Southern, eastern New Zealand petroleum systems examined

Richard Cook
Institute of Geological & Nuclear Sciences
Lower Hutt, N.Z.

Roger Gregg
New Zealand Crown Minerals
Wellington

Hydrocarbon indications have been found in four of the eight wells drilled in the Great South basin. In Kawau-1A a mid-Cretaceous sandstone tested predominantly gas up to 6.8 MMcfd. Strong indications (oil staining) in the sandy facies of the Late Cretaceous between 3,350-3,600 m in Toroa-1 could not be tested due to failure of the hole. Similarly upper Cretaceous neritic sands in Galleon-1 in the Canterbury basin, just north of the Otago Peninsula, tested both oil/condensate and gas up to 2,240 st-tk b/d and 10.6 MMcfd. Oil shale is known in the Waiau basin and was used commercially in the early 1990s.

Although wells have been drilled in each of these basins, their potential is hardly tested. The main parameters for exploration are best indicated by the Great South basin.

Sedimentary sequence

The Great South basin was formed as a complex rift system during the mid-Cretaceous before the New Zealand crustal block separated from West Antarctica and has mostly remained tectonically quiet since then. Regional subsidence and waning sediment supplies resulted in a regional marine transgression, and the sediments reflect progressively deeper water. Most of the basin's sedimentary sequence is related to Cretaceous regional tectonics.

Source rocks

Late Cretaceous and Paleocene coals exhibit excellent potential for mixed gas and oil (Fig. 6 [42338 bytes]) with their average HI of 250 at the onset of maturation. Late Cretaceous and Paleocene mudstones and shales are not as good, but in Toroa-1, Kawau-1A, and Pakaha-1 the TOC averages 1% with an HI average of 200, ranging up to 350. This suggests that they could source significant oil and gas.

Biomarker and isotopic correlation of Kawau-1 condensate and potential source rocks suggests that mid-Cretaceous coaly sediments have produced the condensate and various oil shows. Although these sediments contain abundant coaly material, biomarkers indicate that the condensate have experienced significant marine influence. Higher-plant biomarkers are different in Cretaceous and Tertiary coals from freshwater swamps, such as in Taranaki. In the Great South basin, only very low levels of woody gymnosperm-derived diterpanes and angiosperm-derived triterpanes are present.

The present day maturation levels in Tara-1 measured in maturation and thermal models indicate that significant generation begins at around 2,500-2,800 m and expulsion at 3,500-3,800 m depths.

Reservoir potential

Sandstones are the most likely reservoir lithology in the Great South basin. The sands are likely to have been deposited in a range of environments; nonmarine lower coastal plain, fluvial and marginal marine to mid-shelf. The fluvial and lower coastal plain sandstones range in average porosity from 15-25% and, even where more deeply buried, they range from 10-20%. Mid-Cretaceous sandstones were derived from quartz-rich rocks. Upper Cretaceous-Paleocene marginal marine sands and lowstand shoreline sandstones show good porosity averaging 15-25%.

Seals

The Great South basin is similar to Taranaki in hosting widespread nonmarine and marginal marine sediments. Sandstones within nonmarine deposits of several Great South basin wells averages 50% of the interval. Shelf mudstones provide a further seal for marine sandstones and are likely to be continuous. Sand to shale ratios in the shelf are 1:4. Late Tertiary tectonics are not likely to have created reservoir leakage.

Structures

Most mapped structures are related to compactional drape of latest-Cretaceous and Paleocene deposits over faulted basement blocks. In the northwest, Paleocene tectonic activity has reversed nearshore and onshore northeast trending faults.

Structures mapped and identified by Hunt International Petroleum Co. now need to be reconsidered as drilling sites in the light of newer concepts of plays and leads developed for the basin. Hunt mapped the basin only at the top Paleocene level, and other levels are now considered possible plays. Faulting of mid- and Late Cretaceous deposits also provides potential for additional structures and seals.

Stratigraphic plays should also be considered, especially marginal to drape structures where winnowed sands could have been deposited.

Exploration potential

The large seismic data base, the drilled wells, and the oil and gas indications in the basin all point to an underexplored basin with considerable potential. Additionally in the 1970s and 1980s water depths were a major constraining factor on exploration and development, but advances in technology have reduced the significance of these technical challenges.

Province variations

The Canterbury basin has close similarities to the Great South basin, except that Cretaceous sediment is not as widespread or as thick. The Paleocene black shale, a potential source rock, is possibly buried deeply enough in this region for petroleum generation. Biomarkers of the condensates and shows within the Canterbury basin indicate a similar marginal marine origin to Great South basin hydrocarbons. Upper Tertiary tectonics through the Canterbury basin may have developed significant structuring in the offshore region.

The Western Southland basins have thinner Cretaceous sequences but have been buried sufficiently to generate hydrocarbons. Upper Tertiary tectonics, however, dominate their histories, and while adding significant structural potential, also provide a risk of breach of any reservoir.

Eastern province

The East Coast is an interesting exploration challenge, with significant oil and gas seeps along the North Island and in Marlborough. About 70% of the 31 onshore wells have shows. Only two wells have been drilled in the potentially more prospective offshore area. The most recent Titihaoa-1 had significant gas shows and good reservoir sands and Hawke Bay-1 encountered gas, but the combination needed for a commercial hydrocarbon trap has yet to be found.

The East Coast of the North Island is geologically different from the western and southern provinces. The East Coast basin developed as an oceanward facing passive margin from the Late Cretaceous to the end of the Paleogene. Near the start of Miocene it was affected by the onset of subduction of the Pacific Plate, which led to an allochthonous sheet of Cretaceous and Paleogene aged sediments across the northern half of the basin. This was followed by dextral strike slip faulting that eventually became more orthogonal, while compressive faulting dominates the Neogene.

Stratigraphy

The stratigraphic framework of East Coast basins started in the mid-Cretaceous with the deposition of grey- wacke flysch and mudstones with shelfal sands. Accelerated Neogene tectonism, due to plate boundary development, created bathyal flysch and mudstone, punctuated by shelfal sands and greensand units. Limestones became more common in the Late Miocene and Plio-Pleistocene.

Source rocks

Unlike most other basins, the East Coast has large amounts of marine source rock (Fig. 7 [11017 bytes]) with some Cretaceous units containing significant carbonaceous material. The richest potential source rock is the Paleocene Waipa-wa black shale, which averages 5.3% TOC. Biomarker studies of onshore seep oils have shown matching with Cretaceous to Paleocene sediments. Onshore maturation measurements show that the oil window is 3,000-4,500 m. Offshore, however, the post-Paleogene sequence thickens and it is likely the Waipawa black shale (Paleocene) is mature in many areas.

Reservoir rocks

Sandstones of various ages (often reworked) are very clean with porosities recorded in excess of 30%, averaging 10-15% even at depth. A marine continental margin setting exists throughout, and continuously changing sea levels have deposited sandstones in many environments. The most likely reservoirs are paralic to shelfal sands, slope channel complexes, and bathyal fan deposits. Shallow Neogene marine limestones onshore also show excellent reservoir potential.

Seals

The marine nature of the sequence and the dominance of finer sediments means that seals are not considered a limiting factor.

Structure

Compression in the north and extension in the south was present during the mid-Cretaceous, but the latest Cretaceous and Paleogene were comparatively quiet. Renewed tectonism in the early- to mid-Miocene developed the present structures. The west initially had mainly strike slip movement while more orthogonal compression in the east produced spectacular structuring with massive shortening due to plate convergence. Structural development is not a problem, but it complicates the stratigraphy and the juxtaposition of the source and reservoir rocks (Fig. 8 [61849 bytes]).

Potential

Large areas of the East Coast basin are prospective for hydrocarbons, and while there have been a number of exploration wells many of them are not recent and hence have not tested well-defined structures. Modern seismic, sequence stratigraphy, and new exploration paradigms are needed to compile a new strategy for exploration that will overcome the structural complexity and lateral stratigraphic changes that have hindered previous explorers.

A current view of the prospectivity of all New Zealand basins is also shown (Fig. 9 [140209 bytes]).

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