James A. Deckelman
Magellan Petroleum Australia Ltd.
Brisbane
An undrilled prospect with 140 sq km of seismicly defined structural closure, demonstrated petroleum potential, and the prospect of expanding gas markets were the factors that led Magellan Petroleum Australia Ltd. to acquire EP 15, a large exploration permit in Australia's Northern Territory.
The acquisition of EP 15 provided Magellan with title to a 15,500 sq km area encompassing most of the Ngalia basin, a virtually unexplored area only 80 km north of the oil and gas producing Amadeus basin.
Following the grant of the permit in 1990, Magellan launched a prudent and low cost exploration effort that added three prospects to the permit's portfolio.
At the same time, however, seismic stratigraphic work downgraded the potential of the permit's original and largest prospect, and it became increasingly clear that the state government would not support the interstate sale of gas, an element critical to the commercial success of the project.
Magellan now faces an exploration challenge much different to that it originally envisaged.
TECTONO-STRATIGRAPHIC FRAMEWORK
The Ngalia basin is an elongate intracratonic basin encompassing 16,000 sq km of the central Australian outback (Fig. 1) (23561 bytes).
It is 80 km north of the Amadeus basin, which hosts more than 55 million bbl of proven original oil and condensate in place and more than 1.2 tcf of proven original gas in place. The Ngalia basin was contiguous with the Amadeus basin through much of geologic time.
The Ngalia basin sedimentary sequence ranges from late Proterozoic to Carboniferous in age (Fig. 2) (11219 bytes). It rests unconformably on Precambrian igneous and metamorphic basement and contains seven major interformational unconformities.
The preserved Proterozoic to Ordovician sequence, comprised of marine siliciclastics, carbonates, and evaporates, differs from the Devonian to Carboniferous sequence which consists mainly of continental clastics.
Although the maximum aggregate thickness of Ngalia basin sediments exceeds 9,000 m,1 the greatest known preserved thickness of sediments is 6,400 m. The preserved sedimentary section is thickest in the north, imparting a pronounced asymmetry to the basin.
Repeated periods of tectonism affected the Ngalia basin from Proterozoic to early Permian time.1 2 From a petroleum perspective, periods of late Proterozoic dextral shear and Carboniferous compression were most significant .3 These events had the strongest influence on petroleum generation and migration, the greatest effect on reservoir quality, and created the structural traps that form the basin's primary exploration targets.
PREVIOUS DRILLING
Only one petroleum exploration well, the Davis 1, has been drilled in the permit area (Fig. 1) (23561 bytes). It was drilled in 1981, prior to Magellan's current tenure, near the crest of a closed anticline with excellent surface expression.
The well was designed to evaluate the petroleum potential of strata then considered to be correlative with Ordovician petroleum reservoirs in the Amadeus basin.
It was located 1.85 km west of a shallow mineral exploration well, DDH DAY 1, which encountered minor amounts of gas in the Carboniferous Mt. Eclipse sandstone. Although the structure's closure was well defined at the surface, closure at depth was uncertain because no seismic data had been acquired in the area.
Davis 1 was drilled with air to TD 1,899 m. It penetrated a thick Carboniferous and an abbreviated Cambrian and Precambrian sequence before terminating in low grade metamorphosed orthoquartzite intruded by granite (Fig. 3) (10840 bytes). No gas detection equipment was operational at the time of drilling, but "trip gas" was recorded on two occasions and wireline logs indicated moderately high hydrocarbon saturation in several zones in the Mt. Eclipse sandstone and the Mt. Doreen formation (Fig. 3) (10840 bytes).
In addition, gas-saturated formation water accumulated in the hole while tripping prior to cutting a bottomhole core. The accumulated water was displaced with mud, and gas emanating from the water flared for several hours.
On an air- and nitrogen-free basis, methane was the dominant component of an air-contaminated sample of this gas (see table) (4179 bytes). Although the origin of the gas is uncertain, it is likely that it was produced from low porosity limestone in the Adelaidean Mt. Doreen formation, perhaps with minor contribution from sandstone in the middle part of the Mt. Eclipse sandstone.
Despite the encouraging shows of gas, the penetrated sequence was dominantly water-saturated and had poor reservoir quality. Moderate porosity was present in the upper and middle parts of the Carboniferous Mt. Eclipse sandstone, but it reduced considerably with depth due to the burial-induced effects of silicification. Low porosity limestone was intersected in the Adelaidean Mt. Doreen formation; the remainder of the penetrated sequence was generally devoid of porosity. Accordingly, the well was plugged and abandoned.
PETROLEUM GEOLOGY
SOURCE ROCKS
Although the Carboniferous Mt. Eclipse sandstone and the Adelaidean Albinia formation may have source potential, the Rinkabeena shale is the only formation in the permit area likely to generate appreciable quantities of petroleum (Fig. 2) (11219 bytes).
The Rinkabeena shale is a transgressive marine sequence comprised of light grey to black calcareous and locally pyritic shale. It is preserved in two lobes centered in the northeastern and northwestern parts of the basin, where it is likely to be greater than 500 m thick.
Geochemical analysis of samples from Davis 1 indicates that the Rinkabeena shale is a post mature source for gas and that its source potential increases toward the base of the formation. Analyzed samples have a maximum total organic carbon content of 0.8% and, in one sample, a discernible organic maceral suite comprised of converted sapropelic organic matter and micrinite.
GENERATION, MIGRATION
Lopatin maturation principles, when applied to Ngalia basin burial history curves, suggest that Adelaidean source rocks entered their peak oil generation phase prior to or during deposition of the Mt. Eclipse sandstone. Continued sedimentary loading during later phases of deposition of the Mt. Eclipse sandstone, and possible minor loading in post-Carboniferous time, probably progressed the maturation process to the gas generation stage prior to the end of deposition of the Mt. Eclipse sandstone. Migration of some Adelaidean-sourced gas may have immediately followed its generation, but most gas probably migrated into structures formed subsequently during the Carboniferous Mt. Eclipse orogeny.
Most potential source rocks in the Mt. Eclipse sandstone, except perhaps for those at the base of the formation, probably never reached a peak oil or gas generation phase. All empirical data from the permit area indicate that the Ngalia basin is gas prone.
RESERVOIRS
Yuendumu sandstone. The Yuendumu sandstone has the permit's greatest conventional reservoir potential. It is a transitional fluvial to shallow marine sequence comprised of fine to coarse grained quartz arenite with lesser amounts of quartz wacke, arkose, and subarkose. It is confidently correlated with the Arumbera sandstone of the Amadeus basin, which contains up to 21.7% porosity on logs, hosts 38 bcf of proven and probable original gas in place at Dingo field, and has produced substantial flows of gas in several other wells.
Porosity in the Yuendumu sandstone is likely to result from the secondary dissolution of feldspar and carbonate cement. Porosity originated by this process in the Arumbera reservoir at Dingo field.
Kerridy sandstone. The Kerridy sandstone is a flu-vio-deltaic sequence comprised of interbedded sandstone and siltstone. It has no demonstrated reservoir potential except where it is fractured. It had little to no matrix porosity in Davis 1 (average ø < 1%; maximum ø : 6.9%), but it is the primary aquifer in the Yuendumu area, where it produces water from a network of tectonic features.
In the western part of the permit area, the Kerridy sandstone comprises two high-amplitude stacked sequences that exhibit northward downlap and contain northward prograding clino-forms (Fig. 4A) (69916 bytes). These sequences are interpreted to be deltaic lobes that prograded toward a basinal area to the north. The depositional architecture of the Kerridy sandstone contrasts markedly with the overlying Mt. Eclipse sandstone, which displays southward thinning and onlap (Fig. 4A) (69916 bytes).
Mt. Eclipse sandstone. The Mt. Eclipse sandstone is a proximal molasse sequence that accumulated in a dominantly fluvial environment. It is comprised of sandstone and conglomeratic sandstone with shale and siltstone interbeds. That part of the Mt. Eclipse sandstone that occurs at shallow depths commonly has good porosity.
Vaughan Springs quartzite. The Vaughan Springs quartzite is comprised of sandstone, orthoquartzite, and minor conglomerate. The Treuer member of the Vaughan Springs quartzite contains siltstone, sandstone, and in the central part of the basin a significant thickness of evaporites. With the exception of fluvial sediments at the base of the formation, the Vaughan Springs quartzite was deposited primarily in a marine environment.
Because of its high degree of consolidation, the Vaughan Springs quartzite is likely to have little conventional reservoir potential. However, in tectonicly disturbed areas and in extensional areas at the crests of anticlines, it may have considerable fractured reservoir potential. The Heavitree quartzite, its Amadeus basin correlative, produced flows of gas from fractures in the Magee 1 well.
Djagamara formation. The Djagamara formation, previously thought to have excellent reservoir properties on the basis of outcrop characteristics and its tentative correlation with the oil and gas producing Pacoota sandstone of the Amadeus basin, is now known to be a poor reservoir at depth.
SEALS
Effective seals are likely to be developed in the salt-bearing Treuer member of the Vaughan Springs quartzite, in the Rinkabeena shale, in the Walbiri dolomite, and in impermeable shale and siltstone of the Bloodwood formation (Fig. 2) (11219 bytes). The Rinkabeena shale, because of its lithology and thickness, should adequately seal hydrocarbons reservoired in the Vaughan Springs quartzite. The Walbiri dolomite and the Bloodwood formation, ideally situated to seal hydrocarbons reservoired in the Yuendumu sandstone, also should form excellent seals.
The dominant trapping mechanism in the Ngalia basin is structure. Most structural traps are related to periods of late Proterozoic dextral shear and-or Carboniferous compression that resulted, in most areas, in the formation of faulted anticlines.
Traps with both structural and stratigraphic components are recognized in only a few areas.
RECENT EXPLORATION
Since the grant of the permit in 1990 Magellan has carried out a low-cost exploration effort focusing on the delineation of large, previously recognized Newhaven prospect and the identification of new prospects addressing potential Cambrian reservoirs that were absent in Davis 1.
In the first permit year, Magellan reprocessed much of the permit's existing seismic data and carried out a detailed surface geologic mapping program to delineate a series of surface structures in the northern part of the permit area. In the second permit year, 100 line km of 75-fold Vibroseis seismic data were acquired to further delineate leads identified in the seismic data reprocessing and surface mapping programs.
The results of this work were mixed. The potential of the Newhaven prospect was downgraded when a seismic stratigraphic interpretation showed that a key interval, previously interpreted to be correlative with Ordovician petroleum producing strata in the neighboring Amadeus basin, was actually Proterozoic in age. At the same time, however, three new prospects were identified.
PETROLEUM PROSPECTS
WEST REEL PROSPECT
The West Reef prospect is a seismicly defined, low relief, east-southeast trending structural high that formed during periods of late Carboniferous compression (Fig. 4) (69916 bytes). It is located in the northwestern part of the permit area, approximately 23 km southwest of the Davis 1 well.
Progradational sediments in the Kerridy sandstone (Fig. 4A) (69916 bytes) and a potentially fractured Vaughan Springs quartzite form the primary reservoir objectives. Hydrocarbons are expected to be sourced by the Rinkabeena shale and sealed by intraformational shales and fine grained clastics in the basal part of the Mt. Eclipse sandstone.
Success at the West Reef prospect depends largely on a substantial improvement in the reservoir quality of the Kerridy sandstone, fracturing in the Vaughan Springs quartzite, and the sealing integrity of the Mt. Eclipse sandstone. The prospect is likely to be gas prone, and additional seismic data are required to confirm the structure's southward closure (Fig. 4B) (69916 bytes). A 3,170 m well is required to test this prospect.
WEST TREUER PROSPECT
The West Treuer prospect is located in the northwestern part of the permit, approximately 30 km southwest of Davis 1. It is a seismicly defined prospect consisting of two structural highs developed on the upthrown side of northeast trending thrust faults (Fig. 5) (10316 bytes). These highs developed during periods of late Proterozoic compression and were probably modified during the Carboniferous Mt. Eclipse orogeny. Lateral closure is entirely structural in nature; vertical closure is provided by impermeable sediments in the Kerridy sandstone which unconformably overlie Proterozoic reservoirs at the crest of the structure.
The West Treuer prospect targets extensional fractures that are interpreted to have developed at the crest of the structure in the Vaughan Springs quartzite. The Rinkabeena shale, directly overlying the Vaughan Springs quartzite on the flanks of the structure, is the probable source, and impermeable sediments in the Kerridy sandstone are probable seals.
The prospect is likely to be gas prone and can be fully tested with a well drilled to a depth of 3,600 m.
NEWHAVEN PROSPECT
The Newhaven prospect is located in the central part of the permit area along an easterly trending fault complex that resulted from late Proterozoic dextral shear and Carboniferous northward and southward salt-involved thrusting (Fig. 6) (32211 bytes). It contains several seismicly defined structural culminations that form a contiguous closed area in excess of 140 sq km.
The Vaughan Springs quartzite is the primary reservoir objective. Due to its degree of consolidation and tectonic history, it is expected to be highly fractured in this area.
Salt in the overlying Treuer member of the Vaughan Springs quartzite should form an effective seal, and the Rinkabeena shale, which overlies the Vaughan Springs quartzite to the east, is the expected source. The Kerridy sandstone, structurally closed in the western part of the prospect area, may constitute a secondary objective.
The prospect is expected to be gas prone and can be fully tested with a well drilled to 1,620 m.
BEANTREE PROSPECT
The Beantree prospect is located in the north-central part of the permit, approximately 21 km southwest of Yuendumu. It is an easterly trending anticline, bounded to the south by a series of north-dipping thrust faults, which formed in response to southward compression and associated sinistral shear. Outcrop and seismic data define fault-independent closure to the Rinkabeena shale level in all directions. The Yuendumu sandstone, lying at a depth of only 480 m, is the primary target at the Beantree prospect. The Rinkabeena shale is the probable source; the Walbiri dolomite and the
Bloodwood formation are probable seals. Secondary targets with possible fracture development are brittle carbonates of the Mt. Doreen formation and highly indurated clastics in the Treuer member of the Vaughan Springs quartzite. All of these targets can be reached by a well drilled to a depth of 2,100 m.
The Beantree prospect is flanked by the Kerridi prospects to the east and by the Walbiri prospect to the north (Fig. 7A) (32185 bytes). These prospects would considerably enhance the potential of the area if a petroleum discovery were made at the Beantree prospect.
MARKETING OBSTACLES
For most explorers the search for oil and gas is far more challenging that the sale. This was certainly true for Magellan when it acquired EP 15 in 1990. Most intrastate gas markets were satisfied, but oil was readily marketable and promising gas markets were emerging across state borders, primarily in Queensland's Mt. Isa mining district and in South Australia's capital city of Adelaide.
Two years later, however, an unexpected development paralyzed the state's gas industry. Nearby Amadeus basin producers, having all existing Northern Territory gas markets satisfied until the year 2008 plus 500 bcf of uncommitted reserves, were denied state government approval to market their surplus gas interstate. In the foreseeable future, the marketing of gas discovered in EP 15 would therefore be nearly impossible.
Third-party access to the Amadeus basin-Darwin trunk line, talk of a national pipeline grid, and new local markets are encouraging signs for Northern Territory gas producers. In addition, a major discovery of gas in EP 15 may constitute the critical addition to Northern Territory reserves required for the sale of gas interstate. Until that happens, however, marketing will be every bit as challenging as exploring in a permit that is expected to be gas prone.
THE FUTURE
EP 15 is one of the world's few remaining petroleum provinces that contains large, undrilled, shallow structures in reasonable proximity to production. Due to technical and recently introduced commercial risks, however, the fate of the permit is now uncertain. Its future lies in the hands of persevering explorers like Magellan and a government with the courage to actively encourage resource development with tangible market incentives.
ACKNOWLEDGMENTS
The author gratefully acknowledges the technical contributions of John Davidson of Petrecon Australia Pty. Ltd., the drafting efforts of Gordon Hoffer, and the word processing skills of Ruth Watkins.
REFERENCES
- Wells, A.T., and Moss, F.J., The Ngalia basin, Northern Territory, stratigraphy and structure, Bureau of Mineral Resources Bull. 212, Australian Government Publishing Service, Canberra, 1983, 88 p.
- Shaw, R.D., Zeitler, P.K., McDougall, I., and Tingate, P.R., The Paleozoic history of an unusual intracratonic thrust belt in central Australia based on 40Ar - 39Ar, K-Ar and fission track dating, Jour. Geol. Soc. London, Vol. 149, 1992, pp. 937-954.
- Davidson, J.K., Seismic/structural interpretation of the Ngalia basin, unpublished report for Magellan Petroleum Australia Ltd., 1991, 17 p.
THE AUTHOR
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
