METHOD AND SYSTEM FOR USING WELLBORE INSTRUMENTS WITH A WIRED PIPE STRING

Abstract

A wellbore instrument system includes a pipe string extending from earth's surface to a selected depth in a wellbore. The pipe string includes at least one of an electrical conductor and an optical fiber signal channel. A power generator sub is coupled at one end to a lower end of the pipe string. At least one electrically powered wellbore instrument is coupled to the other end of the adapter sub.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention relates generally to the field of wellbore instruments and well logging methods. More specifically, the invention relates to systems and methods for operating electrically powered instruments in a well using a wired pipe string as a signal communication channel.

2. Background Art

Well logging instruments are devices configured to move through a wellbore drilled through subsurface rock formations. The devices include one or more sensors and other devices that measure various properties of the subsurface rock formations and/or perform certain mechanical acts on the formations, such as drilling or percussively obtaining samples of the rock formations, and withdrawing samples of connate fluid from the rock formations. Measurements of the properties of the rock formations made by the sensors may be recorded with respect to the instrument axial position (depth) within the wellbore as the instrument is moved along the wellbore. Such recording is referred to as a “well log.”

Well logging instruments can be conveyed along the wellbore by extending and withdrawing an armored electrical cable (“wireline”), wherein the instruments are coupled to the end of the wireline. Such conveyance relies on gravity to move the instruments into the wellbore. Extending and withdrawing the wireline may be performed using a winch or similar spooling device known in the art. It is also known in the art to use “logging while drilling” (“LWD”) instruments in certain circumstances. Such circumstances include expensive drilling operations, where the time needed to suspend drilling operations in order to make the wellbore accessible to wireline instruments would make the cost of such access prohibitive, and wellbores having a substantial lateral displacement from the surface location of the well. Such circumstances include large lateral displacement of the wellbore particularly where long wellbore segments having high inclination (deviation from vertical). In such cases, gravity is not able to overcome friction between the instruments and the wellbore wall, thus making wireline conveyance impracticable. LWD instrumentation has proven technically and economically successful under the appropriate conditions.

There are several types of wireline instrument conveyance known in the art for the foregoing conditions. One conveyance technique includes coupling the wireline instruments to the end of a coiled tubing having a wireline disposed therein. The wireline instruments are extended into and withdrawn from the wellbore by extending and retracting the coiled tubing, respectively. A subset of such coiled tubing techniques includes preliminary conveyance of the wireline configurable well logging instruments to a selected depth in the wellbore using a threadedly coupled pipe “string.” See, for example, U.S. Pat. No. 5,433,276 issued to Martain et al.

Another well logging instrument conveyance technique includes coupling wireline configurable well logging instruments to the end of a drill pipe or similar threadedly coupled pipe string. A wireline is coupled to the instruments using a “side entry sub” which provides a sealable passage from the exterior of the pipe string to the interior thereof. As the pipe string is extended into the wellbore, the wireline is extended by operating a conventional winch. An example of the foregoing is described in U.S. Pat. No. 6,092,416 issued to Halford et al. and assigned to the assignee of the present invention.

Recently, a type of drill pipe has been developed that includes a signal communication channel. See, for example, U.S. Pat. No. 6,641,434 issued to Boyle et al. and assigned to the assignee of the present invention. Such drill pipe has in particular provided substantially increased signal telemetry speed for use with LWD instruments over conventional LWD signal telemetry, which typically is performed by mud pressure modulation or by very low frequency electromagnetic signal transmission.

The foregoing drill pipe having a signal communication channel has not proven effective at transmitting electrical power from the surface to an instrument string disposed at a lower end of the pipe. In wireline conveyance of wellbore instrument, electrical power is transmitted from the surface to the instruments in the wellbore. In MWD and LWD, electrical power may be provided by batteries, or by an electric generator operated by flow of fluid through the pipe. When wired pipe is used for signal telemetry, the amount of electrical power required by the instruments may be substantially reduced because the signal telemetry device used in MWD/LWD, typically a mud flow modulator, uses a substantial portion of the total electrical power used by the instruments.

What is needed is a method and system for pipe conveyance of wellbore instruments that includes substantial signal telemetry capability, and does not require the use of armored electrical cable for transmission of electrical power to the instruments in the wellbore or signal communication from the instruments to the surface, or does not require the use of large batteries for power storage.

SUMMARY OF THE INVENTION

A wellbore instrument system according to one aspect of the invention includes a pipe string extending from earth's surface to a selected depth in a wellbore. The pipe string includes at least one of an electrical conductor and an optical fiber signal channel. A power generator sub is coupled at one end to a lower end of the pipe string. At least one electrically powered wellbore instrument is coupled to the other end of the adapter sub.

A method for well surveying according to another aspect of the invention includes moving at least one wellbore instrument along a wellbore at one end of a segmented pipe string. The pipe string includes a signal communication channel associated therewith. The method includes generating electrical power to operate the wellbore instrument at a location proximate a downhole end of the segmented pipe string. Measurements from at least one sensor in the instrument are communicated to the signal communication channel. The communicated measurements are detected at a surface end of the communication channel.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example of “wireline configurable” well logging instruments being conveyed through a wellbore using a wired pipe string.

FIGS. 2 through 5 show examples of an adapter sub.

FIG. 6 shows a power generator portion of an adapter sub.

FIG. 7 shows another example of an adapter sub including a packer to isolate the well logging instrument from flow.

FIG. 8 shows an example of a longitudinal slip joint that may be used in some examples.

FIG. 9 shows an example of signal processing devices to adapt wireline configurable well logging instrument telemetry to wired pipe string telemetry.

FIG. 10 shows another example wellbore instrument that may be disposed at a lower end of the pipe string shown in FIG. 1.

DETAILED DESCRIPTION

Generally, the invention relates to devices for conveying a wellbore instrument or a “string” of such instruments through a wellbore using a wired pipe string for conveyance and signal communication. The wired pipe string may include an electrical generator and power storage module or “sub” for supplying electrical power to operate the instrument and for providing telemetry to signal communication channel in the wired pipe string. The wired pipe string may be assembled and disassembled in segments to effect conveyance in a manner known in the art for conveyance of segmented pipe through a wellbore. In FIG. 1, a drilling rig 24 or similar lifting device moves a conduit or pipe called a “wired pipe string” 20 within a wellbore 18 that has been drilled through subsurface rock formations, shown generally at 11. The wired pipe string 20 may be extended into the wellbore 18 by threadedly coupling together end to end a number of segments (“joints”) 22 of wired drill pipe. Wired drill pipe is structurally similar to ordinary drill pipe and includes at least one electrical conductor or at least one optical fiber associated with each pipe joint to act as a signal communication channel. Wired drill pipe includes some form of signal coupling to communicate signals along the channel between pipe joints when the pipe joints are coupled end to end as shown in FIG. 1. See, as a non-limiting example, U.S. Pat. No. 6,641,434 issued to Boyle et al. and assigned to the assignee of the present invention for a description of a type of wired drill pipe that can be used with the present invention.

The wired pipe string 20 may include an assembly or “string” of wellbore instruments at a lower end thereof. In the present example, the wellbore instrument string may include wireline configurable well logging instruments 13 coupled to a lower end thereof. As used in the present description, the term “wireline configurable well logging instruments” or a string of such instruments means one or more well logging instruments that can be conveyed through a wellbore using armored electrical cable (“wireline”), and which cannot be used in a pipe string for conducting drilling operations as a part of the pipe string. Wireline configurable well logging instruments are thus distinguishable from “logging while drilling” (“LWD”) instruments, which are configurable to be used during drilling operations and form part of the pipe string itself. The purpose for coupling the wireline configurable logging instrument string 13 to the end of the wired pipe string 20 will be further explained below. As will be further explained below with reference to FIG. 10, LWD and related drill string instrumentation may also be used as the wellbore instrument(s).

Several of the components disposed proximate the drilling unit 24 may be used to operate part of the system of the invention. These components will be explained with respect to their uses in drilling the wellbore to better enable understanding the invention. The pipe string 20 may be used to turn and axially urge a drill bit (FIG. 10) into the bottom of the wellbore 18 to increase its length (depth). During drilling of the wellbore 18, a pump 32 lifts drilling fluid (“mud”) 30 from a tank 28 or pit and discharges the mud 30 under pressure through a standpipe 34 and flexible conduit 35 or hose, through the top drive 26 and into an interior passage (not shown separately in FIG. 1) inside the pipe string 20. The mud 30 exits the drill string 20 through courses or nozzles (not shown separately) in the drill bit (FIG. 10), where it then cools and lubricates the drill bit and lifts drill cuttings generated by the drill bit (FIG. 10) to the Earth's surface.

When the wellbore 18 has been drilled to a selected depth, the pipe string 20 may be withdrawn from the wellbore 18, and an adapter sub 12 and the well logging instrument string 13 may be coupled to the end of the pipe string 20. The pipe string 20 may then be reinserted into the wellbore 18 so that the instruments 13 may be moved through, for example, a highly inclined portion 18A of the wellbore 18 which would be inaccessible using armored electrical cable (“wireline”) to move the instruments 24. During well logging operations, the pump 32 may be operated to provide fluid flow to operate one or more turbines (not shown in FIG. 1) in the well logging instrument string 13 to provide power to operate certain devices in the well logging instrument string 13.

As the well logging instrument string 13 is moved along the wellbore 18 by moving the pipe string 20 as explained above, signals detected by various devices, non-limiting examples of which may include an induction resistivity instrument 16, a gamma ray sensor 14 and a formation fluid sample taking device 10 (which may include a fluid pressure sensor (not shown separately)) are selected to be included in a telemetry transceiver (FIG. 9) in the adapter sub 12 for communication along the signal channel in the wired pipe string 20. A the surface, a telemetry transmitter 36A can be used to wirelessly transmit signals from the wired pipe string 20 to a receiver 36B. Thus, the wired pipe string 20 may be freely moved, assembled, disassembled and rotated without the need to make or break a wired electrical or optical signal connection. Signals from the receiver 36B, which may be electrical and/or optical signals, for example, may be conducted (such as by wire or cable) to a recording unit 38 for decoding and interpretation using techniques well known in the art. The decoded signals typically correspond to the measurements made by one or more of the sensors in the well logging instruments 10, 14, 16. Other sensors known in the art include, without limitation, density sensors, neutron porosity sensors, acoustic travel time or velocity sensors, seismic sensors, neutron induced gamma spectroscopy sensors and microresistivity (imaging) sensors.

The functions performed by the adapter sub 12 may include providing a mechanical coupling (explained below) between the lowermost threaded connection on the pipe string 20 and an uppermost connection on the well logging instruments 13. The adapter sub 12 may also include one or more devices (explained below) for producing electrical and/or hydraulic power to operate various parts of the well logging instruments 13. Finally, the adapter sub may include signal processing and recording devices (explained below) for selecting signals from the well logging instrument 13 for transmission to the surface using the wired pipe string 20 and recording signals in a suitable storage or recording device (explained below) in the adapter sub 12.

It will be appreciated by those skilled in the art that in other examples the top drive 26 may be substituted by a swivel, kelly, kelly bushing and rotary table (none shown in FIG. 1) for rotating the pipe string 20 while providing a pressure sealed passage through the pipe string 20 for the mud 30. Accordingly, the invention is not limited in scope to use with top drive drilling systems.

Having explained the system components generally, more detailed description of examples of certain system components follows. FIG. 2 shows one example of the adapter sub 12. Wired drill pipe, such as in the above provided example, is known to have digital signal telemetry capacity between one hundred thousand and one million bits per second. Wired drill pipe known in the art, however, does not efficiently transmit electrical power. The adapter sub 12, therefore, may include a turbine 41 that is rotated by flow of drilling fluid moved by the pump (32 in FIG. 1) as explained above. In the present example, the turbine 41 may be disposed in a housing 40 therefor. As will be explained below with reference to FIG. 6, the turbine housing 40 may include threaded connections configured to couple to the lowermost threaded connection on the wired pipe string 20. An electric generator or alternator, shown at 43, disposed in the turbine housing 40 or in a separate a housing 42 therefor may be rotationally coupled to the turbine 41. Use of the terms “generator” and “alternator” herein is intended to be interchangeable in that use of either direct current electric generators or alternating current generators is within the scope of this invention, and the term “generator” as used below and in the appended claims is intended to include both types of device within its scope. Electrical output from the generator 43 may be conditioned to operate various components in the well logging instruments in a power conditioner module 44.

The turbine 41 in some examples may have a controllable response to fluid flow, such as by controllable blade pitch, a controllable brake (not shown) or controllable bypass ports (FIG. 6). Other methods include a controllable distance between the rotor and stator (either passive—based on the thrust force of the flow/rotational speed or actively controlled) or variable distance between the tips of the turbine blades and the housing (by moving either the turbine or the housing axially relative to the other, with one or both having a coned shape). Again, this could be achieved passively based on the thrust force, the rotational speed or combination of the two, or it could be controlled actively. These last two methods effectively alter the efficiency of the turbine. Such controllable turbine response feature may provide proper operation of the generator 43 under widely variable electrical load conditions.

The present example contemplates that a formation fluid sampling and pressure testing instrument (10 in FIG. 1) may be coupled to the power conditioner module 44, either directly or through other well logging instruments. One non-limiting example of such a formation fluid sampling and pressure testing instrument is described in U.S. Pat. No. 6,659,177 issued to Bolze et al. and assigned to the assignee of the present invention. Formation testing instruments, as a general matter, may include a power/control and signal processing module (“FT power”) 46 and a pump module (“FT pump out”) 48. The pump out 48 may include a fluid pump 47 that is operable at a controllable rate, and is selectively coupled, using solenoid operated valves (not shown), to a probe (not shown) placed in contact with the formation (11 in FIG. 1). The fluid pump 47 is used for, among other purposes, withdrawing samples of connate fluid from the formations (11 in FIG. 1). Certain details of the formation testing instrument (10 in FIG. 1) are not relevant to the invention and are not shown herein for clarity of the illustration. In the present example, the fluid pump 47 may be operated by an electric motor 45. Additional electrical power provided by the generator 43 may be used to operate the other well logging instruments (14, 16 in FIG. 1) coupled to the wired pipe string (20 in FIG. 1).

FIG. 3 shows another example of the adapter sub 12. The example adapted sub shown in FIG. 3 includes a turbine 41 as in the previous example. The example of FIG. 3, however, includes an hydraulic pump 49 rotationally coupled to and operated by the turbine 41. Hydraulic power generation by the turbine 41 may facilitate power output control for widely ranging electrical load imparted by the well logging instruments (10, 14, 16 in FIG. 1). In the example of FIG. 3, hydraulic power provided by the hydraulic pump 49 may drive an hydraulic motor 51 which itself drives the generator 43. Remaining components of the well logging instruments may be as in the previous example.

FIG. 4 shows another example in which the hydraulic pump provides hydraulic power to directly operate the pump 47A in the formation testing instrument (10 in FIG. 1). Part of the hydraulic power provided by the hydraulic pump 49 may drive an hydraulic motor 51A to operate the generator 43A as in the example of FIG. 3. Because the formation tester pump 47A can consume a very large amount of power, in the example of FIG. 4 it may be possible to use a much smaller generator 43A than the examples shown in FIGS. 2 and 3.

Another example of the adapter sub 12 may include a first turbine 41A coupled to a generator 43B and a second turbine 41B coupled to the formation tester pump 47B. In the present example, the second turbine 41B can provide power to operate the formation tester pump 47B directly or through hydraulic conversion, and the first turbine 41A may provide power to operate the generator 43B for all electrical consumption of the well logging instruments (10, 14, 16 in FIG. 1).

An example of the adapter sub is shown in more detail in FIG. 6. The adapter sub 12 housing 40 may include an upper threaded connection 50 configured to couple to the lowermost threaded coupling on the wired pipe string (20 in FIG. 1). Such threaded coupling may include a communication device 52 disposed in a thread shoulder 50A of the upper threaded connection 50. The communication device may be electromagnetic, as explained, for example, in the Boyle et al. patent referred to above. The housing 40 may include one or more controllable bypass valves 54. The controllable bypass valves 54 may be operated, for example, by solenoids (not shown) to selectively enable part of the fluid flow through the pipe string (20 in FIG. 1) to be diverted into the wellbore (18 in FIG. 1) above turbine 41, thus reducing the output of the turbine 41. The housing 40 may include fixed discharge ports 56 below the turbine 41 to enable fluid flow to operate the turbine 41. The housing may include a lower threaded connection 58 that is configured to couple to an upper threaded connection 60 in the well logging instrument string, shown as power module 44 of the formation testing instrument, although the particular well logging instrument that couples to the adapter sub 12 is not a limit on the scope of the present invention.

In some circumstances it may be desirable to isolate the well logging instruments from flow of fluid through the wired pipe string (20 in FIG. 1). An example implementation shown in FIG. 7 can address the foregoing. The adapter sub 12 may include a turbine housing 40 as in the previous examples, in which may be disposed the turbine 41 and generator 43. The housing 40 in FIG. 7 can include a flow diverter 40A to direct flow from within the pipe string back up the wellbore (18 in FIG. 1). In the present example, an inflatable packer 62 may be disposed between the turbine housing 40 and the uppermost portion of the well logging instrument string, which may be the power conditioner module 44. The inflatable packer 62 may be any type known in the art and may be inflated using wellbore fluid or hydraulic fluid, for example. When the packer 62 is inflated, fluid moving above the packer 62 is prevented from affecting those portions of the well logging instruments below the packer 62. Such isolation may reduce the possibility of probe seal failure when extracting samples of formation fluid, for example.

In the event that the measurement and/or sampling procedure performed in the wellbore (18 in FIG. 1) requires the well logging instrument to be stationary, but the pipe string is not stationary at the surface, e.g. on a floating drilling platform having relatively ineffective heave compensation devices or in heavy wave conditions, a longitudinal slip joint may be included in the well logging instrument string. The longitudinal slip joint can also be used to compensate for thermal expansion of the wired pipe string (20 in FIG. 1) due to temperature changes. An example slip joint is shown at 70 in FIG. 8. In the present example, the slip joint may include an upper housing 72 engaged, for example, with the turbine housing 40, and a lower housing 74 engaged with the power conditioner module 44. The upper 72 and lower 74 housings slidably engage each other and may be sealed using o-rings 76 or similar sealing device that enables relative longitudinal movement between the upper and lower housings.

As explained above, the digital data handling rate (bandwidth) of typical wired pipe strings is about 1 million bits per second. As is known in the art, typical wireline configurable well logging instruments strings can generate signal data at large multiples of the bandwidth of typical wired pipe strings. Accordingly, it is desirable to use the available wired pipe string bandwidth to communicate to the surface those signals from the well logging instrument string (13 in FIG. 1) that are most valuable to obtain substantially as they are measured (in “real time”). Other data that are not typically valuable to obtain in real time, for example, instrument diagnostic measurements may be stored in a local data storage device. It is also desirable to be able to change the particular signals transmitted to the surface in real time, as well as to change the sample rate of such real time transmission. For example, certain well logging measurements, such as induction resistivity corresponding to large lateral distance from the wellbore, change relatively slowly with change in axial position of the well logging instrument string. It may be possible to send such measurements to the surface at relatively slow rates (e.g., 1-100 Hz), while measurements that change more rapidly (e.g. microresistivity measurements made for wellbore imaging) may be transmitted at much higher rates (e.g., 1 KHz to 1000 KHz).

An example signal processing and recording unit that can perform the foregoing telemetry conversion and formatting is shown in block diagram form in FIG. 9. The communication device 52 (also shown FIG. 6) in that couples signals to the signal communication channel in the wired pipe string is in signal communication with a telemetry transceiver 80 (“WDP transceiver”) configured to communicate signals in the telemetry format used for the wired pipe string (20 in FIG. 1). The WDP transceiver 80 is preferably bidirectional. A command decoder 82 may interrogate the telemetry signals from the WDP transceiver 80 to detect any commands originating from the recording unit (38 in FIG. 1). Such commands may include instructions to deploy the formation tester (10 in FIG. 1), to extract samples through the formation tester and to withdraw the formation tester from contact with the formations (11 in FIG. 1). Commands may also include instructions to send different instrument measurement signals from the well logging instrument string (13 in FIG. 1) to the recording unit (38 in FIG. 1) over the wired pipe string. Another type of instruction that may be detected in the command decoder 82 is time/depth records. As the pipe string is moved along the wellbore, the axial position in the wellbore (depth) of a reference point on the pipe string or on the instrument string may be used to indicate the depth of each instrument sensor in the instrument string. The depth is typically determined by measuring the elevation of the top drive (26 in FIG. 1) and adding to the elevation the length of all the individual components of the pipe string and instrument string. The elevation may be recorded automatically in the recording unit (38 in FIG. 1) by use of appropriate sensors on the drilling unit (24 in FIG. 1). The time/depth data may be used to generate a record with respect to depth of measurements made by the various sensors in the instrument string.

The command decoder 82 may transmit instructions to change the data sent over the wired pipe string to an intermediate telemetry transceiver 86. The intermediate telemetry transceiver 86 receives well logging instrument measurements from the instrument string by signal connection to a well logging instrument telemetry transceiver 88 in the instrument string 13. The well logging instrument telemetry transceiver 88 may be the same type as used in any wireline configurable well logging instrument string, and is preferably configured to transmit signals over an armored electrical cable (“wireline”) when the instrument string is deployed on a wireline. In the present example, all well logging instrument signals that would be transmitted over the wireline if so connected are communicated to the intermediate telemetry transceiver 86. Depending on the instruction from the surface some of the signals are communicated to the WDP telemetry transceiver 80 for communication over the wired pipe string. Remaining well logging instrument signals may be communicated to a mass data storage device 84 such as a solid state memory or hard drive. The mass data storage device 84 may also receive and store the same signals that are transmitted to the surface over the wired pipe string. The foregoing components, including the WDP telemetry 80, mass data storage 84, command decoder 82 and intermediate telemetry 86 may be enclosed in the adapter sub 12 in some examples. In other examples, the foregoing components may be enclosed in a separate housing (not shown) that is itself coupled to the adapter sub 12 and to the instrument string 13.

The invention as explained above may be used in conjunction with a number of other drilling and measurement devices known in the art. Non-limiting examples of such other devices may include the following. The wireline configurable well logging instruments may be inserted into a sleeve or a drill collar to protect them from being damaged during rotation and/or lateral movement, and can enable fluid pumped from the surface to flow around them for cooling purposes.

A sleeve or drill collar may cover less than the entire string of well logging instruments, thus allowing sections of the instrument string to come into direct contact with the formations (11 in FIG. 1) for measurement or sample extraction purposes.

A drill bit may be added at the bottom of the instrument string to allow drilling to continue while logging or between logging/sampling operations in conjunction with a drilling motor. The motor and/or a rotary steerable directional drilling system may be included between the drill bit and the well logging instruments to improve drilling efficiency and allow controlling the trajectory of the wellbore (18 in FIG. 1).

Logging while drilling (“LWD”) and/or measurement while drilling (“MWD”) instruments known in the art may be included at any location in the wired pipe string (20 in FIG. 1) to enable alternative measurements, or as a contingency to the failure of the well logging instrument string or failure of communication using the wired pipe string.

Stabilizers, reamers or wear bands may be placed on the foregoing sleeve or on a drill collar for directional control, wellbore conditioning, hole opening or other reasons.

Existing measurement while drilling telemetry technology (mud pressure modulation telemetry) may be used as two way communication with the surface instead of wired drill pipe or as a contingency to the failure of the wired drill pipe.

An example of the foregoing LWD and/or MWD instruments used as the wellbore instrument instead of the wireline configurable instrument (13 in FIG. 1) is shown in FIG. 10. A bottom hole assembly (“BHA”) 13A may include LWD instruments, such as a resistivity measuring device 80, and a combination sensor 82 including a directional sensor (including wellbore direction sensor D and wellbore inclination sensor I) and nuclear well logging sensors (including natural gamma ray sensor GR, density sensor DE and neutron sensor N). The particular arrangement of sensors shown in FIG. 10 is only meant to illustrate a possible BHA configuration and is not in any way intended to limit the scope of the invention. The foregoing sensors 80, 82 may be coupled to the lower end of the wired pipe string 20. Examples of the foregoing sensors include those used to provide services sold under the service marks CDR and CDN, which are service marks of an affiliate of the assignee of the present invention. A lower end of the sensor arrangement, shown at the bottom of combined sensor 82 may include a rotary steerable directional drilling system 84, which may include selectively operable pads 84A to urge the BHA 13A in a selected direction to change the trajectory of the wellbore. An example of a rotary steerable direction drilling system is one used to provide services sold under the service mark POWERDRIVE, which is a service mark of an affiliate of the assignee of the present invention. The lowermost end of the BHA 13A will typically include a drill bit 86 to increase the axial length (depth) of the wellbore by drilling.

In the example shown in FIG. 10, the adapter sub of the previously described examples may be modified into another type of adapter sub 12A which may include electric generation and signal communications devices as explained above, and may include a power storage device 12B, such as batteries or large capacitors (energy storage devices) to store electrical power produced, for example, by operation of a turbine in response to flow of drilling fluid through the pipe string. The adapter sub 12A in FIG. 10 would not need any form of mud flow bypass if the lower end is configured to be coupled to LWD and/or MWD instrument (which are usually disposed inside one or more drill collars having mud passages therethrough). During times when the turbine and generator are not operative, for example, during pipe connections, the power storage device 12B may provide sufficient power to operate all the sensors in the BHA 13A. In other examples, the power storage device 12A may operate a wireline configurable instrument string as shown in and as explained with reference to FIGS. 6 and 9.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A wellbore instrument system, comprising:

a pipe string extending from earth's surface to a selected depth in wellbore, the pipe string including at least one of an electrical conductor and an optical fiber signal channel

a power generator sub coupled at one end to a lower end of the pipe string; and

at least one electrically powered wellbore instrument coupled to the other end of the adapter sub.

2. The system of claim 1 wherein the power generator sub includes a turbine for converting flow of fluid through the pipe string into power to operate the at least one wellbore instrument.

3. The system of claim 2 wherein the turbine includes a device for adjusting response of the turbine to fluid flow.

4. The system of claim 3 wherein the response adjusting device includes at least one bypass valve disposed between the turbine and the pipe string.

5. The system of claim 2 wherein the turbine is functionally coupled to a generator.

6. The system of claim 2 wherein the turbine is functionally coupled to an hydraulic pump.

7. The system of claim 1 wherein the pipe string comprises pipe segments threadedly coupled end to end, each pipe segment including at least one signal communication device in a longitudinal end thereof for coupling signals to a device coupled to the pipe segment.

8. The system of claim 1 further comprising an inflatable packer disposed between the pipe string and the at least one wellbore.

9. The system of claim 1 further comprising at least one longitudinal slip joint disposed at a selected position along the system.

10. The system of claim 1 wherein the adapter sub comprises a first turbine coupled to a generator and a second turbine coupled to an hydraulic pump.

11. The system of claim 1 wherein the at least one wellbore instrument at least one of a formation testing instrument, an induction resistivity instrument, a gamma ray sensor.

12. The system of claim 1 further comprising a telemetry converted configured to receive signals from the at least one wireline configurable instrument and to reformat the signals for transmission over the pipe string.

13. The system of claim 1 wherein the wellbore instrument comprises at least one wireline configurable well logging instrument.

14. The system of claim 1 wherein the wellbore instrument comprises at least one logging while drilling instrument.

15. The system of claim 1 wherein the generator sub comprises a power storage device configured to operate the wellbore instrument during times when an electric generator in the generator sub is not operating.

16. A method for well logging, comprising:

moving at least one wellbore instrument along a wellbore at one end of a segmented pipe string, the pipe string including a signal communication channel associated therewith;

generating electrical power proximate a downhole end of the segmented pipe string to operate the wellbore instrument;

communicating measurements from at least one sensor in the instrument to the signal communication channel; and

detecting the communicated measurements at a surface end of the communication channel.

17. The method of claim 16 further comprising storing at least some of the measurements in a data storage device proximate the well logging instrument.

18. The method of claim 16 wherein the generating electrical power includes converting flow of fluid through the pipe string into power to operate the at least one well logging instrument.

19. The method of claim 18 wherein the converting comprises rotating a generator.

20. The method of claim 18 wherein the converting comprises rotating an hydraulic pump.

21. The method of claim 18 wherein the converting comprises rotating a turbine, the rotating including adjusting a response of the turbine to compensate for power load imparted by the well logging instrument.

22. The method of claim 16 further comprising changing a longitudinal distance between the pipe string and the wellbore.

23. The method of claim 16 further comprising storing electrical power proximate a location of the generating electrical power, and operating the at least one wellbore instrument during times when the generating electrical power is not performed using the stored electrical power.