Phase behaviour results indicated that the mass and size of asphaltene particles precipitated from the mixtures were strongly dependent on the CO 2 concentration. Coreflood test results showed that the severity of formation damage was related to the initial core permeability as well as the quantity and size of the asphaltene particles precipitated. The damage mechanism was found analogous to the 1/3 and 1/7 rule of thumb that related the size of particulates in injected water to potential permeability reduction. It was also observed that formation damage caused by shallow solid invasion was more readily removed by crude oil injection while remediation of formation damage caused by deep solid invasion, was more difficult. ABSTRACTThe precipitation of asphaltene during CO 2 miscible flooding can lead to production losses and reduced efficiencies. Having a clear understanding of the asphaltene deposition mechanism can help the oil industry to develop effective engineering practice to minimize asphaltene deposition and develop treatment program to restore well productivity. This paper presents results of phase behavior and core flood tests conducted at reservoir pressure and temperature conditions to identify the dominating factors associated with permeability reduction during CO 2 miscible flood of a light oil reservoir.

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This paper is part of a series of papers on the results of Enhanced Gas Recovery (EGR) research conducted at the Alberta Research Council during 2003 to 2007. In this Joint Industry Project (JIP), the soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modelling and economic analyses. The results of Phase I gas-gas displacement tests conducted at relative high pressure and temperature (6.2 MPa and 70 °C) in 4 cm diameter 30 cm long Berea core were recently reported(1, 2). In the second phase (2004–2005) of the JIP, the main targets were low pressure volumetric (closed) reservoirs in advanced stages of exploitation and also gas bearing strata overlaying oil sand intervals. Pressure maintenance of a depleting gas reservoir by waste gas injection can serve to:arrest the decline in gas production rate, prevent premature well abandonment and increase ultimate recovery;discourage the advance of an aquifer (if present) into the gas zone; andin the case of Gas-Over-Bitumen situations, mitigate declining reservoir pressure during natural gas production to enable exploitation of the underlying oil sands. One example of a field application of this EGR technology was the GRIPE Project operated by Paramount Resources during 2005 and 2006. A series of gas-gas displacement tests were conducted at room temperature and at pressures between 0.7 and 3.5 MPa in the presence of connate water in 5 cm diameter ? 2 m long sandpacks. Experimental parameters, such as nature of the injection gas, displacement pressure and displacement rate were systematically varied to study their effect on the displacement efficiency. Numerical simulations of the experimental results were also conducted to gain a better understanding of the interrelationship between the different variables. The laboratory results showed that during low velocity displacement of methane by flue gas in a homogeneous linear sandpack, molecular diffusion has a dominating effect on the recovery of marketable methane. Reasonable values of molecular diffusion coefficient for different gas-gas displacement conditions were obtained by matching the experimental test results with the numerical simulation. In spite of anticipated adverse effects of mixing between displaced and displacing gas due to molecular diffusion under low pressure and low flow velocity conditions, incremental recoveries of marketable methane under the experimental conditions were encouraging and suggest that EGR by gas-gas displacement can prolong the productive life and increase natural gas recovery from many volumetric gas reservoirs. Introduction Alberta currently has about 42,000 gas pools which are in different stages of exploitation, and many of them are approaching the end of their productive lives. The main goal for the second phase of our Joint Industry Project was to investigate enhanced gas recovery from low pressure volumetric (closed) reservoirs that are in advanced stages of exploitation and also, enhancing recoveries from gas bearing strata overlaying oil sand intervals. Pressure maintenance of a depleting gas reservoir by waste gas injection can serve to:arrest the decline in the gas production rate, prevent premature well abandonment and increase ultimate recovery;

Enhanced gas recovery by gas-gas displacement can be achieved economically in several situations. For mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, injection of waste gas can increase the ultimate gas recovery by maintaining gas production rates and preventing premature well abandonment. For water-driven gas reservoirs, pressure maintenance by gas injection will serve to (1) retard the influx of aquifer and (2) partially mitigate water coning caused by excessive pressure drawdown. This paper presents the results of laboratory core displacement tests conducted to investigate the feasibility of enhanced natural gas production by using exhaust gas from combustion of bitumen in an oxygen rich atmosphere. A synthetic gas mixture containing carbon dioxide, nitrogen and sulfur dioxide was used to represent the exhaust gas of interest. Displacement tests were conducted in Berea core and in porous media prepared with silica sand as well as crushed carbonate rocks at pressures ranging from 0.69 to 6.2 MPa. The objectives of the experiments were to determine the effects of (1) pressure, (2) displacing gas composition (3) formation water and (4) rock mineralogy on recovery efficiency of uncontaminated methane from the porous media.Several interesting phenomena were observed during the course of this investigation. Separation of injection gas components was observed in the effluent gas during displacement. Breakthrough of carbon dioxide and sulfur dioxide were delayed relative to nitrogen. This can be attributed to the higher solubility of CO 2 and SO 2 in water relative to nitrogen. These results are beneficial to natural gas production as they reduce the operating costs associated with corrosion during production of CO 2 and SO 2 . The amount of green house gases and acid gases being sequestered in the reservoir will also increase due to these effects.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper reviews design and performance data on sixteen (16) CO 2 huff 'n puff projects conducted in different wells in the Forest Reserve oilfield of Trinidad and Tobago over the last twenty (20) years. Specific inferences on conditions under which these projects succeeded in increasing oil production were generalized taking into account published results of similar projects elsewhere.