The shrinking of the OCS oil and gas program continues. In an attempt to placate opponents of the Willow project, the President has removed the entire Beaufort Sea from oil and gas leasing consideration. Unsurprisingly, the opponents of Willow are no less irate.
Under the authority granted to me in section 12(a) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1341(a), I hereby withdraw from disposition by oil or gas leasing for a time period without specific expiration the areas designated by the Bureau of Ocean Energy Management as the Beaufort Planning Area of the Outer Continental Shelf that have not previously been withdrawn.
The 5 Hilcorp leases identified above (Northstar and Liberty projects) are all that remains of the once promising Beaufort Sea planning area.The Kulluk, pictured above, was a unique conical shaped and ice strengthened drilling vessel that operated in the US and Canadian Beaufort from 1983-1993.BP’s Mukluk well being drilled from an artificial island in the US Beaufort Sea in 1983. The $120 million exploratory well was the most expensive in history, but did not find commercial quantities of hydrocarbons.
Senator Manchin and the Alaska delegation criticized the DOI decision memo for Sale 258. The memo implied that the highest allowable royalty rate was chosen to minimize bidder interest and limit future production. Unfortunately, the “Inflation Reduction Act,” which mandated these lease sales, was not particularly helpful in creating interest in the less attractive OCS tracts like those in the Cook Inlet and the shallower waters of the Gulf of Mexico.
Sec. 50261 of the IRA raised the minimum allowable royalty rate from 12 1/2% to 16 2/3%, while capping the maximum rate at 18 3/4%. This provision favors deepwater operators, typically majors and large independents, whose royalty rates were capped at 18 3/4%, the same rate as for previous OCS sales.
Conversely, the IRA royalty provisions penalize the smaller companies and gleaners who are critical to sustaining shallow water (shelf) operations, including environmentally favorable nonassociated (gas-well) natural gas production, by raising the minimum royalty rate to 16 2/3%. DOI exacerbated IRA’s impact by electing to charge the highest allowable royalty rate for Cook Inlet and GoM shelf leases. The net result was a 50% royalty rate increase from prior sales (12.5 to 18.75%).
The table below illustrates the royalty rate implications of the IRA language and the DOI decisions.
Area
Sale
Date
% royalty: <200m water depth
% royalty: >200m water depth
Cook Inlet
244
6/21/2017
12.5
12.5
GoM
256
11/18/2020
12.5
18.75
GoM
257
11/17/2021
12.5
18.75
Cook Inlet
258
12/30/2022
18.75
18.75
GoM
259
3/29/2023
18.75
18.75
Notes:
The base primary term for GoM shelf leases is only 5 years vs. 10 years for leases in .>800 m of water.
In lease year 8 and beyond the rental rates are nearly double for shelf leases vs. deepwater leases ($40/ac vs. $22/ac).
While deepwater development typically requires more time, the higher rental penalty for delayed shelf production (which must be approved by BSEE) is not warranted. $40/acre or $240,000 per year (plus inspection and permitting fees) is a high cost for a marginal shelf lease.
Cook Inlet Sale 244 drew 14 high bids totaling more than $3 million. Sale 258 drew only 1 bid of $64,000. While many factors influence lease sale participation, the 50% increase in royalty rate certainly made the Cook Inlet leases less attractive.
Other than the increased royalty rate, the terms for both Cook Inlet sales were essentially the same. The primary lease term was 10 years and the minimum bonus bid was $25/hectare for both sales. The rental rate was increased by only $3/hectare ($13 to $16).
The only current Alaskan OCS production is from Northstar, a joint State-Federal Unit in the Beaufort Sea. The production island is in State waters, but 7 of the wells produce from the Federal sector. The field was originally developed by bp, but Hilcorp is the current operator. To date, BSEE has conducted 5 inspections of the facility in 2022, and no incidents of noncompliance (INCs) were identified.
Per BOEM records, 4 companies operate Pacific (California) OCS facilities that are currently producing. Three of those operators have superior 2022 inspection records. No INCs were issued to either Exxon (11 Santa Ynez Unit inspections) or Freeport-McMoRan (24 Platform Irene inspections). Only 2 warning INCs were issued during 12 inspections of Beta Operating Co. platforms Ellen, Elly, and Eureka in the Beta Unit offshore Long Beach.
Number of regions in which lease sales will be proposed: BOE thinks 2, the Gulf of Mexico and Alaska. There is no chance of >2. A GoM only proposed program is possible, but we doubt that Alaska will be eliminated at this early stage.
Number of lease sales proposed: BOE guesses a total of 7 sales, 5 in the GoM and 2 in Alaska. The “under” is probably a better bet than the “over,” unless they eschew area-wide GoM sales and propose an increased number of more targeted sales.
For comparison, the previous six 5-Year Programs have included 10-12 GoM sales (11.3 average), 1-8 Alaska sales (4.3 ave.), 0-1 Atlantic sales (0.3 ave.), and no Pacific sales.
In March, a gas release incident occurred while drilling a disposal well in the Alpine field on the North Slope of Alaska. While there were no injuries or environmental impacts, the investigation and findings will help minimize well construction risks during future operations. The report is attached.
Some comments:
I like the way the report, related information, and all situation reports were posted in a timely manner on the Alaska Oil and Gas Conservation Commission (AOGCC) homepage. It’s refreshing that the AOGCC homepage is 100% substantive and completely devoid of the spin and propaganda you find on most government and corporate websites. (For comparison purposes, check out the Department of Energy and Department of the Interior homepages.)
The ConocoPhillips (CP) incident report is concise, logically organized, and clearly written.
The findings are consistent with the data, and the supporting figures are legible and understandable.
Instead of blaming the crew or using the “human error” cop out for the leak-off test execution and subsequent monitoring issues, the report rightfully attributes those failures to company procedures and communications. This reflects well on CP’s understanding of the human and organizational factors that contribute to safety performance, and CP/AOGCC efforts to foster a strong safety culture. (Remember the shameful prosecution of well site leaders Bob Kaluza and Don Vidrine following the Macondo blowout.)
Conoco Phillips will try injecting carbon dioxide into the hydrate. Laboratory tests show that injecting carbon dioxide displaces methane, which comes out of the hydrate as a gas. The idea is that the carbon dioxide molecules take the place of the methane molecules in the hydrate, keeping it stable.
This could be neat, if it works. Carbon dioxide would be permanently sequestered, or stored, underground, while the methane is extracted and the hydrate is left intact.
One question the Conoco Phillips production test will attempt to answer is whether this reaction in the hydrate can occur fast enough for methane production to reach practical volumes.
The comment below is an understatement, but the enormous energy potential justifies the research.
This isn’t a slam dunk, though. The technical challenges are considerable.
The federal Environmental Appeals Board, which is part of the EPA, reviewed the permits. It found last week that the analysis of the impact of nitrogen dioxide emissions from the ships on Alaska Native communities was too limited, and remanded the permits so that problems cited by the board could be fixed by the agency.
The closest proposed drill site is 60 miles off shore and about 80 miles from Wainwright, an Inupiat Eskimo village 710 miles northwest of Anchorage.
Shell’s submission to the BOEMRE provides more details on discharge plans for their Beaufort Sea exploratory drilling, and confirms that all muds and cuttings generated in drilling below the 20″ casing will be transported out of the Beaufort for disposal. Shell also plans to transport gray water and sanitary wastes, bilge, and ballast water to approved discharge sites. This is about as close as you can get to true “zero discharge” when conducting exploratory drilling from a floating drilling unit.
Shell has agreed to transport its used drilling fluids from Beaufort Sea exploration drilling out of the Arctic if the company finally gets government permission to drill a well next summer. Alaska Journal of Commerce
I assume this includes all drilling fluids and drilled solids (cuttings) except for the spud mud and cuttings generated prior to installing the riser? If so, I believe this will be a first for an exploratory well drilled from a floating rig in US offshore waters.
Bud's Offshore Energy (BOE) 