Patterns of discovery in Australia: Part 2

M.T. Bradshaw, C.B. Foster, M.E. Fellows, D.C. Rowland
Australian Geological Survey Organization
Canberra

This is the second and concluding part of an article on patterns of discovery in Australian oil and gas exploration. Part 1, includings Figs. 1-10, appeared last week (OGJ, June 7, 1999, p. 37).

1973-77: the doldrums

In late 1972, the conservative coalition government of 23 years was replaced by the Whitlam Labor government (1972-75), which burst on the scene with a reform agenda. In 1973, the global price of oil soared (Fig. 8) when war in the Middle East led to the Arab oil embargo, but, in Australia, political factors-regulated markets and prices and taxation-effectively blocked the effect of high oil prices (Fig. 11 [67,362 bytes]).

The fixed-price contract artificially maintained a low oil price for existing fields. World parity pricing was introduced in 1975 for newly discovered fields, and thus the differential between "old" and "new oil" was established. Other government policies (subsidy stopped, restricted foreign capital inflow, a national oil company mooted) were also a disincentive to investment, and there was practically a hiatus in the exploration and discovery process (Fig. 8).

Annual success rates were highly variable (Fig. 9) because of the small sample size: In 1976, only 15 exploration wells were drilled. Yet, despite the abysmal levels of activity, some key developments did occur. More of Australia's geological resources became accessible to explorers (Fig. 11). In 1975, the first deepwater well, Hapuku-1, was drilled in 384 m of water in the Gippsland basin, and deepwater permits were taken up on the Exmouth plateau in 1977.

The high global oil price, new drilling technology, and new geological knowledge all underpinned the move to deeper water. The BMR continental margins surveys (1970-73) and Shell Australia Ltd. surveys had revealed the Exmouth plateau and its potential for giant fields (Exon and Willcox, 1978; Wright and Wheatley, 1979).

A key development onshore was the recognition that the Mesozoic Eromanga basin did contain hydrocarbons (Fig. 12 [194,303 bytes]). For over a decade, wells drilling to underlying Cooper basin targets failed to properly assess the younger sediments. In some cases, Cooper basin development wells intersected but did not recognize overlying thin Mesozoic Eromanga petroleum pools. The accepted wisdom that the Eromanga was water-flushed was overturned by the Namur gas discovery in 1976 and the oil flow in Poolowanna-1 in 1977 (Table 1, Part 1).

1978-88: Rising, falling oil prices

The second cycle of exploration and discovery in Australia was very strongly controlled by the oil price (Fig. 8): The oil crisis of 1978-79, precipitated by the Iranian revolution, again sent global oil prices soaring to heights never seen again. In Australia, exploration investment was able to respond in a more favorable fiscal and regulatory regime (Fig. 13 [74,645 bytes]). Tax write-offs, the elevated price for "new oil," and other incentives were sufficient to encourage high levels of exploration activity, despite the high cost of money as reflected in business lending rates (Fig. 14 [50,490 bytes]). The high oil price made smaller, newly discovered fields commercial, and nonconventional petroleum resources such as oil shale were again considered a viable option in the heady days of $40 (U.S.)/bbl oil. Advances in organic geochemistry and maturation modeling now ensured that exploration was driven by the search for viable source rocks as well as for structures (Fig. 13). Detailed experimentation and establishment of criteria to assess the quality and thermal state of potential source rocks (Rock Eval) by French researchers (Robert, 1988) were a key development. During this cycle, the supremacy of the four-way dip closure was also challenged, and the deliberate search for subtle stratigraphic traps began using the sequence stratigraphic concepts of Vail and others (Payton, 1977; Halbouty, 1982).

Exploration drilling reached record levels in the early 1980s, as did the number of discoveries. For all that activity, however, the volumetric success of the first cycle of exploration was not achieved. The only giant fields found were gas: Scarborough and Gorgon. Some very significant oil discoveries were also made (Harriet, Jabiru, Jackson) although none over 100 million bbl-with the exception of Fortescue in the Gippsland basin.

This was the period when the myth that Australia is gas-prone became firmly entrenched (Fig. 13). The discovery of the giant gas fields at North Rankin and Scott Reef (Robertson et al., 1976) in the early 1970s established this view and was one of the factors contributing to the downturn in the mid-1970s. The disappointment of the dry gas found on the Exmouth plateau tended to confirm this opinion. When the search was restricted to onshore, the oil-prone Paleozoic Larapintine systems were explored, but later offshore discoveries were from younger petroleum systems whose source rocks commonly had a land plant contribution that tended to favor gas generation (Bradshaw et al., 1994). However, recent studies (O'Brien et al., 1998) show that post-accumulation process, rather than original source type, is often the determinant of whether a field is gas or oil on the North West Shelf.

Many plays, no giants

Although no giant oil fields were found, there were many discoveries in a great diversity of plays and basins (Fig. 15 [204,125 bytes]). Jabiru and Challis established a new productive province in the Timor Sea, and commercial hydrocarbon gas (North Paaratte) was found in the Otway basin (Table 1). Jackson, drilled in 1981, was the premier onshore find of this second cycle of exploration. It remains the largest oil field found in the Eromanga basin, and it was soon followed by other oil discoveries in the Queensland section of the basin, including Nockatunga (1981), Tintaburra (1983), and Bodalla South (1984).

In 1982, nearly 20 years after the Barrow Island discovery, the next commercial follow-up was found: the South Pepper oil field (Williams and Poynton, 1985). A string of other fields in the Barrow subbasin followed-Harriet, North Herald, Chervil (1983), and Saladin (1985). The Blina oil discovery (1981) in the Upper Devonian carbonates of the Canning basin was the first commercial find in the basin after over 50 years of exploration; the Sundown discovery in Permian sandstones the next year proved an additional play type.

After peaking in 1980-81, oil prices declined, falling rapidly in 1985-86. Exploration drilling followed a similar pattern, with a lag of 2 or more years (Fig. 8). Offshore exploration (peak year 1983) appears more sensitive to price control than less-expensive onshore drilling (peak year 1985, Fig. 2). In Australia, the decline in oil prices was compounded by the initial uncertainty surrounding the introduction of the Resource Rent Tax in 1985, high interest rates (Fig. 14), and the stock market crash of October 1987.

The success rate also shows a steep decline in the mid 1980s (Fig. 9), possibly because the technology of the era was being pushed to its limit at the end of the cycle, when most of the robust prospects had already been drilled. Evidence that the discovery rate was limited by the level of technology is provided by the many discoveries in the next cycle made close to where earlier wells had narrowly missed accumulations. Examples include the Macedon-Pyrenees oil and gas fields found in 1992-93 on the same structure that had been unsuccessfully drilled as West Muiron-1, 1A, and 2 in 1972-75 and again in 1981, as Jurabi-1 (Mitchelmore and Smith, 1994); and the Tenacious discovery made in 1996 after Octavius-1 (with 3 sidetracks) and Octavius-2 had failed to intersect the oil column when drilled in the mid-1980s (Bradshaw et al., 1998). The decline in the success rate may also reflect the effect of staff reductions: 1986 was also the year of major "downsizing" by several companies. Employment levels in the petroleum industry, as reported by APEA, dropped from a peak in 1985 of 14,328 to a low of 8,814 in 1986 (Bogan, 1988).

1989-98: technology supreme

In the mid to late 1980s, Australian exploration activity was checked but it did not fall to the dismal levels of the mid 1970s and in the early 1990s began to climb again (Fig. 1). The large Wanaea oil discovery (150 million bbl recoverable at 50% probability-Department of Resource Development, 1998) in 1989 stimulated interest by re-establishing the feedback loop between discovery, perceived prospectivity, and increased exploration (Fig. 16 [75,857 bytes]).

The Griffin discovery (47 million bbl) the next year followed by Wandoo (57 million bbl) entrenched this relationship for the Carnarvon basin. In 1990-91, the Persian Gulf crisis and war briefly made the oil price rise sharply (Fig. 8), but in this third cycle advances in technology, principally 3D seismic, have been the driver of the discovery process. The upward trend in success rate (Fig. 9) through the 1990s is evidence of the impact of 3D seismic as an exploration tool in decreasing trap risk (Vaughan, 1993).

An expansion of Australia's effective geological endowment also occurred in 1989. The Timor Gap Treaty between Australia and Indonesia was signed, allowing exploration in the newly created joint development Zone of Cooperation (ZOC) in the Timor Sea (Fig. 16). This area had been out of bounds since 1975, due to uncertainty of tenure related to the change of regime in East Timor.

The offshore resources accessible to exploration now includes water depths to 2,300 m or more, due to improvements in engineering technology. Fig. 2 shows that there has been a small rise in the average water depth of offshore exploration wells during the 1990s, although the great depths plumbed in 1979-80 remain untouched in Australia.

Deepwater exploration is occurring in other provinces (Gulf of Mexico, West Africa, and Brazil), but it is a moot point whether similar endeavors will occur in Australia in a climate of depressed oil prices. Explorers may recall that the offshore wells drilled in the Gippsland basin to find the giant fields in the 1960s were the first offshore wells drilled in the world in a basin where there was no established onshore production. Perhaps the deepwater basins of the southern margin will follow a similar exploration history, being the first deepwater discoveries made in a basin where there is no production on the shelf?

In 1995-96, growth in global oil demand-especially from Asia-coupled with the perception of oil being a declining resource (Campbell, 1995) led to a rise in oil prices (Fig. 8). This short-lived upswing coincided in Australia with a string of notable discoveries-Cornea, Undan-Bayu in the Australia-Indonesia ZOC (Brookes et al., 1996) and Laminaria (Smith et al., 1996)-that showed there remain large oil fields, if not giants, to be found "down under." The resulting strong level of activity is still being maintained, despite very low oil prices and the Asian economic crisis. Figures to date show that 1998 will be a record year for offshore exploration drilling, but there has been a decline in the number of onshore wells (Fig. 2).

The question remains as to whether there will be another fall in exploration activity with continued low oil prices as in the previous cycle. Some companies in previous downturns have adopted a deliberate counter-cyclic strategy that uses a time of low oil prices for research, investment, and adding reserves through purchase rather than exploration. Another counter-balance to declining exploration activity is that Australia is now a preferred exploration destination (Baker, 1995). Although global exploration is declining, Australia's market share is growing, helped in part by a competitive fiscal regime, a stable political system, ease of access to geological information, and an enhanced perception of the petroleum prospectivity of the continent in response to recent discoveries.

A sharp decline in the annual success rates marked the close of the previous two cycles of exploration and discovery, but, as yet, there is no indication of a similar fall in the 1990s (Fig. 9). There are still entire petroliferous basins where the new technologies of this cycle have not been applied, including the Arafura basin and the Abrolhos subbasin, and the thick Mesozoic basins of the southern margin remain largely untested (Edwards et al., 1999).

Fig. 17 [183,176 bytes] shows the effect of the 1990s discoveries that have put the Browse basin (Gywdion, Cornea), the Beagle subbasin (Nebo), and the Sahul and Flamingo synclines (Elang, Laminaria) on the oil discovery map. Apart from the new basin areas, there have also been new plays added to the inventory. The Maitland gas/condensate discovery is the first accumulation found in the Cenozoic of the Carnarvon basin (Sit et al., 1994). Long-range migration was demonstrated by the Wandoo discovery, which proved the eastern margin of Carnarvon basin to be an oil province (Delfos and Boardman, 1994).

The Gwydion (Spry and Ward, 1997) and Cornea (Stein et al., 1998) discoveries on the eastern margin of the Browse basin followed. They were found in an area of shallow basement that had previously been considered nonprospective (Figs. 12 and 17). Perseus, found in 1996, more than 40 years after the first discovery in the basin, is not only a new play type (Taylor et al., 1998), but it may be the largest field in the Carnarvon basin in terms of BOE, having 200 million bbl of liquids and over 8 tcf of gas (Department of Resource Development, 1998).

During 1970-95, Australia's remaining oil reserves stayed approximately unchanged, as new additions replaced production; and most of the increase in initial reserves was due to growth in reserves and extensions of large fields discovered before 1970, in the first cycle of exploration and discovery (Bureau of Resource Sciences, 1997).

A similar pattern, over a longer time period, is seen for reserves in the U.S., as reported by McCabe (1998). Most of the increase in reserves was due to revisions and adjustments to earlier found fields, excepting the dramatic spike of the Prudhoe Bay discovery in 1970. Since the 1920s, additions to reserves in the U.S. have kept a steady 10-14 year inventory of supply (Fig. 3 in McCabe, 1998). However, recent discoveries in Australia have produced a jump in initial oil, condensate, and gas reserves, increasing the liquids inventory by nearly 200 million bbl in the latest estimates (AGSO, 1998).

This pattern of discovery, with recent finds rivaling those of the first harvesting of resources, emphasizes that Australia is underexplored and that much undiscovered potential remains to be found.

The next cycle?

Hydrocarbon exploration and discovery is a complex process pushed by factors both real and imagined; perceptions can be as important as reality. It has a boom-and-bust pattern typical of many things Australian, from the economy to the El Ni?o-influenced climate and ecology (Flannery, 1995).

With increasing understanding of the drivers of activity, such as the oil price itself, the industry's responses may become more moderated, and the swings in activity may become less extreme as suggested in Fig. 1. Campbell and Laherrere (1998) predict declining global production and corresponding rising oil prices in the first decade of next century; this may be the stimulus to a fourth cycle of increased exploration activity in Australia.

An analysis of the maps and Table 1 reveals a number of basins where indications of hydrocarbons are yet to culminate in commercial discoveries-Arafura, Georgina, Officer, and Duntroon basins. Another example is the Abrolhos subbasin of the Perth basin (Houtman subbasin in some usages-Hocking, 1994), where Houtman No. 1 intersected a gas-saturated Jurassic sandstone with a considerable liquids content (Seggie, 1990) and Livet No. 1 recovered live oil from a residual column in a Permo-Triassic sandstone (Oil & Gas Gazette, 1996).

The onshore Paleozoic basins are more problematic. The organic matter in Larapintine source rocks is dominated by algal material so that oil generation is favored, but only over a narrow range of time and temperature, with the main maturation event in the middle Palaeozoic (Bradshaw et al., 1994). Careful analysis of the operation of the petroleum system is required, in order to find accumulations that have been preserved over the hundreds of millions of years or areas where late generation and trapping may have occurred.

Acknowledgments

The authors thank Rex Bates for drafting the figures; Ian Lavering, John Bradshaw, and Peter and Robyn Purcell for reviewing the paper; Bev Allen and others in the library for research assistance; and colleagues from AGSO and industry for useful discussions during the development of these concepts. Prof. Bill Mandle, University of Canberra, and Lynne Thompson, Treasury, provided useful economic and historical information and perspective. The authors publish with the permission of the Executive Director, AGSO.

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