Current HLD-NAC theory and most simulators represent multicomponent mixtures with three lumped components, where the excess phases are also assumed pure. This can cause significant errors, and discontinuities in chemical flooding simulation for surfactant mixtures. We coupled the HLD-NAC and pseudo-phase models to develop an EOS for microemulsions where surfactant, polymer, alcohol, alkali and monovalent/divalent ions can partition differently into the excess phases and microemulsion phase as temperature and pressure are changed.
We develop a pseudo-phase model to calculate partitioning of components between lumped components or namely pseudo-phases. The pseudo-phase model is based on a transformed composition space. The partitioning model is based on different mechanisms such as cation exchange like reactions for ions and surfactant hydration properties. Next, the three-pseudo-component HLD-NAC EOS is used to calculate curvature of the interface and microemulsion phase composition based on pseudo-phases. That is, the microemulsion phase consists of a curved ruled surface between water and oil pseudo-phases. Polymer partitioning is updated based on micelle radius. Finally, the phase compositions are converted back from pseudo-phase space to the original composition space.
This model is the first comprehensive and mechanistic flash calculation algorithm based on HLD-NAC and pseudo-phase theory to calculate microemulsion properties for mixtures without the assumption of pure excess phases. This algorithm allows for modeling of the chromatographic separation of surfactant, soap, alcohol, alkali and polymer components in chemical flooding processes. Current microemulsion models usually ignore the differing partitioning of components between excess and microemulsion phases, generating discontinuities that slow computational time and adversely impact accuracy.
Aqueous foam has been demonstrated through laboratory and field experiments to be a promising conformance control technique. This study explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A distinguishing feature of this surfactant is its ability to dissolve in supercritical CO2 and to form Wormlike Micelles (WLM) at elevated salinity. Presence of WLM led to an increase in viscosity of the aqueous surfactant solution. Our study investigates how the presence of WLM structures affect transient foam behavior in a homogenous porous media (sand pack).
Sand pack foam flooding experiments were performed with two aqueous phase salinities: low salinity (15 wt. % NaCl) associated with spherical-shaped micelle and high salinity (20 wt. % NaCl) associated with WLM. We compared the onset of strong foam propagation and foam apparent viscosity buildup rate between the two salinity cases. The effect of WLM presence in transient foam behavior was investigated for co-injection and water-alternating-gas (WAG) injection strategies. In all foam flooding experiments, the surfactant was delivered in the CO2 phase.
Strong foam was generated in all foam flooding experiments, with an apparent foam viscosity of at least 600 cp for co-injection and 200 cp for WAG floods after five total injected pore volumes. The observed strong foam indicated that the delivery of surfactant in the CO2 phase was successful and that the surfactant molecules partition to the water phase in the sand pack. In comparison to the low salinity cases, the high salinity foam floods associated with the presence of WLM led to better foam performance. We observed an earlier onset of strong foam propagation as well as a higher apparent viscosity buildup rate. Better foam performance at higher salinity may be attributed in large part to the presence of WLM structures in the foam liquid phase. Entanglement of these WLM structures may have led to in-situ viscosification of the foam liquid phase and an increase in disjoining pressure between foam films. Both phenomena may have reduced the rate of foam film coalescence.
WLM structures behave similarly to polymer molecules. Our study may offer evidence that WLM is a valid alternative to polymer as an additive to enhance foam conformance control performance. Some potential advantages of WLM over polymer include: Delivery of surfactant in the gas phase (to alleviate the injectivity issue typically associated with high viscosity polymer-surfactant solution), resistance to extreme temperature and salinity, and reversible shear degradation.
Higher stability of the bulk and dynamic foam with polymer addition to the aqueous phase has been demonstrated experimentally. Recent experiments indicated that the efficacy of polymer enhanced foam (PEF) is dependent on polymer type and surfactant-polymer interaction. However, numerical modeling of PEF flow in porous media has been relatively less well understood due to the additional complexity. In this work, we propose modifications to the population-balance foam model for PEF modeling, and their successful use in matching the experimental results.
The population-balance model proposed by Chen and co-workers has been used as development platform. Upon reviewing various aspects in the physics of foam generation, coalescence and mobility reduction in porous media with the addition of polymer, a modified population-balance model was proposed with new parameters pertaining to the polymer effect on the net foam generation and the limiting capillary pressure. The new model was implemented and used to history match foam coreflood experiments with and without polymer.
In addition to the foam apparent viscosity increase due to higher viscosity of the aqueous phase, polymer also impacts foamability and foam stability of bulk foam as indicated in the literature. Our modified population-balance model introduce the viscosity terms in foam generation and coalescence coefficients to account for postulated positive impact on reducing liquid drainage and foam coalescence and negative impact on the characteristic time needed for bubble snap-off in porous media. Additionally, a modification in the limiting capillary pressure was proposed in the new model to include the polymer effect based on our analysis of the disjoining pressure. Two new model parameters are proposed and implemented accordingly. The new foam model succeeded in history-matching the anionic-surfactant-based and nonionic-surfactant-based PEF corefloods with different types of polymers through tuning the two new model parameters. The simulations also captured the transient increasing of the pressure drops induced by polymer transport and adsorption. The proposed model can be used to provide meaningful values of the model parameters that were able to explain the physical mechanisms behind the PEF floods and to guide future experimental design to further constraint the choices of model parameters.
This work provided new methodology to model PEF flow in porous media using the mechanistic population-balance approach for the first time. With proper calibrations of the parameters proposed in the model, the new model can therefore be used to simulate PEF EOR processes to describe the combined effect of foam and polymer on the mobility control of the injectants.
Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm2. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
Doorwar, Shashvat (Chevron Energy Technology Company) | Lee, Vincent (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Traditionally, all surfactant processes require viscous polymer to mobilize the oil bank. Recent literature shows that for highly dipping reservoirs, a continuous surfactant injection process can be stabilized with gravity alone, by slowing down the processing rate. We extend the gravity stable approach for surfactant slug processes and demonstrate the importance of maintaining gravity stability between slug and chase in addition to gravity stability between microemulsion and slug. Four sandpack experiments were conducted and pictures of the sandpack were taken at regular intervals to provide visual evidence of stable or unstable interfaces. Different color dyes were used to aid visualization of clear fluids. Gravity-stabilized surfactant-only processes eliminate the need of polymer and other facilities associated with surfactant polymer or alkali-surfactant-polymer processes. The slug process described in this paper is a significant improvement on the continuous surfactant injection gravity stable process published earlier.
The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.
In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.
The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the production rates of solvent and bitumen decrease.
The efficiency of this process is evaluated using Cumulative Steam-Oil Ratio (CSOR) and cumulative solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates.
We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on
We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model
Kim, Ijung (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Worthen, Andrew J. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | Lotfollahi, Mohammad (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | DiCarlo, David A. (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
SmartWater flooding through injection of chemistry optimized waters by tuning individual ions is recently getting more attention in the industry for improved oil recovery in carbonate reservoirs. Most of the research studies described so far in this area have been limited to studying the interactions at rock-fluids interfaces by measuring contact angles, zeta potential, and adhesion forces. The other widely reported interfacial tension data at oil-water interfaces do not consider the formation of interfacial monolayer and the interfacial tension is estimated as an average parameter relying on the properties of two individual bulk phases. As a result, such measurements have serious shortcomings to provide any details on complex microscopic scale interactions occurring directly at the interface between crude oil and water to understand the SmartWater flood recovery mechanism.
In this study, two novel interfacial instruments of interfacial shear rheometer and surface potential sensor were used to study microscopic scale interactions of various individual water ions at both air-water and complex crude oil-water interfaces. The measured interfacial rheology data indicated totally different interfacial behavior at crude oil-water interface when compared to air-water interface due to presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. These interfaces behaved like a viscous fluid without exhibiting viscoelastic solid like properties. Lower interfacial viscous modulus was observed for certain key ions such as calcium, magnesium, and sodium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface.
The interesting results observed with certain water ions at fluid-fluid interfaces are expected to work in tandem with rock-fluids interactions to impact oil recovery in SmartWater flood. At first, they play a role to control the accessibility of active water ions to approach the rock surface, interact with it and subsequently alter wettability. Next oil droplets adhering to the rock surface will be detached and released due to favorable interactions occurring at rock-fluids interfaces. The interfacial film between oil and water can then quickly be destabilized due to less viscous interfaces observed with certain ions to promote drop-drop coalescence and easy mobilization of released oil droplets. This coalescence process is sequential and it would continue until the formation of small oil bank.
This is the first study that showed added importance of fluid-fluid interactions in SmartWater flood by using direct measurements on individual water ions at crude oil-water interface. In addition, a new oil recovery mechanism was proposed by combining both the interactions occurring at fluid-fluid and rock-fluids interfaces. The new fundamental knowledge gained in this study will provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces to optimize oil recovery from SmartWater flood.
Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 °C) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.