Coup threatens Mauritania’s oil, gas industry
Mauritania’s nascent oil and gas industry, already under threat from the al-Qaeda terrorist organization, is facing more uncertainty following a bloodless coup staged by Army commanders.
The coup began when President Sidi Ould Cheikh Abdallahi fired the country’s top four military officials. According to reports, the officials had been suspected of supporting lawmakers who had accused the president of corruption and disagreed with his efforts to reach out to Islamic hard-liners.
Abdallahi was detained by presidential guard units and held against his will at the presidential palace compound. Meanwhile, a military junta, which took over state radio and television, announced the formation of a new “state council,” led by Gen. Mohamed Ould Abdel Aziz, one of the four generals fired earlier in the day.
A US spokesman issued a statement condemning “in the strongest possible terms” the Mauritanians’ military’s overthrow of the democratically elected government of Mauritania, while European Union Development Commissioner Louis Michel said the president should be quickly released and returned to his post.
In July, Malaysia’s state-owned Petronas said it obtained positive results from its exploration program in Mauritania when a well drilled 2 km away from its original Banda-1 discovery confirmed the existence of “significant” quantities of oil and gas.
Petronas said further exploratory work will be necessary to determine the overall size of the reservoir, but gas resources could be in excess of 1 tcf. Around the same time, al-Qaeda’s North Africa network said it planned to attack interests held by the US, which it said was establishing military bases and seeking control of the region’s energy sources.
China establishes new energy agency
China’s National Development and Reform Commission (NDRC) established a new nine-department government agency, the National Energy Administration (NEA), to secure energy supplies.
Lin Boqiang, an economics professor at Xiamen University, said the consolidation of agencies under NEA signals that China will focus more on energy strategy and planning for sustainable development.
Of the nine merged departments, four were in charge of separate energy sectors, while the other five were involved in policy, development planning, energy conservation, and international cooperation. Responsibility for domestic pricing of energy will be shared by NEA and NDRC. NEA will make proposals concerning price adjustments but will need approval from NDRC and the State Council, while NDRC will consult NEA when it adjusts energy prices.
Apart from pricing, however, NEA will assume NDRC’s responsibilities in several other key areas to include charting energy strategy and policies as well as managing separate sectors for oil, gas, coal, electricity, nuclear, and renewable energy.
NEA will manage China’s strategic oil reserves, including building and releasing such reserves and supervising the management of commercial reserves.
The new agency will have approval of the biggest overseas investments in energy resources and will negotiate and sign energy contracts with foreign governments and institutions.
The Chinese government announced plans in March to create a bureau to integrate energy management, marking the first time it has established a central organization to deal with energy issues since dissolving the ministry of energy in 1993.
Trinidad and Tobago audit shows 30.8 tcf of gas
An audit of Trinidad and Tobago’s natural gas reserves for 2007 shows that the country has 30.8 tcf of gas.
The audit, conducted by Ryder Scott Co., was presented to the Caribbean twin-island nation’s standing committee on energy. It shows proved reserves as 16.997 tcf, probable reserves at 7.883 tcf, and possible reserves at 5.888 tcf. The audit shows a rate of reserves to production ratio of 13 years.
In presenting the audit, Ryder Scott Senior Petroleum Engineer Larry McHalffey noted that there had been a virtual 100% replacement of reserves for 2007. He said, “What this means is: for the entire [year of] 2007, all the gas used in Trinidad and Tobago was replaced. This is a positive sign for Trinidad and Tobago.” Ryder Scott put Trinidad and Tobago’s annual gas use at 1.3 tcf.
The audit also places the Caribbean island’s exploration potential of an additional 31.253 tcf.
The figures do not take into account the recently announced discoveries made by PetroCanada and Canada Superior. McHalffey said Ryder Scott also did not consider the Trinidad and Tobago offshore ultradeep water in assessing the exploration potential. Trinidad and Tobago’s ultradeep has not been explored but is expected to be bid in 2009.
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Exploration & Development Quick TakesPetrobras to begin Tupi pilot production in 2009
Petroleo Brasileiro SA (Petrobras) plans to start oil production from its giant Tupi field in the Santos basin off Rio de Janeiro state in March 2009, the company’s chief executive told reporters Aug. 1 in London.
Jose Sergio Gabrielli said initial output in the pilot project would be 20,000-30,000 b/d. This is expected to rise to 100,000 b/d in 2010.
Tupi, which holds an estimated 5-8 billion bbl of oil reserves, is challenging because it is in a frontier presalt reservoir deeper at 2,100 m than discoveries in the Campos basin and farther in distance: 300 km vs. 150 km for Campos.
Consequently, Tupi also poses logistical difficulties in accessing the deposit, and Petrobras faces rising costs in a tight services market. Petrobras is keen to focus its personnel on developing the field quickly, which could boost Brazil’s current 14 billion bbl oil and gas reserves by more than 50%.
The country’s president has established a group to investigate whether a separate oil company should develop Brazil’s subsalt reserves. It will present its proposal within the next few months, Gabrielli said. He is a member of the group.
Last year, Petrobras announced a business plan of $112.4 billion for 2008-12, but this did not include Tupi. Gabrielli said the company would have to increase its borrowing, and new figures would be unveiled in September or October. Petrobras expects to order 28 new drilling rigs during 2013-17.
Gabrielli told investors the company plans to produce 1.95 million b/d of oil next year, and production will rise to 2.42 million b/d in 2012 and 2.81 million b/d in 2015.
Encore Acquisition drills its first Sanish well
Encore Acquisition Co. recently completed its first well in the Sanish formation of the Bakken shale in the Williston basin.
Currently, Encore is drilling a second Sanish well in Charlson field. That well is expected to be completed in the third quarter. The company plans to drill six wells total in the Sanish this year.
The recently completed Charlson 11-16H well, in Williams County, ND, was brought on stream July 23 at an initial production rate of 1,106 boe/d through 7-in. casing.
Fort Worth-based Encore has a 96% working interest in the well. The company owns 10,400 net acres in the area.
The company plans to add a third rig to drill Bakken and Sanish wells in August. Upon arrival of the additional rig, Encore plans to drill a Sanish well in its Cherry Creek prospect.
Maurel & Prom discovers oil in Gabon
Maurel & Prom has tested 5,510 b/d of oil from the Omko exploration well that was drilled 6 km east of Onal field in Gabon. M&P expects to appraise the discovery by yearend, depending on rig availability.
Oil was produced from two separate intervals, the Kissenda and the base sandstone. Kissenda, more than 56 m, reached 3,050 b/d through a 40⁄64-in. choke with a 595 psi head pressure. Base sandstone, more than 43.5 m, produced 2,460 b/d through a 32⁄64-in. choke with 660 psi head pressure.
In both cases, the oil is 35.7-36.7° gravity, M&P said. The Omko-1 well, formerly named Alonha-C, reached 1,800 m.
The company said the discovery validated the sedimentary basin in the northeast area of Onal field. The company will follow this well with exploration well Alonha B. Other exploration wells are scheduled in this area, among them Alonha A, Onal East, and Maroc, M&P said.
The company will drill exploration well N’Zamo to study the southwestern area of the field. M&P holds 100% interest in the exploration permit Omoueyi, and Gabon has a 15% right of return.
Drilling & Production Quick TakesChevron starts production from Agbami oil field
Chevron Corp.’s Nigerian affiliate, Star Deep Water Petroleum Ltd., has started oil production from Agbami field off Nigeria.
Chevron, which said first oil flow from Agbami field was achieved July 29 from a floating production, storage, and offloading vessel, expects initial production to reach more than 100,000 b/d of oil.
It expects production at the field—the largest deepwater discovery in Nigeria—to increase to 250,000 b/d of oil and natural gas liquids by yearend 2009.
Star Deep Water Petroleum signed the agreement in 2005 to award the contract for the construction of the FPSO vessel for Agbami to South Korea’s Daewoo Shipping & Marine Engineering Corp.
In January 2000 then-Texaco Inc.—since acquired by Chevron—announced the completion of testing on the Agbami-2 appraisal well, which confirmed that “the Agbami structure is a giant discovery with potential recoverable reserves in excess of 1 billion boe.”
It said that “the well test surpassed expectations and, together with other technical data, suggests that the Agbami discovery likely ranks among the largest single finds to date in deepwater West Africa.”
According to Texaco, the Agbami-2 well delineated the discovery announced in January 1999. The initial well, Agbami-1, encountered 420 ft of oil pay in multiple zones. Complete appraisal of the field will require further delineation drilling and technical studies.
Apache, EGPC JV lets Salam gas plant contracts
Khalda Petroleum Co., a joint venture of Apache Corp. and Egyptian General Petroleum Corp., let a contract to Petrofac Ltd. for engineering and procurement services for an additional gas train at the Salam natural gas plant on Apache’s Khalda Concession in Egypt’s Western Desert.
The new facility, expected to come online in late 2010, will be Khalda’s fifth gas processing facility at Salam. It will be built next to the third and fourth Salam gas trains, now under construction.
Apache earlier awarded Petrofac contracts totaling $375 million to construct the third and fourth trains, each of which will have the capacity to process 100 MMcfd of gas and 14,000 b/d of condensate.
In November 2006, Apache reported that EGPC and Egyptian Natural Gas Holding Co. had approved construction of the fourth processing train at the Salam plant.
Apache said the fourth train, along with the recently approved third train, would increase the capacity to process gas from Apache’s Jurassic formation gas reserves to 710 MMcfd of gas and 66,000 b/d of condensate, including access to processing capacity at Shell’s Obaiyed plant.
At the time, Apache said gross production from its Jurassic fields was “512 MMcfd of gas and 18,200 b/d, the limit of existing processing facilities.”
Petrofac last month said it had acquired production engineering firm, Eclipse Petroleum Technology Ltd., for an initial £7 million, with a further payment of as much as £16 million to be determined by “the level of future profitability.” Eclipse will form part of Petrofac’s facilities management.
StatoilHydro delivers oil to FPSO from Vilje field
StatoilHydro has delivered first oil from Vilje field in the Norwegian North Sea to the Alvheim floating production, storage, and offloading vessel. The field is estimated to hold 52 million bbl of recoverable oil.
Production from Vilje is expected to reach a plateau of 35,000 b/d by the end of second quarter.
Marathon Petroleum Norge AS operates the FPSO, which is connected to the field via a 19-km pipeline. The field has two subsea templates and two production wells.
StatoilHydro operates Vilje with a 28.85% interest. This is the first StatoilHydro-operated field on the Norwegian Continental Shelf that is tied in to an installation operated by another operator.
OGX leases Ocean Quest semi for Campos blocks
Brazil’s privately held OGX Petroleo e Gas Participacoes has signed an agreement with Diamond Offshore Netherlands BV, a subsidiary of Diamond Offshore Drilling, for the charter of a third drilling rig.
The Ocean Quest semisubmersible rig, under a 2-year contract, will be used in the Santos basin from the second half of 2009. OGX said the rig can drill as deep as 7,600 m in water as deep as 1,100 m.
OGX last week announced it had contracted two other offshore drilling rigs from Diamond Offshore for 3 years. It said the two rigs also would be used for drilling in the Campos basin as of the second half of 2009.
According to reports, OGX broke an earlier contract signed with Queiroz Galvao Oleo e Gas, a unit of the local industrial conglomerate Queiroz Galvao, for the charter of the Alaskan Star semisubmersible drilling rig.
In early July, OGX announced the signing of a 3-year charter of the Alaskan Star, which Queiroz Galvao Purfuracoes SA purchased in 1995 from Western Co., Houston, for $11.7 million.
Shortly after OGX announced the signing of the Alaska Star, Brazilian federal police raided the home and offices of company founder Eike Batista in a probe of alleged fraud and tax evasion. OGX said the investigation has no relation with the company’s operations and does not represent any adverse effect on its business plan.
Founded by Batista in September 2007, OGX was listed on Sao Paulo Stock Exchange Bovespa in June. According to reports, its initial public offering, one of the biggest ever on the Sao Paulo market, was oversubscribed five times.
OGX is said to hold concession rights in some 21 blocks in the Campos, Santos, Espirito Santo, and Para-Maranhao basins. Company plans call for some $1.3 billion investment in the blocks.
Processing Quick TakesIdemitsu Kosan upgrades Chiba, other refineries
Idemitsu Kosan Co. will spend ¥16 billion to upgrade the 45,000 b/d fluid catalytic cracking unit at its 220,000 b/d Chiba refinery east of Tokyo.
In the face of declining market rates for its fuel oil, the firm aims to increase production of naphtha and propylene, while decreasing production of heavy fuel oil.
After the upgrade, due for completion in April 2011, the unit’s production of heavy fuel oil will be reduced by 200,000 kl./year, while its production of naphtha and propylene will increase by 260,000 kl./year.
In May, Idemitsu Kosan Co. sold 30,000 tonnes of heavy grade fuel oil for loading in early June, described by company and trading sources as likely to be its first spot sale of the fuel in 3 years.
Sources said that Chiba was running at nearly full capacity then and that stocks were high. They said such a rare export compounded pressure on an Asian market already “awash” with supply due to weak Chinese demand.
At the time, the price spread between fuel oil and Dubai crude worsened to minus $27.15/bbl from minus $26.80/bbl, more than doubling year-on-year from the 2007 level of $13.55.
Last November, Idemitsu Kosan Co. said it planned to triple its capacity to export refined products at Chiba and at its 160,000 b/d Aichi refinery.
Reports said the refiner wants to export a combined 3 million kl./year of jet fuel, gasoil, and gasoline, up from current capacity of 1 million kl./year, by reforming pipelines and revamping switching pumps.
After revamping the Chiba and Aichi facilities, Idemitsu Kosan plans to expand the export capacity of its 140,000-b/d Hokkaido refinery and 120,000-b/d Tokuyama refinery.
Pemex finds more refineries, pipelines needed
Mexico’s Petroleos Mexicanos, in a study released to the country’s Congress, has underscored the need for additional refining resources or, lacking them, additional pipelines within the country.
Pemex said construction of a 300,000 b/d refinery in Tula in Hidalgo state would provide the greatest net present value. In addition to the $8.17 billion cost of the refinery itself, investment in associated infrastructure would be $852 million.
The proposed refinery also would require construction of a new $769 million oil pipeline from Nuevo Teapa to the Chicontepec region, while a further $64 million would extend to a new multipurpose pipeline to eliminate bottlenecks.
The study suggested other possible locations for a refinery, including a 300,000 b/d facility in Tuxpan, in Veracruz state, which is supplied at the moment by refineries in Tula and Salamanca with some support from the Salina Cruz refinery.
The Pemex study considered other sites for a new refinery, including Campeche in Campeche state; Manzanillo in Colima state; Lazaro Cardenas in Michoacan state; Cadereyta in Nuevo Leon state; Salina Cruz in Oaxaca state; Dos Bocas in Tabasco state; and Minatitlan in Veracruz state. Absent a new refinery, the Pemex report said, Mexico will need to invest some $1.61 billion in central and western Mexico for a number of new pipelines to complement existing distribution systems.
The suggested lines include: a 310 km, 24-in. pipeline from Tuxpan in Veracruz state to Tula in Hidalgo state; 327 km of 18-in. from Tuxpan to Puebla to Valle de Mexico; 241 km from Tula to Salamanca, Guanajuato state; 225 km from Tula to Toluca in Mexico state; 65 km of 8-in. from Tula to Pachuca, Hidalgo state; 99 km from Valle de Mexico to Cuernavaca; 236 km from Salamanca to Guadalajara; 234 km from Salamanca to Aguacalientes to Zacatecas; and 94 km from Salamanca to Leon in Leon state.
Hellenic lets refinery upgrading contracts
Hellenic Petroleum SA has awarded engineering, procurement, and construction management contracts to Foster Wheeler Ltd. for an upgrading project at the company’s refinery at Thessaloniki in northern Greece. The scope of the project is the production of low-sulfur fuels, which also results in significant environmental improvements.
Foster Wheeler’s scope comprises a 15,000 b/sd continuous catalytic reformer, modification of the existing atmospheric distillation unit in order to switch the operation from high- to low-sulfur crudes and revamp the existing naphtha hydrofiner and crude light ends processing unit to increase the refinery’s processing capacity to 26,000 b/sd for light products.
The project is expected to be completed by yearend 2010.
Transportation Quick TakesAlaska lawmakers grant gas pipeline license
The Alaska Senate on Aug. 1 approved a state license for Trans- Canada Corp. to pursue federal certification for a 1,715-mile natural gas pipeline from the Alaska North Slope to the Alberta Hub in Canada.
The Alaska House of Representatives approved the measure last month (OGJ, July 28, 2008, Newsletter).
Gov. Sarah Palin praised the legislature’s work, noting that this is a first step, and that it does not guarantee pipeline construction. The license is being awarded under the Alaska Gasline Inducement Act. The Senate voted 14-5 in favor of granting TransCanada the license. Under AGIA, TransCanada was one of five companies that applied and the only one that satisfied the guidelines, Palin said previously.
Meanwhile, BP PLC and ConocoPhillips are working on a pipeline proposal called Denali. They announced Apr. 8 plans to build a 4 bcfd gas pipeline that would extend from the ANS to Canada and potentially on to the US (OGJ, Apr. 14, 2008, p. 30).
Shell declares force majeure after Nembe attack
Royal Dutch Shell PLC declared force majeure on its export commitments at its Nigerian Bonny Light terminal after Nigerian militants damaged its Nembe oil trunk pipeline in the Niger Delta.
The Movement for the Emancipation of the Niger Delta (MEND) claimed responsibility for the attacks on two pipelines early on July 28 that forced Shell to shut in the line fed by two smaller lines.
According to Nigerian reports, the main pipeline transports 130,000 b/d of oil to export terminals.
The company did not say how much oil production is reduced or how long it would take to restore supplies. Its force majeure announcement spans July to September supply contracts, but the volume of oil covered is unclear.
The loss is likely to exacerbate already high crude prices. Militants have so far cut Nigeria’s output by almost a quarter to pressure the federal government to increase the level of oil revenue given to their communities and reduce their poverty.
YPFB, Transredes start laying GCC gas line
After earlier delays, Bolivia’s state-owned Yacimientos Petroliferos Fiscales Bolivianos (YPFB) and recently nationalized gas transporter Transredes began construction of the 130 MMcfd Gasoducto Carrasco-Cochabamba (GCC) natural gas pipeline.
The $170 million GCC line will consist of 250 km of 16-in. pipe extending from the gas-producing region of Carrasco to the city of Cochabamba.
GCC is to help solve gas supply restrictions for the industry in Cochabamba, La Paz, Oruro, and Potosi arising from the insufficient capacity of the Gasoducto al Altiplano (GAA).
In May, it was reported the pending construction of GCC would be delayed by up to 90 days due to the nationalization of Transredes.
On June 2, the Bolivian government took over TR Holdings, the holding company that owned half of Transredes. TR Holdings was controlled by Royal Dutch Shell PLC (50%) and Ashmore Energy International (50%).
After the takeover, which gave YPFB 97.378% of Transredes, the Bolivian government said it would pay AEI and Shell $48/share for their interest in TR Holdings. The two firms reportedly are considering plans to sue the Bolivian government.
Meanwhile, to calm uncertainty over the fate of the company’s projects, Transredes’ incoming president and director Gary Daher Canedo said in June that the firm would still meet its investment and expansion commitments.
As part of YPFB, Canedo said Transredes would “prioritize” the GCC construction project as well as the extensions of the existing GAA and Gasoducto Villamontes-Tarija (GTV).
In May, before it was nationalized, Transredes had already completed phase two works on the GVT, raising its capacity to 13.8 MMcfd at a cost of $23.5 million.
Last November, Bolivia’s President Evo Morales inaugurated the phase three expansion works of the GAA, which will connect to the GCC, increasing its transport capacity to 32 MMcfd from 27 MMcfd.
