Chapter 1
Fundamentals

1.1 Introduction

Commercial supply of electric power began in the late 1880s through electrification of the Wall Street area in New York City using direct current (DC) technology pioneered by Thomas Alva Edison. It was driven by the availability of DC generators and incandescent bulbs working with DC. Use of DC was the only option for electric supply until Nicola Tesla advocated for the use of alternating current (AC) form. Amidst fierce competition and lobbying for both DC and AC options, historically known as war of currents [1], AC started to win primarily due to more efficient power transmission enabled by use of transformers to step up or down voltage levels to reduce the power losses. As the need for long distance power transmission grew, the efficiency became a predominant consideration, which worked in favor of AC. For the first half of the twentieth century, AC transmission enjoyed unrivaled popularity and growth while DC was virtually ruled out for electric power transmission.

During the early 1950s, there was renewed interest in the use of DC technology primarily driven by the need for long distance cable transmission. It was realized that the power capacity of an AC cable reduces drastically due to excessive charging current even for moderate distances and voltage levels necessitating the use of DC cables where no such limitation exists. This led to the first DC cable link between mainland Sweden and Gotland island in 1953. Although DC reappeared in the scene in the context of cable transmission, it was soon realized that DC could be a cost-effective option even for overhead line transmission if the transmission distance is very high (beyond 1000 km) where AC transmission capacity is increasingly limited due to stability considerations.

Electric power generation and consumption continued to use AC, which meant converters were required at both ends to convert AC-to-DC and then DC-to-AC. At the beginning, these converters were based on mercury arc valves until the semiconductor switching devices like a thyrsitor was commercially available for high power applications. The converter technology evolved over time driving the costs down, which meant overhead DC transmission started to be cost-effective even for relatively small distances of the order of 700–900 km. This triggered a proliferation of long distance overhead DC links either embedded between two points within an AC system or interconnecting two separate AC systems. Alongside overhead DC lines, underground or subsea DC cables were also installed in different parts of the world. Until the late 1990s, high voltage directcurrent (HVDC) converter stations were built with either mercury-arc (before the seventies) or semiconductor switches, which could be turned on in a controllable way but relied on the polarity reversal of AC system voltage for turning off (or commutation). Over the years, the so-called line-commutated converter (LCC)-based HVDC technology got matured. Today, it constitutes the bulk of the installed and planned DC transmission capacity around the world.

It was only after 1997 that semiconductor switches with both controlled turn-on and turn-off capability, like an insulated gate bipolar transistor (IGBT) became commercially available at high power ratings. This enabled the use of voltage-sourced converter (VSC)-based HVDC technology, which offered significant advantages over its LCC counterpart. These include but are not limited to reliable operation with weak AC systems, low cost and footprint of converter stations, use of lighter, and stronger cables that makes VSC particularly attractive for offshore transmission. Despite the obvious potential and promise, the uptake of VSC technology was initially hindered by its limited power ratings (few hundred MWs) compared to LCC (up to 8000 MW). Rapid development in the VSC technology since has resulted in availability of relatively higher ratings (up to 1000 MW is under development now) for VSC-based HVDC links, but it is yet to catch up with the ratings offered by LCC.

Most of the HVDC links in operation today are connected between two points of a single AC system or two separate AC systems. These are commonly known as point-to-point HVDC links. There are only two exceptions around the world where the HVDC system has more than two points of connections to the AC system, which is referred to as multi-terminal direct current (MTDC) systems. Incidentally, both multi-terminal links in operation—Sardinia–Corsica–Italy link and Quebec–New England link—work with power flowing through the DC link from a generation center (e.g., hydro power from James Bay region in the north of Quebec province) to a main load center (e.g., Boston area and parts of New England) with another intermediate load center (e.g., Montreal region) on the way. However, unlike a meshed interconnected AC network, a truly meshed HVDC grid is yet to be realized in practice. For overhead lines, HVDC is cost-effective only at large transmission distances (e.g., above 600 km) at which level meshed interconnections are not economically justifiable. For underground or subsea cable transmission, the distance beyond which DC technology is effective is much shorter. This has resulted in a number of point-to-point interconnections between AC systems separated by sea to allow exchange of cost-effective electricity.

With increased penetration of intermittent renewable energy sources (e.g., wind power), balancing the supply and demand is likely to be a major problem. To ensure reliable operation of the system, there is a growing need for meshed interconnection to effectively share the diverse portfolio of renewable energy resources and thereby increase operational flexibility. For instance, in Europe, the hydropower from Norway and solar power in Spain and Portugal could be utilized when the wind is not blowing in the UK or mainland Europe and viceversa. To enable such sharing of power and also harness remote offshore wind, there is a business case for setting up an European Offshore Supergrid [2, 3, 4, 5]. There are several visions for an offshore grid in Europe, some of which are shown in Fig. 1.1. One aspect in common with all such visions is that several DC links are connected at a single point forming a DC grid.

Figure 1.1 Visions for European Offshore Supergrid [2, 3, 4, 5].

Because of the subsea transmission distances involved, the only viable option is to use DC, which essentially calls for an MTDC or meshed grid. In such a meshed DC grid, the power flow in the DC links would have to reverse frequently depending on the geographical distribution of renewable generation and the electricity price differential at a given point in time. The VSC technology allows such power flow reversals without altering the DC voltage polarity and is therefore the only option for a meshed DC grid. LCC on the other hand relies on reversing voltage polarity to change the power flow direction which is not a problem for a point-to-point link but does not support a meshed grid operation without physical isolation. The situation is different from the two multi-terminal links in operation today where power flow is essentially unidirectional (from generation to load centers). Hence, they work with LCC technology, which was the only available option anyway at the time of installation of these systems.

The business case for meshed MTDC grids based on the VSC technology is getting stronger in Europe and elsewhere in the world. In China, the five-terminal Zhoushan project is expected to be operational in 2015 [6]. Despite tremendous potential, a VSC MTDC grid is yet to be realized in practice. There are several technical barriers that manufacturers, network planners, and operators are trying to resolve to facilitate the deployment of an MTDC grid. Protection and fault-current interruption in VSC MTDC grids are arguably the most challenging research and development problems that the manufacturers and academia are presently engaged in. As VSC MTDC grids are unprecedented with no operational experience, the network operators do not have much understanding of the interaction between an MTDC grid and the host AC systems and the overall stability. Moreover, there is lack of clarity about whether and how an MTDC grid could be operated and controlled to support the host AC systems. The prerequisite to studying the above in a systematic way is to develop a generic modeling and stability analysis framework for VSC MTDC grids that is compatible with those for conventional AC systems. This can then be used to analyze the overall stability of AC-MTDC grids and identify and resolve potential interactions. System support provisions (for instance frequency support) through an MTDC grid are beneficial for the network operation especially, considering the lower inertia of the turbine systems. However, they need to be exercised carefully to avoid adverse interactions leading to potential overall instability.

A comprehensive modeling, analysis, and control design framework aimed at evaluating the impact and potential benefits of DC grids on the surrounding AC network is the subject matter of this monograph. The main body of the monograph begins with an overview of the VSC systems which are the basic building blocks of MTDC grids. A generic modeling framework for MTDC grid is developed enabling easy integration of the MTDC grid model with a multi-machine AC system model for stability studies. One particular concern is how an MTDC grid would react to loss/outage of one or more converter stations and the resulting power imbalance. Sharing the burden of such...