As global oil demand remains stunted by the COVID-19 pandemic and the measures being taken to prevent its spread, producers across North America are pursuing ways to curtail output to help rebalance the market.

Many onshore producers have shut in supply at the wellhead, but offshore operators in the U.S. Gulf of Mexico might not have the same degree of flexibility.

"It's, actually, maybe just a little bit trickier," Talos Energy Inc. President and CEO Timothy Duncan said during a May 7 earnings call.

Justin Rostant, Wood Mackenzie's principal analyst for U.S. Gulf of Mexico upstream oil and gas research, said in a May 20 phone interview that while it is fairly simple to shut in wells, it is far more complicated to bring them back online.

"You can shut in with a push of a button or a few turns of a valve. It is what happens when you bring a well back online," Rostant said.

Rostant said that about 200,000 barrels of oil per day are currently shut-in in the Gulf of Mexico. Oil production in the Gulf, which hit a record high of 2 million barrels per day in February, accounts for about 16% of total U.S. oil output and 5% of natural gas production.

Offshore producers are accustomed to shutting in wells during hurricanes, but Duncan said extended shut-ins can lead to long-term problems with reservoirs.

The longer a well remains offline, the higher the potential cost and risk to return it to prior performance, Rostant said.

"Some wells may return to full capacity and some may not. Other wells that are uneconomical could be abandoned," he said.

"Offshore wells tend to be more involved and, as a result, ramping down (and up, again) an offshore installation is generally much more complex than an onshore operation," Royal Dutch Shell PLC spokeswoman Cindy Babski said in a May 18 email. "But bear in mind that no two wells and assets are the same which means that it's never going to be a like-for-like comparison."

Shell, one of the largest operators in the Gulf of Mexico, had not shut in any production from the region as of May 18, Babski said.

Duncan said that unlike onshore operators, which tend to have wells near handling facilities, offshore producers' subsea wells might flow oil 20 miles to the nearest handling facility.

"The overarching emphasis is on liquidity," Duncan said. "Are these decisions to shut in liquidity-accretive? Are they liquidity-enhancing? And ... those calculations really vary from asset to asset offshore, I would say in a more complicated way than they do onshore," he said.

Offshore operators are under no obligation to scale back operations. The Bureau of Safety and Environmental Enforcement, or BSEE, which polices the offshore drilling market, requires operators to shut in production only when inspectors deem operations unsafe, the BSEE said in a May 15 email.

However, curtailing offshore production due to market conditions is not unprecedented. Following an oil price collapse in 2014, decreasing profit margins and expectations for a lengthy oil price recovery prompted many operators to pull back on deepwater Gulf exploration spending and to restructure or delay drilling rig contracts in 2015 and 2016.

Talos has yet to encounter any required production shut-ins resulting from midstream or storage capacity constraints, Duncan said. "In recent weeks, we've initiated production shut-ins in several fields in order to either accelerate previously planned maintenance and upgrade activities or reduce production where it makes sense to do so in the near term."

Overall, production curtailments in the Gulf of Mexico will likely remain minimal in the coming months, but BSEE said operators are not required to report amounts of curtailed well production.

Independent producer Murphy Oil Corp., which operates seven producing fields in the deepwater Gulf of Mexico, disclosed it is shutting in 40,000 barrels per day of oil in May, mostly from its offshore wells. Murphy pumped 186,000 barrels of oil equivalent per day in the first quarter, including 110,000 bbl/d of oil, about half of which came from its global offshore fields.

While Hess Corp. has not yet shut in any Gulf of Mexico output, the company's average production from the region is expected to drop about 6,500 boe/d from the first quarter to the second, CEO John Hess said during the company's first-quarter earnings call. The company does not plan to drill any more wells in the Gulf of Mexico this year, he said.

Oil major Chevron Corp. has reduced output at various North American operations due to low oil prices, but production at its Gulf of Mexico-operated facilities has not been shut in, company spokeswoman Veronica Flores-Paniagua said in a May 11 email. Chevron's first-quarter output in the Gulf of Mexico averaged 200,000 bbl/d of oil, 112 MMcf/d of natural gas and 12,000 bbl/d of NGLs, she said.

Chevron CEO Mike Wirth said on the company's first-quarter earnings call that between 200,000 boe/d and 300,000 boe/d will be curtailed company-wide in May, with further reductions expected in June. However, most of the curtailments will come from onshore wells in one of the world's hottest plays — the U.S. Permian Basin.

"We are trying to avoid the need for abrupt shut-ins. So these truly are, broadly speaking, curtailments rather than shut-ins, with a very conscious effort to preserve reservoir and well integrity," Wirth said during the call.

"The technical issues, the logistics, financial issues and economic issues can vary, but broadly speaking, we've taken some complete shutdowns. In general, if you can keep production flowing, you can mitigate some of the risks of a hard shutdown or restart, which can be solved with people, money and technology," Wirth said during a May 14 interview with IHS Markit.

Like Chevron, Exxon Mobil Corp. will shut in production at its higher-producing and costlier wells in the Permian, CEO Darren Woods said during the company's May 1 earnings call.

"You're better off deferring that high production rate into a period with better pricing," Woods said. "Depending on how the market evolves, we've got the flexibility to bring a lot of those wells back on quickly."

Exxon spokeswoman Julie King confirmed that in the second quarter, Exxon expects to shut in 400,000 boe/d of production around the globe. About one-third will be in the Permian Basin, one-third will occur at the Kearl oil sands operations in Canada and the rest will be based on restrictions in various OPEC countries.