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1/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Cryogenic CO2/H2S capture technologies for
remote natural gas processing
Mehdi Panahi
Trial Lecture
December 1st, 2011Trondheim
2/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
3/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
4/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Green house gases cause global warming: CO2, the major one
Intergovernmental Panel on Climate Change (IPCC):
“Emissions must be reduced by 50% to 85% by 2050 if global warming is to be confined to between 2°C to 2.4°C”
World energy demand is increasing• more fossil fuels• 130% rise in CO2 emissions by 2050• rise in global average temperature by 6°C
CO2 effect on Global warming
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Associated CO2 with natural gas is one of the sources of global CO2 emissions
CO2 content in natural gas varies between 2-65% and in some reserves is even more!
Increasing demand for natural gas has made reserves with high CO2 content economically
H2S is often present with CO2 in natural gas reserves
CO2 emission from gas processing plants
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Natural gas containing H2S > 4 ppm is called “sour gas”
Natural gas containing acidic gases like CO2/H2S is called “acid gas”
To produce “sweet gas”, CO2 and H2S (for technical and environmental reasons) must be removed and stored
Specs. for natural gas pipelines:CO2: ≤ 2-4 mol% (varies by the country)H2S: ≤ 4 ppm
Specs. of natural gas for LNG plants:CO2: < 50 ppmH2S: < 4 ppm
Definitions and Spec in gas processing plants
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Most high CO2 natural gas resources are located in SE Asia, NW Australia, Central USA, North Africa and Middle East
It is estimated 1/5-1/3 of global natural gas resources have significant amounts of CO2 and H2S
Natuna gas field in Indonesia, the largest high CO2 reserve: (>70%v)
LaBarge gas field (65% CO2) in SW Wyoming (USA), discovered in 1963, production delayed until1986 because of high CO2 concentration
High acid gas content natural gas reserves
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Adsorption (chemical,C / physical,P)Activated carbon (C), Chemsweet (C), Molecular sieves (P), Zinc oxide (C)
Absorption (mostly chemical)ADIP, Alkazid, Amisol, Benfield, Catacarb, CNG (P), Estasolvan, Flexsorb SE, Flour Econamine, Flour solvent, Giammarco-Vetrocoke, MEA, MDEA, Purisol (P), Rectisol (P), Seaboard, Selexol (P), Sepasolv MPE (P), SNPA-DEA, Stretford, Sulfiban, Sulfinol, Tripotassium Phosphate, Vaccum Carbonate, Zinc oxide
Cryogenic distillationControlled Freeze Zone (CFZ), Ryan Holmes, Cryocell, Sprex, Twister
Membrane
Different (old/new) Technologies for CO2/H2S removal
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Applications of different technologies in gas processing plants for removing of acid gases
AdsorptionSuitable for reducing CO2 content from 3% to 0.5%
Not applicable for high CO2 concentration streams since it needs frequent regeneration of solid bed
AbsorptionSuitable for low pressure streams with CO2 content of 3-25%
This method is the conventional method, which is widely used in natural gas processing industries
Not suitable for very high CO2 concentration streams due to large solvent recirculation and consequently large heat duty in the stripper for solvent regeneration
10/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Applications of different technologies in gas processing plants for removing of acid gases
MembraneFlexible for different CO2 concentrations, but maintaining high performance of membrane in presence of varying contaminants of natural gas stream is a challenge
Traditional technologies: - remove acid gases at near atmospheric pressures, - required significant amount of energy to compress acid gases for re-injection for Enhanced Oil Recovery (EOR)
Cryogenic distillationSuitable for removing high CO2/H2S contents from natural gas streams especially for offshore applications
11/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
12/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Point 1:Feed
Point 2: reaching the VL zone
Chilling the feed
Point 3:
-8 (-22°C)
Vapor: 72% CH4
Liquid: 18% CH4
Point 4: Vapor: 85% CH4
Target: natural gas product with 1% CO2
Feed: 50% CH4/50% CO2
Achieving natural gas with CH4 purity of >85% is not possible in one conventional distillation column
Solidification point of CO2
Phase diagram for CO2/CH4 in 650 Psia (44 bar)
(-62°C)
Figure from: H.G. Donnelly and D.L. Katz, Phase equilibria in the carbon dioxide-methane system, I&EC, 46 (1954), 3, 511-517
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Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
14/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Ryan Holmes method
The Figure from: A. S. Holmes, J. M. Ryan, Cryogenic distillation separation of acid gases from methane, US patent, 1982
Idea: Adding a solids-preventing agent e.g. NGL, to the solids potential zone of cryogenic distillation column
Invented by Arthur S. Holmes and James S. Ryan at Koch Process Systems, US in 1982
Pre-cooler
Cooling to cryogenic
temperatures
Agent should have a freezing temp. below condenser Temp.
By adding sufficiently agent, the liquid composition is moved away from the freezing point
This method is commonly used in gas processing plants
Suitable for offshore applications?
15/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
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Controlled Freeze Zone method (CFZTM)CFZTM method:
invented at Exxon production research in 1983patented in 1985
First pilot plant (the picture in the right) at Exxon’s Clear Lake Gas plant in Pasedena (1987):
0.6 MMSCFD, CO2 (from 15% to 65%), pressure (38-42 bar)
Quality of products:while the design of top product (natural gas) specification was pipeline specs, it met LNG feed required specs!
The design of methane loss at the bottom product (liquid CO2) was 1%, but it reached 0.5%
Further studies were stopped due to collapse in oil pricesFigure from: J. A. Valencia, P. S. Northorp, C. J. Mart, Controlled Freeze Zone™ Technology for enabling processing of high CO2 and H2S gas reserves, ExxonMobil Upstream Research Company IPTC 12708 (2008)
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Exxon’s first CFZ commercial demonstration plant at Shute Creek gas processing plant
Scale up: 23
Integrated with a gas field injection
Initial tests prove removal of CO2 content from 65% down to <1000ppm (July 2011)
The tests are still being done in 2011-2012
Figure from: C. Condon, M. Parker, Shute Creek Gas Treating Facility Project Updates, The Wyoming Enhanced Oil Recovery Institute 5th Annual Wyoming CO2 Capture Conference, 13 July 2011
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CFZ method: thermodynamic concept
-57°C
14 bar
42 bar
32°C-101°C
82 bar
Figure from the references below:
H.G. Donnelly and D.L. Katz, Phase equilibria in the carbon dioxide-methane system, I&EC, 46 (1954), 3, 511-517 and J. A. Valencia, P. S. Northorp, C. J. Mart, Controlled Freeze Zone™ Technology for enabling processing of high CO2 and H2S gas reserves, ExxonMobil Upstream Research Company IPTC 12708 (2008)
critical point of
methane
critical point of CO2
Rather than avoiding solidification, CFZ allows acid gases to freezeOperating at higher pressure than CO2 solidification pressure (?)Limitation of locus of the critical pointsStill far from the required purity for methane product
-1°C
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Operating the column in lower pressure than solidification pressure
Operation crosses the solidification region
3 operational zones are present:
1. Stripping section (conventional distillation)
2. Solidification (controlled freeze zone, CFZ) section
3. Rectifying section (conventional distillation)
Feed (mixture of CH4 and CO2) enters somewhere near the middle of column
Reboiler duty; allowable loss of methane in CO2 liquid bottom product
Condenser temperature; required specs for purified methane
CFZ distillation operation
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Liquid from the top distillation section is sprayd into the CFZ section
Warmer temperature vaporize the lighter components
Solid (pure CO2) is formed in CFZ section and fall on the liquid layer
Bottom part of CFZ is kept above solidification temperature
Vapor rises from the bottom distillation section to the CFZ section
Colder temperature in CFZ section condenses CO2
CO2 product (liquid)/or any other acid gas, easily to be pumped for geo-sequestration or for EOR purposes
methane product (high quality) available in high pressure
Figure from: B.T.Kelly, J. A. Valencia, P. S. Northorp, C. J. Mart, Controlled Freeze Zone™ for developing sour gas reserves, Energy Procedia 4 (2011), 824-829
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Operational temperature will depend on feed composition and product specification
CFZ distillation operates at constant pressure
Optimized pressure of CFZ column depends on
• pressure of the gas reserve,
• required pressure for purified natural gas (sales spec),
• geometry of the column
Optimal operation of CFZ distillation
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Advantages of CFZ method
Suitable for high CO2/H2S content natural gas reserves
Separation is done in a single column, low investment cost, less challenges for offshore applications
Purified natural gas product in high pressure (reduce the compressor work to export by the pipeline)
Availability of CO2/H2S product in liquid form, readily to be pumped for EOR, geo-sequestration purposes
23/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
24/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Cryocell method
This method was developed by Cool Energy Ltd and tested in collaboration with Shell in Australia (Perth)
Idea:
CO2 sublimation point: -78.5°C (at 1 bar)
CH4 (major component of Natural gas) sublimation point: -182°C (at 1 bar)
Mixture of light hydrocarbons + CO2 at certain T,P: Vapor-Liquid-Solid phases
Solid phase: pure CO2, Vapor/Liquid phase: CO2 + hydrocarbons
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Figure from: A. Hart and N. Gnanendran, Cryogenic CO2 Capture in Natural Gas, Energy Procedia 1 (2009), 697-706
Thermodynamic behavior of mixture of hydrocarbons + CO2
VLSE diagram for a high CO2 content natural gas: 50% CO2, 40% CH4, 10%
other light hydrocarbons
2- Feed is cooled down to above solidification temperature of CO2(liquid phase)
3- Liquid is isenthalpic flashed through a Joule-Thomson valve into a separator; solid-vapor-liquid
1- Mixture (feed) at pressure > 50 bar and ambient temperature
Selection of appropriate: - pre-cooling temperature - flash pressure
to minimize CO2 content in vapor phase and methane content in liquid phase
before JT valve
after JT valve
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Different Cryocell configurations
Based on natural gas composition:
- high (>20%) or low (<20%) CO2 composition
- lean (recovery uneconomical) or rich of NGLs
4 process flow configurations
low CO2/lean Natural gas
low CO2/Rich Natural gas
high CO2/lean Natural gas
high CO2/Rich Natural gas
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Cryocell process diagram for low CO2/lean Natural gas
Figure from: A. Hart and N. Gnanendran, Cryogenic CO2 Capture in Natural Gas, Energy Procedia 1 (2009), 697-706
Base case Cryocell flow diagram
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Figure from: A. Hart and N. Gnanendran, Cryogenic CO2 Capture in Natural Gas, Energy Procedia 1 (2009), 697-706
Cryocell process diagram for high CO2/Rich Natural gas
Additional bulk CO2 removal column and NGL recovery
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Cryocell field results
Design of demonstration plant based on scheme for low CO2-lean gas (2008, 2009)
Removing down CO2 content from 60% to 26%, 40% to 14%, 21% to 4% and from 13% to 3%
Excellent match between tests and simulation results (Aspen Hysys + CryoFlash)
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Comparison between Cryocell and Amine Absorption
Amine CryoCellSale gas rate, MMSCFD 37.7 27.8 38.2 29.6
Investment cost(1000 AUD), accuracy 30%
CO2 20% CO2 35% CO2 20% CO2 35%
64,359 108,777 48,877 67,464
Compression Power (MW) 1.9 3.8 4.3 7
Electrical load (MW) 1.3 2.2 0.2 0.3
Process Heating (MW) 19 35 < 0.1 < 0.1
The data from: A. Hart and N. Gnanendran, Cryogenic CO2 Capture in Natural Gas, Energy Procedia 1 (2009), 697-706
Other advantages of Cryocell: No need for chemical solvent, no make up water, no heating system, no potential foaming
Cryocell has higher maintenance costs for rotating equipment
Suitable for offshore applications
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Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
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Sprex (Special pre-extraction) method
Patented by IFP in 1994 and further developed in joint with TOTAL
Idea:Improving the economics of amine absorption processes for removal of high H2S content (as high as 40%) in natural gas, where acid gases are re-injected to the reservoir
Temperature of cryogenic section is -65°C
High pressure liquid H2S ready to be pumped into the reservoir
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A temperature of -60°C to -70°C must be attained
Sprex (Special pre-extraction) method
Figure from: ToTAL website
http://www.total.com/MEDIAS/MEDIAS_INFOS/239/EN/sour-gas-2007.pdf?PHPSESSID=cec2fdfc960710c595870d3827bb4269
Much smaller amine absorption
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Raw gas flowrate (MMSM3/day) 4.6 (165 MMSCFD)
Treatment Pressure 70 bar
Acid gas injection pressure 150 bar
Feed gas composition H2S:35%, CO2:7.5%, C1:65.2%, C2+:1%
Treated gas specs H2S: 4ppm, CO2: 2%
Amine Amine+Sprex 30
Capex (MM USD) 153 128
Power consumption (MW) 52 30
Steam consumption (MW) 46 34
The data from: F. Lallemand, F. Lecomte and C. Striecher, “Highly Sour Gas Processing, H2S bulk removal with the Sprex Process”, IPTC 10581, 2005
Comparison of Sprex method with Amine absorption
Sprex decreses the amine absorption size significantly
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Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
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Twister method
Idea: condensation and separation in supersonic velocity (extremely short residence time), thermodynamically similar to a turbo-expander
Figure from: P. Schinkelshoek, H. D. Epsom, Supersonic gas conditioning commercialization of Twister technology, 87th annual convention, Grapevine, Texas, USA
Expansion DistillationPressure Recovery
Temperature drop by transforming pressure to kinetic energy (i.e. supersonic velocity)
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Twister method has been successfully applied for water dehydration and NGL/LPG extraction
First commercial offshore application in 2004 for dehydration of 600 MMSCFD sour gas at Bintulu in Malaysia (6 Twister tubes in two parallel dehydration units)
A Twister process scheme has been developed for H2S/CO2 bulk removal from sour gas
An amine absorption process is needed to purify the outlet of Twister to the required specs; methane recovery of 95% is expected
Compact lightweight Twister can significantly decrease the size of conventional absorption processes, suitable for offshore applications
Twister method
38/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
Outline
1. Introduction
2. Cryogenic technologies
- Ryan Holmes method
- Controlled freeze zone (CFZ) method
- Cryocell method
- Sprex method
- Twister technology
3. Conclusions
39/41 M. Panahi ’Cryogenic CO2/H2S capture technologies for remote natural gas processing’
CFZ, Cryocell, Sprex and Twister seem to be very promising and advanced options
Increasing demand for natural gas has made high acid gas reserves economically
Conclusions
Cryogenic technologies are suitable for offshore applications processes, and operation in high pressure;
- small sizes compared to conventional amine absorption- less energy requirement- separation of acid gases in liquid form and high pressure; readily to be pumped to the reservoir
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References[1] Sources of CO2 IPCC Special Report on Carbon dioxide Capture and Storagehttp://www.ipcc.ch/pdf/special-reports/srccs/srccs_chapter2.pdf
[2] J. Hao, P.A. Rice, S.A. Stern, Upgrading low-quality natural gas with H2S and CO2 selective polymer membranes: Part I. Process design and economics of membrane stages without recycle streams, Journal of Membrane Science, 209, 1, 177-206
[3] D. A. Coyle, V. Patel, Process and Pump services in the LNG industry, Proceedings of 22nd international pump user symposium 2005,
[4] http://en.wikipedia.org/wiki/Sour_gas
[5] WFJ Burgers, PS Northrop, HS Kheshgi, JA Valencia, Worldwide development potential for sour gas, Energy Procedia, 4 (2011), 2178–2184
[6] H. J. Herzog and E. M. Drake, Carbon dioxide recovery and disposal from large energy systems, Energy and the Environment, 12 (1996), 145-166
[7] J. A. Valencia, B. K. Mentzer, Processing of High CO2and H2S Gas with Controlled Freeze Zone™ Technology, ExxonMobil Upstream Research Company GASEX 2008 Conference
[8] http://www.fischer-tropsch.org/DOE/DOE_reports/GRI/gri-86_0009-1/86_0009-1,%20Part%204,%20Pages%20298%20-%20409.pdf
[9] E. Keskes, C.S. Adjiman, A. Galindo, and G. Jackson, a physical absorption process for the capture of CO2 from CO2-rich natural gas streams, Chemical Engineering Department, Imperial College London, http://www.geos.ed.ac.uk/ccs/Publications/Keskes.pdf
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References[10] H.G. Donnelly and D.L. Katz, Phase equilibria in the carbon dioxide-methane system, I&EC, 46 (1954), 3, 511-517[11] J. A. Valencia, P. S. Northorp, C. J. Mart, Controlled Freeze Zone™ Technology for enabling processing of high CO2 and H2S gas reserves, ExxonMobil Upstream Research Company IPTC 12708 (2008)[12] B.T.Kelly, J. A. Valencia, P. S. Northorp, C. J. Mart, Controlled Freeze Zone™ for developing sour gas reserves, Energy Procedia 4 (2011), 824-829[13] C. Condon, M. Parker, Shute Creek Gas Treating Facility Project Updates, The Wyoming Enhanced Oil Recovery Institute 5th Annual Wyoming CO2 Capture Conference, 13 July 2011
[14] A. Hart and N. Gnanendran, Cryogenic CO2 Capture in Natural Gas, Energy Procedia 1 (2009), 697-706[15] P. Schinkelshoek, H. D. Epsom, Supersonic gas conditioning commercialization of Twister technology, 87th annual convention, Grapevine, Texas, 2008[16] P. Schinkelshoek, H. D. Epsom, Supersonic gas conditioning for NGL recovery, offshore technology conference, Houston, 2008[17] A. S. Holmes, J. M. Ryan, Cryogenic distillation separation of acid gases from methane, US patent, 1982[18] http://www.total.com/MEDIAS/MEDIAS_INFOS/239/EN/sour-gas-2007.pdf?PHPSESSID=cec2fdfc960710c595870d3827bb4269
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Thank you for your attention!