Based on physical modelling, this paper discusses the feasibility of injecting additives to control the conformance of the cyclic steam stimulation (CSS) and steam drive processes in the Biquan 10 Block of the Henan Oil Field. The lab test results show that waterflooding with the addition of a carbamide surfactant can decrease residual oil saturation by 4.7% and that steam drive with the addition of this same surfactant can improve the sweep volume and increase the oil recovery factor by 17.5%. Also, field application results confirmed that injecting this surfactant in the CSS and steam drive processes can increase oil production, lower steam-oil ratio (SOR) and improve the economic benefitssignificantly. Introduction The CSS process has been applied in developing the heavy oil reservoirs in the Henan Oil Field since the late 1980s. It has been clearly demonstrated that with increasing the cycles of steam stimulation, the oil production rate decreases and SOR can rapidly reach the economic limit. For improving the oil production rate and recovery factor, the steam drive process needs to be applied as a subsequent technology. However, the reservoir in the Henan Oil Field is thin and interbedded so it is a challenge to operate the conventional steam drive process. To reduce the steam channeling effect, a number of high temperature resistant plugging surfactants have been tested, but they could not achieve ideal and persistent results(1). This paper discusses the development of a new kind of conformance control agent ? carbamide surfactant. The lab testing results and field applications of the steam drive process with the addition of a carbamide surfactant in Well Group 577, Biqian 10 Block, Henan Oil Field, are described in detail below. Mechanism and Physical Modelling When the carbamide surfactant is injected into the reservoir with steam, carbamide decomposes into CO2 and NH3 under high temperatures. The decomposition can be expressed as follows: Equation (available in full paper) The physical modelling shows that, with increasing temperature and pressure, the carbamide decomposes even faster but its concentration does not affect the decomposition speed. The produced CO2 dissolves in heavy oil and NH3 can react with some acid in the oil. As a result, the heavy oil volume expands and viscosity decreases. At 50 °C, when the oil-carbamide solution (30 wt% carbamide) ratio is 4 to 1, the oil viscosity can be reduced by 73% to 80%. The single tube displacement efficiency test shows that adding carbamide solution (30 wt% carbamide) into hot water will increase the displacing efficiency by 6.5%. Field Application and Discussion Reservoir Geology and Production History Well pattern 577 in the east of Biqian 10 block was selected for the field test. The well pattern is an inverted 9-spot with injector-producer spacing of 70 m and 100 m. The pay zone is the IV-9 layer of the H-3 interval in the Hetaoyuan Formation. The basic reservoir parameters are as follows:

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Foamy oil behavior contributes significantly to the anomalously high primary recovery of heavy oils observed in the Orinoco Belt, Venezuela. Nowadays, disappearance of this phenomenon results in a rapid increase in the produced GOR and a fast decline in oil production when the reservoir pressure is below the pseudo-bubble pressure. This paper presents the results of a laboratory investigation, including pressure-volume-temperature (PVT) studies of foamy oil-natural gas mixtures and coreflood tests, for evaluating the feasibility of the natural gas injection process for enhanced heavy oil recovery with foamy oil characteristics. The study characterized the natural gas dissolution process in the foamy oil, and examined the effects on viscosity reduction and foamy oil swelling of the presence of natural gas. Coreflood tests were carried out to investigate the effects on oil recovery of injection mode (huff-n-puff, continous gas injection, and intermittent gas injection) and their different process parameters, such as reservoir pressure, injection timing, permeability and the size of the gas slug. The results indicate that significant amounts of natural gas could dissolve in the oil, which would cause oil swelling, viscosity reduction and artificial foamy oil formation. Core-flooding tests show that the natural gas huff-n-puff process could increase oil recovery 7.8% compared to the primary pressure depletion process, indicating a greater potential for recovering heavy oil. The continous and intermittent gas flood processes were not viable methods to enhance oil recovery from the heavy oil reservoirs in the Orinoco Belt, Venezuela.