A New Generation Chemical-Flooding Simulator

John, Ajita; Han, Choongyong; Delshad, Mojdeh; Pope, Gary A.; Sepehrnoori, Kamy

doi:10.2118/89436-pa

Cited by 19 publications

(4 citation statements)

References 22 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…More realistic models have been made available in different chemical flooding simulators in the last decades. UTCHEM and REVEAL on one hand, CMG-STARS and Eclipse, on the other hand, account for the main recovery mechanisms in ASP flooding in different ways (John et al 2005;Han et al 2007 and Mohammadi et al 2009). The distinctive mechanisms in these two types of reservoir simulators primarily represent the physics associated with the reduction in IFT.…”

Section: Introductionmentioning

confidence: 99%

Impact of Alkaline-Surfactant-Polymer Flooding Model on Upscaled Recovery Predictions: Medium and Heavy Oils

Kazempour¹,

Alvarado

Manrique³

et al. 2014

Day 3 Fri, September 26, 2014

View full text Add to dashboard Cite

Alkali-surfactant-polymer (ASP) flooding is a commercially viable enhanced oil recovery method. The complexity of chemical interactions, multi-phase flow, emulsification, capillary number changes and upscaling issues, especially in highly heterogeneous reservoir, make field designs difficult to extrapolate from coreflood measurements. In this work, two representaions of low interfacial tension conditions in chemical flooding were evaluated to determine the impact of model formulation on scaling-up from lab data to field situations. The first one is a mechanistic model based on interpolation of relative permeability curves parametrized with respect to the local capillary number. The second model requires tracking a thermodynamically stable phase known to exist at water-oil ultralow interfacial tension, namely a microemulsion. To perform this analysis, two sets of chemical coreflooding results were history matched and then the tuned models were utilized for field-scale predictions. For ASP flooding, a sensitivity analysis was implemented to show the importance of microemulsion phase on ASP upscaled (field scale) forecast. In this study, coreflooding experiments were performed using three different crude oils, case I: heavy oil with high acid number, case II: medium oil with high acid number and finally, case III: light oil with very low acid number. Predictions between the two modeling approaches are shown to diverge from each other upon upscaling of core-scale history matched models. This discrepancy is mostly attributed to the need to track a microemulsion phase behavior as well as its properties. Effects are more pronounced for heavier oil with high acid number. The results of this analysis should be useful to constrain field projections of any field design of surfactant-assisted EOR projects. Additionally, this study provides guidelines to understand existing uncertainties in current chemical flooding simulation regarding our ability to accurately predict the results of such a chemical flood design.

show abstract

Section: Introductionmentioning

confidence: 99%

Impact of Alkaline-Surfactant-Polymer Flooding Model on Upscaled Recovery Predictions: Medium and Heavy Oils

Kazempour¹,

Alvarado

Manrique³

et al. 2014

Day 3 Fri, September 26, 2014

View full text Add to dashboard Cite

show abstract

“…Numerical simulators (John et al 2005, Shutang et al 1996 have been developed in the past for chemical flooding in which the IFT changes along the reservoir with time. John et al (2005) incorporate oil/surfactant/brine-phase behavior using Hand's rule and trapping number model for relative permeability in their simulator. Most simulation studies are focused on the study of chemical EOR in nonfractured reservoirs without wettability alteration.…”

Section: Introductionmentioning

confidence: 99%

Oil Recovery From Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory Experiments and Mechanistic Simulations

Adibhatla

Mohanty

2008

SPE Reservoir Evaluation &Amp; Engineering

122

View full text Add to dashboard Cite

Waterflooding recovers little oil from naturally fractured carbonate reservoirs if the matrix is oil-wet and fracture intensity is high. Laboratory experiments and mechanistic simulations have been conducted to understand the injection of dilute anionic surfactant solutions into oil-wet, fractured reservoirs. In this process, surfactant diffuses into the matrix, lowering the interfacial tension (IFT) and contact angle, which decreases the capillary pressure and increases oil relative permeability, enabling gravity to drain up the oil. The rate of oil recovery increases with an increase in matrix permeability, a decrease in initial gas saturation, a decrease of fracture height or spacing, and an increase in the wettabilityaltering capabilities of the surfactant. Increasing the surfactant concentration does not necessarily enhance the oil recovery rate, because IFT and wettability alterations are not linearly related to surfactant concentration. Adsorption of anionic surfactants on calcite can be suppressed with an increase in pH and a decrease in salinity.

show abstract

“…Tong and Chen [31] developed an isothermal, fully implicit, three-phase, three-dimensional model to simulate polymer flooding with the black oil model. John et al [32] and Han et al [33] implemented Winsor Type I [34] microemulsion phase behavior using Hand's rule [35] in a fully implicit equation of state (EOS) compositional simulator (GPAS), which was further extended by Han et al [36] to account for the Equivalent Alkane Carbon Number (EACN) and Najafabadi et al [37] to account for the other Winsor microemulsion types. Another fully implicit four-phase simulator with similar capabilities was developed by Patacchini et al [38].…”

Section: Introductionmentioning

confidence: 99%

A Systemic Comparison of Physical Models for Simulating Surfactant–Polymer Flooding

Alhotan,

Batista Fernandes,

Delshad

et al. 2023

Energies

View full text Add to dashboard Cite

Three different reservoir simulators that utilize both two-phase and three-phase microemulsion phase behavior models are used to model surfactant–polymer flooding to determine and compare their results. Different models are used in each simulator to describe the physical behavior of injected chemicals into the reservoir, which raises the need to benchmark their results. The physical behavior models of polymer and surfactant were constructed and verified on a 1D scale reservoir model and further verified in a 3D model. Finally, simulations were conducted in a field-scale reservoir containing 680,400 grids, where results were compared and analyzed. The 1D and 3D model results suggest an excellent match between the different simulators in modeling surfactant–polymer floods. In the case of the field-scale model, the simulators matched in terms of oil recovery and total volumes produced and injected, while having similar reservoir pressure profiles but with significant discrepancies in terms of injected and produced chemicals. These results indicate that despite the differences in the calculated injected and produced chemicals due to the different models in the simulators, the effect of surfactant–polymer floods on oil recovery, total injected and produced fluids, and average pressure profiles can be comparably modeled in all of the three simulators.

show abstract

A New Generation Chemical-Flooding Simulator

Cited by 19 publications

References 22 publications

Impact of Alkaline-Surfactant-Polymer Flooding Model on Upscaled Recovery Predictions: Medium and Heavy Oils

Impact of Alkaline-Surfactant-Polymer Flooding Model on Upscaled Recovery Predictions: Medium and Heavy Oils

Oil Recovery From Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory Experiments and Mechanistic Simulations

A Systemic Comparison of Physical Models for Simulating Surfactant–Polymer Flooding

Contact Info

Product

Resources

About