Accumulation Models of the Oil Pools of Block XXI of Tamsag Basin in Mongolia

2014 ◽  
Vol 962-965 ◽  
pp. 522-525
Author(s):  
Liang Zhao
Keyword(s):  
Water Distribution ◽  
Physical Property ◽  
Reverse Fault ◽  
The South ◽  
Hydrocarbon Migration ◽  
The North ◽  
Oil Water ◽  
Migration Pathways

This document explains different tectonic styles and sedimentary fillings give rise to the different accumulation combinations and accumulation models between the south and the north frogs of East Subsag of South Buir Sag. The Tsagaantsav Formation oil pools, subject to the rupture of the fault-period tectonic layers, has developed multiple types of traps including reverse fault blocks, fault noses and drag anticlines. They are close to the oil-generating sags, in the indicator areas of hydrocarbon migration where hydrocarbon pools, particularly tectonic-controlled pools, are easily formed. The lithology and physical property play an important controlling role over the formation of oil pools with complicated oil-water distribution relationship. The constant and the late active ruptures as longitudinal hydrocarbon migration pathways, together with the sedimentary sands of multiple genesis types, have given shape to the multi-formation lithologic, lithologic-tectonic or tectonic accumulation combinations.

Research on Types of Oil Reservoirs and Character of Oil-Water Distribution in Heidimiao Layer

2013 ◽  
Vol 772 ◽  
pp. 789-794
Author(s):  
Gui You Lv
Keyword(s):  
Water Distribution ◽  
Oil And Gas ◽  
Dominant Role ◽  
Three Dimensional ◽  
Physical Property ◽  
Research Area ◽  
Oil Reservoir ◽  
Well Testing ◽  
Testing Data ◽  
Oil Water

This paper takes Yingtai area which is located in the south of Qijia-Gulong sag and part of central sag area in the north of the Songliao Basin as the research area. Then combining all information of core, logging, three-dimensional seism and well testing data, it studies the reservoir type and oil-water distribution characteristics of Heidimiao by analyzing the comparison charts of sandstone, profile map of reservoir, T07 structure diagram, well testing data, stratum thickness, sandstone thickness, ratio of sandstone thickness to stratum thickness, porosity values, permeability contour maps. The reservoir lithology of Heidimiao oil layer is siltstone-oriented with poor physical property. The main controlling factor of oil-water distribution is the lithology, followed by the structure. Heidimiao oil layer mainly includes three types, lithological oil reservoir, lithological - structural oil reservoir and structural oil reservoir, among which lithological reservoir plays a dominant role. Its oil-water distribution is characterized by the pattern of upper-water and bottom-oil; when the fault acts as the pathway for the longitudinal migration of oil and gas, the pattern changes to the upper-oil and bottom-water. This research could provide reliable geological basis for the research of old well re-examination, favorable area evaluation and horizontal well drilling design.

Geophysical modeling of Devonian plutons in the southern Gulf of St. Lawrence: implications for Appalachian terrane boundaries in Maritime Canada

2007 ◽  
Vol 44 (11) ◽  
pp. 1551-1565 ◽  
Author(s):  
Lori A Cook ◽  
Sonya A Dehler ◽  
Sandra M Barr
Keyword(s):  
Magnetic Anomaly ◽  
Prince Edward Island ◽  
Sedimentary Cover ◽  
Complex Structure ◽  
Physical Property ◽  
Gravity Anomalies ◽  
The South ◽  
Cape Breton Island ◽  
The North ◽  
Cape Breton

A prominent positive magnetic anomaly spans the 100 km distance between Prince Edward Island and Cape Breton Island in the southern Gulf of St. Lawrence. The anomaly occurs in an area of complex structure where Appalachian terrane boundaries are poorly resolved because of thick late Paleozoic sedimentary cover. Analysis of the magnetic anomaly led to the interpretation that it is produced by four separate, approximately circular, source bodies aligned along the northwesterly trend of the anomaly. Seismic data, physical property measurements, and magnetic and gravity anomalies were used to further investigate the anomaly sources through forward modeling techniques. The four source bodies have densities and magnetic susceptibilities compatible with dioritic to granitic compositions. Modeling also suggests that basement to the north of the plutons has higher density and susceptibility than basement to the south, and hence the source bodies are interpreted as plutons emplaced along the boundary between Ganderian composite terranes to the north and the Ganderian Brookville – Bras d’Or terrane to the south. This interpretation suggests that the Ganderia–Avalonia boundary is located farther south, and shows the need for re-evaluation of the location and role of the Canso fault in offsetting terranes between Cape Breton Island and southern New Brunswick.

THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION

1985 ◽  
Vol 25 (1) ◽  
pp. 235 ◽  
Author(s):  
A.F. Williams ◽  
D.J. Poynton
Keyword(s):  
Middle Miocene ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Source Rocks ◽  
The South ◽  
Hydrocarbon Migration ◽  
Tectonic Event ◽  
The North ◽  
Migration History

The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.

scholarly journals Gravity anomaly to identify Walanae fault using second vertical derivative method

2018 ◽  
Vol 2 (1) ◽  
pp. 34
Author(s):  
Marsellei Justia ◽  
Muhammad Fikri H Hiola ◽  
Nur Baiti Febryana S
Keyword(s):  
Gravity Data ◽  
Moving Average ◽  
Normal Fault ◽  
Reverse Fault ◽  
The South ◽  
Vertical Derivative ◽  
The North ◽  
Free Air ◽  
Free Air Anomaly ◽  
Fault Mechanism

<p class="Abstract">Research has been conducted to identify the Walanae Fault, coordinates 4–6 S and 118-120 E using anomalous gravity data. This research uses data measurement of Topography and the Free Air Anomaly from the TOPEX/Poseidon satellite. Then the authors processed to obtain the bouguer anomalies and made modeling by using the Surfer 10. The authors used the Second Vertical Derivative (SVD) with filter Elkins of Moving Average then analyze the graph of the SVD. The results shows the value of the residual anomaly in the north of fault is 25.21 mGal, in the middle occur range 17.67 mGal to 24.98 mGal and 30,376 mGal in the south of fault. The authors indicates the existence of a difference between the gravity between the Walanae Fault with surrounding geologic. From these results also show that Walanae Fault has a reverse fault mechanism in the northern part and the normal fault mechanism in the middle to the south, the authors conclude that the Walanae Fault is divided into two segments, that is the northern and the southern segment.</p>

Regional seal characterisation for CO2 storage, Northern North Sea

2020 ◽  
Author(s):  
Christopher Lloyd ◽  
Mads Huuse ◽  
Bonita Barrett
Keyword(s):  
North Sea ◽  
Co2 Storage ◽  
The South ◽  
Feature Maps ◽  
Seismic Attribute ◽  
North East ◽  
The North ◽  
Attribute Analysis ◽  
Northern North Sea ◽  
Migration Pathways

&lt;p&gt;Estimations of CO&lt;sub&gt;2&lt;/sub&gt; storage capacities for saline aquifers, particularly the Utsira Formation (northern North Sea) have previously been calculated using a variety of numerical approaches. These are mainly based off reservoir depth maps and averaged petrophysical properties. In these first-pass estimations, a thick shale succession in the overburden is assumed to form the top seal. This is unlikely to be representative of the true, regional lithological heterogeneity and 3D variability of stratigraphic architecture, which may promote CO&lt;sub&gt;2&lt;/sub&gt; migration out of the reservoir during injection.&lt;/p&gt;&lt;p&gt;This study utilises a recently acquired regional high-resolution 3D broadband seismic dataset (37,500 km&lt;sup&gt;2&lt;/sup&gt;) and &gt;200 wells in the North Viking Graben, with the aim to fully characterise the overburden of the potential CO&lt;sub&gt;2&lt;/sub&gt; reservoir (Northern Utsira Formation). The objectives are to analyse: i) the presence and spatial extent of sandstone bodies in the overburden and their connectivity with the reservoir; ii) the presence of sand-filled slope channels on the clinoform foresets that may act as migration pathways; iii) evidence of previous fluid migration through the overburden. Manual seismic interpretation and well correlation is augmented by automated horizon propagation (Palaeoscan) to map individual clinoforms across the region. This is integrated with seismic attribute analysis, frequency decomposition and automated well lithology extraction to understand regional sand distribution and feature analysis (e.g. identification of channels and their fill, and possible shallow gas).&lt;/p&gt;&lt;p&gt;Large fan-shaped sandstone bodies (10s km-scale) are identified in the lower foresets and bottomsets of the clinothems. In the west, these are in connection with the Utsira Fm., or separated from it by a thin (&lt;10 m) shale layer. These sands can be both beneficial to the storage capacity by producing additional gross reservoir volume (if sealed and below the critical depth for CO&lt;sub&gt;2&lt;/sub&gt;), or detrimental to it if they provide a path to bypass the Utsira Fm. top seal. In the south east, sand-filled slope channels and lobes (km-scale) are recorded in the prograding clinothems but are not observed to be in connection with the Utsira Fm. (located &gt;100 m above top Utsira Fm.). No sand-filled channels were identified in the north east from seismic attribute analysis, however the well lithology extraction for this region contained ~3% sand, thus there is a possibility of sub-seismic resolution features. In the south, foresets directly downlap the Utsira Fm. This geometry juxtaposes several individual clinothems against the reservoir, increasing the likelihood of migration if there is sand presence. This contrasts with the scenario in the north, where the bottomset of a single clinothem disconnects the reservoir from younger clinothems and restricts potential migration.&lt;/p&gt;&lt;p&gt;The outcome of this study is an integration of each of the regional feature maps to generate: i) a seal thickness map between the Utsira Fm. and the first overlying sand body; ii) the first leakage risk map of the Utsira Fm. that captures geological geometry and lithology distribution. These can be incorporated into any future storage estimations and identification of potential injection sites.&lt;/p&gt;

The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 183-190 ◽  
Author(s):  
Keith J. Fletcher
Keyword(s):  
Upper Jurassic ◽  
Western Boundary ◽  
The South ◽  
Submarine Fan ◽  
Water Contact ◽  
The North ◽  
Oil Water ◽  
Clay Formation ◽  
A Minor ◽  
North And South

abstractThe Central Brae Oilfield is the smallest of three Upper Jurassic fields being developed in UK, Block 16/07a. The field was discovered in 1976 and commended production in September 1989 through a sub-sea template tied back to the Brae 'A' platform in the South Brae Oilfield. The field Stooip is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs.The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sanstone with a minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.

scholarly journals Seismic Structural Analysis of the Alam-El Bueib Formation, Qasr Oil Field, North Western desert, Egypt

2019 ◽  
pp. 20-25
Author(s):  
Farouk I Metwalli ◽  
Mahmoud S Yousif ◽  
Nancy H El Dally ◽  
Ahmed S Abu El Ata
Keyword(s):  
Lower Cretaceous ◽  
Oil Field ◽  
Western Desert ◽  
Normal Faults ◽  
Reverse Fault ◽  
The South ◽  
Late Mesozoic ◽  
Clastic Rocks ◽  
The North ◽  
North Western

The Qasr oil and gas Field is located in the north western desert of Egypt. It belongs to the southeastern part of the Lower Jurassic-Cretaceous Shushan Basin. The Lower Cretaceous Alam-El Bueib formation composed of clastic rocks with noticeable carbonate proportions, and forms multiple oil-bearing sandstone reservoirs in Qasr field. The study aims to define and analyze the Surface and subsurface structural features which are a key issue in assessing reservoir quality. Through this integrated approach, one may be able to identify lithologies and fluids in this region and provide possibly new hydrocarbon fairways for exploration. For this purpose, seismic and well data were interpreted and mapped in order to visualize the subsurface structure of the Cretaceous section. Results show the effect of NE-SW, NW-SE, and E-W trending normal faulting on the Lower Cretaceous Alam-El Bueib formation and is extended to the Upper Cretaceous Abu Roash Formation. The effect of folding is minimal but can be detected. These normal faults are related to the extensional tectonics which affected the north western desert of Egypt during the Mesozoic. One reverse fault is detected in the eastern part and is related mostly to the inversion tectonics in the Late Mesozoic. The depth structure contour maps of the Alam-El Bueib horizons (AEB-1, AEB-3A, and AEB-3D) show several major normal faults trending NE-SW and minor normal faults trending NW-SE. One larger branching normal fault trending E-W and lies to the south of the study area. These step-normal faults divide the area into a number of tilted structural blocks which are shallower in the south and deepen to the north. The area of study was most probably affected by E-W trending normal faults during the opening of the Atlantic Ocean in the Jurassic. Later right-lateral compression resulted from the movement of Laurasia against North Africa, changed their trend into NE-SW faults with minor NW-SE trending folds. These compressive stresses are also responsible for the reverse faulting resulted by inversion in the Late Mesozoic.

Beier Depression Petroleum System Study in Hailaer

2014 ◽  
Vol 668-669 ◽  
pp. 1546-1549
Author(s):  
Jing Yi Wang ◽  
Shang Ming Shi ◽  
Xian Li Du
Keyword(s):  
Water Distribution ◽  
Oil And Gas ◽  
Field Work ◽  
Petroleum System ◽  
Reverse Fault ◽  
Guide Field ◽  
Distribution Rule ◽  
Surface Active ◽  
Oil Water ◽  
Buried Hill

Through the study of Beier depression accumulation critical moment, divided into three sets of petroleum system in beier depression: passive faulted depression primary petroleum system, active faulted depression primary petroleum system and fault depression transform secondary petroleum system. Through the typical reservoir oil-water distribution rule and reservoir dissect result can get to know oil and gas of Beier depression concentration distribute in passive faulted depression sequence petroleum system, mainly develop reverse fault block reservoir as well as buried hill reservoir blocked by fault and uncomformable surface, active faulted depression sequence petroleum system mainly develop structure and fault-lithologic composite reservoir; Secondary petroleum system mainly develops fault lithologic reservoir; Secondary petroleum system and primary petroleum system ‘complementary’ distribution of oil and gas. Through the petroleum system classification, to find the distribution regularity of oil and gas, and guide field work.

Long-term Cyclic Variations of Prominences, Green and Red Coronae over Solar Cycles

2000 ◽  
Vol 179 ◽  
pp. 201-204
Author(s):  
Vojtech Rušin ◽  
Milan Minarovjech ◽  
Milan Rybanský
Keyword(s):  
Emission Lines ◽  
High Latitudes ◽  
Green Line ◽  
Solar Cycles ◽  
The South ◽  
Coronal Emission ◽  
Local Maxima ◽  
The North ◽  
Cyclic Variations

AbstractLong-term cyclic variations in the distribution of prominences and intensities of green (530.3 nm) and red (637.4 nm) coronal emission lines over solar cycles 18–23 are presented. Polar prominence branches will reach the poles at different epochs in cycle 23: the north branch at the beginning in 2002 and the south branch a year later (2003), respectively. The local maxima of intensities in the green line show both poleward- and equatorward-migrating branches. The poleward branches will reach the poles around cycle maxima like prominences, while the equatorward branches show a duration of 18 years and will end in cycle minima (2007). The red corona shows mostly equatorward branches. The possibility that these branches begin to develop at high latitudes in the preceding cycles cannot be excluded.

Sign in / Sign up

Export Citation Format

Share Document