THE UNIFIED POWER FLOW CONTROLLER - A CONCEPT BECOMES REALITY Colin Schauder

Siemens-Westinghouse, Pittsburgh, PA, U. S. A.

Introduction The Unified Power Flow Controller (UPFC) [2,3,9,16] is the first member of an emerging family of advanced Flexible AC Transmission System (FACTS) controllers that use multiple synchronous voltage sources (SVS) [4] operated conjunctively to optimize the use of electric power transmission networks. Each such SVS is typically an electronic voltage-sourced inverter that can be shunt-connected (STATCOM) [1,5-71 or series-connected (SSSC) [8,14] to the power network. A STATCOM or an SSSC can operate on its own, using the inherent ability to generate or absorb reactive power at its ac terminals. These devices are, however, unable to negotiate real power from the network unless they are equipped with an additional source or sink of real power at their dc terminals. This leads to the concept of joining multiple STATCOMs and/or SSSCs together at their dc terminals. The joined units are thus free to negotiate real power at their ac terminals, subject only to the constraint that the total average power at the dc bus must be zero. The dc bus interconnection can be performed between locally situated SVS units or, using a dc power line, between units that are separated by some distance. The UPFC combines a single STATCOM and a single SSSC. The Interline Power Flow Controller (IPFC) [ 1 j] combines two SSSCs in different (possibly asynchronous) lines; and the so- called Back-To-Back STATCOM scheme combines WO STATCOMs and provides dc power transmission between two (possibly asynchronous) ac buses.

I INERTER

NO2

(a) Single Line UPFC

' INVERTER

NO2 T t

(6) M u W e UPH:

I INVERTER INVERTER I NO. 1 NO2 I - -

(c) lntedine P o w ~ Flow Conbollu (IPFC)

(d) Back-To-Back STATCOM

Fig. 1. FACTS controllers using multiple inverters

Clearly there are many other possibilities for this family of equipment. For example, a single STATCOM can be combined with multiple SSSCs inserted in the different lines radiating from a substation. Figure 1 illustrates some of these schemes. The UPFC is the first of these multiple SVS concepts to have been successfully demonstrated in a working high power installation for American Electric Power at Inez, Kentucky in the U.S.A. [11-13,17]. This paper gives an overview of the practical aspects of UPFC design and operation. and illustrates the implementation of the equipment and the achievable performance with particular reference to the Inez installation. Basic Principle of the UPFC A simplified schematic of a UPFC is shown in Fig. 2. The main features are two inverters. one connected in series with the line through a series insertion transformer, and one connected in shunt with the line through a second transformer. The dc terminals of the two inverters are connected together and their common dc voltage is supported by a capacitor bank. The series inverter is used to inject a controlled voltage, Vinj , in series with the line and thereby to force the power flow to a desired value. In general, the series inverter will exchange real and reactive power with the line while performing this duty. The reactive power is electronically provided by the series inverter, and the real power is transmitted to the dc terminals. The shunt inverter is controlled in such a way as to provide precisely the right amount of real power at its dc terminals to meet the real power needs of the series inverter and to regulate the voltage, Vdc, of the dc bus. The shunt inverter derives this power from its connection to the ac bus. and its remaining capacity can be used to generate reactive power for regulation of the ac bus voltage. The UPFC thus offers the unique capability of independently regulating the real and reactive power flows (P and Q) on the transmission line, while also regulating the local bus voltage.

5 Mechanical p Tansmission l- Bypass + Line

Breaker

'p 'p

Opbmization Control

0 Control System F 1 Fig. 2. Block Diagram Showing the Main Elements of a UPFC

System UPFC Control A. Shunt Inverter The shunt inverter is operated in such a way as to draw a controlled current from the ac bus. The current reference is chosen to sarisfy the shunt reactive power reference and to provide any real power needed to balance the real power of the series inverter. A small amount of real power is also drawn to

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cover the power losses of the inverter and magnetics. The shunt reactive power reference can be either capacitive or inductive.

VAR Control Mode. In var control mode the reference input is a simple var request that is maintained by the control system regardless of bus voltage variation.

Automatic Voltage Control Mode. In voltage control mode, the shunt inverter reactive current is automatically regulated to maintain the transmission line voltage at the point of connection to a reference value, with a defined slope characteristic. The slope factor defines the per unit voltage error per unit of inverter reactive current within the current range of the inverter B. Series Inverter The series inverter controls the magnitude and angle of the voltage injected in series with the line. This voltage injection is always intended to influence the flow of power on the line. Two alternative modes can be used to determine the actual value of the injected voltage:

Voltage Injection Mode. The series inverter generates a voltage vector (across the line-side terminals of the insertion transformer) with magnitude and phase angle requested by reference input.

Automatic Power Flow Contra[ Mode. In automatic power flow control mode, the series injected voltage is determined automatically and continuously by a vector control system to ensure that the desired values of P and Q (looking into the transmission line) are maintained despite system changes. This is an extremely powefil mode of operation that has not previously been achievable with conventional line compensating equipment. C. Control Block Diagrams The mode of operation that most clearly shows the capabilities of the UPFC is with the shunt inverter in automatic voltage control and the series inverter in automatic power flow control. Consequently a control block diagram is shown in Fig. 3, giving greater detail of these control schemes. For clarity only the most significant features are shown.

Fig. 3. Control block diagram for shunt inverter in voltage control mode and series inverter in power flow control mode.

Design Considerations Figure 2 shows the main power circuit components for the UPFC. There are several overriding constraints that apply to the design of these components:

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Series Inverter Overcurrent Protection. GTO-based inverters are limited in their peak turn-off current capability and also typically have limited rated continuous current capability. Since the line current defines the series inverter current, it is to be expected that, under certain fault conditions, the line current may exceed the inverter capability and it will not be able to operate normally. The inverter must be designed so that it is able to turn off its GTO valves safely at the onset of the high current condition, and, in addition, the elevated current must be diverted while inverter operation is suspended so that it does not overcharge the dc bus capacitors. Typically, the mechanical bypass breaker provided on the line side of the insertion transformer is not fast enough to divert the fault current and protect the inverter. Consequently an additional fast (electronic) bypass switch is required. This may be located across the primary or secondary terminals of the insertion transformer. If the system fault capacity is suficiently low, it may be possible to use the inverter valves to provide the electronic bypass function.

Common DC Bus Voltage. The two inverters are joined at the dc terminals and must therefore be able to operate under all conditions with a common dc bus voltage. Since the shunt inverter always generates an output voltage roughly equal to the ac bus voltage, and the series inverter must vary its output voltage from zero to maximum, it follows that at least the series inverter must be capable of freely controlling the ratio between the dc voltage and its ac output voltage. If the shunt inverter has similar capability, then the dc-bus voltage can be set at a constant nominal high value. Otherwise the dc bus voltage will vary somewhat with shunt inverter loading, causing some change in the maximum ac output voltage available from the series inverter.

Real Power Exchange. Real power will typically be required to flow between the two inverters through the dc bus. The maximum value for this power must be determined from system load flow studies, so that adequate buswork can be provided. Furthermore, the flow of real power through the inverters implies that they can operate at any terminal power factor. The inverter valves must be designed for worst case duty cycles resulting from this freedom. When considering the rating of the shunt inverter, the maximum continuous current loading is obtained from the quadrature combination of the real and reactive current loading of the inverter.

Series Inverter Current Ratinn. Unlike the shunt inverter, where the controls determine inverter current, the series inverter current is essentially defined by the transmission line current. The MVA rating of the series inverter is thus obtained from the product of maximum line current (at which the inverter is required to operate) and maximum series injected voltage. This rule applies irrespective of whether the maximum injected voltage and maximum operating line current would ever occur simultaneously.

Constraints on Series Injected Voltage The magnitude of the series injected voltage, Vin' is limited by the maximum voltage rating of the inverter and 'its associated series insertion transformer. The maximum value for Vin' may be constant, or may vary slightly with changes in the bc bus voltage, depending on the inverter design. In general, values of Vinj with magnitude below the maximum can be supplied at any phase angle, resulting in a circular range of achievable values for (Vi + Vinj) as illustrated in Fig. 4.

BOUNDARY OF BOUNDARY OF ACHIEVABLE RANGE

,. - __---e MINIMUM SHADED AREA IS THE

ALLOWABLE ACHIEVABLE

ALLOWABLE RANGE FOR V,

(FOR A PARTICULAR L?5!Js’ 77- VALUE OF I,,,,.)

l,i, AND v2

Fig. 4. Effect of Constraints on the Final Range of V2

Note that the series insertion transformer has an associated leakage inductance, XL , Thus Vin, is not precisely the voltage, V21, that appears across the primary terminals of the transformer, but rather V21 = ( Vinj - jIlineXL ). Clearly the primary terminal voltage is determined not only by the inverter but also by the prevailing line current. In Fig. 3 the circular range of achievable values for V2 = ( Vi + Vinj - jIlineXL ) is illustrated for an arbitrary value of Iline. This range changes as the line current changes. Another important limitation on the operation of the series inverter arises if it is necessary to limit the allowable range of voltage, V2, in magnitude. In most applications the UPFC will be located in a substation, where Vi will be the voltage at the regulated substation bus, and V2 will be the voltage on the outgoing line side of the equipment. The UPFC has the intrinsic ability to raise or lower the magnitude of V2 by a large fraction (50% in Fig. 3). This can present a problem simply from the point of view of voltage stresses on the line, or if the line would be tapped for any purpose. In general, therefore, it will be necessary to impose some limits on the allowable magnitude of V2. Clearly, if both Vi and V2 were to be tightly regulated in magnitude, then the only tolerable values of V21 would be those that produce angle shifts between these two voltages. Usually it is acceptable to permit some variation in the magnitude of V2 and this restriction is enforced electronically by the UPFC control system. Fig. 3 shows an upper and lower limit locus for Vz superimposed on the plot of achievable range for V2. The resulting shaded area of intersection represents the achievable and allowable range for V2 under the line current condition illustrated. The UPFC control system is responsible for staying within this region, irrespective of the operating mode chosen for the equipment.

Inez UPFC Project AEP selected the Inez area, located in the south central part of the AEP System, for the application of a UPFC because of the critical need to increase power transfer capability and provide voltage support in this area. An integral part of the project was the construction of a new 32-mile high capacity double circuit line between Big Sandy and Inez Stations. This 138 kV line has an ultimate thermal capability of carrying about 950 MVA. The W F C is connected in series with the new line at Inez, and is primarily intended to provide voltage regulation at Inez and to boost the power flow from Big Sandy under certain contingency conditions SO that the full thermal capability of the line can be utilized. The main features of the equipment are the two +!60 MVA inverters which respectively provide the shunt and series SVS for UPFC operation. Each inverter is of the three-level type, comprising multiple ”pole” structures, each carrying 4 GTO- thyristor valves. Each valve in turn comprises a string of eight or nine 4000 A, 4500 V, GTO-thyristors connected in series. These pole structures are grouped in four three-high stacks in the valve hall of the site building to make a single inverter. The shunt and series inverters stand adjacent to each other in the valve hall, separated by a protective wall. Also indoors, behind the two inverters, are the associated dc-busses and dc capacitor banks. The inverters feed overhead ac busses that pass through the building wall and connect to transformers located outdoors. Each inverter has an associated intermediate transformer for waveform shaping, as well as a main transformer used for coupling into the transmission line. The series inverter is rated to inject up to 0.16 p.u. voltage into the transmission line, with a nominal line current of 4000 A. Central controls for the two inverters are housed in a separate control room within the main building and communicate with the poles exclusively through optical fiber cables. Fig. 5 shows an aerial view of the site, where the building (housing power electronics and control), and the outdoor transformers and buswork, are visible. The transmission line towers for the Inez-Big Sandy line can clearly be seen in this picture. Figure 6 shows a view of the two inverters inside the valve hall. Figure 7 is a simplified one-line diagam of the Inez Substation, showing the main elements of the UPFC and their inter- connection with switchgear and other components. Note in particular that, in addition to the main shunt and series coupling transformers (TR2 and TR4 respectively), an additional shunt coupling transformer (TR3) is provided. This additional transformer can be energized by either inverter No. 1 or inverter No. 2. It can thus serve as a spare for TR2 or, altematively, can be operated with inverter No. 2 as a second shunt-connected inverter, giving a total of 5320 Mvar shunt reactive capability.

Fig. 6 View of the two *I60 MVA GTO-based inverters ~ _ ” . U

Fig. j Aerial view of the Inez Substation

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Fig. 7 One-line diagram of UPFC instaIIation at Inez.

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Fig. 9. UPFC Holding unity power factor.

Measured UPFC Performance In the course of commissioning the Inez UPFC, tests were performed to verify its predicted capability. For this purpose, the UPFC was directed to produce large controlled swings of real and reactive power on the Big Sandy line, and significant swings of voltage at the Inez station, while measurements were recorded. For these tests the shunt inverter was in automatic voltage control mode and the series inverter in automatic power flow control mode. Measured data was available from the UPFC control system and was recorded at one second intervals, using the sign convention defined in Fig. 8.

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Fig. 10. UPFC changing reactive power (Q).

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Of the many different cases recorded, two representative cases have been selected for inclusion here. The first of these, shown in Fig. 9, shows the UPFC maintaining unity power factor looking into the transmission line, while producing large swings in real power, P, on the line, and also maintaining the Inez bus at 1 p.u. This case demonstrates the ability of the UPFC to keep Q constant (zero in this case), while simultaneously varying the real power transmitted. It is of particular interest because driving a line at unity power factor makes it possible to deliver the largest amount of real power into the line for the lowest current. This should result in the most efficient use of the line from a thermal point of view. Figure 10 shows the second case in which the UPFC is instructed to produce large swings in Q on the Big Sandy line while maintaining constant real power flow, P, and regulating the Inez bus voltage to 1 p.u. Note that the changes in Q at the line terminals are balanced almost entirely by equal and opposite changes in the reactive output of the shunt inverter, which acts to maintain the Inez voltage. The reactive power generated at Inez is thus “exported” down the Big Sandy line without changing the voltage at Inez, C d without changing the reactive power on any of the other lines leaving the substation. The UPFC can therefore regulate the station bus voltages at both the sending and receiving ends of a transmission line, while still freely controlling the real power flow, P, on the line.

INEZ A-PHASE VOLTAGE (PU) I 1 I I 1

Performance under unbalanced fault conditions The performance of the UPFC under fault conditions was studied during the design stage using an analog TNA model of the UPFC equipment and an extensive model of the AEP network. A comprehensive discussion of these tests is beyond the scope of this paper, but two representative cases are included here to show how the equipment responds to disturbed system conditions. The first case shown is for a line-to-line-to- ground fault at the Big Sandy generating station (about 30 miles from Inez). Figure 11 shows the response of the shunt inverter, which is initially operating in automatic voltage control mode at its capacitive limit (160 Mvar). At the onset of the fault the two phase voltages at Inez are severely depressed. The shunt inverter continues to operate through the fault, providing approximately rated capacitive output current and helping to support the Inez voltage. The inverter output current shows a small amount of positive sequence third harmonic content while the fault persists. The calculated megavar output of the shunt inverter during the fault shows a drop commensurate with the drop in the Inez positive sequence bus voltage, as would be expected. Figure 12 shows the second case, a single line to ground fault at Big Sandy, with the same initial operating conditions. Once again the shunt inverter provides useful output during the fault. In this case the megavar output is higher during the fault because of the relatively higher positive sequence bus voltage.

IN= A-PHASE VOLTAGE lPUl 1

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SHUNT INVERTER OUTPUT (Mvar) a 1 I I

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Fig. 12. Shunt inverter response to a single line to ground fault at Big Sandy station.

Conclusion With the commissioning of the Inez installation, the UPFC has now completed the transition from concept to a working high power equipment. All of the predictions resulting from extensive modeling efforts have been verified, and it has been demonstrated that the UPFC can indeed control the P and Q on a transmission line independently while simultaneously regulating the local ac bus voltage. This opens the door to a variety of possible solutions for power flow control using multiple inverters connected through a common dc bus. Utility system planners now face a considerable challenge as they consider how and where to apply these controllers and how to represent them in models for planning studies. Acknowledgement The Inez UPFC project referred to in this paper was jointly undertaken by American Electric Power (AEP), the Electric Power Research Institute (EPRI), and Westinghouse Electric Corporation (now Siemens). The author would like to acknowledge the efforts of the many individuals in these organizations who have contributed to the success of the project, including Dr. A. Keri and Mr. A. Mehraban (AEP), Dr. A. Edris (EPRI), and Mr. L. Kovalsky and Dr. L. Gyugyi (Siemens). References [l] S. Mori et al.. "Development of Large Static VAR Generator

Using Self-Commutated Inverters for Improving Power System Stability," IEEE, PES Winter Power Meeting, Paper No. 92WM165-1, 1992.

[2] L. Gyugyi, "A Unified Power Flow Control Concept for Flexible AC Transmission Systems," IEE Proceedings-C, Vol. 139, No.4, July 1992.

[3] L. Gyugyi et al., "The Unified Power Flow Controller: A New Approach to Power Transmission Control," IEEE Transactions on Power Delivery, Vol. 10, No. 2, April 1995.

[4] L. Gyugyi, "Dynamic Compensation of AC Transmission Lines by Solid-state Synchronous Voltage Sources," IEEE, PES Summer Power Meeting, Paper No. 93 SM 434-1 PWRD, 1993.

[SI C. Schauder et al., "Development of a &IO0 WAR Static Condenser for Voltage Control of Transmission Systems," IEEE, PES Summer Power Meeting, Paper No. 94 SM 479- 6 PWRD, 1994.

[6] F. Ichikawa et al.,"Operating Experience of a 50 MVA Self- Commutated SVC at the Shin-Shinano Substation," Proceedings of International Power Electronics Conference (IPEC), Tokyo, 1995.

[7] C. Schauder et al., "TVA STATCON Project: Design, Installation and Commissioning," CIGRE Paper 14-1 06, 1996.

[8] L. Gyugyi et al., "Static Synchronous Series Compensator: A Solid-State Approach to the Series Compensation of Transmission Lines," IEEE, PES Winter Power Meeting, Paper No. 96 WM 120-6 PWRD, 1996.

[9] C. D. Schauder et al., "Operation of the Unified Power Flow Controller (UPFC) Under Practical Constraints," IEEE, PES Winter Power Meeting, 1997, Paper No. PE-

[lo] C. Schauder et al., "Operation of +/-lo0 Mvar TVA STATCON," IEEE, PES Winter Power Meeting, 1997 , Paper No. PE-509-PWRD-0-01-1997.

[I I] A. S. Mehraban et al., "Application of the World's First UPFC on the AEP System," EPRI Conference - The Future of Power Delivery, Washington DC, April 9-1 1, 1996.

[12] M. E Rahman, "Unified Power Flow Controller on the AEP System - System Studies and Planning Considerations," EPRI Conference - The Future of Power Delivery, Washington DC, April 9-1 1, 1996.

51 1-PWRD-0-11-1996.

[13] C. Schauder et. al., "AEP UPFC Project: Installation, Commissioning, and Operation of the +160 MVA STATCOM (Phase I)," IEEE, PES Winter Power Meeting, 1998, Paper No. PE-515-PWRD-0-12-1997.

[I41 K. Sen, "SSSC - Static Synchronous Series Compensator: Theory, Modeling, and Applications," IEEE Transactions on Power Delivery, Vol. 13, No. 1, January 1988, Paper

[I51 L. Gyugyi et al., "The Interline Power Flow Controllpr Concept: A new Approach to Power Flow Management in Transmission Systems," IEEE, PES Summer Meeting, 1998, Paper No. PE-3 16-PWRD-0-07-1998

[I61 K. Sen et al, "UPFC - Unified Power Flow Controller: Theory, Modeling, and Applications," - IEEE, PES Winter Meeting, 1997, Paper No. PE-282-PWRD-0- 12- 1 997.

[17] B. A. Rem et al., "World's First Unified Power Flow Controller on the AEP System" CIGRE Paper 14-107, 1998.

NO. PE-862-PWRD-0-04-1997.

0 1998 The Institution of Electrical Engineers. Printed and published by the IEE, Savoy Place, London WCOR OBL, UK.

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