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The effects of in-situ emulsion formation and superficial velocity on foam performance in high-permeability porous media
Foam has been considered as a mobility control agent for Enhanced Oil Recovery (EOR) applications in heterogeneous and fractured reservoirs. Foam enhances sweep efficiency by enabling the injected gas to flow from high-permeability to low-permeability regions. The foam injection velocity is an essential factor affecting foam mobility control and flow behavior. Furthermore, the presence of remaining oil adversely impacts foam generation leading to a failure in governing mobility control. In this study, foam performance in establishing mobility control effect and favorable apparent viscosity was experimentally investigated under a range of total superficial velocities in the presence and absence of crude oil during foam propagation in high permeability sand packs representing a propped fracture network. In the absence of oil, a pronounced effect of total superficial velocity on the mobility control performance was observed at the transition foam quality regime. Co-injection of oil and foam led to noticeable foam destabilization, as expected. However, a further increase in oil fractional flow resulted in larger overall flow resistance. We found that the formation of in-situ surfactant/oil emulsion contributed to the high apparent viscosity exhibited at the steady-state condition. These findings suggest that the steady-state flow resistance established during foam flooding at high oil saturations should be interpreted as the mobility control effect resulting from emulsion formation rather than the development of strong foam.
Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Final Report)
Southwest Research Institute® (SwRI ® ), Schlumberger Technology Corporation (SLB), and Chevron Corporation ® (Chevron) developed a novel, optimized, and lightweight process for natural gas (NG) to replace water as a low-cost fracturing medium with a low environmental impact. Hydraulic fracturing is used to increase oil and NG production by injecting high-pressure fluid, primarily water, into a rock formation, which fractures the rock and releases trapped oil and NG. This method was developed to increase yield and make feasible production areas that would not otherwise be viable for large-scale oil and NG extraction using traditional drilling technologies. Since the fracturing fluid is composed of approximately 90% water, one of the principal drawbacks to hydraulic fracturing is its excessive water use and associated large environmental footprint. According to recent data collected at fracture sites within the United States, fracturing applications in North America can consume as much as 9 million gallons of water per well. During the fracturing process, some of the fracturing fluid is permanently lost and the portion that is recovered is contaminated by both fracturing chemicals and dissolved solids from the formation. The recovered water or flow-back represents a significant environmental challenge, as it must be treated before it can be reintroduced into the natural water system. Although there is some recycling for future fracturing, the majority of the flow-back water is hauled from the well site to a treatment facility or to an injection well for permanent underground disposal. To mitigate these issues, an optimized, lightweight and modular surface process using NG to replace a majority of the water was developed as a cost-effective and environmentally clean fracturing fluid. Using NG will result in significantly less consumption since the gas that is injected as a fracturing fluid will be mixed with the formation gas and extracted as if it were from the formation itself. This process will minimize the collection, waste, and treatment of large amounts of water and will reduce the environmental impact of transporting and storing the fracturing fluid. There are two major steps involved in utilizing NG as the primary fracturing medium: (1) increasing the supply pressure of NG to wellhead pressures suitable for fracturing and (2) mixing the required chemicals and proppant needed for the fracturing process at these elevated pressures. The second step (NG-proppant mixing at elevated pressures) still requires demonstration; but very similar processes have been demonstrated in the field with other gases such as nitrogen (N 2 ) and carbon dioxide (CO 2 ). However, the first step (a compact, on-site unit for generating high-pressure NG at costs feasible for fracturing) has not been developed and is currently not commercially available. Due to the inherent compressibility of NG, more energy is required to compress the gas than what is required to pump water (or other incompressible liquids) to the very high pressure required for downhole injection. This project aimed to develop a novel, hybrid method to overcome this challenge. The project accomplishments and findings are discussed in this report. Ultimately, the research and development efforts described herein demonstrate that fracturing with NG foam is a feasible alternative to using water.
PROPPANT-BEARING NATURAL GAS FOAM FOR WATER REDUCTION IN HYDRAULIC FRACTURING OPERATIONS
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Review on Foam-Assisted Gas Injection in Fractured Carbonates for Enhanced Oil Recovery
Not provided.
Rheology and stability of nanoparticle-stabilized CO 2 foam under reservoir conditions
This work investigates the rheology and stability of nanoparticle-stabilized CO 2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Γ), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO 2 foam apparent viscosity featured a mountain-shaped curve versus Γ, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO 2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO 2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.
A Pilot-Scale Evaluation of Natural Gas-Based Foam at Elevated Pressure and Temperature Conditions
Abstract Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The Pilot-scale Foam Test Facility (PFTF) used in these investigations is first described. The PFTF is capable of generating foamed fluids at pressures up to 7,500 psig and at temperatures in excess of 300°F. Then, results from several investigations aimed at proving NG foam at conditions relevant to the field are presented. NG foam was characterized using rheology measurements and flow visualization techniques. Experiments were performed to investigate the texture and stability of NG foam generated by two different mixing methods: one using a custom designed tee to match mixing velocities in the field where the gas phase is jetted into the aqueous stream, and another to ensure comprehensive mixing for laboratory analysis. Parametric studies were conducted to explore the effects of flow rate, foam quality, and temperature on the stability of NG foam. Moreover, different fluid preparations were used to investigate the effect of base fluid and additive concentrations on the stability of NG foams. Additional laboratory studies that investigated foam stability with produced water and multicomponent NG mixtures are also reported. The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.
Fracture Toughness Evaluation of Space Shuttle External Tank Thermal Protection System Polyurethane Foam Insulation Materials
Experimental evaluation of the basic fracture properties of Thermal Protection System (TPS) polyurethane foam insulation materials was conducted to validate the methodology used in estimating critical defect sizes in TPS applications on the Space Shuttle External Fuel Tank. The polyurethane foam found on the External Tank (ET) is manufactured by mixing liquid constituents and allowing them to react and expand upwards - a process which creates component cells that are generally elongated in the foam rise direction and gives rise to mechanical anisotropy. Similarly, the application of successive foam layers to the ET produces cohesive foam interfaces (knitlines) which may lead to local variations in mechanical properties. This study reports the fracture toughness of BX-265, NCFI 24-124, and PDL-1034 closed-cell polyurethane foam as a function of ambient and cryogenic temperatures and knitline/cellular orientation at ambient pressure.
Modification of Fractured Rock Permeability Field Using Polymer Foam to Improve Geothermal System Efficiency
The project aims at developing novel methods for blocking high-permeability pathways in geothermal reservoirs to improve heat exchange efficiency. While the project was at DRI, and now when it has been transferred to UNR, the goal of blocking high-permeability pathways is achieved through targeted injection of heat-sensitive polymer foams, particularly foamed epoxy resins, whose activation and curing are triggered by the ambient thermal field.
Synergistic foam stabilization and transport improvement in simulated fractures with polyelectrolyte complex nanoparticles: Microscale observation using laser etched glass micromodels
Inaccessibility to direct pore scale observation in hydrocarbon recovery of tight shale formations poses a great challenge to water-energy nexus initiatives and necessitates the use of high throughput technologies to emulate environmentally friendly processes. Herein, we employ a precise glass micromodel fabrication and visualization method to isolate the supercritical CO 2 bubbles surrounded by CO 2 -water lamella prepared in saline produced water stabilized with molecular complexation of zwitterionic surfactants (ZS) and polyelectrolyte complex nanoparticles (PECNP). The Selective Laser Enhanced Etching (SLE) technique was selected for micromodel simulation of high-pressure flow. Two representative designs, (1) fracture/micro-crack network 28 and (2) fracture/matrix were etched on fused silica glass with a laser printing machine and scCO 2 foam was injected to study the foamability, propagation, stability, and fluid loss properties. The highly monodispersed and uniformly distributed array of scCO 2 bubbles were detected in flow of scCO 2 foam in highly saline brine containing ionic complexes of positively charged PECNPs and ZS, whereas foam flow with the lamella containing ZS in fractures offered a noticeably large and polydisperse array of scCO 2 bubbles. scCO 2 bubble motion and deformation were traced, and local description of foam flow was visually examined. The confined array of scCO 2 bubbles stabilized by ZS in microcracks was affected by bubble growth and coalescence, whereas the super-populated array of monodispersed scC O2 bubbles with lamella containing complexes of PECNP and ZS were able to fill the channels with stable configurations within the timeframe of comparative stability measurements. The ability of complex fluid to prevent the formation damage was evaluated through fluid loss visualization in micromodels. Probing scCO 2 foam transport in homogenous porous media revealed smaller volume leak-off for scCO 2 foam containing PECNP-ZS ionic complexes.
Intense cyclic heating effects on thermo-fracture and thermal shock of solid tungsten and open-cell tungsten foam
Here we investigate here the effects of transient (cyclic) arc-jet plasma and laser heating on fracture behavior of W-foam and solid tungsten. The two key parameters that control the foam thermomechanical response are its density and mean cell size expressed in Pores Per Inch (PPI). Tungsten foam samples were fabricated with Chemical Vapor Deposition (CVD) with variety of PPI and relative density. These were tested under two types of qualitatively different conditions: (1) high-enthalpy arc-jet, and (2) high-power cyclic laser heating. None of the foam samples showed macroscopic through-thickness cracks. However, distributed micro-cracks were observed on ligaments and their triple junctions. Under the same loading conditions, W-foam and solid tungsten showed similar crack network pattern and characteristic length-scale. However, Crack Opening Displacement (COD) was twice as large in solid W as compared to W-foam. Foam samples that have been previously exposed to a low-pressure helium plasma showed significant changes in their surface forming nano-texture fuzz which was removed by subsequent testing in the arc-jet. Extensive fracture and re-crystallization were observed in the thin solid W disk that was fully-constrained from expansion. Thicker and fully-constrained solid W disks did not display recrystallization, grain growth, and extensive cracking. However, thicker disks that were free to expand showed some recrystallization and extensive through-thickness cracks due to less effective cooling and thus higher temperatures. Laser beam testing showed no visible damage formation at 0.19 GW/m 2 and 0.38 GW/m 2 for both low-density (23%) and high-density (43%) foams at low pulses (100-1000). Micro-cracks were observed after 10,000 pulses at 0.19 GW/m 2 in both foams, and in low-density foam after 100,000 at 0.38 GW/m 2 . The nature of thermomechanical damage in W-foam exposed to extreme power (GW/m 2 ) short-duration laser pulses was found to be qualitatively similar to that of high power (MW/m 2 ) long-duration arc-jet.
High Temperature, High Pressure Stability of Aqueous Foams for Potential Application in Enhanced Geothermal System (EGS)
Enhanced Geothermal Systems (EGS) are typically constructed by injecting high-pressure water into deep hot dry rocks (HDR) under carefully controlled conditions to create new or re-open existing fractures, which usually uses an immense quantity of water. In lieu, a more sustainable technique is to utilize aqueous foams as fracturing fluid to reduce water consumption and waste-water treatments of conventional hydraulic fracturing. Although foam-based fracturing has shown promising results in oil and gas industries, its feasibility is not demonstrated in EGS conditions that usually involve high temperature and high pressures. One potential barrier of utilizing foams in EGS applications is that foams are thermodynamically unstable and will become more unstable with increasing temperature due to liquid drainage, bubble coarsening, and coalescence. This work focuses on evaluation of the stability of selected aqueous foams under high-temperature and high-pressure conditions. Specifically, foams generated with surfactant alfa olefin sulfonate (AOS) were studied at temperature up to 200oC, while the pressure ranged between 100 psi and 1000 psi. The effect of additional stabilizing agents was also examined, including guar gum, bentonite clay, borate salt crosslinker, silicon dioxide nanoparticles (SiO2), and graphene oxide (GO) dispersion. Results showed that the stabilizing agents can enhance the foam thermal stability. Foams made with AOS and the borate salt crosslinker exhibited the longest half-life of 20 min at 200°C when the pressure was at 1000 psi. Data fitting showed that foam stability decreased exponentially as temperature increased. On the other hand, pressure increased the foam half-life which followed a power model. This study indicates that it may be possible to obtain highly stable foams at high-temperature and high-pressure conditions with appropriate stabilizing agents.
High Temperature Stability of Aqueous Foams for Potential Application in Enhanced Geothermal System (EGS)
Enhanced Geothermal Systems (EGS) are typically constructed by injecting high-pressure water into the deep hot dry rocks (HDR) under carefully controlled conditions to create new or re-open existing fractures, which usually utilizes an immense quantity of water. Alternatively, aqueous foam-based fracturing fluids may offer potential advantages over conventional water-based fracturing fluid, including reduced consumption of water and environmental impact. Although foam-based fracturing has shown promising results in oil and gas industries, its applicability to EGS is unknown. Foams are complex mixtures of liquids with gaseous phases that are thermodynamically unstable. Their stability will decrease over time due to liquid drainage, bubble coarsening, and coalescence. Therefore, it is essential to stabilize foam fluids at high temperatures for EGS related applications such as fracking of HDRs.This paper is focused on investigating high-temperature stability of N2-in-water or N2 foams containing different surfactants and stabilizing agents. Foam stability was characterized by the half-life, which is defined as the time a foam decreases to 50% of its original height due to drainage. Surfactants with various concentrations dissolved in deionized water were investigated, including alfa olefin sulfonate (AOS), sodium dodecyl sulfonate (SDS), TergitolTM (NP – 40), and cetyltrimethylammonium chloride (CTAC). Also, the effects of other stabilizing agents, including guar gum, bentonite clay, crosslinker, graphene oxide (GO) dispersion on foam stability were tested. Initial results showed that foam stability decreased dramatically as temperature increased. On the other hand, foams became relatively more stable as pressure increased. Certain stabilizing agents, such as guar gum and crosslinker, can enhance foam stability at a wide range of temperatures. Our results indicate that it may be possible to obtain stable foams at high-temperature, high-pressure conditions with appropriate stabilizing agents.
Structural Continuum Modeling of Space Shuttle External Tank Foam Insulation
The Space Shuttle External Tank is covered with rigid polymeric closed-cell foam insulation to prevent ice formation, protect the metallic tank from aerodynamic heating, and control the breakup of the tank during re-entry. The cryogenic state of the tank, as well as the ascent into a vacuum environment, places this foam under significant stress. Because the loss of the foam during ascent poses a critical risk to the shuttle orbiter, there is much interest in understanding the stress state in the foam insulation and how it may contribute to fracture and debris loss. Several foam applications on the external tank have been analyzed using finite element methods. This presentation describes the approach used to model the foam material behavior and compares analytical results to experiments.
Stability study of aqueous foams under high-temperature and high-pressure conditions relevant to Enhanced Geothermal Systems (EGS)
In Enhanced Geothermal System (EGS) hydraulic fracturing is carried out by injecting cold water into deep Hot Dry Rocks (HDR) under carefully controlled conditions to create new or reopen existing fractures. Water-based fracturing fluids demonstrate some challenges including immense quantity of water usage, water sensitivity of the formations, water blocking, and lack of proppant carrying capacity and transportation. Thus, an alternative is to use foam-based fracturing fluid which offers potential advantage over conventional water-based fracturing fluid such as minimum water usage, reduced wellbore damage, high proppant carrying capacity, and less environmental damage. However, foams are complex mixture of gaseous phase and liquid phase which are thermodynamically unstable at downhole conditions, and their stability can decrease over time due to liquid drainage, bubble coarsening, and coalescence. This paper shows laboratory experiments executed to study foam stability at high temperature (200°C) and high pressure (6.9MPa) conditions which simulates the geothermal environment. Foam stability was characterized by half-life of foam, which is defined as the time taken by the foam to decreases by 50% of its original height due to drainage. In this paper, two types of gaseous phases, nitrogen (N 2 ) and carbon dioxide (CO 2 ) were investigated. Also, based on successful practice of foam-based fracturing fluid in oil and gas industries, four surfactants, including Alpha olefin sulfonate (AOS), Sodium dodecyl sulfonate (SDS), Tergitol™ (NP – 40), and Cetyltrimethylammonium chloride (CTAC) at optimum concentration of 1wt.% were tested for best stability performance. In addition, different stabilizing agents including guar gum, bentonite clay, crosslinker, silicon dioxide nanoparticles (SiO 2 ), graphene oxide (GO) were also studied. Experimental results showed that N 2 foams were more stable than CO 2 foams. It was observed that foam half-life decreased with the increase in temperature. Among all the surfactants, AOS foams showed the most promising thermal stability at high temperatures. Moreover, with the addition of stabilizing agents, foam's half-life was enhanced. Stabilizing agents such as crosslinker and GO dispersion showed the most stable foams with half-life recorded at 20min and 17min, respectively, at 200°C and 6.9MPa. Finally, pressure also showed a positive effect on foam stability; with increased pressure, foam half-life was increased. Based on the experimental data, analytical models for the effect of temperature and pressure were developed, considering foam degradation is a first-order kinetic reaction that linearly depends on the foam drainage mechanism. The effect of temperature on foam half-life was studied as an exponential decay model. In this model, foam half-life is a function of drainage rate constant (D A ) and activation energy (E a ) of the foam system. The effect of pressure on foam half-life was found to obey a power-law model where an increase in pressure showed an increase in foam half-life. Furthermore, a linear relation was studied for the effect of pressure on foam activation energy and drainage rate. Then the combined effects of temperature and pressure were studied, which yielded an analytical model to predict the foam stabilities in terms of half-life for different foam compositions. In conclusion, this research indicates that with an appropriate selection of surfactants and stabilizing agents, it is possible to obtain stable foams, which could replace conventional water fracturing fluid under EGS conditions.
Fracture‐Resistant and Thermally Insulating Ultrahigh‐Temperature Carbide Foams
Dense ultrahigh‐temperature ceramics (UHTCs) carbides are recognized as potential materials for thermal protection systems (TPS) owing to properties beyond existing structural materials’ capabilities. Recent advances in UHTCs have enabled the development of multiscale porous microstructures. Herein, it is highlighted that the porosity in UHTCs are no longer treated as a defect but as a functional property specifically tailored for thermal insulation. It is a promising solution to design and fabricate bulk UHTC foams via a freeze‐drying (FD) approach followed by calibrated pressureless spark plasma sintering. Herein, monolithic TaC and HfC UHTC foams and their composite show the partial solid–solution formation of (Ta, Hf)C with porosity ≥50%. TaC–HfC foam (≈80–92 N) shows an intermediate load‐bearing capability compared to monolithic TaC (≈120–135 N) and HfC (≈28–35 N) foams, with no evident cracking on the sample surface. The thermal conductivity of partial solid‐solution TaC–HfC foam increases up to fivefold compared to parent UHTC foams. In the results, solid solutions’ efficacy and pores’ unidirectionality in providing thermal insulation to TaC–HfC while maintaining its high‐load bearing capability are illustrated. In conclusion, the developed technique establishes a new paradigm shift in UHTCs, expanding their potential for TPS in extreme environments.
Experimental Evaluation of Foam-Assisted Gas Injection in Proppant-Packed Fractured Oil-Wet Carbonate
Not provided.