GENERAL INTEREST Quick Takes
Gulf of Mexico lease sale draws $135 million in bids
Oil and gas companies entered 105 bids totaling $135 million for exploration leases in the Gulf of Mexico Nov. 18, with Royal Dutch Shell PLC offering the most overall and Equinor ASA taking the costliest single prize.
In Bureau of Ocean Energy Management (BOEM) Lease Sale 256, winning bids totaled more than $120 million, the competition moderately active as 23 companies offered bids despite a pandemic severely reducing corporate cash flows.
BOEM Acting Director Walter Cruickshank, talking to reporters after the sale, summarized the bidding activity by saying companies these days are entering fewer bids and being more selective while demonstrating continued interest.
Norway’s Equinor teamed up with Spain’s Repsol SA for the highest winning bid, just $21 dollars shy of $12 million for Walker Ridge Block 365.
Mike Celata, director for BOEM’s Gulf of Mexico region, explained the high bid by noting the block was a little east of Monument field discovery. Equinor, with Repsol as one of its partners, announced the Monument discovery in April (OGJ Online, Apr. 6, 2020).
Top bidders were Shell, offering $28.4 million for 22 blocks (won 21); Chevron Corp., offering $22.5 million for 13 blocks (won 10), Equinor, offering $22.1 million for 7 blocks (won 7), and BP PLC, offering $19.3 million for 13 bids (won 10).
Shell especially showed an interest in the Alaminos Canyon region, where it snapped up 9 tracts.
Most of the interest was in deepwater blocks, as has been usual for many years. Of the 93 blocks receiving bids, 81 were in deepwater, with 18.75% royalty rates, and 12 were in shallow water (less than 200 m), with $12.5% royalty rates.
Senate committee advances two FERC nominees
The nominations of Allison Clements and Mark Christie to be commissioners on the Federal Energy Regulatory Commission (FERC) advanced to the full Senate on voice votes Nov. 18 by the Senate Energy and Natural Resources Committee.
Sens. Lisa Murkowski (R-Ala.) and Joe Manchin (D-W.Va.), chairman and ranking member of the committee respectively, made a point of stressing bipartisanship and their support for both candidates. Schedule time in December for full Senate votes is yet to be determined.
Clements is a consultant and a former attorney for the Natural Resources Defense Council (NRDC), a group well known for suing federal regulators in environmental disputes. She also represented utilities and independent power producers when she worked at a law firm then named Troutman Sanders (now Troutman Pepper Hamilton Sanders).
Christie, chairman of the Virginia State Corporation Commission, has been a member of that state regulatory body for 16 years and has taught regulatory law at the University of Virginia School of Law.
FERC is supposed to have five members but currently is reduced to three. If confirmed, Clements will have a term expiring June 30, 2024, as a successor to Cheryl LaFleur, while Christie will have a term expiring June 30, 2025, as a successor to Bernard McNamee.
WIAG transfers operatorship of two Libyan concessions
Wintershall Aktiengesellschaft (WIAG), a joint venture between Wintershall Dea and Gazprom EP International, transferred operatorship of Contract Areas 91 (former Concession 96) and 107 (former Concession 97) onshore Libya’s Sirte basin to Sarir Oil Operations (SOO), a newly established joint venture between WIAG and the National Oil Corp.
After signing two exploration and production sharing agreements in December 2019, WIAG transitionally operated the fields while SOO was being established and prepared to assume operational responsibility. The vast majority of WIAG’s Libyan personnel has been transferred to SOO and will continue to work in their previous roles, Wintershall said.
Sirte basin lies about 1,000 km southeast of Tripoli in the Al-Wahat municipality. Oil production in contract areas 91 and 107 has been suspended since mid-January due to blockades of export infrastructure.
Exploration & Development Quick Takes
ConocoPhillips to appraise Heidrun area discovery
ConocoPhillips will further appraise a Norwegian Sea gas condensate discovery to determine potential flow rates, the reservoir’s ultimate resource recovery, and plans for development. Preliminary estimates place the size of the discovery at 50-190 million bbl of recoverable oil equivalent.
Well 6507/4-1 (Warka)—the first in PL 1009—was drilled by the Leiv Eiriksson drilling rig 22 miles northwest of Heidrun field and 150 miles from the coast of Norway in 1,312 ft of water to a total depth of 16,355 ft (OGJ Online, Aug. 3, 2020). It was terminated in the Lange formation from the Early Cretaceous Age.
Primary and secondary exploration targets were rocks from Albian and Aptian Ages, respectively, in the Early Cretaceous (Intra Lange formation sandstones), the Norwegian Petroleum Directorate (NPD) said.
According to NPD, in the primary exploration target, the well encountered an 88-ft gas column in Lange formation sandstone layers, with moderate but uncertain reservoir quality. Gas-water contact was not encountered, and no reservoir rocks were encountered in the secondary target. The well has been permanently plugged.
The well was not formation-tested, but extensive data acquisition and sampling have been carried out. The licensees will assess the results together with other nearby prospects for potential development to existing infrastructure.
After completion, the Leiv Eiriksson drilling rig will proceed to drill exploration well 6507/5-10 S (Slagugle) 14 miles north-northeast of Heidrun field in ConocoPhillips-operated PL 891.
ConocoPhillips Skandinavia AS is operator of PL 1009 with 65% interest. PGNiG Upstream Norway AS holds the remaining 35%.
Otway basin gas discovery derisks nearshore prospects
A new nearshore gas discovery in Otway basin Permit Vic/P42(V) off western Victoria builds on a previous nearby discovery at Black Watch-1 and derisks surrounding nearshore prospects in the permit, Beach Energy Ltd., Adelaide, said Nov. 10.
Enterprise-1 was spudded from an onshore location about 3.5 km from Port Campbell and 8 km from the Otway gas plant and drilled directionally to a target 3.2 km offshore.
The well drilled to a total measured depth of 4,974 m and encountered the Cretaceous-age Upper Waarre formation target 89 m high to prognosis at a depth of 4,594 m, which is 2,052 m vertical depth subsea. It intersected a 146-m gas column, including 115 m of net gas pay without identifying a gas-water contact.
Gas samples were taken and indicated a carbon dioxide content of 10% by volume.
Beach plans to case and suspend the well as a future producer. A forthcoming test program will confirm the well productivity as well as provide an estimate of reserves and furnish data for a proposed spur line to the Otway gas plant. Detailed engineering work and the regulatory approvals process for the pipeline is under way.
The gas plant is currently producing 205 terajoules/day, which is half its nameplate capacity.
Beach is operator with 60% interest. OG Energy (part of Ofer Global Group) holds the remaining 40%.
Beach will now move its focus to the forthcoming offshore Otway basin drilling campaign beginning with Artisan-1 during the March 2021 quarter. This will be followed by development wells in Geographe and Thylacine gas fields.
Equinor receives approval to start up Snorre expansion
Equinor has consent from the Norwegian Petroleum Directorate to start up the Snorre expansion project in Blocks 34/4 (PL 057) and 34/7 (PL 089) of the Tampen area, about 200 km west of Florø in the Norwegian North Sea.
The expansion consists of 24 new wells (13 production wells, 11 water-alternating gas injectors) in six subsea templates and will be tied into Snorre A floating tension-leg platform (OGJ Online, Oct. 10, 2018).
Recoverable reserves are about 31 million standard cu m oil equivalent (195 million bbl) in the amended plan for development and operation. The project is expected to increase field production life by 30 years, up to 2040.
Equinor is operator at Snorre (33.3%) with partners Petoro AS (30%), Var Energi AS (18.5%), Idemitsu Petroleum Norge AS (9.6%), and Wintershall Dea Norge AS (8.6%).
Drilling & Production Quick Takes
Aker BP starts Aefugl Phase 1 production
Aker BP has commenced production from Aerfugl gas and condensate field Phase 1 development. Approval for the start was granted by the Norwegian Petroleum Directorate in October.
Development of the Norwegian Sea field will occur in two phases, both with three wells, all of which will be tied in to Skarv FPSO 210 km west of Sandnessjøen in Nordland county for processing and further transport.
Aerfugl lies just west of Skarv field in 350-450 m of water. Phase 1 lies in the southern part of the field. Phase 2, in the northern part of the field, is expected to come on stream in 2021.
Field development is enabled by more efficient reservoir drainage through new vertical valve trees, and long distance, electrically heated flow lines to avoid hydrates in gas pipelines, the operator said, adding that the technology improves heat efficiency and enables longer tie-backs.
The development is adding 5 years lifetime extension to the Skarv FPSO, said Sverre Isak Bjørn, vice-president, operations and asset development, Skarv area, in a Nov. 13 release. When both phases are on stream, utilization of the FPSO will double current levels, he said. Energy efficiency is also set to improve, potentially lowering CO2 emissions from the FPSO by 30-40%/bbl, he said.
The Aefugl gas reservoir is more than 60 km long, 2-3 km wide, and holds about 300 million producible boe in Lysing formation sandstone of Cretaceous age at a depth of 2,800 m.
Total investment cost for the Aerfugl project (Phases 1 and 2) is 8 billion kroner.
Aker BP is operator with 23.9 interest. Partners are Equinor (36.1%), Wintershall Dea (28.1%), and PGNiG (11.91%).
88 Energy raises funds for 2021 Alaskan drilling program
Perth-based 88 Energy Ltd. has raised $10.07 million (Aus.) from investors for its planned 2021 drilling program, including two Project Peregrine wells on the North Slope of Alaska.
Project Peregrine was recently acquired in an off-market takeover of XCD Energy Ltd. Preparations are being finalized for drilling of Merlin-1 and Harrier-1, the first of which is due to spud in late February 2021.
The wells will be drilled into the shallow Nanushuk reservoir using a lightweight workover rig that can be transported off road in pieces by tundra-safe track vehicles along snow trails and gravel roads. Drilling depths of around 5,000 ft are anticipated to reach the reservoir formation which carries multiple conventional targets.
The Peregrine leases lie 35 km south of the ConocoPhillips oil discovery at Willow which holds an estimated 450-800 MMboe. The Merlin prospect is considered a direct analogy to Willow, said 88 Energy managing director Dave Wall.
The prospect lies directly north of the Umiat oil find estimated to contain more than 1 billion bbl of oil in place, while ConocoPhillips’ Harpooon prospect lies 15 km northwest of the Harrier structure.
Final documentation in relation to a farm-out of the project with a preferred bidder is nearing a conclusion with execution of final documents expected before yearend.
Norway production increased in October, NPD says
Norway’s liquids production averaged 1.877 million b/d in October, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 1.772 million b/d in September (OGJ Online, Oct. 28, 2020).
On Apr. 29, the government decided to implement a cut in Norwegian oil production. The production figures for oil in October include this cut of 134,000 b/d in the second half of 2020. Oil production in October is 6.6% lower than the NPD’s forecast, and 2.1% below the forecast so far this year.
The average daily liquids production in October consists of 1.611 million b/o, 253,000 bbl of NGL, and 14,000 bbl of condensate.
The main reasons that production in October was below forecast is strike and maintenance work on some fields.
The total petroleum production for the first 10 months of the year is about 188.6 million standard cu m oil equivalents.
Gazprom obtains record flow from Kara Sea shelf well
Gazprom produced over 1 million cu m/d commercial gas during a test from upper levels of an exploration well in Leningradskoye gas and condensate field off the northwest coast of the Yamal peninsula, proving field productivity at levels higher than anticipated, the company said Nov. 3. The flow is a record-high for Russia’s Arctic shelf fields.
The well helped discover a new gas deposit in the lower levels in October. Commercial gas inflow at the time was 600,000 cu m/d. The field’s current recoverable gas reserves are estimated at 1.9 trillion cu m.
Leningradskoye lies in the Kara Sea within the Leningradsky licensed block. The Yamal production center contains 32 fields with total reserves of 25.5 trillion cu m gas, 1.6 billion tons gas condensate, and 300 million tons oil. It is expected to become a major contributor to the Russian gas industry with up to 360 billion cu m/year of gas production.
PROCESSING Quick Takes
Kentucky refinery to get new life as biodiesel plant
Hemisphere Ltd. LLC subsidiary Continental Refining Co. LLC (CRC) is evaluating a plan to convert CRC’s now idled 5,500-b/d crude oil refinery in Somerset, Ky., into a biodiesel production site.
The proposed $25-million investment would involve acquiring, relocating, and installing a soybean-crushing, biodiesel refining, and blending facility equipped to process 3 million bushels/year of locally sourced soybean production into biofuels and other soy-based products, CRC said on Nov. 18.
Alongside producing up to 5 million gal/year of renewable-based, ultralow-sulfur diesel—including B6 to B100 biodiesel—the repurposed site also would produce high-protein fiber meal for animal feed, soybean oil for industrial use, and crude glycerin.
“Like many rural parts of America, the Pulaski County[,Ky.] region has industries and institutions that rely on diesel fuels,” said Demetrios Haseotes, Hemisphere’s chief executive officer. “And because Kentucky is ranked #15 in the nation for soybean production, the region also has the raw materials and technology to make biodiesel at a scale that reflects the local and regional demand.”
While it disclosed no further operational details regarding the Somerset refinery conversion plan, CRC did confirm that, if approved, construction on the project, as well as reception and processing of soybeans, would begin by October 2021.
The intended agricultural technology, or AgriTech, redevelopment plan for the Somerset refinery follows Haseotes’ 2011 purchase and more than $40-million additional investment to upgrade and modernize crude processing capabilities of the plant, which he restarted in January 2013 after its shuttering in 2010 under former owner Somerset Energy Refining LLC.
Hemisphere subsequently halted operations at the refinery again in 2018 to conduct economic and engineering studies for a proposed $75-million modernization program that would involve an overhaul of every unit in the plant.
In July 2020, however, CRC decided the already idled refinery would permanently remain offline and be redeveloped into another business or commercial properties, according to the operator’s website.
OMV Petrom increases bioblending at Petrobrazi
OMV Petrom SA, Bucharest, has completed a project to boost bioblending capacity as well as improve infrastructure for transport, unloading, and storage of biocomponents at its 4.5-million tonnes/year Petrobrazi refinery in the southeast region of Romania, near Ploiesti City.
Initiated in 2018 and completed at an investment of about €21 million, the project has increased blending capacity of biocontent in fuels produced at the refinery to about 350,000 tpy from 200,000 tpy in alignment with European regulations requiring the renewable energy content in transportation fuels to increase to 14% in 2030 from 10% in 2020 as part of its program to reduce greenhouse gas emissions arising from the transportation sector, OMV Petrom said on Nov. 18.
OMV Petrom—which disclosed no further details regarding work involved during the project—said the Petrobrazi refinery now supplies fuels with a volumetric biocontent of 6.5% in diesel and 8.0% in gasoline.
The increase in bioblending capacity at Petrobrazi comes as one component of a combined effort across all levels of OMV Petrom to meet a goal of reducing its carbon emissions 27% by 2025 vs. the 2010 baseline year, according to Ca˘pra˘u.
OMV Petrom—a member of the United Nations Global Compact since 2013, and which in July 2020 announced its support for recommendations issued by the Task Force on Climate-related Financial Disclosures regarding risks and opportunities on climate change—said its investments since 2005 at the Petrobrazi refinery have totaled €1.8 billion, a third of which has been dedicated to projects aimed at reducing environmental impacts.
Investments to reduce the environmental impacts at the refinery include a €46-million project completed in 2019 at the coker, where the unit’s outdated closed-blowdown system was replaced with a new one equipped with best available technologies for recovery of hydrocarbon vapors to ensure complete elimination of any emissions of potential volatile organic compounds, according to the operator’s 2019 annual report to investors.
OMV Petrom in 2019 also completed startup of a new €65-million Polyfuel unit that—using environmentally friendly technology—has allowed the Petrobrazi refinery to shift as much as 50,000 tonnes of its current production of LPG components into Euro 5-quality gasoline and diesel.
In its 2019 sustainability report, OMV Petrom said it also was making an unspecified investment in a project at Petrobrazi to enable the refinery to coprocess about 90,000 tpy of vegetable and used cooking oils by 2025.
TRANSPORTATION Quick Takes
NLE to invest $1 billion in Keystone XL pipeline
Natural Law Energy (NLE) has agreed to make an equity investment of up to $1 billion in TC Energy Corp.’s Keystone XL pipeline project. The first phase of the transaction is expected to close third-quarter 2021, contingent on NLE securing financing.
As Keystone XL is built, TC Energy will create opportunities for additional Indigenous communities along the project’s corridor both in Canada and the US. The current initiative is in addition to the more than $600 million in Indigenous supplier and employment opportunities expected to be created during the pipeline’s construction. The agreement also allows the possibility of NLE pursuing an interest in future TC Energy liquids projects.
NLE was created as a coalition of First Nations in Saskatchewan and Alberta to pursue economic opportunities for the wealth and benefit of Indigenous Peoples.
Inpex awards McDermott Ichthys booster compression FEED
Inpex Corp. and its partners in the 8.9-million tonne/year Ichthys LNG field development awarded McDermott International Ltd. to provide front-end engineering and design (FEED) services for the project’s booster compression module. The award includes an option to perform engineering, procurement, and construction for the same module.
The booster compression module will be added to Ichthys LNG’s offshore central processing plant off the northwest coast of Western Australia. McDermott is also undertaking umbilicals, risers, and flowlines as part of expanding Ichthys LNG. The company will complete FEED at its Asia Pacific headquarters in Kuala Lumpur.
Ichthys LNG operates two onshore liquefaction trains at a plant near Darwin, Northern Territory, that has space for as many as four more. Gas is transported post-processing to the plant via an 890-km subsea pipeline.
Australia’s National Offshore Titles Administrator renewed Inpex’s Browse basin exploration permit earlier this year. The permit includes production license WA-51-L which contains Ichthys field. Its renewal will allow Inpex to continue exploration through mid-2025.
Inpex is operator of Ichthys LNG with 66.245%. Partners include Total (26%) and Australian subsidiaries of CPC Corp. (2.625%), Tokyo Gas (1.575%), Osaka Gas (1.2%), Kansai Electric Power (1.2%), JERA, (0.735%), and Toho Gas (0.42%).
TAP natural gas pipeline begins commercial service
The 10-billion cu m/year (bcmy) Trans Adriatic Pipeline has begun commercial operations. The start of natural gas shipments on the 878-km pipeline comes 4 1/2 years after the start of construction.
TAP is the European leg of the 3,500-km Southern Gas Corridor, connecting with the Trans Anatolian Pipeline at the Turkish-Greek border and crossing Greece (550 km), Albania (215 km), and the Adriatic Sea (105 km in as much a 810 m of water), before coming ashore in Italy (8 km). It delivers gas from Shah Deniz field in the Azerbaijan sector of the Caspian Sea to markets in Europe and is expandable to 20-bcmy.
Earlier this year TAP agreed to market its transportation capacity through the Prisma European Capacity Platform.
The pipeline is owned by BP (20%), State Oil Co. of Azerbaijan Republic (SOCAR, 20%), Snam SPA (20%), Fluxys SA (19%), Enagás SA (16%), and Axpo Holding AG (5%).