Shale Oil and Gas in Indonesia's South Sumatra Basin: the 2016 USGS Assessment

Using a method based on geology, the U.S. Geological Survey estimates that the South Sumatra Basin Province of Indonesia holds, on average, 689 million barrels of undiscovered continuous shale oil and 3.9 trillion cubic feet of shale gas that could be recovered with current technology.

The basin

The South Sumatra Basin is one of a series of back-arc basins linked to subduction along Sumatra's western margin. From the Eocene to the early Oligocene the region was stretched and rifted into a series of horsts and grabens, which filled with non-marine sediments: river, delta and lake-margin sandstones and shallow- to deep-water lake shales. The thickest source rocks lie in the grabens. One of the basin's source rocks is the rift-age Eocene–Oligocene Lemat Formation, which includes the organic-rich lake shale of the Benakat member.

After rifting stopped, the crust cooled and subsided, making room for more sediment. The source rocks became mature enough to generate oil and gas from the Miocene onward, and compression from the middle Miocene to the Pliocene, driven by subduction, created many structures, some of which trap conventional oil and gas.

The South Sumatra Basin Province, around Palembang, with its shale oil and shale gas assessment units. USGS map, on a National Park Service base.

What counts, and the assessment units

For this assessment, a continuous source-and-reservoir rock needed:

1. more than 2 percent total organic carbon by weight;
2. the right thermal maturity for oil or gas;
3. more than 15 metres of organic-rich shale;
4. Type I or Type II organic matter.

The USGS defined a Lemat Lacustrine Total Petroleum System, bounded by two assessment units — Lemat Lacustrine Shale Oil and Lemat Lacustrine Shale Gas — drawn from published maps of structure, rock types and thermal maturity. The ranges on their areas reflect uncertainty about how far and how thick the source rock extends in the grabens and how mature it is. The geological model is that oil and gas formed in the Lemat source rock in the grabens and that some stayed in it after the rest migrated out; whether enough was retained — perhaps affected by later compression and structural inversion — is the main risk.

Drainage areas, recovery per well and success rates were based on U.S. shale-oil and shale-gas plays, including the lake-bed petroleum system of the Eocene Green River Formation in Utah's Uinta Basin. Mean potential production areas were about 2,425,667 acres for the oil unit and 1,370,667 acres for the gas unit, with half of wells expected to succeed.

The results

Ranges run from a 95 percent to a 5 percent chance.

Sources

• South Sumatra Basin Assessment Team (Christopher J. Schenk, Marilyn E. Tennyson, Timothy R. Klett, Thomas M. Finn, Tracey J. Mercier, Stephanie B. Gaswirth, Kristen R. Marra, Phuong A. Le and Sarah J. Hawkins), Assessment of Continuous Oil and Gas Resources of the South Sumatra Basin Province, Indonesia, 2016, USGS Fact Sheet 2016–3090, December 2016. https://doi.org/10.3133/fs20163090
• Results: USGS Energy Resources Program, http://energy.usgs.gov