Highlights d Marine heatwaves lead to rapid coral mortality and microbial biofilm formation d Microbial metabolic activity results in rapid dissolution of the coral skeleton d Dissolution reduces skeletal hardness and density and increased porosity

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Volume and isosurface rendering are methods of projecting volumetric images to two dimensions for visualisation. These methods are common in medical imaging and scientific visualisation.Head-mounted optical see-through displays have recently become an affordable technology and are a promising platform for volumetric image visualisation. Images displayed on a head-mounted display must be presented at a high frame rate and with low latency to compensate for head motion. High latency can be jarring and may cause cybersickness which has similar symptoms to motion sickness.Volumetric images can be very computationally expensive to render as they often have hundreds of millions of scalar values. Fortunately, certain materials in images such as air surrounding an object boundary are often made transparent and need not be sampled, which improves rendering efficiency.In our previous work we introduced a novel ray traversal technique for rendering large sparse volumetric images at high frame rates. The method relied on the computation of an occupancy and distance map to speed up ray traversal through empty regions.In this work we achieve higher frame rates than our previous work with an improved method of resuming empty space skipping and the use of anisotropic Chebyshev distance maps. An optimised algorithm for computing Chebyshev distance maps on a graphical processing unit is introduced supporting real-time transfer function editing.

Conventional analysis on core plugs from unconsolidated heavy oil sands is challenging to perform. Sometimes doubts exist about whether the results are representative of the in-situ rock fabric. A digital rock pilot study was designed to provide unique data to understand the rock and allow independent verification of laboratory data, such as calculated petrophysical properties, characterization of damage associated with coring and preservation, direct imaging of oil distribution and pore-wall wettability, and characterization of pore types, clays, grains and grain contacts. The pilot study presents successful cryogenic helical X-ray micro-computed tomography (microCT) of preserved plugs maintained in the frozen state throughout the imaging process. Those 3D images were processed to calculate porosity and absolute permeability. Direct imaging of oil distribution by 3D microCT, with X-ray contrasting agents to highlight the oil with complementary characterization of pore-wall wettability by secondary electron Field Emission Scanning Electron Microscopy (FESEM) is presented to confirm observations from the 3D microCT imaging. Finally, Back scattered SEM (BSEM) imaging and automated, quantified mineral mapping are presented. The 3D tomograms from cryogenic microCT imaging were analysed based on morphological characteristics to identify damaged zones, representing >30% of the volume. The calculated absolute permeability of those 3D tomograms ranged from 8.50D to 24.8D across the plug. The undamaged region had distinctly lower kabs (average = 9.71D) than the most damaged region (average = 21.6D), compared to measurements by a traditional laboratory on adjacent screened and cleaned plugs reported as >20D. The oil saturation from direct microCT imaging was 76.3%, compared to conventional core analysis of oil saturation on a sister plug (62.1%). The 3D images show oil filling most of the open pores and the pore-filling and porous minerals. Furthermore, the oil appears to be in direct contact with the mineral grains, indicating that oil is the wetting phase. Wettability imaging by FESEM confirmed that the majority of the mineral surfaces are oil-wet but the layers of asphaltenes are thin. The mineral composition is dominated by quartz (81%) and feldspar (16%) with some minor clay (1.7%) and carbonate (0.3%). The mineralogy indicates that the sample is likely to be unreactive to steam and/or chemical stimulants.

A study was designed to confirm the formation properties obtained from available conventional RCA data and inferred from corrected wireline log data using digital rock analysis (digital RCA and SCAL analysis) on cores from the Greater Burgan field. This study was performed for Kuwait Oil Company, Fields Development Group (S&EK) by FEI Digital Rock Services in 2014. As part of this study, 27 feet of whole core, from the Lower Ahmadi (AHL2) to Upper Wara (WU1) formations, were imaged by X-ray computed tomography (CT) imaging, including 1 foot of partially preserved core. 14 plugs were extracted from these cores and imaged in 3D by a high resolution helical micro-CT. Analysis revealed stark differences in mineralogy, grain size and sorting and the presence of severe fracturing in some plugs due to the fragility and friability of the rock. Sub-plugs were extracted from 10 of the 14 plugs (including one sub-plug from the partially preserved section) and imaged in 3D by helical micro-CT. 7 of the sub-plugs proved suitable for digital RCA and SCAL analysis. The 3D images were used to calculate digital RCA properties (porosity, permeability, grain density, grain size distribution and formation factor) and pore network models were built to perform digital SCAL simulations and predict multiphase transport properties such as Pc, kr and resistivity index for primary drainage and imbibition. In addition, the in situ mineralogy of each plug was analysed using 2D SEM-EDS automated, quantified mineral mapping. The mineral maps, combined with BSEM images, contain rich textural information and were registered into perfect geometric alignment with the 3D micro-CT images. A tight rock workflow was used to identify sub-resolution porosity in 3 of the plugs. Experimental MICP curves showed that substantial portions of the pore throats were below the image resolution, caused by large amounts of pore-filling materials. Hence, pore scale information could not be directly extracted from some images. Consequently, process based modelling was carried out on two plugs to generate pore-networks. A quasi-static pore-network model was used to simulate oil/water displacements and predict multiphase transport properties. Detailed imaging of oil-in-place and porosity was performed on a partially preserved plug to create a map of remaining oil which revealed that oil was retained in most porous grains and strongly retained in clay-rich zones. The digital core analysis results are in agreement with available log and core data. The Lower Ahmadi (AHL2) section is good quality in terms of porosity, permeability and flow properties, whereas the Upper Wara (WU1) section is of poorer quality.