Marathon Oil completes downstream spinoff
Marathon Oil Corp. completed the spinoff of the downstream business, Marathon Petroleum Corp., making Marathon Oil an independent upstream company based in Houston. Marathon Petroleum became an independent refiner based in Findlay, Ohio (OGJ, Jan. 7, 2011, Newsletter).
Clarence P. Cazalot Jr. on July 1 became Marathon Oil's chairman in addition to his responsibilities as president and chief executive officer. To effect the spinoff, Marathon Oil shareholders received one share of Marathon Petroleum common stock for every two shares of Marathon Oil common stock held on June 27.
At yearend 2010, Marathon Oil had net proved reserves of more than 1.6 billion bbl in the US, Angola, Canada, Equatorial Guinea, Indonesia, Iraqi Kurdistan Region, Libya, Norway, Poland, and UK.
UK Treasury moderates tax for new investors
New entrants to the UK Continental Shelf received a tax incentive July 5 when the UK government increased a tax allowance for marginal fields.
The UK Treasury said the Ring Fence Expenditure Supplement will rise to 10% from 6%, enabling companies to offset a greater amount of expenses against taxes.
Oil & Gas UK called the move constructive and an "encouraging first sign" but cautioned that it "will not redress the damage caused by the recent tax increase." It said the relief will help new investors to the UKCS who are otherwise disadvantaged compared with more established players.
Norway's Statoil AS said July 5 it will reactivate plans for the Mariner and Bressay development, $10 billion in projects it postponed when the government included a large tax hike on the industry in its 2011 budget.
Earlier this year the UK Treasury announced a new top tax rate of 81% and a new lower limit of 62% on UK oil and gas production and capped companies' ability to claim tax relief for decommissioning at the old tax rates. A University of Aberdeen study found that substantial long-term reductions in field investment and oil and gas production that would result (OGJ Online, May 6, 2011).
In making the ring fence change, the government "appears to acknowledge that the increase in supplementary corporation tax announced in this year's budget has made the UK less competitive," OGUK said.
OGUK Chief Executive Malcolm Webb said, "We made it clear after the budget that government actions and not just words would be required to begin to rebuild trust and restore the confidence of investors. This will help some new players but much more action is needed including on other reliefs and on the important decommissioning problem in the light of the budget."
DNO to acquire RAK Petroleum's MENA units
DNO International ASA agreed to acquire RAK Petroleum PCL's Middle East and North Africa operating subsidiaries through a stock transaction.
The transaction, estimated at a total value of $250-300 million, will be treated as a merger under Norwegian law. DNO plans to remain based in Oslo. RAK is based in Dubai.
The boards of both DNO and RAK endorsed the proposed transaction July 3. The shareholders of each company have yet to give final approval.
After closing, RAK will hold 40% interest in DNO. Currently, RAK holds 30% interest in DNO.
Vedanta, Cairn guarded on takeover nod
Vedanta Resources PLC and Cairn Energy have responded noncommittally to a June 30 report by the Indian government of conditional approval of Vedanta's acquisition of a controlling interest in Cairn India Ltd.
Vedanta, a mining conglomerate based in London, offered in August 2010 to buy up to 60% of Cairn India for $9.6 billion and has since bought minority interests (OGJ, Apr. 25, 2011, Newsletter). Cairn India holds several exploration and production licenses in India and is developing a complex of fields in Rajasthan with production climbing toward an approved peak of 175,000 b/d.
The deal has been complicated by a dispute over handling of royalty payments in the Rajasthan operation by state-owned Oil & Natural Gas Corp., a 30% partner.
On June 30, the Ministry of Petroleum and Natural Gas reported that the Cabinet Committee on Economic Affairs approved the deal subject to several conditions, including approval by ONGC, settlement of the royalty dispute in favor of ONGC, and withdrawal of an arbitration case over the proposal.
"Cairn has not yet received formal confirmation of any conditions or of further consents attaching to the approval," Cairn Energy, Edinburgh, said in a statement. "Cairn and Vedanta continue to work towards concluding this transaction."
Vedanta said, "Vedanta awaits official intimation of the approval and details of the preconditions from the government of India in order to consider further course of action."
BG sees up to 8 billion boe net in Santos presalt
BG Group said its presalt holdings in the Santos basin off Brazil contain a net potential of 6 billion bbl of oil equivalent mean total reserves and resources, double the group's early 2010 best estimate.
The company estimated a 90% chance that its interests contain at least 4 billion boe and a 10% chance they could hold as much as 8 billion boe net.
BG Group's Santos basin presalt interests include:
• A 30% interest in the BM-S-9 block containing the Guara, Carioca, Abare, and Iguacu discoveries and prospects.
• A 25% interest in BM-S- 10 containing the Parati and Macunaima discoveries and prospects.
• A 25% interest in BM-S-11 with the Lula, Cernambi, and Iara discoveries and prospects.
• A 20% interest in BM-S-50 containing prospects including Sagittario.
• A 40% interest in BM-S-52 including the Corcovado discovery.
The new estimate results from an internal analysis based on probabilistic modeling that took in a wealth of drilling, appraisal, and other data that BG Group has gained or developed in relation to those interests, including:
• A total of 29 wells drilled in the existing discoveries; two wells drilled on Lula since November 2010 proving particularly important in delineating the flanks of the field. Other wells have demonstrated excellent connectivity in the reservoir;
• A total of 19 drillstem tests on current discoveries;
• The shooting and analysis of more than 14,400 sq km of 3D seismic;
• Full analysis of a completed extended well test (EWT) on Lula Sul and early results from the Guara EWT indicating the very large hydrocarbon volumes connected to each wells;
• Production from the first permanent floating production, storage, and offloading vessel on Lula that started up in October 2010;
• Development plans that include enhanced recovery processes to improve ultimate recovery factors for these giant fields; and
• Cost optimization, potential debottlenecking of facilities, and greater well productivity enhancing the economic viability of later phases of development.
BOEMRE releases report on gas hydrate finding methods
Multicomponent seismic data could be more useful than traditional seismic methods in locating natural gas hydrates in deepwater environments, a study funded by the US Bureau of Ocean Energy Management, Regulation, and Enforcement concluded. The study by Louisiana State University's Coastal Studies Institute suggested that new technologies using four-component, ocean bottom cable to acquire multicomponent seismic data have shown promise in locating such gas hydrate deposits, BOEMRE said on July 5.
The study also offered an unparalleled research opportunity to employ the new data set collected from a large area of the northern Gulf of Mexico's upper continental slope to provide a new enhanced imaging capability for the area, the US Department of the Interior agency added.
BOEMRE Director Michael R. Bromwich said the study is critical in finding the most effective way to reach northern gulf gas hydrate deposits for future energy production. "Finding the best and most effective way to gather essential data on these deposits will improve our ability to conduct better resource evaluations of methane hydrates," he observed.
USGS raises Cook Inlet gas resources estimate
The US Geological Survey significantly increased its estimate of recoverable natural gas resources in and around Alaska's Cook Inlet to a mean 19 tcf as it released a new evaluation of the region's oil, gas, and gas resources for the region on June 28.
USGS's previous mean estimate in 1995 was 2.14 tcf. It attributed the increase in undiscovered, technically recoverable southern Alaska resources to new geologic information and data. The Cook Inlet area also contains about 600 million bbl of oil and 46 million bbl of natural gas liquids, USGS said.
"For the first time, USGS has evaluated unconventional (or continuous) as well as conventional petroleum resources in the Cook Inlet region of Alaska," said Brenda Pierce, the agency's energy resources program coordinator. The assessment contains coalbed methane as well as tight gas formations, which require different production methods than conventional gas resources, she noted.
USGS said the assessment of undiscovered Cook Inlet region gas resources ranges from 4.976 tcf to 39.737 tcf (with a 95% and 5% probability, respectively). Of this total, about 72% is estimated to be found in conventional accumulations, 25% in CBM accumulations, and 3% in tight gas accumulations.
The undiscovered oil resource estimate ranges from 108 million bbl to 1,359 million bbl (with a 95% and 5% probability, respectively). The Cook Inlet region's potential oil resources are all conventional, according to USGS.
Drilling & Production — Quick TakesApache expands Forties output with 4D seismic
The location for a UK North Sea Forties field development well that went on production at 12,567 b/d of oil, a 20-year field high, was chosen from 4D time-lapse seismic data, said Apache Corp.
Apache, which shot the most recent 3D survey over the field in 2010, is identifying more areas of bypassed oil from the 4D data. It has tapped another of those targets at the Delta 3-5 development well, which began production at 8,781 b/d of oil.
At 12,567 b/d, the Charlie 4-3 development well had the highest initial rate in Forties since 1990. It follows the previously disclosed Charlie 2-2, completed in March, at 11,876 b/d.
Charlie 4-3 and Delta 3-5 are the eighth and ninth development wells brought on production at Forties this year. Apache expects to drill a total of 16 wells in the field in 2011.
Forties was making 40,000 b/d when Apache acquired it in 2003. With the onset of the new wells in mid-June, gross production rates have reached as high as 70,000 b/d of oil equivalent even with output constraints due to construction projects and temporary pipeline closures.
At the Charlie platform alone, Apache development drilling has hiked production to 30,000 b/d from a low of less than 5,000 b/d in 2006. Apache expects full transmission capacity to become available in the current quarter as planned repair and maintenance work is completed and the Bravo pipeline comes back online.
Apache owns a 97.14% interest in Forties field, the largest single oil accumulation discovered in the UK North Sea and 40 years after its discovery the second highest producing oil field.
Shell orders subsea, topsides systems for Prelude FLNG
Shell Development (Australia) Pty. Ltd. signed agreements with FMC Technologies Inc. for supplying subsea production and associated topsides systems as well as installation and commissioning services for the Prelude field development off Australia.
FMC expects orders associated with the agreements to be received throughout this year.
Prelude field lies in the Browse basin, northeast of Broome, Western Australia, in 820 ft of water. It will become Shell's first field development to use a floating LNG vessel.
FMC will supply seven large-bore subsea production trees, production manifolds, riser bases, subsea control systems, and other related equipment.
The $11 billion project, which is scheduled to come on stream in 2016, is expect to produce 3.6 million tonnes/year of LNG, 1.3 million tpy of condensate, and 400,000 tpy of LPG (OGJ, May 20, 2011).
CNPC begins operations at Al-Ahdab oil field
China National Petroleum Corp. (CNPC) began operations of the first phase of Iraq's Al-Ahdab oil field, according to Chinese official media.
Al-Ahdab is expected to produce 25,000 b/d of oil in the first 3 years and 115,000 b/d in 6 years as stipulated in the $3 billion contract signed with Iraq's Ministry of Oil in 2008.
The project is the first major oil development agreement with an international firm since the fall of Saddam Hussein in 2003. It revived a 1997 contract that granted China exploration rights in Al-Ahdab.
The current Al-Ahdab contract is a service agreement, which allows CNPC to charge a service fee of $6/bbl that will decline to $3/bbl. But the agreement nonetheless provided the Chinese an entry into Iraq ahead of Western majors as part of their effort to develop the high-end oil market in the Middle East.
In 2009, CNPC signed an agreement along with BP PLC to increase production at Iraq's biggest oil field, Rumaila, while a consortium led by PetroChina signed a 20-year agreement to develop Iraq's Halfaya oil field.
PROCESSING — Quick TakesRefiners Holly, Frontier complete merger
Independent refiners Holly Corp., Dallas, and Frontier Oil Corp., Houston, have completed their merger (OGJ Online, May 30, 2011).
The new company, HollyFrontier Corp., Dallas, operates refineries with capacities totaling 443,000 b/d in Artesia, NM; Tulsa; Woods Cross, Utah; El Dorado, Kan.; and Cheyenne, Wyo.
Aramco project to cut Riyadh product sulfur
Saudi Aramco has let a contract to Foster Wheeler SOFCON for front-end engineering design and project management for a project to lower sulfur content of gasoline and diesel produced at its 120,000-b/cd refinery in Riyadh.
The FEED work includes new isomerization, naphtha-splitting, and sulfur guard-bed units and addition of equipment, including a diesel hydrotreater reactor, to existing units. Also included are debottlenecking of the refinery's 33,820-b/cd hydrocracker and gas concentration units and replacement of crude and vacuum distillation tower internals.
The project will lower sulfur content of gasoline and diesel to 10 ppm and the benzene level of gasoline.
Foster Wheeler SOFCON is an unincorporated consortium of a subsidiary of Foster Wheeler's Engineering and Construction Group and A. Al-Saihati, A. Fattani & O. Al-Othman Consulting Engineering Co.
PDVSA lets Barinas hydroskimming contract
Petroleos de Venezuela SA let a front-end engineering design services contract to a unit of Foster Wheeler for the first-phase hydroskimming section of the 100,000-b/d Batalla Santa Ines Refinery under construction in Barinas, Venezuela.
The work includes a basic engineering design package, FEED, and early procurement assistance for the crude distillation unit, naphtha hydrotreater, continuous catalytic reformer, and utilities and offsites facilities. FEED completion is scheduled for this year's third quarter.
PDVSA announced start of construction of the refinery in 2008, saying the facility would run crude from Barinas and Apure states as well as Orinoco heavy crude (OGJ Online, Oct. 13, 2008). It said an initial phase, at the time scheduled for completion this year, would have capacity of 30,000 b/d.
Variable-speed drives going to Utah gas plant
Chipeta Processing LLC, a subsidiary of Anadarko Petroleum Corp., has commissioned Converteam, Pittsburgh, a power-conversion specialist, to supply a complete variable-speed drive system to control two natural gas compressor trains at the Chipeta gas processing plant in Utah. The vendor estimates a savings in energy costs of $2 million/year.
The Converteam variable-speed drive technology is an arch-flash rated, 36-pulse PWM MV7000 drive designed to operate two 32,000-hp, 12-kv synchronous motors over a range of 900 to 1,800 rpm, according to the company.
The Chipeta plant will have cryogenic and refrigeration processing capacity totaling 750 MMcfd. The electric-driven compression and centralized zero-emission dehydration units minimize emissions and increase on-line performance, according to Converteam.
TRANSPORTATION — Quick TakesExxonMobil continues Yellowstone line cleanup
Cleanup efforts continue on a crude oil pipeline leak reported by ExxonMobil Corp. The major discovered an undetermined amount of oil in the early morning of July 2 released into the Yellowstone River from an ExxonMobil Pipeline Co. pipeline. The release originated from a 12-in. OD crude pipeline extending from Silver Tip, Mont., to Billings, Mont. ExxonMobil reports shutting down the pipeline within 7 min of pressure loss and immediately isolating the segment where the release occurred. The company estimates between 750 and 1,000 bbl of oil were released.
ExxonMobil has established a unified command to manage response activities, including recovering oil, monitoring air and water quality, and addressing questions from local residents. ExxonMobil is coordinating the response with the US Environmental Protection Agency, the Montana Department of Environmental Quality, US Department of Transportation Pipeline and Hazardous Materials Safety Administration, Montana Fish, Wildlife and Parks, Yellowstone County Disaster and Emergency Services, and Yellowstone County commissioners.
The unified command has organized the area downstream of the spill into four zones. Cleanup activities are focused in the first two zones, Laurel to Duck Creek Bridge, a distance of 7 miles from the spill location, and Duck Creek Bridge to Johnson Lane (12 miles). Active cleanup in these zones includes more than 48,000 ft of absorbent boom, 2,200 ft of containment boom, and 2,300 absorbent pads. Vacuum trucks and tankers have also been deployed to pick up and dispose of the oil.
Reconnaissance and evaluation activities are under way in the second two zones, Johnson Lane to Miles City (144 miles) and Miles City to Glendive (78 miles). Daily aerial flights over the river will identify additional oil locations and monitor and direct cleanup activity. ExxonMobil teams are also walking the parts of the shorelines where it is safe to do so.
Flooding in the area has so far complicated cleanup efforts. But ExxonMobil has eight boats staged at Coulson Park for deployment for reconnaissance and monitoring on the river.
CPC begins $5.4 billion pipeline expansion
Chevron Neftegaz reported that the Caspian Pipeline Consortium (CPC) has started the construction phase of the $5.4 billion expansion of the Caspian pipeline.
"CPC is a model of cooperation between Russia and Kazakhstan and is an indication of the confidence we have in Russia and in oil transportation from the Caspian region," said Neftegaz Pres. Andrew McGrahan.
The capacity of the 1,500-km pipeline, which carries oil from western Kazakhstan to a dedicated terminal in the Black Sea, will increase to 1.4 million b/d from its current capacity of 730,000 b/d.
Chevron, which is providing project management services to the project, said the expansion will be comprised of the refurbishment of the existing 5 pump stations, and 10 new pumping stations.
The expansion will also see replacement of an 88-km section of the line, six new storage tanks and the addition of a third offshore mooring point at the Black Sea terminal, 10 km north of Russia's Black Sea port of Novorossiysk.
The expansion, which is to be implemented in three phases with capacity increasing progressively from 2012-15, will help CPC take advantage of an expansion at Kazakhstan's Tengiz oil field, which has estimated recoverable reserves of 6-9 billion bbl. Anuarbek Dzhakiyev, deputy general director of the Tengizchevroil joint venture operating the field, last month said the company will invest up to $20 billion over the next 5 years to ramp up production to 36 million tons a year of oil.
DTE Energy unit to build Marcellus gathering system
Bluestone Gathering, a unit of DTE Energy, plans to build and operate a natural gas gathering system in Susquehanna County, Pa., and Broome County, NY. Bluestone will deliver Marcellus shale gas to Millennium Pipeline in Broome County, NY, and to Tennessee Pipeline in Susquehanna, Pa. Bluestone's initial capacity call for more a total of than 250,000 dekatherms/day (dth/d) to the Millennium and Tennessee pipelines.
Southwestern Energy Services Co. signed a long-term agreement with Bluestone, which will be DTE Energy's first gathering project outside Michigan. Bluestone project plans call for 37 miles of 16-in. or 20-in. OD pipeline scheduled to be operational second-quarter 2012. Many miles of high-pressure and low-pressure smaller-diameter pipeline will be used for an in-field gathering system.
DTE Energy, which owns 26.25% of Millennium Pipeline, plans to spend more than $250 million total over 5 years on the Bluestone gathering lateral and the field-gathering system.
Millennium Pipeline plans two expansions scheduled to be operational in late 2012 and late 2013. These two expansions will increase Millennium's capacity to 825,000 dth/d from 525,000 dth/d.
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