Novel Insight Into Foam Mobility Control

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 416-427 ◽  
Author(s):  
M.. Simjoo ◽  
Y.. Dong ◽  
A.. Andrianov ◽  
M.. Talanana ◽  
P.L.J.. L.J. Zitha
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Field Application ◽  
Reduction Factor ◽  
Mobility Control ◽  
Injection Velocity ◽  
Alpha Olefin Sulfonate ◽  
Liquid Saturation ◽  
Nitrogen Foam ◽  
Foam Propagation

Summary A detailed laboratory study of nitrogen-foam propagation in natural sandstones in the absence of oil is reported. The goal of this study was to elucidate further the mechanisms of foam mobility control. The C14–16 alpha-olefin sulfonate (AOS) surfactant was selected to stabilize foam. X-ray computed-tomography (CT) images were taken during foam propagation to map liquid saturation over time. Effects of surfactant concentration and of total injection velocity were examined in detail because these are key parameters for controlling foam strength and foam propagation under field conditions. The experiments revealed that foam mobility decreases in two steps: During initial forward foam propagation, foam mobility decreases by an order of magnitude compared with water mobility; during a secondary backward liquid desaturation, it decreases further by one to two orders of magnitude for sufficiently high surfactant concentrations. The steady-state mobility-reduction factor (MRF) increases considerably with both surfactant concentration and total injection velocity. A hysteresis was observed for a cycle of increasing/decreasing surfactant concentration or total injection velocity. The observed effects could be interpreted mechanistically in terms of surfactant adsorption and foam rheology. Implications for field application of foam for immiscible and miscible gas enhanced oil recovery (EOR) are discussed.

scholarly journals Influence of formation heterogeneity on foam flooding performance using 2D and 3D models: an experimental study

2019 ◽  
Vol 17 (3) ◽  
pp. 734-748 ◽  
Author(s):  
Ling-Zhi Hu ◽  
Lin Sun ◽  
Jin-Zhou Zhao ◽  
Peng Wei ◽  
Wan-Fen Pu
Keyword(s):  
Oil Recovery ◽  
3D Models ◽  
Reduction Factor ◽  
Mobility Control ◽  
Displacement Efficiency ◽  
Vertical Heterogeneity ◽  
Oil Displacement Efficiency ◽  
Heterogeneous Formations ◽  
Major Factors ◽  
Foam Flooding

AbstractThe formation heterogeneity is considered as one of the major factors limiting the application of foam flooding. In this paper, influences of formation properties, such as permeability, permeability distribution, interlayer, sedimentary rhythm and 3D heterogeneity, on the mobility control capability and oil displacement efficiency of foam flooding, were systematically investigated using 2D homogeneous and 2D/3D heterogeneous models under 120 °C and salinity of 20 × 104 mg/L. The flow resistance of foam was promoted as the permeability increased, which thus resulted in a considerable oil recovery behavior. In the scenario of the vertical heterogeneous formations, it was observed that the permeability of the high-permeable layer was crucial to foam mobility control, and the positive rhythm appeared favorable to improve the foam flooding performance. The additional oil recovery increased to about 40%. The interlayer was favorable for the increases in mobility reduction factor and oil recovery of foam flooding when the low permeability ratio was involved. For the 3D heterogeneous formations, foam could efficiently adjust the areal and vertical heterogeneity through mobility control and gravity segregation, and thus enhancing the oil recovery to 11%–14%. The results derived from this work may provide some insight for the field test designs of foam flooding.

A New Effective Multiwalled Carbon Nanotube-Foam System for Mobility Control

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Raja Ramanathan ◽  
Omar Abdelwahab ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Nanotube ◽  
Half Life ◽  
Foam Stability ◽  
Reduction Factor ◽  
Mobility Control ◽  
Multiwalled Carbon Nanotube ◽  
Multiwalled Carbon ◽  
The Core ◽  
Nitrogen Foam ◽  
Mobility Reduction

Summary Nanoparticles have improved a surfactant's ability to create long-lasting foam. Recent studies have widely recommended the use of silica nanoparticles to enhance foam stability. This paper presents an experimental investigation of a new and highly effective alpha olefin sulfonate (AOS)–multiwalled carbon nanotube (MWCNT) system for mobility control during gas enhanced oil recovery (EOR) operations. The new AOS–MWCNT system was evaluated for its foam stability at 150°F using a high-pressure view cell. The MWCNT was obtained as solid particles of aspect ratio up to 100 and silica nanoparticles of median size of 118 nm. The foam system was optimized for its maximum half-life by varying the concentration of the AOS and the nanotube from 0.2 to 1% and 250 to 1,000 ppm, respectively. Compatibility testing with salts was done as well. Coreflood experiments with 1.5-in.-diameter, 6-in.-long Berea sandstone cores were run to calculate the mobility reduction factor at 150°F. Nitrogen foam was injected into the core at 80% foam quality in the tertiary recovery mode, and the pressure drop across the core was measured. The formation brine had a salinity of 5 wt% sodium chloride (NaCl), and the foaming solutions were prepared with 2 wt% NaCl. The optimal concentrations of the AOS solution and the nanotubes for maximum foam stability were determined to be 0.5% and 500 ppm, respectively. The optimized AOS–MWCNT system yielded 60% greater nitrogen foam half-life (32 minutes) than an optimized AOS–silica system at 150°F. The foam half-life of a stand-alone 0.5% AOS solution was 7 minutes. In the presence of crude oil, the foam half-life decreased for all the tested systems. Coreflood experiments at 150°F showed a significant increase in the mobility reduction factor when the new AOS–MWCNT system was used as the foamer instead of stand-alone AOS or AOS–silica system. The new foaming system was stable through the duration of the experiment, yielding foam in the effluent samples. There was no formation damage observed. Salt tolerance for the MWCNT nanofluid was higher than the silica nanofluid. Foam needs to be stable for long periods of time to ensure effective mobility control during gas injection for EOR. This paper investigates a new highly effective AOS-multiwalled carbon nanotube system that outperforms the AOS–silica foaming systems in terms of foam stability and mobility control at 150°F.

Anomalous Foam-Fractional-Flow Solutions at High-Injection Foam Quality

2013 ◽  
Vol 16 (01) ◽  
pp. 40-50 ◽  
Author(s):  
A.. Roostapour ◽  
S.I.. I. Kam
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Mobility Control ◽  
Injection Velocity ◽  
Fractional Flow ◽  
Improved Oil Recovery ◽  
High Injection ◽  
Constant State ◽  
Dry Conditions ◽  
First Time

Summary A thorough understanding of foam fundamentals is crucial to the optimal design of foams for improved oil recovery (IOR) or enhanced oil recovery (EOR). This study, for the first time, presents anomalous foam-fractional-flow solutions that deviate significantly from the conventional solutions at high-injection foam qualities by comparing method-of-characteristics and mechanistic bubble-population-balance simulations. The results from modeling and simulations derived from coreflood experiments revealed the following: The fraction of grinding energy contributed by the flowing gas (fg)There are three regions—Region A with relatively wet (or high fw) injection conditions in which the solutions are consistent with the conventional fractional-flow theory; Region C with very dry (or low fw) injection conditions in which the solutions deviate significantly; and Region B in between, which has a negative dfw/dSw slope showing physically unstable solutions.For dry-injection conditions in Region C, the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional-flow curves, followed by spreading waves or another shock to reach from IJ to J.The location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation. Even though foams at high-injection quality are popular for mobility control associating a minimum amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believed to be helpful to the successful planning of foam IOR/EOR field applications.

Investigation of Countercurrent Imbibition in Oil-Wet Tight Cores Using NMR Technology

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2601-2614 ◽  
Author(s):  
Junrong Liu ◽  
James J. Sheng
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Water Saturation ◽  
Fluid Pressure ◽  
Spontaneous Imbibition ◽  
Alpha Olefin Sulfonate ◽  
Field Scale ◽  
High Concentration ◽  
Countercurrent Imbibition ◽  
Wet Rocks

Summary Countercurrent spontaneous imbibition is one of the most significant mechanisms for the mass transfer between fractures and matrixes in tight reservoirs. Adding surfactants and pressurization are two common methods to enhance the imbibition. In this study, we used the low-field nuclear magnetic resonance (NMR) instrument to monitor the dynamic imbibition processes with surfactants added and fluid pressure applied. The T2 relaxation distribution and corresponding water saturation profiles during the imbibition process were obtained by analyzing NMR responses. We found that sodium alpha-olefin sulfonate (AOS) could improve the oil recoveries of laboratory-scale cores to 22.31 and 29.59% with different concentrations (0.1 and 0.5 wt%). The surfactant addition not only expands the imbibition area, but also reduces the residual oil saturation in the imbibition profile. However, the actual maximum imbibition distances are only approximately a centimeter long (0.9412 and 1.1372 cm), which is insignificant for field scale. Due to the minimal imbibition distance, high-quality hydraulic fracturing is required to generate a large number of fractures for imbibition to ensure considerable oil recovery at the field scale. In addition, surfactant is consumed during spontaneous imbibition of oil-wet rocks and increasing surfactant concentration facilitates the imbibition process. However, arbitrarily increasing the concentration does not achieve the expected oil recovery because of the high adsorption capacity resulting from the high concentration. We need to consider economic efficiency to optimize a reasonable surfactant concentration. It was found that traditional dimensionless scaling models are not applicable in the complicated surfactant-enhanced imbibition. Hence, we proposed a new scaling group for scaling laboratory date to the field in fractured oil-wet formations. Moreover, we compared the imbibition process under different pressure conditions (7.5 and 15 MPa) and found that the effect of fluid pressure on countercurrent imbibition is not obvious.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

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