OGJ Newsletter

June 3, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

GOP senators: Approve Keystone XL on its own merits

Approval of the Keystone XL crude oil pipeline project should be based on its merits, and not linked to higher taxes or more regulations, John A. Barrasso (Wyo.), John Hoeven (ND), and 22 other US Senate Republicans said in a May 23 letter to US President Barack Obama.

"We strongly urge you to immediately approve this vital project, not sentence it to death by a thousand cuts with yet more environmental review and further regulatory delay," the senators wrote.

"You should approve the Keystone XL pipeline project on its merits alone without suddenly moving the goalposts after more than 4 years of review by tethering its fate to wholly unrelated and economically disastrous new regulatory policies," they told the president.

The senators specifically raised concerns about a possible carbon tax, regulation of greenhouse gases from power plants, and a national low carbon fuel standard.

Their letter came a day after the US House passed Rep. Lee Terry's (R-Neb.) bill to bypass the White House and congressional authorize construction of the pipeline's final segment by 241 to 175 votes (OGJ Online, May 23, 2013).

Statoil to get stake in Tanzania Block 6

Norway's Statoil agreed to acquire a 12% working interest in 5,549-sq-km Block 6 offshore Tanzania from Petrobras Tanzania Ltd., the operator.

Water depth in the block is 1,800 m.

Block 6 is 170 km north of Block 2, where Statoil, as operator working in partnership with ExxonMobil Corp., made three natural gas discoveries since 2012 (OGJ Online, Mar. 18, 2013).

After the farmin, which is subject to approval of Tanzanian officials, Block 6 interests will be Petrobras Tanzania 38%, Shell Deepwater Tanzania BV 50%, and Statoil 12%.

Marathon ends talks to sell Athabasca oil sands stake

Marathon Oil Corp. said negotiations to sell its 20% interest in the Athabasca oil sands project have ended without any agreement being reached.

"Marathon Oil is not engaged in further discussions," the company said, noting its goal remains intact to divest $1.5-3 billion during 2011 through Dec. 31.

As of May 22, Marathon had agreed upon or closed on about $1.3 billion in divestitures.

Marathon announced the Athabasca negotiations in October 2012 although it never disclosed the potential buyer's name (OGJ Online, Oct. 29, 2012).

PetroBakken renamed Lightstream Resources

PetroBakken Energy Ltd., Calgary, has received shareholder approval for a name change, effective immediately, to Lightstream Resources. Ltd.

The company's main interests are light-oil properties in the Bakken play of Saskatchewan and Cardium play of Alberta.

The company was spun off last year from Petrobank Energy Resources Ltd., of which it had been a 56%-owned subsidiary (OGJ Online, Dec. 19, 2012).

Exploration & DevelopmentQuick Takes

Statoil has oil find north of Grane field

A group led by Statoil Petroleum AS has attributed 18-33 million bbl of recoverable oil to a discovery well on North Sea license 169 B2 about 7 km north of Grane field and 150 km west of Stavanger, Norway.

The 25/11-27 well in the Grane Unit went to 1,865 m in 126 m of water and proved a 20-m oil column in the Heimdal formation. The licensees will consider various development alternatives based on oil quality and pressure communication with surrounding fields.

The well is in the Grane Unit, where Statoil is operator with 36.66% interest. Petoro AS has 28.94%, ExxonMobil Exploration & Production Norway AS 28.22%, and ConocoPhillips Skandinavia AS 6.17%.

Statoil noted that about 40% of its 2013 exploratory wells on the Norwegian Continental Shelf will be near-field exploration projects. In addition to the Grane area, these wells will target the Oseberg, Fram/Gjoa, and Tampen areas.

The Norwegian Petroleum Directorate said the Songa Trym semisubmersible will proceed to Production License 128 in the Norwegian Sea to drill the Statoil-operated 6608/11-8 appraisal well.

Rosneft to explore Sea of Okhotsk shelf

Inpex Corp., Tokyo, has signed a cooperation agreement to take a one-third stake in two blocks held by Russia's Rosneft on the Sea of Okhotsk that the Russian company believes contain a recoverable resource of 11.3 billion bbl of oil equivalent.

The Magadan-2 and Magadan-3 blocks cover 28,082 sq km in 100-200 m of water 50-150 km offshore south of Magadan in a subarctic part of the Russian Far East. The blocks are in a largely unexplored frontier area, Inpex said.

The two firms will set up a joint venture for which Inpex will fully finance geological exploratory work. Inpex will reimburse development expenses incurred by Rosneft on the blocks and 33.3% of what Rosneft paid to acquire the licenses.

The cooperation agreement provides Inpex with the exclusive right to negotiate final agreements to explore and develop the blocks. Once a final agreement is executed, Inpex will pay Rosneft a one-time bonus for each commercial oil and gas discovery proportionally with its stake in the project.

Mitra Energy follows Malay-Tho Chu discovery

A group led by Mitra Energy Ltd. has spudded the 45-VT-1X exploratory well on sprawling Block 45 on the northeastern margin of the Malay-Tho Chu basin offshore southern Viet Nam, the same basin in which the group reported a recent discovery.

The Ensco 107 jack up is handling the drilling assignment. Mitra Energy has a 35% operated working interest in the PSC. Talisman Energy Inc. has 35% subject to government approval, and Petrovietnam Exploration Production 30%.

The same group last week plugged and abandoned the 46/07-ND-1X well as an oil and gas discovery on adjacent Block 46/07. The group drilled that well to 2,296.6 m measured depth, 2,066 m true vertical depth subsea, and encountered more than 40 m TVD thickness of net pay validated by an extensive MDT and minidrillstem test program.

The 46/07-ND-1X well was first in a three-well program being operated by Mitra Energy on the two blocks.

Lone Pine adds Slave Point light oil acreage

Lone Pine Resources Inc., Calgary, is evaluating alternatives to fund a large light oil exploration prospect in the Devonian Slave Point formation at Hutch in northern Alberta.

Lone Pine estimates horizontal development well costs in the area at $4 million and estimates that each section may contain 5-11 million bbl of original oil in place.

The company acquired 99,840 acres of 100% working interest land prospective for Slave Point light oil in the Hutch area in the quarter ended Mar. 31. Located 125 km northwest of the company's Evi asset, the Hutch property provides Lone Pine with a potential second light oil fairway.

Lone Pine's Slave Point land base now exceeds 180,000 gross acres. The Slave Point at Hutch is 1,000-1,100 m deep compared with 1,600 m at Evi.

Lone Pine was attracted to the Hutch area as an analogous extension to its existing Slave Point acreage on which it has drilled more than 100 horizontal wells.

Capitalizing on lower land costs by being a first mover in the area, Lone Pine has watched industry participants acquire land positions in the area and initiate drilling programs that have continued through this year's first quarter.

Drilling & ProductionQuick Takes

ExxonMobil, InterOil in talks over assets

InterOil Corp. and its joint venture partner, Pacific LNG Group, are talking with ExxonMobil Papua New Guinea Ltd. regarding development of Elk and Antelope gas-condensate fields.

The transaction has been discussed with the government, and any agreement would be subject to government approval. No financial terms were specified yet.

InterOil, Houston, and Pacific LNG are negotiating to sell ExxonMobil an interest that would be sufficient to supply gas to develop another LNG train at ExxonMobil's Konebada site.

InterOil said it is discussing whether gas from Elk and Antelope fields could support an expansion of ExxonMobil Corp.'s LNG project or a new gas-export facility.

Esso Highlands Ltd., an ExxonMobil subsidiary, plans to liquefy and ship gas from Hides, Juha, and Angore fields and associated gas from Kutubu, Agogo, Moran, and Gobe Main oil fields in the Southern Highlands thrust belt. The fields are expected to produce more than 10 tcf of gas and 200 million bbl of liquids in 30 years.

Ground was broken in 2011 for a 6.6-million tonne/year LNG plant 20 km northwest of Port Moresby, and early right-of-way work parallels the Kutubu oil line. Santos and Oil Search Ltd. have interests in the project (OGJ Online, Sept. 5, 2011).

InterOil's proposed LNG facilities in Gulf Province are to have a capacity of 5 million tpy of LNG. Operation is targeted for mid-2014.

Shell lets subsea contract for Stones field development

Royal Dutch Shell PLC has let a subsea equipment contract to FMC Technologies Inc. in a move to continue development of Stones oil and gas field in the Gulf of Mexico.

Discovered in 2005, Stones is an ultradeepwater project in the gulf's Walker Ridge area about 200 miles southwest of New Orleans in 9,600 ft of water. The project encompasses eight US federal Outer Continental Shelf lease blocks in the gulf's Lower Tertiary trend. Shell established first production in the trend area from its Perdido development.

The scope of the contract with FMC includes supply of eight subsea trees, a subsea manifold, topside and subsea controls, and associated equipment.

Earlier this month, Shell announced a final investment decision in the Stones project, which is expected to host "the deepest production facility in the world," according to the company.

The FID set in motion the construction and fabrication of a floating production, storage, and offloading vessel as well as subsea infrastructure. An FPSO design was selected "to safely develop and produce this ultradeepwater discovery, while addressing the relative lack of infrastructure, seabed complexity, and unique reservoir properties," Shell said.

Development of Stones will start with two subsea production wells tied back to the FPSO vessel, followed later by six additional production wells, Shell said.

This first phase of development is expected to have annual peak production of 50,000 boe/d from more than 250 million boe of recoverable resources. Stones field is estimated to contain more than 2 billion boe in place.

Shell holds 100% interest and will operate the development.

EnQuest to acquire interests off Tunisia

EnQuest PLC, London, has agreed to acquire 70% participating interests in the oil-producing and development assets of PA Resources AB in the Gulf of Gabes offshore Tunisia and will become operator.

PA Resources, Stockholm, retains 30% interests in the offshore properties and 100% of its onshore interests in Tunisia.

The acquisition encompasses mature Didon oil field and the Zara Permit, on which two discoveries have been made (OGJ Online, June 12, 2009).

Didon, in 70 m of water 70 km offshore, is a 1976 discovery that began producing in 1998. Cumulative production is 31 million boe. Current production is 1,400 boe/d from a good-quality reservoir with a water cut of about 60%.

EnQuest estimates Didon's net producing proved and probable reserves at 2 million boe. It expects reserves to rise with further development involving the drilling of two infill wells.

Zarat field, 80 km offshore in 90 m of water, is a 1992 oil and condensate discovery in moderate-permeability fractured limestone. EnQuest estimates net contingent resources at more than 40 million boe.

Elyssa gas field, also on the Zara Permit, is 50 km offshore in 50 m of water.

Permit commitments include an appraisal well at Elyssa and an exploratory well on the Zara Permit.

EnQuest agreed to make PA Resources an up-front cash payment of $23 million on completion of the transaction. It also offered carry consideration of up to $93 million contingent on its sanctioning of Zara field development and agreed to make additional contingent payments of as much as $133 million related to project developments and achievement of targets.

PA Resources' onshore Tunisian interests include Douleb, Semmama, and Tamesmida fields and exploration acreage in the Jelma, Makthar, and Jenein Centre licenses.

First Yamal hydraulic frac jobs reported

Gazprom Neft has conducted what it says is the first hydraulic fracturing ever on Russia's Yamal Pensinsula at geologically complex Novoport oil and gas condensate field.

A subsidiary performed five frac jobs in Jurassic reservoirs in four wells—single fracs in vertical wells and a multistage frac in a horizontal well.

Gazprom Neft said all the wells were placed on stream, with total production 2.5 times the predicted rate. All the wells are on primary recovery.

The company has begun drilling the first of three wells planned at a second well pad.

Denis Kashapov, executive director of the Novy Port branch of Gazpromneft Razvitiye, the Gazprom Neft unit, said further hydraulic fracturing of Novoport Jurassic reservoirs is planned.

Novoport is the largest oil and gas condensate field under development in the Yamal area, with explored and estimated reserves of 230 million tonnes of oil and 270 billion cu m of gas.

Methane hydrate test used special ESP

Depressurization in a pioneering test flow of methane from hydrates offshore Japan earlier this year involved a specially designed electric submersible pump system able to separate methane from water and move them to the drillship through separate production strings (OGJ Online, Mar. 12, 2013).

Baker Hughes designed the completion system under contract to Japan Drilling Co. Ltd., which is working for Research Consortium for Methane Hydrate Resources in Japan.

Japan Oil, Gas & Metals National Corp., the well operator, reported the noncommercial flow of methane from hydrates from a well drilled to 300 m below the mud line in 1,000 m of water in the Nankai Trough 60 km off southeastern Japan.

Baker Hughes conducted an engineering study to design a completion system that would lower pressure in the reservoir enough to break down the hydrate to methane and water, control sand during production, and acquire large amounts of downhole data for use in reservoir modeling.

The company provided a system that included 0º C. qualification testing of standard products, a gravel-packed lower completion, the ESP system, a custom-designed dual-string production packer, real-time electronic pressure-temperature and memory gauges, and a distributed temperature-sensing fiber-optic monitoring system.

Baker Hughes said the research consortium estimates methane hydrate formations in the eastern Nankai Trough hold as much as 40 tcf of methane in place.

PROCESSINGQuick Takes

BASF Total cracker revamped to run ethane

BASF Total Petrochemicals LLC (BTP) has completed a revamp of its steam cracker in Port Arthur, Tex., enabling the 1-million-tonne/year facility to process ethane, supply of which is increasing from US shale plays.

Construction of another steam cracker at the site is under consideration.

The existing cracker, adjacent to the 174,000-b/d Port Arthur refinery operated by Total Petrochemicals & Refining USA Inc., was commissioned in 2001 to process naphtha.

Patrick Pouyanne, president of Total Refining & Chemicals, of which the US unit is part, said ethane costs about $30/boe, while naphtha costs about $100/boe.

The cracker now can use butane and propane, which also are cheaper than naphtha, as feedstock.

After the revamp, the Port Arthur cracker can produce as much as 40% of its ethylene from ethane and another 40% from butane and propane.

BTP has begun construction of a 10th ethane-cracking furnace at the facility. Scheduled to come on stream in the second quarter of 2014, the furnace will increase cracking capacity by nearly 15%.

Total owns 40% of BTP. BASF holds 60%.

Total is dedicating its share of ethylene produced by BTP to its polyethylene plant at Bayport, Tex., and its share of propylene to its polypropylene plant at La Porte, Tex..

"In light of the impact of the shale-gas revolution on the global petrochemical industry, Total is also examining a project to build a new ethane steam cracker that would be tied to the original Port Arthur steam cracker to capture maximum synergies while leveraging this cost-advantaged feedstock," Pouyanne said.

Oklahoma gas plant starts up

Caballo Energy LLC, Tulsa, has started up a 60-MMcfd gas processing plant near Carmen, Okla., in Alfalfa County, bringing Caballo's total processing capacity in the region to about 100 MMcfd (OGJ Online, Sept. 18, 2012).

The Carmen plant currently operates at 80% capacity, said Caballo, and serves expanding natural gas production in the liquids‐rich Mississippi Lime and Cana Woodford shale plays. The company said that long-term dedications to the plant total more than 125,000 acres.

It is evaluating adding a second cryogenic processing plant at the 160-acre site that would give Caballo 220 MMcfd in processing capacity at Carmen as earlier as June 2014.

The new plant and Caballo's existing Eagle Chief plant, also in Alfalfa County, serve the company's Eagle Chief system, which includes more than 600 miles of natural gas gathering pipelines and compression in Alfalfa, Blaine, Garfield, Major, and Woods counties. Caballo delivers processed gas to Oneok's gas transportation and Panhandle Eastern pipeline. NGLs move to Oneok's NGL pipeline.

The Eagle Chief system also includes saltwater disposal and crude oil gathering systems. Caballo acquired the Eagle Chief system in December 2011.

Total to add hydrocracker at Antwerp

Total plans a €1 billion modernization of its Antwerp, Belgium, refining and petrochemical complex that will include new upgrading capacity at the 338,000-b/cd refinery.

Total will add a solvent deasphalting unit and a mild hydrocracking unit at the refinery to increase yields of desulfurized diesel and ultralow-sulfur heating oil from heavy fuel oil. It didn't report capacities. The new upgrading facility is to start up in early 2016.

Total also will add a plant to convert refinery fuel gases into petrochemical feedstock, replacing naphtha. The project will increase integration between the refinery and petrochemical units of the complex.

Total will shut down the smallest and oldest steam cracker at Antwerp, now idle, as well as the smallest and oldest polyethylene production line.

TRANSPORTATIONQuick Takes

GDF Suez buys share in Nabucco-West from OMV

GDF Suez has acquired a 9% share in Nabucco Gas Pipeline International GMBH—the partnership company developing the Nabucco-West pipeline—from Austria's OMV AG. The transaction is expected to close in this year's second half, subject to certain conditions. OMV did not offer any specifics of these conditions or disclose the deal's purchase price.

Following closing, partners in Nabucco will be GDF Suez, OMV, Bulgaria's BEH, Turkey's Botas, Hungary's FGSZ, and Romania's Transgaz.

The 800-mile pipeline launched a nonbinding open season earlier this month for shipment of gas from Shah Deniz II to Europe (OGJ Online, May 10, 2013). BP expects the Shah Deniz partners to decide next month between Nabucco and the Trans Adriatic Pipeline as the project's European transport option.

Inpex, Shell to boost stakes in Abadi LNG

Inpex Masela Ltd. and Shell Upstream Overseas Services (I) Ltd. have signed an agreement to acquire and split equally a 10% participating interest to be divested by PT EMP Energi Indonesia in the Abadi LNG project offshore Indonesia (OGJ Online, Jan. 25, 2013).

At completion of the deal, shares will be Inpex Masela, the operator, 65% and Shell 35%.

The companies plan to install a floating LNG facility to produce 2.5 million tonnes/year in the first phase of development of Abadi gas field on the Masela Block in the Arafura Sea.

NEB approves Trans Mountain expansion toll

Canada's National Energy Board has approved toll methodology for the planned expansion of the Trans Mountain Pipeline between Edmonton, Alta., and Burnaby, BC, near Vancouver.

Kinder Morgan Energy Partners LP plans to twin the 1,150-km pipeline to raise total capacity to 890,000 b/d from 300,000 b/d (OGJ Online, Jan. 11, 2013). If completed, the existing pipeline would carry oil products, light crude, and synthetic crude oil. The new pipeline would carry heavier oils.

The project would involve about 980 km of new pipeline and 11 new pump stations. In addition to expanding capacity for exports to the US, the project would give producers in the Canadian oil sands region access they need as output grows to waterborne trade.

The NEB said it has not received an application for physical expansion of the pipeline.