Reservoir evaluation of 8 wells in the Palaeozoic of the Irish Sea area : petrophysical interpretations of clay volume, porosity and permeability estimations

This report details the reservoir evaluation of 8 wells across the Palaeozoic (Carboniferous and Permian age) rocks of the UK Irish Sea for the 21CXRM Palaeozoic project. This reservoir evaluation is based on the petrophysical interpretation of available digital wireline log curve data for 8 wells and associated digitised core porosity and permeability data (available for 6 of the 8 wells interpreted, with 7 to 20 measurements per well) across the Palaeozoic interval (according to reinterpreted stratigraphic formations defined and correlated for this project, documented in Wakefield et al., 2016). Outputs of this part of the project include continuous (along borehole) interpretations of porosity, clay volume, and include basic permeability estimations. These interpreted curves were used to calculate Net to Gross (NTG) values and average porosities and permeabilities for each formation in each well analysed. The highest average porosities were found in the Permian aged Appleby Group (19%; previously termed the Collyhurst Sandstone). This unit also had the highest NTG and second highest average permeabilities of the units examined. Although the highest average permeability is low (0.13 mD) for the Appleby Group, maximum values in the 50-100 mD range are recorded for several wells. The Cumbrian Coast Group (Upper Permian), Pennine Lower Coal Measures (Carboniferous) and Millstone Grit Groups all had reasonable porosities averaging 11-14%, although they have low net to gross values (7-13%). The Cumbrian Coast Group (Upper Permian) includes some evaporite deposits of no reservoir potential themselves, but these could potentially act as a barrier (trap) to any hydrocarbons beneath them. Most of the other units in the wells examined show heterogeneous properties with low net to gross. Although the Millstone Grit Group generally has a low net to gross because of its high clay volume, cleaner reservoir intervals with reasonable porosity exist and more study on the permeabilities and distribution of these could be worthwhile. The basal limestones appear cleaner, but have very low matrix porosities and so are not considered to be potential reservoirs unless fractures contribute to their porosity and permeability (not examined here). Note that given the limited number of wells examined and the regional scale of the project, more detailed study of the reservoirs including mapping property trends and identifying prospective intervals was out of scope of this project. A brief examination of the distributions of net to gross and average porosities, both by formation in each well and for the total Palaeozoic interval in each well was not able to highlight any particular property trends or geographic areas with particularly favourable properties

Reservoir evaluation of 3 wells in the Palaeozoic of the Orcadian Basin (UK North Sea) : petrophysical interpretations of clay volume, porosity and permeability estimations

This report details the reservoir evaluation of 3 wells across the Palaeozoic rocks of the Orcadian Basin of the UK North Sea for the 21CXRM Palaeozoic project. This reservoir evaluation is based on the petrophysical interpretation of available digital wireline log curve data for 3 wells and associated digitised core porosity and permeability data (14 to 67 measurements available for each well) across the Palaeozoic interval (according to reinterpreted stratigraphic formations defined and correlated for this project, documented in Whitbread and Kearsey (2016)). Outputs of this part of the project include continuous (along borehole) interpretations of porosity, clay volume, and include basic permeability estimations. These interpreted curves were used to calculate Net to Gross (NTG) values and average porosities and permeabilities for each formation in each well analysed. The 3 wells were selected based on availability of core data (to allow calibration of log-derived porosities and the estimation of permeabilities) to determine reservoir quality potential in the Devonian interval. The results complement the Hannis (2015) study on Carboniferous and Devonian reservoirs of the Central North Sea. Other reports document the stratigraphic extent of these units (e.g. Whitbread and Kearsey, 2016). Given the limited number of wells examined and the regional scale of the project, more detailed study of the reservoirs including mapping property trends and identifying prospective intervals are not included in this report. The best reservoir properties appear to be found in the Middle Eday Sandstone Formation, which, in well 13/19-1, has a NTG of 1, an average porosity of 14% and the highest permeabilities recorded of the 3 wells (an average of 20 mD with values up to 174 mD estimated from logs calculations derived from associated core data). The Permian Rotliegend Group, and Zechstein Group also show favourable properties, slightly lower NTG and porosities than the Middle Eday Sandstone Formation (Tables 1 and 3) and although no core was available in the 3 wells examined to derive specific permeability measurements from them, log derived estimates from deeper core were up to 208 mD. The Buchan Formation also shows favourable properties, particularly in one well (13/19-1) where NTG was 1, porosity 12% and permeabilities estimated as up to 110 mD. There may also be potential reservoir in the Upper and Lower Strath Rory Formations, as they have good NTG (0.92 and 0.56 respectively) and average porosities (16% and 10% respectively). However, from the data examined, their permeabilities appear comparatively much lower (averages estimated as less than 1 mD, with the highest values estimated (and measured on core) around 5 mD. Over these potential formations of interest, log responses suggest that there are relatively thick intervals of clean “good” reservoir intervals, in comparison to the CNS reservoirs studied which were dominated by a heterolithic succession (Hannis, 2015). The Eday Flagstones, Lower Eday Sandstone and Kupfershiefer formations appear to have poor reservoir properties. The Orcadia and Struie formations and the Granitic basement are not considered to have any in-matrix reservoir potential

Reservoir evaluation of 12 wells in the Devonian-Carboniferous of the Central North Sea : petrophysical interpretations of clay volume, porosity and permeability estimations

This report details the reservoir evaluation of 12 wells across the Devonian-Carboniferous rocks of the UK Central North Sea for the 21CXRM Palaeozoic project. A companion report examines the source rock potential (total organic carbon content) of the non-reservoir intervals (for a different, but overlapping set of wells) (Gent, 2015). This reservoir evaluation is based on the petrophysical interpretation of available digital wireline log curve data for the 12 wells and digitised core porosity and permeability data (1 to 281 measurements available for 7 of the 12 wells) across the Devonian-Carboniferous interval (according to reinterpreted stratigraphic formations defined and correlated for this project, documented Kearsey et al. (2015). Outputs of this part of the project include continuous (along borehole) interpretations of porosity, clay volume, coal presence, and include basic permeability estimations where sufficient data exists to generate these. These interpreted curves were used to calculate Net to Gross (NTG) values and average porosities and permeabilities for each formation in each well analysed. The Yoredale and the Scremerston formations appear to have the most favourable reservoir properties in terms of porosity (up to 19% and 15% respectively), and permeability (up to 45.28 mD and 785.52 mD respectively). However, they have relatively low NTG values (0.27 & 0.18 respectively). The Fell Sandstone Formation has the greatest NTG of the intervals examined (0.61), but porosity and permeability values are lower (0.13 and 42.69mD are the greatest average values from the wells examined). All these reservoirs show heterogeneous character in the geophysical log response, with reservoir intervals interbedded with non-reservoir. Other reports document the stratigraphic extent of these units (e.g. Kearsey et al., 2015). Note that given the limited number of wells examined and the regional scale of the project, more detailed study of the reservoirs including mapping property trends and identifying prospective intervals was out of scope of this project. A brief examination of the distributions of net to gross and average porosities, both by formation in each well and for the total Devonian-Carboniferous interval in each well was not able to highlight any particular property trends or geographic areas with favourable properties

Extraction old and new: toxic legacies of mining the desert in southwestern Africa

This visual essay draws on a 2017 journey from the South African Cape to the Khan valley of Namibia, tracing toxic (deter)mining legacies of roots and routes of mineral extraction. Copper, ilmenite, diamond, zinc and uranium exploitations encounter indigenous presence and resistance as colonial and corporate mineral ‘rushes’ intersect with local realities and cultural landscapes. Environmental mitigation efforts and ‘offsetting’ schemes also leave toxic heritage in their wake as they greenwash profit-driven extractive agendas. Images from sites visited evoke the materialities and atmospheres of these localities, and connections between them

Petrophysical interpretation of selected wells near Liverpool for the UK Geoenergy Observatories project

This report details the petrophysical evaluation of 2 onshore wells near Liverpool UK: Kemira 1 (SJ47NE/101) and Ince Marshes 1 (SJ47NE/100). The results contribute to the geological characterisation for a monitoring experiment in Cheshire for the UK Geoenergy Observatories project. The evaluation is based on the petrophysical interpretation of available digital wireline log curve data for the two wells across the whole logged interval (according to reinterpreted stratigraphic formations defined and correlated for this project). Associated digitised sample data (XRD, XRF, TOC data) is available to help cross-validate the interpretation for 1 of the 2 wells. Outputs for this evaluation include continuous (along borehole) interpretations of clay volume, porosity, and total organic carbon (TOC). These interpreted curves were used to examine the proportions of reservoir rock and shale for each formation in each well and their respective properties. Net reservoir intervals were defined by those intervals where the clay volume was less than 50%, the porosity was more than 5% and no coal intervals were present. Net Shale intervals were defined by those intervals where the clay volume was more than 50% and no coal intervals were present. The Kemira 1 well was logged from the Triassic Bromsgrove Sandstone Formation down to the Carboniferous Westphalian A unit, the base of which is not penetrated (~1400 m logged between 32-1433 m). Data is somewhat limited compared to the Ince Marshes 1 well, comprising parts of a standard log suite, and the curve data is machine-digitised from the legacy log field prints. (Resistivity curves are only available over part of the well; the neutron log was recorded in sandstone matrix units and the specific transformation to limestone matrix units (required for the interpretation) is unknown and has been guessed at; there is less data available for this well in terms of ancillary curves or sample analysis to cross check results than for the Ince Marshes 1 well). The results of the interpretation for this well should therefore be treated with appropriate caution. The Ince Marshes 1 well was logged over the Carboniferous interval comprising the Westphalian C-A and the Millstone Grit Group, the base of which may be drilled through, but was unable to be logged due to hole difficulties (~1084 m logged between 368-1452 m). This well was drilled and logged more recently than the Kemira 1 well and has much more associated data including more advanced logging tools such as image logs, dipole sonic, and elemental spectroscopy to give formation mineral compositions. Sidewall cores were also collected and these and drill cuttings were analysed using various techniques to determine mineral, elemental and total organic carbon contents at the sample depths. There is therefore much more data available with which to cross check and verify results and as such the results of the interpretation can be regarded with a higher level of confidence than those of the Kemira 1 well. The Kemira 1 well contains strata of Permian and Triassic age. These have high reservoir net to gross (NTG) values of 0.99 or 1 (i.e. 100% net reservoir). Their average porosities range from 18- 25% and the Sherwood Sandstone Formation shows the highest average porosity at 25%. Both wells contain older, Carboniferous rocks and these have much lower NTG values, all containing less than 50% reservoir rocks (NTG ranging from 0.08-0.41). Their porosities are also lower, ranging from 8-15%, apart from the Westphalian C unit in the Kemira 1 well, which are anomalously high (23%) resulting from the presence of coal intervals and porosity artefacts adjacent to them (a software/parameter selection limitation Total organic carbon (TOC) was calculated for the rocks beneath the Westphalian B unit in the Ince Marshes 1 well. Shales with TOC values calculated as greater than 1.5 wt% were considered ‘TOC-rich’. The ratio of these to the total formation thicknesses are generally very low: 0.08-0.15 for the Westphalian A and 0.11-0.24 for the Millstone Grit. The lower end of the range is where a OR/17/037; Draft 0.1 Last modified: 2017/05/04 10:09 2 minimum shale thickness cut-off of 2 m is considered. The TOC rich shale in the Westphalian A has an average of 3.38 wt% TOC. However, individual intervals within the unit show typical curve responses for a mature source interval containing hydrocarbons and reach TOC values up to 9.18 wt%. The TOC rich shales in the Millstone Grit have an average of 2.9 wt% TOC. The TOC values measured in samples from sidewall cores and cuttings extend beneath the base of the geophysical well logs to 1575 m. There are 44 measured values averaging 2.89 wt% TOC with a maximum of 6.93 wt% TOC

Interval-Valued Intuitionistic Fuzzy Topsis-Based Model For Troubleshooting Marine Diesel Engine Auxiliary System

In this paper, we present an interval-valued Intuitionistic Fuzzy TOPSIS model, which is based on an improved score function for detecting failure in a marine diesel engine auxiliary system, using groups of experts’ opinions to detect the root cause of failure in the engine system and the area most affected by failures in the diesel engine. The improved score function has been used for the computation of the separation measures from the intuitionistic fuzzy positive ideal solution (IFPIS) and intuitionistic fuzzy negative ideal solution (IFNIS) of alternatives while the criteria weight have been determined using an intuitionistic fuzzy entropy. The study is aimed at providing an alternative method for the identification and analysis of failure modes in engine systems. The results from the study show that although detection of failures in Engines is quite difficult to identify due to the dependency of the engine systems on each other, however using intuitionistic fuzzy multi-criteria decision-making method the faults/failure can easily be diagnosed

Petrography and diagenesis of the Bunter Sandstone Formation in the UK Southern North Sea

This report describes a regional petrographic study of the Triassic aged Bunter Sandstone Formation (BSF) in the northern part of the UK Southern North Sea. To date, the spatial relationships leading to the prediction of regional reservoir quality in the BSF in terms of its potential for storage of CO2 or hydrogen have not been fully understood. Previous studies have been largely focused on the hydrocarbon fields and these have shown that the presence or absence of diagenetic cements can both create barriers and enhance pathways for fluid flow. More recent studies investigating CO2 storage potential through regional dynamic modelling have demonstrated the importance of physical and chemical property distributions. This applies not only to the immediate injection and containment of the CO2 plume but also to the impacts of the pressure footprints created from injecting a large volume of fluid and the potential interaction between neighbouring sites. However, a consensus allowing an extrapolation of reservoir quality prediction to the more data-poor saline aquifer parts of the BSF has not proved straightforward as evidenced by results of a CO2 storage exploration well drilled in 2010. This has highlighted the importance of improving regional understanding of reservoir storage potential for future CO2 or hydrogen appraisal activities. This report adds to the body of research attempting to discern reservoir rock property distribution in the BSF through detailed petrographic observations to understand their diagenetic histories through the analysis of 83 samples across 12 wells. Diagenetic observations are described and presented as a proposed diagenetic history in the figure below. Detrital and near-surface diagenesis (eodiagenetic) characteristics of the BSF are consistent with terrestrial deposition under arid conditions, principally with fluvial origins and a minor aeolian input. The eodiagenetic phases that are particularly characteristic of arid conditions include widespread and locally abundant nodular grains (carbonate and sulphate) and cements (also carbonate and sulphate) that preserve un-compacted and expanded (displaced) grain frameworks. Additionally, some cements have evaporitic textures (e.g. pseudomorphed ‘desert rose’ forms, enterolithic anhydrite). The carbonate nodules (calcite and dolomite) are an abundant framework grain constituent throughout the BSF. These are characterised by dominantly rounded sand sized forms with concentric structures defined by sequential zones of micritic and/or radial fibrous carbonate, and hematitic clays. Nodule cores comprise a mix of silt-grade silicate grains, mixed micrite and clays, and nodule fragments with evidence of varied degrees of reworking. They are most abundant in wells from the central to eastern parts of the study area (Quadrants 43 and 44). These nodules are not ooids sensu stricto, because evidence that they formed through both surface and shallow sub-surface processes is abundant and widespread. Carbonate nodules are locally concentrated in laminations and, together with associated eodiagenetic cements, form dolocrete and calcrete layers, mostly hosted in finer grained laminations with sub-millimetre to centimetre (plus) scale thicknesses. Variable lateral continuity typically reflects the structure of the hosting sedimentary laminations. These features present partial barriers to larger scale porosity interconnectivity and are of sub-seismic-resolution. Subsequent burial diagenesis (mesodiagenesis) is dominated by the formation of further widespread pore-filling cements, mostly of anhydrite and halite. These cements are typically also partially replacive of eodiagenetic nodules. Several episodes of cementation and some of dissolution, have been identified. These are generally poikilotopic cements, which in the case of anhydrite, differentiates it from eodiagenetic sulphate nodules. Anhydrite largely pre-dates halite. Enclosure of anhydrite by halite is largely passive (i.e. anhydrite crystals have euhedral margins), but there is local evidence for dissolution of anhydrite prior to, or during, halite emplacement. Both of these cement phases are preferentially developed in coarser sandstones. Major halite cement is only observed at and below a current burial depth of ~1400 m. This suggests that the halite distribution must be, in part, controlled by current and / or recent conditions. Locally, halite dissolution has occurred preferentially along coarser grained sandstone laminations in otherwise fully cemented intervals. Diagenetic silicate cements are rare over most of the study area. The exceptions to this are samples from the western edge of the study area (Quadrant 41 wells) where compaction textures are well developed and quartz cement is widespread. Heterogeneity of compactional textures is a key characteristic of the BSF observed across the study area. On a sub-millimetre scale, areas of well compacted framework grains exist next to areas with open and expanded fabrics. The looser textures can only partially be explained by grain replacement and dissolution, and the current distribution of diagenetic cements. We conclude that the samples were partially cemented prior to maximum burial, but the cement distribution has changed subsequently. It is clear that the halite and anhydrite cements in their current distribution, cannot have been the primary control on the degree of compaction currently observed in the BSF. This observed textural heterogeneity is consistent with our proposed diagenetic model, which infers that the sandstones had abundant, but not complete, early cements that preserved shallow framework fabrics. As these cements were partial, compactional fabrics were created in the surrounding less- or un-cemented zones. Subsequent dissolution, replacement and / or mobilisation of some or all of the cement phases, post maximum burial, has resulted in the widely recognised heterogeneous compaction fabric which does not correspond to current cement distributions. Since both anhydrite and halite show evidence for both multiple phases of formation and partial dissolution, these are the primary candidate minerals for dissolution / mobilisation. As these phases have also partially replaced some of the framework carbonate nodules, then their subsequent dissolution / mobilisation could also create an apparently uncompacted fabric. One expected outcome of abundant, pre-maximum-burial cementation, is that BSF porosities should be detached from a simple linear variation with maximum burial depth. This is what is observed for the BSF. It is recognised that the conclusions of this study are constrained by the limited numbers of samples (for the extent of the study area) and the fact that they are all sourced from hydrocarbon-interest boreholes which have targeted potential reservoir structures. Many of these structures are a consequence of site-specific halokinesis, therefore with potentially atypical thermal, fluid and structural conditions. Whilst we have gained significant insight into the diagenetic paragenesis, we are unable to adequately predict porosity, a major interest for CO2 and energy storage interests. This is a consequence of the heterogeneities of the BSF in texture, cement distribution and paragenesis. To improve the remaining knowledge gaps and predictabilities of major reservoir properties, further studies are needed: 1. To obtain a better understanding of the distributions of grain fabrics and diagenetic cements, in order to improve predictability of pore size and connectivity, and porosity distribution at a regional scale: • Extend the study to include more samples for detailed modal analysis and minus cement porosity calculation. • Apply petrographic image analysis to more samples and a wider range of properties to characterise actual porosity, grain size and compactional fabric distributions. 2. Develop a high-resolution diagenetic sequence through isotopic studies of the main cements, tied to their paragenetic sequencing using: • Strontium isotope analysis (87Sr/86Sr) to inform the origins of solutes in the diagenetic fluids, and extent of rock-water interaction (target phases - calcite, dolomite, anhydrite and halite). • Stable (oxygen, carbon, sulphur) isotope analysis (δ13C, δ18O and δ34S). These techniques would further inform the mineralisation temperature, and carbon and sulphur sources (target phases - anhydrite, dolomite and calcite cements). • U-Pb dating to obtain absolute dates for carbonate mineral formation. Using petrographically-guided targeting, this will place the paragenetic sequence in absolute time. A major issue for this will be potential contamination of the carbonate phases by finely-disseminated hematite, which is known to preferentially concentrate U and Pb

Modeling the Influence of a Variable Permeability Inclusion on Free-Surface Flow in an Inclined Aquifer

The interaction of sub-surface, gravity-driven flows with inclusions of different permeabilities are investigated theoretically using a model that exploits the relative shallowness of the motion. Numerically computed solutions for steady motion around cylindrical inclusions reveal a range of behaviors dependent on the ratio of the interior to exterior permeability and a dimensionless flow parameter that measures the far-field thickness to the product of the gradient of the slope down which the fluid flows and the width of the inclusion. When the inclusion is relatively narrow, the depth of the flow is little changed from its far-field value and the fluid is focused into inclusions of higher permeability and deflected around those of lower permeability. However, if the inclusion is relatively wide then three qualitatively different regimes emerge, dependent on the ratio of permeabilities. When the interior and exterior permeabilities are similar, then negligible deviation of the flow occurs apart from within thin transition layers at the boundary of the inclusion. When the permeabilities differ significantly, the flow forms deep ponds at either the upstream or downstream boundary of the inclusion for relatively low or high permeability inclusion, respectively, which arise due to deflection or focusing. In each case, asymptotic relationships are derived between the depth of the flow and the parameters. Inclusions of differing cross-section are also analyzed numerically and analytically to draw out the interplay between adjustment, deflection and focusing

External review of the storage plan for the Peterhead Carbon Capture and Storage Project

This document summarises the findings of an external independent review of the storage plan for the proposed Peterhead Carbon Capture and Storage project which aims to store up to 20 million tonnes (Mt) of CO2 within the framework of the European Directive on the geological storage of CO2. The Peterhead Carbon Capture and Storage Project proposes to capture carbon dioxide (CO2) from an existing gas-fired power-station at Peterhead and to store this in geological strata at a depth of around 2600 m beneath the outer Moray Firth. The plan is to store 10 - 15 Mt of CO2 over a ten to fifteen-year period commencing around 2020, but the site is being qualified for 20 Mt to allow for potential extension of the injection period. Storage will utilise the depleted Goldeneye gas condensate field with the Captain Sandstone reservoir as the primary storage container. The Storage Site covers some 70 km2, and comprises the Captain Sandstone and underlying strata of the Cromer Knoll Group, bounded by a polygon some 2 to 3 km outside of the original Goldeneye oil-water contact. The Storage Complex is larger, around 154 km2, bounded some 2 to 7 km outside of the original oil-water contact, and extending upwards to the top of the Dornoch Mudstone at a depth of more than 800 m. The top-seal of the primary container is a proven caprock for natural gas and is formed by the mudstones of the Upper Cromer Knoll Group, the overlying Rødby and Hidra formations and the Plenus Marl. A number of additional seals are present in the overburden within the Storage Complex, as are a number of potential secondary containers which could also serve as monitoring horizons. The geological interpretation of the storage site is based on the comprehensive datasets acquired during the discovery, appraisal and development of the Goldeneye field, and also data from other wells, fields and seismic surveys in the surrounding area. The static geological model of the storage site and adjacent aquifer has been stress tested for the key uncertainties, and it is considered to be robust. The storage capacity of the Goldeneye structure has been calculated using both static (volumetric) methods and dynamic flow modelling together with uncertainty analysis. Total estimated capacity of the structural closure is in the range 25 to 47 Mt and so robustly exceeds the proposed injected amount