RESEARCH ARTICLE


A Novel Approach to Detect Tubing Leakage in Carbon Dioxide (CO) Injection Wells via an Efficient Annular Pressure Monitoring



Liang-Biao Ouyang
Chevron Corporation, P. O. Box 5095, Bellaire, TX 77402-5095, USA.


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© 2015 Ouyang et al.;

open-access license: This is an open access article distributed under the terms of the Creative Commons Attribution 4.0 International Public License (CC-BY 4.0), a copy of which is available at: https://creativecommons.org/licenses/by/4.0/legalcode. This license permits unrestricted use, distribution, and reproduction in any medium, provided the original author and source are credited.

Correspondence: * Address correspondence to this author at the Chevron Corporation, P. O. Box 5095, Bellaire, TX 77402-5095, USA.


Abstract

Due to the unique corrosion potential and safety hazards of carbon dioxide (CO), tubing leakage of CO in a CO injection well may occur and lead to undesired consequences to environment, human being and facility. As a result, quick detection of any carbon dioxide leakage and accurate identification of leakage location are extremely beneficial to obtain critical information to fix the leakage in a prompt manner, prevent incidents / injury / casualty, and achieve high standards of operational safety. Annular pressure monitoring has been identified as an effective and reliable approach for detecting tubing and casing leakage of fluids (including hazardous gas like CO) in a well. Accurate prediction of annular pressure change associated with the leakage will certainly help the operation. In an effort to assess annular pressure characteristics and thus improve understanding of tubing leakage, a multiphase dynamic modeling approach has been applied to simulate the carbon dioxide, completion brine and formation water’s flow and associated heat transfer processes along wellbore, tubing and annulus in carbon dioxide injection wells designed for carbon capture and sequestration (CCS) [1] projects. Two operational scenarios – one for routine CO injection and another for well shut-in – have been considered in the investigation. Key parameters that may have significant impacts on the process have been investigated. On the basis of the investigation, a novel approach has been proposed in the paper for quickly detecting the leakage of carbon dioxide in a CO injection well. Two simple equations have been developed to pinpoint the leakage location by means of real-time measurement and monitoring of the change in annular pressure. Recommendations based on a series of dynamic simulation results have been provided and can be readily incorporated into detailed operating procedures to enhance carbon dioxide injection wells’ operational safety.

Keywords: Annular pressure, carbon capture and sequestration, carbon dioxide, injection well, OLGA, tubing leakage.