Note: Descriptions are shown in the official language in which they were submitted.
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Agent File No. 53170-06
TITLE: Treatment String and Method of Use Thereof
FIELD OF THE INVENTION
The present invention relates to hydraulic or mechanical completion
equipment for wellbores in general, and in particular relates to equipment for
circulating fluids in fracturing and stimulating subterranean formations
bearing oil
or gas.
BACKGROUND OF THE INVENTION
If a hydrocarbon bearing subterranean formation either lacks permeability
or flow capacity for cost effective recovery of the hydrocarbon, then it is
common
practice to use hydraulic fracturing or other treatement of the formation to
increase the flow of the hydrocarbon, typically oil or gas. This method of
stimulation creates flow channels for the hydrocarbon to escape the formation
into a wellbore penetrating the formation, to mainatin well production.
The wellbore typically consists of a metal pipe, commonly known as a
"casing", "production casing", "wellbore liner" or "completion string", which
is
deployed into the borehole and is cemented into place. Fracturing of the
formation occurs when a treatment fluid is pumped under high pressure into the
casing, usually via a tubular treatment string run inside the casing, and is
ejected
through holes in the casing, and through the cement, into the formation to
cause
fractures in its strata. The treatment fluid carries a proppant, such as sand
or the
like, which penetrates the fractures to hold them open after the treatment
fluid
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pressure is released, and can include additives such as acids. Alternatively,
the
formating maybe treated by by injection of fluids at lower pressures than
fracturing, to stimulate the formation without causing fractures in the
strata.
In many fracking or treatement situations, a first treatment fluid is first
pumped down the inner bore of the tubular treatment string and out through
ported assemblies on the treatment string. The ported subs are preferably
isolated from other stages of the formation by an isolation device to ensure
that
the first treatement fluid is directed to the desired zone of the formation to
be
stimulated. The isolation device seals against casing to prevent fluid from
flowing
into the annulus between the treatment string and the casing, and out of the
isolated stage. In a next step, second treatment fluids are pumped down the
well
to frac or otherwise treat or stimulate the formation.
When the isolated zone has been treated, flow of treatment fluids is
reduced or stopped entirely and the treatment string is relased and moved
either
uphole or downhole to thenext zone to be treated.
SUMMARY OF THE PRESENT INVENTION
A tubular member is presented for treating a subterranean formation, the
tubular
member being insertable in a wellbore intersecting the subterranean formation
and adapted to receive a treatment fluid under pressure. The tubular member
comprises at least one assembly having at least one port; a straddle system
comprising an upper packer uphole of the at least one assembly and a lower
packer downhole of the at least one assembly to isolate an annular interval
adjacent the ported assembly between the tubular member and the wellbore;
and at least one flow diverter valve positioned uphole from the upper packer
for
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diverting fluid from within the tubular member through an annulus between the
tubular member and the wellbore to surface.
A method is further provided for treating a subteranian formation. The method
comprises inserting a tubular member into a wellbore intersecting the
subterranean formation, the tubular member being adapted to receive a
treatment fluid under pressure and comprising at least one ported assembly and
one or more flow diverter valves positioned uphole of said ported assembly;
setting an isolation device in an annulus between the tubular member and the
wellbore for hydraulically isolating intervals in the annulus at locations
adjacent
io the at least one ported assembly; flowing a first treatment fluid under
pressure
into the at least one isloated ported assembly to treat the formation in the
isolated interval of the wellbore by pressurized treatment fluid flowing from
the
ported assembly; opening one or more flow diverter valves positioned uphole of
the isolated assembly; and diverting the first treatment fluid from within the
tubular member through the flow diverter valve, through the annulus to
surface.
A further method is provided for treating a subteranian formation, the method
comprising: inserting a tubular member into a wellbore intersecting the
subterranean formation, the tubular member being adapted to receive a
treatment fluid under pressure and comprising plurality of ported assemblies
spaced at intervals along a length of the tubular member and one or more flow
diverter valves positioned uphole of each of said ported assemblies; setting
an
isolation device to hydraulically isolate a first at least one interval in the
annulus,
said first at least one interval having at least one first ported assembly
positioned
therein; flowing treatment fluid under pressure through the first ported
assembly
and and allowing treatment of the formation in the first isolated interval of
the
wellbore by the pressurized treatment fluid;releasing treatment fluid
pressure;
and repeating the steps of: i. opening one or more flow diverter valves
positioned
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uphole of the isolated interval; ii. diverting treatment fluid from within the
tubular
member through the one or more flow diverter valves into the annulus uphole of
the isolated interval, to equalize annular pressure above the isolated
interval with
annular pressure within the isolated interval; iii. initiating movement of
tubular
member to a subesquent interval of the wellbore, said subsequent interval
comprising at least one subsequent ported assembly; iv. setting the isolation
device to hydraulically isolate the subsequent at least one interval in the
annulus;
v. flowing treatment fluid under pressure through the at least one subesquent
ported assembly to the formation in the isolated subsequent intervals of the
wellbore by the pressurized treatment fluid; and vi. releasing treatment fluid
pressure.
A method is further provided for treating one or more isolated intervals of a
subteranian formation. The method comprises flowing treatment fluid under
pressure through a first ported assembly on a tubular member and and allowing
is treatment of the formation in a first isolated interval by the
pressurized treatment
fluid; moving the tubular member to a subesquent interval of the wellbore,
said
subsequent interval comprising at least one subsequent ported assembly; and
simulataneously circulating treatment fluid from within the tubular member
through one or more flow diverter valves into an annulus uphole of the first
isolated interval while moving the tubular member.
BRIEF DESCRIPTION OF THE DRAWING FIGURES
Embodiments of the invention will now be described, by way of example
only, with reference to the accompanying drawings, wherein:
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Figures la to 1m illustrate in cross-section an environment and a method of
fracing or treating a formation using a treatment string within a production
casing
according to an embodiment of the present invention;
Figure 2 is an elevation view of a treatment string with a ported assembly and
a
flow diverter valve of the present invention; and
Figure 31s a process diagram illustrating a first method of the present
invention;
Figure 4 is a process diagram illustrating a second method of the present
invention; and
Figure 5 is a process diagram illustrating a third method of the present
invention.
DESCRIPTION OF PREFERRED EMBODIMENTS
Although the device and method of the present invention may be
employed for various types of wells and completion procedures, such as with
open hole packers in an uncemented well, a horizontal cemented well will be
referred to herein for illustartive purposes.
With reference to Figures la to 1m, a production casing 16, also known
as a completion string or wellbore liner, is inserted, or tripped, into the
wellbore
10 to its terminus 11. An annular space 18, or annulus, is formed between the
casing 16 and the wall of the wellbore 10. The production casing 16 may be
zo considered a tubular member capable of flowing or communicating fluids
under
pressure along the wellbore.
Assemblies 20 are employed to join segments 17 of the production
casing. Alternately, if no pipe segments are to be employed and the assemblies
are to be joined directly, then the assemblies 20 may have cooperative thread
patterns, or alternate joining means.
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The asemblies are preferably ported assemblies 20 having one or more
ports 28. In some cases, the assemblies 20 are of the form of a "burstable
disk", also known as a "rupture disk" or "burst disk". The disk has a rupture
pressure threshold, and is located to block the flow of fluids through the
hole
while intact. Once the treatment fluid pressure reaches this threshold, the
disk
bursts to allow the treatment fluid to escape through the casing hole and
fracture
the formation strata.
Alternatively, some ported assemblies 20 provide a means of sealing a
port 28 in a completion string from fluid flow therethrough when the insert is
io intact.
Further alternatively, the ported assemblies 20 may have shiftable sleeves
that can be opened and closed by any number of means including, but not
limited to hydraulic pressure acting on the sleeve or by mechanical actuation
of
an intervention tool that is deployed by coiled tubing, wireline or other
means
downhole to engage and move the sleeve to open the port 28.
A method of sequential fluid treatment of multiple intervals with a tubular
member in a wellbore is now described. Cement is pumped down the production
casing 16 and through each of the ported assemblies 20. The cement continues
to be pumped until it exits the production casing near the wellbore terminus
11
and begins to fill the annulus 18, including around the collars 20 (fig.1e).
Pumping of the cement is accomplished with a tubular pumping member 112
that pushes the cement down the production casing until it reaches the
terminus
11, at which point the cement has been largely evacuated from the production
casing into the annulus past each of the ported assemblies 20 (fig.1f). The
operator can then slightly pressure-up the casing string to ensure all of the
cement has been evacuated from the casing, sometimes referred to as "bumping
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up the wiper plug". Once the cement sets to securely bond the production
casing
in the wellbore, the well is ready to be completed.
Completion of the well requires, in this example, a coil fracturing or
treatement system where a tubular member preferably in the form of a treatment
string 114 is tripped down the production casing 16 (fig.1g). The treatment
string
114 is located so as to position an isolation device 106 in a manner which
fluidly
isolates a given interval 116 of the production casing.
Preferably a packer/cup or cup/cup type straddle system 106 is employed
as the isolation device to isolate a first ported assembly 20a, referred to
herein
io as the first stage. A treatment fluid is then injected under pressure
into the
isolated interval 116 of the ported assembly. When a threshold pressure is
reached, the treatment fluid exits through the first ported assembly 20a to
initiate
the fracing or other treatment process. The fracing or treatement process
continues in the vicinity of the first ported assembly 20a as the pressurized
treatment fluid (indicated by 119 in fig.1i) exits the ports 28 and through
the initial
cracks to propagate further cracking 120 or to treat or stimulate the
formation.
Once the fracing or treating process is completed for the first stage, the
pressure on the treatment fluid is released and the treatment string is moved
back to create a further isolated interval 120 straddling the a subsequent
ported
assembly 20b (fig.1j), and the above fracing or treating process is followed
for
this second stage. This process is repeated for each stage (fig.1k) until the
last
stage (20f in fig.1L) is completed and the treatment string is rigged out. The
well
is then ready for production by flowing the target fluid (14 in fig 1m) from
the
formation through the many ports and up the production casing to surface.
A further preferred embodiment of the invention is illustrated in Figure 2.
In many fracking or stimulation situations, a first treatment fluid such as
water is
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first pumped down the inner bore of the production string 114 and out through
ported assemblies 20. The ported assemblies 20 are preferably isolated from
other stages of the formation by an isolation device 106, preferably in the
form of
a cup/packer or cup/cup type straddle system 106, comprising an upper packer
106a uphole of the ported assembly 20 and a lower packer 106b downhole of
the ported assembly 20, to ensure that the first treatment fluid is directed
to the
isolated stage 116 of the formation to be stimulated. The straddle system 106
seals against casing 16 to prevent fluid from flowing into the annulus 18
outside
of the isolated stage 116. In a next step, a second treatment fluid,
optionally
sand followed by a fracking slurry, is pumped down the well to frac the
formation.
Alternatively, the second treatment fluid may be a non-fracking second
stimulant.
The pumping of the second treatment fluid acts to displace the first
treatment fluid, typically water, in the inner bore and dispel the first
treatemetn
fluid through the ported assembly 20 and into the formation. Since most
treatment strings 114 can be several kilometers long, a significant amount of
first
treatment fluid is standing in the inner bore that must be displaced into the
formation by the sand. This first fluid is essentially wasted.
To reduce and prevent wastage, the present invention provides one or
more flow diverter valves 110 positioned uphole from the ported assembly 20
and the straddle system 106, that serve to divert the first treatment fluid
standing
in the inner bore of the production string 114 back up through the annulus 18
to
surface where it can be collected and reused. The method is illustrated in
Figure
3.
In further embodiments, as illustrated in Figures 4 and 5, the present flow
diverter valve 110 serves to recycle water or other treatment fluids standing
in
inside the treatment string 114 out to surface when the treatment string 114
is
moved from one interval to be treated, to a subsequent interval.
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By diverting treatment fluid into annulus 18 above upper packer 106a,
fluid pressure above the isolated stage 116 is equalized with pressure
experienced below the upper packer 106a, to release the packer 106a so that
the treatment string 114 can be moved.
A similar pressure equalizing can be created on either side of lower
packer 106b, by means of a bypass valve 200 located downhole of lower packer
106b and which can be opened to allow treatment fluid circulation downhole of
lower packer 106b, to release lower packer 106b and allow the treatment string
114 to move to the next interval. By equalizing pressure on either side of the
io straddle system 106, the straddle system 106 experiences less wear as it
is
moved with the treatment string 114 from interval to interval.
Circulating fluids through the flow diverter valve 110 simultaneously while
moving the treatment string 114 between intervals saves significant time from
traditional methods in which fluid flow must be completely stoped when moving
between intervals, and then started up again.
Fluid pressure created by the flow diverter valve 110 further serves to
maintaining sufficient pressurein the annulus 18 at surface to prevent fluid
from
the treated interval from migrating past the upper packer 106a and up towards
surface.
Opening of the bypass valve 200 advantageously serves to minimize
swabbing effects that result when bottom hole pressure, that is pressure of
the
formation below the first isolated interval 116, is reduced below the
formation
pressure due to the effects of pulling the treatment string 114 uphole from
one
interval to the next. This pressure reduction can detrimentally allow for an
influx
of formation fluids into the wellbore. By opening bypass valve 200, treatment
fluid can be directed downhole of lower packer 106b to equalize pressure and
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maintain bottom hole pressure at or above formation pressure to prevent
ingress
of formation fluids in to the wellbore from the bottom.
With further reference to Figure 2, each of the present flow diverter valves
110 is preferably comprised of an inner sleeve 109 and an outer sleeve 108.
Each of the inner sleeve 109 and the outer sleeve 108 comprise one or more
ports, one of the ports 107 of the outer sleeve 108 being visible in Figure 2.
During stimulation or fracking operations the one or more ports of the inner
sleeve 109 are misaligned with the ports 107 of the outer sleeve 108, to
thereby
prevent water from exiting port 107. Instead water travels down the inner bore
of
treatment string 114 and exits through ported assemblies 20. When the
treatment fluid is switched, for example from water to sand, or when treatment
of
a previously stimulated interval 116 is complete and the treatment string 114
is to
be moved to the next interval to be isolated and treated, the inner sleeve 109
is
shifted or rotated mechanically to align the one or more ports of the inner
sleeve
109 with the one or more ports 107 of the outer sleeve 108. The mechanical
actuation may take the form of the production string itself being moved,
although
other means of actuating the inner sleeve 109 would be obvious to a person of
skill in the art and are included in the scope of the present invention.
At this point, standing water or other treatment fluids in the inner bore of
the treatment string 114 are displaced and caused to exit port 107 and travel
up
the annulus 18 to the surface where it can be collected and reused.
As mentioned earlier, fluid flowing out of exit port 107 and travelling
through
annulus 18 to surface equalizes pressure on either side of the upper packer
106a. this advantageously ensures that formation fluid from the treated
interval
116 does not travel into the wellbore or up to surface.
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More preferably, a metering device may optionally be applied to the
treatment string 114 or to the casing 16 to mearure the flow of fluids being
recyclied back to surface. The metering device provides flow data on the flow
rate of fluids being recyled back to surface to help operators determine when
all
of the recycled fluid has been recovered and when to close the diverter valve
110 and resume normal operation. When the system is ready for treating an
interval through the ported assembly 20, the inner sleeve 109 of the flow
diverter
valve 110 is shifted or rotated to misalign the one or more ports on the inner
sleeve 109 with the one or more ports 107 on the outer sleeve 108, thereby
io preventing fluid flow through these ports. Hydraulic pressure in the
treatment
string 114 helps to maintain the diverter valve 110 in a closed posisiton.
The above description is intended in an illustrative rather than a
restrictive sense, and variations to the specific configurations described may
be
apparent to skilled persons in adapting the present invention to other
specific
is applications. Such variations are intended to form part of the present
invention
insofar as they are within the spirit and scope of the claims below.
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