Mobility reduction is one of the critical parameters in polymer flooding. The EOR polymers have shear thinning bulk rheology, while core flood experiments with hydrolysed polyacrylamide (HPAM) in this paper show four different viscosity regimes. Through a systematic work, in which the molecular weight and degree of hydrolysis as well as the permeability and brine salinity were varied, the apparent viscosity was well-matched with theoretical models. The following four viscosity regimes were identified: (i) At low shear rates, the apparent Newtonian viscosity is less than the bulk viscosity; this effect is because of the inaccessible pore volume (IPV) with the polymer not entering the entire pore space. (ii) Shear thinning behaviour which is controlled by the polymers relaxation time, λ 1 . (iii) At high shear rates, the apparent viscosity increases by increasing the shear rate caused by elongation whose onset is controlled by a critical shear rate which depends on the relaxation time. (iv) At very high shear rates, the apparent viscosity decreases by increasing the shear rate because of mechanical polymer degradation caused by polymer rupture.The controlling parameter is the bulk relaxation time for the polymer. The critical shear rates for elongation and shear degradation increase when the effective molecular weight decreases. Typical injection shear rates in offshore matrix reservoirs exceed the critical shear rate for elongation and shear degradation. Consequently, high molecular weight HPAM will either have poor injectivity or cause fracturing. For injection into fractured wells, the shear rate is substantially reduced and the shear degradation can be avoided. Acrylamido-Propyl-Sulfonate (AMPS) co-polymers have similar apparent viscosity versus shear rate as the HPAM. However, the AMPS co-polymers seem to tolerate higher shear rates before degradation sets in.For comparison, core flood experiments with Xanthan have been performed. This polymer was shear stable and the shear thinning apparent viscosity was similar to the bulk viscosity.The polymers reduced the permeability and the permeability reduction is understood by the polymer size, i.e., the permeability reduction increases by increasing the molecular weight. IntroductionPolymer flooding is an EOR method for improving the sweep efficiency. Polymers increase the water viscosity and reduce the water permeability. The most frequently used EOR polymers are HPAM which can be produced in large volumes and transported to the field as dry powder; biopolymers, such as Xanthan, have also been applied. The EOR polymers are pseudoplastic fluids, with their viscosity decreasing when the shear rate increases; this behaviour is very important in terms of injectivity.Polyacrylamide polymers are known to be sensitive to shear degradation and shear thickening at high shear rates. An overview was given by Heemskerk et al. (1984) and in a recent work by Seright et al. (2009). In this work we relate the shear degradation to the rheological properties of the polymer. When a po...

Microbial enhanced oil recovery (MEOR) represents a possible cost-effective tertiary oil recovery method. Although the idea of MEOR has been around for more than 75 years, even now little is known of the mechanisms involved. In this study, Draugen and Ekofisk enrichment cultures, along with Pseudomonas spp. were utilized to study the selected MEOR mechanisms. Substrates which could potentially stimulate the microorganisms were examined, and l-fructose, d-galacturonic acid, turnose, pyruvic acid and pyruvic acid methyl ester were found to be the best utilized by the Ekofisk fermentative enrichment culture. Modelling results indicated that a mechanism likely to be important for enhanced oil recovery is biofilm formation, as it required a lower in situ cell concentration compared with some of the other MEOR mechanisms. The bacterial cells themselves were found to play an important role in the formation of emulsions. Bulk coreflood and flow cell experiments were performed to examine MEOR mechanisms, and microbial growth was found to lead to possible alterations in wettability. This was observed as a change in wettability from oil wet (contact angle 154 • ) to water wet (0 • ) due to the formation of biofilms on the polycarbonate coupons.

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Mobility reduction is one of the critical parameters in polymer flooding. The EOR polymers have shear thinning bulk rheology, while core flood experiments with hydrolysed polyacrylamide (HPAM) in this paper show four different viscosity regimes. Through a systematic work, in which the molecular weight and degree of hydrolysis as well as the permeability and brine salinity were varied, the apparent viscosity was well-matched with theoretical models. The following four viscosity regimes were identified: (i) At low shear rates, the apparent Newtonian viscosity is less than the bulk viscosity; this effect is because of the inaccessible pore volume (IPV) with the polymer not entering the entire pore space. (ii) Shear thinning behaviour which is controlled by the polymers relaxation time, λ 1 . (iii) At high shear rates, the apparent viscosity increases by increasing the shear rate caused by elongation whose onset is controlled by a critical shear rate which depends on the relaxation time. (iv) At very high shear rates, the apparent viscosity decreases by increasing the shear rate because of mechanical polymer degradation caused by polymer rupture.The controlling parameter is the bulk relaxation time for the polymer. The critical shear rates for elongation and shear degradation increase when the effective molecular weight decreases. Typical injection shear rates in offshore matrix reservoirs exceed the critical shear rate for elongation and shear degradation. Consequently, high molecular weight HPAM will either have poor injectivity or cause fracturing. For injection into fractured wells, the shear rate is substantially reduced and the shear degradation can be avoided. Acrylamido-Propyl-Sulfonate (AMPS) co-polymers have similar apparent viscosity versus shear rate as the HPAM. However, the AMPS co-polymers seem to tolerate higher shear rates before degradation sets in.For comparison, core flood experiments with Xanthan have been performed. This polymer was shear stable and the shear thinning apparent viscosity was similar to the bulk viscosity.The polymers reduced the permeability and the permeability reduction is understood by the polymer size, i.e., the permeability reduction increases by increasing the molecular weight.

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Summary In the coarse-scale simulation of heterogeneous reservoirs, effective or upscaled flow functions (e.g., oil and water relative permeability and capillary pressure) can be used to represent heterogeneities at subgrid scales. The effective relative permeability is typically upscaled along with absolute permeability from a geocellular model. However, if no subgeocellular-scale information is included, the potentially important effects of smaller-scale heterogeneities (on the centimeter to meter scale) in both capillarity and absolute permeability will not be captured by this approach. In this paper, we present a two-stage upscaling procedure for two-phase flow. In the first stage, we upscale from the core (fine) scale to the geocellular (intermediate) scale, while in the second stage we upscale from the geocellular scale to the simulation (coarse) scale. The computational procedure includes numerical solution of the finite-difference equations describing steady-state flow over the local region to be upscaled, using either constant pressure or periodic boundary conditions. In contrast to most of the earlier investigations in this area, we first apply an iterative rate-dependent upscaling (iteration ensures that the properties are computed at the appropriate pressure gradient) rather than assume viscous or capillary dominance and, second, assess the accuracy of the two-stage upscaling procedure through comparison of flow results for the coarsened models against those of the finest-scale model. The two-stage method is applied to synthetic 2D reservoir models with strong variation in capillarity on the fine scale. Accurate reproduction of the fine-grid solutions (simulated on 500'500 grids) is achieved on coarse grids of 10'10 for different flow scenarios. It is shown that, although capillary forces are important on the fine scale, the assumption of capillary dominance in the first stage of upscaling is not always appropriate, and that the computation of rate-dependent effective properties in the upscaling can significantly improve the accuracy of the coarse-scale model. The assumption of viscous dominance in the second upscaling stage is found to be appropriate in all of the cases considered. Introduction Because of computational costs, field-simulation models may have very coarse cells with sizes up to 100 to 200 m in horizontal directions. The cells are typically populated with effective properties (porosity, absolute permeability, relative permeabilities, and capillary pressure) upscaled from a geocellular (or geostatistical) model. In this way, the effects of heterogeneity on the geocellular scale will be included in the large-scale flow calculations. The cell sizes in geocellular models may be on the order of 20 to 50 m in horizontal directions. However, heterogeneities on much smaller scales (cm- to m- scale) may have a significant influence on the reservoir flow (Coll et al. 2001; Honarpour et al. 1994), and this potential effect cannot be captured if the upscaling starts at the geocellular scale.

Wettability is a major factor that affects the flow behavior and recovery efficiency in oil reservoirs. In this study, the effects of wettability on water-oil relative permeability (kr), capillary pressure (Pc) curve and capillary desaturation curve (CDC) have been investigated in laboratory on core scale. Water floods and surfactant floods at different capillary numbers (Nc) were carried out in sandstone rock at different wettability conditions. These floods were followed by oil floods. The kr and Pc curves were estimated by history matching the experimental production and pressure drop. The recovery after water flood was higher at non water-wet conditions but a higher throughput of water was needed. Estimated kr and Pc curves vary with the wettability of the rock. The relative permeability of the wetting phase is more curved than that of the non wetting phase. The measured CDC for oil in mixed-wet condition and the CDC for water in water-wet condition deviate from the typical CDC shape. In these cases, it is found that the measured remaining oil or water saturation is a function of the number of pore volumes injected and also it is largely affected by capillary end effects. Since the residual saturation is difficult to be obtained in core floods at non water-wet conditions, the measured CDC in laboratory experiments does not represent the true CDC. More focus should be directed at relative permeability (corrected for capillary end effects) than the residual oil saturation. The results presented in this paper demonstrate the importance of the wettability of rock on recovery efficiency and also the importance of correcting the laboratory data especially predicting the flow behaviour of non water-wet conditions. Remaining oil saturation based on relative permeability should be used instead of residual oil saturation in evaluation of the potential for tertiary recovery, e.g. surfactant.

The effect of interfacial tension (IFT) on the displacement of the nonwetting and wetting phases has been investigated by the use of simulations/history matching of flooding experiments. In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure (P c ) on measured two-phase properties. The methodology applied in this paper allows improved interpretation of experimental results by correcting for the influence of capillary end effects on the measured capillary desaturation curve (CDC) and on the estimated relative permeability (k r ).Three fluid systems of different IFTs were prepared by use of a solvent system (CaCl 2 brine/iso-octane/isopropanol) rather than a surfactant system with the assumption that both systems have similar flood behavior at reduced IFT. Three coreflood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. The k r functions corrected for capillary end effects were derived by numerically history matching the experimental production and pressure-drop (PD) history.A typical CDC is observed for the nonwetting phase oil, with a roughly constant plateau in residual oil saturation (ROS), S or , below a critical capillary number (N cc ) and a declining slope above N cc toward zero S or . No influence of P c was found for the nonwettingphase CDC.The results from the displacement of the wetting phase formed an apparent CDC with a declining slope and no N cc . Analyzing the wetting-phase results, we find that the wetting-phase CDC is not a true CDC. First, it is a plot of the average remaining water saturation (S w ) in the core which, in all the experiments, is higher than residual water saturation, S wr , obtained from P c measurements. Second, we find that the remaining S w is only partly a function of N c . At low N c , the water production (WP) is limited by capillary end effects. Rate-dependent WP observed with the high-IFT system is fully reproduced in simulations by use of constant k r and P c . The remaining wetting-phase saturation at a low capillary number (N c ) is a result of the core-scale balance between viscous and capillary forces and would, for example, depend on the core length. At a higher N c , the WP is found to be limited by the low k r tail, typical for wetting phases. However, we find that the k r functions become rate dependent at a higher N c , and we assume that this rate dependency can be modeled as a function of N c . The remaining wetting-phase saturation at a higher N c would then be a function of N c and the number of pore volumes (PVs) injected. The observed N c dependency in the flow functions indicates a potential for the accelerated production of the wetting phase by use of surfactant.Assuming that the results obtained here for the wetting phase also apply to oil in a mixed-wet system, it is strongly recommended to evaluate the effect of both P c and N cc when designing a surfactant model for a mixed-wet field. IntroductionAf...