Maturity modelling of well 110/07b- 6

This report details one-dimensional (1D) maturity modelling of well 110/07b- 6 in the Carboniferous rocks of the UK Irish Sea for the 21CXRM Palaeozoic project. The aim of the maturity modelling was to predict when the source rock reached the oil and gas maturity windows, and predict the timing of generation of potential hydrocarbons. Unravelling the burial and thermal history of the Irish Sea has entertained geologists for over 25 years and been subject to numerous studies (e.g. Cowan et al., 1999; Quirk et al., 1999; and references therein). This study specifically focusses on the 1D burial and thermal modelling of well 110/07b- 6 in the East Irish Sea area using BasinMod™ (Platte River Associates software). The regional Palaeozoic stratigraphy is described in Wakefield et al. (2016), the regional source rock geochemistry from legacy well reports is described in Vane et al. (2016) and the regional petroleum system analysis in Pharaoh et al. (2016b). Well 110/07b- 6 was chosen from a restricted number of potential wells as it contained the most comprehensive collection of geochemical data collected from released legacy well reports. The modelled maturity curve with depth was matched to best fit both measured maturity data (vitrinite reflectance) and calculated maturity data (calculated from RockEval Tmax values). A Variscan uplift of 700 m was modelled, as well as a 150 m Cimmerian uplift event and a two-stage Cenozoic uplift of 650 m in the Palaeocene and 450 m from the Eocene to recent. The uplift amount falls to the lower end of the published 1-3 km Cenozoic uplift estimates, and was modelled with a base heat flow of 50 mWm-2 increasing to a 70 mWm-2 peak during the Palaeocene. Deepest burial was reached in the early Cenozoic and the base of the drilled section of Bowland Shale Formation reached main gas generation (base of formation not reached). Main oil and gas generation for the Millstone Grit Group occurred equally in the Jurassic, Cretaceous and early Cenozoic. Oil and gas generation for the Bowland Shale Group occurred mainly in the late Mesozoic and early Cenozoic, with minor oil generation also in the Late Carboniferous. Both the Millstone Grit Group and Bowland Shale Formation in this well have fair source potential remaining. The use of one well for a regional scale study has its obvious limitations. The well chosen is fairly representative of the southern area of the East Irish Sea Basin (EISB) hydrocarbon province, south of the large Morecambe fields and near to the recently discovered Conwy Field (Figure 1). For a more complete understanding of the Solway and Peel-Manx basins to the north-west and Quadrant 109 (Figures 1, 3), geochemical sampling of well cuttings and/or core would be required

Total organic carbon calculation using geophysical logs for 31 wells across the Palaeozoic of the Central North Sea

This report details the source rock total organic carbon (TOC) content calculated from geophysical logs for 31 wells across the Palaeozoic rocks of the UK Central North Sea for the 21CXRM Palaeozoic project. A companion report examines the reservoir evaluation of 12 wells based on petrophysical evaluation of digital wireline log curve data (Hannis, this study). The TOC weight % was calculated for source rock intervals using geophysical well logs calibrated to measured TOC values from core and/or cuttings in the petrophysics software Interactive Petrophysics (IP™), which uses the TOC estimations equations defined by Passey et al. (1990). The Passey et al. method is most reliable in thick shale intervals and cannot calculate TOC in coals and reservoir intervals, which were removed from the analyses. Where possible the geographical distribution of calculated TOC was commented on, however, in general the spatial distribution of the assessed wells was too great to make any confident extrapolations of TOC on a regional scale. Petrophysical log analysis has been used as a regional screening tool to highlight potential TOC rich source rock intervals (shales), over larger depth ranges than is available for core/cuttings sample data. Given time constraints, data availability and the variable nature of the Carboniferous sedimentation, kerogen types have not been taken into consideration. To further the work presented in this report, investigation of the kerogen type in conjunction with the calculated TOC would give a more complete understanding of the hydrocarbon source rocks. Outputs of this part of the project include continuous (along borehole) interpretations of total organic content and clay volume. These interpreted curves were used to calculate net shale to gross formation thickness, ‘pay’ TOC rich (>1 wt%) shale thickness to gross formation thickness (known as Pay to Gross in this report (P/G)) and calculated TOC over the net shale thickness. The source rock formations (according to the reinterpreted stratigraphic formations defined and correlated for this project) assessed for TOC calculation and a summary of the results are given in Table 1. In summary, the results indicate significant thicknesses of organic rich shale through the Carboniferous succession. The Lower Devonian had very low calculated TOC of 0.7 wt% and P/G of 0.07, however, the cutting measured TOC suggest even these figures may be an overestimation

State of stress across UK regions

Knowledge of the in- situ stress field is a key constraint for a variety of sub surface activities and crucial for the safe and sustainable use of the sub surface. However is a lack of available stress magnitude data across the UK. This report assesses legacy stress magnitude data along with new analysis to characterise the UK onshore stress field. To investigate the UK onshore in-situ stress field, three regions were studied. The regions were selected based on the potential availability of information to characterise the stress field and their resource potential for unconventional shale resources, highlighted by Andrews et al. (2013). The study focused on: East Yorkshire and North Nottinghamshire, Cheshire and Lancashire and the Weald. The vertical stress across the UK varies between 23 and 26 MPakm-1 with higher values recorded in Cheshire and Scotland compared to East Yorkshire, North Nottinghamshire and the Weald. Pore pressure measurements from Cheshire, Lancashire, East Yorkshire and North Nottinghamshire are hydrostatic with a gradient of 10.19 MPakm-1. Leak off test and formation integrity test data has been used to estimate the gradient of minimum horizontal stress in Cheshire, Lancashire East Yorkshire and North Nottinghamshire. This estimates show that the minimum horizontal stress gradient is two MPakm-1 higher in Cheshire and Lancashire than East Yorkshire and North Nottinghamshire, which is similar to the differences in vertical stress gradients. Legacy maximum horizontal stress data has been compiled from a variety of techniques from the Coal Authority and peer review publications. This data shows that the maximum horizontal stress > vertical stress, When combined with the leak off test and formation integrity test data (which shows vertical stress > minimum horizontal stress) this indicates that the UK is predominately a strike slip faulting environment. Above 1200 m there are indications of reverse faulting though these are largely confined to igneous rocks in Cornwall, Leicestershire and Cumbria. The available information shows that there are similarities in the stress field across the UK though due to the geographic and stratigraphic constraints on the data more information would help to better characterise the stress field

Impact of in situ stress and fault reactivation on seal integrity in the East Irish Sea Basin, UK

Despite having been affected by several stages of exhumation during the Cretaceous and Cenozoic, the contemporary stress state of the East Irish Sea Basin (EISB) is poorly characterised. As the basin is mature in terms of exploitation of hydrocarbons, future exploration beyond the conventional Sherwood Sandstone Group reservoir (Triassic) necessitates a greater understanding of the in situ stress field, while proposed natural gas storage and carbon sequestration schemes also require detailed stress field information. Using petroleum well data, the in situ stress field of the EISB has been characterised to assess the mechanical seal integrity. A strike-slip stress regime most-likely prevails in the basin, meaning the Maximum Horizontal Stress (SHmax) is the greatest of the principal stresses. Interpretation of stress orientation data suggests that SHmax is oriented 152° ± 12°, consistent with mean stress orientations across the wider region associated with plate boundary forces. Some degree of structural control appears to influence the orientation of SHmax, with orientations locally aligned sub-parallel to major Permo-Triassic basin-bounding faults

A summary of the methodology for the seismic stratigraphic interpretation for the 'GlaciStore' bid to IODP

This report summarises the methodology followed for the seismic interpretation of sedimentary strata that are the overburden sequence and the Palaeogene strata that are prospective CO2 storage formations, in the UK Central North Sea. The interpretation of selected 2D and 3D seismic reflection, well and borehole data in the UK North and Central North Sea is targeted to inform the preparation of the ‘GlaciStore’ proposal for scientific drilling submitted to the International Ocean Discovery Programme (IODP). Drilling sites proposed to IODP lie within the UK and Norwegian sectors of the North Sea. The methodology is described for the interpretation of seismic data for proposed sites within UK waters. The seismic interpretation was undertaken in collaboration with Norwegian members of the GlaciStore consortium. The seismic interpretation was divided into two teams according to depth, into ‘shallower and ‘deeper’ seismic interpretation activities, appropriate to the fields of expertise and experience of the interpreters. The ‘shallower seismic’ interpreters considered strata of latest Neogene and Quaternary age which were deposited during major glacial and interglacial cycles. The ‘deeper seismic’ interpreters considered slightly older strata of Mid Eocene to Quaternary in age. Seven potential UK drill sites were selected to address the scientific objectives in the proposal. 2D and 3D seismic, well, borehole and bathymetry data were used to map buried and open tunnel valleys and to identify any evidence for the presence of shallow gas in the ‘shallower seismic’ interpretation at each drill site. Only sites without any indication of shallow gas features were considered as these pose a serious hazard for drilling. 2D and 3D seismic and well datasets and existing interpretations were collated for the ‘deeper seismic’ interpretation. The hydrocarbon exploration well log data, which were found to be of variable quality, were used to identify and map a number of stratigraphical surfaces of Cenozoic age, and included Quaternary strata, around the grid of seismic lines. Maps from some of the key stratigraphical surfaces are presented, selected to inform the drilling proposal. A plot of acoustic velocity data was prepared to inform future conversion of the seismic interpretation to true vertical depth. Future work, based on the seismic interpretation undertaken to underpin the drilling proposal, is identified. Features observed within the ‘shallower’ and ‘deeper’ seismic interpretations that warrant further investigation are: a chaotic zone within the Quaternary sequence; prograding units within the Eocene Horda Formation; basin centre sandstone bodies as prospective CO2 storage strata within the Horda Formation; systematic mapping of cross-cutting, buried tunnel valleys in the Quaternary sequence from 3D seismic data

An overlooked play? Structure, stratigraphy and hydrocarbon prospectivity of the Carboniferous in the East Irish Sea–North Channel basin complex

Seismic mapping of key Paleozoic surfaces in the East Irish Sea–North Channel region has been incorporated into a review of hydrocarbon prospectivity. The major Carboniferous basinal and inversion elements are identified, allowing an assessment of the principal kitchens for hydrocarbon generation and possible migration paths. A Carboniferous tilt-block is identified beneath the central part of the (Permian–Mesozoic) East Irish Sea Basin (EISB), bounded by carbonate platforms to the south and north. The importance of the Bowland Shale Formation as the key source rock is reaffirmed, the Pennine Coal Measures having been extensively excised following Variscan inversion and pre-Permian erosion. Peak generation from the Bowland source coincided with maximum burial of the system in late Jurassic–early Cretaceous time. Multiphase Variscan inversion generated numerous structural traps whose potential remains underexplored. Leakage of hydrocarbons from these into the overlying Triassic Ormskirk Sandstone reservoirs is likely to have occurred on a number of occasions, but currently unknown is how much resource remains in place below the Base Permian Unconformity. Poor permeability in the Pennsylvanian strata beneath the Triassic fields is a significant risk; the same may not be true in the less deeply buried marginal areas of the EISB, where additional potential plays are present in Mississippian carbonate platforms and latest Pennsylvanian clastic sedimentary rocks. Outside the EISB, the North Channel, Solway and Peel basins also contain Devonian and/or Carboniferous rocks. There have, however, been no discoveries, largely a consequence of the absence of a high-quality source rock and a regional seal comparable to the Mercia Mudstone Group and Permian evaporites of the Cumbrian Coast Group in the EISB

Carboniferous petroleum systems around the Mid North Sea High, UK

The existence of an extensive, prospective Visean–Namurian Carboniferous petroleum system in and around the hitherto under-explored Mid North Sea High is documented. Evidence is drawn from integrated analysis of over 50,000 line kilometres of seismic data and well data, together with regional source rock screening, reservoir analysis and basin modelling. Visean-Namurian marine and non-marine mudstones and coal source rocks are interbedded within fluvial and marine reservoir sandstones within a stacked succession up to 5 km thick. Source rocks are dominantly gas-prone with oil-prone intervals, and have reached oil to gas maturity levels dependent on location. Burial/thermal history modelling indicates a kitchen area on the southern margin of the Mid North Sea High with northwest and northeastwards migration of gas and oil during Mesozoic and Cenozoic times. A variety of structural and stratigraphic traps are possible, including intraformational Carboniferous traps, with a regional seal at Permian (Zechstein) level. Synthesis of many previously unpublished datasets demonstrates the Visean–Namurian play south of the Mid North Sea High as part of an extensive petroleum system from the East Irish Sea, across onshore to offshore UK and into The Netherlands sector of the North Sea. The purpose of this synthesis is to highlight future exploration opportunities beneath and northwards of the productive Westphalian Southern North Sea gas basin, and to begin to de-risk the petroleum systems that are exemplified by the lower Carboniferous Breagh Field in a frontier area of the mature North Sea province

Ex vivo treatment of prostate tumor tissue recapitulates in vivo therapy response

Background: In vitro models of prostate cancer (PCa) are not always reliable to evaluate anticancer treatment efficacy. This limitation may be overcome by using viable tumor slice material. Here we report on the establishment of an optimize