Niobrara oil seen as potential savior for West Coast refiners

Companies from Noble Energy Inc. to Whiting Petroleum Corp. are ramping up output in the Niobrara shale oil play near the Rocky Mountains that may help save U.S. West Coast refiners from dwindling supplies in their own region.

The formation spread across parts of Colorado, Kansas, Nebraska and Wyoming is estimated to hold as much as 2 billion bbl of oil, Energy Information Administration data show. Niobrara’s oil and lease condensate output will reach a record 304,434 bpd this month, the agency said.

The Rocky Mountains play may be a godsend for Western refiners because its crude closely matches the characteristics of oil from the region’s largest domestic supplier, Alaska’s North Slope, where output has declined every year since 2002. A slide in Alaska and California oil production has forced West Coast refiners to increasingly rely on foreign imports and oil shipped by rail from other states.

“We’ve had a number of shipments move by rail, but I don’t think any of it has gone to the West Coast yet,” Gary Willingham, Noble’s senior V.P. of U.S. onshore, said in Denver during a conference on Bakken and Niobrara crudes. “It’s certainly part of our plan to have that flexibility. We want it to go where the demand is and where the best price is.”

The posted price for oil from the Denver-Julesburg basin, where the Niobrara is located, rose $1 to $85.05/bbl Friday, according to the marketing division of Plains All American Pipeline LP.  Alaska North Slope oil rose $1.20 to $107.39/bbl, data compiled at 4:16 p.m. New York time show.

Noble, the largest producer in the Niobrara, expects its output from the basin to surpass 100,000 boed this year and reach 250,000 by 2018, Willingham said at the 2014 DUG Bakken and Niobrara conference. Whiting has three rigs running in its Redtail prospect there and plans to add a fourth in August.

Oil from the Niobrara matches the medium crude Alaska North Slope so well that it may be “demanded by folks on the West Coast,” said Mark Smith, V.P. of development, supply and logistics for Tesoro Corp., the largest refiner in the West.

Niobrara crude “fills the bill” for the West Coast, Jim Volker, Whiting’s CEO, said at the conference. Oil from the formation will have to compete against other Western plays such as the Uinta basin of Utah to supply the region, he said.

Tesoro is developing a terminal at the Port of Vancouver, Washington, with Savage Services Corp. that would take oil off rail cars and load it onto marine vessels for delivery.

“That Niobrara stuff could easily take up space” at the terminal, Smith said.

Wyoming, home to the Guernsey oil-pipeline hub, issued permits last year allowing projects with collectively more than 459,000 bpd of crude trans-loading capacity. It has approved permits for two more sites this year with as much as 146,000 bpd in capacity.

Musket Corp. runs an oil-by-rail terminal in Windsor, Colorado, that began loading unit-trains at the beginning of this year. The White Cliffs pipeline that carries oil from the basin to Cushing, Oklahoma, is scheduled to double capacity to 150,000 bpd this year.

California, home to two-thirds of the West Coast’s refining capacity, received 55,025 bbl of oil by rail from Colorado in December, the most ever for that month, and took in a record 87,951 from the state in May 2013. Colorado oil production reached a record 206,000 bpd in October.

While companies including Noble and Whiting are accelerating drilling in the Niobrara, Continental Resources decided to allocate spending elsewhere this year, said John Kilgallon, the company’s V.P. of investor relations.

“There has been some success by some operators there, but we’re not one of them,” Kilgallon said by telephone March 28.

Providing useful resources, articles and writings on crude oil, other petroleum products, energy and gas. By Blockline and Associate Ltd Nigeria Ltd, online.

CGG starts 3D multi-client survey offshore Norway

CGG has announced the start of a large BroadSeis/BroadSource 3D multi-client survey in the Northern North Sea offshore Norway. The Horda survey will be the largest broadband multi-client program CGG has acquired in NW Europe as well as the largest multi-client 3D survey ever shot by any company in Norway.

Extending from the Horda platform in the southeast to the Sogn Graben in the north, the 19,000 sq km survey program includes the entire quadrant 35 and large parts of quadrant 31, 32 and 36 and covers more than 80 production licences such as Troll, Brage, Fram and Gjoa.

The survey is being acquired by the Viking Vanquish, and a second vessel will join later in the season. The acquisition program will continue in 2015.

Following several recent discoveries the greater Horda area has become an area of high exploration activity. The survey program’s main objective is to provide a large, uniform dataset with increased seismic resolution, which will offer a platform to improve industry understanding of the regional geology.

The survey has received high prefunding from the industry. Early participants have had the option to recommend priority areas and will also be invited to monitor the data processing which will be conducted in CGG’s Oslo subsurface imaging center.

Jean-Georges Malcor, CEO, CGG, said: “CGG is deploying its latest broadband acquisition and subsurface imaging technology on a seismic project of this magnitude in order to meet the industry’s need for state-of-the-art broadband data delivered in a cost-effective manner for  a large area offshore Norway where no equivalent data of this quality exists. The Horda project has already been well received among the key players in the Northern North Sea and we expect the survey to generate a significant uplift in data quality and provide a valuable tool for all stages of ongoing and future E&P activity in the region.”

Providing useful resources, articles and writings on crude oil, other petroleum products, energy and gas. By Blockline and Associate Ltd Nigeria Ltd, online.

Baker Hughes acquires software technology company Perfomix

Baker Hughes stated the acquisition of Perfomix, a Texas-based oilfield software technology company focused on solutions to enhance oil and gas operations' performance. Perfomix will operate as a wholly-owned subsidiary of Baker Hughes and will be integrated into the company' s remote operations services organization.

Perfomix offers a data and advisory services delivery platform to support drilling, pressure pumping, completions and production operations, and regulatory reporting requirements. The addition of Perfomix will expand the Baker Hughes portfolio of field devices integration, real-time data management, visualization, and analytics software, thus complementing existing capabilities with a modern, elastically scalable and standards-based technology platform.

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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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ConocoPhillips raises Eagle Ford resource estimate

ConocoPhillips has reaffirmed its objective to deliver double-digit returns annually to shareholders at its Analyst Meeting held at the New York Stock Exchange. Members of the company’s executive leadership team outlined ConocoPhillips’ goal to consistently deliver 3 to 5% compound annual growth in production and margins.
 
ConocoPhillips also highlighted its substantial U.S. unconventional position and announced an increase of its estimated resource base in the prolific Eagle Ford play. Based on its prime acreage position and technical knowledge, the company has increased its estimates from 1.8 billion to 2.5 billion bbl of oil in place. Production is also expected to increase from current volumes to more than 250,000 boed by 2017.
 
“ConocoPhillips’ wells in the Eagle Ford have the highest oil rates per well and are leading the industry in value. This is attributable not only to the fact that we are in the best part of the play, but also to our relentless focus on  technical innovation and drilling and completion cost efficiencies,” said Chairman and CEO Ryan Lance. “We are applying these benefits and efficiencies across our unconventional portfolio in the Bakken, Permian, Niobrara, Canada, and outside of North America. We believe our unconventional resource base is unmatched, particularly for a company our size."
 
“Beginning this year, we will be growing production and margins across our diverse asset base, and allocating 95% of our annual capital expenditures to growth projects and programs with margins that are higher than our average margin today. We believe we have the asset base, technical capability, world-class workforce and financial strength to deliver on our unique value proposition,” Lance added.
 
Since 2009, ConocoPhillips has added 6.7 billion boe of resources through a diverse and balanced exploration and appraisal portfolio of high-value opportunities. Among the high-quality prospects are four large U.S. Gulf of Mexico discoveries – Tiber, Gila, Shenandoah and Coronado. Further activity is targeting offshore prospects in Australia, Angola and Senegal; conventional exploration in Norway and Indonesia; and unconventional exploration in North America, Poland and Colombia.
 
In its first two years as an E&P company, ConocoPhillips generated proceeds of $12.4 billion from non-core asset sales, advanced new growth projects, achieved visible margin growth, accessed new organic growth opportunities, participated in successful deepwater Gulf of Mexico discoveries and maintained a strong dividend.
 
Over the next several years, ConocoPhillips plans to execute a disciplined capital program of approximately $16 billion per year and achieve the company’s organic reserve replacement target of more than 100%. The company expects to generate 3 to 5% compound annual production growth and margin growth from major development programs and projects already under way in the U.S. Lower 48, Canadian oil sands, UK and Norwegian North Sea, Malaysia and Australia.

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Parex to focus on Colombia in bid to double production

Parex Resources Inc., the Canadian oil producer operating in Latin America, is focusing its growth efforts on Colombia as it aims to double production in the next five years.

CEO Wayne Foo is planning more land and asset acquisitions to boost the company’s output to as much as 50,000 bpd, he said in an interview at Parex’s headquarters in Calgary yesterday. Colombia’s stable government and well-understood oil resources make it a better investment than other countries in the region such as Argentina, Foo said.

“To be relevant in the market, you really have to be in the range of 25,000 to 50,000 barrels a day,” he said. Production will grow as much as 20% annually from 17,500 to 18,500 bpd this year, he said.

Parex began as an oil producer in Argentina in 2003. The Colombian business was spun off in 2009 and based in Calgary. One of about 10 Canadian energy producers operating in Colombia, Parex produces both light and medium crude in the Llanos basin.

Parex’s shares have more than doubled in the past 12 months, valuing the company at about C$1 billion ($911 million). The stock declined 2.1% yesterday, closing at C$9.50 in Toronto.

“They still have upside,” said John Stephenson, who helps oversee about C$3.1 billion at First Asset Investment Management Inc. in Toronto. “Historically they have been drilling targets that were small and they’re now going after bigger plays to add resource.”

The Canadian company has focused on purchasing land near its current holdings in the Llanos basin, boosting its position to about 2 million acres (809,371 hectares) from 250,000 acres in 2009.

Parex’s largest non-state-owned competitor is Pacific Rubiales Energy Co., a Bogota and Toronto-listed company with a market value of about C$6.7 billion. Colombia in February produced about 1 MMbpd of crude, according to the country’s Mines and Energy Ministry.

Oil transportation infrastructure has caught up with production, helping to relieve a bottleneck that existed for producers a couple of years ago, said Parex V.P. Mike Kruchten. Last year the Bicentenario line began operating, while the Ocensa pipeline has been expanded. Calgary-based Enbridge Inc. is also considering building a line to Colombia’s Pacific coast.

“At present there’s lots of excess capacity” in pipelines, said Foo.

Parex earns about 3% to 4% less on its Colombian oil than Brent crude, the global benchmark, said Kruchten. Brent crude for May settlement traded at about $106 a barrel on April 7.

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