Skauge, T. (CIPR Uni Research) | Skauge, A. (CIPR Uni Research) | Salmo, I. C. (CIPR Uni Research) | Ormehaug, P. A. (CIPR Uni Research) | Al-Azri, N. (PDO) | Wassing, L. M. (Shell Global Solutions International BV) | Glasbergen, G. (Shell Global Solutions International BV) | Van Wunnik, J. N. (Shell Global Solutions International BV) | Masalmeh, S. K. (Shell Global Solutions International BV)
Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.
Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.
Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.
History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
In the case of surfactant EOR, an optimum formulation of surfactant has to be injected in the reservoir. This so-called optimum formulation corresponds to a minimum in the interfacial tension and a maximum in oil recovery and may be obtained with an appropriate balance of the hydrophobic and hydrophilic affinities of the surfactant. Salinity—scan tests are generally used to screen phase behavior of surfactant formulations before conducting time-consuming coreflood tests. The objective of this study was to develop a high-throughput dynamic microfluidic tensiometer, with the aim of studying interfacial phenomena between EOR injected formulations and crude oils and of optimizing chemical EOR processes for pilot or field applications.
We have selected a method based on the Rayleigh-Plateau instability and the analysis of the droplets to jetting transition in a coaxial flow of two fluids. In fact, in coaxial flows, the transition between a droplet and a jetting regime depends on the velocities of each phase, the viscosity ratio, the confinement and the interfacial tension (IFT). As the three first parameters are known, the dynamic interfacial tension can be calculated. This microfluidic device has been specifically designed to support high temperatures (up to 150°C), high pressures (up to 150 bars) and is compatible with complex fluids such as crude oils and solutions of surfactants and polymers.
The method was first developed and validated on a microfluidic device on model fluids at ambient temperature and atmospheric pressure for IFTs higher than 1 mN/m. It was then successfully applied for the measurement of IFTs over more than four decades. Measurements were also performed with a crude oil and a typical surfactant formulation. The validation of the HP/HT assembly, which has been designed with the aim to work in reservoir conditions, is currently under progress. By using this tensiometer, it would be quite easy to perform in short time numerous salinity scans on real systems in order to get the evolution of IFT and determine the optimal salinity S*.
Chen, Zhao (New Mexico Inst-Mining & Tech) | Du, Cheng (New Mexico Inst-Mining & Tech) | Kurnia, Ivan (New Mexico Inst-Mining & Tech) | Lou, Junjie (New Mexico Inst-Mining & Tech) | Zhang, Guoyin (New Mexico Petroleum Recovery Research Center) | Yu, Jianjia (New Mexico Petroleum Recovery Research Center) | Lee, Robert L. (New Mexico Petroleum Recovery Research Center)
Hydrodynamic retention is one of the contributors to polymer loss in porous media. In this study, effects of flow rate, polymer molecular weight, and core permeability on hydrodynamic retention were investigated. To quantify hydrodynamic retention, injection of two identical polymer banks at different rates separated by 100 pore volumes of brine flushing was performed. Three HPAM polymers with molecular weights of 6–8 million, 12 million, and 20 million Daltons were tested in a 135 mD sandstone core and xanthan polymer with molecular weight of 2–2.5 million Daltons was tested in an 87 mD sandstone core. The retention of 6–8 million Daltons HPAM in a 1,650 mD sandstone core was also measured. Polymer retention in a fresh core was first measured at low injection rate of 3.11 ft/day. Then, 100 PV of 2% NaCl brine was injected to displace all the mobile polymer molecules in the core till pressure drop across the core became stable. Hydrodynamic retention at elevated flow rates was determined after the completion of retention at lower rates and comparisons with the initial polymer retention were made.
Retention of 96.1 µg/g in the 135 mD core was detected for the 6–8 million HPAM at a flow rate of 3.11 ft/day. Increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day resulted in incremental retention of 2.27 µg/g and 5.38 µg/g, respectively. The injection of a higher molecular weight polymer at the same rate was performed after retention was satisfied with a lower molecular weight polymer. It was found the degree of hydrodynamic retention was greater when higher molecular weight polymers were injected. When core permeability was changed from 135 mD to 1,650 mD, both the initial and hydrodynamic retention were dramatically decreased. The initial retention of xanthan was 66.7 µg/g in an 87 mD sandstone core, which was smaller compared to the retention of HPAM in the similar core. However, hydrodynamic retention measurements of xanthan gives 3.26 µg/g and 6.38 µg/g increments with the increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day, which suggested that the retention of xanthan is slightly more sensitive to the change of injection rate than HPAM. This study also implied that measurement of residual resistance factor after polymer injection should be completed after sufficient brine flushing (around 100 PV), otherwise, an overestimated residual resistance factor might be provided.
Lotfollahi, Mohammad (The University of Texas at Austin) | Kim, Ijung (The University of Texas at Austin) | Beygi, Mohammad R. (The University of Texas at Austin) | Worthen, Andrew J. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Johnston, Keith P. (The University of Texas at Austin) | Wheeler, Mary F. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin)
The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity.
The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity.
A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature.
The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.