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Visual micromodels are a powerful tool for examining the Visual micromodels as used in this study can be defined as mechanisms of oil recovery from porous media at the pore flow apparatuses that enable visual observation of multiphase level. To this end, an algorithm has been developed to create 2-flow behaviour in porous media at the pore level. The glass dimensional flow network patterns simulating porous media micromodels used in this study of enhanced oil recovery are with controlled properties. This has been used to manufacture essentially a flow network etched onto the surface of a glass flow micromodels that have different grain size distributions, plate. The first step in building a micromodel is obtaining a high permeabilities, and heterogeneities. CO 2 floods were carried contrast diagram of a flow network pattern.
Abstract This study investigates the pore-level displacement of medium viscosity oil (200 cP) by brine and aqueous solutions of associative polymers. Associative polymers result in greater aqueous phase viscosities at the same concentration as conventional polymers. Studies are conducted in two-dimensional etched-silicon micro-models under a reflected light microscope. The pore network pattern of the micro-model replicates Berea sandstone. Results include the sweep pattern, oil recovery, and the pore-level distribution of residual oil. Generally, we find that brine and conventional polymer solutions at low concentrations result in severe fingering of the displacing fluid through the oil phase. Associative polymers lead to more stable displacement characteristics, apparently due to greater phase viscosity. Additionally, injection of associative polymers after breakthrough of brine mitigates fingering and improves viscous oil displacement. Experimental results show that associative polymers are a promising method to improve the displacement efficiency of viscous oils. Introduction Waterflooding accounts for about half of all oil recovered, but is generally limited to lighter oils with relatively low in-situ viscosity. A large number of fields holding viscous crude oil exist world-wide. These fields suffer from low recovery factors due to unfavorable mobility ratios in addition to low oil-phase mobility. Application of water injection for viscous oil recovery suffers from the high mobility of water leading to unstable displacement (Riaz et al., 2007). Heterogeneities in reservoir rock exacerbate unstable displacement. Nevertheless, for some situations such as Arctic and offshore reservoirs with viscous oils, there are perceived to be relatively few recovery process options except a water-based injectant. Addition of polymer to injection water reduces injected-phase mobility and provides a first-order solution to the problem of unstable displacement. Injection of viscous aqueous polymer solutions to improve volumetric sweep efficiency is a relatively mature concept. The extensive survey of Manning et al (1983) summarized field results of more than 250 polymer augmented water floods. Over the past decade, interest in polymer flooding has seen a resurgence and the oil volumes produced that are attributed to polymer flooding have grown, Principally, in the Daqing field (China), more than 250,000 bbl/d are produced by polymer injection and incremental oil recovery of up to 14 % is reported (Chang et al., 2006; Yupu and He, 2006). The mechanisms of polymer enhanced oil recovery have been studied with various methods and on various scales. Hele Shaw cells were used to visualise displacement of unfavorable mobility ratio floods (Benham and Olson, 1963; Allen and Boger, 1988). The processes involved in unstable flooding have been described theoretically (Sorbie et al., 1987; Araktingi and Orr, 1993) and examined experimentally (Tang and Kovscek, 2005; Riaz et al., 2007). The advantages of a stable displacement on volumetric sweep have been shown (for example) via streamline simulation (Wang et al, 1999) and field applications of polymer floods were simulated to improve interpretation of flood dynamics (Takaqi et al., 1992). A major cost for polymer injection projects is that of the polymer. In a typical application, 1 kg of polymer may be required to produced 1 m of incremental oil (i.e., 2.84 bbl oil / lb polymer) (Lake, 1989) Hence, an economical polymer should be injected resulting in the greatest oil recovery at the lowest polymer concentration.
Abstract The mobilization of residual oil was investigated in glass micromodels consisting of capillary networks with water-wet wettability as a function of capillary number (ratio of viscous to capillary forces). The micromodels used in this work had variable pore throat and pore body size distribution. Experimental results demonstrated that the entrapped residual oil blobs have a preferable orientation along the macroscopic flow direction of waterflooding. For substantial mobilization of the waterflood residual oil, the corresponding capillary number needs to be 100 times larger than that for the onset of mobilization of the largest blobs in place at the end of waterflooding. The reduced residual oil saturation with increasing capillary number obtained in this study is in qualitative and quantitative agreement with published capillary number curves for water-wet sandstones. A key feature of oil blob mobilization at high capillary number is the break-up of mobilized blobs to sub-pore size droplets as they flow through the pore network, some of which attach to the pore walls and thus making complete mobilization very difficult. It was concluded that class micromodels offer the potential to screen the best surfactant formulations for EOR application using residual oil mobilization experiments and for displacements of continuous oil in place. 1. Introduction A very significant fraction of the oil initially in place in an oil field is permanently trapped at the end of waterflooding operations. This trapped oil is referred to as waterflood residual oil is a strong function of the pore structure heterogeneities, flooding rate and wettability conditions. The residual oil saturation can be 15% of pore volume in homogeneous unconsolidated sands and as high as 50% of the pore volume in pore systems with vugs and high aspect ratio of pore body size to pore throat size. Because of oil shortages globally, abandoned oil fields are revisited by the oil companies to recover this residual oil by applying Enhanced Oil Recovery (EOR) techniques. The waterflood residual oil is recoverable by chemical flooding at high capillary number. The capillary number is defined as the ratio of viscous to capillary forces. A key objective of this work was to develop a better understanding of the residual oil mobilization process and thus improve the design of chemical flooding projects in water-wet and oil-wet reservoirs. Improved Oil Recovery technologies in the UAE will become a reality very soon, as the producing oil fields will run out of the primary oil recovery phase. The advancement of knowledge for the pore scale phenomena of oil trapping and oil mobilization mechanisms was made possible based on studies that used micromodels of capillary networks etched on glass. The glass micromodels are made using a microlithography based technique similar to the making of printed circuits on boards and microchip manufacturing. The desired pattern of pore channels is etched on a glass plate using Hydrofluoric acid. After we drill inlet and outlet ports in the etched glass plate, it is next fused on to another flat glass plate at 725 °C, thus creating a sintered 2-D glass micromodel with a capillary network in place between the sintered glass plates. This porous medium can be used for studying immiscible displacements of oil with water injection. An example of a square capillary network and photograph of the selected pores in the micromodel seen under a microscope is shown in Fig. 1. As indicated on this figure, the residual oil blobs are found to occupy one to several pores. The pores with residual oil in water-wet media are of generally consisting of predominantly large pore size. The water phase occupies the predominantly smaller pores and the pore corners of space that has residual oil occupancy.
Abstract Our previous contact angle measurements showed that phase change plays an essential role in wettability, thus impacting heavy-oil recovery. While oil is the strongly wetting phase in the steam zone, it becomes the opposite in the condensation (hot-water) zone—regardless of temperature. We also showed that the reverse wettability can be changed using new generation chemicals including thermally resistant chemicals (special surfactants, alkalis, water soluble solvents, and ionic liquids). Even though they reveal useful information, contact angle measurements are limited in accounting for the importance of the wettability alteration effect on the phase distribution/entrapment and oil recovery. Micromodel studies are then preferred to assess these characteristics. All observations and measurements in this research were conducted at temperatures up to 200°C on glass bead micromodels. The models were initially saturated with brine solution and then displaced by two types of mineral oils (450 cP and 111,600 cP at 25°C) to maintain initial water and oil saturation. Hot-water was then constantly injected into the micromodels to evaluate the impact of phase change and wettability status on residual saturation development. Similar parameters were also evaluated in pure steam injection by elevating the temperature to match the steam temperature and maintaining pressure below saturation pressure. Next, several chemical additives screened from the previous contact angle and thermal stability measurements were introduced during both hot-water and steam applications to observe their ability in modifying phase distribution, wettability state, and oil recovery at different pressures and temperatures. The result of the experiments in the glass bead micromodel presented that phase distribution and wettability state were sensitive to steam phase (vapor yielded oil-wet or condensate yielded water-wet case). This phenomenon also aligned with the previous hypotheses indicating that phase change has an impact on the wettability state and residual oil saturation. At any circumstances, wettability alteration with chemicals was possible with the anionic surfactant and SiO2 nanofluid. The shape and characteristics of the trapped oil with and without chemicals were identified through micromodel images and suggestions were made as to the conditions (pressure, temperature, and time to apply during the injection application) at which these chemicals show optimal performance. Study and analysis of phase distribution and wettability change in micromodels during hot-water and steam applications provide useful data and understanding of interfacial properties, oil trapping mechanism, and recovery performance of rock/bitumen/hot-water or steam system in the reservoirs. For practitioners, chemical additives were recommended, validated by visual images and thermal stability tests.