Integrating distributed energy resources into the smart grid - Part 1

The electrical power generation, transmission and distribution system thrived for decades with limited intelligence. But present and future demands are necessitating a transition to a smart grid, particularly the need to incorporate distributed energy resources (DERs) into the generation mix.

DERs are defined as small-scale decentralised power storage and generation sites, typically 15 MW or less per unit or site. In most cases, these DERs are not owned by the local utility but, rather, by end users. Power from DERs is used to meet local on-site end user needs and excess power may be sold back to the utility via the local power distribution grid.

Types of DERs include, but aren’t limited to, gas turbines, diesel engines, microturbines, flywheel energy storage systems, fuel cells, batteries and super capacitors. Rooftop solar photovoltaic, small wind power and geothermal sites are also part of the DER mix. Cogeneration is often a feature of DERs with heat produced as part of the power generation process used locally.

Integration of DERs into the local distribution system and ultimately into the entire utility generation, transmission and distribution system is problematic for a number of reasons.

Why DERs?

Most utilities worldwide operate as quasi-independent firms with a significant amount of government oversight. For a variety of reasons, some good and some not, governments worldwide are strongly encouraging and often mandating the incorporation of DERs into utility generation portfolios.

One of the good reasons why governments are promoting DER use is because they lessen the load on utility transmission and distribution systems. Power generated locally on a distributed basis is used in one of two ways: either on site by the owner or by other users through the power distribution system.

Power produced by a DER and not used by the owner may be fed back into the utility local power distribution system. Although it’s impossible to track the exact path of power through the grid, it stands to reason that much of the power produced by DERs stays within local distribution and never reaches the higher voltage level of the transmission system.

Another good reason for the growth of DERs is that they reduce the need for large, centralised power generation plants. As with high-voltage transmission lines, getting government approvals for these large centralised plants is very difficult, time consuming and expensive.

Finally, DERs can be part of an overall green power generation solution. When DERs are renewable, the green impact is obviously positive and DERs can be a good way to incorporate renewables into the generation mix. Some types of renewable DERs, such as geothermal sites, are inherently local and usually relatively small in capacity, making them well suited to distributed, rather than centralised, generation.

On the other hand, DERs burning fossil fuels actually increase overall emissions as compared to large centralised power plants. This is due, in part, to the strict rules government agencies impose on large centralised plants, while DERs, because of their lower MW output and favoured regulatory status, are often exempt from these emissions standards.

So, for both regulatory and technical reasons, a small fossil fuel plant will produce more emissions than a larger plant on a per megawatt basis. It’s also much harder to monitor and regulate emissions from many smaller sites as opposed to fewer and larger sites. There are various methods for making fossil-fueled DERs greener, chief among them cogeneration. With cogeneration, waste heat produced as a by-product of power generation is used locally by the DER.

When utilities ruled the world

To understand the problems posed by DERs, it helps to look at the utility landscape prior to their introduction. Before the advent of DERs and independent power producers (IPPs), most utilities produced all of their power from a relatively small number of large centralised generation facilities.

Power output from these generation facilities was ramped up and down to meet customer demands - most efforts were focused on building sufficient infrastructure to provide power no matter the circumstances.

IPPs emerged during the 1980s. IPPs were connected to the grid but not owned by the utility, and controlling their power output was much more difficult than with utility-owned facilities.

Utility-owned generation facilities are operated with the primary goal of providing power to customers on a predictable and reliable basis. The primary goal of IPPs is to make money by running their facilities at maximum efficiency. These conflicting aims can cause problems because power from IPPs may not be available when needed most by utility customers.

Through various agreements, utilities work with IPPs to reconcile conflicts but it’s often difficult to integrate IPPs into the generation mix. With DERs, the same basic conflict between reliability and profitability exists, but other factors make integration even more difficult.

In terms of sheer size and numbers, DERs are much smaller than IPP facilities and a lot more numerous. It’s much easier for a utility to negotiate reliability agreements with a few large IPPs as opposed to many small DERs. Monitoring compliance with these agreements and assessing penalties where necessary is also much more difficult with DERs than with IPPs.

Both IPPs and DERs must comply with design and test standards for safe integration into the utility system, namely IEEE 1547. Assuring compliance with these standards is again easier for larger and fewer IPPs as opposed to smaller and more numerous DERs.

The bottom line is that IPPs and DERs have greatly complicated the utility generation equation. But that’s not the only impact, as local distribution systems also face issues when integrating DERs.

Beware the back feed

As stated above, before the advent of IPPs and DERs, local utility power distribution systems received all of their power from central generating plants via transmission lines. Power was generated and stepped up to transmission voltage levels then, in some cases, down to subtransmission levels. Substations stepped transmission and sub-transmission voltages down to more manageable levels for local distribution.

Now, as then, substations act as the hub of the local utility power distribution system. Once power is stepped down via substation transformers, it is then distributed through circuit breakers to feeder lines. Each feeder line typically accommodates a few thousand utility residential customers or a much smaller number of larger commercial or industrial customers.

Over the years, utilities have devised a number of methods to find and repair problems on their distribution systems, all predicated on the flow of power through transmission and distribution systems from upstream generation to downstream customers. Frequent maintenance has kept problems to a minimum, but safely performing these activities often depends on the predictable power flow of a radial distribution system.

With DERs in the system, power can be fed back into the local distribution system from a variety of sources located throughout the service area. Locking and tagging out a substation circuit breaker cuts upstream power but a DER can still be backfeeding power into the system.

In other words, if one of the utility customers owns and operates a DER, let’s say a natural gas cogeneration system, the distribution system is no longer a radial system. This creates two major issues. One is that it complicates the protective relaying scheme, which assumes the distribution feeder is radial. Adding downstream generation to a radial feeder system can result in desensitising overcurrent relays such that they no longer trip on electrical faults.

The other problem arises during planned and unplanned shutdowns. Utility crews generally assume a radial system and shut off all upstream power sources at either the substation feeder or the distribution transformer level. In this situation DERs can create a very dangerous and, possibly, lethal situation.

To deal with this issue, utilities require each DER to have an interconnection system that isolates it from the distribution system when it senses a loss of utility voltage. This is typically done by protective relays internal to the generating facility or by a direct transfer trip signal from the substation.

Recommended practices for implementing interconnection systems can be found in IEEE 1547. More specific implementation instructions are often implemented at the utility level.

But that’s not the only way DERs add complexity to the local power distribution system. Balancing the power demands of each DER customer is now a significant issue, as demand must be fed by a continuously changing mix of utility-provided and DER power.

Where’s my power?

For a customer without an on-site DER, meeting power demand is relatively simple. The utility simply monitors voltage levels and makes sure that voltage is sufficiently high to allow the customer to draw their required current. When voltage dips, the power system is adjusted accordingly. Energy delivered to the customer is measured using a meter and the customer is billed accordingly.

But what happens when a customer produces their own power via a DER? First, the customer still wants the utility to maintain a delivery system sufficient to provide all of their power needs for times when their DER is not operating. Second, the customer wants the utility to provide partial power for times when their DER is meeting some but not all of their power needs. Third, the customer may want to be able to sell all power in excess of their needs back to the utility.

This is obviously a much more complex scenario than that of a typical customer and it raises a number of problems for the utility. Power flowing back into the grid must be accurately measured and appropriate adjustments must be made to DER customer utility bills.

As mentioned earlier, there will be times when the utility simply can’t allow the DER customer to backfeed power into the system - and there must be a simple, low-cost and reliable way to ensure that power is not fed back into the system in those situations.

Synchronisation between the DER and the power grid is also critical. Power-generation equipment based on rotating machinery, such as gas turbines and diesel engines, must be synced to grid frequency. If a DER gas turbine is connected to the grid 180 degrees out of phase it will immediately be jerked back into sync and destroyed. Other types of DERs have different but related synchronisation issues.

For local control and for integration into the utility system, DERs need to employ automation systems to monitor conditions and to control equipment. Fortunately, many practical automation solutions are already in place, with more being developed and implemented to match the growth of DERs.

In Part 2

The integration of distributed energy resources into the existing electricity grid poses some safety and management challenges, as we have seen. In Part 2 of this article, we will look at how these challenges can be overcome with current automation technology.

By Gary Frederich and Patric Dove, Advantech Corporation, Industrial Automation Group