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Summary Enhanced oil recovery (EOR) polymer systems such as hydrolyzed polyacrylamide (HPAM) solutions flowing in porous media at high fluxes were reported to cause shear-thickening, a nonlinear viscoelastic (NLVE) phenomenon. Bulk rheological studies are usually performed to characterize the viscous and viscoelastic behaviors of polymer solutions in porous media. To characterize the viscoelastic properties, oscillatory shear rheology based on linear viscoelastic (LVE) data and extensional rheology based on NLVE data have been used. Although both extensional flow and high-speed shear flow can stretch and thicken polymer solutions in a nonlinear fashion, steady-shear rheometry has been used to measure only the viscous and thinning behavior of HPAM systems. In this paper, (a) the thickening ability of HPAM polymer systems formulated with contrasting salinity and molecular weight (MW) concentration is characterized in bulk shear rheometry to analyze if the thickening in the pure shear field correlates with the thickening behavior reported in porous media and other rheometry and (b) the thickening intensity of the polymer solutions of varying salinity concentration in the bulk shear field is compared with the reported mechanical degradation effects in the literature. The shear-thickening index obtained by fitting a power-law model to thickening data in steady-shear rheograms is higher for the high-saline, high-MW low-concentration HPAM systems that have inherently higher nonlinear viscoelasticity. Furthermore, the thickening behavior observed due to salinity variation in bulk steady shear contrasts with linear oscillatory shear behavior but conforms to the thickening behavior observed in porous media and in the extensional field. This signifies that polymer-EOR researchers performing comparative studies on low-salinity and high-salinity polymer floods, and having a shear rheometer at their disposal, must look beyond linear oscillatory rheology and make use of nonlinear steady-shear rheology. There is a direct relation between the shear-thickening index of saline HPAM solutions and their mechanical degradation intensity. This paper shows that the high-speed data in steady-shear rheometry that are usually ignored in EOR literature have useful information and the notion that HPAM solutions are purely thinning in the bulk shear field needs to be reconsidered.

Summary Since the introduction of viscous/capillary concepts by Moore and Slobod (1956), several modifications and advancements have been made to the capillary number (Nc) so that it could have a better correlation with residual oil saturation (Sor) during enhanced oil recovery (EOR). In subsequent years, laboratory-scale studies have indicated that the viscoelastic polymers can influence the Sor reduction at relatively higher fluxes and Nc. Although the flux rate of at least 1 ft/D is reported to be needed for viscoelastic polymers to reduce Sor to a noticeable extent, significant Sor reductions were reported to occur only at higher fluxes that are likely to be seen in the reservoir closer to the wellbore. At similar levels of flux and Nc, the polymer solutions with significant elastic properties have shown higher Sor reduction than viscous polymer of similar shear rheology. However, the existing models used for correlating the polymer’s viscoelastic effect on Sor reduction relies on either core-scale Nc and/or the oscillatory Deborah number (De). De also has limitations in quantifying the polymer’s viscoelastic effects at different salinities. In this paper, a modified capillary number called an extensional capillary number (Nce) is developed using the localized pore-scale extensional viscosity. For viscoelastic polymer solutions, pore-scale apparent viscosity dominated by localized extensional viscosity is calculated to be significantly higher than core-scale apparent viscosity. We provide rheological insights using the variable-strain-rate concept to explain why and when the pore-scale apparent viscosity could become significantly higher, even at a flux of approximately 1 to 4 ft/D, and why it will not be reflected on the core-scale apparent viscosity or pressure drop. An exponential correlation was developed between Nce and Sor using the extensive coreflood experimental data sets extracted from various literature. Performance of Nce for predicting the viscoelastic polymer’s residual oil recovery is compared with conventional Nc, De, and a recent correlation. The results show that newly developed Nce can predict the Sor during polymer flooding for a wide range of operational and petrophysical conditions, including brine-salinity effects.

In general, it is believed that the ultra-low IFT provided by surfactant is a requirement for the higher microscopic recovery efficiency during enhanced oil recovery (EOR). In tight oil shale and shale reservoirs, capillary imbibition become a dominant recovery mechanism where ultra-low IFT becomes less significant or even a retarding force in certain scenarios. Recent researches have emphasized that the microscopic efficiency of CO2 flooding could be improved by adding low IFT surfactants. Surfactants are also used for conformance/mobility control applications in the form of foam. During foam flooding application in naturally fractured reservoirs, the ultra low-IFT conditions is advantageous for oil recovery in dolomite but not in limestone rocks. Although low-IFT conditions positively influences the microscopic recovery during alkali steam-foam flooding, ultra-low IFT is not required. This chapter compiles these cases and sheds insight using fundamental reservoir engineering concepts to understand why the ultra-low IFT conditions, conventionally considered to be a prerequisite for the higher residual oil recovery, are not always beneficial or required or enough during many of the EOR applications.

In this article, extensional rheological data of various polymer solutions, to be used in Azad Trivedi viscoelastic model (AT-VEM) for predicting the viscoelastic behavior of synthetic polymer in porous media are provided. Extensional rheology measurements are performed for different polymer solutions using Capillary breakup extensional Rheometer (CaBER) to obtain the filament diameter with respect to time. Extensional rheological parameters, such as the extensional relaxation time, maximum elongational viscosity at the critical Deborah number and strain hardening index are determined from observed filament diameter with time-based on the Upper Convected Maxwell model, the finite extensible non-linear elastic model, and the power law model.

Theoretically, both the polymer’s resistance to flow and retention are the reasons for the additional pressure drop and resistance factor (RF) generated during polymer flow in porous media. In the case of hydrolyzed polyacrylamide (HPAM), the increase in RF at high flux rates, a phenomenon called shear thickening were successfully correlated in our previous works using the combination of shear and extensional rheology alone. Associative polymers that have gained increased attention for enhanced oil recovery (EOR) applications have relatively a higher retention value in porous media than HPAM. No attempts were made in the literature to investigate whether the associative polymer’s flow behavior at various hydrophobicity in porous media could be correlated using the bulk rheology alone. Further, the role of hydrophobicity and concentration on the associative polymer’s shear thickening and extensional behavior were not studied. In this paper, high flux single phase porous media experiments were performed using three different associative polymers of varying hydrophobicity at 1000 ppm and 2000 ppm concentration in the unconsolidated sand pack. Extensional rheology was performed on these polymers using capillary break-up extensional rheometer. Extensional rheological parameters become lower with increasing hydrophobicity at both 1000 and 2000 ppm. Porous media result indicates that extensional rheology is directly correlated with the RF in associative polymer at 2000 ppm but not at 1000 ppm. At 1000 ppm, the highest RF is exhibited by higher hydrophobic polymer that possess least extensional resistance. Unusually higher retention value observed at 1000 ppm explain the increased RF associated higher hydrophobic polymer or else it could be due to the clustered hydrophobic species formation that appears to be active only if the concentration is not high enough to breakage. It is also our observation that higher retention cannot be predicted through bulk rheological measurements and therefore, this work signifies that a combination of retention and extensional rheological parameters are needed to model the flow behavior of associative polymers in porous media at higher fluxes. Moreover, the relative influence of retention and extensional rheology on the flow behavior of associative polymer is strictly a concentration and hydrophobicity dependent.

Several researchers have investigated the dominant recovery mechanisms among the wettability alteration and interfacial tension (IFT) reduction during surfactant flooding in unconventional, oil-wet reservoirs. Most of the previous studies carried out using spontaneous imbibition fail to answer the dominance of prominent mechanisms, especially with respect to time and location. In this paper, these research gaps are addressed through physico-chemical interactions, and microfluidic studies carried out using zwitterionic surfactant solutions of varying alkyl length and salinity. Based on the IFT and zeta potential values, three surfactant formulations (F1, F2 and F3) are chosen for representative carbonate microfluidic studies. The observations of microfluidic studies are significant to emphasize that at early time F2 and F3 formulation corresponded to higher imbibition rate than F1 formulation due to its higher ability to alter the rock wettability from oil-wet to water-wet. As the front propagates to far location, F1 with ultra-low IFT begins to outperform F3 by providing better microscopic displacement and quicker frontal propagation throughout. In the water-wet media, F1 formulation with the lowest IFT outperforms other formulations at all the time. The results of the study signify that while significant IFT reduction is sufficient for the complete oil displacement in water-wet media, significant IFT reduction at later stage and good wettability alteration at the early stage are needed during surfactant flooding in oil-wet formation.

Heavy oil reserves accounts for more than 8 trillion barrels of the total reserve. Thermal methods such as steam flooding (SF) and its variants have been applied extensively to develop the reserves. Complex heavy oil reservoirs possess certain properties that make the steam flooding ineffective. The properties include low thickness, deeper depth and formation nature (naturally fractured carbonates). Heat losses, gravity override and channeling are the common problems associated with it. Polymer flooding (PF) is one of the major non-thermal methods employed to recover heavy oil. Higher Salinity and divalency in carbonate reservoirs restricts polymer flooding applications. Higher oil viscosity also limits its application. In this work, we investigated the potential of viscoelastic surfactant (VES) in recovering heavy oil in complex reservoirs where steam-flooding and polymer flooding fail. VES exhibits certain unique properties which are ascertained individually. The properties include IFT reduction, viscosity, elasticity, emulsification, salinity resistance, compatibility, and thermal stability. The properties of VES extend its applicability in complex reservoirs and hybrid technique that combined the synergism of VES, P, and hot water has been investigated. Reservoir simulation studies with 5-spot pattern have been conducted to compare the performance of Steam flood, polymer flood, and hybrid VES flooding in thin heavy oil reservoirs. Results indicated that VES could be an ideal hybrid option along with hot water to recover high viscous heavy oil in thin reservoirs.

The thermal methods commonly applied in developing fairly homogeneous heavy-oil reservoirs may not be viable options in channeled heavy-oil reservoirs mainly because the injected fluid (steam) would bypass the heavy oil by flowing through the high permeability channels. Experimentally, it was found that the key to success in developing such reservoirs is to have optimum heat conduction which overcomes the reservoir heterogeneity. Hence, steam flooding, if properly optimized, could overcome this problem. Injection rate and steam quality are the main operational parameters that controls the economic heat propagation in the reservoirs. Additionally, placing the wells in more conducive areas to ensure that the regions with low-to-medium permeability get enough heat, is crucial. In this work, we propose the optimization of steam quality using CMA-ES. A three-dimensional channeled reservoir model undergoing steam flooding was built and CMA-ES was used to estimate the optimal values of three variables of steam flooding. The Net Present Value (NPV) of the project was used as the objective function and three cases of optimization were studied. In Case 1, only the injection and production rates were optimized. In Case 2, well placement was optimized along with the rates. In Case 3, steam quality was included in the list of optimized variables. Results indicated that Case 2 gave higher NPV than Cases 1 and 3 signifying the importance of optimum selection of well placement. Also, it is understood that steam quality is an important parameter which controls the overall steam flooding process and a large number of function evaluations is required to obtain optimum values of steam quality.

Carbonate reservoirs possess the greatest challenge for chemical EOR methods. The challenges limiting the applicability of chemical EOR in carbonate reservoirs are the harsh reservoir conditions and the presence of fractures. Harsh conditions include high salinity, hardness and temperature. These conditions make most of the conventional surfactants and polymers ineffective. Fractures in carbonate reservoir provide the easy conduit for injected slugs to break through the production wells, thereby reducing the sweep efficiency drastically. Thus the carbonate reservoirs are not the best candidate for chemical EOR methods. Viscoelastic surfactant (VES) is the self-assembling surfactant that contributes to displacement and sweep efficiency through the formation of wormlike micelles (WLM). WLM can generate higher viscosity especially at the harsh conditions. The positive impact of VES towards salinity, hardness and temperature could favor its applicability as an EOR fluid. Elastic nature of VES could block the fractures. Three different Viscoelastic surfactants (Ethomin, Armovis and Aquadat) are screened based on WLM growth and IFT. The optimum VES is chosen then. The optimum VES is studied at various concentrations. Surfactants and polymers are added to VES forming S/VES and VES/P system. High Viscosity meant for mobility control and low IFT meant for oil mobilization are the two important parameters which any formulation in chemical EOR is desired for. Hence, ViscosistyIFT ratio of VES, S/VES and VES/P systems are studied individually with sea water of 57000 ppm at the temperature of 70°C. The potential formulation is reported. The potential of VES as the diversion fluid is also studied. Results indicated that Armovis could endure the harsh conditions among the three VES studied. VES system performs better followed by VES/P. VES can be a potential diversion agent.

els (relatively homogenous, fully heterogeneous & discontinuous channeled reservoirs) were used. The objective function was the flood’s net present value (NPV) and Covariance Matrix Adaptation Evolution Strategy (CMA-ES) was used as the optimizer. Results indicated that NPV could be increased significantly for Case 2 in all the models. Discontinuity in heavy oil reservoirs would not be a problem if the optimum well placement is considered

Cyclic Steam Injection (CSS) has been used in the industry to increase the recovery factor and production rate from heavy oil reservoirs. CSS is multi-cycled steam recovery process with three stages and five operational parameters (injection rate and its duration, soak time, production rate and its duration) in each cycle. Determining the optimal values of the operational variables in each cycle, for the existing reservoir conditions is challenging. The difficulty stems from the fact that these parameters cause significant changes in reservoir fluid flow, reservoir behavior and recovery performance during the project duration. Ability to effectively determine the best values of these parameters is expected to increase the recovery efficiency and the profitability of the project. In practice, the parameters of cyclic steam stimulation are often determined by running limited sensitivity studies on some or all the parameters. Such sensitivity studies are however very limited in scope and cannot explore the entire domain of interest. A more efficient method to estimate the optimal parameters of the CSS is to perform automatic optimization using an effective stochastic optimization algorithm. In this work, we propose the use of stochastic optimization to estimate the parameters of CSS. Three different CSS models were developed with three well types (vertical, horizontal and inclined wells). The operational parameters are extremely interdependent in CSS which has mulitiple drive mechanisms. The need for global search is imperative to find the best operating parameters in each cycle. Covariance Matrix adaption Evolution Strategy (CMA-ES) was used to optimize the operational parameters. The project net present value (NPV) was used as the objective function in the optimization process. Results showed that the NPV can be increased significantly when all the operational variables of CSS are optimized. This signifies the importance of simultaneous optimization of soak time, cycle length and rates. The results also showed that the vertical well model gave a higher NPV than the other two well models. The horizontal well model gave the lowest NPV.