Explorer Article
By Susan Eaton
Energized by the recent Statoil ASA-operated Bay du Nord light oil discovery in Newfoundland’s offshore Flemish Pass Basin, earth scientists are gearing up to host the fourth Atlantic Realm Conjugate Margins Conference in St. John’s, Newfoundland, Aug. 20-22.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2014
Explorer Article
By David Brown
Oklahoma! As-yet unlocked SCOOP and STACK plays have plen’y of room for maturation and development.
American Association of Petroleum Geologists (AAPG)
Added on 01 March, 2014
Bulletin Article
Diagenesis significantly impacts mudstone lithofacies. Processes operating to control diagenetic pathways in mudstones are poorly known compared to analogous processes occurring in other sedimentary rocks. Selected organic-carbon-rich mudstones, from the Kimmeridge Clay and Monterey Formations, have been investigated to determine how varying starting compositions influence diagenesis.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated.
The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures.
Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density.
These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
The presence of hydrocarbon-bearing sandstones within the Eocene of the Forties area was first documented in 1985, when a Forties field (Paleocene) development well discovered the Brimmond field. Further hydrocarbons in the Eocene were discovered in the adjacent Maule field in 2009. Reservoir geometry derived from three-dimensional seismic data has provided evidence for both a depositional and a sand injectite origin for the Eocene sandstones. The Brimmond field is located in a deep-water channel complex that extends to the southeast, whereas the Maule field sandstones have the geometry of an injection sheet on the updip margin of the Brimmond channel system with a cone-shape feature emanating from the top of the Forties Sandstone Member (Paleocene). The geometry of the Eocene sandstones in the Maule field indicates that they are intrusive and originated by the fluidization and injection of sand during burial. From seismic and borehole data, it is unclear whether the sand that was injected to form the Maule reservoir was derived from depositional Eocene sandstones or from the underlying Forties Sandstone Member. These two alternatives are tested by comparing the heavy mineral and garnet geochemical characteristics of the injectite sandstones in the Maule field with the depositional sandstones of the Brimmond field and the Forties sandstones of the Forties field.
The study revealed significant differences between the sandstones in the Forties field and those of the Maule and Brimmond fields), both in terms of heavy mineral and garnet geochemical data. The Brimmond-Maule and Forties sandstones therefore have different provenances and are genetically unrelated, indicating that the sandstones in the Maule field did not originate by the fluidization of Forties sandstones. By contrast, the provenance characteristics of the depositional Brimmond sandstones are closely comparable with sandstone intrusions in the Maule field. We conclude that the injectites in the Maule field formed by the fluidization of depositional Brimmond sandstones but do not exclude the important function of water from the huge underlying Forties Sandstone Member aquifer as the agent for developing the fluid supply and elevating pore pressure to fluidize and inject the Eocene sand. The study has demonstrated that heavy mineral provenance studies are an effective method of tracing the origin of injected sandstones, which are increasingly being recognized as an important hydrocarbon play.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
Interpretation of seismic data from the Sorvestsnaget Basin, southwest Barents Sea, demonstrates gradual middle Eocene basin infilling (from the north) generated by southward-prograding shelf-margin clinoforms. The basin experienced continued accommodation development during the middle Eocene because of differential subsidence caused by the onset of early Eocene sea-floor spreading in the Norwegian-Greenland Sea, faulting, salt movement, and different tectonic activity between the Sorvestsnaget Basin and Veslemoy high. During this time, the margin shows transformation from an initially high-relief margin to a progradation in the final stage. The early stage of progradation is characterized by the establishment of generally oblique clinoform shifts creating a flat shelf-edge trajectory that implies a gentle falling or stable relative sea level and low accommodation-to-sediment supply ratio (1) in the topsets. During the early stage of basin development, the high-relief margin, narrow shelf, stable or falling relative sea level, seismicity, and presumably high sedimentation rate caused accumulation of thick and areally extensive deep-water fans. Seismic-scale sandstone injections deform the fans.
A fully prograding margin developed when the shelf-to-basin profile lowered, apparently because of increased subsidence of the northern part. This stage of the basin development is generally characterized by the presence of sigmoid clinoform shifts creating an ascending shelf-edge trajectory that is implying steady or rising relative sea level with an accommodation-to-sediment supply ratio of greater than 1, implying sand accumulation on the shelf. This study suggests that some volume of sand was transported into the deep water during relative sea level rise considering the narrow shelf and inferred high rates of sediment supply.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
Organic-carbon–rich shales of the lower Marcellus Formation were deposited at the toe and basinward of a prograding clinothem associated with a Mahantango Formation delta complex centered near Harrisburg, Pennsylvania. Distribution of these organic-carbon–rich shales was influenced by shifts in the delta complex driven by changes in rates of accommodation creation and by a topographically high carbonate bank that formed along the Findlay-Algonquin arch during deposition of the Onondaga Formation. Specifically, we interpret the Union Springs member (Shamokin Member of the Marcellus Formation) and the Onondaga Formation as comprising a single third-order depositional sequence. The Onondaga Formation was deposited in the lowstand to transgressive systems tract, and the Union Springs member was deposited in the transgressive, highstand, and falling-stage systems tract. The regional extent of parasequences, systems tracts, and the interpreted depositional sequence suggest that base-level fluctuations were primarily caused by allogenic forcing—eustasy, climate, or regional thermal uplift or subsidence—instead of basement fault reactivation as argued by previous workers. Paleowater depths in the region of Marcellus Formation black mudrock accumulation were at least 330 ft (100 m) as estimated by differences in strata thickness between the northwestern carbonate bank and basinal facies to the southeast. Geochemical analysis indicates anoxic to euxinic bottom-water conditions. These conditions were supported by a deep, stratified basin with a lack of circulation.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
We use three-dimensional seismic reflection data and new map-based structural restoration methods to define the displacement history and characteristics of a series of tear faults in the deep-water Niger Delta. Deformation in the deep-water Niger Delta is focused mostly within two fold-and-thrust belts that accommodate downdip shortening produced by updip extension on the continental shelf. This shortening is accommodated by a series of thrust sheets that are locally cut by strike-slip faults. Through seismic mapping and interpretation, we resolve these strike-slip faults to be tear faults that share a common detachment level with the thrust faults. Acting in conjunction, these structures have accommodated a north –south gradient in westward-directed shortening. We apply a map-based restoration technique implemented in Gocad to restore an upper stratigraphic horizon of the late Oligocene and use this analysis to calculate slip profiles along the strike-slip faults. The slip magnitudes and directions change abruptly along the lengths of the tear faults as they interact with numerous thrust sheets. The discontinuous nature of these slip profiles reflects the manner in which they have accommodated differential movement between the footwall and hanging-wall blocks of the thrust sheets. In cases for which the relationship between a strike-slip fault and multiple thrust faults is unclear, the recognition of this type of slip profile may distinguish thin-skinned tear faults from more conventional deep-seated, throughgoing strike-slip faults.
American Association of Petroleum Geologists (AAPG)
Added on 28 February, 2014
Bulletin Article
Predicting the presence and connectivity of reservoir-quality facies in otherwise mud-prone fluvial overbank successions is important because such sand bodies can potentially provide connectivity between larger neighboring sand bodies. This article addresses minor channelized fluvial elements (crevasse-splay and distributary channels) and attempts to predict the connectivity between such sand bodies in two interseam packages of the Upper Permian Rangal Coal Measures of northeastern Australia. Channel-body percent as measured in well logs was 2% in the upper (Aries-Castor) interseam and 17% in the lower (Castor-Pollux) interseam. Well spacing were too great to allow accurate correlation of channel bodies. The Ob River, Siberia, was used as a modern analog to supply planform geometric measurements of splay and distributary channels so that stochastic modeling of channel bodies was possible. The resulting models demonstrated that (1) channel-body connectivity is more uniform between minor distributary channels than between crevasse-splay channels; (2) relatively good connectivity is seen in proximal positions in splays but decreases distally from the source as channel elements diverge; and (3) connectivity tends to be greater down the axis of splays, with more isolated channel bodies occurring at the margins.
American Association of Petroleum Geologists (AAPG)
Added on 31 January, 2014
Energy Policy Blog
By Edith Allison
January 8 the Environmental Protection Agency (EPA) issued a new rule on offshore hydraulic fracturing that takes effect on March 1. The rule adds additional effluent limits and monitoring requirements. Operators would be required to maintain an inventory of chemicals used in drilling operations and report any released into surrounding waters. The new EPA rule applies only to existing development and production platforms, and new exploratory drilling operations in federal waters off the Santa Barbara coast. There are 23 existing production platforms in California federal waters.
American Association of Petroleum Geologists (AAPG)
Added on 13 January, 2014