“A sow and polar bear cub are walking across the east side of the pad. All personnel are advised to stay clear of that area,” Billy announced over the radio. Just a few moments later, the radio crackled again as he advised, “Current wind chill is minus 68 degrees, so everyone working outside must follow the work restrictions provided in your Alaska Safety Handbook.”

Those are just two of the many challenges of extracting Alaskan crude oil at Nikaitchuq (ni′ kət′ chuk). Perched on the shores of the Arctic Ocean, this is a land of many challenges: extreme cold, blowing snow, treacherous slippery walking surfaces, two months of total darkness each year, all wrapped in a sensitive environment next to water, wildlife and tundra. Operations at Nikaitchuq fall under 14 state and federal regulatory/oversight agencies, so accountability for every action comes from many levels in addition to ENI’s corporate guidelines.

The Nikaitchuq Operations facility is capable of producing 40,000 Barrels of crude oil per day at the treatment facility at Oliktok Point. There is also an eleven-acre offshore drill site and a 3.1-mile subsea flow line bundle from the offshore site to the treatment facility.

This extreme environment demands maintenance optimization; when warm crude oil stops flowing through insulated pipelines, it cools to a dense sludge and refuses to budge any further, like “molasses in January.” One malfunctioning valve at the wrong time can shut the entire operation down until warmer weather allows for proper maintenance and repair.

Critical control valves play a major role in the reliability of this processing facility, and a process upset due to a failure of a critical control valve can be extremely costly to the company’s bottom line. Thus, ENI realized that, in order to maintain operation and profitability, it needed to standardize its control valve reliability program to help avoid unplanned events.

The technicians on site were very good at troubleshooting and repairing valves with known problems, but the data that was coming in from the control systems (digital valve controllers or DVC’s) was not being analyzed properly so that we could anticipate problems and initiate preventive maintenance before a valve failure was imminent. We recognized that it was not an ENI technician’s core competency, and developing or hiring a full-time control valve expert was not realistic in this remote location. So, we reached out to Emerson to monitor the data and help us understand, based on the conditions shown in that data, the health of the valves in the units and recommend maintenance or repairs.

Because of cyber security concerns, we decided upon a manual data collection process. That data was then transmitted via a secure HTTPS server to the off-site center where it was analyzed. Analytics, results and recommendations were then sent back via e-mail and, with collaboration between the off-site analysis center and on-site personnel, it was decided what maintenance steps needed to be taken.

Outages are very short at Nikaitchuq, so repair prioritization is very important, and it was challenging to choose the appropriate intervals. Before this system came into place, we had experienced 1 to 3 unplanned outages per year due to control valve break-downs. At $50 per barrel, that can mean $1.2M/day ($50K/hour) loss in production.

ZERO UNPLANNED EVENTS

In a pilot project, we monitored 25 of the most critical valves for 24 months and received various alerts on 20 of the 25 over 2 years. Those alerts varied in severity. Lower severity alerts gave us the opportunity to watch the trend over time, higher severity alerts generated ten actionable work orders. The types of issues identified included high drive signal, excessive friction, travel deviation, incorrect configuration, low friction, low supply pressure, high supply pressure, possible worn seat and controlling off-seat.

A few case studies include:

1. A valve friction PD test detected a stem friction value at 454 lb., which is over the recommended threshold range of 83 – 415. The recommendation was to continue to closely monitor at this point, and perform a valve signature baseline function test during the next shutdown opportunity. If this was not addressed, friction would likely increase to the point where it would impair the valve’s performance and eventually the valve would seize up, causing an outage.
2. A valve was constantly being controlled within 1-2% off the seat (99% to 99% closed). The recommendation from the monitoring staff was that, if this was normal operating conditions, it could cause premature wear on the seating surfaces. If not, they recommended changing the cutoff in the DVC to prevent the valve from responding too rapidly to the drive signal, or check process conditions for proper valve sizing. If this had not been addressed, the trim could have worn prematurely. This could be a result of sizing problems that might be repeated if not identified.
3. In another case, a low friction valve trend showed continuous low valve stem friction below the recommended threshold of 56-280 lb. The recommendation was to check for any visible leaks during shutdown and verify if the valve packing material is properly torqued. It was suggested that we open the valve and inspect to replace packing or any worn “soft goods”. Identifying low friction helps to avoid potential environmental issues or instrument electronics problems due to hot process gases escaping from the valve.

CONCLUSION

ENI operates in an environment that poses additional challenges to those of most oil production facilities. Unplanned downtime of critical control valves has a significant impact in the bottom line of the business, so understanding valve health and optimizing maintenance activities is a necessity. By working with a third party with expertise in analysis and prescription of control valve problems, we have been able to reduce the number of unplanned production outages, increase onstream efficiency and gain confidence in the overall “health” of our critical control valves.