IEA boosts call for OPEC oil on demand forecast
Worldwide oil demand is revised upward for 2010 and 2011 due mostly to buoyant global economic growth but also to cold weather in the northern hemisphere, the International Energy Agency said in its latest monthly Oil Market Report.
The Paris-based agency raised its assessments by 320,000 b/d from a month ago and now puts average oil demand at 87.7 million b/d in 2010, up 2.7 million b/d from a year earlier, and at 89.1 million b/d this year.
Oil demand among Organization for Economic Cooperation and Development member countries is estimated at 46.1 million b/d for 2010, up from 45.4 million b/d in 2009. IEA forecasts that OECD demand this year, however, will decline by 200,000 b/d should winter temperatures revert to their relatively warmer 10-year average.
Chinese demand reached a new record high last November at 10.2 million b/d, largely on rising gas oil use, accounting for roughly half of Asia's increase and for almost a third of total non-OECD growth.
Total non-OECD demand, estimated at 41.6 million b/d in 2010 and up 2.1 million b/d from 2009, will reach 43.2 million b/d in 2011, IEA projects. These prognoses could change, IEA says, depending on the evolution of China's gas oil shortages and as the effects of Iran's subsidy removal become clearer.
Although global oil supply fell by 300,000 b/d to 88.1 million b/d in December due to some temporary outages, supply from the Organization of Petroleum Exporting Countries reached 29.58 million b/d, gaining 250,000 b/d from the previous month and continuing to climb since last spring, IEA reported.
The call for OPEC crude is revised upward for 2011 to 29.9 million b/d from last year's 29.6 million b/d, and IEA notes that the organization's effective spare production capacity has dipped below 5 million b/d for the first time in 2 years.
In the fourth quarter of 2010, oil markets tightened as demand outweighed supply by 700,000 b/d, IEA said. Recent price strength, notably for international benchmark crude Brent, poses an economic risk, the agency warns, if $100/bbl oil becomes entrenched this year.
Qatar appoints energy minister
Qatar's Sheikh Hamad bin Khalifa Al-Thani has promoted Energy Minister Abdullah bin Hamad Al-Attiyah to chief of staff, and has named his successor as Mohammed Saleh al-Sada.
Al-Attiyah became Qatar's energy minister in 1992 and served a 1-year term as president of the Organization of Petroleum Exporting Countries in 1993. In 2007, Al-Attiyah was appointed deputy premier while retaining his position as minister of energy and industry.
During his 19-year tenure as minister of energy and industry, Al-Attiyah oversaw Qatar's development into the world's premier exporter of LNG from a country that had been reliant on oil exports of 480,000 b/d in 1992.
Indeed, Al-Attiyah's promotion came as Qatar prepared to begin operating the last of its 14 liquefied gas plants, a milestone that marks a 15% increase in its capacity to produce LNG.
Samuel Ciszuk, senior Middle East energy analyst at IHS Global Insight in London, said Al-Attiyah's new role in the Emir's court may reflect his achievements as energy minister.
"It is a clear promotion," the analyst said. "He goes to become one of the trusted advisers. The head of the Emiri Diwan is a very important position in the GCC states."
Ciszuk also said that Al-Sada's appointment may be seen as a reward for his having been a good administrator.
"The energy portfolio will change because there won't be the same brilliant growth," Ciszuk said. "It will focus more on administrating what they have rather than growing and formulating new policies."
Mohammed Saleh Al-Sada served as Minister of State for Energy and Industry Affairs after his appointment in 2007. Prior to that appointment, Al-Sada served as managing director of RasGas Co. Ltd.
The appointment placed Al-Sada in a key position regarding Qatar's gas industry as RasGas is the operating company for Ras Laffan LNG Co. Ltd., Ras Laffan LNG Co. Ltd. (II), and Ras Laffan LNG Co. Ltd. (III).
Alberta sees record 2010 oil and gas land sales
In 2010, Alberta's petroleum and natural gas land sales netted the province $2.38 billion (Can.), exceeding the previous sales record of $1.83 billion (Can.) set in 2005. Land sales revenue was $732 million (Can.) in 2009.
In addition, the July 7 sale netted an average price of $2,185 (Can.)/hectare, exceeding the previous high of $2,085 (Can.)/ha.
Alberta's Energy Minister Ron Liepert said, "I credit changes to the royalty structure, particularly the emphasis on using new technologies, for contributing to these record sales. These historic land sale results solidify Alberta's status as the jurisdiction for industry to invest."
Oxy to help develop UAE's Shah sour gas field
Occidental Petroleum Corp. said the government of Abu Dhabi approves its plans to take a 40% participating interest in Shah sour gas field under a 30-year contract. Abu Dhabi National Oil Co. (ADNOC) holds the remaining interest.
ConocoPhillips on Apr. 28, 2010, announced plans to withdraw from a joint venture with ADNOC to develop Shah field. The withdrawal came as part of ConocoPhillips's previously announced strategy to trim global operations (OGJ, Nov. 16, 2009, p. 68). ConocoPhillips had a 40% interest in Shah field.
Ray R. Irani, Oxy's chairman and chief executive, said, "This is another important step in the implementation of our growth strategy and in our relationship with the Emirate of Abu Dhabi."
Shah field contains high-sulfur gas reservoirs 110 miles southwest of Abu Dhabi City. The project will involve construction of several gas gathering systems, new gas and liquid pipelines, and processing trains. The development is expected to produce significant amounts of condensate and NGL.
ADNOC has started developing the field with the majority of project engineering procurement and construction contracts already awarded. Production from the field is scheduled to come on stream in 2014. Project costs are estimated at $10 billion.
Previously, ConocoPhillips and ADNOC had formed a company to drill 20 wells and build infrastructure for production of about 1 bscfd of raw gas yielding 1.6 million tonnes/year of NGL, 30,000-40,000 b/d of condensate, 3.4 million tonnes/year of sulfur, and 500-600 MMscfd of dry gas (OGJ, Nov. 16, 2009, p. 33).
BP to explore Ceduna subbasin off S. Australia
BP PLC was awarded four deepwater blocks in the unexplored Ceduna subbasin of the Great Australian Bight basin off South Australia. Exploration Permit for Petroleum areas EPP 37, EPP 38, EPP 39, and EPP 40 cover a combined 24,000 sq km about 200 km southwest of the city of Ceduna. BP has the right to develop any commercially viable discoveries.
The basin's geology indicates a high potential to contain hydrocarbons, said Phil Home, managing director of BP's Australian upstream oil and gas business.
BP said the proposed exploration would be phased over 6 years and, as part of the regulatory approval process, would be subject to detailed environmental assessment.
The company said seismic surveying could take place in the summer of 2011-12. Drilling isn't expected until 2013 or 2014.
BP said it is committed to use the intervening time to fully implement the lessons learned from the investigations into the Montara and Deepwater Horizon incidents and is working closely with the Australian and South Australian governments and industry to do so.
The Ceduna subbasin is west of the Duntroon subbasin, where a Woodside Petroleum (Pty.) Ltd. group drilled Gnarlyknots-1 in 2003 in 1,315 m of water in EPP 29 about 425 km west of Port Lincoln. Projected to 5,600 m, it went to 4,736 m and was unsuccessful.
Sinopec confirms gas find in Myanmar
Burma Petroleum Co. Ltd, a joint venture of Sinopec International Petroleum Corp. and Myanmar Oil & Gas Enterprise (MOGE), confirmed a major gas discovery in Myanmar.
This followed earlier reports by Myanmar state media that the Chinese-led group had discovered proved reserves of 909 bcf of gas and 7.16 million bbl of condensate in central Myanmar. Official reports said Sinopec made the discovery in Pahtolon oil field after extensive testing.
Last November, there were reports Sinopec found gas while exploring in central Myanmar, but the extent of reserves was not clear. A spokesman for Sinopec said he had no information about the gas discovery.
Win Myint, engineering director of state-owned MOGE, said Sinopec had been exploring for oil and gas near Monyma some 140 km northwest of Mandalay.
Analyst IHS Global Insight said the current discovery was probably "in onshore Block D, where Sinopec has been carrying out exploration activities, drilling the Thingadon 1 well in the Salin subbasin and the Padukkon 3 well."
The find adds to other Chinese projects already under way in the country, including two pipeline projects to carry gas from Myanmar's offshore fields and imported oil to southwestern China. CNPC launched construction of the two pipelines in Anning city near Kunming, the capital of Yunnan province in southwestern China. The planned 440,000 b/d oil pipeline and the 12 billion cu m/day gas pipeline both start at Kyaukryu port on the west coast of Myanmar, where construction began in June (OGJ Online, Sept. 13, 2010).
Drilling & Production — Quick TakesROV evaluates safety of Apache platform in gulf
Apache Corp. on Jan. 18-19 used a remotely operate vehicle (ROV) to evaluate the cause and source of a hydrocarbon release near East Cameron Block 278 Platform B in about 170 ft of water off Louisiana in the Gulf of Mexico.
Workers were on the platform for plugging and abandonment operations of wells when they noticed a hydrocarbon sheen on Jan. 16 and evacuated the platform (OGJ Online, Jan. 18, 2011). Results of the ROV survey will determine the next steps in responding to the water disturbance, Apache said.
The US Bureau of Ocean Energy Management, Regulation, and Enforcement, which is overseeing Apache's efforts, said the ROV is gathering information to evaluate the safety issues associated with the platform. On Jan. 18, BOEMRE said a relief well might be drilled if Apache determined that it was unsafe for crews to return to the platform. The agency gave no details about the suggested relief well.
BOEMRE inspectors conducted a second aerial review Jan. 18 in which they observed no apparent changes to the bubbling and discolored water near the platform.
"The discolored water may possibly be a mixture of sediment from the ocean floor, gas, and formation water. Oil is not believed to be present other than in small amounts of condensate, which quickly evaporates," the agency said. BOEMRE said it will investigate the incident.
Apache said no sheen was observed on Jan. 18. The platform, which has not been in production for nearly a decade, was used to process natural gas and condensate from other facilities. Before Apache shut in the platform for plugging and abandonment operations, East Cameron Block 278 Platform B processed 20 MMcfd from other facilities, the company said.
Total orders more subsea equipment for Girassol
Total Exploration & Production Angola ordered from FMC Technologies Inc. $80 million worth of subsea equipment for its Option 3-Girassol Infills project on Block 17 off Angola. FMC will manufacture and supply three subsea production trees, six wellheads, and assorted flow base and jumper equipment.
FMC said deliveries should commence in fourth-quarter 2011. Total E&P Angola operates Block 17 and has a 40% interest. Partners include Statoil 23.33%, Esso Exploration Angola (Block 17) Ltd. 20%, and BP Exploration (Angola) Ltd. 16.67%.
Facilities slated for Algeria's southern gas fields
In Salah Gas let a $1.2 billion contract to Petrofac Ltd. for the engineering, procurement, and construction to develop the Garet el Befinat, Hassi Moumene, In Salah, and Gour Mohmoudouthern gas fields in southern Algeria.
In Salah Gas is a venture of Sonatrach, BP PLC, and Statoil.
The work includes a new central production and gas gathering facility at In Salah, comprising of two dehydration trains with a 16.8 million cu m/day gas capacity, associated permanent camps, and about 300 km of gas gathering lines and a pipeline to the existing Krechba facility.
Petrofac will also modify the existing Reg facilities with an additional dehydration train and upgrade for future operations the existing Teg and Krechba compression facilities.
Petrofac plans to complete the 50-month project in phases so as to support the maintenance of a 9 billion cu m/year plateau gas production beyond 2013.
BP lets contract for six platform rigs in Caspian Sea
BP PLC let a 5-year contract to Aberdeen-based KCA Deutag AG—with an option for an additional 5 years—to manage all BP-operated platform drilling assets in the Azerbaijan section of the Caspian Sea.
The contract covers platform drilling operations and maintenance on the Central, East and West Azeri, Chirag, Deepwater Gunashli, and Shah Deniz platforms. BP operates Azeri-Chirag-Gunashli and Shah Deniz fields.
On the Chirag platform, KCA Deutag owns the rig, which BP leases. KCA Deutag for years has designed platform rigs for BP in the Caspian region and is designing the next platform rig for Chirag Oil Project, which is scheduled to be installed in 2013. Its operation falls under the new contract.
COP involves development of the Azeri, Chirag, and deepwater portion of the Gunashli fields.
PROCESSING — Quick TakesEncana to sell Colorado gas plant
Encana Corp. unit Encana Oil & Gas (USA) Inc. will sell its Fort Lupton natural gas processing plant in Colorado to Western Gas Partners LP, Houston, for about $303 million.
The Fort Lupton plant processes about 84 MMcfd and lies about 30 miles northeast of Denver. Included in the deal are five gathering pipeline systems and associated compression. Also as part of the transaction, Encana USA has negotiated gas processing fees that allow the company to continue extracting about 3,500 b/d of NGL from its processed natural gas.
The Encana announcement also said the agreement provides "long-term gathering and processing cost stability" for the company's ongoing gas development in the Denver-Julesburg basin.
The sale announcement is related to Encana's recently issued request for companies to bid on buying and completing construction on the Cabin gas plant in British Columbia. That plant has regulatory approval for two phases of development for total processing capacity of 800 MMcfd.
Encana, as operator, is building it to serve producers in the Horn River play in northeast BC. The Cabin plant is in the early stage of first-phase construction, designed to be able to process about 400 MMcfd, and is scheduled to start up in 2012.
Encana expects the Fort Lupton plant sale and the midstream divestiture of the Cabin plant, all of which is subject to certain regulatory approvals and customary closing conditions, to close in first-quarter 2011. Encana USA has owned and operated Fort Lupton since 2000 when one of its predecessor companies acquired the plant as part of a larger acquisition of exploration and production assets.
Petrobras signs contract for units at Refap
Petroleo Brasileiro SA (Petrobras) on Jan. 12 signed a contract for construction of a diesel hydrotreater and hydrogen generation unit at its Alberto Pasqualini refinery (Refap) in Canoas, state of Rio Grande do Sul.
Upon inquiry from Oil & Gas Journal, Petrobras declined to reveal with what company or companies it signed the contract, the contract's value, or when the units were expected to start up, although the company announcement said the work will take "about 3 years."
The HDT II unit, it also said, will be capable of treating 6,000 cu m/day of low-sulfur (10 ppm) diesel, thereby contributing to compliance with the environmental legislation and improving air quality. The UGH II unit will be able to produce 1.25 million cu m/day of hydrogen at 99% purity.
The refinery currently has installed capacity of 200,000 b/d. Production consists mainly of diesel and gasoline, in addition to petrochemical naphtha, propane, LPG (cooking gas), jet fuel, fuel oil, and asphalt.
Manguinhos refinery signs deal with Astra Oil
Brazil's privately held refinery Refinaria de Petroleos de Manguinhos SA signed a memorandum of understanding with Astra Oil Trading NV "to discuss and plan the best use of assets."
Manguinhos said the agreement concerns use of its facilities for treatment of oil to be produced by third parties from Brazil's presalt region. The agreement also covers joint production and storage of ethanol.
Manguinhos' facilities include 210,000 cu m of storage tanks linked by pipeline to Rio de Janeiro port to facilitate exports and imports.
The refinery also will study creation of new companies to operate the facilities at its site in Rio de Janeiro state, southeast Brazil, according to the firm's investor relations director Paulo Henrique Oliveira de Menezes.
The MOU marks the second time in 6 months the Manguinhos refinery agreed to explore the potential of its facilities with another partner.
Last June, state-run Petroleo Brasileiro SA (Petrobras) said it signed a similar letter of intent with the refinery for joint studies of business opportunities. Petrobras said the aim was to identify business opportunities, including partnerships in the refining area.
Petrobras said the agreement covered "modernization of the Manguinhos refinery to produce gasoline, diesel, and other products; transportation and logistics services; and biodiesel production."
Petrobras said the term of the protocol was for 1 year with possibility of renewal, and was limited to "the analysis of opportunities, not creating any additional obligation for the parties nor financial obligations for Petrobras."
It is not clear if Manguinhos's new agreement with Astra Oil Trading is in addition to or supercedes the earlier one with Petrobras.
TRANSPORTATION — Quick TakesAlyeska restarts Trans-Alaska Pipeline System
The Trans-Alaska Pipeline System resumed operations at 10:18 a.m. local time on Jan. 17 after crews at Pump Station 1 successfully installed a 157-ft bypass pipeline. TAPS operator Alyeska Pipeline Service Co., contractors, and regulators are closely monitoring the restarted line.
Alyeska initially shut down the line the morning of Jan. 8 after discovering crude oil in the booster pump building basement at Pump Station 1 at Prudhoe Bay. The leak source appears to be a below-ground pipe encased in concrete, the company said.
The pipeline temporarily restarted Jan. 11 while Alyeska employees and contractors prepared bypass piping. Alyeska shut down TAPS again overnight going into Jan. 15 to begin bypass installation.
During the shutdown oil producers on the North Slope reduced production to first 24% and then 16% of normal. Shortly before the restart, they scaled down further to 12%. All crude oil was routed to two tanks at the pump station.
After detecting the leak, responders installed an 800-gal containment vault and parked vacuum trucks on-site to remove oil from the vault. Total recovery estimate from Pump Station 1 is about 317 bbl.
Alyeska said officials would investigate the source of the leak and that no known harm had occurred to wildlife or the environment as a result of the leak.
EU, Azerbaijan sign SGC agreement
Azerbaijan President Ilham Aliyev and European Commission Pres. Jose Manuel Barroso signed a joint declaration on the establishment of a Southern Gas Corridor (SGC). The leaders signed the agreement after talks in Baku on Jan. 13.
Under the deal, Azerbaijan is set to become a long-term and "substantial contributor" to the SGC. In return, Europe has promised "visa facilitation" for Azeri nationals, which would make travel to EU member states easier for citizens of Azerbaijan.
While there is no mention of the gas volumes to be delivered, there are reports of 10 billion cu m (bcm)/year. This volume would not be enough for Nabucco, the main gas line project in the SGC, which has a planned capacity of 38 bcm.
There are three smaller projects in the SGC that will also need gas: the Trans-Adriatic Pipeline, the Turkey-Greece-Italy Interconnector, and the Azerbaijan-Georgia-Romania Interconnector.
Azerbaijan, which is as keen to diversify its gas exports as the EU wants to diversify its gas imports, is negotiating with several Western companies to grant access to 10 bcm of Azeri gas in Shah Deniz II field. On Jan. 12, Azerbaijan agreed to export at least 10 bcm/year of Azeri gas to Iran. It also sells gas to Russia.
"Azerbaijan will make a further decision on which of these pipelines to prioritize," according to an EU Commission executive.
After leaving Baku, Barroso and Energy Commissioner Gunther Ottinger traveled to Turkmenistan—also with huge gas reserves—in their quest to see the SGC "established and operational as soon as possible."
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