Characteristics of UHV DC Transmission System

CHAPTER 3

Characteristics of UHV DC Transmission System Chapter Outline 3.1 Basic Principles of HVDC Transmission System 3.1.1 Basics of HVDC Conversion Technology 3.1.2 Six-Pulse Converter 96 3.1.3 Twelve-Pulse Converter 103

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3.2 Characteristics of UHV DC Transmission System

104

3.2.1 System Composition 104 3.2.2 Operation of DC Transmission System 110 3.2.2.1 Wiring configurations 110 3.2.2.2 Direction of power flow 112 3.2.2.3 Operation at rated or reduced voltage 113 3.2.2.4 Active power control 114 3.2.2.5 Balanced and unbalanced bipolar operation 115 3.2.2.6 Reactive power control 116 3.2.3 Characteristics and Applications of UHV DC Transmission 118 3.2.3.1 Advantages and applications 118 3.2.3.2 Limitations and development trends of HVDC transmission technology

3.3 Safety, Stability, and Operation of UHV DC Transmission System 3.3.1 3.3.2 3.3.3 3.3.4

Role of AC Systems in Supporting UHV DC Systems 122 Connection of UHV DC Transmission Systems 123 Stability Evaluation Methods for Interconnected UHV DC
AC System Interaction Between UHV DC System and AC System 130

References

120

122

125

132

3.1 Basic Principles of HVDC Transmission System 3.1.1 Basics of HVDC Conversion Technology The application of DC power transmission entails conversion of alternating current to direct current and vice versa. In particular, to allow electric energy to be transmitted from the power source to the load center, alternating current must first be converted into direct current at the sending end, referred to as rectification; direct current must then be converted

Ultra-high Voltage AC/DC Grids. DOI: http://dx.doi.org/10.1016/B978-0-12-802161-3.00003-2

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© 2015 China Electric Power Press. Published by Elsevier Inc. All rights reserved.

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Chapter 3

Figure 3.1 Schematic diagram of a six-pulse rectifier.

back into alternating current at the receiving end, referred to as inversion. The facility where the rectification occurs at the sending end is called a rectifier station, and the facility where the inversion occurs at the receiving end is called an inverter station. Rectifier stations or inverter stations are collectively known as converter stations. The devices that enable rectification and inversion operation are, respectively, called rectifier and inverter, and are collectively known as converter (converter unit). Currently, converter used for HVDC and UHV DC power transmission generally comprise thyristor-based converter bridges and converter transformers that supply the commutation voltage. Thyristor is a technically proven power electronic device that can withstand high voltage and has high through-current capability. The on and off characteristics of thyristor are the basis for analyzing the thyristor conversion technology. A thyristor is characterized by the following: (i) current can only flow from anode to cathode, although a very small reverse current (reverse leakage current) may occur (unless the thyristor is damaged); (ii) it can be turned on if the anode is at a positive voltage with respect to the cathode, namely, a commutating voltage must be present, and a gate pulse is applied; and (iii) once turned on, it cannot be turned off until the current flowing through it decreases to zero. After the thyristor is turned off, sufficient deionization time when the anode is at a negative voltage with respect to the cathode is necessary; otherwise, even if no gate pulse is applied, the thyristor will be turned on when a positive voltage is imposed at the anode.

3.1.2 Six-Pulse Converter 1. Rectifiers Figure 3.1 shows the schematic diagram of a six-pulse rectifier. Figure 3.2 depicts the relevant voltage and current waveforms of a rectifier during normal operation. The six-pulse rectifier works in such a manner that the six bridge arms (valves) V1 through

Characteristics of UHV DC Transmission System 97

(A)

(B)

(C)

(D)

(E)

Figure 3.2 Voltage and current waveforms of a six-pulse rectifier: (A) waveforms of AC electromotive force and voltages at m and n points on DC side with respect to the neutral point; (B) waveforms of DC voltage and voltage across valve 1; (C) sequence and phase of firing pulses; (D) current waveform of valves; and (E) waveform of current through phase A on AC side.

V6 connected in a three-phase bridge configuration are turned on and off sequentially, thereby converting the alternating current into direct current. The numerals 1 through 6 indicate the sequence in which the valves are turned on. Generally, each valve consists of a number of thyristors connected in series; therefore it has the characteristics of thyristors and can meet the DC voltage design requirement. In Figure 3.1, ea, eb, and ec represent, respectively, equivalent electromotive force of individual phases of an AC system and are generally supplied by the converter transformer; Lr represents the equivalent commutation reactance of each phase and mainly consists of the leakage reactance of the converter transformer; Ld represents the inductance of the smoothing reactor. The equivalent line voltages eac, ebc, eba, eca, ecb, and eab are the commutating

98

Chapter 3 voltages of valves. It is specified that the zero crossing point where the commutating voltage changes from negative to positive is the timing start point of the valve’s firing angle α. Under idealized conditions, the three-phase AC system has a symmetrical configuration; therefore, the firing angles of the six valves are equal and evenly spaced and the firing pulses are spaced by 60 . The area of the positive half of the commutating voltage waveform (α 5 0
180 ) is the region where the valves can conduct in forward direction. The instant when a firing pulse is applied (α angle) is the conduction instant of valves. For rectifiers, when α falls within 0
90 (90 not included), the converter outputs a positive DC voltage. Within one power frequency cycle, a valve from the valve group sharing the common anode (namely, V2, V4, and V6) and another different phase from the valve group sharing the common cathode (namely, V1, V3, and V5) will conduct, allowing the AC current to flow through the rectifier into the DC circuit. In this way, the AC current is converted into a DC current. A description of the commutation process by using an example of commutating the current from V1 to V3 follows. Once V3 is turned on, phases A and B of the converter transformer are short-circuited through V1 and V3; at this moment, the current flowing through V3 is equal to the phase-to-phase short-circuit current that increases from zero, whereas the phase-to-phase short-circuit current through V1 is in the reverse direction to its original current and, consequently, the resulting current through V1 is equal to the difference between the two. When the phase-to-phase short-circuit current through V1 becomes equal to the original current, the resultant current through V1 decreases to zero, causing V1 to turn off. At this time, all DC current will flow through V3 and the commutation process completes. Because of the presence of inductance, the current through the valves that are, respectively, turned on and off cannot be varied instantly. The time taken to commutate the current from one valve to another is called “overlap angle” μ. For a six-pulse rectifier, the mean DC voltage Ud1 may be expressed as: 3 Ud1 5 Udi01 cos α 2 Xr1 Id 5 Udi01 cos α 2 dr1 Id π Udi01 5 1:35U1 3 dr1 5 Xr1 π where Udi01 —ideal no-load DC voltage, kV U1—RMS line voltage on the rectifier side of the converter transformer, kV α—firing angle of rectifier, ( ) Id —DC current, kA Xr1 —equivalent commutation reactance, Ω dr1 —specific commutation voltage drop, that is, the DC voltage drop caused by per-unit DC current during commutation, Ω.

(3.1)

Characteristics of UHV DC Transmission System 99 Equation (3.1) gives the rectifier’s DC voltage as a function of its DC current, also known as the rectifier’s voltage
current characteristic. Overlap angle μ is an important parameter of converters and directly affects their reactive power and harmonic performance. The overlap angle of a rectifier is:   2Xr1 Id 2α (3.2) μ1 5 arc cos cos α 2 pffiffiffi 2U1 It is shown in Eq. (3.2) that, during rectifier operation, μ1 decreases with the increase of α (α , 90 ) but increases with the increase of Xr1. When α and Xr1 are constant, μ1 increases with the increase of Id or the decrease of U1. 2. Inverters Inverters discussed here are active inverters; they need an AC system to supply commutating voltage and current. Figures 3.3 and 3.4, respectively, show the schematic diagram and the voltage and current waveforms of a six-pulse inverter. It is shown in Eq. (3.1) that when α , 90 and the internal voltage drop of a converter is ignored, the DC output voltage is positive and the converter operates in rectifier mode; when α 5 90 , the DC output voltage is zero; when α . 90 (but α , 180 ), the DC output voltage is negative and the converter operates in inverter mode. When a converter operates as an inverter on its own, it is impossible for it to supply a DC current to an external load. However, when combined with a rectifier, the inverter serves as load for the rectifier and can operate as intended, driven by the positive DC voltage output from the rectifier. Like the rectifier, a six-pulse inverter also consists of six valves connected in a three-phase bridge configuration and a converter transformer that serves to supply commutation voltage. Each valve contains a number of thyristors connected in series

Figure 3.3 Schematic diagram of a six-pulse inverter.

100 Chapter 3

(A)

(B)

(C)

(D)

(E)

Figure 3.4 Voltage and current waveforms of a six-pulse inverter: (A) waveforms of AC electromotive force and voltages at m0 and n0 points on DC side with respect to the neutral point; (B) waveforms of DC voltage and voltage across valve 1; (C) sequence and phase of firing pulses; (D) waveform of valve current; and (E) waveform of current through phase A on AC side.

and has the characteristics of thyristors. Six valves, V1 through V6, are in the same sequence as that of a rectifier. Also, the current is commutated from one valve to another through the phase-to-phase short-circuit current with the help of the converter transformer. Within one power frequency cycle, one valve connected to the anode and another connected to the cathode that are of different phase will conduct, allowing the DC current to flow into the three-phase windings of the converter transformer. In this way, the DC current is converted to AC current.

Characteristics of UHV DC Transmission System 101 The mean DC voltage Ud2 across the inverter may be expressed by: Ud2 5 2 ðUdi02 cos γ 2 dr2 Id Þ 5 2 ðUdi02 cos β 1 dr2 Id Þ

(3.3)

Udi02 5 1:35U2 3 Xr2 π β 5 180 2 α 5 γ 1 μ dr2 5

where Udi02 —ideal no-load DC voltage through inverter, kV U2 —RMS line voltage on the inverter side of the converter transformer, kV dr2 —commutating voltage drop of inverter, Ω Xr2 —equivalent commutation reactance of inverter, Ω β—advance angle of inverter, ( ) γ—extinction angle, expressed in ( ), a measure of time interval; in this interval, after the valve is turned off and DC current drops to zero, the valve suffers from negative voltage. The overlap angle of an inverter is:   2Xr2 Id p ffiffi ffi μ2 5 arc cos cos γ 2 2γ (3.4) 2U2 During inverter operation, the overlap angle μ2 is a function of Id, U2, γ, and Xr2. Given γ 5 β 2 μ2 , if β is kept constant or nearly constant, then an increase of μ2 will lead to the decrease of γ. If the extinction angle γ is decreased to the point when the time for the negative voltage is applied across the valve is less than that required for it to recover its blocking capability, the valve would conduct again once a positive voltage is applied. This phenomenon is called commutation failure. Commutation failure will result in periodic short-time short-circuiting across the inverter, causing the DC voltage to decrease instantaneously and the DC current to increase instantaneously. To avoid commutation failure, it is specified that γ should be larger than or equal to γ 0. Generally, γ 0 is taken as 17
18 to allow sufficient time for the valve to recover its blocking capability, with due regard to the asymmetry of the three-phase voltage and parameters of the AC system and other factors such as margin reserved for the response time of discrete control. In the case of a rectifier valve, once it is turned off, it will be in a reverse blocking state for a long time; therefore, no commutation failure would result. By comparing Figures 3.2 and 3.4, it is apparent that during the commutation process, the current waveforms of inverter valve and rectifier valve are different because of different firing instants. The rate of increase in valve current shows an increasing tendency for rectifier valves but a declining tendency for inverter valves.

102 Chapter 3 3. Reactive power There is a phase displacement between AC voltage and current in each phase of the converter. It may be approximated to the power-factor angle ϕ of the converter. Both inverter and rectifier need to absorb reactive power from the AC system during operation; therefore, the converter station should be equipped with reactive compensation devices. The power factor of a rectifier station is: cos ϕ1 

 1 cos α 1 cosðα 1 μ1 Þ 2

(3.5)

The power factor of an inverter station is: cos ϕ2 

 1 cos γ 1 cosðγ 1 μ2 Þ 2

(3.6)

The reactive power absorbed by a rectifier is: sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi   Udi01 2 QC1 5 Pd1 tan ϕ1 5 Pd1 21 Ud1 The reactive power absorbed by an inverter is: sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi   Udi02 2 QC2 5 Pd2 tan ϕ2 5 Pd2 21 Ud2

(3.7)

(3.8)

where Pd1 —active power on the rectifier side, MW, Pd1 5 Ud1 Id Pd2 —active power on the inverter side, MW, Pd2 5 Ud2 Id . It is shown in Eqs. (3.7) and (3.8) that thyristor valves absorb a large amount of reactive power during operation, and the amount of reactive power absorbed by converters is directly proportional to the DC power transmitted. The current flowing from the converter to the AC side is not perfectly sinusoidal; therefore, the waveform of resulting DC voltage is not smooth. Through Fourier analysis of the waveforms, a six-pulse converter will produce characteristic harmonics of orders (6k 6 1) and 6k, respectively, on the AC side and DC side (k is a positive integer). Therefore, it is necessary to provide AC filters of (6k 6 1) orders on the AC side, and DC filters of 6k orders on the DC side. The harmonic and reactive power characteristics of thyristor converters have a direct bearing on the requirements of performance and capacity of the converter transformer. For six-pulse converters, the AC-side current and the parameters of the converter transformer are given here.

Characteristics of UHV DC Transmission System 103 a. The RMS line current on AC side may be approximated to: rffiffiffi 2 Id 5 0:816Id (3.9) Ia  3 The RMS fundamental component of line current on the AC side of a rectifier or inverter may be approximated to: pffiffiffi 6 Ia1  (3.10) Id 5 0:78Id π b. The rated capacity of a three-phase converter transformer may be expressed by: π S 5 Udi0N IdN (3.11) 3 where Udi0N —ideal rated no-load DC voltage, kV IdN —rated DC current, kA.

3.1.3 Twelve-Pulse Converter A 12-pulse converter consists of two six-pulse converters. The DC sides of the two sixphase converters are connected in series and the AC sides are connected in parallel. On the valve side, one converter transformer is star-connected and the other is delta-connected, giving rise to a 30 phase displacement between the commutating voltages of two six-pulse converters. A 12-pulse converter may be operated with two double-winding converter transformers or one three-winding converter transformer. Figure 3.5 shows the schematic diagram of a 12-pulse converter operated with two double-winding converter transformers.

Converter transformer

AC system

V1 A

V5 B

V9 C

V7

V11

V3

V2

V6

V10

A

B C

V8

V12

V4

Figure 3.5 Schematic diagram of a 12-pulse converter.

104 Chapter 3 The 12-pulse converter consists of 12 valves numbered from V1 to V12. Numerals of valves shown in Figure 3.5 correspond to the situation in which the voltage in the star configuration leads that in the delta configuration. Within one power frequency cycle, 12 sequential firing pulses in-step with AC system are required and the pulse interval should be 30 . A 12-pulse converter works in the same way as that of a six-pulse converter. Also, it commutates current from one valve to the next through the phase-to-phase short-circuit current of the AC system. The DC voltage across a 12-pulse converter is twice that across a six-pulse converter. A 12-pulse converter will produce characteristic harmonics of orders 12k 6 1 and 12k, respectively, on the AC side and the DC side. Therefore, apart from the ability to increase the DC voltage, a 12-pulse converter is advantageous in the following ways: a. The DC voltage contains less harmonic components. The DC voltage across the 12-pulse converter is the sum of DC voltage across two six-pulse converters. Within one power frequency cycle, 12 pulses occur and each six-pulse converter produces harmonics of orders 6 and 6(2k 1 1) (e.g., 18, 30, 42,. . .) in the DC voltage, which are part of the harmonics produced by the two six-pulse converters, are 180 out of phase with each other, and thus cancel out. As a result, the DC voltage contains only harmonics of orders 12k; therefore, only filters of orders 12k are required on the DC side. b. The AC voltage contains less harmonic components. For a 12-pulse converter operated with two double-winding converter transformers, the harmonics of orders 6(2k
1) 6 1 (e.g., 5, 7, 17, 19,. . .) in AC current simply circulate on the grid side windings between the two transformers, rather than flowing into the AC system. For a 12-pulse converter operated with one three-winding converter transformer, no harmonic of orders 6 (2k
1) 6 1 would be contained in the transformer’s grid side windings because the harmonics of these orders on the two valve side windings are 180 out of phase and thus cancel each other. Therefore, only filters of orders (12k 6 1) are required. The use of 12-pulse converters can effectively improve the harmonic performance on both the AC and DC sides, simplify the filtering devices, reduce the land occupation, and lower the construction costs of converter stations, which are the main reasons why most HVDC transmission systems adopt 12-pulse converters as the basic converter units.

3.2 Characteristics of UHV DC Transmission System 3.2.1 System Composition The DC transmission systems can be classified into two categories in terms of system composition, namely, the two-terminal and multiterminal system, which is also the case with UHV DC transmission systems.

Characteristics of UHV DC Transmission System 105

1

5

DC transmission line

3

4

6

2

9 8

3 2

6

9

10 7

4

7

1

8

AC system II

AC system I

Converter station 1

Converter station 2

Figure 3.6 Schematic of a bipolar two-terminal system: 1, converter transformer; 2, converter valve; 3, smoothing reactor; 4, AC filter; 5, capacitor bank; 6, DC filter; 7, control and protection system; 8, neutral bus; 9, earth electrode line/earth electrode; 10, telecommunication system.

1. Two-terminal system A two-terminal long-distance DC system generally comprises one rectifier station and one converter station built at different geographical location, a transmission line connecting the two terminals, earth electrodes, and earth electrode lines. Figure 3.6 shows the schematic diagram of a typical bipolar configuration. The HVDC system is a DC system connected between different AC buses and comprises the minimum converter units that can be operated independently. The DC system within converter stations may consist of a number of converters and DC and AC switchyard equipment. A converter mainly comprises converter bridges, control and protection systems, and converter transformers. DC switchyard equipment mainly includes smoothing reactors, DC filters, and various types of DC switchgears. AC switchyard equipment mainly includes the filtering and reactive power compensation devices such as AC filters and capacitor banks. The DC secondary system mainly includes the DC control and protection system and associated communication systems. a. The converter valve is the core component of a DC transmission system to allow AC/DC conversion. Mercury-arc valves were once used in early DC transmission systems. However, they were found to have many disadvantages, such as complicated manufacturing, high costs, high failure rate attributable to arc-back, low reliability, and difficult maintenance, that hinder the application and development of DC transmission. With the rapid development of power electronic and microelectronic technologies, the high-voltage and large-power thyristor becomes a mature technology. Characterized by no arc-back failure, easy manufacturing, easy testing, easy operation, and easy maintenance, thyristors have

106 Chapter 3

b.

c.

d.

e.

f.

significantly improved the operating performance and reliability of DC transmission. Since the 1970s, thyristor valve-based converters have become the mainstream products used for DC transmission and greatly promoted the development of DC technology. The thyristor is a low-frequency semiconductor device with no self-turn-off capability. Such thyristors comprise the linecommutated converter in which the valves are commutated through use of the phase-to-phase short-circuit current on the valve side of the converter transformer. There are two types of thyristors used in DC systems, respectively, the electrically triggered thyristor (ETT) and light-triggered thyristor (LTT). The increasing capacity of the DC system requires the development of thyristor technology with higher voltage and current ratings. The high-capacity 6-inch thyristor first developed by China for UHV DC applications is a leading technology around the world. The converter transformer serves to connect the AC system and the converter bridges by realizing the voltage transformation and electrical isolation between the AC and the DC sides and limiting the short-circuit current. There are four available types of converter transformers, the three-phase three-winding, the three-phase twowinding, the single-phase three-winding, and the single-phase two-winding. In contrast to conventional AC power transformers, the valve side windings are subject to not only the combined load stress of DC and AC voltage but also the stress caused by polarity reversal. In addition, a series of harmonic currents is present in windings on both sides. The smoothing reactors and DC filters function together to smooth the current on the DC side, protect the converter station from the line’s steep-front overvoltage, avoid interruption of DC current, and reduce the probability of commutation failures. The DC and AC filters mainly serve to filter the characteristic harmonics generated on both AC and DC sides as the converter acts as a harmonic current source for the former and as a harmonic voltage source for the latter. The reactive power compensation devices are used to provide the reactive power needed by the converter stations. The thyristor-based converter absorbs a large amount of reactive power during its operation, up to 40
60% of the active power delivered by the DC system. To this end, apart from the use of AC filters to supply reactive power, additional compensation devices are required, such as capacitors, condensers, or static VAR (Volt Ampere Reactive) compensators. The DC control and protection system enables the normal start and stop of the system, change of operating modes, automatic regulation of steady state and dynamic state, troubleshooting, and protection of system and equipment, thus playing an important role in guaranteeing the performance and reliability of the DC system. Because of the development of computer technology, all the control and

Characteristics of UHV DC Transmission System 107 protection equipment today incorporate the advanced high-performance multiplemicrocomputer parallel processing technology, standard bus technology, network communication technology with standardized protocols, and the hierarchical redundant structure, which have dramatically improved the control and protection system’s real-time performance and reliability. g. The earth electrode and earth electrode line are connected to the ground or sea to form a DC return circuit. In contrast to the safety earthing equipment in converter stations, it is necessary to take into account several factors for earth electrode and earth electrode line, such as the electro-corrosion caused by ground current to the earth electrodes and the nearby underground metallic conduits, and the saturation of nearby neutral grounding transformers because of the increase in DC bias. When designing the earth electrodes, it is necessary to determine their allowable operating current and operating time. Two-terminal DC transmission systems generally fall into three configurations: monopole (either positive or negative); bipolar (positive and negative poles); and backto-back systems (without DC transmission lines). A monopole system usually uses monopolar ground return configuration or monopolar metallic return configuration as shown in Figure 3.7. Both of the configurations use a high-voltage transmission line. The difference lies in that the former uses the ground or seawater as the return path, whereas the latter uses a lowvoltage line as the return path. In the monopolar ground return configuration, a DC current flows through the earth electrodes, whereas in the monopolar metallic return configuration there is no DC current through the ground and the earthing point on the DC side is of protective earthing. Most bipolar systems adopt neutral bus grounding at both terminals, as shown in Figure 3.6. A bipolar system consists of two independently operated monopolar ground return systems in the same converter station. The two poles share the same earth 3 6

1

4

2

5

3

3

3 2

1

6

6

1

2

4

1

6

5 Low-voltage return path

Earth electrode system (A)

2

Earthing point

(B)

Figure 3.7 Schematic of monopolar DC system wiring configurations: (A) monopolar ground return system and (B) monopolar metallic return system. 1, converter transformer; 2, converter bridge; 3, smoothing reactor; 4, DC transmission line; 5, earth electrode system; 6, AC system.

108 Chapter 3 3 2 4

1

2 1

4

Earthing point in converter station

Figure 3.8 Back-to-back wiring configuration: 1, converter transformer; 2, converter bridge; 3, smoothing reactor; 4, AC system.

electrode line and earth electrode, and the current through the ground is equal to the difference between the two pole currents. During normal balanced bipolar operation, only a small unbalanced current (generally smaller than 1% of the rated current) caused by measuring and control errors flows through the ground. If a pole is out of service due to faults, then the bipolar system can be automatically switched to monopolar operation mode with the loss of, at most, 50% of the total capacity, thus improving the system reliability. Moreover, this configuration allows phased construction of a transmission project. A bipolar system may also adopt the configuration in which only the converter station at one terminal is grounded or the bipolar configuration has a metallic neutral line. However, these two configurations are rarely used in practice. As shown in Figure 3.8, the back-to-back system is a two-terminal system without a DC transmission line and an earth electrode line/earth electrode. In a back-to-back DC system, the rectifier and inverter are located in the same converter station (usually known as a back-to-back converter station) and the two terminals are, respectively, connected to different AC systems. The back-to-back system is mainly characterized by: (i) the DC-side voltage is low but the current is high; (ii) it allows full use of the through-current capability of large-section thyristors; (iii) DC filters and earth electrodes are eliminated, thus lowering the construction cost; and (iv) a number of back-to-back units independent of each other can be constructed within the same converter station and the coordinated control of them may contribute to higher interconnection benefits and stability of AC systems. 2. Multiterminal system A multiterminal system generally consists of three or more converter stations and can interconnect three or more AC grids. Of all the DC transmission projects that have been commissioned around the world, only a few are multiterminal systems. A multiterminal system allows DC power to be collected from multiple sources or transmitted to multiple receiving terminals. Also, it enables a number of AC systems located in different regions

Characteristics of UHV DC Transmission System 109

Inverter station 3 Rectifier station 1

Inverter station 4

Inverter station 2

Inverter station 3

Rectifier station 1 Inverter station 4 Rectifier station 2

(A)

(B)

Figure 3.9 Wiring schematic diagram of multiterminal HVDC transmission systems: (A) parallel multiterminal system and (B) series multiterminal system.

or isolated grids to be interconnected. Each converter station can act as either a rectifier station or an inverter station provided that the total power, when it operates under the rectifier mode, is equal to that when it operates under the inverter mode. As shown in Figure 3.9, the converter stations may be connected either in parallel (DC lines may be arranged in the form of branches or a loop) or in series. For multiterminal systems, indepth studies should be performed for the main circuit and control and protection system because of the complexity in power allocation among converter stations during dynamic and transient processes, system fault management, and measures to improve the system reliability. The HVDC Italy
Corsica
Sardinia (three terminals, small size) and the Quebec
New England system (a five-terminal link with three terminals in practical use) are the examples of multiterminal systems that have been put into operation. In addition, the Nelson River Bipole 1 and Bipole 2 in Canada and the Pacific DC Intertie in the United States are also featured with the operating performance of a multiterminal system. 3. Configuration of main circuit and characteristics of main equipment of a UHV DC transmission system a. Configuration of the main circuit of DC systems: Currently, most UHV DC systems are two-terminal systems. To accommodate the requirement of higher transmission capability, higher DC system voltage and current may be considered. The main circuit of the DC system may adopt a number of converters connected in parallel or series. Through in-depth study of and comparison between the options where one, two, or three 12-pulse converters are connected in series (uniformly or nonuniformly distributed voltage) or in parallel on each pole at each terminal, it follows that operating the power transmission at higher voltage is an economic option. Considering the greatly increased transmission capacity and difficulty in

110 Chapter 3 manufacturing and transportation of converter transformers for 6 800 kV UHV DC systems, it was determined that the option in which two 12-pulse converters carrying the same DC voltage are connected in series on each pole at each terminal is given priority for China’s UHV DC systems. In such an option, each 12-pulse converter has its separate valve hall and double-valve configuration is used. With this option, the voltage can be boosted to the required level, thereby increasing the transmission capacity and reducing power loss. In addition, in the event of outage of one converter, the remaining converters can still operate normally. This ensures the system reliability while increasing the transmission capacity. This typical configuration has been successfully used in practice. The configuration of the main circuit of a UHV DC link also differs from that of a conventional HVDC link in that each converter is connected in parallel with a bypass circuit breaker and associated disconnector so that a 12-pulse converter can be switched in and out readily as well as isolated from the other converters that are in service. In UHV DC systems, dry type smoothing reactors are used and evenly arranged on the pole bus and neutral bus. This can reduce the investment and allow easy switching in and out of 12-pulse converters without causing adverse effect on the steady-state and transient characteristics of the DC system. b. Characteristics of main equipment: In a UHV DC system with two 12-pulse converters connected in series, although the voltage across DC terminals of each converter does not change, an increase in the DC voltage and power of each pole necessitates increased insulation for the valves and converter transformers connected at the high voltage side of the converter, smoothing reactors, and DC filters connected at the pole bus. This places higher requirements on the voltage-dependent equipment in the converter station, such as the high-voltage end ( 6 800 kV) converter transformers and associated bushings and DC wall through bushings and arresters, and necessitates a novel design for the external insulation of station equipment, such as porcelain post insulators, intended to withstand a voltage of 6 800 kV. If it is necessary to increase the DC current while boosting the DC voltage, the through-current capability of thyristor-based converters is required to be increased. The DC current in Xiangjiaba
Shanghai and Jinping
Sunan UHV DC transmission systems is as large as 4000 and 4500 A, respectively; therefore, 6-inch thyristors and associated converter valve cooling systems are used.

3.2.2 Operation of DC Transmission System 3.2.2.1 Wiring configurations One of the major operating characteristics of DC transmission systems, including the UHV DC systems, is that multiple operating modes are available, and manual or automatic

Characteristics of UHV DC Transmission System 111 switching between different modes is possible. How a DC system operates depends on factors such as the configuration of DC circuit, power flow direction, DC voltage, transmitted power, and reactive power control mode, as well as any combination thereof. By considering the system equipment conditions and requirements of the AC systems at both terminals, it is possible to reasonably select the optimal operating mode of the DC system to improve the security, stability, reliability, and equipment availability of both the AC and DC systems. 1. Monopolar configurations Three available monopolar configurations that have varying operating performance and different requirements on equipment are described. a. Monopolar ground return: It requires that the relevant equipment in converter stations, the DC line, and the earth electrode systems at both terminals are all in sound condition. During operation, all the DC current will flow through the ground return path. With this configuration, it is necessary to take into account the constraints imposed by the design of the earth electrode on the current flowing through it and its operating duration. Otherwise, the service life of the earth electrode will be reduced. The line loss in this operating mode is somewhat larger than that of one pole operated under balanced bipolar mode, which is attributed to the resistance of the earth electrodes and earth electrode lines at both terminals added to the DC circuit resistance. b. Monopolar metallic return: In this configuration, it is required that not only the equipment in converter stations at both terminals and the DC line of the operating pole are in sound condition but also the DC line of the pole out of service reaches the same insulation level as the metallic return path. The operating current is simply limited by the overload capability of a monopole, regardless of the earth electrode system. During operation, the resistance of the DC circuit is approximately equal to the sum of the resistance of lines with positive and negative polarity. Therefore, the line loss is approximately twice that of one pole operated under the bipolar mode. This configuration may be used in cases in which the converters or earth electrode system of one pole requires repair after faults or scheduled maintenance or the current to the ground is limited. For a DC system, it is possible to transfer from the monopolar ground return to the monopolar metallic return and vice versa via the ground return transfer switch (GRTS) and metallic return transfer breaker (MRTB) without shutting down the system. This can reduce the power loss due to system outage and contribute to the increased system reliability and availability. c. Monopolar ground return system with two DC lines in parallel: In this configuration, the equipment in converter stations and the earth electrode systems at both terminals of the operating pole and the DC lines of both poles are required to be in sound

112 Chapter 3 condition. The line loss is approximately one-half that of one pole operated under the bipolar operation mode. However, the magnitude of operating current and the operating duration are constrained by the overload capability of a single pole and the design of earth electrodes. Moreover, the metallic return conductors in the DC switchyards at both terminals are required to be fully insulated. 2. Bipolar configurations Both the bipolar metallic return configuration (also called bipole with metallic neutral wire or bipolar three-wire system) and the bipolar configuration with only one converter station grounded (also called bipolar two-wire system) are rarely used in practice. As shown in Figure 3.6, the bipolar configuration with neutral-point earthing at both terminals is commonly used in DC projects. This configuration requires that all the equipment is in sound condition and allows flexible operation and high reliability. During the balanced bipolar operation, only a small unbalanced current flows through the grounding systems at both terminals and thus has little effects on the earth electrodes. It is believed to be the optimum operating mode of a bipolar system. When one pole is out of service because of faults, the DC system can automatically switch to monopolar ground return mode. The healthy pole may compensate the loss of the other pole by increasing its output utilizing its short-term, long-term, or inherent overload capacity to minimize impact on AC systems. For a bipolar system with two 12-pulse converters connected in series at each terminal, each converter consists of one 12-pulse converter valve and one group of associated converter transformers and can operate independently. Thus, each pole has a total of four 12-pulse converters at both terminals. By varying the number of converters put into operation, selecting a monopolar or bipolar system and ground return or metallic return, a total of 45 different configurations are available for a UHV DC system built with two poles, namely, one bipolar configuration with all converters in operation, eight bipolar configurations with an unbalanced number of converters in operation for both poles (i.e., one pole has only one converter in operation while the other pole has two), 16 bipolar configurations with only one converter in service per pole, four monopolar configurations with two converters in service, and 16 monopolar configurations with one converter in service. Added to these is the deicing configuration, in which the two high-voltage end 12-pulse converters are connected in parallel to increase the line current for deicing purposes. 3.2.2.2 Direction of power flow With the aid of the control system, a DC system can flexibly reverse its power flow direction, which is known as power reversal. There are two kinds of power reversals, namely, normal power reversal and emergency power reversal. Generally, the latter is automatically completed by the control system and the former can be either manually or automatically achieved.

Characteristics of UHV DC Transmission System 113 Because of the inherent unidirectional conduction of thyristor valves, the direction of the current through a DC circuit cannot be changed. Therefore, the reversal of power flow direction has to resort to reversing the polarity of pole line voltage. For instance, when a bipolar system transmits power in a forward direction, the voltage polarity of pole 1 is positive and that of pole 2 is negative. After reversal, the voltage polarity of pole 1 becomes negative and that of pole 2 becomes positive. A power reversal necessitates the change of operating conditions of converter stations at both terminals. Particularly, the rectifier station is changed to operate under inverter mode while the inverter station operates under rectifier mode. Therefore, it is required that the control and protection systems of converter stations at both terminals are able to satisfy the control requirements for both the rectifier and inverter operations. Usually, the inverter station as seen along the prevailing transmission direction has a capacity slightly smaller but a reactive power compensation capacity slightly larger than the rectifier station. If the transmission capacity in both directions is required to be the same, then appropriate adjustment and changes have to be made to the converters at both terminals, regulating the range of converter transformer tap changers and reactive power compensation configuration. The normal power reversal may be achieved manually by operators or automatically under predefined conditions. To reduce the impact of power reversal on the AC systems connecting both terminals, the process should be controlled at a relatively slow pace, usually taking a few seconds or longer. If a fault occurs in the AC system that requires urgent active power support from the DC system, then an emergency power reversal may be used. In this case, the quicker the power reversal is, the more effective the support to the AC system is. Because the power reversal involves a change in voltage polarity, the reversal speed mainly depends on the charging and discharging times of equivalent capacitance of DC lines. For overhead lines, this can be completed within a dozen cycles. For DC cable lines, to avoid damages to cable insulation caused by fast voltage polarity reversal, the reversal speed must be limited. UHV DC systems may be provided with bidirectional power flow transmission capability as required. 3.2.2.3 Operation at rated or reduced voltage The DC system voltage is defined as the mean voltage at the line side of the pole bus with respect to the neutral bus in the rectifier station: Udr 5 nUd1 where n—number of six-pulse converters connected in series per pole.

(3.12)

114 Chapter 3 The DC system can be selected manually or automatically to operate at rated or lower voltage. Operating at reduced voltage is an operation that could be used during harsh weather conditions or severe pollution to reduce the probability of fault occurring, thereby increasing the system reliability and availability. The DC voltage can be regulated by quickly varying the firing angle through the control system and changing tap changer positions of converter transformers. Too small a reduction in voltage may not have the desired effect of improving system availability. However, excessive reduction would result in the system operating at a large firing angle, thereby compromising the operating conditions of the system. Generally, the preferred voltage for reduced voltage operation should be 70
80% of the rated voltage with the firing angles reaching up to 40
50 . As long as the system can be operated at the rated voltage, the operation at reduced voltage should be avoided. This is because, for a given transmitted power, reduction in the DC voltage will cause the DC current to increase proportionally, contributing to higher power loss and operating cost. When the system operates at reduced voltage, the operating current is generally limited by the rated current. Therefore, when the system is operated at 70% of the rated voltage, the maximum transmitted power will be reduced to 70% of the rated power. However, to avoid unstable operation of the DC system after a disturbance and to allow desirable recovery characteristics, the low-voltage current limiter may be used to protect the system from operating under low-voltage large-current conditions when the system voltage drops abnormally. In addition, another operating mode is to operate the system with a single converter, reducing the DC voltage by a factor of two. 3.2.2.4 Active power control The active power transmitted by a DC system can be controlled rapidly. There are two control modes, power control and current control. 1. Current control The DC system current is defined as the operating current through each pole: Id 5

Udr 2 Udi R

(3.13)

where Udi—voltage of the inverter-side pole bus with respect to the neutral bus, Udi 5 nU2 R—resistance of the DC circuit, Ω, mainly consisting of resistance of DC lines, smoothing reactors, earth electrode lines, and earth electrodes. It varies from one system configuration to another.

Characteristics of UHV DC Transmission System 115 Under the current control mode, the DC current is maintained constant via the current regulator in the rectifier station. If the inverter station is operated at the extinction-angle γ control mode and the rectifier station is operated at the current control mode, then as the DC voltage experiences small changes, the transmitted power will vary as well. In contrast, if the inverter station is operated at the voltage control mode and the rectifier station is operated at the current control mode, then the transmitted power will remain constant. 2. Power control The DC system power is defined as the output power of the rectifier station. The power of a single pole is given by: Pdm 5 Udr Id

(3.14)

The power of a balanced bipole is given by: Pdb 5 2Pdm

(3.15)

Generally, the DC voltage is controlled by the regulator installed in the inverter station, whereas the current or power is controlled by the regulator installed in the rectifier station. Under the power control mode, the transmitted power is maintained constant via the power regulator installed in the rectifier station. During operation, when the DC voltage increases, the power regulator will operate to reduce the DC current correspondingly; conversely, when the DC voltage decreases, the power regulator will operate to increase the DC current (up to the real-time permissible maximum limit). In this way, the transmitted power can be maintained at or close to the set value. Under the power control mode, the transmitted power is set manually by the operator or automatically according to the predefined load curve. During operation, the DC current changes as a function of the DC voltage. In a coordinated control, the inverter station usually adopts extinction angle or voltage control to stabilize the DC voltage. During operation, the DC voltage changes with the AC system voltage or the DC current. If extinction angle control is adopted, then the extinction angle should be set to the minimum safe value. If voltage control is adopted instead, then the voltage regulator on the inverter side usually maintains constant DC voltage (for operation at either rated or reduced voltage). Normally, the power control mode should be used. If there is a fault occurring to the communication system, then fluctuations in current may cause mismatches in control parameters used by the rectifier and inverter. To avoid this, control mode at the rectifier station may be switched to current control while maintaining the prefault operating current value. 3.2.2.5 Balanced and unbalanced bipolar operation Balanced bipolar operation is an operating mode in which the two poles have the same voltage, current, and, hence, the same transmitted power. In contrast, unbalanced bipolar

116 Chapter 3 operation is an operating mode in which the two poles have different voltage or current. Therefore, the balanced and unbalanced bipolar operations correspond to different combinations of the aforementioned DC voltage and power control modes. The balanced bipolar operation is characterized by the following: (i) both poles are operated at the same rated or reduced voltage; and (ii) power transmitted by both poles is equal because the same current flows through them and the current through the earth electrodes is generally less than 1% of the rated DC current. Normally, this mode is selected for a bipolar system. It has many advantages, including the following: (i) the system’s design capacity can be fully exploited; (ii) the system equipment can operate under desirable conditions; (iii) the system loss is small; and (iv) the operating cost is lower and the reliability is higher. The unbalanced bipolar operation has three categories: unbalanced voltage, unbalanced current, and unbalanced voltage and current operations. The unbalanced voltage operation means that one pole is operated at rated voltage while the other is operated at reduced voltage. In this case, it is desirable to ensure that both poles operate at the same current, thereby reducing the current through the earth electrodes to the minimum. With different operating voltages, the two poles would transmit different power. If the pole that is operated at reduced voltage is also required to reduce its DC current, then both poles will be operated at different voltages and different currents. In this case, the differential current between the poles will flow through the earth electrodes. If both poles use the same voltage control mode but have different current settings, then the system operates at unbalanced current. In this case, the differential current between the poles flows through the earth electrodes. To minimize the effects of unbalanced operation on both the AC and DC systems, the pole operating under the design conditions should usually be placed under power control mode. Thus, irrespective of whether the other pole is operated at reduced voltage or increased/ reduced current, it will try to maintain constant transmitted power for both poles. Moreover, each pole of a bipolar system can operate with a single 12-pulse converter, giving rise to more bipolar operation modes with balanced or unbalanced voltage and power combination. 3.2.2.6 Reactive power control Regarding the reactive power interchanged between the converter station and AC system, the reactive power supplied from the AC system to the converter station is positive and that from the converter station to the AC system is negative. 1. Rectifier station (QS1) QS1 5 QC1 2 QF1 2 QRC1

(3.16)

Characteristics of UHV DC Transmission System 117 2. Inverter station (QS2) QS2 5 QC2 2 QF2 2 QRC2

(3.17)

where QF1 , QF2 —reactive power supplied by the AC filters at rectifier station and inverter station, MVAr, respectively QRC1 , QRC2 —reactive power, respectively, supplied by other reactive power compensation devices at rectifier station and inverter station, MVAr. It is vital to control reactive power at converter stations. This can reduce its effects on the reactive power or voltage of the AC systems, contributing to increased stability of the DC system. Such controllability is achieved through various reactive power control modes provided by the control system. These control modes mainly include the control over the reactive power exchange between converter stations and AC system, and the AC voltage control. In the former works, the reactive power exchange between the converter stations and the AC system should be limited within a certain range, whereas the latter maintains the converter bus voltage within a certain range. Generally, the DC transmission system uses the reactive power control mode. However, when the converter station is connected to a weak AC system or when the AC voltage is somewhat high, the AC voltage control mode may be used instead. The control range of reactive power at converter stations is limited and is restricted by the configuration of reactive power compensations at converter stations, design conditions of equipment at converter stations, system transmission capacity, and control modes. The reactive power control at converter stations is achieved mainly by means of: (i) switching in/out of the AC filter banks or capacitor banks to change the reactive power supplied by the converter stations; and (ii) regulating the firing angles to change the reactive power absorbed by the converters. Switching in/out of filter banks will cause the reactive power to change in a stepped manner. Also, when the DC system is operated under light load conditions, it is necessary to switch-in the absolutely minimal number of filter banks to satisfy the requirement of filter capacity limit. As a result, excess reactive power could potentially be injected into the AC system, causing the AC bus voltage to increase. Therefore, installation of reactive power absorption equipment may be required. In contrast, regulating the firing angles can change the reactive power absorbed by the converters quickly and smoothly and, therefore, is desirable. Quickly increasing the firing angle α or the extinction angle γ can also reduce the dynamic overvoltage on the AC side of converter stations. However, the regulation range of firing angle α is restricted by the DC system performance and equipment stress. In practice, usually a combination of these two is used to achieve satisfactory performance. Also, synchronous condensers or static VAR compensators may be an alternative to control the reactive power at converter stations.

118 Chapter 3 As a UHV DC link transmits more power, the converter stations at both terminals need more reactive power, leading to an increased number of reactive power compensation equipment and more complicated switching and control logics.

3.2.3 Characteristics and Applications of UHV DC Transmission 3.2.3.1 Advantages and applications The UHV DC transmission is an efficient way to achieve bulk power transmission over long distances. In addition to having all the characteristics of the conventional HVDC transmission, UHV DC transmission can take full advantage of bulk power transmission over long distances, which remains an urgent problem in China’s power industry development. A DC overhead line requires only two conductors, one positive and the other negative, and features a simpler tower structure, narrower line corridor, lower construction cost, and line loss. In addition, a DC system may use the ground (or sea) instead of a dedicated conductor as the return path and may take advantage of the low resistivity and lower loss of the ground return. On a DC line, no capacitive current is present and the voltage is uniformly distributed along the line, eliminating the need for installation of shunt reactors. Moreover, it has a large transmission capacity and, hence, is particularly suited for bulk power transmission over long distances. A DC cable line can withstand high voltage, has a large transmission capacity, and has high power density, low line loss, and long service life. In addition, its transmission distance is not restricted by the capacitive current. This is why most long-distance cross-sea and underground transmission lines (e.g., supplying power to cities that are constrained by insufficient line corridor) use DC cables. Increasing the transmission voltage can reduce the power loss while increasing the transmission distance. Because the line loss of a DC overhead line is mainly caused by resistance, UHV DC is more desirable for power transmission over a long distance. With a certain current, increasing the UHV DC transmission voltage is able to increase the transmitted power, which can be up to the maximum power as limited by the thermal limit of DC lines and equipment in converter stations at both terminals, thus making full use of the transmission capacity of UHV DC systems. When it is necessary to increase the DC current to allow a larger transmission capacity, the cross-sectional area of the subconductors of transmission lines may be increased to 1250 mm2 to reduce the line loss. To this end, it is required to improve or enhance some aspects, such as the conductor type, bundle configuration, insulation coordination, insulator string, distance from conductors to the ground, distance from DC lines to other transmission lines that they cross, towers and loads applied thereon, as well as electromagnetic effects.

Characteristics of UHV DC Transmission System 119 The UHV DC transmission system has the following advantages: 1. Isolated by the DC system, interconnection can be made between AC grids operating at different frequencies (e.g., one at 50 Hz and the other at 60 Hz), and each grid can maintain independent operation at its own frequencies and voltages. 2. Because the AC systems interconnected through the DC system are not required to operate synchronously, the transmission capacity and distance of the DC system are not limited by the requirements of the synchronous operation of the AC systems at both terminals. 3. The short-circuit capacity of the connected AC systems is not increased, thus limiting the increase in short-circuit current of AC systems. 4. By virtue of its quick and accurate regulation function, the UHV DC transmission system can increase the stability and transmission capacity of the AC systems, and can serve as the tie line between regional grids to increase the operational stability, reliability, and flexibility of the entire interconnected system. Because of these important characteristics, the UHV DC systems permit bulk power transmission over long distances. China started the study of UHV DC technology in 2005, and results of the study indicate that the conventional HVDC system is a preferred option for power transmission over a distance less than 1300 km, and UHV DC system is more cost-effective for power transmission over a distance more than 1300 km. To date, China has built the Xiangjiaba
Shanghai 6800-kV UHV DC transmission link with a rated transmission capacity of 6400 MW and a transmission distance of 1891 km, and the Jinping
Sunan 6800-kV UHV DC transmission link with a rated transmission capacity of 7200 MW and a transmission distance of 2059 km; both have already been put into service. The operating practices with these links show that the construction cost per unit capacity of a 6800-kV UHV DC link is approximately 28% lower than that of a 6500-kV HVDC link. Apparently, from the techno-economic perspective, UHV DC system is more competitive when used for bulk power transmission over long distances. Reliability is of great importance for UHV DC systems delivering bulk power over long distances. Today, China’s UHV DC systems use a configuration with two 12-pulse converters that are series-connected per pole and have as many as 45 operating modes in normal conditions. In addition, the unique control strategy of switching a single 12-pulse converter online makes it possible to isolate and repair a single 12-pulse converter after a fault occurs. Moreover, the control and protection philosophy aiming at avoiding forced outage of a pole/bipole and the interpole power compensation function intended to minimize the power loss all contribute to greatly increased reliability of UHV DC systems. Because two series-connected 12-pulse converters are provided for each pole, once a single converter is out of service because of a fault, the remaining ones can still operate. Despite the loss of one-half power of the pole, the complete outage of the pole can be avoided.

120 Chapter 3 By using additional connections in the converter stations at both terminals and surge arresters and the primary switches in DC switchyard, it is possible to change the connections of primary equipment and achieve the operating mode whereby the high-voltage end of the two poles is connected in parallel. In this case, the DC line current will be much higher than the rated current, considerably enhancing the deicing capability. Moreover, the operating mode whereby the two poles transmit power in opposite directions and the associated control protection strategy can also protect the line from icing. All these measures can effectively handle the snow and cold weather, consequently greatly reducing the occurrence of outages of the DC transmission system and improving the system reliability. The control and protection system of UHV DC systems has a reasonable hierarchical and distributed structure, as well as a complete redundancy configuration and a self-diagnosing function. The DC protections all use triple configuration and 2-out-of-3 voting logic. The bipolar protection is, respectively, incorporated into the pole protection, with the output strategy of removing the pole that is in trouble. Moreover, the application of the state-ofthe-art technology of the converter maintenance key allows one converter of a monopole to be isolated and repaired while maintaining the other in normal operation. All these features can further improve the reliability of UHV DC systems. Therefore, the annual design fault outage rate for a single pole is reduced from five times to two times per year, and that for a bipole is reduced from 0.1 times to 0.05 times per year. In addition, other important UHV DC features include its controllability of the transmitted active and reactive power, rapid dynamic response, and ability to conduct staged commissioning. To accommodate the bulk power transmission over long distances, the UHV DC technology has greatly evolved and advanced in terms of the system research, main circuit configuration, equipment parameters, control and protection strategy, as well as the operation technology, which have already been applied successfully in actual projects. 3.2.3.2 Limitations and development trends of HVDC transmission technology The thyristor-based HVDC transmission technology still has with a number of problems: a. Compared with an AC system, an HVDC converter station requires more equipment, the converters are expensive to manufacture, and the system configuration and operation are more complicated. b. As the thyristor converters generate harmonics on both the AC and DC sides during operation and consume a large amount of reactive power, it is essential to install AC filters, DC filters, and reactive power compensation devices in converter stations at both terminals, leading to larger land occupation, construction cost, and operation cost. c. Because of the inherent features of thyristor converters, commutation failure is inevitable when the AC and DC systems encounter a fault or disturbance. Although the

Characteristics of UHV DC Transmission System 121 state-of-the-art technology can reduce the probability of commutation failure to a minimum, it cannot be eradicated completely. d. The use of the ground or sea return path may cause electro-corrosion of buried metallic parts and conduits adjacent to the earth electrodes, and other problems such as the bias magnet and vibration due to DC current flowing through the neutral earthing transformers. Moreover, it is difficult to site the earth electrodes when the ground soil resistivity is high. e. The inherent electrostatic adhesion of DC current causes more severe contamination to DC lines and equipment in converter stations than in AC systems, thus requiring higher external insulation level. f. Because the DC current wave has no zero crossing point, it is difficult for HVDC circuit breakers to perform arc extinction, which creates difficulty for intermediate tapping and hinders the development of multiterminal DC system. The HVDC circuit breakers developed so far need to be further improved in terms of technical maturity and economy to accommodate the requirements of UHV DC applications. The UHV DC systems are characterized by large transmission capacity, more equipment, and multiple operating modes, thus necessitating DC control and protection strategies with higher performance and reliability. To accommodate bulk power transmission of UHV DC links, great efforts should be made to develop the main equipment with larger capacity, such as converter valves and transformers, and to improve and update the control and protection system to increase the stability and reliability of the DC system itself. However, it is essential to study how to guarantee the safe and stable operation of UHV DC systems, focusing on the analysis and research of the interaction between the AC and DC systems. Moreover, developing novel technology to address problems currently facing the thyristorbased conversion technology is required. With the advent of insulated gate bipolar transistor (IGBT), a novel metal-oxide semiconductor turn-off device, the voltage source converter (VSC) based on the IGBT and pulse width modulation (PWM) was applied in DC transmission systems. The world’s first test VSC-HVDC system (610 kV, 3 MW, and 10 km) was constructed in 1997 in Sweden. Then, in 1999 in Sweden, the first commercial VSC-HVDC project (680 kV, 50 MW, and 140 km) was put into operation. In 2011, China’s first flexible DC transmission project— Shanghai
Nanhui flexible DC demonstration project (630 kV, 18 MW)—was completed. The Zhoushan flexible DC transmission project (6200 kV, 1000 MW) under construction is a five-terminal link. The application of VSC technology will be further expanded with the increase in the capacity of IGBTs. The VSC-HVDC technology has the following main advantages: (i) it allows simultaneous control of the active and reactive power and requires no reactive power compensation; (ii) VSC converters only generate a small amount of harmonics of high orders; (iii) the VSC

122 Chapter 3 converter is self-commutated and operates in passive inverter mode, making it suitable for power feeding to passive networks; and (iv) the controllable turn-off capability avoids problems such as commutation failures. The VSC-HVDC transmission system needs less equipment, has a simpler structure, and occupies less land. However, because of the constraint imposed by the manufacturing technology of IGBTs, the power loss caused by a VSC converter is approximately double that of a thyristor-based converter. The IGBT’s voltage and current ratings are both lower than that of thyristors. At present, the capacity of the largest IGBT-based project under construction is only 1000 MW. In addition, it is impossible for a VSC-HVDC link to clear faults on the DC side by virtue of its own control capability, which results in relatively low reliability for long-distance overhead lines. For this reason, it is more suitable to be used in transmission links using cable lines with a lower fault rate. Nevertheless, the VSC-HVDC is still a highly promising technology. To deal with the problems with conventional HVDC technology, such as reactive power compensation and commutation failure, the capacitor commutated converter (CCC) technology was developed. It works in such a manner that capacitors are series-connected between the converter and the converter transformer to mitigate the effects of AC system voltage disturbance on the converter and reduce the reactive power compensation needed by the converter station. For CCCs to be applied in actual projects, it is necessary to investigate the overall performance of DC systems and technical requirements on capacitors.

3.3 Safety, Stability, and Operation of UHV DC Transmission System 3.3.1 Role of AC Systems in Supporting UHV DC Systems Considering the uneven distribution of energy sources and load centers and the geographic features of China, DC transmission technology plays an important role in transmitting bulk power from large energy bases over long distances. However, the conventional thyristor converter-based DC systems require the voltage support from AC grids when commutation occurs. Hence, the system capability of AC grids is crucial to the normal operation of the DC system. China has commissioned the most DC transmission links with the largest power transmission capacity around the world. The receiving ends of those links are concentrated at the load centers in the eastern and southern parts of the country. During China’s 12th 5-year plan, Jinping
Suzhou, Hami
Zhengzhou, and Xiluodu
Zhejiang UHV DC transmission links were completed and commissioned successively, making the feature of a multi-DC infeed network in the Eastern China more distinct. Such a dense multi-DC infeed network is unique to China and requires robust AC grids to ensure its normal operation. Therefore, building a robust hybrid grid integrating AC and DC systems that complement and support each other is essential to guarantee the safety and economical efficiency of the grids.

Characteristics of UHV DC Transmission System 123 The UHV DC system has a large transmission capacity and its security and stability are closely related to the robustness of AC systems at the sending and receiving ends. This mainly lies in the following aspects: 1. The AC systems at the sending and receiving ends, respectively, supply commutation voltage to the rectifiers and inverters of the DC system, creating a prerequisite for conversion. 2. The AC systems at both ends are essential for DC transmission. The sending-end AC system serves as the power source to supply the power to be transmitted, whereas the receiving-end AC system serves as the load to consume and accommodate the transmitted power. 3. The sending-end AC system must be sufficiently robust for because it should be able to supply sufficient reactive power and voltage support to the rectifier station. However, it is more capable of withstanding both the active and reactive power surge resulting from faults in the DC system, which is essential in reducing the number of generating units that have to be intertripped under such faults. 4. The robustness of the receiving-end AC system is essential for the safe and stable operation of the DC system, particularly when multiple DC transmission lines are densely terminated at the receiving system. If the receiving-end AC system is robust enough, although there is potential for the commutation to fail at multiple inverter stations when a severe fault occurs in the AC system, its voltage can be recovered rapidly once the fault is cleared and the DC system can also restore to normal operation rapidly. Therefore, when a commutation failure occurs at an inverter station, immediate blocking protection is not required. Instead, if appropriate steps are taken, then the aforementioned recovery process can be accelerated, avoiding consequent commutation failures. In contrast, if the AC system is weak, once a severe fault occurs, its voltage cannot be restored to the normal value and commutation failure will occur at multiple inverter stations, which will further exacerbate the operation of the AC system and cause it to lose stability. In addition, if a fault in the DC system results in blocking of a single pole or bipole, a robust receiving-end AC system is able to withstand the surge caused by abrupt power change and the operating voltage and frequency of the system can be maintained within the normal range, occurrence can prevent load rejection and reducing the load loss to the minimum.

3.3.2 Connection of UHV DC Transmission Systems As the number of DC transmission systems grows, interconnections between AC and DC systems are becoming more and more complicated, from the simple interconnection of a single-circuit DC system with two asynchronous AC systems to the parallel AC/DC power transmission, from the connection of the DC system to a large AC grid at the sending end

124 Chapter 3 to the islanded operation at the sending end, and from single infeed to multiple infeeds. A large hybrid AC/DC system combining several connection modes also appears. These diversified interconnections will inevitably make the system secure and stable, and make the relevant controls more complicated. A DC system can be connected to an AC system mainly in the following modes: 1. Through a single DC circuit: The sending-end grid and the receiving-end grid are interconnected through just a DC link. If this mode is used, then it is necessary to consider the effects of severe fault in the DC system on the AC grids. 2. Single DC circuit, islanded operation: The sending-end power source is directly connected to a DC system through simple electrical connection to transmit power. Although the islanded system at the sending end has a simple configuration, there are some prominent concerns about system stability control, subsynchronous oscillations, overvoltage suppressing measures, and start-up operation. 3. Parallel AC/DC power transmission: This has the following advantages: (i) offers a new transmission mode that enables the system to better accommodate different operating requirements; (ii) increases the AC system robustness and rotational inertia under certain conditions to improve the system damping behavior; and (iii) allows the AC and DC systems to support each other by virtue of fast controllability of the DC system, thus enhancing the transmission capability of the parallel AC/DC system. However, when this mode is used, the AC power network is required to be robust enough to deal with the great amount of power transferred from the DC system and maintain the system voltage at a proper level after the fault. 4. Multi-send-out mode: In this mode, the rectifier stations of multiple DC systems are situated at the same place and are electrically in close proximity to each other. It is mostly used in ultralarge energy bases from where the power is sent out through multiple DC systems to receiving ends at different locations. In China, this mode is widely used in the extra-large energy bases in the northwestern and southwestern regions. To use this mode, it is necessary to perform an in-depth study of the interaction between DC systems and their coordinated control under fault conditions. 5. Multi-infeed mode: In this mode, the inverter stations of multiple DC systems are situated at the same place and are electrically in close proximity to each other. It is commonly used in different regions, such as eastern and southern China, and it will be used more widely as more and more DC systems are built in China. Therefore, it is necessary to perform an in-depth study of the stability and security of the multi-DC infeed network. Apart from these modes, a combination of these modes has also been used in practice. For instance, the hydropower produced in southwest China is sent to east China through a hybrid AC/DC system using a combination of multi-send and multi-infeed modes. In this case, the system stability behavior is more complicated and the operation control becomes more difficult.

Characteristics of UHV DC Transmission System 125 Because a UHV DC system has a large transmission capacity, the voltage class of the AC grid to which the system is connected is a key factor affecting system security and stability. Based on the experiences gained in connecting the UHV DC systems to the 500-kV AC grid, it is expected that in the future it is possible to connect UHV DC systems directly to 1000-kV UHV AC grids and connect the high-voltage and low-voltage converters of a UHV DC system, respectively, to two grids at different voltage classes.

3.3.3 Stability Evaluation Methods for Interconnected UHV DC
AC System A conventional DC transmission system comprises thyristor-based converters that require voltage support from the grid for commutation. Therefore, a conventional DC system can only deliver power to AC grids that are supported by stable power sources, and its transmission capacity is closely related to the robustness and stability of the connected AC system. The transmission capacity of a DC system is restricted by the robustness of the connected AC system, which lies in two aspects: (i) the equivalent impedance of the AC system as seen from the converter bus is related to the fault recovery capability of the AC power network; and (ii) the mechanical inertia (rotational inertia) of the AC system is related to the supporting capability offered by the power sources in it. The robustness of the interconnected AC/DC system is mainly evaluated in terms of the following two indexes. 1. SCR and ESCR The relative robustness of the AC system compared with the connected DC system can be evaluated using the short-circuit ratio (SCR). SCR is defined as the ratio of the short-circuit capacity of the AC system to the rated power of the DC system, namely: SCR 5

SSC Pd

(3.18)

where SSC —the short-circuit capacity of the connected AC system, MVA Pd —rated power of the DC converters, MW. After considering the effect of the reactive compensation devices (such as filters and shunt capacitors) on the system robustness, the effective SCR (ESCR) concept is used to give a more practical evaluation of the total system robustness and it is defined by: ESCR 5

SSC 2 QC Pd

where QC —capacitive reactive compensation, MVAr.

(3.19)

126 Chapter 3 In the case of high SCR/ESCR systems, the variation of active/reactive power in the converter station leads to small AC voltage changes of the converter bus and nearby AC systems. Therefore, the additional transient voltage control at the bus is normally not required. The reactive power balance between the AC system and the converter station can be achieved by switching the reactive power equipment in/out. In the case of low SCR/ESCR systems, the variations in the AC system or in the HVDC power could lead to voltage oscillations and require special control measures, such as additional static VAR compensators or synchronous condensers. The concept of SCR/ESCR offers a simple and visualized way to assess the relative robustness of the AC and DC systems. In practical applications, the SCR/ESCR can be closely correlated with the technical issues such as the voltage stability of the interconnected AC/DC system, AC system overvoltage caused by blocking of the DC system, possible resonance frequency of the interconnected system, and the maximum transmitted power allowed by the AC system. Based on the operating experiences, the interconnected AC/ DC systems of the single-infeed configuration can be classified into three categories in terms of robustness: strong system, ESCR . 3; moderate and weak system, 2 , ESCR , 3; and very weak system, ESCR ,2. Other classification criteria described herein are based on SCR are similar to these. 2. OSCR and OESCR Due to the constraints imposed by the configuration or load variations of the AC system, the DC system usually cannot be operated at full load, that is, actual power transmitted is lower than the rated power. Consequently, the use of SCR/ESCR to evaluate the relative robustness of AC system cannot reflect its effects on the stability of the interconnected system. In view of this, the concepts of operation SCR (OSCR) and operation effective SCR (OESCR) are introduced to indicate the actual SCR and ESCR corresponding to the actual power transmitted. OSCR is defined as: OSCR 5

SSC Pd

(3.20)

operation

where Pd_operation—actual power of DC system, MW. After taking into account the reactive power compensation capacity of the filters and shunt capacitors, the OESCR is defined as: OESCR 5

SSC 2 QC operation Pd operation

where QC_operation—actual net capacitive and reactive compensation, MVAr.

(3.21)

Characteristics of UHV DC Transmission System 127 3. AC system constrained maximum DC power [1] For an interconnected AC/DC system, the DC system may be deemed as a special load of the AC system, as seen from the converter bus, that is, the rectifier side is a load and the inverter side is a power source. In this case, there occurs an instability problem of the AC system under critical condition that is related to the maximum power transmitted through the DC system as constrained by the AC system stability. This maximum limit may be calculated using the following set of equations: 9 Pd 5 CU 2 ½cos 2γ 2 cosð2γ 1 2μÞ > > > Qd 5 CU 2 ½2μ 1 sin 2γ 2 sinð2γ 1 2μÞ > > > > > Id 5 KU½cos γ 2 cosðγ 1 μÞ > > > > Ud 5 Pd =Id = 2 (3.22) Pac 5 ½U cos θ 2 EU cosðδ 1 θÞ=jZ j > 2 > > Qac 5 ½U sin θ 2 EU sinðδ 1 θÞ=jZ j > > > > QC 5 B C U 2 > > > > Pd 2 Pac 5 0 > ; Qd 1 Qac 2 QC 5 0 where γ—extinction angle, ( ) μ—overlap angle, ( ) C, K—parameters of converter transformer and constant related to the reference ratings of DC system Z—equivalent impedance of AC system, Ω θ—equivalent impedance angle of AC system, ( ) δ—phase angle of converter bus voltage, ( ) BC—equivalent susceptance of AC filters, S QC—reactive power generated by AC filters, MVar Pac and Qac—active and reactive power of the equivalent circuit of AC system, MW and MVar. Equation (3.22) contains nine equations and 12 variables. Assuming that the equivalent electromotive force of the AC system remains constant, there will be 11 independent variables. Depending on the objects to be analyzed, two of the 11 variables can be defined as independent variables, and the others are then determined accordingly. Generally, given the SCR in conjunction with the operating conditions and parameters of the DC system, the maximum transmitted power of the DC system under certain interconnection conditions can be obtained using Eq. (3.22). To ensure that the critical stability conditions of the interconnected system can be met when the DC system operates at rated power, it is required that the AC system to which the DC system is connected must be strong enough to provide supports. The constraint relationship described in Eq. (3.22) shows that blindly increasing the transmission capacity

128 Chapter 3 of the DC system without reinforcing the AC grid structure may lead to instability of the power network once the critical operating condition of AC grid at either end is reached. Therefore, coordinated development of both the AC and DC transmission to build hybrid grids interconnecting is essential to maintain the security and stability of the power system. 4. Relative mechanical inertia constant The AC system stability is closely related to its mechanical inertia constant. For the AC system at the receiving end of the DC transmission, its robustness is of vital importance when the DC infeed represents a major part of the supply. An insufficient mechanical inertia indicates the AC system’s poor capability to withstand disturbances. As the UHV DC system transmits an enormous amount of power, a single pole fault or bipole fault will cause a large power deficiency in the AC system. To measure the ratio of the DC power to the equivalent rotational inertia of the AC system, an index of equivalent mechanical inertia of the DC system is introduced. The relationship between the variations of system frequency, mechanical power input, and electrical power output can be represented by: df 5

ðPm 2 Pe Þf0 dt 2H

(3.23)

where Pm —generator mechanical power, MW Pe —generator electrical power, MW f0 —system nominal frequency, Hz H—inertia constant of the generator, s. After the DC system is connected to the AC system, the mechanical inertia constant of the AC system relative to the DC system is Hdc 5 H

SGE Pd

(3.24)

where SGE —system equivalent capacity, MVA. In a simple single-DC infeed system, the variation of AC system frequency as a function of the DC power can be represented by df 5

f0 SGE ðPm 2 Pe Þ dt 2Hdc Pd

(3.25)

Equation (3.24) shows that the larger the proportion of power fed from the DC system, the weaker the receiving-end AC system relative to the DC system. Consequently, the smaller the mechanical inertia of the system, the poorer the capability of the interconnected system is to withstand disturbances. Therefore, the DC infeed proportion should be maintained at a proper level.

Characteristics of UHV DC Transmission System 129 For asynchronous interconnection through a DC system, by using the concept of relative mechanical inertia in conjunction with Eq. (3.25), it is possible to approximately estimate the frequency variation range of the grids in cases when the DC system experiences a single pole or bipole fault at the sending and receiving ends. This method essentially establishes a mathematical relationship between the generator inertia constant, DC transmitted power, and AC system frequency. Thus, the AC system fault clearing time can be calculated based on the estimated system frequency fluctuation, providing a basis for designing the control parameters of generator frequency adjustment. 5. MSCR Although the SCR can reflect the strength of the AC system relative to the DC system satisfactorily in the case of the single-DC infeed configuration, it cannot work effectively for multiple DC infeed system. This is because a multiple DC infeed system has a number of sending ends and the various DC systems interact and affect one another significantly. Simply using SCR to assess a multi-DC infeed system would cause a large deviation and yield an excessively optimistic outcome. By reference to the definition of traditional SCR, International Council on Large Electric systems (CIGRE) has introduced the concept of multi-infeed SCR (MSCR) to evaluate the robustness of the AC system relative to the DC system in a multi-DC infeed configuration. Specifically, MSCR is the ratio of the three-phase short-circuit capacity of the AC system as seen from the converter bus of the ith DC system to the equivalent DC power fed into the interconnection point [2,3], expressed as MISCRi 5 Saci =Pdeqi

(3.26)

where MISCRi —MSCR corresponding to the ith DC system i—ith DC system Saci —three-phase short-circuit capacity as seen from the converter bus of the ith DC system Pdeqi —equivalent DC power of the ith DC system after allowing for the influence of other DC systems, MW. It is obtained from the characteristics of multi-infeed DC/AC system, taking into account factors such as electrical distance, and is transmitted from other DC systems When simply considering the electrical coupling of the AC system and using the multi-port Thevenin equivalent at the converter bus side of the multiple DC systems, the MSCR can be defined as: MISCRi 5

Saci 1 P 5 jZeqii jPdi 1 nj51;j6¼1 jZeqij jPdj Pdeqi

(3.27)

130 Chapter 3 where Zeqii —self-impedance of the ith converter bus in the equivalent impedance matrix, Ω Zeqij —mutual impedance between the ith and jth converter buses in the equivalent impedance matrix, Ω Pdi —rated power of the ith DC system, MW Pdj —rated power of the jth DC system, MW With the MSCR concept, it is possible to evaluate the robustness of the AC system relative to the DC system in multi-infeed configuration. Meanwhile, through analyzing the factors [4] that affect the magnitude of MSCR of individual DC systems, the network structure of the receiving-end AC system can be optimized. This acts as the basis for developing a reasonable strategy that serves to optimize the selected infeed ends for multiple DC systems [5], thus enabling the AC network to provide stronger capability of supporting the UHV DC system.

3.3.4 Interaction Between UHV DC System and AC System 1. Voltage stability Numerous studies show that when considering the stability of a DC infeed system, irrespective of a long-distance transmission system or a back-to-back system, the voltage stability is always the greatest concern. Essentially, the voltage instability results from the fact that the reactive power supplied by the power system cannot meet demand or that the power transmission over a long distance reduces the system voltage to an unacceptable level. The DC system absorbs reactive power during commutation. When other conditions remain unchanged, the larger the DC power, the more reactive power the DC system will absorb and, consequently, the larger the voltage drop that the bus will experience. During normal operation, the reactive power consumed by the DC system is mainly supplied by reactive power compensation devices in converter stations, such as the AC filters and capacitors. In the event of a fault, transient voltage fluctuation will occur. Such change in operating conditions will cause variations in the output of the compensation devices. Whether these devices can supply sufficient reactive power needed by the DC system has a direct bearing on the magnitude of the reactive power exchanged between the AC and DC systems. If the AC system fails to support the dynamic reactive power variations of the DC system, then the AC system will suffer voltage instability. Because UHV DC systems generally transmit an enormous amount of power to load centers, they place higher requirements on the reactive power

Characteristics of UHV DC Transmission System 131 balancing capability and voltage stability of the receiving-end AC system. In addition, the blocking of a single pole or bipole may cause a large amount of power shift to AC interconnection circuits, leading to a significant increase in the amount of reactive power consumed by the AC system, and further compromising the AC system voltage stability. Therefore, during the power network planning and operation, the UHV DC system is required when possible to connect to the robust AC systems at the receiving end and to avoid a situation with too many DC systems terminating in the same region. When necessary, the dynamic reactive power capability of the AC system should be enhanced. 2. Frequency stability Because the DC system transmits a large amount of power that could account for a relatively large proportion of the demand at the receiving-end AC system, any faults occurring in the DC system, such as commutation failures, could lead to significant fluctuation in the transmitted DC power, causing a large shock to both sending and receiving AC systems and, consequently, compromising the system frequency stability. The power that can be transmitted by a DC system has an upper limit that depends on the mechanical inertia constant of the connected AC system. For a parallel AC/DC transmission system, the AC system is required to have a robust structure, large transmission capacity, and high stability margin. When a fault occurs in the DC system, a certain amount of power would be transferred to the AC interconnection lines, thus reducing the amount of generators to be tripped at the sending end and the demand to be disconnected at the receiving end. However, the AC interconnection lines and transformers are likely to be overloaded. Moreover, the AC system voltage may drop because of the increased power flow; therefore, measures should be taken to maintain it at a reasonable level to endure normal operation of the AC system and maintain commutation of the DC system. After a fault on the AC interconnection lines, it is possible to take advantage of the ramp-up, mid-term, and long-term overload capability of the DC system to reduce the load loss and improve system frequency stability. 3. Subsynchronous oscillation The experience gained in the system operation and theoretical analysis show that subsynchronous oscillation is more likely to occur in cases when steam turbine generator units are located near to the rectifier station than in cases when hydro turbine generator units are close to the inverter station. This is particularly the case when the DC system and steam turbine generator units have similarly rated capacities and are close to each other. For an islanded DC transmission system whose sending-end power sources mainly consist of steam turbine generator units, the subsynchronous oscillation problem will be more prominent and is a critical problem affecting the islanded operation. It is recommended in IEC 60919-3:1999 Performance of High-Voltage

132 Chapter 3 Direct Current (HVDC) Systems—Part 3: Dynamic Conditions that the unit interaction factor (UIF) should be used in screening analysis of the subsynchronous oscillations. The UIF is calculated using the following equation:   Pd SSC ðiÞ 2 UIF 5 (3.28) 12 SSC SG ðiÞ where SG(i)—rated capacity of the ith generator, MVA SSC(i)—three-phase short-circuit capacity at the converter bus at the rectifier side excluding the ith generator, MVA SSC—three-phase short-circuit capacity at the converter bus at the rectifier side including the ith generator, MVA. If the UIF is less than 0.1, then the probability of subsynchronous oscillation is considered to be low. The UIF method applies to circumstances in which the generators connected to the same bus have varying shaft mechanical characteristics, that is, they have different inherent torsional frequencies. In cases when multiple generators have the same shaft mechanical characteristics and inherent torsional frequency, the generators of the same type must be treated as an equivalent generator before the UIF method is applied.

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