Chevron announced first oil from its Anchor project in the Gulf of Mexico on Aug. 12. It was the first production from any of the region’s super high-pressure formations at 20,000 lb psi. Heralded as a breakthrough, the company announced that its new technology would release 2 Bbbl of GoM oil that had been unreachable with older technology.
How will that 2 billion in production happen? How long before 20,000 psi production ramps up, and what will it look like in 2030? It’s likely that other related technologies will play a part, as BP and others are also working to reach those plays. Chevron and Wood Mackenzie provide some insight into how this may play out.
Chevron’s ideas
Anchor is a joint project between operator Chevron (62.86%) and TotalEnergies (37.14%), located in the Green Canyon area about 140 miles off the Louisiana Coast. Chevron reports that the Anchor semi-submersible floating production unit (FPU)’s design capacity is 75,000 gross bbl/d of oil and 28 million gross cu ft/d of natural gas. The overall development will include seven subsea wells.
Estimated total recoverable resources from the field may be as much as 440 MMboe. Once production ramps up, Chevron expects Anchor to produce more than 75,000 boe/d for 30 years. And because the Anchor FPU is all-electric, Chevron says its production will be among the lowest-carbon intense in the world.
Anchor is Chevron’s sixth operated GoM facility. The company expects its total production in the region, operated and non-operated, to reach 300,000 boe/d by 2026. Chevron is among the largest GoM leaseholders, with 393 leases as of the second quarter, having added almost 100 leases in lease sales 259 and 261.
Engulfed in change
WoodMac is tracking several other 20,000 boe/d projects underway in Paleogene formations. They include:
Blackstone Energy Partners’ Beacon: The Shenandoah project was first sanctioned in 2021. In 2026, Beacon expects first oil from Monument to tie into Shenandoah. Both are about 160 miles off the Louisiana coast.
Shell Offshore’s Sparta: Sparta was sanctioned in December 2023 and is expecting first oil in 2028. A Shell release says it (51% operator) and Equinor Gulf of Mexico (49%) expect Sparta to reach peak production of about 90,000 boe/d at some point. Estimated discoverable resources are 244 MMboe. It will be Shell’s 15th deepwater host in the GoM.
BP’s Kaskida: The project expects first oil in 2029. Wood Mackenzie looks for BP to sanction Tiber in 2025, with first oil in 2030. Wood Mackenzie looks for BP to start drilling Tiber two to three years before first production. BP is 100% owner of both blocks.
Kaskida is in the Keathley Canyon block 292, 250 miles southeast of New Orleans. BP estimates recoverable resources at around 275 MMbbl of oil equivalent from the initial phase. Additional wells could be drilled in future phases.
Tiber is also in Keathley Canyon, in block 102, 250 miles southeast of Houston and 300 miles southwest of New Orleans. BP has yet to estimate this field’s total recoverable resources.
Economics and technology
The amount of economically recoverable resources in any area depends on technology and pricing. Technology is usually steady in its advance, but prices may vary widely depending on geopolitics, economic health of various countries and other unforeseen factors, like the COVID pandemic.
For Wood Mackenzie, the 2 Bbbl is based on current technology, but the impetus for further improvement is based on rising expenses as much as market prices for oil. Rising daily rig rates will push companies to focus their advances in drilling and completions technology on improving efficiencies to reduce operational costs, the analysts said.
Operators in Paleogene GoM projects have been economizing by using multi-zone completions, artificial lift and waterflooding, much as is done on land, WoodMac said, and Anchor is among those designed with future waterflooding in mind.
Average breakeven prices for the fields—Shenandoah, Monument, Tiber, Kaskida and Sparta—is estimated at about $37/bbl, said Wood Mackenzie. A significant price drop could endanger new projects, but those that are already in progress would likely continue.
Most development is likely to be infrastructure-led exploration to take advantage of existing pipelines. But, Wood Mackenzie noted, improved imaging could uncover future high-impact prospects in what it called “more frontier areas” of the Paleogene play.
Based on already-discovered fields of this size and those which Wood Mackenzie expects to reach that level, production could reach 130,000 boe/d in 2025 and more than double to 300,000 boe/d by 2030.
Court ruling could muddy the waters
In August, a federal judge in Maryland ruled that a key 2020 National Marine Fisheries Service (NMFS) environmental review of Gulf of Mexico oil and gas operations, known as a biological opinion or BiOp, violated the Endangered Species Act. Saying that the NMFS “underestimated the risk and harms of oil spills to protected species,” it vacated that BiOp, effective Dec 20.
Without intervention from a higher court or Congress, Wood MacKenzie Senior Research Analyst Miles Sasser said, “Once the ruling goes into effect, operators must decide whether to proceed with exploration and development activity in the GoM at their own risk or suspend operations until a new review is issued.”
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The previous ruling had provided E&Ps with a framework for operating under leases and permits that had been issued. As long as they abided by that BiOp, operators were free to move forward without risk of fines or sanctions for incidental harm to endangered species under the Endangered Species Act.
Further, the BiOp serves as a blanket review of activity, streamlining the permitting process and lessening the burden on government agencies, Sasser explained
Lacking an active BiOp, he said that regulators would need to evaluate each permit on a case-by-case basis that could create a massive backlog, effectively shutting down the permitting process.
While all Gulf operators should keep their eyes glued to the case’s progress, Sasser sees “companies with large pre-production projects or phased developments as the most at risk given the high up-front capital that has already been invested—certainly 20K falls into this bucket.”
As concerning as this is, Sasser believes there are several possible off ramps as the December date approaches. Most likely, “a stay by an appeals court allowing permitting to continue while the legal challenges play out. The revised BiOp from NMFS is already in the works and expected early in 2025, but it is likely that a new BiOp will face its own legal challenges.”