OGJ Newsletter

Jan. 23, 2012
International news for oil and gas professionals


Dart Energy aggregates unconventional gas business

Dart Energy Ltd., Brisbane, has formed Dart Energy International Shale Pte. Ltd. as a subsidiary that will manage Dart’s European unconventional gas assets acquired in three transactions in 2011.

Dart in February 2011 acquired the 90% of Composite Energy Ltd. it did not own. Composite held 15 unconventional gas licenses for coalbed methane in the UK and three shale gas licenses in Poland. The other two transactions occurred in December 2011.

Dart restructured its arrangements with BG Group PLC such that Dart agreed to acquire BG’s 50% interest in 14 UK CBM licenses and an exclusive 3-month option over a 100% interest in the Saxon I and II shale prospective licenses in Germany.

Dart also agreed to acquire the UK unconventional gas exploration business of Greenpark Energy Ltd., including 22 licenses in the major onshore CBM and shale gas potential regions across the UK. Dart also secured an exclusive option over interests in licenses held by Greenpark in Poland and Spain that are considered prospective for CBM and shale gas.

Dart believes that seven of Greenpark’s UK licenses are also prospective for shale gas and could have shale gas-in-place potential of several trillion cubic feet.

Dart’s combined assets span multiple European jurisdictions characterized by large gas deficits, reliance on imported gas, stable regulatory regimes, extensive and accessible infrastructure, and among the world’s highest current gas prices.

Dart said it sees its European shale portfolio as a stepping stone into the emerging Asian shale gas industry, where multiple governments plan shale gas bid rounds in the next few years.

Pembina Pipeline to buy Provident Energy

Pembina Pipeline Corp. agreed to buy Provident Energy Ltd. for $3.2 billion (Can.) to acquire natural gas liquids assets and create one of Canada’s largest publicly traded pipeline companies in terms of market capitalization. Both companies are based in Calgary.

Terms call for Provident shareholders to receive 0.425 of a Pembina share for each Provident share held. The resulting company will operate as Pembina, which currently operates a crude oil pipeline and natural gas gathering system in western Canada.

The combined company will have a market capitalization of $7.9 billion, Pembina said in a Jan. 16 news release. In comparison, TransCanada Corp. has a market capitalization of $29.2 billion while Enbridge Inc. has a market capitalization of $26.6 billion.

Subject to regulatory approvals, closing is expected after shareholder meetings for both Pembina and Provident. Those meetings are to be scheduled during March. Both companies’ boards are expected to recommend shareholders vote in favor of the transaction.

Bob Michaleski, Pembina president and chief executive officer, said Provident’s NGL extraction, fractionation, and storage assets will accelerate Pembina’s growth plans in those areas. He will retain his title after the deal closes.

“Our expanded footprint will provide greater access to natural gas liquids markets across North America, and will allow us to offer customers a significantly expanded spectrum of energy services,” Michaleski said.

Doug Haughey, Provident president and chief executive officer, said the transaction “leverages off Provident’s strong growth as a pure-play midstream business.”

After closing, the combined company would have assets in Montney, Duvernay, Alberta Deep basin, Pelican Lake heavy oil, Athabasca oil sands, Cardium, Swan Hills, Bakken, Marcellus, and Utica plays.

Directors take reins at Connacher Oil & Gas

Two directors of Connacher Oil & Gas Ltd., Calgary, will oversee day-to-day operations of the company on an interim basis after the departure of Richard A. Gusella, chairman, chief executive officer, president, and interim chief operating officer.

Colin M. Evans, Connacher lead director and president of Evans & Co. Inc., and Kelly J. Ogle, director of Connacher and president and chief executive officer of Trafina Energy Ltd., have been appointed interim comanaging directors.

Connacher produces bitumen and conventional crude oil and natural gas in Canada and operates a 9,500 b/d heavy oil refinery in Great Falls, Mont.


New Zealand East Coast basin shale pursuit resumes

Exploratory drilling has resumed in New Zealand’s nonproducing East Coast basin after a long hiatus.

New Zealand Energy Corp., Vancouver, BC, will deepen the Ranui-1 well drilled to a total depth of 1,134 m by a previous operator on the 100% owned Ranui permit.

Initial drilling encountered 224 m of prospective Whangai shale, but the well did not reach the base of the shale. Upon reentry, NZEC will core as many as four Whangai shale intervals and drill through the base of Whangai into conventional reservoir sands to a planned 1,500 m. The company will run a full suite of open hole logs.

The company is analyzing core from two other test holes drilled in late 2011 on its 100% owned Castlepoint permit. The Orui core hole, TD 125 m, and Te Mai core hole, TD 195 m, cored and tested the Waipawa and Whangai shales. The two shales source more than 300 oil and gas seeps in the basin.

A review of the geochemical and physical properties of the two shale packages will help focus NZEC’s exploration strategy for the shales. The company’s technical team will reprocess existing seismic and plans to shoot 50 line-km of 2D seismic in 2012.

NZEC has two granted permits and one pending permit in the basin that combined cover more than 1.8 million acres.

Mozambique appraisal well cuts 777 ft of gas pay

A well that appraised the Anadarko Petroleum Corp. group’s Lagosta and Camarao discoveries has logged the largest pay count of any well in the complex offshore Mozambique to date.

Lagosta-2, 4.4 miles north of the Lagosta discovery and 5.3 miles south of the Camarao well, encountered 777 total net ft of natural gas pay in multiple zones.

Anadarko said the results “support our recoverable resource estimates of 15 to 30+ tcf of natural gas in the discovery area on our block, as well as provide additional information that will be incorporated into our models to help determine the optimal subsea development plans for the complex.”

Meanwhile, a second deepwater drillship, the Deepwater Millennium, arrived in Mozambique to begin an accelerated test program that will include installing observation gauges and conducting several drillstem tests. Final investment decision for the project is expected in 2013.

Lagosta-2 went to 14,223 ft in 4,813 ft of water in Offshore Area 1 in the Rovuma basin. The partnership will preserve Lagosta-2 for future use during the planned drillstem test program in the Windjammer, Barquentine, and Lagosta complex. Once operations are complete, the Belford Dolphin deepwater drillship will drill the Lagosta-3 appraisal well.

Anadarko is operator of 2.6-million-acre Offshore Area 1 with a 36.5% working interest. Co-owners are Mitsui E&P Mozambique Area 1 Ltd. 20%, BPRL Ventures Mozambique BV 10%, Videocon Mozambique Rovuma 1 Ltd. 10%, and Cove Energy Mozambique Rovuma Offshore Ltd. 8.5%. Mozambique’s Empresa Nacional de Hidrocarbonetos EP’s 15% interest is carried through the exploration phase.

Oregon enhanced geothermal well project nears

A field test of a technology known as enhanced geothermal systems could take place in mid-2012 at the inactive Newberry volcanic site in Deschutes County, Ore., 20 miles south of Bend.

Project operator AltaRock Energy Inc., Seattle, would intermittently inject 24 million gal of cold water into an already drilled 10,600-ft well at Newberry.

The water is expected to create fractures, starting about 6,000 ft deep, in a microseismicity process called hydroshear, similar to hydraulic fracturing, after which biodegradable plastic particles are dropped to seal the fractures temporarily.

Then more cold water is dumped, ostensibly creating successive fracture systems as deep as the bottom of the well and as far as 3,000 ft in diameter. After the plastic disintegrates, water could be circulated to create steam to generate electricity at the surface.

How large a fracture system could be created and how much steam it would return at what temperature are unknown. The technology’s likelihood of inducing earthquakes is also a concern.

The US Department of Energy is funding about half of the project’s $43 million cost. The other contributors include AltaRock, Davenport Newberry Holdings LLC, Stamford, Conn., and Google. The US Bureau of Land Management is accepting public comments on the project.

Developing a commercial project is considered to be at least a decade away. A few generating projects exist worldwide in known geothermal resource areas, but AltaRock maintains that if the fractures can be created artificially projects could be sited almost anywhere hot rocks exist near the surface for conventional rigs to drill multiple production wells.

CNPC gets three Afghanistan Amu Darya blocks

China National Petroleum Corp. has been awarded three Amu Darya basin exploratory blocks in Afghanistan’s 2011 license round.

The blocks are understood to be Kashkari, Bazarkhami, and Zamarudsay, which surround and lie east of the city of Faizabad in northwestern Afghanistan (see map, OGJ, May 4, 2009, p. 52).

Press reports said the Afghan cabinet approved the 25-year deal, which is to be signed in late January 2012, and that field work will likely begin in late 2012.

The Amu Darya basin contains giant gas-condensate fields across the border in Turkmenistan. Each of CNPC’s blocks contains one or more oil fields discovered in earlier years. The Kashkari block, which covers 425,753 acres, includes Angot, discovered in 1967 and understood to be Afghanistan’s only oil field to have been on sustained production.

Angot is 12 km south of the town of Sari Pol, site of Afghanistan’s only refinery.

Five companies had initially qualified to bid in the round: Buccaneer Energy of Australia, CNPC International Ltd., the Petroleum Exploration (Pvt.) Ltd. subsidiary of the Shahzad Group of Pakistan, Schlumberger Ltd. of France, and Tethys Petroleum of the UK (OGJ Online, Apr. 18, 2011).


Fixed platform eyed for field offshore Norway

Statoil proposes to develop Dagny oil and gas field in the Sleipner area of the Norwegian North Sea with a fixed platform and nearby Eirin gas field from the seabed. Dagny was discovered in 1974, Eirin in 1978.

Dagny field oil occurs in the Upper Jurassic Hugin formation at about 3,500 m. The field lies in 120 m of water 30 km north of the Sleipner A platform.

Statoil said recent appraisal drilling established connection between western and eastern parts of the field. The eastern structure is called Ermintrude.

Eirin is about 9 km north of the Dagny discovery well. Most of its gas is in the Upper Triassic Skagerrak formation at a depth of about 4,120 m, according to the Norwegian Petroleum Directorate.

Statoil said subsea Eirin wells will be tied back to the planned Dagny platform. Gas from the Dagny platform will flow through a tieback to Sleipner East field.

The company proposes to load oil onto shuttle tankers from the Dagny platform.

It estimates ultimate production from Dagny and Eirin at 300 million boe.

Statoil, which operates the fields with 58.5% interests, said it will make an investment decision in a year. It envisions the start of production in 2016.

Other provisional interests, subject to negotiation before the development decision, are ExxonMobil Exploration & Production Norway AS 33%, Total 6.5%, and Det Norske 2%.

Fletcher Finucane oil field project gets FID

Santos Ltd. said its $490 million Fletcher Finucane oil field offshore Western Australia has received a final investment decision.

The project, which lies on permit WA-191-P, will be developed through three subsea wells tied back to a Santos-operated floating production, storage, and offloading vessel at Mutineer Exeter field.

Initial gross production is expected to be 15,000 b/d of oil from second-half 2013.

Santos reached FID after buying out Tap Oil’s 8.2% interest in the project for $21.7 million (Aus.).

Tap later said it could not generate sufficient revenue from the sale of oil processed at Mutineer Exeter to warrant the new expenditure.

Anadarko lets Lucius subsea contract to FMC

A group led by Anadarko Petroleum Corp. let a contract to FMC Technologies Inc. to provide subsea systems and services for the deepwater Gulf of Mexico Lucius oil and gas project off Texas.

FMC will provide five subsea production trees and two manifolds for Lucius field on Keathley Canyon Block 875 in 7,100 ft of water.

The Lucius unit, about 275 miles southeast of Galveston, Tex., includes parts of Keathley Canyon Blocks 874, 875, 918, and 919. Anadarko, which operates the unit with a 35% working interest, drilled the discovery well in 2009 (OGJ Online, Dec. 15, 2011).

Subsea system deliveries are scheduled to start in the fourth quarter, FMC said.

Lucius development plans call for using a truss spar with a capacity of 80,000 b/d of oil and 450 MMcfd of gas starting in 2014.

Other participants in the Lucius unit include Plains Exploration & Production Co. 23.3%, ExxonMobil Corp. 15%, Apache Deepwater LLC 11.7%, Petroleo Brasileiro SA 9.6%, and Eni SPA 5.4%.

PROCESSING — Quick Takes

Contracts let for Bataan refinery units

Petron Corp. Mandaluyong City, Philippines, has let contracts for two conversion units in a major upgrade of its 180,000 b/d refinery at Limay, Bataan, about 150 km southwest of Manila (OGJ, Jan. 27, 1997, p. 74).

A subsidiary of Foster Wheeler’s Global Engineering & Construction Group will conduct detailed engineering and procurement services for a 37,500 b/sd delayed coker and engineering and material supply for two coker heaters.

Foster Wheeler handled process design and proprietary technology for the coker.

Earlier, Petron let a contract to Axens to supply technologies for a 15,700 b/sd mild hydrocracker, 35,900 b/sd fluid catalytic cracker, 19,000 b/sd C4 cut purification system, C4 olefins oligomerization unit, two FCC gasoline selective desulfurization units with capacities of 8,000 b/sd and 17,600 b/sd, a 5,800 coker naphtha hydrotreater, and unsaturated LPG treatment units with capacities of 25,000 b/sd and 3,600 b/sd.

The process scheme will maximize production of propylene from the FCC at more than 250,000 tonnes/year.

Daelim Industrial of South Korea has an engineering, procurement, and construction contract for the overall project, which it estimates in value at $2 billion.

OMV eyes sale of Bayernoil refinery stake

OMV AG has taken a step toward refinery divestment in a strategy announced earlier to shift its focus to exploration and production (OGJ Online, Dec. 6, 2011).

The company has appointed Deutsche Bank to assist with what it describes as “the divestment program in the [refining and marketing] business.”

A possible part of that program, it said, is the sale of its 45% stake in the 215,000-b/cd Bayernoil refining complex near Ingolstadt, Bavaria, Germany.

The integrated complex has crude oil distillation and catalytic cracking units with related desulfurization and other facilities at two sites: Vohburg and Neustadt. The Neustadt site also has a mild hydrocracker.

OMV said it is focusing its downstream business on refineries integrated with petrochemicals or upstream operations. Its 209,000-b/cd refinery in Schwechat, Austria, and 72,000-b/cd refinery at Burghausen, Germany, have integrated petrochemicals production. Its 90,000-b/cd Petrobrazi refinery in Ploesti, Romania, is fully adapted to Romanian crude oil (OGJ Online, Apr. 13, 2010).

The company also owns the 70,000 b/d Arpechim refinery in Pitesti but has been operating it intermittently and is reported to be preparing to transfer ownership to the Romanian government.

OMV earlier sold a 52% interest in a Cypriot retail company and announced plans to sell subsidiary downstream companies in Croatia and Bosnia-Herzegovina.


Inpex, Total make FID for Ichthys LNG project

Inpex and Total SA have made the final investment decision to proceed with their $34 billion development of the Ichthys LNG project in northwest Australia.

The two-train, 8.4 million tonne/year project has received its FID, which signals the start of construction of one of the world’s largest LNG facilities and is based on an estimated 40 years’ supply of gas and condensate reserves in the Browse basin field. The gas will be piped more than 800 km to the LNG plant to be built at Blaydin Point near Darwin. Condensate will be sold via a floating production, storage, and offloading vessel at the field, which is off Western Australia.

The investment also is Australia’s second-largest resources project and brings the total capital committed to the country’s LNG sector to more than $175 billion (Aus.). In addition it is the largest single private sector investment ever made in the Northern Territory.

The FID comes just hours after Inpex announced an agreement to sell a 1.575% stake in the project to Tokyo Gas. Previously it had sold Toho Gas a 0.42% equity stake in the project.

In addition Inpex has now firmed up contracts with CPC Corp. of Taiwan and Chubu Electric Power and Toho Gas of Japan to take shipments of LNG from the Ichthys development. This brings total committed gas sales to just under the nameplate capacity of the proposed LNG plant of 8.4 million tpy.

CPC, Chubu, and Toho are buying 1.7 million tpy, 490,000 tpy, and 280,000 tpy, respectively, confirming the nonbinding agreements signed in June 2011.

The FID announcement follows Inpex’s move last week to firm up agreements with five Japanese buyers for 4 million tpy of LNG in December. Inpex and JV partner Total are each taking 1.8 million tpy for their own use.

All agreements are for supply over 15 years.

Ichthys field was discovered in 2000-01. Reserves are put at 12.8 tcf of gas and 527 million bbl of condensate. The project will come on stream at yearend 2016.

In other news, Inpex has been awarded an “exceptional development permit” to build its planned accommodation village for the Ichthys LNG project workers at Howard Springs near Darwin.

The village will house some 2,700 fly-in, fly-out workers needed to build the LNG plant in Darwin Harbour. The village has been designed to be to cope with a further 800 workers if needed.

It is anticipated that work on the village construction will begin early this year.

Inpex has included vegetation buffer zones and low-level lighting to minimize potential impact on the surrounding community.

Partners in the project are Inpex 72.805%, Total 24%, Osaka Gas 1.2%, Tokyo Gas 1.575% and Toho Gas 0.42%.

Inpex lets pipelay contract for Ichthys export line

Inpex Corp. has let a contract to Saipem for the engineering, procurement, construction, and installation (EPCI) of the gas export for the Ichthys LNG project’s gas export pipeline. The 889-km, 42-in. OD pipeline, which will be installed in 275 m of water, will connect the project’s offshore central processing facility to the onshore processing facility in Darwin. Saipem’s currently under-construction Castorone pipelay vessel will complete deepwater work in 2014, while its recently upgraded Semac 1 pipelay barge will lay the shallow water section.

Ichthys LNG is a joint venture of Inpex (76%, operator) and Total SA (24%). Gas from the Ichthys field, in the Browse basin, 200 km offshore Western Australia, will be processed offshore to remove water and extract condensate before transport to Darwin. Inpex expects Ichthys, at peak, to produce 8.4 million tonnes/year of LNG, 1.6 million tpy of LPG, and 100,000 b/d of condensate.

Saipem also won a transportation and installation contract for a 350-km, 20-in. OD Gulf of Mexico gas export pipeline in 100-2,100 m of water. Castorone will perform this work second-half 2013. The pipeline will transport gas from the Lucius and Hadrian South fields.

Castorone is under construction at the Keppel Shipyard in Singapore and is already under contract to lay the Walker Ridge Export Pipeline in the Gulf of Mexico first-quarter 2013 (OGJ Online, Dec. 17, 2010).

Earlier this month Enterprise Products Partners LP and Genesis Energy LP announced plans to build and own an 18-in. OD, 149-mile pipeline for shipment of crude from Anadarko’s Lucius development in southern Keathley Canyon (OGJ Online, Jan. 4, 2012).

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