An improved model to forecast CO2 leakage rates along a wellbore

Tao, Qing; Checkai, Dean; Huerta, Nicolas; Bryant, Steven L.

doi:10.1016/j.egypro.2011.02.522

Cited by 20 publications

(8 citation statements)

References 7 publications

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“…The second source is observations of sustained casing pressure (SCP), see Figure 2 (Bourgoyne et al, 2000;Watson and Bachu, 2007;Tao et al, 2010bTao et al, , 2011. These are observations of gas leakage occurring within one or more internal annuli of a well ( Figure 3) and are monitored by pressure gauges or vent lines on the annuli.…”

Section: Introductionmentioning

confidence: 99%

Probability Distributions for Effective Permeability of Potentially Leaking Wells at CO<sub>2</sub> Sequestration Sites

Carey

2018

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Cover Illustration: A probability distribution of permeability of wells at a hypothetical sequestration site with 1,000 older wells. The wells range from very secure (permeability < 10-18 m 2), to very minor leakage (< 10-16 m 2), to measurable leakage (>10-16 m 2), to significant leakage (>10-12 m 2). The total permeability of the wells is equivalent to 10 D (Darcy), which is dominated by a single defective well. The inset shows a closeup view of leakage pathways in a wellbore system consisting of steel casing, a cement plug, a partially cementfilled annulus and caprock.

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Section: Introductionmentioning

confidence: 99%

Probability Distributions for Effective Permeability of Potentially Leaking Wells at CO<sub>2</sub> Sequestration Sites

Carey

2018

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“…Consequences of leakage can be presented in the form of leaked volume to shallow fresh water aquifers or to the atmosphere. Researchers have also used numerical modeling techniques for well leakage analysis . Nogues et al .…”

Section: Introductionmentioning

confidence: 99%

“…Researchers have also used numerical modeling techniques for well leakage analysis. 9,16,46,[52][53][54][55][56][57][58][59][60][61][62] Nogues et al 46 proposed a simplified formulation to estimate leakage along old wells and pointed out that there could be high uncertainties associated with different parameters in the estimation of maximum probable leakage. Gaurina-Međimurec and Mavar 63 investigated the CO 2 leakage risk from a storage zone looking at different leakage sources and categorized the leaks according to their severity.…”

Section: Introductionmentioning

confidence: 99%

Field‐scale well leakage risk assessment using reduced‐order models

2019

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Oil wells that intersect a potential CO2 storage zone in a depleted oil and gas field may provide leakage pathways. It is essential to estimate the field‐scale leakage risk associated with these wells. In this study, a risk‐based approach is used to estimate the risk of leakage. Existing reduced‐order models for well leakage are used to quantitatively estimate well leakage rates for cased‐cemented, cased‐uncemented, and open wellbores. For each existing well that intersects the storage zone, we introduce the well leakage index (WLI), which accounts for wellbore geometry, distance from the injection well, buffer layers between the storage zone and underground sources of drinking water, and the nature of storage zone boundary type. For an initial injection well location, the total site well leakage index (SWLI) is calculated, which is the summation of the WLI for all of the wells. Next, the injector location is varied areally and SWLI is calculated for a specified number of potential injector well locations in the storage zone area. Small values for the SWLI correspond to low well leakage potential, indicating where injection well locations can be considered. The developed criterion provides a means to systemically find the areas with highest and lowest well leakage potential for a storage zone. Due to the reduced order nature of the developed method, it should be a useful tool in the planning and execution phase of the CO2 geological sequestration process. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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“…Analytical (Nordbotten et al 2004(Nordbotten et al , 2009 and semi-analytical methods (Nordbotten et al 2005;Pan et al 2011a;Réveillère 2013) are usually used to forecast the flux of brine or CO 2 along the wellbore quantitatively. Numerical models are more accurate and computationally demanding when complicated hydrogeological and geological factors are included (Tao et al 2011;Harp et al 2016). What is more, very limited studies consider multiphase (e.g.…”

Section: Introductionmentioning

confidence: 99%

“…Réveillère (2013) presented a semi-analytical solution of brine leakage along the wellbore by taking account of the effect of the density difference between lifting and lifted brines during both upward and downward flow. Tao et al (2011) estimated the single CO 2 phase flow rate along a defect by using the established model; however, only the singlephase flow was considered in these solutions, which is not applicable for problems with multi-phase flow, such as the exsolution of CO 2 from the aqueous phase and transition of the fluid flow in the wellbore from single phase flow to two-phase flow. The process of two-phase flow in the wellbore is very different to that of the single phase, because the density of gas is smaller than that of the brine.…”

Section: Introductionmentioning

confidence: 99%

Numerical studies of CO2 and brine leakage into a shallow aquifer through an open wellbore

Wang

Pan

et al. 2017

Hydrogeol J

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Industrial-scale geological storage of CO 2 in saline aquifers may cause CO 2 and brine leakage from abandoned wells into shallow fresh aquifers. This leakage problem involves the flow dynamics in both the wellbore and the storage reservoir. T2Well/ECO2N, a coupled wellbore-reservoir flow simulator, was used to analyze CO 2 and brine leakage under different conditions with a hypothetical simulation model in water-CO 2-brine systems. Parametric studies on CO 2 and brine leakage, including the salinity, excess pore pressure (EPP) and initially dissolved CO 2 mass fraction, are conducted to understand the mechanism of CO 2 migration. The results show that brine leakage rates increase proportionally with EPP and inversely with the salinity when EPP varies from 0.5 to 1.5 MPa; however, there is no CO 2 leakage into the shallow freshwater aquifer if EPP is less than 0.5 MPa. The dissolved CO 2 mass fraction shows an important influence on the CO 2 plume, as part of the dissolved CO 2 becomes a free phase. Scenario simulation shows that the gas lifting effect will significantly increase the brine leakage rate into the shallow freshwater aquifer under the scenario of 3.89% dissolved CO 2 mass fraction. The equivalent porous media (EPM) approach used to model the wellbore flow has been evaluated and results show that the EPM approach could either under-or overestimate brine leakage rates under most scenarios. The discrepancies become more significant if a free CO 2 phase evolves. Therefore, a model that can correctly describe the complex flow dynamics in the wellbore is necessary for investigating the leakage problems.

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An improved model to forecast CO2 leakage rates along a wellbore

Cited by 20 publications

References 7 publications

Probability Distributions for Effective Permeability of Potentially Leaking Wells at CO<sub>2</sub> Sequestration Sites

Probability Distributions for Effective Permeability of Potentially Leaking Wells at CO<sub>2</sub> Sequestration Sites

Field‐scale well leakage risk assessment using reduced‐order models

Numerical studies of CO2 and brine leakage into a shallow aquifer through an open wellbore

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