Comparing Two Ways of Congestion Management in

Bilateral Based Power MarketVahraz Zamani Farahani Ahad Kazemi

Iran University of Science and Technology

Tehran-Iran

ABSTRACT — The restructuring of the electric powerindustry has involved paradigm shifts in the real timecontrol activities of the power grids. Managing dispatch isone of the important control activities in a power system.With the trend of an increasing number of bilateralcontracts being signed for electricity market trades, thepossibility of insufficient resources leading to networkcongestion may be unavoidable. In this scenario, congestionmanagement becomes an important issue. Real-timetransmission congestion can be defined as the operatingcondition in which there is not enough transmissioncapability to implement all the traded transactions.It may be alleviated by incorporating line capacityconstraints in the dispatch and scheduling process. Thismay involve redispatch of generation or load curtailment.Other possible means for relieving congestion are operationof FACTS devices (TCSC) ,these two ways are compared inthis paper.Index Terms — Congestion Management, Deregulation

,Bilateral Power Market, FACTS devices, TCSC, ISO.

I. INTRODUCTION

The changing nature of electricity supply industry isintroducing many new subjects into power systemoperation related to trading in a deregulated ,competitive market .Commercial pressures on obtaininggreater returns from existing asset suggests anincreasingly important role for dynamic networkmanagement using FACTS devices[1] . In this situation,congestion management becomes an important issuebecause it can make a penalty for market players. Thecongestion management in deregulated power systemcan be solved by load curtailment and using extradevices such as FACTS devices or phase shifters. Thesesolutions will be discussed in forward.[2]

FACTS devices offer a fast series and parallelscompensation and offer flexible power system control[6]-[9]-[12]-[14]-[15], therefore, it can be utilized tocontrol line active and reactive power, achieve morepower transfer capability, and to significantly improvepower system reliability.In a competitive power marketscenario, besides generation, loads, and line flows,contracts between trading entities also comprise the

system decision variables. The following pool andbilateral competitive structures for the electricity markethave evolved:1) Single auction power pools, where wholesale sellers(competitive generators) bid to supply power in to asingle pool. Load serving entities (LSEs or buyers) thenbuy wholesale power from that pool at a regulated priceand resell it to the retail loads.2) Double auction power pools, where the sellers put intheir bids in a single pool and the buyers then competewith their offers to buy wholesale power from the pooland then resell it to the retail loads.3) In addition to combinations of (1) and (2), bilateralwholesale contracts between the wholesale generatorsand the LSEs without third-party intervention.4) Multilateral contracts, i.e., purchase and saleagreements between several sellers and buyers, possiblywith the intervention of third parties such as forwardcontractors or brokers [2]-[4]. In both (3) and (4) the price-quantity trades are up tothe market participants to decide, and not the ISO. Therole of the ISO in such a scenario is to maintain systemsecurity and carry out congestion management. Thecontracts, thus determined by the market conditions, areamong the system inputs that drive the power system.The transactions resulting from such contracts may betreated as sets of power injections and extractions at theseller and buyer buses, respectively. In this paper , at first , the two different structures ofrestructured power system has been mentioned such aspool structure and bilateral structure then the bilateralstructure has been chosen for further research. The twodistinct ways for solving the congestion problem hasbeen declared. At the end these solution have beenexamined and compared by curtailment and usingFACTS devices.

II.TWO MODELS OF DEREGULATED POWERSYSTEM

Two different way of power system operation in

Restructured power system is mentioned below:

A. Pool Structure

Interconnected system operation becomes significantin a deregulated environment. This is because the marketplayers are expected to treat power transactions ascommercial business instruments and seek to maximizetheir economic profits. Now when several gencos decideto interchange power, complications may arise. Aneconomic dispatch of the interconnected system can beobtained only if all the relevant information, viz.,generator curves, cost curves, generator limits,commitment status, etc., is exchanged among all thegencos. To overcome this complex data exchange andthe resulting nonoptimality, the gencos may form apower pool regulated by a central dispatcher. The lattersets up the interchange schedules based on theinformation submitted to it by the gencos. While thisarrangement minimizes operating costs and facilitatessystem-wide unit commitment, it also leads to severalcomplexities and costs involved in the interaction withthe central dispatcher [2]. Conventionally, the optimaloperation of a power system has been based on theeconomic criterion of loss minimization, i.e.,maximization of societal benefit. Pool dispatch followsthe same criterion but with certain modificationsnecessitated by the coexistence of the pool market with ashort-term electricity spot market. Namely, these effectsare demand elasticities and the variation in the spot pricewith the purchaser’s location on the grid. The existenceof the spot market or bilateral market behind the scenedoes not explicitly affect the operation of the ISO.[3]

B. Bilateral Structure

The conceptual model of a bilateral market structureis that gencos and discos enter into transaction contractswhere the quantities traded and the prices are at theirown discretion and not a matter for the ISO; i.e., abilateral transaction is made between a genco and adisco without third party intervention. These transactionsare then submitted to the ISO.In the absence of any congestion on the system, the ISOsimply dispatches all the transactions that are requested,making an impartial charge for the service.The bilateralstructure has been selected in this paper for research.[3]

III. TWO METHODS FOR CONGESTION MANAGEMENT

There are two broad paradigms that may be employedfor congestion management. These are the cost-freemeans and the not-cost-free means [5]. The formerinclude actions like outaging of congested lines oroperation of transformer taps, phase shifters, or FACTSdevices. These means are termed as cost-free onlybecause the marginal costs (and not the capital costs)

involved in their usage are nominal. The not-cost-freemeans include:1) Rescheduling generation. This leads to generationoperation at an equilibrium point away from the onedetermined by equal incremental costs. Mathematicalmodels of pricing tools may be incorporated in thedispatch framework and the corresponding cost signalsobtained. These cost signals may be used for congestionpricing and as indicators to the market participants torearrange their power injections/extractions such thatcongestion is avoided.2) Prioritization and curtailment of loads/transactions. Aparameter termed as willingness-to-pay-to-avoid-curtailment was introduced in [4]. This can be aneffective instrument in setting the transaction curtailmentstrategies which may then be incorporated in the optimalpower flow framework.

IV. DISPATCH FORMULATION WITHCUTAILMENT STRATEGY AND USING FACTS

A. Bilateral dispatch formulation with CurtailmentStrategy

In a bilateral market mode, the purpose of the optimaltransmission dispatch problem is to minimize deviationsfrom transaction requests made by the market players.The goal is to make possible all transactions withoutcurtailments arising from operating constraints.The new set of rescheduled transactions thus obtainedwill be closest to the set of desired transactions, whilesimultaneously satisfying the power flow equations andoperating constraints. One of the most logical ways ofrescheduling transactions is to do it on the basis ofrationing of transmission access. This may be modeledas a user-pay scheme with “willingness-to-pay”surcharges to avoid transmission curtailment. Themathematical formulation of the dispatch problem maythen be given as:

Min f(x,u)where

( ) ( )[ ] ( )[ ]TTT AuuWAuuxuf ...., 00 −−= (1)

subject to:g(x,u)=0h(x,u) ≤ 0

where

W is a diagonal matrix with the surcharges as elementsA is a constant matrix reflecting the curtailmentstrategies of the market participantsu and uo are the set of control variables, actual anddesiredx is the set of dependent variables

g is the set of equality constraints, viz., the power flowequations and the contracted transaction relationships.h is the set of system operating constraints includingtransmission capacity limits.

The bilateral case can be modeled in detail. Weconsider transactions in the form of individual contractswhere a seller i injects an amount of power Tij at onegenerator bus and the buyer j extracts the same amountat a load bus. Let the power system consist of n useswith the first m assumed to be seller buses and theremaining n-m as buyer buses. One particular bus (bus 1)may be designated as the slack to take into accounttransmission losses. The total power injected/extracted atevery bus may be given by the summation of allindividual transactions carried out at those buses, thus:

For i=2 to m, Pi=∑ TijFor j=m+1 to n, Pj=∑ Tij (2)

The transactions Tij also appear in the power flowequality constraints since they act as the controlvariables along with the usual generator bus voltages.The set of control variables can thus be represented asu={∑ Tij ,V}T ,where V is the vector of generator busvoltages.

The real and reactive power flow equations can bewritten in the usual form represented by g(x,u).

The transaction curtailment strategy is implementedby the ISO in collaboration with the market participants.In the case of bilateral dispatch, this strategy concernsthe individual power contracts. One such strategy is suchthat, in case of an individual contract, the curtailment ofthe transacted power injected at the genco bus mustequal the curtailment of the transacted power extractedat the disco bus.

In this case, we may rewrite the dispatch formulation as

Min f(x,u)

where

( ) ( )20

12

., ijijij

n

mj

m

i

TTwuxf −= ∑∑+==

(3)

wij = the willingness to pay factor to avoid curtailment oftransaction

0ijT = the desired value of transaction Tij.

B. Bilateral Dispatch Formulation with FACTSDevices

In this part we look at treating congestionmanagement with the help of flexible AC transmission(FACTS) devices. We consider an integrated approachto incorporate the power flow control needs of FACTS

in the OPF problem for alleviating congestion. Theconcept of flexible AC transmission systems (FACTS)was first proposed by Hingorani [9]. FACTS deviceshave the ability to allow power systems to operate in amore flexible, secure, economic, and sophisticated way.Generation patterns that lead to heavy line flows result inhigher losses, and weakened security and stability. Suchpatterns are economically undesirable. So many FACTSdevices have been mentioned in many papers such asTCSC , TCPAR, UPFC, SVC, STATCOM ,…[1]-[9]. Inthis paper Thyristor-controlled series compensators(TCSC) was selected for evaluation. Combinations ofgeneration and demand unviable due to the potential ofoutages. In such situations, FACTS devices may be usedto improve system performance by controlling the powerflows in the grid. Studies on FACTS so far have mainlyfocused on device developments and their impacts on thepower system aspects such as control, transient andsmall signal stability enhancement, and damping ofoscillations [10]-[13]. With the increased presence ofindependent gencos in the deregulated scenario, theoperation of power systems would require moresophisticated means of power control. FACTS devicescan meet that need.

For the optimal power dispatch formulation usingFACTS controllers, only the static models of thesecontrollers have been considered here [4]. It is assumedthat the time constants in FACTS devices are very smalland hence this approximation is justified.

Thyristor-controlled series compensators (TCSC) areconnected in series with the lines. The effect of a TCSCon the network can be seen as a controllable reactanceinserted in the related transmission line that compensatesfor the inductive reactance of the line. This reduces thetransfer reactance between the buses to which the line isconnected. This leads to an increase in the maximumpower that can be transferred on that line in addition to areduction in the effective reactive power losses. Theseries capacitors also contribute to an improvement inthe voltage profiles.Fig.1. shows a model of atransmission line with a TCSC connected between busesi and j. The transmission line is represented by itslumped π-equivalent parameters connected between thetwo buses. During the steady state, the TCSC can beconsidered as a static reactance -jxc. This controllablereactance, xc, is directly used as the control variable tobe implemented in the power flow equation.

Fig.1. Model of a TCSC

Let the complex voltages at bus i and bus j be denoted asVi <δi and Vj <δj, respectively.The complex power flowing from bus i to bus j can beexpressed as

ijijijijij IVjQPS ** =−=

( ) ( )[ ]ciijjii jBVYVVV +−= *

( )[ ] ( )ijijjicijiji jBGVVBBjGV +−++= *2 (4)

Where( )CLLijij jXjXRjBG −+=+ /1 (5)

Equating the real and imaginary parts of the aboveequations, the expressions for real and reactive power :

( ) ( )jiijjijiijjiijiij BVVGVVGVP δδδδ −−−−= sincos2

( ) ( ) ( )jiijjijiijjicijiij BVVGVVBBVQ δδδδ −+−−+−= cossin2

(6)Similarly, the real and reactive power flows from bus j tobus i will be reversed in notation. The active andreactive power loss in the line can be calculated as

jiijL PPP +=

( )jiijjiijjiji GVVGVGV δδ −−+= cos222

jiijL QQQ +=

( ) ( ) ( )jiijjicijjciji BVVBBVBBV δδ −++−+−= cos222

(7)These equations are used to model the TCSC in the

OPF formulations.The optimal dispatch is comprised ofcomplete delivery of all the transactions and thefulfillment of pool demand at least cost subject tononviolation of any security constraint. It may beassumed that the ISO provides for all loss compensationservices and dispatches the pool power to compensatefor the transmission losses, including those associatedwith the delivery of contracted transactions. The normaldispatch problem is rewritten here as

Min { Pgi, Pdj } ∑ Ci(Pgi) -∑ Bj(Pdj) (8)

subject to:

g(PG, PD,TK ,Q ,V, δ ,F)=0h(PG, PD,TK ,Q ,V, δ ,F) ≤0

where PGi and PDj are the active powers of poolgenerator i with bid price Ci and poolload j with offer price Bj, respectively.If only bilateral transactions are considered, we mayrewrite the dispatch formulation as

Min f(x ,u)Where :

( ) ( )20

12

., ijijij

n

mj

m

i

TTwuxf −= ∑∑+==

(9)

subject to the real and reactive power balance equations

( ) 0)( =−−++ iDCFinjiG PPPPP

iii

( ) 0)( =−−++ iDCF

injiG QQQQQiii

(10)wheren number of buses in the power system, with the first mbuses being gencosand the rest, discoswij the willingness to pay factor to avoid curtailment oftransaction

0ijT the desired value of transaction Tij

iGP ,iGQ are the real and reactive power generation at

genco i.

iDP ,iDQ are the real and reactive load demand at disco

i.

iCP ,iCQ are the real and reactive load curtailment at

disco i.

iP ,

iQ are the real and reactive power injection at bus

i.FinjiP )( , F

injiQ )( are the real and reactive power injectionat bus i, with the installation of FACTS device.

We look at static considerations here for theplacement of FACTS devices in the power system,andour method based on the sensitivity of the total systemreactive power loss (QL) with respect to the controlvariables of the FACTS devices. we consider thefollowing control parameters: net line series reactance(Xij) for a TCSC placed between buses i and j. Thereactive power loss sensitivity factors with respect to thiscontrol variables may be given as follows:

ij

Lij X

Qa∂∂

= (11)

Loss sensitivity with respect to control parameter Xijof TCSC placed between buses i and j.This factor can becomputed for a base case power flow solution. Considera line connected between buses i and j and having a netseries impedance of Xij, that includes the reactance of aTCSC, was written in below:

( )[ ]( )222

2222 .cos2

ijij

ijijjijiji

ij

L

XR

XRVVVV

XQ

+

−−−+=

∂∂ δδ (12)

V. TEST RESULTS

We consider a six-bus system representing aderegulated market with bilateral transactions. An OPF

will be solved for this system to determine the optimalgeneration schedule that satisfies the objective ofminimizing deviations from the desired transactions.

Fig.2. shows the system network configuration. Buses1 and 2 are genco buses and, being PV buses, thevoltages here are specified exactly. At the other buses,the allowable upper and lower limits of voltage arespecified. The losses are assumed to be supplied only bythe generator at bus 1. Table I. provides the system datapertaining to generation and load. In appendix providesthe system network data.

Fig. 2. Six bus system configuration

TABLE ISYSTEM DATA

Voltage p.u.Generator CostCharacteristic, $/hr

GenerationCapacity, MW

Bus

1.05P12+8.5P1+5100 ≤ P1 ≤ 4001

1.063.4P22+25.5P2+950 ≤ P2 ≤ 2002

0.9 ≤ V≤ 1.1--3

0.9 ≤ V≤ 1.1--4

0.9 ≤ V≤ 1.1--5

0.9 ≤ V≤ 1.1--6

A. Test Results with Curtailment Strategy

In this case, bilateral contracts have been consideredbetween each genco and each disco.Table II shows thedesired power transactions.Three strategies for the curtailment of transactions areadopted for congestion management:1) The curtailment on the disco loads is assumed to belinear. In this case, all the willingness to pay factors aretaken to be equal.2) Same as case (1), except that the willingness to payprice premium of loads on buses 1 to 3 is assumed to betwice that of loads on buses 4 to 6.

3) In this case, the price premium of loads on buses 4 to6 is assumed to be twice that of loads on buses 1 to 3.Power flow solution was done by PSAT. Table III showsthe constrained generation and load data obtained fromthe OPF solution. It can be seen that the willingness topay and the participants’ curtailment strategy are twofactors that significantly affect the constrained dispatch.The higher the willingness to pay, the less is thecurtailment of that particular transaction. Thecurtailment strategies implemented have complexeffects. These factors not only affect the curtailment ofits own transaction, but will also impact that of othertransactions

TABLE II. DESIRED TRANSACTIONS BEFORE

CURTAILMENTDesired transactions,

MWBus

#20.0130.0235.0350.0442.0555.06

.TABLE III.

CONSTRAINED GENERATION AND LOAD DATAAFTER RUNNING POWER FLOW

Constrained generation and load, MWBus#

Case (1) Case (2) Case (3)1 109.63 109.62 109.682 124.24 124.41 123.603 34.72 34.93 33.954 48.87 48.86 48.945 40.74 40.72 40.816 53.99 53.97 54.05

B. Test results with FACTS devices

The criteria for deciding device location might bestated as follows that TCSC must be placed in the linehaving the most positive loss sensitivity index aij. Thelines having the most positive loss sensitivity index mustbe chosen for placement of the TCSC devices. For thiswe select lines 5 and 6 from Table IV.

When TCSC devices in the inductive mode ofoperation are connected in series with these two lines,with inductive reactances of 53.6% and 48.2% of theline reactances, espectively, it is seen that the lineoverloads are removed. The effect of optimal powerdispatch with the TCSC devices installed on the lineflows is shown in Table V.

The constrained generation and load data may beobtained after running the OPF with the TCSC installed.Table VI shows a comparison between the data obtainedwith and without FACTS devices in the system for oneparticular curtailment strategy employed by the ISO(Case (1)).

TABLE IVVAR LOSS SENSITIVITY INDEXES

Sensitivity indexTo busFrombus

Line

a14 = -0.179411a16 = -0.123612a23 = -0.23323a25 = -0.15524

a34 = -0.0189435a46 = -0.0184646a56 = -0.044657

TABLE VLINE FLOWS

Line flow (in p.u.)WithTCSC

WithoutTCSC

RatedTobus

Frombus

Line

0.1760.1380.504110.3860.3830.506120.4940.4800.503230.1620.1320.805240.4830.620.574350.4180.5620.556460.0270.0250.30657

TABLE VIOPF RESULTES WITH OR WITHOUT TCSC

Constrained generation and load, MW, Case (1) of3.3.3

With TCSCWithout TCSC

Bus#

109.72109.631124.41124.24234.9634.72349.1448.87441.3240.74553.9953.996

This integrated framework covers the scenario where,even after putting the FACTS devices into operation,there is a need for the ISO to curtail the initial powertransactions in order to maintain the system operationwithin security limits.The OPF result shows that the individual powertransactions suffer less curtailment when FACTS devicesare included in the system.

VII. CONCLUSION

The operational aspects of power systems pose someof the most challenging problems encountered in therestructuring of the electric power industry. In this paperwas looked at one such problem as congestionmanagement becomes an important issue because it canmake a penalty for market players. Congestionmanagement can be solved by curtailment loads or usingFACTS devices. Comparative case studies with andwithout FACTS devices show the efficacy of FACTSdevices in alleviating congestion. Optimal placement ofthese devices leads to improved congestion reductionand less curtailment in the desired power transactions.The bilateral dispatch functions of an ISO are dealt with.This paper then focused on the use of FACTS devices(TCSC) to alleviate congestion. From the case studiescarried out in this report, it was apparent that theinteractions between market players are complex. Anintegrated approach that includes FACTS devices in abilateral dispatch framework to maintain system securityand to minimize deviations from contractualrequirements is then proposed. The approach is validatedthrough numerical examples.

APPENDIXE

SYSTEM NETWORK DATALine chargingadmittance, pu

Reactance,pu

Resistance,pu

From bus– to bus

0.0030.18040.06621-40.0050.29870.09451-60.0040.10970.02102-30.0040.27320.08242-50.0050.31850.10703-40.0010.17920.06394-60.0040.09800.03405-6

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