Brazil’s oil & gas potential continues to grab the industry headlines, with Petrobras confirming more than a score of offshore discoveries, most of them deepwater, in the last 18 months alone. Newcomer OGX confirmed a number of discoveries too, albeit in the country’s shallower waters. It’s not all plain sailing though. Construction delays have stalled some projects lately and another deepwater field was compromised by a subsea blowout. Jennifer Pallanich updates OE’s files on the Brazilian scene.
Petrobras’ discoveries in the deep waters offshore Brazil represent 63% of all deepwater finds off the country in the last five years, according to Maria das Graças Silva Foster, who replaced Sergio Gabrielli at the helm of the Brazilian state operator in February. Despite the level of exploration activity and success, the company is working through some delays that affect its production targets. The company’s 2012-16 business plan attempts to answer a shortfall of 700,000b/d to 1 million b/d on production targets through 2020 that Petrobras set out in its 2011-15 plan.
During an event outlining the 2012-16 plan, Petrobras E&P director José Miranda Formigli said ‘excessive optimism’ had originally informed the schedule for the delivery of new units. ‘Sometimes we were also very optimistic with the production curve that was assigned to some of the reservoirs. And finally . . . we have significant delays on new rigs that should have been arriving in Brazil by 2010 and early 2011, and are still arriving this year. But with this we have a big impact in our production targets for 2011, 2012, and 2013.’
There are other reasons Petrobras reset its production goals, including ‘unrealistic ramp ups’ and optimistic production curves as well as optimistic timing for well construction and interconnection. The company’s 2011-15 business plan assumed production of 4.9 million boe/d in 2020 from its Brazilian operations, while the 2012-16 plan has lowered that target to 4.2 million boe/d.
The delays in drilling rig delivery run from just over 80 days to over 850 days. Petrobras, in its efforts to minimize the chance of further delays in the arrival of drilling rigs, has created new production unit departments in China, Korea, Rio de Janeiro and São Paulo to track progress on the rigs daily.
Graça Foster said Petrobras is watching rigs under construction very closely ‘because the loss in oil is enormous and it cannot happen again’.
While the company works to bring in the drilling rigs that were delayed, it is also focused on the rigs it has ordered in the last 18 months or so. Petrobras awarded the first seven in a series of 28 newbuild drilling rigs with a $4.64 billion contract in February 2011. The first seven are slated to begin operations in 2015 following construction by Sete Brazil and the Estaleiro Atlântico Sul shipyard (EAS) in Brazil. The newbuilds will have an average dayrate of $430,000 to $475,000.
A year after that, Petrobras announced it had approved the award of 21 rigs to Sete Brazil and five to Ocean Rig.
In July 2012, Petrobras finalized the contracts with Sete Brasil for six semi drilling rigs, which are part of the 21-rig package announced in February 2012. Delivery for the semi drillers, intended for drilling up to 10,000m in up to 3000m water depth, is slated to begin in 2016. The rigs will be chartered for 15 years to Petrobras, and Petroserv will operate three. Queiroz Galvão will operate two, and Odebrecht will operate the final rig.
The following month, Petrobras ordered six drillships to be built by Estaleiro Jurong Aracruz, with three each to be operated by Odfjell and Seadrill. The units, to be delivered in 2016, will be used primarily for pre-salt drilling in the Santos Basin. The units are specified to be able to drill up to 10,000m and operate in 3000m water depth.
Also in August 2012, Petrobras signed on for nine drillships to be built in Brazil and chartered to the operator for 15 years. The nine represent the final phase in Petrobras’ plan to order 21 rigs from Sete Brasil. Odebrecht and Etesco are also involved in the contracts. Drillships are slated for delivery beginning in 2016 to drill wells up to 10,000m long in water depths of 3000m. Petrobras expects to use the drillships primarily in the pre-salt region of the Santos Basin.
Petrobras has already seen a bit of production from its pre-salt fields through extended well tests (EWT) since 2009. Earlier this year, the FPSO BW Cidade de São Vicente received first production in the Iracema pre-salt area. The FPSO, which is connected to the RJS-647 well, is in 2212m of water depth. Going online in 1Q 2012, the well was expected to flow for about six months to allow Petrobras and its partners to gather technical data on the behavior of the reservoirs and the oil flow in the subsea lines.
Block operator Petrobras said it expects the well to flow at about 10,000b/d, restricted, during the test phase. Partner BG said all information gathered through the well test would support the development of the final production system in the area, expected to be in operation by the end of 2014 with the installation of the 150,000b/d capacity FPSO Cidade de Mangaratiba. Iracema lies in block BM-S-11, held by Petrobras (65%), BG (25%) and Galp Energia (10%).
Elsewhere in the pre-salt, the Carioca Nordeste EWT to the FPSO Dynamic Producer started in November 2011 at 23,400b/d. Petrobras and its partners were to file a commercial viability announcement on the Carioca area that same month, but the partners requested a delay to the end of 2013 to allow for three additional exploratory wells and an EWT. Petrobras (45%) operates block BM-S-9, containing Carioca, on behalf of BG (30%) and Repsol-Sinopec (25%).
Petrobras had a 216km pipeline installed to serve block BM-S-11. Known as the Lula-Mexilhão gas pipeline, the system connects the Lula field to the shallow water Mexilhão platform. The 18in pipeline can transport up to 10mmcm/d of gas from the pre-salt cluster. The line, which went onstream in September 2011, starts in 2145m of water from the Cidade de Angra dos Reis FPSO in the Lula field and runs to the Mexilhão platform in 172m of water.
Petrobras saw its first well begin producing on a commercial basis in the Santos Basin pre-salt cluster in July 2011 with the 9-RJS-660 well in the Lula field. The well produced an average of 28,436b/d of oil, or 36,322boe/d, to the Cidade de Angra dos Reis. This year, the FPSO is expected to reach a production level of 100,000b/d. A few months prior to that, Petrobras started an EWT in the northeastern part of its Lula field, producing to the BW Cidade de São Vicente FPSO in 2120m of water.
More recently, the FPSO Cidade de Anchieta saw first oil from the pre-salt Baleia Azul field in the Campos Basin. The SBM Offshore-operated FPSO received first oil on 10 September. The FPSO, which is moored in 1221m of water, has the capacity to process 100,000b/d of oil and 3.5mmcm/d of gas. Produced natural gas will be pumped through the Sul-Norte Capixaba pipeline to the Cacimbas natural gas treatment unit on the coast of Espírito Santo.
Under Petrobras’ 2012-16 business plan, a dozen production units under construction are expected to go onstream – to the tune of 1.2 million b/d of increased capacity – between 2012 and 2015. From 2016 to 2018, Petrobras will see seven new systems per year. These steps are intended to help the company reach its 2020 goal of 4.2 million b/d of production onshore and offshore Brazil.
The business plan calls for Petrobras’ E&P Brazil segment to invest $131.6 billion, with 69% of that allocated for production development, 19% for exploration and 12% for infrastructure. Of the $131.6 billion total E&P investment, just over half – 51% – will go to the pre-salt cluster. By 2020, Petrobras expects to see pre-salt production making up 40.5% of Brazil’s oil output. The company has pinned the breakeven range for the first pre-salt fields at $35-$40/bbl.
At the end of 2011, Petrobras declared the Guará field commercial and renamed it Sapinhoá. This field holds an estimated recoverable volume of 2.1 billion boe. The field in block BS-M-9 contains 30°API oil. First oil from the Sapinhoá pilot project is expected in January 2013, with production peaking in 2014. The project is expected to produce 120,000b/d. Based on the experience it has has gained to date from pre-salt activities, Petrobras has been increasing the capacity of units planned for the pre-salt area. For instance, the Sapinhoá north FPSO will have a 150,000b/d and 6mmcm/d capacity.
First oil from the Lula Nordeste pilot is slated for May 2013, with production reaching 120,000b/d and 5mmcm/d of gas.
The pre-salt region figures heavily in Petrobras’ calculations. According to the latest business plan’s production curve, following next year’s anticipated startup of production from the Sapinhoá and Lula NE pilots, Petrobras expects production from Sapinhoá Norte and Iracema Sul in 2014; Lula Alto, Lula Central, Lula Sul, Franco 1, Carioca 1, Lula Norte and Franco 2 in 2016; Lula Ext Sul, Iara Horst, NE Tupi, Carimbé, Aruanã, Iara NW and Franco 3 in 2017; and Franco 4, Sul de Guará, Jupiter, Caracá, and Franco 5 in 2018.
According to co-venturer BG, the partners in Iara expect an EWT in 2013 and to declare commerciality in December 2013; the same targets hold true for the Carioca area.
Part of Petrobras’ production strategy for the pre-salt area, as outlined in PLANSAL, relies on mass-produced FPSOs, with their hulls being built in Brazil. In July 2012, partners in blocks BM-S-9 and BM-S-11 approved $4.5 billion in contracts for the construction of six of eight topside modules for planned replicant FPSOs.
The contracts, which cover the processing plant, utilities and living quarters, went to DM Construtora de Obras/TKK Engenharia, IESA Oleo e Gas, Tome Engenharia/Ferrostaal Industrieanlagen, Keppel Fels do Brasil, Jurong do Brasil Prestação de Serviços and Mendes Jr Trading Engenharia/OSX Construção Naval. At the time, Petrobras said it expected to award contracts for the final two topside modules, as well as integration packages, to the same companies within the next 18 months. Of the FPSOs, six are reportedly slated for the Lula field in block BM-S-11, with two allocated for the Sapinhoá field in BM-S-9.
Two months earlier, Petrobras lined up a series of four VLCC conversions. The VLCCs will become the hulls of the P-74, P-75, P-76 and P-77 platforms, which will operate in the pre-salt transfer of rights area in the Santos Basin. Under the $1.7 billion contract with a consortium formed by construction companies Norberto Odebrecht, OAS and UTC Engenharia, the P-74 conversion will be completed in March 2014, the P-75 in October 2014 and the P-76 and P-77 in 2015.
The work, announced in May 2012, will be done at the Inhaúma Shipyard, which was leased by Petrobras. Following conversion, each hull will move to a different construction site for installation of the production plant and the oil & gas processing modules, along with the integration of the units. Each platform is planned to have production capacity up to 150,000b/d and compression capacity of 7mmcm/d. The units are expected to operate at the Franco and Tupi Northeast prospects, both located in the Santos Basin pre-salt.
Beyond the salt
The Papa Terra project, which entails an FPSO and a TLWP, will see 30 producers and injectors brought online. The project, with 140,000b/d of total capacity, was behind schedule in June, with planned progress of 65% – at late June, according to Formigli, progress was at 52%. First oil has been targeted for July 2013.
Roncador Module 3 is expected to begin production from 17 producer and injector wells to the P-55 semi. Rates are expected at 180,000b/d with peak production slated for April 2015. First oil is targeted for September 2013; Roncador itself has been onstream for years. Roncador Module 4 is expected to begin production through 17 wells to the P-62 FPSO in March 2014. The fourth module is expected to reach similar production levels to Module 3. Peak production is expected in June 2015.
At the same time, Petrobras has opted to postpone certain Campos Basin projects, such as Aruanã and Carindé. Formigli has told investors the reserves are there and EWTs have shown good results, but that the company wants to be realistic about the performance of the reservoir. Any unit placed in the fields would be ‘probably very customized to the location.’ OE