Cut Purses and Poisoned Paintings: Resisting Gender Objectification

The early modern English stage often portrays gender as polarized, creating an unwelcoming atmosphere toward characters who act exhibit characteristics from both male and female genders. Moll Cutpurse from Thomas Dekker and Thomas Middleton’s The Roaring Girl and Alice of Arden of Faversham resist early modern gender boundaries, conflating masculine and feminine attributes as they use objects to navigate their respective social spaces. Critics often describe Moll as a transvestite due to her fashion choice to wear a codpiece, along with her exaggerated, boisterous masculine behavior; however, she consistently defends her biological sex, implicating herself within her arguments concerning female chastity. As she duels with a sword for the honor of women, Moll inhabits a masculine persona. Alice, on the other hand, is often considered solely feminine, yet she exhibits early modern masculine characteristics when she acts within her commodity-driven surroundings to plot her husband’s murder by using poisoned objects and coins. By using objects to exert masculinity, Moll and Alice reveal the early modern concern of women’s abilities to adopt masculine qualities. The male responses within these plays show attempts to contain these women, as both are branded as criminals. Both women act against the law: Moll is a cutpurse, and Alice is an adulteress and, by the conclusion of the play, a murderess. Thus, The Roaring Girl and Arden of Faversham reveal the existence of female characters who defy the gender binary by using objects to adopt masculine characteristics. As they resist polarity, however, Moll and Alice must also exist within the realm of criminality

Screeches from the Red Hen: Public Accommodations Laws and Political Affiliation Discrimination in the United States and Louisiana

The article discusses issues on public accommodations laws and political affiliation discrimination in the U.S. and Louisiana, as well as the provisions of the Louisiana Constitution and the U.S. Constitution on public accommodation

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

Retardation of oil cracking to gas and pressure induced combination reactions to account for viscous oil in deep petroleum basins: evidence from oil and n-hexadecane pyrolysis at water pressures up to 900bar

This study reports a laboratory pyrolysis experimental study on oil and n-hexadecane to rationalise the thermal stability of oil in deep petroleum reservoirs. Using a 25 ml Hastelloy pressure vessel, a 35° API North Sea oil (Oseberg) and n-hexadecane (n-C16), were pyrolysed separately under non-hydrous (20 bar), low pressure hydrous (175 bar) and high liquid water pressure (500 and 900 bar) at 350°C for 24 h. This study reports a laboratory pyrolysis experimental study on oil and n-hexadecane to rationalise the thermal stability of oil in deep petroleum reservoirs. Using a 25 ml Hastelloy pressure vessel, a 35° API North Sea oil (Oseberg) and n-hexadecane (n-C16), were pyrolysed separately under non-hydrous (20 bar), low pressure hydrous (175 bar) and high liquid water pressure (500 and 900 bar) at 350 °C for 24 h. This study shows that the initial cracking of oil and n-hexadecane to hydrocarbon gases was retarded in the presence of water (175 bar hydrous conditions) compared to low pressures in the absence of water (non-hydrous conditions). At 900 bar water pressure, the retardation of oil and n-hexadecane cracking was more significant compared to 175 bar hydrous and 500 bar water pressure conditions. Combination reactions have been observed for the first time in pressurised water experiments during the initial stages of cracking, resulting in the increased abundance of heavier n-alkane hydrocarbons (> C20), the amount of unresolved complex material (UCM), as well as the asphaltene content of the oil. These reactions, favoured by increasing water pressure provide a new mechanism for rationalising the thermal stability of oils, and for producing heavy oils at temperatures above which biodegradation can occur. Indeed, we demonstrate that bitumen from the high pressure Gulf of Mexico basin has been formed from lighter oil components and it possesses similar characteristics to the laboratory oils generated

Thermal cracking of oil under water pressure up to 900 bar at high thermal maturities. 1. gas compositions and carbon isotopes

In this study, a C9+ fraction of saturate-rich Tertiary source rock-derived oil from the South China Sea basin was pyrolyzed in normal and supercritical water using a 25 mL vessel at a range of temperature from 350 to 425 °C for 24 h, to probe pressure effects up to 900 bar on gas yields and their stable carbon isotopic compositions during thermal cracking. Pressure generally retards oil cracking, as evidenced by reduced gas yields, but the trends depend upon the level of thermal evolution. In the early stages of cracking (350 and 373 °C, equivalent vitrinite reflectance of 1.3% R0), pressure still has a strong suppression effect from 200 to 470 bar, which then levels off or is reversed as the pressure is increased further to 750 and 900 bar. Interestingly, the stable carbon isotopic composition of the generated methane becomes enriched in 13C as the pressure increases from 200 to 900 bar. A maximum fractionation effect of ∼3‰ is observed over this pressure range. Due to pressure retardation, the isotopically heaviest methane signature does not coincide with the maximum gas yield, contrary to what might be expected. In contrast, pressure has little effect on ethane, propane, and butane carbon isotope ratios, which show a maximum variation of ∼1‰. The results suggest that the rates of methane-forming reactions affected by pressure control methane carbon isotope fractionation. Based on distinctive carbon isotope patterns of methane and wet gases from pressurized oil cracking, a conceptual model using “natural gas plot” is constructed to identify pressure effect on in situ oil cracking providing other factors excluded. The transition in going from dry conditions to normal and supercritical water does not have a significant effect on oil-cracking reactions as evidenced by gold bag hydrous and anhydrous pyrolysis results at the same temperatures as used in the pressure vessel

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

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

Comparison of the impact of moisture on methane adsorption and nanoporosity for over mature shales and their kerogens

Moisture in shales under reservoir conditions adversely affects gas adsorption and nanoporosity and is also likely to impact on the contribution that kerogen makes to the methane adsorption capacity. To investigate these phenomena, two over mature shales from the Wufeng-Longmaxi Formation, south of the Sichuan basin, and their kerogens isolated by demineralisation were investigated dry and at 95% relative humidity (R.H.) by high-pressure methane adsorption, and low-pressure nitrogen (N2) and carbon dioxide (CO2) sorption. The kerogen concentrates account for 68–97% and 50–64% of the methane adsorption capacities for the shales dry and at 95% R.H. respectively. However, the isolated kerogens could adsorb more methane than the organic matter in the shales because their shallower adsorption isotherms indicate large micropores and small mesopores not evident for the shales. Methane adsorption capacities of the kerogens and shales reduced by 46–72% at 95% R.H. This compares with the reductions in surface area (SA) and pore volume of 81% and 48–59%, respectively, for the kerogens and 98–99% for both SA and pore volume of the shales at 95% R.H. Water can block most micropores less than 1.3 nm reducing the micropores volume and blocking the micropore necks connecting the larger pores, and vastly reducing accessible pores for gas transport. The greater proportional losses in SA and pore volume compared to the methane adsorption capacities is probably due to ice forming at −196 °C in the low-pressure N2 analysis. Failure to take moisture into account for free and adsorbed methane overestimates the total gas in place (GIP) by 36–45% for the shales investigated

Shale gas reserve evaluation by laboratory pyrolysis and gas holding capacity consistent with field data

Exploration for shale gas occurs in onshore basins, with two approaches used to predict the maximum gas in place (GIP) in the absence of production data. The first estimates adsorbed plus free gas held within pore space, and the second measures gas yields from laboratory pyrolysis experiments on core samples. Here we show the use of sequential high-pressure water pyrolysis (HPWP) to replicate petroleum generation and expulsion in uplifted onshore basins. Compared to anhydrous pyrolysis where oil expulsion is limited, gas yields are much lower, and the gas at high maturity is dry, consistent with actual shales. Gas yields from HPWP of UK Bowland Shales are comparable with those from degassed cores, with the ca. 1% porosity sufficient to accommodate the gas generated. Extrapolating our findings to the whole Bowland Shale, the maximum GIP equate to potentially economically recoverable reserves of less than 10 years of current UK gas consumption

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