CO2 plume management in saline reservoir sequestration

Scott M Frailey, Robert J. Finley

Research output: Contribution to journalArticle

Abstract

A significant difference between injecting CO2 into saline aquifers for sequestration and injecting fluids into oil reservoirs or natural gas into aquifer storage reservoirs is the availability and use of other production and injection wells surrounding the primary injection well(s). Of major concern for CO2 sequestration using a single well is the distribution of pressure and CO2 saturation within the injection zone. Pressure is of concern with regards to caprock integrity and potential migration of brine or CO2 outside of the injection zone, while CO2 saturation is of interest for storage rights and displacement efficiency. For oil reservoirs, the presence of additional wells is intended to maximize oil recovery by injecting CO2 into the same hydraulic flow units from which the producing wells are withdrawing fluids. Completing injectors and producers in the same flow unit increases CO2 throughput, maximizes oil displacement efficiency, and controls pressure buildup. Additional injectors may surround the CO2 injection well and oil production wells in order to provide external pressure to these wells to prevent the injected CO2 from migrating from the pattern between two of the producing wells. Natural gas storage practices are similar in that to reduce the amount of "cushion" gas and increase the amount of cycled or working gas, edge wells may be used for withdrawal of gas and center wells used for gas injection. This reduces loss of gas to the formation via residual trapping far from the injection well. Moreover, this maximizes the natural gas storage efficiency between the injection and production wells and reduces the areal extent of the natural gas plume. Proposed U.S. EPA regulations include monitoring pressure and suggest the "plume" may be defined by pressure in addition to the CO2 saturated area. For pressure monitoring, it seems that this can only be accomplished by injection zone monitoring wells. For pressure, these wells would not need to be very close to the injection well, compared to monitoring wells intended to measure CO2 saturation via fluid sampling or cased-hole well logs. If pressure monitoring wells become mandated, these wells could be used for managing the CO2 saturation and aquifer pressure distribution. To understand the relevance and effectiveness of producing and injecting brine to improve storage efficiency, direct the plume to specific pore space, and redistribute the pressure, numerical models of CO2 injection into aquifers are used. Simulated cases include various aquifer properties at a single well site and varying the number and location of surrounding wells for plume management. Strategies in terms of completion intervals can be developed to effectively contact more vertical pore space in relatively thicker geologic formations. Inter-site plume management (or cooperative) wells for the purpose of pressure monitoring and plume management may become the responsibility of a consortium of operators or a government entity, not individual sequestration site operators.

Original languageEnglish (US)
Pages (from-to)4238-4245
Number of pages8
JournalEnergy Procedia
Volume4
DOIs
StatePublished - Jan 1 2011

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Aquifers
Monitoring
Natural gas
Gases
Fluids
Oil well production
Pressure control
Pressure distribution
Numerical models
Throughput
Hydraulics
Availability
Sampling
Recovery
Oils

Keywords

  • Geologic sequestration
  • Plume distribution
  • Storage engineering

ASJC Scopus subject areas

  • Energy(all)

Cite this

CO2 plume management in saline reservoir sequestration. / Frailey, Scott M; Finley, Robert J.

In: Energy Procedia, Vol. 4, 01.01.2011, p. 4238-4245.

Research output: Contribution to journalArticle

Frailey, Scott M ; Finley, Robert J. / CO2 plume management in saline reservoir sequestration. In: Energy Procedia. 2011 ; Vol. 4. pp. 4238-4245.
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