IEEE Power & Energy Magazine - November/December 2021 - 91

will be increasingly challenged in the future. In Brazil, all
hydro plants built since 2000 are run-of-river. For the past
seven years, inflows have been consistently 20% below the
long-term average. Increasing social-environmental constraints
are limiting flexibility provision. About 75% of
Brazil's energy load is met by zero-marginal-cost generation
and inflexible thermal plants (from operating constraints
and take-or-pay gas contracts).
The search for flexibility from supply, demand, and transmission
resources and the cost-efficient coordination of multiple
conflicting water uses will be fundamental to allow the
integration of VRE with minimum curtailment. However,
more advanced market designs and a regulatory framework
that can appropriately reward flexibility providers are
needed to unlock such a future.
Germany still has significant transmission constraints
because grid upgrades are far behind schedule. This leads
to significant redispatch and curtailment costs. While the
redispatch costs decreased in the first three quarters of
2020 (to €227 million), the curtailment of renewable power
plants in the same period increased to 4,800 GWh, which
caused compensation payments of around €580 million. It is
expected that the ongoing transmission upgrades will reduce
curtailment in the future.
Denmark has coped with high shares of wind energy
with minimal curtailment so far, but in 2020, wind was
downregulated by 1.46 TWh, or 9% of the potential wind
production, in the Energinet area. Only 2% of this was curtailed
due to congestion in the Danish grid: 92% was due to
" special downregulation " caused by congestion in the German
grid and a cross-border agreement, and 6% was downregulated
by owners during negative spot prices as normal
market behavior. Curtailment and negative spot prices have
been rather stable over recent years, while the special downregulation
has constantly increased.
In ERCOT, wind curtailment is increasing due to an
increasing number of stability constraints. Real-time transient
stability assessment tools that are currently being
implemented may help to manage constraints more efficiently.
Frequently updated forecasts, 5-min real-time dispatch,
the flexibility of the existing thermal generation fleet,
and existing ancillary services are helping ERCOT address
its current flexibility needs.
However, growing solar capacity brings challenges. The
highest net load ramp rates in 2030 could be three or four
times higher than those in 2019. These ramps are projected
to occur in the morning and evening, corresponding to the
diurnal patterns of both solar generation and aggregate customer
demand.
Congestion on the Transmission System
Transmission expansion is a key enabler for VRE
growth. It delivers resources to loads, provides diversity
of loads and resources, and increases economic
system operations.
november/december 2021
ERCOT is evaluating the reliability and economic benefits
of transmission reinforcements and other solutions
that would increase existing transmission capabilities to
their thermal ratings. In 2018, the transmission limit on the
Panhandle Generic Transmission Constraint (GTC) was
increased by adding two new synchronous condensers to
improve system strength and voltage support in the Texas
Panhandle area. The current study is looking at economic
transmission improvements for the West Texas GTC, a constraint
on the transmission corridor between West Texas and
the rest of the grid.
In Japan, transmission and distribution lines are congested
with variable power flows from remote renewable generation
plants, often located in areas with inexpensive land. A cost-
benefit analysis of network expansion by the transmission
system operator shows positive benefits. A good example is
the expansion of the Tohoku 500-kV network in the northern
part of the main island of Japan to deploy more than 4 GW
of renewable resources.
The Organization for Cross-regional Coordination of
Transmission Operators is studying transmission expansion
in Japan to accommodate increases in renewable energy generation,
including significant offshore wind. Previously, the
amount of transmission (operating line) capacity allocated to
support new generation was estimated in a simple but conservative
way.
New generation was not allowed to connect if the sum
of the maximum possible output of existing generators and
capacity for emergencies was already at the maximum transmission
line capacity (Figure 6). Recently, a revised connectand-manage
process has been implemented to make better use
of existing line capacity to accommodate new generation without
transmission expansion.
In step 1 of this new process, the sum of the allowed generation
capacity is evaluated probabilistically, reflecting
actual variation in generation. The maximum allowed capacity
is set to the maximum expected generation from simultaneously
operating the generators connected.
In step 2, the capacity for emergency use is reduced
with the condition of instantaneous generation tripping
under an N-1 contingency. In step 3, operational measures
are included in cases where the sum of the generation is
exceeding the limits-by redispatch of generation, including
curtailment of VRE, when necessary.
The new connection application began in January 2021
for the two highest-voltage lines (500 and 275 kV). Currently,
applications for 154/66 kV are planned for demonstration
and then the 6.6-kV distribution networks, including
the utilization of demand-side flexibility.
In Europe, the high targets for offshore wind (300 GW
by 2050) lead to a need for new transmission capacity
both offshore and onshore. The European Network of
Transmission System Operators is requested to deliver
offshore development plans for each sea basin by 2023,
based on the offshore generation capacities and locations
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