MWD/LWD
Systems
Introduction
Introduction
Sperry-Sun’s modular MWD (measurement-while-drilling) systems
have been designed to meet a wide variety of directional
surveying/steering, formation evaluation, geosteering, and drilling
efficiency applications. These data, measured while drilling, are
available in real time and recorded modes at the wellsite and can be
transmitted directly to office-based computer systems. In addition,
the MWD data can be made available anywhere in the world in real
time via secure Internet connections.
Sperry-Sun’s modular design allows the tool string to be configured
with virtually any combination of sensors to meet specific
application and BHA design requirements. Three different real-time
telemetry systems (turbine-powered positive mud pulse, batterypowered negative mud pulse, and electromagnetic) are available to
provide dependable real-time data under a wide range of drilling
conditions and with any type of drilling fluid. Real-time data
transmission is supplemented by recording data in downhole
memory for retrieval after each bit run.
The shock, vibration, and heat of the downhole drilling environment
make survival of any electronic instrument difficult. Continuous
improvements in design and qualification have resulted in tough,
reliable systems that perform bit run after bit run. These reliable
systems are operated by experienced, well-trained field engineers
and are backed up by an extensive network of maintenance
facilities.
Sensor Availability and Applications
Sperry-Sun provides a wide variety of MWD/LWD sensors for
various applications, including:


Directional Surveying and Steering

Triaxial magnetometer/accelerometer sensors for wellbore
inclination and aximuth, as well as gravity (high-side) and magnetic
toolface direction

ABI™ (at-bit inclination) triaxial accelerometer mounted in the mud
motor bit box immediately above the bit
Formation Evaluation

DGR™ (dual gamma ray) and GM (gamma module) natural gamma
ray sensors provide API gamma ray logs

EWR-PHASE 4™ (electromagnetic wave resistivity) multiple-depthof-investigation propagation resistivity sensor provides eight
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Introduction
resistivity measurements for determining Rt, even in invaded or
anisotropic formations
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SLD™ (stabilized lithodensity) compensated spectral formation
density tool provides bulk densisty and Pe measurements

CN® (compensated neutron porosity) and CTN™ (compensated
thermal neutron) porosity measurements complement density
measurements for porosity evaluation, gas identification, and
lithology determination

ACOUSTICALIPER™ ultrasonic MWD caliper tool provides
accurate hole size data for log quality control and borehole correction
Geosteering

DGR™ sensor provides high-side and low-side gamma ray logs in
real time to keep the wellbore in the reservoir formation

Deep-reading EWR-PHASE 4™ sensor, combined with the
EWRMOD geosteering modeling program, detects approaching bed
boundaries and fluid contacts

IMM (instrumented mud motor) incorporates either the DGR™
sensor or the EWR-PHASE 4™ sensor into the drive section of the
motor, close to the bit

ABI™ sensor gives instant feedback on directional trends for precise
trajectory control
Drilling Efficiency

PWD® (pressure-while-drilling) service provides highly accurate
downhole annular and bore pressures for monitoring of ECD,
swab/surge pressures, hole cleaning, kick detection, pack-off
detection, downhole leak-off test and formation integrity tests, and
other applications

DDS™ (drillstring dynamics sensor) sensor comprises a triaxial
accelerometer and records average and peak X-, Y-, and Z-axis
accelerations, as well as frequency spectrum data. It can be used to
detect bit bounce, stick/slip, bit whirl, lateral vibrations, and other
harmful drilling conditions.

ACOUSTICALIPER™ tool provides accurate hole size and borehole
ellipticity measurements for monitoring borehole stability and
detecting borehole breakout, washouts, key seats, and ledges. It can
also log while tripping out to facilitate accurate cement volume
calculations when running casing.

MERCURY™ EMT (electromagnetic telemetry) system can be used
for real-time MWD data transmission in situations in which mud
pulse telemetry systems are unable to operate, such as underbalanced
drilling and foam or air drilling.
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Introduction
Tool Size Availability
BHA DIAMETER
3 3/8
86
3½
89
4¾
121
6½
165
6¾
171
7¼
184
7¾
197
8
203
9½
221
MM
MM
MM
MM
MM
MM
MM
MM
MM
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Sensors
Directional (PM, DM, PCD)
At-bit inclination (ABI™)
Gamma ray (GM, PCG)
Azimuthal gamma ray (DGR™)
Resistivity (EWR-PHASE 4™)
Formation density (SLD™)
Neutron porosity (CNØ®)

Neutron porosity (CTN™)
Acousticaliper (ACOUSTICALIPER™)
Sonic (BAT™)
Annular/bore pressure (PWD®)
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Drillstring vibration sensor (DDS™)
Instrumented mud motor (IMM)
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Telemetry Systems
Positive pulse (DWD)
Positive pulse (SOLAR 175®)
Negative pulse
Electromagnetic (MERCURY™)
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Enhanced Formation Evaluation
Sperry-Sun’s modular FE sensors can be configured in a variety of
ways, depending on the information requirements, BHA design, and
well economics. Multiple depth-of-investigation resistivity, bulk
density, neutron porosity, and gamma ray sensors can be combined
for applications ranging from marker bed correlation to hydrocarbon
typing. MWD measurements are typically made within hours of
drilling through zones of interest, when minimal formation damage,
alteration, or formation fluid displacement has occurred. In areas
with difficult drilling conditions, MWD can be used to avoid timewasting conditioning trips or expensive pipe-conveyed logging
operations.
Time lapse logging, or logging the well with MWD at different
times during the drilling process, can enhance FE. Measurements
taken at different times during the drilling process can reveal
dynamic invasion effects, which yield new information on
hydrocarbon mobility, gas-oil-water contact points, and formation
permeability. This type of information is not available at any other
4 of 68
Introduction
time during the life of the well. Sperry-Sun’s suite of FE sensors is
well-suited for this advanced technique due to high-density data
recording and unique measurement technology.
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Telemetry Systems
Telemetry Systems
Overview
Sperry-Sun’s modular MWD/LWD systems have been designed to
accommodate the rapidly changing needs for downhole data with
minimum impact on the drilling operation. Modularity of the
systems allows the tool strings to be customized to specific logging
and drilling requirements. Accurate survey/steering, gamma ray,
multiple depth-of-investigation resistivity, formation density,
neutron porosity, drillstring vibration, and annular pressure data are
available real time and recorded in downhole memory at the wellsite
and can be transmitted directly to office-based computer systems.
The data acquired by Sperry-Sun’s MWD/LWD downhole sensors
can be transmitted to the surface in real time using one of three
different telemetry systems and/or recorded in downhole memory
and retrieved at the surface after each bit run. The three real-time
telemetry systems are:

Negative mud pulse

Positive mud pulse


Standard positive mud pulse (DWD)

High-temperature positive mud pulse (SOLAR 175)
Electromagnetic
The high-speed negative mud pulse system is used for LWD
services in 6 ¾” (171 mm), 8” (203 mm), and 9 ½” (241 mm) tool
sizes. The positive mud pulse system is used for all MWD/LWD
services in all tool sizes, as well as for SLIMHOLE® (4 ¾” [121
mm] tool size) and SUPERSLIM® MWD service. The
MERCURY™ electromagnetic MWD system is employed in
situations in which conventional mud pulse telemetry is not
feasible, such as underbalanced drilling and foam or air drilling.
Negative Pulse Telemetry System
The negative pulser is used to provide MWD/LWD services in 6 ¾”
(171 mm), 8” (203 mm), and 9 ½” (241 mm) tool sizes at a high
data rate (up to 5 bits/second). The pulser’s simple design employs
only a single moving part in a sliding gate-and-seat valve. This
valve momentarily vents fluid from the bore of the drillstring to the
annulus, creating a pressure drop that propagates to the surface
(negative pulse).
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Telemetry Systems
Schematic diagram of the negative pulser
The negative pulser is self-cleaning. During the 100 msec that the
valve is open during each pulse, debris may collect on the intake
screen. However, once the valve closes, mud flow down the bore
washes the screen clean. This self-cleaning design allows LCM
concentrations of up to 40 lb/bbl (115 kg/m3) medium nut plug to be
pumped with no impact on telemetry.
The amplitude of the negative pulse signal is a function of the
differential pressure (350–3,700 psi) between the bore of the
drillstring and the annulus. A minimum pressure drop of 350 psi
below the pulser is recommended for good pulse detection at the
surface, although pulse detection with pressure drops as low as 150
psi has been achieved. If necessary, a pressure-drop sub can be run
below the pulser to increase pressure at the bit. The 6 ¾” (171 mm)
and 8” (203 mm) tools have a mass flow rate limit of 10,000
lb/minute (20,000 lb/minute for the 9 ½” [241 mm] tool) to prevent
excessive erosion of the pulser components.
The negative pulser is normally run at the top of the LWD tool
string to achieve minimum bit-to-sensor spacing. A float sub above
the pulser is recommended to prevent back-flow through the valve
while tripping in to prevent damage. When a float sub is used, it
must be installed above the tool, never below.
The negative pulser is powered by a lithium battery. Redundant bore
pressure sensors are used to detect circulation and activate the
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Telemetry Systems
pulser. The LWD sensors are also battery-powered, which allows
log data to be acquired and stored in memory, even when not
circulating. This feature facilitates efficient re-logging or logging
while tripping.
The negative pulse system can be programmed with two downholeselectable customized data formats. The parameter content of each
format is user-selectable prior to each bit run. The two downloaded
formats can be selected from the surface by a simple pump cycling
routine. This flexibility tailors data transmission to the application.
For example, one format could contain more frequent toolface
updates for steering in a sliding mode, while another format would
allow more formation-evaluation data updates when passing zones
of interest.
The negative pulse system uses a pulse-position modulation data
encoding scheme. The rapid action of the sliding gate-and-seat
valve creates very sharp, discrete pulses. Because the arrival time of
these pulses at the surface can be precisely determined, data values
are encoded as a variable time delay between two consecutive
pulses. This allows multiple bits of data to be communicated with
one pulse, providing a significant increase in data rate compared
with most positive pulse systems, in which under most encoding
schemes each pulse equates to a single binary bit.
Pulse position modulation telemetry
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Telemetry Systems
Negative Pulser Specifications
TOOL OD
Negative pulser
nominal overall length
Nominal maximum
OD
Nominal ID
Connections
Make-up torque range
Maximum dogleg
severity
Sliding
Rotating
Equivalent bending
stiffness
Maximum temperature
6 ¾”
(171 MM)
8”
(203 MM)
Mechanical Specifications
9.5’
9.6’
9 ½”
(241 MM)
10.2’
6 ¾”
8”
9 ½”
1.92”
4 ½” IF boxbox
30,000–
33,000 ft-lb
1.92”
6 5/8” reg
box-box
53,000–
58,000 ft-lb
2.437”
7 5/8” reg
box-box
87,000–
91,000 ft-lb
21°/100’
10°/100’
6.54” x 2.81”
14°/100’
8°/100’
7.76” x 2.81”
14°/100’
8°/100’
9.35” x 3”
Operating Limits
302°F
302°F
(150°C)
(150°C)
18,000 psi
18,000 psi
10,000 lb/min 10,000 lb/min
302°F
(150°C)
15,000 psi
20,000 lb/min
Maximum pressure
Maximum mass flow
(gpm x ppg)
Maximum sand
2%
2%
5%
content
LCM tolerance*
<40 lb/bbl medium nutplug
Pulsation damper
Recommended charge to 60%
Typical pressure loss
42–414 psi
42–414 psi
11–80 psi
over tool (water @
250–1,000 gpm)
*LCM concentrations of 135 lb/bbl have been achieved under laboratory
conditions. Special terms and conditions may apply above 40 lb/bbl.
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Telemetry Systems
MPT™/FEWD Tool Specifications
TOOL OD
121MM
4 ¾” FE
171MM
6-3/4"
216MM
8"
241MM
9-1/2"
Operating Limits
MaxDogleg Severity:
Sliding
Rotating
30°/100 ft
14°/100 ft
Equivalent Bending Stiffness
4.6 in x 2.25 in
Maximum Temperature
21°/100 ft
10°/100 ft
6.54 in. x 2.81
in.
14°/100 ft
14°/100 ft
8°/100 ft
8°/100 ft
7.76 in. x 2.81
in.
9.35 in. x 3in.
302°F (150°C)
302°F (150°C)
302°F (150°C)
302°F (150°C)
Maximum Pressure
18,000 psi
18,000 psi
18,000 psi
18,000 psi
Maximum Flow Rate
150-350 gpm
NA
NA
1600 gpm
Max RPM
250 RPM
180 RPM
180 RPM
180 RPM
Max weight on Bit
25000 lbs
45000 lbs
45000 lbs
45000 lbs
6300 lb/min
10,000 lb/min
10,000 lb/min
20,000 lb/min
2%
1%
1%
5%
<20 lb/bbl
Medium
Nutplug
<40 lb/bbl
Medium
Nutplug
<40 lb/bbl
Medium
Nutplug
-
Maximum Mass Flow (gpm x
ppg)
Maximum Sand Content
LCM Tolerance a
Pulsation Damper
Max Vibration, from SSDS
DDS tool, for all tool sizes
Recommend
Recommend
Recommend
Recommend
charge to 40%
charge to 60%
charge to 60%
charge to 60%
Average X Greater than 6G – <18 Mins
Average Y Greater than 6G – <18 Mins
Average Z Greater than 4G - <8 Mins
Peak X - No.of G's Greater Than 130 G < 50 Peaks
Peak Y - No.of G's Greater Than 130 G <150 Peaks
Peak Z - No.of G's Greater Than 30 G <100 Peaks
Jarring
Typical Pressure Loss Over
Tool (water @ 250–1000
gpm)
Jarring is out side of tool specification.
120 psi at 150
gpm
42–414 psi
42–414 psi
11–80 psi
a
LCM concentrations of 135 lb/bbl have been achieved under laboratory conditions. Special terms and conditions may
apply above 40 lb/bbl
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Telemetry Systems
Typical Telemetry Update Rates with the Negative
Pulse System
TYPICAL TRANSMITTED
PARAMETERS*
.5
1
2
.5
1
2
SEC
SEC
SEC
SEC
SEC
SEC
MIN PULSE TIME
UPDATE RATE
(SEC)**
MIN PULSE TIME
ROP @ 1
SAMPLE/FT
(FT/HR)
Survey†
54
65
90
NA NA
Toolface
4
5
8
900 720
Toolface/gamma ray
8
11
17
450 327
Gamma ray/deep resistivity
6
9
14
600 400
Toolface/gamma ray/deep resistivity 10
14
22
360 257
Gamma ray/shallow/medium, and
12
17
27
300 211
deep resistivity
Toolface/gamma ray/shallow,
16
22
35
225 163
medium, and deep resistivity
Gamma ray/deep
16
22
34
225 163
resistivity/neutron/density
Toolface/gamma ray/deep
20
27
42
180 133
resistivity/neutron/density
Gamma ray/shallow, medium, and
22
30
47
163 120
deep resistivity/neutron/density
Toolface/gamma ray/shallow,
25
35
55
144 102
medium, and deep
resistivity/neutron/density
*Based on INSITE™ system Ver 4.0 software.
**Based on bit width of 40 ms, pulse width of 100 ms, and average data
values.
†Time includes 30-sec transmission delay from starting pumps.
NA
450
211
257
163
133
102
105
85
76
65
RLL® LWD Service
For applications in which real-time data are not required, SperrySun’s RLL® (recorded lithology logging) service can be a costeffective alternative to real-time MWD systems. This service
provides LWD data recorded while drilling or wiping and retrieved
from the tool’s downhole memory when the tool is tripped to the
surface. All of Sperry-Sun’s MWD/LWD sensors can be run in a
recorded-only mode, some of which are listed below.

DGR™ sensor

EWR-PHASE 4 sensor

CN sensor
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Telemetry Systems

CTN™ sensor

SLD™ tool

PWD® service

ACOUSTICALIPER™ tool

DDS™ sensor
The RLL® service can also be used in conjunction with real-time
LWD systems. For example, a high-angle underbalanced well could
be drilled using the MERCURY™ electromagnetic MWD system to
provide real-time directional and gamma ray data for directional
drilling application while resistivity and porosity data are acquired
and stored in downhole memory. This could eliminate the time and
cost of wireline logging and simultaneously provide a “triplecombo” log for quantitative formation evaluation. The RLL®
service can be particularly cost-effective when compared with
drillpipe-conveyed wireline tools for logging high-angle and
horizontal wells.
In the ABI™/azimuthal DGR™ configuration, the dual azimuthal
gamma ray measurements near the bit can provide early detection of
a change of formation and determine the relative angle at which the
bit has crossed a bed boundary. This can tell the operator which way
to steer the well in order to stay in the producing formation.
The gamma will detect a change in “formation lithology” as it
crosses the boundary. We can determine whether the top or bottom
of the reservoir has been penetrated, thus allowing us to steer back
into the reservoir if we exit prematurely. We can also determine
whether a facies change has been encountered or a fault boundary
has been crossed.
Gamma Ray Sensors
DGR™ Sensor
Overview
Redundant dual
detector banks of
rugged Geiger-Müller
tubes provide
superior reliability.
The DGR™ sensor is made up of two opposed banks of GeigerMüller tubes with two independent detector circuits. This redundant
configuration provides two independent natural gamma ray logs.
The count rates from the two detector banks are typically combined
in order to optimize statistical precision. However, in the unusual
event of a failure of one detector bank, a corrected gamma ray log
12 of 68
Telemetry Systems
can be produced from the second detector bank. The DGR™ sensor
is available in 4 ¾”, 6 ¾”, 8", and 9 ½” tool sizes.
Schematic diagram of the DGR™ sensor showing dual, redundant detector
banks.
Azimuthal gamma ray
measurements are
used in geosteering
applications.
For geosteering in horizontal wells, the DGR™ sensor can be
configured to provide azimuthal gamma ray measurements. In this
application, the two opposed DGR™ sensor detector banks can
provide independent gamma ray logs from the high side and low
side of the borehole. This can, for example, allow the operator to
determine if the bit has exited the top or the bottom of a target
reservoir formation.
DGR™ Sensor Specifications
PARAMETER
SPECIFICATION
Detector type
Dual banks of Geiger-Müller
tubes
8 sec
0–380 API
±3 API @ 50 API
9”
Recommended minimum sample period
Measurement range
System accuracy
Vertical resolution
Operating Limitations
The electronics are mounted on a sealed insert, allowing a clear bore
profile. The sensor package is vibration-tested to 20 g and will
readily cope with normal drilling operations.
13 of 68
Telemetry Systems
The DGR™ sub is normally run with the resistivity sub, providing
an accurate lithology log. It must be run with the CIM (central
interface module) sub, which provides battery power, memory, and
telemetry signal conditioning. It may be made up in any order with
other Sperry-Sun formation evaluation sensors to optimize near-bit
positioning. Make-up is normally conducted prior to mobilization.
The sub may be run slick if desired and with either positive or
negative pulse modules.
The CIM will store data at preset sample rates. This allows a highresolution log to be processed on the surface. Also, high-definition
logs of sections of interest from the real-time telemetry log can be
re-examined by logging while tripping/wiping, etc. Both telemetry
and memory sample rates are programmable to meet operating
requirements.
The DGR™ sensor measurements are relatively unaffected by the
wellbore environment because measurements are normally taken in
gauge and with relatively low mud volumes due to collar
displacement. Corrections can be applied for mud weight,
potassium levels, and borehole size.
Operating Applications
 Well correlation—The DGR™ sensor provides the best possible
correlation in field appraisal and development drilling,
particularly if initially used on exploratory and delineation wells
for development well correlation. In many fields, the DGR™
sensor alone is suitable for real-time casing and core point
selection.
 Safety—The DGR™ sensor will accurately chart bed
stratification. Run with the resistivity sensor, it enables pore
pressure prediction, leading to faster, safer exploratory drilling
and operations in difficult fields.
 Log of record—Run with the resistivity sensor, the DGR™
sensor will provide intermediate logs of definitive quality for
archive uses while providing information to improve drilling
operational efficiency.
 Enhanced interpretation of wireline logs—Higher data sampling
rates (recorded log) give greater definition and more exact bed
delineation, which aids in identifying the smoothing/averaging
effects of high wireline traverse speeds.
 Directional control—The DGR™ sensor allows for improved
trajectory monitoring.
Quality Assurance
Philosophy
14 of 68
Telemetry Systems
The small diameter (4.892”) of the API gamma ray calibration pit
precludes the immersion of typical MWD collars. Consequently, a
secondary calibration standard made of granite was developed and
is located at our Houston headquarters complex. A small diameter
gamma ray sonde was used to establish the correlation between the
primary calibration standard (API pit) and this secondary standard
(284 API units). This block of granite has a 10” diameter air-filled
hole in it, thereby accommodating all MWD tools up to and
including 9 ½” outside diameter tools. The scale factor required to
transform each type of tool’s raw count rate to API units was
determined in the granite secondary standard. Using an air-filled
standard eliminates the perturbing problem of tool size–dependent
borehole attenuation, a fact that would have to be accounted for in a
liquid-filled secondary standard. The field strength, in API units, of
a precisely manufactured clamp-on gamma ray–emitting calibrator
was then determined for each particular tool type. These clamp-on
calibrators are manufactured to produce a radiation field that is
identical to that produced by the master calibrator, which is kept in
Houston. Consequently, any calibrator can be used with any tool.
Additionally, the calibration values, in API units, are adjusted every
two years to account for the gradual decrease in the strength of the
calibrator’s radioactive sources.
Note: In order to be consistent between calibration and
environmental correction reference conditions and to define a waterfilled borehole as the reference condition for gamma ray
environmental effect calculations, the clamp-on calibrator’s field
strength values were adjusted (by approximately 10%) to reflect a
water-filled borehole reference condition.
Methodology
A gamma ray verifier being
used at the Stavanger shop
during a pre-job checkout.
A clamp-on gamma ray–emitting calibrator is used to derive the
unique scale factor for each bank of detectors in a particular tool.
During the calibration process, two count rate readings are
measured for each bank of detectors with counting periods of
sufficient duration to minimize statistical variances. One reading is
taken with the calibrator clamped on the tool, and the second
reading is taken with the calibrator removed (background). The
background reading is used to compensate for local variances in
background gamma ray radiation. These two readings are used in a
linear scaling equation to determine the calibration scale factor
(CALSCL) for each bank of detectors. These tool-specific scale
factors are entered in the surface software system’s database by the
field engineer and are used to transform raw counting rates to values
of API units.
15 of 68
Telemetry Systems
There is little variation in
CALSCL value between
runs.
The CALSCL values determined in the district shop are checked for
stability between logging runs using the same clamp-on
calibrator/verifier and the same procedures used for the actual
calibration. Appropriate changes to the CALSCL factors can be
made on a run-to-run basis. Experience has shown that there is little
variation in CALSCL factors between runs, and consequently these
factors are rarely adjusted at the wellsite.
GM Sensor
The GM sensor is a sonde-based gamma ray sensor designed for
SOLAR 175® operations.
A Geiger-Müller tube design was selected due to the rugged nature
of the tubes and their ability to survive at high temperatures. In a
scintillation detector–based gamma tool, the sodium iodide crystal
element begins to boil off at temperatures exceeding 165°C, which
rendered scintillation detection assemblies unfit for SOLAR 175®
operation.
Similar to that of the DGR™ sensor, the GM sensor telemetry
module will record the gamma ray data at a separate preset ample
rate independent from the real-time update rate. This allows a highresolution log to be processed on the surface. Both telemetry and
memory sample rates are programmable to meet operating
requirements.
The GM sensor contains three stacked individual banks of GeigerMüller tubes, with four tubes in each bank. Unlike the DGR™
sensor, the individual banks of tubes are not designed for
redundancy. Twelve tubes were determined to be the minimum
acceptable to achieve the required count rate for statistical accuracy.
The choice to use three separate stacked banks was based on size
constraints of the sonde. This design involves summing the counts
of the individual banks rather than taking their average for a
combined measurement.
GM Sensor Specifications
PARAMETER
SPECIFICATION
Detector type
Three banks of GeigerMüller tubes
8 sec
±2 API
250 hr of API data at 8-sec
intervals; variable storage
rate or 8–254 sec
Recommended minimum sample period
System accuracy
Recorded data
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Telemetry Systems
Quality Assurance
GM sensor calibration is traceable back to the primary calibration
standard (API pit). Because the GM sensor is sonde-based, two
calibration factors are required to produce an API measurement.
Individual sondes are calibrated using the same clamp-on gamma
ray–emitting calibrator and methodology as with the DGR™ sensor.
This establishes scale factors for the individual detector banks of the
sonde. Collar scale factors used to correct for collar attenuation
were determined for collars of differing ID and OD in the granite
secondary calibration standard at our Houston headquarters. These
two calibration factors are combined in the surface systems database
and are used to transform raw counting rates to values of API units.
The scale factors reflect a water-filled borehole reference condition.
Corrections can be applied for mud weight, potassium levels, and
borehole size.
Resistivity Sensor
EWR-PHASE 4™ Sensor
Overview
Multiple depth-ofinvestigation
resistivity
measurements are
provided.
The EWR (electromagnetic wave resistivity)-PHASE 4™ sensor is a
state-of-the-art, high-frequency induction resistivity sensor. This
tool comprises four radio-frequency transmitters and a pair of
receiver antennas. By measuring both the phase shift and
attenuation from each of the four transmitter-receiver spacings,
eight different resistivity curves with differing depths of
investigation can be provided. The EWR-PHASE 4™ tool is
available in 4 ¾”, 6 ¾”, 8", and 9 ½” (configuration differs due to
tool dimensions) tool sizes and can log boreholes ranging from 5 7/8”
to more than 26" in diameter.
The EWR-PHASE 4™ sensor has four transmitter-receiver spacings.
17 of 68
Telemetry Systems
Anisotropy inversion
and geosteering
modeling are used in
horizontal wells.
These multiple resistivity measurements facilitate various
interpretation programs. The INVAMOD radial inversion program
computes Rt, Rxo, and Di in invaded formations; this can be
particularly applicable when logging significantly after drilling
when formations may be deeply invaded, e.g., logging a cored
interval on a subsequent bit run. The ANIMOD anisotropy inversion
computes Rv, Rh, and relative dip angle when logging anisotropic
formations at high angles, and the EWRMOD geosteering forward
modeling provides a synthetic log along the proposed well path to
use as a correlation "road map" when geosteering horizontal wells.
Sperry-Sun's EWR family of tools has been in commercial service
since 1984 and has established a track record of high reliability
under a wide variety of formation and borehole conditions.
EWR-PHASE 4™ Sensor Specifications
PARAMETER
SPECIFICATI
ON
Minimum sample period
—Real time
—Recorded
Measurement range
—Phase
—CPA
System accuracy @ 10 -m
Vertical resolution
4 sec
3 sec
0.05–2,000
-m
0.1–100 m
±1%
6” for all
spacing
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Telemetry Systems
DIAMETER OF INVESTIGATION
@ 0.2 -M
@ 20 -M
Xshallow phase
Shallow phase
Medium phase
Deep phase
Xshallow CPA
Shallow CPA
Medium CPA
Deep CPA
15”
18”
22”
30”
25”
30”
38”
50”
30”
39”
54”
75”
77”
86”
104”
145”
Operating Limitations
The EWR-PHASE 4™ sensor may be run with positive or negative
telemetry. At higher ROPs, real-time bed resolutions are better
defined with negative pulse telemetry.
Operating Applications

Resolves thin sand beds surrounded by shales

Makes deep measurements before invasion

Improves identification of hydrocarbon/water contacts

Detects movable hydrocarbons
Quality Assurance
Philosophy
The amplitude-measuring
circuit of the EWR-PHASE
4™ tool is calibrated at
operating temperatures
using a precise laboratory
standard.
The relationships between the four phase shifts and four amplitude
ratios sensed by the EWR-PHASE 4™ tool’s two receivers and the
surrounding resistivity were derived from a combination of
measurements made in lakes, rivers, and laboratory tanks and the
results of mathematically modeling the tool’s responses. The
amplitude-measuring circuit of the tool’s receiver is calibrated over
the tool’s operating temperature range using a very precise
laboratory standard. Both the phase shift and amplitude-measuring
circuits have very small inherent electronic offsets. These electronic
offsets and the geometric spreading losses for the attenuation
measurements are quantified by observing the tool’s responses in
air, which is assumed to be infinitely resistive. “Airhang” offset
values, as a function of temperature, are determined for each of the
four transmitter-receiver spacings.
19 of 68
Telemetry Systems
Methodology
Input data, measured data,
and temperature data are
correlated using a different
fifth order polynomial for
each of two operating
frequencies.
The tool’s receiver insert is placed in an oven and connected to a
very precise laboratory attenuator network, which is located in our
Houston headquarters complex. The amplitude of the signal injected
in the near and far receivers’ RF input circuits is varied across the
entire operating range as the temperature is increased. The
temperature is varied from ambient to 140C. The input data, the
measured data, and the temperature data are correlated using a
different fifth-order polynomial for each of the two operating
frequencies, 1 MHz and 2 MHz. A file containing the resulting 48
coefficients is stored in the tool’s EEPROM. This procedure is one
part of the amplitude measurement’s calibration process.
Periodic “airhang”
procedures create new
calibration files.
The entire tool is placed in an oven and heated to approximately
150C. It is then placed on stands in a metallic-free air environment
(“airhang”), and its readings of phase shift and amplitude ratio are
monitored by a test computer as the tool cools down to ambient
temperature. These readings are segmented into temperature-based
cells, each having a range of two degrees, and averaged. These
averages of “airhang” phase shift and amplitude ratio, as a function
of tool temperature, are stored in two files in the tool’s EEPROM.
This procedure is performed periodically in the district shop,
thereby creating new calibration data files that are downloaded into
the tool.
Finally, a file containing just the ambient “airhang” data is created
and downloaded into the tool’s EEPROM. These data are used as
the reference values for pre- and post-job and pre- and post-run QA
“airhang” checks. This ambient “airhang” file is appended to as
required and serves as an onboard historical calibration trend record
because it can hold up to 35 data sets.
Temperature sensor
determines the values of
calibration parameters to
use during data
processing.
A very accurate temperature sensor, located in the EWR-PHASE
4™ receiver, is used to determine the actual temperature of the tool
while logging and consequently the values of the various calibration
parameters to use during data processing. All calibration-related
data processing is performed in the tool while logging.
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Telemetry Systems
Formation Density Sensor
SLD™ Sensor
Overview
The SLD™ (stabilized lithodensity) sensor comprises two gainstabilized, 254-channel spectral scintillation detectors and a Cs137
gamma ray source housed in a steel drill collar. Overlying the
source and detectors is a special stabilizer blade containing three
low-density windows. The stabilizer blade emulates the detector pad
of a wireline density tool, minimizing borehole effect, while the
low-density windows collimate the gamma rays and focus the
measurement. The SLD™ sensor is available in 4 ¾”, 6 ¾”, and 8"
tool sizes and can log boreholes ranging from 5 7/8" to 12 1/4" in
diameter.
Robust "spine-andrib" correction
compensates for up to
1" of stand-off.
Undergauge
stabilizers may be
used to facilitate
sliding with steerable
drilling assemblies.
Rotational rapidsampling technique
provides accurate
density log in
enlarged boreholes.
The basic SLD™ sensor data acquisition and processing are
essentially the same as that for wireline compensated spectral
density tools. Density and Pe values are computed from count rates
in various energy windows at each detector. The compensated
density is then computed from the near-detector and far-detector
density values using a "spine-and-rib" technique. The SLD™ sensor
has a particularly robust spine-and-rib or "delta-rho" compensation
that accurately corrects for stand-off distances of up to 1". This
allows the routine use of ½"-undergauge stabilizers to facilitate
sliding with steerable drilling assemblies.
For stand-off distances greater than 1”, as may be encountered in the
event of significant borehole washout, a statistical analysis
technique is employed to segregate valid data obtained under
minimal stand-off conditions from invalid data obtained at large
stand-off distances. Thus, an accurate formation bulk density log
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Telemetry Systems
can be obtained in enlarged or washed-out boreholes or with
undergauge density tool stabilizers.
SLD™ Sensor Specifications
Hole size
8 ½”
Collar
6 ¾” OD
dimensions
Stabilizer/blade
gauge
Approximate
weight (lb)
Sub connections
Torque (external
connections)
Length
Maximum mass
flow rate
Maximum sand
content
8 ½”, 8 ¼”, 8”
1,600
9 7/8”
6 ¾” OD
12 ¼”
8” OD
9 7/8”, 9 5/8”, 9
3/8”
2,300–3,100
12 ¼”, 12”, 11
¾”
3,650
Box x pin 4 ½”
Box x pin 4 ½”
Box x pin 6 5/8”
IF API
IF API
API reg
30,000–33,000 ft 30,000–33,000 ft 52,000–56,000 ft
lb
lb
lb
12.4’ (3.79 m)
13.48’ (4.12 m)
13.63’ (4.16 m)
10,000 lb/minute (for SLD™ collar only)
5% (for SLD™ collar only)
PARAMETER
BULK DENSITY MEASUREMENT
SPECIFICATION
Recommended minimum sample period
Measurement range
System accuracy
Statistical precision1
Vertical resolution
10 sec
1.0 to 3.10 g/cm3
±0.025 g/cm3
0.015 g/cm3
18”
PHOTOELECTRIC (PE) MEASUREMENT
Measurement range
System accuracy
Statistical precision1
Vertical resolution
1 to 20 B/e
±0.25 B/e (1 - 5 B/e)
± 3% (1 - 5 B/e)
6”
. Statistical precision for a 30-second sample rate in a 2.2 g/cc formation.
Operating Applications

Rapid sampling for density-derived caliper

Bulk density

Photoelectric effect

Borehole standoff

Wireline-quality density measurements
Quality Assurance
Philosophy
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Telemetry Systems
Primary calibration
standards are located in
Houston, with secondary
standards in each major
district.
The primary calibration standards are aluminium (Al), magnesium
(Mg), and marble (zero porosity CaC03) blocks located in our
headquarters facility in Houston, Texas. These consist of several
pieces of each material containing boreholes of 8 ½”, 9 7/8”, 12 ¼”,
and 14” diameters. The density of each block has been determined
by sample analysis. The boreholes in the blocks are vertically
oriented, and the tools are calibrated by pressing them firmly against
the borehole walls.
Secondary calibration standards are used in the major districts. At
present, these are aluminium and magnesium blocks. Calibrations
are performed in slots machined horizontally into these blocks.
These slots have curvatures corresponding to 9 7/8” and 14”
diameter boreholes.
Methodology
Each SLD™ tool is calibrated in the primary standard blocks in
Houston after its manufacture or any major maintenance. The basic
density calibration consists of determining a straight-line
relationship between the logarithm of the counting rate for each
detector and the electron densities of the calibration blocks. Current
practice is to use the magnesium and aluminium for a two-point
density calibration and the tool’s density response in marble as a
QA check. The marble, along with the aluminium and the
magnesium blocks, provides a three-point calibration for the
photoelectric factor calibration.
SLD Spine & Rib
1.0
Borehole Fluids
Spine
Water
10.2 ppg
11.6 ppg
1 1/2"
1.5
13.9 ppg
1 1/4"
16.1 ppg
1"
1/4"
1/2"
3/4"
1/4"
Magnesium Rib
Far (g/cm3)
1/2"
3/4"
1"
2.0
1 1/4"
1 1/2"
Aluminum Rib
2.5
All points taken at 1/4" intervals
3.0
3.0
2.5
2.0
1.5
1.0
Near (g/cm )
3
MWD Density Standoff
Correction Comparison
0.6
True - Far
0.4
SLD
CDN
BHI 6 3/4"
BHI 8 1/4"
ADN
0.2
0.0
-0.2
-0.2
0.0
0.2
0.4
0.6
Far - Near
A spine-and-ribs
comparison of standoff
corrections for all
commercial MWD
density tools showing
the superior response of
the SLD™ sensor.
The basic correction for tool standoff (standoff correction) depends
on the difference in the apparent densities determined individually
from the near and far detectors and is similar in form and
methodology to the “delta-rho” correction utilized in wireline
logging. With each primary standard calibration, standoff data are
acquired using borehole fluids of two different densities. Water is
used in the aluminium block, and 15 ppg mud is used in the
magnesium block. A single polynomial equation is derived from
these data, and the resulting coefficients constitute the standoff
correction calibration for a particular tool. This correction is
effective for standoffs as large as 1” (2.54 cm) and is used in a
conventional logging mode, where counts are averaged through
several rotations of the tool, and in a “rapid sampling” mode, where
small standoff data samples are distinguished from large standoff
data samples by statistical methods.
The calibration procedure using the secondary standard (horizontal)
blocks in the district shop is somewhat different. A well-defined QA
setup procedure precedes the actual calibration in each block. The
purpose of this procedure is to assure intimate contact between the
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Telemetry Systems
tool and the slotted calibration block. The tool is systematically
moved through a set of positions in order to locate the position of
minimum counts, which corresponds to the best contact between the
tool’s detector blade and the block. The two-point density
calibration is performed at zero-standoff only. Therefore, the
standoff correction coefficients determined during the last primary
calibration are maintained. Currently, new photoelectric factor
calibration coefficients are not derived; those determined during the
last primary calibration are maintained. The last several sets of
calibration data are stored in the tool’s memory and serve as an
onboard historical calibration trend record.
The continuous spectral
calibration of each
detector’s output is
accomplished by
monitoring the spectral
position of the cesium
photo peak between
logging runs.
A secondary, but extremely critical, issue is the continuous spectral
calibration of each detector’s output. This is accomplished using
two small cesium reference sources, one of which is near the
scintillation crystal of each detector. This source provides a constant
background spectrum for each detector. The energy gain for each
detector is maintained near 3.3 KeV/channel by the tool’s software,
which detects the photopeak of the reference spectrum and
maintains its position within three channels of channel 200 by
controlling the high-voltage bias on each photomultiplier tube as
well as the electronic gain of each detector’s output circuit.
Monitoring the spectral position of the cesium photopeak between
logging runs is one of the primary wellsite QA checks performed by
the field engineer.
All calibration-related data processing is performed in the tool while
logging.
Neutron Porosity Sensors
CN® Sensor
Overview
The CNØ® (compensated neutron porosity) sensor has been in
commercial service for more than 10 years, providing high-quality
neutron porosity log data with extremely high reliability. The
CNØ® sensor employs two redundant banks of Geiger-Müller tubes
at both the near and far detector spacings. The Geiger-Müller tubes
detect neutron-capture gamma rays. The vast majority of the
detected gamma rays originate from thermal neutron capture in the
drill collar wall, which also shields the detectors from gamma rays
originating in the formation. Thus, the steel drill collar and GeigerMüller tubes function in combination as a thermal neutron detection
system, providing a neutron porosity response and lithology effect
similar to that of conventional thermal neutron tools while
24 of 68
Telemetry Systems
benefiting from the mechanical ruggedness of Geiger-Müller
detectors.
The CNØ® sensor is available in 6 ¾” and 8" tool sizes for logging
boreholes ranging from 8 ½” to 12 ¼” in diameter. For slimhole
neutron porosity service, the 4 ¾” CTN™ tool is available for
logging holes as small as 5 7/8".
CNØ® Sensor Specifications
PARAMETER
SPECIFICATION
Recommended minimum sample period
Measurement range
System accuracy
Statistical precision1
Vertical resolution
10 sec
0–100 pu
±0.5-1 pu @ 20 pu
±2 pu @ 20 pu
24”
. Statistical precision for a 30-second sample rate.
Operating Applications

Porosity measurements

Hydrocarbon typing
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Telemetry Systems
Quality Assurance
Philosophy
All neutron sources’
outputs are periodically
normalized to a master
source.
A neutron porosity tool
being calibrated at the
Stavanger R & M facility.
The primary calibration standard is the API Neutron Log
Calibration Pit located on the campus of the University of Houston.
Additional limestone pits and other “formation simulators” were
used to derive the fundamental relationships between the counting
rates of the tool’s near and far detectors and the porosity (hydrogen
index) of the surrounding medium. A canonical tool’s near and far
detectors’ counting rates were then determined in a water-filled
tank, the secondary calibration standard. These counting rates are
used as the master calibration values, against which all other tools
are calibrated. The apparent porosity is derived from the absolute
counting rates of the near and far detectors. Consequently, all
neutron sources’ outputs are periodically normalized to that of a
master source.
Methodology
Periodically, each CNØ® tool is calibrated by immersing it in a
water-filled tank. A calibration scaling factor that compensates for
minor differences between a particular tool and the canonical tool is
derived for each of the four detector banks. This calibration factor is
used to scale each bank’s counting rate to its canonical value prior
to the derivation of a value of apparent porosity. These four
calibration factors plus the specific source’s normalization factor are
entered in the surface software system’s database by the field
engineer and downloaded to the toolstring during initialization.
A clamp-on gamma ray–emitting verifier is then placed on the tool,
and the increase in counting rate over the background radiation level
is documented for each detector (reference values). These clamp-on
verifiers are manufactured to produce a radiation field that is
identical to that produced by a master verifier that is kept in
Houston. Consequently, any verifier can be used with any tool.
Exact same verification procedure is repeated between logging runs
and is used to monitor the stability of the tool’s response. The
allowable variance from the reference values is  3%.
CTN™ Sensor
Overview
The CTN™ sensor is a new slimhole 4 ¾” neutron porosity tool
designed for logging boreholes ranging from 5 7/8” to 6 ½” in
diameter. The CTN™ sensor can be combined with the slimhole
26 of 68
Telemetry Systems
EWR-PHASE 4™, DGR™, SLD™, and PWD sensors to provide
"triple-combo" logging services in slim holes. The CTN™ tool
employs redundant banks of He3 neutron detectors at both the near
and far spacing for added reliability.
CTN™ Sensor Specifications
PARAMETER
SPECIFICATION
Recommended minimum sample period
Measurement range
System accuracy
10 sec
-5–100 pu
±0.5 pu (0-10 pu)
±5% (10-50 pu)
±1.2 pu @ 30 pu
12”
5.25”
11.14’
600 lb
17,500 ft/lb
503,500 lb
4.715” OD x 2.25” ID
Statistical precision1
Vertical resolution
Maximum OD
Overall length
Total weight
Minimum torsional yield strength
Minimum tensile yield strength
Equivalent bending stiffness
. Statistical precision for a 30-second sample rate.
Operating Limitations
PARAMETER
OPERATING LIMITATION
Temperature (operating)
Temperature (survival)
Sand content
Pressure
RPM
WOB
Dogleg (steering)
Dogleg (rotating)
Flow rate
Mass flow rate
140C
150C
2%
20,000 psi
250
25,000 lb
30/100’
14/100’
350 gpm
5,000 lb/min
Operating Applications

Porosity measurements

Hydrocarbon typing

Cased hole logging
Quality Assurance
The districts use a 4’ diameter water tank and a set of four
aluminum sleeves. The OD of the largest sleeve is 12”, and the ID
of the inner sleeve if 5 ½”. The basic procedure is to take data with
all four sleeves. Next, the outer sleeve is removed, and data are
taken with three sleeves. Finally, the third sleeve is removed, and
27 of 68
Telemetry Systems
data are taken with the remaining two sleeves. Count rates in these
cases correspond approximately to apparent porosities of 15 pu, 25
pu, and 45 pu. These three points will be cross-plotted with the
golden tool response in the sleeves, and a straight line will be fit
through them.
A verifier is also available at the rig site.
Drillstring Vibration Sensor
DDS™ Sensor
Overview
Reduce the number of
downhole tool failures by
modifying BHA design and
drilling parameters to
reduce downhole
vibrations.
The DDS™ sensor is a three-axis shock and vibration sensor whose
electronics and accelerometers are mounted on the insert of the
DGR™ sensor. Tri-axial accelerometers measure lateral, torsional,
and longitudinal vibration. Average, peak, and instantaneous
acceleration data are recorded. Real-time analysis of the data can be
used to detect and identify common causes of damaging downhole
vibration, such as bit bounce, lateral shock, stick/slip, and PCD bit
whirl.
The DDS™ sensor is run as an additional sensor on the negative
pulser inside the gamma insert. It provides downhole vibration
information from three orthogonal accelerometers that can be used
to prevent tool failures. High vibrations have been correlated to
drillstring failures and to the failure of downhole tools, such as
MWD tools. When high-vibration loads are detected, drilling
parameters (e.g., rpm, WOB) can be modified to reduce these
vibrations and reduce the risk of tool failures.
The DDS™ sensor is incorporated into the DGR™ sensor.
28 of 68
Telemetry Systems
Three mutually orthogonal accelerometers are used to measure three
axes of accelerations: X, Y, and Z. The accelerometers are rated for
±200 g with a frequency response of 5,000 Hz and a resolution of
0.2 g. The X axis is used to measure both lateral and radial
acceleration. The Y axis is used to measure both lateral and
tangential acceleration, and the Z axis is used to measure axial
acceleration.
Each accelerometer response is monitored for average, peak, and
instantaneous (burst) acceleration. The peak and average values are
computed every 4 seconds regardless of the operator input data
storage period. In the average acceleration circuit, the signal is halfwave rectified, meaning all the negative values are “clipped”
(ignored). The signal is then integrated over the 4-second time,
frame resulting in an average acceleration for that interval. The
integrator is then zeroed and a new sample frame begins.
In the peak acceleration circuit, the signal is half-wave rectified,
with the resulting signal input to an analog peak detector. The peak
value represents the highest voltage from the accelerometer since
the last sample. After each sample period, the detector is zeroed and
a new peak detection begins.
Instantaneous accelerometer measurements are made when an
operator-selectable downloaded triggering threshold is exceeded.
The sensor has the capability of measuring the accelerometers at
100, 500, 1000, or 2000 times per second. The instantaneous data
measured is called “burst” data, which will be used for vibration
frequency analysis.
The instantaneous circuit has the capability of sampling at three
different resolutions: high, medium, and low. High resolution will
be used to measure accelerations in the 20 g range. The medium
range is 20 g to 60 g, and low resolution is used to measure large
accelerations up to 200 g. The operating specifications for the
DDS™ sensor are the same as for the DGR™ sensor in which it is
mounted.
DDS™ Sensor Specifications
Parameter
Range
Resolution
Sample Rate
Average X, Y, and Z
Peak X, Y, and Z
Instantaneous X, Y, and Z
0–50 g
0–200 g
0–200 g
0.2 g
1g
0.2–1g
4–120 sec
4–120 sec
100–2,000
samples/sec
Operating Applications
DDS™ SENSOR RESPONSE SUMMARY
29 of 68
Telemetry Systems
Harmful Downhole
Conditions
Primary Indication
Secondary Indication
Whirl
High average X and Y
accelerations
Separation between
average X and Y
accelerations
High peak Z
acceleration
High peak X and Y
acceleration
Instantaneous data
analysis
Separation between
peak X and Y
accelerations
High average Z
acceleration
High average X and Y
acceleration
Torsional vibration
(slip-stick)
Axial vibration (bit
bounce)
Lateral shocks
Axial vibration and associated bit bounce can be measured directly
from the Z accelerometer.
In pure lateral vibration, where the RPM is constant, the radial (r2)
and tangential (r) accelerations will both be zero. Consequently,
the X and Y axes measure the vector components ax and ay of the
lateral accelerations. The maximum accelerations can be calculated
by taking the square root of the “peak X” plus “peak Y” data
squared.
Torsional (slip-stick) vibration creates fluctuations in downhole
rpm. These changes are measured by the X and Y accelerometers.
Due to the long period of slip-stick motion (usually several
seconds), the tangential component should be smaller than the radial
component.
Bit whirl, especially backward whirl, has been shown to be a major
contributor to premature PDC bit failure. Maximum whirling
frequency can be calculated from the X and Y accelerometers.
Downhole Pressure Service
PWD® Service
Overview
Sperry-Sun was the first to
commercialize a pressurewhile-drilling tool and
service.
The PWD® service provides annular pressure, bore pressure, and
temperature measurements. Annular pressure is transmitted in real
time every 6 to 30 seconds and displayed as an equivalent mud
weight. Pressure and temperature data are also recorded in
downhole memory at a more frequent sampling rate (as fast as every
2 seconds) and recovered at the end of each bit run. The data can be
displayed as both depth-based and time-based logs to facilitate
interpretation of drilling and non-drilling events.
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Telemetry Systems
PWD sensors are available in 4 ¾”, 6 ¾”, 8", and 9 ½” tool sizes.
PWD tools are compatible with both negative and positive pulser
and electromagnetic telemetry systems.
PWD Sensor Specifications
Tool size
Length
Nominal OD
Maximum OD
Through bore ID
Connection
Measure point from bottom
Maximum build rates rotating/non-rotating in
deg/100’
Maximum flow rate, lb mass/min.
Maximum sand content
Maximum operating temperature
Maximum survival temperature
Temperature measurement range
Maximum pressure, psi
Transducer calibration range, psi
Total error +/–
Repeatability +/–
Recorded resolution
Real-time resolution
Recorded sample rate range, sec
Maximum real-time transmission rate, sec
4 ¾”
6 ¾”
8”
8” HIGH
FLOW
9 ½”
10.62’
4.75”
5.25”
1.25”
3 ½” IF
box-pin
66.24”
15/30
4.51’
6.75”
7.475”
1.92”
4 ½” IF
box-pin
13.51”
8/14
4.51’
8”
8.71”
1.92”
6 5/8” reg
box-pin
13.01”
8/14
4.51’
8”
8.71”
2.375”
6 5/8” reg
box-pin
13.01”
8/14
4.45’
9.5”
9.5”
2.375”
7 5/8” reg
box pin
12.02”
8/14
3,500
2%
175°C
200°C
0–175°C
22,500
0–20,000
12 psi
4 psi
1 psi/bit
0.05%
1–220
6
10,000
2%
175°C
200°C
0–175°C
22,500
0–20,000
12 psi
4 psi
1 psi/bit
0.05%
1–220
6
10,000
2%
175°C
200°C
0–175°C
22,500
0–20,000
12 psi
4 psi
1 psi/bit
0.05%
1–220
6
20,000
2%
175°C
200°C
0–175°C
15,000
0–20,000
12 psi
4 psi
1 psi/bit
0.05%
1–220
6
20,000
2%
175°C
200°C
0–175°C
15,000
0–20,000
12 psi
4 psi
1 psi/bit
0.05%
1–220
6
31 of 68
Telemetry Systems
Recorded temperature sample rate, sec
Maximum real-time temperature sample rate, sec
Memory
Maximum samples
300
6
2MB
1,000,000
300
6
2MB
1,000,000
300
6
2MB
1,000,000
300
6
2MB
1,000,000
300
6
2MB
1,000,000
Operating Applications
Applications of the PWD
sensor:
Recent trends have been towards drilling more advanced wells—
underbalanced, horizontal, extended-reach, multilateral, deepwater,
HPHT (high-pressure/high-temperature), slimhole—while
emphasizing lower overall drilling costs. As a result, attention has
been given to avoiding costly hole problems associated with these
types of wells. These problems are often a result of operating
outside the safe pressure limits defined by pore, collapse, and
fracture pressures.
LOT, lost circulation
Flow/kick detection
Hole cleaning and collapse
Monitor mud properties
Optimize drilling practices
Underbalanced drilling
In the drilling operation, knowledge of circulating hydraulics is
extremely important for efficient drilling. However, assumptions
from hydraulics models about the ECD (equivalent circulating
density), swab/surge pressures, breaking gels, and even mud weight
are often incorrect due to the lack of accurate, downhole
information. This has led to overly optimistic well plans in some
instances and overly conservative plans in others. With SperrySun’s PWD sensor, it is possible to precisely monitor circulating
hydraulics, which removes the uncertainties of the hydraulics
models and enables optimization of the design and safe execution of
the well plan.
In specialized drilling applications, accurate measurements of
downhole pressures are essential to avoid trouble costs. This is
typical of situations in which the safe operating pressure margin
(between the minimum pressure required to avoid collapse and the
maximum pressure that can be tolerated before fracture) greatly
diminishes while drilling (e.g., deepwater, HPHT, extended-reach
wells). In these cases, the mud weight and ECD tolerance are
critical. Accurate determination of the static and circulating mud
pressures are crucial design parameters for successful drilling.
Extended-reach wells present their own challenges. The small
margin between collapse and fracture pressures, viscous muds,
difficult hole cleaning, and reservoir depletion all can limit well
design and cause costly drilling problems. Poor hole cleaning and
collapse can lead to a packed-off well, resulting in excessive time
spent reaming, annular restriction, mud losses, and stuck pipe. The
PWD® service in conjunction with our INSITE™ service allows
you to view the ECD—and the effects of hole cleaning—in real
time. You can view the effects of cuttings mobilization when rotary
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Telemetry Systems
mode is resumed after sliding and keep the ECD well within safe
operating parameters.
The PWD tool has three
modes:

Real-time

Recorded

Pumps-off
Annular pressure increases detected with the PWD sensor have been
correlated with ineffective cuttings removal and poor hole cleaning,
which sometimes can lead to lost circulation. When the PWD
sensor detects an increase in annular pressure at a constant flow
rate, drilling fluid parameters and operating procedures are modified
to assist hole cleaning. On extended-reach wells, the pore, collapse,
and mud loss pressures are often close. In addition, the viscous
muds, high flow rates and string rotary used to aid hole cleaning can
result in high ECD, swab/surge, and reaming pressures. Real-time
PWD information can be of value to keep wellbore pressures
between the safe operating pressure limits and to monitor hole
cleaning.
Another important application for the PWD sensor is the early
detection of well flows and kicks. Shallow water kicks, typical of
deepwater riserless drilling, are characterized by an increase in
annular pressure. Deeper gas, oil, and water kicks show a typical
reduction in annular pressure. This can be dramatic in the case of
gas kicks, and because the sensor is measuring downhole, they can
be picked up earlier than traditional surface measurements.
Slimhole drilling often results in relatively high ECDs. Because of
the small annular volume in slim holes, frictional pressure losses
from circulating and drillstring movement are greater than in
conventional wellbores. Thus, the ECD and swab/surge pressures
are higher relative to the static mud weight. Sperry-Sun’s PWD®
system directly measures and monitors the actual ECD and surge
pressures downhole, providing you with the most accurate
measurements.
In an underbalanced drilling operation, monitoring downhole
pressures is vital to ensure a true underbalanced condition and
prevent formation damage. Using the PWD sensor also helps
optimize gas injection rates; injected nitrogen sometimes can be
equal to 25% or more of the total drilling cost.
Over the past few years, our PWD tools have seen widespread and
increasing application in the North Sea, Gulf of Mexico, and
elsewhere for many operators. Drilling practices have been
successfully changed through the Statfjord reservoir in Norway to
prevent lost circulation in weak coals. Hole-cleaning practices have
been monitored on North Sea extended-reach wells that have
resulted in significant time savings. In addition, shallow water flow
situations in unconsolidated sands have been monitored in Gulf of
Mexico deepwater wells.
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Telemetry Systems
Acousticaliper MWD Tool
ACOUSTICALIPER™ MWD Tool
Overview
Sperry-Sun’s ACOUSTICALIPER™ MWD tool provides an
accurate measurement of borehole diameter during the drilling
process.
The ACOUSTICALIPER™ tool uses three ultrasonic transceivers
(spaced 120° apart) to transmit and receive acoustic signals between
the tool and the borehole wall to determine borehole size and
ellipticity, plus BHA dynamics information. This sensor has its own
processor, memory, power supply, dynamic directional sensors, and
surface communications port so that it can be run as a stand-alone
sensor or in conjunction with other MWD sensors.
Digital electronics are used to enhance the accuracy of the
measurement and extend its operating range.
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Telemetry Systems
The ACOUSTICALIPER™ tool incorporates a magnetometer and
an accelerometer, which are used to derive dynamic directional
information. This information can subsequently be used to calculate
the shape of elliptical boreholes as well as the relative direction of
the axes of the ellipse. Accurate measurements of borehole size can
be made either while rotating or sliding.
Extensive field testing has
proved the
ACOUSTICALIPER™ tool
to be both reliable and
accurate.
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Telemetry Systems
ACOUSTICALIPER™ Tool Specifications
Length
OD (nominal)
Maximum OD (at wearbands)
ID throughbore
Connection type
Build rates
Tool joint torque
Power supply
Measure point
Maximum operating/survival
temperature
Maximum pressure
6 ¾” OD
8” OD
6’
6 ¾”
7.38”
1.92”
4 1/2 IF box x pin
10/100’ (rotary)
21/100’ (sliding)
32,000 ft lb
Lithium battery
1 ¼’
150C / 165C
7 ¾’
8”
9 ½”
1.92”
6 5/8 reg box x pin
8/100’ (rotary)
14/100’ (sliding)
56,000 ft lb
Lithium battery
2 ½’
150C / 165C
18,000 psi
18,000 psi
Operating Limitations
Operating range for the 6 ¾” and 8” tools (water-based muds):
22
Borehole Diameter (in)
20
Centered – 8”
Eccentered – 8”
18
16
14
Centered – 6 3/4”
12
Eccentered – 6 3/4”
10
8
9
10
11
12
13
14
15
16
17
18
Mud Weight (ppg)
The size (and shape) of hole that the ACOUSTICALIPER™ tool
can measure is a function of mud weight/type, tool eccentricity, and
tool size. It is basically a matter of how much standoff can be
measured. The graphic above shows the expected results of the
caliper measurement (the tool range) in water-based mud. The
"centered" case assumes that the tool is mostly centered in the given
hole, which would represent the maximum range.
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Telemetry Systems
The maximum hole size is limited by the (programmable) total
acquisition time for the “echo” waveforms. The “standard”
maximum echo arrival time is 200 microseconds (equivalent to a
standoff of about 6 inches in water at room temperature and
pressure). In lower mud weights (12 lb/gal), the maximum echo
arrival time can be extended to 400 microseconds (equivalent to a
standoff of about 12 inches in water at room temperature and
pressure). This translates into a maximum theoretical range of:
6 3/4" tool
Centered
26"
8" tool
Eccentered
Centered
Eccentered
17"
29"
19"
Note that in extreme cases of eccentering, the echo may be “missed”
due to the oblique angle of reflection.
The ACOUSTICALIPER™ tool can operate in any type of mud—
water-based, diesel oil–based, or synthetic. The tool range will be
slightly reduced in oil-based and synthetic mud due to the increased
attenuation of the acoustic signal.
The ACOUSTICALIPER™ tool has been successfully used in both
"hard" and "soft" formations. For the case of “soft” formations, the
tool range may also be reduced due to the decreased reflectivity of
the borehole wall.
Operating Applications

Environmental correction of MWD gamma ray, resistivity, and neutron
data

Quality control for MWD logs

Maximum horizontal stress field orientation

Real-time assessment of wellbore stability

Evaluation of hole cleaning and hydraulics

Accurate location of tight spots or ledges

Enhanced assessment of directional drilling tendencies

Cement volume estimates
Quality Assurance
The ACOUSTICALIPER™ tool obtains multiple sets (triplets) of
data from the transceiver set to determine an equivalent circular
wellbore diameter. Sixteen or 32 triplets make up a single sample.
Three points define a circle, and therefore all three transceivers
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Telemetry Systems
must have a valid echo detect before an instantaneous circular
borehole diameter can be calculated. If one or more of the
transceiver does not have a valid detect, that triplet is not used in
calculating the equivalent circular wellbore diameter. The valid
instantaneous circular borehole diameters are averaged to obtain the
equivalent circular wellbore diameter. The number of valid and
invalid triplets is stored and can be plotted on a QC log.
The mud type, mud weight, pressure, and temperature affect the
mud acoustic velocity (the value used to convert the echo travel
time into a distance). Imperial measurements have been made to
quantify these effects. These corrections are made in the surface
computer system. Typically the corrections are within 2% to 5%.
To more accurately “tune” the mud acoustic velocity, diameter
readings are taken in casing on every run and a correction factor is
entered. The resultant diameter will have an accuracy of +/-0.1”.
Sonic Tool
BAT™ Tool
Overview
Sperry-Sun’s BAT™ (bi-modal acoustic) tool is the world’s only
dual-array monopole/dipole MWD sonic tool. Major advantages to
using the BAT™ tool are as follows:

Operates in both a “monopole” mode and a “dipole” mode

Presents standard compressional wave, as well as enhanced shear wave,
travel time

Uses standard wireline industry processing techniques that are supported
by various commercial applications
The BAT™ tool offers many new and advanced features:

Two seven-receiver arrays (front and back)

Two high-power, dual-frequency transmitters

Tool design virtually eliminates the tool mode arrival

Full waveform memory storage (256/512 MB)

Two powerful digital signal processors for fast downhole delta-t
calculations

High-speed data retrieval at the surface

Fully programmable transmitter firing modes

High-frequency simultaneous sampling of all the receivers
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Telemetry Systems
Engineering design features include the following:

Proven Sperry-Sun standard designs to ensure high reliability

Collar strength exceeds standard 4 1/2 IF API connection

Integrated with Sperry-Sun’s INSITE™ system and HCIM downhole
processor

Operates in stand-alone and integrated modes
BAT™ Tool Specifications
Length
OD (nominal)
Maximum OD (at fluted wearbands)
ID throughbore
Connection type
Build rates
Tool joint torque
Power supply
Measure point
Maximum operating/survival temperature
Maximum pressure
20’
6 ¾”
7 ¾”
1.92”
4 1/2 IF box x 4 1/2 IF box
10/100’ (rotary)
21/100’ (sliding)
32,000 ft lb
Lithium battery
7 ½’
150C/165C
18,000 psi
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Telemetry Systems
D.E.E.P.™ Service
Overall drilling costs are a critical factor in determining the
financial returns from an oil and gas investment. This is particularly
so in the offshore environment, where operating costs are high, and
in wells in which drilling problems are likely to occur.
Sperry-Sun’s D.E.E.P. ™
drilling optimization
service is of particularly
high value in the drilling of
difficult wells:
Extended-reach/horizontal
Deepwater
HPHT
Hard drilling
Slimhole
Underbalanced
At Sperry-Sun, we recognize the importance of optimizing the
drilling process without compromising well safety or well
objectives. Through careful planning, properly implemented drilling
practices, and the avoidance of trouble, quicker and cheaper drilling
costs can be realized. This is often a difficult area in which to show
tangible benefits, but it demonstrates Sperry-Sun’s commitment to
improving the overall drilling process for the benefit of the industry.
Time is money. Expensive
trouble time can be
prevented using drilling
optimization tools.
Sperry-Sun has recently developed a suite of MWD tools and
services that are aimed at reducing drilling trouble time and
optimizing drilling practices. MWD measurements such as pressure,
vibration, hole size, WOB, and torque have the advantage of seeing
“where the action is downhole,” relaying the information to the
surface, and displaying it in real time. The parallel development of
our INSITE™ (integrated system for information and engineering)
system has enabled this information to be delivered “at the time, in
the manner, and at the place it is needed” from around the rig to the
customer’s office. This allows effective drilling decisions to be
made that add value to the exploration or development project
through reducing overall drilling time.
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Telemetry Systems
Reduce trouble time and
optimize drilling processes
with:
PWD sensor
DDS™ sensor
PP/FG™ software
ACOUSTICALIPER™ tool
WOB/TOB sensor
The potential benefits are clear: downhole MWD drilling
information reduces risk and can significantly reduce downtime and
improve drilling practices, resulting in a quicker learning curve.
Reduced risk allows better economic decisions to be made, thus
improving the net present value of the assets.
PWD Sensor
Uncertainties in downhole pressures lead to many drilling problems
and often poor well design. Risk can be reduced using a PWD
sensor to measure downhole pressures directly, which increases
drilling efficiency and avoids trouble costs.
Operators are increasingly utilizing the PWD sensor to monitor mud
hydraulics, hole cleaning, and well flow/kicks and to prevent lost
circulation. Our pioneering PWD sensor was designed to operate
with Sperry-Sun’s MWD services to allow operators to monitor
annulus and drillstring pressures.
DDS™ Sensor
Sperry-Sun’s DDS™ sensor measures downhole vibrations in real
time. There is evidence that downhole tool damage (MWD, motors,
bits, collars, tubulars) is largely due to drilling-induced downhole
stresses. Much of this damage can be prevented by monitoring
downhole vibrations and modifying BHA design and drilling
parameters.
Vibration mechanisms:
Bit bounce
BHA and bit whirl
Stick slip
Parametric resonance
Forced vibration
The DDS™ sensor measures triaxial shock and vibration. Because
the three axes are measured independently, they can be used to
determine if bit bounce, stick-slip, or bit whirl is occurring. These
detrimental dynamic occurrences can often be eliminated by
adjusting the drilling parameters. Used in real time, the DDS™
sensor detects problem drilling conditions and measures the
effectiveness of drilling parameter changes.
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Telemetry Systems
Elimination of these destructive dynamics leads to increased bit life,
enhanced ROP, and increased reliability of all other BHA
components.
Figure A shows an
example of apparent stickslip motion, which caused
a mechanical BHA failure.
Severe vibrations are
clearly shown on the X and
Y accelerometer data. The
average difference
between the average X and
average Y accelerations
equals 6 g, which implies a
change in downhole rpm of
365.
Figure B shows bit bounce
on runs 4 and 5. Run 6
shows where a shock sub
was added, surface
reduction in vibration, and
an actual increase in
downhole vibrations in the
Z axis.
Figure A
Figure B
DDS™ sensors are increasingly being used in difficult drilling
environments to improve drilling efficiency and reduce downtime
due to tool failure. When used in conjunction with our RIGSITE
PLUS™ or INSITE™ services, a “smart application” performs
online analysis of DDS™ sensor data to diagnose the vibration
mode(s) present. This application also suggests corrective action in
real time by modifying drilling parameters.
INSITE™ service “smart
application” for real-time
drilling optimization using
the DDS™ sensor to
minimize vibration.
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Telemetry Systems
PP/FG® Software
The ability to predict pore and fracture pressures is essential to the
planning and drilling of all wells. If these uncertainties can be
reduced, it can dramatically impact the overall well cost.
Sperry-Sun’s PP/FG® software uses petrophysical data (gamma,
resistivity, density) to predict pore and fracture pressures using an
effective stress approach. This can either be used for well planning
purposes or utilizing FEWD for real-time prediction. We now have
considerable global experience. In North Sea HPHT wells, for
example, the prediction accuracy is ±0.5 ppg (1 SD) for pore
pressure and ±0.3 ppg (1 SD) for fracture pressure.
PP/FG® software can be used at the well planning stage, together
with a suitable wellbore stability model, to optimize casing design
and mud weight selection for field development projects.
ACOUSTICALIPER™ MWD Tool
The ACOUSTICALIPER™ tool incorporates a magnetometer and
an accelerometer, which are used to derive dynamic directional
information. This information can subsequently be used to calculate
the shape of elliptical boreholes as well as the relative direction of
the axes of the ellipse. Accurate measurements of borehole size can
be made either while rotating or sliding.
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