| dc.description.abstract | In the last years the share of distributed generation connected into distribution grids
has increased considerably. As their number increases, distribution and transmission network
operators are becoming aware on the risks DG can represent on the stable operation of
national power systems.
To cope with this, the grid code requirements are becoming more and more
demanding in order to ensure the secure and reliable supply of energy to the end users. Early
grid code requirements were asking Distributed Generation units to disconnect from the grid
when disturbances occurred. This was sufficient because the DG penetration was not so high.
Nowadays, when most of the European power systems must handle a large share of DG units,
more complex and stringent requirements must be fulfilled by the DG units. By reviewing
different grid codes this thesis, shows that the technical connection guidelines are varying
from country to country. Moreover as the grid connection of DG units with power electronics
interface become more widespread, new requirements have found their place in these grid
codes. Some of the new capabilities which non−synchronous DG units have to handle during
fault occurrence in the grid are: fault ride−through capabilities, reactive current injection or
absorption, power oscillations damping and synthetic inertia. In Europe and North America, a
regulatory harmonization approach is seen by the introduction of standards and grid codes for
large interconnected power systems, for example the ENTSO−E grid code and the IEEE 1547
standard. In Norway investments in small scale hydro units and wind turbines are numerous
and expected to increase also as a result of incentives as the green certificates market.
Approximatively 98.5 % of the electricity production originates from large hydro power
plants. But there is also a large potential for small scale hydro generation. As the distribution
grids in the regions where all this potential lies, are in general an ageing infrastructure, the
DSOs are concerned about the technical issues they will have to handle to integrate all DG
units.
The focus of this PhD work is to investigate the technical grid code requirements
related to the integration of small scale hydro generators in the future Norwegian active
distribution grids.
To narrow the research of this work, two main research topics were chosen.
I. The first was to investigate the Low Voltage−Fault Ride Through requirement and to
identify potential shortcomings of it. Two specific topics were studied:
1. The adequacy of the external power systems modelling for assessing the LV−FRT
capabilities of DG units
2. The impact of voltage phase angle variation on the LV−FRT capabilities of DG
units
II. The second research topic deals with the development of reduced order models of
Active Distribution grids (ADG). The aim is to develop practical methods for
establishing model equivalents of ADGs that can be applied by TSOs, when
performing systems studies. Also here two specific research areas were chosen: 1. The development of dynamic equivalents of ADGs for rotor angle transient
stability analysis
2. The development of dynamic equivalents of ADGs for rotor angle small signal
stability analysis
Within these research areas the PhD work contributes with understanding on how the
dynamic equivalents for transient stability can be obtained for a test ADG. Moreover, it was
studied how the characteristics of a disturbances impact the identification of coherent
generators. For the case of small signal dynamic equivalents the work contributes to the slow
coherency theory, related to the identification of slow coherent groups of generators when the
modelling of synchronous generators are increased and when the excitation system is
included.
This research shows that for ADGs with large penetration of small scale hydro units,
the oscillation modes similar with the inter−area modes as for TPSs are the inter−machines
modes within ADGs. This is because of a good damping of these low frequency oscillation
modes. The thesis shows that for ADGs coherency among the DG units some show up within
different local plant modes. Linear analysis with simple models for generators fails to identify
correctly the groups of coherent DGs as the groups which can be recognized by running a
time domain analysis.
A method is proposed which uses time domain decomposition of the state variables
within inter−machines modes to determine the coherent groups. Having this method available,
the computation of phase and magnitude from the time response for a certain oscillation mode
can be done easily. For an ADG the complex Euclidean Distance can be then used to cluster
the units in coherent groups. The proposed method is later used to obtain the parameters of
equivalent groups of coherent generators. In the last part of this work this method is combined
with a model parameter identification algorithm to determine the parameter of aggregated
generators.
The thesis can be summarised as in the following:
1. First, an overview of different national grid codes for DG integration is presented and
some topics which were not covered in the LV−FRT requirement were identified and
investigated. These topics are the inadequacy of external power system modeling and
the absence of voltage phase angle variation. The study of these two research topics
(the inadequacy of external power system modeling and the absence of voltage phase
angle variation) are representing the main contributions of this PhD research to the
LV−FRT requirement.
2. In the second part of the thesis practical methods for establishing model equivalents of
ADGs were developed for the purpose of TPS studies. Dynamic equivalents for
transient and small signal stability were considered.
2.1 When computing the dynamic equivalents for transient stability it was observed
that they are dependent of the characteristics of a disturbance (e.g. location, duration and type. Although these equivalents are disturbance dependent, they
provide a good basis for estimation of the Critical Clearing Time (CCT) as well as
of the transient stability limits with respect to the original model.
2.2 For the case of dynamic equivalents for small signal stability, the classical method
of slow coherency was studied. Further it was shown how the level of modeling
accuracy of the synchronous generator and of the excitation system impacts the
identification of slow coherent generators. It was shown that the use of linear
analysis for simple models of synchronous generators fails to identify correctly
the groups of coherent DGs as seen by running a small disturbance time domain
analysis. To cope with this problem, a method is proposed which uses the time
domain decomposition of state variables to determine the coherent groups and to
obtain the parameters of equivalent generators. | nb_NO |
