Xun Zhong

Date of Award

January 2020

Document Type

Dissertation

Degree Name

Doctor of Philosophy (PhD)

Department

Petroleum Engineering

First Advisor

Hui Pu

Abstract

Surfactant enhanced oil recovery (EOR) technology has received much attraction due to its excellent capability to increase the displacement efficiency by altering the wettability, lowering the oil-water interfacial tension and mobilizing the remaining oil. However, surfactant systems are widely acknowledged to have either low or high adsorption on solid (rock/clay/sediment) surfaces. The adsorption density can be affected by adsorbents, surfactant structure, experimental conditions and some other factors. Also, the driving forces for adsorption vary with different surfactants types. Generally speaking, electrostatic interactions are more prominent for anionic, cationic and zwitterionic surfactants, while chemical interactions are more common for nonionic surfactants.

Proper surfactant adsorption on mineral surfaces can modify interfacial properties and enhance oil recovery while excessive adsorption might result in high cost and limited effectiveness. Economic concerns about chemical flooding should be taken as opportunities to develop new cost-effective formulas that lead to high recoveries. According to the published studies, nanomaterials are good candidates for sacrificial agents or surfactant carriers, meanwhile, some positive synergistic effects produced by mixing surfactants with nanoparticles are favorable for additional oil production. The EOR performance of different nanomaterials together with their limitations were systematically reviewed in Chapter III.

Nonionic surfactants, which occupy over 40.0 % of the global surfactant production, are nonvolatile and benign chemicals widely used in the oil and gas industry. However, their high adsorption loss especially at high temperature and high salinity conditions would limit their large-scale applications. Surfactant MERPOL HCS is a commercial product with cloud point higher than 100 ℃. By integrating hydrophilic silica nanoparticles with surfactant MERPOL HCS, surfactant adsorption was reduced and oil production rate was generally increased. More than 34.0 % OOIP and over 4.0 % OOIP additional oil was recovered compared with 2000 mg/L KCl imbibition and pure surfactant imbibition, respectively. In addition, particles with smaller size turned out to be more effective surfactant carriers and better performance enhancers. However, due to the stability issues of nanoparticles and surfactant, the developed nonionic surfactant-hydrophilic silica nanoparticle augmented system was more suitable for low salinity conditions and the details were shown in Chapter IV.

In order to extend the applications of surfactant-nanoparticle systems to higher salinity conditions, improvements are required. First, the selected surfactant should have higher resistance towards high salinity and elevated temperature. Second, the steric stability of pure nanoparticles should be improved because in normal cases, using surfactant alone as a nanoparticle stabilizer is not enough to overcome the adverse impacts of salts especially when environmental temperature increases. Therefore, in Chapter V, a novel nanofluid formula was developed by integrating a zwitterionic surfactant CAPHS with GLYMO modified silica nanoparticles. According to our experiments, the proposed nanofluid was not sensitive to either monovalent or divalent cations, whose size remained around 10.0 nm in API brine within 8 weeks at 25 ℃ and 4 weeks at 60 ℃. The addition of surfactant into pure nanoparticle systems significantly reduced the concentration of nanoparticles required to induce wettability alteration and the possibility of severe permeability impairment. The presence of nanoparticles also effectively decreased surfactant adsorption loss on rocks and the surfactant concentration needed to produce a low interfacial tension. Moreover, the oil-wet solid surface could be altered to a more water-wet condition beneficial for water imbibition and oil displacement. Core flooding tests showed that the nanofluid composed of 800 mg/L zwitterionic surfactant and 2000 mg/L GLYMO modified silica nanoparticles was able to recover additional 3.12 % and 5.39 % OOIP from Berea sandstone cores in the tertiary recovery mode after surfactant flooding and pure nanoparticle flooding, respectively.

The total dissolved solids in the API brine is 10.0 wt.% and the highest testing temperature is only 60 ℃ in our study. These conditions are still less harsh than the salinity of formation brine and reservoir temperature in most unconventional reservoirs. Therefore, some recommendations are proposed in the Conclusions and Recommendations section. The development of surfactant-nanoparticle augmented systems with higher stability should be continued and the emphasis should be put on the new nanomaterials with small size, novel surfactants, low cost and high efficiency.

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