Industry attention has for years been focused mainly on the regular flow of opportunities coming out of South America’s traditional upstream activity centers of Brazil, Venezuela, Colombia and Argentina.
But the economic uncertainty and quarrelsome geopolitics of South America continue to leave it vulnerable, with the ongoing ramifications from the corruption that has plagued Brazil and Venezuela’s problems with major debt just two of the substantial current threats that loom over the oil and gas industry’s cautious plans to invest.
Hence the surprise emergence of the upstream backwater of Guyana as an exploration hotspot for oil majors Exxon Mobil and Hess has been extremely welcome.
The drilling of the ultradeepwater Liza-1 discovery well in 2015 was a true game changer, and the initial apparent size of the fi nd in the Stabroek Block quickly prompted operator Exxon Mobil to appraise it earlier this year. The Liza-2 well persuaded the normally ultraconservative operator to excitedly issue a recoverable reserves estimate of between 800 MMboe and 1.4 Bboe and describe it as “world class,” while a third appraisal probe in October drilled by the Stena Carron drillship has now prompted it to raise that minimum recoverable reserves estimate to 1 Bboe.
According to Exxon Mobil’s latest plan submitted to the country’s environmental protection agency, the U.S. major already is underway with pre-FEED studies for a converted FPSO development linked to a significant subsea umbilicals, risers and flowline system with subsea manifolds and two subsea production and injection well clusters.
Spread-moored FPSO unit
This would be initially based around a 100,000-bbl/d spread-moored FPSO unit with 1.6 MMbbl of storage capacity and tanker offloading facilities. The development strategy is then expected to see the operator follow the phased and proven approach it adopted for its Kizomba and Kizomba Satellites development in Angola’s deep waters on the other side of the Atlantic, with a “design one, build many” philosophy for the multiple FPSO units.
It’s still too early for a formal decision, but the operator and its partners have indicated in the environmental plan’s outline schedule that the project could be sanctioned by mid-2017. This would help it take advantage of the low market prices that are available for the small number of new offshore development projects being tendered and further squeeze down the project’s breakeven costs. On this basis Guyana could have its first offshore production facility up and running as soon as late 2020 or early 2021, according to Exxon Mobil’s schedule, under a 20-year IP operations phase.
This would be impressively rapid for an offshore sector that previously has seen only sluggish activity and a small number of unsuccessful offshore wells drilled since the 1960s (most of those back in the late 1960s and early 1970s).
The Stabroek Block itself lies about 190 km (120 miles) offshore Guyana and covers 6.6 million acres (26,800 sq km or 10,347.5 sq miles). Exxon subsidiary Esso E&P Guyana Ltd. is the operator with a 45% working interest with partners Hess Guyana Exploration Ltd. (30%) and CNOOC Nexen Petroleum Guyana Ltd. (25%). The Liza-1 discovery well hit 90 m (295 ft) of 32°API crude, while Liza-2 encountered more than 58 m (190 ft) of oil-bearing sandstone reservoirs in Upper Cretaceous formations.
According to partner Hess’ third-quarter results in late October 2016, the Liza-3 well was also more than successful. CEO John Hess described it as “a world-class resource discovery,” adding in the results statement, “Based on the positive results of the Liza-3 well, we now expect Liza to be at the upper end of the previously announced estimated recoverable resources range of 800 MMboe to 1.4 Bboe.”
Deeper pay zone
The well, spudded in early September, is believed to have established a deeper pay zone than the first two wells, hitting about 61 m (200 ft) of net pay after being sidetracked and deepened. It was drilled by the Stena Carron to a total depth of 5,486 m (18,100 ft) in a water depth of 1,829 m (6,000 ft), about 4 km (2.4 miles) from the discovery well. Hess COO Greg Hill added in an investor call that the reservoir had a “very healthy” gas-to-oil ratio that should aid oil production.
There was some disappointment, however, with an exploration well drilled prior to Liza-3 on a separate prospect called Skipjack 40 km (25 miles) northwest of Liza proving unsuccessful. The operator has since moved the drillship about 16 km (10 miles) to the northwest to spud another wildcat, this time on the Payara prospect, which will be followed by further exploration wells during 2017.
Exxon Mobil and Hess have said the block contains further multiple prospects and play types, which they are expecting to drill during 2017 and 2018.
Exxon Mobil also has indicated that it plans to use two dynamically positioned drillships simultaneously to drill the production and injection wells on Liza.
Guyana, a British colony until 1966 that has strong links with the Caribbean, has a fiscal regime that at this nascent stage in its evolution is very explorer-friendly as the republic looks to encourage more companies to its waters.
At present, after any commercial production begins, a licensee will be allowed to recover all capital and operating costs from “cost oil,” which for the first three years is up to 75% of production and thereafter up to 65% of production.
The licensee share of the remaining production or “profit oil” for the first five years is 50% of the first 40,000 bbl/d of oil, 47% for additional production and 45% thereafter.
Uruguay sets depth record
While Guyana has been stealing the headlines in recent times, another of South America’s smaller countries also has been in the spotlight by having the world’s deepest ever offshore well drilled.
Although Total’s Raya-1 wildcat offshore Uruguay proved unsuccessful, the fact that this country—with no production or proven reserves—had the potential to tempt the French major to carry out frontier exploration indicates more activity will follow. Prior to the Total probe, little interest had been shown since the mid-1970s, when two dry wells on the Lobo and Gaviotín prospects were drilled by Chevron on the continental shelf.
The ultra-deepwater Raya-1 well was drilled mid-year, setting a world record after the drillship Maersk Venturer carried out the operation 250 km (155 miles) offshore in a water depth of 3,411 m (11,191 ft). This beat the previous record of 3,170 m (10,401 ft) set by ONGC offshore India.
The South Atlantic Margin continues to be a play of interest to the industry, particularly in light of Brazil’s huge proven reserves just north of Uruguay, and although Total has not released any of cial details about the well’s results, it is continuing to analyze the data. The French operator has shot more than 7,100 sq km (2,741 sq miles) of 3-D seismic over the block.
Two bid rounds held in 2009 and 2012 attracted a number of majors, including Total, which was awarded Block 14 in the second round. It later shared out the risk on the block when Exxon Mobil and Statoil farmed in for 35% and 15%, respectively.
The Norwegian player also is a partner with 35% in neighboring Block 15 in the Pelotas Basin alongside operator Tullow Oil (35%) and partner Inpex (30%).
Tullow and its partners have agreed to a yearlong extension of the contract on Block 15 to complete further seismic activity, with a 3-D shoot covering 2,500 sq km (965 sq miles) set to get underway before year-end 2016 or early in 2017. This is aimed at adding to a number of initial leads previously identied in a 3-D survey carried out by Tullow in 2013.
Uruguay’s oil regulator Ancap is working on plans for a third bid round, possibly in 2017, but the disappointing news from Total’s wildcat and the depressed exploration environment globally might delay those plans into 2018. Up to 17 blocks are expected to be put up for grabs, with ve in shallow waters and the rest in water depths ranging from 100 m (328 ft) to beyond 3,500 m (11,483 ft). They also will include blocks previously held by BP and YPF but later relinquished. The blocks will range in size from 2,500 sq km to 6,500 sq km (2,510 sq miles).
Ancap also is working on improving the incentive to explore, with longer initial exploration periods and higher cost-recovery allowances.