scholarly journals Shale Oil/Gas: A New Opportunity for New Zealand?

2021 ◽  
Author(s):  
◽  
Raul Correa Rechden Filho
Keyword(s):  
New Zealand ◽  
Shale Gas ◽  
Oil And Gas ◽  
East Coast ◽  
Unconventional Reservoirs ◽  
Field Size ◽  
Brittleness Index ◽  
Rock Properties ◽  
Shale Oil ◽  
Geochemical Analyses

<p>Within New Zealand the East Coast Basin encompasses the primary shale oil and gás (unconventional) play areas in which both the Waipawa and Whangai formations are widespread. These formations are oil and gas prone and prevalent throughout a large area of the East Coast Basin. To characterise these two formations and evaluate their shale oil and gas potential, existing analytical results were supplemented by a set of new sample analyses of organic and inorganic geochemistry, and rock properties. Thus, some 242 samples from the Whangai Formation have organic geochemical analyses and 40 have inorganic geochemical analyses; for the Waipawa Formation there are 149 organic and 9 inorganic geochemical analyses. In addition, downhole logs from three exploration wells have been used to calculate the brittleness index of the Whangai Formation. All these data have been grouped by structural block and used to determine where the sweet spots are in each formation. Both basic and more robust statistical analysis (machine-learning) is applied to identify the best prospective area. The Rakauroa Member (Whangai Formation) and the Waipawa Formation have the best rock characteristics as unconventional reservoirs, based on quantity and quality. Maturation appears to be an issue for these formations, although there are some localised areas where the Whangai Formation has better maturity. The brittleness index is calculated only for the Rakauroa Member, given the lack of data available for other members of the Whangai Formation and the Waipawa Formation, and yielded promising results. The Motu block appears to be the best area in which to explore for unconventional oil and gas. The prospective resource volumes for the best case scenario for the Whangai (Rakauroa Member) and Waipawa formations combined in the Motu Block are 17% higher (713MMbbl) than the 2P (proved + probable) reserves of New Zealand for oil and condensate (588MMbbl) and 26% (2.1TCF) of the 2P (proved + probable) reserves of natural gas (7.8 TCF). Economic analysis shows feasibility to explore these unconventional reservoirs for both shale oil or shale gas with an oil price of US$60 for both methodologies tested. However, the methodology applied using standard shale oil and gas assessments shows feasibility only for shale oil. Shale gas would not be economic, unless a higher oil prices, lower costs or a technology was developed to improve the recovery factor of these reservoirs. These results indicate a minimum economic field size of 4.5 km² for this area.</p>

scholarly journals Shale Oil/Gas: A New Opportunity for New Zealand?

2021 ◽  
Author(s):  
◽  
Raul Correa Rechden Filho
Keyword(s):  
New Zealand ◽  
Shale Gas ◽  
Oil And Gas ◽  
East Coast ◽  
Unconventional Reservoirs ◽  
Field Size ◽  
Brittleness Index ◽  
Rock Properties ◽  
Shale Oil ◽  
Geochemical Analyses

<p>Within New Zealand the East Coast Basin encompasses the primary shale oil and gás (unconventional) play areas in which both the Waipawa and Whangai formations are widespread. These formations are oil and gas prone and prevalent throughout a large area of the East Coast Basin. To characterise these two formations and evaluate their shale oil and gas potential, existing analytical results were supplemented by a set of new sample analyses of organic and inorganic geochemistry, and rock properties. Thus, some 242 samples from the Whangai Formation have organic geochemical analyses and 40 have inorganic geochemical analyses; for the Waipawa Formation there are 149 organic and 9 inorganic geochemical analyses. In addition, downhole logs from three exploration wells have been used to calculate the brittleness index of the Whangai Formation. All these data have been grouped by structural block and used to determine where the sweet spots are in each formation. Both basic and more robust statistical analysis (machine-learning) is applied to identify the best prospective area. The Rakauroa Member (Whangai Formation) and the Waipawa Formation have the best rock characteristics as unconventional reservoirs, based on quantity and quality. Maturation appears to be an issue for these formations, although there are some localised areas where the Whangai Formation has better maturity. The brittleness index is calculated only for the Rakauroa Member, given the lack of data available for other members of the Whangai Formation and the Waipawa Formation, and yielded promising results. The Motu block appears to be the best area in which to explore for unconventional oil and gas. The prospective resource volumes for the best case scenario for the Whangai (Rakauroa Member) and Waipawa formations combined in the Motu Block are 17% higher (713MMbbl) than the 2P (proved + probable) reserves of New Zealand for oil and condensate (588MMbbl) and 26% (2.1TCF) of the 2P (proved + probable) reserves of natural gas (7.8 TCF). Economic analysis shows feasibility to explore these unconventional reservoirs for both shale oil or shale gas with an oil price of US$60 for both methodologies tested. However, the methodology applied using standard shale oil and gas assessments shows feasibility only for shale oil. Shale gas would not be economic, unless a higher oil prices, lower costs or a technology was developed to improve the recovery factor of these reservoirs. These results indicate a minimum economic field size of 4.5 km² for this area.</p>

The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand

2008 ◽  
Vol 48 (1) ◽  
pp. 53 ◽  
Author(s):  
Chris Uruski ◽  
Callum Kennedy ◽  
Rupert Sutherland ◽  
Vaughan Stagpoole ◽  
Stuart Henrys
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Plate Boundary ◽  
Source Rocks ◽  
Fault System ◽  
Northern Coast ◽  
The South ◽  
Petroleum Potential ◽  
The North

The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.

Geology, resource potentials, and properties of emerging and potential China shale gas and shale oil plays

2015 ◽  
Vol 3 (2) ◽  
pp. SJ1-SJ13 ◽  
Author(s):  
Shu Jiang ◽  
Jinchuan Zhang ◽  
Zhiqiang Jiang ◽  
Zhengyu Xu ◽  
Dongsheng Cai ◽  
...  
Keyword(s):  
South China ◽  
Shale Gas ◽  
Oil And Gas ◽  
Northwest China ◽  
Shale Oil ◽  
Yangtze Platform ◽  
Lower Paleozoic ◽  
High Maturity ◽  
Shale Reservoirs ◽  
Gas Potential

This paper describes the geology of organic-rich shales in China, their resource potentials, and properties of emerging and potential China shale gas and shale oil plays. Marine, lacustrine, and coastal swamp transitional shales were estimated to have the largest technically recoverable shale gas resource (25.08 trillion cubic meters or 886 trillion cubic feet) and 25 to 50 billion barrels of technically recoverable shale oil resource. The Precambrian Sinian Doushantuo Formation to Silurian Longmaxi black marine shales mainly accumulated in the intrashelf low to slope environments in the Yangtze Platform in South China and in the Tarim Platform in northwest China. The marine shales in the Yangtze Platform have high maturity (Ro of 1.3%–5%), high total organic carbon (mainly [Formula: see text]), high brittle-mineral content, and have been identified as emerging shale gas plays. The Lower Paleozoic marine shales in the Upper Yangtze area have the largest shale gas potential and currently top the list as exploration targets. The Carboniferous to Permian shales associated with coal and sandstones were mainly formed in transitional depositional settings in north China, northwest China, and the Yangtze Platform in south China. These transitional shales are generally rich in clay with a medium level of shale gas potential. The Middle Permian to Cenozoic organic-rich lacustrine shales interbedded with thin sandstone and carbonate beds are sporadically distributed in rifted basins across China. Their main potentials are as hybrid plays (tight and shale oil). China shales are heterogeneous across time and space, and high-quality shale reservoirs are usually positioned within transgressive systems tract to early highstand systems tract intervals that were deposited in an anoxic depositional setting. For China’s shale plays, tectonic movements have affected and disrupted the early oil and gas accumulation, making tectonically stable areas more favorable prospects for the exploration and development of shale plays.

Prospects and Challenges of Developing Unconventional Petroleum Resources in the Anambra Inland Basin of Nigeria

2016 ◽  
Author(s):  
K. Mosto Onuoha ◽  
Chidozie I. Dim
Keyword(s):  
Shale Gas ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Organic Content ◽  
Shale Oil ◽  
Thermal Maturity ◽  
Total Organic Content ◽  
Anambra Basin ◽  
Petroleum Resources ◽  
Oil And Gas Resources

ABSTRACT The boom in the development of unconventional petroleum resources, particularly shale gas in the United States of America during the last decade has had far reaching implications for energy markets across the world and particularly for Nigeria, a country that traditionally has been Africa&rsquo;s leading crude oil producer and exporter. The Cretaceous Anambra Basin is currently the only inland basin in Nigeria where the existence of commercial quantities of oil and gas has been proven (outside the Tertiary Niger Delta Basin). The possibility of similarly finding commercially viable resources of unconventional petroleum resources in the basin appears quite attractive on the basis of the existence of seepages of shale oil and presence of coal-bed methane in some of the coal seams of the Mamu Formation (Lower Coal Measures) in the basin. This paper presents the results of our preliminary assessment of the shale oil and gas resources of the Anambra Basin. Our main objective is to locate the zones of very high quality plays within the basin, focusing on their depositional environments (whether marine or non-marine), areal extent of the target shale formations, gross shale intervals, total organic content, and thermal maturity. Data on the total organic content (TOC %, by weight) and thermal maturity of shales from different wells in the basin show that many of the shales have high TOCs (i.e greater than 2%) comparable to known shale gas and shale oil plays globally. Shale oil seepages are known to occur around Lokpanta in south-eastern Nigeria, but there is a general predominance of gas-prone facies in our inland basins indicating good prospects for finding unconventional petroleum in this and other Nigerian inland sedimentary basins. The main challenge to the exploration of unconventional resources in Nigeria today has to do with the absence of the enabling laws and regulatory framework governing their exploration and subsequent exploitation. The revised Petroleum Industry Bill (PIB) currently under consideration in the National Assembly is expected to introduce drastic and lasting changes in the way the petroleum industry business is conducted in the country, but all the provisions of the draft law pertain mainly to conventional oil and gas resources.

scholarly journals Shale-Oil Development Prospects: The Role of Shale-Gas in Developing Shale-Oil

Energies ◽  
2019 ◽  
Vol 12 (17) ◽  
pp. 3331 ◽  
Author(s):  
Douglas B. Reynolds ◽  
Maduabuchi Pascal Umekwe
Keyword(s):  
Natural Gas ◽  
Shale Gas ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
The United States ◽  
Search Process ◽  
Shale Oil ◽  
Gas Industry ◽  
Oil Development ◽  
The World

Currently, most of the world’s shale-oil is coming from the United States, but more may be needed from non-U.S. sources in order to keep the world price of oil from increasing, and yet a number of petroleum producing countries have yet to develop shale-oil resources. This article investigates why that may be. One reason for this may be the role that shale-gas development plays in the search for shale-oil. In the oil and natural gas industry over much of the 20th century, finding oil has usually been more valuable than finding natural gas because the gas has less energy density than oil, making each BTU (or Joule) of oil energy easier to store, transport and use for consumers. However, since shale source-rock often has both natural gas and oil, then it behooves a shale search process to start by looking for natural gas first rather than oil to enhance the profitability of the search process. The problem, then, is that a shale-oil only search strategy has the same problem that first plagued the oil and gas industry: What do you do with the natural gas? In this paper, we will examine how this “chicken and egg” exploration scenario has played out in the U.S. in order to draw lessons on how difficult shale-oil development will be for the rest of the world.

THE EAST COAST BASIN OF NEW ZEALAND, AN EMERGING PETROLEUM PROVINCE

2005 ◽  
Vol 45 (1) ◽  
pp. 563 ◽  
Author(s):  
C.I. Uruski ◽  
B.D. Field ◽  
R. Funnell
Keyword(s):  
New Zealand ◽  
Seismic Data ◽  
Oil And Gas ◽  
East Coast ◽  
Data Set ◽  
Sequence Stratigraphic ◽  
Large Structures ◽  
Oil Generation ◽  
Wide Range ◽  
Reservoir Facies

More than 300 oil and gas seeps are known in the onshore East Coast Basin of North Island, New Zealand. Spectacular geological structures have been explored by more than 40 wells, only three of which have been offshore. Results are tantalising, with 70% of wells yielding oil or gas shows. Westech’s two gas discoveries onshore at Kauhauroa and Tuhara in northern Hawkes Bay remain un-developed at present.Strong gas shows were encountered in both open-file wells drilled offshore and elevated gas readings were recorded in the recent Tawatawa–1 well, but reservoir quality was poor.Nevertheless, good reservoir facies are abundant in the East Coast Basin. A wide range of Miocene and Pliocene sands and limestones, with porosities of 20% and above are known from outcrop and wells. But, modern, good quality seismic data are essential to allow sequence stratigraphic interpretation and a reasonable likelihood of predicting the distribution of reservoir facies. As part of its program to stimulate exploration in New Zealand, the NZ government is commissioning a new 4,000 km, highquality 2D seismic data set with the intention of making it freely available to interested exploration companies by mid-2005.The very thick sedimentary succession, the presence of direct hydrocarbon indicators on seismic data, the strong gas shows in wells drilled offshore and the reasonable expectation of oil generation and expulsion into numerous large structures with good reservoir facies combine to make the offshore East Coast Basin an attractive exploration venue.

OIL EXPLORATION IN NEW ZEALAND—PAST AND FUTURE TRENDS

1971 ◽  
Vol 11 (1) ◽  
pp. 35
Author(s):  
H. R. Katz
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Small Scale ◽  
Expiry Date ◽  
Seismic Surveys ◽  
The North ◽  
Geophysical Surveys ◽  
Increased Activity ◽  
Commercial Field

The earliest lease for oil prospecting was granted in 1865, and the first bore went down in 1866. Since then and up to 1936, 130 wells were drilled mainly in Taranaki, the East Coast of the North Island and the West Coast of the South Island. No commercial field was discovered, but some oil and gas was found sporadically — sometimes enough for local small-scale consumption — which kept interests alive.The Petroleum Act in 1937 vested all petroleum prospecting and mining rights in the Crown; with minor modification, it has regulated exploration to the present day. The war-time years saw renewed activity by several major companies; the first seismic surveys were undertaken, and some 20 holes were drilled. But except intermittent, small production from the Moturoa field in New Plymouth (the she of the first well of 1866), no further success was achieved and exploration ceased after 1944. The present period of activity started in 1955. On land the Kapuni gas-condensate field was discovered in 1959, and offshore the much larger Maui field in 1969. Both are in the Taranaki Basin which, having the best prospects in the country, has also received far more attention than other areas.Land operations sharply decreased after 1965 when Shell and BP, the only majors with on-land interests, began concentrating on new offshore holdings while still retaining their original big land concessions. Amongst the increasing number of independents continued regrouping of interests, farm deals, etc., have become common, and these companies account for nearly all activity on land during more recent years. Practically all drilling after 1965, which from a 5,686 ft. low in 1966 increased to 28,741 ft. in 1969 and 16,952 ft. in 1970 (the smaller 1970 figure is mainly due to rig shortage), was done by companies other than Shell-BP, many of them newcomers. Since to these the more promising prospects have been unavailable, exploration has noticeably shifted to areas of lesser and even marginal prospects.Concessions have for a number of years covered all lands of even remotest possibilities; the total area leased is around 50,000 sq. miles.Offshore the first concessions were granted in 1965; in 1970 they covered 384,547 sq. miles. Extensive geophysical surveys followed nearly immediately, and the first well was spudded by Esso in October, 1968. The second well, by Shell in March, 1969, discovered the large Maui field, later confirmed by two step-outs. Up to November 1970, 10 offshore wells with an aggregate footage of 101,181 ft. were drilled.I he only offshore rig now has left but additional targets are already established, and more will undoubtedly be after seismic surveys presently in course. Offshore drilling is expected to resume as soon as possible, particularly in concessions soon to expire. In large areas only recently granted, however, excessive water depth of up to 1000 m will prevent drilling for probably many years.On land, the tendency for wider participation in joint ventures is likely to continue. Increased activity by small operators is expected, as domestic rig availability has improved and many concessions are nearing expiry date. New licences to be granted over Greymouth and Canterbury areas which have drawn many competing applications should further stimulate the picture. Since Shell-BP in 1970 finally farmed out their large block in Taranaki which still holds the best prospects and many unexplored features, new operations are expected also there before expiry in 1973; BP-Shell's East Coast holdings expire in 1972 and the future of these two blocks which since 1955 have been in the hands of the same consortium, will probably be most important to further developments in New Zealand.

Important geological properties of unconventional resource shales

2011 ◽  
Vol 3 (4) ◽  
Author(s):  
Roger Slatt
Keyword(s):  
Shale Gas ◽  
Environmental Changes ◽  
Rock Properties ◽  
Type I ◽  
Shale Oil ◽  
Hydrocarbon Production ◽  
General Sequence ◽  
Geomechanical Properties ◽  
Depositional Processes ◽  
Stratigraphic Model

AbstractThe revelation of vast global quantities of potentially productive gas and oil-prone shales has led to advancements in understanding important geological properties which impact reservoir performance. Based upon research on a variety of shales, several geological properties have been recognized as being common and important to hydrocarbon production. (1) transport/depositional processes include hemipelagic ‘rain’, hyperpycnal flows, turbidity current flows, tempestites, wave-reworking, and contour currents in both shallow and deep water settings. (2) Common shale minerals include clays, quartz, calcite, dolomite, apatite, and pyrite; organic constituents include spores (Tasmanites), plant remains, biogenic quartz and calcite, and arenaceous foraminifera. (3) Porosity and permeability are characteristically low with pore sizes ranging down to the nanoscale. Main pore types include intergranular (including pores within clay floccules), porous organic matter, porous fecal pellets, and microfractures. (4) Important geochemical characteristics include organic richness (>3%), maturity (>1.1%Ro for shale gas and 0.6–0.9% for shale oil) and type (I–IV), in addition to certain biomarkers which are indicators of bottom water oxicity during deposition. Remaining hydrocarbon potential [RHP = (S1 + S2)/TOC] also reflects temporal environmental changes. ‘Isotopic reversals’ can be used to detect best producing areas in shale-gas plays. (5) Lithofacies stacking patterns and sequence stratigraphy are the result of eustatic depositional history. A general sequence stratigraphic model is presented here that highlights this commonality. (6) Geomechanical properties are key to drilling, fracturing and production of hydrocarbons. Brittle-ductile couplets at several scales occur in shale sequences. (7) Geophysical properties, when calibrated to rock properties, provide a means of regionally to locally mapping the aforementioned properties. (8) Economic and societal considerations in the exploration and development of resource shales are garnering attention. Many potentially economic shale-gas and shale-oil plays are being identified globally. Risks and uncertainties associated with gas- and oil-rich shales include the lack of long-term production histories, environmental concerns related to hydraulic fracturing, uncertainty in calculating hydrocarbons-in-place, and fluctuations in supply, demand, and price.

Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin

2015 ◽  
Author(s):  
Jamal A. Madi ◽  
Elhadi M. Belhadj
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Lower Silurian ◽  
History Of ◽  
Oil Gas

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

DEVELOPMENTS IN THE CENTRAL AND NORTHEASTERN EAST COAST BASIN, NORTH ISLAND, NEW ZEALAND

2006 ◽  
Vol 46 (1) ◽  
pp. 215 ◽  
Author(s):  
C.I. Uruski ◽  
B.D. Field ◽  
R. Funnell ◽  
C. Hollis ◽  
A. Nicol ◽  
...  
Keyword(s):  
New Zealand ◽  
20Th Century ◽  
Oil And Gas ◽  
East Coast ◽  
Source Rocks ◽  
Late 20Th Century ◽  
Data Set ◽  
General Sequence ◽  
Thermal Models ◽  
The North

Oil production in the East Coast Basin began in the late 19th century from wildcat wells near oil seeps. By the mid-20th century, geology was being applied to oil exploration, but with little success. In the late 20th century, seismic techniques were added to the exploration arsenal and several gas discoveries were made. At each stage it was recognised that exploration in this difficult but tantalising basin required more information than was available. Continuing work by exploration companies, as well as by the Institute of Geological & Nuclear Sciences (GNS), has begun to reduce the risk of exploration. Source rocks have been identified and sophisticated thermal models show that petroleum is being generated and expelled from them as shown by numerous oil and gas seeps onshore. Many potential reservoir sequences have been recognised from outcrop studies and depositional models are being refined. All components of petroleum systems have been demonstrated to be present. The most important deficiency to date is the general lack of high-quality seismic data which would allow recognition of reservoir facies in the subsurface.During early 2005, Crown Minerals, the New Zealand government group charged with promoting and regulating oil and gas exploration, commissioned a high specification regional 2D survey intended to address some of the main data gaps in the offshore East Coast Basin. A broad grid was planned with several regional lines to be acquired with a 12,000 m streamer and infill lines to be acquired with a streamer 8,000 m long. It was expected that the long streamer would increase resolution of Paleogene and Cretaceous units. Several of the lines were actually acquired with a 4,000 m streamer due to unexpectedly high rates of unserviceability. The resulting 2,800 km data set consists of a series of northwest–southeast lines approximately orthogonal to the coast at a spacing of about 10 km as well as several long strike lines.GNS was contracted to produce a series of reports covering source rock distribution, a catalogue of reservoir rocks, a regional seismic interpretation, thermal models and structural reconstruction. The data package and reports are available free of charge to any interested exploration company to accompany the licensing round that was announced on 1 September 2005. The new data set has confirmed the existence of a large, little-deformed basin to the north of North Island and the Bay of Plenty; it has elucidated the complex structure of a large part of the East Coast Basin and has enabled generation of a general sequence stratigraphic model which assists in delineating reservoir targets. On 1 September 2005, the New Zealand government launched a licensing round covering about 43,000 km2 of the East Coast Basin, from the far offshore East Cape Ridge in the north to the northern Wairarapa coast in the south. Four blocks (I, J, K and L) were on offer for a competitive staged work programme bid, closing on 17 February 2006.

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