ALBERT

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: 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: 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: 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: 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: 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: 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: 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.