GAS METERING SYSTEM

1
Table Of Contents
1. DESIGN OVERVIEW GAS METERING SYSTEM
2. ULTRASONIC FLOW METER
3. USM VERIFICATION AND DIAGNOSTIC METHOD
4. FLOW COMPUTER
5. ONLINE GAS CHROMATOGRAPHY (DANALYZER
MODEL 500)
6. MOISTURE ANALYZER AMETEK 3050
7. H2S ANALYZER

2
 DESIGN OVERVIEW
GAS METERING SYSTEM

3
Flow Measurement Principles
Differential Pressure / Orifice
• Use Bernoulli’ equation
• the pressure drop across the constriction is proportional to the square of the flow rate
Coriolis (Mass Flowmeter)
• Coriolis mass flowmeters measure the force resulting from the acceleration caused by
mass moving toward (or away from) a center of rotation (Coriolis Effect)
Turbine
• Turbine flowmeters use the mechanical energy of the fluid to rotate a “pinwheel”
(rotor) in the flow stream.
• Blades on the rotor are angled to transform energy from the flow stream into
rotational energy.
Ultrasonic Flow Meter
• Transit time ultrasonic flowmeters send and receive ultrasonic waves between
transducers in both the upstream and downstream directions in the pipe.
• Under flowing conditions, the upstream wave will travel slower and take more time
than the (faster) downstream wave.
• When the fluid moves faster, the difference between the upstream and downstream
times increases.

4
Flow Meter Selection

5
 Flow Meter Selection
Area Application

6
Flow Meter Selection

7
Flow Meter Selection

8
Flow Meter Selection

9
Flow Meter Selection

10
Flow Meter Selection

11
Gas Metering System Standard

Orifice: AGA Report No.3 Part 1,2,3,4

⮚ Orifice Metering of Natural Gas and Related Hydrocarbon Fluids
Coriolis: AGA Report No.11-2010
⮚ Measurement of Natural Gas by Coriolis Meter
Turbine: AGA Report No.7-2002
⮚ Measurement of Fuel Gas by Turbine Meters
USM: AGA Report No.9-2007
⮚ Measurement of Gas by Multipath Ultrasonic Meters

12
Gas Metering System Standard
Gas Properties:
AGA Report No.8-1992
⮚ Compressibility Factors of Natural Gas and Other Related Hydrocarbon
Gases
GPA Standard 2172-1996 (Option)
⮚ Calculation of Gross Heating Value, Relative Density and Compressibility
Factor for Natural Gas Mixtures from Compositional Analysis
ISO 6976-1995 (Option)
⮚ Natural gas - Calculation of calorific values, density, relative density and
Wobbe index from composition
AGA Report No.10-2002
⮚ Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases
ASTM D 1945-2003
⮚ Standard Test Method for Analysis of Natural Gas by Gas Chromatography

13
Metering Sizing
Primary Process Data: Secondary Process Data:
▪ Design Pressure & Temperature: ▪ Density
✔ To select meter ratings/schedule ▪ Heating Value
✔ To determine zero – span transmitters
▪ Gas Composition
✔ To calculate meter uncertainty
▪ Viscosity
▪ Operational Pressure & Temperature:
✔ To calculate meter uncertainty
▪ Operational, Maximum & Minimum Flowrate:
✔ To select meter capacity and diameter
✔ To calculate meter uncertainty
✔ To calculate turndown ratio
▪ Operational & Maximum DP (Orifice):
✔ To determine zero – span transmitters
✔ To calculate meter uncertainty
✔ To calculate orifice & pipe bore
✔ To calculate beta ratio

14
Metering Sizing (USM)
▪ Design Pressure & Temperature:

USM Rating

15
Metering Sizing (USM)
▪ Operational & Maximum Flowrate:

USM Standard Flow range Sizing

16
Metering Sizing (Turbine)

Turbine Sizing

17
Metering Sizing (Orifice)
Allowed/
Properties Units Min Max
Recommended
Flowrate MMScf/d 2.5 5.0
Differential Pressure In H2O @60 R: 20% to 80% from Max 8.2512 33.0497
Re. Number >4000 602882.70 1205765.40
Std. Flow. Expand.Unc. <1% 0.83332% 0.57416%
Turndown Ratio ≤3:1 2.27 : 1
Design Pressure Psi g 1350
Operational Pressure Psi g 1000
Design Temperature Deg. F 100
Operational Temp.
Pipe Bore
Pipe Cal. Temperature
Deg. F
in
Deg. F
100
5.76100
68
FLOWSOLV
Pipe Exp. Coef. (CS) /Deg. F 6.20E-06
Orifice Bore in 2.11631
Orifice Cal. Temperature Deg. F 68
Orifice Exp. Coef. (316) /Deg. F 9.25E-06
Beta Ratio 0.2 - 0.6 0.36728
Standard Density lb/cf 0.054216
Line Density lb/cf 4.077907
Dynamic Viscosity cP 0.010268
Isentropic Exponent 1.3
PT Zero Psig 0
PT Span Psig 2000
TT Zero Deg. F 0
TT Span
DPT Zero
DPT Span
Deg. F
In H2O @60
In H2O @60
200

40
0
KELTON
Orifice Sizing Calculation

18
Metering Sizing (Uncertainty)

USM Uncertainty AGA Report No. 9

Orifice Uncertainty AGA Report No. 3

19
Metering Accuracy Class

20
Metering Accuracy Class

21
Typical Gas Metering System

22
ULTRASONIC FLOW METER

23
Why Ultrasonic Meter ?
⮚ Advantages of USM vs. other metering technologies
✔ Significantly lower permanent pressure loss (PPL)
✔ Lower Total Costs Of Ownership (TCO)
✔ No moving parts, wear & tear parts, very low maintenance
✔ Remote diagnostics reduce time required for troubleshooting

⮚ Further advantages
✔ Higher capacity (25% / 40% larger than a Turbine / Orifice Meter)
✔ Higher turndown ratio (1:100 / 125 compared to 1:10 / 50 TM /
Orifice)
✔ Higher Accuracy (~0.15% compared to 0.5% / 1.5% TM / Orifice)
✔ Bi-directional measurements possible
✔ Detection of the flow profile with all asymmetries possible,
Turbine and Orifice Meters just give volume-proportional pulses

24
Typical Ultrasonic Meter Skid

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Applied Standard
AGA Report No.9-2007 AGA Report No.8-1992
• Measurement of Gas by Multipath • Compressibility Factors of Natural Gas and
Ultrasonic Meters Other Related Hydrocarbon Gases

AGA Report No.10-2002 GPA Standard 2172-1996 (Option)

• Speed of Sound in Natural Gas and Other • Calculation of Gross Heating Value,
Related Hydrocarbon Gases Relative Density and Compressibility Factor
for Natural Gas Mixtures from
Compositional Analysis

ISO 6976-1995 (Option) ASTM D 1945-2003

• Natural gas - Calculation of calorific values, • Standard Test Method for Analysis of
density, relative density and Wobbe index Natural Gas by Gas Chromatography
from composition

26
Ultrasonic Gas Meter Type
⮚Transit Time Method
• Based of the difference between the transit time of
ultrasonic pulses propagating with and against the flow
direction.
⮚Doppler/Frequencies Shift Method
• Based of the doppler shift that results from th reflection of
an ultrasonic beam off sonically reflective materials, such as
solid particles or entrained air bubbles in a flowing fluid, or
the turbulence of the fluid itself, if the liquid is clean.

Note: AGA Report No.9 is only covers for transit time method

27
Pipe Flow Velocity

Good Flow for Meter: Single Phase, Fully Developed & Turbulent

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Pipe Flow Velocity

V(r) = measured Gas Velocity on r

position
Vmax = measured Gas Vel. on the
center
Re = Reynolds Number
R = Radius of pipe
r = radial position
n = Reynolds Number Function

Re = 105 (n = 7.455), Re = 106 (n = 9.266), Re = 107 (n = 11.109)

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Ultrasonic Measurement Principle

v = measured average gas velocity

c = measured speed of sound
tu = transit time from Tx1 to Tx2
td = transit time from Tx2 to Tx1

Note: the measurement principle only for one path tranducer, how if more than one path ?

30
Multipath Ultrasonic Meter
For multipath layer design the averrage gas
velocity become :

v(pi) = average measure gas velocity on path i

N = number of path
wi = weighthening factors for path i

wi are constants and depending on applied

integration technique related Reynolds
number and tranducers position. Each
manufacturer may have own standard
Multiplication between average velocity and
flowrate area A, yield the volumetric
flowrate Q.

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 Multipath Ultrasonic Meter
Weighthening Factors Example’s

W1=0.125, W2=0.125, W3=0.25, W4=0.25, W5=0.125, W6=0.125

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Accuracy
⮚ Accuracy of an ultrasonic gas meter depends on:
✔ Precise geometry of the meter body and ultrasonic transducer
locations
✔ The integration technique inherent in the design of the meter
✔ The quality of flow profile, levels of pulsation that exists in the
flowing gas stream and gas uniformity
✔ The accuracy of transit-time measurements
⮚ The accuracy of transit-time measurements depends on
✔ The electronic clock stability
✔ Consistent detection of sound pulse wave reference position
✔ Proper compensation for signal delays of electronic components
and transducers

33
Measurement Uncertainty
1. Meter calibration uncertainty
2. Uncertainty arising from difference between the field
installation and the calibration lab
✔Parallel meter runs
✔Installation effects
✔Pressure and temperature effects
✔Gas quality effects
3. Uncertainty due to secondary instrumentation

34
Measurement Uncertainty Calculation’s
Basic mathematical model is given

Combined uncertainty

The combined uncertainty is contributed by several component such as :

✔Uncorrected volume flowrate
✔Pressure measurement
✔Temperature measurement
✔Determintaion of compresibility

35
Measurement Error’s
⮚ Random errors
– Random errors can be caused by various influences on a meter’s
operation
– Random errors normally follow a certain statistical distribution
– The magnitude of the random error can usually be reduced by
acquiring multiple measurement samples and then applying
accepted statistical principles
⮚ Systematic errors
– Systematic errors normally cause repeated measurement errors
for some reason
– Some technique to reduce or eliminate error can be taken such as
1. Wet-calibration
2. Temperature and pressure correction

36
 Measurement Error’s
Temperature Correction

D1 = Di D0 = Dio
X1 = X i X0 = Xio
L1 = Li L0 = Lio
R1 = R1+∆R
α = Thermal expansion coefisien
∆T = temp. at flowing – temp. at dimension measurements

( Daniel use this formula )

37
 Measurement Error’s
Pressure Correction

D1 = Di D0 = Dio
X1 = X i X0 = Xio
L1 = Li L0 = Lio
R1 = R1+∆R
P1 = Pressure at flowing
P0 = Pressure at dimensions measurements
Ew = Modulus young
AGA Report No.9 only mention formula to determine R1 = R0, how about L1 = L0 and X1 = X0 ?
AGA Report No.9 only mention 1 path as example, how about multipath USM?
Geometry approach as solution?

38
 Measurement Error’s
Pressure Correction from Manufacturer (daniel’s)

39
Measurement Error’s
⮚Consideration to apply pressure and temperature
correction
✔Already compensated by wet-calibration ?
✔USM model’s and manufacture’s (manufacturer’s
standard) ?
✔Agreement on pipeline system ?
✔Corrected by flowcomputer or USM ?

40
Operating Condition’s
1. Gas Quality
a. Natural gas composition specified in AGA8
b. Manufacturer should be consulted if :
✔CO2 is above 10%
✔operation near the critical density of natural gas mixture
✔total sulfur level exceeds 20 grains per 100 standard cubic feet
2. Pressure (manufacturer shall specify minimum and
maximum pressure)
3. Temperature (-4 to 140 DegF)
4. Gas Flow Consideration (minimum and maximum
flow rate)
5. Upstream Piping and Flow Profiles
6. Acoustic Noise

41
 Meter Requirement’s
1. Codes and regulations 5. Electronics
2. Quality assurance ✔General requirements
✔Output signal specifications
3. Meter body ✔Electrical safety design
✔ Maximum operating pressure requirements
✔ Corrosion resistance ✔Component replacement
✔ Meter body length and bores
✔ Ultrasonic transducer ports 6. Computer programs
✔ Pressure tap ✔Firmware
✔ Miscellaneous ✔Configuration and maintenance
software
✔ Meter body marking
✔Inspection and auditing functions
4. Ultrasonic transducers ✔Alarms
✔ Specifications ✔Diagnostic measurements
✔ Rate of pressure change
✔ Exchange 7. Documentation
✔ Tranducers test ✔After receipt of order
✔Before shipment

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 General Meter Peformance Requirement’s

For each meter design and size, the manufacturer shall specify flowrate limits for qmin, qt and
qmax.

43
General Meter Peformance Requirement’s
Meter with size 12-inch or larger shall meet the following accuracy:

Meter with size less than 12-inch shall meet the following accuracy:

44
 General Meter Peformance Requirement’s

The USM shall meet the above flow measurement accuracy requirements over the full operating pressure,
temperature and gas composition ranges without the need for manual adjustment, unless otherwise stated
by the manufacturers.
If the USM requires a manual input to characterize the following gas conditions (eg. gas density and
viscosity), the manufacturers shall state the sensitivity of these parameter so that the operator can
determine the need to change the parameter as operating condition change.

45
 Individual Meter Testing Requirement’s
1. Leakage test (minimum 200 psig maintained for 15 minutes minimum)
2. Dimensional measurements
3. Zero-Flow Verification test
✔ No individual path gas velocity be greater than 0.02 ft/s on averages
✔ The speed of sound per path should be within 0.2% of the theoretical value
✔ The performance per path should be 100%
✔ All gain ratings should be within the normal limits provided by the manufacturers
4. Meter and metering package flow-calibration test ( Wet calibration )
✔ Flow calibration at: 0.0125qmax, 0.05qmax, 0.10qmax, 0.25qmax, 0.5qmax, 0.75qmax, and
qmax
✔ Preparation for flow calibration
✔ Calibration of meter package
✔ Calibration adjustment factors
a. Flow-weighted mean error (FWME)
b. Polynomial algorithm
c. piece-wise linear interpolation or other methods
✔ Calibration test report
✔ Final consideration

46
 Individual Meter Testing Requirement’s
Dimensional Measurement

47
Individual Meter Testing Requirement’s
Zero-Flow Verification Test

48
 Individual Meter Testing Requirement’s
Wet-Calibration

49
 Individual Meter Testing Requirement’s
TCC Wet-Calibration Facility (CANADA)

50
 Individual Meter Testing Requirement’s
Forced Technology Closed Loop Wet-Calibration Facility
(DENMARK)

51
 Individual Meter Testing Requirement’s
Flow-Weighted Mean Error Adjustment

Full Scale = Indicated Meter Flow Rate/ Qmax

Weighted Error = Indicated Error * Full Scale value

FWME = Sum of the Weighted Errors/ Sum Full Scale Weighting

FWME = -1.379/2.596
= -0.5312%

Adjustment Factor = 100/100+FWME

= 100/100+ (-0.5312)
= 1.0053

52
 Individual Meter Testing Requirement’s
Polynomial Algorithm Adjustment
Velocity (adj) = bo + b1* Velocity (corr) +
b2*Velocity *(vel/30)^2

b0 = -0.0024
b1 = 1.0051
b2 = 0.0181

Velocity (corr) = 50.08 ft/sec = 15.264 m/s

Velocity (adj) = -0.0024 + (1.0051*15.264) +
0.0182*sin(15.264)*
(15.264/30)^2
= 15.340 m/s
= 50.334 ft/sec

Note : Each manufacturers have standard to

calculate and apply a polynomial

53
 Individual Meter Testing Requirement’s
Piecewise Meter Adjustments

54
 Individual Meter Testing Requirement’s
Wet-Calibration Results

55
 Individual Meter Testing Requirement’s
Wet-Calibration laboratory
Name Location Gas Type Range Pressure Temperature Uncertainty
(m3/hr) (barg) (deg.C) (k=2)
Pigsar Dorsten, Natural 8 - 6500 14 - 50 N/A 0.16%
Germany Gas
Force Vejen, Natural 8 - 10000 0 - 50 15 -25 0.18 – 0.30%
Technology Denmark Gas
GL Noble Durham, Natural 20 - 19500 35 - 55 5 - 15 0.19 – 0.24%
Denton England Gas
NMI Rotterdam, Natural 5 - 30000 0 - 60 N/A 0.15%
Euroloop Netherland Gas
CEESI Iowa, USA Natural 10 - 34000 70 N/A 0.23%
Gas
TCC Manitoba, Natural 30 - 55000 60 – 70 N/A 0.19%
Canada Gas
???? Indonesia ???? ???? ???? ???? ????

56
Installation Requirement’s
1. Environmental requirements 3. Associated Flowcomputer
✔Temperature ✔Flowcomputer calculation (AGA 7)
✔Vibration
✔Electrical noise 4. Maintenance
✔Pulsation
2. Piping configuration
✔Flow direction
✔Piping installation
✔Protrusions and misalignments
✔Internal surface (250 µinch Ra or
smoother is recommended)
✔Thermowhells and sample probe
✔Flow conditioners
✔Orientation of meter
✔Filtration
✔Meter tube ports

57
Installation Requirement’s
AGA 9 installation recommendation

58
 Installation Requirement’s
Manufacturer’s installation recommendation

59
USM VERIFICATION AND
DIAGNOSTIC METHOD

60
Field Verification Test
1. Zero-flow test
✔no individual path gas velocity be greater than ± 0.02 ft/s on average
2. Speed of sound measurement
✔The speed of sound per path should be within ± 0.2% of the theoretical
value(AGA 10)
✔The average speed of sound should be within ± 0.2% of the theoretical
value (AGA 10)
✔The individual path speed of sound measurements should be within ± 0.5
m/s or ± 1.5 ft/s of the average
3. Internal inspections
✔Borescope
✔Cleaning
4. Configuration verifications
✔Dry and wet calibration parameters should be comply with the certificate
✔Dimensional parameters should be comply with the manufacture data

61
Field Verification Test
Diagnostic/Inspection report

62
Field Verification Test
Metrological USM verification form

63
USM Diagnostic Method
⮚Each manufacturers has own method to diagnostic
USM healthy depend on USM chord model.
⮚Every chord design has purpose to analyze flow and
inside surface condition.
⮚Mostly technique to diagnose the meter and flow
condition involve the following:
1. Flow profile
2. Signal quality
3. Automatic Gain Control
4. Velocity of Sound
5. Transit time / time of flight

64
USM Diagnostic Method (Daniel Mark III)

65
USM Diagnostic Method (Daniel Mark III)

66
USM Diagnostic Method (Daniel Mark III)
Flow Profile

Path A

Path B

Path C

Path D

14 14.5 15 15.5 16 16.5 17 17.5 18 18.5 19

Avg Flow Velocity (ft/s)

67
USM Diagnostic Method (Daniel Mark III)
Normal Flow Profile
Path A

Path B

Path C

Path D

14 15 16 17 18 19
Avg Flow Velocity (ft/s)

Blocked CPS Flow

Profile
Path A
Path B
Path C
Path D

14 15 16 17 18 19
Avg Flow Velocity (ft/s)

68
 Avg Performance (%) Avg Gain (dB)

10
20
30
40
50
60
70
90
80

10
20
30
40
60
70
80
90

50

0
100
A

A
B

B
Chord

Chord
C

C
D

D
Average Gain

Average Performance

Upstream
Upstream

Downstream
Downstream

SOS Diff from Avg (ft/s) Turbulence (%)

2
4
6

-0.5
0

-1
0.5

8:41:12…
8:41:12… 8:41:18…
8:41:18… 8:41:24…
8:41:24… 8:41:30…
8:41:30… 8:41:36…
8:41:36… 8:41:42…
8:41:42… 8:41:48…
8:41:48… 8:41:54…
8:41:54… 8:41:59…
TurbulenceA (%)

SndVelDiffA (ft/s)
SndVelDiffC (ft/s)
TurbulenceC (%)

8:41:59… 8:42:06…
8:42:06…
8:42:12…
Time

8:42:12…
Time

8:42:18…
8:42:18…
8:42:24…
Turbulence

8:42:24…
8:42:30… 8:42:30…
8:42:36… 8:42:36…
SOS Diff from Avg

8:42:42… 8:42:42…
8:42:48… 8:42:48…
TurbulenceB (%)
TurbulenceD (%)

SndVelDiffB (ft/s)
SndVelDiffD (ft/s)

8:42:54… 8:42:54…
8:43:01… 8:43:01…
8:43:07… 8:43:07…
USM Diagnostic Method (Daniel Mark III)

69
Lesson Learn (Daniel Mark III)
48 Hour Validation Result
0

Apr-15
Feb-15

Mar-15

Jun-15

Jul-15

Feb-16
Jan16
May-15

Aug-15

Sep-15

Oct-15

Nov-15

Dec-15
-0.1
-0.2
-0.3
Diff (%)

-0.4
-0.5
-0.6
-0.7
-0.8
-0.9
48 Hour Result Flow Velocity Difference

On may 2015 right after USM cleaned, the 48 hour running series validation result
become very high. The condition occurs until the end of February 2016.

70
 Lesson Learn (Daniel Mark III)
SOS Difference From Average USM-A
1.5
SndVelDiffA (ft/s) SndVelDiffB (ft/s) SndVelDiffC (ft/s) SndVelDiffD (ft/s)
From maintenance log archive made
chart that showing the SOS difference
SOS Diff from Avg (ft/s)

1
between every single chord and
0.5
average.
0

-0.5
On may 2015 to February 2016 the SOS
-1 difference on chord A USM-B is high
-1.5 than before. The owner tried to make
SOS Difference From Average USM-B the necessary improvements during that
SndVelDiffA (ft/s) SndVelDiffB (ft/s) SndVelDiffC (ft/s) SndVelDiffD (ft/s) time such as:
1.5
1. Open and cleaning the upstream
SOS Diff from Avg (ft/s)

1
side of USM-B including the pipe
0.5
spool and flow profiler on
0
December 2015.
-0.5
2. Open and cleaning all of
-1
transducers on USM-A on January
-1.5
2015.

71
 Lesson Learn (Daniel Mark III)
Improve after
Turbulance USM-B flow profiler cleaned Cross Flow Improve after
Chord A Chord B Chord C Chord D FT-011 FT-021
1.1 flow profiler cleaned
6
5
1.05
4
3 1
%

2
0.95
1
0 0.9

Symmetry Improve after

flow profiler cleaned

1.1
FT-011 FT-021 There is no running series improvement after
1.05
cleaning on December 2015 and January
2016. The only improvement on december
1
are turbulance, cross flow and symetry. Dirty
0.95
rubber is found inside pipe spool stuck on
0.9
the flow profiler during the cleaning.

72
 Lesson Learn (Daniel Mark III)
Eta USM-A Transit Time Error Chord A
te A FT-011 te A FT-021 Difference
4 Eta BA Eta BD Eta CA Eta CD 1.5

2 1

us
0.5
us

-2 0

-4 -0.5

Eta USM-B
4 Eta BA Eta BD Eta CA Eta CD Eta-BA and Eta-CA on USM-B are shifted
2 more than 2 us from May 2015. This fact
indicating an transit time error on the chord-
us

-2
A. Initial suspision there is dirt on the top of
-4
transducers chord-A, so that the dirt material
affects the velocity of sound.

73
 Lesson Learn (Daniel Mark III)
SOS Diff from Avg (Before Cleaning)
SndVelDiffA (ft/s) SndVelDiffB (ft/s)
SndVelDiffC (ft/s) SndVelDiffD (ft/s)
1
SOS Diff from Avg (ft/s)

0.5
0
-0.5
-1
-1.5
7:55:13 AM
7:51:09 AM
7:51:44 AM
7:52:19 AM
7:52:53 AM
7:53:28 AM
7:54:05 AM
7:54:38 AM

7:55:48 AM
7:56:23 AM
7:56:59 AM
7:57:33 AM
7:58:08 AM
7:58:44 AM
7:59:19 AM
7:59:53 AM
8:00:28 AM
8:01:03 AM
SOS Diff from Avg (After Cleaning) On April 2016, the owner decide to open transducers
SndVelDiffA (ft/s) SndVelDiffB (ft/s) on USM-B and cleaning all of them and no significant
SndVelDiffC (ft/s) SndVelDiffD (ft/s)
0.6 dirt on the top of tranducers.
SOS Diff from Avg (ft/s)

0.4
0.2
0 They found hardened lubricant which may have
-0.2
-0.4 altered the distance between transducers A1 and A2
-0.6
2:57:59…
2:57:31…
2:57:37…
2:57:44…
2:57:52…

2:58:06…
2:58:13…
2:58:19…
2:58:26…
2:58:33…
2:58:42…
2:58:48…
2:58:55…
2:59:02…
2:59:09…
2:59:16…
2:59:23…
2:59:29…

and causing its Chord VOS to deviate away from VOS

of other chords . The dirt is suspected to be lubricant
applied by owner after inspection/ cleaning last May
2015

74
FLOW COMPUTER

75
 Flowcomputer
Purpose
1. Flow correction and calculation
2. Totalizer
3. Reporting
4. Archiving
5. Host data
Requirement
1. Compliances to calculation standard (AGA, ISO, GPA, API, etc.)
2. Durability and reability
3. Redundancy
4. Measurement peformace
5. Cycles time
6. Output & input (pulse, analog, serial, TCP IP, etc.)
7. Memory
8. User interface

76
Orifice Meter Application

77
Ultrasonic Meter Application

78
 Acceptances Criteria
1. Analog Input error should be ± 0.25% full scale
2. Standard calculation should comply by government
regulation and/or sales agreement.
3. Constants parameters should comply by government
regulation and/or sales agreement. (atmospheric
pressure, base pressure, base temperature etc.)
4. Calculation (dynamic and static) deviation should be ± 1%
compare with manual calculation (third party software
such as flowsolv and kelton).
5. Snapshot report, periodic report and totalizer

79
Third Party Software

•FLOWSOLV

•KELTON

80
Flow Computer Verification Form

81
 FloBoss S600 Flash
Overview
• Panel mounted case
• 24vdc supply
• Optional I/O expansion boards up to 3 per unit
• Optional Prover I/O board
• PC Windows configuration tools designed for end user
• Built-in scripting language - custom calculations
• Enhanced communications LAN & high speed serial
• Support up to 10 streams
• 10 levels security
• Maintenance mode
• Applications : Gas (Orifice, Turbine, USM, Coriolis), Liquid
(PD/turbine, Coriolis), Prover (Bi-Directional, Compact, Master
Meter, Uni-Directional)

82
FloBoss S600 Flash
Mechanical
• Modular design
• Standard case accommodates
CPU + 3 x I/O boards
• Panel Mounting

83
FloBoss S600 Flash
Communication Feature’s
• TCP/IP Ethernet
Telnet / FTP / DDE / OPC / Web server
• 5 Available Serial Ports
(2 x RS232, 3 x RS422/485)
• Modbus Protocol
(ASCII, RTU, TCP/IP, ENRON)
• Serial Printer Interface
• Junior Sonic and Senior Sonic Interfaces
• Daniel 2251, 2551 and 2350 Gas
Chromatograph Controller Interfaces
• Micromotion Coriolis Interface
• Supervisory Modbus Maps
• Dedicated Prover Link

84
FloBoss S600 Flash
I/O Feature’s
• 12 x Analogue inputs (24 bit)
• 4 – 20mA / 1 – 5V
• 0 – 20mA / 0 – 5V
• 2 / 3 point field calibration
• 4 x Analogue outputs
• 4 – 20mA / 0 – 20mA
• 3 x RTD (24 bit)
• DIN 43760
• American alpha 0.00392 IPTS/68
• 2 / 3 point field calibration
• 5 x Pulse outputs (½ – 500Hz)
• 16 x Digital inputs
• 12 x Digital outputs
• 4 x Turbine inputs
• 2Hz – 10Khz
• Line integrity check with Level A / B (IP252)
• 3 x Density inputs (25 – 1000Hz)
• Raw pulse output (open collector / differential

85
FloBoss S600 Flash
Config 600 - Overview
• Create / configure applications
• Upload / download configuration files
• Install new firmware
• Extract live / historical data
• Context sensitive help

86
 FloBoss S600 Flash
Config600 - Generator
• Allows the User to build a new configuration
• Six steps
• Select functionality from pre-defined templates

Config600 – PC Setup
• Units
• I/O
• Passwords
• Descriptors
• Cold start values / constants
• Alarms
• Reports
• Communication links
• Existing calculations (can not add new
calculations)

87
 FloBoss S600 Flash
Config600 – System Editor
• Data points
• Calculations
• Alarms

Config600 – Logicalc Editor

• Manipulate data
• Write custom features in a BASIC type language.
• Write, Test & Debug code in a common interface.

88
 FloBoss S600 Flash
Config600 – Modbus Editor
• Modify data for Master or Slave link.

Config600 – Report Editor

• Used to preview and customise reports

89
 FloBoss S600 Flash
Config600 – Display Editor
• View and modify the default display structure

Config600 – Transfer
• Send and retrieve configurations with your PC and
the S600
• Update the S600 VxWorks firmware

90
 FloBoss S600 Flash
Config600 – Packages

Package IPL600 Lite Pro

Config transfer
PCSetup editor
Report editor
Modbus editor
Display editor
Logicalc
System editor
Config generator
S600 archive
S600 view

91
 ONLINE
GAS CHROMATOGRAPHY
(DANALYZER MODEL
500)
92
 Gas Chromatograph
List of Content
1. Chromatography Theory
2. Basic Operation of Online GC
3. Online GC Components
4. Online GC operation
5. MON 2000 Software Operation
6. Online GC Maintenance & Troubleshooting

93
 Chromatography Theory
D:\Materi Training KJG\GC2.jpg

Single column chromatography/

laboratory GC
sample Signal conditioner
regulator Sample injector

detector

oven What.. 12 min..?! are you serious..?!!

Wee need it faster..!!
Chromatography column
Gas Carier What the difference with online GC?
(Helium)

94
Basic Operation of Online GC (Chromatography Method)

1. Most of the online GC will divide

components in to two or three groups to
cutting analyze time.
2. All of those GC use more than one column
and valve.
3. Time event adjustment is crucial.
4. Several GC use more than one oven so
that the time analyze become faster or to
be able to analyze more components.
5. Time analyze able to reach less than 4
minutes to analyze.
6. Components that able to analyzed are
C6+, C7+ to C9+ and H2S depend on
configuration of column, oven and time
event.

95
 Basic Operation of Online GC (Typical Online GC Sequence)

Time Event
Group-1 = C6 1. DC/V, BF/V and S/V switch ON.
Group-2 = C3,iC4, NC4, iC5 and NC5 2. S/V switch OFF after a while to capture precise
Group-3 = N2, C1, CO2 and C2 volume of sample.
3. BF/V switch OFF to flushing back column 1 so
that Group-1 goes to detector.
4. DC/V switch OFF to trapp Group-3 into column
3. Group-2 will allow to detector trough column
2.
5. DC/V switch ON to flush column 3 and Group-3
goes to detector.

96
Basic Operation of Online GC
Types of Detector

Photo Ionization Detector (PID)

Flame Photometric Detector (FPD)

Flame Ionization Detector (FID)

Thermal Conductivity Detector (TCD)

1 PPM 10 PPM 100 PPM 1000 PPM 1 Mole % 100 Mole %

97
Online GC Component’s
B

D
A

A. Sampling System
B. Analyzer
C. Controller

98
Online GC Component’s (Sampling System)

SCS Plate single stream with autocal and bypass

SCS Plate single stream with autocal
What the difference between with and
without bypass?
Why need to add stream bypass?

99
Online GC Component’s (Sampling System)

Four stream SCS Plate

Typical manifold for two carrier gas

100
Online GC Component’s (Analyzer)

Analyzer Sub-Systems

101
Online GC Component’s (Oven)
HEATSIN
DETECTOR K
HOUSING OVEN
HEATSINK OVEN COLUMN
AND VALVES S

SAMPLE
LOOP

6 PORT VALVE

102
Online GC Component’s (Analyzer)

Column

Typical Column Arrangement

103
Online GC Component’s (Analyzer)

Diaphragm Valve Operation

When pneumatic pressure is applied to the actuating
diaphragms, the piston are actuated, thus forcing the sealing
diaphragm against the primary plate. This closes the
passages that are connected at the bottom of the plate.
When pressure is removed, the pistons are free to move and
flow is resumed through the passages.

104
 Online GC Component’s (Analyzer)
Thermal Conductivity Detector
1. Detector design of TCD is based on an electronic circuit known as Wheatstone
bridge.
2. When a current is applied, the voltage between pints (+) and (-) in the circuit will will
be zero as long as the following relationship is true: R1/R 2 =R 3/R 4
3. In a TCD, one of these resistors is placed in contact with mobile phase leaving the
column and another in a reference stream containing only pure mobile phase.
4. As current is passed through the circuit, the wire in the resistors are heat. For those
in contact with the mobile phase and reference stream, some of this heat is
removed.
5. Temperature changes leads to resistance changes of resistors
6. Most compound separated in GC have thermal conductivity of 1-4 X 10-5

105
Online GC Component’s (Controller)
Controller Feature
✔ 8 Analog Input 4-20 mA; four AI for GC analyzer and the
others four AI for additional input.
✔ Max 10 non isolated Analog Output 4-20 mA; two AO are
standard and the others eight are optional.
✔ There are 16 digital Inputs:
1. 5 to read a Modbus address, as defined by DIP switch
positions
Field Mounted Controller 2. 2 to indicate presence and type of front panel as
Explosion Proof (NEMA 4X) defined by switch positions
3. 1 as spare
4. 1 GC alarm, optically isolated, with transient protection
5. 5 stream flow alarms, optically isolated, with transient
protection
6. 1 photocell detector, front panel backlight (night on,
day off)
✔ There are 22 digital outputs:
1. 6 analyzer control
2. 8 driver outputs for DC air solenoids (stream switching,
12 total streams)
3. 5 alarms, optically isolated, with transient protection
4. 3 front panel indicators (green, yellow, red)
Remotely Mounted Controller ✔ There are 3 to 8 communications port available, depending on
19” Rack option package selected. (RS-232, RS-422 or RS-485)

106
Online GC Component’s (Controller)

GC Controller Board Block Diagram

107
GC Operation (local Keypad and
Display)

108
 GC Operation (local Keypad and
• Display)
Interface Components for Local Data Display and Entry
Light Emitting Diode (LED) Indicators

Liquid Crystal Display (LCD)

109
 GC Operation (local Keypad and
Display)
Keypad
These are the numeric keys, ESC, NEXT, BKSP, ENTER, period (.) and () keys (). Thr other keys are
obtained by pressing ALT and the desired letter or symbol on the lower half of the key. For
instance, to obtain capital B, press ALT while simultaneously pressing the B key twice.

110
 GC Operation (local Keypad and
Display)
Keypad

111
 GC Operation (local Keypad and
Display)
Keypad

112
 GC Operation (local Keypad and
•
Display)
Logging On to View or Edit Data
First Time Log-On

113
 GC Operation (local Keypad and
Display)
Subsequent Log-On

114
GC Operation (local Keypad and
Display)

115
 GC Operation (local Keypad and
Display)
Start/Halt an Auto Sequence Analysis

116
GC Operation (local Keypad and
Display)

117
 GC Operation (local Keypad and
Display)
Subsequent Log-On

118
MON 2000 Software Operation (Instalation)

119
MON 2000 Software Operation (First Log On)

120
MON 2000 Software Operation (GC Directory)

121
MON 2000 Software Operation (GC Directory)

122
MON 2000 Software Operation (Connect to GC Unit)

123
MON 2000 Software Operation (Auto Sequence)

124
MON 2000 Software Operation (Single Stream)

125
MON 2000 Software Operation (Halt)

126
MON 2000 Software Operation (Calibration)

127
MON 2000 Software Operation (Chromatogramph Viewer)

128
GC Routine Maintenance Procedure

129
 % Mol Calculation on GC
Determine %mol of gas component
1. Determine peak area of each component
2. By multiply the number of peak area with response
faktor will get %mol of eacf component
%mol = PA x RF
3. Normalize of all contents to 100%

PA = peak area
RF = response factor

How to determine response factor..??

130
Determine Response Factor (Calibration Sequence)
Calibration process
1. Known gas calibration concentration is used as
reference
2. Each GC calibration process consists of three
times cycles
3. Each cycles generate response factor as follow
RF = %mol / PA
4. Final response factor is averaging of all cycles as
New RF
5. If deviation between New RF and Old RF below
10%, then New RF will replace Old RF as used RF

how if response factor not accepted ?

and why?

131
 Excess Response Factor Deviation
Tricks to do force calibration
1. Be sure that the GC in good
condition and or part replacement
has been well implemented
2. Do manual calibration on GC and
necessary event adjusment
3. Repeat the calibration up to
minimum two or three stable New
Most causes of sudden excess response factor RF
deviation are systems change and or part
replacement such as 4. Apply force calibration on the last
1. Column replacement calibration so that used RF replaced
2. Censor replacement by New RF
3. Valve replacement 5. Repeat manual calibration once or
4. Dirt from gas process more to make sure that RF is stable
5. Etc. and the RF deviation no more than
10%

132
Example Analysis Report

133
GC Verification
Requirement that must to meet by GC to pass the verification as follow
1. that correct calibration gas concentration is entered to GC as
reference
2. Perform repeatability test
3. Perform reproducibility test
4. Baseline is clean and straight
5. Check all component are detected
6. Check correct order of component ( C6+, C3, iC4, NC4, iC5, NC5, N2,
C1, CO2, C2)
7. No ghost peak on chromatogram
8. Some manufactures requires RF linearity to pass verification

134
GC Verification Form

135
GC Verification Form

136
Repeatability VS Reproducibility
1. Repeatability—The difference between two successive results obtained by the
same operator with the same apparatus under constant operating conditions on
identical test materials should be considered suspect if they differ by more than
the following amounts:

1. Reproducibility—The difference between two results obtained by different

operators in different laboratories on identical test materials should be
considered suspect if they differ by more than the following amounts:

Source : ASTM-D 45

137
Analyze Baseline

138
Analyze Chromatogram

139
Analyze Chromatogram

140
Analyze Chromatogram

141
Alarm and Possible Causes

142
Alarm and Possible Causes

143
Recommended Spare Parts

144
Recommended Spare Parts

145
Recommended Spare Parts

146
MOISTURE ANALYZER
AMETEK 3050

147
3050 Specification
✔Range : 0.1 – 2500 ppmv
✔Accuracy : +/- 10%
✔Limit of Detection : 0.1 ppmv when used
with dryer
✔Sensitivity : 0.1 ppmv
✔Response Time : 63% to step change in less
then 5 minutes
✔Input Pressure Range : 20 – 50 psig
✔Sample Gas Temperature : 32 to 212 deg.F

148
 3050 Components
1. Moisture Sensor
⮚ Quartz Crystal that has been coated with
proprietary hygroscopic coating
⮚ The coating absorb moisture from a sample gas
stream changing the mass of coating
⮚ Changes in mass are detected as changes in
natural resonance frequency of the oscilator
2. Dryer
⮚ To dry reference gas to less than 0.025ppmv
⮚ Replace periodically – 1 year
3. Moisture Generator
⮚ A divice capable of generating a known precise
moisture level ; typically 50ppmv
⮚ Used for analyzer’s proper operation verification
and calibration

149
3050 Measurement Principle

150
3050 Verification

151
3050 Configurator Software

152
3050 Configurator Software

153
3050 Configurator Software

154
3050 Configurator Software

155
3050 Replacement Parts

156
H2S ANALYZER

157
Principle Operation Tape Analyzer Type
• Reaction of H2S with lead acetate impregnated tape.
• The tape color is white before exposure to H2S.
• On contact with H2S, the lead acetate in the tape is converted to lead sulfide. The
lead sulfide darkens the tape (a brown color).
• A photodiode is used to measure the tape darkness.
• Tape darkness is proportional to the H2S gas concentration contacting the tape over
a specific time at a constant flow.
• The higher the concentration of H2S, the darker the tape becomes.
• to improve the response of the lead acetate tape, the sample gas is bubbled through
a 5% acetic acid solution.

158
Tracker XP H2S Analyzer

Tracker XP Tracker XP Sample Conditioning

Enclosure
159
Tracker XP H2S Analyzer

Tracker XP Electronic
Board

160
 Principle Operation UV Analyzer Type

1. Sample Cell (B) conducts the sample gas stream from the inlet (A), around a folded channel
and returned (C).
2. The cell Windows (D) and the cell itselt are in intimate contact with a heater plate (not
shown) keeping it and sample at a precisely controlled temperature.
3. Light from the hollow cathode lamps (G) enters the front cell window then passes through
the the sample in the top leg of the cell channel and returns (E) to the photometer where
atenuation of specific UV light frequencies is measured.

161
Ametek 933 H2S analyzer

Analytical Block Diagram

162
Ametek 933 H2S analyzer

Sample Flow Diagram

163
Ametek 933 H2S analyzer

Ametek 933 Enclosure

164
 Ametek 933 H2S analyzer
Features & Benefits
✔ Unattended operation for up to 9 months makes the Model 933-C perfect for
remote custody transfer stations
✔ No consumables, reagents, or carrier gas required other than zero gas makes the
analyzer ideal for offshore platforms
✔ High concentrations H2S incidents do not overload the analyzer, as can happen with
lead acetate analyzers
✔ Continuous, fast response time
✔ 933-C permits analysis prior to dehydration for optimal plant control by providing
on-line analysis information one to two minutes in advance of the normal sample
point location located at the sales gas pipe. The savings in off spec gas is significant
and avoiding flaring incidents is significant.
✔ Optional COS concentration

165
Tape Analyzer VS UV Analyzer

166
Tape Analyzer VS UV Analyzer

167
THANK YOU

168