Exploring the Role for Long-Term Hydrogen Storage in Alberta Electricity Generation Sector under Net-Zero Scenario

1. Exploring the Role of Long-Term Hydrogen
Storage in Alberta Electricity Generation Sector
under Net-Zero Scenario
Summer 2023 semi-annual ETSAP meeting
Green Center, Colorado School of Mines, 924 16th St.,
Golden, Colorado 80401, USA.
16th June, 2023
Precious Afolabia, , Ganesh Doluweeraa, Sean McCoya
aDepartment of Chemical and Petroleum Engineering, University of Calgary, 2500 University Dr.
NW , Calgary, T2N 1N4, Canada
precious.afolabi@ucalgary.ca, dgdoluwe@ucalgary.ca,sean.mccoy@ucalgary.ca

2. Presentation Outline
• Context & Background
• Overview of Alberta, hydrogen plan,
electricity grid mix & system structure
• Methodology & Scenarios
• Alberta TEMOA model
• Hydrogen storage system
• Results
• Energy, Environment, Economic result
implications
• Cogen case vs hydrogen storage
• Key Takeaways & Future work
• Acknowledgements
2

3. Alberta (AB) : One of 10 provinces in Canada
Alberta area – 634,658.27 square kilometres
Stats Canada; https://mapfight.xyz/map/alberta/ 3
“Texas of Canada”; Rocky mountains – Summer, Winter

4. The role hydrogen plays in AB net-zero future from a
system perspective
Research Question:
What is the role of
hydrogen in providing
long term energy
storage for the
electricity sector?
4
https://sencanada.ca/content/sen/committee/441/ENEV/reports/Hydrogen-energy-report_e_Final_WEB.pdf
Possible H2 End Use Application in AB

5. AB electricity grid mix is mostly gas (~60%)
Alberta Energy System Operator (AESO) statistics
• Gas Technologies are Cogeneration
(COGEN), Combined Cycle (NGCC) ,
Open cycle (OCGT)
• COGEN contributes about 36% to AB
total generation mix
• Coal is being phased out by 2030
0
10
20
30
40
50
60
70
80
90
Electricity
Generation
(TWh)
Electricity Generation (TWh) Mix
Combined Cycle Coal
Cogeneration Coal to Gas - Steam Boiler
Solar/Storage Hydro
Net Imports Other
Simple Cycle Solar
Storage Wind
5

6. Natural gas capacity is Tied to Oil Sands Cogeneration
• AB’s oil sand make up 95% of
Canada’s oil reserves
• Heat or steam generated by cogen
in the oil sands is used primarily
for operations such as steam-
assisted gravity drainage (SAGD)
and mining
• Cogen is used for plant and
electrical operations and excess
electricity is sold to the grid
• Cogen is cheap as a result of AB
competitive electricity market
Cogeneration (Cogen) is the simultaneous production of heat and electricity – Canada Energy Regulator, AESO
As oil sands production increases so does
Cogen and it is projected to be about 5352
MW by 2022
Location of Alberta’s Oil Reserves
6

7. Using System perspective we developed a
Scenario-based Analysis with TEMOA
Methodology: Long-
term optimization
model
Mathematical
method : Linear
Programming
Objective function:
minimize total cost of
the energy system
Sectoral scope:
Electricity, heating,
transport, hydrogen
Time resolution:
seasonal and diurnal
Availability- open
source, pyomo/python
package
7
Hunter et al., 2013, Gordon et al, 2020, Groissbock 2021
Tools for Energy Model Optimization and Analysis (TEMOA)

8. Key features of the Alberta TEMOA Model
• Model time Horizion: 2020-2050
• Electricity demand growth rate: ~1%
• Temporal resolution: 96 time slice - 4 seasons x 1
day (24 hours)
• Spatial resolution according to AB planning
region
• Technoeconomic parameters of existing/new tech
& fuel prices
• Transmission flow within 6 region in AB
• Import & Interties
• Reserve margin: 35%
• Capacity credit for non dispatchable
• Long term strorage: Hydrogen
8
Intra- Annual Demand and Supply Representation
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123
1 2 3 4
Solar
output
(kW)
Hours in seasonal days
Calgary Wind and Solar Availability
Average of Solar
Average of Wind
0
20000
40000
60000
80000
100000
120000
140000
160000
1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123 1 3 5 7 9 11131517192123
1 2 3 4
Demand
(MW)
Hours in seasonal days
Calgary Seasonal Days Load (MW)
Source: AESO; MERRA-2; CER, NRCAN

9. Simplified Hydrogen Storage System
9
ELECTRICTY
back to Grid
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2020 2025 2030 2035 2040 2045 2050
Efficiency
(%)
Efficiency of Hydrogen Storage System (%)
ELECTROLYSER Discharging-Turbine
Net Efficiency
We estimate that the Hydrogen Storage System will have a net efficiency of 30-44%
Hydrogen STORAGE
–geological storage
(salt cavern)
TURBINE
ELECTROLYSER
Dharik Sanchan Mallapragada, Emre Gençer, Patrick Insinger, David Keith, and Francis Martin O’Sullivan, 8/19/20; IEA Hydrogen by 2050, IRENA , Keith et all, 2010

10. Cost of Hydrogen Storage System
10
Storage Duration represented in TEMOA
Technology Days hours
1 day 1 24
1 week 7 168
1 month 30 720
3 month 90 2160
6 month 180 4320
1 year 365 8760
0
2000
4000
6000
8000
10000
12000
1.0 10.0 100.0
Xp-Power
Specific
Capital
cost
($/kW)
Xe-Energy Specific Capital cost ($/kWh)
Capital Cost: Energy vs Power
Dharik Sanchan Mallapragada, Emre Gençer, Patrick Insinger, David Keith, and Francis Martin O’Sullivan, 8/19/20; IEA Hydrogen by 2050, IRENA , Keith et all, 2010
We estimate that energy capital cost for a 1 Day storage ~ 72.1 $/kWh whereas 1 year is about 1.2 $/kWh

11. Exploratory scenarios for plausible AB future electricity
system
11
Base Case Scenario
(BASE)
* Based on AB energy system
* Coal Phase out by 2030
* No/Low policy intervention
* Carbon price @ $50/tonne
Alberta Carbon Policy
Scenario (ACP)
* Based on AB energy system
* Coal Phase out by 2030
* Introduced Federal carbon tax
policy
* Carbon price increases from base
case to $170/tonne by 2030
Clean Electricity
Standard Scenario
(CES)
* Based on AB energy system
* Coal Phase out by 2030
* Incorporated Clean electricity
standard policy
* Carbon price increases from base
case to $250/tonne by 2035
We developed 3 exploratory scenarios to understand the possible dynamic of the future AB electricity system

12. Cumulative Electricity Capacity Mix for AB
12
0.0
10.0
20.0
30.0
40.0
50.0
60.0
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Electricity
Capacity
(GW)
Electricity Capacity (GW)
[H2_STO]
[Wind]
[Solar]
[Cogen]
[Gas]
[Gas_CCS]
[Coal]
[Others]
While Gas fired plants leads in Base case, we see that Wind has the highest capacity share in ACP & CES
In all scenarios we see coal phase out and replaced with gas

13. Cumulative Electricity Generation Mix for AB
13
0.0
20.0
40.0
60.0
80.0
100.0
120.0
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Electricity
Generation
(TWh)
Electricity Generation (TWh)
[H2_STO]
[Wind]
[Solar]
[Cogen]
[Gas]
[Gas_CCS]
[Coal]
[Others]
We see fossil power is predominant in Base but is being replaced with wind and solar in ACP & CES
CES has the least gas in the mix and almost zero gas by 2050

14. Environmental vs Economic impact
14
Base: emission level dropped from 32.6 MT in 2020 to 24.8 MT in 2050
ACP: CO2 emission drops 32.6 MT in 2020 to 12.2. MT in 2050
CES: CO2 level dropped from 32.6 MT in 2020 to 11.8 MT in 2050
ACP & CES: Bulk of Emission comes from Cogen!!!
0
5
10
15
20
25
30
35
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
CO
2
Emission
(MTCO
2
)
Carbon Dioxide Emission (MTCO2)
[Cogen]
[Gas_CCS]
[Gas]
[Coal] 67.5
76.7
78.3
0.0 20.0 40.0 60.0 80.0 100.0
BASE
ACP
CES
Cost (BCAD)
Total System Costs (Billion CAD)
Comparing BASE to ACP & CES ~ 9-11 Billion CAD
BASE vs ACP shows 13% cost difference
BASE vs CES ~ 16%
ACP vs CES is about 2%.

15. Impact of Cogen in AB Electricity System
15
100%
COGEN
COGEN
generation runs
fully throughout
the model horizon
0%
COGEN
from 2035
COGEN
generation is
reduced to zero
from 2035
How Cogen impacts the long term energy storage & future AB electricity mix

16. Hydrogen Storage system capacity
16
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Total 0.0 0.1 0.4 0.0 1.9 3.2 0.0 2.4 3.9
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Capacity
(GW)
Hydrogen Storage Capacity (GW) in 0%
Cogen
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Total 0.0 0.1 0.4 0.0 1.2 2.3 0.0 1.5 2.8
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Capacity
(GW)
Hydrogen Storage Capacity (GW) in 100%
Cogen
More Storage capacity in the 0% Cogen from 2035 compared to the case with 100% Cogen

17. AB Electricity generation mix without Cogen
17
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Generation
(TWh)
Electricity Generation (TWh)
[H2_STO]
[Wind]
[Solar]
[Cogen]
[Gas]
[Gas_CCS]
[Coal]
[Others]
Taking out COGEN from 2035, we see more gas in BASE but more RE, Storage, Gas_CCS in ACP &CES

18. Environmental & Economic impact (without Cogen)
18
75.4
87.4
89.0
0.0 20.0 40.0 60.0 80.0 100.0
BASE
ACP
CES
Costs (BCAD)
System Costs (Billion CAD)
Base: emission falls from 32.6 MT in 2020 to 22.6 MT in 2050
ACP: CO2 drops from 32.6 MT in 2020 to 0.6 MT in 2050
CES: CO2 drops from 32.6 MT in 2020 to 0MT in 2050
Comparing BASE to ACP & CES ~ 12-13 BCAD
BASE vs ACP shows 16% cost difference
BASE vs CES ~ 18%
ACP vs CES ~ 2%.
0
5
10
15
20
25
30
35
202020352050202020352050202020352050
BASE ACP CES
CO
2
emission
(MTCO
2
)
Carbon Dioxide Emission (MTCO2)
[Cogen]
[Gas_CCS]
[Gas]
[Coal]

19. Key Takeaways
19
With no/low policy intervention as
shown in BASE, the grid will be
dominated by gas-fired plants,
however with carbon policy we
saw a cleaner grid mix
While hydrogen storage capacity
grows in ACP & CES , we see
that it increases when Cogen was
out of the mix by 2035
The cost implication for
achieving zero emission is
relatively low as shown in the
exploratory scenarios

20. Future work
• Integrate other storage option to see their competitiveness
• Vary wind and solar availability percentiles
• Examine AB future with Technology Innovation and
Emissions Reduction Regulation rather than straight up
carbon tax
• Explore alternative energy future using MGA (Modeling-
to-Generate Alternatives) analysis in TEMOA
to vary objective function
• Incorporate carbon dioxide removal technologies like
BECCS, DAC
20

21. Thank you
for
listening!
• Questions?
21
My Advisors: Dr. S. McCoy & Dr. G. Doluweera
This research was undertaken thanks in part to funding from the
University of Calgary, the Canada First Research Excellence
Fund and Werner Graupe International Fellowship in
Engineering.
Acknowledgement

22. AB Electricity Capacity mix without Cogen
22
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
2020 2035 2050 2020 2035 2050 2020 2035 2050
BASE ACP CES
Capacity
(GW)
Electricity Capacity (GW)
[H2_STO]
[Wind]
[Solar]
[Cogen]
[Gas]
[Gas_CCS]
[Coal]
[Others]
Taking out COGEN from 2035, we see more gas in BASE but more RE, Storage, Gas_CCS in ACP &CES

23. Objective function of TEMOA
23
t, v
Technology,
vintage
d day
IC Investment Cost v vintage
LA
Loan
Amoritization
s season
MLL Model Loan Life p period
GDR
Global Discount
Rate
P Model time period
y Number of years
CAP Capacity of plant
LENp Period Length
MTL
Model Tech
Lifetime
ACT Activity (Energy)
Tools for Energy Model Optimization and Analysis (TEMOA)

24. Technoeconomic Parameters -1 Month (720 hours)
24
0%
20%
40%
60%
80%
100%
2010 2020 2030 2040 2050 2060
Efficiency
(%)
Efficiency of Hydrogen Storage (%)
ELECTROLYSER Discharging-Turbine
Net Efficiency
-
500
1,000
1,500
2,000
2,500
3,000
3,500
2020 2025 2030 2035 2040 2045 2050 2055
Capital
Cost
($kW)
Capital cost of the Hydrogen Storage System
($/kW)
Electrolyzer Geological Storage Discharging Turbine
0
20
40
60
80
100
120
2020 2025 2030 2035 2040 2045 2050 2055
Fixed
Cost
($/kW)
Fixed Cost of the Hydrogen Storage system
($/kW/yr)
Electrolyzer Geological Storage Discharging Turbine

25. Spatiotemporal resolution
• Spatial Representation
• Regional division Based on AESO outlook:
• South Planning Region
• Calgary Planning Region
• Central Planning Region
• Northwest Planning Region
• Northeast Planning Region
• Edmonton Planning Region
• Regional assets
• Load projection
25
Alberta Energy System Operator(AESO) 2021 Long-term Outlook

26. Modelling Regional demand
26
0
200
400
600
800
1000
1200
1400
1600
1800
2000
1
275
549
823
1097
1371
1645
1919
2193
2467
2741
3015
3289
3563
3837
4111
4385
4659
4933
5207
5481
5755
6029
6303
6577
6851
7125
7399
7673
7947
8221
8495
Demand
(MW)
Hours
CALGARY Annual Demand
0
20000
40000
60000
80000
100000
120000
140000
160000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Demand(MW)
hours
Load Profiles in Winter
0
20000
40000
60000
80000
100000
120000
140000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Demand(MW)
hours
Load Profiles in Summer
Intra-annual variation of demand for every region
was modelled based on historical data

27. Technoeconomic Parameters
Technology [Tech_acronym]
Overnight cost
(CAPEX)
Fixed O&M
costs
Variable O&M
cost Efficiency
C$/kW C$/kW/Yr C$/MWh %
2020 2030 2050 2020 2030 2050 2020 2030 2050 2020 2030 2050
Open cycle gas turbine [OCGT] 1344 1344 1344 16 16 16 3 3 3 40% 40% 40%
Combined cycle gas turbine [NGCC] 1284 1284 1284 16 16 16 3 3 3 60% 60% 60%
Combined cycle gas turbine with
Carbon Capture and Storage [NGCC_CCS] 3315 3315 3315 37 37 37 8 8 8 50% 50% 50%
Cogeneration [Cogen] 15 15 15 5 5 5 55% 55% 55%
Coal power plant [Coal] 55 55 55 6 6 6 47% 47% 47%
Coal to gas power plant [Coal2Gas] 16 16 16 3 3 3 47% 47% 47%
Hydrogen fired combined cycle
power plants (H2CC) [Hydrogen] 1841 1841 1841 55 55 55 2.75 2.75 2.75 53% 53% 53%
Hydro Power plants [HYDRO] 3715 3715 3715 56 56 56 2 2 2
Solar Photovoltaic [SOLPV] 1513 823 557 13 13 13
Wind power plants [Wind] 2043 1884 1752 13 13 13
Biomass power plants [Biomass] 170 170 170 7 7 7 75% 75% 75%
Battery Energy Storage [BES] 1744 1118 876 44 28 22 85% 85% 85%
Hydrogen storage [H2_STO] 972 972 972
Water Electrolysis Technology [Electrolyzer] 900 700 4501.5% CAPEX 64% 69% 74%
Steam Methane Reforming Plant
with Carbon Capture and Storage [SMR_CCS] 1680 1360 12803% CAPEX 69% 69% 70%
Electricity Transmission and
Distribution [E_ELCTD] 2000 2000 2000
Fuel costs units 2020 2025 2030 2035 2040 2045 2050
Blue Hydrogen C$GJH2 15.6
Green Hydrogen C$GJH2 56.4
Natural gas C$MMBtu 2 3 3 4 4 4 4
Carbon Tax
BASE scenario C$Tonne 30 50 50 50 50 50 50
ACP Scenario C$Tonne 30 95 170 170 170 170 170
CES Scenario C$Tonne 30 95 170 250 250 250 250
27

28. Dispatch Terminology in TEMOA
Availability factor The maximum
amount of electricity that can be
produced in a given hourly time slice,
relative to nominal capacity. For non-
dispatchable technologies such as
solar and wind power, the availability
factors are determined by resource
availability
Capacity credit:The contribution to
peak demand made by non-
dispatchable technologies.
Technology-specific capacities are
multiplied by a capacity credit in the
reserve margin constraint, where the
capacity credit represents the fraction
of capacity that can be relied on
during peak demand periods
Reserve margin is the extra capacity
available after meeting demand. It is
estimated for regions with several
electric systems or for individual
electric systems. A reserve margin of
35%, for instance, indicates that an
electric system has extra capacity
equal to 35% of anticipated peak
demand.
28
https://arxiv.org/ftp/arxiv/papers/2001/2001.07264.pdf