GENERAL INTEREST — Quick Takes
El Paso to sell E&P arm in $7.15 billion deal
El Paso Corp. reported plans to sell its exploration and production business, EP Energy Corp., for $7.15 billion to affiliates of Apollo Global Management LLC and Riverstone Holdings LLC, who are joined by Access Industries Inc. and other parties.
El Paso's entering into a deal to divest its E&P business was contemplated in Kinder Morgan Inc.'s announced agreement to acquire El Paso in 2011 (OGJ Online, Oct. 17, 2011).
The sale of EP Energy is dependent upon completion of the KMI-El Paso transaction, which is expected to close in the second quarter. The sale of EP Energy also is expected to close about the same time as that transaction.
"We are pleased that this pending sale will allow the El Paso exploration and production assets to be kept intact as a single entity," said KMI Chairman and CEO Richard D. Kinder.
Linn Energy to buy BP's Hugoton holdings for $1.2 billion
Linn Energy LLC will acquire BP America Production Co.'s holdings in giant Hugoton field in southwestern Kansas for $1.2 billion. The properties are producing 110 MMcfd of gas equivalent, 37% natural gas liquids, from 730 bcfe of proved reserves. The properties are 98% operated and include full ownership of the 450 MMcfd Jayhawk gas processing plant, whose throughput has been about half of capacity (OGJ, June 6, 2011, p. 88).
Hugoton is the largest US conventional gas field in terms of ultimate recovery, and the BP properties have a 7% decline rate and 18-year reserve life, Linn Energy said.
The properties are 81% proved developed producing with 2,400 operated wells on more than 600,000 contiguous net acres and more than 800 future drilling locations. Estimated 2012 maintenance capital is $30-40 million.
Linn Energy pointed out that it is fully hedged for 5 years for 100% of its natural gas production and 68% of NGL production, utilizing natural gas puts.
USGS issues first ANS shale oil, gas estimates
The US Geological Survey estimated that Alaska's North Slope contains as much as 2 billion bbl of oil and 80 tcf of gas, which are technically recoverable from tight shale formations using currently available technology and industry practices.
Production has never been attempted from these formations, which span much of the Alaska North Slope but are largely absent from the Arctic National Wildlife Refuge primarily because of economics and lack of infrastructure, the US Department of the Interior agency noted. It was the agency's first estimate of the resource potential in ANS shales.
"Providing scientifically sound, publicly available assessments of the quantity of new, untapped oil and gas resources in frontier areas is but the first step in weighing their potential contributions to energy supplies as well as the impacts of recovering them," said USGS Director Marcia K. McNutt.
USGS said there is a large range of uncertainty associated with these assessment numbers due to the nature of estimating undiscovered, continuous resources in source rocks from which no attempt has been made to produce oil or gas.
However, the recent success of shale oil and shale gas development in the Lower 48 states demonstrates the technical viability of such resources, it continued. Consequently, this new USGS assessment provides an estimate of potential resources which may be technically viable in this frontier region, it said.
The study assessed three ANS source rocks: the Triassic Shublik formation, the lower part of the Jurassic-Lower Cretaceous Kingak shale, and the Cretaceous pebble shale unit-Hue shale. The formations are known to have generated oil and gas that migrated into conventional accumulations, including the supergiant Prudhoe Bay field, according to USGS. However, these shales also likely retain oil and gas that did not migrate.
The assessment is a part of the agency's National Oil and Gas Assessment, which periodically provides evaluations of the US oil and gas endowment, USGS said.
Exploration & Development — Quick Takes
Wintershall finding more oil in Bavarian foothills
Wintershall AG completed three exploratory wells in the Alpine foothills in southern Germany where it is using a helicopter-assisted electromagnetic exploration method.
The company found oil at the Aitingen Sud-2, Schwabmunchen-7, and Aitingen Nord-Ost-1 wells in November 2011 through January 2012 in the region south of Augsburg, where the company's existing wells produced 219,000 bbl of oil in 2011. The three wells cost 7.5 million euros.
Crude oil from two of the new wells will flow via steel pipeline to Aitingen from May 2012, where it will be treated and then transported to the refinery in Lingen. The Aitingen Nord-Ost-1 is to be production-tested in April.
The three wells bring the total number of production wells operated by Wintershall in the Alpine foothills to 10.
Wintershall will fly daylight electromagnetic survey lines 100 m apart by helicopter during Feb. 29-Mar. 5 over 93 sq km of the Alpine foothills around GroBaitingen, Kleinaitingen, Graben, and parts of Wehringen.
The method is designed to detect electromagnetic fields in a certain frequency range in places where hydrocarbons lie underground. Wintershall said it is unable to determine the existence of hydrocarbons with the seismic methods previously used, and that the new method could give more direct indications, although drilling is ultimately still required.
Southwestern eyes Denver basin unconventionals
Southwestern Energy Co., Houston, said it has leased 238,057 net acres in the Denver-Julesburg basin in eastern Colorado where the firm will begin testing an unconventional oil play targeting carbonates and shales of middle and late Pennsylvanian to Permian age. Common strata names include the Atoka, Desmoinesian-Cherokee-Excello-Tebo-Marmaton, Missourian, Virgilian, and Wolfcamp, Southwestern Energy said.
The play objectives range in vertical depth from 8,000 to 10,500 ft and are within the oil window. The combined Wolfcamp-Atoka interval is more than 1,500 ft thick.
The primary objectives are alternating low-permeability, 20-100 ft thick carbonates separated by 10-75 ft thick organic-rich, carbonate mudstones; total organic carbon estimates range 2-27%. Total thickness of the objective section is 300-750 ft.
Southwestern Energy obtained the acreage for $42 million, and its leases currently have an 85% average net revenue interest and an average 5-year primary lease term that may be extended 3 years.
The firm submitted a drilling plan to the Colorado Oil & Gas Conservation Commission in February for approval to spud its first well in the second quarter. This well will be drilled vertically to 9,500 ft and cored and then drilled 2,000 ft laterally.
Southwestern Energy said it could greatly increase activity in the area in the next few years if results are positive.
Enerplus adding Marcellus production, reserves
Enerplus Corp., Calgary, will spend $190 million in the Marcellus shale region in 2012, about 80% of which it will allocate to nonoperated interests in northeastern Pennsylvania.
With the low natural gas price environment, Enerplus plans to prudently invest with partners to retain valuable acreage.
Well results have continued to surpass expectations in terms of both initial production rates and declines, the company said. Costs average $7-8 million/well. Some $30-40 million will go to drill appraisal wells on operated leases in Pennsylvania where Enerplus is focused on demonstrating potential and retaining lease interests.
The firm expects to hike its Marcellus production to 70 MMcfd at yearend compared with 25 MMcfd at yearend 2011.
Last year, Enerplus sold 45% of its Marcellus nonoperated acreage position for $568 million, realizing a $272 million net gain. The firm has essentially recovered its entire investment in the region while retaining ownership of 110,000 net acres, 60% operated.
Enerplus invested $210 million on Marcellus delineation and development drilling in 2011, increasing production and hiking booked proved and probable reserves 64% to 154 bcf. An independent best estimate of contingent resources in the Marcellus is 2.3 tcf. Independent reserve evaluators have increased the estimated average estimated ultimate recovery to 6.6 bcf/well from 5.4 bcf.
Meanwhile, in Canada the company will invest $80 million on liquids-rich gas properties in Alberta and British Columbia, down from $91 million in 2011 due to weak gas prices. Operated drilling will target the stacked Mannville and delineate the Montney and Duvernay acreage positions.
Repsol Sinopec gauges Pao Campos presalt find
A Repsol Sinopec-led group has gauged oil and gas at a presalt discovery in the Campos basin offshore Brazil.
The find on the Pao de Acucar prospect on the BM-C-33 block reached two presalt accumulations with hydrocarbon columns totaling 480 m thick with a combined 350 m of pay.
The well flowed at the rate of 5,000 b/d of light oil and 28.5 MMcfd of gas on test of a partial section of the pay zone on a choked drilling test with minor drawdown.
Repsol Sinopec is block operator with 35% interest. Statoil ASA has 35%, and Petrobras has 30%.
Partner Statoil defined Pao as a "high-impact well," meaning one that located more than 250 million bbl of oil equivalent or 100 million boe net to Statoil.
The discovery, in 2,800 m of water 195 km east of Rio de Janeiro state, is the block's third find after Seat and Gavea. Statoil said the group will evaluate the development potential of the Pao and Gavea discoveries.
Statoil said the Pao discovery "increases our understanding of the presalt potential in the Campos basin and improves our confidence in the recently acquired acreage position in the presalt Kwanza basin of Angola."
Statoil operates Peregrino heavy oil field, to the west of the Pao discovery, which started production in April 2011 and in which Sinochem has 40% interest (OGJ Online, Apr. 15, 2011).
PetroMagdalena tests Llanos basin oil find
PetroMagdalena Energy Corp., Toronto, reported an oil discovery on the 70% owned Cubiro block in Colombia's Llanos basin at a structure on trend with Barranquero field to the north and the Tijereto Sur-1X exploratory well to the south.
The company perforated two Upper Guadalupe sands in the Cernicalo-1ST well which produced 530 b/d of 23.9° gravity oil in 5 hr with 30% basic sediment and water on an electric submersible pump.
The well encountered 12 ft of net pay in Upper Guadalupe with 24% porosity and 50% oil saturation and 13 ft of net pay uphole in the Carbonera C7 sand, topped at 5,880 ft measured depth, with 24% porosity and 50% hydrocarbon saturation. The company will also test the C7. Total depth is 6,845 ft MD.
The Cernicalo structure is 1.5 km long and represents the typical exploration play in the basin, the company said.
Meanwhile, PetroMagdalena set 7-in. production casing to total depth of 6,926 ft MD at the Tijereto Sur -1X well to production test the C7 formation.
DONG developing Hejre field offshore Denmark
DONG Energy and Bayerngas will develop high-pressure, high-temperature Hejre oil and natural gas field in the northern Danish Central Graben offshore Denmark.
Development will include installation of a production, processing, and accommodation platform on Danish North Sea License 5/98 with a steel jacket in 70 km of water and drilling of five production wells. Drilling of an additional seven wells, including satellites, is possible, according to documents at the Danish Energy Agency (DEA).
A 90-km pipeline will carry crude oil to a pumping platform on Gorm oil field southeast of Hejre. Natural gas will move northeast through a 24-km pipeline to a connection with the South Arne-Nybro pipeline.
Hejre development will require modifications to the Gorm E platform and to processing facilities at an onshore terminal at Fredericia, Denmark.
DONG estimates total reserves at 170 million bbl of oil equivalent.
Production at undisclosed rates is to begin in 2015.
Hejre is a 2001 discovery by the former Phillips Petroleum International Corp. The discovery well found oil in Late Jurassic sandstones. DEA estimates reservoir depth at 16,500 ft.
DONG acquired the Danish interests of ConocoPhillips International Corp. in 2007 (OGJ Online, Mar. 23, 2007).
Interests now are DONG 60% and Bayerngas 40%.
Drilling & Production — Quick Takes
Total starts oil field offshore Nigeria
Total said production has started from Usan oil field 100 km offshore southeastern Nigeria (OGJ Online, Dec. 9, 2009).
Development of the field, in 750-850 m of water, involves 42 wells connected to a spread-moored floating production, storage, and offloading vessel by a 70-km long subsea network.
The FPSO can process 180,000 b/d of oil and has storage capacity of 2 million bbl of crude oil.
Its 320 m length and 61 m width makes the FPSO one of the largest vessels of its type in the world, Total said.
Total's wholly owned subsidiary Total E&P Nigeria Ltd. operates the block, OML 138, with a 20% interest. Nigerian National Petroleum Corp. holds the concession. Total's partners are Chevron Petroleum Nigeria Ltd. and Esso E&P Nigeria (Offshore East) Ltd., 30% each, and Nexen Petroleum Nigerial Ltd., 20%.
Move targeting oil sands stalls in EU
A European Union technical committee handed Alberta producers a "small victory" by declining to declare fuels made from bitumen to be greater emitters of greenhouse gases than those from other types of crude oil.
The committee didn't muster a majority in support of changes to the EU's fuel quality directive that would raise costs of fuels originating in Alberta's oil sands. But there was no majority in favor of killing the proposal, either.
"Today's vote is a small victory for Alberta," said Alberta Premier Alison Redford in a statement. "But the process in Europe means that a discriminatory fuel quality directive could resurface."
Grizzly reports May River resource estimate
Grizzly Oil Sands ULC said an independent analysis has identified 1.8 billion bbl of exploitable bitumen in place at the May River oil sands property in northern Alberta it has acquired from Petrobank Energy & Resources Ltd. Both companies are based in Calgary (OGJ Online, Feb. 1, 2012).
Privately owned Grizzly reported the assessment, by GLJ Petroleum Consultants Ltd., at the closing of the $225 million (Can.) cash deal.
GLJ assigned 824 million bbl of contingent resource as a best estimate based on the modular steam-assisted gravity drainage scheme Grizzly plans to use. GLJ's development profile shows gross production of 100,000 b/d, Grizzly said.
PROCESSING — Quick Takes
Apache commissions Devil Creek gas plant
Apache Energy Ltd. has commissioned the Devil Creek Gas Plant in Western Australia (OGJ Online, Oct. 14, 2010).
The two-train plant can process 200 MMcfd of natural gas and 1,000 b/d of condensate.
It will receive gas from offshore Reindeer field via a 105-km subsea pipeline. The plant is linked with a trunkline between Dampier and Bunbury.
Apache Energy, West Perth, a subsidiary of Apache Corp., has a 55% interest in the project. Santos Ltd., Adelaide, holds 45%.
HPCL commissions Visakh refinery units
Hindustan Petroleum Corp. Ltd. has commissioned units enabling its Visakh refinery in Andhra Pradesh, India, to produce gasoline with emission standards equivalent to Euro 4 (less than 50 ppm sulfur).
In phases, HPCL commissioned a naphtha hydrotreater, continuous catalytic reformer, FCC-naphtha hydrotreater, and isomerization unit. The company said the work boosted crude capacity to 8.3 million tonnes/year (166,000 b/d).
HPCL also has a diesel hydrotreater project under way to enable the refinery to produce Euro 4 diesel (OGJ Online, Apr. 1, 2010).
Group to study Russian refining efficiency
BP PLC and research groups from the UK and Russia have formed a consortium to study ways to improve energy efficiency of Russian refineries.
The Center of Applied Research on Energy Efficient Heat Exchange and Catalysis (Project UNIHEAT) will try to cut heat loss in refining by as much as 15% by improving operations, enhancing processes, and cutting emissions of carbon dioxide.
Funding will come from BP and the Skolkovo Foundation, created in 2010 to establish a science and technology-development center in a suburb of Moscow.
Other participants are Imperial College London; Imperial Consultants, affiliated with Imperial College; Boreskov Institute of Catalysis, Novosibirsk, Russia; Novosibirsk State University; and UNICAT Ltd., affiliated with Boreskov Institute and Novosibirsk State University.
TRANSPORTATION — Quick Takes
Sabine Pass LNG export project takes step
Cheniere Energy Partners LP (CEP) has taken a step toward a final investment decision on the Sabine Pass LNG export project by entering an exclusive agreement for financing worth $2 billion.
The agreement, with Blackstone Energy Partners LP, Blackstone Capital Partners VI LP, and affiliates, is to finalize and execute definitive agreements to purchase new senior subordinated pain-in-kind units of CEP.
CEP's pending decision covers construction of the first two of four modular liquefaction trains at its Sabine Pass terminal in Cameron Parish, La., which now has 4 bcfd of regasification and sendout capacity (OGJ Online, Dec. 20, 2011).
The company estimates cost of the first two trains, with nominal capacities of 4.5 million tonnes/year of LNG each, at $4.5-5 billion before financing costs.
It would use proceeds from the new financing for the equity portion of costs of developing, building, and placing into service the liquefaction equipment; closing the purchase of the 94-mile Creole Trail pipeline from Cheneire Energy Inc.; and other partnership business.
Malaysia plant to build ninth LNG train
Malaysia's Petronas announced Feb. 22 it will add a ninth LNG train to its Bintulu, Sarawak, complex on Borneo. The train with have a nameplate capacity of 3.6 million tonnes/year and bring total capacity at the site to 27.6 million tpy.
Offshore fields in Sarawak will produce feed gas for the new train up to 850 MMcfd. Plant start-up targets fourth-quarter 2015.
Petronas awarded a frontend engineering and design contract to JGC Corp. and to a joint venture between Japan's Chiyoda Corp. and Italy's Saipem. The engineering, procurement, and construction contract for the new train will be awarded to one of these two entities upon completion of the FEED.
Platts LNG reported a final investment decision about the train will come by first-quarter 2013.
TransCanada to extend Tamazunchale gas line in Mexico
TransCanada Corp. will build, own, and operate a 235-km, 30-in. and 36-in. OD extension to its existing Tamazunchale natural gas pipeline in Mexico. The project is supported by a 25-year natural gas transportation service contract by Mexico's state-owned power company, Comision Federal de Electricidad (CFE).
The project will have contracted capacity of 630 MMcfd and include 37 Mw of installed compression. The extension will start at the end of TransCanada's existing Tamazunchale Pipeline in the state of San Luis Potosi and extend through Hidalgo and Queretaro states, where it will connect with Mexico's National Pipeline System and serve a CFE combined-cycle power generating facility near El Sauz, Queretaro.
The Mexican government recently announced a number of natural gas infrastructure projects for the country and TransCanada said it will pursue future development opportunities in the country.
TransCanada estimates the cost of the project at $500 million and anticipates an in-service date of first-quarter 2014.
The company last year finished work on it 310-km Guadalajara Pipeline, delivering gas from an LNG regasification terminal near Manzanillo on Mexico's Pacific Coast to Guadalajara and also underpinned by a 25-year CFE contract (OGJ Online, May 7, 2009).
Eni to sell Interconnector interests
Eni SPA has agreed to sell its interests in companies related to the bidirectional Interconnector natural gas pipeline between the UK and Belgium to Fluxys G SA and Snam SPA for total consideration of €150 million.
The interests are 16.41% in Interconnector (UK) Ltd., operator of the pipeline; 51% in Interconnector Zeebrugge Terminal SCRL, owner of the Belgian compressor terminal at Zeebrugge; and 10% in Huberator SA, which offers trading-related services in the Zeebrugge Gas Hub.
The Italian company will retain its transportation contracts on the 235-km, 40-in. Interconnector system, which has capacities to carry 25.5 billion cu m/year from Zeebrugge to Bacton, UK, and 20 billion cu m/year in the opposite direction.
Eni said the transaction fits its strategy to shed noncore assets.
Fluxys G is Belgium's independent gas transmission system operator. Snam, Milan, builds and operates gas systems.
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