OGJ Newsletter

May 23, 2011
GENERAL INTERESTQuick Takes

Iran's Ahmadinejad to head next OPEC meeting

Iran's President Mahmoud Ahmadinejad will attend the next meeting of the Organization of the Petroleum Exporting Countries set for June 8 in Vienna, according to Iranian media. Last week, Ahmadinejad announced he would temporarily oversee the country's oil portfolio following his earlier dismissal of Oil Minister Masoud Mir-Kazemi (see story, p. 19).

"Considering that the president is the oil ministry's caretaker, Ahmadinejad will attend the upcoming OPEC meeting," Mohammad Reza Mirtajeddini, a senior government official, told the semi-official Fars news agency.

"The news that Ahmedinejad is coming to OPEC is likely to fill the US with dread as gasoline approaches $4/gal," said IHS Energy senior analyst Samuel Ciszuk, adding, "He might just want to partake in general anti-US and anti-Western rhetoric and realize that trying to block any added OPEC volumes for instance would have a price impact."

Ciszuk said, "He might raise pretty much any issue, just to get the limelight and create some form of price reaction—upwards, one has to assume. Saudi Arabia is likely to see Ahmadinejad's presence as a direct challenge."

Iran is in the midst of a dispute with the West over its nuclear work. It also is often OPEC's leading advocate of higher prices, in contrast to Saudi Arabia which traditionally urges a more moderate pricing stance.

Iran, the second-largest crude producer in OPEC after Saudi Arabia, currently holds the group's presidency and the OPEC president traditionally delivers a speech to kick off the occasion.

US Senator seeks FTC probe of price manipulation

US Sen. Claire McCaskill (D-Mo.) asked Federal Trade Commission Chairman Jon Leibowitz to investigate reports that refiners are cutting back on gasoline stockpiles to keep gasoline prices high. She specifically cited a Kansas City Star article that said wholesale gasoline margins were climbing to levels not seen since Hurricane Katrina in 2005 because of Mississippi River flooding.

"At a time when major refiners and oil companies are making record profits and American families continue to struggle with gasoline at record prices, the idea that refiners may be manipulating the market to keep prices artificially high is offensive," McCaskill said in a May 17 letter.

Officials at the National Petrochemical & Refiners Association and the American Petroleum Institute immediately disputed the allegations.

"This is political theater. We've seen the show before, and we know what the ending will be," NPRA Pres. Charles T. Drevna said. "Dozens of investigations of gasoline price fixing over the years have generated plenty of headlines and political hyperbole, but have failed again and again to find any evidence of wrongdoing."

Refiners have been producing record amounts of gasoline, but world and US petroleum product demand have been increasing, according to API Chief Economist John C. Felmy. "Press releases that call for yet more investigations of prices insult consumers. We need to be producing more oil, and producing more of it at home," he said.

Rowan Cos. to sell LeTourneau for $1.1 billion

Rowan Cos. Inc. entered into a share purchase agreement with Joy Global Inc. to sell its mining and rig construction business, LeTourneau Technologies Inc., for $1.1 billion in cash.

The deal with Joy Global, said Rowan Pres. and Chief Executive Officer Matt Ralls, is consistent with the company's "strategy to separate noncore businesses." Ralls noted that he expects most of the aftertax proceeds, about $875 million, to be redeployed into the company's offshore drilling business, either through continued growth of its high-specification jack up fleet or expansion into the ultradeepwater drilling segment.

Exploration & DevelopmentQuick Takes

ANS well to test methane hydrate technologies

A fully instrumented well that will test innovative technologies to produce methane gas from hydrate deposits has been safely installed on Alaska's North Slope and will be available for field experiments as early as next winter, the US Department of Energy's Fossil Energy Office announced on May 17.

FEO said the well—the result of a partnership of ConocoPhillips and FEO's National Energy Technology Laboratory—will test a technology that involves injecting carbon dioxide into sandstone reservoirs containing methane hydrate. Laboratory studies indicate that the CO2 molecules will replace the methane molecules in the solid hydrate lattice, resulting in the simultaneous sequestration of CO2 in a solid hydrate structure and production of methane gas, FEO said.

Recently completed operations include the acquisition of a research-level suite of measurements through the subpermafrost hydrate-bearing sediments, it indicated. The data confirm the occurrence of 160 ft of gas-hydrate-bearing sand reservoirs in four separate zones, as predicted, and provide insight into their physical and mechanical properties.

An array of downhole pressure-temperature gauges were installed in the well, as well as a continuous fiber-optic temperature sensor outside the well casing, which will monitor the well as it returns to natural conditions following the drilling program, FEO added.

It said in coming months, field trial participants will review the data to determine the optimal parameters for future field testing. Current plans are to reenter the well in a future winter drilling season, and conduct a 1-2 month program of CO2 injection and well production to assess the efficiency of the exchange process.

Following those tests, the remaining time available before the spring thaw (as much as 40 days) may be used to test reservoir response to pressure reduction in the wellbore.

Apache presses Neuquen unconventional gas drilling

Apache Corp. said a subsidiary is continuing to evaluate the potential of unconventional resources in the low-permeability Precuyo formation and Los Molles and Vaca Muerta shales in Argentina's Neuquen basin.

The company said it has drilled more than 70 unconventional wells in four Neuquen fields since 2008. Its production under Argentina's Gas Plus incentive program reached 75 MMcfd of gas with an average price of $4.93/Mcf in April.

One recent well, the horizontal ACS-15h, in Anticlinal Campamento field in southern Neuquen Province, tested at a rate of 7 MMcfd after multistage fracs in the Precuyo, a complex reservoir of volcanics, granites, and tight sands. The well has a 2,800-ft lateral at 12,800 ft true vertical depth. Interests are Apache 85% and Pampa Energia 15%.

Apache said it has identified a couple more locations to drill near ACS-15H in AC field but will study the longer-term performance of the first well before drilling others. Apache has been actively developing the Precuyo in other areas and sees additional upside beyond the AC Field. At this point, however, the company declined to speculate on other development plans.

Developing unconventional resources requires substantial investments, so Apache and other operators need incentives like the Gas Plus program that permits higher prices for gas from unconventional reservoirs, said Jon Graham, Apache's vice-president and country manager in Argentina. Neuquen's extension of Apache's concession agreements also encourages investment, he noted.

OGX declares two Parnaiba fields commercial

OGX SA, Rio de Janeiro, has declared commercial the California and Fazenda Sao Jose accumulations discovered on the PN-T-68 block in northeastern Brazil's onshore Parnaiba basin.

The two fields are expected to reach output of 201 MMcfd of natural gas by 2013 to be preferentially provided to power plants to be built by MPX Energia SA, an EBX group company, in association with Petra Energia SA, both of whom are partners of OGX on the PN-T-68 block.

OGX said it has identified the presence of hydrocarbons in the 1-OGX-34-MA and 3-OGX-38-MA wells on the same block 260 km southwest of Sao Luis (OGJ Online, Sept. 2, 2010).

The OGX-34 well, on the Bom Jesus prospect, discovered 23 m of net gas pay in the Devonian Poti and Cabecas formations. The OGX-38 well, the first Fazenda Sao Jose appraisal well, encountered 43 m of net gas pay in Poti and is still drilling.

OGX, which obtained the Parnaiba concessions 20 months ago, said Gaviao Azul (California) and Gaviao Real (Fazenda Sao Jose) will be the company's first gas fields. Brazil's ANP is analyzing OGX's development plans.

MPX has acquired the site to build a power plant on the PN-T-68 block and has obtained an installation license for 1,863 Mw. MPX has initiated the environmental licensing process for the development of an additional 1,859 Mw in the region.

Drilling & ProductionQuick Takes

Forest fires, floods affect Canadian production

More Canadian operators are reporting temporary shut ins of their production and suspension of drilling and completion activity as a result of forest fires near Slave Lake in northern Alberta and spring floods in southern Saskatchewan and Manitoba.

Penn West Exploration said it has temporarily shut in 35,000-40,000 boe/d of production because of the fires in Alberta and the spring floods in Saskatchewan and Manitoba.

BlackPearl Resources Inc. has temporarily shut in about 700 b/d of oil production at Mooney in northern Alberta because of the fires. Also, Celtic Exploration Ltd. said it has shut in 150 bo/d at Utikuma Lake near Slave Lake because of the fires.

NEB expects a decline in Canadian gas deliverability

Canada's natural gas deliverability may decrease to 12 bcfd in 2013 from the 13.4 bcfd in 2011, according to the midrange scenario in a recent report by Canada's National Energy Board.

Despite this decline, NEB expects Canada to have ample gas supply to meet its needs.

The report, Short-Term Natural Gas Deliverability 2011-13, attributes the decline to two key market factors, namely oversupply of gas in Canada and the US and the shift in drilling away from gas.

The report expects the decline trend to continue unless prices are pushed up because of a closer balance between demand and available supply.

It notes that as of fall 2010, the US had drilled a record number of horizontal wells in major shale gas formations despite a slower growth in demand since 2009, thus creating an overall surplus of gas in the Canadian and US markets.

If US companies continue to drill at high levels, they will meet more American internal demand, keep prices down, and decrease opportunities for Canada to export, the report said.

The report explains that the glut of gas has led Canadian gas producers to pursue other energy products to secure revenues when gas prices are low such as the production of oil and NGLs, which have a higher market value.

The completion of two gas pipelines in the US also will affect the delivery of gas from Canada. Both pipelines will enable more US produced gas to move to markets traditionally served by Canadian exports, the report said.

The Bison Pipeline, which went into service in January, moves gas from Wyoming to the US Midwest via the Northern Border Pipeline. The Ruby Pipeline, scheduled to enter service in June, will move gas from Wyoming into the Pacific Northwest and California.

Combined, both pipelines can carry about 1.9 bcfd. In 2010, total Canadian exports were about 8.9 bcfd, so that this new amount of US pipeline capacity may have a large effect on Canadian gas exports to these markets, the report said.

Osum expands Grosmont carbonates acreage in Alberta

Osum Oil Sands Corp. acquired 32,640 acres of oil sands leases in the Saleski Grosmont carbonate region of northern Alberta. The new leases are contiguous to Osum's existing carbonate holdings complementing the previous 100% owned Saleski acreage and the company's joint venture acreage.

Shell Canada Ltd. was the reported seller, according to various media sources.

Osum will refer to the new lease area as Saleski West and will refer to its previous Saleski 100% acreage as Saleski East.

An independent reservoir evaluator has assigned 870 million bbl of best estimate contingent resources (P50) to Saleski West, which includes Grosmont C and D horizons and Ireton. This increases by 36% Osum's best estimate contingent resources, bringing the corporate total to 3,258 million bbl, plus 360 million bbl of proved plus probable (2P) reserves, Osum said.

Osum noted that the contingent resources at Saleski West could support total production of 80,000 b/d which increases Osum's total long-term sustained production potential from its reserve and resource base by 30% to 350,000 b/d.

A steam-assisted gravity drainage project on the Saleski JV acreage started in December 2010. Laricina Energy Ltd. is the operator of the pilot and holds a 60% interest in the property. Osum holds the remaining 40% (OGJ, Dec. 21, 2009, Newsletter).

Multilateral junction depth record set in China

The world's deepest TAML Level 4 cemented multilateral junction was set in a PetroChina's Tarim Oilfield Co. well in Xinjiang province in northwestern China, according to Halliburton.

Halliburton said the junction was set at 16,696 ft measured depth in the vertical section of a 7-in., 29 lb/ft liner. The main and lateral wellbores were cased and cemented, with both bores cemented at the junction.

The Technology Advancement for Multi-Laterals group established the TAML classification for multilateral junctions.

PROCESSINGQuick Takes

Eni building commercial-scale EST plant

Eni SPA has begun work on a commercial scale plant based on a new hydroconversion process that it says will eliminate production of fuel oil at its 200,000 b/d Sannazzaro refinery near Pavia, Italy. The company expects the 23,000-b/d plant to be complete by yearend 2012.

The company has been developing the process, Eni Slurry Technology (EST), since the 1990s as a route to the full conversion and upgrading of the bottom of the refinery barrel (OGJ, Feb. 23, 2009, Newsletter).

A 1,200-b/sd demonstration plant at Eni's 84,000 b/d Taranto refinery has processed more than 230,000 bbl of various heavy oils since start-up in 2005. Eni has invested €1.1 billion in the project.

Eni describes EST as a type of hydrocracking process. "Its peculiar characteristics concern the use of dispersed catalysts and an original process scheme for the catalyst handling that allows an almost total feedstock conversion as well as high upgrading performance," a technical note says.

The new plant, for which design began in mid-2008, will convert heavy vacuum residue into light and middle distillates. Construction of the reactor began in 2009.

The Sannazzaro refinery has 34,000 b/d of fluid catalytic cracking capacity and 30,000 b/d of hydrocracking capacity for distillate upgrading.

Petronas plans Pengerang refinery, petchem complex

Malaysia's state-run Petronas reported plans to construct a $20 billion refinery and petrochemicals complex at Pengerang in southern Johor state that would raise the country's total refining capacity to 935,300 b/d.

The development, to be called Refinery and Petrochemicals Integrated Development, or Rapid, is expected to be commissioned by yearend 2016.

The Rapid project, which is still at the detailed feasibility study stage, will comprise a 300,000-b/d refinery, a 3 million tonne/year naphtha cracker, and a petrochemical and polymer complex. The project will boost Petronas' total domestic and overseas refining capacity to 748,000 b/d and its Malaysian capacity to 623,000 b/d, the company said.

Described by Petronas as "greater in scale and scope" than its Melaka, Kertih, and Gebeng complexes combined, Rapid is expected to turn Johor into another major petroleum and petrochemical center in the region.

Thailand resid unit to undergo revamp

Star Petroleum Refining Co. Ltd., Rayong, Thailand, has awarded a unit revamp contract to the Global Engineering & Construction Group of Foster Wheeler AG.

The front-end engineering and design contract is for Star Petroleum's residue fluidized catalytic cracking unit's revamp turnaround and inspection project at the Map Ta Phut refinery. Terms of the award were not disclosed; the contract's value, said the announcement, was included in the Foster Wheeler's first-quarter bookings.

The objective of the project is improve onstream reliability together with environmental and performance improvements. The Foster Wheeler announcement said the company expects the FEED to be completed by first-quarter 2012.

Foster Wheeler will carry out the FEED, including licensor selection, and will also work with Star Petroleum to evaluate existing RFCCU maintenance and reliability to identify changes that may be needed the continuous improvement of onstream performance, according to the announcement.

TRANSPORTATIONQuick Takes

BP, ConocoPhillips stop development of Denali gas line

The Denali project, a joint venture of BP PLC and ConocoPhillips, is stopping efforts to develop a pipeline that would transport Alaska North Slope (ANS) natural gas to the US Lower 48. The competing project, a partnership between TransCanada and ExxonMobil Corp. called the Alaska Pipeline Project (APP), is continuing its effort to design and permit a gas line from Alaska.

APP is working toward submitting its project application to the US Federal Energy Regulatory Commission in October 2012. The venture 2 weeks ago submitted the first of its draft resource reports to the commission, with all 11 reports expected by December. The project team will soon begin another field season in Alaska and Canada.

TransCanada said in February as part of its 2010 earnings report that it was working with shippers to resolve conditions received as part of its open season for the pipeline (OGJ Online, Feb. 16, 2011).

Two options were provided in the APP open season. The first option was a pipeline extending roughly 1,700 miles from ANS, through Alaska, the Yukon Territory and British Columbia, to Alberta, from where the gas would be delivered on existing pipeline systems serving North America.

The second option would transport gas about 800 miles from ANS to Valdez, Alas., where it would be converted to LNG in a facility to be built by others and then delivered by ship to North American and internationally.

Both options provided opportunities for Alaska communities to acquire gas from at least five delivery points on the pipeline. The Alberta option also provided the opportunity for local natural gas deliveries in Canada.

A world-class gas treatment plant (GTP) and Point Thomson gas transmission pipeline were components of both options. The GTP would be built next to ANS's Prudhoe Bay facilities to treat the gas for shipment on the pipeline. A roughly 58-mile pipeline would connect the gas supplies of Point Thomson field to the plant and transmission pipeline.

The project team will soon begin another field season in Alaska and Canada, covering topics such as soil permafrost, seismology, fish counts, wetlands, archaeology, and cultural resources. An initial field season was completed in summer and fall 2010.

Plains All American to build Eagle Ford oil line

Plains All American Pipeline LP plans to build a 300,000 b/d, 130-mile oil and condensate pipeline, a marine terminal facility, and 1.5 million bbl of storage to serve growing Eagle Ford production in South Texas. A long-term throughput agreement with Chesapeake Energy Marketing Inc., a subsidiary of Chesapeake Energy Corp., underpins the construction plans.

Chesapeake agreed earlier this month to a 10-year, 100,000 b/d shipping agreement with Enterprise Products Partners for capacity on the Phase II extension of EPP's 350,000 b/d Eagle Ford oil pipeline (OGJ Online, May 6, 2011).

Plains also agreed to provide Chesapeake Midstream Development LP the opportunity to acquire up to a 25% joint ownership interest in the project. Plains and Flint Hills Resources have similarly executed a memorandum of understanding regarding Flint Hills' potential joint ownership of the project.

Flint Hills operates a 300,000 b/d refinery in Corpus Christi, Tex. Plains expects the pipeline to enter service in fourth-quarter 2012 at a cost of about $330 million.

Shell, CPC reach long-term LNG supply deal

Shell Eastern Trading (Pte.) Ltd., trading as Shell Eastern LNG, and CPC Corp. signed a heads of agreement for long-term supply of LNG from Shell's global portfolio.

Shell will supply 2 million tonnes/year for 20 years starting in 2016. This is the first long-term LNG deal between Shell and CPC and makes Shell one the main suppliers of LNG to Taiwan.

Agreements were signed recently by CPC and Shell in Taipei and Singapore, respectively, and "exchanged by the parties" in Taipei. The announcement did not specify which supply projects might be contracted to fulfill the agreements.

Shell Development (Australia) Proprietary Ltd., meanwhile, plans the world's first floating LNG from Shell's Prelude development off Western Australia to start up in 2016 with planned export capacity of less than 1 million tpy (OGJ, Mar. 7, 2011, p. 100).

In addition, Shell holds an interest in the planned Sunrise project, also to employ floating liquefaction, to ship 4 million tpy. That targeted start-up, however, is 2017 at the earliest.

OGJ data show CPC currently operates nearly 21 million tpy at two terminals. The more recent started up in 2009.

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