No abstract

Nanoparticles have gained attention for increasing the stability of surfactant-based foams during CO2 foam-enhanced oil recovery (EOR) and CO2 storage. However, the behavior and displacement mechanisms of hybrid nanoparticle–surfactant foam formulations at reservoir conditions are not well understood. This work presents a pore- to core-scale characterization of hybrid nanoparticle–surfactant foaming solutions for CO2 EOR and the associated CO2 storage. The primary objective was to identify the dominant foam generation mechanisms and determine the role of nanoparticles for stabilizing CO2 foam and reducing CO2 mobility. In addition, we shed light on the influence of oil on foam generation and stability. We present pore- and core-scale experimental results, in the absence and presence of oil, comparing the hybrid foaming solution to foam stabilized by only surfactants or nanoparticles. Snap-off was identified as the primary foam generation mechanism in high-pressure micromodels with secondary foam generation by leave behind. During continuous CO2 injection, gas channels developed through the foam and the texture coarsened. In the absence of oil, including nanoparticles in the surfactant-laden foaming solutions did not result in a more stable foam or clearly affect the apparent viscosity of the foam. Foaming solutions containing only nanoparticles generated little to no foam, highlighting the dominance of surfactant as the main foam generator. In addition, foam generation and strength were not sensitive to nanoparticle concentration when used together with the selected surfactant. In experiments with oil at miscible conditions, foam was readily generated using all the tested foaming solutions. Core-scale foam-apparent viscosities with oil were nearly three times as high as experiments without oil present due to the development of stable oil/water emulsions and their combined effect with foam for reducing CO2 mobility

Carbon capture and subsequent storage (CCS) is identified as a necessity to achieve climate commitments. Permanent storage of carbon dioxide (CO2) in subsurface saline aquifers or depleted oil and gas reservoirs is feasible, but large-scale implementation of such storage has so far been slow. Although sandstone formations are currently most viable for CO2 sequestration, carbonates play an important role in widespread implementation of CCS; both due to the world-wide abundancy of saline aquifers in carbonate formations, and as candidates for CO2-EOR with combined storage. Acidification of formation brine during CO2 injection cause carbonate dissolution and development of reactive flow patterns. Using calcite-functionalization of micromodels we experimentally investigate fundamental pore-scale reactive transport dynamics relevant for carbonate CO2 storage security. Calcite-functionalized, two-dimensional and siliconbased, pore scale micromodels were used. Calcite precipitation was microbially induced from the bacteria Sporosarcina pasteurii and calcite grains were formed in-situ. This paper details an improved procedure for achieving controlled calcite precipitation in the pore space and characterizes the precipitation/mineralization process. The experimental setup featured a temperature-controlled micromodel holder attached to an automatic scanning stage. A high-resolution microscope enabled full-model (22x27 mm) image capture at resolution of 1.1 µm/pixel within 82 seconds. An in-house developed image-analysis python script was used to quantify porosity alterations due to calcite precipitation. The calcite-functionalized micromodels were found to replicate natural carbonate pore geometry and chemistry, and thus may be used to quantify calcite dissolution and reactive flow at the pore-scale.

The flow of CO 2 foam for mobility control in porous media is dictated by the foam texture, or bubble density, which is commonly expressed as the number of bubbles per unit of flowing gas. In most high-pressure laboratory studies of foam in porous media, the local foam texture cannot be determined due to opaque flow systems. Here, we unlock real-time foam texture dynamics at high pressure (100 bar) by utilizing a realistic pore network with an extended field of view. We identified snap-off as the dominant foam generation mechanism, with additional fining of foam texture caused by backward foam propagation. Foam coalescence during continuous CO 2 injection resulted in large gas channels parallel to the general flow direction that reduced the overall foam apparent viscosity. A large fraction of the CO 2 foam remained trapped (X t > 0.97) and stationary in pores to divert CO 2 flow and increase sweep efficiency. The gas mobility was calculated from the fraction of trapped bubbles at the pore-scale, and the apparent foam viscosity agreed with similar injection test performed at core-scale. Hence, improved understanding of CO 2 foam texture evolution (n f ) can strengthen the validation of numerical foam models for upscaling of flow phenomena, instrumental in the development of field scale implementation of CO 2 foam for in carbon utilization and storage applications.

No abstract