The Late Albian Mauddud Formation of North Kuwait is composed of inner ramp carbonates and deltaic clastics. It hosts prolific hydrocarbon reserves in Kuwait and across the Arabian Gulf region where the reservoirs are typically the carbonate deposits. Accurately predicting the reservoir properties in the Mauddud Formation is challenging due to the non-unique wireline signatures, which result from the inherent diagenetic heterogeneity and complexity. 385ft of continuous FMI image log data, collected from a single well covering the entire formation in a north Kuwait field, has been analysed to assess its potential to characterise and extrapolate the sedimentological, diagenetic and reservoir characteristics into uncored wells. Nine distinct image facies have been defined, each of which display a specific image fabric. The image facies have been calibrated with core, thin section petrographic observations and core plug data to aid reservoir quality predictability. The study shows that gross sedimentological and diagenetic characteristics observed in the core, including laminations, patchily distributed cements and bioturbation are identifiable in the image logs. The image facies display mottled, laminated or massive fabrics. The argillaceous, fine-grained deltaic clastics, which are non-reservoir, correspond to the finely laminated image facies, however, these deposits are easily identified in uncored intervals by their distinct wireline log signature. The mottled image facies, which is associated with patchy calcite and dolomite cemented carbonates, are subdivided into six categories primarily based on the mottling size. This work establishes a systematic relationship between the mottling size and the grain to micrite matrix ratio of the deposits, and hence, the depositional setting. The finest mottles, corresponding to the smallest cement patches, are typically associated with micrite-supported lithofacies representing deposition in a low-energy inner ramp environment, while the coarsest mottles are principally observed in the grain-supported carbonate lithofacies, which are prevalent in higher energy inner ramp environments. This relationship, which possibly relates to differences in the bioturbation and/or diagenetic overprint of the deposits, is used as a proxy to interpret the depositional energy in the Mauddud Formation. Cross-laminated and massive image facies are also locally identified and are predominantly associated with high-energy shoal complex carbonates. The image facies, in part, also predict the distribution of some of the best porosity and permeability in this formation, notably in the finer mottled image facies where reservoir quality is good to moderate (HeΦ 12.5-25.8% and Kair 1.04-22.4mD). In the coarser mottled image facies, reservoir quality is heterogeneous, but can be comparably good. Using this approach, the gross rock and reservoir properties of the Mauddud Formation can be partly characterised using FMI data alone. The scheme will be refined using further core-calibrated FMI datasets from additional wells to ultimately aid the prediction of reservoir quality at field-scale.

Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs. A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells. The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of c.60-90° with a dominantly N to E orientation of the sandy barforms. Careful analysis of the orientation of the bounding surfaces between the sandstone packages indicates nearly equal proportions of obliquely and roughly parallel dip orientations in some wells. This suggests the formation of at least some lateral (point) bars and possibly the presence of higher sinuosity channels implying that sandbody architecture and fluid flow pathways could be more complex in the middle Burgan relative to the lower Burgan. The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.

The Lower Arab D Member (Kimmeridgian) in onshore UAE is typically characterised by a thick succession of homogeneous mudstones with local cm-scale interbedded bivalve-rich floatstones, which are thought to have been deposited in a low-energy mid-ramp setting. This sedimentological unit is located at the base of a sour gas reservoir that includes the oolitic grainstones of the Upper Arab D Member. The pore system in these micritic deposits is dominated by matrix-hosted microporosity, along with open to partially cemented fractures, primary intraparticle macropores and rare biomoulds in the shell beds, hence a poor to very good porosity and extremely poor to rarely excellent permeability. Variations in porosity and permeability values appear to be strongly related to variations in the micritic fabric: both porosity and permeability increase when the micritic fabric evolves from anhedral compact with coalescent intercrystalline contacts (associated with very little and poorly connected micropores) to subrounded with facial to subpunctic intercrystalline contacts (with locally well-developed micropores). Micritic fabrics also clearly impact the elastic properties of the rock. Through analysis of elastic moduli calculated from standard density, and shear/compressional sonic wireline logs, the relationship between micritic fabric, porosity, permeability and geomechanical properties has been explored. With the evolution of micritic fabric from anhedral compact to subrounded, Young's Modulus decreases with increasing porosity and permeability, indicating a decrease in the overall stiffness of the mudstones. The implication of this observation is fundamental for the development of natural fractures within the Arab D, which are used as conduits for the vertical fluid flow. Indeed, stylolites with associated partially cemented tension gashes are commonly observed at the rheological boundaries, providing further secondary macroporosity and permeability anisotropy within the reservoir. In this study, the observed link between micritic fabrics, log-derived porosity and elastic moduli within cored intervals has been used to predict micron-scale micritic fabric distribution in uncored wells from wireline logs only.

With the increasing interest in the development of shale reservoirs in Europe, cross-border geoscience co-operation is undoubtedly pivotal in understanding the laterally extensive and vastly underexplored unconventional plays in and around the North Sea. The Upper Jurassic Volgian Farsund Formation is considered to be a key source rock in the North Sea. Organic-rich mudrocks are interbedded with distal silt- to sand-prone turbidites and are commonly punctuated by variably thick dolomitized stringers. The latter are locally hydrocarbon charged, and are considered to have better-preserved microporosity and pore connectivity and higher brittleness compared to the adjacent mudrocks. Hence, an improved awareness of their origin and distribution is essential to understanding this potential unconventional play. In this paper, the origin and lateral continuity of the dolomitized stringers within the Farsund Formation are considered based on the integration of borehole image, sedimentological, petrographical and geochemical data. While acknowledging the high level of uncertainty held in some aspects of this study, based on the restricted dataset, our main purpose is to share preliminary findings and thoughts, which are aimed at prompting wider cross-border discussion.

Throughout the UAE and the wider region, several broadly E-W orientated structural lineaments are observed on seismic within the Cretaceous successions and are described as strike-slip faults. However, in the studied field, these features have not been readily observed in well data. Instead, networks of fractures and deformation features are present in core and borehole images. A study was carried out in an attempt to calibrate well and seismic data and to understand the relationship between the seismically-resolved faults and the fractures observed on core. This study focuses on a dataset from the north-east part of the field, which includes BHI images, cores, full 3D CT scans and conventional logs in four penetrations, three of which are horizontal, drilled through the faults; as well as 3D seismic data and relevant derived horizons and fault polygon interpretations. The available data have been investigated in detail, with all structural features in core, circumferential CT scans and BHI images systematically classified using simple and reproducible descriptive schemes. All the structural features have been orientated using directional data from BHI. The understanding of the character and fill of the fractures observed in core has also been incorporated. A further calibration with seismic and integration of results with information from previous studies allowed a full description of the fracture networks, of their densities within and outside the potential fault corridors of the studied field, as well as an assessment of their potential for reactivation and their possible impact on localised formation compaction. On the BHI images, several sub-vertical fractures have been identified, consisting mainly of mixed resistivity and resistive fractures, striking dominantly WNW-ESE. Particular zones along the wells have noticeably higher fracture densities, where features are organised in clusters; they are intercalated with zones where fractures are rarer. The clustering of fractures within fracture corridors are believed to be fault-related, subvertical and tabular fracture clusters that traverse an entire reservoir unit vertically and extend for several hundreds to thousands of feet laterally. These zones are believed to represent fracture corridors, which correlate with the structural lineaments observed on seismic. The fracture corridor network in the study area shows a variable deformation signature at the different scales of observations, but consists mainly of sub-vertical (dominantly >60°) deformation bands (c.50% of the features identified) and partially-cemented fractures (c.25-40%). Some of these features show a small displacement and it is believed this scaled variation in deformation within the corridors accounts for the overall larger, but relatively minor displacement observed on seismic (c.10-40ft vertical throw and possibly up to c.500m cumulative strike-slip observed in seismic).