Precipitation of mineral scale in wellbores is a major concern in unconventional shale plays. Mineral scaling can negatively impact well performance, requiring costly well-intervention techniques for scale removal and production downtime. It is crucial to understand types of mineral scale occurring, physicochemical conditions that contribute to scale formation, if field practices have influenced the mineral scale, and identify major sources for mineral scaling unconventional shale systems (e.g., fractured/unfractured shale, injected fluid, and formation/flowback water). Here, mineral scale from wellbores were analyzed using laboratory- and synchrotron-based methods to identify scale material (crystalline and amorphous phases). In an attempt to recreate the mineral scaling on wellbore materials, experiments using coupons from well-casing materials in wellbores were reacted with a variety of injection fluid formulations. Additionally, the variety of injection fluid formulations were reacted with shale core and proppant material to determine if components of mineral scale were sourced the shale and transported and precipitate as a new phase in the wellbore.
Mineral scale in lateral sections of wellbores consisted primarily of Fe(III)-(hydr)oxides, magnetite, and siderite indicating varying redox and chemical conditions during precipitation. Experiments with shale core and proppant showed no new mineral precipitation occurred on the proppant material but new mineral precipitation did occur in the shale itself consisting of celestite (SrSO4) and Fe(III)-(hydr)oxides. Celestite formation occurred in experiments that utilized treated produced water (clean brine) as base fluids, which introduced excess Sr2+ in the system. These experiments suggest mineral precipitation in horizontal wellbores targeting shale reservoirs is likely generated from corrosion of casing materials and further influenced by formation water chemistry through introduction of HCO3− and not from fluid/rock interactions in the stimulated reservoir (SRV).
Unconventional shale reservoir systems are prone to mineral scaling which can adversely affect well performance. The main portions of the system that can be affected are the shale matrix, fracture surfaces, proppant packs, and the wellbore. Previous studies focused on changes to shale matrix and fracture surfaces with varying injection formulations, resulting in a reasonable understanding of major alterations occurring during stimulation (Harrison et al. 2017, Jew et al. 2017a, Jew et al. 2017b, Dustin et al. 2018, Jew et al. 2020a, Paukert Vankeuren et al. 2017, Jew et al. 2021, Jew et al. 2022). These alterations to fracture surfaces and shale matrix are dominated by the particular formulation of stimulation fluids, with minimal effects observed from formation water/flowback due to these solutions being out of equilibrium with the formation. Wellbore mineral scaling is different due to the potential impact of flowback/formation water that is produced from the stimulated rock volume (SRV) into the wellbore following hydraulic fracturing operations and shut-in. The transition between injection to shut-in to production (short- and long-term) represent a wide range of potential subsurface chemical reactions. Injection fluids can be highly acidic if an acid spearhead (pad) is used followed by circumneutral to basic fluids via the clean pad and proppant slurries (Harrison et al. 2017, Jew et al. 2017a, Jew et al. 2017b, Dustin et al. 2018, Jew et al. 2020a, Spielman-Sun 2022, Jew et al. 2021, Jew et al. 2022). An additional complication for understanding mineral scale in horizontal wellbores is the impact of proppant transport through the wellbore during pumping and production operations, which could result in scouring of casing materials to expose fresh surfaces for corrosion. Fluid chemistry during early time production is often characterized as a mixture of injection fluid, formation water, and hydrocarbons, which transitions rapidly overtime (weeks) to primarily hydrocarbons and formation waters. Even if an acid pad spearhead is not pumped during completion, there is a strong redox shift in the subsurface during pumping from the introduction of oxygenated water to even higher oxidizing conditions if oxidizing completion additives such as bleach are used. Redox conditions experienced by wellbores further shift when the well is put on production and formation water begins flowing through the wellbore. Production of formation waters causes the system to become anoxic, and depending on the well, increases in HCO3− and H2S concentrations further influencing the type and occurrence of mineral scale.