**5. Foam fracturing fluid performance: laboratory studies**

### **5.1 Foaming agent and water recovery**

 Prior to the implementation, it is important to investigate the performance of fracturing fluid at reservoir conditions. The measurement of fundamental properties of the used foaming agent such as interfacial tension and contact angle that are the basis for reducing capillary pressure are also essential to perform [89, 90]. Additionally, the adsorption of surfactant as a foaming agent is equally important to study in order to estimate the chemical loss in the reservoir during the recovery process. The recovery of injected fluid as well as chemical performance can be experimentally evaluated based on core flow tests. Furthermore, it has been reported that several field pilot tests were conducted to check the performance of surfactant for fracturing applications. Most of the pilot tests were conducted in the Barnett and Marcellus shales utilizing conventional surfactants which include nonionic alcohol ethoxylate surfactants and amphoteric and cationic surfactants [89]. The water recovery using conventional surfactants has been reported to achieve approximately 60% (an average of 3 wells) [89]. Barnett shale is considered notorious for retaining water. Another case study was conducted considering a conventional surfactant and only 2300 bbl of water was recovered out of injected 6430 bbl giving about 28% recovery [89]. A nanofluid has also been employed in fracturing job to reduce the chemical adsorption whereby the recovery of injected water reached about 40% in this case [91, 92]. Both laboratory and field studies revealed that the addition of surfactants to the fracturing fluid system helps in increasing the recovery of additional water. Besides, an increase in overall gas production was also observed.

*CO2 Foam as an Improved Fracturing Fluid System for Unconventional Reservoir DOI: http://dx.doi.org/10.5772/intechopen.84564* 

## **5.2 Foam screening and optimization**

 The proper selection of foaming agent for generating foam fracturing fluid is required to optimize the process under desired conditions. Lin et al. investigated different surfactants at high temperature and the results were compared with those of a conventional foaming agent used previously as fracturing fluid [93]. They performed surface tension, foam stability, and foam viscosity experiment in order to evaluate the surfactant performance for foam generation. It was ascertained that the results from foam stability experiment could give the indication of surfactant performance for foam generation but the foam behavior under fracturing conditions could not necessarily be deduced. The utilization of flow loop foam rheometer has enabled the study on foam viscosity under reservoir operating temperature and pressure conditions. Based on extensive laboratory studies which mainly include foam rheology, a superior performance foam formulation was obtained which was able to provide a stable foam with both CO2 and N2 in a high temperature environment especially where other conventional foamers failed to generate the stable foam. The selected foamer was also found to be having good compatibility with other chemicals in fracturing fluid systems and it has also provided low emulsification as compared to other foamers. When the selected foam formulation through this detailed screening and optimization procedure under reservoir conditions was employed in various fracturing treatments in fields, successful results were achieved.

## **5.3 The role of chemical additives**

Many attempts have been carried out to find the formulation of foam fracturing fluid that can meet the requirement of targeted reservoirs and provide an optimum performance. The synthetic polymer with high concentration has been reported to meet the need of higher viscosity of fracturing fluid. However, the increase in polymer loading would give more severe formation damage due to the formation of fluid residue.

 Some viscoelastic surfactants (VES) have been proposed to generate highly stable and viscous foam fracturing fluid with minimum water contents at high temperature conditions. The increase in surfactant concentration may form worm-like micelles which impart viscoelastic property to the foam lamella, hence generating high strength foam which is a relatively clear approach as compared to that of polymer solutions. The addition of nanoparticles (zinc oxide (ZnO) and magnesium oxide (MgO)) has also been found to improve the temperature tolerance of this type of surfactant from 93 to 121°C [94].

The evaluation of different types of polymer as additives for achieving stable and viscous foam has also been performed by Ahmed et al. [38]. They utilized both conventional HPAM polymers and new associative polymers (possessing higher level of hydrophobes) for bulk foam stability tests using FoamScan as well as foam viscosity measurement using HPHT foam rheometer. It was concluded that the use of conventional polymers was not preferable under harsh reservoir conditions as they are more prone to degradation instead of stabilizing the foam. Meanwhile, associative polymer provided dramatic increase in the viscosity and stability of CO2 foam without undergoing degradation under testing conditions.

 More complex system of CO2 foam has been presented by Xue et al. in which the foam was stabilized with betaine surfactant and silica nanoparticles in the absence and presence of synthetic polymer [95]. The texture of foam was observed from the view cell connected to foam generator having glass bead pack with a permeability of 23 Darcy and the viscosity of foam was measured using a capillary viscometer. It has been reported that an extremely dry (90–98% foam quality) supercritical CO2-inwater-foam prepared in brine presented a high viscosity and stability at 50°C. The data on such high quality foams are very limited [95, 96] and the proposed combination (i.e. surfactant/nanoparticle/polymer) has indicated the possibility of having the strong foam with minimum water content which is desirable for fracturing application. Lauryl amidopropyl betaine, the used surfactant, was able to lower the CO2/water interfacial tension to 5 mN/m. This surfactant attracted anionic NPs (and anionic HPAM in the systems containing polymer) to the CO2/water interface. Nanoparticle presence in the CO2 foam system has remarkably slowed down the Ostwald ripening phenomena, whereas, the polymer slowed down the liquid drainage by increasing the viscosity of continuous phase and surface viscosity [95].

## **5.4 Consideration of different process variables**

 The rheological properties of foam as fracturing fluid have been evaluated by Wilk et al. using flow loop rheometer with a purpose of reducing the amount of water during fracturing operation [97]. They reported that the concentration of foaming agent and polymer prominently impact the foam rheological parameters. The evaluation in rheometer was performed on the basis of two different foam qualities, i.e., 70 and 50%. Their results showed that the 70% quality foam was able to provide stronger foam due to favorable changes in the foam structure and distribution. The foam texture study also revealed that the bubble sized distribution was altered due the presence of different additives and in this case, polymer additive was able to further reduce the bubble diameter which resulted in high viscosity foam.

 Ahmed et al. has investigated polymer free foam performance with different process variables such as surfactant concentration, salinity, temperature, pressure, and shear rate utilizing a high pressure high temperature flow loop system [39, 84]. The rheology of CO2 foam was presented under a wide range of different parameters such as temperature (40–120°C), pressure (1000–2500 psi), salinity (0.5–8 wt%), surfactant concentration (0.25–1 wt%), and shear rate (10–500 s<sup>−</sup><sup>1</sup> ). They presented that 80% foam quality which was found to provide the best performance, expected to be favorable for fracturing job at targeted conditions. These experimental studies found that the foam apparent viscosity under supercritical conditions considerably increases with the increase in surfactant concentration up to 5000 ppm, whereas a continuous increasing trend in foam viscosity appeared as the salinity in the foaming solution was increased. Besides that, the increase in temperature resulted in thermal thinning of foam lamella whereby dropping the foam viscosity. Also, the increment in pressure provided stability to the foam lamella which resulted in high viscosity foam. It was reported that all the foams behaved as shear thinning fluid within the tested shear rate range and power law was fitted on foam viscosity data. The flow behavior indices were found to be the strong function of aforementioned process variables and using viscometric data, the new empirical correlations have been developed, which gives accurate prediction of the apparent viscosity of CO2 foam as a function of process variables. These empirical models may help in predicting the optimum fracturing conditions and also for the fracture simulation modeling study.

## **5.5 Proppant transport effectiveness**

 The experimental study in Hele Shaw slot (**Figure 8**) was presented by Tong et al. for visualizing the proppant transport behavior during foam injection [98]. The foam was generated using conventional surfactant in combination with low molecular weight (8 million Da) polymer solution as viscosifier. In their study, static *CO2 Foam as an Improved Fracturing Fluid System for Unconventional Reservoir DOI: http://dx.doi.org/10.5772/intechopen.84564* 

#### **Figure 8.**

*Laboratory scale Hele-Shaw fracture slot for mimicking induced fracture [98].* 

foam stability and foam viscosity tests were conducted to study the durability and strength of the generated foam. The visualization of foam-based fracturing fluid was studied at different foam qualities and it was reported that proppant transport was quite efficient with high quality foam due to its high viscosity and stability. They reported that the low quality foam was not an effective proppant carrying medium due to high liquid drainage and low apparent viscosity of foam during its transport through the fracture system. It has also been reported that the dry foam allows extremely slow proppant settling compared to wet foams even during high proppant loading.
