MMS approves Cascade-Chinook FPSO plans
The US Minerals Management Service has approved development plans for the Cascade-Chinook oil and natural gas project in the Walker Ridge area of the Gulf of Mexico. Cascade-Chinook lies 165 miles off Louisiana in 8,200 ft of water.
The project, operated by Brazil’s Petroleo Brasileiro SA (Petrobras), will involve the first use of a floating production, storage, and offloading vessel in the gulf. “The Cascade-Chinook project will be the first production from deep discoveries in the Lower Tertiary trend of the Walker Ridge and Keathley Canyon areas of the gulf,” said Lars Herbst, regional director for the MMS gulf region.
“This is an important step for Petrobras and all oil and gas operators exploring in deepwater Gulf of Mexico,” Herbst said, adding, “The FPSO and many associated first-use technologies lead the way in providing the infrastructure necessary to produce safely in the gulf’s ultradeep water.”
The next step in the development process is the MMS review of Petrobras’s deepwater operations plan, which outlines the specific details and capabilities of the FPSO facility and associated new technologies and must be approved before production can begin.
New MMS committee to revise Indian oil valuation
The US Minerals Management Service published a notice on Apr. 28 that it is forming a committee to consider recommendations for revising the rule governing valuation of oil produced from American Indian leases.
The negotiated rulemaking committee will include representatives from the federal government, Indian tribes, individual Indian owners, and the oil and gas industry, the US Department of Interior agency said. It particularly will make recommendations regarding the oil major portion provision contained in most tribal and allotted leases. Those leases define major portion as the highest price paid or offered at the time of production for the major portion of oil produced from the same field, MMS said. It has begun to take nominations for members.
The agency originally announced its intention to establish a negotiated rulemaking committee in December 2007 when it published technical corrections to the March 1988 oil valuation rule, according to MMS Director Randall B. Luthi. “Those technical corrections and the pending recommendations of the negotiated rulemaking committee will bring added certainty to the valuation of oil produced from American Indian lands and help ensure that American Indians receive the proper royalties,” he said.
MMS published a proposed rule for public comment in February 2006 after a series of public meetings with tribes and individual Indian mineral holders, the agency said. It decided to make technical corrections to the current rule and convene the negotiated rulemaking committee after receiving diverse comments from tribes and the oil and gas industry.
Once the committee reaches consensus on the rule’s major portion provision as well as other provisions the committee might want to address, MMS said it will use that recommendation as the basis for an amendment to the rule, which it also will publish in the Federal Register.
Global warming risks underestimated, report says
The risks of global warming were underestimated in the Stern report on climate change, its author said, and urgent action is needed to address the problem.
“However, I’m optimistic about an international agreement,” said Nicholas Stern at the IHS Energy Symposium in London. He called for global leaders to agree by next year on an action plan to reduce carbon emissions and stem world temperatures.
Stern is hopeful that participants at the next environmental summit in Copenhagen will agree to such action. The 700-page report he wrote examines the economic impact of climate change and says 1.5% of the world’s gross domestic product needs to be invested in stabilizing emissions at 500 ppm by 2050. “We need to move quickly,” he said.
However, deforestation and agriculture are also major causes of emissions, Stern warned, and he called for urgent policies to tackle the problems. Carbon capture and storage for hydrocarbons would be important in reducing carbon emissions as would other energy sources such as nuclear and renewables, he said.
Stern recommends carbon trading and taxation, quotas, and auctions of greenhouse gas emissions, which he says are all necessary to change behaviors.
“Poor countries want flows of finance and the transfer of technology to deal with this. We need a clean development mechanism that is better than this one, which is too small and too micro.”
After publishing the report 18 months ago, Stern, a former World Bank chief economist, was severely criticized for “scaremongering.” He has since met with the Chinese and Indian government to discuss how they can address climate change.
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Exploration & Development Quick TakesATP, Newfield make deepwater gulf discoveries
ATP Oil & Gas Corp. recently participated in drilling two successful exploration wells in the deepwater Gulf of Mexico. One is an oil discovery, and the other is a gas-condensate discovery.
Newfield Exploration Co. operates both discoveries. The Gladden prospect on Mississippi Canyon Block 800 found 80 ft of net oil pay. The discovery well was drilled in 3,116 ft of water, and an updip well is being drilled.
The Anduin West prospect on Mississippi Canyon Block 754 found 30 ft of net gas-condensate pay. The well was drilled in 2,696 ft of water.
The Anduin West well is being completed, and a production test is planned. ATP has a 10% working interest in Gladden and a 25% working interest in Anduin West.
Production from the discoveries is expected to begin in late 2009.
ATP’s Innovator floating production platform will handle the oil and gas from both discoveries. Innovator is moored in 3,000 ft of water on Mississippi Canyon Block 711.
Innovatora semisubmersible drilling rig previously named Midland and owned by Rowan Cos. Inc.was acquired by ATP and converted into a floating production platform.
ATP has 100% ownership of Innovator, which handles production from Gomez oil and gas field.
Ecopetrol to evaluate Tempranillo find in Huila
Columbia’s state-owned Ecopetrol will soon begin evaluating an oil and gas discovery in Colombia’s southern province of Huila.
The find, the Tempranillo-1 well, was drilled in the Upper Magdalena Valley basin and is part of Ecopetrol’s wholly owned 10,184-hectare Brisas-Lomalarga-Dina-Potrerillo block.
“During these tests, crude and gas flowed...without artificial assistance. The crude is light and flowed at rates that varied between 1,600-2,400 b/d,” Ecopetrol said, adding that gas output averaged 2-2.75 MMcfd.
“With the results obtained in the initial tests, Ecopetrol will draft a plan to evaluate the discovery’s potential, including an extensive test period that will begin in the next few weeks,” the company said.
Tempranillo-1 is one of 20 wells that Ecopetrol plans to drill this year. Currently, the company produces about 19,000 b/d in Huila.
North Chilean gas flows tease March Resources
March Resources Corp., Calgary, said it is encouraged by admittedly noncommercial gas flows at its first well in northern Chile’s Tamarugal basin.
The company perforated 16 intervals in four zones to evaluate gas shows and drilling breaks in the Cerro Empexa and Cretaceous Guatacondo formations at the Pica-1 well. Gas is thought to be sourced from underlying Late Jurassic Majala formation black shales. Due to limited equipment, all zones are commingled.
The well’s main targets were at 2,800 m to TD 3,110 m, but two perforated intervals between 2,000 m and TD yielded no pressure increase or gas to surface.
Nine intervals were perforated at 1,500-1,800 m. Gas surfaced from each of the first four intervals perforated, but wellhead pressure was too small to measure. Gas continued to surface from the next three intervals perforated, and a small increase in surface pressure was measured, increasing as each interval was perforated and ending at 210 KPa. Shut-in pressure was 760 KPa 12 hr later.
Two intervals were perforated from the top of the Guatacondo formation at 1,350 m to a depth of 1,475 m. Gas continued to surface, but wellhead pressures started to decrease.
Three intervals were perforated at 1,040-1,150 m. Gas continued to surface, but pressure fell to 450 KPa by the end of perforating.
The last perforating tools contained fluid, but it is not known which zones may be wet or whether the fluid is from drilling or the reservoir. March plans to seek the source of the fluids and will try to establish gas flow from the intervals where it observed definitive pressure increases.
Pica-2 is drilling at 1,450 m in Cerro Empexa, and a third location is being cleared.
The Pica North and South Blocks cover a combined 2.5 million acres.
Uganda’s Kingfisher appraisal well spuds
Heritage Oil Ltd., Calgary, has spud the Kingfisher-2 appraisal and exploration well in Block 3A in southern Uganda’s Albert graben.
Projected TD is 4,100 m. Heritage will deviate the well from shore beneath Lake Albert to appraise reservoirs discovered at Kingfisher-1 and evaluate the deeper primary target it did not reach due to rig limits.
High case estimate for the deeper target is six times that of the most likely 118 million bbl gross volume estimated for the four secondary zones.
Kingfisher-1 tested a combined 13,900 b/d of 30-32° gravity oil with some associated wax from four intervals in 2007.
The Kingfisher structure’s areal extent is put at 45 sq km based on a 325-sq-km 3D seismic survey shot in mid-2007.
Heritage’s 2008 program calls for two wells at Kingfisher in Block 3A and two to three wells on Block 1 targeting relatively shallow seismic amplitude anomalies.
Heritage and Tullow Oil PLC hold both blocks 50-50.
Drilling & Production Quick TakesAddax sees FPSO at Ofrima North off Nigeria
A combination of discoveries at Ofrima North 50 km south of Brass, Nigeria, justifies standalone development with a floating production, storage, and offloading vessel and subsea tiebacks, said Addax Petroleum Corp., Calgary.
Addax said its most recent discoveries “give us the critical mass required to develop a successful new standalone oil production hub” and the potential for future gas exports from OML 137. Production may be possible as early as late 2009.
The Ofrima North discovery well, Ofrima-2, cut 170 ft of gross oil-bearing interval in the H42 reservoir and gas-bearing intervals with a gross 29, 43, and 158-ft columns at shallower and deeper depths in 2007.
Ofrima-3, in 75 m of water in the field’s west fault block 1.5 km west of Ofrima-2, found water in H42 and cut a gross 72 ft comprising 30 ft of light oil overlain by 42 ft of rich gas, a 50-ft gross liquids-rich gas column, and a 32-ft gross light oil column. No flow tests were run.
In the main fault block, Ofrima-3A confirmed the western continuity of the H42 oil reservoir and a common oil-water contact with Ofrima-2 about 1 km east.
The Saipem Scarabeo-3 semisubmersible has moved to drill development wells in Okwori and Nda fields 80 km east, and Addax plans to further explore and appraise the area around Ofrima North.
Petrobras orders three newbuild semis
Petroleo Brazileiro SA (Petrobras) signed three lease contracts with Seadrill Ltd. for three newbuild semisubmersible drilling rigs and a separate contract with MPF Corp. Ltd., Bermuda, for a multipurpose floater. The contracts all involve deepwater projects off Brazil, Seadrill said.
Seadrill said its lease contracts are valued at $4.1 billion total:
- One 6-year contract is for the $542 million West Eminence deepwater semi under construction at Samsung shipyard in South Korea (OGJ, Sept. 24, 2007, p. 41).
- Petrobras also signed a 6-year contract for the West Taurus, a $457 million deepwater semi under construction at the Jurong shipyard in Singapore.
Fourth-quarter delivery is scheduled for both West Eminence and West Taurus. Both contracts call for start-up of operation off Brazil in 2,400 m of water in early 2009. - Petrobras, in addition, signed a 6-year contract for West Orion, a $532 million semi under construction at the Jurong shipyard in Singapore. West Orion is scheduled to be delivered during second-quarter 2010. The start-up of operations off Brazil in 2,400 m of water is scheduled for third-quarter 2010.
In a separate deal, Petrobras signed a $630 million contract with MPF for the 3-year lease of its new multipurpose floater MPF-01 under construction at Dragados Offshore SA’s Cadiz, Spain, shipyard. The MPF production-drillship is scheduled for delivery in late 2009.
Petrobras secured an option to extend this contract for another 2 years, making the total value of a 5-year deal $965 million.
In addition, Petrobras recently signed a memorandum of understanding with Noble Corp. to extend the leases of five deepwater rigs currently drilling off Braziltwo semis and three drillshipsfor a period of 29 rig years at a potential cost of $4 billion (OGJ Online, Apr. 4, 2008).
Processing Quick TakesQP lets work contract for refinery in Qatar
Qatar Petroleum has let an engineering contract to Axens to design processing units for a new 250,000 b/d refinery in the Messaieed Industial City in Qatar that is scheduled to start up by first-quarter 2012.
The Al Shaheen refinery will use Axens’ process technologies to establish a 51,000 b/d Hyvahl vacuum residue desulfurization unit; a R2R 60,000 b/d residue fluidized catalytic cracker (RFCC); and a 30,000 b/d Prime-G+ RFCC gasoline desulfurization unit.
The refinery units, combined with advanced technologies, will make this “one of the most modern refinery complexes in the world,” Axens said.
The Hyvahl unit will improve the feed quality to the R2R unit and will coproduce an upgraded diesel cut, Axens reported. Hyvahl has long cycle lengths on the 11% asphalt containing Al Shaheen VR feed because of the permutable reactor system (PRS) system. The PRS system increases hydroprocessing operations by removing particulate matter and metals in the feed, eliminating pressure drop build-up in the hydroprocessing section, it added.
The R2R RFCC is a “cold-wall construction adapted to maximize gasoline and propylene production,” Axens added, and its Prime-G+ FCC naphtha desulfurization technology will enable the production of ultralow-sulfur gasoline, the company said.
Last year, QP let a lump sum front-end engineering design contract to Technip for the facility. An oil pipeline will extend from Al Shaheen oil and gas field 90 km offshore to Messaieed, 110 km onshore, as well as to other import-export facilities (OGJ Online, Aug. 31, 2007).
SK Energy builds diesel unit at Inchon refinery
South Korea’s SK Energy Co. plans to build a 40,000 b/d diesel-producing hydrocracking unit at its refinery in the port city of Inchon, 40 km west of Seoul. The unit will process heavy oil into transportation fuel.
The project aims to increase exports of lighter, higher-value products to China and Southeast Asia. The new unit will produce naphtha, diesel, and kerosine using low-priced bunker-C fuel as feedstock.
SK Energy said construction on the unit, expected to cost 1.5 trillion won, is scheduled to start in June, with commercial production to go online in June 2011.
The facility will eventually increase SK Energy’s overall heavy oil-processing capacity to 202,000 b/d from the current 162,000 b/d. It also will expand the ratio of SK Energy’s heavy-oil processing facilities to overall refining ones to 17.6% from the current 14.5%.
In March, SK Energy completed construction of a residual fluid catalytic cracker at its 840,000 b/d refinery in Ulsan, 414 km southeast of Seoul.
The 60,000 b/d capacity unit is set to launch operations in June, when SK Energy will be operating three RFCCs with a combined capacity of 162,000 b/d.
Nippon Oil to add to Negishi refinery
Japan’s Nippon Oil Corp., facing reduced domestic demand for oil products, plans to increase exports and to begin mass-producing ethyl tertiary butyl ether at yearend 2009.
The petroleum wholesaler will invest about ¥2 billion at its Negishi refinery in Yokohama to build a facility capable of turning out 100,000 kl/year of ETBE. Demand for ETBE in Japan is expected to reach 840,000 kl in 2010, based on projections for sales of biofuel.
Japan currently imports all ETBE used for biofuel, and domestic production will help reduce transport costs and carbon dioxide emissions. Nippon Oil aims to purchase bioethanol from domestic sources in Hokkaido.
Meanwhile, Nippon Oil, aiming to offset the fall in demand for oil products in the domestic market, will nearly double its oil product exports to 2.7 million kl in the fiscal year started in April.
The refiner will increase its export capacity to 260,000 b/d from 230,000 b/d by the fiscal year ending March 2011, said Nippon Oil Pres. Shinji Nishio.
Shinji said most of the planned exports, mainly kerosine, jet fuel, and gas oil, will be sold to oil traders in the Asia Pacific market.
Lummus taps GTC for BTX extraction unit
Chinese Petroleum Corp. (CPC), Taiwan, will use GTC Technology’s GT-BTX extractive distillation technology as part of its No. 6 naphtha cracker and No. 7 BTX project in Lin Yuan, Kaohsiung, Taiwan.
Lummus Technology (formerly ABB Lummus Global) was awarded the overall contract for the project, which will produce 600,000 tonnes/year of ethylene (OGJ, Aug. 13, 2007, p. 10).
GTC’s technology extracts high-purity benzene, toluene, and mixed xylenes (BTX) from hydrotreated pyrolysis gas.
This is the 20th license of the GT-BTX technology.
Transportation Quick TakesIran, Pakistan resume IPI gas line talks
Iran and Pakistan have restarted talks on the design and construction of the 2,700-km Iran-Pakistan-India (IPI) natural gas pipeline. India, which earlier had reservations about the project, is showing interest as well in becoming a project stakeholder.
The proposed line, which initially would transport 600 million cu m/day of gas, is scheduled for completion in 2011.
Following a recent visit of Indian Petroleum and Natural Gas Minister Murli Deora, a delegation from Iran, led by President Mahmoud Ahamdinejad, visited Pakistan to discuss the project. Ahamdinejad met on Apr. 28 with Pakistan President Pervez Musharraf and exchanged views on bilateral matters, including the IPI pipeline project.
India welcomed the Iranian president’s visit and expressed hope that it would advance the project.
According to Deora, the $7.4 billion IPI pipeline deal would be “clinched soon.” He said India and Pakistan were near reaching a general agreement on the transit fee. Deora added that Ahmedinejad’s visit would be utilized to pave the way for trilateral talks on the deal.
Indonesia’s Seroro LNG start-up delayed again
Indonesia’s planned fourth LNG plant, to be built in Senoro, Central Sulawesi, will begin operations later than expected due to a disagreement over the pricing of gas for the facility.
“We have extended the target for initial production as negotiations on the gas prices have yet to reach an agreement,” said Lukman Mahfoedz, president director of Medco E&P. The project partners are Mitsubishi Corp. 51%, state-owned PT Pertamina 29%, and Medco 20%.
Lukman said the Senoro facility is to start production in first quarter 2012, marking the second delay in the project, which was initially expected to go online in 2010 but was delayed until 2011 amid similar price uncertainties. Upstream regulators are still calculating the budget needed to develop the gas fields that will supply the plant.
Project partners will buy gas from two fields in Senoro. The first, on Toili block, is jointly owned by Pertamina and Medco, while the second, on Donggi block, is wholly owned by Pertamina.
Indonesia operates two LNG plants. The Arun LNG plant in Nanggroe Aceh Darussalam has a total capacity of 12.5 million tonnes/year, while the Bontang plant in East Kalimantan has a capacity of 18.5 million tpy.
A third plant in Papua, designed to have capacity of 7.6 million tpy, is due to begin operations under BP PLC by yearend.
Brazilian firm plans $1 billion ethanol line
Brazil Renewable Energy Co. (Brenco) plans to invest $1 billion to build a 1,100-km, 4 million l./year ethanol pipeline extending from Alto Taquari in Mato Grosso state to Santosthe country’s largest portin Sao Paulo state on the country’s south Atlantic seaboard.
Brenco has applied to Brazil’s environmental protection agency Ibama and the national petroleum agency ANP for the necessary licenses to construct the pipeline. Brenco said its line would not compete with other ethanol pipelines planned by state-owned Petroleo Brasileiro SA (Petrobras).
In addition to the Port of Santos, the pipeline will serve five other proposed terminals at Alto Taquari in Mato Grosso; Costa Rica in Mato Grosso do Sul; Paranaiba in Goias state; and Sao Jose do Rio Preto and Paulinia, both in the state of Sao Paulo.
The announcement was made as construction began on Brenco’s 450-million-real sugar and ethanol mill in Alto Taquari. The facility will process 3 million tonnes of sugar cane and produce 275 million l. of ethanol by 2009.
The Alto Taquari mill will be the first of 10 units Brenco plans to build in Brazil by 2009 having a combined capacity of 3.7 billion l./year of ethanol. All of the output will be carried by the proposed ethanol pipeline, which may also ship ethanol produced by other operators in the region.
In 2007, Brazil exported just over 3 billion l. of ethanol, according to the Brazilian Development Ministry Foreign Trade Department. The Port of Santos handled some 60% of the exports, followed by the Port of Paranagua with around 23%.
The country’s ethanol exports are expected to reach 3.91 billion l. in 2008-09, up 27% from the 3.1 billion l. exported in 2006-07, according to the Union of Sugarcane Industries.
Brazil’s total ethanol production in 2007 was reported to be 20-22 billion l. Production is expected to exceed 100 billion l./year by 2025, according to ICIS Chemical Business.
