Numerical investigation of barite scaling kinetics in fractures

Tranter, Morgan; Lucia, Marco De; Kühn, Michael

doi:10.1016/j.geothermics.2020.102027

Cited by 13 publications

(14 citation statements)

References 35 publications

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“…Furthermore, smaller apertures were associated with an increased scaling risk. This finding corresponds to a numerical study for single fractures on the laboratory scale [16], where low fracture aperture was identified as the most important parameter, next to barite supersaturation. This was attributed to the specific inner surface area, which is inversely related to the aperture for an idealised fracture.…”

Section: Scenario Analysissupporting

confidence: 87%

“…The clogging process of barite precipitation in porous and fractured reservoir rock was investigated recently at the laboratory scale, showing significant permeability loss by up to one order of magnitude of the core samples [15]. Fracture aperture is a key parameter here; a numerical study suggests that large fractures are less susceptible to scaling-induced permeability loss, due to the variations in specific reactive surface area [16].…”

Section: Introductionmentioning

confidence: 99%

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Barite Scaling Potential Modelled for Fractured-Porous Geothermal Reservoirs

2021

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Barite scalings are a common cause of permanent formation damage to deep geothermal reservoirs. Well injectivity can be impaired because the ooling of saline fluids reduces the solubility of barite, and the continuous re-injection of supersaturated fluids forces barite to precipitate in the host rock. Stimulated reservoirs in the Upper Rhine Graben often have multiple relevant flow paths in the porous matrix and fracture zones, sometimes spanning multiple stratigraphical units to achieve the economically necessary injectivity. While the influence of barite scaling on injectivity has been investigated for purely porous media, the role of fractures within reservoirs consisting of both fractured and porous sections is still not well understood. Here, we present hydro-chemical simulations of a dual-layer geothermal reservoir to study the long-term impact of barite scale formation on well injectivity. Our results show that, compared to purely porous reservoirs, fractured porous reservoirs have a significantly reduced scaling risk by up to 50%, depending on the flow rate ratio of fractures. Injectivity loss is doubled, however, if the amount of active fractures is increased by one order of magnitude, while the mean fracture aperture is decreased, provided the fractured aquifer dictates the injection rate. We conclude that fractured, and especially hydraulically stimulated, reservoirs are generally less affected by barite scaling and that large, but few, fractures are favourable. We present a scaling score for fractured-porous reservoirs, which is composed of easily derivable quantities such as the radial equilibrium length and precipitation potential. This score is suggested for use approximating the scaling potential and its impact on injectivity of a fractured-porous reservoir for geothermal exploitation.

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Section: Scenario Analysissupporting

confidence: 87%

Section: Introductionmentioning

confidence: 99%

Barite Scaling Potential Modelled for Fractured-Porous Geothermal Reservoirs

2021

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“…The barite saturation index decreased significantly in the effluent. Elevated temperature and pressure could promote barite precipitation by increasing nucleation and crystal growth rate once the fluid was injected into the shale cores.…”

Section: Results and Discussionmentioning

confidence: 99%

Influence of Flow Pathway Geometry on Barite Scale Deposition in Marcellus Shale during Hydraulic Fracturing

et al. 2021

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Barite scaling is a common problem in the shale gas industry. Barite precipitation due to rock-fluid interactions has been studied intensively in static and flow-through experiments, but the impact of flow pathway geometry on barite scaling remains a question. The complex fracture passages can lead to local concentrated geochemical interactions, resulting in spatially variable scaling distribution. In this study, designed patterns with channels and holes were milled in two Marcellus shale cores to represent the main flow pathways, where the slow flow travels from the inlet to the outlet, and near-stagnant zones, where the fluid is trapped. Hydraulic fracturing fluid, created using synthetic produced water and Monongahela River water as base fluid, was injected at 0.02 mL/min into the cores at 66 °C, a core pressure of 12.4 MPa (1800 psi), and a confining pressure of 13.8 MPa (2000 psi) for 28 days. For the core with both channels and holes, barite coatings formed in the channels and the holes, with thicker barite accumulations occurring on the non-patterned half of the core adjacent to the holes on the milled half. For the core with only holes, proppants were added to prop up the main flow pathways. Barite formed on the propped fracture surface. The proppants in the holes were covered with and glued together by barite. Such barite-proppant conglomerates were not found in the main propped fracture. These barite-proppant conglomerates may block transport pathways as well as the barite coatings.

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“…barite (e.g. Tranter et al, 2021), resulting in increased bulk density. Therefore, the gravity data allow a much better spatial resolution of the potentially permeable fracture zones than the structural geological information alone.…”

Numerical investigation of barite scaling kinetics in fractures

Cited by 13 publications

References 35 publications

Barite Scaling Potential Modelled for Fractured-Porous Geothermal Reservoirs

Barite Scaling Potential Modelled for Fractured-Porous Geothermal Reservoirs

Influence of Flow Pathway Geometry on Barite Scale Deposition in Marcellus Shale during Hydraulic Fracturing

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