Long ignored by industry, marginal oil fields are suddenly viewed as a resource worth tapping into
In the summer of 2016, Brent Janke—at the time Suncor Energy’s vice-president for its East Coast operations—had a message for the people of Newfoundland and Labrador.
The Calgary-based company, and operator of the Terra Nova offshore oil field located 350 kilometres southeast of St. John’s, was not content to see the asset stop producing in 2022 as expected. Janke said there was potential to add another 100 million barrels of oil to Terra Nova’s reserves. “There are a fair number of opportunities in the Terra Nova region,” Janke told a crowd gathered at the St. John’s Convention Centre attending the annual Newfoundland & Labrador Oil and Gas Industries Association conference. “We could have the field producing an additional 10 years. We intend to be here for some time to come.”
Suncor’s desire is not unique in the oil and gas industry. Offshore projects are costly and the time between paying off that investment and making a profit can be lengthy. That’s why oil and gas companies are always looking for ways to extend the life of their offshore assets. If they can lengthen the time an oil field is producing, the more profits they can reap.
It’s also widely accepted that the best place to look for oil and gas is in places where it has already been found. In the case of Newfoundland and Labrador, that is primarily in the Jeanne d’Arc Basin in the Grand Banks area where the Terra Nova, Hibernia, White Rose and Hebron oil fields have been discovered and developed.
In some cases this oil has already been discovered, but the sector’s players have never been able to develop it economically. These pools of oil are referred to as ‘marginal’ fields. They are small in size (generally consisting of less than 50 million barrels of oil equivalent in reserves) and aren’t of interest to companies when oil prices are high. But oil prices haven’t been high, and have been stuck in the US$50 range (and lower) since 2014. That has the industry shelving expensive projects and taking a second look at these previously ignored fields.
The topic is on the mind of NOIA, which represents 600 companies involved in the energy services side of the oil and gas business. At its 2017 conference, the agenda included a panel discussion on untapped resources and a presentation from Arild Selvig of Technip FMC on satellite tiebacks for marginal fields.
Technip FMC’s Selvig says this is a trend in many oil and gas basins where companies are shifting their attention to brownfield projects—ones based on prior work or a discovered/producing oil and gas accumulation. “With the low oil prices, operators are looking for opportunities with lower risk. Typically those are the ones where they know oil is in the ground,” Selvig says. “There will also be lower capital expenditures in the sense you tap into existing infrastructure. In this context you have marginal fields that were not economical or stranded in a high-cost environment that are now economical or will be economical with new concepts.”
There are a fair number of opportunities in the Terra Nova region. We could have the field producing an additional 10 years.
Brent Janke, Suncor’s former vice president, East Coast
Selvig is not just blowing smoke here. At his presentation in June at the NOIA conference he introduced a slide showing that capital expenditures for brownfield developments in the Norwegian Continental Shelf, which includes the North Sea, Barents Sea and Norwegian Sea, are forecast to increase by 131 per cent from 2016-2030 while greenfield developments decline four per cent during the same period.
He also says that breakeven prices for subsea projects have fallen from US$82 per barrel in 2014 to US$58 per barrel in 2017, or 30 per cent. But Selvig says these costs savings aren’t likely to stick when oil prices improve. Much of the reduction in costs has been achieved by squeezing better pricing from the businesses that provide products and services to developers as exploration and development opportunities dwindled.
But if and when oil prices recover, and activity increases, the supply chain will look to improve their margins. As a result, prices in the supply chain will increase and the 30 per cent reduction in costs will evaporate. “Most of the 30 per cent reduction is not sustainable,” Selvig says. “The challenge to the industry is to find sustainable improvements that stick in good times.”
The concept Technip FMC is floating to industry is having all the equipment to install and hookup development of marginal fields located on one vessel. Selvig says it would normally take two or three vessels to install the subsea production system, the flowlines taking oil and gas from the wellhead to production equipment and risers. “With our concept you have everything in one mobilization,” he says. “It’s all about cost. You’ve got a small footprint and everything is located and can be installed by one vessel.”
Whether Technip’s or some other solution will convince operators in Newfoundland’s offshore to consider developing marginal fields hinges on several factors. One is the Canadian regulatory system, which the federal government is reviewing right now. If changes are made that industry views too cumbersome and expensive, interest in developing small oil fields could die off quickly. Oil price is another factor. Selvig admits that if prices increase, bigger projects will be “taken off the shelf” as companies look to find and develop elephant fields like Hibernia, which produced its one billionth barrel of oil in 2016.
The enthusiasm to tap marginal oil fields could have staying power though. If cost-effective ways to develop them are found, and companies aren’t willing to leave discovered oil in the ground, they may decide the lower risks are worth the somewhat lower rewards.