OIL AND GAS
TABLE OF CONTENTS
A major campaign of enhanced oil recovery (EOR) in offshore fields will be crucial for sustaining the world's future oil supply, according to renowned petroleum consultant Dr. Rafael Sandrea.
Sandrea, president of Tulsa, Okla.-based IPC Petroleum Consultants Inc., is the author of a groundbreaking, provocative new multiclient study published in May by the Oil & Gas Journal Research Center.
Offshore fields have been the main source of growth for world oil production in recent years, as onshore oil output has been essentially flat during the last two decades, he notes. But less than a fourth of the world's ultimate recoverable oil reserves in offshore fields has been produced to date. That opens the door for a big EOR push to extract the remaining technically recoverable oil offshore. Sandrea also contends that EOR is a more cost-effective way to add reserves than is exploration or acquisition.
In his multiclient study, Future Oil & Gas Supply: A Quantitative Analysis, Dr. Sandrea employs a unique, proprietary methodology to provide a holistic assessment of the global oil and natural gas resource base, with the view to evaluate its potential production capacity over the medium and long term. He employs a novel approach that has long informed his exclusive services as an advisor to governments and intergovernmental bodies and as a consultant to major oil companies and the world's leading investment bankers and other financial institutions on matters of risk analysis for international upstream petroleum investments and appraisal of global oil and gas reserves and resources.
The global offshore oil and gas sector's production performance the past two decades has been "remarkable," noted Sandrea, adding that offshore fields now account for about a third of world oil and gas production, expressed in oil-equivalent terms.
But offshore's potential is even greater, he said, given the vast remaining discovered resources.
"Globally, a total of 500 billion barrels [bbl] of offshore oil has been discovered, of which 200 billion bbl has already been produced," Sandrea said. "The ultimate recoverable reserves for the global offshore could be near 850 billion bbl."
Offshore oil production will continue to grow strongly in the medium term and is expected to reach 35 million barrels per day (b/d) by 2015, up from 24 million b/d in 2005, he estimated.
The disparity in discovered vs. produced reserves is even greater for offshore natural gas, Sandrea said: "In regard to offshore natural gas reserves, more has been discovered (580 billion bbl of oil equivalent) than oil, and barely one-sixth has been produced."
Dr. Sandrea estimates in his study that the total volume of discovered, conventional original-oil-in-place (OOIP) resource worldwide is nearly 11 trillion bbl; this number excludes the vast heavy oil and oil sands regions of Venezuela and Canada. Today the average worldwide recovery factor in oil fields is only 22 percent of OOIP.
He contends that an effort to increase that recovery factor by a single percentage point would add more than 100 billion bbl of oil to the world's reserves -- enough to replace almost four years of global oil production. In fact, Sandrea asserted, " ... 70 percent is a tenable level of recovery."
"EOR is indispensable to extract this massive volume of oil left underground -- almost 80 percent -- while extending the economic life of the abundant mature oil fields," Sandrea said in his study. "However, at the present time, barely 3 percent of the world's oil production comes from EOR."
Increasing oil field recovery rates by a single percentage point would yield ten times as much added reserves as new discoveries and extensions, he pointed out.
And the economics favor EOR today, especially at a time when oil prices are at stratospheric levels -- as are oil and gas companies' operating costs. Sandrea estimates that EOR could add reserves at a capital expenditure of $2- 4/bbl, compared with about $4-6/bbl for deepwater development, almost $13/bbl for acquisitions, and more than $14/bbl for overall global finding and development costs.
He estimated that industry would need to spend $200-400 billion to improve the world's average recovery rate by a single percentage point to recover that incremental 100 billion bbl. That compares with industry's current global E&D spending of $260 billion/year.
While deepwater and ultradeepwater exploration and development has garnered headlines with spectacular successes, Sandrea's study pointed to geological evidence that, to date, suggests the deep water is a play with limited prospectivity within a global offshore context.
Given the minimal application of EOR offshore today, that suggests EOR could ultimately make a greater -- and more cost-effective -- contribution to future offshore oil production than the deepwater plays, Sandrea concludes.
The changing notion of "high" oil prices and surging demand from Brazil are triggering a revaluation of oil services companies and raising hopes the industry's five-year upswing will last well into the next decade.
Analysts say offshore valuations had been capped by market belief that oil prices, only last year deemed expensive at $75 per barrel, will eventually fall and end the boom.
But as the view takes hold that oil could for the foreseeable future stay above $100 a barrel -- or even near its current $125 -- more break-neck expansion is being priced in by markets.
"The re-rating of the energy sector is now underway," Morgan Stanley said in a note last month, raising its target multiples for oil service, equipment and contract drilling stocks "to account for multiple expansion across the energy sector".
It said the market's "unwillingness to re-rate energy" -- with the oil services sector trading at a 24 percent discount to the S&P 500 -- was "symptomatic of a lack of belief in sustainability of energy prices and energy earnings".
Morgan Stanley expects oil services and equipment companies to trade at an average of 14.6 times 2010 earnings, up from its previous view of 13.8 times. It expects drillers, on average, at 9.6 times 2010 earnings, up from 9.3 times.
In Norway, which has a large chunk of Europe's offshore oil services market, the sector's eight top companies jointly showed a 15 percent rise in first-quarter operating profit but lagged average forecasts in Reuters polls of analysts by 3 percent.
The results displayed both greater earnings power and the risks of cost inflation and project delays, said analysts.
"The outlook for the sector is extremely good if oil is at $90 or $150 (per barrel), but it's not that easy to find cheap companies," Hans Thrane Nilsen, a fund manager at Norwegian insurer Storebrand, told Reuters. "The boom is set to last for a long time, really until the world starts using less oil."
The biggest Oslo-listed driller, Seadrill, said that surging global demand, including from the oil world's latest darling, Brazil, would easily absorb the 80 deepwater drilling units and 84 jack-up rigs on order around the world.
"It seems market demand is able to absorb the supply increases ... and this has yet to adversely affect the terms and dayrates, in particular for deepwater units," Seadrill said when issuing first-quarter results last week.
Petrobras has said that giant deepwater discoveries made off Brazil may generate demand for up to 40 more new rigs over the next year five years. Analysts say that may boost Norwegian drillers who, unlike more cautious U.S. peers, have built rigs without orders and locked up valuable slots at shipyards.
Merger and acquisition activity, recently rekindled by smaller deals aimed at security rig capacity, may too drive up valuations but eat into development spending and dividends.
"We are likely to see M&A as new rigs are delivered to Norwegian start-ups which would be taken over by the big guys in Houston -- which were late in ordering but have the knowledge, contacts and contracts," Storebrand's Nilsen said.
Soaring rig capacity will enable the development of more fields and boost orders for subsea equipment and pipelines, a boon for companies such as Subsea 7, Acergy and Norwegian engineering powerhouse Aker Solutions.
"Concerns over a dwindling backlog (by Aker Solutions) should dwindle as the cycle gushes on," Handelsbanken said in a note, raising its earnings per share view for Aker Solutions, formerly Aker Kvaerner, by 3 and 5 percent in 2008 and 2009.
The higher growth trajectory predicted by analysts for the oil services sector could tumble if the global economy falters and demand for oil and gas drops.
Norwegian broker Fondsfinans said growing rig capacity would also lead to a "gradual return to mid-cycle profitability" for the sector during the first half of the next decade.
Whiting Petroleum Corp., the oil and natural-gas producer that raised more than $200 million selling Canadian trust units in April, agreed to buy Utah gas properties from Chicago Energy Associates LLC for $365 million, expanding Rocky Mountain output beyond Colorado and Wyoming.
Bloomberg News reports that the purchase includes stakes in 31 producing gas wells and development acreage in the Flat Rock natural-gas field, Denver- based Whiting said April 5. The purchase includes $35 million for 44 miles (70.8 kilometers) of pipelines.
The wells have 19 million cubic feet of production per day and proved reserves in the purchase total 115.2 billion cubic feet, Whiting said. Separately, Whiting announced first-quarter net income rose almost sixfold to $62.3 million, or $1.47 a share, from $10.7 million, or 29 cents, a year earlier, as it sold more oil and gas at higher prices.
Whiting plans additional drilling with goals to increase Flat Rock production 70 percent next year and double it by 2010, Chief Executive Officer James J. Volker said in the statement.
Whiting increased this year's exploration and development budget by $100 million to $740 million to accelerate oil production from its North Ward Estes field in Texas after crude prices rose.
Oil and gas companies want Colorado regulators to limit the proposals they're considering as they update regulations amid record natural gas development in the state.
The Colorado Oil and Gas Association trade group says there's not enough time to adequately study and respond to all the rules proposed by state staffers. The group submitted a request May 1 that some of the rules be considered this spring and summer and others be looked at later.
Hearings are scheduled for June on the comprehensive overhaul of how oil and gas developers do business in Colorado. The goal is to adopt the rules by mid-July.
"It's too much to do in too little time," Ken Wonstolen, an attorney for the trade group, told state officials.
Environmentalists opposed to the request said the regulations need to be updated because of the expanding gas development across the state.
The state Oil and Gas Commission, the main regulatory body, planned to rule on the group's request May 22.
Colorado issued a record 6,368 drilling permits last year, six times the total in 1999. About a third more permits were approved in the first quarter of this year than a year ago and state officials say about 8,000 permits might be issued this year if the pace continues.
"In light of the boom, this rule-making is long overdue," said Mike Chiropolos of Western Resource Advocates, a Boulder-based environmental law and policy group.
The proposed rules would implement two laws passed last year to give more weight to public health, wildlife and the environment when making decisions about oil and gas development.
The industry and its supporters, including some legislators, have warned that the proposed rules could drive up costs and dampen companies' interest in Colorado, where the industry generates billions of dollars in economic benefits and employs thousands of people.
Wonstolen told oil and gas commission members May 1 during a meeting on the rule-making process that a major revision of regulations completed in 1994 took six years.
The Colorado Oil and Gas Association said that considering the 900 pages of proposed changes by July would violate state laws guaranteeing people's rights to be heard and protest.
The association also argues that the proposed rules exceed what the Legislature intended when it approved the laws requiring input from state health, environment and wildlife experts on energy development. Wonstolen suggested first concentrating on the basic requirements, including ways to minimize impacts on wildlife.
"(The association's) proposal ignores part of the legislative mandate for new rules to protect the public welfare and environment," Dave Neslin, acting Oil and Gas Commission director, said after the meeting.
The proposal could indefinitely delay action on such rules as requiring companies to disclose what chemicals these companies use, spills from oil and gas drilling waste pits and reclamation bonds, Neslin said. Thousands more wells could be approved before some of those issues are considered, he added.
"That would limit the commission's choices before the rule-making begins and the evidence is presented," Neslin said.
Climate change legislation pending in Congress could significantly reduce clean-burning natural gas production and send refining production and jobs overseas at a time the nation needs more supplies of all energy sources, according to a report released May 5 by API.
The study, prepared by ICF International and commissioned by API, also estimates that the increased cost of fuel production could result in a shift, as of 2020, of an estimated three million barrels per day of U.S. refining production overseas where foreign refiners would not be required to account for greenhouse gas emissions related to their operations as they would in the U.S. Neither of these impacts identified by ICF is apparent in a Lieberman/Warner analysis conducted by the Energy Information Administration.
ICF looked at the potential supply-side impacts of the Lieberman-Warner cap-and-trade climate bill. It estimated that oil and natural gas companies could be required to spend almost $23 billion for allowances for facility greenhouse gas emissions and another $183 billion for allowances for emissions from consumer use of fuels in the year 2020. For exploration and production, this new cost burden for facility emission allowances alone is estimated to reduce gas well drilling more than 30 percent by 2020, effectively cutting natural gas production volume by as much as 12 percent by 2030.
While the ICF study didn't look at the direct impact of the bill on consumers, the EIA last week said the bill would "increase energy prices and energy bills for consumers" and "increase the cost of using energy, which reduces real economic output, reduces purchasing power, and lowers aggregate demand for goods and services."
The studies underscore the need for Congress to take a balanced approach to energy and climate change policy, API President and CEO Red Cavaney said. Cavaney said the oil and natural gas industry has been addressing the climate change issue through deep investments in alternative energy and emission mitigation technology and through energy efficiency operations in its own operations.
"We all have a role to play on energy and climate -- industry, government and consumers -- and we all need to work together to successfully meet these challenges," Cavaney said. "This particular legislation would be difficult to implement and could lead to less domestic natural gas and fuel production at a time America's consumers will need more, not less, supplies of reliable energy."
ExxonMobil announced May 5 it is committing more than $100 million to complete development and testing of an improved natural gas treating technology that could make carbon capture and storage more affordable and significantly reduce greenhouse gas emissions.
The company plans to build a commercial demonstration plant near LaBarge, Wyo., where it will use ExxonMobil's Controlled Freeze Zone technology, known as CFZ. CFZ is a single-step cryogenic separation process that freezes out and then melts the carbon dioxide and removes other components including hydrogen sulfide, which is found in so-called sour gas. If successful, the process will reduce the cost of carbon dioxide removal from produced natural gas.
"This technology will assist in the development of additional gas resources to meet the world's growing demand for energy and facilitate the application of carbon capture and storage, to reduce greenhouse gas emissions," said Mark Albers, senior vice president of Exxon Mobil Corp.
Using the CFZ process, the carbon dioxide and other components are discharged as a high-pressure liquid stream for injection into underground storage or for use in reservoir management to enhance oil recovery. Besides reducing the cost of separation, transportation and reinjection, the CFZ process can eliminate the use of solvents, sulfur plants and carbon dioxide venting in processing of the natural gas.
The new demonstration plant will advance the CFZ technology to commercial application, and be located at ExxonMobil's Shute Creek Treating Facility. It will process about 14 million cubic feet of gas per day for injection and test a wide range of gas compositions to evaluate the extent of its applicability to the world's undeveloped gas resources.
Construction will commence this summer for operational startup in late 2009. Testing is expected to occur over one to two years. The detailed engineering, procurement, and construction management will be provided by URS Washington Division.
CFZ was developed by ExxonMobil Upstream Research Company and has undergone significant improvements since the 1980s, when, in an industry first, it proved the concept of freezing carbon dioxide in natural gas separation with a CFZ pilot plant.
ExxonMobil has more than 50 years of large-scale sour gas production experience, which includes design and operation of the two largest carbon dioxide and hydrogen sulfide injection projects in the world. The company has developed industry-leading expertise in managing safety, reliability and technical challenges associated with highly sour oil and gas developments.
UOP LLC on May 2 announced a price increase of 15 percent for all solid phosphoric acid (SPA) catalysts used in the refining and petrochemical industries. The price adjustments are effective immediately or as contracts allow.
UOP is increasing the prices of SPA catalysts because of the continued high cost of energy and rising raw material prices. The products affected include UOP SPA-1 catalyst, UOP SPA-2 catalyst, UOP SPA-1C catalyst, UOP HO B1 catalyst, and UOP HO B2 catalyst.
UOP initially developed SPA catalysts in the early 1930s. They are used in the production of polymer gasoline, a gasoline blending component and higher olefins for the production of lube oil additives, surfactants, agricultural chemicals and coatings as well as cumene, a key intermediary in the production of phenol and acetone.
Williams announced May 6 that its Transco pipeline would be holding a binding open season from May 6 to June 2 to obtain shipper commitments for an expansion designed to connect domestic natural gas supplies originating from the Rockies, Appalachia, and the emerging Marcellus shale supply regions to growing markets on the East Coast.
Williams held non-binding open seasons in late 2007 for its proposed Rockies Connector Pipeline and Transco's Northeast Connector Project. After discussions with potential shippers, Williams now has combined the two projects and plans to construct and operate them as an expansion of its existing Transco pipeline system. The combined projects will be known as the Northeast Supply Project.
"We received a very positive response from the market during our initial open seasons for both the Rockies Connector and Northeast Connector components," said Phil Wright, president of Williams' natural gas pipeline business. "As a result of discussions with potential shippers we are now pursuing these projects jointly as a single, Transco-owned and operated project, providing a continuous path for growing domestic supply sources to serve demand on the east coast."
The proposed Northeast Supply Project includes a 250-mile extension of the Transco system that would connect the Rockies Express Pipeline near Clarington, Ohio to Transco's mainline in southeastern Pennsylvania. The project also provides for an expansion of Transco's existing system, giving shippers a seamless path from Clarington to delivery points in Transco's Zone 6. Included in the expansion is a proposed new lateral from Transco's existing pipeline in northern New Jersey to a new delivery point in lower Manhattan. The new delivery point would tie-in with Consolidated Edison Company of New York, significantly increasing natural gas delivery capability to New York City. Firm transportation service is anticipated to be available as early as November 2011.
The proposed expansion will be subject to approval by the Federal Energy Regulatory Commission and other agencies.
Golden Triangle Storage, Inc., a wholly owned subsidiary of AGL Resources, on Wednesday broke ground on its underground natural gas storage project located on the Spindletop salt dome on the southern edge of Beaumont in Jefferson County, Texas.
Dana Grams, president of Pivotal Energy Development, the division of AGL Resources overseeing the Golden Triangle Storage project said "The project will add much-needed storage, enhance the region's growing energy infrastructure and provide local economic benefits."
Golden Triangle Storage will store natural gas in two caverns hollowed out of the Spindletop salt dome, approximately a half-mile to a mile below ground. It also will include an approximately nine-mile pipeline that will link the storage facility with nearby transmission pipelines to access natural gas supplies and deliver stored gas to market.
The Golden Triangle Storage project will increase storage capacity in Jefferson County, and is expected to enhance the area's position as a national energy hub and increase the functionality of both its existing and planned energy infrastructure. The project will give customers high-deliverability storage at a liquid market point; easy access to multiple supply sources, including liquefied natural gas imports; and potential interconnections to six existing and planned pipelines serving diverse markets with counter-seasonal demand.
The company plans to initially offer up to 12 billion cubic feet (Bcf) of working gas capacity in two caverns. By adding caverns, the project could continue growing to a maximum of 28 Bcf in capacity in future years.
Initial commercial operations are slated to begin in late 2010 to early 2011, with a second cavern expected to come online in 2012.
MoBay Storage Hub, an affiliate of Falcon Gas Storage Co., Inc., on May 5 announced that all 10 Bcf of the Phase I firm storage service offered during its recently concluded open season has been awarded.
The MoBay open season attracted 12 bidders in an interactive online auction held on May 1 for three-cycle, two-cycle and single-cycle/seasonal storage service. Bidders included both new and existing customers. The total volume bid was over 40 Bcf. MoBay expects to execute binding precedent agreements with the winning bidders by May 15, 2008.
Phase I of the MoBay project, scheduled for completion in October 2009, will provide 50 Bcf of high-deliverability, multi-cycle (HDMC) gas storage capacity with 1.0 Bcfd of withdrawal and injection capacity. Binding precedent agreements already had been executed with nine shippers for 29.4 Bcf of MoBay's Phase I working gas capacity prior to the open season.
"We're very pleased with the number and quality of companies that applied to participate in the MoBay open season bidding process, and also with the online auction process itself," said Edmund Knolle, MoBay's chief operating officer. "Interest has been strong across the board from large producers, marketers, natural gas pipelines, and utilities in both the Northeast and Southeast. The results of the open season reaffirm our view that the MoBay Storage Hub will fundamentally alter the Eastern Gulf Coast region's natural gas dynamics. MoBay is uniquely positioned next to multiple interstate pipelines, well east of major pipeline bottlenecks."
Located in south Alabama at the nexus of the Southeast natural gas pipeline system, the MoBay Storage Hub will provide direct access into over 6 Bcfd of pipeline capacity serving the Florida market, as well as the Northeast and Atlantic states.
MoBay's open season auction was facilitated by XG2, Inc., based in Austin, Texas.
Falcon's NorTex Gas Storage Company subsidiary owns and operates 35 Bcf of gas storage capacity with nearly 1.0 Bcfd of aggregate deliverability from Hill-Lake and Worsham-Steed. Through its MoBay Storage Hub LLC affiliate, Falcon is developing a 50 Bcf HDMC gas storage project in southern Alabama with 1.0 Bcfd of injection and withdrawal capacity. In addition, Falcon is developing a 20 Bcf HDMC gas storage project in the Desert Southwest that will be located near the San Juan Blanco Hub. Falcon subsidiaries also are involved in crude oil production, including enhanced oil recovery; natural gas transportation, processing and NGLs production; and natural gas, crude oil and NGLs marketing and trading.
U.S. government and offshore oil industry officials on May 15 declared their readiness for the 2008 hurricane season, including a new effort to strengthen "high-consequence" structures in the U.S. Gulf of Mexico.
Not only has the scientific knowledge improved about hurricane behavior in the Gulf, oil companies now are following new regulations designed to keep offshore facilities in place during even the biggest storms. Government and industry groups also have beefed up hurricane response measures, the officials said.
"We are much better prepared than we were three years ago," said Walter Cruickshank, deputy director of the U.S. Minerals Management Service, recalling the widespread destruction by Hurricanes Katrina and Rita in 2005.
Cruickshank was joined at a news briefing by officials of the U.S. Coast Guard and American Petroleum Institute to call attention to the June 1 start of official hurricane season, which ends Nov. 30.
Gulf infrastructure was still hurting from 2004's Hurricane Ivan when Katrina and Rita destroyed more than 100 platforms and shut in 92 percent of oil and 83 percent of natural gas output.
The U.S. Gulf accounts for 25 percent of U.S. domestic oil output and 15 percent of gas production, so it is important to minimize disruptions from hurricane winds that can exceed 150 mph and waves that can reach 90 feet, officials said.
The MMS has identified 65 offshore structures that are considered "high-consequence" because of their location, function or proximity to other important infrastructure and to require companies to assess and strengthen them if needed.
MMS Gulf Region Director Lars Herbst said new engineering standards, based on a new estimate of worst possible storm conditions, is being applied to platforms, especially those in the Central Gulf and deeper waters.
The government office has asked companies operating the facilities to submit assessment reports by June 1, said Herbst. Then, it will determine what steps, if any, are needed to ensure the safety of the platforms, he said.
MMS has added a Coast Guard official to its "continuation of operations" committee to improve coordination. MMS also has bolstered its readiness to temporarily shift offices from New Orleans to Houston if necessary, officials said.
In addition, MMS officials said they have incorporated most of the guidelines into regulations enforceable as law by the agency.
Those standards include increased mooring lines for floating drilling rigs, many of which came loose in 2005 and floated freely, often damaging seabed pipelines with dragging anchors.
Also, the decks of most fixed platforms near the coastline have been raised to withstand higher waves, and standards are tighter for securing equipment. The minimum distance between platform decks and the water has been increased from 50 to 70 feet.
Plans are in place to shift flows of oil and gas in the event of damage to undersea pipelines, officials said. Oil can be moved ashore in barges and gas can be rerouted to other pipelines, they said.
Other measures already have been taken and continue to be implemented to toughen offshore oil infrastructure, including stronger mooring of floating structures and better tie-down of equipment on platform decks to withstand hurricane winds. There are more than 4,000 manned platforms, scores of drilling rigs and hundreds of miles of pipelines on the seafloor.
Since 2005, the industry, through its main trade group, the American Petroleum Institute, has introduced several sets of guidelines for offshore producers and drillers, meant to better protect some infrastructure during hurricanes.
Officials acknowledged, however, that more could be done. For instance, floating rigs that could come loose aren't required to be outfitted with tracking devices that would allow the Coast Guard or other mariners to keep up with where they are.
"We don't require that, but we want it," said Rear Adm. Joel Whitehead, the Coast Guard's District 8 commander in New Orleans.
The government office has asked companies operating the facilities to submit assessment reports by June 1, said Lars Herbst, regional director of the office's Gulf of Mexico region. Then, it will determine what steps, if any, are needed to ensure the safety of the platforms, he said.
The hurricane season runs from June 1 to Nov. 30.
After relatively quiet seasons in 2006 and 2007, forecasters say the 2008 season should produce a higher-than-normal number of storms.
The U.S. Environmental Protection Agency (EPA) is seeking comments on the state of Texas's petition to reduce the volume of renewable fuel required to be used in motor vehicles and other engines.
In an April 25, 2008, letter to EPA, Governor Rick Perry asked EPA to halve the nationwide renewable fuels standard (RFS) mandate for the production of ethanol derived from grain, citing adverse economic impact due to higher corn prices in Texas. EPA is publishing a Federal Register notice opening a 30-day comment period on the request. The RFS mandate for 2008 is the equivalent of 9 billion gallons.
The Energy Policy Act of 2005 established the RFS program, and volume levels were increased in the Energy Independence and Security Act, which was signed into law in December 2007. The 2005 energy law also included provisions enabling the EPA Administrator to grant a full or partial waiver if implementation of the RFS would severely harm the economy or environment of a state, region, or the entire country, or if EPA determines that there is inadequate domestic supply of renewable fuel. In consultation with the Departments of Agriculture and Energy, EPA must decide on a waiver request within 90 days of receiving it.
Diesel fuel gets priority as petroleum refiners prepare to process more heavy oil.
U.S. petroleum companies are investing in new domestic refining capacity on a scale not seen in decades. Over the next five years the industry will add more than one million bbl/d of distillation capacity, according to the U.S. Department of Energy’s Energy Information Administration (EIA, Washington D.C).
"It’s a step change in expansion," says Rick Boyd, business development executive with Celerant Consulting (Lexington, MA). The main driver, he says, is fuel prices, which have not only enriched petroleum companies, but have improved the social climate for the industry. "Back in the 1990s it was difficult to get permits to expand and the public didn’t realize there were supply pressures. But now, with gasoline selling for $3 – 4 a gallon, people are more aware of the petroleum industry and regulators are more inclined to allow expansions."
Current U.S. refining capacity is approximately 17.6 million bbl/d which is insufficient to meet the demand for fuels. For example, imports of gasoline blending components and finished motor gasoline have been averaging about 30 million bbl/mo in recent months.
As it happens, gasoline is not a major issue, says Joanne Shore, a senior analyst with EIA’s Petroleum Division. She notes that gasoline is available at relatively low prices from Europe, which has a gasoline surplus as Europeans continue to switch to diesel-powered vehicles. Also, U.S. demand for gasoline is expected to decline over the next 15 years because of government regulations that require higher fuel efficiency for light-duty vehicles and higher use of biofuels. At the same time, the demand for distillate will continue to grow, says Shore, "and this will be a challenge for refiners."
The expansion plans of the U.S. petroleum refining industry show the growing popularity of hydrocracking.
U.S. CAPACITY EXPANSION PLANS (Numbers are in barrels per day)
Creep and shutdowns
Energy Information Administration
The biggest change facing refiners for the next few years will be an increasing use of heavy oils, particularly from Alberta oil sands. Consequently, much of the new capacity is being designed to upgrade heavy oil for the production of gasoline, diesel fuel and other fuels. Also, the growing demand for distillate is reflected in the amount of hydrocracking capacity that is being added, compared to the relatively modest capacity of fluid catalytic cracking (FCC) capacity for gasoline production (see table).
Other issues are: a new federal regulation that calls for the ethanol content of gasoline to be increased; the integration of biofuels into the refinery feed mix, and a federal rule that calls for the benzene content of gasoline to be reduced to 0.6% by January 2011. Looming in the background is a law that would limit carbon dioxide emissions, still under discussion in Congress.
Bitumen, the product of oil sands, typically has a specific gravity of less than 10 API and has a high content of sulfur, metals and total acid number (TAN). Coking followed by hydrotreating is the common way to upgrade heavy oil. These processes may be done in the field or at a refinery.
If upgrading is done in the field, the product is a synthetic crude (syncrude) of 25 – 30 API that can be shipped via pipelines. Otherwise, bitumen is treated in one of two ways to make it suitable for pipeline transmission. One is to dilute it with light syncrude to make "synbit" and the other is to mix it with a diluent (light ends) to make "dilbit." The dilbit method requires two parallel pipelines: one to ship the product and the other to recycle the diluent after the customer has separated it from the bitumen.
A new heavy-oil upgrading process that is said to achieve up to 100% conversion of the heaviest feedstock, thus avoiding the need for coking, has been developed by Chevron Corp.’s Technology Center (Richmond, CA). "We can put in heavy oil, of less than 10 API gravity, and produce a blend that is mostly gasoline, jet and diesel fuels," says James Murphy, business manager for the technology. In contrast, he says, conventional refining technology achieves less than 80% conversion.
Called Vacuum Resid Slurry Hydrocracking (VRSH), the process has been extensively piloted and will be tested in a pre-commercial plant at Chevron’s refinery in Pascagoula, Mississippi. Construction of the 3,500-bbl/d plant is scheduled to start later this year.
Heavy oil or vacuum resid is slurried with a proprietary catalyst, mixed with hydrogen and circulated through several reactors at temperatures ranging from 775 to 850°F and pressures of 2,000 – 3,000 psig. A small amount of catalyst is removed continuously through a slipstream and subsequently reactivated and returned to the process. Murphy adds that the cost of VRSH is expected to be similar to that of Lummus Technology’s LC-Fining hydrocracking process for heavy oil and residue, which is licensed by Chevron Lummus Global, a partnership.
A process for upgrading heavy oil that had not been actively marketed in the past because of low crude and product prices has been revived by UOP LLC (Des Plaines, IL), which has bought the rights from Natural Resources Canada (Ottawa). UOP has improved the process and is offering it for license. "At today’s crude and product prices the economics are attractive," says Dan Gillis, business manager for heavy oil.
In the slurry hydrocracking process, a base metal catalyst is mixed with heavy oil or vacuum resid and the slurry is fed into the bottom of an upflow reactor. Hydrogen is added in the reactor and more than 90% of the feed is converted to distillate and naphtha, which exit the top of the vessel. The reactions take place at 1,800 – 2,000 psig and 800 – 880°F.
A hydrotreating process whose applications include mild hydrocracking of FCC feed, treating of ultra-low-sulfur diesel fuel and severe gas oil hydrotreating is offered by DuPont Stratco Clean Fuel Technologies (Leawood, KS). An advantage of the IsoTherming process is that H2 is dissolved in the liquid feed before the liquid enters the reactor, thereby avoiding a high volume of H2 in the vapor phase. IsoTherming uses standard catalysts and operates under standard hydrotreating conditions, but is said to be less expensive than conventional hydroprocessing. Valero plans to install an IsoTherming unit in its Paulsboro, N.J., refinery, where it will further the company’s goal of producing more distillate for ultra-low-sulfur-diesel fuel.
The rapid growth in heavy-oil processing is providing a bonanza for hydrogen suppliers. As an illustration, Air Products (Lehigh Valley, PA) is now starting up its third hydrogen plant in Canada. Located near Edmonton, Alta., the 105-million-scfd plant is interconnected with a 71-million-scfd plant that started up in 2006. The two plants will serve Petro-Canada’s Edmonton refinery, plus several additional customers. Air Products’ third plant, of 80 million scfd, started up in Sarnia, Ont., in 2006 and supplies two nearby refineries. All use natural gas-based steam-methane reforming.
Stephen Losby, general manager for Air Products in Canada, estimates that about 1 billion scfd of hydrogen is now being produced in Alberta for petroleum processing and expects the demand will grow to 2.5 – 3 billion scfd when syncrude production reaches 3 – 4 million bbl/d. At the same time, he estimates that the U.S. will install up to 1.0 billion scfd of additional hydrogen capacity.
The prospect of having to use a lot more hydrogen has prompted a search for a less-expensive source than steam methane reforming (SMR) of natural gas. Since many refineries have or are installing cokers, one possibility is coke gasification.
The capital cost of a coke-gasification plant is about 2.7 times that of an SMR plant, says Dale Simbeck, vice-president of the consulting firm SFA Pacific, Inc. (Mountain View, CA). However, with coke priced at $1/million Btu versus $6.60/million Btu for natural gas, plants using either process would have the same hydrogen cost, assuming a five-year payback on the investment. At higher natural gas prices, or after the payback of the investment, coke gasification can have a cost advantage, he says.
Simbeck adds that the economics of coke gasification require large scale and spare capacity to assure a steady supply of hydrogen. The economics can also be improved by polygeneration. For example, an installation might consist of three gasifiers, with two producing hydrogen and a standby unit that is used for cogeneration when it is not needed for hydrogen production.
Gasification also offers flexibility in terms of feed and products. Shell Global Solutions (US) Inc. (Houston), for instance, offers two variations of gasification technology — one for solid feeds such as petroleum coke, coal and biomass, and the other for liquids such as oil distillates and refinery residues. The processes have been installed in several refineries and make a variety of products, including hydrogen, syngas for fuel, ammonia, methanol and oxo-chemicals.
A pressure-swing-adsorption (PSA) process for recovering hydrogen from process streams that is said to provide a mass-transfer rate up to 100 times higher than that of conventional PSA is being marketed jointly by ExxonMobil Research and Engineering Co. (Fairfax, VA) and QuestAir Technologies Inc. (Burnaby, B.C., Canada). Called Rapid Cycle PSA, the process employs structured adsorbent rather than beads and uses two rotary valves to switch gases between adsorbent beds, at up to100 cycles/min. The installed cost is said to be 30 – 50% lower than that of conventional PSA. A demonstration unit that was installed at an ExxonMobil affiliate refinery in France went into commercial operation in March.
A controversial issue in the U.S. refining industry is the Energy Independence and Security Act of 2007, which mandates that 9 billion gal of renewable fuels (mostly ethanol) be blended into the transportation fuel supply this year, increasing to 36 billion gal in 2022. In a statement before the Senate Energy and Natural Resources Committee in February, Charles Drevna, president of the National Petrochemical & Refiners Association (NPRA, Washington, DC) protested that it was doubtful enough ethanol would be available to meet the near-term requirement.
Drevna also pointed out that most vehicles cannot use fuel blends greater than E-10 (10% ethanol, 90% gasoline) because ethanol is corrosive, but such blends may be needed to meet the mandate by 2010. The only vehicles able to use these blends are E-85 vehicles, he said, but these represent only 6 million out of more than 240 million registered vehicles.
As an alternative to ethanol, which is simply blended with gasoline, some organizations are developing processes that produce fuels compatible with petroleum-derived products. The goal is to integrate bioprocesses into a conventional refinery, says Jennifer Holmgren, UOP’s director of renewable energy and chemicals.
UOP and Eni S.p.A. (Milan, Italy) have jointly developed a process in which vegetable oils and animal fats are converted to a "green" diesel that can be blended with petroleum-derived diesel fuel. The UOP/Eni Ecofining process will be commercialized in 2009 – 2010 in refineries in Italy and Portugal. In each case the Ecofining plant will contribute 100 million gal/yr to the diesel fuel pool, says Holmgren.
Within the next two years UOP expects to commercialize a process that will convert cellulosic waste to gasoline, diesel and jet fuels. The company’s partners in the development are the National Renewable Energy Laboratory (NREL, Golden, CO) and the Pacific Northwest National Laboratory (Richland, WA). The partners have piloted the process, in which waste is subjected to fast pyrolysis to obtain pyrolysis oil, which is then upgraded to transportation fuels via UOP hydroprocessing technology
A drawback of bio-oil is that it contains 10 – 40% oxygen, versus essentially none for petroleum, as well as a high percentage of water. Holmgren says that UOP has developed ways to take out both the oxygen and water, but declines to give details except to say the oxygen is removed by hydroprocessing, followed by a second hydroprocessing step to obtain fuel.
Refiners are preparing to meet a new regulation from the U.S. Environmental Protection Agency (EPA; Washington D.C) that calls for the benzene content of all gasoline to be reduced to an average of 0.62 vol% by Jan. 1, 2011. At present the limit is 1% for reformulated gasoline only. In addition, refiners will have to meet a maximum average benzene standard of 1.3 vol%, effective July 1, 2012.
Reformate from catalytic reforming accounts for about 50 – 75% of the benzene in the gasoline pool, so a popular way to reduce the benzene content is to fractionate the naphtha feed to the reformer and remove benzene precursors (C6 paraffins, cyclohexane and methylcyclopentane). However, this method is not expected to be sufficient for the new standards.
A new process called BenZap that is said to reduce the benzene content of reformate by more than 99% has been developed by GTC Technology (Houston). BenZap is situated downstream of the reformer and employs hydrogenation in combination with a platinum catalyst to convert benzene to cyclohexane and other more acceptable compounds.
ExxonMobil Research and Engineering Co. (EMRE) offers Benzout, a reformate alkylation process in which benzene-rich streams are reacted with light olefins such as ethylene or propylene. Benzout converts benzene to high-octane alkylate, with a 2 – 5 gain in octane numbers, thus avoiding the octane loss and H2 consumption of conventional processes, according to EMRE.
A pervaporation membrane that selectively removes benzene (or other aromatics) from aliphatic compounds has been developed by PolyAn GmbH (Berlin). The membrane has been tested in combination with extractive distillation to obtain pure benzene. PolyAn is working with Borsig Membrane Technology GmbH (Gladbeck, Germany) to scale up the process.
Other companies that offer benzene-reduction technology include Axens North America Inc., (Houston), CDTech, (Houston), and UOP.
Brazilian state-run energy giant Petroleo Brasileiro (PBR), Petrobras, confirmed May 26 an oil and gas find in the Gulf of Mexico.
According to Petrobras, the Stones-3 exploration well confirmed the presence of oil and natural gas in the WR 508 block, about 200 miles off the coast of Louisiana. Petrobras holds a 25% stake in the exploration block.
Italian oil and natural gas company Eni SpA (E) had announced the find also on May 26. Eni holds a 15% stake in the block.
"This result confirms the potential of significant oil reserves in this type of reservoir in the Gulf of Mexico, where Petrobras operates the Cascade and Chinook fields," Petrobras said in a regulatory filing.
The discovery was made at a water depth of 2,286 meters and a total depth of 8,960 meters under the seabed. Oil was found in multiple reservoirs, Petrobras said.
The Stones-3 well is part of the Stones discovery. Royal Dutch Shell PLC ( RDSA) is the main operator in the block with a 35% stake. Petrobras' U.S. unit, Petrobras America, holds the company's 25% stake, while Marathon Oil (MRO) has a 25% share and Eni has a 15% slice.
URS Corp. said that it has been awarded a contract by ExxonMobil to provide detailed engineering, procurement and construction management services for a commercial demonstration plant that will use ExxonMobil's Controlled Freeze Zone (CFZ) technology. CFZ seeks to expand the use of carbon capture and storage by reducing the cost of removing carbon dioxide from natural gas.
Developed by ExxonMobil Upstream Research Company, the CFZ process accomplishes low-cost, energy-efficient separation of high-purity methane from CO2 and H2S in a single step. Process and mechanical features establish a controlled freezing environment that overcomes the typical solidification barrier for methane-CO2 separation by distillation. The technology is a significant advancement for removing CO2 and other contaminants from highly sour gas resources around the world and facilitates their reinjection either for geosequestration or enhanced recovery purposes.
Construction on the treatment facility, which will be located at ExxonMobil's Shute Creek Treating Facility near LaBarge, Wyoming, will commence this summer, and operational startup is expected in late 2009.
Mustang Engineering, part of international energy services company John Wood Group PLC, announced that its pipeline business unit is providing engineering, survey and map drafting services to Florida Gas Transmission Company, LLC, a Delaware limited liability company, for its Phase 8 Expansion Project.
Mustang's portion of the project involves approximately 300 miles of 42-inch and 36-inch natural gas pipeline in Mississippi, Alabama and the Florida Panhandle. Phase 8 is part of Florida Gas Transmission's approximate 5,000-mile natural gas pipeline bringing gas into Florida from Texas, Louisiana, Mississippi and Alabama.
Weitz & Luxenberg P.C. has secured a landmark MTBE settlement against some of the country's biggest oil companies, which have agreed to pay $423 million in a suit involving the contamination of 153 public water systems nationally.
Of the settlement, Robert Gordon of Weitz & Luxenberg said, “This is an excellent settlement on behalf of our clients. The oil companies knew that MTBE would contaminate drinking water when they used it. The defendants who have settled have lived up to their responsibility by not only paying cash but by offering treatment of future contaminated wells for the next 30 years.”
The MTBE litigation, brought by Weitz & Luxenberg and Baron & Budd, addressed the gasoline additive methyl tertiary butyl ether, or MTBE. The chemical is now banned in many states because it can affect the taste and odor of drinking water at extremely low levels.
The lawsuit claimed that MTBE was a defective product that led to massive contamination and that the chemical was used by the defendant companies despite those entities being aware that it posed environmental and potential health risks. The Environmental Protection Agency has found that MTBE caused cancer in lab rats exposed to high doses.
Filed with U.S. District Judge Shira Scheindlin in New York, the settlement involves about a dozen oil companies, including ConocoPhillips, Shell, BP, Chevron and Marathon. The original lawsuit, brought in 2003 by public water providers in 17 states, was subsequently consolidated into one federal case. As part of the agreement, the defendants will be required to fund a 30-year clean-up program for contaminated wells and surrounding areas.
Six oil corporations and refineries did not settle, including Exxon Mobil Corp and five smaller companies including chemical maker Lyondell Petrochemical Corp.
“We look forward to trying the case against Exxon Mobil,” said Gordon. “It is not right that the most profitable corporation in the history of the world can contaminate our drinking water knowingly, and then expect the taxpayers to clean up their mess.”
Cabot Aerogel, a business of Cabot Corporation, recently announced its patented and patent-pending Nanogel aerogel Compression Pack product has been selected to insulate a 60 km subsea pipeline in the deepwater Gulf of Mexico. Energy Resource Technology (ERT), a wholly owned subsidiary of Helix Energy Solutions Group, is the operator of the pipeline located in Danny field development, Garden Banks block 506.
The 8 inch-in-12 inch pipe-in-pipe tieback will be the longest aerogel- insulated pipeline ever constructed and the first time that aerogel has been used in an S-lay application. It will also be the first pipe-in-pipe system to be installed by Helix's new state-of-the-art 480-foot long DP S-lay pipeline installation vessel, Caesar, that is under construction.
The Caesar can lay pipe from 6-inch to 42-inch OD and with its 400-ton tension capacity, the vessel can install pipe in water depths in excess of 6,500 feet, and install large diameter trunk lines in shallow water.
The ultra-low conductivity of Nanogel aerogel is a key enabler of ERT's pipe-in-pipe system design, which has a low U-value of 0.15 BTU/hr.ft2 degrees Fahrenheit (0.85 W/m2 K) while maintaining a 12-inch outer jacket pipe. Additionally, the rugged design of the Nanogel Compression Pack packaging system makes it well-suited for pipe-in-pipe applications where weld slag, scale, and other factors can pose significant challenges or create delays for systems using less durable products.
The Nanogel Compression Packs that will insulate the ERT Danny pipe-in-pipe system consist of packs of compressed Nanogel aerogel with an integrated protective outer layer of high-density polyethylene. These packs are applied to 40-foot sections of inner pipe and expanded to their precise final forms prior to insertion of the insulated inner pipe into an outer pipe. The completed pipe units will then be transported offshore where they will be welded together aboard the Caesar.
"We are delighted to be working with Cabot on ERT's first aerogel project and consider this technology to be a critical component in achieving the performance that is required in today's deepwater environment. The mechanical strength of Nanogel combined with the durable form of Cabot's Compression Pack system provide added benefits during pipeline fabrication and installation, "says Majid Al-Sharif, ERT subsea manager for the Danny field development project.
Sometimes called "frozen smoke", aerogel is the lightest and best insulating solid in the world. Nanogel, Cabot's branded aerogel, is a hydrophobic aerogel produced as particles. Each particle consists largely of air (~95%) contained in nano-sized pores that severely inhibit heat transfer through the material. Nanogel particles can be contained in various ways to facilitate incorporation into a wide range of systems including pipe-in-pipe systems, LNG & cryogenic gas transportation and storage systems, insulative coatings, daylighting panels, sporting equipment, clothing, and others. Cabot produces Nanogel in a state-of-the-art manufacturing facility located near Frankfurt, Germany where it began commercial production in 2003.
Gulf Onshore, Inc. has announced they have closed on several oil and gas leases in Throckmorton and Shackleford Counties, Texas which total 3,200 acres and have 80 existing well bores. The leases have multiple existing producing wells. The Company paid 10,000,000 shares of its Common stock, par value .001, as consideration for the leases. The engineering report shows proved developed producing (PDP) and proved developed non producing (PDNP) reserves of 454,194 Bbls of oil and 8.98 MMcfg of gas.
As part of the acquisition of the Throckmorton and Shackleford County leases Gulf also acquired the Operator Curado Energy Resources, Inc. Curado is a registered Operator with the Railroad Commission of Texas. Gulf paid $250,000.00 in the form of a one year note for 100% of the outstanding stock of Curado.
The Department of Environmental Protection has ordered two natural gas drilling companies to suspend a portion of their operations at separate sites in Lycoming County for violating Pennsylvania’s Clean Streams Law.
Appalachia LLC and Chief Oil and Gas LLC operate impoundment areas in Cogan House Township and Mifflin Township, respectively; that collect water for use in the companies’ exploratory drilling operations in the Marcellus Shale.
The impoundments draw tens of thousands of gallons of water per day from nearby waterways. Such large volume diversions could impair the existing uses of the waterways.
The Clean Streams Law empowers DEP to protect the quality of Pennsylvania’s waterways and the volume of water therein.
“Drilling for natural gas is a water intensive endeavor,” said DEP Northcentral Regional Office Director Robert Yowell.
“That’s even more so in the case of the Marcellus Shale, where this type of drilling can often times consume millions of gallons of water. In the course of their operations, neither Range Resources nor Chief Oil and Gas have taken the necessary precautions to protect nearby streams from pollution or impairment during the drilling process.
“We need to ensure that bodies of water involved near Hoagland Run and First Fork Larry’s Creek—both high quality tributaries—and Mud Run and Big Sandy Run are protected for the residents of Lycoming County and the entire Susquehanna watershed.”
DEP’s action coincides with an enforcement action taken by the Susquehanna River Basin Commission under its own regulatory authority.
Range Resources and Chief Oil and Gas failed to obtain the required approval from the SRBC for the ongoing water withdrawal. Permits are required for this type of activity because of the potential to impair or destroy the basin’s water resources and cause pollution.
“These orders will remain in effect until the department has received and approved a water management plan from both companies, and each firm has obtained the necessary permits,” said Yowell.
The water management plan will help ensure that drilling operations do not have an adverse effect on the nearby streams or water resources.
Current regulations for natural gas exploring and drilling in Pennsylvania call for operators to obtain proper permits to construct and develop oil and gas wells and prevent the pollution or destruction of the state’s water resources.
As the natural gas industry responds to increased energy market demands, Pennsylvania has become a hot-bed for gas exploration and development, particularly in the Marcellus Shale geologic formation. The department has received and reviewed a record-setting number of applications for gas wells permits over the past four years.
“All companies, in-state or out-of-state, planning natural gas drilling activities on Pennsylvania’s soil must abide by the commonwealth’s environmental rules and regulations that protect and safeguard the state’s natural resources,” said Yowell. “With increased interest and activity in oil and gas drilling throughout the state, Pennsylvania will experience a boost to its local economies, but we want to make sure that our environment and natural resources are not sacrificed in the process.”
DEP and other state agencies and commissions will begin conducting site inspections at all permitted natural gas exploration and drilling sites. During inspections, DEP field personnel will be on-hand to review procedures and regulations with operators and land-owners.
In June, DEP and its partners including the Department of Conservation and Natural Resources, the Pennsylvania Fish and Boat Commission, SRBC, the Delaware River Basin Commission and the County Conservation Districts will host current and prospective natural gas exploration operators and owners to discuss Pennsylvania’s oil and gas industry, the industry’s future, and the state’s environmental rules and regulations.
TransCanada Corp., which has an application for a state license pending before the Alaska legislature, is confident of its ability to deliver the long-desired mega project shipping North Slope natural gas to U.S. markets, its chairman said May 29.
"Clearly there's a market demand for this project. It is the most significant source of natural gas that can be brought to market. And I would argue that TransCanada is the company to make this project happen," company chief executive Hal Kvisle said in a news conference with Gov. Sarah Palin.
Palin has recommended that the legislature approve a project license for the TransCanada for the line, which would run nearly 2,000 miles from Prudhoe Bay to the Alberta-British Columbia border. The line would ship the North Slope's vast natural gas supplies -- 35 trillion cubic feet of known reserves, and potentially much more yet to be confirmed -- to consumers in the lower 48 states.
Lawmakers were to convene in a special session in Juneau the first week of June to start deliberations on the TransCanada application. May 29 was the second of three days of public meetings in Anchorage detailing the application and the state's evaluation of the project.
TransCanada is well-qualified for the project, Palin said at the news conference
"This is not some newfangled oddity, never-been-done-before in their portfolio," the governor said.
Kvisle said he is unfazed by a new $31 billion cost estimate unveiled by the state's consultants. TransCanada's $26 billion estimate still stands, he said, adding that both estimates encompass a wide range of probability, appropriate for such an early point in the planning. "We're comfortable with our cost estimate at this point in time," he said.
He is also confident that TransCanada will be able to strike a deal with the three major North Slope oil producers -- BP, ConocoPhillips and Exxon Mobil -- that would result in them shipping the natural gas they have under lease through the new pipeline.
"I am pretty comfortable that we're going to come up with something they find attractive," he said.
He argued that TransCanada produces none of the gas it ships through its 36,500 miles of pipeline throughout North America, and has no problem keeping those lines full and operating. "We didn't become the largest mover of natural gas in North America without having good relations with our customers," he said.
The three producers have argued that they should control any North Slope natural gas line because they are the companies that would bear the financial risk of shipping project.
ConocoPhillips and BP are promoting their own pipeline project, an alternate to TransCanada's; that would follow the same general route and serve the same market but be producer-owned. That proposal needs no state sanction and is not scheduled to be formally considered by the legislature.
TransCanada, meanwhile, has several multibillion-dollar projects scheduled to be built before any construction starts on the Alaska project. Those include the Keystone crude oil pipeline system, the huge Mackenzie Valley natural gas pipeline in the Northwest Territories and various expansions of existing lines.
There is "no better way to get ready to build the Alaska pipeline than to build a lot of other pipelines along the way," Kvisle said.
"We're very careful about not taking on more than we can handle, because the consequences for TransCanada (in) not being able to execute this project would be very severe," he said.
The long-term success of an Alaska natural gas pipeline depends on future discoveries of natural gas beyond the proven 35 trillion cubic feet of reserves, most of that in Prudhoe Bay.
Kvisle said he has faith that the promise of a natural gas pipeline will inspire companies to explore for and develop more natural gas. "We have no doubts or worries about the future amount of gas available on the North Slope," he said.
Federal oil and gas leases could be sold on top of western Colorado's Roan Plateau even as members of the state's congressional delegation try to restrict the amount of land that can be developed, and when.
The Colorado Bureau of Land Management office planned to announce by June 13 which federal properties in the state will be offered for lease in the Aug. 14 auction.
"Whether or not Roan Plateau parcels will be on there is still open question," BLM spokesman Steven Hall said Monday.
An effort by Sen. Ken Salazar and Reps. Mark Udall and John Salazar to modify the BLM's plan for the Roan Plateau won't stop the agency from offering the leases if it decides to, Hall said.
The BLM approved a final management plan in March that projects drilling 1,570 wells from 193 sites, or well pads, on the public land on the plateau over 20 years.
That includes 210 wells from 13 pads on top.
A bill by the three Colorado Democrats is similar to a plan by Gov. Bill Ritter that the BLM rejected. They propose that roughly 39,000 acres on the plateau be declared too environmentally sensitive to drill.
That's up from the 36,184 acres recommended by the governor and the 21,034 acres in the federal plan.
The bill includes the state's suggestion to phase in leases on top of the plateau rather than leasing the land all at once.
Cody Wertz, Sen. Salazar's spokesman, said the senator is looking for a measure to attach the bill to.
The Roan Plateau has become a focus as Colorado's natural drilling has increased. The BLM estimates the plateau about 180 miles west of Denver contains 9 trillion cubic feet of recoverable natural gas and could generate between $428 million and $565 million in royalties and lease payments for the state.
Conservationists have questioned the BLM's estimates, saying the amount of gas is likely lower. They also say the Roan provides crucial winter habitat for some of the country's largest elk and mule deer herds and is home to mountain lions, peregrine falcons, bears, rare plants and genetically pure native cutthroat trout dating to the last ice age.
Several area communities have opposed drilling on public land on the plateau's top. There is drilling on private land.
"Every time the public or Congress or the governor has intervened on this and asked for protection, the Bush administration has plowed forward," said Clare Bastable, conservation director for the Colorado Mountain Club. "So the fact that the (BLM is) pursuing leases of the Roan is not a surprise. It is certainly disappointing, but again, I don't believe this battle is over."
Marc Smith, executive director of the Denver-based Independent Petroleum Association of Mountain States, said he was pleased that the BLM might begin to allow limited energy development on small portion of the Roan Plateau.
"Congress gave clear instructions to the BLM in 1997 when it passed bipartisan legislation to transfer management responsibility of the lands for the purpose of developing natural gas resources," Smith said.
The chief executive of Russian gas monopoly OAO Gazprom said his company has made a proposal to ConocoPhillips and BP to join a massive gas pipeline project in Alaska.
The $30 billion project will when finished carry around 4 billion cubic feet of natural gas from Alaska's North Slope to North American markets.
Alexei Miller also said he expects hydrocarbon prices to continue rising as demand grows despite global economic problems.
"The fight for resources is intensifying," Miller told investors and corporate executives at a Kremlin-backed forum in St. Petersburg.
Crude oil posted its biggest-ever one-day gain Friday, closing up $10.75 a barrel, or 8.4%, at a record $138.54 on the New York Mercantile Exchange.
Donald Benson, Chairman and Chief Executive Officer of Nordic Oil and Gas Ltd. announced that the Corporation has signed a contract with a drilling company to commence drilling the first of two wells on Nordic's Preeceville, Saskatchewan property. Transportation of the rig began May 26 and was expected to be at the first well site by midday.
Weather permitting, the first well was to be spud late May 26 or on May 27. As stated previously, it was expected that drilling would take between four and five days to complete. The rig would then be moved to the second site, where clearing and preparation was to be completed.
"We have secured one of the best rigs available as we intend to drill to the basement, which is about 1,200 metres in depth," Mr. Benson stated. "Again, weather permitting, we should have both wells drilled by June 9, 2008."
The House of Commons passed legislation May 28 to implement a national renewable fuel standard that would require gasoline sold in Canada to contain 5% ethanol by 2010. The bill also requires that 2% of the diesel sold in the country come from renewable sources by 2012.
Canada's minority Conservative government was backed by the opposition Liberal party in the vote, according to news reports. The bill must now go through the Senate, which is dominated by the Liberal party.
The Canadian Renewable Fuels Association praised the bill. "Today, the House of Commons voted to grow beyond oil. Thanks to this vote, we will lower greenhouse gas emissions, provide new opportunities for Canadian farmers, and bring about competition at the pump. With oil and gas prices at record highs, the case for viable alternatives to petroleum has never been stronger," Gordon Quaiattini, the association's president, said in a press release.
By the end of 2008 Canada will have the capacity to produce more than 1.0 billion liters a year of ethanol, according to information provided by the Canadian Renewable Fuels Association.
The 5% renewable fuels content in gasoline by 2010 will require ethanol production of just over 2.0 billion liters, Robin Speer, the association's director of public affairs, said in an earlier interview.
Canada currently has the capacity to produce 100 million liters of biodiesel annually, but will need to produce 500 million liters per year to meet the 2% target, Speer said.
Bolivian President Evo Morales nationalized Bolivia's main gas pipeline company, expanding his control over the Andean country's natural resources one day after losing two regional referendums on his rule.
Morales issued a decree seizing the majority stake in Transredes Transporte de Hidrocarburos SA owned by Europe's Royal Dutch Shell Plc and Ashmore Energy International. Bolivia's state energy company held 47 percent. Morales said Transredes ``conspired'' against his government and rejected talks aimed at giving Bolivia control of the company.
The move is the latest by Morales to fulfill campaign pledges to ``re-found'' Bolivia by taking over energy and mining companies and directing more tax revenue from provinces to the treasury. The government forced oil companies to renegotiate contracts in 2006 and last year seized Glencore International AG's tin smelter. The actions have helped fuel discontent among business groups and provincial leaders.
``Morales is under pressure,'' David Scott Palmer, a professor of Latin American politics at Boston University, said in an interview. ``This is an effort by Morales to lash out in a way that will deflect attention from his problems.''
Bolivia, the poorest country in South America, has the continent's second-largest reserves of natural gas, after Venezuela. Morales, 48, assumed the presidency in January 2006 after promising to take greater control of natural resources to help the country's largely poor, indigenous majority.
``Despite having a series of meetings between the government's negotiating team and the executives of Transredes, the company insistently rejected the government's proposal,'' said a statement issued by Morales's office. ``We won't accept authorities or managers or companies that come to conspire against democracy or against the national government.''
Shell can't comment on the takeover until it has a chance to review and assess the action, said Eurwen Thomas, a spokesman in London. Kenny Juarez, an outside spokesman hired by Ashmore, declined to comment.
The move to nationalize Transredes, which operates 5,700 kilometers (3,500 miles) of pipelines in Bolivia, follows a May 1 announcement by Morales that the government would acquire a majority stake in the company. Terms of the takeover weren't disclosed.
Shell, Europe's largest oil producer, and Ashmore each owned 25 percent of the pipeline through a joint venture called TR Holdings Ltd, according to Transredes. TR Holdings named five of the seven members of the company's board of directors, with two representing Bolivia, according to the Transredes Web site.
Opposition congressman Fernando Messmer said the move will ``increase uncertainty and doubts'' for companies in Bolivia, the official news agency ABI reported.
Investment in exploration and production in Bolivia's oil and gas industry fell to $149 million last year from $650 million in 2002, the lowest since 1996, according to the Santa Cruz-based Hydrocarbons Chamber. The chamber's members include Petroleo Brasileiro SA, Total SA, and BG Group Plc.
Petrobras is in a "very good position" after making huge deep-water oil discoveries off Brazil in recent months, the top executive of Brazil's national oil company said May 6.
But it may need to start building its own deep-water drilling rigs or form a strategic alliance to get more rigs if the company is to unlock the potential of its vast offshore fields, Petrobras CEO Jose Sergio Gabrielli De Azevedo said during a news conference at the Offshore Technology Conference in Houston.
"We have to think about nontraditional ways to get those critical resources, because in the next several years we will need a lot of drilling rigs," Gabrielli said.
The prediction comes after Petrobras said late last year its Tupi field in the Santos Basin may contain up to 8 billion barrels of oil and natural gas, an amount that could boost the country's reserves by more than 50 percent.
Recently, it looked like Petrobras had made an even bigger find, when Haroldo Lima, head of Brazil's National Petroleum Agency, said the company's deep-water Carioca field could hold up to 33 billion barrels of oil.
But Petrobras officials have not confirmed that figure, and Gabrielli again declined to comment.
The discoveries mean there could be a big opportunity for U.S. companies that provide rigs, services and equipment to the offshore oil and gas industry.
"All indications are that the opportunity will be great," said Ricardo Monico, general manager of Brazil for Cameron, a Houston company that makes subsea drilling systems.
The Tupi field alone could require installation of about 600 subsea "trees" that regulate the flow of fluids at the wellhead, roughly double the number of trees in all of Brazil's offshore fields today, he said.
And Cameron, whose business is rapidly growing with Petrobras, hopes to get more of the work, Monico said.
So, too, do Houston-area drilling contractors like Transocean, Pride International, Noble and Diamond Offshore, which own the lion's share of the small number of specialized floating rigs needed to operate in Brazil's deep waters, and oil field service companies like Halliburton and Schlumberger that offer technical know-how for drilling in harsh environments.
Petrobras is well-liked among its suppliers because it is open to new ideas and willing to experiment with different technology, said Chuck Chauviere, president of Hydril, a maker of high-tech pressure-control products used in offshore drilling that was purchased by GE Oil and Gas in April.
"If new deep-water technology is going to be developed, Petrobras is one of the companies who will do it," he said.
But the company still needs drilling rigs to harvest the oil and natural gas deep below the seafloor off Brazil. Gabrielli said the company has not decided whether it will enter the rig-building business but pointed to its entry into ship hull building when it needed more FPSO vessels to produce oil and gas.
In Brazil, Petrobras has been a pioneer of the FPSO, or floating production storage and offloading ship, and recently won a preliminary approval to bring the first one to the Gulf of Mexico.
Petrobras now produces 2.3 million barrels a day of crude oil, enough to meet the energy needs of Brazil and still have some left over.
The company expects to reach 3.2 million barrels a day by 2012 and 4.2 million barrels per day by 2015, Gabrielli said.
The company also plans to expand its oil refining capacity from 1.9 million barrels a day to 3 million barrels a day by 2015.
Petrobras could decide by May 9 if it will buy Valero Energy Corp.'s 275,000-barrel-per-day refinery in Aruba, said Paulo Roberto, director of Petrobras' downstream division.
The company's board was scheduled to meet May 9 and planned to discuss whether to move forward buying the facility, but "we are not committed to make a decision," Gabrielli said.
In November, Valero said it was exploring strategic alternatives for its Aruba plant, estimated to be worth upwards of $4 billion. Valero also is trying unload refineries in Memphis, Tenn.; Krotz Springs, La; Ardmore, Okla.; and Lima, Ohio, which it already sold.
Bill Day, a Valero spokesman, would not confirm whether Petrobras is a possible buyer for the Aruba plant. But the company expects to have a transaction on Aruba by the end of the second quarter, he said.
Petrobras is also in negotiations to increase its stake in a refinery in Pasadena at the Houston Ship Channel, Gabrielli said.
Now a 50 percent owner with Astra Oil, Petrobras is said to be considering full ownership of the 100,000-barrel-a-day plant, as well as an expansion that would double its size. But company officials would not elaborate on negotiations.
Brazil on May 26 announced plans to spend at least US$5 billion to develop deep water oil finds, building new ships and hiring rigs as soaring world fuel prices boost demand for drilling equipment.
State-run oil company, Petroleo Brasileiro SA, or Petrobras, will spend $5 billion to build 146 ships and plans to hire 40 deep-water drilling rigs and platforms, President Luiz Inacio Lula da Silva told shipbuilders in Niteroi, a harbor town near Rio de Janeiro's coast. Analysts said the additional equipment could cost an extra $15 billion.
Petrobras has made a series of large offshore oil finds in the nearby Santos Basin, including a possible 8 billion barrel discovery at the Tupi field in November; the biggest in the Western Hemisphere since 1976.
But as global oil prices soar, competition for equipment to tap that oil is increasing. Petrobras now leases nearly 80 percent of all deep-water drilling vessels in the world, according to local media reports. A Petrobras spokesman declined to confirm that figure or give his name, citing company policy.
The plan to modernize Petrobras' own fleet would employ about 8,000 shipbuilders, at least 70 percent of them Brazilian, and would require an additional 3,800 crew members once the ships are complete in 2017, Petrobras said in a statement.
Silva noted that Brazil's naval industry has grown more than 20 times since he took office in 2003, from 1,900 to 40,000 workers today.
Petrobras, which Silva said has become the world's sixth largest company, announced last week that it had discovered new medium-grade crude deposits in the Santos Basin at a depth of 4.2 miles (6.8 kilometers). It did not estimate the size of the find.
Deep underwater layers of sand, rock and salt make extraction expensive.
Brazil's push to find $135-a-barrel crude in water more than 2 kilometers deep is prompting AIG SunAmerica Asset Management Corp. to invest in Keppel Corp., the world's biggest oil-rig maker.
Jersey City, New Jersey-based SunAmerica Asset, owned by American International Group Inc., bought 865,000 shares after a 24 percent decline in the first quarter, according to regulatory filings. Since then, Singapore-based Keppel has climbed 19 percent, five times as much as the Straits Times Index. The shares, priced 19 percent below smaller competitor Sembcorp Marine Ltd. based on estimated 2009 profit, may rise 27 percent to S$15 over the next 12 months, according to Merrill Lynch & Co. analyst Melinda Baxter.
``Demand for rigs and floating platforms will continue to be robust for at least the next four to five years,'' said Soo Hai Lim, a member of the emerging-markets team responsible for $12 billion of Asian equities, including Keppel, at Baring Asset Management Ltd. in Hong Kong.
``We favor Keppel and Sembcorp Marine because they are the leaders in the industry,'' said Lim, whose firm is a unit of Springfield, Massachusetts-based MassMutual Financial Group.
Keppel is selling more deep-water rigs, which are twice as expensive as those for shallower water, as supplies tighten amid an intensifying search for untapped reserves further from shore. That helped the company post profit margins last quarter that were 1.9 percentage points wider than Sembcorp Marine's, according to data compiled by Bloomberg.
Of 20 analysts surveyed by Bloomberg, 16 recommend buying Keppel and four say to hold it. The company's offshore and marine unit accounted for half of first-quarter net income.
Keppel dropped 2 percent to close at S$11.56 in Singapore. Sembcorp Marine fell 2.9 percent to S$4.35.
Petroleo Brasileiro SA, Brazil's (Petrobras) state-owned oil company, plans to order 40 drill ships and platforms worth about $30 billion for delivery by 2017 after finding the Tupi field, the largest Western Hemisphere discovery since 1976. The field may contain 5 billion to 8 billion barrels.
``We are likely to see order-book momentum picking up again in the short term,'' Winnifred Heap at JPMorgan Chase & Co. in Singapore wrote in a May 21 note. The analyst rates Keppel and Sembcorp Marine ``overweight.''
An offshore platform takes as long as 32 months to design and build after a contract is signed. That means Petrobras will continue to award orders until 2014 to meet a 2017 delivery target, according to analysts.
Keppel and Sembcorp Marine may capture 27 percent of the global market this year for semisubmersible rigs, which use anchors weighing more than 10 metric tons, JPMorgan said.
Petrobras, based in Rio de Janeiro, said May 21 it struck oil in a well in 2.1 kilometers (1.3 miles) of water off the coast of Sao Paolo state. The company has leased about 80 percent of the world's deepest-drilling offshore rigs to explore that find and other prospects.
The head of Brazil's oil agency said last month that the nearby Carioca field may hold 33 billion barrels of crude, making it potentially the world's third-largest. Petrobras is evaluating the field and hasn't confirmed the estimate.
Such findings may require even more offshore-equipment spending, Petrobras Chief Financial Officer Almir Barbassa said May 21.
Oil companies including Exxon Mobil Corp., Royal Dutch Shell Plc and BP Plc will spend a record $98.7 billion this year on exploration and production, more than quadruple the amount eight years ago. Crude oil rose to a record of more than $135 a barrel on May 22 as OPEC ministers said they could do nothing to stop a rally that may be heading to $200 a barrel.
``The underinvestment in the 1980s and '90s in the industry gave rise to this jump in the oil prices,'' Choo Chiau Beng, Keppel's senior executive officer, said April 24. ``There will be demand for offshore equipment.''
Keppel, whose Brazilian yard is the largest in the Southern Hemisphere, has completed projects for Petrobras that produce more than half the country's output of 1.8 million barrels a day, according to Keppel's Web site.
The Singapore company's S$11.8-billion ($8.69 billion) backlog at the end of March includes a $1.2 billion Petrobras contract for a semisubmersible platform.
Demand for the offshore units has pushed up prices the past two years. Samsung Heavy Industries Co., the world's second- largest shipbuilder, won a record $942 million order for a drill ship earlier this month from Stena AB, owner of Sweden's biggest ferry company.
Higher labor and material costs associated with construction of the P-51 offshore platform for Petrobras helped push Keppel's fourth-quarter operating profit, or sales minus the cost of goods sold and administrative expenses, down 40 percent. That prompted DBS Vickers Securities to advise caution on the shares.
``We are still avoiding Keppel for the moment,'' the Singapore firm said in a May 22 note. It has a ``hold'' rating for Keppel.
Even so, investors say the tight yard capacity and higher fuel prices will translate into more offshore-equipment orders, extending the industry's boom.
``The upcycle for offshore equipment, like drill ships and offshore platforms, has just started,'' said Park Hyoung Ryol, who helps manage $1.2 billion, including Samsung Heavy shares, at Consus Asset Management Co. in Seoul.
A shortage of drilling rigs and looming relinquishment deadlines have made Brazil's state oil company Petrobras delay tests on potentially huge subsalt finds like Carioca and move the rigs to other blocks.
Petrobras chief executive, Jose Sergio Gabrielli, said on May 26 that production evaluation tests would have to wait and expected no additional information on the Carioca reserve any time soon.
"We ceased doing tests on Carioca to fulfill the compulsory exploration program, so we don't have to relinquish areas," he told reporters. Some geologists say Carioca and three adjacent blocks may have probable reserves of over 30 billion barrels.
If no oil is found in blocks under concessions until a certain deadline, operators have to return parts and then the whole of the area to the government.
Gabrielli said the Bem-te-vi, or BMS-8, area, where Petrobras recently announced a light oil find, would also have to wait for new equipment to get more information about the crude accumulation. The rig from there has been transferred to another subsalt area, known as Iara, he said.
Exploration and production director Guilherme Estrella said that by the beginning of next year, Petrobras has to inform the National Petroleum Agency about oil finds in all the area with subsalt crude accumulations. The offshore area extends along the coasts of three Brazilian states.
"We have to present evaluation plans for all those fields by the end of 2010; we are running against time," he said.
On May 26 Petrobras launched a previously announced plan to contract 40 drilling ships and platforms to operate in deep and ultra-deep waters by 2017.
The priority will be to build the units in Brazil, but Gabrielli said the domestic market was not ready to meet the demand in the short term.
"We will evaluate how much the international market can deliver and will see what the possibilities of the local shipyards are. The international volume will tell us how many units we need to contract in Brazil," he said.
With oil prices chalking up record highs, oil exploration equipment is in short supply and becoming more expensive. Gabrielli said renting a deepwater rig cost, on average, between $400,000 and $600,000 a day.
Petrobras has only made production evaluation tests at the Tupi subsalt field, where it made a recoverable reserve estimate last November of between 5 billion and 8 billion barrels.
Estrella said two more wells will be drilled there and a long-term production test will start on Tupi in March next year to produce 10,000 to 20,000 barrels per day.
"Only then will we have more concrete information on the reservoir," he said.
He said a theory that some reserves in the subsalt cluster were continuous has not yet been confirmed, but it was a possibility that required more studies.
Analysts are bullish on Brazil's oil potential, expecting the country to become a major world oil producer with big reserves of light oil in the subsalt cluster.
Foreign companies like Royal Dutch Shell, BG Group Plc, Exxon Mobil Corp, Hess Corp and Portugal's Galp have stakes in high-potential subsalt blocks along with Petrobras.
Keppel Corp., the world's largest maker of oil rigs, said its unit received a $385 million order from Brazil for a semi-submersible rig to drill for offshore fuel.
Keppel Offshore & Marine Ltd. will deliver the deepwater platform to Queiroz Galvao Oleo e Gas in the second half of 2011, Singapore-based Keppel said in a statement today. The contract excludes drilling and sub-sea equipment, which will be supplied by the Rio de Janeiro-based company, Keppel said.
Record oil prices and depleting reserves in shallower waters are prompting companies such as Exxon Mobil Corp. and Royal Dutch Shell Plc to spend a record $98.7 billion on exploration and production this year, more than quadruple the sum eight years ago. Petroleo Brasileiro SA, Brazil's state-controlled oil company, approved a plan on May 30 to order 12 drilling rigs from overseas shipyards, the first of a 40-rig building plan.
The first batch of rigs, to be operational by the end of 2012, will be built abroad because Brazil lacks the shipyard capacity.
The announcement comes after Keppel won a $537 million contract on May 30 from Dallas-based Ensco International Inc. for a new ultra-deepwater semi-submersible rig to be delivered in the first half of 2012. Ensco ordered another rig from Keppel for $512 million on May 7.
Keppel shares dropped 1.8 percent to close at S$12.12 in Singapore, before the announcement. The stock has dropped 6.8 percent this year, compared with a 9 percent decline in the Straits Times Index.
The Panamanian government has presented the cornerstones of its plan to become a fuel supply and distribution center in the region.
The minister of Commerce and Industry, Manuel Jose Paredes, said in May at a regional forum on energy security that that is the goal being pursued by President Martin Torrijos's administration.
Among the projects being contemplated is a refinery for Puerto Armuelles, a town on Panama's Pacific coast near the border with Costa Rica.
That project, feasibility studies for which are being carried out by a consortium made up of U.S.-based Occidental Petroleum and state-owned Qatar Petroleum, "is part of our national hydrocarbon policy ... which, if brought to fruition, could play an important role in supplying the country" with energy, Paredes said.
The study, expected to be completed before the end of 2008, will definitively determine whether the construction of the refinery is viable, the official said.
Paredes also unveiled Panama's plans with regard to energy security and cooperation with its regional neighbors on changes needed given the growth in energy demand.
The forum on energy security was organized by Caribbean-Central American Action, an independent organization that promotes private sector-led sustainable economic development in the Caribbean Basin.
Speakers at the event pointed out that continued economic growth in the Central America countries - all net importers of fuel products - depends in large part on the supply of energy from outside the region.
Peru planned to auction 17 parcels for petroleum prospecting starting May 6, with the hope of capturing some $800 million of exploration investment, the government said on May 5.
The lots are located throughout the Andean country, along the Pacific Ocean and in the mountains. Eight jungle tracks will be bid off, Ronald Egusquiza, the president of the state-run Perupetro, said.
May 6 will be the second auction, Egusquiza said.
Last year, Peru's government, which is actively encouraging foreign companies to invest in oil and gas explorations in its quest to become more energy self-sufficient, auctioned 19 parcels.
Egusquiza said companies have until September 8 to submit their offers. Results will be released two days later.
He acknowledged some of the 17 lots in the auction cut into national parks and nature reserves.
In recent months, Peru has come under fire from rights groups that say the government is not doing enough to protect the environment. Indigenous people who have shunned contact with the rest of society are thought to live within some of the parcels included in the auction.
Peru, a net oil importer, hopes to become a net exporter by 2010. The Andean country produced 41.6 million barrels of crude oil last year.
TransCanada Corp., owner of Canada's largest natural-gas pipeline system, confirmed it may seek to build a gas pipeline in Peru as part of its strategy to supply expanding North American demand.
``It's purely an exploratory activity at this point,'' spokeswoman Shela Shapiro said today in a telephone message. ``The idea has some inherent possibilities.''
Calgary-based TransCanada and Petroleo Brasileiro SA, Brazil's stated-controlled oil company, may become the third group to bid on the pipeline, President Alan Garcia said yesterday. The conduit may cost as much as $1.2 billion, and the South American country may call for bids ``in the coming weeks'' if rival projects persist, he said in a broadcast by state television TV Peru.
TransCanada owns more than 59,000 kilometers (36,669 miles) of pipelines in Canada, the U.S. and Mexico, according to the company's Web site. The Peruvian project suits TransCanada's strategy of linking producing regions with North American consuming markets, Shapiro said.
``It's a logical fit for Peruvian gas to get into the North American market,'' she said. Gas futures in New York today rose to as much as $12.376 per million British thermal units, the highest since December 2005, as distributors compete to secure supply that can be stored for consumption during North America's winter, when demand peaks.
Dallas-based Hunt Oil Co. is leading a group planning to build a plant on Peru's coast to process 677 million cubic feet of gas in a liquefied form, or LNG. Exports to Mexico from the $3.9 billion project are forecast to begin in May 2010, closely held Hunt has said.
A LNG plant is ``part'' of TransCanada's exploratory efforts, Shapiro said, without elaborating.
Peru, South America's fifth-largest gas producer, is counting on $6 billion in oil and gas investment projects to double gas output and drive 7 percent annual economic growth over the next four years.
Paris-based Suez SA and New York-based investment fund Conduit Capital Partners LLC are holding talks to submit a joint proposal for the pipeline. Energy Transfer Partners, a U.S. natural-gas transporter and propane marketer, has also fielded a bid.
Royal Dutch Shell Plc and TransCanada plan to appeal New York State's denial of permits for a proposed LNG terminal in Long Island Sound. New York Governor David Paterson on April 12 rejected the project because of potential environmental damage.
An Apache Corp. pipeline has ruptured in Western Australia, resulting in a fire and the evacuation of 153 people.
The Houston-based oil and gas firm reported June 3 a pipeline rupture and fire at its Varanus Island gas processing and transportation hub offshore Western Australia.
The island's operations, which account for approximately 330 million cubic feet of natural gas and 8,000 barrels of oil per day, have been interrupted. Apache's net production flowing through the Varanus facility is approximately 200 MMcf and 5,000 barrels per day.
Apache CEO G. Steven Farris says the company has notified gas customers who will be affected by the disruption in gas supply. For now, the firm is unsure of when throughput will resume.
The oil and gas industry has welcomed comments by Australia’s Resources Minister, Martin Ferguson; that the Government will look at future tax breaks and financial concessions for offshore exploration.
Mr. Ferguson said he would push for more deregulation of global energy markets but also support local projects to deliver low-emission fossil fuels and renewable energy.
He said the review of the taxation system by the Treasury secretary, Ken Henry, would include an assessment of the issue.
The review will look at barriers to investment in "large-scale downstream gas processing projects in Australia, the particular hurdles faced by remote gas developers, and consideration of the future policy framework for new sunrise industry investment in Australia's gas sector, including new LNG [liquefied natural gas] and gas-to-liquids".
Mr Ferguson said the new technologies were attracting a growing premium as low-emissions energy resources.
"New gas projects such as Gorgon, Browse, and Sunrise are struggling to get off the ground, and it is therefore time to even up the playing field for investment," the minister said.
The chief executive of the Australian Petroleum Production and Exploration Association, Belinda Robinson, welcomed the announcement.
Ms Robinson said one of the issues faced by the industry was the capital depreciation rate offered in competing countries such as Qatar, Algeria, Malaysia and Indonesia. She said companies investing in those countries were offered rates three times as favourable as in Australia.
"The fiscal settings that we have in Australia at the moment are not conducive to growing and investing in industries that are capital intensive."
With favorable policies, Ms Robinson said Australia had the capacity to triple natural gas exports and increase gas use for electricity generation.
Mr Ferguson said gas liquefaction was becoming increasingly sought after, with plants in Qatar and Malaysia supplying large markets in Europe and Thailand.
The Department of Resources, Energy and Tourism is working on an Action Agenda with gas-to-liquid and coal-to-liquid developers.
Officials from India and Pakistan said their countries were interested in an increased role for China in the Iran-Pakistan-India pipeline.
Pakistani officials told the Fars News Agency that Iran and China have already discussed joining forces on the $7.2 billion project.
Likewise, Chinese officials said they were interested in exploring involvement in the project as a means to seek additional natural resources to meet growing demand.
"China is in urgent need of more energy. Of course, we will be interested," said He Yafei with the Chinese Foreign Affairs Ministry.
India expressed concern over the security issues involved in the project but continued to stress the overall value of the joint pipeline, called IPI, or the Peace Pipeline.
The 1,724-mile pipeline will deliver natural gas from Iran to Pakistan and India.
The United States, meanwhile, is backing an alternative pipeline, the TAPI pipeline, which joins Turkmenistan, Afghanistan, Pakistan and India to discourage Central Asian countries from using Iranian resources.
China’s Shahepu County, adjacent to two expressways and an airport, plans to build the largest seamless pipe base in northeastern China with an annual production value of CNY 10 billion this year.
The county plans to build 60 seamless pipe projects within this year, 12 of which have been approved, each with a capacity of 150,000- tonnes per year to 200,000 tonnes per year. It created an annual production value of CNY 5 billion from seamless pipe industry in 2007.
Seamless steel pipe for the transportation of water, LNG and oil has become increasingly popular for its corrosion resistant property amid rising demand on liquid energy because of a shortage of solid energy.
India has extended the deadline for bids in its latest licensing round by six weeks, its third extension as prospective bidders are waiting for the government to clear doubts on the tax regime in the energy sector.
Companies can now submit bids by the end of June instead of the earlier mid-May deadline, "to give more time to prospective bidders to finalize their bidding strategy", the government said in a statement.
Industry officials say that the new tax regime appears to give a tax holiday to companies that find oil but not to those which discover gas, making it difficult for firms to make a bid as they cannot predict what they may discover.
"We are waiting for clarity on tax issues," Petroleum Minister Murli Deora told Reuters.
India has offered 57 oil and gas blocks under its ongoing auction round, the seventh under the New Exploration and Licensing Policy (NELP) launched in 1999.
India is wooing private capital for exploration, and encouraging local firms to buy stakes in foreign oil and gas projects to meet the surging energy needs of Asia's third-largest economy.
Previous NELP rounds have been dominated by local firms, with state-run explorer Oil and Natural Gas Corp and Reliance Industries bagging a large number of blocks.
Indonesia's upstream oil and gas regulator BP Migas said May 27 it has signed five production-sharing contracts (PSCs) with a number of investors, including a local unit of Italy's Eni.
BP Migas said it signed PSCs with Eni Indonesia Ltd., Malaysia's Genting Oil & Gas Ltd, U.S.-based Murphy Overseas Ventures, a consortium comprising CNOOC Southeast Asia Ltd. and Petronas Carigali Overseas Sdn Bhd, and Swedish oil and gas firm Lundin Oil and Gas B.V.
'The total investment commitment of these companies to carry out exploration activities in the first three years is estimated to reach $201.45 million, including for (the conduct of a) geology and geophysics study and a seismic survey of the sites,' Luluk Sumiarso, director general for oil and gas at the ministry, said during the signing agreement.
Genting Oil and Gas Ltd signed a PSC contract to develop the Kasuri block in Papua, while Eni Indonesia Ltd signed a contract to develop the West Timor block.
Murphy Overseas Ventures signed a contract to develop the South Barito block in South Kalimantan, while Lundin Oil secured a contract to develop the Rangkas block in West Java.
The consortium of CNOOC Southeast Asia and Petronas Carigali also signed a contract to develop the Southeast Palung Aru block. CNOOC Southeast Asia is the Indonesian subsidiary of CNOOC Ltd.
The contracts were signed on the sidelines of the Indonesia Petroleum Association's three-day convention starting May 27.
Also on May 27, BP Migas signed a production sharing contract with a consortium consisting of PT Medco CBM Sekayu and South Sumatra Energy Inc. to develop a coal bed methane (CBM) project in Sumatra island.
No details were given.
Separately, BP Migas chairman Raden Priyono said that state-owned electricity company PT Perusahaan Listrik Negara (PLN) has signed an agreement with PT Pertamina EP, unit of state-owned oil and gas company PT Pertamina, for the purchase of 63 trillion British thermal units (BTUs) of natural gas from Pertamina over a period of eight years.
Pertamina EP will supply natural gas to PLN from its Glagah Kambuna gas field. The contract is worth $260 million.
Priyono said four other companies -- including independent power producer PT Multidaya Prima Elektrindo and petrochemical company PT Medco Methanol Bunyu -- also signed gas purchase agreements with suppliers for a combined contract value of $318 million.
Foster Wheeler Ltd, through its UK-headquartered subsidiary Foster Wheeler Energy Limited, has been awarded an engineering and materials supply contract by Samsung Engineering Co. Ltd. for two gas turbine exhaust waste heat recovery units for an ethane separation plant in Thailand.
The contract is awarded for the PTT Public Co. Ltd. (PTT) ethane separation plant at Map Ta Phut Industrial Complex, with Samsung as PTT’s engineering, procurement, construction and pre-commissioning contractor for the plant. The Foster Wheeler contract value for this project was not disclosed and will be included in the company’s first-quarter 2008 bookings.
“Foster Wheeler has designed and supplied some of the world’s more technically advanced waste heat recovery units. This award reflects our ability to deliver a cost-effective waste heat recovery solution incorporating selective catalytic NOx reduction, to meet Thailand’s stringent emissions standards,” said Michael J. Beaumont, Chairman and CEO of Foster Wheeler Energy Limited.
Gazprom and Bulgargaz, the Russian and Bulgarian state controlled gas distributors will sign an agreement for the creation of a company to design the section of the trans Black Sea South Stream gas pipeline that will cross Bulgarian territory. In January 2008 both countries signed an intergovernmental agreement on the project, splitting evenly the project company equity and opting for a Bulgarian domicile. The Bulgarian Russian agreement has been submitted for review by the competent ministries.
It will also have to be ratified by parliament. According to the text of the agreement posted on the website of the Bulgarian economy ministry, Gazprom is named as the operator of pipe on Bulgarian territory. In addition to the bilateral agreements with Bulgaria, Serbia and Italy a further multilateral intergovernmental accord will also be signed with the countries lying on the route of the facility.
Ms Galina Tosheva deputy economy minister of Bulgaria said that the undersea section of the pipeline will be built and operated by a different company where Bulgaria will have no stake.
The Hungarian ambassador-at-large for the Nabucco pipeline dismissed allegations his country is holding the program back with its interest in an alternative project, South Stream.
The Hungarian Oil and Gas Public Ltd. Co., known by its Hungarian acronym MOL, is one of six companies engaged in the 2,050-mile Nabucco pipeline that will transport natural gas from Turkey to Austria via Hungary, Bulgaria and Romania.
Mihaly Bayer, the Hungarian official, sidestepped criticism that his country's support for the South Stream project -- which will transport Russian natural gas to Italy -- made Hungary the weak link in the Nabucco consortium.
"I was appointed in order to see what Hungary can do to accelerate the project," he told the Turkish Daily News. "This shows the full support of the Hungarian government to Nabucco."
Bayer said embracing alternative projects addresses the broader goal of meeting the rising energy demand in Europe.
"Although progress has been slow, the Nabucco project has been the most advanced," Bayer said. "The South Stream project is just an agreement; there is no company, no route."
The $6 billion Nabucco project is slated for completion by 2012 at the earliest.
Lansdowne Oil & Gas Plc. said it has granted a farm-in option to Island Oil and Gas Plc.'s Island Expro Ltd. for a number of part blocks in the prospective Old Head gas trend in licence 4/07, in the Celtic Sea offshore Ireland.
Under the option terms, Island will acquire a seismic survey of about 100 km of 2D data over the area and will have the right to carry out the drilling and testing of a farm-in well in the area.
The option extends up to Dec. 31, 2008, and if exercised, the well is expected to drill before July 31, 2010, depending on rig availability.
Should the option be exercised, Island will become the operator and acquire a 58 percent interest, while Lansdowne retains the rest.
In a separate statement, Island said it believes there is additional potential at Old Head for low risk gas prospects.
Island CEO Paul Griffiths said that the company's studies in the area indicated that it had 'the potential to contain material gas resources that, with synergies created by the development of infrastructure at Old Head, may lead to early development and increased near-term cash flow if successfully drilled.'
Island added that its joint venture partners on license 4/05 (the 'Old Head of Kinsale'), Valhalla Oil and Gas Ltd. and Encore Oil Plc., will be offered a pro-rata share of the option agreement, which, if exercised, would reduce Island's net interest in the area to 38 percent.
The use of the mobile facility Scarabeo 5 has been granted to StatoilHydro for the drilling of a pilot well on the Q template on the Kristin field. The new consent is an extension of the existing consent and applies to drilling on the Q template.
StatoilHydro has used Scarabeo 5 for drilling and completion of wells on the Kristin field since 2003. The company currently has consent to complete drilling activities related to the subsea templates N, P, S and R.
StatoilHydro's Plan for Development and Operation (PDO) of the Morvin field was approved on April 25. This is the first PDO approved in the merged StatoilHydro. The oil and gas field Morvin is a typical example of a middle-size project in the vicinity of existing infrastructure.
The field is located in the Norwegian Sea, 15km NW of Åsgard. Subsea templates and tubings are planned to be installed this very summer, whereas first oil is scheduled for the late summer of 2010. The Morvin development concept will include two subsea templates tied in to Åsgard B for processing through a 20km pipeline.
The Plan for Development and Operation includes investments of NOK 8.7 billlion. In addition StatoilHydro is exploring the possibilities of a fourth production well at about NOK 1.2 billion. A production rate of about 27,000bpd is expected in the peak period, StatoilHydro's share being 18,000bpd.
Aurelian Oil & Gas Plc. said it has entered into a farm-out agreement with its joint venture partner and Romania's state gas company SNGN Romgaz S.A. for projects in Romania, Slovakia and Poland.
The oil and gas exploration company said in Slovakia, Romgaz will earn a 25 percent interest in Aurelian's three licenses Svidnik, Medzilaborce and Snina by paying a 50 percent share of the $5 million seismic programme.
Romgaz is therefore effectively participating on the same terms as JKX Oil & Gas Plc., whose farm-in was announced on April 7, the company said.
In Poland, Romgaz will earn a 15 percent interest each from Aurelian and GB Petroleum Plc. in the Cybinka and Torzym concessions awarded in February. Romgaz will pay a 45 percent share of the cost of this survey, Aurelian said.
Aurelian will hold a 35 percent participating interest after the farm-in in Poland, while GB will have 25 percent, Romgaz 30 percent and Avobone Poland B.V. the remaining 10 percent.
Within Romania, Romgaz will earn a 40 percent interest in the Bacau concession by paying 66.67 percent of the Lilieci-1 well.
After the farm-in, Aurelian will hold a 41 percent participating interest, while Romgaz and Europa Oil & Gas Plc. will hold 40 percent and 19 percent respectively.
Aurelian and Romgaz have also agreed to work together to evaluate the next tender round of concessions to be offered by the National Agency for Mineral Resources.
Petroleum Inc. has announced it has signed a Letter of Commitment with Senergy,
an international integrated oil services company, to utilize the Byford Dolphin
semi-submersible drilling rig to drill a well on the company's Bourbon prospect.
This well, if successful, is expected to recover over 160 million barrels of oil. Fox has secured the drilling rig for a 22-day slot in the fourth quarter of 2008.
Aker Solutions in Aberdeen (UK) has been awarded a three-year contract, plus options, to provide Fairfield Energy with engineering, procurement and construction services on the Dunlin Alpha platform in the northern North Sea. The contract is valued at between GBP 20 and 30 million annually. Aker Solutions will undertake a number of initial studies on the installation, followed by an aggressive program of modifications, including onshore engineering work, procurement and offshore construction.
In delivering the contract Aker Solutions will be working very closely with Amec as the Dunlin platform duty holder. The Dunlin oilfield is situated 195km NE of Lerwick, with first production in August 1978 from the Dunlin Alpha platform.
Britain granted licenses for two North Sea oil fields May 28, attempting to help stabilize global energy markets by encouraging major oil producers to drill.
John Hutton, Britain's business and enterprise secretary, authorized the new oil field developments and said there are plans to help companies extract crude from previously unprofitable sections of about 30 existing fields.
The decision was announced after talks in Aberdeen, Scotland, between Prime Minister Gordon Brown, Treasury chief Alistair Darling and members of Oil & Gas U.K., a trade body for companies operating in the North Sea.
The two new fields have an estimated total output of 50 million barrels, and additional daily production in the existing fields could produce up to 20,000 extra barrels per day, Hutton's ministry said.
It said the new fields will be operated by Petrofac Energy Developments Ltd. and that production will start in the first half of next year.
"For four decades we have produced huge amounts of oil and gas from the North Sea," Brown said in Scotland. "The issue for us is how we can maintain supply in the next few years - how we can use what everybody recognizes are very substantial reserves still available in the North Sea."
The British leader said the 13-nation Organization of Petroleum Exporting Countries should also increase production to help lower skyrocketing fuel prices.
Brown's office, however, said the prime minister did not support a proposal from French President Nicolas Sarkozy to cut fuel taxes across Europe.
On May 27, hundreds of trucks blocked off a highway in London to protest the soaring cost of fuel in Britain - where diesel now costs more than $9 a gallon.
A delegation of drivers handed a letter to Brown's Downing Street office calling for a cut in fuel taxes for trucking companies.
In an opinion piece for The Guardian newspaper, Brown insisted the best long-term solution is to become a low-carbon economy.
He said all countries must reduce their dependence on fossil fuels and reduce consumption. He said spiraling fuel costs should top the agenda at a summit of the Group of Eight industrialized nations next month.
"The cause of rising prices is clear: growing demand and too little supply to meet it both now and - perhaps of even greater significance - in the future," Brown wrote. "Our goal that Britain becomes a low-carbon economy is now an economic priority as well as an environmental imperative."
Brown also said Britain plans to build one of the world's first commercial-scale carbon capture and storage coal plants.
Carbon capture is an experimental technology meant to reduce greenhouse gas emissions by locking dangerous gases deep in the earth.
A consortium of foreign oil companies led by French giant Total is threatening to block government plans to fully develop the North Sea's last frontier, which contains over a fifth of Britain's flagging oil and gas reserves.
In a surprise visit to the Oil & Gas UK conference in Aberdeen during the last week of May, Gordon Brown met senior executives from the consortium - which includes US heavyweight Chevron, Italy's ENI and Denmark's Dong Energy - and some of their rivals to try to broker a deal.
The two sides are represented on an industry task force set up by the government to work out how best to develop the estimated 4 billion barrels of oil and gas equivalent lying beneath deep water west of the Shetland Islands.
Total, which owns the largest fields in the region, is resisting demands that it build a pipeline large enough to transport the gas stranded in fields owned by the consortium's rivals. It says to do so without tax incentives would not be economic. It has instead proposed building a smaller pipeline, costing a third less, which would connect with its existing infrastructure elsewhere in the North Sea to bring the consortium's gas to the British mainland.
Its rivals worry that Total will deny them access to its pipeline. This would mean that up to half of the reserves could remain unexploited at a time when oil prices are hitting $130 a barrel and the government wants to maximise remaining North Sea production.
The government wants Total to build a larger, more expensive pipeline directly to the mainland, which could handle 700 million cubic feet of gas per day, 6 per cent of UK demand. This would also allow more oil to be produced because it cannot be pumped from fields unless the accompanying gas can also be shipped. The entire cost of fully developing the region is estimated at £4bn.
At the meeting with the Prime Minister, Total was told to find new partners to help build the larger pipeline. Total plans to issue a tender early this summer. British companies Centrica or National Grid could be interested as might other majors such as Chevron, which owns large reserves in the area beyond its stake in the consortium. But if no other companies come forward, or the government does not provide tax incentives, the French oil company is expected to decide later this year to go ahead with its smaller pipeline.
Oil and gas explorer Dana Petroleum has made a "significant" gas discovery in the sea off Egypt. The announcement boosted Dana's share price by 3 per cent June 2.
The well, in the Mediterranean, is Aberdeen-headquartered Dana's first gas find off Egypt, where it already has major oil explorations underway, producing around 11,000 barrels of oil a day.
The discovery, in partnership with Gaz de France, is to be capped to be used as a potential gas production well in the future.
Dana holds a 50 per cent interest in the discovery and the license area of West El Burullus, which contains numerous additional prospects at both shallow and deeper horizons. Gaz de France also owns a 50 per cent stake.
Chief executive Tom Cross said: "Making a discovery with our first well highlights the outstanding exploration potential of West El Burullus and significantly increases the likelihood of success for additional prospects which are being identified."
He added that most exploratory drill holes were closed off after the initial tests, but said the Egyptian discovery was so good that the company planned to suspend it for potential re-entry when production starts.
He said "In a production scenario, we feel this well could do a lot more than this."
He said the area around the field was a strong source of gas.
Cross added: "This is very significant because this is an area that is largely untapped. All around us are world-class facilities. The quality of the other companies interested in the area shows us that – BP is on one side and BG Group on the other."
Dana, which recently bought a 40 per cent stake in an exploration block in the Gulf of Suez – its sixth deal off Egypt – and has had four discoveries since Christmas, ended the day 47p, or 2.57 per cent, up at 1,877p.
Cross added that Dana's oil was unhedged, meaning shareholders benefit from the rocketing oil prices.
Nigeria's state oil firm and the local arm of Exxon Mobil has begun work on plans for a natural gas to liquid petroleum plant, a project Nigeria hopes will reduce its dependence on imported fuel.
Nigeria is the world's eighth biggest oil exporter but its four state-owned refineries have frequent production problems, largely due to mismanagement and vandalism, saddling it with an annual fuel import bill of some $4 billion.
With oil prices expected to continue hitting record highs, those costs are likely to rise. International oil companies are meanwhile using higher price assumptions for business planning, making a greater range of project viable.
"The project will use the latest technology to convert gas to liquid for petrol and will significantly reduce the nation's importation of petrol," Nigeria's Oil Minister Odein Ajumogobia said in a statement.
"It is in line with government's aspiration to utilize the nation's abundant natural gas resources," he said at a ceremony launching two committees to oversee the project.
John Chaplin, managing director of Exxon's subsidiary Mobil Producing Nigeria, said the project will involve the building of port facilities in the southeastern state of Akwa Ibom and said Exxon was committed to being a "catalyst for development".
ExxonMobil said its chairman and chief executive, Rex Tillerson, had discussed the project with Nigerian President Umaru Yar'Adua during a visit in March.
The company said the project was still in the planning stages and gave no details of a timeframe or production potential.
Chevron Corp., the second-largest U.S. oil company, plans to spend $20 billion over five years to boost production in Africa to help meet global demand for oil, natural gas and cleaner fuels, the company said.
The amount will be 30 percent more than was spent during the previous five years, Peter Robertson, vice chairman of Chevron, said in an interview.
Global demand for energy may increase by 50 percent by 2025, Robertson said.
``The world is saying it needs it,'' said Robertson. Almost all of the money will be spent in the sub-Sahara's largest oil producers, Nigeria and Angola, where Chevron is developing deposits, he said.
Up to $5 billion will be used for a plant in Escravos in Nigeria's Niger Delta region, which will convert gas-to-diesel, Robertson said. The facility, when completed in 2012, will have the capacity to produce about 30,000 barrels a day of a grade of diesel that will have fewer pollutants, said Robertson.
Chevron also plans to start producing up to 125,000 barrels of oil a day in Tombua Landana, Angola in the next few years at a cost of $3 billion, he added.
Drilling crews of Severburgaz (a sub branch of Burgaz) have now begun the mobilization of a drilling rig supplied by the Uralmash-Burovoye Oborudovanie plant for the drilling of four wells in the Bovanenkovskoye field of Yamal Peninsula.
In May, the Severburgaz specialists will visit the site of Uralmash-Burovoye Oborudovanie to take part in the test assembly and disassembly of new drilling rigs that will be supplied to Yamal. The drilling is now scheduled to begin this summer, and is expected to produce 140 billion cum of gas annually.
Rosneft, Gazprom Sign Agreement to Share Offshore Oil and Gas Fields
OJSC Rosneft and OAO Gazprom have signed a protocol to share Arctic and Far Eastern offshore oil and gas fields, an unnamed source at a government agency said.
The source added that the two state-owned energy giants also plan to submit a proposal for developing offshore fields to the Russian Federal Subsurface Resources Agency (Rosnedra).
'The programs have not yet been submitted to Rosnedra, but the deadline for submitting them has not yet been set either,' the source said.
McDermott International, Inc. announced recently that subsidiaries of J. Ray McDermott, S.A. ("J. Ray") were recently awarded two contracts for offshore construction projects. Both of the contracts will be included in McDermott's second quarter 2008 backlog, and have a combined value in excess of $500M.
The first award, from OOO LUKOIL-Nizhnevolzhskneft, a subsidiary of OAO LUKOIL Oil Company, is a contract to install offshore facilities in the Yuri Korchagin field. J. Ray's scope of work includes the transportation and installation of the piles for the ice-resistant fixed platform LSP-1, as well as transportation and installation of Single Point Mooring substructure, piles and the topsides.
The second award, from Esso Australia Resources Pty Ltd, is an engineering, procurement, construction and installation contract for work on the Kipper Tuna Gas Project located in the Bass Strait, Victoria, Australia. "This is a very significant contract for J. Ray, as it encompasses a wide range of services and marks a return to working with Esso Australia," said Bob Deason, Chief Executive Officer of J. Ray.
AMEC plc has been awarded a five-year Engineering Modification Services (EMS) contract for BP in Azerbaijan. The value of the new contract is estimated to be US$500 million over the five years. Under the contract, which is an extension of an existing eight-year contract, AMEC will provide engineering and construction management services to enhance and extend the life of all of BP's offshore installations in the Azeri sector of the Caspian Sea, which represents around 20% of BP's global production.
The facilities include the Chirag, Central Azeri, West Azeri, East Azeri and Shah Deniz and the soon-to-be-developed Deep Water Guneshli assets, which are of strategic importance to Azerbaijan. Together, they currently produce over 1 million barrels of oil and 700 million standard cubic feet of gas per day.
The State Oil Co. of Azerbaijan, SOCAR, said it is considering the offer made by Russian gas giant Gazprom for Azeri gas contracts.
Gazprom chief Alexei Miller made the proposal with Azerbaijani President Ilham Aliyev. SOCAR President Rovnag Abdullayev said, however, the organization was studying several proposals from different countries in order to "choose the most profitable one," reporting by the Azerbaijan Business Center said Tuesday.
"Each of the potential buyers wants to get maximum gas volume," Abdullayev said.
The developments boost the position of SOCAR to develop Stage 2 of the Shah Deniz gas field in Azerbaijan. The Norwegian energy company StatoilHydro operates Stage 1 of the Shah Deniz field, the largest such reserve in Azerbaijan.
Officials estimate the total reserves in the Shah Deniz field approach 22 trillion cubic feet of gas with 101 million tons of condensate. Gas production within Stage 2 begins in 2012.
Kazakh President Nursultan Nazarbayev signed a law on May 29 ratifying the oil-rich state's participation in the strategic BTC pipeline to the Mediterranean, his office said.
The law is based on an agreement signed with Azerbaijan in 2006 under which Kazakhstan is to deliver oil by ship to the starting point in Azerbaijan of the Baku-Tbilisi-Ceyhan pipeline.
The pipeline was inaugurated in 2005 with strong U.S. backing and has its outlet in the Turkish port of Ceyhan. It is regarded as a pioneering project as it brings oil to world markets independently of Soviet-era master Moscow.
Kazakh state oil company Kazmunaigaz later signed a protocol on ensuring deliveries to the pipeline with the companies developing two super-giant oil fields, Kashagan and Tengiz.
Initially they are to provide 25 million tonnes per year to the pipeline, possibly rising to 38 million tonnes.
However, the timetable remains vague due to uncertainty over the much-delayed development of Kashagan. The Kashagan project is being undertaken by an unwieldy Western-led consortium and is now expected to come on line in 2012 or 2013.
Washington views the BTC pipeline as a way of reducing Western dependence on oil from Russia and the volatile Middle East.
Officials from Turkey and the European Union signed a memorandum of understanding on a Trans-Caspian gas pipeline to bypass Russia.
EU Energy Commissioner, spokesman, Ferran Tarradellas Espuny said Andris Piebalgs, commissioner for energy at the European Commission, met with President Gurbanguly Berdymukhamedov of Turkmenistan to discuss bilateral cooperation on a new Central Asian gas pipeline.
"It is a first towards an energy dialogue, even an energy partnership in the future," Tarradellas Espuny told New Europe.
Iraq's oil ministry said May 6 it has postponed the deadline for bids to develop the Akkas gas field, a prized natural gas field in western Iraq, until May 18.
The announcement came two weeks after the previous deadline expired. Authorities did not provide a reason for the postponement.
But the oil ministry previously said in a report that Iraq has been unable to lure enough bids from foreign or local companies for oil and gas projects due to lack of security.
The Akkas field, which has estimated reserves of more than 2.15 trillion cubic feet, is located in the former Sunni insurgent stronghold of Anbar province. Development of the Akkas field could boost the economy in Sunni areas, where support for the government remains tenuous.
Early this year, the ministry said it was negotiating with Royal Dutch Shell PLC to conduct output tests for the field, which has five wells that are ready to be interconnected.
It could produce up to 50 million cubic feet a day as a first stage. That could be increased to 500 million cubic feet a day, which could be pumped through Syria and Turkey to consumers in Europe.
The ministry also postponed until May 18 bids for a separate tender to help construct two oil pipelines to link the Basra oil fields in southern Iraq with Iran's Abadan refinery. The project's aim is to export crude oil and import refined petroleum products through Shatt-al-Arab waterway.
Iraq has the world's third-largest oil reserves with an estimated 115 billion barrels, and it also sits on an estimated 112 trillion cubic feet of natural gas reserves.
Most of the country's vast petroleum wealth is located in the Kurdish north and the Shiite south.
Group Inc. on May 21 announced that it will provide equipment and technology to Foster Wheeler for the Saudi Aramco Manifa Arabian Heavy Crude Program, in Saudi Arabia. The development of the Manifa oil field, located in the Persian Gulf, includes construction and expansion of new processing infrastructure to handle an additional 900,000 bpd of Arabian heavy crude. The project is planned for a 2011 completion.
NATCO will supply the world's fifth-largest crude oil field with advanced dehydration & desalting technology including design and fabrication of six trains treating a total of 900,000 barrels per day (bpd). Each train will be comprised of one TriVolt dehydrator and two TriVolt desalter units for a total of 18 vessels.
NATCO has been supplying the TriVolt technology to Saudi Aramco for over thirty years. The equipment design includes flexibility for future capacity increases by up to fifty percent through a retrofit to NATCO's Dual Frequency electrostatic technology.
This contract, which was awarded in first quarter 2008, follows NATCO's recent announcement regarding the joint venture with Al-Rushaid Petroleum Investment Company for the NATCO Jubail Fabrication Facility which is scheduled to be operational by February 2009, and highlights the market opportunity for NATCO technologies in the Saudi Arabian market. All 18 NATCO vessels for this project will be fabricated within the Kingdom of Saudi Arabia.
The private energy firm Dana Gas and the Emirates General Petroleum Corp. announced the completion of a 1 billion cubic feet per day common user gas pipeline.
Dana Gas and a consortium of end-users from the United Arab Emirates signed a memorandum of understanding in January 2006 to begin work on the 20-mile pipeline in the emirate of Sharjah.
Dana Gas and the Emirates General Petroleum Corp., or Emarat, both hold a 50 percent stake in the project. Engineers completed the first phase of the pipeline in May 2006.
"This strategic partnership has set an example for further regional cooperation, and will elevate the level of service provided to the end users of this vital pipeline," said Dana Gas General Manager Rashid Al-Jarwan in a news release.
The pipeline connects the Sharjah gas hub in northeast United Arab Emirates to the Al Hamriya Port in the emirate of Dubai.
Acting Emarat General Manager Jamal Abdul Rahman al-Medfa said the project completion is in line with a series of accomplishments in the region, adding he was "delighted" with the joint effort "and the existing level of cooperation between the public and private sector" on the pipeline.
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