Pore-to-Core EOR Upscaling for CO2 Foam for CCUS

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2793-2803 ◽  
Author(s):  
Arthur Uno Rognmo ◽  
Sunniva Brudvik Fredriksen ◽  
Zachary Paul Alcorn ◽  
Mohan Sharma ◽  
Tore Føyen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Apparent Viscosity ◽  
Shear Thinning ◽  
Liquid Films ◽  
Carbonate Reservoir ◽  
Sweep Efficiency ◽  
Reference Case ◽  
Foam Generation ◽  
Co2 Foam ◽  
Gas Fractions

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.

scholarly journals CO2 Foam and CO2 Polymer Enhanced Foam for Heavy Oil Recovery and CO2 Storage

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5735
Author(s):  
Ali Telmadarreie ◽  
Japan J Trivedi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Storage ◽  
High Mobility ◽  
Pressure Profile ◽  
Gas Production ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Co2 Foam

Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. High oil viscosity, high mobility ratio, inadequate sweep, and reservoir heterogeneity adds more challenges and severe difficulties during any EOR method. Foam injection showed potential as an EOR method for challenging and heterogeneous reservoirs containing light oil. However, the foams and especially polymer enhanced foams (PEF) for heavy oil recovery have been less studied. This study aims to evaluate the performance of CO2 foam and CO2 PEF for heavy oil recovery and CO2 storage by analyzing flow through porous media pressure profile, oil recovery, and CO2 gas production. Foam bulk stability tests showed higher stability of PEF compared to that of surfactant-based foam both in the absence and presence of heavy crude oil. The addition of polymer to surfactant-based foam significantly improved its dynamic stability during foam flow experiments. CO2 PEF propagated faster with higher apparent viscosity and resulted in more oil recovery compared to that of CO2 foam injection. The visual observation of glass column demonstrated stable frontal displacement and higher sweep efficiency of PEF compared to that of conventional foam. In the fractured rock sample, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion. Aside from oil production, the higher stability of PEF resulted in more gas storage compared to conventional foam. This study shows that CO2 PEF could significantly improve heavy oil recovery and CO2 storage.

Supercritical CO2-Foam Screening and Performance Evaluation for CO2 Storage Improvement in Sandstone and Carbonate Formations

2021 ◽  
Author(s):  
Ying Yu ◽  
Alvinda Sri Hanamertani ◽  
Shehzad Ahmed ◽  
Zunsheng Jiao ◽  
Jonathan Fred McLaughlin ◽  
...  
Keyword(s):  
Surface Tension ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Mobility Control ◽  
Zwitterionic Surfactant ◽  
Water Displacement ◽  
Sweep Efficiency ◽  
Foam Generation ◽  
Co2 Foam ◽  
Reservoir Conditions

Abstract Injecting carbon dioxide (CO2) as foam during enhanced oil recovery (EOR) can improve injectate mobility and increase sweep efficiency. Integrating CO2-foam techniques with carbon capture, utilization and storage (CCUS) operations is of recent interest, as the mobility control and sweep efficiency increases seen in EOR could also benefit CO2 storage during CCUS. In this study, a variety of different charge, hydrocarbon chain length, head group surfactants were evaluated by surface tension, bulk and dynamic CO2-foam performance assessments for CCUS. The optimal foam candidate was expected to provide satisfying mobility control effects under reservoir conditions, leading to an improved water displacement efficiency during CO2-foam flooding that favors a more significant CO2 storage potential. All tested surfactants were able to lower their surface tensions against scCO2 by 4-5 times, enlarging the surface area of solution/gas contact; therefore, more CO2 could be trapped in the foam system. A zwitterionic surfactant was found to have slightly higher surface tension against CO2 while exhibiting the highest foaming ability and the most prolonged foam stability with a relatively slower drainage rate among all tested surfactants. The dynamic performance of scCO2-foam stabilized by this zwitterionic surfactant was also evaluated in sandstone and carbonate cores at 13.79 MPa and 90°C. The results show that the mobility control development in carbonate core was relatively slower, suggesting a gradual foam generation process attributed to the higher permeability than the case in sandstone core. A more significant cumulative CO2 storage potential improvement, quantified based on the water production, was recorded in sandstone (53%) over the carbonate (47%). Overall, the selected foam has successfully developed CO2 mobility control and improved water displacement in the occurrence of in-situ foam generation, hence promoting the storage capacity for the injected CO2. This work has optimized the foaming agent selection method at the actual reservoir conditions and evaluated the scCO2-foam performance in establishing high flow resistance and improving the CO2 storage capacity, which benefits integrated CCUS studies or projects utilizing CO2-foam techniques.

Direct Visualization and Quantification of NCF-Strengthened CO2 Foam Generation, Propagation and Sweep in a 2D Heterogeneous Fracture Network Model

2021 ◽  
Author(s):  
Bing Wei ◽  
Qiong Yang ◽  
Runxue Mao ◽  
Qingtao Tian ◽  
Dianlin Wang ◽  
...  
Keyword(s):  
Surfactant Solution ◽  
Gravitational Effect ◽  
Fracture Network ◽  
Co2 Injection ◽  
Sweep Efficiency ◽  
Foam Generation ◽  
Co2 Foam ◽  
Fracture Systems ◽  
Reservoir Conditions ◽  
Reduction Of Co2

Abstract CO2 foam holds promising potential for conformance improvement and mobility reduction of CO2 injection in fractured systems. However, there still exists two main issues hampering its wide application and development, 1. Instability of CO2 foam lamellae under reservoir conditions, and 2. Uncertainties of foam flow in fracture systems. To address these two issues, we previously developed a series of functional nanocellulose materials to stabilize the CO2 foam (referred to NCF-st-CO2 foam), while the primary goal of this paper is to thoroughly elucidate foam generation, propagation and sweep of NCF-st-CO2 foam in fractured systems by using a self-designed visual heterogeneous fracture network. We found that NCF-st-CO2 foam produced noticeably greater pressure drop (ΔP) than CO2 foam during either co-injection (COI) or surfactant solution-alternating-gas (SAG) injection, and the threshold foam quality (fg*) was approximately 0.67. Foam generation was increased with total flow rate for CO2 foam and stayed constant for NCF-st-CO2 foam in fracture during COI. CO2 breakthrough occurred at high flow rates (>8 cm3/min). For SAG, large surfactant slug could prevent CO2 from early breakthrough and facilitate foaming in-situ. The increase in sweep efficiency by NCF-st-CO2 foam was observed near the producer for both COI and WAG, which was attributed to its better foaming capacity. Film division and behind mainly led to foam generation in the fracture model. Gravity segregation and override was insignificant during COI but became noticeable during SAG, which caused the sweep efficiency decreased by 3~9% at 1.0 fracture volume (FV) injected. Due to the enhanced foam film, the NCF-st-CO2 foam was able to mitigate gravitational effect, especially in the vicinity of producer.

Performance of Silica Nanoparticles in CO2 Foam for EOR and CCUS at Tough Reservoir Conditions

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 406-415 ◽  
Author(s):  
Arthur U. Rognmo ◽  
Noor Al-Khayyat ◽  
Sandra Heldal ◽  
Ida Vikingstad ◽  
Øyvind Eide ◽  
...  
Keyword(s):  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Elevated Temperatures ◽  
Co2 Storage ◽  
Sweep Efficiency ◽  
Co2 Foam ◽  
Reservoir Conditions ◽  
Incremental Oil Recovery ◽  
Surface Modified

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

Pseudo-Plastic Behavior of a Film Foam Flow with Carbon Dioxide as the Internal Gas Phase

2011 ◽  
Vol 221 ◽  
pp. 15-20 ◽  
Author(s):  
Dong Xing Du ◽  
Ying Ge Li ◽  
Shi Jiao Sun
Keyword(s):  
Porous Media ◽  
Shear Rate ◽  
Gas Phase ◽  
Oil Recovery ◽  
Apparent Viscosity ◽  
Flow Behavior ◽  
Plastic Behavior ◽  
Straight Tube ◽  
Foam Flow ◽  
Co2 Foam

There are many attractive features for using CO2 foam injection in Enhanced Oil Recovery (EOR) processes. For understanding CO2 foam rheology in porous media, an experimental study is reported in this paper concerning CO2 film foam flow characteristics in a vertical straight tube. Foam is treated as non-Newtonian fluid and its pseudo-plastic behavior is investigated based on power law constitutive model. It is observed the CO2 film foam flow shows clear shear-thinning behavior, with flow consistency coefficient of K=0.15 and flow behavior index of n=0.48. The apparent viscosity of flowing CO2 film foam is under the shear rate of 50s-1 and under the shear rate of 1000s-1, which are 19 and 3 times higher than the single phase water. It is also found CO2 foam has lower apparent viscosity than the foam with air as the internal gas phase, which is in consistence with experimental observations for lower CO2 foam flow resistance in porous media.

Approximate Pore-Level Modeling for Apparent Viscosity of Polymer-Enhanced Foam in Porous Media

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 17-25 ◽  
Author(s):  
Chun Huh ◽  
William R. Rossen
Keyword(s):  
Porous Media ◽  
Pressure Drop ◽  
Power Law ◽  
Bubble Size ◽  
Apparent Viscosity ◽  
Shear Thinning ◽  
Oil Reservoir ◽  
High Shear ◽  
Sweep Efficiency ◽  
Ellis Model

Summary Foam is used in the oil industry in a variety of applications, and polymer is sometimes added to increase foam's stability and effectiveness. A variety of surfactant and polymer combinations have been employed to generate polymer-enhanced foam (PEF), typically anionic surfactants and anionic polymers, to reduce their adsorption in reservoir rock. While addition of polymer to bulk foam is known to increase its viscosity and apparent stability, polymer addition to foams for use in porous media has not been as effective. In this pore-level modeling study, we develop an apparent viscosity expression for PEF at fixed bubble size, as a preliminary step to interpret the available laboratory coreflood data. To derive the apparent viscosity, the pressure-drop calculation of Hirasaki and Lawson (1985) for gas bubbles in a circular tube is extended to include the effects of shear-thinning polymer in water, employing the Bretherton's asymptotic matching technique. For polymer rheology, the Ellis model is employed, which predicts a limiting Newtonian viscosity at the low-shear limit and the well-known power-law relation at high shear rates. While the pressure drop caused by foam can be characterized fully with only the capillary number for Newtonian liquid, the shear-thinning liquid requires one additional grouping of the Ellis-model parameters and bubble velocity. The model predicts that the apparent viscosity for PEF shows behavior more shear-thinning than that for polymer-free foam, because the polymer solution being displaced by gas bubbles in pores tends to experience a high shear rate. Foam apparent viscosity scales with gas velocity (Ug) with an exponent [-a/(a+2)], where a, the Ellis-model exponent, is greater than 1 for shear-thinning fluids. With a Newtonian fluid, for which a = 1, foam apparent viscosity is proportional to the (-1/3) power of Ug, as derived by Hirasaki and Lawson. A simplified capillary-bundle model study shows that the thin-film flow around a moving foam bubble is generally in the high-shear, power-law regime. Because the flow of polymer solution in narrower, water-filled tubes is also governed by shear-thinning rheology, it affects foam mobility as revealed by plot of pressure gradient as a function of water and gas superficial velocities. The relation between the rheology of the liquid phase and that of the foam is not simple, however. The apparent rheology of the foam depends on the rheology of the liquid, the trapping and mobilization of gas as a function of pressure gradient, and capillary pressure, which affects the apparent viscosity of the flowing gas even at fixed bubble size. Introduction When a gas such as CO2 or N2 is injected into a mature oil reservoir for improved oil recovery, its sweep efficiency is usually very poor because of gravity segregation, reservoir heterogeneity, and viscous fingering of gas, and foam is employed to improve sweep efficiency with better mobility control (Shi and Rossen 1998; Zeilinger et al. 1996). When oil is produced from a thin oil reservoir overlain with a gas zone, a rapid coning of gas can drastically reduce oil production rate, and foam is used to delay the gas coning (Aarra et al. 1997; Chukwueke et al. 1998; Dalland and Hanssen 1997; Thach et al. 1996). During a well stimulation operation with acid, a selective placement of acid into a low-permeability zone from which oil has not been swept is desired, which can be accomplished with use of foam (Cheng et al. 2002). For environmental remediation of subsurface soil using surfactant, foam is used to improve displacement of contaminant, such as DNAPL, from heterogeneous soil (Mamun et al. 2002).

Nanoparticle-Stabilized Carbon Dioxide Foam Used In Enhanced Oil Recovery: Effect of Different Ions and Temperatures

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1416-1423 ◽  
Author(s):  
Jingshan San ◽  
Sai Wang ◽  
Jianjia Yu ◽  
Ning Liu ◽  
Robert Lee
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Produced Water ◽  
Foam Stability ◽  
Bivalent Ions ◽  
Foam Generation ◽  
Co2 Foam ◽  
Nacl Concentration ◽  
Different Temperatures ◽  
Carbon Dioxide Co2

Summary This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized carbon dioxide (CO2) foam generation. CO2 foam was generated by coinjecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and at different temperatures. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the sodium chloride (NaCl) concentration increased from 1.0 to 10%. In addition, the foam bubble became smaller and foam stability improved with the increase in NaCl concentration. The CO2-foam mobility decreased from 13.1 to 2.6 md/cp when the NaCl concentration increased from 1 to 10%. For the bivalent ions, the generated CO2-foam mobility decreased from 19.7 to 4.8 md/cp when CaCl2 concentration increased from 0.1 to 1.0%. Synthetic produced water with total dissolved solids (TDS) of 18,583 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than 2 days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.

Model calibration for forecasting CO2-foam enhanced oil recovery field pilot performance in a carbonate reservoir

2019 ◽  
Vol 26 (1) ◽  
pp. 141-149
Author(s):  
M. Sharma ◽  
Z. P. Alcorn ◽  
S. B. Fredriksen ◽  
A. U. Rognmo ◽  
M. A. Fernø ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Model Calibration ◽  
Carbonate Reservoir ◽  
Pilot Performance ◽  
Co2 Foam

New Insight on Carbonate-Heavy-Oil Recovery: Pore-Scale Mechanisms of Post-Solvent Carbon Dioxide Foam/Polymer-Enhanced-Foam Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1655-1668 ◽  
Author(s):  
Ali Telmadarreie ◽  
Japan J. Trivedi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Carbonate Reservoirs ◽  
Heavy Oil Recovery ◽  
Pore Scale ◽  
Sweep Efficiency ◽  
Solvent Injection ◽  
Co2 Foam ◽  
The Matrix ◽  
Heavy Crude

Summary Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by nonthermal processes. Solvent, gas, water, and water-alternating-gas (WAG) injections are the main methods for carbonate-heavy-oil recovery in the WCSB. Because of the fractured nature of carbonate formations, many advantages of these production methods are usually in contrast with their low recovery factor. Alternative processes are therefore needed to increase oil-sweep efficiency from carbonate reservoirs. Foam/polymer-enhanced-foam (PEF) injection has gained interest in conventional heavy-oil recovery in recent times. However, the oil-recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fractured heavy-oil-carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil. This study introduces a new approach to access the unrecovered heavy oil in fractured-carbonate reservoirs. Carbon dioxide (CO2) foam and CO2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore-scale phenomena during CO2-foam/PEF injection. In addition, the static bulk performances of CO2 foam/PEF were analyzed in the presence of heavy crude oil. A high-definition camera was used to capture high-quality images. The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO2 PEF, CO2 foam lamella broke much faster and resulted in the collapse of the foam during heavy-oil recovery after solvent flooding. It appeared that foam played a greater role than just gas-mobility control. Foam showed outstanding improvement in heavy-oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy-oil-sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO2 foam and PEF remarkably increased heavy-oil recovery after solvent injection into the fractured reservoir.

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