Feeds:
Posts
Comments

Archive for the ‘Regulation’ Category

RIP John Fitzgerald

Posted in Canada, Offshore Energy - General, Regulation, tagged , , , , , on August 1, 2022| Leave a Comment »

The offshore world lost an important figure over the weekend with the passing of John Gregory Fitzgerald. As Chairman and CEO of the Canada Newfoundland Offshore Petroleum Board in the late 1990’s, John presided over the first production from the massive Hibernia field. He also approved the pioneering Terra Nova project, the first FPSO development in a harsh, iceberg laden environment.

John worked closely with his international counterparts and hosted an important offshore safety meeting in St. John’s in 1996. It was an honor to be associated with such an outstanding individual and dedicated safety leader.

RIP John, your contributions will not be forgotten.

Read Full Post »

More on the Manchin-Schumer bill

Posted in climate, energy policy, Gulf of Mexico, Offshore Energy - General, Offshore Wind, Regulation, tagged , , , , , on July 29, 2022| Leave a Comment »

Here is a link to the entire bill. Good weekend reading for energy policy nerds. 😀

The energy sections begin on page 232 and continue until the end (page 725!). Some highlights from an offshore energy perspective (more important items in bold):

  • p. 429 – Tax credit eligibility for offshore wind energy components including blades, nacelles, foundations, and towers.
  • p. 447 – Credits for CCS equipment
  • p. 460 – For offshore wind facilities, this section specifies the % of the total costs that must be expended in the US for the facility to qualify as being manufactured in the US. That % rises gradually to 55% after 12/31/2027.
  • p. 518 – Eligibility of CCS for credits
  • p. 615 – $100 million for offshore wind electricity transmission planning, modelling, and analysis. (Seems like a lot for planning and analysis.)
  • p. 621 – $10 million for oversight by DOE Inspector General. (Those folks will have their hands full!)
  • p. 628 – Authorizes wind leasing in the EGOM and South Atlantic areas withdrawn from all leasing at the end of the Trump administration.
  • p. 631 – Authorizes offshore wind leasing adjacent to US territories. (Should be interesting!)
  • p. 632 – Codifies increase in offshore royalty rates: range of 16 2/3% – 18 3/4% for 10 years; not less than 16 2/3 % thereafter
  • p. 640 – The provision requiring that royalty be paid on flared/vented gas could be problematic. The exceptions are not consistent with those currently in the regulations, and would be difficult for BSEE/ONRR to manage. The proposed legislation (exception 1) exempts “gas vented or flared for not longer than 48 hours in an emergency situation that poses a danger to human health, safety, or the environment.” However, current BSEE regulations allow limited (48 hours cumulative) flaring for certain operations (e.g. during the unloading or cleaning of a well, drill-stem testing, production testing, and other well-evaluation testing). This flaring is essential but not normally an emergency situation. Requiring royalty payments for such essential, but not emergency, flaring would be unreasonable and inconsistent with the intent of this provision (minimize unnecessary flaring and venting).
  • p. 641 – Per our previous post, this section reinstates Lease Sale 257 (GoM) and requires that the scheduled 2022 lease sales 258 (GoM) and 259 (Cook Inlet) be held by 12/31/2022. Lease Sale 261 (GoM) must be held by 9/30/2023. Saddle up!

Read Full Post »

Alaska and Pacific OCS compliance leaders

Posted in Alaska, California, Offshore Energy - General, Regulation, tagged , , , , , , , , on July 21, 2022| Leave a Comment »

Northstar, Beaufort Sea

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.

Marine life on Platform Eureka, from this Hakai article

Read Full Post »

SCOTUS: West Virginia 6, EPA 3. These statements should resonate with regulators and industry.

Posted in climate, energy policy, Gulf of Mexico, Offshore Energy - General, Regulation, tagged , , , , , on June 30, 2022| Leave a Comment »

When Congress seems slow to solve problems, it may be only natural that those in the Executive Branch might seek to take matters into their own hands. But the Constitution does not authorize agencies to use pen-and-phone regulations as substitutes for laws passed by the people’s representatives.

Justice Gorsuch in concurrence

Capping carbon dioxide emissions at a level that will force a nationwide transition away from the use of coal to generate electricity may be a sensible “solution to the crisis of the day.” New York v. United States, 505 U. S. 144, 187 (1992). But it is not plausible that Congress gave EPA the authority to adopt on its own such a regulatory scheme in Section 111(d). A decision of such magnitude and consequence rests with Congress itself, or an agency acting pursuant to a clear delegation from that representative body.

Justice Roberts for the majority

At first glance, the SCOTUS decision would seem to affect the regulation of GHG emissions on the OCS and possibly the Lease Sale 257 decision (now being appeal), which was based on BOEM’s failure to estimate the effect of reduced OCS production on GHG emissions outside the US.

Read Full Post »

Exxon and API responses to White House letters to refiners

Posted in energy policy, Offshore Energy - General, Regulation, tagged , , , on June 17, 2022| Leave a Comment »

Good response from Exxon to the White House letter.

In the short term, the U.S. government could enact measures often used in emergencies following hurricanes or other supply disruptions — such as waivers of Jones Act provisions and some fuel specifications to increase supplies. Longer term, government can promote investment through clear and consistent policy that supports U.S. resource development, such as regular and predictable lease sales, as well as streamlined regulatory approval and support for infrastructure such as pipelines.

Exxon

Perhaps Exxon will return to the Gulf of Mexico if the Administration commits to regular and predictable oil and gas lease sales. The company hasn’t drilled a well in the Gulf since 2019.

The longer API letter comments on the fundamentals of refining markets and operations while also addressing the Administration’s “end fossil fuel rhetoric” and negative regulatory signals. Who would want to make major refinery investments under these circumstances?

Read Full Post »

Inspector General reports on Gulf of Mexico flaring violator

Posted in energy policy, Gulf of Mexico, Offshore Energy - General, Regulation, tagged , , , , on June 16, 2022| Leave a Comment »

IG Report

We determined that over approximately 5 years, the energy company’s venting and flaring activities exceeded regulatory limits without the required approvals, resulting in a loss of Federal mineral royalties and resources. More specifically, we identified approximately 229,066 MCF of vented and flared natural gas as suspicious or exceeding the allowable amount across four platforms in the Gulf of Mexico between January 2014 and April 2020. We presented our findings to ONRR, which assisted us in analyzing the energy company’s venting and flaring activities and determining the amount of lost Federal mineral royalties. Based on this analysis, ONRR submitted and secured a proof of claim in the amount of $712,857.82 for unpaid mineral royalties during the energy company’s bankruptcy proceeding.

OIG report 6/13/2022

Comments:

  1. The report doesn’t name the company, but one can make an educated guess based on some of the information provided (e.g. number of platforms the company operated, bankruptcy proceedings, etc.)
  2. The regulator usually finds out about false or misleading recordkeeping. Reports from employees, anonymous or otherwise, are a common source of such charges, as was the case here. (In my District in California, a toolpusher informed us that BOP pressure test records were being falsified. This led to multiple felony convictions.)
  3. The IG’s recommendations to BSEE and ONRR are reasonable and appropriate:
    1. Examine venting and flaring reports for patterns that may reflect violations or amounts that exceed permissible limits.
    2. Develop a process to ensure that royalties are being paid for improperly flared or vented gas.
  4. As BOE has previously reported, available public flaring data do not match. These data inconsistencies should be addressed.
  5. BSEE/ONRR should make more detailed flaring/venting data publicly available so differences between facilities and sectors (e.g. deepwater vs. shelf) can be assessed. Efforts should also be made to post these data in a more timely manner. Data for 2021 are still not available.

Read Full Post »

Whenever oil and gas prices rise, we hear the non-producing leases shtick

Posted in energy policy, Offshore Energy - General, Regulation, tagged , , , , on May 13, 2022| Leave a Comment »

Department of the Interior spokesperson: “there are 10.9 million acres of offshore federal waters already under lease to industry,” and “of those, the industry is not producing on more than three-quarters (75.7% or 8.26 million acres).”

Fox Business

As if the preventable expiration of the 5 year leasing program wasn’t bad enough, we get to hear the non-producing leases bit yet again. This pitch was popularized during the oil embargoes in the 1970’s and resurfaces whenever it is deemed to be politically helpful.

New comments:

Old comments:

  • 539 days since the last US offshore oil and gas lease sale
  • 182 lease sales since 1954, but none since 2020
  • Only 0.5% of US offshore land is leased for oil and gas exploration and production (assuming commercial quantities of oil and gas are discovered).
  • When you acquire a lease, you are not purchasing oil and gas. You are acquiring the right to explore for, and hopefully produce, those resources. Most leases will never produce.
  • Drilling strategies are linked to geophysical data and geologic information obtained in drilling other wells in the area and region.
  • Leases expire if they are not producing by the end of the lease term, which is 5 to 10 years depending on location.
  • You pay bonuses for all leases and annual rental fees for non-producing leases. None of these payments are returned if no discoveries are made.
  • US offshore leases are among the smallest in the world, only a fraction of the sized of those offered by most other nations with offshore oil and gas programs. This complicates exploration and often makes development contingent on the acquisition of additional tracts at future sales.
  • Oil is where you find it, not where you or the government think it is or want it to be.

Read Full Post »

Questions about Gulf of Mexico carbon sequestration

Posted in CCS, climate, energy policy, Gulf of Mexico, pipelines, Regulation, tagged , , , , , , , , on May 12, 2022| Leave a Comment »

Background:

Questions:

  • What are the costs per ton of offshore carbon sequestration including emissions collection, offshore wells and platforms, the associated pipeline infrastructure, ongoing operational and maintenance costs, and decommissioning?
  • What is the timeframe given that the starting point is likely years away?
  • How long would CO2 sequestration continue.
  • Who pays? Polluters? Federal subsidies? Tax credits?
  • Who is liable for:
    • safety and environmental incidents associated with these projects?
    • CO2 that escapes from reservoirs, wells, and pipelines (now and centuries from now)?
    • decommissioning?
    • hurricane preparedness and damage?
  • For Gulf of Mexico sequestration, how much energy would be consumed per ton of CO2 injected? Power source? Emissions?
  • To what extent will these operations interfere with other offshore activities?
  • Relatively speaking, how important is US sequestration given:
  • What are the benefits of offshore sequestration relative to investments in other carbon reduction alternatives?
  • Will BOEM conduct a proper carbon sequestration lease sale with public notice (as required by BOEM regulations) such that all interested parties can bid?
    • What will be the lease terms?
    • Environmental assessment?
    • How will bids be evaluated?
  • What happens to the Exxon bids if the Judge’s Sale 257 decision is reversed?
  • What is the status of the DOI regulations mandated in the legislation with an 11/15/2022 deadline?
    • When will we see an Advanced Notice or Notice of Proposed Rulemaking?
    • Given that DOI has no jurisdiction over the State waters and onshore aspects of these projects, what is the status of parallel regulatory initiatives?
  • Finally and most importantly, how does drilling offshore sequestration wells instead of exploration and development wells increase oil and gas production?
highly simplified conceptual diagram

Read Full Post »

Thank you US Coast Guard….

Posted in Offshore Energy - General, Regulation, tagged , , , , , , , , , on May 11, 2022| Leave a Comment »

….for continuing to recognize the Conservation Division of the Geological Survey (USGS) as the US offshore safety regulator, even though 40 years have passed since that was the case and there have been 3 successor bureaus. 😀

33 CFR § 140.4 Relationship to other law. (current text excerpted from Coast Guard Subchapter N regulations)

(a) Design and equipment requirements of this subchapter for OCS facilities, including mobile offshore drilling units in contact with the seabed of the OCS for exploration or exploitation of subsea resources, are in addition to the regulations and orders of the U.S. Geological Survey applicable to those facilities.

USGS North Atlantic District, Hyannis, MA, Halloween 1980

Most of us old-timers think the best regulatory framework for the offshore program was in the USGS days (pre-1982). Some of this may be nostalgia, but there are some good reasons for this thinking:

  • USGS was/is an internationally acclaimed scientific organization that was always headed by a renowned geologist. The regulatory program was thus somewhat insulated from political pressures. Vince McKelvey, Bill Menard, and Dallas Peck were the Directors when I worked for USGS. Their credentials are linked. Bill and Dallas visited our Hyannis office (not at Halloween 😀) and were very supportive.
  • The Conservation Division was responsible for onshore operations on Federal lands as well as offshore activity. This facilitated information sharing and offered diverse career opportunities. My first bosses in New Orleans had worked previously in the Farmington and Roswell, NM offices.
  • We had excellent synergy with the other USGS divisions. The Marine Science Center in Woods Hole was an incredible resource for our Hyannis office. The Woods Hole office, particularly Mike Bothner and Brad Butman, had a critical role in the Georges Bank Monitoring Program, the best ever (in my biased opinion) environmental study of exploratory drilling operations in a frontier area.
  • The USGS Conservation Division had a very small and supportive headquarter’s staff, which minimized the potential for conflict with field offices.
  • Prior to the formation of the Minerals Management Service (MMS) in 1982, the Bureau of Land Management was responsible for leasing, but all regulatory functions were under USGS. This included resource evaluation/conservation, plan review and approval, permitting, inspections and enforcement, and investigations. The division of MMS responsibilities, most notably the assignment of plan approval to the leasing bureau (BOEM) rather than the regulatory bureau (BSEE), complicates the work of both bureaus and is a prescription for inefficiency, confusion, overlap, and conflict.

Read Full Post »

Macondo revisited, Part 4: What might have been

Posted in accidents, Gulf of Mexico, Offshore Energy - General, Regulation, well control incidents, tagged , , , , , , on April 21, 2022| Leave a Comment »

While the previously discussed planning, cementing, and well suspension issues allowed the well to flow, there were many other equipment, operational, and management deficiencies that elevated the incident to a disaster. Below are those that bother me the most:

  • Blowout Preventers
    • The Deepwater Horizon BOP stack had a single blind shear ram. Regardless of what the regulations allowed, you don’t drill a complex well like this without redundant shearing capability (and at the time of the blowout most deepwater drillers were using rigs with dual shear rams). All well control emergencies requiring the emergency disconnect sequence, deadman, and autoshear functions are dependent on effective shearing capability. You can have redundancy in every other BOP element, but without dual shear rams, you don’t have a redundant BOP system. Further, for full redundancy both shear rams should be capable of sealing the well bore after shearing. In that regard, the present regulations and the applicable standard (API S 53) require only one shear ram capable of sealing. They are thus deficient and should be updated.
    • The DWH BOP system did not have full bore shearing capability (available at the time) which may have sheared the deflected drill pipe.
    • The DWH BOP system was not properly maintained and recertified as required by regulation.
    • Transocean’s “condition based maintenance” was a euphenism for “fix it when it fails.” Perhaps worse, BP authorized the continuation of operations knowing that an annular preventer was leaking.
  • The initial flow from the well was directed to the mud-gas separator instead of being routed overboard via the diverter. Routing the flow to the diverter would have provided additional time for the crew to safely evacuate.
  • Gas detectors
    • Not all gas detectors were fully operational. As justification, Transocean’s report expressed concerns about alarm fatigue, a weak excuse. Alarm issues can be effectively managed without disabling the devices.
    • The gas detectors did not automatically shutdown the generators, the source of the initial explosion. This is somewhat understandable on a dynamically positioned rig that is dependent on power to maintain position. However, someone should have shut down the generators as soon as gas was detected.
  • Engine overspeed devices didn’t work, and apparently weren’t tested regularly. Had they worked, the engine room explosion may have been prevented.
  • The crew had time to activate the Emergency Disconnect Sequence, but did not.
    • Deficient training
    • Uncertain chain of command
    • Fear of repercussions?

Read Full Post »

« Newer Posts - Older Posts »