OGJ Newsletter

April 3, 2017
International news for oil and gas professionals

Aramco president welcomes tax-rate cut

Saudi Aramco Pres. and Chief Executive Officer Amin H. Nasser welcomed a Mar. 27 tax cut that he said would bring his company's tax burden "in line with international benchmarks."

In a move seen as preparation for an initial public offering of 5% of the company as early as next year, the government lowered Aramco's tax rate to 50% from 85% (OGJ Online, Apr. 25, 2016). The change applies to "those authorized to operate in oil and hydrocarbon material production in the kingdom," according to a government statement.

The 50% rate applies to companies with capital investments in Saudi Arabia exceeding $100 billion. Rates of 65-85% apply to smaller investors.

In a follow-up statement, Finance Minister Mohammed bin Abdullah Al-Jadaan said the rate cuts won't hurt the government's ability to fund public services. He said revenue declines from the tax cut would be offset by dividends from state-owned companies and other investment income.

Canadian budget nips drilling preferences

Current-year deductibility of exploratory drilling costs succumbs to what the Canadian government describes as a campaign against "inefficient fossil-fuel subsidies" in a federal budget proposed Mar. 22.

The budget treats costs of successful exploration as those of development wells now are treated: written down over time on a declining-balance basis.

Costs of unsuccessful exploratory wells still could be charged to expense in the year of occurrence.

The budget also ends the current ability of small producers to expense costs of development drilling as they're incurred when the timing preference benefits flow-through investors.

"The government has a strong plan to invest in clean growth that will help create middle-class jobs and get the country on the path to a low-carbon economy," said the introduction to the changes in a budget document. "Consistent with this plan, Canada has made a commitment with its partners in the G20 and Asia-Pacific Economic Cooperation to phase out inefficient fossil-fuel subsidies. Such subsidies can encourage wasteful consumption, impede investment in clean energy sources, and undermine efforts to combat the threat of climate change."

Keep eastern gulf closed to leasing, Fla. lawmakers say

US Sen. Bill Nelson (D-Fla.) and 16 members of the US House of Representatives from the Sunshine State urged US Sec. of the Interior Ryan Zinke to keep the eastern Gulf of Mexico closed to oil and gas activity if he decides to develop a new 2017-22 US Outer Continental Shelf management plan.

"Drilling in this area threatens Florida's multibillion-dollar, tourism-driven economy and is incompatible with the military training and weapons testing that occurs there," they said in a Mar. 24 letter to the secretary. "If you do choose to draft a new plan, we strongly urge you to keep the eastern gulf off-limits."

Zinke has not said whether he plans to start considering a new 5-year OCS plan so soon after the Obama administration finalized one on Jan. 17 that begins on July 1. One of his predecessors as secretary, Dirk A. Kempthorne, started the process 2 years ahead of schedule in 2008 after global crude oil prices nearly doubled in a year to more than $120/bbl (OGJ Online, July 31, 2008).

When Congress passed the 2006 Gulf of Mexico Energy Security Act, it closed most of the eastern gulf to oil and gas activity, including all areas east of the Military Mission Line, Nelson and the other members of Florida's congressional delegation said in their letter.

"In 2015, the Department of Defense reiterated its opposition to offshore drilling activities in this vital training area," the federal lawmakers said.

Exploration & DevelopmentQuick Takes

New Zealand opens 2017 exploration permit round

The New Zealand government is hoping for a more positive industry response to its latest exploration permit round than it received in 2016.

Energy and Resources Minister Judith Collins announced the new round of eight blocks this week, calling for tenders to five offshore areas, two onshore areas, and one area a combination of both.

The offshore blocks include:

• One 150,566-sq-km area surrounding existing permits the Northland-Reinga basin (17NRN-R1).

• One 64,978-sq-km area surrounding existing permits in the Taranaki basin (17TAR-R1).

• One 49,630-sq-km area in the Pegasus-East Coast basin off the east of the north island (17PEC-R1).

• One 5,569-sq-km enclave in the Hawk Bay region in the East Coast basin (17PEC-R2).

• One 204,928-sq-km region surrounding existing permits in the Great South-Canterbury basin off the southeast of the south island (17GSC-R1).

The onshore blocks are:

• One 1,021-sq-km area in the Plymouth region of the Taranaki basin (17TAR-R2).

• One 3,568-sq-km block in the Great South basin at the southern tip of the south island (17SLD0-R1).

The combination onshore and offshore area covering 1,475 sq km is in the north Taranaki basin (17TAR-R3).

The blocks are being offered on a work program bid process. The offer is open until Sept. 6. The government expects to grant the successful tender offers in December.

Eni discovers oil with first Mexico well

Eni SPA discovered the presence of oil in the Amoca-2 well, the first drilled by an international operator in Mexico since the 2013 energy reform. The well lies in the Gulf of Mexico's Southeast basin 1,200 km west of Ciudad del Carmen in 25 m of water in Mexico's Campeche Bay. Eni was awarded the 67-sq-km block along with Amoca, Mizton, and Tecoalli fields in Mexico's National Hydrocarbons Commission Round One second tender in 2015 (OGJ Online, Sept. 30, 2015).

Amoca-2 reached a total depth of 3,500 m and encountered 110 m of net oil pay from several Pliocene reservoir sandstones, of which 65 m were in a deeper, previously undrilled horizon. Shallower formations contained 18° gravity oil. Eni said the newly discovered deeper sandstones "contain high quality light oil." The operator is assessing reserves.

The company will move ahead with its Area 1 drilling campaign with a new well in the Amoca area, Amoca-3, followed by the Mizton-2 and Tecoalli-2 delineation wells, which will be drilled this year to appraise existing discoveries as well as targeting new undrilled pools.

Eni holds a 100% stake in the Area 1 production-sharing agreement and is evaluating options for a fast-track phased development of the fields.

Cairn Energy group finds more oil offshore Senegal

A joint venture led by Cairn Energy PLC made an oil discovery in its VR-1 well offshore Senegal, notching up its eighth consecutive successful well in the region since drilling began in 2004.

Consortium member FAR Ltd., Perth, announced that the VR-1 well intersected a 97-m gross oil column across multiple reservoirs and recorded the highest net pay in any well drilled there to date.

Wireline logging and sampling through the SNE section of the well have been completed. VR-1 will now be deepened into the secondary Aprian carbonate objectives below SNE field.

VR-1 was drilled 5 km west of the SNE-1 discovery well and is being drilled to appraise the lower and upper reservoir units in the western sector of SNE field (OGJ Online, Mar. 8, 2017).

FAR said the Lower 520 reservoir, which is a key reservoir in plans for the Phase 1 development of SNE field, showed the best reservoir properties of all other reservoirs sampled in the field to date. VR-1 intersected a 16-m oil interval in this reservoir.

The deeper 540 reservoir, with an 11-m interval in oil, has only been seen previously in the SNE-2 well where the oil interval was just 2 m thick.

FAR anticipates that the results of the VR-1 well so far, together with the recent SNE-5 well results, will lead to a revision of contingent resources estimate for SNE field as well as impact the design of the development plan.

The 1C resource is currently estimated at 348 million bbl vs. the minimum economic field size of 200 million bbl.

FAR has 15% interest in SNE field. Cairn, ConocoPhillips, and Petrosen hold respective interests of 40%, 35%, and 10%.

Statoil submits development plans for Njord, Bauge

Statoil ASA has submitted plans for development and operation to the Norwegian Petroleum Directorate for Njord field and the nearby Bauge discovery, with total capital spending of 19.8 billion kroner. Production is expected to start in both areas in fourth-quarter 2020.

Njord, which began producing in 1997, was shut down in 2016 and the Njord A platform and Njord B storage ship were towed to shore for repairs and upgrades.

Operator Statoil and partners in the Njord Unit in production licenses 107 and 132 expect to spend 15.7 billion kroner on Njord. Investments include reinforcement of the hull of the Njord A platform, upgrade of deck equipment, the drilling of 10 production wells, and upgrades on the Njord B storage ship.

NPD said estimated remaining reserves at Njord are 6.2 million cu m of oil, 16.3 billion cu m of natural gas, and 4.1 million tonnes of natural gas liquids.

Bauge, 16 km northeast of Njord, will have expected investments of 4.1 billion kroner. Plans include the drilling of two production wells and one injection well, a pipeline to Njord A, and an umbilical from the subsea Hyme field.

NPD said Bauge was proved in 2013 with the 6407/8-6 well. Recoverable resources are estimated at 7.9 million cu m of oil, 1.9 billion cu m of gas, and 1 million tonnes of NGLs.

Statoil said Bauge will be the first user of Cap-X technology, a next-generation subsea production system. "Cap-X costs less to produce and install," said Margareth Ovrum, Statoil's executive vice-president for technology, projects, and drilling.

Drilling & ProductionQuick Takes

Maersk Oil to redevelop Danish North Sea's Tyra field

Maersk Oil has reached an agreement with the Danish government providing terms to enable the Danish Underground Consortium (DUC) partners to advance a full redevelopment plan for the Tyra field facilities toward a FID by yearend.

Pending FID, production from Tyra is now expected to stop in December 2019 instead of the previously planned permanent shuttering date of October 2018, and then restart in March 2022 on completion of redevelopment (OGJ Online, Jan. 3, 2017). The full redevelopment program requires a resequencing of engineering activities from the decommissioning and partial redevelopment scenario outlined in December 2016.

Tyra field has experienced subsidence of the chalk reservoir leading to the platforms sinking around 5 m in the last 30 years, reducing the gap between the sea and the platform decks. A full redevelopment would restore current infrastructure, including the gas processing hub and five surrounding satellite fields such as Harald and Valdemar.

Maersk adds that redevelopment also could enable future production of oil and gas from the DUC license area as well as third-party projects. Since 1984, Tyra has processed 90% of the Denmark's gas production.

Tyra field is operated by Maersk Oil on behalf of DUC, a partnership of AP Moller-Maersk with 31.2% interest, Royal Dutch Shell PLC 36.8%, Danish state-run Nordsofonden 20%, and Chevron Corp. 12%.

Phased expansion planned Odoptu Stage 2 in Russia

India's ONGC Videsh Ltd. said 32 wells are planned for a phased expansion of the Sakhalin I Odoptu development in Russia.

Extended-reach drilling from onshore to offshore in Odoptu Stage 2 is planned for two sites 9 km apart: the North Wellsite and the South Wellsite.

ONGC Videsh said the Krechet land rig, a new drilling rig, spudded its first well Feb. 28 after completing conductor driving for the first four wells. The company expects to reach measured depths of 13,300 m, along with total vertical depths of 2,000 m. The rig was fabricated in the Keppel AmFELS yard in Brownsville, Tex. Modules were shipped on five barges into the Sea of Okhotsk and Piltun Bay in the northeastern part of Sakhalin Island.

The fully enclosed drilling rig and pipe barn allow the crew to perform drilling in temperatures of 21° C. yearround.

The Odoptu Stage 2 development is expected to start production in the third quarter. The field is expected to reach its peak production of 65,000 b/d in 2018.

Odoptu Stage 1 oil and natural gas production began in 2010 (OGJ Online, Sept. 29, 2010).

Operator Exxon Neftegas Ltd. has 30% as does Sodeco. ONGC Videsh and Rosneft each have 20%.

Wintershall basing 2017 plans on $55/bbl Brent

Germany's Wintershall Holding GMBH increased oil and natural gas production 8% to 165 million boe in 2016, with higher volumes coming primarily from Norway and Russia.

"Russia is our most important core region," said CEO Mario Mehren at the company's annual press conference.

The company cited Russia and Argentina for low costs of production and reserve replacement.

Wintershall's proved reserves at yearend 2016 were 1.62 billion boe, and its reserves-to-production ratio was 10 years.

Nine of 14 exploration and appraisal wells drilled in 2016 discovered oil or gas compared with 17 of 25 in 2015.

The company's plans for 2017 are based on an average price of $55/bbl for Brent crude. The average price was $44/bbl in 2016 and $52/bbl in 2015.

Its key projects in the coming years will be Maria and Aasta Hansteen in Norway, the Achimov formation in Russia, and in the Tierra del Fuego and Neuquen provinces in Argentina.

Wintershall has a 50% share in the development of Block 1A of the Achimov formation in Urengoy field in western Siberia and plans to develop Blocks 4A and 5A. Also in western Siberia, the company said Yuzhno Russkoye gas field has been producing at plateau since 2009.

In Argentina, Wintershall has shares in 15 fields both onshore and offshore. It said offshore field Vega Pleyade "is a key project for Wintershall in Argentina and will make a vital contribution to the natural gas supply on the Argentinean market."

In Libya, with "difficult political conditions," Wintershall resumed production in September from onshore concession 96 "at a low level" of 35,000 boe/d.


Total partners to expand USGC petchem production

Total SA has signed a preliminary agreement with Nova Chemicals Corp., Calgary, and Borealis AG of Vienna to build a steam cracker and polyethylene (PE) production plant at Houston-based subsidiary Total Petrochemicals & Refining USA Inc.'s (TPRI) manufacturing sites along the Texas Gulf Coast.

Partners in the proposed joint venture would develop and hold ownership interest in both a grassroots, 1 million-tonne/year ethane steam cracker at Total's 178,000-b/d integrated refinery in Port Arthur, Tex., and a 625,000-tpy PE plant based on Borealis' proprietary Borstar PE process at Total's petrochemical production site in Bayport, Tex., the companies said.

Nova Chemicals and Borealis also would take ownership interest in Total's existing 400,000-tpy PE plant at Bayport.

Intended to help meet growing global demand for PE by taking advantage of competitively priced ethane feedstock from US shale production as well as easy export access to markets abroad, the cost-effective brownfield investment project also enables Total, Nova Chemicals, and Borealis to leverage existing synergies to help further integrate and expand their respective businesses in the Americas, the companies said.

Pending regulatory approvals, the JV is scheduled to form and final investment decision taken on the project by yearend, the companies said.

If approved, the $1.7-billion ethane cracker and Borstar PE unit are planned for startup in late 2020.

Total said it expects to hold a 50% stake in the new JV.

Total's announcement of the proposed partnership with Nova Chemicals and Borealis follows the French operator's previous confirmation of its plan build a 1 million-tpy ethane steam cracker at the Port Arthur production site, which alongside the refinery, also hosts BASF Corp. (60%)-TPRI (40%) jointly owned BASF Total Petrochemicals LCC's more than 1 million-tpy ethylene plant.

According to its 2016 annual report to investors released in March, Total completed front-end engineering design for Port Arthur's proposed ethane steam cracker in mid-2016.

Total also said on Mar. 27 that it has let a contract to CB&I, Houston, to provide engineering, procurement, and construction services for the new cracker.

Magellan Midstream settles Texas splitter dispute

Magellan Midstream Partners LP has entered into a fee-based, take-or-pay agreement with Trafigura Trading LLC for the exclusive use of Magellan's 50,000-b/d condensate splitter in Corpus Christi, Tex. The agreement was made as part of an amicable resolution of a dispute between the parties under the previous contract. Magellan has dismissed its lawsuit against Trafigura as part of the resolution.

Magellan recently completed construction of the splitter, which is fully supported by the long-term commitment from Trafigura. Magellan expects to begin commercial operation of the splitter during late second quarter.

In conjunction with the agreement, Magellan will build an additional 300,000 bbl of storage to bring total storage supporting the splitter to 1.5 million bbl. The firm also will make other minor modifications to the splitter, increasing expected capital spending for the project to $330 million.


Chevron brings Gorgon Train 3 on stream

A joint venture led by Chevron Australia has begun production of LNG from Train 3 at its Gorgon-Jansz project on Barrow Island in Western Australia.

The 5.2 million-tonne/year train will enable the $54-billion Gorgon facilities to ramp up to full production capacity of 15.6 million tpy.

The start-up comes just after the project shipped its 50th LNG cargo from the island earlier this month.

While describing the start of the third train as a milestone event, Nibel Hearn, Chevron Australia managing director, also recently noted that there is unlikely to be any near-term investments in a fourth train at the site.

The costly project has been plagued by problems during its long construction period. Train 1 came on stream 12 months ago, but shipped just one cargo before production was stopped for lengthy remedial work. Train 2 came on stream in October last year and quickly ramped up to 90% of nameplate capacity before it, too, suffered a short suspension of production in February. It was shut down again in early March for planned maintenance work, which the company says will enable modification works to improve the train's capacity and reliability.

Chevron added that the commissioning of Train 3 went smoothly and the company has applied the experience gained from the start-up of the first two trains to put the project on track to reach its full planned capacity.

The Gorgon-Jansz consortium is Chevron 50%, and ExxonMobil Corp. and Royal Dutch Shell PLC, 25% each.

Chevron's other big project in Western Australia, the $34-billion Wheatstone LNG development, is on schedule to begin production at midyear.

Refining NZ seeks bigger oil cargoes into Northland

New Zealand Refining Co. Ltd. (Refining NZ) is seeking public consultation on a proposed project to bring in bigger cargoes of crude oil to its 107,000-b/d refinery at Northland, in Marsden Point, New Zealand, near Whangarei.

A detailed overview of the project will be available in and around Whangarei from Mar. 25 with refinery staff on hand to answer questions and receive public feedback, which will be followed by more formal information days from Apr. 7-8, where interested parties will be able to speak with independent experts about a series of in-depth studies related to the proposal, Refining NZ said.

This second round of public consultation follows the first round of broader consultation in March 2015, the feedback from which has continued to shape Refining NZ's evaluation of and approach to the project, the refiner said.

Under its current proposal, Refining NZ is seeking to accommodate deliveries of larger crude cargoes into Marsden Point by deepening the shipping channel at the entrance to Whangarei Harbor and around the refinery jetties and turning basin (where ships turn as they depart) via dredging, as well as straightening the channel's current S-shaped bend through a channel realignment.

While Aframax oil tankers (700,000 bbl) deliver the majority of crude feedstock to the refinery, larger Suezmax tankers (1 million bbl) that occasionally carry crude to Marsden Point can do so only partially loaded because the shipping channel is not deep enough to allow the Suezmax tankers to carry in full-capacity shipments.

Since Suezmax vessels already visit the refinery, the planned project would reduce the number of frequency of crude tankers entering the harbor since crude deliveries would be arriving in larger-sized parcels, Refining NZ said.

Should the project advance, up to half of the refinery's delivered crude shipments (about 20 million bbl/year) would arrive on ships carrying 1 million bbl at a time vs. current ship deliveries of 500,000-700,000 bbl), helping to improve Refining NZ's freight economics, and, as a result, its ability to compete with imported fuels (OGJ Online, Oct. 25, 2016).

A definitive timeline for the project, however, has yet to be confirmed.