Some thoughts on the influence of pressure and thermal history assumptions on petroleum systems modelling

The use of petroleum systems modelling (PSM) requires the integration of the geological sciences with petroleum engineering, physics and chemistry. In a recent paper in JPG (October 2014, vo. 37, pp 329–348), Mahanjane et al. (2014) applied a 1-D petroleum systems model to the study of maturation and petroleum generation in northern Mozambique. However, PSM cannot divorce itself from the fundamental laws of mechanics and thermodynamics when attempting to derive a thermal history to be used for the modelling of maturation and petroleum generation. As will be shown in this brief Comment, the application of mechanics and thermodynamics to the derivation of the thermal history may require some radical changes to the methods currently used in PSM. Mechanics and thermodynamics require a reducing heat flow during subsidence, but require an increased heat flow during inversion. The failure to apply mechanics and thermodynamics during thermal history derivation in PSM arises from a failure to incorporate the effects of pressure into the kinetic models used for predicting maturation and petroleum generation. Pressure increases the activation energy of endothermic reactions including maturation and petroleum generation in the kinetic model used to predict the reaction rate, and results in higher temperatures being required to produce the same transformation ratio as would be required for the current temperature – time kinetic models. Incorporating pressure should enable the same thermal history obtained from tectonic history-mechanic-thermodynamic models to be used as those used to calibrate the thermal history using maturity parameters such as vitrinite reflectance

High pressure water pyrolysis of coal to evaluate the role of pressure on hydrocarbon generation and source rock maturation at high maturities under geological conditions

This study investigates the effect of water pressure on hydrocarbon generation and source rock maturation at high maturities for a perhydrous Tertiary Arctic coal, Svalbard. Using a 25 ml Hastalloy vessel, the coal was pyrolysed under low water pressure (230–300 bar) and high water pressure (500, 700 and 900 bar) conditions between 380 °C and 420 °C for 24 h. At 380 °C and 420 °C, gas yields were not affected by pressure up to 700 bar, but were reduced slightly at 900 bar. At 380 °C, the expelled oil yield was highest at 230 bar, but reduced significantly at 900 bar. At 420 °C cracking of expelled oil to gas was retarded at 700 and 900 bar. As well as direct cracking of the coal, the main source of gas generation at high pressure at both 380 °C and 420 °C is from bitumen trapped in the coal, indicating that this is a key mechanism in high pressure geological basins. Vitrinite reflectance (VR) was reduced by 0.16 %Ro at 380 °C and by 0.27 %Ro at 420 °C at 900 bar compared to the low pressure runs, indicating that source rock maturation will be more retarded at higher maturities in high pressure geological basins

Maturity, oil source rock and retorting potential of perhydrous coals in the Central Tertiary Basin, Spitsbergen

The occurrence of perhydrous (oil-prone) coal deposits within the Firkanten Formation of the Central Tertiary Basin (CTB) in Spitsbergen, is well documented and the oil present is reportedly sourced from the coals (Mokogwu, 2011; Marshall et al., 2015a). This study uses a total of 146 coal samples covering areas of the eastern coalfield (Bassen, Breinosa and Lunckefjellet) and the western coalfield (Colesdalen) of the CTB to investigate the maturity, oil source rock potential, and retorting potential of these perhydrous coals. In addition, the controls on the oil potential of the coals are considered to provide measures that could be used to determine the optimum resource areas in the basin. Samples were provided by Store Norske Spitsbergen Kulkompani AS, and include drill cores, mine sections and outcrop sections from the Svea, Longyear, Svarteper and Askeladden seams (eastern coalfield), and the Sputnik and Verkny seams (western coalfield). The vitrinite reflectance (VR) of the investigated coals are suppressed by bitumen impregnation and hydrogen enrichment of vitrinites; this is indicated by a general decrease in VR towards the top of the Longyear seam, which correlates with increasing Soxhlet yields towards the top of the seam, and a strong negative correlation of VR vs HI (Hydrogen Index) (R square between 0.73 - 0.78 in all areas), which is not maturity induced. Other evidences of VR suppression include a relatively wide range of VR values (between 0.50 - 0.79% Ro) within these seams, which are notably ≤2.1 m thick in all areas investigated, and wide ranges of VR distribution with bi-modal histograms observed in most samples (due to maceral effects rather than mixing of coal seams). Additionally, aliphatic biomarker and aromatic maturity parameters do not decrease towards the top of the Longyear seam (contrary to VR which decreases towards seam top), and indicates that the coals are generally in the maturity range of around 0.70% Ro or higher. Tmax appear suppressed, and the re-arrangements of methylphenanthrene isomers with increasing maturity also appear delayed/suppressed when there is aliphatic enrichment. True (i.e. unsuppressed) VR was estimated using the Lo (1993) method which gives thermal maturities of around 0.68, 0.78, 0.80 and 0.88% Ro in the Bassen, Lunckefjellet, Breinosa and Colesdalen areas respectively. True VR values indicate peak temperatures of around 104 °C in Bassen, 116 °C in Lunckefjellet, 118 °C in Breinosa and 125 °C in Colesdalen. Coalification gradients in the Adventdalen area equate to around 0.37% Ro/km, with an estimated geothermal gradient of approximately 55 °C/km. Peak burial depths in the Adventdalen area range from 1.9 km (up-dip), to 2.2 km (down-dip), indicating an overall overburden erosion estimate of between 0.9 – 1.2 km. In the Lunckefjellet area, peak burial depth is around 2.1 km, which implies a missing overburden of 1.1 km. In Colesdalen, peak burial depths are considerably higher at around 2.3 km, with a missing overburden estimate of 1.4 km. The implications of these results on burial and subsequent uplift and erosion are discussed. The oil potential of the studied coals appears to be mainly due to perhydrous detrovitrinites, although other vitrinites including collotelinite, in addition to some liptinites, may have significantly contributed. Rock-Eval analysis indicates that the coals are enriched in Type II and a mixture of Types II/III kerogens with high HI (150 - 410 mg HC/g TOC), variable TOC contents (44.5 – 89.8 %), and high S2 contents (109 – 368 mg/g), all of which indicate excellent oil potential. The mean S1 contents are 6.8, 11.8, 15.0 and 14.5 mg/g for the Bassen, Lunckefjellet, Breinosa and Colesdalen coals respectively, which reflect the maturity trend across these four localities (i.e. increasing maturity from Bassen, through Lunckefjellet, to Breinosa and Colesdalen). The Bassen coals are at the onset of oil generation, while the Lunckefjellet coals are at peak oil generation/onset of oil expulsion. The Breinosa and Colesdalen coals however, are already expelling oil (meaning they are in the effective oil window), although all samples (i.e. from all four localities) have low production index (PI < 0.10), which suggest that significant expulsion have not occurred. Results indicate that the Lunckefjellet coals will give the best indication of the maturity at which oil expulsion occurs in the CTB. The oil-proneness of the coals resulted from marine influence upon the peatlands, and the consequent marine sulphur enrichment (between 0.4 – 17.7 % S in the coals). The Askeladden, Svarteper and Verkny coals generally contain more sulphur than the Longyear and Sputnik coals, and this trend is consistent with that of oil potential. Between sample localities, oil potential generally increases in the direction towards the inferred palaeocoastline. The varying sulphur contents within seams and between localities are assessed, and the implications of this variation on oil potential are examined and discussed. In addition to the influence of sulphur on oil potential, there are other marine as well as non-marine related factors on oil potential which have been examined and discussed to help in delineating the optimum resource areas in the basin. Results indicate that greatest oil potential is mainly due to the combination of the following factors: a) Thermal maturity (true VR of around 0.78% Ro) b) Relative sea level rise leading to S contents in excess of 0.5 % c) Stable hydrology (i.e. relatively large/stable groundwater catchment) d) Fe/S ratio significantly <0.87 e) Optimum pH levels (alkalinity, which favours high microbial degredation) f) Relative distance to inferred palaeocoastline and local topography g) Ash content ≤30 % Retorting of the CTB coals showed highest bulk yields at Lunckefjellet (160 mg/g on dry whole coal – dwc basis), with sections within seams yielding up to 240 mg/g dwc. At Breinosa and Colesdalen, bulk yields of 140 and 100 mg/g dwc respectively were measured. Lowest bulk yield was measured at Bassen (80 mg/g dwc). Residual semi-coke ranges between 60 – 75 % of starting material in all areas. Retorting yields are notably limited by coal swelling/blocking of the reactor vessel; consequently, further work involving other methods such as the Grey-King assay are required to fully measure the retorting potential in these coals. With a maximum coal resource of 3,300 Mt, of which 600 Mt is recoverable in the CTB (Orheim, 1982), maximum hydrocarbon resource via retorting would range between 3,188 – 5,394 Mbbl in place, with 580 – 981 Mbbl recoverable by mining

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

Stable polycyclic aromatic carbon (SPAC) content as an improved parameter for determining biochar stability

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Maturity, oil source rock and retorting potential of perhydrous coals in the Central Tertiary Basin, Spitsbergen

The occurrence of perhydrous (oil-prone) coal deposits within the Firkanten Formation of the Central Tertiary Basin (CTB) in Spitsbergen, is well documented and the oil present is reportedly sourced from the coals (Mokogwu, 2011; Marshall et al., 2015a). This study uses a total of 146 coal samples covering areas of the eastern coalfield (Bassen, Breinosa and Lunckefjellet) and the western coalfield (Colesdalen) of the CTB to investigate the maturity, oil source rock potential, and retorting potential of these perhydrous coals. In addition, the controls on the oil potential of the coals are considered to provide measures that could be used to determine the optimum resource areas in the basin. Samples were provided by Store Norske Spitsbergen Kulkompani AS, and include drill cores, mine sections and outcrop sections from the Svea, Longyear, Svarteper and Askeladden seams (eastern coalfield), and the Sputnik and Verkny seams (western coalfield). The vitrinite reflectance (VR) of the investigated coals are suppressed by bitumen impregnation and hydrogen enrichment of vitrinites; this is indicated by a general decrease in VR towards the top of the Longyear seam, which correlates with increasing Soxhlet yields towards the top of the seam, and a strong negative correlation of VR vs HI (Hydrogen Index) (R square between 0.73 - 0.78 in all areas), which is not maturity induced. Other evidences of VR suppression include a relatively wide range of VR values (between 0.50 - 0.79% Ro) within these seams, which are notably ≤2.1 m thick in all areas investigated, and wide ranges of VR distribution with bi-modal histograms observed in most samples (due to maceral effects rather than mixing of coal seams). Additionally, aliphatic biomarker and aromatic maturity parameters do not decrease towards the top of the Longyear seam (contrary to VR which decreases towards seam top), and indicates that the coals are generally in the maturity range of around 0.70% Ro or higher. Tmax appear suppressed, and the re-arrangements of methylphenanthrene isomers with increasing maturity also appear delayed/suppressed when there is aliphatic enrichment. True (i.e. unsuppressed) VR was estimated using the Lo (1993) method which gives thermal maturities of around 0.68, 0.78, 0.80 and 0.88% Ro in the Bassen, Lunckefjellet, Breinosa and Colesdalen areas respectively. True VR values indicate peak temperatures of around 104 °C in Bassen, 116 °C in Lunckefjellet, 118 °C in Breinosa and 125 °C in Colesdalen. Coalification gradients in the Adventdalen area equate to around 0.37% Ro/km, with an estimated geothermal gradient of approximately 55 °C/km. Peak burial depths in the Adventdalen area range from 1.9 km (up-dip), to 2.2 km (down-dip), indicating an overall overburden erosion estimate of between 0.9 – 1.2 km. In the Lunckefjellet area, peak burial depth is around 2.1 km, which implies a missing overburden of 1.1 km. In Colesdalen, peak burial depths are considerably higher at around 2.3 km, with a missing overburden estimate of 1.4 km. The implications of these results on burial and subsequent uplift and erosion are discussed. The oil potential of the studied coals appears to be mainly due to perhydrous detrovitrinites, although other vitrinites including collotelinite, in addition to some liptinites, may have significantly contributed. Rock-Eval analysis indicates that the coals are enriched in Type II and a mixture of Types II/III kerogens with high HI (150 - 410 mg HC/g TOC), variable TOC contents (44.5 – 89.8 %), and high S2 contents (109 – 368 mg/g), all of which indicate excellent oil potential. The mean S1 contents are 6.8, 11.8, 15.0 and 14.5 mg/g for the Bassen, Lunckefjellet, Breinosa and Colesdalen coals respectively, which reflect the maturity trend across these four localities (i.e. increasing maturity from Bassen, through Lunckefjellet, to Breinosa and Colesdalen). The Bassen coals are at the onset of oil generation, while the Lunckefjellet coals are at peak oil generation/onset of oil expulsion. The Breinosa and Colesdalen coals however, are already expelling oil (meaning they are in the effective oil window), although all samples (i.e. from all four localities) have low production index (PI < 0.10), which suggest that significant expulsion have not occurred. Results indicate that the Lunckefjellet coals will give the best indication of the maturity at which oil expulsion occurs in the CTB. The oil-proneness of the coals resulted from marine influence upon the peatlands, and the consequent marine sulphur enrichment (between 0.4 – 17.7 % S in the coals). The Askeladden, Svarteper and Verkny coals generally contain more sulphur than the Longyear and Sputnik coals, and this trend is consistent with that of oil potential. Between sample localities, oil potential generally increases in the direction towards the inferred palaeocoastline. The varying sulphur contents within seams and between localities are assessed, and the implications of this variation on oil potential are examined and discussed. In addition to the influence of sulphur on oil potential, there are other marine as well as non-marine related factors on oil potential which have been examined and discussed to help in delineating the optimum resource areas in the basin. Results indicate that greatest oil potential is mainly due to the combination of the following factors: a) Thermal maturity (true VR of around 0.78% Ro) b) Relative sea level rise leading to S contents in excess of 0.5 % c) Stable hydrology (i.e. relatively large/stable groundwater catchment) d) Fe/S ratio significantly <0.87 e) Optimum pH levels (alkalinity, which favours high microbial degredation) f) Relative distance to inferred palaeocoastline and local topography g) Ash content ≤30 % Retorting of the CTB coals showed highest bulk yields at Lunckefjellet (160 mg/g on dry whole coal – dwc basis), with sections within seams yielding up to 240 mg/g dwc. At Breinosa and Colesdalen, bulk yields of 140 and 100 mg/g dwc respectively were measured. Lowest bulk yield was measured at Bassen (80 mg/g dwc). Residual semi-coke ranges between 60 – 75 % of starting material in all areas. Retorting yields are notably limited by coal swelling/blocking of the reactor vessel; consequently, further work involving other methods such as the Grey-King assay are required to fully measure the retorting potential in these coals. With a maximum coal resource of 3,300 Mt, of which 600 Mt is recoverable in the CTB (Orheim, 1982), maximum hydrocarbon resource via retorting would range between 3,188 – 5,394 Mbbl in place, with 580 – 981 Mbbl recoverable by mining

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 solvent type and condition on biomass liquefaction to produce heavy oils in high yield with low oxygen contents

Bio-oils produced by processes such as slow or fast pyrolysis typically contain high water and oxygen contents, which make them incompatible with conventional fuels. It is therefore necessary to upgrade the bio-oils to reduce their oxygen and water contents. The bio-oil upgrading process can consume up to 84 wt% of the initial bio-oil it is therefore important to develop other alternative approaches to generate high quality bio-oil. Thermolytic liquid solvent extraction (LSE) has been considered as a potential viable process due to the high liquid yield, better product quality and water free nature of the final products. In this study, a novel LSE process of biomass liquefaction has been studied under various conditions of solvent type, temperature, and biomass species. Compared to currently available commercial pyrolysis approaches, this process using tetralin as a solvent is shown to be capable of generating high quality bio-oil with low oxygen contents (ca. 5.9%) at extremely high overall conversions of up to 87 and 92 (%) dry and ash free basis (DAF) from Scotch pine and miscanthus, respectively. Overall, the study has demonstrated the advantages of LSE for bio-oil generation from biomass, in terms of producing high conversions to liquid products that are compatible with existing petroleum heavy feedstocks

Investigation of the fluid behavior of asphaltenes and toluene insolubles by high-temperature proton nuclear magnetic resonance and rheometry and their application to visbreaking

The fluid behavior of asphaltenes at elevated temperatures impacts coke formation in a number of hydrocarbon conversion processes, including visbreaking and delayed coking. In this study, the asphaltenes from a number of sources, namely, a vacuum residue, a petroleum source rock (Kimmeridge clay) bitumen obtained by hydrous pyrolysis, and bitumen products from a sub-bituminous coal and pine wood obtained by thermolytic solvent extraction using tetralin, have been characterized using high-temperature proton nuclear magnetic resonance (1H NMR), and the results correlated with those from small-amplitude oscillatory shear rheometry. Further for comparison, the coke (toluene insolubles) obtained from visbreaking the vacuum residue was also characterized. All of the asphaltenes became completely fluid by 300 °C, with hydrogen being completely mobile with coke formation, identified as a solid phase, not occurring to a significant extent until 450 °C. Extremely good agreement was obtained between high-temperature 1H NMR and rheometry results, which confirmed that the asphaltenes were highly fluid from 300 °C, with initial signs of resolidification being observed at temperatures of around 450 °C. During softening, extremely good correlations between fluid hydrogen and phase angle were obtained as the asphaltenes softened. The toluene insolubles however did contain some fluid material; thus, it cannot be regarded as strictly solid coke, but clearly, with increasing temperature, the fluid material did convert to coke. Under actual process conditions, this fluid material could be responsible for coke adhering to reactor surfaces

Study of pyrolysis for biochar production from biomass feedstocks using a simplified Aspen Plus model

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