OGJ Newsletter

May 18, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Noble to acquire Rosetta for $2.1 billion

Noble Energy Inc., Houston, has agreed to acquire Rosetta Resources Inc., Houston, in an all-stock transaction valued at $2.1 billion, plus the assumption of Rosetta's net debt of $1.8 billion as of Mar. 31. The deal is expected to close in the third quarter.

Rosetta's liquids-rich asset base includes 50,000 net acres in the Eagle Ford shale and 56,000 net acres in the Permian basin, of which 46,000 acres are in the Delaware basin and 10,000 are in the Midland basin.

Noble says it has identified more than 1,800 gross horizontal drilling locations. Of that total, the Permian features 1,200 locations, of which about 700 are in the Wolfcamp A interval, with the rest split among Bone Springs and other Wolfcamp zones. The remaining third are in the Eagle Ford. The company overall sees net unrisked resource potential of 1 billion boe.

Rosetta's assets produced 66,000 boe/d in the first quarter and had yearend 2014 proved reserves of 282 million boe. More than 60% of Rosetta's current production and proved reserves are liquids. Noble anticipates a compounded production growth rate from these assets over the next several years of 15%/year, generating positive free cash flow on an annual basis.

Rosetta shareholders in the deal will receive 0.542 of a share of Noble common stock for each share of Rosetta common stock held. Following the deal, Rosetta shareholders are expected to own 9.6% of Noble outstanding shares.

Both companies' boards have unanimously approved the terms of the agreement, and Rosetta's board has recommended that its shareholders approve the deal. Completion is subject to the approval of the Rosetta shareholders and certain regulatory approvals and customary conditions.

Noble's US onshore acreage comprises core operations in the DJ basin and Marcellus shale (OGJ Online, Feb. 20, 2015). The firm last week reported a first-quarter net loss of $22 million.

Seven Group increases interest in Beach Energy

The diversified Seven Group Holdings, Perth, media combine has taken another bite of Beach Energy Ltd., Adelaide (OGJ Online, Feb. 3, 2015). It has increased its interest in Beach from 16.24% up to 18.29% following the acquisition of an extra 26.6 million shares at prices of about $1.12 (Aus.)/share.

Earlier this month, Seven moved from 13.79% to 16.24%. The company has been gradually acquiring Beach shares since Mar. 11. Seven is now nearing the 19.99% threshold that would require it to make a takeover offer, although there is no indication that it plans that objective.

Seven has also been buying up Beach's partner and rival in the Cooper basin, Drillsearch Energy Ltd., Sydney. Seven has 18.86% of Drillsearch, again nearing a takeover threshold.

The company has said nothing about its energy ambitions and may simply want seats on the boards of both companies that have good cash flows from the Cooper basin fields.

Seven also has an interest in the Crux and Echuca Shoals gas-condensate fields in the Browse basin off Western Australia via its takeover of Nexus Energy last year.

APPEA appoints Roberts as chief executive officer

The Australian Petroleum Production & Exploration Association has appointed Malcolm Roberts as its chief executive officer, following the resignation of David Byers earlier this year to take up a senior role in public policy and government affairs with BHP Billiton.

Roberts is currently chairman of the Queensland Competition Authority. Before that Roberts served as chief-of-staff to Australian Government Minister for Industry Ian Macfarlane and has worked in the Department of the Prime Minister and Cabinet.

Roberts also has been chief executive officer with the Energy Networks Association and had leadership roles with the National Generators' Forum, the Australian National Retailers Association, and the Housing Industry Association.

Roberts will take up his APPEA role in mid-June, succeeding acting Chief Executive Officer Paul Fennelly.

Exploration & DevelopmentQuick Takes

Karoon reports test results for Echidna wildcat

Karoon Gas Australia Ltd.'s test of the Echidna-1 wildcat in the Santos basin offshore Brazil resulted in a stabilized flow rate of 4,650 bo/d from Paleocene reservoirs with a flowing head pressure of 504 psi on a 1-in. choke.

The flow, over a 2-hr period, was constrained by the test facilities. An earlier DST in the Paleocene over the intervals 1,767-1,806 m and 1,813-1,843 m over a 24-hr period averaged a stabilized flow of 3,200 bo/d through a 44⁄64-in. choke with a wellhead flowing pressure of 733 psi and a gas-oil ration of 701 cf/bbl.

Physical oil samples measured 38.6° API with a gas-oil ratio of 701 cf/bbl. There was no measurable carbon dioxide or sulphur dioxide present and no sand production.

Echidna-1 was drilled on Block S-M-1102 and intersected a 213-m gross thickness oil column with 104 m of net pay across Paleocene and Maastrichtian reservoirs.

Karoon says the Maastrichtian section will be evaluated with cores and production tested in "more optimally located appraisal wells on the field."

The company added that the Paleocene reservoir quality at Echidna is better than observed anywhere else in Karoon's Brazilian acreage.

Operator Karoon, with 65% interest, and Pacific Rubiales Energy Corp., with the remaining interest, have decided not to take up a second well option.

Instead the joint venture will continue geoscience and engineering work to characterize both Echidna and the earlier Kangaroo discoveries. Further appraisal drilling is planned in the near term. Pre-FEED studies will be conducted in parallel with the appraisal drilling program.

Both Kangaroo and Echidna confirm the validity of the salt flank play in the region and other prospects with a similar play type are present in the acreage.

Cairn-led JV contracts drillship for work off Senegal

A joint venture led by Cairn Energy PLC and containing ConocoPhillips and Perth-based FAR Ltd. has signed up the Ocean Rig Athena drillship to drill as many as 6 wells surrounding its SNE-1 oil discovery late this year into 2016 (OGJ Online, Apr. 14, 2015).

The JV has formally submitted a 3-year evaluation plan to the government of Senegal for 3 firm and 3 optional exploration and appraisal wells.

Ocean Rig Athena is currently working for ConocoPhillips offshore Angola.

The drilling program will comprise two appraisals of SNE-1 including cores through, and tests of, the reservoir. There also will be 1 shelf exploration well within a 25-km radius of the discovery.

In addition the group plans a 2,000-sq-km 3D seismic survey over the Sangomar and Rufisque blocks to aid understanding the prospectivity of the contract area.

SNE has a gross estimate 2C contingent resource of 330 million bbl with excellent reservoir characteristics. Operator Cairn hopes to develop the field by 2020, subject to a successful appraisal campaign.

The three contingent wells are subject to ongoing evaluation of the FAN-1 discovery and the results of the 3 firm wells.

Drilling & ProductionQuick Takes

EIA: Oil output from US shale to fall 86,000 b/d in June

Crude oil production in June from seven major US shale plays is expected to decrease 86,000 b/d compared with May to 5.6 million b/d, about even with where the total stood in March, according to the US Energy Information Administration's latest Drilling Productivity Report (DPR).

The DPR focuses on the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica, which altogether accounted for 95% of US oil production increases and all US natural gas production increases during 2011-13.

The total June decline represents a 47,000-b/d loss in the Eagle Ford to 1.6 million b/d, a 31,000-b/d loss in the Bakken to 1.3 million b/d, and a 16,000-b/d loss in the Niobrara to 411,000 b/d.

The Permian has maintained production growth over the past few months, albeit at a shrinking rate. Output from the basin in June is expected to increase 7,000 b/d-a third of total growth for April-to 2.1 million b/d.

New-well oil production/rig will continue to rise across the board in June, with the Permian up 26 b/d to 296 b/d, Bakken up 21 b/d to 631 b/d, Eagle Ford up 20 b/d to 720 b/d, and Niobrara up 17 b/d to 497 b/d.

US natural gas production, meanwhile, is expected to drop 112 MMcfd in June to 46.2 bcfd, comprising an 81-MMcfd loss in the Eagle Ford to 7.4 bcfd, a 65-MMcfd loss in the Niobrara to 4.6 bcfd, a 30-MMcfd loss in the Bakken to 1.5 bcfd, and a 6-MMcfd loss in the Permian to 6.4 bcfd. Output from the Utica and Marcellus, however, will respectively rise 49 MMcfd and 21 MMcfd to 2.5 bcfd and 16.7 bcfd.

ExxonMobil brings Banyu Urip field on stream

ExxonMobil Corp. has brought on stream its giant Banyu Urip oil field on the Cepu block in East Java, Indonesia, after overcoming disputes with state-run Pertamina.

The field was discovered in 2001 and hailed as one of the largest in Asia in the past 15 years. However, disagreements between ExxonMobil and Pertamina slowed development plans.

A final investment decision was made in 2012, although early limited production did commence in late 2008 (OGJ Online, Dec. 12, 2008).

Pertamina relented because of Indonesia's rising oil demand and declining production from existing fields.

The development has more than 50 subsea wells, a central processing facility, and a 1.7-million bbl capacity floating production, storage, and offloading vessel.

Production began at a rate of 75,000 b/d and is expected to ramp up to 200,000 b/d by yearend.

At full production, Banyu Urip will be Indonesia's largest oil project. Recoverable reserves are estimated to be 375-450 million bbl.

Coniston oil field comes on stream

The Apache Energy-Inpex Corp. joint venture's Coniston oil field, which straddles licenses WA-35-L and WA-55-L offshore Western Australia, has been brought on stream 2 years later than scheduled.

The project includes development of Coniston field and nearby Novara field via a subsea tieback to systems already in place for Van Gogh field.

The development also makes use of Van Gogh's Ningaloo Vision floating production, storage, and offloading vessel, which was recently modified for the subsea hook-up in Singapore.

The vessel can process 150,000 b/d of liquids, which includes 63,000 b/d of oil. It has storage capacity for 540,000 bbl of oil. The new development includes six Coniston production wells and one production well at Novara connected to a new subsea manifold at Coniston and a pipeline end manifold at Novara.

The FPSO supplies dry gas for gas-lift in the new wells via 4-in. and 6-in. gas injection lines.

Dual 12-in. flowlines have been laid from the two fields to Van Gogh. Oil then enters the FPSO through flexible flowlines and riser bases.

Development of the Coniston project began in 2011 with a scheduled completion date in 2013. This was pushed out twice-to 2014 and then 2015.

Apache says Coniston will flow at 18,000 b/d. It was found in 2000 and has estimated reserves of 15.7 million bbl of oil. Novara was discovered in 1989.

Apache has 52.501% and Inpex 47.499%, although Apache's Australian business unit was sold in April to a consortium of private equity firms led by Macquarie Bank and Brookfield Holdings for $2.1 billion (Aus.) (OGJ Online, Apr. 7, 2015).

BPTT to start drilling in Juniper gas field

Starting next week, BP Trinidad & Tobago LLC (BPTT) reported it will begin drilling its first of five wells in its Juniper natural gas field 50 miles offshore Trinidad and Tobago's southeast coast in the next week. BPTT has reported that the wells will be drilled by Diamond Offshore Drilling Inc.'s Ocean Victory semisubmersible drilling rig.

The Juniper project, BPTT's first subsea field development, will have a production capacity of 590 MMscfd and is expected to start production in 2017.

The rig, which is capable of drilling to 25,000 ft in as much as 6,000 ft of water, is under contract for an initial 2-year term. It is expected to drill 5 subsea wells, which will be tied back to Juniper platform.

This will be the third rig in operation on BPTT's offshore facilities, joining the SKD Jaya and the Rowan EXL II.

BPTT let a contract to Technip for the design, detailed engineering, procurement, construction, load out, and mechanical completion of 4,300-short-ton topsides and a 6,100-short-ton jacket for the Juniper project in 2014's third quarter (OGJ Online, Sept. 9, 2014).

PROCESSINGQuick Takes

Braskem advances Mexican petrochemicals project

Braskem Idesa SAPI, a 75-25 joint venture of Braskem SA, Sao Paulo, and Groupo Idesa SA de CV, Mexico City, is nearing completion of its long-planned Etileno XXI petrochemical complex in the Coatzacoalcos-Nanchital region of the Mexican state of Veracruz (OGJ, July 7, 2014, p. 90; July 1, 2013, p. 90).

By the end of this year's first quarter, physical construction on the project was 92% completed, with all associated engineering and procurement activities concluded, Braskem said.

With precommissioning and testing of equipment and systems at the complex now under way and progressing as planned, the project remains on schedule for start-up during second-half 2015, the company said.

Braskem said the total cost of the project, which initially was pegged at $2.5-3 billion, currently stands at $5.2 billion (OGJ, July 2, 2012, p. 78).

The Etileno XXI complex will include a 1.05 million-tonne/year ethylene cracker that uses Technip technology; two high-density polyethylene plants with capacities of 400,000 tpy and 350,000 tpy, respectively, based upon technology from Ineos; as well as a 300,000-tpy low-density polyethylene plant that uses technology from LyondellBassell (OGJ Online, Mar. 31, 2011).

The complex will also house the following installations: storage, waste treatment, and utilities, including a 150-Mw combined-cycle power and steam cogeneration plant; a logistics platform for shipment of 1 million tpy of polyethylene via rail, truck, or bagged; and administrative, maintenance, control room, and other buildings (OGJ Online, Oct. 5, 2012).

The Braskem-Idesa JV previously signed a 20-year supply agreement with state-owned Petroleos Mexicanos for the supply of 66,000 b/d of ethane based on pricing at Mont Belvieu, Tex., to feed the complex's cracker (OGJ, July 4, 2011, p. 100).

While the Etileno XXI project continues to advance, Braskem's majority shareholder, Odebrecht SA, has extended the timeline for development of its proposed Appalachian Shale Cracker Enterprise (Ascent) petchem complex in Wood County, W.Va., which would include an ethane cracker, three polyethylene plants, and associated infrastructure for water treatment and energy cogeneration (OGJ Online, Nov. 15, 2013).

While Odebrecht has entered a series of agreements for Ascent (OGJ Online, Nov. 4, 2014), a feasibility study for the project now will require more time the company initially expected in view of changing global crude oil and polyethylene prices since the project's conception, Braskem recently told investors.

Fire hits at Shell's German refining complex

Royal Dutch Shell PLC has extinguished a fire that occurred at its Shell Deutschland Oil GMBH-operated petrochemicals plant at Wesseling, Germany, which together with the Godorf refinery near Cologne-Godorf, comprise Shell's 325,000-b/d integrated Rheinland refinery, Germany's largest (OGJ Online, Jan. 11, 2012; Aug. 4, 2009).

The fire, which broke out in a cracker furnace at the Wesseling olefins plant around 2 p.m. local time on May 10, was extinguished by the plant's fire brigade just after 9 p.m., Shell said in a series of releases.

An investigation into the cause of the incident is now under way, Shell said. The company did not disclose details regarding either the impact to processing units or the current status of operations at the refinery.

Shell recently completed a series of upgrades to improve efficiency and boost production volumes at the Wesseling plant, including modifications to furnaces, compressors, column systems, tubes, and pipes at the complex's 2A naphtha steam cracker (OGJ Online, Mar. 17, 2015).

The revamp, which enabled the upgraded 2A steam cracker to increase production of ethylene, propylene, C4, and pygas by 15%, came as part of Shell's late 2011 decision to increase throughput and improve feedstock flexibility at the 2A cracker following the shutdown of the plant's 2B cracker alongside the company's strategy to strengthen both its refining-chemicals integration and feedstock position of core manufacturing locations across the world.

During 2014, Wesseling's 2A steam cracker, which receives advantaged feedstock and absorbs byproduct streams from the nearby Godorf site, had an ethylene production capacity of 272,000 tonnes/year, according to Shell's latest strategy report to investors.

Investigation launched into fire at Greek refinery

An investigation is under way into the cause of an early May fire at Hellenic Petroleum SA's 148,000-b/d refinery in Aspropyrgos, Greece, that left several workers injured.

The fire broke out at 8:20 a.m. local time on May 8 in an unidentified unit and was extinguished by the refinery's on-site firefighting team, Hellenic Petroleum said.

The incident, which occurred during scheduled maintenance on the unit, sent six workers to regional hospitals with mild to severe burns.

Panagiotis Lafazanis, Greece's minister of reconstruction of production, environment, and energy, who visited the refinery to meet with Hellenic Petroleum officials on the day of the incident, has called for an immediate investigation into the cause of the fire, according to a ministry statement.

Details regarding the current status of operations at the refinery have not been disclosed.

The planned maintenance turnaround at the Aspropyrgos refinery was to include a series of upgrades designed to improve energy efficiency at the plant, as well as a splitter debottlenecking project to boost production of propylene, Hellenic Petroleum said in its annual report for 2014.

Hellenic Petroleum also plans to undertake a series of initiatives this year at its other two refineries in Greece as part of the company's long-term DIAS refining excellence program, which aims to optimize and improve the operation, maintenance, and competitiveness of its three Greek processing centers.

At its 100,000-b/d Elefsina refinery, which together with the Aspropyrgos refinery comprises its South Refining Hub, Hellenic Petroleum said it expects to complete investments in 2015 for a project to recover hydrogen from the fuel gas stream of the refinery's hydrocracker complex, as well as a project to connect the refinery with a natural gas grid as an alternative source for hydrogen production.

According to its latest annual report, during 2014, Hellenic Petroleum executed the following DIAS-related projects at its Greek refineries: maximizing the capacity of vacuum distillation, hydrocracking, and flexicoking units of the Elefsina refinery; reducing use of fuel oil at the Elefsina refinery; limiting steam losses at the 93,000-b/d Thessaloniki refinery; and installing a new high-efficiency boiler to replace older boilers at the Aspropyrgos refinery.

TRANSPORTATIONQuick Takes

Gazprom, CNPC sign HOA on western route

OAO Gazprom and China National Petroleum Corp. signed a heads of agreement for gas supply via the western route from Western Siberia to China. The companies had signed a framework agreement on the western route last November (OGJ Online, Nov. 11, 2014).

Gazprom said the western route will not affect the Power of Siberia project, an eastern route for gas delivery from the Irkutsk and Yakutia gas production centers to the Far East (OGJ Online, Oct. 14, 2014).

The HOA was signed May 8 in Moscow by Alexey Miller, chairman of the Gazprom management committee, and Wang Dongjin, CNPC vice-president. Attending were Russian President Vladimir Putin and Chinese President Xi Jinping.

The parties also signed another agreement of strategic cooperation outlining main areas of joint actions in the gas sector; an earlier agreement expired last year.

US DOE sanctions LNG exports from Cove Point

The US Department of Energy reported that that it has issued a final authorization for Dominion Cove Point LNG LP to export US-produced LNG to countries that do not have a free-trade agreement with the US from its Cove Point LNG terminal in Calvert County, Md.

The terminal is authorized to export LNG up to the equivalent of 770 MMscfd of natural gas for a period of 20 years.

"The development of US natural gas resources is having a transformative impact on the US energy landscape, helping to improve our energy security while spurring economic development and job creation around the country," DOE said. This increase in gas production is expected to continue, DOE said, adding that the US Energy Information Administration forecasts a record average production rate this year of 72.4 bcfd.

Dominion Cove Point began construction on the export project in the fall after receiving authorization from the US Federal Energy Regulatory Commission (OGJ Online, Oct. 30, 2014).