Da, Chang (The University of Texas at Austin) | Elhag, Armo (Khalifa University of Science and Technology) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Alzobaidi, Shehab (The University of Texas at Austin) | Zhang, Xuan (China University of Petroleum) | Al Sumaiti, Ali (Khalifa University of Science and Technology) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University) | Johnston, Keith (The University of Texas at Austin)
Stabilization of CO2 in water (C/W) foams with surfactants at high temperatures and high salinities is challenging, due to limited solubility of surfactants in aqueous phase, foamability and thermal stability. The apparent viscosities of C/W foams has been raised to up to 35 cP with viscoelastic aqueous phases formed with a diamine surfactant, C16-18N(CH3)C3N(CH3)2 (Duomeen TTM), or a zwitterionic surfactant, cetyl betaine, at 120 °C in 22% total-dissolved-solids (TDS) brine. Duomeen TTM is switchable from the nonionic (unprotonated amine) state, where it is soluble in CO2, to the cationic (protonated amine) state in an aqueous phase under pH ~6. Therefore, it may be injected in either the aqueous phase or the CO2 phase. The formation of viscoelastic phases with both surfactants lowers the minimum pressure gradient (MPG), and strengthens the lamella against drainage and Ostwald ripening by making the external aqueous phase more viscous, leading to stable foam even at very high foam quality. Both surfactants were shown to have excellent thermal stability and to form unstable emulsions when mixed with oil (dodecane). The core flood results showed that strong foam could be easily generated with both surfactants at a superficial velocity of 4 ft/day. The oil/water (O/W) partition coefficient of Duomeen TTM was very sensitive to pH, while that of cetyl betaine was constant over a wide range of pH. The ability to stabilize C/W foams at high temperature and salinity conditions with a single thermally stable surfactant is of great benefit to a wide range of applications including EOR, CO2 sequestration and hydraulic fracturing.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University)
The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-mD formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.
The low-IFT foam process was investigated through core flooding experiments in homogenous and fractured oil-wet cores with sub-10-mD matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer (AOS C14-16) were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the core flooding experiments.
Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-mD matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-mD matrix permeability achieved 64% incremental oil recovery compared to water flooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluids flow in it. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids, such as mineral dissolution and the exchange of Calcium and Magnesium, were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It therefore may cause injectivity and phase trapping issues especially in the homogenous limestone.
Results in this work demonstrated that despite the challenges associated with limestone dissolution, a low-IFT foam process can remarkably extend chemical EOR in fractured oil-wet tight reservoirs with matrix permeability as low as 5 mD.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total E&P) | Mateen, Khalid (Total E&P) | Ren, Guangwei (Total E&P) | Bourdarot, Gilles (Total E&P) | Morel, Danielle (Total E&P) | Bourrel, Maurice (Total E&P) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding.
A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10-2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.
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.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in many carbonate reservoirs is challenging due to unfavorable conditions such as oil-wet surface wettability, high reservoir heterogeneity and high brine salinity. We present the feasibility and injection strategy investigation of ultralow-interfacial-tension (ultralow-IFT) foam in a high temperature (above 80°C), ultra-high formation salinity (above 23% TDS) fractured carbonate reservoir.
Because a salinity gradient is generated between injection sea water (4.2% TDS) and formation brine (23% TDS), a frontal-dilution map was created to simulate frontal displacement processes and thereafter used to optimize surfactant formulations. IFT measurements and bulk foam tests were also conducted to study the salinity gradient effect to ultralow-IFT foam performance. Ultralow-IFT foam injection strategies were investigated through a series of core flood experiments in both homogenous and fractured core systems with initial two-phase saturation. The representative fractured system included a well-defined fracture by splitting core sample lengthwise and controllable initial oil/brine saturation in the matrix by closing the fracture with a rubber sheet at high confining pressure.
The surfactant formulation showed ultra-low IFT (10-2-10-3 mN/m magnitude) at the displacement front and good foamability at under-optimum conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved over 60% incremental oil recovery compared to water flooding in oil-wet fractured systems due to the selective diversion of ultralow-IFT foam. This effect resulted in crossflow near foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowed back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to make it challenging for foam propagation in the fractured system by forming Winsor II condition near foam front and hence killing the existing foam.
Results in this work demonstrated the feasibility of ultralow-IFT foam in high temperature, ultra-high salinity fractured carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped mobilize the residual oil for better displacement efficiency. The selective diversion of foam makes it a good candidate as a mobility control agent in fractured system for better sweep efficiency.
Abbaszadeh, Maghsood (Innovative Petrotech Solutions) | Varavei, Abdoljalil (Innovative Petrotech Solutions) | Rodriguez-de la Garza, Fernando (Pemex E&P) | Villavicencio, Antonio Enrique (Pemex E&P) | Lopez Salinas, Jose (Rice University) | Puerto, Maura C. (Rice University) | Hirasaki, George (Rice University) | Miller, Clarence A. (Rice University)
An integrated methodology is presented for the development of a comprehensive empirical foam model based on tailored laboratory tests and representative numerical simulations that encompass processes of foam generation, coalescence, and shear thinning along with rheological characteristics and associated flow regimes. Steady-state and unsteady-state laboratory experiments of foam floods in a vertical column of sandpack with and without oil at different surfactant concentrations and at varied gas/surfactant-solution injection rates are designed, conducted, and analyzed. The logic and basis of these experiments are provided. Test results from experiments in the presence of oil provide information on the oil-induced foam/lamella coalescence functions. Unsteady-state experiments capture foam-generation and foam-dry-out phenomena, whereas steady-state experiments capture the effects of foam quality, foam velocity, and surfactant concentration. Process-based numerical simulations of these experiments are combined with basic governing analytical relationships of foam flow to provide a methodology for a comprehensive empirical foam model and to uniquely define the model parameters to preserve consistency with simulations of foam-flow processes. A procedure is presented to fully model the effect of surfactant concentration on foam strength and to quantify all concentration-function parameters, and, in particular, epsurf.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Bourrel, Maurice (Total) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in highly heterogeneous carbonate reservoirs is typically inefficient because of the high permeable fracture networks and unfavorable capillary force resulting from oil-wet matrix. Foam as a mobility control agent has been proposed to mitigate reservoir heterogeneity by diverting injected fluids from the highly permeable fractured zones into the low permeable unswept rock matrix, hence improving the sweep efficiency. This paper presents the use of a low-interfacial-tension foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. The novel formulation providesboth mobility control and oil-water interfacial tension (IFT) reduction to overcome the unfavorable capillary forces preventingdisplacing fluids from entering oil-filled matrix. Thus, as expected, the combination of these two effects significantly improves oil recovery compared to either foam or surfactant flooding.
In this research, the three-component surfactant formulation was tailored by phase behavior tests in seawater with crude oil from a targeted reservoir. The optimized formulation can simultaneously generate 10−2 mN/m IFT and strong foam in porous media with oil present, as demonstrated by IFT measurements and foam floodingtests. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting core lengthwise and precisely controlled of aperture by applying specific confining pressure. The foam flooding experiments reveal that the low-IFT foaming formulation in an oil-wet fractured Edward Brown dolomite recovers about 72% of oil while water flooding only recovers less than 2%,and it is more efficient than foam flooding lacking low oil-water IFT property.The core flood test results also indicate that low-IFT foam diverts mostly surfactant solution into matrix because of (1) the mobility reduction due to foam in the fracture network, (2) significantly lower capillary entry pressure for surfactant solution compared to gas and (3) the increase of mobility to water in the matrix by the low oil-water IFT displacing residual oil in the matrix. This selective diversion effect of the novel foaming system allows to carry out the surfactant flooding at low IFT condition in the low permeability matrix to recover the trapped oil, which is otherwise impossible with simple surfactant or high-IFT foam flooding in highly heterogeneous or fractured reservoirs.
Cui, Leyu (Rice University) | Ma, Kun (Rice University) | Puerto, Maura (Rice University) | Abdala, Ahmed A. (Petroleum Institute at Abu Dhabi) | Tanakov, Ivan (Rice University) | Lu, Lucas J. (Rice University and Petroleum Institute at Abu Dhabi) | Chen, Yunshen (University of Texas at Austin) | Elhag, Amro (University of Texas at Austin) | Johnston, Keith P. (University of Texas at Austin) | Biswal, Sibani L. (Rice University) | Hirasaki, George (Rice University)
The low viscosity and density of carbon dioxide (CO2) usually result in the poor sweep efficiency in CO2-flooding processes, especially in heterogeneous formations. Foam is a promising method to control the mobility and thus reduce the CO2 bypass because of the gravity override and heterogeneity of formations. A switchable surfactant, Ethomeen C12, has been reported as an effective CO2-foaming agent in a sandpack with low adsorption on pure-carbonate minerals. Here, the low mobility of Ethomeen C12/CO2 foam at high temperature (120°C), high pressure (3,400 psi), and high salinity [22 wt% of total dissolved solids (TDS)] was demonstrated in Silurian dolomite cores and in a wide range of foam qualities. The influence of various parameters, including aqueous solubility, thermal and chemical stability, flow rate, foam quality, salinity, temperature, and minimum-pressure gradient (MPG), on CO2 foam was discussed. A local-equilibrium foam model, the dry-out foam model, was used to fit the experimental data for reservoir simulation.
Fernø, Martin A. (University of Bergen) | Gauteplass, Jarand (University of Bergen) | Pancharoen, Monrawee (Stanford University) | Haugen, Åsmund (University of Bergen) | Graue, Arne (University of Bergen) | Kovscek, Anthony R. (Stanford University) | Hirasaki, George (Rice University)
Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.
Abbaszadeh, Maghsood (Innovative Petrotech Solutions) | Kazemi Nia Korrani, Aboulghasem (Innovative Petrotech Solutions) | Lopez-Salinas, Jose Luis (Rice University) | Rodriguez-de La Garza, Fernando (Pemex E&P) | Villavicencio Pino, Antonio (PEMEX E&P) | Hirasaki, George (Rice University)
Practical application of foams for chemical and solvent EOR processes requires a representative and predictive model for foam flow and its mobility control characteristics. Many parameters such as surfactant concentration, shear rate, capillary number, oil saturation, and salinity affect foam flow behavior. Accordingly, different mechanistic and empirical foam models have been investigated in the literature and implemented in commercial simulators. Usually parameters in these models are tuned to match lab data for a particular foam-surfactant and oil system characteristics.
This paper presents process-based numerical simulations for modeling of foam-surfactant flow in a vertical sandpack column based on two sets of laboratory experimental data. The experimental setup, procedure, measurements and data analysis are discussed to provide apparent foam viscosity data for modeling. In the first lab tests, foam quality is constant and the total fluid velocity changes for shear thinning effect; while in the second tests, foam quality is varied at a fixed total velocity. The parametric matching of lab data is based on both fine-scale numerical simulations of the sandpack experiments as well as theoretical considerations of governing flow physics. The foam model is tuned to variable velocity foam flow of the first data set and then used to predict the second data set as consistency check. Based on this experimentally-tuned model, a validated foam model is constructed for use in field-scale commercial simulations of surfactant-foam flow in pilot testing of a naturally fractured reservoir. The model predictions for the second data set as well as the associated sensitivity analysis prove that our modeling approach is applicable for large scale predictions.
The results of this paper illustrate a novel experimental procedure, a creative data analysis scheme and a comprehensive methodology for developing a process-based mechanistic foam model. The presented methodology for matching lab data is unique as it includes varying both foam quality and foam velocity for shear thinning and foam dry-out phenomena. As such, this model is shown to include basics physics of foam flow in porous media for large-scale field applications.