General Interest — Quick Takes
APGA backs bills to stop EPA's GHG program
A trade association representing 720 municipally and publicly owned natural gas distributors expressed its support for legislation aimed at halting the US Environmental Protection Agency's effort to regulate greenhouse gases under the Clean Air Act.
"In our view, Congress never intended the CAA to be used to control [GHGs] which do not manifest their impacts in the same manner as the pollutants controlled by the act," said American Public Gas Association Pres. Bert Kalisch.
"Efforts to address [GHG] emissions will have wide-ranging and significant impacts upon US energy consumers, the energy industry, and the economy as a whole," Kalisch wrote in a Mar. 15 letter to congressional leaders. "For this reason, it is APGA's position that efforts to reduce [GHG] emissions must be resolved by Congress alone."
EPA has said that it is formulating GHG regulations in response to a 2007 US Supreme Court finding that the emissions are covered under the CAA if threatening public health and the environment. EPA issued such an endangerment finding on Dec. 7, 2009.
US Sen. Lisa Murkowski (R-Alas.), the Energy and Natural Resources Committee's ranking minority member, introduced a disapproval resolution with 85 cosponsors on Jan. 21 aimed at stopping EPA so Congress can address the matter. Opponents say that her bill and others which have been introduced in the House as well as the Senate would create a dangerous precedent of lawmakers overturning a regulation which is based on a scientific finding.
"Only the legislative process can provide for thorough consideration of the resources that should be undertaken to reduce [GHG] emissions, including taking full advantage of the benefits the direct use of natural gas could provide in terms of overall emissions reduction," said Kalisch.
Indonesia's new law could cut oil output in half
Indonesia's upstream regulator BPMigas said the country's oil production could drop to half of its 965,000 b/d target in the 2-3 years it will take the industry to adjust to a new environmental law.
BPMigas Chairman R. Priyono cited one regulation that requires companies to lower the temperature of liquid waste by 5° C. that could adversely impact PT Chevron Pacific Indonesia, which uses steam flood and boils water to produce steam. "If the waste-water temperature is too restrictive, then the steam cannot be produced and used," he said.
Priyono cited another example in ConocoPhillips's operation in Belanak oil field, which contains a high degree of mercury. He said a regulation limiting the average mercury concentration to 40 ppm will require the company to redesign its facility.
"The refinery is not available in Indonesia. It's available among other options in Thailand. If the standards are implemented, the field's production will decrease by between 28,000-40,000 b/d of oil," Priyono said.
Oil and gas firms have already signaled their concerns about the new law. CPI said its production could fall by 248,000 b/d, while PT Pertamina EP said its production might drop by 61,000 b/d.
According to analyst IHS Global Insight, reports of a massive drop in oil production will likely resonate with the authorities who suspended Indonesia's membership in the Organization of Petroleum Exporting Countries in 2008 and are suffering from lower state revenues due to difficulties in increasing crude oil output. The analyst said, "Pressure by BPMigas and other contractors could thus result in a modification of implementing regulations to the 2009 Environmental Law, due to be finalized in April, to accommodate the most pressing concerns of contractors."
Eni plans to bring 41 fields on stream in 4 years
Italy's Eni SPA plans to bring 41 fields on stream in 4 years, resulting in 560,000 boe/d of new production in 2013. The oil and gas company plans to operate 75% of that new production.
Eni expects its production will grow more than 2.5%/year through 2013 and more than 2%/year up to 2016, according to Paolo Scaroni, Eni chief executive officer.
Assuming a $65/bbl oil prices, Eni expects its 2010 production will be in line with 2009 at 1.77 million boe/d. In 2013, production likely will exceed 2 million boe/d, Eni said.
Production growth will be focused on new high potential areas, particularly Iraq, Scaroni said. Eni, Occidental Petroleum Corp., and Korea Gas Corp. hold a technical services contract to redevelop Iraq's Zubair field near Basra (OGJ, Feb. 1, 2010, Newsletter).
Led by Eni, the group plans to boost Zubair production to 1.2 million b/d from 200,000 b/d within 6 years and to maintain that production level for 7 years. During 2010-13, Eni expects investments of €52.8 billion, up 8% from its 2009-12 plan. Exploration and production projects will account for the entire increase in investments, the company said.
Exploration & Development — Quick Takes
Total to develop gas fields west of Shetland
Total SA plans to develop the Laggan and Tormore gas fields west of the Shetland Islands, subject to UK government approval.
The £2.5 billion development lies in 600 m of water on Blocks 206/1a, 205/4b, and 205/5a, about 140 km off the Shetland Islands.
Total estimates that the fields contain 230 million boe of reserves and will have a 500 MMscfd peak gas production rate or a 93,000 boe/d peak rate when condensates are included.
The company plans to start work almost immediately on the offshore gas infrastructure and on a new gas processing plant at Sullom Voe on Shetland. It expects first gas production in 2014.
From the Sullom Voe gas plant, the produced gas will enter a 230-km export pipeline that will tie into the existing Frigg UK line. The Frigg line will transport the gas to the Total operated Saint Fergus gas terminal, north of Aberdeen. Total also has acquired Chevron North Sea Ltd.'s 10% interest and Eni UK Ltd.'s 20% interest in the fields. Total now holds an 80% interest with the remaining interest held by DONG E&P (UK) Ltd.
Petrobras finds oil near Piranema field
Petroleo Brasileiro SA (Petrobras) reported the discovery of light oil below salt 28 km off the Brazilian state of Sergipe.
It said the 3-PRM-12-SES well, in the northern part of the Piranema concession area in the Sergipe basin, indicated presence of 44º gravity oil in good-quality sandstone.
The well was drilled to 2,693 m in 800 m of water.
Petrobras plans a second well and is considering a development scheme tied to the production platform on nearby Piranema oil field. It estimated economically recoverable oil in the discovery at 15 million bbl.
BG Norse finds oil near Snorre field in North Sea
BG Group subsidiary BG Norge AS discovered oil near Norway's Snorre field in the North Sea, the Norwegian Petroleum Directorate announced.
NPD said BG Norge, operator of production license 374 S, is in the process of completing the drilling of wildcat well 34/5-1 S about 25 km northeast of the Snorre field.
The primary exploration target was to prove petroleum in Lower Jurassic reservoir rocks (the Cook formation). The secondary exploration target was to prove petroleum in Lower Jurassic to Upper Triassic reservoir rocks (the Statfjord formation).
"Oil was proven in the Cook formation, while the Statfjord formation was dry," NPD said, adding that the licensees will consider the resource potential by drilling an appraisal well as a sidetrack from well 34/5-1 S.
NPD said the well was not formation-tested, but extensive data acquisition and sampling have been carried out. It said 34/5-1 S is the first exploration well in production license 374 S, which was awarded in APA 2005.
The well was drilled to a vertical depth of 3,712 m subsea and was terminated in the Statfjord formation.
The water is 387 m deep. After the appraisal well is drilled, well 34/5-1 S will be permanently plugged and abandoned.
Well 34/5-1 S was drilled by the Bredford Dolphin semisubmersible rig, which will now drill appraisal well 34/5-1 A on the discovery.
Norway, while warning of the potential for espionage directed against its oil and gas industry, last month launched its 2010 oil and gas licensing round for predefined areas (APA).
"Good and regular access to acreage is necessary to secure further activity on the Norwegian Continental Shelf," said Norwegian Oil Minister Terje Riis-Johansen (OGJ Online, Feb. 25, 2010).
Drilling & Production — Quick Takes
North Rankin B installation to set records
The floatover installation of the North Rankin B (NRB) platform topsides on Australia's North West Shelf will set world weight and water-depth records, says a contractor.
The 23,600-ton topsides will be set on a steel jacket in 413 ft of water. Wood Group's Mustang calls it the world's deepest open-water floatover steel jacket.
Woodside Energy Ltd., Australian operator of the North West Shelf Venture, selected Mustang to provide the independent assessment and verification of readiness for the installation.
The NRB is part of a redevelopment project that will recover low-pressure natural gas from North Rankin and Perseus gas fields, extending field life to about 2040, according to Woodside.
The NRB, scheduled for start-up in 2013, will be bridge-linked to the North Rankin A platform 100 m away. The platforms will function as a single integrated facility known as the North Rankin hub.
The NRB topsides will be transported to the field on a 20-m high deck support frame for installation, without cranes, atop the jacket at an elevation of 28 m.
The North Rankin A platform, 135 km northwest of Karratha, Western Australia, can handle 1.815 bscfd of gas produced by 25 wells. North Rankin field was discovered in 1971, Perseus in 1996.
Discoverer drillship starts operations for Chevron
Transocean Ltd. reported the newbuild ultradeepwater drillship Discoverer Inspiration has started operations for Chevron USA Inc. in the Gulf of Mexico under a 5-year drilling contract.
The vessel is an enhanced version of Transocean's three predecessor Enterprise-class drillships, which have set deepwater drilling records in recent years, including the world water-depth drilling record of 10,011 ft set by the Discoverer Deep Seas while working for Chevron in the Gulf of Mexico.
The dual-activity technology, along with a new and enhanced top drive system, a high-pressure mud system, and other unique features of the drillship target the drilling of wells up to 40,000 ft of total depth. The rig also has a variable deckload of more than 20,000 tonnes and the capability of drilling in up to 12,000 ft of water.
AIOC sanctions Chirag oil project
Azerbaijan International Operating Co. (AIOC) has sanctioned the investment of $6 billion for the Chirag oil project.
The project plans to increase oil production and recovery from the Azeri, Chirag, and deepwater portion of the Gunashli fields (ACG fields) through a new offshore facility that will fill a gap in the field infrastructure between the existing Deepwater Gunashli and Chirag-1 platforms.
AIOC expects the project to recover an additional 360 million bbl of oil from the ACG fields with first oil production from the project starting in 2013.
The project involves installing new wells that will primarily target the currently producing Fasila reservoirs and also the Balakhany X, IX, and VIII reservoirs above the Fasila. AIOC expects facility construction and the predrill program to cost about $4 billion and has slated the remaining $2 billion for drilling development wells from the platform.
AIOC developed the ACG fields in several phases. Chirag has been on production since 1997 as part of the early oil project. The Azeri Project Phase 1-Central Azeri production followed in early 2005. This was followed by production from Phase 2-West Azeri starting in January 2006, from East Azeri starting in October 2006, and from Phase 3-Deepwater Gunashli starting in April 2008.
AIOC expects overall production from the ACG fields to reach 1 million bo/d and the fields to eventually produce more than 5 billion bbl of oil. To date the fields have produced 1.4 billion bbl of oil.
Operator BP PLC has a 34.1% interest in the ACG fields. Other interest owners are Chevron Corp. 10.2%, State Oil Co. of the Azerbaijan Republic 10%, Inpex Corp. 10%, Statoil ASA 8.6%, ExxonMobil Corp. 8%, Turkish Oil Corp. 6.8%, Devon Energy Corp. 5.6%, Itochu Corp. 3.9%, and Hess Corp. 2.7%.
Processing — Quick Takes
Saudi-Shell refinery boosts ULSD output
Saudi Aramco Shell Refinery Co. (Sasref) has completed a project to increase production of ultralow-sulfur diesel at its 305,000-b/d refinery at Jubail, Saudi Arabia.
The 50-50 joint venture of Saudi Aramco and Shell built a high-pressure diesel hydrodesulfurization unit and revamped two crude units and an existing diesel HDS unit.
The new and revamped facilities have begun production of 100,000 b/d of diesel with less than 10 ppm sulfur.
The project also included in-line blending and amine treatment facilities.
The Sasref hydrocracking refinery yields mainly middle distillates from Arabian Light crude.
Japan, Australia to launch coal-to-gas project
Japan and Australia are expected to sign an agreement next month or possibly later to work together on a project to convert low-quality coal into natural gas, according to Japanese media.
The Nikkei Business Daily (NBD) reported that the two governments are expected to start building a large trial facility in Victoria state in the year ending Mar. 31, 2012. The report said the construction contract will likely be awarded to Nippon Steel Engineering Co.
The pilot plant is scheduled to begin operating in fiscal 2014, and large commercial plants would be built at a cost of as much as ¥100 billion, if the initial tests prove successful.
With an eye toward exporting gas output to Japan and elsewhere, the plant also is expected to be equipped with an LNG production facility, with commercial production coming online as early as in fiscal 2015.
According to NBD, a commercial plant will be capable of producing more than 300,000 tonnes/year of gas, which is equal to about 0.5% of Japan's annual LNG imports.
Nippon Steel Engineering has the technology to boost the energy efficiency of the coal gasification process to 85%, the highest level in the world.
The technology is also expected to reduce carbon dioxide emissions from the process by nearly 10% compared with the discharges from US coal gasification plants.
The Japanese-Australian project will have an even smaller carbon footprint because carbon dioxide emissions are expected to be captured and stored underground.
The report added that Japan also aims to build similar coal gasification plants in the Asia-Pacific region, where large low-quality coal reserves are found.
Transportation — Quick Takes
ExxonMobil's PNG LNG project completes SPAs
ExxonMobil Corp. reported that all sales and purchase agreements with LNG buyers and financing arrangements with lenders for its Papua New Guinea LNG (PNG LNG) project are complete, and affiliate Esso Highlands Ltd. is "proceeding with full execution" of the project.
PNG LNG includes gas production and processing in the country's Southern Highlands and western provinces; 6.6 million tonnes/year liquefaction capacity and storage northwest of Port Moresby on the Gulf of Papua; and more than 450 miles of pipelines connecting production, plant, and storage.
The project will supply four LNG customers in Asia through long-term sales: CPC Corp., Osaka Gas Co. Ltd., Tokyo Electric Power Co. Inc., and Unipec Asia Co. Ltd., a unit of China Petroleum and Chemical Corp. (Sinopec).
Investment for the initial phase of the project, excluding shipping, is estimated at $15 billion. Over its 30-year life, said the announcement, PNG LNG will produce more than 9 tcf of gas. First LNG deliveries are set for 2014.
Funding for PNG LNG project will come from the venture partners and through market-rate loans arranged with export credit agencies and commercial sources, said the company.
In May 2009, Papua New Guinea, representatives of project area landowners, and four provincial and 10 local governments approved the PNG LNG "Umbrella Benefits Sharing Agreement" (OGJ Online, May 27, 2009). The agreement outlines revenue-sharing streams from royalties, development taxes, and equity dividends totaling $5.6-7.5 billion over the project life.
PetroVietnam, Chevron to lay $1 billion gas line
PetroVietnam Gas Corp. (PV Gas) has formed a partnership with a Chevron Corp.-led consortium to construct a $1 billion pipeline that would transport natural gas from Chevron's fields in southern Vietnam to the Mekhong Delta region.
PV Gas agreed to hold a 51% stake in the venture, which will involve the building of a 398-km pipeline—246 km offshore and 152 km onshore. Other consortium participants include Mitsui Oil Exploration Co. (Moeco) and Thailand's PTT Exploration & Production PLC (PTTEP).
The pipeline will transport as much as 18.3 million cu m/day of gas from Blocks B, 48/95, and 52/97, which lie off southwestern Vietnam.
PV Gas will serve as the line's operator. The line will supply gas to industrial users in the southern province of Ca Mau, including to a 3,000-Mw electric power plant as well as to a fertilizer complex.
Stakeholders in Blocks B and 48/95 are Chevron 42.38%, Moeco 25.62%, PetroVietnam Exploration & Production Corp. 23.5%, and PTTEP 8.5%.
Chevron holds a 43.4% share in Block 52/97, while PetroVietnam E&P holds 30%, Moeco 19.6%, and PTTEP 7%.
The Chevron-led group is preparing gas development from its offshore gas fields, in line with a heads of agreement for front-end engineering and design concluded in July 2009 with Vietnam Oil & Gas Group.
Keystone XL crude line gets NEB, SD approval
Canada's National Energy Board Mar. 11 approved an application from TransCanada Keystone Pipeline GP Ltd. to construct and operate the Keystone Gulf Coast Expansion Project (Keystone XL), as well as the proposed tolls for the pipeline once it becomes operational.
Keystone XL is a 1,980-mile, 36-in. OD crude oil pipeline extending from Hardisty, Alta., to a delivery point near existing terminals in Nederland, Tex., serving the Port Arthur, Tex., refining market. Keystone XL will interconnect in Cushing, Okla., with a leg of the Keystone pipeline connecting its original terminus in Patoka, Ill., with the Cushing hub before continuing to the Gulf Coast. Line fill to Patoka is under way, with first crude expected to arrive midyear.
The XL expansion will increase the capacity of the Keystone Pipeline System to 1.1 million b/d from 590,000 b/d. The $12 billion system is 83% subscribed with long-term commitments of 910,000 b/d for an average term of about 18 years.
The Canadian portion of Keystone XL involves construction and operation of 529 km of new pipeline and related facilities from Hardisty, Alta., to the US border at Monchy, Sask. NEB approval included 22 conditions, all of which must be met before TransCanada will be granted permission to open the pipeline, as well as an obligation to monitor the pipeline's greenhouse gas emissions.
NEB said it found the proposed pipeline to be in the public interest and accepted that the project would connect a large, long-term, and strategic market for Western Canadian oil with the US Gulf Coast in a manner that would bring economic and other benefits to Canadians.
Separately, TransCanada received a permit from the South Dakota Public Utilities Commission on Mar. 12 to construct and operate the South Dakota portion of Keystone XL line. Additional applications for US regulatory approvals of Keystone XL are under way. TransCanada expects decisions by the fourth quarter.
Construction is expected to begin in first-quarter 2011 with deliveries of oil to the Gulf Coast to begin in first-quarter 2013.
Argentina gas line to cross Strait of Magellan
Argentina has launched a $314 million, 37.7-km natural gas pipeline across the Strait of Magellan, linking Cabo Espiritu Santo in Tierra del Fuego province with Cabo Vírgenes in Santa Cruz province.
The new line "allows us to give more gas to homes and also to the country's industry," said Argentine President Cristina Fernandez de Kirchner, adding that the project is the country's "most important gas project in the past 32 years."
The new pipeline was built as an expansion to the existing San Martin pipeline in an effort by the government to increase gas supplies from Tierra del Fuego to the Argentinean mainland.
Buenos Aires hopes the new line will help boost gas production after 6 years of shortages and tight supplies. Argentina's gas production fell by 7.3% to 132.6 million cu m/day in 2009 from 143.1 million cu m/day in 2004.
In particular, officials believe the new pipeline will permit the start-up or restart of operations at gas fields by a consortium comprised of Total SA, Wintershall, and Pan American Energy, including the onshore Ara and Canadon Alfa fields as well as Hidra, Kaus, Argo, Carina, and Aries fields offshore.
Argentina's planning minister Julio De Vido said the new line initially will begin transporting 5.5 million cu m/day in June, with an additional 2 million cu m/day coming online in early 2011. Together, the two pipelines will provide 18.5 million cu m/day in 2011—an increase of nearly 70% over the current 11 million cu m/d.
Analyst IHS Global Insight was upbeat about the new line, saying that Argentina "has periodically suffered gas supply disruptions in recent years and increasing investments in production and new pipelines are regarded as the key to improving the situation."
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