US20060042792A1

US20060042792A1 - Methods and apparatus for locating a lateral wellbore

Info

Publication number: US20060042792A1
Application number: US10/924,673
Authority: US
Inventors: Michael Connell
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2004-08-24
Filing date: 2004-08-24
Publication date: 2006-03-02

Abstract

The present invention relates generally to lateral wellbore operations, and more particularly, to downhole tools that include a logging tool for locating a lateral wellbore and associated methods. In some embodiments, the present invention discloses a method for use in lateral wellbore operations that includes entering a lateral wellbore from a primary wellbore with a tool comprising a logging tool, and verifying entry into the lateral wellbore using the logging tool. In yet other embodiments, the present invention discloses methods of locating lateral wellbores from a primary wellbore, and downhole tools that comprise logging tools, such as casing collar locators, radiation detection logging tools, or combinations thereof.

Description

BACKGROUND

The present invention relates generally to lateral wellbore operations, and more particularly, to downhole tools that include a logging tool for locating a lateral wellbore and associated methods.
Operators seeking to produce hydrocarbons from subterranean formations often employ multilateral wells. Unlike conventional vertical wells, multilateral wells include a primary wellbore and a series of lateral wellbores that branch from the primary wellbore. The primary wellbore may be a generally horizontal, generally vertical, or otherwise formed portion of a wellbore. Although multilateral wells are often more expensive to drill and complete than conventional wells, multilateral wells are generally more cost-effective overall, as they usually have greater production capacity and higher recoverable reserves. Because fewer multilateral wells than conventional wells are needed to recover the same amount of hydrocarbons, overall drilling and capital expenses may be reduced. In addition to being cost-effective, multilateral wells are also an attractive choice in situations where it is necessary or desirable to reduce the amount of surface drilling operations, such as when environmental regulations impose drilling restrictions.
Although multilateral wells may offer advantages over conventional wells, they may also involve greater complexity, which may pose additional challenges. One such challenge involves the location and entry of specific laterals that branch from the primary wellbore. For example, working over a lateral wellbore may be complicated by problems associated with locating and entering the lateral wellbore. A number of techniques have been developed for locating and entering the laterals so that lateral wellbore operations may be performed. As defined herein, “lateral wellbore operations” are defined to include any suitable subterranean operation that may be performed in a lateral wellbore using a downhole tool, including, but not limited to, jetting, logging, analyzing, stimulating, cementing, or other suitable operations known to those of ordinary skill in the art. One such technique for locating and entering lateral wellbores involves the installation of special jewelry in the casing at the junction of the lateral and primary wellbores. This jewelry allows the landing of whipstocks adjacent to the junction to force any subsequent tubing run into the primary wellbore into the desired lateral wellbore. However, this technique is undesirable, inter alia, because the special jewelry generally may not be added after the primary casing is cemented in place. Furthermore, installation of the special jewelry may add undesirable expense to the completion of the well.
Another technique for locating and entering a lateral wellbore involves the utilization of a downhole tool that comprises an indexing tool, a kickover knuckle joint attached at a lower end of the indexing tool, and a wand attached at a lower end of the kickover knuckle joint. Coiled tubing may be run into a primary wellbore with the downhole tool attached at an end thereof. The downhole tool may first be lowered to the bottom of the primary wellbore to tag the bottom thereof and establish a maximum depth. After recordation of this depth, the downhole tool may then be raised to the estimated location of a junction of a lateral wellbore with the primary wellbore. At this point, the kickover knuckle joint may be used to deflect the wand away from the longitudinal axis of the downhole tool, and the downhole tool may be raised or lowered in the primary wellbore. To orientate the downhole tool in the primary wellbore, the indexing tool may be used to rotate the wand relative to the coiled tubing. When a lateral wellbore is located, the tip of the wand is allowed to fully bend into the lateral wellbore. Accordingly, when the wand fully bends, pressurized fluid in the downhole tool may be vented, which may be sensed at the surface thereby providing a surface indication to the operator that a lateral wellbore has been located. Because the wand controls the venting process, selection of the appropriate wand length may be critical in locating the lateral.
This technique, however, has drawbacks. One drawback with this technique is that the downhole tool may not include a means for accurate depth control downhole. For example, standard coiled tubing depth measurement may be off by as much as 100 feet. Therefore, when the downhole tool is raised to the estimated location of the junction, the location of the downhole tool may not be near the actual location of the junction so the downhole tool may be searching for the junction in the wrong location. Another drawback with this technique is that the venting portion of the downhole tool may not reliably signal the operator that a lateral wellbore has been located. In some instances, the tip of the wand may not fully bend even though it is in a lateral wellbore so that no venting takes place. Even further, for example, the downhole tool may vent when it is not in the lateral wellbore, inter alia, because curvature of the coiled tubing above the downhole tool may be sufficient to allow for the wand to fully bend. Because of these possible inaccuracies with the venting portion of the downhole tool, once the operator believes that a lateral wellbore has been located, the operator oftentimes will lower the downhole tool to the bottom of the lateral wellbore to tag the bottom thereof. This depth may be compared with the previously recorded depth of the primary wellbore to determine if a lateral wellbore has been found. If the two depths are identical, a lateral wellbore has not been found, and the operator must repeat the procedure for locating a lateral wellbore. The necessity for tagging the bottom of the primary and lateral wellbores may add undesirable delays to lateral wellbore operations.

SUMMARY

The present invention relates generally to lateral wellbore operations, and more particularly, to downhole tools that include a logging tool for locating a lateral wellbore and associated methods.
In one embodiment, the present invention provides a method for use in lateral wellbore operations. The method includes entering a lateral wellbore from a primary wellbore with a tool comprising a logging tool. The method further includes verifying entry into the lateral wellbore using the logging tool.
Another embodiment of the present invention provides a method of locating a lateral wellbore of a multilateral well, wherein the multilateral lateral well comprises a primary wellbore and a lateral wellbore that branches from the primary wellbore at a junction. The method includes positioning a tool comprising a logging tool within the multilateral well. The method further includes moving the tool within the multilateral well. And the method further includes determining whether the tool has entered the lateral wellbore using the logging tool.
Anther embodiment of the present invention provides a method of locating and entering a lateral wellbore from a primary wellbore, the lateral wellbore branching from the primary wellbore at a junction. The method includes positioning a downhole tool in the primary wellbore at a first location posterior to the junction, the downhole tool comprising a casing collar locator. The method further includes positioning the downhole tool in the primary wellbore at a second location anterior to the junction subsequent to positioning the downhole tool in the primary wellbore at the first location. The method further includes moving the downhole tool from the second location towards the junction. And the method further includes determining whether the downhole tool has entered the lateral wellbore using the casing collar locator.
Anther embodiment of the present invention provides a method of locating and entering a lateral wellbore from a primary wellbore, the lateral wellbore branching from the primary wellbore at a junction. The method includes positioning a downhole tool comprising a radiation detection logging tool in the primary wellbore. The method further includes moving the downhole tool towards the junction. And the method further includes determining whether the downhole tool has entered the lateral wellbore using the radiation detection logging tool.
Another embodiment of the present invention provides a downhole tool, the downhole tool including a logging tool. The downhole tool further includes a kickover knuckle joint connected to the logging tool. And the downhole tool further includes a wand connected to the kickover knuckle joint. Optionally, an orienting sub may be connected between the logging tool and the kickover knuckle joint.
The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, wherein:
FIG. 1 is a schematic drawing depicting a downhole tool in accordance with an embodiment of the present invention.
FIGS. 2 a and 2 b are side-cross sectional views depicting a casing collar locator in accordance with an embodiment of the present invention.
FIG. 3 is a side-cross sectional view depicting a radiation detection logging tool in accordance with an embodiment of the present invention.
FIG. 4 is a side-cross sectional view drawing depicting a combination casing collar locator/radiation detection logging tool in accordance with an embodiment of the present invention.
FIG. 5 a is a schematic drawing depicting a cased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed at a first location in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 5 b is a schematic drawing depicting an uncased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed at a first location in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 6 a is a schematic drawing depicting a cased lateral wellbore that branches from a primary wellbore, a downhole tool of the present invention disposed at a second location in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 6 b is a schematic drawing depicting an uncased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed at a second location in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 7 a is a schematic drawing depicting a cased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 7 b is a schematic drawing depicting an uncased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed in the primary wellbore in accordance with an embodiment of the present invention.
FIG. 8 a is a schematic drawing depicting a cased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed in the lateral wellbore in accordance with an embodiment of the present invention.
FIG. 8 b is a schematic drawing depicting an uncased lateral wellbore that branches from a primary wellbore, and a downhole tool of the present invention disposed in the lateral wellbore in accordance with an embodiment of the present invention.
FIG. 9 is a theoretical collar log of a primary wellbore in accordance with an embodiment of the present invention.
FIG. 10 a is a theoretical collar log of a cased lateral wellbore in accordance with an embodiment of the present invention.
FIG. 10 b is a theoretical collar log of an uncased lateral wellbore in accordance with an embodiment of the present invention.
While the present invention is susceptible to various modifications and alternative forms, specific exemplary embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

The present invention relates generally to lateral wellbore operations, and more particularly, to downhole tools that include a logging tool for locating a lateral wellbore and associated methods.
According to the methods of the present invention, a logging tool may be used to verify entry into a lateral wellbore that branches from a primary wellbore. The logging tool may be incorporated into any downhole tool suitable for locating and entering a lateral wellbore from a primary wellbore. The downhole tool comprising a logging tool may be positioned in a primary wellbore containing a lateral wellbore that branches therefrom. Any suitable technique may be used to attempt entry into the lateral wellbore that branches from the primary wellbore. While attempting entry, the logging tool may be used to generate a fingerprint as the logging tool is moved further into the primary and/or lateral wellbore. As defined herein, “fingerprint” is defined to mean any data that identifies a wellbore based on characteristics of the wellbore and/or the formation surrounding the wellbore, such as the location (or lack thereof) of casing collars in the wellbore (e.g., a collar log) or the emission of radiation by the formation (e.g., a gamma ray log or a neutron radiation log). The logging tool may be used to verify whether the attempt to enter the lateral wellbore was successful and, thus, whether the downhole tool has entered the lateral wellbore. The fingerprint generated during the attempted entry should be compared with a fingerprint of the primary wellbore and/or a preexisting fingerprint of the lateral wellbore. If the fingerprint generated during the attempted entry is not equivalent to the fingerprint of the primary wellbore, then entry into the lateral wellbore was accomplished. Similarly, if the fingerprint generated during the attempted entry is equivalent to the preexisting fingerprint of the lateral wellbore, entry into the lateral wellbore was accomplished. However, if the fingerprint generated during the attempted entry is equivalent to the fingerprint of the primary wellbore, entry into the lateral wellbore was not accomplished. Similarly, if the fingerprint generated during the attempted entry is not equivalent to the fingerprint of the lateral wellbore, entry into the lateral wellbore was not accomplished. As those of ordinary skill in the art will appreciate, the steps of attempting to enter the lateral wellbore may be repeated until entry into the lateral wellbore is verified. Once entry into the lateral wellbore is verified, the downhole tool may be utilized to perform any suitable lateral wellbore operation.
The details of the present invention will now be described with reference to the accompanying figures. Referring now to FIG. 1, a downhole tool in accordance with the present invention is shown generally by reference numeral 100. From upper end 102 to lower end 104, in one embodiment, downhole tool 100 includes logging tool 106, orienting sub 108, kickover knuckle joint 110, and wand 112. The various components of downhole tool 100, in certain embodiments, may be connected to each other end to end with threaded connections. In some embodiments, downhole tool 100 provides for fluid communication through its length. Optionally, downhole tool 100 may further include at least one centralizer (not shown) to radially centralize downhole tool 100 in a wellbore.
Logging tool 106 may be used to verify entry into a lateral wellbore. Generally, a fingerprint of a wellbore may be generated using logging tool 106. More particularly, logging tool 106 senses data that may be used to identify a wellbore. The sensed data may then be transmitted to the surface (or other suitable location) and used to determine the location of and possible entry of the downhole tool 100 into the lateral wellbore. Locating and entering the lateral wellbore using downhole tool 100 of the present invention will be discussed in more detail below. Furthermore, logging tool 106 may assist in establishing accurate depth control for downhole tool 100, for example, by correlating the fingerprint generated using logging tool 106 with preexisting fingerprints for the wellbore so that measurements errors may be compensated for. Generally, the logging tool may be any suitable tool that may be used in accordance with the present invention to generate a fingerprint of a wellbore. In some embodiments, logging tool 106 is a casing collar locator, a radiation detection logging tool, or a combination thereof (e.g., a combination casing collar locator/radiation detection logging tool).
Suitable casing collar locators for use in the present invention include any casing collar locator that may be incorporated into the downhole tool 100 of the present invention and used in generating a fingerprint of a wellbore. An example of a suitable casing collar locator is the DEPTHPRO casing collar locator, which is available from Halliburton Energy Services, Duncan, Okla. As those of ordinary skill in the art will appreciate, other suitable casing collar locators may be incorporated into downhole tool 100 of the present invention. Referring now to FIG. 2 a and FIG. 2 b, an example casing collar locator in accordance with the present invention is shown generally by reference number 200. Casing collar locator 200 includes housing 201 and fluid flow passageway 202 extending through its length for providing fluid communication through housing 201. So that fluid flows thru casing collar locator 200 and into lower end 104 of downhole tool 100 (shown on FIG. 1), plug 204 prevents the flow of fluid into a wellbore (not shown) and directs the flow of fluid from fluid flow passageway 202, through side passageway 206, and out of casing collar locator 200 through lower fluid flow passageway 208.
Casing collar locator 200 further includes collar detector 210, control unit 212, battery pack 214, and a communication unit 216. While FIG. 2 a shows collar detector 210, control unit 212, battery back 214, and communication unit 216 as separate units, in other embodiments, the units may be combined as appropriate. For example, in one embodiment, battery pack 214 and control unit 212 may be combined together as a single unit prior to incorporation into casing collar locator 200. Collar detector 210, control unit 212, battery pack 214, and communication unit 216 may be electrically connected by suitable wires and contacts and should be positioned within housing 201 without blocking fluid flow passageway 202. Those of ordinary skill in the art will appreciate that collar detector 210 may include a source of magnetic field, e.g., magnets 215, or it may rely on the Earth's magnetic field. Collar detector 210 further includes an electromagnetic coil assembly 218. Generally, control unit 212 houses electric circuit boards and other components 220. The electric circuit boards and other components 220 may include central processors and other similar computer equipment capable of receiving and interpreting data as known to those skilled in the art. Battery pack 214 provides power for collar detector 210, control unit 212, and communication unit 216, and may be any suitable device for generating sufficient electricity to provide the needed power, such as batteries or a generator. Communication unit 216 provides the means for transmitting a pressure pulse detectable at the surface or other suitable locations. Those of ordinary skill will recognize that a wide variety of suitable pressure pulse generation systems may be incorporated into casing collar locator 200. In one embodiment, communication unit 216 may include solenoid valve 222, flow passageway 224, piston 226, and spring 228.
As those of ordinary skill in the art will appreciate, collar detector 210 is capable of sensing a change in the magnetic flux as downhole tool 100 passes a casing collar as downhole tool 100 is moved within a wellbore. Collar detector 210 generates a signal corresponding to the change in magnetic flux, which is transmitted to control unit 212. Control unit 212 receives this signal and compares it to a predetermined threshold value. When this threshold value is met or exceeded by the change in magnetic flux input to control unit 212, control unit 212 directs communication unit 216 to transmit a pressure pulse to the surface (or other suitable location). In some embodiments, a pressure pulse may transmitted to the surface by the blockage of fluid flow through fluid flow passageway 202 for a predetermined period of time (e.g., about 3 seconds). For example, control unit 212 may direct solenoid valve 222 to open. When solenoid valve 222 is open, fluid is directed into flow passageway 224 where the fluid applies pressure to piston 226. As pressure is applied to piston 226, it lowers and compresses spring 228 until piston 226 rests on shoulder 230. When resting on shoulder 230, piston 226 blocks side passageway 206. This causes a pressure pulse in fluid flow passageway 202 detectable at the surface that indicates a casing collar has been located from which a collar log may be generated. Those of ordinary skill in the art should be able to select the appropriate mechanism for sensing the pressure pulse and recording it as a collar log. While casing collar locator 200 has been described utilizing a mud-pulse telemetry system as the data transmission system, the casing collar locator 200 may be equipped with a data transmission system for transmitting the sensed information along a wireline (not shown) or in any other suitable manner.
Suitable radiation detection logging tools for use in the present invention include any radiation detection logging tool that may be incorporated into downhole tool 100 of the present invention and used in a generating a fingerprint of a wellbore. Referring now to FIG. 3, an example radiation detection logging tool in accordance with the present invention is shown generally by reference number 300. Radiation detection logging tool 300 includes housing 301 and fluid flow passageway 302 extending through its length for providing fluid communication through housing 301. During logging operations, fluid flow passageway 302 may be blocked by rupture disc 303, wherein rupture disc 303 prevents communication of fluid pressure to lower end 104 of downhole tool 100 (shown on FIG. 1). One or ordinary skill in the art, with the benefit of this disclosure should be able to incorporate a rupture disc into the radiation detection logging tool 300.
Radiation detection logging tool 300 further includes radiation detector 304, control unit 306, battery pack 308, and communication unit 310. While FIG. 3 shows radiation detector 304, control unit 306, battery back 308, and communication unit 310 as separate units, in other embodiments, the units may be combined as appropriate. For example, in one embodiment, battery pack 308 and control unit 306 may be combined together as a single unit prior to incorporation into radiation detection logging tool 300. Radiation detector 304, control unit 306, battery pack 308, and communication unit 310 may be electrically connected by suitable wires and contacts and should be positioned within housing 301 without blocking fluid flow passageway 302. Generally, radiation detector 304 measures radiation in the wellbore as downhole tool 100 is moved therein. For example, radiation detector 304 may be a gamma ray detector that senses gamma counts emitted by formation rocks. Those of ordinary skill in the art will appreciate that radiation detector 304 may any suitable device for measuring radiation emitted by formation rock, such as a gamma ray detector or a neutron detector. Generally, control unit 306 houses electric circuit boards and other components 312. The electric circuit boards and other components 312 may include central processors and other similar computer equipment capable of receiving and interpreting data as known to those skilled in the art. In some embodiments, radiation detector 304 may be turned on and off in response to signals received from control unit 306. Battery pack 308 provides power for radiation detector 304, control unit 306, and communication unit 310, and may be any suitable device for generating sufficient electricity to provide the needed power, such as batteries or a generator. Communication unit 310 provides the means for transmitting a pressure pulse detectable at the surface (or other suitable location). U.S. Pat. No. 5,586,084, the disclosure of which is incorporated herein by reference in its entirety, describes a mud pulser that may be readily adapted for use with communication unit 310. Alternative pressure pulse generation systems are well known in the art.
Radiation detector 304 is capable of measuring radiation (e.g., gamma ray emissions, neutron emissions, or both) in the wellbore and generating a signal corresponding to the measured radiation. Radiation detector 304 transmits this signal to control unit 306. Control unit 306 receives this signal and directs communication unit 310 to generate detectable changes in fluid pressure corresponding to the measured radiation. For example, communication unit 310 may be capable of producing a series of pressure pulses detectable at the surface (or other suitable location). For example, communication unit 310 may produce pressure pulses within fluid flow passageway 302 that are detectable at the surface which correspond to the measured radiation from which a gamma ray or a neutron radiation log may be generated. Those of ordinary skill in the art should be able to select the appropriate mechanism for sensing the pressure pulse and recording it as a gamma ray or neutron radiation log. While radiation detection logging tool 300 has been described utilizing a mud-pulse telemetry system as the data transmission system, the radiation detection logging tool 300 may be equipped with a data transmission system for transmitting the sensed information along a wireline (not shown) or in any other suitable manner.
Suitable combination casing collar locators/radiation detection logging tools for use in the present invention include any combination casing collar locator/radiation detection logging tool that may be incorporated into downhole tool 100 of the present invention and used in generating a fingerprint of a wellbore. An example of a suitable combination casing collar locator/radiation detection logging tool is described in commonly owned U.S. patent application Ser. No. 10/796,548, filed on Mar. 9, 2004, the disclosure of which is incorporated herein by reference in its entirety. As those of ordinary skill in the art will appreciate, other suitable combination casing collar locators/radiation detection logging tools may be incorporated into downhole tool 100 of the present invention. Referring now to FIG. 4, an example combination casing collar locator/radiation detection logging tool in accordance with the present invention is shown generally by reference number 400. Combination casing collar locator/radiation detection logging tool 400 includes housing 401 and fluid flow passageway 402 extending through its length for providing fluid communication through housing 401. During logging operations, fluid flow passageway 402 may be blocked by rupture disc 403, wherein rupture disc 403 prevents communication of fluid pressure to lower end 104 of downhole tool 100 (shown on FIG. 1). One or ordinary skill in the art, with the benefit of this disclosure should be able to incorporate a rupture disc into the combination casing collar locator/radiation detection logging tool 400.
Combination casing collar locator/radiation detection logging tool 400 further includes collar detector 404, radiation detector 406, control unit 408, battery pack 410, and communication unit 412. While FIG. 4 shows collar detector 404, radiation detector 406, control unit 408, battery back 410, and communication unit 412 as separate units, in other embodiments, the units may be combined as appropriate. For example, in one embodiment, battery pack 410 and control unit 408 may be combined together as a single unit prior to incorporation into combination casing collar locator/radiation detection logging tool 400. Collar detector 404, radiation detector 406, control unit 408, battery pack 410, and communication unit 412 may be electrically connected by suitable wires and contacts and should be positioned within housing 401 without blocking fluid flow passageway 402. Those of ordinary skill in the art will appreciate that collar detector 404 may include a source of magnetic field, e.g., magnets 414, or it may rely on the Earth's magnetic field. Collar detector 404 further includes an electromagnetic coil assembly 416. Generally, radiation detector 406 measures radiation in a wellbore as downhole tool 100 is moved therein. For example, radiation detector 406 may be a gamma ray detector that senses gamma counts emitted by formation rocks. Those of ordinary skill in the art will appreciate that radiation detector 406 may any suitable device for measuring radiation emitted by formation rock, such as a gamma ray detector or a neutron detector. Generally, control unit 408 houses electric circuit boards and other components 418. The electric circuit boards and other components 418 may include central processors and other similar computer equipment capable of receiving and interpreting data as known to those skilled in the art. In some embodiments, radiation detector 406 may be turned on and off in response to signals received from control unit 408. Battery pack 410 provides power for collar detector 404, radiation detector 406, control unit 408, and communication unit 412, and may be any suitable device for generating sufficient electricity to provide the needed power, such as batteries or a generator. Communication unit 412 provides the means for transmitting a pressure pulse detectable at the surface (or other suitable location). U.S. Pat. No. 5,586,084 describes a mud pulser that may be readily adapted for use with communication unit 412. Alternative pressure pulse generation systems are well known in the art.
As those of ordinary skill in the art will appreciate, collar detector 404 is capable of sensing a change in the magnetic flux as downhole tool 100 passes a casing collar as downhole tool 100 is moved within a wellbore. Collar detector 404 generates a signal corresponding to the change in magnetic flux and transmits it to control unit 408. Control unit 408 receives the signal and compares this change in magnetic flux to a predetermined threshold value. When this threshold value is met or exceeded by the change in magnetic flux input to control unit 408, control unit 408 directs communication unit 412 to transmit this data to the surface (or other suitable location). For example, communication unit 412 may produce detectable changes in pressure within fluid flow passageway 402. These pressure pulses are detectable at the surface and indicate a casing collar has been located from which a collar log may be generated. Radiation detector 406 is capable of measuring radiation (e.g., gamma ray emissions, neutron emissions, or both) in the wellbore and generating a signal corresponding to the measured radiation. Radiation detector 406 transmits this signal to control unit 408. Control unit 408 receives this signal and directs communication unit 412 to transmit this data to the surface (or other suitable location) in the manner described above. Those of ordinary skill in the art should be able to select the appropriate mechanism for sensing the pressure changes in fluid flow passageway 402 and recording it as a collar log, gamma ray log, or a neutron radiation log. While combination casing collar locator/radiation detection logging tool 400 has been described utilizing a mud-pulse telemetry system as the data transmission system, it may be equipped with a data transmission system for transmitting the sensed information along a wireline (not shown) or in any other suitable manner.
Referring again to FIG. 1, orienting sub 108 may be connected between logging tool 106 and kickover knuckle joint 110. Orienting sub 108 may be any known device for rotating kickover knuckle joint 110 and wand 112 about the longitudinal axis LA of downhole tool 100. Examples of suitable devices include, but are not limited to, an indexing tool or a continuously run motor. Where an indexing tool is employed, the indexing tool may provide a rotation of a fixed number of degrees (e.g., 45 degrees) about the LA of downhole tool 100 when the indexing tool is activated. In one embodiment, the indexing tool is hydraulically activated so that it is activated when the flow of fluid through the indexing fluid is started and stopped. Where a continuously run motor is employed, such motor may provide continuous 360-degree rotation about the LA of downhole tool 100. One of ordinary skill in the art with the benefit of this disclosure will be able to select and employ the appropriate orienting sub 108 for a particular application.
Kickover knuckle joint 110 may be connected to orienting sub 108. Kickover knuckle joint 110 may be any suitable device adapted to deflect wand 112 with respect to the LA of downhole tool 100. Kickover knuckle joint 110 attaches wand 112 to downhole tool 100. In some embodiments, kickover knuckle joint 110 is a selectively activated knuckle joint. An example of a suitable selectively activated knuckle joint is the “Hydraulic Kickover Joint”, which is available from PCE, Dorset, United Kingdom. As will be appreciated by those skilled in the art, the selectively activated knuckle joint may not bend until it is activated. In a preferred embodiment, the selectively activated knuckle joint is hydraulically activated, wherein the selectively activated knuckle joint bends when a predetermined hydraulic pressure is reached therein. The activation of the selectively activated knuckle joint may then be controlled from the surface by controlling the hydraulic pressure within the selectively activated knuckle joint. Other suitable kickover knuckle joints 110 include, but are not limited to, restricted ball joints, pin joints, bourdon tubes, or an asymmetrically slotted member with internal pressurization means. One of ordinary skill in the art with the benefit of this disclosure should be able to select and implement the appropriate kickover knuckle joint 110 for a particular application.
Wand 112 is the bottom portion of downhole tool 100 that selectively deflects from alignment with the LA of downhole tool 100 to enter a lateral wellbore. Wand 112 is connected to kickover knuckle joint 110. In some embodiments, there may be more than one wand (not shown) at the bottom of downhole tool 100. Wand 112 should be of a length sufficient so that one end of wand 112 deflects into a lateral wellbore when it passes the lateral wellbore. As those of ordinary skill in the art will appreciate, wand 112 will be longer in casing with larger casing sizes than in smaller casing sizes. In some embodiments, wand 112 may be adjustable in length, for example, by telescoping. In some embodiments, the shape of wand 112 may be varied so long as the wand 112 is suitable for use in the present invention, for example, wand 112 may have some curvature or angularity (not shown).
As will be understood by those in skilled in the art, wand 112 further may include components useful in lateral wellbore operations, inter alia, for analyzing, treating, stimulating, and/or cementing the lateral wellbore. For example, as shown in FIG. 1, wand 112 may include a nose or toe 114 attached at an end thereof. In some embodiments, nose 114 may contain one or more ports. Even further, for example, the ports in nose 114 may include jetting nozzles disposed therein. Furthermore, components for analyzing and/or treating wellbores may also be located at other locations within downhole tool 100.
Wand 112 may be deflected with respect to the. LA of downhole tool 100 by kickover knuckle joint 110 to a predetermined maximum deflection angle α. The maximum deflection angle α of wand 112 by kickover knuckle joint 110 depends on a number of factors, including the inner diameter of the primary wellbore, the length of wand 112, and other factors known to those of ordinary skill in the art. Generally, a suitable maximum deflection angle α for wand 112 with respect to the LA of downhole tool 100 may be in the range from about 3 degrees to about 30 degrees.
Downhole tool 100 may further include an optional centralizer for centralizing downhole tool 100 in a lateral and/or primary wellbore. Any number or type of centralizers may be utilized in accordance with the present invention as desired by one skilled in the art. As those of ordinary skill in the art will appreciate, the length of wand 112 may be adjusted based on whether a centralizer is used with downhole tool 100.
Referring now to FIG. 5 a through FIG. 8 b an embodiment for locating and entering a lateral wellbore from a primary wellbore is illustrated. Downhole tool 100 may be the same as those previously described and may include logging tool 106, orienting sub 108, kickover knuckle joint 110, wand 112, and nose 114. Downhole tool 100 is shown disposed in primary wellbore 500 that penetrates subterranean formation 502. Generally, primary wellbore 500 may be lined with a slotted liner or casing string, e.g., primary casing 504, that may be cemented to subterranean formation 502. Primary casing 504 may include sections of pipe connected by one or more casing collars 506. Example depths for one or more casing collars 506 are indicated on FIG. 5 a through FIG. 8 b. Those of ordinary skill in the art will appreciate the circumstances when primary wellbore 500 should or should not be cemented. Even though FIG. 5 a through FIG. 8 b depict primary wellbore 500 as a vertical wellbore, the downhole tool 100 and methods of the present invention may be suitable in generally horizontal, generally vertical, or otherwise formed portions of wells.
Lateral wellbore 508 branches from primary wellbore 500 at junction 510. Primary wellbore 500 and lateral wellbore 508 may be drilled into subterranean formation 502 using any suitable drilling technique. As desired, lateral wellbore 508 may be lined with a casing string or slotted liner, e.g., lateral casing 512, as shown in FIG. 5 a, or left openhole, as shown in FIG. 5 b. In the embodiments where lateral wellbore 508 is lined with lateral casing 512, lateral casing 512 may or may not be cemented to subterranean formation 502. Furthermore, lateral casing 512 may include sections of pipe connected by one or more lateral casing collars 514. Example depths for one or more lateral casing collars 514 are indicated on FIGS. 5 a, 6 a, 7 a, and 8 a. Those of ordinary skill in the art will appreciate the circumstances when lateral wellbore 508 should or should not be cased and whether such casing should or should not be cemented.
As illustrated in FIG. 5 a for a cased lateral wellbore 508 and FIG. 5 b for an uncased lateral wellbore 508, downhole tool 100 should be positioned in primary wellbore 500. In some embodiments, primary wellbore 500 may be positioned at a first location that is below or posterior to the estimated location of junction 510. In one embodiment, the first location may be about 100 feet below or posterior to the estimated location of junction 510. While positioning downhole tool 100 at the first location, wand 112 may be maintained at angle coincident with or substantially coincident with the LA of downhole tool 100.
Next, as illustrated in FIG. 6 a for a cased lateral wellbore 508 and FIG. 6 b for an uncased lateral wellbore 508, downhole tool 100 may be positioned in primary wellbore 500 at a second location above or anterior to the estimated location of junction 510. In one embodiment, the second location may be about 100 feet above or anterior to the estimated location of junction 510. While positioning downhole tool 100 at the second location, wand 112 may be maintained at an angle coincident with or substantially coincident with the LA of downhole tool 100.
Furthermore, while raising or retrieving downhole tool 100 to the second location, logging tool 106 may be used in generating a fingerprint of primary wellbore 500. As previously discussed, this fingerprint may be a gamma ray log, a neutron radiation log, or a collar log of primary wellbore 500. For example, radiation emissions may be measured by logging tool 106 (e.g., a radiation detection logging tool) and transmitted to the surface (or other suitable location) while positioning downhole tool 100 in primary wellbore 500. The measured radiation emissions may be recorded as a gamma ray log or a neutron radiation log. Even further, for example, the location of one or more casing collars 506 in primary wellbore 500 may be sensed with logging tool 106 (e.g., a casing collar locator) and transmitted to the surface (or other suitable location) while positioning downhole tool 100 in primary wellbore 500. This sensed location(s) may be recorded as a collar log. Referring now to FIG. 9, depicted is a theoretical collar log that is a graphical representation of pressure versus depth that indicates the sensed location of one or more casing collars 506 in primary wellbore 500. The pressure spikes on the collar log indicate the sensed location of one or more casing collars 506. Among other things, this collar log may be used by an operator to correct his depth counters to compensate for measurement errors that may occur while running downhole tool 100 in primary wellbore 500. As one of ordinary skill in the art will appreciate, where a suitable fingerprint (e.g., a collar log, gamma ray log, neutron radiation log) of primary wellbore 500 is available downhole tool 100 may first be positioned in primary wellbore 500 at a second location without initially positioning downhole tool 100 at the first location.
Referring again to FIG. 6 a and FIG. 6 b, once downhole tool 100 is positioned at the second location, lower end 104 of downhole tool 100 should be deflected with respect to the LA of downhole tool 100. For example, kickover knuckle joint 110 should deflect wand 112 with respect to the LA of downhole tool 100 so that nose 114 is in contact with an inner surface of primary casing 504. In some embodiments, this may be accomplished by increasing the flow rate through downhole tool 100 until the hydraulic pressure therein is sufficient to deflect wand 112. The energy used to deflect wand 112 should be maintained and generally should be greater than the energy sufficient for nose 114 to reach the inner surface of primary casing 504. The inner surface of primary casing 504 should constrain wand 112 and prevent it from further deflection. Those of ordinary skill in the art will appreciate that wand 112 may deflect even further with respect to the LA of downhole tool 100 if the constraining force of primary casing 504 were removed.
Referring now to FIG. 7 a for a cased lateral wellbore and FIG. 7 b for an uncased lateral wellbore, downhole tool 100 may next be moved (e.g., lowered) from the second location in primary wellbore 500 towards junction 510. As downhole tool 100 is moved, nose 114 should remain in contact with the inner surface of primary casing 504. The energy used to deflect wand 112 should be maintained while moving downhole tool 100 in primary wellbore 500. When downhole tool 100 passes junction 510, lower end 104 (shown in FIG. 1) of downhole tool 100 enters lateral wellbore 508. For example, when junction 510 is reached, the constraining force of primary casing 504 is removed and wand 112 deflects further with respect to the LA of downhole tool 100 so that toe 114 of wand 112 may enter lateral wellbore 508. In some embodiments, kickover knuckle joint 110 and wand 112 may be rotated using orienting sub 108 while moving downhole tool 100 towards junction 510.
Referring now to FIG. 8 a for a cased lateral wellbore 508 and FIG. 8 b for an uncased lateral wellbore 508, downhole tool 100 may next be moved into lateral wellbore 508 behind toe 114. While moving downhole tool 100 from the second location in primary wellbore 500 towards junction 510 and into lateral wellbore 508, logging tool 106 should be used to verify entry of downhole tool 100 into lateral wellbore 508. For example, logging tool 106 should be used to generate a fingerprint as downhole tool 100 moves from the second location in primary wellbore 500 and into lateral wellbore 508. As previously discussed, the fingerprint may be a gamma ray log, a neutron radiation log, or a collar log. For example, radiation emissions may be measured by logging tool 106 (e.g., a radiation detection logging tool) and transmitted to the surface (or other suitable location) while moving downhole tool 100 into lateral wellbore 508. The sensed radiation emissions may be recorded as a gamma ray log or a neutron radiation log. Even further, for example, the location of one or more lateral casing collars 514 in lateral wellbore 508 may be sensed with logging tool 106 (e.g., a casing collar locator) and transmitted to the surface (or other suitable location) while moving downhole tool 100 into lateral wellbore 508. This sensed location(s) may be recorded as a collar log. Referring now to FIG. 10 a, depicted is a theoretical collar log that is a graphical representation of pressure versus depth that indicates the sensed location of one or more lateral casing collars 514 in lateral wellbore 508, wherein lateral wellbore 508 is cased. Referring now to FIG. 10 b, depicted is a theoretical collar log that is a graphical representation of pressure versus depth that indicates the presence, or lack thereof, of casing collars in lateral wellbore 508, wherein lateral wellbore 508 is uncased. The pressure spikes on these collar logs indicate the sensed location of one or more lateral casing collars 514. As will be understood by those of ordinary skill in the art the one or more casing collars indicated on the collar log of lateral wellbore 508 may be a primary casing collar 506 that logging tool 106 passes prior to its entry into lateral wellbore 508.
To verify entry into lateral wellbore 508, the fingerprint of lateral wellbore 508, obtained as described above, may be compared with any suitable fingerprint of primary wellbore 500. For example, determining whether downhole tool 100 has entered into lateral wellbore 508 may comprise comparing a collar log sensed by a casing collar locator with a collar log of primary wellbore 500. Even further, for example, determining whether the downhole tool 100 has entered lateral wellbore 508 may comprise comparing a gamma ray or a neutron radiation log sensed by a radiation detection logging tool with a gamma ray or a neutron radiation log of primary wellbore 500. In some embodiments, the fingerprint of primary wellbore 500 may be a fingerprint obtained as described above when navigating downhole tool 100 within primary wellbore 500 or any suitable fingerprint of primary wellbore 500 that is available. If the fingerprint of lateral wellbore 508 is not equivalent to the fingerprint of primary wellbore 500, then entry into lateral wellbore 508 is verified and downhole tool 100 successfully located and entered lateral wellbore 508. Furthermore, in some instances, there may be a suitable preexisting fingerprint of lateral wellbore 508. The preexisting fingerprint of lateral wellbore 508 may have been generated during previous operations in lateral wellbore 508, such as drilling. Where a suitable preexisting fingerprint of lateral wellbore 508 is present, the fingerprint of lateral wellbore 508 obtained as described above may be compared to the preexisting fingerprint of lateral wellbore 508 to verify whether downhole tool 100 has entered lateral wellbore 508. For example, determining whether the downhole tool 100 has entered lateral wellbore 508 may comprise comparing a gamma ray or a neutron radiation log sensed by a radiation detection logging tool with a pre-existing gamma ray or a neutron radiation log of lateral wellbore 508. If the fingerprint of lateral wellbore 508 is equivalent to the pre-existing fingerprint of lateral wellbore 508, then entry into lateral wellbore 508 is verified and downhole tool 100 successfully located and entered lateral wellbore 508. As those of ordinary skill in the art will appreciate, the comparison to the pre-existing fingerprint of lateral wellbore 508 may be done in combination with or independently to a comparison with the fingerprint of primary wellbore 500.
After entry into lateral wellbore 508 has been verified, lower end 104 (e.g., wand 114) of downhole tool 100 may be returned to an angle coincident with or substantially coincident with the LA of downhole tool 100 as illustrated on FIG. 8 a and FIG. 8 b. In some embodiments, lateral wellbore operations in lateral wellbore 508 may then be conducted.
However, if the fingerprint of lateral wellbore 508 is equivalent to the fingerprint of primary wellbore 500 and/or the fingerprint of lateral wellbore 508 is not equivalent to the preexisting fingerprint of lateral wellbore 508, then downhole tool 500 did not locate and enter lateral wellbore 508. For example, junction 510 may have been on an opposite side of primary wellbore 500 than where nose 114 was deflected. As one of ordinary skill in the art will appreciate, downhole tool 100 then is actually in primary wellbore 500 and the fingerprint obtained is not the fingerprint of lateral wellbore 508 but is instead the fingerprint of primary wellbore 500. Downhole tool 100 may then be returned to the second location above or anterior to junction 510 and orienting sub 108 may be used to rotate wand 112 about the LA of downhole tool 100. The above procedure may then be repeated until it is determined using the above verification procedures whether downhole tool 100 has successfully located and entered lateral wellbore 508.
Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims.

Claims

1. A method for use in lateral wellbore operations, comprising:

entering a lateral wellbore from a primary wellbore with a tool comprising a logging tool; and

verifying entry into the lateral wellbore using the logging tool.

2. The method of claim 1 wherein the logging tool is a casing collar locator, a radiation detection logging tool, or a combination thereof.

3. The method of claim 1 wherein verifying entry into the lateral wellbore comprises:

generating a fingerprint of the lateral wellbore using the logging tool; and

comparing the fingerprint of the lateral wellbore with a fingerprint of the primary wellbore and/or a pre-existing fingerprint of the lateral wellbore.

4. The method of claim 3 wherein the fingerprint is a collar log, a gamma ray log, or a neutron radiation log.

5. The method of claim 3 wherein the fingerprint of the primary wellbore was generated using the logging tool.

6. The method of claim 1 further comprising moving the tool in the primary wellbore towards a junction, wherein the lateral wellbore branches from the primary wellbore at the junction.

7. The method of claim 6 further comprising positioning the tool at a location anterior to the junction prior to moving the tool towards the junction.

8. The method of claim 7 further comprising generating a fingerprint of the primary wellbore using the logging tool while positioning the tool at a location anterior to the junction.

9. The method of claim 7 further comprising positioning the tool at a location posterior to the junction prior to positioning the tool at a location anterior to the junction.

10. The method of claim 1 further comprising conducting a lateral wellbore operation subsequent to verifying entry into the lateral wellbore.

11. A method of locating a lateral wellbore of a multilateral well, wherein the multilateral lateral well comprises a primary wellbore and a lateral wellbore that branches from the primary wellbore at a junction, comprising:

positioning a tool comprising a logging tool within the multilateral well;

moving the tool within the multilateral well; and

determining whether the tool has entered the lateral wellbore using the logging tool.

12. The method of claim 11 wherein determining whether the tool has entered the lateral wellbore comprises comparing a fingerprint generated by the logging tool while moving the tool with a fingerprint of the lateral wellbore and/or a fingerprint of the primary wellbore.

13. The method of claim 11 wherein the logging tool is a casing collar locator, a radiation detection logging tool, or a combination thereof.

14. The method of claim 11 further comprising generating a fingerprint of the primary wellbore using the logging tool.

15. The method of claim 14 wherein the fingerprint is a collar log, a gamma ray log, or a neutron radiation log.

16. The method of claim 11 wherein positioning the tool within the multilateral well comprises positioning the tool at a first location in the primary wellbore posterior to the junction.

17. The method of claim 16 wherein positioning the tool within the multilateral well further comprises positioning the tool at a second location anterior to the junction subsequent to positioning the tool at the first location in the primary wellbore.

18. The method of claim 17 further comprising generating a fingerprint of the primary wellbore while positioning the tool at the second location in the primary wellbore.

19. The method of claim 17 wherein moving the tool within the multilateral well comprises moving the tool from the second location in the primary wellbore towards the junction.

20. The method of claim 11 further comprising entering the lateral wellbore while moving the tool within the multilateral well.

21. A method of locating and entering a lateral wellbore from a primary wellbore, wherein the lateral wellbore branches from the primary wellbore at a junction, comprising:

(a) positioning a downhole tool in the primary wellbore at a first location posterior to the junction, wherein the downhole tool comprises a casing collar locator;

(b) positioning the downhole tool in the primary wellbore at a second location anterior to the junction subsequent to positioning the downhole tool in the primary wellbore at the first location;

(c) moving the downhole tool from the second location towards the junction; and

(d) determining whether the downhole tool has entered the lateral wellbore using the casing collar locator.

22. The method of claim 21 wherein determining whether the downhole tool has entered the lateral wellbore comprises comparing a collar log of the lateral wellbore sensed by the casing collar locator with a collar log of the primary wellbore.

23. The method of claim 21 further comprising rotating the downhole tool about a longitudinal axis of the downhole tool subsequent to determining whether the downhole tool has entered the lateral wellbore.

24. The method of claim 21 further comprising repeating steps (b) through (d) subsequent to determining whether the downhole tool has entered the lateral wellbore.

25. The method of claim 21 wherein the first location is about 100 feet posterior to the junction.

26. The method of claim 21 further comprising sensing the location of one or more casing collars in the primary wellbore with the casing collar locator while positioning the downhole tool in the primary wellbore at the second location.

27. The method of claim 21 wherein the second location is about 100 feet anterior to the junction.

28. The method of claim 21 further comprising deflecting an end of the downhole tool with respect to a longitudinal axis of the downhole tool.

29. The method of claim 28 wherein the end of the downhole tool enters the lateral wellbore when the downhole tool passes the junction.

30. The method of claim 29 further comprising moving the downhole tool into the lateral wellbore.

31. The method of claim 29 further comprising sensing the location of one or more casing collars within the lateral wellbore.

32. The method claim 30 further comprising returning the end of the downhole tool to an angle substantially coincident to the longitudinal axis of the downhole tool after the downhole tool moves into the lateral wellbore.

33. The method of claim 21 further comprising sensing the location of one or more casing collars within the primary wellbore.

34. A method of locating and entering a lateral wellbore from a primary wellbore, wherein the lateral wellbore branches from the primary wellbore at a junction, comprising:

(a) positioning a downhole tool comprising a radiation detection logging tool in the primary wellbore;

(b) moving the downhole tool towards the junction; and

(c) determining whether the downhole tool has entered the lateral wellbore using the radiation detection logging tool.

35. The method of claim 34 wherein determining whether the downhole tool has entered the lateral wellbore comprises comparing a gamma ray log of the lateral wellbore generated using the radiation detection logging tool with a gamma ray log of the primary wellbore and/or a pre-existing gamma ray log of the lateral wellbore.

36. The method of claim 34 wherein determining whether the downhole tool has entered the lateral wellbore comprises comparing a neutron radiation log of the lateral wellbore generated using the radiation detection logging tool with a neutron radiation log of the primary wellbore and/or a pre-existing neutron radiation log of the lateral wellbore.

37. The method of claim 34 further comprising rotating the downhole tool about a longitudinal axis of the downhole tool subsequent to determining whether the downhole tool has entered the lateral wellbore.

38. The method of claim 37 further comprising repeating steps (a) through (c) subsequent to determining whether the downhole tool has entered the lateral wellbore.

39. The method of claim 34 further comprising generating a gamma ray log of the primary wellbore while positioning the downhole tool in the primary wellbore.

40. The method of claim 34 further comprising generating a neutron radiation log of the primary wellbore while positioning the downhole tool in the primary wellbore.

41. The method of claim 34 further comprising deflecting an end of the downhole tool with respect to a longitudinal axis of the downhole tool.

42. The method of claim 41 wherein the end of the downhole tool enters the lateral wellbore when the downhole tool passes the junction.

43. The method of claim 42 further comprising moving the downhole tool into the lateral wellbore.

44. The method of claim 43 further comprising measuring radiation emissions within the lateral wellbore.

45. The method of claim 44 wherein the radiation emissions are gamma ray emissions, neutron radiation emissions, or both.

46. The method claim 43 further comprising returning the end of the downhole tool to an angle substantially coincident to the longitudinal axis of the downhole tool after the downhole tool moves into the lateral wellbore.

47. The method of claim 34 further comprising measuring radiation emissions within the primary wellbore.

48. A downhole tool, comprising:

a logging tool;

a kickover knuckle joint connected to the logging tool; and

a wand connected to the kickover knuckle joint.

49. The downhole tool of claim 48 wherein the logging tool is a casing collar locator, a radiation detection logging tool, or a combination thereof.

50. The downhole tool of claim 49 wherein the logging tool comprises:

a housing;

a fluid passageway for providing fluid communication through the housing; and

a radiation detector positioned within the housing for measuring radiation in a wellbore and for generating a signal corresponding to the measured radiation;

51. The downhole tool of claim 50 wherein the radiation detector comprises a gamma ray detector or a neutron detector.

52. The downhole tool of claim 50 wherein the logging tool further comprises:

a communication unit positioned within the housing;

a control unit positioned within the housing for receiving the signal from the radiation detector and for directing the communication unit to transmit a pressure pulse; and

a battery pack for powering the radiation detector, the control unit, and the communication unit.

53. The downhole tool of claim 49 wherein the casing collar locator comprises:

a housing;

a fluid passageway for providing fluid communication through the housing; and

a casing collar detector positioned within the housing for sensing the location of one or more casing collars in a wellbore and for generating a signal corresponding to the sensed location.

54. The downhole tool of claim 53 wherein the radiation detection logging tool comprises:

a communication unit positioned within the housing;

a control unit positioned within the housing for receiving the signal from the casing collar detector and directing the communication unit to transmit a pressure pulse; and

a battery pack for powering the casing collar detector, the control unit, and the communication unit.

55. The downhole tool of claim 49 wherein the combination casing collar locator/radiation detection logging tool comprises:

a housing;

a fluid passageway for providing fluid communication through the housing;

a casing collar detector positioned within the housing for sensing the location of one or more casing collars in a wellbore and for generating a signal corresponding to the sensed location; and

a radiation detector positioned within the housing for measuring radiation in the wellbore and for generating a signal corresponding to the measured radiation.

56. The downhole tool of claim 55 wherein the combination casing collar locator/radiation detection logging tool further comprises:

a communication unit positioned within the housing;

a control unit positioned within the housing for receiving the signal from the casing collar detector and the radiation detector, and for directing the communication unit to transmit a pressure pulse; and

a battery pack for powering the casing collar detector, the radiation detector, the control unit, and the communication unit.

57. The downhole tool of claim 48 further comprising an orienting sub connected between the logging tool and the kickover knuckle joint.

58. The downhole tool of claim 57 wherein the orienting sub includes an indexing tool or a continuously run motor.

59. The downhole tool of claim 57 wherein the orienting sub is operated hydraulically.

60. The downhole tool of claim 48 wherein the kickover knuckle joint is a selectively activated knuckle joint.

61. The downhole tool of claim 48 wherein the kickover knuckle joint is operated hydraulically.

62. The downhole tool of claim 48 wherein the wand is adjustable in length.

63. The downhole tool of claim 48 wherein the wand includes a nose attached at an end thereof.

64. The downhole tool of claim 63 wherein the nose contains one or more ports.

65. The downhole tool of claim 48 wherein the wand may be deflected with respect to the longitudinal axis of the downhole tool to a predetermined maximum deflection angle.

66. The downhole tool of claim 65 wherein the predetermined maximum deflection angle is in the range of from about 3 degrees to about 30 degrees.