Assessments Of Hydrocarbon Potential

Techniques used in the assessment of the hydrocarbon potential of specific basins vary considerably with the amount of knowledge available for that basin. The simplest is to compare the basin size with other producing basins and to use a worldwide average hydrocarbon yield. The normally used yield is 1900 m3 (12,000 barrels) of oil or oil equivalent (1070 m3 gas equivalent to one m3 oil) per km3 of sediment (Miller et al., 1975; St. John, 1986). The accuracy of this method can be questioned as the validity of the worldwide analog chosen depends on the presence in the basin of the basic requirements of oil generation. Hence, the preferred evaluation method is to compare the various parameters which control the generation and accumulation of oil or gas with those for nearby producing basins with similar geological settings and histories. Once a basin has been drilled and most of the exploration parameters have been defined, then a basin can be separately evaluated much more accurately. As most of the basins of the southern Pacific have not yet been explored in detail, it is necessary in most instances to use the comparative techniques to evaluate the various controlling conditions for hydrocarbon generation and accumulaton.

There are four principal parameters which control hydrocarbon accumulation.

Source material

Natural oils and gases are a complex mixture of hydrocarbon compounds that range from methane to long chain waxes and aromatic molecules. They are formed from non-skeletal organic debris that has been buried in sedimentary rock. The first major criterion for exploration is to have large enough concentrations of organic material present to form a potential source bed. The type of the organic debris can affect the type of hydrocarbon generated. When coals or shales contain the debris of terrestrial higher plant-life of trees and shrubs, gases and gas condensates or waxy light crude oils are produced (Tissot and Welte, 1978). This is the normal situation in New Zealand and in the Gippsland Basin. When marine shales contain planktonic debris as the primary source of organic matter, heavier to light crude oil with smaller amounts of gas tend to be formed. These are the types of oils found in the North Sea and Middle East. Until well samples become available to assess whether sufficient organic matter is present, the presence and type of source rock are inferred. These inferences are based on the assumption of similar geologic conditions being present in similar basins and knowledge of present-day oceanography (Demaison, 1984).


When organic matter is buried for a sufficient period, the temperature and pressure increase and the transformation from organic debris to natural oils and/ or gases takes place. The source rock at this point is said to be "mature". At more extreme conditions beyond the "maturation" level, the more complex hydrocarbon molecules start to break down to simple gases and eventually these will dissociate to carbon and hydrogen. There is therefore an optimum set of conditions for the formation of oil and gas known as the "oil window". The definition of the maturation conditions for the potential source rocks is therefore the second criterion for exploration. Normally, this is measured within a well using the effects of chemical change on the reflectance of coaly particles or the colour change in pollens and spores (Héroux et al., 1979; Hood et al., 1975). The zone of maturation for oil is accepted when a reflectance (Ro) of 0.6 for marine and 0.7 for non-marine source rocks has been reached. Even if no wells have been drilled in a basin, it is possible to model the depth at which maturation is reached using the basic knowledge of the burial history of a basin and the heat flow (Tissot and Welte, 1978).


Once hydrocarbons have been formed they are disseminated through the source rock. Before any commercial recovery can be made, the hydrocarbons must be concentrated in a reservoir rock. Commonly, these are well-graded sandstones or porous limestones with 20-30% pore space. Along with the porosity, it is necessary to have good permeability that will allow the free flow of oil and gas from the rock under production. As with source rocks, the presence of reservoir rock can only be inferred until the area has been drilled.


The final criterion for hydrocarbon accumulation is the presence of a trap. Just as oil and gas float on water so they rise in a reservoir rock. In situations where the reservoir rock is sealed by a cap rock and is a raised structure, hydrocarbons can accumulate. Good knowledge of the rock sequences (stratigraphy) allows interpretation of whether a cap rock or seal is present. The raised structural positions are formed by folding and/or faulting if they are not a natural feature of the rock such as a buried reef. Detailed seismic surveys are used to find such structural features. These surveys also delineate the extent of the structures. By combining this with the thickness of the reservoir, an estimate of the likely size of any potential reserves can be obtained. The faulting and folding in a basin are the result of the forces acting on the sediments. These are often active well after the sediment has been laid down and are usually unique to each basin. The broad geological situation of a basin, including the timing of major compressional or tensional events, can give some idea of the type of structure to be expected in an unexplored basin.

REGIONAL HYDROCARBON EVALUATION Exploration provinces limited to Cretaceous-Tertiary basins

The southern Pacific coast of the Gondwana supercontinent consisted of portions of what has become eastern Australia, New Zealand and western Antarctica. The Palaeozoic interior of Gondwana was composed of sedimentary and igneous rocks which have become the schists and gneisses of the Transantarctic Mountains of Antarctica, the Great Dividing Range of Tasmania and Australia and the western province in New Zealand which consists of Nelson, Fiordland and, in the east, the Campbell Plateau.

Seaward of the old Gondwana Coast, deep ocean basins filled with sediment during the early to Mid-Mesozoic. The rocks so formed, together with their associated volcanics and accreted ophiolites, suggest subduction along this ancient coastline during Permian to Jurassic times (St. John, 1986). These rocks now make up a partially to fully metamorphosed belt exposed in the Southern Alps of New Zealand and in Marie Byrd Land, Ellsworth Land and the ranges of the Antarctic Peninsula.

Because all of these rocks have been exposed to the extreme temperatures and pressures of metamorphism, their source and reservoir potentials have been degraded. The hydrocarbons in the rocks have been degraded and any pore space has been filled by minerals. The main hydrocarbon potential is therefore restricted to those basins containing the younger Cretaceous and Tertiary sediments.

Sedimentary infill and reservoir rock similarity

To evaluate the hydrocarbon potential of the basins of the southern Pacific, we compare them with hydrocarbon-producing basins close by, namely the Taranaki and Gippsland Basins. This is necessary because some of the basins have not been drilled and their rock infill sequences are as yet unknown.

With the basins now spread over a latitudinal range of 38°S to 78°S with vastly different present-day climates, it is difficult to see how any analogy of the basins could be valid. We must, however, go back 100 million years to the Late Cretaceous when the continents of the region made up part of the Gondwana supercontinent. The areas that would subsequently contain the prospective basins of

Gippsland, Taranaki, Campbell Plateau and the Ross Sea were then grouped very closely (Fig. 6.2) (Grindley and Davey, 1982).

With the onset of the breakup of Gondwanaland, a series of depressions and failed rifts formed and it was these depressions which began to accumulate the sediments that now form the various basins (Falvey, 1974).

Typically, such basins formed through separation are initially infilled by nonmarine river sediments followed progressively, as the sea encroaches, by deltaic coal measures, then beach and marine sands and shales leading eventually to open ocean carbonate muds. It can be expected that similar reservoir rocks (porous and permeable sandstones) will occur in all of these basins.

Source rock similarity

While the similar geological environments will give rise to similar sediments, it is the climate which controls the type and amount of organic matter growing in a region and this in turn controls the hydrocarbon source rock potential.

Given that the basins were all grouped together within a narrow latitude range of 10-20° and had similar non-marine to marginal marine depositional environments during the Upper Cretaceous, it is not unreasonable to suggest that all the basins were receiving very similar organic debris. From the reconstructions of Gondwanaland, we find, however, that these basins lay at latitudes of 70-80°S. This is well south of what could be considered a temperate forest zone today. Yet, the deposition of extensive coals containing dominantly temperate climate podocarps with lesser beeches and ferns in the New Zealand and the Gippsland basins (Mildenhall, 1980) means that the latitudinal climatic zonation during the Late Cretaceous to Eocene was not similar to the present regime. Recent work by Hallam (1984) on the distribution of minerals deposited in environments controlled by specific climates and the distribution of coals worldwide suggests that a much broader temperature versus latitude zonation occurred during the Jurassic and Cretaceous than at the present. During this time, the variation of temperture from pole to equator was possibly 20°C instead of the present 40-50°C. In the southern Pacific, such a zonation probably continued up to the Eocene about 40 million years ago when polar ice sheets began to dominate the Antarctic continent (Barron et al., 1988).

Overall, it is reasonable then to expect that all the basins of the southern Pacific during the Late Cretaceous up to the Eocene had the same marginal marine and lowland temperate forest floral types leading to similar potential source rocks.

This Cretaceous to Palaeocene period is also a period of significant marine organic deposition throughout the world (Fischer, 1982; Dean et al., 1984; Schlanger, 1986; Brooks and Fleet, 1987). These organic-rich marine sediments would provide potential source rocks if similar deposits were present in the basins of the region. As mentioned earlier, these marine sediments would also be most likely to generate oil rather than gas.

By the Late Oligocene, the picture had changed as the opening seaways started to affect the climate and cause botanical isolation (Kennett et al., 1972; Kennett, 1977,1980). However, as will be shown later, the important source rocks occur in the Eocene and earlier sequences. Valid analogies of source potential between the basins can therefore be made.

Maturity and trap comparisons

Unlike the controls on the source and reservoir, the controls on maturity and trap geometry are not limited to the Late Cretaceous and Early Tertiary. The maturity is controlled by the depth of burial of the source sediments and this is highly variable between the basins. To evaluate it, each basin must therefore be considered independently.

The structural configurations are also unique to each basin as the stresses associated with each basin following the breakup of Gondwanaland have varied widely both in timing and strength.

To evaluate the hydrocarbon potential of the basins of the Antarctic Sector of the Pacific, it is therefore important to look at the various basins in detail and to draw comparisons between them so as to evaluate the various parameters needed for hydrocarbon accumulation. The first stage is to describe the hydrocarbon occurrences in the two adjacent productive basins, the Gippsland and Taranaki Basins.

Gippsland Basin

The Gippsland Basin lies at the eastern end of the Bass Strait, in southeastern Australia (Fig. 6.3) and is one of the world's major coal- and petroleum-bearing basins. The basin is wedge-shaped and approximately 50,000 km2 in area of which four-fifths lies offshore. It contains up to 5 km of Cretaceous and Tertiary sediments with an average thickness of 3.5 km.

Exploration since 1964 has resulted in the discovery of several commercial oil fields, three of which are in the giant category (8 x 107m3, Halbouty et al., 1970). The total recoverable reserves for this basin are now quoted at 3.2 x 108 m3 of oil, 6.4 x 107 m3 of LPG and 2 x 1010 m3 of gas. This equates to a reserve factor of 2300 m3 oil equivalent/km3 of sediment which is close to the figure of 1900 m3/km3 mentioned earlier as a worldwide average.

Most of the hydrocarbons found in the Gippsland Basin are trapped at the top of the Late Cretaceous to Eocene Latrobe Group. Here, erosional and structural highs occur under the unconformably overlying shales. The reservoirs are therefore the alluvial-deltaic sands of the Latrobe Group. Most of the sedimentary rocks below the reservoirs are of non-marine origin, and the coal material within the Latrobe and Early Cretaceous Strzelecki Groups has been suggested as the source of the hydrocarbons (Threlfall et al., 1976; Shibaoka et al., 1978). The main Gippsland oils are high in wax and the distribution of biological markers confirms that terrestrial organic material was the source of oil (Thomas, 1982; Burns et al., 1984). At the western margin of the basin, a number of low to medium gravity naphthenic crudes has been recovered. These show the biological marker characteristics of the other waxy and plant-derived oils. However, they have subsequently been biodegraded due to the invasion by meteoric water (Threlfall et al., 1976; Thomas, 1982).

The measured maturation levels within the basin show that the main generation zone lies at a depth of about 2.8 km. At the centre of the basin, this lies within the top of the Latrobe Group. However, extrapolation of the maturation/ depth trend suggests that the Strzelecki Group is overmature to have generated oil in the recent past (Shibaoka et al., 1978).

The seal over the structures is provided by the calcareous mudstones and marls of the Miocene Lakes Entrance formation and the Gippsland limestone.

The structural development under the erosional unconformity at the top of the Latrobe Group has given rise to the majority of the hydrocarbon traps of the basin. The initial basin formation resulted from a rifting phase between the Jurassic and Early Cretaceous (Smith, 1982). This led to the deposition of the Strzelecki Group, consisting of non-marine sandstones, volcaniclastics and conglomerates on the basin margins with more mudstones and coals accumulating along the central axis of the basin. Towards the end of the Early Cretaceous, subsidence decreased with some uplift in the latter part of the Early Cretaceous (Threlfall et al., 1976). The resultant unconformity was then followed in the Late Cretaceous by a second rifting phase. This led to the deposition of the Late Cretaceous to Eocene coal-bearing deposits of the Latrobe Group. Cessation of ocean formation in the Tasman Sea by the Early Eocene marked the end of the rift-associated subsidence which was replaced by compression and wrench faulting (Smith, 1982). During this compressional phase, several major eustatic cycles from Early Eocene to the Early Oligocene led to the development of the Latrobe unconformity. It is the wrench faulting together with the unconformity which provided the structuring of the reservoirs allowing hydrocarbon accumulations. The removal of compression during the Early Miocene resulted in a phase of extremely rapid burial and shelf development over the basin which has lasted to the present day. Marine sediments deposited since that time form the seal for the structures and provide the overburden which has allowed the oil generation in the basin.

Taranaki Basin

The Taranaki Basin lies off the west coast of the North Island of New Zealand. It covers more than 80,000 km2, of which about three-quarters is offshore. The offshore parts range down to 500 m water depth but most of the basin lies in the 100-250 m depth range. Up to 11 km of sediment has accumulated in part of the graben, although the average thickness is about 4 km.

Seismic coverage of the basin has been extensive and some 56 deep wells onshore and 30 offshore have been drilled since 1965. Since the early 1960s recoverage reserves of 10" m3 of gas and 4.3 x 107 m3 of oil and condensate have been located in the Maui, Kapuni and McKee Fields (Cook, 1985) together with several new fields yet to be produced. This equates to a reserve factor of 500 m3 oil equivalent/km3 sediment. This is only about one-quarter of the worldwide average of 1900 m3/km3.

Most hydrocarbons discovered in the Taranaki Basin are trapped near the top of the Eocene Kapuni Group. The reservoirs are the alluvial and marginal marine sandstones associated with coal measure sequences, although other marine sandstones in the Miocene and Pliocene have also contained hydrocarbons (Robinson and King, 1988). The hydrocarbons have been shown geochemically to be derived from coals, probably from the Late Cretaceous Pakawau and the Kapuni Groups (Cook, 1988). These hydrocarbons are primarily gas/condensates, although a significant amount of high wax oil has also been found. The measured maturation levels from the biomarkers and the well samples suggest that the oils have been generated at depths greater than 5 km (reflectance 0.9%) which confirms that the Pakawau Group coals are the primary source. Kapuni Group members may well also have generated hydrocarbons in the northern parts of the graben (Cook, 1988). The marine equivalents to the Kapuni Group and the overlying Oligocene and Miocene limestones and mudstones provide seals for the various reservoirs throughout the basin.

The Taranaki Basin developed during the Late Cretaceous to Eocene as a result of the rifting phase associated with the opening of the Tasman Sea. However, with the onset of compression during the Upper Oligocene to Miocene, the basin separated into the more stable Western Platform and the Taranaki Graben complex. The northern part of the Graben is an area of continuous subsidence and oblique faulting (Knox, 1982) and contains extensive Miocene and Pliocene vol-canics (Pilaar and Wakefield, 1984). This contrasts with the southern Taranaki Graben where predominantly reverse faulting occurred (Knox, 1982). The Late

Eocene to Late Miocene faulting is recognizable along the Cape Egmont Fault Zone which separates the Graben from the Western Platform. This faulting is probably related to the development of the active plate boundary beneath the North Island and the dextral transform faulting along the Alpine Fault 35-10 Ma B.P. (Carter and Norris, 1976; Knox, 1982). From the Late Miocene to Pleistocene, the graben underwent compressional deformation which caused reverse faulting, especially low angle thrust faults. These thrust faults along the eastern margin of the graben are particularly important as they form the structures of the McKee, Tariki, Ahuroa and Waihapa Fields. This complex tectonic history has given rise to the structures associated with the various fields and most have a combination of fault and fold closure. In size, they range from giant, as found in the Maui gas/ condensate Field, down. While the obvious large structures of the basin have now been drilled, there remain many more intermediate and commercially viable structures to be drilled. The complex tectonics of the region may also give rise to other types of structure and reservoir combinations which are as yet untested.


The Soiander Trough lies at the southern end of the South Island of New Zealand. It forms a submarine depression between the continental Campbell Plateau and the oceanic Macquarie Ridge to the west. At its head are a series of

Fig. 6.4. Map of southwestern New Zealand showing the location of the sedimentary basins.

small sub-basins which are considered to have some hydrocarbon potential. They are the Solander, Balleny and the onshore Waiau and Te Anau Basins (Fig. 6.4).

The two offshore basins extending to the 1,000 m isobath cover about 14,000 km2 whilst the onshore basins cover about 6,000 km2. Although the offshore basins extend well to the south, possibly tripling the area, water depths there exceed 1,500 m. Little work has been completed in the deepwater region and the full extent of the basin has yet to be defined. The thickest sedimentary section in all the basins is about 6 km, with an average of about 3 km. This would suggest that the basin has a hydrocarbon potential of 1 x 108 m3 oil equivalent, although none of this has yet been found.

Early exploration interest in the onshore part of the region resulted from the thin oil shale deposits discovered near the coast in the Waiau Basin. However, it has only been in the last decade and a half that there has been interest in the offshore area. Over this time, the area out to about 1,000 m water depth has received extensive seismic coverage. Since 1975, two wells have been drilled offshore and two onshore but these had disappointing results.

The subsidence in the basins has been controlled by major faults and has a complicated tectonic history resulting from the response to the regional stresses and the proximity of the area to the southern end of the Alpine Fault and hence Pacific plate margin (Norris and Carter, 1980; Grant, 1985).

While any one of the local histories of the basins is complex, especially during the Late Tertiary, all the basins have a similar framework to their stratigraphy and tectonics.

During the Late Cretaceous and Early Tertiary, the initial relief on the stable landscape of mostly Palaeozoic rocks was reduced by erosion and infilling of the block-faulted topography. The Cretaceous to Eocene sediments show relatively steep dips on the regional seismic profiles. They are assumed to be relatively coarse sediments derived from the west of the bounding faults and make up to 3 km of the sequence. The coal measure sequence seen on the eastern margin of the Waiau Basin could well be a major part of these sequences. They occur in a similar situation to those in the Taranaki Basin where the Pakawau coal measures are locally deposited within the middle Cretaceous topography. The mature land-surface during the Late Eocene was abruptly affected by a phase of tectonism which allowed a rapid marine incursion. TTiis resulted in the deposition of coarse breccias, arkosic sandstones and flysch which in the west pass up to chalks and in the east to fine-grained clastic sediments (Norris and Carter, 1980).

The Plio-Pleistocene deposition consisted of further marine clastic sediments in the south but in the north of the Waiau Basin deposits became fluvial and glacial. Throughout the area, these sediments are warped and faulted with Pliocene fault reactivation and the large-scale uplift of the basins (Grant, 1985). The basins have not been uplifted much by comparison to the 9-15 km suggested for the adjacent Fiordland region (Suggate, 1963), although some surface truncation is suggested in seismic profiles. While the uplift is recognizable in the Solander and Waiau region, it is greater in the Balleny Basin where upwards of 1-1.5 km of section loss is shown (Grant, 1985).

Hydrocarbon potential

The 3 km of Cretaceous and lower Tertiary sediments at the base of the basins holds the key to their hydrocarbon potential. These are the Ohai Group coal measures as seen in the eastern margin of the Waiau Basin and the conglomerates and Eocene sands of the western margin.

While the conglomerates would be of no interest as a source of hydrocarbons or as a potential reservoir, the coals are similar to those found in the Taranaki Basin. Such coal measures are therefore the primary objective for exploration as they would provide both the oil and gas source together with reservoir-quality sands.

Whether such coal sequences are buried deep enough to have generated significant hydrocarbons is questionable (Cook, 1988). Because of the widespread uplift since the Pliocene, large volumes of the more mature section may be closer to the surface than normal. Present burial depths cannot therefore be used to exclude the maturation potential of the basins. This is borne out by the Ohai coal measures being on the present-day surface with a rank of high volatile bituminous equivalent to reflectance of 0.53 (Black, 1980). The Late Tertiary marine sequences would provide surficial seal for any trap.

While detailed structural maps have not been made for the Solander Trough basins, the regional work of Grant (1985) suggests that significant to large folded and faulted structures are present.

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