Imbibition Oil Recovery from Montney Core Plugs: The Interplay of Surfactants, Osmotic Potential, and Wettability

• Author / Creator

  Lin Yuan

• Due to advances in hydraulic fracturing technology, hydrocarbon can now be produced at economic rates from unconventional resources with ultralow permeability and porosity. However, in general, over 90% of the original oil in place cannot be produced after hydraulic fracturing operations. Recent core analysis and wettability studies indicate that most of the remaining oil is trapped in sub-micron oil-wet pores, which can hardly be accessed by water. Subsequent EOR operations or re-fracturing jobs for producing the remaining oil are attractive but expensive and in some cases risky due to insufficient information on downhole completion conditions. In this study, we characterize rock-fluid properties such as wettability and pore size distribution to understand the mechanisms controlling oil recovery from tight rocks. We evaluate the idea of adding surfactants and nanoparticles in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods.

  In this study, we conducted a series of rock-fluid experiments to investigate 1) wettability of several core plugs from the Montney Formation and its correlations with other petrophysical properties such as pore-throat size distribution, and 2) the effects of wettability, salinity, microemulsion (ME) and nanoparticle additives of different concentrations on imbibition oil recovery. First, we evaluated wettability by conducting spontaneous imbibition experiments using reservoir oil and brine on six twin core plugs from the Montney Formation. In addition, we investigated the correlations between wettability and other petrophysical properties obtained from MICP data and tight-rock analyses. Second, we injected oil into partly brine-saturated core plugs to arrive at residual water saturation. Third, we performed soaking experiments on oil-saturated core plugs using fresh water, reservoir brine, and a ME system, and measured the volume of produced oil with respect to time. The soaking fluids were characterized by measuring density, viscosity, surface tension (ST) and interfacial tension (IFT). We also evaluated nanoparticle-assisted imbibition oil recovery by conducting systematic contact-angle and counter-current imbibition tests under different conditions of brine salinity and nanoparticles concentration.

  We observe faster and higher oil imbibition into the core plugs compared with brine imbibition, suggesting strong affinity of the samples to oil. The equilibrated normalized imbibed volume of oil (Ioeq) positively correlates with the volume fraction of small pores, represented by the tail part of MICP pore-throat size distribution profiles. This suggests that the tight parts of the pore network which contain reservoir oil under in-situ conditions are preferentially oil-wet. The results of soaking experiments show that imbibition oil recovery positively correlates with the water-wet porosity measured by spontaneous brine imbibition into the dry core plugs. Fresh water imbibition results in around 3% (of initial oil volume in place) higher oil recovery compared with that of brine imbibition, possibly due to osmotic potential. Soaking the oil-saturated core plugs in ME solution after brine or fresh water soaking results in 1-2% incremental oil recovery. Soaking the oil-saturated core plugs immediately in ME solution results in faster oil recovery compared with the case when the plugs are first soaked in water and then in ME solution. Contact angle tests indicate that all the core plugs tend to be oil-wet in the presence of reservoir brine and fresh water. However, the results of dynamic contact angle measurements show that the nanoparticle additives in reservoir brine and fresh water make the rock water-wet by decreasing the water contact angle from more than 90 to less than 60. Wettability alteration is more pronounced in the presence of fresh water than reservoir brine. The imbibition oil-recovery tests show faster and higher oil recovery in the presence of the nanoparticle additives compared with the reference cases of brine and fresh water, consistent with the results of contact-angle tests. The mechanism behind wettability alteration and oil recovery can be explained by structural disjoining pressure.

• Subjects / Keywords

  • Imbibition Oil Recovery; Wettability; Osmotic Potential; Surfactants.

• Graduation date

  Fall 2019

• Type of Item

  Thesis

• Degree

  Master of Science

• DOI

  https://doi.org/10.7939/r3-nhj9-fs51

• License

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