The droop-controlled grid-forming sources are well known for robust voltage and frequency control and the ability to balance power between multiple sources in a microgrid. However, these sources may become overloaded with the possibility of collapsing the microgrid. This paper presents an overload mitigation control strategy which can autonomously transfer the extra load of the overloaded source to other sources without communications. The main advantages of this control strategy are that it maintains voltage control of the overloaded sources and does not need to switch between grid-forming control and grid-following control. A small signal model is established to study the system stability. Simulation and on-site test results verify the effectiveness of this control strategy.

1 aDu, Wei1 aLasseter, Robert, H. uhttp://ieeexplore.ieee.org/document/8274300/http://xplorestaging.ieee.org/ielx7/8263544/8273724/08274300.pdf?arnumber=827430001890nas a2200193 4500008003900000245009300039210006900132260001200201300001000213520126900223653001301492100002301505700001601528700002201544700002201566700002001588700001701608856007101625 2016 d00aOptimal Pricing to Manage Electric Vehicles in Coupled Power and Transportation Networks0 aOptimal Pricing to Manage Electric Vehicles in Coupled Power and c07/2016 a1 - 13 aWe study the system-level effects of the introduction of large populations of Electric Vehicles on the power and transportation networks. We assume that each EV owner solves a decision problem to pick a cost-minimizing charge and travel plan. This individual decision takes into account traffic congestion in the transportation network, affecting travel times, as well as congestion in the power grid, resulting in spatial variations in electricity prices for battery charging. We show that this decision problem is equivalent to finding the shortest path on an "extended" transportation graph, with virtual arcs that represent charging options. Using this extended graph, we study the collective effects of a large number of EV owners individually solving this path planning problem. We propose a scheme in which independent power and transportation system operators can collaborate to manage each network towards a socially optimum operating point while keeping the operational data of each system private. We further study the optimal reserve capacity requirements for pricing in the absence of such collaboration. We showcase numerically that a lack of attention to interdependencies between the two infrastructures can have adverse operational effects.

10aRM11-0071 aAlizadeh, Mahnoosh1 aWai, Hoi-To1 aChowdhury, Mainak1 aGoldsmith, Andrea1 aScaglione, Anna1 aJavidi, Tara uhttps://certs.lbl.gov/publications/optimal-pricing-manage-electric01354nas a2200193 4500008003900000022001400039245008100053210006900134260001200203300001000215520073000225653001300955653003100968100001800999700002301017700002101040700002201061856007701083 2015 d a0885-897700aOn-line Calibration of Voltage Transformers Using Synchrophasor Measurements0 aOnline Calibration of Voltage Transformers Using Synchrophasor M c10/2015 a1 - 13 aUn-calibrated instrument transformers present at the inputs of phasor measurement units (PMUs) can significantly degrade their outputs. This also causes problems in downstream applications that use PMU data. This paper presents a method for calibrating voltage transformers online using synchrophasor measurements. The proposed approach aims to find the optimal locations where good quality measurements must be added so as to bring the calibration error of all the measurements below a pre-defined threshold. The IEEE-118 bus system, the IEEE-300 bus system, and a 2383 bus Polish system have been used as the test systems for this analysis. The advantage of the proposed approach is its effectiveness and robustness.

10aAA13-00310asynchrophasor applications1 aPal, Anamitra1 aChatterjee, Paroma1 aThorp, James, S.1 aCenteno, Virgilio uhttps://certs.lbl.gov/publications/line-calibration-voltage-transformers01857nas a2200205 4500008003900000022001400039245009600053210006900149260001200218300001000230520118400240653001001424653003201434653002901466653002801495653001301523100002401536700001801560856007301578 2015 d a0885-895000aOptimal Topology Control With Physical Power Flow Constraints and N-1 Contingency Criterion0 aOptimal Topology Control With Physical Power Flow Constraints an c01/2015 a1 - 93 aIn this paper, a novel solution method is proposed for the optimal topology control problem in AC framework with N-1 reliability. The resultant new topology of the proposed method is guaranteed to yield a better objective function value than the global solution of the problem with the original topology. In order to prove our statement, semi-definite programming relaxation is formulated to find a lower bound to the objective function value of the problem. The proposed method is favorable for parallelization to increase the computational efficiency, and the parallel computing flowchart is presented. Computational time of the algorithm for IEEE test cases is reported. An in-house power market simulator is developed to simulate a market environment complete with optimal topology control mechanism. Simulations held by participating human subjects are analyzed under the subtitles of the total operating cost, real power losses, and locational marginal price (LMP) variance. A simple example is illustrated to show that the resultant network topology may increase the real power losses while still providing a lower operating system cost than that of the original topology.10aCERTS10alocational marginal pricing10aoptimal power flow (OPF)10areliability and markets10aRM13-0031 aPoyrazoglu, Gokturk1 aOh, HyungSeon uhttps://certs.lbl.gov/publications/optimal-topology-control-physical01384nas a2200193 4500008003900000245007700039210006900116260004400185300001000229520075500239653001300994653000901007653001001016653003201026100002001058700002101078700001501099856007601114 2014 d00aOpen-loop PDCI probing tests for the Western North American power system0 aOpenloop PDCI probing tests for the Western North American power aNational Harbor, MD, USAbIEEEc07/2014 a1 - 53 aPoorly-damped electromechanical oscillations are of concern in the western North American power system. Recent development of reliable real-time wide-area measurement systems has enabled the potential for large-scale damping control approaches for stabilizing critical oscillation modes. The current approach being developed is feedback modulation of the Pacific DC Intertie (PDCI). This paper summarizes several years of open-loop actual-system PDCI probing tests. This includes a total of 56 tests conducted in 2009, 2011, and 2012. Test goals are to: 1) evaluate the controllability and robustness of the PDCI with WAMS feedback for damping; and 2) compare actual-system results to model-based transient stability and eigenanalysis studies.

10aAA14-00610aAARD10aCERTS10asynchrophasor-based control1 aTrudnowski, Dan1 aKosterev, Dmitry1 aWold, Josh uhttps://certs.lbl.gov/publications/open-loop-pdci-probing-tests-western01860nas a2200277 4500008003900000245010000039210006900139260004400208300001000252520097200262653001301234653000901247653001001256653001201266653000901278653001701287653003601304653003201340100002301372700002001395700002101415700002201436700002601458700002601484856007201510 2014 d00aOptimal locations for energy storage damping systems in the Western North American interconnect0 aOptimal locations for energy storage damping systems in the West aNational Harbor, MD, USAbIEEEc07/2014 a1 - 53 aElectromechanical oscillations often limit transmission capacity in the western North American Power System (termed the wNAPS). Recent research and development has focused on employing large-scale damping controls via wide-area feedback. Such an approach is made possible by the recent installation of a wide-area real-time measurement system based upon Phasor Measurement Unit (PMU) technology. One potential large-scale damping approach is based on energy storage devices. Such an approach has considerable promise for damping oscillations. This paper considers the placement of such devices within the wNAPS system. We explore combining energy storage devices with HVDC modulation of the Pacific DC Intertie (PDCI). We include eigenanalysis of a reduced-order wNAPS system, detailed analysis of a basic two-area dynamic system, and full-order transient simulations. We conclude that the optimal energy storage location is in the area with the lower inertia.

10aAA14-00610aAARD10aCERTS10adamping10aHVDC10aoscillations10aphasor measurement units (PMUs)10asynchrophasor-based control1 aByrne, Raymond, H.1 aTrudnowski, Dan1 aNeely, Jason, C.1 aElliott, Ryan, T.1 aSchoenwald, David, A.1 aDonnelly, Matthew, K. uhttps://certs.lbl.gov/publications/optimal-locations-energy-storage01829nas a2200193 4500008003900000245007600039210006900115260003600184300001000220520119500230653001001425653002201435653002901457653002801486653001301514100001501527700002501542856006801567 2014 d00aAn optimization based generator placement strategy in network reduction0 aoptimization based generator placement strategy in network reduc aPullman, WA, USAbIEEEc09/2014 a1 - 63 aSolving the optimal power flow (OPF) problem on a large power system is computationally expensive. Network reduction and ac-to-dc network conversion can relieve this burden by simplifying the full system model to a smaller and mathematically simpler model. Traditional reduction methods, like Ward reduction, fractionalize generators when the buses they are attached to are removed, and scatters these fractions to topologically adjacent buses. In some OPF applications, this type of generator modeling is problematic. An improved approach is to keep generators intact by moving them whole to buses in reduced model and then redistributing loads to maintain base-case line flows. Determining generator placement using a traditional shortest electrical distance (SED) based method may result in cases where the OPF solution on reduced model is infeasible while the full model has a feasible solution. In this paper, an improved generator placement method is proposed. Tests show that the proposed method yields a better approximation to the full model OPF solutions and is more likely to produce a reduced model with a feasible solution if the unreduced model has a feasible solution.

10aCERTS10anetwork reduction10aoptimal power flow (OPF)10areliability and markets10aRM11-0051 aZhu, Yujia1 aTylavsky, Daniel, J. uhttps://certs.lbl.gov/publications/optimization-based-generator01887nas a2200217 4500008003900000245007000039210006900109260003900178300001200217520122000229653001001449653000901459653001301468100002301481700001601504700002001520700002201540700001801562700001701580856007201597 2014 d00aOptimized path planning for electric vehicle routing and charging0 aOptimized path planning for electric vehicle routing and chargin aMonticello, IL, USAbIEEEc10/2014 a25 - 323 aWe consider the decision problem of an individual EV owner who needs to pick a travel path including its charging locations and associated charge amount under time-varying traffic conditions as well as dynamic location-based electricity pricing. We show that the problem is equivalent to finding the shortest path on an extended transportation graph. In particular, we extend the original transportation graph through the use of virtual links with negative energy requirements to represent charging options available to the user. Using these extended transportation graphs, we then study the collective effects of a large number of EV owners solving the same type of path planning problem under the following control strategies: 1) a social planner decides the optimal route and charge strategy of all EVs; 2) users reach an equilibrium under locationally-variant electricity prices that are constant over time; 3) the transportation and power systems are separately controlled through marginal pricing strategies, not taking into account their mutual effect on one another. We numerically show that this disjoint type of control can lead to instabilities in the grid as well as inefficient system operation.

10aCERTS10aPEVs10aRM11-0071 aAlizadeh, Mahnoosh1 aWai, Hoi-To1 aScaglione, Anna1 aGoldsmith, Andrea1 aFan, Yue, Yue1 aJavidi, Tara uhttps://certs.lbl.gov/publications/optimized-path-planning-electric01617nas a2200217 4500008003900000245009600039210006900135260003800204300001000242520084800252653000901100653003901109653001001148653002501158653003601183653002901219100002401248700003601272700002101308856007001329 2013 d00aOnline estimation of power system distribution factors — A sparse representation approach0 aOnline estimation of power system distribution factors A sparse aManhattan, KS, USAbIEEEc09/2013 a1 - 53 aThis paper proposes a method to compute linear sensitivity distribution factors (DFs) in near real-time without relying on a power flow model of the system. Instead, the proposed method relies on the solution of an underdetermined system of linear equations that arise from high-frequency synchronized measurements obtained from phasor measurement units. In particular, we exploit a sparse representation (i.e., one in which many elements are zero) of the desired DFs obtained via a linear transformation, and cast the estimation problem as an IO-norm minimization. As we illustrate through examples, the proposed approach is able to provide accurate DF estimates with fewer sets of synchronized measurements than earlier approaches that rely on the solution of an overdetermined system of equations via the least-squares errors method.

10aAARD10aAutomatic Switchable Network (ASN)10aCERTS10adistribution factors10aphasor measurement units (PMUs)10apower system reliability1 aChen, Yu, Christine1 aDominguez-Garcia, Alejandro, D.1 aSauer, Peter, W. uhttps://certs.lbl.gov/publications/online-estimation-power-system01316nas a2200229 4500008003900000022001400039245011100053210006900164260001200233300001600245490000700261520058700268653001300855653000900868653001000877653001700887653003600904100001700940700001700957700003800974856007401012 2013 d a0885-895000aOscillation modal analysis from ambient synchrophasor data using distributed frequency domain optimization0 aOscillation modal analysis from ambient synchrophasor data using c05/2013 a1960 - 19680 v283 aThis paper provides a distributed frequency domain algorithm for real-time modal estimation of large power systems using ambient synchrophasor data. By dividing the computation between a supervisory central computer and local optimizations at the substation level, the algorithm efficiently estimates multiple dominant mode frequencies, damping ratios and mode shapes from wide-area power system measurements. The algorithm, called distributed frequency domain optimization, is tested on known test systems and archived real power system data from eastern and western power systems.10aAA13-00410aAARD10aCERTS10aoscillations10aphasor measurement units (PMUs)1 aNing, Jiawei1 aPan, Xueping1 aVenkatasubramanian, Vaithianathan uhttps://certs.lbl.gov/publications/oscillation-modal-analysis-ambient01848nas a2200289 4500008003900000020002200039245007100061210006800132260003800200300001000238520094200248653001001190653002801200653002401228653002901252653002601281653002801307653001301335100001201348700002401360700001201384700002501396700002001421700002301441700002501464856006901489 2012 d a978-1-4673-2306-200aOptimal generation investment planning: Pt. 1: network equivalents0 aOptimal generation investment planning Pt 1 network equivalents aChampaign, IL, USAbIEEEc09/2012 a1 - 63 aThe requirements of a network equivalent to be used in new planning tools are very different from those used in traditional equivalencing procedures. For example, in the classical Ward equivalent, each generator in the external system is broken up into fractions. For newer long-term investment applications that take into account such things as greenhouse gas (GHG) regulations and generator availability, it is computationally impractical to model fractions of generators located at many buses. To overcome this limitation, a modified- Ward equivalencing scheme is proposed in this paper. The proposed scheme is applied to the entire Eastern Interconnection (EI) to obtain several backbone equivalents and these equivalents are tested for accuracy under a range of operating conditions. In a companion paper, the application of an equivalent developed by this procedure is used to perform optimal generation investment planning.

10aCERTS10aEastern Interconnection10ainvestment planning10aoptimal power flow (OPF)10aPower system modeling10areliability and markets10aRM11-0051 aShi, Di1 aShawhan, Daniel, L.1 aLi, Nan1 aTylavsky, Daniel, J.1 aTaber, John, T.1 aZimmerman, Ray, D.1 aSchulze, William, D. uhttps://certs.lbl.gov/publications/optimal-generation-investment01554nas a2200277 4500008003900000020002200039245008300061210006900144260003800213300001000251520067600261653001000937653002400947653002600971653002600997653002801023653001301051100001201064700001201076700002401088700002501112700002001137700002301157700002501180856007101205 2012 d a978-1-4673-2306-200aOptimal generation investment planning: Pt. 2: Application to the ERCOT system0 aOptimal generation investment planning Pt 2 Application to the E aChampaign, IL, USAbIEEEc09/2012 a1 - 63 aPower system planning and market behavioral analysis using the full model of a large-scale network, such as the entire ERCOT system, are computationally expensive. Reducing the full network into a small equivalent is a practical way to reduce the computational burden. In a companion paper, a modified-Ward equivalencing procedure has been proposed. In this paper, the proposed scheme is applied to the ERCOT system to obtain several backbone equivalents, the accuracy of which are tested under a range of operating conditions. The ERCOT equivalent is used in a system planning tool to perform optimal generation investment studies with promising results observed.

10aCERTS10ainvestment planning10aPower system modeling10apower system planning10areliability and markets10aRM11-0051 aLi, Nan1 aShi, Di1 aShawhan, Daniel, L.1 aTylavsky, Daniel, J.1 aTaber, John, T.1 aZimmerman, Ray, D.1 aSchulze, William, D. uhttps://certs.lbl.gov/publications/optimal-generation-investment-002024nas a2200241 4500008003900000022001400039245008000053210006900133260001200202300001400214490000700228520127300235653002001508653002001528653002701548653002801575653002701603653001301630100002201643700002401665700002001689856007301709 2012 d a0885-895000aOptimal Generation Mix With Short-Term Demand Response and Wind Penetration0 aOptimal Generation Mix With ShortTerm Demand Response and Wind P c05/2012 a830 - 8390 v273 aDemand response, defined as the ability of load to respond to short-term variations in electricity prices, plays an increasingly important role in balancing short-term supply and demand, especially during peak periods and in dealing with fluctuations in renewable energy supplies. However, demand response has not been included in standard models for defining the optimal generation technology mix. Three different methodologies are proposed to integrate short-term responsiveness into a generation technology mix optimization model considering operational constraints. Elasticities are included to adjust the demand profile in response to price changes, including cross-price elasticities that account for load shifts among hours. As energy efficiency programs also influence the load profile, interactions of efficiency investments and demand response are also modeled. Comparison of model results for a single year optimization with and without demand response shows peak reduction and valley filling effects, impacting the optimal amounts and mix of generation capacity. Increasing demand elasticity also increases the installed amount of wind capacity, suggesting that demand response yields environmental benefits by facilitating integration of renewable energy.10ademand response10aload management10apower system economics10areliability and markets10arenewables integration10aRM11-0021 aDe Jonghe, Cedric1 aHobbs, Benjamin, F.1 aBelmans, Ronnie uhttps://certs.lbl.gov/publications/optimal-generation-mix-short-term01437nas a2200265 4500008003900000020002200039245008200061210006900143260003300212300001400245520059000259653002000849653001800869653002700887653002800914653001500942653001300957100002300970700001900993700001801012700002501030700002201055700002001077856007401097 2012 d a978-1-4673-2065-800aOptimal power and reserve capacity procurement policies with deferrable loads0 aOptimal power and reserve capacity procurement policies with def aMaui, HI, USAbIEEEc12/2012 a450 - 4563 aDeferrable loads can be used to mitigate the variability associated with renewable generation. In this paper, we study the impact of deferrable loads on forward market operations. Specifically, we compute cost-minimizing ex-ante bulk power and reserve capacity procurement policies in the cases of fully deferrable and non-deferrable loads. For non-deferrable loads, we analytically express this policy on a partition of procurement prices. We also formulate a threshold policy for deferrable load scheduling in the face of uncertain supply, that minimizes grid operating costs.

10aload management10aload modeling10apower system economics10areliability and markets10arenewables10aRM11-0061 aSubramanian, Anand1 aTaylor, J., A.1 aBitar, Eilyan1 aCallaway, Duncan, S.1 aPoolla, Kameshwar1 aVaraiya, Pravin uhttps://certs.lbl.gov/publications/optimal-power-and-reserve-capacity02074nas a2200193 4500008003900000022001400039245008000053210006900133260001200202300001400214490000700228520146600235653002701701653001301728100002101741700002101762700002501783856007201808 2011 d a0922-680X00aOptimal transmission switching: economic efficiency and market implications0 aOptimal transmission switching economic efficiency and market im c10/2011 a111 - 1400 v403 aTraditionally, transmission assets for bulk power flow in the electric grid have been modeled as fixed assets in the short run, except during times of forced outages or maintenance. This traditional view does not permit reconfiguration of the transmission grid by the system operators to improve system performance and economic efficiency. The current push to create a smarter grid has brought to the forefront the possibility of co-optimizing generation along with the network topology by incorporating the control of transmission assets within the economic dispatch formulations. Unfortunately, even though such co-optimization improves the social welfare, it may be incompatible with prevailing market design practices since it can create winners and losers among market participants and it has unpredictable distributional consequences in the energy market and in the financial transmission rights (FTR) market. In this paper, we first provide an overview of recent research on optimal transmission switching, which demonstrates the substantial economic benefit that is possible even while satisfying standard N−1 reliability requirements. We then discuss various market implications resulting from co-optimizing the network topology with generation and we examine how transmission switching may affect locational Marginal Prices (LMPs), i.e., energy prices, and revenue adequacy in the FTR market when FTR settlements are financed by congestion revenues.10apower system economics10aRM08-0011 aHedman, Kory, W.1 aOren, Shmuel, S.1 aO'Neill, Richard, P. uhttps://certs.lbl.gov/publications/optimal-transmission-switching-101464nas a2200229 4500008003900000022001400039245006100053210006100114260001200175300001600187490000700203520077700210653001000987653002700997653002801024653001301052100002101065700002501086700003001111700002101141856007201162 2009 d a0885-895000aOptimal Transmission Switching With Contingency Analysis0 aOptimal Transmission Switching With Contingency Analysis c08/2009 a1577 - 15860 v243 aIn this paper, we analyze the N-1 reliable dc optimal dispatch with transmission switching. The model is a mixed integer program (MIP) with binary variables representing the state of the transmission element (line or transformer) and the model can be used for planning and/or operations. We then attempt to find solutions to this problem using the IEEE 118-bus and the RTS 96 system test cases. The IEEE 118-bus test case is analyzed at varying load levels. Using simple heuristics, we demonstrate that these networks can be operated to satisfy N-1 standards while cutting costs by incorporating transmission switching into the dispatch. In some cases, the percent savings from transmission switching was higher with an N-1 DCOPF formulation than with a DCOPF formulation.10aCERTS10apower system economics10areliability and markets10aRM08-0011 aHedman, Kory, W.1 aO'Neill, Richard, P.1 aFisher, Emily, Bartholome1 aOren, Shmuel, S. uhttps://certs.lbl.gov/publications/optimal-transmission-switching-003070nas a2200253 4500008003900000245005500039210005500094260003900149520234600188653001002534653001302544653002302557653001502580100001902595700002502614700001902639700001802658700001702676700002502693700001502718700002002733700001402753856004902767 2009 d00aOverview of the CERTS microgid laboratory test bed0 aOverview of the CERTS microgid laboratory test bed aCalgary, AB, CanadabIEEEc07/20093 aThe objective of the CERTS microgrid test bed project was to enhance the ease of integrating energy sources into a microgrid. The project accomplished this objective by developing and demonstrating three advanced techniques, collectively referred to as the CERTS microgrid concept, that significantly reduce the level of custom field engineering needed to operate microgrids consisting of generating sources less than 100 kW. The techniques comprising the CERTS microgrid concept are: 1) a method for effecting automatic and seamless transitions between grid-connected and islanded modes of operation, islanding the microgrid's load from a disturbance, thereby maintaining a higher level of service, without impacting the integrity of the utility's electrical power grid; 2) an approach to electrical protection within a limited source microgrid that does not depend on high fault currents; and 3) a method for microgrid control that achieves voltage and frequency stability under islanded conditions without requiring high-speed communications between sources. These techniques were demonstrated at a full-scale test bed built near Columbus, Ohio and operated by American electric power. The testing fully confirmed earlier research that had been conducted initially through analytical simulations, then through laboratory emulations, and finally through factory acceptance testing of individual microgrid components. The islanding and resychronization method met all Institute of Electrical and Electronics Engineers Standard 1547 and power quality requirements. The electrical protection system was able to distinguish between normal and faulted operation. The controls were found to be robust under all conditions, including difficult motor starts and high impedance faults. The results from these tests are expected to lead to additional testing of enhancements to the basic techniques at the test bed to improve the business case for microgrid technologies, as well to field demonstrations in- volving microgrids that involve one or more of the CERTS microgrid concepts. Future planned microgrid work involves unattended continuous operation of the microgrid for 30 to 60 days to determine how utility faults impact the operation of the microgrid and to gage the power quality and reliability improvements offered by microgrids.

10aCERTS10aMG-TB00110amicrogrid test bed10amicrogrids1 aEto, Joseph, H1 aLasseter, Robert, H.1 aSchenkman, Ben1 aStevens, John1 aKlapp, David1 aVolkommer, Harry, T.1 aLinton, Ed1 aHurtado, Hector1 aRoy, Jean uhttp://ieeexplore.ieee.org/document/5211205/02868nas a2200181 4500008003900000020002300039245007300062210006900135260004500204520226400249653000902513653002202522653001002544653002902554653002602583100003102609856004602640 2008 d a978-0-549-68802-0 00aOn-line cascading event tracking and avoidance decision support tool0 aOnline cascading event tracking and avoidance decision support t aAmes, IAbIowa State Universityc06/20083 aCascading outages in power systems are costly events that power system operators and planners actively seek to avoid. Such events can quickly result in power outages for millions of customers. Although it is unreasonable to claim that blackouts can be completely prevented, we can nonetheless reduce the frequency and impact of such high consequence events. Power operators can take actions if they have the right information provided by tools for monitoring and managing the risk of cascading outages. Such tools are being developed in this research project by identifying contingencies that could initiate cascading outages and by determining operator actions to avoid the start of a cascade. A key to cascading outage defense is the level of grid operator situational awareness. Severe disturbances and complex unfolding of post-disturbance phenomena, including interdependent events, demand critical actions to be taken on the part of the operators, thus making operators dependent on decision support tools and automatic controls. In other industries (e.g., airline, nuclear, process control), control operators employ computational capabilities that help them predict system response and identify corrective actions. Power system operators should have a similar capability with online simulation tools. To create an online simulator to help operators identify the potential for and actions to avoid cascades, we developed a systematic way to identify power system initiating contingencies for operational use. The work extends the conventional contingency list by including a subset of high-order contingencies identified through topology processing. The contingencies are assessed via an online, mid-term simulator, designed to provide generalized, event-based, corrective control and decision support for operators with very high computational efficiency. Speed enhancement is obtained algorithmically by employing a multi-frontal linear solver within an implicit integration scheme. The contingency selection and simulation capabilities were illustrated on two systems: a test system with six generators and the IEEE RTS-96 with 33 generators. Comparisons with commercial grade simulators indicate the developed simulator is accurate and fast.10aAARD10acascading outages10aCERTS10adecision-support systems10asituational awareness1 aKhaitan, Siddhartha, Kumar uhttp://dl.acm.org/citation.cfm?id=155942901583nas a2200205 4500008003900000020002200039245005700061210005300118260003900171300001000210520095100220653001001171653001301181653002301194653001501217100002801232700002201260700002501282856007001307 2008 d a978-1-4244-1905-000aThe operation of diesel gensets in a CERTS microgrid0 aoperation of diesel gensets in a CERTS microgrid aPittsburgh, PA, USAbIEEEc07/2008 a1 - 83 aIn this paper the operation of diesel engine-driven wound-field synchronous generator sets as distributed generators (DGpsilas) is studied. The objective of this work is to develop the modeling and control framework for such gensets to enable their operation in a distribution system that contains multiple DGpsilas including inverter-based sources. The paper presents experimental results for the interaction of conventional gensets with inverter-based sources in a microgrid test system. From the test results it is observed that there is significant circulating reactive power between the sources as well as frequency oscillations caused by the response of the conventional genset controller. A new controller for the genset is proposed that alleviates these issues and enables the various sources to share power and maintain power quality within the system. The operation of the new controller is demonstrated using simulation results.

10aCERTS10aMG-TB00210amicrogrid test bed10amicrogrids1 aKrishnamurthy, Shashank1 aJahns, Thomas, M.1 aLasseter, Robert, H. uhttps://certs.lbl.gov/publications/operation-diesel-gensets-certs02042nas a2200301 4500008003900000245008200039210006900121260002800190300000700218520104400225653003201269653001701301653001201318653002501330653001201355653003701367653003901404653004101443653002701484653002601511100001801537700002501555700002101580700002401601700002401625700001901649856007201668 2008 d00aOptimal Technology Selection and Operation of Commercial- Building Microgrids0 aOptimal Technology Selection and Operation of Commercial Buildin aBerkeleybLBNLc01/2007 a103 aThe deployment of small (< 1-2 MW) clusters of generators, heat and electrical storage, efficiency investments, and combined heat and power (CHP) applications (particularly involving heat-activated cooling) in commercial buildings promises significant benefits but poses many technical and financial challenges, both in system choice and its operation; if successful, such systems may be precursors to widespread microgrid deployment. The presented optimization approach to choosing such systems and their operating schedules uses Berkeley Lab's Distributed Energy Resources Customer Adoption Model (DER-CAM), extended to incorporate electrical and thermal storage options. DER-CAM chooses annual energy bill minimizing systems in a fully technologyneutral manner. An illustrative example for a hypothetical San Francisco hotel is reported. The chosen system includes one large reciprocating engine and an absorption chiller providing an estimated 11% cost savings and 8% carbon emission reductions under idealized circumstances.

10abuilding management systems10acogeneration10acooling10acost optimal control10aDER-CAM10adispersed storage and generation10adistributed energy resources (der)10aelectricity markets and policy group10apower system economics10apower system planning1 aMarnay, Chris1 aVenkataramanan, Giri1 aStadler, Michael1 aSiddiqui, Afzal, S.1 aFirestone, Ryan, M.1 aChandran, Bala uhttps://certs.lbl.gov/publications/optimal-technology-selection-and02053nas a2200325 4500008004100000022001400041245008100055210006900136260001200205300001200217490000700229520104700236653003201283653001401315653001701329653001201346653002501358653003701383653002401420653002501444653002701469653002601496100001801522700002501540700002101565700002401586700002401610700001901634856007401653 2008 eng d a0885-895000aOptimal Technology Selection and Operation of Commercial-Building Microgrids0 aOptimal Technology Selection and Operation of CommercialBuilding c08/2008 a975-9820 v233 aThe deployment of small ( < 1-2 MW ) clusters of generators, heat and electrical storage, efficiency investments, and combined heat and power (CHP) applications (particularly involving heat-activated cooling) in commercial buildings promises significant benefits but poses many technical and financial challenges, both in system choice and its operation; if successful, such systems may be precursors to widespread microgrid deployment. The presented optimization approach to choosing such systems and their operating schedules uses Berkeley Lab's Distributed Energy Resources Customer Adoption Model (DER-CAM), extended to incorporate electrical and thermal storage options. DER-CAM chooses annual energy bill minimizing systems in a fully technology-neutral manner. An illustrative example for a hypothetical San Francisco hotel is reported. The chosen system includes one large reciprocating engine and an absorption chiller providing an estimated 11% cost savings and 8% carbon emission reductions under idealized circumstances.

10abuilding management systems10abuildings10acogeneration10acooling10acost optimal control10adispersed storage and generation10adistributed control10aoptimization methods10apower system economics10apower system planning1 aMarnay, Chris1 aVenkataramanan, Giri1 aStadler, Michael1 aSiddiqui, Afzal, S.1 aFirestone, Ryan, M.1 aChandran, Bala uhttps://certs.lbl.gov/publications/optimal-technology-selection-and-001407nas a2200229 4500008003900000022001400039245007300053210007100126260001200197300001600209490000700225520070000232653001000932653002700942653002800969653001300997100002101010700002501031700003001056700002101086856007001107 2008 d a0885-895000aOptimal Transmission Switching—Sensitivity Analysis and Extensions0 aOptimal Transmission Switching—Sensitivity Analysis and Extensio c08/2008 a1469 - 14790 v233 aIn this paper, we continue to analyze optimal dispatch of generation and transmission topology to meet load as a mixed integer program (MIP) with binary variables representing the state of the transmission element (line or transformer). Previous research showed a 25% savings by dispatching the IEEE 118-bus test case. This paper is an extension of that work. It presents how changing the topology affects nodal prices, load payment, generation revenues, cost, and rents, congestion rents, and flowgate prices. Results indicate that changing the topology to cut costs typically results in lower load payments and higher generation rents for this network. Computational issues are also discussed.10aCERTS10apower system economics10areliability and markets10aRM08-0011 aHedman, Kory, W.1 aO'Neill, Richard, P.1 aFisher, Emily, Bartholome1 aOren, Shmuel, S. uhttps://certs.lbl.gov/publications/optimal-transmission-switching02780nas a2200241 4500008004100000022001400041245009200055210006900147260001100216300001000227490000600237520198900243653003102232653001202263653003902275653005202314653001802366100002402384700001802408700002102426700003302447856005802480 2005 eng d a1614-713800aOptimal selection of on-site power generation with combined heat and power applications0 aOptimal selection of onsite power generation with combined heat c3/2005 a33-620 v13 aWhile demand for electricity continues to grow, expansion of the traditional electricity supply system, or macrogrid, is constrained and is unlikely to keep pace with the growing thirst western economies have for electricity. Furthermore, no compelling case has been made that perpetual improvement in the overall power quality and reliability (PQR) delivered is technically possible or economically desirable. An alternative path to providing high PQR for sensitive loads would generate close to them in microgrids, such as the Consortium for Electricity Reliability Technology Solutions (CERTS) Microgrid. Distributed generation would alleviate the pressure for endless improvement in macrogrid PQR and might allow the establishment of a sounder economically based level of universal grid service. Energy conversion from available fuels to electricity close to loads can also provide combined heat and power (CHP) opportunities that can significantly improve the economics of small-scale on-site power generation, especially in hot climates when the waste heat serves absorption cycle cooling equipment that displaces expensive on-peak electricity. An optimisa-tion model, the Distributed Energy Resources Customer Adoption Model (DER-CAM), developed at Berke-ley Lab identifies the energy bill minimising combination of on-site generation and heat recovery equipment for sites, given their electricity and heat requirements, the tariffs they face, and a menu of available equip-ment. DER-CAM is used to conduct a systemic energy analysis of a southern California naval base building and demonstrates a typical current economic on-site power opportunity. Results achieve cost reductions of about 15% with DER, depending on the tariff. Furthermore, almost all of the energy is provided on-site, indicating that modest cost savings can be achieved when the microgrid is free to select distributed genera-tion and heat recovery equipment in order to minimise its over all costs.

10adecentralised optimisation10aDER-CAM10adistributed energy resources (der)10adistributed generation' combined heat and power10apower quality1 aSiddiqui, Afzal, S.1 aMarnay, Chris1 aBailey, Owen, C.1 aLaCommare, Kristina, Hamachi uhttp://ts-publishers.com/abstracts/volume-1-number-1/01264nas a2200181 4500008003900000245011700039210006900156260005300225300000700278520060400285653001300889653000900902653003800911653001000949100002600959700002100985856007601006 2000 d00aOperating Environment and Functional Requirements for Intelligent Distributed Control in the Electric Power Grid0 aOperating Environment and Functional Requirements for Intelligen aAlbuquerquebSandia National Laboratoryc04/2000 a223 aThe restructuring of the U.S. power industry will surely lead to a greater dependence on computers and communications to allow appropriate information sharing for management and control of the power grid. This report describes the operating environment for system operations that control the bulk power system as it exists today including the role NERC plays in this process. Some high-level functional requirements for new approaches to control of the grid are listed followed by a description of the next research steps that are needed to identify specific information management functions.

10aAA00-00110aAARD10aadvanced measurements and control10aRTGRM1 aSmathers, Douglas, C.1 aAkhil, Abbas, A. uhttps://certs.lbl.gov/publications/operating-environment-and-functional