OGJ Newsletter

Dec. 10, 2012
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Mining firm to buy Plains E&P, MMR Exploration

Freeport-McMoRan Copper & Gold Inc. reported plans Dec. 5 to acquire Plains Exploration & Production Co. and McMoRan Exploration Co. in cash-stock transactions to create what Freeport-McMoran is calling "a premier US-based natural resource company." The two acquisitions will create a corporation worth about $60 billion, including debt, Freeport-McMoRan said.

Terms call for Freeport-McMoRan to pay $6.9 billion in cash and stock for Plains E&P and to pay $3.4 billion in cash for McMoRan Exploration. The $3.4 billion amounts to $2.1 billion net of 36% interest in McMoRan Exploration that already is owned by Freeport-McMoRan and Plains E&P.

Upon closing, McMoRan shareholders also will receive a distribution of units in a royalty trust that will hold a 5% overriding royalty interest on future production in McMoRan's offshore assets.

Freeport-McMoRan is regaining McMoRan Exploration, which was spun off from the mining company in 1994.

The transactions are expected to be finalized during second-quarter 2013, subject to regulatory approvals and customary closing conditions.

Freeport-McMoRan Chairman James R. Moffett said, "The combined mining and oil and gas teams have significant management and share a strong commitment to safety, community development, and environmental management." Freeport-McMoRan is based in Phoenix.

Plains E&P is an independent oil and gas company in Houston that owns assets in California, Louisiana, and the deepwater Gulf of Mexico.

McMoRan Exploration is an independent based in New Orleans. It has assets in the gulf and onshore gulf coast.

IHS: Upstream capital, operating costs rise

Capital and operating costs of oil and gas upstream projects continue to increase in a trend not likely to end next year, according to IHS indexes.

In the 6 months ending Sept. 30, the proprietary IHS Upstream Capital Cost Index, which is based on 2000 costs, increased by 1% to 230. In the 6 months before that period, the index had risen 2.3% (OGJ Online, July 2, 2012).

The new level matched the index peak set in the comparable period of 2008, IHS said.

Of 10 markets tracked in the index calculation, only two had declines: steel, 9%, and engineering and project management, 0.1%.

The IHS Upstream Operating Cost Index increased to 190 in the 6 months ending Sept. 30 from 189 in the preceding period.

Influences in operating costs noted by IHS include oil-price declines, economic uncertainty, high activity levels, and shortages of skilled workers.

IHS said it expects capital and operating costs to rise by 4-5% in 2013.

DOI to hold first wind energy lease sale on OCS

The US Department of the Interior plans to sell leases for wind farms offshore Rhode Island, Massachusetts, and Virginia, marking the first lease sale for wind energy on the Outer Continental Shelf, officials said from Washington, DC, on Nov. 30.

Interior Sec. Ken Salazar announced competitive lease sales are planned for 2013 in two areas. Salazar made the announcement along with Interior Deputy Sec. David J. Hayes and US Bureau of Ocean Energy Management Director Tommy P. Beaudreau.

"As we experience record domestic oil and gas development, we are moving forward at the same time with efforts to ensure that America continues to lead the world at developing the energy of the future," Salazar said.

Hayes said, "Holding competitive lease sales on the wind-rich East Coast is ushering in a new chapter in America's development of renewable energy." Federal officials are working closely with Rhode Island and the other states to identify the best areas for offshore wind farms, he said.

BOEM announced the Proposed Sale Notices to offer 277,550 acres in one area offshore Virginia and another area off Massachusetts and Rhode Island. The areas proposed for leasing are expected to be able to support more than 4,000 Mw of wind generation.

The area of mutual interest proposed for leasing off Rhode Island and Massachusetts covers 164,750 acres and is about 9 nautical miles south of Rhode Island's coastline. The area will be auctioned as two leases, the North Zone and South Zone.

The proposed lease area offshore Virginia will be auctioned as a single lease and covers 112,800 acres about 23.5 nautical miles offshore southern Virginia.

BOEM has posted online more information about the proposed sale notice for Rhode Island and Massachusetts and also the proposed sale notice for offshore Virginia.

Currently, the US has no offshore wind farms although some are in development in state waters off Massachusetts, Rhode Island, New Jersey, and Delaware.

The Cape Wind project, a wind farm under construction in federal water off Cape Cod, Mass., is scheduled to be running in 2015. It was approved before the competitive leasing system for wind energy was implemented.

OMV to sell Bosnia-Herzegovina retail unit

OMV AG, as part of a strategic streamlining of its downstream business enabling it to concentrate on exploration and production, has signed an agreement to sell its marketing subsidiary in Bosnia-Herzegovina to NIS, Novi Sad, Serbia (OGJ Online, Jan. 13, 2012).

NIS will acquire OMV BH, a wholly owned subsidiary of OMV Refining & Marketing based in Sarajevo. The subsidiary operates 28 service stations representing about 8% of the Bosnia-Herzegovina retail market.

OMV didn't report terms of the sale.

Exploration & DevelopmentQuick Takes

Fourth Sergipe-Alagoas UDW well finds oil

Petroleo Brasileiro SA (Petrobras) has discovered oil at a fourth 2012 ultradeepwater discovery in the Sergipe-Alagoas basin offshore Brazil in an area more than 900 miles northeast of most of the company's presalt discoveries in the Santos basin.

The 1-SES-172 (1-BRSA-1108-SES) well, called Muriu, encountered light oil in 67 m of excellent quality reservoirs of the Calumbi formation, which varies in age from Upper Cretaceous to Tertiary in parts of the basin.

The well went to 5,347 m in 2,583 m of water 85 km offshore Aracaju on the SEAL-M-424 block of Petrobras's exclusively held BM-SEAL-10 concession, the third concession on which the company has discovered ultradeepwater hydrocarbons.

The other three discoveries, which Petrobras made between August and October 2012, are 1-SES-168 (Moita Bonita), 3-SES-165 (Barra), and 1-SES-167 (Farfan).

Petrobras said it confirmed the Muriu find through log data analysis, pressure data analysis, and fluid sampling. The firm plans to finish logging and gather rock and fluid data to assess strategy and characterize the reservoir. It will then submit a discovery assessment plan to Brazil's National Petroleum Agency.

N. Platte is giant Lower Tertiary gulf oil find

Cobalt International Energy Inc. has made a Lower Tertiary Wilcox oil discovery in the southeastern part of the Garden Banks planning area in the deepwater Gulf of Mexico.

The discovery's potential is several hundred million barrels of oil, said Total SA, which has a 40% nonoperated interest in the project in which Cobalt is operator with 60%.

Extensive wireline evaluation indicates that the well on its North Platte prospect on Garden Banks Block 959 encountered several hundred feet of net oil pay in multiple Inboard Lower Tertiary sands, Cobalt said. That thickness is in line with the predrill estimate, the company said.

James H. Painter, executive vice-president, Gulf of Mexico, said, "North Platte was one of the most challenging wells that the industry has drilled in the Gulf of Mexico, and to have drilled this well to total depth in a safe manner and in near record time is especially gratifying."

North Platte went to 34,500 ft in 4,400 ft of water. Cobalt had a rig preparing to spud North Platte in May 2010 when the Department of the Interior implemented the 2010 drilling moratorium, requiring Cobalt to move off the rig.

Eni resumes Sirte exploratory drilling in Libya

Eni SPA's North African subsidiary has resumed onshore exploratory drilling in Libya with a well in the Sirte basin that will test a new geological play in EPSA IV 2008 Contract Area A (see map, OGJ, Apr. 18, 2005, p. 29).

The A1-108/4 well is 300 km south of Benghazi and is projected to 14,500 ft. The well is the first of an onshore drilling program that is set to continue into 2013.

Eni noted that it was the first international company to resume production in September 2011, through the Mellitah Oil & Gas 50-50 joint venture with Libya National Oil Corp. in giant Bu Attifel field.

Eni was also the first company to lift force majeure status in Libya, in December 2011, and to resume offshore exploration in February 2012 by shooting a 3D seismic survey.

Drilling & ProductionQuick Takes

RIL seeks arbitration over big KG-D6 fine

Reliance Industries Ltd., Mumbai, has sought arbitration in its dispute with the Indian government over oil and gas fields in the deepwater KG-D6 block offshore eastern India after the government imposed a fine of $1.005 billion (OGJ Online, Aug. 13, 2012).

The Ministry of Petroleum and Natural Gas for months has pressured RIL to increase drilling in response to shortfalls in gas production against projections in development approvals. RIL blames poor reservoir performance.

In a statement, the government said average production from the block in the current fiscal year has been 29.81 MMscfd of gas, compared with 86.73 MMscfd targeted in development plans approved for D1, D3, and MA fields.

It said six of 18 producer wells in D1 and D3 have ceased production because of water loading and sand ingress. In MA field, it said, two oil and gas wells out of six have ceased flowing because of water ingress.

The government blames "nondrilling of the required number of gas producer wells in D1 and D3 fields" set by an addition to an initial development plan.

It said RIL has responded that performance of existing wells in the main channel area and reservoir characteristics of overbank areas indicate that additional wells in D1 and D3 fields might not improve production or recovery rates.

RIL has told the government that reservoir behavior and characteristics vary from predictions and that pressure declines are several times those originally expected.

The company said early watering of some wells was unexpected, although overall water production has been low. And it has told the government geologic complexity hampers its ability to set further drilling locations.

M. Veerappa Moily, who became minister of petroleum and natural gas in October, has rejected RIL's arguments. He imposed the fine in the form of disallowance of the cost of production facilities.

US Chamber report advocates aggressive use of EOR

Wider use of enhanced oil recovery in the US could contribute significant additional revenue to the federal budget, a new report by the US Chamber of Commerce's Institute for 21st Century Energy suggested.

"At a time when lawmakers are seeking to avoid falling off the fiscal cliff, increasing energy production and the resulting government revenue, jobs, and economic growth should be at the top of the agenda," said Karen A. Harbert, the Energy Institute's president.

"We've chosen to highlight carbon dioxide EOR because broader usage of this proven technology could be one of the next big things in energy production, bringing trillions of dollars in new government revenue to our coffers while reducing oil imports," she explained.

The Nov. 27 report said that a US Department of Energy analysis projects that EOR could economically recover 67 billion bbl of oil, assuming a price of $85/bbl. That would translate into $1.4 trillion in new government revenue, as well as billions of dollars in private investment, it indicated.

More aggressive EOR use in the US also would benefit the environment, Harbert added. "EOR will increasingly utilize carbon dioxide that would otherwise be emitted into the atmosphere, while generating additional oil production from fields that are in decline," she said.

"While CO2 EOR shouldn't be seen as a replacement for new production, it is another valuable tool that should be fully realized in our quest to become more self-reliant," Harbert maintained.

Work to start on Heidelberg truss spar hull

Technip will perform early work on a truss spar hull for development of deepwater Heidelberg oil field in the Gulf of Mexico under a letter of intent from operator Anadarko Petroleum Corp. (OGJ Online, Apr. 19, 2012).

It will start construction of the 23,000-ton hull and do other work, including the purchase of long-lead items, in anticipation of project sanctioning about the middle of next year.

The spar, to be installed in 5,310 ft of water, will be able to handle production of 80,000 b/d of oil and 2.3 million cu m/day of natural gas.

PROCESSINGQuick Takes

Sasol to start design work on Louisiana GTL plant

Sasol will proceed with front-end engineering and design for an integrated gas-to-liquids plant and ethane cracker with downstream derivatives at the company's site near Lake Charles, La.

The GTL plant will be the first of its kind in the US and produce 4 million tonnes/year (tpy; 96,000 b/d) of transportation fuel, including GTL diesel and other chemicals. Sasol's own feasibility study proposed the Louisiana plant produce GTL diesel, GTL naphtha, LPG, GTL base oils, paraffin, linear alkyl benzene, and medium and hard wax.

Sasol estimates current project costs for the plant at $11-14 billion. The project will be delivered in two phases, each consisting of 48,000 b/d. The first phase is to begin operations in 2018, the second in 2019.

In September and November 2011, respectively, Sasol had announced it would conduct feasibility studies to evaluate the GTL and the ethylene cracker (OGJ, Sept. 19, 2011, Newsletter; OGJ Online, Nov. 30, 2011).

The ethane cracker, said Sasol, will allow it to expand its differentiated ethylene derivatives business in the US and benefit from current low US natural gas prices and abundance of ethane.

Current cracker project costs are $5-7 billion, it said. Sasol expects operation to be achieved during 2017 and estimates the plant will produce 1.5 million tpy of ethylene with downstream derivative plants.

Andre de Ruyter, Sasol senior group executive, said in a phone press conference that the company expects the current expanded ratio between oil and natural gas prices to continue, even in the face of increased natural gas demand from expanding chemical capacity along the US Gulf Coast and from proposed LNG export projects from the area.

"We don't think the competition [from LNG export] will be of sufficient scale to alter the supply-demand economics" of Sasol's project. "We think the best use for [US-produced] natural gas is local rather than export," said de Ruyter.

He also cited the highly backward integration of Sasol's natural gas supply options, especially its holdings in Canada, as a reason to feel confident in natural gas prices remaining where they can continue to support the GTL plant's economics.

Horace O. Hobbs, managing director for the Houston office of Muse, Stancil & Co., told OGJ the consultancy's analysis continues to support projects like Sasol's. "The southwestern Louisiana location should provide an excellent combination of natural gas availability, access to product markets, and relatively low cost construction," Hobbs said.

Also in its announcement, Sasol said it will phase in the next stage of its planned GTL plant in Western Canada. The company completed a feasibility study in 2012 and has started the required regulatory application and land procurement processes.

This investment, however, will be phased after the integrated Lake Charles GTL and cracker projects, it said. Sasol will consider a decision to proceed with FEED later.

Petrobras taps membrane system for gas processing

Petroleo Brasileiro SA (Petrobras) has chosen membrane systems from UOP LLC, Des Plaines, Ill., to process natural gas aboard eight new floating production, storage, and offloading vessels. The FPSOs will handle production from Lula oil field in the Santos basin off Brazil, UOP said.

Each Separax membrane systems will remove carbon dioxide and water from as much as 6 million cu m/day following vessel commissioning expected between 2014 and 2017. Petrobras awarded the units in October 2011, said the announcement, and Honeywell's UOP will deliver the membrane units between 2013 and 2017.

UOP said the new systems for Petrobras will join two already installed aboard FPSOs owned and operated by a third party in Tupi and Guara fields.

Contract let for planned Kuwaiti refinery

Kuwait National Petroleum Co. has let a $528 million project management consultancy contract to AMEC for the 615,000 b/d refinery planned at Al Zour (OGJ Online, July 1, 2011).

KNPC says the main object of the refinery is to "supply power-generation plants in Kuwait with environment-friendly fuel and provide alternatives for gas imports and heavy fuel consumption."

TRANSPORTATIONQuick Takes

Woodside to buy into Leviathan LNG offshore Israel

A joint venture of Noble Energy Mediterranean, Delek Drilling LP, Avner Oil & Gas Exploration LP, and Ratio Oil Exploration LP has reached agreement with Australian company Woodside Petroleum Ltd. on terms under which Woodside can buy into the 349/Rachel and 30/Amit licences offshore Israel that contain the Leviathan gas field. Woodside is the preferred partner in a competitive bidding process.

Woodside would acquire a 30% interest in the field which is estimated to contain reserves of 17 tcf of gas. Woodside also would be included in other exploration opportunities in the permits.

The agreement involves an initial up-front payment of $696 million. Woodside has also offered $200 million once laws permitting LNG export from Israel are in place. This would be followed by a payment of $30 million on final investment decision for a Leviathan LNG development.

In addition there would be potential annual revenue sharing payments equal to 11.5% of Woodside's incremental revenue above an agreed escalating price threshold over the life of the project capped at $1 billion.

Under the agreement, Woodside would be operator of any LNG development in the Leviathan permits. Noble said there would be an initial production from the field into the Israeli domestic market in 2016, however a pre-FEED assessment for an LNG project is also under way.

The deal is subject to a number of conditions, including execution of a fully termed agreement.

Planned Pacific Northwest LNG plant marks progress

Petronas Carigali Canada Ltd. and Progress Energy Resources Corp., Calgary, owners of what they have now named Pacific Northwest LNG, said Dec. 4 they have moved the project to pre-FEED following a successful feasibility study.

To be built on Lelu Island, off the Hecate Strait in the District of Port Edward, BC, the plant will initially include two, 3.8-million tonne/year (tpy) trains with expansion capability for a third.

If Canadian authorities approve the acquisition of Progress by Petronas, throughput of natural gas at Pacific Northwest LNG will increase to 6 million tpy/train. Only a few weeks ago, Canada denied the acquisition but negotiations are apparently proceeding (OGJ Online, Oct. 29, 2012).

If Pacific Northwest LNG proceeds, estimated investment in the LNG export plant will be $9-11 billion (Can.), "depending on the final project scope," the companies said.

Petronas and Progress reiterated they expect final investment decision in late 2014, with first LNG exports in 2018.

Permits sought for South Texas LNG export

Pangea LNG (North America) Holdings LLC, Ingleside, Tex., has begun seeking approvals to build an LNG export plant on Corpus Christi Bay in South Texas.

Pangea applied to the US Department of Energy to export as much as 8 million tonnes/year of LNG to all current and future countries with which the US has a Free Trade Agreement and plans to file a similar application for LNG exports to any other country with which the US has no FTA in effect.

The project—South Texas LNG Export—will be in the city of Ingleside on the La Quinta Ship Channel, part of the Port of Corpus Christi. It will sit on a portion of 550 acres that include ½ mile of frontage on the federally maintained deepwater ship channel.

The announcement said Pangea has had the site under option since June. A separate pipeline would connect the LNG plant to extensive interstate and intrastate natural gas transmission pipelines in South Texas.

John Godbold, project director for Pangea LNG, said project feasibility and preliminary design are now under way by CB&I, Houston. If this application process moves forward on schedule, he said, the South Texas LNG plant could be in operation by 2018.