FEATURE | South America’s offshore boom accelerates in Guyana and Brazil

FEATURE | South America’s offshore boom accelerates in Guyana and Brazil

Photo: Wood Mackenzie
Photo: Wood Mackenzie

It’s official. Offshore South America is a top investment destination.

South America’s upstream sector of the past conjures images of the onshore heavy oil fields of Colombia and Venezuela. But in recent years, regional activity has pivoted offshore, where repeated success in Guyana and world-class productivity in Brazil have elevated offshore South America to its status as a top investment destination.

Since 2015, Brazil and Guyana have dominated the newsflow from the region. Brazil led with a series of successful licensing rounds after adjusting its local content policies and other regulatory improvements. Guyana followed with more than 4 billion boe of resource discovered to date in the Stabroek block. The revitalisation of mature fields in Brazil’s Campos basin offers even greater upside.

How Guyanna discoveries are changing the game

The discoveries are a game changer for all partners. ExxonMobil has in the Liza Complex one of its five key growth pillars and the project helps to address the Major’s relative lack of deepwater exposure. For Hess, Guyana growth will supplement its key Bakken position. At peak output in 2026, the project accounts for 30 per cent of total company production. CNOOC is the leading Chinese NOC exploring offshore Latin America, with exposure to Mexico, Guyana, Argentina and Brazil. On its international portfolio, Guyana is the NOC’s second largest country in terms of value and reserves.

Liza’s potential could extend across the Equatorial Margin, which accounts for almost 25 per cent of Latin America’s offshore licensed acreage. A full range of companies is present. All the Majors (except for Eni), large independents, prominent explorers and Asian NOCs have interests in the region. With 80 per cent exploration success rate, the Liza complex still has 20 targets to chase. The Equatorial Margin extends to Suriname, French Guyana and Northeast Brazil, where geological similarities are expected.

Santos still in the headlines

Since the early 2010s, pre-salt discoveries in Brazil’s Santos basin have dominated international headlines, drawing investments from some of the largest oil companies in the world, including ExxonMobil, Equinor, Shell and Total. Today, Santos is the top producing basin in Brazil, accounting for 50 per cent of the country’s oil and gas production.

In 2017 and 2018, Brazil licensing activity peaked. Signature bonuses totalled US$6.5 billion over five licensing rounds. A sixth round (PSC Round 5) is scheduled for September 2018 and four pre-salt blocks will be offered. The four blocks contain 12 billion boe of in-place volumes. A DRO round for the Transfer of Rights Surplus volumes is expected for 2019. Wood Mackenzie estimates over nine billion boe of recoverable volumes in the four areas containing these volumes.

Too soon to write off the Campos basin?

Petrobras’ investment focus has shifted to the more prolific Santos basin over the past decade, at the expense of the ageing Campos basin. Without further investment, 32 platforms will reach their economic cut-off by 2025. The decommissioning of the 32 platforms and their related infrastructure will cost US$8 billion. However, the same sum could be invested towards the redevelopment of these mature fields. We estimate redevelopment could add 230,000 boe/d by 2025 and postpone 60 per cent of the decommissioning costs to post-2030.

Some redevelopment activities are already underway. They include 4D seismic surveying to identify bypassed oil pockets, infill drilling, water flooding optimisation and increasing platforms water handling capacity. Moreover, future use of EOR techniques presents additional upside to production.

Petrobras and Equinor are partnering in the Roncador oil field in the Campos basin to use infill drilling and 4D seismic surveying to extend the life of the field. According to Wood Mackenzie’s analysis, the successful deployment of these technologies will extend the economic life of the field by eight years and add 500 million barrels of oil equivalent to the field’s reserves – increasing the NPV10 by US$1.6 billion.

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