Lessons Learned Summary LL20170401 Dispatched Reduction in - - PowerPoint PPT Presentation

Lessons Learned Summary

Rick Hackman, NERC April 20, 2017

LL20170401 “Dispatched Reduction in Generation Output Causes Frequency Deviation”

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LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

http://www.nerc.com/pa/rrm/ea/Pages/Lessons-Learned.aspx

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• Inadequate data definition resulted in transfer of

incomplete data to security-constrained economic dispatch unit commitment software.

• This resulted in undesirable unit commitment outputs

from the Balancing Authority’s dispatch software.

• System operators attempted to intervene, however,

some dispatch instructions could not be blocked or

• verridden.
• There was a large reduction in generation output that

caused the BA’s area control error (ACE) and system frequency to deviate for almost 20 minutes.

LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

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LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

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LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

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LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

Corrective Actions

• Resolve the data transfer design that led to the data

inconsistency in the unit commitment software

• Improve existing automated controls to block dispatches

that exceed certain criteria

• Improve system operator manual intervention capabilities
• The entity developed additional manual controls for

system operators and support personnel until software and automation improvements can be implemented.

• System operators involved in the event developed lessons

learned training for system operators and support personnel.

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LL20170401 Dispatched Reduction in Generation Output Causes Frequency Deviation

Lessons Learned

• Automated & manual controls for dispatch software

should be reviewed, tested, and operators trained in its use periodically under various conditions.

• A system operator and/or a generator operator should be

able to intervene to override automated dispatch signals.

• BAs should review ramp rates of fast-ramping resources

and determine the ramping that can be absorbed at steady state.

• System operators & support staff should have guidance &

training on troubleshooting security-constrained economic dispatch software issues.

DRAFT Reliability Guideline

Gas and Electrical Operational Coordination Considerations

Preamble

It is in the public interest for the North American Electric Reliability Corporation (NERC) to develop guidelines that are useful for maintaining or enhancing the reliability of the Bulk Electric System (BES). The Technical Committees of NERC; the Operating Committee (OC), the Planning Committee (PC) and the Critical Infrastructure Protection Committee (CIPC) per their charters are authorized by the NERC Board of Trustees (Board) to develop Reliability (OC and PC) and Security (CIPC) Guidelines. Guidelines establish voluntary codes of practice for consideration and use by BES users, owners, and operators. These guidelines are developed by technical committees and include the collective experience, expertise and judgment of the industry. Reliability guidelines are not to be used to provide binding norms or create parameters by which compliance to standards is monitored or enforced. While the incorporation and use

• f guideline practices is strictly voluntary, the review, revision, and development of a program using these

practices is highly encouraged to promote and achieve the highest levels of reliability for the BES.

Background and Purpose

Coordination of operations between the gas and electric industries has become increasingly important

• ver the course of the last decade. The electric power sector’s use of gas, specifically natural gas fired

generation, has grown exponentially in many areas of North America due to increased availability, potentially more competitive costs in relation to other fuels and a move throughout the industry to lower emissions to meet environmental goals. With increased growth in usage comes greater reliance and associated risk due to the dependency that each industry now has on the other. In addition, most of the dependency risk lies within the electric industry since much of the generation capacity using natural gas as its primary fuel does not hold long term firm gas pipeline capacity/transportation rights. The

• perational impact of these dependencies requires gas and electric system operators to actively

coordinate planning and operations. The goal of the coordination is to ensure that both the gas and electric systems remain secure and reliable during normal, abnormal and emergency conditions. This guideline attempts to provide a set of principles and strategies that may be adopted should the region in which you operate requires close coordination due to increased dependency. This guideline does not apply universally, and an evaluation of your area’s unique needs is essential to determine which principles and strategies you apply. The guideline principles and strategies may be applied by RCs, BAs, TOPs, GOs and GOPs in order to ensure reliable coordination with the gas industry. Finally, the document focuses on the areas of preparation, coordination, communication and intelligence that may be applied in order to coordinate operations and minimize risk.

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 2

Guideline Content:

• A. Establish Gas and Electric Industry Coordination Mechanisms
• B. Preparation, Supply Rights, Training and Testing
• C. Establish and Maintain Open Communication Channels
• D. Intelligence and Situational Awareness
• E. Summary
• A. Establish Gas and Electric I ndustry Coordination Mechanisms
• Establish Contacts
• An essential part of any coordination activity is the identification of the participants. For gas

and electric coordination this involves identification of the natural gas pipeline, gas suppliers and Local Distribution Companies “LDC” gas entities as well as operations staff within the electric footprint boundaries and in some instances beyond those boundaries. Once these contacts are established, additional coordination activities can begin. Industry trade

• rganizations such as the Interstate Natural Gas Association of America (INGAA), Natural Gas

Supply Association (NGSA), American Gas Association or a regional entity such as the Northeast Gas Association (all areas in North America have regional entities that are most likely members

• f the American Gas Association) may be able to aid in development of operational contacts

and the establishment of coordination protocols. These contacts should be developed for long and short term planning/outage coordination as well as near term and real-time operations. The contacts should include both control room operating staff contacts as well as

• management. Establishing and maintaining these contacts is the most important aspect of gas

and electric coordination. Past lessons learned have taught the industry that the first call you make to a gas transmission pipeline or LDC should not be during abnormal or emergency conditions.

• Communication Protocols
• Once counterparts are identified in the gas industry, communications protocols will need to be

established within the regulatory framework of both the gas and electric utility entities looking to coordinate and share information. The Federal Energy Regulatory Commission issued a Final Rule under Order No. 787 allowing interstate natural gas pipelines and electric transmission

• perators to share non-public operational information to promote the reliability and integrity
• f their systems. Since the inception of this rule and the subsequent incorporation of those

rules into the associated tariffs, followed by the appropriate confidentiality agreements, gas and electric entities have been able to freely share operational data. Some of the data that could be shared to improve operational coordination could include but is not necessarily limited to the following:

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 3

• Providing detailed operational reports to the gas pipeline operators by specific assets,
• perating on specific pipelines, which specify expected fuel burn by asset, by hour over the

dispatch period under review. It is important to convert dispatch plans from electric power (MWh) to gas demand (dekatherms/day) when conveying that information to gas system

• perators.
• Combining the expected fuel to be used by asset on each pipeline in aggregate to provide

an expected draw on the pipeline by generation connected to that pipeline on an hourly basis and on a gas and electric day basis.

• Exchanging real-time operating information in both verbal and electronic forms (e.g., pipeline

company informational postings) of actual operating conditions on specific assets on specific pipelines.

• Outage planning for elements of significance to include sharing detailed electric and gas asset

scheduling information on all time horizons and coordinating outages of those assets to ensure reliability on both the gas and electric systems. This coordination should include if possible face to face coordination meetings.

• Sharing normal, abnormal and emergency conditions in real-time and ensuring each entity

understands the implications to their respective systems. This should include gas and electric entities proactively reaching out to the operators of stressed gas systems to discuss the impacts, adverse or otherwise, of their expected or available actions. Under extreme gas system operating conditions, understand the direct impacts to electric generation assets when gas pipelines are directed under force majeure conditions.

• The sharing of non-public operating information between the electric operating entity and

LDC, intrastate pipelines, and gathering pipelines is not covered under FERC Order 787 and because of this, individual communication and coordination protocols should be established with each LDC and intrastate pipelines within the footprint of the operating entity. Understanding the conditions under which an LDC or intrastate pipeline would interrupt gas fired generation is of particular importance and incorporating this information into operational planning will assist in identification of potential at risk generation. Setting up electronic/email alerts from each LDC or intrastate pipeline as to the potential declaration of interruptions is

• ne key means of real time identification of potential loss of generation behind the LDC city

gate or meter station on an intrastate pipeline.

• Coordinating Procurement Time Lines
• Operating entities may want to consider changing next day operating plan scheduling practices

to align more efficiently with gas day procurement cycles. The gas and electric industries

• perate on differing timelines for the Day Ahead planning processes and in real-time, with the

electric day on a local midnight to midnight cycle. The gas industry process operates on a differing timeline with the operating day beginning at 9 a.m. Central Clock Time and uniform throughout North America. This difference in operating days can lead to inefficient scheduling

• f natural gas to meet the electric day demands. In many instances throughout North America,

the electric industry has moved the development and publishing of unit commitments and

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 4

next day operating plans in order to ensure that generation resources have the ability to procure and nominate natural gas more efficiently to better meet the scheduling timelines of the gas industry. In addition, the gas industry has adjusted some of its nomination and scheduling practices to allow for more efficient scheduling which meet the needs of the electric system. Coordinating and modifying scheduling practices using more effective time periods may allow for a higher level of pipeline utilization, but more importantly, provide the early identification of constraints that may require starting gas generation with alternate fuels,

• r using non-gas fired facilities for fuel diversity to meet the energy and reserve needs of the

electric system.

• Identification of Critical Gas System Components and Dual-fuel Supplier Components
• It is essential that gas and electric entities are coordinated to ensure that critical natural

gas pipelines, compressor stations, LNG, storage, natural gas processing plants, and other critical gas system components are not subject to electric utility Under Frequency and or Manual Load shedding programs. – Electric transmission and distribution owners are capable of interrupting electrical load either automatically through under frequency load shedding relays installed in substations throughout North America or via manual load shedding ordered by RCs, BAs and or TOPs via SCADA. These manual and automatic load shedding protocols are part of every entity’s emergency procedures. Entities should ensure critical gas sector infrastructure is not located on electrical circuits that are subject to the load shedding described above. Electric operators should establish contact with the gas companies operating within its jurisdiction to compile a list of critical gas and other fuel facilities which are dependent upon electric service for operations. This list should also consider the availability of backup generation at critical gas facilities. Once the list is compiled, a comprehensive review of load shedding procedures/schemas/circuits should be done to verify that critical infrastructure is not connected to or located on any of those predefined circuits. This review should be considered for evaluation at least annually.

• In a similar manner, it may be appropriate to coordinate with secondary fuel (e.g., diesel or

fuel oil) suppliers to ensure that any necessary critical terminals, pump stations, and other critical components are not subject to electric utility Under Frequency and or Manual Load shedding programs. This is especially appropriate if adequate on-site fuel reserves are not guaranteed and just-in-time fuel delivery practices are required.

• Operating Reserves
• The electric industry may want to consider adjustments to operating reserve requirements to

better reflect the increased reliance on natural gas for the generation fleet. For instance, if the loss of a fuel forwarding facility has the ability to result in an instantaneous or near instantaneous electric energy loss, that contingency should be reflected in the reserve procurement for the operating day. In addition some electric operators are considering the implementation of a risk based operating reserve protocol that increases or decreases the

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 5

amount of operating reserve procured based upon the risks identified to both the gas and electric system.

• B. Preparation, Supply Rights, Training and Testing
• Assessments
• Preparing the gas and electric system for coordinated operations requires up front

assessments and activities to ensure that when real-time events occur, the system operators are prepared for and can effectively react. Preparation activities that may be considered include the following:

• Developing a detailed understanding of where and how the gas infrastructure interfaces

with the electric industry including: – Identifying each pipeline (interstate and intrastate) which operates within the electric footprint and mapping the associated electric resources which are dependent upon those pipelines. – Identifying the level and quantity of pipeline capacity service (firm or interruptible; primary/secondary) and any additional pipeline services (storage, no-notice, etc.) being utilized by each gas fired generator. – Developing a model of and understanding the non-electric generation load that those pipelines and LDCs serve and will protect when curtailments are needed. – Identifying gas single element contingencies and how those contingencies will impact the electric infrastructure. For instance, although most gas side contingencies will not impact the electric grid instantaneously, they will most likely be far more severe than electric side contingencies over time because they may impact several generation

• facilities. When identifying gas system contingencies, the electric entity should consider

what the gas operator will do to secure its firm customers including the potential that the gas system will invoke mutual aid agreements with other interconnected pipelines which may involve curtailment of non-firm electrical generation from the non-impacted pipeline to aid the other. – Understanding how gas contingencies may interact with electric contingencies during a system restoration effort. – An additional example of appropriate actions to consider as part of the assessment phase of preparation is provided as a Natural Gas Risk Matrix

• Emergency Procedure Testing and Training
• Consider the development of testing and training activities to recognize abnormal gas system
• perating conditions and to support extreme gas contingencies such as loss of compressor

stations, pipelines, pipeline interconnections, large LNG facilities, etc. that can result in multiple generator losses over time. Particular attention should be focused on any gas related contingency that may result in an instantaneous generation loss.

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 6

• Consider the addition of electric and natural gas coordination and interdependencies training

to educate and exercise RCs, BAs, TOPs, and GOPs during potentially adverse natural gas supply disruptions.

• If voltage reduction capability exists within your area, practical testing and training should be

considered as part of seasonal or annual work plans.

• The use of manual firm load shedding may be required for beyond criteria extreme gas and or

electric contingencies. Consideration should be given to practicing the use of manual load- shedding in a simulated environment. These simulations should also be used as part of recurring system operator training at a minimum. The use of tabletop exercises can be a valuable training aid, but wherever possible, consideration should be given to using an advanced training simulator that employs the same tools the operators would use to accomplish the load shedding tasks.

• Develop and drill internal communication protocols specific to potential natural gas

interruptions.

• Generator Testing
• Consideration should be given to adopting generator testing requirements for dual fuel
• auditing. Some items to consider when establishing a dual fuel audit program are:
• How often should the audits be conducted and under what weather and temperature

conditions.

• Verify sufficient alternate fuel (e.g., fuel oil) inventory to ensure required generation

response and output.

• Capacity reductions on alternate fuels.
• Understanding the exact time it takes to startup, switch to alternate fuel, ramp to and
• perate at full capacity, ramp down and resource shut down. Additional consideration

should be given for those assets which require a shutdown in order to swap to an alternate fuel source.

• The operating entity should consider any environmental constraints the generator under

test must meet in order to swap to and operate on the alternate fuel.

• Capacity and Energy Assessments
• Consideration should be given to the development of a forward looking capacity analysis which

the electric industry is very familiar with but applying the impacts of fuel restrictions that may

• ccur due to pipeline constraints or other fuel delivery constraints such as LNG shipments or

liquid fuel delivery considerations. In order to conduct these types of assessments, the analysis needs to consider the LDC loads within the region. The weather component of the assessment should consider normal, abnormal and extreme conditions (i.e., Gas Design Day which is the equivalent to the highest peak that the pipeline was designed for). This capacity assessment can be on several time horizons including; Real-time, Day Ahead, Month Ahead and Years into the future. These assessments should consider pipeline maintenance, known future outages,

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 7

construction and expansion activities as well as all electric industry considerations, including known or potential regulatory changes, which are normally analyzed.

• In addition to a capacity assessment which only represents a single point in time, consideration

should be given to the development of a seasonal, annual or multiannual energy analysis that uses fuel delivery capability/limitations as a component. Such assessments can be scenario based, should simulate varied weather conditions over the course of months, seasons and/or years, and consider the same elements as discussed in the capacity analysis. The output of the assessments should determine whether there is the potential for unserved energy and/or determine the ability to provide reserves over the period in question.

• Winter Readiness Training
• Recent system events have magnified the need to ensure that seasonal awareness and

readiness training is completed within the electric industry including System Operators, Generator Operators and Transmission Operators. Seasonal readiness training for winter weather could include reviews and training associated with dual fuel testing, emergency capacity and energy plans, weather forecasts over the seasonal period, fuel survey protocols and storage readiness. Other areas that require attention in winter readiness training include reviewing and setting specific operational expectations on communications protocols. Finally, any winter readiness seminars should include individual generator readiness such as ensuring adequate fuel arrangements are in place for unit availability, adequate freeze protection guidelines are in place, understanding access to primary and secondary fuels and testing to switch to alternate fuels, ensuring all environmental permitting is in place for the fuel options available to the asset, and making sure that the Balancing and Transmission Operators are kept apprised of the unit availability.

• Extreme Weather Readiness Training
• Seasonal readiness training for extreme summer weather events (e.g., Gulf of Mexico

hurricane) could exercise response to potential natural gas supply limitations and corresponding decreases in natural gas deliveries that may impact electric generation. Many of the same benefits as winter readiness exercises can be realized with the added benefit of training under summer operating conditions when electric loads are higher than winter loads.

• C. Establish and Maintain Open Communication Channels
• Industry Coordination
• In the long and short term planning horizons, regularly scheduled meetings between the gas

and electric industries should be held to discuss upcoming operations including outage coordination, industry updates, project updates and exchange of contact information.

• Operating entities should consider the development of a coordinated and annually updated set
• f operational and planning contact information for both the gas and electric industries. This

information should include access to emergency phone numbers for management contacts as

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 8

well as all control center real-time and forecaster desks for use in normal, abnormal and emergency conditions.

• Gas and Electric emergency communication conference call capability should be considered

between the industries such that operating personnel can be made available from both industries immediately, including off hours and within the confines of the individual confidentiality provisions of each entity. Electric sector personnel should periodically monitor pipeline posted information and notices.

• Emergency Notifications to Stakeholders
• Operating Entities may want to consider proactive notifications to stakeholders of abnormal

and or emergency conditions on gas infrastructure to ensure widespread situational awareness and obligations associated with dispatch relationships in the electric sector. An example of a notification used for generators in New England appears below: Depending upon the level of severity and risk exposure, these written notifications and a means to communicate them may need to be followed up with direct verbal communications.

• Emergency Communication Protocols in the Public and Regulatory Community
• Most every electric operating entity has long standing capacity and energy emergency

plans in place that focus on public awareness, abnormal and emergency communications as well as appeals for conservation and load management. However, as the gas and electric industry become further dependent, considerations should be made for both industries to coordinate for extreme circumstances. Gas and electric operators in coordination with public officials may find situations where the energy of both the gas and electric sector is required to be reduced in order to preserve the reliability of both. While these types of

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 9

efforts are still in their infancy they should be explored depending upon the particular circumstances of each entity’s region.

• D. I ntelligence and Situational Awareness
• Fuel Surveys and Energy Emergency Protocols
• Energy emergency procedures and fuel surveys can be important tools in understanding the

energy situation in a region. The surveys can be used to determine energy adequacy for the region’s electric power needs and for the communications and associated actions in anticipation or declaration of an energy emergency. Interestingly, the fuel surveys will most likely focus on the fuel availability of other types of fuels if the gas infrastructure is the constrained resource. Examples of an Energy Emergency and Fuel Survey Protocol which could be used as part of coordination efforts can be found at the following links:

• Click here for: Energy Emergency Example
• See section 7.3.5 in Manual 14 for a seasonal survey example
• See section 6.4 of Manual 13 for a real-time survey example:
• Fuel Procurement
• Operating entities should consider evaluating each electric generators natural gas

procurement and commitment to determine fuel security for the operating day.

• The electric operating entity can collect publicly available pipeline bulletin board data and

compare the gas procurement for individual generators against the expected electric

• perations of the same facility in the current or next day’s operating plan. An example of

this type of data collection appears below with the data helping to determine if enough fuel is available to meet an individual plant or in aggregate an entire gas fleet’s expected

• peration for the current or future day. The report can indicate whether a fuel surplus or

deficit exists by asset or for an entire pipeline. If sufficient gas has not been nominated and scheduled to the Generator meter, assessments can be done to determine the impact on system operations and the operating staff may call the generator to inquire as to whether the intention is to secure the requisite gas supply to match its expected dispatch plus

• perating reserve designations.

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 10

Varying configurations of generator gas supplies can quickly complicate reports. Efforts should be made prior to the development of such reporting tools to ensure that all facets

• f gas scheduling can be displayed. Not all scheduled gas data will be publically available,

especially when dealing with LDC- and intrastate-connected generators. Generators are

• ften supplied by multiple pipelines simultaneously and may change supply sources based
• n daily natural gas prices. The electric operating entity should list its range of contractual

arrangements with the natural gas sector such as firm supply, no-notice storage, etc.

• Gas System Visualization
• Several Reliability Coordinators have developed visualization tools to provide scheduling and

real-time operations staff with situational awareness which tie the gas and electric infrastructure together at their common point of operation. What follows is an example of one such tool which has been made generic for the purposes of the illustration. The bubbles in the tool indicate the functionality which is available to the user with notes that follow.

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 11

DRAFT Reliability Guideline: Gas and Electrical Operational Coordination Considerations 12

• E. Summary

The transformation in the fuel sources used to power electric generation throughout North America and in particular, the continued increase in the use of natural gas has naturally led to the coordination processes discussed in the preceding guideline. The guideline should serve as a reference document that NERC functional entities may use as needed to improve and ensure BES reliability and is based upon actual lessons learned over the last several years as natural gas has developed into the fuel of choice due to its availability and economic competitiveness. The document focuses on the areas of preparation, coordination, communication, and intelligence that may be applied to improve gas and electric coordinated operations and minimize interdependent risks. Each entity should assess the risks associated with this transformation and apply a set of appropriate processes and practices across its system to mitigate those risks. The guidance is not a “one size fits all” set of measures but rather a list of principles and strategies that can be applied according to the circumstances encountered in a particular system, Balancing Authority, generator fleet or even an individual Generator Operator.

9-10 May 2017

ELECTRIC AND NATURAL GAS INTERDEPENDENCIES AND COORDINATION: TRAINING, EXERCISES, AND RESILIENCE PLANNING

ARGONNE GRID RESILIENCE TEAM

• Describe the work done

by Argonne emphasizing

• perator training and

tools with regard to the

• perational practices of

and the interface with the gas industry.

2

PRESENTATION OBJECTIVE

Source: www.projectsmart.co.uk

PRESENTATION OUTLINE

3

• Who are we
• Who we have worked with
• Risk, interdependencies, and resilience
• Review of approaches, methods, tools, and

capabilities

• Review of current activities and collaboration with
• perators
• Questions and discussion

OPERATING BUDGET IN 2015

$750M

EMPLOYEES IN 2015

3,300+

EXTERNAL USERS OF RESEARCH FACILITIES

6,500+

WHO ARE WE?

4

• Part of the U.S. Department of

Energy (DOE)

• Managed by UChicago Argonne, LLC
• Origins in Manhattan project
• Main site: 1500-acre site in Illinois,

southwest of Chicago

• Diverse basic and applied research

portfolio

ARGONNE IS PART OF A COMPLEX OF 17 NATIONAL LABORATORIES

5

HISTORY OF INFRASTRUCTURE ASSESSMENT METHODS AND TOOLS

• Long history of natural gas

and electric infrastructure assessment and modeling activities

• DOD – Facility Isolation

and Systems Analysis

• DOE – Energy

Infrastructure Assessments and Hurricane Support

• FEMA – New Madrid

Seismic Zone Study

• DHS – Regional Resiliency

Assessment Program

• More recent engagement

and/or activities with MISO, GridEx IV, FRCC, several NERC initiatives, PJM, and WECC

• Argonne’s Resilient

Infrastructure Initiative

6

ARGONNE RESILIENT INFRASTRUCTURE INITIATIVE

• Modeling critical infrastructure systems for optimal disaster

planning, emergency response, and community recovery

• Identifying resilient infrastructure design to minimize impacts of

disasters

• Creating innovative materials and technologies to strengthen

infrastructure

MODELING INFRASTRUCTURE INTERDEPENDENCIES TO UNDERSTAND SYSTEMIC RISK

7

http://www.anl.gov/egs/group/resilient-infrastructure

CRITICAL INFRASTRUCTURE INTERDEPENDENCIES COMPOUND SYSTEMIC RISK

Interdependencies Are a “Risk Multiplier”

8

Increase intensity and create new threats/hazards Expand the set of vulnerabilities Generate cascading and escalating consequences Expand the set of mitigation requirements

• Anticipate Consequences • Decrease Vulnerabilities
• Enhance Resilience Capabilities • Decrease Risk

INTERDEPENDENCIES ARE CRITICAL FOR EFFECTIVE RISK MANAGEMENT

9

Protect Infrastructure and Prevent Intrusions Mitigate the Effects of Disruptions (Incidents) Assist in the Management of Incidents Facilitate Recovery from Incidents

PROTECTION MITIGATION RESPONSE RECOVERY RISK MANAGEMENT THREATS Physical Geographic Logical Cyber

DISRUPTIONS CASCADE BETWEEN INFRASTRUCTURE SYSTEMS

10

Electric Power Grid Natural Gas Network

Gas-Fired Electric Power Plants Natural Gas Processing Plants

EP and NG Outages

Disruption of Natural Gas Network Disruption of Electric Power Grid

INTERDEPENDENCIES AFFECT MULTIPLE CRITICAL SECTORS

11

Source: Argonne 2016, DOE 2017 (QER)

ARGONNE RESILIENCE MODELING TOOLS COVER ENTIRE RESILIENCE SPACE

12

POST-EVENT DURING EVENT PRE-EVENT Respond Prepare (anticipate) Recover Mitigate

Respond Detect Identify Recover Protect

Grid Resilience

System Performance Time

Scenario or Threat Definition

• Describe plausible triggering

event, such as weather/climate (hurricanes, ice storms, tornados), earthquakes, cyber,

• thers

Physical Impact Assessment

• Using fragility curves, assess

physical damage to relevant infrastructure, including generators, towers/poles, wires, substations, fuel infrastructure (natural gas, coal, petroleum, etc.)

System Modeling

• Model impact of loss of fueling

infrastructure

• Model impact of loss of

multiple grid assets

• Determine potential islanding

and extent of blackout

System Restoration and Response Modeling

• Physical restoration/repair

time; crew scheduling/staging

• Electrical restoration at

transmission-level

• Electrical restoration at

distribution level

• Response logistics

ARGONNE HAS BROAD ENERGY SECTOR RESILIENCE CAPABILITIES

13

From Scenario Definition to System Restoration

ARGONNE RESEARCH DESIGNED TO CREATE VALUE

14

Advanced Algorithms

• Predictive modeling
• Advanced math/solvers
• Scalable solutions for
• ptimization
• Integrative Frameworks

Model Development

• Resource optimization
• Stochastic UC/operations
• Power market tools
• Large-scale grid tools

Model Applications

• Integration studies
• Power market design
• Long-term investment

dynamics

• Grid resilience, cascading

failures power system restoration

• Storage value/impacts
• Climate change impacts

Deployment

• EPFAST/NGFAST/POLFAST
• HEADOUT, RESTORE, EGRIP
• GTMax/ EMCAS/CHEERS
• EZMT
• AMP
• onVCP/vBEOC

From Development of Advanced Algorithms and Models to Commercialization and Deployment

ARGONNE RESILIENCE MODELING TOOLS

15

Prepare

Self-assessment/ maturity (ERAP-D)

Emergency planning (onVCP/ SyncMatrix, SpecialPop, AMP) EP/PSR exercise/ drill (Scenarios, Threat-Damage, Impact Models) Gas-electric coordination (NGfast/ NGrealtime)

Mitigate

Mitigation assessment (EPfast, NGfast, POLfast, others)

Resource mitigation measures, dependencies (IST-RMI)

Power system restoration, blackstart resource planning (EGRIP) Gas-electric coordination (NGfast/ NGrealtime)

Respond

Impact assessment (Threat-Damage, Impact Models)

Hurricane assessment (HEADOUT)

Emergency management/resp

• nse (onVCP,

vBEOC) Response logistics (AMP)

Recover

Real-time PSR analysis (EGRIP) Emerge-Manage., Communication, Collaboration (onVCP/vBEOC) Recovery logistics (AMP)

ARGONNE RESILIENCE MODELING TOOLS

• EPfast examines the

impacts of power outages on large electric grid systems

• Models the tendency of

power systems to “island” after either man‐made or natural disturbances, which can lead to regional power disruptions

• Recently applied in

Extended Power Outage Studies for FEMA V and VIII

• NGfast is a natural gas –

electric interdependency tool

• Estimates impacts to natural

gas sector from user-defined hazards and determines gas-fired power plants at-risk

• f fuel disruptions
• Applied in Extended Power

Outage Study for FEMA VIII

• Currently being applied for

NERC Single Point of Disruption (SPOD) Study

16

Site A Site B

Substation “X” (345 kV)

Potential Blackout Area Resulting from Outage of 345-kV Substation

• RESTORE offers

insights into physical

• utage repair times at

critical infrastructure facilities

• Identifies the

dependencies of the affected infrastructure and its impact on the restoration process

16

• EGRIP is an AC power flow

based cascading failure/outage and integrated power system restoration optimization tool

• Supports restoration planning

and operational decision- making for bulk-level and distribution-level restoration

• Applied in Extended Power

Outage Studies for FEMA V and VIII

ARGONNE RESILIENCE MODELING TOOLS

• onVCP and vBEOC

provide situational awareness and Common Operating Picture for drills/exercises and during actual events

• 4000+ users; 700 unique
• rganizations; used in

CUSEC Capstone-14 and 2015 Operation Power Play

• AMP evaluates logistics

and transportation feasibility of emergency response plans

• AMP is the Program of

Record for Military Transportation Analysis

• Used by USTRANSCOM

for logistics analysis for large power outage

17 Simulated Restoration Times by Census Tract and Population Affected

OVERVIEW OF CURRENT EP/NG TRAINING, SCENARIO DEVELOPMENT, AND MODELING ACTIVITIES

18

IMPROVED TRAINING: MISO GAS/ELECTRIC COORDINATION

• Developed NERC-certified

training course for MISO system operators on natural gas and electric coordination

• Trained over 600 MISO grid
• perators on electric/gas

interdependencies as part of 2015 and October-2016 NERC-certified EP/PSR training cycle

• Geared toward creating a

greater awareness of electric- gas emergency scenarios and vulnerabilities in MISO and NERC footprint

• Similar training is anticipated

for other RCs or ISOs in 2017

19

TRAINING COURSE ON GAS- ELECTRIC ISSUES: PART 1

Part 1: Overview and Presentation of Concepts

• Summary of regional gas/electric coordination activities
• Overview of regional capacity and generation profiles,

trends, and projections

• Increased reliance on natural gas and historical events
• Issues that impact natural gas service to generation

providers

• Natural gas infrastructure concepts relevant to the

region

• Electric power and natural gas interdependency

concepts

20

TRAINING COURSE ON GAS- ELECTRIC ISSUES: OVERVIEW

21

Natural gas infrastructure consists of upstream, mid- stream, and downstream components

• Upstream Components
• Production Wells, Natural Gas

Processing Plants, Originating Compressor Stations

• Mid-stream Components
• High-Pressure Pipelines,

Intervening Compressor Stations (gas- or electric- driven), and Storage

• Downstream Components
• City Gates, Distribution

System, Storage, Delivery Points, Compressor Stations, and Loads

Electric Interdependency

• Customer demand exceeds contracted pipeline capacity
• Pressure problems on the gas system
• Physical disruption of the gas system
• Supply limitations
• Curtailment generally occurs in the winter, but customers

should be prepared to curtail year round

• Pipeline companies rely on two common methods to protect

the operational integrity of the pipeline:

• Operational flow orders (OFO)
• Curtailment

22

TRAINING COURSE ON GAS-ELECTRIC ISSUES: GAS SUPPLY DISRUPTIONS

• Operational Flow Order:
• Requires shippers to

balance their supply with their customers' usage on a daily basis, within a specified tolerance band (percent of allowable variance)

• Curtailment:
• Firm transportation -

no interruption in service, unless force majeure

• Interruptible

transportation - subject to interruption at the option of the pipeline company

TRAINING COURSE ON GAS-ELECTRIC ISSUES: GAS SUPPLY DISRUPTIONS

23

TRAINING COURSE ON GAS- ELECTRIC ISSUES: PART 2

Part 2: Situational Awareness via Scenario-based Exercise

• Application of Public Information and Bulletin Boards
• Application of NGfast Simulation Model to Assess

Impacts and Mitigation Options

24

IMPROVED DRILLS/EXERCISES: SUPPORT NERC GRIDEX-IV NATIONAL EXERCISE

• Participated in GridEx III: 4 team

members participated as evaluators and

• bservers to identify areas of

improvement in the conduct and formulation of the training exercise

• Part of NERC-led working group

developing GridEx-IV; serving on the Operations Subteam

• Contributed significantly to the injects in

the Master Scenario Event List regarding electric power, natural gas, and communication interdependencies

25 25

THREATS/HAZARDS VARY BY REGION AND FORM BASIS FOR SCENARIOS

26

SERC

• Supported MISO working group for Emergency Preparedness and Power

System Restoration (EP/PSR) since spring 2015

• Participated in April 2016 spring drill on preparedness and October 2016

fall drill on response/recovery (Oct 4+5, Oct 18+19)

• Spring drill included hurricane scenario and impact on various assets,

including power plants, substations, transmission assets, and communications

• Fall drill focused on restoration while facing natural gas issues
• Currently assisting MISO with 2017 Spring Drill (gas/electric/telecom)

IMPROVED SCENARIO DEVELOPMENT: EP/PSR EXERCISES/DRILLS

27

Gas-Electric Interdependency

IMPROVED SCENARIO DEVELOPMENT: EP/PSR EXERCISES/DRILLS

• Customized initiating

event/threat

• Natural (e.g., hurricane)
• Man-made (e.g., cyber)
• Customized

impact analysis

• Grid
• Telecom
• Fuel

28

Power Plants at Risk

Entergy Services, Inc.

Microwave Comms at Risk

IMPROVED SCENARIO DEVELOPMENT: EP/PSR EXERCISES/DRILLS

• Customized interdependency analysis

29 Natural Gas Processing Plants

Direct Connect NG Power Plants

Coal Plants

Electric-Driven Compressors

IMPROVED DRILLS/EXERCISES:

SUPPORT FEMA REGIONAL POWER OUTAGE EXERCISES

Location of Natural Gas- fired Power Plants Disrupted by Postulated Electric Outage Scenario

• Enable resilience stakeholders to

consider restoration/recovery aspects for more effective emergency preparedness exercises

• EPfast for impact/outage analysis,

EGRIP to find optimal restoration plan that minimizes the overall power system restoration time

• DHS/FEMA Region 5: Grid

impacts and response/recovery/ restoration from large-scale cyber attack

• DHS/FEMA Region 8: Impacts of

major winter storm based on January 1949 Blizzard

Restoration results estimated by Argonne’s EGRIP model for FEMA Region V

30

ARGONNE STUDIES A RANGE OF NATURAL GAS ISSUES ACROSS THE NATION

31

• Local Distribution Companies (LDCs)
• Interstate Pipeline Companies
• Gas Associations

Analyses for DOE and DHS Studies Conducted in Close Collaboration with Gas Industry: Hazards & Threats Analyzed for DHS and DOE

NGFAST APPLICATION: IMPACT OF A NMSZ EVENT ON FEMA REGION V

32

40 Type Low High Resid 15 15 Comm 6,415 32,076 Indust 4,860 14,580 Elect 16 49 Total 11,307 46,720 Illinois People Affected:

2,195 Type Low High Resid 896 896 Comm 7,028 35,141 Indust 272 817 Elect

• Total

8,197 36,854 Kentucky People Affected:

75,371 Type Low High Resid 31,145 31,145 Comm 11,593 57,964 Indust 845 2,535 Elect 1 2 Total 43,583 91,646 Missouri People Affected: 2,472 Type Low High Resid 985 985 Comm 1,113 5,565 Indust 221 664 Elect 4 13 Total 2,324 7,227 Indiana People Affected:

Impacts to Other States:

NGfast results discussed with gas sector at DOE-FEMA and DOE workshops.

NGFAST APPLICATION: DOE CASCADIA IMPACTS ON ELECTRIC SECTOR

• 2012 DOE project to analyze impacts of a

Cascadia Subduction Zone (CSZ) earthquake.

• Downstream impacts on electric sector

estimated using NGfast tool:

• FEMA HAZUS approach used to determine

pipeline damage from a CSZ event

• Approximately 1.9 GWe of gas-fired

generation affected over a multi-state region (WA, OR, CA, NV):

• Amount of electric capacity at-risk per state is

not significant (except for Washington)

• Total of 1.9 GWe does not include power

plants damaged by earthquake or tsunami

• The above estimate does not include loss of

natural-gas-fired power plants in British Columbia.

33

NGFAST APPLICATION: FEMA REGION VIII IMPACT ON POWER PLANTS – WINTER STORM

• Applied NGfast tool to estimate

impacts of January 1949 Blizzard.

• Cold weather in the western United

States has historically disrupted natural gas production:

• San Juan Basin, which stretches across

southern Colorado, is especially susceptible to freeze-offs due to the water production in those areas.

• Power plants at-risk of loss of gas

supply based on type of transport contract:

• EIA 923 data for 2014 indicates most

power plants have interruptible transport contracts.

• NGfast tool used to estimate reduction

in natural gas generating capacity and impacts on other customer classes.

34

• Over 60 UGSs with potential impacts on power plant capacity
• 12 UGS facilities appear to have the potential to affect 2 GW or

more of available generation capacity

• Largest predicted impacts from UGSs owned by independent
• perators; many located in Gulf Coast
• Aliso Canyon not the only California UGS with potential impacts

NGFAST APPLICATION: INTERAGENCY TASK FORCE

35

https://anl.box.com/s/q 6yqtnexfvlhyobn1dzlwn cr5xc8vf88

NGFAST APPLICATION: NERC SPOD STUDY

• Update most recent analysis on

UGS impacts published in December 2016 report using additional data not previously available

• Using Argonne’s NGfast tool,

analyze potential electric sector impacts of disruption of

• perations of 100-plus

interstate transmission pipelines and any of a dozen current LNG import terminals

36

Plant icon size determined by MW Capacity. Searching for a plant zooms in to the plant location and brings up the details about the plant

NGFAST APPLICATION: NEW REAL-TIME VERSION FOR MISO

• Latest version deployed in March 2017
• Also deployed to FERC Office of Energy Infrastructure

Security

37

NGfast Simulation Engine Spring/Summer 2017 Version

IMPROVED AWARENESS: REAL- TIME GAS-ELECTRIC TOOL DEPLOYED TO MISO

• Next phase will merge MISO-internal data including critical

notices and generator schedule/dispatch info (data will remain strictly within MISO)

38

NGRealtime Data Visualization (Client Machine) NGRealtime Data Server (Argonne Server) December Version MISO Gas Critical Notices MISO Request Early 2017 Version MISO UC/ED Operations Platform MISO Request Early 2017 Version

IN SUMMARY

• Argonne offers extensive experience and expertise and a range
• f tools to meet stakeholder needs for grid operational analysis,

investment planning, vulnerability and resilience analysis and evaluation, operational drill and exercise support, and faster and more efficient response and recovery

• Argonne works with diverse stakeholders, including electric and

gas industry, other interdependent industries, and emergency response agencies

• Argonne conducts extensive analyses and studies that feed into
• perational exercises with various stakeholders and have

already led to tangible steps to improve grid resilience

• Argonne seeks continued collaboration with RCs and ISOs in a

meaningful and productive way to address regional electric/natural gas coordination concerns

39

FOR MORE INFORMATION PLEASE CONTACT:

40

Jim Kavicky

Risk and Infrastructure Science Center Argonne National Laboratory 630-252-6001 kavicky@anl.gov

Steve Folga

Risk and Infrastructure Science Center Argonne National Laboratory 630-252-3728 sfolga@anl.gov

Guenter Conzelmann

Center for Energy, Environmental, and Economic Systems Analysis Argonne National Laboratory 630-252-7173 guenter@anl.gov

NGFAST APPLICATION: DHS NEBRASKA RRAP ELECTRIC IMPACTS – WELL FREEZE-OFFS

• Scenario assumed harsh winter conditions

cause many production fields in Wyoming and Colorado to freeze:

• Freezing of wells significantly (up to 75%)

curtails supplies typically transported by Kinder Morgan Interstate Gas Transmission (KMIGT).

• Similar to situation in Southwestern U.S. in early

February 2011 which curtailed over 7 Bcf/d of natural gas production.

• NGfast identified at-risk electric generators

which receive natural gas from KMIGT:

• Most natural gas-fired power plants have

alternative fuels capability.

• Low amount of natural gas-fired electric

generation in Nebraska.

• Do not expect loss of local generation to lead to

voltage concerns because of available backup fuel inventories.

41

NGFAST APPLICATION: DHS RRAP IN CALIFORNIA – SAN ANDREAS FAULT EARTHQUAKE

• Scenario assumed a M7.8 earthquake in southernmost section
• f San Andreas Fault in California:
• Multiple Southern California Gas Company (SoCalGas) pipelines

are at-risk of rupture.

• Pipelines within Cajon Pass at-risk of disruption determined using

FEMA HAZUS approach.

• Supply-demand balance for SoCalGas indicated a small

shortfall in natural gas supply under summer peak conditions:

• There may actually not be a shortfall under summer peak

conditions after a San Andreas earthquake because customer demand for natural gas may drop due to disruption of electricity and damaged structures that will not require gas supply.

• Customer demand after an earthquake during winter or

summer peak conditions can be satisfied through gas withdrawal from SoCalGas underground storage facilities:

• Assuming emergency withdrawals from SoCalGas storage fields.
• Based on maximum deliverability of 3,760 MMcf/day.
• Did NOT consider current closure of Aliso Canyon storage field.

42

2017 Summer Reliability Assessment

Bill Lamanna, Senior Engineer of Reliability Assessment May 9-10, 2017 ORS Meeting

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• Resource Adequacy
• All areas except NPCC-New England project sufficient Planning Reserve

Margins

• Management of Renewables in Over-supply Conditions
• Flexible, load-following resources must be available
• Abundant hydro resources in California
• Higher than average curtailments of renewables expected
• Aliso Canyon Outage in Southern California
• No anticipated reliability impact to bulk power supply
• Solar Inverter Dynamics and Disturbance Performance
• NERC Alert (to be published) identifies potential risks for certain

inverter designs

• 2017 Solar Eclipse
• No anticipated reliability impact to bulk power supply

Key Findings

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Resource Adequacy

Summer 2017 Anticipated/Prospective Reserve Margins Compared to Reference Margin Level

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Management of Renewables in Over- Supply Conditions EIA: California Drought Status

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Management of Renewables in Over- Supply Conditions EIA: California Snow Water Equivalent

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Aliso Canyon Outage in Southern California

Over 100 MW built in less than 6 months

(Source: GTM Research)

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Solar I nverter Dynamics and Disturbance Performance

• On August 16, 2016, the Blue Cut Fire caused thirteen faults on

500 kV transmission lines

• No qualified events but Entities volunteered to work with the

ERO to understand the occurrences

Source: SCE

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• Purpose: To evaluate potential reliability consequences of the August

21, 2017 total solar eclipse on the BPS, with a focus on peak system

• perations.
• Main Objectives:
• Develop an extreme case using ideal weather conditions under peak

system operations

• Scenario eclipse test case which includes hourly load data, forecasted

photovoltaic generation with a built in range

• Identify and assess the eclipse test cases for any potential system

reliability and/or operational impacts

2017 Solar Eclipse, Wide Area Assessment

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2017 Eclipse Path and Eclipse Bands

Direct normal irradiance by annual average (Wh/m2/day), eclipse bands and locations of transmission photovoltaic resources

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• Results of the total eclipse whitepaper:
• Showed no impacts to the reliability of the BPS, but will impact
• perations in solar-dense areas
• Some states with a large amount of PV resources are expected to have:
• Increased load
• Changes to ramping profiles, unit commitment, and balancing
• General Recommendation:
• Areas should secure non-PV resources for system operations
• Perform advance coordination with neighboring systems for transfers

2017 Solar Eclipse Key Results

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