|HAO WAKATIAKITOLEHTIMA MAU MALATT US009995135B2

(12) United States Patent ( 10) Patent No.: US 9,995 , 135 B2

Petrovic et al. (45) Date of Patent: Jun . 12 , 2018
(54 ) SYSTEM AND METHOD FOR
CONTROLLING A DUAL TELEMETRY
(52) CPC
U .S. .CI.......... E21B 47/ 122 (2013 . 01) ; E21B 17 /003
MEASUREMENT WHILE DRILLING (MWD )
TOOL
(2013 .01 ); E21B 47/011 (2013.01);
(Continued )
(71) Applicant: Mostar Directional Technologies, Inc.,
@
(58 ) Field of Classification Search
Calgary (CA ) CPC ......... ................ E21B 47 /12 ; E21B 47 / 122
( Continued )
(72 ) Inventors: John Petrovic, Calgary (CA ); Victor
@
(5656) References Cited
Petrovic , Calgary (CA ); Matthew R .
White, Calgary (CA ); Neal P . Beaulac , U .S . PATENT DOCUMENTS
Chestermere (CA ) 4 , 160 ,970 A 7/ 1979 Nicolson
( 73 ) Assignee : Mostar Directional Technologies Inc.,
@ 4 ,348 ,672 A 9/ 1982 Givler
Calgary (CA ) (Continued )
( * ) Notice : Subject to any disclaimer, the term of this
@ FOREIGN PATENT DOCUMENTS
patent is extended or adjusted under 35 CA 1255358 A 6 / 1989
U .S .C . 154 (b ) by 0 days. days . ?? 1301328 C 5 /1992
(21) Appl. No.: 15 /248,948 (Continued )
(22 ) Filed : Aug . 26 , 2016 OTHER PUBLICATIONS
(65 ) Prior Publication Data Proceedings of the Ocean Drilling Program , Initial Reports, vol.
194 , Mar. 28 , 2002 , pp . 30 - 36 , Isern et al.
US 2017/0009570 A1 Jan. 12 , 2017 (Continued )
Primary Examiner — Kevin Kim
Related U .S . Application Data (74 ) Attorney, Agent, or Firm — Brett J. Slaney ; Blake ,
(63) Continuation of application No. 14 /275 ,474 , filed on Cassels & Graydon LLP
May 12 , 2014 , now Pat. No. 9,482 ,085, which is a (57 ) ABSTRACT
(Continued ) A system and method are provided for operating a dual
telemetry measurement while drilling (MWD ) system . The
( 30 ) Foreign Application Priority Data method includes sending a downlink command to a down
hole system to switch between a first telemetry mode and a
Apr. 21, 2006 (CA) 2544457
second telemetry mode , one of the first and second telemetry
(51) Int. CI. modes comprising mud pulse telemetry, and the other of the
E21B 47/ 12 (2012 .01) first and second telemetry modes comprising electromag
GOIV 11/ 00 ( 2006 .01) netic (EM ) telemetry .
(Continued ) 22 Claims, 19 Drawing Sheets

Obtain data from sensors

Master controller encades

and outputs encoded data
to pulse module

EM transmitter module
Intercepts encoded signal
Inputmode

EM or
Pulse ?

Set x = 1 Set x = 0
 US 9, Page
995 ,135
2
B2

Related U .S . Application Data 7 , 080, 699

7 , 255, 183
B2 7 / 2006
B2 . 8 /2007
Lovell et al.
Cramer
continuation of application No. 14 /010 ,600 , filed on AN
7 , 268, 696
7 ,573, 397
B2 9 /2007
B2 8 / 2009
Rodney et al .
Petrovic et al .
Aug. 27 , 2013 , now Pat. No . 8 ,749,399 , which is a 8 ,154 ,420 B2 4 /2012 Petrovic et al.
continuation of application No. 13 /418 ,019 , filed on 2001/0023614 A1 * 9 /2001 Tubel . .. .. .. ... . .. E21B 23 /03
Mar. 12 , 2012 , now Pat. No. 8 ,547 ,245 , which is a 73/ 152 .39
continuation of application No. 11/735 , 151, filed on 2003 /0183384 Al 10 /2003 Das et al.
2004 /0104047 A 6 / 2004 Peter
Apr. 13 , 2007 , now Pat . No. 8 , 154 ,420 , which is a 2004/0251027 Al * 12 /2004 SonnierT .............. E21B 31/ 00
continuation -in - part of application No. 11 /538 , 277 , 166 / 297
filed on Oct. 3 , 2006 , now Pat. No. 7 ,573 ,397 . 2006 /0202852 AL 9 /2006 Peter et al.
2006 /0214814 Al * 9 /2006 Pringnitz ..... E21B 47/ 12
(51) Int. Ci. 340 /855 .4
E21B 47/18 ( 2012 .01) 2006 /0220650 Al 10 /2006 Lovell et al.
E21B 17700 ( 2006 .01) 2006 / 0225920 Al 10/ 2006 Treviranus et al.
E21B 47/01 (2012.01) 2007/ 0052551 A1 3/2007 Lovell et al.
F16L 15 /08 ( 2006 .01) FOREIGN PATENT DOCUMENTS
HOIB 17/20 ( 2006 .01)
(52 ) U .S . CI. 2209423 Al 1/ 1998
CPC .............. E21B 47/ 12 (2013 .01) ; E21B 47 / 18 2078090 C 2 /1999
( 2013.01); E21B 47/ 185 ( 2013.01); E21B
47/ 187 ( 2013.01); F16L 15 / 08 ( 2013.01) ;
GOLV 11 /002 ( 2013 .01); HOIB 17 /20
( 2013.01)
O
CA
CA
CA
2282810
2323654
2329454
2096941
2392670
A1
A1
C
A1
3 / 2000
4 /2001
6 / 2001
7 /2001
7 /2001
(58 ) Field of Classification Search 2436056 A1 9 / 2002
USPC ...................... ................ 340 /853.1, 853 .3 2455396 1 /2003
2411083 Al 5 /2003
See application file for complete search history.

5
2476259 Al 8 /2003
2617328 8 /2003
( 56 ) References Cited 2260307
2442475 Al
12 /2003
3 / 2004
U . S . PATENT DOCUMENTS 2499331 A1 4 /2004
2508374 A1 6 / 2004
4 , 901, 289 A 2/ 1990 Cretin et al. 2506808 7 /2004
4 ,945, 761 A
5 ,138,313 A
5 , 160, 925 A
8 / 1990
8 / 1992
11/ 1992
Lessi et al.
Barrington
Dailet et al.
?? 2420402
2515193 Al
2232213
8 / 2004
8 / 2004
9 / 2004
5 ,456 , 106 A
5 ,602, 541 A
5 , 749 ,605 A
5 ,899 ,958 A
5 ,924 ,499 A
5 ,945 ,923 A
5 , 964,839 A
10 / 1995
2 / 1997
5 / 1998
5 / 1999
7 / 1999
8/ 1999
Harvey et al.
Comeau et al.
Hampton , III et al .
Doweli et al.
Birchak et al.
Soulier
10 / 1999 Johnson et al .
c
UU
2469574
2471067 Al
2201552 0
2476370
2476321 Al
2495170 A1
2460371 Al
12 /2004
12 /2004
1 /2005
1 /2005
2 /2005
7 /2005
9 /2005
6 ,050, 353 A 4 / 2000 Logan et al. CA 2249300 10 /2005
6 ,098, 727 A 8/ 2000 Ringgenberg et al. CA 2261686 C 2 / 2006
6 , 144 ,316 A11/ 2000 Skinner ?? 2496170 A1 8 /2006
6 , 158 ,532 A12/ 2000 Logan et al. CA 2552514 2 /2007
6 ,177, 882 B1 1/2001 Ringgenberg et al. GB 2346509 A 8 / 2000
6 ,196, 335 B1 3 / 2001 Rodney WO WO 00 / 13349 Al 3 /2000
6 , 224 ,997 B1 5 / 2001 Papadopoulos WO WO 2004 /061269 A1 7 / 2004
6 , 404, 350 B1 6 / 2002 Soulier
6, 414, 905 B1 7 / 2002 Owens et al. OTHER PUBLICATIONS
6 , 572, 152 B2 6 / 2003 Dopf et al.
6, 727, 827 B1 4 /2004 Edwards et al. National Energy Technology Laboratory, Project No. DE -AC26
6 , 736, 222 B2 5 /2004 Kuckes et al. 97FT34175 , “ Development of a High Temperature Logging While
6, 856,225 B1 2 / 2005 Chalitsios et al.
6, 909 , 667 B2 6 / 2005 Shah et al . Drilling Tool,” Jun . 1, 2005 .
6 , 926, 098 B2 8 /2005 Peter
6 , 937 ,159 B2 8 /2005 Hill et al. * cited by examiner
U . S . Patent Jun. 12 , 2018 Sheet 1 of 19 US 9,995,135 B2

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U , S , Patent Jum . 12, 2018 Sheet 3 of 19 _ US 9,995,135 B2
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U . S . Patent Jun. 12 , 2018 Sheet 4 of 19 US 9,995,135 B2

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U . S . Patent Jun. 12 , 2018 Sheet 5 of 19 US 9,995,135 B2

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U . S . Patent Jun. 12 , 2018 Sheet 6 of 19 US 9,995,135 B2

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U . S . Patent Jun. 12 , 2018 Sheet 8 of 19 US 9 ,995 , 135 B2

45 Rig Floor
Display

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U . S . Patent Jun. 12 , 2018 Sheet 9 of 19 US 9,995,135 B2

10Figure
132
17
28
Clock Log me ory
134
EMret EMx
pet
EM

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Curent Sense
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Micro Contrler Serial Driver 140
EM

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130
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Pts

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U . S . Patent Jun . 12 , 2018 Sheet 10 of 19 US 9, 995 , 135 B2

From Pressure
Transducer Pulse
Decoder PC

32 To Rig Floor
Display

Figure 11
38

FIE
EMrell 150 152 154
EMrx Gain Filter Gain Filter Gain

160 160 160 160 153 160

User Interface
Pressure 7 158 Prix ' To Pulse
Transducer Decoder
Emulator
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Figure 12
U . S . Patent Jun . 12, 2018 Sheet 11 of 19 US 9 , 995 , 135 B2

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OUT1
L32
Pulse Decoder 1

Pax
138
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13FIGURE
EMex
EM TransmiterModule
Pris

Directional Module ?
U . S . Patent Jun. 12 , 2018 Sheet 12 of 19 US 9 , 995 , 135 B2

Obtain data from sensors

EM surface system
obtains EM signals
Master controller encodes
and outputs encoded data
to pulse module

Amplify , filter and convert

EM signal to a current
signal
EM transmittermodule
intercepts encoded signal

Send current signal to

pulse decoder
EM transmitter amplifies
encoded signal

Pulse decoder decodes

and outputs information to
Transmit amplified EM PC and to rig floor display
signals

Figure 14
U . S . Patent Jun 12, 2018 Sheet 13 of 19 US 9 , 995,135 B2

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U . S . Patent Jun. 12 , 2018 Sheet 14 of 19 US 9,995,135 B2

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U . S . Patent Jun . 12 , 2018 Sheet 15 of 19 US 9 ,995 ,135 B2

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132
Clock Log me ory
Figure
134
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VibrationSwitch 1222
142 Cur entSense
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U . S . Patent Jun . 12 , 2018 Sheet 16 of 19 US 9,995 ,135 B2

38a

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Gain Filter Gain
160 153 160
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158
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U . S . Patent Jun . 12 , 2018 Sheet 17 of 19 US 9 ,995 , 135 B2

Obtain data from sensors

Master controller encodes

and outputs encoded data
to pulse module

EM transmitter module
intercepts encoded signal
Inputmode

EM or
Pulse ?

Set x = 1 Set x = 0

Figure 20( a )
U . S . Patent Jun. 12 , 2018 Sheet 18 of 19 US 9 ,995, 135 B2

Directpulse signal to

HHI
pulse module
Set y = 1

Generate and transmit

pressure pulses in mud
column Bypass EM signal
conditioning and direct
current signal to pulse
decoder
Pressure transducer converts
pressure pulses into current
signal and sends current
signal to surface station Pulse decoder decodes
and outputs information to
PC and to rig floor display

EM surface system
intercepts current signal
from transducer

Figure 20(b )
U . S . Patent Jun. 12 , 2018 Sheet 19 of 19 US 9 , 995 , 135 B2

...

Direct EM signals to EM
signal conditioning circuit
EM transmitter amplifies
encoded signal

Amplify , filter and convert

EM signal to a current
signal
Transmit amplified EM
signals

Send current signal to

pulse decoder
EM surface system
obtains EM signals
.. . .. . .

Pulse decoder decodes

and outputs information to
PC and to rig floor display
Set y = 0

Figure 20 ( c )
 US 9 , 995, 135 B2
SYSTEM AND METHOD FOR known for many years as a technique for providing infor
CONTROLLING A DUAL TELEMETRY mation to the driller regarding the particular earth formation
MEASUREMENTWHILE DRILLING (MWD) being drilled .
TOOL In one logging technique , a probe or “ sonde” that houses
5 formation sensors is lowered into the wellbore once drilling
CROSS -REFERENCE TO RELATED has progressed or completed . The probe is supported by and
APPLICATIONS connected to the surface via an electrical wireline, and is
used to obtain data and send the data to the surface . A
This application is a continuation of U .S . patent applica paramount problem with obtaining downhole measurements
tion Ser. No. 14 /275 ,474 filed on May 12 , 2014 , which is a 10 via a wireline is that the drilling assembly must be removed
continuation of U . S . patent application Ser. No. 14 /010 ,600 or “ tripped ” from the wellbore before the probe can be
filed on Aug. 27. 2013 (now U . S . Pat. No. 8 ,749. 399 ), which lowered into the wellbore to obtain the measurements .
is a continuation of U . S . patent application Ser. No . 13 /418 , Tripping a drill string is typically time consuming and thus
019 filed on Mar. 12 , 2012 ( now U . S . Pat . No. 8, 547 , 245 ), costly , especially when a substantial portion of the wellbore
which is a continuation of U . S . patent application Ser. No . 15 has been drilled .
11/735 ,151 filed on Apr. 13 , 2007 (now U . S . Pat. No. To avoid tripping the drill string , there has traditionally
8 . 154 .420 ), which is a continuation -in -part of U . S . patent been an emphasis on the collection of data during the drilling
application Ser. No. 11/538 ,277 filed on Oct. 3, 2006 ( now process . By collecting and processing data during the drill
U .S . Pat. No. 7 ,573 , 397 ) , which claims priority from Cana - ing process , without the necessity of tripping the drill string,
dian Patent Application No . 2 , 544 ,457 filed on Apr. 21 , 20 the driller can make modifications or corrections to the
2006 , the contents of these applications being incorporated drilling process as necessary . Such modifications and cor
herein by reference. rections are typically made in an attempt to optimize the
performance of the drilling operation while minimizing
FIELD OF THE INVENTION downtime. Techniques for concurrently drilling the well and
25 measuring downhole conditions are often referred to as
The present invention relates generally to data acquisition measurement-while - drilling (MWD ). It should be under
during earth drilling operations and telemetry systems there - stood that MWD will herein encompass logging -while
for, and has particular utility in measurementwhile drilling drilling (LWD ) and seismic -while -drilling (SWD ) tech
(MWD ) applications. niques , wherein LWD systems relate generally to
30 measurements of parameters of earth formation , and SWD
DESCRIPTION OF THE PRIOR ART systems relate generally to measurements of seismic related
properties.
The recovery of subterranean materials such as oil and gas In MWD systems, sensors or transducers are typically
typically requires drilling wellbores a great distance beneath located at the lower end of the drill string which , while
the earth ' s surface towards a repository of the material. The 35 drilling is in progress, continuously or intermittently moni
earthen material being drilled is often referred to as " for - tor predetermined drilling parameters and formation data .
mation ” . In addition to drilling equipment situated at the Data representing such parameters may then be transmitted
surface, a drill string extends from the equipment to the to a surface detector /receiver using some form of telemetry.
material formation at the terminal end of the wellbore and Typically, the downhole sensors employed in MWD appli
includes a drill bit for drilling the wellbore . 40 cations are positioned in a cylindrical drill collar that is
The drill bit is rotated and drilling is accomplished by positioned as close to the drill bit as possible .
either rotating the drill string, or by use of a downhole motor There are a number of telemetry techniques that have
near the drill bit. Drilling fluid , often termed “mud ” , is been employed by MWD systems to transmit measurement
pumped down through the drill string at high pressures and data to the surface without the use of a wireline tool.
volumes ( e . g . 3000 p .s . i. at flow rates of up to 1400 gallons 45 One such technique involves transmitting data using
per minute ) to emerge through nozzles or jets in the drill bit. pressure waves in drilling fluids such as drilling mud . This
The mud then travels back up the hole via the annulus telemetry scheme is often referred to as mud -pulse telem
formed between the exterior of the drill string and the wall etry . Mud- pulse telemetry involves creating pressure signals
of the wellbore . On the surface , the drilling mud may be in the drilling mud that is being circulated under pressure
cleaned and then re - circulated . The drilling mud serves to 50 through the drill string during the drilling operation . The
cool and lubricate the drill bit , to carry cuttings from the base information that is acquired by the downhole sensors is
of the bore to the surface , and to balance the hydrostatic transmitted utilising a particular time division scheme to
pressure in the formation . effectively create a waveform of pressure pulses in the mud
A drill string is generally comprised of a number of drill column . The information may then be received and decoded
rods that are connected to each other in seriatim . A drill rod 55 by a pressure transducer and analysed by a computer at a
is often referred to as a " sub ” , and an assembly of two or surface receiver .
more drill rods may be referred to as a “ sub -assembly " . In a mud -pulse system , the pressure in the drilling mud is
It is generally desirable to obtain information relating to typically modulated via operation of a valve and control
parameters and conditions downhole while drilling . Such mechanism , generally termed a pulser or mud -pulser. The
information typically relates to one or more characteristics 60 pulser is typically mounted in a specially adapted drill collar
of the earth formation that is being traversed by the wellbore positioned above the drill bit . The generated pressure pulse
such as data related to the size , depth and/ or direction of the travels up the mud column inside the drill string at the
wellbore itself; and information related to the drill bit such velocity of sound in the mud , and thus the data transmission
as temperature , speed and fluid pressure . The collection of rate is dependent on the type of drilling fluid used . Typically ,
information relating to conditions downhole , commonly 65 the velocity may vary between approximately 3000 and
referred to as “ logging” , can be performed using several 5000 feet per second . The actual rate of data transmission ,
differentmethods . Well logging in the oil industry has been however, is relatively slow due to factors such as pulse
 US 9 ,995,135 B2
spreading, distortion, attenuation, modulation rate limita - re -assembled and drilling restarted . The inherent downtime
tions , and other disruptive forces such as ambient noise in while tripping the drill string can often be considerable and
the transmission channel. A typical pulse rate is on the order thus undesirable .
of one pulse per second (i.e. 1 Hz). In general, one problem associated with mud -pulse telem
An often preferred implementation of mud -pulse telem - 5 etry is that it can only be used during the drilling operation
etry uses pulse position modulation for transmitting data. In
pulse position modulation , pulses have a fixed width and the asdrilling
it relies on the flow of mud in the mud - column. When
is interrupted , e .g . when adding a sub to the drill
interval between pulses is proportional to the data value string, there is no medium to transmit data .
transmitted . Mud -pressure pulses can be generated by open It is therefore an object of the present invention to obviate
ing and closing a valve near the bottom of the drill string so 10 or mitigate at least one of the above -mentioned disadvan
as to momentarily restrict the mud flow . In a number of tages .
knownMWD tools, a “ negative ” pressure pulse is created in
the fluid by temporarily opening a valve in the drill collar so SUMMARY
that some of the drilling fluid will bypass the bit, the open
valve allowing direct communication between the high 15
pressure fluid inside the drill string and the fluid at lower In one aspect, there is provided a method of operating a
pressure returning to the surface via the exterior of the dual telemetry measurement while drilling (MWD ) system ,
string. Alternatively, a “ positive ” pressure pulse can be the method comprising: sending a downlink command to a
created by temporarily restricting the downward flow of of downhole system to switch between a first telemetry mode
drilling fluid by partially blocking the fluid path in the drill 20 and a second telemetry mode, one of the first and second
string. telemetry modes comprising mud pulse telemetry , and the
Electromagnetic (EM ) radiation has also been used to other of the first and second telemetry modes comprising
telemeter data from downhole locations to the surface (and electromagnetic (EM ) telemetry .
vice - versa ). In EM systems, a currentmay be induced on the In another aspect, there is provided a surface system for
drill string from a downhole transmitter and an electrical 25 a dual telemetry measurement while drilling (MWD ) sys
potential may be impressed across an insulated gap in a tem , the surface system comprising controller configured to
downhole portion of the drill string to generate a magnetic operate flow of a mud motor to send a downlink command
field that will propagate through the earth formation . The to a downhole system to switch between a first telemetry
signal that propagates through the formation is typically mode and a second telemetry mode , one of the first and
measured using a conductive stake that is driven into the 30 second telemetry modes comprising mud pulse telemetry ,
ground at some distance from the drilling equipment. The and the other of the first and second telemetry modes
potential difference of the drill string signal and the forma comprising electromagnetic ( EM ) telemetry .
tion signal may then be measured , as shown in U .S . Pat.No.
4 , 160 , 970 published on Jul. 10 , 1979 . BRIEF DESCRIPTION OF THE DRAWINGS
Information is transmitted from the downhole location by 35
modulating the current or voltage signal and is detected at Embodiments will now be described by way of example
the surface with electric field and/or magnetic field sensors . with reference to the appended drawings wherein :
In an often preferred implementation of EM telemetry , FIG . 1 is a schematic view of a drilling system and its
information is transmitted by phase shifting a carrier sine environment;
wave among a number of discrete phase states . Although the 40 FIG . 2 ( a ) is an external plan view of a downhole portion
drill string acts as part of the conductive path , system losses of a mud pulse tool drill string configuration .
are almost always dominated by conduction losses within FIG . 2 (b ) is an external plan view of a downhole portion
the earth which , as noted above , also carries the electro - of an EM tool drill string configuration .
magnetic radiation . Such EM systems work well in regions FIG . 3 ( a ) is an external plan view of a mud pulse tool
where the earth ' s conductivity between the telemetry trans - 45 string .
mitter and the earth ' s surface is consistently low . However, FIG . 3 (b ) is an external plan view of a EM tool string.
EM systems may be affected by distortion or signal damp FIG . 4 is a sectional view of a region of isolation in the
ening due to geologic formations such as dry coal seams, EM tool string of FIG . 3 (b ) along the line IV - IV showing the
anhydrite, and salt domes . EM tool string positioned therein .
Telemetry using acoustic transmitters in the drill string 50 FIG . 5 is an exploded perspective view of a gap sub
has also been contemplated as a potential means to increase assembly .
the speed and reliability of the data transmission from FIG . 6 is an exploded view of a power supply .
downhole to the surface . When actuated by a signal such as FIG . 7 is a pair of end views of the battery barrel of FIG .
a voltage potential from a sensor, an acoustic transmitter 6.
mechanically mounted on the tubing imparts a stress wave 55 FIG . 8 is a sectional view along the line VIII - VIII shown
or acoustic pulse onto the tubing string. in FIG . 6 .
Typically , drillers will utilize one of a wireline system , a FIG . 9 is a schematic diagram showing data flow from a
mud -pulse system , an EM system and an acoustic system , directionalmodule to a surface station via an EM transmitter
most often either an EM system or a mud -pulse system . module in an EM MWD system .
Depending on the nature of the drilling task , it is often more 60 FIG . 10 is a schematic diagram of the EM transmitter
favourable to use EM due to its relatively faster data rate module shown in FIG . 9 .
when compared to mud -pulse . However, if a signal is lost FIG . 11 is a schematic diagram of a surface station
due to the presence of the aforementioned geological con - utilizing a conventional pulse telemetry system .
ditions , the rig must be shut down and the drill string tripped FIG . 12 is a schematic diagram of the EM surface system
to swap the EM system with an alternative system such as 65 shown in FIG . 9 .
a mud -pulse system which , although slower, is generally FIG . 13 is a plot showing signal propagation according to
more reliable . The drill string would then need to be the arrangement shown in FIG . 9 .
 US 9,995 ,135 B2
FIG . 14 is a flow diagram illustrating an EM data trans will hereinafter be referred to as a “mud column" and
mission in the EM MWD system shown in FIG . 9 . generally denoted by the character “ M ” .
FIG . 15 is an external plan view of a downhole portion of An MWD tool 30 is located within the drill string 20
an EM and pulse dual telemetry tool drill string configura toward its lower end 19 . The MWD tool 30 transmits data to
tion . 5 the surface to a remote MWD surface station 34 . The data
FIG . 16 is an external plan view of an EM and pulse dual transmitted to the surface is indicative of operating condi
telemetry tool string. tions associated with the drilling operation . In one embodi
FIG . 17 is a schematic diagram showing data flow in an ment, the MWD tool 30 transmits the data to a pulse tool
EM and pulse dual telemetry MWD system . surface system 32 via an EM surface system 38 using EM
FIG . 18 is a schematic diagram of the EM transmitter 10 telemetry as explained below .
module shown in FIG . 17 . The EM surface system 38 is used to receive , condition
FIG . 19 is a schematic diagram of the EM surface system and convert data transmitted in an EM signal such that the
shown in FIG . 17 . conditioned data is compatible with the pulse tool surface
FIG . 20 (a ) is a flow diagram illustrating a data transmissystem 32 . The EM surface system 38 thus acts as an EM
sion using EM and pulse telemetry in the EM and pulse dual 15 signal conditioner and is configured to interface with the
telemetry MWD system shown in FIG . 17 . pulse decoder 32. Normally, a pressure transducer on the
FIG . 20 (b ) is a flow diagram continuing from B in FIG . drilling equipment interfaces with the pulse decoder 32 and
20 ( a ). thus the interface between the EM surface system 38 and the
FIG . 20 ( c ) is a flow diagram continuing from C FIG . pulse decoder 32 is preferably similar to the interface
20 ( a ). 20 between the pulse decoder 32 and a connector from a data
cable extending from the transducer. The pulse decoder 32
DETAILED DESCRIPTION OF THE DRAWINGS is connected to a computer interface 36 , e . g . a personal
computer in the surface station 34 , to enable a user to
The following describes, in one embodiment, an MWD interact with the MWD tool 30 remotely . The pulse decoder
tool providing EM telemetry while utilizing existing pulse 25 32 also outputs a decoded signal to a rig floor display 45 via
tool modules . In general, an EM signal is generated by a data connection 44. Accordingly , the MWD tool 30 shown
repeating an amplified version of a conventional pulse signal in FIG . 1 is configured to interface with and operate using
that is intended to be sent to a pulse module , and transmitting existing mud pulse modules from an existing pulse MWD
this repeated signal to the surface in an EM transmission . In system as will be explained in greater detail below .
this way , the same components can be used without requir - 30 The EM transmission is generated by creating a potential
ing knowledge of the encoding scheme used in the pulse difference across a region of isolation 29 in the drill string
signal. Therefore , the following system is compatible with 20 and is formed by generating an electromagnetic (EM )
any existing downhole directional module that generates a field F which propagates outwardly and upwardly through
signal for a pulse module. The pulse signal can be inter the formation 16 to the surface and creating and transmitting
cepted , amplified , and sent to an EM surface system by 35 a return signal S through the drill string 20 . A conductive
applying a potential difference across a region of isolation in member 50 , typically an iron stake driven into the formation
the drill string. The EM surface system receives , conditions 16 , conducts the formation signal through a data connection
and converts the received signal into a signal which is 52 to the EM surface system 38 and the return signal is
compatible with a conventional surface pulse decoder. In transmitted from the surface station 34 over line 41 to a
this way , existing software and decoding tools already 40 connection on the drill rig 12 . As can be seen in FIG . 1 , the
present in the pulse surface decoder can be utilized while negative dipole for the EM signal is provided by a connec
providing EM telemetry capabilities . tion to the drill string 20 at a location which is above the
In another embodiment, the following provided dual pulse region of isolation 29 and the positive dipole for the EM
and EM telemetry capabilities by using a multiplexing signal is provided by a connection to the drill string 20 at a
scheme to direct the pulse signal to either the pulse module 45 location which is below the region of isolation 29 . It will be
for transmission using pulse telemetry or to the EM trans - appreciated that either signal ( formation or drill string ) can
mitter module for transmission using EM telemetry . At the be the EM signal or the return signal, however the arrange
surface , the EM surface system receives either signal and ment shown in FIG . 1 is preferred since the drill string 20
routes the appropriate signal to the pulse decoder. The pulse typically provides a better reference than the formation 16 .
decoder is unable to distinguish between telemetry modes 50 In another embodiment, the MWD tool 30 provided dual
enabling existing software and hardware offered by a pulse telemetry capabilities thus capable of transmitting data to the
system can be used . It will be appreciated that the following surface receiver station 34 using either EM telemetry (as
examples are for illustrative purposes only . discussed above ), or mud pulse telemetry by transmitting
Drilling Environment data through the mud column M by way of a series of
Referring therefore to FIG . 1 , a drilling rig 10 is shown in 55 pressure pulses. The pressure pulses are received by the
situ at a drilling site 12 . The rig 10 drills a wellbore 14 into pressure transducer, converted to an appropriate compatible
an earth formation 16 . The wellbore 14 is excavated by signal (e . g . a current signal) which is indicative of the
operating a drill bit 18 disposed at a lower end 19 of a drill information encoded in the pressure pulses , and transmitted
string 20 . The drill string 20 is supported at an upper end 21 over a data cable directly to the pulse decoder 32 as will be
by drilling equipment 22 . As the bit 18 drills into the 60 explained in greater detail below .
formation 16 , individual drill rods 24 are added to the drill MWD Tool — Downhole Configuration
string 20 as required . In the example shown in FIG . 1 , the Referring to FIG . 2 ( a ), a conventional downhole drill
drill bit 18 is driven by a fluid or mud motor 26 . The mud string configuration for a mud pulse MWD tool string 80 is
motor 26 is powered by having the drilling equipment 22 shown (see FIG . 3 ( a ) for pulse tool string 80 ) . An example
pump drill fluid , hereinafter referred to as “ mud” , through a 65 of such a mud pulse MWD tool is a TensorTM MWD tool
hollow conduit 28 defined by interior portions of the con - sold by GE EnergyTM The conventional mud pulse drill
nected subs 24 . The column of fluid held in the conduit 28 string configuration comprises a drill bit 18 driven by a mud
 US 9 ,995 , 135 B2
motor 26 connected thereto . Connected to the mud motor 26 data , magnetometer data , gamma data etc . The directional
is a universal bottom hole offset (UBHO ) 60, which inter module 94 comprises a master controller 96 which is respon
nally provides a tool string landing point for the pulse tool s ible for acquiring the data from one or more sensors and
string 80 . Connected to the UBHO 60 is the serially con creating a voltage signal, which is typically a digital repre
nected drill rods 20 forming the upstream portion 62 of the 5 sentation of where pressure pulses occur for operating the
drill string 20 . The upstream portion 62 of the drill string 20 pulse module 86 .
is typically formed using a few non -magnetic drill rods to Yet another module interconnect 90 is used to connect a
provide a non -magnetic spacing between magnetically sen second battery 98 , typically another 28 V battery , to the
sitive equipment and the other drill rods, which can be directional module 94 . The second battery 98 includes a
magnetic . 10 connector 99 to which a trip line can be attached to permit
Referring to FIG . 2 (b ), a downhole drill string configu - tripping the tool string 80 . The tool string 80 can be removed
ration for an EM MWD tool string 100 is shown ( see FIG . by running a wireline down the bore of the drill string 20 .
3 (b ) for EM tool string 100). It can be seen in FIG . 2 (b ) that The wireline includes a latchingmechanism that hooks onto
the drill bit 18 ,mud motor 26 and UBHO 60 are configured the connector 99 (sometimes referred to as a “ spearpoint" ) .
in the same way shown in FIG . 2 ( a ), however, interposed 15 Once the wireline is latched to the tool string 80 , the tool
between the UBHO 60 and the upstream portion 62 of the string 80 can be removed by pulling the wireline through the
drill string 20 , is the region of isolation 29 . In one embodi drill string 20 . It will be appreciated that the tool string 80
ment, the region of isolation 29 comprises a first sub - shown in FIG . 3 ( a ) is only one example and many other
assembly 64 connected to a second sub - assembly 67, arrangements can be used . For example , additional modules
wherein the first sub assembly 64 is comprised of a first sub 20 may be incorporated and the order of connection may be
65 and second sub 66 isolated from each other by a first varied . Other modules may include pressure and gamma
non -conductive ring 70 and the second sub - assembly 67 is modules, which are not typically attached above the second
comprised of a third sub 68 and fourth sub 69 isolated from battery 98 but could be . All the modules are designed to be
each other by a second non - conductive ring 72 . The EM tool placed anywhere in the tool string 80, with the exception of
string 100 is preferably aligned with the region of isolation 25 the pulse module 86 which is located at the bottom in
29 such that a tool isolation 102 in the EM tool string 100 connection with the pulser 84 .
is situated between the first and second non -conductive rings Referring now to FIG . 3 (b ), the EM tool string 100 is
70 , 72 . However, it can be appreciated that the region of shown . The EM tool string 100 is configured to be posi
isolation 29 is used to isolate the drill string 20 and thus the tioned within the downhole drill string configuration shown
tool isolation 102 may be above or below so long as there is 30 in FIG . 2 (b ). The EM tool string 100 comprises a modified
a separation between points of contact between the tool landing bit 104 that is sized and keyed similar to the landing
string 100 and the drill string 20 as will be discussed below . bit 82 in the pulse tool string 80 but does not include the mud
As will also be discussed below , the EM tool string 100 is valve 84. In this way, the EM tool string 100 can be oriented
configured to interface with the existing UBHO 60 such that within the drill string 20 in a manner similar to the pulse tool
the EM tool string 100 can be used with the existing modules 35 string 80. In this embodiment, an EM transmitter module
in a conventional pulse tool string 80 such as those included 106 is connected to the modified landing bit 104 in place of
in a GE TensorTM tool. the mud pulse module 86 . The EM transmitter module 106
The pulse tool string 80 is shown in greater detail in FIG . includes electrical isolation 102 to isolate an upstream EM
3 ( a ). The pulse tool string 80 is configured to be positioned tool portion 108 from a downstream EM tool portion 110 .
within the drill string configuration shown in FIG . 2 ( a ). The 40 The electrical isolation 102 can be made from any non
pulse tool string 80 comprises a landing bit 82 which is conductive material such as a rubber or plastic . A quick
keyed to rotate the pulse tool string 80 about its longitudinal change battery assembly 200 ( e. g . providing 14 V ) may be
axis into a consistent orientation as it is being landed . The used in place of the first battery 88 discussed above , which
landing bit 82 includes a mud valve 84 that is operated by is connected to the EM transmitter module 106 using a
a mud pulse module 86 connected thereto . In normal pulse 45 module interconnect 90 . It will be appreciated that although
telemetry operation , the mud valve 84 is used to create the quick change battery assembly 200 is preferable , the first
pressure pulses in themud column M for sending data to the battery 88 described above may alternatively be used . The
surface . A first battery 88 , typically a 28 V battery is directional module 94 and second battery 98 are connected
connected to the mud pulse module through a module in a manner similar to that shown in FIG . 3 ( a ) and thus
interconnect 90 . The module interconnect 90 comprises a 50 details of such connections need not be reiterated .
pair of bow springs 92 to engage the inner wall of drill string It can therefore be seen that downhole , a conventional
20 and center the pulse tool string 80 within the drill string pulse tool string 80 can be modified for transmitting EM
20 . The bow springs 92 are flexible to accommodate differ signals by replacing the landing bit 82 and pulse module 86
ently sized bores and are electrically conductive to provide with the modified landing bit 104 and EM transmitter
an electrical contact with the drill string 20 . The intercon - 55 module 106 while utilizing the other existing modules. The
nects 90 are typically rigid while accommodating minimal modified landing bit 104 enables the EM transmittermodule
flexure when compared to the rigidity of the tool string 100 . 106 to be oriented and aligned as would the conventional
Other interconnects (not shown )may be used , which are not pulse module 86 by interfacing with the UBHO 60 in a
conductive, where an electrical contact is not required . such similar fashion .
other interconnects are often referred to as “ X - fins ” . 60 Region of Isolation Gap Sub - Assembly
Another module interconnect 90 is used to connect the The placement of the EM tool string 100 within the
first battery 88 to a direction and inclination module 94 . The conduit 28 of the drill string 20 is shown in greater detail in
direction and inclination module 94 (hereinafter referred to FIG . 4 . As discussed above , the EM tool string 100 is aligned
as the " directional module 94 " ) acquires measurement data with the region of isolation 29 , and the region of isolation 29
associated with the drilling operation and provides such data 65 comprises a first sub -assembly 64 connected to a second
to the pulse module 86 to convert into a series of pressure sub -assembly 67, wherein the first sub -assembly 64 com
pulses . Such measurement data may include accelerometer prises first and second subs 65, 66 and the second sub
 US 9 ,995, 135 B2
10
assembly 67 comprises third and fourth subs 68, 69 . As can provides a smooth surface to assist in threading the subs
be seen , the shoulders of the subs 65 and 66 are separated by together while also providing a layer of cushioning.
a non -conductive ring 70 , and the threads of the subs 65 and The insulative layers 71 and 73 can , in another embodi
66 are separated by a non -conductive layer 71. Similarly, the ment, also comprise a cloth or wrappingmade from a fabric
shoulders of the subs 68 and 69 are separated by another 5 such as , Vectran , Spectra , Dyneema, any type of Aramid
non -conductive ring 72 , and the threads of the subs 68 and fiber fabric , any type of ballistic fabric , loose weave fabrics ,
69 are separated by another non - conductive layer 73 . The turtle skin weave fabrics to name a few . In general, a
rings 70 and 72 are made from a suitable non -conductive material that includes favourable qualities such as high
material such as a ceramic . Preferably , the rings 70 and 72 tensile strength at low weight, structural rigidity , low elec
are made from either TechnoxTM or YTZP -HippedTM , which 10 trical conductivity , high chemical resistance , low thermal
are commercially available ceramic materials that possess shrinkage, high toughness (work -to -break ), dimensional sta
beneficial characteristics such as high compressive strength bility , and high cut resistance is preferred . In general, the
and high resistivity . For example , TechnoxTM 3000 grade insulative layers 71 and 73 and the rings 70 and 72 provide
ceramic has been shown to exhibit a compressive strength of electrical isolation independent of the material used to
approximately 290 Kpsi and exhibit a resistivity of approxi- 15 construct the subs 65 , 66 , 68 and 69 . However, preferably
mately 109 Ohmcm at 25° C . the subs 65 , 66 , 68 and 69 are made from a non -magnetic
The subs each have a male end or " pin " , and a female end material so as to inhibit interference with the electromag
or “ box” . For constructing the region of isolation 29 , the pins netic field F .
and boxes that mate together where the ceramic ring 70 , 72 The insulative layers 71, 73 may further be strengthened
is placed should be manufactured to accommodate the 20 with an epoxy type adhesive which serves to seal the
ceramic rings 70 , 72 as well as other insulative layers sub -assemblies 64, 67. In addition to the epoxy adhesive, a
described below . To accommodate the rings 70, 72 , the pin relief 179 may be machined into the box of the appropriate
end of the subs are machined . Firstly , the shoulder (e . g . see subs as seen in the enlarged portion of FIG . 4 . The relief 179
59 in FIG . 5 ) is machined back far enough to accommodate is sized to accommodate a flexible washer 180 , preferably
the ceramic ring 70 , 72 . It has been found that using a 1/2 " 25 made from polyurethane with embedded rubber O -rings 182 .
zirconia ring with a 1/2" reduction in the shoulder is particu - The washer 180 is placed in the relief such thatwhen the pin
larly suitable . The pin includes a thread that may be custom is screwed into the box , the outside shoulders 59 , 75 ( see
or an API standard . To accommodate the isolation layers 71 , FIG . 5 also ) engage the ceramic ring 70 or 72 , an inside
73, the thread is further machined to be deeper than spec to shoulder also engages where the washer 180 is seated . The
make room for such materials . It has been found that to 30 polyurethane is preferably a compressible type , which can
accommodate the layers 71 and 73 described in detail below , add significant safeguards in keeping moisture from seeping
the pins can be machined 0 .009" to 0 .0010 " deeper than into the threads. The addition of the O - rings 182 provides a
spec . The shoulders are machined back to balance the torque further defence in case of cracking or deterioration of the
applied when connecting the subs that would normally be polyurethane or similar material in the washer 180 . In this
accommodated by the meeting of the shoulders as two subs 35 way, even if the epoxy seal breaks down , a further layer of
come together. protection is provided . This can prolong the life of the region
The thread used on the pins is preferably an H90 API of isolation 29 and can prevent moisture from shorting out
connection or an SLH90 API connection due to the preferred the system .
90° thread profile with a relatively course . This is preferred FIG . 5 illustrates an exploded view of an exemplary
over typical 60° thread profiles . It will be appreciated that 40 embodiment of the first sub -assembly 64 utilizing a ceramic
the pins can be custom machined to include a course thread coating and a wrapping of woven fabric in addition to the
and preferably 90° thread profile . To achieve the same effect other insulative layers discussed above . In a preferred
as the H90 API connection, a taper of between 1. 25 " and 3 " assembly method , the sub - assembly 64 is assembled by
per foot should be used . In this way , even greater flexibility applying the ceramic coating to the pin of the sub 65 and
can be achieved in the pin length , diameter and changes 45 then applying a layer of electrical tape (not shown ). The
throughout the taper. ceramic ring 70 is then slid over the male -end of the first sub
In one embodiment, the insulative layers 71 , 73 comprise 65 such that it is seated on the shoulder 59 . The epoxy may
the application of a coating, preferably a ceramic coating , to then be added over the electrical tape to provide a moisture
the threads of the pins to isolate subs 65 from sub 66 and sub barrier. A wax stringmay also be used if desired . The washer
68 from sub 69 . A suitable coating is made from Aluminium 50 180 is then inserted into the relief 179 . The wrapping 71a is
Oxide or Titanium Dioxide . This locks the corresponding then wrapped clockwise around the threads of the pin of the
subs together to provide complete electrical isolation . When sub 65 over the electrical tape , as the female-end of the
using a ceramic coating, the pin should be pre -treated , second sub 66 is screwed onto the male -end of the first sub
preferably to approximately 350° C . Also when applying the 65 , until the shoulder 75 engages the ring 70 . As the
ceramic coating, the pin should be in constant rotation and 55 female -end of the second sub 66 is screwed onto the
the feed of the applicator gun should be continuous and male -end of the first sub 65 . In this way, the ring 70 provides
constant throughout the application process. It will be appre electrical isolation between the shoulders 59 and 75 , and the
ciated that any insulative coating can be applied to the cloth 71a , ceramic , tape and epoxy provides electrical
threads. As noted above , the threads are manufactured or isolation between the threads. As such , the sub 65 is elec
modified to accommodate the particular coating that is used , 60 trically isolated from the sub 66 . It will be appreciated that
e . g ., based on the strength , hardness , etc . of the material used the second sub -assembly 67 can be assembled in a similar
and the clearance needed for an adequate layer of isolation . manner.
In another embodiment, after application of the ceramic It will be appreciated that all of the above insulative
coating, a layer of electrical tape or similar thin adhesive materials can be used to provide layer 71 as described , as
layer can be included in the insulative layers 71 and 73 to 65 well as any combination of one or more . For example , the
add protection for the ceramic coating from chipping or ceramic coating may be used on its own or in combination
cracking from inadvertent collisions. The electrical tape with woven fabric 71a . It can be appreciated that each layer
 US 9 ,995 , 135 B2
provides an additional safeguard in case one of the other battery 210 from the barrel 208 and bulkhead 202 ; replacing
layers fails . When more than one insulative material is used the battery 210 with a new battery ; and reassembling the EM
in conjunction with each other, the isolation can be consid - module 104 , barrel 208 and directionalmodule 94 . Since the
ered much stronger and more resilient to environmental upper connector 214 and lower connector 212 are visually
effects . 5 different, the nature of the battery 210 should assist the
As shown in FIG . 4 (also seen in FIG . 2 (b )), the sub operator in placing the battery 210 in the barrel 208 in the
assemblies 64 and 67 are connected together without any correct orientation . Similarly, since , in this example , only
electrical isolation therebetween . The upstream tool portion the end 203 connects to a bulkhead 202, if the entire battery
108 is electrically connected to the drill string 20 at contact assembly 200 is removed , the ends 201 , 203 should be
point 74 and the downstream tool portion 110 is electrically 10 obviously distinguishable to the operator.
connected to the drill string 20 at contact point 76 provided It can therefore be seen that the battery 210 can be readily
by the interface of the modified landing bit 104 and the removed from the barrel 208 when a new battery is to
UBHO 60 . It can be seen that the sub -assemblies 64 and 67 replace it. The arrangement shown in FIGS. 6 - 8 thus enables
should be sized such that when the modified landing bit 76 a “ quick change ” procedure to minimize the timerequired to
is seated in the UBHO 60 , the tool isolation 102 is between 15 change the battery 210 , which can often be required in poor
the non -conductive rings 70 and 72 and more importantly, environmental conditions . It can be appreciated that mini
such that the bow Springs 92 contact the drill string 20 above mizing downtime increases productivity , which is also desir
the region of isolation 29. This enables the electric field F to able.
be created by creating the positive and negative dipoles.
Power Supply — Quick Change Battery 20 MWD Tool - First Embodiment
As discussed above, the EM tool string 100 may include
a quick change battery assembly 200 . The quick change A schematic diagram showing data flow in one embodi
battery assembly 200 can provide 14V or can be configured ment, from a series of downhole sensor 120 to the surface
to provide any other voltage by adding or removing battery station 34 using the EM tool string 100 is shown in FIG . 9 .
cells . Preferably , the quick change battery assembly 200 is 25 The sensors 120 acquire measurements for particular down
connected to the other modules in the EM tool string 100 as hole operating parameters and communicate the measure
shown in FIGS. 6 - 8 . Referring first to FIG . 6 , an exploded ments to the master controller 96 in the directional module
view is provided showing the connections between the 94 by sending an arbitrary m number of inputs labelled IN , ,
battery assembly 200 and the EM module 104 using module IN ,, . . . , IN , from an arbitrary m number of sensors 120 .
interconnect 90 . In the example shown , the battery assembly 30 The master controller 96 is part of an existing pulse MWD
200 includes a battery barrel 208 that is connected directly module , namely the directional module 94 , as discussed
to the module interconnect 90 at one end 201 and thus the above . The master controller 96 generates and outputs a
end 201 includes a similar interconnection . A bulkhead 202 pulse transmission signal labelled P , which is an encoded
is connected to the other end 203 of the battery barrel 208 voltage pulse signal.
to configure the end 203 for connection to the module 35 Generally, encoding transforms the original digital data
interconnect 90 attached further upstream of the directional signal into a new sequence of coded symbols. Encoding
module 94 . Typically , another battery assembly 98 is in turn introduces a structured dependency among the coded sym
connected to the directional module 94 as discussed above . bols with the aim to significantly improve the communica
The battery barrel 208 houses a battery 210 . The battery tion performance compared to transmitting uncoded data . In
210 includes a number of battery cells . It will be appreciated 40 one scheme, M - ary encoding is used (e . g . in the GE Ten
that the barrel 208 can be increased in length to accommo- sorTM tool), where M represents the number of symbol
date longer batteries 210 having a greater number of cells. alternatives used in the particular encoding scheme.
The battery 210 in this example includes a lower 45 degree The encoded data is then modulated , where , modulation is
connector 212 and an upper 90 degree connector 214 . The a step of signal selection which converts the data from a
lower connector 212 preferably includes a notch 213, which 45 sequence of coded symbols ( from encoding ) to a sequence
is oriented 45 degrees from the orientation of a notch 215 in of transmitted signal alternatives . In each time interval, a
the upper connector 214 . The notches 213 and 215 are particular signal alternative is sent that corresponds to a
shown in greater detail in FIG . 7 . The notches 213 and 215 particular portion of the data sequence . For example , in a
are different from each other so as to be distinguishable from binary transmission , where two different symbols are used ,
each other when the battery 210 is installed and thus 50 the symbol representing a “ high ” or “ 1 ” , will be sent for
minimize human error during assembly . As can be seen in every “ 1” in the sequence of binary data . In the result, a
FIG . 7 , the notches 213 and 215 are generally aligned with waveform is created that carries the original analog data in
respective retention mechanisms 220 and 222 . The mecha- a binary waveform . Where M is greater than 2 , the number
nisms 220 and 222 are preferably pin assemblies that of symbol alternatives will be greater and the modulated
maintain the position of the battery 210 in the barrel 208 . 55 signal will therefore be able to represent a greater amount
The upper end 214 of the battery 210 is preferably data in a similar transmission .
centered in the barrel 208 using a bushing 216 , as shown in M -ary encoding typically involves breaking up any data
FIGS. 7 and 8 (wavy line in FIG . 7 ) . The bushing 216 is word into combinations of two (2 ) and three ( 3 ) bit symbols ,
arranged along the inside of the barrel 208 at end 203 and each encoded by locating a single pulse in one -of- four or
situates the upper connector 214 to inhibit movement and 60 one -of -eight possible time slots . For example , a value 221
potential cracking of the battery casing. encodes in M -ary as 3 , 3 , 5 . The 3 , 3 , 5 sequence comes from
The battery 210 can be changed in the field either by the binary representation of 221 , which is 111011 101. In this
removing the battery barrel 208 from the EM module 104 way, the first 3 comes from the 2 -bit symbol 11 , the second
and the directional module 94 or , preferably , by disconnect 3 comes from the 3 -bit symbol 011 , and the 5 comes from
ing the directional module 94 from the bulkhead 202 (which 65 the 3 -bit symbol 101.
disconnects the upper connector 214 ); disconnecting the It can be appreciated that different directional modules 94
lower connector 212 from the EM module 104 by pulling the may use different encoding schemes, which would require
 US 9 ,995, 135 B2
13 14
differentdecoding schemes. As will be explained below , the A data connection D may also be provided for commu
EM transmitter module 106 is configured to intercept and nicating between the EM controller module 122 and an
redirect an amplified version of Pw such that the EM trans optional EM receiver ( not shown ) that can be included in the
mitter module 106 is compatible with any directional mod - EM transmitter module 106 . This can be implemented for
ule 94 using any encoding scheme. In this way , the EM 5 providing bi -directional communication allowing the EM
transmitter module 106 does not require reprogramming to transmitter module 106 to receive commands/ information
be able to adapt to other types of directional modules 94 . from the surface system 34 via EM signals and relay the
This provides a versatile module that can be interchanged information to the EM controller module 122 .
with differentmud pulse systems with minimum effort . The microcontroller 126 passes the encoded pulse signal
The output Põ is a modulated voltage pulse signal. The 10 Pa to the EM amplifier module 124 . The microcontroller 126
modulated signal is intended to be used by the pulse module also outputs voltage and current limit signals Vlim and Ilim
86 to generate a sequence of pressure pulses according to the respectively that are used by the amplifier module 124 to
modulation scheme used . However , in the embodiment control a voltage limiter 136 and a current limiter 138
shown in FIG . 9 , the EM transmitter module 106 intercepts respectively. The EM signal is fed into an amplifier 140 in
the modulated voltage signal. The EM transmitter module 15 the amplifier module 124 in order to repeat an amplified
106 includes an EM controller module 122 and an EM version of the Pt signal in an EM transmission to the
amplifier module 124 . The controller module 122 intercepts surface.
P and also outputs a flow control signal f and communi A current sense module 142 is also provided , which
cation signal Comm . The flow control signal f is used to senses the current in the EM signal that is to be transmitted ,
determine when " flow " is occurring in the drilling mud . 20 namely EM , as feedback for the current limiter and to
Ultimately , when fluid is being pumped downhole (" flow generate a current output signal low for the controller module
on ” condition ), drilling has commenced and data is required 122 . The amplified EM signal labelled EM ' is monitored by
to be transmitted to the surface. Although EM telemetry does the voltage limiter 136 and output as Vout to the controller
not require “ flow ” in the drilling mud to be operational, module 122 . As can be seen in FIG . 9 , a connection point 74
existing directional modules 94 are designed to work with 25 above the isolation 102 provides a conductive point for
pulse modules 86 . As such , existing directional modules 94 return signal EMrer, and EM is sent to a connection 76 in
require flow in order to operate since pressure pulses cannot the UBHO 60, which as shown in FIG . 3 (b ) is naturally
be created in a static fluid column M . Moreover, when flow below the isolation 102 .
stops, the drill string 20 and the MWD tool 30 become The EM transmit signal EM , is the actual EM transmis
“ stable " and allow other more sensitive measurements to be 30 sion , and is sent through the formation 16 to the surface . The
acquired ( e. g . accelerometer and magnetometer data ), stored EM return signal EM ,et is the return path for the EM
and transmitted on the next " flow on " event. transmission along path S through connection 144 . It willbe
The flow control signal f in the EM controllermodule 122 appreciated that either signal (EMG or EMret ) can be the
is used to instruct the master controller 96 when a consistent signal or the return ,however the arrangement shown in FIG .
vibration has been sensed by the vibration switch 128 . The 35 9 is preferred since the drill string 20 typically provides a
master controller 96 may then use the flow signal f to better reference than the formation 16 . EM propagates
activate its internal “ flow on ” status . The Comm signal is through the formation as a result of creation of the positive
used to allow communication between the EM controller and negative dipoles created by the potential difference
module 122 and the master controller 96 . Such communi- across the connections 74 and 76 , which creates the electric
cation allows the EM controller module 122 to retrieve 40 field F . The ground stake 50 conducts the EM signal and
operational information that the MWD operator has pro - propagates a received signal EM along line 52 to the
grammed into the master controller 96 before the job has surface station 34 .
commenced , e. g . current limit values . The surface station 34 , when using conventional mud
The EM controller module 120 and EM amplifier module pulse telemetry may include the components shown in FIG .
122 are shown in greater detail in FIG . 10 . The controller 45 11 . A mud pulse signal which propagates up through the
module 120 comprises a microcontroller 126 , which drilling mud M is received and interpreted by a pressure
receives the encoded Por signal, and generates the flow transducer, which sends a current signal to the pulse decoder
control signal f. The flow signal f is generated in response to 32 . The pulse decoder 32 then decodes the current signal and
an output from a vibration switch 128 connected to the generates an output to send to the PC 36 for the user to
microcontroller 126 . The vibration switch 128 responds to 50 interpret, which may also be sent to the rig floor display 45 .
vibrations in the drill string 20 generated by mud flow , As can be seen in FIG . 9 , where the conventional mud pulse
which is generated by a mud pump included in the surface system is adapted to transmit using EM telemetry , the EM
drilling equipment 22 . The microcontroller 126 also com - surface system 38 intercepts the incoming EM signal EM ,
municates with a serial driver 130 to generate the Comm and generates an emulated received pulse signal labelled
signal. In a GE TensorTM tool, the Comm signal is referred 55 P . The emulated pulse signal P , ' is generated such that the
to as the Qbus. pulse decoder 32 cannot distinguish between it and a normal
Optionally, the controller module 120 may also include a received pulse signal Pyr. In this way , the pulse decoder 32
clock 132 for time stamping information when such infor - can be used as would be usual, in order to generate an output
mation is stored in the EM controller module log memory OUT, for the PC 36 , output OUT, for the rig floor display
134 . This enables events stored in the logging memory 134 60 45 .
to be correlated to events stored in memory in the master The PC 36 is generally used only for interfacing with the
controller 96 or events that occur on the surface , once the system , e . g . programming the MWD toolstring 100 and
memory is downloaded . The EM controller module 122 is pulse decoder 32 , and to mimic the rig floor display 45 so
thus capable of logging its own operational information ( e. g . that the operator and directional driller can see in the surface
current limits, resets etc .) and can log information it receives 65 station 34 what is seen on the rig 10 without leaving the
via the Comm line connected to the master controller 96 station 34 . Optionally, an interface connection 148 may be
(e.g . mode changes ). provided between the PC 36 and the EM surface system 38
 US 9 ,995 , 135 B2
15 16
for controlling parameters thereof and to communicate ter module 106 can be used with any type of pulse system
downhole as discussed above . The operatormay thus use the without requiring additional programming .
PC 36 to interface with the EM surface system 38 and send The pulse signal Px is intended to be sent to the pulse
changes in the operational configuration by way of another module 86 but is intercepted by the EM transmitter module
EM signal ( not shown ), which may or may not be encoded 5 106 . Regardless of the encoding scheme being used , the
in the same way as the master controller 96 , downhole via microcontroller 126 obtains and redirects the pulse signal P &
EM , and EM , EMr. The EM receiver would then receive , to the EM amplifier module 124 . The microcontroller 126
decode and communicate configuration changes to the EM does not decode or have to interpret the pulse signal P , in
controller module 122 . The EM receiver module would thus 10 any way and only redirects the signal to the amplifiermodule
124 . The amplifier 140 amplifies the P signal to create
be in communication with EMret and EMq downhole. amplified EM signal EM ', which is transmitted from the EM
The EM surface system 38 is shown in greater detail in transmittermodule 106 as EM signal EM , with a return path
FIG . 12 . The received EM signal EM , is fed into a first gain being provided for return signal EM -ot.
amplifier 150 with the return signal EMFpt also connected to During operation , the amplified signal EM ' is fed through
the amplifier 150
the ampler 130 inin order
order toto provide
provide aa ground
ground reference for 1515 the
relerence for the current
c sense module 142 to continuously obtain a
the EM signal EM . x The amplifier 150 measures the poten current reading for the signal. This current reading is fed
tial difference of the received EM signal EM ,x and the back to the current limiter 138 so that the current limiter 138
ground reference provided by the return signal EMret and can determine if the amplifier 140 should be adjusted to
outputs a referenced signal. The referenced signal is then achieve a desired current. The current and voltage limit and
filtered at a first filtering stage 151. The first filtering stage 20 amplification factor are largely dependent on the type of
151 may employ a band reject filter, low pass filter, high pass battery being used and thus will vary according to the
filter etc . The filtered signal is then fed into a second gain equipment available . The voltage of the amplified signal is
amplifier 152 to further amplify the signal, which in turn is also monitored by the voltage limiter 136 to determine if the
fed into a second filtering stage 153. The second filtering amplifier 140 should be adjusted to achieve a desired
stage 153 can be used to filter out components that have not 25 voltage . The microcontroller 126 also monitors the ampli
already been filtered in the first filtering stage 151. The fied output voltage Vow and amplified output current low to
filtered signal is then fed to a third gain amplifier 154 in adjust the voltage limit Vlim and current limit Ilim signals .
order to perform a final amplification of the signal. It will be The limits are typically adjusted according to predeter
appreciated that the number of filtering and amplification mined parameters associated with the directional module 94
stages shown in FIG . 12 are for illustrative purposes only 30 which are used in order to increase or decrease signal
and that any number may be used in order to provide a strength for different formations and are changed downhole
conditioned signal. The signal is then fed into a pressure by instructing the master controller 96 with differentmodes .
transducer emulator 158 , which converts the filtered and The EM controller module 122 is used to communicate with
amplified voltage signal into a current signal thus creating the master controller 96 as discussed above , to determine the
emulated pulse signal P . !. The emulated pulse signal P . ' is 35 active mode and to set the current limit accordingly . Typi
then output to the pulse decoder 32 . cally , the current limit is set as low as possible for as long
It can be seen in FIG . 12 that the filtering and amplifi as possible to save on power consumption , however , this
cation stages 150 - 154 each include a control signal 160 factor is largely dependent on transmission capabilities
connected to a user interface port 156 . The user interface through the formation and the available battery power.
port 156 communicates with the PC 36 enabling the user to 40 During operation , the microcontroller 126 also generates
adjust the gain factors and filter parameters ( e .g . cut off the flow signal f and Comm signal to indicate when flow is
frequencies ). It will be appreciated that rather than employ - detected and to effect communication with the master con
ing connection 148 to the PC 36 , the EM surface system 38 troller 96 .
may instead have its own user interface such as a display and The transmitted EM signal is received at the EM surface
input mechanism to enable a user to adjust the gain and 45 system 38 as EM , and the signal returned via EM -t. These
frequency parameters directly from the EM surface system signals are typically in the milli- volt to micro - volt range ,
38. which is largely dependent on the depth of the down hole
antenna and the formation resistance . The potential differ
Exemplary Data Transmission SchemeFirst ence of these signals is then measured by the first amplifier
Embodiment 50 150 and a combined signal amplified and filtered to com
pensate for attenuation and altering caused by the formation .
Referring now to FIGS . 13 and 14 , an example data The amplified and filtered signal is then fed into the pressure
transmission scheme for the embodiment shown in FIGS. transducer emulator 158 to convert the voltage pulse sent via
9 - 12 will now be explained .Measurements are first obtained EM telemetry, into a current signal. It has been found that for
by one or more of the sensors 120 , typically while the 55 a GE TensorTM pulse decoder 32, a current signal in the
equipment 22 is drilling. Measurements can be obtained range of 4 - 20 mA is sufficient to mimic the pulse signal P
from many types of sensors, e.g . accelerometers, magne normally sent by a pressure transducer. This conversion
tometers , gamma, etc . As discussed above, the sensors 120 ensures that the emulated pulse signal Pr' is compatible with
feed data signals IN ,, IN ,, . . . , IN , to the master controller the pulse decoder 32 . This avoids having to create new
96 in the directional module 94 . The master controller 96 60 software and interfaces while enabling the user to utilize EM
encodes the data using its predefined encoding scheme. As telemetry with existing directional modules.
mentioned above , a GE TensorTM tool typically utilizes The emulated current signal Pyx ' is then fed into the pulse
M -ary encoding. Other pulse tools may use a different type decoder 32 . The pulse decoder 32 then decodes and outputs
of encoding . The encoded pulse signalPis then output by the information carried in the encoded signal to the PC 36
themaster controller 96 . As discussed above , EM controller 65 enabling the user in the surface station 34 to monitor the
122 is compatible with any type of encoding scheme and is downhole parameters . Another output can also be transmit
not dependent on such encoding. As such , the EM transmit- ted simultaneously via line 44 to the rig floor display 45 to
 US 9 ,995 , 135 B2
17 18
enable the drilling equipment operators to also monitor the seen , the drill bit 18 and mud motor 26 are unchanged , as
downhole conditions. FIG . 13 shows an exemplary signal well as the upstream portion 62 of the drill string 20 and the
plot at the various stages discussed above. region of isolation 29 . In order to accommodate both the EM
Mode changes can be executed in the downhole tool transmitter module 106 and the pulse module 86 in a dual
string by communicating from the surface system to the 5 telemetry tool string 170 , an elongated , modified UBHO 60a
downhole tool string. Some forms of communication can is used . The modified UBHO 60a compensates for the
include , but are not limited to , downlinking and EM trans - increased distance between where the tool string 170 lands
missions. Downlinking is only one common form of com - and where the isolation 102 is in alignment with the region
munication , in particular for a GE TensorTM tool, for chang - of isolation 29 . As shown in FIG . 16 , the dual telemetry tool
ing between pre -configured modes in the master controller 10 string 170 includes the traditional landing bit 82 with the
96 . Downlinking can be performed by alternating flow on pressure valve 84, which is connected to the pulse module
and flow off (pumps on , pumps off) at the surface , with 86 . A modified interconnect 91 is then used to connect the
specific timing intervals , where certain intervals correlate to EM transmitter module 106 to above the pulse module 86 .
differentmodes . The flow on and flow off events are detected Upstream from the EM transmitter module 106 is the same
by the vibration switch 138 on the EM controller module 15 as shown in FIG . 3 ( b ) and thus the details of which need not
122 and in turn the flow signal f is toggled accordingly . This be reiterated .
is then interpreted by the master controller 96 , which is Referring to both FIG . 15 and FIG . 16 , it can be seen that
always monitoring the flow line f for a downlink . Once a in the dual telemetry tool string 170 , the EM transmitter
downlink has occurred , depending on the timing interval, the module 106 is spaced further from the landing point and the
master controller 96 changes to the desired mode . The EM 20 traditional pulse landing bit 82 is used . Similar to the EM
controller module 122 communicates via the Comm line to tool string 100 , existing mud pulse modules can be used with
the master controller 96 to determine the correct mode, and the EM modules to create a dual telemetry MWD tool 30 .
adjusts its own settings accordingly ( e . g . pulse /EM opera - FIG . 17 shows an electrical schematic for the second
tion - dual telemetry discussed below , current limit , etc . ). embodiment. It can be seen that the configuration is largely
The surface system 38 is also watching for the flow events 25 the same with various modifications made to accommodate
and changes its operating mode to match the downhole both telemetry modes . A modified controller module 122a ,
situation . includes a multiplexer 172 to enable the EM transmitter
The MWD tool 30 shown in FIGS. 9 - 12 enables a driller module 106a to bypass the amplifier module 124 and send
to upgrade or add EM capabilities to existing mud -pulse the pulse signal P ., directly to the pulse module 84 when
systems. When switching between telemetry modes in a 30 operating in pulse telemetry mode . The modified controller
single telemetry embodiment, only the pulse module 86 and module 122a is shown in FIG . 18 . It can be seen that the
landing bit 82 needs to be removed downhole (along with multiplexer 172 is operated by a signal x provided by a
batteries as required ), and a connection swapped at the modified microcontroller 126a to direct Por either to the
surface station 34 . The connection would be at the pulse microcontroller 126a or bypass to the pulse module 84 . A
decoder 32 , namely where a pressure transducer would 35 surface pressure transducer 176 is also shown, which would
normally be connected to the pulse decoder 32 . In order to normally be in fluid communication with the mud column M
switch the downhole components between mud -pulse telem so as to be able to sense the pressure pulses sent by the pulser
etry and EM telemetry , the drill string 20 could be tripped , module 86 . The other components shown in FIG . 18 are
however, switching at the surface can be effected off -site by similar to those discussed above as indicated by the similar
simply swapping connectors at the pulse decoder 32 and 40 reference numerals and thus details thereof need not be
there would be no need to access the rig 10 or drilling reiterated .
equipment 22 in order to make such a change. The pressure At the surface, a modified EM surface system 38a is used
transducer can thus remain installed in the rig 10 whether as shown in FIG . 19 . It can be seen that the filtering and
EM or mud -pulse telemetry is used . Of course , a wireline amplification stages 150 -154 , user interface port 156 and
could instead be used rather than tripping the entire drill 45 emulator 158 are the same as shown in FIG . 12 . A surface
string 20 to add further efficiencies. multiplexer 174 is used to enable either the emulated pulse
It may be noted that when a switch between telemetry signal P , ' to be sent to the pulse decoder 32 in EM telemetry
modes is made between shifts , i.e . when the string 20 is to mode as discussed above , or the normal pulse signal P ,
be tripped anyhow , the driller will not likely be unduly obtained from the pressure transducer 176 . A modified
inconvenienced . The quick change battery 200 can also be 50 interface signal 148 includes a connection to themultiplexer
used to save time since it can be swapped in an efficient 174 to enable the user to send a mode control signal y to the
manner . multiplexer 174 to change telemetry modes.
MWD Tool Second Embodiment Exemplary Data Transmission Scheme Second
55 Embodiment
In another embodiment, shown in FIGS. 15 - 20 , theMWD
tool 30 is adapted to offer dual telemetry capabilities, in Referring now to FIGS. 20(a ), 20 (6 ) and 20 (c ), an
particular, to accommodate both an EM telemetry mode and example data transmission scheme for the second embodi
mud - pulse telemetry mode without tripping either or both of ment shown in FIGS. 15 - 19 will now be explained . Refer
the tool string and drill string . It will be appreciated that in 60 ring first to FIG . 20 (a ), similar to the first embodiment, data
the following description , like elements will be given like is obtained from the sensors 120 by the master controller 96 ,
numerals, and modified ones of the elements described and an encoded output is sent to the pulse module 86 . Also
above will be given like numerals with the suffix " a ” to as before , the EM transmitter module 106 intercepts the
denote modules and components that are modified for the encoded signal Pr. When in operation , the microcontroller
second embodiment . 65 126a is provided with a mode type, indicating whether to
Referring first to FIG . 15 , a downhole drill string con - operate in an EM mode or a pulse mode . The telemetry mode
figuration for the second embodiment is shown. As can been can be indicated by downlinking from the surface system 34 .
 US 9,995 ,135 B2
20
The microcontroller 126 determines the appropriate mode between a first telemetry mode and a second telemetry
and if pulse telemetry is to be used , control signal x is set to mode while the system is downhole , one of the first and
1 such that the multiplexer 172 directs the pulse signal Pex to second telemetry modes comprising mud pulse telem
the pulse module 86 as can be seen by following “ B ” to FIG . etry , and the other of the first and second telemetry
20 ( b ). In the pulse mode, the EM transmitter module 106 5 modes comprising electromagnetic (EM ) telemetry,
does not operate on a signal and thus is idle during the pulse wherein the downlink command is generated by con
mode The pulse module 86 uses the transmit pulse signalPbx trolling flow of mud in a mud column in a drill string
to generate a series of pressure pulses in the mud column M , into which the MWD system has been deployed .
which are sensed by the pressure transducer 176 at the 2 . The method of claim 1, wherein the downlink com
surface , where they are converted into a current signal and 10 mand is generated by alternating flow on and flow off from
sent to the surface station 34 . the surface , using specific timing intervals .
As before , the EM surface system 38a intercepts the 3 . The method of claim 2 , wherein the downlink com
received pulse signal Pyx and directs the signal to the pulse mand is detectable by a vibration switch in the downhole
decoder 32, thus bypassing the EM circuitry. This is accom - system .
plished by having the interface signal 148a set the control 15 4 . The method of claim 3, wherein the vibration switch
signal y = 1 , which causes the multiplexer 174 to pick up the responds to vibrations generated by mud flow to cause
pulse signal Pyr . This is then fed directly into the pulse generation of a flow signal in the downhole system .
decoder 32 , where the signal can be decoded and output as 5 . The method of claim 2 , wherein the timing intervals
described above . correlate to different modes .
Turning back to FIG . 20(c ), if the microcontroller 126a is 20 6 . The method of claim 2 , wherein the alternating flow on
instructed to operate in EM telemetry mode, control signal and flow off corresponds to pumps on and pumps off
x is set to x = 0 , which causes multiplexer 172 to direct the operations.
pulse transmit signal P & to the amplifier module 124 , which 7. The method of claim 1, further comprising monitoring
can be seen by following “ C ” to FIG . 20 ( c ). It can be flow events at a surface system to change an operating mode
appreciated from FIG . 20 ( c ) that transmission in the EM 25 for the surface system according to the second telemetry
telemetry mode operates in the same way as in the first mode .
embodiment with the addition of the interface signal 148a 8 . The method of claim 7 ,wherein changing the operating
setting control signal x to x = 0 , causing the multiplexer 174 mode for the surface system comprises enabling a corre
to direct the emulated pulse signal Pr' to the pulse decoder sponding receiver module to decode received signals .
32 . Accordingly, details of such similar steps need not be 309 . Themethod ofclaim 1, further comprising detecting an
reiterated. instruction to change telemetry modes.
Therefore, the use of dual telemetry may be accomplished 10 . The method of claim 9 , wherein the instruction is
by configuring a dual telemetry tool string 170 as shown in generated at a surface system .
FIG . 16 with a modified EM transmitter module 106 , and 11 . A system for controlling a dual telemetry measure
modifying receiver module 38 to include a multiplexer 174 . 35 ment while drilling (MWD ) system , the system comprising
This enables the EM modules to work with the existing pulse a controller configured to operate flow of a mud motor to
modules . An EM transmission may be used that mimics a send from surface , a downlink command to a downhole
mud -pulse transmission or the original pulse signal used . In system to remotely switch the downhole system between a
the result , modifications to the pulse decoder 32 , pulse first telemetry mode and a second telemetry mode while the
module 86 or landing bit 82 are not required in order to 40 system is downhole , one of the first and second telemetry
provide an additional EM telemetry mode while taking modes comprising mud pulse telemetry, and the other of the
advantage of an existing mud-pulse telemetry . Moreover, the first and second telemetry modes comprising electromag
drill string 20 does not require tripping to switch between netic (EM ) telemetry , wherein the downlink command is
mud -pulse telemetry and EM telemetry in the second generated by controlling flow ofmud in a mud column in a
embodiment. 45 drill string into which the MWD system has been deployed .
12 . The system of claim 11 , wherein the downlink com
Further Alternatives mand is generated by alternating flow on and flow off from
the surface, using specific timing intervals.
It will be appreciated that the tool strings 100 and 170 can 13 . The system of claim 12 , wherein the downlink com
also be modified to include other modules, such as a pressure 50 mand is detectable by a vibration switch in the downhole
module (not shown ). For example , a similar arrangement as system .
shown in FIG . 3 (b ) could be realized with the pressure 14 . The system of claim 13 , wherein the vibration switch
module in place of the pulse module 86 and the modified responds to vibrations generated by mud flow to cause
landing bit 104 in place of the landing bit 82 . It will be generation of a flow signal in the downhole system .
appreciated that the tool string 100 may also bemodified to 55 15 . The system of claim 12 , wherein the timing intervals
include pulse telemetry , EM telemetry and a pressure mod correlate to differentmodes.
ule by making the appropriate changes to the drill string 20 1 6 . The system of claim 12 , wherein the alternating flow
to ensure that the isolation exists for EM telemetry . on and flow off corresponds to pumps on and pumps off
Although the above has been described with reference to operations.
certain specific embodiments, variousmodifications thereof 60 17 . The system of claim 11 , further configured to monitor
will be apparent to those skilled in the art as outlined in the flow events at the system to change an operating mode for
claims appended hereto . the system according to the second telemetry mode .
The invention claimed is : 18 . The system of claim 17 , wherein changing the oper
1 . A method of operating a dual telemetry measurement ating mode for the system comprises enabling a correspond
while drilling (MWD ) system , the method comprising: 65 ing receiver module to decode received signals.
sending from surface , a downlink command to a down- 19 . The system of claim 11 , further comprising detecting
hole system to remotely switch the downhole system an instruction to change telemetry modes.
 US 9 ,995 , 135 B2
21
20 . The system of claim 19 , wherein the instruction is
generated at the system .
21. The method of claim 1 , further comprising :
detecting the downlink command at the downhole system ;
and
toggling a flow signal to indicate desired mode change to
a controller of the downhole system .
22 . The system of claim 11 , further comprising a module
in the downhole system configured for:
detecting the downlink command at the downhole system ; 10
and
toggling a flow signal to indicate desired mode change to
a controller of the downhole system .
* * *