CA2633904C - Battery assembly for a downhole telemetry system - Google Patents

Abstract

A system and method are provided for providing electromagnetic (EM) measurement-while--drilling (MWD) telemetry capabilities using an existing mud- pulse MWD tool. An EM tool intercepts the output from the mud-pulse tool and generates an EM signal that mimics a mud--pulse pressure signal. The EM signal is intercepted at the surface by a receiver module that conditions the signal and inputs the signal into the existing pulse tool receiver. Since the EM signal mimics a mud-pulse signal, the pulse tool receiver does not require software or hardware modifications in order to process an EM telemetry mode. The EM tool can be adapted to also provide dual telemetry by incorporating a conventional pressure pulser that would normally be used with the pulse tool.

Description

I BATTERY ASSEMBLY FOR A DOWNHOLE TELEMETRY SYSTEM

4 100011 The present invention relates generally to data acquisition during earth drilling operations and telemetry systems therefor, and has particular utility in measurement while 6 drilling (MWD) applications.

8 100021 The recovery of subterranean materials such as oil and gas typically requires 9 drilling wellbores a great distance beneath the earth's surface towards a repository of the material. The earthen material being drilled is often referred to as "formation". In addition to 11 drilling equipment situated at the surface, a drill string extends from the equipment to the 12 material formation at the terminal end of the wellbore and includes a drill bit for drilling the 13 wellbore.

14 [0003] The drill bit is rotated and drilling is accomplished by either rotating the drill string, or by use of a downhole motor near the drill bit. Drilling fluid, often termed "mud", is 16 pumped down through the drill string at high pressures and volumes (e.g.
3000 p.s.i. at flow rates 17 of up to 1400 gallons per minute) to emerge through nozzles or jets in the drill bit. The mud then 18 travels back up the hole via the annulus formed between the exterior of the drill string and the 19 wall of the wellbore. On the surface, the drilling mud may be cleaned and then re-circulated.
The drilling mud serves to cool and lubricate the drill bit, to carry cuttings from the base of the 21 bore to the surface, and to balance the hydrostatic pressure in the formation.

22 [0004] A drill string is generally comprised of a number of drill rods that are connected 23 to each other in seriatim. A drill rod is often referred to as a "sub", and an assembly of two or 24 more drill rods may be referred to as a "sub-assembly".

100051 It is generally desirable to obtain information relating to parameters and 26 conditions downhole while drilling. Such information typically relates to one or more 27 characteristics of the earth formation that is being traversed by the wellbore such as data related 28 to the size, depth and/or direction of the wellbore itself; and information related to the drill bit 21784503.1 I such as temperature, speed and fluid pressure. The collection of information relating to 2 conditions downhole, commonly referred to as "logging", can be performed using several 3 different methods. Well logging in the oil industry has been known for many years as a 4 technique for providing information to the driller regarding the particular earth formation being drilled.

6 100061 In one logging technique, a probe or "sonde" that houses formation sensors is 7 lowered into the wellbore once drilling has progressed or completed. The probe is supported by 8 and connected to the surface via an electrical wireline, and is used to obtain data and send the 9 data to the surface. A paramount problem with obtaining downhole measurements via a wireline is that the drilling assembly must be removed or "tripped" from the wellbore before the probe 11 can be lowered into the wellbore to obtain the measurements. Tripping a drill string is typically 12 time consuming and thus costly, especially when a substantial portion of the wellbore has been 13 drilled.

14 100071 To avoid tripping the drill string, there has traditionally been an emphasis on the collection of data during the drilling process. By collecting and processing data during the 16 drilling process, without the necessity of tripping the drill string, the driller can make 17 modifications or corrections to the drilling process as necessary. Such modifications and 18 corrections are typically made in an attempt to optimize the performance of the drilling operation 19 while minimizing downtime. Techniques for concurrently drilling the well and measuring downhole conditions are often referred to as measurement-while-drilling (MWD).
It should be 21 understood that MWD will herein encompass logging-while-drilling (LWD) and seismic-while-22 drilling (SWD) techniques, wherein LWD systems relate generally to measurements of 23 parameters of earth formation, and SWD systems relate generally to measurements of seismic 24 related properties.

100081 In MWD systems, sensors or transducers are typically located at the lower end of 26 the drill string which, while drilling is in progress, continuously or intermittently monitor 27 predetermined drilling parameters and formation data. Data representing such parameters may 28 then be transmitted to a surface detector/receiver using some form of telemetry. Typically, the 21784503.1 I downhole sensors employed in MWD applications are positioned in a cylindrical drill collar that 2 is positioned as close to the drill bit as possible.

3 100091 There are a number of telemetry techniques that have been employed by MWD
4 systems to transmit measurement data to the surface without the use of a wireline tool.

[0010] One such technique involves transmitting data using pressure waves in drilling 6 fluids such as drilling mud. This telemetry scheme is often referred to as mud-pulse telemetry.
7 Mud-pulse telemetry involves creating pressure signals in the drilling mud that is being 8 circulated under pressure through the drill string during the drilling operation. The information 9 that is acquired by the downhole sensors is transmitted utilising a particular time division scheme to effectively create a waveform of pressure pulses in the mud column. The information may 11 then be received and decoded by a pressure transducer and analysed by a computer at a surface 12 receiver.

13 100111 In a mud-pulse system, the pressure in the drilling mud is typically modulated via 14 operation of a valve and control mechanism, generally termed a pulser or mud-pulser. The pulser is typically mounted in a specially adapted drill collar positioned above the drill bit. The 16 generated pressure pulse travels up the mud column inside the drill string at the velocity of sound 17 in the mud, and thus the data transmission rate is dependent on the type of drilling fluid used.
18 Typically, the velocity may vary between approximately 3000 and 5000 feet per second. The 19 actual rate of data transmission, however, is relatively slow due to factors such as pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces such as 21 ambient noise in the transmission channel. A typical pulse rate is on the order of one pulse per 22 second (i.e. 1 Hz).

23 100121 An often preferred implementation of mud-pulse telemetry uses pulse position 24 modulation for transmitting data. In pulse position modulation, pulses have a fixed width and the interval between pulses is proportional to the data value transmitted. Mud-pressure pulses 26 can be generated by opening and closing a valve near the bottom of the drill string so as to 27 momentarily restrict the mud flow. In a number of known MWD tools, a "negative" pressure 28 pulse is created in the fluid by temporarily opening a valve in the drill collar so that some of the 21784503.1 1 drilling fluid will bypass the bit, the open valve allowing direct communication between the high 2 pressure fluid inside the drill string and the fluid at lower pressure returning to the surface via the 3 exterior of the string. Alternatively, a "positive" pressure pulse can be created by temporarily 4 restricting the downward flow of drilling fluid by partially blocking the fluid path in the drill string.

6 100131 Electromagnetic (EM) radiation has also been used to telemeter data from 7 downhole locations to the surface (and vice-versa). In EM systems, a current may be induced on 8 the drill string from a downhole transmitter and an electrical potential may be impressed across 9 an insulated gap in a downhole portion of the drill string to generate a magnetic field that will propagate through the earth formation. The signal that propagates through the formation is 11 typically measured using a conductive stake that is driven into the ground at some distance from 12 the drilling equipment. The potential difference of the drill string signal and the formation signal 13 may then be measured, as shown in US Patent No. 4,160,970 published on July 10, 1979.

14 100141 Information is transmitted from the downhole location by modulating the current or voltage signal and is detected at the surface with electric field and/or magnetic field sensors.
16 In an often preferred implementation of EM telemetry, information is transmitted by phase 17 shifting a carrier sine wave among a number of discrete phase states.
Although the drill string 18 acts as part of the conductive path, system losses are almost always dominated by conduction 19 losses within the earth which, as noted above, also carries the electromagnetic radiation. Such EM systems work well in regions where the earth's conductivity between the telemetry 21 transmitter and the earth's surface is consistently low. However, EM
systems may be affected 22 by distortion or signal dampening due to geologic formations such as dry coal seams, anhydrite, 23 and salt domes.

24 100151 Telemetry using acoustic transmitters in the drill string has also been contemplated as a potential means to increase the speed and reliability of the data transmission 26 from downhole to the surface. When actuated by a signal such as a voltage potential from a 27 sensor, an acoustic transmitter mechanically mounted on the tubing imparts a stress wave or 28 acoustic pulse onto the tubing string.

21784503.1 1 [0016] Typically, drillers will utilize one of a wireline system, a mud-pulse system, an 2 EM system and an acoustic system, most often either an EM system or a mud-pulse system.
3 Depending on the nature of the drilling task, it is often more favourable to use EM due to its 4 relatively faster data rate when compared to mud-pulse. However, if a signal is lost due to the presence of the aforementioned geological conditions, the rig must be shut down and the drill 6 string tripped to swap the EM system with an alternative system such as a mud-pulse system 7 which, although slower, is generally more reliable. The drill string would then need to be re-8 assembled and drilling restarted. The inherent downtime while tripping the drill string can often 9 be considerable and thus undesirable.

100171 In general, one problem associated with mud-pulse telemetry is that it can only be 11 used during the drilling operation as it relies on the flow of mud in the mud-column. When 12 drilling is interrupted, e.g. when adding a sub to the drill string, there is no medium to transmit 13 data.

14 100181 It is therefore an object of the present invention to obviate or mitigate at least one of the above-mentioned disadvantages.

17 100191 In one aspect, there is provided a battery assembly for a measurement while 18 drilling (MWD) tool string, the battery assembly comprising: a battery barrel configured to be 19 removably attachable at each end to other modules in the tool string; a battery comprising a first end and a second end, the first end and second end being visually and physically distinguishable 21 from each other to encourage loading the battery into the battery barrel in a single orientation;
22 and at least one retention mechanism attached to the interior of the battery barrel to centre the 23 battery in the battery barrel.

100201 An embodiment of the invention will now be described by way of example only 26 with reference to the appended drawings wherein:

21784503.1 1 100211 Figure 1 is a schematic view of a drilling system and its environment;

2 [0022] Figure 2(a) is an external plan view of a downhole portion of a mud pulse tool 3 drill string configuration.

4 100231 Figure 2(b) is an external plan view of a downhole portion of an EM
tool drill string configuration.

6 100241 Figure 3(a) is an external plan view of a mud pulse tool string.

7 100251 Figure 3(b) is an external plan view of a EM tool string.

8 100261 Figure 4 is a sectional view of a region of isolation in the EM tool string of Figure 9 3(b) along the line IV-IV showing the EM tool string positioned therein.

[0027] Figure 5 is an exploded perspective view of a gap sub-assembly.
11 100281 Figure 6 is an exploded view of a power supply.

12 100291 Figure 7 is a pair of end views of the battery barrel of Figure 6.

13 100301 Figure 8 is a sectional view along the line VIII-VIII shown in Figure 6.

14 100311 Figure 9 is a schematic diagram showing data flow from a directional module to a surface station via an EM transmitter module in an EM MWD system.

16 100321 Figure 10 is a schematic diagram of the EM transmitter module shown in Figure 17 9.

18 [0033] Figure 11 is a schematic diagram of a surface station utilizing a conventional 19 pulse telemetry system.

100341 Figure 12 is a schematic diagram of the EM surface system shown in Figure 9.
21 100351 Figure 13 is a plot showing signal propagation according to the arrangement 22 shown in Figure 9.

21784503.1 1 [0036] Figure 14 is a flow diagram illustrating an EM data transmission in the EM MWD
2 system shown in Figure 9.

3 [0037] Figure 15 is an external plan view of a downhole portion of an EM and pulse dual 4 telemetry tool drill string configuration.

100381 Figure 16 is an external plan view of an EM and pulse dual telemetry tool string.
6 [0039] Figure 17 is a schematic diagram showing data flow in an EM and pulse dual 7 telemetry MWD system.

8 100401 Figure 18 is a schematic diagram of the EM transmitter module shown in Figure 9 17.

100411 Figure 19 is a schematic diagram of the EM surface system shown in Figure 17.

11 100421 Figure 20(a) is a flow diagram illustrating a data transmission using EM and pulse 12 telemetry in the EM and pulse dual telemetry MWD system shown in Figure 17.

13 100431 Figure 20(b) is a flow diagram continuing from B in Figure 20(a).
14 [0044] Figure 20(c) is a flow diagram continuing from C Figure 20(a).
DETAILED DESCRIPTION OF THE DRAWINGS

16 [0045] The following describes, in one embodiment, an MWD tool providing EM
17 telemetry while utilizing existing pulse tool modules. In general, an EM
signal is generated by 18 repeating an amplified version of a conventional pulse signal that is intended to be sent to a pulse 19 module, and transmitting this repeated signal to the surface in an EM
transmission. In this way, the same components can be used without requiring knowledge of the encoding scheme used in 21 the pulse signal. Therefore, the following system is compatible with any existing downhole 22 directional module that generates a signal for a pulse module. The pulse signal can be 23 intercepted, amplified, and sent to an EM surface system by applying a potential difference 24 across a region of isolation in the drill string. The EM surface system receives, conditions and 21784503.1 I converts the received signal into a signal which is compatible with a conventional surface pulse 2 decoder. In this way, existing software and decoding tools already present in the pulse surface 3 decoder can be utilized while providing EM telemetry capabilities.

4 100461 In another embodiment, the following provided dual pulse and EM
telemetry capabilities by using a multiplexing scheme to direct the pulse signal to either the pulse module 6 for transmission using pulse telemetry or to the EM transmitter module for transmission using 7 EM telemetry. At the surface, the EM surface system receives either signal and routes the 8 appropriate signal to the pulse decoder. The pulse decoder is unable to distinguish between 9 telemetry modes enabling existing software and hardware offered by a pulse system can be used.
It will be appreciated that the following examples are for illustrative purposes only.

11 Drilling Environment 12 100471 Referring therefore to Figure 1, a drilling rig 10 is shown in situ at a drilling site 13 12. The rig 10 drills a wellbore 14 into an earth formation 16. The wellbore 14 is excavated by 14 operating a drill bit 18 disposed at a lower end 19 of a drill string 20.
The drill string 20 is supported at an upper end 21 by drilling equipment 22. As the bit 18 drills into the formation 16, 16 individual drill rods 24 are added to the drill string 20 as required. In the example shown in 17 Figure 1, the drill bit 18 is driven by a fluid or mud motor 26. The mud motor 26 is powered by 18 having the drilling equipment 22 pump drill fluid, hereinafter referred to as "mud", through a 19 hollow conduit 28 defmed by interior portions of the connected subs 24. The column of fluid held in the conduit 28 will hereinafter be referred to as a "mud column" and generally denoted 21 by the character "M".

22 100481 An MWD too130 is located within the drill string 20 toward its lower end 19.
23 The MWD tool 30 transmits data to the surface to a remote MWD surface station 34. The data 24 transmitted to the surface is indicative of operating conditions associated with the drilling operation. In one embodiment, the MWD tool 30 transmits the data to a pulse tool surface 26 system 32 via an EM surface system 38 using EM telemetry as explained below.

21784503.1 1 100491 The EM surface system 38 is used to receive, condition and convert data 2 transmitted in an EM signal such that the conditioned data is compatible with the pulse tool 3 surface system 32. The EM surface system 38 thus acts as an EM signal conditioner and is 4 configured to interface with the pulse decoder 32. Normally, a pressure transducer on the drilling equipment interfaces with the pulse decoder 32 and thus the interface between the EM
6 surface system 38 and the pulse decoder 32 is preferably similar to the interface between the 7 pulse decoder 32 and a connector from a data cable extending from the transducer. The pulse 8 decoder 32 is connected to a computer interface 36, e.g. a personal computer in the surface 9 station 34, to enable a user to interact with the MWD tool 30 remotely. The pulse decoder 32 also outputs a decoded signal to a rig floor display 45 via a data connection 44. Accordingly, the 11 MWD tool 30 shown in Figure 1 is configured to interface with and operate using existing mud 12 pulse modules from an existing pulse MWD system as will be explained in greater detail below.
13 100501 The EM transmission is generated by creating a potential difference across a 14 region of isolation 29 in the drill string 20 and is formed by generating an electromagnetic (EM) field F which propagates outwardly and upwardly through the formation 16 to the surface and 16 creating and transmitting a return signal S through the drill string 20. A
conductive member 50, 17 typically an iron stake driven into the formation 16, conducts the formation signal through a data 18 connection 52 to the EM surface system 38 and the return signal is transmitted from the surface 19 station 34 over line 41 to a connection on the drill rig 12. As can be seen in Figure 1, the negative dipole for the EM signal is provided by a connection to the drill string 20 at a location 21 which is above the region of isolation 29 and the positive dipole for the EM signal is provided by 22 a connection to the drill string 20 at a location which is below the region of isolation 29. It will 23 be appreciated that either signal (formation or drill string) can be the EM
signal or the return 24 signal, however the arrangement shown in Figure 1 is preferred since the drill string 20 typically provides a better reference than the formation 16.

26 100511 In another embodiment, the MWD tool 30 provided dual telemetry capabilities 27 thus capable of transmitting data to the surface receiver station 34 using either EM telemetry (as 28 discussed above), or mud pulse telemetry by transmitting data through the mud column M by 29 way of a series of pressure pulses. The pressure pulses are received by the pressure transducer, 21784503.1 I converted to an appropriate compatible signal (e.g. a current signal) which is indicative of the 2 information encoded in the pressure pulses, and transmitted over a data cable directly to the pulse 3 decoder 32 as will be explained in greater detail below.

4 MWD Tool - Downhole Configuration 100521 Referring to Figure 2(a), a conventional downhole drill string configuration for a 6 mud pulse MWD tool string 80 is shown (see Figure 3(a) for pulse tool string 80). An example 7 of such a mud pulse MWD tool is a TensorTM MWD tool sold by GE EnergyTM. The 8 conventional mud pulse drill string configuration comprises a drill bit 18 driven by a mud motor 9 26 connected thereto. Connected to the mud motor 26 is a universal bottom hole offset (UBHO) 60, which internally provides a tool string landing point for the pulse tool string 80. Connected 11 to the UBHO 60 is the serially connected drill rods 20 forming the upstream portion 62 of the 12 drill string 20. The upstream portion 62 of the drill string 20 is typically formed using a few 13 non-magnetic drill rods to provide a non-magnetic spacing between magnetically sensitive 14 equipment and the other drill rods, which can be magnetic.

100531 Referring to Figure 2(b), a downhole drill string configuration for an EM MWD
16 tool string 100 is shown (see Figure 3(b) for EM tool string 100). It can be seen in Figure 2(b) 17 that the drill bit 18, mud motor 26 and UBHO 60 are configured in the same way shown in 18 Figure 2(a), however, interposed between the UBHO 60 and the upstream portion 62 of the drill 19 string 20, is the region of isolation 29. In one embodiment, the region of isolation 29 comprises a first sub-assembly 64 connected to a second sub-assembly 67, wherein the first sub assembly 21 64 is comprised of a first sub 65 and second sub 66 isolated from each other by a first non-22 conductive ring 70 and the second sub-assembly 67 is comprised of a third sub 68 and fourth sub 23 69 isolated from each other by a second non-conductive ring 72. The EM tool string 100 is 24 preferably aligned with the region of isolation 29 such that a tool isolation 102 in the EM tool string 100 is situated between the first and second non-conductive rings 70, 72. However, it can 26 be appreciated that the region of isolation 29 is used to isolate the drill string 20 and thus the tool 27 isolation 102 may be above or below so long as there is a separation between points of contact 28 between the tool string 100 and the drill string 20 as will be discussed below. As will also be 21784503.1 1 discussed below, the EM tool string 100 is configured to interface with the existing UBHO 60 2 such that the EM tool string 100 can be used with the existing modules in a conventional pulse 3 tool string 80 such as those included in a GE TensorTM tool.

4 100541 The pulse tool string 80 is shown in greater detail in Figure 3(a).
The pulse tool string 80 is configured to be positioned within the drill string configuration shown in Figure 2(a).
6 The pulse tool string 80 comprises a landing bit 82 which is keyed to rotate the pulse tool string 7 80 about its longitudinal axis into a consistent orientation as it is being landed. The landing bit 8 82 includes a mud valve 84 that is operated by a mud pulse module 86 connected thereto. In 9 normal pulse telemetry operation, the mud valve 84 is used to create pressure pulses in the mud column M for sending data to the surface. A first battery 88, typically a 28 V
battery is 11 connected to the mud pulse module through a module interconnect 90. The module interconnect 12 90 comprises a pair of bow springs 92 to engage the inner wall of drill string 20 and center the 13 pulse tool string 80 within the drill string 20. The bow springs 92 are flexible to accommodate 14 differently sized bores and are electrically conductive to provide an electrical contact with the drill string 20. The interconnects 90 are typically rigid while accommodating minimal flexure 16 when compared to the rigidity of the tool string 100. Other interconnects (not shown) may be 17 used, which are not conductive, where an electrical contact is not required. such other 18 interconnects are often referred to as "X-fins".

19 100551 Another module interconnect 90 is used to connect the first battery 88 to a direction and inclination module 94. The direction and inclination module 94 (hereinafter 21 referred to as the "directional module 94") acquires measurement data associated with the 22 drilling operation and provides such data to the pulse module 86 to convert into a series of 23 pressure pulses. Such measurement data may include accelerometer data, magnetometer data, 24 gamma data etc. The directional module 94 comprises a master controller 96 which is responsible for acquiring the data from one or more sensors and creating a voltage signal, which 26 is typically a digital representation of where pressure pulses occur for operating the pulse module 27 86.

21784503.1 1 100561 Yet another module interconnect 90 is used to connect a second battery 98, 2 typically another 28 V battery, to the directional module 94. The second battery 98 includes a 3 connector 99 to which a trip line can be attached to permit tripping the tool string 80. The tool 4 string 80 can be removed by running a wireline down the bore of the drill string 20. The wireline includes a latching mechanism that hooks onto the connector 99 (sometimes referred to as a 6 "spearpoint"). Once the wireline is latched to the tool string 80, the tool string 80 can be 7 removed by pulling the wireline through the drill string 20. It will be appreciated that the tool 8 string 80 shown in Figure 3(a) is only one example and many other arrangements can be used.
9 For example, additional modules may be incorporated and the order of connection may be varied. Other modules may include pressure and gamma modules, which are not typically 11 attached above the second battery 98 but could be. All the modules are designed to be placed 12 anywhere in the tool string 80, with the exception of the pulse module 86 which is located at the 13 bottom in connection with the pulser 84.

14 100571 Referring now to Figure 3(b), the EM tool string 100 is shown. The EM tool string 100 is configured to be positioned within the downhole drill string configuration shown in 16 Figure 2(b). The EM tool string 100 comprises a modified landing bit 104 that is sized and 17 keyed similar to the landing bit 82 in the pulse tool string 80 but does not include the mud valve 18 84. In this way, the EM tool string 100 can be oriented within the drill string 20 in a manner 19 similar to the pulse tool string 80. In this embodiment, an EM transmitter module 106 is connected to the modified landing bit 104 in place of the mud pulse module 86.
The EM
21 transmitter module 106 includes electrical isolation 102 to isolate an upstream EM tool portion 22 108 from a downstream EM tool portion 110. The electrical isolation 102 can be made from any 23 non-conductive material such as a rubber or plastic. A quick change battery assembly 200 (e.g.
24 providing 14 V) may be used in place of the first battery 88 discussed above, which is connected to the EM transmitter module 106 using a module interconnect 90. It will be appreciated that 26 although the quick change battery assembly 200 is preferable, the first battery 88 described 27 above may alternatively be used. The directional module 94 and second battery 98 are connected 28 in a manner similar to that shown in Figure 3(a) and thus details of such connections need not be 29 reiterated.

21784503.1 1 [0058] It can therefore be seen that downhole, a conventional pulse tool string 80 can be 2 modified for transmitting EM signals by replacing the landing bit 82 and pulse module 86 with 3 the modified landing bit 104 and EM transmitter module 106 while utilizing the other existing 4 modules. The modified landing bit 104 enables the EM transmitter module 106 to be oriented and aligned as would the conventional pulse module 86 by interfacing with the UBHO 60 in a 6 similar fashion.

7 Region of Isolation - Gap Sub-Assembly 8 100591 The placement of the EM tool string 100 within the conduit 28 of the drill string 9 20 is shown in greater detail in Figure 4. As discussed above, the EM tool string 100 is aligned with the region of isolation 29, and the region of isolation 29 comprises a first sub-assembly 64 11 connected to a second sub-assembly 67, wherein the first sub-assembly 64 comprises first and 12 second subs 65, 66 and the second sub-assembly 67 comprises third and fourth subs 68, 69. As 13 can be seen, the shoulders of the subs 65 and 66 are separated by a non-conductive ring 70, and 14 the threads of the subs 65 and 66 are separated by a non-conductive layer 71. Similarly, the shoulders of the subs 68 and 69 are separated by another non-conductive ring 72, and the threads 16 of the subs 68 and 69 are separated by another non-conductive layer 73. The rings 70 and 72 are 17 made from a suitable non-conductive material such as a ceramic. Preferably, the rings 70 and 18 72 are made from either TechnoxTM or YTZP-HippedTM, which are commercially available 19 ceramic materials that possess beneficial characteristics such as high compressive strength and high resistivity. For example, TechnoxTM 3000 grade ceramic has been shown to exhibit a 21 compressive strength of approximately 290 Kpsi and exhibit a resistivity of approximately 109 22 Ohm-cm at 25 C.

23 (0060] The subs each have a male end or "pin", and a female end or "box".
For 24 constructing the region of isolation 29, the pins and boxes that mate together where the ceramic ring 70, 72 is placed should be manufactured to accommodate the ceramic rings 70, 72 as well as 26 other insulative layers described below. To accommodate the rings 70, 72, the pin end of the 27 subs are machined. Firstly, the shoulder (e.g. see 59 in Figure 5) is machined back far enough to 28 accommodate the ceramic ring 70, 72. It has been found that using a 1/2"
zirconia ring with a 21784503.1 1 1/2" reduction in the shoulder is particularly suitable. The pin includes a thread that may be 2 custom or an API standard. To accommodate the isolation layers 71, 73, the thread is further 3 machined to be deeper than spec to make room for such materials. It has been found that to 4 accommodate the layers 71 and 73 described in detail below, the pins can be machined 0.009" to 0.0010" deeper than spec. The shoulders are machined back to balance the torque applied when 6 connecting the subs that would normally be accommodated by the meeting of the shoulders as 7 two subs come together.

8 100611 The thread used on the pins is preferably an H90 API connection or an 9 API connection due to the preferred 90 thread profile with a relatively course. This is preferred over typical 60 thread profiles. It will be appreciated that the pins can be custom machined to 11 include a course thread and preferably 90 thread profile. To achieve the same effect as the H90 12 API connection, a taper of between 1.25" and 3" per foot should be used. In this way, even 13 greater flexibility can be achieved in the pin length, diameter and changes throughout the taper.
14 100621 In one embodiment, the insulative layers 71, 73 comprise the application of a coating, preferably a ceramic coating, to the threads of the pins to isolate subs 65 from sub 66 16 and sub 68 from sub 69. A suitable coating is made from Aluminium Oxide or Titanium 17 Dioxide. This locks the corresponding subs together to provide complete electrical isolation.

18 When using a ceramic coating, the pin should be pre-treated, preferably to approximately 350 C.
19 Also when applying the ceramic coating, the pin should be in constant rotation and the feed of the applicator gun should be continuous and constant throughout the application process. It will 21 be appreciated that any insulative coating can be applied to the threads.
As noted above, the 22 threads are manufactured or modified to accommodate the particular coating that is used, e.g., 23 based on the strength, hardness, etc. of the material used and the clearance needed for an 24 adequate layer of isolation.

100631 In another embodiment, after application of the ceramic coating, a layer of 26 electrical tape or similar thin adhesive layer can be included in the insulative layers 71 and 73 to 27 add protection for the ceramic coating from chipping or cracking from inadvertent collisions.
21784503.1 1 The electrical tape provides a smooth surface to assist in threading the subs together while also 2 providing a layer of cushioning.

3 100641 The insulative layers 71 and 73 can, in another embodiment, also comprise a cloth 4 or wrapping made from a fabric such as, Vectran, Spectra, Dyneema, any type of Aramid fiber fabric, any type of ballistic fabric, loose weave fabrics, turtle skin weave fabrics to name a few.
6 In general, a material that includes favourable qualities such as high tensile strength at low 7 weight, structural rigidity, low electrical conductivity, high chemical resistance, low thermal 8 shrinkage, high toughness (work-to-break), dimensional stability, and high cut resistance is 9 preferred. In general, the insulative layers 71 and 73 and the rings 70 and 72 provide electrical isolation independent of the material used to construct the subs 65, 66, 68 and 69. However, 11 preferably the subs 65, 66, 68 and 69 are made from a non-magnetic material so as to inhibit 12 interference with the electromagnetic field F.

13 100651 The insulative layers 71, 73 may further be strengthened with an epoxy type 14 adhesive which serves to seal the sub assemblies 64, 67. In addition to the epoxy adhesive, a relief 179 may be machined into the box of the appropriate subs as seen in the enlarged portion 16 of Figure 4. The relief 179 is sized to accommodate a flexible washer 180, preferably made from 17 polyurethane with embedded rubber o-rings 182. The washer 180 is placed in the relief such that 18 when the pin is screwed into the box, the outside shoulders 59, 75 (see Figure 5 also) engage the 19 ceramic ring 70 or 72, an inside shoulder also engages where the washer 180 is seated. The polyurethane is preferably a compressible type, which can add significant safeguards in keeping 21 moisture from seeping into the threads. The addition of the o-rings 182 provides a further 22 defence in case of cracking or deterioration of the polyurethane or similar material in the washer 23 180. In this way, even if the epoxy seal breaks down, a further layer of protection is provided.
24 This can prolong the life of the region of isolation 29 and can prevent moisture from shorting out the system.

26 [0066] Figure 5 illustrates an exploded view of an exemplary embodiment of the first 27 sub-assembly 64 utilizing a ceramic coating and a wrapping of woven fabric in addition to the 28 other insulative layers discussed above. In a preferred assembly method, the sub-assembly 64 is 21784503.1 1 assembled by applying the ceramic coating to the pin of the sub 65 and then applying a layer of 2 electrical tape (not shown). The ceramic ring 70 is then slid over the male-end of the first sub 65 3 such that it is seated on the shoulder 59. The epoxy may then be added over the electrical tape to 4 provide a moisture barrier. A wax string may also be used if desired. The washer 180 is then inserted into the relief 179. The wrapping 71 a is then wrapped clockwise around the threads of 6 the pin of the sub 65 over the electrical tape, as the female-end of the second sub 66 is screwed 7 onto the male-end of the first sub 65, until the shoulder 75 engages the ring 70. As the female-8 end of the second sub 66 is screwed onto the male-end of the first sub 65.
In this way, the ring 9 70 provides electrical isolation between the shoulders 59 and 75, and the cloth 71a, ceramic, tape and epoxy provides electrical isolation between the threads. As such, the sub 65 is electrically 11 isolated from the sub 66. It will be appreciated that the second sub-assembly 67 can be 12 assembled in a similar manner.

13 100671 It will be appreciated that all of the above insulative materials can be used to 14 provide layer 71 as described, as well as any combination of one or more.
For example, the ceramic coating may be used on its own or in combination with woven fabric 71 a. It can be 16 appreciated that each layer provides an additional safeguard in case one of the other layers fails.

17 When more than one insulative material is used in conjunction with each other, the isolation can 18 be considered much stronger and more resilient to environmental effects.

19 100681 As shown in Figure 4 (also seen in Figure 2(b)), the sub-assemblies 64 and 67 are connected together without any electrical isolation therebetween. The upstream tool portion 108 21 is electrically connected to the drill string 20 at contact point 74 and the downstream tool portion 22 110 is electrically connected to the drill string 20 at contact point 76 provided by the interface of 23 the modified landing bit 104 and the UBHO 60. It can be seen that the sub-assemblies 64 and 67 24 should be sized such that when the modified landing bit 76 is seated in the UBHO 60, the tool isolation 102 is between the non-conductive rings 70 and 72 and more importantly, such that the 26 bow springs 92 contact the drill string 20 above the region of isolation 29. This enables the 27 electric field F to be created by creating the positive and negative dipoles.
28 Power Supply - Quick Change battery 21784503.1 1 100691 As discussed above, the EM tool string 100 may include a quick change battery 2 assembly 200. The quick change battery assembly 200 can provide 14V or can be configured to 3 provide any other voltage by adding or removing battery cells. Preferably, the quick change 4 battery assembly 200 is connected to the other modules in the EM tool string 100 as shown in Figures 6-8. Referring first to Figure 6, an exploded view is provided showing the connections 6 between the battery assembly 200 and the EM module 104 using module interconnect 90. In the 7 example shown, the battery assembly 200 includes a battery barrel 208 that is connected directly 8 to the module interconnect 90 at one end 201 and thus the end 201 includes a similar 9 interconnection. A bulkhead 202 is connected to the other end 203 of the battery barrel 208 to configure the end 203 for connection to the module interconnect 90 attached further upstream of 11 the directional module 94. Typically, another battery assembly 98 is in turn connected to the 12 directional module 94 as discussed above.

13 100701 The battery barrel 208 houses a battery 210. The battery 210 includes a number 14 of battery cells. It will be appreciated that the barrel 208 can be increased in length to accommodate longer batteries 210 having a greater number of cells. The battery 210 in this 16 example includes a lower 45 degree connector 212 and an upper 90 degree connector 214. The 17 lower connector 212 preferably includes a notch 213, which is oriented 45 degrees from the 18 orientation of a notch 215 in the upper connector 214. The notches 213 and 215 are shown in 19 greater detail in Figure 7. The notches 213 and 215 are different from each other so as to be distinguishable from each other when the battery 210 is installed and thus minimize human error 21 during assembly. As can be seen in Figure 7, the notches 213 and 215 are generally aligned with 22 respective retention mechanisms 220 and 222. The mechanisms 220 and 222 are preferably pin 23 assemblies that maintain the position of the battery 210 in the barrel 208.

24 100711 The upper end 214 of the battery 210 is preferably centered in the barre1208 using a bushing 216, as shown in Figures 7 and 8 (wavy line in Figure 7). The bushing 216 is 26 arranged along the inside of the barrel 208 at end 203 and situates the upper connector 214 to 27 inhibit movement and potential cracking of the battery casing.

21784503.1 1 [0072] The battery 210 can be changed in the field either by removing the battery barrel 2 208 from the EM module 104 and the directional module 94 or, preferably, by disconnecting the 3 directional module 94 from the bulkhead 202 (which disconnects the upper connector 214);

4 disconnecting the lower connector 212 from the EM module 104 by pulling the battery 210 from the barrel 208 and bulkhead 202; replacing the battery 210 with a new battery;
and reassembling 6 the EM module 104, barrel 208 and directional module 94. Since the upper connector 214 and 7 lower connector 212 are visually different, the nature of the battery 210 should assist the operator 8 in placing the battery 210 in the barrel 208 in the correct orientation.
Similarly, since, in this 9 example, only the end 203 connects to a bulkhead 202, if the entire battery assembly 200 is removed, the ends 201, 203 should be obviously distinguishable to the operator.

11 [0073] It can therefore be seen that the battery 210 can be readily removed from the 12 barrel. 208 when a new battery is to replace it. The arrangement shown in Figures 6-8 thus 13 enables a "quick change" procedure to minimize the time required to change the battery 210, 14 which can often be required in poor environmental conditions. It can be appreciated that minimizing downtime increases productivity, which is also desirable.
16 MWD Tool - First Embodiment 17 100741 A schematic diagram showing data flow in one embodiment, from a series of 18 downhole sensor 120 to the surface station 34 using the EM tool string 100 is shown in Figure 9.
19 The sensors 120 acquire measurements for particular downhole operating parameters and communicate the measurements to the master controller 96 in the directional module 94 by 21 sending an arbitrary m number of inputs labelled INI, IN2, ... , INm from an arbitrary m number 22 of sensors 120. The master controller 96 is part of an existing pulse MWD
module, namely the 23 directional module 94, as discussed above. The master controller 96 generates and outputs a 24 pulse transmission signal labelled PtX which is an encoded voltage pulse signal.

100751 Generally, encoding transforms the original digital data signal into a new 26 sequence of coded symbols. Encoding introduces a structured dependency among the coded 27 symbols with the aim to significantly improve the communication performance compared to 28 transmitting uncoded data. In one scheme, M-ary encoding is used (e.g. in the GE TensorTM
21784503.1 1 tool), where M represents the number of symbol alternatives used in the particular encoding 2 scheme.

3 100761 The encoded data is then modulated, where, modulation is a step of signal 4 selection which converts the data from a sequence of coded symbols (from encoding) to a sequence of transmitted signal alternatives. In each time interval, a particular signal alternative 6 is sent that corresponds to a particular portion of the data sequence. For example, in a binary 7 transmission, where two different symbols are used, the symbol representing a"high" or "1 ", 8 will be sent for every "1" in the sequence of binary data. In the result, a waveform is created that 9 carries the original analog data in a binary waveform. Where M is greater than 2, the number of symbol alternatives will be greater and the modulated signal will therefore be able to represent a 11 greater amount data in a similar transmission.

12 100771 M-ary encoding typically involves breaking up any data word into combinations 13 of two (2) and three (3) bit symbols, each encoded by locating a single pulse in one-of-four or 14 one-of-eight possible time slots. For example, a value 221 encodes in M-ary as 3, 3, 5. The 3, 3, 5 sequence comes from the binary representation of 221, which is 11 ( 011 1101. In this way, the 16 first 3 comes from the 2-bit symbol 11, the second 3 comes from the 3-bit symbol 011, and the 5 17 comes from the 3-bit symbol 101.

18 100781 It can be appreciated that different directional modules 94 may use different 19 encoding schemes, which would require different decoding schemes. As will be explained below, the EM transmitter module 106 is configured to intercept and redirect an amplified 21 version of Ptx such that the EM transmitter module 106 is compatible with any directional 22 module 94 using any encoding scheme. In this way, the EM transmitter module 106 does not 23 require reprogramming to be able to adapt to other types of directional modules 94. This 24 provides a versatile module that can be interchanged with different mud pulse systems with minimum effort.

26 [0079] The output P, is a modulated voltage pulse signal. The modulated signal is 27 intended to be used by the pulse module 86 to generate a sequence of pressure pulses according 28 to the modulation scheme used. However, in the embodiment shown in Figure 9, the EM
21784503.1 1 transmitter module 106 intercepts the modulated voltage signal. The EM
transmitter module 106 2 includes an EM controller module 122 and an EM amplifier module 124. The controller module 3 122 intercepts Pt,, and also outputs a flow control signal f and communication signal Comm. The 4 flow control signalf is used to determine when "flow" is occurring in the drilling mud.
Ultimately, when fluid is being pumped downhole ("flow on" condition), drilling has 6 commenced and data is required to be transmitted to the surface. Although EM
telemetry does 7 not require "flow" in the drilling mud to be operational, existing directional modules 94 are 8 designed to work with pulse modules 86. As such, existing directional modules 94 require flow 9 in order to operate since pressure pulses cannot be created in a static fluid column M. Moreover, when flow stops, the drill string 20 and the MWD too130 become "stable" and allow other more 11 sensitive measurements to be acquired (e.g. accelerometer and magnetometer data), stored and 12 transmitted on the next "flow on" event.

13 100801 The flow control signalf in the EM controller module 122 is used to instruct the 14 master controller 96 when a consistent vibration has been sensed by the vibration switch 128.
The master controller 96 may then use the flow signalf to activate its internal "flow on" status.
16 The Comm signal is used to allow communication between the EM controller module 122 and 17 the master controller 96. Such communication allows the EM controller module 122 to retrieve 18 operational information that the MWD operator has programmed into the master controller 96 19 before the job has commenced, e.g. current limit values.

100811 The EM controller module 120 and EM amplifier module 122 are shown in 21 greater detail in Figure 10. The controller module 120 comprises a microcontroller 126, which 22 receives the encoded P,,, signal, and generates the flow control signal f The flow signalf is 23 generated in response to an output from a vibration switch 128 connected to the microcontroller 24 126. The vibration switch 128 responds to vibrations in the drill string 20 generated by mud flow, which is generated by a mud pump included in the surface drilling equipment 22. The 26 microcontroller 126 also communicates with a serial driver 130 to generate the Comm signal. In 27 a GE TensorTM tool, the Comm signal is referred to as the Qbus.

21784503.1 1 100821 Optionally, the controller module 120 may also include a clock 132 for time 2 stamping information when such information is stored in the EM controller module log memory 3 134. This enables events stored in the logging memory 134 to be correlated to events stored in 4 memory in the master controller 96 or events that occur on the surface, once the memory is downloaded. The EM controller module 122 is thus capable of logging its own operational 6 information (e.g. current limits, resets etc.) and can log information it receives via the Comm line 7 connected to the master controller 96 (e.g. mode changes).

8 100831 A data connection D may also be provided for communicating between the EM
9 controller module 122 and an optional EM receiver (not shown) that can be included in the EM
transmitter module 106. This can be implemented for providing bi-directional communication 11 allowing the EM transmitter module 106 to receive commands/information from the surface 12 system 34 via EM signals and relay the information to the EM controller module 122.

13 100841 The microcontroller 126 passes the encoded pulse signal PtX to the EM amplifier 14 module 124. The microcontroller 126 also outputs voltage and current limit signals Vl;,,, and Il,m respectively that are used by the amplifier module 124 to control a voltage limiter 136 and a 16 current limiter 138 respectively. The EM signal is fed into an amplifier 140 in the amplifier 17 module 124 in order to repeat an amplified version of the Pt,, signal in an EM transmission to the 18 surface.

19 100851 A current sense module 142 is also provided, which senses the current in the EM
signal that is to be transmitted, namely EMt, as feedback for the current limiter and to generate a 21 current output signal Ioõt for the controller module 122. The amplified EM
signal labelled EM' is 22 monitored by the voltage limiter 136 and output as Voõt to the controller module 122. As can be 23 seen in Figure 9, a connection point 74 above the isolation 102 provides a conductive point for 24 return signal EMret, and EMt,t is sent to a connection 76 in the UBHO 60, which as shown in Figure 3(b) is naturally below the isolation 102.

26 100861 The EM transmit signal EMtX is the actual EM transmission, and is sent through 27 the formation 16 to the surface. The EM return signal EMret is the return path for the EM

28 transmission along path S through connection 144. It will be appreciated that either signal (EMt,, 21784503.1 1 or EMret) can be the signal or the return, however the arrangement shown in Figure 9 is preferred 2 since the drill string 20 typically provides a better reference than the formation 16. EMt, 3 propagates through the formation as a result of creation of the positive and negative dipoles 4 created by the potential difference across the connections 74 and 76, which creates the electric field F. The ground stake 50 conducts the EM signal and propagates a received signal EM, 6 along line 52 to the surface station 34.

7 [0087] The surface station 34, when using conventional mud pulse telemetry may include 8 the components shown in Figure 11. A mud pulse signal which propagates up through the 9 drilling mud M is received and interpreted by a pressure transducer, which sends a current signal to the pulse decoder 32. The pulse decoder 32 then decodes the current signal and generates an 11 output to send to the PC 36 for the user to interpret, which may also be sent to the rig floor 12 display 45. As can be seen in Figure 9, where the conventional mud pulse system is adapted to 13 transmit using EM telemetry, the EM surface system 38 intercepts the incoming EM signal EM, 14 and generates an emulated received pulse signal labelled Pr,,'. The emulated pulse signal P,' is generated such that the pulse decoder 32 cannot distinguish between it and a normal received 16 pulse signal PrX. In this way, the pulse decoder 32 can be used as would be usual, in order to 17 generate an output OUT1 for the PC 36, output OUT2 for the rig floor display 45.

18 100881 The PC 36 is generally used only for interfacing with the system, e.g.
19 programming the MWD toolstring 100 and pulse decoder 32, and to mimic the rig floor display 45 so that the operator and directional driller can see in the surface station 34 what is seen on the 21 rig 10 without leaving the station 34. Optionally, an interface connection 148 may be provided 22 between the PC 36 and the EM surface system 38 for controlling parameters thereof and to 23 communicate downhole as discussed above. The operator may thus use the PC
36 to interface 24 with the EM surface system 38 and send changes in the operational configuration by way of another EM signal (not shown), which may or may not be encoded in the same way as the master 26 controller 96, downhole via EMTet and EM,/EM,,,. The EM receiver would then receive, decode 27 and communicate configuration changes to the EM controller module 122. The EM receiver 28 module would thus be in communication with EMLet and EMt,, downhole.
21784503.1 1 100891 The EM surface system 38 is shown in greater detail in Figure 12. The received 2 EM signal EMrx is fed into a first gain amplifier 150 with the return signal EMret also connected 3 to the amplifier 150 in order to provide a ground reference for the EM
signal EMrX. The 4 amplifier 150 measures the potential difference of the received EM signal EMr,, and the ground reference provided by the return signal EMret and outputs a referenced signal.
The referenced 6 signal is then filtered at a first filtering stage 151. The first filtering stage 151 may employ a 7 band reject filter, low pass filter, high pass filter etc. The filtered signal is then fed into a second 8 gain amplifier 152 to further amplify the signal, which in turn is fed into a second filtering stage 9 153. The second filtering stage 153 can be used to filter out components that have not already been filtered in the first filtering stage 151. The filtered signal is then fed to a third gain 11 amplifier 154 in order to perform a fmal amplification of the signal. It will be appreciated that 12 the number of filtering and amplification stages shown in Figure 12 are for illustrative purposes 13 only and that any number may be used in order to provide a conditioned signal. The signal is 14 then fed into a pressure transducer emulator 158, which converts the filtered and amplified voltage signal into a current signal thus creating emulated pulse signal PrX'.
The emulated pulse 16 signal P,' is then output to the pulse decoder 32.

17 [0090] It can be seen in Figure 12 that the filtering and amplification stages 150-154 each 18 include a control signal 160 connected to a user interface port 156. The user interface port 156 19 communicates with the PC 36 enabling the user to adjust the gain factors and filter parameters (e.g. cut off frequencies). It will be appreciated that rather than employing connection 148 to the 21 PC 36, the EM surface system 38 may instead have its own user interface such as a display and 22 input mechanism to enable a user to adjust the gain and frequency parameters directly from the 23 EM surface system 38.

24 Exemplary Data Transmission Scheme - First Embodiment 100911 Referring now to Figures 13 and 14, an example data transmission scheme for the 26 embodiment shown in Figures 9-12 will now be explained. Measurements are first obtained by 27 one or more of the sensors 120, typically while the equipment 22 is drilling. Measurements can 28 be obtained from many types of sensors, e.g. accelerometers, magnetometers, gamma, etc. As 21784503.1 1 discussed above, the sensors 120 feed data signals IN 1, IN2, ..., IN,,, to the master controller 96 in 2 the directional module 94. The master controller 96 encodes the data using its predefmed 3 encoding scheme. As mentioned above, a GE TensorTM tool typically utilizes M-ary encoding.
4 Other pulse tools may use a different type of encoding. The encoded pulse signal P," is then output by the master controller 96. As discussed above, EM controller 122 is compatible with 6 any type of encoding scheme and is not dependent on such encoding. As such, the EM
7 transmitter module 106 can be used with any type of pulse system without requiring additional 8 programming.

9 100921 The pulse signal PtX is intended to be sent to the pulse module 86 but is intercepted by the EM transmitter module 106. Regardless of the encoding scheme being used, 11 the microcontroller 126 obtains and redirects the pulse signal Pt,t to the EM amplifier module 12 124. The microcontroller 126 does not decode or have to interpret the pulse signal P,,, in any 13 way and only redirects the signal to the amplifier module 124. The amplifier 140 amplifies the 14 P,,, signal to create amplified EM signal EM', which is transmitted from the EM transmitter module 106 as EM signal EM,,, with a return path being provided for return signal EMret.
16 100931 During operation, the amplified signal EM' is fed through the current sense 17 module 142 to continuously obtain a current reading for the signal. This current reading is fed 18 back to the current limiter 138 so that the current limiter 138 can determine if the amplifier 140 19 should be adjusted to achieve a desired current. The current and voltage limit and amplification factor are largely dependent on the type of battery being used and thus will vary according to the 21 equipment available. The voltage of the amplified signal is also monitored by the voltage limiter 22 136 to determine if the amplifier 140 should be adjusted to achieve a desired voltage. The 23 microcontroller 126 also monitors the amplified output voltage Voõt and amplified output current 24 Ioõt to adjust the voltage limit Vi;,,, and current limit h;,,, signals.

[0094] The limits are typically adjusted according to predetermined parameters 26 associated with the directional module 94 which are used in order to increase or decrease signal 27 strength for different formations and are changed downhole by instructing the master controller 28 96 with different modes. The EM controller module 122 is used to communicate with the master 21784503.1 1 controller 96 as discussed above, to determine the active mode and to set the current limit 2 accordingly. Typically, the current limit is set as low as possible for as long as possible to save 3 on power consumption, however, this factor is largely dependent on transmission capabilities 4 through the formation and the available battery power.

100951 During operation, the microcontroller 126 also generates the flow signalf and 6 Comm signal to indicate when flow is detected and to effect communication with the master 7 controller 96.

8 [0096] The transmitted EM signal is received at the EM surface system 38 as EM,, and 9 the signal returned via EMSet. These signals are typically in the milli-volt to micro-volt range, which is largely dependent on the depth of the down hole antenna and the formation resistance.
11 The potential difference of these signals is then measured by the first amplifier 150 and a 12 combined signal amplified and filtered to compensate for attenuation and altering caused by the 13 formation. The amplified and filtered signal is then fed into the pressure transducer emulator 14 158 to convert the voltage pulse sent via EM telemetry, into a current signal. It has been found that for a GE TensorTM pulse decoder 32, a current signal in the range of 4-2OmA is sufficient to 16 mimic the pulse signal P, normally sent by a pressure transducer. This conversion ensures that 17 the emulated pulse signal Pr,' is compatible with the pulse decoder 32.
This avoids having to 18 create new software and interfaces while enabling the user to utilize EM
telemetry with existing 19 directional modules.

100971 The emulated current signal P,' is then fed into the pulse decoder 32.
The pulse 21 decoder 32 then decodes and outputs the information carried in the encoded signal to the PC 36 22 enabling the user in the surface station 34 to monitor the downhole parameters. Another output 23 can also be transmitted simultaneously via line 44 to the rig floor display 45 to enable the drilling 24 equipment operators to also monitor the downhole conditions. Figure 13 shows an exemplary signal plot at the various stages discussed above.

26 [0098] Mode changes can be executed in the downhole tool string by communicating 27 from the surface system to the downhole tool string. Some forms of communication can include, 28 but are not limited to, downlinking and EM transmissions. Downlinking is only one common 21784503.1 1 form of communication, in particular for a GE TensorTM tool, for changing between pre-2 configured modes in the master controller 96. Downlinking can be performed by alternating 3 flow on and flow off (pumps on, pumps off) at the surface, with specific timing intervals, where 4 certain intervals correlate to different modes. The flow on and flow off events are detected by the vibration switch 138 on the EM controller module 122 and in turn the flow signalf is toggled 6 accordingly. This is then interpreted by the master controller 96, which is always monitoring the 7 flow linef for a downlink. Once a downlink has occurred, depending on the timing interval, the 8 master controller 96 changes to the desired mode. The EM controller module 122 communicates 9 via the Comm line to the master controller 96 to determine the correct mode, and adjusts its own settings accordingly (e.g. pulse/EM operation - dual telemetry discussed below, current limit, 11 etc.). The surface system 38 is also watching for the flow events and changes its operating mode 12 to match the downhole situation.

13 [0099] The MWD tool 30 shown in Figures 9-12 enables a driller to upgrade or add EM
14 capabilities to existing mud-pulse systems. When switching between telemetry modes in a single telemetry embodiment, only the pulse module 86 and landing bit 82 needs to be removed 16 downhole (along with batteries as required), and a connection swapped at the surface station 34.
17 The connection would be at the pulse decoder 32, namely where a pressure transducer would 18 normally be connected to the pulse decoder 32. In order to switch the downhole components 19 between mud-pulse telemetry and EM telemetry, the drill string 20 could be tripped, however, switching at the surface can be effected off-site by simply swapping connectors at the pulse 21 decoder 32 and there would be no need to access the rig 10 or drilling equipment 22 in order to 22 make such a change. The pressure transducer can thus remain installed in the rig 10 whether EM
23 or mud-pulse telemetry is used. Of course, a wireline could instead be used rather than tripping 24 the entire drill string 20 to add further efficiencies.

1001001 It may be noted that when a switch between telemetry modes is made between 26 shifts, i.e. when the string 20 is to be tripped anyhow, the driller will not likely be unduly 27 inconvenienced. The qu.ick change battery 200 can also be used to save time since it can be 28 swapped in an efficient manner.

21784503.1 1 MWD Tool - Second Embodiment 2 [00101] In another embodiment, shown in Figures 15-20, the MWD tool 30 is adapted to 3 offer dual telemetry capabilities, in particular, to accommodate both an EM
telemetry mode and 4 mud-pulse telemetry mode without tripping either or both of the tool string and drill string. It will be appreciated that in the following description, like elements will be given like numerals, 6 and modified ones of the elements described above will be given like numerals with the suffix 7 "a" to denote modules and components that are modified for the second embodiment.

8 1001021 Referring first to Figure 15, a downhole drill string configuration for the second 9 embodiment is shown. As can been seen, the drill bit 18 and mud motor 26 are unchanged, as well as the upstream portion 62 of the drill string 20 and the region of isolation 29. In order to 11 accommodate both the EM transmitter module 106 and the pulse module 86 in a dual telemetry 12 tool string 170, an elongated, modified UBHO 60a is used. The modified UBHO
60a 13 compensates for the increased distance between where the tool string 170 lands and where the 14 isolation 102 is in alignment with the region of isolation 29. As shown in Figure 16, the dual telemetry tool string 170 includes the traditional landing bit 82 with the pressure valve 84, which 16 is connected to the pulse module 86. A modified interconnect 91 is then used to connect the EM
17 transmitter module 106 to above the pulse module 86. Upstream from the EM
transmitter 18 module 106 is the same as shown in Figure 3(b) and thus the details of which need not be 19 reiterated.

1001031 Referring to both Figure 15 and Figure 16, it can be seen that in the dual telemetry 21 tool string 170, the EM transmitter module 106 is spaced further from the landing point and the 22 traditional pulse landing bit 82 is used. Similar to the EM tool string 100, existing mud pulse 23 modules can be used with the EM modules to create a dual telemetry MWD tool 30.

24 1001041 Figure 17 shows an electrical schematic for the second embodiment.
It can be seen that the configuration is largely the same with various modifications made to accommodate 26 both telemetry modes. A modified controller module 122a, includes a multiplexer 172 to enable 27 the EM transmitter module 106a to bypass the amplifier module 124 and send the pulse signal PtX
28 directly to the pulse module 84 when operating in pulse telemetry mode. The modified 21784503.1 1 controller module 122a is shown in Figure 18. It can be seen that the multiplexer 172 is operated 2 by a signal x provided by a modified microcontroller 126a to direct P',' either to the 3 microcontroller 126a or bypass to the pulse module 84. A surface pressure transducer 176 is also 4 shown, which would normally be in fluid communication with the mud column M
so as to be able to sense the pressure pulses sent by the pulser module 86. The other components shown in 6 Figure 18 are similar to those discussed above as indicated by the similar reference numerals and 7 thus details thereof need not be reiterated.

8 [00105] At the surface, a modified EM surface system 38a is used as shown in Figure 19.
9 It can be seen that the filtering and amplification stages 150-154, user interface port 156 and emulator 15 8 are the same as shown in Figure 12. A surface multiplexer 174 is used to enable 11 either the emulated pulse signal P,' to be sent to the pulse decoder 32 in EM telemetry mode as 12 discussed above, or the normal pulse signal PrX obtained from the pressure transducer 176. A
13 modified interface signal 148 includes a connection to the multiplexer 174 to enable the user to 14 send a mode control signal y to the multiplexer 174 to change telemetry modes.

Exemplary Data Transmission Scheme - second embodiment 16 1001061 Referring now to Figures 20(a), 20(b) and 20(c), an example data transmission 17 scheme for the second embodiment shown in Figures 15-19 will now be explained. Referring 18 first to Figure 20(a), similar to the first embodiment, data is obtained from the sensors 120 by the 19 master controller 96, and an encoded output is sent to the pulse module 86.
Also as before, the EM transmitter module 106 intercepts the encoded signal PtX. When in operation, the 21 microcontroller 126a is provided with a mode type, indicating whether to operate in an EM mode 22 or a pulse mode. The telemetry mode can be indicated by downlinking from the surface system 23 34.

24 1001071 The microcontroller 126 determines the appropriate mode and if pulse telemetry is to be used, control signal x is set to I such that the multiplexer 172 directs the pulse signal Pt, 26 to the pulse module 86 as can be seen by following "B" to Figure 20(b). In the pulse mode, the 27 EM transmitter module 106 does not operate on a signal and thus is idle during the pulse mode 28 The pulse module 86 uses the transmit pulse signal PtX to generate a series of pressure pulses in 21784503.1 I the mud column M, which are sensed by the pressure transducer 176 at the surface, where they 2 are converted into a current signal and sent to the surface station 34.

3 [00108] As before, the EM surface system 38a intercepts the received pulse signal Prx and 4 directs the signal to the pulse decoder 32, thus bypassing the EM circuitry.
This is accomplished by having the interface signal 148a set the control signal y = 1, which causes the multiplexer 174 6 to pick up the pulse signal PrX. This is then fed directly into the pulse decoder 32, where the 7 signal can be decoded and output as described above.

8 [00109] Turning back to Figure 20(c), if the microcontroller 126a is instructed to operate 9 in EM telemetry mode, control signal x is set to x = 0, which causes multiplexer 172 to direct the pulse transmit signal PtX to the amplifier module 124, which can be seen by following "C" to 11 Figure 20(c). It can be appreciated from Figure 20(c) that transmission in the EM telemetry 12 mode operates in the same way as in the first embodiment with the addition of the interface 13 signal 148a setting control signal x to x = 0, causing the multiplexer 174 to direct the emulated 14 pulse signal PrX to the pulse decoder 32. Accordingly, details of such similar steps need not be reiterated.

16 [00110] Therefore, the use of dual telemetry may be accomplished by configuring a dual 17 telemetry tool string 170 as shown in Figure 16 with a modified EM
transmitter module 106, and 18 modifying receiver module 38 to include a multiplexer 174. This enables the EM modules to 19 work with the existing pulse modules. An EM transmission may be used that mimics a mud-pulse transmission or the original pulse signal used. In the result, modifications to the pulse 21 decoder 32, pulse module 86 or landing bit 82 are not required in order to provide an additional 22 EM telemetry mode while taking advantage of an existing mud-pulse telemetry. Moreover, the 23 drill string 20 does not require tripping to switch between mud-pulse telemetry and EM telemetry 24 in the second embodiment.

Further Alternatives 26 [00111] It will be appreciated that the tool strings 100 and 170 can also be modified to 27 include other modules, such as a pressure module (not shown). For example, a similar 21784503.1 1 arrangement as shown in Figure 3(b) could be realized with the pressure module in place of the 2 pulse module 86 and the modified landing bit 104 in place of the landing bit 82. It will be 3 appreciated that the tool string 100 may also be modified to include pulse telemetry, EM

4 telemetry and a pressure module by making the appropriate changes to the drill string 20 to ensure that the isolation exists for EM telemetry.

6 1001121 Although the above has been described with reference to certain specific 7 embodiments, various modifications thereof will be apparent to those skilled in the art as 8 outlined in the claims appended hereto.

21784503.1

Claims (13)

Claims:

1. A battery assembly for a measurement while drilling (MWD) tool string, said battery assembly comprising:
- a battery barrel configured to be removably attachable at each end to other modules in said tool string;
- a battery comprising a first end and a second end, said first end and second end being visually and physically distinguishable from each other to encourage loading said battery into said battery barrel in a single orientation; and - at least one retention mechanism interacting between said battery and the interior of said battery barrel to maintain the position. of said battery in said battery barrel while enabling said battery to be pulled from said battery barrel;
wherein said retention mechanism allows for the isolated removal of said battery from said battery barrel while maintaining operability of said battery barrel and said retention mechanism within said battery assembly.

2. The battery assembly according to claim 1 wherein said first and second ends each comprise a different notch.

3. The battery assembly according to claim 2 wherein said first end comprises a 45 degree notch and said second end comprises a 90 degree notch.

4. The battery assembly according to any one of claims 1 to 3 further comprising a bushing surrounding at least one of said first and second ends to centre said at least one of said first and second ends in said battery barrel.

5. The battery assembly according to any one of claims 1 to 4 wherein said at least one retention mechanism comprises a pin assembly.

6. The battery assembly according to claim 5 wherein said pin assembly is aligned with a respective one of said first and second ends.

7. The battery assembly according to any one of claims 1 to 6 further comprising a module interconnect to connect said battery barrel at one end to one of said other modules.

8. The battery assembly according to claim 7 further comprising a bulkhead to connect said battery barrel at another end to another of said other modules.

9. The battery assembly according to any one of claims 1 to 8 wherein said battery comprises a number of cells.

10. The battery assembly according to claim 2 or claim 3 comprising a pair of said retention mechanisms, said notches being generally aligned with respective ones of said retention mechanisms.

11. A measurement while drilling (MWD) tool comprising the battery assembly according to any one of claims 1 to 10.

12. The MWD tool according to claim 11 comprising EM telemetry capabilities.

13. The MWD tool according to claim 11 or claim 12 comprising mud pulse telemetry capabilities.