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Abstract Microscopic Visualization of the porous media can provide valuable information to enhance understanding of pore-scale transport phenomena. Here, a micromodel which its grains and pores are non-uniform in size, shape and distribution is considered as porous medium. The pore size distribution as well as pore length distribution was extracted by applying an image analysis technique. A two-dimensional random network model of the micromodel has been constructed which the non-uniformity is considered by assigning measured distribution functions. The random particle method was applied for correlating and predicting dispersion coefficients based on probabilistic approaches. Statistical derivations result in a new functional dependence for the longitudinal and transverse dispersion coefficients in terms of pore velocity and ensemble averages. Prediction from derived model for both longitude and transverse dispersion is in close agreement with the experimental data. Despite the simplicity of the proposed network model, its accurate prediction provides some confidence that it can be considered as a reasonable approximation of the complex nature of porous media with reliable predictive capability. Introduction Dispersion in porous media is one of the most extensively studied fundamental transport properties in physics with applications in improved oil recovery, hydrology and chemical engineering. The geometry and topology of the microscopic pores control transport properties of porous medium, e.g., dispersion and permeability (Sahimi, 1993). On the other hand, the exact solutions of fluid flow and convection-diffusion equations at the pore scale are extremely difficult to obtain, due to the complexity of the boundary conditions at the irregular pore/grain interface(Man and Jing, 2000). Therefore, it is important to have a reliable tool that can provide plausible estimates of the properties. Instead of searching for exact solution, research efforts have focused on ways to simplify the irregular pore systems. Such simplified versions of porous medium are called 'network model', which can be the only possible means of understanding the flow through porous media from a microscopic point of view (Dullien, 1992). Network models, which are exemplified by the work of Fatt (1956), can be applied either as stochastic model or as a fixed model, depending on whether or not the pores which constitute the connections in the network are considered having a probability distribution of sizes. In a sense, the randomly oriented network models are simply more general network models in which the connecting links in the networks are permitted a distribution of orientations, radii and lengths rather than being fixed as, for example, the edges of regular polyhedral. In comparison with the deterministic model of Taylor (1953 and 1054) and Aris (1956), there has been much work to represent dispersion through statistical models. The idea behind a statistical approach is that to attribute probabilities to predict the distribution of many tracer particles at a certain time, which were initially in close proximity to each other at initial time. In short, over large enough time periods, the time-averaged velocity of a single particle can be used in place of the averages taken over the whole group of particles; thus the problem reduces to that of the random motion of a single particle (Bear, 1072).
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.
- North America > United States (1.00)
- Asia > China > Heilongjiang Province > Daqing (0.24)
- Europe > France > Chateaurenard Field (0.99)
- Europe > Austria > Vienna Basin > Pirawarth Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract In this paper the simulation is described of water-alternating-gas injection (WAG) flood cycles in 2-D etched glass mixed-wet micromodels, using a 3-D pore-scale network model for three-phase immiscible flow in porous media of arbitrary wettability. Although most network model input parameters can be explicitly derived from the experiments, the precise wettability parameters are not directly available. Therefore, a sensitivity study was carried out, using the network model in 2-D mode, to obtain the wettability characteristics, i.e. the contact angle values and distribution, and the fraction of water-wet pores. Good qualitative and quantitative agreement was found between the experimental and simulated recoveries over the various WAG cycles, and the final residuals were well reproduced (as well as some observed "random recovery jumps"). The simulated displacement statistics showed many so-called multiple displacement chains involving oil, up to around the third WAG cycle. The experimental and simulated fluid distributions were generally in good agreement in thatdifferent gas fingers were observed during various gas floods, oil movement was observed mainly during the first few WAG cycles, and during water floods, significant amounts of gas were displaced. Additionally, previously described simulations of water-wet and oil-wet experiments are compared with the present mixed-wet simulations. There are close similarities between the mixed-wet and oil-wet cases, which both maintain some continuity of oil through wetting films, but these cases are quite different from the water-wet case, which has continuity of water through wetting films in all pores. This paper further validates the pore-scale mechanisms incorporated in a network model that is capable of predicting three-phase relative permeabilities and capillary pressures for complicated processes such as WAG. Introduction Modelling hydrocarbon recovery processes involving three-phase flow, such as Water-Alternating-Gas injection (WAG) requires accurate knowledge of the corresponding capillary pressure and relative permeability functions. However, there are significant experimental difficulties in obtaining these quantities and over recent years pore-scale network models are emerging as potential predictive tools. These models take into account the pore-scale flow mechanisms, which in turn have to be underpinned by observations from microscopic flow experiments. Micromodels consisting of a 2-D porous structure etched in glass or other transparent materials are of great help in visualising these mechanisms. When the detailed flow mechanisms are incorporated in the network model, we may then directly compare the network flow simulations with the micromodel flow experiments, as a way of validating the network model (e.g. van Dijke et al., 2004, 2006). In the present paper, this task has been carried out for WAG experiments in mixed-wet micromodels, described by Sohrabi et al. (2001, 2004). Several authors have emphasised the importance of the spreading behaviour (of oil) on the pore-scale three-phase flow mechanisms, as well as the role of the wettability of the medium (see e.g. Øren and Pinczewski (1995), Vizika and Lombard (1996), Keller et al. (1997) and Dong et al. (2005)). In strongly water-wet media, the presence or absence of spreading oil layers in gas filled pores plays an important role in improving oil recovery. In oil-wet and weakly water-wet media it is the presence or absence of oil wetting films surrounding the water and gas phases, depending on the degree of wettability, that may enhance recovery. This affects the detailed mechanism of which phase displaces which and in what size of pore (van Dijke and Sorbie, 2002b).
- Research Report > Experimental Study (0.88)
- Research Report > New Finding (0.66)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
A Pore Level Study of MIOR Displacement Mechanisms in Glass Micromodels Using Rhodococcus sp 094
Crescente, Christian Miguel (StatoilHydro) | Rekdal, Andreas (StatoilHydro) | Abraiz, Akram | Torsaeter, Ole (Norwegian U. of Science & Tech) | Hultmann, Lisbeth (NTNU) | Stroem, Arne (NTNU) | Rasmussen, Kjetill (Norwegian U. of Science & Tech) | Kowalewski, Espen (Statoil ASA)
Abstract Micromodel experiments have been executed in order to have better insight into the displacement mechanisms allowing Rhodococcus sp. 094 to increase oil recovery. Changes caused by the bacteria in the fluid interfaces and pore walls have been recorded and are presented. The previously suspected mechanisms are further confirmed by the results, but a much better insight into the details of how the process occurs has been obtained and a theory for this process is developed. Introduction Previous publications by the authors have already stated the effectiveness of Rhodococcus sp. 094 to increase oil recoveries from Berea cores with pure hydrocarbons (dodecane) consistently with an additional 4 % and at the most favorable conditions with up to 9%. The mechanisms suspected for the additional recovery have been: Selective plugging, interfacial tension (IFT) reduction, and changes in wettability. In those publications, the work has focused on standard reservoir lab measurements, especially Berea corefloodings and interfacial tension and wettability measurements. Glass micro model experiments can complement very well these experiments, by providing a look into the process as it unfolds in the pore space. Even though the glass micromodels used have limitations from the larger pore size deriving from the fabrication process limitations, and from the homogenous and two dimensional geometry of the flow, they can still be an invaluable tool for understanding complex mechanisms, testing hypotheses and qualitatively provide a guide of the changes occurring in the pore space with different EOR methods. It was also possible to estimate the saturation by using image analysis software, which has made it possible to plot the enhanced oil recovery vs. the capillary desaturation curve (CDC). A total of ten experiments where brine and brine with either the surfactant producing or the non-surfactant producing variant of the Rhodococcus sp. 094 bacterium are presented. The results obtained in the micromodel flooding are analyzed in conjunction with the results from coreflooding experiments, and in this way a much better understanding of the mechanisms emerges, and a hypothesis can be proposed. By designing new experiments to test this hypothesis, it can be confirmed, improved or disproved.
- Asia (1.00)
- North America > United States > Oklahoma (0.29)