Effect of Sub-core Scale Heterogeneity on Relative Permeability Curves of Porous Sandstone in a Water-supercritical CO2 System

Kogure, Tetsuya; Nishizawa, Osamu; Chiyonobu, Shun; Yazaki, Yukihiro; Shibatani, Seiji; Xue, Ziqiu

doi:10.1016/j.egypro.2013.06.354

Cited by 12 publications

(11 citation statements)

References 1 publication

Supporting

Mentioning

Contrasting

Order By: Relevance

“… Compilation of capillary number‐saturation data for drainage CO 2 ‐brine relative permeability core floods from Akbarabadi and Piri [], Bachu and Bennion [], Bennion and Bachu [], Kogure et al . [], Krause et al . [], Krevor et al .…”

Section: Discussionmentioning

confidence: 99%

“…Capillary number is calculated for all CO 2 ‐brine steady state drainage relative permeability data sets reported in the literature, for which fractional flow data are reported [ Akbarabadi and Piri , ; Bachu and Bennion , ; Bennion and Bachu , ; Kogure et al ., ; Krause et al ., ; Krevor et al ., ; Manceau et al ., ; Perrin and Benson , ; Pini and Benson , ; Ruprecht et al ., ; Zhang et al ., ]. If Δ P is not reported, this is calculated from the data provided using the multiphase extension to Darcy's law (equation ).…”

Section: Scaling Heterogeneity In Co2‐brine Core Floodsmentioning

confidence: 99%

See 1 more Smart Citation

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

Reynolds

Krevor

2015

Water Resources Research

122

144

View full text Add to dashboard Cite

We provide a comprehensive experimental study of steady state, drainage relative permeability curves with CO 2 -brine and N 2 -deionized water, on a single Bentheimer sandstone core with a simple two-layer heterogeneity. We demonstrate that, if measured in the viscous limit, relative permeability is invariant with changing reservoir conditions, and is consistent with the continuum-scale multiphase flow theory for water wet systems. Furthermore, we show that under capillary limited conditions, the CO 2 -brine system is very sensitive to heterogeneity in capillary pressure, and by performing core floods under capillary limited conditions, we produce effective relative permeability curves that are flow rate and fluid parameter dependent. We suggest that the major uncertainty in past observations of CO 2 -brine relative permeability curves is due to the interaction of CO 2 flow with pore space heterogeneity under capillary limited conditions and is not due to the effects of changing reservoir conditions. We show that the appropriate conditions for measuring intrinsic or effective relative permeability curves can be selected simply by scaling the driving force for flow by a quantification of capillary heterogeneity. Measuring one or two effective curves on a core with capillary heterogeneity that is representative of the reservoir will be sufficient for reservoir simulation.

show abstract

Section: Discussionmentioning

confidence: 99%

Section: Scaling Heterogeneity In Co2‐brine Core Floodsmentioning

confidence: 99%

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

Reynolds

Krevor

2015

Water Resources Research

122

144

View full text Add to dashboard Cite

show abstract

“…Dissolution pathways were determined by variable distributions of the physical features (e.g., microfractures) and reactive phases present in the rock. Sub‐core scale heterogeneity usually includes both pore size distribution and micro structures of rock associated with tectonic activities . Perrin and Benson conducted CO 2 /brine two‐phase flow experiments under reservoir conditions using two samples of different heterogeneities, with a focus on the connectivity of high porosity layers.…”

Section: Introductionmentioning

confidence: 99%

“…Sub-core scale heterogeneity usually includes both pore size distribution and micro structures of rock associated with tectonic activities. 21 Perrin and Benson 22 conducted CO 2 /brine two-phase flow experiments under reservoir conditions using two samples of different heterogeneities, with a focus on the connectivity of high porosity layers. Their results highlighted the strong influence of sub-core scale heterogeneities on the spatial distribution of steady state CO 2 .…”

Section: Introductionmentioning

confidence: 99%

Pore‐scale investigation of effects of heterogeneity on CO₂ geological storage using stratified sand packs

Liu

Jiang

et al. 2017

Greenhouse Gases

View full text Add to dashboard Cite

The geological sequestration of CO2 is considered to have great potential. However, the heterogeneity that characterizes most geological reservoirs significantly affects the migration, trapping, and leakage of CO2. The present study involved a pore‐scale investigation of the effects of heterogeneity in pore size and wettability using stratified sand packs. A stratified glass bead (BZ06+BZ02) pack and a quartz+dolomite pack were introduced in flow experiments at gaseous CO2 (gCO2) and supercritical CO2 (scCO2) conditions. Different injection rates, namely, 0.1, 0.3, and 0.6 mL/min, were applied to the drainage while a constant rate of 0.1 mL/min was maintained for the imbibition. High resolution CT imaging and subsequent processing of the images were used to analyze the effects of heterogeneity in pore size and wettability. The results indicate that heterogeneity in pore size and wettability alters the intrinsic percolation abilities of the individual layers of the stratified structure and weaken the linear correlation between CO2 volume and slice‐averaged porosity. It was also observed that water films sometimes exist in the layers with smaller pore spaces after drainage and it can trigger snap off events. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

show abstract

“…This effect is further enhanced by the spatial distribution and orientation of the heterogeneities relative to the direction of flow. Kogure et al . measured the relative permeability for the water–CO 2 system in sandstones during an injection experiment by using X‐ray technology.…”

Section: Introductionmentioning

confidence: 99%

Experimental determination of wettability and heterogeneity effect on CO₂ distribution in porous media

Liu

Jiang

et al. 2015

Greenhouse Gases

View full text Add to dashboard Cite

The geological sequestration of carbon dioxide (CO2) is considered a promising technology for CO2 emissions. However, accurate estimation of the storage capacity for CO2 remains a challenge owing to the effect of capillary pressure variation. The CO2‐salty aqueous contact angle and sub‐core scale heterogeneity are the major factors that influence capillary pressure. This paper reports the results of CO2/brine two‐phase flow experiments in porous media by using an X‐ray computed tomography (CT) technique at 40°C and 8 Mpa and examines the strong influence of wettability and sub‐core scale heterogeneities on the spatial distribution of CO2. Gas injection experiments were conducted at flow rates of 0.1 mL/min, 0.2 mL/min, and 0.5 mL/min, and the porous media were packed with feldspar, quartz, or dolomite. This study indicates that at the core scale, the wettability of porous media is a crucial factor in determining CO2 saturation. Capillary fingering and low CO2 saturation occurred with high water wettability. Sub‐core scale heterogeneities controlled the CO2 distribution and saturation variation along the porous media, particular that with small pore sizes. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

show abstract

Effect of Sub-core Scale Heterogeneity on Relative Permeability Curves of Porous Sandstone in a Water-supercritical CO2 System

Cited by 12 publications

References 1 publication

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

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

Pore‐scale investigation of effects of heterogeneity on CO₂ geological storage using stratified sand packs

Experimental determination of wettability and heterogeneity effect on CO₂ distribution in porous media

Contact Info

Product

Resources

About

Effect of Sub-core Scale Heterogeneity on Relative Permeability Curves of Porous Sandstone in a Water-supercritical CO2 System

Cited by 12 publications

References 1 publication

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

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

Pore‐scale investigation of effects of heterogeneity on CO2 geological storage using stratified sand packs

Experimental determination of wettability and heterogeneity effect on CO2 distribution in porous media

Contact Info

Product

Resources

About

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

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

Pore‐scale investigation of effects of heterogeneity on CO₂ geological storage using stratified sand packs

Experimental determination of wettability and heterogeneity effect on CO₂ distribution in porous media