M.T. Bradshaw, C.B. Foster, M.E. Fellows, D.C. Rowland
Australian Geological Survey Organisation
This is the first of a two-part article on patterns of discovery in Australian exploration. The second part will appear in OGJ's Exploration section June 14. It was adapted from a presentation at the 1999 Australian Petroleum Production and Exploration Association conference in Perth on Apr. 18-21 that was also published in the 1999 Appea Journal, Vol. 39, Part 1. Authors' references will appear in the second part of this article.The story of Australia's long search for commercial hydrocarbons has been well told previously by Wilkinson (1988a and b, 1991) and others (Robertson, 1988; Murray, 1972); and the Australian Petroleum Production & Exploration Association (Appea) web page has an excellent timetable of events (www.appea.com.au). But here, we are concerned less with the narrative of discovery and more with understanding the processes involved.
The pattern shown in Fig. 1 [44,561 bytes] is one of a long, slow prelude of unrewarded exploration followed by three cycles of drilling activity and hydrocarbon discovery. The first commercial oil find was Moonie No. 1 in Queensland in 1962, and a flood of discoveries followed through the 1960s, including giant oil and gas fields. The rate of activity and discovery was severely checked in the mid-to-late 1970s. The second cycle of exploration and discovery occupied the late 1970s through the late 1980s, and we are now in the midst of a third cycle. Since the 1960s, many and diverse discoveries have been made, but no further giant oil fields have been found, although several giant gas fields with significant liquids content have been added to Australia's reserves.
Initially, all activity was confined onshore (Fig. 2 [54,738 bytes]) but widely spread across the continent. The 1960s boom heralded the move to the continental shelf; the move to deeper water actually occurred in the doldrums of the late 1970s. In recent decades, most activity and expenditure has been offshore, and there has been a shift in focus from the southeast corner (Gippsland basin) to the North West Shelf (Carnarvon, Bonaparte, and Browse basins). Over time, more productive basins have been added to Australia's inventory of petroleum resources, and none have yet ceased production, although some are now in decline (Gippsland, Surat).
Almost all of the basin areas that now contain an oil or gas discovery were recognized as hydrocarbon-bearing by the end of the first cycle of exploration in 1972 (Table 1 [30,203 bytes in PDF format]). The only additions in the 26 years since then include the Eromanga basin (Namur gas field in 1976), Otway basin (North Paaratte gas field, 1979), Exmouth Plateau (Scarborough giant gas field, 1980) and Beagle subbasin (Nebo oil discovery, 1993). The Petrel gas blow-out (1969), the Puffin oil discovery (1972), and the Scott Reef gas discovery (1971) had already marked the Browse and Bonaparte basins as petrolifierous, long before the commercial discoveries of the 1980s and 1990s.
Petroleum supersystems (Bradshaw 1993; Bradshaw et al, 1994) provide a framework for understanding Australian hydrocarbon occurrences in their geological context. Using this criteria, all of the currently productive petroleum supersystems were discovered by 1964. The Proterozoic Centralian supersystem (Dingo gas field, 1981, Amadeus basin, Ozimic et al., 1986 ) is the only proven supersystem since added. The relative contribution of Mesozoic sources (Murta supersystem) and Permian sources (Gondwanan supersystem) to the hydrocarbon accumulations of the Eromanga basin remains an issue for debate (Boreham and Summons, 1999). In Table 1, the Dullingari oil discovery is listed as having been sourced from Mesozoic Murta source rocks, relying on the geochemical evidence presented by Jenkins (1989).
Discovery processFig. 3 [70,973 bytes] depicts the elements of the discovery process. Exploration activity, namely the drilling of wells, results in hydrocarbon discoveries. The ratio between the number of discoveries made and the number of exploration wells drilled varies through time (Fig. 1), as expressed by the success rate. The success rate is controlled by the natural geological endowment of the area and the efficiency of exploration, plus random chance. Advances in technology and the growth of geological knowledge work toward improving the efficiency of exploration.
In almost all cases worldwide, the primary driver of exploration is the hope of commercial success, as measured by profits returned to stockholders (Fig. 4 [73,267 bytes]). In times of conflict, survival-through continued access to fuel-may become paramount, rather than commercial considerations. Also at that time, innovation and alternate fuels are tested, developed, and used (oil shale, gas generation from charcoal, etc.).
Political and economic factors and the perception of hydrocarbon prospectivity are the variables controlling the level of exploration activity in an area (Fig. 4). Among the political factors influencing the decision to explore and invest, Appea (1998a) lists: the certainty of administrative process, access to acreage, fiscal regime, and complexity of the regulatory regime. Economic factors include the investment climate, costs of operations, oil prices, and availability of gas markets.
A discovery itself affects the exploration process: It adds to geological knowledge and improves the perception of prospectivity, and positive feedback may lead to more exploration and further discoveries. On the other hand, discoveries tap into the finite geological resources of a basin (Fig. 4), such that there are then fewer fields to find. Also, because the largest fields are often found first, the chance of discovering giant or even large fields is lessened. However, running counter to this trend are the effects of improving technology and geological knowledge, such that more of the basin's resources become accessible. Exploration may move to deeper water or pursue new plays. Changes in economic factors can also increase the value of the basin's resources, as higher prices and new markets may allow the development of smaller oil accumulations, gas reserves, or oil shales.
Discovery through time Pre-1960: false dawnsOil shales were discovered in the Permian sediments of the Sydney basin only 14 years after European settlement, by the French World Scientific Expedition in 1802 (Appea, 1998b). However, the obvious surface seepages of liquid hydrocarbons that directed initial exploration efforts elsewhere were lacking in Australia, and it was the false guides of beach strandings of bitumen and algal mats in coastal lagoons that inspired the first wells ( Fig. 5 [134,567 bytes]). The great depth of 9 m was reached at Salt Creek, in the Coorong of South Australia in 1866, and first "offshore" well was drilled in Albany Harbor in 1907. Gas and oil shows in water bores (Table 1) prompted a low and sporadic level of drilling through the first half of the century. Most activity was concentrated around Roma, in the Surat basin of Queensland, where the town had been lit by gas for 10 days in 1906 and condensate sales commenced in 1928. Lake Bunga No. 1 drilled in the onshore Gippsland basin in 1924 is noted by Appea (1998b) as the first Australian oil discovery. There was limited and difficult production from Ranneywells (wide shafts sunk down to the Oligocene oil sands) through the war years, but it was not until 1953 that the first oil flow in Australia occurred at Rough Range No. 1, in the Carnarvon basin. Unfortunately, disappointment continued, and the following nine wells drilled at Rough Range were dry (Johnstone, 1979).
Fig. 6 [72,316 bytes] shows the main elements of the exploration process during 1850-53. The main driver was the growing market demand for petroleum products. In the 19th Century, whale oil was used for lighting, but, as the price rose with declining whale stocks, kerosine (mineral oil) was substituted leading to the development of oil shale deposits in the Sydney basin (1865, Pioneer Kerosine Works at Port Kembla). The advent of the motor car early in the 20th century expanded the market, and the high price of imported oil was a spur to local explorers. The Australian government recognized the need to cut the growing import bill (12.3% by value of all imports in the mid-1950s) and offered rewards and subsidies (Robertson, 1988).
Perceptions of prospectivity waxed and waned, as apparent hydrocarbon discoveries proved of insufficient size for sustained exploitation. Initially, Australia was thought petrolifierous, but the failure of early efforts established this orthodox wisdom of low prospectivity: Australia had no oil fields because it was geologically too old, and the absence of seeps was proof of this. In 1924, E. C. Andrews, the chief government geologist of New South Wales, reported that "ellipseOil, if found to exist in Australia, does not occur in the same manner as it does in other countries such as America, Asia, and East Indies, for if such were the case, it would have been found easily" (Andrews, 1924). Andrews was right. Most of the oil was offshore, and once the continental shelf became accessible in the 1960s, giant discoveries were made. Seeps did exist, but they were subsea, and only now do we have the technology to see them (O'Brien et al, 1998). In spite of these pronouncements, the local industry, augmented by international explorers, continued the search, and gained some reward when the Rough Range discovery sparked a surge in drilling activity and a stock market boom (Murray, 1972) and put Australian oil exploration on the world map.
The role of chance or luck in the discovery process (Fig. 6) is clearly demonstrated by Rough Range, where the only successful well of 10 was the first, and its location was determined by logistical considerations (Johnstone, 1979). When the top of the surface anticline was drilled, it proved to be dry, as did another seven wells drilled on the structure. Rough Range No. 10 recovered salt water with traces of waxy oil and gas on test, even though it was located only 244 m away from the original discovery well that had flowed 500 b/d of oil (Johnstone, 1979). The Rough Range accumulation was very small and geochemically anomalous (AGSO and GeoMark, 1996), but it produced a flow of oil at a critical time that sustained the search for indigenous hydrocarbons in Australia.
While the lucky first postwar well at Rough Range was a great stimulus to exploration, the failure of subsequent wells reversed the process-drilling activity declined, the value of Ampol Ltd. shares crashed, and perceptions of prospectivity were probably at their lowest. To counter this pessimism, the federal government introduced a 50% subsidy scheme for exploration drilling in 1957 (Robertson, 1988), and, in 1959, the Australian Petroleum Exploration Association (APEA) was formed because of "concern at waning public, government and even professional interest in Australia's oil search" (Wilkinson, 1988). These efforts were rewarded; drilling and seismic surveying increased, the first commercial finds of oil and gas were made in the Surat basin in the early 1960s, and a bonanza of discoveries followed over the next 10 years.
Figure 5 shows the state of knowledge of Australia's sedimentary basins and hydrocarbon occurrences in the period to 1960. The map has imprecise basin outlines, the underlying infra-basins were not recognized, and the offshore area was a "blank." Technology was at a similarly low level. The early years of the search were also hampered by a lack of drilling rigs and geophysical input. The level of knowledge grew exponentially with the addition of overseas expertise from the major explorers and the efforts of the Bureau of Mineral Resources, which shot the first seismic survey at Roma in 1949-50.
Each indication of gas in water bores sparked drilling activity, to be followed by disappointment. The coastal bitumen strandings added to the confusion, and it is only with recent advances in geochemistry that their message is being deciphered. Alexander et al. (1994) identified an Indonesian source for most strandings, and Edwards et al. (1999) have proposed a local offshore origin for others. In 1960, after almost 100 years of exploration, the only conventionally producible hydrocarbons were gas in the Surat basin and oil in the Carnarvon basin at the fabled Rough Range.
The hydrocarbons in the Surat basin were reservoired in Mesozoic sandstones but sourced from the Permian Gondwanan sediments of the underlying Bowen basin (Fig. 5). Rough Range was a representative of the Westralian supersystem, with the standard hydrocarbon habitat of the Carnarvon basin: oil in Lower Cretaceous sands sealed by Cretaceous shales. However, rather than being derived from marine Jurassic source rocks (Bradshaw et al., 1994), the oil in this case has been found to have been derived from non-marine facies (AGSO and GeoMark, 1996). Oil shows in water bores in the Canning basin and oil shales in the Georgina basin showed that the early Palaeozoic rocks of the Larapintine Supersystem were petrolifierous (Table 1). The Austral supersystem of the southern margin was signposted by the oil sands in the Gippsland basin.
1960-72: 'Fuels rush in'Murray (1972) must take responsibility for the title of this section, but the pun captures the essence of this episode when discovery followed discovery and the level of exploration activity built, as success bred further success. Fig. 7 [78,650 bytes] depicts the exploration process during this first major cycle of exploration and discovery. The big difference from the earlier period was the effect of technology, causing an improvement in exploration efficiency and making more of Australia's geological endowment accessible. Seismic and other geophysical surveying (Dooley, 1988) revealed the bones of the continent, the search for structural traps was paramount in exploration philosophy, and wells were more effectively located as valid tests. Advances in offshore drilling put the younger and more prospective basins of the continental shelves within explorers' reach, and giant fields were found in the Carnarvon and Gippsland basins.
These discoveries increased levels of exploration activity, fed the stock market resources boom, and set up a positive feedback loop of perceived greater prospectivity (Fig. 7). In 1972, flushed with the success of the first-cycle discoveries, the first quantitative estimate for undiscovered hydrocarbon resources in Australia was published (Konecki, 1972): 120 billion boe-the biggest estimate ever. Since then, as no more giant oil fields have been found, the estimates have become more conservative, with the current consensus view bouncing around 2-4 billion bbl of oil at the 50% probability level (McKay, 1983; Forman et al., 1992). As Powell et al. (1990) point out, these estimates are a realistic lower limit of the petroleum potential, but the real target for exploration remains the small, but significant, chance of very much larger potential expressed at the 5% probability level.
The price of oil remained low throughout this period, as it had been for the earlier part of the century (Fig. 8 [59,161 bytes]) and is again now. Despite the availability of cheap imported oil, Australian crude oil production was encouraged by regulated pricing and preferential treatment as feedstock to local refineries (Lavering, 1990). Australia experienced a resources boom, stimulated in part by oil but mainly by mineral discoveries (iron ore and nickel). The production of these mineral deposits for export required large infrastructure developments and the establishment of new townships in remote areas. The nation no longer rode on sheep's back, as mineral exports displaced wool as the major earner of foreign exchange. The recently discovered petroleum replaced imports, being primarily used for domestic consumption.
This success, after so long a search, was seen by the federal government as an objective achieved, and the exploration subsidy was now decreased (Fig. 7). There was further market intervention by the government in the form of regulated pricing, at slightly above import parity levels, to encourage the development of the local oil industry. In 1969, the government removed the 75¢ (Aus.)/bbl import parity price regime and entered into a 5-year, fixed-price contract for Bass Strait oil. This was a decision that had important implications in the years ahead, when the price of oil soared on the world market.
Australia's first cycle of petroleum discoveries followed a pattern seen in many basins the world over-the largest fields, in the most obvious trap types, are found first. The list of premier oil fields in Australian basins that were the first fields found includes Moonie (Surat), Mereenie (Amadeus), Dongara (Perth), Marlin (Gippsland), and Tirrawarra (Cooper). The success rates were not high (Fig. 9 [70,049 bytes]), but, in terms of discovery of giant oil fields, the first cycle of exploration and discovery, 1960-72, was the most successful.
The Commonwealth government's petroleum search subsidy scheme (1957-74) stimulated activity in previously unexplored areas (Powell et al., 1990). The discoveries drove further exploration drilling and seismic surveying, which escalated the level of geological knowledge and, in turn, improved exploration efficiency and led to more discoveries (Fig. 7). The fruit of this sustained effort through the 1960s is seen in Fig. 10 [179,184 bytes]-basins are now seen to extend offshore and new depocenters (Browse) are recognized there. Onshore, the older infra-basins underlying the Great Artesian basin are shown. In comparison with Fig. 5, much more of the map now shows oil and gas discoveries in numerous basins across the continent and a significant discovery in every Phanerozoic petroleum supersystem.
In the second part of this article, the authors analyze patterns of discovery in Australian exploration during these cycles: 1973-77 (the doldrums), 1978-88 (rising and falling oil prices), and 1989-98 (technology supreme); they also draw conclusions from their analysis of these patterns about the next cycle to come.
Marita Bradshaw is a Principal Research Scientist at AGSO and during 1996 was on staff exchange with WMC Resources working with the International New Ventures team. She has a BSc (Hons.) degree in Geomorphology from the University of Sydney and a PhD in evaporite and carbonate geology from the University of Western Australia. She has worked on Australian petroleum geology for the past 18 years, with a special emphasis on the North West Shelf, both at Esso Australia and then at AGSO. She played a fundamental role in the three AGSO-APRIA projects: Palaeogeographic Maps, Phanerozoic History of Australia, and Australian Petroleum Systems. Marita's current interests are in petroleum systems and oil families, and she is a member of GSA and PESA. E-mail: [email protected]
Clinton Foster is the Petroleum Research Group Leader and Senior Principal Research Scientist in Research Palynology in the Petroleum and Marine Division of AGSO. From 1976 to 1981, he was a Palynologist in the Geological Survey of Queensland. Prior to joining AGSO in 1991, he worked for Western Mining Corp., in charge of the application of palynology to both metals and hydrocarbon exploration. This research interest, particularly in the Permian and Triassic, continues at AGSO. A graduate of the Universities of Adelaide [BSc (Hons, First)], and Queensland (PhD), he is also an honorary Research Fellow at the University of Western Australia, and Adjunct Professor in Earth Sciences at Deakin University. He is a member of GSA, PESA, AAPG, and AASP. E-mail: [email protected]
Melissa Fellows graduated from the Australian National University in 1991 with a Bachelor of Economics and a Bachelor of Science with Honors (Geology). She has been employed with AGSO since 1993 working in a number of projects over a range of geoscience disciplines, including the Fill Spill project in the Timor Sea, Australian Seismic Hazard Assessment and the Urban Coastal Impacts Study in Moreton Bay. She is currently working with the Australian Basin Evaluation program on the Southern Margin. She is a member of PESA. E-mail: [email protected]
David Rowland has been employed by AGSO since 1995 and has provided technical support for the Australian Petroleum Systems Project and the National Biostratigraphic and Reservoir Database Project. David manages the RESFACS (Reservoir, Facies, and Hydrocarbon Shows) database and assists with the management of the STRATDAT (biostratigraphic) database. David holds an Associate Diploma in Geoscience, an Advanced Certificate in Applied Computing, and has three years of industrial experience in mining and exploration. E-mail: [email protected]
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