Posts Tagged ‘deepwater production’

The September total reflects production from recent deepwater startups, including King’s Quay (Murphy) and Spruance (LLOG). Other new deepwater facilities should further boost GoM oil production next year as forecasted by BOEM (table below). Unfortunately, the BOEM forecast considerably overstates 2022 production and appears to be optimistic for the outyears. This is a significant concern given that US offshore leasing policy, as reflected in the 5 Year Plan, is naively focused on throttling long-term production. See the rather startling quote below:

BOEM’s short-term (20-year) production forecast for existing leases shows steady growth from 2022 through 2024 and declining thereafter (see Section 5.2.1). The long-term nature of OCS oil and gas development, such that production on a lease can continue for decades makes consideration of future climate pathways relevant to the Secretary’s determinations with respect to how the OCS leasing program best meets the Nation’s energy needs.

5 Year Leasing Program, p.3

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On Monday, the offshore world lost Mike Conner, an outstanding engineer and a major contributor to the success of the US offshore program.

Mike is the person most responsible for the Deepwater Operations Plan (DWOP), a pioneering safety-case approach to regulating deepwater oil and gas development. The DWOP program was initiated 30 years ago and facilitated deepwater production at a time when there were no deepwater-specific regulations or standards. Innovative tension leg platform, compliant tower, spar, production semisubmersible, and subsea projects would not have been possible without the DWOP program. 93% of Gulf of Mexico oil production and 76% of the gas is now attributable to deepwater production facilities. Thanks in large part to the DWOP program, these facilities have had a nearly flawless safety and environmental record.

While his obituary is no yet available, this link announces Mike’s well-deserved selection for the OTC Heritage Award in 2017, and provides good information on Mike and his career.

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Waiting for a boost from the deepwater startups. The first of that group, King’s Quay did not begin producing until April.

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Federal Oil & Bas Corp. (FOGCO)

Guyana’s pending decision regarding the formation of a national oil company brings back memories of unsuccessful attempts to do the same in the US in the 1970s.

The most serious attempt at forming a national oil company in the US was a 1975 Senate bill to establish the Federal Oil and Gas Corporation or FOGCO. (Oddly, the bill’s sponsors weren’t troubled by that acronym.) FOGCO was proposed at a time when natural gas supplies didn’t satisfy demand, and that was the primary impetus behind the legislation. (Supply issues went away when price controls were lifted.)

Concerns about a FOGCO then and now:

  • The political pressures under which a national oil company operates are not conducive to sound, expeditious decisionmaking. (Unfortunately, some current industry execs seem overly responsive to pressure from governments and activist organizations, which is not always in the best interest of the company and its shareholders).
  • Would limit competition and private investment.
  • Would delay or prevent innovation:
    • The shale revolution was driven by nimble private companies operating on private land in supportive states. Why is there Marcellus shale development in PA, WV, and OH, and none in NY? (Hint: It’s not the absence of resources.) Why could the US shale experience not be replicated in Europe?
    • Innovative deepwater development projects were driven by private companies and the supportive public policies of the 1990s.
  • A national oil company could be the first step in the process of nationalizing the petroleum industry.

Guyana is far different from the US and should do what is perceived to be in their best interest. Best wishes to the people of Guyana as they weight their options.

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Murphy has announced first oil from the King’s Quay floating production unit in the Gulf of Mexico. The initial production rate has not been released, but the facility is expected to process up to 80,000 BOPD and 100 million cu ft of gas per day from subsea wells.

Murphy’s six partners all appear to be investment companies. This type of support is essential given the reduced Gulf of Mexico participation by some of the major oil companies. Ridgewood Energy has the largest stake among the Murphy partners. In the “old days,” the partners were typically other exploration and production companies.

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Deepwater production is noteworthy for widely dispersed surface structures supplemented with subsea systems. In the past 30 years, the total number of Gulf of Mexico platforms declined by 50% while the oil production doubled. Of course, this level of production is not sustainable without regular lease sales and increased exploration. In that regard, the signs are not good.

435 GoM shelf platforms have been removed in just the last 5 years (2017-2021). The loss of platforms is accompanied by a loss of marine habitat that the rigs-to-reefs program has partially compensated for. There have been a number of other interesting proposals for the use of old platforms, some more serious than others.

Current number of Gulf of Mexico platforms by water depth:

water depthfloating and fixed production platforms
all depths1757
>400 m52
>1000 m35
>1500 m16
>2000 m7

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Shell Vit0
Chevron Anchor
BP’s Argos
Murphy’s King’s Quay

After a several year lag in deepwater Gulf of Mexico development, a new generation of projects is moving toward first production. Shell’s Vito and Whale, BP’s Argos, Chevron’s Anchor, and Murphy’s King’s Quay are similar in many ways including the following:

  • Floating production units
  • Lighter, smaller semisubmersible designs
  • Excellent structural integrity and storm performance characteristics
  • Lower project costs, shorter cycle times
  • 4000 to 8600′ water depth
  • Subsea wells, small surface footprint
  • High production rates anticipated: 100,000 – 150,000 BOE/D
  • Standardized equipment
  • Energy efficient gas turbines
  • Advanced remote monitoring, fewer onboard staff
  • Simpler = safer (assuming equivalent well and production safety system integrity)
  • Limited number of wells + high production rates/well + efficient power generation and processing equipment + restricted flaring + pipeline transportation = low GHG intensity production

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Per Offshore-Energy.biz, BP’s semi-submersible Argos production platform has arrived on location in the Gulf of Mexico. The floating platform will operate in 4500′ of water as part of BP’s Mad Dog 2 project. Production, which is expected to reach 140,000 boe/d, should begin in the 2nd quarter of 2022.

Per BOEM’s platform data base, this will be the 58th surface production facility in the deepwater (>1000′) GoM and the first such facility installed since Shell’s Appomattox in June, 2018. These platforms account for more than 90% of US offshore oil production.

BP photo: Argos at Ingleside, TX
BP graphic

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In light of energy security and price considerations, rebounding oil demand, uncertainty about the long-term viability of non-conventional onshore production, and the elimination of most other offshore options, sustaining deepwater GoM production should be a high-priority U.S. policy objective. The deepwater GoM also offers significant environmental advantages in that approximately 1.6 million BOPD are produced from only 58 widely dispersed surface facilities that are well maintained, closely monitored and inspected, and distant from shore. Another advantage of US deepwater production is the low carbon intensity relative to other sources of petroleum (more on this in a later post).

EIA (Chart 1) projects relatively stable GoM production over the next 2 years. Platt’s (Chart 2) is forecasting a slight decline in 2021 production primarily because of COVID-related delays in the initiation of production at Shell’s VIto and PowerNap and BP’s Mad Dog 2 and Thunder Horse South 2 facilities. Based on the latest available EIA data, current stabilized GoM oil production appears to be in the 1.7-1.8 million BOPD range.

Going forward, the concern is the high rate of reserve depletion and the absence of drilling activity needed to replace reserves. Schlumberger data through 2016 (Chart 3) show depletion rates rising to above 20%, the highest (by far) of the offshore regions analyzed. I was unable to find more recent data, but unless this trend line has made a sharp turn, production declines are likely in the next 3-5 years. Further, drilling trends do not suggest the likelihood of significant reserve growth. Data from BSEE’s Borehole File (Chart 4) indicate deepwater well start activity that is comparable to the moratorium years of 2010 and 2011. Even more concerning is the absence of exploratory drilling (chart 5) and the very few operating companies that are drilling deepwater wells. Only five operators have spudded deepwater exploratory wells in 2021 YTD. One US supermajor hasn’t started a well since 2019, and another US major has essentially exited the Gulf.

Deepwater production trends are not easily reversed, so dialogue is urgently needed to assess the implications of declines in drilling, reserves, and industry interest. As the resource manager on behalf of the public, BOEM is the logical choice for initiating these discussions. BOEM’s Norwegian equivalent, the Norwegian Petroleum Directorate (NPD) demonstrates the importance of pro-active land management. The NPD has done an outstanding job of sustaining exploration activity and production consistent with Norwegian safety and environmental values, which are among the highest in the world. On their website, NPD provides ongoing updates on exploration, production, and reserve depletion parameters. Their competency and commitment to sustaining production on the Norwegian shelf is underscored in this news release, an excerpt from which is pasted below:

Exploration is of great importance for the long-term value creation on the shelf. The supply of oil and gas resources from new discoveries, as we have seen so far this year, is necessary so that activity in the petroleum industry does not fall sharply after 2030. Without new discoveries, production can fall by more than 70 percent in 2040 compared to 2020, says Torgeir Stordal, director of Technology and coexistence in the Norwegian Petroleum Directorate.

NPD, July 21, 2021
monthly crude oil production from U.S. federal gulf of Mexico
Chart 1, EIA GoM Production Forecast
Chart 2


Chart 3: Depletion calculated as annual production divided by proved-developed reserves at end of same year

Chart 4: Data from BSEE Borehole File; 2021 Data as of 7/23
Chart 5: Data from BSEE Borehole File; 2021 Data as of 7/23

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