Risk of Leakage versus Depth of Injection in Geological Storage

Celia, Michael A.; Nordbotten, Jan Martin; Bachu, Stefan; Dobossy, M.; Court, Benjamin

doi:10.1016/j.egypro.2009.02.022

Cited by 60 publications

(39 citation statements)

References 7 publications

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“…For assessment of the risk of CO 2 leakage from storage sites, wellbore integrity and quality of the casing annulus were recently investigated by experimental (field and lab scale) studies [Bachu and Bennion, 2009;Celia et al, 2009;Crow et al, 2010;Liteanu and Spiers, 2010] and using theoretical analyses [Checkai, 2012;Tao and Bryant, 2014]. Bachu and Bennion [2009] conducted a series of laboratory experiments on cement samples representing the annular space between the casing and the formation.…”

Section: 1002/2014wr016146mentioning

confidence: 99%

Numerical investigation of methane and formation fluid leakage along the casing of a decommissioned shale gas well

Nowamooz

Lemieux

Molson

et al. 2015

Water Resources Research

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Methane and brine leakage rates and associated time scales along the cemented casing of a hypothetical decommissioned shale gas well have been assessed with a multiphase flow and multicomponent numerical model. The conceptual model used for the simulations assumes that the target shale formation is 200 m thick, overlain by a 750 m thick caprock, which is in turn overlain by a 50 m thick surficial sand aquifer, the 1000 m geological sequence being intersected by a fully penetrating borehole. This succession of geological units is representative of the region targeted for shale gas exploration in the St. Lawrence Lowlands (Qu ebec, Canada). The simulations aimed at assessing the impact of well casing cementation quality on methane and brine leakage at the base of a surficial aquifer. The leakage of fluids can subsequently lead to the contamination of groundwater resources and/or, in the case of methane migration to ground surface, to an increase in greenhouse gas emissions. The minimum reported surface casing vent flow (measured at ground level) for shale gas wells in Quebec (0.01 m 3 /d) is used as a reference to evaluate the impact of well casing cementation quality on methane and brine migration. The simulations suggest that an adequately cemented borehole (with a casing annulus permeability k c 1 mD) can prevent methane and brine leakage over a time scale of up to 100 years. However, a poorly cemented borehole (k c ! 10 mD) could yield methane leakage rates at the base of an aquifer ranging from 0.04 m 3 /d to more than 100 m 3 /d, depending on the permeability of the target shale gas formation after abandonment and on the quantity of mobile gas in the formation. These values are compatible with surface casing vent flows reported for shale gas wells in the St. Lawrence Lowlands (Quebec, Canada). The simulated travel time of methane from the target shale formation to the surficial aquifer is between a few months and 30 years, depending on cementation quality and hydrodynamic properties of the casing annulus. Simulated longterm brine leakage rates after 100 years for poorly cemented boreholes are on the order of 10 25 m 3 /d (10 mL/d) to 10 23 m 3 /d (1 L/d). Based on scoping calculations with a well-mixed aquifer model, these rates are unlikely to have a major impact on groundwater quality in a confined aquifer since they would only increase the chloride concentration in a pristine aquifer to 1 mg/L, which is significantly below the commonly recommended aesthetic objective of 250 mg/L for chloride.

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Section: 1002/2014wr016146mentioning

confidence: 99%

Numerical investigation of methane and formation fluid leakage along the casing of a decommissioned shale gas well

Nowamooz

Lemieux

Molson

et al. 2015

Water Resources Research

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“…At typical subsurface temperature and pressure conditions in terrestrial crust, separate-phase supercritical CO 2 , henceforth for simplicity referred to as "gas," is less dense than aqueous phase. CO 2 injected into a saline aquifer will thus experience an upward buoyancy force, will tend to accumulate under a caprock, and will migrate toward shallower depth whenever suitable permeable pathways are available, such as fractures, faults, or improperly abandoned wells (Nordbotten et al 2005;Pruess 2008;Celia et al 2008).…”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation Studies of the Long-term Evolution of a CO2 Plume in a Saline Aquifer with a Sloping Caprock

Pruess

Nordbotten

2011

Transp Porous Med

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We have used the TOUGH2-MP/ECO2N code to perform numerical simulation studies of the long-term behavior of CO 2 stored in an aquifer with a sloping caprock. This problem is of great practical interest, and is very challenging due to the importance of multiscale processes. We find that the mechanism of plume advance is different from what is seen in a forced immiscible displacement, such as gas injection into a water-saturated medium. Instead of pushing the water forward, the plume advances because the vertical pressure gradients within the plume are smaller than hydrostatic, causing the groundwater column to collapse ahead of the plume tip. Increased resistance to vertical flow of aqueous phase in anisotropic media leads to reduced speed of up-dip plume advancement. Vertical equilibrium models that ignore effects of vertical flow will overpredict the speed of plume advancement. The CO 2 plume becomes thinner as it advances, but the speed of advancement remains constant over the entire simulation period of up to 400 years, with migration distances of more than 80 km. Our simulations include dissolution of CO 2 into the aqueous phase and associated density increase, and molecular diffusion. However, no convection develops in the aqueous phase because it is suppressed by the relatively coarse (sub-) horizontal gridding required in a regional-scale model. A first crude sub-grid-scale model was developed to represent convective enhancement of CO 2 dissolution. This process is found to greatly reduce the thickness of the CO 2 plume, but, for the parameters used in our simulations, does not affect the speed of plume advancement.

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“…The values obtained for Darcy flux given in Table 2 are consistent with the generally accepted values for flow of formation fluids in the Alberta basin, of the order of 1-10 cm per year or less (Gunter et al, 1996). Permeability, porosity and salinity data for Belly River, Cardium, Viking, Manville, Nordegg, and Ellerslie aquifers were obtained from Celia et al (2009) and Bachu and Bennion (2008). Data on the permeability and porosity and salinity of the glauconitic aquifer was obtained from Hassanzadeh et al (2005).…”

Section: Data For Long-term Leakagementioning

confidence: 95%

“…For these reasons the interest in injection of acid gas from sour natural gas fields is increasing worldwide (Shah et al, 2008). Acid gas injection is considered to be an analogue for geo-sequestration of carbon dioxide which is expected to increase in the future (Gunter et al, 1996;Celia et al, 2009). Analysis of the potential leakage of acid gas and associated detrimental effects, in addition to being important in its own right, is relevant to the geo-sequestration of carbon dioxide.…”

Section: Introductionmentioning

confidence: 98%

Analysis of potential acid gas leakage from wellbores in Alberta, Canada

LeNeveu¹

2011

International Journal of Greenhouse Gas Control

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Risk of Leakage versus Depth of Injection in Geological Storage

Cited by 60 publications

References 7 publications

Numerical investigation of methane and formation fluid leakage along the casing of a decommissioned shale gas well

Numerical investigation of methane and formation fluid leakage along the casing of a decommissioned shale gas well

Numerical Simulation Studies of the Long-term Evolution of a CO2 Plume in a Saline Aquifer with a Sloping Caprock

Analysis of potential acid gas leakage from wellbores in Alberta, Canada

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