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Newton-Evans Surveys Underway

by Chuck on November 2, 2016

Outlook Study for HV and MV Equipment Purchasing Plans
Newton-Evans Research is conducting a study of U.S. electric utility plans for T&D equipment purchases over the coming 36 months. If you work in power transmission or distribution and specify or procure equipment, you can help the utility community by participating in the study. In turn, we will share back the findings and provide an honorarium as well. Aggregated equipment demand levels will have an influence on prices and options for capital equipment used in power transmission and distribution. The survey results will be reported only in aggregate form. Here is a link to the SM version of the survey:

https://www.surveymonkey.com/r/ElectricEquipmentPurchasePlansSurvey.

Thank You for your consideration of this request.

 

EMS/SCADA/DMS/OMS Usage Patterns and Plans – 2017-2019
Newton-Evans Research is underway with its 14th study of EMS/SCADA/DMS and OMS activities. If you are involved with utility systems operations technology and would like to participate along with more than 100 other leading utilities, please complete the online survey found here: https://www.surveymonkey.com/r/2016EMS-SCADA-DMS-OMS-Survey. In turn, we will share back the study’s findings with you, which will enable your utility to conduct internal benchmarking vis-a-vis the broader control systems user community – by type and size of utility. An honorarium will also be provided. Thank you for your consideration of this request.

Guest Article by Vince Martinelli

The reliable operation of the North American power grid is testament to the quality of design, planning and execution over multiple generations of utility engineers. As part of this progression, previous grid modernization efforts added high-performance sensing and communications technologies, first to generation and transmission, and eventually to the distribution system. These technologies helped utilities squeeze more capacity and resiliency out of existing assets cost-effectively, reacting to changes driven by load growth and diversification, as well as industry restructuring.

These trends led to broadly deployed “automation” in the medium-voltage (MV) portion of the distribution system. Medium-voltage substations, where high-voltage power is stepped down to MV on its path toward end customers, have seen the greatest degree of automation. Combined with automation at some of the MV devices downstream from the substation, such as reclosers, capacitor banks and line regulators, this provides the ability to measure and control the system with higher fidelity as compared to managing from the transmission layer. Utilities have evaluated technologies, tested specific solutions in trials, validated use cases and financial models, and made prudent investment choices in rolling out MV automation.

History Repeating Itself
A similar “automation” transition is now happening at the low-voltage (LV) level. Driven by higher reliability expectations, growth of rooftop solar PV generation, energy efficiency programs, the emergence of electric vehicles in the transportation mix, and the promise of battery storage for a range of grid-connected applications, new pressure is being placed towards the edge of the grid. It is more acute in some service areas than others, and can be clustered within one utility’s territory – or even within specific feeder circuits. Driven by these trends, the next frontier in grid modernization is at the interface between the MV distribution layer and the LV distribution layer, centered on the humble distribution transformer, as represented in Figure 1.

Fig1
Figure 1. LV Substations provide critical new capabilities for grid modernization.

Similar to the MV automation rollout, LV substation modernization will happen first at acute “pain points,” becoming more widespread as the technology matures and the detailed use cases are developed.

Active LV Substations Solve Multiple Problems
Among the variety of potential applications, local voltage regulation is a clear “pain point” that cannot be addressed at the MV layer alone. Whether for increasing PV hosting capacity at the neighborhood level by countering voltage rise during reverse power flow, or for supporting energy efficiency programs where the goal is to deliver voltage to customers at the lower end of the acceptable ANSI A range, the benefits of adding automation to the distribution transformer – what we refer to as an LV substation – are becoming clear.

Figure 2 shows two examples of LV Substations deployed by U.S. electric utilities. In each case, a standard distribution transformer is paired with a grid automation device providing control with power electronics-based multi-function regulating capabilities, visibility with onboard current and voltage sensors, and automation with processing and memory components and communications capabilities. These regulating functions include voltage regulation in forward and reverse power flow, power factor correction, and harmonics mitigation. The system also reduces voltage sags, swells, and flicker for the customer connected downstream.

These compact, maintenance-free systems take advantage of existing “real estate” on poles and pads, simplifying the easement process and providing an alternative to costly upgrades on the MV system. The flexible communications platform can integrate with SCADA on the MV system and interact with downstream LV devices, such as AMI (“smart meters”) or behind-the-meter resources, such as next-generation smart inverters, EV chargers or energy storage resources.

Fig2
Figure 2. LV Substation implementations for (a) an overhead system and (b) underground plant, featuring coupled integration with a distribution transformer for siting on a standard pad in a residential area. Adding a power electronics-based regulator with integrated sensing, computing, communications and control software brings grid modernization to legacy distribution transformers.

Figure 3 shows voltage data at a particular customer meter over several months without grid automation; then with the voltage regulation from the LV Substation in place. Voltage variability before upgrading the system reflects MV voltage variations, with dips well below ANSI limits, as delivered to the distribution transformer. When the power electronics regulator is activated with an initial setpoint at 240 V, the only variability at the customer is the load-dependent voltage drop on the LV line itself. This particular customer, and neighboring customers behind this LV substation, now receive compliant voltage and superior power quality, independent of the bulk MV system.

Fig3
Figure 3. Customer voltage delivery improvement measured by utility AMI voltage data showing the control provided by power electronics voltage regulation after introducing the automated LV Substation.

Looking Toward the Near Future
The daily news cycle reminds us that the forces putting pressure on the distribution grid are accelerating, driven largely by changes in how customers choose to participate in their energy future. Whether it’s Hawaii mandating a 100% renewables goal; solar power’s levelized cost of energy continuing to plummet; New York’s REV plan; the ongoing retirement of coal-fired power plants; or nationwide deployment of EV charging stations, the trends are clear.

Fortunately, the concept of automated LV Substations – elevating the status of the long-serving distribution transformer – provides a capital-efficient blueprint for a path forward, modeled after the successful rollout of automation in the MV distribution layer. The difference today is that localized pressure points call for localized solutions appropriate for the demands of the LV layer. The evolution of power electronics-based system designs has resulted in compact, reliable and cost-effective options to consider.


Vince Martinelli is responsible for managing the company’s product roadmap and articulating the business case for agile grid infrastructure. Vince brings over 25 years of product experience and an in-depth understanding of how to effectively drive new technology into legacy systems, transforming them in the process. He joined Gridco Systems in 2013 from Amazon Robotics (formerly Kiva Systems), where he led a team responsible for the integration of Kiva’s robotic order fulfillment system into Amazon’s global network. Prior to Amazon, Martinelli led the North American arm of Professional Services at Sycamore Networks. He has also held senior management positions at Corning Inc., including product management roles in the Optical Fiber business. Vince earned both the SB and SM degrees in Materials Science & Engineering, with a concentration in Economics, from MIT, where he was a Tau Beta Pi Fellow and an Academic All-American athlete.

For further information on multi-function power electronics-based regulation systems that turn distribution transformers into automated LV Substations, please visit www.gridcosystems.com

Volume One of this 2016 study of protection and control is based on a sample of North American investor-owned, public and cooperative electric power utilities.
The data provides information on a segmented basis by type of utility and by number of customers served. These tables help illustrate occasional important differences in the findings based on the type and size of utility.

The findings in this report are based on survey responses received from 79 electric utilities that include 16 investor-owned, 28 public power, 26 cooperatives, 4 electric power consulting groups, and 5 Canadian electric utilities. This survey was conducted between April and May of 2016. Initial phone calls were placed to utility officials and relay engineers to invite them to complete the survey either as a Microsoft Word attachment via email, or completing an online survey on www.surveymonkey.com. Reminders were sent via email every 2 weeks until the last call deadline was issued.

The 79 utilities participating in this year’s study represent 31 million electricity end users/customers, having 3,340 transmission substations and 7.841 distribution substations covering over 800,000 total T&D line miles. This sample is about 20% of the North American customer base and approximately 15.7% of utility-operated transmission and distribution substations. Newton-Evans has previously estimated that direct shipments to utilities account for about 40% of the overall North American market for protective relays.

Each question in this report contains:

  1. A pie chart or bar chart summarizing how all of the survey participants responded to the question
  2. A table (or series of tables) showing the data by:
    1. Summary: all survey respondents
    2. Investor Owned: investor owned utilities
    3. Public Power: publically owned utilities (municipals, public utility districts, state or federal government)
    4. Cooperative: member owned electric utility cooperatives
    5. Canada: electric companies in Canada
    6. Other/Consultant: respondents representing power technology companies, industrial facilities
    7. <100,000: electric utilities serving fewer than 100,000 customers
    8. 100,000 to 499,999: between 100,000 and 499,999 customers
    9. >=500,000: 500,000 or more customers (either directly via distribution, or indirectly via generation and transmission.)
  3. Some written analysis and observations based on the tables and charts

What approaches are you using to operate a WAN for remote access to relays?
While 24% of the respondents said they don’t operate a WAN for remote relay access, almost half said they connect via serial port terminal servers or data concentrators. Forty percent use firewalls in conjunction with the WAN, while just over one-third said they use routers with encryption or VPN capabilities to access relays over a WAN. Other mentions included “gateways”.

WAN Usage for Remote Access to Relays
relayWANs

Does your utility’s control system use protocol IEC 61850 for Substation Automation, Protection, Control, or SCADA?
Seventeen respondents said they use IEC 61850 in at least one of the four areas. Thirteen percent said they use 61850 within the substation, and another 6% said they plan to use it in the substation by 2018. About 80% of the respondents have no use or plans for IEC 61850 in any area, and 89% said they don’t use or plan to use IEC 61850 for SCADA.

Use/Plans for IEC 61850
IEC61850

What % of your relays have been in service for more than 15 years?
Overall, 55% of survey respondents reported that more than one-half of their protective relays have been in service for more than 15 years. Out of all 76 respondents to this question, twelve said that less than 20% of their installed base is older than 15 years. However, in some cases the useful lifespan of a protective relay is stated as nearly 30 years. There are installations of electro-mechanical relays that have been in operation since the 1960’s according to some utility officials. According to the observations reported in Table 23, two-thirds of relays installed at surveyed IOUs (and nearly two-thirds among Canadian respondents) have been installed for more than 15 years.

Percent of Relays Among Newton-Evans Sample that are >15 years in service
RelaysOver15yrs


To order Volume 1 of The Worldwide Study of the Protective Relay Marketplace in Electric Utilities: 2016-2018 visit our reports page or fax an order form to 1 410 750 7429: www.newton-evans.com/relaymarketplacestudy2016-2018

The Worldwide Study of the Protective Relay Marketplace in Electric Utilities: 2016-2018, a four volume report series by Newton-Evans Research Company, is scheduled for publication in August 2016. Volume 1 – North American Market is now available.

Overview
Newton-Evans’ Worldwide Study of the Protective Relay Marketplace: 2016-2018 is planned to be a multi-client study which encompasses the world market for protective relays in the electric utility industry. This four volume report series will be the seventh worldwide study of protective relays which Newton-Evans has undertaken. Participants in this market study will include utility engineers and managers from investor-owned utilities, municipal and provincial utilities, cooperative utilities within the United States and Canada, together with national power systems throughout the world. The study will measure current market sizes and contains projections on a world region basis for the next several years. The entire research program will define the product and market requirements which suppliers must meet in order to successfully participate in one or more of these diverse world market regions.

Newton-Evans Research Company estimates from our earlier 2012 relay market study indicate that the North American protective relay market stood at almost $600 million for both utility and industrial applications. It will be important for the P&C community to learn how changes in the world market conditions since 2014 will affect the outlook for 2016-2018.

To read more about this upcoming study and get ordering information, see the brochure page.

Role of Synchrophasors and Teleprotection Continues to Grow, Providing Better Situational Awareness and Visualization to Help Prevent Outages

Newton-Evans Research Company has prepared an interim news release based on preliminary findings from 59 large and mid-size North American electric utilities.

Among the early trends reported in this first of a four volume set of reports are these:

  1. The percentage of microprocessor relays in the mix of all protective relays used by utilities continues to increase with each passing year.
  2. The vast majority of new and retrofit units being planned for purchased are also digital relays, but in some of the protection applications studied, such as motor protection and large generator applications, and in installations where electrical interference is strong, electromechanical and older solid state relays continue to have a niche market position.
  3. Real-time analysis of synchrophasor data has become a key application for the emerging field of operational analytics for transmission operators.

MicroprocessorRelaysInstalledBasePct
Communications protocol usage patterns in North American utilities of all sizes continue to rely on DNP3, the dominant protocol in use in the North American region. IEC 61850 is found in some of the TOP 100 utilities, but is by no means prevalent as of mid-2016.

Relay redundancy being used for microprocessor-based relaying terminals varies by application as seen in the chart below.

RedundantRelaySchemes2016
The 2016 Newton-Evans survey of electric utilities includes more than 20 detailed product functionality topics, related technical questions, and market-related issues, together incorporating more than 250 items of information from each of the participating utilities.

This year’s study will result in a series of four reports published during June and July. These reports are geared to the planning needs of protective relay suppliers, power industry consultants, and utility protection and control departments. The four volumes include the North American Market Study, the International Market Study, Supplier Profiles, and Global Market Assessment and Outlook.

Further information on the research series The World Market for Protective Relays in Electric Utilities: 2016-2018 is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone: 410-465-7316 or visit www.newton-evans.com for additional information or to order the report series online.

Newton-Evans Research Company is currently conducting a study of the market for laboratory testing of medium and high voltage electric power T&D equipment. The purpose of this study is to find out how electricity producers, T&D companies, industrial facilities and transit and rail companies handle testing of equipment such as: power transformers, load tap changers, switchgear, load interruptors, outdoor circuit breakers, fused cutouts, relays, capacitors, load break switches, reclosers and instrument transformers.

Some of the tests for these pieces of equipment that are routinely performed in a laboratory situation include: arc flash, internal arcing fault, load and capacitive switching, short circuit interruption and withstand, overload, interrupting current tests, switching tests and cable/line charging. These laboratory-based tests are sometimes performed in-house by electric utility staff, but more often an outside consultant, equipment manufacturer, university or commercial test lab is hired to perform these tests.

In an effort to better serve electric power utilities, generating companies and industrial facilities, test labs want to know: “If you had the opportunity to troubleshoot a technical problem “off the grid” using an independent lab, what are some of the problems or issues you would test in that situation?”

If you or someone you know is involved in equipment testing or maintenance planning and would like to take our survey and receive a report of findings from this study, and a stipend, send inquiries to info@newton-evans.com or call 800-222-2856. A link to our survey, hosted by Surveymonkey.com, is available here:
https://www.surveymonkey.com/r/ElecPwrEquipTestingSurvey2016

Progress Report on the 2016-2018 Study of Protective Relays

March 23, 2016

This week the staff at Newton-Evans Research is in the midst of conducting pre-testing of our 2016 survey design with our panel of leading utility contributors. After reviewing the results and feedback from our panel, we will finalize the North American version of the survey and begin requesting participation from utilities, ISO/RTO organizations, industrial firms […]

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Electric Utility Spending on Relay Testing, Use of WANs for Remote Access

March 9, 2016

Here are some excerpts from previous Protection and Control studies; some of these topics will be revisited in our 2016 survey. Overall, do you plan to increase, decrease or maintain current levels of capital investment for relay testing equipment, software and training? The overwhelming majority of the 2012 sample indicated that they plan to maintain […]

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Role of Electric Power Utility Operational Technology Consulting Firms

February 24, 2016

There are a large number of consulting services providers to Operations and Engineering staffs in the electric power industry. In North America, Tier One providers include the Structure Group business unit within Accenture, KEMA DNV GL, QUANTA-Technology, PE (Power Engineers), PSC, SISCO, UISOL and others. Several of these firms have their origins as T&D engineering […]

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Asset Management of T&D Equipment and Integration of Renewables Needs Advanced Field Testing Methodology

February 12, 2016

Guest Article contributed by Paul Leufkens We read with much interest “T&D Testing Topics” about the role and importance of lab and field testing to the electrical power industry. When Chuck published this recently as part of reviewing 2015 activities he described many different test activities by various organizations with very diverse purposes. From there […]

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