ALBERT

Description: This paper successfully applied the geoengineering workflow for integrated well-test analysis to characterise fluid flow in a newly discovered fractured reservoir in the Barents Sea. A reservoir model containing fractures and matrix was built and calibrated using this workflow to match complex pressure transients measured in the field. We outline different geological scenarios that could potentially reproduce the pressure response observed in the field, highlighting the challenge of non-uniqueness when analysing well-test data. However, integrating other field data into the analysis allowed us to narrow the range of uncertainty, enabling the most plausible geological scenario to be taken forward for more detailed reservoir characterisation and history matching. The results provide new insights into the reservoir geology and the key flow processes that generate the pressure response observed in the field. This paper demonstrates that the geoengineering workflow used here can be applied to better characterise naturally fractured reservoirs. We also provide reference solutions for interpreting well-tests in fractured reservoirs where troughs in the pressure derivative are recognisable in the data.

Description: The geometry, distribution, and rock properties (i.e. porosity and permeability) of turbidite reservoirs, and the processes associated with turbidity current deposition, are relatively well known. However, less attention has been given to the equivalent properties resulting from laminar sediment gravity-flow deposition, with most research limited to cogenetic turbidite-debrites (i.e. transitional flow deposits) or subsurface studies that focus predominantly on seismic-scale mass-transport deposits (MTDs). Thus, we have a limited understanding of the ability of sub-seismic MTDs to act as hydraulic seals and their effect on hydrocarbon production, and/or carbon storage. We investigate the gap between seismically resolvable and sub-seismic MTDs, and transitional flow deposits on long-term reservoir performance in this analysis of a small (

Description: Recently, time-lapse seismic (4D seismic) has been steadily used to demonstrate the relation between field depletion and 4D seismic response, subsequently to have more efficient field management. A key component of the reservoir monitoring is the knowledge of fluid movement and pressure variations. This information is vital to assist infill drillings and a trustworthy source to update reservoir models, consequently improving model-based reservoir management and decision-making process. However, in practice the 4D seismic interpretation of reservoirs with multipart production regime possesses ambiguities through different levels of uncertainty. Complex nature of some 4D seismic signals emphasizes the roles of competing effects, geology, rock and fluid interactions. Hence, a reliable 4D interpretation requires an interdisciplinary approach entailing data analysis and insights from geophysics, engineering and geology. In this research, a step-wise workflow was introduced to reduce uncertainties in the 4D seismic interpretation and provide diagnoses to perform better reservoir surveillance. In parallel, the workflow expresses the use of engineering data analysis to conduct a consistent interpretation and encompasses the 3D and 4D seismic attributes with engineering data analysis. This study is implemented in a Brazilian heavy-oil offshore field where production started in 2013. The field experienced intense production activity up to 2016, making the deep-water field an ideal candidate to explore the challenges in interpreting complex 4D signals. Beyond these challenges, significant understanding of reservoir behavior is obtained and suggestions are made to improve the reservoir simulation model, which could support reservoir engineers with data assimilation applications.

Description: In order to reduce uncertainties around CO2 containment for the South West Hub CCS site (Western Australia), conceptual fault hydrodynamic models are defined, and numerical simulations are carried out. These simulations model worst-case scenarios with a plume reaching a main compartment bounding fault near the proposed injection depth and at the faulted interface between the primary and secondary containment interval.The conceptual models incorporate host rock and fault properties accounting for fault zone lithology, cementation, and cataclastic processes but with no account for geomechanical processes as the risk of reactivation is perceived as low. Flow simulations are performed to assess cross- and up-fault migration in case of plume-faults interaction.Results near the injection depth suggest that the main faults are likely to experience significant reduction in transmissivity and impede CO2 flow. This could promote migration of CO2 vertically or along the stratigraphic dip.Results near the interface between the primary and secondary containment intervals show that none of the main faults would critically control CO2 flow nor would they act as primary leakage pathways. CO2 flow is predicted to be primarily controlled by the sedimentological morphology. The presence of baffles in the secondary containment interval is expected to be associated with local CO2 accumulations; additional permeability impacts introduced by faults is minor.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: Geological carbon sequestration (GCS) is necessary to help meet emissions reduction goals, but groundwater contamination may occur if CO2 and/or brine were to leak out of deep storage formations into the shallow subsurface. For this study, a natural analogue was investigated: in the Virgin River Basin of southwest Utah, water with moderate salinity and high CO2 concentrations is leaking upward into shallow aquifers that contain heavy metal-bearing concretions. The aquifer system is comprised of the Navajo and Kayenta formations, which are pervasive across southern Utah and have been considered as a potential GCS injection unit where they are sufficiently deep. Numerical models of the site were constructed based on measured water chemistry and head distributions from previous studies. Simulations were used to improve understanding of the rate and distribution of the upwelling flow into the aquifers, and to assess the reactive transport processes that may occur if the upwelling fluids were to interact with a zone of iron oxide and other heavy metals, representing the concretions that are common in the area. Various mineralogies were tested, including one in which Pb+2 was adsorbed onto ferrihydrite, and another in which it was bound within a solid mixture of litharge (PbO) and hematite (Fe2O3). Results indicate that metal mobilization depends strongly on the source zone composition and that Pb+2 transport can be naturally attenuated by gas phase formation and carbonate mineral precipitation. These findings could be used to improve risk assessment and mitigation strategies at geological carbon sequestration sites.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: Carbon capture, utilization and storage (CCUS) is considered a major part of the Portuguese strategy for reducing CO2 emissions. Some industrial sectors, the most prominent being the cement sector, require the implementation of CO2 storage to reach carbon neutrality by 2050. This article presents and characterises the areas with potential for CO2 storage in mainland Portugal. The lithostratigraphic and tectonic frameworks of the onshore and offshore basins are presented; a site screening process was conducted, based on basin- and regional-scale assessments, resulting in the definition of eight possible storage clusters, seven of which are offshore. The storage capacity was estimated for those clusters, with a central (P50) value of 7.09 Gt; however, the most interesting locations are in the Lusitanian Basin (West Iberian Margin), both onshore and offshore, as they present high capacity and are located favourably in relation to the industrial CO2 emitters. Considering only the potential sites of this basin, their storage capacities are greater than 3 Gt CO2, of which 259 Mt are onshore.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: The construction of subsurface reservoir models is typically aided by the use of outcrops and modern analogue systems. We show how process- based models of depositional systems help develop and substantiate reservoir architectural concepts. Process-based models can simulate assumptions relating to the physical processes influencing sedimentary deposition, accumulation and erosion on the resultant 3D sediment distribution. In this manner, a complete suite of analogue geometries can be produced by implementing different sets of boundary conditions based on hypotheses of depositional controls. Simulations are therefore not driven by a desired/ defined outcome in the depositional patterns, but their application to date in reservoir modelling workflows has been limited because they cannot be conditioned to data such as well logs or seismic information.In this study a reservoir modelling methodology is presented that addresses this problem using a two-step approach: process-based models producing 3D sediment distributions, which are subsequently used to generate training images for multi-point geostatistics.The approach has been tested on a dataset derived from a well-exposed outcrop from central Utah. The Ferron Sandstone Member includes a shallow marine deltaic interval that has been digitally mapped using a high resolution Unmanned Aerial Vehicle (UAV) survey in 3D to produce a virtual outcrop (VO). The VO was used as the basis to build a semi-deterministic outcrop reference model against which to compare the results of the combined process/Multiple Point Statistics (MPS) geostatistical realizations. Models were compared statically and dynamically by flow simulation.When used with a dense well dataset, the MPS realizations struggle to account for high levels of non-stationarity inherent in the depositional system that are captured in the process-based training image. When trends are extracted from the outcrop analogue and used to condition the simulation, the geologically realistic geometries and spatial relationships from the process-based models are directly imparted onto the modelling domain, whilst simultaneously allowing the facies models to be conditioned to subsurface data.When sense-checked against preserved analogues, this approach reproduces more realistic architectures than traditional, more stochastic techniques.

Description: Secure retention of CO2 in geological reservoirs is essential for effective storage. Solubility trapping, the dissolution of CO2 into formation water, is a major sink on geological timescales in natural CO2 reservoirs. Observations during CO2 injection, combined with models of CO2 reservoirs, indicate the immediate onset of solubility trapping. There is uncertainty regarding the evolution of dissolution rates between the observable engineered timescale of years and decades, and the 〉10 kyr state represented by natural CO2 reservoirs. A small number of studies have constrained dissolution rates within natural analogues. The studies show that solubility trapping is the principal storage mechanism after structural trapping, removing 10–50% of CO2 across whole reservoirs. Natural analogues, engineered reservoirs and model studies produce a wide range of estimates on the fraction of CO2 dissolved and the dissolution rate. Analogue and engineered reservoirs do not show the high fractions of dissolved CO2 seen in several models. Evidence from natural analogues supports a model of most dissolution occurring during emplacement and migration, before the establishment of a stable gas–water contact. A rapid decline in CO2 dissolution rate over time suggests that analogue reservoirs are in dissolution equilibrium for most of the CO2 residence time.Supplementarymaterial: Dissolution rate for all plots and exponential function curves for scenarios A and B are available at https://doi.org/10.6084/m9.figshare.c.5476199Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: The Sea of Hebrides Basin and Minch Basin are late Paleozoic–Mesozoic rift basins located to the NW of the Scottish mainland. The basins were the target of small-scale petroleum exploration from the late 1960s to the early 1990s, with a total of three wells drilled within the two basins between 1989 and 1991. Although no commercially viable petroleum discoveries were made, numerous petroleum shows were identified within both basins, including a gas show within the Upper Glen 1 well in Lower Jurassic limestones. Organic-rich shales have been identified throughout the Jurassic succession within the Sea of Hebrides Basin, with one Middle Jurassic (Bajocian–Bathonian) shale exhibiting a total organic carbon content of up to 15 wt%. The focus of this study is to review the historical petroleum exploration within these basins, and to evaluate whether the conclusions drawn in the early 1990s of a lack of prospectivity remains the case. This was undertaken by analysis of seismic reflection data, gravity and aeromagnetic data, and sedimentological data from both onshore and offshore wells, boreholes and previously published studies. The key findings from our study suggest that there is a low probability of commercially sized petroleum accumulations within either the Sea of Hebrides Basin or the Minch Basin. Ineffective source rocks, likely to be due to low maturities (due to lack of burial) and the fact that the encountered Jurassic and Permian–Triassic reservoirs are of poor quality (low porosity and permeability), has led to our interpretation of future exploration being high risk, with any potential accumulations being small in size. While petroleum accumulations are unlikely within the basin, applying the knowledge obtained from this study could provide additional datasets and insight into petroleum exploration within other NE Atlantic margin basins, such as the Rockall Trough and the Faroe–Shetland Basin.

Description: The thick and heterogeneous salt section in the Santos Basin, offshore Brazil, imposes great challenges in accessing the pre-salt hydrocarbon reservoirs, especially in relation to seismic imaging, signal quality and depth positioning. Some problems arise from the current velocity models for the salt section, which, for the majority, assume that the salt is a homogeneous halite layer. In the Santos Basin, the commonly assumed salt – halite – only makes up to 80% of the mineral in this section. The inclusion of other salts as stratification in the velocity models, based on seismic attributes, has achieved good results in the last decade, especially for depth resolution. In this work, we analyse the benefits of different velocity models, considering presence/absence of salt stratification and comparing the gross rock volume above the oil–water contact. The results show a significant effect on the depth resolution of the events, as well as on volume estimation, indicating that the greater the reliability captured by the complex velocity models, the greater the confidence in the resulting volumetric information.

Description: Aptian siliciclastic onshore deposits of the Mucuri Member are important reservoirs in the Espírito Santo Basin (eastern Brazil). A detailed quantitative petrographical and textural analysis of well core samples was performed in order to unravel their depositional processes and conditions, in relation to previously proposed depositional models. The results allowed differentiation between two groups of sandstone samples, characterized by different textural characteristics associated to different depositional processes and environments within the Mucuri depositional system. Fluvial sandstones are represented by medium- to coarse-grained, poorly sorted arkoses, rich in plutonic rock fragments and feldspar grains, mainly transported by traction. Coastal-lacustrine sandstones correspond to very fine- to fine-grained, moderately sorted micaceous arkoses, mainly transported in suspension. The application of a discriminant function based on grain-size parameters validated previously proposed depositional settings for the studied sample groups. The combination of grain-size and shape data revealed differences in hydraulic equivalence and shape between grains from different depositional settings. In terms of hydraulic equivalence, micas in the fluvial sediments present lower settling velocity values, in contrast to the relatively large mica grains in the coastal sediments, which are hydraulically equivalent with the associated quartz and feldspar grains. The results of this study provide key information regarding depositional conditions (transportation mechanisms, grain-settling velocity and mineral hydraulic fractionation) at the margins of the Aptian pre-salt system, which can constrain the hydrological conditions and the sediment type available for distal lacustrine areas.

Description: Outcrops are valuable for analogous subsurface reservoirs in supplying knowledge of fine-scale spatial heterogeneity pattern and stratification types, which are difficult to obtain from subsurface reservoir cores, well logs or seismic data. For petrophysical properties in a domain where the variations are relatively continuous and not dominated by abrupt contrasts, the spatial heterogeneity pattern can be characterized by a semivariogram model. The outcrop information therefore has the potential to constrain the semivariogram for subsurface reservoir modelling, even though it represents different locations and depths, and the petrophysical properties may differ in magnitude or variance. However, the use of outcrop-derived spatial correlation information for petrophysical property modelling in practice has been challenged by the scale difference between the small support volume of the property measurements from outcrops and the typically much larger grid cells used in reservoir models. With an example of modelling the porosity of an outcrop chalk unit in eastern Denmark, this paper illustrates how the fine-scale spatial correlation information obtained from the sampling of outcrops can be transferred to coarser-scale models of analogue rocks. The workflow can be applied to subsurface reservoirs and ultimately improves the representation of geological patterns in reservoir models.

Description: We use 3D seismic reflection data from the Levant margin, offshore Lebanon to investigate the structural evolution of the Messinian evaporite sequence, and how intra-salt structure and strain varies within a thick salt sheet during early-stage salt tectonics. Intra-Messinian reflectivity reveals lithological heterogeneity within the otherwise halite-dominated sequence. This leads to rheological heterogeneity, with the different mechanical properties of the various units controlling strain accommodation within the deforming salt sheet. We assess the distribution and orientation of structures, and show how intra-salt strain varies both laterally and vertically along the margin. We argue that units appearing weakly strained in seismic data may in fact accommodate considerable subseismic or cryptic strain. We also discuss how the intra-salt stress state varies through time and space in response to the gravitational forces driving deformation. We conclude that efficient drilling through thick, heterogeneous salt requires a holistic understanding of the mechanical and kinematic development of the salt and its overburden. This will also enable us to build better velocity models that account for intra-salt lithological and structural complexity in order to accurately image sub-salt geological structures.

Description: Natural open fractures are present in sidewall cores and in whole-core samples from pre-salt reservoirs in the licence block BM-C-33 in the Campos Basin, Brazil. Open fractures are also observed in borehole image logs, and fracture densities are in general high. The highest density of open fractures is seen in the damage zones above and below larger cavities (amalgamated cavern damage zones (ACDZs)). Outside the ACDZs the fracture density is high in silicified carbonates, where it tends to increase with decreasing porosity. Clean dolomites are less fractured than the silicified interval, while the less brittle argillaceous dolomites have the lowest fracture density. Some fractures appear vuggy on borehole image logs, and fracture densities are high close to vugs and larger cavities. The positive correlation between fractures and vugs is caused by flow of dissolving fluids through open fractures, and fracturing at stress concentrations around vugs. Two major fault zones have been interpreted from borehole image logs that have damage zones with very high fracture density. The well-test permeability is much greater than the matrix permeability estimated from sidewall core and log measurements. This excess permeability is attributed to fractures, in combination with caverns and intervals with frequent vugs.

Description: Three different outcrops are selected in this study, each representing a shallow-marine system with varying heterogeneity provided by siliciclastic–carbonate mixing that may form a small or large stratigraphic trap. The impact of these styles of mixed facies on CO2 storage is relatively poorly known. This study demonstrates the significance of these systems for safe CO2 geological storage, as stratigraphic traps are likely to be a significant feature of many future storage sites. The three 3D models are based on: (1) the Grayburg Formation (USA), which displays spatial permeability linked to variations in the mixture of siliciclastic–carbonate sediments; (2) the Lorca Basin outcrop (Spain), which demonstrates the interfingering of clastic and carbonate facies; and (3) the Bridport Sand Formation outcrop (UK), which is an example of a layered reservoir and has thin carbonate-cemented horizons. This study demonstrates that facies interplay and associated sediment heterogeneity have a varying effect on fluid flow, storage capacity and security. In the Grayburg Formation, storage security and capacity are not controlled by heterogeneity alone but are influenced mainly by the permeability of each facies (i.e. permeability contrast), the degree of heterogeneity and the relative permeability characteristic of the system. In the case of the Lorca Basin, heterogeneity through interfingering of the carbonate and clastic facies improved the storage security regardless of their permeability. For the Bridport Sand Formation, the existence of extended sheets of cemented carbonate contributed to storage security but not storage capacity, which depends on the continuity of the sheets. These mixed systems especially minimize the large buoyancy forces that act on the top seal and reduce the reliance of the storage security on the overlying cap rock. They also increase the contact area between the injected CO2 and brine, thereby promoting the CO2 dissolution processes. Overall, reservoir systems with mixed carbonate–siliciclastic facies contribute to improving the safe and effective storage of CO2.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: With the increasing demand for CO2 storage into the subsurface, it is important to recognize that candidate formations may present complex stress conditions and material characteristics. Consequently, modelling of CO2 injection requires the selection of the most appropriate constitutive material model for the best possible representation of the material response. The authors focus on modelling the geomechanical behaviour of the reservoir material, coupled with multi-phase flow solution of CO2 injection into a saline saturated medium. It is proposed to use the SR3 critical state material model which considers a direct link between strength-volume-permeability that evolves during the simulation; furthermore the material is considered to yield prior to reaching a peak strength in agreement with experimental observations. Verification of the material model against established laboratory tests is conducted, including multi-phase flow accounting for relative permeabilities and fluid densities. Multi-phase flow coupled to advanced geomechanics provides a holistic approach to modelling CO2 injection into sandstone reservoirs. The resulting injection pressures, CO2 migration extent and patterns, formation dilation and strength reduction are compared for a range of in-situ porosities and incremental material enhancements. This work aims to demonstrate a numerical modelling framework to aid in the understanding of geomechanical responses to CO2 injection for safe and efficient deployment and is particularly applicable to CO2 sequestration in less favourable aquifers with a relatively low permeability, receiving CO2 from a limited number of injection wells at high flow rates. The proposed framework can also enable additional features to be incorporated into the model such as faults and detailed overburden representation.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Description: A quantitative seismic interpretation study is presented for the Lower Cretaceous Tuxen reservoir in the Valdemar Field, which is associated with heterogeneous and complex geology. Our objective is to better outline the reservoir quality variations of the Tuxen reservoir across the Valdemar Field. Seismic pre-stack data and well logs from two appraisal wells form the basis of this study. The workflow used includes seismic and rock physics forward modelling, attribute analysis, a coloured inversion, and a Bayesian pre-stack inversion for litho-fluid classification. Based on log data, the rock physics properties of the Tuxen interval reveal that the seismic signal is more governed by porosity than water-saturation changes at near-offset (or small angle). The coloured and Bayesian inversion results were generally consistent with well-log observations at the reservoir level and conformed to interpreted horizons. Although the available data have some limitations and the geological setting is complex, the results implied more promising reservoir quality in some areas than others. Hence, the results may offer useful information for delineating the best reservoir zones for further field development and selecting appropriate production strategies.

Description: In order to calibrate equations for fault seal capacities to a specific basin, faults were analysed using core material from several Neogene hydrocarbon fields in the Vienna Basin, Austria. All studied specimens are siliciclastic rocks that were sampled from a depth interval of

Description: A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from 7 countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c.400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, maximum burial depth as well as the depth at the time of faulting. The results indicate which factors may have the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes.Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

Description: These are commonly interlinked and the relative importance of each can be difficult to unravel. These variables include geological parameters such as depositional environment which has long been considered a key factor influencing the production characteristics of fields. However, quantifying the importance of any single factor, such as depositional environment, is complicated by impact of the other variables (geological and engineering) and their numerous interdependencies.The main aim of this study is to unravel the impact of the depositional environment and primary facies architecture on reservoir performance using an empirical study of oil fields from the Norwegian Continental Shelf. A database of 91 fields, with a total of 7.8 billion barrels of oil in place has been built. Within this a total of 93 clastic reservoirs were classified into three gross depositional environments: continental , paralic/shallow marine and deep marine . The reservoirs were further classified into eight depositional environments in order to provide further granularity and capture their depositional complexities. A further 28 parameters which capture other aspects that also impact production behaviour, such as reservoir depth, fluid type, structural complexity etc were recorded for each reservoir. Principal component analysis (PCA) was utilized to explore the importance of sedimentological dependent variables in the dataset, and to determine the parameters that have the strongest influence on the overall variability of the dataset. PCA revealed that parameters associated with field size and depth of burial had the most influence on recovery factor. Gross depositional environment and other stratigraphic dependent parameters were the most significant geological factors. Fluid properties, such as API and average gas-oil ratio were unexpectedly among the less important parameters.

Description: Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO2–brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO2–methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO2–brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters.Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

Description: An analysis of the petrophysical and diagenetic effects of the emplacement of Cretaceous basaltic lava flows (Serra Geral Formation) on aeolian sandstones (Botucatu Formation) has been undertaken on core samples from the Paraná Basin, Brazil. Between 0.1 to 1 m from the contact zone, acoustic wave velocities and porosities in sandstones show a significantly wider scatter than those located 〉1m away from the lava contact. Higher P-wave values (av. 3759.3 ms-1) occur between 0.1 to 1 m from the lava contact in contrast to those areas 〉 1 m away (av. 3376.8 ms-1), whilst the average porosity is 6.5% near the contact (0.1 to 1 m), and 10.7% away from the contact (〉1 m). Petrographic evaluation reveals two diagenetic pathways responsible for modification of the petrophysical properties: early hydrothermal Mg-rich authigenesis (Type 1) and early chemical dissolution (Type 2). Type 3 diagenesis occurs away from the lava-sediment contact (〉1 m) with the appearance of poikilitic calcite and smectite. The sandstone samples associated with Types 1 and 2 diagenesis display a decrease in porosity and increased acoustic velocities in relation to Type 3, while Type 3 samples show little or no variation in reservoir properties. The lava-induced diagenetic effects at the sandstone-lava contacts (0.1 to 1 m) may form a baffle or seal to fluids around the margins of the sandstone bodies. Therefore, whilst diagenesis associated with lava emplacement may hinder reservoir quality around the margins, the original reservoir properties are preserved within these large sandstone bodies.Supplementary material: Petrophysical and petrographic data is available as annex files. https://doi.org/10.6084/m9.figshare.c.5244473

Description: Naturally fractured reservoirs are important contributors to global petroleum reserves and production. Existing classification schemes for fractured reservoirs do not adequately differentiate between certain types of fractured reservoirs, leading to difficulty in understanding fundamental controls on reservoir performance and recovery efficiency. Three hundred naturally fractured reservoirs were examined to define a new classification scheme that is independent of the type of fracturing and describes fundamentally different matrix types, rock properties, fluid storage and flow characteristics.This study categorises fractured reservoirs in three groups: 1) Type 1: characterized by a tight matrix where fractures and solution-enhanced fracture porosity provide both storage capacity and fluid-flow pathways; 2) Type 2: characterized by a macroporous matrix which provides the primary storage capacity where fractures and solution-enhanced fracture porosity provide essential fluid-flow pathways; and 3) Type 3: characterized by a microporous matrix which provides all storage capacity where fractures only provide essential fluid-flow pathways. Differentiation is made between controls imparted by inherent natural conditions, such as rock and fluid properties and natural drive mechanisms, and human controls, such as choice of development scheme and reservoir management practices.The classification scheme presented here is based on reservoir and production characteristics of naturally fractured reservoirs and represents a refinement of existing schemes. This refinement allows accurate comparisons to be made between analogous fractured reservoirs, and trends and outliers in reservoir performance to be identified. Case histories provided herein demonstrate the practical application of this new classification scheme and the benefits that arise when applying it to the understanding of naturally fractured reservoirs.

Description: 〈span〉〈div〉Abstract〈/div〉At the 2015 United Nations International Climate Change Conference in Paris (COP21), 197 national parties committed to limit global warming to well below 2°C. But current plans and pace of progress are still far from sufficient to achieve this objective. Here we review the role that geoscience and the subsurface could play in decarbonizing electricity production, industry, transport and heating to meet UK and international climate change targets, based on contributions to the 2019 Bryan Lovell meeting held at the Geological Society of London. Technologies discussed at the meeting involved decarbonization of electricity production via renewable sources of power generation, substitution of domestic heating using geothermal energy, use of carbon capture and storage (CCS), and more ambitious technologies such as bioenergy and carbon capture and storage (BECCS) that target negative emissions. It was noted also that growth in renewable energy supply will lead to increased demand for geological materials to sustain the electrification of the vehicle fleet and other low-carbon technologies. The overall conclusion reached at the 2019 Bryan Lovell meeting was that geoscience is critical to decarbonization, but that the geoscience community must influence decision-makers so that the value of the subsurface to decarbonization is understood.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We predict stresses and strains in the Tarfaya salt basin on the West African coast using a 3D static geomechanical model and compare the results against a simplified 2D plane-strain model. Both models are based on present-day basin geometries, are drained, and use a poroelastic description for the sediments and visco-plastic description for salt. We focus on a salt diapir, where an exploratory well has been drilled crossing a major fault. The 3D model shows a significant horizontal stress reduction in sediments at the top of the diapir, validated with measured data later obtained from the well. The 2D model predicts comparable stress reduction in sediments at the crest of the diapir. However, it shows a broader area affected by the stress reduction, overestimating its magnitude by as much as 1.5 MPa. Both models predict a similar pattern of differential displacement in sediments along both sides of the major fault, above the diapir. These displacements are the main cause of horizontal stress reduction detected at the crest of the diapir. Sensitivity analysis in both models shows that the elastic parameters of the sediments have a minimal effect on the stress–strain behaviour. In addition, the 2D sensitivity analysis concludes that the main factors controlling stress and strain changes are the geometry of the salt and the difference in rock properties between encasing sediments and salt. Overall, our study demonstrates that carefully built 2D models at the exploration stage can provide stress information and useful insights comparable to those from more complex 3D geometries.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The inherent heterogeneity of carbonate rocks suggests that carbonate-hosted fault zones are also likely to be heterogeneous. Coupled with a lack of host-fault petrophysical relationships, this makes the hydraulic behaviour of carbonate-hosted fault zones difficult to predict. Here we investigate the link between host and fault rock porosity, permeability and texture, by presenting data from series of host rock, damage zone and fault rock samples from normally faulted, shallowly buried limestones from Malta. Core plug X-ray tomography indicates that texturally heterogeneous host rocks lead to greater variability in the porosity and permeability of fault rocks. Fault rocks derived from moderate to high porosity (〉20%) formations experience permeability reductions of up to six orders of magnitude relative to the host; 〉50% of these fault rocks could act as barriers to fluid flow over production timescales. Fault rocks derived from lower porosity (〈20%) algal packstones have permeabilities that are lower than their hosts by up to three orders of magnitude, which is unlikely to impact fluid flow on production timescales. The variability of fault rock permeability is controlled by a number of factors, including the initial host rock texture and porosity, the magnitude of strain localisation, and the extent of post-deformation diagenetic alteration. Fault displacement has no obvious control over fault rock permeability. The results enable better predictions of fault rock permeability in similar lithotypes and tectonic regimes. This may enable predictions of fault zone sealing potential when combined with data on fault zone architecture.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We use a 2D forward finite-element model to explore how a laterally continuous permeable bed impacts the geological evolution and the geomechanical properties of a salt basin. We show that a permeable bed tilted by rise of a salt diapir substantially increases pore pressure in sediments near the diapir through hydraulically connecting these sediments to deep, high-overpressure sediments far from the diapir. The pore-pressure increase near the diapir has the following significant consequences: it causes a faster rise of the diapir; brings sediments near the diapir close to shear failure 〈span〉in situ〈/span〉; causes unloading of sediments around the crest of the permeable bed; and reduces the margin of appropriate mud weights for drilling near the diapir. The rise of the salt diapir induces concentrated lateral deformation and thereby overpressure in mudrocks encasing the permeable bed in an area near the bottom of the basin. This anomalously high overpressure is in marked contrast with the overpressure in the permeable bed, resulting in a large pore-pressure gradient between the permeable bed and encasing mudrocks. Our study provides insight into the importance of permeable beds to the structural evolution of a salt basin and to the exploration and production of hydrocarbon near salt diapirs.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Traditional methods for imaging salt bodies seldom consider near-salt stress perturbations caused by salt, and the associated velocity perturbations of seismic waves in the sediments near the salt. To demonstrate the importance of stress changes caused by the salt on accurately imaging salt bodies, in this study we develop and apply a combined method of geomechanical stress modelling and salt imaging. We simulate the stress perturbations in sediments induced by a salt sphere using a static geomechanical model, and calculate the associated velocity changes of seismic waves in the sediments by using our model stress perturbations. We use the reverse time migration and imaging method to image the salt sphere, and then analyse the imaging results of two cases including and excluding the effects of stress perturbations by the salt sphere on velocity changes of seismic waves. The results show that the near-salt velocity changes of seismic waves induced by stress perturbations near salt bodies can have a significant impact on the salt imaging. We find that when the effects of near-salt stress perturbations are ignored, the imaging of the salt sphere is clearly distorted: the salt sphere is extended vertically and becomes a salt ellipse with a vertical major axis. In contrast, when we include the effects of near-salt stress perturbations, the imaging of this salt sphere accurately matches the salt geometry and position. Thus, the near-salt stress perturbations should not be ignored in salt imaging. This study provides scientific insights for petroleum geologists and exploration geophysicists on the relationship between near-salt stress perturbations and accurate imaging of salt structures.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The post-rift history of the North Viking Graben has been backstripped in 3D, producing a sequence of palaeobathymetric maps that culminates at the Late Jurassic synrift stage. The backstripping takes into account the three main processes which drive post-rift basin development: thermal subsidence, flexural-isostatic loading and sediment compaction. Before backstripping was performed, the Norwegian Trench, a bathymetric feature within the present-day seabed, was smoothed in order to remove associated decompaction artefacts within the backstripping results.Palaeobathymetric restorations at the top and base of the Paleocene take into account regional transient dynamic uplift, probably related to the Iceland Plume. 350 m of uplift is incorporated at the Base Tertiary (65 Ma) and 300 m at the Top Balder Formation (54 Ma), followed by rapid collapse of this same uplift.At the top of the Lower Cretaceous (98.9 Ma), very localized fault-block topography, inherited from the Jurassic rift, is predicted to have remained emergent within the basin. At the Base Cretaceous (140 Ma), the fault-block topography is much more prominent and numerous isolated footwall islands are shown to have been present. At the Late Jurassic synrift stage (155 Ma), these islands are linked to form emergent island chains along the footwalls of all of the major faults. This is the Jurassic archipelago, the islands of which were the products of synrift footwall uplift. The predicted magnitude and distribution of footwall emergence calibrates well against available well data and published stratigraphic information, providing important constraints on the reliability of the results.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Bitumen-bearing fractures and vugs were investigated in the highly organic-rich Jordan Oil Shale (JOS) of Late Cretaceous to Eocene age, which has potential as a highly fractured, unconventional hydrocarbon play. Bitumen is present as macroscopically visible deposits and as inclusions in the cement of abundant natural fractures and adjacent vugs. The frequency of bitumen occurrence in fractures closely correlates with Total Organic Carbon (TOC) and burial depth. Petrographic and organic-geochemical analyses on bitumen samples extracted from fractures and their host rock matrix show that the fracture-filling bitumen comprises indigenous low maturity hydrocarbons derived from the surrounding organic-rich Oil Shale and has not migrated from a deeper source. Maturity indicators imply that the oil shale is in the pre-oil generation stage of early catagenesis throughout the investigated area, but with a regional increase in thermal maturity from west to east as the result of greater maximum burial depth. Bitumen mobilization in the host rock was mainly controlled by vertical loading stress acting on the non-Newtonian bitumen phase in load bearing configurations in the organic-rich matrix. Bitumen fractures were developed by hydraulic fracturing as the result of fluid overpressure in the organic matter. Overpressured bitumen has acted as a fracture driver, generating bitumen veins in both the organic-rich mudstones and the adjacent chert and silicified intervals.〈strong〉Supplementary material:〈/strong〉〈a href="https://doi.org/10.6084/m9.figshare.c.4602290"〉https://doi.org/10.6084/m9.figshare.c.4602290〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Salt structures present numerous challenges for targeting reservoirs. Salt movement within the subsurface can follow complex pathways, producing deformation patterns in surrounding strata which are often difficult to decipher. Consequently, the relative role of key salt-flow drivers and geological sensitivities on salt-structure evolution are often poorly understood. To address this, we have developed 2D geomechanical models using the finite-element method to simulate salt diapir and pillow development in two extensional tectonic settings. We conducted model sensitivity analyses to examine the influence of geological parameters on field-scale salt structures and their corresponding deformation pattern. Modelled diapirs developing in thin-skinned extensional settings closely resemble published analogue experiments; however, active and passive stages of diapir growth are seldom or never reached, respectively, thus challenging existing ideas that diapir evolution is dominated by passive growth. In all modelled cases, highly strained domains bound the diapir flanks where extensive small-scale faulting and fracturing can be expected. Asymmetrical diapirs are prone to flank collapse and are observed in models with fast extension or sedimentation rates, thin roof sections or salt layers, or initially short or triangular-shaped diapirs. In modelled thick-skinned extensional settings, salt pillows and suprasalt overburden faults can be laterally offset (decoupled) from a reactivating basement fault. This decoupling increases with increased salt-layer thickness, overburden thickness, sedimentation rate and fault angle, and decreased fault slip rates. Contrary to existing consensus, overburden grounding onto the basement fault scarp does not appear to halt development of salt structures above the footwall basement block.〈strong〉Supplementary material:〈/strong〉 Animations for all model runs are available at 〈a href="https://doi.org/10.6084/m9.figshare.c.4446272"〉https://doi.org/10.6084/m9.figshare.c.4446272〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Aquifer thermal energy storage (ATES) as a complement to fluctuating renewable energy systems is a reliable technology to guarantee continuous energy supply for heating and air conditioning. We investigated a high-temperature (HT) mono-well system (〈span〉c〈/span〉. 100°C), where the well screens are separated vertically within the aquifer, as an alternative to conventional doublet ATES systems for an underground storage in northern Oman. We analysed the impact of thermal inference between injection and extraction well screens on the heat recovery factor (HRF) in order to define the optimal screen-to-screen distance for best possible systems efficiency. Two controlling interference parameters were considered: the vertical screen-to-screen distance and aquifer heterogeneities. The sensitivity study shows that with decreasing screen-to-screen distances, thermal interference increases storage performance. A turning point is reached if the screen distance is too close, causing either water breakthrough or negative thermal interference between the screens. Our simulations show that a combined heat plume with spherical geometry results in the highest heat recovery factors due to the lowest surface area to volume ratios. Thick aquifers for mono-well HT-ATES are thus not mandatory. Our study shows that a HT-ATES mono-well system is a feasible storage design with high heat recovery factors for continuous cooling or heating purposes.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Hydrogen storage in porous geological formations is a potential option to mitigate offsets between power demand and generation in an energy system largely based on renewables. Incorporating hydrogen storage into the energy network requires the consideration of multiple scenarios for storage settings and potential loading cycles, causing a high computational effort. Therefore, homogenous replacement models are constructed by applying different spatial averaging methods for permeability and linearized relative permeability to an ensemble of heterogeneous reservoir representations of a potential hydrogen storage site. The applicability of these replacement models for approximating storage characteristics, such as well flow rates, pressure changes and power rates, is investigated by comparing their results to the results of the full heterogeneous ensemble. It is found that using the arithmetic mean to estimate the lateral and the harmonic mean for the vertical permeability in the homogeneous replacement models provides an approximation to the median of the heterogeneous ensemble for pressure changes, storage flow rate, gas in place and power output. Basic time-dependent effects of reducing well flow, and thus the power rates, during an extraction cycle can also be represented by these homogeneous replacement models. Using geometric means is found not to yield a valid representation of the storage behaviour.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉CO〈sub〉2〈/sub〉 storage in salt rock is simulated with the finite element method (FEM), assuming constant gas pressure. The initial state is determined by simulating cavity excavation with a continuum damage mechanics (CDM) model. A micro–macro healing mechanics model is proposed to understand the time-dependent behaviour of halite during the storage phase. Salt is viewed as an assembly of porous spherical inclusions that contain three orthogonal planes of discontinuity. Eshelby's self-consistent theory is employed to homogenize the distribution of stresses and strains of the inclusions at the scale of a representative elementary volume (REV). Pressure solution results in inclusion deformation, considered as eigenstrain, and in inclusion stiffness changes. The micro–macro healing model is calibrated against Spiers’ oedometer test results, with uniformly distributed contact plane orientations. FEM simulations show that independent of salt diffusion properties, healing is limited by stress redistributions that occur around the cavity during pressure solution. In standard geological storage conditions, the displacements at the cavity wall occur within the first 5 days of storage and the damage is reduced by only 2%. These conclusions still need to be confirmed by simulations that account for changes in gas temperature and pressure over time. For now, the proposed modelling framework can be applied to optimize crushed salt back-filling materials and can be extended to other self-healing materials.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉In carbonate rocks, channelized fluid flow through fracture conduits can result in the development of large and connected karst networks. These cavity systems have been found in multiple hydrocarbon and geothermal reservoirs and are often associated with high permeable zones but also pose significant challenges in drilling and reservoir management. Here, we expand on the observed interplay between fractures, fluid flow and large cave systems, using outcrop analysis, drone imagery and fluid flow modelling. The studied carbonate rocks are heavily fractured and are part of the Salitre Formation (750-650 Ma), located in central Bahia (NE-Brazil). Firstly, the fracture, - and cave network data show a similar geometry and both systems depict three main orientations, namely; 1) NNE-SSW, 2) NW-SE and 3) ESE-WNW. Moreover, the two datasets are dominated by the longer NNE-SSW features. These observed similarities suggest that the fractures and caves are related. The presented numerical results further acknowledge this observed correlation. These results show that open fractures act as the main fluid flow conduits, with the aperture model defining the fracture-controlled flow contribution. Furthermore, the performed modelling highlights that geometrical features such as, length, orientation and connectivity play an important role in the preferred flow orientations.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The Carboniferous Bowland Shale Formation of the UK is a proven hydrocarbon source rock and currently a target for shale gas exploration. Most existing analysis details lithofacies and geochemical assessment of a small number of boreholes. Given a paucity of relevant borehole cores, surface samples provide a valuable contribution to the assessment of this unconventional gas source. This study reviews existing literature on the formation's hydrocarbon geochemistry and provides new lithological descriptions of seven lithofacies, XRD mineralogy and hydrocarbon-specific geochemical data for 32 outcrop localities within the Craven and Edale basins, respectively in the northern and southern parts of the resource area. Low oxygen indices suggest that the majority of samples are relatively unaltered (in terms of hydrocarbon geochemistry), and therefore suitable for the characterisation of the shale organic character. Total organic carbon (TOC) ranges from 0.7 to 6.5 wt %, with highest values associated with maximum flooding surfaces. Mean T〈sub〉max〈/sub〉 values of 447°C and 441 °C for the Edale and Craven basins, respectively, suggest nearly all the samples were too immature to have generated appreciable amounts of dry gas. The oil saturation index is consistently below the 〉100 mg/g TOC benchmark, suggesting that they are not prospective for shale-oil.〈strong〉Supplementary material:〈/strong〉 description of sample location details is available at 〈a href="https://doi.org/10.6084/m9.figshare.c.4444589"〉https://doi.org/10.6084/m9.figshare.c.4444589〈/a〉.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The early Miocene Wadi Waqb carbonate in the Midyan Peninsula, NE Red Sea is of great interest not only because of its importance as an archive of one of the few pre-salt syn-rift carbonate platforms in the world, but also as a major hydrocarbon reservoir. Despite this importance little is known about the diagenesis and heterogeneity of this succession. This study uses petrographic, elemental chemistry, stable isotope (δ〈sup〉13〈/sup〉C and δ〈sup〉18〈/sup〉O) and clumped isotope (Δ〈sub〉47〈/sub〉) analyses to decipher the controlling processes behind the formation of various diagenetic products, especially dolomite, from two locations (Wadi Waqb and Ad-Dubaybah) which have experienced different diagenetic histories. Petrographically, the dolomites in both locations are similar, and characterized by euhedral to subhedral crystals (50-200 µm) and fabric-preserving dolomite textures. Clumped isotope analysis suggests slightly elevated temperatures were recorded in the Ad-Dubaybah location (up to 49 °C) whereas the Wadi Waqb location shows a sea surface temperature (∼30 °C). These temperature differences, coupled with distinct δ〈sup〉18〈/sup〉O〈sub〉VPDB〈/sub〉 values, can be used to infer the chemistry of the fluids involved in the dolomitization processes, with fluids at the Wadi Waqb location displaying much higher δ〈sup〉18〈/sup〉O〈sub〉SMOW〈/sub〉 values (up to +4‰) compared to those at the Ad Dubaybah location (up to -3‰). Two different dolomitization models are proposed for the two sites: a seepage reflux, evaporative seawater mechanism at the Wadi Waqb location, and a fault-controlled, modified seawater mechanism at the Ad-Dubaybah location. At Ad-Dubaybah, seawater was modified through interaction with the immature basal sandstone aquifer, the Al-Wajh Formation. The spatial distribution of the dolostone bodies formed at these two locations also supports the models proposed here, with the Wadi Waqb location exhibiting massive dolostone bodies while the dolostone bodies in the Ad-Dubaybah location are mostly clustered along the slope and platform margin. Porosity is highest in the slope sediments due to the interplay between higher precursor porosity, grain size of the original limestone, and dolomitization. Ultimately, this study provides insights into the prediction of carbonate diagenesis in an active tectonic basin and the resultant porosity distribution of a pre-salt carbonate reservoir system.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Accurate estimation of rock elastic and failure parameters plays a vital role in the petroleum, civil, and geotechnical engineering applications. During drilling operations, continuous logs of rock elastic and failure parameters are considered very helpful to optimize geomechanical earth models. Commonly, rock elastic and failure parameters are estimated using well logs and empirical correlations. These are calibrated with rock mechanics laboratory experiments conducted on core samples. However, since these samples are expensive to get and time-consuming to test. Artificial Intelligence (AI) models based on available petrophysical well logs such as bulk density, compressional wave travel time, and shear wave travel time are utilized to predict static Young's modulus (Estatic) and unconfined compressive strength (UCS) – with an emphasis on carbonate rocks. We present two AI techniques in this study: artificial neural network (ANN) and adaptive neuro fuzzy inference system (ANFIS). The dataset used in this study contains 120 data points obtained from a Middle Eastern carbonate reservoir from which we develop an empirically correlated ANN model to predict Estatic and ANFIS model to predict UCS. A comparison between the UCS, predicted by the proposed ANFIS model, and with the published correlations show that ANFIS model predicted the UCS with less error and high coefficient of determination. The error obtained from ANFIS model was 4.5% while other correlations resulted in up to 30% of error on a published dataset. On the basis of results obtained we can say that the developed models will help geomechanical engineers to predict E〈sub〉static〈/sub〉 and UCS using well logs without the need to measure them in the laboratory.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Most carbonates have a dual porosity and permeability (matrix and fracture). As fractures are preferential conduits for fluid flows, fracture networks strongly impact reservoir hydraulic properties. Two fracture patterns can affect reservoirs: random background fractures in the host rock and damage zone clustered fractures in fault zones. This study identifies the structural and diagenetic attributes of both fracture patterns and determined their respective impact on reservoir properties. The study focuses on the East part of La Fare Anticlinal (SE France). Lower Cretaceous, Urgonian facies carbonates underwent a polyphase tectonic history. Faults were set up as normal and were later reactivated as strike-slip. We made a 290m scan-line along the outcrop to characterize fracture network in and outside the fault zones. The diagenetic analysis on 45 thin sections in Polarized Light Microscopy, with SEM and cathodoluminescence evidenced 3 cementation phases and 2 micrite recrystallization phases. This study shows that fault zone structural properties and deformation are dependent of initial host rock background fractures network. Fault zone structure with damage zone fracture network encouraged the fluid to flow and the cementation of S2 phase. This fluid flow, absent in the host rock strongly modified the reservoir properties of the studied zone.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We present a review of the Chang 7 Member oil shale, which occurs in the middle –late Triassic Yanchang Formation of the Ordos Basin in central north China. The oil shale has a thickness of 28 m (average), an area of around 30,000 km2 and a Ladinian age. It is mainly brown-black to black in colour with a laminar structure. It is characterized by average values of 18wt% TOC (total organic carbon), 8wt% oil yield, and 8.35 MJ/kg calorific value, 400kg/t hydrocarbon productivity, and kerogen of type I-II1, showing a medium quality. On average it comprises 49% clay minerals, 29% quartz, 16% feldspar, and iron oxides, closed to the average mineral composition of global shale. The total SiO2 and Al2O3 comprise 63.69wt% of the whole rock, indicating a medium ash type. The Sr/Ba is 0.33, V/Ni is 7.8, U/Th is 4.8, and the FeO/Fe2O3 is 0.5, indicating formation in a strongly reducing, fresh water or low salinity environment. Multilayered intermediate acid tuff is developed in the basin, which may have promoted the formation of the oil shale. The Ordos Basin was formed during the northward subduction of the Qinling oceanic plate during Ladinian to Norian in a back-arc basin context.〈strong〉Supplementary material:〈/strong〉〈a href="https://doi.org/10.6084/m9.figshare.c.4411703"〉https://doi.org/10.6084/m9.figshare.c.4411703〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Hydrogen storage in porous geological formations is a potential option to mitigate offsets between power demand and generation in an energy system largely based on renewables. Incorporating hydrogen storage into the energy network requires the consideration of multiple scenarios for storage settings and potential loading cycles, causing a high computational effort. Therefore, homogenous replacement models are constructed by applying different spatial averaging methods for permeability and linearized relative permeability to an ensemble of heterogeneous reservoir representations of a potential hydrogen storage site. The applicability of these replacement models for approximating storage characteristics, such as well flow rates, pressure changes and power rates, is investigated by comparing their results to the results of the full heterogeneous ensemble. It is found that using the arithmetic mean to estimate the lateral and the harmonic mean for the vertical permeability in the homogeneous replacement models provides an approximation to the median of the heterogeneous ensemble for pressure changes, storage flow rate, gas in place and power output. Basic time-dependent effects of reducing well flow, and thus the power rates, during an extraction cycle can also be represented by these homogeneous replacement models. Using geometric means is found not to yield a valid representation of the storage behaviour.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Salt structures present numerous challenges for targeting reservoirs. Salt movement within the subsurface can follow complex pathways, producing deformation patterns in surrounding strata which are often difficult to decipher. Consequently, the relative role of key salt-flow drivers and geological sensitivities on salt-structure evolution are often poorly understood. To address this, we have developed 2D geomechanical models using the finite-element method to simulate salt diapir and pillow development in two extensional tectonic settings. We conducted model sensitivity analyses to examine the influence of geological parameters on field-scale salt structures and their corresponding deformation pattern. Modelled diapirs developing in thin-skinned extensional settings closely resemble published analogue experiments; however, active and passive stages of diapir growth are seldom or never reached, respectively, thus challenging existing ideas that diapir evolution is dominated by passive growth. In all modelled cases, highly strained domains bound the diapir flanks where extensive small-scale faulting and fracturing can be expected. Asymmetrical diapirs are prone to flank collapse and are observed in models with fast extension or sedimentation rates, thin roof sections or salt layers, or initially short or triangular-shaped diapirs. In modelled thick-skinned extensional settings, salt pillows and suprasalt overburden faults can be laterally offset (decoupled) from a reactivating basement fault. This decoupling increases with increased salt-layer thickness, overburden thickness, sedimentation rate and fault angle, and decreased fault slip rates. Contrary to existing consensus, overburden grounding onto the basement fault scarp does not appear to halt development of salt structures above the footwall basement block.〈strong〉Supplementary material:〈/strong〉 Animations for all model runs are available at 〈a href="https://doi.org/10.6084/m9.figshare.c.4446272"〉https://doi.org/10.6084/m9.figshare.c.4446272〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉At the 2015 United Nations international climate change conference in Paris (COP21), 197 national parties committed to limit global warming to well below 2°C. But current plans and pace of progress are still far from sufficient to achieve this objective. Here we review the role that geoscience and the subsurface could play in decarbonising electricity production, industry, transport, and heating, to meet UK and international climate change targets, based on contributions to the 2019 Bryan Lovell meeting held at the Geological Society of London. Technologies discussed at the meeting involved decarbonisation of electricity production via renewable sources of power generation, substitution of domestic heating using geothermal energy, use of carbon capture and storage (CCS), and more ambitious technologies such as bioenergy and carbon capture and storage (BECCS) that target negative emissions. It was noted also that growth in renewable energy supply will lead to increased demand for geological materials to sustain the electrification of the vehicle fleet and other low-carbon technologies. The overall conclusion reached at the 2019 Bryan Lovell meeting was that geoscience is critical to decarbonisation, but that the geoscience community must influence decision makers so that the value of the subsurface to decarbonisation is understood.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We use a 2D forward finite-element model to explore how a laterally continuous permeable bed impacts the geological evolution and geomechanical properties of a salt basin. We show that a permeable bed tilted by rise of a salt diapir substantially increases pore pressure in sediments near the diapir by hydraulically connecting these sediments to deep, high-overpressure sediments far from the diapir. The pore-pressure increase near the diapir has the following significant consequences: it causes a faster rise of the diapir, brings sediments near the diapir close to shear failure 〈span〉in situ〈/span〉, causes unloading of sediments around the crest of the permeable bed, and reduces the margin of appropriate mud weights for drilling near the diapir. The rise of the salt diapir induces concentrated lateral deformation and thereby overpressure in mudrocks encasing the permeable bed in an area near the bottom of the basin. This anomalously high overpressure is in marked contrast with the overpressure in the permeable bed, resulting in a large pore-pressure gradient between the permeable bed and encasing mudrocks. Our study provides insight into the importance of permeable beds to the structural evolution of a salt basin and to the exploration and production of hydrocarbon near salt diapirs.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The spatial geometry of microporosity influences fluid flow through chalk reservoirs and aquifers, hence numerous geological processes. Analysing porosity is hence often critical in geological studies. Techniques such as mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) and X-ray computed tomography (CT) are expensive and hence often inapplicable to many geological studies, which often necessitate the analysis of large numbers (100's) of samples.On the other hand, scanning electron microscopes (SEM) have become widely available. SEM imagery analysis is therefore cheaper and faster. However, extracting meaningful porosity descriptors from SEM images can be difficult, in part because of the difficulty to digitally separate pores in laterally continuous pore networks. Moreover, mathematical morphology can be automated to collect porosity parameters from 100's of images in a short time frame. The technique also quantifies the shape complexity of porosity. Considering the influence of pore geometry on fluid flow, the capacity of image analysis to decompose the pore network by pore shapes is crucial when building flow models. This study concludes that mathematical morphology constitutes an alternative to other techniques in geological studies of microporosity. Lithologies dominated by micro- and nannoporosity, such as shales and tight sandstones, could also benefit from this technique.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Rock physics analyses of data from a wildcat well 7117/9-1 drilled in the Senja Ridge area, located in the Norwegian Barents Sea, reveal a change in stiffness within the fine-grained Paleogene Sotbakken Group sediments, caused by the transformation of opal-A to opal-CT, and opal-CT to quartz. This change manifests as flat spots on 2D seismic profiles. These flat spots were mistaken as hydrocarbon-water contacts, which led to the drilling of well 7117/9-1. Rock physics analyses on this well combined with a second well (7117/9-2) drilled further northwest and updip on the Senja Ridge, indicate overpressure within the opal-CT rich zones overlying the opal-CT to quartz transformation zones in the two wells. The absence of opal-A to opal-CT and opal-CT to quartz flat spots on seismic in the second well is attributed to differences in temperature and timing of uplift. In AVA modelling, both the opal-A to opal-CT and opal-CT to quartz interface points plotted on the wet trend, whereas the modelled gas-brine, oil-brine and gas-oil contacts fell within the quadrant-I. These findings will be useful in understanding the nature of compaction of biogenic silica-rich sediments where flat spots could be misinterpreted as hydrocarbon related contacts in oil and gas exploration.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We present the results of a feasibility study for seismic monitoring using conventional surface seismic experiments at the CaMI Field Research Station, Alberta, Canada, where a small volume of gas-phase CO〈sub〉2〈/sub〉 is being injected into a sandstone reservoir at a depth of 300 m. We first apply a careful fluid substitution procedure to the results of reservoir gas saturation and pressure responses obtained from fluid flow simulations. We test different methods to compute the bulk modulus of the fluid for different fluid saturation models. Assuming a semi-patchy model and considering only the replacement of brine with a maximum saturation of 50% CO〈sub〉2〈/sub〉, we estimate the reduction in P-wave velocity to be 20%. Adding an increase in pore pressure of 2.7 MPa increases the P-wave velocity reduction to 32%. After including a field-based signal-to-noise ratio of 5% to the synthetic seismic data, the time-lapse seismic anomaly should be detectable after one year of injection (266 tonnes of CO〈sub〉2〈/sub〉).〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Traditional methods for imaging salt bodies seldom consider near-salt stress perturbations caused by salt, and the associated velocity perturbations of seismic waves in the sediments near the salt. To demonstrate the importance of stress changes caused by the salt on accurately imaging salt bodies, in this study we develop and apply a combined method of geomechanical stress modelling and salt imaging. We simulate the stress perturbations in sediments induced by a salt sphere using a static geomechanical model, and calculate the associated velocity changes of seismic waves in the sediments by using our model stress perturbations. We use the reverse time migration and imaging method to image the salt sphere, and then analyse the imaging results of two cases including and excluding the effects of stress perturbations by the salt sphere on velocity changes of seismic waves. The results show that the near-salt velocity changes of seismic waves induced by stress perturbations near salt bodies can have a significant impact on the salt imaging. We find that when the effects of near-salt stress perturbations are ignored, the imaging of the salt sphere is clearly distorted: the salt sphere is extended vertically and becomes a salt ellipse with a vertical major axis. In contrast, when we include the effects of near-salt stress perturbations, the imaging of this salt sphere accurately matches the salt geometry and position. Thus, the near-salt stress perturbations should not be ignored in salt imaging. This study provides scientific insights for petroleum geologists and exploration geophysicists on the relationship between near-salt stress perturbations and accurate imaging of salt structures.〈/span〉

Description: 〈span〉〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Accurate estimation of rock elastic and failure parameters plays a vital role in petroleum, civil and geotechnical engineering applications. During drilling operations, continuous logs of rock elastic and failure parameters are considered very helpful in optimizing geomechanical earth models. Commonly, rock elastic and failure parameters are estimated using well logs and empirical correlations. These are calibrated with rock mechanics laboratory experiments conducted on core samples. However, since these samples are expensive to get and time-consuming to test, artificial intelligence (AI) models based on available petrophysical well logs such as bulk density, compressional wave and shear wave travel times are utilized to predict the static Young's modulus (〈span〉E〈/span〉〈sub〉static〈/sub〉) and the unconfined compressive strength (UCS) – with an emphasis on carbonate rocks. We present two AI techniques in this study: an artificial neural network (ANN) and an adaptive neuro-fuzzy inference system (ANFIS). The dataset used in this study contains 120 data points obtained from a Middle Eastern carbonate reservoir from which we develop an empirically correlated ANN model to predict 〈span〉E〈/span〉〈sub〉static〈/sub〉 and an ANFIS model to predict the UCS. A comparison between the UCS, predicted by the proposed ANFIS model, and the published correlations show that the ANFIS model predicted the UCS with less error and with a high coefficient of determination. The error obtained from the ANFIS model was 4.5%, while other correlations resulted in up to 30% error on a published dataset. On the basis of the results obtained, we can say that the developed models will help geomechanical engineers to predict 〈span〉E〈/span〉〈sub〉static〈/sub〉 and the UCS using well logs without the need to measure them in the laboratory.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Fracture scaling parameters are an important input for modelling of naturally fractured reservoirs, but are very difficult to derive from subsurface data. Extensive areas of exposure in the northern Kurdistan Region of Iraq provide useful outcrop analogues for nearby producing and potential hydrocarbon fields. A variety of data acquisition methods are used to analyse fracture systems in carbonates of the Upper Cretaceous Aqra–Bekhme Formation across a wide range of scales. When plotted on length–intensity graphs, the collated data lie below an upper envelope that follows a power-law distribution over five orders of magnitude between 0.1 and 3000 m, and which defines the maximum likely intensity of background fracturing across the region. Contouring the length–intensity data shows the distribution of intensities below the upper envelope, and allows modal and minimum likely intensities to be estimated. Likely causes for the observed variation in fracture intensities include the domainal nature of deformation, the proximity to high strain zones including faults, second-order effects such as ladder fractures, and variations in the thickness of mechanical layering.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The reservoir properties of distal lower-shoreface and distal wave-dominated delta-front deposits, which consist of sandstone beds with locally scoured bases and mudstone interbeds, are poorly understood. The lower Rannoch Formation (Middle Jurassic Brent Group) forms an interval of such heterolithic sandstones in many North Sea reservoirs, and is used to illustrate a workflow for rapid estimation of reservoir properties and their sensitivity to key parameters. Mudstone-interbed thickness distributions in cored reservoir successions are compared to the thickness distribution of sandstone scour-fills in an outcrop analogue(s) in order to identify mudstones with the potential to form laterally extensive barriers to vertical flow. Effective 〈span〉k〈/span〉〈sub〉v〈/sub〉/〈span〉k〈/span〉〈sub〉h〈/sub〉 at the scale of several typical reservoir-model grid cells (200 × 100 × 20 m) is estimated in intervals bounded by these mudstone barriers via a simple analytical technique that is calibrated to previously documented reservoir-modelling experiments, using values of sandstone proportion measured in cored reservoir successions. Using data from the G2 parasequence (Grassy Member, Blackhawk Formation, east-central Utah, USA) outcrop analogue, mudstones bounding 3–8 m-thick, upwards-coarsening successions in the lower Rannoch Formation may define separate stratigraphic compartments in which grid-cell-scale effective 〈span〉k〈/span〉〈sub〉v〈/sub〉/〈span〉k〈/span〉〈sub〉h〈/sub〉 is estimated to be 0.0001–0.001 using a streamline-based analytical method.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Bitumen-bearing fractures and vugs were investigated in the highly organic-rich Jordan oil shale (JOS) of Late Cretaceous–Eocene age, which has potential as a highly fractured, unconventional hydrocarbon play. Bitumen is present as macroscopically visible deposits, and as inclusions in the cement of abundant natural fractures and adjacent vugs. The frequency of bitumen occurrence in fractures closely correlates with total organic carbon (TOC) and burial depth. Petrographical and organic-geochemical analyses on bitumen samples extracted from fractures and their host-rock matrix show that the fracture-filling bitumen comprises indigenous low maturity hydrocarbons derived from the surrounding organic-rich oil shale and has not migrated from a deeper source. Maturity indicators imply that the oil shale is in the pre-oil generation stage of early catagenesis throughout the investigated area, but with a regional increase in thermal maturity from west to east as the result of greater maximum burial depth. Bitumen mobilization in the host rock was mainly controlled by vertical loading stress acting on the non-Newtonian bitumen phase in load-bearing configurations in the organic-rich matrix. Bitumen fractures were developed by hydraulic fracturing as the result of fluid overpressure in the organic matter. Overpressured bitumen has acted as a fracture driver, generating bitumen veins in both the organic-rich mudstones and the adjacent chert and silicified intervals.〈strong〉Supplementary material〈/strong〉〈strong〉:〈/strong〉 A summary of core data and photographs of the fracture bitumen and matrix bitumen are available at 〈a href="https://doi.org/10.6084/m9.figshare.c.4602290"〉https://doi.org/10.6084/m9.figshare.c.4602290〈/a〉〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We present the results of a feasibility study for seismic monitoring using conventional surface seismic experiments at the CaMI Field Research Station, Alberta, Canada, where a small volume of gas-phase CO〈sub〉2〈/sub〉 is being injected into a sandstone reservoir at a depth of 300 m. We first apply a careful fluid substitution procedure to the results of reservoir gas saturation and pressure responses obtained from fluid flow simulations. We test different methods to compute the bulk modulus of the fluid for different fluid saturation models. Assuming a semi-patchy model and considering only the replacement of brine with a maximum saturation of 50% CO〈sub〉2〈/sub〉, we estimate the reduction in P-wave velocity to be 20%. Adding an increase in pore pressure of 2.7 MPa increases the P-wave velocity reduction to 32%. After including a field-based signal-to-noise ratio of 5% to the synthetic seismic data, the time-lapse seismic anomaly should be detectable after one year of injection (266 tonnes of CO〈sub〉2〈/sub〉).〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We combine a power-law microfracture size distribution function with an expression for fracture propagation rate derived from subcritical fracture propagation theory and linear elastic fracture mechanics, to derive a geomechanically based deterministic model for the growth of a network of layer-bound fractures. This model also simulates fracture termination due to intersection with perpendicular fractures or stress-shadow interaction. We use this model to examine key controls on the emergent geometry of the fracture network.First, we examine the effect of fracture propagation rates. We show that at subcritical fracture propagation rates, the fracture nucleation rate increases with time; this generates a very dense network of very small fractures, similar to the deformation bands generated by compaction in unconsolidated sediments. By contrast, at critical propagation rates, the fracture nucleation rate decreases with time; this generates fewer but much larger fractures, similar to the brittle open fractures generated by tectonic deformation in lithified sediments. We then examine the controls on the rate of growth of the fracture network. A fracture set will start to grow when the stress acting on it reaches a threshold value, and it will continue to grow until all the fractures have stopped propagating and no new fractures can nucleate. The relative timing and rate of growth of the different fracture sets will control the anisotropy of the resulting fracture network: if the sets start to grow at the same time and rate, the result is a fully isotropic fracture network; if the primary fracture set stops growing before the secondary set starts growing, the result is a fully anisotropic fracture network; and if there is some overlap but the secondary set grows more slowly than the primary set, the result is a partially anisotropic fracture network. Although the applied horizontal strain rates are the key control on the relative growth rates of the two fracture sets, we show that the vertical effective stress, the initial horizontal stress, the elastic properties of the rock and the inelastic deformation processes, such as creep, grain sliding and pressure solution, all exert a control on the fracture growth rates, and that more isotropic fracture networks will tend to develop if the vertical effective stress is low or if the fractures are critically stressed prior to the onset of deformation.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We demonstrate statistically significant self-organized clustering over a length scale range from 10〈sup〉−2〈/sup〉 to 10〈sup〉1〈/sup〉 m for north-striking opening-mode fractures (joints) in Late Archean Mount Owen Quartz Monzonite. Spatial arrangement is a critical fracture network attribute that until recently has only been assessed qualitatively. We use normalized fracture intensity plots and the normalized correlation count (NCC) method of Marrett 〈span〉et al.〈/span〉 to discriminate clustered from randomly placed or evenly spaced patterns quantitatively over a wide range of length scales and to test the statistical significance of the resulting patterns. We propose a procedure for interpreting cluster patterns on NCC diagrams generated by the freely available spatial analysis software CorrCount. Results illustrate the efficacy of NCC to measure fracture clustering patterns in texturally homogeneous Archean granitic rock in a setting distant (〉2 km) from folds or faults. In their current geological setting, these regional fractures are conduits for water flow and their patterns – and the NCC approach to defining clusters – may be useful guides to the spatial arrangement style and clustering magnitude of conductive fractures in other, less accessible fractured basement rocks.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Reliable production forecasting for fractured carbonate reservoirs is a challenge. Natural fractures, adverse wettability and complex matrix heterogeneity are all uncertain and can all negatively impact upon recovery. Ideally, we should consider different reservoir concepts encapsulated in a large ensemble of reservoir models to quantify the impact of these and other geological uncertainties on reservoir performance. However, the computational cost of considering many scenarios can be significant, especially for dual porosity/permeability models, rendering robust uncertainty quantification impractical for most asset teams.Flow diagnostics provide a complement to full-physics simulations for comparing models. Flow diagnostics approximate the dynamic response of the reservoir in seconds. In this paper we describe the extension of flow diagnostics to dual porosity models for naturally fractured reservoirs. Our new diagnostic tools link the advective time of flight in the fractures to the transfer from the matrix, identifying regions where transfer and flux are not in balance leading to poor matrix oil sweep and early breakthrough. Our new diagnostics tools have been applied to a real field case and are shown to compare well with full-physics simulation results.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉In carbonate rocks, channelized fluid flow through fracture conduits can result in the development of large and connected karst networks. These cavity systems have been found in multiple hydrocarbon and geothermal reservoirs, and are often associated with high-permeability zones, but also pose significant challenges in drilling and reservoir management. Here, we expand on the observed interplay between fractures, fluid flow and large cave systems, using outcrop analysis, drone imagery and fluid-flow modelling. The studied carbonate rocks are heavily fractured and are part of the Salitre Formation (750–650 Ma), located in central Bahia (NE Brazil). Firstly, the fracture and cave network data show a similar geometry, and both systems depict three main orientations, namely; NNE–SSW, NW–SE and ESE–WNW. Moreover, the two datasets are dominated by the longer NNE–SSW features. These observed similarities suggest that the fractures and caves are related. The presented numerical results further acknowledge this observed correlation. These results show that open fractures act as the main fluid-flow conduits, with the aperture model defining the fracture-controlled flow contribution. Furthermore, the performed modelling highlights that geometrical features such as length, orientation and connectivity play an important role in the preferred flow orientations.〈strong〉Thematic collection:〈/strong〉 This article is part of the Naturally Fractured Reservoirs collection available at: 〈a href="https://www.lyellcollection.org/cc/naturally-fractured-reservoirs"〉https://www.lyellcollection.org/cc/naturally-fractured-reservoirs〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The carbonate–evaporite depositional combination of Late Jurassic age, incorporates the most prolific oil-producing intervals in the world and forms many giant fields. The succession is the top member of four upwards-shoaling carbonate–anhydrite cycles of Upper Kimmeridgian age, and is overlain by the impermeable anhydrite in northern Arabia. The weak depositional contrasts in carbonate ramp settings make the lateral seal configurations subtle and tough to recognize. Multiple attribute analyses based on an artificial neural network (ANN) can delineate the internal character of the reservoir and seal in a consistent way.In order to recognize the sedimentary facies and characterize stratigraphic traps within this reservoir interval, multiple seismic attributes were input to an unsupervised ANN. Unsupervised ANN offers a powerful means of classification, implemented here using a single-layer perceptron network. The network is trained by comparing the neurons to the input vectors using competitive-learning techniques. Once a neuron migrates to the centre of a class, the network stabilizes, training is finished and the neuron is assigned to a representative class. Without prior information, the unlabelled class is calibrated and analysed by lithofacies generated from log and core data. Further sedimentary facies are recognized by integrating local geological knowledge.The depositional environments in the study area are well characterized by the unsupervised ANN, and the recognized sedimentary facies are consistent with the drilled wells and the resulting geological model. Lagoonal deposits of the inner-ramp, ramp-crest shoal and proximal deposits of the middle ramp are recognized within the study area. The widespread ramp crest with peloid and oolitic grainstones provides good reservoirs, whereas the lagoonal deposits distributed between the shoals have a greater abundance of tight limestone with low porosity and permeability, thereby forming a good lateral seal. The selected study area, covering the Rimthan Arch is considered a favorable area for the presence of stratigraphic traps. The sedimentary facies recognition helps to define potential areas for favourable prospect definition and hence prospect ranking.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉In many petroleum-bearing, data-poor ‘frontier’ basins, source, reservoir and seal distribution is poorly constrained, making it difficult to identify petroleum systems and play models. However, 3D seismic reflection data provide an opportunity to directly map the 3D distribution of key petroleum system elements, thereby supplementing typically sparse, 1D sedimentary facies information available from wells. Here, we examine the Farsund Basin, an underexplored basin offshore southern Norway. Despite lying in the mature North Sea Basin, the Farsund Basin contains only one well; meaning there remains a poor understanding of its hydrocarbon potential. This east-trending basin is anomalous to the north-trending basins present regionally, having experienced a different tectonic, and most likely geomorphological, evolution. We identify a series of east-flowing rivers in the Middle Jurassic, the distribution of which are controlled by salt-detached faults. In the Middle Jurassic, a series of carbonate reefs, expressed as subcircular amplitude anomalies, developed. Within the Upper Jurassic we identify numerous curvilinear features, which correspond to the downlap termination of southwards-prograding deltaic clinoforms. We show how seismic-attribute-driven analysis can determine the geomorphological development of basins, offering insights into both the local and regional tectonostratigraphic evolution of an area, and helping to determine its hydrocarbon potential.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The McMurray Formation is one of the most significant bitumen deposits in Canadian oil sands. Bitumen-bearing sand intervals deposited and reworked in fluvial, tidal or estuarine environments result in heterogeneous sediment distributions comprising clean sands and low-permeability muddy laminae or mud drapes. These interlayers increase the difficulty in estimating reservoir permeability, which is a critical geological parameter to predict the performance of 〈span〉in situ〈/span〉 thermal processes of the oil sands projects. In this paper, we describe a bedding-scale geomodelling and simulation workflow using core images, core-plug and Vshale logs to estimate the effective permeability (〈span〉K〈/span〉〈sub〉h〈/sub〉, 〈span〉K〈/span〉〈sub〉v〈/sub〉) in the Upper McMurray Formation. Details of five steps in this workflow are presented. To show the general applicability of this workflow, three pay-zone facies from tidal-channel infilled deposits of the Mackay River Project, CNPC, were selected to demonstrate this sedimentary process mimicking bedding-scale geomodelling strategy. The results of effective permeability estimation have the potential to improve history matching in flow simulations and performance forecasting.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉CO〈sub〉2〈/sub〉 storage in salt rock is simulated with the finite element method (FEM), assuming constant gas pressure. The initial state is determined by simulating cavity excavation with a continuum damage mechanics (CDM) model. A micro–macro healing mechanics model is proposed to understand the time-dependent behaviour of halite during the storage phase. Salt is viewed as an assembly of porous spherical inclusions that contain three orthogonal planes of discontinuity. Eshelby's self-consistent theory is employed to homogenize the distribution of stresses and strains of the inclusions at the scale of a representative elementary volume (REV). Pressure solution results in inclusion deformation, considered as eigenstrain, and in inclusion stiffness changes. The micro–macro healing model is calibrated against Spiers’ oedometer test results, with uniformly distributed contact plane orientations. FEM simulations show that independent of salt diffusion properties, healing is limited by stress redistributions that occur around the cavity during pressure solution. In standard geological storage conditions, the displacements at the cavity wall occur within the first 5 days of storage and the damage is reduced by only 2%. These conclusions still need to be confirmed by simulations that account for changes in gas temperature and pressure over time. For now, the proposed modelling framework can be applied to optimize crushed salt back-filling materials and can be extended to other self-healing materials.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Rift-related magmatism resulting in widespread igneous intrusions has been documented in various basins, including the Faroe Shetland Basin (UK), Voring and Møre Basins (Norway) and along the NW Shelf of Australia. Seismic mapping, combined with field work, has resulted in greater understanding of subsurface intrusive plumbing systems, but knowledge of emplacement style and the mechanisms by which intrusions propagate is limited. The interpretation of a 3D seismic dataset from the Exmouth sub-basin, NW Shelf Australia, has identified numerous igneous intrusions where a close relationship between intrusions and normal faults is observed. These faults influence intrusion morphology but also form pathways by which intrusions have propagated up through the basin stratigraphy. The steep nature of the faults has resulted in the intrusions exploiting them and thus manifesting as fault-concordant, inclined dykes, whereas in the deeper parts of the basin, intrusions that have not propagated up faults typically have saucer-shaped sill morphologies. This transition in the morphology of intrusions related to fault interaction also highlights how dykes observed in outcrop may link with sills in the subsurface. Our interpretation of the seismic data also reveal subsurface examples of bifurcating intrusions with numerous splays, which have previously only been studied in outcrop.〈strong〉Supplementary material:〈/strong〉〈a href="https://doi.org/10.6084/m9.figshare.c.4395974"〉https://doi.org/10.6084/m9.figshare.c.4395974〈/a〉〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Aquifer thermal energy storage (ATES) as a complement to fluctuating renewable energy systems is a reliable technology to guarantee continuous energy supply for heating and air conditioning. We investigated a high-temperature mono-well system (~100°C), where the well screens are separated vertically within the aquifer, as alternative to conventional doublet ATES systems for an underground storage in northern Oman. We analysed the impact of thermal inference between injection and extraction well screens on the heat recovery factor (HRF) in order to define the optimal screen-to-screen distance for best possible systems efficiency. Two controlling interference parameters were considered: the vertical screen-to-screen distance and aquifer heterogeneities. The sensitivity study shows that with decreasing screen-to-screen distances thermal interference increases storage performance. A turning point is reached if the screen distance is too close, causing either water breakthrough or negative thermal interference between the screens. Our simulations show that a combined heat plume with spherical geometry results in the highest heat recovery factors due to the lowest surface-area over volume ratios. Thick aquifers for mono-well HT-ATES are thus not mandatory. Our study shows that a HT-ATES mono-well system is a feasible storage design with high heat recovery factors for continuous cooling or heating purposes.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The carbonate-evaporite depositional combination of Late Jurassic age is the top member of four upward-shoaling carbonate-anhydrite cycles in Upper Kimmeridgian age. The weak depositional contrasts in carbonate ramp setting make the lateral seal configurations subtle and tough to recognize. Multiple attribute analysis based on Artificial Neural Network (ANN) can delineate the internal character of the reservoirs and seals in a consistent way.In order to recognize the sedimentary facies within this reservoir interval, multiple seismic attributes input to an unsupervised ANN. Unsupervised ANN is a powerful classification technique, which is implemented using a single layer perceptron network. The network is trained by comparing the neurons to the input vectors using competitive-learning techniques. Once a neuron migrates to the center of the class, the network stabilizes and training is finished. Without prior information, further sedimentary facies are recognized by integrating local geological knowledge.The depositional environments in the study area are well characterized by unsupervised ANN and are consistent with the drilled wells and the geological model. Lagoonal deposits, ramp crest shoal and proximal deposits are recognized within the study area. The sedimentary facies recognition helps define potential areas for favorable prospect definition and hence prospect ranking.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉CO〈sub〉2〈/sub〉 storage in salt rock is simulated with the Finite Element Method (FEM), assuming constant gas pressure. The initial state is determined by simulating cavity excavation with a Continuum Damage Mechanics (CDM) model. A micro-macro healing mechanics model is proposed to understand the time-dependent behavior of halite during the storage phase. Salt is viewed as an assembly of porous spherical inclusions that contain three orthogonal planes of discontinuity. Eshelby’s self-consistent theory is employed to homogenize the distribution of stresses and strains of the inclusions at the scale of a Representative Elementary Volume (REV). Pressure solution results in inclusion deformation, considered as eigenstrain, and in inclusion stiffness changes. The micro-macro healing model was calibrated against Spiers’ oedometer test results, with uniformly distributed contact plane orientations. FEM simulations show that independent of salt diffusion properties, healing is limited by stress redistributions that occur around the cavity during pressure solution. In standard geological storage conditions, the displacements of the cavity occur within the five first days of storage and the damage is reduced by only 2%. These conclusions still need to be confirmed by simulations that account for changes of gas temperature and pressure over time. For now, the proposed modeling framework can be applied to optimize crushed salt back filling materials and can be extended to other self-healing materials.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Reliable production forecasting for fractured carbonate reservoirs is a challenge. Natural fractures, adverse wettability and complex matrix heterogeneity are all uncertain and can all negatively impact upon recovery. Ideally, we should consider different reservoir concepts encapsulated in a large ensemble of reservoir models to quantify the impact of these and other geological uncertainties on reservoir performance. However, the computational cost of considering many scenarios can be significant, especially for dual porosity/permeability models, rendering robust uncertainty quantification impractical for most asset teams.Flow diagnostics provide a complement to full-physics simulations for comparing models. Flow diagnostics approximate the dynamic response of the reservoir in seconds. In this paper we describe the extension of flow diagnostics to dual porosity models for naturally fractured reservoirs. Our new diagnostic tools link the advective time of flight in the fractures to the transfer from the matrix, identifying regions where transfer and flux are not in balance leading to poor matrix oil sweep and early breakthrough. Our new diagnostics tools have been applied to a real field case and are shown to compare well with full-physics simulation results.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉The following chemostratigraphy study was conducted on Paleozoic sediments encountered in 14 wells in eastern Saudi Arabia. A total of 1,500 samples were analysed by ICP-OES (Inductively Coupled Plasma – Optical Emission Spectrometry) and ICP-MS (Inductively Coupled Plasma – Mass Spectrometry), with data acquired for 48 elements, ranging from Na to U in the periodic table. The aim was to utilise chemostratigraphy, in conjunction with existing biostratigraphic, lithostratigraphic and sedimentological data, to define the Hercynian Unconformity in each well and to recognise stratigraphic boundaries occurring above and below it. This was necessary as the unconformity eroded to different stratigraphic levels in each well, with Devonian, Silurian and Ordovician sediments found immediately below it in adjacent locations. In the absence of chemostratigraphic, biostratigraphic and sedimentological data, it is often very difficult to define this boundary and others using lithostratigraphy alone as many stratigraphic intervals yield similar GR log trends. For example, a low ‘blocky’ GR response is typical of both the Carboniferous Ghazal Member and the Ordovician Sarah Formation. Similarly, both the Silurian Sharawra Member and the Silurian-Devonian Tawil Formation produce a ‘ratty’ GR trend. Each stratigraphic member and formation was found to have distinctive chemostratigraphic, biostratigraphic, sedimentological and/or wireline log signatures.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉Upper Permian (Zechstein Supergroup) evaporites have a major control on structural styles and prospectivity in the UK Southern North Sea (SNS). They form the regional super-seal for the main Rotliegend Group (Leman Sandstone Formation) reservoir play fairway immediately beneath. The evaporites have highly variable thicknesses due to the syndepositional basin architecture, differential loading and post-depositional deformation through diapirism and salt withdrawal. The halokinetic activity leads to touchdown (welding) of the supra-salt section onto the sub-salt strata and the development of narrow (up to 15 km-wide) graben systems. The interpretation and depth conversion of well-calibrated, high-quality, 3D post-stack time-migrated (PSTM) seismic data along the southwestern margin of the basin show that a NW–SE-striking elongate extensional Dowsing Graben System transects the area. The graben is defined by a series of large, overlapping, en echelon listric growth faults, with oblique secondary planar faults, which sole-out on two main (deep and shallow) décollement levels in the Zechstein Supergroup and the Middle Triassic Röt Halite Member. Whilst its initial formation was related to Mesozoic extension, the graben system also displays a contractional overprint resulting from regional compression and structural inversion during the Cenozoic. Detailed mapping of the Zechstein Supergroup has revealed that the evolution of the extensional system was influenced by the ESE–WNW-striking anhydrite–carbonate Zechstein shelf-margin. The occurrence of variable-thickness, low-velocity sediments within the graben impacts seismic imaging and depth conversion, leading to prospective structures being overlooked; something that has implications for prospectivity in the SNS and other evaporite basins where similar graben occur.〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉We present the results of a feasibility study for seismic monitoring using conventional surface seismic experiments at the CaMI Field Research Station, Alberta, Canada where a small volume of gas-phase CO〈sub〉2〈/sub〉 is being injected into a sandstone reservoir at a depth of 300 m. We first apply a careful fluid substitution procedure to the results of reservoir gas saturation and pressure responses obtained from fluid flow simulation. We test different methods to compute the bulk modulus of the fluid for different fluid saturation models. Assuming a semi-patchy model and considering only the replacement of brine with a maximum saturation of 50% CO〈sub〉2〈/sub〉, we estimate the reduction in P-wave velocity to be 20%. Adding an increase in pore pressure of 2.7 MPa increases the P-wave velocity reduction to 32%. After including a field-based signal-to-noise ratio of 5% to the synthetic seismic data, the time-lapse seismic anomaly should be detectable after 1 year of injection (266 tonnes of CO〈sub〉2〈/sub〉).〈/span〉

Description: 〈span〉〈div〉Abstract〈/div〉An efficient, numerical local upscaling technique for estimating elastic geomechanical properties in heterogeneous continua is proposed. The upscaled anisotropic elastic properties are solved locally with various boundary conditions and reproduce the anisotropic geomechanical response of fine-scale simulations of sand-shale sequence models with horizontal and inclined shale bedding planes. The algorithm is automated in a parallel program and can be used to determine optimum upscaling ratios in different regions of the reservoir. The successful application of the proposed upscaling method in a field-scale coupled reservoir-geomechanics simulation demonstrates improvement in overall computational efficiency while maintaining accuracy in the geomechanical response and reservoir performance.〈/span〉