Characterizing flow behavior for gas injection: Relative permeability of CO<sub>2</sub>‐brine and N<sub>2</sub>‐water in heterogeneous rocks

Reynolds, Catriona; Krevor, Samuel

doi:10.1002/2015wr018046

Cited by 116 publications

(153 citation statements)

References 57 publications

(117 reference statements)

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“…The total saturation throughout each experimental stage remained approximately constant, at a value close to the residual nonwetting phase saturation during imbibition, as measured on larger core samples (24). However, the amount contributed by the different ganglia populations changed with both time and flow rate (Figs.…”

Section: Significancesupporting

confidence: 70%

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Reynolds

Menke

Andrew

et al. 2017

Proc. Natl. Acad. Sci. U.S.A.

151

114

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The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term "dynamic connectivity," using fast pore-scale X-ray imaging. We image the flow of N 2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.steady state | pore-scale imaging | immiscible two-phase flow | dynamic connectivity | geologic CO 2 storage T he definition of relative permeability is based on a conceptual model where each phase occupies its own static, connected fraction of the pore space (1-3). Observations of two-phase flow in beadpacks and micromodels at low flow rates show that the wetting-and nonwetting-phase fluids flow through their own network of separate stable pathways. Increasing the saturation of one phase increases the number of channels occupied by one fluid and decreases the number occupied by the other. The nonwetting phase generally occupies the large pores, whereas the wetting phase occupies the small pores and indentations in the surface of the solid (4-7).When the balance of capillary and viscous forces is modified such that viscous forces begin to dominate at the pore scale, the nonwetting phase can be pushed out of the pore space and flow can occur through the advection of disconnected ganglia (8, 9). The onset of ganglion motion is well understood, and this flow behavior has been observed during steady-state flow in model pore spaces (1-3, 7, 10-13).The key observation during slow steady-state flow, typical of most displacements in natural settings, such as during hydrocarbon recovery or CO2 storage, is that the pathway, once established, remains stable (2, 4-7). Flow patterns for different wettabilities have also been quantified in micromodel studies (14). Again, once flow pathways were established, they were not observed to change. However, there are no studies thus far that have investigated this flow behavior in the pore space of natural rocks.Developments in micro X-ray computed tomography (X-ray CT) mean that pore-scale phenomena can now be observed in rocks at reservoir conditions in both laboratory-based scanners and synchrotron beamlines (8,9,(15)(16)(17). This technological advance has allowed, for instance, observations of residual trapping (18) and wetting behavior (19).Fast synchrotron tomography allows the acquisition of images in under 60 s. Many unsteady-state, dynamic, pore-scale processes have been imaged, including Haines jumps (15), capillary pressure changes during reservoir cond...

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Section: Significancesupporting

confidence: 70%

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Reynolds

Menke

Andrew

et al. 2017

Proc. Natl. Acad. Sci. U.S.A.

151

114

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“…Here, for the sake Fig. 5 Possible combinations of the effective aspect ratio and transverse capillary number computed using data from laboratory flooding experiments (blue data points; Dawe et al 1992;Cinar et al 2006;Reynolds and Krevor 2015), mini-models (dark data points; Ringrose et al 1993) and oilfield case studies (red data points ;Cronquist 1968;Reitzel and Callow 1977;George and Stiles 1978). These computed data confirm capillary crossflow can be significant across many length scales, ranging from the core scale to the field scale (e.g.…”

Section: Applicable To Flow Along Layersmentioning

confidence: 56%

“…Core-flooding experiments are often performed at conditions where the capillary-to-viscous force balance which control flow can significantly change with parameters such as the flow rate or the fluid properties (Honarpour et al 1995;Reynolds and Krevor 2015;Krause and Benson 2015). It is important to perform experiments at various flow conditions to quantify how scales influence the results and extrapolate the results in a consistent manner (Huang et al 1995).…”

Section: Discussionmentioning

confidence: 99%

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

et al. 2017

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We examine the effect of capillary and viscous forces on the displacement of one fluid by a second, immiscible fluid across and along parallel layers of contrasting porosity, and relative permeability, as well as previously explored contrasts in absolute permeability and capillary pressure. We consider displacements with wetting, intermediate-wetting and non-wetting injected phases. Flow is characterized using six independent dimensionless numbers and a dimensionless storage efficiency, which is numerically equivalent to the recovery efficiency. Results are directly applicable to geologic carbon storage and hydrocarbon production. We predict how the capillary-viscous force balance influences storage efficiency as a function of a small number of key dimensionless parameters, and provide a framework to support mechanistic interpretations of complex field or experimental data, and numerical model predictions, through the use of simple dimensionless models. When flow is directed across layers, we find that capillary heterogeneity traps the non-wetting phase, regardless of whether it is the injected or displaced phase. However, minimal trapping occurs when the injected phase is intermediate-wetting or when high-permeability layers contain a smaller moveable volume of fluid than low-permeability layers. A dimensionless capillary-to-viscous number defined using the layer thickness rather than the more commonly used system length is most relevant to predict capillary heterogeneity trapping. When flow is directed along layers, we show that, regardless of wettability, increasing capillary crossflow reduces the distance between the leading edges of the injected phase in each layer and increases storage efficiency. This may be counter-intuitive when the injected phase is non-wetting. Crossflow has a significant impact on storage efficiency only when high-permeability layers contain a smaller moveable volume of fluid than low-permeability layers. In that case, capillary heterogeneity traps the wetting phase, regardless of whether it is the injected or displaced phase. B Yacine Debbabi

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“…The gas/water relative-permeability data should be measured with large viscous forces, i.e. large capillary numbers, to remain invariant to changes in the reservoir conditions and consistent with the derivation of the relative permeability from fractional-flow theory described by Eqs 3 and 4 23 . When surfactant is present in the porous medium formation of foam creates large pressure gradients leading to increase in the corresponding capillary numbers given by…”

Section: Resultsmentioning

confidence: 69%

Effect of Foam on Liquid Phase Mobility in Porous Media

Eftekhari¹,

Farajzadeh²

2016

SPE Improved Oil Recovery Conference

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We investigate the validity of the assumption that foam in porous media reduces the mobility of gas phase only and does not impact the liquid-phase mobility. The foam is generated by simultaneous injection of nitrogen gas and a surfactant solution into sandstone cores and its strength is varied by changing surfactant type and concentration. We find, indeed, that the effect of foam on liquid-phase mobility is not pronounced and can be ignored. Our new experimental results and analyses resolve apparent discrepancies in the literature. Previously, some researchers erroneously applied relative permeability relationships measured at small to moderate capillary numbers to foam floods at large capillary number. Our results indicate that the water relative permeability in the absence of surfactant should be measured with the capillary pressure ranging up to values reached during the foam floods. This requires conducting a steady-state gas/water core flood with capillary numbers similar to that of foam floods or measuring the water relative-permeability curve using a centrifuge.Foams are used in several subsurface applications ranging from aquifer remediation 1 to maximizing oil extraction from hydrocarbon fields 2 . The purpose is either to block the high-permeability layers with foam and divert the fluids into the low-permeability layers or to create a viscous pressure gradient to oppose gravity override.Foam exhibits two flow regimes depending on the gas fractional flow (i.e., foam quality) in porous media 3 . In the high-quality regime, the pressure gradient along the core is nearly independent of gas superficial velocity, while in the low-quality regime, the pressure gradient is nearly independent of liquid superficial velocity. For a constant total superficial velocity, the high-quality regime is the range of foam quality where the pressure gradient decreases with an increasing foam quality, whereas in the low-quality regime the pressure gradient increases with the increasing foam quality.Most foam models currently in use are built on the concept of the limiting capillary pressure (P c * ), above which foam becomes unstable 4,5 . A basic assumption of these models is that foam in porous media only affects the gas mobility (quotient of the gas relative permeability by its viscosity) and the liquid mobility remains unchanged. This of course simplifies the models and reduces the number of the input parameters based on the experimental observations [6][7][8][9][10] . Bernard et al. 10 were the first to conclude that for a given water saturation presence of foam does not affect liquid relative permeability. Figure 2 in ref. 10 compares the water relative permeability in presence and absence of the foaming agent in a 3.5-Darcy sandpack. At 0.01 wt% and 1.0 wt% surfactant concentrations, the water relative permeability deviates from the rest of the data points. The difference becomes even more pronounced when the data points are plotted on a logarithmic scale. At the lower concentration of 0.01 wt%; however, the presence ...

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Characterizing flow behavior for gas injection: Relative permeability of CO₂‐brine and N₂‐water in heterogeneous rocks

Cited by 116 publications

References 57 publications

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Effect of Foam on Liquid Phase Mobility in Porous Media

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Characterizing flow behavior for gas injection: Relative permeability of CO2‐brine and N2‐water in heterogeneous rocks

Cited by 116 publications

References 57 publications

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Effect of Foam on Liquid Phase Mobility in Porous Media

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Product

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Characterizing flow behavior for gas injection: Relative permeability of CO₂‐brine and N₂‐water in heterogeneous rocks