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

Abstract

By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). We are investigating the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. Much of our previous work has measured surfactant-imbibition rates and oil-recovery values in laboratory cores from the Bakken shale, Niobrara chalk/shale, and Eagle Ford formations. With optimized surfactant formulations at reservoir conditions, we observed oil-recovery values up to 20% of OOIP incremental over brine imbibition. However, whether surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil-production rates in a field setting. This, in turn, depends on three factors: the area of formation contact (through fractures and microfractures) when/where the surfactant formulation is introduced; the rates of surfactant imbibition; and the distances of surfactant imbibition into the rock and ultimate oil-displacement effectiveness. In this paper, we use analytical models to scale laboratory surfactant-imbibition rates to a field scale in fractured-shale formations.In laboratory cores, we observed imbibition rates that varied inversely with time. Dimensionless scaling groups were applied that compensate for the effects of sample size and shape, boundary conditions, permeability, porosity, and viscosity. Calculations were made of available fracture area, assuming typical horizontalwell lengths and transverse-induced-fracture spacing in typical Bakken wells. These fracture areas were coupled with our imbibition-scaling groups to estimate oil-recovery rates in a field setting. Considering realistic timing, surfactant imbibition will generally not proceed more than a few meters into the low-permeability shale/chalk formations. These calculations indicate insufficient fracture area to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results from geological, microseismic, and pressure-transient studies indicate considerably greater area associated with natural microfractures in our target formations. When the increased area suggested by the presence of microfractures is included in our analyses, the surfactant-imbibition process appears quite promising.

Microscopic Imbibition Characterization of Sandstone Reservoirs and Theoretical Model Optimization

“….……..………………………………………………………… (13) Experiments have indicated that the transition zone has a great impact in the early stage, and the mean water saturation of a specimen is much lower than S wmax ; in the later stage, the imbibition zone expands, and the transition zone has a less significant effect, while the mean water saturation of the specimen gradually approaches S wmax .…”

A Systematic Approach for Upscaling of the EOR Results from Lab-Scale to Well-Scale in Liquid-Rich Shale Plays

“…The primary recovery factor is possibly in the range of 1-2 % in some of the plays in North America (Wang et al, 2016). The low percentage is due to initial high production rates, followed by a quick decline.…”

EOR of Spontaneous Imbibition by Surfactant Solution for Tight Oil Reservoirs

“…The imbibition recovery was calculated based on the triple exponential functions [7]. Wang et al [8] established the scaling law of surfactant imbibition rate for fractured shale formation, and it was demonstrated that the surfactantimbibition would proceed more than a few meters into the low-permeability shale/chalk formation. To enhance oil recovery of spontaneous imbibition in a tight matrix, many researchers have proposed the effects of wettability alteration and low IFT.…”