Northern Taranaki graben described as promising area in New Zealand

The 10,000 sq km Northern Taranaki graben (Fig. 1) is a significant exploration opportunity within a producing basin. It is the most underexplored and prospective part of the Taranaki basin and has been picked by some analysts as the most promising exploration theater in New Zealand for finding large oil and gas accumulations.

The graben is a mainly Neogene offshore depocenter that extends for about 200 km north of the Taranaki Peninsula. Bound to the west by the Cape Egmont Fault Zone and to the east by the Turi Fault Zone, the 50 km-wide graben contains up to 8 km of Cretaceous and Tertiary strata. A series of intrusive and extrusive igneous centers marks the onset of graben development in the Miocene.

Exploration history

Exploration of the northern graben has been discouraged by the difficulty of imaging subsurface igneous features and the sediments beneath them and by the depth to the traditional (mainly Eocene) Taranaki basin reservoirs. Only a few exploration wells have been drilled within the graben and none to stratigraphic levels deeper than the Miocene.

However, these past ventures have acquired a substantial 2D seismic grid that provides a sound basis for the search for further prospects.

The only wells drilled within the graben itself are Mangaa-1 (drilled in 1970), Kahawai-1 (1990), and Awatea-1 (1996). A number of wells supply peripheral control including Turi-1 and Tangaroa-1 (both with shows), Okoki-1, Taimana-1, and Arawa-1.

The most significant exploration result has been a subeconomic oil discovery in the first of four wells drilled on the Kora structure on the western margin of the graben. Kora-1, drilled in 1988, flowed 668 b/d from Miocene Mohakatino formation volcaniclastics, but the targeted underlying Eocene sandstones were of poor quality due to hydrothermal alteration. In December 2002, a discovery was made at Karewa-1 which was targeting Eocene Mangaa formation sands in the far north of the graben.

Near the southeastern margin of the graben, Pohokura gas-condensate field, discovered in 2000, is under development and expected to be in production by 2006.

Graben development

The northern graben is a major structural feature within the greater Taranaki basin. Deposition of the numerous reservoir units has been principally controlled by faulting, and, in the Middle to Late Miocene, by volcanism associated with graben formation.

Initial structural development of the northern graben took place during the late Cretaceous, when the Taranaki basin first developed as a series of interconnected rift subbasins. Within these rift grabens, organic-rich, mainly terrestrial sediments of the Rakopi formation were deposited in a north-flowing drainage system. During the latest Cretaceous, the rift graben system was progressively flooded from the north, and the marginal marine deposits of the North Cape formation were deposited.

Rifting ceased in the Paleocene, and the region gradually deepened to bathyal water depths. A regional anoxic event in the late Paleocene resulted in deposition of the Waipawa formation, a marine black shale.

A major late Eocene channel system in the central part of the graben is coeval with the basin-floor sands of the Tangaroa formation farther north and may be the conduit along which these excellent reservoir-quality sands were transported northward into the graben. Along the eastern margin, the middle to late Eocene is represented by the Mangahewa formation coastal deposits. An almost continuous mid to late Eocene reservoir fairway of shelf margin shore-face deposits, slope channels, and basin-floor fans is thus inferred throughout much of the northern graben.

Extensional faulting in the Middle to Late Miocene was accompanied by subduction-related arc volcanism. The Mohakatino volcanic center comprises at least 20 andesitic volcanic cones that cover an area of about 3,200 sq km. Most were erupted in bathyal water depths and entombed by Pliocene and Pleistocene sediments, so that many are little eroded and clearly imaged on seismic reflection profiles (Fig. 2). Volcanism was accompanied by intrusion of magma into basin-fill sediments and basement rocks.

Rapid subsidence of as much as 4 km since the middle Miocene created a huge depocenter. Voluminous clastic sediment supply from the south and east was deposited as the Giant Foresets formation, which filled in bathyal water depths to shelf level by the Pleistocene.

Source and generation

An active hydrocarbon generation and migration system is demonstrated by shows in several wells, by oil tested in Kora-1, and by numerous gas anomalies on seismic data.

The northern Taranaki basin has two recognized source rocks: coals and interbedded shales of the Late Cretaceous Rakopi and North Cape formations, the principal source rocks throughout the Taranaki Basin; and the Waipawa formation, a late Paleocene marine shale which has been geochemically correlated to the Kora oil and shows in several other wells.

Source rock type affects the potential maturity of sediments because of the difference in generation kinetics between Type II and Type III kerogen. Without considering the effects of Miocene igneous activity, thermal modeling indicates that present day maturity of source rocks for oil expulsion requires burial depths of 3,500-4,500 m, dependent on source rock type.

Modeling indicates that the major phase of petroleum expulsion is associated with rapid progradation of the shelf in the Pliocene and Pleistocene, although in some deeper parts of the basin, generation and expulsion occurred as early as the Eocene. Regional-scale multi-1D modeling indicates 240 billion bbl of oil and gas equivalent have been generated over the last 5 million years from Late Cretaceous source rocks within the area shown in Fig. 3.

In areas close to volcanism, models indicate that magmatism stimulated generation at higher stratigraphic levels from about 14 to 8 Ma. While volcanism is normally considered to be detrimental to hydrocarbon prospectivity, examples from the northern graben indicate that aspects of the volcanism may be beneficial to the hydrocarbon system, forcing maturation and directing migration as well as controlling the deposition of reservoir rocks, developing traps and providing seal.

Reservoirs and accumulations

Potential reservoirs include Eocene coastal, slope, channel, and basin-floor complexes of the Mangahewa, McKee, and Tangaroa formations as well as Miocene to Pliocene submarine-fan sands of the Mount Messenger and Mangaa formations. Late Cretaceous shoreline sands of the North Cape formation have high porosities with excellent reservoir potential indicated from well data but are yet to be proven.

All the major oil and gas fields in the Taranaki basin produce from Eocene sandstone sequences. Sands of this age are also present in the northern graben where Tangaroa formation sandstone is considered to be highly prospective with over 20% porosity at depths of 3,200 to 3,800 m, yielding hydrocarbon shows in several wells.

The Miocene and younger basin-floor turbidite sandstones are productive reservoirs in fields beneath the Taranaki Peninsula. These units extend northward into the graben and have excellent reservoir characteristics where they crop out at the uplifted eastern margin. Oil flow in Kora-1 from the Miocene volcaniclastic Mohakatino formation proves its significance as a reservoir unit within the graben. Reservoir degradation caused by hydrothermal alteration appears to be limited to a radius of a few kilometers from the center of the volcanic dome.

Seal is provided at various levels in the area by Eocene and Miocene mudstones and thick Plio-Pleistocene shelf mudstones and slope deposits. Zones of overpressuring are evident in many wells drilled in the region, indicative of fluid confinement and the effectiveness of seals. Migration modeling of the northern graben shows that petroleum entrapment occurs at top Cretaceous and Eocene levels, with gas chimneys developing over the largest accumulations (Fig. 4).

Exploration potential

The northern graben is one of the most promising exploration opportunities in New Zealand.

Trap concepts fall mainly into two distinct categories: those which owe their existence to the graben-forming tectonics and those associated with the igneous centers. Several very large structures are present in both categories, and numerous leads with recoverable reserve estimates in excess of 100 million bbl were identified in a 2001 evaluation.

Closure areas range up to 80 sq km or more in as much as 140 m of water and drilling depths of 3,000 and 4,800 m. Plays include inversion structures, normal fault bounded blocks, and overthrusts that have been proven elsewhere in the Taranaki basin.

There is also good potential for hydrocarbon accumulations in structures associated with Miocene volcanism.

The graben is currently open to exploration via a licensing round.

Details are available: (www.crownminerals.govt.nz).

Acknowledgment

Institute of Geological and Nuclear Sciences modeling of petroleum generation and entrapment using IES patented Petromod software was funded by the New Zealand Foundation for Research, Science and Technology.

References

1.Hart, Alan, "Taranaki basin yielding large oil and gas discoveries," OGJ, July 16, 2001, p. 38.

2.Hart, Alan, "Numerous play types evident in Taranaki basin," OGJ, July 23, 2001, p. 40.

The authors
Alan Sherwood ([email protected]) is a consultant specializing in technical editing and writing in various media. He has previously worked as a coal exploration geologist with New Zealand Geological Survey and as a technical editor with the South Pacific Applied Geoscience Commission. He has a BSc in geology and MSc and MPhil degrees in earth sciences and has worked in New Zealand, Canada, Fiji and the South Pacific, Southeast Asia, and Antarctica.

Vaughan Stagpoole is a geophysicist with GNS. His research interests are in the uses of geophysical and geological data to understand tectonic processes involved in the formation and development of sedimentary basins. He has a BSc (Hon.) and PhD from Victoria University.

Rob Funnell is a geoscientist with GNS specializing in heat flow and thermal modeling of sedimentary basins, the development of basin models to quantify petroleum prospectivity, and risk. Rob has an MSc from the University of Waikato (NZ) and MSc, DIC from the University of London.

Dave Darby is a fluid modeler with GNS, working on simulation of hydrocarbon migration, compaction, and overpressure. Dave has experience with British Gas in the UK and the Woods Hole Oceanographic Institution in the US. He has a BSc (Hon.) and PhD from Glasgow University.