Modeling foam flow through porous media in the presence of oil is essential for various foam-assisted enhanced oil recovery (EOR) processes. We performed an in-depth literature review of foam-oil interactions and related foam modeling techniques, and demonstrated the feasibility of an improved bubble populationbalance model in this paper. We reviewed both theoretical and experimental aspects of foam-oil interactions and identified the key parameters that control the stability of foam lamellae with oil in porous media. Upon reviewing existing modeling methods for foam flow in the presence of oil, we proposed a unified population-balance model that can simulate foam flow both with and without oil in standard finite-difference reservoir simulators. Steadystate foam apparent viscosity as a function of foam quality was used to evaluate the model performance and sensitivity at various oil saturations and fluid velocities. Our literature review suggests that, among various potential foam-oil interaction mechanisms, the pseudo-emulsion-film (gas/aqueous/oil asymmetric film) stability has a major impact on the foam-film stability when oil is present.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Patil, P. D. (The Dow Chemical Company) | Knight, T. (The Dow Chemical Company) | Katiyar, A. (The Dow Chemical Company) | Vanderwal, P. (The Dow Chemical Company) | Scherlin, J. (Fleur De Lis Energy LLC) | Rozowski, P. (The Dow Chemical Company) | Ibrahim, M. (Schlumberger) | Sridhar, G. B. (Schlumberger) | Nguyen, Q. P. (The University of Texas at Austin)
This paper summarizes the overall response from the CO2-foam injection in the Salt Creek field, Natrona County, Wyoming. Conformance control of CO2 by creating foam between supercritical CO2 and brine to improve the sweep efficiency is documented in this paper. The foam was implemented in an inverted fivespot pattern in the Salt Creek field where the second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 ft and at a depth of approximately 2,200 ft. The initial phase of the foam pilot design involving identifying the pilot area, performing coreflood experiments, performaing dynamic reservoir simulation for history match, and forecasting with foam have been documented in the literature. As a part of the foam pilot monitoring, a gas tracer study was performed before and after the injection of foam in the reservoir. The initial planning, monitoring, and part of foam response is covered in earlier publications. The last surfactant injection in the field was in June 2016. This paper provides the complete analysis of the results from the foam pilot. The foam pilot was successful in demonstrating the deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. Also overall, a 22% decrease in CO2 injection amount is realized due to better utilization of CO2 compared to the baseline.
Zeng, Y. (Department of Chemical and Biomolecular Engineering, Rice University) | Bahrim, R. Z. Kamarul (Petronas) | Bonnieu, S. Vincent (Shell Global Solutions International) | Groenenboom, J. (Shell Malaysia) | Shafian, S. R. Mohd (Petronas) | Manap, A. A. Abdul (Petronas) | Tewari, R. D. (Petronas) | Biswal, S. L. (Department of Chemical and Biomolecular Engineering, Rice University)
This paper investigates the effect of rock permeability on foam transport in porous media both at the core-level and at the field level for enhanced oil recovery (EOR) applications. Foam offers promise to simultaneously address the issues that limit the overall oil recovery efficiency of water-alternating-gas (WAG) process such as viscous fingering, gravity override, and reservoir heterogeneity. However, in the literature, limited foam data were reported using actual reservoir cores at harsh conditions. In this paper, a series of methane (CH4) foam flooding experiments were conducted in 3 different actual cores from a proprietary reservoir at elevated temperature. It is found that foam strength is significantly correlated with rock permeability. We calculated the apparent viscosity based on the measured pressure drop along the core samples at steady state. The calculated apparent viscosity was found to be selectively higher in cores of high permeabilities compared to that in cores of low permeabilities. We parameterized our foam system using a texture-implicit-local-equilibrium model to understand the dependence of foam parameters on rock permeability. In addition, we established a 2-layered heterogeneous model reservoir in the Shell in-house simulator called MoReS (Modular Reservoir Simulator) to systematically study and compare the driving forces for fluid diversion during foam flooding at the field level including the gravitational force, the viscous force, and the capillary force. During the WAG process, gravitational force kept the gas from sweeping the lower part of the reservoir. The gravity can be overcome by viscosifying the gas with surfactant solution. In addition, capillary pressure which hinders the gas from entering the low permeability region can actually redistribute the two phases during foam EOR and improves the sweep efficiency. It is concluded that foam can effectively improve the conformance of the WAG EOR in the presence of reservoir heterogeneity.
A correct understanding of foam generation, coalescence and transport at achievable reservoir flow rates has been a key issue for its applications in enhanced oil recovery processes. Use of foam models to simulate foam flow in the reservoir requires establishing of the parameters in the lab. This is generally done at relatively high flow rates in a so-called strong-foam state, which covers both high- and low-quality foam regimes that are used to fit foam modeling parameters. In the reservoir, because of the in situ velocities changing between near and far from the wellbore, there is a need for the foam model to be able to predict the foam behavior at two different foam states with high and low velocities, respectively. Depending upon the petrophysical properties of the reservoir, one may not generate and transport strong foam at the low-velocities away from the well.
Bubble population-balance models are considered a useful tool to understand foam flow through porous media by addressing the phenomenon from the first principle of physics. We investigated the capability of available population-balance models to simulate these two foam states over a wide range of velocities. Using an example case, the same set of data was fit to two well-known models at relatively high flow rates. Both models fit the steady-state data at high-flow rates reasonably well through proper tuning of the parameters. One foam model, reported by Afsharpoor and co-workers in 2010, predicted a weak-foam state with much lower apparent viscosity at low flow rates; however, the other model, reported by Chen and co-workers in 2010, predicted much higher pressure gradient at low flow rates with the same set of relative permeability and capillary pressure curves, due to the shear-thinning effect and the foam generation effect in the absence of a minimum pressure gradient (MPG). We observed significantly different foam rheology above the MPG: shear-thinning behavior when the foam texture reaches the maximum and Newtonian behavior when the foam texture is below the maximum. Below the MPG, a shear-thickening behavior, with an abrupt change at the boundary, was predicted by Afsharpoor model as was earlier observed in several experiments reported in the literature. The sensitivity of MPG to the corresponding critical velocity in Afsharpoor model is also studied in this work.
The data acquired in steady-state experiments have to be in the strong-foam state in order to estimate correct parameters in the model to simulate foam behavior in high- and low-quality regimes. However, if the experimental data acquired at low fluid velocities is available and indicates a weak-foam state at low velocities, one can use Afsharpoor model to predict this weak-foam state away from the well. Note that the findings are limited to steady-state foam flows in relatively homogeneous systems, while transient foam modeling and the impact of heterogeneity / pore-network distribution are yet to be investigated.
The use of alkaline polymer surfactant flooding techniques is becoming more common-place, particularly in projects where heavier and more viscous crude oil is produced. While the efficacy of increasing recovery factors cannot be disputed, often there is little consideration given to the implications of these enhanced oil recovery (EOR) chemicals breaking through into producer wells and entering the produced water handling system. The impact caused by EOR chemical breakthrough can be varied, but most commonly the efficacy of oil/water separation is seriously affected. The contribution that EOR chemicals can have on reservoir souring is often underestimated, as is the effect they can have upon standard production chemicals such as scale and corrosion inhibitors.
This paper draws upon the importance of different fluid ratios during EOR operations and the challenges that EOR chemical breakthrough has upon the produced water treatment strategy. A field case history specifically addressing the challenge of fluid separation at different fluid ratios and the impact on water in oil and oil in water emulsion stability.
Jong, Stephen (University of Texas at Austin) | Nguyen, Nhut M. (University of Texas at Austin) | Eberle, Calvin M. (University of Texas at Austin) | Nghiem, Long X. (Computer Modelling Group Ltd.) | Nguyen, Quoc P. (University of Texas at Austin)
Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model.
We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM.
The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control.
We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Foam enhanced oil recovery techniques involving super critical CO2 and surfactants are becoming popular these days due to the ability of foam to appreciably overcome problems like gravity override and viscous fingering commonly associated with gas injection. Foam lowers the mobility of the injected fluid consequently increasing the sweep efficiency. Since CO2 at super critical conditions is unable to generate strong foam several surfactants have been tested with sc-CO2 for foam stability at actual reservoir conditions. In this work, an amine oxide-based amphoteric fluorosurfactantwas injected with sc-CO2 for the first time in sandstone cores initially saturated with 0.15 vol% surfactant solution.
The concentration of the surfactant solution was kept above its critical micelle concentration (CMC) of 0.10 vol% which was determined through interfacial tension (IFT) measurements between sc-CO2 and surfactant solution at 1500 psi and 50°C. Co-injection of sc-CO2 and 0.15 vol% surfactant solution was performed at varying temperature conditions (35°C, 50°C and 80°C) and constant pressure of 1500 psi. In-situ foam quality was varied from 0.50 to 0.95 by varying the individual gas and surfactant injection flow rates to observe its effect on foam mobility. Each foam quality was maintained until steady state conditions prevailed. Strong foam or weak foam was characterized based on pressure response across the core.
The results of this study show that foaming ability of the surfactant with sc-CO2 increases from 35°C to 50°C. But as temperature is increased to 80°C its foaming ability decreases. In all cases, strongest foam is generated at highest foam quality of 0.90. Maximum steady state pressure drop for 0.90 foam quality was 16 psi at 35°C and 220 psi at 50°C whereas at 80°C it was 60 psi indicating foam became weaker at the same foam quality at high temperatures. Also, 0.90 was found to be the critical foam quality (fg*) in all cases above which if foam quality is increased foam seems to weaken indicated by decline in pressure drop across the core. Steady state pressure drop was stable for about 0.5 PV of injection at all foam qualities indicating high foam stability with this surfactant.
This study provides a new alternative for CO2-foam flooding highlighting the usefulness of the surfactant even at very low concentrations, thus mitigating the high cost of these types of surfactants. Furthermore, this surfactant is a greener substitute to conventional surfactants as it does not contain environmentally harmful substances.