AGR wins NCS frame agreement with Premier Oil

AGR has been assigned by Premier Oil to deliver a range of services within the Norwegian Continental Shelf (NCS).

The contract period is for five years plus an additional three years. The scope of the agreement covers well management and well planning services for exploration drilling and field developments. The work scope will encompass delivery of resources, competence and methodology by AGR’s well management team in Norway.
 
Sjur Talstad, AGR’s E.V.P, Norway and Russia, said: “We are pleased to continue the close working relationship with Premier Oil on the Norwegian Continental Shelf (NCS). The activity will be carried out from our fast growing Stavanger office which has an excellent track record of delivering well management and operational HSE support."
 
AGR recently celebrated drilling over 500 well projects in 25 countries for 106 clients - an average of one drilling project commenced every 10 days since 2000. On the NCS, the company has managed over 80 drilling projects on 14 rigs on behalf of 21 operators. Last year, AGR’s Norway team was involved in 15% of exploration wells drilled on the NCS.

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Emerson invests $60 million in new flow measurement facility

Emerson Process Management is expanding the company’s existing manufacturing and engineering services campus in Cluj-Napoca, Romania.

The expansion includes a new, 18,800-sq-m flow measurement manufacturing building. This $60-million investment will help meet growing demand for the company’s flow measurement products and services in Europe and other regions.

Additionally, in the summer of 2014, Emerson Process Management moves into a separate, newly constructed $16-million facility on the Cluj campus that will be home to the Regional Project Engineering Center and the European System Integration Center for its PlantWeb Solutions Group. This facility will house up to 600 employees who provide engineering and support services for European control systems and automation projects, plus an initial 100 additional personnel to assemble and test control systems for projects throughout Europe.

The new flow technology manufacturing building will offer calibration, services, and customer training facilities for Emerson Process Management’s Micro Motion, Rosemount, and Roxar flow measurement technologies. This facility will provide modern and spacious production capabilities as well as offices for engineering and customer support services, and fulfill market demands for quality and traceable calibration.
 
In addition, a state-of-the-art customer experience center is planned that will incorporate training and meeting facilities, along with displays of Emerson technologies.  The new facility adds to Emerson’s current European network of facilities, which includes an existing flow manufacturing and service center in Ede, the Netherlands.

“These additional capabilities increase our flexibility and ability to manage our European customers’ most challenging needs,” said Sonnenberg.

The company’s Cluj-Napoca campus currently manufactures Fisher pressure regulators, Roxar flow metering and flow assurance products, Rosemount Analytical products, Leroy-Somer power generators, Control Techniques electrical equipment for photovoltaic power plants, RIDGID tools, and Appleton A.T.X. lighting fixtures and junction boxes for hazardous and adverse environments.

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VNG Norway discovers 226-m hydrocarbon column near Njord field

VNG Norge AS, operator of production licence 586, has concluded the drilling of exploration well 6406/12-3 S. The test results indicate a discovery far larger than expected.

The well was drilled on the Halten Terrace, about 33 km southwest of the Njord field.

The main objective of the well was to test the hydrocarbon potential in the Pil prospect, up-dip from the offset well 6406/12-1 S. The primary reservoir target was Upper Jurassic sandstones of the Rogn and Melke formations.

The well encountered a 91 m gas column and a 135 m oil column in Upper Jurassic sandstones. Preliminary analyses based on extensive coring, wireline logs and pressure data show that the well has encountered sandstones with very good reservoir properties.

An extensive data acquisition program was carried out in the well, including a successful production test. The production rate was 1,067 Sm3 oil per flow day through a 56/64-in. nozzle. The test showed good flow properties and the gas/oil ratio was 152 Sm3/Sm3. Preliminary estimates place the size of the discovery at between 8 and 27 million Sm³ recoverable oil equivalents with a considerable additional upside volume within the Pil closure not proven by the well.

Production licence 586 was awarded on 4 February 2011 (APA 2010) and this was the first well to be drilled in the licence. 6406/12-3 S was drilled to a vertical depth of 3,738 ms below sea level, and was terminated in the Upper Jurassic Melke formation. The water depth is 324 meters. The well will now be permanently plugged and abandoned.

Well 6406/12-3 S was drilled by the Transocean Arctic drilling facility, which will now first drill a a down dip sidetrack to prove up the lateral extent of the Pil reservoir and the upside case.

This will be followed by a further sidetrack to assess the potential of the neighbouring Bue target.

VNG Norge is the operator in PL586 with a 30% share. Partners are Spike Exploration (30 %), Faroe Petroleum Norge (25 %) and Rocksource Exploration Norway (15 %).

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AWE provides Pateke-4H drilling update

AWE reported that the Pateke-4H development well, including the sidetrack section, was at a measured depth of 4,083 m with the 9 5/8 in. casing successfully installed and cemented to a depth of 3,669 m. Preparations are under way for the drilling of the next interval using an 8 ½ in. drilling assembly to drill horizontally through the reservoir section to a planned measured depth of 5,361 m.
 
The Kapuni F10 sandstone objective has already been intersected on prognosis with oil shows and real time logging measurements indicating the likely presence of an oil bearing reservoir. The commercial significance of the oil shows will not be clear until the horizontal drilling is completed and the reservoir size and quality is fully assessed.
 
The Pateke-4H development well is in PMP 38158 and AWE is the operator. Located in the offshore Taranaki basin, New Zealand, PMP 38158 contains the Tui, Amokura and Pateke fields and has been producing since 2007.
 
Pateke-4H is targeting a mapped northern extension of the currently producing Pateke field. The well is being drilled in water depth of approximately 124 m with a planned total measured depth of 5,361 m, including a 1,272 m horizontal section. If successful, the well will be completed for subsequent tie-back to the Tui FPSO (Umuroa) for production in 2015.

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Shell shelves plans to boost Ormen Lange gas output

Royal Dutch Shell Plc postponed a project designed to boost natural gas recovery from its Ormen Lange deposit offshore Norway, citing higher costs and doubts on reserves.

“The oil and gas industry has a cost challenge,” said Odin Estensen, chairman of the Ormen Lange Management Committee, in a statement. “This, in combination with the maturity and complexity of the concepts and the production volume uncertainty, makes the project no longer economically feasible.”

Shell and other oil companies including Statoil ASA are cutting spending amid rising costs and stagnating oil and gas prices. The delay at Ormen Lange, which delivers as much as 20% of the UK’s gas consumption, comes as the standoff between Russia and the European Union over the annexation of Crimea has raised concerns over fuel supplies to Europe.

The delay on the compression project was supported by partners Statoil, Dong Energy A/S and Exxon Mobil Corp. It was opposed by Norway’s state-owned Petoro AS, also a partner. Prime Minister Erna Solberg this month warned companies against “unacceptable” delays to recovery projects, saying they risk damaging the goodwill they enjoy from the government.

Shell shares dropped 0.6% to 2,200 pence as of 10:18 a.m. in London. Statoil fell 0.8% to 165.4 in Oslo.

The partners remain committed to maximizing recovery at Ormen Lange “in a sustainable manner,” said Shell, the operator of Norway’s second-largest gas field.

Norway, western Europe’s largest oil and gas producer, has seen output drop 20% over the past decade. The government is pushing for companies to maximize recovery from existing fields instead of moving on to more profitable projects. Statoil, Norway’s largest producer, has also announced it’s reviewing plans to build a new platform at the North Sea Snorre deposit to extract an additional 300 MMbbl of oil.

Shell said the timing of the Ormen Lange compression project wasn’t critical to the ultimate recovery rate at the field. “We’re fully aligned to the government’s steer to increase the recovery factor,” Kitty Eide, a company spokeswoman, said in an emailed reply to questions.

In a letter to the government in February, Shell said that a tax increase last year on oil and gas companies will make the Ormen Lange project less profitable, echoing other companies that have warned the change would hurt marginal projects.

“It’s not a deciding factor, but did not help the economics of the project,” Eide said. The company declined to provide details on investment or production-volume estimates for the compression project, or when the license partners expected to make a decision on a future project, she said.

Benchmark gas prices in the UK, where Ormen Lange’s production is shipped through the 1,200-km (745 mi) Langeled pipe, the world’s second-longest pipeline, have fallen 24% so far this year.

The field was discovered in the Moere basin of the Norwegian Sea in 1997 and started producing 10 years later. Output reached 21.5 Bcm of gas last year, a fifth of Norway’s total production. Remaining reserves were estimated at 194.5 Bcm of gas at the end of 2013, down from an initial 314.6 Bcm, according to the Norwegian Petroleum Directorate.

The project delay has no implications for current production, Shell’s Eide said.

Troll, Norway’s largest gas field, has remaining reserves of 955 Bcm. Troll produced 29.6 Bcm of the fuel last year.

Shell and its partners had been studying two offshore compression solutions -- either a subsea concept or a platform -- to compensate for declining pressure over time.

Petoro, which manages Norway’s direct stakes in offshore fields, shares Shell’s view that the current concepts for compression were unprofitable, making a postponement reasonable, Sveinung Sletten, a spokesman, said by phone. The company didn’t support the operator’s decision because it lacked clear plans for future compression projects, he said.

“We haven’t been presented with good enough plans for how the operator will continue its work on compression,” he said. “We want a stronger commitment, and we want sufficient resources allocated to the upcoming work to secure the extraction of remaining profitable resources at Ormen Lange.”

Oslo-based Aker Solutions ASA, which designed a pilot project for Ormen Lange seabed compression, said it wouldn’t comment on the internal decision-making process. The company also worked on the world’s first subsea gas compression facility at Statoil’s Aasgard field in the Norwegian Sea.

“Although delayed, subsea compression at Ormen Lange remains an opportunity for us in the future,” Bunny Nooryani, an Aker Solutions spokeswoman, said in an email.

Norwegian weekly Teknisk Ukeblad reported last month that FMC Corp. had beaten Aker Solutions to an initial contract on the Ormen Lange compression system.

Aker Solutions slid 2.3% to 90.3 kroner in Oslo trading.

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Statoil to cut oil sands CO2 emissions by 20%

Statoil ASA expects to decrease carbon-dioxide emissions per barrel from its Canadian oil-sands projects by 20% within six years, responding to environmental criticism of the crude production method.

Norway’s biggest energy producer said yesterday that carbon intensity from its oil-sands operations rose 25% from a year earlier to 69.7 kilograms of carbon dioxide per barrel.

Statoil is applying solvents to its steam-assisted techniques and will use valves to better direct steam to areas that need it, Staale Tungesvik, president of Canadian operations, said in a telephone interview. The Stavanger-based company also is considering different drilling techniques and more efficient water-recycling processes.

“The difference between oil sands and conventional oil production is that we use gas to heat water to create steam, so the footprint of CO2 is very much out of the generation of steam,” Tungesvik said. “We believe that we have identified technologies that will help us reach our target of reducing CO2 intensity by 20% by 2020.”

Emissions from Alberta’s oil sands have become a focal point for opposition to Calgary-based TransCanada Corp.’s Keystone XL pipeline, which would carry bitumen from the oil sands to U.S. Gulf Coast refineries. Opponents like billionaire Tom Steyer say the line would encourage companies to exploit the world’s third-largest crude reserves, unlocking vast amounts of carbon and accelerating climate change.

Carbon emissions from the oil sands won’t improve without new government policy, said PJ Partington, an Ottawa-based analyst at the Pembina Institute, an environmental think tank.

“Without more stringent policies to drive innovation and deployment of new technologies, carbon intensity is expected to remain flat for the foreseeable future,” Partington said by phone.

The intensity of greenhouse gases in oil-sands emissions fell 7.7% from 2008 to 2012, the Canadian Association of Petroleum Producers, an industry group, said in a Nov. 5 report.

Oil-sands crude is on average 9% more carbon intensive than the U.S. average on a wells-to-wheels basis, which measures CO2 emissions from the start of oil production through to combustion, according to the CAPP report.

Statoil’s carbon emissions from oil-sands production will likely decline this year, Tungesvik said. “With stable production and new technology, I would expect we’ll have lower numbers this year than we had last year,” he said.

By 2025, the Norwegian company has voluntarily targeted to reduce CO2 intensity at its oil-sands operations by 40%.

“It’s about earning more money,” Tungesvik said. “And we think that should go hand-in-hand to improve environmental impact.”

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