The state-run oil and gas companies that are the operating entities of the Chinese government, namely Sinopec, CNPC and CNOOC, are globally active in seeking oil for China. Countries where these NOCs have completed deals in the last ten years or so cover the globe, from Australia and Mongolia to Kazakhstan and Oman; across Africa from Kenya to Algeria and Mauritania and throughout South America. All inevitably accompanied, of course, by support from ‘China Inc.’ in the form of loans, infrastructure and the like.
This high level of activity is based on China’s need for resources and, in the case of the South China Sea, its assessment that there may be 200 Bbo, as well as 2,000 Tcf of gas, under it.
Does the history and recent experience of exploration in this region – and in South East Asia more generally – indicate that such huge resources may remain undiscovered and if so, where might they be?
A Historical Perspective
There is a long history of exploration in South East Asia, beginning with the observation of seepages in the Dutch East Indies; by 1865, more than 50 seeps had been identified in the region. The first successful oil well was drilled in northeastern Sumatra in 1885 and the Royal Dutch company was launched in 1890, by the end of the century becoming a key global competitor of Standard Oil.
Just over a hundred years later, the descendants of Royal Dutch/Shell knew the South East Asian petroleum story very well, perhaps better than anybody. The broad ideas discussed below originate from a regional review of the oil and gas potential of South East Asian Tertiary basins, carried out by Shell during the 1990s and reported by the eminent Shell geologist Harry Doust (Doust and Sumner, 2007). As discussed previously in GEO ExPro (Vol. 7, No. 5) the main conclusions of this study were that petroleum prospectivity could be linked to the presence and relative development of a small number of petroleum system types (PSTs), common to the South East Asian family of basins as they pass through an early Tertiary Syn-Rift to late Tertiary Post-Rift geological history. These exhibit an almost exclusively land plant and/or lacustrine algal charge system and are characterized by rapid short wavelength sedimentary variations involving a distinct suite of depositional environments and their associated lithofacies.
What is especially relevant is that these South East Asian PSTs are in the main thoroughly explored and have significant production histories, allowing us to ask two crucial questions; firstly, “what field sizes do such PSTs yield?”, and secondly, “are there any special issues connected with them?”
In answer, Doust and Sumner believe that the Pre-Rift (pre-Tertiary basement) is only lightly explored, while fields producing from Early Syn-Rift lithofacies are oil-rich but small, with average ultimate reserves of 25 MMbo and 60 Bcfg. Fields producing from Late Syn-Rift lithofacies are oil-prone but with significant gas (2:1 ratio) and of moderate size, with average ultimate reserves of 55 MMbo and 293 Bcfg. In the Early Post-Rift, gas predominates, perhaps due to access to contemporaneous gas-prone marine source rocks, while the average field size is only 28 MMbo but an impressive 2.2 Tcf of gas. Finally, in the Late Post - Rift, average field sizes are moderate – 41 MMbo and 486 Bcfg. Potentially, contemporaneous turbidites, distal from the deltaic depocentres, offer a exciting play in present-day deep water.
As mentioned above, lacustrine source rocks are important and these provide a complication, in that the reservoired crude oil usually has a high wax content. The difficulty with waxy crude is that it can have a tendency to turn solid en route from the reservoir to the processing facilities or in a pipe-line. The technology to overcome this problem, including the injection of chemicals, lighter oils and the heating of flow/pipelines, exists and has led to successful production throughout South East Asia.
Reflecting on the raw data of South East Asian exploration success rates, discovery sizes and finding costs, both Wood Mackenzie and IHS have asserted* that since around 2003, the number of discoveries has been rising slowly but the resource additions have been dropping, and whilst exploration success rates are more or less holding up, discovery sizes are dropping. Average recoverable reserves are only 5–10 MMb for oil and 5–20 MMboe for gas fields; overall, gas is more prominent. Discovery costs are rising more rapidly than elsewhere and so there is competitive pressure from other regions, meaning that while exploration is just about profitable globally, it would appear that in South East Asia it is not.
Thus, this broad brush summary could be thought to suggest that much of South East Asia is either ‘Mature’ or in the ‘Red’ zone.
However, South East Asia is large, with a complex geo logical his tory and com plex poli tics, and Longley from GIS-Pax* indicated that recent and planned activity gives plenty of encouragement at the play level. He pointed out that last two years have delivered a variety of material discoveries around the region, in ‘Frontier’ areas and in new plays in ‘Mature’ areas, by both large and small companies using old and new technologies. Results have demonstrated that significant exploration potential remains, both in accessible areas and in areas underexplored due to boundary disputes. Many already identified exciting plays will be drilled and tested in the next two years, and he sees no reason that this should not continue into the foreseeable future.
Where are Giants Waiting?
IHS recently published an interesting creaming curve analysis of distinct plays in seven basins ranging from ‘Frontier’ to ‘Mature’, which reveals that significant potential remains for hydrocarbon discoveries in South East Asia. They observe from their data that past exploration demonstrates a while the marine/transgressive wedges, channels, and fan lobes plays have been explored only intermittently. For the latter, only the Kutei and Baram Basins have produced discoveries, most notably the Kikeh discovery, with fan lobes yet to be penetrated in Kutei. Exploration has also focused on plays close to existing discoveries and in shallower water to minimize risk. However this spatial constraint produces false plateaus in the creaming curves, as play types become locally exhausted.
IHS’s comparison of these seven basins shows that the fall in exploration discoveries for the past decade is mainly because of a concentration on mature plays, combined with the neglect of other unproven or relatively less prospective plays. They suggest that significant discoveries (greater than 1 Bboe) in areas like Kutei’s Upper Miocene-Pliocene play and Baram’s turbidite play may be possible and that, according to a yet-to-find analysis, basins like Rakhine and Song Hong might hide around 4 Bboe in undiscovered reserves.
Based on recent discoveries and IHS’s analysis, the realistic hopes for ‘Giant’ fields would therefore seem to be either deep water, as exemplified by the Deepwater Pearl River Mouth and some of Indonesia (Kutei; Baram), or more remote areas such as West Papua, where new play ideas and modern technology may be deployed.
Equally, it must be said that some areas, such as the Makassar Straits, have proved disappointing, dropping directly from ‘Frontier’ to ‘Red’; while the technical approach* to some of the onshore areas, such as onshore Borneo or northern Thailand, seems to be bereft of any modern technologies such as gravity gradiometry or wireless (3D) seismic.
Returning to the theme of China’s thirst for oil, perhaps we can expect Chinese NOCs to seek entry to these areas with recognized unexplored potential for Giants, while we may see the Chinese government focusing on its declared rights in the South China Sea, especially the Deep Water areas.
*as presented at the SEAPEX Conference, Singapore, April 2011.
Chan and Mair: IHS, 2011
Doust and Sumner: Petroleum Geoscience, Volume 13, 2007