Riyaz Kharrat

This study evaluates the technical and economic feasibility of liquid polymer emulsions as substitutes for powder polymers in polymer flooding applications, particularly in space-constrained, low-permeability reservoirs in Austria. Rheological tests determined that target viscosities of 20 mPa·s at 20 °C and a shear rate of 7.94 s⁻¹ were achieved using concentrations of 1200 ppm for liquid polymer 1 (LP1), 2250 ppm for liquid polymer 2 (LP2), and 1200–1400 ppm for powder polymers. Injectivity tests revealed that liquid polymers encountered challenges in 60 mD and 300 mD core plugs, with pressure stabilization not achieved at injection rates of 1–2.5 ft/day. Powder polymers demonstrated stable injectivity, with powder polymer 1 (PP1) showing an optimal performance at 10 ft/day and a low residual resistance factor (RRF). Two-phase core floods using PP1 and powder polymer 2 (PP2) at 1 ft/day yielded incremental oil recovery factors of approximately 5%, with a maximum of 8% observed for higher viscosity slugs. Economic analysis indicated that over a 3-year horizon, liquid polymers are 30% cheaper than powder polymer Option 1 but 100% more expensive than Option 2. Over a 10-year horizon, liquid polymers are 50% more expensive than both powder polymer options. Although liquid polymers offer logistical advantages, they are unsuitable for low-permeability reservoirs. Powdered polymers, particularly PP1, are recommended for pilot implementation due to superior injectivity, mechanical stability, and recovery performance.

This study investigates the fundamental ion-specific (Na⁺, Cl^-, Mg²⁺, and SO₄^2-) interactions governing a polar model oil (decane + benzoic acid) at the calcite/carbonated brine interface by adopting a fully atomistic molecular dynamics (MD) simulation. By bridging molecular-scale interactions with macroscopic mechanisms, such as interfacial tension (IFT) reduction, oil viscosity, and wettability changes, this work provides the first direct mechanistic validation of phenomena that have previously been inferred only from experimental observations in carbonated smart water flooding systems. The results demonstrate that enhanced interactions between carboxylic acids and anions at the oil/brine interface significantly influence CO₂ diffusion and distribution within the oleic phase, which affects the apparent oil viscosity. While variations in brine ionic composition cause only modest changes in IFT, a pronounced reduction is observed with increased concentrations of polar molecules in the oil phase. Structural analysis reveals that divalent ions (Mg²⁺, SO₄^2-) are excluded from the hydration layers near the calcite surface but alter the arrangement of Na⁺ and Cl^- ions in the hydration layer covering the calcite surface, thereby influencing wettability. Notably, SO₄^2- neutralizes the calcite surface positive charge and facilitates Mg²⁺ access to the interface, promoting desorption of benzoic acid (BA) from the surface through the Mg-BA association. This highlights the cooperative role of SO₄^2- and Mg²⁺ in releasing polar species from the calcite surface. The findings underscore the dominant influence of IFT over contact angle in capillary-driven recovery and show that apparent viscosity is more sensitive to CO₂ content and overall salinity than specific ions. Therefore, from an industrial perspective, maintaining seawater-like salinity enriched with divalent ions offers a practical strategy to enhance the mobilization of polar acidic components during carbonated water flooding in carbonate reservoirs, supporting the design of more efficient Enhanced Oil Recovery (EOR) formulations.

This study examines the connections between various fracture indicators and production data with an example from one of the giant fields in the Middle East producing complex fractured carbonate lithologies. The field under study hosts two reservoirs with a long development and production history, including carbonates from the Asmari and Bangestan Formations. A fracture intensity map was generated based on the interpretation of image logs from 28 wells drilled within the field. Mud loss data were collected and mapped based on the geostatistical Gaussian Random Function Simulation (GRFS) algorithm. Maximum curvature maps were generated based on Asmari structural surface maps. Comparing the results shows a good agreement between the curvature map, fault distribution model, mud loss map, fracture intensity map, and productivity index. The results of image log interpretations led to the identification of four classes of open fractures, including major open fractures, medium open fractures, minor open fractures, and hairline fractures. Using the azimuth and dip data of the four fracture sets mentioned above, the fracture intensity log was generated as a continuous log for each well with available image log data. For this purpose, the fracture intensity log and a continuous fracture network (CFN) model were generated. The continuous fracture network model was used to generate a 3D discrete fracture network (DFN) for the Asmari Formation. Finally, a 3D upscaled model of fracture dip and azimuth, fracture porosity, fracture permeability, fracture length, fracture aperture, and the sigma parameter (the connectivity index between matrix and fracture) were obtained. The results of this study can illuminate the modeling of intricate reservoirs and the associated production challenges, providing insights not only during the initial production phase but also in the application of advanced oil recovery methods, such as thermal recovery.

This study delves into the properties and behavior of xanthan TNCS-ST, a specialized variant designed for enhanced oil recovery (EOR) purposes. A notable aspect of this polymer is its transparency and capability to dissolve in high salt concentrations, notably up to 18% total dissolved solids. Various laboratory methods are employed to assess the polymer’s distinctive traits, including transparency, salt tolerance, and high pyruvylation. These methods encompass preparing xanthan solutions, conducting filtration tests, assessing energy consumption, and measuring rheological properties. The findings highlight the influence of salt concentration on xanthan’s filterability, indicating increased energy requirements for dissolution with higher salt and xanthan concentrations. Additionally, this study observes temperature-dependent viscosity behavior in different solutions and evaluates the shear stability of xanthan. A significant and novel characteristic of TNCS-ST is its high salt tolerance, enabling complete dissolution at elevated salt concentrations, thus facilitating the filterability of the xanthan solution with sufficient time and energy input. Core flooding experiments investigate fluid dynamics within porous rock formations, particularly sandstone and carbonate rocks, while varying salinity. The results underscore the substantial potential of the new xanthan polymer, demonstrating its ability to enhance oil recovery in sandstone and carbonate rock formations significantly. Remarkably, the study achieves a noteworthy 67% incremental recovery in carbonate rock under the high salinity level tested, suggesting promising prospects for advancing enhanced oil recovery applications.

The structural and dynamic properties of fluids under confinement in a porous medium differ from their bulk properties. This study delves into the surface structuring and hydrodynamic characteristics of oil/thin film carbonated brine two-phase within a calcite channel upon salinity variation. To this end, both equilibrium and non-equilibrium molecular dynamics simulations are utilized to unveil the effect of the carboxylic acid component (benzoic acid) in a simple model oil (decane) confined between two thin films of carbonated brine on the oil-brine-calcite characteristics. The salinity effect was scrutinized under four saline carbonated waters, deionized carbonated water (DCW), carbonated low-salinity brine (CLSB, 30,000 ppm), carbonated seawater (CSW, 60,000 ppm), and carbonated high-salinity brine (CHSB, 180,000 ppm). An electrical double layer (EDL) is observed at varying salinities, comprising a Stern-like positive layer (formed by Na⁺ ions) followed by a negative one (formed by Cl^- ions primarily residing on top of the adsorbed sodium cations). By lowering the salinity, the Na⁺ ions cover the interface regions (brine-calcite and brine-oil), depleting within the brine bulk region. The lowest positive surface charge on the rock surface was found in salinity corresponding to seawater. Two distinct Na⁺ peaks at the oleic phase interface have been observed in the carbonated high-salinity brine system, enhancing the adsorption of polar molecules at the thin brine film interfaces. There is a pronounced EDL formation at the oleic phase interface in the case of CSW, resulting in a strong interface region containing ions and functional fractions. Likewise, the oil region confined by CSW exhibited the lowest apparent viscosity, attributed to the optimized salinity distribution and inclination of benzoic acid fractions uniformly at the brine-oil interface, acting as a slippery surface. Moreover, the results reveal that the presence of polar fractions could increase the oil phase's apparent viscosity, and introducing ions to this system reduces the polar molecules' destructive effect on the apparent viscosity of the oil region. Therefore, the fluidity of confined systems is modulated by both composition of the brine and oil phases.

Numerous reservoirs that play a significant role in worldwide petroleum production and reserves contain fractures. Typically, the fractures must form a connected network for a reservoir to be classified as naturally fractured. Characterizing the reservoir with a focus on its fracture network is crucial for modeling and predicting production performance. To simplify the solution, dual-continuum modeling techniques are commonly employed. However, to use continuum-scale approaches, properties such as the average aperture, permeability, and matrix fracture interaction parameters must be assigned, making it necessary to improve the fracture depiction and modeling methods. This study investigated a fractured reservoir with a low matrix permeability and a well-connected fracture network. The focus was on the impact of the hierarchical fracture network on the production performance of gas-based enhanced oil recovery methods. The discrete fracture network (DFN) model was utilized to create comprehensive two-dimensional models for three processes: gas injection (GI), water alternating gas (WAG), and foam-assisted water alternating gas (FAWAG). Moreover, dimensionless numbers were employed to establish connections between properties across the entire fracture hierarchy, spanning from minor to major fractures and encompassing the fracture intensity. The results indicate that the FAWAG process was more sensitive to fracture types and networks than the WAG and GI processes. Hence, the sensitivity of the individual EOR method to the fracture network requires a respective depth of description of the fracture network. However, other factors, such as reservoir fluid properties and fracture properties, might influence the recovery when the minor fracture networks are excluded. This study determined that among the enhanced oil recovery (EOR) techniques examined, the significance of the hierarchical depth of fracture networks diminished as the ratio of major (primary fracture) aperture to the aperture of medium and minor fractures increased. Additionally, the impact of the assisted-gravity drainage method was greater with increased reservoir height; however, as the intensity ratio increased, the relative importance of the medium and minor fracture networks decreased.

Naturally fractured reservoirs are indescribable systems to characterize and difficult to produce and forecast. For the development of such reservoirs, the role of naturally forming fractures in the different development stages needs to be recognized, especially for the pressure maintenance and enhanced oil recovery stages. Recent development in the field of naturally carbonate fractured aimed at fracture characterization, fracture modeling, and fracture network impact of fracture networks on oil recovery were reviewed. Consequently, fracture identification and characterization played pivotal roles in understanding production mechanisms by integrating multiple geosciences sources and reservoir engineering data. In addition, a realistic fracture modeling approach, such as a hybrid, can provide a more accurate representation of the behavior of the fracture and, hence, a more realistic reservoir model for reservoir production and management. In this respect, the influence of different fracture types present in the reservoir, such as major, medium, minor, and hairline fractures networks, and their orientations were found to have different rules and impacts on oil production in the primary, secondary, and EOR stages. In addition, any simplification or homogenization of the fracture types might end in over or underestimating the oil recovery. Improved fracture network modeling requires numerous considerations, such as data collection, facture characterization, reservoir simulation, model calibration, and model updating based on newly acquired field data are essential for improved fracture network description. Hence, integrating multiple techniques and data sources is recommended for obtaining a reliable reservoir model for optimizing the primary and enhanced oil recovery methods.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO₂ could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO₂ nanoparticles compared to amine-treated SiO₂ by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.