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Abstract Three-dimensional circumferential CT-scans have transformed how core is described and calibrated with borehole image (BHI) datasets to refine reservoir rock typing and facies description. This paper focuses on the value of circumferential CT-scans in the assessment of plug and bed-scale heterogeneities. It shows how careful re-orientation and calibration with borehole images can help unravel sandbody geometries and orientation, and the potential effects of cross-cutting deformation bands on permeability architecture and sweep efficiency. This is demonstrated using aeolian-dominated core examples, supported with circumferential CT-scans, minipermeability data, conventional logs and BHI data, taken from the Jurassic Norphlet Formation from producing fields in the Gulf of Mexico. The formation overlies Early Jurassic Louann Salt, and syn-depositional halokinesis significantly influenced depositional accommodation space, facies distribution, and preservation potential. Furthermore, deposition during active salt tectonics has resulted in complex deformation band networks within these clean sandstones. CT-scan density contrasts highlight stratification types and deformation bands not always visible on slabbed core. Furthermore, BHI re-orientated CT-scans provide high-resolution dip/azimuth data and aid aeolian bedset bounding surface definition, which is important for determining dune geometry and stacking patterns. Hence, an integrated approach using core, circumferential CT-scan and calibrated BHI has been essential for deciphering the complexity of these deposits.
Abstract Quad 29 in the Central North Sea is a focus for bp, with a strategy to identify remaining hydrocarbon accumulations to tieback to existing infrastructure. Capercaillie was appraised in 2017 with well 29/04e-5 and sidetrack 29/04e-5z. A gas cap and thin oil rim were intersected within the siliciclastic Paleocene–Eocene Sele Formation. The reservoir sandstones were deposited in a deep marine setting by sediment-gravity flow processes. Within the context of a relatively detailed knowledge of the surrounding area, the reservoir data-operational risk-cost balance was addressed through acquisition of a full wireline logging suite, pressure data, latest-generation microresistivity images and targeted large-volume rotary sidewall cores (RSWCs), with the latter two favoured over whole core. Mature deepwater descriptive schemes were applied at the sidewall core (lithotype), bed (borehole image facies) and bed-stack (depositional package) scales. This hierarchical approach provided robust sedimentological data to underpin higher-order depositional models, which together were used as a framework to (1) constrain the reservoirs’ mineralogical and textural attributes, (2) establish the main controls on rock quality and (3) explain the resulting variations in porosity and permeability. This study demonstrates that the careful integration of data derived from the latest borehole imaging tools and large-volume RSWCs can be a successful means of characterizing reservoirs from a sedimentological, reservoir quality and reservoir architecture perspective in mature basins. Similar approaches to geological reservoir characterization in such settings are likely to be a common cornerstone of cost-effective development during the energy transition.
The analysis of the micro-occurrence state of irreducible water in anthracite fracture network based on digital core
Geological elements in the in thirteenth-century treatise “ La Composizione del Mondo ” (The composition of the World) by Ristoro d’Arezzo
Study of Micro-structures and their Relation with Occurrence of Mineral Matter in Ramagundam Coals, Godavari Basin, India: Implications on Coal and Hydrocarbon Industries
Controls on Production in the Eagle Ford: Permeability, Stratigraphy, Diagenesis, and Fractures
ABSTRACT The Cenomanian–Turonian Eagle Ford of South Texas is largely composed of two interbedded rock types: marls and limestones. The marls consist mainly of coccoliths with sand- and silt-size grains predominantly comprised of planktonic foraminifera with lesser amounts of inoceramid fragments and other carbonate grains. The limestones are recrystallized, and they contain calcified radiolarians and calcispheres, with almost all pore spaces having been filled with calcite cement. Most of the hydrocarbons in the Eagle Ford, regardless of thermal maturity, reside in the pore network of the marls. Economic production of hydrocarbons stored in these marls, which have nanodarcy permeabilities, can only be obtained by inducing and maintaining fractures with hydraulic stimulation. The interbedding of the marls with limestones form centimeter-scale brittle–ductile (or stiff-compliant) couplets that influence hydraulic fracturing over a range of scales, and at the smallest scale it may increase production by hosting complex near-wellbore fracture systems. Natural fractures that were already present may be open or cemented and reactivated during hydraulic stimulation and contribute to production. This can generate a hybrid fracture system with a larger drainage area and fracture surface area to allow for crossflow from the matrix to fractures. The Eagle Ford is a dual-porosity system, with the hydrocarbon stored in the marls feeds a network of progressively larger natural and induced fractures that carry those hydrocarbons to the wellbore. In most cases, the Eagle Ford will be most productive when the “right” mixture of marl and limestone are present. Too much limestone lowers the storage capacity of the system, and too much marl reduces the complexity of the fracture system. The distribution of the limestones is important: Even if the percentage of limestone in two sections is equal, hydraulic stimulation will produce a more complex fracture network when the limestone is present as a series of thin interbeds rather than as a single thick limestone. The interbedding of limestone and marl can be measured using limestone frequency—the number of limestone beds per unit thickness. Variation in production is observed in wells on the same pad completed with the same treatment but landed in zones of differing limestone frequency, with production in these wells increasing with limestone frequency. Also, in a multivariate analysis involving numerous engineering and geologic variables and over 1000 wells, all measures of interbedding reduced to a single factor, which we call limestone frequency, which positively correlated with production.
Permeability of carbonate fault rocks: a case study from Malta
Thermal properties of sedimentary rocks in the Tarim Basin, northwestern China
ABSTRACT The Lower Cretaceous (Barremian) Zubair Formation in North Kuwait represents a major clastic pulse above the Ratawi Formation. Depositional environments and the sequence stratigraphic framework play a key part in the reservoir development and production strategy with distinct depositional barriers giving rise to multiple fluid contacts. Reservoir structure and fault pattern control fluid redistribution. The Zubair Formation was deposited within a (weakly) tidally influenced deltaic system with episodes of marine influence. The sedimentary sequence consists of highly mature clastic deposits with variable and heterogeneously distributed argillaceous matter, containing negligible amounts of expandable clay minerals. The dominant sandstones range from very fine to medium-grained and are weakly to moderately overprinted by authigenic mineral precipitates. Reservoir quality is mainly controlled by the primary depositional detrital clay content, with additional control by grain size and minor quartz cementation within the cleanest deposits. A sequence stratigraphic framework adopting field-wide correlatable surfaces forms the basis for the division of the Zubair layers. Lower Zubair deposition (Z10 gross reservoir unit) occurred within a tidally influenced deltaic system locally with a stronger marine influence and diminished clastic influx at the very base. Above a widespread mud-prone marine barrier, the heterogeneous middle Zubair interval (Z20–30) comprises a mixture of sand and mud-prone delta-top-or-front deposits and tidally influenced channel-fills. The main reservoir unit of the upper Zubair (Z40) comprises at least four episodes of incision and fills by sand-prone, tidally influenced channel deposits. The overlying upper Zubair (Z50–60) is largely mud-prone with only minor channel development, including channel-fill sandbodies incised into more marine-influenced deposits in the uppermost part of the Zubair. Reservoir development to a large extent depends on genetic aspects of the Zubair reservoirs. The tidally influenced upper Zubair channel-fills represent the best reservoir facies in the Raudhatain field and have been the main targets of initial development. The amalgamation of individual channels forms a number of complex, heterogeneous, and variably interconnected reservoirs. There is good aquifer support for the upper Zubair sand in such a depositional setting. The middle Zubair channel sandbodies show lesser support from the aquifer and represent a second priority for development. Shoreface and mouthbar sandstones potentially form more aerially extensive intervals of poorer quality reservoir that are locally interconnected with the channels. Such thin but laterally extensive sands are the target of current and future development of the reservoir with maximum reservoir contact wells. Complex structural aspects, filling, and up-structure oil migration have resulted in a leaking trap in the Zubair reservoir in the Sabiriyah field. Only stratigraphic traps and extensive sealing by deltaic and marine mudrocks have trapped oil in the Lower Zubair sand (Z10). Other prolific oil reservoirs in the Raudhatain field are water wet with residual oil saturation in the Sabiriyah field. The mechanism for the formation of tar plugs in the Raudhatain field has illustrated the importance of leaking faults. The Raudhatain field has been produced for the last six decades. The initial phase of depletion continued until 2000. Subsequently, peripheral water injection began into different zones of the reservoir. The injection plan is based on the reservoir geometry and sandbody continuity, pressure depletion, and the production plan. Well design and type have evolved over time with higher well diameters drilled after effective control of the lost circulation zone in the overlying Shuaiba limestones. The current development plan includes drilling horizontal wells for effective depletion of the reservoir. Production in the Sabiriyah field started in 2008, mainly from thin shoreface, mouthbar, and channel sandbodies at the Zubair base in the southern part of the field.