OGJ Newsletter

March 11, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

German utility RWE to sell oil, gas E&P unit

German utility RWE AG announced plans to sell its oil and gas exploration and production business, RWE Dea AG, based on a decision by the firm's executive board regarding an overall corporate strategic repositioning.

"The planned disposal would…take considerable pressure off future capital expenditure and therefore make an essential contribution to improving RWE's financial headroom," an RWE news release said.

Executives are evaluating their options regarding how such a divestiture might be implemented.

RWE Chief Financial Officer Bernhard Gunther said E&P is capital-intensive. The Hamburg-based RWE Dea has acreage and production assets in 14 countries with an emphasis toward the North Sea and North Africa. Last year RWE Dea produced 84,000 boe/d.

Previously, RWE Dea planned to sell some exploration licenses, mostly in Egypt. But Gunther said those assets attracted only limited interest from potential buyers, and the executive board now believes the entire exploration and production business is more apt to attract a buyer.

Western Gas to buy Marcellus gathering assets

Western Gas Partners LP, an Anadarko Petroleum Corp.-owned master limited partnership, agreed to acquire a 33.75% interest in the Liberty and Rome gas gathering systems from Anadarko and a 33.75% interest in the Larry's Creek, Seely, and Warrensville gas gathering systems from an affiliate of Chesapeake Energy Corp.

All assets operate in the Marcellus shale in north-central Pennsylvania with combined total throughput of more than 1.2 bcfd.

The Anadarko acquisition will cost Western $490 million, financed with about $220 million of cash on hand, the borrowing of $246 million on its revolving credit facility, and the issuance of 449,129 common units to Anadarko at an implied price of roughly $54.55/share. The Chesapeake acquisition will cost $133.5 million, financed through borrowings on Western's revolving credit facility.

Chesapeake last year sold midstream assets in the Marcellus, Utica, Eagle Ford, Haynesville, and Niobrara shales to Access Midstream Partners (OGJ Online, Dec. 12, 2012) as part of ongoing efforts to reduce long-term debt.

Japex to buy stake in Canada LNG

Japan Petroleum Exploration Co. (Japex) agreed to join the proposed British Columbia Pacific Northwest LNG venture and to buy a stake in the North Montney shale gas project from Malaysia's Petronas.

The price that Japex plans to pay was not disclosed. British Columbia Pacific Northwest is among a number of proposed LNG export terminals in the US and Canada.

Petronas acquired the Pacific Northwest LNG export terminal project last year when Petronas bought Progress Energy Resources Corp. for $5.4 billion (OGJ Online, June 28, 2012).

Petronas plans to make a final investment decision on the LNG project by Dec. 31, 2014. Commercial operations could start by the end of 2018. Japex said it plans to receive 1.2 million tonnes/year of LNG from the project, providing that both the transaction and the project are finalized.

Japex announced it signed a heads of agreement with Petronas. Terms call for Japex to acquire a 10% interest of the natural gas blocks in North Montney, BC, through new Canadian subsidiary Japex Montney Ltd., and also 10% interest of Pacific Northwest LNG project on Lelu Island off the Hecate Strait in the District of Port Edward, BC.

Petronas Carigali Canada Ltd. and Progress Energy Resources Corp., Calgary, owners of Pacific Northwest LNG, said last year they have moved the project to pre-FEED following a successful feasibility study. Plans call for the plant to initially include two, 3.8-million tonne/year trains with expansion capability for a third (OGJ Online, Dec. 5, 2012).

Singapore's Temasek to boost its stake in Repsol

Temasek Holdings, a Singapore government investment fund, bought another 5% stake in Repsol SA for $1.35 billion as Repsol continues efforts to maintain its investment-grade credit rating. Temasek is lifting its Repsol stake to 6.3% interest, Repsol said.

Repsol's credit rating has been under scrutiny since Argentina took control of YPF SA and expropriated Repsol's majority stake in YPF last year (OGJ Online, Apr. 17, 2012).

Temasek, which is among the world's biggest sovereign investors, had no immediate comment on the transaction.

Repsol recently sold LNG gas assets to Royal Dutch Shell PLC for $4.4 billion cash (OGJ Online, Feb. 26, 2013).

Exploration & DevelopmentQuick Takes

Apache gauges Egypt Khalda, Abu Gharadig oil, gas

Apache Corp. has completed an oil and gas-condensate discovery on the north flank of the Khalda Ridge producing complex in the Western Desert of Egypt, a country in which the company plans to drill 270 wells in 2013, including more than 60 exploratory wells.

The Amoun NE-1X discovery tested at a combined rate of 3,186 b/d of oil and condensate and 11 MMcfd of natural gas per day from two zones in the Jurassic Upper and Lower Safa formations.

Amoun NE-1X was the first 2013 well among several planned locations targeting multiple liquids-rich objectives on the northern and southern flanks of Khalda Ridge. The planned wells' proximity to production facilities is expected to enable quick completion and start of production.

The latest discovery, which followed 2012's highly successful full-field development program at Unas field on the ridge's southern flank, confirms additional exploratory drilling potential in a prolific producing area in the heart of the Khalda concessions.

Apache will drill three development wells offsetting Amoun NE-1X and test two nearby exploratory plays and several additional prospects on the ridge's southern flank later in 2013.

Amoun NE-1X went to 14,028 ft on the Khalda Development Lease 2 miles east of Shams field. Besides the 101 ft of Jurassic Safa pay tests, the well encountered 50 ft of oil pay in three Cretaceous Alam el Buieb-3 sands.

Apache also reported success at the WD 33 Development Lease acquired in 2010.

Apache's exploratory and development drilling on WD 33 in the Abu Gharadig basin began in late 2012, and the recently completed WD 33-5, which cost $3.65 million to drill and complete, tested at 2,324 b/d of oil and 600 Mcfd of gas from the Abu Roash E reservoir. As many as five more locations may be required for full development, and three exploratory wells are planned in the area this year.

Also in the Abu Gharadig basin, the Karama-15 well on the Karama Development Lease test-flowed 2,136 b/d of oil with original reservoir pressure in the Abu Roash G reservoir along the western flank of Karama field. The Karama-15, which cost $2.1 million, confirmed as many as seven more drilling locations. Karama field was Apache's first discovery in the Abu Gharadig basin in 2001.

Aussies to meld Perth basin oil-gas, geothermal search

AWE Ltd., Sydney, signed a memorandum of understanding with a subsidiary of Green Rock Energy Ltd. to drill wells to demonstrate geothermal energy potential in Western Australia's onshore Perth basin on lands that overlap AWE's oil and gas exploratory licenses.

The project, which has been awarded $5.4 million in Western Australia government funding, will involve drilling wells sited to maximize the probability of geothermal success and to provide AWE with data on known target hydrocarbon formations. The companies will seek commonwealth government funds.

Drilling to the deeper geothermal reservoirs could provide AWE with valuable information about its shallower conventional and unconventional oil and gas assets. The various permits lie within 40 km of the Indian Ocean coast from north of Mount Horner oil field about 70 km south beyond Woodada gas field.

Green Rock's Mid West Geothermal Power Pty. Ltd. unit has made considerable progress in identifying the most prospective geothermal resources since its permits were awarded in 2009, including the use of leading edge interpretation of 3D seismic data.

The $5.4 million is awarded on a 1-for-3 basis by the state government's Low Emissions Energy Development Fund towards demonstrating commercial production of geothermal energy.

Combined state and government funding would enable the drilling of two test wells with AWE providing the balance of drilling costs.

A key objective will be selecting optimal well locations for acquiring data on geothermal temperatures and flow rates sufficient for geothermal power generation and that allow AWE to enhance its assessment of potential hydrocarbon bearing formations. The target geothermal reservoirs lie at 3,000-3,500 m.

In consideration for joining the joint venture, AWE will pay MWGP as much as $250,000 conditional on completion of milestones up to and including the commonwealth funding being secured. If that funding is obtained, AWE has the right to farm in for a 50% interest in the most suitable GEP and would become operator of the drilling program, with geothermal well design and testing overseen by MWGP.

If commercial production of geothermal energy is successfully demonstrated, AWE will have the right to continue its participation in the project including the right to farm into MWGP's remaining GEPs on terms to be agreed.

Johan Sverdrup oil test 'best in North Sea'

The result from the latest appraisal well in the Johan Sverdrup area offshore Norway "in terms of reservoir quality of the Volgian reservoir represents one of the best tests ever seen in the North Sea," said Lundin Petroleum AB, Stockholm.

Lundin Petroleum's Norwegian subsidiary is operator of the Johan Sverdrup discovery.

The 16/3-5 well went to a total depth of 2,025 m below mean sea level in PL501 about 3 km south of the 16/3-4 appraisal well and 3 km east of the 16/2-7 appraisal well. Well 16/3-5 found a 30-m gross oil column, shallow to depth prognosis, consisting of a 14-m Upper Jurassic sandstone of excellent quality above a 16-m oil column in a Permian Zechstein Group carbonate of varying reservoir quality.

A drillstem test in the Upper Jurassic sandstone sequence flowed at a rate of more than 4,700 b/d of oil on a 48/64-in. choke. The test showed exceptional flow properties, better than estimated from log evaluations, the company said. DST analysis indicates a laterally continuous reservoir without flow barriers.

The Zechstein carbonate DST resulted in low flow rates, but logs, core, and losses while drilling are indicating upside potential for better flow properties in the Zechstein sequence, the company said.

The company will plug the well and move the Bredford Dolphin semisubmersible to PL359 to drill the Lundin-operated Luno II exploration prospect.

Eni, Petrovietnam sign new upstream pact

Eni SPA and Petrovietnam have signed an agreement covering joint assessment of unconventional hydrocarbon resources in Vietnam, adding to a broader upstream agreement the companies signed earlier this year (OGJ Online, Jan. 23, 2013).

Under the new agreement, a Petrovietnam-Eni team will conduct the study.

The earlier agreement covers exploration in Vietnam and elsewhere.

Drilling & ProductionQuick Takes

Hess reports drilling results offshore Ghana

Hess Corp. announced that it has completed drilling its seventh exploratory well, Pecan North-1, on deepwater Tano-Cape Three Points block offshore Ghana. Pecan North-1 found 40 ft of net oil pay in Turonian-aged reservoir. The well was drilled in 7,411 ft of water about 7 miles northeast of the Pecan-1 well.

Pecan North-1 follows several previously reported discoveries. These were Cob, 31 ft net oil pay; Pecan 1, 245 ft net oil pay; Almond-1, 53 ft net oil pay; Beech-1, 146 ft net oil pay; Hickory North-1, 98 ft net gas condensate pay; and Paradise-1, 120 net ft oil pay and 295 net ft gas-condensate pay. The water depths of these wells were 5,623 to 8,245 ft.

Hess states that it has achieved outstanding drilling performance for drilling time and cost per foot. The gross costs per well for the last three wells averaged $40 million/well, including success case logging. Hess now plans to submit appraisal plans for its discoveries to the Ghanaian government for approval on or before June 2.

Hess is license operator with 90% interest Ghana National Petroleum Corp. has 10% (OGJ Online, Dec. 12, 2012).

St. Malo oil flow rate tops 13,000 b/d

Chevron Corp. has disclosed that it flow-tested the initial development well in St. Malo field in the deepwater Gulf of Mexico last year at an equipment-constrained rate of more than 13,000 b/d of oil.

St. Malo field, which a Chevron-led five-company group expects to bring on production in 2014, is a joint $7.5 billion development with Jack field in 7,000 ft of water 280 miles south of New Orleans.

The St. Malo PS003 well test on Walker Ridge Block 678 took place in August and September 2012 and tapped Lower Tertiary sands more than 20,000 ft below the sea floor. Chevron didn't offer why it had not revealed the test results until now.

Chevron and partners set several records in 2006 when they completed what at that time was the only extended well test of a Lower Tertiary well in Jack field. The Jack-2 well in Walker Ridge Block 758 sustained flow rates of more than 6,000 b/d of oil from 40% of the total measured net pay of more than 350 ft (OGJ, Sept. 25, 2006).

Jack and St. Malo fields lie within 25 miles of each other in the southeastern reaches of the Lower Tertiary Trend and are being developed with a host floating production unit to be sited between the two fields.

The unit is planned to have a design capacity of 177,000 b/d of oil equivalent to accommodate a maximum of 94,000 boe/d from Jack/St. Malo plus output from third-party tiebacks (OGJ Online, Apr. 26, 2011).

Chevron has a 51% working interest in St. Malo field. Petrobras has 25%, Statoil 21.5%, and ExxonMobil and Eni SPA 1.25% each.

Delphi Energy brings horizontal wells on stream

Delphi Energy Corp. of Calgary reported encouraging results from its initial development of its Montney play at Bigstone where Delphi last year brought three horizontal Montney wells on stream and recently brought on stream a fourth horizontal well (OGJ Online, May 22, 2012).

The 15-10-60-23W5 well at East Bigstone was drilled in late-2012 to 4,455 m depth with a lateral length of 1,424 m. The well was completed using a 20-stage slickwater hybrid completion. Total drill and completion costs were estimated at $8.3 million. East Bigstone is northwest of Edmonton, Alta.

The well was brought on production Jan. 27. During its first 12 full days on production, the well averaged 4.2 MMcfd of raw gas. Associated condensate and natural gas liquids also were produced.

Total production rate over this initial period was 990 boe/d, of which 37% was NGLs.

Initial results of this well, and particularly a new completion design employed, were very encouraging as compared with the first three wells drilled in East Bigstone, which were completed with gelled oil hydraultic fracturing, Delphi said.

Delphi expects to commence drilling operations after spring break-up on the previously announced farm-in acreage to earn a 75% interest in the Montney and Nordegg on the 32.5-section land block. All total, Delphi will hold an average working interest of 85% in 78.5 sections of prospective Montney and Nordegg rights in the Bigstone area.

The company's Montney production at East Bigstone was shut-in on Feb. 12 because of unscheduled pipeline repairs on a third-party main gathering pipeline. The outage was expected to continue until early March.

PROCESSINGQuick Takes

Rising gas supply aids methanol outlook

Greater availability of natural gas in New Zealand is behind the restart and expansion of methanol plants in New Zealand, said Methanex Corp., Vancouver, BC.

Methanex plans to increase operating capacity at its New Zealand operations to 2.2 million tpy, a gain of 700,000 tpy, by the end of 2013. The company secured a new natural gas supply that will enable the restart of the methanol plant at its Waitara Valley site by late in the third quarter, adding 500,000 tpy of production.

In addition, Methanex will add capacity at the Motunui site by increasing distillation to add another 200,000 tpy. Capital cost of the two projects is a combined $65 million.

As a result of the improved natural gas supply position that continues to develop in the country, Methanex has "arrangements in place to underpin production at our three-plant operation in New Zealand for years to come."

LPG vessel orders grow, but spot charter rates flat

Rising demand has prompted owners to order more and larger LPG vessels, according to Drewry Maritime Research.

LPG demand has been improved by a growing consumption base in emerging economies, with supply bolstered by an expected emergence of new export sources, notably the US and the Russia.

Drewry expects LPG demand in the so-called saturated markets, such as Japan and South Korea, to remain robust on the back of government support and increasing consumption in sectors other than residential. China has also been investing in propane dehydrogenation units, which could cause its imports to recover in the medium and long term.

These market expectations, from both the supply and demand side, have led ship owners to believe that medium and long-term tonne-mile demand could rise. Newbuilding activity has gained momentum in response, said Drewry.

Only five VLGCs orders occurred in 2010 and four in 2011, but there were 11 orders for VLGCs, aggregating more than 900,000 cu m, during 2012. The average vessel size has also grown, to 32,125 cu m last year from 15,179 cu m in 2010, on the back of the 11 VLGC orders.

Gibson Shipping Energy, meanwhile, saw spot charter rates for available VLGC as relatively flat, following recent sharp declines. Ex-dry dock vessels have been particularly difficult to book due to accessibility issues with some Japanese receivers. Discussion focused on the Atlantic, according to Gibson, with cargoes out of Houston being talked as far out as mid-April but first-half March discussion also still heard for ex-West Africa and Algeria volume.

FACTS Global Energy, Honolulu, has projected LPG exports from the US Gulf to approach 10 million tons/year by 2020, compared with 3.3 million tpy in 2011 (OGJ Online, Oct. 1, 2012).

Latin America has so far received the bulk of LPG exports from the US, but as volumes grow FGE expects US producers to increasingly seek outlets in Europe and Asia.

TRANSPORTATIONQuick Takes

QGC connects Curtis Island plants to mainland

QGC Pty. Ltd. simultaneously laid two 1-m gas pipelines across Gladstone Harbor, using the same trench to connect the Queensland Curtis LNG project and Australia Pacific LNG project—both on Curtis Island—to the mainland.

The segments will connect each project's main pipelines from Surat basin gas fields, about 300 km inland, to the Curtis Island LNG plants.

Pipelay entailed winching the lines 2.3 km from the mainland to Curtis Island in what QGC described as Australia's longest large-diameter underwater pipe pull. The harbor crossing involved construction of temporary facilities including a 2-km road, two bridges, and a railway line to move the pipes across two creeks, marshes, and mud flats. A temporary 450-tonne capacity winch on Curtis Island pulled the pipes—which together weigh 8,000 tonnes—through the subsea trench, which will now be filled with gravel and rock to protect the pipelines.

Co-locating the pipelines and installing them concurrently minimized environmental and boating disruption, QGC said. The crossing follows raising the roof on Queensland's first LNG storage tank, completed Feb. 8.

QGC, a BG Group company, managed the project, with lay work completed by MCJV, a joint venture of McConnell Dowell Constructors (Aus.) Pty. Ltd. and Consolidated Contracting Co. Australia Pty. Ltd. BG agreed last year to sell a stake in Queensland Curtis LNG to China National Offshore Oil Corp. (OGJ Online, Oct. 31, 2012).

Gazprom approves Vladivostok LNG investment

Gazprom's management committee has approved investment in the Vladivostok LNG export project in Russia.

The LNG plant, to have three trains with capacities of 5 million tonnes/year each, is part of Gazprom's Eastern Gas Program integrating field development and transportation projects (OGJ Online, Nov. 1, 2012). The plant will be built on the Lomonosov Peninsula in Perevoznaya Bay.

The first Vladivostok train is to start up in 2018, receiving gas from the Sakhalin, Yakutia, and Irkutsk production centers. Target markets are in the Asia-Pacific region.

Gazprom said the LNG development plan includes establishment of a special-purpose company and the start of negotiations with LNG purchasers.