Scenario simulations of CO2 injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden

Chasset, Coralie; Jarsjö, Jerker; Erlström, Mikael; Cvetković, Vladimir

doi:10.1016/j.ijggc.2011.06.003

Cited by 33 publications

(16 citation statements)

References 35 publications

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“…). A number of deep boreholes have been drilled and several sandstone layers have been identified which constitute potential candidates for geological storage of carbon dioxide . These sandstone layers appear in the Lower Cretaceous and Lower Jurassic sequences.…”

Section: The South Scania Site Swedenmentioning

confidence: 99%

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

et al. 2014

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Carbon dioxide (CO2) injection in deep saline formations causes pressure increase which may be detrimental to the mechanical integrity of the storage reservoir. Injection induced pressure build‐up is a limiting factor for CO2 injection rates and storage capacity. In this study, we extend a semi‐analytical solution (based on one‐dimensional, two‐phase, two‐component radial flow) for application to estimate pressure build‐up and maximum injection rate of CO2 at a field site (South Scania, Sweden) using the method of superposition of image well solutions to account for the straight‐line boundaries imposed by three fault zones. The semi‐analytical approach for estimating pressure build‐up is validated by comparison to numerical simulations based on TOUGH2‐ECO2N. We analyze injection pressure sensitivity due to uncertainty in reservoir parameters as well as boundary conditions. Maximum injection rates and pressure limited capacity estimates are presented. This work demonstrates the use of semi‐analytical solutions to analyze pressure limitation on storage capacity for realistic reservoirs with irregular (non‐circular) boundaries. It is also shown that the semi‐analytical approach can also be used to evaluate the benefit of having multiple injection wells in terms of increasing the injection‐pressure‐limited storage capacity. The methodology presented in this study is useful for screening analysis of storage sites as well as for operation design and optimization where pressure build‐up as a limiting factor influences the objective function.

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Section: The South Scania Site Swedenmentioning

confidence: 99%

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

et al. 2014

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“…Although pressure drops below the limit threshold after only a few days, caprock damage could be done within this time, so for caution we should reduce injection rate a little, to a mass rate of 3.7 kg/s (∼ 15% less than the initial rate). Note also that oscillations can be seen for the pressure transient of all simulation cases, but this is very marked in the case of the VGTM k rl with m = 0.56 (Fig. ).…”

Section: Model Developmentmentioning

confidence: 99%

“…Numerical simulations are often used for injectivity studies of GCS at every scale: laboratory experiment, pilot site, and basin‐wide reservoir . A CO 2 injection performance assessment via different parameter uncertainty scenarios was carried out for the Nisku (Wabamun Lake Area, Alberta, Canada), Ketzin (Germany), and Scania (Sweden) saline aquifers . To our knowledge, DSA with low matrix permeability on the order of O(1 × 10 −15 ) m 2 such as the Bécancour aquifers have very seldom been assessed for GCS.…”

Section: Introductionmentioning

confidence: 99%

Injectivity of carbon dioxide in the St. Lawrence Platform, Quebec (Canada): A sensitivity study

et al. 2013

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Injectivity of CO2 in the Bécancour deep saline aquifers, St. Lawrence Platform (Québec), was investigated using 2D radial numerical simulations with TOUGH2/ECO2N. In order to have an appropriate choice for the CO2 injection rate and the duration of injection, sensitivity analyses were carried out, considering different values of hydrodynamic, chemical‐petrophysical, and geometric parameters affecting CO2 injection in a brine reservoir. The parameterization analysis for capillary pressure and relative permeability models indicated large uncertainty for this case study. Simulations took into account Bécancour reservoir conditions in which the maximum pressure was limited to the fracturing pressure. The sensitivity analysis provides guidance on potential injection scenarios. To remain below fracturing pressure, intermittent 5‐year injection periods can be used, with a mass injection rate up to ∼ 20 kg/s, alternating with half‐year periods without injection. This scenario could give maximum CO2 storage in the aquifer. CO2 storage capacities in different phases were calculated versus time. This study shows that the northeastern reservoir block of the Bécancour area could host about 10 Mt CO2, which represents 15% to 50% of regional yearly CO2 emissions during about 60 and 20 years for the case of the injection formation permeability of 0.89 × 10−15 m2 and 4.17 × 10−15 m2, respectively. Finally, this modeling study will also be the basis for the design of a pilot CO2 injection test at the study site. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

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“…This indicates that buoyancy and relative permeability effects – due to the different properties of brine and CO 2 – are not significant on the short timescale of brine‐CO 2 injection, assuming continuous injection. Heterogeneities are expected to influence or even enhance salt clogging since they affect the flow of CO 2 and consequently the location of salt precipitation . 39 We used a heterogeneously layered model with a varying vertical porosity and permeability to assess this effect.…”

Section: Discussionmentioning

confidence: 99%

Intentional salt clogging: a novel concept for long‐term CO₂ sealing

2013

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Well abandonment in the context of CO2 storage operations demands a mitigation strategy for CO2 leakage along the wellbore. To prevent possible CO2 transport toward the surface and to protect the wellbore material from contact with acid brine, we propose forming a salt seal around the wellbore at reservoir level, after CO2 injection into a depleted gas field. The mechanism of water evaporation into dry gas and subsequent salting‐out of the dissolved halite is a well‐known issue in hydrocarbon production. We propose alternating injection of brine and CO2 to facilitate intentional salt clogging of the reservoir. Salt clogging was studied with TOUGH2, simu‐lating multiple cycles of brine and CO2 injection. We developed two near‐well reservoir models – a homogeneous 2D model and a more complex heterogeneous 2D model – using certain characteristics of the K12‐B depleted gas field. The homogeneous 2D model yields a 50‐cm thick salt bank around the well and complete permeability impairment after eight cycles of brine‐CO2 injection. Addition of vertical permeability heterogeneities causes variation in the lateral extent of salt precipitation and hence vertical discontinuities in the salt bank. A carefully designed injection strategy – with more injection cycles and lower injection rates – improves the vertical sealing. Predictions of the amount of required clogging for effective sealing would benefit from more accurate porosity‐permeability relationships and insights in the long‐term stability of the salt bank regarding re‐dissolution. We conclude that alternating brine‐CO2 injection could be a promising method for intentional salt‐clogging of the near‐wellbore area. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

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Scenario simulations of CO2 injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden

Cited by 33 publications

References 35 publications

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

Injectivity of carbon dioxide in the St. Lawrence Platform, Quebec (Canada): A sensitivity study

Intentional salt clogging: a novel concept for long‐term CO₂ sealing

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Scenario simulations of CO2 injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden

Cited by 33 publications

References 35 publications

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO2 storage at the South Scania site, Sweden

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO2 storage at the South Scania site, Sweden

Injectivity of carbon dioxide in the St. Lawrence Platform, Quebec (Canada): A sensitivity study

Intentional salt clogging: a novel concept for long‐term CO2 sealing

Contact Info

Product

Resources

About

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

Modeling of pressure build‐up and estimation of maximum injection rate for geological CO₂ storage at the South Scania site, Sweden

Intentional salt clogging: a novel concept for long‐term CO₂ sealing