UK North Sea Research Articles

Site characterization of the Endurance CO 2 store, Southern North Sea, UK

The Endurance saline aquifer CO 2 store in the UK North Sea is the planned storage site for CO 2 emissions that will be captured from the East Coast Cluster. The site has been characterized to assess its suitability for injectivity, containment and capacity. The injection target is the Early Triassic Bunter Sandstone Formation, consisting of fine-grained sandstones deposited in fluvial, lacustrine and playa lake environments that were subject to repeated aeolian and fluvial reworking. The sandstones have excellent reservoir quality and are likely to be well connected due to the lack of preserved heterolithic layers. The trap is a large, four-way dip-closed anticline, sealed by mudstones and evaporites of the Middle Triassic Dowsing Formation. The top seal sediments are laterally extensive and geomechanically strong, and faulting observed in the overburden does not appear to connect to the reservoir, providing confidence that CO 2 containment will be secure. The risk of leakage through existing legacy wells is assessed as low. The maximum effective CO 2 storage capacity is c . 450 Mt: Phase 1 development of 100 Mt is equivalent to a storage efficiency factor of 3%, which is achievable without the need for brine production. First injection is planned from 2027.

Ion-Exchange Membranes Extract Lithium From North Sea Oilfield Brines

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215585, “Lithium Extraction From North Sea Oilfield Brines Using Ion-Exchange Membranes,” by Botelho Disu, Roozbeh Rafati, and Amin S. Haddad, University of Aberdeen, et al. The paper has not been peer reviewed. _ The annual demand for lithium for low-carbon technology applications has been growing exponentially. A necessity exists in the current environment for continuous lithium production from both conventional sources and novel extraction sites from alternative brine resources such as oil fields and geothermal sites. in the complete paper, the lithium potentiality of the UK North Sea is evaluated. Identification of North Sea Lithium-Rich Oil and Gas Fields Maps show lithium-ion concentration diffusing from 55 ppm in the western region into low concentrations in the central, northern, and eastern regions of the UK North Sea. Such estimates suggest lithium enrichment in oilfield brine from the Beatrice, Clymore, Gannet, Cly, Auk, and Flumar fields. However, because such map distribution of lithium is achieved based only on one-third of the imputed data, a correlative evaluation with the entire body of data is needed to provide a much more feasible interpretation. When lithium distribution was evaluated simultaneously with strontium/iron/potassium (Sr/Fe/K) total dissolved solids, the rich brine was primarily located across the central, eastern, southern, and western fields. The central and eastern concentrations were estimated to have a lithium-rich brine with concentrations of up to 40 ppm, with lithium-ion presence gradually increasing toward the east. Most of the fields in this region are oil fields, including Montrose, Arbroath, Ula, Nelson, Brisling, Gyda, Ekofisk, and Bream, with Harald possibly being the only gas field with lithium-enriched brine. On the other hand, the lithium-rich fields in the southern and western regions are all gas fields, including the Esmond, Anglia, Lemman, Ann, and Viking fields. Statement of Theory and Definition The economic feasibility of lithium extraction from brine has been observed to be a function of its initial concentration. For oilfield brines, when using novel direct-lithium-extraction (DLE) technologies, the brine concentration economic feasibility for production is reduced to a cutoff benchmark of 50 ppm. However, ongoing developments in DLE technologies envision a feasible, efficient, and highly selective recovery of lithium from brines with low concentrations, even sea water. Manganese ion-sieve powder is a DLE technology that has gathered growing interest. However, one of the main challenges of its application in continuous industrial processes consists of operational challenges that its original powder form can cause. Therefore, forming is necessary if ion-sieve adsorbents are to have an industrial application. This paper has reported and discussed the experimental results of forming the adsorbent powders into different ion-exchange membranes (foam, flat sheet, and granular spherical beads) and their application for lithium extraction from simulated North Sea brine. The complete paper details the description and application of experimental equipment and processes.

Quantifying the mineral magnetic signature of petroleum systems and their source rocks: a study on the Inner Moray Firth, UK North Sea

SUMMARY This study aims to expand on existing connections between magnetic minerals and hydrocarbons within petroleum systems. Previous studies have focussed on single-source petroleum systems whereas this study, for the first time, analyses a multi-source petroleum system to investigate potential correlations between different kerogen type source rocks and magnetic minerals. To do this, the study investigates the magnetic mineral characteristics of the Inner Moray Firth (IMF), UK North Sea, through room-, low- and high-temperature techniques, and correlates this to published basin and petroleum systems modelling results that show a three-source hydrocarbon mix. Magnetic mineral analysis identifies extensive evidence for magnetite, goethite and siderite, alongside more minor lepidocrocite and iron sulphides. Although we find that magnetite is ubiquitous within the IMF, its abundance is relatively low, and, in contrast, the relatively magnetically weak goethite is more likely the most abundant magnetic mineral throughout the IMF. In agreement with previous studies, we find magnetic enhancement at oil-water contacts (OWCs); however, here, we identify two different magnetic enhancement processes at OWCs in wells, which are dependent on the amount of sulphur available in the local environment. Wells with low levels of sulphur have increasing levels of magnetite towards the OWC, with the magnetic enhancement occurring at the top of the water-saturated section. Sulphur-rich environments display an increase in iron sulphides near the OWC at the bottom of the oil-saturated sediments. Additionally, we confirm the presence of siderite as indicator of upward vertical migration. Combining with petroleum system model predictions, we find direct links between iron hydroxide presence and Type I and II–III kerogen source rocks, and iron sulphide presence with Type II kerogen source rocks. This study shows the potential for further utilization of magnetic mineral analysis within hydrocarbon exploration and petroleum system definition.

Evaluation of shale oil and gas plays - Part I: Shale reservoir property modelling of the North Sea Kimmeridge Clay Formation

The Kimmeridge Clay Formation (KCF) forms the source rock for most conventional hydrocarbon accumulations within the UK North Sea. However, only a few previous studies have analyzed the potential of the KCF for unconventional resources (i.e., shale oil and gas).Here, we use machine learning techniques combined with established rock property equations to generate geochemical, petrophysical and geomechanical logs for 16 wells within Quadrant 15 of the Outer Moray Firth, UK North Sea. The neural network models used to generate geochemical logs are trained using the Levenberg-Marquardt backpropagation algorithm. The generated well logs and new KCF depth maps, constrained by an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 48 wells, are used for 3D geostatistical modelling of KCF properties across the area. The resulting KCF property maps allow us to assess the shale oil and gas play potential across the region.Our results suggest good organic richness and hydrocarbon yield potential for the KCF within the study area, with up to 9 wt% original total organic carbon (TOCo), 48 mg/g original hydrocarbon yield (S2o), and 607 mg/gTOC original hydrogen index (HIo). Modelled total porosity values range between 2 and 13%, and brittleness indices lie between 25 and 65%, within the range reported for proven shale oil and gas plays.A sweet spot map, created by integrating our modelled KCF properties, indicates prospective areas for shale oil and gas exploitation within the central Witch Ground Graben, and to a lesser extent areas of the Piper Shelf and Claymore-Tartan Ridge. These areas show good potential based on all investigated properties, with respect to industry standards.

Geochemical characterization and paleo-burial history modelling of unconventional resources: A case study from the Kimmeridge Clay Formation (KCF) in the UK North Sea

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data.

Lithology and Lithofacies Characteristics of Deeply Buried Clastic Reservoirs in Alternating Wet-arid Climate and its Hydrocarbon Significance

There have been series of HPHT (high temperature and high pressure) reservoirs with good quality and high productivity discovered in the Triassic Skagerrak Formation in the Central Graben of the UK North Sea. The bottlenecks for further E&P activity are the complicated depositional facies and high reservoir heterogeneity. The main reservoir space is a mixed porosity network composed of primary pores, micro-pores, secondary pores, secondary micro-pores and micro-fractures. Reservoirs of the Skagerrak Formation have greatly varied lateral connectivity as well as poor vertical connectivity. In the case of sufficiently high pressure differentials, hydrocarbon can be fed from high-potential area to low-potential area. There is no simple linear relationship between depth and reservoir quality. The primary depositional texture (grain size/sorting/clay content, etc.) linked to facies has a fundamental control on reservoir quality. Clean and well sorted cross laminated sandstone has the best reservoir quality, while the reservoir quality of planar laminated sandstone decreased due to increased degree of compaction caused by mica drapes. The reservoir quality of the fine-grained ripple cross laminated sandstone is even poorer than that of the planar laminated sandstone, due to abundant mica and clay drapes. Mottled bioturbated sandstone is fine grained with high clay content, which is more muddy because of containing burrows and insect larva. Pedoturbated sandstone has the poorest reservoir quality due to severe dolomite cementation. The dominant detrital material of the Skagerrak Formation is feldspar that provides abundant secondary porosity by alteration and dissolution. Chlorite coats are commonly developed and stained with residual oil or bitumen, which clearly inhibits quartz cementation and feldspar overgrowth. The presence of these clay coats contributes to the preservation of anomalously high porosity at depth in the cleaner and coarser grained fluvial channel facies. The Skagerrak formation facies is a dryland fluvial-lacustrine depositional system which is controlled by fluctuations of depositional base level due to salt mobilisation. The Skagerrak formation consists of several cycles that are vertically separated by lacustrine mudstone. The reservoir permeability system is composed of active fluvial channel sandstones, terminal splay sandstones, abandoned fluvial channel sandstones, minor channel sandstones connecting fluvial channel and terminal splay, as well as low-permeability faults, while the active fluvial channel sandstone is the “sweet spot”. The analysis of controls on deeply buried reservoir quality is significant to precisely predict “sweet spot” in the Skagerrak Formation.

Development of Methods for Top-Down Methane Emission Measurements of Oil and Gas Facilities in an Offshore Environment Using a Miniature Methane Spectrometer and Long-Endurance Uncrewed Aerial System

Summary With atmospheric methane concentrations rising and spurring increased social concern, there is a renewed focus in the oil and gas industry on methane emission monitoring and control. In 2019, a methane emission survey at a bp asset west of Shetland was conducted using a closed-cavity methane spectrometer mounted onboard a long-endurance fixed-wing uncrewed aerial vehicle (UAV). This flight represents the first methane emissions survey of an offshore facility with a miniature methane spectrometer onboard a UAV with subsequent flights performed. A small laser spectrometer was modified from an open-cavity system to a closed-cavity onboard the aircraft and yielded in-flight detection limits (3 seconds) of 1,065 ppb methane above background for the 2019/2020 sensor version and 150 ppb for the 2021 sensor versions. Through simulation, the minimum detection limits of sensors in mass flow rate were determined to be 50 kg/h for the 2019/2020 campaign and 2.5 kg/h for the 2021 campaigns, translating to an obtainable measurement for 23% and 82% of assets reporting higher than 1 kg/h according to the 2019 Environmental Emissions Monitoring System (EEMS) data set, respectively. To operationalize the approach, a simulation tool for flight planning was developed using a Gaussian plume model and a scaled coefficient of variation to invoke expected methane concentration fluctuations at short time intervals. Two methods were developed to calculate offshore facility-level emission rates from the geolocated methane concentration data acquired during the emission surveys. Furthermore, a Gaussian plume simulator was developed to predict plume behavior and aid in error analysis. These methods are under evaluation, but all allow for the rapid processing (<24 hours) of results upon landing the aircraft. Additional flights were conducted in 2020 and 2021 with bp and several UK North Sea operators through a Net Zero Technology Centre (NZTC)-funded project, resulting in a total of 18 methane emission survey flights to 11 offshore assets between 2019 and 2021. The 2019 flight, and subsequent 2020–2021 flights, demonstrated the potential of the technology to derive facility-level emission rates to verify industry emission performance and data.

Chapter 10. Sequence stratigraphy in the exploration for North Sea Jurassic stratigraphic traps

Abstract The application of sequence stratigraphic concepts and methods significantly enhances the evaluation of stratigraphic traps. In this chapter, five examples of, as yet undrilled, potential UK North Sea Jurassic combination stratigraphic traps, from the East Shetland Platform, South Viking Graben, Inner Moray Firth and Central Graben, are discussed and the potential application of sequence stratigraphic methods in their evaluation considered.

Defensive pessimism-like thinking in practice: the (dys)functional strategy for coping with risk uncertainty in the offshore oilfield?

UK Continental Shelf (UKCS) offshore oilfield drilling is recognised as a high-hazard occupation that occurs in one of the riskiest locations in the world. Dangerous machinery, combustible hydrocarbons, unpredictable weather conditions, rapidly shifting situational factors, rotating crews, and lengthy travel over rough seas by helicopter are just some salient risk-factors. At present, little scholarly research explores how regular offshore workers develop cognitive strategies to attempt to cope with ever-present risks. This research draws on an embedded ethnography of a remote offshore oilfield drilling platform in the UK North Sea. The risks of working offshore and the strategies workers developed and employed to deal with continual risk uncertainties were discussed in face-to-face interviews with thirty-five active drilling crew as they laboured on complex well-drilling operations. Notably, defensive pessimism (DP) like thinking was recurrently exhibited, with many workers recounting detailed narratives of mental role-play for ‘worst case’ offshore and helicopter travel scenarios. Often, thinking appeared interlinked with strengthening motifs for workers’ preparation and planning skills regarding occupational risk possibilities. These strategies are presented, as is a discussion of the effects such strategies had upon oilmen. The benefits of growing scholarly conversation surrounding DP-like thinking in practice are highlighted. alongside the methodological application of DP theory for further study surrounding practical development of coping strategies in similar high-risk workspaces.

Application of Pressure Transient Analysis in Highly Deviated Reservoir

Conventional pressure transient analysis (PTA) alone may not be a reliable scientific tool for safe oilfield operations and reservoir development, according to earlier studies. The pressure responses were plotted using a skilled simulator in this study to examine the application of PTA and produce an exhaustive analysis. The Nelson oilfield, which is in the UK's North Sea, specifically addressed reservoir characterization and field development in a highly deviated well. The work also used sensitivity analysis and log-log diagnostic plotting to create a model that best matched a short pressure build-up (PBU) test. As a result, reservoir characteristics like permeability, porosity, and reservoir height were modeled, computed, and analyzed alongside wellbore characteristics. For various wells in the Nelson field, averages of core logs, seismic data, and wireline logs were taken to verify the accuracy of these models. Reservoir characterization was accomplished using PTA in conjunction with field data, which improved pre-existing macro and micro datasets. The use of a simulator and such additional data undoubtedly helped to improve field development strategies as well.

Basin and petroleum systems modelling to characterise multi-source hydrocarbon generation: A case study on the inner Moray Firth, UK North Sea

In this paper we used basin and petroleum systems modelling (BPSM) of the Inner Moray Firth, UK North Sea to identify the contributions of different source rocks, mixing ratios of accumulated hydrocarbons, and migration pathways of charging the three known fields in the basin – Beatrice, Jacky and Lybster fields. In this study, model scenarios indicate that extensive faulting is a key control on hydrocarbon migration and accumulation, that the accumulations in the basin do not contain Kimmeridge Clay Formation oil, and that they are mixed in a ratio of ∼65:35 Devonian Fish Bed vs Pentland Formation contribution. Migration modelling suggests that Beatrice Field was charged predominantly by proximally sourced hydrocarbons, whereas Jacky and Lybster fields were charged by a near-even mix of proximal and deep-basin hydrocarbons from the Great Glen Sub-Basin.

The value of core in mature field development – examples from the UK North Sea

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

Effect of Hydrocarbon Presence and Properties on the Magnetic Signature of the Reservoir Sediments of the Catcher Area Development Region, UK North Sea

This paper presents a detailed study investigating the effect of hydrocarbon presence on magnetic mineral diagenesis in sediments from the Catcher Area Development (CAD) region, UK North Sea, between 1,000 and 1,500 m (True Vertical Depth Sub-Sea). Magnetic analysis of core samples from hydrocarbon fields of the region and nearby dry-well sandstones (background) was carried out to determine if their signatures can serve as a proxy for understanding petroleum reservoir systems. From the background samples, nanometric and micron-sized magnetite, hematite and titano-iron oxides, were identified. Hydrocarbon presence in the reservoir sediments was found to diminish the iron-oxide signature and favour the precipitation of hexagonal pyrrhotite, siderite and potentially vivianite, lepidocrocite, greigite and paramagnetic iron sulphides. Hexagonal pyrrhotite was found at the oil-water transition zones. This relationship is possibly related to biodegradation at this interface. Siderite was found in increased abundance at shallower depths within the reservoir, which we attribute to hydrocarbon vertical migration and biodegradation. The interbedded shales also experienced significant magnetic mineral diagenesis that depended on its proximity to the hydrocarbon plume. These findings suggest that mineral magnetism can be applied to the identification of oil-water transition zones, reserve estimation, production planning and the determination of hydrocarbon migration pathways. It also suggests that mineral magnetic methods can be used to estimate the timing of hydrocarbon migration.

Siderite occurrence in petroleum systems and its potential as a hydrocarbon-migration proxy: A case study of the Catcher Area Development and the Bittern area, UK North Sea

We report a detailed magnetic study of Tertiary sandstone cores from the Bittern field, West Central Graben, and Catcher Area Development (CAD), West Central Shelf, UK North Sea that identified siderite as a potential magnetic proxy for the differentiation of vertical and lateral hydrocarbon migration. Magnetic hysteresis experiments revealed increased presence of paramagnetic minerals in the oil-stained sandstones of the fields compared to the nearby dry Tertiary (unstained) sandstone of offset wells. Within the oil-stained sandstones, the paramagnetic proportion is highly variant, with low and high paramagnetic sections present. Detailed experiments including thermomagnetometry between 10 K and 900 K and XRD analysis, combined with Mössbauer spectroscopy confirmed that this increase in paramagnetic response was primarily due to the formation of siderite. An increase in the quantity of paramagnetic clays and occasionally pyrite also contributed to the increased response. Siderite and iron sulphides have been interpreted to form during hydrocarbon migration and potentially oil biodegradation. We propose that hydrocarbon migration pathways may be indicated by the distribution of siderite. We argue that as hydrocarbons migrate vertically and the equilibrium partial pressure of CO2 with the environment reduces, essential HCO3− is produced which reacts with available Fe2+ to form siderite if all the other diagenetic requirements for its formation are met. The distribution of siderite and magnetic susceptibility values along the oil-stained layer provides a tool for the determination of the migration pathways in low sulphur hydrocarbon environments containing reactive iron.

E&P Notes (January 2022)

E&P Notes (January 2022)

Development of KPI’s for Ageing Export Pipelines in the UK North Sea

Abstract: Export pipelines are of inestimable value to the oil and gas industry, as they have continuously provided a path and means for hydrocarbon transportation. The most recent report from the UK HSE shows that there are about 1372 pipelines installed in the UK North-sea and about 442 of them are ageing export pipelines. The most unique function of these pipelines is to convey fluids from HC wells to the available processing facility; which are applicable for both onshore and offshore applications. During the useful life of these pipelines, they encounter various degradations that range from fatigue, corrosion, thermal expansion, spans, erosion and many other associated third-party challenges. It is the responsibility of duty holders to ensure that these degradations do not propagate into triggering hazardous and catastrophic incidents, to this effect, it is necessary for operators to protect the state of these pipelines by the application of an efficient management structure known as Pipeline Integrity Management System (PIMS). Keywords: Pipeline, Export, Ageing, Key Performance Indicators, PARLOC, OGP, Management, Integrity, Degradation Mechanism, Mitigation, PIMS.

Examining oilmen’s notions of ‘fatherhood masculinity’ as a pathway to understand increased offshore oilfield safety behaviours

This study explores how notions of fatherhood masculine identity held by offshore oilfield workers positively influenced safety and risk predispositions in the workplace. Findings are based on a ‘rapid’, two week, embedded ethnography of a remote offshore drilling platform in the UK North Sea. Ethnography was reflective of the traditional two-week ‘hitch’ permitted for most UK offshore oilfield workers. Drawing directly from the workplace narratives of thirty-five oilmen labouring in a variety of different roles in the North Sea drilling sector, this study presents how oilmen working in the traditionally hazardous and ‘high risk’ industry redeveloped previously risky masculine notions of workplace identity. For many men, this process of reimagining was intertwined with fatherhood. Oilmen formulated “softer, safer” masculine identity practices founded upon notions of distanced breadwinning, self-preservation, and returning home safe to their onshore families. Such notions readily replaced - and rendered “outdated” - oilmen’s previous and historic identity narratives largely linked to risky and hypermasculine workplace norms. Identity reformations resulted in a safer workplace culture that normalised and respected men who upheld safety, and marginalised men who performed risky or dangerous workplace behaviours. Implications upon worksite safety and for future research are discussed.

Seismic chimney characterisation in the North Sea – Implications for pockmark formation and shallow gas migration

Fluid-escape structures within sedimentary basins permit pressure-driven focused fluid flow through inter-connected faults, fractures and sediment. Seismically-imaged chimneys are recognised as fluid migration pathways which cross-cut overburden stratigraphy, hydraulically connecting deeper strata with the seafloor. However, the geological processes in the sedimentary overburden which control the mechanisms of genesis and temporal evolution require improved understanding. We integrate high-resolution 2D and 3D seismic reflection data with sediment core data to characterise a natural, active site of seafloor methane venting in the UK North Sea and Witch Ground Basin, the Scanner pockmark complex. A regional assessment of shallow gas distribution presents direct evidence of active and palaeo-fluid migration pathways which terminate at the seabed pockmarks. We show that these pockmarks are fed from a methane gas reservoir located at 70 m below the seafloor. We find that the shallow reservoir is a glacial outwash fan, that is laterally sealed by glacial tunnel valleys. Overpressure generation leading to chimney and pockmark genesis is directly controlled by the shallow geological and glaciogenic setting. Once formed, pockmarks act as drainage cells for the underlying gas accumulations. Fluid flow occurs through gas chimneys, comprised of a sub-vertical gas-filled fracture zone. Our findings provide an improved understanding of focused fluid flow and pockmark formation within the sediment overburden, which can be applied to subsurface geohazard assessment and geological storage of CO2.

Halokinetic modulation of sedimentary thickness and architecture: A numerical modelling approach

AbstractSubsurface salt flow can deform overlying strata and influence contemporaneous sedimentary systems. Studying salt‐sediment interactions is challenging in the subsurface due to poor imaging adjacent to salt, and in the field due to the dissolution of halite. Discrete Element Modelling provides an efficient and inexpensive tool to model stratigraphy and deformation around salt structures, which is advantageous over other modelling techniques as it realistically recreates brittle processes such as faulting. Six 2D experiments were run representing 4.6 Myr to determine the effect of salt growth on syn‐kinematic stratigraphy. Halokinetic deformation of stratigraphic architecture was assessed by varying sediment input rates through time. Results show the realistic formation and evolution of salt‐related faults which define a zone of halokinetic influence ca. 3 times the width of the initial diapir. Outside of this, early diapiric and syn‐kinematic stratigraphy are undeformed. Within this zone, syn‐kinematic strata are initially isolated into primary salt withdrawal basins, onlapping and thinning towards the salt‐cored high. In most models, syn‐kinematic strata eventually thin across and cover the diapir roof. Thinning rates are up to six times greater within 350 m of the diapir, compared to further afield, and typically decrease upwards (with time) and laterally (with distance) from the diapir. Outputs are compared to a subsurface example from the Pierce field, UK North Sea, which highlights the importance of considering local fluctuations in diapir rise rate. These can create stratigraphic architectures that may erroneously be interpreted to represent increases/decreases in sedimentation rate. Exposed examples, such as the Bakio diapir, northern Spain, can be used to make inferences of the expected depositional facies, below model resolution. Our models aid the prediction of sedimentary unit thickness and thinning rates and can be used to test interpretations arising from incomplete or low‐resolution subsurface and outcrop data when building geological models for subsurface energy.

Sedimentological and diagenetic controls on the reservoir quality of marginal marine sandstones buried to moderate depths and temperatures: Brent Province, UK North Sea

A study of the Brent Group sandstones, in well 211/13-A33 in the Thistle Field, northern North Sea, UK, from a sequence of shoreface, foreshore, delta plain and finally barrier shoreline depositional environments, was undertaken with the aim of contrasting the roles of depositional and diagenetic processes on reservoir quality. These subarkosic and sublitharenite sandstones were buried to ~9000 ft TVDSS and have experienced a maximum burial temperature of about 95 °C. This study utilised wireline and core analysis data, with core samples studied using petrography, XRD, SEM-CL, and SEM-EDS. The dominant diagenetic cements are kaolinite and siderite, with minor quantities of pyrite, chlorite, illite, K-feldspar, calcite and quartz cement. A common sequence of diagenetic events occurred in sandstones from all four depositional environments. The dominant reservoir quality controlling factors are depth-controlled mechanical compaction and variable kaolinite growth, with grain size being an important secondary control. The shoreface sandstones have the highest degree of compactional porosity-loss because they have the greatest quantity of detrital ductile grains. Quartz cement is a minor phase in all formations because these sandstones have only just exceeded the temperature threshold for quartz cement growth. Siderite is found in all formations but with the greatest quantity found in the shoreface and delta plain sandstones, since these environments were most enriched in detrital iron minerals such as biotite and chlorite. The shoreface sandstones host stratigraphically-localised, pore-occluding calcite cement that has compartmentalised the reservoir. Overall, the foreshore and delta plain sandstones have the best reservoir quality because they have (i) few ductile grains resulting in low degrees of compaction, (ii) low quantities of pore-filling cement and (iii) they tend to be medium-grained. In contrast, the shoreface sandstones and barrier shoreline sandstones have poorer reservoir quality as they have (i) moderate to large quantities of ductile grains, (ii) moderate quantities of pore-filling cement and (iii) they tend to be fine- or very fine-grained. Detrital sand mineralogy and grain size vary as a function of depositional environment and these have subsequently played a major role in linking diagenesis and reservoir quality to depositional environment.