Coriolis Meter Overview
Seth Harris
O&G Manager – Northern Rockies
Emerson Confidential
What is a Coriolis Meter?
A. A volume meter
B. A mass meter
C. A densitometer
D. A process diagnostic tool
E. A highly accurate,
low/no maintenance meter
F. All of the above
Coriolis 101
Coriolis Theory of Operation
Micro Motion:
The Birthplace of Coriolis



Original Micro Motion Manufacturing
Founded in 1977
Invented first practical
Coriolis flow and density
meter
Valued for its precision
– Direct mass measurement
– Multivariable capabilities
• Mass Flow
• Volume Flow
• Density
• Temperature
First Micro Motion Sensor
1,000,000th Micro Motion Sensor
Manufactured by year end 2014
Gaspard-Gustave CORIOLIS
(1792 – 1843)
History & Industry Guidelines
Coriolis Sensor Components
Drive coil
Flow Tubes
Sensor Coil /
“Pick-off coil”
Sensor Coil /
“Pick-off coil”
RTD
Case
Manifold /
“Splitter”
Process
Connection
Sensor
Coriolis 101
Theory of Operation — Mass Flow
Process fluid enters the sensor and
flow is split with half the flow through
each tube. The sensor flow tubes are
vibrated in opposition to each other by
energizing a drive coil. Tubes are
oscillated at their natural frequency.
Magnet and coil assemblies, called
pick-offs, are mounted to the flow
tubes. As each coil moves through
the uniform magnetic field of the
adjacent magnet it creates a voltage
in the form of a sine wave.
Coriolis 101
Theory of Operation — Mass Flow
During a no flow
condition, there is no
Coriolis effect and the
sine waves are in
phase with each other.
When fluid is moving through the sensor's tubes, Coriolis
forces are induced, causing the flow tubes to twist in
opposition to each other. The time difference between the
sine waves is measured and is called Delta-T, which is
directly proportional to the mass flow rate.
Coriolis 101
Theory of Operation — Mass Flow
The Flow Calibration Factor consists of
10 characters, including two decimal points.
The first five digits are the flow calibration factor.
This calibration factor, multiplied by a given
Delta-T, yields mass flow rate in grams/sec.
The last three digits are a temperature
coefficient for the sensor tube material. This
coefficient compensates for the effect of
temperature on tube rigidity (% change in
rigidity per 100°C).
The Flow Calibration Factor applies to liquid
and gas, and is linear throughout the entire
range of the meter
Coriolis 101
Theory of Operation — Density
Density measurement is based on the natural frequency
of the system including the flow tubes and the process fluid.
As the mass increases, the
natural frequency of the system
decreases.
As the mass decreases, the
natural frequency of the system
increases.
Coriolis 101
Theory of Operation — Density
Coriolis 101
Theory of Operation — Volume
(indirect or calculated)
Coriolis 101
Volume Flow Rate
• Volumetric Flow is a calculated variable
• Volume can be referenced to standard
temperature using the temperature input
• Coriolis meters are preferred for volume
measurements
• Liquids – Measured Density
–
–
–
–
Low pressure drop
Wide turndown
High accuracy
High degree of linearity
• Gas – User Provided Base Density
=0
Coriolis 101
Review - 3 Basic Measurements
Mass Flow Rate - Twist
• Higher the mass
flow rate – more
twist
– ∆T = Time delay
Density - Frequency
Temperature - RTD
• Lighter the fluid →
Higher Frequency
• Heavier the fluid →
Lower Frequency
• Compensate for
Tube Stiffness
changes
• Not for custody
transfer of liquids
Coriolis 101
Emerson Confidential
Emerson Confidential
12
12
Product Overview & Recent
Advancements
ELITE Coriolis Portfolio Combines Premium Meter Performance,
Electronics and Software Offering
ELITE
Improvements
F-SERIES
Improvements
R-SERIES
±0.4 – 0.5% Mass Flow
±0.003
g/cm3
Density
±0.05% - 0.1% Mass Flow

±0.0002 – 0.0005 g/cm3 Density

Sensor Sizes 1/12-12inch
(DN1-DN300)

±0.1 – 0.2% Mass Flow

0.25% Gas accuracy

±0.0005 – 0.002 g/cm3 Density

Widest Turndown

Sensor Sizes 025-300


Best Sensitivity

Turndown


Low/No T & P effects

Improved Sensitivity

Entrained Gas Performance

±0.5% Volume Flow

Reduced T & P effects

Sensor Sizes 025-200

Smart Meter Verification

Smart Meter Verification

Limited Transmitter Capabilities

Transmitter Flexibility

Transmitter and Software Offering

From Chemical Injection to Large Transport Pipelines…….
Performance Specification
Standard
Optional
Mass/Volume Accuracy
±0.1% of rate
±0.05% of rate
Mass/Volume Repeatability
±0.05% of rate
±0.025% of rate
Density Accuracy
±0.0005 g/cm3
±0.0002 g/cm3
Density Repeatability
±0.0002 g/cm3
±0.0001 g/cm3
Gas Mass Flow Accuracy
±0.25% of rate (CMFS meters)
±0.35% of rate (CMF meters)
CMFS Meter
CMF High Capacity
Large CMF
Small CMF Meter
1/12”
1/2”
1”
DN1
DN15
DN25
2”
3”
4”
DN50 DN80 DN100
6”
8”
10”
12”
DN150
DN100
DN100
DN100
Comprehensive Large ELITE Offering for your High
Flow Rate Needs
CMF200
CMF300
CMF350
CMF400
CMFHC2
CMFHC3
CMFHC4
2inch
(DN50)
3inch
(DN80)
4inch
(DN100)
6inch
(DN150)
8inch
(DN200)
10inch
(DN250)
12inch
(DN300)
1,760
403
5,840
1340
10,700
2455
15,200
3490
28,900
6632
49,000
11245
75,000
17210
±0.1%
(±0.05%)
±0.1%
(±0.05%)
±0.1%
(±0.05%)
±0.1%
(±0.05%)
±0.1%
±0.1%
±0.1%
±0.05%
(±0.025%)
±0.05%
(±0.025%)
±0.05%
(±0.025%)
±0.05%
(±0.025%)
±0.05%
±0.05%
±0.05%
Density Accuracy
(g/cm3)
±0.0002
±0.0002
±0.0002
±0.0002
±0.0002
±0.0002
±0.0002
Density Repeatability
±0.0001
±0.0001
±0.0001
±0.0001
±0.0001
±0.0001
±0.0001
Gas Mass Flow Accuracy
(% of rate)
±0.35%
±0.35%
±0.35%
±0.35%
±0.35%
±0.35%
±0.35%
Line Size
Nominal Flow Rate
(lb/min / bbls/hr – Oil @ 0.75
g/cm3)
Liquid Mass Flow Accuracy
(% of rate)
Liquid Mass Flow
Repeatability
(% of rate)
Micro Motion 2000 Series Transmitters
• 2500 DIN Rail Transmitter
– Two 4-20mA output, one frequency, RS
– 485
– Digital options: HART and Modbus
– Remote mount & DC power only
• 2700 Transmitter
– 2700 Configurable I/O, two 4-20mA
outputs, one frequency
– Digital options: HART, Foundation
Fieldbus, Profibus PA
– Modbus with Analog version only
– Available with stainless steel housing
– Self-switching AC and DC power
• 9739 MVD
– Two analog (mA) outputs
– Frequency output
– HART and Modbus
5700 Transmitter
•
•
•
•
Five output channels
Three analog (mA) output option
Frequency pulse output
Digital protocols: Modbus and HART
Special Features / Options
•
•
•
•
•
•
•
Fully configurable through display
Smart Meter Verification
Discrete batch control
Concentration measurement
Petroleum measurement and API correction option
Zero verification
Historian feature
Transmitter Improvements that Can Have a Big Impact on Your Operations
Five Output Channels
Main Design Drivers
• Industry Leading Output Selection
• Two linked Pulse outputs + One independent Pulse
for maximum flexibility in applications like proving
• Ease of Use
Channels
A
B
C
D
E
mA HART
mA
mA
mA-Input
RS-485
FO
FO
FO
DO
DO
DO
DI
DI
Variables Available for Outputs
Mass Flow
External Pressure
Volume Flow
Velocity
Density
Drive Gain
Temperature
Two Phase Indication
External Temperature
Application Specific (% Fill)
– Improve productivity
– Eliminate need for special service tools
– Minimize time in the field
• Measurement Confidence
– Absolute trust in the output from your meter
– Diagnostics and tools to resolve uncertainty
• Process Insight
– Enable the ability to “go back in time” to
understand a process event
– Open a window into your process for informed
optimization
5700 with Ethernet!
• Expansion of the popular 5700 Coriolis
transmitter platform to include an
Ethernet output version
• Native Ethernet architecture and
connections, no extra converters or
adapters needed
• Multiple protocol choices including
EtherNet/IP, Modbus TCP and
PROFINET
• On-board Web server for easy
configuration
• Simplified PLC integration
Liquid Coriolis Measurement &
O&G Industry Guidelines
Mounting Considerations for Liquid Service
Use your common piping practices to
minimize:
• Do NOT use the sensor to support the
piping
• The sensor does not require external
supports.
Liquid Volume Measurement Basics
Volumetric Flow is a Calculated Variable
Volume Flow 
Mass Flow
Density
Lbs/HR
=
Lbs/BBL
BBLs/HR
Emerson Confidential
Oil Custody Transfer
• Generics of Crude Oil
– Contracts are the rule of law
– 3rd Party Influences…..
• American Petroleum Institute Guidelines (API)
– Various Existing Standards for Reference including but not limited
to:
• 18.1 – Measurement Procedures for Crude Oil Gathered from
Small Tanks by Truck
• 5 – Metering
• 6.1 – Generic LACT
• 7 – Various Temperature Measurements
• 3 – Tank Gauging (Various)
• Etc., etc.
– Not Requirements…..unless?
Requirements vs. Guidelines
API MPMS Chapter 5.6
Custody Transfer of Crude Oil Using Coriolis
Emerson Confidential
24
BLM Oil Measurement Guidelines – Crude Oil
43 CFR 3174
Onshore Order 4
• Overall concept: Prescriptive requirements
for equipment and procedures with
opportunity to request meter-specific
variances from the local field office.
• Approved Methods for Oil Custody Transfer:
– Manual tank gauging
– LACT using positive displacement meter
• Overall concept: Provide prescriptive
measurement procedures as a default with
the option for national approval of new or
alternative equipment or methods that meet
well-defined performance criteria.
• Oil Custody Transfer Approved (default
methods):
–
–
–
–
–
Manual tank gauging
Automatic tank gauging
LACT with positive displacement meter
LACT with Coriolis meter
Stand-alone Coriolis meter
Production Measurement Team for Future Considerations
Pressure Considerations
Pressure Drop
Minimum Back Pressure
• Coriolis meters are sometimes smaller
line sizes than the main pipeline
– Sizing program calculates the
pressure drop through the meter.
– More pressure drop is created by
pipe reducers and a prover.
– Back pressure valves are often
needed to increase pressure in the
meter and the prover to prevent
cavitation.
• Back Pressure Valve should be installed
downstream of the prover connections.
• The amount of backpressure recommended
is calculated as follows:
Pb = 2ΔP + 1.25Pe
Where:
Fluid Stability
Pb = minimum backpressure required (psig)
ΔP= pressure drop across the meter at max rate
Pe = equilibrium vapor pressure of the fluid at
operating temperature (psia)
Velocity and Recoverable Pressure Drop
Total energy = pressure head + velocity head + elevation head
Sensor
Flow
Pressure, psia
Inlet pipe
Outlet pipe
Pressure loss
(I.e. by sizing program)
Vapor Pressure
Avoid Pressure Below Vapor Pressure
Total energy = pressure head + velocity head + elevation head
Sensor
Flow
Pressure, psia
Inlet pipe
Outlet pipe
High Vapor Pressure
Liquid flashes
(boils)
Gas condenses
Proving determines a Meter Factor
Known Volume
= Meter Factor
Indicated Volume
• If the meter factor is greater then 1.0000 the meter is
under-registering (reading low).
• If the meter factor is less then 1.0000 the meter is overregistering (reading high).
Potential causes for Meter Factor Being Out – Crude Oil
• Meter Factor is High = Meter is reading low
– Density reading is high?
• Paraffin or other buildup
– Meter bypass?
– Missing pulses at a flow computer
• Electrical issues
• Meter Factor is Low = Meter is reading high
– Density reading is low?
• Gas breakout or lack of meter back pressure
– Prover bypass?
• Double block and bleed seal
• Four way valve seal on bi-di
Direct Mass Measurement
API MPMS 14.7 Standard for Mass Measurement of Natural Gas Liquids
• Direct Mass Measurement
– Coriolis meter is programmed
for mass pulse output
Qm=Imm x MFm
Where:
Qm=mass flow
IMm=indicated coriolis meter mass
MFm=meter factor for coriolis
meter mass
Proving – Direct Mass
• If the Coriolis meter is providing a mass pulse output, the prover reference volume
must be converted to mass.
• Density for conversion must be measured at the prover (DMF is density meter
factor).
• Meter and prover volumes are not corrected (no CTPL).
• Base prover volume (BPV) is corrected for temperature and pressure effects on
steel (CTPS).
DT
Mass = Volume X (Density x DMF)
Inferred Mass Measurement
API MPMS 14.7 Standard for Mass Measurement of Natural Gas Liquids
• Inferred Mass Measurement
– Volumetric flow measurement with on line density measurement
Qm= IV x MFv x ρf x DMF
Where:
• Qm = mass flow
• IV = indicated meter
volume at operating conditions
• MFv = volumetric meter factor
• ρf = indicated density at
flowing conditions
• DMF = density meter factor
Coriolis
Meter
Repeatability
• Repeatability between proving runs
– Repeatability is used to determine if conditions exist such that a valid meter factor can be
obtained from the data.
• API repeatability criteria is based on obtaining a random uncertainty of ±0.00027 or less for the meter
factor
• The calculation of repeatability can be based on pulses from the meter or the meter factor which
has been calculated for each proving run.
• Example of calculating repeatability with a 3.0 barrel prover with 10K pulses per barrel using the
average data method:
•
•
•
•
•
30001
30005
30005
30010
30015
Maximum - Minimum
Minimum
X 100 = 0.04%
Reproducible Proving Results
• Meter factor shift from a previous proving is referred to as reproducibility.
• Generally, a plus or minus 0.0025 shift in factor should be evaluated. This would indicate a change of 0.25%
which was the traditional accuracy statement for a flow meter. Companies have internal standards that vary
from changes of 0.1% to 0.5% from previous factor as case for pulling the meter for evaluation.
• A meter’s specification for repeatability may be 0.05%. An interpretation of this as
reflected in meter factor shift between provings would be a shift of 0.0005 in
factor. It is not realistic to expect this type of reproducibility of proving results.
Potential causes for Meter Factor Being Out - NGLs
• Meter Factor is High = Meter is reading
low
– Density reading is high?
• Paraffin or other buildup
– Meter bypass?
– Missing pulses at a flow computer
• Electrical issues
• Meter Factor is Low = Meter is reading
high
– Density reading is low?
• Gas breakout or lack of meter back
pressure
– Prover bypass?
• Double block and bleed seal
• Four way valve seal on bi-directional
valve
• Factors that cause density changes
– Temperature
– Pressure
– Composition
• If the density measurement conditions
(temperature, pressure, and/or composition)
differ from the conditions in the volume flow
meter, inferred mass accuracy is impacted
• If the density measurement conditions
(temperature, pressure, and/or composition)
differ from the conditions in the volume
prover, direct mass proving accuracy in
impacted
Gas Properties Overview
Seth Harris
Emerson O&G Manager
Using Mass Flow for Gas Measurement
Condition 1
“Actual” conditions
ρ1
P1
Condition 2
“Standard” conditions
T1
ρ2
P2
P1 = 150 psig
T1 = 150°F
ρ1 = 0.73 lb/ft3
T2
P2 = 0 psig
T2 = 60°F
ρ2 = 0.07 lb/ft3
Mass Flow is:




Independent of temperature and pressure
Better mass & energy balance
Reduced process variability
Meaningful quantity measurement of
compressible fluids
General Gas Properties
Gas Density and Specific Gravity Definitions
Term
Gas Density
Definition
The mass of gas per unit volume at the
actual pressure and temperature conditions
(@ Line Conditions)
Standard Density This the density of a gas @ standard
(Also known as: Base
or Normal Density)
Relative Density
Specific Gravity
conditions of temperature or pressure (eg.
1 atm, 15.556oC or 1 Bar, 20oC)
Ratio of density of a gas to the density of air,
where the density of both gasses are taken
at identical conditions of temperature &
pressure
The ratio of molecular weight of a gas to that
of molecular weight of dry air. (Dry Air
Density = 28.96469)
Units
g/cc
or
kg/m3
g/cc
or
kg/m3
None
None
Why measure Mass directly for Gas Flow?
P = 50 psia
• Gases are compressible
– Density changes with Pressure and Temperature
** Volumetric flow is usually meaningless: “acfm”
need mass flow: “lb/hr”, “scfm”
P = 100 psia
Same volume
2x the gas!
General Gas Properties
Gas Coriolis & Industry Guidelines
Mounting Considerations for Gas Service
Use your common piping practices to
minimize:
• Do NOT use the sensor to support the
piping
• The sensor does not require external
supports.
Oil & Gas Industry Approvals
API Manual of Petroleum
Measurement Standards (MPMS) &
AGA Standards
–
–
AGA Report No. 11 Dec. (2003)
API Chapter 14, Section 9 (2003)
• The Measurement of Natural Gas by
Coriolis Meters
• Second edition Feb 2013
History & Industry Guidelines
Emerson Confidential – Please Do not Distribute
AGA Report No. 11 / API MPMS Ch. 14.9
Measurement of Natural Gas by Coriolis Meter
 Tightening of performance requirements from ± 1.0% to ± 0.7%
 Water calibration transfers to gas only when the manufacturer has proof of testing by a
3rd party.
 Additional meter “verification” steps will guide the user on the need to flow test
 Flow testing can be performed in the field per new guidelines
 New appendices added:
 Coriolis Gas Flow Measurement System
 Coriolis sizing equation
 Coriolis Uncertainty section and Example Uncertainty Calculation
History & Industry Guidelines
Conversion of Mass to Volume at
Standard Conditions
 AGA11 Eqn. D.2
 lbs/day ÷ lbs/ft3 = ft3/day
 AGA8 Detail
 Non-ideal gas law:
Pb, Tb, R are constants.
Note: Zb does not vary more than
0.02% at base conditions.
 AGA8 Gross 1 or 2
 Note: ρ(Air) is constant.
NO PRESSURE OR TEMPERATURE Measurement Required to Convert
from Mass to Standard Volume. Molar weight, Base Compressibility, and
Specific Gravity Are ALL DETERMINED BY GAS COMPOSITION.
History & Industry Guidelines
Gas Volume Measurement Basics
Mass Flow
Volume Flow 
Density
• Volumetric Flow is a Calculated Variable
Lbs/Day
=
Lbs/SCF
`
SCF/Day
Emerson Confidential
API Chapter 14.9/AGA 11 Overview
• Meter Requirements
Corilois Meter Performance Specification
– Documentation and Interface: Drawings, Outputs options
(232, 485 or Pulse), Diagnostics, Documentation
– Testing: Static Pressure Testing, Alternative Calibration
Report/Traceability to National/International Standards
 Better reference uncertainty possible in liquid (e.g., water)
labs
 Meters may also be calibrated in gas laboratories
 Option for Piece-Wise Linearization (PWL) used by
ultrasonic meters is available for fine tuning by third-party
gas labs
• Meter Sizing & Selection Criteria
– Process Conditions
– Required meter accuracy
Error Limit
= +1.4% (Qmin ≤ Qi < Qt)
1.40
1.20
1.00
0.80
Error Limit
= +0.7% (Qt ≤ Qi ≤ Qmax)
0.60
Percent Error (%)
 Meters may be calibrated for natural gas in liquid
laboratories
1.60
Repeatability
±1.0% (Qmin ≤ Qi < Qt)
0.40
0.20
0.0
Maximum P-P Spread
0.7% (Qt < Qi ≤ Qmax)
-0.20
-0.40
Repeatability
±0.35% (Qt ≤ Qi ≤ Qmax)
-0.60
Error Limit
= -0.7% (Qt ≤ Qi ≤ Qmax)
-0.80
-1.00
-1.20
Error Limit
= -1.4% (Qmin ≤ Qi < Qt)
-1.40
-1.60
0
Q min
Qt
Flow Rate (Q i)
Q max
History & Industry Guidelines
Emerson Confidential
47
API Chapter 14.9/AGA 11 Overview (cont’d)
• Gas Flow Calibration Requirements
– Reports, Facility Requirements, Documentation
• Installation Requirements
– Temperature (Ambient and Process, not required for mass
based measurement)
– Pressure – Upstream installation is preferred, if needed
• Field Meter Verification
– Transmitter Verification – Cal Factors, etc.
– Sensor Verification – Consult Meter Manufacturer → SMART
Meter Verification
– Temperature Verification
– Meter Zero Verification – Verify Zero Function
History & Industry Guidelines
Emerson Confidential
48
API Chapter 14.9/AGA 11 Overview (cont’d)
• Flow Performance Testing – in-situ verification
– Alternative Fluids
• Recalibration
– AGA 6, Field Proving by Transfer Standard Method
History & Industry Guidelines
Emerson Confidential
49
Appendix E
Coriolis Gas Flow Measurement System
History & Industry Guidelines
Emerson Confidential
50
BLM Measurement Guidelines – Natural Gas
43 CFR 3175
Onshore Order 5
• Overall concept: Prescriptive requirements
for equipment and procedures with
opportunity to request meter-specific
variances from the local field office.
• Overall concept: Provide prescriptive
measurement procedures as a default with
the option for national approval of new or
alternative equipment or methods that meet
well-defined performance criteria.
• Approved Methods of Gas Custody
Transfer:
• Gas Custody Transfer (default methods):
– Orifice meter with chart recorder
– Electronic flow computer (statewide NTLs)
–
–
–
–
Flange-tapped orifice meter (primary device)
Chart recorders (less than 200 Mcf/day)
Electronic gas measurement (EGM)
Standard methods of gas sampling and analysis
Production Measurement Team for Future Considerations
Application Specific Technical
Details, Troubleshooting and
Prolink III Interface
Micro Motion Zero Verification Video - YouTube
Span vs. Zero
y  mx b

Meter
Zero
Flow Calibration Factor
Coriolis Meter Zeroing Best Practices
• Most applications → Use factory zero
• To verify zero after installation, first:
– Ensure no flow condition
– Ensure meter is full of fluid (gas or liquid, not both)
– Ensure process conditions are stable
• Next: Initiate Micro Motion Zero Verification Tool
– Monitors 8 parameters to check stability of process and
check current zero value
What is Pressure Effect on Round Tubes?
• Internal pressure changes the shape of the flow tube
– Tube ovality becomes round
– Tube bends straighten
• Changes in flow tube shape increases stiffness of flow tube
• Changes in tube stiffness directly affects sensor calibration
m  FCF * time delay
FCF  tube stiffness
• As pressure increases, tube stiffness
increases
• For small sensors with relatively thick tube
walls, this effect is small
• Amount of twist is less for the same mass
flow as pressure/stiffness increases
• Pressure effect will cause an under reading
therefore the correction required is in the
positive direction
Indicated Flow Rate
Pressure Effect on Coriolis Meters
Actual Flow Rate
Pressure Span
Effect
Qmindicated  MFm * FCF * 1  FTmimo *tmimo * 1 FPmimo * ( Poper  Pcal )
* Tmeasured  Tzerostored * LD * (1  EDC )
Actual Flow Rate
Compensation Options
Emerson Confidential
Verification Addresses Challenges of Calibration and Proving
Calibration
Validation
Verification
• Establish relationship
between flow rate and signal
produced by sensor
• Should be traceable and
accredited
• Compare meter to a
reference to confirm
performance
• Example: Prover or master
meter
• Correlate diagnostics to
primary variables
• Example: Structural integrity of
tubes
In-situ Verification with Smart Meter Verification
Frequency Response Function
Typical internal SMV
verification
On-demand

One button

10
10
10
3
Freq=sqrt(K/M)
Formal report

Less than 2 minutes

No interruption to
process or
measurement
Scales with host
systems
10
1
0
Nominal K Nominal M
-1
Frequency (Hz)
Meter verification procedure
Test tones
K
M
Tones
Peak ~1/
2
No extra equipment


FRF Magnitude

10
Sensor
response
10
2
Look Beyond the Meter with SMV Professional
Process
• Installation
• Multiphase Flow
Detection
• Operating flow
range
Sensor
• Tube stiffness
• Drive coil
• Pickoff coils
• RTD
• Tube coating
Transmitter
• Sensor signal
• Zero calibration
• Configuration
• Alerts
Updated SMV Capabilities
Basic
1500, 1700, 2400,
2500, 2700, 5700
1500, 1700, 2400,
2500, 2700
5700
Included
Licensed
90-DayTrial, Licensed
Improved detection
X
X
X
Scheduler
X
X
X
X
X
Compatibility
Report
Coating detection
Emerson Confidential
Professional
X
Installation verification
X*
Multiphase diagnostic
X*
Flow range diagnostic
X*
* Additional functionality in ProLink III Professional
62