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.
Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k < 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.
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.
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.
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.
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 giant mature light oil field under miscible WAG injection is a potential candidate for foam application to control gas mobility and reduce field gas – oil ratio (GOR). We conducted a feasibility study which comprised live oil corefloods at reservoir conditions and compositional numerical simulation coupled with a foam formulation. The objectives of this study were to identify critical variables and potential detrimental factors for the process implementation; and evaluate the GOR decrease due to foam application.
This feasibility study comprises an evaluation of the effect of foam on a field scale through numerical simulation, and the study of foam creation under reservoir conditions through coreflood experiments. We used a compositional simulator with an empirical foam implementation to predict the effect of foam in a mechanistic sector model of a high production area of the field. Simulation results show that foam is able to reduce field GOR by reducing the mobility of injected gas in high permeability layers. It became clear that the incremental oil production is strongly dependent on gas production limits; thus, foam application has to be coupled with overall field optimization.
Due to challenging field conditions for foam application, we performed an extended laboratory study. Static mixing experiments allowed surfactant compatibility limits in mixtures of formation and injection brines to be defined. In addition, a series of corefloods showed that foam can be successfully generated with a commercial alpha-olefin-sulfonate surfactant under reservoir pressure and temperature in presence of live reservoir oil, rich hydrocarbon gas and injection brine.
To our knowledge this is the first published feasibility study of foam application in a mature miscible WAG project including compositional simulation and live oil corefloods with rich hydrocarbon gas injection under reservoir conditions.
Immiscible Water Alternating Gas (WAG) projects can be enhanced by using foaming surfactant in the water slugs with the objective to create viscous foam thereby improving the mobility ratio between gas and the liquid phases. The effective dynamic behavior of foam is complex and dependent on many parameters, such as water saturation, oil saturation, surfactant concentration, and capillary number. Besides the WAG design parameters, such as WAG slug size, and WAG ratio, one should also consider how to time and scale the amount of surfactant to be injected, in terms of concentration and slug size. Part of the dynamics of foam behavior has been calibrated in laboratory experiments showing the effective foam strength in foam scans and its dependency on foam quality (With foam quality defined as the gas volumetric flow rate compared to total gas and liquid volumetric flow rate). Nevertheless, small scale experiments have their limitations and uncertainties remain on field scale performance. Deep down in the formation, factors such as foam strength and stability, and adsorption of surfactant are considered uncertain. These factors call for pilots to de-risk the application further. Simulation studies show that foam strength has a major impact on both ultimate recovery as well as surfactant concentration in the produced streams – stronger foam resulting in lower surfactant concentrations.
The injection strategy also has an important impact on recovery. In some cases, recovery efficiency can be impaired if strong foam is created in the immediate wellbore environment, thereby hampering injection and pore-volume throughput. Sustained injectivity during FAWAG is hence an important component to derisk either in pilots, or lab and simulation studies. This paper demonstrates the impact of different injection strategies and offers some suggestions to mitigate the risk of reduced injectivity during FAWAG.
The goal of this work is to develop foams stabilized by a combination of nanoparticles and surfactants for high-temperature, high-salinity reservoirs. Two types of silica nanoparticles (LNP1, LNP2) with different grafted low molecular weight ligands/polymers were used. First, aqueous stability tests of these formulations were performed at high-temperature (80 °C) and high-salinity conditions (8 wt% NaCl and 2 wt% CaCl2). The screened nanoparticles were used in combination with a surfactant. Second, bulk foam tests were performed to evaluate their foaming performance in bulk. Finally, oil displacement experiments were conducted in an in-house, custom-built 2D sand pack with flow visualization. The sand pack had two layers of silica sand — top layer with 40-70 mesh and bottom layer with 100-120 mesh, which resulted in a permeability contrast of 6:1. Water flood with subsequent foam flood was performed. The grafting of low-molecular-weight polymers/ligands on silica nanoparticle surfaces resulted in steric stabilization under high-temperature and high-salinity conditions. In the oil displacement experiments in the layered sand packs, the water flood recoveries were low (~33% OOIP) due to channeling in the top high-permeability region, leaving the bottom low-permeability region completely unswept. Foam flooding with just the surfactant leads to a drastic improvement in sweep efficiency. It resulted in an incremental oil recovery as high as 43.3% OOIP. Different cross-flow behaviors were observed during foam flooding. Significant cross-flow of oil from low-permeability region to high-permeability region was observed for the case of surfactant. Conversely, the LNP2-surfactant blend resulted in no crossflow from the low permeability layer with complete blocking of the high-permeability region due to the formation of in-situ emulsion. Such selective plugging of high-perm channels via nanoparticles with optimum surface coating has significant potential in recovering oil from heterogeneous reservoirs.
Use of foams to control CO2 floods conformance is attracting a renewed interest in recent years due its flexibility and ease of application. This application becomes even more attractive in current times of low oil price, as it can be an inexpensive mean to maximize CO2 utilization efficiency and increase production at no capital expenses. However, it is generally recognized that to maximize chances of success of a pilot application, an appropriate foaming formulation must be designed for a given reservoir and characterized in petrophysics lab. This usually requires an extensive laboratory work that is not always compatible with cost constraints.
We present a new cost-effective workflow that focuses on evaluating two formulation performance indicators derived from the population balance model: foam creation (related to foaming power) and resistance to foam destruction (related to foam stabilization against coarsening and coalescence).
We assess these two parameters in representative reservoir conditions by measuring foam mobility reduction in porous media and foam lifetimes. Experimental results and simple scaling arguments show that these two measurements, both of importance to the application, are mostly independent. This shed light on a recurring question pertaining to the relevance of bulk foam experiments to predict foam efficiency in porous media. With this in mind, we present a new approach for measuring mobility reduction in porous media with a higher throughput than usual corefloods experiments. This methodology is based on sandpack experiments as well as serial coreflood experiments that allow multiple successive formulations testing. We show that the link between sandpack and coreflood results is far from being straightforward, and depends on static (geometrical) as well as dynamic (flow) parameters.
Overall, this work provides new insights on the major performance indicators used to evaluate foam efficiency for gas conformance control in oil reservoirs. We build on this understanding to present a novel approach that can help developing more efficient foam EOR solutions. In particular, it allows tailoring foaming agents properties (such as foaminess and foam stabilization) to specific conditions of a given application (oil saturation, vertical heterogeneity, etc…).