GENERAL INTEREST Quick Takes
BOEM rescinds March offshore lease sale
The Interior Department has rescinded the record of decision it has issued for an offshore oil and gas lease sale scheduled for March.
The Bureau of Ocean Management (BOEM) said it was rescinding the record of decision for Lease Sale 257 to comply with President Biden’s executive order establishing a moratorium on federal oil and gas leasing, both onshore and offshore.
Biden’s moratorium, under Executive Order 14008, required an indefinite halt to leasing while the new administration conducts a comprehensive review of oil and gas policy (OGJ Online, Jan. 27, 2021). No date was set for completion of the review.
Erik Milito, president of the National Ocean Industries Association, issued a statement expressing hope that Lease Sale 257 will be held after the policy review is completed.
“Pursuant to the Outer Continental Shelf Lands Act, Interior completed multiple environmental reviews and specifically considered the climate impacts in 2016 during the Obama administration,” Milito said.
“The Obama Administration review of the 2017-2022 Five Year Plan for offshore oil and gas leasing determined GHG emissions would be higher without these lease sales because energy production would be outsourced to foreign countries resulting in a higher carbon footprint,” Milito said, referring to greenhouse gas emissions that can contribute to climate change.
The oil industry may not be overly troubled if the lease sale is delayed only a short time, especially given the financial constraints companies are enduring because of the pandemic. Lease Sale 256 was delayed in 2020 from August to November to allow time for additional analysis of oil and gas markets in light of the pandemic (OGJ Online, Nov. 18, 2020).
The concern may be focused more on questions hanging over long-term policy. Jason McFarland, president of the International Association of Drilling Contractors, issued a statement expressing his disappointment and saying the BOEM decision “brings further uncertainty to the livelihoods of hundreds of thousands of American energy workers.”
Enerplus to acquire Williston basin operator
Enerplus Corp. has agreed to acquire all shares of Bruin E&P HoldCo LLC for total cash consideration of $465 million.
With the deal, Enerplus acquires 151,000 net acres in the Williston basin in North Dakota concentrated in the Fort Berthold area, including 30,000 net acres contiguous with Enerplus’ tier 1 acreage position. The acquisition includes about 24,000 boe/d day of existing production (72% tight oil, 14% NGL and 14% natural gas), 84 MMboe of proved plus probable reserves, and an inventory of 149 (111 net) drilling locations (including drilled uncompleted wells).
Upon closing, expected in early March, Enerplus estimates it will hold more than a decade of drilling inventory capable of sustaining production at 2021 levels, with additional drilling inventory upside on Bruin’s acreage if commodity prices strengthen.
The acquisition will be funded with a new $400 million term loan and a concurrent $115 million bought deal equity financing. Enerplus will not assume any debt of Bruin as part of the acquisition.
Assuming completion of the deal and a 10-month contribution from the Bruin assets to Enerplus’ 2021 results, the company expects to deliver 2021 production of 103,500-108,500 boe/d, including 63,000-67,000 b/d of liquids. Capital spending in 2021 is expected to be $335-385 million.
Triangle Energy acquires Perth basin assets
Triangle Energy (Global) Ltd. has agreed to acquire a 50% interest in production license PL L7 from Key Petroleum Ltd. as well as affiliate Key Midwest Pty Ltd.’s combined 86.94% interest in exploration permit EP 437, both onshore Perth basin, Australia. A wholly owned Triangle subsidiary will hold the relevant interests.
Triangle will assume all of Key’s ongoing work program commitments within EP 437, which requires acquisition of 20 sq km of 3D seismic and the drilling of one well prior to the end of the permit term’s 3rd year on May 27, 2022, with a second discretionary well due by the end of the permit term on May 22, 2023.
A larger 3D survey will be acquired across the area which will also tie into the existing Irwin 3D survey to the south and extend into EP 437 to the west. The primary aim is to provide a near complete coverage of the Bookara Shelf hydrocarbon fairway.
Triangle will pay to Key a cash consideration of $600,000 (Aus.), any outstanding cash calls in respect of L7 based on agreed work program and budget plus a 5% gross overriding royalty payable on production from L7 and EP 437.
At completion of the agreement, the existing farmout agreement between Key and Triangle in relation to L7 will terminate and the parties will release each other from all claims and liabilities with respect to L7.
Exploration & Development Quick Takes
PTTEP confirms gas discovery offshore Malaysia
PTT Exploration and Production Public Co. Ltd. (PTTEP), through subsidiary PTTEP HK Offshore Ltd. (Malaysia Branch), confirmed its largest-ever gas discovery with the Lang Lehah-2 appraisal well in the Sarawak SK 410B project offshore Malaysia.
The appraisal followed the gas discovery of its first exploration well, Lang Lebah-1RDR2, in 2019 (OGJ Online, June 28, 2019). Lang Lebah-2 was completed in mid-January 2021. Drilled to 4,320 m TD, the 600 m of net gas pay indicates a larger reservoir than the initial estimate. The well test shows a flow rate of 50 MMcfd of gas. The result will accelerate the development plan for the project.
Sarawak SK 410B lies 90 km offshore Sarawak, Malaysia. PTTEP HKO is operator with 42.5% participating interest. Partners are KUFPEC Malaysia (SK-410B) Ltd. (42.5%) and Petronas Carigali Sdn. Bhd. (15%).
Beach confirms Enterprise resource size
Beach Energy Ltd., Adelaide, has confirmed gas and condensate reserves in its Enterprise-1 discovery in inshore waters of the Otway basin of western Victoria.
The well, drilled from an onshore location into offshore permit VicP42(V), has led to a 2P reserves booking for the field of 34 MMboe. This includes 161 petajoules of gas, 352,000 tonnes of LPG, and 4 million bbl of condensate at an initial gas-condensate yield of 25 bbl/million cu ft.
The reserves estimate includes an allowance for expected reductions in condensate yield as the reservoir depletes, the company said.
The results are better than pre-drill expectations and the discovery will help to ensure a continued pipeline of gas to the nearby Otway gas plant which supplies the Australian east coast market, the company said.
Beach plans to commence front-end engineering and design (FEED) activities during the next few months, aiming for a final investment decision for Enterprise development during the 2021-22 financial year. First gas is expected during the first half of the 2022-23 financial year.
Further exploration in the vicinity of Enterprise using the Enterprise-1 onshore drill pad is expected.
Beach also has taken delivery of the Ocean Onyx semi-submersible drilling rig which is now on location preparing to spud the company’s Artisan-1 well in permit Vic/P43 further offshore.
Artisan-1 lies in 71 m of water about 32 km from the coast. It is the first well in a multi-well program in the region for Beach.
Beach is 60% interest holder and operator of both Vic/P42(V) and Vic/P43. OG Energy holds the remaining 40%.
LLOG signs infrastructure deal for Taggart development
LLOG Exploration Offshore LLC has signed an infrastructure agreement with Eni SPA related to development of the Taggart discovery in the deepwater Gulf of Mexico.
The agreement provides LLOG access to Eni and Marubeni Oil & Gas (USA) LLC’s existing subsea infrastructure connected to the Williams-owned Devils Tower Spar in Mississippi Canyon 773.
In June 2020, LLOG sanctioned its 100%-owned Taggart discovery and signed a production handling agreement for development via tieback to the spar (OGJ Online, June 17, 2020). Initial development plans include the completion and tie back of two wells with first production expected in first-half 2022.
Taggart was discovered on Mississippi Canyon Block 816 in 5,650 ft of water through the Mississippi Canyon 816 #1 discovery well in 2013. The well was drilled to 11,562 ft TD and encountered a total of 97 ft of net pay in two Miocene objectives. Two subsequent appraisal wells were drilled in 2015 and 2019 and encountered 147 ft and 84 ft of net pay, respectively.
Drilling & Production Quick Takes
88 Energy set to drill Merlin-1 wildcat
Perth-based 88 Energy Ltd. received approval from Alaskan authorities to drill its Merlin-1 wildcat in the National Petroleum Reserve-Alaska (NPR-A) region of the North Slope of Alaska.
The well is scheduled to spud in late February or early March and is part of the company’s Project Peregrine.
In anticipation of approval, field operations recommenced in January with commissioning of Rig 111 now nearing completion. Rig mobilization was scheduled to begin the first week of February. A single lane snow road to the location was expected to be complete by mid-February.
Merlin-1 is targeting a prospective resource of 645 million bbl. Flow testing is planned if wireline logging confirms a discovery.
88 Energy holds 100% working interest in the project that will reduce to 50% following completion of funding as part of a recent farm-in by a group of private US oil and gas professionals under umbrella company Alaska Peregrine Development Co. As part of the deal, 88 Energy is to be carried for the first $10 million of an estimated $12.6 million total cost for Merlin-1.
A second well, Harrier-1, with an expected cost of $7 million, is expected to immediately follow Merlin, subject to Merlin-1 results and permit approvals. The prospect has potential to hold 417 million bbl of prospective resource.
Both prospects target the region’s Nanushuk reservoir and lie between ConocoPhillips’ Willow oil discovery to the north and Umiat oil field to the south.
Wintershall completes Nova project top hole drilling
Wintershall Dea has progressed its Nova field project, having completed a low-emission top-hole drilling campaign 2 weeks ahead of schedule (OGJ Online, Oct. 22, 2020). The company will next move to drill three production wells and three water injection wells ahead of a planned production start in 2022.
Nova lies about 120 km northwest of Bergen and 17 km southwest of the Gjøa platform in the Norwegian North Sea in 370 m of water.
The recent campaign, carried out by the Seadrill-operated West Mira rig, involved drilling 3,400 m of top hole for the production and water injection wells on two different templates. Five of the six were drilled in one batch with repetitive operations.
Nova is being developed as a subsea tieback connecting two templates to the existing Neptune Energy-operated Gjøa platform. Gjøa will receive production fluids and provide injection water and lift gas to Nova field. Oil from Nova will be transported from Gjøa through the Troll Oil Pipeline II to Mongstad, and associated gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St. Fergus, UK, supplying the European energy market.
Wintershall Dea is operator at Nova (45%), with partners Spirit Energy Norge AS (20%), Edison Norge AS (15%), Sval Energi AS (10%), and ONE-Dyas Norge AS (10%).
Tullow takes cautious view of 2021 production
Tullow Oil PLC expects drilling of the Goliathberg-Voltzberg North exploration well on Block 47 (50%) in Suriname to begin shortly. News comes as part of the company’s 2021 outlook released Jan. 27. Work also continues developing prospect inventory on Orinduik and Kanuku licences offshore Guyana.
The group’s working interest oil production is forecast to average 60,000-66,000 b/d this year. The forecast reflects the drilling hiatus in 2020, a planned shut-down in September on Jubilee, and deferred development drilling on Simba in Gabon.
Capital expenditure for the year is forecast at $265 million with an additional $100 million to be spent on decommissioning.
In Ghana, oil production from Jubilee and TEN for the year to date is in line with expectations, supported by gas offtake from the government of Ghana of 125 MMscfd.
A new oil offloading system is being commissioned on Jubilee and is expected to be ready for a first lifting in February.
A drilling rig is being mobilized to Ghana to commence operations in the year’s second quarter. The first new production well on Jubilee is expected to be onstream in the third quarter.
In the non-operated portfolio, development drilling is restarting in Gabon and Equatorial Guinea, whilst decommissioning activity continues in Mauritania and the UK.
In Kenya, following approval of the 2021 work program and budget, Tullow received an extension to its exploration licenses to end-2021. Tullow and its joint venture partners are now reworking the development project and expect to submit a revised plan to the Kenyan government later this year.
In Côte d’Ivoire, Tullow has reduced its onshore exploration portfolio to focus on the CI-520 block.
For 2020, the group’s working interest oil production averaged 74,900 b/d.
PROCESSING Quick Takes
Orlen lets contract for Lithuanian refinery
PKN Orlen SA subsidiary Orlen Lietuva AB has let a contract to DuPont Clean Technologies, a division of E.I. DuPont de Nemours & Co., to provide technology licensing for a grassroots alkylation unit to be built at its 10-million tonnes/year refinery in Mažeikiai, Lithuania.
As part of the contract, DuPont Clean Technologies will supply alkylation and spent acid regeneration (SAR) technologies for the refinery, including licensing, engineering, and technical services for the proprietary STRATCO alkylation and MECS SAR units, DuPont said.
The STRATCO alkylation unit will use LPG in the conversion process to produce 6,000 b/sd of alkylate, while the 75-tonnes/day MECS SAR unit will provide the refinery a consistent supply of sulfuric acid to be used as catalyst for the alkylation unit.
Intended to help increase the Mažeikiai refinery’s complexity, flexibility, and profitability to ensure its long-term competitiveness, the STRATCO alkylation and MECS SAR units—both scheduled for startup in 2025—will enable Orlen Lietuva to generate low-sulfur, high-octane, low-RVP alkylate with zero olefins that meets Euro 6-quality standards, according to the service provider.
Orlen Lietuva’s ongoing modernization program at the Mažeikiai refinery also includes proposed construction of a residue conversion unit under the operator’s planned bottom-of-the-barrel (BOTB) improvement project, the company said in its latest annual report to investors. With contracts for technology licensing, basic design, and procurement already awarded, Orlen Lietuva said it expects to complete the BOTB project in 2023 at an estimated budget of $385.3 million.
In its latest annual report to investors, parent Orlen said a project to increase distillate yields also is under way at the Mažeikiai refinery. Further details regarding either the BOTB or distillate yields projects have yet to be disclosed.
IOC adding new processing unit at Haldia refinery
Indian Oil Corp. Ltd. (IOC) has broken ground on construction of a new processing unit to improve quality and production capacity of lubricant base oils at its recently expanded 8-million tonnes/year refinery in Haldia, Purba Medinipur, West Bengal, India.
Shri Narendra Modi, India’s prime minister, laid the foundation stone of the planned catalytic dewaxing unit in a ceremony on Feb. 7, the Indian government said in a release IOC reposted to its website.
Part of India’s commitment to produce cleaner fuels, the catalytic dewaxing unit—which, once in service, will be the Haldia refinery’s second—comes as part of IOC’s capacity augmentation of its Bharat Stage VI (BS-VI, equivalent to Euro 6) plant to produce low-sulfur fuels and help reduce India’s current reliance on imports of lube base oils, Modi said.
Start of construction on the project follows IOC’s 2019 contract award to Chevron Lummus Global LLC to deliver technology licensing and engineering for the 270,000-tonne/year lubricants base oil plant, which will be equipped with CLG’s proprietary Isodewaxing and Isofinishing technologies (OGJ Online, July 30, 2019).
First proposed in 2016, the catalytic dewaxing unit at Haldia will be equipped to produce 100% premium API Group III base oils by processing unconverted oil from an upstream hydrocracking unit at the refinery. The unit also will have the capability to produce API Group II base oils, as well as white oil and transformer oil as specialty products, according to a series of IOC official project documents filed with Indian regulators.
Granted final environmental clearance to proceed by India’s Ministry of Environment, Forest, & Climate Change on Jan. 5, 2021, the estimated 9.67-billion rupee catalytic Isodewaxing unit will include construction of new off-site and auxiliary installations, as well as a new piping system to interconnect the grassroots unit to existing units at the refinery, according to project documents.
In a 2019 description of the proposed project, IOC said the Haldia refinery currently operates a 200,000-tpy catalytic Isodewaxing unit for poruction of API Group II base oils.
The new unit is scheduled for startup by November 2022, according to IOC’s latest annual report to investors.
TRANSPORTATION Quick Takes
Venture Global closes loan funding Plaquemines LNG
Venture Global LNG Inc. has closed a $500 million term loan to fund pre-final investment decision construction activities on the 10-million tonne/year (tpy) Phase 1 of its Plaquemines LNG liquefaction plant, in Plaquemines Parish, La.
Venture Global plans to begin full construction of Plaquemines LNG in 2021. The company last year awarded Phase 1’s engineering, procurement, and construction contract to KBR (OGJ Online, Nov. 24, 2020).
It has contracted 3.5 million tpy of Phase 1 capacity under binding 20-year offtake agreements and received both US Department of Energy export authorization and final Federal Energy Regulatory Commission approval.
JPMorgan Chase Bank NA, Morgan Stanley Senior Funding Inc., Mizuho Bank Ltd., and Bank of America NA, all of which were lenders to Venture Global’s Calcasieu Pass LNG project, are funding the loan. The new loan was upsized to $500 million from $400 million based on strong lender interest, according to Venture Global.
Enbridge receives Line 5 tunnel environmental permit
Enbridge Energy has received approval from the Michigan Department of Environment, Great Lakes, and Energy (EGLE) for certain permits required to build a utility tunnel under the Straits of Mackinac to house a proposed replacement for Enbridge’s 68-year old, 540,000-b/d Line 5 dual petroleum products pipelines currently lying on the lakebed. EGLE’s review of the permit applications concluded that the proposed construction of a tunnel beneath the lakebed can be done in compliance with state environmental laws.
EGLE acknowledged public concerns about the existing oil pipeline and affirmed the Michigan Department of Natural Resources’ conclusion that the current pipeline violates the public trust doctrine and poses an unacceptable risk to the Great Lakes.
The permit approvals followed a 9-month review period and cover Enbridge’s National Pollutant Discharge Elimination System Wastewater Permit (NPDES), bottomlands, and wetlands permit applications. EGLE’s permit review confirmed that the proposed tunneling project would have minimal impact on water quality in the Great Lakes and would not affect protected public uses of Michigan’s water resources.
EGLE’s review determined that the proposed project would result in minimal impact to wetlands, estimating wetlands affected to be 0.13 acres, an area roughly one-tenth the size of a football field. Enbridge will be required to protect 1.3 acres of existing Great Lakes coastal wetlands and purchase wetlands credits from a state wetlands mitigation bank to address this impact.
“Although this proposed tunnel project has illuminated numerous related policy issues, the basis for our decision is required to be limited to compliance with the relevant environmental statutes created by our legislature,” said EGLE director Liesl Clark. “Our review showed construction of the proposed tunnel could comply with state environmental laws. We have issued permits designed to ensure that if a tunnel is constructed, it will be in strict compliance with relevant statutes and adhere to stringent protections against impacts to the Great Lakes.”
The EGLE permits do not resolve Michigan Gov. Gretchen Whitmer’s effort to shut down Line 5’s current operations. Enbridge is challenging those efforts in federal court (OGJ Online, Nov. 25, 2020). Permits from the Michigan Public Service Commission and the US Army Corp of Engineers also are still required.