Petroleum Prospectivity of the Tasman Frontier

2014 ◽  
Vol 54 (2) ◽  
pp. 520
Author(s):  
Francois Bache ◽  
Vaughan Stagpoole ◽  
Rupert Sutherland ◽  
Julien Collot ◽  
Pierrick Rouillard ◽  
...  
Keyword(s):  
Source Rock ◽  
New Caledonia ◽  
Source Rocks ◽  
Rock Composition ◽  
Seismic Reflection Data ◽  
Bottom Simulating Reflector ◽  
Reflection Data ◽  
Stratigraphic Framework ◽  
Well Data ◽  
The One

The Fairway Basin lies between Australia and New Caledonia in the northern Tasman Frontier area with water depths ranging from less than 1,000–2,400 m. This basin was formed in the mid-to-late Cretaceous during the eastern Gondwana breakup and since then has received detrital and pelagic sediments. It is known for its 70,000 km2 bottom simulating reflector, interpreted as one of the world’s largest gas hydrate layers or as a regional diagenetic front. The seismic reflection data shows sedimentary thicknesses (up to 4 km) and geometries capable of trapping hydrocarbons. The authors interpreted the seismic stratigraphy and available well data in terms of paleogeography and tectonic evolution. This work allowed the discovery of a deeply buried delta, probably of the same type as the deep-water Taranaki Delta. This stratigraphic framework is used to constrain multi-1D generation modelling and to test three main hypotheses of source rocks. The most likely scenario, similar to the one accepted for the Taranaki petroleum province, are a type-III and type-II source rocks intercalated in a Cretaceous prograding series. Another possible scenario is a source rock equivalent to the east Australian Walloon Formation and the occurrence of the marine source rock in the pre-rift sequence. Although, the large modelled volumes at this stage are speculative due to limited data on source rock composition, richness and distribution, as well as on the presence and quality of reservoir and seal, this study confirms the prospectivity of the Fairway Basin and the need for more data to further assess this basin.

Petroleum implications of stacked deltas in the Fairway Basin, offshore New Caledonia, Northern Tasman Frontier

2014 ◽  
Vol 54 (2) ◽  
pp. 537
Author(s):  
Pierrick Rouillard ◽  
Julien Collot ◽  
Francois Bache ◽  
Rupert Sutherland ◽  
Karsten Kroeger ◽  
...  
Keyword(s):  
Source Rock ◽  
New Caledonia ◽  
Source Rocks ◽  
Rock Composition ◽  
Seismic Reflection Data ◽  
Bottom Simulating Reflector ◽  
Reflection Data ◽  
Stratigraphic Framework ◽  
Well Data ◽  
The One

The Fairway Basin lies between Australia and New Caledonia in the northern Tasman Frontier area with water depths ranging from less than 1,000–2,400 m. This basin formed in mid-to-Late Cretaceous during eastern Gondwana breakup and received detrital and pelagic sediments since that time. It is known for a 70,000 km2 bottom simulating reflector interpreted as either one of the world’s largest gas hydrate layers or as a regional diagenetic front. Seismic reflection data shows sedimentary thicknesses (up to 4 km) and geometries capable of trapping hydrocarbons. We interpret seismic stratigraphy and available well data in terms of paleogeography and tectonic evolution. This work allowed the discovery of a deeply buried delta probably of the same type as the deepwater Taranaki Delta. This stratigraphic framework is used to constrain multi-1D generation modelling and to test three main hypotheses of source rocks. The most likely scenario, similar to the one accepted for the Taranaki petroleum province, are a type-III and type-II source rocks intercalated in Cretaceous prograding series. Another possible scenario is a source rock equivalent to the East Australian Walloon Formation and occurrence of marine source rock in the pre-rift sequence. Although large modelled volumes at this stage are speculative due to limited data on source rock composition, richness and distribution, as well as on the presence and quality of reservoir and seal, this study confirms the prospectivity of the Fairway Basin and the need for more data to further assess this basin.

scholarly journals Inversion tectonics: a brief petroleum industry perspective

2020 ◽  
Author(s):  
Gábor Tari ◽  
Didier Arbouille ◽  
Zsolt Schléder ◽  
Tamás Tóth
Keyword(s):  
Petroleum Industry ◽  
Structural Complexity ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
Seismic Reflection Data ◽  
Reflection Seismic ◽  
Reflection Data ◽  
Well Data

Abstract. The concept of structural inversion was introduced in the early 1980s. By definition, an inversion structure forms when a pre-existing extensional (or transtensional) fault controlling a hangingwall basin containing a syn-rift or passive fill sequence subsequently undergoes compression (or transpression) producing partial (or total) extrusion of the basin fill. Inverted structures provide traps for petroleum exploration, typically four-way structural closures. As to the degree of inversion, based on large number of worldwide examples seen in various basins, the most preferred petroleum exploration targets are mild to moderate inversional structures, defined by the location of the null-points. In these instances, the closures have a relatively small vertical amplitude, but simple in a map-view sense and well imaged on seismic reflection data. Also, the closures typically cluster above the extensional depocentres which tend to contain source rocks providing petroleum charge during and after the inversion. Cases for strong or total inversion are generally not that common and typically are not considered as ideal exploration prospects, mostly due to breaching and seismic imaging challenges associated with the trap(s) formed early on in the process of inversion. Also, migration may become tortuous due to the structural complexity or the source rock units may be uplifted above the hydrocarbon generation window effectively terminating the charge once the inversion occurred. For any particular structure the evidence for inversion is typically provided by subsurface data sets such as reflection seismic and well data. However, in many cases the deeper segments of the structure are either poorly imaged by the seismic data and/or have not been penetrated by exploration wells. In these cases the interpretation of any given structure in terms of inversion has to rely on the regional understanding of the basin evolution with evidence for an early phase of substantial crustal extension by normal faulting.

Dynamics and evolution of continental margin clinoform systems

2020 ◽  
Author(s):  
Gerben de Jager ◽  
Dicky Harishidayat ◽  
Benjamin Emmel ◽  
Ståle Emil Johansen
Keyword(s):  
Sea Level ◽  
Continental Margin ◽  
Water Depth ◽  
Large Scale ◽  
Barents Sea ◽  
Source Rocks ◽  
Sea Level Changes ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Geological Processes

<p>Clinoforms are aquatic sedimentary features commonly associated with strata prograding from a shallower water depth into a deeper water depth. They are very sensitive to changes in water depth, rapidly moving along the shelf in response to sea level changes.  By reconstructing the initial clinoform geometry of buried clinoforms, an estimate of the paleo water depth (PWD) can be made. When this is done for several subsequent clinoform sets the amounts and rates of bathymetric changes can be calculated.</p><p>Here we present a novel approach to estimate clinoform parameters and depositional depths for continental margin clinoforms using seismic reflections, wellbore and biostratigraphy data. Seismic interpretation of three relatively east-west regional full-stack seismic reflection data from the continental margin of the western Barents Sea revealed twelve Late Cenozoic horizons. The clinoform shapes have been restored by removing the effects of compaction and flexural isostasy (backstripping). This includes the effects of glacial/interglacial scenarios on horizons with strong glaciomarine seismic indications.</p><p>Based on the reconstructed clinoform geometries we use empirical relationships from literature between clinoform geometry and depositional depth to estimate PWD values. In these analyses it is possible to estimate the PWD of the upper rollover point and the toe point by measuring the bottomset height, foreset height and topset height. A sensitivity analysis study has also been done on several different scenarios, varying elastic thickness, decompaction and net to gross ratio. Comparison with biostratigraphic water depth estimates indicate that PWD estimates revealed from clinoform parameters give reliable results.</p><p>Any mismatch between the backstripped PWD values and the PWD values derived from the clinoform geometry can then be attributed to geological processes not included in the backstripping process. Among others, these could be explained by rifting, thermal effects in the lithosphere, faulting or eustatic sea level changes. This allows the quantification of the magnitude of these large-scale crustal processes through time.</p><p>We will demonstrate that this method can further constrain the PWD on the continental margin clinoform system and thus can help to improve the understanding of the interplay between sedimentary processes and large-scale crustal processes. Furthermore, the PWD estimates will be a reliable input for further analysis of source-to-sink and stratigraphic forward modeling studies as well as reservoir and source rocks prediction on the petroleum development and exploration.</p><p> </p>

METHOD USING ELLIPSES TO INTERPRET SEISMIC REFLECTION DATA

Geophysics ◽  
1964 ◽  
Vol 29 (6) ◽  
pp. 926-934
Author(s):  
Gary S. Gassaway
Keyword(s):  
Seismic Reflection ◽  
Seismic Velocity ◽  
Vertical Section ◽  
Reflection Point ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
The One ◽  
Time Of Travel ◽  
Reflecting Surfaces ◽  
Reflecting Surface

The properties of an ellipse can be used to interpret seismic reflection data by using the positions in a vertical section of a shot and a geophone as the foci of an ellipse. With the shot and geophone as the foci, the total time of travel of a reflected seismic wave serves as the constant necessary to define the ellipse. The reflecting surface then is tangent to this ellipse. Therefore, if many ellipses are plotted, the reflecting surfaces may be found by drawing smooth curves that are tangent in common to closely intersecting families of arcs. This basic principle is extended to the interpretation of complex structures that are not perpendicular to the line of traverse and to areas where the seismic velocity changes with depth by the following steps: The shots and geophones are plotted on a graph where the units along both the ordinate and the abscissa are virtual seismic traveltimes. These positions of the shots and geophones are then used as the foci of the ellipses as above. The reflecting surfaces are then drawn tangent to the dark bands of closely intersecting elliptical arcs. From this graph the one‐way time from a shot to a point of reflection, and from the point of reflection to a geophone may be scaled off; this is done by drawing the elliptical radii from the shot and geophone to the point of tangency between the ellipse and reflecting surface. The lengths of these radii are the one‐way times at the time scale of the graph. With the attitude of the wavefront as it returned to the surface at a geophone determined by a spread of three parallel geophone lines, and the one‐way time from the reflection point, one has the necessary and sufficient data to find the point of reflection in space coordinates for the assumed velocity function. Using the ray paths from the shot and geophone to this reflection point, the dip and strike of the reflecting surface at this point are found. This process is then repeated for every shot‐geophone combination for each reflecting surface.

scholarly journals Organic geochemical and petrographical characteristics of the major lower cretaceous petroleum source rock (Makhul Formation) in Kuwait - Arabian Gulf

2021 ◽  
Vol 49 (1) ◽  
Author(s):  
Fatma K. Bahman ◽  
◽  
Fowzia H. Abdullah ◽  
Abbas Saleh ◽  
Hossein Alimi ◽  
...  
Keyword(s):  
Organic Matter ◽  
Sea Level ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Arabian Gulf ◽  
Carbon Isotope Ratio ◽  
Middle Part ◽  
Source Rocks ◽  
Peak Oil ◽  
Rock Composition

The Lower Cretaceous Makhul Formation is one of the major petroleum source rocks in Kuwait. This study aims to evaluate the Makhul source rock for its organic matter richness and its relation to the rock composition and depositional environment. A total of 117 core samples were collected from five wells in Raudhatain, Ritqa, Mutriba, Burgan, and Minagish oil fields north and south Kuwait. The rock petrographical studies were carried out using a transmitted and polarized microscope, as well as SEM and XRD analyses on selected samples. Total organic matter TOC and elemental analyses were done for kerogen type optically. The GC and GC-MS were done as well as the carbon isotope ratio. The results of this study show that at its earliest time the Makhul Formation was deposited in an anoxic shallow marine shelf environment. During deposition of the middle part, the water oxicity level was fluctuating from oxic to anoxic condition due to changes in sea level. At the end of Makhul and the start of the upper Minagish Formation, the sea level raised forming an oxic open marine ramp depositional condition. Organic geochemical results show that the average TOC of the Makhul Formation is 2.39% wt. High TOC values of 6.7% wt. were usually associated with the laminated mudstone intervals of the formation. The kerogen is of type II and is dominated by marine amorphous sapropelic organic matter with a mixture of zoo- and phytoplankton and rare terrestrial particles. Solvent extract results indicate non-waxy oils of Mesozoic origin that are associated with marine carbonate rocks. The formation is mature and at its peak oil generation in its deepest part in north Kuwait.

scholarly journals Stratigraphic development and petroleum prospectivity of northern Zealandia

2021 ◽  
Author(s):  
◽  
Zelia Dos Santos
Keyword(s):  
New Zealand ◽  
Papua New Guinea ◽  
Source Rock ◽  
New Caledonia ◽  
New Guinea ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Seismic Unit ◽  
Eastern Australia ◽  
Basin Floor

<p>Northern Zealandia lies between Australia, New Zealandia, and New Caledonia. It has an area of 3,000,000 km2 and is made up of bathymetric rises and troughs with typical water depths of 1000 to 4000 m. I use 39,309 line km of seismic-reflection profiles tied to recent International Ocean Discovery Program (IODP) drilling and three boreholes near the coast of New Zealand to investigate stratigraphic architecture and assess the petroleum prospectivity of northern Zealandia.  Sparse sampling requires that stratigraphic and petroleum prospectivity inferences are drawn from better-known basins in New Zealand, Australia, New Caledonia, TimorLeste and Papua New Guinea. Five existing seismic-stratigraphic units are reviewed. Zealandia Seismic Unit U3 is sampled near New Zealand and may contain Jurassic Muhiriku Group coals. Elsewhere, Seismic Unit 3 may have oil-prone equivalents of the Jurassic Walloon Coal Measure in eastern Australia; or may contain Triassic-Jurassic marine source rocks, as found in offshore Bonaparte Basin, onshore Timor-Leste, and the Papuan Basin in Papua New Guinea. Seismic Unit U2b (Mid-Cretaceous) is syn-rift and may contain coal measures, as found in Taranaki-Aotea Basin and New Caledonia. Seismic Unit U2a (Late Cretaceous to Eocene) contains coaly source rocks in the southeastern part of the study area, and may also contain marine equivalent carbonaceous mudstone, as found at Site IODP U1509. Unit U2a is transgressive, with coaly source rocks and reservoir sandstones near its base, and clay, marl and chalk above that provides a regional seal. Seismic Unit U1b (Eocene-Oligocene) is mass-transport complexes and basin floor fans related to a brief phase of convergent deformation that created folds in the southern part of the study area and regionally uplifted ridges to create new sediment source areas. Basin floor fans may contain reservoir rock and Eocene folding created structural traps. Seismic Unit U1a is Oligocene and Neogene chalk, calcareous ooze, and marl that represents overburden. Mass accumulation rates (MAR) and climatic temperatures were high in the late Miocene and early Pliocene, resulting in peak thermal maturity and hydrocarbon expulsion at ~ 3 Ma.  Approximately one-fifth of the region has adequate source rock maturity for petroleum expulsion at the base of Seismic Unit U2: Fairway Basin (FWAY), southern New Caledonia Trough (NCTS) and Reinga Basin (REIN). Plays may exist in either Seismic Unit U3 or U2, with many plausible reservoir-seal combinations, and several possible trapping mechanisms: unconformities, normal faults, folds, or stratigraphic pinch-out. The rest of the region could be prospective, but requires a source rock to exist within Seismic Unit U3, which is mostly unsampled and remains poorly understood.</p>

New perspectives on the source rock facies of the Andaman Trough, offshore North Sumatra based on the latest onshore oil sampling and analysis

2021 ◽  
Author(s):  
D. Ariyono
Keyword(s):  
Source Rock ◽  
Pour Point ◽  
Petroleum System ◽  
Source Rocks ◽  
Late Oligocene ◽  
Administrative District ◽  
Stratigraphic Framework ◽  
Lacustrine Source Rock ◽  
Wax Content ◽  
North Sumatra

The Andaman sub-basin, located offshore Aceh Indonesia, is considered to be one of Indonesia’s most underexplored basins, despite its proximity to the giant gas and condensate fields of Arun, NSO A, NSO J and South Lhok Sukon, where in excess of 6 MMboe has been produced to date. The understanding of the Petroleum System in the offshore Andaman Trough, has historically been challenged by poor imaging of the basin architecture and limited penetration and retrieval of source rock intervals and hydrocarbon fluids for analysis. Mubadala Petroleum, as operator of the Andaman I PSC, conducted a geological field study to collect multiple oil samples from fourteen (14) onshore traditional wells across the Bireun and Aceh Timur Administrative District (Figure 1). Those samples were analyzed in laboratory for their physical properties and parameters derived from those analyzes where integrated to fully characterize oils produced in the onshore Aceh area and establish the organofacies and maturity of their source facies precursors. The results were then used as calibration for the analysis and subsurface modeling of the offshore petroleum system of the Andaman sub-basin. Previous authors have postulated that Late Oligocene to Early Miocene marine shales were the main source rocks for oil in the Andaman Trough. Oil samples collected onshore as part of this study however, were sourced by peak to late mature oil-prone lacustrine source rock facies, yielding high API (42.7 – 50.8°), low pour point, low sulphur, and low wax content fluids. Integration of these findings with the upgraded tectono-stratigraphic framework provided by the 2019 MC3D survey, reprocessed multi-vintage 2D, and reinterpretation of biostratigraphic analysis, has enabled the delineation of a postulated Paleogene lacustrine source rock facies in the Andaman Trough. This model does not preclude the potential of other source rock facies to be present and active within the Andaman Trough, including the gas-prone fluvial Eocene-Oligocene Parapat Formation, but it supports the possibility that oil may have been generated in the Andaman Trough.

Stratigraphic development and petroleum prospectivity of northern Zealandia

2021 ◽  
Author(s):  
◽  
Zelia Dos Santos
Keyword(s):  
New Zealand ◽  
Papua New Guinea ◽  
Source Rock ◽  
New Caledonia ◽  
New Guinea ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Seismic Unit ◽  
Eastern Australia ◽  
Basin Floor

<p>Northern Zealandia lies between Australia, New Zealandia, and New Caledonia. It has an area of 3,000,000 km2 and is made up of bathymetric rises and troughs with typical water depths of 1000 to 4000 m. I use 39,309 line km of seismic-reflection profiles tied to recent International Ocean Discovery Program (IODP) drilling and three boreholes near the coast of New Zealand to investigate stratigraphic architecture and assess the petroleum prospectivity of northern Zealandia.  Sparse sampling requires that stratigraphic and petroleum prospectivity inferences are drawn from better-known basins in New Zealand, Australia, New Caledonia, TimorLeste and Papua New Guinea. Five existing seismic-stratigraphic units are reviewed. Zealandia Seismic Unit U3 is sampled near New Zealand and may contain Jurassic Muhiriku Group coals. Elsewhere, Seismic Unit 3 may have oil-prone equivalents of the Jurassic Walloon Coal Measure in eastern Australia; or may contain Triassic-Jurassic marine source rocks, as found in offshore Bonaparte Basin, onshore Timor-Leste, and the Papuan Basin in Papua New Guinea. Seismic Unit U2b (Mid-Cretaceous) is syn-rift and may contain coal measures, as found in Taranaki-Aotea Basin and New Caledonia. Seismic Unit U2a (Late Cretaceous to Eocene) contains coaly source rocks in the southeastern part of the study area, and may also contain marine equivalent carbonaceous mudstone, as found at Site IODP U1509. Unit U2a is transgressive, with coaly source rocks and reservoir sandstones near its base, and clay, marl and chalk above that provides a regional seal. Seismic Unit U1b (Eocene-Oligocene) is mass-transport complexes and basin floor fans related to a brief phase of convergent deformation that created folds in the southern part of the study area and regionally uplifted ridges to create new sediment source areas. Basin floor fans may contain reservoir rock and Eocene folding created structural traps. Seismic Unit U1a is Oligocene and Neogene chalk, calcareous ooze, and marl that represents overburden. Mass accumulation rates (MAR) and climatic temperatures were high in the late Miocene and early Pliocene, resulting in peak thermal maturity and hydrocarbon expulsion at ~ 3 Ma.  Approximately one-fifth of the region has adequate source rock maturity for petroleum expulsion at the base of Seismic Unit U2: Fairway Basin (FWAY), southern New Caledonia Trough (NCTS) and Reinga Basin (REIN). Plays may exist in either Seismic Unit U3 or U2, with many plausible reservoir-seal combinations, and several possible trapping mechanisms: unconformities, normal faults, folds, or stratigraphic pinch-out. The rest of the region could be prospective, but requires a source rock to exist within Seismic Unit U3, which is mostly unsampled and remains poorly understood.</p>

Seismic identification of a karstified reservoir in the Adriatic Sea

Geophysics ◽  
1990 ◽  
Vol 55 (12) ◽  
pp. 1639-1644 ◽  
Author(s):  
M. Mendes ◽  
W. Beydoun ◽  
J. M. Planchon ◽  
A. Tarantola
Keyword(s):  
Adriatic Sea ◽  
S Wave ◽  
Seismic Line ◽  
Maximum Information ◽  
Seismic Reflection Data ◽  
Prestack Migration ◽  
Hydrocarbon Reservoir ◽  
Reflection Data ◽  
Ratio Image ◽  
Well Data

In this study, an elastic prestack migration/inversion (M/I) scheme was applied to a 2-D seismic line collected in the Adriatic Sea. The objective was to use M/I images to describe a hydrocarbon reservoir, consisting of karstified, brine‐saturated limestones. The M/I technique offers the benefit of extracting maximum information from seismic reflection data to describe, and in some cases characterize, the reservoir target. M/I images are calibrated with well data and represent approximate changes in P- and S-wave impedances across the reservoir. Combining these two images yields a Poisson’s ratio image.

scholarly journals Evolution of seafloor pockmarks along the Northern Orange Basin, Offshore South Africa: Interplay between fluid flow and bottom current activities

2021 ◽  
Author(s):  
Ovie Eruteya ◽  
Nehemiah Dominick ◽  
Yakup Niyazi ◽  
Emna Meftah ◽  
Kamaldeen Omosanya ◽  
...  
Keyword(s):  
Global Climate ◽  
Source Rocks ◽  
Climate Forcing ◽  
Bottom Current ◽  
Continental Margins ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Mechanism Control ◽  
Biogenic Components ◽  
Pressure Regime

Pockmarks are pervasive geomorphologic features identified along continental margins resulting from fluid expulsion on the seafloor. However, the understanding of the underlying geological mechanism/control in relation to their evolution, distribution, and morphology is limited, especially along data-starved continental margins such as the Northern Orange Basin. Analysis of a high-quality 3D seismic reflection data reveals at least 50 individual pockmarks, two channel-like depressions and several irregular depressions in water depth ranging between 800 m and 2400 m. Morphologically, the pockmarks are circular, elongated, comet-like and crescentic in shape, with diameters and depths ranging between ∼0.2 - 2.8 km and ∼10 - 130 m, respectively. Preferential alignment of these pockmarks on the seafloor in relation to the axis of underlying turbidite channels, erosional morphologies and mass transport complexes portray a genetic relationship. The slope architecture hints at the possibility of both deep and shallow fluid source driving pockmark formation. Under this scenario, deep thermogenic gas derived from Cretaceous source rocks migrated along fault systems associated with the Late Cretaceous Megaslide complex to the overburden. The fluids are stored/redistributed in contourite and turbidite channels and subsequently focused toward the seafloor under an increased pore pressure regime. Yet, the fluids may be either solely biogenic gas or heterogeneous, incorporating biogenic components and pore-water derived from the channels and dewatering of the contourites. Importantly, the discovery of crescentic and elongated end-member pockmark morphologies indicate post-formation sculpting of the initial pockmark morphologies by bottom currents. The discovery of these deep-water pockmarks opens the possibility that such fluid escape features may be more widespread than currently documented in the Northern Orange Basin. This has implications in understanding of the petroleum system here and their potential role in the South Atlantic marine ecosystems and global climate change in terms of the expulsion of climate forcing gases.

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