GENERAL INTEREST — Quick Takes
Statoil vacates Alaska Chukchi Sea leases
Statoil ASA reported it will vacate leases it holds in the Chukchi Sea off Alaska and close its office in Anchorage because they are no longer competitive. Its Nov. 17 action came after Shell Offshore Co. made a similar move with its Alaska federal offshore leases for the same reason (OGJ Online, Sept. 28, 2015).
"Since 2008, we have worked to progress our options in Alaska," said Tim Dodson, Statoil executive vice-president for exploration. "Solid work has been carried out, but given the current outlook we could not support continued efforts to mature these opportunities."
The decision means Statoil will leave 16 federal Chukchi Sea leases it operates, and its stakes in 50 tracts operated by ConocoPhillips Co. The leases were awarded in the a 2008 lease sale and are due to expire in 2020.
The US Bureau of Safety and Environmental Enforcement denied Shell and Statoil's request for suspensions on Oct. 16, which would have allowed them to retain leases in the Beaufort as well as Chukchi Seas beyond their original 10-year terms (OGJ Online, Oct. 16, 2015). The Beaufort Sea leases are due to expire in 2017.
Dodson said Statoil's studies, research, and activities in Alaska have given the firm skills and expertise that it can leverage in other northern environment opportunities in the future. "Our understanding of the challenges and opportunities has increased considerably over the last years," he indicated.
US Senate Energy and Natural Resources Committee Chair Lisa Murkowski (R-Alas.) expressed concern that a second company with federal leases off Alaska's coast decided to walk away in as many months.
"Low oil prices may have contributed to Statoil's decision, but the real project killer was this administration's refusal to grant lease extensions; its imposition of a complicated, drawn-out, and ever-changing regulatory process; and its cancellation of future lease sales that have stifled energy production in Alaska," Murkowski said.
API to Obama: Emphasize market-driven climate tactics
When Obama administration representatives arrive in Paris for upcoming global climate talks, they should stress the successful market-driven approach that helped the US lead the world in reducing greenhouse gas emissions while increasing its oil and gas production, the American Petroleum Institute urged.
"There should be no place for dogmatic adherence to ideology," API Pres. Jack N. Gerard told reporters in a Nov. 16 teleconference. "The US has an opportunity to show how it has reduced greenhouse gas emissions even as it has increased energy production. Our success is driven by investment, innovation, and entrepreneurial spirit."
Gerard noted that a new analysis by API, using US Energy Information Administration and World Bank data, finds states could reach goals more efficiently under the administration's Clean Power Plant using more gas instead of wind and solar.
Gerard also cited US Environmental Protection Agency figures showing methane emissions from US oil and gas operations are plummeting, with the largest reductions coming from hydraulically fractured natural gas wells.
"The fact is that the nation's 21st century energy renaissance, which has made domestically produced natural gas cheap and abundant, has helped us achieve substantial and sustained emissions reductions without command and control style regulatory intervention," said Gerard. "By contrast, the administration continues to hew to last century's thinking that increased energy production and achieving climate goals are mutually exclusive, pursuing costly government mandates to detriment of the American consumer and our economy.
"Our message is we're achieving true emissions reductions in the real world without government directives," he maintained. "The key point we're making that the US has shown it is the leader in carbon emission reduction around the world. This administration needs to remember this success story. The US model, as evidenced by recent history, clearly works."
UK energy policy to cut coal, boost gas
The UK, in a major policy shift, will boost the use of natural gas and nuclear energy, end the use of coal within 10 years, and limit subsidization of renewable energy.
Speaking Nov. 18 at the Institution of Civil Engineers in London, Amber Rudd, secretary of state for energy and climate change, said, "Energy security has to be the No. 1 priority."
UK energy policy in recent years has centered on combating climate change, relying on heavy subsidies for renewable energy that have made UK electricity prices among the highest in Europe. In her speech, Rudd asked a question indicating a policy turn toward a balance of interests: "How do we achieve an energy system that is secure, affordable, and clean?"
The energy secretary said the government will propose to begin restricting coal use for power generation in 2023 and to close all coal-fired power stations by 2025.
"One of the greatest and most cost-effective contributions we can make to emission reductions in electricity is by replacing coal-fired power stations with gas," she said. The coal phaseout will proceed only "if we're confident that the shift to new gas can be achieved within these timescales."
She said nuclear energy and gas both are "central to our energy secure future."
But nuclear power has to be affordable, she added, declaring, "Green energy must be cheap energy."
Rudd cited UK progress toward development of an offshore wind industry but said: "It is still too expensive. So our approach will be different. We will not support offshore wind at any cost. Further support will be strictly conditional on the cost reductions we have seen already accelerating."
The government already has cut subsidies for solar energy.
Schlumberger-Cameron merger cleared by US DOJ
The proposed $14.8-billion merger of Schlumberger Ltd. and Cameron International Corp. has been unconditionally cleared by the US Department of Justice, granting early termination of the waiting period required by the Hart-Scott-Rodino Antitrust Improvements Act (OGJ Online, Aug. 26, 2015).
Completion of the proposed merger remains subject to approval by Cameron stockholders and the satisfaction or waiver of other closing conditions in the merger agreement. A special meeting of Cameron stockholders is scheduled for Dec. 17, during which they are expected to cast their votes.
Schlumberger and Cameron expect to close the merger in first-quarter 2016. Until then, the companies will continue to operate separately and independently.
Exploration & Development — Quick Takes
E. Newfoundland's 2015 round draws $1.2 billion in bids
The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) received 13 bids totaling more than $1.2 billion for its NL15-01EN, the first call for bids in the Eastern Newfoundland region under the scheduled land tenure system (OGJ Online, July 6, 2015). C-NLOBP offered 11 offshore parcels totaling more than 2.5 million hectares in the Flemish Pass basin. The 13 bids included 9 companies and 7 parcels were awarded during the license round.
Several companies were awarded sole operatorship for several blocks including NL15-01-09, on which Statoil ASA successfully bid more than $423 million for 100% interest. The block is adjacent the operator's Mizzen discovery in 2009, and Harpoon and Bay du Nord discoveries in 2013 (OGJ Online, Sep. 26, 2013). Nexen Energy ULC was awarded 100% interest in Block NL15-01-10, located to the south of Statoil's recent discoveries. According to C-NLOPB documents, the company bid $261 million for the parcel.
Block NL15-01-02 was awarded to partners Chevron Canada Ltd., Statoil Canada Ltd., and BG International Ltd. Chevron will lead as operator on the first block with 35% interest, with 35% and 30% interest to Statoil and BG, respectively.
On NL15-01-05, Statoil has an operating interest of 40%, with partners ExxonMobil Canada Ltd. 35%, and BG 30%.
Three additional Statoil operated blocks include NL15-01-06 with Statoil 34% as operator, ExxonMobil 33%, BP Canada Energy Group ULC 33%; NL15-01-07 with Statoil 34% as operator, ExxonMobil 33%, BP 33%; and NL15-01-08 with Statoil 50% and BP 50%.
C-NLOPB's announcement included several parcels with unsuccessful bids: NL15-01-01, NL15-01-02, NL15-01-04, and NL15-01-04.
Statoil now holds an extensive position in Flemish Pass. In November 2014, Statoil undertook an 18-month exploration drilling program in the Flemish Pass to further appraise the Bay du Nord discovery and test new prospects in the great basin area. Husky Energy Inc. partners with Statoil with 35% interest in Bay du Nord.
Deepwater parcels awarded offshore Nova Scotia
The Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) has awarded two of its deepwater parcels. Statoil ASA committed to spend $82 million to explore Blocks NS15-1 Parcel 1 and Parcel 2. The offshore blocks are in 1,050-3,100 m of water about 250 km from Halifax, NS. They cover a combined 650,000 sq km.
In May 2015, Nova Scotia announced the availability of seven new offshore deepwater blocks. Parcels 1 and 2 are adjacent to Shell Canada Ltd.'s deepwater acreage acquired in 2012 with partners Suncor Energy Ltd. and ConocoPhillips (OGJ Online, May 11, 2015).
C-NSOPB said Shell spudded its first exploration well on the Scotian shelf, Cheshire L-97, on Oct. 23. As of Nov. 11, the projected 7,532-m well had reached a depth of 3,326 m. The well is being drilled by the Stena IceMax in 2,143 m of water.
Newfoundland Labrador 2015 seismic season closes
The fifth consecutive acquisition season offshore Newfoundland Labrador has closed for 2015, according TGS-NOPEC Geophysical Co. The current season yielded more than 27,000 km of 2D multiclient seismic data and two multiclient 3D surveys, both in excess of 4,000 sq km.
TGS is partnered with Petroleum Geo-Services in the region. The joint venture library now includes 112,000 km of modern, long-offset, broadband 2D seismic data and 9,000 sq km of 3D seismic data. The library includes 83,700 km of TGS vintage data (OGJ Online, May 11, 2015).
Drilling & Production — Quick Takes
BG plans billion-dollar drilling campaign in Queensland
BG Group PLC has been given the green light to begin a $1.7-billion (Aus.) drilling program in Queensland's Surat basin as part of its commitment to the coal seam-based LNG project in Gladstone.
Up to 400 wells will be drilled in the next 2 years to maintain gas supply to the LNG plant.
Called the Charlie project, the drilling will take place west of the town of Wandoan. Leighton Contractors has won the main contract for the work.
Environmental approval for Charlie was granted by the federal government in December of last year.
BG began shipments of LNG from its Curtis Island plant near Gladstone in January and has delivered 62 cargoes since then to Asian markets. The group needs to continue drilling new wells every year to maintain supplies.
China National Offshore Oil Corp. and Tokyo Gas Co. Ltd. are partners in the group and will fund part of the work. However BG will bear most of the cost because it has 73.5% interest in the gas permits.
The project also includes the laying of 725 km of water and gas gathering lines as well as a compression station, power lines, and water handling facilities. The facilities will be spread over an area of about 2,500 hectares.
Aje field offshore Nigeria ready to begin production
Panoro Energy ASA, Oslo, reported the completion of the Aje-4 well in the Benin basin's Aje field offshore Nigeria. Oil production is slated to begin by yearend at an initial rate of 10,000 b/d.
The well is connected by subsea manifold and production flowlines to Rubicon Offshore International's floating production, storage, and offloading vessel, First Puffin, which produced oil from Puffin field in the Timor Sea.
Aje field lies 24 km offshore and is estimated to contain 200 million bbl of 2C contingent resources in Cenomanian-age reservoirs. Additional resources may be present in a separate reservoir and these may be accessed through a Stage 2 development comprising two more wells.
Yinka Folawiyo Petroleum Co. Ltd., which operates oil mining lease (OML) 113 on which Aje-4 sits, discovered the field in 1996, drilling appraisal wells Aje-1 and Aje-2 to confirm oil pay in the Turonian and Cenomanian reservoirs respectively. By 2004, Yinka was seeking partnerships to develop the field and drill Aje-3 to confirm the structural interpretation of the field and determine fluid distribution (OGJ Online, Sept. 3, 2004).
Aje-4 was drilled in 2008. Oil and gas accumulations were reevaluated and the field was declared commercial. Field development entered its first phase in 2014 with a $220-million investment (OGJ Online, Oct. 10, 2014).
OML 113's term runs through July 2018 and may be extended by the Nigerian government.
Yinka is operator with 25% interest in the field.
NPD gives go-ahead for Edvard Grieg production start-up
The Norwegian Petroleum Directorate (NPD) has granted consent to start production from the Lundin Norway AS-operated Edvard Grieg field on Production License 338 in the North Sea.
Production is expected to begin toward yearend. Development costs have increased slightly, but within the uncertainty range of +/-20% in the plan for development and operation investment projections, NPD says.
Edvard Grieg-on the Utsira High about 35 km south of Grane and Balder fields-is developed with a standalone processing platform on a steel-jacket structure (OGJ Online, Apr. 14, 2015).
Oil will be transported through the Edvard Grieg oil pipeline (EGOP) to the Grane pipeline, and then on to the Sture terminal north of Bergen. Gas will be transported via the Utsira High gas pipeline (UHGP), which is tied-in to the Scottish Area Gas Evacuation (SAGE) pipeline on the UK side.
The NPD earlier this month greenlighted start-up of the EGOP and UHGP systems (OGJ Online, Nov. 6, 2015).
Oil and gas from neighboring Ivar Aasen field will be processed on Edvard Grieg, and then routed through the same transport systems. Production start-up on Ivar Aasen is scheduled for late 2016.
PROCESSING — Quick Takes
Takreer commissions Ruwais refinery expansion
Abu Dhabi Oil Refinery Co. (Takreer) has completed a long-planned expansion project designed to double crude processing capacity of the Ruwais refining complex in the United Arab Emirates, about 385 miles west of Abu Dhabi City (OGJ Online, Feb. 9, 2011).
The Ruwais crude capacity expansion has been fully commissioned, with the refining complex now operating at 100% rates at its newly expanded capacity of more than 800,000-b/d, Jasem Ali Sayegh, Takreer's chief executive officer, told local news agencies on Nov. 11
In addition to a new 417,000-b/d crude distillation unit (CDU), other recently commissioned units now operating at full production include associated hydrotreating units, while a new 127,000-b/d residue catalytic cracking (RFCC) unit continues to ramp up to full operating rates from its current production capacity of about 75%, according to the company.
Alongside the CDU and RFCC, the expanded Ruwais refinery, which initially was due to be completed in 2013 (OGJ Online, Feb. 26, 2008) before a delay to first-half 2014 (OGJ Online, Dec. 1, 2014, p. 34), also was to include the following units: a 200,000-b/d vacuum distillation unit, a 57,000-b/d hydrocracker, a 69,000-b/d naphtha hydrotreater, a 108,000-b/d kerosine hydrotreater, a 75,000-b/d diesel hydrotreater, a 37,000-b/d gasoline hydrotreater, and a 23,000-b/d isomerization (C4) unit.
Takreer previously said it planned to invest about $10 billion in the Ruwais expansion.
South Korean firm plans ethylene capacity expansion
Korea Petrochemical Industry Co. Ltd. (KPIC), Seoul, has let a contract to Mitsubishi Hitachi Power Systems Ltd. (MHPS) to supply power generation technology and equipment as part of a broader project designed to expand ethylene production capacity at its 470,000-tonne/year Onsan Naphtha Cracking Center (NCC) in Ulsan, South Korea.
MHPS will deliver its proprietary gas-fired H-25 turbine, as well as a generator, to expand capacity of NCC's in-house power generation system in order to accommodate KPIC's plan to nearly double ethylene production at Onsan, MHPS said.
Capable of using methane off-gas derived from NCC to fuel the Onsan plant, the new power generation system is scheduled to be commissioned in June 2017, according to the service provider.
A value of the contract was not disclosed.
MHPS, which supplied the Onsan plant with its first H-25 gas turbine in 2006, said KPIC intends to boost NCC's ethylene production capacity to 800,000 tpy.
A startup timeframe for the proposed ethylene expansion, however, has yet to be disclosed.
In addition to ethylene, KPIC's produces 350,000 tpy of propylene, 110,000 tpy of benzene, 55,000 tpy of toulene, 35,000 tpy of m-Xylene, and 200,000 tpy of ethylene oxide-ethylene glycol.
Contract let for hydrogen plant at Montana refinery
US farmer-owned cooperative CHS Inc. has let a contract to Technip SA, Paris, to build a grassroots hydrogen plant at its 55,000-b/d refinery at Laurel, Mont. (OGJ Online, Sept. 2, 2015).
Technip, which plans to execute the project out of its Claremont, Calif., office, will deliver engineering, procurement, and construction (EPC) services for the proposed hydrogen plant, which is to have a production capacity of 40,000 normal cu m/hr, the service company said.
As part of the EPC contract, Technip will equip the plant with its proprietary top-fired steam reforming technology for the production of high-purity hydrogen as well as the export of steam.
The plant's design also will include the latest nitrogen oxide-reduction technology to limit omissions to a minimum, according to Technip.
The hydrogen plant is due to be completed in 2017.
Technip valued the contract at €50-100 million.
In addition to previously supplying a steam reformer and parallel reformer for the Laurel refinery, Technip also completed two hydrogen projects for CHS's 85,000-b/d refinery in McPherson, Kansas, the service provider said.
First announced in 2014, the Laurel hydrogen plant project comes as part of CHS's broader strategy to boost overall efficiency, diesel production, and crude processing flexibility at its two refineries to help meet fuel demands of its rural-American market base (OGJ Online, Sept. 4, 2014).
At the Laurel refinery, CHS said it would invest more than $400 million in upgrading projects, which in addition to the new hydrogen plant, will include modifications to an existing crude unit at the site.
Both projects are aimed at increasing the refinery's crude throughput rates as well as its production of diesel, the company said.
The Laurel upgrade also will involve modifications to an existing hydrocracker that, alongside further expanding diesel output, will enable the refinery to process a more flexible slate of crudes and limit production interruptions.
TRANSPORTATION — Quick Takes
Ban looms on tankers off northern British Columbia
Canadian Prime Minister Justin Trudeau appears ready to fulfill a campaign promise to ban crude oil tankers off northern British Columbia in a move that would throw the proposed Northern Gateway Pipeline into question.
The $6.5 billion, 1,177-km twin pipeline proposed by Enbridge Corp. would carry blended bitumen from Alberta to a terminal at Kitimat, BC, and return diluent to Alberta.
Trudeau, whose Liberal party won a pivotal election Oct. 19, has asked new Transport Minister Marc Garneau to make the crude-oil tanker ban a priority, according to press reports.
As a potential link between the Canadian oil sands and global trade, the Northern Gateway proposal gained importance when US President Barack Obama on Nov. 6 rejected TransCanada Corp.'s application for the border crossing of the Keystone XL project, which would have increased pipeline capacity between Alberta and the US Gulf Coast (OGJ Online, Nov. 6, 2015).
TransCanada also has proposed a project called Energy East, which would link the oil sands with eastern Canadian provinces and the Atlantic.
TransCanada withdraws Keystone route application
TransCanada Corp. formally notified Nebraska's Public Service Commission that it is withdrawing its revised route application for the proposed Keystone XL crude oil pipeline.
The move came after the Obama administration's Nov. 6 denial of the project's cross-border permit after more than 7 years of delays (OGJ Online, Nov. 6, 2015).
The company, which filed the application with Nebraska's PSC in early October, said on Nov. 18 that it did not seem appropriate to keep it active following the administration's permit denial action.
"Although we are withdrawing the application at this time, we are reserving the right to reapply to the PSC at a later date and remain committed to completing the final leg of the Keystone Pipeline system, [which] has already safely delivered over 1 billion bbl of Canadian and US crude oil to the Midwest and Gulf Coast," it said in a statement.
