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Research Papers: Petroleum Engineering

Shale Caprock/Acidic Brine Interaction in Underground CO2 Storage

[+] Author and Article Information
Abiola Olabode

Craft & Hawkins
Department of
Petroleum Engineering,
Louisiana State University,
2129 Patrick F. Taylor Hall,
Baton Rouge, LA 70803
e-mail: aolabo2@lsu.edu

Mileva Radonjic

Craft & Hawkins
Department of
Petroleum Engineering,
Louisiana State University,
2131 Patrick F. Taylor Hall,
Baton Rouge, LA 70803
e-mail: mileva@lsu.edu

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received October 3, 2013; final manuscript received February 6, 2014; published online June 5, 2014. Assoc. Editor: Andrew K. Wojtanowicz.

J. Energy Resour. Technol 136(4), 042901 (Jun 05, 2014) (6 pages) Paper No: JERT-13-1281; doi: 10.1115/1.4027567 History: Received October 03, 2013; Revised February 06, 2014

Shale caprock integrity is critical in ensuring that subsurface injection and storage of anthropogenic carbon dioxide (CO2) is permanent. The interaction of clay-rich rock with aqueous CO2 under dynamic conditions requires characterization at the nanoscale level due to the low-reactivity of clay minerals. Geochemical mineral–fluid interaction can impact properties of shale rocks primarily through changes in pore geometry/connectivity. The experimental work reported in this paper applied specific analytical techniques in investigating changes in surface/near-surface properties of crushed shale rocks after exposure (by flooding) to CO2–brine for a time frame ranging between 30 days and 92 days at elevated pressure and fractional flow rate. The intrinsically low permeability in shale may be altered by changes in surface properties as the effective permeability of any porous medium is largely a function of its global pore geometry. Diffusive transport of CO2 as well as carbon accounting could be significantly affected over the long term. The estimation of permeability ratio indicated that petrophysical properties of shale caprock can be doubled.

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Figures

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Fig. 4

X-ray diffractogram of bulk mineralogical analysis of CO2–brine reacted shale (sample B) before and after the 3-month experiment. The peaks are better resolved in post-reacted samples suggesting better crystallinity. In addition, Muscovite decrease is observed and an increase in Chlorite, although Feldspar seems to be unchanged.

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Fig. 5

X-ray diffractogram for bulk mineralogical analysis of CO2–brine contacted shale (sample C) before and after the 3-month experiment. Albite and Kaolinite ratio to Feldspar changed over the course of 92 days, while Muscovite/Chlorite to Feldspar ratio is not significantly changed differing from samples A and B.

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Fig. 6

X-ray diffractogram for bulk mineralogical analysis of precipitates obtained from CO2–brine contacted shale samples' effluent after the 3-month experiment. It showed high pitch noise indicating large amorphous content in the precipitates.

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Fig. 9

Cumulative specific surface area for sample C with less than 5.5 nm pores over the 3 months of CO2–brine flooding. It shows that significant surface area changes occur in pore sizes that are less than 3.5 nm with net overall increase at the end of the third month.

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Fig. 8

Cumulative specific surface area for sample B with less than 5.5 nm pores over the 3 months of CO2–brine flooding. It shows that significant surface area changes occur in pore sizes that are less than 3.5 nm with net overall increase at the end of the third month.

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Fig. 7

Cumulative specific surface area for sample A with less than 5.5 nm pores over the 3 months of CO2–brine flooding. It shows that significant surface area changes occur in pore sizes that are less than 3.5 nm with the surface area converging back to the control sample initial value.

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Fig. 3

X-ray diffractogram for bulk mineralogical analysis of CO2–brine contacted shale (sample A) before and after the 3-month experiment. It showed less noise in the CO2–brine contacted sample indicating reduced amorphous content. The most significant changes in the ratio of Feldspar to Muscovite and Chlorite with an increased presence of the later minerals as experiment progressed.

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Fig. 2

pH evolution chart of effluent from shale/CO2–brine flooding experiment over a 3-month period. Three distinct regions of pH change indicate the geochemical buffer strength of the shale caprock under continuous contact mode.

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Fig. 1

Schematics of experimental setup in shale-CO2–brine flooding

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Fig. 10

Plot of permeability ratio of the shale caprock samples over the 3-month experimental period. Sample B consistently had the lowest ratio indicating a strong resistance to flow within connected rock matrix pores.

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