Download a case-study of the greek power system

A SPATIAL MULTI-PERIOD LONG-TERM ENERGY
PLANNING MODEL: A CASE-STUDY OF THE GREEK POWER
SYSTEM
Nikolaos E. Koltsaklis,a Athanasios S. Dagoumas,b,c Georgios M. Kopanos,d
Efstratios N. Pistikopoulos,d Michael C. Georgiadis,a1
a
Aristotle University of Thessaloniki, Department of Chemical Engineering, 54124
Thessaloniki, Greece
b
Electricity Market Operator S.A., 185 45 Piraeus, Greece
c
University of Piraeus, Department of International and European Studies, 185 34 Piraeus,
Greece
d
Imperial College London, Department of Chemical Engineering, Centre for Process Systems
Engineering, SW7 2AZ London, UK
LONG ABSTRACT
The long-term Generation (or capacity) Expansion Planning (GEP) problem is defined
as the determination of the optimal type of energy technologies, the capacity expansion,
location and time construction of new power generation plants while minimizing total
cost over a long planning horizon. The projected electricity demand as well as any
economic, technical and environmental constraints must be satisfied. The optimization
of the GEP problem is a very crucial and challenging task that should consider multiple
aspects and decision criteria. There are various available supply technologies that can
be deployed to meet the electricity demand. These supply options can be identified
based on several factors, including operational technical characteristics, environmental
impact, variations on the fuel prices, and construction lead times and life-times of the
power plants.
This work presents a new spatial mixed-integer linear programming (MILP) framework
for the centralized GEP problem. The optimal structure of the power system over the
planning horizon of interest is also identified. To the best of our knowledge, there is no
previous work in the literature that addresses simultaneously: (i) the area discretization
in zones, taking into account the spatial nature of the power system, thus allowing
electricity transmission as well as energy resource transportation between the zones,
and (ii) the integrated energy resources management (import, availability,
transportation, storage) with electricity production and power capacity additions,
representing in a more analytical and comprehensive way the structure of the power
sector.
1
Corresponding author. Tel.: +30 2310 994184; fax: +30 2310 996209
E-mail addresses: [email protected] (M. C. Georgiadis)
The key decisions determined by the model, at each time period, include: (i) the power
capacity expansion of each type of power generation technology during each time
period, (ii) the electricity production of each type of power generation technology in
each zone and time interval, (iii) the optimal locations of new power plants, (iv) the
quantity of energy resources used by each power generation technology in each location
(zone), and the quantity of energy resources transported among the zones, and (v) the
electricity flow rates among the zones of the overall (national) power system as well as
the electricity imports from neighbouring regions (countries).
So as to minimize total power system expansion cost (including investment cost for
new technologies, fixed and variable operational and maintenance (O&M) cost for all
technologies, fuel cost, electricity imports and transmission cost, energy resource
storage and transportation cost, and CO2 emission cost) under full electricity demand
satisfaction.
The proposed model has been applied on a case study of the Greek interconnected
power system. In order to capture the spatial nature of the Greek interconnected electric
system, the country is divided into five geographical zones. Each zone is associated
with corresponding electricity demand, energy resources potential and existing installed
capacity. The Greek power system consists of lignite, natural gas, oil, hydro, wind and
solar power plants, having a total installed capacity of 15408.2 MW. The installed
capacity of lignite-fired power plants is equal to 4928 MW, accounting for 32% of the
total installed capacity, while that of natural gas units’ amounts to 4556.4 MW,
constituting 30% of the total and being the second largest power generation technology,
in terms of power capacity. Hydro units play a significant role in the Greek power mix
with an existing capacity of 3017 MW, making up 20% of the total installed capacity.
The remaining part is shared among heavy fuel oil, wind and solar power plants.
Concerning electricity demand, the forecast used in this study has taken into account
the severe economic crisis and the expecting decrease in the future electricity
consumption of the country. Thus, beginning from around 50 TWh in 2012, it is
assumed that the demand decreases by 2.5% annually for the period 2012-2014 as a
consequence of the economic recession. For the period 2015-2021, it is expected a
significant demand growth of 6% per annum. During the latter part of the studied
period, 2022-2030, it is assumed a stabilization of the demand, growing at a medium
annual rate of 1.1% and reaching around 83 TWh in 2030.
The overall pattern of the results indicates a trend shift from fossil fuels with significant
environmental impact, such as lignite and heavy fuel oil, to cleaner fuels, such as natural
gas, as well as to renewable energy resources which have zero carbon footprints. Thus,
while the installed capacity of lignite-fired power plants was 4928 MW at the beginning
of the period and rises to 5428 MW in 2021 due to the planned construction of two
lignite-fired units in zone 2, it results in 3316 MW in 2030 due to the decommissioning
of some old lignite plants. In addition to the planned integration and retirement of lignite
units, the model does not indicate the construction of a new lignite plant in any zone of
the country. The main reasons for this trend are the binding constraints regarding the
CO2 emissions cap, the compulsory renewables (RET) production of at least 40% of the
total electricity production from 2020 onwards, the relatively high carbon prices
adopted in the model, and the relatively low caloric value of the Greek lignite deposits.
Natural gas units benefit from the increased price of CO2 emissions and their total
capacity amounts to 6043.9 MW in 2030, starting from 4556.4 MW in 2012, since the
model suggests the construction of two natural gas combined cycle units with total
capacity of 630.4 MW in 2017. These plants are constructed in zone 3. In addition to
them, two units with firm commissioning plans become part of the system and their
capacity equals 1217 MW. Overall 360 MW of old natural gas plants are withdrawn.
The old heavy fuel oil units are involved with capacity of 730 MW in 2012 and 2013,
and then they are withdrawn from the system. Hydropower units maintain a constant
rate in the power mix reporting a slight increase in their capacity, since from 3017 MW
in 2012 it becomes equal to 3648.7 MW in 2030.
The wide variation in the power mix comes from RET, particularly from wind parks.
The installed capacity of wind turbines starts from 1452.4 MW in 2012, reaches 5452.4
MW in 2020, and results in 8452.4 MW in 2030. Correspondingly, solar plants from
723.7 MW in 2012 become equal to 2123.7 in 2020 and 2723.7 MW in 2030. The
results also indicate a small contribution from geothermal and biomass plants with total
capacity of 60 and 9.1 MW respectively in 2030. The total installed capacity of
renewable energy technologies reaches 14893.8 MW in 2030.
The binding restrictions imposed concerning the maximum allowable CO2 emissions
and the mandatory electricity production rate from RET lead to a variation in the
observed electricity profile per technology. Lignite units account for approximately
51.8% of the total electricity generation in 2012 (26.2 TWh), fall to around 40% in 2020
(24.7 TWh), and shrink to the low 20.9% in 2030 (17.1 TWh). The numbers in absolute
terms may not show the actual percentage reduction, but the whole increase in
electricity demand should be taken into consideration. Natural gas units will play a
balancing role between the fossil fuel dominant and the zero emissions power
generation mix. Thus, from approximately 27% in 2012 (13.7 TWh), they make up
approximately 38.1% in 2030 with electricity production of 31.3 TWh. In terms of
electricity production, they surpass the lignite plants from 2024 onwards and comprise
the power technology with the largest share in the satisfaction of the electricity demand.
From 2012 onwards, the availability and capacity factor of natural gas plants are
characterized by a sharp increase, while those of lignite plants remain quite stable with
small fluctuations during the whole period. Regarding RET, hydroelectric units
maintain a constant rate of approximately 11.5% in 2020 to result in 8.6% in 2030.
Wind parks report the largest increase, because from 7.5% in 2012 (3.8 TWh), they
constitute around 23% in 2020 (14.2 TWh) and 26.8% in 2030 (22 TWh), representing
the second largest power generation contributor in the system. They have exceeded the
lignite-fired electricity production since 2025. Finally, solar plants more than double
their share in electricity generation, from 2.2% in 2012 (1.1 TWh) to around 5% in 2030
(4.1 TWh). Their rate remains relatively low because this power technology is
characterized by low availability. The remainder, less than 1% during the whole period,
is distributed among the new geothermal and biomass units, while 3.4% of the total
electricity demand on average is met by electricity imports.
In general, the results indicate that the Greek power system is in a transition period
from the dominant lignite-fired power generation to a low-carbon power generation
profile wherein RET such as wind turbines, solar plants and hydropower plants play an
increasing role. Natural gas comprises the fuel that will bridge the gap between the
current carbon intensive energy economy and the low-carbon economy. The CO2
emission price, within the specified limits, does not change the general picture of the
power production breakdown as the fuel cost comprises the main component of the total
cost of the power system. The difference among the fuel cost of lignite and natural gas
units is considerable while the influence of CO2 emissions price is minor. The carbon
pricing would be significant, only if a regulatory price floor was set. This could send a
price signal in the relevant emission markets and would enhance the evolution of low
carbon technologies. But again, in case of Greece the low price of domestic lignite
requires a carbon price at the level of 50 € per tonne CO2, or a political decision of
stopping construction lignite units. Natural gas price and wind power capital cost play
also a key role in the power capacity mix and subsequently to the total electricity
generation profile. Small increases in electricity demand are mainly met by additional
biomass installed capacity and production.
PUBLICATIONS
Koltsaklis N.E., A.S. Dagoumas, G.M. Kopanos, E.N. Pistikopoulos and M.C.
Georgiadis, 2014, “A Spatial Multi-period Long-term Energy Planning Model”,
Applied Energy, Vol. 115, pp.456-482
Koltsaklis N.E., Dagoumas A.S., Kopanos G.M., Pistikopoulos E.N., Georgiadis M.C.,
2013, A mathematical programming approach to the optimal long-term national energy
planning, Chemical Engineering Transactions, Vol. 35, 625-630 (Keynote Lecture at
16th Conference Process Integration, Modeling and Optimization for Energy Saving and
Pollution Reduction (PRES’ 2013), Rhodes, Greece, 29 September-2 October 2013)
Koltsaklis N.E., Dagoumas A.S., Kopanos G.M., Pistikopoulos E.N., Georgiadis M.C.,
2013, An MILP model for the optimal long-term energy planning model at a national
level: A Case Study of the Greek Power System. 9th Panhellenic Scientific Chemical
Engineering Congress, Athens (in Greek)