The tectono-sedimentary evolution of the enigmatic Old Red Sandstone terrane of the Northwest Dingle Domain perplexed generations of geologists. The Domain remained largely misinterpreted, unappraised or simply disregarded. Its fundamental impact on regional basin dynamics was grossly overlooked. This integrated sedimentological, stratigraphical and structural research unravels the complexities of this unique red-bed collage. The Northwest Dingle Domain is largely structurally-constrained between two ENE- trending Caledonian structures: the North Kerry Lineament and the Fohemamanagh Fault. It comprises four unconformity-bounded Groups: the Lower Devonian Smerwick Group; the Middle Devonian Pointagare Group; and the Late Devonian Carrigduff and Ballyroe Groups. Their fluvial-aeolian, and locally tidal, sedimentation patterns profile Late Caledonian transpression to Middle-Late Devonian extension. The inherent primary structural control on basin location, development, geometry, sedimentary-fill and preservation is manifest in the Northwest Domain. A hierarchical cyclicity to fluvial-aeolian basin-fill architecture is established in order to differentiate between climatic, tectonic and eustatically-controlled 'sequence stratigraphy' in active strike-slip and extensional syn-rifi basin settings. The Acadian emplacement of the Smerwick Group Terrane set the foundations of the Northwest Dingle Domain. The Smerwick Group documents sandy and gravelliferous ephemeral-fluvial and erg-margin aeolian processes on an ancient terminal fan. The Pointagare Group is cogenetic with the Caherbla Group of south Dingle. Together they record the renewed influx of coarse-grained sediment in the form of transverse alluvial fans and axial braidplains in response to increased tectonism followed by overstep of an erg complex. The Pointagare-Caherbla basin model highlights the fundamental structural control on basin topography, palaeodrainage patterns, provenance, palaeowind directions and sedimentation style in tectonically-active extensional basins. The Ballyroe and Carrigduff Groups record syn-rift basin-margin fluvial and precursive tidally-influenced sedimentation on the active northern margin of the Munster Basin half-graben. These coarse clastic wedges represent feeder zone deposition proximal to the finer-grained distributary zone terminal fan deposits which infilled the Munster Basin to the south.

No description available.

Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization.

This study is a statistical analysis of the sandstone distribution within the Arkansas Jackfork Group which is a passive margin fan complex. Passive margin fan systems are typically associated with long fluvial transport, fed by deltas, wide shelf, efficient basin transport, that result in a bypassing system. Passive margin fans are generally fine-grained, mud rich, and well sorted. These fans can be separated into three units (upper, middle, and lower fan) based on their location within the fan and how the sediments are deposited. Five outcrops from the Arkansas Jackfork Group have been chosen for this study and each were divided into different facies dependent on sandstone percentages in certain bed sets. The amount of sandstone for each facies was calculated and a statistical approximation for each outcrop was determined. Sandstone distribution curves were made for each outcrop to show a graphic representation of how the sandstone is dispersed. After analyzing different upper, middle, and lower fan outcrops, it is clear there is an obvious change in the sandstone percentage and distribution. The upper fan deposit has an overall sandstone percentage of approximately 77.5% and is deposited in beds that are mainly amalgamated; 10-30m thick. Sandstone is deposited moderately even and is quite concentrated throughout the exposure. The middle fan outcrops contain approximately 72.6% sandstone and show similar patterns, except that the amalgamated sandstone beds are not as thick, 5-15m and contain more shale in between layers. As expected the lower fan outcrop is completely different in both sandstone percentage and distribution. The lower fan has approximately 65.4% sandstone. The distribution of sandstone is more concentrated in each of the individual units, or systems, but the overall complex has two systems separated by a massive marine shale bed, 33.5 m, that contains virtually no sand.

To characterize low-pressure, brittle deformation in porous, granular rock, notchcut cylinders (30 mm neck diameter) of Berea Sandstone were extended in a triaxial apparatus from 10 to 160 MPa confining pressure at strain rates of 10-4 s-1 and 10-5 s-1. Acoustic emission counts were monitored when extending samples at a slow strain rate. Stress at fracture is characterized by the least compressive principal stress, ??3, and maximum compressive principal stress, ??1 (??1 = Pc). A change in strength dependence on pressure at Pc = 50 MPa corresponds to a change from pure macroscopic extension fracture to mixed-mode opening and shear fracture, and likely reflects the increase in mean stress that suppresses the propagation of extension fractures and the interaction between closely-spaced stepped cracks. Within the extension fracture regime (Pc < 50 MPa), ??3 at failure becomes slightly more tensile with an increase in Pc. At Pc > 50 MPa, ??3 at failure becomes more compressive with an increase in Pc and follows Coulomb behavior; however, the angle between the fracture surface and ??1 increases continuously with Pc. Fracture surfaces characteristic of the extension to shear fracture transition appear as linked, stepped extension fractures; the length of extensional segments decreases with increasing pressure. The onset of acoustic emissions and inelastic strain at fracture occurs at earlier points in the strain history with pressure, consistent with the Griffith prediction of the beginning of fracture growth.

Thesis (Ph. D.)--University of Texas at Austin, 1999. / Vita. Includes bibliographical references (leaves 128-134). Available also in a digital version from Dissertation Abstracts.

No description available.

The Shattuck Sandstone Member of the Guadalupian age Queen Formation was deposited in back-reef environments on a carbonate platform of the Northwest Shelf (Permian Basin, New Mexico, USA) during a lowstand of sea level. At Mesa Queen Field, the Shattuck Sandstone is a sheet-like sand body that averages 30 ft (9.1 m) in thickness. The Shattuck Sandstone includes deposits of four major siliciclastic environments: (1) fluvial sandflats, (2) eolian sand sheets, (3) inland sabkhas, and (4) marine-reworked eolian sands. Fluvial sandflat deposits are further subdivided into sheetflood, wadi plain, and river-mouth deposits. Dolomites, evaporites, and siliciclastics that formed in adjacent coastal sabkha and lagoonal environments bound the Shattuck Sandstone from above and below. The Shattuck Sandstone is moderately- to well-sorted, very fine-grained subarkose, with a mean grain size of 98 μm (3.55φ). Eolian sand sheet, wadi plain, and marine-reworked eolian facies comprise the productive reservoir intervals. Reservoir quality reflects intragranular and intergranular secondary porosity formed by partial dissolution of labile feldspar grains, and pore-filling anhydrite and dolomite cements. Vertical successions and regional facies patterns support previous interpretations that these deposits formed during a sea-level lowstand and early stages of the subsequent transgression. Facies patterns across the shelf indicate fluvial sandflats prograded over coastal and continental sabkhas, and eolian sand deposition became more common during sea-level fall and lowstand. During subsequent transgression, eolian sediments in the upper portion of the Shattuck Sandstone were reworked as coastal and lagoon environments became reestablished on the inner carbonate platform.

Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization.

No description available.