Electricity + Control November 2018

TEMPERATURE MEASUREMENT + INSTRUMENTATION

been able to leverage data from those towering machines to prevent component failures and make minor design tweaks that make them more effi- cient, often at no additional expense. Such depar- tures from traditional applications hold the promise of paring operational costs and furthering sustaina- bility by using data analytics to better understand our environment and drive greater decisions about costs, materials and the amount of energy used or, more importantly, wasted. Utilities are interested in improving grid reliabil- ity and efficiency through the use of automation and a deeper understanding of grid operations. To achieve that, according to the Black & Veatch’s report, one-third of utilities plan to implement ad- vanced metering infrastructure. Thirty percent ex- pect to put in place a distributed energy resources management system, with an equal percentage looking at outage management systems. Twen- ty-eight percent are considering new modelling tools for distribution planning ( Figure 2 ).

as part of a coordinated data monitoring strategy, linked to asset life cycle plans; and 22% say they will implement smart infrastructure projects as ex- isting assets are retired. Some 17% are planning for wholesale replacement of existing assets with smart assets. Twenty percent of respondents are not includ- ing smart infrastructure implementation as part of their repair/replacement programs or capital plans. Putting strategy into practice An emerging trend among utilities operating in the DER space is the narrowing focus on determining the appropriate level of monitoring and the corre- sponding economic investment. The question be- comes: What is the right level of monitoring from a cost and production standpoint? Let’s look at an example of solar.Typically, plants monitor at the inverter level because inverters are the most common point of on-site failure, and it’s the first level of observation. Inverter data can pro- vide critical performance metrics such as power lost during dc to ac conversion, or fault code infor- mation for remote troubleshooting. At the utility scale, the growing trend is to build large plants using smaller inverters (string invert- ers). For example, instead of using one 2 MW in- verter, a plant would use multiple 100 kW invert- ers. Building large plants using smaller inverters offers the ability to communicate on a much small- er level while also delivering operations and main- tenance (O&M) and production benefits. Failure on smaller inverters also means smaller losses. However, from the financial perspective, it does not always make sense to repair each individual inverter – rather, it is more economical to repair inverters in batches. The fix has to pay for itself. Other levels of monitoring take an even closer look. Subarray monitoring on larger systems takes it one step deeper, providing greater visibility to identi- fy issues at the string or module level. Specific sub- array or zone monitoring breaks apart an inverter’s array into smaller metered arrays, allowing for easier identification of strings and areas of the array without investing in costly site visits and/or analysis. String level monitoring offers even more gran- ularity. Used by utility-scale PV plants to detect low production and potential energy loss, string monitoring combines 20 to 30 modules per string. These groups of strings then are combined in

To assimilate DERs into the generation mix, utilities are returning to the Internet of Things.

What types of investments, system operational tools and/or changes is your organisation implementing or planning to implement to enable greater distributed energy resource (DER) deployment and management? (Select all that apply).

Advanced Metering Infrastructure (AMI)

33.3% 29.6% 29.6% 27.8% 25.9% 25.9% 25.9% 24.1% 24.1% 22.2% 18.5% 16.7% 14.8% 13.0% 11.1%

Distributed Energy Resource Management System (DERMS) Outage Management Systems (OMS) New modelling tools for distribution planning Tracking DER installations in centralised GIS database/distribution network model Enabled Sensors, Supervisory Control and Data Acquisition (SCADA) Energy Management System (EMS) Advanced Distribution Management System (ADMS) Improvement/revision of current processes Incorporation of DER into the integrated resource planning (IRP) process On line customer engagement tools or portal Demand Response Management System (DRMS) Distribution Management System (DMS)

Streamlined/automated interconnection

Organizational design changes

Service based support

3.7% 7.4%

None of the above

Survey results show that the majority of utilities (80%) are planning to add smart assets as a crit- ical component of their repair/replacement pro- grammes. Of that number, 41% plan to add smart assets in critical areas guided by cost/benefit anal- ysis; 25% are looking at deploying smart assets

Electricity + Control

NOVEMBER 2018

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