IEEE Power & Energy Magazine - May/June 2017 - 36

Experience shows that a centralized solution
using coordinated OLTC and DRESs allows for the
highest amounts of hosting capacity.
generation curtailment is allowed under exceptional conditions. In France, for instance, the use of special contracts to
agree on the limits of curtailment has been tested.

A Case in the Field
HC analysis should be executed case by case. Figure 6 is a
good example of typical grid conditions. As is frequently the
case, some feeders are voltage constrained (F01, F03, F04,
and F07) while others are current constrained (F02, F05, F06,
and F08). When SG solutions are applied, the HC is increased.
Some of the feeders become current constrained (F04), but
others become voltage constrained (F01, F02, and F07).
The increase in HC resulting from voltage-control solutions can vary for different feeders. Figure 6 only shows the
VVC solution applied on a primary substation. However,
fix curtailment could produce a 29% HC increase for these
feeders while the use of OPF could lead to up to a 169% HC
increase. These significantly different results are also due to
the different characteristics of the feeders. Using the VVC
solution (Figure 6), feeder F01 presents an HC increase of
1.5 MW in a line that had originally a capacity of 3 MW. On
the other hand, feeder F03 originally presented only 1 MW,
and the HC increase obtained with VVC is just an extra
0.5 MW. For feeder F04, curtailment or nonfirm connection
contracts could be good strategies to limit the total current in
this line. For feeder F01, other voltage-control applications
could be more effective than the selected one.

8
7

HC (MW)
Asls/VVC

6
5
4
3
2

F08

F07

F06

F05

F04

F03

F02

F01

Feeder

figure 6. Feeder screening: the classification of feeders as
voltage constrained (blue) or loading constrained (red) with
the indication of HC and an HC increase for each one of
the feeders of a primary substation.
36

ieee power & energy magazine

Transition to Business as Usual
SG research offers a number of alternative solutions for increasing HC. Solutions have a range of pros and cons in terms of
cost, performance, flexibility, and ease of implementation.
What is needed to replace the current operational methods and
equipment with these new solutions? Which are the drivers of
the transition from R&D proposals to business as usual?

Regulatory Aspects
To allow R&D results to become business as usual, utilities
need regulatory changes, but even more importantly they
need stable and predictable regulatory frameworks. Utilities
require consistent regulatory support for large investments
in grid reinforcements and innovative solutions. Frequent
regulatory changes should be avoided, and when changes
are necessary, they should be implemented with total transparency for stakeholders and with consideration for previous
investments not already recovered.
National policy makers should take into account that
DRES grid connection charges and costs are spread over all
consumers' bills. The repartition of costs, responsibilities, and
functions among the stakeholders should be fair. There are
SG solutions that should become business as usual to foster
DRES integration efficiently. The main regulatory updates
needed are discussed next.
Regulation Should Allow the DSOs to
Control Distributed Energy Resources

Distributed energy resources (DERs) should usually be controlled by the DSO to ensure the quality of service and system reliability without unnecessary grid investments. Given
that DSOs often lack the capacity to control DERs, they are
forced to calculate the worst-case scenario to evaluate the
grid capacity to reliably host new generation sources. Consequently, this leads to conservative limits.
Pilot projects in Eberstalzell and Koestendorf (Austria)
studied how residential photovoltaic (PV) generation impacts
the LV grid and how these sources can contribute to grid stabilization. The largest gains in terms of voltage-band management have been obtained by implementing a coordinated
control, which acts upon a voltage-regulating transformer and
the solar generators to regulate the active or reactive power
injection. This coordinated control is made possible by power
line communications for getting voltage measurements from
smart meters and remotely parameterizing the solar inverter
controls. This change would affect large amounts of small
devices and may require exploring alternative approaches to
may/june 2017

Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - May/June 2017