Understanding rock-fluid interactions in tight oil formations

• Author / Creator

  Ali Habibi

• Combination of horizontal drilling and hydraulic fracturing has led to improved oil recovery from unconventional resources over the past decade. In spite of the huge amount of oil in-place, the primary oil recovery factor is very low (3-10 % of initial oil in-place) in unconventional resources. This is due to ultra-low permeability, complex pore structure, and oil-wet (or mixed-wet) behavior of tight formations. To guarantee economically long-term oil production from tight formations, enhanced oil recovery (EOR) techniques should be implemented as soon as fracturing operations start. The first step to develop any EOR technique is to understand the wettability of tight formations. The next step is to investigate interactions among reservoir fluids, rock surface, and fracturing fluids.This study aims at understanding the (i) wettability of Montney (MT) tight rocks at core-scale and pore-scale and (ii) mechanisms responsible for oil displacement from these rocks using CO2 and surfactant solutions. First, spontaneous imbibition tests and contact angle measurements are conducted to evaluate the wettability of and oil recovery from the MT tight rocks. Next, the Derjaquin, Landau, Verwey, and Overbeek (DLVO) theory is applied to investigate how mineral heterogeneity affects wettability of the MT rocks. Finally, two EOR techniques are used to investigate further oil recovery from the MT rocks after water spontaneous imbibition. These techniques use CO2 and non-ionic octylphenol ethoxylate (OPE) surfactant solutions. Different experiments are designed to study the rock-fluid interactions at bulk-phase and core-scale conditions. The spontaneous imbibition results show that water can imbibe into the oil-saturated core plugs and produce oil up to 45% of initial oil in-place while oil cannot imbibe into the water-saturated core plugs. These observations suggest the water-wet behavior for the oil (or water)-saturated core plugs. The water contact angles calculated (using DLVO theory) for the solid surface/water/oil system confirm the water-wet behavior of the core plugs. Disjoining pressures calculated for this system also show that water film covering the rock surface is stable.Investigating CO2-oil interactions at bulk-phase conditions shows high oil swelling factor (up to 1.390) at reservoir conditions (2000 psig and 50C). The results of cyclic CO2 tests also show that oil recovery factor from oil-saturated core plugs is high (up to 66% of original oil in-place). The proposed mechanisms for oil production are: 1) oil swelling as a result of CO2 dissolution into the oil, and 2) evaporation of oil components and expelling out of core plugs.Investigating the surfactant solutions-oil interactions at bulk-phase and core-scale conditions shows that mixed non-ionic octylphenol ethoxylate (OPE) surfactants can spontaneously imbibe into the oil-saturated core plugs. The final oil recovery factor from mixed surfactant solutions is higher than that for reference case (water without surfactants). In addition to (i) decreasing IFTs for mixed surfactant solutions and (ii) preferentially wetting the rock surface by mixed surfactant solutions, additional mechanisms are responsible for improved oil recovery. The higher oil recovery factor for the mixed solutions can be explained by (i) improved adsorption tendency of mixed surfactants on the rock surface due to the existence of OPE15 (soluble in oil), (ii) formation of small micelles (100-200 nm) in mixed solutions. The existence of small mixed micelles facilitates surfactant imbibition into narrow pores (Pthroat<100 nm) for oil expulsion.

• Subjects / Keywords

  • Wettability
  • DLVO theory
  • Thin film stability
  • Enhanced oil recovery

• Graduation date

  Spring 2019

• Type of Item

  Thesis

• Degree

  Doctor of Philosophy

• DOI

  https://doi.org/10.7939/r3-wkk6-pw13

• License

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