Thermal decompaction of rocks

Engelder

et al. 2015

Bulletin

Self Cite

in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to 4 × 10 3 m 3 (7 to 14 × 10 4 ft 3 ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to ∼270 kg∕m 3 (∼16.9 lb∕ft 3 ) in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ∼10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%-0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ∼1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Section: Computation Of Salt Diffusion Into the Fracturementioning

confidence: 96%

A model describing flowback chemistry changes with time after Marcellus Shale hydraulic fracturing

Engelder

et al. 2015

Bulletin

Self Cite

“…The ''standard'' n F = 1.5 is based on data for igneous rocks of low permeability (Balashov and Zaraisky, 1982;Zaraisky and Balashov, 1995). For porosities of sandstone of 0.25 and shale of 0.05, the inverse factor equals 0.16 and 0.007, respectively (i.e.…”

Section: Reactive Transport Modelingmentioning

confidence: 99%

Reaction and diffusion at the reservoir/shale interface during CO2 storage: Impact of geochemical kinetics

Guthrie

Lopano

et al. 2015

Applied Geochemistry

Self Cite

Editorial handling by M. Kersten a b s t r a c tWe use a reactive diffusion model to investigate what happens to CO 2 injected into a subsurface sandstone reservoir capped by a chlorite-and illite-containing shale seal. The calculations simulate reaction and transport of supercritical (SC) CO 2 at 348.15 K and 30 MPa up to 20,000 a. Given the low shale porosity (5%), chemical reactions mostly occurred in the sandstone for the first 2000 a with some precipitation at the ss/sh interface. From 2000 to 4000 a, ankerite, dolomite and illite began replacing Mg-Fe chlorite at the sandstone/shale interface. Transformation of chlorite to ankerite is the dominant reaction occluding the shale porosity in most simulations: from 4000 to 7500 a, this carbonation seals the reservoir and terminates reaction. Overall, the carbonates (calcite, ankerite, dolomite), chlorite and goethite all remain close to local chemical equilibrium with brine. Quartz is almost inert from the point of its dissolution/-precipitation. However, the rate of quartz reaction controls the long-term decline in aqueous silica activity and its evolution toward equilibrium. The reactions of feldspars and clays depend strongly on their reaction rate constants (microcline is closer to local equilibrium than albite). The timing of porosity occlusion mostly therefore depends on the kinetic constants of kaolinite and illite. For example, an increase in the kaolinite kinetic constant by 0.25 logarithmic units hastened porosity closure by 4300 a. The earliest simulated closure of porosity occurred at approximately 108 a for simulations designed as sensitivity tests for the rate constants.These simulations also emphasize that the rate of CO 2 immobilization as aqueous bicarbonate (solubility trapping) or as carbonate minerals (mineral trapping) in sandstone reservoirs depends upon reaction kinetics -but the relative fraction of each trapped CO 2 species only depends upon the initial chemical composition of the host sandstone. For example, at the point of porosity occlusion the fraction of bicarbonate remaining in solution depends upon the initial Na and K content in the host rock but the fraction of carbonate mineralization depends only on the Ca, Mg, Fe content. Since ankerite is the dominant mineral that occludes porosity, the dissolved concentration of ferrous iron is also an important parameter. Future efforts should focus on cross-comparisons and ground-truthing of simulations made for standard case studies as well as laboratory measurements of the reactivities of clay minerals.

“…Fick's first law for diffusion through porous media for one dimension is (Archie, 1942;Brace, 1977): Here this factor is approximated as , with tortuosity coefficient for packed spheres, is equal to 1 for sandstone, and 1.5 for shale. The "standard" F n = 1.5 is based on data for igneous rocks of low permeability (Zaraisky and Balashov, 1995;Balashov and Zaraisky, 1982). At a sandstone porosity of 0.25, and shale porosity of 0.05, the inverse factor equals 0.16 and 0.007 for sandstone and shale, respectively, with a ss/sh ratio 22.7.…”

Section: Variation Of the Transport Properties Of The Shale Porous Mementioning

confidence: 99%

Predictive Modeling of CO<sub>2</sub> Sequestration and Storage in Deep Saline Sandstone Reservoirs: Sensitivity Analysis of Mineral Rates in Reactive Transport

Brantley

Guthrie

et al. 2017

Self Cite