Log in to view your state's edition
You are not logged in
Bookmark and Share
December 18, 2013
CO2 sequestration in Class II wells

Transitioning a well that uses carbon dioxide (CO2) for the enhanced recovery (ER) of oil or gas to one that sequesters CO2 may require a new permit under the Safe Drinking Water Act (SDWA).  In a new guidance document, the EPA reviews the differences in requirements under an ER or Class II permit and a CO2 geological sequestration (GS) Class VI permit. 

Risks from CO2

In December 2010, the EPA published minimum federal requirements under the SDWA for the underground injection of CO2 for the purpose of GS.  In the rule, the EPA noted that CO2 itself is not a drinking water contaminant.  But CO2 in the presence of water forms carbonic acid, which can cause leaching and mobilization of naturally occurring metals or other contaminants (e.g., arsenic and lead) from geologic formations into groundwater.  Another potential risk to underground sources of drinking water (USDW) is the presence of impurities such as hydrogen sulfide or mercury in the captured CO2 stream. 

In addition, the pressures needed for injection may force native brines (naturally occurring salty water) into USDWs, causing degradation of water quality and affecting drinking water treatment processes.  GS pressures also increase the potential that a CO2 plume will spread into a USDW.

Based on these new risks, the Agency’s Class VI permit established significant new requirements under SDWA’s underground injection control (UIC) program to ensure that sequestered CO2 does not infiltrate USDWs. 

Increased pressure

In the guidance, the EPA states that if the “business model” for a well or group of wells changes from an ER-focused activity to one that maximizes CO2 injection volumes and permanent storage, the types of risk noted above will need to be mitigated by the more comprehensive requirements of a Class VI permit.  For example:

  • The area of review (AoR) delineation requires sophisticated modeling for Class VI operations whereas the AoR for Class II operations may be delineated using a fixed radius or a radial calculation.
  • Well construction standards are more specific for Class VI wells, and more- frequent mechanical integrity testing of Class VI wells is required.  Monitoring of groundwater quality and tracking the fate of the injectate and induced pressure front are required under the Class VI program, but not the Class II program.
  • Postinjection monitoring is required only under the Class VI program.
  • Multiple Class II wells within a single field may be permitted on a field basis through the use of a single area permit.  Area permits are not allowed for Class VI wells; instead, each Class VI well in a given field or site must be permitted individually.

Adaptive rulemaking

There is no automatic requirement that a Class II well operator transitioning to GS obtain a Class VI permit.  If the operator can establish that GS will not present an increased risk to a USDW, the operations would continue to be permitted under the Class II requirements.  On the other hand, if the permitting authority determines that CO2 trapped in the subsurface as a result of ER poses a risk to USDW, a Class VI permit will likely be required even if the well is performing ER and not CS.

The EPA emphasizes that the guidance establishes no new requirements and is intended to assist permitting agencies in the practical application of the UIC regulations.  The Agency adds that it is taking an “adaptive rulemaking” approach to regulating Class VI injection wells; this means that permitting decisions will be made on a case-by-case basis and may contain provisions that differ from what is written in the guidance.

Guidance on Transitioning Class II Wells to Class VI Wells

Twitter   Facebook   Linked In
Follow Us