Flow-Rate Behavior and Imbibition in Shale

Abstract

Summary As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, we are studying oil flow through and, especially, brine intake into shale to displace oil. Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre shale in North Dakota, USA. We studied porosity, permeability to oil, permeability to water, and spontaneous brine intake for the Pierre shale. We found that porosities for Pierre shale cores were relatively high—from 25 to 35%. Porosities for our measurements of Bakken cores averaged less than 3%. Bakken oil imbibed into dry Pierre shale cores (up to 5 mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130™) was higher than for Bakken oil—apparently because of deposition of wax/asphaltenes/particulates on the Pierre core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3.32×10–5 to 2.19×10–4 md when injecting Bakken oil and from 4.85×10–4 to 2.34×10–3 md when injecting Soltrol 130. Permeability to Bakken oil for a Bakken core (with no water present) averaged 4.84×10–4 md. In Pierre shale and Bakken cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. Saline brine spontaneously entered into oil-saturated Pierre cores, yielding recovery values up to 41% of original oil in place (OOIP). During exposure to brine, our results indicated an increase in permeability—presumably by mineral dissolution during forced brine injection and by cracking (possibly caused by clay swelling) during spontaneous brine intake. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Before these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling. The laboratory results will help during a current study of surfactant and brine imbibition in the Bakken formation.

Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations

“…2 and 3, oil-recovery results by use of brine were comparable with those by use of surfactant formulations. This situation was an exception to our previous findings (Wang et al 2012;Zhang et al 2013). We report these results here simply to reveal some of our best imbibition results, and we leave the mechanistic explanation for the results for future papers.…”

“…Our previous work (Wang et al 2012) revealed that Bakken cores in their native state are generally oil-wet, with Amott-Harvey indices ranging from -0.150 to -0.810. In this same study, we also demonstrate that the wettability indices fell within a similar range after cleaning (with toluene and methanol) and resaturation with Bakken crude oil.…”

“…In our previous studies (Wang et al 2012;Zhang et al 2013), we identified surfactant formulations that consistently altered the wetting state of Bakken cores toward water-wet. In particular, during Amott-Harvey measurements on 13 different cores, the average shift of wettability index was þ0.47 units (comparing brine imbibition with surfactant imbibition).…”

Status of surfactant EOR technology

“…The literature on shale oil rocks indicates that they are most likely oil-wet (Phillips et al, 2007;Wang et al, 2011;Mirchi et al, 2014). Shuler et al (2011) did some surfactant spontaneous imbibition tests.…”

“…The core slices they used were 1.5 inches in diameter and ½ inches in thickness. Wang et al (2011) also investigated brine imbibition into the outcrop Pierre shale core slices. The core sample thicknesses were 0.65-5 mm.…”