دانلود Surfactant Formulation Study For Bakken Shale Imbibition

Abstract

This paper investigates an idea for chemical imbibition using surfactant formulations to stimulate oil recovery from oil shale. One goal of this research is to identify a formulation that promotes imbibition while minimizing clay swelling and formation damage. Experiments directed toward this goal involved balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to enhance oil recovery from the shale with ultra-low porosity and permeability in the middle member of the Bakken formation in the Williston Basin of North Dakota. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.

Using spontaneous imbibtion, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed where brine and surfactant (0.05-0.2 wt % concentration) imbibition yielded recovery values of 1.55 to 76% OOIP at high salinity (150-300 g/L: 15-30 wt %) and temperatures ranging from 23°C-120°C. Six key observations were noted: (1) an ethoxylate nononic surfactant, an internal olefin sulfonate anonic surfactant, and an amine oxide cationic surfactant were more stable than the other surfactants for temperatures from 105-120°C. They were effective in imbibing and displacing oil at high temperature. (2) Adding alkali to surfactant formulations increased oil recovery from Bakken shale. However, sodium carbonate reacted with divalent cations and precipitated when added to our highly saline brines. To counter this effect, sodium metaborate was added to surfactant solutions to reduce or prevent precipitation. (3) An ethoxylate nononic surfactant and an internal olefin sulfonate anionic surfactant were more tolerant of high salinity than other surfactants and display higher oil recoveries at high temperature. For Bakken cores, surfactants did not imbibe effectively using distilled or low salinity water. (4) Varying the hardness of the surfactant formulation had a major effect on imbibition and oil displacement. (5) In some cases, clay flaking from the shale was observed when contacting brine (without surfactant) or contacting amine oxide cationic surfactant with higher alkane numbers in brine. However, for the later situation, it could be improved by changing pH of surfactant solution. (6) For a given surfactant, oil recovery can be maximized by identifying the optimal surfactant concentration, brine salinity, sodium metaborate concentration, and divalent cation content.