OGJ Newsletter

Aug. 13, 2012
International news for oil and gas professionals


EIA projects slightly higher global oil demand growth

Worldwide liquids fuels consumption will rise by 800,000 b/d this year and by 900,000 b/d in 2013, according to the latest outlook from the US Energy Information Administration. In last month’s Short-Term Energy Outlook (STEO), EIA projected that global oil demand would climb by 700,000 b/d during both 2012 and 2013.

In its latest STEO, EIA sees China, the Middle East, Central and South America, and other countries outside of the Organization for Economic Cooperation and Development accounting for nearly all consumption growth. Projected OECD liquid fuels consumption will decline by 430,000 b/d in 2012 and by 130,000 b/d in 2013.

EIA expects that OPEC members will continue to produce more than 30 million b/d of oil over the next 2 years to accommodate the projected increase in worldwide oil consumption and to counterbalance supply disruptions. Projected OPEC oil production will increase by 900,000 b/d in 2012 and then remain flat in 2013 as non-OPEC supply growth rises and stocks increase slightly.

Iran’s oil production will fall by 1 million b/d by yearend from estimated output of 3.6 million b/d at yearend 2011, and by an additional 200,000 b/d next year not only due to sanctions, but also due to the country’s inability to make the investments necessary to offset natural production decline from existing wells, EIA said.

Non-OPEC production is forecast to increase by 600,000 b/d this year and by 1.3 million b/d in 2013. The area with the most growth will be North America, where production will climb by 940,000 b/d this year and by 440,000 b/d next year.

EIA expects that Kazakhstan, which will commence commercial production in Kashagan field next year, will increase its total production by 200,000 b/d in 2013. In Brazil, output is projected to rise by 140,000 b/d in 2013, with increased output from its offshore, presalt oil fields.

Forecast production also will rise in China, Russia, and Colombia over the next 2 years, while production declines in Mexico and the North Sea, according to the STEO.

Rosneft, Itera form gas joint venture

Rosneft and Itera Group have completed a deal creating a joint venture that will produce and sell natural gas based on assets of Itera Oil & Gas Co.

Rosneft acquires 51% of the JV in exchange for a 100% interest in the charter capital of Kynsko-Chaselskoye Neftegaz and $173.4 million cash, subject to adjustment.

Kynsko-Chaselskoye owns the Kysnko-Chaselsk license block in the Krasnoselkupsk region of the Yamalo-Nenets Automous District. The license includes deposits designated Kynskoye, Fakhirovskoye, Novo-Chaselskoye, Naumovskoye, Ust-Chaselskoye, and Verkhne-Chaselskoye. Total reserves are estimated at 40.2 million tonnes of oil and 284.2 billion cu m (bcm) of gas.

The Itera Oil & Gas assets underlying the JV also are in the Yamalo-Netets region. They include:

• A 49% interest in Purgaz, which is developing Gubinsky gas-condensate field, currently producing 15 bcm/year from 95 production wells. Reserves exceed 216 bcm. Gazprom holds the other 51%.

• A 49% interest in Sibneftegaz, which holds licenses to develop Beregovoye, Pyreynoye, Khadyryakhinskoye, and Zapadno-Zapolyarnoye fields. Total reserves are 490 bcm. The fields now produce 10.3 bcm/year from 75 wells. The remaining 51% interest is held by Novatek.

• A 67% interest in Uralsevergaz, a supplier of natural gas to the Sverdlovsk region. The Sverdlovsk government holds a 30% interest.

Japan’s Inpex closes on BC shale gas venture

A consortium led by Japan’s Inpex Corp. has closed on a transaction with Nexen Inc., creating a joint venture to develop unconventional shale gas assets in the Horn River, Cordova, and Liard basins in northeastern British Columbia.

Nexen, which sold a 40% working interest in its British Columbia assets for $700 million, remains the operator with 60% interest (OGJ Online, Nov. 29, 2011).

The 40% is owned by Inpex Gas British Columbia Ltd. (IGBC), of which Inpex owns 82% and JGC Corp. owns 18% interest. JGC is an engineering contractor with project management capabilities in refining, gas processing, LNG, and petrochemicals.

Nexen and IGBC are continuing with completion activities on an 18-well pad in the Horn River basin, which is scheduled to come on stream during the fourth quarter. Nexen and IGBC plan to jointly appraise shale assets and investigate the feasibility of LNG exports.

Tri-Valley, affiliates file Chapter 11 bankruptcy

Tri-Valley Corp., Bakersfield, Calif., and its affiliates have filed for Chapter 11 bankruptcy in district court in Delaware.

Tri-Valley has received a debtor-in-possession financing commitment of $11 million by its senior secured lender, George T. Gamble 1991 Trust, of which $3.85 million represents new credit availability, to support business operations during the bankruptcy proceeding.

Upon approval by the bankruptcy court, the new debtor-in-possession financing and cash generated from Tri-Valley’s operations will be used to support the business during the bankruptcy process.

Tri-Valley said it met in June and July with its financial advisor and representatives of the Gamble Trust and the Opus Special Committee to discuss strategic alternatives. The company concluded that the only feasible way to repay creditors and generate a substantial return to Opus investors was to sell the assets, including those at Pleasant Valley and Claflin, in a competitive sale.

The company believes that no value for Tri-Valley stockholders may result from the bankruptcy process, given, among other things, the priority of claims of the company’s secured and unsecured creditors and the resolution of the outstanding alleged claims between Opus, Tri-Valley Corp., and Tri-Valley Oil & Gas.

Exploration & DevelopmentQuick Takes

Halcon upbeat about NGL potential in Texas

Halcon Resources Corp. Chief Executive Officer Floyd C. Wilson said his company is upbeat about the natural gas liquids potential of the Midway-Navarro formations in the Texas counties of Austin and Colorado.

“This is a pure wildcat discovery,” Wilson said during an Aug. 2 earnings conference call.

Halcon was named Ram Energy Resources until it was bought by Wilson, chief executive officer of Petrohawk Energy. Wilson also is chairman and president of Halcon.

BHP Billiton Ltd. bought Petrohawk Energy for $12 billion last year. Earlier this year, Halcon bought GeoResources Inc. for nearly $1 billion (OGJ Online, Apr. 25, 2012).

Wilson said Halcon plans to acquire 25,000-75,000 net acres in the Permian Midway-Navarro play, adding a 1-rig drilling program is expected to spud 4-6 wells this year. The play is being developed vertically. The first well, Kollatschny 1, reached 17,320 TD in Austin County. Halcon believes the well to be a two-zone discovery.

“We have made significant strides towards our goal of building a liquids-rich asset base with substantial drilling inventory,” Wilson said. This includes Halcon’s acquisitions in the Tuscaloosa marine shale and the Utica shale.

Beach Energy makes discovery in Bauer oil field

A joint venture of Beach Energy and Drillsearch Energy made a reservoir discovery in existing Bauer oil field in permit PEL 91 in South Australia’s Cooper Eromanga basin.

The Bauer-5 appraisal and development well flowed 1,160 b/d of oil from a 5-m thick section of the Birkhead formation, previously regarded as a secondary target.

The oil column was intersected in a stratigraphic trap and could have significant impact on the proved and probable reserves within the field.

The same well also confirmed the northeast extension of the field by intersecting a 6-m oil pay in the main Namur Sandstone reservoir.

The Birkhead find has led to a change of plans in the development drilling program with Bauer-6 and Bauer-7 now to be deepened to evaluate the extent of the new play.

The permit has already been confirmed as a highly prospective section of the Western Flank (of the Cooper basin) oil fairway and the discovery has established that the area contains multiple oil plays and pay zones.

Gran Tierra hikes Putumayo field’s oil reserves

Midyear 2012 reserves for Costayaco field in the Putumayo basin of Colombia are up sharply since the end of 2011, said Gran Tierra Energy Inc., Calgary.

Costayaco proved reserves are up 38% to 20.4 million bbl of oil. Proved and probable reserves are up 40% to 23.2 million bbl, and proved, probable, and possible reserves are up 21% to 26.7 million bbl. Calculated in accordance with US Securities and Exchange Commission rules, the increases are several percentage points less, Gran Tierra said. Costayaco is the company’s largest asset.

Gran Tierra revised its 2012 capital program to $396 million, a $60 million reduction, deferring spending from area not expected to affect production capacity or near-term high value reserve addition projects.

The company’s production in the quarter ended June 30 averaged 10,308 boe/d in Colombia, down 33% due to three pipeline disruptions, 3,693 boe/d in Argentina, up 31%, and 126 b/d in Brazil. Oil production increased from the Moqueta, Jilguero, and Melero oil discoveries.

Reservoir performance at Costayaco field, on Gran Tierra’s 100% owned Chaza block, continues to exceed expectation. Consulting engineers have increased the original oil in place estimate by using lower water saturation combined with more production history and pressure data. The company believes further reserve growth is possible given the reservoir’s strong response to water injection.

The 3D seismic over Moqueta indicates that the structure’s eastern flank extends more than 2.5 km northeast at the level of lowest known oil in existing wellbores, implying that reserve potential may exist on the east flank of the structure. Moqueta-8, to spud in September, will evaluate this.

Moqueta-7, to spud in early August, will evaluate further downdip potential of the oil columns encountered in the Villeta U, Villeta T, and Caballos reservoirs 960 m west-southwest of the Moqueta-4 appraisal well. Gran Tierra intends to target the interpreted oil-water contact, not yet encountered by drilling, some 225 ft below the lowest known oil in existing wellbores. Moqueta-7 may be used as an oil producer or water injector depending on results.

Drilling & ProductionQuick Takes

Karakuduk field marks oil production milestone

Giant Karakuduk oil and gas field in western Kazakhstan’s Mangistau region produced 10.22 million bbl of oil and 5.3 bcf of gas in 2011 and produced its 10 millionth ton of oil in 2012, said Lukoil Overseas Holding Ltd.

Lukoil and Sinopec manage the field on a parity basis for the KarakudukMunai operating entity. Field employment is 520 people, 97% of whom are Kazakh citizens.

Discovered in 1972, Karakuduk’s commercial development started in 1998 under a 25-year subsoil use contract signed in 1995. Karakuduk, in the North Caspian basin 365 km northeast of Aktau, produced its millionth ton of oil in 2003. Lukoil’s involvement dates to the end of 2005.

KarakudukMunai is applying numerous techniques in the field to maintain oil output at plateau level and increase the recovery factor. These include cluster and horizontal drilling, sidetracking, and hydraulic fracturing.

The field’s associated gas is gathered, processed, and used in the field or transported to industrial and residential customers, Lukoil said.

Reserves hiked for Lindbergh SAGD project

Better-than-expected production in a pilot phase, filing of an application for commercial development, and delineation drilling have yielded a large increase in the reserves estimate for the Lindbergh thermal oil sands project operated by Pengrowth Energy Corp. near Bonnyville, Alta.

GLJ Petroleum Consultants Ltd. assigned the project 13 million bbl of total proved bitumen reserves and 95 million bbl proved plus probable, effective June 30. Estimates last Dec. 31 were 4.4 million bbl proved and 6.3 million bbl proved plus probable. The new contingent reserves estimate is 281.2 million bbl.

Pengrowth, Calgary, filed applications last December for the first phase of commercial development via steam-assisted gravity drainage (SAGD) of the Lindbergh project, in which it holds a 100% interest. It hopes initially to drill 22 well pairs and achieve production of 12,500 b/d of bitumen in early 2015.

In the pilot project, Pengrowth began injecting steam into both wells of two well pairs last February. It said the reservoir responded more quickly than expected. In May it installed pumping equipment in the producer wells and began SAGD production.

In June the well pairs produced 650 b/d of bitumen each. Average instantaneous steam-oil ratio (SOR) was less than 2. The planned project design SOR is 3.5.

Pengrowth warned early results might not indicate long-term performance but called them encouraging.

“These pilot results support our belief that we have a clean, high-quality, homogeneous reservoir with good oil mobility that is amendable to SAGD recovery,” said Steve De Maio, vice-president, in situ oil development and operations.

Transocean considering Brazil court order on spills

Transocean Ltd. continues operating in Brazil while it evaluates a court order to suspend operations within 30 days while two offshore oil seeps are investigated. The court order also applied to Chevron Corp., which shut production at Frade field in March and has no other production in Brazil.

“We maintain that this case is without merit and reiterate that Transocean crews acted responsibly and quickly, following the highest industry standards,” a Transocean spokesman told OGJ on Aug. 2. “In addition, the ANP has stated that Transocean is not at fault in the Frade incident. We have a very strong case, and we will use every legal means necessary to prove it.”

Transocean provided the drilling rig for Chevron’s Frade offshore oil project where seeps were reported in November 2011 and March 2012.

The field, discovered in 1986, lies in 3,800 ft of water in the Campos basin about 230 miles northeast of Rio Janeiro. Chevron Corp., which has 51.74% interest, started production at Frade field in 2009 (OGJ Online, June 23, 2009).

Chevron operates Frade, which produced 18° gravity oil from shallow reservoirs requiring long horizontal wells. Chevron Brasil Upstream Frade Ltda. received authorization from Brazil’s National Petroleum Agency (ANP) for a temporary suspension of field production (OGJ Online, Mar. 16, 2012).

Last year, Chevron reported well-control operations significantly reduced an oil seep believed to be coming from an appraisal well (OGJ, Nov. 21, 2011, Newsletter).


RFS flaws need to be addressed, API official warns

Problems in the federal Renewable Fuels Standard that have emerged over several months need to be addressed soon, an American Petroleum Institute official warned. But he added that the oil and gas industry’s largest association isn’t ready yet to join livestock producers in seeking an RFS waiver for 2013.

“We’re trying to educate policymakers. This obviously is a complex issue, but one which has real world implications,” API Downstream Director Bob Greco said. “We need a solution. In some cases, it will need to be legislative. Others, it will be regulatory.”

Flaws that have emerged range from the so-called ethanol blend wall, which he said could arrive as soon as next year, to requirements for refiners to use cellulosic biofuels that don’t yet exist, he told reporters during an Aug. 8 teleconference.

Mandates under the 2007 Energy Independence and Security Act pose problems because biofuel requirements were based on projections of significantly higher gasoline demand than what has occurred; the commercial cellulosic biofuel production which was expected to materialize in a few years has not; and issues involving the 10% ethanol blend wall and possible impacts of using more in motor fuels were not fully comprehended, API said in a new analysis.

The US Environmental Protection Agency’s approach to implementing some of these mandates also has created problems, Greco said. “Some things are out of its control,” he said. “Others, such as cellulosic mandates, involve authority it already has. Since EPA has refused to recognize the reality of the cellulosic market, Congress may need to address it.”

ESAI: Shale development to boost ethylene exports

A natural gas liquids boom stemming from development of US shale plays will spur investments in export-related petrochemical plans targeting Latin America, Energy Security Analysis Inc. (ESAI) said in a recent report.

With US demand for ethylene derivatives growing modestly, expanding petrochemical capacity will be export-oriented. ESAI expects the US surplus of ethylene derivatives to expand to over 4 million tonnes/year (tpy) by 2016, a 40% increase from 2011. The US is seeing considerable activity, almost all of which is based on the pace of shale gas exploration and production and the prospects for cheap, large volumes of natural gas as potential feedstock (OGJ, May 7, 2010, p. 88).

Consequently, US ethylene is becoming more competitive in global markets given its feedstock price advantage over naphtha, ESAI reported Aug. 2 in its 5-year Global Industrial Fuels Outlook. ESAI is based in Boston.

Two proposed crackers tentatively are scheduled to come on stream during 2012-16, and several existing plants are undergoing upgrades to absorb more ethane. The last time a cracker was built in the US was 2000.

In response to increased liquids production from Marcellus and Utica shales in Pennsylvania and Ohio, Royal Dutch Shell selected a site near Pittsburgh for the potential construction of a petrochemical complex (OGJ Online, Mar. 15, 2012).

Dow Chemical Co. plans to invest $1.7 billion to build a 1.5-million-tpy cracker at its Freeport, Tex., center (OGJ Online, Apr. 30, 2012).

Expanded CNPC Hohhot refinery due tests

CNPC Hohhot Petrochemical Co. is ready to begin trial operations of an expansion and upgrade of its refinery and petrochemical complex at Hohhot, Inner Mongolia Autonomous Region, reports parent China National Petroleum Corp.

The project more than triples crude capacity to 5 million tonnes/year (tpy). It includes a 5 million tpy atmospheric distillation unit, a 2.8 million tpy catalytic cracking unit, and a 150,000 tpy polypropylene unit, CNPC said.


Hammerfest LNG plant production being restarted

Statoil said the Hammerfest LNG plant on Melkoya gradually is being returned to full production, and that the restart began in late July and early August following a temporary shutdown because water got into natural gas dryers.

Water ingression on July 10 caused ice formation in the cooling circuit, Statoil said (OGJ Online, July 12, 2012). The Snohvit offshore development, which feeds Hammerfest, is the first in the Barents Sea.

Tesoro plans to move more Bakken crude by train

Tesoro Corp. plans to move 50,000 b/d of oil from the Bakken formation in North Dakota to its 120,000-b/cd refinery in Anacortes, Wash., by yearend, CEO Greg Goff said during a second-quarter earnings conference call.

Last year, Tesoro announced plans to transport 30,000 b/d on a dedicated unit train. Earlier this year, Tesoro said it had authorization to bring 50,000 b/d of Bakken crude into its Anacortes rail unloading terminal.

In a news release, Tesoro said it expects to load the first unit train with Bakken crude oil destined for Anacortes sometime during August, and the Anacortes unloading terminal is on schedule to be completed in September.

Tesoro anticipates rail shipments will start in September at 30,000 b/d and be ramped up to 50,000 b/d by yearend.

Last year, Tesoro executed a long-term agreement with Rangeland Energy LLC for access to Rangeland’s crude loading terminal and pipeline facility in Williams County, ND. It will have a direct connection to Tesoro Logistics’ High Plains crude oil gathering system (OGJ Online, July 15, 2011).

On Aug. 2, Tesoro reaffirmed its intention to offer the unit train unloading facility in Anacortes to Tesoro Logistics LP, a limited partnership formed by Tesoro Corp. to own, operate, develop, and acquire oil and products logistics assets.

At the Mandan, ND, refinery, Tesoro in June completed a $35 million expansion that enables Tesoro to handle more oil from the Bakken formation and elsewhere in the Williston basin (OGJ Online, Mar. 21, 2011).


A recent General Interest story incorrectly denoted gallons instead of barrels in citing the cost of water (OGJ, July 30, 2012, p. 20). The corrected sentence should read as follows: Breitling Oil & Gas used to buy water for 50¢/bbl but now farmers are refusing to sell the company water at 75¢/bbl.