Oil and gas demand is ramping up in Asia. Eastern Asia is hot for U.S. oil exports at the moment, while regional oil production, particularly in Southeast Asia, has waned, but not halted. Massive natural gas E&P projects, on the other hand, are on the upswing, especially in Vietnam and Indonesia. But geopolitical risks loiter, as China recently forced the cancelation of a Vietnamese E&P project, again demonstrating that supply and demand are not the only major market influences in Asia.
Vietnamese projects. In January 2017, ExxonMobil and PetroVietnam signed an agreement to develop Ca Voi Xanh, or the Blue Whale gas project, which potentially will feed five power plants in the coming years: four in Chu Lai, and another in Dung Quat. Blue Whale is aptly named. Located in the deepwater section of Block 118 in the Phu Khanh basin, at depths of 300 m, it has 150 Bcm of reserves, making it Vietnam’s largest gas field. It is three times larger than the Lan Tay and Lan Do fields combined, traditionally Vietnam’s largest. First gas is expected as early as 2021, and maybe as late as 2023. The project costs $4.6 billion and could reap revenues of $60 billion over its life.
Blue Whale is most likely safe from China’s military intimidation in the South China Sea, but there are potential risks. First, ExxonMobil’s wellhead is reportedly just 16 km from China’s polemic South China Sea nine-dash line boundary, which slices through part of Block 118. Second, because the gas reserves here are so extensive, China might militarize this area and drill directly next to, or even inside of, the Blue Whale find, as it has done in the Shirakaba/Chunxiao gas field dispute with Japan.
Beijing’s past offshore activities off central Vietnam demonstrate the potential. It placed its colossal Marine Oil 981 rig in this area in 2014, presumably to explore for hydrocarbons close to where the Phu Khanh and Nam Con Son basins near each other. A second 981 deployment in 2015 happened 80 km north of Blue Whale. Both deployments were highly controversial and backed by threats of military force. Third, Beijing is not beyond forcing projects closed in this area, as evidenced by its actions on July 25, when it told Spain’s Repsol to stop drilling in Vietnam’s Block 136/3, which is within China’s nine-dash line. Beijing’s Foreign Ministry said, “China urges the relevant party to cease the relevant unilateral infringing activities and, with practical actions, safeguard the hard-earned positive situation in the South China Sea.”
Repsol CFO Miguel Martinez said to the press, “We are working with PetroVietnam, and with the Vietnamese authorities, and the only comment is that right now, operations have been suspended.” He added that the project, so far, had cost the company $27 million, a substantial loss.
The back-story here is that China threatened Vietnam with a military strike, if it did not stop drilling, and Vietnam’s politburo reportedly had an intense dispute over it. All of this is occurring, as Vietnam needs unfettered access to local E&P and international hydrocarbon imports. In August, Hanoi became a net importer of oil at 100,000 bpd, in part to feed its two refineries, one so new that it’s slated to begin operations in late 2017 or early 2018.
Indonesian activity. Meanwhile, in Indonesia, Eni started gas production at the deepwater Jangkrik Complex in the Muara Bakau Block during May. Located in the Kutei basin, in water depths between 200 m and 500 m, Jangkrik is 80 km off the coast of Samarinda. The complex consists of two gas fields, Jangkrik and Jangkrik Northeast.
On June 22, Eni shipped 22,500 m3 of LNG from the complex to Indonesia’s domestic market, its first-ever production from this mega-project. At full output, there will be 10 subsea wells connected to Eni’s Jangkrik FPU, which will produce 450 MMcfd, and maybe as much as 600 MMcfd. From the FPU, gas then flows via a 79-km pipeline to the Onshore Receiving Facility, and then on to the Bontang gas liquefaction plant. The Jangkrik Complex is expected to help grow Indonesia’s domestic production to the point that the country will not need to import LNG, perhaps as early as 2020, say government sources.
Elsewhere in Indonesia, London-listed Empyrean announced in June that it had discovered gas at its Mako South-1 well, offshore in the Duyung Block of the Natuna basin, about 260 km northwest off the Natuna Islands. The find is in waters ranging between 60 m and 100 m, and some estimates say it holds 902 Bcf of natural gas.
Natuna is not supposed to be within China’s nine-dash line, but with so much natural gas at stake, and with China ignoring Indonesian economic boundaries regarding fishing, a China-Vietnam situation developing here cannot be ruled out. In 2013 and 2016, Indonesian maritime enforcement vessels confronted illegal Chinese fishermen in waters just north of Natuna, and both times they were forced to wave off by Chinese Coast Guard vessels threatening force or carrying out ramming tactics.
However, ExxonMobil and Pertamina’s PSC dispute over E&P activity in East Natuna field has been pricklier than Chinese natural resource harassment. In July, ExxonMobil bowed out of negotiations to develop East Natuna, which holds approximately 46 Tcf of gas. ExxonMobil cited two problematic issues for dropping out: 1) Pertamina’s disadvantageous PSC terms; and, 2) The fact that the carbon dioxide content of the gas in East Natuna is more than 70%, which makes processing highly expensive. Indonesia still needs foreign technology to exploit this area, however, and it aims to increase the attractiveness of its PSC terms for foreign energy companies. At present, Indonesia’s PSC share is 57% for oil and 52% for gas.
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