In an environment of low oil prices and low economic returns for heavy oil operations, SAGD and VAPEX processes appear very promising from a technical point of view. The purpose of this paper is to present guidelines for screening heavy oil reservoirs for exploitation by Steam Assisted Gravity Drainage (SAGD) and VAPEX processes. Viability in the field would be strongly governed by factors such as net pay thickness, oil viscosity, presence of gas cap or bottom water, barriers to vertical flow, containment of the steam or vapour chamber within the target area, lateral and vertical extent of steam/vapour chambers, number of new horizontal/vertical wells to be drilled, solvent recovery, facilities requirements, etc. Exploitation viability of heavy oil reservoirs is evaluated under different reservoir settings using a combination of reservoir/geological analyses and numerical simulation. This evaluation helps provide guidelines for screening reservoir prospects for the application of SAGD/VAPEX processes. The viability of these processes is sensitive to the reservoir characteristics of the specific target areas. Introduction The exploitation of heavy oil and bitumen is of primary interest to many oil companies due to the decline of conventional oil reserves. The magnitude of these resources worldwide, is of the order of 1 trillion m3 (6 trillion bbl) of oil in place, a major part of which is present in Venezuela. Canada is ranked second with an estimated original oil in place (OOIP) of 400 billion m3 (2.7 trillion bbl); twice that of the total conventional oil deposits in the Middle East (Janisch, 1979). The heavy oil and oil sand deposits of the USA are approximately 16 and 10 billion m3 of in-place resource respectively, mostly in Utah, Texas, Kentucky and California. The province of Alberta contains significant heavy oil and oil sand deposits, the total estimated resource being about 250 billion m3, buried at a depth of 0–800 m, of which only less than 5% is suitable for open-pit mining from shallow reservoirs (Wightman, 1989). The heavy oil deposits of Alberta and Saskatchewan consist of Athabasca (McMurray Formation), Wabasca (Grand Rapids Formation), Cold Lake (Clearwater Formation), Peace River (Blue Sky/Gething Formation), Lloydminster (Mannville Formation) and Grosmont Formation deposits (Figure 1). These collectively represent fluvial, deltaic, and marine depositional environments. The oil bearing deposits may often be composed of numerous stacked sandstone bodies which may or may not be in communication with one another. Vertical and lateral barriers to flow may consist of extensive shale layers, or localized shale lenses and shale filled channels. Other features which may affect the pay zone continuity include erosional features, salt collapse sink holes and fractures. The most critical factor to SAGD and VAPEX would be the ability of the steam/vapour chamber to confine the injected fluids, thus facilitating the recovery of mobilized bitumen/solvent. Therefore, in addition to pay zone continuity, other features such as grain size variation within the pay zone and the localized size, shape, and structure of the pay zone may promote or discourage such confinement and recovery of the injectant. The response to SAGD/VAPEX is therefore likely to be very site-specific. Earlier studies (Kasraie et al., 1996) had suggested limitations of 10 metres of continuous pay and a minimum permeability of 100 md for these processes to be economically viable, assuming confinement and injectant recovery. Such screening criteria (based on net pay and permeability) would be significantly affected by localized reservoir features which are controlled by the depositional environment and post depositional alterations (diagenesis). P. 867

No abstract

Introduction During miscible flooding of oil reservoirs by light hydrocarbon gases, deposition of asphaltenes inside reservoirs, and injection and production wells, can cause severe problems thereby adversely affecting the economics of oil recovery. In spite of this, very limited information regarding the asphaltene adsorption/deposition within porous media during gas miscible flooding, is available. In the present work, the flow of oil-solvent mixtures through porous media during a gas miscible flood was mechanistically studied in the laboratory under simulated reservoir conditions. The tests mimic the phenomena occurring within a small pore volume encroached by increasing amounts of solvent, in the course of a miscible flood. Experimental Two Canadian crude oils, known to be prone to asphaltene deposition in the field, were selected for this study: one from the Pembina Nisku pool in west-central Alberta and the other from Rainbow Keg River field in north-western Alberta. Both these oils have an asphaltene content of about 2%. For studying asphaltene related effects inside porous media during miscible flooding, a high pressure coreflood equipment was constructed (Figure 1). Berea cores were used as porous media during this investigation. The lengths of the cores were over 20 cm and the diameters, 1.9 cm. The porosity was 16-17%. The effective permeability to oil was in the range of 36 to 116 mD; these values were measured at a residual water saturation of 27–28% and were used as reference values for the subsequent flow of oil-solvent mixtures. Reservoir brine was used to initially saturate the core; a subsequent oil flood reduced the brine saturation to the residual brine saturation. Results Variations in effective permeability ratio (Kef/Kefo) upon flow of Rainbow Keg River oil-propane mixture are presented in Figure 2; here Kefo is the original value of effective permeability (for oil), while Kef is the current value for a given propane concentration in the mixture. All the concentrations are expressed in vol. %. The reduction of Kef begins as soon as propane is injected, that is, at a concentration of 15% propane, and it continues until propane concentration, reaches 100%. As a matter of fact, when injecting pure propane, the Kef is reduced to almost zero, implying a total blockage of the porous medium. There are two rates of permeability decrease with increasing propane concentrations, corresponding to two distinct ranges of propane concentrations. The first range is up to 51% for which the decrease is very steep. For propane concentration higher than 51%, the decrease is less severe. At the end of the first range, the Kef had decreased to 26% of its original value. P. 703^

Pyrobitumen is a black solid insoluble carbon-rich deposit derived from thermal degradation of hydrocarbons. This organic material has been commonly found in carbonate rocks worldwide. In a recent SPE paper, we have shown that pyrobitumen can cause fines migration, oil-wetting and acid sensitivity problems. More importantly, the presence of pyrobitumen severely occludes porosity and reduces permeability. There are no known chemical treatment processes to remove pyrobitumen in-situ near the wellbore. The objective of this study is to design a chemical treatment process, which will enhance well productivity of pyrobitumen-containing formations by removing the organic material in-situ. Since pyrobitumen is insoluble in any organic solvents, several strong oxidants are evaluated at elevated temperatures. These beaker experiments show that sodium hypochlorite is the best oxidant The kinetics of the oxidation process is carefully measured in these beaker tests. Subsequent coreflood experiments are performed to study the effectiveness of pyrobitumen removal using the sodium hypochlorite treatment at various temperatures, with different types of pyrobitumen, and in the presence of residual oil. Detailed petrographic analyses of the pre- and post-flooded core samples are conducted to find out the extent and location of pyrobitumen removal from the pore structure of cores. Effluent samples from the coreflood tests are analysed to understand the oxidation process of pyrobitumen in the core. In addition, concerns of scale precipitation, corrosion byproducts, and chlorinated hydrocarbon production from the sodium hypochlorite treatment are also addressed. The coreflood results show that significant improvement of core permeability by thirty to forty fold can be achieved by removing pyrobitumen from core samples using the newly developed chemical process. Visual and microscopic examination of the core samples before and after the treatment shows that the pyrobituzen material is removed by the oxidant. These laboratory results demonstrate that similar degrees of well productivity improvement is attainable by using this process. Introduction The term "pyrobitumen" was first introduced by Abraham (1945) who based his bitumen classification system on the analysis of chemical composition and physical properties. Some of the properties of pyrobitumen reported by Jacob (1989) were:colour, jet black, opaque in transmitted light;hardness, <2.5;density, 1.0-1.2 g/cc;reflectance % in oil, 0.01-0.7;fluorescence, 0.1-2.0; andsolubility in CS2, insoluble. A most recent publication by Shaw et al. (1995) provided a comprehensive study on the effect of pyrobitumen on hydrocarbon recovery. These authors showed that pyrobitumen can cause fines migration, oil-wetting and acid sensitivity problems. More importantly, the presence of pyrobitumen severely occludes porosity and reduces permeability. The objective of this study is to enhance well productivity of carbonate formations by chemically removing pyrobitumen in-situ because until now there are no known chemical treatment processes. As a result of this study, US and Canadian patents were filed and granted for the treatment process. Experimental Procedures Sample Selection The Rainbow Keg River and Bigstone Leduc formations' cores were chosen because samples from these reservoirs yielded sufficient extracted pyrobitumen to be used for preliminary kinetics measurements. They also contain different pyrobitumen types and represent different reservoir conditions. The Rainbow Keg River pyrobitumen is a lower thermal grade pore- and vug-filling fine grained mosaic epi-impsonite. The Bigstone Leduc pyrobitumen is a higher thermal grade pore- and vug-lining coarse grained mosaic epi- to meso-impsonite. Five 1.5 inch diameter core plugs were chosen for this study, four from the Rainbow Keg River formation and one from the Bigstone Leduc formation. Pyrobitumen Determination The weight of pyrobitumen in the carbonate samples is determined using the whole rock ashing method. This method involves the complete oxidation of pyrobitumen at temperatures ranging from 450–600 C. P. 161^

Pyrobitumen is a black solid insoluble carboniferous deposit derived from thermal degradation of hydrocarbons. Although the organic material has been observed in carbonate rocks world-wide, very little is known about its effect on some basic rock properties such as porosity, permeability, wettability, and potential for formation damage. All of these properties play significant roles in hydrocarbon recovery processes. In this study, the amount and distribution of pyrobitumen were determined using a newly developed ashing method. Potential formation damage, which can be caused by entrainment of pyrobitumen during waterflood, oil production and acidstimulatio, was examined using coreflood experiments. Electrophoretic mobility measurments and surfacant adsorption coreflood experiements were performed to study the effects of pyrobitumen on the surface propeties and adsorption behaviour of these carbonat rocks. The effect of pyrobitumen on the wettability of carbonate rocks was investigated in the contact angle experiments. Introduction Objectives and Scope Pyrobitumen, a solid, black, bituminous material, has been observed insignificant quanities worldwide, especially in Albetra Devonian carbonates. Thesolid hydrocarbons are present in the carbonate rock as either pore-filling orpoe-lining material within the vugular and the intercrystalline pore network. Although pyrobitumen has been observed in Alberta carbonate reservoirs, very little is known about its effect on some basic rock properties such as porosity, permeability, and wettability. All of these properties may have a significant influence on hydrocarbon recovery processes.