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Assessment of CO2 Injectivity During Sequestration in Depleted Gas Reservoirs

Division of Physical Science and Engineering, King Abdullah University of Science and Technology, KAUST, Building 5/3221, Thuwal 23955-6900, Saudi Arabia
Laboratoire d’Hydrologie et Geochemie de Strasbourg, University of Strasbourg/ENGEES/CNRS, 67084 Strasbourg, France
Departments of Geology and Environmental Engineering, University of Cincinnati, Cincinnati, OH 45221, USA
Author to whom correspondence should be addressed.
Geosciences 2019, 9(5), 199;
Received: 3 April 2019 / Revised: 14 April 2019 / Accepted: 18 April 2019 / Published: 5 May 2019
PDF [1608 KB, uploaded 5 May 2019]


Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO 2 transitions from the dense-state to the gas-state, CO 2 density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO 2 expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO 2 expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO 2 injectivity. Understanding the transient multiphase phase flow behavior of CO 2 within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO 2 from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO 2 within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO 2 heating at the wellhead are assessed. View Full-Text
Keywords: CO2 sequestration; depleted gas reservoirs; flow assurance; Joule–Thomson effect; CO2 hydrates CO2 sequestration; depleted gas reservoirs; flow assurance; Joule–Thomson effect; CO2 hydrates

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This is an open access article distributed under the Creative Commons Attribution License which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited (CC BY 4.0).

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Hoteit, H.; Fahs, M.; Soltanian, M.R. Assessment of CO2 Injectivity During Sequestration in Depleted Gas Reservoirs. Geosciences 2019, 9, 199.

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