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NARROW
GeoRef Subject
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all geography including DSDP/ODP Sites and Legs
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Africa
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Central Africa
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Angola
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Cabinda Angola (1)
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Congo Basin (1)
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Wilcox Group (2)
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Mesozoic
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Paleozoic
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Primary terms
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Africa
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Far East
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Atlantic Ocean
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Challenger Knoll (2)
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De Soto Canyon (2)
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Garden Banks (1)
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Sigsbee Escarpment (2)
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North Sea (22)
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carbon
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upper Quaternary (1)
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Tertiary
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upper Miocene (3)
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upper Neogene (1)
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Paleogene
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middle Eocene
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Carrizo Sand (2)
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Claiborne Group (1)
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Cook Mountain Formation (1)
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Queen City Formation (1)
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-
-
Oligocene
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Machine learning applications to seismic structural interpretation: Philosophy, progress, pitfalls, and potential
Structure-oriented filtering in unsupervised multiattribute seismic facies analysis
Fluid discrimination using detrended seismic impedance
Self-supervised delineation of geologic structures using orthogonal latent space projection
Assessing model uncertainty for the scaling function inversion of potential fields
Seismogeologic, Structural, and Tectonic Characteristics of the Continental Margin of the Siberian Platform (Khatanga–Lena Interfluve)
Understanding the information content in gravity gradiometry data through constrained inversions for salt bodies
3D seismic interpretation with deep learning: A brief introduction
Elastic full-waveform inversion of steeply dipping structures with prismatic waves
Velocity model building for single-offset VSP data via deformable-layer tomography: A Texas salt dome example
Salt extrusion kinematics: insights from existing data, morphology and InSAR modelling of the active emergent Anguru diapir in the Zagros fold and thrust belt, Iran
Progressive transfer learning for low-frequency data prediction in full-waveform inversion
Interactions between deep-water gravity flows and active salt tectonics
Interpolation method based on pattern-feature correlation
Deep-learning seismic full-waveform inversion for realistic structural models
Abstract The Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO 2 storage. In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 10 6 t of dense phase CO 2 each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.
Abstract The Mungo Field is a mature producing asset located in the UK Central North Sea. Discovered in 1989 and brought on production in 1998, it is the largest field within the Eastern Trough Area Project (ETAP). Production occurs via a normally unattended installation and is tied back to the ETAP Central Processing Facility. It is a pierced, four-way dip closure against a salt diapir. Light oil is present within steeply dipping Late Paleocene sandstone and Early Paleocene–Late Cretaceous chalk intervals. The vertical relief of the salt stock is around 1500 m TVDSS and top of the salt canopy lies at about 1350 m TVDSS. The Paleocene sandstones (Forties Sandstone Member of the Sele Formation, Lista Formation and Maureen Formation) make up the primary reservoir and have been extensively developed in three phases since 1998 under water injection and natural depletion. The sandstones were deposited as deep-water turbidite complexes (submarine fans with local channels) on and around the flanks of the rising salt diapir. More recently, successful stimulation of the Chalk Group, coupled with re-evaluation of core and well-log data, has indicated that economic production rates could also be achieved from the underlying fractured chalk reservoir.
Abstract The Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer. The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy. The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.
The Morag Field, Block 16/29a, UK North Sea
Abstract The Morag Field is a small oilfield underlying the Maureen Field in UK Block 16/29a. Black oil is trapped within Upper Permian, Morag Member, vuggy and fractured dolomite rafts between 9300 and 10 600 ft true vertical depth subsea. The dolomite reservoir occurs at the top of a Zechstein salt dome. Morag was discovered in 1979 by well 16/29a-A1, the first platform well drilled for the overlying Maureen Field with its Paleocene sandstone reservoir. Morag was produced via a single well (16/29a-A1) between 1991 and 1994. Three more platform wells were drilled into the Permian interval prior to Maureen Field start up but only one penetrated oil-bearing dolomite (16/29a-A2). An additional well (16/29a–A23Z) was drilled into the Morag Field in 1993. The well encountered Morag Member at virgin pressure and tested oil at high flow rate but then the well failed due to mechanical problems. Oil in place was calculated to be about 24 MMbbl in four independent fault blocks. Ultimately 16/29a-A1 delivered 2.6 MMbbl from a fault block calculated to have held 6.7 MMbbl stock tank oil initially in place.