Skyrocketing oil prices caused by Russia’s war on Ukraine and Biden’s war on hydrocarbons present the Gulf of Mexico E&P industry with a conflicting brew of circumstances.
While the demand for oil becomes even more critical, U.S. operations in the Gulf are stymied by outrageous fortune. A successful Gulf lease sale was summarily cancelled. Court and regulatory maneuverings have further stalled lease sales and, at the moment, halted the processing of drilling permits for federal waters.
For the deepwater Gulf, these slings and arrows imperil future production more than today’s immediate needs. In a region where hugely complex and expensive projects can take decades, the repercussions will come tomorrow.
THE FRONT LINE
Drilling permits and leasing on federal lands and waters were blocked in February after a federal judge in Louisiana found in favor of Republican attorney generals from oil states.
At issue is the “cost estimate of carbon emissions,” an economic model aimed at determining the social impact of climate change. The Biden administration raised it from $7/ton to $51/ton of carbon dioxide. The judge said the increase would artificially increase the cost estimate of leases and harm energy producing states.
Louisiana Attorney General Jeff Landry called it a win and said the Biden order “was an attempt by the government to take over and tax the people, based on winners and losers chosen by the government.” But the more immediate and contrary result was that the federal government used the ruling to stop work on new leases and drilling permits.
“Work surrounding public-facing rules, grants, leases, permits and other projects has been delayed or stopped altogether so that agencies can assess whether and how they can proceed,” said the Department of Justice. “The consequences of the injunction are dramatic,” said the administration. The White House’s Office of Information and Regulatory Affairs said dozens of actions at the departments of Energy, Transportation and the Interior, as well as the Environmental Protection Agency (EPA) will be “postponed or reworked.”
But on April 15, the Interior Department quietly announced plans to hold its first onshore oil and gas lease sales since Biden took office. DOI is opening just 144,000 acres for lease and will charge operators higher royalties to drill on federal lands, raising them for the first time. Royalty rates will increase to 18.75% from 12.5%. So far, no news on plans for the Gulf.
Lease sales in the Gulf and elsewhere had already been challenged and set aside. On Jan. 27, 2021, President Biden issued Executive Order 14008, titled “Tackling the Climate Crisis at Home and Abroad.” It required a “pause” in new oil and natural gas leases on public lands or in offshore waters, pending completion of a comprehensive review and reconsideration of Federal oil and gas permitting and leasing practices.”
The order resulted in a series of actions using environmental legislation and processes to delay, confound and stop U.S. oil and gas development across the board. Arctic National Wildlife Reserve (ANWR) leases were issued, then paused and ultimately suspended. Next door in the National Petroleum Reserve, operations were delayed by a new review of an environmental statement published last year. The planned Cook Inlet OCS Oil & Gas Lease Sale 258 off Alaska’s south-central coast was sidelined on Feb. 2.
Gulf of Mexico leasing was hit Feb. 12, 2021, when BOEM rescinded the Record of Decision for Lease Sale 257. Planned for March 2022, it was the eighth sale under the 2017-2022 National Oil and Gas Leasing Program. But the game was on again in September, when a U.S. District Court compelled BOEM to hold the auction while conducting its “comprehensive review of the deficiencies associated with its offshore and onshore oil and gas leasing program.”
And so, on Nov. 17, 2021, Lease Sale 257 was held. Thirty-three companies participated, submitting $191,688,984 in total bids for 308 tracts covering 1.7 million acres in the Western, Central and Eastern Planning Areas. Highest bids came from Anadarko (Occidental) for Alaminos Canyon ($10,001,252) and Green Canyon 551 ($6,001,252). It was followed by Chevron for Mississippi Canyon 40 ($4,409,990) and Walker Ridge 842 ($4,341, 006). Other successful bidders included Shell, BHP Billiton and LLOG exploration.
But, like ANWR, it didn’t last long. The deal made it to Jan. 27, 2022, when a federal judge annulled the sale, claiming it did not sufficiently take climate change into account.
BY THE NUMBERS
GOM production took a dip in 2020 and 2021. But there is basis for improvement this year. In deepwater operations, which account for the lion’s share of GOM production, a dozen or more recent discoveries are lined up: Murphy’s new fields are due to come online; and some big startups are planned, including BP’s Mad Dog Phase 2 and Shell’s Vito. Deeper, high-pressure prospects will open up over the next couple of years, as two high-capacity drillships go to work for BOE’s Shenandoah and Chevron’s Anchor projects.
At the start of 2022, leading Gulf operators, ranked by volume of production, were Anadarko Petroleum (Occidental) Shell Offshore, QuarterNorth Energy, GOM Shelf, Renaissance Offshore, Monforte Exploration, EnVen Energy Ventures, Ankor Energy, and Samchully Energy and Environment, Table 1.
Total oil and gas production from the U.S. Outer Continental Shelf (OCS) dropped in 2020. Most of that decline occurred in the GOM region, by far the dominant producer versus the Alaska and Pacific regions.
For the first time since 2013, total OCS oil production fell by 91,311,659 bbl for a total 606,377,776 bbl. There wasn’t much help in 2021, with BSEE figures for the first 11 months totaling 572,454,932 bbl, Table 2.
In the Gulf, oil production in 2020 was 601,351,182 bbl, down from 692,760,802 bbl in 2019. It was the first decline since 2014. In 2021, January to November, the production tally was still low at 568,280,596 bbl.
Total OCS gas production dropped to 809,482,112 Mcf, down from 1,040,044,903 Mcf in 2019. In the Gulf, gas fell from 1,034,420,387 Mcf in 2019 to 804,537,475 Mcf in 2020. In 2021, January to November, production was not much improved at 735,705,076 Mcf.
Deepwater production continued to dominate the GOM as a percentage of total
output. In 2020, that portion gained, with oil at about 93% of the regional total and gas at about 73%; in 2019 the figures were 91% and 70%, respectively, Fig. 1.
But in terms of total deepwater production, 2020 output dropped to 557,809,297 bbl, compared to 629,665,171 bbl in the year prior, and 575,767,623 bbl in 2018. The total for deepwater gas in 2020 was 589,255,880 Mcf, down from 721,301,118 Mcf in 2019.
Rig activity in the Gulf has been relatively steady over the last year at roughly 14 rigs. On March 25, 2022, there were 14 rotaries working, up 2 rigs from the same period in 2021, according to Baker Hughes. There were 20 rigs working in March 2020.
Well permits marked a two-year decline in 2021, with 148 shallow-well permits and 633 permits for deepwater wells. The 781 total permits are down 20 from the 2020 yearly total and minus 238 from 2019’s figure. As of February 2022, BSEE had approved 64 permits—12 shallow-water and 52 deepwater permits, Table 3.
BSEE breaks out permits in six categories—new well, revised new well, bypass, retrieved bypass, sidetrack and revised sidetrack. The number of permits for each type varies year to year with project demand. For 2021 shallow permits, the biggest category was revised sidetracks, with 53 permits; in 2020, there were 23. The deepwater permits were more consistent, with the revised new well category accounting for 417 approvals in 2021, compared to 410 in 2020.
The two ultra-deepwater drillships that Transocean has been building for Gulf operators are due on location in 2022 and 2023. Their arrival will open up new high-pressure prospects, with the first drillship use of 20,000-psi BOP technology and 3-million-pound hookload capacity.
Transocean’s Deepwater Titan and Deepwater Atlas are built in Singapore by Semcorp Marine’s Jurong Shipyard. The advanced vessels were started in 2014 and have faced Covid-related delays. Nevertheless, they appear to be headed toward a GOM arrival this year and next. Deepwater Atlas will work for BOE Exploration and Production during second-half 2022; Deepwater Titan is scheduled to be onsite for Chevron U.S.A. in first-quarter 2023.
Anchor. Chevron needs the Deepwater Titan’s high-pressure BOP and massive hookload for its Anchor project in the Green Canyon area. Anchor’s first phase calls for a seven-well subsea development and semisubmersible floating production platform. The planned facility has a design capacity of 75,000 bopd and 28 MMcfgd. Total recoverable oil-equivalent resources may exceed 440 MMbbl.
Chevron discovered the Anchor find in 2015, when its Well 2 in Green Canyon Block 807 found oil in multiple zones of the Lower Tertiary Wilcox sands. The well is in about 5,000 ft of water and was drilled to 33,749 ft, MD. The project was sanctioned in 2019 and is expected to cost $5.7 billion, Fig. 2.
Arrival of the Deepwater Titan will start a development process expected to see first oil in 2024. Recoverable assets are estimated to exceed 440 MMbbl.
Shenandoah. BOE Exploration will use the Deepwater Atlas in drilling and completion of its Shenandoah project. Each phase should last a little less than a year. Transocean says the drillship will use dual 15,000-psi BOPs for the drilling program and switch over to the 20,000-psi BOP for the well completion phase.
The Shenandoah discovery well was drilled in 2009 by Anadarko Petroleum on Walker Ridge Block 52. It is in 5,750 ft of water. The 30,000-ft, TD, well found about 300 ft of oil pay in the Lower Tertiary Wilcox sands, and appraisal wells were drilled. In August 2021, a group comprised of BOE (operator), Navitas Petroleum and HEQ Deepwater awarded Transocean the Deepwater Atlas contract to develop Shenandoah. The subsea development will produce through a production platform.
A Navitas timeline shows completion of subsea facilities in early 2023 and subsea pipelines in early 2024, with first oil expected in June 2024. The project was originally planned on a regional hub model similar to the DeltaHouse and Who-Dat fields.
Mad Dog 2. The Argos floating production platform for Mad Dog 2 arrived at the Ingleside, Texas, Kiewit Offshore Services fabrication yard in April 2021. BP (operator) plans start-up for second-quarter 2022, Fig. 3.
The platform was built by Samsung Heavy Industries in South Korea and transported by the BOKA Vanguard. It is expected to support about 800 jobs in Ingleside and about 250 jobs once in operation, says BP. After final work and inspections at Kiewit, the 60,000-ton platform will be towed to location, about 6 mi from the original Mad Dog spar, about 190 mi south of New Orleans, where it will operate in 4,500 ft of water,
Mad Dog 2 is the southwest extension of Mad Dog field and may have recoverable oil-equivalent resources exceeding 500 MMbbl. BP has a 60.5% interest, along with co-owners BHP (23.9%) and Union Oil Company of California, an affiliate of Chevron Corp. (15.6%).
Vito. Fabrication of Shell’s Vito floating production unit was completed in December 2021 by Sembcorp Marine. It will be transported to the Gulf, where production is scheduled for this year, Fig. 4.
Vito is a Miocene development discovered in 2009. It is laid out on four Mississippi Canyon lease blocks under 4,000 ft of water. It features eight subsea wells and a deep (18,000 ft) in-well gas lift. Peak production is expected to be in excess of 900,000 boed. The development is owned by Shell Offshore Inc. (63.11%, operator) and Equinor (36.89%).
Whale. Shell also has started construction of an FPU for its Whale project. Sembcorp is also the shipbuilder, and Shell says the design is a 99% replicated hull and an 80% replication of the topsides from its Vito project. The FID for the project was announced in July 2021 after a year-long Covid delay. Production is scheduled in 2024.
The Whale production facility is in Alaminos Canyon Block 773, next to the Shell-operated Silvertip field, and approximately 10 mi from the Shell-operated Perdido platform. The development, in more than 8,600 ft of water, features a semi-submersible production host with 15 oil wells.
Whale is owned by Shell Offshore Inc. (60%, operator) and Chevron U.S.A. Inc. (40%). Peak production is estimated at 100,000 boed, and the asset has an estimated recovery of 490 MMboe.
St Malo. Ongoing work on the St. Malo field waterflood is aimed at first injection in 2023. The Chevron-operated field in Walker Ridge will get two new production wells, three injectors and topsides water injection equipment. It will be Chevron’s first waterflood project in the Wilcox trend.
Chevron holds a 51% working interest in St. Malo field, along with co-owners MP Gulf of Mexico, LLC (25%), Equinor Gulf of Mexico LLC (21.5%), Exxon Mobil Corporation (1.25%) and Eni Petroleum US LLC (1.25%).
Ballymore. A subsea tie-back for Chevron’s Ballymore field was announced in mid-April 2021 by Worley, which will provide engineering and procurement services to support subsea and topsides systems. The field is in Mississippi Canyon Block 607, in about 6,581 ft of water. Chevron is the operator (60%) with TOTAL E&P USA Inc. (40%) as co-owner.
Khaleesi-Mormont and Samurai. King’s Quay FPS is scheduled to go into service in mid-2022, in Khaleesi/Mormont and Samurai fields, says operator Murphy Oil. In March, the company said its well completion program was underway, and final pre-commissioning activities were ongoing to receive first oil during second-quarter 2022. The FPS is designed to process 80,000 bopd and 100 MMcfgd.
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