Oil Recovery Applications Research Articles

High performance carbon dioxide foams of nanocomposites of binary colloids for effective carbon utilization in enhanced oil recovery applications

Most of conventional carbon dioxide (CO2) foams show limitations in practical applications due to several issues such as thermal stability, disintegration of bubble, dissolution of lamella, and deterioration of rheological property. However, stability of these foams can be improved by including a nanomaterial that makes them stable via Pickering stabilization. Homo-agglomeration, causing large size aggregates, is an important issue with colloidal formulations which reduces foam efficacy due to unsuccessful nanoparticle (NP) adsorption on CO2 surface. Therefore, this study reports the use of nanocomposite of binary NPs (SiO2 and TiO2) in stabilizing CO2 foams at moderate pressure (70 bar) and temperature (90 °C) conditions, to find their use in oilfield practices. CO2 foam stabilized by nanocomposites was studied for thermal stability using microscopic and rheological analysis at 70 bar/90 °C followed by UV–vis and contact angle tests to investigate colloidal interaction with CO2. TiO2 inclusion resulted into remarkable changes in the thermal stability and rheological behavior of SF foam by delaying the process of CO2 coalescence. In addition, the study suggests that TiO2 NP reduces the size of foam bubble through enhanced adsorption as demonstrated by lamella formation and that foam (STF-3, 0.5 wt% SiO2 + 0.1 wt% TiO2) showed least dependency on varying shear, pressure, and temperature conditions. Moreover, the rheological properties such as viscosity and viscoelastic nature of CO2 foams, stabilized by these nanocomposites, show potential for real field applications. Thus, the proposed study highlights the important mechanism of CO2 foam of binary NP system (nanocomposites) followed by rheological analysis of CO2 foam at real conditions, which is useful for CO2 based oil recovery applications.

Flow of hydrophobically associating polymers through unconsolidated sand pack: Role of extensional rheology and degree of association

Theoretically, both the polymer’s resistance to flow and retention are the reasons for the additional pressure drop and resistance factor (RF) generated during polymer flow in porous media. In the case of hydrolyzed polyacrylamide (HPAM), the increase in RF at high flux rates, a phenomenon called shear thickening were successfully correlated in our previous works using the combination of shear and extensional rheology alone. Associative polymers that have gained increased attention for enhanced oil recovery (EOR) applications have relatively a higher retention value in porous media than HPAM. No attempts were made in the literature to investigate whether the associative polymer’s flow behavior at various hydrophobicity in porous media could be correlated using the bulk rheology alone. Further, the role of hydrophobicity and concentration on the associative polymer’s shear thickening and extensional behavior were not studied.In this paper, high flux single phase porous media experiments were performed using three different associative polymers of varying hydrophobicity at 1000 ppm and 2000 ppm concentration in the unconsolidated sand pack. Extensional rheology was performed on these polymers using capillary break-up extensional rheometer. Extensional rheological parameters become lower with increasing hydrophobicity at both 1000 and 2000 ppm. Porous media result indicates that extensional rheology is directly correlated with the RF in associative polymer at 2000 ppm but not at 1000 ppm. At 1000 ppm, the highest RF is exhibited by higher hydrophobic polymer that possess least extensional resistance. Unusually higher retention value observed at 1000 ppm explain the increased RF associated higher hydrophobic polymer or else it could be due to the clustered hydrophobic species formation that appears to be active only if the concentration is not high enough to breakage. It is also our observation that higher retention cannot be predicted through bulk rheological measurements and therefore, this work signifies that a combination of retention and extensional rheological parameters are needed to model the flow behavior of associative polymers in porous media at higher fluxes. Moreover, the relative influence of retention and extensional rheology on the flow behavior of associative polymer is strictly a concentration and hydrophobicity dependent.

Enhancement of Heavy Oil Recovery with High CO2 Injection Rates in Silica Nanochannel

Abstract CO2 injection enhanced oil recovery has become one of the most important approaches to develop heavy oil from reservoirs. However, the microscopic displacement behavior of heavy oil in the nanochannel is still not fully understood. In this paper, we use CO2 as the displacing agent to investigate the displacement of heavy oil molecules confined between the hydroxylated silica nanochannel by nonequilibrium molecular dynamics simulations. We find that for heavy oil molecules, it requires more much higher displacing speed to fully dissipate the residual oil which is found related to the decreased CO2 adsorption on the silica nanochannel. A faster CO2 gas injection rate will lower the CO2 adsorption inside the nanochannel, and more CO2 will participate in the displacement of the heavy oil. The results from this work will enhance our understanding of the CO2 gas displacing heavy oil recovery and design guidelines for heavy oil recovery applications.

Fluoropolymer Microemulsion: Preparation and Application in Reservoir Wettability Reversal and Enhancing Oil Recovery.

Reservoir wettability is an important factor in the process of reservoir reconstruction. Especially in hydrophilic formation, it is easy to cause a water-locked phenomenon. A new type of fluoropolymer microemulsion was prepared by emulsion polymerization, and its structure and properties were characterized. The average particle size in the prepared emulsion was about 2.0 μm. The emulsion had good stability and wettability reversal performance for the storage of 30 days. After the treatment of 2.0 wt % emulsion, the contact angle between the core and water changed from 26 to 128°, the core surface free energy decreased from 66 to 2.6 mN/m, and the saturated water imbibition amount of the core decreased from 1.38 to 0.15 g. The ability of the fluoropolymer microemulsion to enhance oil recovery was evaluated by the visual displacement experiment. The fluoropolymer microemulsion can increase the displacement efficiency by more than 10%. The wettability of the core changed from hydrophilicity to hydrophobicity, and wettability reversal was achieved.

Rheology, characteristics, stability, and pH-responsiveness of biosurfactant-stabilized crude oil/water nanoemulsions

The successful utilization of nanoemulsions in several applications would require the formulation of emulsions with excellent characteristics. Ideally, the nanoemulsions should be stabilized using bioemulsifiers, which do not negatively impact the environment throughout their cradle-to-grave lifetime. Thus, crude oil-in-water (O/W) nanoemulsions with exceptional properties were prepared in this study using rhamnolipid biosurfactant as a bioemulsifier. The obtained results reveal that rhamnolipid can produce O/W nanoemulsions with an average droplet size as low as 35.0 ± 6.6 nm. The nanoemulsions also have highly negative zeta potential, low interfacial tension, and long-term kinetic stability. Interestingly, almost all the formulated O/W nanoemulsions using different rhamnolipid dosages and oil/water ratios showed three different flow behaviors (i.e., shear-thinning, Newtonian, and shear-thickening at low, medium, and high shear rates, respectively). Additionally, the nanoemulsion formulated using 50/50 crude oil/water volumetric ratio displayed higher apparent viscosity than the crude oil at elevated temperatures (greater than 63 ⁰C). Furthermore, despite that all the formulated nanoemulsions were extremely stable, they can be easily, completely, and quickly (within ≤ 1 h) switched-off if needed via pH-switching. The results presented herein demonstrate the potential of biosurfactants for enhanced oil recovery (EOR) and other oilfield applications.

Preparation of polyoxypropylene surfactant-based nanoemulsions using phase inversion composition method and their application in oil recovery

Emulsification using phase inversion composition (PIC) was achieved by changing the composition of surfactants at a constant temperature. The method has great potential to scale up applications due to the ease in the formation of nanoemulsions and the relatively low energy involved. Surfactants containing composition-sensitive polyoxyethylene (POE) chains are widely used to prepare nanoemulsions using the PIC method. It is, therefore, anticipated that surfactants containing composition-sensitive polyoxypropylene (POP) chains can also be used to prepare nanoemulsions using the PIC method. The POP surfactant D230-2OA, containing short POP chains, was obtained from the electrostatic interactions between hydrophilic POP diamine (D230) and hydrophobic oleic acid (OA). The synthesized D230-2OA was used as an emulsifier in the preparation of the n-dodecane-in-water nanoemulsion using the PIC method. The effects of D230-2OA concentration, oil-to-surfactant weight ratio, and NaCl concentration on the droplet size of the nanoemulsions was investigated using dynamic light scattering (DLS). The morphology of the nanoemulsion was characterized using cryogenic transmission electron microscopy (cryo-TEM). The wettability of the crude oil–saturated quartz plate before and after treatment with nanoemulsions was obtained using contact angle measurement. A core flooding experiment demonstrated the efficiency of the diluted nanoemulsion in enhanced oil recovery, with an additional recovery of 21.30%. The nanoemulsion prepared with the POP surfactant as the emulsifier using the PIC method has wide application in petroleum recovery.

Surface Modified Arundo Donax Natural Fibers for Oil Spill Recovery

ABSTRACT The use of green materials for oil recovery applications is the goal to be achieved to reduce the environmental impact of these essential processes. In this context, Arundo Donax L. is a plant known for its wide uses whose absorbent properties have been previously investigated. In this paper, the influence of silane surface treatment on the absorbent behavior of natural fibers extracted from the culms of this eco-friendly and cost-effective material was assessed. A close correspondence has been identified between the physical characteristics of the investigated oil and the fiber size, by means of microstructural and morphological analysis. Excellent results have been achieved with an absorption uptake of six to almost eight times its own weight, coupled with an improved selectivity of pollutant/water absorption, making the surface modified Arundo Donax fibers a potential effective material for oil recovery applications.

Microscale investigation of DNAPL displacement by engineered graphene quantum dots in heterogeneous porous media

This x-ray microtomography study investigates the dynamic pore-scale displacement of a dense non-aqueous phase liquid (DNAPL) such as heavy crude oil in a heterogeneous aquifer rock using carbonaceous nanoparticles. The nanoparticles were synthesized from Wyoming coal and consisted of a mixture of graphene quantum dots (GQD) and engineered graphene quantum dots (E-GQD) in equal proportions. Synergistic interactions between GQD and E-GQD at the oil/water interface reduced the DNAPL/brine interfacial tension (IFT) from 13.4 mN/m to 5.4 mN/m. In addition, the nanofluid mixture altered the wettability of the minerals found in the rock (quartz, carbonate, and feldspar) from oil-wet to water-wet with average contact angles of 66°, 51°, and 60°, respectively. The wettability alteration was more pronounced in carbonates due to the tendency of GQD to adsorb on these surfaces. Analyses of the saturation profiles and pore-scale fluid occupancy maps revealed that the wettability alteration was not instantaneous and required a short soaking time for the fluid-rock interactions to take place. IFT reduction alone was not enough to displace the DNAPL at the early stages of nanofluid flooding because of the high density and viscosity of the oil. As a result, the nanofluid did not outperform brine after 1 pore volume (PV) of injection. On the other hand, the nanofluid was able to invade small pores that were not accessible to brine after 3 PV of injection due to both IFT and contact angle reduction, which lowered the threshold capillary pressure of these pores. Subsequently, more medium and large pores were invaded by the nanofluid as the injection continued, leading to an 11% increase in DNAPL recovery after 20 PV of nanofluid injection, as compared to waterflooding. This incremental recovery is significant considering that the experiments were performed with a heavy oil at ambient temperature, which is more representative of aquifer conditions. Thus, the GQD-based nanofluid has the potential to achieve much larger recoveries in deeper heavy oil reservoirs provided enough soaking time is allowed. The insights provided by this study could be used to validate pore-scale network models or guide in the design and selection of more effective nanomaterials for aquifer remediation or enhanced oil recovery applications.

Deriving optimal and adaptive nanoparticles-assisted foam solution for enhanced oil recovery applications: an experimental study

Here, Fe2O3 and SiO2 nanoparticles are synthesized and utilized to investigate their effects on foam stability and flowing behavior in porous media. At first, the effect of main operative parameters including surfactant concentration, formation water composition and dosage, and temperature on foam stability are studied at static condition for preparation of an optimal foam solution. Then, the synthesized nanoparticles are dispersed in optimal foam solution for subsequent main experiments. High pressure-high temperature microscopic injection experiments are employed to assess the oil-flow displacement in heterogeneous porous medium pattern by foam injection in the absence and presence of the nanoparticles. The results show that sodium dodecyl sulfonate surfactant concentration of 0.75 wt% provides the optimal dosage independent of other factors. The foam solution becomes unstable with increasing the salinity. Conversely, the presence of more sulfate ions improves the foam stability and foam textural characteristics. In the presence of the synthesized nanoparticles significant enhancement of foam solution stability is observed. Microscopic analysis of the injection experiments in glass micromodel reveals postponement of the displacing fluid breakthrough time, lessening the severity of the finger phenomenon at displacement front, and higher oil recovery for Fe2O3 and SiO2 nanoparticles-assisted foam solutions. However, the enhancement of the foam textural features and flowing behavior are more manifest in the case of SiO2 nanoparticles compared to the Fe2O3 nanoparticles.

Buckley–Leverett Theory for a Forchheimer–Darcy Multiphase Flow Model with Phase Coupling

This paper is dedicated to the modeling, analysis, and numerical simulation of a two-phase non-Darcian flow through a porous medium with phase-coupling. Specifically, we introduce an extended Forchheimer–Darcy model where the interaction between phases is taken into consideration. From the modeling point of view, the extension consists of the addition to each phase equation of a term depending on the gradient of the pressure of the other phase, leading to a coupled system of differential equations. The obtained system is much more involved than the classical Darcy system since it involves the Forchheimer equation in addition to the Darcy one. This model is more appropriate when there is a substantial difference between the phases’ velocities, for instance in the case of gas/water phases, and applications in oil recovery using gas flooding. Based on the Buckley–Leverett theory, including capillary pressure, we derive an explicit expression of the phases’ velocities and fractional water flows in terms of the gradient of the capillary pressure, and the total constant velocity. Various scenarios are considered, and the respective numerical simulations are presented. In particular, comparisons with the classical models (without phase coupling) are provided in terms of breakthrough time among others. Eventually, we provide a post-processing method for the derivation of the solution of the new coupled system using the classical non-coupled system. This method is of interest for industry since it allows for including the phase coupling approach in existing numerical codes and software (designed for solving classical models) without major technical changes.

Application of Nanofluid Injection for Enhanced Oil Recovery (EOR)

The use of nanofluids has been investigated and established for several applications in the oil and gas industry. Using nanoparticles for Enhanced Oil Recovery (EOR) applications underlines their small size in comparison with the size of the rock pore throats; consequently, they could easily transport into porous rocks with minimum retention effect and permeability reduction. Nanoparticles can significantly increase the oil recovery by enhancing both the fluid properties and fluid-rock interaction properties. In this study, commercial silica nanoparticles dispersions were used in standard core flooding experiments to evaluate the effect of the nanofluid injection on the incremental oil recovery. This will open the door for taking the nanotechnology from the lab to the oil field.

Micellization of Rhamnolipid Biosurfactants and Their Applications in Oil Recovery: Insights from Mesoscale Simulations.

The dissipative particle dynamics (DPD) mesoscopic method is used to investigate the self-assembly of rhamnolipid congeners and their aggregation behaviors with paraffins including nonane and pentadecane. The coarse-grained force field is parameterized by combining molecular dynamics (MD) simulations, COSMOtherm calculations, and available experimental data. This model reproduces the vesicular formation of α-l-rhamnopyranosyl-β-hydroxydecanoyl-β-hydroxydecanoate (Rha-C10-C10) reported by all-atom MD simulations. The vesicle composed of Rha-C10-C10 is found to be most stable at a surfactant concentration of 100-146 mM based on asphericity analysis. The architecture of rhamnolipid congeners affects the morphology of their aggregates. Di-rhamno-di-lipidic dRha-C16-C16 forms vesicles with a thicker unilamellar layer of 3.2 nm. Rha-C16-C16 forms vesicles at a lower concentration of 70 mM, but the enclosed water space collapses when the surfactant concentration increases. dRha-C10-C10 forms wormlike micelles, which agglomerate into a torus and interconnected network at higher concentrations. In the presence of alkane molecules, dRha-C10-C10 maintains its wormlike micellar morphology with alkane molecules wrapped inside the aggregates. For Rha-C10-C10, Rha-C16-C16, and dRha-C16-C16, nonane molecules are distributed in the hydrophobic subdomain formed by rhamnolipid molecules. Spherical vesicles are formed at a surfactant concentration of 50 mM and then develop into ellipsoidal vesicles when the concentration increases to 125 mM. When mixed with pentadecane, the alkane molecules are aggregated and surrounded by surfactants forming a core-shell structure at a low surfactant concentration of 20 mM. At higher alkane and surfactant concentrations, the morphologies develop into disk micelles, wormlike micelles, and vesicles, with pentadecane molecules being distributed and packed with rhamnolipids. The obtained simulation results suggest that these biosurfactants have potential as environmental remediation agents.

Rheological and thermal stability of interpenetrating polymer network hydrogel based on polyacrylamide/hydroxypropyl guar reinforced with graphene oxide for application in oil recovery

Abstract The purpose of the present work is to enhance the thermal stability and rheological properties of semi-interpenetrating polymer network (IPN) hydrogel based on partially hydrolyzed polyacrylamide/hydroxypropyl guar (HPAM/HPG) nanocomposite reinforced with graphene oxide (GO), at temperatures (200 and 240 °F) for use in oil recovery applications. FTIR spectra of the IPN nanocomposite hydrogels revealed interactions of GO with HPAM/HPG chains. An increase in the viscosity is also observed from the rheological study. Moreover, IPN and its nanocomposite hydrogels exhibited non-Newtonian behavior. The decline of viscosity of IPN nanocomposite hydrogels was observed with an increase in the temperature from 200 to 240 °F but was still higher than IPN hydrogel without GO. Dispersion of GO through the HPAM/HPG hydrogel matrix was evaluated by SEM morphology and electrical conductivity. The IPN nanocomposite hydrogels showed high viscosity stability, thermal stability, and flow activation energy as compared to IPN hydrogel without GO. Therefore, the addition of 0.1 wt.% of GO to the HPAM/HPG matrix is suitable to create a cross-linked polymer solution with improved properties which may be beneficial for use in oil recovery applications.

Preparation and application of nanofluid flooding based on polyoxyethylated graphene oxide nanosheets for enhanced oil recovery

In this paper, an innovative polyoxyethylated graphene oxide-based nanofluid (P-GO-O) for enhanced oil recovery was prepared. Transmission electron microscopy (TEM), Fourier transform infrared spectrometer (FTIR), Raman spectra, thermogravimetric analysis (TGA), and UV–vis spectra analysis were used to characterize the P-GO-O nanosheets. Moreover, zeta potential, temperature resistance, and salinity tolerance were evaluated to determine the dispersion stability of the P-GO-O nanofluid. The zeta potential of P-GO-O in deionized water was −39 mV, and the P-GO-O nanofluid exhibited excellent high temperature and high salinity resistance. Benefiting from its structure, the P-GO-O nanofluid was capable of lowering the oil–water interfacial tension to 12.2 mN/m and changing the oil-wet surface to the water-wet surface. In the oil displacement test, the oil recovery ratio of P-GO-O nanofluid (17.2%) was higher than the GO-O (octadecylaminated graphene oxide) nanofluid (6.7%), which was attributed to its better stability and wettability alteration. These results indicated that the P-GO-O nanofluid had the potential for enhanced oil recovery (EOR) application.

The effects of in-situ emulsion formation and superficial velocity on foam performance in high-permeability porous media

Foam has been considered as a mobility control agent for Enhanced Oil Recovery (EOR) applications in heterogeneous and fractured reservoirs. Foam enhances sweep efficiency by enabling the injected gas to flow from high-permeability to low-permeability regions. The foam injection velocity is an essential factor affecting foam mobility control and flow behavior. Furthermore, the presence of remaining oil adversely impacts foam generation leading to a failure in governing mobility control. In this study, foam performance in establishing mobility control effect and favorable apparent viscosity was experimentally investigated under a range of total superficial velocities in the presence and absence of crude oil during foam propagation in high permeability sand packs representing a propped fracture network. In the absence of oil, a pronounced effect of total superficial velocity on the mobility control performance was observed at the transition foam quality regime. Co-injection of oil and foam led to noticeable foam destabilization, as expected. However, a further increase in oil fractional flow resulted in larger overall flow resistance. We found that the formation of in-situ surfactant/oil emulsion contributed to the high apparent viscosity exhibited at the steady-state condition. These findings suggest that the steady-state flow resistance established during foam flooding at high oil saturations should be interpreted as the mobility control effect resulting from emulsion formation rather than the development of strong foam.

Portable rheometer to overcome the challenge of measuring low viscosity solution of acrylamide-based polymers at high temperature with an affordable cost for O&G applications

Performances of rotational shear rheometers are sometimes limited to measuring low viscosity at high temperatures of water-based polymer solutions. These limitations are typically due to the instrument resolution, sample inertia, and volumetric effects. Moreover, such measurements are not possible for temperatures exceeding 80 °C because of evaporation phenomena leading to a distortion of the value. The working principle of rheometers suitable for measuring viscosity above the boiling temperature reduces their sensitivity and limits their use to high-viscosity fluids. Acrylamide-based polymers are viscoelastic complex fluids exhibiting non-Newtonian behavior. Their viscosifying properties are strongly related to their charge density, molar mass, temperature, and salinity. The prediction of their rheological properties at high temperatures is challenging and is often extrapolated with an empiric law, such as Arrhenius equation. To the best of our knowledge, no commercially available rheometers are capable of measuring low viscosity of water-soluble complex fluids at high temperatures. In this work, we investigate a home-made fully automated capillary rheometer that has been developed to give an accurate measurement of viscosity and intrinsic viscosity of polymer solutions. This device is an affordable cost portable apparatus compared with a commercialized rheometer specifically designed for a wide range of viscosities and temperatures for various applications. The intrinsic viscosity has been measured on two acrylamide-based polymers of different chemical compositions using the capillary rheometer at high temperatures. This device has also been explored for measurement of a water-soluble polymer solution viscosity commonly used in enhanced oil recovery applications to limit chemical degradation.

Toward Reducing Surfactant Adsorption on Clay Minerals by Lignin for Enhanced Oil Recovery Application.

The significant loss of surfactants during reservoir flooding is a challenge in oil field operations. The presence of clay minerals affects the surfactant performance, resulting in surfactant losses. This is because the mineralogical composition of the reservoir results in unpredicted adsorption quantity. Therefore, this paper seeks to investigate Aerosol-OT’s adsorption on different quartz/clay mineral compositions during the flow. Also, it investigates adsorption mitigation by preflushing with lignin. The dynamic experiments were conducted on sand packs composed of quartz-sand and up to a 7% clay mineral content. The results obtained from the surfactant losses were compared with/without lignin preflush at different pH values. The main observation was the direct relationship between increasing the composition of clay minerals and the surfactant pore volume required to overcome the adsorption. The highest adsorption calculated was 46 g/kg for 7% kaolinite. Moreover, lignin successfully reduced the adsorption of Aerosol-OT by 60%. Therefore, the results demonstrate that the effects of the clay mineral content on adsorption could be efficiently minimized using lignin at a high pH.

Thermosensitive Core-Shell Fe3O4@poly(N-isopropylacrylamide) Nanogels for Enhanced Oil Recovery.

An investigation on the application of thermosensitive core-shell Fe3O4@PNIPAM nanogels in enhanced oil recovery was successfully performed. Here, the unique core-shell architecture was fabricated by conducting the polymerization at the surface of 3-butenoic acid-functionalized Fe3O4 nanoparticles and characterized using X-ray diffraction (XRD), 1H NMR, vibration sample magnetometer (VSM), and high-resolution transmission electron microscopy (HR-TEM). According to the results, this core-shell structure was beneficial for achieving the desired high viscosity and low nanofluid mobility ratio at high temperatures, which is essential for enhanced oil recovery (EOR) application. The results demonstrated that the nanogels exhibited a unique temperature-dependent flow behavior due to the PNIPAM shell's ability to transform from a hydrated to a dehydrated state above its low critical solution temperature (LCST). At such conditions, the nanogels exhibited a significantly low mobility ratio (M = 0.86), resulting in an even displacement front during EOR and leads to higher oil production. Based on the result obtained from sand pack flooding, about 25.75% of an additional secondary oil recovery could be produced when the nanofluid was injected at a temperature of 45 °C. However, a further increase in the flooding temperature could result in a slight reduction in oil recovery due to the precipitation of some of the severely aggregated nanogels at high temperatures.

Flow and structural analysis of sedimentary rocks by core flooding and nuclear magnetic resonance: A review.

Fluid flow analyses and investigations of associated structural variations in rock formations are important due to the complex nature of rocks and the high heterogeneity that exists within fluid-rock systems. Variations in fluid-rock parameters need to be ascertained over time with continuous or cyclic fluid injection into subsurface rocks for enhanced oil recovery and other subsurface applications. This Review introduces the use of the core flooding-nuclear magnetic resonance (NMR) technique for analysis of combined fluid flow and structural features in subsurface fluid-rock systems. It presents a summary of the results realized by various researchers in this area of study. The influence of several conditions, such as geochemical interactions, wettability, inherent heterogeneities in fluid flow and rock properties, and variations in these parameters, is analyzed. We investigate NMR measurements for both single fluid phase saturation and multiphase saturation. Additionally, the processes for identifying and distinguishing different fluid phases are emphasized in this study. Furthermore, capillary pressure and its influence on fluid-rock parameters are also discussed. Although this study emphasizes subsurface rocks and enhanced oil recovery, the experimental combination is also extended to core flooding using several other injection fluids and porous media. Finally, research gaps pertaining to core flooding-NMR systems regarding fluid flow, structural changes, fluid-rock systems, and instrumentation are pointed out. Transient flow analysis involving structural variations is suggested for future work in this regard.

CO2 mobility control improvement using N2-foam at high pressure and high temperature conditions

The high mobility of CO2 in porous media is an issue in most subsurface CO2 projects worldwide, demonstrated by uncontrolled and rapid migration through the reservoir, early well breakthroughs and poor sweep efficiency. Improved mobility control of CO2 is needed to accelerate and improve the value-creation from subsurface CO2 projects, both in terms of energy produced and volumes of CO2 stored. Field-proven conformance and mobility control techniques, such as foam, provide a cost-effective and sustainable alternative to overcome geological and process constraints observed with CO2 flow in reservoirs.In this laboratory study, we have investigated CO2 mobility control by foam in sandstone core samples at typical North Sea reservoir conditions, 220 barg and 100°C, respectively. Two important aspects related to any field application of foam have been evaluated and discussed: I) Can strong CO2-foams be generated at reservoir conditions using AOS surfactant? If not, II) can relatively simple modifications to the foam system be made to improve foam properties and CO2 mobility control?Our results show that only high-mobility CO2-foams with low degree of CO2 mobility reduction are obtained at 220 barg and 100°C. An easy way to improve the foam properties at reservoir conditions is suggested by changing the gas-phase in foam to nitrogen (N2). The N2-foams display improved foam generation performance, larger mobility control in terms of mobility reduction factors (MRF) and ability to block subsequent CO2 injection.An alternative strategy for applying foam for CO2 conformance and mobility control in subsurface CO2 projects, which emerges from this study, is to initiate the foam treatment with nitrogen followed by subsequent CO2 injection to change the main direction of CO2 flow to enhance the displacement area or reduce uncontrolled CO2 production between the injecting and producing wells (as illustrated in the graphical abstract). The possible mechanisms explaining the observed differences in foam properties using CO2 versus N2, including implications that could be helpful for future studies and CO2 field applications are discussed further in more detail.The efficiency and limitations of miscible CO2 flooding to recover oil and simultaneously store CO2 after extensive water flooding are also demonstrated in this article, which are relevant to enhanced oil recovery (EOR) and subsequent CO2 storage applications, known as the Carbon Capture Utilization and Storage (CCUS).