SEQUESTERING CO2 IN HOUSTON-POWERPOINT

SEQUESTERING CO2 IN HOUSTON-POWERPOINT - Sequestering CO2...

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Unformatted text preview: Sequestering CO2 Final Presentation Final Group 8 Lisa Cox Meghan Forester Jacob Hedden Jennifer Scroggin Thomas Smith Tuesday, April 29, 2003 Overview Overview Introduction to Sequestration Introduction Separation Methods Separation Transportation Network Transportation Sequestration Methods Sequestration Mathematical Model Mathematical Results and Recommendations Results What is sequestration? What Storage to reduce atmospheric levels Storage of CO2 Four Methods of Sequestration Four – Geologic – Ocean – Terrestrial – Mineral Motivation Motivation Post-Industrial Revolution Post – CO2 levels steady increase Global Warming/Greenhouse Effect Global – Greenhouse gases (i.e. CO2) Kyoto Protocol Kyoto – Possible ratification by U.S. – Requires 12% reduction in CO2 emissions by 2010 Climate Stewardship Act of 2003 Climate Power plant emissions Power Fossil fuel combustion Fossil – 97% of all CO2 emissions – Power plants are major sites of fossil fuel combustion CO2 emissions in U.S. CO – 2nd highest in Greenhouse Gas emissions per capita in 1998 – Major cities are highest contributors Houston, Texas Houston, Reducing CO2 in Harris County Reducing Large power plants Large Proximity of depleted hydrocarbon Proximity reservoirs, brine aquifers, and the ocean Seven power plants in Harris County Seven – emitted 5.3 million tons of CO2 in 2000 Harris County Power Plants Harris Power Plant Schematic Power Burning of natural Burning gas in air Heat generation to Heat make steam Steam driven Steam turbine for distribution of electrical power Reaction products Reaction emitted to atmosphere Project Objectives Project Governmental Perspective Governmental – Recent legislation to decrease carbon dioxide emissions Determine reasonable emissions Determine reduction requirements – Minimize electricity cost increase Why Separate? Why Flue gas composition Flue ~ 4 wt% CO2 wt% High flow rates High ~ 0.5-57 million tons/year Sequestration pressure Sequestration ~ 1000 psia Methods of Separation Methods Absorption in a packed tower Absorption Adsorption on solids Adsorption Refrigeration Refrigeration Oxygen-enriched fuel firing Oxygen Membrane Separation Membrane Reaction with Calcium Hydroxide Reaction Absorption/Stripping Absorption/Stripping Monoethanolamine solvent Monoethanolamine – High solubility of CO2 in MEA Random packing (polyethylene rings) Random – Increased contact area between flue gas and solvent Separation with heat after absorption Separation – 85% CO2, 15% H20 PFD PFD 98% CO2 1 atm CO2 + H20 1 atm 120 F Clean Flue Gas Exhaust Flue Gas 1 atm 356 F Compressor: 20 psia Scrubber Absorber Isothermal Flash 35 F Regenerator Heat Exchanger 1 Outlet Temp: 90 F H20 Saturated Steam Rich MEA 136 F Heat Exchanger 2 Outlet Temp: 200 F 30% MEA in H20 240 F Heat Exchanger 3 Outlet Temp: 90 F Centrifugal Pump 2000 hp MEA Mixer H20 Economics Economics Commercially available units Commercially – Wittemann Carbon Dioxide Equipment – Includes all components Capital Cost Capital – 250-15,000 kg/hr flue gas – $0.5-$50 million/unit Operating Cost Operating – $0.17/kg flue gas Calcium Hydroxide Calcium Carbonation Carbonation CO2 + Ca (OH ) 2 → CaCO3 + H 2O ∆H R = −179 kJ mol Calcination Calcination 580o C CaCO3 → CaO + CO2 ∆H R = 4.19 kJ Slaking Slaking CaO + H 2 O → Ca (OH ) 2 ∆H R = −63.9 kJ mol mol Assumptions Assumptions High rate of reaction under alkaline High conditions (pH>10) – Addition of NaOH Mass transfer limiting Mass – Diffusion of CO2 in Ca(OH)2 solution Modeling the system Modeling Flanking view Flanking Top view Top Reactor Design Reactor Gas Sparger Gas – Commercially available (Mott Corp) – Even distribution of bubbles – 2 mm diameter bubbles Cross-sectional area Cross – Determined by throughput – Volumetric flow rate estimated by IGL Compressibility factor=0.9989 Compressibility Height Height – Determined by rate of mass transfer P&ID P&ID Flue Gas 1 atm 480 F Heat Exchanger Outlet Flue Gas: 298 K Flue Gas: 0% CO2 Flue Gas 0% CO2 CT CH4 Combustion Chamber Flame Temperature: 834 C Calcium Hydroxide Reactor CC Calcium Hydroxide Reactor AIR Holding Tank for Excess Ca(OH)2 Solution NaOH Flue Gas 0% CO2 H20 S-15 CO2 1 atm 580 C pHC LC pHT LA Calcium Hydroxide Regenerator Calcium Hydroxide Reactor S-14 PC Pressure Vessel 50 psia PT CO2 for Sequestration Economics Economics Capital cost considerations Capital – Heat Exchanger – Reactor – Calcium Hydroxide – Calciner – Gas Sparger Operating Cost Operating – Hot/Cold Utilities C a p ita l C o s t (M illio n $ ) Capital Cost Capital 3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 0.E+00 1.E+06 2.E+06 3.E+06 4.E+06 Capacity (kg/hr) Capital Cost ($)= 331,000+0.454*Capacity (kg/hr) 5.E+06 6.E+06 Operating Cost Operating Energy Balance Energy Q ≈ n∆H Final Operating Cost Final – $0.0047/kg flue gas Oxygen-Enriched Fuel Firing Oxygen Alternative to separation Alternative Air Separation Air Combustion in pure oxygen Combustion Drawbacks Drawbacks – High capital – High operating costs – Retrofit to existing equipment Transportation Network Transportation Required for delivery of CO2 to Required collection point – “Sam Bertron” power plant Compressed at site of separation Compressed Combined and liquefied at collection Combined point – Compressed for sequestration (1300 psia) – Liquefied with cooling Transportation Schematic Transportation Capital Cost Capital – $9.02-$9.35 million – 8,400-131,000 kg/hr Operating Cost Operating – $.83/ton CO2 Transportation Capital Cost Transportation Capital Cost (Million $) 9.3 9.25 9.2 9.15 9.1 9.05 9 0 20000 40000 60000 80000 100000 120000 Flow rate (kg/hr) Capital Cost ($)= 9,000,000+2.67*Capacity (kg/hr) Final Piping Network Final Ocean Sequestration Ocean Ocean capacity Ocean – Largest capacity sequestration method – Est. 1.4×1012 to 2×1016 metric tons Injection Injection – Various depths – Liquid CO2 Overview Overview Formation of clathrate hydrates Formation – Densities change with injection depth – Effects long-term storage potential Injection Depth Clathrate Hydrate Implications Shallow (< 2700 m) Low density CO2 resurfacing Deep (≥ 2700 m) High density Ocean floor pooling Complications Complications Rapid injection decreases pH Rapid – Considerable effect on ocean environment Legal restrictions Legal – CO2 considered an industrial waste Transportation costs Transportation – Economically prohibitive – LPG tankers $650 million $650 – Rigid Pipeline $16 million/km $16 Transportation Costs Transportation Fraction Sequestered Power Requirements Required # Tankers (1Tanker /325MW) Minimum # Tankers Cost (Million $) 0.1 398.5 1.23 2 100 0.2 797 2.45 3 150 0.3 1195.5 3.68 4 200 0.4 1594 4.90 5 250 0.5 1992.5 6.13 7 350 0.6 2391 7.36 8 400 0.7 2789.5 8.58 9 450 0.8 3188 9.81 10 500 0.9 3586.5 11.04 12 600 1 3985 12.26 13 650 Conclusions Conclusions Economics unfavorable Economics Safety issues for ocean ecosystem Safety Legal constraints on waste disposal Legal in ocean Other sequestration options exist Other Geologic Sequestration Geologic Brine Aquifers Largest estimated geologic CO2 Largest sequestration capacity (est. 500 billion tons CO2 globally) globally) Most aquifers are easily accessible from Most CO2 generation sources and many are already utilized for waste disposal Current studies are investigating “sealing” Current layer rock properties and the possibility of brine displacement which could contaminate potable water Brine Aquifers – Process Overview Brine Considerations: Non-hydrocarbon Non producing injection interval Supercritical CO2 Supercritical desired for desired injection “Sealing” boundary “Sealing” layers Source: Engineering & Economic Assessment of Carbon Dioxide Sequestration in Saline Formations Brine Aquifers – Harris County Brine Frio Formation is Frio brine-bearing sandstone – shale sequence 28–35% porosity 28 Anahuac Formation Anahuac provides thick clay wedge seal Est. capacity of Est. 230-390 Billion tons CO2 To EOR Storage Tanks Compressed CO2 sent to pre-existing injection wells located 12 miles from collection point Capital Investment for Brine Aquifers Capital Capital Investment (Million $) 72.5 72.0 71.5 71.0 70.5 70.0 0.E+00 2.E+04 4.E+04 6.E+04 Capacity (kg/hr) Capital Cost ($) = 70,000,000 + 27.75*Capacity (kg/hr) 8.E+04 1.E+05 Geologic Sequestration Geologic EOR 32 Million tons CO2 utilized annually 32 in US Injection technology well developed Injection Current research projects monitoring Current injected CO2 flow patterns to better assess true sequestration capability Profit potential from CO2 sales could Profit help offset separation and transportation costs EOR – Process Overview EOR CO2 injected into CO depleted oil reservoirs Reservoir pressure Reservoir increases Crude oil viscosity Crude decreases As a result, As recovery factors increase by ~10% Crude Oil CO2 Source: http://www.netl.doe.gov/publications/proceedings/ 01/carbon_seq/2a4.pdf EOR Option for Harris County EOR Capacity Assessment 51 oil wells 51 Average well Average conditions: 40 acres surface area 37 feet pay height 3,100 feet depth 115 °F & 1364 psi API gravity 29° Assumptions: Assumptions: 15% porosity 45% water saturation Concentration of Oil Wells in Harris County EOR Option for Harris County EOR Estimated Oil in Place: Estimated 48 Million bbls originally 34 Million bbls currently remaining 29 Million bbls ultimately unrecoverable CO2 solubility at reservoir conditions: CO 780 scf/bbl in crude oil 160 scf/bbl in water Sequestration Capacity: Sequestration 1.7 Million tons CO2 soluble in unrecoverable crude oil & formation water EOR EOR Specifications & Parameters Additional Fixed Additional Capital Investment of $300,000 Selling Price of CO2 Selling $35/ton Sent to EOR Storage Tanks To Brine Aquifers Planning Model Planning Linear Model Linear General Algebraic Modeling System General (GAMS) Interface Uses CPLEX to solve linear model Uses – Material Balances – Cost Equations – Emissions Trading – Enhanced Oil Recovery Flow Sheet for Model Flow Ei = Y ⋅ Vi + 0.001 ⋅ Ai ∑E Vent to atmosphere Plants: Separation Methods: Qi = Ai + Bi + Vi i ≤X i 1 A Material Balance 2 B A 3 B A Di Di = h ⋅ Ai 4 B A 5 B A 6 B A 7 B A B Fi Fi = l ⋅ Bi Collection Point: CE = ∑ (D j j + Fj) Collection Point W’EOR’ Sequestration Methods: Enhanced Oil Recovery ‘EOR’ W’Aquifers’ Brine Aquifers ‘Aquifers’ CE = ∑ W j j Cost Equations Cost Equipment Costs Equipment Operating Costs Operating Transportation Costs Transportation Total Capital Investment Total Profit from selling CO2 Profit Profit from emissions trading Profit Total Annualized Cost Total Equipment Costs Equipment Each separation and sequestration Each method has a binary variable – 1 if used – 0 if not used Equipment costs are assumed to be Equipment linear with capacity Equipment Binary Fixed Cost = Variable × Cost + [Capacity]× [Variable Cost ] Operating Costs Operating Includes Includes – Utility cost – Raw materials Operating Flow Operating Cost = Rate × Slope Units of operating cost slope are Units $/(kg/hr) Transportation Costs Transportation Similar to operating cost Similar Depends on the distance to transport Depends Transportation CO 2 Site Transportation = Flow Rate × Distance × Slope Cost Transportation cost slope Transportation – $/((Kg/hr) mile) Profit from Selling CO2 Profit Sell for EOR Sell Profit = Flow rate to EOR (Price of Profit CO2) Can only sell a certain amount for Can this purpose W'EOR ', t ≤ 17,400 kg/hr Emissions Trading Emissions 2 Categories of Emissions Trading Categories (ET) – Internal : Among 7 power plants in Harris County – External : If Harris County plants exceed required emissions reductions, excess units of reduction can be sold for profit Emissions Trading Emissions Incentive to capture and sequester Incentive more CO2 Helps to offset costs to electricity Helps consumers Terminology Terminology – Emissions Reduction Credit (ERC) – 1 ERC is 1 ton of CO2 sequestered beyond required reduction Emissions Trading Emissions No official government CO2 ET No program Pricing Estimates Pricing – Wharton Econometric Forecasting Associates – $54/ERC – Will vary over time with same trend as electricity prices Emissions Trading Emissions Voluntary Programs Voluntary – Chicago Climate Exchange Equation for model Equation – ET within network in Harris county generates no profit – Externally, profit can be generated – Profit = Price per ERC (Number of ERCs) Total Annualized Cost Total – Translation to electricity price increase Divide by the total capacity of all of the Divide plants in the network Result: $/kWh needed for the sequestration Result: to pay for itself – Objective of mathematical model: minimize cost increase to electricity consumers Model Results - Summary Model 15% Reduction over 10 years (1.5% 15% per year) Calcium Hydroxide separation in all Calcium cases Depending % emissions reduction, Depending different plants will separate and sequester CO2 Use Brine Aquifers to sequester Use Model Results – Electricity Cost Model Scenarios 0.074 0.072 Cost ($/kWh) 0.07 0.068 0.066 0.064 0.062 0.06 0 2 4 6 8 10 Year 0% Reduction 15% Reduction 35% Reduction 50% Reduction 12 Model Results – Emissions Model Reductions (Total Annualized Cost) Total Annualized Cost (Millions $/yr) 350 300 250 200 150 100 50 0 0 2 4 6 8 10 year 15% Reduction 35% Reduction 50% Reduction 12 Model Results – Electricity Price Model due to changing Ca(OH)2 Cost Electricity Price ($/kWh) 0.07 0.068 0.066 0.064 Base Estimate 0.062 0.06 0 2 4 6 8 10 12 year -30% Error -20% Error -10% Error 10% Error 20% Error 30% Error Model Results – Total Annualized Model Cost for changing Ca(OH)2 Cost Total Annualized Cost (Millions $/yr) 160 140 120 100 80 60 40 20 0 0 2 4 6 8 10 year -30% Error 10% Error -20% Error 20% Error -10% Error 30% Error Base Estimate 12 Model Results – Electricity Price for Model Transportation Cost Variation 0.07 Electricity Price ($/kW h) 0.068 0.066 0.064 Base Estimate 0.062 0.06 0 2 4 6 8 10 year -30% Error -10% Error 10% Error 30% Error 12 Model Results – Total Annualized Model Cost for Transportation Variation 6 Total Annualized Cost ($x10 /yr) 140 120 100 80 60 40 20 0 0 2 4 6 8 10 year -30% Error 10% Error -10% Error 30% Error Base Estimate 12 Model Results – Aquifers Model Electricity Price Sensitivity N e w E le c tric ity P ric e ($ /k W h ) 0.07 0.068 0.066 0.064 Base Estimate 0.062 0.06 0 2 4 6 8 10 Year of Project -30% Error -20% Error -10% Error 10% Error 20% Error 30% Error 12 Total Annualized Cost (M illions $/yr) Model Results – Aquifers Total Model Annualized Cost Sensitivity 140 120 100 80 60 40 20 0 0 2 4 6 8 10 Year of Project -30% Error 20% Error -20% Error 30% Error -10% Error Base Estimate 10% Error 12 Price of Electricity ($/kW h) Model Results – Price Sensitivity Model for ERC 0.07 0.068 0.066 0.064 Base Estimate 0.062 0.06 0 2 4 6 8 10 Year -30% -20% -10% 10% 20% 30% 12 T o ta l A n n u a liz e d C o s t (M illio n s o f $ /y r) Model Results – Price Sensitivity Model for ERC 140 120 100 80 60 40 20 0 0 2 4 6 8 10 Year -30% Error 20% Error -20% Error 30% Error -10% Error Base Estimate 10% Error Model Results Model Price Sensitivity of CO2 Price – In order to use EOR some capital investment is required – Current price of CO2 $35/ton ($0.039/kg) – EOR is not a viable option in the 30% deviation range for the price of CO2 – In order for EOR to be used, the price of CO2 would have to be $370/ton ($0.41/kg) This is extremely unlikely This Demonstrated by Stochastic Model Demonstrated Risk Analysis Risk Incorporate risk into mathematical Incorporate model Variables with the greatest amount Variables of risk – Price of Electricity Forecasting by Energy Information Forecasting Administration – Price of CO2 – Price of ERC – Price of CO2 and ERC will vary with same trend as electricity cost -2 Cost ($x10 / kWh) Forecasting of Electricity Prices Forecasting 7.4 7.2 7 6.8 6.6 6.4 6.2 1995 2005 2015 2025 Year Source: Energy Information Administration http://www.eia.doe.gov/oiaf/aeo/aeotab_1.htm Cost ($/ton) Forecasting of CO2 Prices Forecasting 38 36 34 32 30 28 26 24 22 20 0 2 4 6 Year of Project 8 10 Forecasting of ERC Prices Forecasting P r ic e o f E R C ($ ) 60 55 50 45 40 35 30 0 2 4 6 Year of Project 8 10 12 Conversion to Stochastic Model Conversion Obtain average values for each year Obtain for risky variables Obtain standard deviation for each Obtain year Add scenarios to the model Add – Assume normal distribution with 30 scenarios – Generate values for variables within model Conversion to Stochastic Model Conversion Change objective function Change – Minimize expected cost increase of electricity – Expected Value: E ( x ) = Pr{x}⋅ x The stochastic model will tell us The “Here and Now” decisions – What should we install now to have the best result for all of the possible scenarios Results of Stochastic Model Results – Price Histogram 0.3 Probability 0.25 0.2 0.15 0.1 0.05 0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.024 0.026 Electricity Price Increase ($/kWh) R is k Risk Curve Risk 1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 0 0.005 0.01 0.015 0.02 Price Increase of Electricity ($/kWh) 0.025 0.03 Recommendations Recommendations Stochastic model doesn’t warrant Stochastic any major changes over deterministic model – 15% Reduction over 10 years – Calcium Hydroxide separation in all cases – Depending % emissions reduction, different plants will separate and sequester CO2 – Use Brine Aquifers to sequester Recommendations Recommendations Stochastic model recommends different Stochastic capacities than deterministic model Year 1 2 3 4 5 6 7 8 9 10 Plant where Ca(OH)2 System Installed Deterministic Model Stochastic Model Sam Bertron and Sam Bertron Deepwater Greens Bayou, Hiram Webster Clarke, and Webster Increase Capacity of Sam Increase Capacity of Bertron and add Hiram Greens Bayou Clarke Increase Capacity of Sam Increase Capacity of Bertron Greens Bayou TH Wharton No additions necessary Increase Capacity of No additions necessary Greens Bayou No additions necessary No additions necessary Greens Bayou No additions necessary Increase Capacity of Sam Deepwater Bertron Increase Capacity of Sam No additions necessary Bertron ...
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