CA2951814A1

CA2951814A1 - Methods and electrically-actuated apparatus for wellbore operations

Info

Publication number: CA2951814A1
Application number: CA2951814A
Authority: CA
Inventors: Per Angman; Mark Andreychuk; Allan PETRELLA
Original assignee: Kobold Services Inc
Current assignee: Kobold Corp
Priority date: 2012-04-27
Filing date: 2013-04-29
Publication date: 2013-10-31

Abstract

Embodiments of a bottomhole assembly BHA for completion of a wellbore are deployed on electrically-enabled coiled tubing (CT) and permit components of the BHA to be independently electrically actuated from surface for completion of multiple zones in a single trip using a single BHA having at least two electrically-actuated variable diameter packers. One or both of the packers may be actuated to expand or retract for opening and closing off a variety of flowpaths between the BHA and the wellbore, in new wellbores, old wellbores, cased wellbores, wellbores with sleeves and in openhole wellbores. Additional components in the BHA, which may also be electrically¨actuated or powered, permit perforating, locating of the BHA in the wellbore such as using casing collar locators and microseismic monitoring in real time or in memory mode.

Description

1 "METHODS AND ELECTRICALLY-ACTUATED APPARATUS FOR WELLBORE

2 OPERATIONS"

3

4 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.

Apparatus and methods are known for single-trip completions of deviated wellbores, such as horizontal wellbores. To date, unlike the drilling industry which commonly utilizes intelligent apparatus for drilling wellbores, particularly horizontal or deviated wellbores, the fracturing industry has relied largely on mechanically-actuated apparatus to perform at least a majority of the operations required to complete a wellbore. This is particularly the case with coiled-tubing deployed bottom hole assemblies (BHA's), largely due to the difficulty in providing 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 wireline deployed within an interior of CT to actuate conventional select-fire 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 vertical portions and very long horizontal wellbores. Use of coiled tubing to deploy conventional BHA's, particularly using small diameter CT, is problematic in such 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 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 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 I I

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.

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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 required. The length of the perforating guns impacts conventional operations, 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 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 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 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 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 wellbores having previously formed perforations or opened ports therein, particularly 22 where sleeves cannot be actuated to close, two spaced apart isolation apparatus I I

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 pressures are not monitored directly, but instead are calculated from parameters 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 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 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 operation. Alternatively, an extensive microseismic surface array may be used.
Both

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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.

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 I I

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.

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, 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;

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1 , Figure 4 is a representative illustration of a BHA according to Fig. 1A, deployed in a wellbore using electronically-enabled coiled tubing, a plurality of 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 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 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 decrease in rock stress about a previously fractured zone during fracturing of an adjacent zone, fracturing fluid being delivered to the annulus above the packer at 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.

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.

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 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 described in co-pending, US published application US2008/0263848 to Andreychuk, referred to herein as electrically-enabled CT. Electrical conductors 14, such as a wireline, multi-conductor cables, fiber optic cables and combinations thereof are 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

during repeated operations. In an embodiment multiple conductors 14 are surrounded by an outer insulated sheath for forming a protected cable for welding directly to the inner wall of the CT 12, and heat treated together with the CT

22 during manufacturing prior to use. The electrically-enabled CT can be used to 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.

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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.

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 I I

1 into the wellbore 16, being cased 18, an annulus 34 is formed between the 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 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

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 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

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 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 variables such as friction, horizontal length of the wellbore 16, the size and 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 appropriate balance between injection rates and pumping rates to avoid pulling the 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 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 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 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.

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 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 adjacent a distal end 152 of the BHA 10. While any type of selectively-actuated 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.

Microseismic monitoring option Optionally, where fracturing of the formation 30 is monitored using a microseismic fracture monitoring system, one or more seismic sensors 140, such as 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 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 I I

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.

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 1 packer and to act as a piston for pumpdown purposes and could include a third 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

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 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 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.

'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 surface S. In each of the thirty segments 92, there are three shaped charges 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 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 , II

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 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 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 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 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 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 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 combination with the accurate timing of detonation, to improve development of velocity profiles, sensor orientation and sensor calibration used in the microseismic 13 monitoring.

.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 perforation of the casing 18. The data, in combination with the accurate time of 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.

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.

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

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.

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 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 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 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 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 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 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 position to flow treatment fluid F, at fracturing pressures, from the CT 12 through the 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 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 wellbore. Release of the packer 22f can also include actuation of an equalization 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.

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.

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.

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.

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 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 electrically-actuated to the sealing diameter, acts to isolate the annulus 34 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, 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 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.

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.

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.

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.

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 independent controllability of the variable diameter packers 22, the same BHA

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 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 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.

17 Perforated wellbores 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 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.

1 Perforation option 2 Where a zone of interest has not been previously perforated, the 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 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 position the perforating apparatus 84, such as the perforating gun assembly 90, 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.

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 22f,22s, the electronics sub 80 further comprises electronics connected to additional 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 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.

1 Pressure equalization ¨ single and multi-packer embodiments 2 With reference to Fig. 8B, another embodiment of a two packer arrangement is provided, illustrated in cased wellbore, in which both the first, 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 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.

Similarly, the second packer 22s is associated with a bypass or 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 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.

1 Mechanical release ¨ single and multi-packer embodiments 2 As one of skill will appreciate, the BHA 10 further comprises 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 wellbore 16. Use of such release mechanisms avoids the need to disconnect the 7 BHA 10 unless absolutely necessary.

9 ,Microseismic monitoring ¨ single and multi-packer embodiments In embodiments disclosed herein and as described in Applicant's 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, 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 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 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).

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 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).

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 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 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.

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 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 wellbore 16 using the linear array of fiber optic sensors 190, estimates of the noise 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.

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 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 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 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 embodiments, the geophones 140 are placed at about 5m to about 10m apart.

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 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 sensors, a 10% error in velocity becomes significant by the time the signals reach a 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 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 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.

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.

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.

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.

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 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 1 multiple sites in side-by-side wellbores in a formation required according to prior art 2 "zipper" fracturing techniques.

Claims

THE EMBODIMENTS IN WHICH AN EXCLUSIVE PROPERTY OR
PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A system for completing and treating a wellbore, the system comprising:
electrically-enabled coiled tubing (CT) having a CT bore formed therethrough, and a bottom hole assembly (BHA) having, from a proximal end to a distal end, at least a treatment head and a packer, wherein the treatment head comprises fracturing ports to an annulus between the BHA and wellbore, the packer being electrically-actuated and comprising a packer element; and an electric packer drive electrically connected to the CT for electrically actuating the packer element between a first sealing diameter for sealing in the wellbore and at least a second running diameter, the running diameter being sized to be movable within the wellbore and acting as a piston for pumping the BHA and CT downhole within the wellbore.

2. The system of claim 1, wherein the packer further comprises slips.

3. The system of claim 1 wherein the CT and BHA form an injection string, the system further comprising:
a strain sensor along the injection string uphole of the packer, the strain sensor electrically connected to the CT for providing signals indicative of axial loading in the string at about BHA, a controller for receiving axial loading signals and for managing a rate of injection of the CT and a rate of pumping of the BHA for managing the axial loading.

4. The system of claim 1 wherein the wellbore is cased or lined, further comprising:
a casing collar locater (CCL) for engaging a casing collar for positioning the BHA in the wellbore; and a perforating apparatus for perforating the casing or liner.

5. The system of claim 2 wherein the perforating apparatus is an electrically-actuated, selectively-fired perforating gun further comprising a plurality of perforating segments, the system further comprising:
a top connector sub at the perforating apparatus for selectively triggering each of the perforating segments; and a firing panel at surface, the firing panel being electrically connected to the CT and to the top connector sub.

6. The system of claim 1, wherein the BHA comprises a throughbore and the treatment head further comprises a valve for alternately directing fluid to either the fracturing ports or the throughbore, the valve being electrically actuated, the BHA further comprising an electric valve drive electrically connected to' the CT for actuating the valve.

7. The system of claim 6 wherein the valve further directs fluid from the throughbore to a bore of the BHA below the packer.

8. The system of claim 1 wherein the electric drive further actuates the packer to a minimum packer diameter for tripping out of the wellbore.

9. The system of claim 2 wherein the CCL is electronic and electrically connected to the CT through an electronics sub in the BHA.

10. The system of claim 1 wherein the BHA further comprises:
one or more seismic sensors for monitoring microseismic signals during fracturing.

11. The system of claim 10 wherein the one or more sensors are two or more axially spaced, 3-component geophones.

12. The system of claim 10 wherein the one or more seismic sensors are positioned downhole of the treatment head for isolating the one or more sensors therefrom.

13. The system of claim 10 further comprising sensors for determining orientation of the one or more seismic sensors relative to surface.

14. The system of claim 10 wherein microseismic data from the one or more seismic sensors are electrically connected to the CT for communication of microseismic data to surface in real time.

15. The system of claim 10 further comprising a downhole processor with memory for storing microseismic data from the one or more seismic sensors for retrieval therefrom at surface.

16. The system of claim 1 wherein the CT further comprises fiber optics extending uphole from the BHA for optical signal communication between the BHA and surface.

61 ' 17. The system of claim 10 wherein the CT further comprises fiber optics extending uphole from the BHA, the fiber optics forming a linear array of distributed fiber optic sensors for along the wellbore for detecting compressional waves from background noise and transmitting the signals therefrom to surface, for removal of the noise from the microseismic signals.

18. The system of claim 10 wherein the two or more axially spaced, 3-component geophones further comprise arms electrically connected to the CT
and actuable between an extended position for coupling the geophones to the casing or wellbore for seismic coupling thereto; and a retracted position for decoupling therefrom.

19. The system of claim 1 wherein the BHA further comprises:
an electronics sub; and pressure sensors electrically connected to the electronics sub for monitoring pressure above and below the at least one packer, the electronics sub electrically connected to the CT for communications to surface.

20. The system of claim 19 wherein the BHA further comprises:
temperature and vibration sensors electrically connected to the electronics sub.

21. The system of claim 1 wherein the packer is a first packer and the electric drive is a first electric drive, the system further comprising:
a second packer, uphole of the treatment head, the second packer having a packer element and being electrically-actuated; and a second electric packer drive electrically connected to the CT for electrically actuating the second packer element between the sealing position and at least a second running diameter, the running diameter of the second packer element being sized to be movable within the wellbore and acting as a piston for pumping the BHA and CT downhole within the wellbore.

22. The system of claim 21 wherein:
the first packer element is electrically-actuated to a minimum diameter; and the second packer element is electrically-actuated for pumping the BHA and CT down hole within the wellbore.

23. The system of claim 21, wherein the BHA is secured in the wellbore as a result of pressure balancing across the first and second packers.

24. The system of claim 21 wherein the BHA further comprises:
an electronics sub; and pressure sensors electrically connected to the electronics sub for monitoring pressure above and below each of the first and second packers.

25. The system of claim 21, wherein the BHA comprises a throughbore and the treatment head further comprises a valve for alternately directing fluid to either the fracturing ports or the throughbore, the valve being electrically actuated, the BHA further comprising an electric valve drive electrically connected to the CT for actuating the valve.

26. The system of claim 25 wherein the valve further directs fluid from the throughbore to a bore of the BHA below the packer.

27. The system of claim 21 wherein the BHA further comprises:
one or more seismic sensors for monitoring microseismic signals during fracturing.

28. The system of claim 27 wherein the one or more sensors are two or more axially spaced, 3-component geophones.

29. The system of claim 27 wherein the one or more seismic sensors are positioned downhole of the treatment head for isolating the one or more sensors therefrom.

30. The system of claim 27 further comprising sensors for determining orientation of the one or more seismic sensors relative to surface.

31. The system of claim 27 wherein microseismic data from the one or more seismic sensors are electrically connected to the CT for communication of microseismic data to surface in real time.

32. The system of claim 27 further comprising a downhole processor with memory for storing microseismic data from the one or more seismic sensors for retrieval therefrom at surface.

33. The system of claim 21 wherein the CT further comprises fiber optics extending uphole from the BHA for optical signal communication between the BHA and surface.

34. The system of claim 27 wherein the CT further comprises fiber optics extending uphole from the BHA, the fiber optics forming a linear array of distributed fiber optic sensors for along the wellbore for detecting compressional waves from background noise and transmitting the signals therefrom to surface, for removal of the noise from the microseismic signals.

35. The system of claim 21 wherein the wellbore is cased or lined and having fluid communication with the wellbore, further comprising a casing collar locater (CCL) for engaging a casing collar for positioning the BHA in the wellbore.

36. The system of claim 35 further comprising perforating apparatus for perforating the casing or liner.

37. The system of claim 36 wherein the perforating apparatus is an electrically-actuated, selectively-fired perforating gun further comprising a plurality of perforating segments, the system further comprising:
a top connector sub at the perforating apparatus for selectively triggering each of the perforating segments; and a firing panel at surface, the firing panel being electrically connected to the CT and to the top connector sub.

38. A method of deploying and positioning a BHA in a wellbore comprising:
deploying the BHA in electrically-enabled coiled tubing, the BHA
comprising at least one packer having an electrically-actuable packer element electrically actuating the packer element to expand to a running diameter being less than a diameter of the wellbore;
pumping fluid through an annulus between the wellbore and the BHA, the packer element acting as a hydraulic piston for pumping the packer, the BHA
and the CT downhole in the wellbore; and electrically actuating the packer element to expand to a sealing diameter for sealing the annulus.

39. The method of claim 38 wherein the step of deploying the BHA, when encountering debris in the wellbore, further comprises:
'electrically actuating the packer element to reduce to a minimum diameter less than the running diameter, to permit the debris to pass the packer and BHA.

40. A method for treating one or more zones of interest in a formation intersected by a cased wellbore comprising:
providing a bottom-hole assembly (BHA) and electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, at least one packer and a perforating apparatus, preparing BHA packer for running into the wellbore by electrically actuating a packer element to a running diameter pumping fluid through an annulus between the BHA and the casing to act at the packer for pumping the BHA and CT downhole and positioning the perforation apparatus adjacent a lowermost zone of interest;
actuating the perforating apparatus to perforate the casing at the zone of interest;
pumping fluid through the annulus for pumping the BHA and CT
downhole so as to position the packer below the perforations;
electrically-actuating the packer element to a sealing position to seal the annulus and anchor the BHA in the cased wellbore;
pumping a treatment fluid through the annulus, through the coiled tubing and through the treatment head, or both, for delivery to the perforations and the zone of interest;
stopping the pumping of the treatment fluid;
equalizing pressure across the packer;

electrically-actuating the packer element from the sealing diameter to the running diameter;
pulling the CT and BHA uphole for repositioning the perforating apparatus adjacent another uphole zone of interest; and without removing the BHA from the wellbore, repeating the steps for the at least the another uphole zone of interest.

41. The method of claim 40 wherein the pumping of the treatment fluid through the annulus, or through the CT for pumping through the treatment head, or both, further comprises electrically actuating a valve at the treatment head for altemately directing fluid from the CT bore to the annulus.

42. The method of claim 40 wherein the perforating apparatus is an electrically-actuated perforating gun comprising a plurality of perforating segments electrically connected to the CT and to a firing panel at surface, the step of actuating the perforating apparatus comprises:
electronically actuating, from the firing panel, a select one or more of the perforating segments.

43. The method of claim 40 wherein the BHA further comprises a casing collar locator (CCL), the step of positioning the BHA further comprising:
engaging the CCL with a casing collar adjacent the zone of interest for positioning the BHA.

44. The method of claim 43 wherein the casing collar locator (CCL) is electrically connected to the CT, the step of positioning the further comprises:
electrically sensing a casing collar or perforations in the wellbore at the zone of interest with the CCL for positioning the BHA.

45. The method of claim 40 wherein the BHA further comprises pressure sensors electrically connected to the CT above and below the packer;
and after the step of electrically actuating the packer element to reduce from the sealing diameter to the running diameter for relocating the BHA in the wellbore or tripping the BHA out of the wellbore, the method further comprising:
monitoring the pressure data from the one or more pressure sensors at surface for determining when the pressure above the packer and below the packer are balanced.

46. The method of claim 40 wherein the cased wellbore has a plurality of spaced apart ported sleeve subs incorporated therein, sleeves in the ported sleeve subs being actuable between a closed position for blocking one or more ports through the casing and an open position for opening the one or more ports for treating the formation therethrough, the method comprising:
engaging the sleeve at the zone of interest with the BHA and electrically-actuating the BHA to move the sleeve to the open position.

47. The method of claim 46, after the step of pumping the treatment fluid to the perforations, further comprises:
engaging the sleeve with the BHA and electrically-actuating the BHA
to move the sleeve to the closed position.

48. The method of claim 40, wherein the BHA further comprises one or more 3-component sensors, the method comprising:
monitoring microseismic events in the wellbore and outside the wellbore using the one or more 3-component sensors for collecting microseismic data from x, y and z.

49. The method of claim 48 wherein the one or more 3-component sensors are electrically connected to the CT, the method comprising:
transmitting the x, y and z data from the two or more 3-component sensors to surface through the electrically-enabled CT, in real time.

50. The method of claim 48, wherein one or more 3-component sensors comprise storage memory and a battery, the method further comprising:
storing the x, y and z data from the two or more 3-component sensors in the memory retrieving the storage memory to surface with the BHA.

51. The method of claim 40 wherein the packer is a downhole first packer and the BHA further comprises an uphole second packer having a packer element independently controllable from the first packer, the second packer being spaced uphole of the fracturing ports and electrically connected to the CT;
the step of deploying the BHA further comprising:
electrically actuating the packer element of one or both of the first and second packers to expand the diameter to the running diameter;
pumping fluid through the annulus for pumping the one or both of the first and second packers and the BHA downhole; and prior to pumping treatment fluid through the annulus, actuating the packer element of the second packer to retract to a minimum packer diameter.

52. The method of claim 51 wherein one or more perforations has sanded-off, the method further comprising:
releasing the second packer by electrically actuating the packer elements of the second packer to reduce the diameter to about a minimum disameter;
pumping a fluid through the CT bore for circulating the fluid to surface through the annulus for cleaning sand from the perforations; and when cleaned electrically-actuating the second packer to re-expand the packer element to the sealing diameter for re-sealing the annulus between the BHA and the wellbore uphole of the perforations; and pumping the treatment fluid to the perforations and into the formation.

53. The method of claim 40 for use in wellbores having existing perforations or open ports therein, wherein the packer is a first packer and the BHA
further comprises a second packer having a packer element independently controllable from the first packer, the second packer being positioned uphole of the fracturing ports, further comprising:
positioning the BHA having the second packer uphole of the existing perforations or open ports and the first packer downhole thereof;

independently electrically-actuating the packer element of each of the first packer and the second packer to the sealing diameter for sealing the annulus between the BHA and the wellbore above and below the existing perforations;
pumping the treatment fluid through the CT bore to the fracturing ports for delivery to the zone of interest;
stopping the pumping of the treatment fluid; and independently electrically-actuating the packer element of the first packer and the packer element of the second packer to reduce the diameter to the running diameter.

54. A method for treating multiple intervals of one or more formations intersected by a cased wellbore having existing perforations or open ports therein, at one or more zones of interest, the method comprising:
injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, a first packer downhole of the treatment head and a second packer uphole of the treatment head wherein the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore, and each of the first and second packers comprises a packer element and an electric packer drive electrically connected to the coiled tubing for independently actuating the packer element of the first and second packer between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore.
electrically-actuating the packer element of one or both of the first and second packers to the running position;
pumping fluid through an annulus between the BHA and the casing to act at the packer in the running diameter for positioning the BHA having the first packer below the existing perforations or open ports and the second packer thereabove for straddling the perforations or open ports;
electrically-actuating the packer element of the first packer and the second packer to the sealing position to seal in the wellbore;
anchoring the BHA in the cased wellbore;
pumping a treatment fluid through the CT bore to the fracturing ports for delivery to the perforations or open ports and to the zone of interest;
stopping the pumping of the treatment fluid;
equalizing pressures above, between and below the first and second packers;
electrically actuating the packer elements of the first and second packer element to reduce from the sealing diameter to at least the running diameter;

repositioning the BHA so as to straddle existing perforations or open ports between the first and second packers at another zone of interest; and without removing the BHA from the wellbore, repeating the steps for the at least the another zone of interest.

55. The method of claim 54 wherein the wellbore further comprises one or more zones of interest without existing perforations or opened ports therein, the BHA further comprising a perforating apparatus downhole of the first packer, the method further comprising:
positioning the BHA having the perforating apparatus adjacent one of the one or more zones without existing perforations or opened ports;
actuating the perforating apparatus to form new perforations at the zone of interest without existing perforations;
repositioning the BHA having the first packer downhole of the new perforations and the second packer thereabove;
independently electrically-actuating the packer element of the first and second packer to expand to the sealing diameter for sealing the annulus between the BHA and the wellbore;
pumping the treatment fluid through through the CT bore to the fracturing ports for delivery to the perforations and to the formation therethrough;
stopping the pumping of treatment fluid;

equalizing pressures above, between and below the first and second packers;
independently electrically actuating the packer element of each of the first and second variable diameter packers to reduce to at least the running diameter; and repositioning the BHA adjacent another zone of interest without removing the BHA from the wellbore.

,56. The method of claim 54 wherein the perforating apparatus is an electrically-actuated perforating gun comprising a plurality of perforating segments electrically connected to the CT and to a firing panel at surface, the step of actuating the perforating apparatus comprises:
electronically actuating, from the firing panel, a select one or more of the perforating segments.

57. A method for treating multiple intervals of one or more formations intersected by a cased wellbore in a single trip wherein one or more perforations has sanded-off, the method comprising:
injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, from a proximal end to a distal end, at least a treatment head, a first packer downhole of the treatment head and a second packer uphole of the treatment head wherein the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore; and the first and second packers comprises a packer element and an electric packer drive electrically connected to the coiled tubing for independently actuating the packer element of the first and second packer between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore.
positioning the BHA having the second packer uphole of perforations or open ports at a first zone of interest and the first variable diameter packer downhole thereof;
electrically-actuating packer elements of the second packer to expand the variable diameter to a sealing diameter for sealing an annulus between the BHA
and the wellbore;
electrically-actuating packer elements of the second packer to expand the variable diameter to a sealing diameter for sealing an annulus between the BHA
and the wellbore therebelow;

pumping a treatment fluid to the perforations and into the formation, through the coiled tubing to the fracturing ports and to the perforations or opened ports; and wherein when the perforations or open ports sands off releasing the second variable diameter packer by electrically actuating the packer elements of the second packer to reduce the diameter of the second packer to a minimum packer diameter;
continuing pumping a fluid for circulating the fluid to surface through the annulus for cleaning sand from the perforations for clearing the sand-off and thereafter electrically-actuating the second packer to re-expand the packer elements to the sealing diameter for re-sealing the annulus between the BHA and the wellbore uphole of the perforations; and pumping the treatment fluid to the perforations and into the formation, through the coiled tubing to the fracturing ports and to the perforations or opened ports.

58. A method for reducing rock stress during treatment of a formation comprising:
deploying a BHA in a wellbore;
positioning fracturing ports in the BHA adjacent a first zone of interest;
setting a packer in the BHA below the fracturing ports to isolate an annulus between the BHA and the wellbore;
delivering treatment fluid to the fracturing ports for fracturing the formation at the zone of interest;
releasing the packer;
repositioning the BHA for positioning fracturing ports in the BHA at a subsequent zone of interest adjacent the first zone of interest;
setting the packer to isolate the annulus; and 'while delivering treatment fluid to the fracturing ports for fracturing the formation at the subsequent adjacent zone of interest;
flowing fluid through the BHA to below the packer for delivery to the first zone of interest for reducing rock stress in the first zone of interest during fracturing of the adjacent zone of interest.

59. The method of claim 58 further comprising:
repeating the steps of repositioning, setting and flowing fluid below the packer to the zones therebelow while delivering treatment fluid to another subsequent zones of interest.

60. A method for reducing rock stress during treatment of a formation comprising:
injecting a bottom-hole assembly (BHA) into the wellbore using electrically-enabled coiled tubing (CT), the CT having a CT bore therethrough, the BHA having, the BHA having, from a proximal end to a distal end, at least a treatment head and a packer, wherein the treatment head comprises fracturing ports, a throughbore and a valve for alternately directing fluid between the fracturing ports and the throughbore; and the packer comprises a packer element and an electric packer drive electrically connected to the coiled tubing for actuating the packer element between a sealing diameter for sealing in the wellbore and a running diameter for acting as a piston to aid in moving the BHA and CT downhole within the wellbore;
electrically-actuating the packer element to the running position;
pumping fluid through an annulus between the BHA and the casing to act at the packer for positioning the BHA so as to position the packer below perforations in the wellbore;
electrically-actuating the packer element to the sealing position to seal in the wellbore;
pumping a treatment fluid through the annulus, through the CT, or both, for delivery to the perforations and the zone of interest;

stopping the pumping of the treatment fluid;
electrically actuating the packer element to reduce from the sealing diameter to the running diameter;
repositioning the BHA at a subsequent adjacent zone of interest; and while delivering treatment fluid to the fracturing ports for fracturing the formation at the subsequent adjacent zone of interest;
actuating the valve for delivery fluid to the fracturing ports and to the throughbore for delivering fluid below the packer; and 'flowing fluid below the packer for delivery to the first zone of interest for reducing rock stress in the first zone of interest during fracturing of the subsequent adjacent zone of interest.

61. The method of claim 60 further comprising:
repeating the steps of repositioning, setting and flowing fluid below the packer to the zones therebelow while delivering treatment fluid to another subsequent zones of interest.