U.S. patent application number 10/937649 was filed with the patent office on 2006-03-09 for perforation method and apparatus.
Invention is credited to David O. Johnson, C. Jason Pinto, Stephen R. Thompson.
Application Number | 20060048937 10/937649 |
Document ID | / |
Family ID | 35995045 |
Filed Date | 2006-03-09 |
United States Patent
Application |
20060048937 |
Kind Code |
A1 |
Pinto; C. Jason ; et
al. |
March 9, 2006 |
Perforation method and apparatus
Abstract
A signature element is attached to a downhole cable or other
protected equipment and the signal from a signature position
detector is used, at least in part, to control the orientation of a
directed perforating device or other directional device. Signal
emitting sources can include a radioactive material added to an
encapsulating composition of a downhole cable.
Inventors: |
Pinto; C. Jason; (Sandy,
UT) ; Thompson; Stephen R.; (Bakersfield, CA)
; Johnson; David O.; (Spring, TX) |
Correspondence
Address: |
KONNEKER & SMITH P. C.
660 NORTH CENTRAL EXPRESSWAY
SUITE 230
PLANO
TX
75074
US
|
Family ID: |
35995045 |
Appl. No.: |
10/937649 |
Filed: |
September 9, 2004 |
Current U.S.
Class: |
166/255.2 ;
166/297; 166/55.1; 166/66 |
Current CPC
Class: |
E21B 47/024 20130101;
E21B 43/119 20130101 |
Class at
Publication: |
166/255.2 ;
166/297; 166/066; 166/055.1 |
International
Class: |
E21B 43/117 20060101
E21B043/117; E21B 47/09 20060101 E21B047/09 |
Claims
1-19. (canceled)
20. An apparatus for orienting a perforating device away from a
cable in a well, the apparatus comprising: (a) a radioactive
signature element located at a known position relative to the
cable; (b) a radiation detector for detecting the orientation of
the signature element with respect to the perforating device; and
(c) means for reorienting the perforating device away from the
cable.
21. The apparatus of claim 20 wherein said means for reorienting
comprises a rotator for rotating the perforating device about a
longitudinal axis of the well.
22. The apparatus of claim 20 wherein the radiation detector
comprises a movable aperture which rotates relative to a
longitudinal axis of the well.
23. The apparatus of claim 20 wherein the signature element
comprises an irradiated wire.
24. The apparatus of claim 23 wherein the irradiated wire comprises
an irradiated cobalt 60 alloy wire and the radiation detector
comprises a gamma ray detector.
25. The apparatus of claim 23 wherein the cable comprises a coaxial
cable for transmitting signals from a transducer.
26. The apparatus of claim 20 wherein the signature element
comprises a radioactive tracer fluid in a capillary tube.
27. An apparatus for orienting a perforating device away from a
cable in a well, the apparatus comprising: (a) an irradiated wire
producing gamma rays, the wire being located at a known position
relative to the cable; (b) a gamma ray detector for detecting the
orientation of the irradiated wire with respect to the perforating
device; and (c) means for reorienting the perforating device away
from the cable.
28. The apparatus of claim 27 wherein the irradiated wire comprises
an irradiated alloy wire.
29. The apparatus of claim 27 wherein the irradiated alloy wire is
contained in a protective stainless steel tube.
30. The apparatus of claim 27 wherein the irradiated wire is
compounded with an encapsulating sheath of the cable.
31. The apparatus of claim 27 wherein the irradiated wire comprises
an irradiated cobalt 60 alloy wire.
32. The apparatus of claim 31 wherein the cable comprises a fiber
optic cable.
33. The apparatus of claim 32 wherein the irradiated cobalt 60
alloy wire is separate from the fiber optic cable.
34. The apparatus of claim 31 wherein the gamma ray detector
comprises a movable aperture which rotates relative to a
longitudinal axis of the well.
35. The apparatus of claim 27 wherein the perforating device is
supported by a support structure located substantially above a
ground surface.
36. The apparatus of claim 35 wherein the support structure is a
well workover rig.
37. The apparatus of claim 27 wherein the perforating device
comprises a directed perforating tool having unequally spaced
cartridges.
38. The apparatus of claim 27 wherein movement of at least a
portion of the gamma ray detector also moves at least a portion of
the means for reorienting the perforating device.
39. A method of orienting a perforating device away from a cable in
a well, the method comprising the steps of: positioning a
radioactive signature element in a known position relative to the
cable; detecting the signature element with a radiation detector;
and orienting the perforating device away from the cable in
response to the detecting step.
40. The method of claim 39, wherein the positioning step further
comprises separating the signature element from the cable in the
well.
41. The method of claim 39, wherein the positioning step further
comprises incorporating the signature element in the cable, and
wherein the orienting step further comprises orienting the
perforating device away from the signature element.
42. The method of claim 41, wherein the incorporating step further
comprises providing the signature element as an irradiated
wire.
43. The method of claim 42, wherein the providing step further
comprises forming the irradiated wire from a cobalt alloy
material.
44. The method of claim 43, wherein the cobalt alloy material is
cobalt 60.
45. The method of claim 42, further comprising the step of
conducting electricity through the irradiated wire.
46. The method of claim 39, wherein the positioning step further
comprises incorporating the signature element in an encapsulating
material of the cable.
47. The method of claim 39, wherein the positioning step further
comprises incorporating the signature element in a wire of the
cable.
48. The method of claim 47, further comprising the step of
positioning the wire in a tubing string of the cable.
49. The method of claim 39, wherein the positioning step further
comprises incorporating the signature element in a shielding
component of the cable.
50. The method of claim 39, wherein the positioning step further
comprises incorporating the signature element in a grounded
component of the cable.
51. The method of claim 39, wherein the positioning step further
comprises positioning the signature element in a tubing string of
the cable.
52. The method of claim 51, wherein the signature element is a
radioactive tracer fluid.
53. The method of claim 52, wherein the positioning step further
comprises positioning the tracer fluid in a tubing string of the
cable.
54. The method of claim 39, further comprising the step of
positioning the detector in a tubing string with the cable.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a national stage filing under Chapter II
of the Patent Cooperation Treaty of International Application No.
PCT/US03/09156, filed Mar. 24, 2003, which claims priority to U.S.
Provisional Application No. 60/368,032 filed Mar. 27, 2002. The
entire disclosures of these prior applications are incorporated
herein by this reference.
BACKGROUND
[0002] This invention in part, relates to well drilling and
completion devices and processes. More specifically, the invention,
in part, is concerned with providing devices and methods that
improve the ability to azimuthally orient perforating devices away
from downhole cables within a perforating zone.
[0003] Conventional wells and well completions typically provide
little or no downhole instrumentation and/or fluid control
capability. Some conventional well completion procedures are
relatively simple, essentially running production or injection
tubing into the well along with perforating, gravel packing, and/or
logging steps as needed. Pressure and flow control in conventional
oil, gas or other fluid-producing wells typically use valves and
instruments located at or near the surface in a Christmas tree
arrangement. Formation fluids are typically produced until a
downhole problem occurs, e.g., reservoir pressure declines or the
water-cut increases or something else happens downhole that
significantly reduces production or prevents the well from further
commercial operation.
[0004] To evaluate the cause of production or injection problems in
a conventional well, the well is typically taken off-line and one
or more logging tools supported by a wireline are run through the
tubing within the well. The logging tools may be used to check
downhole fluid pressures, fluid types, zonal flowrates or other
parameters at one or more depths to try to determine the cause of
the production or injection decline and the corrective action
needed. Once the problem is determined and/or new production or
injection zones identified, the wireline tools are typically
removed and a second re-entry into the off-line well is
accomplished to correct the problem, e.g., using a workover rig.
For example, a second re-entry might lower a perforating tool to
re-perforate/re-complete the well at a new producing level. These
conventional well completions, re-entries, and re-completions may
consume unacceptable lost production time and costs, especially
when applied to deepwater, multi-producing zone, high temperature,
and/or high-pressure reservoirs and wells.
[0005] In contrast to conventional wells and well systems, the term
"intelligent" and "smart" wells and well systems may refer to wells
having downhole process control, instrumentation, and/or related
components. Other terms used for intelligent or smart well systems
include SCRAMS (Surface Controlled Analysis and Management System),
IRIS (Intelligent Remote Implementation System), and RMC (Reservoir
Monitoring & Control).
[0006] But no matter what these well systems are called, they
enable real-time downhole operation, surveillance, data
interpretation, intervention, and/or process control in a
continuous feedback loop. The smart wells allow problems to be
detected and possibly minimized or corrected without taking the
well off-line. Smart well systems can therefore operate for long
periods without the need to shut down and introduce instrumentation
or additional wireline tools. However, the introduction of
perforating tools is still typically required during the less
frequent workover processes.
[0007] A smart well system typically uses downhole tubing, cables
or other means for transmitting power, real-time data or control
signals to or from surface equipment and downhole devices such as
transducers and control valves. Power and signals typically use
transmission means such as electric and/or fiber optic cables, but
other transmission devices can include fluid tubing.
[0008] Other well applications may also have cables or other
transmission means present during operations that may include
perforating. Other well processes and applications that may require
downhole transmission means include wells having a submersible
electric pump, measurement while drilling (MWD) methods, and the
use of downhole directional & inclination indicators, hydraulic
actuators, and power supplies, e.g., for data transmission using
mud pulse telemetry.
[0009] Perforating or re-perforating a well having a downhole cable
or other transmission device must avoid damaging the transmission
device during the perforating process, typically requiring a step
of azimuthally orienting a directional-perforating device. The
orienting step directs the perforating action away from nearby
cables or other devices in the well. Orientating methods may
include magnetic oriented techniques (MOT), obtaining positional
data from downhole probes, using gravity-actuated orienting devices
for non-vertical boreholes, limiting operations to within guided
downhole paths, obtaining orienting data from gyroscopes, and using
mechanical indicators or orientation subs.
[0010] However, the orienting step can add significant cost and/or
present feasibility problems, especially when high temperature,
corrosive fluids, high pressures, multiple completion zones, or
other difficult downhole conditions are encountered. The added
costs and problems can also be compounded by the added time to
accomplish the orienting step for deep offshore wells. For example,
application of current MOT techniques may be limited by high
downhole temperatures and since typical well depths have been
increasing, increasing downhole temperature problems for MOT
processes may be encountered.
SUMMARY
[0011] In one embodiment, the invention adds a position signaling
or a detectable signature element to a cable or other equipment to
be protected and a signal or signature position detector that, at
least in part, controls the orientation of a directed perforating
device. The detection of the position signal or signature allows
the perforating device to be oriented in a desired azimuthal
position that avoids damaging the cable. Signal emitting sources
can include a radioactive material added to an encapsulating
composition of a downhole cable or an irradiated Cobalt alloy wire
along with electric wires in the cable. Various types of signal
detectors can be used, e.g., a Geiger, Mueller, or scintillation
counter, combined with a moveable apertured shield or another
directional device, e.g., a Rotascan and/or Tracerscan model
manufactured by Halliburton and available in Houston, Tex. or a
POT-C manufactured by Schlumberger and available in Houston, Tex.
The position signal detector assembly is preferably connected to a
scallop, strip gun, or other conventional directed perforating tool
(e.g., a Model OP perforating tool supplied by Halliburton) in such
a way that perforations are directed away from the detected cable
or cable assembly. Connecting the directed perforating tool and the
signal detector allows a reliable perforation and re-perforation of
the well without re-entry and without damage to the cable or other
downhole equipment not intended to be perforated.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 shows a side cross-sectional view of an embodiment of
an inventive assembly within an underground wellbore;
[0013] FIG. 2 shows a process flow diagram of an inventive method
using the assembly shown in FIG. 1;
[0014] FIG. 3 shows a side schematic view of another embodiment of
an inventive assembly within an underground wellbore;
[0015] FIG. 4 shows a cross-sectional view taken at 4-4 as shown in
FIG. 3; and
[0016] FIG. 5 shows a schematic side view of one embodiment of a
perforating and detecting tool.
[0017] In these Figures, it is to be understood that like reference
numerals refer to like elements or features.
DETAILED DESCRIPTION
[0018] FIG. 1 shows a side cross-sectional view of a wellbore 3
having an inventive position emitter or signature device included
with cable 7 or other device to be protected from being perforated
and a perforating & position-detecting tool assembly 2. The
wellbore 3 extends through overburden OB and penetrates a formation
of interest F to be perforated. In the embodiment of the invention
shown, the tool assembly 2 is suspended within the wellbore 3 on a
slickline or wireline WL and supported by a drilling rig, well
workover equipment, or other support structure SS. Installed within
a portion of the wellbore 3 is a casing string or other well
tubular 4 extending generally downward from at or near a ground
surface G, but not necessarily extending the entire length of the
wellbore to the well bottom 5.
[0019] In the embodiment shown, a downhole pressure transducer or
other downhole signal-handling device 6 is located below the tool
assembly 2 at or near the well bottom 5. The pressure transducer 6
produces an electrical signal representative of downhole fluid
pressure. The pressure-representing electrical signals are
transmitted through a cable 7 (e.g., a coaxial cable, conduit, or
other transmitting means) that extends within an annular space 8
(typically filled with fluid) past the tool assembly 2 to a data
recorder 9 or other upper signal-handling means located above the
tool assembly, e.g., at or near the ground surface G. In other
embodiments, the lower or downhole signal handling device 6 may be
replaced or supplemented by other signal, fluid, or power consuming
devices, e.g., a submersible pump, or other signal handling means
such as a well logging tool, a distributed temperature sensor (DTS)
system, a localized temperature sensor, an inflow control valve
(ICV), a fluid density sensor, a two or three-phase flow meter, a
fiber optic viewer, or other well downhole tools, instrumentation,
and control devices. The cable 7 is preferably a coaxial cable
assembly, but other transmission means may be used to replace or
supplement the coaxial cable.
[0020] Although FIG. 1 shows the transducer 6 located at or near
the well bottom 5, alternative downhole devices connected to
transmission means may be located elsewhere at or below the tool
assembly 2. The alternative devices may be connected to the well
tubular 4, supported by a wireline, imbedded into one or more
formations, or otherwise located and supported within or near the
wellbore 3.
[0021] In other alternative embodiments, the cable 7 may be passed
through the tool assembly 2, coiled or otherwise located under
surface G rather than running alongside the tool 2 as shown. The
cable 7 may also be supplemented or replaced with other devices to
be protected from the perforating charges, e.g., instrumentation,
tubing, fiber optic cables, ducted passageways, or other means for
transmitting electric current, electromagnetic pulses, fluid
flow/pressure, or other signal media. In still other alternative
embodiments, the upper signal-handling means 9 may be remotely
located from the well and it may also be supplemented or replaced
by a power supply, controller, data processors, fluid processors,
or other transmission processing devices.
[0022] In one embodiment, a signature element or signal emitter is
added to the cable 7 to form a detectable cable assembly 7a that
extends across formation thickness T, preferably a radioactive
gamma-ray emitter is added to the cable. The radioactive emitting
portion of cable assembly 7a preferably produces at least about
0.01 microcuries/foot (0.01 microcuries per 0.30 meters), more
preferably at least about 0.1 microcuries/foot (0.1 microcuries per
0.30 meters) as a position signal. In one embodiment, the
radioactive emitter can take the form of an irradiated cobalt-alloy
wire running parallel to a copper or other electrically conductive
wire within a protective stainless steel and/or encapsulating
plastic sheath of cable 7. Examples of an encapsulating plastic
material include Halar, Hylar and Santoprene. In another
embodiment, the signal emitter component of cable assembly 7a may
take the form of a radioactive material compounded with or added to
the encapsulating plastic instead of a separate irradiated wire. In
still other embodiments, the radioactive emitter component of the
cable assembly 7a can take the form of a series of separated
radioactive sources along a portion of the length of the cable 7,
an irradiated electrically-conductive wire (avoiding the need for a
separate emitting wire), radioactive materials compounded with an
electrically conductive wire, radioactive materials compounded with
shielding or grounded components of the cable, or an irradiated
protective sheath.
[0023] The selection of radioactive materials depends on the length
of time a position signal is needed, the sensitivity of the
directional detector, and limits imposed by safe handling
procedures. Preferred radioactive materials have a half-life at
least comparable to the length of time a position signal is needed.
For example, if a single perforating process is expected to be
accomplished within about a month after irradiation, an irradiated
cobalt 60 alloy may be used.
[0024] In still other embodiments, a signature element or another
position-signal emission source may be added to the cable 7 in
place of a gamma-ray emitting material. Added signature elements
can include high density materials such as lead (e.g., detectable
by directional gravity sensors in tool assembly 2), magnetic
materials (detectable by directional EMF sensors), color coating
(e.g., detectable by downhole video cameras), electrically
conductive or insulating materials (e.g., detectable by directional
logging tools), and cable protuberances, e.g., detectable by
feelers or other downhole contacting devices. Still other emission
sources can include beta ray emitters, impressing an alternating
carrier current or other electromagnetic signal-generating
potential in the conductive wire portion of cable 7 (e.g.,
detectable by a directional EMF sensor in the tool assembly 2),
other electromagnetic emitters and detectors, fluid
pressure/pulsing sources or other acoustic/pressure wave signal
emitters in cable 7 (e.g., detectable by a directional seismic or
other acoustic sensor in assembly 2), and a heat or light emitter
in cable 7, e.g., detectable by a directional infrared detector in
tool assembly 2.
[0025] The perforating and detecting tool assembly 2 shown in FIG.
1 consists primarily of a perforating subassembly or means for
directionally perforating 10, a partially shielded radioactive or
other directional signal or signature detecting means 11, and a
motor support member 12 or other means for supporting and orienting
the assembly. Other components may include a centralizer, rotation
actuator, casing collar locator, shock sub, phased perforation
charges, radiation shield, and instrumentation to determine
inclination.
[0026] When the perforating charges PC in the perforating
subassembly 10 are actuated in an oriented position, a portion of
the casing 4 and the formation of interest F are penetrated,
typically using one or more explosive perforating cartridges and/or
projectiles PC. As shown, the perforating charges PC are not
equally spaced around the circumference of the tool assembly 2, but
are concentrated in a direction opposite to the location of devices
to be protected such as cable 7. By orienting the perforating
charges PC in conjunction with and opposite to the orientation of
the position sensor 11 when detecting the cable emitter or
signature element (also see FIGS. 3 & 4), the perforating
charges PC are directed away from the cable 7 and will avoid
damaging the cable. A variety of perforating charges PC can be used
as long as they are not omnidirectional. Other means for directed
perforating could include shaped charges, explosive bolts, and
rupturing pressurized fluid containers that are partially
contained.
[0027] In the embodiments shown in FIGS. 1, 3, & 4, the
directional gamma-ray detector or transmitter position sensor 11 is
part of the detecting and perforating tool assembly 2 and is
attached to and rotated with the perforating subassembly 10. This
tying together of opposite orientations of the detector and
perforating means may avoid the need for separate detecting and
orienting steps. In other embodiments, an alternative position
sensor 11 may be spaced apart from the perforating subassembly 10,
supported separately from the perforating subassembly, combined
with the perforating subassembly but not rotated or oriented in
conjunction with the perforating subassembly, e.g., used as part of
a two step program whereby the first run would be for cable
detection and/or formation mapping purposes and a second run would
be for orientation and perforation.
[0028] The process of using the detecting and perforating tool
assembly 2 illustrated in FIG. 1 is shown in FIG. 2. The initial
placing step 1s runs a cable assembly 7a (including a
cable-position signal emitter or other position-detectable element)
into a well. The initial placing step 1s positions a portion of the
cable assembly 7a with the detectable element proximate to at least
a portion of a formation of interest as shown in FIG. 1. After the
cable assembly 7a is placed in the well, FIG. 2 shows a second
placing step 2S places a position detecting and a well perforating
means in the well. The position detecting means is capable of
detecting the azimuthal orientation of the signature element or
position-signal emitter (and the associated transmitting means)
within the wellbore. In an orienting step 3S, the perforating means
is oriented substantially away from the signal transmitting means
based at least in part on the detected signal or signature
orientation produced by the detecting means with the detector
detecting the orientation of the signature element or
position-signal emitter. After the orienting step 3S and in the
absence of removing the detector or another running step, the
perforating means is actuated in a perforating step 4S to penetrate
the casing and/or formation of interest followed by a fluid
production step 5S. In an alternative procedure if cables or other
devices are dangerously close to the portion of the formation to be
perforated, the position-signal detector and perforating tool is
run into the well twice, with the first run orienting and mapping
locations followed by a second run relocating endangered cables or
other devices and actuating the perforating means in the desired
azimuthal orientation.
[0029] In another alternative process, use of a downhole gamma ray
detecting device is combined with a process step for detecting
radioactive tracers injected into the formation. In this added
process step, a radioactive tracer fluid is injected into various
formations of interest and the downhole radiation detector is used
to monitor the changes in radioactivity proximate to the formations
of interest prior to the step 4S of actuating the perforator. The
monitored changes in radioactivity are correlated to tracer fluid
motions and are used, at least in part, to determine which
formations of interest to perforate as well as the optimum
orientation of the perforations.
[0030] In still another alternative process embodiment, a downhole
radioactive detector is used after the perforating step 4S to help
determine the portion of an injection fluid (such as water in a
water flood production process) flowing into the formation of
interest. A radioactive tracer is added to an injection fluid that
is injected into the formation of interest. Upon later injecting
and/or producing fluid from this well or other wells with
detectors, the radioactive detector can be used to help determine
the fluid flow patterns within the formation.
[0031] FIG. 3 shows a side view of another embodiment of the
inventive tool assembly 2a within an underground wellbore 3a. The
tool assembly is run into a 7-inch (18 cm) nominal diameter casing
4a that extends downward from a wellhead WH within the wellbore 3a.
In alternative embodiments, a casing and/or liner 4a can extend
from at or near the ground surface G to the well bottom 5a.
[0032] As shown in FIGS. 3 and 4, a tubing assembly 13 (including
tubing string 15) is run into the casing 4a and wellbore 3a
supporting a perforating and detector tool assembly 2a. The
multiple horizontal arrows shown in FIG. 3 penetrating the
formation of interest F from the tool assembly 2a illustrate the
directed orientation of the non-uniform perforating action with the
wellbore 3a. The tubing assembly 13 is run into the wellbore 3a
until it passes the formation of interest F to a desired depth, or
until a fluid control device 14 attached to the tubing assembly 13
is located proximate to the well bottom 5a. In this embodiment, the
tubing assembly 13 includes an encapsulated control line 16
attached to a 27/8 inch (7.3 cm) nominal diameter tubing string 15.
The control line 16 is generally attached to the exterior of the
tubing string 15, but in alternative embodiments, the control line
may be unattached or may be attached to the interior of the tubing
string.
[0033] The power cable or control line 16 includes an irradiated
cobalt alloy wire producing gamma rays extending over at least a
portion of the control line and producing at least about 0.01
microcuries per foot (0.01 microcuries per 0.30 meters), preferably
at least about 0.1 microcuries per foot (0.1 microcuries per 0.30
meters) or more. The irradiated portion of the wire in the power
cable 16 typically extends over a distance of at least a few
inches, more typically several feet or meters. Longer irradiated
wire sections and/or more sensitive detectors may allow the use of
irradiated wire in power cable 16 producing less radiation per foot
in alternative embodiments. In other alternative embodiments, using
a short half life radioactive material, short wire sections and/or
less sensitive detectors may require an irradiated wire producing
significantly more than 0.1 microcuries per foot (0.1 microcuries
per 0.30 meters), such as at least about 1 microcurie per foot (1
microcurie per 0.30 meters).
[0034] In the embodiment shown, a string of tubing sections 15
extends from the ground surface G to at or near the well bottom 5a
within wellbore 3a. In other embodiments, several different
diameters of tubing and/or casing sections may be used to comprise
the casing and tubing strings 4a & 15, the casing string may
terminate prior to the well bottom 5a, the tubing string may be
cemented in place, and one or more tubing strings may be used.
[0035] FIG. 4 is a cross-sectional view of the embodiment shown in
FIG. 3 at section 4-4. In this embodiment, the tubing string 15 is
composed of N-80 steel sections having a nominal outside diameter
of 27/8 inches (7.3 cm) and a wall thickness of about 0.31 inches
or 0.79 cm. Fluid typically occupies the fluid gap FG between the
interior of tubing string 15 and the tool assembly 2a, nominally
about a 1/2 inch (1.3 cm) concentric fluid gap in this embodiment.
In order to maintain this fluid gap FG, spring-loaded fingers,
centralizers, standoffs, or other positioning means may be used to
generally locate the tool assembly 2a in the center of the wellbore
3a.
[0036] The tool assembly 2a comprises a gamma ray detector 17
within a rotatable shield 18 having an aperture or opening OP,
preferably an opening measuring at least about 1/4 inch or 0.63 cm,
more preferably at least about 1/2 inch or 1.3 cm. The rotatable
shield 18 is preferably composed of a tungsten alloy, but other
radioactive shielding materials may be used. By rotating the
apertured shield 18 with opening OP, the orientation of a gamma ray
source 19 within the power cable 16 can be determined by the
detector 17 since little or no signal will be generated by the
detector unless the opening OP of the shield 18 is positioned
between the source 19 and the detector.
[0037] In the embodiment shown in FIG. 4, the irradiating portion
of the power cable 16 comprises a cobalt alloy source 19, an
encapsulating material 20, and three capillary tubing strings 21.
The attachment of the power cable 16 to the tubing string 15, e.g.,
by strapping, can provide an offset of about 0.6 inches (1.5 cm)
from the OD of the tubing string 15 to the irradiated alloy wire
19. Alternatively, the irradiated wire may be proximate to the
tubing string 15. The preferred irradiated cobalt 60 wire produces
about 3-4 microcuries for a nominal 20-foot (6 meter) section of
wire, but a similar length of cobalt alloy wire producing about 1-2
microcuries may also be used in some applications. In an
alternative embodiment instead of an irradiated wire 19, one or
more capillary tubing strings 21 may be filled with a detectable
fluid, such as a fluid having a radioactive tracer that can be
detected by an orientation sensor.
[0038] The encapsulating material 20 of the power cable 16
preferably comprises a non-electrically conductive plastic to form
an insulating barrier. The encapsulating material 20 also cushions
and protects the interior components of the power cable 16 from
some environmental hazards. The encapsulating material 20 forms the
exterior portion of the power cable 16 having a maximum diameter of
about 0.75 inches (1.9 cm) for this embodiment.
[0039] Each of the three capillary tubing strings 21 has a diameter
of approximately 1/4 inch (0.6 cm) with a nominal 0.035 inch (0.089
cm) wall thickness in this embodiment, however, other diameters and
wall thicknesses may be used. The wire 19 and capillary tubing
strings 21 are typically twisted within the power cable 16 about
one turn for every 20 feet (6 meters) of the cable. Alternative
embodiments may use other cable or tubing attachment means,
multiple wires (with one or more wires being a source of radiation
or other orienting signals), more or less twisting per unit length,
and more or less capillary tubing strings within the encapsulated
assembly.
[0040] FIG. 5 shows a schematic side view diagram of the detecting
and perforating tool assembly 2a shown in FIGS. 4 & 5. A
slickline or wireline 22 supports the tool assembly 2a, preferably
allowing the tool assembly to be run into a wellbore 3a (see FIG.
3) and a portion to rotate within the wellbore. Attached to the
slickline 22 is a hold down/centralizer 23 or other means for
securing and generally positioning the tool assembly 2a near the
center of the wellbore 3a (see FIG. 3). Attached to the hold
down/centralizer 23 is a motor section 24 that rotates the attached
focusing and position-signal emission detector 25. The emission
detector 25 is directionally adjustable to detect gamma ray
radiation from a position-signal emitter and power cable 16 (see
FIG. 3) indicating the azimuthal orientation of a downhole cable
with reference to the orientation of the perforating means 26,
preferably by means of an apertured shield connected to a rotatable
perforating means 26, both of which are rotated by the motor
section 24. In a similar embodiment, the directional radiation
detector portion of the assembly may be as described in SPE paper
number 38589, "Enhancing Frac-Pack Evaluations with Directional and
Spectral Gamma Ray Measurements."
[0041] The perforating gun or other perforating means 26 is
preferably attached to the rotatable portion of the oriented
radiation detector 25. Preferably, the directional explosions from
some or all of the perforating charges in the perforating gun 26
are oriented away from the focused or apertured direction in the
gamma detector 25 that indicates the direction of the power cable
shown in FIG. 3. This allows the perforating gun 26 to be
automatically positioned at the desired azimuthal orientation when
the radiation detector 25 detects the maximum signal strength
emanating from the gamma ray emitter and power cable 16 shown in
FIG. 3.
[0042] Further advantages of the orienting invention include
improved perforating safety and reliability by assuring proper
azimuthal orientation, reduced cost for multiple perforations by
avoiding multiple entries (e.g., directionally discharging only a
portion of the perforating charges at one location and
directionally discharging another portion at a second location),
and allowing multiple perforations in one wellbore having different
azimuthal directions. When combined with other process steps
especially for smart well completions, other advantages of the
improved orienting invention include limiting the cost and time
required for combined process steps and improved reliability of
smart well control devices.
[0043] Still other alternative embodiments are possible. These
include using multiple differently oriented perforating guns
connected to a radioactive detector, means for reorienting a cable
or other signal transmitting means such as circumferentially
repositionable mechanical hooks extending from a tool supported
within the wellbore, combining perforation and drilling and/or
whipstock tools with a radioactive or other cable detecting means,
replacing the perforating means with other formation penetrating
means, using a controllable radioactive emitter in conjunction with
a radioactive detector and tool assembly to calibrate the
radioactive detector, and placing a radioactive detector within a
thermal blanket or other environmentally protective enclosure.
[0044] This application discloses a signature element, which is
attached to a downhole cable or other protected equipment; and the
signal from a signature position detector is used, at least in
part, to control the orientation of a directed perforating device
or other directional device. Signal emitting sources can include a
radioactive material added to an encapsulating composition of a
downhole cable.
[0045] The Applicant reserves the right to claim or disclaim now or
in the future any feature, combination of features, or
subcombination of features that is disclosed herein.
[0046] All of the numerical and quantitative measurements set forth
in this application (including in the description, claims,
abstract, drawings, and any appendices) are approximations.
[0047] The invention illustratively disclosed or claimed herein
suitably may be practiced in the absence of any element which is
not specifically disclosed or claimed herein. Thus, the invention
may comprise, consist of, or consist essentially of the elements
disclosed or claimed herein.
[0048] The following claims are entitled to the broadest possible
scope consistent with this application. The claims shall not
necessarily be limited to the preferred embodiments or to the
embodiments shown in the examples.
[0049] Although the preferred embodiment of the invention has been
shown and described, and some alternative embodiments also shown
and/or described, changes and modifications may be made thereto
without departing from the invention. Accordingly, it is intended
to embrace within the invention all such changes, modifications,
and alternative embodiments as fall within the spirit and scope of
the appended claims.
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