General Interest — Quick Takes
NGSA, AXPC chime in on OTC market reform
US House floor action to reform over-the-counter derivatives markets could increase commercial hedging and risk-management costs enormously unless it includes language specifically excluding these activities, two oil and gas association executives warned.
Mandatory clearing of all OTC derivatives could remove as much as $900 billion from a fragile US economy, the presidents of the Natural Gas Supply Association and the American Exploration & Production Council said in a Dec. 4 letter to US House Speaker Nancy Pelosi (D-Calif.) and the Agriculture, Energy and Commerce, and Financial Services committees' chairmen and ranking minority members.
"Mandating centralized clearing and margins is a recipe for unintended negative economic consequences," NGSA Pres. R. Skip Horvath said in a separate statement. "If all estimated hedging transactions are forced into clearing, it could either cost the US economy an estimated $900 billion—the price tag of the entire 2009 economic stimulus package and then some—or force many companies to scale back their hedging, exposing customers to increased commodity and financial risk," Horvath said.
He added, "It would cost the energy industry alone tens of billions of dollars, effectively drive smaller participants out of the market and centralize risk, all at a time when dollars are instead needed to create energy jobs, build infrastructure, and meet environmental goals. That's the exact opposite of the effect that policymakers intend and couldn't come at a worse time for the struggling economy."
An OTC derivatives regulation provision is part of a financial reform bill sponsored by Financial Services Committee Chairman Barney Frank (D-Mass.) that the House was scheduled to consider on Dec. 9.
In their letter, Horvath and AXPC Pres. Bruce Thompson said there needed to be an exemption for energy derivatives used for hedging. Without a clear exclusion, physical natural gas supply agreements risk being defined as swaps and included in a clearing mandate, they indicated.
"Mandatory clearing is too high a price for energy derivatives transactions that do not contribute to systemic risk," Horvath maintained.
DOE's CCS funding includes project in W. Texas
The US Department of Energy will provide $350 million to support a project designed to capture carbon from a proposed electric power plant near Midland-Odessa, Tex., and transport it to the Permian basin where it will be used in enhanced oil recovery, US Energy Secretary Steven Chu announced.
The Texas Clean Energy Project, which will be led by Summit Texas Clean Energy LLC (STCE) of Bainbridge Island, Wash., was one of three efforts receiving $979 million of federal support under the third round of DOE's Clean Coal Initiative. The other two will involve carbon capture from existing coal-fired power plants and storage in deep saline formations in West Virginia and Alabama.
"By harnessing the power of science and technology, we can reduce carbon emissions and create new clean energy jobs," Chu said Dec. 4 as he announced the funding. "This investment is part of our commitment to advancing carbon capture and storage technologies to the point that widespread, affordable deployment can begin in 8-10 years."
The award came nearly 2 years after the Midland-Odessa area lost its bid to become the site of Future Gen, the country's first fully integrated commercial power plant and CCS system, to Matoon, Ill.
STCE plans to integrate Siemens' gasification and power generating technology with carbon capture technologies to effective capture 90% of the carbon dioxide (2.7 million tonnes/year) at the planned 400-Mw plant near Midland-Odessa, DOE's Fossil Energy office said.
The captured carbon dioxide will be treated and compressed, then transported by pipeline to Permian basin oil fields in West Texas for use in EOR operations, it said. The University of Texas's Bureau of Economic Geology will design and assure compliance with a state-of-the-art sequestration monitoring, verification, and accounting program, DOE said. The project is expected to take 8 years.
A second project, led by Southern Co. Services Inc., will receive $295 million of federal funding over 11 years to retrofit CO2 capture equipment on an existing Alabama Power Co. plant north of Mobile for ultimate sequestration in deep saline formations. SCS also plans to explore potentially using this captured CO2 in EOR applications, DOE said.
Sudan seeks police withdrawal from oil regions
A leading member of Sudan People's Liberation Movement has called for immediate withdrawal of Sudan's national police from areas around oil fields in the southern region of the country.
Edward Lino, SPLM chairman in Abyei, told members of the group's liberation council that the presence of Sudanese national police inside Abyei territory violates the so-called Abyei road map and protocols, which aim at securing peace in the region. Lion said the road map and the protocols state that security of the region will be strictly controlled by joint integrated units [JIU] and joint integrated police units [JIPU] and not by one side alone.
"Why are these police forces still deployed around oil installation areas?" Lino asked.
"In the light of this clear provision, I call upon the central government to immediately consider withdrawal of the national police still in Abyei territory so that security of the oil companies, their personnel and assets remains under the control of the JIUs and JIPUs," he said.
Lino's call coincided with a renewed announcement by the semiautonomous government of southern Sudan that it plans to construct a 50,000-b/d refinery in Warap state that will serve the needs of other states west of the Nile River.
The facility will require $2 billion of investment and will take 36 months to complete, said southern Sudan's Energy Minister John Luk, while Minister of Information and Broadcasting Paul Mayom Akech said oil for the refinery will be sourced Block 5A in Unity state.
Luk's announcement repeats statements he made in October, when the government of southern Sudan approved plans to build a $2 billion refinery in Akon, Warap state that would serve all seven states west of the Nile (OGJ Online, Oct. 19, 2009).
Last month, China National Petroleum Corp., apparently shrugging off environmentalists' concerns, signed three oil and gas cooperation agreements of its own with the government of Sudan.
The agreements consist of a memorandum of understanding on the second phase expansion of Khartoum refinery, advance payment for crude trading and an agreement to swap equity between CNPC's Block 6 and Malaysia State Oil's Block 5A (OGJ Online, Nov. 20, 2009).
Exploration & Development— Quick Takes
Husky adds S. China Sea gas find at Liwan
A unit of Husky Energy Inc., Calgary, gauged another large gas-condensate discovery on deepwater Block 29/26 in the eastern South China Sea, near the company's 2006 Liwan discovery from which it hopes to begin gas production in 2013.
Deliverability from the LH 34-2-1 discovery could exceed 140 MMcfd of gas, similar in character to the Liwan 3-1 wells, Husky said.
LH34-2-1, in 1,145 m of water 23 km northeast of Liwan 3-1 gas-condensate field, cut a "significant thickness" of excellent quality, gas-charged reservoir, Husky said. It tested gas with a high liquids content at an equipment-restricted rate of 55 MMcfd.
Excited that its drilling program is validating the company's geological predictions in the little-drilled area, Husky noted that front-end engineering and design for the Liwan 3-1 field development, to which the LH 34-2-1 discovery will be tied in, is at an advanced stage. The company expects to submit a development plan to regulatory authorities in early 2010.
Meanwhile, the West Hercules semisubmersible is preparing to spud another exploratory well on the 551,000-acre block, and Husky plans to appraise LH 34-2 in early 2010. CNOOC Ltd. has the right to participate for up to 51% working interest in the Liwan development.
PetroKamchatka drilling in Far East Russia
PetroKamchatka PLC, Jersey, Channel Islands, UK, is drilling its first exploration well on the Tigil block on Far East Russia's Kamchatka Peninsula and plans to begin trading this month on Canada's Toronto Stock Exchange.
Incorporated in December 2008, PetroKamchatka has secured seven onshore exploration licenses that total 8.1 million acres onshore on Kamchatka Island. It has identified numerous prospects and leads on modern 2D seismic on the Tigil and Icha blocks.
KNOC Kamchatka Petroleum Ltd., owned 55% by Korea National Oil Corp., and the Koryakia Property Fund, an investment agency of the Koryakia Okrug Administration, Kamchatka, have 50% and 5% interests, respectively, in the Tigil and Icha blocks.
PetroKamchatka, through its indirect interest in CJSC Tigil Exploration, is drilling below intermediate casing set at 1,519 m at its first well on the Tigil block.
CJSC Tigil is required to drill two wells on Tigil, one in calendar 2009 and one calendar 2010. The second well is to spud in spring 2010.
The 2010-11 work programs and budgets on the two blocks are subject to the approvals of the joint venture partner, KKPL, and PetroKamchatka's ability to obtain adequate financing.
Kosmos confirms Odum oil find off Ghana
Kosmos Energy, private Dallas operator, confirmed its 2008 Odum discovery off Ghana, proving the potential of the Campanian play on the West Cape Three Points Block east of giant Jubilee oil field.
The company's Odum-2 appraisal well cut 66 ft of net hydrocarbon-bearing pay in high-quality stacked sandstone reservoirs over a 597-ft gross interval about 4 km northeast of the Odum-1 discovery well. The Odum discovery is 18 km east of Kosmos Energy's Mahogany-1 exploration well and Jubilee field (see map, OGJ, Dec. 8, 2008, p. 40).
Odum-2's 66 ft of net oil pay is in two intervals that appear to be in static pressure communication with the Odum-1 well, Kos-mos Energy said. Odum-2 encountered an oil-water contact 190 ft below lowest known oil in Odum-1, extending the known oil column beyond the deepest oil seen in Odum-1.
Reservoir fluid samples recovered indicate the crude to be of 18-19° gravity. The Atwood Hunter semisubmersible drilled Odum-2 to 8,222 ft in 2,677 ft of water.
Odum-2 confirms the second of Kosmos Energy's four oil and gas discoveries off Ghana, where the company has drilled nine consecutive successful exploration and appraisal wells.
The Atwood Hunter will move to the adjacent Deepwater Tano Block to drill the Tweneboa-2 appraisal well that will evaluate the most recent oil find made by Kosmos Energy and partners. That group is drilling the Mahogany Deep-2 appraisal well using the Aban Abraham drillship.
Drilling & Production — Quick Takes
Aramco targets Manifa start-up in 2013
Saudi Aramco says it has finished 60% of the causeway and drilling island system and installed all offshore jackets in its shallow-water Manifa heavy-oil development project.
The project, which a company newsletter article calls "the largest single offshore crude oil project in Saudi Aramco's history," came under review when oil prices fell last year but is proceeding with start-up delayed by 2 years (OGJ, Nov. 24, 2008, Newsletter). Now scheduled on stream in 2013, the field will be able to produce 900,000 b/d of Arabian Heavy crude, 90 MMscfd of associated gas, and 65,000 b/d of condensate. Project completion is projected for 2015.
The Manifa project includes 27 man-made islands connected by 41 km of causeway in a bay that contains intensive algal habitats and dense beds of sea grass. Marine life in the bay includes pearl oysters, hamour fish, crabs, dolphins, shrimp, and sea turtles.
Aramco said it originally thought 30% of the causeway would have to be open for seawater circulation. Research determined that nearly natural circulation could be achieved with only about 10% of the causeway open, which lowered project costs.
In a Dec. 4 speech in Bangalore, India, Aramco Pres. and Chief Executive Officer Khalid A. Al-Falih said that when Aramco made the decision to develop Manifa field the price of oil was $70/bbl. After the award of initial contracts, the crude price fell to $35/bbl, but costs didn't fall proportionately, and projections for global oil demand were trimmed. "We reviewed the program, and with some execution plan modifications, including deferring completion by 2 years, decided to continue," he said.
Colombia's Rancho Hermoso adds two new pays
Canacol Energy Ltd., Calgary, said its third and last development well of 2009 at Rancho Hermoso field in Colombia's Llanos basin found oil in two previously nonproducing formations and flowed 33° gravity oil at the rate of 3,944 b/d from one of the new pays.
Canacol Energy has 100% operated working interest in the field, and the Rancho Hermosa-5 well is in a southern extension area of the field that has remained undrilled since Colombia's state Ecopetrol discovered Rancho Hermoso in 1984.
The well found oil in Upper Cretaceous Guadalupe and Paleocene Los Cuervos in addition to Eocene Mirador, the regular field pay. TD is 9,578 ft measured depth.
RH-5 penetrated Mirador 40 ft high to prognosis. It found oil pay in Mirador at 8,939-74 ft true vertical depth with 7 ft of net interpreted oil pay thickness and average porosity of 26%, Los Cuervos at 8,990-9,020 ft with 9 ft of net interpreted oil pay thickness and average porosity of 27%, and Guadalupe at 9,037-69 ft with 24 ft of interpreted oil pay thickness and average porosity of 28%.
Guadalupe perforations at 9,042-50 ft flowed at a final rate of 3,944 b/d and 318 Mcfd of gas, natural, with water cut decreasing to 6%, on a ¾-in. choke at 145 psi bottomhole flowing pressure. The interval was tested 24 hr with rate increasing steadily throughout the test. Canacol Energy believes that the produced water is completion fluid.
Unlike production from the Mirador reservoir, for which it receives a tariff for each barrel of oil produced, production from the Guadalupe and the Los Cuervos reservoirs will bring Canacol Energy 25% of gross oil production under the terms of the production-sharing agreement with Ecopetrol.
Libya delays plans to boost oil output
The Libyan government, hit by budget constraints and by current market conditions, has announced a delay of up to 5 years in its previously released plans to raise its oil output capacity.
"Our plan was to reach 3 million b/d by 2012, but because of the market conditions, as well as budget constraints," we delayed it to 2017, said Shokri Ghanem, chief executive officer of Libya's state-owned National Oil Corp. (NOC).
"By 2016-17, we can reach the 3 million b/d target, but we need more budget allocations," Ghanem said on the sidelines of a meeting of oil ministers of Arab countries belonging to the Organization of the Petroleum Exporting Countries. Ghanem said Libya's present production capacity is "almost 2 million b/d" and that his country is meeting its OPEC quota of 1.5 million b/d.
Meanwhile, Ghanem confirmed earlier reports that Hess Corp. has discovered "quite a big filed" of natural gas in the Gulf of Sirte, where it operates together with NOC.
According to Hess, its fully owned subsidiary Hess Libya Exploration Ltd. carried out a successful test of its discovery well A1-54/01 in the Mediterranean off Libya.
It said the A1-54/01 well was originally drilled in the Arous Al-Bahar prospect in 2008 and found hydrocarbons in several intervals with a combined gross section of about 500 ft.
Hess recently reentered and perforated the well over a 300-ft carbonate interval and performed a drill stem test.
The well flowed 27 MMscfd of "good quality" gas and 533 b/d of condensate through a 52⁄64-in. choke, Hess said, adding that the test was performed using the sixth-generation dynamically positioned Stena Forth drillship.
After operations on this well, Hess said the Stena Forth will return to complete the drilling of an appraisal well, A2-54/01, which lies 7 miles northwest of the discovery well.
Well A1-54/01 was drilled in 2,807 ft of water in Area 54, which is 35 miles offshore in the Sirte basin. The Hess unit holds a 100% working interest in Area 54, which it operates under an exploration and production-sharing agreement with NOC.
Processing — Quick Takes
Boiler failure kills Valero refinery worker
Officials of Valero Energy Corp. and regulatory authorities are investigating the cause of what the company described as "a failure of a boiler" that killed one worker and injured two others at the company's 225,000-b/cd refinery at Texas City, Tex.
Killed by the mishap at 9 p.m. Dec. 4 was Tommy Manis, 40, of Alvin, Tex. Injuries to the other workers were described as minor.
Valero said the refinery continued to operate. It said there was no environmental effect to the area.
Shell pulls out of Chinese refinery plans
Royal Dutch Shell PLC reported last week it has withdrawn from talks with China Petroleum & Chemical Corp. (Sinopec) and Kuwait Petroleum Corp. that were to lead to construction of a $9 billion, 300,000-b/d refinery in China's Guongdong province.
A Shell spokesperson told OGJ that, due to "strategic and commercial considerations, Shell has decided not to pursue the downstream opportunity currently in discussion between KPC and Sinopec."
Regional media speculation agreed that the move opens the way for other international oil companies to join the joint venture. In its quoted comments, Sinopec made clear it would retain a 50% interest, leaving any other party to carve out a stake from KPC's 50% interest.
Shell is seen as pulling away from new downstream ventures in favor of more oil and natural gas exploration and production.
A memorandum of understanding is in force between state-run KPC and Sinopec to build the refinery and petrochemical complex that will produce 1 million tonnes/year of ethylene. Kuwait is to supply all the oil for the project.
Chinese government approval for the project is expected in first-quarter 2010.
Kupe gas project off New Zealand starts up
Origin Energy New Zealand Ltd. has begun commissioning the offshore Kupe field with initial production, moving natural gas and liquids ashore via pipeline to a gas processing plant at Hawera (see map, OGJ, July 16, 2001, p. 38).
Full start-up is likely within 2 months, said Andrew Stock, Origin's executive general manager of major development projects.
Kupe gas project participants are Origin (50%, operator), a wholly owned subsidiary of Origin Energy Ltd.; Genesis Energy (31%); New Zealand Oil & Gas Ltd. (15%); and Mitsui E&P Australia Pty. Ltd. (4%)
Paul Zealand, Origin executive general manager of upstream oil and gas, said once Kupe was in full operations, it would provide 10-15%/year of the country's gas demand for 15-20 years. Kupe will produce up to 90,000 tonnes/year of LPG, more than 50% of the country's demand, he said.
Over the project life, Kupe is expected to provide 6.6 billion cu m of gas, 1.1 million tonnes of LPG, and 14.7 million bbl of light crude.
Transportation — Quick Takes
Two more firms join Santos basin LNG scheme
Repsol YPF SA and Galp Energia have joined Petroleo Brasileiro SA (Petrobras) and BG Group to develop front-end engineering and design for the construction of an onboard natural gas liquefaction unit that will operate 300 km off Brazil. The planned site is on Blocks BM-S-9 and BM-S-11 in Santos basin's presalt pole.
The unit is one of the transportation technologies being considered to flow gas produced in the presalt layers, according to Petrobras.
Stakes in the expanded joint venture are now Petrobras holding 51.1%, while BG, Repsol YPF, and Galp each hold 16.3% interests. The JV partners also are partners in Blocks BM-S-9 (Petrobras, BG, and Repsol YPF) and BM-S-11 (Petrobras, BG, and Galp).
The tender for preparation of the FEED for the unit was started last August (OGJ Online, Nov. 18, 2009). Planned installation of the unit will be near the floating oil and gas production units and receive, process, and liquefy as much as 14 million cu m/day of associated gas.
Petrobras also said the unit will store and transfer processed products (LNG, propane, and butane) to vessels, which, in turn, will then transport them to market. The LNG, the company said, will be delivered to regasification terminals, which will vaporize it and inject it into the gas pipeline network.
Petrobras operates LNG regasification terminals in Brazil: in Pecem, state of Ceara, and in the Guanabara Bay, state of Rio de Janeiro (OGJ, July 27, 2009, p. 33).
Petrobras said the unit will allow Santos basin's presalt pole gas reserves to be monetized, "ensuring flexibility to supply the internal market and the possibility of exporting the product in the spot market" when demand in the Brazilian thermoelectric segment is low.
Chevron signs deal for Wheatstone project
Chevron Australia has signed an offtake agreement with Tokyo Electric Power Co. (Tepco) to sell 4.1 million tonnes/year of LNG from the Wheatstone project over a 20-year term.
The heads of agreement is believed to be worth about $90 billion (Aus.).
In addition, Tepco is planning to acquire a 15% interest in the Wheatstone field licenses along with an 11.25% interest in the proposed gas processing facilities planned for Ashburton North near Onslow on the Western Australian coast.
Western Australian Premier Colin Barnett hailed the agreement by noting that his State will benefit from significant new export earnings and from an additional 200 terajoules of domestic gas, which is part of the project program.
Barnett said the Wheatstone project also would bring new development to Onslow in the form of a deepwater port and the establishment of an 8,000 hectare strategic industrial park at the Ashburton North site.
The initial stage for Wheatstone will have a capacity to produce 8.6 million tonnes/year of LNG and will also include the domestic gas plant.
Chevron expects to make a final investment decision on the project in 2011.
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