Abstract The first two decades of the twenty-first century have seen significant advances across a wide range of reservoir characterization techniques, from microscale digital rock physics to macroscale 3D and 4D seismic. At the same time, industry downturns and the requirements of the energy transition have demanded improved understanding of the value and impact of subsurface data to justify their acquisition and commercial relevance. Despite changing technologies and demands, the acquisition, description and analysis of core remains a fundamental tool in managing subsurface uncertainty and associated risk. Value continues to be created in relation to the reservoir property, sedimentological, diagenetic and structural characterization of subsurface reservoirs, and these are the focus of the Core Values volume. The enduring business impact of core reflects advances in acquisition methods and laboratory-based core analysis (Theme 1 of the volume); the recent development of multi-sensor core scanning and associated artificial intelligence (AI) tools that allow unprecedented high-resolution data collection and visualization (Theme 2); the integration of core-derived data with new complementary technologies, leading to improved characterization of both cored and uncored intervals (Theme 3); the changing nature and role of legacy core collections due to digitization and improved data access (Theme 4). These are complemented by the need to better understand both existing hydrocarbon resources and other subsurface energy-related systems, particularly CCUS (carbon capture, utilization and storage), geothermal energy and the long-term storage of nuclear waste (Theme 5). Through the energy transition core will remain the ground truth foundation to any subsurface understanding and evaluation. At the same time, the technologies available to maximize the applied value of core will continue to develop and evolve, with the integration of diverse and complex core-derived and core-related datasets becoming the norm. Even in the face of AI's impact and value in handling such datasets, those earth scientists who can effectively analyse, interpret and integrate core will still be best placed to meet the subsurface challenges of the future.

Abstract Core samples from the subsurface can provide unambiguous direct information to guide operator decisions. Core may be acquired with drilling equipment (full-bore core) or by post-drill wireline methods (sidewall core). Both approaches have distinct profiles of cost, risk, sample type and value, and an operator must select the most appropriate to progress business in an informed way. The option to selectively core after drilling and perceptions of lower cost and risk might indicate that sidewall coring will always be the best approach. Recent developments to increase the size and quality of rotary sidewall samples would only add weight to this view. It is not all good news for sidewall core, however. Individual sample size and total volume delivered per run are tiny; weak rock or high overbalance pressure may cause poor recovery and biased datasets; time between drilling and logging allows mud invasion and borehole relaxation, so samples are often broken and pore fluids contaminated. Sidewall sample sets therefore leave a higher degree of uncertainty when compared to full-bore core. It is this operator's view that both approaches have a role to play in reducing subsurface uncertainty, and cost, risk and value should be carefully considered when deciding which to apply.

Abstract Core analysts principally study the storage, flow and saturation properties of porous rocks and sediments. Some of the derived parameters are specific to hydrocarbon production but many have commonality with other subsurface disciplines such as hydrology and soil science. Traditional core analysis involves direct physical experimentation on core plugs to derive a range of parameters used as calibration for conventional well logs, and to predict hydrocarbon reserves and recovery. The mechanisms and processes for obtaining such data have evolved significantly during the last century, from the manual instruments of the mid-twentieth century to the accredited digital data collection and recording of the 1990s onwards. X-ray micro- and nano-scale computed tomography (CT) imaging led to the development of the digital rock physics subdiscipline in the early 2000s. This has subsequently allowed direct visualization of fluid flow at the pore scale, imaging the wetting phase and multiphase fluid mobility. Multiscale imaging workflows are being developed to overcome issues around heterogeneous rock and the limited field of view associated with the highest resolution X-ray CT images. Hybrid workflows, which combine digital rock physics with traditional core analysis, are becoming increasingly common to meet the challenges associated with some of the most difficult to constrain properties, such as relative permeability. At a larger scale, the recent development of multisensor core logging (MSCL) tools has allowed the cost-effective acquisition of essentially continuous high-resolution 1D, 2D and 3D datasets from both slabbed and unslabbed whole core. Often aided by artificial intelligence to manage and interpret these large physical and chemical datasets, both new and legacy core can be rapidly screened to allow representative subsampling for detailed laboratory experimentation. The context and data provided by the MSCL then allows effective upscaling of these time- and cost-intensive point-source measurements. In the last decade, extended reality (XR) has resulted in a step change in the ability to visualize and integrate core and core-derived information with other subsurface datasets. A very wide range of scales can be managed effectively, from micrometre- to centimetre-scale petrographical and core analysis data, to metre-scale well logs and up to kilometre-scale 3D and 4D seismic. These tools allow stakeholders to work and meet from any location in a common workspace, and efficiently scale and interrogate data in a virtual 3D environment. The various advances in core analysis and associated technologies during the early twenty-first century mean that the study of porous media to help enable the energy transition looks assured. During the coming decades, applications as diverse as carbon capture, utilization and storage (CCUS), hydrogen storage, geothermal energy generation, mining for critical minerals, palaeoclimate studies, radioactive waste management, and site surveys for windfarms will all continue to benefit from the data and understanding derived from core analysis.

Abstract A core repository is a physical record of a country's or commercial organization's subsurface wealth. Some of the largest core repositories hold thousands of kilometres of core material and it is a challenge to turn this physical archive into an accessible digital resource for all. Non-destructive multi-sensor core logger, hyperspectral and X-ray imaging techniques offer a unique chance to rescue valuable data trapped within core samples, improving the way that a core repository delivers data to academic or industrial end users. Here we present a case study of an archived petroleum core acquired in 1985 at the Osprey Field, UK Continental Shelf. Data from the UK National Data Repository are augmented by a multi-sensor core logger, hyperspectral and X-ray dataset that is uploaded into a cloud-based digital repository. The data were analysed using a multi-variant analysis to reclassify the original lithological interpretations, uncovering a greater proportion of clay and cemented horizons than was previously interpreted. A workflow is established to optimize the use of legacy cores and exploit the abundance of data trapped within the core repository using continuous multi-sensor core scanning and imaging data, which are stored within the virtual environment for visualization and access to all.

Abstract Drill core is a vital resource for subsurface characterization and informs process understanding. However, it is expensive to collect and, as a result, the geoscience community increasingly relies on data from legacy core to address today's energy challenges. Many countries store geological materials collected over decades in national archives. In the UK, over 600 km of drill core is currently stored at the UK national core repository, which covers a breadth of the UK's geology, including those targeted for resources, energy and waste storage. The challenge is to maximize the value of these analogue archives and new core when deposited – improving access to materials and associated data, whilst simultaneously maximizing preservation to ensure optimized use, now and in the future. This paper summarizes the BGS approach to characterize drill core more efficiently and consistently using a multiple-technique core scanning approach set within a project-specific core scanning workflow to increase core data acquisition and complement traditional core characterization practices. Thus, creating a digital record of the core, preserving it beyond its physical lifetime and improving accessibility. This paper highlights the benefits and challenges of this long-term endeavour, especially in making the data open access and discoverable.

Abstract Hyperspectral core imaging as a commercial technology is fairly new to the oil and gas industry, providing a rapid and non-destructive method for mapping mineralogy of drill core and cuttings. The technology makes use of infrared spectrometers that collect imagery across the visible, near infrared, short-wave infrared and thermal (long-wave) infrared range that contains information related to a variety of mineral species, and in some cases including mineral chemistry and texture. In this paper we illustrate how the mineralogical information can be used directly for a variety of applications relevant to reservoir quality, including mineral mapping, sedimentological mapping and upscaling of micro information to the well scale. Statistical analysis allows the data to be used to segment cores into different rock types, and via calibration to quantitative mineralogical techniques, the data can be used to construct continuous curves of quantitative mineralogy, total organic content and production parameters.

Abstract This paper presents core analysis practices developed to increase the value of cores in reservoir characterization workflows. Core analysis traditionally implies extensive rock testing programmes that require large numbers of plug samples. Numerous stakeholders compete for intact core material and often do not base sample selection criteria on objective and reliable information. As a consequence, samples dedicated to core analysis programmes consume a significant fraction of the material available, yet they are selected on the basis of very little a priori information and therefore do not necessarily capture the complexity of the targeted formations. In an attempt to change this paradigm, we promote a more integrated core analysis solution combining transdisciplinary, high-resolution, non-destructive measurements on whole cores, for an early yet objective description of cores and the rapid estimation of formation properties. The first section describes multidisciplinary and non-destructive tests designed to increase the value of information from cores while keeping a minimal footprint. Core samples are scanned along a fit-for-purpose surface, with a collection of sensors interfaced to the same table-top equipment. Technologies including ultra-high-resolution pictures, elemental composition and the direct measurements of geomechanical properties provide continuous and high-resolution profiles with a unique depth reference. Panoramic pictures are processed to extract textural and colour features and grain size distributions. Grain size distributions are backed up by analysis of topographical maps created with a laser scan. The results are combined under one unique format, thereby easing interdisciplinary work from the verification of standard tests (routine core analysis, rock mechanical test) to the construction of robust predictive rock models. The paper describes machine learning schemes applied to core datasets. Unsupervised schemes are designed to identify rock facies, while supervised schemes are used to classify tested rocks into predefined rock facies with known petrophysical properties. Case studies highlight the benefits of this approach of core analysis in conjunction with artificial intelligence for the automated identification and classification of rock facies. This novel approach to core analysis leverages a detailed and comprehensive knowledge of the distributions of core properties, available under one unique format for all disciplines, which eases interdisciplinary work and significantly improves existing core analysis standards. It also provides a sound basis to train artificial intelligence rock reservoir property predictors linking well-log data to core-based lithofacies signatures.

Abstract Today's geoscience challenges often require repurposing of data and samples from legacy boreholes. Collection of new deep core is expensive; maximizing this investment is vital. However, the condition of legacy cores varies due to factors including recovery, sampling, lithology, and storage. Rock Quality Designation analysis is often undertaken on new core but this only provides a snapshot of core condition and will not be indicative of subsequent condition. Poor core condition can make destructive analytical techniques impossible and also impacts non-destructive techniques including core scanning. Since 2011, BGS have systematically collected 125 000 core images. This study investigates if core condition of this archive can be assessed using automated analysis by machine learning. A neural network-based approach was used to segment these images. By differentiating imaged core from their background, properties such as number of fragments and total rock area were determined and used to assess core condition. Analysis of outputs demonstrates that with minimal input data, core condition can be rapidly assessed. This allows users to better understand and visualize core. This can be used to qualitatively assess non-destructive data, improve success of destructive sampling through targeted sampling and reduce the time and effort spent interacting with physical material.

Abstract The role of the subsurface team is to reduce technical risk and uncertainty associated with profile delivery, for both hydrocarbon production and the injection of water or gases, enabling confident reservoir management and investment decisions. Core is a key resource for delivering this objective, providing the only opportunity to directly observe and measure the reservoir rock. However, it is expensive to acquire and the decision to take new core should be clearly linked to a business objective. A combination of depositional and diagenetic factors can result in carbonate reservoirs being highly heterogeneous, making them a challenge to find and develop. Core studies can significantly improve understanding of the controls on heterogeneity and its distribution within the subsurface, but to maximize value, they should be fully integrated with wireline logs, seismic and production or test data to predict likely reservoir behaviour. For example, thin (<1 m) high or low permeability zones can dominate production yet remain very subtle or undetectable in wireline log or seismic data alone. During exploration and appraisal, sufficient data and knowledge are required to enable appraise/develop or walk-away decisions. Appropriate geological description of core material helps to establish original volumes in place, net-to-gross, depositional setting, age, reservoir architecture and large-scale flow zones. Core material can also help establish other key reservoir parameters such as saturation, reservoir fluids, seismic rock properties and geomechanical properties as well as influence decisions such as well design, development strategy and facility requirements. As a field is developed and production matures, reservoir behaviour may change and detail of the sedimentology, structure, diagenesis, baffles and thin heterolithic permeability zones may become more important. In carbonate reservoirs, this often requires the integration of existing legacy core or new core material and targeted surveillance data, such as injection and production logging tool (ILT/PLT) or saturation logs, to understand the stratigraphic, depositional and diagenetic controls on flow units and improve predictive capability. Moving a reservoir from natural depletion onto waterflood or enhanced oil recovery (EOR) may need more advanced core-based data from core flood experiments to deliver maximum value from the reservoir. New core material, or detailed review and new sampling of existing or analogue legacy core, may be required to understand complex rock–fluid interactions and the value that waterflood or EOR could bring to a development. To maximize the value and insights gained from core, it is essential to use it throughout a field's life. High quality description and a well-considered sampling regime should be carried out at the earliest opportunity to provide baseline data. However, periodically revisiting the core enables the entire subsurface team to keep testing hypotheses and refreshing models. Where there is no core material available in the field, analogue field core can be especially useful both to narrow uncertainty and explore possible alternative models. A multi-disciplinary approach integrating new data with core observations helps refine and improve predictions and can lead to the identification of significant additional opportunities as reservoir behaviour matures and field development progresses.

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 The Gohta discovery well 7120/1-3, drilled on the Loppa High in the SW Barents Shelf in northern Norway encountered a meteoric karst system hosted by the late Permian lower Røye Formation that formed during a period of sub-Triassic exposure. The karst system is preserved as a series of interbedded collapse breccias representing formerly open palaeocaves, matrix-rich breccias that represent palaeocave fills with in situ and reworked stalactites and stalagmites. Layers of ‘Swiss cheese’ texture are interpreted as zones of dissolution in marine-meteoric mixing zones that may have controlled the levels of palaeocave development within the Gohta structure. These other cavities and the matrix of karst breccias were infilled by layered fine doloarenite matrix interpreted as an internal fill generated by collapse. This was followed by a later matrix of dark grey argillaceous mudstone that is interpreted as an external fill that pre-dates the overlying Klappmyss Formation. The karst system has undergone complex early diagenesis that includes extensive dissolution, early leaching of silica, the precipitation of pyrite on internal surfaces and sediment and the precipitation of carbonate and silica as speleothems and vadose cement. A borehole imaging log (BIL) was run across the lower Røye and Triassic Klappmyss formations, including the cored interval that provides a record of inclination and azimuth of the karst fills and in situ Røye Formation. The core provides information about the origin and timing of the different karst fills, and the BIL provides information about their azimuth and inclination. This integrated use of core and BIL data allows the incremental tilting history of the Loppa High structure during exposure to be reconstructed. At present, the Gohta structure has a finite tilt of 5–10° to the SE. The plunge of in situ stalagmites and stalactites suggests that the karst system was initiated while the Røye Formation was slightly tilted to SE. The dip of karst components and the host stratigraphy indicate several phases of incremental tilting during deposition of the doloarenite and argillaceous mudstone karst matrix. There appears to have been a reversal of tilt of the Gohta structure prior to its onlap by the Klappmyss Formation.

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.

Abstract Core-based studies have had material impacts on the understanding of a number of late-life, mature North Sea Brent Group hydrocarbon reservoirs. These studies have included sedimentological, diagenetic and reservoir quality focused evaluations of core. The primary objective of the studies has been to improve conceptual and qualitative models that can be utilized in reservoir modelling and also for infill drilling and well workover evaluations. Most of these studies have been undertaken on old core samples collected in the 1980s and 1990s. Two case studies are described here that provide examples of the utility of core in mature fields. (1) Heather Field calcite: to quantitatively assess the distribution of calcite cements and their impact on hydrocarbon volumes and reservoir quality distribution in Brent reservoirs. (2) Thistle Field Etive Formation barriers and baffles: to characterize and describe the origin and distribution of low-permeability intervals within the Etive Formation reservoir. These two studies used a wide variety of core-based techniques including core logging and description, optical microscopy and petrographical studies, isotope analyses, X-ray diffraction (XRD) and scanning electron microscopy-energy dispersive X-ray spectroscopy (SEM-EDS) (FEI Company analysis tool and software, QEMSCAN)-based mineralogy, portable-X-ray fluorescence (XRF), NDTr and Thermo Scientific Inc. NITON TM operational software (NDT) geochemical analysis, as well as image analysis of grain size and texture. These data were then integrated with other subsurface datasets, such as well log, seismic data and well performance data, in order to address the specific reservoir challenge. These new and focused reappraisals of core demonstrate the dual value of core-based studies, which can: improve the understanding of producing hydrocarbon reservoirs, leading to improved productivity and recovery. Core is a full asset life-cycle resource and provides critical insight at all stages of field maturity as production behaviour changes and alternative development strategies are considered; further our general knowledge and understanding of clastic sedimentology and diagenesis using rich and diverse core-based datasets backed up by substantial well log and seismic datasets.

Abstract Well Mondot-1 was drilled, cored and logged behind an outcrop of the Eocene Sobrarbe deltaic complex in the Aínsa Basin, Spanish Pyrenees. The data acquired represent a fluvial-dominated delta system prograding over a carbonate slope in the presence of active tectonism, and form part of a basin-to-grain teaching set for subsurface professionals. This paper highlights the workflow step(s) to move from a 1D core description to 2D and 3D correlations, including some of the pitfalls caused by rapid lateral facies variability, which is a common challenge in subsurface reservoir description. The core allows direct log-to-lithology comparison across a full deltaic succession. In the proximal and distal delta fronts, there are clear differences from the closely adjacent outcrop that are ascribed to lateral facies changes and delta front slumping. Two approaches to core display are described, as means towards making such data available to a wider audience: an augmented reality display run over a slabbed core, and a virtual whiteboard display carrying easily scalable viewing possibilities. These approaches can be deployed for other cores, allowing visualization and analysis where people are otherwise unable to travel to the physical location, or in circumstances where the core is now inaccessible.

Abstract Detailed knowledge of subseismic structures and their influence on reservoir production performance is important for optimal reservoir management. Predicting subseismic structures from seismic-scale structural interpretations is inherently difficult without the use of core data. Cores allow direct measurements of porosity and permeability of deformed rocks and enable researchers to make detailed investigation of deformation mechanisms and cementation processes. Frequency, distribution and sometimes orientation of planar structures can be constrained. Such observations are then used together with location relative to seismically mapped fault and fold structures, and with respect to lithology and stratigraphy. However, a significant gap exists between the scale of core observation and the size of structures mappable from seismic data. Bridging this gap requires a sound general understanding of the different structures that occur in reservoirs, which, in addition to faults, includes drag folds, veins, fractures and the many types of deformation bands that can exist in porous rocks. Proper understanding of such subseismic structures is primarily based on outcrop-based observations and analyses, aided by physical experiments and numerical modelling. We stress that integrating such cutting-edge knowledge with core, seismic and other case-specific subsurface data in an appropriate tectonic context is paramount for realistic reservoir characterization and successful reservoir management.

Abstract Improved understanding of hydraulic fractures is needed to optimize petroleum well drilling and completion strategies. Yet direct observations of hydraulic fractures are rarely made, and reliance is placed on indirect methods such as microseismic monitoring, interference tests, fibre optic detection of fracturing in adjacent wells and numerical modelling. While these techniques provide useful insights, verification of such studies is commonly lacking; core taken through stimulated intervals offers a robust option for verification. We make the case that core can provide complementary information at a different scale from other data types. Core from a slant well adjacent to two stimulated wells at the Hydraulic Fracture Test Site (HFTS1) in West Texas revealed 375 hydraulic fractures, striking 090°±20°, subparallel to present-day S Hmax . There are more hydraulic fractures than expected, and clustering across a range of scales from approximately 1 cm to 50 m. The largest cluster correlates with high microseismic event density. Diversion, bifurcation, and segmentation structures may account for the large number of fractures observed and the orientation spread. Reactivation of sealed natural fractures and bedding planes is relatively uncommon. Proppant sand packs and patches occur in a few locations, particularly where hydraulic fractures are complex.

Abstract The UK National Geological Repository (UKNGR) is the largest collection of British geoscience samples, with 16 m ‘specimens’, including 600 km of drillcore. Samples are available for study/subsampling by commercial organizations and researchers. Data, reports and publications must be returned. Raw data are available after 2 years. The scientific method requires published results to be repeatable, necessitating the archiving of samples. Re-purposing samples for new research saves money and time and thereby reduces risk. The National Geological Repository (NGR) has cost over £200 bn to collect and the cost of a single deep cored borehole would be outside the funding of most research projects, so the operation of an NGR makes financial sense. Many of the boreholes have been extensively characterized, so new research can build on the wealth of published data. The NGR has been at the forefront of international efforts to utilize digitization and the World Wide Web to improve the impact of the collections. Geographical information system (GIS) access was provided to the onshore borehole collection in 2000, and GIS access and text searching were added to the other collections over the next 10 years. This was followed by high-resolution images of the UK Continental Shelf (UKCS) cores, petrological thin-sections, and images, stereo anaglyphs and 3D-digital models of British-type fossils.