Brazil sustains period of expansion – exploration and production – Statistical Data Included
Kurt S. Abraham
Despite recent setbacks, Brazil’s E&P sector continues to thrive. Activity is buoyed by good, plentiful discoveries, the widening participation of foreign operators, large field development projects and an extremely supportive government
To say that the last 12 months have been a tumultuous period for Brazil’s E&P industry would be an understatement. At times, the sector has experienced the high est of highs, and at other moments, unbe lievable lows have occurred.
Some of the high points include the overwhelming success of the second licensing round; a string of new discov eries; the announcement last fall of a restructuring plan within Petrobras to heighten its efficiency; and the naming of Jose Jorge de Vasconcelos Lima in March as the country’s new Mines and Energy Minister.
On the negative side, there has been considerable squabbling among politi cal parties in the government over the future of Petrobras, as well as the entire upstream industry. Petrobras also has endured an embarrassing string of acci dents, capped by the tragic, fatal explo sions onboard the P-36 floating pro duction vessel (see sidebar story) that caused the semisubmersible to sink. Ironically, the P-36 accident came just two days after Vasconcelos Lima was sworn in as Mines and Energy Minister.
NATIONAL POLICY/LEASE SALES
As Brazil entered the 1990s, Petro bras struggled to develop all its discov ered oil and gas reserves with limited investment funds. As the situation became more acute in the mid-1990s, the Brazilian government finally took the bold step of ending the state firm’s monopoly of oil and gas activity.
Under a careful, gradual plan, foreign operators were allowed to enter the coun try’s upstream sector. Officials also cre ated a new regulatory agency, National Petroleum Agency (ANP), to oversee control of the sector, replacing supervision previously supplied by Petrobras.
The cornerstone of ANP’s opening of E&P activity to foreign participation has been a system of licensing rounds. To date, two rounds have been held. These occurred in June 1999 and June 2000, with 27 and 23 blocks offered, respectively. In Round 1, 23 of the 27 blocks offered were offshore, including 12 tracts in the Campos and Santos basins. Among a field of 38 prospective bidders, 10 multinationals offered $182 million for rights to 12 blocks. By contrast, Round 2 was far more successful. The 23 blocks offered included 13 tracts offshore (seven in deep water). Of these, only two areas were not sold. Companies paid $264 million for the Round 2 concessions.
A third round is scheduled this month, with 53 blocks slated for bid ding, Fig. 1. Many of the third-round blocks are deepwater tracts, although a smaller proportion is in the Campos basin (compared to the earlier rounds). ANP has set a $150,000 minimum price for the 31 deepwater areas, identified as “A” blocks. The minimum price for 14 shallow-water and onshore areas (“B” blocks) is $100,000, and the beginning rate for another eight onshore tracts (“C” blocks) is $50,000.
Bidding among foreign firms and domestic companies is expected to be spirited. Companies that entered the E&P sector via the first two rounds or through joint ventures and farm-ins with Petrobras included Agip, Amerada-Hess, Chevron, Coastal (now E1 Paso Energy), Devon Energy, Enterprise Oil, Exxon Mobil, Kerr-McGee, PanCanadian Petroleum, Repsol-YPF, Shell, Texaco, TotalFinaElf and Unocal.
Ironically, Petrobras made a strong showing in both rounds, obtaining numerous blocks for itself. In Round 2, Petrobras secured eight of the 10 areas for which it bid. The state company and its associated groups accounted for nearly three-quarters of the money raised from the sale. Brazilian firm Ranier Engineering also did well, bidding alone for four onshore oil fields.
When one considers the acreage that ANP held back from bidding, as well as the tracts that Petrobras won in Rounds 1 and 2, the state firm in effect continues to hold rights to the most promising fields and prospects. This is particularly true for the Campos basin. There is no doubt that opening offshore tracts to foreign operators should increase the discovery rate for new deepwater and ultra-deepwater fields. Nevertheless, some foreign firms have expressed reluctance to enter the Brazilian process. The primary reason involves conditions prescribed by the government under the existing petroleum fiscal regime. These include a special petroleum tax, royalty arrangements and inclusion of several front-end taxes.
More than 30 oil fields have been discovered in the shallow and deep waters of the prolific Campos basin along Brazil’s southeastern coast, Fig. 2. Supporting the theory that the South American and African tectonic plates were once connected, the geology of Campos basin is very similar to that of the Angolan basin.
Seven deepwater fields have achieved giant status, and a major portion of their reserves are in water depths greater than 1,000 m (3,280 ft). According to ANP, Campos basin offshore fields and their onshore extensions collectively hold proven, recoverable oil/condensate reserves of 7 to 8 billion bbl.
Petrobras last September signed a farm-out agreement with Coplex, now a subsidiary of Canada’s Naftex Energy. The contract calls for further exploration of 1,981-s Block BS-3 in the Santos basin, as well as development of the tract’s Coral and Estrela do Mar fields, about 100 mi offshore.
Discoveries. There has been a steady stream of new finds during the last 10 months. Shell said last September that it hit hydrocarbons in its first offshore well drilled in Block BM-C-10 of the Campos basin. Initial indications were found in the upper section of the 1SHEL-1-ESS well. Shell proceeded to drill a deeper section and conduct an analysis of what was rumored to be a sizeable oil find. However, confirmation and details have not been provided.
Meanwhile, in October 2000, Petro bras drilled a large gas find offshore in Block BCAM-40 of the Camamu basin. The 1-BRSA-14-BAS reportedly tapped a reservoir of more than 700 Bcf of gas in 125 ft of water, 16 mi off the coast of Bahia. The well was drilled to a 5,997-ft TD. Pay was found at depths of 3,871 and 4,626 ft, in the Agua Grande and Sergi formations, respectively. Petrobras stated that the field should produce between 70 MMcfgd and 100 MMcfgd, when it is developed.
Amerada Hess struck oil and gas last November in BS-2A on Block BS-2. Although details were not disclosed, the firm said that it had aimed at the target with the best chances of finding hydro carbons, rather than just test the largest structure. On the basis of BS-2A’s results, Amerada Hess began drilling on its BC-8 block during that same month. The company holds a 32% stake in Block BS-2 by virtue of a farm-out by Petrobras in 1998. The latter firm retains a 40% interest.
Such joint ventures have become commonly known as “blue blocks,” and they were farmed out before Brazil’s first licensing round in 1999. Most permits on these tracts are set to expire in August 2001. Meanwhile, on another blue block, Coastal Corp. (now El Paso Energy) hit an onshore gas find last November in the BPAR-10 at a depth of 9,840 ft. The 1-Rio Vora-2P-PR encountered gas in four separate sands of the Permian Rio Bonito formation. Further drilling to a final TD of 12,30 ft was conducted, and additional testing was scheduled. The site is a few miles west of the city of Pitanga in the state of Parana.
In December 2000, Petrobras announced an offshore oil find in the Campos basin, at a water depth of 2,243 m (7,359 ft). The discovery tested 3,000 bpd of 35[degrees]API oil. This is said to be the company’s first find in water depths of more than 2,000 m. Petrobras planned to drill additional wells to deter mine whether the find is commercial. The firm also began the new year in good fashion by striking oil in early January at the 1-BRSA-33-ESS well of the Campos basin. Oil was found in an interval between 9,232 and 9,514 ft. Water depth at the tract is 4,085 ft. Further evaluation was underway. This was followed last month by a find of 35[degrees]API oil in deepwater Block BS-500 of the Santos basin, at a depth 0f 4,920 ft.
In April 2001, Devon Energy and Rep sol-YPF announced discoveries on their respective tracts. Devon said that indications of oil were found in the BPOT-2 Block, in shallow waters offshore northeastern Bahia state. Repsol-YPF reported to ANP, that it struck gas in the BES-3 shallow-water tract offshore Espirito Santo state. Meanwhile, TotalFinaElf begand drilling its first well in the BC-2 Block during February. The company supposedly struck a discovery with the well, but no details have been forthcoming.
Early this year, British Gas was finishing a seismic shoot over its B-11 Block in the Santos basin. ExxonMobil also was drilling its Pelotas basin prospect in Block BP-1. Texaco also began drilling the $1.5-billion Frade prospect early this year in nearly 5,000 ft of water. During second-half 2001, Unocal is to begin an $80-million program in the BC-9 Block of Potiguar basin that contains Pescada Arabaiana field. ENI will hold off operations until 2002, when it has plans for drilling in Blocks BM-POT-1, BM-S-4, BM-C-3 and BM-C-4.
Several offshore field development projects are underway, not all of them operated by Petrobras. Enterprise Oil awarded a $55-million contract last October for a drilling program as part of the Bijupira-Salema field development project. The program is expected to begin in mid-2001 and last two years, with 16 wells provisionally planned. This would include seven production wells and four water injectors at Bijupira, plus three production wells and two water injectors at Salema. The fields are adjacent to each other in the Campos basin, about 55 mi from Cabo de Sao Tome, in water depths ranging from 1,575 to 2,887 ft. Enterprise also awarded a $270-million con tract in April 2001 for provision of an FPSO and subsea equipment. The FPSO will process up to 70,000 bopd and store as much as 1 MMbbl of oil.
Last November, Petrobras signed a financing deal for Albacora oil field. The $170-million deal is with Japanese firms Nissho Iwai Corp. and INPEX, and it finances completion of production development at Albacora. The field is in the Campos basin, offshore the state of Rio de Janeiro. As Albacora Phase II is completed, the field’s output will rise to 150,000 bopd from 50,000 bopd.
In January 2001, Petrobras also received two additional vessels for its Marlim Sul field development. The P-40 floating production platform and P-38 FSO arrived at Guanabara Bay for additional equipment installation before heading to the field site in the Campos basin. Together, the vessels will comprise the first of four so-called production system modules at Marlim Sul. The P-40 can process up to 150,000 bopd and export a maximum of 212 MMcfgd. The first module should go on stream in July and reach peak output in November. When all four modules are complete, Marlim Sul should hit peak output of 360,000 bopd in 2007.
Drilling levels. The entry of foreign operators, coupled with much-higher oil prices, has improved drilling activity drastically throughout Brazil. Wells drilled had fallen to only 240 (for 1.5 million ft) in 1999, from 321 in 1998 (for 1.8 million ft). However, ANP said that drilling rebounded 17% last year, to 281 wells. The outlook this year is for 21% improvement, to 341 wells. Offshore activity is expected to jump 56% higher, to 140 wells.
Petrobras continues to break its own oil production records with impressive regularity. Last September, Brazilian output surpassed 1.34 million bopd, led by an increase to 508,000 bopd at Petrobras’ Marlim field. The company also began exports of Marlim’s crude last year. At Marlim, where water depths range from 2,145 to 3,465 ft, there are 86 wells in operation, controlled from seven production plat forms. The field first went onstream from an early output scheme in March 1991.
Marlim supplies about 50% of Campos basin output and 38% of Brazil’s total oil production. As a whole, the basin began producing more than 1 mil lion bopd in July 2000, representing 78% of national output.
On December 30, 2000, Petrobras shattered its September record by establishing a new one-day output mark of 1,531,365 bopd. The firm also set a monthly average production record in December of 1,458,000 bopd. Credit for the new records was given to additional new deepwater wells at Roncador and Marlim fields. For 2000, the daily output averaged 1.271 MMbopd.
Petrobras produces nearly all of Brazil’s oil, although other sources have begun to establish a small presence. Union Pacific Resources (now Anadarko Petroleum) was the first private operator, producing several hundred bpd onshore. Then, in July 2000, Santa Fe Snyder (now Devon Energy) became the first private offshore operator. The firm’s Carauna field went onstream in the Potiguar basin, producing initially from a single well (CES-124) at about 1,000 bpd of 23[degrees]API crude. The company planned to re-enter three more wells and drill two additional new wells as part of a pilot production program. If all goes well, Carauna field will be fully developed by 2004, with peak output of more than 30,000 bopd.
ANP last October prequalified 56 companies to bid on mature fields relinquished by Petrobras. The firms included 40 Brazilian and 16 foreign companies. Nine firms were disqualified, because they had either failed to submit complete documentation, did not have sufficient net worth or presented excessive indebtedness. A two day auction of 11 separate blocks containing 73 mature oil fields was held on May 10-11. Unfortunately, only two blocks received bids. The winning bids were submitted by the W Washington Company for Block BA-1 ($8.1 mil lion, a 53% premium) and Ranier Engineering for Block AL-1 ($6.7 million).
All the various good news occurring in Brazil’s production sector unfortunately has been somewhat overshadowed by a string of accidents during the last 12 months. In July 2000, Petrobras was fined $28 million by the Parana state government for inadvertently allowing more than 25,000 bbl of crude to escape. The spillage took place at a rupture in a pipeline at the Getulio Vargas refinery, and some of the crude found its way into the Iguazu River.
Then, in March 2001, the much-pub licized explosions occurred on Petrobras’ largest floating production plat form, the P-36 (see sidebar story). The accident killed 11 people and caused the vessel to sink, resulting in the spillage of more than 7,500 bbl of diesel oil.
Less than a month later, yet another oil spill occurred, again offshore. At the P-7 production platform in Bicudo field in the Campos basin, more than 160 bbl of crude oozed from a connection in the production piping while the BI-12 well was undergoing an early morning test. Petrobras temporarily halted production of 15,000 bopd from Bicudo, while the spill was cleaned up and repairs were made to the piping involved.
If these problems were not enough, ANP last December announced that it was preparing a gas well audit for the Campos basin, to see whether or not Petrobras has been “wasting” natural gas through flaring. The audit reportedly was completed in February, but no results have been announced. ANP has the power to punish Petrobras for flaring, if it so decides. According to published reports, the firm could be flaring as much as 210 MMcfgd, or nearly one-third of Brazilian gas demand. The company already has had to pay a 10% royalty on the production cost for about 140 MMcfgd that it flares. There have been allegations that the gas was flared to boost the demand for imports of Bolivian gas, thereby ensuring the feasibility of the Bolivia-Brazil pipeline.
Nearly two-thirds of the blocks offered in the third licensing round this month are deepwater tracts.
Brazil Round 3
Offshore (43 blocks)
Espiritio Santo 7
Onshore (10 blocks)
Espirito Santo 2
ANP’s Toniatti sees busy times ahead for Brazil’s E&P
Concurrent with its decision to open up Brazil’s petroleum sector and end Petrobras’ monopoly, the Brazilian government in 1998 created a new governing body for the industry. This organization, Agencia Nacional do Petroleo (ANP), has embarked on an ambitious program of licensing rounds to encourage upstream participation by foreign firms. Recently, ANP’s director in charge of licensing, blocks, data and other lease sale aspects, Giovanni Toniatti, shared his thoughts with World Oil about his agency’s role in Brazil’s upstream and its future vision.
Question: What is your concept of the role that ANP plays in the overall structure of Brazil’s E&P industry?
Answer: After barely three years of ANP’s existence, a number of developments have been introduced into the Brazilian E&P industry. First, from one sole operator (Petrobras) up to 1998, we now have 34 new E&P companies actively present in the country, represented by most of the international majors, many medium independents; mostly foreign and some newly formed domestic companies. Their participation in the business comes either through partnership with Petrobras or by property acquisitions in the tenders (Rounds 1 and 2).
This massive presence is a clear signal for more investments, for acceleration toward Brazil’s goal of self-sufficiency in oil and gas, and also for the establishment of a competitive scenario that benefits the final consumer. For the purpose of succeeding with licensing blocks, ANP did develop a very efficient database (BDEP–Banco de Dados de Exploracao e Producao). Also, from the very beginning, ANP has encouraged and fostered spec surveys (mainly marine seismic) that have contributed greatly to enhancing the attractiveness of Brazilian prospects.
Q: What are the Brazilian government’s attitude and policies toward E&P?
A: The Brazilian government has implemented a series of steps responding to the demands and needs of the E&P players. One important initiative is the possibility of temporary admission of E&P tools, exempt of duty. Also relevant is the special permission given foreign E&P companies to operate bank accounts in hard currency.
On the other hand, there are still some difficulties to overcome in environmental permitting. The federal environ mental agency-IBAMA–was not fully prepared for the new role of monitoring and inspecting the offshore.
Before the opening of the monopoly, Petrobras, as the national oil company, took care of environmental issues in a “self-regulated” way. Presently, together with Petrobras itself, all new operators are under the rule of the environ mental authority. The sudden surge in demand for permits is causing severe delays in some operations, much to the distress of the companies. This undesirable situation should be overcome by means of close cooperation of all involved authorities (IBAMA, ANP, Navy, among others)
Q: What are some goals that ANP has for Brazil’s E&P industry, either short-term or long-term?
A: The continued fomentation of hydrocarbon exploration was interrupted when Petrobras lost its monopoly. It had been the company’s legal task to update data and information on all of Brazil’s sedimentary basins. Now, it is ANP’s responsibility–as expressed in the Petroleum Law–to promote studies, surveys and research of all sedimentary basins. The law, indeed, establishes a dedicated budget for these activities. However, ANP will not operate any of this.
The Brazilian Geological Survey will be engaged for regional geological and geophysical surveying. Universities and their institutes are going to carry out more specific projects. All of this will be done with the collaboration of consulting companies, Brazilian and international.
Q: In your view, how successful were the first two licensing rounds?
A: The first two licensing rounds were very successful. The second one was better than the first, mainly due to the optimal oil price experienced in mid-2000 which pro vided the industry a good cash situation.
Q: What is the status of the third licensing round?
A: The third round–Brazil Round 3–is being prepared according to the established schedule. It will be held on June 19 and 20.
Q: Besides licensing, are there any initiatives or projects that ANP is leading or contributing to?
A: ANP is planning and organizing the national repository of rocks and fluids (cores and oil samples) for all the country’s territory. It will be placed downtown, in Rio de Janeiro’s harbor area. This facility will be endowed with laboratories and proper facilities for studying and sampling by companies.
Q: What is ANP’s outlook for activity levels in 2001?
A: Our estimate for wells drilled during 2001 is around 90 exploration wells and 340 development wells. The average production for the year will amount to 1.5 million boed.
Q: It must have been very distressing to see the Petrobras 36 accident occur. What steps is ANP taking to investigate the accident?
A: The P-36 accident has been very distressing, indeed. ANP has formed an investigation team, together with the Brazilian Navy. So far, no one of the entities investigating the case has a conclusive result on what really happened.
Petrobras comes to grips with P-36 accident
In the early morning of March 15, 2001, Petrobras experienced every operating company’s worst nightmare: an explosive offshore accident that resulted in 11 deaths and the loss of a major floating production unit. As the world’s largest semi submersible, floating production unit (FPU)–in terms of productive capacity–Petrobras 36 (P 36) had only been producing at Roncador field since May 2000. When the incident occurred, the P-36 was producing 84,000 bopd and 46 MMcfgd. Roncador is 130 km (81 mi) offshore Rio de Janeiro state, in the deepwater Campos basin. The P-36 had been projected to peak by 2002 at its capacity of 180,000 bopd and 170 MMcfgd.
According to company officials and vessel personnel, a pair of explosions rocked the P-36. The initial blast occurred at 22 minutes past midnight within the starboard aft column. This explosion is believed to have taken place between the third and fourth floors, apparently causing the seawater and ventilation pipes to rupture. In turn, the fourth floor flooded, and officials said water probably poured through the main ventilation system into the pump room, the water injection room and the thruster room in the pontoon below. Water flow into the pontoon was responsible for the start of the platform’s listing that eventually reached 27[degrees].
At 39 minutes past midnight, the second explosion occurred inside or at the top of the column. This explosion trapped the damage control team in the column, killing 10 people instantly and leaving another man with burns over 98% of his body. Although rescued by helicopter, he died one week later in Galeao Air Force Hospital, in Rio de Janeiro. The remaining 164 people on board were evacuated to the Petrobras 47 FSO, 12 km (7.5 mi) away. The last person left the P-36 at about 6 a.m.
A series of interconnected compartments continued to flood after the explosions, and the gradual listing of the P-36 carried the platform beyond a so-called “critical angle.” Nevertheless, Petrobras mounted a strong effort to stabilize the vessel. Vents for compartments inside the column and pontoon were closed, and then nitrogen and air were injected into flooded compartments through second deck vents, as well as underwater by divers, through pontoon openings. A total of 21 support vessels, plus the P-23 rig and two European firms specializing in salvage operations-Titan and Smit Tak–were involved in rescue attempts. How ever, a combination of unknown damage in the column and pontoon, and changing weather conditions pre vented these efforts from being completed in time. On March 20, despite all efforts to save it, the P-36 sank to an ocean depth of 1,300 m (4,265 ft).
Post P-36 activities at Roncador.
Petrobras on March 19 established a special commission to investigate causes of the accident. Der Norske Veritas (DNV) also was contracted to pro vide independent review and support. Although Petrobras originally set a report deadline of April 20, DNV asked for a 60-day extension to complete its review. The final report is now due at the middle of this month. Nevertheless, an interim report surmised that natural gas escaped the gas processing system and leaked into the column before igniting. “It has to do most probably with natural gas being in a column where there shouldn’t be gas,” said Petrobras Chair man and CEO Henri Phillipe Reichstul during a briefing at OTC in Houston.
Petrobras now intends to replace the P-36/P-47 development scheme with “Module 1A,” which will have two phases. The first will include installation of a floating unit (FPU) to resume output from five of six wells previously linked to P-36, plus three new producers and three new injectors. The FPU will have a capability of 90,000 bopd, 113 MMcfgd and 90,000 bwpd. It should be onstream by September 2002 and may be either a chartered FPSO or a conversion of the P-47 from an FSO into an FPSO. Neogtiations were underway at press time with potential suppliers.
The second phase will include an FPU that has a 180,000-bopd processing capacity. It will be connected to all 19 wells at Roncador, including the 11 that will be transferred from Phase 1. Gas compression and water injection capabilities will be similar to the original volumes (254.3 MMcfgd and 150,000 bwpd, respectively)designed into the P-36. Phase 2 should go onstream by January 2004.
COPYRIGHT 2001 Gulf Publishing Co.
COPYRIGHT 2001 Gale Group