Communications & PJM All-Call Overview. Interconnection Training Program Module FC

Transcription

1 Disclaimer This training presentation is provided as a reference for preparing for the PJM Certification Exam. Note that the following information may not reflect current PJM rules and operating procedures. For current training material, please visit: PJM 2014

2 Communications & PJM All-Call Overview Interconnection Training Program Module FC 1 3/6/2014

3 Module Objectives Given a specific generation and/or transmission operating requirement, identify the need for use of 3-part communication Given specific operating information, demonstrate the use of 3-part communication in accordance with NERC Standard COM-002 Explain satellite telephone communications and identify the importance of the testing process Explain the nuclear plant communication process given a special situation or event affecting a nuclear plant within PJM 2 3/6/2014

4 Agenda Review of Communication Best Practices and 3-Part Communication Nuclear Plant Interface/Communication Process PJM All-Call Process Satellite Phone Testing Overview PJM Telecommunications Overview 3 3/6/2014

5 Communications Review Efficient and effective communications are critical to the operation of a Power System Communications cannot be taken for granted Communications must be concise Communications must be understood 4 3/6/2014

6 Poor Communication Consequences General: Some things don t get done Some things are done late or incomplete Mistakes are made Duplication of work Sender blames receiver AND Receiver blames sender for misunderstandings and poor results 5 3/6/2014

7 Poor Communication Consequences Poor Communication Consequences- Dispatching Mistakes and duplication of work Possible personal injury Possible equipment damage Possible interruption to customer load Possible loss of revenue Lack of confidence between individuals 6 3/6/2014

8 Communication Best Practices Good Utility Practices As Defined By The Federal Energy Regulatory Commission (FERC) Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result of the lowest reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region. 7 3/6/2014

9 Communication Best Practices What do we mean by communication best practices? Using the best or ideal communication practices Communication practices which will further avoid mistakes and miscommunications Coincide with current communication standards 8 3/6/2014

10 Communication Best Practices What are the different communication requirements/ practices which Operators must consider? Best Practices PJM Manuals NERC Standards 9 3/6/2014

11 Communication Best Practices Who should utilize these communication best practices? Everyone operating within the PJM system Some of these practices are not voluntary They do not apply only to PJM Operators Goal is to utilize them on a day-to-day basis in conjunction with the use of 3-part communication 10 3/6/2014

12 Communication Best Practices Data Verbal Written Types of Communication Exchange 11 3/6/2014

13 Communication Best Practices - Identification How can you prevent miscommunications from the start of your communication process? Identify yourself at the beginning of the communication process First Name, Last Name, Company ~ Ideal or Best Practice Last Name, Company ~ Minimum 12 3/6/2014

14 Communication Best Practices - Terminology What are some key things to remember about using proper terminology? Helps avoid mistakes and miscommunications Use correct terminology during normal operations Avoid the use of jargon or lingo Use of phonetic alphabet when appropriate Avoid the use of acronyms 13 3/6/2014

15 Acceptable Acronyms Acronyms are acceptable if: Acronym is better known than the definition I.e. ESPN, IBM, VHS, CBS, edart Acronym is widely known in society USA, PC, UFO, DVD Acronym is widely known in electric industry PJM, LMP, NERC, FERC You are positive your receiver knows the acronym When in doubt, spell it out! 14 3/6/2014

16 They are considered legal documentation Use for operations review / after-the-fact analysis Must be complete, clear and concise, and legible (if written) Avoid acronyms Document stations/equipment Communication Best Practices - Logging What is the importance of/correct logging process? 15 3/6/2014

17 Communication Best Practices - Logging Logging Process Best Practices Must be complete, accurate, and legible Should be of relevant data Should be used to support strategic decisions Should be used to document actions taken Entries should include time and way of tracking author 16 3/6/2014

18 Communication Best Practices - Logging Logging Process Best Practices Use correct terminology Should be in pen No erasures or white-out Good entries should not generate questions If in doubt, log it Examples: Units Running, Changes, Trippings, Any Discrepancies 17 3/6/2014

19 Communication Best Practices Identifying Equipment/Lines What should be identified by Operators? Identify by name, reference to: Equipment Stations Lines (Terminal Terminal, Voltage, Line #) Devices Repeat of information should include names as well 18 3/6/2014

20 Communication Best Practices Identifying Equipment/Lines NERC Advisory: COM 002-2: Communications & Coordination NERC requires communication exchanges which involve equipment should include names of equipment instead of using generic terms ie. Station ABC open 345 kv breaker number 123 vs. Let s get that breaker open 19 3/6/2014

21 Directives & 3-Part Communication 20 3/6/2014

22 Directives & 3-Part Communication NERC Standard COM-002 has been implemented which includes mandatory use of 3-part communication Expectations include use of this process in any and all internal and external communications. NERC Standard COM : Communication & Coordination Purpose: To ensure Balancing Authorities, Transmission Operators, and Generator Operators have adequate communications and that these communications capabilities are staffed and available for addressing a real-time emergency condition. To ensure communications by operating personnel are effective. 21 3/6/2014

23 Directives & 3-Part Communication NERC Standard COM : Communication & Coordination R2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall issue directives in a clear, concise, and definitive manner; shall ensure the recipient of the directive repeats the information back correctly; and shall acknowledge the response as correct or repeat the original statement to resolve any misunderstandings. 22 3/6/2014

24 Directives & 3-Part Communication PJM defines a Directive as the following: Instructions from PJM to its members to take actions to control their Interconnected Reliability Operating Limit (IROL) or initiate load dump measures for capacity or transmission emergencies. Control Center Requirements Full Definition Found In: PJM Manual 1 Section 4: Control Center & Data Exchange Requirements 23 3/6/2014

25 Directives & 3-Part Communication Generation Operations Requiring 3-Part Communication:* Unit starts Unit trips or releases Requests from PJM for additional generation edart ticket numbers Synchronized Reserve or Regulation assignments Manual dispatch of generation Emergency operations related information *Partial list - Manual M1, Section /6/2014

26 Directives & 3-Part Communication Transmission Operations Requiring 3-Part Communication:* Transmission switching Capacitor switching Outages (edart ticket number and line numbers, not every circuit breaker) PCLLRW issuance and cancellation TLR cuts in transactions Market to Market redispatch Emergency operations related information *Partial list - Manual M1, Section /6/2014

27 Directives & 3-Part Communication Directives as defined by PJM require use of 3-Part Communication Internal audits are performed to verify use of 3-Part Communication Best practice: Use of 3-Part Communication for all exchanges (per M-1) Message Repeat Confirm 26 3/6/2014

28 Directives & 3-Part Communication Message Clear & Concise Speak Slowly Re-start communication process when signs of confusion are present 27 3/6/2014

29 Directives & 3-Part Communication Repeat Ask for clarification if necessary Understand information Repeat back information correctly and thoroughly Note: Provider/Sender of information should prompt repeat of information if not done voluntarily 28 3/6/2014

30 Directives & 3-Part Communication Confirm Repeat message if necessary Correct receiver of information if repeated incorrectly Provide proper confirmation Acceptable Yes, that is correct Ok, that is correct Correct Unacceptable Yeah, man OK Alright, yeah, bye 29 3/6/2014

31 Directives & 3-Part Communication How do we handle All-Call Messaging and 3-Part Communication? Since the All-Call messaging is a form of 1-way communications, 3-part communication is not required Verification or clarification of All-Call messages are the responsibility of the Operator Contact PJM Shift Supervisor or other appropriate individual 30 3/6/2014

32 Repeating back information incorrectly Failing to be thorough in repeatback (ie. not naming stations/lines/devices) Sender failing to correct the Receiver of information Directives & 3-Part Communication Examples of what would result in red flag during NERC Audit: 31 3/6/2014

33 Why Should We Use 3 Part Communication? Improves SAFE operation Increases the probability of communicating critical information correctly Helps to eliminate assumptions Establishes clear objectives Provides continuity of work practices Serves as a Checks and Balances on communications But most importantly. 32 3/6/2014

34 When Do I Use 3 Part Communication? Am I providing information to be documented? Am I giving or receiving directions? Is this a request that requires some action? Is this operational information? 33 3/6/2014

35 Additional Tips on How to Use 3 Part Communication Identify yourself at the beginning of the communication process Avoid using words and/or language that indicates indecisiveness or assumptions As a Sender, speak slowly and clearly so the Receiver can write the instructions if necessary. If you are writing instructions or information, write them down BEFORE repeating back. 34 3/6/2014

36 Operating Example Lessons Learned Conversation between PJM and MOC Names, companies, unit information, voices changed Listen to conversation Read transcript in exercise Answer questions following exercise Work in small groups 15 minutes to complete 35 3/6/2014

37 Agenda Review of General Communication Practices and PJM Communication Protocols Nuclear Plant Interface/Communication Process PJM All-Call Process Satellite Phone Testing Overview PJM Telecommunications Overview 36 3/6/2014

38 Nuclear Plant Interface/Communication Purpose is to review communication expectations with Nuclear Plants owners and operators This includes communications surrounding current and future operations between PJM, nuclear plant operators, and transmission owners (TOs) The nuclear plant communications protocol stresses the importance of accurate and timely communications between all parities involved 37 3/6/2014

39 Nuclear Plant Interface/Communication PJM Manual 39 documents Nuclear Plant Interface Coordination Appendix A: Nuclear Plant Communications Protocol will provide additional details regarding requirements Manual coincides with NERC Standard NUC Nuclear Plant Interface Coordination 38 3/6/2014

40 Nuclear Plant Interface/Communication Who is responsible for communicating information? All necessary communications between PJM and the nuclear plant should be through the Transmission Owner (TO) If the plant needs to speak directly with PJM, the Transmission Owner should be included in the discussion via a 3-way call PJM will request all actions and provide information to the nuclear plant through the Transmission Owner 39 3/6/2014

41 Nuclear Plant Interface/Communication What are the requirements involving these communications between affected parties? All affected parties should follow proper communication protocol when disseminating information All affected parties should be familiar with and understand key phrases and terms used by each other, especially during special/critical events The receiver of the message should immediately disseminate information to their shift team and/or Shift Supervisor 40 3/6/2014

42 Nuclear Plant Interface/Communication What are the requirements involving these communications between affected parties? Accurate logging procedures should be followed when logging of information is required (may be needed later for investigation purposes) All parties should be mindful of their own reporting obligations and carry these out as necessary (ie. NERC, NRC, etc) 41 3/6/2014

43 Agenda Agenda Review of General Communication Practices and PJM Communication Protocols Nuclear Plant Interface/Communication Process PJM All-Call Process Satellite Phone Testing Overview PJM Telecommunications Overview 42 3/6/2014

44 PJM ALL-CALL 43 3/6/2014

45 Receiving PJM All-Call Messages 1 PJM issues message and the phone rings at LCC or MOC 2 Operator must pick-up and speak to activate the message (Name & Company) 44 3/6/2014

46 Receiving PJM All-Call Messages 3 Listen to all-call message Press 9 to repeat message Press 6 to acknowledge receipt of message 4 Question Initiator or Supervisor (for Emergency Messages) 5 Call will track to next number 45 3/6/2014

47 Message Categories Operational Scheduling Emergency Procedures 46 3/6/2014

48 Message Categories Operational General Information (GD, PD, MC or SS depending on message) Generation Dispatch (Generation Dispatcher) Instantaneous Reserve Checks (Generation Dispatcher) Off-cost Operations (Power Dispatcher) Solar Magnetic Disturbance Information (Generation Dispatcher) Time Correction Information (Generation Dispatcher) 500 kv & Above Switching (Power Dispatcher) 47 3/6/2014

49 Message Categories Scheduling Scheduling Information (Master Coordinator) Regulation Information (Master Coordinator) 48 3/6/2014

50 Message Categories Emergency Procedures Emergency Alerts, Warnings, and Actions (GD, PD, MC or SS depending on message) Minimum Generation Information (Master Coordinator or Generation Dispatcher depending on shift) Synchronized Reserve Activations (Generation Dispatcher) Supplementary Status Report (Master Coordinator) 49 3/6/2014

51 All-Call Responses Supplementary Status Report Compile information that is requested. Enter information into edart Minimum Generation Information Request Compile information that is requested. Enter information into edart 50 3/6/2014

52 All-Call Responses 100% Synchronized Reserve Inform generators to provide synchronized reserves Monitor generators performance Off-cost or Constrained Operations Dispatch generators in accordance with PJM instruction (if applicable) Inform PJM of any deviation from instructions 51 3/6/2014

53 All-Call Responses Loading Maximum Emergency Direct generators to load to their Max Emergency MWs per PJM s directives Minimum Generation Declaration or Event Direct generators to reduce output in accordance with capability reported to PJM 52 3/6/2014

54 All-Call Responses Quick-start Requests Notify generators to operate (if applicable) Monitor adherence to request and log actions Start Failure Requests Gather information (if applicable) Provide PJM with requested information 53 3/6/2014

55 All-Call Responses Instantaneous Reserve Checks Gather information Enter IRC into edart Block Loading CT s Notify generators to operate (if applicable) Monitor adherence to request and log actions 54 3/6/2014

56 All-Call Responses Emergency Procedures Implement emergency procedures Inform PJM of any deviation from request SMD Information Implement SMD procedures in accordance with PJM 55 3/6/2014

57 Agenda Review of General Communication Practices and PJM Communication Protocols Nuclear Plant Interface/Communication Process PJM All-Call Process Satellite Phone Testing Overview PJM Telecommunications Overview 56 3/6/2014

58 Satellite Phone Review Satellite Phone tests are normally conducted by PJM on the third Sunday of each month Tests are conducted to verify that all equipment is working correctly and proper communication protocols are being used Two tests are conducted including the use of the Push-to-Talk (PTT) and Twoway Point-to-Point systems 57 3/6/2014

59 Satellite Phone Review When Does Testing Take Place? Tests may need to take place more frequently depending on current security level Homeland Security level Yellow requires weekly testing take place Initiation of Yellow Homeland Security level requires initial daily testing and weekly testing thereafter 58 3/6/2014

60 Satellite Phone Review Who Participates In The Testing? All Member Companies with satellite phone systems participate in the tests Transmission Owners must have satellite phones at both their primary and back-up facilities Generation Operator (GO) Control Centers must have satellite phones when one or more units total 500 MW or greater 59 3/6/2014

61 What Are The Main Purposes of Testing? Satellite Phone Review The testing ensures proper functionality and reliability of the satellite phone system at both PJM & Member Company locations Allows the opportunity to test readiness level of Operators Operators have the opportunity to become familiar with the satellite phone equipment 60 3/6/2014

62 Satellite Phone Review Communication Protocols & Testing Testing ensures proper communication protocols are being followed when using the satellite phone system Speak clearly, slowly and be mindful of pronunciations Use proper code words when communicating Over when message/statement complete Out when terminating transmissions (Initiator) Always identify your LCC and your name 61 3/6/2014

63 Agenda Review of General Communication Practices and PJM Communication Protocols Nuclear Plant Interface/Communication Process PJM All-Call Process Satellite Phone Testing Overview PJM Telecommunications Overview 62 3/6/2014

64 Real-time Data Real-Time Data PJM and Member Companies analyze the security of the system using real-time information The model and results of PJM and the Member Companies network applications is only as accurate as the input data used in the calculations and modeling. Garbage in. Garbage out Per NERC Standard IRO-001-2, requirement 2, PJM has determined and listed the data required from the Member Companies in order to accurately monitor the security of the electric system. 63 3/6/2014

65 Data Requirements Analog Data measurements required Voltages for buses at 34 kv & above MW & MVAR values for individual generating units > than 1 MW MW & MVAR values for designated transmission facilities at 69 kv & above (for single-phase metering, B-phase is preferred) Transformer phase angle regulator (PAR) tap Transformer load tap changer (LTC or TCUL) tap MVAR values for synchronous condensers MW & MVAR injections on buses at 34 kv and above Selected station frequencies 64 3/6/2014

66 Data Requirements Status Data required Circuit breaker status for each modeled facility at 69 kv and above Breaker and disconnect statuses as modeled Transformer fixed tap settings (change in no-load tap setting) 65 3/6/2014

67 Data Exchange EMS data is exchanged periodically on one of several fixed cycles, as well as on demand, by exception, and interactively. Cyclic Data Sent from Member Companies to PJM includes data needed for: PJM control programs Monitoring generation Monitoring transmission Monitoring interchange Sent from PJM EMS to Member s EMS includes: System control data Generation & transmission information required for monitoring & security analysis programs Area Regulation data 66 3/6/2014

68 Data Exchange Fast Scan Rate Must be at least every six seconds (NERC) Used to develop ACE and regulation values. Slow Scan Rate Longer than six seconds Dispatch control values, security monitoring and data tracking Hourly Data Accumulated energy values 67 3/6/2014

69 Data Exchange Data exchanged by exception, on demand or interactively: Breaker Disconnect Line status changes Emergency messages in text format Data Accuracy Max of 2% overall inaccuracy of data from transducers or potential transformers/current transformers (PTs/CTs) 68 3/6/2014

70 Data Exchange ICCP Inter-control Center Communication Protocol International standard Used to exchange data between control centers, utilities, power pools, regional control centers, etc. DNP3 Distributed Network Protocol Primarily used for communications between a master station and RTUs 69 3/6/2014

71 RCIS IDC NEPOOL NYISO MISO PJM EMS SUB RTU PECO EMS GEN MW/MVARS CB Pos Voltage TransCo SUB RTU DPL EMS GEN SUB RTU GEN BGE EMS GEN 70 3/6/2014 Substation

72 Data Link Outages EMS Advanced Applications Single State Estimator solution Basis for the PJM Unit Dispatch System (UDS) Network Applications Package Interruptions to data / inaccurate data could result in: Non-convergence to the state estimator Inability of PJM and Member LCC s to monitor the transmission system Unnecessary ICCP link outages / database maintenance Avoid if possible Multiple company ICCP datalink outages could result in: PJM or Member Company EMS Security Analysis issues Potential system reliability issues even during moderate load levels. 71 3/6/2014

73 Data Link Outages Scheduling Data Link Outages Planned Outages: Attempt to schedule 24 hours in advance Only one company planned outage should be scheduled in any time period PJM staff has the authority to: Reschedule or cancel a member company scheduled planned outage based on system conditions Reschedule or cancel a member company scheduled planned outage based on existing ICCP data link outages Deny a request for a member company planned outage if requested time has been previously scheduled 72 3/6/2014

74 Data Link Outages Scheduling Data Link Outages cont d During Peak Load Operations, to the extent possible, emergency changes should occur: During Summer operations - prior to 11:00 EPT During Winter operations - between 10:30 14:30 EPT Weekly routine maintenance should be canceled or rescheduled to days when emergency procedures are not anticipated. 73 3/6/2014

75 Data Link Outages Unscheduled Data Link Outages Considerations / actions: MOC or Generator Owner/Operator Contact PJM Dispatch to report/discuss problem Recognize prior UDS approved base-point is stale while ICCP problems exist Resolve communications issue (support staff) Manually dispatch directions to plants verbally if problem is not resolved within 10 minutes Log manual dispatch directions Provide a contact person to PJM Dispatch to enhance operations during reliability issues. 74 3/6/2014

76 Data Link Outages Unscheduled Data Link Outages Considerations / actions: LCC or Merchant Transmission Contact PJM Dispatch to report/discuss problem Resolve communications issue (support staff) Contact PJM Dispatch regarding transmission constraints Verbally communicate critical data to PJM Dispatch as needed Provide a contact person to PJM Dispatch to enhance operations during reliability issues. 75 3/6/2014

77 Data Link Outages Unscheduled Data Link Outages cont d Considerations / actions PJM Actions Contact MOC/LCC to discuss communication issues Resolve communication issue Recognize prior UDS approved base-point as stale while ICCP link is down Communicate zonal cost if communication issues are not resolved within 10 minutes Communicate targeted generation dispatch if transmission constraints arise Log manual dispatch/reassign regulation as necessary Communicate impact on ability to monitor transmission system Elevate communication to Shift Supervisor if reliability issues arise. 76 3/6/2014

78 RTU Outages RTU Outages All outages that affect PJM s ability to receive telemetered data must be reported Scheduled outages should be communicated to PJM one day in advance and again prior to the outage In the case of RTU s for 345 kv and above, personnel at the station will have to relay critical data to the LCC and PJM Data to be kept manually updated includes: MW line flows for 500 kv and higher line and all tie lines Bus voltages for all 500 kv and higher stations Affected data must be updated: After loss of major generator or transmission line When value has a change of 100 MW or more for 500 kv and above, 50 MW for 345 kv and below At least every 30 minutes 77 3/6/2014

79 Manually Entered Data What is it? Data that is manually entered and updated by the System Operator Steps: Identify suspected data Verify validity of suspected data Use other tools, your experience & knowledge, and other computer models if available Sanity check - bus summation calculations Determine requirements for updating (For 500kV & higher RTU or tie lines, 30 minutes, Manual 3) Resolve cause of bad data Once data issue is corrected, restore telemeter value to normal. 78 3/6/2014

80 Manually Entered Data Keeping on top of Manually Entered Data Start of Shift: Identify points that are currently updated manually Shift turnover sheet or pass down from previous shift EMS displays that summarize manually replaced data During Shift: Monitor system for additional bad data Take necessary action to correct data when found Update values or status of current manually replaced data End of Shift: Inform your relief of all points currently manually entered. Update shift turnover sheet or pass down 79 3/6/2014

81 Manually Entered Data 3/6/

82 Manually Entered Data 3/6/

83 Manually Entered Data 3/6/

84 Impacts of Bad Data So What? Safety of personnel Reliability Energized vs. De-energized Uninterrupted Operation Economy Overloaded lines lead to outages State estimator and Security analysis results incorrect. Violation of limits (Actual, LTE, STE or Load Dump) Operating the system at the least cost Bad SE / SA results could lead to unnecessary out-of-merit operation. 83 3/6/2014

85 Impacts of Bad Data So What? Localized MWH readings for large customers Single value in substation Company Wide Communication links down with control centers System Wide Economic dispatch not followed (ACE not on zero) Interconnection Wide Inaccurate net tie flows 84 3/6/2014

86 Examples 85 3/6/2014

87 Homer City 86 3/6/2014

88 Impacts of Bad Data Examples Homer City South 345/230 Auto Transformer CB MW/MVAR reading for South Auto Transformer was identified as being incorrect Problem started 13:30. While awaiting repair by field personnel, LCC manually replaced the points and updated them on a periodic basis During one update the low side CB was inadvertently manually replaced in the closed position Location of MW value in relation to CB was very close South Auto Transformer 230 kv CB tripped open on 22:36 No indication to LCC due to status and MW/MVAR points being manually replaced As a result, contingency analysis results for Homer City North Auto Transformer were inaccurate 87 3/6/2014

89 Impacts of Bad Data Examples Homer City South Auto transformer MW value was manually replaced and being updated periodically by LCC. 3/6/

90 In the process of manually updating the value on one occasion the low side CB was inadvertently manually replaced in the closed position. Impacts of Bad Data Examples 3/6/

91 14:10 14:30 14:50 15:10 Impacts of Bad Data Examples 15:30 15:50 16: HOMERCIT N.AUTO-S XFORMER L, 5/1/ Binding Violation STE Limit 95% Limit UDS Controlled Limit Solution (+20min) SE Flow 3/6/

92 Impacts of Bad Data Examples Homer City loading 00:00 to /6/

93 Nagel Ties 92 3/6/2014

94 Impacts of Bad Data Examples Nagel Tie Line Metering Problem Problems with NAGEL tie lines resulted in: Inaccurate PJM ACE calculation PJM over-generation High interconnection frequency 93 3/6/2014

95 Impacts of Bad Data Examples TVA PJM began experiencing problems on the: Nagel-Phipps Bend (TVA tie, 500Kv) inaccurate Nagel- Sullivan (TVA tie, 500Kv) Nagel Cane River (CPLW tie, 230Kv , 10/4 inaccurate Tie line values gradually drifted from actual values. No sudden step changes that would have alerted operators. CPLW 94 3/6/2014

96 Impacts of Bad Data Examples The inaccurate tie values resulted in PJM over generating between 10/3/ :00-10/4/ :00, contributing to high frequency for an 18 hour period 95 3/6/2014

97 Impacts of Bad Data Examples At approximately 8:20 am on Oct 3, 2006 both the CPLW CANE RIVER and TVA NAGEL-PHIPPS Bend tie-line meters began reporting what appear to be incorrect values. Nagel - Cane River 230 kv 10/4/2006 9:00:00 AM aa_ rt_ ln/line:23 0-nag-ca n1 :a _mw cp _rt_ln/lin e:230 -nag-can1:b_ mw :00 10:00 12:00 14:00 16:00 18:00 20:00 22:00 0:00 2:00 4:00 6:00 8: /6/2014

98 Impacts of Bad Data Examples The Nagel-Phipps Bend line appears to have returned to a correct value at 15:22 on Oct 3, The Cane River tie appears to have returned to a correct value at 8:20am on OCT 4th, Nagel - Sullivan 500 kv 10/4/ :00:00 AM 50 0 aa_rt_ln /line :5 00-nag -sul:a_mw tv_rt_ln/line:5 00-nag -sul:b_mw :00 10:00 12:00 14:00 16:00 18:00 20:00 22:00 0:00 2:00 4:00 6:00 8: /6/2014

99 Impacts of Bad Data Examples In addition to this error, the Nagel Sullivan tie also began reading a bad value during the same time period Nagel - Phipps Bend 500 kv 10/4/2006 9:00:00 AM a a_ rt_ ln/line:50 0-n ag- phi:a _mw tv_r t_ ln/line:50 0-n ag-p hi:b _mw :00 10:00 12:00 1 4:00 1 6:00 1 8:00 20:00 22:00 0:00 2:00 4:00 6:00 8: /6/2014

100 Impacts of Bad Data Examples While changing the RTU configuration at Nagel Station, technicians inadvertently disconnected three cables affecting tie-line metering Tie line measurements drifted slowly after cables were disconnected, this is a characteristic of the RTU when the MW input is left open ended The AEP and PJM EMS relies on significant spikes (100 MW) in readings to generate a rate of change alarm 99 3/6/2014

101 Impacts of Bad Data Examples AEP and PJM did not detect bad SE data for numerous hours PJM operators are responsible for reviewing bad data as part of shift turnover, operator did follow proper shift turnover procedures but did not detect the problem AEP support staff, not real time operators, review SE bad data during normal working hours The AEP Transmission Services Coordinator became aware of the problem when the meter error values increased significantly over a period of several hours AEP contacted maintenance personnel to look into the problem 100 3/6/2014

102 FE EMS Cutover 101 3/6/2014

103 Impacts of Bad Data Examples FE RTU Cutovers Planned cutover from Siemens EMS to AREVA EMS to occur over a 2 day period (1 st day was PJM holiday) Numerous ICCP uploads were performed to update the source of analog data being sent to PJM As cutovers progressed, the sign on several analog data items became mismatched between the PJM EMS and the PJM GMS /6/2014

104 Impacts of Bad Data Examples FE RTU Cutovers Thirteen data items going to the PJM GMS system needed an invert record to make them match the correct values going to the PJM EMS Some of the effects of the error were passed on to member companies through the EMS ICCP links Affected the network applications of PL and PE /6/2014

105 Impacts of Bad Data Examples FE RTU Cutovers Numerous cable/rtu moves were performed over 1 st and 2 nd day Once FE had confirmed the integrity of the data on AREVA EMS they would perform an ICCP db upload get the data to PJM PJM engineer would then verify the data and make note of any problems requiring corrective action 104 3/6/2014

106 Impacts of Bad Data Examples FE RTU Cutovers PJM personnel found mismatch on some data points in Penelec and informed FE of issues at end of 2 nd day 34 hours after start of cutovers PJM and FE engineers worked together to indentify 13 points that had incorrect sign being passed to PJM GMS Performed database upload to invert sign on values and correct issues 105 3/6/2014

107 Impacts of Bad Data Examples FE RTU Cutovers This was first of 3 planned EMS cutovers planned No formal procedures that outlined data verification process During future cutovers, points that needed invert applied were identified prior to start of data migration Additional checks to be made to ensure data quality is correct 106 3/6/2014

108 NEPA Interface 107 3/6/2014

109 Impacts of Bad Data Examples Northeast PA (NEPA) Transfer Limit A transfer limit to ensure transient stability in Northeastern Pennsylvania (NEPA). It consists of a set of transmission lines whose total MW flow is monitored and controlled to provide an accurate indication of the synchronous stability power export limit /6/2014

110 Impacts of Bad Data Examples Northeast PA (NEPA) Transfer Limit Transmission lines in the NEPA transfer interface are: Susquehanna-Wescosville 500 kv line Siegfried-Harwood 230 kv line Harwood-East Palmerton 230 kv line (Originally Susquehanna East Palmerton 230 kv Line) Siegfried-Frackville 230 kv line Juniata-Sunbury 500 kv line Lackawanna-Peckville 230 kv line Lackawanna-Oxbow 230 kv line Montour-Elimsport 230 kv line Montour-Clinton 230 kv line Sunbury-Elimsport 230 kv line 109 3/6/2014

111 Impacts of Bad Data Examples PJM RTO maintains the stability transfer limit and monitors and controls the transfer limit flows. When flows across the NEPA transfer interface are exceeding its limit, PJM RTO determines where and the amount of generation that must be reduced within this interface to reduce the flow /6/2014

112 Impacts of Bad Data Examples Normal operations: NEPA transfer export limit is adjusted based on out of service generation and transmission facilities With all facilities in service, the base stability limit is 3900 MW Subtractors associated with specific facility outages are then applied to determine the actual transfer export limit 111 3/6/2014

113 Impacts of Bad Data Examples Events on April 28, 2008: Circuit Breaker 2140 removed a facility from service and caused PJM to see a violation on the transfer limit PJM had a difference with PL of ~ 400 MW in flow on the interface PJM used more conservative values and issued Local Min Gen Event in area to return flows under the interface limit This included 200 MW reduction on nuclear units in the area Facility was returned to service and Local Min Gen Event cancelled at 0012 on 4/29/08 Operators on shift investigated and found cause for differences in values between PJM and PL PJM model did not include changes to 230 kv system causing the calculations to be incorrect 112 3/6/2014

114 Impacts of Bad Data Examples PJM Model 113 3/6/2014

115 Impacts of Bad Data Examples PPL Model 114 3/6/2014

116 Summary PJM requires accurate data for the reliable operation of the bulk electric system Errors in data can lead to unreliable and uneconomic operation of the electric system System operators are responsible for recognizing and correcting bad data 115 3/6/2014

117 QUESTIONS? 116 3/6/2014

118 Disclaimer: PJM has made all efforts possible to accurately document all information in this presentation. The information seen here does not supersede the PJM Operating Agreement or the PJM Tariff both of which can be found by accessing: For additional detailed information on any of the topics discussed, please refer to the appropriate PJM manual which can be found by accessing: /6/2014