that are associated with existing coiled tubing or
jointed
tubing stimulation methods and hence providing significant economic and
technical
benefit over existing methods.
Specifically, the invention involves suspending a bottomhole assembly in the
wellbore to individually and sequentially perforate and treat each of the
desired
multiple zones while pumping the multiple stages of the stimulation treatment
and to
deploy a mechanical re-settable sealing mechanism to provide controlled
diversion of
each individual treatment stage. For the purposes of this application,
"wellbore" will
be understood to include below ground sealed components of the well and also
all
sealed equipment above ground level, such as the wellhead, spool pieces,
blowout
preventers, and lubricator.
The new apparatus consists of a deployment means (e.g., coiled tubing, jointed
tubing, electric line, wireline, tractor system, etc.) with a bottomhole
assembly
comprised of at least a perforating device and a re-settable mechanical
sealing
mechanism that may be independently actuated from the surface via one or more
signaling means (e.g., electronic signals transmitted via wireline; hydraulic
signals
transmitted via tubing, annulus, umbilicals; tension or coinpression loads;
radio
transmission; fiber-optic transmission; etc.) and designed for the anticipated
wellbore
environment and loading conditions.
In the most general sense, the term "bottomhole assembly" is used to denote a
string of components consisting of at least a perforating device and a re-
settable
sealing mechanism. Additional components including, but not limited to,
fishing
necks, shear subs, wash tools, circulation port subs, flow port subs, pressure
equalization port subs, temperature gauges, pressure gauges, wireline
connection subs,
re-settable mechanical slips, casing collar locators, centralizer subs and/or
connector
subs may also be placed on the bottomhole assembly to facilitate other
anticipated
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auxiliary or ancillary operations and measurements that may be desirable
during the
stimulation treatment.
In the most general sense, the re-settable mechanical sealing mechanism
performs the function of providing a "hydraulic seal", where hydraulic seal is
defined
as sufficient flow restriction or blockage such that fluid is forced to be
directed to a
different location than the location it would otherwise be directed to if the
flow
restriction were not present. Specifically, this broad definition for
"hydraulic seal" is
meant to include a "perfect hydraulic seal" such that all flow is directed to
a location
different from the location the flow would be directed to if the flow
restriction were
not present; and an "iinperfect hydraulic seal" such that an appreciable
portion of flow
is directed to a location different from the location the flow would be
directed to if the
flow restriction were not present. Although it would generally be preferable
to use a
re-settable mechanical sealing that provides a perfect hydraulic seal to
achieve optimal
stimulation; a sealing mechanism that provides an imperfect hydraulic seal
could be
used and an economic treatment achieved even though the stimulation treatment
may
not be perfectly diverted.
In the first preferred embodiment of the invention, coiled tubing is used as
the
deployment means and the new method involves sequentially perforating and then
stimulating the individual zones from bottom to top of the completion
interval, with
the stimulation fluid pumped down the annular space between the production
casing
and the coiled tubing. As discussed further below, this embodiment of the new
apparatus and method offer substantial improvements over existing coiled
tubing and
jointed tubing stimulation technology and are applicable over a wide range of
wellbore architectures and stimulation treatment designs.
Specifically, the first preferred embodiment of the new method and apparatus
involves the deployment system, signaling means, bottomhole assembly, and
operations as described in detail below, where the various components, their
orientation, and operational steps are chosen, for descriptive purposes only,
to
correspond to components and operations that could be used to accommodate
hydraulic proppant fracture stimulation of multiple intervals.
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In the first preferred embodiment for a hydraulic proppant fracture
stimulation
treatment, the apparatus would consist of the BHA deployed in the wellbore by
coiled
tubing. The BHA would include a perforating device; re-settable mechanical
sealing
mechanism; casing-collar-locator; circulation ports; and other ancillary
components
(as described in more detail below).
Furthermore, in this first preferred embodiment, the perforating device would
consist of a select-fire perforating gun system (using shaped-charge
perforating
charges); and the re-settable mechanical sealing mechanism would consist of an
inflatable, re-settable packer; a mechanical re-settable slip device to
prevent
downward axial movement of the bottomhole assembly when set; and pressure
equalization ports located above and below the inflatable re-settable packer.
In addition, in this first preferred einbodiment, a wireline would be placed
interior to the coiled tubing and used to provide a signaling means for
actuation of
select-fire perforation charges and for transmission of electric signals
associated with
the casing-collar-locator used for BHA depth measurement.
Referring now to Figure 1, an example of the type of surface equipment that
could be utilized in the first preferred embodiment would be a rig up that
used a very
long lubricator 2 with the coiled tubing injector head 4 suspended high in the
air by
crane arm 6 attached to crane base 8. The wellbore would typically comprise a
length
of a surface casing 78 partially or wholly within a cement sheath 80 and a
production
casing 82 partially or wholly within a cement sheath 84 where the interior
wall of the
wellbore is composed of the production casing 82. The depth of the wellbore
would
preferably extend some distance below the lowest interval to be stimulated to
accommodate the length of the bottomhole assembly that would be attached to
the end
of the coiled tubing 106. Coiled tubing 106 is inserted into the wellbore
using the
coiled tubing injection head 4 and lubricator 2. Also installed to the
lubricator 2 are
blow-out-preventors 10 that could be remotely actuated in the event of
operational
upsets. The crane base 8, crane arm 6, coiled tubing injection head 4,
lubricator 2,
blow-out-preventors 10 (and their associated ancillary control and/or
actuation
coinponents) are standard equipment components well known to those skilled in
the
art that will accommodate methods and procedures for safely installing a
coiled tubing
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bottonihole assembly in a well under pressure, and subsequently removing the
coiled-tubing bottomhole assembly from a well under pressure.
With readily-available existing equipment, the height to the top of the coiled
tubing injection head 4 could be approximately 90 feet from ground level with
the
"goose-neck" 12 (where the coil is bent over to go down vertically into the
well)
approaching approximately 105 feet above the ground. The crane arm 6 and crane
base 8 would support the load of the injector head 4, the coiled tubing 106,
and any
load requirements anticipated for potential fishing operations (jarring and
pulling).
In general, the lubricator 2 must be of length greater than the length of the
bottomhole assembly to allow the bottomhole assembly to be safely deployed in
a
wellbore under pressure. Depending on the overall length requirements and as
determined prudent based on engineering design calculations for a specific
application, to provide for stability of the coiled tubing injection head 4
and
lubricator 2, guy-wires 14 could be attached at various locations on the
coiled tubing
injection head 4 and lubricator 2. The guy wires 14 would be firmly anchored
to the
ground to prevent undue motion of the coiled tubing injection head 4 and
lubricator 2
such that the in'tegrity of the surface components to hold pressure would not
be
compromised. Depending on the overall length requirements, alternative
injection
head/lubricator system suspension systems (coiled tubing rigs or fit-for-
purpose
completion/workover rigs) could also be used.
Also shown in Figure 1 are several different wellhead spool pieces which may
be used for flow control and hydraulic isolation during rig-up operations,
stimulation
operations, and rig-down operations. The crown valve 16 provides a device for
isolating the portion of the wellbore above the crown valve 16 from the
portion of the
wellbore below the crown valve 16. The upper master fracture valve 18 and
lower
master fracture valve 20 also provide valve systems for isolation of wellbore
pressures
above and below their respective locations. Depending on site-specific
practices and
stimulation job design, it is possible that not all of these isolation-type
valves may
actually be required or used.
The side outlet injection valves 22 shown in Figure 1 provide a location for
injection of stimulation fluids into the wellbore. The piping from the surface
pumps
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and tanks used for injection of the stimulation fluids would be attached with
appropriate fittings and/or couplings to the side outlet injection valves 22.
The
stimulation fluids would then be pumped into the wellbore via this flow path.
With
installation of other appropriate flow control equipment, fluid may also be
produced
from the wellbore using the side outlet injection valves 22. It is noted that
the interior
of the coiled tubing 106 can also be used as a flow conduit for fluid
injection into the
wellbore.
The bottomhole assembly storage wellbores 24 shown in Figure 1 provide a
location for storage of spare or contingency bottom-hole assemblies 27, or for
storage
of bottomhole assemblies that have been used during previous operations. The
bottomhole assembly storage wellbores 24 may be drilled to a shallow depth
such that
a bottomhole assembly that may contain perforating charges may be safely held
in
place with surface slips 26 such that the perforating charges are located
below ground
level until the bottomhole assembly is ready to be attached to the coiled
tubing 106.
The bottoinhole assembly storage wellbores 24 may be drilled to accommodate
placement of either cemented or uncemented casing string, or may be left
uncased
altogether. The actual number of bottomhole assembly storage wellbores 24
required
for a particular operation would depend on the overall job requirements. The
bottomhole assembly storage wellbores 24 could be located within the reach of
the
crane arm 6 to accommodate rapid change-out of bottomhole assemblies during
the
course of the stimulation operation without the necessity of physically
relocating the
crane base 8 to another location.
Referring now to Figure 2A, coiled tubing 106 is equipped with a coiled
tubing connection 110 which may be comiected to a shear-release/fishing neck
combination sub 112 that contains both a shear-release mechanism and a fishing
neck
and allows for the passage of pressurized fluids and wireline 102. The shear-
release/fishing neck combination sub 112 may be connected to a sub containing
a
circulation port sub 114 that may provide a flow path to wash debris from
above the
inflatable, re-settable packer 120 or provide a flow path to inject fluid
downhole using
the coiled tubing 106. The circulation port sub 114 contains a valve assembly
that
actuates the circulation port 114 and the upper equalization port 116. The
upper
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equalization port 116 may be connected to a lower equalization port 122 via
tubing
through the inflatable, re-settable packer 120. Both the circulation port 114
and the
upper equalization port 116 would preferably be open in the "running
position",
thereby allowing pressure communication between the internal coiled-tubing
pressure
and the coiled tubing by casing annulus pressure. Within this document,
"running
position" refers to the situation where all components in the bottomhole
assembly
possess a configuration that permits unhindered axial movement up and down the
wellbore. The lower equalization port 122 located below the inflatable, re-
settable
packer 120 is always open and flow through the equalization ports is
controlled by the
upper equalization port 116. The circulation and equalization ports can be
closed
simultaneously by placing a slight compressive load on the BHA. To prevent
potential back-flow into the coiled tubing when the circulation port 114 is
open in the
running position, a surface pressure can be applied to the coiled tubing 106
such that
the pressure inside the circulation port 114 exceeds the wellbore pressure
directly
outside the circulation port 114. The re-settable, inflatable packer 120 is
hydraulically
isolated from the internal coiled tubing pressure in the' running position.
The
inflatable, re-settable packer 120 can gain pressure communication via
internal
valving with the internal coiled tubing pressure by placing a slight
compressive load
on the BHA. Mechanically actuated, re-settable axial position locking devices,
or
"slips," 124 may be placed below the inflatable, re-settable packer 120 to
resist
movement down the wellbore. The mechanical slips 124 may be actuated through a
"continuous J" mechanism by cycling the axial load between compression and
tension. A wireline connection sub 126 is located above the casing collar
locator 128
and select-fire perforating gun systein. A gun connection sub 130 connects the
casing
collar locator 128 to select-fire head 152. The perforating gun system may be
designed based on knowledge of the number, location, and tliickness of the
hydrocarbon-bearing sands within the target zones. The gun system will be
composed
of one gun assembly (e.g., 134) for each zone to be treated. The first
(lowest) gun
assembly will consist of a select-fire head 132 and a gun encasement 134 which
will
be loaded with perforating charges 136 and a select-fire detonating system.
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Specifically, a preferred einbodiment of the new method involves the
following steps, where the stimulation job is chosen, for descriptive
purposes, to be a
multi-stage,llydraulic, proppant-fracture stimulation.
1. The well is drilled and casing is cemented across the interval to be
completed,
and if desired, one or more bottomhole assembly storage wellbores are drilled
and completed.
2. The target zones within the completion interval are identified (typically
by a
combination of open-hole and cased-hole logs).
3. The bottomhole assemblies (BHA), and perforating gun assemblies to be
deployed on each BHA anticipated to be used during the stimulation
operation, are designed based on knowledge of the number, location, and
thickness of the hydrocarbon-bearing sands within the target zones.
4. A reel of coiled tubing is made-up with a preferred embodiment BHA
described above. The reel of coiled tubing would also be made-up to contain
the wireline that is used to provide a signaling means for actuation of the
perforating guns. Preferably, the desired quantity of appropriately configured
spare or contingency BHA's would also be made-up and stored in the
bottomhole assembly storage wellbore(s). The coiled tubing may be
pre-loaded with fluid either before or after attaching the BHA to the coiled
tubing.
5. As shown in Figure 1, the coiled tubing 106 with BHA is run into the well
via
a lubricator 2 and the coiled tubing injection head 4 is suspended by crane
arm 6.
6. The coiled tubingBHA is run into the well while correlating the depth of
the
BHA with the casing collar locator 128 (Figure 2A).
7. The coiled tubingBHA is run below the bottom-most target zone to ensure
that there is sufficient wellbore depth below the bottom-most perforations to
locate the BHA below the first set of perforations during fracturing
operations.
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As shown in Figure 2A, the inflatable, re-settable packer 120 and re-settable
mechanically actuated slips 124 are in the n.imling position.
8. As shown in Figure 2B, the coiled tubing/BHA is then raised to a location
within the wellbore such that the first (lowest) set of perforation charges
136
contained on the first gun assembly 134 of the select-fire perforating gun
system are located directly across the bottom-most target zone where precise
depth control may be established based on readings from the
casing-collar-locator 128 and coiled tubing odometer systems (not shown).
The action of moving the BHA up to the location of the first perforated
interval will cycle the mechanical slip "continuous J" mechanism (not shown)
into the pre-lock position where subsequent downward motion will force the
re-settable mechanical slip 124 into the locked position thereby preventing
further downward movement. It is noted that additional cycling of the coiled
tubing axial load from compression to tension and back will return the re-
settable mechanical slips to running position. In this manner, the mechanical
slip continuous J mechanism coupled with the use of compression and tension
loads transmitted via the suspension means (coiled tubing) are used to provide
downhole actuation and de-actuation of the mechanical slips.
9. The first set of perforation charges 136 are selectively-fired by remote
actuation via wireline 102 commuiv.cation with the first select-fire head 132
to
penetrate the casing 82 and cement sheath 84 and establish hydraulic
communication with the formation 86 through the resultant
perforations 230-231. It will be understood that any given set of perforations
can, if desired, be a set of one, altliough generally multiple perforations
would
provide improved treatment results. It will also be understood that more than
one segment of the gun assembly may be fired if desired to achieve the target
number of perforations whether to remedy an actual or perceived misfire or
simply to increase the number of perforations. It will also be understood that
an interval is not necessarily limited to a single reservoir sand. Multiple
sand
intervals could be perforated and treated as a single stage using other
diversion
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agents suitable for simultaneous deployment with this invention within a given
stage of treatment.
10. As shown in Figure 2C, the coiled tubing may be moved to position the
circulation port 114 directly below the deepest perforation 231 of this first
target zone to minimize potential for proppant fill above the inflatable,
re-settable packer 120 and minimize high velocity proppant flow past the
BHA.
11. The first stage of the fracture stimulation fireatment is initiated by
circulating a
small volume of fluid down the coiled tubing 106 through the circulation
port 114 (via a positive displacement pump). This is followed by initiating
the
pumping of stimulation fluid down the annulus between the coiled tubing 106
and production casing 82 at fracture stimulation rates. The small volume of
fluid flowing down the coiled tubing 106 serves to keep a positive pressure
inside the coiled tubing 106 to resist proppant-laden fluid backflow into the
coiled tubing 106 and to resist coiled tubing collapse loading during
fracturing
operations. It is noted that as an alternative means to resist coiled tubing
collapse, an internal valve mechanism may be used to maintain the circulation
port 114 in the closed position and with positive pressure then applied to the
coiled tubing 106 using a surface pump. As an illustrative example of the
fracture treatment design for stimulation of a 15-acre size sand lens
containing
liydrocarbon gas, the first fracture stage could be comprised of "sub-stages"
as
follows: (a) 5,000 gallons of 2% KCI water; (b) 2,000 gallons of cross-linked
gel containing 1 pound-per-gallon of proppant; (c) 3,000 gallons of cross-
linked gel containing 2 pounds-per-gallon of proppant; (d) 5,000 gallons of
cross-linked gel containing 3 pounds-per-gallon of proppant; and (e) 3,000
gallons of cross-linked gel containing 4 pound-per-gallon of proppant such
that 35,000 pounds of proppant are placed into the first zone.
12. As shown in Figure 2C, all sub-stages of the first fracture operation are
completed with the creation of the first proppant fracture 232.
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13. At the end of the first stage of the stimulation treatment, should
proppant in
the wellbore prevent the coiled tubingBHA from immediate movement; fluid
can be circulated through the circulation port 114 to wash-over and clean-out
the proppant to free the coiled tubing/BHA and allow movement.
14. As shown in Figure 3A, the coiled tubing/BHA is then pulled uphole to
slightly above the second deepest target zone such that the second set of
perforation charges 146 contained on the select-fire perforating gun
system 144 are located slightly above the second deepest target zone where
again precise depth control is established based on readings from the
casing-collar-locator 128 and coiled tubing odometer systems. The action of
moving the BHA upward (to slightly above the second interval to be
perforated) will cycle the re-settable mechanical slip "continuous J"
mechanism into the pre-lock position. Further cycling of compression/tension
loads are performed to place the mechanical slip continuous J mechanism back
into the running position. The coiled tubing/BHA is then moved downward to
position the perforation charges 146 contained on the select-fire perforating
gun system 144 directly across from the second deepest target zone where
again precise depth control is established based on readings from the
casing-collar-locator 128 and coiled tubing odometer systems.
15. The second set of perforation charges 146 are selectively-fired by remote
actuation via the second select-fire head 142 to penetrate the casing 82 and
cement sheath 84 and establish hydraulic communication with the
formation 86 through the resultant perforations 240-241.
16. As shown in Figure 3B, the coiled tubing may be moved down the wellbore to
position the BHA several feet below the deepest perforation 241 of the second
target zone. Subsequent movement of the BHA up the wellbore to position the
circulation port 114 directly below the deepest perforation 241 of this second
target zone will cycle the re-settable mechanical slips 124 into the pre-lock
position, where subsequent downward motion will force the re-settable
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mechanical slips 124 into the locked position thereby preventing further
downward movement.
17. As shown in Figure 3C, downward movement engages the re-settable
mechanical slips 124 with the casing wall 82 thereby preventing further
downward movement of the BHA. A compression load on the coiled tubing is
then applied and this load closes the circulation port 114 and upper
equalization port 116, and creates pressure communication between the
inflatable, re-settable packer 120 and the internal coiled tubing pressure.
The
compression load also locks the circulation port 114 into a position directly
below the deepest perforation 241 of this second target zone (to minimize
potential for proppant fill above the inflatable, re-settable packer 120 and
minimize high velocity proppant flow past the BHA) and with the re-settable,
inflatable packer 120 positioned between the first and second perforated
intervals.
18. A further compression load is set down on the coiled tubing/BHA to test
the
re-settable mechanical slips 124 and ensure that additional downward force
does not translate into further movement of the BHA down the wellbore.
19. As shown in Figure 3D, the inflatable, re-settable packer 120 is actuated
by
pressurizing the coiled tubing 106 to effect a hydraulic seal above and below
the inflatable, re-settable packer 120. A compression load is maintained on
the
BHA to maintain pressure communication between the internal coiled tubing
pressure and the inflatable, re-settable packer 120, to keep the circulation
port 114 and the upper equalization port 116 closed, and to keep the re-
settable
mechanical slips 124 in the locked and energized position. The inflatable,
re-settable packer 120 is maintained in the actuated state by maintaining
pressure in the coiled tubing 106 via a surface pump system (it is noted that
alternatively, the inflatable, re-settable packer could be maintained in an
actuated state by locking pressure in to the element using an internal valve
remotely controlled from surface by a signaling means compatible with other
BHA components and other present signaling means).
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20. The second stage of the fracture stimulation treatment is initiated with
fluid
pumped down the annulus between the coiled tubing 106 and production
casing 82 at fracture stimulation rates while maintaining compression load on
the BHA to keep the circulation port 114 and upper equalization port 116
closed, and maintaining coiled tubing pressure at a sufficient level to resist
coiled tubing string collapse and to keep the inflatable, re-settable packer
120
inflated and serve as a hydraulic seal between the annular pressure above the
packer before, during and after the fracture operation and the sealed wellbore
pressure below the inflatable, re-settable packer.
21. All sub-stages of the fracture operation are pumped leaving a minimal
under-flush of the proppant-laden last sub-stage in the wellbore so as not to
over-displace the fracture treatment. If during the course of this treatment
stage, the seal integrity of the inflatable, re-settable packer 120 is
believed to
be compromised, the treatment stage could be temporarily suspended to test
the packer seal integrity above the highest (shallowest) existing perforations
(e.g., perforation 240 in Figure 3D) after setting the inflatable, re-settable
packer 120 in blank pipe. If the seal integrity test were to be performed, it
could be desirable to perform a circulation/washing operation to ensure any
proppant that may be present in the wellbore is circulated out of the wellbore
prior to conducting the test. The circulation/washing operation could be
performed by opening the circulation port 114 and then pumping of circulation
fluid down the coiled tubing 106 to circulate the proppant out of the
wellbore.
22. As shown in Figure 3E, all sub-stages of the second fracture operation are
completed with the creation of a second proppant fracture 242.
23. After completing the second stage fracture operation and ceasing injection
of
stimulation fluid down the annulus formed between the coiled tubing 106 and
production casing 82, a small tension load is applied to the coiled tubing 106
while maintaining internal coiled tubing pressure. The small applied tension
first isolates the inflatable, re-settable packer pressure from the coiled
tubing
pressure thereby locking pressure in the inflatable, re-settable packer 120
and
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thereby maintaining a positive pressure seal and imparting significant
resistance to axial movement of the inflatable, re-settable packer 120. In the
same motion, the applied tension may then open the circulation port 114 and
equalization port 116 thereby allowing the coiled tubing pressure to bleed off
into the annulus formed by the coiled tubing 106 and production casing 82
while simultaneously allowing the pressure above and below the inflatable,
re-settable packer 120 to equilibrate. The surface system pump providing
internal coiled tubing pressure may be stopped after equilibrating the
downhole pressures.
24. After the pressures inside the coiled tubing, in the annulus formed by the
coiled tubing 106 and production casing 82 above the inflatable, re-settable
packer 120, and in the annulus formed by the BHA aid production casing 82
below the inflatable, re-settable packer 120 equilibrate, a compressive load
placed on the coiled tubing will close the circulation port 114 and upper
equalization port 116 before releasing the pressure trapped within the
inflatable, re-settable packer 120 into the coiled tubing 106. This release of
internal pressure from the inflatable, re-settable packer 120 will allow the
inflatable, re-settable packer 120 to retract from the production casing wall,
as
shown in Figure 3F, in the absence of an external differential pressure across
the inflatable, re-settable packer 120 which could otherwise result in forces
and movement that could damage the coiled tubing 106 or BHA.
25. Once the inflatable, re-settable packer 120 is unset, as shown in Figure
3F,
tension pulled on the coiled tubingBHA could de-energize the re-settable
mechanical slips 124 thereby allowing the BHA to be free to move and be
repositioned up the wellbore.
26. If at the end of the second stage of the stimulation treatment, proppant
in the
wellbore prevents the coiled tubing/BHA from immediate movement, fluid
may be circulated through the circulation port 114 to wash-over and clean-out
the proppant to free the coiled tubingBHA and allow upward movement of the
BHA after releasing the inflatable, re-settable packer.
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27. The process as described above is repeated until all planned zones are
individually-stimulated (Figures 3A to 3F represent a BHA designed for a
three zone stimulation).
28. Upon completion of the stimulation process, the components of the BHA are
returned to running position and the coiled tubingBHA assembly is removed
from the wellbore.
29. If all the desired target zones have been stimulated, the well can be
immediately placed on production.
30. If it is desirable to stimulate additional zones, a reel of coiled tubing
may be
made-up with a slightly modified BHA. as shown in Figure 4A. In this
assembly, the only alteration to the BHA of the preferred embodiment
described above may be the addition of a select-fire-set mechanical plug 164
or select-fire set bridge-plug 164 located below the lowest select-fire gun
assembly as shown in Figure 4A. In general, the select-fire-set mechanical
plug 164 can be either a bridge plug or a fracture baffle. A fracture baffle
would generally be preferred if it is desirable to simultaneously produce
zones
separated by the plug immediately after the stiinulation job.
31. The modified BHA, shown in Figure 4A, consists of a select-fire
perforating
gun system (Figure 4A depicts a gun system comprising perforating guns 174,
184 and 194 with associated charges 176, 186 and 196 and select-fire heads
172, 182 and 192), a casing-collar-locator 128, flow ports 114, 116 and 122,
an inflatable, re-settable packer 120, a re-settable mechanical axial slip
device 124 and select-fire bridge plug 164 set using select-fire head 162. The
modified BHA is run into the well via a lubricator and the coiled tubing
injection head suspended by crane or rig above the wellhead.
32. The coiled tubingBHA is run into the well while correlating the depth with
the casing collar locator.
33. As shown in Figure 4A, the coiled tubing/modified BHA is run into the
wellbore to position the select-fire mechanical-plug 164 above the last
previously stimulated zone 252.
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34. As shown in Figure 4B the select-fire firing head 162 is fired to set the
select-fire mechanical plug 164 above the last previously stimulated zone 252.
35. After the bridge-plug select-fire head 162 is activated to set the select-
fire
bridge-plug 164, the coiled tubing/modified BHA is then raised to a location
within the wellbore such that the first (lowest) set of perforation charges
176
contained on the select-fire perforating gun system are located directly
across
the next, bottom-most target zone to be perforated where precise depth control
may be established based on readings from the casing-collar-locator 128 and
coiled tubing odometer systems located on the surface equipment. The action
of moving the BHA up to the location of the first perforated interval will
cycle
the re-settable mechanical slips 124 into the locked position and will require
cycling the coiled tubing axial load from compression to tension and back to
return the re-settable mechanical slips to running position.
36. As shown in Figure 4B, the first set of perforation charges 176 on the
modified BHA are selectively-fired by remote actuation via the second
select-fire head 172 to penetrate the casing 82 and cement sheath 84 with
perforations 270, 271 and establish hydraulic communication with the
formation 86 through the resultant perforations 270-271.
37. If there is insufficient space between the last previously placed
perforations 250, 251 and the location of the next set of perforations 270,
271
to be stimulated to enable appropriate placement of the BHA for perforation,
isolation and stimulation of the next set of perforations 270, the select-fire
bridge plug 164 may be set below the last previously stimulated
perforations 250, 251, and the inflatable, re-settable packer may be employed
during the first stimulation operation to isolate the upper-most
perforations 270, 271 from the previously stimulated perforations 250, 251.
38. The entire process as described above is then repeated as appropriate
until all
planned zones are individually-stimulated (Figure 4A and Figure 4B
represent a BHA designed for an additional three zone stimulation operation).
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It will be recognized by those skilled in the art that the preferred
suspension
method when proppant-laden fluids are involved would be conventional jointed
tubing or coiled tubing, preferably with one or more circulation ports so that
proppant
settling in the wellbore could easily be circulated out of the wellbore.
Treatments
such as acid fracturing or matrix acidizing may not require such a capability
and could
readily be perfonned with a deployment system based on cable such as slickline
or
wireline, or based on a downhole tractor system.
It will be recognized by those slcilled in the art that depending on the
objectives of a particular job, various pumping systems could be used and
could
involve the following arrangements: (a) pumping down the annulus created
between
the cable or tubing (if the deployment method uses cable or tubing) and the
casing
wall; (b) pumping down the interior of the coiled tubing or jointed tubing if
the
suspension method involves the use of coiled tubing or jointed tubing and
excess
friction and proppant erosion were not of concern for the well depths
considered; or
(c) simultaneously pumping down the annulus created between the tubing (if the
deployment method involves tubing) and the casing wall and the interior of the
tubing
if excess friction and proppant erosion were not of concern for the well
depths
considered.
Figure 5 illustrates a second embodiment of the invention where coiled tubing
is used as the deployment means and excess friction is not of concern and
either
proppant is not pumped during the job or use of proppant is not of concern.
Figure 5
shows that coiled tubing 106 is used to suspend the BHA and BHA components. In
this embodiment, the individual zones are treated in sequential order from
shallower
wellbore locations to deeper wellbore locations. In this embodiment, as shown
in
Figure 5, circulation port 114 is now placed below the inflatable, re-settable
packer 120 such that treatment fluid may be pumped down the interior of coiled
tubing 106, exit the circulation port 114, and be positively forced to enter
the targeted
perforations. As an illustration of the operations, Figure 5 shows that the
inflatable,
re-settable packer 120 has been actuated and set below perforations 241 that
are
associated with a previous zone hydraulic fracture 242. The inflatable, re-
settable
packer 120 provides hydraulic isolation such that when treatment fluid is
subsequently
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pumped down the coiled tubing 106, the treating fluid is forced to enter
previously
placed perforations 230 and 231 and create new hydraulic fractures 232. The
operations are then continued and repeated as appropriate for the desired
number of
fornlation zones and intervals.
Figure 6 illustrates a third embodiment of the invention where coiled tubing
is
used as the deployment means and excess friction is not of concern and either
proppant is not pumped during the job or use of proppant is not of concern.
Figure 6
shows that coiled tubing 106 is used to suspend the BHA and BHA components. In
this embodiment, the individual zones may be treated in any order. In this
embodiment, as shown in Figure 6, a straddle-packer inflatable sealing
mechanism 125 is used as the re-settable sealing mechanism and the circulation
port
114 is now placed between the upper inflatable sealing element 121 and the
lower
inflatable sealing element 123. When the upper inflatable sealing element 121
and the
lower inflatable sealing element 123 are actuated, treatment fluid may be
pumped
down the interior of coiled tubing 106 to exit the circulation port 114, and
then be
positively forced to enter the targeted perforations. As 'an illustration of
the
operations, Figure 6 shows that the upper inflatable sealing element 121 and
the
lower inflatable sealing element 123 have been actuated and set across
perforations 241 that are associated with the next zone to be fractured. The
inflatable,
re-settable packer 120 provides hydraulic isolation such that when treatment
fluid is
subsequently pumped down the coiled tubing 106, the treating fluid is forced
to enter
previously placed perforations 240 and 241 and create new hydraulic fractures
242.
The operations are then continued and repeated as appropriate for the desired
number
of formation zones and intervals.
Figure 7 illustrates a fourth embodiment of the invention where a wireline 102
is used as the deployment means to suspend the BHA and BHA components. In this
embodiment, the individual zones are treated in sequential order from deeper
wellbore
locations to shallower wellbore locations. In this embodiment, as shown in
Figure 7,
treatment fluid may be pumped down the annulus between the wireline 102 and
production casing wall 82 and be positively forced to enter the targeted
perforations.
In this embodiment, the inflatable re-settable packer 120 also contains an
internal
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electrical pump system 117, powered by electrical energy transmitted downhole
via
the wireline, to inflate or deflate the inflatable, re-settable packer 120
using wellbore
fluid. Figure 7 shows that the inflatable, re-settable packer 120 has been
actuated and
set below the perforations 241 that are associated with the next zone to be
fractured.
The inflatable, re-settable packer 120 provides hydraulic isolation such that
when
treatment fluid is subsequently pumped down the annulus between the wireline
102
and production casing 82, the treating fluid is forced to enter perforations
240 and 241
and create new hydraulic fractures 242. The operations are then continued and
repeated as appropriate for the desired number of formation zones and
intervals.
A fifth embodiment of the invention involves deployment of additional tubing
strings or cables, hereinafter referred to as "umbilicals", interior and/or
exterior to
coiled tubing (or jointed tubing). As shown in Figure 8A and Figure 8B, a
tubing
umbilical 104 is shown deployed in the interior of the coiled tubing 106. In
this
embodiment, the tubing umbilical 104 is connected to the re-settable sealing
mechanism 120 and in this embodiment the re-settable sealing mechanism 120 is
now
actuated via hydraulic pressure transmitted via the umbilica1104. In general,
multiple
umbilicals can be deployed either in the interior of the coiled tubing and/or
in the
annulus between the coiled tubing and production casing. In general, the
umbilicals
can be used to perform several different operations, including but not limited
to,
providing (a) llydraulic communication for actuation of individual BHA
components
including, but not limited to, the sealing mechanism and/or perforating
device; (b)
flow conduits for downhole injection or circulation of additional fluids; and
(c) for
data acquisition from downhole measurement devices. It is noted that as shown
in
Figure 8A, the BHA also includes centralizers 201, 203, and 205 that are used
to keep
the BHA centralized in the wellbore when BHA components are in the running
position.
The use of an umbilical(s) can provide the ability to hydraulically engage
and/or disengage the re-settable mechanical sealing mechanism independent of
the
hydraulic pressure condition within the coiled tubing. This then allows the
method to
be extended to use of re-settable mechanical sealing mechanisms requiring
independent hydraulic actuation for operation. Perforating devices that
require
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hydraulic pressure for selective-firing can be actuated via an umbilical. This
may then
allow the wireline, if deployed with the coiled tubing and BHA, to be used for
transmission of an additional chamel or channels of electrical signals, as may
be
desirable for acquisition of data from measurement gauges located on the
bottomhole
assembly; or actuation of other BHA components, for example, an electrical
downhole motor-drive that could provide rotation/torque for BHA components.
Alternatively, an umbilical could be used to operate a hydraulic motor for
actuation of
various downhole components (e.g., a hydraulic motor to engage or disengage
the re-
settable sealing mechanism).
The use of an umbilical(s) can provide the ability to inject or circulate any
fluid downhole to multiple locations as desired with precise control. For
example, to
help mitigate proppant settling on the sealing mechanism during a hydraulic
proppant
fracture treatment, umbilical(s) could be deployed and used to provide
independent
continuous or intermittent washing and circulation to keep proppant from
accumulating on the sealing mechanism. For example, one umbilical could run to
just
above the re-settable mechanical sealing mechanism while another is run just
below
the re-settable mechanical sealing mechanism. Then, as desired, fluid (e.g.,
nitrogen)
could be circulated downhole to either or both locations to wash the proppant
from the
region surrounding the sealing mechanism and hence mitigate the potential for
the
BHA sticking due to proppant accumulation. In the case of fluid circulation,
it is
noted that the umbilical size and fluid would be selected to ensure the
desired rate is
achieved and is not unduly limited by friction pressure in the umbilical.
In addition to umbilicals comprised of tubing strings that provide hydraulic
communication downhole as a signaling means for actuation of BHA components
(or
possibly as a signal transmission means for surface recording of downhole
gauges), in
general, one or more wireline or fiber-optic cables could be deployed in the
wellbore
to provide a electrical or electro-optical communication downhole as a
signaling
means for actuation of BHA components (or possibly as a signal transmission
means
for surface recording of downhole gauges).
Figure 9 illustrates a sixth embodiment of the invention where a tractor
system, comprised of upper tractor drive unit 131 and lower tractor drive unit
133, is
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attached to the BHA and is used to deploy and position the BHA within the
wellbore.
In this embodiment, the individual zones are treated in sequential order from
deeper
wellbore locations to shallower wellbore locations. In this embodiment, the
BHA also
contains an internal electrical pump system 117, powered by electrical energy
transmitted downhole via the wireline 102, to inflate or deflate the
inflatable,
re-settable packer 120 using wellbore fluid. In this embodiment, treatment
fluid is
pumped down the annulus between the wireline 102 and production casing wall 82
and is positively forced to enter the targeted perforations. Figure 9 shows
that the
inflatable, re-settable packer 120 has been actuated and set below the
perforations 241
that are associated with the next zone to be fractured. The inflatable, re-
settable
packer 120 provides hydraulic isolation such that when treatment fluid is
subsequently
pumped down the annulus between the wireline 102 and production casing 82, the
treating fluid is forced to enter perforations 240 and 241 and create new
hydraulic
fractures 242. The operations are then continued and repeated as appropriate
for the
desired number of formation zones and intervals.
As alternatives to this sixth embodiment, the tractor system could be
self-propelled, controlled by on-board computer systems, and carry on-board
signaling systems such that it would not be necessary to attach cable or
tubing for
positioning, control, and/or actuation of the tractor system. Furthermore, the
various
BHA components could also be controlled by on-board computer systems, and
carry
on-board signaling systems such that it is not necessary to attach cable or
tubing for
control and/or actuation of the components. For example, the tractor system
and/or
BHA components could carry on-board power sources (e.g., batteries), computer
systems, and data transmission/reception systems such that the tractor and BHA
components could either be remotely controlled from the surface by remote
signaling
means, or alternatively, the various on-board computer systems could be
pre-programmed at the surface to execute the desired sequence of operations
when the
deployed in the wellbore.
In a seventh embodiment of this invention, abrasive (or erosive) fluid jets
are
used as the means for perforating the wellbore. Abrasive (or erosive) fluid
jetting is a
common method used in the oil industry to cut and perforate downhole tubing
strings
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and other wellbore and wellhead components. The use of coiled tubing or
jointed
tubing as the BHA suspension means provides a flow conduit for deployment of
abrasive fluid-jet cutting technology. To accommodate this, the BHA is
configured
with a jetting tool. This jetting tool allows high-pressure high-velocity
abrasive (or
erosive) fluid systems or slurries to be pumped downhole through the tubing
and
through jet nozzles. The abrasive (or erosive) fluid cuts through the
production casing
wall, cement sheath, and penetrates the formation to provide flow path
communication to the formation. Arbitrary distributions of holes and slots can
be
placed using this jetting tool throughout the completion interval during the
stimulation
job. In general, abrasive (or erosive) fluid cutting and perforating can be
readily
performed under a wide range of pumping conditions, using a wide-range of
fluid
systems (water, gels, oils, and combination liquid/gas fluid systems) and with
a
variety of abrasive solid materials (sand, ceramic materials, etc.), if use of
abrasive
solid material is required for the wellbore specific perforating application.
The jetting tool replaces the conventional select-fire perforating gun system
described in the previous six embodiments, and since this jetting tool can be
on the
order of one-foot to four-feet in length, the height requirement for the
surface
lubricator system is greatly reduced (by possible up to 60-feet or greater)
when
compared to the height required when using conventional select-fire
perforating gun
assemblies as the perforating device. Reducing the height requirement for the
surface
lubricator system provides several benefits including cost reductions and
operational
time reductions.
Figure 10 illustrates in detail a seventh embodiment of the invention where a
jetting tool 310 is used as the perforating device and jointed tubing 302 is
used to
suspend the BHA in the wellbore. In this embodiment, a mechanical compression-
set,
re-settable packer 316 is used as the re-settable sealing device; a mechanical
casing-collar-locator 318 is used for BHA depth control and positioning; a one-
way
full-opening flapper-type check valve sub 304 is used to ensure fluid will not
flow up
the jointed tubing 302; a combination shear-release fishing-neck sub 306 is
used as a
safety release device; a circulation/equalization port sub 308 is used to
provide a
method for fluid circulation and also pressure equalization above and below
the
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mechanical compression-set, re-settable packer 316 under certain
circumstances; and a
one-way ball-seat check valve sub 314 is used to ensure that fluid may only
flow
upward from below the mechanical compression-set, re-settable packer 316 to
the
circulation/equalization port sub 308.
The jetting tool 310 contains jet flow ports 312 that are used to accelerate
and
direct the abrasive fluid pumped down jointed tubing 302 to jet with direct
impingement on the production casing 82. In this configuration, the mechanical
casing collar locator 318 is appropriately designed and connected to the
mechanical
coinpression-set, re-settable packer 316 such as to allow for fluid flow
upward from
below mechanical compression-set, re-settable packer 316 to the
circulation/equalization port sub 308. The cross-sectional flow area
associated with
the flow conduits contained within the circulation/equalization port sub 308
are sized
to provide a substantially larger cross-sectional flow area than the flow area
associated
with the jet flow ports 312 such that the majority of flow within the jointed
tubing 302
or BHA preferentially flows through the circulation/equalization port sub 308
rather
than the jet flow ports 312 when the circulation/equalization port sub 308 is
in the
open position. The circulation/equalization port sub 308 is opened and closed
by
upward and downward axial movement ofjointed pipe 302.
In this embodiment, jointed tubing 302 is preferably used with the mechanical
compression-set, re-settable paclcer 316 since the mechanical compression-set,
re-
settable packer 316 can be readily actuated and de-actuated by vertical
movement
and/or rotation applied via the jointed tubing 302. Vertical movement and/or
rotation
is applied via the jointed tubing 302 using a completion rig-assisted snubbing
unit
with the aid of a power swivel unit as the surface means for connection,
installation,
and removal of the jointed tubing 302 in to and out of the wellbore. It is
noted that
the surface hardware, methods, and procedures associated with use of a
completion
rig-assisted snubbing unit with a power swivel unit are common and well-known
to
those skilled in the art for connection, installation, and removal of jointed
tubing
in/from a wellbore under pressure. Alternatively, use of a completion rig with
the aid
of a power swivel unit, and stripping head in place of the snubbing unit,
could
accommodate connection, installation, and removal of the jointed tubing
in/from a
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wellbore under pressure; again this is common and well-known to those skilled
in the
art for connection, installation, and removal ofjointed tubing in/from a
wellbore under
pressure. It is further noted that the surface rig-up and plumbing
configuration will
include appropriate manifolds, piping, and valves to accommodate flow to,
from, and
between all appropriate surface components/facilities and the wellbore,
including but
not limited to, the jointed tubing, annulus between jointed tubing and
production
casing, pumps, fluid tanks, and flow-back pits.
Since the mechanical compression-set, re-settable packer is actuated via
jointed tubing 302 vertical movement and/or rotation, fluid can be pumped down
the
jointed tubing 302 without the necessity of additional control valves and/or
isolation
valves that may otherwise be required if an inflatable paclcer was used as the
re-
settable sealing device. The interior of the jointed tubing 302 is used in
this fashion to
provide an independent flow conduit between the surface and the jetting tool
310 such
that abrasive fluid can be pumped down the jointed tubing 302 to the jetting
too1310.
The jet flow ports 312 located on the jetting tool 310 then create a high
velocity
abrasive fluid jet that is directed to perforate the production casing 82 and
cement
sheatli 84 to establish hydraulic communication with the formation 86.
Figure 10 shows the jetting tool 310 has been used to place perforations 320
to penetrate the first formation interval of interest, and that the first
formation interval
of interest has been stimulated with hydraulic fractures 322. Figure 10
further shows
the jetting tool 310 has been repositioned within the wellbore and used to
place
perforations 324 in the second formation interval of interest, and that the
mechanical
compression-set, re-settable packer 316 has been actuated to provide a
hydraulic seal
within the wellbore in advance of stimulating perforations 324 with the second
stage
of the multi-stage hydraulic proppant fracture treatment.
It is noted that the jet flow ports 312 may be located within approximately
six-
inches to one-foot of the mechanical compression-set, re-settable packer 316
such that
after pumping the second proppant fracture stage, should proppant accumulation
on
the top of the mechanical compression-set, re-settable packer 316 be of
concern, non-
abrasive and non-erosive fluid can be pumped down the jointed tubing 302 and
through the jet flow ports 312 and/or the circulation/equalization port sub
308 as
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necessary to clean proppant from the top of the mechanical compression-set,
re-settable packer 316. Furthermore, the jetting tool 310 may be rotated (when
the
mechanical compression-set, re-settable packer 316 is not actuated) using the
jointed
tubing 302 which may be rotated with the surface power swivel unit to further
help to
clean proppant accumulation that may occur above the mechanical compression-
set,
re-settable packer 316. Since the perforations are created using a fluid jet,
perforation
burrs will not be created. Since perforation burrs are not present to
potentially
provide additional wear and tear on the elastomers of the mechanical
compression-set
re-settable packer 316, the longevity of the mechanical compression-set re-
settable
packer 316 may be increased when compared to applications where perforation
burrs
may exist.
It is fiirther noted that the flow control provided by the one-way ball-seat
checlc valve sub 314 and the one-way full-opening flapper-type check valve sub
304
only allows for pressure equalization above and below the mechanical
compression-set, re-settable packer 316 when the pressure below the mechanical
compression-set, re-settable packer 316 is larger than the pressure above the
mechanical compression-set, re-settable packer 316. In circuinstances when the
pressure above the mechanical compression-set, re-settable packer 316 may be
larger
than the pressure below the mechanical compression-set, re-settable packer
316, the
pressure above the mechanical compression-set, re-settable packer 316 can be
readily
reduced by performing a controlled flow-back of the just stimulated zone using
the
annulus between the jointed tubing 302 and the production casing 82; or by
circulation of lower density fluid (e.g., nitrogen) down the jointed tubing
302 and up
the annulus between the jointed tubing 302 and production casing 82.
The one-way full-opening flapper-type check valve sub 304 is preferred as this
type of design accommodates unrestricted pumping of abrasive (or erosive)
fluid
downhole, and furthermore allows for passage of control balls that, depending
on the
specific detailed design of individual BHA components, may be dropped from the
surface to control fluid flow and hydraulics of individual BHA components or
provide
for safety release of the BHA. Depending on the specific tool design, many
different
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valving configurations could be deployed to provide the functionality provided
by the
flow control valves described in this embodiment.
As alternatives to this seventh embodiment, a sub containing a nipple could be
included which could provide the capability of suspending and holding other
measurement devices or BHA components. This nipple, for example, could hold a
conventional casing-collar-locator and gamma-ray tool that is deployed via
wireline
and seated in the nipple to provide additional diagnostics of BHA position and
location of formation intervals of interest. Additionally, multiple abrasive
jetting
tools can be deployed as part of the BHA to control perforation cutting
characteristics,
such as hole/slot size, cutting rate, to accommodate various abrasive
materials, and/or
to provide system redundancy in the event of premature component failure.
It will be recognized by those skilled in the art that many different
components
can be deployed as part of the bottomhole assembly. The bottomhole assembly
may
be configured to contain instrumentation for measurement of reservoir, fluid,
and
wellbore properties as deeined desirable for a given application. For example,
temperature and pressure gauges could be deployed to measure downhole fluid
temperature and pressure conditions during the course of the treatment; a
densitometer
could be used to measure effective downhole fluid density (which would be
particularly useful for determining the downhole distribution and location of
proppant
during the course of a hydraulic proppant fracture treatment); and a
radioactive
detector system (e.g., gamma-ray or neutron measurement systems) could be used
for
locating hydrocarbon bearing zones or identifying or locating radioactive
material
within the wellbore or formation.
Depending on the specific bottomhole assembly components and whether the
perforating device creates perforation holes with burrs that may damage the
sealing
mechanism, the bottomhole assembly could be configured witli a "perforation
burr
removal" tool that would act to scrape and remove perforation burrs from the
casing
wall.
Depending on the specific bottomhole assembly components and whether
excessive wear of bottomhole assembly components may occur if the assembly is
run
in contact with the casing wall, centralizer subs could be deployed on the
bottomhole
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assembly to provide positive mechanical positioning of the assembly and
prevent or
minimize the potential for damage due to the assembly running in contact with
the
casing wall.
Depending on the specific bottomhole assembly components and whether the
perforation charges create severe shock waves and induce undue vibrations when
fired, the bottomhole assembly may be configured with vibration/shock
dampening
subs that would eliminate or minimize any adverse effects on system
performance due
to perforation charge detonation.
Depending on the deployment system used and the objectives of a particular
job, perforating devices and any other desired BHA components may be
positioned
either above or below the re-settable sealing mechanism and in any desired
order
relative to each other. The deployinent system itself, whether it be wireline,
electric
line, coiled tubing, conventional jointed tubing, or downhole tractor may be
used to
convey signals to activate the sealing mechanism and/or perforating device. It
would
also be possible to suspend such signaling means within conventional jointed
tubing
or coiled tubing used to suspend the sealing and perforating devices
themselves.
Alternatively, the signaling means, whether it be electric, hydraulic, or
other means,
could be run in the hole externally to the suspension means or even housed in
or
comprised of one or more separate strings of coiled tubing or conventional
jointed
tubing.
With respect to treatments that use high viscosity fluid systems in wells
deeper
than about 8,000 feet, several major teclinological and economic benefits are
immediately derived from application of this new invention. Reducing the
friction
pressure limitations allows treatment of deeper wells and reduces the
requirement for
special fracture fluid formulations. Friction pressure limitations are reduced
or
eliminated because the high viscosity fluid can be pumped down the annulus
between
the coiled tubing or other suspension means and production casing. Since
friction
pressure limitations can be reduced or eliminated from that experienced with
pumping
high viscosity fluid systems down the interior of coiled tubing, well depths
where this
technique can be applied are substantially increased. For example, assuming
1-1/2-inch coiled tubing deployed in a 5-1/2-inch outer diameter 17-pound-per-
foot
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casing, the effective cross-sectional flow area is approximately equivalent to
a 5-inch
outer diameter casing string. With this effective cross-sectional flow area,
well depths
on the order of 20,000 feet or greater could be treated and higher pump rates
(e.g., on
the order of 10 to 30-barrels-per-minute or more) could be achieved for
effective
proppant transport and hydraulic fracturing using high viscosity fluids.
Since the annulus typically may have greater equivalent flow area,
conventional fracturing fluids can be used, as opposed to special low-
viscosity fluids
(such as Dowell-Schlumberger's C1earFracTM fluid) used to reduce friction
pressure
drop through coiled tubing. The use of conventional fracturing fluid
technology
would then allow treatment of formations with temperatures greater than 250 F,
above
which currently available higher-cost specialty fluids may begin to degrade.
The sealing mechanism used could be an inflatable device, a mechanical
compression-set re-settable packer, a mechanical compression-set straddle-
packer
design, cup-seal devices, or any other alternative device that may be deployed
via a
suspension means and provides a re-settable hydraulic sealing capability or
equivalent
fun.ction. Both inflatable and compression set devices exist that provide
radial
clearance between seals and casing wall (e.g., on the order of 0.25-inches to
1-inch for
inflatable devices or 0.1 - 0.2 inches for compression-set devices) such that
seal wear
and tear would be drastically reduced or eliminated altogether. In a preferred
embodiment of this invention, there would be sufficient clearance between the
sealing
mechanism in its deactivated state and the casing wall to allow rapid movement
into
and out of the wellbore without significant damage to the sealing mechanism or
without pressure control issues related to surging/swabbing the well due to
tool
movement. The increased clearance between the seal surface and the casing wall
(when the seal is not actuated) would also allow the coiled tubing/BHA to be
tripped
in and out of the hole at much faster speeds than are possible with currently
available
coiled tubing systeins. In addition, to minimize potential undesirable seal
wear and
tear, in a preferred embodiment, the perforating device would accommodate
perforating the casing wall such that a perforation hole with a relatively
smooth edge
would be achieved. Alternatively, the mechanical re-settable sealing mechanism
may
not need to provide a perfect hydraulic seal and for,example, could retain a
small gap
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around the circumference of the device. This small gap could be sized to
provide a
sealing mechanism (if desired) whereby proppant bridges across the small gap
and
provides a seal (if desired) that can be removed by fluid circulation.
Furthermore
depending on the specific application, it is possible that a stimulation job
could
proceed in an economically viable fashion even if a perfect hydraulic seal was
not
obtained with the mechanical re-settable sealing mechanism.
Since the perforating device is deployed siinultaneously with the re-settable
sealing mechanism, all components can be depth controlled at the same time by
the
same measurement standard. This eliminates depth control problems that
existing
methods experience when perforation operations and stimulation operations are
performed using two different measurement systems at different times and
different
wellbore trips. Very precise depth control can be achieved by use of a casing-
collar-
locator, which is the preferred method of depth control.
The gross height of each of the individual perforated target intervals is not
limited. This is in contrast to the problem that existing coiled tubing
systems possess
using a straddle-packer like device that limits application to 15 - 30 feet of
perforated
interval height.
Since permanent bridge plugs are not necessarily used, the incremental cost
and wellbore risk associated with bridge plug drill-out operations is
eliminated.
If coiled tubing is used as the deployment means, it is possible that the
coiled
tubing string used for the stimulation job could be hung-off in the wellhead
and used
as the production tubing string, wliich could result in significant cost
savings by
eliminating the need for rig mobilization to the well-site for installation of
conventional production tubing string comprised ofjointed tubing.
Controlling the sequence of zones to be treated allows the design of
individual
treatment stages to be optimized based on the characteristics of each
individual zone.
Furthermore, the potential for sub-optimal stimulation because multiple zones
are
treated simultaneously is essentially eliminated by having only one open set
of
perforations exposed to each stage of treatment. For example, in the case of
hydraulic
fracturing, this invention may minimize the potential for overflush or sub-
optimal
placement of proppant into the fracture. Also, if a problem occurs such that
the
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treatment must be terminated, the up-hole zones to be stimulated have not been
compromised, since they have yet to be perforated. This is in contrast to
conventional
ball sealer or coiled tubing stimulation methods, where all perforations must
be shot
prior to the job. Should the conventional coiled tubing job fail, it may be
extremely
difficult to effectively divert and stimulate over a long completion interval.
Additionally, if only one set of perforations is open above the sealing
element, fluid
can be circulated without the possibility of breaking down the other multiple
sets of
open perforations above the top sealing element as could occur in the
conventional
coiled tubing job. This can minimize or eliminate fluid loss and damage to the
formation when the bottomhole circulation pressure would otherwise exceed the
formation pore pressure.
The entire treatment can be pumped in a single trip, resulting in significant
cost savings over other techniques that require multiple wireline or rig work
to trip in
and out of the hole in between treatment stages.
The invention can be applied to multi-stage treatments in deviated and
horizontal wellbores. Typically, other conventional diversion technology in
deviated
and horizontal wellbores is more challenging because of the nature of the
fluid
transport of the diverter material over the long intervals typically
associated with
deviated or horizontal wellbores.
Should a screen-out occur during the fracture treatment, the invention
provides
a metliod for sand-laden fluid in the annulus to be immediately circulated out
of the
hole such that stimulation operations can be recommenced without having to
trip the
coiled tubing/BHA out of the hole. The presence of the coiled tubing system
provides
a means to measure bottomhole pressure after perforating or during stimulation
operations based on pressure calculations involving the coiled tubing string
under
shut-in (or low-flow-rate) conditions.
The presence of the coiled tubing or conventional jointed tubing system, if
used as the deployment means, provides a means to inject fluid downhole
independently from the fluid injected in the annulus. This may be useful, for
example, in additional applications such as: (a) keeping the BHA sealing
mechanism
and flow ports clean of proppant accumulation (that could possibly cause tool
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sticking) by pumping fluid downhole at a nominal rate to clean off the sealing
mechanism and flow ports; (b) downhole mixing applications (as discussed
further
below); (c) spotting of acid downhole during perforating to aid perforation
hole clean-
up and communication with the formation; and (d) independently stimulating two
zones isolated from each other by the re-settable sealing mechanism. As such,
if
tubing is used as the deployment means, depending on the specific operations
desired
and the specific bottonihole assembly components, fluid could be circulated
downhole
at all times; or only when the sealing element is energized, or only when the
sealing
element is not energized; or while equalization ports are open or closed.
Depending
on the specific bottomhole assembly components and the specific design of
downhole
flow control valves, as may be used for example as integral components of
equalization ports subs, circulation port subs or flow port subs, downhole
flow control
valves may be operated by wireline actuation, hydraulic actuation, flow
actuation,
"j-latch" actuated, sliding-sleeve actuated, or by many other means known to
those
skilled in the art of operation and actuation of downhole flow control valves.
The coiled tubing system still allows for controlled flowback of individual
treatment stages to aid clean up and assist fracture closure. Flowback can be
performed up the aimulus between the coiled tubing and the production casing,
or
alternatively, flowback may even be performed up the coiled tubing string if
excessive
proppant flowback were not to be considered a problem.
The perforating device may be comprised of commercially-available
perforating systems. These gun systems could include what will be referred to
herein
as a "select-fire" system such that a single perforation gun assembly is
comprised of
multiple charges or sets of perforation charges. Each individual set of one or
more
perforation charges can be remotely controlled and fired from the surface
using
electric, radio, pressure, fiber-optic or other actuation signals. Each set of
perforation
charges can be designed (number of charges, number of shots per foot, hole
size,
penetration characteristics) for optimal perforation of the individual zone
that is to be
treated with an individual stage. Witli current select-fire gun technology,
commercial
gun systems exist that could allow on the order of 30 to 40 intervals to be
perforated
sequentially in a single downhole trip. Guns can be pre-sized and designed to
provide
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for firing of multiple sets of perforations. Guns can be located at any
location on the
bottomhole assembly, including either above or below the mechanical re-
settable
sealing mechanism.
Intervals may be grouped for treatment based on reservoir properties,
treatment design considerations, or equipment limitations. After each group of
intervals (preferably 5 to approximately 20), at the end of a workday (often
defined by
lighting conditions), or if difficulties with sealing one or more zones are
encountered,
a bridge plug or other mechanical device would preferably be used to isolate
the group
of intervals already treated from the next group to be treated. One or more
select-fire
set bridge plugs or fracture baffles could be run in conjunction with the
bottomhole
assembly and set as desired during the course of the completion operation to
provide
positive mechanical isolation between perforated intervals and eliminate the
need for a
separate wireline run to set mechanical isolation devices or diversion agents
between
groups of fracture stages.
In general, the inventive method can be readily employed in production
casings of 4-1/2 inch diameter to 7-inch diameter with existing commercially
available perforating gun systems and mechanical re-settable sealing
mechanisms.
The inventive method could be employed in smaller or larger casings with
mechanical
re-settable sealing mechanisms appropriately designed for the smaller or
larger
casings.
If select-fire perforating guns are used, 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 at shot density ranging between 1 and 6 shots per
foot, but
preferably 2 to 4 shots per foot. In a preferred embodiment, as many as 15 to
20
individual guns could be stacked one on top of another such that the assembled
gun
system total length is preferably kept to less than approximately 80 to 100
feet. This
total gun length can be run into the wellbore using a readily-available
surface crane
and lubricator system. Longer gun lengths could also be used, but may require
additional or special surface equipment depending on the total number of guns
that
would make up the complete perforating device. It is noted that in some unique
applications, gun lengths, number of charges per gun, and shot density could
be
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greater or less than as specified above as final perforating system design
would be
impacted by the specific formation characteristics present in the wellbore to
stimulated
In order to minimize the total length of the gun system and BHA, it may be
desirable to use multiple (two or more) charge carriers uniformly distributed
around
and strapped, welded, or otherwise attached to the coiled tubing or connected
below
the mechanical re-settable sealing mechanism. For exainple, if it were desired
to
stimulate 30 zones, where each zone is perforated with a 4-ft gun, a single
gun
assembly would result in a total length of approximately 150 feet, which may
be
impractical to handle at the surface. Alternatively, two gun assemblies
located
opposite one anotlier on the coiled tubing could be deployed, where each
assembly
could contain 15 guns, and total length could be approximately 75-feet, which
could
readily be handled at the surface with existing lubricator and crane systems.
An alternative arrangement for the perforating gun or guns would be to locate
one or more guns above the re-settable mechanical sealing mechanism. There
could
be two or more separate gun assemblies attached in such a way that the charges
were
oriented away from the components on the bottomhole assembly or the coiled
tubing.
It could also be a single assembly with charges loaded more densely and firing
mechanisms designed to simultaneously fire only a subset of the charges within
a
given interval, perhaps all at a given phase orientation.
Although the perforating device described in this embodiment used remotely
fired charges or fluid jetting to perforate the casing and cement sheath,
alternative
perforating devices including but not limited to chemical dissolution or
drilling/milling cutting devices could be used within the scope of this
invention for
the purpose of creating a flow path between the wellbore and the surrounding
formation. For the purposes of this invention, the term "perforating device"
will be
used broadly to include all of the above, as well as any actuating device
suspended in
the wellbore for the purpose of actuating charges or other perforating means
that may
be conveyed by the casing or other means external to the bottomhole assembly
or
suspension method used to support the bottomhole assembly.
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The BHA could contain a downhole motor or other mechanism to provide
rotation/torque to accommodate actuation of mechanical sealing mechanisms
requiring rotation/torque for actuation. Such a device, in conjunction with an
orienting device (e.g., gyroscope or compass) could allow oriented perforating
such
that perforation holes are placed in a preferred compass direction.
Alternatively, if
conventional jointed tubing were to be used, it is possible that rotation and
torque
could be transmitted downhole by direct rotation of the jointed tubing using
rotation
drive equipment that may be readily available on conventional workover rigs.
Downhole instrumentation gauges for measurement of well conditions (casing
collar
locator, pressure, temperature, pressure, and other measurement gauges) for
real-time
downhole monitoring of stimulation job paraineters, reservoir properties,
and/or well
performance could also be deployed as part of the BHA.
In addition to the re-settable mechanical diversion device, other diversion
material/devices could be pumped downhole during the treatment including but
not
limited to ball sealers or particulates such as sand, ceramic material,
proppant, salt,
waxes, resins, or other organic or inorganic compounds or by alternative fluid
systems
such as viscosified fluids, gelled fluids, foams, or other chemically
formulated fluids.
or other injectable diversion agents. The additional diversion material could
be used
to help minimize the duration of the stimulation treatment as some time
savings could
be realized by reducing the number of times the mechanical diversion device is
set,
while still achieving diversion capabilities over the multiple zones. For
example in a
3,000 foot interval where individual zones nominally 100 feet apart are to be
treated,
it may be desirable to use the re-settable mechanical diversion device working
in 500
foot increments uphole, and then divert each of the six stages with a
diverting agent
carried in the treating fluid. Alternatively, limited entry techniques could
be used for
multiple intervals as a subset of the gross interval desired to be treated.
Either of
these variations would decrease the number of mechanical sets of the
mechanical
diversion device and possibly extend its effective life.
If a tubing string is used as the deployment meais, the tubing allows for
deployment of downhole mixing devices and ready application of downhole mixing
technology. Specifically, the tubing string can be used to pump chemicals
downhole
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and through the flow ports in the bottomhole assembly to subsequently mix with
the
fluid pumped in the tubing by production casing annulus. For example, during a
hydraulic fracturing treatment, it may be desirable to pump nitrogen or carbon
dioxide
downhole in the tubing and have it mix with the treatment fluid downhole, such
that
nitrogen-assisted or carbon dioxide-assisted flowback can be accommodated.
This method and apparatus could be used for treatinent of vertical, deviated,
or
horizontal wellbores. For example, the invention provides a method to generate
multiple vertical (or somewhat vertical) fractures to intersect horizontal or
deviated
wellbores. Such a technique could enable economic completion of multiple wells
from a single pad location. Treatment of a multi-lateral well could also be
performed
wherein the deepest lateral is treated first; then a plug is set or sleeve
actuated to
isolate this lowest lateral; the next up-hole lateral is then treated; another
plug is set or
sleeve actuated to isolate this lateral; and the process repeated to treat the
desired
number of laterals within a single wellbore.
If select-fire perforating guns are used, although desirable from the
standpoint
of maximizing the number of intervals that can be treated, the use of short
guns
(i.e., 4-ft length or less) could limit well productivity in some instances by
inducing
increased pressure drop in the near-wellbore reservoir region when compared to
use of
longer guns. Well productivity could similarly be limited if only a short
interval
(i.e., 4-ft length or less) is perforated using abrasive jetting. Potential
for excessive
proppant flowback may also be increased leading to reduced stimulation
effectiveness.
Flowback would preferably be performed at a controlled low-rate to limit
potential
proppant flowback. Depending on flowback results, resin-coated proppant or
alternative gun configurations could be used to improve the stimulation
effectiveness.
In addition, if tubing or cable are used as the deployment means to help
mitigate potential undesirable proppant erosion on the tubing or cable from
direct
impingement of the proppant-laden fluid when pumped into the side-outlet
injection
ports, an "isolation device" can be rigged up on the wellhead. The isolation
device
may consists of a flange with a short length of tubing attached that runs down
the
center of the wellhead to a few feet below the injection ports. The bottomhole
assembly and tubing or cable are run interior to the isolation device tubing.
Thus the
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tubing of the isolation device deflects the proppant and isolates the tubing
or cable
from direct impingement of proppant. Such an isolation device would consist of
an
appropriate diameter tubing such that it would readily allow the largest outer
diameter
dimension associated with the tubing or cable and bottomhole assembly to pass
through unhindered. The length of the isolation device would be sized such
that in the
event of damage, the lower master fracture valve could still be closed and the
wellhead rigged down as necessary to remove the isolation tool. Depending on
the
stimulation fluids and the method of injection, an isolation device would not
be
needed if erosion concerns were not present. Although field tests of isolation
devices
have shown no erosion problems, depending on the job design, there could be
some
risk of erosion damage to the isolation tool tubing assembly resulting in
difficulty
removing it. If an isolation tool is used, preferred practices would be to
maintain
impingement velocity on the isolation tool substantially below typical
erosional
limits, preferably below about 180 ft/sec, and more preferably below about 60
ft/sec.
Another concern with this technique is that premature screen-out may occur if
fluid displacement during pumping is not adequately measured as it may be
difficult
to initiate a fracture with proppant-laden fluid across the next zone to be
perforated. It
may be preferable to use a KCl fluid or some other non-gelled fluid or fluid
system for
the pad rather than a gelled pad fluid to better initiate fracturing of the
next zone.
Pumping the job at a higher rate with a non-gelled fluid between stages to
achieve
turbulent flush/sweep of the casing will minimize the risk of proppant screen-
out.
Also, contingency guns available on the tool string would allow continuing the
job
after an appropriate wait time.
Although the embodiments discussed above are primarily related to the
beneficial effects of the inventive process when applied to hydraulic
fracturing
processes, this sliould not be interpreted to limit the claimed invention
which is
applicable to any situation in which perforating and performing other wellbore
operations in a single trip is beneficial. Those skilled in the art will
recognize that
many variations not specifically mentioned in the examples will be equivalent
in
function for the purposes of this invention.
