U.S. patent application number 14/921712 was filed with the patent office on 2016-04-28 for treatment string and method of use thereof.
The applicant listed for this patent is TEN K ENERGY SERVICE LTD.. Invention is credited to Ian Kendall Kent.
Application Number | 20160115770 14/921712 |
Document ID | / |
Family ID | 55791585 |
Filed Date | 2016-04-28 |
United States Patent
Application |
20160115770 |
Kind Code |
A1 |
Kent; Ian Kendall |
April 28, 2016 |
TREATMENT STRING AND METHOD OF USE THEREOF
Abstract
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 diverting fluid from
within the tubular member through an annulus between the tubular
member and the wellbore to surface. Methods are further provided
for treating a subteranian formation
Inventors: |
Kent; Ian Kendall; (Okotoks,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
TEN K ENERGY SERVICE LTD. |
Beaumont |
|
CA |
|
|
Family ID: |
55791585 |
Appl. No.: |
14/921712 |
Filed: |
October 23, 2015 |
Current U.S.
Class: |
166/305.1 ;
166/185 |
Current CPC
Class: |
E21B 34/10 20130101;
E21B 43/162 20130101; E21B 43/26 20130101; E21B 43/14 20130101;
E21B 2200/06 20200501; E21B 33/124 20130101 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 34/10 20060101 E21B034/10; E21B 43/14 20060101
E21B043/14; E21B 33/124 20060101 E21B033/124 |
Foreign Application Data
Date |
Code |
Application Number |
Oct 24, 2014 |
CA |
2869250 |
Claims
1. A tubular member 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 comprising: a. at least one
assembly having at least one port; b. 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 c. at least one flow diverter valve
positioned uphole from the upper packer for diverting fluid from
within the tubular member through an annulus between the tubular
member and the wellbore to surface.
2. The tubular member of claim 1, wherein each of the one or more
flow diverter valves comprises: an inner ported sleeve shiftable
within an outer ported sleeve, wherein said inner ported sleeve is
shiftable from a first position in which one or more ports on the
inner ported sleeve are misaligned with one or more ports on the
outer ported sleeve, to a second position in which one or more
ports on the inner ported sleeve are aligned with one or more ports
on the outer ported sleeve.
3. The tubular member of claim 2, wherein the inner sleeve is
shiftable by hydraulic pressure.
4. The tubular member of claim 1, further comprising at least one
bypass valve located downhole of the lower packer for circulating
treatment fluid from within the tubular member through the annulus
between the tubular member and the wellbore downhole of lower
packer.
5. A method for treating a subteranian formation, comprising: a.
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; b. setting an isolation device in an annulus
between the tubular member and the wellbore for hydraulically
isolating intervals in the annulus at locations adjacent the at
least one ported assembly; c. flowing a first treatment fluid under
pressure into the at least one isolated ported assembly to treat
the formation in the isolated interval of the wellbore by
pressurized treatment fluid flowing from the ported assembly; d.
opening one or more flow diverter valves positioned uphole of the
isolated assembly; and e. diverting the first treatment fluid from
within the tubular member through the flow diverter valve, through
the annulus to surface.
6. The method of claim 5, wherein diverting the first treatment
fluid through the annulus to surface balances pressure around the
isolation device and prevents egress of formation fluid from
treated interval into the wellbore and up to surface.
7. A method for treating a subteranian formation, the method
comprising: a. 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; b. 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; c. flowing
treatment fluid under pressure through the first ported assembly
and allowing treatment of the formation in the first isolated
interval of the wellbore by the pressurized treatment fluid; and d.
repeating the steps of: i. releasing treatment fluid pressure; ii.
opening one or more flow diverter valves positioned uphole of the
isolated interval; iii. circulating 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; iv. simultaneously moving the tubular member
to a subsequent interval of the wellbore, said subsequent interval
comprising at least one subsequent ported assembly; v. setting the
isolation device to hydraulically isolate the subsequent at least
one interval in the annulus; and vi. flowing treatment fluid under
pressure through the at least one subsequent ported assembly to the
formation in the isolated subsequent intervals of the wellbore by
the pressurized treatment fluid.
8. The method of claim 7, wherein the tubular member is moved
downhole for treating the wellbore therebelow.
9. The method of claim 7, wherein the tubular member is moved
uphole for treating the wellbore thereabove.
10. The method of claim 7, wherein diverting treatment fluid from
within the tubular member through the one or more opened flow
diverter valves prevents migration of fluid from the isolated
treated interval up the annulus to surface.
11. The method of claim 7, further comprising, prior to moving the
tubular member: i. opening at least one bypass valve located
downhole of the isolated interval; and ii. circulating treatment
fluid from within the tubular member through the at least one
bypass valve into the annulus downhole of the isolated assembly
simultaneously while moving the tubular member, to equalizing
annular pressure below the isolated interval with annular pressure
within the isolated interval.
12. A method for treating one or more isolated intervals of a
subteranian formation, the method comprising: a. flowing treatment
fluid under pressure through a first ported assembly on a tubular
member and allowing treatment of the formation in a first isolated
interval by the pressurized treatment fluid; b. moving the tubular
member to a subsequent interval of the wellbore, said subsequent
interval comprising at least one subsequent ported assembly; and c.
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.
Description
FIELD OF THE INVENTION
[0001] 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
[0002] 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 treatment 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 maintain well
production.
[0003] 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 pressure is released, and can include additives such as
acids. Alternatively, the formatting maybe treated by injection of
fluids at lower pressures than fracturing, to stimulate the
formation without causing fractures in the strata.
[0004] In many fracking or treatment 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 treatment
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.
[0005] When the isolated zone has been treated, flow of treatment
fluids is reduced or stopped entirely and the treatment string is
released and moved either uphole or downhole to the next zone to be
treated.
SUMMARY OF THE PRESENT INVENTION
[0006] 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 diverting fluid from
within the tubular member through an annulus between the tubular
member and the wellbore to surface.
[0007] 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 the at least one ported assembly; flowing a
first treatment fluid under pressure into the at least one isolated
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.
[0008] 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 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 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 subsequent 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 subsequent ported assembly to the
formation in the isolated subsequent intervals of the wellbore by
the pressurized treatment fluid; and vi. releasing treatment fluid
pressure.
[0009] 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 allowing treatment of the
formation in a first isolated interval by the pressurized treatment
fluid; moving the tubular member to a subsequent 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
[0010] Embodiments of the invention will now be described, by way
of example only, with reference to the accompanying drawings,
wherein:
[0011] FIGS. 1a 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;
[0012] FIG. 2 is an elevation view of a treatment string with a
ported assembly and a flow diverter valve of the present invention;
and
[0013] FIG. 3 is a process diagram illustrating a first method of
the present invention;
[0014] FIG. 4 is a process diagram illustrating a second method of
the present invention; and
[0015] FIG. 5 is a process diagram illustrating a third method of
the present invention.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0016] 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 illustrative
purposes.
[0017] With reference to FIGS. 1a 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 considered a
tubular member capable of flowing or communicating fluids under
pressure along the wellbore.
[0018] Assemblies 20 are employed to join segments 17 of the
production casing. Alternately, if no pipe segments are to be
employed and the assemblies 20 are to be joined directly, then the
assemblies 20 may have cooperative thread patterns, or alternate
joining means.
[0019] The assemblies 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.
[0020] 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 intact.
[0021] 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.
[0022] 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 up the
wiper plug". Once the cement sets to securely bond the production
casing in the wellbore, the well is ready to be completed.
[0023] Completion of the well requires, in this example, a coil
fracturing or treatment 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.
[0024] 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 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
treatment 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.
[0025] 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.
[0026] A further preferred embodiment of the invention is
illustrated in FIG. 2. In many fracking or stimulation situations,
a first treatment fluid such as water is 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.
[0027] The pumping of the second treatment fluid acts to displace
the first treatment fluid, typically water, in the inner bore and
dispel the first treatment 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.
[0028] 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
FIG. 3.
[0029] In further embodiments, as illustrated in FIGS. 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.
[0030] 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.
[0031] 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 straddle system 106, the straddle system 106 experiences less
wear as it is moved with the treatment string 114 from interval to
interval.
[0032] 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 stopped when moving between
intervals, and then started up again.
[0033] Fluid pressure created by the flow diverter valve 110
further serves to maintaining sufficient pressure in the annulus 18
at surface to prevent fluid from the treated interval from
migrating past the upper packer 106a and up towards surface.
[0034] 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 maintain bottom hole pressure at or above
formation pressure to prevent ingress of formation fluids in to the
wellbore from the bottom.
[0035] With further reference to FIG. 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 FIG. 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.
[0036] 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.
[0037] 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.
[0038] More preferably, a metering device may optionally be applied
to the treatment string 114 or to the casing 16 to measure the flow
of fluids being recycled back to surface. The metering device
provides flow data on the flow rate of fluids being recycled 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 preventing fluid flow
through these ports. Hydraulic pressure in the treatment string 114
helps to maintain the diverter valve 110 in a closed position.
[0039] 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 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.
* * * * *