Note: Descriptions are shown in the official language in which they were submitted.
CA 02951814 2016-12-15
1 "METHODS AND ELECTRICALLY-ACTUATED APPARATUS FOR WELLBORE
2 OPERATIONS"
3
4
6
7
8
9
11 FIELD
12
Embodiments of the disclosure relate to methods and apparatus used
13 for
completion of a wellbore and, more particularly, to methods utilizing
electrically-
14 actuated apparatus for performing completion operations and optionally,
simultaneous microseismic monitoring thereof.
16
17 BACKGROUND
18
Apparatus and methods are known for single-trip completions of
19
deviated wellbores, such as horizontal wellbores. To date, unlike the drilling
industry
which commonly utilizes intelligent apparatus for drilling wellbores,
particularly
21
horizontal or deviated wellbores, the fracturing industry has relied largely
on
22
mechanically-actuated apparatus to perform at least a majority of the
operations
23
required to complete a wellbore. This is particularly the case with coiled-
tubing
1
CA 02951814 2016-12-15
1
deployed bottom hole assemblies (BHA's), largely due to the difficulty in
providing
2
sufficient, reliable electrical signals and power from surface to the BHA and
from the
3 BHA to surface.
4 It is
known to deploy BHA's for completion operations using jointed
tubular, wireline or cable and using coiled tubing (CT). Further it is known
to use
6
wireline deployed within an interior of CT to actuate conventional select-fire
7
perforation charges and to transmit signals associated with casing-collar
locators
8 used in depth measurement such as taught in US Patent 7,059,407.
9 As new
resources are being developed, the industry has an interest in
fracturing operations in horizontal wells, such as wellbores which may have
minimal
11
vertical portions and very long horizontal wellbores. Use of coiled tubing to
deploy
12
conventional BHA's, particularly using small diameter CT, is problematic in
such
13
wellbores as one cannot easily run in CT to the toe of the very long
horizontal
14 wellbores.
, Generally, a conventional BHA for use with CT and used for
16
completion of new wellbores incorporates a jetting sub for perforation of
casing or
17 the
wellbore wall and a single sealing element, such as a resettable bridge plug,
for
18 sealing
the wellbore below the jetted perforations for treating the formation
19
therethrough. The treatment fluid, such as a fracturing fluid, is then pumped
through
the annulus between the casing and the CT, or through the bore of the CT, or
both.
21 In the
case of previously perforated wellbores, a separate BHA is used
22 which
incorporates two spaced-apart sealing elements, such as packer cups or
2
I I
CA 02951814 2016-12-15
1 mechanically-set or hydraulically-set packers, which straddle the existing
2 perforations. Treatment fluid is delivered through the bore of the CT to
be delivered
3 to the perforations isolated between the sealing elements.
4 Prior art tools used for performing fracturing operations at
multiple
zones in a formation have used wireline deployed, electrically-actuated bridge
plugs
6 which are pumped into the wellbore. The known pump-down bridge plugs have
a
7 single, fixed diameter being slightly smaller than the wellbore for
deployment into
8 the wellbore and require a valve at a toe of the wellbore to get rid of
fluid used to
9 pump the bridge plug into place. As wireline is comparatively weak and
cannot pull
more than about 2500 lbs at surface, and much less at depth, the wireline
cannot be
11 reliably used to release or to pull the bridge plugs to surface. Thus,
multiple bridge
12 plugs must be used and left in the wellbore to be drilled out later, at
considerable
13 expense. After the bridge plug has been set, the casing is perforated
with
14 perforating guns located above the bridge plug. The bridge plug and the
perforating
guns are often deployed together so that both operations, isolating and
perforating,
16 can be done in the same wireline run. When the perforations have been
shot, the
17 wireline is pulled out of the hole and the fracture fluid is pumped
through the casing.
18 Once the fracture is completed, the steps of setting the bridge plug and
perforating
19 followed by pumping the frac are repeated for sequential uphole
intervals until the
fracturing job on the wellbore is complete. This method is commonly referred
to as
21 "plug and perf". Following fracturing of all of the zones, the bridge
plugs are drilled
22 out.
3
I I
CA 02951814 2016-12-15
1
Conventional perforating guns are also incorporated into BHA's which
2 are
used for completion of new wellbores. Typically, conventional perforating guns
3 utilize
detonation cord for connecting between and actuating a plurality of spaced
4 apart
shaped charges therein which results in a very long perforating gun.
Generally, in embodiments of conventional operations, it is desirable to
perforate as
6 many
zones as possible in a single run. In order to maximize the number zones
7 which
can be perforated, very long conventional select-fire perforating guns are
8
required. The length of the perforating guns impacts conventional operations,
9
requiring very tall cranes and other support apparatus to hold and inject the
very
long gun assemblies and BHA into very tall lubricators, often exceeding about
30
11 meters.
In many cases, the number of zones which can be perforated in a single trip
12 is limited to permit a reasonable length for the BHA and lubrication
apparatus.
13 In many
cases, at least two separate BHA's are required when
14
operators are fracturing both new wellbores and previously perforated
wellbore. In
the case of new wellbores, once perforations are formed or a sliding sleeve is
16
actuated to open pre-existing ports in the casing, a single isolation
apparatus is
17 used to
seal the annulus therebelow to isolate the newly-formed perforations to be
18 treated
from the previous perforations formed therebelow. Treatment fluid can be
19
delivered to the formation through the annulus between the casing and the ct,
or, in
some cases, through the CT, or through both at the same time. In the case of
old
21
wellbores having previously formed perforations or opened ports therein,
particularly
22 where
sleeves cannot be actuated to close, two spaced apart isolation apparatus
4
I I
CA 02951814 2016-12-15
1 are
required to straddle the perforations or ports to be treated and treatment
fluid is
2 delivered through the tubing string to the isolated perforations or ports
3 therebetween.
4 As will
be appreciated by those of skill in the art, monitoring pressure
downhole during fracturing operations is indicative of how the formation is
reacting
6 to the
fracturing operation and may also be indicative of the integrity of the
isolation
7 apparatus and the formation between adjacent zones. Generally, downhole
8
pressures are not monitored directly, but instead are calculated from
parameters
9
measurable at surface. For example, when treatment fluid is delivered to the
formation through one or the other of the annulus or the tubing string, the
other can
11 act as
a "dead leg". For example, when the treatment fluid is delivered through the
12
annulus, a minimal, constant amount of a deadhead fluid is delivered through
the
13 tubing
string to act as the "dead leg", maintaining pressure within the tubing
string.
14 The
pressure required to maintain the constant fluid delivery is monitored from
surface and can be used for calculating fracture extension pressure and
formation
16 breakdown pressure, as well as fracture closure pressure.
17 It is
known to use microseismic monitoring where operators wish to
18 monitor
fracture growth and development, either in real time or retroactively to
19
optimize subsequent fracturing operations. Prior art systems typically require
a
conveniently located offset observation wellbore and wireline truck to deploy
an
21 array
of sensors in the observation wellbore, which can monitor the fracturing
22
operation. Alternatively, an extensive microseismic surface array may be used.
Both
5
I I
CA 02951814 2016-12-15
1 systems benefit from use of a multi-string shot tool (MSST) for creating
known
2 microseismic. events as a result of detonation of string shots therewith
at known
3 locations in the wellbore to aid in developing more accurate velocity
profiles and
4 calibrating the sensors.
Clearly, there is great interest in the industry to develop tools which
6 enable completion of multiple zones in a single trip while optimizing the
apparatus
7 required and reducing cost and operational man hours. There is a further
interest in
8 apparatus and methods for improving the ability to accurately monitor
fracture
9 growth and placement for optimizing fracturing operations. Further, there
is interest
in developing tools having diagnostic capabilities that would greatly improve
the
11 reliability of the tools and processes used.
12
13 SUMMARY
14 Embodiments of systems and methods for completion of a wellbore
disclosed herein utilize electrically-enabled coiled tubing for bidirectional
16 communication of signals between a bottomhole assembly (BHA) and surface
and
17 for providing 'power to the BHA components which can be electrically
actuated or a
18 combination of electrically-actuated and mechanically-actuated
components. The
19 BHA comprises at least one electrically-actuated, variable diameter
packer located
below treatment ports and which is substantially infinitely variable with
respect to
21 diameter within the limitations of the actuation mechanism. The packer
has
22 elements which can be expanded to seal the wellbore, to act as a piston
for
6
I I
CA 02951814 2016-12-15
1 pumping the BHA downhole and for pulling the CT therewith, or to fully
retract and
2 at any diameter therebetween.
3 When the BHA further comprises two or more, spaced apart, variable
4 diameter packers, positionable on either side of treatment ports, the
packers can be
individually controlled with respect to diameter for opening and closing a
variety of
6 fluid pathways between the wellbore and the BHA having functionality
heretofore
7 impossible with conventional completion tools.
8 In embodiments, the BHA can further comprise additional components
9 such as perforating apparatus, casing collar locators for locating within
cased and
lined wellbores, microseismic sensors, fiber optics, sensors for directly
measuring
11 pressure, temperature, vibration, strain and other parameters related to
the BHA
12 and completion operation. The further components can be electrically-
actuated or
13 powered or can be mechanical or combinations thereof.
14
BRIEF DESCRIPTION OF THE DRAWINGS
16 Figure 1A is a representative illustration of a bottomhole
assembly
17 BHA according to an embodiment of the disclosure and having a single,
variable
18 diameter packer incorporated therein;
19 Figure 1B is a fanciful cross-sectional view according to Fig. 1A;
Figures 2A-2C are fanciful cross-sectional views of a variable
21 diameter packer according to Fig. 1A; more particularly,
7
CA 02951814 2016-12-15
1 Fig. 2A
illustrates elements of the packer expanded to a slightly
2 smaller
diameter than an inner diameter of a wellbore in which the
3 centralized packer is being pumped downhole by fluid drive;
4 Fig. 2B
illustrates elements of the packer retracted to permit
passage of the packer by debris in the wellbore in which the centralized
6 packer is being pumped downhole; and
7 Fig. 2C
illustrates elements of the packer fully retracted to
8 permit pulling the packer uphole in the wellbore;
9 Figure
3A is a representative illustration of a selectively actuated
perforating gun incorporated in a BHA according to Fig. 1A;
11 Figure 3B is a cross-sectional view according to Fig. 3A;
12 Figure
30 is an illustration of a plurality of segments forming a portion
13 of an
embodiment of a perforating gun assembly positioned in a wellbore, shown
14 without
the top sub or connection to the wireline or electrically-enabled for
illustrative purposes only, perforations being shown (solid black) to
illustrate the
16 effect of detonation of shaped charges therein;
17 Figure
3D is a cross-sectional view of a segment of the plurality of
18 segments, according to Fig. 3C;
19 Figure
3E is a sectional view of a segment of the perforating gun
assembly according to Fig. 30;
21 Figure 3F is an exploded view according to Fig. 3E;
8
I I
CA 02951814 2016-12-15
1 ,
Figure 4 is a representative illustration of a BHA according to Fig. 1A,
2
deployed in a wellbore using electronically-enabled coiled tubing, a plurality
of
3
selectively actuated perforating gun assemblies in the BHA being
electronically
4 connected to a firing panel at surface;
Figures 5A-5D are representative illustrations of use of an
6
embodiment of the BHA according to Fig. 1A for perforating and fracturing a
7 formation according to embodiments of the disclosure, more particularly
8 Fig. 5A
illustrates selective actuation of a segment of the
9
perforating gun for forming a perforation uphole from a previous perforation
in a wellbore;
11 Fig. 5B
illustrates repositioning of the BHA to position the
12 variable volume packer below the perforations created in Fig. 5A; and
13 Fig. 50
illustrates fracturing through the perforations created in
14 Fig. 5A
and above the packer, fracturing fluid being delivered through the
coiled tubing for delivery from fracturing ports in the BHA to the
perforations;
16 Fig. 50
illustrates reverse circulation of debris from the annulus
17 to
surface after fracturing, clean fluid being delivered through the annulus to
18 the
fracturing ports and open fluid path in the valve for circulation of debris to
19 surface;
Figure 6 is a diagrammatic representation of a process for minimizing
21
decrease in rock stress about a previously fractured zone during fracturing of
an
22
adjacent zone, fracturing fluid being delivered to the annulus above the
packer at
9
CA 02951814 2016-12-15
1 pressure P1 and fluid being delivered through the coiled tubing to the
annulus below
2 the packer at P2, P2 being greater than P1 for pressuring the formation
about the
3 previous fracture;
4 'Figure
7 is a representative illustration of a bottomhole assembly BHA
according to Fig. 1A having two, spaced-apart, variable diameter packers
6 incorporated therein, a first packer being below the fracturing ports and
valve, and a
7 second packer being above the fracturing ports and valve;
8 Figure
8A is a representative illustration of a bottomhole assembly
9 BHA according Fig. 7 and having fracturing ports between the two spaced
apart
packers instead of a valve;
11 Figure
8B is a representative illustration of a bottom hole assembly
12 according to an embodiment having equalization valves associated with
first and
13 second packers actuable for pressure equalization across the first and
second
14 packers before moving the BHA in the wellbore;
Figure 9 is a representative illustration of a BHA according to an
16 embodiment having microseismic sensors incorporated therein and in
combination
17 with a linear array of fiber optic sensors deployed along at least a
portion of a
18 horizontal wellbore; and
19 Figure
10 is a table representing a variety of embodiments of the BHA
according to embodiments disclosed herein.
21
22
CA 02951814 2016-12-15
1 DETAILED DESCRIPTION
2 '
Embodiments are described herein in the context of fracturing
3 however as one of skill in the art will understand, systems and methods
disclosed
4 herein are also applicable to other completion and stimulation
operations.
Embodiments described herein utilize electrically-actuated downhole
6 tools incorporated into a bottom-hole assembly (BHA) for completion of
multiple
7 zones of interest in a formation during a single trip into the wellbore.
Use of
8 electrically-actuated BHA components permits functionality heretofore not
seen in
9 conventional, mechanically-actuated BHA components. In embodiments,
separate
electrically-actuated drive components permit independent operation of optimal
11 BHA components, used individually or in combination, such as isolation
apparatus,
12 perforating apparatus, fracturing subs, microseismic monitoring
apparatus, and the
13 like. Further, use of the electrically-actuated tools allows the BHA to
be more
14 compact than conventional BHA's used for the same purposes, suitable for
lubricator deployment. One further advantage is that tools incorporated in the
BHA,
16 such as perforating guns, actuated electrically from surface provide
accurate times
17 of perforation and actuation of fracturing operations which aid in more
accurate
18 microseismic monitoring of fracture growth and placement.
19 In
embodiments, most, if not all, of the components of the BHA are
electrically actuated. In other embodiments, only some of the components are
21 electrically actuated for maximal advantage and are used together with
22 mechanically-actuated components.
11
CA 02951814 2016-12-15
1 While
applicable to a variety of wellbore types, apparatus and
2 methods
described herein are particularly suitable for deviated, horizontal or
3 directional wellbores and particularly those of very long or extended
length.
4 The
terms "uphole" and "downhole" used herein are applicable
regardless the type of wellbore; "downhole" indicating being toward a distal
end or
6 toe of
the wellbore and "uphole" indicating being toward a proximal end or surface
7 of the
wellbore. Further, the terms "electronically-actuated" and "electrically-
8 actuated" are used interchangeably herein and may be dependent upon the
9 characteristics of the component being actuated.
Bottom hole apparatus (BHA) 10, according to embodiments
11 described herein, are deployed on coiled tubing (CT) 12. Bi-directional
12
communication for actuation of the electrically-actuated tools from surface
and
13 receipt
of data therefrom is possible using electrically-enabled CT 12, such as
14
described in co-pending, US published application US2008/0263848 to
Andreychuk,
referred to herein as electrically-enabled CT. Electrical conductors 14, such
as a
16
wireline, multi-conductor cables, fiber optic cables and combinations thereof
are
17
retained to an inner wall of the CT 12 to avoid problems associated with
loosely
18 hanging
cabling and to permit reliable and resilient reeling and unreeling of the CT
19 12
during repeated operations. In an embodiment multiple conductors 14 are
surrounded by an outer insulated sheath for forming a protected cable for
welding
21
directly to the inner wall of the CT 12, and heat treated together with the CT
12
22 during
manufacturing prior to use. The electrically-enabled CT can be used to
12
CA 02951814 2016-12-15
1 simultaneously conduct fluid as well as electrical service pulses and
signals, as well
2 as power.
3 As one of skill in the art will understand, any electrically-
enabled CT
4 12, which provides sufficient electrical capability to actuate components
in the BHA
10 as well as permits bi-directional communication between the BHA 10 and
6 surface, would be suitable for use in embodiments described herein.
7 Applicant believes that fracturing operations are particularly
useful in
8 horizontal wells, such as wellbores 16 which have minimal vertical
portions and very
9 long horizontal wellbores, for example, wellbores with horizontal
portions extending
to at a measured depth of at least 23,000 feet in the Williston Basin, an area
which
11 extends from southern Saskatchewan and Manitoba, Canada into Montana,
North
12 Dakota and South Dakota, USA. Further, fracturing operations can be
performed on
13 offshore wellbores. Coiled tubing (CT) 12 can be used in such
operations. The
14 diameter of the CT 12, and the length of the horizontal wellbore 16
which can be
accessed using conventional CT-deployed apparatus and methodologies, are
16 largely dictated by the displacement required to push the CT 12 into the
very long
17 wellbores 16, Embodiments disclosed herein permit use of relatively
small diameter
18 CT 12, such as 11,6 inch electrically-enabled CT to deploy the BHA 10 to
the toe of a
19 very long wellbore 16. Further, use of CT 12, unlike pulling limitations
of
conventional wireline, can exert much higher pulling forces depending upon the
CT
21 size and material specifications, being sufficient to raise the BHA 10
therefrom to
22 surface S.
13
I I
CA 02951814 2016-12-15
1 Embodiments described herein are useful for treating or fracturing
2 new wellbores 16, both completed with casing 18 and open-hole wellbores
20, or
3 previously perforated cased wellbores 16, or open-hole wellbores.
4 More particularly, an embodiment comprising first and second
separately controllable, spaced apart electrically-actuated variable diameter
packers
6 22f, 22s, operated as described in greater detail below, can be used for
operations
7 in both new and old wellbores using a single BHA 10. The first and second
packers
8 22f, 22 are substantially infinitely variable with respect to diameter
within the
9 limitations of the actuation means.
Embodiments described herein are used to select an optimal
11 fracturing operation such as that which permits reducing pumping rates
and
12 volumes compared to conventional pumping rates and volumes. Often the
pumping
13 rates are set by the large size of CT used to access the total depth of
the wellbore.
14 Using embodiments describe herein permits reducing the diameter of the
electrically-enabled CT 12 compared to conventional CT used for fracturing.
Using
16 conventional apparatus and methodologies, reductions in diameter of the
CT 12 to a
17 small diameter CT 12 has presented difficulties as the small CT 12 is
difficult to
18 push to the toe of very long wellbores 16.
19
SINGLE PACKER EMBODIMENTS
21 Having reference to Figs. 1A and 1B, a bottom-hole assembly (BHA)
22 10 deployable using electrically-enabled coiled tubing 12, is shown.
When deployed
14
I I
CA 02951814 2016-12-15
1 into the wellbore 16, being cased 18, an annulus 34 is formed between the
BHA 10
2 and the casing 18. The electrically-enabled CT 12 is capable of
conducting fluid F
3 through a bore 38 extending therethrough as well as electrical pulses and
signals
4 through the conductors 14 retained therein.
Beginning at a proximal end 40, the BHA 10 comprises at least a
6 fracturing head 55, having a plurality of fracturing ports 56 and an
electrically-
7 actuable valve 50 therein and a first electrically-actuated variable
diameter packer
8 22f positioned therebelow.
9 In an embodiment the BHA 10 is fluidly connected to a distal end
42 of
the electrically-enabled CT 12 through a ball-actuated release sub or
disconnect 44
11 as is understood in the art. Electrical connection between the
electrically-enabled
12 CT 12 and the BHA's components therebelow can be accomplished in a
number of
13 ways, including but not limited to conductors extending therefrom
through a bore 46
14 of the BHA 10 or conductors extending therefrom through an electrical
race formed
about a periphery of the BHA's components.
16 The fracturing head 55 comprises the valve 50, such as an
17 electrically-actuated solenoid valve. Best seen in Fig. 1B the valve 50
is fluidly
18 connected to, the bore 38 of the electrically-enabled CT 12 through the
ball-actuated
19 disconnect 44. The valve 50 comprises a housing 52 having a throughbore
54
formed therethrough contiguous with the bore 38 of the CT 12 and the bore 46
of
21 the remainder of the BHA 10 therebelow. The plurality of fracturing
ports 56 extend
I I
CA 02951814 2016-12-15
1 radially outwardly from the throughbore 54 through the housing 52 for
delivery of
2 fluid F therethrough.
3 The valve 50 can be electrically-actuated to a first position to
divert
4 fluids F, flowing from the CT 12 through the plurality of fracturing
ports 56. When
actuated to a second position, the valve 50 permits the flow of fluids F in
the
6 throughbore 54 to be delivered through the bore 46 of the BHA 10
therebelow and
7 to the annulus 34, such as through a fluid crossover port 60. Valve 50
could be
8 configured to isolate the throughbore 54 from the annulus
9 The valve 50 is operatively connected to an electric valve drive
62
which receives signals from surface through the electrically-enabled CT 12 for
11 controlling the position of the valve 50.
12 Having reference to Figs. 1B and 2A-2C, the BHA 10 further
13 comprises the first variable diameter packer 22f operable between at
least two
14 positions: sealed to the wellbore or undersized for pumping. When in the
sealed
position the first packer 22f functions to seal the annulus 34 between the BHA
10
16 and the casing 18 or wellbore wall 36 when actuated to expand to a
sealing
17 diameter. The first packer 22f further comprises slips for anchoring the
first packer
18 22f in the wellbore which are actuated to engage the casing 18 or
wellbore 16 when
19 the firsrt packer 22f is expanded to the sealing diameter.
In the second position, the first variable diameter packer 22f is sized to
21 a running position, forming an uphole piston face 64 when expanded to a
running
22 diameter, being greater than a minimum packer diameter when the packer
22f is in
16
CA 02951814 2016-12-15
1 a
third, fully retracted position, and less than a diameter of the casing 18 or
wellbore
2 16. In
the running position, the running diameter of the first packer 22f is sized to
3 just
under casing drift. Fluid F is pumped through the annulus 34 against the
uphole
4 piston face 64 to push the first packer 22f, and BHA 10 connected thereto,
downhole.
6 The
running diameter is variable and depends upon a number of
7
variables such as friction, horizontal length of the wellbore 16, the size and
8
parameters related to the CT, the weight of the BHA and the like. In general
the
9 running
diameter is the smallest diameter which works to effectively move the BHA
10 downhole with sufficient pulling force to pull the CT 12 therewith.
11 The BHA
can be fit with a strain gauge (not shown) which can
12 measure
axial load in the BHA 10 to assist the operator to understand if the piston
13 force
on the first packer 22f is too high and also to understand where resistance
14 may be
coming from, being either from debris in the wellbore 16 or as a result of
drag friction of the CT 12. As one of skill in the art will appreciate, the
strain gauges
16 or
sensors provide data to surface through the CT 12 to assist with determining
an
17
appropriate balance between injection rates and pumping rates to avoid pulling
the
18 BHA 10
apart. In, other words, the CT and BHA form an injection string, the system
19 further
comprising a strain sensor along the injection string uphole of the packer,
such as in the BHA 10 above the packer 22f, the strain sensor electrically
21
connected to the CT for providing signals indicative of axial loading in the
string at
22 about
BHA. A controller is provided for receiving axial loading signals and for
17
CA 02951814 2016-12-15
1 managing a rate of injection of the CT and a rate of pumping of the BHA
for
2 managing the axial loading. The controller is typically located at
surface.
3 Further, the wellbore 16 might be fit with a toe burst sub (not
shown)
4 to enable pump down so that fluid displaced below the first packer 22f
can be
pushed into the formation 30 at the toe of the wellbore 16. The CT 12 is
pulled
6 therewith for positioning the BHA 10 at zones of interest in the
formation 30 over
7 very long horizontal wellbores, the BHA 10 placing the CT 12 in tension
and
8 effectively conveying the CT 12 long distances. Further, with the first
packer 22f
9 expanded to the running diameter, the BHA 10 can be lifted in the
wellbore using
the CT 12 for repositioning the BHA 10 within the wellbore 16 during
fracturing from
11 toe to heel. The first variable diameter packer 22f can be reduced to
the third
12 minimum packer diameter, such as for tripping out of the wellbore 16.
13 In an embodiment, the first variable-diameter packer 22f has an
14 electronically-actuated packer element 66 for varying the diameter of
the first packer
22f. The first packer 22f is positioned below the valve 50 and above the fluid
16 crossover port 60 in the BHA 10. Thus, when the valve 50 is actuated to
do so, fluid
17 F flows through the throughbore 54 to below the first variable-diameter
packer 22f
18 and outwardly to the annulus 34 therebelow though the fluid crossover
port 60.
19 The first variable diameter packer 22f is electrically actuated,
having a
drive sub 70f. The first packer drive sub 70f receives signals from surface S
for
21 electronically actuating the packer element 66 for varying the diameter
of the first
22 variable-diameter packer 22f. In an embodiment, an electric motor 72
electrically
18
CA 02951814 2016-12-15
1 connected to the drive sub 70f can be used for accurate and fine control
of the
2 packer diameter. In an embodiment, the electric motor 72 can drive
conical
3 actuators 74, swash plates or other means, for engaging and expanding the
packer
4 element 66. In an embodiment, an electric motor and linear screw actuator
are used
to drive the conical actuators 74. Means are provided for reducing friction
and for
6 adjusting the gear ratio between a gear ratio for light load over much of
the
7 actuators stroke and a high gear ratio, such as about 1:250, when the
actuator
8 engages the conical actuators 74.
9 An electronics sub 80 comprising at least electronics for
monitoring a
pressure P2 'below the first packer 22f and for optionally monitoring a
pressure P1
11 above the first packer 22f, is also incorporated into the BHA 10, such
as below the
12 first packer 22f and the first packer drive sub 70.
13 For location of the BHA 10 within the wellbore 16, the BHA 10
further
14 comprises an electronic casing collar locator (CCL) 82 which is capable
of detecting
casing collars and which may also be capable of detecting perforations. The
16 electronics sub 80 also comprises electronics associated with the
operation of the
17 CCL 82. The electronically-actuated CCL 82 is useful throughout the
completion
18 operation for accurately determining the positioning of the BHA 10 in
the wellbore
19 16.
Alternatively, in embodiments, a mechanical CCL can be used.
21
22
19
CA 02951814 2016-12-15
1 Perforation Option
2 In a
general tool for simple cased or lined wells 16 or as a backup to
3 failed
sleeved subs, an electronically-actuated perforating apparatus 84 is also
4
incorporated into the BHA 10. Such perforating apparatus 84 may comprise an
electronically-detonated, selectively-actuated perforating gun assembly 90,
such as
6 shown
in Figs. 3A-3F, or alternatively may comprise perforating apparatus which
7 are
electronically or electro-mechanically-actuated to mechanically punch or drill
8 through the casing 18 or liner for creating perforations therein.
9 In
embodiments, as shown in Figs. 1A and 1B, an electronically-
detonated selectively-actuated perforating gun assembly 90 can be mounted
11
adjacent a distal end 152 of the BHA 10. While any type of selectively-
actuated
12
perforating gun can be used, embodiments described herein utilize a
perforating
13 gun 90
having a plurality of segments 92 which are wired in such as way as to
14 permit
each segment 92 to be detonated selectively and individually, such as from a
firing panel 94 at surface (Fig. 4) as described in greater detail below.
16 In
embodiments, a magnet 150 may optionally be mounted at the
17 distal
end 152 of the BHA 10 for picking up metallic debris in the wellbore 16, such
18 as during run in.
19
Microseismic monitoring option
21
Optionally, where fracturing of the formation 30 is monitored using a
22
microseismic fracture monitoring system, one or more seismic sensors 140, such
as
CA 02951814 2016-12-15
1 axially-spaced, 3-component (x,y,z) geophones, are also incorporated into
the BHA
2 10. The one or more 3-component sensors 140 are incorporated in the BHA 10
3 between the first packer 22f and the perforating gun assembly 90.
4 In embodiments, each seismic sensor 140 is coupled to the casing
18
or wellbore wall.
6 In an embodiment, each sensor 140 has elements or arms 142 which
7 can be actuated, such as electronically, to contact the casing 18 or
wellbore wall 36
8 for seismically coupling the sensors 140 thereto and enhancing signal
detection
9 when the BHA 10 is positioned for fracturing. The arms 142 can be
retracted any
time the BHA 10 is to be moved within the wellbore 16 or removed therefrom.
11 Alternatively, each sensor 140 comprises conventional centralizers
12 (not shown) which extend outwardly from the sensors 140 and which act to
couple
13 the sensors 140 to the casing 18 or wellbore wall.
14 In order to accurately determine the position of a microseism
resulting
from a fracturing operation, one must know the orientation of the one or more
16 sensors 140 and therefore means are provided to ensure that the sensors
140 are
17 either oriented in a known orientation when landed or that any resulting
orientation
18 can be determined, in real time or in a memory mode, so as to permit the
data to be
19 mathematically manipulated.
In an embodiment, each of the sensors 140 is pivotally mounted within
21 the BHA 10 and a housing 144 for each sensor 140 is weighted to ensure
that the
22 sensor 140 orients to a known orientation when deployed in the wellbore,
such as
21
I I
CA 02951814 2016-12-15
1 prior to extending the arms 142 for coupling the sensor 140 in the
wellbore 16.
2 Alternatively, the weighting of the housing causes the sensors 140 to
rest on the
3 casing or wellbore wall and no additional coupling apparatus is required.
4 'Alternatively, in another embodiment, each of the sensors 140 has
position sensors, such as accelerometers or MEMS sensors, which are capable of
6 providing signals to surface, or to a downhole processor with a battery
and memory,
7 regarding the orientation of each of the sensors 140. The data from the
sensors 140
8 is then mathematically manipulated with respect to the orientation of the
sensors
9 140, as is understood in the art.
Details of embodiments comprising the microseismic monitoring
11 option are discussed in greater detail below.
12
13 Electrically actuated variable diameter packers
14 In greater detail, and having reference again to Figs. 2A-2C, in
embodiments, in order to move the BHA 10 deployed on small diameter
electrically-
16 enabled CT 12 to the toe of very long wellbores 16, the packer element
66 of the
17 first variable diameter packer 22f is expandable and retractable for
varying the outer
18 diameter. One position for the first packer 22f is to act as a piston
and be effectively
19 pumped downhole, pulling the small diameter electrically-enabled CT 12
therewith.
The first packer 22f is centralized in the wellbore, such as using
conventional
21 centralizing elements 124. When inserted into the wellbore, the packer
element 66
22 of the first packer 22f is electronically actuated to at least two
positions: to seal as a
22
CA 02951814 2016-12-15
1 packer
and to act as a piston for pumpdown purposes and could include a third
2
position, being fully retracted to minimize accidental engagement and damage.
In
3 the
second, pumpdown position the packer element 66 is expanded in diameter to
4 the
running diameter, being a diameter less than a diameter of the wellbore 16.
The
increased packer diameter permits effective generation of substantially
maximal
6 fluid
force on the BHA 10. Fluid F is pumped through the annulus 34 to act at the
7 uphole
piston face 64 of the first packer 22f for pushing the first packer 22f and
BHA
8 10, and
for pulling the electrically-enabled CT 12 therewith, to adjacent a toe of a
9 very
long wellbore 16. For example using 2000 psi and a 12 square inch packer
face, as is the case for 4 1/2 inch diameter casing 18, a 24,000 lb force is
generated
11 which
can push the first packer 22f and BHA 10 to the toe of about a 4000m TVD
12
wellbore 16. Depending upon the size and type of CT 12 used about 50,000Ibs to
13 about
150,000 lbs of of pulling force can be exerted to raise the BHA 10 to surface
14 S.
Advantageously, as shown in Fig. 2B, the packer element 66 of the
16 first
variable diameter packer 22f can also be temporarily varied in diameter to a
17 third
smaller diameter than the running diameter to run past debris D encountered in
18 the
wellbore 16. Should there be an indication at surface that the BHA 10 is not
19
advancing in the wellbore 16, the diameter can be controllably reduced,
actuated
electronically, such that the first packer 22f and the BHA 10 can pass the
debris D,
21 after
which the diameter of the first packer 22f can once again be increased to the
22 pumpdown or running diameter for achieving substantially maximum axial
23
CA 02951814 2016-12-15
1 displacement. As shown in Fig. 2C, the first packer 22f can also be
actuated to the
2 third position for a smallest or minimum packer diameter for tripping out
of the
3 wellbore 16.
4
'Selectively-fired electrically actuated perforating gun
6 Having reference to Figs. 3A to 3F and 4, in an embodiment, the
7 selectively-actuated perforating gun 90 comprises the plurality of
segments 92
8 which are operatively connected to the electrically-enabled CT 12 through
a top
9 connector sub 96 at a proximal end 98 of the perforating gun 90.
As shown schematically in Fig. 3B and in greater detail in Figs. 30 to
11 3F, each segment 92 comprises a detonator 100 and an electronically-
actuated
12 triggering means 102, such as a built in electronic switch, and one or
more shaped
13 charges 104. In embodiments, the electronic switch 102 is built into a
detonator
14 housing 106 in which the detonator 100 is mounted. The one or more
shaped
charges 104 are mounted radially about the detonator housing 106. Where two or
16 more shaped charges 104 are used, the charges 104 are spaced from one
another
17 at phased angles thereabout. The one or more shaped charges 104 in each
18 segment 92 can be fired from surface independently of the one or more
charges
19 104 in each of the other segments 92 in the perforating gun assembly 90.
In the embodiment shown in Figs. 3A, 30 and 4, there are thirty
21 cylindrical segments 92, stacked end-to-end, the detonator 100 and
switch 102 in
22 each of the 30 segments 92 being electronically connected to the firing
panel 94 at
24
CA 02951814 2016-12-15
surface S. In each of the thirty segments 92, there are three shaped charges
104
2 which are spaced circumferentially about the segment 92 at about 1200 from
one
3 another and in proximity to the detonator 100 for actuation of the shaped
charges
4 104. Perforating gun assemblies 90, according to embodiments of the
disclosure,
are relatively short compared to conventional perforating gun assemblies. In
an
6 embodiment, each of the perforation segments 92 is less than about 180mm in
7 length. A perforating gun assembly 90 having thirty segments 92 is
therefore less
8 than about 5.5m in length.
9 As shown in Figs. 3C to 3E, and in an embodiment, the shaped
charges 104 in each segment 92 are operatively connected to the
detonator/switch
11 100,102 by positioning the charges 104 in close proximity to a primer
end or
12 blasting cap, 108 of the detonator 100 housed in the segment 92. Thus,
the
13 perforating gun 90 does not require detonation cord to be run and
connected
14 between each of the segments 92 and can be made much shorter than
perforating
guns which rely on detonation cord to transmit the detonation to shaped
charges
16 spaced further away.
17 ,As shown in Figs. 3E and 3F, the detonator 100 is mounted in the
18 detonator housing 106. The switch (not shown) is built into the
detonator housing
19 106. The detonator housing 106 is supported by a connection ring 110 for
insertion
into an upper housing 112 of the segment 92. Electrical connections, between
the
21 top sub 96 and the switch 102 and detonator 100 can be tested for each
segment
22 92 at this stage of assembly to ensure the connections are viable,
without danger of
li
CA 02951814 2016-12-15
1 actuating the shaped charges 104. The electrical connections are through
2 conductive pin connections 114 at proximal 116 and distal 118 ends of the
3 detonator housing 106.
4 Once the electrical connections have been tested and verified, the
shaped charges 104 are inserted into a shaped charge retainer 120. The
detonator
6 housing 106 passes though a bore 122 in the center of the shaped charge
retainer
7 120 for positioning the charges 104 adjacent the primer end 108 of the
detonator
8 100 therein and is secured therein for co-rotation with the shaped charge
retainer
9 120 as it is threaded into the upper housing 112. In embodiments, the
detonator
housing 106 , has slots formed therein which engage forks on the shaped
charges
11 104 for securing the detonator housing 106 to the shaped charge retainer
120.
12 A pin connector housing 128 is threaded into a distal end 130 of
the
13 shaped charge retainer 120. The pin connector housing 128 can also be
threaded
14 to the shaped charge retainer 120 prior to insertion of the shaped
charges 104.
, Thereafter, a lower tubular housing 132 is positioned over the shaped
16 charges 104 to complete the segment 92 and the upper housing 112 of a
17 subsequent segment 92 is threaded onto the pin connector housing 128,
18 sandwiching the lower tubular housing 132 therebetween. The detonator
100 and
19 detonator housing 106 supported in the subsequent segment 92 extends
into the
pin connector housing 128 so as to permit an electrical connection between the
21 conductive connection pin 114 on the distal end 118 of the detonator
housing 106 in
26
,
II
CA 02951814 2016-12-15
1 the first segment 92 with the conductive connection pin 114 on the
proximal end
2 116 of the detonator housing 106 in the subsequent segment 92.
3 Following testing of the electrical connection for the subsequent
4 segment 92, the shaped charges 104 can be loaded therein as described
above.
Thus, a perforating gun 90 according to this embodiment is lengthened a
segment
6 92 at a time. Each switch 102 built into the detonators 100 is
independently
7 triggered by the firing panel 94. Thus, there is little to no danger that
a segment 92
8 having the charges 104 loaded therein can be actuated when the electrical
9 connections are tested in another segment 92 being added.
In embodiments, a single conductor 134 connects all segments 92 in
11 the perforating gun assembly 90 and each segment 92 comprises means for
12 independently triggering shaped charges 104 mounted in each segment 92.
The
13 shaped charges 104 are typically detonated from a bottom segment 92 of
the gun
14 90 to a top segment 92 of the gun 90 as the conductor134 may be damaged
by
detonation of the shaped charges 104.
16 The firing panel 94 may be connected to the plurality of segments
92
17 through the single conductor 134 connected to all of the detonators 100
having
18 switches 102 located at the detonator 100. Alternatively, the firing
panel 94 can be
19 connected through multiple conductors 134n.
As shown in Fig. 4, perforating gun assemblies 90 having any desired
21 number of segments 92 are possible according to embodiments described
herein.
22 Where perforating guns 90 with segments 92 in excess of about twenty to
about
27
CA 02951814 2016-12-15
1 thirty segments 92 are desired, one or more additional wires can be run
from the top
2 sub 96 to one or more tandem subs to which a further about twenty to
about thirty or
3 more segments are connected as previously described. In this way, the
4 conductance is optimized throughout all of the segments 92 between the
top sub
96 and the tandem sub where tandem subs are used to lengthen the perforating
6 gun 90 and increase the number of segments 92 which can be used in a
single run.
7 For example, each thirty-segment perforating gun assembly, having
3
8 shaped charges 104 in each segment 92, can create ninety perforations. If
multiple,
9 thirty-segment perforating gun assemblies 90 are stacked end-to-end and
electrically connected to the firing panel 94, multiples of the ninety
perforations can
11 be performed in a single trip. The shaped charges 104 in one segment 92
can be
12 fired at a zone of interest or the shaped charges 104 in more than one
segment 92
13 can be detonated to increase the number of perforations in the zone. The
same
14 firing panel 94 used to actuate the switches 102 and detonators 100 of a
single,
thirty-segment assembly 90 is used to actuate the additional thirty-segment
16 assemblies 90. Once the first thirty segments 92 have been fired, a
switch 136 can
17 be flipped at the firing panel 94 to actuate a second or even third set
of segments
18 92 in another of the assemblies 90. In this case, perforation of very
long wellbores
19 16 can be accomplished without having to pull the BHA 10 from the
wellbore 16.
The switch 102 and detonator 100 in each segment 92 receives the
21 electronic signal transmitted from the firing panel 94 at surface,
through the
22 electrically-enabled CT 12, and responds to actuate detonation of the
shaped
28
CA 02951814 2016-12-15
1 charges
104 in the selected segment 92 within about 0.5 ms. Time of firing is
2 therefore known within about 0.5ms.
3 By way
of example only, detonators 100, switches 102 and firing panel
4 94
systems, suitable for use in embodiments described herein, are available from
DYNAenergetics GmbH & CO. KG, Laatzen, Germany.
6 The
exact time of firing of the perforating gun 90 as described above
7 can be
particularly advantageous when the wellbore 16 is to be fractured following
8
perforation and if a microseismic fracture monitoring system is in place to
monitor
9 the
growth and placement of the fractures. The firing of the perforating guns 90
creates noise events in the wellbore 16 to be fractured which can be used, in
11
combination with the accurate timing of detonation, to improve development of
12
velocity profiles, sensor orientation and sensor calibration used in the
microseismic
13 monitoring.
14
.Microseismic sensors 140, positioned at least at surface, such as in
an array, and/or the sensors 140 incorporated in the BHA 10, are able to
detect the
16 noise
events resulting from the detonation of the shaped charges 104 or the
17
perforation of the casing 18. The data, in combination with the accurate time
of
18
initiation of the noise events, is particularly useful in calculating a
velocity profile for
19 the formation' to be fractured.
Generally, the shaped charges 104 in each segment 92 are detonated
21 at
different locations in the wellbore 16. The firing panel 94 at surface is used
for
22 firing
the shaped charges 104 in each of the perforating gun segments, as desired.
29
CA 02951814 2016-12-15
1 For example, the shaped charges 104 in a first distal perforating gun
segment 92
2 are fired when the perforating gun 90 is located at a first location in
the wellbore 16,
3 such as adjacent a toe of the wellbore 16. Thereafter, the perforating
gun 90 is
4 repositioned to a second location in the wellbore 16 and the shaped
charges 104 in
a second of the segments 92 are fired. The repositioning and firing of the
shaped
6 charges 104 is repeated for the remaining segments as the perforating gun
90 is
7 relocated toward the heel or uphole within the wellbore 16.
8 Embodiments disclosed herein further comprise fluid isolation
9 between segments 92 of the perforating gun 90 such that when the shaped
charges
104 are detonated, fracturing fluid F and the like cannot flow between
segments 92.
11 As shown in Fig. 3E, the pin connection housing 128 provides fluid
isolation
12 between the adjacent segments 92.
13 In embodiments where the perforating apparatus 84 is an
electrically-
14 actuated punch tool or electrically-actuated drilling assembly or the
like, the tool can
be electrically-actuated from surface to form any number of perforations in
the
16 casing in each zone of interest. In this embodiment, the number of
perforations
17 which can be made is not limited by the perforating apparatus 84 as is
the case in
18 the perforating gun 90 which has a fixed number of shaped charges 104
therein.
19
New wellbores
21 Single packer embodiments as described herein are particularly
22 suitable for use in new wellbores. New wellbores 16 are drilled, but
have not yet
I
CA 02951814 2016-12-15
1 been completed. Further, new wellbores 16 can be cased 18 and which have
ported
2 sliding sleeve subs 24 installed therein, sliding sleeves 26 therein
having not yet
3 been actuated for opening ports 28 in the ported subs 24 to access
formation 30
4 therebeyond. In embodiments, the sliding sleeves 26 may also be
selectively
closable to stop communication between the formation 30 and a bore 32 of the
6 casing 18 therethrough.
7
8 In use in new cased or lined wellbores
9 In use, as shown in Figs. 2A-2C, 4, and 5A-5C, the BHA 10 is
connected to the electrically-enabled CT 12 and is injected into the wellbore
16
11 through a lubricator 160. As the BHA 10 is relatively compact, the
lubricator 160 has
12 a height which is much shorter than required for a conventional single-
trip BHA. In
13 embodiments, the lubricator 160 is about 12m compared to 20m to 30m and
greater
14 required for a conventional BHA. Further, surface equipment 162, such as
cranes,
can be used .to raise embodiments of the BHA 10 compared to equipment required
16 to raise and inject longer conventional BHA's.
17 Once run into the wellbore 16, as shown in Fig. 2A, the packer
18 element 66 of the first packer 22f is electronically actuated to expand
to the running
19 diameter. Fluid F is pumped into the annulus 34 formed between the
electrically-
enabled CT-deployed BHA 10 and the wellbore wall 36 or casing 18 for acting at
the
21 uphole piston face 64 of the expanded packer element 66 for pumping the
first
22 packer 22f and the BHA 10 connected thereto into the wellbore 16, such
as to a toe
31
CA 02951814 2016-12-15
1 164 of
the wellbore 16 (Fig. 4). The electrically-enabled CT 12 is pulled downhole
2 with
the first packer 22f and the BHA 10. Typically the BHA 10 is run into the toe
64
3 as
fracturing , is performed at intervals or zones of interest from the toe 164
of the
4 wellbore toward a heel 166 of the wellbore 16.
As shown in Fig. 5A, when the BHA 10 is accurately positioned, using
6 the CCL
82, the perforating gun 90 is adjacent a non-perforated zone of interest in
7 the
formation 30. A select detonator 100 and switch 102 in a segment 92 of the
8
selectively actuated perforating gun 90 is electronically-actuated from the
firing
9 panel
94 at surface S for perforating the wellbore 16 or casing 18, if cased. Where
the wellbore 16 is cased and the casing 18 is cemented into place, the cement
C
11 may
also be perforated by the explosion of the shaped charges 104. Alternatively,
12 one may
simply pump fracturing fluid F, at fracturing pressures, through the
13
perforations In the casing 18, to fracture the cement and access the
formation, as is
14 understood in the art.
Thereafter, a shown in Fig. 5B, the BHA 10 is repositioned such that
16 the
first packer 22f is positioned below the latest or most recently formed
17
perforations and above any previous perforations. The packer element 66 of the
first
18 packer
22f is electrically-actuated to expand to the sealing diameter to seal the
first
19 packer
22f against the wellbore 16 or casing 18 and isolate the annulus 34
therebelow.
21 As
shown in Fig. 5C, the valve 50 is electrically-actuated to the first
22
position to flow treatment fluid F, at fracturing pressures, from the CT 12
through the
32
CA 02951814 2016-12-15
1
throughbore ,54 to exit the fracturing ports 56 to the annulus 34 above the
first
2 packer
22f for delivery through the latest perforations P to the formation 30
3 therebeyond.
4 Having
reference to Fig. 5D, when the zone of interest has been
fractured, the valve 50 can either be shut off to stop the flow of fluid F
through the
6 bore 46
of the BHA 10 or maintained open to permit reverse circulation of debris D
7 from
the annulus 34 to surface S through the bore 38 of the electrically-enabled CT
8 12 by
flowing a clean fluid Fc down the annulus 34. Alternatively, clean fluid Fc
can
9 be
circulated down the bore 38 of the electrically-enabled CT 12 with reverse
circulation of debris D to surface S through the annulus 34. The ability to
open and
11 flush
the first packer 22f permits the operator to run with a higher sand density,
12 even
risking sand off because of the ease with which one can recover. One can fully
13 retract the first packer 22f and circulate the sand out of the well.
14 When a
fracture is complete, one can use CT strain sensors to
determine whether downhole conditions have changed, such as due to temperature
16 effects
resulting in residual set-down or pull-up on the first packer 22f. CT set-down
17 or pull-up load can be adjusted accordingly to protect the packer 22f.
18 The
first packer 22f is thereafter released from the wellbore 16 by
19
electronically-actuating the packer element 66 to reduce to the running
diameter to
unseal from the wellbore (Fig. 2A) and permit relocation of the BHA 10 through
the
21
wellbore. Release of the packer 22f can also include actuation of an
equalization
33
CA 02951814 2016-12-15
1 valve to equalize the pressure across the packer 22f before or at the
same time as
2 the packer 22f is released.
3 Electric motors in the first packer drive sub 70f actuated to
reduce the
4 diameter of the first packer 22f, turn a shaft which, in turn, moves a
mandrel having
a valve thereon which opens prior to release of the packer element 66 to
release
6 pressure above and below the first packer 22f. Having reference to Figs.
1B and 6,
7 as pressure can be monitored above and below the first packer 22f, using
pressure
8 sensors 170 positioned for monitoring the pressure P1 in the annulus 34
above the
9 first packer 22f and the pressure P2 in the annulus 34 below the first
packer 22f.
one can monitor the pressures P1,P2 until equalized prior to unseating the
first
11 packer 22f and moving the BHA 10.
12 The BHA 10 is then lifted using the electrically-enabled CT 12 to
13 position the perforating gun 90 adjacent the next zone of interest,
uphole from the
14 previously perforated and completed zone. Once again, a segment 92 of
the
perforating gun 90 is electronically actuated using the firing panel 94 at
surface S
16 and the shaped charges 104 in another of the segments 94 are detonated.
Fluid F
17 is pumped against the piston face 64 of the first packer 22f for moving
the BHA 10
18 downhole for positioning the first packer 22f below the newly created
perforations P
19 in the uncompleted zone. Once in position, the packer element 66 is
electronically
actuated from surface S to expand to the sealing diameter to seal against the
21 wellbore wall 36 or casing 16 and the fracturing operation is repeated,
as described
22 above.
34
CA 02951814 2016-12-15
1 In conventional completion operations, a "dead leg" is used not
only to
2 prevent collapse of the CT 12 under pressure from fluids in the annulus
34, but also
3 to permit calculation of pressure to determine reaction of the formation
30 to the
4 fracturing operation.
In embodiments described herein, and having reference again to Figs.
6 1B and 6, the downhole electronic capabilities provided by the
electrically-enabled
7 CT 12 and c6nnections within the BHA 10 permit direct measurement of
parameters
8 such as pressure, temperature, vibration and the like. Pressure sensors
170 are
9 positioned for monitoring the pressure P2 in the annulus 34 below the
first packer
22f. The pressure sensors 170 are electrically connected to the electronics
sub 80
11 for transmission of data to surface S via the electrically-enabled CT
12. While a
12 pressure P1, above the first packer 22f, can be calculated at surface S,
the
13 electronics sub 80 can also be electrically connected to pressure
sensors 170 which
14 directly monitor the pressure P1 in the annulus 34 above the first
packer 22f. As will
be appreciated by those of skill in the art, pressure P1 above the first
packer 22f is
16 indicative of how the formation 30 is reacting to the fracturing
operation while
17 pressure P2 below the first packer 22f may be indicative of the
integrity of the
18 packer element 66 of the first packer 22f and the formation 30 between
adjacent
19 zones. Further, after stopping pumping of the fracture fluid F, fracture
closure
pressures can also be monitored.
11
CA 02951814 2016-12-15
1 The ability to measure pressures may be particularly advantageous
2 when high rate foam fracturing is performed as measuring pressure enables
3 understanding of the quality of the foam at the perforations.
4
Cased wellbores with sliding sleeves
6 As shown in Fig. 1A, it is known to incorporate a plurality of the
ported
7 sliding sleeve subs 24 into the casing 16 or in a liner in a wellbore 16.
The sliding
8 sleeves 26 are opened for opening the pre-existing ports 28 in the casing
18,
9 minimizing the need to perforate the casing 18 for accessing the
formation 30
therebeyond. In some cases, the opened sliding sleeves 26 can also be actuated
to
11 close for isolating portions of the formation 30 from fluids flowing
through the casing
12 18.
13 In embodiments, as taught in Applicant's co-pending US application
14 13/773,455, ,the entirety of which is incorporated herein, the BHA 10
further
comprises a CCL 82 which can be mechanical or electronic and which detects
16 collars between joints of casing 18, rather than a bottom of the sliding
sleeve 26, as
17 in the prior art. Thus, the CCL 82 is used to locate the BHA 10 based on
a location
18 of the casing 18 or locating collar adjacent and downhole of the ported
sliding
19 sleeve sub 24. Accordingly, the length of the ported sub 24 and sleeves
26 do not
need to be a function of BHA length and therefore not as long as the prior
art. The
21 CCL 82 does not need to be a specialized CCL for detecting a profile at
the lower
22 end of the prior art ported sub and sliding sleeve therein.
36
CA 02951814 2016-12-15
1 In
embodiments, the CCL 82 is spaced below the first packer 22f,
2 such as
by a length of relatively inexpensive pup joint, positioning the CCL 82, when
3
engaged, to appropriately position the fracturing ports 56 at or near the pre-
existing
4 ports
28 in the ported sub 24 when the CCL 82 engages the locating collar 19. In
embodiments, the downhole end of the ported sub 24, the locating collar 19 or
6 lengths
of adjacent casing 18 are aggressively profiled to assist detection by the
7 CCL 82.
8 In
embodiments, when the CCL 82 locates the BHA 10 for positioning
9 the
fracturing ports 56 adjacent the open ports 28 in the ported sub 24, the first
packer 22f is located below the open ports 28. The first packer 22f, when
11
electrically-actuated to the sealing diameter, acts to isolate the annulus 34
12
therebelow from fracturing fluids F which can be delivered to the fracturing
ports 56
13 in the
BHA 10 either through the electrically-enabled CT 12 for delivery to the open
14 ports
28 in the casing 18, directly to the open ports 28 in the casing 18 through
the
annulus 34 above the first packer 22f, or through both.
16 In
embodiments where the CCL 82 is an electronically-actuated CCL,
17
detection of an end of the ported sleeve sub 24 can be accurate within
millimeters.
18 The
accuracy of detection of the location of the sleeve sub 24 further permits the
19 ported
sleeve sub 24 to be much shorter than a conventional sleeve sub. The
reduction in length significantly reduces the cost of the sleeve subs 24 and
the BHA
21 10. In
embodiments, both the sleeve sub 24 and the BHA 10 are reduced in length
22 to
about one-half or less that of a conventional sleeve sub and BHA. In
37
CA 02951814 2016-12-15
1 embodiments, the BHA 10, excluding the length of the perforating
apparatus 84, is
2 about 4m to about 5m.
3 Sleeves 26 can be opened using a variety of conventional sleeve
4 opening and closing techniques, including but not limited to setting the
first packer
22f within the sleeve 26, expanding the packer element 66 and thereafter
utilizing
6 fluid F to force the first packer 22f and sleeve 26 to shift the sleeve
26 axially
7 therein, electronically or mechanically actuating a shifting tool (not
shown)
8 incorporated in the BHA 10 to engage the sleeve 26 and shift the sleeve
26 axially
9 therein or by actuating a rotational opening tool to engage the sleeve 26
for rotation
to an open position. Alternatively, differential pressure can be used to
hydraulically
11 open the sleeve 26.
12 In embodiments, where there has been a failure of the sliding
sleeve
13 26 to open, the selectively actuated perforating gun assembly 90 can be
used to
14 perforate the ported sub 24. Further, the perforating gun assembly 90
can be used
to create perforations in the casing 18 at zones of interest where there are
no
16 sliding sleeve subs 24.
17
18 In use - cased wellbores with ported sleeve subs
19 Once the sleeve 26 has been moved to open the ports 28 in the
ported sleeve sub 24 or perforations P have been made through the casing 18 or
21 ported sub 24, where sleeves 26 did not exist or failed to open,
treatment
22 therethrough proceeds as previously described above.
38
CA 02951814 2016-12-15
1 In embodiments, following treatment, the ports 28 in the ported
sleeve
2 subs 24 are closed, as is understood by those of skill in the art.
3
4 MULTIPLE PACKER EMBODIMENTS
In embodiments, having reference to Fig. 7, the BHA 10 further
6 comprises at least the second, variable diameter packer 22s, spaced
uphole from
7 the first variable diameter packer 22f and the valve 50. Embodiments
having two
8 packers 22f,22s are particularly suitable for use in previously
perforated wellbores,
9 newly perforated wells having all of the zones perforated therein,
wellbores having
sleeves 26 which are in the open position or in openhole wellbores 20.
11 The first and second variable diameter packers 22f,22s straddle
the
12 fracturing ports 56. In embodiments, a second packer drive sub 70s
positioned
13 below the second packer 22s is electronically actuated to vary the
diameter of the
14 packer element 66 in the second packer 22s. Optionally, the first packer
drive sub
70f may be electrically connected to both the first and second variable
diameter
16 packers 22f,22s and is capable of independently electronically actuating
packers
17 elements 66 in both the first and second packers 22f, 22s. In either
case, the packer
18 elements 66, of the first and second packers 22f, 22s are independently
variable
19 with respect to diameter.
21
39
CA 02951814 2016-12-15
1 New wellbores
2 While a
separate BHA 10 having the first and second packers 22f, 22s
3 can be used for previously perforated or openhole wellbores, due to the
4
independent controllability of the variable diameter packers 22, the same BHA
10
used for the previously perforated wellbores 16 is also used for new wellbores
16.
6 The
second packer 22s may simply not be used during the fracturing operation. In
7 this
case, the second packer 22s may be used to assist in moving the BHA 10
8 within
the wellbore by increasing the diameter of the packer elements to the running
9
diameter but it is thereafter reduced to the minimum packer diameter once the
BHA
10 is positioned with the first packer 22f below the perforations P or opened
sleeve
11 26.
Thus, during the subsequent fracturing operation treatment fluids F can be
12
delivered through the annulus 34 to the perforations P, as well as through the
bore
13 38 of the electrically-enabled CT 12.
14 Use of
one tool suitable for new or old wells reduces inventory and
improves standardization.
16
17 Perforated wellbores
18
Previously perforated or newly perforated wellbores 16 are wellbores
19 16 that
have had perforations P made in the casing or liner 18 for production of
formation fluids therethrough. During the life of the previously perforated
wellbore
21 16,
there may be a need to stimulate production from the formation 30 or otherwise
22 treat
the formation 30, such as by fracturing. As the existing perforations P
whether
CA 02951814 2016-12-15
1 newly made or existing, wherever they occur along a length of the
wellbore 16,
2 provide fluid connections to the formation 30, select perforations P at a
zone of
3 interest must be isolated from the remaining perforations P for treatment
of only the
4 zone of interest.
6 Cased wellbores with open sliding sleeves
7 Previously perforated wellbores 16 may also be wellbores 16 having
8 ported sleeve subs 24 incorporated therein which have been previously
opened by
9 shifting or rotating sleeves 26 which thereafter have not or cannot be
closed.
11 In use in cased, perforated wellbores or in openhole wellbores
12 The BHA 10 is lowered into the wellbore 16 until the perforations
P at
13 the zone of interest are located between the first and second variable
diameter
14 packers 22f,22s. One can use a CCL to position the BHA 10 as described
above.
Once in position, the first and second packers 22s,22f are independently
16 electrically-actuated to expand the packer element 66 to the sealing
diameter,
17 straddling the perforations P therebetween. Fracturing fluid F is
delivered through
18 the electrically-enabled CT 12 and exits the fracturing ports 56 to the
formation 30
19 isolated betWeen the first and second packers 22f, 22s or through the
perforations P
to the formation 30 therebeyond.
21
22
41
CA 02951814 2016-12-15
1 Perforation option
2 Where a
zone of interest has not been previously perforated, the
3
diameter of the packer element 66 of at least the second variable diameter
packer
4 22s is
expanded to the running diameter for pumping the BHA 10 downhole. The
first packer 22f, below the valve 50 and fracturing ports 56 can be at a
smaller
6
diameter than the second packer 22s or can also be at the running diameter
during
7 pumping
downhole. The BHA 10 is pumped downhole as described above to
8
position the perforating apparatus 84, such as the perforating gun assembly
90,
9
adjacent the non-perforated zone of interest and a segment 92 of the
perforating
gun assembly 90 is actuated electronically from surface to perforate the
casing or
11 liner 18.
12
Thereafter, the BHA 10 is pumped further downhole to position the
13 newly
formed perforations P between the first and second packers 22f,22s. The
14 packers
22f,22s are thereafter independently electronically-actuated to the sealing
diameter on either side of the newly formed perforations P and the fracturing
16 operation is performed, as previously described.
17 .In
embodiments having the first and second variable diameter packers
18
22f,22s, the electronics sub 80 further comprises electronics connected to
additional
19
pressure sensors 170 for monitoring the fracturing pressure P3 between the
first
and second packers 22f,22s.
21 In an
embodiment, as shown in Fig. 8A, in contrast to the embodiment
22 shown
in Figs. 1A, 1B and 7, the fracturing head 55 may not require a valve
42
CA 02951814 2016-12-15
1 between the 'first and second variable diameter packers 22f,22s.
Fracturing ports
2 56 can be in constant fluid communication with the bore 38 of the
electrically-
3 enabled CT 12 for delivery of treatment fluid F therethrough to the
fracturing ports
4 56 to the annulus 34 and to the formation 30 through the perforations P.
Optionally, embodiments may comprise a safety valve 180, such as a
6 1/4 turn electrically-actuated valve or manual check valve, positioned
between the
7 disconnect 44 and the second packer 22s. Should there be a disconnect to
leave
8 the tool downhole, the safety valve could be used to prevent flow uphole
through
9 the CT 12.
11 Openhole wellbores
12 In the case of openhole completions, as there are no casing
collars to
13 locate using the CCL 82, the BHA 10 is positioned in the wellbore 16
using depth
14 control means such as a logging tool or a depth measurement tool at
surface which
measures the length of CT 12 deployed. The first and second packers 22f,22s
are
16 positioned adjacent the zone of interest and the packing elements 66 are
expanded
17 to the sealing diameter for sealing against the uncased and unlined wall
36 of the
18 wellbore 16.
19
43
CA 02951814 2016-12-15
1 Pressure equalization ¨ single and multi-packer embodiments
2 With
reference to Fig. 8B, another embodiment of a two packer
3
arrangement is provided, illustrated in cased wellbore, in which both the
first,
4
downhole packer 22f is electrically actuable and the second, uphole packer 22s
is
also electrically actuable. The first packer 22f includes slips 171 for
securing the
6 BHA in
the wellbore. The first packer 22f is associated with a bypass or
7
equalization valve 23f for releasing differential pressure across the packer
22f
8 before
releasing. Equalization ports 25f fluidly communication between the CT bore
9 38 and
the annulus 34. The equalization valve 23f operates the ports 25f between
open and closed positions and is actuated by the first packer drive sub 70f,
first
11 opening the valve 23f and then releasing the packer 22f.
12
Similarly, the second packer 22s is associated with a bypass or
13
equalization valve 23s for releasing differential pressure across the second
packer
14 22s
before releasing. Equalization ports 25s fluidly communication between the CT
bore 38 and the annulus 34. The equalization valve 23s operates the ports 25s
16 between
open and closed positions and is actuated by the second packer drive sub
17 70s, first opening the valve 23s and then releasing the packer 22s.
18 In one
embodiment, to move the BHA 10, one would release the
19 uphole,
second packer 22s, by first equalizing pressure across the packer,
electrically-actuating the second packer 22s to release from the sealing
diameter to
21 the
running diameter or the minimum diameter. As stated above, one can monitor
22 the
pressure above and below the second packer 22s and above and below the first
44
CA 02951814 2016-12-15
1 packer 22f using pressure sensors 170 (P1,P2 and P3). Thereafter, one
prepares
2 to release the downhole, first packer 22f, by equalizing pressure across
the first
3 packer 22f and checking for undue stain in the BHA above the first packer
22f. CT
4 set-down or pull-up load can be adjusted accordingly to protect the
packer 22f.
The CT can be injected or pulled to neutralize residual axial forces on the
BHA
6 before releasing the slips. If the slips 171 are released before
neutralizing the
7 strain, the packer 22f,22s could be damaged. Once strain has been
neutralized, the
8 first packer 22f is the electrically-actuated to release from the sealing
diameter to
9 the running diameter or the minimum diameter. The BHA 10 can be moved to
another position or pulled out of hole.
11 As discussed, the variable electrically-actuated packer is usable
as a
12 pump-down piston configuration, however as the pumping forces can be
very large
13 and the rate of the injection is determined separately, there is the
risk of over-run
14 injecting and backing up of the CT 12 in the wellbore 16, or an under-
running of the
injector resulting in large tensile forces in the CT 12. A failure of the BHA
10 and
16 CT 12 is possible, resulting in loss of the BHA 10.
17 While the BHA 10 is secured in both the cased or openhole wellbore
18 16 as a result of pressure balancing across the two packers 22f, 22s,
slips 171 can
19 also be set in at least the first packer 22f for securing the BHA 10 in
the wellbore 16.
21
CA 02951814 2016-12-15
1 Mechanical release ¨ single and multi-packer embodiments
2 As one
of skill will appreciate, the BHA 10 further comprises
3
mechanical release mechanisms, such as shear pins or pressure-actuated dogs
4 and the
like as are understood in the art, for releasing the first and second packers
22f,22s from the wellbore 16 in the event that the BHA 10 becomes stuck in the
6
wellbore 16. Use of such release mechanisms avoids the need to disconnect the
7 BHA 10 unless absolutely necessary.
8
9 ,Microseismic monitoring ¨ single and multi-packer embodiments
In embodiments disclosed herein and as described in Applicant's
11
copending US provisional application 61/774,486, incorporated herein by
reference,
12 using
at least one sensor 140, such as a geophone, accelerometer or the like,
13
integrated into the BHA 10, the at least one sensor 140, typically a 3-
component
14 sensor,
detects compressional waves (P) and shear waves (S) from microseismic
events in the wellbore and outside the wellbore. However, one cannot easily
16
separate signals from the event of interest from signals derived from noise
occurring
17 as a
result of apparatus used for pumping the fracture and other inherent noise
=
18 events.
19 As
shown in Fig. 9, fiber optic distributed sensors 190, such as those
in one or more optical fibers deployed in the wellbore 16 and which span a
length of
21 the
wellbore, are capable of detecting P-waves, but do not typically detect S-
waves.
22 The one
or more optical fibers or linear array of fiber optic sensors 190 are capable
46
CA 02951814 2016-12-15
1 of detecting energy originating from within the formation 30 adjacent the
wellbore
2 16. The detected energy can be used only to estimate distance away from
the linear
3 array 190 at which the energy originated, but not the direction and thus
is not
4 particularly useful in positioning the event in the formation 30.
Applicant believes that the combination of the ability to obtain both P-
6 wave and S-wave data, using at least one sensor 140 deployed adjacent the
7 microseismic event (fracture), and the ability to obtain a large amount
of signals
8 from the plurality of P-wave sensors in the linear array of fiber optic
distributed
9 sensors 190 extending along the length of the wellbore 16, would permit
one of skill
to more accurately determine the position of the signals from the desired
11 microseismic event (fracture) while removing background noise. The fiber
optic
12 distributed sensors 190 are utilized for mapping the background noise in
the
13 wellbore, the noise mapping being useful to "clean up" the data obtained
from the at
14 least one sensor 140.
Further, because positioning of the microseismic event (fracture) is
16 from within the wellbore 16, Applicant believes that only a minimal
surface array or
17 possibly no surface array is required. Further, if no surface array is
required, there is
18 no need for a velocity profile between wellbore 16 and surface.
19 In an embodiment, therefore, at least one 3-component sensor 140
is
incorporated into the BHA 10 which is used for performing a fracturing
operation
21 and which is deployed into the wellbore on coiled tubing (CT).
47
CA 02951814 2016-12-15
1 More particularly, three orthogonally oriented geophones in each
2 sensor 140 provide several benefits. The first is simply to account for
the
3 uncertainty in where the source of incident energy originated. By having
3
4 orthogonal geophones in each sensor 140, one is able to capture incident
energy
arriving from any direction. Since any single geophone is only capable of
capturing
6 motion in a single direction, at least 3 oriented orthogonally in each
sensor 140
7 permit capturing motion in any one arbitrary direction.
8 Secondly, with the ability to detect motion in any direction, one
can
9 capture both compressional (P) waves, having particle motion in the
direction of
propagation, and shear (S) waves, having particle motion perpendicular to the
11 direction of propagation, with equal fidelity.
12 Thirdly, by measuring the difference in arrival time between the
13 observed compressional and shear wave arrivals for a single event, in
combination
14 with an understanding of the local velocity structure, a distance from
the 3-
component sensor 140 can be calculated for the origin of that event.
16 Fourthly, both azimuth and inclination of the waveform impinging
on
17 the sensor can be determined. By a process referred to as hodogram
analysis,
18 which involves cross-plotting the waveforms recorded on pairs of
geophones, the
19 direction of arrival at any 3-component sensor 140 can be determined, to
within 180
degrees. Effectively, the vector defining the direction from which the energy
21 impinged on a single 3-component sensor 140 would have a sign ambiguity.
The
22 direction of arrival could be either (x,y,z) or (-x,-y,-z).
48
11
CA 02951814 2016-12-15
1 By
adding a second 3-component sensor 140 at some distance from
2 the
first sensor 140, directional ambiguity can be substantially eliminated. The
3 second
3-component sensor 140 permits measurement of a time delay between the
4
observed P or the observed S wave arrivals on each of the first and second 3-
component sensors 140. One can then tell which of the two, possible arrival
6
directions is the correct one. The only problem is if the event origin is
located on the
7 plane
that bisects the first and second 3-component sensors 140, which, in reality,
8 is most
likely, due to noise contamination, the region of ambiguity likely being
larger
9 than
simply the bisecting plane. Adding a third 3-component sensor 140, spaced
some distance from the first and second 3-component sensors 140, substantially
11 eliminates the final uncertainty.
12
Further, at least one or more fiber optic distributed acoustic sensors
13 190 are
operatively attached to an inside of the coiled tubing CT, as is understood
14 in the
art, and are spaced to extend along at least a portion of the length of the
wellbore 16.
16 Noise,
such as caused by the frac pumps, sliding sleeves, fluid
17
movement through the CT 12 and the like, is readily transmitted by the metal
CT 12.
18 The
fiber optic distributed sensors 190, in contact with a wall of the CT 12,
readily
19 detect
the transmitted noise. A baseline can be obtained prior to turning on the
pumps and initiating the fracturing operation to assist with mapping the noise
once
21 the
operation is initiated. Furthermore, by actively monitoring the noise within
the
22
wellbore 16 using the linear array of fiber optic sensors 190, estimates of
the noise
49
CA 02951814 2016-12-15
1 at the at least one 3-component sensor 140 can be made. The noise
estimates can
2 then be subtracted from the 3-component sensor data, such as obtained during
3 fracturing. Subtracting the noise from the 3-component sensor data
effectively
4 improves the ability of the 3-component sensors to detect a microseismic
event
resulting from the fracturing and a signature thereof.
6 As the fiber optic distributed sensors 190 are sensitive to
tensile
7 loading, the optical fibers are embedded in an adhesive or other material
which is
8 not compressible, but which is suitably flexible for CT operations. Thus,
any strain
9 changes imparted to the optical fibers are as a result of the microseisms
and not to
strain imposed by deploying the optical fibers in the CT 12.
11 In embodiments, surface probes such as in an array about the
12 wellbore, are not required. Optionally however, a surface array of
sensors can be
13 used.
14 As shown in Fig. 9, three or more, 3-component-type geophones 140
are incorporated into the BHA 10. The three or more geophones 140 are spaced
16 from each other along a length of the BHA 10 and are isolated from the
flow of
17 fracturing fluid, such as by being positioned downhole from the
treatment head 55,
18 incorporated therein.
19 Data collected by the geophones 140, situated in the wellbore 16
adjacent the fracturing events, can be transmitted to surface in real time,
such as
21 through the 'electronically-enabled CT 12 or the system can be operated
in a
22 memory mode, the data being stored in the geophones 140 for later
retrieval.
CA 02951814 2016-12-15
1 As is
understood by those skilled in the art, both power and signals
2 can be
transmitted using a single wire. In embodiments, a separate wire is
3
incorporated in the electrically-enabled CT for operating the microseismic
sensors
4 140 and
a separate wire is incorporated for operating the other components of the
BHA 10.
6 In
embodiments, fiber optics incorporated into the electrically-enabled
7 CT may
be used to send data to surface from all of the BHA components, including
8 the microseismic sensors 140.
9 Based
upon conventional microseismic monitoring performed remote
from the wellbore 16, one of skill would have thought it desirable to space
the
11
geophones as far apart as possible in the wellbore, such as by about 100m, to
12 provide
optimum time resolution therebetween. Practically speaking however, when
13
deployed with the BHA, the spacing between the geophones is limited by the
size of
14 the
lubricator 160 at surface for injecting the BHA 10 into the wellbore 16. In
embodiments, the geophones 140 are placed at least about 1m apart. In
16
embodiments, the geophones 140 are placed at about 5m to about 10m apart.
17
However, because the geophones 140 are positioned so close to the fracturing
18 events and because there is replication of the arrival times of both the
19
compressional (p) and shear (s) waves at each of the geophones 140 permitting
calculation of distance, calculation of velocity becomes less important and
thus, the
21 closer
spacing is satisfactory. For example, in a conventional arrangement of
22
sensors, a 10% error in velocity becomes significant by the time the signals
reach a
51
CA 02951814 2016-12-15
1 distant surface or observation well array. In embodiments disclosed
herein however,
2 when the geophones 140 are placed so close to the fracturing event, velocity
3 becomes less significant, particularly as there are fewer intervening
layers between
4 the event and the sensors 140 through which the signal must pass.
Applicant believes that the frequency of noise generated through
6 pumping of the fracture may be at a higher frequency than that of the
microseismic
7 event outside the wellbore (lower frequency). However, even if the
frequencies are
8 substantially similar, Applicant believes that the event can be
recognized and any
9 effects of the lower frequencies noise can be minimized, according to
embodiments
disclosed herein.
11 It is assumed that the acoustic noise, such as from fluid flows or
12 travelling through metal casing 18, tubular and the like, are linear
trends and that
13 only one component of a 3 component geophone 140 will be affected by the
noise.
14 In reality, Applicant believes the other two components will likely also
detect at least
some of the noise.
16 As previously described, the three or more geophones 140 are
17 coupled to the casing 18 or wellbore 16 and the orientation of each of
the
18 geophones 140 is known or can be mathematically adjusted for orientation
and
19 thereafter interpreted.
Applicant believes that the addition of the linear array of fiber optic
21 sensors 190, used in combination with the three or more geophones 140
produces
22 signals sufficiently clean to permit accurate determination of the
position of the
52
CA 02951814 2016-12-15
1 microseismic event within the formation 30. Noise mapped from the fiber
optic
2 sensors 190 is removed from the signals at each of the three geophones
140 and
3 the clean signals are thereafter used to locate the microseismic event
(fracture), as
4 is understood by those of skill in the art.
Optionally, the sensors 140 may be decoupled from the remainder of
6 the components of the BHA 10 to reduce noise associated therewith.
7 Monitoring of microseismic events in real time provides the
ability to
8 understand where the fracture is being positioned in the formation 30 and
how the
9 fracture is growing in all directions (x,y,z) relative to the pumping
rates, the
particular fracturing fluid and any number of other parameters with respect to
the
11 fracturing operation. The ability to rapidly optimize the design and
placement of
12 fractures provides the ability to build databases related thereto which
may be of
13 great use to the industry in improving fracture operations. Further,
such information
14 permits data, such as where the fluid has gone, to be provided for the
public record
regarding each stage of the fracturing operation and fracture location and
extent.
16 , Particularly advantageous, when monitoring in real time, is the
ability
17 to determine whether a fracture has broken out of a zone or is
imminently in danger
18 of breaking out of a zone so that pumping can be stopped. This is of
great interest,
19 for many reasons, where the fracture is breaking towards a water zone.
Growth of a fracture, vertically or horizontally at a certain rate, may be
21 related to the pumping rate and concentration of the fracturing fluid.
Over time and
22 using the data obtained by embodiments disclosed herein, one could
design a
53
CA 02951814 2016-12-15
1 fracturing operation to achieve maximum vertical height without breaking
out of the
2 zone and maximum, economic horizontal displacement leading to horizontal
well
3 spacing optimization and field development optimization.
4 In the case of openhole wellbores 12, embodiments using
microseismic monitoring as described herein are less susceptible to noise as
there
6 is less transmission of noise in the wellbore 16 without the casing or
liner 18.
7
8 Additional embodiments
9 Embodiments of the BHA's described above comprise substantially
electrically-actuated tools. As one of skill in the art will appreciate
however,
11 embodiments are possible which utilize a combination of mechanically-
actuated and
12 electrically-actuated tools.
13 In an embodiment using electrically-enabled CT, mechanically-
14 actuated fracturing tools, such as taught in Applicant's co-pending US
application
13/773,455 incorporated herein in its entirety, or other, conventional
mechanically-
16 actuated fracturing tools, may be combined with electrically-actuated
perforating
17 apparatus, as taught herein.
18 In yet another embodiment, using electrically-enabled and/or fiber
19 optic-enabled CT, mechanically-actuated fracturing tools and perforating
apparatus
can be combined with microseismic monitoring apparatus as taught herein and
21 which is operable in real time having data transmission to surface
through the CT.
54
CA 02951814 2016-12-15
1 Embodiments utilizing electrically-enabled and/or fiber optic-
enabled
2 CT, mechanically-actuated fracturing tools and perforating apparatus
combined with
3 microseismic monitoring operated in a memory mode can use signals
transmitted to
4 surface through the fiber optics for minimizing noise in the data which
is later
retrieved from the BHA.
6
7 Diagnostic Testing
8 A minifrac test is an injection falloff diagnostic test that is
performed
9 for establishing formation pressure and permeability prior to pumping the
main
fracture stimulation. A short fracture is created during the injection of
fluid, without
11 proppant, and the fracture closure is observed during the ensuing
falloff period. The
12 minifrac is used to establish design parameters for the main fracture
stimulation and
13 is typically performed immediately prior thereto.
14 Using a BHA 10, according to an embodiment having the first and
second variable diameter packers 22f,22s disclosed herein, the minifrac is
pumped,
16 and following pumping the minifrac, the first packer 22f is unset from
the sealing
17 position and the CT is unloaded with nitrogen. Thereafter, the first
packer 22f is
18 reset to the sealing position and additional testing can be performed,
such as the
19 DFIT or NFIT test to monitor the fracture closure pressure, production,
or the like.
21
CA 02951814 2016-12-15
1 Rock Stress Relief
2 Where
adjacent zones in the formation 30 are to be fractured, there is
3 concern
that, reductions in rock stress about a previously fractured zone might
4 cause a
fracture formed in the adjacent zone to break through to the previous
fracture.
6 Having
reference again to Fig. 6, and to minimize reductions in rock
7 stress
about the previous fractures, the valve 50 is actuated to permit fluid to be
8
delivered through the bore 38 of the electrically-enabled CT 12 to the fluid
crossover
9 port 60
below the first packer 22f. The fluid F exits the fluid crossover port 60 to
the
annulus 34 below the first packer 22f and to the previously perforated and
fractured
11 zones
therebelow to enter the perforations P and fractures to increase the rock
12 stress
about the previous fractures. In this case, while fluid F is delivered through
13 the
fluid crossover port 60, the fracturing fluid F is simultaneously delivered to
the
14 annulus
34 above the first packer 22f at suitable fracturing pressures for exiting the
perforations P and fracturing the newly perforated, adjacent zone. In
embodiments,
16 clean
fluid Fc is delivered through the electrically-enabled CT 12 to the annulus 34
17 below
the first packer 22f to elevate the pressure P2 therein to be equal to or
18 greater than the pressure P1 above the first packer 22f.
19 The
ability to provide fluid F below the first packer 22f through the
electrically-enabled CT 12 using the valve 50 provides a relatively simple
means to
21 avoid
the problems related to reduced rock stress and which largely avoids the
22 need
for the complex, carefully orchestrated, simultaneous fracturing operations at
56
CA 02951814 2016-12-15
1 multiple sites in side-by-side wellbores in a formation required
according to prior art
2 "zipper" fracturing techniques.
3
57
