Foam-Assisted Water–Gas Flow Parameters: From Core-Flood Experiment to Uncertainty Quantification and Sensitivity Analysis

Valdez, Andrés; Rocha, Bernardo Martins; Façanha, J.M.F.; Souza, Alexandre Vilela Oliveira de; Pérez‐Gramatges, Aurora; Chapiro, Grigori; Santos, Rodrigo Weber dos

doi:10.1007/s11242-021-01550-0

Cited by 12 publications

(15 citation statements)

References 36 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…We remark that we perform GSA before calibration of the simulation models on the basis of experimental observations. As such, GSA is keyed to (i) improving our understanding of the importance of each model parameter on target model outputs, and hence (ii) identifying quantities which might be of limited influence in the context of a subsequent model calibration (e.g., Dell'Oca et al 2017;Valdez et al 2021;Ranaee et al 2019;2021).…”

Section: Surrogate Model Gsa and Stochastic Model Calibrationmentioning

confidence: 99%

Sensitivity-based Parameter Calibration of Single- and Dual-continuum Coreflooding Simulation Models

et al. 2022

View full text Add to dashboard Cite

Our study is keyed to the development of a viable framework for the stochastic characterization of coreflooding simulation models under two- and three-phase flow conditions taking place within a core sample in the presence of preferential flow of the kind that can be associated with the presence of a system of fractures. We do so considering various modeling strategies based on (spatially homogeneous or heterogeneous) single- and dual-continuum formulations of black-oil computational models and relying on a global sensitivity-driven stochastic parameter calibration. The latter is constrained through a set of data collected under a water alternating gas scenario implemented in laboratory-scale coreflooding experiments. We set up a collection of Monte Carlo (MC) numerical simulations while considering uncertainty encompassing (a) rock attributes (i.e., porosity and absolute permeability), as well as (b) fluid–fluid/ fluid–solid interactions, as reflected through characteristic parameters of relative permeability and capillary pressure formulations. Modern moment-based global sensitivity indices are evaluated on the basis of the MC model responses, with the aim of (i) quantifying sensitivity of the coreflooding simulation results to variations of the input uncertain model parameters and (ii) assessing the possibility of reducing the dimensionality of model parameter spaces. We then rest on a stochastic inverse modeling approach grounded on the acceptance–rejection sampling (ARS) algorithm to obtain probability distributions of the key model parameters (as identified through our global sensitivity analyses) conditional to the available experimental observations. The relative skill of the various candidate models to represent the system behavior is quantified upon relying on the deviance information criterion. Our findings reveal that amongst all tested models, a dual-continuum formulation provides the best performance considering the experimental observations available. Only a few of the parameters embedded in the dual-continuum formulation are identified as major elements significantly affecting the prediction (and associated uncertainty) of model outputs, petrophysical attributes and relative permeability model parameters having a stronger effect than parameters related to capillary pressure.

show abstract

Section: Surrogate Model Gsa and Stochastic Model Calibrationmentioning

confidence: 99%

Sensitivity-based Parameter Calibration of Single- and Dual-continuum Coreflooding Simulation Models

et al. 2022

View full text Add to dashboard Cite

show abstract

“…These types of analyses have been applied to selected basin-scale depositional settings across geologic time scales (e.g., [33] and references therein). Similarly, sensitivity and uncertainty analyses have been recently applied to aid the appraisal of key elements driving the documented complexities associated with multiphase flow through porous media ( [35][36][37][38]). The solution of an inverse problem is challenging due to a variety of factors, including e.g., issues related to non-uniqueness (see, e.g., [39], and, [37,38]with reference to two-phase flow scenarios).…”

Section: Introductionmentioning

confidence: 99%

Stochastic inverse modeling of transient laboratory-scale three-dimensional two-phase core flooding scenarios

Dell’Oca

Manzoni

Siena

et al. 2023

International Journal of Heat and Mass Transfer

View full text Add to dashboard Cite

“…Surfactant-alternating gas (SAG) combined with foams dispersed in gas injections leads to an increased treatment depth than SAG alone, and the foams block high-permeability fractures. This process increases the potential of inaccessible fractures until then [13][14][15]. Hence, implementing a proper process requires extensive laboratory work and simulation studies to be effective.…”

Section: Introductionmentioning

confidence: 99%

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

et al. 2022

View full text Add to dashboard Cite

More than half of all recoverable oil reserves are found in carbonate rocks. Most of these fields are highly fractured and develop different zonations during primary and secondary recovery stages; therefore, they require a different developmental approach than conventional reservoirs. Experimental results for water-alternating gas injection [WAG] and foam-assisted water-alternating gas [FAWAG] injection under secondary and tertiary recovery conditions were used to investigate these enhanced oil recovery [EOR] methods in gas-invaded reservoirs. The relative permeability curves of the cores and the fitting foam parameters were derived from these experiments through history matching. These findings were then used in a quarter five-spot, cross-sectional, and a sector model of a carbonate reservoir where a double five-spot setup was implemented. The fracture and matrix properties’ impact on the recovery was illustrated through the cross-sectional model. The gas mobility reduction effect of the FAWAG was more noticeable than that of WAG. The apparent viscosity of the gas was increased due to the foam presence, which caused a diversion of the gas from the fractures into the matrix blocks. This greatly enhanced the sweep efficiency and led to higher oil recovery. The gas front was much sharper, and gravity overrides by the gas were much less of a concern. The properties of the fracture network also had a significant effect on the recovery. Oil recovery was found to be most sensitive to fracture permeability. At the same time, sweep efficiency increased substantially, improving the recovery rate in the early injection stages, and differed slightly at the ultimate recovery. However, a lower fracture permeability facilitated gas entry into the matrix blocks. The results of the reservoir sector model were similar to the core and pilot. However, the WAG injection recovered more of the uppermost layers, whereas significant portions of the lowest layer were not effectively recovered. In contrast, FAWAG was more effective in the lowest layer of the reservoir. The FAWAG was a beneficial aid in the recovery of gas-invaded fractured reservoirs, increasing the oil recovery factor with respect to WAG.

show abstract

Foam-Assisted Water–Gas Flow Parameters: From Core-Flood Experiment to Uncertainty Quantification and Sensitivity Analysis

Cited by 12 publications

References 36 publications

Sensitivity-based Parameter Calibration of Single- and Dual-continuum Coreflooding Simulation Models

Sensitivity-based Parameter Calibration of Single- and Dual-continuum Coreflooding Simulation Models

Stochastic inverse modeling of transient laboratory-scale three-dimensional two-phase core flooding scenarios

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

Contact Info

Product

Resources

About