Diffusion-Dominated Proxy Model for Solvent Injection in Ultratight Oil Reservoirs

Abstract

Summary Enhanced oil recovery (EOR) by solvent injection offers significant potential to increase recovery from shale oil reservoirs, which is typically between 3 and 7% original oil in place (OOIP). The rather sparse literature on this topic typically models these tight reservoirs on the basis of conventional-reservoir processes and mechanisms, such as by convective transport using Darcy's law, even though there is little physical justification for this treatment. The literature also downplays the importance of the soaking period in huff ’n’ puff. In this paper, we propose, for the first time, a more physically realistic recovery mechanism based on solely diffusion-dominated transport. We develop a diffusion-dominated proxy model assuming first-contact miscibility (FCM) to provide rapid estimates of oil recovery for both primary production and the solvent huff ’n’ soak ’n’ puff (HSP) process in ultratight oil reservoirs. Simplified proxy models are developed to represent the major features of the fracture network. The key results show that diffusion-transport considered solely can reproduce the primary-production period within the Eagle Ford Shale and can model the HSP process well, without the need to use Darcy's law. The minimum miscibility pressure (MMP) concept is not important for ultratight shales where diffusion dominates because MMP is based on advection-dominated conditions. The mechanism for recovery is based solely on density and concentration gradients. Primary production is modeled as a self-diffusion process, whereas the HSP process is modeled as a counter-diffusion process. Incremental recoveries by HSP are several times greater than primary-production recoveries, showing significant promise in increasing oil recoveries. We calculate ultimate recoveries for both primary production and for the HSP process, and show that methane injection is preferred over carbon dioxide injection. We also show that the proxy model, to be accurate, must match the total matrix-contact area and the ratio of effective area to total contact area with time. These two parameters should be maximized for best recovery.

Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution, Transport, and Primary and Secondary Recovery in Nano-Porous Media

“…If this bending pressure is extrapolated to a permeability close to zero, as depicted in Figure 19, the extrapolated pressure is the same as the first contact minimum miscibility pressure (FCMMP) of CO 2 and Bakken oil, which is 4940 psia from the swelling test calculations shown in Figure 20. These results are consistent with the conclusion of Cronin et al [25] who found that for diffusion-dominated systems, only FCMMP is important and MCMMP is not applicable in gas flooding of ultra-tight reservoirs. Similarly, for pressures lower than the MMP, the recovery of heterogeneous pore size reservoir is lower than 10 nm pore size homogenous reservoir but higher than 10 µm pore size homogenous case.…”

Unified Theory of Ultimate Hydrocarbon Recovery for Primary and Cyclic Injection Processes in Ultratight Reservoirs

“…Counter-diffusion occurs during the huff and soak because solvent diffuses from fractures into matrix while hydrocarbon simultaneously diffuses into the fractures 6,19,26 . However, in this study, we assume a constant pore volume and ignore mass transfer between V wf and ultratight matrix when using Eq.…”

“…These correlations can provide insight into drilling locations and expected recoveries, but they are not fundamentally based on the underlying physics and require significant historical data. Instead, maximum recovery (at infinite time) can be easily quantified by the density reduction between initial and producing conditions, which is independent of fracture-matrix contact area and transport rates 6 .…”

“…Miscibility attained in this manner results from interaction of advective transport (flow governed by relative permeability) and phase behavior such that the forward contact (oil tie line), backward contact (gas tie line), or a cross-over tie line controls miscibility 17,18 . In an ultratight reservoir matrix, however, miscibility becomes a function of solubility because advection-dominated flow conditions required for the MCM process are no longer relevant 6 . Instead, transport within a tight matrix is anticipated to be a diffusion-dominated process 6,19 .…”

“…In an ultratight reservoir matrix, however, miscibility becomes a function of solubility because advection-dominated flow conditions required for the MCM process are no longer relevant 6 . Instead, transport within a tight matrix is anticipated to be a diffusion-dominated process 6,19 . Concentration gradients within the matrix near the matrix-fracture interface control mass transport in these reservoirs for the primary production and HnP process due to the significant contact area created during hydraulic fracturing between the matrix and fracture network.…”