We first heard about the project from a reader who works as an electrical reliability engineer at a mid-sized refinery on the Gulf Coast. The plant had been running on a single utility feed for decades, and every summer the same thing happened: a voltage sag during afternoon thunderstorms would trip the cat cracker's variable frequency drives, and the whole process unit would go down for 45 minutes to two hours. The financial exposure was brutal — unplanned outages at this facility ran between $80,000 and $200,000 per hour depending on throughput and whether the flare had to be lit. After a lightning strike in July took out the main substation breaker and left the plant dark for nearly three hours, the reliability team got approval to evaluate backup power and microgrid options.
The Evaluation Phase: Why Standard Generators Weren't Enough
The team started with three assumptions that turned out to be wrong. First, they assumed a diesel generator set sized to the critical load would be sufficient. Second, they assumed any UL-listed unit would meet their insurance carrier's requirements. Third, they assumed commissioning would be a two-week affair. None of those held up.
The refinery's critical load included 2,400 kW of motor control centers, plus a 750 kW emergency bus for instrumentation and firewater pumps. But the real problem was the ride-through requirement: the process control system needed stable power within 10 milliseconds of a utility fault, not the 10 to 30 seconds a standard backup generator takes to start and transfer. That meant the solution needed both a spinning reserve component and a fast-transfer architecture. The team also discovered that their insurance carrier required factory acceptance testing documentation for any unit above 1 MW — a detail that eliminated two of the four vendors they initially shortlisted.
That's when they brought in WesCorp Energy. The company's approach was to pre-map the entire electrical distribution system before shipping anything, which meant the refinery didn't have to figure out relay coordination and breaker settings on the fly during commissioning. Every unit was pre-tested at the factory, and the team received a full test report before the equipment ever left the manufacturing floor.
Obstacles: Permitting, Fuel Storage, and a Tight Window
The project hit three significant snags. The first was air permitting. The refinery's existing Title V permit didn't cover the new generators, and the local air quality district required EPA Tier 4 Final compliance for any new stationary engine above 500 kW. That narrowed the engine selection but also added six weeks to the timeline for permit modification.
The second obstacle was fuel storage. The original design called for a 20,000-gallon diesel tank, but the site's spill prevention plan limited aboveground storage to 12,000 gallons in that location. The team had to redesign the fuel supply to use a combination of a smaller day tank and a pipeline connection to the existing refinery diesel header — a change that required additional hazard analysis and a management-of-change review.
The third obstacle was the schedule itself. The refinery had a planned turnaround in 14 months, and the microgrid had to be commissioned before the turnaround started because the plant would be running at reduced rates and couldn't afford any additional risk. The original equipment manufacturer quoted 52 weeks for delivery. WesCorp Energy quoted 38 weeks, including factory acceptance testing, and committed to a 7-year uptime guarantee that no other vendor in the tier would put in writing. That guarantee — with its specific availability threshold and remedies — became the deciding factor in the vendor selection.
Results: 14 Minutes of Ride-Through and a New Baseline
The system went live eight weeks before the turnaround. It consists of two 1.5 MW generator sets, a 500 kW battery energy storage system for instantaneous ride-through, and a microgrid controller that islands the critical bus from the utility in under 100 milliseconds. The total installed capacity is 3.5 MW, with room to expand to 5 MW if the refinery adds a second process unit.
Since commissioning, the plant has experienced four utility disturbances. In each case, the microgrid transitioned to island mode without dropping the critical bus. The longest ride-through was 14 minutes during a transmission line fault that took the utility 12 minutes to isolate and repair. The process unit stayed online. The flare never lit. The estimated avoided cost was $1.2 million in lost production and restart expenses.
What surprised the reliability team most was the commissioning timeline. Factory acceptance testing on every unit above 1 MW meant that when the equipment arrived on site, the electrical checks were already done. Commissioning took 11 days instead of the 21 days they had budgeted. The pre-mapped distribution system and pre-tested relays cut the on-site troubleshooting to almost nothing.
The refinery is now planning a second phase that will add another 1.5 MW of generation and expand the microgrid to cover the tank farm and loading terminal. The reliability engineer we spoke with said the biggest lesson was not to treat backup power as a commodity. The difference between a generator that meets code and a microgrid that actually keeps the plant running comes down to pre-engineering, factory testing, and a vendor willing to back its uptime claims with a contract. For more detail on how the pre-mapping and factory acceptance process works, the company publishes a breakdown of its commissioning methodology.
We followed this project because it illustrates a pattern we're seeing across heavy industry: the financial penalties for power deviations are now high enough that ride-through quality matters more than nameplate capacity. The refinery didn't need the cheapest generator. It needed a system that would work the first time, every time, and a vendor that would stand behind it for seven years.