Nigeria’s May production lowest since 2003
Violence pulled Nigerian oil production in May to its lowest level since early 2003, according to the International Energy Agency’s June Oil Market Report.
IEA estimated average production during the month at 2.01 million b/d, down 245,000 b/d from April.
Production shut-ins in May reached a high of nearly 1 million b/d and averaged more than 800,000 b/d for the month.
IEA estimates Nigerian production capacity at 2.49 million b/d, excluding 545,000 b/d considered long-term shut-in.
During May, the agency said, attacks on offshore vessels and onshore pipelines and pumping stations caused these production cuts:
- Abiteye field, 55,000 b/d, now restored.
- Bomu manifold, attacked twice, 170,000 b/d, now restored.
- Funiwa field, 15,000 b/d, now restored.
- Akri and Oshi fields, 80,000 b/d, now being restored.
- Nembe pipeline leak, 77,000 b/d, still offline.
- Okono field offshore, 65,000 b/d, still offline.
- Tebida field, 40,000 b/d, still offline.
IEA called security of oil industry workers “precarious” and noted that many non-Nigerian service companies have withdrawn from the Niger Delta. It also cited Chevron Corp.’s withdrawal of nonessential offshore workers for a month because of security problems (OGJ Online, May 2, 2007). This month, following political developments seen as potentially disruptive, the UK advised its citizens to leave Bayelsa, Delta, and Rivers states.
IEA said workers’ unions are considering a strike this month to protest oil price increases and the sale of government stakes in two refineries.
MMS announces latest RIK contracts
The US Minerals Management Service will receive more than 3.7 million bbl of oil as royalties in-kind under contracts awarded to four US producers, the Department of the Interior agency said.
Chevron Products Co., Shell Trading Co., ExxonMobil Oil Corp. and Marathon Petroleum Co. submitted the winning bids. They will supply some 3,726,000 bbl over 9 months, or 13,800 b/d, beginning July 1, MMS said.
The RIK program came under fire in Congress. Section 201 of HR 2337 would limit such royalties to purchases for the Strategic Petroleum Reserve. The bill went through markup by the House Natural Resources Committee starting June 6 and was approved by final vote June 13.
MMS said taking royalties in-kind allows it to generate more revenue by reselling it on the open market. The program also reduces regulatory costs and reporting costs and shortens the compliance cycle, MMS said.
In a June 5 letter to Natural Resources Committee Chairman Nick J. Rahall (D-W.Va.), Deputy US Sec. of the Interior P. Lynn Scarlet said the RIK program has generated $28.8 million in additional federal revenue. It also reduced administrative costs by 30% from royalty in-value activities, saving another $2.3 million, she said.
The bill’s provision also would eliminate partnerships MMS has with several states regarding royalties in-kind and end a program under which RIK crude is used to help supply small refiners, Scarlet said.
Quebec authorizes carbon emissions tax
Quebec has authorized Canada’s first carbon emissions tax, effective Oct. 1. An estimated $200 million (Can.) of annual tax revenues will be used to reduce greenhouse-gas emissions and improve public transit, officials said.
The Quebec cabinet approved the tax, which was proposed more than a year ago. Quebec’s Natural Resources Minister Claude Bechard suggested oil companies would absorb the tax rather than pass it on to consumers, but analysts expect retail prices to rise.
The amount of the tax varies according to the amount of carbon dioxide each fuel produces. The tax is to 0.8¢ (Can.)/l. for gasoline, 0.9¢ /l. for diesel, 0.96¢ /l. for light heating oil, and $8/tonne for coal.
Three companies, Petro-Canada Products Ltd., Shell Canada Ltd., and Valero Energy Corp., operate refineries in Quebec.
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Exploration & Development - Quick TakesBP, Noble make deepwater gulf find with Isabela
BP PLC and Noble Energy Inc. hit hydrocarbon pay with their Isabela prospect about 150 miles southeast of New Orleans in the Gulf of Mexico. Isabela lies on Mississippi Canyon Block 562 in 6,500 ft of water and was drilled to 19,100 ft TD. The discovery found “hydrocarbons in two high-quality reservoirs,” Noble said.
The well, which was spud on Feb. 28, has been temporarily suspended pending development plans. The most likely development scenario, says Noble, is a subsea tieback to nearby Na Kika production facility, operated by BP.
Chuck Davidson, Noble Energy chairman, president, and chief executive, said Isabela could add production by late 2009. Noble also has acquired an interest in adjacent acreage with additional exploration potential.
BP operates Isabela with a 66.67% interest. Noble holds 33.33%.
Marathon drills Droshky appraisal well in gulf
Marathon Oil Corp. has completed a successful appraisal of its Droshky discovery on Green Canyon Block 244 in the Gulf of Mexico 137 miles off Louisiana.
The appraisal program consisted of drilling a downdip sidetrack well in about 2,900 ft of water and a lateral sidetrack well.
The downdip sidetrack encountered more than 600 ft of net oil pay, and the lateral sidetrack encountered 300 ft of net oil pay.
The discovery well, which was drilled to 21,190 ft TD, had encountered 250 ft of net oil pay (OGJ, Apr. 16, 2007, Newsletter).
Based on the results of the three well penetrations, Marathon estimates the Droshky discovery holds mean reserves of 80-90 million gross boe.
Preliminary analysis suggests that Droshky holds 30-32° gravity oil, which is similar to that of Troika field. All pay intervals are in the Upper Miocene formation, Marathon said.
The company expects to produce this field via subsea completions through the Troika field production system, 2 miles away and the Bullwinkle platform.
Marathon said production could start as early as 2010 if regulatory approvals and key equipment deliveries are timely.
First Calgary lets contract for Algeria’s MLE project
First Calgary Petroleums Ltd. has let a front-end engineering and design contract to Genesis Oil & Gas Consultants Ltd. for its Menzel Ledjmet East (MLE) project on Block 405B in Algeria.
The FEED study is expected to take 6 months, FCP said.
FCP is working with Sonatrach to develop the block by 2009 under a $1.3 billion development plan. The partners will produce 200 MMcfd of gas from MLE oil and gas field in Algeria’s Berkine basin and will build associated infrastructure (OGJ Online, Feb. 19, 2007).
MLE, which is pegged to hold reserves of 230 million boe, will send gas to a gas plant, field gathering system, and facilities designed to process 230 MMcfd of raw gas on a gross basis along with associated gas liquids and oil. There are proposals to increase the plant’s capacity to as much as 400 MMcfd.
Gulfsands to develop Khurbet East in Syria
Gulfsands Petroleum PLC, London, has suspended for future production the Khurbet East-1 discovery well on Block 26 in Syria after conducting a drillstem test (OGJ Online, Mar. 28, 2007).
During the test, the well flowed 35º gravity oil to the surface at the rate of 478 b/d from a 102-m interval of Triassic Kurrachine dolomite at 3,098 m, the deepest of four reservoirs indicating hydrocarbons. GOR was 2 Mscf/bbl.
Gulfsands said wireline logs in the discovery well indicated 26.4 m of net oil pay in Cretaceous Chilou at 1,319 m and 22.5 m of net oil pay in Cretaceous Massive at 1,917 m. The company also cored 16 m of net pay in Tertiary Butmah at 2,850 m and recovered gas.
It refrained from testing the shallower zones to preserve mechanical integrity of the well for production.
Gulfsands, operator with a 50% interest in the block, will drill the Khurbet East-2 appraisal well immediately to test Cretaceous and Tertiary targets.
It plans to shoot a 3D seismic survey over the Khurbet East structure, a large fault-bound structural culmination with closure mapped at multiple intervals. Areal extent is 15 sq km at the level of the Kurrachine dolomite formation.
The discovery well is 12 km southwest of Souedieh oil field and 12 km south of Roumelan oil field. Development can use existing infrastructure.
Iraq Taq Taq wells flow oil at high rates
The TT-06 appraisal well in Taq Taq field in the Kurdistan sector of northeastern Iraq has flowed oil at an aggregate rate of 18,900 b/d of 48° gravity at a low gas-oil ratio from three unstimulated Cretaceous-age formations.
It is the third appraisal well drilled in the field since 2006 by Taq Taq Operating Co., a joint venture of Genel Enerji AS and Addax Petroleum Corp., Calgary. TT-04 tested at nearly 30,000 b/d, and TT-05 tested at more than 25,000 b/d.
A 105-m perforated Shiranish interval flowed 15,380 b/d, 51 m of Kometan flowed 2,020 b/d, and 10 m of Qamchuga flowed 1,500 b/d on 128/64, 40/64, and 32/64-in. chokes, respectively. TT-06 is the third of a six-well appraisal program.
Addax said it anticipates that “constructive efforts of the Kurdistan Region and Iraq towards finalizing a legal framework will enable the corporation to generate a full development plan for the Taq Taq field.”
Taq Taq field, 60 km northeast of Kirkuk, was discovered in 1978. Two more wells were drilled in the 1990s.
Petrobras, ONGC sign asset swap deal
Petroleo Brasileiro SA (Petrobras) has entered into a swap deal with Oil & Natural Gas Corp. (ONGC), whereby Petrobras will gain participating interest in certain of ONGC’s offshore exploration blocks off India, while ONGC will gain equity in certain of Petrobras’s blocks off Brazil.
This swap agreement marks Petrobras’s first entry into India.
ONGC will have 25-30% equity in three exploration blocks off Brazil. In kind, Petrobras will have 15-40% stake in three deepwater blocks off India.
In Brazil, the blocks are in Maranhão, in the Sergipe-Alagoas basin, and in the Santos basin. In India, the blocks to be explored are in the Krishna Godavari, Mahanadi, and Cauvery basins. All of these blocks are in deep waters and at least one well will be drilled in each basin.
Drilling & Production - Quick TakesOman resumes oil exports following cyclone
Oman lost more than $200 million in the first 3 days of its oil exports’ suspension due to Tropical Cyclone Gonu, an Omani official said on June 11.
The Mina Al-Fahl oil terminal, through which Oman exports 650,000 b/d of crude, resumed oil exports June 9. Now all of the country’s oil ports, including Sultan Qaboos and Sur terminals, are functioning normally.
The unnamed Omani official told the Kuwait News Agency that Omani oil pipelines were not affected by the storm but that it caused extensive damage to the country’s infrastructure, including electricity, communication, and transportation sectors.
Meanwhile, shipments of LNG from the Oman LNG terminal at Sur resumed June 10 after exports were halted earlier in the week as a precautionary measure. Oman LNG exports most of its LNG to Japan, South Korea, and India.
The Sur facility was operating at full capacity on June 10 with the first ship under way since the beginning of the storm, according to an official of Oman LNG.
The resumption of activity at Oman’s oil and gas export facilities followed the general reopening of the country’s main port of Sohar on June 7, after being closed June 6 as the cyclone approached.
The port reopened the morning of June 7 having no major damage, according to Jan Meijer, chief executive of Sohar Industrial Port Co., which operates the facility.
Mubarek infill well spudded off Sharjah
Sky Petroleum Inc., Austin, Tex., said drilling has started on the K2-ST3 sidetrack in Mubarek oil field operated by Crescent Petroleum Co. International Ltd. off Sharjah.
PT Apexindo’s Rani Woro cantilever jack up is drilling the well at the Mubarek K wellhead platform to a target depth of 13,500 ft in the Late Cretaceous Ilam/Mishrif oil reservoir. The well sidetracks the Mubarek K-2 well, drilled to test the Early Cretaceous Thamama reservoir, which produces gas and condensate in the field.
Results are expected in third quarter after testing, Sky said.
The well is the second well in a Mubarek infill-drilling program covered by an agreement Sky signed in 2005 with Buttes Gas & Oil Inc., a subsidiary of Crescent Petroleum, Sharjah. Sky’s commitment is two wells with costs capped at $25 million. It has the option to drill four more wells capped at $12.5 million each.
The first well, H2, had produced 83,692 bbl of oil by Mar. 31, since coming on stream May 16, 2006.
Mubarek, producing since 1974, is undergoing redevelopment after the companies identified attractive prospects from a 3D seismic survey. The field has produced more than 100 million bbl of oil. It has nine wellhead platforms, a production platform with capacities of 60,000 b/d of oil and 150 MMscfd of gas, infield pipelines, and a 600,000 bbl floating storage unit.
Sky’s agreement includes a right of first refusal for exploration of the Sir Abu Nu’ayr prospect off Abu Dhabi. That project is under evaluation.
China’s Jidong field to serve domestic market
Anticipated production from Nanpu block in China’s Jidong field will likely go to the country’s domestic market, according to a Western oil company executive.
Early indications suggest the Nanpu oil is 32º gravity with a sulfur content of 0.1%, according to Paul Wright, project manager for Chevron Corp.’s commercial integration team.
That makes the oil a heavier sweet grade and best suited for processing by China’s domestic refiners, Wright told an industry conference in Singapore. While not involved in the development of the block, Chevron has been drilling in Bohai Bay, where the Nanpu block is located.
PetroChina earlier said its discovery at the Nanpu block, reported to be China’s largest in 30 years, holds proven reserves of 405 million tonnes of oil and 140 billion cu m of gas.
Processing - Quick TakesSinopec to raise product exports through JV
China Petroleum & Chemical Corp. (Sinopec) plans to increase its product exports by joining with two Singapore-based companies, ItalSing Petroleum Co. Pte. Ltd. and AP Oil International Ltd., to produce its brand-name lubricants for Asian Pacific markets.
Sinopec’s automotive lubricants will be made in Singapore by Italsing, a joint venture of Singapore Petroleum Co. and Eni International BV, while AP Oil will make the Chinese firm’s marine lubricants.
Sinopec said it is considering a direct manufacturing presence in the city-state, but will first focus on developing the market through contract manufacturing.
No details were reported on the value of the contract manufacturing deals with the two Singapore companies, but Sinopec said it would initially produce 5,000-7,000 tonnes/year of lubricants through them.
In a separate statement, AP Oil said it has a 5-year contract with Sinopec to blend mainly marine lubricants. It said the volume would vary according to Sinopec’s requirements.
Lyondell lets contract for Chinese chemical plant
A unit of Lyondell Chemical Co. has let a contract to Jacobs Engineering Group Inc. for engineering design services related with Lyondell’s 4.44 billion yuan venture with Sinopec Zhenhai Refinery & Chemical for a propylene oxide-styrene monomer (POSM) manufacturing facility to be built in Ningbo, China.
Jacobs is committed to prepare the technical details of Lyondell’s project design package for what is to be the largest POSM facility in the world.
The facility is expected to produce 274,000 tonnes/year of propylene oxide and 620,000 tonnes/year of styrene monomer. It is slated for operation in 2009.
Lyondell earlier said it is to get a share of the propylene oxide (PO) profitability from the plant in exchange for its POSM technology and overall operating and technical experience, and the two partners will jointly market all PO manufactured by the new facility (OGJ, May 7, 2007, Newsletter).
Iran in early planning stages for Asian refineries
Iranian Oil Minister Kazem Vaziri-Hamaneh said his country is in discussions to store strategic oil reserves in China and to build refineries elsewhere in Asia.
Vaziri-Hamaneh said Iran was in discussions to store crude in China, but he offered few details apart from telling reporters at a news conference: “We have some plans.”
Elsewhere, Vaziri-Hamaneh said Iran is finalizing five Asian joint-venture refinery projects in China, Indonesia, Malaysia, Singapore, and Syria for a total capacity of 1.1 million b/d.
“We are supposed to be the partner in these refineries and also to provide the crude oil for those refineries,” he told reporters on the sidelines of the conference in Malaysia.
Vaziri-Hamaneh did not offer details on the projects, but a National Iranian Oil Co. official said Iran aimed to supply crude to a planned refinery in northern Malaysia.
In April Malaysian officials said discussions were under way over a proposed refinery complex and pipeline across northern Malaysia.
Apart from a 320-km pipeline, they said, plans call for a 200,000 b/d coastal refinery to be built by a joint venture of local firm SKS Development Sdn. Bhd. and NIOC (OGJ Online, Apr. 17, 2007).
Transportation - Quick TakesFinal North Baja gas line EIS completed
Staffs from the US Federal Energy Regulatory Commission and the California State Lands Commission (CSLC) jointly concluded that the proposed North Baja natural gas pipeline expansion project will be environmentally acceptable, the agencies said on June 8.
The project, which has been proposed by a US subsidiary of TransCanada Corp., would be the US portion of a system to deliver natural gas from terminals in Mexico to California and other southwestern US markets. It would be built adjacent to a line which was completed in 2002. A Sempra Energy subsidiary would own the Baja California segment.
The US segment, reviewed by FERC and CSLC, would be comprised of an 80-mile loop of 42-in. and 48-in. line; a 2.1-mile, 36-in. lateral to Southern California Gas Co.’s existing Blythe compressor station; a 46-mile, 16-in. lateral to the existing Imperial Irrigation District El Centro generating station, and other associated facilities.
The agencies issued a final environmental statement and review that were prepared in collaboration with the US Bureaus of Land Management and Reclamation. BLM will use the documents to consider amending the California Desert Conservation Area Plan and the Yuma District Resource Plan, the agencies indicated.
The project’s sponsor said it plans to minimize its impact on the Imperial Dunes Recreation Area by building the pipeline through the dunes within the All American Canal/Interstate 8 corridor.
FERC and CSLC noted that directional drilling would be used to avoid disturbing the Colorado River, All American and East Highline canals beds and banks, and associated wetland and riparian areas. The project’s sponsor has agreed to consult with the appropriate Indian tribes and regulatory agencies before beginning construction, they said.
Illinois-Gulf Coast crude line under study
Enbridge Inc. and ExxonMobil Pipeline Co. are studying a crude oil pipeline that would connect refining centers on the US Gulf Coast with production in the oil sands region of Alberta.
The pipeline under study would carry crude from a hub at Patoka, Ill., to Beaumont, Tex., and on to Houston. Straight-line distances total about 715 miles.
At Patoka, the pipeline would link with Enbridge systems that carry crude from Edmonton and Fort McMurray, Alta., to the Chicago area and eastern Canada.
Enbridge said it and ExxonMobil Pipeline have held discussions with potential shippers about the scope, timing, and value of the proposal. It said the project is targeted to be in service as soon as the end of 2010.
Enbridge is expanding its capacity to carry crude from Alberta.
Its Southern Access mainline expansion, under construction, ultimately will add 400,000 b/d of capacity between Hardisty, Alta., and Flanagan, Ill., near Chicago.
Its planned Alberta Clipper project involves construction of a 36-in. diameter pipeline from Hardisty to Superior, Wis., and the addition of pumping capacity on a new 42-in. pipeline between Superior and Flanagan. It has increased the expected capacity of the project to 450,000 b/d from 400,000 b/d.
In its Southern Access extension, Enbridge would lay a 36-in. pipeline with 400,000 b/d of capacity between Flanagan and Patoka.
Cyprus seeks bids for LNG supplies, gas storage
Cyprus will launch a tendering process for LNG supplies and gas storage infrastructure, according to local reports.
The government will accept tenders for a temporary offshore storage facility as a stop gap and it also is seeking companies interested in constructing a permanent onshore site.
The LNG supplies and gas storage will help Cyprus to reduce carbon emissions within the European Union. Government spokesman Vasilis Palmas was quoted as saying that the Cypriot cabinet had approved both a LNG regasification terminal and gas storage, but did not give a timeframe.
Rows have broken out among political circles in Cyprus, however, on whether it should opt for land-based gas storage or a floating offshore unit. Government officials estimate that an onshore facility could take 5-7 years to complete.
Critics have argued against a floating storage unit, claiming it is a risk as the technology is untested and could be a waste of taxpayers’ money. A floating unit is estimated to take as long as 5 years to implement.
Cyprus is committed to using cleaner forms of energy within the EU by 2009. The island relies mainly upon heavy fuel oil for its electric power generation.