10 th ECCRIA 15 September 2014 CCS system modelling: enabling technology to help accelerate commercialisation and manage technology risk Adekola Lawal Senior Consultant, Power & CCS
Overview Systems modelling for CCS CCS process models Power generation Solvent-based CO 2 capture CO 2 compression CO 2 transmission and injection Applications Case Study 1 CCS Chain Shell CCS Operability study DECC Industrial CCS study
Systems modelling for CCS
CCS chains Existing technology in a new configuration Government Policy Strategic Infrastructure development H&S Grid demand Flexibility Efficiency Fuel mix Trip scenarios Tools PROATES GTPro Ebsilon Dymola Aspen Plus Sizing Flexibility Buffer storage Amine loading Tools Capital cost gproms optimisation PROMAX Energy sacrifice Aspen Plus Heat integration Solvent issues Optimal operating point Efficiency Tools New design Various in-house Impurities Control Safety Composition effects Phase Tools behavior Capacity OLGA Buffering PIPESIM / packing Routing Safety Depressurisation Control Leak detection Injection/storage Compression Supply variability Composition Thermodynamics Tools Temperatures OLGA / hydrates Well Prosper/Gap performance Long-term storage dynamics Back-pressures new technology required to address the new challenges posed by integrated CCS system
The CCS System modelling Tool-kit Project 2011-2014 Energy Technologies Institute (ETI) ~ 3m project commissioned & co-funded by the ETI Objective: end-to-end CCS modelling tool gproms modelling platform & expertise Project Management
System-wide modelling Key enabling technology for CCS Explore complex decision space rapidly based on highfidelity, technically realistic models resolve own technical and economic issues take into account upstream & downstream behaviour Manage interactions and trade-offs Evaluate technology existing and next-generation judge relative merits of emerging technologies support consistent, future-proof choices Integrating platform for working with other stakeholders in chain collaborative R&D, working with academia
CCS System Modelling Tool-Kit gccs initial scope (2014/Q3) Process models Power generation Conventional: pulverised-coal, CCGT Non-conventional: oxy-fuelled, IGCC Solvent-based CO 2 capture CO 2 compression & liquefaction CO 2 transportation CO 2 injection in sub-sea storage Materials models cubic EoS (PR 78) flue gas in power plant Corresponding States Model water/steam streams SAFT-VR SW/ SAFT- Mie amine-containing streams in CO 2 capture SAFT- Mie near-pure post-capture CO 2 streams
CCS components process models
Sub-system #1 Supercritical pulverized coal power plant Governor valve Turbine sections Generator Boiler Air Coal Feed Water Heaters Flue gas treatment Deaerator Condenser > 10 recycles & closed water/steam loop
gccs Power Plant library conventional power generation CCGT power plant Natural Gas Gas Turbine Steam drums Air Stack Economisers, superheaters, evaporators Condensate return Generator Input flexibility: Total power output or natural gas flowrate specified Steam turbines Steam to Capture Plant Condenser
Sub-system #1 other power technologies considered Oxyfuel power plant Steam cycle Process side Oxyfuel boiler and recycle Compression and purification
Process side Sub-system #1 other power technologies considered Oxyfuel power plant Steam Cycle
Sub-system #1 other power technologies considered IGCC power plant Integrated Gasification Combined Cycle power plant (IGCC) HRSG and steam turbines Gasification and syngas cooling Gas turbine Acid gas removal (AGR) and sulphur recovery unit (SRU) Air separation unit (ASU) and compression Syngas conditioning
Sub-system #2 CO 2 capture plant CO 2 capture rate controller Absorber Solvent /water makeup controllers Stripper Condenser Reboiler CO 2 inlet Direct Contact Cooler (DCC) Buffer Tank
Sub-system #3 CO 2 compression plant Fixed speed electric drive Variable speed electric drive Dehydration unit Compression section (Frame #1: 4 ; Frame #2 2) Cooler KO drum Surge valve
Sub-system #4 CO 2 transmission pipelines 160m -200m Emergency shutdown valves (ESD) Gate valve CO 2 flowmeter Pipelines Schedule 40, 18 Vertical riser from sea bed 20km 200km
Sub-system #5 CO 2 injection & storage in reservoir Distribution header Choke valves Wellhead connections 20m above water, 70m submerged Wells 7, 2km Reservoir ~250 bar
System overview Chemical absorption MEA solvent 90% CO 2 capture 220km of pipeline Onshore and Offshore 29, equations/variables 27,991 algebraic 4 compression trains 1,709 differential ~MWe 2 frames per train Computation time Supercritical Surge (on desktop control computer) ~200s for steady Offshore dense-phase Pulverized coal (acknowledgement: state (much) less injection; 4 injection wells (acknowledgement: E.ON) Rolls-Royce) for sensitivity runs ~7h for 50h dynamic simulation ~2km reservoir depth (acknowledgement: CO2DeepStore)
System model hierarchy
Case Study: state-state analysis
Steady-state scenarios Scenario Description Power plant operation (% of nominal load) Capture plant operation (CO2 % captured) SS1.1 (a,b,c) Base Load Power Plant (a) 100%; (b) 75%; (c) 50% 0% (no capture) SS1.2 (a, b) Base load CCS Chain 100% (a) 90%; (b) 50% SS1.3 (a, b) Part Load Analysis (a) 75%; (b) 50% 90% SS1.4 SS1.5 Extreme Weather: Max Summer 100% 90% Extreme Weather: Max Winter 100% 90% Affected sub-systems Base Extreme Extreme Winter Cooling water Power, Capture, Compression 18 22 7 Temperatures ( o C) used for model calibration Case Summer (e.g. Stodola constants for steam turbines; HTA for feed water heaters, etc.) Air Power, Transmission, 15 30-15 Injection Sea water Transmission, Injection 9 14 4 NB. Geothermal gradient of +27.5 o C / km
Steady-state analysis Power generation : coal milling + power plant auxiliaries : coal milling + power plant auxiliaries + CO 2 compression : capture plant steam 100% 0% 75% 0% 50% 0% 100% 90% 100% 50% 75% 90% 50% 90% 100% 90% Summer 100% 90% Winter
Case Study: dynamic analysis
Grid Demand (MW) System-wide modelling Typical day in 2010 00 00 40000 30000 20000 10000 Wind= low penetration Baseload=Inflexible Nuclear Flexible =(Gas and Coal) varies around the demand curve Barrage = Intermittent Tidal Barrage Useable Wind Flexible Lose Base or Spill Spill Baseload -Spill 0-10000 00:30 12:30 00:30 12:30 Time Source:
Grid Demand (MW) System-wide modelling Windy day in 2030 with high wind penetration 00 00 Wind= high penetration Flexible =(Gas and Coal) varies around the demand curve and also variations in wind power 40000 Barrage Useable Wind 30000 Flexible Lose Base or Spill 20000 Spill Baseload 10000 -Spill 0-10000 00:30 12:30 00:30 12:30 Time Additional power at night is large enough to impact base load plant requires spill of renewable or baseload power. Source:
Dynamic analysis Scheduled changes in power plant load Scenario DS1.1 Scenario DS1.2 Power Power Load Load 100% 100% 5 hours 23.5 hours 5 hours 75% 5 mins 1 hour 5 mins 75% 5 mins 42.5 hours Time Time
Volume fraction Mass flowrate (kg/s) Stem position Stem position Mass flowrate (kg/s) Net Efficiency (%) Dynamic analysis Power plant 70 65 60 55 (a) Coal mass flowrate 50 3 4 5 6 7 (b) Power plant net efficiency 8 9 10 400 38 37 36 35 Power plant net 34 33 efficiency 32 3 4 5 6 7 (c) Governor valve stem position 8 9 10 400 1 0.5 0 3 4 5 6 7 (d) LP turbine inlet valve stem position 8 9 10 400 1 0.5 0 3 4 5 6 7 (e) Flue gas mass flowrate 8 9 10 400 750 650 3 4 5 6 7 (f) CO2 volume fraction in flue gas 8 9 10 400 0.138 0.1375 Coal mass flowrate Governor valve stem position LP turbine inlet valve stem position Flue gas mass flowrate CO2 vol fraction 0.137 3 4 5 6 7 8 9 10 400 Time (hours) Controller maintains steam to reboiler >3.5bar Steam is saturated here
Lean solvent flowrate (kg/s) Reboiler steam requirement (kg/s) CO2 capture rate (%) Dynamic analysis CO 2 capture plant Volume fraction Level (%) Level (%) Level (%) CO2 product flowrate (kg/s) Specific regeneration requirement (MJ/kg CO2) ic demand (m3/tonne CO2) t Power (MWe) 96 (a) CO2 capture rate 94 92 90 88 86 CO 2 capture rate 84 3 4 5 6 7 8 9 10 400 Time (hours) (a) Absorber sump level 80 70 60 50 40 3 4 5 6 7 8 9 10 400 (b) Stripper sump level 80 1 1 1400 1300 1200 1100 (b) Lean solvent flowrate to absorber 1000 3 4 5 6 7 8 9 10 400 Time (hours) 120 (c) Reboiler steam requirement Solvent flowrate to absorber 70 60 50 (a) CO2 product flowrate 40 160 3 4 5 6 7 8 9 10 400 150 (c) Absorber liquid holudp at 8.5m 0.04 140 0.035 0.03 130 120 110 DS 1.1 DS 1.2 CO2 production rate (kg/s) 0.025 100 3 4 5 6 7 8 9 10 400 0.02 Time (hours) 3 4 5 6 7 8 9 10 400 (b) Specific regeneration requirement 4 (d) Buffer tank level 400 300 100 Steam to reboiler 80 3 4 5 6 7 8 9 10 400 Time (hours) DS 1.1 DS 1.2 200 3.5 100 Solvent buffer tank level (%) 0 3 3 4 5 6 7 8 9 3 4 5 6 7 8 9 10 400 10 400 Time (hours) Time (hours) (c) Solvent specific demand 25 20 15
Mass flowrate (kg/s) Net Efficiency (%) Dynamic analysis Power/CO 2 capture two-way coupling Reboiler steam demand (kg/s) (a) Flue gas mass flowrate Flue gas flowrate 3 4 5 6 7 8 9 10 400 41 (b) Power plant net efficiency vs reboiler steam demand 120 40 39 38 37 Power plant net efficiency vs. reboiler steam demand 36 3 4 5 6 7 8 9 10 80 Time (hours) 100
Pressure (bara) Pressure (bara) Power requirement (MWe) Power requirement (MWe) Dynamic analysis CO 2 compression plant Surge margin (%) Surge margin (%) Surge margin (%) Surge margin (%) Surge margin (%) Surge margin (%) 8 (a) Electric drive 1 power requirement 7.5 7 3 4 5 6 7 8 9 10 400 5 4.5 4 3.5 38.4 38.3 38.2 38.1 (b) Electric drive 2 power requirement 3 3 4 5 6 7 8 9 10 400 (c) Dehydrator inlet pressure 38 3 4 5 6 7 8 9 10 400 100 99 98 97 (d) Compressor discharge pressure 96 3 4 5 6 7 8 9 10 400 Time (hours) DS 1.1 DS 1.2 Drive #1 power Drive #2 power Dehydrator inlet pressure Compressor discharge pressure Compressor surge control 50 40 30 20 10 (a) Compressor section 1 surge margin 0 3 4 5 6 7 8 9 10 400 (b) Compressor section 2 surge margin 50 40 30 20 10 0 3 4 5 6 7 8 9 10 400 (c) Compressor section 3 surge margin 50 40 30 20 10 0 3 4 5 6 7 8 9 10 400 (d) Compressor section 4 surge margin 50 40 30 20 10 0 3 4 5 6 7 8 9 10 400 (e) Compressor section 5 surge margin 50 40 30 20 10 0 3 4 5 6 7 8 9 10 400 (f) Compressor section 6 surge margin 50 40 30 20 10 Surge margins Drive #1, Section #1 Drive #1, Section #2 Drive #1, Section #3 Drive #2, Section #1 Drive #2, Section #2 Drive #2, Section #3 0 3 4 5 6 7 8 9 10 400 Time (hours)
Mass flowrate (kg/s) Dynamic analysis CO 2 transmission pipelines Buffer potential for flexible operation 160 150 140 130 120 110 Pipeline inlet At landfall valve At 100km Pipeline outlet 100 5 10 15 20 25 30 35 40 45 50 Time (hours)
Dynamic analysis CO 2 injection & storage Mass flowrate (kg/s) Load returned after 1 hour 150 140 130 120 110 Mass flowrate of injected CO2 100 0 5 10 15 20 25 400 30 Time (hours) DS 1.1 DS 1.2 Load maintained at 75% MCR
Case Study: Shell Flexibility
Operability studies of capture plant Source: Shell
Case Study: Industrial CCS Techno-economics
Industrial CCS Techno-economics Source: Carbon Capture Journal
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