Insights into the fractional flow of low salinity water flooding in the light of solute dispersion and effective salinity interactions

Al-Ibadi, Hasan; Stephen, Karl Dunbar; Mackay, Eric James

doi:10.1016/j.petrol.2018.12.001

Cited by 24 publications

(7 citation statements)

References 37 publications

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“…Researchers [19][20][21][22][23][24][25][26] have examined the dispersion of the surfactant solute front, involving numerical and physical dispersion at the core scale. However, owing to the fact that physical dispersion is ever so often offset by numerical dispersion; the first is ignored.…”

Section: Modelling Of Surfactant Floodingmentioning

confidence: 99%

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Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

Akinyele¹,

Stephen²

2021

Preprint

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Numerical simulation of surfactant flooding using conventional reservoir simulation models can lead to unreliable forecasts and bad decisions due to the appearance of numerical effects. The simulations give approximate solutions to systems of nonlinear partial differential equations describing the physical behavior of surfactant flooding by combining multiphase flow in porous media with surfactant transport. The approximations are made by discretization of time and space which can lead to spurious pulses or deviations in the model outcome. In this work, the black oil model was simulated using the decoupled implicit method for various conditions of reservoir scale models to investigate behaviour in comparison with the analytical solution obtained from fractional flow theory. We investigated changes to cell size and time step as well as the properties of the surfactant and how it affects miscibility and flow. The main aim of this study was to understand pulse like behavior that has been observed in the water bank to identify cause and associated conditions. We report for the first time that the pulses occur in association with the simulated surfactant water flood front and are induced by a sharp change in relative permeability as the interfacial tension changes. Pulses are diminished when the adsorption rate was within the value of 0.0002kg/kg to 0.0005kg/kg. The pulses are absent for high resolution model of 5000 cells in x direction with a typical cell size as used in well-scale models. The growth or damping of these pulses may vary from case to case but in this instance was a result of the combined impact of relative mobility, numerical dispersion, interfacial tension and miscibility. Oil recovery under the numerical problems reduced the performance of the flood, due to large amounts of pulses produced. Thus, it is important to improve existing models and use appropriate guidelines to stop oscillations and remove errors.

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Section: Modelling Of Surfactant Floodingmentioning

confidence: 99%

“…To examine the stability of the numerical solution in the Surfactant flood model, we assume Equation.11 as the limit, and to ensure our model is an advection dominated system. The timestep limit can be given as [25]:…”

Section: = (6)mentioning

confidence: 99%

Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

Akinyele¹,

Stephen²

2021

Preprint

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“…During the recent years, some further studies have been performed on the impact of mixing/physical dispersion on the performance of LSWF. − However, to the best of our knowledge, no study has focused on suppressing physical dispersion and mixing of brines, even though some of the influencing factors are well studied. ,, To name a few, Al-Ibadi et al (2019), by running a number of numerical simulations, concluded that the mobility of brine is affected by salinity and the front of injected LS brine moves with a lower velocity compared to the front of the HS brine . Attar and Muggeridge (2018) also performed a number of simulations and concluded that the volume of injected LS brine must be higher than 0.6 PV to address the concerns regarding the performance of LSWF due to dispersion …”

Section: Introductionmentioning

confidence: 99%

“…15,17,20 To name a few, Al-Ibadi et al (2019), by running a number of numerical simulations, concluded that the mobility of brine is affected by salinity and the front of injected LS brine moves with a lower velocity compared to the front of the HS brine. 20 Attar and Muggeridge (2018) also performed a number of simulations and concluded that the volume of injected LS brine must be higher than 0.6 PV to address the concerns regarding the performance of LSWF due to dispersion. 17 During LSWF, there are basically two moving fronts: a leading front and a succeeding front.…”

Section: Introductionmentioning

confidence: 99%

Polymer-Enhanced Low-Salinity Brine to Control In Situ Mixing and Salt Dispersion in Low-Salinity Waterflooding

2021

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Although viability of low-salinity waterflooding (LSWF) at the laboratory scale has been proven, there are some challenges associated with its field application, which sheds uncertainties on its economic success. One of the challenges is the minimum required volume of low-salinity water, which should be injected to the reservoir due to the salt dispersion in porous media. Once the low-saline brine is injected into the reservoir, mixing of injected (low-salinity) and resident (high-salinity) brines occurs and the developed mixing zone grows continuously as the front moves from the injection well toward the production well. Increase in the salinity of the front reduces the efficiency of LSWF. In this paper, we demonstrate experimentally that if low-salinity brine is augmented with a small amount of a polymer (as a viscosifying and mobility control agent), salt dispersion can be significantly suppressed. In this regard, a systematic series of single-phase sandpack flooding experiments was designed and performed. The impacts of salinity of resident high-salinity brine, salinity of low-salinity brine, and polymer concentration on mixing (dispersion) control were investigated. Analytical and numerical simulation methods were implemented to analyze the experimental data and infer dispersivity. The results show that adding 200 ppm of partially hydrolyzed polyacrylamide (HPAM) to the injection brine reduces the dispersivity by more than 70%. Once the dispersivity is reduced, the salinity profile becomes sharper; thus, significantly less volume of low-salinity brine will be required to establish low-salinity conditions in the whole core. Additionally, the analysis of variance shows that polymer concentration and salinity of high-salinity brine are the main factors affecting the dispersivity. The total salinity of low-salinity brine was found to be comparatively less important.

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“…Moreover, there is a range of salinity in which the wettability, fluid mobility, and residual oil saturation can change [25,26]. This is called the effective salinity range [24,27]. It is also observed that there is occasionally a change to the maximum relative permeability of water.…”

Section: Introductionmentioning

confidence: 99%

Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs

et al. 2020

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Low salinity waterflooding is an effective technique to accelerate and boost oil recovery. The impact of this technique has been investigated widely in laboratories for various scales and rock typing, most of which have demonstrated a potential improvement in oil recovery. This improvement has been attributed to several chemical and physical interactions that led to a change in the wettability to become more water-wet, as well as a reduction in the residual oil saturation. Meanwhile, it is rare to find a discussion in the literature about the efficiency of low salinity flooding in naturally fractured reservoirs. Therefore, in this work, we investigate the potential advantages of this method in fractured reservoirs using numerical simulations. A new approach to estimate the weighting factor using a tracer model has been proposed to determine the brine salinity and, hence, its properties in the mixing region. We have also used the relative permeability curves as a proxy for any physical and chemical mechanisms which are not represented explicitly in the model. The simulation outcomes highlighted the advantage of low salinity waterflooding in fractured reservoirs. An increment in oil recovery by 10.7% to 13% of Stock Tank Oil Initially In Place (STOIIP) was obtained using the dual- and single-porosity model, respectively. Therefore, the low salinity waterflooding technique represents a promising low-cost, effective method in fractured reservoirs.

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Insights into the fractional flow of low salinity water flooding in the light of solute dispersion and effective salinity interactions

Cited by 24 publications

References 37 publications

Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

Polymer-Enhanced Low-Salinity Brine to Control In Situ Mixing and Salt Dispersion in Low-Salinity Waterflooding

Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs

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