At petrochemical refineries and natural gas plants, the process of producing oil and gas involves an array of complicated steps. Every part of the industrial process depends on a reliable supply of electrical power to keep the machinery in motion. Production downtime is costly and, in the case of natural gas plants, the entire production run can literally go up in flames. As a result, most large oil and gas facility personnel consider onsite generators as their primary power sources and grid connections as insurance policies. From this viewpoint, it's easy to see why these employees place great importance on the proper protection and monitoring of onsite generators.

The Yates Gas Plant

One facility that fits the above description is Marathon Oil Co.'s Yates gas plant in Lakewood, N.M. The plant, which primarily serves as a support facility for the Yates oil field, houses a large compressor station that recycles gas for injection into the reservoir.

The Yates plant had a history of unreliable power service. Short outages would upset the plant's chemical and cryogenic processes, creating out-of-spec product. During these events, plant engineers had to purchase fuel commercially to restart the facility, which could cost $15,000 (based on market values). Extended power outages also created huge deficits in oil production at the Yates field, which generates about 20,000 barrels a day. At $25 a barrel, that's a revenue stream of approximately $500,000.

Charlie Adams, a senior engineer with Marathon Oil, was one of a handful of engineers assigned to resolve the problem.

“The existing hardware was all pure analog devices with no historical data capture capabilities,” says Adams. “Pinning down problems was really a series of educated guesses.”

According to Adams, the engineers zeroed in on what they call the trip index — the breaker trip frequency of the utility feeders, where a utility tie and two generator sets feed power into the bus. Handwritten maintenance records showed a thousand trips on the utility tie-breaker in a three-year period, translating to about one trip per day. With that information, Adams knew the primary job was to bring the trip index down.

Further investigation uncovered a messy, overlapping combination of generator and governor control problems, reverse power trips, significant transient issues, and unreliable electromechanical relays with questionable maintenance histories.

Eventually, the engineers decided to replace the unreliable relays on the utility feeders with SEL-351 digital relays (see photo), install two SEL-300G generator relays, and replace 34 aging electromechanical relays.

Marathon Oil personnel already had installed a base of another manufacturer's relay, so Adams knew he would need compelling data to justify the switch to SEL. His research yielded favorable reviews, culminating with a positive response from their electric utility in Texas.

“Reliability is a big issue due to the exposure a public utility has, and they made the decision to change out the other relays and go exclusively with the SEL-351 feeder management relays,” says Adams. “When I showed my people what our local power supplier had gone through…my recommendation wasn't even challenged.”

Retrofitting the 12.5kV switchgear was a significant task that required a rigid one-week shutdown window based on the plant's mechanical maintenance schedule. After six months of planning and preparation, engineers installed the new relays and programmed the new hardware.

Microprocessor-based relays like the ones installed at the Yates plant are programmed for various types of protection and control, which reduces wiring costs and increases overall system reliability. Additional benefits include the following:

Sequential event reports and waveform captures

Unlike electromechanical or static protection systems, digital relays provide a window into a power system during disturbances. For example, generation was interrupted at the Yates plant when a cable shield wire shorted two generator phase conductors to ground. The faulted generator and a second generator were both connected to the load bus at the time of the fault. Waveforms for both generators were captured and the reports were analyzed.

One report confirmed a valid protection operation due to a fault within the generator differential protection zone. This analysis led to a change of the percent slope settings on both generator protection systems, which added a larger degree of external fault protection with little loss of internal fault sensitivity.

Notice how, in Fig. 1, the waveform from the faulted generator shows that generator current continues to flow after trip outputs have opened the connection to the load bus. This confirms that the fault is within the differential zone and the fault current was not interrupted by the tripped generator bus-tie breaker.

Source location

Another benefit was the engineers' ability to collect data that could determine if problems were coming from the supply side or the demand side. At times, Adams has shown captured data to power companies and helped solve problems at the supply level.

Remote access and monitoring capabilities

According to Adams, Marathon Oil employs a handful of people to support power systems throughout the company, which covers a fair amount of territory. The ability to remotely manage devices is an advantage.

Adams uses remote access to configure devices and access surveillance reports. He typically calls the relays twice a day to conduct status checks and to look at the triggers and histories for smoking guns.

Recently, he noticed a problem with the DC batteries that power the critical trip circuits for the Yates' breakers. The battery systems are 125VDC, and twice a day he observed a pattern where they would cycle through an intense recharge well in excess of 140V before cycling back to normal levels. After keeping an eye on the pattern for a few weeks, Adams captured hard data demonstrating the event and passed it to the electricians, who located and fixed some problems with the charging connections.

Current transformer performance assessment

Engineers at the Yates plant were able to use the monitoring capability of the digital relays to detect current transformer saturation and DC offset.

The ultimate measure of the project's success was a fourfold improvement in the trip index. When the power system was brought back up, the trip index factor had gone from nearly 1.0 to about 0.25.

The Indian Basin Plant

As a result of the Yates project, Adams received a call from engineers at the Indian Basin plant in Iraan, Texas — another one of Marathon's premier asset bases in its southern business unit. The Indian Basin plant has a more complicated power system consisting of a 480V bus, three turbine generators, a utility connection, and a standby feeder.

The Indian Basin plant has a much higher risk of production losses because of the large volume of natural gas that goes to flare during an outage. Production levels run at approximately 250 million cubic feet a day. If natural gas is selling at $3 per thousand cubic feet when an outage occurs, then a $750,000-a-day revenue stream evaporates at a rate of $30,000 an hour. This figure doesn't include fixed facility startup costs that can soar to $100,000.

The challenge with this facility was integrating two additional distributed generators and one 900 hp motor. These generators and the motor fed into and drew startup power from the bus. The facility was also experiencing many of the same types of problems as the Yates plant, including phantom trips and fluttering generator controls. The engineers at Indian Basin consulted Adams after hearing about his accomplishments at the Yates plant.

Although the superintendent at Indian Basin was rather possessive of the generator controls and packages that were critical to the plant, he was impressed enough with the Yates project to agree to the installation of an additional SEL-351 relay on the Indian Basin bus. Adams is currently pitching a retrofit of the generator relays for the Indian Basin plant.

Conclusion

Digital relays provide improved installation economics over discrete electromechanical or static relay systems because of their multifunction protection platforms. They improve overall system reliability through reduced installation complexity, continuous self-monitoring features, and a substation-hardened design. But the biggest advantage of digital relays is their ability to capture waveform data during system disturbances.

Jon Steinmetz is a field application engineer with SEL. You can reach him at jon_steinmetz@selinc.com. For more information, visit www.selindustrial.com or www.selinc.com.