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The Business Case for Decentralized Power Regulation at the Low-Voltage Secondary

The Business Case for Decentralized Power Regulation at the Low-Voltage Secondary

This article, the last of a three-part series, focuses on the business justification for Agile Grid Infrastructure: multi-function power electronics systems that are deployed along the low-voltage secondary.

In our previous articles, “The Need for Distributed, Dynamic, and Decoupled Power Flow Control in Distribution” and “Agile Grid Infrastructure, a New Class of Hardware Systems for Electric Power Distribution,” we discussed the challenges facing distribution utilities and a new class of active grid infrastructure, based on multi-function power electronics, advanced controls and distributed networking, needed to address those challenges. Agile Grid Infrastructure, which enables the control of power quality and power flow in a distributed, dynamic and decoupled fashion, has the potential to truly transform today’s distribution grid into an active, two-way power exchange system.

The modern distribution grid still delivers safe, reliable and affordable energy, but is falling short in accommodating both increasing levels of variable generation from Distributed Energy Resources (DER) and changing customer load profiles.  Satisfying energy efficiency policies, via Conservation Voltage Reduction (CVR); actively controlling voltage to reduce peak capacity needs; and addressing the increasing demand for higher power quality and system reliability is also a growing concern.  Ultimately, these evolving priorities provide a new lens through which to consider the growing disparity between utility revenue and underlying costs.  As leading distribution utilities around the world begin to gain comfort with Agile Grid Infrastructure and deploy it on a systemic scale, the discussion of benefits, costs and payback has come into focus.  Although many utilities prefer to stick to conventional Business-as-Usual (BAU) approaches, the business case for Agile Grid Infrastructure can be so compelling that one might ask: “Why wouldn’t you leverage power electronics throughout your grid today?”

The New “BAU”

When evaluating the cost effectiveness of Agile Grid Infrastructure, it is essential to understand what functionality is being provided along with the resulting value streams.  Not all power electronics systems for the distribution grid are created equal.  In this article we examine the case for In-Line Power Regulators (IPRs), purposefully designed to extract maximum value from utility-grade power electronics and make life simpler for distribution planning, engineering and operations personnel. 

The IPR is a multi-function power electronics hardware system deployed along the secondary, based on a combination of series- and shunt-connected power converters and providing a number of power monitoring and management functions including voltage regulation, reactive power compensation, harmonic cancellation and voltage and current sensing.  This utility-grade device represents a new class of agile grid infrastructure that is designed specifically to help distribution utilities cost-effectively address today’s challenges while providing recurring benefits for 25 years or more.  What makes this approach even more compelling is that with selective application of the new IPR systems, utilities can extend the life of all legacy assets currently deployed.  This is part of the new “BAU” – Business Advantage for Utilities.

As discussed in the previous articles, one of the most important functions provided by the IPR is voltage regulation.  How will utilities assure customer voltage compliance in light of 21st century power distribution requirements?  By decoupling primary and secondary voltage and providing a wide range (±10%) of continuous, precise and dynamic voltage boost and voltage buck, the IPR effectively addresses a number of existing and emerging requirements including ANSI compliance, asset life extension, DG integration, energy efficiency or CVR, utility-side peak demand reduction or Demand Response (DR), and power quality sag/swell mitigation.  Many of these applications require more than 0.5% to 1.5% voltage adjustment along with the ability to actively provide voltage boost or buck to deal with a variety of loading and generation scenarios.  The old business-as-usual solutions, such as reconductoring or asset replacement, are proving to be inadequate in responding to these demands.

The IPR also regulates power factor by injecting leading or lagging reactive power (4-quadrant operation), unlike switched or fixed capacitors that only provide leading VARs, and improves power quality by actively cancelling current harmonics towards the grid and voltage harmonics towards customer loads.  Finally, the IPR provides built-in voltage and current sensors, enabling it to provide power quality/flow monitoring supporting various reliability, revenue protection and asset management applications, including distribution transformer monitoring, energy theft detection, Fault Detection, Isolation and Restoration (FDIR) and Outage Management.  Table 1 summarizes the functions provided by the IPR and the resulting applications that it can address, as well as specific utility benefits. 

Table 1 – Key IPR Functions, Applications and Benefits

 

Function

Application

Benefits

Voltage Regulation

ANSI Compliance

  • Avoid costly reconductoring or transformer replacement and assure voltage compliance irrespective of network impedance and loading.

 

Asset Extension

  • Reduce operation of mechanical LTCs, line regulators and switched capacitor banks by simplifying feeder Volt-VAR Control (VVC)
  • Avoid increased operation (wear and tear) of mechanical Load Tap Changers (LTCs), line regulators and switched capacitor banks caused by variable and distributed generation

 

DG Integration

  • Manage voltage rise and fluctuations to increase PV hosting capacity and ensure more reliable integration of DG
  • Ensure ANSI compliance
  • Avoid CBEMA/ITIC violations and customer equipment damage/failure

 

Energy Efficiency / CVR

  • Local benefit: ensure compliance with CVR targets at all times; optimize local consumption based on load characteristics
  • Feeder-level: decouple limiting loads from feeder, unlocking energy savings that would otherwise be stranded by centralized (MV-only) CVR schemes

 

Peak Demand Reduction

  • Local and feeder-level: dynamically adjust voltage during peak periods to reduce consumption, effectively increasing system capacity and/or reducing congestion, enabling deferment and reduction of Generation, Transmission and Distribution capacity investments
  • Avoid demand charges
  • Utility-controlled DR asset — no dependency on third parties or end customer participation

 

Power Quality – Sag/Swell Mitigation

  • Prevent motors from stalling due to system disturbances, e.g. air conditioners
  • Prevent DG from nuisance tripping
  • Fewer momentary outages

Reactive Power Compensation

Distributed Power Factor Correction

  • Maintain desired power factor where it is most effective — as close to the loads as possible, reducing line losses and the amount of reactive power required in the system, thereby freeing up distribution system capacity

Harmonic Cancellation

Power Quality – Reduced Harmonic Distortion

  • Cancel current harmonics as seen by the grid caused by non-linear loads and PV inverters; prevent accumulation of 3rd-order harmonics, high neutral currents and protect utility equipment from damage
  • Cancel voltage harmonics from the grid to the customer to protect customer equipment from damage

Voltage and Current Sensing

Asset Management – Distribution Transformer Monitoring

  • Monitor the load, environment and health of the distribution transformer asset in support of condition-based maintenance, resulting in lower maintenance costs and fewer equipment failures

 

Revenue Protection – Energy Theft Detection

  • Support for energy theft detection by comparing the energy through the distribution transformer with that at the subtending meters

 

Power Quality – Power Flow and Quality Monitoring

  • Improved monitoring and forecasting of load and grid performance, enabling a more efficient mix of generation and ancillary services that could be optimized to reduce cost
  • Monitor power flow to determine presence of undesired reverse flow for lineman safety
  • Monitor and capture power quality throughout the distribution grid and being delivered to end customers

 

Reliability – FDIR and Outage Management

  • Reduce momentary and sustained outages, improving SAIDI/ SAIFI/MAIFI metrics
  • Detect and provide notifications/alerts on fault currents, outages and service restorations
  • Ensure CVR compliance during feeder isolation events

The New BAU Meets the Utility Cost-Effectiveness Framework

As with all utility solutions, new or old, it is necessary to evaluate cost-effectiveness in order to drive adoption.  Will the benefit-to-cost calculation stand up to detailed scrutiny and analysis?  To find out, we solicited help from leading industry experts. 

In partnership with Energy + Environmental Economics (E3), a third-party, independent consulting and advisory firm that specializes in North American electricity markets, we developed the following framework to evaluate the cost-effectiveness of the IPR, placing value on the major functions and categorizing their associated benefits.  Leveraging the Standard Practice Manual (SPM) economic framework, cost-effectiveness tests that are commonly used to evaluate potential grid investments were adopted and applied to the IPR.  Table 2 below summarizes the key benefits provided by the IPR within the three standard cost-effectiveness tests: the Lifecycle Revenue Requirement Test, the Total Resource Cost Test, and the Societal Cost Test.

Table 2 – Summary of Cost-Effectiveness Tests

 

 

 

 

 

Use Case

Costs

Lifecycle Revenue Requirement Test

Total Resource Cost Test

Societal Cost Test

CAPEX

OPEX

Avoided CAPEX

Avoided OPEX

Further Benefits

Further Benefits

Localized Deployment
Single IPR Device

LV IPR

IPR power losses (1%)

Avoided baseline solution distribution equipment

CVR - EE (limited to customers behind IPR)

Sag/Swell Mitigation

Improved customer satisfaction

 

 

Avoided need for transformer monitoring equipment

Avoided increase in distribution transformer losses

Better performance of customer-sited DG

Uncapped emissions reductions (NOx)

 

 

CVR - system capacity (limited to customers behind IPR)

Power factor correction

Harmonic cancelation

 

Feeder Level
Multiple IPR Devices

All of the above

LV IPRs

IPR power losses (1%)

New substation transformers

Reduced Wear on MV device(s)

Lower SAIDI/SAIFI

Reduced land use

 

 

New capacitors

Decreased distribution maintenance (outage detection)

 

Expedited DG interconnection

 

 

New relays and switches

CVR - EE (OLTC derived benefit)

 

 

 

 

CVR - system capacity (OLTC derived benefit)

Increased sensing on secondary

 

 

The primary metric of cost-effectiveness for capital improvements to utility distribution systems is the “lifecycle revenue requirement.”  This is the industry standard for comparing alternative investment plans.  In many jurisdictions, if a distribution investment satisfies this criterion, there would not be a need to get additional authorization from the utility regulator.  However, this metric is quite restrictive and only includes those costs and benefits that must be collected from customers to pay for utility equipment.  Benefits for utility customers would not be included, such as fewer and shorter outages, better power quality and other improvements in utility services.

The recommended approach to value those attributes of the IPR that benefit customers is the Total Resource Cost (TRC) test.  The TRC includes monetized costs and benefits to customers, as well as monetized benefits that do not impact revenue requirements, such as sag/swell mitigation and reduced outage frequency and duration.  When appropriate, the recommended approach to non-monetized benefits, such as improved customer satisfaction, is the Societal Cost Test (SCT).  This cost-effectiveness framework can be used when considering IPRs for a variety of utility applications or programs.

The New BAU and CVR

Consider a CVR program in which the utility is interested in further lowering the primary feeder voltage to achieve greater energy efficiency.  The conventional approach to CVR relies solely on the control of MV-oriented equipment (LTCs, line regulators and capacitor banks) to manage feeder voltage.  This type of equipment can help flatten and lower voltage across the MV primary.  However, they are generally not able to lower service voltages enough to meet desired savings goals without risking under-voltage excursions.  The hidden constraint is the LV secondary voltage drop, which can be 5% or more at scattered locations for certain periods of time.  Secondary distribution networks are not part of the conventional voltage regulation zones.  To reliably and consistently deliver on CVR savings targets, utilities need to identify and actively regulate secondary voltage at these limiting points, thereby enhancing the systemic gains possible through centralized operation of MV regulation infrastructure.  If this can be achieved, the upside is a significant improvement in peak reduction, energy savings and overall efficiency – putting CVR goals within reach, or enabling more aggressive CVR goals to be realistically achieved.

Once the limiting points have been identified, the utility generally has a few options available: reconductor the secondary or replace the distribution transformer to reduce the voltage drop (aka “the old BAU”), or deploy an IPR to boost the voltage.  If the amount of voltage drop that needs to be compensated is greater than 0.5-1.5%, which is generally the case, the only viable options are reconductoring or using an IPR, since transformer upsizing typically only changes the voltage drop by a fraction of a percent, and is not guaranteed to solve the problem, especially as local supply/demand dynamics change over time. 

Although reconductoring costs for utilities vary widely across the country, a typical cost estimate to reconductor a single-phase secondary is approximately $10,000-$12,000 for overhead (including material and labor), and approximately twice that for underground, especially for direct buried systems. Given the relatively high cost for reconductoring, using an IPR is a clear choice for each location.  For approximately 5% of transformer locations, this typically results in a small investment of $30,000 to $60,000 per feeder, versus double that if the utility were to reconductor.

By deploying a handful of IPRs at each of these limiting points, the utility is now able to further reduce voltage along the medium-voltage primary, increasing peak reduction and energy savings across the entire feeder – typically on the order of $500,000 to $1.5M (NPV) depending on the feeder.  Thus a small investment in IPRs can be leveraged into a large amount of feeder-wide savings, resulting in a highly compelling outcome for the Lifecycle Revenue Requirement test.

The remainder of IPR functionality: reactive power compensation, source current and load voltage harmonic cancellation, and voltage and current sensing, while still relevant for many other distribution grid applications, effectively become additional sources of value that continue to strengthen the Lifecycle Revenue Requirement test and enable highly positive Total Resource Cost and Societal Cost tests.

Agile Grid Infrastructure is the New Business Advantage for Utilities

The commercial availability of Agile Grid Infrastructure, such as In-Line Power Regulators, represents a transformational opportunity for the industry.  Based on commonly used utility cost-effectiveness tests, these multi-function, utility-scale power electronics devices offer compelling value when deployed locally and throughout the distribution system, particularly when compared against conventional business-as-usual approaches such as reconductoring and asset replacement.

Grid modernization is no longer just about replacing old assets or investing in smart meters.  It now includes the transformation of the distribution system into an active, intelligent and two-way power exchange that enables reliable, efficient, affordable and sustainable energy for generations to come.  Selecting the right Agile Grid Infrastructure is the first critical step, as not all solutions are created equal.  When evaluating options, it is important to select an architecture that can cost-effectively address current and emerging applications while providing a foundation for a truly modern grid.  That is the new BAU.

 

 

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