scholarly journals Structure, Faulting and Gas Accumulation: Southeast Wanganui Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Lloyd Pledger
Keyword(s):  
Sand Dunes ◽  
Thrust Fault ◽  
Aerial Survey ◽  
Petroleum Exploration ◽  
High Resistivity ◽  
Burial Depth ◽  
Hydrocarbon Source Rock ◽  
Seismic Line ◽  
Biogenic Gas ◽  
Pull Apart Basin

<p>There has been low interest in petroleum exploration in the Wanganui Basin as it lacks known hydrocarbon source rock of sufficient age or burial depth. However, the onshore Southeast Wanganui Basin has many occurrences of methane-rich biogenic gas found in shallow water wells. This project used three studies across the Horowhenua area to examine the faulting style in the Southeast Wanganui Basin where it is bounded by the Tararua range- front, and how this faulting relates to the accumulation of gas deposits in the shallow sedimentary section. South of Levin the Tararua range front steps laterally near Muhunoa East Road. A previous seismic reflection line identified a deep intra-basement arrival, which could have been either a low-angle thrust fault or side-swipe from a pull-apart basin at the step in the Tararua range front. Two seismic lines and a gravity survey found no sub-vertical drops in basement depth which would indicate the presence of a pull-apart basin or a favourable surface off which a laterally travelling seismic wave could reflect. The intra-basement arrival on the previous seismic line was therefore interpreted to be from an intra-basement low-angle thrust fault. Also two biogenic gas sites also were surveyed. A shallow gas reservoir east of Levin on Wallace Road, abutting the Tararua range front, had been discovered when a water well was drilled; and a potential reservoir southwest of Sanson was located when an aerial survey identified a domed structure with high resistivity. In both areas biogenic gas was thought to be trapped in buried sand dunes at a depth of approximately 20 m. Shallow seismic refraction and reflection methods and amplitude variation with offset analysis were used to map both reservoir bodies and confirm the presence of biogenic gas.</p>

scholarly journals Structure, Faulting and Gas Accumulation: Southeast Wanganui Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Lloyd Pledger
Keyword(s):  
Sand Dunes ◽  
Thrust Fault ◽  
Aerial Survey ◽  
Petroleum Exploration ◽  
High Resistivity ◽  
Burial Depth ◽  
Hydrocarbon Source Rock ◽  
Seismic Line ◽  
Biogenic Gas ◽  
Pull Apart Basin

<p>There has been low interest in petroleum exploration in the Wanganui Basin as it lacks known hydrocarbon source rock of sufficient age or burial depth. However, the onshore Southeast Wanganui Basin has many occurrences of methane-rich biogenic gas found in shallow water wells. This project used three studies across the Horowhenua area to examine the faulting style in the Southeast Wanganui Basin where it is bounded by the Tararua range- front, and how this faulting relates to the accumulation of gas deposits in the shallow sedimentary section. South of Levin the Tararua range front steps laterally near Muhunoa East Road. A previous seismic reflection line identified a deep intra-basement arrival, which could have been either a low-angle thrust fault or side-swipe from a pull-apart basin at the step in the Tararua range front. Two seismic lines and a gravity survey found no sub-vertical drops in basement depth which would indicate the presence of a pull-apart basin or a favourable surface off which a laterally travelling seismic wave could reflect. The intra-basement arrival on the previous seismic line was therefore interpreted to be from an intra-basement low-angle thrust fault. Also two biogenic gas sites also were surveyed. A shallow gas reservoir east of Levin on Wallace Road, abutting the Tararua range front, had been discovered when a water well was drilled; and a potential reservoir southwest of Sanson was located when an aerial survey identified a domed structure with high resistivity. In both areas biogenic gas was thought to be trapped in buried sand dunes at a depth of approximately 20 m. Shallow seismic refraction and reflection methods and amplitude variation with offset analysis were used to map both reservoir bodies and confirm the presence of biogenic gas.</p>

scholarly journals Reservoir quality and its controlling diagenetic factors in the Bentiu Formation, Northeastern Muglad Basin, Sudan

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Yousif M. Makeen ◽  
Xuanlong Shan ◽  
Mutari Lawal ◽  
Habeeb A. Ayinla ◽  
Siyuan Su ◽  
...  
Keyword(s):  
Clay Content ◽  
Petroleum Exploration ◽  
Reservoir Quality ◽  
Burial Depth ◽  
Petroleum Reservoir ◽  
Fine Grained ◽  
Porosity And Permeability ◽  
Negative Role ◽  
Crevasse Splay ◽  
Channel Deposits

AbstractThe Abu Gabra and Bentiu formations are widely distributed within the interior Muglad Basin. Recently, much attention has been paid to study, evaluate and characterize the Abu Gabra Formation as a proven reservoir in Muglad Basin. However, few studies have been documented on the Bentiu Formation which is the main oil/gas reservoir within the basin. Therefore, 33 core samples of the Great Moga and Keyi oilfields (NE Muglad Basin) were selected to characterize the Bentiu Formation reservoir using sedimentological and petrophysical analyses. The aim of the study is to de-risk exploration activities and improve success rate. Compositional and textural analyses revealed two main facies groups: coarse to-medium grained sandstone (braided channel deposits) and fine grained sandstone (floodplain and crevasse splay channel deposits). The coarse to-medium grained sandstone has porosity and permeability values within the range of 19.6% to 32.0% and 1825.6 mD to 8358.0 mD respectively. On the other hand, the fine grained clay-rich facies displays poor reservoir quality as indicated by porosity and permeability ranging from 1.0 to 6.0% and 2.5 to 10.0 mD respectively. A number of varied processes were identified controlling the reservoir quality of the studies samples. Porosity and permeability were enhanced by the dissolution of feldspars and micas, while presence of detrital clays, kaolinite precipitation, iron oxides precipitation, siderite, quartz overgrowths and pyrite cement played negative role on the reservoir quality. Intensity of the observed quartz overgrowth increases with burial depth. At great depths, a variability in grain contact types are recorded suggesting conditions of moderate to-high compactions. Furthermore, scanning electron microscopy revealed presence of micropores which have the tendency of affecting the fluid flow properties in the Bentiu Formation sandstone. These evidences indicate that the Bentiu Formation petroleum reservoir quality is primarily inhibited by grain size, total clay content, compaction and cementation. Thus, special attention should be paid to these inhibiting factors to reduce risk in petroleum exploration within the area.

ENVIRONMENTAL IMPACT OF SEISMIC OPERATIONS IN THE OTWAY BASIN, SOUTH AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 741 ◽  
Author(s):  
M. L. Williams ◽  
A. J. Boulton ◽  
M. Hyde ◽  
A. J. Kinnear ◽  
C. D. Cockshell
Keyword(s):  
Environmental Management ◽  
Environmental Impact ◽  
Vegetation Structure ◽  
South Australia ◽  
Petroleum Exploration ◽  
Seismic Exploration ◽  
Native Vegetation ◽  
Seismic Line ◽  
The Impact ◽  
Seismic Lines

The Department of Mines and Energy, South Australia (DME) contracted Michael Williams and Associates Pty Ltd to audit the environmental management of seismic exploration operations in the South Australian Otway Basin. The audit was carried out in early 1992 and covered petroleum exploration operators and DME environmental management systems. An innovative field sampling technique was developed to compare the environmental impact of two different seismic line clearing techniques. Recovery of native vegetation as measured by vegetation structure was also quantified.The audit found DME to have a dynamic and integrated environmental management system while company systems varied in standard. Wide consultation assisted the audit process.As a result of clearing for agriculture, native vegetation covers only six per cent of the Otway Basin. With the strict limitations to broad-scale vegetation clearance since the mid-1980s and the cessation since 1991, the greatest environmental impact of seismic exploration is the clearance of native vegetation for access by seismic vehicles. Native vegetation structure and associated abiotic variables on seismic lines and adjacent control sites, were subject to a classification and ordination analysis which compared the impact of seismic lines constructed by bulldozer or Hydro-ax (industrial slasher). Post-seismic recovery rates of three different vegetation associations were also determined. This analytical technique permits the effects of seismic line clearance to be compared with the natural variability of specific vegetation associations within a region. In interpreting the results however, there is a confounding effect of line type and year as most of the more recent seismic lines were constructed using a Hydro-ax. Results indicate that Hydro-ax clearing affects vegetation structure less than bulldozing. Most Hydro-ax sites recovered within a few years whereas some sites, bulldozed as early as 1971, particularly tussock grasslands, have not yet recovered.This study provides a significant break-through in the debate about the persistence of seismic impacts on native vegetation. As a rapid preliminary assessment, sampling vegetation structure rather than floristics, provides a cost-effective audit and monitoring technique which can be used by non-specialists in a range of petroleum exploration environments. Any significant structural differences may require more detailed analysis to determine if floristic composition also differed.

Seed germination and seedling emergence of three Artemisia species (Asteraceae) inhabiting desert sand dunes in China

2006 ◽  
Vol 16 (1) ◽  
pp. 61-69 ◽  
Author(s):  
Kazuo Tobe ◽  
Liping Zhang ◽  
Kenji Omasa
Keyword(s):  
Seed Germination ◽  
Sand Dunes ◽  
Seedling Emergence ◽  
Light Sensitivity ◽  
Burial Depth ◽  
Secondary Effects ◽  
Seed Burial ◽  
Desert Sand ◽  
Light Fluence ◽  
Artemisia Species

Artemisia ordosica,A. arenariaandA. sphaerocephalaare semi-shrubs inhabiting desert sand dunes in China and often used to rehabilitate desertified areas. Improvement of dune rehabilitation success by sowing requires better understanding of the processes involved in the control of seed germination and seedling emergence in these species. Thus, (1) effects of temperature, light and osmotica (polyethylene glycol-6000) on seed germination, and (2) effects of seed burial depth in sand and irrigation regime on seedling emergence, were studied under controlled conditions. Seeds of the three species required light for germination, and the light fluence needed for germination was dependent on temperature. Seedling emergence of the three species was maximal (70–94%) for seeds sown at a depth of 2.5 mm, and decreased with increasing seed burial depth when the pots were initially and subsequently treated with 16 mm and 3 mm irrigation at 1-d intervals. However, when the pots were initially and subsequently treated with 8 mm and 3 mm irrigation at 2-d intervals, seedling emergence was almost completely suppressed due to water deficiency in sand. It is suggested that the probability of seed germination and seedling emergence of the three species in the field is very limited, because the light requirement restricts seed germination to shallow sand layers where water is lost rapidly due to evaporation. Temperature appeared to have secondary effects on seed germination, by modifying the light sensitivity of seeds.

Discovery of Bioclastic Dolostone in the Second Member of Shahejie Formation in Bozhong Depression

2014 ◽  
Vol 962-965 ◽  
pp. 117-120
Author(s):  
Yu Jing Wang ◽  
Jiao Wang
Keyword(s):  
Physical Property ◽  
Source Area ◽  
Oil Field ◽  
Petroleum Exploration ◽  
Burial Depth ◽  
Shahejie Formation ◽  
Deep Reservoir ◽  
High Production ◽  
Bozhong Depression ◽  
Better Than

Reservoir quality is the key for the petroleum exploration for middle-deep formation in the Bozhong Depression because the middle-deep reservoir is with the characteristics of big burial depth and poor physical property which is difficult to predict, but the physical property of dolostone reservoir (includes bioclastic dolostone and terrigenous clastic dolostone) is significant better than that of the clastic reservoir in the same depth in the second member of Shahejie Formation of QHD36-3 oil field, which could be one of the frontier for high production reservoir exploration. The paper concludes that the development of dolostone is mainly controlled by paleogeomorphology and paleo water depth as well as the distance from the source area. Building up the related sedimentary pattern is good for the exploration aiming at bioclasti dolostone and terrigenous clastic dolostone reservoir.

Velocity‐depth ambiguity of reflection traveltimes

Geophysics ◽  
1990 ◽  
Vol 55 (3) ◽  
pp. 266-276 ◽  
Author(s):  
Samuel H. Bickel
Keyword(s):  
Noise Level ◽  
Seismic Velocity ◽  
Wiener Filter ◽  
Line Length ◽  
Velocity Estimation ◽  
Inhomogeneous Layer ◽  
Burial Depth ◽  
Resolution Limit ◽  
Seismic Line ◽  
Interval Velocity

The conversion of time horizons to depth is fundamental to exploration geophysics. The interval velocity used in the conversion is often estimated from the stacking velocity, assuming that each layer’s interval velocity is homogeneous. However, even for one laterally inhomogeneous layer above a flat reflector the stacking velocity can swing violently about its average and conventional methods of velocity estimation fail. I show that violent swings in the stacking velocity are a symptom of a long‐wavelength ambiguity between the burial depth to an interface and interval velocity. Lateral variations in seismic velocity with a spatial wavelength of about 2.7 D, where D is the depth to the reflecting horizon, cannot be unambiguously resolved from traveltime measurements. The spatial wavelength of this ambiguous component varies from 2.57 D, for very small source‐receiver separations, to 2.86 D for source‐receiver separations equal to D. Spectral components of the stacking velocity at wavelengths shorter than this ambiguous value are amplified in size and reversed in polarity relative to the interval velocity. A practical inverse filter that corrects for these distortions produces an interval velocity that is almost totally lacking in low‐frequency components, giving a very distorted picture of the interval velocity. Since the wavelength of total ambiguity changes with offset, a complete description of the velocity and depth fields can, in theory, be extracted from a combination of multiple‐offset traveltime measurements. However, the wavelength of total ambiguity is such a weak function of source‐receiver separation that multiple offset processing, in practice, does little to resolve the ambiguity. In fact, the Rayleigh resolution limit implies that three or more offset measurements are more effective than two only if the seismic‐line length is at least 20 D. In a series of numerical experiments with the line set to 100 D and a spatial noise level of .01% in each channel I used a two‐channel Wiener filter to successfully extract the full‐band response for a simultaneous step change in velocity and in depth. The method fails for lines shorter than 20 D because of the transients that arise when the data are shorter than the filter. Stability was achieved by increasing the noise level to 1% in the design of the Wiener filter, but low spatial frequencies were lost and the estimated velocity‐depth model was distorted. If the results of this single flat‐layer analysis apply to practical situations, the velocity‐depth ambiguity may continue to plague exploration seismologists for some time to come.

scholarly journals Geochemical characteristics and origins of biodegraded oils in the Bongor Basin (Chad) and their implications for petroleum exploration

2022 ◽  
pp. 014459872110695
Author(s):  
Dingsheng Cheng ◽  
Lirong Dou ◽  
Qingyao Chen ◽  
Wenqiang Wang
Keyword(s):  
Crude Oil ◽  
Oil Quality ◽  
Geochemical Characteristics ◽  
Oil Reservoirs ◽  
Petroleum Exploration ◽  
Tectonic Activity ◽  
Crude Oils ◽  
Rift System ◽  
Burial Depth ◽  
Geological Conditions

The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.

The role of deep seismic reflection data in understanding the architecture and petroleum potential of Australia's onshore sedimentary basins

2010 ◽  
Vol 50 (2) ◽  
pp. 726 ◽  
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Leonie Jones ◽  
Josef Holzschuh
Keyword(s):  
Seismic Reflection ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Deep Seismic Reflection ◽  
Reflection Data ◽  
Stratigraphic Sequences

The onshore energy security program, funded by the Australian Government and conducted by Geoscience Australia, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focussing on overall basin geometry and internal sequence stratigraphy, will be presented here, with the aim of assessing the petroleum potential of the basins. At the southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA–M6) crosses the Burke River structural zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bounded in the west by a rift border fault. Given the overall architecture, this basin will be of interest for petroleum exploration. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga Basin and was unknown prior to being detected on two seismic lines (06GA–M4 and 06GA–M5) acquired in 2006. Following this, seismic line 07GA–IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and a post-depositional thrust margin indicate that the original succession was much thicker than preserved today and may have potential for a petroleum system. The Yathong Trough, in the southeast part of the Darling Basin in NSW, has been imaged in seismic line 08GA–RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. Previous studies indicate that the upper part of this basin consists of Devonian sedimentary rocks, with potential source rocks at depth. In eastern South Australia, seismic line 08GA–A1 crossed the Cambrian Arrowie Basin, which is underlain by a Neoproterozoic succession of the Adelaide Rift System. Stratigraphic sequences have been mapped and can be tied to recent drilling for mineral and geothermal exploration. Shallow drill holes from past petroleum exploration have aided the assessment of the petroleum potential of the Cambrian Hawker Group, which contains bitumen in the core, indicating the presence of source rocks in the basin system.

Structural and stratigraphic architecture of Australia's frontier onshore sedimentary basins: the Western Officer and Southern Carnarvon basins, Western Australia

2012 ◽  
Vol 52 (2) ◽  
pp. 670
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Arthur Mory ◽  
Roger Hocking ◽  
Sarah Marshall ◽  
...  
Keyword(s):  
Western Australia ◽  
Sedimentary Basins ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Sequence Stratigraphic ◽  
Reflection Data ◽  
Half Graben ◽  
Seismic Lines ◽  
Carnarvon Basin

During the past five years, the Onshore Energy Security Program, funded by the Australian Government and conducted by Geoscience Australia, in conjunction with state and territory geological surveys, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. This extended abstract presents data from two seismic lines collected in Western Australia in 2011. The 487 km long Yilgarn-Officer-Musgrave (YOM) seismic line crossed the western Officer Basin in Western Australia, and the 259 km long, Southern Carnarvon Seismic line crossed the Byro Sub-basin of the Southern Carnarvon Basin. The YOM survey imaged the Neoproterozoic to Devonian western Officer Basin, one of Australia's underexplored sedimentary basins with hydrocarbon potential. The survey data will also provide geoscientific knowledge on the architecture of Australia's crust and the relationship between the eastern Yilgarn Craton and the Musgrave Province. The Southern Carnarvon survey imaged the onshore section of the Ordovician to Permian Carnarvon Basin, which offshore is one of Australia's premier petroleum-producing provinces. The Byro Sub-basin is an underexplored depocentre with the potential for both hydrocarbon and geothermal energy. Where the seismic traverse crossed the Byro Sub-basin it imaged two relatively thick half graben, on west dipping bounding faults. Structural and sequence stratigraphic interpretations of the two seismic lines are presented in this extended abstract.

Structural and stratigraphic architecture of Australia's frontier onshore sedimentary basins: the Arckaringa, Officer, Amadeus, and Georgina basins

2011 ◽  
Vol 51 (2) ◽  
pp. 703
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Wolfgang Preiss ◽  
Sandra Menpes ◽  
Josef Holzschuh ◽  
...  
Keyword(s):  
Sedimentary Basins ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Northern Margin ◽  
The North ◽  
Reflection Data ◽  
Southern Margin ◽  
Seismic Lines

The Onshore Energy Security Program—funded by the Australian Government and conducted by Geoscience Australia—has acquired deep seismic reflection data in conjunction with state and territory geological surveys, across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Here, we present data from two seismic lines collected in SA and NT. Seismic line 08GA-OM1 crossed the Arckaringa and Officer basins in SA and the southern-most Amadeus Basin in NT. Seismic line 09GA-GA1 crossed the northeastern part of the Amadeus Basin and the complete width of the southern Georgina Basin in NT. Structural and sequence stratigraphic interpretations of the seismic lines will be presented here, followed by an assessment of the petroleum potential of the basins. Seismic line 08GA-OM1 also crosses the Neoproterozoic to Devonian eastern Officer Basin. The basin is structurally complex in this area, being dominated by south-directed thrust faults and fault-related folds—providing potential for underthrust petroleum plays. The northern margin of the basin is overthrust to the south by the Mesoproterozoic Musgrave Province. To the north, the Moorilyanna Trough of the Officer Basin is a major depocentre of up to 7,000 m deep. Both seismic lines cross parts of the eastern Amadeus Basin. Seismic line 08GA-OM1 shows that the southern margin of the basin is overthrust to the north by the Musgrave Province with the main movement during the Petermann Orogeny. In the northeast, seismic line 09GA-GA1 crosses two parts of the basin separated by the Paleoproteroozic to Mesoproterozoic Casey Inlier (part of the Arunta Region). The northern margin of the basin is imaged seismically as a southward-verging, thinned-skinned thrust belt, showing considerable structural thickening of the stratigraphic succession. Seismic line 09GA-GA1 was positioned to cross that part of the southern Georgina Basin that was considered previously to be in the oil window. Here, the basin has a complex southern margin, with Neoproterozoic stratigraphy being thrust interleaved with basement rocks of the Arunta Region. The main part of the basin, containing a Neoproterozoic to Devonian succession, is asymmetric, thinning to the north where it overlies the Paleoproterozoic Davenport Province. The well, Phillip–2, drilled adjacent to the seismic line, intersected basement at a depth of 1,489 m, and has been used to map the stratigraphic sequences across the basin.

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