This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO 2 ) for enhanced oil recovery, depending on the CO 2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO 2 injection (R F ¼ 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 Â10 À9 m 2 =s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO 2 injection declined exponentially with increasing diffusion lengths from the CO 2 -filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oilrecovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.

Summary A carbon–dioxide (CO2) –foam enhanced–oil–recovery (EOR) field pilot research program has been started to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic–CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory– and field–scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2–foam field trial, including pilot–well–selection criteria and laboratory corefloods combined with reservoir–scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant–alternating–gas (SAG) injection, while assessing CO2–storage potential. Laboratory investigations include dynamic aging, foam–stability scans, CO2–foam EOR corefloods with associated CO2 storage, and unsteady–state CO2/water endpoint relative permeability measurements. Tertiary CO2–foam EOR corefloods at oil–wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility–reduction factors (MRFs) up to 340 compared with pure–CO2 injection at reservoir conditions. Oil recovery, gas–mobility reduction, producing–gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.

No abstract

Summary In this paper, we describe a laboratory investigation of a nonionic surfactant for carbon dioxide-(CO2-) foam mobility control in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. A method of high-performance liquid chromatography-evaporativelight-scattering detector (HPLC-ELSD) was followed for characterizing the surfactant stability. The foam transport process was studied in the absence and the presence of East Seminole crude oil, with test results showing that strong CO2-foam forms in either a bulk-foam test or foam-flow test. An oxygen scavenger, carbohydrazide, was found effective for controlling the stability of the surfactant up to 80°C and total dissolved solid of ∼34,000 ppm. Moreover, a phosphonate scale inhibitor was investigated and found to be compatible with the oxygen scavenger to accommodate a surfactant solution in a gypsum-oversaturated reservoir brine. During the oil-fractional flow test, an emulsion appears to form, causing a noticeable pressure increase; however, emulsion generation failed to cause a significant phase plugging in the test. Also, a STARS™ (Computer Modelling Group Ltd., Calgary, Alberta, Canada) foam model was applied to obtain the foam parameters from the foam-flow experiments at steady-state conditions. The insights from laboratory experiments better enable translation of the foam technology to the field.

This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

No abstract

Summary This paper presents an ongoing CO2–foam upscaling research project that aims to advance CO2–foam technology for accelerating and increasing oil recovery, while reducing operational costs and lessening the carbon footprint left during CO2 enhanced oil recovery (EOR). Laboratory CO2–foam behavior was upscaled to pilot scale in an onshore carbonate reservoir in Texas, USA. Important CO2–foam properties, such as local foam generation, bubble texture, apparent viscosity, and shear–thinning behavior with a nonionic surfactant, were evaluated using pore–to–core upscaling to develop accurate numerical tools for a field–pilot prediction of increased sweep efficiency and CO2 utilization. At pore–scale, high–pressure silicon–wafer micromodels showed in–situ foam generation and stable liquid films over time during no–flow conditions. Intrapore foam bubbles corroborated high apparent foam viscosities measured at core scale. CO2–foam apparent viscosity was measured at different rates (foam–rate scans) and different gas fractions (foam–quality scans) at core scale. The highest mobility reduction (foam apparent viscosity) was observed between 0.60 and 0.70 gas fractions. The maximum foam apparent viscosity was 44.3 (±0.5) mPa·s, 600 times higher than that of pure CO2, compared with the baseline viscosity (reference case, without surfactant), which was 1.7 (±0.6) mPa·s, measured at identical conditions. The CO2–foam showed shear–thinning behavior with approximately 50% reduction in apparent viscosity when the superficial velocity was increased from 1 to 8 ft/D. Strong foam was generated in EOR corefloods at a gas fraction of 0.70, resulting in an apparent viscosity of 39.1 mPa·s. Foam parameters derived from core–scale foam floods were used for numerical upscaling and field–pilot performance assessment.