We present results of a detailed investigation of the steam/ solvent-coinjection-process mechanism by use of a numerical model with homogeneous reservoir properties and various solvents. We describe condensation of steam/solvent mixture near the chamber boundary. We present a composite picture of the important phenomena occurring in the different regions of the reservoir and their implications for oil recovery. We compare performances of various solvents and explain the reasons for the observed differences. An improved understanding of the process mechanism will help with selecting the best solvent and developing the best operating strategy for a given reservoir. Results indicate that as the temperature drops near the chamber boundary, steam starts condensing first because its mole fraction in the injected steam/solvent mixture (and hence its partial pressure and the corresponding saturation temperature) is much higher than the solvent's. As temperature declines toward the chamber boundary and steam continues to condense, the vapor phase becomes increasingly richer in solvent. At the chamber boundary where the temperature becomes equal to the condensation temperature of both steam and solvent at their respective partial pressures, both condense simultaneously. Thus, contrary to steam-only injection, where condensation occurs at the injected steam temperature, condensation of steam/solvent mixture is accompanied by a reduction in temperature in the condensation zone and the farther regions. However, there is little change in temperature in the central region of the steam chamber. The condensed steam/solvent mixture drains outside the chamber, leading to the formation of a mobile liquid stream (drainage region) where heated oil, condensed solvent, and water flow together to the production well. The condensed solvent mixes with the heated oil and further reduces its viscosity. The additional reduction in viscosity by solvent more than offsets the effect of reduced temperature near the chamber boundary. As the steam chamber expands laterally because of continued injection and as temperature in the hitherto drainage region increases, a part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation (ROS) in the steam chamber. Therefore, ultimate oil recovery with the steam/solvent-coinjection process is higher than that in steam-only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the ROS there. Our explanation is corroborated by the experimental results reported in the literature, which show smaller ROS in the steam chamber after a steam/solvent-coinjection process. A lighter solvent has a lower viscosity, a higher volatility, and a higher molar concentration of solvent in the drainage region. Thus, a lighter solvent causes a greater reduction in the viscosity of the heated oil and also leads to a lower ROS. Therefore, the lightest condensable solvent (butane, under the conditions investigated) provides the most favorable results i...
Subsurface upgrading of heavy oil via solvent deasphalting has been reported previously under laboratory and field conditions. However, these processes require a relatively high solvent-to-oil ratio (SvOR > 1:1 v/v) to induce subsurface asphaltene precipitation, increase oil production, and upgrade crude oil in situ. In our previous work, lab experiments demonstrated that asphaltene precipitants reduce the SvOR (∼30−50 vol %) for subsurface upgrading at initial reservoir conditions and when heat is also applied. In this work, the preparative separations were carried out using benzoyl peroxide (BP), Fe 2 O 3 , and NiO nanoparticles as asphaltene precipitants for Venezuelan and Canadian heavy crude oils. Initial experiments showed that BP is the most effective additive, producing an increase of ∼21 wt % in the asphaltene content for a 2500 mg/kg dosage. Preparative separations at 5:1 vol/wt ratio and 50 °C showed that the order of activity as asphaltene precipitants is BP > NiO > Fe 2 O 3 . In the presence of nickel-and iron-containing precipitants, most of these metals are found in the asphaltenes indicating that the nanoparticles are acting as nucleation sites. Spectroscopic and mechanistic studies using BP as precipitant suggest a free radical mechanism that involves the thermally initiated homolytic cleavage of BP, follow by abstraction of a hydrogen atom from the asphaltenes or maltenes to produce free radical species. In the termination steps, the latter species react with each other to generate new asphaltene species that are not present in the original crude oils.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractInjection of a pH-sensitive polymer has been proposed recently as a novel deep-penetrating mobility control method, and the development of a simulation capability for its scale-up is reported here. An aqueous dispersion of polymer microgel, whose swelling property shows a strong dependence on pH, preferentially flows into high-permeability zones under acidic conditions. Since the injected fluid viscosity is low, small injection pressures are needed to inject the polymer. Geochemical reactions increase the pH, causing the polymercontaining fluid to experience a viscosity increase of several orders of magnitude thereby altering the flow pattern of subsequently injected fluid. Because the viscosity of microgel dispersions can be controlled with adjustment of pH, this process can be employed both as a deep-penetrating mobility control method (with moderate polymer viscosity) and as a conformance control method (with immobile gel generation).Polymer-bank placement design and process scale-up requires simulation of transport of microgel, acid-mineral geochemical reactions, pH changes, and the coupling between aqueous phase composition and viscosity. Such a capability has been implemented in a commercial reservoir simulator and preliminary simulations verify the operation and effectiveness of the complex new features, which can describe both the mobility and conformance control applications. Determination of reservoir mineralogy and mineral reaction rates is critical to modeling in-situ pH changes accurately. History matching of coreflood acid injection experiments was used to estimate geochemical reactions and reaction rates occurring in Berea cores. Linear and radial geometry floods in 2-layer reservoir models were carried out as preliminary scaleup simulations. Acidic fluids can be propagated farther into a reservoir in a low-pH state, using high injection velocity, an acid preflush, or weak acids. The Damkohler number was found to be a useful dimensionless quantity for characterizing acid floods with pH-sensitive polymer. Slugs of pH-sensitive polymer improve oil recovery better than continuous polymer flooding or waterflooding.The simulator was successfully used to history match coreflood experiments, to model techniques to propagate low-pH fluids deep into reservoir, and to demonstrate the effectiveness of pH-sensitive polymer slug treatments for conformance control. 1. Benson, I., "Numerical Simulation of pH-Sensitive Polymer Injection as a Conformance Control Method", M.S.
We present results of a detailed investigation of the steam-solvent co-injection process mechanism using a homogeneous numerical model and three different solvents. The mechanistic model developed in this study describes coupled heat and mass transfer at the chamber boundary and its implications in detail. We present a composite picture of interplay of the process variables, the important phenomena occurring in the different regions of the reservoir and their consequences for oil recovery. The results are corroborated by literature experimental results and field data. The model will help with selecting the best operating strategy for a given reservoir.Results show that the injected steam and solvent vapor condense near the steam chamber boundary. The temperature near the chamber boundary drops because of a reduction in the partial pressure of steam.The condensed steam-solvent mixture drains outside the chamber boundar leading to the formation of a mobile liquid stream where heated oil, water and condensed solvent flow together to the production well. The condensed solvent and water are immiscible and therefore, form separate flow streams. The condensed solvent mixes with the heated oil in the water-oil stream and reduces its viscosity beyond that caused by heating alone, resulting in higher oil production rate. As the steam chamber expands laterally because of continued injection and temperature in the hitherto drainage region increases, part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation in the steam chamber. Therefore, ultimate oil recovery with steam-solvent co-injection process is higher than that in steam only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the residual oil saturation at that location.Thus, steam-solvent co-injection causes a higher oil production rate because of an additional reduction in oil viscosity and a higher ultimate recovery because of a reduction in residual oil saturation. IntroductionSteam Assisted Gravity Drainage (SAGD) has become the technology of choice for exploiting the huge resource base of bitumen. There are more than ten commercial SAGD projects in Canada. The field performance indicates that the process offers high production rate and high ultimate recovery. However, this process requires a large volume of steam injection. The observed steam-oil ratio (SOR) in the field is in the range of 3-5 (Jimenez, 2008). A large usage of steam affects the project economics adversely and also has a detrimental impact on the environment.
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