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• Characterize the correlations between carbonate permeability and morphological properties. • Establish the relationships between foam rheology and pore throat and pore body distributions, pore aspect ratio, and permeability. • Explain how characteristic rock morphology causes a significant difference in foam dynamics between carbonates and sandstones. • Impact of carbonate microheterogeneity on transient foam behavior. Foam is considered a successful method for providing conformance control during enhanced oil recovery. It helps reduce gravity segregation, viscous fingering, and minimizes injected fluid loss into high permeability zones. Foam rheology has been studied and well understood in sandstones but its behavior in carbonate rocks is not well defined. This study aims to quantify the impact of pore properties represented by permeability, pore throat size (d T), pore body size (d B) and aspect ratio (R) on foam rheology in carbonate rocks. The results are contrasted with foam rheology in natural sandstone rocks. The studied carbonates possess complex pore structures, with bimodal distributions of pore throat and pore body sizes. Pore properties were shown to affect the magnitude of foam viscosity (μ a)-foam quality relationship, but the observed trend is unchanged in different rocks. μ a was found to linearly correlate with (d T 2) and permeability. It was shown to increase exponentially with d B with a marked increase at d B > 30 μm. All the carbonates had aspect ratios R ≫ 2.5 indicating plentiful foam germination sites. As a result, the aspect ratio does not correlate strongly with μ a. Pore structure properties were shown to have a strong impact on the μ a -shear rate ( γ ̇ a) relationship, by directly impacting the magnitude of both μ a and γ ̇ a , and also by influencing the foam texture. Finally, pore properties were shown to impact factors governing foam transient behavior. Rocks with smaller (d T) are shown to have weaker foam generation and propagation, as well as a larger specific surface area leading to larger dynamic adsorption. Overall, the results of this work indicate that the successful implementation of foam for mobility control in carbonate reservoirs will depend on a good understanding of the rock pore structure. [ABSTRACT FROM AUTHOR]

Water management in mature waterflooded reservoirs is a top priority to push more oil out and control water production. Excess water production through fractures and high permeability thief zones is a growing concern for sweep efficiency and oil production. Gel treatment has been applied widely to plug thief zones and reduce excess water production to improve macroscopic sweep efficiency. Field studies demonstrated that gel treatments can be applied successfully in mature and fractured reservoirs to reduce unwanted fluid production to lower the operating cost causing premature well abandonment. The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel and develop a conformance control reservoir simulator to help screen oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce water production. These microgels can be injected as suspension in water into an injection well. Many experiments were performed to understand the transport mechanism of microgels through porous media and to identify the control variables. The lab data include oil recovery, water-cut, resistance factor, residual resistance factor, oil viscosities, gel concentrations, salinity, gel rheology, and gel strength. The success of gel treatment depends on the magnitude of permeability reduction and flow diversion. We have developed correlations for resistance factor, residual resistance factor and apparent viscosity as a function of gel strength, gel concentration, rock permeability, salinity, and flow rate. The models are validated against lab measurements and implemented into a reservoir simulator called UTGEL. Gel properties such as rheology and adsorption are also investigated. The mechanistic models and numerical tools developed will help select future conformance control candidates for a given field and optimize the gel chemistry and treatment. [ABSTRACT FROM AUTHOR]

• A novel algorithmic model is proposed to simulate foam flooding EOR process. • Pore-level foam flow behavior is simulated at designated pressure constraints. • Impacts of excessive pressure on pore-scale foam propagation are studied. • Weak foam performance in pore network is appropriately captured for the first time. • Formation of immobile foam is described as a function of foam generation rate. Foam has been used for decades in petroleum industry for enhanced oil recovery (EOR) due to its mobility adjustment ability. A variety of mechanistic models have been proposed to study foam flow in porous media from multiple scales. In these models, such as population balance models, some important parameters (e.g. , foam generation/coalescence rate, flowing foam fraction) are treated empirically since they cannot be obtained from conventional lab experiments. To improve the accuracy and reliability of foam description in these foam-assisted processes, pore network model interwoven with invasion percolation with memory (IPM) method has become a powerful tool in studying foam flow characteristics in porous media, which can predict relative permeability and flowing gas fraction with fully consideration of pore-scale mechanisms of foam generation, destruction, and propagation. However, the assumption of exactly sufficient incremental pressure difference used in conventional IPM-based pore-scale foam modeling is rigorous, not only making it difficult to conduct relevant experimental validations, but also creating potential algorithmic conflicts when simulates displacements in weak foam regime or displacements incorporated with foam coalescence mechanisms. In this study, a novel mixed-sorting rule, which proceeds the displacement by describing the transition between immobile foam bank and mobilized foam flow quantitively, is incorporated into IPM-based foam propagation model. In this way, the immobile foam bank is identified based on effective lamellae generation rate, whereas the mobilized foam flow is distinguished by frontal displacing velocity, respectively. Results estimated with proposed method successfully capture key properties that define pore-scale foam behavior at excessive pressure constraints from formation of immobile foam bank, foam mobilizing pressure thresholds, and fractal dimension of displacement pattern, etc. [ABSTRACT FROM AUTHOR]

• One of the few papers on foam-liquid displacements using a Hele-Shaw cell. • 2D micromodel pattern is printed from an actual rock using 3D printing technology. • The results showed that secondary foam injection is the most efficient technique. • The effectiveness of foam is due to both emulsification and displacement effects. • Surfactant concentration in foams should be optimized to account for retention. Gas flooding is one of the most effective enhanced oil recovery (EOR) techniques. However, mobility control of the injected gas has always been an issue, especially for heterogeneous and fractured reservoirs. There is still a need to understand the phase interference (relative Permeability) and oil production from such heterogeneous and fractured systems. This study investigates the displacement of oil in a fractured system, conducted in a Hele-Shaw set up with a pattern of obstructions or impermeable regions. This 2D pattern is printed from an actual rock cross-section, obtained from high-resolution micro-computed tomography. Different displacement fluids were utilized, including water, gas, and foam in secondary and tertiary injection modes. Relative permeability curves were generated, which depict the interference between the phases flowing through the Hele-Shaw cell with tortuosity. The results showed that secondary foam injection is the most efficient technique as opposed to the other methods. Also, N 2 -foam achieves better recovery than air-foam, which is due to the solubility of N 2 gas in the aqueous phase. This study provides more insight into foam flooding when high surfactant concentration is used. Under this condition, the effectiveness of foam injection compared to conventional water and gas injections is due to both emulsification and foam displacement effects. [ABSTRACT FROM AUTHOR]

• Oil-induced VES was identified within the Winsor III microemulsion domain. • VES provides both ultralow o/w IFT and mobility control in oil displacement. • Faster and greater tertiary oil recovery was achieved by oil-induced VES. • VES can be made with high-salinity formation water without complex water treatment. It has been observed that alkylpropoxy sulfates, sometimes called extended surfactants, exhibit an oil-induced viscoelastic behavior. This unique behavior occurs within the Winsor III microemulsion domain where the microemulsions are deemed "oil-starved", meaning that the oil content of the system is below the solubilizing capacity of the microemulsion. The resulting viscoelastic fluid offers dual benefits of producing both ultra-low oil/water interfacial tension (IFT) and favorable rheological characteristics such as serving as a displacing agent within the porous medium. In this work, the potential of the oil-induced viscoelastic formulations was explored in tertiary recovery application. First, the formulations were carefully tuned to achieve an ultralow IFT with the site-specific crude. Then only 4 – 6 vol% of crude oil or substitute paraffinic oil, was added with the freshly prepared aqueous solution to trigger the desired rheological behavior. The resulting fluid was then injected to the porous medium. Based on the results of 1-D glass column and 2-D Hele–Shaw cell studies, smoothly advancing of oil banks were realized shortly after injection of the viscoelastic fluids, which in turn led to fast oil breakthrough, high oil cut, and better tertiary recovery. Significant advantages of the developed viscoelastic systems are that they offer a robust system with versatile polymer-free injection package and the potential for field tertiary recovery involving a single-slug that drastically improves the volumetric sweep efficiency and the microscopic displacement efficiency, without the complex water treatment system and polymer mixing system required for surfactant-polymer (SP) or alkaline- surfactant-polymer (ASP) floods. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) from carbonate formations has been challenging due to reservoir heterogeneity, unfavorable wettability, and low permeability. Thus, the application of traditional water-based EOR methods such as micellar-polymer flood in these reservoirs has been limited. With the increasing availability of natural gas, we introduce a new foam EOR concept utilizing the raw mixture of natural gas liquids (MNGLs). This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and MNGLs with dissolved non-aqueous foam stabilizing additive to maximize oil recovery based on crude oil-MNGLs miscibility and sweep efficiency due to foam improved mobility control. The objective of this study is to evaluate the performance of this unconventional foam process to improve miscible displacement in low permeability rocks. Coreflood experiments were conducted using heterogeneous carbonate cores with sub-10-mD permeability. It was found that non-aqueous foam-assisted miscible displacement can achieve promising ultimate recovery factors while significantly reducing the amount of injected MNGLs. The overall recovery could be increased up to 18% with a foaming additive dissolved in the MNGLs slug. The measured pressure drops along the core indicate that in-situ generation of foam significantly delayed the injectant breakthrough and recovered the unswept oil much further away from the injection point. [ABSTRACT FROM AUTHOR]