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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
PostIndustrial 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
~ 0.557 million tons/year Sequestration pressure
Sequestration
~ 1000 psia Methods of Separation
Methods
Absorption in a packed tower
Absorption
Adsorption on solids
Adsorption
Refrigeration
Refrigeration Oxygenenriched 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
– 25015,000 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 Crosssectional 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 S15 CO2
1 atm
580 C pHC
LC
pHT
LA Calcium Hydroxide
Regenerator Calcium Hydroxide
Reactor S14 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 OxygenEnriched 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
– 8,400131,000 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 longterm 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:
Nonhydrocarbon
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
brinebearing
sandstone – shale
sequence
28–35% porosity
28
Anahuac Formation
Anahuac
provides thick clay
wedge seal
Est. capacity of
Est.
230390 Billion
tons CO2 To EOR
Storage Tanks Compressed CO2 sent to
preexisting 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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 Chemical Engineering

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