Estimating CO2 Fluxes Along Leaky Wellbores

Abstract

Summary Large-scale geological storage of carbon dioxide (CO2) is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. Knowing the range of effective permeability of faulty cement is essential for estimating the risk of CO2 leakage. The central premise of this paper is that the leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the leakage pathway in any wellbore that CO2 might encounter. Thus, field observations of SCP can be used to estimate transport properties of a CO2-leakage pathway. Uncertainty in the estimate can be reduced by accounting for constraints from well-construction geometry and from physical considerations. We then describe a simple CO2-leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant-pressure) exit. The latter assumption provides a worst-case leakage flux. By use of pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for the cases of buoyancy-driven (post-injection) and pressure-driven (during injection) leakage. Assuming the frequency distribution is representative of SCP wells, we observe that in leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure (several psi/D), the effective permeability of the leakage path is in the range of microdarcies to hundreds of microdarcies, and the corresponding CO2 fluxes are comparable with naturally occurring background fluxes observed at the ground surface. In pathways corresponding to intermediate and fast buildup rate of casing pressure (tens to hundreds of psi/D), the effective permeability is in the range of tenths to tens of millidarcies, and the CO2 fluxes are comparable with surface flux measurements at the Illinois basin and at the natural seep at Crystal Geyser (Utah). In pathways corresponding to very fast buildup rate (thousands of psi/D), the effective permeability is from tens to hundreds of millidarcies and the CO2 fluxes are up to three orders of magnitude higher than those measured at Crystal Geyser.

Modeling Gas Migration, Sustained Casing Pressure, and Surface Casing Vent Flow in Onshore Oil and Gas Wells

“…In our simulation, we assumed the same well properties as Xu and Wojtanowicz () with the exception of an effective cement permeability of 5 × 10 −15 m 2 instead of 1.48 × 10 −15 m 2 (Table ). The larger effective cement permeability was required to match the SCP data using our modeling approach because we did not assume steady state gas flow through the cement column as done in previous models (Rocha‐Valadez et al, ; Tao et al, ; Xu & Wojtanowicz, ). Furthermore, we assumed variable gas viscosity and compressibility in the cement column in contrast to the Xu and Wojtanowicz () model that assumed constant gas properties.…”

“…Previous work has interpreted SCP and SCVF data with the assumption that all leaked gas remains in the wellbore and either collects in the headspace above the annular liquid or escapes as SCVF (Tao et al, ; Xu & Wojtanowicz, ). However, evidence from Alberta, where over 2,000 wells exhibited gas migration in the absence of SCVF (Bachu, ), and Colorado, where over 270 wells exhibited a level of SCP sufficient to displace the annular liquid in the surface casing of the well (Lackey et al, ), suggests that gas can escape the wellbore below the wellhead and influence SCP/SCVF behavior.…”

“…As previously noted, we represented the vertical flow of stray gas through damaged cement as single‐phase real gas flow through a porous medium with an effective cement permeability that reflects cement quality. With the exception of Nemer et al (), who modeled two‐phase flow (nitrogen and crude oil) through the faulty cement of wells at the U.S. Strategic Petroleum Reserve, previous SCP modeling studies employed a single‐phase approach to model gas flow through cement in previous SCP modeling studies (Rocha‐Valadez et al, ; Somei, ; Tao et al, ; Xu & Wojtanowicz, , ). We also neglected the compressibility of cement and microannuli in comparison to the compressibility of the gas.…”

Sealing of fractures in a representative CO2 reservoir caprock by migration of fines

“…In carbon capture and storage operations pressure build up has been reported to change over time and can be as high or higher than the 1.72–2.14 MPa pressure that was used for the pressure drop in this study (Table 1). 29 …”

A model of cement-formation interface failure length in supercritical CO2-ECBM and storage injection well considering the coal swelling effect under high pressure

“…One of the main risks identified with storing CO 2 in the subsurface is the potential for leakage through existing wells penetrating the caprock (Nygaard et al 2014). Tao et al (2014) developed a prediction model of CO 2 leakage rate along wellbore based on sustained casing pressure data. Loizzo et al (2011) studied four leakage pathway classes of wellbore including mud channels, chimneys, micro-annuli and no cement, and quantified the risk of leakage.…”