Phase Behavior, Adsorption Behavior and Interfacial Properties of Fluids in Shale Reservoirs

• Author / Creator

  Liu, Yueliang

• Shale oil/gas resources are becoming an increasingly important energy resource. Compared to conventional reservoirs, shale generally consists of a large proportion of organic matters. Organic matter is mainly comprised of kerogen, within which a significant amount of nanopores may reside. Due to the presence of kerogen, the distribution of fluid molecules in shale can be strongly affected by the fluid/pore wall interactions, leading to significant fluid adsorption on pore surface and thus resulting in a quite different phase behavior in shale reservoirs from that in conventional ones. In addition to the fluid/pore wall interactions, capillary pressure comes into play an important role in affecting the two-phase equilibria, whenever two-phase equilibrium appears in the confined spaces in shale. Understanding of phase behavior, adsorption behavior, and interfacial properties of fluids in shale is of critical importance for more accurately determining the macroscopic and microscopic distribution of fluids in shale reservoirs as well as understanding the mechanisms governing the fluid transport in shale reservoirs.
  In this thesis, we first investigate the phase behavior of pure hydrocarbons and hydrocarbon mixtures in nanopores by applying the Peng-Robinson equation of state (PR-EOS) (Peng and Robinson, 1976) with capillary pressure model (Nojabaei et al., 2013) and by applying the engineering density functional theory (DFT), respectively. The capillary pressure between vapor phase and liquid phase is incorporated into PR-EOS. The computed results using the PR-EOS with capillary pressure model show that: phase behavior of hydrocarbons in nanopores deviates from that in bulk; the dew-points and the critical points vary in pores with different sizes. Comparison with the engineering DFT shows that the widely used PR-EOS with capillary pressure model is not reliable in describing confined fluid phase behavior. Considering that pores with different sizes generally coexist in shale samples, we further investigate the phase behavior of fluid in a double-pore system using molecular dynamic (MD) simulations. We observe that as system pressure decreases, heavier hydrocarbons tend to accumulate in smaller pores, while lighter ones can be readily recovered from the organic pores. CO2 can readily recover C1 from both micro- and meso-pores, but cannot effectively replace nC4 from these pores. Hydrocarbons generally exhibit different fluid-distribution patterns in different nanoscale pores due to the different levels of fluid/pore wall interactions.
  Fluid molecules can strongly adsorb on shale surface due to their strong affinity to organic pore walls. To investigate the adsorption behavior of hydrocarbons on shale samples, we initially measure the excess adsorption isotherms of pure hydrocarbons on shale samples. A pragmatic method is proposed to determine the adsorption-phase density yielded by the GCMC simulation method; this leads to the more accurate determination of absolute adsorption isotherms based on the measured excess ones. According to grand canonical Monte Carlo (GCMC) simulation results, absolute adsorption is always higher than the measured excess adsorption. It is also found that individual hydrocarbons exhibit distinct adsorption capacities towards organic pore surface, which leads to the competitive adsorption of hydrocarbon species towards organic pore surface. An experimental study is further conducted to investigate the effect of competitive adsorption on bulk-fluid phase behavior; specifically, phase equilibrium of gas mixtures with the presence of actual shale samples is measured with a PVT setup. We observe that competitive adsorption of different species on shale alters the bubble-point pressure of the original fluid mixtures, confirming competitive adsorption affects the phase behavior of fluids in shale reservoirs.
  Although the PR-EOS with capillary pressure model is not precise in describing the in-situ phase behavior of shale fluids, the convenience of using it to quickly describe the confined phase behavior makes this approach still widely used in the shale industry. However, the interfacial tension (IFT) used in such model needs to be accurately determined. Targeting the vapor-liquid equilibria of gas/brine mixtures, IFTs for the CO2+CH4/brine systems are measured using the axisymmetric drop shape analysis (ADSA) under shale reservoir conditions. We find that the presence of CO2 reduces the IFT of the CO2+CH4/brine systems, while salts can increase the IFT of this system. These findings will be also useful for achieving a better understanding on the mechanisms of enhanced shale gas recovery using CO2 injection.

• Subjects / Keywords

  • Interfacial tension
  • Adsorption
  • Shale reservoirs
  • Confined fluid
  • Phase Behavior

• Graduation date

  Fall 2018

• Type of Item

  Thesis

• Degree

  Doctor of Philosophy

• DOI

  https://doi.org/10.7939/R30C4T17X

• License

  Permission is hereby granted to the University of Alberta Libraries to reproduce single copies of this thesis and to lend or sell such copies for private, scholarly or scientific research purposes only. Where the thesis is converted to, or otherwise made available in digital form, the University of Alberta will advise potential users of the thesis of these terms. The author reserves all other publication and other rights in association with the copyright in the thesis and, except as herein before provided, neither the thesis nor any substantial portion thereof may be printed or otherwise reproduced in any material form whatsoever without the author's prior written permission.