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Deepwater GOM Project Claims Industry First

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Deepwater GOM Project Claims Industry First

 

 

 

LLOG Exploration Offshore, L.L.C. reported Tuesday that it has ordered subsea trees from TechnipFMC for its Shenandoah Project in the deepwater Gulf of Mexico (GOM).

The subsea trees represent the first material equipment order for Shenandoah, and the order marks an industry first for subsea trees designed to withstand pressures up to 20,000 pounds per square inch (psi), LLOG contends.

“LLOG is excited about signing this subsea tree order which is a first in the industry and a significant milestone towards the development of our Shenandoah project,” LLOG Chief Operating Officer Rick Fowler commented in a written statement emailed to Rigzone. “LLOG is pleased to expand our strategic alliance with TechnipFMC who has provided all of LLOG’s subsea equipment for more than a decade.”

The Shenandoah discovery occupies the unit comprising Walker Ridge blocks 51, 52 and 53 in the deepwater GOM approximately 200 miles (322 kilometers) south of New Orleans, operated LLOG stated. Other Shenandoah partners include Venari Offshore, LLC, Navitas Petroleum and Beacon Offshore Energy.

LLOG noted the Shenandoah leases are currently held under a suspension of production (SOP) and will be developed with a new floating production system. In addition, the Covington, La.-headquartered company stated the Shenandoah partners will drill multiple wells to develop the estimated 100 to 400 million barrels targeting previously discovered oil-bearing Upper and Lower Wilcox reservoirs.

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Why do they need trees capable of withstanding 20,000psi? If there is no engineering basis for it, they are wasting money.

@James Regan Any idea why they’d need these trees?

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On 10/16/2019 at 9:35 AM, Douglas Buckland said:

Why do they need trees capable of withstanding 20,000psi? If there is no engineering basis for it, they are wasting money.

@James Regan Any idea why they’d need these trees?

There are some 20K BOP systems out there now, however why you would require 20K trees etc is a little confusing, who's producing at this kind of pressure or the possibility of reaching 20K or greater, BP. BP is working in HPHT areas of the GOM, it makes sense the BP drilling HPHT in the GOM would be the ones to go overboard with BSEE etc. The article also remarks on 25K Systems being designed.

The trees may be able to hold this kind of pressures and temps but what about the production tubing and casing? Would be interesting to see a 25,000psi test against the tooling and tree, interesting indeed.

https://www.oedigital.com/news/454268-reaching-20k

If we are talking about designing systems for these types of reservoirs its a good sign for the deepwater market, these fields must be big and worth the R&D.

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(edited)

Sounds expensive. What are typical production pressures like in deep sea GOM wells? I'm used to seeing SICP around 5k psi, but not much higher, on land rigs. 

Do they have a lot of saturated gas they're expecting to evolve out if they don't maintain really high pressure? It must be some heavy casing.

 

Edited by PE Scott

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On 10/16/2019 at 1:35 PM, Douglas Buckland said:

Any idea why they’d need these trees?

Viewing pleasure. Trees are nice.

  • Haha 2

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7 hours ago, DayTrader said:

Viewing pleasure. Trees are nice.

Traders.....😖

  • Haha 2

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image.png.5af3a19aab1c6701f0e4345993facf58.png

Rystad Energy expects that this high activity level will be sustained through the winter season and into 2020. Around 30 to 50 exploration wells will be drilled per year towards 2023.

“Our preliminary analysis shows that a total of 130 wells are likely to be drilled this year – a 16% increase compared to 2018. The increased activity this year relates primarily to an uptick in exploration drilling, a segment that will see around 55 wells completed,” says Eivind Drabløs, an analyst on Rystad Energy’s offshore rig team. “This brings activity levels in line with the record pace last seen in 2013 and 2015, before the effects of the oil price collapse took hold on the drilling market in Norway.”

Subsea development wells are forecast to experience a growth spurt beginning in 2020 and lasting several years. Several large upcoming subsea field developments, such as Johan Castberg, Snorre Expansion, and Wisting, will also spark an increase in long-term contracts for harsh-environment semisubmersible rigs authorised for operations in Norway. Meanwhile, development wells associated with wellhead platforms – so-called dry wells – will see a flatter forward trend.

While offshore drilling share prices have fallen sharply over the past year, rig rates and utilisation rates are on the rise. On the NCS, average day rates now hover around US$300 000/d for floaters, up 76% since they bottomed out during the oil and gas downturn.

“The offshore rig market is propelled by the increased sanctioning of greenfield projects, coupled with a substantial amount of brownfield work aimed at maintaining legacy production,” said Oddmund Føre, head of the offshore rig team. “Some E&P companies are even increasing exploration efforts in a quest to replace declining reserves, resulting in a ‘trickle-down’ effect that is driving up rig counts and day rates.”

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Bloomberg) -- An auction next month of oilfields in Brazil may be the priciest ever held, raising at least $50 billion in licensing fees and compensation, according to people familiar with government estimates.

Exxon Mobil Corp., Royal Dutch Shell Plc and other energy giants are set to vie for deep-sea deposits that could hold 15 billion barrels of oil, almost twice as much as Norway’s reserves. Winners at the Nov. 6 auction are expected to pay $25 billion in licensing fees, plus share a portion of their production with the government.

In addition, bidders will need to negotiate payments to state-controlled Petroleo Brasileiro SA for investments it has already made in the area. Those payments could add another $25 billion to $45 billion in costs, according to officials familiar with government figures who asked not to be named because the information is private.

The auction is unique in part because one of the four areas being offered is already gushing more than half of the daily output from Venezuela. It’s a rare opportunity for an industry more accustomed to exploring riskier offshore prospects that can take a decade or more to develop.

Fourteen producers -- including Petrobras -- have signed up to participate in the auction.

Petrobras didn’t respond to requests for comment. The Brazilian oil regulator, known as ANP, declined to comment on the total amount the auction could raise. It said payments to Petrobras will be negotiated between the company and its partners, without government interference.

The offerings are at the heart of the pre-salt, a giant expanse of oil deposits about the size of Ohio trapped beneath a layer of salt under the Atlantic seabed. The four prospects -- Buzios, Itapu, Sepia and Atapu -- are estimated to hold as much as 15 billion barrels of recoverable crude, according to a study by Houston-based consultancy Gaffney, Cline & Associates.

Buzios is already Brazil’s second-largest field by production, with output of about 425,000 barrels a day -- at a time when Venezuelan production is running at 700,000. It has four platforms that are tapping about a dozen wells, with room for other wells to be drilled and the current ones to be ramped up further.

Payment Terms

Brazil’s federal audit court estimates the compensation to Brazil’s oil company could reach $45 billion under proposed guidelines. It has recommended the government lower certain parameters like the estimated price of Brent crude to make the deals more attractive, according to the people familiar. The court’s estimates and recommendations for the sale are confidential.

The Brazilian Petroleum Institute, an industry group that represents some of the bidders, estimates the payments to Petrobras will be worth between 120 billion and 130 billion reais ($29 billion-$31 billion). A study by Wood Mackenzie Ltd. released Monday estimates $24 billion.

The rules do not specify how the payments to Petrobras should be settled. A combination of cash, crude and investments over many years is a possibility. Licenses last for three decades. Winning bidders will have 18 months to reach an agreement with Petrobras before the oil regulator is required to step in as mediator.

As for the licensing payments, the largest chunk of the $25 billion will be due this year and the remainder in 2020, all in cash.

A 2009 auction of development rights for Iraqi oil included larger reserves, but was done using different methodology under which companies were bidding for the right to service the oil fields and get paid per barrel by the government.

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(Bloomberg) -- The U.S. has forfeited some $18 billion tied to oil and gas production in the Gulf of Mexico since 2000 because of a decades-old law that gave energy companies a break on paying royalties when drilling in deep waters, federal investigators concluded Thursday.

The foregone revenue will keep climbing, as energy companies continue to harvest oil and gas royalty-free from dozens of affected tracts in the Gulf, long after lawmakers realized sloppy legislative writing prevented the government from making the price breaks temporary.

The dynamic is providing “corporate welfare at taxpayer expense,” said Democratic Representative Raul Grijalva, the head of the House Natural Resources Committee who requested the Government Accountability Office report.

At issue is a 1995 law Congress passed to spur deep-water drilling by waiving royalty payments that energy companies must make to the federal government for oil and gas extracted from federal waters. Some lawmakers said they aimed to make that royalty relief temporary if oil and gas prices or production jumped above certain levels.

But specific price thresholds didn’t make it into the statute or the lease contracts issued by the Clinton administration in 1998 and 1999. And in 2007, a federal court ruled the Interior Department couldn’t force companies to pay royalties on production from even more deep-water leases inked between 1996 and 2000, saying they were barred by that federal law. If Congress intended to impose price thresholds on royalty relief, an appeals court later said, “it certainly knew how to do so.”

The misstep is benefiting a slew of oil and gas companies, including Exxon Mobil Corp., Equinor Gulf of Mexico LLC, Chevron USA Inc. and Eni Petroleum US LLC, according to lease data reviewed by Bloomberg.

The Interior Department took issue with some of the GAO’s analysis but said it would consider the agency’s recommendations for changes to offshore leasing and royalty programs.

Oil industry advocates leaned on the 2007 court ruling affirming the royalty relief program.

“The courts have ruled there was nothing ambiguous about the 1995 act,” said Ben Marter, a spokesman for the American Petroleum Institute. “Those who would require the companies that took Congress at its word to now pay royalties retroactively are engaging in a dangerous game of bait-and-switch.”

Offshore oil and gas production in U.S. coastal waters is a significant source of revenue for federal coffers, bringing in almost $90 billion from 2006 through 2018, according to the GAO.

The lure of royalty relief sometimes spurred lucrative bidding on drilling rights in the Gulf. According to the GAO, the U.S. collected nearly $2 billion in additional bids from more aggressive bidding for deep-water tracts sold with the promise of royalty-free production from 1996 through 2000. However that initial jackpot was dwarfed by the foregone revenues ever since, the GAO said.

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Floating shale gas LNG producer moving ahead with build out plans

 

 

Delfin Midstream has furthered its floating approach to liquified natural gas processing. The Houston-based company announced this week that after working with Samsung Heavy Industries and Black & Veatch in early 2019 on a concept to design and develop a floating LNG vessel suited for the Gulf of Mexico, the company is now moving forward with plans to construct and buildout the vessel.

According to Delfin, many land-based LNG export projects seek ‘economies-of-scale’ to lower their costs by developing 10 to 20 million metric tons per annum projects. By re-purposing existing offshore pipelines and building the FLNG Vessels at efficient, low-cost Asian shipyards, Delfin can achieve total capital costs around $500 to $550 Tpa for just 3.5 Mtpa FLNG Vessels. The company added that each FLNG Vessel can be developed independently with its own commercial and

 

financial structure. This enables Delfin to offer standard tolling models with terms of 10 to 25 years, integrated structures or JV arrangements with offtakers, producers and/or traders. Delfin’s existing offshore pipelines connect directly to the extensive network of onshore pipeline systems, with ample supply capacity for the first 2 to 3 FLNG Vessels.

“The two most important innovations of the last 20 years in the global gas market have been the shale gas revolution and the emergence of floating LNG technologies for regasification and liquefaction. Delfin combines these two innovations to offer the LNG market a low cost, simple and flexible LNG supply solution,” said Dudley Poston, CEO of Delfin.

Samsung Heavy Industries was established in 1974 and is today one of the largest ship builders in the world.

The design and engineering work on the FLNG vessel is expected to be complete by mid-2020.

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