Gas injection, the fastest growing tertiary oil recovery technique, holds the promise of significant recoveries from those depleted oil reservoirs around the world which fall into a pressure range of (50-200) bar mainly. However, its application with the usual techniques is restricted by the need for various surface facilities such as enormous gas supply and storage. The only surface facility that downhole gasification of hydrocarbons (DHG) requires, on the other hand, is a portable electricity generator. DHG consists in producing inert gases, H2, CO, CO2 and CH4 through the steam reforming reaction of a part of the produced oil in a gasifier-reformer reactor positioned alongside the producer well in the reservoir. The gases, mainly H2 -the most effective displacing gas among produced gases- are injected into a gas cap above the oil formation, to increase oil recovery through a gas displacement drive mechanism. So far, DHG has only been tested under laboratory conditions using methane, pentane/reservoir gas and naphtha/reservoir gas as feedstock at conditions of reservoir pressure up to 130 bar. The studies varied reaction temperature, steam to carbon (S/C) ratio, catalyst types and catalyst loading in the gasifier-reformer reactor of a small pilot scale rig. These experimental studies demonstrated that pressure is one of the main factors influencing the effectiveness of the DHG process. From this starting point, the present investigation was directed at extending the pressure range up to 160 bar in the gasifier-reformer reactor using a naphtha fraction as feedstock in order to investigate whether the conversion and H2 concentration in produced dry gas can be maintained at acceptable levels under conditions of high pressure. To this end, experimental studies were carried out within the laboratory using the existing DHG rig on the small pilot scale, which was successfully commissioned and revamped for the purposes of this study. Initially, the investigation focused on exploring operating conditions, namely, steam to carbon (S/C) ratio, length of the gasifier-reformer reactor tube/ catalyst loading and the relative performance of two different catalysts. Subsequently, experiments on shutdown/start up cycles followed by variation of temperature were performed to simulate the effect of sudden electrical disruptions that usually occur in field operations. Experimental results using naphtha at pressure from 80 to 160 bar at 650 ºC, S/C= 6 achieved total feedstock conversion, no coke deposits and, most importantly, high H2 concentration in the produced dry gas (56-63 vol. % plus other gases). The best result was obtained with a crushed HiFUEL R110 catalyst (40-60 wt. % of NiO/CaO.Al2O3) and a reactor tube length of 72 cm, but the results with a C11-PR catalyst (40 wt. % of NiO/MgO.Al2O3) and a reactor tube length of 30 cm were similarly favourable. These results were supported by results of a numerical DHG model which indicated total feedstock conversion and values of H2 around 67 vol. % (using n-heptane as model surrogate). The results suggest that the DHG process is technically feasible at the pressure values studied, perhaps up to 200 bar where there are many hundreds of depleted, light oil reservoirs, especially in North America and other parts of the world below that pressure value.

Mixtures of bacterial and thermogenic methane are found both at vents at the seafloor and in reservoirs in the deep subsurface of the Gulf of Mexico continental slope. The C1-C5 gas that most recently charged reservoirs of Jolliet (GC 184), Genesis (GC 160/161) and Petronius (VK 786) fields is estimated to include 17%-28%, 31%-51%, 31%-49% bacterial methane, respectively. Geochemical assessment of the reservoir gas in the fields show that the gas may be the product of thermal cracking of Upper Jurassic crude oil before final migration to the reservoirs. The gas from three different fields is of similar thermal maturity levels. In contrast to oil in reservoirs in the fields, which shows biodegradation effects, the C1-C5 reservoir gas is unaltered by biodegradation. Late gas migration may have occurred at or near present burial depth and flushed the reservoir system of previously biodegraded hydrocarbon gas to include any previous bacterial methane. Molecular and isotopic properties of reservoir gas and oil suggest that bacterial methane mixed with thermogenic hydrocarbon gas before entering the reservoirs. Thus the source of the bacterial methane is logically deeper than the present depth (>~4 km) and temperatures of the reservoirs. High sedimentation rate and low geothermal gradient may offer conditions favorable for generation and preservation of bacterial methane in deep subsurface petroleum system of the Gulf slope. Bacterial methane dispersed across the large drainage areas of the deep subsurface petroleum system may have been swept by migrating fluids at >4 km, and then charged both vents (GC 185, GC 233 and GC 286) at the seafloor and reservoirs in the deep subsurface. The volume of bacterial methane from geologically significant depth in rapidly subsiding basins may be underestimated.