One grid independent system operator’s (ISO) evaluation of the COVID-19 impact on electric load patterns, however, is that it is not too dramatic on that level so far.

The Electric Reliability Council of Texas, which oversees transmission for most of that state, is putting out a weekly update on load pattern changes during this immediate era of the sickness which has already killed more than 11,000 Americans since February.

The ERCOT data shows little impact to daily peaks, although the morning load from 6 a.m. to 10 a.m. dropped six to 10 percent lower than what the forecast model would predict typically. That margin from normality to the pandemic period is narrowing considerably when all time periods are factored in.

 “The overall load reduction for the ERCOT region has leveled off over the past two weeks,” said ERCOT Manager of Load Forecasting and Analysis Calvin Opheim in a statement. “Based on the data analyzed from the weeks of March 22 and 29, weekly energy use is down by approximately two percent.”

Any changes to the summer peak load forecast will be announced in mid-May when ERCOT releases its final summer Seasonal Assessment of Resource Adequacy and the Capacity, Demand and Reserves Report. A specific release date has not yet been set. 

On March 31, ERCOT put out its own pandemic planning actions document focused on protecting its staff and enacting best practices. ERCOT manages the flow of electricity to more than 26 million Texas customers, nearly 90 percent of the state’s load.

Other ISOs or regional transmission organizations in the U.S. include Southwest Power Pool, Midcontinent System Operator, PJM Interconnection, ISO-New England, California ISO and New York ISO.

Chris Moser, who oversees all plant operations for NRG Energy, will be a keynote speaker in the Wednesday, November 20 session, joining host utility Entergy’s Chief Operating Officer Paul Hinnenkamp on that day. Football and New Orleans legend Archie Manning will kick off the POWERGEN first day keynote on Tuesday, November 19.

POWERGEN International happens November 19-21 at the Ernest N. Morial Convention Center in New Orleans. The event attracts close to 15,000 attendees from around the world, including employees from more than 80 power generators and utilities already registered.

“This year’s POWERGEN will definitely up the input from the electric utility sector, so we are thrilled to have Chris Moser joining Paul Hinnenkamp at the Wednesday keynote,” said Rod Walton, content director for Power Engineering and POWERGEN International. “These are true operations experts who know the power generation mix inside and out and will bring that insight to the stage. We are excited to hear more.”

Moser, who has been with NRG Energy for 11 years, is executive vice president of operations. He oversees plant operations, commercial business, engineering and construction efforts.

Prior to that he was senior vice president of commercial operations, responsible for optimization of NRG’s wholesale generation fleet. Before NRG, Moser worked in various positions for Dynegy Inc., including as managing director of Midwest, where he led the monetization of Dynegy’s MISO and PJM transmission system portfolios.

He also has worked for Sawyer/Miller Group and the Safe Energy Communications Council. Moser has a master’s degree from the University of Pittsburgh and a bachelor’s degree from Hamilton College.

NRG Energy is based in Princeton, New Jersey, and in Houston. Its power mix is generated by natural gas, solar, battery storage, nuclear, oil and coal resources. The company serves close to 3 million retail customers in 11 states and the District of Columbia

POWERGEN International’s content tracks and knowledge hubs also have more than 30 utility speakers scheduled over the three days. One of those will be Moser’s colleague Skip Zahn, NRG’s vice president of asset management, speaking on the restarting of the Gregory gas-fired power plant earlier this year after a three-year shutdown.

Competitive market power generator Vistra Energy will close four coal-fired power plants in Illinois to meet state mandates on pollution standards.

The company will shutter the Coffeen, Duck Creek, Havana and Hennepin power plants. Together they generate more than 2,000 MW in capacity and support hundreds of jobs.

Texas-based Vistra says the reasons behind the closures include revisions in the state multi-pollutant standard rule. The additional standards aim for reductions in annual caps for sulfur dioxide (SO₂₎ and nitrogen dioxide (NOx).

The shutdowns could happen by the end of the year, pending approval by grid operators, Midcontinent Independent System Operator (MISO) and PJM Interconnection, and approval of the termination of certain tariffs by the Federal Energy Regulatory Commission. The plant retirements will drive down Vistra’s allowed emissions by 57 and 61 percent for SO₂and NOx, respectively, according to the company.

“Even though today’s retirement announcements were inevitable due to the changing regulatory environment and unfavorable economic conditions in the MISO market, they are nonetheless difficult to make,” said Curt Morgan, Vistra’s president and CEO. “By far, the hardest decisions we make in our business are those that significantly impact our people. As always, we will do right by those who are impacted by this announcement. Our employees take pride in the work they do, and we appreciate their decades of service providing reliable and affordable power to Illinois, particularly in years like this one with periods of extreme cold and heat.”[Native Advertisement]

As a result, the retirement of the four plants will further reduce annual allowable SO₂ and NOx emissions in the MPS group of plants, driving total allowable emissions down by 57 and 61 percent, respectively, from that allowed under the former MPS rule. While not explicitly required by the MPS, CO₂ emissions will also be significantly reduced by approximately 40 percent relative to 2018 levels.

Approximately 300 jobs will be eliminated across the four plant sites. Vistra is providing outplacement services and working with state workforce agencies to assist the employees impacted by the closures.

The 915-MW Coffeen coal-fired plant has operated for 54 years. Duck Creek, located in Canton, Ill.,  was completed in 1976 and has 425 MW in generating capacity,

The 434-MW Havana, Ill., plant is 41 years old. The 294-MW Hennepin site is, by far, the oldest among the Vistra properties with operations beginning in 1953.

Southern Power announced that the 345 MW, second combined cycle unit at the Mankato Energy Center is ready for commercial operation. The combination of two gas-fired units brings Mankato’s capacity to 760 MW.

“The completion of the Mankato Energy Center expansion represents an incredible accomplishment for our employees and partners involved with the project,” said Southern Power President Bill Grantham. “Together, the team applied their considerable skills and expertise to make the project a success while demonstrating a strong commitment to safety.”

Southern Power is selling the Mankato Energy Center to Xcel Energy for $650 million. The transaction is still waiting for regulatory approval and should be closed by the third quarter.

Xcel has been Mankato’s customer under long-term power purchase agreements.

Southern acquired the facility in October 2016. It was Georgia-based utility’s first generating assets within the Midcontinent Independent System Operator (MISO).

Capstone’s C600 Signature Series stand-alone microturbine will run all electric power equipment at a remote and unmanned compressor station while running on locally available high-pressure natural gas (HPNG). Wyoming is the nation’s largest coal producer, but increasingly is embracing gas-fired and renewable power production at work sites to lower emissions.

“Burning coal drove much of yesterday’s energy supply,” said Daren Jamison, CEO of Capstone. “However, we believe clean natural gas, biogas and renewable natural gas are the answers for our future. A natural gas-fueled power plant emits 60 percent less carbon dioxide than a coal-fired power plant.”

The order was secured by Horizon Power Systems, Capstone’s distributor for the western mountain states of the U.S. and western Canada. Wyoming currently ranks amongst the top five states with the most natural gas reserves.

“Compressor stations always face some natural gas leakage in compressor applications. Microturbines are an effective solution in helping operators such as this one become green by using available ‘slip-gas’ to produce power while reducing emissions,” said Jim Crouse, executive vice president of sales and marketing of Capstone. “Cost savings come from the fact that our microturbines can eliminate the need for utility power or the addition of costly diesel generation and reduce the environmental footprint of the site.”

The C600 series has a 600-kW rating with up to 90 percent in combined heat and power (CHP) efficiency rating. It footprint is slightly less than 10 feet wide, 20 feet deep and 10 feet high.

To date, Capstone has shipped more than 9,000 units to 73 countries and have saved customers an estimated $253 million in annual energy costs and 350,000 tons of carbon emissions, according to the company.

Starwood is acquiring the 325-MW combined cycle Garrison Energy Center in Delaware and the 503-MW RockGen Energy Center peaker facility in Wisconsin. No financial terms were disclosed.

Garrison was one of Calpine’s newer power projects and achieved commercial operation in 2015. It is a dual fuel facility within the PJM Interconnection.

RockGen is a simple-cycle dual fuel plant built in 2001 and dispatches into MISO Zone 2. It’s portfolio is full contracted for nearly five years.

“This unique transaction is the culmination of a significant amount of work with the Calpine team to craft a deal that would achieve multiple objectives. For Starwood, the portfolio represents a combination of scale and risk-mitigation, and is an excellent complement to our existing generation investments,” said Himanshu Saxena, CEO of Starwood Energy. 

Starwood Energy has executed more than $7 billion in transactions. Calpine is the nation’s largest producer of gas-fired generation for competitive markets, with more than 26,000 MW of capacity.

The transaction is subject to customary regulatory approvals and is expected to close in mid-2019. King & Spalding LLP served as legal counsel to Starwood.

Each of these systems will use natural gas to provide power and thermal energy for the manufacturing process. By capturing and utilizing heat that would otherwise be wasted from the production of electricity, on-site CHP systems require less fuel to produce the same amount of energy and reduce reliance on more expensive local grid power.

The C200 systems will be installed at an energy drink manufacturer where the thermal energy will be used to create steam for the manufacturing process, and the two C65s will be installed at a produce packager where the exhaust will be used to create chilled water used in the vegetable packaging process. Both applications will reduce cost, improve efficiency and lower emissions.

“DTC has made a significant investment of both time and money in order to be one of the CHP market leaders in Mexico,” said Darren Jamison, President and CEO at Capstone. “They recently dedicated a new headquarters in Guadalajara to support their growth throughout Mexico. The new facility includes a state-of-the-art remote monitoring facility that allows DTC’s technical staff to oversee that their customers’ Capstone microturbine systems are operating at peak performance.”

Capstone’s C65 generates up to 65kW of electric power while the CHP unit delivers up to another 150 kW. The C200 generates 200 kW capacity and includes what Capstone calls the world’s largest single-unit air bearing microturbine.

Mexico’s General Climate Change law set the goal to reduce greenhouse gas emissions on a national level 30 percent by 2020. This law also introduced the requirement that beginning in 2018, large and industrial electricity consumers must transition by 2024 to consuming 35 percent of their electricity from clean energy sources.

Minneapolis-based Xcel agreed to purchase the gas turbine combined cycle Mankato Energy Center, which Southern Co. acquired in 2016 and was its first asset in the Midcontinent Independent System Operator territory. Mankato has been providing power to Xcel customers under a power purchase contract.

The facility will have a generating capacity of 760 MW once an expansion is completed early next year. The completion of the sale, subject to regulatory approval and other closing conditions, is expected to be mid-2019. 

“Securing the Mankato gas plant is a great value for our customers as it will provide significant cost savings and operating flexibility for the long term,” said Chris Clark, president, Xcel Energy–Minnesota, South Dakota, North Dakota. “As we continue to transition to cleaner energy sources and reduce reliance on coal, this plant will help us continue to deliver reliable electricity while keeping bills low.”

Xcel Energy is planning for several power plant retirements and contract expirations in the mid-2020s, including Sherco coal-fired units in Minnesota. Acquiring this plant now provides certainty that energy from these newer generating units will be available and benefit customers over the life of the plant compared to simply purchasing the output.

Xcel Energy currently has nearly 100 employees in the Mankato area with several facilities, including a power plant and a service center. The company is also building a new transmission line in the area to deliver low-cost energy to customers throughout the region.

Southern bought the Mankato Energy Center from Calpine Corp. for $395.5 million. The Xcel subsidiary Northern States Power had a PPA running through 2026.

Calpine first proposed to build the Mankato facility in 2004. A 345-MW expansion was initiated last year, according to reports.

From 1996 to 2016, transmission investment jumped from less than $4 billion to more than $20 billion, creating a crunch on utilities striving to keep rates stable (U.S. Energy Information Association).

What’s behind the increase? After the 2003 Northeast Blackout that resulted in 50 million people being out of power for two days causing 11 deaths and costing $6 billion, the U.S. Congress put new reliability standards in place. It is part of the reason for higher transmission costs, which started spiking in 2006. Older asset replacement, improved monitoring, controls and switching technology and accommodating renewable energy is also part of the picture.

Government data shows the largest expenditures are related to power lines – overhead conductors, poles, fixtures, towers and substation equipment. Regional transmission organization fees have risen swiftly as well. The EIA forecast calls for flat generation prices — thanks to low natural gas costs – for the next decade with a slow growth in transmission investment. Most of the costs can be passed through to customers, but in a distributed energy world where customers have more generation choices, utilities are better served to keep costs down.

The power gen dilemma: Coal and nuclear are out, natural gas in. What about renewable energy?

Each Midwest utility’s situation is unique, but there are three or four typical scenarios and power generation mixes:

Type 1. No generation. Purchase from wholesale market via contract.

Type 2. Smaller market. Some generation.

Type 3. Larger market. Some or mostly self-generated, purchase from wholesale market for rest.

Type 4. Self-generation. Self-generates or owns shares from major generation facility and receives allotted power supply.  

Market conditions for both power generation and power delivery present opportunities and challenges for Midwest utilities. The first and most important question owners should ask is should they own, co-own or buy generation from the market?

Next comes an analysis of a realistic expectations from existing assets; the type of future you are planning for; what assets you will need and how you value reliability and resiliency. Only then can a utility decide a course of action.

Case study: City of Lebanon, Ohio

To understand how to approach the power gen dilemma, it is illustrative to look at the city of Lebanon, Ohio. We performed a detailed municipal utility study for Lebanon, a city of 25,000 located in the Cincinnati metropolitan area in southwest Ohio. Lebanon’s municipal utility illustrates both the opportunities and the challenges presented by today’s power markets. Lebanon asked us to study its alternatives and consider renewable energy generation.

Lebanon’s issues are applicable to many Midwest utilities: It has a long history of self-generation; owns and operates mostly older generation assets with minimal incentive to invest in new generation and renewables are starting to have an impact. Dispatch patterns on non-renewable generation are driving the need for more flexibility, and, finally, transmission costs are rising.

The renewable energy impact has just begun. For example, the Midcontinent Independent System Operator (MISO) projects that renewable energy additions in its system — less than 20 GW in 2017 — will rise every year and total 35 GW in 2021. Renewables significantly impact both transmission and generation operations.

Generation fleet

Lebanon’s peak load is 75 MW, maintained by power supply contracts with the grid and a fleet of dual-fuel combustion turbines and reciprocating engines ranging in ages from 50- to 78 years, used for emergency generation. During the past decade, the city followed the national trend of higher transmission and distribution investment and paid higher transmission fees to the grid as well.

Given the age of its fleet, Lebanon faces either replacing it or buying most of its power from the grid, a scenario that can lead to sudden and sharp cost increases that get passed to the customer base. Lebanon needed to understand what type of future it was planning for by analyzing contemporary trends and forecasts.

Forecasting has its risks

Forecasting is a tricky and often fruitless business. For example, a 1973 forecast for the year 2000 by a high-level government and industry committee predicted coal would be 20 percent of U.S. generation, oil 10 percent, natural gas 3 percent and nuclear 62 percent. The 2000 actual numbers were 52-, 3-, 16- and 20 percent respectively.

By 2030, transmission costs are projected to grow from 1.32 cents per kilowatt hour to 1.57; and up to 1.64 by 2050, according to EIA’s Energy Outlook. The agency’s economists predict distribution costs to rise from 2.98 cents per kilowatt hour in 2017 to 3.7 in 2030 and 3.73 by 2050. Generation costs are predicted to drop. Natural gas is expected to stay stable for 10 years and reserve margins for most regions are considered more than adequate, even with coal retirements, according to NERC’s 2017 Long-Term Reliability Assessment.

If transmission costs are going to rise, Lebanon will consider strategies to minimize those costs. The major component of future transmission charges from the power pool are for capacity and demand and importing less energy would reduce those charges. For example, Lebanon could have saved $580,000 in transmission charges by importing 10 percent less energy in 2017.

The city could reduce usage through demand reduction programs, but its customer mix would not allow a large enough total percentage reduction. It could run peaking generation at expected peaks, run base load generation to continuously reduce the amount of electricity that is imported, build a new transmission line to a different generation node, or install energy storage to use during peak hours to minimize imported power.

Generation options limited in the Midwest

The city of Lebanon made the following considerations for future generation: non-renewables renewable energy, regulatory issues, financing and cash flow and battery storage.

The study team eliminated nuclear, coal, fuel oil and diesel and combined heat and power because of cost and scale. Combustion engines, simple cycle combustion turbines were considered, both new, retrofit of current assets and the grey or aftermarket.

As for renewable energy, photovoltaic and wind are the only options, because there is no local resource for biomass, geothermal, hydroelectricity, concentrating photovoltaic and concentrating solar thermal energy.

Financial considerations and modeling

Stanley Consultants built financial models on several different alternatives, including four alternatives using either combustion gas turbines and reciprocating combustion engines, all producing close to the 20 MW of power that would reduce transmission costs. Four other scenarios involved a full 20 MW of solar power on purchased land, the same including battery storage, 1.5 MW on city-owned land and 2.3 MW on city land. The chart below shows the relative capital costs of each approach. The models considered such factors as inflation, projected natural gas prices and the low amount of solar irradiance and intermittent wind in the region.

Source: Stanley Consultants

The models showed that the payback period on the generation assets did not vary greatly. The shortest payback period was 8 years on grey market Warsila engines; the longest 14.2 years on the small solar on city property. Most of the rest of the options would pay back within a couple years of each other.

Engineers prepared “tornado charts” that illustrated how different generation decisions would be affected by a plus or minus 20 percent change in a variety of market variables. From the tornado charts, the high sensitive variables were put through a parametric analysis to investigate impact on payback from potential ranges. Bill escalation rate, capacity factor and natural gas prices can affect the economic feasibility of self-generation. In other words, a small bill escalation rate, a spike in natural gas prices or low capacity factor may not justify self-generation. However, if general trends continue, the parametric analysis shows benefit from running a 30- to 40 percent capacity factor on overall payback.

Source: Stanley Consultants

Financing. Lebanon has $10 million in its electric fund. If it chooses to spend that, it would have to finance 60 percent of the remaining $20-plus million cost if the city chose to build a 20 MW facility as part of the 3-year plan. There are many benefits to financing for project funding. The project can be completed sooner and provides revenue and self-generation benefits sooner. Also, due to the current generation market, there is a buyer’s market for gensets and financing can allow city to take advantage of low prices and good lead times for RICE (reciprocating internal combustion engine) gensets.

Stanley Consultants also developed a 10-year plan for building a 10 MW facility with provisions for adding another 10 MW in year 10. The funding gap is in consideration of the city’s cash flow.

Permitting. Operating existing generation assets more than just in emergency and backup situations would have regulatory and permitting impacts, with respect to both the Ohio EPA and federal EPA. Similarly, adding new generation in the form of new combustion turbines or reciprocating engines would also have regulatory and permitting impacts. With respect to new generation options, new greenfield sites were considered and not expanding generation at the current site. The simple cycle combustion turbine option offers the most operational flexibility to avoid a major source operating permit. A new combustion turbine would require on-going annual performance testing to demonstrate continuous compliance with the NOx standard.

Energy storage. Don’t expect 50 percent drops in battery costs going forward. The way the market’s going, the City of Lebanon would need four hours of storage with a 7.5 MW load. If the peaking system is 10 MW or less, storage might have an application. For larger utilities, cost makes storage difficult.

Conclusion

The three basic options to consider as part of the upcoming capital planning schedule are:

Option 1 — Decommission existing generation, monitor wholesale market conditions and add new generation when generation becomes more cost-effective, with payback in 5- to 7 years. Continue to purchase power off the market as contract prices have declined. This option is a short-term approach that avoids issuance of debt and the risks associated with capital investment. In the event new generation is decided upon, it will be difficult to cost-effectively time the investment.

Option 2 — Decommission existing generation, move forward with 10 MW of new generation ($15.7 million) and plan to begin installing an additional 10 MW of new generation in year 8 ($8.5 million).  While this option lowers the maximum capital investment in any one year, it will add more capital cost by breaking the investment into two phases versus one.

Option 3 — Decommission existing generation, move forward with 20 MW new generation ($23.4 million) using financing for a portion of the investment. This takes advantage of low new generation demand and better prices for equipment and services.

The City of Lebanon chose to perform an electric rate analysis in early 2019 and use that information to choose either option 2 or 3.

Like other Midwest utilities, considering their delivery node within the Midwest grid, renewables are not a slam dunk decision. Reliable, cheap coal generation abounds in the region, despite many coal plant retirements, and therefore remains an attractive choice.

Likewise, after being in business for 100 years, conservative Midwest utilities don’t want to be at total risk to inevitable market fluctuations. They want to retain some control of their rate structure and to fulfill commitments to their customers. The Lebanon City Council understood and approved the plan to retain some control over power generation. That scenario is likely to repeat itself in other Midwest cities during the next decade.

About the authors: Joe Jancauskas, P.E., is an electrical power consultant with Stanley Consultants in the firm’s Denver office. He has more than 30 years of experience in the design, analysis, construction, modification, operation, maintenance and asset management of power systems. He also served as a national spokesperson for the industry as an expert for the U.S. Council for Energy Awareness.

Matt Irvin, P.E., is a mechanical engineer with Stanley Consultants in the Denver office. His experience includes design engineering, feasibility studies, plant decommissioning planning and engineering, plant condition assessments, controls design, owner’s engineer services, expert witness testimony and performance testing and tuning.

This arrangement served the Raleigh business district well for over 30 years, resulting in a low frequency of events and power loss. Over time, as the number of customers grew, both load per customer and customer density increased as well. As greater portions of the modern economy have become reliant on dependable electric service, customer expectations for high reliability of that service have also grown.

Due to these factors, as well as a need to replace aging equipment in these areas, Duke Energy launched a proof of concept effort to better understand the roles automation and telecom technologies should play. The company’s objective is to develop greater expertise in these technologies through exploring opportunities to integrate high-speed automation switching solutions into its modernized distribution grid designs to improve electric service reliability for its customers.

Introduction to Proof of Concept

As part of a proof of concept for future distribution schemes, Duke Energy has completed the second phase of a project on a distribution system feeder for the Raleigh Central Business District underground system. The feeder consists of two radially operated 12kV underground circuits. Solid dielectric vacuum switches with integrated visible break were installed in nine network vaults during phase 1 of the project. To achieve high electric service availability for the central business district, a communications-assisted, high-speed protection system was developed. Its unique communication architecture utilizes IEC 61850 GOOSE messaging (the messaging protocol previously used by NASA’s Rover communications system for high interference communications) and serial based communications in parallel, enabling the relays to interrupt, isolate and restore power via the nine vault switches.

An important aspect of the acceptance test was testing the protection and control scheme. In this scheme, 18 relays and two communication technologies, work together as a system. Due to the interdependency of the network protection system and its components, it was critical to test every component as part of a system rather than limiting testing to a component level. Multiple acceptance criteria were defined by determining the initial state of the power system, the incident fault anticipated and the expected system state after protection system operation (i.e., after interruption, isolation and restoration of the system had occurred). The acceptance criteria were directly configured into the test environment by using a power system model that calculated the test set outputs. A single PC controlled a total of nine test sets (representing each of the nine network vaults), simultaneously injecting all signals according to the selected test case.

One requirement for placing the protection system into live operation after installation was the successful completion of field site acceptance testing (SAT). Site acceptance testing included testing the individual switching nodes during commissioning followed by a series of simultaneous network system response testing involving all of the switches.

The requirements for the proof of concept included the following:

1. System must be able to respond on its own to isolate an event.

2. System must have the ability to be flexible in its design to allow for the meeting of multiple

use cases for operation and circuit configuration.

3. System must have the ability to overcome the failure of primary systems, including

communications, switchgear, or automation relays.

4. System must be able to isolate a fault and restore the maximum number of customers within

a predetermined timeframe

5. Operation of the system must allow for either remote or local operation by an operator from

outside of the enclosed space environment to promote the safety of the employees.

6. System must allow for reconfiguration to its normal state with a single remote command.

7. System must allow for remote designation of new normal state.

8. System must be self-contained, not reliant on a single automation controller or other single

point of failure component.

9. Hardware design must allow for watertight conditions and the ability to isolate the control

from the switch components[EK1] .

Testing Methodology

To ensure an operable test setup, the test team utilized novel software which offered two features: the ability to run a power system simulation and the ability to control multiple test sets from a single software instance. Because the power system simulation introduced the ability to calculate currents and voltages, it simplified test case set up by calculating all currents and voltages for each relay in the power system automatically. Also, because the software enabled the team to control multiple test sets from one instance, the test case could run via a single button click. As part of the simulations, the software calculated the transient signals, distributed them to each test set and set the start time. After execution, all binary traces measured at the relay were transferred back to the software to be instantly assessed. One essential requirement of the simulation was a test of the circuit breaker response, which ran independently on the test set.  

The first execution injected a transient signal containing the fault incident. As expected, two of the breakers tripped selectively with a short delay. However, because the transient signals were already sent to all nine test sets, the test setup could not respond in real time. If the relays trip at the same time again when injecting the same fault quantities, the software automatically starts another iteration that will include the subsequent breaker events.

The same iterative process occurred again during the restoration.  The test sets measured a close command for the normally open breaker. The software recalculated the transients now containing the fault event, the isolation events and the restoration event. With the final execution, results similar to a real-time simulator were achieved.

The simplicity of test case definitions required for this iterative closed-loop simulation increased the likelihood of finding any errors in the protection system logic. In the case of a logic error, the misoperation is directly visible in a single line diagram, eliminating the need to investigate trip and close commands of ten different relays in a binary trace diagram.

The full loop system under test consisted of nine individual underground vaults located around downtown Raleigh. Each vault contained two relays. The primary relay measured two three-phase currents. The two three-phase voltages were measured via voltage sensors outputting low level signals. These conditions required each test set to have at least six phase currents and six low level voltage outputs.

Typically, when performing comprehensive field testing, a second test set would have been required to support the injection of test signals into the tap relay. For typical field testing of all nine vaults of the Raleigh underground system, 18 test sets would have been required. However, since the Duke Energy test team were primarily evaluating system behavior under full communication load (which mainly involved the primary relays), the testers determined that, as with the FAT (Factory Acceptance Testing), setting up an additional test set for each tap relay would be gratuitous. Instead, the test team opted for testing each tap way in the loop scheme, separate from the other tap ways, which still allowed for fully testing the system. This reduced the total setup actions required, thus reducing the risk of introducing error into the test sets.

Each underground vault test setup included one test set connected to a GPS antenna synchronized to IEEE 1588 precision time protocol (PTP). An Ethernet connection was used to communicate between these test sets via Duke Energy’s existing fiber network[EK2] .

Each test set needed to be connected to a relay inside the vault. In order to achieve this, a custom test cable was utilized to connect all required signals from the test set (switch status, CT secondaries, etc.) to the relay cabinet, effectively simulating the switchgear. The test cable used the same submersible connector and pin configuration as the cable that connected the interface cabinet to the relay cabinet.

All test cases were run on a single PC from a centralized location, above an underground vault in downtown Raleigh. The team performed two different groups of tests:

·  The first was a series of half-loop tests performed using five different test sets at four of the underground vaults. Each vault location had an assigned GPS clock for synchronization, with one location containing two test sets and sharing a single GPS clock. The two test sets were located at the vault where the tap way test would take place. This allowed for tests to be performed on eight of the primary ways and two of the tap ways, avoiding the need to remove the equipment from service.

·  The second group of tests (full loop tests) included all nine vaults in the system, utilized nine test sets and focused on testing all 9 primary ways together as a system.

Lessons Learned from Site Testing

Lessons learned to make setup smoother

The complexity of the system required the design team to coordinate up to nine test sets

simultaneously. This setup demanded significant resources (both equipment and personnel) to be on site for the testing in the individual vaults. Each test set required multiple connections for injecting the analog signals, binary signals and inputs from the relays, as well as connections for the GPS clocks. A simple connection error may have easily resulted in the test providing incorrect results, requiring

physical entry back into a vault to correct a connection. The team paid extra attention to ensure that all test connections were verified prior to the start of testing to avoid such adjustments during the site test[EK3] .

Lessons Learned from changes in FAT topology to SAT topology

Due to differences between the initial system design and the final system build, changes were required to the IEC 61850 GOOSE virtual bit mapping and serial bit mapping. Updates to relay logic were also made to reflect these changes. Due to discrepancies discovered during site acceptance testing, on-the-fly settings adjustments were required which introduced additional levels of uncertainty to the initial test results.

When designing the topology to be tested during the FAT, the team would have been wise to avoid assumptions about switchgear orientation relative to the source breakers. Had the team intentionally reoriented one or two devices in the FAT topology, a better understanding of the effects device orientation has on the logic would have been revealed. Necessary logic changes could have been

identified and implemented at the factory rather than during the SAT.

Locational Challenges

Due to the heavy foot traffic around each of the underground vault locations, the design team located the associated testing equipment within each of the nine vaults, to avoid having the equipment located on the ground level and assigning dedicated personnel to monitor each exposed access point. However, with the GPS clocks located in an underground vault rather than located in direct line of sight to open sky, the clocks experienced some losses of communication during the test set up. To remedy this, the team placed GPS clocks as close to the ground level as possible to allow for uninterrupted communication[EK4] .

About the authors: Peter Hoffman is Manager, Grid Monitoring, Control and Intelligence within Grid Architecture of Grid Solutions Engineering and Technology, an organization within Duke Energy’s Grid Solutions department. Grid Monitoring, Control, and Intelligence is focused on the technical aspects of effectively unlocking the value of future grid investments for customers and operations that are part of Duke Energy’s Grid Investment Plan, focusing on the development, evaluation, and enablement of both near term and strategic paradigm shifting solutions and capabilities within the operational technology space of the Distribution circuit, segment, and device levels. Peter has worked in several roles for Duke Energy, including Technology Evaluation Manager, Strategic Grid Business Investment Planning, Distribution Standards, Corporate Protection Engineer for Distribution, and various field engineering positions. He also has worked in Transmission Protection with the Tennessee Valley Authority. Peter is a registered professional engineer in SC and NC and is a graduate of NC State University with a bachelor’s degree in Electrical Engineering and an MBA with a focus on Innovation and Services Management. Peter and his family reside near Charlotte.

Erich Keller is Manager of Automation Engineering in Distribution Automation at G&W Electric Co. in Bolingbrook, IL. He is responsible for managing power system automation specification, design, factory acceptance testing and site commissioning. Before joining G&W in 2011, Erich was employed at ZIV USA in Des Plaines, IL. Erich Keller received a B.S. degree in Electrical Engineering from Valparaiso University and M.S. degree in Electrical Engineering from the Illinois Institute of Technology

Christopher Pritchard was born in Dortmund, Germany. He started his career in power as an electrical energy technician. Christopher received a diploma in Electrical Engineering at the University of Applied Science in Dortmund in 2006. He joined OMICRON electronics in 2006 where he worked in application software development in the field of testing solutions for protection and measurement systems and is now the responsible Product Manager for system-based testing solutions.

John Hart is a Senior Engineer in Grid Solutions at Duke Energy, focusing on protection and automation strategy development. He is a registered Professional Engineer and has worked in the energy industry for over 6 years. He received his Bachelor of Science in Electrical Engineering from University of North Carolina at Charlotte and is pursuing a Master of Science in Electrical Engineering from North Carolina State University.