Bulletin of the Geological Society of Malaysia, Volume 72, November 2021, pp. 63 – 88
Mazlan Madon1
Department of Geology, Universiti Malaya, 50603 Kuala Lumpur, Malaysia
Author email address: mazlan.madon@gmail.com
Abstract: Since the first oil discovery in the Malay Basin in 1969, more than 700 exploratory wells have been drilled. To date, there are more than 181 oil and gas discoveries, about half of which are currently in production and about a dozen are already in their secondary or tertiary recovery stages. In 2014 it was estimated that a total of over 14.8 billion barrels of oil equivalent (bboe) of recoverable hydrocarbon resource have been discovered in the basin, contributing to approximately 40% of the total hydrocarbon resources of Malaysia. By the end of the first decade of exploration in 1979, all the major basin-centre anticlinal structures had been tested. This play type contributed 60% of the total discovered resource in the basin. By 1981 this most prolific play type had been practically exhausted, as all the giant fields (those with recoverable resource > 0.5 bboe) had been found. As “creaming” of the basin-centre anticlinal play continued into the early 1980s, exploration efforts gradually shifted to the newly discovered western margin play types, particularly in the Western Hinge Fault Zone, Tenggol Arch and the adjacent Penyu Basin. There was a “lull” period from 1985 to about 1990, due to the global oil crisis, after which exploration was rejuvenated through significant discoveries in several play types on the northeastern ramp margin. This followed a successful drilling campaign that lasted until around 1997 and contributed an additional ~1 bboe of recoverable resources over a seven-year period. Since then, most of the incremental resource addition came from the highly gas-charged play in northern region that comes under the Malaysia-Thai Joint Development Area (JDA) and on the northeastern ramp margin, which includes the Commercial Arrangement Area (CAA) between Malaysia and Vietnam. Individually, however, the hydrocarbon volumes in these later discoveries were relatively small compared to the earlier discovered play types. Subsequently, new play types were pursued, including stratigraphic channels, deeper reservoirs beneath existing fields, high pressure/high temperature (HPHT) reservoirs, overpressured and tight reservoirs, and fractured basement reservoirs. All had some measure of success but none were able to volumetrically match the discoveries made decades earlier. As of end of 2018, over 2100 exploration and development wells had been
drilled in the entire basin. Based on the creaming curve, since around 1990 and into the fifth decade of exploration, the incremental resource addition has been increasing steadily at an average rate of ca. 120 MMboe per year. The data indicate that the expected average discovery size would be less than 25 MMboe, and that at least 5 wells need to be drilled per year to sustain the same rate of resource addition. If no new plays are explored and no significant discoveries made, resource addition is expected to plateau beyond 2020. The basin needs a new stimulus, and more importantly, new exploration play concepts to sustain exploration business.
Keywords: Malay Basin, play types, discovery history, creaming curve, undiscovered resources, remaining potential
DOI: https://doi.org/10.7186/bgsm72202106
