Numerical simulation of surfactant–polymer coreflooding experiments for carbonates

AlSofi, Abdulkareem M.; Liu, Jim S.; Han, Ming; Aramco, Saudi

doi:10.1016/j.petrol.2013.09.009

Cited by 42 publications

(11 citation statements)

References 28 publications

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“…The experiments performed on the Kenali Asam and the Tempino fields' core samples both showed that the relative permeabilities of the investigated cores, even from the same formation, varied significantly from one core plug to another, as has been stated by Alsofi, et al [21]. According to them, this is probably caused by the relatively wide changes in topology.…”

Section: Discussion Of Interpolation Setsupporting

confidence: 55%

“…Otherwise, whether the prediction the simulation has good agreement can only be shown by the different scenarios of varying the slug size of the injected blended surfactant-polymer. This result has pointed to some researches carried out that have reported on similar cases, in which, in order to attain a chemical EOR flooding match, the end-point of the relative permeability needed to be changed intentionally [21][22][23]. In this research, the authors have employed Eq.…”

Section: Discussion Of Interpolation Setmentioning

confidence: 99%

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Surfactant-Polymer Coreflood Simulation and Uncertainty Analysis Derived from Laboratory Study

Hakiki¹,

Maharsi²,

Marhaendrajana³

2015

J. Eng. Technol. Sci.

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Abstract. This paper presents a numerical simulation study on coreflood scale derived from a laboratory study conducted on light oil and water-wet sandstone samples from fields at Tempino and Kenali Asam, Sumatra, Indonesia. A rigorous laboratory study prompted a specified surfactant type among dozens of screened samples, i.e. AN3NS and AN2NS-M for Kenali Asam and Tempino, respectively. The coreflood scale numerical simulation study was performed using a commercial simulator, on the basis of the results from the laboratory study, at a constant temperature of 68°C, 0.3 cc/min injection rate and under 120 psia confining pressure. To get better recovery, the cores were tested using surfactant and polymer in a blended mode, containing 0.03% w/w polymer diluted in each field brine, which accommodated around 8000 ppm salinity. The most significant variable in the multiphase flow is the relative permeability curve, which is affected by interfacial tension (IFT) during waterflooding and surfactant-polymer (SP) flooding. This study shows that relative permeability will be shifted at ultra-low IFT (10 -3 to 10 -4 mN/m). This shifting phenomenon is governed by the interpolation parameter set, which implicitly represents the capillary number. Further work in matching the numerical results to the coreflood was conducted by changing the interpolation parameters.

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Section: Discussion Of Interpolation Setsupporting

confidence: 55%

Section: Discussion Of Interpolation Setmentioning

confidence: 99%

Surfactant-Polymer Coreflood Simulation and Uncertainty Analysis Derived from Laboratory Study

Hakiki¹,

Maharsi²,

Marhaendrajana³

2015

J. Eng. Technol. Sci.

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“…Surfactant-polymer flooding is an important process, because it offers the co-acting mechanisms of reduced interfacial tension and mobility control that efficiently increases oil recovery [8]. Numerical simulations have been conducted to evaluate the effect of surfactant-polymer slugs' sizes, polymer and surfactant concentrations, brine salinity, and the onset of hydrodynamic instability during the displacement of viscous oils by lower viscosity driving fluids such as surfactant-polymer, among others [120,121]. Polymer flooding in unconsolidated sand formations has also been studied through numerical modeling and laboratory-scale experiments, which indicates that polymer properties, fluid mobility, and formation plasticity influence the fracturing mechanisms in unconsolidated porous media during polymer flooding; for more details, the readers are referred to Khodaverdian et al [122] and the references therein.…”

Section: Flow Behavior Of Polymers Through Porous Mediamentioning

confidence: 99%

Evaluation of Polymeric Materials for Chemical Enhanced Oil Recovery

2020

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Polymer flooding is a promising enhanced oil recovery (EOR) technique; sweeping a reservoir with a dilute polymer solution can significantly improve the overall oil recovery. In this overview, polymeric materials for enhanced oil recovery are described in general terms, with specific emphasis on desirable characteristics for the application. Application-specific properties should be considered when selecting or developing polymers for enhanced oil recovery and should be carefully evaluated. Characterization techniques should be informed by current best practices; several are described herein. Evaluation of fundamental polymer properties (including polymer composition, microstructure, and molecular weight averages); resistance to shear/thermal/chemical degradation; and salinity/hardness compatibility are discussed. Finally, evaluation techniques to establish the polymer flooding performance of candidate EOR materials are described.

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“…Although ASP flooding has been proven to be an effective method for enhancing oil recovery and has been fruitful in actual oil fields [25][26][27], due to the late birth of this technique, its enhanced recovery mechanism and characteristics, especially the evolution of pressure field, remain to be explored. Physical experiments [27][28][29] and numerical simulation [30][31][32][33][34] about ASP have been conducted in recent years. Li et al [35] studied performance of ASP systems and effects of the individual component.…”

Section: Introductionmentioning

confidence: 99%

Development Performance and Pressure Field Evolution of ASP Flooding

Wang

et al. 2020

Advances in Polymer Technology

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ASP (alkali-surfactant-polymer) is acknowledged as an effective technology to improve the oil recovery. The microscopic displacement efficiency and macroscopic sweep efficiency have been discussed in detail for the past few years. However, development performance, especially pressure characteristics, needs to be further studied. This paper aims to explore the pressure evolution performance during ASP flooding, of which the results will shed light on development characteristics of ASP flooding. The study on ASP flooding pressure field development is conducted by laboratory and numerical methodology. A large sandpack laboratory model with vertical heterogeneous layers is used to monitor pressure performance during the ASP flooding. With the help of interpolation methods, a precise and intuitive pressure field is obtained based on pressure data acquired by limited measurement points. Results show that the average formation pressure and its location are changing all the time in the whole process. In addition, the influence of heterogeneity and viscosity on recovery and pressure is also probed in this paper. We built a numerical simulation model to match the experiment data considering the physical and chemical alternation in ASP flooding. Also, response surface methodology (RSM) is adopted to obtain the formula between pressure functions and influencing factors.

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Numerical simulation of surfactant–polymer coreflooding experiments for carbonates

Cited by 42 publications

References 28 publications

Surfactant-Polymer Coreflood Simulation and Uncertainty Analysis Derived from Laboratory Study

Surfactant-Polymer Coreflood Simulation and Uncertainty Analysis Derived from Laboratory Study

Evaluation of Polymeric Materials for Chemical Enhanced Oil Recovery

Development Performance and Pressure Field Evolution of ASP Flooding

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