As production in the Permian Basin drives growth for Chevron Corp., a trio of other shale and tight assets, Tengiz expansion projects in Kazakhstan and subsea tieback opportunities in the Gulf of Mexico (GoM) are also primed to help push the company toward its goals.

The U.S. major said March 5 it expects to deliver 3% to 4% annual global production growth through 2023.  About 1.5 million barrels of oil equivalent per day (MMboe/d) in new production is anticipated, driven mainly by lower risk, short-cycle assets.

“The biggest source of new production is expected to come from the Permian,” Jay Johnson, executive vice president, upstream, for Chevron, told analysts.

Chevron aims to boost its Permian shale production to 900,000 barrels per day (bbl/d) by year-end 2023. The company’s production in the Permian jumped 84% to about 377,000 bbl/d by year-end 2018, compared to a year earlier.

The company isn’t alone in its quest.

Exxon Mobil Corp. announced revisions to its Permian Basin growth plans, aiming to ramp up production by nearly 80% to more than 1 MMboe/d by 2024. The news was delivered by Exxon Mobil on March 5 as Chevron executives shared its plans during the company’s annual Security Analyst Meeting. Exxon Mobil will have its annual day with analysts March 6.

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“A growing source of new production is the other shale and tight assets, including Vaca Muerta, Duvernay and Appalachia. Later in the period, we expect contributions from major capital projects that are already in execution such as FGP [Future Growth Project at Tengiz],” Johnson said. “Our new production over the next five years is not dependent on sanctioning new major capital projects. By the end of 2023, these sources should contribute around 1 ½ million barrels of new production each day.”

Production growth plans comes as energy companies continue working to meet rising global demand. They are also aiming to do so while also keeping spending in check, taking advantage of technology offerings and other methods to drive efficiency and returning more cash to shareholders.

Other Shales: Chevron is developing emerging shale and tight assets in Argentina’s Loma Campana in the southern Vaca Muerta shale, Canada’s Duvernay and Appalachia’s Marcellus. Cost and production improvements are already yielding “attractive returns” as the company steps up its drilling program in Argentina, having added about 162,000 net acres in the Vaca Muerta.

“We have an eight-well pilot in the El Trapial area and another four-well pilot in the adjacent Narambuena area scheduled for this year,” Johnson said. “We believe these three areas could offer an incremental 2 billion barrels of resource.”

He added the company is also generating value, particularly from condensate to local markets, in the Duvernay, while low development costs and improved infrastructure are strengthening realizations and making returns competitive for gas in the Marcellus and Utica shale plays.

Tengiz Field Expansion: Work at the Tengiz Field, where the integrated Future Growth Project (FGP) and the Wellhead Pressure Management Project (WPMP) are underway to increase production, progresses toward first oil in 2022 for Tengizchevroil. As explained by Chevron, WPMP provides “facilities that allow new and existing wells to flow even at lower reservoir pressures,” while the FGP aims to “enhance recovery and increase production to approximately 1 million barrels of oil equivalent per day.”

The five-phase FGP-WPMP is expected to hit the peak of logistics activity this year. Chevron reported that the engineering phase is 90% complete and the offsite module fabrication phase is 65% complete. “In South Korea we are building a total of 91 process processing utility modules. In Italy we are building five gas turbine generators and in Kazakhstan we are building 75 pipe rack modules,” Chevron said. The project also includes an offloading facility adjacent to the field in the Caspian Sea.

Twenty-five wells for the drilling phase have also been drilled and completed.

Gulf of Mexico: In the GoM, focus remains on improving returns, including by lowering unit operating and development costs by deploying standardized equipment and using fit-for-purpose surface facilities.

Operating costs have been cut in half to less than $10 per barrel, compared to 2014, Johnson said, adding the company is targeting $16-$20 unit development costs for newer fields such as Anchor, Ballymore and Whale. That would be a third lower than the company’s last set of greenfield deepwater investments, he said.

The company is also looking to capitalize on subsea tieback opportunities, given Johnson said about 60% of Chevron’s exploration blocks are within tieback range. Plus, recently certified multiphase subsea pumps, which will be tested later this year at the deepwater Jack-St. Malo Field, are capable of increasing recovery and extending the lengths of tiebacks.

Rather than homeruns, or big greenfield projects, “there’s going to be a lot of singles and doubles with tiebacks into facilities,” which are highly economic as well, Chevron CEO Mike Wirth said.

Technology: Wirth also pointed out at that the company is “aggressively expanding the application of digital technologies and working to broaden their impact across our company. We’re using digital to change the way we work and to strengthen a culture of innovation and agility.”

Earlier, Barclays analyst Paul Cheng asked about how digitalization will improve operations, looking for specific examples.

“We have the ability now to actually run decline curve analysis, not only on our own wells but on every well in the basin, every month and this is done through artificial intelligence,” Johnson responded. “It gives us tremendous insight into how the basin is working, where the most prolific areas [are]. … It’s just across the board.”

He admits it is still early in process, but he believes digital efforts will pay off in terms of driving efficiency.

“I think it’s going to revolutionize the upstream business,” Johnson said.

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