EXPLORATION IN THE EAST COAST BASIN, NEW ZEALAND

1972 ◽  
Vol 12 (1) ◽  
pp. 39
Author(s):  
W.C. Leslie ◽  
R.J.S. Hollingsworth
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Geological Structure ◽  
Seismic Survey ◽  
Porosity And Permeability ◽  
Rugged Topography ◽  
Complex Geological Structure ◽  
Petroleum Development ◽  
Made In

Numerous oil and gas seeps have been known in the East Coast Basin of New Zealand since the last century; however, no commercial discovery has been made in the region. Although a number of wells was drilled earlier, the present phase of systematic geological and geophysical exploration was begun by BP Shell Todd Petroleum Development Limited in 1957 and by 1970 had resulted in the drilling of five wells. These wells indicated the presence of thick marine mudstones and siltstones of Cretaceous through Tertiary age, but failed to find any suitable reservoir beds. This, plus complex geological structure and rugged topography are major problems of the region, particularly in the northern portion.Beaver Exploration subsequently became interested in the area because of the presence of a porous Pliocene coquina limestone (known as the Te Aute Beds) cropping out in the Southern Hawke's Bay region. This unit was considered to be a good drilling target if it occurred adequately sealed in the deeper parts of the basin. In an effort to determine this, Beaver conducted a Seismic Survey with the object of tracing the limestone from outcrop into the subsurface, where hopefully it would be found structurally closed.The survey was successful and three drill sites were chosen. In two of these the drill penetrated the Te Aute Beds which had excellent porosity and permeability but were water filled; in the third well the reservoir was missing. Correlations between the seismic and the drilling results indicated that the Te Aute Beds are probably mappable at least over some parts of the Southern Hawke's Bay region. The problem now is to find these beds in areas where they are less likely to be water flushed.

APPLICATION OF A MULTIDIMENSIONAL DETERMINISTIC-STATISTICAL NUMERICAL CORRELATION MODEL TO REFINE THE STRUCTURE OF THE AS11 HORIZON OF THE ZAPADNO-KAMYNSKOYE FIELD

2021 ◽  
Vol 7 (3) ◽  
pp. 123-135
Author(s):  
Anatoly M. NIKASHKIN ◽  
Alexey A. KLIMOV
Keyword(s):  
Oil And Gas ◽  
Geological Structure ◽  
Correlation Model ◽  
Gas Reservoirs ◽  
Work Related ◽  
Correlation Models ◽  
Complex Geological Structure ◽  
Geophysical Information ◽  
Well Correlation ◽  
Clay Layers

One of the primary and significant tasks in the construction of geological models of oil and gas reservoirs and development facilities is the problem of correlation of productive layers. This task, as a rule, is reduced to the identification and areal tracing of presumably even-aged oil and gas strata, horizons, and layers characterized by clear boundaries between sand strata and clay layers overlapping them. The practice of work related to modeling the structure of oil and gas horizons, layers and strata indicates that the correlation is not always unambiguous. The ambiguity is especially noticeable when correlating strata characterized by a clinoform structure, one of the examples is the Achimov strata. The most reliable basis for well correlation is GIS materials and lithological features of the interlayers forming individual layers. Clay interlayers and clay strata separating productive deposits provide valuable information when choosing a correlation model in sedimentary sections. These interlayers are characterized by the greatest consistency in area and are most clearly displayed on geophysical diagrams by the nature of the drawings of GIS curves. However, even in this case, i. e. when using the entire accumulated volume of the most diverse lithological and field-geophysical information, the correlation models of the sections turn out to be different and often even opposite. In this paper, the authors had to face a similar situation when correlating the horizon AS11 of the Zapadno-Kamynskoye field. The paper describes a method for clarifying the position of the chops of the productive horizon of oil and gas deposits using a multidimensional deterministic-statistical numerical model of the correlation of sedimentary strata. The proposed approach allows us to uniquely determine the positions of the chops in the conditions of a complex geological structure of the object, high thin-layered heterogeneity. A concrete example shows the advantages of the proposed approach in comparison with the traditional one.

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.

SEISMIC INVESTIGATION OF THE MERRIMELIA FIELD

1983 ◽  
Vol 23 (1) ◽  
pp. 192
Author(s):  
B. L. Smith
Keyword(s):  
Oil And Gas ◽  
Seismic Survey ◽  
Gas Field ◽  
Central Dome ◽  
Oil Reserves ◽  
Oil And Gas Field ◽  
Well Data ◽  
Field Area ◽  
Made In ◽  
Commercial Oil

The Merrimelia oil and gas field, 40 km north of Moomba in SA, is located on the central dome of the Gidgealpa-Merrimelia-Innamincka Trend within the Cooper/Eromanga Basins.Geophysical studies have been instrumental in the investigation of the field since the discovery of commercial Permo-Triassic gas at Merrimelia- 5 in 1970 based on the results of the Merrimelia Seismic Survey. Subsequent seismic recorded during the 1980 Karawinnie Survey resulted in the location of Merrimelia-6 which, in 1981, discovered commercial oil in the Jurassic Namur Member and Hutton Sandstone, and Triassic gas, previously unknown.To allow accurate mapping of the field's oil reserves, a detailed half kilometre grid was recorded during the 1981 Namooka Seismic Survey. The programme comprised 110 km of 24-fold Vibro- seis coverage. Interpretation of the seismic and well data has resulted in recognition of a complex stratigraphic component superimposed on the Merrimelia structural high. Considerable detailed seismic work has contributed to a better understanding of the seismic reflection sequence and hence improved geophysical prognoses.Seismic studies of the Merrimelia field are continuing as further discoveries, most recently oil in the Triassic at Merrimelia-12 and gas in the Tirrawarra Sandstone at Merrimelia-13, are made in the field area.

scholarly journals Productivity Criteria for Complex Reservoirs Based on the Study of Deep-Adsorbed Gases

2021 ◽  
Vol 133 (2) ◽  
pp. 27-30
Author(s):  
D. A. Kobylinskiy ◽  
Keyword(s):  
Research Method ◽  
Oil And Gas ◽  
Geological Structure ◽  
Core Material ◽  
Test Results ◽  
The West ◽  
Gas Field ◽  
The Core ◽  
Oil And Gas Field ◽  
Complex Geological Structure

The work is devoted to the development of geochemical criteria for determining the nature of saturation for deep-adsorbed gases in the core. As the object of investigation used the core material selected in the fields in the Nadym-Pyrskoy oil and gas field. In each sample, 72 components were determined, namely, hydrocarbons of different material groups: normal, branched, polycyclic, and aromatic compounds from butane to dodecane. With respect to the quantitative distribution and correlation among the components, qualitative geochemical indicators of sediment productivity have been developed. The saturation character established by the criteria of deep-adsorbed gases was confirmed by the test results. In this regard, this research method significantly increases the effectiveness of diagnostics of prospective deposits, the application of which is relevant in the territory of the West Siberian oil and gas basin, especially when studying deep-submerged deposits of complex geological structure.

Exploring New Zealand's marine territory

2011 ◽  
Vol 51 (1) ◽  
pp. 549 ◽  
Author(s):  
Chris Uruski
Keyword(s):  
New Zealand ◽  
Deep Water ◽  
Seismic Data ◽  
East Coast ◽  
Sedimentary Basins ◽  
Petroleum Exploration ◽  
Seismic Survey ◽  
Data Set ◽  
Eastern Australia ◽  
Deep Water Part

Around the end of the twentieth century, awareness grew that, in addition to the Taranaki Basin, other unexplored basins in New Zealand’s large exclusive economic zone (EEZ) and extended continental shelf (ECS) may contain petroleum. GNS Science initiated a program to assess the prospectivity of more than 1 million square kilometres of sedimentary basins in New Zealand’s marine territories. The first project in 2001 acquired, with TGS-NOPEC, a 6,200 km reconnaissance 2D seismic survey in deep-water Taranaki. This showed a large Late Cretaceous delta built out into a northwest-trending basin above a thick succession of older rocks. Many deltas around the world are petroleum provinces and the new data showed that the deep-water part of Taranaki Basin may also be prospective. Since the 2001 survey a further 9,000 km of infill 2D seismic data has been acquired and exploration continues. The New Zealand government recognised the potential of its frontier basins and, in 2005 Crown Minerals acquired a 2D survey in the East Coast Basin, North Island. This was followed by surveys in the Great South, Raukumara and Reinga basins. Petroleum Exploration Permits were awarded in most of these and licence rounds in the Northland/Reinga Basin closed recently. New data have since been acquired from the Pegasus, Great South and Canterbury basins. The New Zealand government, through Crown Minerals, funds all or part of a survey. GNS Science interprets the new data set and the data along with reports are packaged for free dissemination prior to a licensing round. The strategy has worked well, as indicated by the entry of ExxonMobil, OMV and Petrobras into New Zealand. Anadarko, another new entry, farmed into the previously licensed Canterbury and deep-water Taranaki basins. One of the main results of the surveys has been to show that geology and prospectivity of New Zealand’s frontier basins may be similar to eastern Australia, as older apparently unmetamophosed successions are preserved. By extrapolating from the results in the Taranaki Basin, ultimate prospectivity is likely to be a resource of some tens of billions of barrels of oil equivalent. New Zealand’s largely submerged continent may yield continent-sized resources.

EXPLORATION OPPORTUNITIES, EAST COAST BASIN, NEW ZEALAND

2000 ◽  
Vol 40 (1) ◽  
pp. 39
Author(s):  
J.B. Frederick ◽  
E.J. Davies ◽  
P.G. Smith ◽  
D. Spancers ◽  
T.J. Williams
Keyword(s):  
New Zealand ◽  
Late Miocene ◽  
Joint Venture ◽  
East Coast ◽  
High Amplitude ◽  
Petroleum Exploration ◽  
Early Miocene ◽  
Seismic Survey ◽  
Seismic Events ◽  
Submarine Fan

The Westech-Orion Joint Venture holds onshore Petroleum Exploration Permit 38329 and offshore PEPs 38325, 38326 and 38333 in the East Coast Basin, New Zealand. The Joint Venture holds 24,117 km2 covering Hawkes Bay and the Wairarapa shelf.The Westech-Orion Joint Venture has drilled six exploratory wells and five appraisal wells in the onshore East Coast Basin over a two year period. All wells encountered significant gas shows, with two wells discovering hydrocarbons in potentially commercial volumes. Each well was drilled on the crest of a seismically mapped structure, characterised by asymmetric folding over a northwest dipping thrust fault.Prior to this drilling program, the reservoir potential of the Wairoa area was inferred to be dominated by turbidite sandstones of the Tunanui and Makaretu formations (Mid-Late Miocene). The new wells show that the Mid Miocene and parts of the Early and Late Miocene pinch out across the 'Wairoa High'.One of the primary onshore reservoirs is the Kauhauroa Limestone (Early Miocene), a bryozoan-dominated, tightly packed and cemented limestone with dominantly fracture porosity. The other primary reservoir is the Tunanui Sandstone (Mid Miocene), which in well intersections to date comprises medium-thickly bedded sandstone, with net sand typically 40%. The sands have high lithic content, and are moderately sorted and subangular-subrounded.Abnormally high formation pressures were encountered in all wells, ranging up to 3,400 psi at 1,000 m. Crestal pressure gradients commonly exceed 70% of the lithostatic pressure gradient, despite the relative proximity to outcrop. The overpressure may reflect relatively young uplift of fossil pressures, with insufficient time for pressure equilibration within a generally overpressured system.The prospectivity of the area has been highgraded by recent maturation and reservoir studies in Hawkes Bay and by gas discoveries in Westech-Orion wells onshore northern Hawkes Bay. Maturation studies identified nine kitchen areas with oil migration commencing in the Late Miocene. Seismic stratigraphy and correlation with onshore wells identified offshore submarine fan deposits of Eocene, Early Miocene, Mid Miocene and Pliocene age.A 594 km2 exploration 3D seismic survey was acquired in Hawke Bay in April 1999, and 685 km of 2D seismic were acquired in March 2000. Preliminary interpretation of the 3D survey has yielded five prospects, each covering 20–90 km2. One prospect is a lowstand fan identified by stacked mounding and bidirectional downlap, correlated with the onshore Mid Miocene Tunanui Sandstone. High amplitude seismic events of Mid-Late Miocene ages are inferred to be pulses of submarine fan development, in places associated with direct hydrocarbon indicators (DHIs). High amplitude seismic events in the Pliocene include a package of high amplitude seismic reflectors interpreted as structurally trapped DHI truncated by a major unconformity.

scholarly journals Hydrocarbon accumulation patterns of Shaximiao Formation in Longgang, Sichuan Basin

2020 ◽  
Vol 194 ◽  
pp. 01045
Author(s):  
WANG Zhiguo ◽  
JIN Wei ◽  
CHENG De’an
Keyword(s):  
Black Shale ◽  
Sichuan Basin ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Bottom Part ◽  
Porosity And Permeability ◽  
Made In ◽  
Low Porosity

Recent years, progress has been made in hydrocarbon exploration of Shaximiao Formation in Sichuan Basin. The Shaximiao formation is fluvial facies deposit, the reservoir is channel sandstone with a low porosity and permeability, oil and gas generate from black shale of the Lianggaoshan formation and the Da’anzhai section of Ziliujing formation. In Longgang, immigration channel is the key condition of accumulation of Shaximiao formation. There are two kinds of immigration channels, fractures caused by hydrocarbon generation overpressure release and faults. Oil generated from Lianggaoshan shale immigrated to the sandstone of bottom part of Sha1, oil and gas generated from Da’anzhai black shale immigrated to upper part sandstone though faults. There is no water in the reservoir. Channel sandstone and source faults interpretation is the key point of exploration success.

scholarly journals ANALYSIS OF FRACTION CONTENTS IN ROCK SCRATCH TESTS FOR ESTIMATING THE ANGLE OF INTERNAL FRICTION FOR THE SEDIMENTARY COVER OF THE KOVYKTA FIELD

2021 ◽  
Vol 12 (3S) ◽  
pp. 748-753
Author(s):  
K. V. Toropetsky ◽  
G. A. Borisov ◽  
A. S. Smirnov ◽  
A. V. Nosikov
Keyword(s):  
Internal Friction ◽  
Sedimentary Cover ◽  
Geological Structure ◽  
Seismic Survey ◽  
Southeastern Part ◽  
Lower Paleozoic ◽  
Angle Of Internal Friction ◽  
Granulometric Analysis ◽  
Complex Geological Structure ◽  
Scratch Tests

The article describes the possibility of using the granulometric analysis of rock cuttings formed in controlled core scratching tests to estimate the angle of internal friction.The study object is the Kovykta gas-condensate field (GCF) that occupies a wide area in the southeastern part of the Irkutsk amphitheater of the Siberian platform. This uniquely complex geological structure holds significant reserves of hydrocarbons. Its sedimentary cover is composed of the Vendian – lower Paleozoic and partly Riphean formations. Their total thickness exceeds 6000 m, as estimated from the new seismic survey data [Vakhromeev et al., 2019].The sedimentary cover of the Kovykta GCF has been studied by surface and borehole geophysical techniques, remote sensing and geostructural methods, in combination with the tectonophysical approach [Seminsky et al., 2018] based on drilling data, including standard and special core sampling data.

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>

PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING

2007 ◽  
Vol 47 (1) ◽  
pp. 145 ◽  
Author(s):  
C. Uruski ◽  
C. Kennedy ◽  
T. Harrison ◽  
G. Maslen ◽  
R.A. Cook ◽  
...  
Keyword(s):  
New Zealand ◽  
Seismic Data ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Source Rocks ◽  
Seismic Survey ◽  
Recording Time ◽  
Petroleum Potential ◽  
South Basin ◽  
Time Migration

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.

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