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.

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.

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.

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.

CO2-Foam Rheology Behavior Under Reservoir Conditions

2019 ◽  
Author(s):  
Abdulaziz S. Al-Qasim ◽  
Sunil Kokal ◽  
Fawaz AlOtaibi
Keyword(s):  
Rheological Properties ◽  
Surfactant Solution ◽  
Experimental Results ◽  
Co2 Injection ◽  
Liquid Ratio ◽  
Conformance Control ◽  
Co2 Foam ◽  
Reservoir Conditions ◽  
The Impact ◽  
Injection Modes

Abstract Super critical carbon dioxide (SC-CO2) flooding is one of the most important enhanced oil recovery (EOR) methods used for conformance control and deep diversion of SC-CO2. It minimizes gravity override of SC-CO2 bypassing oil in the lower part of the formation. This paper investigates the impact of various parameters such as liquid/liquid ratio, different foam qualities and different injection modes on the SC-CO2-foam quality and its rheological properties. SC-CO2 foam can control the SC-CO2 mobility, enhance the sweep efficiency in reservoirs and improve the conformance control. Experimental results shows that combining foam with supercritical and dense CO2 will reduce the mobility of SC-CO2 to oil and water, stabilize the SC-CO2 injection front and mitigate the gravity override to a great extent resulting in less amount of unwept oil and better displacement efficiency and more recovery gain. Different set of lab experiments designed and conducted to identify the right ratio that can drastically increase SC-CO2 viscosity. In this work, we explored the rheological properties of SC-CO2 foam/gel chemicals with different pressure and temperature. Two different types of surfactants were tested. The experimental setup and conditions were designed to allow surfactant to mix with SC-CO2 under high reservoir pressure and temperature (HPHT) to create foam to evaluate and screen the foam quality and texture. The rheological properties of the SC-CO2-foam were investigated by varying the shear rate, shear stress, foam quality, injection modes and foaming agent concentrations at reservoir conditions. The effects of foam quality and liquid/liquid ratio, pressure and temperature on SC-CO2-foam at synthetic brine-environment rheology behavior, stability and mobility of foam were investigated. The foam study experiments were conducted using different scenarios: once by injecting SC-CO2 and surfactant solutions simultaneously and another time by alternate injection of CO2/surfactant solution at different flow rates at different foam qualities. The experimental results have shown that the foam mobility (total mobility of CO2 /surfactant solution) decreased with increasing foam quality ranging from 20% to 80%. The rheological properties of N2-foam were investigated and compared with SC-CO2-foam properties. This was correlated with the images of the high pressure, high temperature (HPHT) foams that were captured through microscope at different time intervals and analyzed to indicate their stability.

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.

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.

Visualization of CO2 foam generation, propagation and sweep in a complex 2D heterogeneous fracture network

Fuel ◽  
2021 ◽  
Vol 302 ◽  
pp. 121000
Author(s):  
Fayang Jin ◽  
Shenggen Chen ◽  
Bing Wei ◽  
Dianlin Wang ◽  
Weipeng Yang ◽  
...  
Keyword(s):  
Fracture Network ◽  
Foam Generation ◽  
Co2 Foam

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

2014 ◽  
Author(s):  
Martin Anders Ferno ◽  
Jarand Gauteplass ◽  
Monrawee Pancharoen ◽  
Asmund Haugen ◽  
Arne Graue ◽  
...  
Keyword(s):  
Experimental Study ◽  
Fracture Network ◽  
Sweep Efficiency ◽  
Foam Generation

scholarly journals Pore- and Core-Scale Insights of Nanoparticle-Stabilized Foam for CO2-Enhanced Oil Recovery

Nanomaterials ◽  
2020 ◽  
Vol 10 (10) ◽  
pp. 1917
Author(s):  
Zachary Paul Alcorn ◽  
Tore Føyen ◽  
Jarand Gauteplass ◽  
Benyamine Benali ◽  
Aleksandra Soyke ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Primary Objective ◽  
Co2 Injection ◽  
Foam Generation ◽  
Co2 Foam ◽  
Hybrid Nanoparticle ◽  
Scale Characterization ◽  
Generation Mechanisms

Nanoparticles have gained attention for increasing the stability of surfactant-based foams during CO2 foam-enhanced oil recovery (EOR) and CO2 storage. However, the behavior and displacement mechanisms of hybrid nanoparticle–surfactant foam formulations at reservoir conditions are not well understood. This work presents a pore- to core-scale characterization of hybrid nanoparticle–surfactant foaming solutions for CO2 EOR and the associated CO2 storage. The primary objective was to identify the dominant foam generation mechanisms and determine the role of nanoparticles for stabilizing CO2 foam and reducing CO2 mobility. In addition, we shed light on the influence of oil on foam generation and stability. We present pore- and core-scale experimental results, in the absence and presence of oil, comparing the hybrid foaming solution to foam stabilized by only surfactants or nanoparticles. Snap-off was identified as the primary foam generation mechanism in high-pressure micromodels with secondary foam generation by leave behind. During continuous CO2 injection, gas channels developed through the foam and the texture coarsened. In the absence of oil, including nanoparticles in the surfactant-laden foaming solutions did not result in a more stable foam or clearly affect the apparent viscosity of the foam. Foaming solutions containing only nanoparticles generated little to no foam, highlighting the dominance of surfactant as the main foam generator. In addition, foam generation and strength were not sensitive to nanoparticle concentration when used together with the selected surfactant. In experiments with oil at miscible conditions, foam was readily generated using all the tested foaming solutions. Core-scale foam-apparent viscosities with oil were nearly three times as high as experiments without oil present due to the development of stable oil/water emulsions and their combined effect with foam for reducing CO2 mobility

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

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