AAPG members are being asked to help create an educational research facility to study a part of England's Jurassic Coast.
The fact that velocity models based on seismic reflection surveys commonly do not consider the near-surface geology necessitates filling the gap between the top of a velocity model and the surface of the Earth. In this study, we present a new workflow to build a shallow geologic model based exclusively on borehole data and corroborated by laboratory measurements. The study area is in Chemery (France), located at the southwestern border of the Paris Basin, where a large amount of borehole data is publicly available. The workflow starts with identifying lithologic interfaces in the boreholes and interpolating them between the boreholes. The three-dimensional (3-D) geometry of the lithologies then allows interpretation of the position, orientation, and offset of fault planes. Given the importance of the fault interpretation in the modeling process, a combination of different approaches is used to obtain the most reasonable structural framework. After creating a 3-D grid, the resulting 3-D structural model is populated with upscaled velocity logs from the boreholes, yielding the final near-surface P-wave velocity model. To better constrain the velocity model, we conducted laboratory measurements of P- and S-wave velocities in dry and water-saturated conditions on all lithologies in the model. The laboratory data were used to populate the 3-D near-surface model with VP/VS ratio values. The presented workflow accounts for one-dimensional borehole data and is much more iterative and time-consuming than workflows based on two-dimensional seismic sections. Nevertheless, the workflow results in a robust 3-D near-surface model allowing for structural interpretations and revealing the 3-D seismic velocity field.
Anomalously high porosities and permeabilities are commonly found in the fluvial channel sandstone facies of the Triassic Skagerrak Formation in the central North Sea at burial depths greater than 3200 m (10,499 ft), from which hydrocarbons are currently being produced. The aim of our study was to improve understanding of sandstone diagenesis in the Skagerrak Formation to help predict whether the facies with high porosity may be found at even greater depths. The Skagerrak sandstones comprise fine to medium-grained arkosic to lithic-arkosic arenites. We have used scanning electron microscopy, petrographic analysis, pressure history modeling, and core analysis to assess the timing of growth and origin of mineral cements, with generation, and the impact of high fluid pressure on reservoir quality. Our interpretation is that the anomalously high porosities in the Skagerrak sandstones were maintained by a history of overpressure generation and maintenance from the Late Triassic onward, in combination with early microquartz cementation and subsequent precipitation of robust chlorite grain coats. Increasing salinity of pore fluids during burial diagenesis led to pore-filling halite cements in sustained phreatic conditions. The halite pore-filling cements removed most of the remaining porosity and limited the precipitation of other diagenetic phases. Fluid flow associated with the migration of hydrocarbons during the Neogene is inferred to have dissolved the halite locally. Dissolution of halite cements in the channel sands has given rise to megapores and porosities of as much as 35% at current production depths.
The Heidrun field, located on the Halten Terrace of the mid-Norwegian continental shelf, was one of the first giant oil fields found in the Norwegian Sea. Traditional reservoir intervals in the Heidrun field lie within the Jurassic synrift sequence. Most Norwegian continental shelf fields have been producing from these Jurassic reservoirs for the past 30 yr. Production has since declined in these mature fields, but recently, exploration for new reservoirs has resurged in this region. The Jurassic rifted fault blocks form a narrow continental shelf in Norway, thereby greatly reducing the areal extent for exploration and development within existing fields. As the rift axis is approached farther offshore, these Jurassic reservoirs become very deep, too risky to drill, and uneconomical. This risk has prompted exploration in more recent years of the shallower Cretaceous, postrift stratigraphic succession. Cretaceous turbidites have been found in the Norwegian and North Seas, and the discovery of the Agat field in the Norwegian North Sea confirms the existence of a working petroleum system capable of charging Cretaceous reservoirs. These Cretaceous reservoirs were deposited as slope- and basin-floor fans within a series of underfilled rifted deeps along the Norwegian continental shelf and are thought to be sourced from the localized erosion of Jurassic rifted highs. We use three-dimensional seismic and well data to document the geomorphology of a deep-water, Lower Cretaceous wedge (Cromer Knoll Group) within the hanging wall of a rift-related half graben formed on the Halten Terrace offshore mid-Norway. Seismic attribute extractions taken within this Lower Cretaceous wedge reveal the presence of several lobate to elongated bodies that seem to cascade over fault-bounded terraces associated with rifted structures. These high-amplitude, elongated bodies are interpreted as deep-water sedimentary conduits that are time equivalent to the Cretaceous basin-floor fans in more distal parts of the basin to the west. These half-graben fills have the potential to contain high-quality Cretaceous sandstones that might represent a potential new reservoir interval within the Heidrun field.
North Sea rejuvenation, onshore unconventional exploration and Eastern Mediterranean exploration have resulted in a growing Young Professional (YP) demographic in Europe.
Geoscience students from the University of Utah took the top prize in this year’s AAPG/AAPG Foundation Imperial Barrel Award competition, beating out 10 other teams from geoscience departments from around the world.
We describe the structure, microstructure, and petrophysical properties of fault rocks from two normal fault zones formed in low-porosity turbiditic arkosic sandstones, in deep diagenesis conditions similar to those of deeply buried reservoirs. These fault rocks are characterized by a foliated fabric and quartz-calcite sealed veins, which formation resulted from the combination of the (1) pressure solution of quartz, (2) intense fracturing sealed by quartz and calcite cements, and (3) neoformation of synkinematic white micas derived from the alteration of feldspars and chlorite. Fluid inclusion microthermometry in quartz and calcite cements demonstrates fault activity at temperatures of 195C to 268C. Permeability measurements on plugs oriented parallel with the principal axes of the finite strain ellipsoid show that the Y axis (parallel with the foliation and veins) is the direction of highest permeability in the foliated sandstone (10–2 md for Y against 10–3 md for X, Z, and the protolith, measured at a confining pressure of 20 bars). Microstructural observations document the localization of the preferential fluid path between the phyllosilicate particles forming the foliation. Hence, the direction of highest permeability in these fault rocks would be parallel with the fault and subhorizontal, that is, perpendicular to the slickenlines representing the local slip direction on the fault surface. We suggest that a similar relationship between kinematic markers and fault rock permeability anisotropy may be found in other fault zone types (reverse or strike-slip) affecting feldspar-rich lithologies in deep diagenesis conditions.
Operation Overlord: An unassuming, extraordinary quiet man keeps a secret about his heroic past in silence throughout his entire life.
A three-dimensional seismic data set and published data from exploration wells were used to reconstruct the tectonostratigraphic evolution of the Mandal High area, southern North Sea, Norway. The Mandal High is an elongated southeast-northwest–trending horst. Three fault families in the Lower Permian sequence, inherited from the basement structural grain of Caledonian origin, are interpreted: (1) a north-northwest–south-southeast–striking fault family, (2) a northeast-southwest–striking fault family, and (3) a near east-west–striking fault family. In addition, an east-southeast–west-northwest–striking fault family (4) that formed during Late Jurassic rifting and was reverse reactivated in the Late Cretaceous is interpreted. We suggest that inversion occurred because of small dextral motion along fault family 1. A final fault family (5) displays various strike orientations and is associated with salt movements.
Seven chronostratigraphic sequences defined by well data and recognized on three-dimensional seismic data are interpreted and mapped: Early Permian rifting in a continental environment; Late Permian deposition of the Zechstein salt and flooding; Triassic continental rifting; uplift and erosion in the Middle Jurassic with deposition of shallow-marine and deltaic sediments; rifting and transgression in a deep-marine environment during the Late Jurassic; a post-rift phase in a marine environment during the Early Cretaceous; and flooding and deposition of the Chalk Group in the Late Cretaceous. An eighth sequence was interpreted—Paleogene–Neogene—but has not been studied in detail. This sequence is dominated by progradation from the east and basin subsidence. Well and seismic data over the Mandal High reveal that large parts of the high were subaerially exposed from Late Permian to Late Jurassic or Early Cretaceous, providing a local source of sediments for adjacent basins.
Similar to the Utsira High, where several large hydrocarbon discoveries have been recently seen, the Mandal High might consist of a set of petroleum plays, including fractured crystalline basement and shallow-marine systems along the flanks of the high, thereby opening up future exploration opportunities.
AAPG Europe’s annual APPEX Global conference returned to the Business Design Centre in London in March, attracting more than 700 attendees representing independent oil and gas producers, major corporations and national oil companies.
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