scholarly journals Core-scale sensitivity study of CO2 foam injection strategies for mobility control, enhanced oil recovery, and CO2 storage

2020 ◽  
Vol 146 ◽  
pp. 02002
Author(s):  
Zachary Paul Alcorn ◽  
Sunniva B. Fredriksen ◽  
Mohan Sharma ◽  
Tore Føyen ◽  
Connie Wergeland ◽  
...  
Keyword(s):  
Steady State ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Injection Strategy ◽  
Gravity Effects

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.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

A Laboratory and Numerical-Simulation Study of Co-Optimizing CO2 Storage and CO2 Enhanced Oil Recovery

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1227-1237 ◽  
Author(s):  
Fatemeh Kamali ◽  
Furqan Hussain ◽  
Yildiray Cinar
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Immiscible Displacement ◽  
Sandstone Sample ◽  
Miscible Displacements ◽  
Gravity Effects ◽  
Optimization Function ◽  
Carbon Dioxide Co2 ◽  
And Storage

Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.

scholarly journals Synthesis and Characterization of Polymeric Surfactant from Palm Oil Methyl Ester and Vinyl Acetate for Chemical Flooding

REAKTOR ◽  
2021 ◽  
Vol 21 (2) ◽  
pp. 65-73
Author(s):  
Agam Duma Kalista Wibowo ◽  
Pina Tiani ◽  
Lisa Aditya ◽  
Aniek Sri Handayani ◽  
Marcelinus Christwardana
Keyword(s):  
Methyl Ester ◽  
Interfacial Tension ◽  
Vinyl Acetate ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Polymeric Surfactant ◽  
Chemical Flooding

Surfactants for enhanced oil recovery are generally made from non-renewable petroleum sulfonates and their prices are relatively expensive, so it is necessary to synthesis the bio-based surfactants that are renewable and ecofriendly. The surfactant solution can reduce the interfacial tension (IFT) between oil and water while vinyl acetate monomer has an ability to increase the viscosity as a mobility control. Therefore, polymeric surfactant has both combination properties in reducing the oil/water IFT and increasing the viscosity of the aqueous solution simultaneously. Based on the study, the Critical Micelle Concentration (CMC) of Polymeric Surfactant was at 0.5% concentration with an IFT of 7.72x10-2 mN/m. The best mole ratio of methyl ester sulfonate to vinyl acetate for polymeric surfactant synthesis was 1:0.5 with an IFT of 6.7x10-3 mN/m. Characterization of the product using FTIR and HNMR has proven the creation of polymeric surfactant. Based on the wettability alteration study, it confirmed that the product has an ability to alter from the initial oil-wet to water-wet quartz surface. In conclusion, the polymeric surfactant has ultralow IFT and could be an alternative surfactant for chemical flooding because the IFT value met with the required standard for chemical flooding ranges from 10-2 to 10-3 mN/m.Keywords: Enhanced Oil recovery, Interfacial Tension, Methyl Ester Sulfonate, Polymeric surfactant, vinyl acetate

In-Situ Visualization of Multidimensional Imbibition in Dual-Porosity Carbonates

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1631-1642 ◽  
Author(s):  
Amar J. Alshehri ◽  
Anthony R. Kovscek
Keyword(s):  
Oil Recovery ◽  
Experimental Results ◽  
Wettability Alteration ◽  
X Ray ◽  
Surfactant Solutions ◽  
Phase Saturation ◽  
Gravity Effects ◽  
The Matrix ◽  
Ultralow Ift

Summary Oil recovery by waterflood is usually small in fractured carbonates because of selective channeling of injected water through fractures toward producers, leaving much of the oil trapped in the matrix. One option to mitigate the low recovery is to reduce fracture uptake by increasing the viscosity of the injected fluids by use of polymers or foams. Another option, that is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory, provided that cores are moderately long and oriented vertically. Besides investigating the role of gravity on oil recovery, the effect of surfactant-flood mode (secondary-flood mode and tertiary-flood mode) on the ultimate recovery (UR) was also investigated. To investigate the predictions of this analysis, coreflood experiments were conducted by use of carbonate cores and monitored by an X-ray computed-tomography (CT) scanner featuring true vertical positioning to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems by use of the whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant. To study gravity effects, surfactant reduced interfacial tension (IFT) from 40 to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Another surfactant was used to study the flood-mode effect; this surfactant reduced IFT from 40 to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary-surfactant-flood experiment and a secondary-surfactant-flood experiment. The secondary-flood experiment showed an improvement in recovery with the early implementation of the surfactant flood relative to the tertiary-flood experiment. This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the effect of flood mode on UR. Moreover, this work emphasizes the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily because of wettability alteration but mainly because of gravity effects. Experimental results are presented primarily as 1D and 3D reconstructions of in-situ oil- and water-phase saturation obtained by use of X-ray CT.

Recent Advances in Surfactant EOR

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 889-907 ◽  
Author(s):  
George J. Hirasaki ◽  
Clarence A. Miller ◽  
Maura Puerto
Keyword(s):  
Phase Separation ◽  
Crude Oil ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Naphthenic Acids ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Recent Advances ◽  
Carbonate Formations

Summary In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, and the process became known as alkaline/surfactant/polymer flooding (ASP). It was recently found that the adsorption of anionic surfactants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are also capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultralow interfacial tension (IFT) makes it possible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil/water gravity drainage. The alkaline/surfactant process consists of injecting alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant determines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and to inject polymer with the surfactant without phase separation. An additional benefit of the presence of the soap component is that it generates an oil-rich colloidal dispersion that produces ultralow IFT over a much wider range of salinity than in its absence. It was once thought that a cosolvent such as alcohol was necessary to make a microemulsion without gel-like phases or a polymer-rich phase separating from the surfactant solution. An example of an alternative to the use of alcohol is to blend two dissimilar surfactants: a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single-phase region with NaCl or CaCl2 is greater for the blend than for either surfactant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without phase separation under some conditions. The injected surfactant solution has underoptimum phase behavior with the crude oil. It becomes optimum only as it mixes with the in-situ-generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work. Foam can be used for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil displacement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.

scholarly journals CO$$_{2}$$ Convection in Hydrocarbon Under Flowing Conditions

2021 ◽  
Author(s):  
Trine S. Mykkeltvedt ◽  
Sarah E. Gasda ◽  
Tor Harald Sandve
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Cost Effective ◽  
Fine Grid ◽  
Cost Effective Method ◽  
Gravity Effects ◽  
Petroleum Resources ◽  
Nearby Point ◽  
Diffusive Processes

AbstractCarbon-neutral oil production is one way to improve the sustainability of petroleum resources. The emissions from produced hydrocarbons can be offset by injecting capture CO$$_{2}$$ 2 from a nearby point source into a saline aquifer for storage or a producing oil reservoir. The latter is referred to as enhanced oil recovery (EOR) and would enhance the economic viability of CO$$_{2}$$ 2 sequestration. The injected CO$$_{2}$$ 2 will interact with the oil and cause it to flow more freely within the reservoir. Consequently, the overall recovery of oil from the reservoir will increase. This enhanced oil recovery (EOR) technique is perceived as the most cost-effective method for disposing captured CO$$_{2}$$ 2 emissions and has been performed for many decades with the focus on oil recovery. The interaction between existing oil and injected CO$$_{2}$$ 2 needs to be fully understood to effectively manage CO$$_{2}$$ 2 migration and storage efficiency. When CO$$_{2}$$ 2 and oil mix in a fully miscible setting, the density can change non-linearly and cause density instabilities. These instabilities involve complex convective-diffusive processes, which are hard to model and simulate. The interactions occur at the sub-centimeter scale, and it is important to understand its implications for the field scale migration of CO$$_{2}$$ 2 and oil. In this work, we simulate gravity effects, namely gravity override and convective mixing, during miscible displacement of CO$$_{2}$$ 2 and oil. The flow behavior due to the competition between viscous and gravity effects is complex, and can only be accurately simulated with a very fine grid. We demonstrate that convection occurs rapidly, and has a strong effect on breakthrough of CO$$_{2}$$ 2 at the outlet. This work for the first time quantifies these effects for a simple system under realistic conditions.

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