Geologic Sequestration of Carbon 

Dioxide 

Underground Injection Control (UIC) 

Program Class VI Well Area of Review 

Evaluation and Corrective Action 

Guidance

Office of Water (4606M) EPA 816-R-13-005 May 2013 
UIC Program Class VI Well Area of Review i 

Evaluation and Corrective Action Guidance

Disclaimer 

The Federal Requirements under the Underground Injection Control Program for Carbon 

Dioxide Geologic Sequestration Wells (75 FR 77230, December 10, 2010), known as the Class 

VI Rule, establishes a new class of injection well (Class VI). 

The Safe Drinking Water Act (SDWA) provisions and U.S. Environmental Protection Agency 

(EPA) regulations cited in this document contain legally-binding requirements. In several 

chapters this guidance document makes suggestions and offers alternatives that go beyond the 

minimum requirements indicated by the Class VI Rule. This is intended to provide information 

and suggestions that may be helpful for implementation efforts. Such suggestions are prefaced by 

“may” or “should” and are to be considered advisory. They are not required elements of the rule. 

Therefore, this document does not substitute for those provisions or regulations, nor is it a 

regulation itself, so it does not impose legally-binding requirements on EPA, states, or the 

regulated community. The recommendations herein may not be applicable to each and every 

situation. 

EPA and state decision makers retain the discretion to adopt approaches on a case-by-case basis 

that differ from this guidance where appropriate. Any decisions regarding a particular facility 

will be made based on the applicable statutes and regulations. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. EPA is taking 

an adaptive rulemaking approach to regulating Class VI injection wells, and the agency will 

continue to evaluate ongoing research and demonstration projects and gather other relevant 

information as needed to refine the rule. Consequently, this guidance may change in the future 

without a formal notice and comment period. 

While EPA has made every effort to ensure the accuracy of the discussion in this document, the 

obligations of the regulated community are determined by statutes, regulations or other legally 

binding requirements. In the event of a conflict between the discussion in this document and any 

statute or regulation, this document would not be controlling. 

Note that this document only addresses issues covered by EPA’s authorities under the SDWA. 

Other EPA authorities, such as Clean Air Act (CAA) requirements to report carbon dioxide 

injection activities under the Greenhouse Gas Mandatory Reporting Rule (GHG MRR), are not 

within the scope of this document. 
UIC Program Class VI Well Area of Review ii

Evaluation and Corrective Action Guidance

Executive Summary

EPA’s Federal Requirements Under the Underground Injection Control (UIC) Program for 

Carbon Dioxide Geologic Sequestration Wells has been codified in the U.S. Code of Federal 

Regulations (40 CFR 146.81 et seq.), and is referred to as the Class VI Rule. This rule 

establishes a new class of injection well (Class VI) and sets minimum federal technical criteria 

for Class VI injection wells for the purposes of protecting underground sources of drinking water 

(USDWs). This guidance is part of a series of technical guidance documents that EPA is 

developing to support owners or operators of Class VI wells and UIC Program permitting 

authorities in the implementation of the Class VI Rule. The Class VI Rule and related documents 

are available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

The Class VI Rule requires owners or operators of Class VI injection wells to delineate the area 

of review (AoR) for the proposed Class VI well, which is the region surrounding the proposed 

well where USDWs may be endangered by the injection activity [40 CFR 146.84]. The Class VI 

Rule requires that the AoR be delineated using computational modeling and the AoR must be 

reevaluated periodically during the lifetime of the geologic sequestration (GS) project [40 CFR 

146.84]. Within the AoR, the owners or operators must identify all potential conduits for fluid 

movement out of the injection zone, including both geologic features and artificial penetrations 

[40 CFR 146.84(c)(1)(iii)]. The owner or operator must then evaluate those artificial penetrations 

that may penetrate the confining layer(s) of the injection project for the quality of casing and 

cementing, and in the case of abandoned wells, for the quality of plugging and abandonment, and 

perform corrective action on any identified artificial penetrations that could serve as a conduit for 

fluid movement [40 CFR 146.84(c)(2), 146.84(c)(3), and 146.84(d)]. The Class VI Rule allows, 

at the discretion of the UIC Program Director, the use of “phased” corrective action, where 

certain regions of the AoR are addressed prior to injection and other regions of the AoR are 

addressed during the injection phase of the project [40 CFR 146.84(b)(2)(iv)]. 

This guidance provides information regarding modeling requirements and recommendations for 

delineating the AoR, describes the circumstances under which the AoR is to be reevaluated, and 

describes how to perform an AoR reevaluation. In addition, the guidance presents information on 

how to identify, evaluate, and perform corrective action on artificial penetrations located within 

the AoR. 

The introductory section reviews the definition of the AoR and regulations pertaining to AoR 

and corrective action in the Class VI Rule. Following that section:

 Section 2 addresses computational modeling of GS; 

 Section 3 addresses AoR delineation using computational models; 

 Section 4 addresses identification, evaluation, and performing corrective action on 

artificial penetrations within the AoR; and

 Section 5 addresses AoR reevaluation.
UIC Program Class VI Well Area of Review iii

Evaluation and Corrective Action Guidance

For each section, the guidance:

 Explains how to perform activities necessary to comply with AoR and corrective 

action requirements (e.g., performing computational modeling). Illustrative examples 

are provided in several cases; 

 Provides references to comprehensive reference documents and the scientific 

literature for additional information; and

 Explains how to report to the UIC Program Director the results of activities related to 

AoR and corrective action. 
UIC Program Class VI Well Area of Review iv

Evaluation and Corrective Action Guidance

Table of Contents

Disclaimer ........................................................................................................................................ i

Executive Summary ........................................................................................................................ ii

Table of Contents ........................................................................................................................... iv

List of Figures ................................................................................................................................ vi

List of Tables ................................................................................................................................ vii

Acronyms and Abbreviations ...................................................................................................... viii

Definitions...................................................................................................................................... ix

Unit Conversions .......................................................................................................................... xii

1. Introduction ............................................................................................................................. 1

1.1. Overview of the Class VI Rule AoR and Corrective Action Requirements .................... 2

1.2. Organization of this Guidance.......................................................................................... 5

2. Computational Modeling for Geologic Sequestration ............................................................ 7

2.1. Modeled Processes ......................................................................................................... 10

2.2. Model Parameters ........................................................................................................... 11

2.2.1. Intrinsic Permeability .............................................................................................. 14

2.2.2. Relative Permeability and Capillary Pressure......................................................... 16

2.2.3. Injection Rate .......................................................................................................... 19

2.2.4. Fluid Properties and Equations of State .................................................................. 19

2.2.5. Mass-Transfer Coefficients ..................................................................................... 19

2.2.6. Mineral Precipitation Kinetic Parameters ............................................................... 20

2.2.7. Model Orientation and Gridding Parameters .......................................................... 20

2.3. Computational Approaches ............................................................................................ 21

2.3.1. Numerical Approaches............................................................................................ 21

2.3.2. Analytical, Semi-Analytical, and Hybrid Approaches ........................................... 22

2.4. Model Uncertainty and Sensitivity Analyses ................................................................. 22

2.5. Model Calibration .......................................................................................................... 23

2.6. Existing Codes used for Development of GS Models.................................................... 28

3. AoR Delineation Using Computational Models ................................................................... 30

3.1. AoR Delineation Class VI Rule Requirements .............................................................. 30

3.2. Data Collection and Compilation ................................................................................... 31

3.2.1. Site Hydrogeology .................................................................................................. 31

3.2.2. Operational Data ..................................................................................................... 32

3.3. Model Development ....................................................................................................... 33

3.3.1. Conceptual Model of the Proposed Injection Site .................................................. 33

3.3.2. Determination of Physical Processes to be Included in the Computational 

Model ...................................................................................................................... 36

3.3.3. Computational Model Design ................................................................................. 36

3.3.3.1. Computational Code Determination ................................................................ 36

3.3.3.2. Model Spatial Extent, Discretization, and Boundary Conditions .................... 37
UIC Program Class VI Well Area of Review v 

Evaluation and Corrective Action Guidance

3.3.3.3. Model Timeframe ............................................................................................ 37

3.3.3.4. Parameterization .............................................................................................. 37

3.3.4. Executing the Computational Model ...................................................................... 38

3.4. AoR Delineation Based on Model Results ..................................................................... 38

3.4.1. Determination of Threshold Pressure Front ............................................................ 39

3.5. Reporting AoR Delineation Results to the UIC Program Director ................................ 48

4. Identifying Artificial Penetrations and Performing Corrective Action ................................. 50

4.1. Rule Requirements ......................................................................................................... 50

4.2. Identifying Artificial Penetrations within the AoR ........................................................ 51

4.2.1. Historical Research ................................................................................................. 52

4.2.2. Site Reconnaissance ................................................................................................ 53

4.2.3. Aerial and Satellite Imagery Review ...................................................................... 53

4.2.4. Geophysical Surveys ............................................................................................... 53

4.2.4.1. Magnetic Methods ........................................................................................... 54

4.2.4.3. Electromagnetic Methods ................................................................................ 56

4.2.4.4. Ground Penetrating Radar ............................................................................... 56

4.3. Assessing Identified Abandoned Wells.......................................................................... 56

4.3.1. Abandoned Well Plugging Records Review........................................................... 57

4.3.2. Abandoned Well Field Testing ............................................................................... 60

4.4. Performing Corrective Action on Wells Within the AoR .............................................. 62

4.4.1. Plugging of Wells within the AoR .......................................................................... 65

4.4.2. Remedial Cementing ............................................................................................... 66

4.5. Reporting Well Identification, Assessment, and Corrective Action to the UIC 

Program Director............................................................................................................ 66

5. AoR Reevaluation ................................................................................................................. 68

5.1. Class VI Rule Requirements Related to AoR Reevaluation .......................................... 68

5.2. Conditions Warranting an AoR Reevaluation ................................................................ 69

5.2.1. Minimum Fixed Frequency..................................................................................... 69

5.2.2. Significant Changes in Operations.......................................................................... 69

5.2.3. Results from Site Monitoring that Differ From Model Predictions ........................ 70

5.2.4. Ongoing Site Characterization ................................................................................ 71

5.3. Performing an AoR Reevaluation .................................................................................. 71

5.3.1. Demonstrating Adequate Existing AoR Delineation .............................................. 75

5.3.2. Modifying the Existing AoR Delineation ............................................................... 75

References ..................................................................................................................................... 78
UIC Program Class VI Well Area of Review vi

Evaluation and Corrective Action Guidance

List of Figures 

Figure 1-1: Flow Chart of Monitoring and Modeling at a GS Project............................................ 3

Figure 2-1: Equations of State for Carbon Dioxide ........................................................................ 9

Figure 2-2: Example Relative Permeability-Saturation and Capillary Pressure-Saturation 

Relationships for Water and Carbon Dioxide ........................................................... 17

Figure 2-3: Geologic Schematic of Frio Brine Pilot Project......................................................... 25

Figure 2-4: Observed and Modeled Carbon Dioxide Arrival at the Observation Well Based 

on Change in Fluid Density ....................................................................................... 26

Figure 2-5: Observed and Modeled Pressure Increase at (a) the Injection Well and (b) the 

Monitoring Well ........................................................................................................ 26

Figure 2-6: Comparison of (a) Initial and (b) Post-Calibration Model Predictions of Carbon 

Dioxide Plume Evolution .......................................................................................... 27

Figure 3-1: Hypothetical Conceptual Site Model for Geologic Sequestration ............................. 34

Figure 3-2: Fluid Density Functions for Varying Salinities ......................................................... 40

Figure 3-3: Hypothetical Geologic Sequestration Site: Cross Sectional Schematic and 

Calculations ............................................................................................................... 43

Figure 3-4: Hypothetical Geologic Sequestration Site: Model Predicted Maximum Pressure 

Within the Injection Zone ......................................................................................... 45

Figure 3-5: Hypothetical Geologic Sequestration Site: Model Predicted Extent of 

Supercritical Carbon Dioxide Plume Over Time ...................................................... 46

Figure 3-6: Hypothetical Geologic Sequestration Site: Initial Area of Review Based on 

Model Results ............................................................................................................ 47

Figure 4-1: Total Field Aeromagnetic Map, Cook Creek Oil Field, Arcadia, Oklahoma ............ 55

Figure 4-2: Examples of Carbon Dioxide Leakage Through Improperly Abandoned Wells ....... 58

Figure 4-3: Well Evaluation Decision Tree .................................................................................. 64

Figure 5-1: Hypothetical Geologic Sequestration Site: Comparison of Model Predictions and 

Plume Monitoring Results at 20 Years of Injection .................................................. 72

Figure 5-2: Hypothetical Geologic Sequestration Site: Comparison of Model Predictions and 

Pressure Monitoring Results at 20 Years of Injection............................................... 73

Figure 5-3: Hypothetical Geologic Sequestration Site: Initial AoR Delineation and

Delineation after Reevaluation .................................................................................. 77
UIC Program Class VI Well Area of Review vii

Evaluation and Corrective Action Guidance

List of Tables

Table 2-1: Model Parameters for Multiphase Fluid Modeling of Geologic Sequestration .......... 12

Table 4-1: Tools for Assessment of the Integrity of Abandoned Wells ....................................... 62
UIC Program Class VI Well Area of Review viii

Evaluation and Corrective Action Guidance

Acronyms and Abbreviations

AoR Area of review

API American Petroleum Institute

CAA Clean Air Act

CFR Code of Federal Regulations

DOE United States Department of Energy

EPA United States Environmental Protection Agency 

GHG MRR Greenhouse Gas Mandatory Reporting Rule 

GPR Ground penetrating radar

GS Geologic sequestration

LBNL Lawrence Berkeley National Laboratory

MAE Mean-absolute error

mD Millidarcies

ME Mean error

MIT Mechanical integrity test

MPa Megapascals

PISC Post-injection site care 

RCSP Regional Carbon Sequestration Partnership 

RMSE Root-mean squared error

SDWA Safe Drinking Water Act

UIC Underground Injection Control 

USDW Underground source of drinking water

USGS United States Department of the Interior, United States Geological Survey
UIC Program Class VI Well Area of Review ix

Evaluation and Corrective Action Guidance

Definitions 

Key to definition sources: 

1: 40 CFR 146.81(d). 

2: Definition drafted for the purposes of this document. 

3: Class VI Rule Preamble. 

4: 40 CFR 144.3. 

Area of Review (AoR) means the region surrounding the geologic sequestration project where 

USDWs may be endangered by the injection activity. The area of review is delineated using 

computational modeling that accounts for the physical and chemical properties of all phases of 

the injected carbon dioxide stream and displaced fluids, and is based on available site 

characterization, monitoring, and operational data as set forth in 40 CFR 146.84.1 

Boundary condition parameters refers to the parameters that describe fluid flow rates and/or 

pressures at the edges of the model domain and in the location of injection/extraction wells.2 

Capillary Pressure refers to the difference of pressures between two phases existing in a system 

of interconnecting pores or capillaries. The difference in pressure is due to the combination of 

surface tension and curvature in the capillaries.2 

Computational code refers to a series of interrelated mathematical equations solved by 

computer to represent the behavior of a complex system. For the purposes of GS, computational 

models represent, at a minimum, the flow and transport of multiple fluids and components in 

varying phases through porous media. Computational codes offer the ability to predict fluid flow 

in the subsurface using scientifically accepted mathematical approximations and theory. The use 

of computational codes is necessary because the mathematical formulations describing fluid flow 

are complicated and in many cases, non-linear. Several codes have been specifically developed 

or tailored for injection activities similar to GS, and can be used for this purpose.2 

Computational model means a mathematical representation of the injection project and relevant 

features, including injection wells, site geology, and fluids present. For a GS project, site specific 

geologic information is used as input to a computational code, creating a computational model 

that provides predictions of subsurface conditions, fluid flow, and carbon dioxide plume and 

pressure front movement at that site. The computational model includes all model input and 

predictions (i.e., outputs).2

Confining zone means a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class 

VI wells operating under an injection depth waiver, confining zone means a geologic formation, 

group of formations, or part of a formation stratigraphically overlying and underlying the 

injection zone.1
UIC Program Class VI Well Area of Review x 

Evaluation and Corrective Action Guidance

Constitutive relationship typically means, empirically based approximations used to simplify 

the system and estimate unknowns in cases where the parameters of the governing equations are 

not readily available for use in the equation because necessary information is not typically 

measurable, and thus not directly input into the model. An example of a constitutive relationship 

is relative permeability-saturation functions. These functions estimate the relative permeability 

of a particular fluid in a porous media as a function of its saturation at a given location and time. 

This permeability is then used in the governing equation to predict flow.2 

Equation of state refers to an equation that expresses the equilibrium phase relationship 

between pressure, volume and temperature for a particular chemical species.2

Geologic sequestration (GS) means the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply 

to carbon dioxide capture or transport.1

 

Geophysical surveys refers to the use of geophysical techniques (e.g., seismic, electrical, 

gravity, or electromagnetic surveys or well logging methods such as gamma ray and spontaneous 

potential) to characterize subsurface rock formations.3

 

Governing equation refers to the mathematical formulae that form the basis of the 

computational code are termed governing equations. For GS modeling, they govern the predicted 

behavior of fluids in the subsurface provided by the code. Governing equations are mathematical 

approximations for describing flow and transport of fluids and their components in the 

environment.2 

Ground Penetrating Radar (GPR) refers to a geophysical method that utilizes microwave 

technology in order to characterize features found in the subsurface.2

 

Heterogeneity refers to the spatial variability in the geologic structure and/or physical properties 

of the site.2 

Hysteresis means the phenomenon where the response of a system depends not only on the 

present stimulus, but also on the previous history of the medium. For example, in a GS project, 

relative permeability, capillary pressure, and residual trapping will depend upon the saturation 

history of the formation.2 

Immiscible refers to the property wherein two or more liquids or phases do not readily dissolve 

in one another.2 

Initial conditions refers to parameter values at the start of the model simulation.2 

Intrinsic permeability refers to a parameter that describes properties of the subsurface that 

impact the rate of fluid flow. Larger intrinsic permeability values correspond to greater fluid 

flow rates. Intrinsic permeability has units of area (distance squared).2

Model calibration means adjusting model parameters in order to minimize the difference 

between model predictions and monitoring data at the site.2
UIC Program Class VI Well Area of Review xi

Evaluation and Corrective Action Guidance

Multiphase flow refers to flow in which two or more distinct phases are present (e.g., liquid, 

gas, supercritical fluid).2 

Numerical Artifacts refers to model results that are created erroneously based on computational 

limitations of the model, which may result from improper model development.2 

Parameter means a mathematical variable used in governing equations, equations of state, and 

constitutive relationships. Parameters describe properties of the fluids present, porous media, and 

fluid sources and sinks (e.g., injection well). Examples of model parameters include intrinsic 

permeability, fluid viscosity, and fluid injection rate.2 

Relative permeability refers to a factor, between 0 and 1, that is multiplied by the intrinsic 

permeability of a formation to compute the effective permeability for a fluid in a particular pore 

space. When immiscible fluids (e.g., carbon dioxide, water) are present within the pore space of 

a formation, the ability for flow of those fluids is reduced, due to the blocking effect of the 

presence of the other fluid. This reduction is represented by relative permeability.2 

Sensitivity Analyses refers to the study of how the output of a model varies based in changes to 

an input variable or model parameter over a specified range of values. The results of a sensitivity 

analysis determine the which input variable and model parameter variability have the greatest 

effect on the model results.2 

Stochastic Methods means the use of probability statistical methods in development of one or 

more possible realizations of the spatial patterns of the value(s) of a given set of model 

parameters.2 

Underground Injection Control Program refers to the program EPA, or an approved state, is 

authorized to implement under the Safe Drinking Water Act (SDWA) that is responsible for 

regulating the underground injection of fluids by wells injection. This includes setting the federal 

minimum requirements for construction, operation, permitting, and closure of underground 

injection wells.2 

Underground Source of Drinking Water (USDW) means an aquifer or its portion which 

supplies any public water system; or which contains a sufficient quantity of ground water to 

supply a public water system; and currently supplies drinking water for human consumption; or 

contains fewer than 10,000 mg/l total dissolved solids; and which is not an exempted aquifer.4 
UIC Program Class VI Well Area of Review xii

Evaluation and Corrective Action Guidance

Unit Conversions

Imperial/Non-Metric Unit Metric Unit

1 Foot 0.3048 Meters

1 Mile 1.609 Kilometers

1 Pound per Square Inch (psi) 0.006895 Megapascals (MPa)

Temperature in Degrees Fahrenheit (oF) Temperature in Degrees Celsius =

(oF – 32) x 0.56

1 Pound (lb) 0.4536 Kilograms

1 Megatonne (Mt) 1 x 106 Tonnes

1 Metric Ton (tonne; t) 1,000 kg

1 Cubic Foot 0.0283 Cubic Meters
UIC Program Class VI Well Area of Review 1 

Evaluation and Corrective Action Guidance

1. Introduction 

Area of review (AoR) evaluations and corrective action are long-standing permit requirements of 

the Underground Injection Control (UIC) Program of the U.S. Environmental Protection Agency 

(EPA). The AoR refers to the delineated region surrounding the injection well(s) wherein the 

potential exists for underground sources of drinking water (USDWs) to be endangered by the 

leakage of injectate and/or formation fluids. Typically, for injection well classes other than Class 

VI, the AoR is defined either as a fixed radius around the injection well or by a relatively simple 

radial calculation. Owners or operators of injection wells are required to identify any potential 

conduits for fluid movement, including artificial penetrations (e.g., abandoned well bores) within 

the AoR, assess the integrity of any artificial penetrations, and perform corrective action where 

necessary to prevent fluid movement into a USDW [40 CFR 144.55, 146.84(d)]. 

The Class VI Rule introduces enhanced AoR and corrective action requirements for Class VI 

injection wells that are tailored to the unique circumstances of geologic sequestration (GS) of 

carbon dioxide projects [40 CFR 146.84]. The purpose of this guidance is to identify appropriate 

methods for delineating the AoR and performing corrective action for Class VI injection wells.

The intended primary audiences of this guidance document are Class VI injection well owners or 

operators and their representatives conducting AoR delineation modeling or performing artificial 

penetration identification, assessment, and corrective action activities. The UIC Program staff 

who are responsible for reviewing and approving Class VI injection well permit applications and 

related reports concerning AoR delineation and corrective action are another intended audience 

of this guidance document. 

This document is one of a series of technical guidance documents intended to provide 

information and possible approaches for addressing various aspects of permitting and operating a 

Class VI injection well. Three of these companion guidance documents focus on site 

characterization, well construction, and testing and monitoring: 

 The UIC Program Class VI Well Site Characterization Guidance;

 The UIC Program Class VI Well Construction Guidance; and

 The UIC Program Class VI Well Testing and Monitoring Guidance. 

These guidance documents are intended to complement each other and to assist owners or 

operators in preparing permit applications that satisfy the requirements of the Class VI Rule. 

Class VI injection well regulations are tailored to the characteristics of individual sites. For 

example, the required site characterization data collected will inform the model development for 

AoR delineation, and AoR models will be reevaluated, and perhaps change, based on the results 

of site testing and monitoring data (Figure 1-1). Cross-linkages between guidance documents are 

noted in the text where appropriate. Additional guidance on developing, presenting, and using 

the required Class VI project plan information as part of a Class VI injection well permit 

application is provided in the UIC Program Class VI Well Project Plan Development Guidance. 
UIC Program Class VI Well Area of Review 2 

Evaluation and Corrective Action Guidance

1.1. Overview of the Class VI Rule AoR and Corrective Action Requirements

The Class VI Rule defines the AoR as the region surrounding the GS project where USDWs may 

be endangered by the injection activity [40 CFR 146.84(a)]. The purpose of the AoR and 

corrective action requirements of the Class VI Rule is to ensure that the areas potentially 

impacted by a proposed GS operation are delineated, all wells that need corrective action receive 

it, and that this process is updated throughout the injection project. While the details of all of the 

requirements are presented in later sections of this guidance, the basic requirements that owners 

or operators of GS projects must meet include: 

• Prepare, maintain, and comply with an AoR and Corrective Action Plan that includes all 

of the required elements of the plan [40 CFR 146.84(b)]; 

• Delineate the AoR using computational modeling and identify all wells that require 

corrective action [40 CFR 146.84(c)]; 

• Perform all required corrective action on wells in the AoR [40 CFR 146.84(d)]; 

• Reevaluate the AoR throughout the life of the project [40 CFR 146.84(e)]; 

• Ensure that the Emergency and Remedial Response Plan and financial responsibility 

demonstration account for the most recently approved AoR [40 CFR 146.84(f)]; and 

• Retain modeling inputs and data used to support AoR reevaluations for 10 years [40 CFR 

146.84(g)].

If a vertical leakage pathway out of the injection zone is present, USDWs in the vicinity of a 

proposed Class VI injection well may be endangered by (1) movement of carbon dioxide into the 

USDW, impairing drinking water quality through changes in pH, contamination by trace 

impurities in the injectate (e.g., mercury, hydrogen sulfide), and leaching of metals and/or 

organics; and (2) movement of non-potable water (e.g., brine) out of the injection formation into 

a USDW as caused by elevated formation pressures induced by injection. Therefore, the AoR 

encompasses the region overlying the separate-phase (e.g., supercritical, liquid, or gaseous)

carbon dioxide plume and the region overlying the pressure front where fluid pressures are

sufficient to force fluids into a USDW. While it may often be the case that the AoR will 

encompass the boundary of the GS project, within which all project activities will occur, the 

Class VI Rule does not require that the AoR and overall project boundary be equivalent in all 

cases.

The Class VI Rule requires that “the AoR is delineated using computational modeling that 

accounts for the physical and chemical properties of all phases of the injected carbon dioxide 

stream and is based on available site characterization, monitoring, and operational data” [40 CFR 

146.84(a)]. As discussed below, GS computational modeling for Class VI injection wells is 

complex and requires advanced methods. Additionally, the AoR must be reevaluated at a 

minimum fixed frequency not to exceed five years, or when monitoring and operational 

conditions warrant [40 CFR 146.84(e)]. The purpose of Class VI well AoR reevaluations is to 
UIC Program Class VI Well Area of Review 3 

Evaluation and Corrective Action Guidance

ensure that site monitoring data are used to update modeling results, and that the AoR delineation 

reflects any changes in operational conditions. The general relationship between site 

characterization, modeling, and monitoring activities at a GS project is shown in Figure 1-1. 

Figure 1-1: Flow Chart of Monitoring and Modeling at a GS Project. 
UIC Program Class VI Well Area of Review 4 

Evaluation and Corrective Action Guidance

An individual Class VI permit must be obtained separately for each injection well, as area 

permits are not allowed under the Class VI Rule [40 CFR 144.33]. However, EPA anticipates 

that, in many cases, multiple injection wells will be operated within a single GS project. If 

approved by the UIC Program Director, AoR delineation and corrective action activities may be 

performed collectively for all wells included within a single project. All required submittals (e.g., 

maps of the delineated the AoR and the AoR and Corrective Action Plan) must be submitted 

separately for each well, however, so that they may be incorporated into each well’s Class VI 

permit. In all cases, EPA recommends that AoR delineation models account for all wells 

injecting into (including any injection wells associated with other UIC well classes or other Class 

VI operations) or pumping from the injection zone or any other zones that are hydraulically 

connected to the injection zone. 

The corrective action requirements for Class VI wells are generally similar to those for other 

injection well classes. However, due to the potentially large AoR of GS projects, EPA has 

allowed the use of phased corrective action, if approved by the UIC Program Director [40 CFR 

146.84(b)(2)(iv)]. If phased corrective action is approved by the UIC Program Director, owners 

or operators would be allowed to perform corrective action only on the subset of artificial 

penetrations located within the AoR prior to injection that are located in regions nearest the 

injection well(s). Corrective action would continue during injection in the remaining regions of 

the AoR prior to carbon dioxide migration or pressure elevation in that area. EPA encourages 

owners or operators to perform all necessary corrective action on deficient wells identified 

during the initial AoR delineation or AoR reevaluations before the end of the injection phase. 

As a part of a Class VI permit application, the owner or operator must submit an AoR and 

Corrective Action Plan that describes the anticipated activities that will be performed to comply 

with these requirements [40 CFR 146.84(b)]. The AoR and Corrective Action Plan must be 

approved by the UIC Program Director prior to submittal of the initial AoR delineation and 

issuance of a permit [40 CFR 146.84(b)]. This plan will facilitate dialogue between the owners 

or operators and the UIC Program Director to ensure that the UIC Program Director understands 

and agrees early in the project lifetime with the methods necessary to delineate the AoR and 

complete all required corrective action. A Class VI AoR and Corrective Action Plan must 

include the following information [40 CFR 146.84(b)]:

1. The method for delineating the AoR, including the model to be used, assumptions that 

will be made, and the site characterization data on which the model will be based; 

2. The minimum fixed frequency, at least once every five (5) years, that the owner or 

operator proposes to reevaluate the AoR; 

3. The site- and project-specific monitoring and operational conditions that would warrant a 

reevaluation of the AoR prior to the next routinely scheduled reevaluation; 

4. How specific monitoring and operational data (e.g., injection rate and pressure) will be 

used to inform an AoR reevaluation; 
UIC Program Class VI Well Area of Review 5 

Evaluation and Corrective Action Guidance

5. How corrective action will be conducted, including what corrective action will be 

performed prior to injection and what, if any, portions of the AoR will have corrective 

action addressed on a phased basis and how the phasing will be determined; 

6. How corrective action will be adjusted if there are changes in the AoR; and 

7. How site access will be guaranteed for future corrective action.

The requirements related to the AoR and Corrective Action Plan are discussed in depth in the 

UIC Program Class VI Well Project Plan Development Guidance. 

1.2. Organization of this Guidance 

This guidance document is organized to generally follow the sequence of AoR delineation and 

corrective action activities that an owner or operator will perform over the life of a proposed and 

later permitted Class VI injection project. These activities will generally proceed as described 

below. 

Prior to the issuance of a permit for the construction of a new Class VI well (or the conversion of 

an existing well):

1. Collection of relevant site characterization and operational data [40 CFR 146.82(a)(3), 

146.82(a)(5), 146.82(a)(6), and 146.83]; 

2. Determination of relevant operational data that will inform the AoR modeling [40 CFR 

146.82(a)(7), and 146.82(a)(10)-(11)]; 

3. Development of an AoR and Corrective Action Plan [40 CFR 146.82(a)(13) and

146.84(b)]; 

4. Performing AoR modeling and delineation [40 CFR 146.82(a)(2)]; and

5. Identification and assessment of artificial penetrations within the AoR [40 CFR 

146.82(a)(4)]. 

Prior to granting approval for injection: 

6. Collection and/or updating of relevant site characterization and operational data that will 

inform AoR modeling [40 CFR 146.82(c)(2)-(5), 146.82(c)(7), and 146.83]; 

7. Identification of any needed updates to the AoR and Corrective Action Plan [40 CFR 

146.82(c)(9)];

8. Finalizing AoR modeling and delineation [40 CFR 146.82(c)(1)]; and

9. Performing corrective action on those penetrations that may serve as a conduit for fluid 

movement [40 CFR 146.82(c)(6) and 146.84(d)]. 
UIC Program Class VI Well Area of Review 6 

Evaluation and Corrective Action Guidance

During injection and post-injection site care (PISC):

10. Reevaluation of the AoR periodically, at least once every five (5) years [40 CFR 

146.82(c)(9) and 146.84(e)], and updating the AoR and Corrective Action Plan; and 

11. If phased corrective action is approved or when additional corrective action is warranted 

based on AoR reevaluations, performing corrective action [40 CFR 146.82(c)(6) and 

146.84(d)]. 

Activities (1) through (5) must be performed prior to receiving approval to construct a Class VI 

injection well and activities (6) through (9) must be performed prior to receiving approval to 

inject carbon dioxide, and their results must be submitted to the UIC Program Director as part of

the Class VI injection well permit application [40 CFR 146.82(a)]. The remaining activities will 

be performed after a permit application has been approved by the UIC Program Director and the 

Class VI injection well is actively operating. 

This guidance document generally focuses on activities (4), (5), (8), (9), (10), and (11), as 

follows: 

• Section 2 provides background on computational modeling of GS activities;

• Section 3 discusses performing computational modeling to delineate the AoR and comply 

with permit requirements (activities 4 and 8); 

• Section 4 focuses on abandoned well identification, assessment, and corrective action on 

all artificial penetrations within the AoR (activities 5, 9, and 11); and

• Section 5 focuses on reevaluation of the AoR (activity 10).

Site characterization activities (activities 1 and 6) are discussed briefly in this guidance (Section 

3.2), and are covered in more detail in the UIC Program Class VI Well Site Characterization 

Guidance. Preparation of the AoR and Corrective Action Plan (activity 3) and identification of 

any updates (activity 7) are also discussed briefly herein, and in more detail in the UIC Program 

Class VI Well Project Plan Development Guidance. 
UIC Program Class VI Well Area of Review 7 

Evaluation and Corrective Action Guidance

2. Computational Modeling for Geologic Sequestration

This section discusses the fundamentals of computational modeling for GS to provide the 

necessary background for owners or operators, and to assist in understanding and complying 

with the Class VI Rule. While computational modeling for GS may entail a vast amount of 

complex information, the purpose of this section is to provide a brief introduction to the 

modeling techniques and fundamentals that may be necessary or significant for satisfying the 

specific rule requirements. Following an introduction that explains the use of modeling in the 

context of meeting the requirements of the Class VI Rule: 

• Section 2.1 discusses the processes that can be modeled;

• Section 2.2 presents a discussion of the parameters that are included in AoR models; 

• Section 2.3 presents available computational approaches, including numerical, analytical, 

semi-analytical, and hybrid approaches; 

• Section 2.4 discusses model uncertainty and sensitivity analyses; 

• Section 2.5 discusses model calibration; and 

• Section 2.6 provides an overview of existing codes used for development of GS models. 

The AoR for a Class VI injection project must be delineated using a computational model that 

accounts for the physical and chemical properties of all phases of the injected carbon dioxide [40 

CFR 146.84(a)]. A computational model is based on available data, and it is a mathematical 

representation of the GS project and relevant features, including injection wells, site geology, 

and fluids present. As described below, a site-specific computational model is designed by 

incorporating the GS site and operational characteristics into a computational code, which is a 

computer program that has been designed to simulate multiphase flow and other pertinent 

processes in geologic media based on scientific principles and accepted mathematical (i.e., 

governing) equations. 

Computational codes that may be used for modeling of GS are necessarily more technically 

complex than commonly used ground water flow codes because GS modeling considers 

multiphase (e.g., gas, liquid, supercritical fluid) flow of several fluids (i.e., ground water, carbon 

dioxide, hydrocarbons), phase changes of carbon dioxide, heat flow, and significant pressure 

changes. Furthermore, in some cases models consider reactive transport (e.g., chemical reactions 

between constituents) and geomechanical processes (e.g., induced fault activation). As discussed 

below, the Class VI Rule requires that the AoR be delineated using models that include 

multiphase flow [40 CFR 146.84(a)], but not necessarily reactive transport or geomechanical 

processes. However, inclusion of these processes in the AoR delineation model may be 

important in some cases and may be required by the UIC Program Director.
UIC Program Class VI Well Area of Review 8 

Evaluation and Corrective Action Guidance

Several codes are available that are capable for use in development of adequate models for 

delineation of the AoR at a GS site and for complying with Class VI injection well permit 

requirements (Section 2.6). Although available codes are sophisticated and based on the bestavailable scientific understanding, computational models are approximations and are never 

perfect representations of reality, and they cannot provide a completely accurate prediction of 

fluid movement at a GS site. Therefore, the characterization of model uncertainty, using 

sensitivity analyses, and conducting model calibrations are very important parts of many 

computational approaches. 

Research studies have provided valuable information on the capabilities of available models, 

what information may be collected in order to properly inform model development, and how the 

model results may be presented. Importantly, the information and guidance provided here is 

based on currently available data, scientific research, and project experience. EPA recognizes 

that data collected from future GS projects may advance GS computational modeling and AoR 

delineation. EPA is committed to an adaptive approach for regulation of GS projects and may 

revisit aspects of Class VI federal regulations, and guidance, as new data becomes available.

There is a long history of simulating multiphase flow and transport in porous media using 

computational models. Comprehensive reviews of multiphase flow in porous media and 

modeling are provided elsewhere (e.g., Pinder and Gray, 2008; Miller et al., 1998; Gerritsen and 

Durlofsky, 2005; Finsterle, 2004). These models solve a series of governing equations to predict 

the composition and volumetric fraction of each phase state (e.g., liquid, gas, supercritical fluid) 

as a function of space and time for a particular set of circumstances. Governing equations are 

formulated to describe the flow and transport of several chemical species in several phases, in 

which interphase mass transfer may be important. Typically, flow equations are derived by 

substituting a multiphase form of Darcy’s Law into continuum balance expressions. 

The solution of the continuum balance equations requires that they be supplemented with closure 

relations that express unknowns in terms of accessible parameters. These include equations of 

state and constitutive relationships. Equations of state express the equilibrium phase relationship 

between pressure, volume, and temperature for a particular chemical. Accepted equations of state 

for carbon dioxide are presented in Figure 2-1, and are discussed in Section 2.2.4. Constitutive 

relationships are typically empirically based approximations used to simplify the system and 

estimate unknowns. Examples of constitutive relationships are saturation-relative permeability 

relationships, interphase mass transfer relations, and solution reaction relations. 
UIC Program Class VI Well Area of Review 9 

Evaluation and Corrective Action Guidance

Figure 2-1: Equations of State for Carbon Dioxide.
UIC Program Class VI Well Area of Review 10

Evaluation and Corrective Action Guidance

2.1. Modeled Processes

Computational codes used for GS vary in complexity and may include routines for multiphase 

flow, reactive transport, and geomechanical processes. Traditionally, codes have been developed 

as separate entities to simulate these processes. Present-day simulators typically address and 

couple multiphase flow with geomechanical processes or geochemical processes. However, 

depending on site-specific characteristics, where the geochemical and geomechanical processes 

are significant, robust simulation of GS may require interactive coupling of all three processes.

The Class VI Rule only requires that multiphase flow be included in computational modeling.

However, the owner or operator, or the UIC Program Director, may determine that reactive 

transport and/or geomechanical modeling should also be included for a particular proposed 

project. For example, reactive transport could be relevant if permeability and/or porosity are 

predicted, based on previous testing, to change as a result of precipitation/dissolution reactions. 

Geomechanical processes could be relevant if previous testing has indicated that pressure and 

stress changes hydrogeologic properties and/or affects confining unit integrity. 

Codes used to simulate multiphase flow generally incorporate some or all of the following 

processes: phase transition behavior of carbon dioxide (gas, liquid, supercritical fluid) and 

associated buoyancy; dissolution of carbon dioxide in brine and oil and associated increased 

density; dissolution of water in carbon dioxide; variable viscosity and density of brine and 

carbon dioxide phases; thermal effects such as cooling or freezing due to carbon dioxide 

expansion from supercritical and liquid phases; and reduced fluid permeability due to the 

presence of several immiscible fluids within a pore space.

Codes used to simulate reactive transport generally incorporate rate-limited intra-aqueous 

reactions, mineral dissolution and precipitation, changes in porosity and permeability due to 

these reactions, and multi-component gas mixtures. Reactive transport models can be used to 

determine the impact of carbon dioxide and its co-injectates (e.g., hydrogen sulfide, sulfur 

dioxide) on aquifer acidification, the concomitant mobilization of metals, and any mineral 

trapping of carbon dioxide (e.g., precipitation of carbonate minerals). Reactive transport models 

can also be used to assess corrosion of well construction materials as influenced by carbon 

dioxide. 

The length scales associated with interfacial geochemistry are very small (e.g., micrometers to 

millimeters) compared to multiphase flow simulation (meters to kilometers). Small grid spacing 

around these regions may imply associated small time steps, so that the overall problem becomes 

computationally demanding when trying to couple these reactions to multiphase flow. Data 

related to geochemical rate parameters are generally lacking (e.g., Knauss et al., 2005; Xu et al., 

2006), and have to be estimated for a wide range of possible environmental conditions and 

mineralogical interfaces. Several common codes that may be used for AoR delineation, such as 

ECLIPSE, normally do not include routines for reactive transport.

Geomechanical codes can be used to evaluate the effect of reservoir pressurization and buoyancy 

on the integrity of geologic confining units, reactivation of existing fractures and faults, and rock 

properties such as porosity and permeability. The amount and spatial distribution of pressure 
UIC Program Class VI Well Area of Review 11

Evaluation and Corrective Action Guidance

buildup in a geologic formation will depend on the rate of injection, the permeability and 

thickness of the injection formation, the mechanistic properties of the rock matrix, the 

permeability of the confining units, and the presence or absence of permeability barriers, and 

boundary conditions of the system. Models used to simulate geomechanical processes generally 

incorporate effective stress/strain relationships, aperture stiffness and associated closing and 

widening, and variation in porosity and permeability. Geomechanical modeling may require 

simulation on both a large and small scale (individual fractures), which can be computationally 

challenging (i.e., require long model processing times on the order of days). When individual 

fractures are considered, the spatial grid resolution may need to be on the order of meters or less. 

Therefore, smaller-domain models may be necessary to investigate migration through individual 

fractures. Generally, simulation of flow through a fractured reservoir requires codes that have 

been designed for this purpose. 

2.2. Model Parameters

A parameter is a variable in the governing equations of the model that may be of uniform value 

throughout the domain, or may vary in space and time. While maintaining salient features of the 

hydrogeologic system, some system aspects are often lumped together in simulation models and 

described by effective parameters that are estimated or averaged from several data sources. 

Relevant parameters for multiphase flow modeling of GS are summarized in Table 2-1, and 

include hydrogeologic characteristics, fluid properties, chemical properties, fluid injection and 

withdrawal rates, initial and boundary conditions, system orientation (e.g., model domain, grid 

cell size), and simulation control parameters. Initial conditions describe parameter values at the 

start of the model run. Boundary condition parameters describe conditions of the system (e.g., 

fluid flow rates and/or pressures) at the edges of the model domain and at the location of 

injection and/or extraction wells. While fluid injection and/or withdrawal rates and simulation 

control parameters are project specific, other particularly important site- and project-specific 

parameters for GS include formation intrinsic permeability, porosity, relative permeability, 

compressibility, fluid viscosity, and fluid density. These parameters are discussed in the 

following subsections. 

Parameter values are to be based on site data to the extent possible. However, as discussed 

below, in cases where detailed site geologic characterization data are unavailable (i.e., if 

formation testing is not complete or core samples are not available), parameter values may be 

estimated from standard values or relationships in the scientific literature. Model calibration, 

which may occur during AoR reevaluation, consists of adjusting a subset of the estimated 

parameter values to minimize the difference between model simulations and observed 

monitoring data. Model parameters may also be adjusted based on newly acquired site 

characterization data. For example, data gathered during well logging may inform updates to 

parameter values. See the UIC Program Class VI Well Site Characterization Guidance for more 

information. 
UIC Program Class VI Well Area of Review 12

Evaluation and Corrective Action Guidance

Table 2-1: Model Parameters for Multiphase Fluid Modeling of Geologic Sequestration. 

Parameter Description Estimation Methods Dimensions

Hydrogeologic Properties

Intrinsic Permeability

Represents properties of the 

subsurface that impact the rate 

of fluid flow.

See the UIC Program Class 

VI Well Site Characterization 

Guidance, and Section 2.2.1 

of this guidance

L

2

Porosity

The relative volume of void 

space within a formation. 

Controls the volume of carbon 

dioxide that may be stored.

See the UIC Program Class 

VI Well Site Characterization 

Guidance

Dimensionless

Capillary Pressure

The pressure difference across 

the interface of two immiscible 

fluids (e.g., carbon dioxide and 

water)

Calculated based on fluid 

saturations (see Section 

2.2.2 of this guidance)

M/LT2

Relative Permeability

Factor that determines the 

decrease in permeability for a 

fluid due to the presence of 

other immiscible fluids

Calculated based on fluid 

saturations (see Section 

2.2.2 of this guidance)

Dimensionless

Fluid Pressure

Force acting on a unit area, 

measure of the potential energy 

per volume of fluid

See the UIC Program Class 

VI Well Site Characterization 

Guidance

M/LT2

Temperature Measure of the internal energy 

of a fluid

See the UIC Program Class 

VI Well Site Characterization 

Guidance

Temperature

Formation Compressibility

Measure of change in aquifer 

volume with a change in fluid 

pressure

See the UIC Program Class 

VI Well Site Characterization 

Guidance

LT2/M

Water Saturation

The percent of system void 

space occupied by aqueous 

fluids

See the UIC Program Class 

VI Well Site Characterization 

Guidance

Dimensionless

Carbon Dioxide Saturation

The percent of system void 

space occupied by carbon 

dioxide

Calculated by the 

computational model

Dimensionless

Storativity

The volume of fluid released 

from storage per unit decline in 

head per unit area of the 

formation

See Standard References, 

e.g., Fetter, 2001 Dimensionless

Fluid Properties

Viscosity Measure of the internal 

resistance to flow

Calculated based on 

equations of state, also 

influenced by fluid 

composition (see Section 

2.2.4 of this guidance)

M/LT
UIC Program Class VI Well Area of Review 13

Evaluation and Corrective Action Guidance

Parameter Description Estimation Methods Dimensions

Density The mass of a fluid per unit 

volume

Calculated based on 

equations of state, also 

influenced by fluid 

composition (see Section 

2.2.4 of this guidance)

M/L3

Composition

Molecular makeup, by volume 

or mass, of a fluid. 

Measurement of salinity, 

concentration of trace 

compounds

See the UIC Program Class 

VI Well Site Characterization 

Guidance

M/L3

Fluid Compressibility The change in volume of a fluid 

from a unit change in pressure

See Standard References, 

e.g., Perry and Green, 1984 LT2

/M

Chemical Properties

Aqueous Diffusion 

Coefficient

The rate of chemical transport 

due to a concentration gradient

See Standard References, 

e.g., Tamimi et al., 1994 L

2

/T

Aqueous Solubility

The maximum concentration of 

a chemical (e.g., carbon dioxide) 

dissolved in the aqueous phase

Salinity, temperature and 

pressure dependent (see 

Spycher et al., 2003; 

Spycher and Pruess, 2005)

M/L3

Solubility in Carbon Dioxide

The maximum concentration of 

a chemical (e.g., water) 

dissolved in separate-phase 

carbon dioxide.

Temperature and pressure 

dependent (see Spycher et 

al., 2003; Spycher and 

Pruess, 2005)

M/L3

Fluid injection and withdrawal rates

Injection Rates Injection rates at each well Planned site

operational data L

3

/T

Withdrawal Rates Any fluid withdrawal rates 

within model domain

Measure rates for wells 

conducting pumping

within the AoR

L

3

/T

Boundary Conditions

Fluid pressures and/or flow 

rates at the edges of the model 

domain

Tested in conjunction with 

model extent, to ensure no 

artificial influence on model 

results

Varies

Fluid injection and withdrawal rates (Continued)

Initial Conditions

Fluid pressures and/or flow 

rates within the domain at the 

beginning of the model run

Based on pre-injection site 

characterization data, see 

the UIC Program Class VI 

Well Site Characterization 

Guidance

Varies
UIC Program Class VI Well Area of Review 14

Evaluation and Corrective Action Guidance

Parameter Description Estimation Methods Dimensions

System Orientation and Simulation Controls

Model Extent (domain) The lateral extent of the model 

in all directions

Tested in conjunction with 

boundary conditions, to 

ensure no artificial influence 

on model results

L 

Number of Model Layers Model vertical discretization

Based on conceptual site 

model of site stratigraphy, 

see the UIC Program Class 

VI Well Site Characterization 

Guidance

Dimensionless

Layer Thickness Vertical extent of each model 

layer

See the UIC Program Class 

VI Well Site Characterization 

Guidance

L 

Grid Cell Size Lateral size of each model cell

May vary throughout 

domain, as dictated by 

conceptual model and 

computational necessities

L

2

Model Timeframe The complete duration of the 

model run

Tested to ensure long 

enough to allow for 

pressure decline to preinjection conditions

T 

Time Step Size

The duration of each temporal 

interval during the model 

timeframe

Often controlled by code, 

tested to ensure small 

enough to not artificially 

influence results

T 

L = Length; M = Mass; T = Time

2.2.1. Intrinsic Permeability

Intrinsic permeability is a property of the solid phase (i.e., porous medium) in the subsurface that 

impacts the rate of fluid flow. Larger intrinsic permeability values correspond to greater fluid 

flow rates. Intrinsic permeability has units of length squared and is often reported in the units of 

millidarcies (mD); one mD is equal to 9.9·10-16 square meters (m2). Typical permeability values 

for an injection zone at a GS project range from 1 to 102 mD (e.g., Sorensen et al., 2005; Fischer 

et al., 2005; MGSC, undated; ISGS, 2009). Typical permeability values for a confining unit (e.g., 

shale) range from 10-7 to 10-4 mD (e.g., Soeder, 1988). 

Intrinsic permeability incorporates the effects of formation porosity, pore structure, such as poresize distribution and connectivity, and the presence of fractures or faults. The spatially 

heterogeneous nature of subsurface materials results in a heterogeneous intrinsic permeability 

distribution in most formations. Additionally, intrinsic permeability is an anisotropic parameter, 

in that lateral intrinsic permeability is often significantly larger than vertical intrinsic 

permeability due to depositional layering. Anisotropy in intrinsic permeability, both vertical and 

horizontal, may also be an effective property of fractured rock media. Intrinsic permeability is 

typically estimated from a combination of hydrogeologic field tests (e.g., aquifer tests, pressure 
UIC Program Class VI Well Area of Review 15

Evaluation and Corrective Action Guidance

fall-off tests), laboratory core analysis, and geophysical well logging. The UIC Program Class 

VI Well Site Characterization Guidance provides details regarding estimation of formation 

intrinsic permeability. Intrinsic permeability values are often adjusted during model calibration. 

See Box 2-1 for more information. 

During the development of the computational model, the model developer determines how to 

estimate values of intrinsic permeability within the entire model domain based on results of site 

characterization activities at discrete locations. For modeling purposes, the simplest description 

of intrinsic permeability is a homogenous distribution, which incorporates a single value for the 

entire subsurface domain based on an average of available data. A model that assumes a

homogeneous permeability distribution, however, will not account for heterogeneity (if it exists)

that causes preferential flow paths or confining strata, or for the depth dependence of 

permeability in an updipping formation. Another option is to incorporate a layered distribution, 

which incorporates a single permeability value for each geologic stratum in the domain, and can 

be constructed by using geologic maps and cross-sections of the proposed project site. 

Alternatively, geostatistical and stochastic methods are available to create a statistical ensemble 

of possible permeability distributions that incorporate both lateral and vertical heterogeneity 

based on available site characterization data. Spatial variability of permeability is thus described 

by a relatively small number of geostatistical parameters. Considering the large areas that are 

anticipated to be modeled for AoR delineations of proposed Class VI injection well project sites, 

techniques are among the best methods for incorporating realistic heterogeneity distributions into 

the computational model with limited data (see inset, Box 3-1). 

Compared to homogeneous or layered permeability distributions, depending on the available 

data, intrinsic permeability fields developed with geostatistical techniques may provide a more 

realistic representation of conditions within the formation, and resulting models may better 

represent carbon dioxide migration through high-permeability channels. Commercial software 

packages are available for use in the development of heterogeneous intrinsic permeability 

distributions based on available site data (e.g., T-PROGS; Carle, 1999). See Doughty and Pruess 

(2004), Juanes et al. (2006), Obi and Blunt (2006), and Flett et al. (2007) for examples of the 

development of heterogeneous profiles based on geostatistical techniques. For more information 

regarding the use of geostatistical methods, see the UIC Program Class VI Site Characterization 

Guidance. 

Several previous studies have evaluated the impact of permeability values on computational 

modeling results, through the use of parameter sensitivity analyses. Law and Bachu (1996) and 

Lindeburg (1997) demonstrated that for a homogeneous system, carbon dioxide mobility 

increases with increased formation permeability. Comparing homogeneous formations and those 

with layered heterogeneities, Lindeberg (1997) showed that the presence of thin shale layers 

increases sweep and thus carbon dioxide dissolution. For systems that are heterogeneous in three

dimensions, Flett et al. (2007) illustrated that increased heterogeneity resulted in increased lateral 

migration and therefore dissolution. However, increasing heterogeneity also decreased the rate of 

residual phase trapping by delaying water imbibition into previously carbon dioxide-filled pore 

space. Overall, increased heterogeneity resulted in slower carbon dioxide migration and 
UIC Program Class VI Well Area of Review 16

Evaluation and Corrective Action Guidance

decreased accumulation at the confining layer compared to a homogeneous case. Pruess (2008) 

showed that for discharge through a fault, decreased fault permeability resulted in delayed 

leakage to the surface and an increased maximum leakage rate.

Simulations by Zhou et al. (2008) indicate that patterns of formation pressure increase induced 

by carbon dioxide injection are sensitive to permeability. Larger formation permeability values 

resulted in less localized pressure increase surrounding the injection well. In addition, larger 

confining layer permeability resulted in less pressure buildup throughout the formation due to 

pressure dissipation and associated brine leakage. 

2.2.2. Relative Permeability and Capillary Pressure 

When immiscible fluids (e.g., carbon dioxide, water) are present within the pore spaces of a 

geologic formation, the ability for flow of one of those fluids is reduced, due to the blocking 

effect of the presence of the other fluid. Note that under any reservoir conditions, ground water 

and carbon dioxide will be immiscible, and ground water and hydrocarbons will be immiscible. 

Carbon dioxide and hydrocarbons, however, may be miscible or immiscible based on reservoir 

conditions. The relative permeability is a scaling factor that represents the reduction in the 

capacity for fluid flow due to the presence of other phases in porous media, with a value between 

0 and 1. This value is multiplied by the intrinsic permeability of a geologic formation in order to 

compute the effective permeability for a fluid in a particular pore space. The relative 

permeability of a fluid is based on the properties and amounts of all fluids present within the 

system. The greater the amount of pore space occupied by a particular fluid or phase (measured 

as fluid saturation), the greater the relative permeability will be for that fluid. Because fluid 

saturations change over time and location, relative permeability values typically vary during 

model simulations. 

The relative permeability for each fluid is typically calculated as a function of fluid saturations at

each location and time within a model. This is achieved via a relative permeability-saturation 

function. The relative permeability-saturation function shape is based on properties of the porous 

media and fluids present at a particular site. Residual fluid saturation also impacts the shape of 

the relative permeability function, and describes the minimum fluid saturation within the porous 

medium following immiscible fluid displacement. An example relative permeability-saturation 

function is given in Figure 2-2. Note that this example function has been developed for a specific 

site (Doughty, 2007) and may not be applicable to other GS sites. Capillary pressure-saturation 

relationships (also known as characteristic curves) are also of importance because capillary 

pressure gradients provide a driving force for fluid movement under unsaturated conditions. 
UIC Program Class VI Well Area of Review 17

Evaluation and Corrective Action Guidance

Figure 2-2: Example Relative Permeability-Saturation and Capillary PressureSaturation Relationships for Water and Carbon Dioxide. 

Reproduced with permission of Springer Science + Business Media. 
UIC Program Class VI Well Area of Review 18

Evaluation and Corrective Action Guidance

Previous research has shown that model predictions are very sensitive to the shape of the relative 

permeability-saturation functions used. The UIC Program Class VI Well Site Characterization 

Guidance provides details regarding measurement of relative permeability. Ideally, laboratory 

core-analysis techniques will be used for experimental measurement of the relative permeabilitysaturation and capillary pressure-saturation functions for a particular site at reservoir conditions, 

with carbon dioxide and representative native fluids (e.g., Perrin et al., 2008; Bachu and 

Bennion, 2008; Plug and Bruining, 2007). If this is not feasible, relative permeability-saturation 

relationships may be estimated from core analysis using other immiscible fluids (e.g., Doughty et 

al., 2007). Alternatively, previously reported functions may be used, such as those presented in 

Figure 2-2, if the experimental system was very similar to the site conditions for which the 

model will be applied. Relative permeability-saturation relationships are also commonly adjusted 

during model calibration. 

Doughty and Pruess (2004) compared site-specific characteristic curves to “generic” curves at 

the Frio, TX GS pilot project site and found that the choice of characteristic curves had a 

significant impact on plume size, shape, and mobility. The authors point out that the differences 

in plume behavior for different sets of characteristic curves had important implications for 

operation and monitoring of the pilot test. Similarly, Doughty et al. (2007) found that model 

results were very sensitive to characteristic curve parameters. The authors constrained the value 

of characteristic curve parameters by calibration to monitoring data. 

Pruess (2008) compared the effect of using three-phase characteristic curves developed for 

organic liquid-water-air systems (Stone, 1970) and simple linear characteristic curves. The 

choice of characteristic curves was found to have a significant impact on the observed leakage 

rate of carbon dioxide through a fault system. The linear characteristic curves resulted in 

simulated earlier leakage of carbon dioxide to the surface and lower leakage rates. Use of threephase relationships resulted in small fluid permeability at intermediate saturations due to phaseinterference effects. 

The impact of using hysteretic versus non-hysteretic characteristic curves has also been 

compared. Hysteresis refers to the dependence of the shape of the characteristic curve on the 

history of fluid flow within the formation. For example, characteristic curves are often observed 

to have a different shape when non-wetting fluids (e.g., supercritical carbon dioxide) are 

displacing wetting fluids (e.g., formation water), than when wetting fluids are displacing nonwetting fluids. Juanes et al. (2006) showed that consideration of hysteresis and capillary trapping 

resulted in the carbon dioxide being spatially distributed over a larger area with less 

accumulation at the confining layer. Doughty (2007) found that results from simulations with 

non-hysteretic curves did a poor job of matching simulations with hysteretic curves in 

homogeneous and heterogeneous media. Relative to non-hysteretic cases, simulations including 

hysteresis exhibited a more mobile plume leading edge (where there is no water imbibition) and 

a slower trailing edge with a significant amount of residual trapping (due to water imbibition).
UIC Program Class VI Well Area of Review 19

Evaluation and Corrective Action Guidance

2.2.3. Injection Rate

The carbon dioxide injection rate at proposed Class VI injection wells is incorporated into the 

model by assigning the injection rate parameter at a constant or variable-rate boundary condition, 

or by defining various source terms for specific nodes that correspond to injection location. 

However, it is important to note that calculated pressure values where injection rates are applied 

may need to be monitored to identify flow-controlled or pressure-limited cases. Several 

researchers have reported that increasing the carbon dioxide injection rate results in increased 

migration rates (e.g., Law and Bachu, 1996; Saripalli and McGrail, 2002; Juanes et al., 2006). 

Juanes et al. (2006) considered capillary trapping in highly heterogeneous media, and found that 

increased injection rate resulted in more simulated residual trapping due to invasion of carbon 

dioxide into a wider range of pore sizes. Therefore, in the long term, increased injection rates 

actually decreased the final simulated extent of carbon dioxide migration, as more mass was 

immobilized through capillary forces. Pruess (2008) modeled leakage to the ground surface 

through a fault system, and simulations indicated that larger injection rates resulted in increased 

maximum surface discharge rates relative to injection rates.

2.2.4. Fluid Properties and Equations of State

The density, viscosity, and phase-state of the carbon dioxide injectate, ground water, and any 

other fluids that may be present (e.g., hydrocarbons), are important model input parameters.

However, these properties change significantly across the temperature and pressure range that 

will be encountered at GS projects, and they are also affected by salinity. The equations of state 

describe these fluid properties and the existence of phases as a function of pressure and 

temperature; they are used by the model to calculate properties at conditions encountered in the 

simulation as they change with location and time. Graphs developed from accepted equations of 

state for carbon dioxide are depicted in Figure 2-1. Previous studies have shown that model 

results are sensitive to the equations of state used (Pruess et al., 2004; Han and McPherson, 

2008). 

The composition of the injectate will be reflected in several chemical and physical parameters 

assigned to the carbon dioxide fluid in the model simulations. Several studies have evaluated the 

impact of common carbon dioxide stream impurities hydrogen sulfide and sulfur dioxide on 

geochemical reactions and mineral trapping. Both Knauss et al. (2005) and Xu et al. (2007) 

showed that the addition of hydrogen sulfide had little impact, whereas the addition of sulfur 

dioxide resulted in a lower pH in the injection zone, less carbon-bearing mineral precipitation, 

and more formation-mineral dissolution.

2.2.5. Mass-Transfer Coefficients

Mass transfer coefficients describe the equilibrium concentration of chemical constituents (e.g., 

water, carbon dioxide) between separate phases. For example, the equilibrium aqueous 

concentration of carbon dioxide dissolved in ground water in contact with separate-phase (e.g., 

supercritical) carbon dioxide is described by a partitioning coefficient. Other mass-transfer 
UIC Program Class VI Well Area of Review 20

Evaluation and Corrective Action Guidance

coefficients describe the distribution of constituents between the gaseous, aqueous, separatephase carbon dioxide, and solid phases. For the case of reactive transport modeling, masstransfer coefficients describe equilibrium concentration of constituents between mineral and 

dissolved phases. Similar to fluid properties, mass-transfer coefficients are in many cases 

temperature and pressure dependent. Mass-transfer coefficients may also be dependent on 

properties of the formation and fluids present, such as ground water salinity. Reference 

documents are available that provide many necessary mass-transfer coefficients (e.g., Green and 

Perry, 2008), and several commonly used codes include necessary mass-transfer coefficients 

(e.g., TOUGH2-ECO2N; Pruess and Spycher, 2007).

2.2.6. Mineral Precipitation Kinetic Parameters

Mineral precipitation is a subset of reactive transport problems and represents a trapping 

mechanism for carbon dioxide as well as a mechanism for permeability modification. As noted 

above, the Class VI Rule does not stipulate that reactive transport be considered in AoR 

delineation modeling. However, the owner or operator, or the UIC Program Director, may 

determine that reactive transport modeling should be considered for a particular project. 

Studies accounting for mineral precipitation typically include precipitation kinetic (i.e., rate) 

parameters. Although precipitation rates have a large impact on mineral trapping, there is a great 

deal of uncertainty related to these parameters (Knauss et al., 2005; Xu et al., 2006). 

Furthermore, complex interrelationships exist between the rates of separate mineral species in a 

formation. For example, a sensitivity analysis for trapping through dawsonite [NaAl(CO3)(OH)2] 

precipitation showed that decreasing dawsonite kinetics resulted in increased formation of other 

trapping minerals calcite [CaCO3] and magnesite [MgCO3] (Knauss et al., 2005). Izgec et al. 

(2008) showed that changes in formation permeability resulting from mineralization reactions 

were very sensitive to kinetic rate parameters. Several modeling studies have indicated that 

geochemical equilibrium following injection may not occur for thousands of years (e.g., Xu et 

al., 2006; Gaus et al., 2005). 

2.2.7. Model Orientation and Gridding Parameters

Numerical modeling requires the developer to define the spatial and temporal domains, grid 

spacing and gridding routine, and domain boundaries. These features of the model are typically 

designed with an effort to minimize computational demand and therefore processing time. 

However, there is potential for erroneous results based on grid features of the model (i.e., 

numerical artifacts), which can mask or enhance the effects of physical processes. A few studies 

have focused on evaluating the impacts of numerical artifacts for models of GS. 

Doughty and Pruess (2004) tested the impact of varying grid cell sizes for a model of the Frio 

formation pilot GS project site in Texas. They found that the overall pattern of plume movement 

was similar for different grid sizes, but overly coarse grids were not able to simulate buoyancydriven flow within individual sand channels. The authors also observed that the choice of grid 

block sizes and gridding routine could result in preferential flow in the grid axis direction and 
UIC Program Class VI Well Area of Review 21

Evaluation and Corrective Action Guidance

numerical dispersion. Similarly, Juanes et al. (2006) observed that overly coarse grid block sizes 

that did not capture specific migration pathways overestimated carbon dioxide movement and the 

amount of capillary trapping. Doughty et al. (2007) note that higher-resolution models are 

needed for understanding of near well-bore effects. Yamamoto and Doughty (2009) demonstrate 

that grid refinement may have a substantial effect on overall simulated plume extent. Methods 

have been developed to establish numerical grids with high resolution in areas of interest (e.g., 

near well bores and fractures), and lower resolution in other areas, such as near the model area 

boundaries. 

2.3. Computational Approaches

Computational codes consist of the set of interrelated mathematical equations (i.e., governing 

equations, constitutive relationships, and equations of state) that are solved simultaneously in 

order to predict fluid movement, pressure changes, and other changes, as a function of both 

location and time. These equations include complex partial differential equations that cannot be 

easily solved, and require complex estimation techniques. In most cases, numerical 

approximation methods, discussed below, will be needed to adequately represent the several 

physical processes necessary to delineate the AoR and comply with the Class VI Rule. 

In certain circumstances, simpler analytic and semi-analytic approaches may be used to 

complement numerical efforts in delineating the AoR. As discussed below, analytic and semianalytic approaches are not capable of representing several processes and features that are 

important for predictions of fluid movement, and they often assume simple geometry and 

homogeneity. 

2.3.1. Numerical Approaches

Computational models used for practical applications typically consist of a numerical 

formulation of the governing equations applied over a spatially discretized model domain that 

defines the spatial extent and resolution of the problem (i.e., the model grid). This formulation is 

solved by a numerical method, such as finite element or finite difference approximation. The 

model grid is partitioned into grid cells, smaller spatial sub-units within the model. Fluid and 

heat flow is then solved between adjoining grid cells, while maintaining a mass and energy 

balance within the model. Phase changes, mass transfer, and chemical reactions can also be 

calculated for phases and constituents within a cell. Each cell can be assigned unique parameter 

values for physical properties (i.e., intrinsic permeability, porosity), allowing for threedimensional, detailed representations of physical heterogeneity. Numerical models may be used 

for steady-state problems (in which injection and withdrawal rates are constant and the solution 

is obtained only for infinite time when system variables become constant and the solution 

becomes independent of the initial condition) and transient problems (in which injection and 

withdrawal rates may vary in time, and the solution is obtained at several discrete times during 

the model timeframe while the system variables exhibit change in time and depend upon the 

initial condition). 
UIC Program Class VI Well Area of Review 22

Evaluation and Corrective Action Guidance

In addition to detailed geologic heterogeneity, numerical models are typically capable of 

representing density-driven fluid flow (e.g., the buoyancy of carbon dioxide) and the dissolution 

of carbon dioxide into ground water. Numerical models can also represent irreducible (i.e., 

residual) fluid saturations (i.e., the amount of fluid being “trapped” in geologic formation pore 

space even after another immiscible fluid has passed through that area), multiphase flow effects, 

and the concomitant reduced permeability.

The scale of spatial and temporal discretization of the model affects the accuracy of the solutions 

to these numerical formulations. Finer scales of time and space reduce numerical solution error.

However, computational demand increases as the length scale (e.g., grid cell size) and time scale 

(e.g., time-step size) decrease, and as additional processes are simulated. Methods have been 

developed to mitigate increases in computational demand, while focusing on regions and times 

of interest, such as adaptive grid block size (i.e., mesh) refinement. Another possibility is the use 

of parallel computing, in which a single problem is broken up and distributed among many 

processors (e.g., Zhang et al., 2007). 

2.3.2. Analytical, Semi-Analytical, and Hybrid Approaches

Analytical and semi-analytical models may be used to complement numerical modeling efforts in 

AoR delineation for Class VI wells. Compared to numerical models, analytical models have 

much lower computational requirements and therefore lower processing times. Analytical and 

semi-analytical codes may also be particularly useful for assessing the transport of carbon 

dioxide through abandoned well bores, which is difficult in numerical models due to the 

disparity in spatial scales. Analytical and semi-analytical models also may be used as screening 

tools to quickly assess potential storage sites, or as a relatively simple comparative check on 

numerical modeling results. Celia and Nordbotten (2009) suggest the use of hybrid numericalanalytical models for cases where a large-scale numerical model could be combined with local 

analytical models (e.g., describing wells), or the use of semi-analytical solutions where analytical 

solution is used in the spatial dimension and finite-stepping is used for temporal changes.

However, strictly analytical and semi-analytical models are not able to explicitly account for 

detailed physical and chemical characteristics of carbon dioxide injected as required under the 

Class VI Rule. They are also not able to simulate other important processes, such as capillary 

trapping, or account for varying injection rates or formation heterogeneity. The applicability of 

these models is limited to simplified cases where an exact function can be found to satisfy the 

governing equation and boundary and initial conditions. For example, in most cases, these 

models assume homogenous aquifers (i.e., no variability in physical structure, porosity, or 

intrinsic permeability). For most formations this is an unrealistic assumption, and it neglects 

preferential fluid movement through heterogeneous channels within geologic formations. 

2.4. Model Uncertainty and Sensitivity Analyses

As discussed above, computational models are an approximate representation of reality, and thus 

predictions exhibit some degree of uncertainty. Model uncertainty is a result of the uncertainties 
UIC Program Class VI Well Area of Review 23

Evaluation and Corrective Action Guidance

related to the underlying science of the governing equations and the uncertainty in the parameter 

values input to represent the actual system (USEPA, 2003). Uncertainty in governing equations 

and model framework may arise from incomplete scientific data or lack of knowledge, as well as 

the necessary simplifications that translate scientific concepts into mathematical equations.

Parameter uncertainty results from poor data quality (e.g., measurement errors, analytical 

imprecision, limited sample size), lack of data, and the inherent variability in natural systems.

Model predictions depend largely on the values input for a number of key parameters and thus 

may be significantly impacted by incomplete knowledge, or they may be process and scale 

dependent. The predictive accuracy of a model improves with improved data quality, increased

data quantity, realistic assumptions that reflect observed conditions and scientific knowledge, 

and a modeling domain (extent and resolution) that sufficiently and accurately represents the GS 

project.

Significant uncertainty exists in modeling predictions of GS due to the difficulty in determining 

the geological formation structure and permeability field throughout the extensive area likely to 

be impacted by proposed large injection volumes, a relative lack of data on the behavior of 

supercritical carbon dioxide in the subsurface, the drastic changes in transport behavior of carbon 

dioxide caused by changes in pressure and/or temperature, and the buoyant nature of carbon 

dioxide relative to native formation ground water. 

The impact of parameter uncertainty on modeling results can be characterized through a model 

sensitivity analysis, which consists of sequentially varying a single parameter in successive

model simulations while keeping all other model features constant. Sensitivity analyses provide 

an indication of those modeling parameters that are most sensitive (i.e., that most impact 

predictions of carbon dioxide migration, trapping, and pressure changes), and provide guidance 

for what parameters to focus on during data collection, parameter estimation, and model 

calibration. Accepted guides to environmental modeling (e.g., NRC, 2007) recommend the use 

of sensitivity analyses in submission of modeling results. Parameters that are sensitive for a 

particular model will be based on case-specific circumstances, and will be identified via 

sensitivity analyses. 

2.5. Model Calibration 

Model calibration consists of using the computational model to simulate a past time period for 

which monitoring data are available and adjusting relevant model parameters to reduce 

differences between model results and the observed monitoring data. For example, during initial 

model development, in-situ pressure data of the injection zone may be available for comparison 

to model predictions of pre-injection fluid pressures. After the initiation of carbon dioxide 

injection, monitoring data may be available regarding changes in reservoir pressure and fluid 

properties that may be used to calibrate the model. It is generally understood that model 

calibration reduces model error in prediction of future conditions. 

Examples of observed data that may be used for model calibration include carbon dioxide 

saturation values and fluid pressures. Model calibration involves adjustment of model 

parameters, termed “calibration parameters,” in order to minimize the difference between 
UIC Program Class VI Well Area of Review 24

Evaluation and Corrective Action Guidance

simulated and observed data values. Calibration parameters for a particular model will be site

specific, but they will commonly include intrinsic permeability and relative permeabilitysaturation function parameters. Calibration may involve incorporating additional heterogeneities 

or highly-permeable pathways. A case study of model calibration to monitoring data at an early 

GS research site, the Frio Brine Pilot in Texas, is provided in Box 2-1 of this guidance document. 

Model calibration is never perfect, in that simulated and observed values for a computational 

model will not agree exactly. Calibration statistics are often used to characterize the error 

difference between model simulations and observed data values. The objective of model 

calibration is to minimize the value of the calibration statistics to the extent possible, using 

model parameters values consistent with site data or realistic estimates. 

Common calibration statistics include the mean error (ME), mean-absolute error (MAE), and the 

root-mean squared error (RMSE). The ME is a simple average of the residual error between 

observed and simulated values and, therefore, positive values will offset negative values. The 

ME therefore provides an indication of the net bias (positive or negative) of the model simulated 

values. MAE is similar to the ME, with the important distinction that the sum of the absolute 

values of the residuals is calculated, thereby eliminating the offset that occurs by adding positive 

and negative values. The MAE, therefore, is always positive and represents the average 

difference between observed and simulated values. The RMSE is similar to the MAE, although 

negative values of the residual between observed and simulated values are eliminated by 

squaring the difference, and then the square root of the sum is determined prior to computing the 

average. 

Model calibration may be conducted by use of computer programs designed for this purpose 

(i.e., automated calibration, see Finsterle, 2004), and/or adjusted manually based on best 

professional judgment. In practice, the automated programs can be cumbersome; therefore, 

manual parameter adjustment is a more standard practice in the calibration of complex models. 
UIC Program Class VI Well Area of Review 25

Evaluation and Corrective Action Guidance

Box 2-1. Model Calibration Case Study: Frio Brine Pilot Project

Pilot projects of GS can provide valuable insight into modeling predictions and monitoring 

results comparison. The Frio Brine Pilot Project, in Dayton, TX, is an early experimental 

project conducted primarily by researchers at the Texas Bureau of Economic Geology and 

Lawrence Berkeley National Laboratory (LBNL). Two carbon dioxide injection and 

monitoring experiments (Frio I and Frio II) have been conducted at Frio, supplemented by 

numerical modeling. In this text box, separate-phase carbon dioxide data from monitoring 

wells, pressure monitoring data, and geophysical monitoring data are presented. These figures 

and discussion are taken from Doughty et al. (2007) and Ajo-Franklin et al. (2008). 

A geologic schematic of the Frio pilot site is shown in Figure 2-3. For the Frio I pilot, 1,600 

metric tons of carbon dioxide were injected over 10 days into a steeply dipping brinesaturated later at a depth of 1,500 m. For the Frio II pilot, approximately 350 metric tons of 

carbon dioxide was injected at a depth of 1,600 m. A number of pre-injection site 

characterization, and operational and post-injection monitoring activities were conducted 

along with both injections. 

Figure 2-3: Geologic Schematic of Frio Brine Pilot Project. The arrow at top indicates the north direction. 

From: Doughty et al. (2007).Reproduced with permission of Springer Science + Business Media.

For the Frio I pilot, a numerical model was calibrated by constraining the value of several 

parameters to a variety of monitoring data. Key calibration parameters were determined to be 

multi-phase flow parameters that describe the relative permeability-saturation relationship 
UIC Program Class VI Well Area of Review 26

Evaluation and Corrective Action Guidance

Box 2-1. Model Calibration Case Study: Frio Brine Pilot Project, continued

(referred to in the study as the irreducible liquid saturation, Slr) and the van-Genuchten (i.e., 

characteristic curve) parameter (m). The value of these parameters was constrained by several 

types of monitoring data (see Doughty et al., 2007). The researchers focused on calibration to 

the arrival time of carbon dioxide at the monitoring well, and pressure monitoring at the 

injection and monitoring wells. The arrival time of carbon dioxide at the injection well was 

determined based on a reduction of fluid density collected at the observation well using a Utube sampling apparatus. The observed arrival time was compared to a series of model runs, 

varying Slr and m (Figure 2-4). In addition, the observed pressure increase at both the 

monitoring and the injection wells were compared to model predictions (Figure 2-5). Based 

on these results, the value of the parameter Slr was constrained to a range of 0.15 to 0.30, and 

the value of m was constrained to 0.9. 

Figure 2-4: Observed and Modeled Carbon Dioxide Arrival at the Observation Well Based on Change in 

Fluid Density. From: Doughty et al. (2007). Reproduced with permission of Springer Science + Business 

Media.

Figure 2-5: Observed and Modeled Pressure Increase at (a) the Injection Well and (b) the Monitoring 

Well (from Doughty et al., 2007). Reproduced with permission of Springer Science + Business Media.
UIC Program Class VI Well Area of Review 27

Evaluation and Corrective Action Guidance

Box 2-1. Model Calibration Case Study: Frio Brine Pilot Project, continued

Frio II used an initial numerical model to predict the evolution of the carbon dioxide plume 

over time. Observed seismic geophysical data of plume migration showed that a thin finger of 

carbon dioxide moved further up-dip than initially predicted by the model. The model was 

calibrated to the seismic monitoring results by, among other changes, increasing the value of 

the intrinsic permeability throughout the model, and increasing the thickness of a highpermeability channel at the confining zone-injection zone interface. The initial and datacalibrated model results are shown in Figure 2-6. 

(a)

(b)

Figure 2-6: Comparison of (a) Initial and (b) Post-Calibration Model Predictions of Carbon Dioxide 

Plume Evolution. From: Ajo-Franklin et al. (2008).
UIC Program Class VI Well Area of Review 28

Evaluation and Corrective Action Guidance

2.6. Existing Codes used for Development of GS Models

A wide variety of modeling exercises have been reported in the peer-reviewed literature for GS 

and have been reviewed previously (Schnaar and Digiulio, 2009). Several computational codes 

have been developed for multiphase flow and transport problems, and a number of these codes 

are publicly or commercially available for the owners or operators of a GS project to use in AoR 

delineation modeling. Codes reported in the literature used for modeling of GS include 

petroleum reservoir codes (STARS, Law and Bachu, 1996; GEM, Kumar et al., 2004; ECLIPSE, 

Zhou et al., 2004; Juanes et al., 2006; CHEARS, Flett et al., 2007) and codes that have been 

developed at U.S. Department of Energy (DOE) national laboratories for a range of multiphase 

flow and transport problems (STOMP, CRUNCH, Knauss et al., 2005; TOUGH-series, Finsterle, 

2004; Xu et al., 2006; Doughty and Pruess, 2004; Doughty, 2007). Additionally, DOE provides a 

summary of available models that have been used to model processes associated with injection 

for GS at the Regional Carbon Sequestration Partnership (RCSP) project sites. The document 

presents the types of data that are needed for various models and how to obtain such information 

(NETL, 2011). These codes vary not only in the physical processes considered, but also in 

numerical techniques such as the spatial discretization method, iteration approach, and gridding 

routines. The codes mentioned above are provided as examples that may be used for GS 

modeling, and the lists given are not meant to include all available codes, or to suggest 

preference for certain codes over others. 

Codes used for modeling GS consider multiphase flow of carbon dioxide in supercritical, liquid, 

and gaseous phases including miscible and immiscible displacement, dissolution of carbon 

dioxide in ground water, density-driven flow, and flow of ground water as impacted by injection. 

Available codes may also be further categorized based on their ability to consider, or to be 

adjusted to consider, complex three-dimensionally heterogeneous formations, residual phase 

trapping and characteristic-curve hysteresis, mineral precipitation/dissolution reactions and 

subsequent mineral phase trapping and leaching of heavy metals, carbon dioxide sorption in 

coal-bed methane problems, and leakage through abandoned well bores. Models based on the 

TOUGH-series codes have been widely reported in the literature and are capable of considering 

three-dimensional heterogeneous formations, carbon dioxide dissolution, residual phase trapping 

and characteristic-curve hysteresis, coupled fluid flow and geomechanical processes, and mineral 

precipitation (e.g., Finsterle, 2004; Doughty, 2007; Xu et al., 2006; Rutqvist et al., 2008).

Several codes were compared for identical GS problems in an LBNL study (Pruess et al., 2004) 

in order to evaluate code comparability. Ten research groups representing six countries 

participated in the study. The codes evaluated included TOUGH-series codes (LBNL, CSIRO 

Petroleum, Industrial Research Limited), ECLIPSE 300 (Los Alamos National Laboratory), and 

STOMP (Pacific Northwest National Laboratory), among others. The problems considered 

varied in complexity and included mixture of gases in an open system, radial flow from an 

injection well, discharge along a fault zone, injection with mineral trapping, and injection with 

enhanced-oil recovery. For the most part, model results for the different codes were found to be 

in good agreement. Most discrepancies were traced to differences in the calculation of fluid 

properties (e.g., viscosity). These results emphasize the need for accurate descriptors of carbon 

dioxide transport properties and equations of state. 
UIC Program Class VI Well Area of Review 29

Evaluation and Corrective Action Guidance

The use of proprietary codes (i.e., codes not available for free to the general public) may prevent 

full evaluation of model results (e.g., NRC, 2007). There are several aspects of a model that can 

be proprietary, and some may be more important than others for computational model 

evaluation. For example, use of a proprietary user interface with a publicly available code may

not present a significant problem. Several popular codes in the petroleum-reservoir engineering 

discipline are proprietary (e.g., ECLIPSE). However, these codes have been used in peerreviewed studies to model GS, and operators of particular GS sites may prefer to use these codes 

as they have previous experience with them. As discussed below, when using a proprietary 

model for AoR delineation, site operators of GS projects are encouraged to clearly disclose to the 

UIC Program Director the code assumptions and, if necessary, governing equations and 

equations of state with the permit application. 
UIC Program Class VI Well Area of Review 30

Evaluation and Corrective Action Guidance

3. AoR Delineation Using Computational Models

Determination of the AoR for proposed Class VI wells will consist of data collection and 

compilation, development of the site computational model, delineation of the AoR based on 

model results, and submission of the model results and AoR delineation to the UIC Program 

Director with the Class VI permit application. The AoR and Corrective Action Plan must 

describe how the owner or operator plans to conduct these activities and is subject to UIC 

Program Director approval [40 CFR 146.84(b)]. 

The AoR delineation model must be submitted with the Class VI permit application—i.e., with 

the proposed AoR and Corrective Action Plan, as required at 40 CFR 146.82(a)(13)—and the 

modeled AoR will be finalized after all site data are collected and pre-injection testing is 

complete, per 40 CFR 146.82(c)(1). Therefore, the submittal, evaluation, and approval of the 

AoR, as part of the AoR and Corrective Action Plan, may be an iterative process, involving 

multiple drafts, until all the information required is submitted at the appropriate level of detail as 

determined by the UIC Program Director. See the UIC Program Class VI Well Project Plan 

Development Guidance for more information on the AoR and Corrective Action Plan. Also see 

the UIC Program Class VI Implementation Manual for additional information on how permitting 

authorities will review the information submitted by owners or operators.

This section describes the AoR delineation process and provides several quantitative examples 

revolving around a hypothetical GS site. EPA recommends that model development in all cases 

be conducted by a professional expert with the understanding of multiphase flow processes and 

experience with application of sophisticated computational models. 

3.1. AoR Delineation Class VI Rule Requirements

The following Class VI Rule requirements pertain to AoR delineation: 

• 40 CFR 146.84(a): The AoR is the region surrounding the GS project where USDWs 

may be endangered by the injection activity. The AoR is delineated using computational 

modeling that accounts for the physical and chemical properties of all phases of the 

injected carbon dioxide stream and is based on available site characterization, 

monitoring, and operational data. 

• 40 CFR 146.84(c)(1): Owners or operators of Class VI wells must predict, using existing 

site characterization, monitoring and operational data, and computational modeling, the 

projected lateral and vertical migration of the carbon dioxide plume and formation fluids 

in the subsurface from the commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient to cause the movement of injected 

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed 

time period as determined by the UIC Program Director. The model must: 

(i) Be based on detailed geologic data collected to characterize the injection zone(s), 

confining zone(s), and any additional zones; and anticipated operating data, 
UIC Program Class VI Well Area of Review 31

Evaluation and Corrective Action Guidance

including injection pressures, rates, and total volumes over the proposed life of 

the GS project; 

(ii) Take into account any geologic heterogeneities, other discontinuities, data quality, 

and their possible impact on model predictions; and 

(iii) Consider potential migration through faults, fractures, and artificial penetrations.

3.2. Data Collection and Compilation 

Computational modeling utilizes the required site characterization data for a proposed Class VI 

injection well site and applies scientifically accepted principles to estimate the carbon dioxide 

plume and pressure front migration. The extent to which site and operational conditions are 

realistically represented determines the validity of the resulting model predictions. Site 

characterization data inform model parameterization and the development of the model and, 

therefore, adequate data collection, analysis, and compilation are integral components of model 

development. Table 2-1 of this guidance provides a summary of important model parameters, 

many of which are determined based on site characterization data. 

A variety of site characterization data are required to be collected for proposed GS projects [40 

CFR 146.82 and 146.83]. These data are required to verify that the proposed injection zone at the 

characterized site has adequate injectivity to accept the injected carbon dioxide at the proposed 

rate and adequate volume to store the injectate over the lifetime of the project. Furthermore, site 

characterization data verify that suitable confining zone(s) are present to restrict the upwards 

movement of carbon dioxide. Additional features of the site, such as baseline geochemistry and 

pre-injection fluid pressures, inform the interpretation of future monitoring results and support 

reactive transport modeling if it is chosen to be used. As discussed below, much of the site 

characterization data collected at the proposed Class VI injection well site are also necessary to 

inform computational model development and AoR delineation. Site characterization 

requirements and methods are discussed in more detail in the UIC Program Class VI Well Site 

Characterization Guidance. 

3.2.1. Site Hydrogeology 

Regional and site-specific geology provide the foundations of the computational model used to 

delineate the AoR. This includes site stratigraphy, including formation elevation and thickness, 

as presented in cross sections and/or topographic maps. It is recommended that any data 

regarding structural geology (including folding, and fracture and fault systems) be identified and 

used when creating the computational model. For each geologic formation at the proposed 

injection site, hydrogeologic information, including initial fluid pressure, horizontal and vertical 

gradients, and ground water flow direction and velocity, should be considered. Other important 

characteristics include intrinsic permeability and porosity of all formations ranging from the 

uppermost USDW to beneath the injection zone. Where injection depth waiver applications are 

considered, EPA recommends that these parameters be determined for all formations down to 

and including the first USDW below the injection zone. See the UIC Program Class VI Well 

Injection Depth Waivers Guidance for additional information. EPA recommends that the 
UIC Program Class VI Well Area of Review 32

Evaluation and Corrective Action Guidance

heterogeneity of these characteristics within each formation also be evaluated. Data regarding the 

heterogeneity of these parameters are of particular importance in representing the injection and 

confining zone(s). The Class VI Rule requires that AoR computational modeling take into 

account any geologic heterogeneities and other discontinuities [40 CFR 146.84(c)(1)(ii)]. 

Thorough characterization of multiphase flow parameters is also recommended to properly 

inform the computational modeling. These include parameters describing the capillary pressuresaturation and relative permeability-saturation relationships of each formation, with the injection 

and confining zones being of particular importance. See Figure 2-2 of this guidance for more 

information. EPA recommends that accepted formulations of these relationships be defined that 

are as specific to the site and fluids of interest (e.g., brine, carbon dioxide) as possible. 

The quantity of data used to inform model development is recommended to be, at least, based on 

the Class VI Rule site characterization requirements, as discussed in the UIC Program Class VI 

Well Site Characterization Guidance. For pertinent data types, as discussed above, all data 

collected to comply with site characterization requirements may be considered in the AoR 

delineation. Furthermore, EPA recommends that any additional pertinent data available in the 

vicinity of the site, for example from the U.S. Geological Survey (USGS) or other sources, also 

be included in model development. 

Additionally, EPA recommends that the lateral and vertical extents of all formations predicted to 

exhibit contact with supercritical carbon dioxide or elevated pressure over the lifetime of the 

proposed GS project be characterized for hydrogeologic properties. This may be an iterative 

process because initial model estimates of plume and pressure front migration may indicate 

further migration than previously assumed. In these cases, some additional site characterization 

in these regions may be requested by the UIC Program Director before a permit is approved.

EPA recommends that adequate data be collected to reasonably estimate site heterogeneity.

Collection of sufficient data is always a challenge in geologic studies, and this is compounded by 

the large areas that may be impacted by GS projects. Use of geophysical site characterization 

techniques may reduce the burden of site characterization over large areas. See the UIC Program 

Class VI Well Site Characterization Guidance for more information on using geophysical 

methods to assist with collecting the required site characterization data for a Class VI injection 

well permit application. 

3.2.2. Operational Data 

The Class VI Rule requires that the AoR computational modeling for a Class VI injection well be 

based on existing or proposed operational data including injection pressures, rates, and total 

volumes over the lifetime of the GS project [40 CFR 146.84(c)(1)(i)]. EPA recommends that

operational data also include the location and number of injection wells, and the injection well 

construction details (e.g., total depth, perforated interval). In the case of GS projects with 

multiple Class VI injection wells, it is important to note that each Class VI well is required to be 

permitted separately, as area permits are not allowed [40 CFR 144.33(a)(5)]. However, EPA 

strongly encourages potential Class VI injection well owners or operators to account for all 
UIC Program Class VI Well Area of Review 33

Evaluation and Corrective Action Guidance

injection wells associated with the proposed project, or any other injection or extraction wells in 

the area, when developing the AoR model. EPA recommends that a single AoR delineation 

model be used for all Class VI injection wells for a single GS project, and that the model include 

the influences of all relevant wells. EPA also recommends that overlapping pressure 

perturbations be evaluated for a given basin or hydraulically connected formations to determine 

any combined risk to USDWs. The owner or operator may consult the UIC Program Director 

regarding any existing or planned projects in the vicinity of the proposed well. 

3.3. Model Development

Once adequate data are collected, model development consists of the formation of a conceptual 

site model, design of the mathematical framework and grid, and parameterization (i.e., 

determination of input parameter values) (USEPA, 2003). The model is then executed to provide 

predictions of fluid movement and pressure perturbations during the lifetime of the project. 

A Note Regarding Hypothetical Examples

Several informative boxes are included within this guidance that provide examples of the 

AoR delineation and reevaluation process based on a hypothetical site (Box 3-1, Box 3-2, 

Box 5-1, and Box 5-2). The hypothetical site presented is not intended to be representative of 

all GS projects. Assumptions and methods used in hypothetical examples may not be valid in 

all cases. A length scale has not been included on hypothetical site figures, such that an 

allowable size of the AoR, or distance between wells, is not unintentionally inferred from the 

figures.

3.3.1. Conceptual Model of the Proposed Injection Site 

A conceptual site model is a schematic representation of the proposed GS project, including all 

major geologic elements present in the flow system and any relevant physical processes. In the 

delineation process, the conceptual model is translated mathematically into a numerical model to 

be solved for pressure and saturation. The conceptual site model is informed primarily by the 

collected site characterization data and the proposed operational conditions, such as well-field 

configuration and injection rates. EPA recommends that descriptions of the conceptual site 

model present a clear statement and description of each element of the site, as well as any 

assumptions and hypotheses related to the proposed injection site and the reasoning behind them 

(e.g., lab experiments, empirical data, or peer-reviewed literature). The conceptual site model 

also identifies the modeling region in three dimensions. Geologic stratigraphy, any other relevant 

geologic features, all physical processes that will impact migration of carbon dioxide and ground 

water, chemical species of interest, location of USDWs and potential conduits, conditions at site 

boundaries that may inform model boundary conditions, and areas of sparse site characterization 

data are also identified in the conceptual site model. See Box 3-1 for more information about the 

conceptual site model. 
UIC Program Class VI Well Area of Review 34 

Evaluation and Corrective Action Guidance

Box 3-1. Hypothetical Example of a Conceptual Site Model

A conceptual site model describes the general features of the anticipated Class VI project, 

using one or several schematics and diagrams. EPA recommends that schematics be used to 

show the general project orientation, both at the surface and at depth, important site features, 

and known processes that will impact plume and pressure front evolution at the site. Report 

text accompanying the conceptual site model schematic describes the relevant features at the 

site. A hypothetical example conceptual site model schematic is shown in Figure 3-1, and the 

example accompanying text is below.

For this hypothetical project, three injection wells are planned to inject a total of two million 

tons of carbon dioxide per year for 30 years. The source of carbon dioxide is a coal-fired 

power plant located approximately 200 miles to the north of the injection site. The injectate 

will be supplied via pipeline to the site, delivered to a surface facility, and then supplied 

separately to each of the injection wells. The injectate will be greater than 99% pure carbon 

dioxide at all times, containing trace amounts of sulfur dioxide and nitrogen oxides. 

Figure 3-1: Hypothetical Conceptual Site Model for Geologic Sequestration. 
UIC Program Class VI Well Area of Review 35

Evaluation and Corrective Action Guidance

Box 3-1. Hypothetical Example of a Conceptual Site Model, continued

Injection will occur into a saline formation (Unit N), with a measured salinity of 50,000 mg/L, 

at a depth of approximately 1,800 meters below ground surface. The formation dips slightly, 

and carbon dioxide and pressure front movement are expected to be generally greater in the 

up-dip direction. The permeability of the injection zone has been measured to range from 1 to 

50 mD, with lower permeabilities generally at higher elevations and at the contact between 

the confining and injection zones. 

A shale unit, at least 20 meters thick throughout the vicinity, serves as the primary confining 

unit (Unit M). The depth of the lowermost USDW (Unit C) varies somewhat throughout the 

vicinity, but it is generally from 200 to 500 meters below ground surface. Intervening layers 

of sand, shale, and clay units exist between the confining layer and lowermost USDW. A 

secondary confining zone (Unit K) has been identified. 

The majority of carbon dioxide is expected to migrate upwards through the zones of higher 

permeability until encountering lower permeability zones within the injection zone, or the 

injection zone/confining zone contact, and be physically trapped. Capillary trapping, mineral 

trapping, and dissolution of carbon dioxide into ground water will also occur; however, at this 

point the rate and total amount expected to be sequestered via the different mechanisms has 

not been quantified. Currently, ground water in all subsurface formations flows generally to 

the west. It is expected that pressure increases within the injection zone induced by the project 

will cause ground water to generally flow radially away from the injection wells.

Two relevant geologic zones with a concentration of fractures are located in the vicinity of the 

project, as shown on Figure 3-1. Fractures exist primarily in Unit K, the secondary confining 

unit, but also are potentially identified in the primary confining zone, Unit M. Geologic 

studies of the fractures and preliminary modeling have indicated that due to the orientation 

and fracture widths, they will not serve as a leakage pathway during carbon dioxide injection. 

However, these two relevant geologic zones will likely be locations for enhanced monitoring 

during the lifetime of the project, based on consultation with the UIC Program Director. 

A former oil and gas field is located to the northeast of the project. Further analysis, including 

modeling, is used to determine if carbon dioxide may migrate into this area. If migration is 

detected, enhanced corrective action and monitoring will occur within the area of the former 

oil and gas field in consultation with the UIC Program Director. A fault zone exists far to the 

east of the proposed site. Carbon dioxide is not expected to migrate as far as the fault zone. 

However, this feature may also be further evaluated over the course of project, along with the 

potential for brine migration through the fault zone as a result of pressure buildup in the 

formation. 
UIC Program Class VI Well Area of Review 36

Evaluation and Corrective Action Guidance

3.3.2. Determination of Physical Processes to be Included in the Computational 

Model

Prior to developing the computational model for a proposed Class VI injection well AoR 

delineation, the owner or operator will need to determine what physical processes will be 

considered in the computational model. This determination is based on the most significant 

processes identified in the conceptual model, as well as those processes that can be realistically 

included in the computational model. At a minimum, the Class VI Rule requires that the model 

include multiphase flow of carbon dioxide and formation fluids [40 CFR 146.84(a) and (c)(1)]. 

Additional processes may be necessary for certain projects. For example, reactive transport could 

be relevant if permeability and/or porosity are predicted, based on previous testing, to change as 

a result of precipitation/dissolution reactions. In addition, geomechanical processes could be 

relevant if pressure and stress may change hydrogeologic properties. If the aqueous carbon 

dioxide plume is a potential risk factor, carbon dioxide dissolution into ground water may also be 

considered in the AoR delineation model. 

For some model applications, including reactive transport and geomechanical processes may be 

impractical. Complications can arise from increases in computational demands (i.e., extremely 

long computer processing times), lack of meaningful data on mineral precipitation/dissolution 

kinetics, or the inability of preferred computational code. Furthermore, including these processes 

may be unnecessary in many cases because the impact on plume and pressure front migration 

may be relatively minor. The Class VI Rule does not require including reactive transport and 

geomechanical processes in the AoR delineation modeling. However, the UIC Program Director 

may request that the owner or operator include these additional processes in AoR delineation 

modeling in cases where doing so would improve the understanding of plume and pressure 

migration for the project.

3.3.3. Computational Model Design 

After a conceptual site model has been developed, and the processes that will be considered have 

been determined, the next step is to develop the site computational model. This includes the 

determination of an appropriate computational code, and parameterization (i.e., populating the 

code with the selected site-specific parameters) in order to develop the model.

3.3.3.1. Computational Code Determination 

To create the computational model, EPA recommends that a code be used that includes routines 

for the relevant physical processes at the site based on peer-reviewed theory and equations, 

including equations of state for carbon dioxide and other chemical species of interest. EPA 

recommends that the code also include accurate mass-transfer coefficients, including solubility 

of carbon dioxide, as a function of primary thermodynamic variables (e.g., temperature, pressure, 

phase saturations). If using an independently developed or untested code, EPA also recommends 

that the developer model test cases found in the literature to verify the accuracy of the model 

before submitting the Class VI injection well permit application to the UIC Program Director 

(e.g., see Pruess et al., 2004). 
UIC Program Class VI Well Area of Review 37

Evaluation and Corrective Action Guidance

3.3.3.2. Model Spatial Extent, Discretization, and Boundary 

Conditions

The computational model will be designed by determining the spatial boundaries of the problem 

and spatial discretization. It is recommended that lateral grid spacing be fine enough to resolve 

heterogeneities, as discussed above (e.g., Doughty and Pruess, 2004). Vertically, the model is 

recommended to include the injection zone, with sufficient vertical resolution to properly 

account for buoyant plume migration, and a sufficient section of the primary confining zone to 

demonstrate to the satisfaction of the UIC Program Director that no leakage is expected to occur 

through the confining zone. In some cases, the UIC Program Director may require that additional 

zones be included in the computational model, such as overlying USDWs. Inclusion of 

additional zones may allow for estimation of vertical leakage rates and pressure changes above 

the primary confining zone, which may aid in performing risk assessments and designing the 

Class VI testing and monitoring program. 

Boundary conditions are typically based on hydrogeologic conditions in locations corresponding 

to the edges of the model domain where the domain extends beyond the pressure front and/or 

plume. Model testing may be conducted to ensure that grid spacing, gridding routine, and 

boundary conditions do not result in numerical artifacts that impact the model results. If results 

of such testing indicate artificial impacts, then adjustment of the model may be necessary prior to 

running the model for a proposed Class VI injection well AoR delineation. 

3.3.3.3. Model Timeframe

The Class VI Rule requires that the model used to delineate the AoR for a proposed Class VI 

injection well be run from the commencement of injection activities until the plume movement 

ceases, until pressure differentials sufficient to cause the movement of injected fluids or 

formation fluids into a USDW are no longer present, or until the end of a fixed time period as 

determined by the UIC Program Director [40 CFR 146.84(c)(1)]. In order to meet these 

conditions, it may be necessary for the model simulation of the GS project to extend for several 

hundred or thousands of years (e.g., Flett et al., 2007). 

3.3.3.4. Parameterization

Parameterization is the final step in the initial development of the computational model, and it 

consists of populating the computational code with the selected site-specific parameters. Key 

parameters include formation intrinsic permeability, porosity, phase-partitioning coefficients, 

and relative permeability-saturation parameters. Parameter values are based on the site-specific 

data as much as possible, but may also be based on values and relationships from the scientific 

literature. Geostatistical techniques can also be used to create a representation of realistic, threedimensionally heterogeneous conditions in the subsurface. See Section 2.2 of this guidance for 

more information on model parameters. In some cases, a reasonable range of parameter values 

may be identified for the purposes of later sensitivity analyses.
UIC Program Class VI Well Area of Review 38

Evaluation and Corrective Action Guidance

3.3.4. Executing the Computational Model

The computational model is executed (i.e., solved) after parameterization, and this consists of 

using the code to calculate phase saturations and composition, fluid pressures, and other system 

aspects within the model domain for each point in time and space separated by specified 

intervals (i.e., time step, grid spacing). Model results are typically text files that contain modeled 

data for each grid cell, during each time step. In some cases, the model results will need to be

post-processed following execution of the model before they can be easily visualized and 

interpreted. For example, model results may need to be transformed to produce site coordinates.

Model results of particular interest for Class VI injection well AoR delineation include 

estimation of the extent of the separate-phase carbon dioxide plume migration and changes in 

fluid pressures within the injection zone over time. See Section 3.4 for more information on AoR 

delineation. 

The use of an a priori AoR delineation based on computational modeling predictions highlights 

the need for uncertainty and sensitivity analyses for the initial prediction. Conservative 

predictions will be needed prior to the commencement of injection and the availability of any 

site-specific data on carbon dioxide migration paths and rates. EPA recommends conducting 

sensitivity analyses as the principal evaluation tool for characterizing the most and least 

important sources of error in computational models (USEPA, 2003). Based on these results, 

maximum-risk scenario simulations can be conducted considering plume extent and pressure 

perturbation predictions that account for uncertainties in the model. 

3.4. AoR Delineation Based on Model Results

The planned or predicted AoR submitted with the permit application for a proposed Class VI 

injection well is required to be based on a delineation of the area where the GS project may cause 

endangerment of USDWs, which in turn is required to be based on the results of computational 

modeling [40 CFR 146.84(a) and 40 CFR 146.84(c)(1)]. The boundaries of the AoR are based on 

simulated predictions of the extent of the separate-phase (i.e., supercritical, liquid, or gaseous) 

plume and pressure front. As such, EPA recommends that the AoR encompass the maximum 

extent of the separate-phase plume or pressure front over the lifetime of the project and entire 

timeframe of the model simulations. The pressure front, as described below, is the extent of 

pressure increase of sufficient magnitude to force fluids from the injection zone into the 

formation matrix of a USDW. 

In the case of GS projects with multiple Class VI injection wells, the owner or operator must 

apply for and obtain a Class VI injection well permit for each individual well [40 CFR 

144.33(a)(5)]. However, as discussed previously, a single AoR modeling exercise may be 

conducted for all wells within a single project at the discretion of the UIC Program Director. In 

all cases, EPA recommends that the AoR delineation boundaries for the cumulative GS project 

be based on modeling that accounts for the anticipated injection rates from all planned Class VI 

injection wells.
UIC Program Class VI Well Area of Review 39

Evaluation and Corrective Action Guidance

Box 3-2 provides a hypothetical example of an AoR delineation based on computational 

modeling results, including the calculation of the threshold pressure that defines the pressure 

front. The determination of the pressure front in Box 3-2 (Step 2) is consistent with existing 

standard practices for other well classes of the UIC Program (e.g., Thornhill et al., 1982) and is 

applicable to any Class VI injection well for which, prior to injection, the injection zone is underpressurized compared to the lowermost USDW (i.e., Method 1, Section 3.4.1). Determination of 

the pressure front is discussed in more detail in Section 3.4.1. 

3.4.1. Determination of Threshold Pressure Front

The pressure front may be defined as the minimum pressure within the injection zone necessary 

to cause fluid flow from the injection zone into the formation matrix of the USDW through a 

hypothetical conduit (i.e., artificial penetration) that is perforated in both intervals. Several 

methods, as described below, are available to estimate the value of the pressure front, and are 

based on various assumptions. The owner or operator is encouraged to consult with the UIC 

Program Director to determine which method is appropriate for the proposed GS project. For 

instance, if an existing aquifer exemption is proposed to be expanded for a GS project, the 

pressure front may be determined based upon the pressure increase necessary for formation 

fluids to be displaced into portions of aquifer that are not exempted. 

Method 1. Pressure front based on bringing injection zone and USDW to equivalent hydraulic 

heads (applicable to under-pressurized case only). 

As stated by Thornhill et al. (1982), the pressure-front component of the AoR is “the area around 

an injection well where, during injection, the [hydraulic] head of the formation fluid in the 

injection zone is equal to or greater than the [hydraulic] head of USDWs.” Defined this way, the 

pressure-front (Pi,f) may be calculated by the following equation:

Pi,f = Pu + ρig ∙ (zu − zi) [Eq-1] 

where Pu is the initial fluid pressure in the USDW, ρi is the injection-zone fluid density, g is the 

acceleration due to gravity, zu is the representative elevation of the USDW, and zi is the 

representative elevation of the injection zone. Similarly, the increase in pressure that may be 

sustained in the injection zone (ΔPi,f) is given by: 

∆Pif = Pu + ρig ∙ (zu − zi) − Pi [Eq-2] 

where Pi is the initial pressure in the injection zone. Eq-1 and Eq-2 are subject to the assumption 

that the hypothetical open borehole is perforated exclusively within the injection zone and 

USDW. 

A positive value of ΔPi,f (Eq-2) corresponds to an injection reservoir that is under-pressurized 

relative to the USDW and can accommodate an increase in pressure equal to ΔPi,f prior to 

potential fluid migration into the drinking water reservoir. A ΔPi,f value of zero corresponds to 

the hydrostatic case, and a negative value of ΔPi,f relates to a situation where the injection zone is 
UIC Program Class VI Well Area of Review 40

Evaluation and Corrective Action Guidance

already over-pressurized and thus subject to potential fluid leakage from the injection reservoir 

to the drinking water aquifer even prior to the planned GS project. Eq-1 and Eq-2 are only 

applicable for calculating the allowable pressure increase for the under-pressurized case (i.e., 

positive value of ΔPi,f). Alternative methods may be applicable for the hydrostatic case or overpressurized cases (see below). 

EPA recommends that Eq-1 and Eq-2 be applied using values of pressure and fluid density (i.e., 

Pu, Pi, and ρi) based on direct measurement of fluid properties in the direct vicinity of the 

proposed project (i.e., see the UIC Program Class VI Well Site Characterization Guidance).

Notably, the results of Eq-1 and Eq-2 are sensitive to the injection-zone fluid density (ρi), which 

is influenced by the pressure, temperature, and salinity of the injection zone. Salinity, pressure, 

and temperature tend to increase with depth below the ground surface. If site-specific fluid 

density values at reservoir conditions are not available, injection zone fluid density may be 

estimated based on measured salinity, temperature, and pressure. Figure 3-2 presents fluid 

density as a function of depth below ground surface for several different salinities, based on the 

method of Peng and Robinson (1976). 

Figure 3-2: Fluid Density Functions for Varying Salinities.

Note also that, in using this method, Pi,f is a function of the fluid density of the injection zone, 

the elevation of both formations, and the fluid pressure within the USDW. To the extent that 

these parameters vary spatially in the vicinity of the project, the value of Pi,f may also vary 

throughout the region of the AoR. 
UIC Program Class VI Well Area of Review 41

Evaluation and Corrective Action Guidance

Method 2. Pressure front based on displacing fluid initially present in the borehole (applicable 

to hydrostatic case only). 

Under hydrostatic conditions, a pressure increase within the injection zone may be allowable due 

to the fact that water entering a hypothetical borehole from the injection zone will be more dense 

than the fluid initially present in that borehole. Fluid from the injection zone will displace the 

fluid in the borehole, which will flow into the USDW. However, below a calculated threshold 

pressure, a new pressure equilibrium will be established, and fluid from the injection zone will 

not intrude into the USDW.

As given by Nicot et al. (2008) and Bandilla et al. (2012), assuming (1) hydrostatic conditions 

and (2) initially linearly varying densities in the borehole and constant density once the injectionzone fluid is lifted to the top of the borehole (i.e., uniform density approach), the threshold 

pressure increase (ΔPc) may be calculated:

∆Pc = 1

2 ∙ g ∙ ξ ∙ (zu − zi)2 [Eq-3] 

where ξ is a linear coefficient defined by: 

ξ = ρi−ρu

zu−zi

[Eq-4] 

and where ρu is the fluid density of the USDW. 

Nicot et al. (2008) also present a solution subject to the assumption of linearly varying densities 

in the borehole both initially and when the injection zone fluid is lifted to the top of the borehole 

(i.e., equilibrium approach), rather than the uniform density approach (assumption #2) used to 

derive Eq-3 (see Nicot, 2008 and Bandilla, 2012). Birkholzer et al. (2011) state that the value of 

ΔPc calculated using the uniform density approach (Eq-3) may be less precise than the 

equilibrium approach, but it is easier to apply and also more conservative for protection of the 

USDW. 

At pressure increase less than ΔPc, the fluid originally present in the borehole will leak into the 

USDW. This fluid leakage from the borehole may be acceptable and not cause degradation of 

water quality within the USDW, as the volume of water in the borehole may be minor and 

quickly diluted by water in the surrounding aquifer. 

Calculation of the allowable threshold pressure increase using these methods (Eq-3 and Eq-4) is

applicable only to the hydrostatic case. In some instances, site-specific fluid pressure and density 

measurements may not be available at the time of preparing the permit application and initial 

AoR delineation in order to evaluate if the injection reservoir is over- or under-pressurized. If 

warranted by previous site knowledge (i.e., no previous large-scale fluid withdrawal or injection 

from the injection zone), it may be acceptable to initially assume hydrostatic conditions. The 

owner or operator may choose to use these methods (Eq-3 and Eq-4) for an initial estimate of the 
UIC Program Class VI Well Area of Review 42

Evaluation and Corrective Action Guidance

threshold pressure allowable for delineation of the AoR. However, once site-specific data are 

available for the proposed injection zone following construction of injection or monitoring wells, 

EPA recommends reevaluation of the hydrostatic assumption. If the reservoir is underpressurized, the allowable threshold pressure increase may be greater than calculated using Eq-3 

(see Method 1, above). However, if the injection reservoir is actually over-pressurized, the 

allowable pressure increase will be less than calculated using Eq-3. 

Methods for over-pressurized cases.

In some instances, the desired injection zone may already be over-pressurized relative to the 

USDW prior to the injection project (i.e., ΔPi,f value is negative using Eq-2). In this situation, 

fluid leakage would occur from the injection zone to the USDW through a borehole perforated 

within both zones even prior to commencing injection. Additional pressure increase within the 

injection zone owing to the injection associated with the GS project may increase fluid leakage 

rates. Determination of the allowable pressure increase to be used in AoR delineation for the 

over-pressurized case may require more sophisticated methods than the analytical equations 

described above for Methods 1 and 2. 

Possible methods to estimate an acceptable pressure increase for over-pressurized reservoirs 

include: 

1. Using similar methods as described in Nicot et al. (2008), some over-pressurization 

within the injection zone may be allowable without causing sustained fluid leakage, 

owing to the density differential between the injection zone and USDW. If the value of 

ΔPc using Eq-3 is greater than the absolute value of ΔPi,f using Eq-2, the difference in 

magnitude between the two may be used as an estimate of the allowable pressure 

increase, subject to the assumptions used to derive Eq-3 (see Method 2, above). To date, 

peer-reviewed research papers on this topic have developed analytical solutions only for 

the hydrostatic case. Future publications may address the initially over-pressurized case 

and, if so, these methods may be used to calculate an allowable pressure increase in an 

over-pressurized reservoir. 

2. A multiphase numerical model may be designed to model leakage through a single well 

bore, or through multiple well bores in the formation (see e.g., Birkholzer et al., 2011). 

Additional pressure increases up to a certain point within an already over-pressurized 

injection zone may not cause an appreciable increase in fluid leakage rates through a 

hypothetical borehole. A sensitivity analysis may be conducted to bound the modeled 

leakage rates.

3. In conjunction with item #2 above, numerical or analytic ground water modeling may be 

conducted for the USDW to estimate how additional fluid leakage caused by the injection 

project is diluted within the USDW and attenuated. Dilution of fluid leakage from a 

borehole is impacted by the natural background flow rate of water within the USDW, 

which is turn a function of the hydraulic gradient, aquifer thickness, and hydraulic 

conductivity. An additional pressure increase may be allowable if it can be demonstrated 
UIC Program Class VI Well Area of Review 43

Evaluation and Corrective Action Guidance

to the UIC Program Director that negligible degradation of the USDW would result from 

increased fluid leakage rates. 

Box 3-2. Hypothetical Example of an AoR Delineation

The AoR is based on the results of computational modeling and encompasses the predicted 

maximum extent of the separate-phase plume or pressure front over the lifetime of the project. 

The pressure front is defined as the pressure, within the injection zone, great enough to force 

fluids from within the injection zone through a hypothetical open conduit into any overlying 

USDW. This box provides a hypothetical example of an AoR delineation using a stepwise 

approach. The example scenario is based on the conceptual site model described above (see 

Box 3-1). First, the threshold pressure that defines the pressure front is determined. Next, 

maps showing the maximum extent of the plume and pressure front are overlaid and the AoR 

is delineated.

Step 1. Determine the Pressure Front 

A cross-sectional schematic of the hypothetical scenario is shown in Figure 3-3, which also 

presents values for fluid density, and pressure (units of megapascals, MPa, equal to 1·106 Pa) 

for each formation. 

Figure 3-3: Hypothetical Geologic Sequestration Site: Cross Sectional Schematic and Calculations. 
UIC Program Class VI Well Area of Review 44

Evaluation and Corrective Action Guidance

Box 3-2. Hypothetical Example of an AoR Delineation, continued

The methodology used here is consistent with the determination of the pressure front for other 

well classes within the UIC Program (e.g., USEPA, 2002). As explained above, in Section 3.4 

of this guidance, this methodology is applicable to any proposed Class VI injection well for 

which, prior to injection, the injection zone is not over-pressurized compared to the 

lowermost USDW (i.e., the injection zone has a lower or equal hydraulic head as compared to 

the lowermost USDW).

The pressure front is determined by calculating the minimum pressure within the injection 

zone (Pi,f) necessary to cause fluid flow from the injection zone into the formation matrix of 

the USDW through a hypothetical conduit (i.e., artificial penetration) that is perforated in 

both intervals. Pi,f is calculated using Eq-1 (Section 3.4.1). In this example, Pi,f is 14.6 MPa. 

Step 2. Inspect Model Results to Determine the Maximum Extent of the Pressure Front (Pf) 

The computational model will provide a prediction of the pressures within the injection zone 

over time. For the purpose of AoR delineation, EPA recommends using the pressure 

distribution corresponding to the time of maximum lateral extent of the pressure front (Pi,f). 

This will likely correspond to a time of maximum injection rates during the operational phase 

of the project or to the end of a long injection period. 

EPA recommends contouring these predictions of pressure increase and providing the 

predictions on a base map of the proposed project area (Figure 3-4). In this recommended 

contour map, EPA also recommends highlighting the pressure equivalent to Pi,f. In the 

hypothetical example provided here, the region encompassed by Pi,f includes the three 

planned Class VI injection well locations and a significant distance surrounding the area of 

the proposed injection wells. 
UIC Program Class VI Well Area of Review 45

Evaluation and Corrective Action Guidance

Box 3-2. Hypothetical Example of an AoR Delineation, continued

Figure 3-4: Hypothetical Geologic Sequestration Site: Model Predicted Maximum Pressure Within the 

Injection Zone. 

Step 3. Inspect Model Results to Determine the Maximum Extent of the Separate-Phase 

Plume

The computational model will also provide a prediction of the extent of the separate-phase 

plume as it evolves over time. EPA recommends that these data be also contoured and 

provided on a base map (Figure 3-5). In the example provided here, the maximum extent of 

the supercritical plume, as predicted by the model, exists at 50 years after carbon dioxide 

injection commences.
UIC Program Class VI Well Area of Review 46

Evaluation and Corrective Action Guidance

Box 3-2. Hypothetical Example of an AoR Delineation, continued

Figure 3-5: Hypothetical Geologic Sequestration Site: Model Predicted Extent of Supercritical Carbon 

Dioxide Plume Over Time. 

Step 4. Delineate the AoR

Lastly, the maximum extent of the separate-phase plume and pressure front is compared and 

overlaid on the base map (see Figure 3-6). The AoR is delineated by drawing the contour line 

that encompasses the maximum extent of the separate-phase plume or pressure front (Figure 

3-6).
UIC Program Class VI Well Area of Review 47

Evaluation and Corrective Action Guidance

Box 3-2. Hypothetical Example of an AoR Delineation, continued

It is important to note that the region encompassed by the pressure front will not in all cases 

be larger in all directions than the extent of the separate-phase plume. This is because the 

pressure front does not include all areas exhibiting any increase in pressure, only pressure 

great enough to cause fluid movement into a USDW. Therefore, pressure differentials may 

still exist outside of the pressure front, and separate-phase fluids may migrate beyond the 

extent of the pressure front. For this reason, it is necessary to calculate the extent of both the 

plume and pressure front to delineate the AoR for a proposed Class VI injection well and to 

submit these separate delineation results to the UIC Program Director with the permit 

application. 

Figure 3-6: Hypothetical Geologic Sequestration Site: Initial Area of Review Based on Model Results. 
UIC Program Class VI Well Area of Review 48

Evaluation and Corrective Action Guidance

3.5. Reporting AoR Delineation Results to the UIC Program Director 

The owner or operator is required to submit the AoR and Corrective Action Plan with the initial 

permit application [40 CFR 146.82(a)(13)]. Information pertaining to how this plan should be 

submitted is provided in the UIC Program Class VI Well Project Plan Development Guidance. 

The final delineated AoR based on computational modeling is submitted to the UIC Program 

Director prior to receiving authorization to inject [40 CFR 146.82(c)(1)]. 

EPA recommends that this permit application submittal include all necessary information for the 

UIC Program Director to evaluate the AoR delineation results and replicate the computational 

modeling exercise if he or she elects to do so, as well as all model input and output data and files. 

This may include providing inputs for the UIC Program Director to use in their verification 

modeling effort. The owner or operator and the UIC Program Director should discuss the 

specific needs as the permit application is submitted. For additional information on submitting 

information to support Class VI permit applications, please see the UIC Program Class VI Well 

Recordkeeping, Reporting, and Data Management Guidance for Owners and Operators.

EPA recommends that the permit application submittal include the following in support of the 

AoR delineation: 

 The conceptual site model and all supporting data on which the model is based, including 

the description of geologic stratigraphy and any relevant geologic features. See Box 3-1 

of this guidance document for more information; 

 Attributes of the code used to create the computational model, including the code name, 

name of developing organization, a full accounting of or reference to the model 

governing equations, scientific basis, and any simplifying assumptions; 

 A description of the model domain, i.e., the model’s lateral and vertical extents, geologic 

layer thickness, and grid cell sizes, as presented on maps and cross-sections; 

 An accounting of all equations of state used for all fluids modeled (e.g. ground water, 

carbon dioxide); 

 Any constitutive relationships, such as relative-permeability saturation relationships, and 

how they were determined; 

 Values of all model parameters, as detailed in Table 2-1 of this guidance document, 

throughout the entire model domain, as a function of time if necessary, including initial 

conditions and boundary conditions, and a description of how model parameters were 

determined based on site characterization data. This information may be submitted in 

tabular or graphical/map formats; 

 If required by the UIC Program Director, the owner or operator must also include raw 

model input and output files [40 CFR 146.82(a)(21)]. These files may be useful in model 
UIC Program Class VI Well Area of Review 49

Evaluation and Corrective Action Guidance

verification, or if the UIC Program Director wishes to run alternative 

simulations/scenarios with the model;

 Model results, including predictions of carbon dioxide and pressure-front migration over 

the lifetime of the project. EPA recommends that the model results be presented in the 

form of contour maps, cross sections, and/or graphs showing plume and pressure front 

migration as a function of time, and that the permit application submittal include the 

outcome of parameter sensitivity analyses; 

 A description of pressure front calculation and delineation of the AoR; and 

 If required by the UIC Program Director, the relevant qualifications and professional 

experience of any individuals and/or consulting firms responsible for model 

development, AoR delineation, and reevaluation, including examples of previous 

multiphase modeling studies conducted. 
UIC Program Class VI Well Area of Review 50

Evaluation and Corrective Action Guidance

4. Identifying Artificial Penetrations and Performing Corrective 

Action 

The purpose of AoR delineation for a proposed GS project is to determine the area where any 

geologic features or artificial penetrations (e.g., wells) may become conduits for fluid movement 

out of the injection zone, or additional zones, and potentially cause endangerment to a USDW.

Artificial penetrations include any man-made structures, such as wells or mines, which provide a 

flow path out of the injection zone. The Class VI Rule requires that the owner or operator 

prepare, maintain, and implement a AoR and Corrective Action Plan that includes a description 

of how corrective action will be performed on any artificial penetrations through the confining 

zone and whether such action will be phased [40 CFR 146.84(b)(2)(iv)]. 

This section discusses the identification and evaluation of artificial penetrations and the 

performance of required corrective action (if necessary). Monitoring activities necessary for 

detection of fluid leakage into USDWs are discussed in the UIC Program Class VI Well Testing 

and Monitoring Guidance. 

4.1. Rule Requirements

The following rule requirements pertain to corrective action within the AoR:

• 40 CFR 146.84(c)(2): Using methods approved by the UIC Program Director, identify all 

penetrations, including active and abandoned wells and underground mines, in the AoR 

that may penetrate the confining zone(s). Provide a description of each well’s type, 

construction, date drilled, location, depth, record of plugging and/ or completion, and any 

additional information the UIC Program Director may require;

• 40 CFR 146.84(c)(3): Determine which abandoned wells in the AoR have been plugged 

in a manner that prevents the movement of carbon dioxide or other fluids that may 

endanger USDWs, including use of materials compatible with the carbon dioxide stream; 

• 40 CFR 146.84(d): Perform corrective action on all wells in the AoR that are determined 

to need corrective action, using methods designed to prevent the movement of fluid into 

or between USDWs, including use of materials compatible with the carbon dioxide 

stream, where appropriate;

• 40 CFR 146.84(e)(2): During the AoR reevaluation process, identify all wells in the 

reevaluated AoR that require corrective action in the same manner specified in 40 CFR 

146.84(c);

• 40 CFR 146.84(e)(3): Perform corrective action on wells requiring corrective action in 

the reevaluated AoR in the same manner specified in 40 CFR 146.84(d); 

• 40 CFR 146.84(e)(4): Revise the AoR and Corrective Action Plan as necessary whenever 

the AoR is reevaluated.
UIC Program Class VI Well Area of Review 51

Evaluation and Corrective Action Guidance

4.2. Identifying Artificial Penetrations within the AoR 

The Class VI Rule requires potential Class VI injection well owners or operators to identify all 

artificial penetrations located within the delineated AoR, including active and abandoned wells 

and underground mines, that may penetrate the confining zone, and provide a description of each 

well’s type, construction, date drilled, location, depth, and if applicable, the record of plugging 

and/or completion, and any additional information the UIC Program Director may require [40 

CFR 146.84(c)(2)]. If the identified abandoned wells have been improperly plugged or not 

plugged at all, such penetrations can provide unimpeded flow conduits out of the injection zone. 

As such, they must be properly plugged in order to prevent endangerment of USDWs [40 CFR 

146.84(d)].

A variety of types of abandoned wells may exist within the delineated AoR of a proposed GS 

project, including wells constructed prior to federal or state regulation (i.e., in the late 1800s or 

early 1900s) and any recently decommissioned wells. Wells constructed during early oil 

exploration, including cable-tool drilled wells, pose the largest risk because these wells may be 

relatively deep and often consist of an open (i.e., non-cased) well bore over much of their length. 

These older wells may also not have been documented in state or local records. 

Historically, wells no longer in use may not have been plugged and abandoned by today’s 

common standards. Prior to the early 1900s, there were no regulations concerning well 

abandonment and it is unlikely that those wells were abandoned properly. Even in states 

regulating well abandonment, it is likely that any wells abandoned before 1952 may have 

inadequate plugs (Ide et al., 2006). In 1952, the American Petroleum Institute (API) published its 

standards for cements for oil and gas wells. Prior to that, cement often lacked sufficient additives 

to achieve the proper cement setting in the conditions experienced in oil and gas wells. As a 

result, the plugs in many of these older wells failed to set properly and may have experienced 

channeling and/or cement failure because of fluid intrusion into the improperly set cement. 

The potential also exists for more recently constructed wells to have been decommissioned 

improperly. For example, owners or operators may have gone bankrupt and failed to plug their 

wells or used substandard materials. 

Depending on site conditions and corrosion, “properly” plugged wells may also contain zones 

(i.e., annular spaces) that could serve as a conduit for fluid movement. In other cases, the well 

plugs may have degraded over time because of a poor cement job and/or corrosive conditions. 

Even properly plugged wells may have been plugged with types of cement that could degrade 

when in contact with a carbon dioxide plume. See the UIC Program Class VI Well Construction 

Guidance for information on compatibility of different materials with a carbon dioxide stream.

Detecting abandoned wells can be very challenging in certain locations because of the variety of 

wells that may exist. In addition, steel casings, the primary detectable portion of the well, were 

often removed from abandoned wells for recycling and use during World War II (Gochioco and 

Ruev, 2006). These challenges are compounded by the potentially large AoR delineation 

determined for a proposed Class VI injection project, and therefore the greater surface area that 

will have to be evaluated for the presence of artificial penetrations. However, as discussed 
UIC Program Class VI Well Area of Review 52

Evaluation and Corrective Action Guidance

below, several methods and sources of information are available to identify those artificial 

penetrations in a relatively efficient manner. The primary stages of an abandoned well 

investigation within the AoR include historical research, site reconnaissance, review of aerial and 

satellite imagery, and one or more geophysical surveys. The reader is referred to additional 

standard references regarding identification of artificial penetrations for further information 

(Jordan and Hare, 2002; Frischknecht et al., 1985; ASTM, 2005). 

4.2.1. Historical Research

Most deep wells that may penetrate the primary confining zone of a proposed GS project site are 

related to oil and gas exploration and production. Deep well drilling for oil and gas exploration 

dates back to the 1870s. State and local databases of well exploration may include locations of 

abandoned wells, and EPA recommends conducting a records review as the first step in 

abandoned well identification within the delineated AoR for a proposed Class VI injection well. 

In addition, state and local records will provide information on the time period and types of 

exploration that have been conducted in an area, and they may also provide information on 

typical completion and abandonment methods in a given field. This records search will provide a 

list of known abandoned wells, and it may inform additional stages of abandoned well 

identification. 

State well databases will, in most cases, provide valuable information for assistance with the 

identification of abandoned wells. Prior to well construction, a government permitting authority 

requires owners or operators to seek a permit to drill from a specific agency, such as a state

natural resources agency, environmental quality agency, or geological survey. Most states 

maintain records of drilled wells, including location, construction, operating, and plugging 

information. Although these records can take many forms, many states now have comprehensive 

databases of these well records that have been digitized and made available online. However, 

when conducting this historical records search, owners or operators of proposed Class VI 

injection wells should be aware that older well records may not have been entered into databases. 

In some cases, the records from different time periods may be filed in separate locations or on 

separate types of media. 

For example, the Wyoming Oil and Gas Conservation Commission maintains a digital database, 

accessible online, of wells within the state. (See http://wogcc.state.wy.us for more information 

on this database.) Basic information is available to the public regarding each well, including 

geophysical survey results where available. The database can be searched by location, well 

name, and well number, among other fields. The state also has a “well book” available online, 

which contains records of older wells not entered in the database. 

In addition, county records, including survey maps, ownership records, and chain-of-title and 

property lease history, maintained by local tax assessors and county clerks, list abandoned wells 

in many cases. Such records may also indicate land use and indicate areas and timeframes in 

which drilling activities likely occurred. Private data compilation services often maintain detailed 

databases for the purpose of oil and gas exploration, including information regarding well 

locations, plugging, and abandonment. Often these services will maintain maps of known well 
UIC Program Class VI Well Area of Review 53

Evaluation and Corrective Action Guidance

locations. While these maps can be out of date, most private services have been known to update 

their database for a fee. 

4.2.2. Site Reconnaissance

Site reconnaissance includes interviewing local residents and property owners, as well as 

conducting a physical search for features indicative of abandoned wells. Initial site 

reconnaissance may be informed by the historical database research. For example, the records 

search may indicate that, with a great deal of confidence, certain regions of the AoR have never 

been subject to oil and gas exploration, deep well injection, or any other activity that may result 

in deep well penetration. In this case, the owners or operators may choose to exclude those areas 

from any additional well identification efforts. 

Local residents that may be well informed regarding abandoned wells include oilfield workers 

and service company employees, including consultants, and property and drilling-rights 

ownership brokers. Such informed residents may be able to provide information on the areas and 

timeframes where past drilling occurred. They may also be able to give additional details in 

response to specific questions and provide information on locations, completion methods, and 

plugging of wells. 

Surface features that may be indicative of abandoned wells include abandoned well derricks, 

access roads, brine pits, or vegetation stress associated with brine leakage. Detection of these 

features at a site indicates the possible likelihood of one or more wells in the area. EPA 

recommends that, because the AoR is likely to cover a large area, a surface review for such 

features is most effectively supplemented by use of aerial surveys or photos. 

4.2.3. Aerial and Satellite Imagery Review

EPA recommends that historical aerial photographs and satellite imagery be used in the 

identification of abandoned wells. Aerial photographic surveys, taken from airplanes, were 

conducted beginning in the 1930s and are available from a variety of governmental and private 

information services. All historical aerial photos within the AoR are recommended to be 

reviewed for evidence of past drilling activity. Surface features that provide a “signature” of 

drilling activity include drill derricks, rig platforms, brine pits, power sources, and access roads. 

Depending on the resolution of the image, satellite (i.e., remote sensing) images may be used to 

detect wellheads, derricks, and surface features indicative of abandoned wells. These include 

spatial patterns indicative of a well site, brine pits, modified topography, and vegetation stress 

associated with brine leakage. 

4.2.4. Geophysical Surveys 

Geophysical surveys, including magnetic, ground penetrating radar (GPR), and electromagnetic 

methods, can be used in the detection of abandoned wells. EPA recommends conducting 

geophysical surveys throughout regions of the AoR that may have been subject to oil and gas 
UIC Program Class VI Well Area of Review 54

Evaluation and Corrective Action Guidance

exploration, deep well injection, or any other activity that may result in deep well penetration.

Geophysical methods will supplement other identification methods, discussed above. 

Geophysical methods can help to pinpoint locations of known wells where surface evidence of 

the well has been removed or can help to identify abandoned wells that are undocumented. The 

type(s) of geophysical surveys conducted at a proposed Class VI injection well site are based on 

known site subsurface and surface conditions. In general, at least two different types of 

geophysical surveys are recommended in order to parse data background noise and to inform the 

interpretation of survey results. As discussed below, ground or aerial (e.g., aeromagnetic) 

surveys may be conducted, depending on the size of the area of interest. 

4.2.4.1. Magnetic Methods

The magnetic method is one of the oldest and most well developed geophysical techniques, and 

it is the standard method used for abandoned well detection. Magnetic surveys measure a 

component of the magnetic field near the land surface. Any anomalies in the magnetic field are 

caused by subsurface features, which could include abandoned well bores with iron or steel 

casings. Anomalies associated with well casings are typically distinguishable from the 

background magnetic field. 

Magnetic surveys are applicable to abandoned wells with iron or steel casings or to wellheads in 

areas with relatively low background magnetic signatures. Areas with significant cultural 

development on the surface or in the shallow subsurface may have high interferences. Airborne 

magnetic surveys can detect most wells constructed with approximately 200 feet or more of at 

least 8-inch casing, and in some cases, very large cavities (Frischknecht et al., 1985). However, 

open well bores, non-steel casings, or severely corroded casings cannot typically be detected 

with a magnetic survey. 

Ground or aerial (i.e., aeromagnetic) surveys may be conducted, depending on the size of the 

area of interest. Aeromagnetic surveys will likely be more practical for most GS projects due to 

the anticipated size of the delineated AoR, as they can collect large amounts of data in a 

relatively short amount of time. Both ground and aerial surveys are conducted along straight-line 

transects. EPA recommends that that ground survey transect spacing be no larger than 20–30 

feet, and aerial survey transect spacing be no larger than 50–100 feet (Jordan and Hare, 2002). 

Magnetic surveys may be conducted to measure the total magnetic field, or the vertical or 

horizontal field gradients. For the purpose of locating abandoned well bores, the total magnetic 

field measurement type is recommended. During these surveys, EPA recommends that the 

operator periodically return to a common point to ensure instrument repeatability, continuously 

measure diurnal variation in the magnetic field, and avoid high magnetic gradients. Data 

processing of magnetic surveys includes incorporation of spatial positioning data, correction for 

diurnal variation, and data filtering. 

Figure 4-1 compares aeromagnetic survey results for the Coon Creek oil field in Oklahoma to 

abandoned wells identified from aerial imagery (USGS, 1995). As shown in the figure, magnetic 

anomalies associated with well casings are typically apparent. However, this figure also reveals 
UIC Program Class VI Well Area of Review 55

Evaluation and Corrective Action Guidance

some of the typical challenges that may be faced by owners or operators in abandoned well bore 

identification. One challenge is that, due to the presence of other buried infrastructure (e.g., 

pipes), certain regions exhibit larger magnetic field values even if wells are not present. 

Additionally, some wells may not be identified in the aeromagnetic survey, most likely because 

of well casing removals. These challenges demonstrate the benefits of using multiple survey 

techniques in order to properly identify abandoned wells. 

4.2.4.2.

Figure 4-1: Total Field Aeromagnetic Map, Cook Creek Oil Field, Arcadia, Oklahoma. 

From: USGS (1995).
UIC Program Class VI Well Area of Review 56

Evaluation and Corrective Action Guidance

4.2.4.3. Electromagnetic Methods

Electromagnetic methods used for abandoned well bore detection include frequency-domain and 

time-domain electromagnetic surveys. These surveys consist of an electromagnetic transmitter 

that establishes an electromagnetic field measured by a receiver. Similar to magnetic surveys, 

electromagnetic surveys are non-invasive, as both the transmitter and receiver are positioned 

above the ground surface. Both surface and aerial electromagnetic surveys are possible. The 

depth at which these instruments are able to detect objects depends on the size and geometry of 

the sensor, the size and conductivity of the target, and the potential interference from other 

sources, such as fences and pipelines. Generally, object detection at depths ranging from a few 

meters to several hundred meters is possible. Larger and more complex arrays are required at 

greater depths. Aerial surveys are not likely able to detect small objects, such as well casings, but 

may detect brine plumes, which may indicate the presence of abandoned wells (Jordan and Hare, 

2002). 

Abandoned well bore detection using electromagnetic methods is based on the larger 

conductivity of steel casings and other well materials compared to surrounding soils and 

geologic formations. These methods may detect anomalous fluids associated with leakage from 

an abandoned well. Frequency-domain electromagnetic methods can measure current induced in 

the subsurface by the electromagnetic field established by the transmitter. Induced current 

establishes a secondary electromagnetic field detected by the receiver. The magnitude of the 

induced current is a function of subsurface conditions, including conductivity. Time-domain 

electromagnetic methods measure the decay of the secondary magnetic field created by the 

induced current, and they can be especially useful for detection of brine leakage. 

4.2.4.4. Ground Penetrating Radar

GPR may be used in abandoned well bore detection and in finding other artificial penetrations. 

Unlike other geophysical methods, GPR does not rely on the presence of a steel or iron well 

bore, so it may be able to detect open boreholes and non-metallic materials. GPR uses high 

frequency radio waves to measure the transmission of electromagnetic energy. The investigation 

depth possible depends on the frequency of the radio waves and the conductivity of the ground. 

The greater the depth, the less resolution the instrument will have. For small objects, such as well 

casings, depths are limited to a few meters (Jordan and Hare, 2002). This depth limitation may 

lessen the value of GPR in areas with large topographical changes. GPR is also slower than 

magnetic or electromagnetic methods. GPR is likely not as practical to use throughout the 

delineated AoR as an initial larger scale survey method because the distance between transect 

lines for sufficient resolution is too small. Instead, EPA recommends using GPR to determine the 

exact location of abandoned well bores within a given area that have already been identified by 

earlier, larger scale surveys. 

4.3. Assessing Identified Abandoned Wells 

After all artificial penetrations within the AoR that may penetrate the confining zone have been 

identified, the owners or operators of a proposed Class VI injection well must evaluate the 
UIC Program Class VI Well Area of Review 57

Evaluation and Corrective Action Guidance

potential for each artificial penetration to serve as a conduit for fluid movement. In particular, 

owners or operators must establish which abandoned wells in the AoR, if any, have not been 

plugged in a manner that would prevent the movement of carbon dioxide or other fluids that may 

endanger USDWs [40 CFR 146.84(c)(3)]. To prevent fluid movement, abandoned wells should 

include a cement plug through the primary confining zone, and/or across the injection 

zone/confining zone contact, with sufficient integrity to contain separate-phase carbon dioxide 

and elevated pressures. The type of plugging that is sufficient to contain carbon dioxide and 

formation fluids from the injection zone will be site specific and should be reviewed with the 

UIC Program Director. In the absence of an adequate plug across the confining zone, crossmigration may occur where fluids enter a permeable zone below the lowermost USDW and then 

migrate upward from that zone. See Figure 4-2 for more information. EPA recommends cement 

surface plugs (typically required by well abandonment regulations), and the UIC Program 

Director may require additional plugs based on site-specific circumstances.

Evaluation of the wells in the AoR requires a two-step approach. The first step is to review 

whatever records are available, as outlined in Section 4.3.1, for information relevant to proper 

plugging. The second step is to perform physical tests on wells that are suspect or for which no 

records are available.

4.3.1. Abandoned Well Plugging Records Review 

A records review can aid in reducing the number of identified wells that may need to be 

evaluated by future field testing. Records of wells that have been recently abandoned, have no 

mentions of any difficulties experienced during the abandonment procedure, are cased holes, and 

have plugs and cement situated to isolate the injection zone from other fluid containing zones 

may be used to justify reduction in the number of follow-up field investigations. If records are

incomplete or indicate that the well has not been plugged or was inadequately plugged, followup field investigations should be performed. Identified undocumented wells will have no records 

and will require field investigation in order to determine the quality of plugging, as required in 

the Class VI Rule [40 CFR 146.84(c)(3)]. The owner or operator may also choose to plug any 

questionably abandoned wells rather than go through the expense of evaluating the plugs. 

There are many elements in existing reports that can help in determining the adequacy of 

abandonment procedures for identified wells located within the AoR. Some key elements to 

review include, but are not limited to:

 Well depth and completion; 

 Well abandonment date; 

 Open hole or cased hole; 

 Location of plugs; 

 Casing and cementing records; 

 Records of mechanical integrity tests (MITs) or logs performed; and

 Well deviation.
UIC Program Class VI Well Area of Review 58

Evaluation and Corrective Action Guidance

Figure 4-2: Examples of Carbon Dioxide Leakage Through Improperly Abandoned Wells. 
UIC Program Class VI Well Area of Review 59

Evaluation and Corrective Action Guidance

The well completion depth is important in determining if the identified abandoned well may 

penetrate the proposed confining zone(s). If the well completion depth is above the confining 

zone(s), no further action would likely need to be taken. The date of abandonment may also 

provide information as to the adequacy of the abandonment procedure. Whether the well was 

abandoned with casing or as an open hole is an important consideration in determining the 

likelihood that the well might act as a conduit for fluid movement. Open holes are susceptible to 

cross-migration between aquifers. If the hole is open and there is not a proper plug located at a 

depth corresponding to the primary confining zone, fluids may migrate out of the injection zone 

and into a USDW. For cased holes, EPA recommends that integrity of the casing be evaluated. 

The location and type of plugs are also important factors, especially in open-hole wells. The plug 

locations must be reviewed in order to determine the quality of plugging, as required in the Class 

VI Rule [40 CFR 146.84(c)(3)]. For example, EPA recommends that the injection zone be 

isolated from all other formations with plugs. This may be especially important if a well was 

completed in a formation deeper than the proposed injection zone. EPA recommends that any 

length of the well in the proposed injection zone be properly isolated by means of plugs and 

casing. Mechanical plugs and cemented casing are not sufficient for the long-term isolation of 

carbon dioxide, as eventually the metal is likely to corrode and the plug will fail (Randhol et al., 

2007). Therefore, cement plugs are considered superior to mechanical plugs for preventing the 

movement of fluids into or between USDWs. EPA recommends that cement plugs be located 

across the bottom of any casings, at the base of the lowermost USDW, and that plugging fluid 

(i.e., composition, specific gravity) characteristics be considered, as drilling fluid of sufficient 

weight may resist displacement by the injectate or mobilized fluids.

The integrity of any existing casing and cement must be determined in order to assess the quality 

of well construction and plugging, as required in the Class VI Rule [40 CFR 146.84(c)(3)]. EPA 

recommends reviewing the casing and cement quality through the proposed injection zone in 

order to ensure that they are appropriate for contact with carbon dioxide, as well as reviewing 

any additional well records that may indicate unusual conditions experienced during casing and 

cementing. Events such as a loss of circulation, well bore stability problems, lack of the use of 

centralizers, and/or improper removal of drilling mud before cementing can all lead to premature 

cement or casing failure. Reviewing load calculations, if available, and comparing them to actual 

events recorded in the drilling log may give the owners or operators an indication of an underdesigned casing that may be susceptible to failure. For example, if the casing had a low axial 

loading stress and stuck pipe was experienced during casing placement, it is possible that the 

casing may have experienced damage. The materials used for the well casing and cement must 

also be assessed to see if they are compatible with carbon dioxide, in order to comply with Class 

VI Rule requirements [40 CFR 146.84(c)(3)]. See the UIC Program Class VI Well Construction 

Guidance for more information on compatibility of different materials with a carbon dioxide 

stream.

Any tests performed on the well prior to its abandonment can also be useful information. An 

MIT such as a pressure test, noise log, temperature log, or cement evaluation log can provide 

information on any known or suspected leaks. If leaks were encountered, EPA recommends 

determining if the source of the leak was found and repaired. If the leaks were not sealed, 
UIC Program Class VI Well Area of Review 60

Evaluation and Corrective Action Guidance

corrective action would be required to be taken to plug the leaks as discussed below [40 CFR 

146.84(d)]. Drilling records can yield clues as to areas that might be susceptible to failure. Mud 

logs and open-hole caliper logs can show areas of weak formations. Weak formations are 

susceptible to well bore instability and subsequent cement failure. Cement evaluation logs and 

temperature logs taken at the time of completion can also give an idea of the condition of the 

cement, although degradation is always possible after well completion. Any corrosion logs will 

help provide information on the condition of the casing. Results from mechanical caliper logs, 

electromagnetic thickness logs, or down-hole video can show the casing condition when the well 

was abandoned. For more information regarding these logs and tests, see the UIC Program Class 

VI Well Testing and Monitoring Guidance. 

Evaluation of well records for deviation during drilling may also identify wells more likely to be 

in need of corrective action, as deviated wells are far more likely to fail than wells with no 

deviation (Watson, 2009). Events such as well bore collapse during drilling or conditions that 

placed unusual loads on the casing may also indicate a higher chance of failed well bore 

integrity. EPA recommends that the design casing load also be checked to ensure adequacy for 

the actual loads faced by the well.

4.3.2. Abandoned Well Field Testing 

After all the available records have been reviewed, any wells located within the AoR that cannot 

be proven to have plugs adequate to prevent migration of carbon dioxide or formation fluids out 

of the injection zone must be evaluated by field tests in order to determine the quality of 

plugging, as required in the Class VI Rule [40 CFR 146.84(c)(3)]. Evaluation and corrective 

action for wells which the plume is not expected to reach in the near future may be phased. If the 

owner or operator chooses and the UIC Program Director agrees, the evaluation may be omitted 

and the wells re-plugged. If the integrity of the bottom plug or cement is in question, and records 

cannot prove that the plugging is adequate, EPA recommends that the surface plug and possibly 

additional plugs down-hole be drilled out and tests conducted to determine the adequacy of 

abandonment. There are numerous field tests available to evaluate the integrity of abandoned 

wells. Several of these tests are discussed in detail in the UIC Program Class VI Well Testing 

and Monitoring Guidance. Additionally, the owner or operator must demonstrate guaranteed site 

access to wells potentially needing corrective action in the future [40 CFR 146.84(b)(iv)]. The 

owner or operator is encouraged to consult the UIC Program Director regarding any difficulties 

in gaining site access in order to evaluate and perform corrective action on any identified 

improperly plugged abandoned wells. 

EPA recommends that both the casing and the cement plugs be evaluated. Casing failure is most 

common at joints and in weak formations where instability around the well bore can lead to 

failed cement and to casing buckling. Weak formations are also common areas for cement 

failure, as are high pressure formations, due to fluid intrusion. Tools used to evaluate the cement 

and casing include, but are not limited to: 

 Multi-finger caliper log; 

 Sonic scanner; 
UIC Program Class VI Well Area of Review 61

Evaluation and Corrective Action Guidance

 Ultrasonic imaging tool; 

 Cement evaluation log; 

 Radioactive tracer; 

 Cased hole dynamic tester; 

 Modular sidewall coring tool; and 

 Cased hole fluid test. 

Multi-finger caliper logs measure the radius of the borehole in a non-destructive way. They can 

give a 360-degree picture of the inside of the casing and identify any defects caused by 

corrosion, erosion, or other events (e.g., dropped tools). 

A sonic scanner sends out sound waves and measures the returned waves in receivers. The log 

provides information on the quality of the casing-cement bond and the cement-formation bond. 

The sonic scanner averages the results for the entire radius and therefore cannot provide threedimensional pictures of the cement bond, or determine the reasons for a poor quality cement 

bond. An ultrasonic imaging tool is another non-destructive tool that uses ultrasonic transmitters 

and receivers to determine information about the casing and cement. The ultrasonic imaging tool 

can return 360-degree information on casing thickness, cement thickness, and cement bond. 

More information on these tools can be found in Duguid and Crow (2007) and Close et al. 

(2009). 

A cement evaluation log is another tool used and log results include information on both the 

cement and the bond quality. This log provides results that are averaged over the circumference 

of the well, and testing is typically conducted in combination with an ultrasonic imaging tool to 

provide more complete information on the three-dimensional picture of the well. In some cases, 

the cement hardens while the well casing is under pressure and, when pressure is released, 

microannuli can form between the casing and cement. If unconnected to other cracks, these 

microannuli cannot transmit fluid, but they will appear in logging results as a potential poor 

bond. This artifact can be evaluated by performing the cement evaluation log under pressure 

(Randhol et al., 2007). Radioactive tracers also can be used to detect leaks in casing and cement 

and fluid leaking along channels in the well bore. Radioactive tracers are injected down the well, 

and gamma detectors are used to detect any fluid flow. 

Cased-hole dynamic testers measure mobility or porosity. They can be used to determine the 

porosity of the cement. They are semi-destructive tests as they do create a small hole in the 

casing and cement; however, the hole is patched after the test is run. The instrument works well 

in highly permeable formations or in cement, while performance in lower porosity formations is 

still under investigation. 

Modular sidewall coring tools take small cores of the casing and cement for analysis in the 

laboratory. Laboratory analyses can include scanning electron microscopy, X-ray diffraction, and 

measurements of permeability and density. This is a more destructive test that leaves 

approximately 1-inch diameter holes in the side of the well, which is then patched with a 

remedial cement squeeze after testing is completed. Cased-hole fluid testers can be run with the 
UIC Program Class VI Well Area of Review 62

Evaluation and Corrective Action Guidance

cased-hole mobility tool, using optical instruments to determine what fluids are present in the 

formation outside the well bore. 

In general, EPA recommends that these tests be run sequentially, from the simplest and least 

destructive tests to the more complicated and destructive tests. This way, if a flaw is found with a 

simpler test that determines that the well should be plugged or otherwise remediated, the more 

expensive and destructive tests may be avoided. The typical order of running the tests is caliper 

log, sonic and ultrasonic tools, cased-hole mobility and fluid tests, and then sidewall cores 

(Duguid and Crow, 2007). This set of tools can be used to determine the quality of the casing and 

cement; if flaws such as degraded cement porosity, casing corrosion, microannuli in the cement, 

channels between the cement and casing or cement and formation, or missing cement are found, 

the Class VI Rule requires that corrective action be performed on the well [40 CFR 146.84(d)]. A 

brief summary of the main methods for evaluating cement and casing condition along with major 

benefits and disadvantages are included in Table 4-1 below. 

Table 4-1: Tools for Assessment of the Integrity of Abandoned Wells. 

Tool Target Advantages Disadvantages

Multifinger calipers Casing Non-destructive, relatively 

simple

Only examines interior, only 

detects casing damage

Sonic Logs Cement Non-destructive, yields 

information on cement bond

Results averaged over well 

circumference, can’t indicate 

reasons for poor quality bond

Ultrasonic Logs Casing, 

Cement

Non-destructive, can detect 

flaws in casing and cement, 

provides three-dimensional

images 

Sensitive to well fluids

Cement evaluation log Cement

Non-destructive, yields 

information on quality of 

cement bond

Results averaged over well 

circumference

Tracers Leak 

detection

Can pinpoint routes of leaks, 

channeling

Radioactive tracers require special 

handling and may have negative 

public perception

Dynamic Cased Hole 

Tester Cement Can determine porosity of cement

Semi-destructive, untested in low 

porosity conditions

Sidewall coring Cement Can give detailed analysis of 

cement condition Destructive

4.4. Performing Corrective Action on Wells Within the AoR 

The Class VI Rule requires that owners or operators of Class VI injection wells perform 

corrective action on all artificial penetrations in the AoR that may penetrate the confining zone 

and are determined to have been plugged and abandoned in a manner such that they could serve 
UIC Program Class VI Well Area of Review 63

Evaluation and Corrective Action Guidance

as a conduit for fluid movement and endanger USDWs [40 CFR 146.84(d)]. In performing 

corrective action, owners or operators must use methods designed to prevent the movement of 

fluid into or between USDWs, including use of materials compatible with the carbon dioxide 

stream, where appropriate [40 CFR 146.84(d)]. Figure 4-3 presents a decision tree that illustrates 

how the various evaluation tools can be used together to evaluate abandoned wells in an efficient 

and logical manner. 

As described above, the Class VI Rule allows owners or operators to perform corrective action 

on a phased basis, if approved by the UIC Program Director. If a phased approach is approved 

for performing corrective action for a GS project, EPA recommends that all required corrective 

action on wells identified as deficient during the permit application process (or AoR 

reevaluations) receive corrective action prior to the end of the injection phase. 

It is possible that some corrective action may be performed during the post-injection phase. For 

example, if the plume and pressure front movement were to deviate from predictions, this may 

necessitate corrective action for newly identified artificial penetration during the post-injection 

phase.

Performing corrective action on improperly abandoned wells is intended to prevent the 

movement of carbon dioxide or other mobilized fluids into or between USDWs. Acceptable 

forms of corrective action include well plugging and/or remedial cementing of the improperly 

abandoned well. In addition to corrective action, EPA recommends performing enhanced 

monitoring in the vicinity of improperly abandoned wells, including ground water monitoring 

and using indirect geophysical techniques for obtaining monitoring results. Appropriate 

monitoring for Class VI injection wells is discussed in the UIC Program Class VI Well Testing 

and Monitoring Guidance. 
UIC Program Class VI Well Area of Review 64

Evaluation and Corrective Action Guidance

Figure 4-3: Well Evaluation Decision Tree. 
UIC Program Class VI Well Area of Review 65

Evaluation and Corrective Action Guidance

4.4.1. Plugging of Wells within the AoR 

Plugging of Class VI injection wells at the cessation of the injection phase of the project is 

discussed in detail in the UIC Program Guidance on Class VI Well Plugging, Post-Injection Site 

Care, and Site Closure. This section focuses on the plugging of improperly abandoned wells 

within the AoR prior to the commencement of injection. However, because similarities exist in 

plugging techniques for abandoned wells and former injection wells, the reader should refer to 

the UIC Program Guidance on Class VI Well Plugging, Post-Injection Site Care, and Site 

Closure for further detail regarding well plugging techniques for Class VI injection wells. 

A well requires plugging if records indicate that an abandoned well was not plugged, was 

plugged and abandoned improperly, or has not been plugged in a manner that prevents 

movement of carbon dioxide or other fluids that may endanger USDWs [40 CFR 146.84(c) and 

(d)]. In addition, where records indicate that a well plug does not exist at a depth corresponding 

to the primary confining layer of the GS project, EPA recommends that the well have an 

additional plug set at this depth to meet the requirements of the Class VI Rule. Where records 

indicate that there are no well plugs below USDWs or other permeable formations that may 

exhibit cross flow of mobilized fluids, additional plugs may be required by the UIC Program 

Director for proper corrective action in these zones. Also, in wells that were plugged but the 

evaluation techniques discussed in Section 4.3 of this guidance document reveal cracks, 

channels, or annuli in the plug that would allow fluid migration, EPA recommends drilling out 

and replacing the plug. In addition, if the plug material may corrode in a carbon-dioxide rich 

environment, EPA recommends replacing it. For wells where casing exists at depths 

corresponding to the injection and/or confining zone and the annular space may serve as a 

conduit for fluid movement if not properly cemented, remedial cementing may be necessary or 

the casing may need to be removed and replaced with a cement plug. See Section 4.4.2 of this 

guidance document for more information on remedial cementing. 

For the plugging of improperly abandoned wells within the AoR, EPA recommends that a plug 

be set at a depth interval corresponding to the primary confining zone overlying the injection 

zone of the Class VI injection well. In the absence of an adequate plug across the confining zone, 

cross-migration may occur wherein fluids enter a permeable zone below the lowermost USDW 

and then migrate upward from that zone. See Figure 4-2 of this guidance document for more 

information. However, in order to supplement the confining-zone plug, ideal additional plugging 

zones include the bottom of any casings and across any USDWs. A surface plug would also 

typically be required by local well abandonment regulations to ensure that there is no risk of 

anyone physically falling into the well bore. 

To provide the best possible barrier to carbon dioxide migration out of the injection zone, EPA 

recommends that corrective action be conducted in a manner to provide multiple barriers to 

carbon dioxide migration and avoid underground cross-flow. Materials that are compatible with 

the carbon dioxide must be used where appropriate [40 CFR 146.84(d)]. Material compatibility 

with carbon dioxide is discussed further in the UIC Program Class VI Well Construction 

Guidance. 
UIC Program Class VI Well Area of Review 66

Evaluation and Corrective Action Guidance

4.4.2. Remedial Cementing

Properly cementing improperly abandoned wells located within the delineated AoR between any 

existing well casing and the geologic formation, especially through the injection zone, provides 

an important fluid migration barrier. EPA recommends performing remedial cementing in order 

to meet the corrective action requirements of the Class VI Rule if a well has been properly 

plugged but the records, or any testing such as that described in Section 4.3 of this guidance, 

indicate that the cement surrounding the well bore has failed or has cracks, channels, or annuli 

that could allow migration of carbon dioxide. Key areas on which to focus remedial cementing 

include depths corresponding to the injection zone and through any other permeable zones. 

Remedial cementing is performed through squeeze cementing, where the cement is emplaced 

into the affected area. For more information on cement squeezes, refer to Reynolds and Kiker 

(2003). Increased pressure on the cement forces water out of the cement slurry leaving behind 

the partially dehydrated cement. Cement squeezes can either be low pressure or high pressure. 

Low pressure squeezes are used to set a small amount of cement in a given area and operate at a 

pressure lower than the fracture pressure of the formation. Higher pressure squeezes are used 

when channels or disconnected microannuli are to be cemented. The higher pressure squeezes 

may fracture the formation and then allow the cement to flow into disconnected channels. 

Cement squeezes can be performed using either a packer or a bradenhead squeeze. The methods 

differ in how the treated section is isolated from the rest of the well. In the packer squeeze, 

packers isolate the area to be treated, and a bridge plug isolates the area below the area to be 

cemented, while a modified packer with a bypass valve isolates the area above the treated area.

Cement retainers are used if significant back pressure is expected. A bradenhead squeeze only 

isolates the area below the area to be cemented. It is typically used only if the casing above the 

treated area is strong enough to withstand the squeeze pressure. In cement squeezes, either 

drillable packers or retrievable packers can be used. Drillable packers allow less freedom in 

placement but better control of the cement. They are preferred if high pressures are maintained 

on the cement after the squeeze. 

Cements used in squeeze cementing can vary depending on the nature of the defect. The Class 

VI Rule requires that all materials used for cementing of abandoned wells be compatible with the 

carbon dioxide stream, where appropriate [40 CFR 146.84(d)]. Traditional cements may be 

supplemented with or replaced by materials such as polymer gels and acrylic grouts. Acrylic 

grouts can be used for small casing leaks or cases where pressure leak off is detected. High 

concentration low molecular weight polymers can be used for small to moderate leaks. High 

molecular weight polymers are typically used for channeling and lost circulation applications. 

Cement or cement/polymer blends are typically used for severe leaks (Randhol et al., 2007). 

4.5. Reporting Well Identification, Assessment, and Corrective Action to the UIC 

Program Director

As discussed in the UIC Program Class VI Well Project Plan Development Guidance, the AoR 

and Corrective Action Plan, submitted with the initial stage of the permit application, must 
UIC Program Class VI Well Area of Review 67

Evaluation and Corrective Action Guidance

indicate what well identification and assessments will be used and how corrective action will be 

conducted [40 CFR 146.84(b)(2)(iv)]. The plan is a condition of the permit and is subject to UIC 

Program Director approval [40 CFR 146.84(b)]. 

Owners or operators seeking a Class VI injection well permit are required to report the following 

information regarding abandoned wells within the AoR that may penetrate the primary confining 

zone: the well’s type, construction, date drilled, location, depth, record of plugging and/or 

completion, and any additional information required by the UIC Program Director [40 CFR 

146.82(a)(4)]. This information may be found in acceptable public and private databases, where 

available. See Section 4.2.1 for more information. In cases where available records do not 

provide the necessary information or indicate that the well was plugged improperly, in a 

questionable manner, or with materials inappropriate for contact with carbon dioxide, then site 

investigations must be performed to establish the condition of the well, as discussed previously 

[40 CFR 146.84(c)(3)]. 

The UIC Program Director will review the submitted well information to ensure completeness 

and may consult with officials at oil and gas or water agencies to ensure that the well search was 

thorough. The UIC Program Director will also review well completion records to determine 

those wells that may penetrate the primary confining zone and will likely compare this list to 

wells scheduled for corrective action and submitted with the Class VI injection well permit 

application. For those identified abandoned wells that have been determined by the owner or 

operator to not require corrective action, the UIC Program Director will likely review the records 

of plugging and any field testing conducted, to verify that the well does not require corrective 

action. If information on the depth or condition of the plug(s) is missing, the UIC Program 

Director may request additional tests or require the well to be re-plugged. 

Reports of any tests done on abandoned wells must be submitted to the UIC Program Director

with the permit application along with a list of wells for which corrective action will be 

conducted, as part of the AoR and Corrective Action Plan required at 40 CFR 146.84(b). Before 

receiving authorization to inject, the owner or operator must submit a report on the status of 

corrective action [40 CFR 146.82(c)(6)], indicating the number, type, and location of the plugs. 

EPA recommends that owners or operators also submit any records of remedial cementing with 

the Class VI injection well permit application, along with cement logs showing the methods used 

and the results of the remedial cementing. Testing and remedial cementing records for wells 

which are part of a planned later stage of corrective action may be submitted after that phase is 

completed. 
UIC Program Class VI Well Area of Review 68

Evaluation and Corrective Action Guidance

5. AoR Reevaluation

The Class VI Rule requires owners or operators of permitted Class VI injection wells to 

reevaluate the AoR delineation on a regular basis, at a frequency of at least once every five (5) 

years [40 CFR 146.84(e)]. The purpose of AoR reevaluation is to ensure that the initial model 

predictions are adequate for predicting the extent of the separate-phase carbon dioxide plume and 

pressure front. To this end, AoR reevaluation consists of a comparison of modeling predictions 

and the required site monitoring data [40 CFR 146.90] and a revision of the model used to 

delineate the AoR when necessary. Because Class VI injection well permits are granted for the 

lifetime of the project, AoR reevaluation is the primary opportunity for the owner or operator and 

the UIC Program Director to assess the project’s operation and take additional appropriate 

actions, if necessary, to protect USDWs. If a revision of the AoR delineation is necessary, a 

revision of the AoR and Corrective Action Plan is also required [40 CFR 146.84(e)(4)], along 

with other related project plans that may be dependent on the extent of the delineated AoR, 

including the Testing and Monitoring Plan [40 CFR 146.90(j)]. It is important to note that a 

change in the AoR and/or the AoR and Corrective Action Plan after the permit is issued may 

constitute a modification of the Class VI permit, and would be subject to public notice [40 CFR 

144.39(a)(5)(i)]. 

Reevaluations of the AoR must continue throughout the life of the GS project, including the 

post-injection phase [40 CFR 146.84(e)]. It is likely that, following cessation of injection, the 

area of increased pressure will reduce in size as pressures dissipate; therefore, EPA expects that 

the reviews will entail an examination of monitoring data and confirmation and communication 

to the UIC Program Director that no modifications to the AoR or amendments to any plans are 

needed. However, this step is necessary to ensure that USDWs are not endangered and that all of 

the plans in force (including the PISC and Site Closure Plan and the Emergency and Remedial 

Response Plan) remain protective of USDWs.

5.1. Class VI Rule Requirements Related to AoR Reevaluation

The following Class VI Rule requirements pertain to reevaluation of the AoR: 

• 40 CFR 146.84(e): At the minimum fixed frequency, not to exceed five years, as 

specified in the AoR and Corrective Action Plan, or when monitoring and operational 

conditions warrant, owners or operators must: 

(1) Reevaluate the AoR in the same manner specified in 40 CFR 146.84(c)(1); 

(2) Identify all wells in the reevaluated AoR that require corrective action in the 

same manner specified in 40 CFR 146.84(c);

(3) Perform corrective action on wells requiring corrective action in the 

reevaluated AoR in the same manner specified in 40 CFR 146.84(d); and

(4) Submit an amended AoR and Corrective Action Plan or demonstrate to the 

UIC Program Director through monitoring data and modeling results that no 

amendment to the AoR and Corrective Action Plan is needed. Any amendments 
UIC Program Class VI Well Area of Review 69

Evaluation and Corrective Action Guidance

to the AoR and Corrective Action Plan must be approved by the UIC Program

Director, must be incorporated into the permit, and are subject to the permit 

modification requirements at 40 CFR 144.39 or 144.41, as appropriate. 

5.2. Conditions Warranting an AoR Reevaluation 

AoR reevaluation is required at a minimum fixed frequency of at least once every five years, or 

when monitoring and operational conditions warrant [40 CFR 146.84(e)]. EPA recommends that 

monitoring and operational conditions that may warrant a reevaluation of the AoR include: 

 Significant changes in site operations that may alter model predictions and the AoR 

delineation; 

 Monitoring results for the injected carbon dioxide plume and/or the associated pressure 

front that differ significantly from model predictions; or 

 New site characterization data obtained that may significantly change model predictions 

and the delineated AoR. 

Any site-specific criteria that will trigger an AoR reevaluation for a particular project must be 

included in the AoR and Corrective Action Plan [40 CFR 146.84(b)(2)(ii)]. 

5.2.1. Minimum Fixed Frequency

As stated above, the owners or operators of permitted Class VI injection wells must reevaluate 

the AoR delineation at least once every five years [40 CFR 146.84(e)]. The planned fixed 

frequency for reevaluation must be included in the AoR and Corrective Action Plan [40 CFR 

146.84(b)(2)(i)]. The AoR may need to be reevaluated more frequently than the previously 

scheduled timeframe based on other factors. In these cases, the schedule for AoR reevaluation 

may be updated appropriately. At no time may AoR reevaluation occur less than once every five

years [40 CFR 146.84(e)]. 

5.2.2. Significant Changes in Operations

Significant changes in operation of the GS project and/or individual Class VI injection wells 

mandate an AoR reevaluation [40 CFR 146.84(e)]. The UIC Program Director may require an 

AoR reevaluation prior to approving any operational changes. If allowed by the UIC Program 

Director, operational changes may occur prior to reevaluation of the AoR. In these cases, EPA

recommends that the AoR reevaluation be submitted to the UIC Program Director within an 

agreed-upon timeframe of instituting such changes, as described in the AoR and Corrective 

Action Plan. 

EPA recommends that proposed operational changes warranting an AoR reevaluation may

include, but are not limited to, a change in the location or number of Class VI injection wells 

injecting into the same injection zone and/or a change in carbon dioxide injection rates, volumes, 

or pressures outside of the limits of the original permit and AoR delineation. Additional 
UIC Program Class VI Well Area of Review 70

Evaluation and Corrective Action Guidance

operational changes that may warrant an AoR reevaluation, if required by the UIC Program 

Director, include a change in the composition of the injectate or changes in fluid production rates 

from the injection or overlying zones. Based on the discretion of the UIC Program Director, 

short-term routine operational changes (e.g., temporary well shut-ins) may not warrant 

reevaluation of the AoR. 

In addition, the owner or operator may choose to perform an AoR reevaluation based on other 

operational changes, with the approval of the UIC Program Director. Specific operational 

triggers for an AoR reevaluation for a particular Class VI injection well must be included in the 

AoR and Corrective Action Plan submitted with the permit application for that particular 

injection well [40 CFR 146.84(b)(2)(ii)]. Operational changes that trigger a reevaluation may be 

associated with the GS project under which the permitted Class VI injection well operates or 

with separate projects that inject carbon dioxide into the same injection formation. 

5.2.3. Results from Site Monitoring that Differ From Model Predictions

EPA recommends that collection of any monitoring data (required under 40 CFR 146.90) that 

indicate carbon dioxide and/or pressure front migration significantly different than that predicted 

by the current AoR delineation model warrant an AoR reevaluation. Specific criteria for 

differences in monitoring data and model predictions that may trigger an AoR reevaluation for a 

particular project must be included in the AoR and Corrective Action Plan [40 CFR 

146.84(b)(2)(ii)]. In such cases, when monitoring data and modeling predictions differ, the 

owner or operator is encouraged to notify the UIC Program Director and submit an AoR 

reevaluation within timeframes that have been established in the AoR and Corrective Action 

Plan. Methods for monitoring the evolution of the carbon dioxide plume and associated pressure 

front are discussed in more detail in the UIC Program Class VI Well Testing and Monitoring 

Guidance. An example of evaluation of monitoring results during AoR reevaluation is provided 

in Box 5-1. 

The owner or operator is required to perform monitoring to track the extent of the carbon dioxide 

plume and the presence or absence of elevated pressure [40 CFR 146.90(g)]. Pressure monitoring 

is required using direct methods (e.g., pressure transducers) within the injection zone, and 

indirect methods for plume tracking are also required unless the UIC Program Director 

determines, based on site-specific geology, that such methods are not appropriate [40 CFR 

146.90(g)(1) and (2)]. Additionally, the owner or operator is required to perform periodic 

monitoring of ground water quality and geochemical changes above the primary confining zone 

that may be a result of carbon dioxide movement through the confining zone [40 CFR 

146.90(d)]. On a site-specific basis, the UIC Program Director may require additional 

geochemical monitoring within the injection zone as a component of carbon dioxide plume 

tracking [40 CFR 146.90(i)]. 

EPA recommends that pressure measurements indicative of pressure-front migration further than 

that predicted by the current computational model warrant an AoR reevaluation. In practice, this 

would be indicated by an observed increase in pressure at monitoring wells greater than 

predicted by the computational model. In some cases, pressure measurements may fluctuate, and 
UIC Program Class VI Well Area of Review 71

Evaluation and Corrective Action Guidance

short-term temporary pressure increases (e.g., spikes) may not warrant an AoR reevaluation. 

EPA recommends that the specific pressure monitoring results that would trigger an AoR 

reevaluation be included in the AoR and Corrective Action Plan. For example, the owner or 

operator may specify the magnitude and duration of increased pressure that would trigger an 

AoR reevaluation for each monitoring well. 

Results of carbon dioxide plume and pressure-front tracking using indirect methods, such as 

periodic geophysical surveys, may also be used for comparison to model predictions. 

Geophysical survey results provide information over relatively large areas, as opposed to “point” 

measurements provided by monitoring wells. Geophysical survey results are intended to provide 

an estimate of the extent of the separate-phase carbon dioxide plume and, in some cases, pressure 

changes. EPA anticipates that results of indirect monitoring that indicate carbon dioxide 

migration (1) outside of the boundaries of the current AoR delineation, or (2) at rates 

significantly greater than current model estimates would also warrant an AoR reevaluation.

EPA also recommends performing an AoR reevaluation if the results of the ground water 

geochemical sampling indicate separate-phase (i.e., supercritical, liquid, or gaseous) carbon 

dioxide migration outside of the boundaries of the current AoR delineation, or at rates 

significantly greater than predicted by the computational model. The presence of separate-phase 

carbon dioxide in the sampled fluids above the confining zone is evidence of carbon 

dioxide/fluid migration out of the injection zone and is cause to notify the UIC Program Director 

pursuant to 40 CFR 146.91(c)(1). In addition, elevated carbon dioxide aqueous concentrations 

may indicate the presence of separate-phase carbon dioxide in the immediate vicinity of the 

monitoring well. 

5.2.4. Ongoing Site Characterization

Site characterization is not a one-time exercise at GS project sites. As additional site 

characterization data are collected via geophysical surveys, the drilling of new injection or 

monitoring wells, or from other sources, the data must be subsequently incorporated into the 

existing computational model used for AoR delineation [40 CFR 146.84(c)(1) and (e)(1)]. Types 

of data that may be incorporated into a reevaluation include newly identified potential conduits 

for fluid movement, updated information regarding injection or confining zone extent and 

thickness, or further characterization of formation heterogeneity. The UIC Program Director may 

also require an AoR reevaluation based on any newly available site characterization data that 

may impact current modeling predictions. 

5.3. Performing an AoR Reevaluation 

The first step in performing an AoR reevaluation for a Class VI injection well is a comparison of 

the available monitoring data and the model predictions. If Class VI owners or operators believe 

that monitoring and modeling data are consistent and that revision of the model is not necessary, 

they must demonstrate this to the UIC Program Director in lieu of revising the computational 

model [40 CFR 146.84(e)(4)]. However, if monitoring data and modeling predictions differ 

significantly, then the Class VI owner or operator must submit an amended AoR and Corrective 
UIC Program Class VI Well Area of Review 72

Evaluation and Corrective Action Guidance

Action Plan and revise both the computational model and the AoR delineation results [40 CFR 

146.84(e)(1) and (4)]. 

Box 5-1. Hypothetical Example of an AoR Reevaluation

An AoR reevaluation consists of comparing monitoring results of plume and pressure-front 

movement to model predictions. In this hypothetical example, a continuation of the scenario 

presented earlier in Boxes 3-1 and 3-2, the AoR reevaluation required after 20 years of 

injection is illustrated below. In this example, the previously required AoR reevaluations at 5, 

10, and 15 years did not result in any AoR delineation modifications. 

Comparison of Plume Monitoring Data 

In this hypothetical scenario, monitoring data are available from eight monitoring wells 

screened within the injection zone and from an indirect geophysical monitoring technique. 

Monitoring well data are used to assess the potential presence of separate-phase carbon 

dioxide at each location. The data indicate that separate-phase carbon dioxide is present at one 

of the monitoring wells. These data are compared to initial model predictions of plume 

evolution for 20 years after the commencement of injection (Figure 5-1). Carbon dioxide is 

detected at MW-6, outside of the areas predicted by the model to exhibit carbon dioxide. 

Figure 5-1: Hypothetical Geologic Sequestration Site: Comparison of Model Predictions and Plume 

Monitoring Results at 20 Years of Injection.
UIC Program Class VI Well Area of Review 73

Evaluation and Corrective Action Guidance

Box 5-1. Hypothetical Example of an AoR Reevaluation, continued

Compared to monitoring well data, geophysical data provide a larger-area estimate of the 

extent of separate-phase carbon dioxide. The geophysical and monitoring-well data are 

consistent in their general evaluation of where separate-phase carbon dioxide is present. 

Geophysical data and model results are generally consistent for the plume emanating from 

Injection Well #3, and inconsistent for Injection Wells #1 and #2. The carbon dioxide plume 

may have migrated differently than originally predicted for several reasons, as discussed 

below. 

Comparison of Pressure Monitoring Data 

Bottom-hole pressure data are collected at all of the eight monitoring wells. This example 

focuses on data collected at three of the wells, MW-1, MW-2, and MW-6. For actual projects, 

EPA recommends that data from all monitoring wells be considered. Graphs of pressure 

monitoring data over the first 20 years of the project, compared to modeling results, are 

presented in Figure 5-2. 

Figure 5-2: Hypothetical Geologic Sequestration Site: Comparison of Model Predictions and Pressure 

Monitoring Results at 20 Years of Injection. 
UIC Program Class VI Well Area of Review 74

Evaluation and Corrective Action Guidance

Box 5-1. Hypothetical Example of an AoR Reevaluation, continued

Pressure monitoring data are consistent with modeling predictions on the western edge of the 

project (MW-1). The general scatter in the monitoring data are expected, and there is no 

significant bias (i.e., less than, greater than) in comparing the monitoring data and modeling 

results. Data from the northern portion of the project (MW-2) indicate that actual pressure 

increases in the injection zone are lower than model predictions. This area has exhibited less 

of a pressure perturbation caused by injection than originally predicted. In contrast, data from 

the eastern portion of the site (MW-6) indicate that there has been a larger pressure increase 

than originally predicted. These data are generally consistent with the plume migration data, 

presented above, which showed that the plume has migrated further east than originally 

predicted. 

Outcome of Monitoring Data and Model Comparison 

This comparison indicates that, after 20 years of injection, modeling results and monitoring 

data compare favorably in some regions of the site. However, the plume and pressure front 

appear to have migrated further to the east than initially predicted. This disparity may be due 

to several factors. Examples include the presence of a high-permeability pathway within the 

injection zone that had not been fully characterized during initial site characterization, or the 

dip angle at the injection zone/confining zone interface being larger than originally assumed. 

Based on this comparison, the operator of the project site, in consultation with the UIC 

Program Director, decided to calibrate the AoR model and re-delineate the AoR. See Box 5-2 

for more information. 
UIC Program Class VI Well Area of Review 75

Evaluation and Corrective Action Guidance

5.3.1. Demonstrating Adequate Existing AoR Delineation 

An AoR reevaluation does not necessarily need to result in revisions or updates to the site 

computational model. If the owner or operator determines that no changes are necessary, the 

required reevaluation may consist of demonstrating this to the UIC Program Director [40 CFR 

146.84(e)(4)]. EPA recommends that demonstrating the adequacy of the current AoR delineation 

includes verification that existing operational and site characterization data have been 

incorporated into the model and that existing monitoring data agree with the modeled

predictions. 

EPA recommends that the Class VI injection well owners or operators submit any new 

operational, monitoring, or site characterization data that have been received since the last AoR 

reevaluation to the UIC Program Director. EPA also recommends that details regarding how this 

information has been incorporated into the site computational model be presented, as newly 

received operational or site characterization data may impact model input parameter values. 

Integral to demonstrating that the current AoR delineation is adequate is the comparison of 

monitoring data and model predictions. EPA recommends that this comparison take the form of 

graphics and informative maps showing the general agreement between monitoring results and 

model predictions, and that all available monitoring data be considered, including fluid 

geochemistry monitoring, pressure monitoring, and geophysical surveys. 

5.3.2. Modifying the Existing AoR Delineation

Any significant differences between operational monitoring results and the existing model 

predictions that are the basis for the AoR delineation, for example as discussed in Section 5.2.3 

of this guidance document, warrant a modification to the existing AoR delineation [40 CFR 

146.84(e)]. The steps in revision of the AoR delineation include adjusting the site conceptual 

model, model calibration (i.e., adjusting model parameters), and presentation of adjusted model 

results and the newly delineated AoR to the UIC Program Director. 

EPA recommends that the site conceptual model be revised based on new site characterization, 

operational, and, in some cases, monitoring data. The new conceptual site model schematic may 

be provided to the UIC Program Director along with the AoR reevaluation information, with any 

changes highlighted. Examples of changes to the conceptual model include new injection wells, 

newly elucidated geologic features (e.g., stratigraphic layers), or a revised permeability field.

Following revision of the site conceptual model, revision of the existing AoR delineation may 

require model calibration in order to minimize the differences between monitoring data and 

model simulations (see Section 2.5 of this guidance). EPA recommends that the relative error 

difference between monitoring data and model predictions be quantified via the use of 

calibration statistics (e.g., ME, MAE, RMSE). To the extent possible, the value of the calibration 

statistics should be minimized during model calibration. The value of the model calibration 

statistics also informs the expected uncertainty and error in model predictions of future 
UIC Program Class VI Well Area of Review 76

Evaluation and Corrective Action Guidance

conditions. Following model calibration, the AoR delineation may be revised using methods 

described in Section 3.4 of this guidance. 

In reporting an AoR computational model and delineation revision, EPA recommends that all 

model attributes, as given in Section 3.5 of this guidance document, be re-submitted to the UIC 

Program Director. In addition, EPA recommends that the model calibration process and final 

AoR delineation results be presented in detail as part of the submission with: 

• Adjusted input parameter values listed; 

• Graphs comparing observed and modeled values of carbon dioxide migration and fluid 

pressure; 

• Model results showing carbon dioxide and pressure front migration over time included; 

and

• The value of the model calibration statistics. 

The newly delineated AoR may be presented on maps which would highlight similarities and 

differences in comparison with previous AoR delineations. See Box 5-2, below, for an example 

of a hypothetical AoR reevaluation. 

If a revision of the AoR delineation is necessary, an amendment to the AoR and Corrective 

Action Plan is also required, along with possible amendments to other related project plans [40 

CFR 146.84(e)(4) and (f)]. EPA recommends that the amended AoR and Corrective Action Plan 

explain any differences in corrective action activities that result from AoR revision, including a 

demonstration of adequate surface access rights in order to perform the required corrective action 

activities. See Section 4 for more information on performing corrective action. Furthermore, in 

some cases, GS project attributes that are outside the scope of the Class VI Rule and the UIC 

Program, such as pore-space ownership rights, may be related to the size of the AoR. In these 

cases, the owners or operators are encouraged to consult with the UIC Program Director, or 

another applicable regulatory agency, following a revision of the AoR in order to proceed. 
UIC Program Class VI Well Area of Review 77

Evaluation and Corrective Action Guidance

Box 5-2. Hypothetical Example of a Presentation of the Revised AoR

After the site computational model has been revised through model calibration to monitoring 

data, and/or updating with new operational or site characterization parameters, the AoR must 

be re-delineated [40 CFR 146.84(e)]. See Box 3-2 for more information on AoR delineation; 

the same general methods should be used during the reevaluation. Once the AoR has been 

revised, it may be presented on a site base map in comparison to the former AoR delineation 

(Figure 5-3).

In this hypothetical example, the AoR reevaluation has resulted in an AoR delineation that 

extends generally farther toward the east than previously. This is consistent with the 

monitoring data (Box 5-1) indicating further plume and pressure front migration toward the 

east. The model was revised to match monitoring data by adjusting intrinsic permeability 

values within the injection zone and the dip angle at the injection/confining zone interface. 

The region newly identified as located within the delineated AoR (between the purple and 

blue contour lines) must be subjected to the artificial penetration identification, assessment, 

and corrective action procedures as discussed in Section 4 of this guidance document [40 CFR 

146.84(e)(2) and (3)]. Furthermore, the revision of the AoR requires revisions to the AoR and 

Corrective Action Plan and other project plans, as discussed in the UIC Program Class VI

Well Project Plan Development Guidance. Changes to the AoR and Corrective Action Plan 

may demonstrate a need to secure new surface access rights for the newly included area. The 

owner or operator may also contact the applicable regulatory agency for other project 

attributes (e.g., new pore space ownership rights) that are outside the scope of the Class VI 

Rule and the UIC Program. 

Figure 5-3: Hypothetical Geologic Sequestration Site: Initial AoR Delineation and Delineation after 

Reevaluation.
UIC Program Class VI Well Area of Review 78

Evaluation and Corrective Action Guidance

References 

Ajo-Franklin, J., Doughty, C., & Daley, T.M. 2008. Combining Analysis of Continuous ActiveSource Seismic Monitoring (CASSM) and Multiphase Flow Modeling for CO2

Sequestration: The Frio II Brine Pilot. Presented at the 7th Annual Conference on Carbon 

Capture and Sequestration. May 5-8, Pittsburgh, Pennsylvania. 

ASTM International. 2005. Standard guide for locating abandoned wells. Designation D 6285-99 

(Reapproved 2005).

Bachu, S., & Bennion, B. 2008. Effects of in-situ conditions on relative permeability 

characteristics of CO2-brine systems. Environmental Geology, 54:1707-1722. 

Bandilla, K.W., Kraemer, S.R., & Birkholzer, J.T. 2012. Using semi-analytic solutions to 

approximate the area of potential impact for carbon dioxide injection, International 

Journal of Greenhouse Gas Control, 8:196-204, ISSN 1750-5836, 

10.1016/j.ijggc.2012.02.009. 

Birkholzer, J.T., Nicot, J.P., Oldenburg, C.M., Zhou, Q., Kraemer, S., & Bandilla, K. 2011. 

Brine flow up a well caused by pressure perturbation from geologic carbon sequestration: 

Static and dynamic evaluations. International Journal of Greenhouse Gas Control, 

5:850-861. 

Carle, S.F. 1999. T-PROGS: Transition Probability Geostatistical Software, Version 2.1. 

Celia, M.A., and Nordbotten, J.M. 2009. Practical modeling approaches for geologic storage of 

carbon dioxide. Ground Water, 47:627-638. 

Close, D., Cho, D., Horn, F., & Edmundson, H. 2009. The Sound of Sonic: A Historical 

Perspective and Introduction to Acoustic Logging. CSEG Recorder pp. 34-43 

Doughty, C., & Pruess, K. 2004. Modeling supercritical carbon dioxide injection in 

heterogeneous porous media. Vadose Zone Journal, 3(3):837–847. 

Doughty, C. 2007. Modeling geologic storage of carbon dioxide: Comparison of non-hysteretic 

and hysteretic characteristic curves. Energy Conversion and Management 48: 1768–

1781. 

Doughty, C., Freifeld, B.M., & Trautz, R.C. 2007. Site characterization for CO2 geologic storage 

and vice versa – the Frio brine pilot, Texas, USA as a case study. Environmental 

Geology, DOI 10.10007/s00254-007-0942-0. 

Duguid, A., & Crow, W. 2007. CO2 Well Integrity and Wellbore Monitoring. Presented at the 

Carbon Sequestration Leadership Forum (CSLF) 2nd Capacity Building in Emerging 

Economies Workshop. October 18-19, Porto Alegre, Brazil. 
UIC Program Class VI Well Area of Review 79

Evaluation and Corrective Action Guidance

Fetter, C.W. 2001. Applied Hydrogeology, 4th Edition. Prentice Hall, Upper Saddle River, NJ. 

598p. 

Finsterle, S. 2004. Mulitphase inverse modeling: Review and iTOUGH2 applications. Vadose 

Zone Journal, 3:747-762. 

Fischer, D.W., LeFever, J.A., LeFever, R.D., Helms, L.D., Sorensen, J.A., Smith, S.A., 

Steadman, E.N., & Harju, J.A. 2005. Mission Canyon Formation Outline. PCOR 

Partnership Fact Sheet, May 2005. 

Flett M., Gurton, R., & Weir, G. 2007. Heterogeneous saline formations for carbon dioxide 

disposal: Impact of varying heterogeneity on containment and trapping. Journal of 

Petroleum Science and Engineering, 57:106-118. 

Friskchknecht, F.C., Raab, P.V., & van Ee, J.J. 1985. Project Summary: Location of abandoned 

wells with geophysical methods. EPA-600/SR-84-085. 

Gaus, I., Azaroual, M., & Czernichowski-Lauriol, I. 2005. Reactive transport modeling of the 

impact of carbon dioxide injection on the clayey cap rock at Sleipner (North Sea). 

Chemical Geology, 217:319-337. 

Gerritsen, M.G., & Durlofsky, L.J. 2005. Modeling fluid flow in oil reservoirs. Annual Reviews 

in Fluid Mechanics, 37:211-238. 

Green, D.W., & Perry, R.H. 2008. Perry's Chemical Engineers' Handbook, 8th Edition. 

McGraw-Hill Book Co., New York, NY. 

Gochioco, L.M., & Ruev Jr, F. 2006. Detecting and imaging hard-to-find abandoned wells and 

pipelines. The Leading Edge, March 2006, 358-361. 

Han, W.S., & McPherson, B. 2008. Comparison of two equations of state for application of 

carbon dioxide sequestration. Advances in Water Resources, 31:877-890. 

Ide, T., Friedmann, S.J., & Herzog, H. 2006. Carbon Dioxide Leakage through Existing Wells: 

Current Technology and Regulations, presented at the 8th International Conference on 

Greenhouse Gas Control Technologies. June 2006, Trondheim, Norway. 

Illinois State Geological Survey (ISGS). 2009. Enhanced Oil Recovery I: Loudon Single-Well 

Huff ‘n’ Puff. Midwest Geologic Sequestration Consortium. Report Issued December 31. 

U.S. DOE Contract: DE-FC26-03NT41994. 

Izgec, O., Demiral, B., Bertlin, H., & Arkin, S. 2008. CO2 injection into saline carbonate aquifer 

formations II: Comparison of numerical simulations to experiments. Transport in Porous 

Media, 73:57-74. 
UIC Program Class VI Well Area of Review 80

Evaluation and Corrective Action Guidance

Jordan, P.W., & Hare, J.L. 2002. Locating Abandoned Wells: A Comprehensive Manual of 

Methods and Resources. Prepared for Solution Mining Research Institute, Research 

Project Report No. 2002-SMRI.

Juanes, R., Spiteri, E.J., Orr Jr., F.M., & Blunt, M.J. 2006. Impact of relative permeability 

hysteresis on geological CO2 storage. Water Resources Research, 42. W12418. 

Knauss K.G., Johnson, J.W., & Steefel, C.I. 2005. Evaluation of the impact of CO2, cocontaminant gas, aqueous fluid and reservoir rock interactions on the geologic 

sequestration of CO2. Chemical Geology, 217:339-350. 

Kumar, A., Noh, M., Pope, G.A., Sephehrnoori, K., Bryant, S., & Lake, L.W. 2004. Reservoir 

Simulation of Carbon Dioxide Storage in Deep Saline Aquifers. SPE/DOW Fourteenth 

Symposium on Improved Oil Recovery. April 2004, Tulsa Oklahoma. 

Law, D.H.-S., & Bachu, S. 1996. Hydrogeological and numerical analysis of CO2 disposal in 

deep aquifers in the Alberta sedimentary basin. Energy Conversion and Management, 

37:1167-1174. 

Lindeberg, E. 1997. Escape of CO2 from aquifers. Energy Conversion and Management, 

38:S235-S240. 

Midwest Geologic Sequestration Consortium (MGSC). Undated. Screening Criteria for Geologic 

Carbon Dioxide Sequestration. http://www.sequestration.org/sc_model.htm 

Miller, C.T., Christakos, G., Imhoff, P.T., McBride, J.F., Pedit, J.A., & Trangenstein, J.A. 1998. 

Mulitphase flow and transport modeling in heterogeneous porous media: challenges and 

approaches. Advances in Water Resources, 21(2): 77-120. 

National Energy Technology Laboratory (NETL). 2011. Risk Analysis and Simulation for 

Geologic Storage of CO2. DOE/NETL-2011-1459. 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/BPM_RiskAnalysisSimulation

.pdf 

National Research Council (NRC). 2007. Models in Environmental Regulatory Decision 

Making. Prepared by Committee on Models in the Regulatory Decision Process. 

Nicot, J.P., Oldenburg, C.M., Bryant, S.L., & Hovorka, S.D. 2008. Pressure perturbation from 

geologic carbon sequestration: Area-of-review boundaries and borehole leakage driving 

forces. Energy Procedia. 

Obi, E.-O. I., & Blunt, M.J. 2006. Streamline-based simulation of carbon dioxide storage in a 

North Sea aquifer. Water Resources Research, 42: W03414. 
UIC Program Class VI Well Area of Review 81

Evaluation and Corrective Action Guidance

Peng, D.Y., & Robinson, D.B. 1976. A new two-constant equation of state. Industrial and 

Engineering Chemistry Fundamentals, 15:59-64. 

Perrin, J.-C., Krause, M., & Benson, S.M. 2008. Relative permeability properties of the 

CO2/Brine system in saline aquifers: An experimental study. Presented at the 7th Annual 

Conference on Carbon Capture and Sequestration. May 5-8, Pittsburgh, Pennsylvania. 

Perry, R.H., & Green, D. 1984. Perry’s Chemical Engineers’ Handbook, Sixth Edition. 

McGraw-Hill Book Co., New York, NY. 

Pinder, G.F., & Gray, W.G. 2008. Essentials of Multiphase Flow in Porous Media. John Wiley 

& Sons, Inc., Hoboken, NJ. 

Plug, W.J., & Bruining, J. 2007. Capillary pressure for the sand- CO2-water system under 

various pressure conditions. Application to CO2 sequestration. Advances in Water 

Resources. 30:2339-2353. 

Pruess, K., and Spycher, N. 2007. ECO2N – A fluid property module for the TOUGH2 code for 

studies of CO2 storage in saline aquifers. Energy Conversion and Management. 48:1761-

1767. 

Pruess, K., Garcia, J., Kovscek, T., Oldenburg, T.C., Rutqvist, J., Steefel, C., & Xu, T. 2004. 

Code intercomparison builds confidence in numerical simulation models for geologic 

disposal of CO2. Energy, 29(9-10):1431-1444. 

Pruess, K. 2008. Leakage of CO2 from geologic storage: Role of secondary accumulation at 

shallow depth. International Journal of Greenhouse Gas Control, 2:37-46. 

Randhol, P., Valencia, K., Taghipour, A., Akervoll, I., & Carlsen, I.M. 2007. Ensuring Well 

Integrity in Connection with CO2 Injection. SINTEF report 31.6920.00/02/07. 

Reynolds, R.R., & Kiker, R.D. 2003. Produced Water and Associated Issues — A Manual for the 

Independent Operator. Oklahoma Geological Survey Open File Report 6-2003. Prepared 

for the South Midcontinent Region of the Petroleum Technology Transfer Council. 

Rutqvst, J., Birkholzer, J.T., & Tsang, C.F., 2008. Coupled Reservoir-Geomechanical Analysis 

of the Potential for Tensile and Shear Failure Associated with CO2 Injection in 

Multilayered Reservoir Caprock Systems. International Journal of Rock Mechanics and 

Mining Sciences, 45(2):132-143. 

Saripalli, P., & McGrail, P. 2002. Semi-analytical approaches to modeling deep well injection of 

CO2 for geologic sequestration. Energy Conversion and Management, 43:185-198. 

Schnaar, G., & Digiulio, D.C. 2009. Computational modeling of the geologic sequestration of 

carbon dioxide. Vadose Zone Journal, 8:389-403. 
UIC Program Class VI Well Area of Review 82

Evaluation and Corrective Action Guidance

Soeder, D.J. 1988. Porosity and Permeability of Eastern Devonian Gas Shale. SPE Formation 

Evaluation. March 1988, 116-124. 

Sorensen, J.A., Smith, S.A., Fischer, D.W., Steadman, E.N., & Harju, J.A. 2005. Potential 

Carbon Dioxide Storage Capacity of the Saline Portions of the Lower Cretaceous Aquifer 

System in the PCOR Partnership Region. PCOR Partnership Fact Sheet, October 2005. 

Spycher, N., Pruess, K., & Ennis-King, J. 2003. Carbon dioxide-water mixtures in geologic 

sequestration of carbon dioxide. I. Assessment and calculation of mutual solubilities from 

12 to 100 degrees Celsius and up to 600 bar. Geochemical et Cosmochimica Acta, 

67:3015-3031. 

Spycher, N., & Pruess, K. 2005. Carbon dioxide-water mixtures in geologic sequestration of 

carbon dioxide. II. Partitioning in chloride brines at 12-100 degrees Celsius and up to 600 

bar. Geochemical et Cosmochimica Acta, 69:3309-3320. 

Stone, H.L. 1970. Probability model for estimating three-phase relative permeability. Trans. 

AIME 249:214-218. 

Tamimi, A.E., Rinker, B., & Sandall, O.C. 1994. Diffusion coefficients for hydrogen sulfide, 

carbon dioxide, and nitrous oxide in water over the temperature range 293-368 K. 

Journal of Chemical & Engineering Data, 39:330-332. 

Thornhill, J.T., Short, T.E., & Silka L. 1982. Application of the Area of Review Concept. 

Ground Water, 20:32-38. 

United States Environmental Protection Agency (USEPA). 2002. Drinking Water Academy, 

Underground Injection Control Modules, Lesson 8: Area of Review. 

http://www.epa.gov/safewater/dwa/pdfs/2%20uic%20modules/dwaUIC-uicpermit2.pdf 

USEPA. 2003. Draft Guidance on the Development, Evaluation, and Application of Regulatory 

Environmental Models. Prepared by The Council for Regulatory Environmental 

Modeling. 

United States Geological Survey (USGS). 1995. Fact Sheet 163-95: Magnetic Surveys for 

Locating Abandoned Wells. 

Watson, T.L. 2009. CO2 Storage: Wellbore Integrity Evaluation and Integrity Across the 

Caprock, presented at the 2009 SPE Conference on CO2 Capture. November 2-4, San 

Diego, CA. 

Xu, T., Sonnenthal, E., Spycher, N., & Pruess K. 2006. TOUGHREACT—A simulation program 

for non-isothermal multiphase reactive geochemical transport in variably saturation 

geologic media: Applications to geothermal injectivity and CO2 geological sequestration. 

Computers & Geosciences, 32:145-165. 
UIC Program Class VI Well Area of Review 83

Evaluation and Corrective Action Guidance

Xu, T., Apps, J.A., Pruess, K., & Yamamoto, H. 2007. Numerical modeling of injection and 

mineral trapping of CO2 with H2S and SO2 in a sandstone formation. Chemical Geology, 

242:319-346. 

Yamamoto, H., & Doughty, C. 2009. Investigation of gridding effects for numerical simulation 

of carbon dioxide geologic sequestration,” Proceedings of TOUGH Symposium, LBNL., 

September 2009, Berkeley, CA.

Zhang, K., Doughty, C., Wu, Y.-S., & Pruess, K. 2007. Efficient parallel simulation of CO2

geologic sequestration in saline aquifers, SPE 106026, presented at 2007 SPE Reservoir 

Simulation Symposium. February 26-28, Houston, TX,. 

Zhou, Q., Birkholzer, J.T., Tsang, C.F., & Rutqvist, J. 2008. A method for quick assessment of 

CO2 storage capacity in closed and semi-closed saline formations. International Journal 

of Greenhouse Gas Control, 2(4):626-639. 

Zhou, W., Stenhouse, M.J., Arthur, R., Whittaker, S., Law, D.H.-S., Chalaturnyk, R., & Jazrawi,

W. 2004. The IEA Weyburn CO2 monitoring and storage project – modeling of the longterm migration of CO2 from Weyburn. In: Wilson M., Gale, J., Rubin, E.S., Keith, D.W., 

Gilboy, C.F., Morris, T., & Thambimuthu K. (Eds). Greenhouse gas control technologies: 

proceedings of the 7th International Conference on Greenhouse Gas Control 

Technologies. September 5-9, Vancouver, BC.