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.

Experimental Study of Foam Generation, Sweep Efficiency, and Flow in a Fracture Network

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1140-1150 ◽  
Author(s):  
M. A. Fernø ◽  
J.. Gauteplass ◽  
M.. Pancharoen ◽  
A.. Haugen ◽  
A.. Graue ◽  
...  
Keyword(s):  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Fracture Network ◽  
Mobility Control ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Foam Generation ◽  
Gas Mobility ◽  
Mobility Reduction

Summary Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

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.

Visualizing and Quantifying Generation, Propagation, and Sweep of Nanocellulose-Strengthened Carbon Dioxide Foam in a Complex 2D Heterogeneous Fracture Network Model

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Bing Wei ◽  
Qingtao Tian ◽  
Shengen Chen ◽  
Xingguang Xu ◽  
Dianlin Wang ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Network Model ◽  
Gravitational Effect ◽  
Fracture Network ◽  
Sweep Efficiency ◽  
Co2 Foam ◽  
Reservoir Conditions ◽  
Foam Film ◽  
Carbon Dioxide Co2

Summary There exist two main issues hampering the wide application and development of carbon dioxide (CO2) foam in conformance improvement and CO2 mobility reduction in fractured systems: (1) instability of foam film under reservoir conditions and (2) uncertainties of foam flow in complex fractures. To address these two issues, we previously developed a series of nanocellulose-strengthened CO2 foam (referred to as NCF-st-CO2 foam), while the primary goal of this work is to thoroughly elucidate generation, propagation, and sweep of NCF-st-CO2 foam in a visual 2D heterogeneous fracture network model. NCF-st-CO2 foam outperformed CO2 foam in reducing gas mobility during either coinjection (COI) or surfactant-alternating-gas (SAG) injection, and the threshold foam quality was approximately 0.67. Foam creation was increased with the total superficial velocity for CO2 foam and almost stayed constant for NCF-st-CO2 foam in fractures during COI. For SAG, large surfactant slug could prevent CO2 from early breakthrough and facilitate foaming in situ. The improved sweep efficiency induced by NCF-st-CO2 foam occurred near the producer for both COI and SAG. 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 decrease by 3 to 9%. Owing to the enhanced film, NCF-st-CO2 foam enabled mitigation of the gravitational effect, especially around the producer.

scholarly journals Enhancement of a foaming formulation with a zwitterionic surfactant for gas mobility control in harsh reservoir conditions

2021 ◽  
Author(s):  
Miguel Angel Roncoroni ◽  
Pedro Romero ◽  
Jesús Montes ◽  
Guido Bascialla ◽  
Rosario Rodríguez ◽  
...  
Keyword(s):  
Mobility Control ◽  
Zwitterionic Surfactant ◽  
Reservoir Conditions ◽  
Gas Mobility

Estimation of CO2 Storage Capacity in Oil Reservoir after Waterflooding：Case Studies in Xinjiang Oilfield from West China

2013 ◽  
Vol 734-737 ◽  
pp. 1183-1188 ◽  
Author(s):  
Xiao Liang Zhao ◽  
Xin Wei Liao ◽  
Wan Fu Wang ◽  
Chang Zhao Chen ◽  
Chang Lin Liao ◽  
...  
Keyword(s):  
Greenhouse Gas ◽  
Storage Capacity ◽  
Greenhouse Gas Emission ◽  
Water Saturation ◽  
Material Balance ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Water Displacement ◽  
Gas Emission ◽  
Sweep Efficiency

CO2 storage in oil reservoirs is an important method to reduce Greenhouse Gas Emission. It was proven to have a great CO2storage capacity and economic potentials via EOR by injecting CO2into oil reservoirs. In China, most oil reservoirs went through waterflooding, and have high water saturation at present. The storage capacity in these oil reservoirs can be estimated on base of material balance method which considers the volume of displaced water and oil, CO2 sweep efficiency, and CO2 solution in oil and water. Case studies of four reservoirs selected from Xinjiang oilfield in China are conducted, the theoretical storage capacity and effective storage capacity is estimated. The results show that oil reservoir can provide much larger storage capacity, and oil and water displacement and CO2dissolution in remaining oil and water are the main forms of CO2storage in oil reservoirs after waterflooding. It’s a great option to inject CO2 into these reservoirs to reduce Greenhouse Gas emission, and the detailed storage capacity is worth further studies.

scholarly journals Performance of surfactant blend formulations for controlling gas mobility and foam propagation under reservoir conditions

2020 ◽  
Vol 10 (8) ◽  
pp. 3961-3969
Author(s):  
Muhammad Khan Memon ◽  
Khaled Abdalla Elraies ◽  
Mohammed Idrees Ali Al-Mossawy
Keyword(s):  
Crude Oil ◽  
Foam Stability ◽  
High Mobility ◽  
Reduction Factor ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Surfactant Solutions ◽  
Reservoir Conditions ◽  
Gas Mobility ◽  
Mobility Reduction

Abstract The use of surfactant is one of the possible solutions to minimize the mobility of gases and improve the sweep efficiency, but the main problem with this process is its stability in the presence of injection water and crude oil under reservoir conditions. In this study, the three types of surfactant anionic, nonionic and amphoteric are examined in the presence of brine salinity at 96 °C and 1400 psia. To access the potential blended surfactant solutions as gas mobility control, laboratory test including aqueous stability, interfacial tension (IFT) and mobility reduction factor (MRF) were performed. The purpose of MRF is to evaluate the blocking effect of selected optimum surfactant solutions. Based on experimental results, no precipitation was observed by testing the surfactant solutions at reservoir temperature of 96 °C. The tested surfactant solutions reduced the IFT between crude oil and brine. The effectiveness and strength of surfactant solutions without crude oil under reservoir conditions were evaluated. A high value of differential pressure demonstrates that the strong foam was generated inside a core that resulted in delay in breakthrough time and reduction in the gas mobility. High mobility reduction factor result was measured by the solution of blended surfactant 0.6%AOS + 0.6%CA406H. Mobility reduction factor of other tested surfactant solutions was found low due to less generated foam by using CO2 under reservoir conditions. The result of these tested surfactant solutions can provide the better understanding of the mechanisms behind generated foam stability and guideline for their implementation as gas mobility control during the process of surfactant alternating gas injection.

Carbon Dioxide Foam Rheology in Porous Media: A CT Scan Study

SPE Journal ◽  
2007 ◽  
Vol 12 (02) ◽  
pp. 245-252 ◽  
Author(s):  
Dongxing Du ◽  
Pacelli Lidio Jose Zitha ◽  
Matthijs G.H. Uijttenhout
Keyword(s):  
Carbon Dioxide ◽  
Porous Media ◽  
Water Saturation ◽  
Control Measure ◽  
Co2 Storage ◽  
Mobility Control ◽  
Low Flow ◽  
Total Recovery ◽  
Foam Flow ◽  
Co2 Foam

Summary Carbon dioxide (CO2) foam has been widely studied in connection with its application in enhanced oil recovery (EOR). This paper reports an experimental study concerning CO2 foam propagation in asurfactant-saturated Bentheim sandstone core and the subsequent liquid injection with the aid of X-ray computed tomography (CT). The experiments were carried out under various system backpressures. It is found that CO2 foam flows in a characteristic front-like manner in the transient stage and that the water saturation keeps at relatively high level at the outlet of the porous media because of CO2 solubility and capillary end effect. The subsequent surfactant solution injection shows a significant fingering behavior, accompanied by a low flow resistance over the core. It is also found that CO2 foam flow shows higher liquid saturation near the outlet and lower pressure drops under higher system backpressures. This can be attributed to the solubility of CO2 in the liquid phase. The results indicate the advantage of using foam in EOR processes such as water alternating foam (WAF), in which foam flow has higher sweep efficiency and stronger mobility control ability compared, for instance, to water alternating gas (WAG). Nevertheless, care should be taken during the water-injection stage in order not to favor the fingering. Introduction Foam applications in EOR and fluid (acid) diversion have grown considerably over the last three decades. For instance, WAGhas been regularly used in the field as a gasflood mobility control measure. Nevertheless, this technique has not always demonstrated the desired beneficial mobility effects because of the gravity segregation and the unstable preceding of the front between the water and moremobile gas (Holm 1987; Smith 1988). Creating foam by adding surfactant to the aqueous phase has proven to be able to increase the total recovery significantly by increasing the apparent viscosity of the system (Holm and Josendal 1974; Ali et al. 1985; Patzek 1996; Zhdanov et al. 1996; Turta and Signhal 1998). There are many attractive features of EOR using CO2 foaminjection. First, carbon dioxide is a proven solvent for reconnecting, mobilizing, and recovering waterflood residual oil. Many studies (Stalkup 1983) have shown that CO2 can achieve miscible-like displacement efficiency through multiple contacts (partitioning and extraction) with the crude oil. Second, CO2 is available naturally in large quantities and as a byproduct of lignite gasification and many manufacturing processes. Its price is also low, and there are no other large-volume uses competing for CO2. Third, with the push toward sustainable power production and the increasing realization for the need to reduce CO2 emissions, EOR using CO2 is becoming an important alternative for geological CO2 storage.

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