Low crude oil sweep efficiency may be the result of channeling of injected water through high permeability sands in heterogeneous reservoirs. In these cases the efforts have been focused in improving the distribution of injected water in the wellbore through treatments using cements, gelling agents, and other short radius plugging materials. It has been proven that such treatments contribute to a better water distribution in the formation around the wellbore However, they are unlikely to be completely successful because, deeper in the formation, the fluid may divert. Laboratory and field studies have suggested that oil-in-water emulsions can be used to obtain a deeper formation plugging and this results in better sweep efficiency and a greater oil recovery. However, the suitability of this method for fractured formations remains relatively unknown. This paper presents the second phase of a three-phase study. The first phase consisted at the formulation of a heavy oil-in-water emulsion. Alkaline solutions were used as emulsifier agents. Parameters such as alkaline solution type and concentration, oil/water ratio, and shear rate were optimized in order to obtain a stable emulsion with an average drop diameter of 3 m. The second phase comprises the laboratory evaluation of the plugging effectiveness of the emulsion. The third phase will address the development of a field-pilot test. In order to accomplish the second phase objective, coreflood experiments were conducted at 80 C, with a confining pressure of 3000 psi and an injection pressure of 1000 psi. Various types of cores were used, including some with a longitudinal fracture. It was observed that an undesired breakdown of the emulsion generates plugging at the core injection inlet. A flush with an alkaline conditioner is required to minimize the breaking of the emulsion before it enters the cores. This preflush has no effect on the core permeability. Externally produced emulsions injected into the cores after the pre-flush with the alkaline conditioner reduced the permeability up to 80%. No time degradation on the emulsion plug was observed even after 27 PV of water injected. Introduction A number of studies has proved that oil-in-water (o/w) emulsion can cause permeability reduction. McAuliffe postulated and tested in parallel cores experiments that o/w emulsions would enter the most permeable layers of the reservoirs, where it is trapped. The trapped emulsion creates enough blockage for the water injected afterwards, resulting in a diversion process the improves the overall oil recovery. Considering an initial situation where three oil bearing layers (A, B and C) are waterflooded If one of these three layers (A) has higher permeability than the other two, most of the injected water should flow through it sweeping the oil, but leaving the other two layers (B and C) unswept. After the blockage of layer A with an emulsion, layers B and C can be swept, increasing the recovery of oil. The only field pilot test of this process was conducted in the Midway Sunset field, California. P. 611

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This paper presents field test results of sixteen steam soaked wells in which the injected steam was treated with two different surfactants selected in the laboratory as being the most suitable to he applied under Bolivar Coast Conditions. The laboratory research was done by Shell Laboratorium (Netherlands) and Intevep-PDVSA Research Center (Venezuela) and the main selecting criteria was the pressure drop measured in the porous media during steam Foam Flow tests. The two steam Foam Formulations selected were, a long-chain alkyraryl toluene sulphonate (SURFACTANT 1) and a branch-chain alkyraryl benzene sulphonate (SURFACTANT 2). The SURFACTANT 1 was used in nine wells while the SURFACTANT 2 was injected in seven. The stimulation mechanism of SURFACTANT 1 seems to be steam diversion to the less produced sands and for SURFACTANT 2 it appears to be a change of interfacial properties in the water-oil-rock system. Although most of the steam foamed wells had not completed the production cycle, it can he concluded that 60% of them have presented positive response to steam foam. The initial oil rate response was equal to or slightly greater than that expected from a normal cycle, but steam Foamed wells produced up to three times the additional cumulative oil expected (75,000 bls vs. 25.000 bls for a third cycle). This is due to the fact that the decline of the oil production rate was lowered to about 12% pa. which is indeed close to that of primary production. The better oil production performances were obtained when the steam penetrated deeper into previously non productive layers. The maximum diversion registered was close to 90 feet as compared to 35 feet of the initial profile. Introduction Steam soak has proved to be a very efficient re-recovery process in the heavy oil reservoirs on the Bolivar Coast In Western Venezuela. The effectiveness of this method is intimately related to compaction which is the main production mechanism in these reservoirs. In order to minimise the benefits obtainable from this method the oil production should ideally come From all the sands of the reservoir. Nevertheless, the challenge of uniformly distributing the injected steam to each productive sand has been one of the greatest operational problems, At present selective injection is accomplished by the installation of special mechanical completion equipment, but this procedure complicates production operations thereby increasing costs. in order to enhance the steam injection profile and increase the recovery from heavy oil reservoirs, a programme was initiated to evaluate the use of foaming agents to reduce the mobility of steam. Laboratory tests carried out using values of steam quality, steam injection rates, pressure and temperature representative of the prevalent conditions in the Bolivar Coast, resulted in the identification of two appropriate surfactants. There upon a programme of field tests was initiated in Tia Juana, Lagunillas, and Bachquero in order to:Evaluate the capacity of the steam foam mixture to reduce the effective permeability to steam. P. 915^

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