Contaminant Control:
a New Approach
David Burns
davbur@sps2test.com
Scientific Process Solutions
a division of Perry Equipment Corporation
Introduction


Scientific Process Solutions
(SPS) is a division of Perry
Equipment Corporation
(PECO) that offers field
contaminant measurement
and consulting services.
SPS serves the natural gas
transmission and processing,
chemical processing,
refining, and power
generation industries.
Contaminants and Contaminant
Mixtures
Contaminant
–Solids
–Liquids
–Semi-solids
–Foams
–Emulsions
Types
Solids

Common solid contaminants
–
–
–
Formation solids (reservoir and frac sand)
Corrosion solids (iron sulfide, iron oxide)
Precipitating solids (elemental sulfur, salt
compounds)
Formation Solids
Corrosion Solids
(Iron Sulfide)
Precipitating Solids
Sulfur Compounds
Precipitating Solids
Siloxane Compounds
Liquids












lube oil
salt water or brine
water condensate
hydrocarbon condensate
crude oil
glycol (TEG)
gas processing amines
corrosion inhibitors
biocides
foaming agents
defoaming agents
mecury
Semi-solids

Semi-solids are usually mixtures of solid and liquid contaminants
Foams

Foams are mixtures of gases and liquids
Emulsions

Emulsions are mixtures of different liquids and gas
Contaminants and Contaminant
Mixtures
Each
of these different types of contaminants and
contaminant mixtures can cause serious process
problems if the filtration separation system is not
properly designed to handle them.
Hard to remove contaminant mixtures are more
common than ever due to increased use of well head
and pipeline injection chemicals.
Greater contaminant removal performance is required
today, due to the increased use of industry technology
like formulated processing solvents, membrane
separators, gas fired turbines, LoNox nozzles and
burner tips.
Filtration & Separation Devices


Filtration technology has greatly advanced over the
last few years to meet industry’s need for improved
performance.
This advancement in new filtration technologies
makes the equipment selection process even more
difficult.
Filtration & Separation Devices
Gas Filters
Technology
Typical Application
Dry Gas Filters
Solids removal.
Knock Out Drums
Removal of bulk pipeline liquids.
Vane Separators
Cyclones
Removal of continuous pipeline
liquids. Used usually upstream of
other more efficient filtration
equipment.
Removal of continuous pipeline
liquids. Usually used on the suction
and discharge of compressors.
Removal of low surface tension
pipeline liquids and semi-solids.
Removal of bulk pipe solids.
Scrubbers
Removal of small liquid slugs.
Slug Catchers
Removal of large liquid slugs.
Filter Separators
Removal of pipeline liquids and solids.
Coalescers
Removal of low surface tension liquids
and aerosols.
Gemini Purasep Coalescer
Removal of low surface tension
liquids, solids, and aerosols.
Wire Mesh Separators
Centrifugal Separators
Performance
Characteristics
Uses replaceable filter elements and
has a limited dirt holding capacity.
Large liquid handling capacity and low
removal efficiency.
Low cost with moderate removal
efficiency.
Low cost and low removal efficiency.
Low cost, high pressure drop and
improved removal efficiency.
Low cost, no replacement parts and
improved removal efficiency.
Low cost and moderate removal
efficiency
Large vessels or piping systems with
very low removal efficiency.
Uses replacement elements and has
a good removal efficiency. Low
element replacement cost.
Excellent removal efficiency. Low
contaminant handling ability. High
element replacement cost.
Excellent removal efficiency.
Moderate contaminant handling
ability. Moderate element replacement
cost.
Filtration & Separation Devices
Liquid Filters
Technology
Typical Application
Cartridge Filters
Solid and semi-solid removal.
Hydrocyclones
Removal of bulk pipeline solids.
Basket Strainers
Bag Filters
Removal of bulk pipeline solids. Used
usually upstream of other more
efficient filtration equipment.
Removal of pipeline solids.
Liquid Phase Separators or
Coalescers
Separation of two immisible liquids.
Removal of free moisture from fuels. .
Performance
Characteristics
Uses replaceable filter elements and
has a limited dirt holding capacity.
Removal efficiency depends on
element technology used. Usually
used where excellent removal
efficiency is needed.
Large solids handling capacity with
moderate removal efficiency.
Low cost with moderate to low
removal efficiency.
Low cost. Removal efficiency
depends on contaminant and bag
technology used. Low bag
replacement cost. Short life when
semi-solids are present.
Excellent separation efficiency. High
element cost. Low solids handling
ability.
The Contaminant Dictates the Method




A system’s contaminant content and properties
dictate the separation technology used.
It is important to provide detailed scientific data on a
system’s contaminant species on RFQ process data
sheets.
Detailed scientific data on a system’s contaminant
species will help insure that filtration separation
technologies are selected that will provide the
required removal efficiency at an optimum
operational cost.
Optimally designed filtration and separation
equipment will save money.
Field Experiences
Example 1
Field Experiences
Example 1




This processing facility had 4 coalescers experience a decrease
in removal performance.
The additional vane mist extractor had been selected for use on
the coalescers to handle high liquid loads.
However, over 4 years time the extreme solids loading
eventually plugged off the drainage ports of the vane mist
extractors, sending more liquid to the coalescer elements than
they could handle.
Had up front contaminant testing been done on this system, the
large solids load would have lead filtration designers to use a
different technology to protect the coalescer elements for the
system’s high liquid and solids contaminant content.
Field Experiences
Example 1

The Solution
–
–
–
–
Solvent and steam cleaning failed.
Coalescers had to be cut open to be cleaned.
Coalescers were put back into service.
Bulk solids loading removal technologies are being reviewed
for installation upstream of the coalescers.
Field Experiences
Example 2


A custody transfer station was having problems with
liquid contamination fouling pressure control and
measurement equipment.
A surplus filter separator was sized for the gas flow
rate and installed to eliminate the contamination
causing the problems.
Field Experiences
Example 2


The problems continued.
SPS was hired to test the contaminant loading
entering and exiting the filter separator.
Field Experiences
Example 2



The inlet gas stream was measured to contain 98
liters per day of free liquid contaminant entering the
filter separator.
The filter separator outlet gas stream was measured
to contain 98 liters per day of free liquid contaminant
entering the filter separator.
The liquid was identified to be lube oil with a surface
tension of 28 dynes/cm.
Field Experiences
Example 2

Conclusion
– The liquid contaminant’s surface tension was too low for a
filter separator to work properly.

The Solution
– A slug catcher and high liquid loading horizontal coalescer
were installed in place of the filter separator.

The Result
– Test results of the new system measured an outlet
contaminant content of 0.43 PPB(wt) or about 0.007 liters of
carryover per day.
– Pressure control and measurement equipment are now
working properly.
Field Experiences
Example 3



This gas element came
under attack from a
contaminant that was not
chemically compatible with
it’s media material.
It is important to study the
chemical compatibility of all
of a system’s contaminant
species with any filter
materials that might be
used.
This is a case where a filter
element problem can go
undetected contaminating
downstream processes.
Field Experiences
Example 3

The Solution
– A chemically compatible element material was selected and
installed in service.
– No other process problems have been reported.
Field Experiences
Example 4



A natural gas fired turbine
failed it’s NOx emissions
requirement.
The turbine’s LONOx fuel gas
nozzles were found to be
damaged and partially
plugged off with
contaminant.
The LONOx nozzles were
protected by a 1 micron
filtration separation system.
Field Experiences
Example 4

Conclusion
– The standard 1 micron filtration vessel was not efficient
enough for the system’s contaminant size.

The Solution
– A 0.3 micron high dirt loading coalescer vessel was installed.

The Result
– The turbine passed it’s next NOx emissions test.
– No additional nozzle damage has occurred.
Field Experiences
Example 5


A gas processing facility was
experiencing plant iron
sulfide contamination
resulting in excessive TEG
and amine filter element
changes.
The system’s inlet gas 0.3
micron coalescer was tested
and found to be allowing
iron sulfide contamination to
pass downstream.
Field Experiences
Example 5

Conclusion
– The standard 0.3 micron element technology was not
sufficient to remove the system’s iron sulfide contaminant.
– Dry pipeline conditions and high velocities worked to shear
the iron sulfide contaminant size distribution to be partially
under 0.3 microns in size.

The Solution
– An iron sulfide removing element technology was installed in
the existing coalescer.
– An upstream water wash system was also installed.
Field Experiences
Example 5

The result
– Down stream element life was extended by 7 times.
– The water wash system worked with the iron sulfide element
technology to wash the contaminant off of the coalescer
elements extending their life to over a year and counting.
A New Approach



Gather information on your system’s contaminant
species before entering the bidding process.
Have liquid samples from the system or at least a
nearby system analyzed for identification, surface
tension, viscosity, pH, density, total suspended solids
loading, and solid particle size.
If possible, have the system on-line tested for
contaminant loading and size. Testing done on-site
will provide important contaminant content data that
is not available from laboratory tests.
A New Approach
Field Testing Protocols
DCM (Direct Contaminant Measurement Laser Testing)
CCM (Coalescer Contaminant Measurement Testing)
SCM(Solids Contaminant Measurement Filter Disk Testing)
A New Approach
DCM
Direct Contaminant Measurement
A New Approach
DCM
Direct Contaminant Measurement
DCM Specifications
The DCM protocol utilizes a high pressure laser particle counter to
measure and quantify aerosol contaminant in a gas stream.
The protocol is used for testing down stream of coalescers,
Gemini Purasep units, and filter separators.
 Measurement range 0.3 - 8 micron
 Operating pressure range 2 - 2000 psi
 Operating temperature range 40 - 180 deg. F
 Maximum aerosol content 30 ppm
 Maximum gas velocity 30 ft/sec
Scientific Process Solutions
Direct Measurement Contaminant Analysis
High Pressure Laser Field Test Report
Test Summary No.
1
Date:
Tested By:
Vessel Type:
Element Type:
Client:
Testing Location:
Vessel Model No: PGCPH-18-382-34-750
Input Values
Vessel Flow Rate: (MMSCFD)
Operating Pressure: (PSIG)
Operating Temperature: (F)
Specific Gravity:
Vessel ID: (inches)
Liquid Density: (lbs/ft3)
Number of Samples:
Ave. Particle
Size (micron)
0.300
0.350
0.400
0.450
0.500
0.550
0.600
0.650
0.700
0.750
0.800
1.000
3.000
5.000
8.000
Particle
Wt (lbs)
2.49E-17
3.96E-17
5.91E-17
8.42E-17
1.15E-16
1.54E-16
2.00E-16
2.54E-16
3.17E-16
3.90E-16
4.73E-16
9.24E-16
2.49E-14
1.15E-13
4.73E-13
147
586
81
0.6
34
50
360
Sample
Average
34022.43
15257.16
6926.63
1405.64
25.15
22.25
2.14
0.09
0.01
0.00
0.01
0.01
0.00
0.00
0.00
Average
Sample wt
8.4863E-13
6.0432E-13
4.0954E-13
1.1833E-13
2.9042E-15
3.4202E-15
4.2784E-16
2.2489E-17
1.7555E-18
1.0796E-18
6.5512E-18
5.1182E-18
0
0
0
Calculations
Compressibility:
Flow Rate: (acfh)
Gas Density: (lbs/ft3)
X-Sec Area: (ft2)
Sample Velocity: (ft/hr)
Flow Meter Setting: (ml/sec)
0.925
144316
1.946
6.305
22889
16.0
Sample Sequence:
10 Sec
22-Jan-04
T. Borjon, D. Burns
Gemini
PGC-382
Testing Notes
Liquid Surface Tension: (dyn/cm)
Sample Collection Time: (sec.)
Sample Connection:
Atm Press.
Sampling Duration 11:03-12:03 (min)
10
Pipeline
14.7
60
Total Accumulated Sample Wt: (lbs/10sec)
Total Accumulated Sample Wt: (lbs/sec)
1.99E-12
1.99E-13
Carryover PPM (wt)
0.007368
Carryover Gal/Day
0.00595
Notes:
Ave Total Counts
57662
Average Particle Counts Versus Micron Size
50000
45000
40000
35000
30000
25000
20000
15000
10000
5000
0
0.300
0.350
0.400
0.450
0.500
0.550
0.600
0.650
0.700
0.750
0.800
1.000
3.000
5.000
A New Approach
CCM
Coalescer Contaminant Measurement
A New Approach
CCM
Coalescer Contaminant Measurement
CCM Specifications
The CCM test coalescer system is designed to measure free liquids
and aerosols in almost any application. The CCM unit is
commonly used for testing gas separators and scrubbers. The
unit can also be used to quantify the inlet gas streams to
coalescers, Gemini Purasep units, and filter separators.
 Liquid collection range
0.3 micron - free liquid
 Operating pressure range 2 - 1480 psi
 Operating temperature range - 40 - 250 deg F
 Testing sample line size 1/2” - 1”
Scientific Process Solutions
Coalescer Contaminant Measurement Analysis
Test Summary No.
6
Date:
File Name:
Tested By:
Test Vessel Type:
Element Type:
Client:
Testing Location: Compressor Station
Vessel Name/No:
Sample Point: Upstream Pipeline High Point Vent
Input Pipeline Values
Pipeline Flow Rate: (MMSCFD)
Operating Pressure: (PSIG)
Operating Temperature: (F)
Specific Gravity:
Pipeline ID: (inches)
Liquid Density: (lbs/ft3)
Test Start Time:
Test Finish Time:
81.3
319
81
0.75
19.25
50
12:15:00
4:15:00
Calculations
Compressibility:
Flow Rate: (acfm)
Gas Density: (lbs/ft3)
Pipeline X-Sec Area: (ft2)
Gas Velocity: (ft/min)
4:15:00
Totals
20
Special Testing Notes:
Input Test Vessel Values
Operating Pressure: (PSIG)
341
Operating Temperature: (F)
60
Sampling Line Diameter ID:(inch)
1
Sampling pipe X-sec Area: (ft2)
0.0055
Sample Line Velocity: (ft/min)
1100.08
0
1440
Test Vessel Flow Rate: (acfm)
Total Testing Period: (minutes)
Total Testing Period: (hours)
240
4.00
Test Start DP: (in of WC)
Test Finish DP: (in of WC)
6.00
0
0
Liquid Collection Summarys
Upper Sum p Low er Sum p
(milliliters)
20
Tomas Borjon, David Burns
77V-1-312-8-1480
NGGC312
Initial Totalizer Reading: (cuft)
Final Totalizer Reading: (cuft)
Liquid Collection Log
Time
0.912
2360
1.371
2.021
1167.54
Nov. 5, 2003
(milliliters)
0
0
Total Liq
(milliliters)
20
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20
Total
Total
Total
Total
Total
Total
Amount of Liquid Collected: (milliliters)
Amount of Liquid Collected in Upper Sump (aerosols): (milliliters)
Amount of Liquid Collected in Lower Sump (free liq): (milliliters)
Liquid Mass Collected: (lbs)
Liquid Mass Collected in Upper Sump (aerosols): (lbs)
Liquid Mass Collected in Lower Sump (free liq): (lbs)
20
20
0
0.0353
0.0353
0.0000
Total Mass of Gas Tested
Total Gas Tested During Testing Period: (cuft)
Total Gas Tested During Testing Period: (lbs)
1440
1974.89
Liquid Contaminant Content Level
Liquid Aerosol Content in the gas: (PPM wt)
Free Liquid Content in the gas: (PPM wt)
17.9
0.0
Total Liquid Content in the Gas Stream: (PPM wt)
17.9
Pig entered plant receiver at 2:50 p.m.
A New Approach
SCM
Solids Contaminant Measurement
A New Approach
SCM Particle Sizing Laboratory Equipment
A New Approach
SCM
Solids Contaminant Measurement
SCM Specifications
The SCM testing protocol is used to quantify solid or semi-solid
contaminant content in a gas stream. Microscopic analysis can
be added to provide a particle size distribution.


Operating pressure range 2 - 2000 psi
Operating temperature range - 40 - 250 deg f
A New Approach



Provide the contaminant data on filtration separation
specification data sheets for E&C’s to include during
the bidding process.
Performance verify new and existing filtration and
separation equipment. Include performance
verification in initial equipment scope of supply.
Have process optimization studies done for your plant
or facility’s contaminant control equipment.
A New Approach

The Result
– Scientific contaminant data provided on RFQ data sheets will
result in the purchase of filtration separation systems that
will provide optimum operational performance at an
optimum capital and operational cost.
– Performance verification of new and existing equipment will
identify problems before additional damage to expensive
downstream equipment occurs.
– Process optimization studies of contaminant control systems
will lower overall plant operational cost.
Thank you for your kind attention.
Questions???