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Uruguay, take three

Written by  Karen Boman Monday, 25 September 2017 00:00

Renowned for its agriculture and livestock industries, Uruguay has sought to expand its oil and gas exploration and production sector over the past decade. The South American nation hopes that its third offshore licensing round will attract investment needed to prove Uruguay’s offshore hydrocarbon resources.

MIEM, ANCAP launch Uruguay's third licensing round in Houston. Image from ANCAP.

Uruguay is now qualifying companies for its third oil and gas licensing round, scheduled to take place 24-26 April 2018.  Seventeen blocks, ranging in size from 2400sq km to 7600sq km, are available in water depths ranging from 50m to 2400m. The blocks lie in three offshore basins – Punta del Este, Pelotas, and Oriental del Plata – and represent different geologies and water depths. Type I corresponds to the shallow water Punta del Este basin, Type II to the Pelotas Basin, and Type III to the deepwater Oriental del Plata basin.

A road show held on 18 September in Houston served to officially announce the bid round. The event saw representation from operators such as Anadarko Petroleum, Apache, Hess, Nexen-CNOOC, Lukoil, Cobalt International Energy, Repsol, Kosmos Energy, ConocoPhillips, Chevron, Noble Energy, Murphy Oil, ONGC Videsh, Talos Energy and Frontera Energy, said Uruguayan regulator ANCAP in a 19 September press statement. ANCAP reported seeing strong interest in data room meetings.

To date, only three offshore oil and gas wells have been drilled, and Uruguay has no oil production currently.  Uruguyan officials and state energy firm ANCAP said they hoped to change that, touting the nation’s geologic potential, its energy infrastructure investment, greater availability of seismic data, and a stable, investor-friendly business climate.

Maersk Venturer. Image from Maersk.

Offshore history

To date, the only exploration wells drilled off Uruguay include Chevron’s Lobo and Gavoitin wells in 1976 in the Punta del Este Basin, and Total’s Raya exploration well in 2016 in the Pelotas Basin.

Lobo and Gavoitin came up dry. ANCAP has identified abundant fluid inclusions of light oil and gas in cutting from the synrift, transition and early drift sequences of Lobo and Gaviotin, which correspond to 32° API oil of probable lacustrine origin, while gas inclusions showed high values of ethane and methane.

Raya, then the deepest water well in the world (in 2016), failed to encounter commercial hydrocarbons, but was successful from the perspectives of time, budget, drilling and engineering, Horvath said.

“The [Raya] project proves that Uruguay is prepared to handle complex offshore oil and gas projects that require high levels of coordination,” Horvath said.

Total drilled Raya in in 3400m water depth using the ultra deepwater Maersk Venturer drillship.

New contracts

Image from ANCAP.

The contract model offered in Round III is nearly identical to Round II, but it now allows operators to not only qualify for exploration and production, but also for exploration only, said Ignacio Horvath, ANCAP exploration and production manager. The goal of the change is to attract independents that are focused on exploration, too.

Other adjustments for qualification requirements have been made to account for the current market. These include longer exploration periods of 10 years for Type III blocks in the ultra-deepwater Oriental del Plata, versus eight years for Type I and Type II blocks in the other basins. The contract term for the exploitation period is 30 years, with the option to extend another 10 years. Cost recovery limits also have been changed to account for differences in the blocks. For Types I and II recovery limits are 60% for oil and 80% for gas; for Type III, the cost recovery limit is 70% oil and 90% natural gas, said Santiago Ferro, ANCAP´s Head of E&P Administration and Contracts.

To qualify to offer for one area in exploration only, companies will have to have average equity for the past three years of over US$100 million for Type I blocks in the shallower Punta del Este Basin. For Type II and Type III blocks in the Pelotas and Oriental del Plata basin, average equity of more than $200 million and over $300 million will be needed. They also will need additional equity for each additional area on which they bid: $25 million for Type I areas, $50 million for Type II, and $100 million for Type III, Ferro said.

To qualify to offer for one area for exploration and production, companies will need average equity for the past three years of more than $200 million for Type I areas, $400 million for Type II areas, and $600 million for Type III areas. For each additional area, they will need equity of $50 million for Type I, $100 million for Type II, and $200 million for Type III.

If a company that has qualified for exploration only makes a discovery, they will have to either prove they can fulfill the obligations of production under the bidding round terms, or farm out at least 40% interest to a company that meets the requirements as an operator.

The deadline for companies to qualify for bidding is 6 April 2018.  

Domestic commitment ramps up

Uruguay is seeking investment in its oil and gas sector to fulfill the goals of its energy policy. Ratified in 2010, Uruguay’s energy policy through 2030 seeks to attract participation of state and private oil and gas firms in Uruguay, diversify the nation’s resources to include oil, gas and renewables, promote energy efficiency, and ensure its citizens have adequate access to energy resources, said Guillermo Moncecchi, Uruguay’s deputy minister of industry, energy and mining.

Following the establishment of ANCAP’s exploration and production arm in 2007, Uruguay has attracted more than $1 billion in investment, including $736 million from international oil companies, $200 million from service companies, and $200 million in seismic acquisition agreements. Uruguay now has seven exploration and production contracts in place, including two for onshore and five for offshore basins, Horvath said. Besides Total, companies active offshore include Shell, Exxonmobil, and Statoil.

Prior to 2012, no 3D seismic data was available of Uruguay’s offshore; today, more than 42,000sq km has been gathered. The amount of 2D seismic available also has grown from 13,000km before 2012 to 41,000km today. Horvath said that ANCAP would continue to sign additional multiclient agreements to further increase the amount of seismic data available.

ANCAP’s geoscience team has already matured some play types from leads to prospects, including the shallow water Morfeo prospect, and the deepwater prospects, Smith and Esmeralda, said Pablo Gristo, ANCAP’s head of Geoscience. Located in 180m of water at a sediment depth of 7125m, Morfeo is estimated to hold a mean estimated ultimate recovery (EUR) of 5.1 Tcf dry gas. The Smith prospect, which lies in 1600m of water at a sediment depth of 3300m, is estimated to have a mean EUR of 331 MMbbl and .4 Tcf gas. Esmeralda, which sits in 1350m of water, has an estimated mean EUR of 718 MMbbl.

ANCAP also has seen some reservoirs and traps that can be identified as resembling analogies from recent discoveries in the South Atlantic, such as the Sea Lion discovery in the Falkland Basin. Still, a lot of work remains to gain more insight into Uruguay’s offshore basins.

“It’s time for geologists and geoscientists to open their minds to new ideas and models and bring to ANCAP what it needs, more knowledge,” Gristo concluded.

Read more:

Uruguay launches third offshore licensing round

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