Published by Alaska Automation | Electrical, Mechanical & SCADA Engineering

Designing and maintaining electrical systems for remote power generation is a discipline that tests every assumption you would make in a conventional engineering environment. The problems that surface in remote Alaska communities — and in remote communities across northern Canada and the Pacific Northwest — are not always the most technically complex issues an electrical engineer will encounter in their career, but they are often the most consequential. When the nearest spare transformer is two days away by bush plane, and the community it serves has no backup power source, getting the engineering right the first time is not just a professional standard. It is an operational imperative.

This article addresses the most common and most impactful issues that electrical engineers encounter in remote community power generation, with specific attention to the Alaskan context.

1. Aging and End-of-Life Generation Equipment

The majority of remote Alaskan communities that rely on diesel generation are running equipment that was installed in the 1980s and 1990s. Generator sets, switchgear, automatic transfer switches, and protection relays from that era are approaching or have already exceeded their design service lives. The consequences are predictable: increasing failure frequency, spare parts that are no longer manufactured, and control systems running proprietary software with no upgrade path.

What makes this hard: Utility managers and cooperative boards often know their equipment is aging but lack the engineering resources to assess the actual risk and develop a prioritized replacement plan. The result is reactive maintenance — repairing failures rather than preventing them — which is more expensive, less reliable, and harder to plan around.

The engineering response: A condition assessment study that combines equipment age data with operational history, failure mode analysis, and a risk-ranked replacement schedule gives operators and boards the information they need to make capital planning decisions. It also identifies the items that represent the highest risk of unplanned outage — the failures that cannot wait for the next capital budget cycle.

2. Protection System Coordination on Isolated Grids

In a utility interconnected grid, fault current levels are relatively predictable, and protection coordination — ensuring that the right breaker opens for any given fault, and that it opens fast enough to prevent damage — is a well-understood engineering problem. On a small, isolated community grid with one or two diesel generators, the problem is considerably more complex.

Fault current on a small isolated system is directly proportional to generator size. When a generator trips offline, fault current levels drop dramatically — and protection relays that were set for normal operating conditions may no longer operate correctly under reduced-generation scenarios. In the worst case, a fault on the distribution system does not clear at all, and the generator(s) continue to feed the fault until they are damaged.

Common failures in this area:

• Protection relay settings that were calculated for a specific generation configuration and never updated when generators were added or removed

• Mismatches between available fault current and the interrupting ratings of installed breakers and fuses

• Lack of ground fault protection on grounded-wye distribution systems, leading to sustained single line-to-ground faults that degrade insulation over time

The engineering response: A protection coordination study, updated to reflect the current generation configuration and distribution system topology, is the fundamental deliverable. For systems where the generation mix has changed significantly over time, field verification of existing relay settings — not just a desktop review — is essential.

3. Load Management and Demand Response on Fuel-Constrained Systems

In remote communities, fuel supply is finite and expensive. Every kilowatt-hour wasted in transmission losses, inefficient loads, or unnecessary peak demand represents a direct cost to residents and ratepayers. On systems where total generation capacity is tight, unmanaged load growth can push peak demand close to — or beyond — installed capacity, forcing load shedding at the worst possible times.

Electrical engineers working in this environment are increasingly called on to design and implement automatic load management systems that prioritize essential loads, shed interruptible loads when generation capacity is constrained, and integrate with demand response programs for large customers (typically commercial facilities and industrial loads within the community).

Key design considerations:

• Load priority tiers must be defined in consultation with community leadership and utility management — the engineering team should facilitate the conversation, not make the call unilaterally

• Automatic load shedding schemes must be tested under realistic conditions before they are relied upon

• Load management systems that integrate with SCADA allow operators to monitor demand in real time and make proactive adjustments before automatic shedding is triggered

4. Integration of Renewable Generation with Diesel Systems

Adding wind, solar, or hydro generation to an existing diesel-only system is operationally and technically more complex than it appears from the outside. The penetration level of the renewable source — how much of the total load it can serve at peak output — directly determines the complexity of the control system required to maintain grid stability.

At low penetration levels (below roughly 25% of total generation capacity), renewable integration is relatively straightforward. As penetration increases, the control challenges multiply: diesel generators operating at minimum stable load become a source of instability; the response time of diesel governors is not fast enough to compensate for rapid renewable output fluctuations; and islanding protection on the renewable inverters must be carefully coordinated to prevent them from tripping unnecessarily.

What electrical engineers need to get right:

• Renewable inverter settings — specifically, frequency and voltage ride-through settings — must be coordinated with the diesel generator protection settings. Mismatched settings are the most common cause of unnecessary renewable resource disconnections.

• Energy storage systems (batteries) are increasingly used as a buffer to enable higher renewable penetration. The battery management system (BMS) and its integration with the overall plant control system require careful engineering to operate safely and efficiently.

• The diesel generator fuel savings from renewable integration are frequently overstated in early project analyses. A realistic assessment of minimum load constraints, spinning reserve requirements, and part-load diesel fuel consumption rates is needed to produce a credible dispatch model.

5. Cold-Weather Equipment Specification Failures

Specifying electrical equipment for cold-weather operation sounds straightforward — check the nameplate operating temperature range, confirm it covers your design minimum, and move on. In practice, this process breaks down frequently enough that cold-weather failures represent one of the most persistent problems in remote Alaska electrical work.

Common specification gaps:

• Battery systems specified at -20°F ambient without accounting for the significant reduction in battery capacity at low temperatures. A battery bank sized for room temperature performance may deliver 30-40% less capacity at -20°F.

• Lubricants in motor bearings and gearboxes that are rated for the ambient temperature but not for extended cold soak conditions (i.e., equipment that has been de-energized and sitting in the cold for days before startup)

• Instrument transmitters and pressure gauges with fill fluids that gel or freeze at temperatures below their rated minimum operating temperature, causing erratic readings or transmitter damage

• Communications equipment — radios, modems, cellular routers — that meets the specified temperature range in a laboratory test but has inadequate thermal management for continuous outdoor operation in an Alaska winter

The engineering response: Cold-weather specification requires going beyond the nameplate operating temperature to understand how a specific piece of equipment will actually perform at sustained low temperatures. This means consulting with manufacturers' applications engineers, reviewing field experience from similar installations, and in some cases specifying supplemental heating (heat tape, thermostatically controlled heaters in enclosures) even for equipment that nominally meets the temperature specification.

6. Documentation Gaps in Inherited Systems

Perhaps the most universally frustrating challenge in remote community power engineering is working with systems where the as-built documentation does not match the as-installed reality — or where documentation does not exist at all.

This is not a failure of any individual. Remote facilities change over time: generators get replaced, circuits get added, relay settings get adjusted. Documentation that starts out accurate degrades over years of undocumented field changes. The electrical engineer arriving at a remote site to perform a protection coordination study or design a new interconnection is working from drawings that may be decades out of date and field conditions that do not match anything on paper.

The practical approach: Budget time and cost for as-built verification on any project that involves modifying an existing system. This means physically tracing cables, verifying breaker ratings, reading installed relay settings, and cross-referencing against available documentation before beginning engineering design work. It takes time and costs money. It costs less than designing a modification based on incorrect information and discovering the discrepancy during commissioning.

Remote community power engineering rewards humility, preparation, and experience. The problems are real, the consequences of failure are serious, and the solutions require engineers who understand not just the technical principles but the operational environment they are designing for.

Alaska Automation's electrical engineering team works with utilities, cooperatives, and industrial operators across Alaska and the Pacific Northwest on exactly these challenges. Reach out to us if you are working through any of the issues described here — we are glad to talk through your specific situation.