The Multiphase Flow Properties of the CO2/water system in Reservoir Rocks

Sam Krevor, Ronny Pini, Lin Zuo, Boxiao Li, Sally M. BensonEnergy Resources Engineering, Stanford University

A GE medical CT Scanner is used to perform the scans of the core. The entire setup, including six pumps, heat exchangers, and high pressure tubing is set up in the scanning room.

An aluminum core holder with heating control is used to hold the core during experiments. Cores are sealed in concentric jackets of teflon and nickel foil.

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The Rocks

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The Method

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Four sandstone rock cores, 5.08cm in diameter and 10 cm long, were used representing a range of reservoir properties and rock types. The above figures show the variation in porosity in each core. A Berea was used because of its utility in making comparisons with other studies.

Three other rocks, one each from the Paaratte formation in Southern Australia, the Mt. Simon in Illinois, and the Tuscaloosa massive sand from Alabama are from target reservoirs where large volume CO2 injection pilot projects are either underway or under development.

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Challenge: Different Flow Regimes

•  Multiphase flow parameters (relative permeability) are best understood in the viscous dominated regime

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Capillary Dominated

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- A large number of simulation studies have demonstrated the importance of understanding the multiphase flow properties of CO2/water systems for accurate characterization of the movement and immobilization of CO2 injected into the subsurface.

- These studies show that the ultimate distribution of CO2 in the subsurface is sensitive to the character of the relative permeability characteristic curves, that hysteresis in the relative permeability function plays a large role in determining the ultimate distribution of the CO2 plume, and that intra-reservoir capillary trapping can immobilize significant percentages of injected CO2 as a residual phase.

- At the same time, there is limited experimental observation of these properties at reservoir conditions. - In this work, we have performed multiphase flow characterization tests using water and supercritical CO2 with four sandstone rocks

representing a range of reservoir characteristics. - We were interested to resolve issues regarding the endpoint relative permeability and the nature of residual trapping in various rock

lithologies. Additionally, the use of the Berea allows for a comparison of these results with past studies using both CO2/brine systems and oil/brine systems and an assessment of the suitability of using analogue fluid systems in characterizing flow properties relevant to the CO2/water system.

Berea915 mD

Porosity

Mt. Simon7.5 mD

Paaratte1156 mD

Tuscaloosa220 mD

Steady state relative permeability tests were performed to derive the relative permeabilty-saturation relationship for the CO2/water system in each core at 50 C and 9 MPa pore pressure. Using the steady-state method allowed us to asses the impact of common issues in core-flooding experiments such as capillary end effects, heterogeneity, and gravity fluid segregation through x-ray imaging. In the above images are 1-mm slice average saturations along the length of the core during various fractional flows of CO2 and water. The color graphs show the sub-core

CO2 saturation during 90% CO2 flow. Both show that capillary end effects and gravity segregation of the fluids are not playing a large role in the relative permeability estimate for each rock.

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CO2 Saturation

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TuscaloosaMt. Simon

Multiphase Flow Characterization

Relative Permeability

- The results of the four drainage relative permeability tests are shown in the above figure. Relative permeability varies as expected with lithologic properties of the rocks; The high permeability Berea and Paaratte are similar, the Tuscaloosa exhibits the flow characteristics of a poorly sorted rock, and the Mt. Simon is somewhere in between.

- Low CO2 saturations persist, even at the highest fractional flow rates, as has been seen in previous studies. We have shown that this results from the limitations in capillary pressure that can be achieved with the low viscosity CO2 in typical coor-flooding setups [1].

- The results for the Berea are shown with data from [3] for CO2/brine at 12.4 MPa pore pressure and 50 C on a Berea sandstone with permeability 430 mD, and from [4] in which the same results were obtained for both oil/water and N2/water in a 200 mD Berea. The observations made in this study are virtually indistinguishable from the past measurements made with CO2/brine, oil/water, and N2/water systems. This suggests that the use of analogue fluids is appropriate for rock characterization relevant to CO2 flooding.

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The Impact of Heterogeneity

- In one core, we had the opportunity to investigate the impact of a natural heterogeneity on the flow properties of the rock. - A piece of the Mt. Simon core had two regions of distinct capillarity: An upstream 10 cm long region of the core consisted of a relatively high

permeability and homogenous sand. A downstream 3 cm long region of the core consisted of a low permeability region characterized by significant cross-bedding and a high capillary entry pressure for CO2.

- During a drainage process of CO2 displacing water, CO2 builds up upstream of the capillary barrier. - Once in place, CO2 on the upstream side of the barrier cannot be displaced during 100% water flooding leading to trapped saturations that are a

factor 2-5 times higher than what would be expected from residual trapping alone.- Simulation results are shown on the right. The characteristic saturation buildup and good matches for the pressure drop across the core could be

obtained if the bulk core and barrier had permeabilities of 7.5 Darcy and .01 mD respectively. While this is an exceedingly simple representation of the core, the results indicate that the rock is characterized by bulk regions of high permeability and low capillary entry pressures and thin bedding planes with low permeabilities and high capillary entry pressures.

ACKNOWLEDGEMENTS: The Global Climate and Energy Project and their contributors provided funding for this work.

Residual Trapping

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- Graphs plotting the residual CO2 saturation vs. the initial CO2 saturation prior to imbibition are shown above. - Absolute values for the residual saturation observed in this study (dependent on the maximal CO2 saturation that was obtained) range between

10-33% gas saturation. - The results of the Berea are plotted along with results from [5] for both supercritical CO2/water and decane/water systems in an unfired Berea, and

oil/water and gas/water data from [4] in a fired Berea. The trapping is consistent with what has been observed for both CO2/water systems and analagous fluid systems in Berea sandstone.

- In the case of the Mt. Simon the initial vs. residual curve appears to be non-monotonic, suggestive of a rock with mixed wetting behavior. Interestingly, studies have shown that the CO2/water system is mixed wet on mica surfaces, a mineral that is taken to be an analogue to the illite found in abundance in the Mt. Simon.

[1] Krevor, Pini, Zuo, Benson (Submitted) Relative permeability and trapping of CO2 and water in sandstone rocks at reservoir conditions Water Resources Research[2] Krevor, Pini, Li, Benson. (2011) Capillary heterogeneity trapping of CO2 in a sandstone rock Geophysical Research Letters Vol. 38, L15401[3] Perrin, Benson (2009) An Experimental Study on the Influence of Sub-Core Scale Heterogeneities on CO2 Distribution in Reservoir Rocks Transport in Porous Media, Vol. 82, No 1, pp 93-109[4] Oak (1990) Three-Phase Relative Permeability of Berea Sandstone Journal of Petroleum Technology, Vol. 42, No. 8, pp 1054-1061[5] Pentland, El-Maghraby, Iglauer, Blunt (2011) Measurements of the capillary trapping of super-critical carbon dioxide in Berea sandstone Geophysical Research Letters Vol. 38, L06401