| Carbon dioxide has a stronger binding than methane to the organic matter contained in the
matrix of shale rocks [1]. Thus, the injection of CO2 into shale formation may enhance the
production rate and total amount of produced methane, and simultaneously permanently store
pumped CO2. Carbon dioxide can be injected during the initial fracking stage as CO2 based
hydraulic fracturing, and/or later, as a part of enhanced gas recovery (EGR) [2]. Economic
and environmental benefits makes CO2 sequestration in shales potentially very for
industrial-scale operation [3].
However, the effective process requires large area of fracture-matrix interface, where CO2
and CH4 can be exchanged. Usually natural fractures, existing in shale formation, are
preferentially reactivated during hydraulic fracturing, thus they considerably contribute to
the flow paths in the resulting fracture system [4]. Unfortunately, very often these
natural fractures are sealed by calcite [5]. Consequently the layer of calcite coating
surfaces impedes exchange of gases, both CO2 and CH4, between shale matrix and
fracture.
In this communication we address the question whether carbonic acid, formed when CO2 is
mixed with brine, is able to effectively dissolve a calcite layer present in the natural fractures.
We investigate numerically fluid flow and dissolution of calcite coating in natural shale
fractures, with CO2-brine mixture as a reactive fluid. Moreover, we discuss the differences
between slow dissolution (driven by carbonic acid) and fast dissolution (driven by stronger
hydrochloric acid) of calcite layer.
We compare an impact of the flow rate and geometry of the fracture on the parameters of
practical importance: available surface area, morphology of dissolution front, time scale of
the dissolution, and the penetration length. We investigate whether the dissolution is
sufficiently non-uniform to retain the fracture permeability, even in the absence of the
proppant. The sizes of analysed fractures varying from 0.2 x 0.2 m2 up to 4 x 4 m2, together
with discussion of a further upscaling, make the study relevant to the industrial
applications.
While the results of this study should be applicable to different shale formations throughout
the world, we discuss them in the context of preparation to gas-production from Pomeranian
shale basin, located in the northern Poland.
[1] Mosher, K., He, J., Liu, Y., Rupp, E., & Wilcox, J. Molecular simulation of methane
adsorption in micro-and mesoporous carbons with applications to coal and gas shale systems.
International Journal of Coal Geology, 109, 36-44 (2013)
[2] Grieser, W. V., Wheaton, W. E., Magness, W. D., Blauch, M. E., & Loghry, R, "Surface
Reactive Fluid’s Effect on Shale." Proceedings of the Production and Operations Symposium,
31 March-3 April 2007, Oklahoma City (SPE-106815-MS)
[3] Tao, Z. and Clarens, A., Estimating the carbon sequestration capacity of shale formations
using methane production rates, Environmental Science and Technology, 47, 11318-11325
(2013).
[4] Zhang, X., Jeffrey, R. G., & Thiercelin, M. (2009). Mechanics of fluid-driven fracture
growth in naturally fractured reservoirs with simple network geometries. Journal of
Geophysical Research: Solid Earth, 114, B12406 (2009)
[5] Gale, J.F., Laubach, S.E., Olson, J.E., Eichhubl, P., Fall, A. Natural fractures in
shale: A review and new observations. AAPG Bulletin 98(11):2165–2216 (2014) |