Abstract
To study improved oil recovery (IOR) via laboratory experiments at the pore scale, we performed waterflooding experiments in a glass 2.5D micromodel (dual depth: 12 and 27 μm) with crude oil (CRO) and brines of variable compositions at temperatures ranging from 22 °C (room temperature) to 90 °C. The time-dependent residual oil saturation (ROS) for various flooding and aging protocols was extracted from optical microscopy images of the entire pore space in the micromodel. Additionally, we used high-resolution images to examine the microscopic distributions of oil and brine at the subpore level. Variation of the fluid aging history (before the first flooding with high-salinity water, HSW) revealed that sequential aging with formation water and CRO led to significantly higher ROS values than aging with CRO only. Video analysis of the pore space showed that most of the oil was trapped via a complete bypassing of the deep pores. On increasing the waterflooding temperature, both the ROS and the fraction of bypassed pores became smaller. An increase in dewetting of tiny oil drops and films from the pore walls supports the notion of a ROS decrease via a wettability alteration. Subsequent flooding with low-salinity water (LSW) did not lead to recovery of additional oil, regardless of aging condition or temperature. Our results show the significance of fluid aging and temperature to design a successful microfluidic IOR strategy.
Highlights
A persistent concern on improved oil recovery (IOR) applications is that significant amounts of oil remain trapped in the oil reservoir
Based on our measurements of the interfacial tensions and viscosities of our system (Table 1), we find that the capillary number ranges between ∼6 × 10−6 and ∼8 × 10−7, indicating that capillary forces must play an important role at all temperatures and brine compositions.[62,63]
The strongest effect is, observed when the crude oil (CRO) aging is preceded by exposure to formation water (FW); this leads to a residual oil saturation (ROS) of 46%
Summary
A persistent concern on improved oil recovery (IOR) applications is that significant amounts of oil remain trapped in the oil reservoir. The use of microfluidics has recently emerged as an alternative, quick, and efficient method to mimic oil recovery.[10,11] In principle, microfluidics can offer quantification of residual oil and microscopic observation of pore scale physical phenomena at a relatively low cost This is made possible through the broad availability of materials for fabrication (e.g., glass,[12,13] silicon,[14−16] or polymers17−20), the low consumption of chemicals, the accurate fluid control and detection, and the flexible design of the pore space. Surface-active components (asphaltenes and resins) are known for their ability to adsorb onto rock surfaces as well as brine/CRO interfaces.[50−54] These adsorption (and desorption) behaviors depend on brine composition and temperature and can play distinct roles in wettability alteration during both the initial aging and subsequent waterflooding stages To examine this aspect, we study the behavior of (nondiluted) crude oil in a glass microfluidic chip at various temperatures. We use optical microscopy at high magnification to examine for the presence of tiny droplets or thin films in the pores after the waterflooding
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