From the Journal of Petroleum Technology

“Overall, the 10-year window shows the risk that shale faces as sweet spots are exhausted, while no new plays are being identified. … What happens when basin-specific risks emerge and you’re a pure play?”  – Wood Mac

Staying on top is tough, and the US onshore oil business is no exception. This sector, mostly in the form of the Permian Basin, has been both the lowest-cost source of added barrels of oil and the largest source of added supply.

Current pipeline bottlenecks are capping its growth, but the long-term problem is that its costs are rising as its best rock is being drilled, while alternative plays are offering profitable exploration and production options.

“In 10 years there will be significant threats to tight oil wells being the lowest-cost source of supply,” said Robert Clarke, research director for Lower 48 Upstream at consultancy Wood Mackenzie. He added that its ability to add production for less than other producers “will start to erode.”

The comment made during a presentation at the Unconventional Resources Technology Conference (URTeC) is both a pessimistic recognition of the costs that come with intensive development of the best prospects, and an indication that the offshore sector is becoming a better value.

While US onshore still holds an edge, international oil companies are finding attractive options for diversifying their portfolios, mixing onshore with offshore conventional fields, where finding and development costs are down, as is the amount of time that it takes to bring them on line.

“Overall, the 10-year window shows the risk that shale faces as sweet spots are exhausted, while no new plays are being identified,” Clarke said, adding, “Conversely in conventional, there have been some big exploration successes the past 2 years.

“Diversified portfolios mean that capital could move away from tight oil in the future if the cost curve evolves like we model it,” Clarke said. He pointed out that Chevron, ExxonMobil, and Shell “have exposure to some fantastic conventional exploration plays that could have superior economics to the Permian in a few years. That presents a risk to overall tight oil activity in the future.”

Already other shale plays are seeing spending increases as operators look for alternatives where pipelines and logistics are not as tight in the Permian, and there are a lot of offshore discoveries that were made before the oil price bust to consider.

“The industry is putting money into lowest cost assets correctly and they are growing,” Clarke said.

Consultancy Rystad Energy predicts that 100 offshore projects will be sanctioned this year, up from 60 in 2017 and 40 in 2016. Equally striking is the fact that the average budget per project is $1 billion, compared with $1.8 billion in 2013 when oil prices were still up around $100/bbl

“The offshore suppliers have created their own comeback,” says Audun Martinsen, vice president of oilfield service research at Rystad Energy. “Their constant search for cost reductions and streamlining of operations has enabled them to cut offshore project costs by almost 50% compared with the heights of the last cycle.”

While the cost of onshore US drilling and completion services have been rising for a couple of years, oversupply of offshore drilling rigs and other big-ticket items has kept prices down.

“They have also improved the efficiencies of their operations, thus shortening lead times from project sanctioning to first oil. As an example, the time required to drill and complete a well has fallen by 30% in the North Sea, the Gulf of Mexico, and Brazil over the past 4 years,” Martinsen said.

Developing projects in phases reduces the upfront cost, simplifies the projects offshore where complex mega-projects were prone to overruns. The lead time now has been reduced to five years now compared with 9 prior to the crash, according to Wood Mackenzie.

Production from these projects will also be more modest. The average project approved last year was expected to add 230 million bbl of oil reserves, half the size of fields developed before the crash, Wood Mackenzie reported.

But Clarke’s 10-year prediction comes with the caveat that 10 years in the shale business leaves a lot of time for technological change in a business that was just getting going a decade ago.

“EOG is an example of doing far more for far less,” he said, pointing to an EOG presentation showing comparable well production using less water and less proppant.

He said major producers are using predictive analytics to improve productivity and said he would like to see more collaboration among small companies to share the cost of research and development programs.

And he sees significant risks in betting on one kind of play. “The perplexing thing is that many of these companies have gone ‘all in’ and become virtual pure plays” in onshore basins, Clarke said, asking, “What happens when basin-specific risks emerge and you’re a pure play.”


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