scholarly journals Gas miscible displacement: Foams for mobility control and improvement in gas sweep efficiency

1989 ◽  
Author(s):  
F. Llave ◽  
F. Chung ◽  
R. Louvier ◽  
D. Hudgins
Keyword(s):  
Miscible Displacement ◽  
Mobility Control ◽  
Sweep Efficiency

Pore-Scale Transport Mechanisms and Macroscopic Displacement Effects of In-Situ Oil-in-Water Emulsions in Porous Media

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Chuan Lu ◽  
Wei Zhao ◽  
Yongge Liu ◽  
Xiaohu Dong
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Mobility Control ◽  
Pore Scale ◽  
Sweep Efficiency ◽  
Emulsion Droplets ◽  
Oil In Water ◽  
Retention Volumes

Oil-in-water (O/W) emulsions are expected to be formed in the process of surfactant flooding for heavy oil reservoirs in order to strengthen the fluidity of heavy oil and enhance oil recovery. However, there is still a lack of detailed understanding of mechanisms and effects involved in the flow of O/W emulsions in porous media. In this study, a pore-scale transparent model packed with glass beads was first used to investigate the transport and retention mechanisms of in situ generated O/W emulsions. Then, a double-sandpack model with different permeabilities was used to further study the effect of in situ formed O/W emulsions on the improvement of sweep efficiency and oil recovery. The pore-scale visualization experiment presented an in situ emulsification process. The in situ formed O/W emulsions could absorb to the surface of pore-throats, and plug pore-throats through mechanisms of capture-plugging (by a single emulsion droplet) and superposition-plugging or annulus-plugging (by multiple emulsion droplets). The double-sandpack experiments proved that the in situ formed O/W emulsion droplets were beneficial for the mobility control in the high permeability sandpack and the oil recovery enhancement in the low permeability sandpack. The size distribution of the produced emulsions proved that larger pressures were capable to displace larger O/W emulsion droplets out of the pore-throat and reduce their retention volumes.

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.

Switchable Nonionic to Cationic Ethoxylated Amine Surfactants for CO2 Enhanced Oil Recovery in High-Temperature, High-Salinity Carbonate Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 19 (02) ◽  
pp. 249-259 ◽  
Author(s):  
Yunshen Chen ◽  
Amro S. Elhag ◽  
Benjamin M. Poon ◽  
Leyu Cui ◽  
Kun Ma ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Salinity ◽  
Capillary Tube ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Displacement Front ◽  
Flow Pathways ◽  
Co2 Flow ◽  
Carbon Dioxide Co2

Summary To improve sweep efficiency for carbon dioxide (CO2) enhanced oil recovery (EOR) up to 120°C in the presence of high-salinity brine (182 g/L NaCl), novel CO2/water (C/W) foams have been formed with surfactants composed of ethoxylated amine headgroups with cocoalkyl tails. These surfactants are switchable from the nonionic (unprotonated amine) state in dry CO2 to cationic (protonated amine) in the presence of an aqueous phase with a pH less than 6. The high hydrophilicity in the protonated cationic state was evident in the high cloudpoint temperature up to 120°C. The high cloud point facilitated the stabilization of lamellae between bubbles in CO2/water foams. In the nonionic form, the surfactant was soluble in CO2 at 120°C and 3,300 psia at a concentration of 0.2% (w/w). C/W foams were produced by injecting the surfactant into either the CO2 phase or the brine phase, which indicated good contact between phases for transport of surfactant to the interface. Solubility of the surfactant in CO2 and a favorable C/W partition coefficient are beneficial for transport of surfactant with CO2-flow pathways in the reservoir to minimize viscous fingering and gravity override. The ethoxylated cocoamine with two ethylene oxide (EO) groups was shown to stabilize C/W foams in a 30-darcy sandpack with NaCl concentrations up to 182 g/L at 120°C and 3,400 psia, and foam qualities from 50 to 95%. The foam produces an apparent viscosity of 6.2 cp in the sandpack and 6.3 cp in a 762-μm-inner-diameter capillary tube (downstream of the sandpack) in contrast with values well below 1 cp without surfactant present. Moreover, the cationic headgroup reduces the adsorption of ethoxylated alkyl amines on calcite, which is also positively charged in the presence of CO2 dissolved in brine. The surfactant partition coefficients (0 to 0.04) favored the water phase over the oil phase, which is beneficial for minimizing losses of surfactant to the oil phase for efficient surfactant usage. Furthermore, the surfactant was used to form C/W foams, without forming stable/viscous oil/water (O/W) emulsions. This selectivity is desirable for mobility control whereby CO2 will have low mobility in regions in which oil is not present and high contact with oil at the displacement front. In summary, the switchable ethoxylated alkyl amine surfactants provide both high cloudpoints in brine and high interfacial activities of ionic surfactants in water for foam generation, as well as significant solubilities in CO2 in the nonionic dry state for surfactant injection.

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.

Foams for Mobility Control and Improved Sweep Efficiency in Gas Flooding

1998 ◽  
Author(s):  
T. Zhu ◽  
A. Strycker ◽  
C.J. Raible ◽  
K. Vineyard
Keyword(s):  
Mobility Control ◽  
Sweep Efficiency ◽  
Gas Flooding

Laboratory Investigations of Factors Influencing Polymer Flood Performance

1975 ◽  
Vol 15 (04) ◽  
pp. 338-346 ◽  
Author(s):  
M.T. Szabo
Keyword(s):  
Oil Recovery ◽  
Polymer Solutions ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Polymer Injection ◽  
Polymer Flood

Abstract Numerous polymer floods were performed in unconsolidated sand packs using a C14-tagged, cross-linked, partially hydrolyzed ployacrylamide, and the data are compared with brine-flood performance in the same sands. performance in the same sands. The amount of "polymer oil" was linearly proportional to polymer concentration up to a proportional to polymer concentration up to a limiting value. The upper limit of polymer concentration yielding additional polymer oil was considerably higher for a high-permeability sand than for a low-permeability sand. It is shown that a minimum polymer concentration exists, below which no appreciable polymer oil can be produced in high-permeability sands. The effect of polymer slug size on oil recovery is shown for various polymer concentrations, and the results from these tests are used to determine the optimum slug size and polymer concentration for different sands. The effect of salinity was studied by using brine and tap water during polymer floods under similar conditions. Decreased salinity resulted in improved oil recovery at low, polymer concentrations, but it had little effect at higher polymer concentrations. Polymer injection that was started at an advanced stage of brine flood also improved the oil recovery in single-layered sand packs. Experimental data are presented showing the effect of polymer concentration and salinity on polymer-flood performance in stratified reservoir polymer-flood performance in stratified reservoir models. Polymer concentrations in the produced water were measured by analyzing the radioactivity of effluent samples, and the amounts of retained polymer in the stratified models are given for each polymer in the stratified models are given for each experiment. Introduction In the early 1960's, a new technique using dilute polymer solutions to increase oil recovery was polymer solutions to increase oil recovery was introduced in secondary oil-recovery operations. Since then, this new technique has attained wide-spread commercial application. The success and the complexity of this new technology has induced many authors to investigate many aspects of this flooding technique. Laboratory and field studies, along with numerical simulation of polymer flooding, clearly demonstrated that polymer additives increase oil recovery. polymer additives increase oil recovery. Some of the laboratory results have shown that applying polymers in waterflooding reduces the residual oil saturation through an improvement in microscopic sweep efficiency. Other laboratory studies have shown that applying polymer solutions improves the sweep efficiency in polymer solutions improves the sweep efficiency in heterogeneous systems. Numerical simulation of polymer flooding, and a summary of 56 field applications, clearly showed that polymer injection initiated at an early stage of waterflooding is more efficient than when initiated at an advanced stage. Although much useful information has been presented, the experimental conditions were so presented, the experimental conditions were so variable that difficulties arose in correlating the numerical data. So, despite this good data, a systematic laboratory study of the factors influencing the performance of polymer flooding was still lacking in the literature. The purpose of this study was to investigate the effect of polymer concentration, polymer slug size, salinity in the polymer bank, initial water saturation, and permeability on the performance of polymer floods. The role of oil viscosity did not constitute a subject of this investigation. However, some of the data indicated that the applied polymer resulted in added recovery when displacing more viscous oil. The linear polymer-flood tests were coupled with tests in stratified systems, consisting of the same sand materials used in linear flood tests. Thus, it was possible to differentiate between the role of polymer in mobility control behind the flood front in each layer and its role in mobility control in the entire stratified system through improvement in vertical sweep efficiency. A radioactive, C14-tagged hydrolyzed polyacrylamide was used in all oil-recovery tests. polyacrylamide was used in all oil-recovery tests. SPEJ P. 338

Ensemble-Based Optimization of the Water-Alternating-Gas-Injection Process

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0786-0798 ◽  
Author(s):  
Bailian Chen ◽  
Albert C. Reynolds
Keyword(s):  
Net Present Value ◽  
Optimization Technique ◽  
Water Injection ◽  
Mobility Control ◽  
Co2 Injection ◽  
Optimal Controls ◽  
Co2 Flooding ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Water Alternating Gas

Summary CO2-water-alternating-gas (CO2-WAG) flooding generally leads to higher recovery than either continuous CO2 flooding or waterflooding. Although CO2 injection increases microscopic displacement efficiency, unless complete miscibility is achieved, suboptimal sweep efficiency may be obtained because of gravity segregation and the channeling of CO2 through high-permeability zones or by viscous fingering. Alternating water injection with CO2 injection results in better mobility control and increases sweep efficiency. Water injection also increases pressure that promotes miscibility. However, poorly designed WAG parameters can result in suboptimal WAG performance. In this work, given the number of WAG cycles and the duration of each WAG cycle, we apply a modification of a standard ensemble-based optimization technique to estimate the optimal well controls that maximize life-cycle net present value (NPV). By optimizing the well controls, we implicitly optimize the WAG ratio (volume of water injected divided by the volume of gas injected). We apply the optimization methodology to a synthetic, channelized reservoir. The performances of optimized WAG flooding, optimized waterflooding, and optimized continuous CO2 flooding are compared. Because of the similarity between WAG and surfactant alternating gas (SAG foam), we also optimize the SAG process and provide a more computationally efficient way to optimize the SAG process with the optimal well controls obtained from WAG as the initial guesses for the optimal controls for SAG.

Synergy of Polymer for Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery

2021 ◽  
Author(s):  
Taniya Kar ◽  
Abbas Firoozabadi
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Synergistic Effects ◽  
Water Injection ◽  
Mobility Control ◽  
Residual Oil ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Abstract Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.

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