Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 "PRESSURE-ACTUATED PERFORATION WITH
2 CONTINUOUS REMOVAL OF DEBRIS"
3
4 FIELD OF THE INVENTION
This invention relates to a method and apparatus to perforate or re-
6 perforate a well and then to substantially and immediately thereafter
circulate a
7 fluid for removal of solids and debris from an underground formation for an
8 aggressive completion or stimulation.
9
BACKGROUND OF THE INVENTION
11 To recover hydrocarbons such as oil and natural gas from
12 subterranean formations through a wellbore penetrating the earth to the
13 hydrocarbon-bearing formation, it is common to pertorm a completion,
including
14 perforating, and in some circumstances to perform some type of stimulation
procedure in order to enhance the recovery of the valuable hydrocarbons.
16 In order to recover the hydrocarbons, a well is drilled from the
17 surface to the formation. Following drilling, the well is generally
completed by
18 installing a tubular well casing in the open borehole and cementing the
casing in
19 place. Because the casing and cement forms a continuous hollow column, no
wellbore fluids are able to enter the well to be transported to and recovered
at the
21 surface.
22 For this reason, it is common to provide openings through the
23 casing and cement annulus in the zone of interest by perforating the casing
and
24 cement into the surrounding formation to provide access from the formation
into
the wellbore for recovery of the formation fluids. In situations where
existing
26 perforations are deemed inadequate the formation can be stimulated using a
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1 variety of other techniques such as acidizing, fracturing, flushing, or re-
2 perforating, any of which can produce debris.
3 Forms of debris include drilling or perforation debris, debris from
4 cementing operations, and/or mud solids. Naturally occurring debris such as
sand, silts or clays can also be present. In some formations shales and shale
6 chunks, pyrite, coal and other fragmented sections of formations can be
7 produced. This debris should be quickly removed from the wellbore or
formation
8 in order to prevent it from causing a blockage, or eroding or damaging
production
9 equipment. In some instances the removal of increased volume of debris can
substantially enhance production.
11 Completion or stimulation methods include a method described in
12 US Patent Re. 34,451 to Donovan et al wherein a perforating gun with an
13 external auger is mounted to a tubing string to both aid in clean-up of the
debris
14 from the perforations as well as to facilitate the movement of the gun out
of the
debris. The auger flights create a tortuous path increasing the velocity of
16 produced formation fluids and improves the ability of those fluids to carry
debris.
17 Hydrostatic loll fluid is circulated to remove debris and produced
hydrocarbons.
18 Thereafter, proppent is pumped down tubing and into the formation. The
auger
19 facilitates the removal of the gun packed in the sand.
In US Patent 4,560,000 to Upchurch a well perforating technique
21 actuates a firing mechanism of a tubing-conveyed perforating gun using a
22 pressure difference between at different points in the borehole. The
technique
23 obtains the benefit of underbalanced conditions to aid in creating a
localized
24 cleansing effect as the formation fluids enter the well casing.
2
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1 Further, Applicant was part of the development of an aggressive
2 perforating-while-foaming (PWF) production process to increase the
production
3 capability of a well. This process has gained wide usage over the last 4
years
4 within the heavy oil industry, specifically wells drilled into
unconsolidated
sandstone formations. This method produced more sand in a shorter period of
6 time than other more traditional methods. It is strongly suspected that this
7 immediate removal of sand is linked to the superior performance of these
wells.
8 A perforating gun is tubing conveyed down an underbalanced well. The gun is
9 detonated using a drop bar and remote trigger. Foam is almost simultaneously
injected and continuously circulated through the wellbore, carrying with it
debris
11 from the formation.
12 Although continuous circulation of foam effectively removes debris
13 from the wellbore in the PWF process, the remote trigger can create un-safe
work
14 practices as a result. As well, drop-bars are not considered practical in
highly
deviated wells since the bar may not reach the bottom. Upchurch relies solely
on
16 formation pressure to clean out the wellbore, which can be insufficient in
low
17 pressurized formations and can prevent comprehensive elimination of debris
from
18 the wellbore. Donovan's method is also dependent on formation pressure to
19 clean out the perforation debris from the wellbore, but is aided by the
auger
blades. Removal of wellbore debris is not a controlled factor in either case.
If
21 debris is not completely removed from the wellbore, it may block
perforations,
22 limit production, damage production equipment, or plug the outside or the
inside
23 of the production tubing reducing, partially or totally restricting
production. In
24 such instances, well clean-out procedures would be repeatedly required at a
large expense.
3
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1
2 SUMMARY OF THE INVENTION
3 A process is described for creating openings in a well casing and
4 which substantially and immediately accommodates clean-up and production of
debris. In a preferred embodiment, a pressure-actuated perforating gun is
fired
6 adjacent a zone in the formation to be perforated for forming openings.
7 Substantially immediately thereafter, a fluid is continuously injected
through a
8 downhole pressure-actuated injection means or port near the openings and is
9 circulated up through a wellbore at a sufficient velocity or elutriation
rate
overcome settling of debris and therefore to remove and lift debris from the
11 formation. Optionally, an uphole foam injection means or port can aid in
12 adjusting the hydrostatic head above the perforating gun. The tubing string
13 extends sufficiently above the wellbore at surface to enable lowering of
the tubing
14 string and downhole injection means or port to below the openings for
enhanced
removal of debris.
16 In a broad aspect, a process for creating openings between a
17 wellbore and a formation comprises running-in a tubing string into the
wellbore to
18 position a perforating gun adjacent a perforating zone, pressurizing to a
first
19 pressure to fire the perforating gun and produce openings between the
wellbore
and the formation, pressurizing to a second pressure to actuate a downhole
21 injection means and injecting fluid therethrough at a sufficient velocity
or
22 elutriation rate to convey debris from the wellbore by circulating the
fluid out
23 through the downhole injection means of the wellbore to at surface. It is
24 preferable to lower the tubing string during circulation so as to re-
position the
4
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1 location of the downhole injection means to below the openings. Typically
2 thereafter the tubing string is then removed.
3 In another broad aspect, an apparatus for creating openings
4 between a wellbore and a formation comprises a tubing string in the casing
and
extending downhole from surface for positioning a perforating gun adjacent a
6 perforating zone and forming an annulus between the tubing string and the
7 casing, a downhole injection port located on the tubing string for injection
of fluid
8 at an elutriation rate so as to continuously remove debris from the
wellbore, and
9 means to pressurize the tubing for firing the perforating gun and opening
the
downhole injection means. An uphole foam injection means can be located on
11 the tubing string for cleaning out the well and displacing wellbore fluid
to create a
12 desired fluid level.
5
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1 BRIEF DESCRIPTION OF THE DRAWINGS
2 Figures 1 a - 1 b are a simplified cross-sections of a wellbore
3 illustrating apparatus run-in on a tubing string for placement of a
perforating gun
4 adjacent a formation before firing and for injection fluids, respectively;
Figures 2a - 2g are a series of schematics of stages of the
6 methodology according to one embodiment of the invention; and
7 Figure 3a - 3c are flowcharts of some steps of an embodiment of
8 the invention according to Figs. 2a-2g and illustrating some optional
9 embodiments.
6
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1 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
2 With reference to Fig. 1 a, in a preferred embodiment, it is desirable
3 to create openings 10 in a well casing 12 of a wellbore annulus 14 or
wellbore 16
4 adjacent an underground formation 18. Herein, the openings 10 are more
conventionally referred to as perforations 20 which enable communication
6 between the wellbore 16 and the formation 18 through the casing 12.
Generally,
7 the perforations 20 are created by firing a perforating gun 22 in the
wellbore 16.
8 Debris generally exists in the formation and in the casing which results
from
9 operations including drilling or perforation debris, debris from cementing
operations, and from mud solids. Naturally occurring debris such as sand,
silts or
11 clays can also be present in the formation. In some formations shale, shale
12 chunks, pyrite, coal and other fragmented particles of the formation can be
13 produced.
14 As shown in Fig. 1 b and Figs. 2c and 2d, dabris is removed by
substantially immediately commencing to inject and circulate a fluid 24 at
16 sufficient velocities or rates so as to overcome settling velocities from
some or
17 substantially all of the debris for the fluid and lift this debris to
surface 26. Such
18 rates are termed herein as elutriation rates.
19 Fluids 24 are chosen for their elutriation characteristics, such as
density, viscosity, and flow velocities as well as how they interact with
wellbore
21 fluid 46 and formation fluids 66. The possibility of formation damage
should
22 always be considered when choosing a fluid 24. Fluid 24 options can include
low
23 density foams, gases, or liquids.
24 As shown in Figs. 1 a,1 b, the formation 18 and wellbore 16 are
prepared for an aggressive completion or stimulation techniques using a
7
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1 preferred embodiment of the present invention. A suitable wellhead
configuration
2 comprises a spool 28 having a fluid and debris outlet 30 providing
communication
3 with the wellbore 16, a blow-out preventor 32 and a pack-off 34 at a
wellhead 36,
4 and a fluid injection inlet 38.
With reference also to Figs. 2a-2g and Figs. 3a-3c, a completion is
6 prepared comprising a tubing string 40 fit at its distal end with the
pressure-
? actuated perforating gun 22 set to fire at a first pressure, and a downhole
8 injection means or port 42 set to open or burst at a second pressure. The
9 downhole injection port 42 is located uphole of the perforating gun 22. The
tubing string 40 is made up with conventional components to assist in
11 establishing a tubing tally and the like.
12 The apparatus enables injection of fluid 24 for lifting debris from the
13 wellbore 16 such as when there is not sufficient formation production
volume or
14 pressure to remove the debris or where the debris has a high enough density
to
be unaffected by usual formation production. Circulation of a suitable fluid
24 can
16 be implemented providing enhanced lift. Such fluid 24 is circulated at
sufficient
17 velocity, viscosity and density or elutriation conditiors and rates to
remove the
18 debris.
19 Generally, a fluid level 62 is established above the perforating gun
22. Circulation of fluid 24 is established through the fluid injection inlet
38 at the
21 surface 26 and wellbore fluid 46 and fluid 24 are recovered through the
spool 28
22 at the surface 26. Additionally, the downhole injection port 42 is
preferably a
23 conventional pressure-activated 'S' drain or burst plug 50.
24 At Fig. 2a and step 100 of Fig. 3a (Fig.3a,100), if the well is a good
candidate for the operation, the tubing string 40 is run in Fig.3a,101 and
8
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1 preferably positioned Fig.3a,102 in the wellbore 16 such that the
perforating gun
2 22 is located across from a zone 60 to be perforated and is covered by some
3 wellbore fluid 46. Of course, safe procedures must be used in a completions
4 operation or stimulation technique including proper tubing string entry
techniques.
The tubing string 40 is packed off above the wellbore 16, as shown in Figs.
6 1 a,1 b.
7 As shown in Fig. 2b and Fig. 3b at A, if the desired fluid level 62
8 exists Fig. 3a,103, the tubing string 40 is pressurized using pressurizing
means
9 and the perforating gun is actuated. The fluid level 62 creates a minimum
hydrostatic pressure above the perforating gun 22 allowing maximum inflow from
11 the formation 18 once the formation 18 is perforated, but covers the
perforating
12 gun 22 to keep it from splitting.
13 The tubing string 40 is pressurized Fig.3b,104 to the first pressure
14 far actuati ng a firing head 54 of the perforating gun 22 and forming
perforations
20. Activation of the perforating gun 22 is not affected by its orientation in
the
16 well casing 12. An explosion 64 creating perforations 20 in the well casing
12
17 between the wellbore 16 and the reservoir or formation 18 for recovery of
18 formation fluids 66.
19 At Fig. 3b,105 if a misfire occurs and the drain 50 is blown or
opened, the tubing string 40 needs to removed and the problem diagnosed Fig.
21 3b,106. If required, the 'S' drain, burst plug 50 and/or firing head 54 are
serviced
22 or replaced. The tubing string 40 is run-in hole and the process starts
again.
23 As shown in Fig. 2c, and if there was no misfire, as soon as
24 physically possible, substantially immediately after firing the perforating
gun 22,
fluid 24 is continued to be pumped into the tubing string 40, applying further
9
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1 pressure Fig.3b,107 to a second pressure, greater than the first pressure,
for
2 actuating the pressure-actuated "S" drain or burst plug 50, at the downhole
3 injection port 42 enabling fluid communication therethrough with the
wellbore 16.
4 A pump, or optionally, pressurized gas may be used to apply pressure in the
tubing string 40.
6 Circulation of the fluid 24 conveys or aides the conveyance of the
7 debris up the wellbore 16 to the surface 26 for removal of substantially all
debris.
8 Turning to Fig. 2d and to Fig. 3c,108, when circulating fluid 24 and
9 for more effective removal of the debris, the tubing string 40 is slowly
lowered so
that downhole injection port 42 is below the perforations 20. At Fig. 2e and
Fig.
11 3c,109, it can be desirable in some instances to stroke, or lower and
raise, the
12 tubing string 40 periodically to prevent lodging of the debris and sand
flowing into
13 the wellbore 16 between the tubing string 40 and well casing 12. This
action can
14 continue until sufficient debris has been successfully removed.
Once the operation is complete and sufficient debris has been
16 removed from the wellbore 16, the well's productivity thereafter is
increased.
17 At Fig. 2e and Fig. 3c,110 the tubing string 40 is then raised to
18 elevate the perforating gun 22 above the perforations 20. At Fig. 2f and
Fig.
19 3c,111, one of a variety of techniques can be used to apply sufficient
hydrostatic
head to kill the well before safely pulling Fig. 3c,112 the tubing string 40
from the
21 wellbore 16. Typically the methodology for killing the well is tailored to
the
22 particular well and can include simply diminishing fluid 24 circulation to
allow
23 formation fluid 66 production to fill the annulus 14 and kill the well or
more
24 aggressively load up with suitable wellbore fluid 46.
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1 At Fig. 2g, and as an objective of rehabilitating the formation 18, a
2 production string 68 with a production pump 70 can be run in to re-establish
3 production from the treated well.
4 In an alternate embodiment, and returning at Fig. 3a, 103 if the fluid
level 62 is deemed inappropriate, and as shown in Fig. 2b the hydrostatic head
6 may be adjusted. If the fluid level is too low Fig. 3a,103,B, conventional
wellbore
7 fluid 46 can be added Fig. 3b,200 to the wellbore 16 for increasing or
creating an
8 optimal fluid level 62 by adding wellbore fluid 46 down the annulus.
9 In another embodiment of the invention, at Figs. 2a,2b and Fig.
3a,103,C it may be desirable to reduce the hydrostatic head above the
11 perforating gun 22. An optional uphole injection means or port 44 is
located
12 uphole of the downhole injection port 42. The uphole injection port 44 is
13 preferably a conventional rotational valve 48. The rotational valve 48 is
14 strategically located to establish the desired fluid level 62 uphole of the
downhole
injection port 42 and the perforating gun 22.
16 In Figs. 2a and Fig.3a,101, the tubing string 40 is lowered into the
17 wellbore 16 with the rotational valve 48 in the open position. If the well
has not
18 been previously cleaned out, or if too much hydrostatic pressure exists, at
19 Fig.3a,102 a well depth 56 is tagged and low density foam or suitable fluid
can be
circulated through the rotational valve 48 to displace any wellbore fluid 46
to
21 create the desired fluid level 62. The rotational valve 48 can be
positioned at
22 other locations in the wellbore 16 and fluid 24 circulated Fig. 3b,300 to
remove
23 wellbore fluid 46 above the rotational valve 48, resulting in the desired
fluid level
24 62. Thereafter, the perforating gun 22 may need to be re-positioned to
align with
the zone 60 to be perforated. Accordingly, at Fig. 2b and Fig. 3b, 301, the
tubing
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1 is rotated to close the rotational valve 48, discontinuing any foam
injection and
2 creating a continuously sealed tubing string 40 for pressurizing.
3 The preferred fluid 24 is low density foam. Inherently, foam has a
4 high viscosity at low shear rates making it extremely useful as a
circulating
medium in low pressure reservoirs. These properties minimize fluid loss to the
6 formation and reduce needed annular velocities yet provide sufficient debris
7 elutriation with high lifting capability at minimum circulating pressures.
Circulation
8 conditions including bam generated with natural gas or nitrogen instead of
air
9 can be used to clean out higher pressure wells.
Alternatively, production fluids can also be used. A variety of
11 natural and process additives or polymers are available to increase the
lifting,
12 carrying and suspending capability of the fluid.
13 It will be readily apparent to those skilled in the art that many
14 variations, application, modifications and extensions of the basic
principles
involved in the disclosed embodiments may be made without departing from its
16 spirit or scope.
17 As suggested n Fig. 3a at 100, some wells are better candidates
18 than others for this process, and while this process was developed for the
criteria
19 described below, is not limited to these applications which include:
~ Sand production initiation in stubborn sand formations for
21 cold heavy oil production with sand ,
22 ~ Known drilling damage completions,
23 ~ Enhanced and rapid drainage geometry development, and
24 ~ Enhanced initial and cumulative production.
12
