Laboratory Testing to Assess Suitability of Geological Storage Prospects and the Associated Risks of CO2 Hydrates During CO2Injection (III) – Assessment of Thermal Hydrate Inhibitors

Abstract

Abstract Most emerging techniques for laboratory evaluation of Carbon Capture Utilization and Storage (CCUS) projects refer to traditional geoscience core analysis methods of porosity, permeability, mineralogy caprock integrity, etc. However, analytical programs must go beyond typical oil and gas reservoir evaluation workflows when assessing injectivity impairment and measurements to control it. This work aims to highlight key operational challenges related to CO2 injection into low-pressure target formations and provides a new approach to assessing injectivity impairment caused by CO2 hydrates formation in the near wellbore. Newly built core flooding apparatus, designed specifically for low temperature conditions, has been used to measure permeability changes during injection of liquid or gaseous carbon dioxide across a range of formation water compositions, fluid saturations, temperatures (-25 °C to + 30 °C) and pressures to demonstrate the effect on injectivity of various formation damage mechanisms, including formation of CO2 hydrates, scale and ice. This work required design of a new test rig and approach for the range of conditions expected in CO2 injection into depressurized hydrocarbon reservoirs (mainly low-pressure gas fields). Controlled, repeatable generation of the damage mechanism is required to evaluate preventative and remediation options, such as chemical inhibitors. Initial testing of the apparatus involved injection under hydrates-forming conditions by varying pressure while flowing CO2 into a core at various brine saturations, where severe blockages were observed to form. Altering the input parameters, enables the locus of CO2 hydrates to be located in this porous medium as well as determining their formation kinetics and likely plugging mechanism. Reproduction of injectivity impairment under a variety of conditions demonstrated the ability to form, dissipate and re-form hydrates, which then allowed the performance testing of inhibitors, which were shown either to limit or eliminate injectivity impairment. The current paper presents use of the equipment and methodologies to assess the application of the thermodynamic hydrate inhibitor, monoethylene glycol (MEG), to circumvent this impairment and to determine the minimum required dose of the inhibitor to prevent CO2 hydrates within a porous medium. By quantifying the MEG dose requirement in this manner, this hydrates-suppressing chemical can be used either to design well treatments using it either as an inhibitor or for remediation of a partial blockage caused by a CO2 hydrate in the near-wellbore of a CCUS well.