Brazil hopes that pre-salt development will proceed undeterred, while Argentina offers incentives to help meet its rising demand.
Peter Howard Wertheim and Dayse Abrantes, Rio de Janeiro
The oil and gas sectors of Brazil, Colombia, Argentina and Venezuela were caught at very different stages of evolution when the present international slump hit the industry at dizzying speed and put a crimp on projects. Authorities in Brazil, which occupies roughly half of South America, refuse to acknowledge that low oil prices might jeopardize ultra-deepwater pre-salt E&P projects that could vault the country into being one of the top 10 oil exporters and change the region’s geopolitical balance. Colombia, a country friendly to foreign investors, was starting to experience growth in its oil and gas industry. The government’s recent success against left-wing guerillas in a four-decade-old civil conflict promised long-awaited economic stability.
Argentina was following a semi-nationalistic path with price controls on oil and gas, but high inflation and the need to increase production forced the government into a quick turn-around, and it offered incentives such as tax rebates, which were readily accepted by the oil industry. Venezuela’s nationalization, along with its possession of majority stakes in JVs with IOCs, did not bode well for the development of its projects. Although China and Russia have become strong economic partners of Venezuela, because the country’s economy is overwhelmingly dependent on oil revenues, it will probably be the most affected by diving oil prices.
HOPES STILL HIGH FOR BRAZIL’S PRE-SALT
Brazil’s newfound geopolitical importance became especially clear after an initial discovery of major new pre-salt oil and gas reserves offshore in the Santos Basin in 2007 was quickly followed by other pre-salt finds.
By mid-2009, Brazil’s proved oil reserves could nearly double from the current 14.4 billion boe with production coming online from the estimated 5-8 billion-bbl Tupi Field - the country’s breakthrough pre-salt oil discovery - and the 3 billion-bbl Iara find, both in Block BM-S-11 of the Santos Basin.
Unofficial estimates soared to 50 billion bbl, with talks about a pre-salt cluster of fields making headlines in a world reeling from oil priced at over $150/bbl, Fig. 1. These reports placed Brazil in the ranks of big reserve holders like Nigeria and Venezuela.
 |
|
Fig. 1. Location of Brazil’s pre-salt cluster.
|
|
However, the dramatic drop in world oil prices may jeopardize Brazil’s short-term pre-salt bonanza. According to Brazilian Chief of Staff and Petrobras Chairman Dilma Rousseff, the country faces two main challenges concerning the pre-salt layer: keeping investments planned for drilling and preventing the country from falling victim to the so-called “curse of oil” - economic dependency on oil reserves.
A former mines and energy minister, Rousseff emphasizes that exploring the pre-salt should not be pushed off into the future. “The pre-salt is supposed to be explored right now, and it is a key tool for positioning Brazil within the resumption of economic growth,” she said.
To assure economic development and employment, Rousseff said, Brazil will launch tenders to hire rigs and supply boats, sign long-term contracts for services and offer support for the expansion of the naval industry capacity.
Petrobras President José Sergio Gabrielli also expects pre-salt development to move forward quickly despite the recent downturn in crude prices. “Pre-salt development is viable at $35 oil,” Gabrielli said at a recent press conference.
Rousseff told reporters that a prolonged, 30,000-bpd production test is scheduled at Tupi Field in March 2009. The test is expected to set the stage for pilot production forecast at 100,000 bpd. The early production first requires investments of $4.5 billion, Rousseff said.
Proposed regulatory changes. Mines and Energy Minister Edison Lobão told World Oil that an inter-ministerial commission will “soon” send proposals to President Lula for changing regulatory measures related to the pre-salt. Although the minister would not go into details, local analysts believe the government will present a bill to Congress next year to change the concession model to profit-sharing for the pre-salt areas.
Asked about details of the new regulatory model, Lobão said, “I don’t know yet; I have only one vote.”
In addition, Lobão favors the creation a second oil company on the model of Norway’s Petoro. Under that model, the government would maintain direct control of pre-salt fields under production-sharing agreements, with the government and private companies working together to explore and develop oil deposits.
Also, a sovereign fund would be created with oil proceeds that would be used to fund further development as well as social projects to mitigate Brazil’s widespread poverty.
Deepwater rig delays. Meanwhile, the fledgling Brazilian deepwater drilling rig industry is running up against the realities of the tight credit market. Several of the contract winners haven’t been able to borrow money needed to finish construction on the rigs they promised, which can cost more than $600 million each. Should their struggles continue, Brazil’s hopes to increase production by 2 million boe/day by 2015 are at serious risk. A crucial 12-rig program was budgeted to cost about $8 billion for Petrobras to carry out the promised development push on the pre-salt discoveries.
Petrobras postponed construction tenders for 28 deep-sea drilling rigs to 2009, said Jose Jorge de Moraes, Jr., general manager for new business at the company’s E&P department.
Jubarte test a pre-salt milestone. A long-duration test with production of 10,000 bpd of 28°API light oil and 17.7 MMcfd of associated gas marked the first production from pre-salt in September 2008 at Jubarte Field, Fig. 2. The field lies north of the Campos Basin, some 48 mi off the southern coast of Espírito Santo state on Block BC-60 in 4,341 ft of water.
 |
|
Fig. 2. From left to right, Brazilian Mines and Energy Minister Edison Lobão, Chief of Staff Dilma Rousseff, the FPSO P-34 operator, Petrobras President Jose Gabrielli and Brazilian President Luiz Inácio Lula da Silva at the startup of the first pre-salt oil production at Jubarte Field. Courtesy of Petrobras.
|
|
Gabrielli said the first pre-salt oil in Jubarte will leverage the development of the other pre-salt wells the company has in the Espírito Santo, Campos and Santos Basins: “This well will teach us what to do in Tupi, Jupiter and Carioca.”
Production in the pre-salt layer in Espírito Santo was predicted based on the 36,000 bpd of 17°API heavy oil Petrobras was already producing from reserves estimated at 600 million boe in Jubarte’s post-salt layer. Most of the needed infrastructure was already in place, and the distance from the reservoirs to the coast is shorter than the distance from pre-salt reservoirs in the Santos Basin to São Paulo or Rio de Janeiro.
Anadarko strikes pre-salt oil. Anadarko recently announced the first pre-salt discovery off Brazil by a company other than state-run Petrobras.
With a 30% stake, Anadarko operates Block BM-C-30 in 4,650 ft of water depth off the coast of Espírito Santo in partnership with Devon (25%), EnCana Brasil Petroleo Ltd. (a unit of Bharat Petro Resources Ltd. and Videocon Industries, 25%) and SK do Brazil (a subsidiary of South Korean SK Energy, 20%).
Preliminary results at Well 1-APL-1-ESS in the Wahoo prospect indicate 195 ft of net pay with similar characteristics to Jubarte. The well is about 25 mi southeast of the Jubarte 1-ESS-103A well.
Outside the pre-salt cluster. There are 470 blocks undergoing exploration after nine auctions organized by Brazil’s regulator, the National Petroleum, Natural Gas and Biofuel Agency (ANP), since 1999.
According to ANP, Brazil’s average 2.2 million boe/day output during October 2008 was produced by 284 fields in 10 basins. However, more than 80% was produced from 40 fields in the Campos Basin, where foreign companies have four concessions: Repsol-YPF shares production with Petrobras in Albacora Leste Field, Royal Dutch Shell works with Petrobras in Bijupira and Salema Fields, and Devon Energy and SK do Brasil have a 60/40 deal in Polvo Field.
There are 86 fields producing in the Reconcavo Basin in Bahia state, all of them operated by Brazilian companies, mostly Petrobras.
The Potiguar Basin in Rio Grande do Norte state has 64 producing fields, mostly onshore, and is the country’s third-largest producing province. There are three fields producing from partnerships between Petrobras and Unopaso, which is an association between Unocal and El Paso oil companies.
Espírito Santo has 42 producing fields on- and offshore, and is Petrobras’ second-highest producing state, with output of 3.00 Bcfd of gas and about 110,000 bopd - up greatly from 30,000 bopd in 2006.
While Sergipe-Alagoas Basin in the northeastern coastal area has 36 producing fields, the famous Santos Basin has only three producing fields.
The three producing fields at Solimões Basin, in Amazon state, are second only to the Potiguar Basin’s onshore fields in terms of volume produced, and the oil from Urucu Field in Solimões is very light.
The remaining producing fields are in Tucano Basin (five) and Camamu Basin (one), both south of Bahia state, and in Ceará Basin (four) in the northeastern state of the same name.
Production development is taking place in 67 fields in Brazil, 19 of them in the Campos Basin.
Chevron expects to begin production at Frade Field in the Campos Basin during second-quarter 2009. As operator, Chevron holds a 51.7% stake; Petrobras has 30% and Frade Japan, 18.3%. Chevron plans to drill six wells and expects production to reach 85,000 bpd in 2011.
Chevron executive George Kirkland said the dynamically positioned drillship Noble Leo Segerius will drill the wells, with target depths of 8,668-12,464 ft.
At Santos Basin, 12 fields are in production, including a partnership of Shell, Chevron and Petrobras in two fields and between Petrobras and Norse Energy in another two fields.
Shell Brasil has stakes in four blocks under exploration in the Santos Basin. On another block, BM-S-54, where Shell owns a 100% interest, the company announced plans to start drilling below a salt layer at the end of 2009.
No investment reduction. Petrobras E&P Director Guilherme Estrella, a renowned geologist and former head of Petrobras’ R&D center, has said several times that there are no technological barriers to the pre-salt activities.
“Petrobras is not thinking about reducing investments nor excluding any projects,” Estrella said, echoing statements by President Lula and federal officials. Petrobras’ current five-year plan through 2012 has an investment budget of $112 billion, which does not include pre-salt investments.
According to Estrella, the business plan for 2009-2013, yet to be released, will not decrease investments and will include pre-salt projects as new investments.
The US dollar’s appreciation against the real will offset weaker oil prices, company CFO Almir Barbassa said at a press conference in Rio de Janeiro. Petrobras made a record $4.9 billion in net profits in third-quarter 2008. “We don’t lose as much as a company that sells its products only to the domestic market,” Barbassa said.
In 2008, Petrobras exported an average 574,000 bpd of crude, of which some 65% was shipped to the US, 24% to China, 5.5% to Europe and 5.2% to other South American countries.
Petrobras lost its upstream monopoly in 1997, causing a rush of foreign oil companies. About 50 IOCs have concession areas in the country, most of them in partnership with Petrobras. The company’s economic, financial and operational results show that even in the competitive scenario of the last 10 years, the net profit jumped from $1.533 billion in 1997 to $21.512 billion in 2007, a whopping increase of 1,330%.
Last year’s exploration success was of 59%, with 64 of 109 exploration wells drilled finding oil or gas.
Petrobras is also planning to export refined products, but needs to build five refineries in Brazil to expand the production of gasoline, diesel, fuel oils and aviation fuel. Petrobras has 15 refineries, 11 in Brazil and four abroad, including a partnership with Astra Oil Trading NV in Pasadena, Texas. However, the most recent Brazilian refinery was built in 1980.
Plans to increase production. Gabrielli says Petrobras intends to increase production from 2.4 million boe/day, which includes about 200,000 boe/day abroad, to 4.1 million boe/day in 2015.
In addition to the March 2009 extended well test at Tupi, production will start in 2009 on Frade Field, operated by Chevron, and the Parque das Conchas fields, operated by Shell, both in the Campos Basin with capacity at each to reach 100,000 bopd.
The government recently announced a pilot project for Tupi to begin producing in fourth-quarter 2010, with capacity to reach 100,000 bopd. Estimated costs for the project are as high as $4.5 billion. Cachalote and Baleia Franca Fields, in Espírito Santo Basin, will begin producing to the FPSO Capixaba in 2010, with capacity for 100,000 bopd by 2010.
By 2011, Module 3 of Marlim Sul Field in the Campos Basin has capacity to reach 100,000 bopd with the arrival of the P-56 platform, and Jubarte Field will ultimately have capacity for 180,000-bopd production.
Also in Campos Basin, production is planned by 2012 on Module 3 of Espadarte Field and Module 4 of Roncador Field (to platform P-62), each with capacity for 100,000-bopd output. Petrobras is also planning two additional 100,000-bopd-capacity pilot programs for the Santos Basin pre-salt by 2012, in the Iara and Guará prospects.
COLOMBIA’S OIL AND GAS BOOM
Colombia is now the “most popular” country in Latin America for foreign investment in oil and gas production, according to Armando Zamora, director-general of the Agencia Nacional de Hidrocarburos (ANH), the country’s hydrocarbon regulator.
Investment rose to $3.5 billion last year from $1.8 billion in 2006, and is expected to reach $5 billion this year. Zamora hopes to lift oil production to 1 million bpd in the next decade, from 531,000 bpd in 2007.
Although that year state-owned Ecopetrol certified reserves of 1.4 billion boe, Colombia’s energy ministry issued a statement saying that the heavy oil area alone could hold 20 billion bbl of recoverable resources.
There are 470 active exploration, development and production projects in Colombia, with 123 exploration wells drilled from January through October 2008.
Castilla, Tenay, Tello, La Cira, Casabe and Orito are the main fields operated by Ecopetrol alone, while Rubiales, Nare, Cosecha, Caricare and Caño Limón are operated by Ecopetrol in association with private companies.
Last September, French oil company Maurel & Prom signed an E&P contract with ANH covering the 914-sq-mi Muisca area in the Eastern Cordillera region, 62 mi northeast of Bogota. The company committed to shoot 62 mi of 2D seismic and drill one exploration well during the next 2 years.
In early December, Gran Tierra Energy completed Costayaco-6, a new well in Costayaco Field, in the Chaza Block, in the Putumayo Basin of southern Colombia, encountering oil deeper in the primary reservoir zone than previous wells in the field with an MD of 8,867 ft and a TVD of 8,571 ft. The well is waiting on testing, which is scheduled to begin in late December. The Calgary, Alberta-based company operates Costayaco Field and the Chaza Block with a 100% working interest.
Subsequently, Gran Tierra released a communiqué stating that its $198 million 2009 capital budget is dedicated to further developing Costayaco Field. Four development wells and three workovers are budgeted along with oil and water lines, two pump stations, tank batteries and support facilities. New seismic and the Moqueta-1 exploration well north of Costayaco are also planned.
There are 36 projects in the Caguan-Putumayo Basin, in the Colombian Amazon region. Fourteen additional areas there were scheduled to be auctioned during December 2008, the contracts for which will be signed in January 2009. The basin has 13 exploration contracts signed with private companies covering 1,200 sq mi.
Emerald Energy Plc’s Vigia-6 development well in Vigia Field was completed as an oil producer. The well encountered the targeted Cretaceous Une and Gacheta reservoirs, and tested at an initial stable rate of over 850 bpd with only a small amount of water.
Following the encouraging results in wells Vigia-5 and -6 during the current drilling campaign, Emerald decided to drill another development well in Vigia Field. The company will use about 1,500 ft of the cased wellbore from the unsuccessful Vigia-4 well drilled in 2007.
Meanwhile, fifty blocks received bids in Colombia’s 2008 mini licensing round, out of 102 blocks offered in areas including the Eastern Llanos Basin, the Middle Magdalena valley, the Upper Magdalena Basin and the Eastern Cordillera region. Total investment in the new areas will reach close to $346 million.
“In all of 2008, close to 100 blocks have been awarded with promised investments over $1 billion,” ANH Director-General Zamora told the news service BNamericas.
Bidding companies were from Colombia, France, Argentina, Canada and Venezuela. Ecopetrol took four blocks - Llanos 4, Llanos 9, Llanos 14 and VMM 6. The state company plans to invest $90 million in the blocks over the next three years. The winning companies are expected to sign E&P contracts with ANH in coming months.
ARGENTINA TAKES ACTION TO EXPAND OUTPUT
The US Energy Information Administration (EIA) expects that Argentina’s average oil production will be 770,000 bpd in 2008 and 760,000 bpd in 2009. In the first nine months of 2008, Argentina’s oil output averaged 625,600 bbd and gas output averaged 4.916 Bcfd.
Argentina had 2.6 billion bbl of proved oil reserves as of January 2008, up from 2.5 bbl in 2007, according to EIA.
New incentives. President Cristina Fernández de Kirchner launched the “Petroleum Plus” incentive program in November 2008 to encourage companies to explore for and produce more oil.
After signing a deal with eight IOCs, Planning Minister Julio De Vido said at a press conference that the country’s programs will generate investments of $8.57 billion, of which $6.45 billion will go to E&P and about $2.1 billion will go toward improving refinement capacity and for converting fuel oil into diesel.
The minister said this will boost crude production by 13% over the next 5 years, and that gas producers will invest $1.5 billion between 2009 and 2011 in 18 exploration and production projects that are expected to boost national output by 300 MMcfd by 2012. The gas investments will take place under a separate incentive program called “Gas Plus.”
BP, Chevron, ExxonMobil, Occidental Petroleum, Repsol-YPF, Royal Dutch Shell and Petrobras signed the deal to maintain investment plans and production levels in Argentina during 2009 and to suspend layoffs for 6 months.
New exploration will be carried out in fields including Acambuco, Anticlinal Grande, Cerro Dragon, La Calera, Ramos, Ramos Mejia and Ramos, De Vido said.
De Vido added that new technologies will be used for further development at the already producing Centenario and Senal Picada-Punta Bradas Fields. However, the minister did not give details about these new technologies.
Another 20 projects are under analysis that may benefit from Gas Plus. These projects could increase gas output by an additional 706 MMcfd, he said.
Spain’s Repsol-YPF, the biggest operator in Argentina, controls nearly 45% of the country’s oil reserves and about 40% of its gas market. The company plans to drill three exploration wells offshore Chubut province and one offshore Santa Cruz province in the coming months, launching long-awaited exploration in the San Jorge Basin. The wells will require entrance of a shallow-water jackup into Argentine waters. The same equipment will also drill wells in the Austral Basin.
Repsol-YPF may also drill three exploration wells in the San Jorge Basin for the Aurora project, in addition to one or two wells on the E-2 license in the offshore Austral Basin with Enarsa, Argentina’s state-owned oil company, in the Helix Project. All of these projects are in drilling depths of less than 8,200 ft.
Under the incentive program, the greater the increase in reserves and production, the greater the tax benefits will be for companies, De Vido said, adding that companies will also be able to qualify for reduced value-added and income taxes under the program.
When determining which companies qualify for benefits, the government will measure future reserve and output levels and compare them with reserve and production levels from first-half 2008. For refineries, it will measure future production levels and compare them with the most productive month from 2008. Those companies that surpass this year’s levels will be eligible for the tax benefits.
If they boost production enough, energy companies will be able to use the incentives to reduce export taxes. Construction of a refinery would qualify a company for tax rebates and other income and value-added tax incentives, De Vido said.
Operators plan for 2009. One of the first companies to announce its intent to subscribe to the Petroleum Plus program was Argentina’s No. 2 oil and gas producer, BP-controlled Pan American Energy (PAE). PAE accounts for 17% of the oil and 14% of the gas produced in Argentina. The company said it could invest $2.5 billion to build a new refinery capable of processing 100,000 bpd. PAE signed a letter of intent with the government and is analyzing the project.
Also, Gran Tierra Energy Inc. allocated $10 million in 2009 for work in Argentina’s Noroeste Basin, where it is the largest exploration landholder with interests in eight blocks totaling 1.6 million gross acres.
The company will shoot 162 sq km of 3D seismic on the Chivil and Surubi Blocks to define structural and stratigraphic traps on trend with its 2008 Proa-X1 oil discovery. It will also work over nine wells and upgrade facilities. One development well not included in the budget may be drilled in fourth-quarter 2009, depending on Proa-X1’s production performance. Further exploration drilling is contemplated in 2010 based on results of the 3D seismic program and the development well.
VENEZUELA’S DIVERGING FIGURES
According to Oxford Analytica, oil revenues account for some 90% of Venezuela’s export earnings, more than 50% of the government’s budget revenues and about 30% of gross domestic product. Thus, the impact of diverging figures is very strong, both in Venezuela and abroad.
For example, state-owned Petroleos de Venezuela SA (PDVSA) recently announced that 172 oil and gas rigs are in operation throughout the country, but only 84 were actually used to drill new wells. However, Baker Hughes Inc. counted 76 operating oil rigs in October, of which eight are operating gas fields in Venezuela.
PDVSA officials insist that the oil rig counts by Baker Hughes fail to take into account dozens of other rigs used to clean and improve the productivity of old wells.
State officials say that for security reasons the government now owns and controls more than 50% of the oil rigs operating in the country. So far, PDVSA has purchased 13 Chinese oil rigs, but President Hugo Chavez has signed agreements with Chinese companies to construct a drill assembly plant in Venezuela to supply the country’s needs. Venezuela still secures almost three-quarters of its rigs through contracting with foreign suppliers.
On Oct. 29, the energy ministry announced that Venezuela’s petroleum certified reserves had expanded to 152.5 billion bbl. On the same day, Chavez told the press that Venezuela was producing 3.3 million bopd but would reduce output by 129,000 bopd to comply with OPEC limits.
According to PDVSA, the country produced 3.15 million bopd in 2007. However, OPEC reports the country’s production at 2.41 million bopd. The lowest figure for 2007 was given by the International Energy Agency (IEA): 2.35 bopd. According to BP, Venezuelan production in 2007 was 2.6 million bopd.
Orinoco development. During last November’s official visit to Venezuela by Russian President Dmitry Medvedev, Gazprom formalized an agreement with Venezuela’s energy ministry for the second phase of the joint quantitative analysis and certification of the gas reserves in the Junín-3, Ayacucho-2 and Ayacucho-3 Blocks in the Orinoco oil belt. The first agreement was signed last July.
Although PDVSA holds the exclusive right to produce gas in the country, Chávez and Igor Sechin, a Russian minister, celebrated Gazprom’s participation in exploration of the gas-prone Urumaco-I Block in early November.
The Urumaco-I Block is a part of the Rafael Urdaneta project, which covers an area of almost 12,000 sq mi and is estimated to hold reserves of 23 Bcfg.
In early November, the Escorpión Vigilante platform started to drill for a 15,000-ft target in Urumaco-I, where PDVSA estimates there are 3.8 Bcf of associated gas. Two exploration wells are planned for the 385-sq-mi block.
PDVSA also signed a memorandum of understanding with Russian oil company Lukoil and Russian-British partnership TNK-BP to form mixed enterprises to exploit Orinoco oil reserves, which were nationalized in May 2007.
According to Lukoil’s Vice President Andrey Kuzyaev, the company recently purchased a 320,000-bpd refinery in Italy that can manage Venezuela’s heavy crude, which Lukoil has been exploring together with PDVSA since 2005.
PDVSA’s President Rafael Ramirez said the Orinoco belt contains 1.3 trillion bbl of hydrocarbons, of which recovery of 272 billion bbl is economically viable with the use of existing technology.
According to Ramirez, joint efforts in Orinoco and in the Gulf of Venezuela may lead to the production of 1 million bbl of oil by the end of 2010. The development plan for Orinoco calls for a massive upgrading of the petroleum infrastructure, including refining and storage systems. PDVSA has already signed JVs with a wide variety of foreign oil companies for the Orinoco belt. These earlier joint ventures, which involve ExxonMobil, ChevronTexaco, Statoil, ConocoPhillips and BP, were later changed by Venezuela’s government to grant PDVSA a minimum 60% stake in each.
International bidding round upcoming. Reeling from the slumping oil prices, Venezuela has set up a Carabobo tender for seven blocks in the Orinoco belt.
While PDVSA has said it will require a 70% stake in any JV formed during the round, analysts expect the NOC actually to require its traditional 60% stake. However, PDVSA said that even in this scenario JV partners will have to finance at least 30% of its 60%.
PDVSA reported in December 2008 that 19 companies including majors had purchased $2 million data packages for the round.
Besides creating JVs, the round also calls for the construction of three new heavy crude upgraders in Soledad, Anzoátegui state, with capacity around 200,000 bpd each. The oil ministry expects to sign contracts with winning firms on June 4, 2009.
Analyst reactions to the round have been mixed. While some think that Venezuela will have a tough time attracting serious investment in the midst of worldwide financial crisis, others expect companies to jump at the chance to add proved reserves. 
|
THE AUTHORS
|
|
|
Peter Howard Wertheim is an international journalist based in Rio de Janeiro covering the oil and gas industry in Brazil and other Latin American countries for the past two decades. He did post-graduate work in literature at the University of Essex, Colchester, UK. Mr. Wertheim is co-authoring a book about Brazil’s oil industry in an international context with his wife, Dayse Abrantes. He can be reached at peterhw@frionline.com.br.
|
|
|
|
Dayse Abrantes is an independent journalist based in Rio de Janeiro, Brazil, and a contributing editor for World Oil. She studied at Chaffey College in Claremont, Calif. She can be contacted at daysew@frionline.com.br.
|
|
|
