Chevron is shifting its spending focus to “short-cycle, higher return activity that utilizes existing infrastructure” as major projects are completed and market conditions force tighter spending.

The move bodes well for the Permian, where Chevron holds about 2 million net acres and resources of about 9 billion barrels of oil equivalent, and adds promise for potential profit-yielding international shale plays such as the Duvernay and Vaca Muerta.

“By the middle of the next decade you could see 20-25% of our production in short-cycle shale and tight activity,” Chevron CEO John Watson said on call March 8.

But the San Ramon, Calif.-based company is not losing sight of the bigger picture, having recently begun LNG production at Gorgon and progressing at Wheatstone LNG in Australia with eight of nine wells complete. It also has plans to take a final investment decision (FID) on the Tengiz expansion project in Kazakhstan by mid-year.

The annual update was delivered as oil and gas companies continue to cope with lower commodity prices that have cut into profit.

A day after oil prices surged above $40 per barrel (/bbl) only to fall again, Chevron said that it will cut its capital budget by up to 36% in 2017 and 2018. Plans, which were unveiled during Chevron’s security analyst meeting, are to dole out between $17 billion and $22 billion annually in 2017 and 2018. Chevron said it will spend about $26.6 billion this year, while growing production.

Base and short-cycle spending accounted for 40% of Chevron’s capital program in 2015. That will grow to 45% this year, 60% in 2017 and 65% in 2018 as the company focuses on more shale, tight oil and brownfield opportunities.

Permian Power

In the Permian, “our transition to horizontal factory mode is fully operational, utilizing four-well pads and increasing lateral lengths,” said Jay Johnson, executive vice president, upstream, for Chevron. Performance appears to have paid off over the last year:

  • Horizontal well costs fell by 40%;
  • Drilling footage per day jumped by 45%;
  • Reduced drilling days per well by 50% in the Bradford Ranch horizontal program in the Midland Basin; and
  • Frac stages per day increased by 115%.

Production in the Permian grew 33% from 2014 to 2015 with around 100,000 barrels per day (bbl/d) of potential upside by 2020. “In 2016, nine horizontal development programs are planned with around seven operated and nine non-operated rigs. We expect to drill around 175 wells this year,” Johnson said.

Chevron, Permian, shale, tight oil, production

Chevron said it has 1,300 operated well locations in the Permian that offer a 10% return at $40 WTI or less; 4,000 wells at $50 or less and 5,500 at $60 or less. The calculations were based on only a third of its Permian Basin portfolio.

Learnings from the Permian will be leveraged in other shale plays where Chevron operates.

The appraisal program is advancing in the Duvernay, Johnson said, where unit development costs have fallen by 35%.

Meanwhile, the Vaca Muerta development has moved into “horizontal factory mode” and well costs have been reduced by 20% since late 2014, he added. “Initial 30-day peak production rates are encouraging with some recent wells achieving rates of around 800 barrels of oil per day. The combination of lower costs and increased well recoveries has reduced unit development costs by around 30%.”

Base Buildup

Compared to greenfield projects, investments in base projects are typically less risky, have shorter cycle times and leverage existing infrastructure, Johnson said.

Chevron’s well factory operations are “legacy assets where there is a large queue of similar opportunities that lend themselves to factory mode development,” Johnson added, noting these include the Gulf of Thailand, California’s San Joaquin Valley and Indonesia. “An attractive queue of brownfield opportunities also exists in the deep water.”

In the deepwater Gulf of Mexico, about 80% of Chevron’s capital investment over the next two years is for brownfield developments, including Tahiti and Jack/St. Malo.

The break-even economics for each well is usually between $20 and $40 Brent, Johnson said. Helping to offset declines across Chevron’s base business, he added, are infill drilling and debottlenecking facilities.

However, there are some longer-cycle projects that will be needed to meet demand, Watson added before noting Chevron’s deepwater and international production successes and works in progress.

Chevron called the Tengiz future growth (FGP) and wellhead pressure management project (WPMP) in Kazakhstan a major brownfield opportunity. As reservoir pressures decline at the plant, Chevron said WPMP would provide additional wells and pressure boosting facilities to maintain existing production, while FGP would add production and injection trains to increase production by 250,000 to 300,000 bbl/d.

A final investment decision is expected in mid-2016, following alignment on costs and project financing, Johnson said.

Loaded Queue

Industrywide, low commodity prices among other factors have led to delayed FIDs and stalled projects. Oil and gas producers have hit the brakes on 68 upstream projects, mostly in deep water, with a combined capex of $380 billion, leaving billions of barrels of hydrocarbons in the ground, the energy consultancy Wood Mackenzie reported in January.

Most of the stalled projects are high-cost deepwater ones.

Chevron is moving forward, however, with several major projects. Besides Gorgon, which recently started LNG and condensate production with first cargo expected this month, Wheatstone LNG is on track to startup this year as well as several other major projects.

First production is expected in second-half 2016 for Alder in the Gulf of Mexico (GoM); Mafumeira Sul, offshore Angola and Bangka, offshore Indonesia. In addition, second-quarter 2016 could bring the first LNG cargo at Angola LNG as well as trains 2 and 3 at Chuandongbei in China.

Additional opportunities for growth across the globe exist. They include conventional E&A wells, such as those in Australia, Kurdistan, Suriname, Nigeria, the Republic of Congo and the GoM, as well as shale and tight oil in basins across the Americas. Focus will be greater on the latter.

“There will be selective long-cycle projects, but I think we will be turning to a more traditional ratio,” Watson said. “If anything, there is potential to the upside with the shale and tight oil opportunity that might not have been envisioned eight or 10 years ago.”

Velda Addison can be reached at vaddison@hartenergy.com.