Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR SINGLE-TRIP
TIME PROGRESSIVE WELLBORE TREATMENT
INVENTOR: GREGG W. STOUT
BACKGROUND OF INVENTION
1. Field of the Invention
[0001] The present invention relates to apparatus and methods for oil
and gas wells
to enhance the production of subterranean wells, either open hole, cased hole,
or cemented
in place and more particularly to improved multizone stimulation systems.
2. Description of Related Art
[0002] Wells are drilled to a depth in order to intersect a series of
formations or
zones in order to produce hydrocarbons from beneath the earth. Some wells are
drilled
horizontally through a formation and it is desired to section the wellbore in
order to
achieve a better stimulation along the length of the horizontal wellbore. The
drilled wells
are cased and cemented to a planned depth or a portion of the well is left
open hole.
[0003] Producing formations intersect with the well bore in order to
create a flow
path to the surface. Stimulation processes, such as fracing or acidizing are
used to increase
the flow of hydrocarbons through the formations. The formations may have
reduced
permeability due to mud and drilling damage or other formation
characteristics. In order to
increase the flow of hydrocarbons through the formations, it is desirable to
treat the
formations to increase flow area and permeability. This is done most
effectively by setting
either open-hole packers or cased-hole packers at intervals along the length
of the
wellbore. These packers isolate sections of the formations so that each
section can be
better treated for productivity. Between the packers is a frac port and in
some cases a
sliding sleeve or a casing that communicates with the formation or sometimes
open hole.
In order to direct a treatment fluid through a frac port and into the
formation, a seat or
valve may be placed above a sliding sleeve or below a frac port. A ball or
plug may be
dropped to land on the seat in order to direct fluid through the frac port and
into the
formation.
[0004] One method, furnished by PackersPlus, places a series of ball
seats below
the frac ports with each seat size accepting a different ball size. Smaller
diameter seats are
at the bottom of the completion and the seat size increases for each zone as
you go up the
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well. For each seat size there is a ball size so the smallest ball is dropped
first to clear all
the larger seats until it reaches the appropriate seat. In cases where many
zones are being
treated, maybe as many as 20 zones, the seat diameters have to be very close.
The balls
that are dropped have less surface area to land on as the number of zones
increase. With
less seat surface to land on, the amount of pressure you can put on the ball,
especially at
elevated temperature, becomes less and less. This means you can't get adequate
pressure
to frac the zone because the ball is so weak, so the ball blows through the
seat.
Furthermore, the small ball seats reduce the I.D. of the production flow path
which creates
other problems. The small I.D. prevents re-entry of other downhole devices,
i.e., plugs,
running and pulling tools, shifting tools for sliding sleeves, perforating gun
size (smaller
guns, less penetration), and of course production rates. In order to remove
the seats, a
milling run is needed to mill out all the seats and any balls that remain in
the well.
[0005] The size of the ball seats and related balls limits the number of
zones that
can be treated in a single trip. Furthermore, the balls have to be dropped
from the surface
for each zone and gravitated or pumped to the seats.
[0006] Another method, used by PackersPlus, U.S. patent 7,543,634 B2,
places
sleeves in the I.D. of the tubing string. These sleeves cover the frac ports
and packers are
placed above and below the frac ports. Varying sizes of balls or plugs are
dropped on top
of the sleeves and when pressuring down the tubing, the pressure acts on the
ball and the
ball forces the sleeve downward. Once again you have the restriction of the
ball seats and
theoretically, and most likely in practice, when the ball shifts the sleeve
downward, the
frac port opens and allows the force due to pressure diminish off before the
sleeve is fully
opened. If the ball and sleeve remain in the flow path, the flow path is
restricted for the
frac operation.
[0007] It would be advantageous to have a system that had no ball seats
that
restrict the I.D. of the tubing and to eliminate the need to spend the time
and expense of
milling out the ball seats, not to mention the debris created by the milling
operation. Also,
it would be beneficial to have a system that automatically fully opens each
sliding sleeve
and isolates the zone below, progressively up the well bore, before each zone
is
stimulated. Such a system allows stimulation of one zone at a time to achieve
the
maximum frac efficiency for each zone. In addition, it would be advantageous
to be able
to, in the future, isolate any zones by closing a sliding sleeve. For example,
a single zone
could be shut off if it began producing water or became a theft zone.
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a
[0008] Furthermore, it would be greatly advantageous to eliminate the time
and
logistics required for dropping numerous balls into the well, one at a time,
for each zone in
the well to be treated. It would also be advantageous to have a multizone frac
system that
functioned automatically while all zones were being stimulated in order to
minimize the
time surface pumping equipment is setting idol between pumping zones.
[0009] Many wells are being stimulated at multiple zones through the well
bore by
use of composite plugs such as the "Halliburton Obsidian Frac Plug" or the
"Owen Type
'A' Frac Plug". A composite plug is set near, or below, a zone and then the
zone is treated.
Another composite plug is set in the next upper zone and that zone is treated,
and so on up
the well bore until multiple plugs remain in the well. The composite plugs are
then drilled
out which can be time consuming and expensive. The shavings from the mill
operation
leave trash in the well and can also plug off flow chokes at the surface. It
would be
advantageous to have a system that eliminated the use and drilling out of
composite or
millable plugs. Of course, this approach would apply to new well completions
where
equipment, of the present invention, could be placed into the well prior to
treating.
[0010] Other well completions, such as intelligent wells, are designed to
operate
downhole devices by use of control lines running from the surface to various
downhole
devices such as packers, sleeves, valves, etc. An example of this type of
system can be
found in Schlumberger Patent US 6,817,410 B2. This patent describes use of
control lines
and the various devices they operate. It is obvious the use of control lines
can make the
completion very complicated and expensive. The present invention allows
operation of
some types of downhole devices possible without the use of control lines. For
example,
the present invention describes a timer/pressure device that could be placed
both above
and below a sliding sleeve, and days, months, or even years later, a sliding
sleeve, or series
of sliding sleeves, could be programmed to open or close.
[0011] There are other wells that sometimes require well intervention. A
product
called a Well Tractor, supplied by Welltec, is used to aid in shifting sliding
sleeves opened
or closed in long horizontal wells or highly deviated wells, sometimes in
conjunction with
wireline or coiled tubing operations. The present invention offers an
alternate and more
economical solution to functioning downhole devices in wells without well
intervention.
BRIEF SUMMARY OF THE INVENTION
[0012] This invention provides an improved multizone stimulation system to
improve the conductivity of the well formations with reduced rig time, no
milling, and no
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control lines from the surface and, for some other applications, reduce well
intervention.
The equipment for all zones can be conveyed in single work string trip and
frac units can
stay on location one time to treat all zones.
[0013] This invention relates to an automatic progressive stimulation
system where
no control line or ball drop apparatus are needed. This system can also
eliminate the need
to set and mill out composite plugs in newly planned well completions. When
single zone
or multiple zone wells are to be completed with plans of stimulation and then
producing,
the equipment in the present invention can be utilized. This invention is
comprised of three
major components; a packer, a timer/pressure device, and a sliding
sleeve/valve assembly.
Although, in some cases, a packer may not be needed, for example, if the
system is
cemented in place. The combination of these three components, or two
components
without the packer, has been given the name "Frac Module".
[0014] I. The packer can be several types, such as those that set
hydraulically by
applying tubing pressure, those that are Swellable, or those that are
Inflatable, to mention a
few.
[0015] II. The timer/pressure device is a device that can be actuated by
application
of well pressure such as tubing pressure or annulus pressure. This pressure
can act on a
pressure sensitive device, which in turn triggers a timing device where the
timing device,
or a plurality of timing devices, can be set to any desired time, before it
triggers a pressure
generating device which is turn applies pressure to a downhole tool in order
to activate the
tool.
[0016] III. The sliding sleeve is a typical type sleeve that can open or
close a port,
or series of ports, that allow fluids or slurries to travel down the well
conduit, through the
ports, and communicate with the formation. For the present invention, the
sliding sleeve
would be of the piston type where pressure acts on a piston and in turn shifts
the sleeve. A
frangible flapper valve, or other type of valve, is positioned above the
sliding sleeve and
closes when the sliding sleeve shifts downward. The valve directs flow through
the ports
in the sliding sleeve and isolates the zone below.
[0017] A series of frac modules placed in the well act in unison, where
all packers
are set at once and all timers/pressure devices are triggered at once, with a
single
application of tubing pressure. Each timer in each zone can be set to a
desired time so that,
for example, the lowermost timer actuates a pressure generating device after
one hour
from the time when tubing pressure was initially applied. The pressure
generating device
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creates pressure that communicates with a piston on the sliding sleeve to open
the sliding
sleeve and close the flapper valve. This first zone is treated through the
sliding sleeve
ports before the next upper sliding sleeve opens.
[0018] The next upper Frac Module timer is set for 2 hours, for
example, from the
time when initial tubing pressure was applied. At the end of the two hour time
period, the
timer actuates a pressure generating device to open its sliding sleeve so the
zone can be
treated. Timers in each zone can be set to the desired time to allow
stimulating as many
zones as required.
[0019] The timing devices can be set so that all zones can be nearly
continuously
treated in order to optimize the use of surface stimulation equipment. The
timers are
versatile enough where all the timers can be triggered at once. A portion of
timers can be
triggered at one selected pressure while others are triggered at different
selected pressures,
or sequences of applied pressures. A further option includes a pressure
sensitive device
that is attached to or built into each timing device, which monitors well
pressure so that
when well pressure reaches a predetermined level, the timers go into a "Stand-
Down-
Mode". Surface applied well pressure can be in the form of a series of
pressure increase or
decreases in conjunction with pressure holds or simply a decrease in pressure
to a pre-
selected level. For example, if frac pumping is in process and all of the
timers are running,
if the frac operation stops for some reason and frac pressure drops below a
selected point,
all of the timers go into a "Stand-Down-Mode" where the timers stop
temporarily. The
timers remember the time used up to that point and when pump pressure resumes,
all of
the timers begin running once again for the balance of the time remaining in
each timer.
All of the timers remain in their preprogrammed sliding sleeve activation
sequence.
[0020] To those familiar with the art of well completions, it is
obvious that the
scope of this invention is not limited to just timer/pressure generating
devices shifting
sliding sleeves open or closed but can also be used to actuate any type or
combination of a
downhole tool device, or devices, in any timing sequence, such as perforating
guns,
valves, packers, etc. More than one timing/pressure device can be used to
function a single
type multiple times by setting the timers at different time spans.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)
[0021] FIG.s 1, 2, and 3 placed end-to-end make up a schematic view of
an
embodiment of the present invention.
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[0022] FIG. 4
is a schematic view of three Frac Modules assembled in tandem in a
well completion.
[0023] FIG. 5
is a schematic showing a second embodiment of a timer/pressure
device that can be used in the Frac Module.
[0024] FIG. 6
is a schematic showing a third embodiment of a timer/pressure
device that includes a "Stand-Down-Mode" device that can be used in the Frac
Module.
[0025] FIG. 7
is a schematic showing a fourth embodiment of a timer/pressure
device that is a modification of the device in Figure 5 where a "Stand-Down-
Mode"
device has been added.
[0026] FIG. 8
is a well schematic showing an embodiment of a Frac Module
without any packers where the entire system is cemented in place.
[0027]
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0028] With
reference to FIG. 1, a schematic of an embodiment of the present
invention shows a 90 degree lengthwise cross-section of the apparatus. This
portion of the
apparatus is a simplified view of a tubing pressure hydraulically set packer
2, although
packers such as swell and inflatable packers may be used. A packer maybe used
that has a
slip system added and a packer may be used that has a release device added.
[0029] Tubing
string 1 has a connecting thread 3 that connects to top sub 4. Top
sub 4 threadably connects to packer mandrel 7. Packing element 5 and gage ring
6 are
positioned over mandrel 7. Ratchet ring 8 is located and threadably locked
inside housing
9. Piston 10 is threadably connected to gage ring 6 and ratchet ring 8 engages
piston thread
96 as piston 10 strokes upward (left end of drawing). Seals 11 and 12 form a
seal in bores
97 and 98 and between piston 10. Tubing pressure 52 enters port 14 and acts
across seals
11 and 12 to move piston 10 upward compressing packing element 5. Fluid is
displaced
through port 16. Ratchet ring 8 locks piston 10 so the packing element 5 stays
compressed
and sealed inside outer casing 99. Housing 9 has pin thread 13 facing
downward.
[0030]
Referring to FIG. 2, the timer/pressure assembly 18 is shown in a
schematic. This schematic illustrates a totally mechanical timing/pressure
device although
other types of devices can be substituted such as a pressure sensitive
pressure transducer
interconnected to an electronic timer that initiates a pyrotechnics gas
pressure generating
device, for example. Such a device is shown in FIG. 5.
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[0031] Referring to the schematic, thread 17 of pin 13 connects to outer
chamber
19. Inner chamber 20 is trapped inside outer chamber 19 to form an annular
space between
the two chambers. Piston 25 has seals 23 and 24 that seal inside of inner and
outer
chambers 19 and 20. Tubing pressure 52 enters port 21 and chamber 22 to act on
piston
25. The top end of compression spring 29 is shown in a near solid height
condition where
spring 29 makes solid contact with piston 25 at location 28.
[0032] The bottom end of compression spring 29 makes solid contact with
orifice
piston 33 at location 30. Shear screws 31 shearably connect orifice piston 33
to inner
chamber groove 100. Piston 25 is allowed to stroke downward until face 26
contacts
shoulder 27.
[0033] A flow control device, such as a LEE Visco Jet 32 is located inside
of
orifice piston 33 so that fluid, such as silicone oil, located in chamber 39
can only pass
tInv Visco Jet 32 and into chamber 40. Seals 34 and 35 seal orifice piston 33
on the inside
walls of chamber 39. orifice piston 33 has face 36 that travels through
chamber 39 to make
contact with face 37 of pressure release rod 38. Pressure chamber 48 is
threadably
connected to outer chamber 19 at thread 50. Seals 42 and 49 isolate chamber 45
where
chamber 45 is charged with a pressurized gas, such as nitrogen. Seals 41 on
both ends of
pressure release rod 38 also isolate chamber 45 to hold pressurized gas within
the
chamber. Chamber 39 communicates with chamber 44 through gap 47.
[0034] Bores 46 inside of pressure chamber 48 are of near equal, or equal,
diameter and seals 41 are of near, or equal, diameter so that pressure release
rod 38 is in
the pressure balanced condition when exposed to pressure from either chambers
39 or 45.
Pressure release rod 38 is held relative to chamber 48 by a low force spring
loaded detent
ball 101 to prevent pressure release rod 38 from moving until contacted by
orifice piston
face 36.
[0035] Chamber 45 is charged with high pressure nitrogen gas through
nitrogen
charge valve 58 and longitudinal hole 53. Hole 53 is sealed off at one end
with plug 56 but
is open to chamber 45 at the opposing end. Seals 59 and 60 seal the nitrogen
charge valve
58 in order to prevent passage of gas out of chamber 45 and past the valve 58.
[0036] A doughnut sleeve with internal o-rings and a sealed alien wrench,
not
shown, slides over nitrogen charge valve 58 to allow unscrewing Valve 58 to
allow
passage of gas through the doughnut and into chamber 45. Once chamber 45 is at
the
desired pressure, the valve 58 is closed with the Allen wrench to seal the
chamber 45.
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[0037] Upper sleeve housing 68 is threadably attached to chamber 48 with
thread
61 and sealed with seals 62. Longitudinal hole 54 communicates with chamber
44, not
exposed to charged gas pressure at this time, and chamber 55 and hole 57.
Seals 63 isolate
chamber 55 from pressure 52. Seals 51 isolate pressure 52 from chambers 39 and
44.
[0038] Pressure release rod 38 has recesses 43 and 102 so when shifted
downward
by spring force in spring 29 and face 36, seal 41 leave seal bore 46 and
pressurized gas can
move from inside chamber 45 to chamber 55 and into hole 57.
[0039] Frangible flapper valve 65 is mounted by axle 66 and is spring
biased with
spring 67 to rotate from the open position, shown, to the closed position.
Finger 64
temporarily holds the Flapper 65 in the open position. Axle 66 is positioned
on the
upstream portion of sleeve 71 and is carried by it.
[0040] Referring to FIG. 3, this schematic shows ported sliding sleeve 95.
Upper
sleeve housing 68 shows the continuation of hole 57 that communicates with
chamber 72.
Sleeve piston 76 has seal 74 and 75 that isolate chambers 72 from 77. Screw 73
connects
piston 76 to sleeve 71. Seal 69 isolates chamber 72 from pressure 52 and seal
80 isolates
chamber 77 from pressure 52. Seals 69 and 80 are of the same diameter so that
sleeve 71 is
pressure balanced, or near pressure balanced from pressure 52 so pressure 52
does tend to
move sliding sleeve 71 up or down. Gas pressure in chamber 72 acts on piston
76 to move
sliding sleeve 71 downward or to the open position.
[0041] Single or multiple ports 70 go through the wall of upper sleeve
housing 68
and sleeve 71 and seals 69 and 80 prevent pressure or fluid from traveling
from location
103, through ports 70 and to location 104, or vice versa. If pressure in
chamber 72 is
greater than pressure in chamber 77 and pressure acts on piston 76, the piston
76 and
sliding sleeve 71 will move downward toward chamber 77. During this movement,
fluid
exits ports 78 and 79 to area 104. When seal 74 passes port 78, gas pressure
above piston
76 and in chamber 72 passes through port 78 allowing the gas pressure to
equalize.
[0042] Downward movement of sleeve 71 allows seal 69 to move past port 70
so
that flow passage can occur from area 103 to area 104. Also, when the sliding
sleeve 71
moves downward, flapper 65 moves away from finger 64 and rotates around axle
66
allowing spring 67 to rotate flapper 65 to the closed position.
[0043] Collets 88 and 89 are common to sliding sleeves and come in
different
geometries. The collets lock the sliding sleeve 71 either in the up or down
position in
recesses 87 and 90. Shifting tool profiles are added to the inside of the
sliding sleeve 71 to
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use mechanical shifting tools run on wireline or tubing, to shift the sliding
sleeve 71
closed or back open at some future time.
[0044] Sleeve housing 83 is threadably connected to upper sleeve housing
68 with
thread 81. A stop key 85 may be employed to engage shoulder 86 to stop the
downward
movement of sliding sleeve 72 as to not load collets 88 and 89 in compression.
Stop key
85 sets in pocket 82 and can move downward in slot 84.
[0045] Bottom sub 93 is threadably attached to sleeve housing 83 with
thread 91
and is sealed with seals 92. Pin thread 94 connects to a tubing spacer which
in turn
connects to another Frac Module or possibly a bottom locator seal assembly
that stings
into a sump packer.
[0046] Referencing FIG. 4, this schematic shows a possible completion
hookup
105 using three Frac Modules 106, 107, and 108 although many Frac Modules may
be
used. The well has casing 116 and below location 127 the well casing 116 can
continue or
the well can be open hole passing through zones 111, 112, and 113. Packers
117, 118, and
119 can be tubing pressure hydraulic set packers for cased hole or swellable
or tubing
pressure set inflatable packers for either cased hole or open hole. Each zone
can have a
timer/pressure device 122, 121, and 120 and a ported sliding sleeve valve
assembly 125,
124, and 123. Each zone can be separated by tubing spacers 114 and tubing 115
runs to the
surface or a hydraulic set production packer (not shown). A sump packer 109
can be set
prior to running the completion string of frac modules. The bottom of the
completion
string can have a typical locator seal assembly 110 that stings into sump
packer 109. If it is
desired not to run a sump packer 109, the sump packer can be replaced with an
additional
tubing pressure set hydraulic packer that is set by dropping a ball on a seat
below the
packer. In either case, all tubing pressure set packers will set at the same
time, if desired.
Each zone is isolated with packers set above and below each zone and the
sliding sleeves
in the closed position.
[0047] Referring to FIG. 5, this is a schematic of an embodiment of the
present
invention showing a second method of producing pressure to shift a sliding
sleeve or other
downhole device. Referencing FIG. 2, this device can be put in the place of
the device
described in FIG. 2.
[0048] Once again, there is an outer chamber 19, an Inner chamber 20, a
port 21, a
chamber 22, seals 23 and 24, a chamber 44, and a hole 57. Pressure from area
52 enters
port 21 into chamber 22 and into hole 129. Pressure in hole 129 acts on a
pressure
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sensitive device, such as a pressure transducer 130. The pressure transducer
triggers a
switch 131 that starts an adjustable timer 132 that is set for a time frame,
say 4 hours. The
timer can be pre-set at the surface prior to running the tools into the well.
The timer can be
set for any time increment desired, for example from 1 minute to 100 hours, or
longer. At
the end of 4 hours it triggers a switch 133 to supply battery power 134 to an
igniter 135, or
initiator. The battery power can also run the timer or the timer can be purely
mechanical.
Power supplied to the igniter 135 triggers the igniter 135, or initiator, to
cause the material
in the gas generator 136 to burn, react, or mix, and produce high pressure
gas. The high
pressure gas pressure increases in chamber 44, travels through hole 57 to act
on the piston
76, shown in FIG. 3. Pressure on the piston 76, shifts the sliding sleeve 71
to the open, or
down, position. Components 130, 131, 132, 133, 134, 135, and 136 can be moved,
or
substituted with other mechanisms, to different relative positions to achieve
the same goal
of producing gas pressure. These components can be in a single cartridge
modular form,
say one assembly, and can be miniaturized or improved by use of
microelectronics. Also,
more than one timer/pressure device can be used for redundancy and reliability
purposes.
[0049] The device in FIG. 5, and the device in FIG. 2, illustrate that
more than one
technique can be used to create a timer/pressure device, and the present
invention is not
limited to one technique.
[0050] Furthermore, it is important to recognize that the timer/pressure
device
described in FIGS. 2 and 5 can be positioned relative to the sliding sleeve,
FIG. 3, either
above or below the sliding sleeve, although if the timer/pressure device were
positioned
below the sliding sleeve, the hole 57 arrangement would be slightly more
complicated
when shifting the sleeve upward. A first timer/pressure device can be used to
open the
sleeve and a second timer/pressure device can be positioned below the sliding
sleeve to
close the sliding sleeve at a specified time in the future.
[0051] Referring to FIG. 6, this is a schematic of an embodiment of the
present
invention showing a third method of producing pressure to shift a sliding
sleeve or activate
other downhole devices. Tubular section 9 has thread 17 that connects to top
sub 137.
Piston housing 146 threadably connects to top sub 137 at thread 138. Piston
143 is
positioned inside of piston housing 146 and top sub 137 and seals 141, 142 and
144 form
pressure seals at bores 169, 170, and 171 around piston 143. Chamber 177 is
either an
atmospheric chamber if port 140 is plugged or is exposed to pressure external
to the tool
through port 140 if port 140 is not plugged. Shear screws 145 shearably lock
piston 143 to
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a groove 168 in top sub 137. Seals 141 and 142 prevent pressure at 52 from
traveling thru
hole 139 and to pressure in port 140. Seals 142 and 144 prevent pressure at 52
from
traveling thru hole 139 and into hole 178 and on into chamber 151. Inner
housing 155 is
threadably connected to piston housing 146 with thread 148 and sealed with
seal 149.
Outer housing 172 is threadably connected to piston housing 146 with thread
147 and
sealed with seal 150. Positioned inside housings 172 and 155 is a pressure
sensitive device
152, which may be a pressure transducer, a switch 154, a timer 156, a switch
157, a
battery pack 158 all of which control a metal piercing device 159. The metal
piercing
device forms a hole in membrane 162 and may be a drill, punch, or an explosive
squib that
is designed to perforate metal. The Figure shows an electric powered motor 159
with a
drill 161 with a spring 160 that forces the drill 161 against membrane 162 as
to create
communication with pressurized gas chamber 45. Of course the motor 159, can be
replaced with an electrical detonated explosive squib that is designed to form
small hole in
metal. The squib would be similar to a DuPont Electronic Detonator Type "S".
Pressure
transducer 152 has seals 173 and 153 that seal near chamber 151 to prevent
pressure or
fluids in chamber 151 from traveling through gap 47 and into chamber 44 and
hole 57.
Components 152, 154, 156, 157, 158 and 159 can be rearranged, simplified, or
compacted
so that when the pressure transducer is activated by pressure 52, the timer
begins running
and turns the piercing device on after a programmed period of time. Also, a
plurality of
these components can be used to create redundancy in the system. A second
pressure
sensitive device 164 is also in communication with hole 143. Programmable
controller 165
has the logic to turn switch 166 on or off based on the status of the pressure
at 52. Wires
163 attach to timer circuitry 156 so that switch 166 can stop timer 156, where
timer
remembers time already spent, and restarts timer for the remaining un-spent
time,
commonly called the "Stand-Down-Mode". This "Stand-Down-Mode" device can also
be
powered by battery 158, if desired, or have its own battery. The "Stand-Down-
Mode"
device can also be built as part of the components 152, 154, 156, 157, 158,
and 159.
Controller 165 has programmable logic that senses the status of pressure 52
where
controller 165 can be set to sense a threshold pressure at 52 where the
threshold pressure is
the pressure that would exist if all pressure pumping from the surface ceased.
The
threshold pressure could be calculated based on the static bottom-hole-
pressure plus a
minimal applied pressure, say 500 PSI or 1000 PSI. If bottom-hole-pressure is
5000 PSI
then the threshold pressure, pre-programmed into all of the timers, could be
6,000 PSI at
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the timer pressure transducers. When pressure dropped equal to or less than
the threshold
pressure, all of the timers in the system would go into the "Stand-Down-Mode"
until
pressure pumping was resumed to increase pressure above the threshold
pressure. The
logic in controller 165 could also be set to respond to a series or plurality
of pressure
pulses of varying magnitudes and durations in order to put the timers into the
"Stand-
Down-Mode" and a second series of pressure pulses to remove the timers from
the "Stand-
Down-Mode". All timers 156 would go to and from the "Stand-Down-Mode" in
unison as
to preserve the overall zone-by-zone timing sequence that is preprogrammed
into the
system for sequential fracing of all zones. The remaining components in Figure
6 are the
same ones shown in Figure 2 except that the chamber 45 is now a sealed chamber
in order
to reduce potential leak paths, i.e., no rod 38 with seals 41. Rather than
shifting rod 38 to
release pressurized gas in chamber 45, the membrane 162 is ruptured to release
the
pressurized gas into hole 57 that in turn acts on the sliding sleeve piston
76, of Figure 3, to
activate the sliding sleeve 71.
[0052] Referring to FIG. 7, this is a schematic identical to Figure 5
except that the
controller 167 has been added in the circuitry to provide a "Stand-Down-Mode",
if
desired.
[0053] Referring to FIG. 8, this is a well schematic similar to Figure 4
except that
the packers 117, 118, and 119 have been removed from the Frac Modules and also
the
tools are placed in an open hole section of the well where the open hole 175
is filled with
cement 176. Also, in a cemented completion, there is no need for the sump
packer 109 or
locator 110.
DESCRIPTION OF OPERATION
[0054] With reference to the example in FIG. 4, a typical completion is
shown but
many variations of this occur as known by those who are familiar with the
variations that
occur in configuring well completions.
[0055] A well has been drilled, cased, cemented, and perforated, although
this
system may be used in open hole completions with selection of the appropriate
packers.
Casing 116 is shown in this example with zones and perforations 111, 112, and
113 in the
casing. The objective is to stimulate all of the zones 111, 112, and 113 in a
single trip
without well intervention. A sump packer 109 is properly located and set below
the
lowermost zone 113 although this packer may be substituted with a packer
similar to
packer 119 by landing a ball against a seat below where packer 109 is shown.
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[0056] A "completion string" is run into the well consisting of a locator
snap latch
seal assembly 110, tubing spacer 114, frac module 108, tubing spacer 114, frac
module
107, tubing spacer 114, frac module 106, tubing spacer 114, a
service/production packer
(not shown), and work string or production 115. The length of tubing spacers
114 are
made to position the frac modules 106, 107, and 108 between the producing
zones 111,
112, and 113.
[0057] The single trip completion string is landed in sump packer 109. The
location of sump Packer 109 is based on logs of the zones so that all
equipment could be
spaced out properly. Therefore, by locating the completion assembly on the
sump packer
109, all Frac Modules 106, 107 and 108 will be properly positioned in the
well. Snap latch
seal assembly 110 can be used to verify position of the system before setting
any of the
packers 117, 118, and 119. The locator snap latch seal assembly 110 seals in
the sump
packer 109 and will locate on the sump packer. The locator snap latch seal
assembly 110 is
designed to allow pulling of the work string 115 to get a load indication on
the sump
packer 109 and then snap back in and put set-down weight on the sump packer
109. The
above steps are common in the art of completing wells.
[0058] At this point in time the completion hardware, shown in FIG. 4, is
properly
positioned around all the zones to be stimulated. All stimulation equipment
has been
positioned around the well at the surface and all frac lines have been
assembled and
pressure tested. A pumping company has done stimulation pre-planning for each
zone and
has all the necessary materials ready to pump, along with backup surface
units. The Frac
Module Timers were all set prior to running the system into the well but at
this point in
time, none of the timers have been actuated. The pumping company knows how
long it
will take to pump each zone and the timers were pre-set based on how long it
will take to
frac each zone. The timers were pre-set to allow extra time for any required
surface
operations during the overall process.
[0059] Now that the completion system is in the proper position in the
well and all
surface equipment has been nippled-up, the zones are ready to stimulate.
[0060] At this point all the sliding sleeves in each Frac Module are in
the closed
position. The operator may decide to do a low pressure system pressure test at
this time
before actuating any downhole devices. The entire system is pressured up, for
example, to
500 psi and held for a period of time until there is proof of no leaks in the
system.
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[0061] At this point all surface equipment is running and the well is
ready to
stimulate. The first step is to set all of the packers, assuming that they are
hydraulic tubing
pressure set packers. If they are swellable packers, the operator will wait to
begin
operations until all of the Swellable packers have had time to swell.
[0062] Continuing and assuming the packers are tubing pressure set, the
surface
pump units begin applying tubing pressure 126 inside of work string 115 to
packer setting
ports 14. All of the packers may be designed to begin setting at 1,500 psi and
may not
fully set until the tubing pressure reaches 3,500 psi, for example. This
pressuring operation
will take several minutes.
[0063] The same pressure 52 used to set the packers 117, 118, and 119,
also
reaches the Frac Module timer pressure devices 122, 121, and 120. In this
case, all of the
timers have been set to actuate close to the exact same time so when the
tubing pressure
reaches 1,500 psi, for example, all the devices 122, 121, and 120 start
counting time. If the
lowermost zone 113 is to be stimulated first, the timer in device 120 may have
been set at
30 minutes, i.e., the amount of time before the first sliding sleeve 123 is
opened and the
flapper in the closed position. The timer is zone 112 may be been set for 2
hours and the
timer in zone 111, may have been set for 3 hours.
[0064] At this point in time, possibly 15 minutes after initial setting
pressure was
applied, all of the packers are set and all of the timers are running. It is
now critical to
begin pumping the job since the timer clocks are ticking, unless the stand-
down mode is to
be utilized. The first zone 113 will need to be fraced but the sliding sleeve
123 in Frac
Module 108 must first open. The following paragraphs will explain how the
sliding sleeve
123 opens.
[0065] Referring to FIGS. 2 and 3, pressure in area 52 enters port 21 and
chamber
22 and acts on piston 25. Piston 25 and solid height compressed spring 29
pushes on
orifice piston 33. As piston 25 face 26 moves to shoulder 27, shear screws 31
shear against
groove 100. The shear screws 31 may be set to shear at 1,500 psi applied to
piston 25. The
force in spring 29 has sufficient force to move orifice piston 33 downward
against the
fluid in chamber 39. The fluid in chamber 39 must be forced through Lee Visco
Jet 32.
The Visco Jet has a Lohm rating that allows fluid to travel through the jet at
a specified
rate with a specified fluid, such as silicone oil, 200 cs. The specified flow
rate of the fluid,
the load of spring 29, and the total volume of fluid in chamber 39, controls
the velocity
and time in which the orifice piston moves toward rod 38. The variables of
spring load, Jet
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Lohm rating, fluid type, and total fluid volume can be adjusted ahead of time
to achieve a
30 minute time dwell until face 36, of orifice piston 33 contacts face 37 of
the rod 38.
[0066] The spring 29 has sufficient load and stroke to move rod 38
downward
through charged nitrogen chamber 45. When the rod undercuts 102 of rod 38 move
downward and seals 41 move out of seal bores 46, nitrogen gas is allowed to
exit chamber
45 and enter chamber 44, hole 54, and hole 57. The gas pressure is of
sufficient magnitude
so when it acts on sliding sleeve piston 76, the sliding sleeve 71 is shifted
downward to
open up frac port 70. Frac port 70 then allows fluid communication form area
103 to area
104.
[0067] Simultaneously, flapper 65 is pulled downward away from finger 64,
and
flapper 65 rotates around axle 66, and is biased to the closed position by
spring 67 to form
a seal on top of sliding sleeve 71. Once the sliding sleeve 71 is fully
shifted downward,
excess nitrogen gas is allowed to escape through port 78 in order to equalize
pressure
around the sliding sleeve 71. This is important in case the sliding sleeve 71
needs to be
shifted closed by mechanical shifting tools, at a later point in time after
the well has been
treated. The seals 23 and 24 on piston 25 provide a seal to prevent
communication of fluid
backward from port 78 to port 21 or vice versa. In this case, once the sliding
sleeve 71 is
fully shifted down, the collets 89 lock in groove 90 to hold the sliding
sleeve in the open
position. Likewise, when the sliding sleeve 71 is closed, collets 88 lock in
groove 87 to
hold the sliding sleeve 71 in the closed position.
[0068] At this point in time, the sliding sleeve 123 is shifted open and
the flapper
65 is sealing the top of the sliding sleeve 71 so when pumping fluid from the
surface of the
well, fluid will not pass through the inside of sliding sleeve 71, but will be
blocked by the
flapper 65 and directed through frac Port 70 and into formation 113.
[0069] Formation 113 is treated by pumping fluid, or slurry, down work
string
115, through the upper Frac Modules 106 and 107 and out of ports 70 located in
Frac
Module 108, and thru perforations 113 and into formation 113. This operation
has been
planned by the pumping company to be complete before the 2 hour time period
programmed in Frac Module 107. Of course the 2 hour time period could have
been
reduced to minimize the time between treating zones.
[0070] After 2 hours from the original initiation point of setting the
packers and
starting the timers, the sliding sleeve 71 in Frac Module 107 opens and
flapper 65 closes
per the above described process, so zone 112 can now be treated.
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[0071] This process continues for all zones that are in the completion and
stimulation program for the well. As each zone is treated up the well, each
Frac Module
operates independently from the others, so failure of one to operate does not
affect the
operation of the others.
[0072] Once all zones are treated, the surface stimulation equipment can
move off
location. Flow from the formations can be used to attempt to clean up the
well. The flow
will open the flappers and allow fluid to move up hole.
[0073] It is also common practice to go back in the well, wash out excess
proppant, if proppant was used, break the frangible flapper disc's, and close
sliding sleeve
71 for zone isolation, if desired. The sliding sleeves have profiles machined
in the inside
of the sleeves so that standard type mechanical shifting tools can be used to
either open or
close the ports 70.
[0074] Referring to FIG. 6, where the "Stand-Down-Mode" feature has been
added
to the timing/pressure device along with an actuation piston, and a different
means to
provide energy to shift the sliding sleeve. In operation, before running the
system into the
well, all Frac Module timers have been preprogrammed to run a selected period
of time.
Typically the lowermost timer will be set to open a sleeve first, the second
sleeve 30
minutes later, and the third sleeve 60 minutes later and so on up the tool
string. Also,
based on planned well pressure at the tools the "Stand-Down-Mode" Controllers
are set to
either the threshold pressure or the pressure pulse sequence. When all of the
frac Modules
are positioned in the well and it is time to begin the frac operation, tubing
pressure 52 is
applied from the surface of the well. All of the Frac Modules see the same
tubing pressure
52 at the same time. Pressure 52 enters at port 139. All Frac Module pistons
143 have been
set to shear screws 145 at the same pressure. This pressure is calculated
based on the area
of piston 143, i.e., area at seal 144 minus the area of seal 141 and the total
shear value of
the screws 145. For example, all the pistons 143 will be set to open when 1500
PSI is
applied to port 139 from the surface. 2000 PSI may be applied to be certain
that all pistons
have shifted. The pistons 143 will shift upward when pressure 52 acts on seals
141 and
144 and since pressure at location 140 is less, a resulting force upward will
shear the
screws 145 as the pistons move upward. Well pressure from location 140 or 52
has not
entered into holes 178 since seals 142 and 144 have isolated holes 178.
Although, as
pistons 143 move upward, seals 144 move up bores 171 until holes 178 are
exposed to
well pressure 52. At this time well pressure 52 enters holes 178 and enters
chambers 151
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and into pressure transducers 152. The pressure simultaneously enters all Frac
Module
Pressure Transducers at once, therefore, activating switch 154 which in turn
starts all
timers 156. Simultaneously, pressure is acting on pressure transducer 164 and
controllers
165 will tell switches 166 to allow the timers 156 to keep running as long as
tubing
pressure 52 is maintained from the surface at a pre-selected level. The timers
156 will
typically activate the lower-most Frac Module first. In this module, the timer
156 will turn
on switch 157 to connect battery power 158 to piercing device 159. Piercing
device
159/161 will produce a hole in membrane 162. Pre-charged gas pressure in
chamber 45
will escape into chamber 174, through gap 47, into chamber 44, into hole 54,
into chamber
55, into hole 57 and act on piston 76 (Fig. 3) to shift sliding sleeve 71 to
open frac port 70
and release the flapper 65 from the open position to the closed position. With
the first
Flapper closed and the first sleeve open, the first zone can be Fraced. During
the Fracing
operation, if surface pumping ever stops for any reason and the pressure 52
drops to a pre-
programs threshold pressure, the controllers 165, will cause all Frac Module
switches 166
to open the battery power circuits in wires 163 to stop all timers 156. The
timers 156 are
the type that if power is lost, the timer will remember the time it ran before
power was
lost. When surface pumping resumes, pressure 52 increases above the pre-
programmed
threshold and controller 165 then closes the circuit in wires 163, and all
timers resume
operating where they left off Once the first zone is Fraced, the timer in the
next zone up
the well will open the next sliding sleeve. As long as pumping continues, the
zones up the
well can be continuously Fraced until all zones are treated. If there are
pumping delays,
the timers will go into the "Stand-Down-Mode" until pumping resumes.
[0075] Referring to FIG. 7, the "Stand-Down-Mode" feature has been added
to the
timing/pressure device described in figure 5. This figure shows the controller
167
integrated into the pressure transducer 130 and switch 131 devices. The system
will work
similar to the Fig. 4 operation but will include the "Stand-Down-Mode" as
described in the
Fig 6 operation described above. Overall, this option can provide a more
compact timing
unit.
[0076] Referring to FIG. 8, the completion hook-up has been simplified by
eliminating isolation packers 117, 118, and 119 from the Frac Modules. Also,
the Sump
packer 109 and locator 110 are not shown. The Packers are not needed since the
completion is cemented in open hole 175. The cement 176 seals completely
around the
Frac Modules. Sliding sleeve 123 is opened first and surface pump pressure is
used to
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break through the cement and initiate a fracture in the producing formation.
As the timers
progressively open each sliding sleeve closes a flapper and each respective
zone is broken
down and fraced.
[0077]
Although the present invention has been described with respect to specific
details, it is not intended that such details should be regarded as
limitations on the scope of
the invention, except to the extent that they are included in the accompanying
claims.
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