Exploration and Production Technologies
Development of Nanoparticle-Stabilized Foams To Improve Performance of Water-less Hydraulic Fracturing Last Reviewed 6/15/2015


The overall objective of this project is to develop a new method of stabilizing foams for frac fluids by adding surface-treated nanoparticles to the liquid phase. The research will use  commercially available nanoparticles. The fracturing fluids will be those already employed in hydraulic fracturing: carbon dioxide [CO2], nitrogen [N2], water, and liquefied petroleum gas [LPG]).

The University of Texas at Austin, Austin, TX, 78712-0228

The vast majority of hydraulic fracturing jobs are formulated with fresh water. The rapid development of hydraulically fractured unconventional oil and gas reservoirs had made significant demands on water resources. A decisive advantage of foamed fluids is that they use substantially less water. Foamed fluids for hydraulic fracturing have been used for more than forty years. They have been used to improve flowback and cleanup after treatment, to improve stimulation performance by reducing leakoff rates, and to reduce fluid blocking of hydrocarbon production from the reservoir. Nanoparticles with suitable surface coatings have several advantages specific to the application of foamed-fracturing fluids: they can stabilize foams very effectively and for long periods; they are small enough to stabilize small bubbles which increase viscosities required for  carrying proppant; they are much smaller than fracture widths and pores in proppant packs, which allows them to be transported out of the reservoir during flowback; and their coating and concentration can be tuned to different fluid/fluid systems. Crucially, the mechanism by which nanoparticles stabilize foam differs from the mechanism for current technologies using surfactants and emulsifiers.  Nanoparticles enable a potentially significant advance: foams can be generated that will carry proppant into a fracture but will break at a tunable threshold pressure after the stage is pumped and will not re-form in the proppant pack during flowback. These advantages would simplify the design and reliability of foamed-fracturing jobs, thus reducing one of the obstacles to using less water for hydraulic fracturing

This project seeks to demonstrate that suitably coated nanoparticles can stabilize foams of fluids useful for hydraulic fracturing at elevated pressures and at temperatures ranging from ambient to reservoir. The water-based foams require four to five times less water per barrel of fluid than conventional water-based fracturing fluids. The LPG foam would require no water and three to five times less LPG than current water-less fluids. Thus, this research would have a significant impact on the development of unconventional oil and gas resources in areas where water use and/or disposal is constrained.

The results of this research will expand the options available to operators for hydraulic fracturing and can simplify the design and field implementation of foamed frac fluids. The technology will make it easier for operators to switch to reduced-water or zero-water hydraulic fracturing campaigns, thereby alleviating one of the most sensitive challenges for domestic hydrocarbon production.

Accomplishments (most recent listed first)

  • The fluid transport and fracture opening simulations confirmed that higher foam viscosity generated wider fractures with smaller fracture half-length. Fracture cleanup simulations have demonstrated the advantage of using dry foams. They show that fracturing fluid cleanup for foam-based fracturing fluids could take 10 days as opposed to that of a viscous fracpad which could take up to 1000 days.
  • The mechanisms involved in foam creation and stability have been experimentally investigated. Surfactant reduces the interfacial tension, and thus, facilitates bubble generation and decreases the capillary pressure to reduce the drainage rate of the lamellae. The lauramidopropyl betaine (LAPB) foam, which is cationic, also attracts anionic nanoparticles to the interface. The adsorbed nanoparticles at the interface are shown to form a barrier that slows down Ostwald ripening, with or without the addition of polymer, and increases foam stability.
  • The nanoparticle/surfactant/LAPB-stabilized foam quality has been improved up to 0.98 internal phase volume. (Note that the fracturing fluids reported in literature have CO2 fraction at most 0.75. ) For foams stabilized with mixture of LAPB and NPs, fine 70 µm bubbles and high viscosities on the order of 100 cP at >90% internal phase fraction were stabilized for hours to days. The viscosity of 90% foams is inversely proportional to the bubble size.
  • Nanoparticle/surfactant/polymer synergy was explored in order to increase the foam viscosity. CO2-in-Water (C/W) foams of 70 centipoise (cP) at 0.95 quality were stabilized by using 0.15 % hydrolyzed polyacrylamide (HPAM), 1% Nissan EOR-5XS nanoparticles and 0.08 % LAPB surfactants, which is comparable to typical viscosities of fracturing fluids reported in literature.
  • Phase behavior studies of mixtures of a series of different polymers, surface modified nanoparticles and surfactants have been further investigated to show that the formulations were stable in CO2 saturated 2% potassium chloride brine at pressures and temperatures relevant to field operation conditions (1000–5000 pounds per square inch, 50 degrees Celsius).
  • A simulator for nanoparticle-stabilized foam flowback after hydraulic fracturing has been developed in order to study the effect of depressurization on nanoparticle-stabilized foams. A preliminary comparison of fracture propagation with slick water, viscous fracpad, and 0.9-quality foam shows that foams leave a much cleaner proppant bed after fracturing, which can subsequently improve production from the formation.
  • Stable CO2-in-water foams were produced in a beadpack using mixtures of surface-modified, commercially available silica nanoparticles and three carboxybetaine surfactants. These foams have much higher viscosity than foams generated with the either the nanoparticles or surfactant alone. This synergy is a remarkable property and, to our knowledge, not previously demonstrated.
  • Building on this synergy between nanoparticles and a very low concentration of betaine surfactant, the project team was able to generate stable 90 percent quality CO2-in-water foams, with apparent viscosities as high as 50 cP, by adding 0.1 percent partially hydrolyzed polyacrylamide polymer. The polymer provides a second, distinct synergistic effect: foam cannot be generated until a threshold polymer concentration is reached.
  • Conceptual models have been developed to predict stability of bulk foams and foams in porous media under different operating and synthesis conditions with particular attention paid to the influence of pressure, which is the proposed mechanism for controlling foam destabilization for flowback after fracture stimulation.

Current Status (June 2015)
Foam generation experiments are being conducted to explain the basis for the nanoparticle, surfactant, and polymer synergy in foam stabilization. Of particular interest is keeping the CO2:water ratio high, while maintaining synergy, and determining the role of temperature and pressure in operating conditions. ). 

A detailed literature review on particle-surfactant interactions and their influence on foam and  emulsion stability under different conditions has provided some insight on how to tune the interactions to reservoir conditions. A more detailed study of like-charged particles and surfactants for foams, as well as a study of the interactions between surfactants and surface-modified particles (e.g., Nissan EOR-series and PEG-coated particles) is being conducted because this information does not appear to be available in the literature.

Numerical simulation software has been written for the propagation of CO2-water bulk foams stabilized by nanoparticles. Fracture geometry was obtained using commercial software. The project team is focusing on simulating fracture clean-up. A population balance model was coupled with a pressure, mass, and colloid filtration model to simulate foam flow inside a fracture. Preliminary simulations show that foam lowers water saturation compared to conventional fluids. The project team continues to test the software under multiple scenarios and improve models of foam formulations, with or without surfactant or polymer, provided by experimental work.

Two publications will be submitted; the experimental work is to be submitted in Langmuir, and the modeling work will be submitted to Energy and Fuels . An additional two papers are in preparation

Project Start: October 1, 2013
Project End: September 30, 2016

DOE Contribution: $1,089,660
Performer Contribution: $272,995

Contact Information:
NETL – Gary Covatch (gary.covatch@netl.doe.gov or 304-285-4589)
UT– Masa Prodanovic (masha@utexas.edu or 512-471-0839)

Additional Information:

Quarterly Project Performance Report [PDF-983KB] January - March, 2014

Quarterly Project Performance Report [PDF-784KB] October - March, 2013 

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