Organic geochemistry of Palaeozoic source rocks, central North Sea (CNS)

This report details a regional analysis of the source rock quality and potential of Palaeozoic rocks of the UK Central North Sea for the 21CXRM Palaeozoic project. The objective was to undertake a regional screening of all intervals to identify source rocks using new and legacy datasets of all Carboniferous and Devonian samples. In addition, a literature review (Appendix 1) summarises source and kerogen typing information from legacy reports. The background and stratigraphic nomenclature are given in Monaghan et al. (2016), details on individual well interpretations and stratigraphy are given in Kearsey et al. (2015). Geological context on the results of this work are included in basin modelling (Vincent, 2015) and were synthesised into a petroleum systems analysis in Monaghan et al. (2015). New and legacy Carboniferous and Devonian source rock geochemical data were examined per well using industry standard criteria to give an overview of the source rock quality, type (oil or gas prone) and maturity. The aims of this study were to classify the source rock quality of 33 wells, to examine if intervals were ‘gas-prone’ or ‘oil-prone’, and to ascertain the hydrocarbon generation stage of each well based on Rock-Eval pyrolysis, vitrinite reflectance (VR, where available) and total organic carbon (TOC) data. The term ‘gas prone’ was used to describe source rocks that have or could generate gas; ‘oil prone’ for source intervals that have or could generate oil. This study was a rapid screening exercise to identify intervals or areas of interest, and as such the data and inferences must be used concomitantly with other geological data to fully assess the source rock potential within the studied wells. It should be noted that the wells studied penetrate different parts of the geological succession and in many cases only small sections of the Devonian and Carboniferous interval. An initial sift through the wells with available geochemical data indicated that 33 wells had enough data to be usefully evaluated. Subsequently it was found that 8 of the 33 wells had incomplete, unreliable or otherwise poor source rock quality data sets and therefore were not analysed further; the reasons are detailed in this report. The remaining 25 wells selected for analysis were: 43/28-2, 26/07-1, 26/08-1, 36/13-1, 36/23-1, 38/16-1, 38/18-1, 39/07-1, 41/08-1, 42/10a-1, 42/10b-2ST, 42/09-1, 41/10-1, 42/10b-2, 41/15-1, 43/21-2, 41/01-1, 41/20-1, 41/14-1, 43/02-1, 43/17-2, 43/20b-2, 43/28-1, 43/28-2, 44/13-1, 44/16-1. Samples analysed from the majority of these wells were interpreted to be gas prone in the Carboniferous succession (Figure 1). 1. 41/10-1, 41/14-1 and 41/20-1 contained source rocks that were both gas window mature (e.g. VR >1.3) and can be regarded as excellent gas source. Strata in 43/17-2, 44/16-1 and 43/28-1 were also gas mature in all or parts of the section of interest, but with variable source rock quality. The six wells all had low S2 peaks: this may be due to either prior hydrocarbon generation and depletion or the initial presence of low amounts of non-inert kerogen. 2. 41/15-1, 42/10b-2 and 43/21-2 were also identified as possessing good gas-prone source rocks with elevated S2 values and also a high maturity attained by the source rocks. 41/01-1 was identified as a good for gas generation in the deeper section. 3. 26/07-1, 26/08-1, 36/13-1, 38/16-1, 39/07-1, 41/08-1, 42/10a-1, 42/10b-2ST, 42/09-1, 43/02-1, 43/20b-2, 43/28-2 and 44/13-1, contain good to excellent quality source rocks, but have not matured sufficiently to generate significant amount of gas, so these can be regarded as poor gas sources based on their current maturity. If present, in deeper basins some of these intervals will have generated significant quantities of gas

Impact of high water pressure on oil generation and maturation in Kimmeridge Clay and Monterey source rocks: implications for petroleum retention and gas generation in shale gas systems

This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources

Organic geochemistry of Palaeozoic Source Rocks of the Irish Sea, UK

The East Irish Sea gas and oil fields (Triassic reservoir e.g. Morecambe, Lennox) are believed to be sourced from the underlying Carboniferous strata (e.g. Armstrong et al., 1997; Quirk et al. 1999 and references therein). This study undertook a systematic screening of Rock-Eval and vitrinite reflectance data extracted from released legacy well reports with the aim of providing a data based, regional overview of Carboniferous source rock intervals and their levels of maturity in the wider Irish Sea study area. The method and description of calculated parameters used are given in Vane et al. (2015). The Palaeozoic stratigraphy of the region is described in Wakefield et al. (2016b) and the regional petroleum systems analysis in Pharaoh et al. (2016). Released geochemical data from the Palaeozoic of the Irish Sea is sparse and a variety of stratigraphical units have been sampled, mostly from units other than the likely main source rock interval (Bowland Shale Formation and equivalents). Nine wells were evaluated: 110/02b-10, 110/07-2, 110/07b-6, 110/09a-2, 111/25-1A, 113/27-1, 113/27-2 and 113/27-3. Well 110/12a-1 was not assessed due to the absence of key maturity information. In these wells, the Pennine Lower Coal Measures, Millstone Grit Group and Bowland Shale Formation are mainly gas-prone strata of poor-fair generative potential remaining and mature to the gas window at the sampled intervals in Quadrants 110 and 113 (Figure 1). Within the limited well sample set examined, high Total Organic Carbon (TOC) coal intervals have the best generative potential remaining. The Cumbrian Coastal Group, Appleby Group and Carboniferous Limestone Supergroup present in two wells in Quadrant 111 are at oil to gas window maturity levels, but have low TOC and low residual hydrocarbon generative potential

Organic geochemistry of Palaeozoic Source Rocks, Orcadian Study Area, North Sea, UK

A systematic screening of TOC, Rock-Eval and vitrinite reflectance data extracted from released legacy well reports was undertaken with the aim of providing a data based, regional overview of source rock intervals and their levels of maturity. Released, publicly available data is sparse; much of the data for the Devonian of the Orcadian Basin is contained with confidential commercial reports (see Greenhalgh (2016) for a literature review of available information with regards to source rocks and migrated Palaeozoic oils in this area). The regional screening approach used and technical parameters are described in Vane et al. (2015). The detailed stratigraphy is presented in Whitbread and Kearsey (2016; see Figure 2) and this regional screening is incorporated into the basin modelling work of Vincent (2016) and petroleum systems synthesis of Monaghan et al. (2016)

Palaeozoic petroleum systems of the Orcadian Basin to Forth Approaches, Quadrants 6 - 21, UK

This report synthesises the results of the 21CXRM Palaeozoic project to describe the Carboniferous and Devonian petroleum systems of the Orcadian Basin to Forth Approaches area (Quadrants 6 – 21). Petroleum systems of the Orcadian study area that involve significant Palaeozoic elements are not wholly contained within Devonian, Carboniferous and Permian strata. A number of producing fields attest to two main proven petroleum systems; i. Co-sourced Devonian oil (with Jurassic oil) within a Jurassic reservoir: the Beatrice, Jacky and Lybster fields; ii. Jurassic-sourced oil in a Devonian and/or Carboniferous reservoir: the Buchan, Stirling, Claymore, Highlander fields. (Jurassic-sourced oil in a Permian (Zechstein) reservoir is also proven in the Carnoustie, Ettrick and Claymore fields, and in a Rotliegend reservoir in the Dee discovery). A number of additional unproven petroleum system elements are considered in this report; i. Possibilities for Devonian and Carboniferous sourcing or co-sourcing (with Jurassic oil) of Devonian, Carboniferous and Permian (Rotliegend) reservoirs in those areas underlain by proven Palaeozoic source rock; ii. Possibilities for migrated Jurassic and/or Devonian and/or Carboniferous hydrocarbons onto horst blocks and the regional Grampian High, into basement, Palaeozoic or younger reservoirs. Focusing on frontier areas north and east of the Inner Moray Firth and from the north-eastern Forth Approaches to Grampian High, integration of a large volume of seismic, well, geophysical, organic geochemistry, maturity and reservoir property data at regional scale has established: Source rocks A wide extent of potential Devonian lacustrine source rocks mapped seismically from the Inner Moray Firth to the East Orkney Basin and north of the Halibut Horst. Geochemically-typed Devonian-sourced oil shows, oil seep data outside the area of mature Kimmeridge Clay Formation, burial depth and a limited organic geochemistry/maturity dataset indicative of Devonian source rocks that are potentially mature for oil generation outside the Inner Moray Firth. Good quality gas- and oil-prone Carboniferous source rocks are mapped from the Witch Ground Graben to north eastern end of the Forth Approaches. Wells drilled on highs indicate oil-window thermal maturity levels. Oil and gas shows and basin modelling indicate Carboniferous strata buried more deeply in adjacent basins may reach gas maturity levels, with Cenozoic maturation. Key source rock intervals are: o Lower Devonian, lacustrine Struie Formation (Quadrants 11, 12), oil prone. o Middle Devonian, lacustine Orcadia Formation and Eday Group (Quadrants 11- 15 and possibly Quadrants 19, 20), oil prone. o Visean – Namurian (lower-mid Carboniferous) fluvio-deltaic Firth Coal Formation, gas and oil prone. (This unit is age-equivalent of the Scremerston and Yoredale Formations, Cleveland Group source rocks in Quadrants 25-44

Palaeozoic petroleum systems of the central North Sea/Mid North Sea High

This report synthesises the results of the 21CXRM Palaeozoic project to describe the Carboniferous and Devonian petroleum systems of the Central North Sea/Mid North Sea High area (Quadrants 25–44). Focusing on frontier areas to the north of the Southern North Sea gas fields and west of the Auk-Flora ridge, integration of a large volume of seismic, well, geophysical, organic geochemistry, maturity and reservoir property data at regional scale has established: Extensional to strike-slip Devonian and Carboniferous basins cutting across the Mid North Sea High on orientations strongly controlled by basement inheritance, granites and a complex Palaeozoic stress field. Varsican orogenic transpression and inversion was superimposed resulting in a variety of structural trapping styles and burial/uplift histories, and a complicated pre-Permian subcrop map. A widespread spatial and temporal extent of oil and gas mature source rock intervals within the Carboniferous succession particularly; o lower Carboniferous (Visean) coals and mudstones of the Scremerston Formation, dominantly fluvio-deltaic and lacustrine with some marine influence, dominantly gas prone. Gas mature in Quadrant 41 and central-southern Quadrants 42-44 and oil mature in the Forth Approaches and North Dogger Basin o lower-mid Carboniferous (Visean-Namurian) coals and mudstones of the Yoredale and Millstone Grit formations in fluvio-deltaic to marine cycles, gas prone with oil prone intervals. Gas mature in central Quadrant 41 and southern Quadrants 42-43, oil mature across northern Quadrants 41-44, Quadrant 36, 38 and 39. o Lower-mid Carboniferous (Visean-Namurian) mudstones and siltstones of the Cleveland Group, over 1 km thick, deposited in dominantly marine environments. Gas mature to overmature in southern Quadrants 41-44 and modelled as having generated oil and gas. Potentially widespread reservoir intervals of varying reservoir quality. Favourable intervals include the Upper Devonian sandstone of the Buchan Formation expecially where fractured, channels within the fluvio-deltaic lower-mid Carboniferous (Visean-Namurian) Scremerston, Yoredale and Millstone Grit formations, the laterally extensive, high net:gross Fell Sandstone Formation, and possibly turbidites or shoreface sands within marine mudstones/siltstones in southern Quadrants 41-44 (likely tight gas unless early hydrocarbon charged) Widespread opportunities for structural (fault/fold/dip) traps utilising a Silverpit mudstone, or Zechstein evaporite seal as in the Breagh Field. Intraformational Carboniferous seals are documented widely in onshore Carboniferous fields and in some offshore fields and should be further investigated, particularly in mudstone/siltstone-dominated basinal successions with modelled Carboniferous and recent hydrocarbon generation, along with possibilities for stratigraphic traps. Basin modelling predicts oil and gas generation at a variety of times (Carboniferous, Mesozoic and Cenozoic dependent on the well) from lower-mid Carbonferous (Visean-Namurian) strata in Quadrants 41-44. In the Forth Approaches, Quadrant 29/North Dogger basins and on the poorly constrained Devonian-Carboniferous Mid North Sea High, oil window maturity levels are modelled at selected wells in a largely gas-prone sequence, though basinwards gas maturity may be achieved. It is recommended that the contribution and volumetrics of relatively thin oil-prone intervals within the Carboniferous succession be further investigated

Overview of the 21CXRM Palaeozoic Project : a regional petroleum systems analysis of the offshore Carboniferous and Devonian of the UKCS

This report gives an overview of the 21CXRM Palaeozoic Project background, scope and products (Sections 1-3). It explains how the component reports and datasets of the project fit together. Overview technical information (e.g. key diagrams and charts applicable across the reports for each area) is reproduced in Sections 6 and 7 for reference, particularly as background for users of the specialist reports. A visual representation of the regional coverage and quantity of digital Palaeozoic Project products is given in Figure 1

Evaluation of hydrochars from lignin hydrous pyrolysis to produce biocokes after carbonization

Hydrochars were obtained after hydrous pyrolysis of a pine Kraft lignin using different reaction conditions (temperature, water content and residence time) and the residues were characterized through a wide range of analytical techniques including high-temperature rheometry, solid-state 13C nuclear magnetic resonance (NMR), thermal gravimetric analysis (TGA), diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) and field emission scanning electron microscopy (FE-SEM). The results indicated that an increase in reaction temperature, an increase in residence time or a decrease in water content reduces the amount of fluid material in the residue. The hydrous pyrolysis conditions studied were not able to increase the maturation of lignin, which would result in an increase in the resolidification temperature, but reduced the amount of mineral matter in the hydrochar produced. On the other hand, the hydrochars obtained from pristine lignin, torrefied lignin (300 °C, 1 h) and their 50:50 wt.%/wt.% blend at temperatures of 350 °C after 6 h using 30 ml of water had lower ash contents (45%) is excessively high compared to that of the good coking coal (10%) and the micro-strength of the biocokes (R139%) and high microporous surface areas ( > 400 m2/g) of the biocokes and high alkalinity index of the lignins (>27%) compared to those of the coke (27% and 145 m2/g) and coal (0.6%), respectively. Furthermore, the biocoke derived from the hydrous pyrolysed torrefied lignin did not agglomerate, which could not be explained by changes in the chemical properties of the material and requires further investigation

Selective hydrogenation of levulinic acid to γ-valerolactone over copper based bimetallic catalysts derived from metal-organic frameworks

The transformation of biomass or feedstocks derived from biomass into fuels or chemicals with added value is an essential step in the process of transitioning to a low-carbon energy system. In this study, metal-organic framework (MOF)-derived non-noble bimetallic catalysts (copper-cobalt [CuCo], copper-nickel [CuNi] and copper-iron [CuFe]) were synthesized and used for selective levulinic acid (LA) hydrogenation to γ-valerolactone (GVL). The results demonstrated that adding the second metal could significantly improve the Cu@C catalytic activity. A 100% yield of γ-valerolactone was obtained by using the CuCo@C catalyst at 220 °C, 10 bar of H2 and a reaction time of 4 h. Advanced characterizations demonstrated that the excellent catalytic activity benefits from the even concentration of both metals on the surface, the abundance of active sites (Lewis and Bronsted) created by the even dispersion of both metals and the accessible surface area and pore volume originated from MOF precursor. The copper-based bimetallic catalysts also showed excellent catalytic durability with no significant decrease in GVL selectivity. Using MOF as a precursor for catalyst preparation can enable high dispersion of active metal sites and prevent their leaching, coking (carbon deposit) or aggregation in the carbon matrix during catalytic testing

Formation of bitumen in the Elgin/Franklin complex, Central Graben, North Sea: Implications for hydrocarbon charging

The Elgin/Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n-hexadecane and n-octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions however contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking.1-D basin models of well 29/5b-6 and a pseudowell east of the Elgin/Franklin complex utilise a thermal history derived from the basin’s rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from Elgin/Franklin to produce a composite model for petroleum generation, diagenetic-cement and bitumen formation