Contaminant Control: a New Approach David Burns davbur@sps2test Scientific Process Solutions

1. Contaminant Control: a New Approach David Burns davbur@sps2test.com Scientific Process Solutions a division of Perry Equipment Corporation

2. 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.

3. Contaminants and Contaminant Mixtures Contaminant Types Solids Liquids Semi-solids Foams Emulsions

4. Solids • Common solid contaminants • Formation solids (reservoir and frac sand) • Corrosion solids (iron sulfide, iron oxide) • Precipitating solids (elemental sulfur, salt compounds)

5. Formation Solids

6. Corrosion Solids(Iron Sulfide)

7. Sulfur Compounds Precipitating Solids

8. Siloxane Compounds Precipitating Solids

9. 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

10. Semi-solids • Semi-solids are usually mixtures of solid and liquid contaminants

11. Foams • Foams are mixtures of gases and liquids

12. Emulsions • Emulsions are mixtures of different liquids and gas

13. 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.

14. 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.

15. Filtration & Separation DevicesGas Filters

16. Filtration & Separation DevicesLiquid Filters

17. 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.

18. Field ExperiencesExample 1

19. Field ExperiencesExample 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.

20. Field ExperiencesExample 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.

21. Field ExperiencesExample 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.

22. Field ExperiencesExample 2 • The problems continued. • SPS was hired to test the contaminant loading entering and exiting the filter separator.

23. Field ExperiencesExample 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.

24. Field ExperiencesExample 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.

25. Field ExperiencesExample 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.

26. Field ExperiencesExample 3 • The Solution • A chemically compatible element material was selected and installed in service. • No other process problems have been reported.

27. Field ExperiencesExample 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.

28. Field ExperiencesExample 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.

29. Field ExperiencesExample 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.

30. Field ExperiencesExample 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.

31. Field ExperiencesExample 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.

32. 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.

33. A New Approach Field Testing Protocols DCM (Direct Contaminant Measurement Laser Testing) CCM (Coalescer Contaminant Measurement Testing) SCM(Solids Contaminant Measurement Filter Disk Testing)

34. A New Approach DCM Direct Contaminant Measurement

35. A New Approach DCM Direct Contaminant MeasurementDCM 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

37. A New Approach CCM Coalescer Contaminant Measurement

38. A New Approach 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” CCM Coalescer Contaminant MeasurementCCM Specifications

40. A New Approach SCM Solids Contaminant Measurement

41. A New Approach SCM Particle Sizing Laboratory Equipment

42. A New Approach 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 SCM Solids Contaminant MeasurementSCM Specifications

43. 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.

44. 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.

45. Thank you for your kind attention.

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