Note: Descriptions are shown in the official language in which they were submitted.
21707:~1
LOCATOR AND SETTING TOOL
AND METHODS OF USE THEREOF
BACKGROUND OF THE INVENTION
The present invention is a continuation-in-part of United States Patent Application
Serial No. 08/028,963, filed March 10, 1993.
Field of the Invention
The present invention relates generally to improved methods and apparatus for use
in placing barrier members, such as packers, plugs or other locks, within strings of tubular
members. More particularly, the invention relates to improved means for locating a barrier
member within a cased wellbore and then setting the barrier member within the wellbore.
Description of the Related Art
The use of plugs, locks and other barrier members in oilfield tubular members is
well-known in the art. A packer assembly, as particularly described relative to the
preferred embodiment herein, is normally installed to securely and sealingly engage the
interior wall of a wellbore and provide fluid and pressure isolation between sections of the
wellbore. Once the packer assembly is set, a tubing string may be inserted into the
wellbore and latched into the packer assembly so that production operations may be
conducted. When those operations have been completed, the tubing string is unlatched
from the packer assembly and removed from the wellbore. A pulling tool may be run into
the wellbore thereafter to engage the packer and unset it so that it may be removed from
the wellbore.
Using conventional techniques, barrier members such as packers or locks are often
set within a casing string, tubing string or other string of tubular members with an
21~7~1
explosive charge which rapidly expands portions of the barrier member to cause them to
engage the inside walls of the surrounding tubular member, thus setting the member. The
use of explosives for setting is not reliable, however, since a small asymmetries in the
geometry of the explosion may cause the barrier member to become set off-center within
the tubular member making it more prone to failure under stress. Further, rapid setting,
such as by explosive methods, may cause the setting elements of the barrier member to
be structurally deformed during setting and, thus, weakened.
A packer assembly is typically intended to be placed in a wellbore at a particular
depth from surface which is specified by the customer and supplied to the well operators.
Normally, it is desired to set the packer above a set of perforations in the casing. Proper
placement and setting of a packer assembly, however, requires some information
regarding the location at which the packer assembly is being set within the wellbore.
Casing joints, the couplings between two casing sections, appear at intervals along the
casing and present gaps or discontinuities in the casing wall which may prevent the
packer assembly's elastomeric sealing element from sealing properly at those locations.
If the well operators can determine beforehand that the depth or location specified by the
customer for placement of the packer assembly will result in the packer's sealing element
being set at a casing joint, they can inform the customer and obtain guidance for adjusting
the location for setting the packer assembly or receive other instructions.
Well operators normally try to avoid casing joints by correlating their estimate of
the depth at which the packer assembly will be set with recorded depths of casing collars.
- 2170711
Unfortunately, potential problems or inaccuracies with both sets of data often prevent a
precise correlation. Because casing joints appear roughly every thirty feet along the
wellbore, an inaccurate correlation risks undesired setting of a packer at a casing joint.
The operators obtain an estimation of the depth at which the tool will be positioned
when it is disposed in the wellbore by physically measuring the length of the running
arrangement used to dispose a tool into a wellbore. For example, if a tool is disposed into
a wellbore on a 500 foot running string, it would be assumed that the tool would be
disposed at a depth of 500 feet below the surface. However, running arrangements tend
to stretch slightly in the wellbore, as a result of heat and weight, skewing the estimate.
A 5/16" monofilament cable has an average stretch rate of 1.2 ft/kft/klb. However, the
rate of actual stretch will vary depending upon the weight of the bottom hole assembly
and the depth at which the running arrangement is disposed. It is, therefore, difficult to
obtain a precise actual depth estimate using only physical measurement of the running
arrangement.
A casing collar locator log is made up when a casing string is run and lists the
recorded depths at which the threaded casing collars that join adjacent casing sections
at the casing joints will be found. Once the casing is cemented, the collars are intended
to form permanent reference points for measuring depth. If the location of a casing collar
is known, the planned location for setting of a packer can be adjusted upward or
downward within the wellbore to avoid setting the packer at the casing joint. However,
the casing collar locator log for an older well may be unavailable when needed. Also,
217~711
older collars occasionally rust through and allow the portion of the casing string below the
rusted collar to slip downward, altering the locations of the collars below. If an operator
lacks accurate casing collar location information, reliable correlation with data obtained
from physical measurement of the running arrangement may be impossible.
It is therefore desirable to have an improved means of positioning packer assemblies
or other barrier members within a wellbore. Accordingly, the present invention provides
a means for accurately reconciling the disposed depth of a packer assembly with the
locations of casing collar during a packer setting operation. New methods and apparatus
for setting a packer assembly or other barrier member are described which can be used
to avoid inadvertent settings at connections between the tubular members, such as casing
joints. The present invention also provides improved methods and apparatus for setting
the barrier member wherein the member is slowly radially expanded by a setting assembly
which is actuated by power transmitted from the surface.
SUMMARY OF THE INVENTION
The invention features an electrically powered locator and setting tool. This tool
is capable of setting a barrier member within a cased wellbore or other string of tubular
members and may be later modified and converted to a pulling tool which can unset and
retrieve the barrier member from the wellbore. Prior to setting the barrier member, the
locator and setting tool can position a barrier member, such as a packer or plug within a
cased wellbore or other string of tubular members in a manner such that the barrier
member will not be set at a casing joint.
~ ~170711
In a preferred embodiment, the locator and setting tool preferably features a single
tool arrangement made up of a composite housing containing a casing collar locator and
a packer setting assembly. The casing collar locator includes a detection means which
detects the actual locations of casing collars along a casing string. The locator then
provides a signal indicative of these locations. The setting section of the tool includes a
motor and an associated linear drive section or working assembly which will operate an
attached retrievable packer assembly to set the packer assembly at a desired point in the
wellbore.
A remote power source, usually located at the surface of the wellbore, supplies
electrical energy to the locator and setting tool through an electrically conductive power
line which can be extended down through the wellbore. Because the locator and setting
tool is preferably run into a wellbore by wireline, the power line is typically disposed along
or within the wireline running arrangement. In instances where the locator and setting
tool is run into the wellbore by tubing conveyance, the power line will be located within
the tubing string.
In methods of operation described herein, a planned setting point within a cased
wellbore is established based upon recorded well logs and customer requirements. The
planned setting point is established at a point in the casing string where no joint is
recorded. A packer assembly is disposed into a wellbore using the locator and setting tool
to a point proximate the planned setting point according to physical measurement of the
running arrangement. Via manipulation of the running arrangement, locations of casing
17~71 1
collars around the planned setting point are detected by the casing collar locator. The
detected depths of the casing collars are then compared to the recorded collar depths.
If the detected and recorded depths match, the packer assembly may be set at the
planned setting point. If there is a discrepancy between the detected and recorded collar
depths, however, the customer can be informed and warned that setting the packer at the
planned setting point may result in setting at a joint. The adjusted setting point is
established in a portion of the wellbore where no casing joint has been detected which
could prevent the barrier member from establishing or maintaining a fluid seal when set.
According to the methods herein described, the locator and setting tool is
removably affixed to a retrievable packer assembly. The "offset distance," the
approximate longitudinal distance from the casing collar locator's detection means and the
sealing member of the packer assembly, is measured. A running arrangement and a
power line are attached to the locator and setting tool. Once the setting point has been
adjusted and verified as described, the locator and setting tool and the affixed packer
assembly are disposed within the wellbore to the depth of the setting point. The packer
assembly may then be set inside the wellbore by operation of the packer setting assembly.
In preferred embodiments, a retrievable packer assembly is employed for later removal
from the wellbore by operation of a modified locator and setting tool.
The setting assembly of the locator and setting tool features a setting assembly
which is actuated by remotely transmitted power. In a preferred embodiment, the power
is transmitted from a source at the surface of the well via a power line located within the
_ 2170711
running arrangement. The setting assembly features a gearmotor-driven working
assembly which imparts opposing axial or longitudinal forces and motion to portions of
the barrier member in order to set it within a wellbore. The distance of the opposing axial
motion defines a setting stroke for the setting assembly.
Following setting of the barrier member and disengagement of the locator and
setting tool from the barrier member, a clutch arrangement limits the length of the setting
stroke for the setting assembly. The clutch arrangement prevents excessive opposing
axial or longitudinal motion which might result in harm to the gearmotor or other
components of the setting assembly.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic overall view showing an exemplary locator and setting tool
constructed in accordance with the present invention with an attached packer assembly
disposed within a wellbore.
FIGS. 2A-2E are a partial cross-sectional view of an exemplary locator and setting
tool constructed in accordance with the present invention and in connection with a
retrievable packer assembly.
FIG. 3 is a vertical cross-section of a portion of the exemplary locator and setting
tool.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring first to Figure 1, a portion of cased wellbore is shown. The wellbore
portion includes an inner metallic casing string 50 and a surrounding cement sheath 52
~170711
disposed within a potential subterranean petroleum producing zone 54. The casing string
50 encloses a wellbore 56 and includes an upper casing section 58 and lower casing
section 60, which are jointed in a longitudinally, coaxial relation at a casing joint indicated
generally at 62. It should be understood that the casing string 50 actually consists of a
large number of connected casing sections. Only a single joint 62 is shown for purposes
of illustration.
The casing joint 62 features a casing collar 64 of a type known in the art. The
casing collar 64 surrounds and threadedly engages each casing section 58, 60 to join
them. A gap 66 is located between the upper and lower casing sections 58, 60. A
wireline 68 suspends packer setting tool 70 within the wellbore 56.
The casing collar locator section 72 includes a device or assembly for detecting
casing mass changes that occur at collar joints. A number of suitable casing collar locator
assemblies are known which use magnetic coil induction to detect changes in casing
thickness. When the locator passes through a casing collar, the magnet/coil assembly
outputs an induced current which results in a signal which is transmitted to the tool
operators at the surface. An exemplary assembly will be described here in enough detail
for the reader to understand its general operation. A preferred casing collar locator
assembly is the Universal Casing Collar Locator Tool (UCCL) marketed by Halliburton Co.
The UCCL uses a four coil, six magnet arrangement to detect casing changes. This type
of device is commonly used with perforating gun arrangements.
~l7a7ll
Referring now to Figures 2A-2E, the locator and setting tool 70 is now described
in greater detail. Where components of relatively well known design are employed, their
structure and operation will not be described in great detail. Connections between
components, although not specifically described in all instances, are shown schematically
and comprise conventional connection techniques such as threading and the use of
elastomeric 0-ring or other seals for fluid tightness where appropriate. The use of terms
such as "above," "upper," and "below" are used to identify the relative position of tool
components as shown disposed within an exemplary wellbore and with respect to
distance to the surface of the wellbore as measured along the wellbore path.
The locator and setting tool 70 is generally comprised of an upper casing collar
locator section 72 and a lower setting section 74. As will be described, a portion of the
setting section 74 is made up of a working assembly which is detachably connectable to
a retrievable packer assembly.
An outer composite housing 76 encloses the locator and setting tool 70 and
extends from the top 78 of the tool to its lower end 80. The top 78 of the tool 70
features an appropriate connector sub 82 to facilitate coupling of the housing 76 to a
running arrangement such as wireline 68 by use of conventional means such as a clamp
ring type cablehead assembly available from numerous commercial vendors including
Halliburton Logging Systems of Houston, Texas and Titan Specialties, Inc. of Pampa,
Texas. The sub 82 encloses an electrically conductive plug 84 which will engage a
complimentary conductive device on the running arrangement. As FIG.2A illustrates, the
~ ~170711
wireline running arrangement 68 includes a coaxially disposed power cable 86 which will
engage the plug 84 when the wireline running arrangement has been connected at the
upper end 78 of the tool 70 so that electrical power may be transmitted from the power
cable 86 into the plug 84.
The connector sub 82 is affixed to an annular non-magnetic sleeve 88 at threaded
connection 90. The non-magnetic sleeve 88 is preferably made up of a non-magnetic
metal such as a beryllium, nickel or copper alloy. Similarly, the non-magnetic sleeve 88
is affixed to a lower sub 92 at threaded connection 94. The connector sub 82, sleeve 88
and lower sub 92 collectively enclose the casing collar locator section 72. As noted, the
components making up the detector means of the casing collar locator are preferably the
same as or similar to standard casing collar locator devices such as the UCCL. By way
of background, however, they will be described now in limited detail. Within the casing
collar locator section 72, an electrical conduit 96 extends downward from the plug 84 to
a voltage protector device 98 such as a "double diode" assembly which protects electrical
components of the casing collar locator section 72 during operation of the setting section
74.
A coil and magnet assembly 100 is positioned axially between upper and lower
elastomeric shock absorbing elements 102 and 104, respectively. The operation of a coil
and magnet assembly 100 to magnetically induce current changes in electrically energized
coils upon detection of changes in metallic casing thickness is well known in the art and
will not be described in further detaii. It is noted that the coil and magnet assembly 100
-- 21~0711
functions as a detection means for determining in this manner the actual locations of
casing collars and thus casing joints within a wellbore. In addition to this detection
function, the casing collar locator section also generates a signal representative of these
locations and transmits them to the surface using known techniques via a signal conduit
(not shown) coaxially disposed within the wireline or other running arrangement. The
voltage protector device 98 extends through each shock absorbing element 102,104 and
the coil and magnet assembly 100 to provide electrical power to the coil and magnet
assembly 100.
A tubular neck member 106 extends between the casing collar locator section 72
and setting section 74 adjoining the two sections and forming a portion of the housing 76.
The neck member 106 includes a radially enlarged lower end 108 which presents an
upward facing engagement shoulder 110. An upper setting sub 112 forms a bell housing
which surrounds the neck member 106 and presents an internal downwardly facing
annular engagement shoulder 114 which is complimentary to the engagement shoulder
110. The upper setting sub 112 is connectable at its lower end to pin housing sub 116
by means of a threaded connection 118. When the upper setting sub 112 is fully
engaged with the pin housing 116 and the threaded connection 118 is tightened, the
shoulders 110 and 114 will be engaged as well, forming a secure connection between the
casing collar locator section 72 and the setting section 74. An electrical feedthrough
conduit 120 is centrally disposed within the neck member 106.
`- ~170711
The remainder of the composite housing 76 is made up as follows. Pin housing
116 is affixed by means of a threaded connector 117 to a gearmotor housing 119. The
gearmotor housing 119 is in turn affixed at threaded connection 121 to a jackscrew
housing 123. Below the jackscrew housing 123, clutch housings 125 are threadedly
affixed to the jackscrew housing 123. The clutch housings 125 include a reduced
diameter lower end 127 and an external thread 129 by which cylindrical sleeve 160 is
attached to the clutch housings 125. A number of radial bushings or packings 162 are
enclosed within the lower end 127 and secured into place by a threaded end cap 164.
Referring now to FIG. 2E, the cylindrical sleeve 160 is affixed at its lower end to a radially
enlarged adapter sleeve 166 by means of an adapter fitting 168 and bushing sleeve 170.
The adapter sleeve 166 contains a number of laterally-disposed assembly holes along its
length which permit operators access to interior components and serve as vent holes.
The lower end of the adapter sleeve 166 comprises the lower end 80 of the housing 76
of the tool 70 and presents a downwardly and outwardly-facing engagement shoulder
172 as well as an extension portion 174 of reduced external diameter.
Returning to FIG. 2B, the pin housing 116 encloses a setting assembly activating
pin 120 which is fashioned of electrically conductive material to engage the electrical
feedthrough conduit 120 when the casing collar locator section 72 and setting section 74
are connected as described above. A compression spring mechanism 124 surrounds pin
122 and biases it toward the conduit 120 to ensure this engagement. Insulator sleeves
126 surround the pin 122 to prevent transmitted electrical energy from being dissipated
2170711
into the pin housing 116. The insulator sleeves 126 are preferably formed of ceramic or
other non-conductive material. Electrical power transmitted to the pin 120 is relayed
through suitable electronic components 128 to a controller board 130 and from there via
controller wires 132 to gearmotor 134. Upon receiving electrical power through the
components 128, the controller board 130 initiates operation of the gearmotor 134. The
gearmotor 134 may be of any suitable type. For the embodiment described herein, a
motor operating at 7500 rpm in an unloaded condition and approximately 5000 rpm in a
loaded condition, and having a horsepower rating of approximately 1 /30th of a
horsepower has been found satisfactory. In this same embodiment, the gearmotor 134
is coupled through a gear box 136 which provides approximately 5000: 1 gear reduction
to a convention rotational drive assembly 138 to drive a jackscrew assembly generally
indicated at 140.
Suitable commercially available gearmotors include Globe type BD DC motors such
as the A-2400 motor available from the Globe Motor Division of Precision Mechnique
Labinal, 2275 Stanley Ave., Dayton, Ohio 45404, (513) 228-3171. Also suitable are BD
and BL DC permanent magnet planetary gearmotors such as the A-2430 motors from
Globe Motors. The jackscrew assembly 140 is preferably a conventional assembly, such
as those manufactured and sold by Warner Electric Brake & Clutch Co. of South Beloit,
Illinois 61080, (815) 389-3771 as model R-1105 Ball Screw.
The rotational drive assembly 138, when actuated, will rotate an elongated collar
member 139 about its own longitudinal axis within the jackscrew housing 123. A
~17~711
14
lubricated packing 141 and bearings 143 are disposed between the jackscrew housing
123 and the collar member 139. The collar member 139 is affixed at its upper end to the
rotational drive assembly 138 and at its lower end to an axially rotatable sleeve assembly
144.
The jackscrew assembly 140 also includes a threaded shaft 142 which moves
longitudinally, at least initially, in response to rotation of the outer sleeve assembly 144.
In the preferred embodiment described herein, the threaded shaft 142 will be a 5 pitch
shaft. The threaded shaft 142 includes an elongated threaded portion 146 and a generally
smooth, polished lower extension 148. The threaded portion 146 is operationally
associated with the sleeve assembly 144 by means of a plurality of ball bearings (not
shown) which engage the threads of the threaded portion 146. The threaded shaft 142
further includes a pair of diametrically opposed keys, one of which is shown at 150,
which cooperate with a clutch block 152 coupled to threaded shaft 142. As shown in
FIG. 2E, the lower portion of the lower extension 148 is threadedly engaged via a
conversion nut 176 to a generally cylindrical tension sub 178. Threaded connection 180
interconnects tension sub 178 with a guide bushing 182.
Returning now to FIG. 2C, the clutch housings 125 enclose a generally cylindrical
sleeve 199 which includes a pair of diametrically opposed keyways 154 which extend
along at least a portion of the length of the sleeve 199. Keys 150 extend radially
outwardly from the threaded shaft 142 through the clutch block 152 to engage each of
the keyways 154 in the sleeve 199 thereby preventing rotation of the threaded shaft 142
- 217~7~1
relative to the sleeve 199. The keys 150 are maintained within the clutch block 152 by
means of pins 153. Reference to FIG. 3 helps to illustrate the relationship of these
components.
Rotation of the sleeve assembly 144 in one direction will cause the threaded shaft
142, clutch block 152 and keys 150 to move longitudinally upwardly relative to the sleeve
199. An upper position for the keys 150 is shown at 150a in FIG. 2C. Rotation of the
sleeve assembly 144 in the opposite direction causes the threaded shaft 142 and clutch
block 152 to move longitudinally downwardly relative to the sleeve 199. To set a barrier
member in the manner described in this preferred embodiment, the sleeve assembly 144
will need to be rotated so as to cause upward longitudinal movement of the threaded
shaft 142. As will be appreciated by those skilled in the art, because movement of the
shaft 142 occurs relative to the sleeve 199, operation of the setting section 74 results
in a linear action drive or working assembly which is capable of generating force and
motion in opposing axial or longitudinal directions simultaneously. As will be described
shortly, the application of opposing axial or longitudinal forces and motion to portions of
a barrier member may be used to set that barrier member within a wellbore. The upward
movement of the threaded shaft 142 (and any affixed components) with respect to the
sleeve 199 (and affixed components) is referred to as a setting stroke.
Above a certain level within the sleeve 199, as indicated in FIG. 2C, the sleeve 199
includes a relatively enlarged internal diameter bore 156 such that moving the clutch block
152 into the bore 156 removes the outwardly extending keys 150 from being restricted
-
~1~0711
16
against rotational movement within the sleeve 199. Accordingly, continued rotation of
the sleeve assembly 144 will also result in free rotation of the threaded shaft 142 within
the sleeve 199. By placement of the enlarged internal diameter bore 156 a measured
distance along the sleeve 199, the amount of axial movement of the threaded shaft 142
along the sleeve 199 can be established. The clutch function of the jackscrew 140
thereby serves as a safety device to prevent burn-out of the electric motor and also serves
to limit the length of the setting stroke of the setting section 74.
Referring once more to FIGS. 2D-2E, the upper portion of an exemplary retrievable
packer assembly 200 is shown in connection with the locator and setting tool 70 for
location and setting of the packer assembly 200 within a wellbore. A preferred packer
assembly of this type is the Otis Versa-Trieve Packer currently commercially available from
Halliburton Energy Services, 2601 Beltline Road, Carrollton, Texas 75006, (214) 418-
3000. Other retrievable packer assemblies may be suitable for use as well. Such packer
assemblies are moveable between set and unset conditions by axial movement of a sleeve
or other component to axially compress slips and sealing elements causing them to
extrude or extend radially outward until they contact the casing wall of the borehole. A
ratchet mechanism may be used to secure the axially displaced components of the packer
assembly such that the packer is maintained in its set condition.
In order to aid in understanding of the invention, some general features of this
packer assembly 200 will now be briefly described. The packer assembly 200 features
a top sleeve 202 which is threadedly connected at 204 to an outer shear sub sleeve 206.
~170711
The top sleeve 202 presents an inwardly-directed fishing neck 205 which is useful for
retrieval of the packer assembly 200 in conventional ways such as by use of a fishing
tool. It is noted that the outer diameter of the guide bushing 182 is shaped and sized to
fit within the interior diameter of the sleeve 206 and be reciprocally moveable therewithin.
The lower end of the shear sub sleeve 206 is threadedly engaged at 208 to a packer
element sub 210. The packer element sub 210 includes an element support mandrel 213
which radially presents one or more elastomeric sealing elements 212. Located on either
axial end of the sealing elements 212 are end members 214 (one shown). The sealing
elements 212 may be moved between an unset condition, wherein they have a radially
reduced diameter as shown in FIG. 2E, and a set condition (not shown) wherein the
elements 212 are axially compressed by the end members 214 to a radially expanded
condition. This manner of setting and unsetting of sealing elements is well known in the
art. Lower portions of the packer assembly 200 (not shown) may further include sets of
slips which are radially expandable in a similar manner to engage an inner casing wall and
radially retractable to release the packer assembly 200 from engagement with the casing
wall.
Located radially within the lower portion of the shear sub sleeve 206 is a packer
mandrel 216 which is affixed by threading 220 at its lower end to mid mandrel 220 for
joint reciprocal movement within the shear sub sleeve 206. A cylindrical guide tube 222
is disposed radially within the packer mandrel 216 and mid mandrel 220 axially below the
guide bushing 182. Upward axial movement of the packer mandrel 216 and mid mandrel
~170711
220 with respect to the shear sub sleeve 206 will cause the slips (not shown) and sealing
elements 212 of the assembly 200 to be moved into their set conditions.
The locator and setting tool 70 is removably affixed to the packer assembly 200
in the following manner. Shear pins 184 affix the guide bushing 182 to packer mandrel
216. It is important that the shear pins 184 provide a total shear resistance force which
is greater than the amount of force required to set the packer assembly 200, but less than
the maximum amount of axial force which can be generated through operation of the
rotational drive assembly 138 by the gearmotor 134. In one preferred embodiment, four
shear pins are used which present a total shear resistance force of 6000 pounds. The
shear pins 184 can be emplaced to connect these components only when the threaded
shaft 142 of the jackscrew assembly 140 is axially extended to nearly its fullest length.
Once the shear pins 184 have been emplaced to connect the guide bushing 182 and
packer mandrel 216, the extension portion 174 is disposed within the upper end of the
upper sub 202 until the engagement shoulder 172 of the sleeve 166 abuts the upper end
of the upper sub 202 as shown in FIG. 2E.
When affixed as described, upward axial movement of the tension sub 178 of the
tool 70 within the shear sub sleeve 206 results also in upward axial movement of the
guide bushing 182, packer mandrel 216 and mid mandrel 218 within the shear sub sleeve
206. Similarly, the slips and sealing elements 212 will be unset when the packer mandrel
216 and mid mandrel 218 are forced downward with respect to the shear sub sleeve 206.
~17071 1
During a typical setting operation, the setting section 74 is operated to set the
packer assembly 200 and then to release the locator and setting tool 70 from the
emplaced packer assembly 200. Actuation of the rotational drive assembly 138 by the
gearmotor 134 will result in the upward longitudinal or axial movement of the threaded
shaft 142 from rotation of the outer sleeve assembly 144. The lower extension 148 of
the shaft 142 will be drawn axially upward along with the conversion nut 176, tension
sub 178, guide bushing 182, packer mandrel 216 and mid mandrel 218. During this
movement, the top sleeve 202, outer shear sub sleeve 206 and end members 214 of the
packer element sub 210 are prevented from upward movement by the engagement of the
upper sub 202 with the adapter sleeve 166 of the locator and setting tool 70, and upward
axial movement of the described components occurs with respect to these. As a result
of this relative movement, the packer assembly 200 is moved to its set position.
As the upward movement of the shaft 142 continues, shear pins 184 are sheared
allowing the guide bushing 182 to separate from the packer mandrel 216 and move
upwardly with respect to it. The guide bushing 182 can then be drawn toward and
ultimately into the adapter sleeve 166. At this point, the locator and setting tool 70 is
released from the packer assembly 200 and can be withdrawn from the casing string 50
while leaving the packer assembly 200 set within the casing string 50.
Following the setting operation, the clutch function described previously will cause
the linear type drive action of the setting section 74 to cease by permitting free rotation
of the threaded shaft 142 rather than forced linear movement. The clutch arrangement
-- ~17û711
thereby serves to define the length of the setting stroke provided by the setting section
74. If, for example, a linear displacement of the threaded shaft 142 (and affixed
components) of 8 inches is needed to set the packer assembly 200 and to cause full
disengagement of the locator and setting tool 70 from the packer assembly 200, the
setting stroke may be defined by the clutch arrangement to be just greater than that
amount (i.e. 8.25 inches).
In operation, the locator and setting tool 70 is used to first locate and then to set
a packer assembly 200 within the wellbore 56. The locations of desired setting points
for packers are typically supplied prior to packer setting and are expressed in terms of a
depth below the surface. The running arrangement should be physically measured, either
prior to or during the running operation, so that the packer assembly 200 will be placed
proximate the planned desired setting point. Prior to running the tool 70 and affixed
packer assembly 200, it is preferred that a measurement be taken to determine the
distance between a reference point "X" at a central portion of the casing collar locator
section 72 (See FIG. 2A for illustrative position) and a reference point "Y" at a central
portion of the sealing elements 212. This should provide an approximate "offset
distance" by which the position of the tool 70 and affixed packer assembly 200 should
be adjusted upward within the wellbore 56 prior to setting the packer assembly 200.
Once a planned desired setting point has been provided, the locator and setting tool
70 and packer assembly 200 are disposed within the wellbore 56 on wireline 68 at least
to the depth of the desired setting point using the running arrangement physical
217~711
measurement. Preferably, the packer setting tool 70is lowered several hundred feet
below the planned desired setting point.
Next, the tool 70is slowly raised within the wellbore 56. The casing collar locator
section 72 will detect the actual location of casing joints such as 62 as the casing collar
locator section 72 passes the joint. Readings from the casing collar locator section are
transmitted to the surface. These readings are recorded on a log and compared to the
depths of casing collars recorded in the well's casing collar locator log and/or other
previous logs or records which detail the collar locations in order to reconcile the two sets
of data. If no meaningful discrepancies between the two sets of data exist, the tool 70
and packer assembly 200 may be disposed to the planned desired setting point and then
set within the wellbore.
If, during the comparison, any discrepancies between the two sets of data are
noted. The process may be repeated to verify that the readings from the casing collar
locator section 72. If discrepancies continue to exist, the packer assembly 200 should
not be set, and the customer should be notified to obtain instructions as to how to
proceed. The customer should be informed that the depth of the packer assembly as
determined by physical measurement could not be reconciled with the recorded depths
of casing collars and that setting the packer assembly at the planned desired setting point
may result in the packer assembly's sealing elements 212 being set against a casing joint.
It is suggested that in most cases, the planned setting point could be adjusted by a small
distance to reconcile it with the detected locations of casing collars.
217071i
If and when it has been determined to set the packer assembly 200 at the adjusted
planned setting point, the locator and setting tool 70 and packer assembly 200 is then
lowered to the adjusted setting point and then raised the "offset distance" measured
previously and the packer assembly 200 set. Once this has been, the packer assembly
200 should be in position to be set at the approximate location of the desired setting
point.
It is noted that setting of the packer assembly 200 by means of the setting section
74 will result in controlled, even and centralized setting of the slips and sealing elements
212 against the walls of the wellbore 56. This affords an advantage over those prior art
systems which employ explosive charges to set packer assemblies. Use of explosive
charges can cause these elements to deform during setting or become set off-center or
skewed in the wellbore.
The tool 70 is further preferably designed to permit an extended duration setting
sequence for the packer assembly 200. In most instances and constructions, the setting
sequence requires more than one minute of setting time to move portions of the packer
assembly 200 from an unset condition to a set condition in the wellbore. Optimally,
setting times of greater than five minutes are obtained.
It is further noted, although not described in any detail here, that the emplaced
packer assembly 200 may have a tubing string (not shown) subsequently latched into it
for use in production of hydrocarbons from a zone below the packer. The tubing string
may be removed and the packer assembly retrieved by a number of methods. Among
2170~1
these are the use of an Otis VRT Retrieving Tool commercially available from Halliburton
Energy Services, 2601 Beltline Road, Carrollton, Texas 75006, (214) 418-3000. This
type of removal involves engaging a portion of the packer assembly's guide tube 202 and
jarring upward to remove the packer assembly.
The setting section 74 may be thought of as providing a working assembly which
is engageable with portions of the packer assembly 200 to set it. The working assembly
of the setting section 74 may further be thought of as having inner components, including
the threaded shaft 142 with its lower extension 148, which are radially surrounded by
outer components, including sleeve 166, which are each engageable with a portion of a
barrier member to be set within a string of tubular members. When so engaged, the inner
and outer components are axially moveable in opposite axial directions relative to each
other to set the barrier member. Although in the preferred embodiment described herein
the inner components are moved in a downward axial direction with respect to the outer
components to accomplish setting of the packer assembly 200, it should be understood
that constructions would be possible wherein a barrier member would be set when the
inner components are moved axially upward with respect to the outer components.
Additionally, it should be pointed out that the setting section described with respect
to the present invention may be configured to engage and unset particular barrier
members as well as set them. One example is the wireline-retrievable "Monolock" tubing
string lock available from Halliburton Energy Services.
2170711
24
It will, therefore, be readily understood by those persons skilled in the art that the
present invention is susceptible of a broad utility and application. Many embodiments and
adaptations of the present invention other than those herein described, as well as many
variations, modifications, and equivalent arrangements will be apparent from or reasonably
suggested by the present invention and the foregoing description thereof, without
departing from the substance or scope of the present invention. For example, the locator
and setting tool 70 may be disposed into a wellbore using tubing conveyance rather than
wireline disposal. Alternatively, the variations of the apparatus described herein may be
used for location and setting of other types of barrier members, such as nippleless locks,
within other types of strings of tubular members. Accordingly, while the present
invention has been described herein in detail in relation to its preferred embodiments, it
is to be understood that this disclosure is only illustrative and exemplary of the present
invention and is made merely for purposes of providing a full and enabling disclosure of
the invention. The foregoing disclosure is not intended or to be construed to limit the
present invention or otherwise to exclude any such embodiments, adaptations, variations,
modifications and equivalent arrangements, the present invention being limited only by the
claims appended hereto and the equivalents thereof.
