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We document the tectonic and metamorphic evolution of thrust nappes of the eastern island of Elba. The area exposes a natural cross section of the Northern Apennines hinterland, from the metamorphic basement units to the overlying continent- and ocean-derived nappes. We integrated mapping, analysis of structures and microstructures, and the interpretation of drill core logs with lithostratigraphic, metamorphic, and geochronological constraints, producing a novel geological map of eastern Elba (1:5’000 scale). We show that the area experienced polyphase Oligocene – Pliocene contractional tectonics marked by in-sequence and out-of-sequence thrusting accompanied by folding and overprinted by faulting in the Pliocene. Magmatism occurred during contraction with post-magmatic thrusting ultimately coupling HP-LT and LP-HT units. Drill core logs allow for the first time the reconstruction of the N-dipping character of the Zuccale Fault, which represents the youngest (late Miocene – early Pliocene) large-scale structure in the area.

SummaryCarbon dioxide (CO2) enhanced oil recovery (EOR) has long been practiced in the US as an efficient mean for enhancing oil production. Many of the US CO2-EOR developments have been designed horizontally. This is because of a viscous-dominated CO2 flow regime that is prevalent in these developments driven by thin and low-permeability reservoirs. Reservoirs and fluid properties are different in the North Sea. Pays are usually thicker with better petrophysical properties. Lighter oils can also be found in North Sea reservoirs. This suggests that a dissimilar flow regime might prevail CO2 displacements in the North Sea developments, which could favor a dissimilar CO2-EOR process design. This study thus compares CO2 flow regimes between several North Sea and US reservoirs. We use scaling analysis to characterize and compare CO2 flow regimes between these two classes of reservoirs. Scaling analysis characterizes CO2 displacement in each reservoir system using three dimensionless numbers: gravity, effective aspect ratio, and mobility ratio. Displacement experiments conducted in stochastically generated permeability fields, under exactly matched magnitudes of the derived dimensionless numbers, reveal the prevailing CO2 flow regime in each reservoir system. Results of scaling analysis indicate that CO2 flooding in the North Sea reservoirs can be generally characterized with a larger gravity number, smaller effective aspect ratio, and smaller mobility ratio than the average US CO2 flooded reservoirs. Flow regime analysis indicates that unlike the majority of the US CO2 flooded reservoirs, CO2 flow regimes tend to be more gravity-dominated in the North Sea class of reservoirs. CO2 flow regimes in the North Sea systems are expected to suffer from a higher degree of instability because of thicker North Sea pays, which limit effective crossflow. Understanding the differences and characteristics of CO2 flow regimes in the North Sea prospects can help operators design their CO2 flooding more efficiently, which could increase the recovery factor (RF) as well as address CO2 storage requirements, a necessary consideration for CO2-EOR deployment in the North Sea.

SummaryScale inhibitor (SI) squeeze treatments are one of the most common techniques to prevent downhole scale formation. In this paper, we present the optimization of treatment design for multiple wells included in offshore campaigns. Two offshore fields with 8 and 12 production wells in west Africa were considered that are separately treated via yearly squeeze campaigns. The wells included in each campaign are treated in a single trip of the supply vessel. Based on the storage capacity of the vessel, the available volume of SI onboard should be optimally allocated to each of the wells (having different properties and water production rates), so that they are all protected from scaling for 1 year until the next campaign is carried out. A hybrid optimization methodology was applied to optimize the squeeze campaign design.The gradient descent (GD) algorithm was first applied to derive the squeeze “isolifetime proxies” related to each well. Each proxy includes all the possible squeeze designs that result in 365 days of squeeze lifetime in the well. Using these proxies, any combination of wells’ squeeze designs could be nominated as the campaign design, because that would result in treating all wells until the next campaign. The multiobjective particle swarm optimization (MOPSO) technique was implemented to optimize the campaign design by simultaneously minimizing the total SI volume and the total injection time for the whole campaign. Minimizing the total pumping time would consequently minimize the deferred oil volume and the total cost of squeezes in the field.Finally, the Pareto Front was identified for each field, showing the most optimum campaign designs. The Pareto Front was shown to be a valuable tool for the operator to make a trade-off between the size of the vessel and the injection time; that is, to use a bigger vessel to transport more inhibitor to the wells or to use a smaller one but for a longer time to inject more water during the squeeze treatments in the field. A cost analysis was performed to identify the most optimum deployment plan providing the most optimum inhibitor allocation strategy, including the optimum inhibitor volume and the optimum injection time for each campaign.

A new hybrid, sigma-pressure vertical coordinate was recently added to the Weather Research and Forecasting (WRF) Model in an effort to reduce numerical noise in the model equations near complex terrain. Testing of this hybrid, terrain-following coordinate was undertaken in the WRF-based Rapid Refresh (RAP) and High-Resolution Rapid Refresh (HRRR) models to assess impacts on retrospective and real-time simulations. Initial cold-start simulations indicated that the majority of differences between the hybrid and traditional sigma coordinate were confined to regions downstream of mountainous terrain and focused in the upper levels. Week-long retrospective simulations generally resulted in small improvements for the RAP, and a neutral impact in the HRRR when the hybrid coordinate was used. However, one possibility is that the inclusion of data assimilation in the experiments may have minimized differences between the vertical coordinates. Finally, analysis of turbulence forecasts with the new hybrid coordinate indicate a significant reduction in spurious vertical motion over the full length of the Rocky Mountains. Overall, the results indicate a potential to improve forecast metrics through implementation of the hybrid coordinate, particularly at upper levels, and downstream of complex terrain.

We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

SummaryWe propose a workflow to optimize the configuration of multiple-interacting-continua (MINC) models and overcome the limitations of the classical dual-porosity (DP) model when simulating chemical-component-transport processes during two-phase flow. Our new approach captures the evolution of the saturation and concentration fronts inside the matrix, which is key to design more effective chemical enhanced-oil-recovery (CEOR) projects in naturally fractured reservoirs. Our workflow is intuitive and derived from the simple concept that fine-scale single-porosity (SP) models capture fracture/matrix interaction accurately; it can hence be easily applied in any reservoir simulator with MINC capabilities. Results from the fine-scale SP model are translated into an equivalent MINC model that yields more accurate results compared with a classical DP model for oil recovery by spontaneous imbibition; for example, in a water-wet (WW) case, the root-mean-square error (RMSE) improves from 0.123 to 0.034. In general, improved simulation results can be obtained when selecting five or fewer shells in the MINC model. However, the actual number of shells is case specific. The largest improvement in accuracy is observed for cases where the matrix permeability is low and fracture/matrix transfer remains in a transient state for a prolonged time. The novelty of our approach is the simplicity of defining shells for a MINC model such that the chemical-component-transport process in naturally fractured reservoirs can be predicted more accurately, especially in cases where the matrix has low permeability. Hence, the improved MINC model is particularly suitable to model chemical-component transport, key to many CEOR processes, in (tight) fractured carbonates.

Many unconventional reservoirs exhibit a high level of vertical heterogeneity in terms of petrophysical and geo-mechanical properties. These properties often change on the scale of centimeters across rock types or bedding, and thus cannot be accurately measured by low-resolution petrophysical logs. Nonetheless, the distribution of these properties within a flow unit can significantly impact targeting, stimulation and production. In unconventional resource plays such as the Austin Chalk and Eagle Ford shale in south Texas, ash layers are the primary source of vertical heterogeneity throughout the reservoir. The ash layers tend to vary considerably in distribution, thickness and composition, but generally have the potential to significantly impact the economic recovery of hydrocarbons by closure of hydraulic fracture conduits via viscous creep and pinch-off. The identification and characterization of ash layers can be a time-consuming process that leads to wide variations in the interpretations that are made with regard to their presence and potential impact. We seek to use machine learning (ML) techniques to facilitate rapid and more consistent identification of ash layers and other pertinent geologic lithofacies. This paper involves high-resolution laboratory measurements of geophysical properties over whole core and analysis of such data using machine-learning techniques to build novel high-resolution facies models that can be used to make statistically meaningful predictions of facies characteristics in proximally remote wells where core or other physical is not available. Multiple core wells in the Austin Chalk/Eagle Ford shale play in Dimmitt County, Texas, USA were evaluated. Drill core was scanned at high sample rates (1 mm to 1 inch) using specialized equipment to acquire continuous high resolution petrophysical logs and the general modeling workflow involved pre-processing of high frequency sample rate data and classification training using feature selection and hyperparameter estimation. Evaluation of the resulting training classifiers using Receiver Operating Characteristics (ROC) determined that the blind test ROC result for ash layers was lower than those of the better constrained carbonate and high organic mudstone/wackestone data sets. From this it can be concluded that additional consideration must be given to the set of variables that govern the petrophysical and mechanical properties of ash layers prior to developing it as a classifier. Variability among ash layers is controlled by geologic factors that essentially change their compositional makeup, and consequently, their fundamental rock properties. As such, some proportion of them are likely to be misidentified as high clay mudstone/wackestone classifiers. Further refinement of such ash layer compositional variables is expected to improve ROC results for ash layers significantly.

Summary Conventional carbonate reservoirs contain most of the world’s oil and gas reserves. However, the recovery factors after primary and secondary oil recovery remain low overall. Surfactant-based enhanced oil recovery can be used to enhanced oil recovery by changing the wettability of the rock and reducing the interfacial tension. In this study, we incorporated the experimentally validated surfactant models into a high-resolution outcrop analogue model. We built core-scale simulation models based on the experimental data to identify the key physical mechanisms that lead to increased oil recovery. We then parametrise the respective models in order to obtain a better understanding of physico-chemical processes during surfactant injection. Using advanced assisted history-matching methods, we were able to match the laboratory results for both the Spontaneous Imbibition and core flooding. We then implemented the results from the core-scale at a larger scale i.e., inter-well scale model. We used a realistic analogue outcrop for the Shuaiba and Kharaib formations in the Middle East, in order to understand how complex geological structures and multi-scale heterogeneities impact the recovery processes and effectiveness of surfactant-based enhanced oil recovery.

The permeability structure of a fault zone is strongly dependent on the occurrence of meso-scale fracture patterns within the damage zone. Here, structural analyses of Virtual Outcrop Models (VOM) integrated with Discrete Fracture Network (DFN) modelling are used to constrain the relationship between meso-scale fracture patterns and the bulk permeability of a regional-scale fault zone. The Goddo Fault Zone (GFZ, Bomlo – Norway) is a long-lived extensional fault zone cutting across a granodioritic body developed during the long-lasting rifting of the North Sea. Fracture geometrical characteristics and the spatial variation of fracture intensity derived from VOM structural analysis were adopted as input for stochastic DFN models representing selected portions of the GFZ to constrain the variability of the structural permeability tensor K related to the mesoscopic fracture pattern. The intensity of fault-related fracture set(s), and the associated structural permeability computed with DFN models, likely exhibits a decreasing power-law trend within the damage zone with increasing distance from the fault cores. The orientation of the maximum K tensor component is controlled by the intersection direction of the dominant fracture sets. These results highlight the fundamental role of mesoscopic fracture patterns in controlling the bulk petrophysical properties of large fault zones.

The E-vergent Northern Apennines formed by Oligocene-Miocene convergence and westward subduction of Adria beneath Europe. Extension ensued in the Mid-Late Miocene reflecting lower plate roll-back and causing opening of the back-arc Northern Tyrrhenian Sea. Post-orogenic extension is commonly advocated as the main driver of the exhumation of the belt's inner domain high-pressure/low-temperature (HP-LT) rock units. The Acquadolce Subunit of the Eastern Elba nappe stack contains HP-LT rocks recording peak blueschist conditions of 1.5–1.8GPa at 320°C–370°C loosely dated to the Oligocene-Early Miocene. It is sandwiched by two Late Miocene, out-of-sequence top-to-the E thrusts between Jurassic LP serpentinites on top and HT–LP contact metamorphosed marbles at its base. We document widespread W-verging ductile asymmetries within the Acquadolce Subunit, which correspond to top-to-the W extensional shearing for the nappe stack current orientation. This allowed for early syn-orogenic exhumation from blueschist- to greenschist-facies conditions, wherein coeval W-directed extension at the top of the exhuming units acted synchronously with E-directed thrusting at their base causing exhumation by extrusion in an overall contractional setting. The basal, E-vergent thrusting is, however, challenging to document as the wedge has since been reworked by Late Miocene, E-verging compressive tectonics, contact metamorphism, and later extension, obliterating much of the evidence supporting exhumation by extrusion during the early stages of wedge build-up. Syn-orogenic exhumation by extrusion from deep structural levels within the orogenic wedge is a viable mechanism to account for other exhumed HP-LT units in the inner part of the belt.

We investigate the effect of heterogeneous petrophysical properties on Low Salinity Water Flooding (LSWF). We considered reservoir scale models, where the geological properties were obtained from a giant Middle East carbonate reservoir. The results are compared against a typical sandstone model. We simulated low salinity induced wettability changes in field scale models in which the petrophysical properties were randomly distributed with spatial correlation. We examined a wide range of geological realisations which mimic complex geological structures. Sandstone was simulated using a log-linear porosity-permeability relation with fairly good correlation. A carbonate reservoir from the Middle East was simulated where a much less correlated porosity permeability relationship was obtained. The salinity of formation water was set to typically observed values for the sandstone and carbonate cases. A number of simulations were then carried out to assess the flow behaviour. We have found that the general trend of permeability-porosity correlation has a key role that could mitigate or aggravate the impact of spatial distributions of petrophysical properties. We considered models with a log-linear permeability-porosity correlation, as generally observed for sandstone reservoirs. These are likely to be directly affected by the spatial distribution more than models with a power permeability-porosity correlation, which is often reported for flow units of carbonate reservoirs. The scatter of data in the permeability-porosity correlations had a relatively small impact on the flow performance. On the other hand, the effect of heterogeneity decreases with the width of the effective salinity range. Thus, uncertainty in carbonate reservoirs arises due to the ambiguity of spatial distribution of permeability and porosity would be less affects the LSWF predictability than in sandstone case. Overall, the incremental oil recovery due to LSWF was higher in the carbonate models than the sandstone cases. We observe from uncertainty analysis that the formation waterfront was less fingered than the low salinity waterfront and the salinity concentration. The dispersivity of salinity front and the water cut can be estimated for models with various degrees of heterogeneity. The outcome of the study is a better understanding of the implications of heterogeneity on LSWF. In some cases the behaviour can appear like a waterflood in very heterogeneous cases. It is important to assess the reservoir effectively to determine the best business decision.

In any flooding process, the flow pattern determines the quality of the macroscopic sweep and expected recovery efficiency. The flow pattern also controls the choice of the flooding strategy. This study compares CO2 flow patterns between two major classes of reservoirs; first, the United States CO2 flooded reservoirs, considered as benchmark for CO2 application elsewhere, and second, the North Sea class of reservoirs considered as future target for CO2 flooding offshore. An inventory of reservoir data was first prepared by inspecting the literature. North Sea reservoirs are characterised with higher temperatures, higher pressures, thicker pays and higher permeabilities. Well spacing is also larger in the North Sea and these reservoirs are depleted faster. Using appropriate correlations, the in-situ CO2 and oil properties were inferred for each individual reservoir knowing its ambient reservoir conditions. Scaling analysis was used to characterise the CO2 displacing oil process in each reservoir by calculating a few key dimensionless numbers. Numerical simulation of CO2 displacing oil in stochastic permeability fields revealed the CO2 flow pattern in each individual reservoir. Although CO2 and oil densities are comparable in North Sea and United States classes of reservoirs, scaling analysis shows that "gravity numbers" for a CO2 displacing oil process are an order of magnitude larger offshore North Sea. This indicates a more gravity dominated CO2 flooding in the North Sea compared to United States reservoirs principally due to thicker pays and significantly higher permeabilities in this province but not due to larger CO2 and oil density contrast. The "mobility number" for a CO2-oil displacement process is also considerably lower (or better) in the North Sea due to lower North Sea oil viscosities. This indicates, in the absence of gravity, the viscous CO2 flooding is expected to be more stable in the North Sea. "Effective aspect ratios", illustrating the degree of cross flow are also lower in the North Sea mainly due to considerably thicker pay reservoirs in these systems. Visual comparison of displacement profiles in different stochastic permeability fields shows that, unlike the majority of United States CO2 flooded reservoirs where the displacement may be characterised with an unstable viscous dominated process, in the North Sea CO2 flow patterns vary mostly between gravity dominated and stable viscous displacements. Better understanding of the CO2 flow pattern can help in the selection of the appropriate CO2 flooding process e.g. selection between horizontal and gravity stable CO2 flooding or the decision to implement WAG instead of continuous CO2 injection for future provinces targeted for CO2-EOR like the North Sea. North Sea reservoirs thus may benefit from a different CO2 flood design than that observed historically in the United States since their CO2 flow patterns is fundamentally different.

Petroleum-rich basins at a mature stage of exploration and production offer many opportunities for large-scale Carbon Capture and Storage (CCS) since oil and gas were demonstrably contained by low-permeability top-sealing rocks, such as shales. For CCS to work, there must be effectively no leakage from the injection site, so the nature of the top-seal is an important aspect for consideration when appraising prospective CCS opportunities. The Lower Cretaceous Rodby Shale and the Palaeocene Lista Shale have acted as seals to oil and gas accumulations (e.g., the Atlantic and Balmoral fields) and may now play a critical role in sealing the Acorn and East Mey subsurface carbon storage sites. The characteristics of these important shales have been little addressed in the hydrocarbon extraction phase, with an understandable focus on reservoir properties and their influence on resource recovery rates. Here, we assess the characteristics of the Rodby and Lista Shales using wireline logs, geomechanical tests, special core analysis (mercury intrusion) and mineralogical and petrographic techniques, with the aim of highlighting key properties that identify them as suitable top-seals. The two shales, defined using the relative gamma log values (or Vshale), have similar mean pore throat radius (approximately 18 nm), splitting tensile strength (approximately 2.5 MPa) and anisotropic values of splitting tensile strength, but they display significant differences in terms of wireline log character, porosity and mineralogy. The Lower Cretaceous Rodby Shale has a mean porosity of approximately 14 %, a mean permeability of 263 nD (2.58 &times, 10&minus, 19 m2), and is calcite rich and has clay minerals that are relatively rich in non-radioactive phases such as kaolinite. The Palaeocene Lista Shale has a mean porosity of approximately 16% a mean permeability of 225 nD (2.21 &times, 19 m2), and is calcite free, but contains abundant quartz silt and is dominated by smectite. The 2% difference in porosity does not seem to equate to a significant difference in permeability. Elastic properties derived from wireline log data show that Young&rsquo, s modulus, material stiffness, is very low (5 GPa) for the most shale (clay mineral)-rich Rodby intervals, with Young&rsquo, s modulus increasing as shale content decreases and as cementation (e.g., calcite) increases. Our work has shown that Young&rsquo, s modulus, which can be used to inform the likeliness of tensile failure, may be predictable based on routine gamma, density and compressive sonic logs in the majority of wells where the less common shear logs were not collected. The predictability of Young&rsquo, s modulus from routine well log data could form a valuable element of CCS-site top-seal appraisals. This study has shown that the Rodby and Lista Shales represent good top-seals to the Acorn and East Mey CCS sites and they can hold CO2 column heights of approximately 380 m. The calcite-rich Rodby Shale may be susceptible to localised carbonate dissolution and increasing porosity and permeability but decreasing tendency to develop fracture permeability in the presence of injected CO2, as brittle calcite dissolves. In contrast, the calcite-free, locally quartz-rich, Lista Shale will be geochemically inert to injected CO2 but retain its innate tendency to develop fracture permeability (where quartz rich) in the presence of injected CO2.

Solution gas drive following depressurization of oil reservoirs below the bubble point is the oldest and perhaps one of the most challenging oil recovery mechanisms to quantify. Part of the challenge lies in designing repeatable experiments and then translating experimental observations into practical solutions in the field – laboratory depressurization rates are typically orders of magnitude higher than practical field rates. Using a case study we show how pore network modelling can help make sense of the underlying physical mechanisms governing gas flow behaviour in porous media during solution gas drive whilst also serving as a forward modelling tool for developing relative permeability functions for use in field scale simulators. Core scale simulations performed on a pore network anchored to measured petrophysical properties of a 0.23mD chalk core from a North Sea reservoir show a very weak correlation between depletion rate and critical gas saturation, contrary to observations in higher permeability clastic media. In addition, solution gas drive oil recovery was found to increase with higher initial water saturation.

Three-dimensional (3-D) printing provides a fast, cost-effective way to produce and replicate complicated designs with minimal flaws and little material waste. Early use of 3-D printing for engineering applications in the petroleum industry has stimulated further adoption by geoscience researchers and educators. Recent progress in geoscience is signified by capabilities that translate digital rock models into 3-D printed rock proxies. With a variety of material and geometric scaling options, 3-D printing of near-identical rock proxies provides a method to conduct repeatable laboratory experiments without destroying natural rock samples. Rock proxy experiments can potentially validate numerical simulations and complement existing laboratory measurements on changes of rock properties over geologic time scales. A review of published research from academic, government, and industry contributions indicates a growing community of rock proxy experimentalists. Three-dimensional printing techniques are being applied to fundamental research in the areas of multiphase fluid flow and reactive transport, geomechanics, physical properties, geomorphology, and paleontology. Further opportunities for geoscience research are discussed. Applications in education include teaching models of terrains, fossils, and crystals. The integration of digital data sets with 3-D printed geomorphologies supports communication for both societal and technical objectives. Broad benefits that could be realized from centralized 3-D printing facilities are also discussed.

Carbon Capture and Storage (CCS) is an essential tool in the fight against climate change. Any prospective storage site must meet various criteria that ensure the effectiveness, safety and economic viability of the storage operations. Finding the most suitable site for the storage of the captured CO2 is an essential part of the CCS chain of activity. This work addresses the site selection of a second site for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project in the North Sea (offshore northeast Scotland). This secondary site has been designed to serve as a backup and upscaling option for the Acorn Site, and has to satisfy pivotal project requirements such as low cost and high storage potential. The methodology followed included the filtering of 113 input sites from the UK CO2Stored database, according to general and project-specific criteria in a multi-staged approach. This criteria-driven workflow allowed for an early filtering out of the less suitable sites, followed by a more comprehensive comparison and ranking of the 15 most suitable sites. A due diligence assessment was conducted of the top six shortlisted sites to produce detailed assessment of their storage properties and suitability, including new geological interpretation and capacity calculations for each site. With the new knowledge generated during this process, a critical comparison of the sites led to selection of East Mey as the most suitable site, due to its outstanding storage characteristics and long-lasting hydrocarbon-production history, that ensure excellent data availability to risk-assess storage structures. A workshop session was held to present methods and results to independent stakeholders; feedback informed the final selection criteria. This paper provides an example of a criteria-driven approach to site selection that can be applied elsewhere., Project ACT-Acorn is gratefully thanked for funding this study. ACT Acorn, project 271500, received funding from BEIS (UK), RCN (Norway) and RVO (Netherland), and was co-funded by the European Commission under the ERA-Net instrument of the Horizon 2020 programme. ACT Grant number 691712. J. Alcalde is funded by MICINN (Juan de la Cierva fellowship - IJC2018-036074-I). S. Ghanbari is currently supported by the Energi Simulation. Energi Simulation is also thanked for funding the chair in reactive transport simulation held by E. Mackay.

SummaryIn waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.

The detailed characterization of internal fault zone architecture and petrophysical and geomechanical properties of fault rocks is fundamental to understanding the flow and mechanical behaviour of mature fault zones. The Goddo normal fault (Bømlo – Norway) accommodated c. E-W extension related to North Sea Rifting from Permian to Early Cretaceous times [1]. It represents a good example of a mature, iteratively reactivated and thus long-lived (seismogenic?) fault zone, developed in a pervasively fractured granitoid basement at upper crustal conditions in a regional extensional setting.Field characterization of the fault zone’s structural facies and analysis of background fracture patterns in the protolith have been integrated with in-situ petrophysical and geomechanical surveys of the recognized fault zone architectural components. In-situ air-permeability and mechanical directional tests (performed with NER TinyPerm III air-minipermeameter and DRC GeoHammer, L-type Schmidt hammer, respectively) have allowed for the quantification of the permeability tensor and mechanical properties (UCS and elastic modulus) within each brittle structural facies. Mechanical properties measured parallel to fault rock fabric of cataclasite- and gouge-bearing structural facies differ by up to one order of magnitude from those measured perpendicularly to it (~10 MPa vs. 100-200 MPa in UCS, respectively). Accordingly, permeability of cataclasite- and gouge-bearing facies is several orders of magnitude larger when measured parallel to fault-rock fabric than that perpendicular to it (10-0-10-1 D vs. 10-2-10-3 D, respectively). Virtual outcrop models (VOMs) of the fault zone were obtained from high-resolution UAV-photogrammetry. Field measurements of fracture orientations were used for calibration of the VOMs to construct a statistically robust fracture dataset. The results of VOMs structural analysis allowed for the quantification of fracture intensity and geometrical characteristics of mesoscopic fracture patterns within the different domains of the fault zone architecture.Results from field, VOMs structural analysis, and in-situ petrophysical investigations have been integrated into a realistic 3D fault zone model with the software 3DMove (Petex). This model can be used to investigate the influence of mesoscopic fracture patterns, related to either the fault zone or the background fracturing, on the hydro-mechanical behaviour of a mature fault zone. In addition, the evolution of the hydro-mechanical properties through time can be assessed by integrating the progressive development of brittle structural facies and fracture sets developed during the incremental strain and stress history into the model. This contribution proposes a geologically-constrained method to quantify the geometry of 3D fault zones, as a possible tool for models to be adopted in stress-strain analysis, hydraulic characterization and in the mechanical analysis of fault zones.[1] Viola, G., Scheiber, T., Fredin, O., Zwingmann, H., Margreth, A., & Knies, J. (2016). Deconvoluting complex structural histories archived in brittle fault zones. Nature communications, 7, 13448.

The coupling of CO2 emissions and tectonic activity in active plate margins is becoming increasingly prominent, as remote sensing techniques make this relationship readily observable on a global sc...

The alternate injection of CO gas and water (CO WAG) adds more complexity to the development of carbonate oil reservoirs. First, the switching between water and gas cycles causes oscillations in the pressure and flow rate because of variable fluid mobilities. Second, gravity segregation can occur since the CO2 is less dense than water (and oil) under most reservoir conditions. Moreover, since the injected fluids are generally cooler than the initial reservoir temperature, heat exchange is constantly happening because the injected fluids (especially water) extract heat from the reservoir rock as they propagate from cooler to warmer regions. These changes in temperature disturb the flow behaviour not only by modifying the physical properties of the fluids, such as densities and viscosities, but also by enhancing calcite dissolution and subsequent pore space alterations. In this work, we simulate multiphase flow coupled with heat exchange and mineral reactions to model the porosity and permeability changes during CO2 WAG injection in carbonate oil reservoirs. A multilayered model of a limestone reservoir is initialised with 500 bar to calculate calcite volume changes in a more reactive environment comparable with the Brazilian pre-salt, as compared to reported (carbonate) field cases and simulations. Porosity changes are derived from volume change of calcite at each time step, while permeability is updated following the formulation of Carman-Kozeny. Dissolution zones around the injectors are calculated as well as their impact on permeability and injectivity increase. Special considerations are made regarding the mass of calcite that can potentially precipitate in the production system (i.e. scale management). This contibution extends the knowledge about the impacts of calcite dissolution and re-precipitation on CO2 WAG operations in deep carbonate reservoirs. The novelty lies on the investigation of the effects of cross-flow between layers and gravity segregation on the scale deposition. Moreover, this model extends our previous work on twodimensional simulation by including the vertical heterogeneity. We show how reactions proceed in layer of different properties and what are the risks of scale deposition at well perforations for a given vertical profile of initial porosity and permeability.

Summary Modelling the dynamic fluid behaviour of Low Salinity Water Flooding (LSWF) at the reservoir scale is a challenge which requires a coarse grid enable prediction in a feasible timescale. However, evidence shows that using low resolution models will result in a considerable mismatch compared with an equivalent fine scale model with the potential of strong numerically induced oscillations. This work examines two new upscaling methods in a heterogenous reservoir where viscous crossflow takes place to improve the precision of predictions. We apply two approaches to upscaling of the flow to improve precision. In the first upscaling method, we shift the effective salinity range for the coarse model based on algorithms that we have developed to correct for numerical dispersion. The second upscaling method uses appropriate pseudo relative permeability curves that we derive. The shape of this new set of relative permeability is designed based on a modified fractional flow analysis of LSWF that we have developed and captures the relationship between dispersion and the waterfront velocities. This approach removes the need for explicit simulation of salinity transport. We applied these approaches in layered models and for permeability distributed as a correlated random field. Upscaling by shifting the effective salinity range of the coarse model gave a good match to the fine case scenario, while considerable mismatch was observed for traditional upscaling of the absolute permeability only using averaging methods. For highly coarsened models, this method of upscaling reduces the oscillations appear, but they can be apparent. On the other hand, upscaling by using a single (pseudo) relative permeability produced more robust results with a very promising match to the fine scale scenario. These methods of upscaling showed promising results where they were used to upscale fully communicating and non-communicating layers as well as models with randomly correlated permeability. Unlike documented methods in literate, these newly derived methods take into account the crucial effect of numerical dispersion and effective concentration on fluid dynamic using mathematical tools. These methods could be applied for other models where the phase mobilities change as a result of an injected solute, such as surfactant flooding and alkaline flooding. Usually these models use two sets of relative permeability and switch from one to another as a function of the concentration of the solute.

The Acquadolce Subunit on the Island of Elba, Italy, records blueschist facies met- amorphism related to the Oligocene–early Miocene stages of continental collision in the Northern Apennines. The blueschist facies metamorphism is represented by glaucophane- and lawsonite-bearing metabasite associated with marble and calcs- chist. These rock types occur as lenses in a schistose complex representing fore- deep deposits of early Oligocene age. Detailed petrological analyses on metabasic and metapelitic protoliths, involving mineral and bulk-rock chemistry coupled with P–T and P–T–X(Fe 2 O 3 ) pseudosection modelling using PERPLE_X, show that the Acquadolce Subunit recorded nearly isothermal exhumation from peak pressure– temperature conditions of 1.5–1.8GPa and 320–370°C. During exhumation, peak lawsonite- and possibly carpholite- or stilpnomelane-bearing assemblages were overprinted and partially obliterated by epidote-blueschist and, subsequently, albite- greenschist facies metamorphic assemblages. This study sheds new light on the tec- tonic evolution of Adria-derived metamorphic units in the Northern Apennines, by showing (a) the deep underthrusting of continental crust during continental collision and (b) rapid exhumation along ‘cold’ and nearly isothermal paths, compatible with syn-orogenic extrusion.

We propose a workflow to optimise the configuration of multiple interacting continua (MINC) models and overcome the limitations of the classical dual-porosity model when simulating chemically enhanced oil recovery processes. Our new approach captures the evolution of the concentration front inside the matrix, which is key to design a more effective chemically enhanced oil recovery projects in naturally fractured reservoirs. Our workflow is intuitive and based on the simple concept that fine-scale single-porosity models capture fracture-matrix interaction accurately and can hence be easily applied in a commercial reservoir simulator. Results from the fine-scale single-porosity system are translated into an equivalent MINC method that yields more accurate results than the classical dual-porosity model or a MINC method where the shells are arbitrarily selected. Our approach does not require the tuning of capillary pressure curves ("pseudoisation"), diffusion coefficients, MINC shells, or the generation of recovery type curves, all of which have been suggested in the past to model more complex recovery processes. A careful examination of the fine-scale single-porosity model ("reference case") shows that a number of nested shells emerge, describing the advance of the concentration and saturation fronts inside the matrix. The number of shells is related to the required degree of refinement, i.e. the number of shells, in the improved MINC model. Using the results from a fine-scale single-porosity simulation to set up the shells in the MINC model is easy and requires only simple volume calculations. It is hence independent of the chosen simulator. Our improved MINC method yields significantly more accurate results compared to a classical dual-porosity model, a MINC method with equally sized shells, or a MINC model with arbitrarily refined shells for a number of recovery scenarios that cover a range of matrix wettabilities and permeabilities. In general, improved results can be obtained when selecting five or fewer shells in the MINC. However, the actual number of shells is case-specific. The largest improvement is observed for cases when the matrix permeability is low. The novelty of our approach is the easy-to-use method to define shells for a MINC model to predict chemically enhanced oil recovery from naturally fractured reservoirs more accurately, especially in cases where the matrix has low permeability. Hence the improved MINC method is particularly suitable to model chemical EOR processes in (tight) fractured carbonates.

When investigating the storage of CO 2 in deep saline formations, many studies assume a smooth, abrupt interface between the storage and the sealing formations. Typically, though, the surface is irregular, due to sedimentological and stratigraphic effects or structural deformation. In this study, the area where the CO 2 migrates beneath the caprock is investigated. A set of numerical simulations were conducted to investigate the impacts of various factors on CO 2 storage, such as top morphology, tilt, k v /k h ratio and the presence of a transition zone, where there is a gradational change from storage formation to caprock. In the models tested, the k v /k h ratio was most important during the injection period, but after injection ceased, the tilt was more important. The amplitude of the ridges, which were used to represent the top morphology, did not have a large effect but, as expected hindered or encouraged migration depending on whether they were perpendicular or parallel to the tilt. A transition zone can increase the security of storage by lessening the amount of CO 2 accumulating underneath the caprock. Therefore it is important to characterise the interface in terms of the size of irregularities and also in terms of the existence of any transition zone. The latter has not been addressed in previous works. A simple formula was derived to predict the limiting tilt for trapping to occur in models with a sinusoidal interface with wavelength, λ, and amplitude, A. Although this is a simplified approach, it provides a means of assessing whether the topography of the top surface will give rise to significant trapping or not.

This study provides an understanding of the impact of geochemical reactions during and after CO2 injection into a potential storage site. The results of calculations of geochemical reactivity of reservoir rock and of cap rock during and after CO2 injection were performed using a geochemical simulator, with the calculations showing that for these conditions up to 0.5 mol of CO2 can be dissolved per kg of water. The risk of dissolution of primary cements was considered and identified. In addition, the potential of carbonation reactions to permanently sequester CO2 was considered, although these reactions were shown to be very slow relative to other processes. The implications for security of storage are that while dolomite nodules exist in the sandstone formation, these do not contribute significantly to the overall rock strength, and hence the risk of dissolution of the formation or caprock causing significant leakages pathways is very low. Further calculations were performed using a commercial reservoir simulation code to account for brine evaporation, halite precipitation and capillary pressure re-imbibition. The impact on injectivity was found not to be significant during continuous and sustained injection of CO2 at a constant rate. Capillary pressure effects did cause re-imbibition of saline brine, and hence greater deposition, reducing the absolute porosity by up to 13%. The impact of the halite deposition was to channel the CO2, but for the configuration used there was not a significant change in injection pressure. (C) 2016 Published by Elsevier B.V.

Summary Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine-chemistry data set was developed. Systematic analysis of this data set enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, along with improving its prevention and remediation. A study of the individual-ion trends in the produced brine by use of the plot types developed for the reacting-ions toolkit (Ishkov et al. 2009) provides insights into the components that are involved in in-situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion-exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells. A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced-water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate, on the basis of the endpoint formation- and injection-brine compositions and the erroneous assumption that no reactions in the reservoir impact the produced-water composition. Nonetheless, the usual effects of temperature, pressure, and brine composition are accounted for in these calculations by use of classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion, which greatly reduces the severity and potential for scale formation. However, ion-exchange reactions are also observed, and these too affect the scale risk and the effectiveness of scale inhibitors in preventing deposition. Additionally, comprehensive analysis by use of a geochemical model is conducted to predict the evolution of the produced-brine compositions at the production wells and to test the assumptions about which in-situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced-brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behavior. This helps to establish confidence that the model can be used as a predictive tool in this field.

Studies of oil reservoirs show that unconformities may occur between the reservoir and the caprock. At the boundary where the unconformity occurs, there may be a layer of higher permeability compared to the caprock. Such traps may occur at CO 2 storage sites and, therefore, their effect should be investigated. In this work, we simulate CO 2 storage beneath angular unconformities, where sandstone layers have been tilted and eroded prior to the deposition of a caprock. After preliminary studies into the effect of gridding such traps, we describe simulations of a range of 2D and 3D models. The results reveal that migration of CO 2 is influenced by the lithology beneath the unconformity, which could have been modified by weathering or diagenesis. This can have both positive and negative effects on the CO 2 storage capacity and security. It shows that an unconformity model that has a layer of high permeability at the interface between the aquifer and the caprock, as a result of weathering or diagenesis, can contribute to pressure diffusion across the reservoir. This could improve CO 2 sequestration by providing pathways for CO 2 migration to access other parts of the storage complex. However, this could also have a negative effect on the security of CO 2 storage by providing pathways for CO 2 to migrate out of the storage formation and so increase the risk of CO 2 leakage.

Approximately 20,000 metric tons of CO2 were injected in the top sequence of the Mississippian age carbonate reservoir to evaluate potential for CO2 Enhanced Oil Recovery (EOR) and to estimate potential of transitioning to geologic CO2 storage through EOR. This paper focuses on tracking of CO2 plume movement in the reservoir using results of reservoir fluid chemical composition monitoring, CO2 plume and injection impact delineation, and studying effects of faults and naturally occurring fractures on fluid movement at the Wellington Field. We found that one of 12 identified and mapped faults worked as a partial barrier to CO2 movement and the associated damage zone and fracture network performed as a flow conduit, determining CO2 flow paths.

This study aims to understand the process behind the worldwide connection between deep crustal/upper mantle earthquakes and CO2 emissions along faults in rift zones. We do this by studying CO2-induced mineral reactions that facilitate strain localization in peridotites from an ancient rift zone in the Seiland Igneous Province (SIP), North Norway. Strain localization in association with hydration processes is well documented in all types of tectonic settings and has major implications for rheological behavior in active plate margin processes. The implications of CO2-bearing fluids are less studied, though experiments have shown how CO2 can influence the flow laws of olivine by imposing a brittle and more localized type of deformation. This study documents narrow shear zones observed within ultramafic rocks from the Seiland Igneous Province (SIP) comprising large volumes (>20,000 km3) of mafic, ultramafic, silicic and alkaline melts that were emplaced into the lower continental crust (25–30 km) between 570 and 560 Ma under an extensional regime. The extensional shear zones are mm cm-scale and contain extremely fine-grained material with a distinct shape preferred orientation (SPO), but weak to absent crystallographic preferred orientation. The shear zones offset dykes across numerous micro-faults that are documented in areas close to a major fault zone cutting through the area. Within the shear zones, olivine and clinopyroxene react to form orthopyroxene and dolomite at approximately 11 kb and 850 °C according to the reaction: 2 Olivine + Clinopyroxene + 2 CO2 = Dolomite + 2 Orthopyroxene This reaction formed coronas of orthopyroxene and dolomite between olivine and clinopyroxene in the shear zones. In addition, large olivine grains proximal to the shear zones show a microfabric with subgrain walls decorated by rounded grains of dolomite and more irregular and elongated grains of orthopyroxene. Clinopyroxene grains are separated from the enstatite and dolomite by at least hundreds of microns, suggesting material transport within the shear zone. The shear zones thus provide a unique insight into the interplay between CO2-metasomatism and reaction accommodated strain softening. Carbonation-driven cracking and mineral reaction also serves to reduce grain size, making grain boundary sliding an efficient process, further enhancing the rheological contrast between the shear zone and the host rock. The sudden decrease in rock strength could lead to rapid deformation and triggered pseudotachylite formation during earthquake events in the near proximity of the micro-shear zones. Our observations match the relations between CO2 emissions and earthquakes observed in present rift environments such as the East African rift and in New Zealand, and underline the importance of active shear zones as fluid conduits in the lower crust and upper mantle. © 2019 The Authors. Published by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Understanding the reservoir connectivity advances engineering and management decisions and enhances overall field performance. A method to investigate injector to producer connectivity from an identified proportion of the injected brine in the produced water is proposed. Chloride, sodium, boron and lithium are ideal tracers: typically they do not participate in geochemical reactions. These ions track injection water without retardation, and if their concentration differences with formation brine are high enough to overcome measurement errors, then they may be used as indicators of the mixing ratio between injection and formation brines. This paper proposes the use of this mixing ratio to distinguish brines and to calculate the normalised contribution of injected water in the cumulative produced water volume. A producer to injector connectivity plot allows engineers to categorise the pressure support for production wells in one plot. This approach was applied to North Sea field data. A mineral scaling risk analysis was performed using the Injector Contribution characteristic plot. Wells being supported by commingled injected seawater and aquifer water were most at risk of BaSO4 precipitation. Historic data for a field case were analysed to examine potential scaling regimes. A set of well candidates for enhanced oil recovery to reduce residual oil in the oil leg was also identified. Most of the water produced in these wells came from injectors, rather than from the aquifer. Those wells have good communication throughout the oil leg and as a result quick water breakthrough occurs. As well as resulting in an early onset of BaSO4 scaling, an Enhanced Oil Recovery (EOR) chemical that is injected would more quickly reach the producers and therefore the potential for chemical EOR applications can be measured. This suggested metric helps to identify that other wells do not experience much seawater production, but are more strongly supported by the aquifer, and so there would be no apparent benefit in reducing residual oil by injecting chemical. This set of wells might benefit potentially from infill drilling nearby, or conformance control methods. The proposed technique does not require additional sampling to be performed over and above the measured historical produced water compositions that are routinely collected by operators during offshore production for scale management purposes. The analysis to select well candidates for EOR or areas for infill drilling is significantly more challenging using a conventional approach, and we propose that this novel metric of "Producer to Injector connectivity" will be beneficial for the decision making process.

In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues. We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.

Many diverse challenges – political, economic, legal and technical – face the continued development and deployment of geological storage of anthropogenic CO 2 . Among the technical challenges will be the satisfactory proof of storage site security and efficacy. Evidence from many past geotechnical projects has shown the investigations and analyses that are required to demonstrate safe and satisfactory performance will be site specific. This will hold for the geomechanical assessment of saline aquifer storage site integrity where, compared to depleted hydrocarbon fields, there will be no previous pressure response history or rock property characterization data available. The work presented was carried out as part of a project investigating the improvement in levels of confidence in all aspects of saline aquifer site selection and characterization that could be expected with increasing data availability and in-depth analysis. Attention focused on the geomechanical modelling and the rock mechanics data used to populate models of two storage sites in geological settings analogous to those where CO 2 storage might be considered. Coupled geomechanical models were developed from reservoir simulation models initially incorporating generic rock mechanical properties and then laboratory-derived site-specific properties. The models were run in various configurations to investigate the effect of changing the rock mechanical properties on the geomechanical response of the storage systems. Modelling results showed that the pressure response at one site due to low injectivity caused significant potential for fault reactivation. Increasing the number of injection wells, thereby reducing the individual rates needed to deliver the target capacity, reduced the injection pressures and ameliorated, but did not eliminate, this adverse response.

The geometry of the depositional facies and the sandbody continuity in turbidite and fluvial reservoirs controls the stratigraphic heterogeneity, and therefore controls permeability structure. This has implications for CO 2 injectivity from localized pressure build up around injection wells, and migration pathways due to dispersive flow, which results in CO 2 contacting more of the rock volume than would be the case in a homogenous system. This reservoir simulation study is an investigation of the impact of geological heterogeneity in channelized sandstone formations on pressure buildup during CO 2 injection. Four geological models of fluvial and turbidite depositional systems were constructed, typical of those which occur in the Southern North Sea and the Central North Sea regions. Model grid cells were reduced to less than 10 m in places to properly represent the individual channel structures and 2 m near wellbores. This presented a challenge for simulation to capture the impact of injectivity accurately with high resolution for a basin-scale model. Sensitivity studies were carried out in two groups with different net to gross (NTG) ratios and mean permeabilities. The simulation results showed that connectivity to sand-body volumes, through the individual fluvial channel interconnections, may be poor, and so CO 2 does not readily access the entire volume. Furthermore, if the mean permeability is less than 10 mD, only NTG, or the volume fraction of high permeability channels, affects the injectivity; the facies type, i.e. fluvial or turbidite, does not affect strongly the minimum injectivity for all models with 80% sand.

The migration of CO 2 stored in deep saline aquifers depends on the morphology of the top of the aquifer. Topographical highs, such as anticlines, may trap CO 2 and limit the distance migrated, or elevated ridges may provide pathways enabling CO 2 to migrate further from the injector. For example, seismic data of the Utsira formation at the Sleipner storage site indicates that a branch of the CO 2 plume is moving to the north [1] . It is therefore important to study the interface between the aquifer and the caprock when assessing risk as CO 2 storage sites. Undulations in the top surface of an aquifer may either be caused by sedimentary structures [2] , or by folding. In addition, irregularities may be generated by faulting [2] . Large-scale features are detected using seismic data (i.e. structures with amplitudes greater than 10 m), and such structures will generally be included in reservoir or aquifer models. However, smaller- scale features could also have an effect on a CO 2 plume migration, and this is the topic of our study. We have conducted simulations in models with a range of top-surface morphology, and have examined the distance migrated and the amount of dissolution. The results from this study suggest that the effects of sub-seismic variations in the topography of the aquifer/caprock interface are unlikely to have a significant impact on the migration and dissolution of CO 2 in a saline aquifer, compared with tilt or permeability anisotropy. The results were most sensitive to the kv/kh ratio during the injection period.

The Bunter Sandstone Formation in the UK Southern North Sea has the potential to become an important CO2 storage unit if carbon dioxide capture and storage becomes a widely deployed option for the mitigation of greenhouse gases. A detailed geological model of a region of the Bunter Sandstone consisting of four domed structural closures was created using existing seismic, well log and core data. Compositional simulation of CO2 injection was performed to estimate the storage capacity of domes within the system. The injection was constrained by both pressure and CO2 migration criteria, and the storage efficiencies of the domes (volume of stored CO2 divided by the pore volume of the dome) were calculated when injection ceased. A sensitivity study evaluated the effect of varying the total aquifer volume, reservoir heterogeneity and injection well location. A wide range of storage efficiency values were obtained across the different simulation cases, ranging from 4% (closed dome) to 33% (homogeneous model). Intra-reservoir heterogeneity, specifically in the form of continuous low permeability layers has an important effect on storage capacity in dome-like structures, because it increases the tendency for CO2 to migrate laterally from the storage complex via structural spill points.

A series of waterflood simulations were performed to investigate the effect of basinal position and facies permeability within a turbidite sheet system on oil recovery efficiency. Simulations used three-dimensional outcrop models of the Peira Cava system, comprising gravel, sandstone, thin-bedded heterolithic and mudstone facies. Recovery efficiency declines with increasing permeability heterogeneity and is influenced by the interaction of vertical bed-permeability trends and flood-front gravity slumping. The occurrence of gravels with permeabilities lower than overlying sandstones produces optimum recoveries. High permeability gravels act as thief zones, enhanced by downward gravity slumping, reducing normalized recovery by up to 34 %. The effect of thief zones on recovery is related to their permeability contrast, abundance, thickness, lateral continuity, vertical position within permeable units and the permeability of underlying facies. Proximal to distal stratigraphic variations produce relatively small differences in normalized recovery of up to 13 % in models with the highest permeability heterogeneity. Differences in recovery are interpreted to reflect spatial trends in facies architecture, which determine the effectiveness of high permeability gravel thief zones. The poorest recovery is recorded from the medial model where recovery is lower than distal areas because of higher gravel abundance and thicknesses and lower compared to proximal areas because of the higher lateral continuity of gravels and underlying low-permeability mudstones.

When simulating foam floods, uncertainties exist in both the foam and reservoir parameters however the combination of these uncertainties are rarely incorporated in forecasting. Foam flooding is an effective enhanced oil recovery method that controls mobility, reduces gas relative permeability, delays gas breakthrough and helps improve sweep efficiency. Thus it is often used in highly heterogeneous reservoirs where significant subsurface uncertainties exist. Foam uncertainties exist as (a) foam stability is controlled by a number of factors such as critical water and surfactant concentrations, brine salinity, and oil saturation which are unknown in the subsurface spatially and (b) foam flood simulation requires the accurate description of multiple parameters used in the foam flood models which are unknown. This study quantifies and compares the impact of uncertainties associated with foam model parameters with the heterogeneity of a fractured carbonate reservoir, an analogue to the highly prolific Arab D formation. Foam model parameters are not known a-priori but can be tuned to experimental data, which ideally represent a range of foam regimes and reservoir conditions. Geological heterogeneities in fractured carbonate reservoirs are complex and include, matrix wettability, fracture density/orientation and initial saturation distribution. To quantify uncertainties geological uncertainties in fractured carbonate reservoirs, an automated framework was used to history match the production response of a fractured carbonate field by varying geological parameters. This accounts for the geological uncertainties during a waterflood, which are then combined with foam uncertainties from experimental analysis in the optimisation step, by optimising the mean response of the model to foam flooding across a range of geological and foam scenarios. Our workflow used a combination of Particle Swarm Optimisation for history matching and manual optimisation, the final results of which show a wide range of possible impacts of foam flooding from different but equally well matched reservoirs. The novelty of our work is that it demonstrates how parameters that control foam stability and hence effectiveness in mobility control are related to both foam properties and geological uncertainty. Carrying these uncertainties into foam model properties from core to field scale will translate into considerably more robust estimates of uncertainty when predicting field-scale recovery compared to simulations that only consider uncertainty in the reservoir model.

The Bunter Sandstone Formation in the Southern North Sea is folded into a number of simple 4-way dip-closed structures (domes). Most of these structures are saline water-bearing, although some of them do contain significant gas accumulations, suggesting that the brine-saturated domes may have potential for the long-term storage of CO2. This study investigates the effect of geological structure and heterogeneity on CO2 storage through the use of geological models and reservoir simulation. Dynamic modeling focussed on the determination of the storage efficiency of a particular dome and from this, its CO2 storage capacity. Under initial modeling conditions, a storage efficiency of around 19% was derived, though this is shown to be highly sensitive to a range of uncertain parameters. An interesting interplay exists between the reservoir heterogeneity and dome structure, whereby the evolving CO2 plume is prevented from rising buoyantly to the top of the formation by the presence of impermeable horizons, which facilitates rapid migration towards the structural spill-points. Sensitivity analysis further emphasizes the importance of characterizing reservoir heterogeneity in studies for long-term carbon capture and storage.

One of the many challenges facing carbon capture and storage will be to provide convincing evidence of the geomechanical integrity of any proposed geological storage site. Contrary to storage in depleted hydrocarbon fields, storage in saline aquifer presents many more unknowns in this respect because there will probably be no known previous pressure response history or rock property characterisation. The work presented here was carried out as part of a project investigating the improvement in levels of confidence in all aspects of site selection and characterisation that could be expected with increasing data availability for saline aquifers. Attention here was focused on geomechanical modelling and the rock mechanics data used to populate these models. The models initially used generic geomechanical property data and the potential for shear failure of the intact rock and (fault) reactivation of fractured rock investigated. The models were then updated with laboratory measured rock mechanical properties for actual rock from the proposed storage system locality. The modelled results were changed marginally but did not identify any significant issues of criticality because of the relative geomechanical “benignness” of the storage site.

It is generally assumed that scale inhibitor squeeze treatments in production wells are displaced radially into the formation, since it is normal to pump these treatments below the fracture pressure. However, it is known that thermal stresses as a result of injecting cold fluids can result in thermally induced fractures (TIF). The first question that this paper addresses is the evidence of thermal fracturing during low volume ( The process involves modelling of fractured and unfractured treatments to identify what are the advantages and disadvantages of temporarily fracturing a well during a squeeze treatment in terms of inhibitor placement. While inhibitor may be placed at a greater distance from the wellbore if the formation is fractured during the treatment, the surface area of rock contacted during the treatment may be less than is the case in radial displacements. Issues such as consolidated vs unconsolidated formations, initial reservoir temperature, fluid temperature at the sandface during injection, injection rate and fracture dimensions should be considered. In general, this work demonstrates that there are clear advantages to temporarily fracturing a well during a squeeze treatment, depending on the inhibitor return concentrations required to prevent mineral scale formation.

Climatological characteristics of mesoscale convective vortices (MCVs) occurring in the state of Oklahoma during the late spring and summer of four years are investigated. The MCV cases are selected based on vortex detection by an objective algorithm operating on analyses from the Rapid Update Cycle (RUC) model. Consistent with a previous study, true MCVs represent only about 20% of the mesoscale relative vorticity maxima detected by the algorithm. The MCVs have a broad range of radii and intensities, and their longevities range between 1 and 54 h. Their median radius is about 200 km, and their median midlevel relative vorticity is 1.2 × 10−4 s−1. There appears to be no significant relationship between MCV longevity and intensity. Similar to past estimates, approximately 40% of the MCVs generate secondary convection within their circulations. The mean synoptic-scale MCV environment is determined by the use of a RUC-based composite analysis at four different stages in the MCV life cycle, defined based on vortex detection by the objective algorithm. MCV initiation is closely tied to the diurnal cycle of convection over the Great Plains, with MCVs typically forming in the early morning, near the time of maximum extent of nocturnal mesoscale convective systems (MCSs). Features related to the parent MCSs, including upper-level divergent outflow, midlevel convergence, and a low-level jet, are prominent in the initiating MCV composite. The most significant feature later in the MCV life cycle is a persistent mesoscale trough in the midlevel height field. The potential vorticity (PV) structure of the composite MCV consists of a midlevel maximum and an upper-level minimum, with some extension of elevated PV into the lower troposphere as the vortex matures. The environment immediately downshear of the MCV is more conducive to secondary convection than the environment upshear of the MCV. This midlatitude MCV climatology represents an extension of past individual case studies by providing mean characteristics of a large MCV population; these statistics are suitable for the verification of MCV simulations. Also presented is the first high-resolution composite analysis of the MCV environment at different stages of the MCV life cycle, which will aid in identifying and forecasting these systems.

Surface pressure manifestations of mesoscale convective vortices (MCVs) that traversed Oklahoma during the periods May–August 2002–05 are studied using the Weather Surveillance Radar-1988 Doppler (WSR-88D), the Oklahoma Mesonet, and the NOAA Profiler Network data. Forty-five MCVs that developed from mesoscale convective systems (MCSs) have been investigated, 28 (62%) of which exhibit mesolows detectable at the surface. Within this group, three distinct patterns of precipitation organization and associated mesolow evolution have been identified. The remaining 17 (38%) of the cases do not contain a surface mesolow. Two repeating patterns of precipitation organization are identified for the latter group. The three categories of MCVs possessing a surface mesolow are as follows. Nineteen are classified as “rear-inflow-jet MCVs,” and tend to form within large and intense asymmetric MCSs. Rear inflow into the MCS, enhanced by the development of an MCV on the left-hand side relative to system motion, produces a rear-inflow notch and a distinct surface wake low at the back edge of the stratiform region. Hence, the surface mesolow and MCV are displaced from one another. Eight are classified as “collapsing-stratiform-region MCVs.” These MCVs arise from small asymmetric MCSs. As the stratiform region of the MCS weakens, a large mesolow appears beneath its dissipating remnants due to broad subsidence warming, and at the same time the midlevel vortex spins up due to column stretching. One case, called a “vertically coherent MCV,” contains a well-defined surface mesolow and associated cyclonic circulation, apparently due to the strength of the midlevel warm core and the weakness of the low-level cold pool. In these latter two cases, the surface mesolow and MCV are approximately collocated. Within the group of MCVs without a surface mesolow, 14 are classified as “remnant-circulation MCVs” containing no significant precipitation or surface pressure effects. Finally, three are classified as “cold-pool-dominated MCVs;” these cases contain significant precipitation but no discernible surface mesolow. This study represents the first systematic analysis of the surface mesolows associated with MCVs. The pattern of surface pressure and winds accompanying MCVs can affect subsequent convective development in such systems. Extension of the findings herein to tropical oceans may have implications regarding tropical cyclogenesis.

The fate of carbon dioxide (CO2) injected into a deep saline aquifer depends largely on the geological structure within the aquifer. For example, low permeability layers, such as shales or mudstones, will act as barriers to vertical flow of CO2 gas, whereas high permeability channels may assist the lateral migration of CO2. It is therefore important to include permeability heterogeneity in models for numerical flow simulation As an example of a heterogeneous system, a model of fluvial-incised valley deposits was used. Flow simulations were performed using the generalized equation-of-state model—greenhouse gas software package from Computer Modelling Group, which is a compositional simulator, specially adapted for CO2 storage. The impacts of residual gas and water saturations, gas diffusion in the aqueous phase, hysteresis, and permeability anisotropy on the distribution of CO2 between the gaseous and aqueous phases were examined. Gas diffusion in the aqueous phase was found to significantly enhance solubility trapping of CO2, even when hysteretic trapping of CO2 as a residual phase is taken into account.

Summary Extensive studies have confirmed that altering ionic composition of injection water has a big impact on the ultimate oil recovery. Different mechanisms have been proposed to explain the positive effects of Smart Water injection, but no single one is universally accepted as the dominant mechanism. Therefore, in the paper, we conduct a three-dimensional reactive transport modelling study to investigate the geochemical processes during seawater flooding altering seawater with different sulphate concentrations injected into a carbonate reservoir which can help the understanding of the possible mechanism behind Smart Water injection. A series of calcite and anhydrite mineral reactions are key in situ chemical reactions in the study. At the early stage, CO2 partitioning from the hydrocarbon phase into the brine causes significant calcite dissolution. This process can be enhanced by increasing sulphate concentration in the injection water. Sulphate concentration in the injection has a significant impact on whether the calcite is continuously dissolved or not after the CO2 front passes. In the modelling cases that include thermal transport, reservoir temperature is cooled by injection water, and thus anhydrite precipitation and calcite dissolution are decreased.