OGJ Newsletter

March 23, 2015
International news for oil and gas professionals


Tillerson: NorAm energy revolution needs sound policies

The US government needs to adjust its energy policies to ensure the country realizes all the benefits of the new era of energy abundance, said Rex W. Tillerson, ExxonMobil Corp. chairman and chief executive officer, during a Mar. 12 address to The Economic Club of Washington.

Tillerson specifically called for Congress and the White House to enable US exports of oil and natural gas, approve the Keystone XL crude oil pipeline, and make the regulatory process less burdensome and more transparent.

"No one can say for sure how the industry will evolve next or where it will go, but one of the enduring lessons of our industry is that sound policy rewards wide and disciplined investments, spurs economic growth and improved environmental performance, and leads to greater peace and prosperity."

Tillerson boasted recent growth in the US energy sector, and its impact on the American economy, mentioning breakthroughs in the integration of hydraulic fracturing and horizontal drilling as a major driver of the industry's expansion.

He noted that while the energy sector accounts for just less than 7% of the American economy, it has accounted for about 30% of the nation's economic growth since the 2008 financial crisis. "The energy industry has been an economic engine for the entire nation at a time of recession, slow growth, and falling labor participation rates," he said, also highlighting the environmental strides that have been made in recent years.

"Because natural gas emits up to 60% less carbon dioxide than other major sources when used for power generation, our abundant and reliable supplies have been instrumental in reducing our nation's carbon dioxide emissions to levels not seen since the early 1990s," Tillerson said.

UK budget includes oil and gas tax relief

The UK government has delivered on promises made late last year to ease the tax burden on the struggling offshore oil and gas industry.

In its budget for 2015-16, the government enacted tax changes announced in its autumn statement and in a subsequent meeting with industry leaders (OGJ Online, Dec. 4, 2014).

Oil & Gas UK Chief Executive Malcolm Webb said the budget announcement "lays the foundation for the regeneration of the UK North Sea."

The trade group estimated the measures will encourage additional investment of £4 billion and development of 500 million boe of oil and natural gas "in the near-term alone."

The key rate changes are cuts in the supplementary charge, paid atop a 30% corporate tax on production begun after 1993, to 20% from 30% and in the petroleum revenue tax on older production to 35% from 50%. The supplementary rate cut is larger than announced earlier.

The budget also provides for a new investment allowance, replacing a complex system of allowances now in place.

According to the government, these and other moves will raise UK production by a cumulative 120 million boe over the next 5 years, boosting output in 2019 by 15%.

Egyptian group, Tamar partners sign gas deal

Partners in Tamar natural gas field offshore Israel have signed a contract for interruptible sales of gas to Dolphinus Holdings Ltd. of Egypt.

Delek Group, a Tamar interest holder, said the Tamar partners will offer Dolphinus at least 177 bcf of gas in the first 3 years of the contract, subject to a rate limit of 250 MMcfd and pipeline capacity constraints.

Dolphinus will take delivery of the gas at Ashkelon, which is connected to Egypt by a pipeline operated by East Mediterranean Gas Co. The Tamar partners must secure an export permit for the sales. Tamar gas moves ashore by pipeline to Ashdod, where it enters the Israel Gas Lines Ltd. system.

Delek said the contract links the gas price to the price of Brent crude oil and includes a minimum level. It described the buyer as a consortium of Egyptian industrial and commercial gas users not owned by the government.

According to Noble Energy, operator, Tamar has capacity exceeding 1 bcfd and has produced an average 750 MMcfd since start-up in March 2013. It plans to expand capacity to 1.5 bcfd next year. Noble last year signed a contract to deliver a total of 66 bcf of Tamar gas over 15 years to a group in Jordan beginning in 2016 (OGJ Online, Feb. 20, 2014).

Exploration & DevelopmentQuick Takes

Gas find ups resource base for Aasta Hansteen field

Discovery well 6706/12-2, drilled by Transocean Ltd.'s Spitsbergen drilling rig for operator Statoil ASA, proved a 105-m gas column in the Nise formation of the Snefrid Nord prospect in the Norwegian Sea.

The Snefrid Nord discovery, drilled to a vertical depth of 2,714 m in 1,312 m of water, is in the Voring area nearby the Luva, Haklang, and Snefrid South discoveries comprising Aasta Hansteen field development.

Statoil estimates the volumes in Snefrid Nord at 31-57 million boe recoverable. The discovery will be evaluated for future tie-in to the Aasta Hansteen infrastructure.

"The Snefrid Nord discovery increases the resource base for the Aasta Hansteen field development project by around 15%," said Irene Rummelhoff, Statoil senior vice-president, exploration, Norway.

Torolf Christensen, Statoil vice-president for the Aasta Hansteen project, said, "The Snefrid Nord discovery makes the Aasta Hansteen development project more robust and prolongs the Aasta Hansteen production plateau. It will utilize both the Aasta Hansteen and the Polarled gas pipeline capacity."

The company this year is drilling two exploration wells in the vicinity of Aasta Hansteen to prove the area's potential. After completing Snefrid Nord, the Transocean Spitsbergen will move to neighboring production license 602 to drill an exploration well in the Roald Rygg prospect.

"Near-field exploration is the main focus of our Norwegian continental shelf exploration program in 2015," explained Rummelhoff. "By proving additional timely resources, we extend the production life of our fields and create significant value."

Aasta Hansteen, where production start-up is expected in 2017, is the biggest ongoing field development project in the Norwegian Sea, and will have the largest spar platform in the world, Statoil says (OGJ Online, July 13, 2012; Aug. 26, 2014).

Its plan for development and operations was approved by the Norwegian Ministry of Petroleum and Energy in 2013.

Exploration well 6706/12-2 is part of PL218. Statoil holds 51% interest alongside Wintershall Norge AS 24%, OMV (Norge) AS 15%, and ConocoPhillips Skandinavia AS 10%. Wintershall farmed into the acreage last year (OGJ Online, Dec. 1, 2014).

Wintershall to drill well in Aguada Federal block

Wintershall Holding GMBH plans to drill an exploratory well on the Aguada Federal block in central Argentina to examine the potential of shale rock in the Vaca Muerta formation.

The German company has plans for a second well this year. Depending on results from the vertical wells, Wintershall plans to drill up to six horizontal wells in the area.

Operator Wintershall Energia SA gained a 50% interest in the block in Neuquen province in 2014. Gas y Petroleo del Neuquen SA also has 50% (OGJ Online, Apr. 8, 2013).

"There is a great deal of potential in shale rock in Argentina, but we need additional insights regarding the exact nature of the reservoir," said Mario Mehren, a Wintershall director responsible for exploration and production in Argentina.

Active in Neuquen province for more than 20 years, Wintershall also holds shares in San Roque, Aguada Pichana, and Bandurria blocks.

Santos finds more wet gas in west Cooper basin

Santos Ltd. and Drillsearch Energy Ltd. have discovered wet gas in their Kyanite-1 wildcat in permit PEL 513 in the western Cooper basin fairway in South Australia.

It is the fourth discovery for the pair in the last five wells of their proposed eight-well exploration program in the region in 2015.

Kyanite-1 was drilled to a total depth of 3,354 m. Wireline logs have confirmed an aggregate estimate of 24.2 m of net gas pay over several intervals in the Permian-age Patchawarra formation with a gross interval of 534.3 m.

In addition, 8.5 m of net gas pay was encountered in the underlying Tirrawarra Sandstone/Merrimelia formation over a gross interval of 59.1 m.

Formation pressure testing indicates good permeability and there is also potential for unconventional hydrocarbons in several zones.

Kyanite-1 result is enhanced by being close to existing infrastructure. The well has been cased and suspended as a future gas producer.

Santos has 60% of the permit; Drillsearch has 40%. Drillsearch is being free-carried through the remainder of 2015.

Drilling & ProductionQuick Takes

Knarr field oil flow starts offshore Norway

Production has begun at deepwater Knarr oil field in the Norwegian North Sea.

Operator BG Group didn't report initial flow rates but said the Petrojarl Knarr floating production, storage, and offloading vessel has capacity of 63,000 boe/d. The vessel, moored in 400 m of water about 45 km northeast of Snorre field, can store 800,000 bbl of oil.

Oil flow has started from Knarr field in the Norwegian North Sea, and field operator BG Group said the Petrojarl Knarr FPSO vessel, moored in 400 m of water 45 km northeast of Snorre field, has a production capacity of 63,000 boe/d and can store 800,000 bbl of oil.

BG is operating the FPSO, built by Samsung Heavy Industries in South Korea, under a 6-year contract with extension options from Teekay, which also is providing shuttle tankers.

Development included six wells drilled through two drilling templates and connected to the FPSO via a 4.5 km pipework bundle. Associated natural gas moves through a new, 106-km, 12-in. pipeline linked to existing systems and operated by Gassco (OGJ Online, Mar. 2, 2015).

BG estimates gross reserves at 80 million bbl of oil in the Lower Jurassic Cook formation. It expects the field to produce for at least 10 years. The field's former name was Jordbaer.

Interests in the license, PL373 S, are BG 45%, Idemitsu Petroleum Norge 25%, Wintershall 20%, and DEA Norge 10%.

Petrobras starts up P-61 platform in Papa Terra field

Petroleo Brasileiro SA (Petrobras) has started up the P-61 tension-leg platform in Papa Terra field on the southern tip of the Campos basin, 110 km offshore Brazil.

Sitting in 1,200 m of water, platform P-61 operates alongside the P-63 floating production, storage, and offloading unit, which began operations in November 2013 (OGJ Online, Nov. 12, 2013). Thirteen production wells will be interconnected to P-61. The platform's first well, PPT-16, is currently operating. Five production and six injection wells are interconnected to P-63, with five more injection wells slated to be added.

Production from P-61 is transferred via flexible lines to P-63, which is capable of processing 140,000 b/d of oil and 1 million cu m of gas, and injecting 340,000 bbl of water.

Shuttle tankers transport the oil from the field, and surplus gas not consumed on the platforms is injected into a nearby reservoir. The P-61 topside was built at the Keppel Felds shipyard in Singapore. The hull and topside were combined at the Brasfels shipyard in the city of Angra dos Reis, Rio de Janeiro.

The presence of reservoirs with 14-17° gravity oil, as well as the project's large water depths, have made the development of Papa-Terra field one of Petrobras' most complex projects, the company says.

P-61 is connected to a tender-assisted drilling platform, and equipped with a drilling and well completion rig, representing the first time that such a platform has operated off Brazil. Its wells are dry completion, meaning well control valves reside on the platform instead of on the sea floor.

The P-63 production wells are connected to the platform through subsea flexible pipes equipped with electric heating known as an Integrated Production Bundle. The field's 18 production wells feature subsea centrifuge pumps.

Petrobras operates Papa Terra with 62.5% interest, partnering with Chevron Corp. 37.5%, whose presence Petrobras says is significant given Chevron's experience with such complex deepwater projects.

Lukoil completes deal to enter Etinde PSA

OAO Lukoil has completed its deal to enter the Etinde production-sharing agreement offshore Cameroon in the Gulf of Guinea. Lukoil took 30% interest, down from the previously reported 37.5%, from Bowleven PLC, which maintains 20%. Additionally, operator New Age (African Global Energy) Ltd. took 10% from Bowleven in the deal, down from the previously reported 12.5%, and now holds 30% in the project. Lukoil has already met all preliminary conditions of the acquisition agreement signed in June 2014 (OGJ Online, June 24, 2014).

Cameroon's state-owned Societe Nationale des Hydrocarbures is the other partner with 20%.

In return, Bowleven receives $250 million, including $165 million in initial cash proceeds; an estimated $5 million cash to follow for working capital; up to $40 million (net) carry for two Etinde appraisal wells, including testing; $15 million cash to be received on completion of appraisal drilling; and $25 million cash contingent upon and to be received at Etinde development project FID.

"Planning for the appraisal drilling on the Intra Isongo is already under way with locations for the two wells nearing finalization," said Kevin Hart, Bowleven chief executive. "With a carry in place to cover our share of drilling and testing we are looking forward to appraising this exciting reservoir interval."

The Etinde PSA was signed in 2008. The license to develop the Etinde area, valid for 20 years, was issued in July 2014.


Puma Energy acquires Milford Haven refinery

Singapore-based Puma Energy Group Pte. has purchased a series of UK midstream and downstream assets from Murco Petroleum Ltd., a subsidiary of Murphy Oil Corp., including the shuttered 135,000-b/d Milford Haven refinery at Pembrokeshire, Wales.

Under the agreement's terms, Puma Energy will convert the closed refinery into a state-of-the-art storage facility, the company said.

In addition to the Milford Haven refinery, the acquisition includes three inland terminals at Westerleigh, Theale, and Bedworth, as well as Murco's UK wholesale and distribution business, Puma Energy said.

The purchase of Murco's assets will increase Puma Energy's midstream storage capacity by about 1.4 million cu m from its previous 5.6 million cu m, the company said.

This latest deal follows several failed attempts by Murphy to sell the Welsh refinery and inland terminals, the most recent of which occurred late last year (OGJ Online, Nov. 5, 2014).

While Murphy earlier had tried to work with local unions, staff, and government to find a solution to keep the Murco plant in operation (OGJ Online, Apr. 3, 2014), the company formally announced in November 2014 following the failed sale that it would officially decommission the already idled refinery to be operated as a petroleum storage and distribution terminal.

The refinery's closure and conversion into a storage and distribution hub follows Murphy's decision to divest its UK downstream operations as part of the company's global exit from the midstream and downstream sectors (OGJ Online, Oct. 16, 2012; July 23, 2010).

Shell wraps cracker revamp at German complex

Shell Chemicals Ltd., a subsidiary of Royal Dutch Shell PLC, has completed upgrades to improve efficiency and boost production volumes 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 revamp, which involved modifications to furnaces, compressors, column systems, tubes, and pipes at the complex's 2A naphtha steam cracker, already has lowered stack temperatures and reduced fuel consumption at the plant, Shell said.

The project also has enabled the upgraded 2A steam cracker to increase production of ethylene, propylene, C4, and pygas by 15%, the company said.

The decision to increase throughput and improve feedstock flexibility at the 2A cracker came in late 2011, following the shuttering of the Wesseling plant's 2B cracker as part of the company's strategy to strengthen both its refining-chemicals integration and feedstock position of core manufacturing locations across the world, according to Graham van't Hoff, executive vice-president for Shell Chemicals.

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, Shell recently told investors.

NIS lets contracts for unit at Serbian refinery

Serbia's JSC Naftna Industrija Srbije (NIS) has let contracts to CB&I, Houston, for technology licensing and front-end engineering design for a delayed coking unit at its 4.8 million-tonne/year refinery at Pancevo.

CB&I's scope of work on the project also will include an extensive process planning study designed to evaluate how best to integrate the delayed coker with the refinery's existing fluid catalytic cracker (FCC) and hydrocracker, CB&I said.

The refinery's existing FCC and hydrocracker employ technology previously licensed respectively by CB&I and Chevron Lummus Global, a CB&I-Chevron joint venture, the service provider said. A value of the contract was not disclosed.

In September 2014, NIS completed a $5.5 million planned modernization overhaul of the Pancevo refinery, which involved the renovation of all refining processes at the plant as well as replacement and inspection of refinery equipment (OGJ Online, Aug. 25, 2014).

The company most recently completed a modernization of Pancevo's FCC complex in August 2013 to enhance production of high-quality gasoline, which was preceded by the November 2012-commissioning of a new hydrocracking and hydrotreating complex at the refinery to enable increased output of Euro 5-standard fuels.

In 2009, NIS awarded a contract valued at more than $70 million to CB&I to provide detailed engineering, procurement services, construction management, and commissioning for the Pancevo refinery's hydrocracking-hydrotreating complex, including all associated support, auxiliary, and offsite systems, according to an Oct. 15, 2009, release from CB&I.


Pluto LNG plant production shut after Cyclone Olwyn

Woodside Petroleum Ltd. has temporarily shut-in production at its Pluto LNG plant after the Atwood Osprey submersible drilling rig drifted near Pluto flowlines during Cyclone Olwyn, which impacted the Australia's northwest coast on Mar. 12.

The rig, contracted to Chevron Australia Pty. Ltd. by Atwood Oceanics Inc., parted several mooring lines and drifted 3 nautical miles from its original position at the Iago 1B well.

Underwater inspections have confirmed the integrity of the flowlines. Production will be restarted from the plant when the rig has been relocated away from Pluto development area.

The rig is currently stable with a support vessel in position, and preliminary results indicate minimal damage. It's estimated to be out of service for 30 days while repairs are made. No rig personnel were injured in the event.

The Iago 1B well had been shut down and secured in accordance with Chevron's cyclone demobilization procedures, and the rig had ballasted down and evacuated all its rig personnel in advance of the cyclone.

Atwood Oceanics says it's coordinating its efforts with Chevron, the Australian offshore regulator, and other affected parties. Woodside's $15-billion (Aus.) Pluto facilities on the Burrup Peninsula started production in 2012 (OGJ Online, May 7, 2012).

DNV GL updates two pipeline guides

DNV GL has updated recommended practices for corroded pipelines and for integrity management of submarine pipeline systems. The update to DNV-RP F101, dealing with corroded pipelines, includes new methods for estimating pressure resistance of a pipeline containing long axial grooving and for assessing internal corrosion development with time. The pressure-resistance estimation methodology is applicable to pipelines with other patterns of internal corrosion, DNV GL said.

Other updates enhance compliance with the newest edition of the offshore standard DNV-OS-F101 rev. 2013-10 in areas such as pressure definitions and terminology, characteristic material properties, partial safety factors and fractile values, and supplementary material requirements.

The revision of DNV-RP-F116, covering offshore pipeline integrity management, provides more-comprehensive guidelines for carrying out risk assessments. Also revised are guidelines for integrity management reviews and recommendations for identifying key performance indicators.

US industry scoreboard - 3/23

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