OGJ Newsletter

April 15, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Investments in shale plays highlight foreign JVs

Investments in shale plays in the US, which totaled $133.7 billion during 2008-12, highlight a renewed trend toward foreign joint ventures, the US Energy Information Administration reported. JVs by non-US companies accounted for 20% of this total.

Since 2008, foreign companies have invested more than $26 billion in tight oil and shale gas plays and participated in 21 JVs with US acreage holders and operators. The rest of the investments include part of outright acquisitions and joint ventures among American companies and financial institutions.

Foreign investors in JVs usually buy a percentage of the host company's shale plays acreages through an upfront cash payment and commit to cover part of the drilling cost within an agreed-upon timeframe. These deals are mutually beneficial. US operators get financial support, while foreign companies gain the latest experience in horizontal drilling and hydraulic fracturing that may be transferable to other regions. Through the JVs, foreign investors also can benefit from operating in a stable market with a sound legal system and low political risk.

Similar to the trend of US operations, more liquids-prone areas—such as the Eagle Ford, Utica, and Wolfcamp plays—are becoming the focus of most of the recent JV deals.

EIA pegs summer gasoline prices lower than 2012

According to the US Energy Information Administration's latest Short-Term Energy Outlook, the retail price for regular gasoline during the summer driving season is expected to average $3.63/gal. This price is slightly below average prices over the last two summers, reflecting a small decline in crude oil prices and expected gasoline consumption, as well as higher gasoline inventory levels.

As the main contributor for less-expensive gasoline, the average price of Brent crude oil is expected to average $107.50/bbl this summer, down 1.4% from last summer.

US gasoline inventories for the 2013 summer driving season started at 220 million bbl compared with 219 million bbl a year ago. Withdrawals of gasoline from inventories this summer are expected to be about one half of last year's level of 98,000 b/d and inventories are forecast to stabilize by the middle of summer and end the season at almost 210 million bbl.

Other major characteristics of EIA's forecast about the 2013 summer gasoline market include:

• Gasoline consumption is expected to be down 20,000 b/d (–0.2%), as a 0.3% rise in highway travel is more than offset by improvements in vehicle fuel efficiency.

• Gasoline production may increase by 20,000 b/d (0.3%)

• Net imports of gasoline are expected to be 1.1% lower than in 2012.

Penn Virginia to buy Eagle Ford shale assets

Penn Virginia Corp. agreed to pay Magnum Hunter Resources Corp. $400 million to acquire producing and undeveloped leasehold interests in the South Texas Eagle Ford shale, said the Radnor, Pa., independent.

The acquisition of 40,600 gross (19,000 net) acres includes 43 producing wells and 345 potential drill sites in Gonzales and Lavaca counties. Estimated proved reserves are 12 million boe with current production of 3,200 boe/d, Penn Virginia said.

Closing is scheduled for early to mid-May, subject to customary post-closing adjustments.

After closing Penn Virginia will have 83,000 gross (54,000 net) contiguous acres in the oil window of the Eagle Ford shale.

"With this acquisition, we now expect to drill up to 62 (39.3 net) Eagle Ford shale wells during 2013, as compared to current guidance of 38 (28.8 net) Eagle Ford shale wells," Penn Virginia said.

The independent also expanded its Eagle Ford holdings last year (OGJ Online, Oct. 3, 2012).

Exploration & DevelopmentQuick Takes

Wintershall group proves Skarfjell oil find

A Wintershall Norge AS group will drill a second appraisal well on the southern end of Skarfjell oil field in the northeastern North Sea offshore Norway after an appraisal well in the field's northern reaches confirmed earlier estimated resource range of 60-160 million bbl of oil.

The purpose of the 35/9-8 appraisal well, 16 km southwest of the Gjoa platform was to prove oil in the Upper Jurassic Intra Heather sandstones as found in the Skarfjell 35/9-7 discovery well 1.8 km south. The well confirmed the northern extension, and a production test demonstrated reservoir deliverability, Wintershall said.

The 35/9-8 well, drilled to 3,232 m true vertical depth below mean sea level in 368 m of water, found a 64-m hydrocarbon column in Intra Heather sandstone with gross thickness and good reservoir quality as expected. It also found the oil-water contact. The entire reservoir was cored and extensive data and samples collected. Pressure data show communication with the discovery well.

After drilling the southern appraisal well in mid-2014, the company will evaluate a combined development with other area discoveries as a standalone project or tieback to Gjoa field.

License interests are Wintershall Norge 35%, Capricorn Norge AS (formerly Agora Oil & Gas AS) 20%, Bayerngas Norge AS 20%, Edison International Norway 15%, and RWE Dea Norge AS 10%.

Piceance Niobrara gas find tops 1 bcf in 100 days

A Niobrara shale discovery well on production for 100 days in western Colorado's Piceance basin has recovered more than 1 bcf of gas, the same volume as a typical well recovers from the Williams Fork formation over a 25-30-year life, said WPX Energy Inc., Tulsa.

WPX, which spudded its second Niobrara well last week, holds 180,000 net acres of leases in the basin's Niobrara/Mancos unconventional play and intends to drill four horizontal Niobrara wells in 2013.

Initial rate was 16 MMcfd at 7,300 psi flowing pressure at the Garfield County discovery well, which averaged about 10 MMcfd in its first 90 days despite being choked substantially (OGJ Online, Jan. 23, 2013).

WPX believes that the discovery over time has the potential to more than double the company's proved, probable, and possible reserves, which were 18 tcf at the end of 2012, said Ralph Hill, president and chief executive officer.

The company said it has extensive processing and takeaway capacity under contract in the basin to support Niobrara production.

The Niobrara and Mancos shales generally lie at depths of 10,000 to 13,000 ft and the Williams Fork at 6,000 to 9,000 ft. In the Piceance basin, WPX holds an average 66% working interest in the Niobrara and Mancos shales.

Lundin finds oil on Utsira high western flank

A group led by Lundin Petroleum AB has made an oil discovery on the western flank of the Utsira high 15 km south of Edvard Grieg field in the Central North Sea offshore Norway.

Lundin Petroleum as operator plans to production-test the 16/4-6S exploratory well in 101 m of water on the Luno II prospect in PL359.

The well drilled through a section of close to 200 m of sand with a high net-to-gross content and proved a gross oil column in excess of 40 m. The well encountered an oil-water contact at 1,950 m below mean sea level. The oil is light and of good quality. Pressure data indicate that the petroleum system in Luno II is different from that seen in Edvard Grieg and Johan Sverdrup fields, Lundin Petroleum said. A comprehensive coring, logging, and fluid sampling program has been performed.

Ashley Heppenstall, president and chief executive officer of Lundin Petroleum, said, "We are very pleased that Luno II appears to be another significant discovery on the Utsira high. The existence of a thick reservoir section at this location is excellent news. The reservoir quality, whilst not the same as Johan Sverdrup, appears good and will now be tested. We expect to provide a range of recoverable resources from the discovery after testing is completed in 2-3 weeks time."

After the test program, the Bredford Dolphin semisubmersible will be moved to Lundin Norway operated PL501 to continue the appraisal drilling on the Johan Sverdrup discovery.

Lundin Norway is operator of the PL359 with a 40% interes, and Statoil Petroleum ASA and Premier Oil PLC have 30% each.

Drilling & ProductionQuick Takes

Parex finds oil pay on Llanos basin blocks

Parex Resources Inc., Calgary, has found oil pay at a northern extension well of Las Maracas field on the Los Ocarros block 320 km northeast of Bogota and tested new oil pay at the La Casona-1 well on the El Eden block 210 km northeast of Bogota in Colombia's Llanos basin.

Wireline logs at the Las Maracas-8, drilled in a record 10 days, indicate 34 ft true vertical depth of net pay in the Mirador formation and 22 ft TVD in middle Gacheta. The well is being cased for completion from Mirador initially. After completion, the rig will drill Maracas-9 to the Gacheta and Une reservoirs.

Las Maracas field is producing 8,000-9,000 b/d of oil, and the permanent production facility is on schedule for completion by the end of May.

Parex Resources also carried out an extensive test program of the Une and Gacheta reservoirs in its La Casona-1 discovery well using a workover rig.

The Une formation averaged 1,700 b/d of 35° gravity oil with gas at the rate of 6 MMcfd over a 56-hr period under natural flow. End-test water cut measured 1%.

A number of basal Gacheta sands not previously described in net pay numbers revealed in November 2012 were also tested and produced 105 b/d of light 24° gravity oil and 500 Mcfd of gas. Water cut at the end of the test was 2%.

A middle Gacheta sand was tested separately but yielded no flow to surface. It was speculated that the test was dry due either to formation damage or that the well required more clean-up time to flow naturally.

The Mirador formation, which had good oil shows and potential hydrocarbon pay on logs, could not be tested in this well due to a poor cement bond. It is expected that the Mirador, Gacheta, and Une reservoirs will be further evaluated with a follow-up well, La Casona-2, to be drilled later this year.

Parex Resources is procuring production facilities that include natural gas compression equipment and plans to use the produced gas as a power source at the Las Maracas and Kona production facilities. The La Casona discovery is expected to go on production in the third quarter of 2013.

Petroamerica Oil Corp., Calgary, which issued the well results, holds a 50% participating interest in the Los Ocarros block and a 40% participating interest in the El Eden block, 15% of which is still pending approval by Colombia's National Hydrocarbon Agency.

Stone Energy secures deepwater rig

Stone Energy Corp. has contracted a dynamically positioned deepwater drilling rig from Ensco PLC for its Cardona oil development program on Mississippi Canyon Block 29 in the Gulf of Mexico.

Stone will use the 8500 series rig starting in this year's second half to drill the Cardona South well. The independent plans to tie back both Cardona wells to the wholly owned Pompano platform and begin production in late 2014.

Stone, operator, holds a 65% working interest in the Cardona wells. The company acquired the Mississippi Canyon 29 and Pompano platform assets from BP PLC last year (OGJ Online, Nov. 21, 2011).

In addition, the ENSCO 81 jack-up rig will begin drilling on a 3-4 well conventional shelf/deep gas drilling program in May 2013. Stone plans to drill the Hammerlock oil prospect on South Timbalier 100, followed by the Taildancer oil prospect on Ship Shoal 113 and one or two additional wells. In May, Stone expects the Parker 50B inland barge rig to spud an infield oil well prospect in the Stone-operated Clovelly field. Stone holds a 94% working interest in Hammerlock and a 100% working interest in Taildancer and Clovelly.

Statoil taps Odfjell for Mariner drilling

Statoil has let a contract to Odfjell Drilling for platform drilling and related services at Mariner heavy oil field in UK waters 150 km east of the Shetland Islands.

The 4-year, £160-million contract begins on Nov. 16 and has 2-year extension options.

Statoil expects the field to produce an average of 55,000 b/d of oil during the plateau period of 2017-20 through a steel drilling, production, and quarters platform into floating storage facilities (OGJ Online, Feb. 15, 2013).

The platform will have 50 well slots, but Statoil expects to use multibranch wells, sidetracks, and slot reuse to reach more than 140 production and injection targets (OGJ Online, Sept. 8, 2011). A jack up rig will supplement early drilling.

Odfjell will provide platform drilling services, maintenance of the drilling facility, and drillpipe logistics for Mariner with options on development of Bressay heavy oil field to the northeast. Statoil expects to make a development decision about Bressay field this year.

Statoil operates Mariner field for a group that includes JX Nippon Exploration & Production (UK) and Alba Resources Ltd.

PROCESSINGQuick Takes

Shell Australia looks to sell Geelong refinery

Shell Australia is looking for a buyer for its only refinery in southeastern Australia, the Geelong refinery, as part of Shell's global strategy to concentrate investments on large-scale sites, such as the company's Pulau Bukom refinery in Singapore.

The Geelong refinery can process up to 120,000 b/d. In an Apr. 4 news release, Shell said other parties are likely to want to enter or expand in the Australian refining market.

The 118,000-b/cd facility, opened in 1954, is about 50 km west of Melbourne in Victoria.

The plant produces ultralow-sulfur diesel among a wide range of products (OGJ Online, July 16, 2002).

OGJ's statistics for Geelong show capacities of 40,000 b/cd catalytic cracking, 11,000 b/cd semiregenerative catalytic reforming, 20,000 b/cd cyclic catalytic reforming, and 113,500 b/cd hydrotreating (OGJ, Dec. 3, 2012).

Andrew Smith, Shell Refining (Australia) Pty. Ltd. vice-president, said he hopes to conclude a sale by yearend 2014. If it cannot negotiate a sale on acceptable terms, Shell said options include converting the Geelong refinery into an import terminal.

Shell has done that with its former Clyde refinery in Sydney where conversion is under way.

Separately, Caltex Australia Ltd. recently announced plans to convert its Kurnell refinery in Sidney to an import terminal. Chevron Corp. owns half of Caltex Australia.

Shell has operated in Australia for more than 110 years. It supplies fuel to around 900 Shell-branded service stations across Australia—along with aviation fuel, marine fuel, chemicals, bitumen, and lubricants.

Eagle Ford prompts more South Texas fractionation

TexStar Midstream Services LP, San Antonio, will install two fractionation units in Corpus Christi, Tex., adjacent LyondellBasell's Equistar Chemicals LP olefins plant.

Combined, the new fractionators will be able to process 63,000 b/d of NGLs from the Eagle Ford shale; Equistar will operate the fractionators for TexStar, the company said.

The announcement follows news earlier this month from Phillips 66 that it will develop a 100,000-b/d NGL fractionator at Old Ocean, Tex., near the company's Sweeny refinery, some 40 miles southwest of Houston. Construction will begin early next year with start-up by second-half 2015, said the company (OGJ Online, Apr. 3, 2013).

Equistar will provide various utilities to the new Corpus Christi units and purchase ethane and propane under a long-term agreement.

The units will sit on a 40-acre site owned by Equistar and leased to TexStar. Construction will begin this month with start-up projected for later this year.

Equistar has recently announced plans to expand ethylene capacity at Corpus Christi by 800 million lb/year.

Yamal LNG lets EPC contract

JSC Yamal LNG has let a contract for engineering, procurement, supply, construction, and commissioning on its planned 16.5-million tonne/year natural gas liquefaction plant to a consortium of France's Technip and Japan's JGC.

JSC Yamal LNG consists of OAO Novatek (80%) and Total (20%). The plant will be supply by reserves from South Tambey gas condensate field located on the Yamal Peninsula.

TRANSPORTATIONQuick Takes

Kinder Morgan pursues Permian-to-California line

Kinder Morgan Freedom Pipeline LLC, a subsidiary of Kinder Morgan Energy Partners LP, is holding a binding open season to determine industry interest in the development of an oil pipeline to transport crude oil from the Permian basin of West Texas to the refining complexes of northern and southern California.

The 277,000-b/d Kinder Morgan Freedom Pipeline would move crude oil from the Wink-Midland, Tex., area to anticipated intrastate pipeline interconnections near Emidio and Pentland, Calif.

Subject to sufficient customer support and regulatory approvals, Kinder Morgan plans to begin work on the Freedom Pipeline by June 2015 for an in-service date of yearend-2016.

The 1,025-mile pipeline will consist of roughly 740 miles of converted El Paso Natural Gas Co. LLC (EPNG) lines, 22 miles of new pipeline as interconnections in California, and 200 miles of pipeline between Wink and El Paso, Tex. Freedom construction will also include tanks in Wink, Midland, and the California delivery points.

New construction will occur in or adjacent to existing right-of-way for almost its entire length. The open season closes May 2.

Magellan Midstream Partners LP and Sunoco Logistics each last year proposed pipelines to bring Permian basin crude to the Texas Gulf Coast.

Magellan's BridgeTex Pipeline would move 278,000 b/d from Colorado City, Tex., to the Houston-Texas City refining complex (OGJ Online, June 12, 2012). Magellan formed a joint venture with Occidental Petroleum Corp. to build BridgeTex—including 2.6-million bbl of storage and 50 miles of pipeline between Houston and Texas City—in November. The companies expect BridgeTex to enter service mid-2014.

Phase 1 of Sunoco's Permian Express would move 150,000 b/d from Wichita Falls, Tex., to Nederland-Beaumont (OGJ Online, June 27, 2012), beginning as early as later this quarter.

CenterPoint to gather XTO Bakken crude production

CenterPoint Energy Bakken Crude Services LLC (CEBCS), an indirect, wholly owned subsidiary of CenterPoint Energy Inc., has entered into a long-term agreement with XTO Energy Inc., a subsidiary of ExxonMobil Corp, to gather XTO's crude oil production through a new crude oil gathering and transportation pipeline system in North Dakota's Bakken shale. The agreement with XTO is the first entered into from an open season announced by CEBCS Feb. 19.

Under the terms of the agreement, which includes volume commitments, CEBCS will build and operate a gathering system in Dunn and McKenzie counties, ND, for shipment of XTO crude. The system will have capacity of 19,500 b/d.

Earlier this year Targa Resources Partners LP closed on a purchase of Saddle Butte Pipeline LLC's Williston basin crude oil pipeline and terminal system, including 155 miles of Bakken shale pipeline in McKenzie, Dunn, and Mountrail counties (OGJ Online, Nov. 16, 2012).

Jordan works toward installing FSRU in 2014

Jordan's Ministry of Energy & Mineral Resources (MEMR) earlier this month launched a tender for supply of LNG to the country.

Importing LNG will meet increased demand for electric power generation fuel and, when required, address shortfalls and disruption in the supply of pipeline gas from Egypt, said a MEMR statement. In 2011-12, civil unrest in Egypt led to several attacks on the 165-mile southbound leg of the Arab Gas Pipeline that supplies gas to Jordan (OGJ Online, Oct. 4, 2008).

The planned floating LNG import terminal at Aqaba, at the top of the Gulf of Aqaba, will have an initial baseload sendout capacity of 150 MMcfd; MEMR expects it to begin operating in late 2014.

Issue of this tender, MEMR said, is the final step in implementation of Jordan's LNG import strategy.

In late February, the ministry selected Golar LNG Ltd. to supply the floating storage and regasification unit (FSRU). The vessel will have storage capacity of 160,000 cu m of LNG and an ultimate sendout of 490 MMcfd. MEMR expects to sign a time-charter party agreement next month.

In mid-January, Aqaba Development Corp. issued a request for proposals for design and construction of required infrastructure at Aqaba. Bids are due on Apr. 23.

And, in December 2012, the ministry signed a memorandum of understanding with the operator of the 242-mile Jordanian gas transmission pipeline, also part of the Arab Gas Pipeline. An agreement covering transportation of regasified LNG from the import terminal to Jordan's power plants is being negotiated and the ministry expects it will be signed "in the near future."

The 745-mile Arab Gas Pipeline was installed between 2002 and 2008 to bring gas from Arish south, around the tip of Israel then back north, meeting gas demand in Jordan, Lebanon, and Syria.