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Brazil's mature oil, gas fields hold potential, but reforms still needed: officials

Increase font size  Decrease font size Date:2019-11-07   Views:57
Brazil could dramatically boost oil and natural gas output from mature fields over the next decade, but additional regulatory measures are needed to make the areas attractive to new players as major oil companies shift their focus to development of the country's massive subsalt play, industry officials said last week at the Brasil Offshore Technology Conference 2019.

"The potential is enormous, equal to the potential of the subsalt," Francilmar Fernandes, chief operations officer at Brazilian independent producer PetroRio said at the conference. PetroRio thinks that minimal revitalization efforts in the Campos Basin could add 200,000 b/d by 2025, Fernandes said. "So why aren't mature fields being redeveloped? Because it's hard."

The slow pace of Brazilian state-led oil company Petrobras' divestment program as well as high costs and uncertainties regarding decommissioning of old platforms and abandoning wells are key factors, industry officials said. Brazil's National Petroleum Agency is in the process of implementing new rules and regulations aimed at increasing output from mature areas in an effort to lure fresh investments, including implementing an Open Acreage program to make areas available and reducing royalty rates on incremental output gleaned from redevelopment.

"The government has a challenge to revitalize these fields," Marcelo Castilho, the ANP's superintendent of production development, said.

About 241 mature fields are eligible for the reduced royalties program, with 40 requests already made, Castilho said. But only one request, by Petro Rio to reduce royalties on higher output at the Polvo Field after a 2018 drilling campaign, is close to being approved, Castilho said. The measure would cut royalties to 5% from 10% previously.


Petrobras currently has more than 100 onshore and offshore fields up for sale under its $26.9 billion divestment plan for 2019-2023, but a drawn-out process for shedding much of its aging production has turned off many investors. Many of the concession contracts are from Brazil's Round Zero, which was held in 1998 and allowed Petrobras to reserve areas and production facilities it held under the previous monopoly.

The contracts expire in 2025, so ANP has pushed Petrobras to determine what areas it wants to keep and invest in with the remainder sold or returned to ANP by the end of 2019. Petrobras, however, is pushing for more time and asked the ANP this week to push the deadline into early 2020.

The ANP also has already approved 12 extensions to Round 0 contracts, including eight offshore that total about $28.9 billion in fresh investments by Petrobras, Castilho said. Another 53 extension requests, which require new development plans for each field, are currently under evaluation, Castilho said.

Petrobras declared interest in continuing to invest in 71 fields, with the remaining 183 concessions to be sold or returned to the regulator, Castilho said.

But dealing with Brazil's biggest oil producer is not a task for the lighthearted, especially after Petrobras implemented an arduous sales process to avoid any possibility of corruption after a scandal was uncovered in 2014, industry officials said.

"Acquiring anything from Petrobras isn't easy," said Reynal Timothee, general manager at Perenco Brazil.

Timothee also said potential investors face issues regarding the structural integrity of offshore installations that may be 30-40 years old. Repairs need to be made to pass inspections involved in the sale, which can increase costs and quickly erode the minimal margins smaller players need to make such investments economically feasible.

Perenco recently closed on a deal to buy 100% of the Carapeba, Pargo, and Vermelho fields from Petrobras for $370 million. The deal included seven fixed-jacket platforms, several of which were in rough shape and needed repairs, Timothee noted. The fields, which produce about 8,000 b/d, represent Perenco's first foray into output in Latin America's biggest oil and gas producing country.

Recovery rates at the fields were about 25%, which is in line with the broader Campos Basin, but lags behind the industry average of 30%-35%. Each 1% increase in recovery rate would add 1 million barrels of new production, according to ANP. Perenco, for example, has been able to squeeze recovery rates of 45%-55% from similar fields in Africa, Timothee said.

"Without changes, these fields would have been abandoned," Timothee said of Carapeba, Pargo, and Vermelho.


The ANP is also working to resolve issues related to decommissioning and abandoning old fields, which often requires onerous financial guarantees that are impediments to small- and medium-size players, Castilho said, adding, "we need to treat small players different from big players."

Concession contracts bind oil companies to carry out decommissioning and well abandonment activities, but the regulations are still being formulated, Castilho noted.

"That's what the industry needs to know: what modalities will be accepted," Castilho said.

Oil companies also face a tightening market for equipment and services, with much of the industry focused on the massive subsalt play. That could lead to higher costs for people and suppliers that can further erode margins and curtail investments, officials said. New tax incentives could also help stoke activity in redevelopment, with the Repetro tax regime mainly geared to alleviate the tax burden on new offshore floating production units.

"Each dollar is relevant for a small player," said Alexandre Calmon, an oil and gas attorney at local firm Tauil and Chequer Advogados.
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