GENERAL INTERESTQuick Takes
US late-November oil exports top imports
The US exported more crude oil and petroleum products than it imported during the week ending Nov. 30, according to the Energy Information Administration’s Weekly Petroleum Status Report.
The country thus became a net oil exporter for the first time since World War II, at the end of which US oil exports exceeded imports. By 1950, the US had become a net oil importer, a status unchanged until now.
But the margin is narrow and reflects only a single week’s data.
EIA estimates exports of oil—including crude, products, and fuel ethanol—in November’s last week at 9.049 million b/d, only 211,000 b/d above imports.
Crude-oil imports during the week exceeded exports by 4.016 million b/d, while product exports topped imports by 4.227 million b/d.
OPEC’s output averaged 33 million b/d last month
The Organization of Petroleum Exporting Countries produced 32.97 million b/d on average for November, down 11,000 b/d from October, secondary sources to the cartel reported Dec. 12 in its Monthly Oil Market Report.
Saudi Arabia’s production climbed by 377,000 b/d from October to November to reach 11.01 million b/d.
The Saudi production increase was offset by supply declines from Iran—whose oil exports are under US sanctions—as well as Venezuela, Nigeria, and Iraq.
The latest report comes after OPEC and some non-OPEC countries announced a 1.2 million-b/d cut in production starting Jan. 1, 2019 (OGJ Online, Dec. 7, 2018). The cut is based on October production levels. OPEC countries agreed to cut production by 800,000 b/d, while Russia and nine allied producers collectively will cut 400,000 b/d.
The production cut was agreed upon in OPEC’s efforts to support oil prices, which have declined about 30% since early October. Analysts blamed recent price declines on oil investors’ concerns about rising world oil supplies.
Chevron’s 2019 budget includes short-cycle projects
Chevron Corp. estimates it will spend $20 billion in 2019 to support its upstream and downstream projects.
The company’s 2019 capital and exploratory budget is “highlighted by our world-class Permian basin position, additional shale and tight development in other basins, and our major capital project at TCO in Kazakhstan,” said Michael K. Wirth, chairman and chief executive officer. “Our investments are anchored in high-return, short-cycle projects, with more than two thirds of spend projected to realize cash flow within 2 years.”
Upstream, some $10.4 billion is earmarked to sustain and increase currently producing assets, including $3.6 billion for the Permian and $1.6 billion for other shale and tight investments, the company said. About $5.1 billion of the upstream program is planned for major capital projects now under way, including $4.3 billion associated with the Future Growth Project at Tengiz oil field in Kazakhstan (OGJ Online, July 5, 2016). Global exploration funding is expected to be $1.3 billion. The remaining upstream capital will be for early-stage projects supporting potential future developments.
About $2.5 billion of planned capital spending is associated with the company’s downstream businesses, Chevron said.
Cenovus to focus 2019 budget on oil sands projects
Cenovus Energy Inc., Calgary, expects to allocate the majority of its planned 2019 budget of $1.2-1.4 billion to sustain base production at its Foster Creek and Christina Lake oil sands operations. The company also plans to complete construction of the Christina Lake Phase G expansion (OGJ Online, Dec. 9, 2016). With an approved design gross capacity of 50,000 b/d, production startup from the expansion is expected in second-half 2019.
The company said efficiency improvements at its oil sands operations and a reduction in Deep basin development plans due to the current commodity price environment result in a 4% reduction in total planned capital spending compared with its 2018 forecast. Currently, the company is marketing a package of noncore properties in the East Clearwater area of the Deep basin.
Manchin named Senate Energy panel’s top Democrat
US Sen. Joe Manchin (D-W.Va.) will become the Energy and Natural Resources Committee’s ranking minority member when Congress reconvenes in January, it was announced on Dec. 12. He will succeed Maria E. Cantwell (D-Wash.), who has been the committee’s top Democrat since January 2015.
“This committee has a long history of bipartisanship that has helped propel our nation’s energy technology forward,” said Manchin, who has been a member since he was sworn to succeed the late Sen. Robert C. Byrd in November 2010 after 6 years as West Virginia’s governor.
“West Virginia is a leading energy producer and major contributor to advanced energy technologies, and I intend to ensure this progress is continued,” Manchin said.
Exploration & DevelopmentQuick Takes
French Guyana: Total commits to exploration campaign
Total SA reported on plans to begin its exploration campaign on the Guyane Maritime license, 150 km off French Guyana. Total’s objective on the license is to drill one last exploration well, following the five formerly drilled during 2011-13 to conclude definitively whether an exploitation phase is relevant.
Addressing environmental concerns about operating in the area, Total said the closest reef is 30 km from the drilling area in 100 m of water and is not coral. The company plans to drill in 2,000 m of water.
“According to the scientists who carried out a 50-day oceanographic survey on-site in 2017, including those from the Paris National Museum of Natural History, it is a discontinuous rocky plateau, on the edge of the continental shelf, presenting scattered biological communities where hundreds of samples have been taken for study,” the company said.
Total said it will report on the progress of its drilling throughout the process, as part of the Committee for Monitoring and Consultation. This commission, led by the authorities, includes 50 economic and social actors.
Total invites national government organizations, who wish to do so, to visit its installations to understand the precautionary measures taken on its drilling rig and to create an opportunity for reasoned dialogue, the company said.
Total said there are 200 people on board its drilling ship and the five support vessels around it. As such, a safety perimeter forbids navigation of all unauthorized watercraft within 500 m of the well.
The Guyane Maritime license is an existing exploration license that was awarded in 2001. Its extension was requested in March 2016 and granted on Sept. 14, 2017. The license covers 24,000 sq km beyond the Guyanese continental shelf.
Total signs E&P contracts for blocks off Mauritania
Total SA and the Ministry of Petroleum, Energy, and Mines of Mauritania have signed an agreement awarding Total two exploration and production contracts for Blocks C15 and C31 deep offshore Mauritania, covering a 14,175-sq km area. Based on the contracts, Total will serve as operator of these two blocks with a 90% interest alongside the Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (SMHPM), which will hold the remaining 10%.
Combined with its participation interest and operatorship in Blocks C7, C9, and C18, the award of these latest blocks “strengthens Total’s position in the emerging hydrocarbons basin offshore Mauritania,” the company said.
“This agreement contributes to the implementation of Total’s strategy that aims to explore basins in proven yet underexplored petroleum systems,” said Arnaud Breuillac, president, E&P.
According to its exploration program, Total has plans to drill a well on Block C9 in 2019.
YPF, Petronas plan Vaca Muerta development
The state-owned companies of Argentina and Malaysia are forming a joint venture to invest $2.3 billion over 4 years in Vaca Muerta shale development in the Latin American country.
According to press reports of an announcement by the office of Argentine President Mauricio Macri, the work will be on the Amarga Chica block in the province of Nequen, where YPF and Petronas have worked together on exploration and pilot production (OGJ Online, Aug. 28, 2014).
According to the reports, the companies, each with half-interest, hope to produce 60,000 boe/d of oil and gas by 2022. Investment might reach $7 billion over 20 years.
YPF works jointly with other international operators on other licenses in its 12,000-sq-km Nequen basin concession.
Groups sue to stop Mid-Atlantic OCS seismic surveys
Nine environmental organizations have sued US Commerce Sec. Wilbur L. Ross and the National Marine Fisheries Service (NMFS) on Dec. 11 after NMFS issued incidental harassment authorizations on Nov. 30 to five contractors seeking to conduct the first seismic surveys since the 1980s for oil and gas on the US Mid-Atlantic Outer Continental Shelf (OGJ Online, Nov. 30, 2018).
The Sierra Club, Oceana, Natural Resources Defense Council, and other national organizations were joined by groups from North Carolina and South Carolina in their filing in US District Court for South Carolina. They charged that NMFS violated the 1973 Endangered Species Act by deciding, contrary to the best available science, that the offshore seismic tests would not harm the North Atlantic right whale and other threatened and endangered species in the waters.
BOEM extends comment period for Beaufort Sea sale
The US Bureau of Ocean Energy Management has extended the public comment period for a proposed environmental impact statement (EIS) relating to a proposed 2019 Beaufort Sea oil and gas lease sale, the agency’s Anchorage office said on Dec. 11.
Due to disruptions caused by the Nov. 30 Anchorage-area earthquake, the comment period, formerly scheduled to end Dec. 17, will now end Jan. 4, 2019, it said.
BOEM already has held one public meeting on the matter, but has rescheduled three others, it said. Those meetings now will be held in Utiqiagvik (Barrow) on Dec. 17, Nuiqsuit on Dec. 18, and Kaktovik on Dec. 19, the agency said.
Drilling & ProductionQuick Takes
ADNOC sells interest in onshore concession
Abu Dhabi National Oil Co. (ADNOC) reported that a 4% stake in its onshore concession has been acquired by North Petroleum International Co. Ltd., a subsidiary of China ZhenHua Oil Co. Ltd. Previously, the stake was held by CEFC China Energy Co. Ltd.
The ownership change has been approved by Abu Dhabi’s Supreme Petroleum Council and is in line with the UAE leadership’s directives to grant access to Abu Dhabi’s oil and gas concessions to partners who offer technology, operational experience, capital, or market access.
China ZhenHua Oil is 100% indirectly owned by the Assets Supervision and Administration Commission of the State Council, a Chinese-government agency that supervises and manages more than 100 state-owned assets and enterprises in a variety of businesses including telecommunications, oil and petrochemicals, and transportation.
China ZhenHua Oil operates 11 oil and gas upstream projects in six countries, with gross production of close to 10 million tonnes/year. The company joins BP PLC 10%, Total SA 10%, China National Petroleum Corp. 8%, Inpex Corp. 5%, and GS Energy 3% as participants in the onshore concession and shareholders of ADNOC Onshore. ADNOC retains a majority 60% share in the ADNOC Onshore operated concession.
Troll Phase 3 moves ahead with PDO approval
Equinor will work with partners and suppliers to bring on stream Phase 3 of giant Troll oil and gas field in the Norwegian North Sea in the first half of 2021 following approval of its development and operation plan (PDO) (OGJ Online, July 3, 2018).
The Ministry of Petroleum and Energy approved the plan, which includes the installation of two subsea templates and drilling of eight production wells targeting natural gas reserves in the Troll West structure and tied back to the Troll A platform with a 36-in. pipeline. According to Equinor, Phase 3 extends the plateau production for gas from the Troll field by about 7 years, and the expected productive life by about 17 years.
Troll field has produced 33 billion boe of oil and gas since production began in 1995. The Norwegian Petroleum Directorate estimates remaining reserves of 38 billion boe. Capital expenditures of 7.8 billion kroner will help extend the productive life of the Troll field beyond 2050.
“Troll is the biggest gas producer on the NCS, meeting 7-8% of Europe’s total daily gas consumption,” said Gunnar Nakken, Equinor’s senior vice-president for operations west.
Torger Rod, Equinor’s senior vice-president for project management, said Troll Phase 3 has a breakeven of less than $10/bbl and can deliver another 2.2 billion boe from the field with a carbon dioxide intensity of 0.1 kg/bbl.
The partnership let marine installation and subsea facilities contracts to Nexans, Deep Ocean, IKM, Allseas, and Marubeni. Contracts for subsea facilities and the construction of a new processing module on the Troll A platform were awarded to Aker Solutions (OGJ Online, May 16, 2018).
Operator Equinor holds a 30.58% interest. Other interests are Petoro 56%, Norske Shell 8.1%, Total E&P Norge 3.69%, and ConocoPhillips Scandinavia 1.62%.
PROCESSINGQuick Takes
Contract let for Russian hydrocracking complex
PAO Novatek subsidiary OOO Novatek-Ust-Luga has let a contract to Haldor Topsoe AS to supply proprietary technology for hydrogen production as part of a hydrocracking complex upgrade to be completed at its 120,500-b/d gas condensate fractionation and transshipment refinery at the all-season port of Ust-Luga on the Baltic Sea in Russia.
Alongside training of Novatek operators, Haldor Topsoe will deliver licensing, basic and detailed engineering, all equipment—including a pressure-swing adsorption (PSA) unit and water-treatment unit—steel structures, and catalyst for the 30,000-cu m hydrogen plant, which will be based on the modular Haldor Topsoe Convection Reformer (HTCR) technology, the service company said.
Novatek-Ust-Luga selected the preassembled skid-mounted HTCR unit for its ability to meet the operator’s strict requirements for minimal water consumption as well as the unit’s small footprint and fast delivery, Haldor Topsoe said.
Basic engineering on the hydrogen plant is under way, with the plant slated for full commissioning during second-quarter 2020.
When the hydrocracking complex is completed, Novatek-Ust-Luga will increase production of kerosine, diesel, and naphtha due to deep conversion of atmospheric residue after distillation of stable gas condensate, Haldor Topsoe said.
In its quarterly report to investors for the period ending Sept. 30, 2018, Novatek said it has completed the tender list of participants for the proposed project, with engineering surveys also now under way.
Main construction activities on the hydrocracker upgrade—which will cost an estimated 19 billion rubles—are scheduled to begin in 2019 and be completed by mid-2020, the operator said.
Started up in 2013, the Ust-Luga complex currently processes stable gas condensate into light and heavy naphtha, jet fuel, ship fuel component (fuel oil) and gas oil and enables Novatek to ship petroleum product products to international markets. The complex also allows for transshipment of stable gas condensate to export markets.
Contract details outlined for North Dakota refinery
McDermott International Inc. has confirmed details of its scope of work on previously awarded contract by Meridian Energy Group Inc. to finalize front-end engineering design for Meridian’s grassroots 49,500-b/sd high-conversion Davis refinery to be built in Billings County in the heart of southwestern North Dakota’s Bakken shale region (OGJ Online, Dec. 5, 2018).
McDermott plans to develop the FEED within the context of an anticipated modular execution and construction approach for the project, the service provider said.
Following conclusion of the FEED study, McDermott said both parties will endeavor to enter into an engineering, procurement, and construction agreement to build the refinery.
McDermott valued the FEED contract—which will be reflected in the service provider’s fourth-quarter backlog—at $1-50 million.
With site preparation and grading at the Davis site under way, Meridian said it currently is proceeding with final design, equipment fabrication, and procurement for the project.
Full construction activities and foundation work on the refinery are scheduled to resume in spring 2019 for a targeted commissioning date sometime in 2020.
The FEED and planned EPC agreements follow the North Dakota Department of Health’s division of air quality issuance in June to Meridian of the final permit-to-construct the project under the first application in history for a full-conversion refinery of this size and complexity to seek and receive permitting to construct under classification as a synthetic minor source of air contaminants (OGJ Online, June 13, 2018).
Once in operation, the refinery will produce ultralow-sulfur diesel and premium gasoline from prolific crude feedstocks from the Bakken shale basin using advanced technologies intended to maximize operational efficiencies while minimizing environmental impacts (OGJ Online, Dec. 6, 2017; Aug. 10, 2016).
TRANSPORTATIONQuick Takes
Yamal LNG begins Train 3 exports
PAO Novatek has begun LNG exports from Train 3 of its Yamal LNG plant in Russia, reaching the site’s planned full capacity of 16.5 million tonnes/year.
Novatek said it completed work on the 5.5-million tpy third train more than a year ahead of schedule. An additional 900,000-tpy train is under construction with startup planned for early 2020.
Yamal LNG, which shipped its first cargo in December 2017, is supported by a fleet of Arc7 ice-class tankers supplemented by lower ice-class tankers to transport LNG cargos. It has loaded more than 100 cargoes totaling about 7.5 million tonnes, Novatek said. Natural gas is sourced from the 4.6-billion boe onshore South Tambey gas and condensate field on the Yamal peninsula.
Novatek owns 50.1% of Yamal LNG, with Total SA (20%), China National Petroleum Corp. (20%), and Silk Road Fund (9.9%). The plant’s production is sold under long-term contracts based primarily on oil-indexed price formulas.
Novatek plans to produce 55-60 million tpy of LNG in Russia by 2030. It is partnered with Total in Arctic LNG 2 on the neighboring Gydan peninsula in northern Siberia. Arctic LNG 2’s planned capacity is 19.8 million tpy, using gas from the 7 billion-boe Utrenneye field. The project will involve installation of three gravity-based structures in the Gulf of Ob, each supporting a 6.6 million-tpy liquefaction train. The companies expect Arctic LNG 2 production to start in 2023.
EPIK plans Australia’s fifth proposed LNG terminal
South Korean developer EPIK, based in Seoul, has proposed the establishment of a floating LNG import terminal at the Port of Newcastle north of Sydney on Australia’s east coast.
EPIK has signed an agreement with the Port of Newcastle to conduct preliminary work on the project, which is expected to cost as much as $430 million (Aus.), including onshore infrastructure.
The company noted that based on its assessment of the New South Wales gas market, particularly in east coast centers like Newcastle and Sydney, the new low-cost floating storage and regasification unit (FSRU) terminal will be viable.
It will provide an infrastructure capable of providing a cost-effective source of alternative gas supplies to the region on a long-term basis.
The capacity of Newcastle LNG will be about 1.5 million tonnes/year. It would be the fifth LNG import terminal proposed to satisfy Australia’s future east coast demand—following one proposed for South Australia, two for Victoria, and one for New South Wales. However, analysts question the viability of multiple import facilities.
Adelaide-based consultancy EnergyQuest says that total domestic supply did fall by 18.8 petajoules in the September quarter because of lower production from Bass Strait, although this was offset by a 25% (or 16.6 petajoule) decline in gas use as coal and renewables replace gas in electric power generation. It is a trend that EnergyQuest expects will continue well into 2019.
On the other side of the argument, the consultant casts doubt on the ability of Queensland’s gas reserves to continue to make up the perceived future supply shortfalls further south along the east coast.
This has increased the perceived urgency and economic sense for the establishment of LNG import terminals at Port Kembla south of Sydney and at Crib Point on Western Port Bay in Victoria.
ADNOC, Inpex to study LNG bunkering
A unit of Abu Dhabi National Oil Co. and Inpex Corp. will assess potential for joint LNG bunkering development under a new framework agreement.
ADNOC Logistics & Services and Inpex will consider collaborating on LNG bunkering projects in Abu Dhabi and other regions, including Southeast Asia.
The companies cited expectations for increased use of LNG to fuel ships other than LNG carriers as desulfurization rules take effect for marine heavy oil in 2020.
